ANNUAL REPORT
December 31, 2021
Petrus Resources Ltd. (“Petrus” or the “Company”) (TSX: PRQ) is pleased to report financial and operating results as at and for the three and twelve
months ended December 31, 2021 and to provide 2021 year end reserves information as evaluated by Insite Petroleum Consultants Ltd. ("Insite").
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.
Q4 2021 HIGHLIGHTS
•
•
•
•
Commodity price improvement – Realized price per boe increased by 92% in the fourth quarter of 2021 compared to the fourth
quarter of 2020 due to strengthened oil, natural gas and NGL pricing, which increased by 81%, 78% and 140%, respectively.
Operating netback up 112% – Operating netback(1) increased by 122% to $33.12/boe in the fourth quarter of 2021 up from
$14.95/boe in the fourth quarter of 2020.
Total funds flow up 62% – Petrus generated funds flow and corporate netback(2) of $10.4 million and $19.26/boe in the fourth
quarter of 2021, 62% and 75% higher, respectively, than the fourth quarter of the prior year
Increased capital activity – Petrus incurred capital expenditures of $12.2 million in the fourth quarter of 2021 compared to $2.8
million in the fourth quarter of 2020. Petrus began execution of its fourth quarter 2021 drilling program in November, which
included the Company’s first operated well in North Ferrier. In December, the Company drilled two net wells in its core Ferrier
area.
ANNUAL 2021 HIGHLIGHTS
•
•
•
Transformative debt reduction – During 2021, Petrus executed transactions that transformed its debt position, as follows:
◦
◦
◦
◦
Reduced net debt(1) by 46% from $114.4 million to $61.8 million;
Debt to fourth quarter 2021 annualized funds flow (excluding realized hedge settlements) is now 1.5x;
Second lien term loan settled in full; and
First lien debt is now fully conforming at $57.7 million drawn.
Funds flow per boe up 41% – Petrus generated funds flow and corporate netback of $33.4 million and $15.19/boe in 2021, 26%
and 40% higher, respectively, than funds flow of $26.4 million and $10.93/boe in 2020.
Capital expenditures doubled – Petrus incurred $26.9 million of capital expenditures in 2021, compared to $14.3 million in 2020;
drilling ten gross (6.4 net) wells in Ferrier and North Ferrier.
• Maintained production – Petrus held production relatively flat at 6,009 boe/d through 2021 as it focused on debt repayment,
which limited capital reinvestment during the first nine months of the year.
2022 OUTLOOK(3)
The completion of the debt restructuring transactions during the third quarter of 2021 transformed Petrus from a company with limited
capital resources to one with the ability to create meaningful shareholder value. The substantial debt reduction associated with the second
lien debt settlement and equity financing has bolstered the Company’s financial position and provides the flexibility required to invest in
the development of its land base and unlock proven value.
On March 1, 2022, the Company entered into a definitive agreement to acquire producing oil and gas properties that are held by a privately
owned limited partnership and its general partner (the "Acquired Entities") for total consideration of approximately $14.4 million,
consisting of 10 million common shares of the Company issued at a deemed price of $1.44 per share based on the volume weighted
average trading price of the common shares of the Company on the TSX for the five trading days prior to the date of the Agreement (the
"Acquisition"). The Acquisition is expected to close in March 2022 and is subject to customary closing conditions.
For more information, please refer to the related press release dated March 1, 2022.
Petrus' Board of Directors has approved a 2022 capital budget of $50 to $55 million. Capital will be largely focused on the drilling,
completion and tie-in of 14 net wells in Ferrier. The 2022 budget was constructed using a price forecast of WTI at US$69.00/bbl, AECO at
$3.20/GJ and a foreign exchange rate of US$0.79. Through the successful execution of this capital plan, Petrus is expecting to:
•
Achieve a 2022 exit production rate of 9,000 to 9,500 boe per day (62% conventional natural gas, 25% light crude oil and 13%
natural gas liquids), a projected increase of 40 to 50% compared to 2021 average annual production.
•
•
Generate in excess of $60 million in annual funds flow, an anticipated 65 to 80% improvement compared to 2021 results.
Continue to reduce debt and further strengthen the Company’s balance sheet.
(1)Non-GAAP measure or non-GAAP ratio. Refer to "Non-GAAP and Other 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. Refer to "Non-GAAP and
Other Financial Measures".
(3)Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto.
PRESIDENT’S MESSAGE
This past year was a transformational one for Petrus and, as a result of the strategic changes we made, the Company is well
positioned to take advantage of the improved macro-outlook for the Canadian oil and gas industry. It was my pleasure to join the
Petrus team in April 2021 and, with the support of our shareholders and Board of Directors, continue to repair Petrus’ balance sheet
and put an end to declining production and cash flow. We successfully reduced the company’s net debt by nearly half, substantially
improving Petrus’ financial position and providing the much needed flexibility to begin deploying more of our cash flow to generate
production growth and leverage our existing infrastructure.
After drilling only 3.2 net wells in 2020, we doubled our drilling activity with 6.4 net wells drilled in 2021 including five operated
wells: four in our core Ferrier area and one in our emerging North Ferrier area. Production was held relatively flat throughout the
year. However, with the three net wells that we drilled at the end of 2021 and the fourteen net wells planned for 2022, we are
forecasting significant production and cash flow growth in the year ahead. Cash flow was up in 2021, mostly because of higher
commodity prices though hedging losses moderated the gains. These lower-priced hedge contracts, put in place in 2020 during the
tumultuous COVID-19 pandemic, extend only to the end of the first quarter of 2022, after which we will start to see the full effect of
the improved commodity prices in our cash flow. Net debt was reduced significantly last year and is now forecast to be less than
one times cash flow by the end of the year. Shareholder equity value increased almost 8 fold over the year from a combination of
share price increase (4x) and new equity issued, and equity accounted for 58% of the enterprise value of the company at year end,
up from 9% in 2020, and this will continue to improve as we create value while reducing debt.
Petrus has been sitting on a strong asset base with a fantastic team in place to execute the development of those assets. With the
improved macro environment and the debt issues largely behind us, 2022 will be the year to show what the Company is capable of.
We appreciate the support of our shareholders and Board of Directors and we will continue to develop and work hard to generate
the return on investment our shareholders expect.
Ken Gray
President, Chief Executive Officer and Director
RESERVES
Petrus’ 2021 year end reserves were evaluated by independent reserves evaluator, InSite Petroleum Consultants Ltd. ("Insite"), 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, 2021 ("2021 Insite
Report"). Additional reserve information as required under NI 51-101 will be included in our Annual Information Form for the year ended
December 31, 2021, 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 a majority 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 2021 Insite Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Insite:
As at December 31, 2021
Total Company Interest (1)(3)
Reserve Category
Proved Producing
Proved Non-Producing
Proved Undeveloped
Total Proved
Proved + Probable Producing
Total Probable
Total Proved Plus Probable
Conventional
Natural Gas
(mmcf)
Light and
Medium
Crude Oil
(mbbl)
NGL
(mbbl)
Total
(mboe)
NPV 0%(2)
($000s)
NPV 5%(2)
($000s)
NPV 10%(2)
($000s)
49,580
1,066
82,065
132,711
59,462
67,070
199,781
885
2
1,725
2,612
1,057
2,300
4,912
2,550
24
5,797
8,371
3,049
3,812
12,183
11,698
204
21,200
33,101
14,017
17,291
50,392
119,994
1,756
302,220
423,970
163,359
321,029
744,999
136,554
128,517
1,509
193,014
331,078
162,738
193,091
524,168
1,329
130,575
260,421
146,541
130,210
390,631
(1Tables may not add due to rounding.
(2NPV 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 Insite's pricing assumptions.
(3)Total company interest reserve volumes presented above and in the remainder of this Annual Report are presented as the Company's total working interest before the deduction of royalties
(but after including any royalty interests of Petrus).
In 2021, Petrus’ development program generated proved developed producing ("PDP") reserve volume additions of 3.0 mmboe. The
Company produced 2.2 mmboe and had dispositions of 1.3 mmboe of PDP reserves. The Company ended the year with 11.7 mmboe of PDP
reserves (29% crude oil and liquids).
Petrus ended 2021 with $129.9 million, $260.4 million and $390.6 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 2021 Insite Report. In 2021, the Company realized
Finding, Development and Acquisition (“FD&A”) costs of $15.64/boe for PDP reserves.
Based on the 2021 Insite Report, the Company’s PDP reserve value before-tax, discounted at 10% is $1.33 per share (96,707,912 basic
common shares outstanding at December 31, 2021). On the same basis, the P+P reserve value before tax, discounted at 10%, is $4.04 per
share.
Page |4
FUTURE DEVELOPMENT COST
Future Development Cost ("FDC") reflects Insite'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 2021 Insite Report:
Future Development Cost ($000s)
2022
2023
2024
2025
2026
Total FDC, Undiscounted
Total FDC, Discounted at 10%
Total Proved
Total Proved + Probable
49,560
68,890
68,752
40,854
5,629
233,684
194,687
49,560
76,030
68,752
82,203
66,942
343,489
270,860
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2017 to 2021(3):
December 31, 2021
December 31, 2020
December 31, 2019
December 31, 2018
December 31, 2017
Proved Producing
FD&A ($/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 ($000s)
Total Proved + Probable
FD&A ($/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)
15.64
8.90
5.4
1.4
1.6
14.54
8.53
5.5
1.4
1.7
10.51
9.24
15.3
5.1
2.3
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)
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
1.1
1
233,684
156,815
174,027
194,757
182,086
10.57
8.36
23.3
6.4
2.3
0.37
0.37
17.7
(1.3)
33.7
(7.32)
190.21
15.4
—
(2.1)
6.49
5.15
17.1
1.5
2.4
14.87
17.28
12.3
1.7
1.0
343,489
252,335
267,652
290,876
283,030
(1)Refer to "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.
(2)Certain changes in FD&A costs and F&D costs produce non-meaningful figures as discussed in "Oil and Gas Disclosures" in the Management's Discussion & Analysis attached hereto.
While FD&A costs and F&D costs, reserve life index, reserve replacement ratio and FD&A recycle ratio 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 |5
NET ASSET VALUE
The following table shows the Company's Net Asset Value ("NAV"), calculated using the 2021 Insite Report and Insite's December 31, 2021
price forecast:
As at December 31, 2021 ($000s except per share)
Present Value Reserves, before tax (discounted at 10%) (1)
Undeveloped Land Value (2)
Net Debt (3)
Net Asset Value
Fully Diluted Shares Outstanding
Estimated Net Asset Value per Share
Proved Developed
Producing
Total Proved
Proved + Probable
128,517
35,634
(61,779)
102,372
103,889
$0.99
260,421
35,634
(61,779)
234,276
103,889
$2.26
390,631
35,634
(61,779)
364,486
103,889
$3.51
(1)Based on the 2021 Insite Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company's December 31, 2021 audited consolidated financial statements.
(3)See "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto.
Page |6
MANAGEMENT'S DISCUSSION & ANALYSIS
December 31, 2021
MANAGEMENT’S DISCUSSION & ANALYSIS
The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus"
or the "Company") as at and for the year ended December 31, 2021. This MD&A is dated March 2, 2022 and should be read in
conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2021 and 2020. The
Company’s consolidated financial statements are prepared in accordance with Canadian generally accepted accounting principles ("GAAP")
which require publicly accountable enterprises to prepare their financial statements using International Financial Reporting Standards
("IFRS"). Readers are directed to the "Advisories" section at the end of this MD&A regarding forward-looking statements and boe
presentation and to the section "Non-GAAP and Other Financial Measures" herein.
The principal undertaking of Petrus is the investment in energy assets. The operations of the Company consist of the acquisition,
development, exploration and exploitation of these assets. The Company’s head office is located at 2400, 240 - 4th Avenue SW, Calgary,
Alberta, Canada. Additional information on Petrus, including the most recently filed Annual Information Form ("AIF"), are available under
the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedar.com.
Page |8
SELECTED FINANCIAL INFORMATION
OPERATIONS
Average production
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Total (boe)
Light oil weighting
Realized Prices
Natural gas ($/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 (cash)
General & administrative expense
Cash finance expense
Decommissioning expenditures
Funds flow & corporate netback(2)
($/boe)
FINANCIAL (000s except $ per share)
Oil and natural gas revenue
Net income (loss)
Net income (loss) per share
Basic
Fully diluted
Funds flow
Funds flow per share
Basic
Fully diluted
Capital expenditures
Weighted average shares outstanding
Basic
Fully diluted
As at period 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, 2021
Dec. 31, 2020
Dec. 31, 2021
Sept. 30, 2021
Jun. 30, 2021
Mar. 31, 2021
23,680
1,019
1,043
6,009
27,640
1,021
980
6,608
23,494
1,002
962
5,880
23,942
937
1,010
5,937
24,291
1,214
1,046
6,309
22,985
923
1,158
5,912
2,193,432
2,418,259
540,924
546,227
574,084
532,099
17 %
15 %
20 %
21 %
19 %
15 %
4.03
78.82
44.09
36.90
0.14
(4.72)
32.32
(5.89)
(1.79)
24.64
(5.34)
0.49
(1.95)
(2.34)
(0.31)
15.19
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
5.45
89.71
56.35
46.29
0.06
(6.34)
40.01
(5.02)
(1.87)
33.12
(9.52)
0.04
(2.24)
(1.58)
(0.56)
19.26
4.04
82.56
45.10
37.00
0.18
(3.94)
33.24
(5.57)
(1.81)
25.86
(6.41)
0.02
(1.47)
(3.30)
(0.27)
14.43
3.28
75.99
39.76
33.87
0.19
(4.87)
29.19
(6.80)
(1.84)
20.55
(3.21)
1.77
(2.41)
(2.52)
(0.14)
14.04
3.33
66.61
36.79
30.55
0.15
(3.74)
26.96
(6.12)
(1.62)
19.22
(2.28)
0.04
(1.65)
(1.93)
(0.27)
13.13
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2021
Sept. 30, 2021
Jun. 30, 2021
Mar. 31, 2021
81,268
114,556
1.83
1.76
33,354
0.53
0.51
26,916
62,557
65,207
96,708
103,889
290,492
42,172
61,779
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
25,070
114,633
1.19
1.11
10,418
0.11
0.10
12,235
96,660
102,868
96,708
103,889
290,492
42,172
61,779
20,306
7,343
0.04
0.03
7,874
0.15
0.14
6,101
54,167
57,638
96,603
100,074
173,101
40,200
60,071
19,553
(4,265)
(0.09)
(0.09)
8,070
0.16
0.16
663
49,513
49,513
49,559
49,559
176,629
40,838
110,346
16,339
(3,155)
(0.06)
(0.06)
6,993
0.14
0.14
7,917
49,469
49,469
49,469
49,469
177,587
42,028
116,634
(1) Non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures".
(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. Refer to "Non-GAAP and
Other Financial Measures".
Page |9
OPERATIONS UPDATE
Fourth quarter average production by area was as follows:
For the three months ended
December 31, 2021
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Ferrier
North Ferrier
Foothills
Central Alberta
Kakwa
Total
16,288
560
799
4,073
1,194
40
26
265
1,405
109
5
347
4,415
257
132
1,126
163
37
4
69
23,465
1,003
966
5,880
Fourth quarter 2021 production averaged 5,880 boe/d compared to 5,937 boe/d in the previous quarter. Three gross (3.0 net) wells were
drilled with one well brought on production late in the quarter adding 114 boe/d to the fourth quarter average, which offset natural
declines. Production was relatively consistent quarter over quarter.
CAPITAL EXPENDITURES
Capital expenditures (net of dispositions) totaled $12.2 million in the fourth quarter of 2021, compared to $2.8 million in the prior year
comparative period. Fourth quarter 2021 capital spending was largely directed toward the drilling, completion and tie-in of three gross (3.0
net) wells in the Ferrier and North Ferrier areas.
Capital expenditures (net of dispositions) totaled $26.9 million in the year ended December 31, 2021, compared to $14.3 million in 2020.
The increase from the prior year is attributed to the Company's increased drilling as commodity prices continued to rise.
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 and facilities
Geological
Land and lease
Dispositions
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
10,769
1,104
—
25
—
337
12,235
3 (3.0)
1,585
777
—
57
—
378
2,797
1 (1.0)
21,882
3,918
—
274
(99)
941
26,916
10 (6.4)
11,477
1,612
—
92
—
1,117
14,298
4 (3.2)
Page |10
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, 2021
Dec. 31, 2020
Dec. 31, 2021
Sept. 30, 2021
Jun. 30, 2021
Mar. 31, 2021
23,680
1,019
1,043
6,009
27,640
1,021
980
6,608
23,494
1,002
962
5,880
23,942
937
1,010
5,937
24,291
1,214
1,046
6,309
22,985
923
1,158
5,912
2,193,432
2,418,259
540,924
546,227
574,084
532,099
34,833
29,322
16,793
320
81,268
4.03
78.82
44.09
36.90
(5.34)
31.56
26,023
16,493
7,472
380
50,368
2.57
44.14
20.84
20.67
2.70
23.37
11,781
8,273
4,985
31
25,070
5.45
89.71
56.35
46.29
8,902
7,120
4,188
96
20,306
4.04
82.56
45.10
37.00
7,261
8,397
3,784
111
19,553
3.28
75.99
39.76
33.87
(9.52)
(6.41)
(3.21)
36.77
30.59
30.66
6,889
5,532
3,836
82
16,339
3.33
66.61
36.79
30.55
(2.28)
28.27
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2021
Dec. 31, 2020
Dec. 31, 2021
Sept. 30, 2021
Jun. 30, 2021
Mar. 31, 2021
3.43
3.38
2.09
2.12
4.41
4.68
3.41
3.36
2.93
2.70
2.98
2.77
80.48
45.69
92.97
84.17
76.16
68.62
43.10
49.39
0.79
17.94
23.23
0.75
54.81
81.90
0.79
47.04
55.58
0.79
34.86
34.02
0.81
35.74
26.04
0.79
Page |11
FUNDS FLOW AND NET INCOME (LOSS)
Petrus generated funds flow of $10.4 million in the fourth quarter of 2021 compared to $6.4 million in the fourth quarter of 2020. The 62%
increase is due to higher commodity prices. In the fourth quarter of 2021 Petrus' total realized price was $46.29/boe compared to $24.05/
boe in the fourth quarter of 2020.
For the year ended December 31, 2021, Petrus generated funds flow of $33.4 million compared to $26.4 million in the prior year. The 27%
increase is due to higher commodity prices partially offset by realized hedging losses.
Petrus reported net income of $114.6 million in the fourth quarter of 2021, compared to a net loss of $0.2 million in the fourth quarter of
2020. The net income in the fourth quarter of 2021 compared to the net loss in the fourth quarter of 2020 is primarily due to the net
impairment reversal of $103.2 million recorded in the fourth quarter of 2021 as well as improved commodity prices after depressed pricing
in 2020 due to the ongoing COVID-19 pandemic.
On a twelve month basis, the Company generated net income of $114.6 million for the year ended December 31, 2021 compared to a net
loss of $97.6 million for the year ended December 31, 2020. The year over year change is due to the $98.0 million impairment loss booked
during the first quarter of 2020 and the net impairment reversal of $103.2 million recorded in 2021.
($000s except per share)
Funds flow
Funds flow per share - basic
Funds flow per share - fully diluted
Net income (loss)
Net income (loss) per share - basic
Net income (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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
10,418
0.11
0.10
114,633
1.19
1.11
96,708
103,889
96,660
102,868
6,424
0.13
0.13
(151)
—
—
49,469
49,469
49,469
49,469
33,354
0.53
0.51
114,556
1.83
1.76
96,708
103,889
62,557
65,207
26,397
0.53
0.53
(97,554)
(1.97)
(1.97)
49,469
49,469
49,469
49,469
OIL AND NATURAL GAS REVENUE
Fourth quarter average production in 2021 was 5,880 boe/d (67% natural gas), 8% lower than the fourth quarter of 2020 (6,357 boe/d; 69%
natural gas). Fourth quarter oil and natural gas revenue in 2021 was $25.1 million compared to $14.1 million in 2020. The 77% increase is
due to significantly higher commodity prices.
Average production for the year ended December 31, 2021 was 6,009 boe/d (66% natural gas), 9% lower than 2020 (6,608 boe/d; 70%
natural gas). Total oil and natural gas revenue increased from $50.4 million in 2020 to $81.3 million in 2021 due to the higher commodity
prices.
The following table presents oil and natural gas revenue by product and the change from the prior comparative periods:
Oil and Natural Gas Revenue ($000s)
Natural gas
Crude oil and condensate
Natural gas liquids
Royalty income
Total oil and natural gas revenue
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2021
December 31, 2020
% Change
December 31, 2021
December 31, 2020
% Change
11,781
8,273
4,985
31
25,070
7,395
4,475
2,195
78
14,143
59 %
85 %
127 %
(60) %
77 %
34,833
29,322
16,793
320
81,268
26,023
16,493
7,472
380
50,368
34 %
78 %
125 %
(16) %
61 %
Page |12
The following table provides the average benchmark and the Company's average realized commodity prices:
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2021
December 31, 2020
% Change
December 31, 2021
December 31, 2020
% Change
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil
Mixed Sweet Blend Edm (C$/bbl)
Natural gas liquids
Propane Conway (US$/bbl)
Butane Edmonton (C$/bbl)
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total average realized price
4.41
4.68
92.97
43.10
49.39
5.45
89.71
56.35
46.29
2.50
2.62
76 %
79 %
49.34
88 %
25.50
19.32
3.07
49.64
23.52
24.05
69 %
156 %
78 %
81 %
140 %
92 %
3.43
3.38
80.48
35.28
30.03
4.03
78.82
44.09
36.90
2.09
2.12
64 %
59 %
45.69
76 %
17.94
23.23
2.57
44.14
20.84
20.67
97 %
29 %
57 %
79 %
112 %
79 %
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
67 %
17 %
16 %
100 %
69 %
15 %
16 %
100 %
66 %
17 %
17 %
100 %
70 %
15 %
15 %
100 %
Natural gas
Natural gas revenue for the year ended December 31, 2021 was $34.8 million, which increased 34% from the prior year ($26.0 million),
despite lower natural gas production. The average realized natural gas price for the year ended December 31, 2021 increased 57% to
$4.03/mcf from the prior year ($2.57/mcf). Natural gas revenue accounted for 43% of oil and natural gas revenue in 2021, compared to
52% in the prior year.
Fourth quarter 2021 natural gas revenue was $11.8 million, which increased 59% from the prior year comparative period ($7.4 million). The
average realized natural gas price in the fourth quarter of 2021 was $5.45/mcf, compared to $3.07/mcf in the fourth quarter of 2020 (78%
increase). Natural gas revenue accounted for 47% of oil and natural gas revenue in the fourth quarter of 2021, compared to 53% in the prior
year comparative period.
The increase in natural gas revenue for the fourth quarter and the year ended December 31, 2021, compared to the same periods in 2020,
was due to the increase in natural gas pricing (AECO 5A) of 76% and 64%, respectively.
Crude oil and condensate
Oil and condensate revenue for the year ended December 31, 2021 was $29.3 million, which increased 78% from the prior year ($16.5
million). The average realized oil and condensate price for the year ended December 31, 2021 increased 79% to $78.82/bbl from the prior
year ($44.14/bbl). Oil and condensate revenue accounted for 36% of oil and natural gas revenue in 2021, compared to 33% in the prior
year.
Fourth quarter 2021 oil and condensate revenue was $8.3 million, which increased 85% from the prior year comparative period ($4.5
million). The average realized oil and condensate price was $89.71/bbl for the fourth quarter of 2021 compared to $49.64/bbl in the fourth
quarter of 2020 (81% increase). Oil and condensate revenue accounted for 33% of oil and natural gas revenue in the fourth quarter of 2021,
compared to 32% in the prior year comparative period.
The increase in oil and condensate revenue is attributed to the rising oil prices in the current quarter and twelve month period as prices
continue to recover from the low pricing seen during 2020 due to the effects of the COVID-19 global pandemic.
Page |13
Natural gas liquids (NGLs)
NGL revenue for the year ended December 31, 2021 was $16.8 million, which increased 125% from the prior year ($7.5 million). The
average realized NGL price for the year ended December 31, 2021 increased 112% to $44.09/bbl from the prior year ($20.84/bbl). NGL
revenue accounted for 21% of oil and natural gas revenue, compared to 15% in the prior year.
Fourth quarter 2021 NGL revenue was $5.0 million, which increased 127% from the prior year comparative period ($2.2 million). The
average realized NGL price was $56.35/bbl for the fourth quarter of 2021 compared to $23.52/bbl in the fourth quarter of 2020. The 140%
increase is attributed to higher contract prices for NGL products, especially butane and propane. Fourth quarter market pricing for propane
at Conway increased 69% from the prior year. Petrus' butane production is priced as a function of WTI (oil) which also increased in the
fourth quarter compared to the prior year. NGL revenue accounted for 20% of oil and natural gas revenue in the fourth quarter of 2021,
compared to 16% in the prior year comparative period.
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.
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
1,941
8 %
1,487
3,428
443
3 %
738
1,181
5,797
7 %
4,564
10,361
1,785
4 %
3,409
5,194
Fourth quarter royalty expense increased from $1.2 million in 2020 to $3.4 million in 2021. On a twelve month basis, total royalty expense
(net of royalty allowances and incentives) increased from $5.2 million in 2020 to $10.4 million in 2021. The increase in royalties for the
fourth quarter and the year ended December 31, 2021 is due to higher revenue (as a result of increased commodity prices).
Gross overriding royalties increased from $0.7 million in the fourth quarter of 2020 to $1.5 million in the fourth quarter of 2021, due to
higher revenue and commodity prices. Gross overriding royalties increased from $3.4 million for the year ended December 31, 2020 to $4.6
million for the year ended December 31, 2021 due to higher revenue (as a result of increased commodity prices).
OTHER INCOME
During the year ended December 31, 2021 the Company recorded $1.4 million as other income. $1.0 million was recorded in the second
quarter of 2021 and related to the settlement of an outstanding dispute associated with the transportation and marketing of the
Company's Ferrier area condensate volume. The remaining $0.4 million is related to a government grant for decommissioning activities
provided to Petrus during the second quarter of 2021.
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 settled 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 at the end of 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.
Page |14
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
Realized hedging gain (loss)
Unrealized hedging gain (loss)
Net gain (loss) on derivatives
(5,148)
6,064
916
381
491
872
(11,713)
(2,408)
(14,121)
6,518
1,661
8,179
In the fourth quarter of 2021, the Company recognized a realized hedging loss of $5.1 million compared to a gain of $0.4 million in the
fourth quarter of 2020. The realized loss in the fourth quarter of 2021 decreased the Company’s corporate netback by $9.52/boe,
compared to an increase of $0.65/boe in 2020. The Company recognized a realized hedging loss of $11.7 million during the year ended
December 31, 2021, in comparison to the $6.5 million gain realized in 2020. The realized loss for the three and twelve months ended
December 31, 2021 was due to higher commodity prices (relative to the respective contracts settled).
During the fourth quarter of 2021, the Company recognized an unrealized gain of $6.1 million compared to an unrealized gain of $0.5
million in the fourth quarter of 2020. The Company recognized an unrealized hedging loss of $2.4 million for the year ended December 31,
2021 compared to an unrealized gain of $1.7 million for the year ended December 31, 2020. The loss represents the change in the
unrealized risk management net liability position during the year ended December 31, 2021. This change is a result of changes related to
contracts entered into and contracts settled during the period as well as changes in value of existing contracts due to changes in commodity
prices.
The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for
2022 and 2023. The Company endeavors to hedge approximately half of its forecast production for the following year, and approximately
30% of its forecast production for the subsequent year. The Company's hedging strategy is intended to provide stability and sustainability
to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk management contracts is included
in note 10 of the Company’s annual consolidated financial statements as at and for the year ended December 31, 2021. The table below
summarizes Petrus’ average crude oil and natural gas hedged volumes. The 12,333 GJ/day of average natural gas hedged for the remainder
of 2021 represents 55% of fourth quarter 2021 average natural gas production.
The following table summarizes the average and minimum and maximum cap and floor prices for the 2022 to 2023 oil and natural gas
contracts outstanding as at the date of this report:
Q4
Avg.(1)
Q1
Q2
2023
Q3
Q4
Avg.(1)
Oil hedged (bbl/d)
Avg. WTI cap price ($C/bbl)
Avg. WTI floor price ($C/bbl)
Q1
Q2
800
70.95
70.95
2022
Q3
—
—
—
—
—
—
—
—
—
200
70.95
70.95
—
—
—
Natural gas hedged (GJ/d)
12,000
13,000
13,000
11,000
12,250
10,000
Avg. AECO 7A cap price ($C/GJ)
Avg. AECO 7A floor price ($C/GJ)
2.96
2.96
3.44
3.44
3.44
3.44
3.67
3.67
3.37
3.37
3.78
3.78
(1)The volumes and prices reported are the weighted average volumes and prices for the period.
OPERATING EXPENSE
The following table shows the Company’s operating expense for the reporting periods shown:
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,500
3.78
3.78
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
2,853
631
3,484
(247)
3,237
5.53
11,134
2,719
13,853
(939)
12,914
5.89
9,673
2,463
12,136
(913)
11,223
4.64
2,182
745
2,927
(212)
2,715
5.02
Page |15
For the three months ended December 31, 2021, net operating expense totaled $2.7 million, a 16% decrease from $3.2 million during the
prior year comparative period. On a per boe basis, net operating expense was 9% lower at $5.02/boe in the fourth quarter of 2021
compared to $5.53/boe in 2020 which is due to increased fixed and variable cost efficiencies.
For the year ended December 31, 2021, net operating expense totaled $12.9 million, a 15% increase from the $11.2 million incurred in the
prior year comparative period.
The increase in operating expense for the year ended December 31, 2021 is due to a number of factors, the most significant, in order of
value, are: lower cost recoveries (on a percentage to total gross operating expense basis); higher power prices; a one-time billing
adjustment for prior year non-operated gas processing fees; and higher property tax and regulatory fees that were deferred or reduced in
2020 as a result of the COVID-19 pandemic relief.
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
1,010
1.87
983
1.68
3,920
1.79
3,452
1.43
Petrus pays commodity and demand charges for transporting its gas on pipeline systems. The Company also incurs trucking costs on the
portion of its oil and natural gas liquids production that is not pipeline connected. For the three months ended December 31, 2021
transportation expense was $1.0 million or $1.87/boe compared to $1.0 million or $1.68/boe in the prior year comparative period. On a
twelve month basis, transportation expense totaled $3.9 million, or $1.79/boe for 2021, which is 11% and 25% higher, respectively, than
the $3.5 million of costs incurred (or $1.43/boe) in the prior year. The increase in transportation expense is attributed to the pipeline firm
transportation contract that began at the end of the second quarter of 2020.
GENERAL AND ADMINISTRATIVE EXPENSE
The following table illustrates the Company’s general and administrative ("G&A") expense which is shown net of capitalized costs directly
related to exploration and development activities:
General and Administrative Expense ($000s)
Personnel, consultants and directors
Administrative expenses
Regulatory and professional expenses
Gross general and administrative expenses
Capitalized general and administrative expenses
Overhead recoveries
General and administrative expenses
General and administrative expense ($/boe)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2021
December 31, 2020
December 31, 2021
December 31, 2020
1,070
491
112
1,673
(289)
(171)
1,213
2.24
1,039
300
326
1,665
(378)
(228)
1,059
1.81
3,529
1,613
688
5,830
(878)
(678)
4,274
1.95
3,028
1,102
1,118
5,248
(1,117)
(722)
3,409
1.41
G&A expense (net of capitalized G&A expense and overhead recoveries) for the fourth quarter of 2021 totaled $1.2 million or $2.24/boe,
compared to $1.1 million or $1.81/boe in the fourth quarter of 2020. Gross G&A expense (before capitalized G&A expense and overhead
recoveries) was consistent with the the prior year ($1.7 million in the fourth quarter of 2021 compared to $1.7 million in the fourth quarter
of 2020) due to lower staffing costs and regulatory expenses.
For the year ended December 31, 2021, gross G&A expense was $5.8 million compared to $5.2 million in the prior year, which represents a
6% increase. Net G&A expense for the year ended December 31, 2021, was $4.3 million or $1.95/boe which is higher than the $3.4 million
or $1.41/boe for the prior year comparative period (38% increase on a per boe basis).
The net and gross increases in G&A are attributed to one-time expenses related to management changes and lower wage subsidy from the
federal government during 2021.
Page |16
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
164
(48)
116
163
(20)
143
355
(96)
259
483
(102)
381
Share-based compensation expense (net of capitalized portion) was $0.12 million for the fourth quarter of 2021, which is 20% lower than
the $0.14 million recognized in the fourth quarter of the prior year. For the year ended December 31, 2021, net share-based compensation
expense was $0.26 million, which is 32% lower than the $0.38 million in the prior year comparative period. The decrease in stock based
compensation expense for the current period and year-end compared to the prior year comparative periods is due to options fully vesting
during 2020 and the deferral of new option grants until late 2021.
FINANCE EXPENSE
The following table illustrates the Company’s finance expense which includes cash and non-cash expenses:
Finance Expense ($000s)
Interest expense
Finance fees
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
811
45
61
—
198
1,115
1,081
375
145
936
107
2,644
4,108
1,025
365
2,573
707
8,778
5,738
923
625
1,813
494
9,593
Fourth quarter total finance expense was $1.1 million in 2021, comprised of $0.2 million of non-cash accretion of its decommissioning
obligations, $0.8 million of cash interest expense and $0.05 million of finance fees. In the fourth quarter of 2020, the Company incurred
total finance expense of $2.6 million, comprised of $0.1 million in non-cash accretion of its decommissioning obligation, $1.1 million cash
interest expense, $0.4 million of finance fees, $0.9 million of non-cash term loan interest payment-in-kind related to the second lien term
loan and $0.1 million of deferred financing fee amortization.
The Company incurred total finance expense of $8.8 million for the year ended December 31, 2021, which is lower than the $9.6 million for
the prior year.
The decreases in total finance expense are due to a lower first lien loan balance and elimination of the second lien term loan during the
year.
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
5,508
10.18
6,121
10.47
22,992
10.48
25,231
10.43
Depletion and depreciation expense is calculated on a unit-of-production (boe) basis. This fluctuates period to period primarily as a result of
changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including
future development cost. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus
probable reserve base.
Petrus recorded depletion and depreciation expense in the fourth quarter of 2021 of $5.5 million or $10.18/boe, compared to the fourth
quarter of 2020, when $6.1 million or $10.47/boe was recorded. The decrease in the depletion expense for the fourth quarter of 2021
compared to the fourth quarter of 2020 was primarily due to lower production in 2021.
Page |17
For the year ended December 31, 2021, the Company recorded $23.0 million or $10.48/boe, compared to $25.2 million or $10.43 per boe
for the prior year comparative period. The decrease in total depletion and depreciation expense is attributed to lower production during
2021.
IMPAIRMENT (REVERSAL)
The following table illustrates impairment losses and reversals recorded in the reporting periods shown:
Impairment (Reversal) ($000s)
Impairment (reversal)
Total
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2021
December 31, 2020
December 31, 2021
December 31, 2020
(103,220)
(103,220)
—
—
(103,220)
(103,220)
98,000
98,000
During 2021, Petrus recorded an impairment reversal of $106.9 million in its Ferrier CGU due to the significant increase in forward
benchmark commodity prices at December 31, 2021 compared to December 31, 2020. In addition, Petrus also recognized an impairment
loss of $3.7 million in its Kakwa CGU. The impairment reversal was allocated to PP&E ($80.6 million) and E&E ($22.6 million). The $103.2
million net amount of the impairment reversal was recorded in the Consolidated Statements of Net Income (Loss) and Comprehensive
Income (Loss). For more information, refer to notes 5 and 6 of the December 31, 2021 audited consolidated financial statements.
Petrus recognized an impairment loss of $98.0 million in the Ferrier CGU during the year ended December 31, 2020, due to the significant
decrease in forward benchmark commodity prices at March 31, 2020 compared to December 31, 2019. For more information, refer to
notes 5 and 6 of the December 31, 2021 audited consolidated financial statements.
SHARE CAPITAL
The Company's authorized share capital consists of an unlimited number of common shares and an unlimited number of preferred shares.
The Company has not issued any preferred shares. The following table details the number of issued and outstanding securities for the
periods shown:
Share Capital (000s)
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, 2021
December 31, 2020
December 31, 2021
December 31, 2020
96,660
102,868
96,708
103,889
5,563
49,469
49,469
49,469
49,469
2,277
62,557
65,207
96,708
103,889
5,563
49,469
49,469
49,469
49,469
2,277
At December 31, 2021, the Company had 96,707,912 common shares and 5,562,549 stock options outstanding.
During the third quarter of 2021, the Company completed a private placement financing of an aggregate of $10 million of common shares
at an issue price of $0.55 per share. All proceeds from the equity financing were applied to outstanding indebtedness under the Company's
first lien loan. Prior to September 30, 2021, Petrus had a second debt instrument, a subordinated secured term loan (the "Term Loan").
During the third quarter of 2021, the Company settled the Term Loan with a principal amount (carrying value) of $39.4 million in
consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus to the holders of the Term Loan at an
issue price of $0.55 per share. The difference between the loan amount and the value of the shares was recorded as contributed surplus.
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, 2021, 1,618,702 DSUs were issued and outstanding (December 31, 2020 – 2,158,270). Each DSU entitles the participants to
receive, at the Company's discretion, either common shares or a cash equivalent to the number of DSUs multiplied by the current trading
price of the equivalent number of common shares. All DSUs vest and become payable upon retirement of the director. The DSUs are
included as equity as the company does not intend to settle the DSUs for cash.
Page |18
LIQUIDITY AND CAPITAL RESOURCES
Petrus has one debt instrument outstanding; a reserve-based, senior secured revolving credit facility with a syndicate of lenders, which is
comprised of an operating facility and a syndicated facility (together, the “Revolving Credit Facility” or “RCF”).
Revolving Credit Facility
At December 31, 2021 the RCF was comprised of a $18.6 million operating facility and a $43.4 million syndicated facility with a maturity
date of May 31, 2022. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the
Company.
At December 31, 2021, the Company had a $0.6 million letter of credit outstanding against the RCF (December 31, 2020 – $0.6 million) and
had drawn $57.7 million against the RCF (December 31, 2020 – $77.5 million).
The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on reserves
and commodity prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous lender consent.
A decrease in the borrowing base could result in a reduction to the available credit under the RCF. During the fourth quarter of 2021, the
syndicate of lenders reconfirmed the Company's borrowing base of $64.8 million, which was reduced by $2.75 million on December 31,
2021 and will be reduced by a further $5.0 million on March 31, 2022. In addition, Petrus and the lenders under the RCF have agreed to a
cash sweep provision under which 75% of excess cash flow will be used to accelerate repayment of the Company's RCF. The next scheduled
borrowing base redetermination date for the RCF is on or before May 31, 2022.
Debt Settlement - Term Loan
During 2021, Petrus had a second debt instrument, a subordinated the "Term Loan". During the third quarter of 2021, the Company settled
the Term Loan with a principal amount of $39.4 million in consideration for the issuance of $15.8 million of common shares of Petrus to the
holders of the Term Loan at an issue price of $0.55 per share.
Liquidity
At December 31, 2021, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $62.0
million due to the classification of the Company's borrowings under its RCF as a current liability. The Company's RCF's maturity date is May
31, 2022. The Company requires an extension or refinancing of its RCF. The borrowings under the RCF are classified as current liabilities in
the December 31, 2021 audited consolidated financial statements, which has no impact on the debt covenants and the Company remains in
compliance with each of its covenants. However, the reclassification of the debt instruments resulted in a working capital deficit of $62.0
million as of December 31, 2021. For the year ended December 31, 2021 the Company generated funds flow of $33.4 million and reduced
its debt $56.3 million from December 31, 2020. Management is actively seeking alternative debt or equity financing to refinance the RCF
prior to May 31, 2022. 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 under its RCF during the subsequent 12 month
period.
Financial Covenants
The Company's RCF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the RCF:
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 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.
Page |19
Contractual Maturities
The following are the contractual maturities of financial liabilities as at December 31, 2021:
$000s
Accounts payable and accrued liabilities
Risk management liability
Current portion of long term debt
Lease obligations
Total
Total
19,690
2,488
57,700
820
80,698
< 1 year
19,690
2,488
57,700
217
80,095
Commitments
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
13,197
< 1 year
2,465
1-5 years
10,392
1-5 years
—
—
—
603
603
> 5 years
340
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, 2021 audited consolidated
financial statements.
Page |20
SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)
Dec. 31,
2021
Sept. 30,
2021
Jun. 30,
2021
Mar. 31,
2021
Dec. 31,
2020
Sept. 30,
2020
Jun. 30,
2020
Mar. 31,
2020
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
Net oil and natural gas revenue
Transportation expense
Operating expense
Operating netback(1)
Realized gain (loss) on derivatives
Other income (cash)
General and administrative expense
Cash finance expense
Decommissioning expenditures
Corporate netback and funds flow(2)
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)
23,494
23,942
24,291
22,985
26,177
26,181
27,630
30,604
1,002
962
5,880
937
1,010
5,937
1,214
1,046
6,309
923
1,158
5,912
980
1,014
6,357
1,103
997
867
819
6,463
6,291
1,134
1,088
7,323
540,924
546,227
574,084
532,099
584,860
594,599
572,440
666,361
25,070
20,306
19,553
16,339
14,143
12,840
9,041
14,344
(3,429)
(2,150)
(2,794)
(1,989)
(1,183)
(1,245)
(867)
(1,899)
21,641
18,156
16,759
14,350
12,960
11,595
8,174
12,445
(1,010)
(991)
(1,057)
(863)
(983)
(967)
(799)
(703)
(2,715)
(3,042)
(3,903)
(3,254)
(3,237)
(2,408)
(2,543)
(3,035)
17,916
14,123
11,799
10,233
8,740
8,220
4,832
(5,148)
(3,504)
(1,843)
(1,215)
21
12
1,018
23
381
184
1,308
3,656
23
99
8,707
1,174
48
(1,213)
(804)
(1,381)
(876)
(1,059)
(635)
(817)
(898)
(856)
(1,803)
(1,444)
(1,029)
(1,456)
(1,286)
(1,831)
(2,089)
(302)
(150)
(79)
(143)
(366)
(79)
(84)
(376)
10,418
7,874
8,070
6,993
6,424
7,551
5,855
6,566
25,070
20,306
19,553
16,339
14,143
12,840
9,041
14,344
0.26
0.24
0.37
0.35
0.39
0.39
0.33
0.33
0.29
0.29
0.26
0.26
0.18
0.18
0.29
0.29
114,633
7,343
(4,265)
(3,155)
(151)
(3,678)
(6,281)
(87,444)
1.19
1.11
0.14
0.13
(0.09)
(0.06)
(0.09)
(0.06)
—
—
(0.07)
(0.13)
(0.07)
(0.13)
(1.77)
(1.77)
96,708
96,603
49,559
49,469
49,469
49,469
49,469
49,469
103,889
100,074
49,559
49,469
49,469
49,469
49,469
49,469
96,660
54,167
49,513
49,469
49,469
49,469
49,469
49,469
102,868
57,638
49,513
49,469
49,469
49,469
49,469
49,469
290,492
173,101
176,629
177,587
177,914
179,895
184,532
193,679
(61,779) (60,071) (110,346) (116,634) (114,361) (116,717) (120,570) (125,974)
(1)Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures".
(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. Refer to "Non-GAAP and
Other Financial Measures".
The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and
corporate netback are affected by commodity prices, exchange rates, Canadian commodity price differentials and production levels. Petrus’
average quarterly production has decreased from 7,323 boe/d in the first quarter of 2020 to 5,880 boe/d in the fourth quarter of 2021. The
20% production decrease is attributable to Petrus' disciplined capital program prioritizing debt repayment as well as non-operated and
third party downtime.
Page |21
SELECTED ANNUAL INFORMATION
($000s unless otherwise noted)
For the year ended,
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 avg. shares outstanding (000s)
Basic
Fully diluted
Total assets
Non-current liabilities
CRITICAL ACCOUNTING ESTIMATES
December 31, 2021
December 31, 2020
December 31, 2019
81,268
1.30
1.30
114,556
1.18
1.10
96,708
103,889
62,557
65,207
290,492
42,172
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
The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses.
Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.
Significant estimates and judgments made by management in the preparation of the financial statements are outlined below. The
Company’s critical accounting estimates can be read in note 2 to the Company’s audited consolidated financial statements as at and for the
year ended December 31, 2021.
In March 2020, the World Health Organization declared the COVID-19 outbreak a global pandemic. The rapid outbreak and subsequent
measures intended to limit the spread of COVID-19 have contributed to a significant increase in economic uncertainty, with more volatile
commodity prices, currency exchange rates and interest rates. The duration and severity of the business disruptions and reduction in
consumer activity nationally and internationally and the resulting financial effect is difficult to reliably estimate. The results of the potential
economic downturn and any potential resulting direct or indirect effect on the Company has been considered in management’s estimates
at period end; however, there could be a further prospective material effect in future periods.
OTHER FINANCIAL INFORMATION
Significant accounting policies
The Company’s significant accounting policies can be read in note 3 of the Company’s audited consolidated financial statements as at and
for the year ended December 31, 2021.
New standards and interpretations
The Company has not adopted any new standards and interpretations for the year ended December 31, 2021.
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
Page |22
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, 2021 and have concluded that the Company's DC&P are
effective at December 31, 2021 for the foregoing purposes.
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, 2021, 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. There has not been any change in Petrus' ICFR that occurred during
the period beginning on October 1, 2021 and ended on December 31, 2021 that has materially affected, or is reasonably likely to materially
affect, Petrus' ICFR.
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, 2021. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that as at December 31, 2021, 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 AND OTHER FINANCIAL MEASURES
This MD&A makes reference to the terms "operating netback", "corporate netback" and "net debt". These non-GAAP and other financial
measures 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. These non-GAAP
and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance
with IFRS as indicators of our performance. Management uses these non-GAAP and other financial measures 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 type at the oil and natural gas lease level. The most directly comparable
GAAP measure to operating netback is funds flow/oil and natural gas revenue. Operating netback is calculated as oil and natural gas
revenue less royalties and operating and transportation expenses. It is presented on an absolute value and on a per unit (boe) basis as a
non-GAAP ratio. See below and under "Summary of Quarterly Results" for a reconciliation of operating netback to oil and natural gas
revenue.
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 on a per unit (boe) basis as a non-GAAP ratio. 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.
They are calculated 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. See below and under "Summary of Quarterly Results" for a
reconciliation of funds flow and corporate netback to oil and natural gas revenue.
Page |23
Oil and natural gas revenue
Royalty expense
Net oil and natural gas revenue
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.
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2021
December 31, 2020
December 31, 2021
December 31, 2020
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
25,070
(3,429)
21,641
(1,010)
(2,715)
17,916
(5,148)
21
(1,213)
(856)
(302)
10,418
46.35
(6.34)
40.01
(1.87)
(5.02)
33.12
(9.52)
0.04
(2.24)
(1.58)
(0.56)
19.26
14,143
(1,183)
12,960
(983)
(3,237)
8,740
381
184
(1,059)
(1,456)
(366)
6,424
24.18
81,268
(2.02)
(10,361)
22.16
(1.68)
(5.53)
14.95
0.65
0.31
(1.81)
(2.49)
(0.63)
70,907
(3,920)
(12,914)
54,073
(11,713)
1,075
(4,274)
(5,133)
(674)
37.04
(4.72)
32.32
(1.79)
(5.89)
24.64
(5.34)
0.49
(1.95)
(2.34)
(0.31)
50,368
(5,194)
45,174
(3,452)
(11,223)
30,499
6,518
354
(3,409)
(6,661)
(904)
20.83
(2.15)
18.68
(1.43)
(4.64)
12.61
2.70
0.15
(1.41)
(2.75)
(0.37)
10.98
33,354
15.19
26,397
10.93
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, 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. See below for a reconciliation of net debt to long term
debt, being our nearest measure prescribed by GAAP (IFRS).
($000s)
Adjusted current assets(1)
Less: adjusted current liabilities(1)
Net debt
As at December 31, 2021
As at December 31, 2020
15,611
(77,390)
(61,779)
7,428
(121,789)
(114,361)
(1)Adjusted for unrealized risk management assets, liabilities, lease obligations and unrealized deferred share unit liabilities.
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2021, which includes disclosure of our oil and natural gas reserves and
other oil and natural gas information in accordance with NI 51-101, is contained in the AIF. The recovery and reserve estimates contained
herein are estimates only and there is no guarantee that the estimated reserves will be recovered.
Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare
Petrus' operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from
the metrics presented in this MD&A, should not be relied upon for investment or other purposes.
F&D Costs 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 costs 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.
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 |24
FD&A Recycle Ratio
The FD&A recycle ratio is calculated by dividing operating netback by FD&A.
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, 2021. The
reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise
stated.
Forward-Looking Statements
Certain information regarding Petrus set forth in this MD&A contains forward-looking statements within the meaning of applicable
securities law, that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”,
“estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking
statements. Such statements represent Petrus’ internal projections, estimates or beliefs concerning, among other things, an outlook on the
estimated amounts and timing of capital investment, anticipated future debt, production, revenues or other expectations, beliefs, plans,
objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual
events or results may differ materially. Although Petrus believes that the expectations reflected in the forward-looking statements are
reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently
subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Petrus’
actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus.
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: prospective
changes to the terms of the RCF and Term Loan; Petrus' capital program, flexibility and utilization of free cash flow; Petrus' utilization of
Federal and Provincial programs; Petrus' expectations regarding 2022 production volumes; Petrus' ability to modify its operations, including
its ability to adjust liquid volumes and the results thereof; expectations regarding the adequacy of Petrus' liquidity and the funding of its
financial liabilities; the impact of the current economic environment on Petrus; the performance characteristics of the Company's crude oil,
NGL and natural gas properties; future prospects; the focus of and timing of capital expenditures; access to debt and equity markets;
Petrus' future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future
royalty rates; drilling, development and completion plans and the results therefrom; and treatment under governmental regulatory regimes
and tax laws. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control,
including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; impact of the economic
crisis on the Company's lenders; willingness of the Company's lenders to negotiate; industry conditions; currency fluctuation; imprecision of
reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of
acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management;
changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire,
explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property
and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources;
completion of the financing on the timing planned and the receipt of applicable approvals; and the other risks. With respect to forward-
looking statements contained in this MD&A, Petrus has made assumptions regarding: future commodity prices and royalty regimes;
availability of skilled labour; timing and amount of capital expenditures; willingness of its lenders to negotiate; the impact of the current
financial crisis; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets;
availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs.
Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in
order to provide shareholders with a more complete perspective on Petrus’ future operations and such information may not be appropriate
for other purposes. Petrus’ actual results, performance or achievement could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking
statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned
that the foregoing lists of factors are not exhaustive.
This MD&A contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Petrus' prospective
results of operations including, without limitation, its ability to repay debt, which are subject to the same assumptions, risk factors,
limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information,
Page |25
although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on
FOFI. Petrus' actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any
of them do so, what benefits Petrus will derive therefrom. Petrus has included the FOFI in order to provide readers with a more complete
perspective on Petrus' future operations and such information may not be appropriate for other purposes.
These forward-looking statements and FOFI are made as of the date of this MD&A and the Company disclaims any intent or obligation to
update any forward-looking statements and FOFI, whether as a result of new information, future events or results or otherwise, other than
as required by applicable securities laws.
BOE Presentation
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“boe”) basis whereby
natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas
measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the
6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip. Boe’s do not represent an
economic value equivalence at the wellhead and therefore may be a misleading measure if used in isolation.
Abbreviations
$000’s
$/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
thousand barrel of oil equivalent
million barrel of oil equivalent
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 |26
CONSOLIDATED ANNUAL FINANCIAL STATEMENTS
As at and for the years ended December 31, 2021 and 2020
INDEPENDENT AUDITOR’S 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, 2021 and 2020, and the consolidated statements of net income (loss) and comprehensive income
(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, 2021 and 2020, and its consolidated financial performance and its consolidated cash flows
for the years then ended in accordance with International Financial Reporting Standards (IFRS).
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 refinance its debt. As stated in Note 2(a), these events or conditions indicate that a material
uncertainty exists that may cast 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 the audit of the consolidated
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 the audit of the consolidated financial statements as a whole, and in forming the auditor’s 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.
Key audit matter
How our audit addressed the key audit matter
Impairment or Impairment Reversal of Property, Plant
and Equipment (“PP&E”) and Exploration and Evaluation
(“E&E”) Assets
As at December 31, 2021, the carrying values of PP&E
and E&E assets were $239.2 million and $35.6 million
respectively. For the year ended December 31, 2021, an
impairment reversal of $106.9 million was recorded with
respect to the Ferrier cash generating unit (“CGU”),
allocated $22.6 million to E&E assets and $84.3 million
to PP&E; and an impairment charge of $3.8 million was
recorded with respect to the Kakwa CGU, allocated
entirely to PP&E. PP&E and E&E assets are tested for
impairment only when circumstances indicate that the
carrying value of a CGU may exceed its recoverable
amount and for impairment reversal when there is any
indication that previously recognized impairment losses
may no longer exist or may have decreased. Impairment
and impairment reversal is determined by estimating a
CGU’s respective recoverable amount. The recoverable
the Ferrier and Kakwa CGUs were
amounts of
determined based on their fair value less costs of
disposal (“FVLCD”), which were estimated using a
discounted cash flow approach. The Company discloses
significant judgments, estimates and assumptions in
respect of impairment in Note 3 to the consolidated
financial statements, and the results of their analysis in
Notes 5 and 6.
the estimated recoverable amount of
Auditing
the
Company’s Ferrier and Kakwa CGUs was complex due
to the subjective nature of the various management
inputs and assumptions and commodity price volatility.
The primary inputs noted in the FVLCD model were
production, pricing, royalties, operating costs, capital
costs, costs of disposal and discount rate.
Other Information
To test the Company's estimated recoverable amounts for
the Ferrier and Kakwa CGUs, we performed the following
procedures, among others:
–
–
–
–
–
–
–
in
against
production
forecasted
the various
the discount
in determining
forecasted prices used
Involved our valuation specialists to assess the
inputs
methodology applied, and
utilized
rate by
industry, economic, and
referencing current
comparable company information, company and
cash-flow specific risk premiums.
Compared
historically realized production.
the
Compared
impairment test to third-party reserve engineer
data.
Assessed forecasted royalties, operating costs 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 consolidated financial statements in
relation to this matter.
Management is responsible for the other information. The other information comprises:
a.
b.
Management’s Discussion and Analysis
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 and 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 in this
auditor’s report. 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 IFRS,
and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements
that are free from material misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a
going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless
management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditor’s Responsibilities for the Audit of the Consolidated Financial Statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from
material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance
is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing
standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered
material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on
the basis of these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and
maintain professional skepticism throughout the audit. We also:
a.
Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error,
design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to
provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one
resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of
internal control.
b. Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.
c. Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related
disclosures made by management.
d. Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit
evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the
Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw
attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s
report. However, future events or conditions may cause the Company to cease to continue as a going concern.
e. Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and
whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair
presentation.
We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and
significant audit findings, including any significant deficiencies in internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding
independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our
independence, and where applicable, related safeguards.
From the matters communicated with those charged with governance, we determine those matters that were of most significance in the
audit of the consolidated financial statements of the current period and are therefore the key audit matters. We describe these matters
in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances,
we determine that a matter should not be communicated in our report because the adverse consequences of doing so would
reasonably be expected to outweigh the public interest benefits of such communication.
The engagement partner on the audit resulting in this independent auditor’s report is Ryan MacDonald.
Calgary, Alberta
March 2, 2022
CONSOLIDATED BALANCE SHEETS
(Presented in 000’s of Canadian dollars)
As at
December 31, 2021
December 31, 2020
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 (note 5)
Property, plant and equipment (note 6)
Total assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank indebtedness
Bank loan (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
Commitments and contingencies (note 19)
Related party transactions (note 21)
Subsequent event (note 23)
See accompanying notes to the consolidated financial statements
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Chairman
4,928
950
9,733
—
15,611
—
35,634
239,247
274,881
290,492
—
57,700
19,690
2,488
217
80,095
603
41,569
—
122,267
455,908
27,846
(315,529)
168,225
290,492
—
1,150
6,278
934
8,362
15
17,568
151,969
169,552
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
(signed) “Donald Cormack”
Donald Cormack
Director
Page |31
CONSOLIDATED STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(Presented in 000’s of Canadian dollars, except per share amounts)
Year ended
Year ended
December 31, 2021
December 31, 2020
REVENUE
Oil and natural gas revenue (note 20)
Royalty expense
Net oil and natural gas revenue
Other income (note 20)
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)
Gain on sale of assets
Impairment (reversal) (notes 5 and 6)
Total expenses
INCOME (LOSS) BEFORE INCOME TAX
Income tax recovery (note 22)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
Net income (loss) per common share
Basic (note 12)
Diluted (note 12)
See accompanying notes to the consolidated financial statements
81,268
(10,361)
70,907
1,448
(14,122)
58,233
12,914
3,920
4,274
259
8,778
108
22,992
(924)
(103,220)
(50,899)
109,132
(5,424)
114,556
1.83
1.76
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)
—
(97,554)
(1.97)
(1.97)
Page |32
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Presented in 000’s of Canadian dollars)
Balance, December 31, 2019
Net loss
Share-based compensation (note 11)
Balance, December 31, 2020
Net income
Deferred Share Unit settlement (note 11)
Issuance of common shares (note 11)
Share issue costs (note 11)
Share-based compensation (note 11)
Balance, December 31, 2021
See accompanying notes to the consolidated financial statements
Share
Capital
430,119
—
—
430,119
—
—
25,900
(111)
—
455,908
Contributed
Surplus
9,112
—
484
9,596
—
(223)
18,119
—
354
27,846
Deficit
(332,531)
(97,554)
—
(430,085)
114,556
—
—
—
—
(315,529)
Total
106,700
(97,554)
484
9,630
114,556
(223)
44,019
(111)
354
168,225
Page |33
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Presented in 000’s of Canadian dollars)
OPERATING ACTIVITIES
Net income (loss)
Adjust items not affecting cash:
Share-based compensation (note 11)
Unrealized (gain) loss on financial derivatives (note 10)
Non-cash finance expenses (note 17)
Non-cash term loan interest payment-in-kind (note 17)
Depletion and depreciation (note 6)
Impairment (reversal) (notes 5 and 6)
Exploration and evaluation expense (note 5)
Gain on sale of assets (note 6)
Recovery of income taxes on debt settlement (note 7)
Other income (note 20)
Decommissioning expenditures (note 9)
Funds flow
Change in operating non-cash working capital (note 18)
Cash flows from operating activities
FINANCING ACTIVITIES
Deferred Share Unit payment (note 11)
Issuance of shares (note 11)
Repayment of revolving credit facility
Drawing (repayment) of bank indebtedness
Repayment of lease liabilities (note 8)
Change in financing non-cash working capital (note 18)
Cash flows used in financing activities
INVESTING ACTIVITIES
Property and equipment dispositions (note 6)
Exploration and evaluation asset expenditures (note 5)
Petroleum and natural gas property expenditures (note 6)
Change in investing non-cash working capital (note 18)
Cash flows used in investing activities
Increase (decrease) in cash
Cash, beginning of year
Cash, end of year
Cash interest paid (note 17)
See accompanying notes to the consolidated financial statements
Page |34
Year ended
Year ended
December 31, 2021
December 31, 2020
114,556
259
2,409
1,072
2,573
22,992
(103,220)
108
(924)
(5,424)
(373)
(674)
33,354
(366)
32,988
(30)
10,107
(19,800)
(32)
(192)
(179)
(10,126)
148
(621)
(26,550)
9,089
(17,934)
4,928
—
4,928
5,133
(97,554)
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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2021 and 2020
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, 2021 and 2020, were approved by the Company’s Audit Committee and
Board of Directors on March 2, 2022.
2. BASIS OF PRESENTATION
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, 2021, the Company's revolving credit facility ("RCF") was due on May 31, 2022. The borrowing under the RCF is classified as a current
liability in the December 31, 2021 consolidated financial statements.
The Company intends to refinance the RCF; however, there is no assurance that it will be successful in this regard, which results in 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.
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”).
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.
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.
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.
i.
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
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
Page |35
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.
ii.
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 CGUs 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.
iii.
iv.
v.
vi.
vii. Measurement of share-based compensation
Share-based compensation recorded pursuant to share-based compensation plans is subject to estimated fair values, forfeiture rates and the
future attainment of performance criteria.
viii. 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.
(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.
Page |36
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 consist 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.
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.
Page |37
The CGUs 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.
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
Page |38
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 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 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.
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.
Page |39
(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 fair value less costs of disposal 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 |40
5. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s exploration and evaluation ("E&E") assets are as follows:
$000s
Balance, December 31, 2019
Additions
Disposition
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation
Transfers to property, plant and equipment (note 6)
Impairment loss
Balance, December 31, 2020
Additions
Disposition
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation (note 11)
Impairment reversal
Transfers to property, plant and equipment (note 6)
Balance, December 31, 2021
36,116
4,590
(58)
(18)
279
26
(367)
(23,000)
17,568
401
(18)
(108)
220
24
22,640
(5,093)
35,634
During the year ended December 31, 2021, the Company incurred exploration and evaluation expense of $0.1 million which relates to expired and nearly
expired undeveloped, non-core land (year ended December 31, 2020 – $0.02 million).
During the year ended December 31, 2021, the Company capitalized $0.2 million of general and administrative expenses (“G&A”) (year ended December 31,
2020 – $0.3 million) and $0.02 million of non-cash share-based compensation directly attributable to exploration activities (year ended December 31, 2020
– $0.03 million).
During the year ended December 31, 2021, the Company transferred $5.1 million from E&E assets to PP&E assets, related to the Ferrier, North Ferrier and
Kakwa Cash Generating Units ("CGUs"), which were brought on production during the second and fourth quarters.
Due to the increase in forward benchmark commodity prices during the year ended December 31, 2021, the Company identified indicators of impairment
reversal in its Ferrier Cash Generating Unit ("CGU"). As a result, for the Ferrier CGU, the Company recorded an impairment reversal of $22.6 million on its
E&E assets, as the recoverable amount exceeded the carrying value. No impairment or impairment reversal for E&E assets was recorded on other CGUs of
the Company.
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 during the year ended December 31, 2020. 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 also tested the Ferrier CGU for impairment on December 31, 2020 and did
not record any further impairment.
Page |41
6. PROPERTY, PLANT AND EQUIPMENT
The components of the Company’s property, plant and equipment ("PP&E") assets are as follows:
$000s
Balance, December 31, 2019
Additions
Capitalized G&A
Capitalized share based compensation
Transfer from exploration and evaluation assets (note 5)
Depletion & depreciation
Increase in decommissioning expenses
Impairment provision
Balance, December 31, 2020
Additions
Property dispositions
Capitalized G&A
Capitalized share-based compensation (note 11)
Transfers from exploration and evaluation assets (note 5)
Depletion & depreciation
Changes in decommissioning provision (note 9)
Impairment reversal
Balance, December 31, 2021
Cost
821,861
8,600
838
77
367
—
3,840
—
835,583
25,593
(14,495)
658
73
5,093
—
329
—
852,834
Accumulated
DD&A
(583,383)
—
—
—
Net book value
238,478
8,600
838
77
—
(25,231)
—
(75,000)
(683,614)
—
12,439
—
—
—
(22,992)
—
80,580
(613,587)
367
(25,231)
3,840
(75,000)
151,969
25,593
(2,056)
658
73
5,093
(22,992)
329
80,580
239,247
At December 31, 2021, estimated future development costs of $343.5 million (December 31, 2020 – $252.3 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, 2021, the
Company capitalized $0.7 million of general and administrative expenses (“G&A”) (year ended December 31, 2020 – $0.8 million) and non-cash share-based
compensation of $0.07 million (year ended December 31, 2020 – $0.08 million), directly attributable to development activities.
During the year ended December 31, 2021, the Company recorded a gain of $0.4 million on the disposition of certain E&E and PP&E assets in the Foothills
CGU for cash consideration of $0.1 million and the assumption of $2.4 million of decommissioning liabilities.
During the year ended December 31, 2021, the Company transferred $5.1 million from E&E assets to PP&E assets, related to the Ferrier, North Ferrier and
Kakwa CGUs that were brought on production during the second and fourth quarters.
At December 31, 2021, in its Ferrier CGU, the Company identified indicator of impairment reversal as a result of improved commodity prices. For the Kakwa
CGU, the Company identified an indicator of impairment due to the decrease in proved and probable reserve values.
As a result of the above indicators, an impairment test on the Company’s PP&E assets was performed. For the Ferrier CGU, the Company recorded an
impairment reversal of $84.3 million on its PP&E assets on December 31, 2021, as the recoverable amount exceeded the carrying amount. The impairment
reversal amount reflects all of the original impairment charges recorded on March 31, 2020 and December 31, 2014, less associated depletion. In addition,
for the Kakwa CGU, the Company recorded an impairment charge of $3.7 million on its PP&E assets.
For the North Ferrier, Central Alberta and Foothills CGUs, the Company did not identify any indicator of impairment or impairment reversal.
The recoverable amount, a level 3 input on the fair value hierarchy, was estimated at its fair value less costs to dispose, using an after--tax discount rate of
11.6% to 13.1%. A 1% increase in the discount rate would have increased impairment by approximately $11.7 million. A 1% decrease in the discount rate
would decrease impairment by approximately $0.2 million. The Company uses the following forward commodity price estimates:
Page |42
Year
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
Canadian Light Sweet
$/Bbl
AECO $/MMbtu
86.77
81.25
78.75
80.33
81.93
83.57
85.24
86.95
88.69
90.46
92.27
3.55
3.25
3.05
3.13
3.19
3.26
3.32
3.39
3.46
3.52
3.60
Escalation rate of 2.0% thereafter.
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.
At December 31, 2021, the carrying balance of the right of use asset was $0.8 million.
During 2021, Petrus recorded minor disposition transactions for petroleum and natural gas properties and equipment for total net cash consideration of
$0.1 million.
7. DEBT
Petrus has one debt instrument outstanding; a reserve-based, senior secured revolving credit facility with a syndicate of lenders, which is comprised of an
operating facility and a syndicated facility (together, the “Revolving Credit Facility” or “RCF”).
Revolving Credit Facility
At December 31, 2021 the RCF was comprised of a $18.6 million operating facility and a $43.4 million syndicated facility with a maturity date of May 31,
2022. The Company has provided collateral by way of a debenture over all of the present and after acquired property of the Company.
At December 31, 2021, the Company had a $0.6 million letter of credit outstanding against the RCF (December 31, 2020 – $0.6 million) and had drawn $57.7
million against the RCF (December 31, 2020 – $77.5 million).
The amount of the RCF is subject to a borrowing base review performed on a semi-annual basis by the lenders, based primarily on reserves and commodity
prices estimated by the lenders as well as other factors. In addition, asset dispositions require unanimous lender consent. A decrease in the borrowing base
could result in a reduction to the available credit under the RCF. During the fourth quarter of 2021, the syndicate of lenders reconfirmed the Company's
borrowing base of $64.8 million, which was reduced by $2.75 million on December 31, 2021 and will be reduced by a further $5.0 million on March 31,
2022. In addition, Petrus and the lenders under the RCF have agreed to a cash sweep provision under which 75% of excess cash flow will be used to
accelerate repayment of the Company's First Lien Loan. The next scheduled borrowing base redetermination date for the RCF is on or before May 31, 2022.
Debt Settlement - Term Loan
Prior to September 30, 2021, Petrus had a second debt instrument, a subordinated secured term loan (the "Term Loan"). During the third quarter of 2021,
the Company settled its Term Loan with a principal amount (carrying value) of $39.4 million (the "Second Lien Settlement") in consideration for the issuance
of $15.8 million (the settlement amount) of common shares of Petrus ("Common Shares") to the holders of the Term Loan at an issue price of $0.55 per
share. The difference between the carrying value and the settlement amount of the debt was added to contributed surplus in the amount of $18.1 million
(net of the recovery of income taxes of $5.4 million).
Liquidity
At December 31, 2021, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $62.0 million due to the
classification of the Company's borrowings under its RCF as a current liability. 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 is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt instrument:
Page |43
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
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 covenants as at December 31, 2021 are summarized in the following table. At December 31, 2021 the Company is in compliance with all
financial covenants.
Financial Covenant Description
Working Capital Ratio
8. LEASES
The Company's lease obligations are as follows:
$000s
Balance, December 31, 2020
Finance expense
Lease payments
Balance, December 31, 2021
The Company's future commitments associated with its lease obligations are as follows:
$000s
Less than 1 year
1 to 3 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 0.60
As at December 31, 2021
1.17
1,012
69
(261)
820
As at December 31, 2021
271
646
917
(97)
820
217
603
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 1.66 percent and an inflation rate of 2.00 percent (1.10 percent and 1.40 percent, respectively, at December 31, 2020).
Changes in estimates in 2020 and 2021 are due to the change in the risk free and inflation rates 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 $41.6 million as at December 31, 2021
($44.5 million at December 31, 2020). The undiscounted, uninflated total future liability at December 31, 2021 is $38.3 million ($41.4 million at
December 31, 2020). The payments are expected to be incurred over the operating lives of the assets.
Page |44
The following table reconciles the decommissioning liability:
$000s
Balance, December 31, 2019
Property dispositions
Other adjustments
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2020
Property dispositions
Other adjustments
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2021
10. FINANCIAL RISK MANAGEMENT
41,259
(98)
(135)
320
(904)
3,520
494
44,456
(2,876)
(373)
489
(674)
(160)
707
41,569
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table
summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2021:
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Fixed price
10,000
$2.61
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Fixed price
600
$62.73
Type
Average Rate (%)
Notional Amount (000s CDN$)
Fixed rate
2.24
$5,000
Asset
—
—
934
15
949
Liability
2,488
2,488
986
41
1,027
Year ended
Year ended
December 31, 2021
(11,713)
December 31, 2020
6,518
(2,409)
(14,122)
1,661
8,179
Contract Period
Natural Gas Swaps
Jan. 1, 2021 to Mar. 31, 2022
Contract Period
Crude Oil Swaps
Jan. 1, 2022 to Mar. 31, 2022
Contract Period
Interest Rate Swaps
Jan.1, 2022 to Jan. 31, 2022
Risk management asset and liability:
$000s At December 31, 2021
Current commodity derivatives
$000s At December 31, 2020
Current commodity derivatives
Non-current commodity derivatives
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s
Realized gain (loss) on financial derivatives
Unrealized gain (loss) on financial derivatives
Net gain (loss) on financial derivatives
Page |45
The Company had the following physical commodity contracts in place as at December 31, 2021:
Contract Period
Natural Gas
Jan. 1, 2022 to Mar. 31, 2022
Apr. 1, 2022 to Oct. 31, 2022
Apr. 1, 2022 to Oct. 31, 2022
Apr. 1, 2022 to Oct. 31, 2022
Apr. 1, 2022 to Oct. 31, 2022
Nov. 1, 2022 to Mar. 31, 2023
Nov. 1, 2022 to Mar. 31, 2023
Nov. 1, 2022 to Mar. 31, 2023
Contract Period
Crude Oil
Jan. 1, 2022 to Mar. 31, 2022
11. SHARE CAPITAL
Type
Total Daily Volume (GJ)
Price (CDN$/GJ)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
1,000
2,000
1,000
2,000
1,000
1,000
1,000
1,000
$4.69
$3.38
$3.33
$3.65
$3.04
$3.78
$3.30
$3.50
Type
Total Daily Volume (Bbl)
Price (CDN$/Bbl)
Fixed price
200
$95.60
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)
Balance, December 31, 2020
Common shares issued for private placement, equity conversion and debt settlement
Common shares issued on exercise of stock options
Share issue costs
Balance, December 31, 2021
Number of Shares
49,469,358
46,909,092
329,462
—
96,707,912
Amount
430,119
25,800
138
(111)
455,946
The Company completed a private placement financing of an aggregate of $10 million of Common Shares at an issue price of $0.55 per share. All proceeds
from the Equity Financing have been applied to outstanding indebtedness under the First Lien Loan (see note 7). Petrus had a second debt instrument, a
subordinated secured term loan. During the third quarter of 2021, the Company settled its Term Loan with a principal amount (carrying value) of $39.4
million in consideration for the issuance of $15.8 million (the settlement amount) of common shares of Petrus to the holders of the Term Loan at an issue
price of $0.55 per share. The difference between the carrying value and the settlement amount of the debt was added to contributed surplus in the amount
of $18.1 million (net of the recovery of income taxes of $5.4 million)
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, 2021, 5,562,549 (December 31, 2020 – 2,276,923) stock options were outstanding. The summary of stock option activity is presented
below:
Page |46
Balance, December 31, 2019
Granted
Cancelled/forfeited
Expired
Balance, December 31, 2020
Granted
Forfeited
Expired
Exercised
Balance, December 31, 2021
Exercisable, December 31, 2021
Number of stock
options
2,361,958
1,122,276
(353,320)
(853,991)
2,276,923
4,637,500
(623,513)
(198,780)
(529,581)
5,562,549
215,851
Weighted average
exercise price
$2.87
$0.23
$1.06
$2.16
$0.40
$0.75
$0.36
$1.68
$0.28
$0.67
$0.29
The following table summarizes information about the stock options granted and currently outstanding:
Range of Exercise Price
Stock Options Outstanding
$0.23 - $0.50
$0.51 - $0.80
$0.81 - $1.00
Number granted
Weighted average
exercise price
Weighted average
remaining life (years)
911,288
3,636,261
1,015,000
5,562,549
$0.26
$0.70
$0.89
$0.67
1.47
2.78
3.01
2.61
During the year ended December 31, 2021, the Company granted 4,637,500 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, 2021 of $0.27 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 (%)
2021
0.15% - 0.49%
1.08 - 3.08
100% to 113%
33 %
— %
2020
0.20% - 0.29%
1.08 - 3.08
80% to 100%
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 trading price of the Company's shares on the grant date. At
December 31, 2021, 1,618,702 DSUs were issued and outstanding (December 2020 – 2,158,270). During the first quarter of 2021, the Company settled
539,568 DSUs for $0.2 million in cash.
Page |47
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. EARNINGS (LOSS) PER SHARE
Year ended
Year ended
December 31, 2021
259
24
73
—
356
December 31, 2020
152
26
77
229
484
Earnings (loss) per share amounts are calculated by dividing the net income (loss) for the period attributable to the common shareholders of the Company
by the weighted average number of common shares outstanding during the period.
Net income (loss) for the year ($000s)
Weighted average number of common shares – basic (000s)
Weighted average number of common shares – diluted (000s)
Net income (loss) per common share – basic
Net income (loss) per common share – diluted
Year ended
Year ended
December 31, 2021
114,556
62,557
65,207
1.83
1.76
December 31, 2020
(97,554)
49,469
49,469
($1.97)
($1.97)
In computing diluted earnings per share for the year ended December 31, 2021, 5,562,549 outstanding stock options and 1,618,702 DSUs were considered
(December 31, 2020 – 2,276,923 and 2,158,270 respectively). 4,547,549 stock options and 1,618,702 DSUs were included in calculating the number of
diluted common shares. There were 1,015,000 stock options that were anti-dilutive as the exercise price was higher than the average share price during the
year ended December 31, 2021.
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 expenses
Capitalized general and administrative expenses
Overhead recoveries
General and administrative expenses
2021
11,134
2,719
13,853
(939)
12,914
2021
5,830
(878)
(678)
4,274
2020
9,673
2,463
12,136
(913)
11,223
2020
5,248
(1,117)
(722)
3,409
Page |48
15. FINANCIAL INSTRUMENTS
Risks associated with financial instruments
Credit risk
The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal
credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound purchasers
under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating to
the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $9.7 million of accounts receivable outstanding
at December 31, 2021 (December 31, 2020 – $6.3 million), $7.4 million is owed from 3 parties (December 31, 2020 – $4.7 million from 3 parties), and the
balances were received subsequent to December 31, 2021. The Company considers accounts receivable outstanding past 120 days to be 'past due'. At
December 31, 2021, the Company had an allowance for doubtful accounts of $0.5 million (December 31, 2020 – $0.5 million). At December 31, 2021, 90%
of Petrus’ accounts receivable were aged less than 120 days and 10% 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, 2021, the Company had a $62.0 million RCF, on which $57.7 million was drawn (December 31, 2020 – $77.5 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 Company's RCF's maturity date is May 31, 2022. The Company requires an
extension or refinancing of its RCF. The borrowings under the RCF are classified as current liabilities in the December 31, 2021 consolidated financial
statements which has no impact on the debt covenants and the Company remains in compliance with each of its covenants. However, the reclassification of
the debt instruments resulted in a working capital deficit of $62.0 million as of December 31, 2021. For the year ended December 31, 2021 the Company
generated funds flow of $33.4 million and reduced its debt $56.3 million from December 31, 2020. Management is actively seeking alternative debt or
equity financing to refinance the RCF prior to May 31, 2022.
The following are the contractual maturities of financial liabilities as at December 31, 2021:
$000s
Accounts payable and accrued liabilities
Risk management liability
Current portion of long term debt
Lease obligations
Total
Total
19,690
2,488
57,700
820
80,698
< 1 year
19,690
2,488
57,700
217
80,095
1-5 years
—
—
—
603
603
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 is exposed to interest rate cash flow risk as the instrument is 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, 2021 would have decreased net income by approximately $0.8 million, which relates to interest expense
on the average outstanding RCF, net of any interest rate swaps to fix the interest rate on loans, assuming that all other variables remain constant
(December 31, 2020 – $1.0 million). A 1% decrease in the Canadian prime interest rate during the year would result in an opposite impact on net income.
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, 2021, it was estimated that a $0.25/GJ decrease in the price of natural gas would have increased net income by $0.2 million
(December 31, 2020 – $1.3 million). An opposite change in commodity prices would result in an opposite impact on net income for the period. As at
December 31, 2021, it was estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased net income by $0.3 million (December 31,
2020 – $1.1 million). An opposite change in commodity prices would result in an opposite impact on net income for the period.
Page |49
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 and finance fees
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
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
Investments
Accounts receivable
Accounts payable and accrued liabilities
Operating activities
Financing activities
Investing activities
2021
5,133
5,133
365
2,573
707
3,645
8,778
2021
199
(178)
(3)
(3,455)
11,982
8,545
(366)
(179)
9,089
2020
6,661
6,661
625
1,813
494
2,932
9,593
2020
179
(773)
—
6,758
(3,655)
2,509
2,527
162
(179)
The following table reconciles the changes in liability resulting from financing activities:
$000s
Balance, December 31, 2020
Cash flows
Payment-in-kind
Non-cash changes
Balance, December 31, 2021
Bank Indebtedness
Revolving Credit
Facility
Term Loan
Total Liabilities from
Financing Activities
32
(32)
—
—
—
77,484
(19,800)
—
16
57,700
36,565
—
2,573
(39,138)
—
114,081
(19,832)
2,573
(39,122)
57,700
19. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The commitments for which the Company is responsible are as follows:
Page |50
$000s
Firm service transportation
Total
13,197
< 1 year
2,465
1-5 years
10,392
> 5 years
340
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
2021
29,322
34,833
16,793
80,948
320
81,268
2020
16,493
26,023
7,472
49,988
380
50,368
During the year ended December 31, 2021, the Company recorded $1.4 million as other income. This amount mainly relates to the settlement of an
outstanding dispute associated with the transportation and marketing of its Ferrier area condensate volume.
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
2021
1,307
85
1,392
2020
890
228
1,118
During the third quarter of 2021, the Chairman of the Company acquired 15,636,364 Common Shares at an issue price of $0.55 per share for total proceeds
of $8.6 million. An individual related to the Chairman of the Company acquired 2,545,455 Common Shares at an issue price of $0.55 per share for total
proceeds of $1.4 million. Two individuals related to the Chairman of the Company settled their Term Loan with the Company for 28,727,273 Common
Shares at an issue price of $0.55 per share.
Page |51
22. DEFERRED INCOME TAXES
$000s
Income (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, 2021 and 2020 are as follows:
$000s
Exploration and evaluation assets and property, plant and equipment
Asset retirement obligations
Share issuance costs
Non capital loss carry-forwards
Unrealized hedging loss
Deferred tax liability
2021
109,132
23.0 %
25,100
1
82
—
—
1,615
(32,222)
(5,424)
(5) %
2021
19,116
(9,561)
—
(8,983)
(572)
—
2020
(97,554)
24.0 %
(23,413)
4
103
—
976
596
21,734
—
— %
2020
—
—
—
—
—
—
The company has unrecognized deductible temporary differences in the form of non-capital loss carry-forward of approximately 224.8 million (2020 -
$341.3 million). The Company had non-capital losses of approximately $263.9 million (2020 – $217.8 million) which may be applied against future income
for Canadian tax purposes. These non-capital losses expire in 2027 and onwards.
At December 31, 2021, the Company has determined it is currently not probable that future taxable profits will be available against which the tax benefits
will be utilized.
23. SUBSEQUENT EVENTS
Subsequent to December 31, 2021, the Company entered into a definitive agreement to acquire producing oil and gas properties that are held by a privately
owned limited partnership and its general partner (the "Acquired Entities") for total consideration of approximately $14.4 million, consisting of 10 million
common shares of the Company issued at a deemed price of $1.44 per share based on the volume weighted average trading price of the common shares of
the Company on the TSX for the five trading days prior to the date of the Agreement (the "Acquisition"). The Acquisition is expected to close in March 2022
and is subject to customary closing conditions.
The Acquisition is a related party transaction under applicable securities legislation as the Acquired Entities are managed and directed by the President and
Chief Executive Officer of the Company, and the President and Chief Executive Officer of the Company and two of Petrus' controlling shareholders own or
control, in aggregate, approximately 70% of the limited partnership's units and 50% of the general partner's shares.
Under IFRS 3, if the acquisition date of a business combination is after the end of the reporting period, but prior to the publication of the consolidated
financial statements, the Company must provide the information required under IFRS 3 unless the initial accounting for the business combination is
incomplete. Due to the nature of the acquisition, the allocation of the purchase price has not been provided because that information has not yet been
finalized.
Page |52
CORPORATE INFORMATION
OFFICER & VICE PRESIDENT
Ken Gray, P.Eng
President and
Chief Executive Officer
DIRECTORS
Don T. Gray
Chairman
Scottsdale, Arizona
Mathew Wong, CPA, CFA, CPA (WA, USA)
Vice President, Finance
Ken Gray
Calgary, Alberta
Patrick Arnell
Calgary, Alberta
Donald Cormack
Calgary, Alberta
Peter Verburg
Calgary, Alberta
SOLICITOR
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
AUDITOR
Ernst & Young LLP
Chartered Professional Accountants
Calgary, Alberta
INDEPENDENT RESERVE EVALUATORS
InSite Petroleum Consultants Ltd.
Calgary, Alberta
BANKERS
TD Securities (Syndicate Lead Agent)
Calgary, Alberta
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 |53