ANNUAL REPORT
December 31, 2022
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, 2022 and to provide 2022 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 2022 HIGHLIGHTS
•
•
•
•
•
Increased production – Total production increased by 55% to 9,113 boe/d in the fourth quarter of 2022, compared to 5,880 boe/d in the
fourth quarter of 2021. Petrus achieved its exit production rate averaging 10,635 boe/d(1) during the last week of December 2022.
Total funds flow up 228% – Petrus generated funds flow(2) and corporate netback(2) of $34.1 million and $40.70/boe in the fourth quarter
of 2022, 228% and 111% higher, respectively, than the fourth quarter of the prior year.
Increased capital activity – Petrus incurred capital expenditures of $37.8 million in the fourth quarter of 2022 compared to $12.2 million
in the fourth quarter of 2021. The Company drilled and completed 6 gross (5.3 net) wells and spent $4.9 million on pipeline, equipment
and facilities.
Operating netback per boe up 20% – Operating netback(2) increased by 20% to $39.84/boe in the fourth quarter of 2022 up from $33.12/
boe in the fourth quarter of 2021, due to significantly higher realized prices.
Commodity price improvement – Petrus' total realized price of $57.81/boe increased by 25% in the fourth quarter of 2022 compared to
the fourth quarter of 2021 ($46.29/boe) as a result of higher commodity prices across all products.
2022 ANNUAL HIGHLIGHTS
•
•
•
•
•
•
Total funds flow up 163% – Petrus generated funds flow and corporate netback of $87.7 million and $31.60/boe in 2022, 163% and 108%
higher, respectively, than funds flow of $33.4 million and $15.19/boe in 2021. The Company achieved its target funds flow guidance for
2022.
Successfully executed 2022 capital program – Petrus incurred $96.7 million of capital expenditures in 2022 (excluding acquisitions and
dispositions), compared to $26.9 million in 2021. 85% of total capital went to drilling and completion costs related to 21 gross (15.6 net)
wells in Ferrier and North Ferrier, 12% of capital went to pipeline, equipment and facilities costs, and the remaining capital went to land
and corporate costs. 2022 capital spending was in line with budget guidance.
Increased production – Petrus increased average annual production by 27% from 6,009 boe/d in 2021 to 7,604 boe/d in 2022.
Debt restructuring complete – The Company entered into agreements with new lenders providing two new credit facilities ("New
Facilities") totaling $55 million; at December 31, 2022, $28.9 million was drawn on the New Facilities. The refinancing completed the
Company’s debt restructuring.
Net debt reduction – Net debt(2) was $50.8 million at December 31, 2022, an 18% decrease from $61.8 million at December 31, 2021. The
Company continues to manage its balance sheet with the goal of maintaining a net debt to funds flow ratio(2) of under 1x.
Rights offering – Petrus closed a $20 million rights offering that was oversubscribed by 84%.
2023 OUTLOOK(3)
In early January, the Petrus team returned to drilling in Ferrier to kick off the 2023 capital program. We have successfully drilled and completed all
of the wells on the first pad site and production associated with these new wells came on in early March. The rig has moved to the second pad site
where drilling operations are well underway. We expect to complete drilling by the end of March and we will suspend drilling and completion
operations over spring break-up.
Given the inherent volatility of our commodity-based business, Petrus has always been committed to being disciplined and flexible. The Company
is continuously evaluating its 2023 capital program to ensure it meets the investment threshold to optimize shareholder return. By investing capital
wisely and generating strong cash flow, Petrus aims to ensure the value of this cash flow is realized by its shareholders. The Company is now in a
position to analyze options available to maximize shareholder value and is in the process of determining the optimum way forward.
(1)Disclosure of production on a per boe basis consists of the constituent product types and their respective quantities. Refer to "BOE Presentation" and "Production and Product Type
Information" for further details.
(2)Non-GAAP measure or non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto.
(3)Refer to "Advisories - Forward-Looking Statements" in the Management's Discussion & Analysis attached hereto.
PRESIDENT’S MESSAGE
This is my second letter to shareholders, and I’d like to reflect a bit on where we’ve come from and what we’ve done over the last couple of years
because I think it illustrates the volatile nature of this business and reinforces the need to be flexible in responding to constantly changing market
conditions.
When I started here in April of 2021, Petrus was in a difficult position with high debt levels (4.1xCF), low commodity prices (AECO $3/GJ winter, WTI
US$58/bbl), and hostile lenders looking to be repaid by whatever means necessary. Years of low prices and limited investment had resulted in
production declining 45% to under 6,000 boe/d. The share price sat at $0.30. However, as we emerged from the worst of the pandemic and energy
demand and prices started to improve, there was hope on the horizon. Everyone involved with Petrus believed the company had great people and
assets, and that if we could just get the debt situation corrected, we could really start generating value for shareholders.
We immediately set out to fix the debt problem. The unpleasant calls and meetings with bankers seemed never ending, but with the support of our
shareholders, we were able to reduce debt from $117 million to $18 million. In May 2022 we ceased doing business with the hostile banks and
brought in a much more supportive, local bank in ATB and a second lien loan with favorable terms from a major shareholder. Step one complete.
Step two was to invest in our assets and get back to what Petrus was built to do – generate strong returns for shareholders through finding,
developing, and producing oil and natural gas efficiently and profitably. The Russian invasion of Ukraine accelerated the increase in oil and gas
prices, and we were finally in a position to take advantage. We fired up two rigs at the start of June 2022 and got to work. It was a bit of a rough
start, but we were finally bringing new production on at the end of September, and it took off from there going from just over 6,000 boe/d in
September to our exit rate of over 10,500 boe/d. It was a very busy time for the Petrus team and not without its challenges, but everyone felt good
about what we were doing and were fully committed to making it a success.
And, successful it was. The numbers speak for themselves. Production was up 66% from December, 2021 to December, 2022. Cash Flow was up
163% year over year and was the highest in company history. PDP value was up 107%. This kind of growth doesn’t just happen. Petrus’ team
stepped up, showed their capabilities, and will be key to our success going forward. Step three to execute and deliver results is well underway.
So, what’s next? First, we recognize there were some unique circumstances that contributed to last year’s success. Commodity prices were the
strongest we have seen in some time, and Petrus’ lack of activity over the past few years made us well positioned to grow quickly. But growth is not
our ultimate goal. Rather, our primary goals are to generate high rates of return from our capital program and high netbacks and cash flow from
our operations. We believe the $138 million in capital invested over the last couple years is consistent with these goals. The growth is just a by-
product of these smart investments. Going forward, the key will be that we continue to make good investment decisions with our shareholders’
money. Growth, guidance, or other extraneous factors should not and will not influence our decision on when and how to invest capital. This is
important to keep in mind because our business is very dynamic and volatile. We must constantly assess our capital program along with the
assumptions that underpin it and remain flexible to make changes when warranted. As I write this, the volatility of our business is again on display
as winter gas prices have declined from $6.20/GJ in December to sub $3.00/GJ currently, with futures prices suggesting more of the same for the
rest of the year. Costs have also increased significantly. It should, therefore, come as no surprise that we are re-evaluating our capital plan and will
make changes if our expected returns do not meet our threshold.
Steps two and three were investing capital wisely and generating strong cash flow. This is an ongoing process which is now well underway. Step
four will be to ensure the value this cash flow represents is realized by our shareholders. We are at a size now where all options for maximizing
shareholder value are available to us, and we are in the process of examining these options to determine the optimum way forward.
Thank you for your support.
Ken Gray
President, Chief Executive Officer and Director
RESERVES
Petrus’ 2022 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, 2022 ("2022 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, 2022, 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 2022 Insite Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Insite:
As at December 31, 2022
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)
Condensate
NGL
(mmbl)
Other
NGL
(mbbl)
73,413
1,188
90,510
165,111
89,582
99,966
265,076
958
—
2,169
3,127
1,131
3,107
6,233
2,311
30
2,469
4,810
2,808
2,065
6,875
2,305
34
3,055
5,394
2,845
3,332
8,725
Total
(mboe)
NPV 0%(2)
($000s)
NPV 5%(2)
($000s)
NPV 10%(2)
($000s)
17,809
262
22,777
40,848
21,715
25,164
66,013
381,134
4,196
327,233
712,562
483,857
476,819
1,189,381
311,376
266,264
2,926
210,153
524,456
366,124
280,470
804,925
2,148
139,021
407,433
300,905
181,937
589,370
(1Tables may not add due to rounding.
(2)NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company's reserves, discounted by 0%, 5% and 10%, respectively
and is presented before tax and based on 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 2022, Petrus’ development program generated proved developed producing ("PDP") reserve volume additions of 7.5 mmboe. The
Company also produced 2.8 mmboe and acquired 1.4 mmboe of PDP reserves. The Company ended the year with 17.8 mmboe of PDP
reserves (31% crude oil and liquids).
Petrus ended 2022 with $266.3 million, $407.4 million and $589.4 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 2022 Insite Report. In 2022, the Company realized
Finding, Development and Acquisition (“FD&A”) costs of $12.50/boe for PDP reserves.
Based on the 2022 Insite Report, the Company’s PDP reserve value before-tax, discounted at 10% is $2.16 per share (123,238,528 basic
common shares outstanding at December 31, 2022). On the same basis, the P+P reserve value before tax, discounted at 10%, is $4.78 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 2022 Insite Report:
Future Development Cost ($000s)
2023
2024
2025
2026
Total FDC, Undiscounted
Total FDC, Discounted at 10%
Total Proved
Total Proved + Probable
112,557
119,861
81,369
—
313,786
277,551
122,732
177,167
158,927
60,998
519,823
442,376
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2018 to 2022(3):
December 31, 2022
December 31, 2021
December 31, 2020
December 31, 2019
December 31, 2018
Proved Producing
FD&A ($/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
(undiscounted) ($000s)
Total Proved + Probable
FD&A ($/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
(undiscounted) ($000s)
12.58
12.70
5.31
3.20
2.91
12.50
12.61
5.39
3.22
2.93
18.24
33.99
12.18
3.79
2.01
15.64
8.90
5.41
0.78
1.58
14.54
8.53
5.50
0.84
1.70
10.51
9.24
15.30
4.50
2.35
4.83
4.83
5.20
1.20
2.60
4.71
4.71
5.20
1.20
2.70
1.29
1.29
10.90
(1.00)
9.80
13.31
12.81
3.80
0.40
1.20
12.49
12.03
4.80
0.50
1.30
1.09
(6.83)
9.90
0.30
14.40
37.76
42.27
4.60
0.20
0.40
11.34
11.55
5.60
0.60
1.40
8.73
8.16
11.10
1.30
1.80
313,786
233,684
156,815
174,027
194,757
15.66
36.12
19.68
6.63
2.34
10.57
8.36
23.29
5.10
2.33
0.37
0.37
17.70
(1.30)
33.70
(7.32)
190.21
15.40
—
(2.10)
6.49
5.15
17.10
1.50
2.40
519,823
343,489
252,335
267,652
290,876
(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 2022 Insite Report and Insite's December 31, 2022
price forecast:
As at December 31, 2022 ($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 Fully Diluted Share
Proved Developed
Producing
Total Proved
Proved + Probable
266,264
34,837
(50,808)
250,293
133,377
$1.88
407,433
34,837
(50,808)
391,462
133,377
$2.94
589,370
34,837
(50,808)
573,399
133,377
$4.30
(1)Based on the 2022 Insite Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company's December 31, 2022 audited consolidated financial statements.
(3)Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures" in the Management's Discussion & Analysis attached hereto.
Page |6
MANAGEMENT'S DISCUSSION & ANALYSIS
December 31, 2022
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, 2022. This MD&A is dated March 14, 2023 and should be read in conjunction
with the Company's audited consolidated financial statements for the years ended December 31, 2022 and 2021. 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 ($/boe)
Royalty income
Royalty expense
Loss on risk management activities
Net oil and natural gas revenue ($/boe)
Operating expense
Transportation expense
Operating netback(1) ($/boe)
Realized gain (loss) on financial derivatives
($/boe)
Other income (cash)
General & administrative expense
Cash finance expense
Decommissioning expenditures
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2022
Sept. 30, 2022
Jun. 30, 2022
Mar. 31, 2022
30,441
1,436
1,094
7,604
23,680
1,019
1,043
6,009
33,201
2,458
1,121
9,113
2,775,561
2,193,432
838,375
28,107
957
997
6,639
610,722
30,913
1,073
1,055
7,280
29,530
1,250
1,207
7,379
662,456
664,010
19 %
17 %
27 %
14 %
15 %
17 %
6.03
113.19
63.26
54.63
0.26
(8.70)
(2.17)
44.02
(7.45)
(2.08)
34.49
(0.58)
0.10
(1.22)
(1.14)
(0.05)
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)
6.04
106.85
56.90
57.81
0.15
(7.92)
(1.26)
48.78
(6.86)
(2.08)
39.84
2.89
0.22
(1.10)
(1.18)
0.03
5.02
111.04
62.25
46.62
0.37
(11.84)
(0.81)
34.34
(8.47)
(1.89)
23.98
1.00
0.05
(1.30)
(0.87)
(0.29)
7.74
133.36
5.20
110.12
74.63
63.33
0.25
(8.64)
(6.76)
48.18
(7.92)
(2.16)
38.10
—
0.04
(1.70)
(1.46)
0.06
60.12
49.31
0.29
(6.89)
—
42.71
(6.76)
(2.17)
33.78
(6.98)
0.07
(0.82)
(1.04)
(0.02)
Funds flow & corporate netback(1) ($/boe)
31.60
15.19
40.70
22.57
35.04
24.99
FINANCIAL (000s except $ per share)
Oil and natural gas revenue
Net income
Net income per share
Basic
Fully diluted
Funds flow(1)
Funds flow per share (1)
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, 2022
152,350
Dec. 31, 2021
81,268
Dec. 31, 2022
48,590
Sept. 30, 2022
28,701
Jun. 30, 2022
42,119
Mar. 31, 2022
32,940
60,868
114,556
22,097
9,822
18,046
10,903
0.53
0.51
87,716
0.76
0.73
96,744
115,189
119,525
123,239
133,377
381,057
63,021
50,808
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
0.18
0.17
34,117
0.28
0.27
37,792
0.08
0.08
13,789
0.11
0.11
49,513
0.16
0.15
23,208
0.21
0.20
4,932
0.11
0.11
16,601
0.17
0.16
5,064
122,545
127,600
122,058
126,822
111,795
117,203
99,189
103,250
123,239
133,377
381,057
63,021
50,808
122,197
131,482
356,050
61,778
48,465
122,017
131,302
302,472
50,924
13,895
106,907
113,883
308,744
46,702
50,044
(1) Non-GAAP financial measure or non-GAAP ratio. 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, 2022
Natural gas (mcf/d)
Oil (bbl/d)
NGLs (bbl/d)
Total (boe/d)
Ferrier
North Ferrier
Foothills
Central Alberta
Kakwa
Total
21,198
1,872
834
6,239
4,498
237
120
1,107
2,360
81
7
481
4,993
247
150
1,230
150
21
10
56
33,199
2,458
1,121
9,113
Fourth quarter 2022 production averaged 9,113 boe/d compared to 5,880 boe/d in the fourth quarter of 2021. Five gross (4.6 net) wells
were spud in the Ferrier area during the quarter. Of these, four (3.6 net) wells were completed and on production by December 31, 2022.
CAPITAL EXPENDITURES
The Company's 2022 capital program accelerated in the second half of 2022 with capital expenditures (excluding acquisitions and
dispositions) totaling $37.8 million in the fourth quarter of 2022, compared to $12.2 million in the prior year comparative period.
Capital expenditures (excluding acquisitions and dispositions) totaled $96.7 million in the year ended December 31, 2022, compared to
$27.0 million in 2021. The increase from the prior year is attributed to the execution of the Company's 2022 capital program.
The following table shows capital expenditures for the reporting periods indicated, excluding acquisitions and dispositions. All capital is
presented before decommissioning obligations.
Capital Expenditures ($000s)
Drill and complete
Oil and gas equipment and facilities
Land and lease
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
32,073
4,921
291
507
37,792
5 (4.6)
10,769
1,104
25
337
12,235
3 (3.0)
81,953
11,853
1,759
1,179
96,744
20 (14.8)
21,882
3,918
274
941
27,015
10 (6.4)
During the first quarter of 2022, Petrus closed an acquisition in its core Ferrier area. Included in this acquisition was approximately 425
boe/d of production and 5,120 net acres of undeveloped land. The acquisition was made for total share consideration of 10 million shares
($15.2 million).
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)
Loss on risk management ($/boe)
Twelve months
ended
Twelve months
ended
Three months
ended
Three months
ended
Three months
ended
Three months
ended
Dec. 31, 2022
Dec. 31, 2021
Dec. 31, 2022
Sept. 30, 2022
Jun. 30, 2022
Mar. 31, 2022
30,441
1,436
1,094
7,604
23,680
1,019
1,043
6,009
33,201
2,458
1,121
9,113
28,107
957
997
6,639
30,913
1,073
1,055
7,280
29,530
1,250
1,207
7,379
2,775,561
2,193,432
838,375
610,722
662,456
664,010
67,025
59,348
25,267
710
152,350
6.03
113.19
63.26
54.63
(0.58)
(2.17)
34,833
29,322
16,793
320
81,268
4.03
78.82
44.09
36.90
(5.34)
—
18,434
24,163
5,869
124
48,590
6.04
106.85
56.90
57.81
2.89
12,990
9,776
5,708
227
28,701
5.02
111.04
62.25
46.62
1.00
21,771
13,022
7,162
164
42,119
7.74
133.36
74.63
63.33
—
(1.26)
(0.81)
(6.76)
13,830
12,387
6,528
195
32,940
5.20
110.12
60.12
49.31
(6.98)
—
Total price including hedging ($/boe)
51.88
31.56
59.44
46.81
56.57
42.33
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil and NGLs
Mixed Sweet Blend Edm (C$/bbl)
WTI (US$/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, 2022
Dec. 31, 2021
Dec. 31, 2022
Sept. 30, 2022
Jun. 30, 2021
Mar. 31, 2022
5.04
5.22
119.41
94.23
0.74
3.43
3.38
80.48
67.96
0.79
4.85
5.29
108.14
82.65
3.95
5.29
115.94
91.56
6.86
5.95
134.99
108.41
4.49
4.35
117.57
94.29
0.74
0.77
0.79
0.79
Page |11
FUNDS FLOW AND NET INCOME
Petrus generated funds flow of $34.1 million in the fourth quarter of 2022 compared to $10.4 million in the fourth quarter of 2021. The
228% increase is due to higher production and improved commodity prices. In the fourth quarter of 2022 Petrus' production was 9,113
boe/d, 55% higher than the 5,880 boe/d during the fourth quarter of 2021. The Company's total realized price was $57.81/boe in the fourth
quarter of 2022 compared to $46.29/boe in the prior year comparative period.
For the year ended December 31, 2022, Petrus generated funds flow of $87.7 million compared to $33.4 million in the prior year. The 163%
increase is due to higher production and improved commodity prices.
Petrus reported net income of $22.1 million in the fourth quarter of 2022, compared to net income of $114.6 million in the fourth quarter
of 2021. The reduction in net income in the fourth quarter of 2022 compared to the fourth quarter of 2021 is primarily due to the
impairment reversal of $103.2 million recorded in the fourth quarter of 2021. Excluding the impairment reversal, net income was 94%
higher in the fourth quarter of 2022 compared to the prior year comparative period.
The Company generated net income of $60.9 million for the year ended December 31, 2022 compared to net income of $114.6 million for
the year ended December 31, 2021. The year over year change is due to the $103.2 million impairment reversal recorded in the fourth
quarter of 2021. Excluding the impairment reversal, net income was 434% higher year over year.
($000s except per share)
Funds flow
Funds flow per share - basic
Funds flow per share - fully diluted
Net income
Net income per share - basic
Net income 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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
34,117
0.28
0.27
22,097
0.18
0.17
123,239
133,377
122,545
127,600
10,418
0.11
0.10
114,633
1.19
1.11
96,708
103,889
96,660
102,868
87,716
0.76
0.73
60,868
0.53
0.51
123,239
133,377
115,189
119,525
33,354
0.53
0.51
114,556
1.83
1.76
96,708
103,889
62,557
65,207
OIL AND NATURAL GAS REVENUE
Fourth quarter average production in 2022 was 9,113 boe/d (61% natural gas), 55% higher than the fourth quarter of 2021 (5,880 boe/d;
67% natural gas). Fourth quarter oil and natural gas revenue in 2022 was $48.6 million compared to $25.1 million in 2021. The 94%
increase is due to higher production and improved commodity prices.
Average production for the year ended December 31, 2022 was 7,604 boe/d (67% natural gas), 27% higher than 2021 (6,009 boe/d; 66%
natural gas). Total oil and natural gas revenue increased from $81.3 million in 2021 to $152.4 million in 2022 due to higher production and
improved 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 ($000s)
Natural gas
Crude oil and condensate
Natural gas liquids
Royalty income
Total oil and natural gas revenue
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2022
December 31, 2021
% Change
December 31, 2022
December 31, 2021
% Change
18,434
24,163
5,869
124
48,590
11,781
8,273
4,985
31
25,070
56 %
192 %
18 %
300 %
94 %
67,025
59,348
25,267
710
152,350
34,833
29,322
16,793
320
81,268
92 %
102 %
50 %
122 %
87 %
Page |12
The following table provides the average benchmark commodity prices and the Company's average realized commodity prices (before
hedging and risk management gains/losses):
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2022
December 31, 2021
% Change
December 31, 2022
December 31, 2021
% Change
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
AECO 7A (C$/GJ)
Crude oil
Mixed Sweet Blend Edm (C$/bbl)
Average realized prices
Natural gas ($/mcf)
Oil ($/bbl)
NGLs ($/bbl)
Total average realized price
4.85
5.29
108.14
6.04
106.85
56.90
57.81
4.41
4.68
10 %
13 %
5.04
5.22
3.43
3.38
47 %
54 %
92.97
16 %
119.41
80.48
48 %
5.45
89.71
56.35
46.29
11 %
19 %
1 %
25 %
6.03
113.19
63.26
54.63
4.03
78.82
44.09
36.90
50 %
44 %
43 %
48 %
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
61 %
27 %
12 %
100 %
67 %
17 %
16 %
100 %
67 %
19 %
14 %
100 %
66 %
17 %
17 %
100 %
Natural gas
Natural gas revenue for the year ended December 31, 2022 was $67.0 million, which increased 92% from the prior year ($34.8 million). The
average realized natural gas price for the year ended December 31, 2022 increased 50% to $6.03/mcf from the prior year ($4.03/mcf).
Natural gas production increased from 8.6 bcf in 2021 to 11.1 bcf in 2022, an increase of 29%. Natural gas revenue accounted for 44% of oil
and natural gas revenue in 2022, compared to 43% in the prior year.
Fourth quarter 2022 natural gas revenue was $18.4 million, which increased 56% from the prior year comparative period ($11.8 million).
The average realized natural gas price in the fourth quarter of 2022 was $6.04/mcf, compared to $5.45/mcf in the fourth quarter of 2021
(11% increase). Natural gas production increased from 2.25 bcf in the fourth quarter of 2021 to 3.1 bcf in the fourth quarter of 2022.
Natural gas revenue accounted for 38% of oil and natural gas revenue in the fourth quarter of 2022, compared to 47% in the prior year
comparative period.
Crude oil and condensate
Oil and condensate revenue for the year ended December 31, 2022 was $59.3 million, which increased 102% from the prior year ($29.3
million). The average realized oil and condensate price for the year ended December 31, 2022 increased 44% to $113.19/bbl from the prior
year ($78.82/bbl). Oil and condensate production increased from 372.0 mbbl in 2021 to 524.4 mbbl in 2022, an increase of 41%. Oil and
condensate revenue accounted for 39% of oil and natural gas revenue in 2022, compared to 36% in the prior year.
Fourth quarter 2022 oil and condensate revenue was $24.2 million, which increased 192% from the prior year comparative period ($8.3
million). The average realized oil and condensate price was $106.85/bbl for the fourth quarter of 2022 compared to $89.71/bbl in the
fourth quarter of 2021, an increase of 19%. Oil and condensate production increased from 92.2 mbbl in the fourth quarter of 2021 to 226.1
mbbl in the fourth quarter of 2022, an increase of 145%. Oil and condensate revenue accounted for 50% of oil and natural gas revenue in
the fourth quarter of 2022, compared to 33% in the prior year comparative period.
Page |13
Natural gas liquids (NGLs)
NGL revenue for the year ended December 31, 2022 was $25.3 million, which increased 50% from the prior year ($16.8 million). The
average realized NGL price for the year ended December 31, 2022 increased 43% to $63.26/bbl from the prior year ($44.09/bbl). NGL
production increased from 382.3 mbbl in 2021 to 399.5 mbbl in 2022, an increase of 5%. NGL revenue accounted for 17% of oil and natural
gas revenue in 2022, compared to 21% in the prior year.
Fourth quarter 2022 NGL revenue was $5.9 million, which increased 18% from the prior year comparative period ($5.0 million). The
average realized NGL price was $56.90/bbl for the fourth quarter of 2022 which is consistent with the realized price of $56.35/bbl in the
fourth quarter of 2021. NGL production increased from 89.0 mbbl in the fourth quarter of 2021 to 103.2 mbbl in the fourth quarter of 2022,
an increase of 16%. NGL revenue accounted for 12% of oil and natural gas revenue in the fourth quarter of 2022, compared to 20% in the
prior year comparative period.
The Company’s NGL production mix consists of ethane, propane, butane and pentanes+. 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. NGL pricing is benchmarked to WTI.
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
4,194
9 %
2,443
6,637
1,941
8 %
1,487
3,428
15,463
10 %
8,698
24,161
5,797
7 %
4,564
10,361
Fourth quarter royalty expense increased from $3.4 million in 2021 to $6.6 million in 2022. On a twelve month basis, total royalty expense
(net of royalty allowances and incentives) increased from $10.4 million in 2021 to $24.2 million in 2022. The increase in royalties for the
fourth quarter and the year ended December 31, 2022 is due to higher revenue (as a result of increased commodity prices and production)
and higher crown royalty rates.
Gross overriding royalties increased from $1.5 million in the fourth quarter of 2021 to $2.4 million in the fourth quarter of 2022. Gross
overriding royalties increased from $4.6 million for the year ended December 31, 2021 to $8.7 million for the year ended December 31,
2022. The increase for both periods is due to higher revenue (as a result of increased production and higher commodity prices).
OTHER INCOME
During the year ended December 31, 2022 the Company recorded $1.4 million as other income ($0.3 million cash). This amount mainly
relates to the recognition of carbon credits ($0.6 million) the Company earned from installing emission reduction equipment and the
recognition of a grant for decommissioning activities ($0.4 million).
RISK MANAGEMENT
The Company utilizes financial derivative contracts and physical commodity 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) for financial derivatives and premium (loss) on risk management activities for physical commodity contracts. The unrealized
gain (loss) is recorded to demonstrate the change in fair value of the outstanding financial derivative contracts during the financial
reporting period for financial statement purposes. Petrus does not follow hedge accounting for any of its risk management contracts in
place. Petrus considers all of its risk management contracts to be effective economic hedges of its underlying business transactions.
Page |14
The table below shows the realized and unrealized gain or loss on financial derivative 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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
Realized hedging gain (loss)
Unrealized hedging gain (loss)
Net gain (loss) on derivatives
2,421
(1,959)
462
(5,148)
6,064
916
(1,601)
7,609
6,008
(11,713)
(2,408)
(14,121)
In the fourth quarter of 2022, the Company recognized a realized hedging gain of $2.4 million compared to a loss of $5.1 million in the
fourth quarter of 2021. The realized gain in the fourth quarter of 2022 increased the Company’s corporate netback by $2.89/boe,
compared to a decrease of $9.52/boe in 2021. The Company recognized a realized hedging loss of $1.6 million during the year ended
December 31, 2022, in comparison to the $11.7 million loss realized in 2021. The realized gain for the fourth quarter of 2022 was due to
lower commodity prices (relative to the respective contracts settled) while the realized loss for the year ended December 31, 2022 was due
to higher commodity prices (relative to the respective contracts settled).
During the fourth quarter of 2022, the Company recognized an unrealized loss of $2.0 million compared to an unrealized gain of $6.1
million in the fourth quarter of 2021. The Company recognized an unrealized hedging gain of $7.6 million for the year ended December 31,
2022 compared to an unrealized loss of $2.4 million for the year ended December 31, 2021. The gain (loss) represents the change in the
unrealized risk management net asset or liability position during the year ended December 31, 2022.
The table below shows the premium (loss) on risk management activities related to physical commodity contracts for the periods shown:
Net Loss on Risk Management Activities ($000s)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2022
December 31, 2021
December 31, 2022
December 31, 2021
Loss on physical commodity contracts
Net loss on risk management activities
(1,056)
(1,056)
—
—
(6,029)
(6,029)
—
—
During the fourth quarter of 2022, the Company recorded a loss of $1.1 million or $1.26/boe related to the settlement of its physical
commodity contracts. For the year ended December 31, 2022, the Company recorded a loss of $6.0 million or $2.17/boe. The losses are a
result of lower contract prices in comparison to benchmark prices during the periods. The average volume of gas hedged through physical
commodity contracts during the fourth quarter of 2022 was 14,333 GJ/d at an average price of $3.98/GJ. There was no loss or premium
recorded during the three and twelve months ended December 31, 2021 as there were no contracts outstanding during these periods.
The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices for
2023 and 2024. The Company endeavors to hedge approximately half of its forecasted production for up to 12 months forward, and
approximately 10% to 25% of its forecasted production for 12 to 24 months forward. The Company's hedging strategy is intended to
provide stability and sustainability to the Company's economic returns, funds flow and capital development plan. A summary of Petrus’ risk
management contracts as at December 31, 2022 is included in note 11 of the Company’s consolidated financial statements as at and for the
year ended December 31, 2022. The 12,583 GJ/day of average natural gas hedged for the 2023 represents 40% of fourth quarter 2022
average natural gas production. The 1,375 bbl/day of average oil hedged for the 2023 represents 56% of fourth quarter 2022 average
natural gas production.
The following table summarizes the average and minimum and maximum cap and floor prices for the 2023 to 2024 oil and natural gas
contracts outstanding as at the date of this report:
Oil hedged (bbl/d)
Avg. WTI cap price ($C/bbl)
Avg. WTI floor price ($C/bbl)
Natural gas hedged (GJ/d)
Avg. AECO 7A cap price ($C/GJ)
Avg. AECO 7A floor price ($C/GJ)
Q1
Q2
1,100
112.23
103.79
6,000
6.67
6.67
1,400
109.98
103.35
15,000
4.10
4.10
2023
Q3
1,500
106.07
99.88
15,000
4.10
4.10
Q4
Avg.(1)
Q1
Q2
1,500
105.84
99.65
14,333
4.39
4.39
1,375
108.23
101.48
12,583
4.49
4.49
1,100
99.13
99.13
14,000
4.53
4.53
1,000
99.09
99.09
4,000
3.26
3.26
2024
Q3
200
94.55
94.55
4,000
3.26
3.26
Q4
Avg.(1)
200
94.55
94.55
1,333
3.26
3.26
625
98.38
98.38
5,833
4.02
4.02
(1)The volumes and prices reported are the weighted average volumes and prices for the period.
Page |15
The following table summarizes the quarterly average volume and average prices for the natural gas physical commodity contracts as at the
date of this MD&A:
Natural gas hedged (GJ/d)
Avg. AECO 7A price ($C/GJ)
(1)The volumes and prices reported are the weighted average volumes and prices for the period.
Q1
Q2
14,000
4.17
—
—
2023
Q3
Q4
Avg.(1)
—
—
—
—
3,500
4.17
OPERATING EXPENSE
The following table shows the Company’s operating expense for the reporting periods shown:
Operating Expense ($000s)
Fixed and variable operating expense
Processing, gathering and compression charges
Total gross operating expense
Overhead recoveries
Total net operating expense
Operating expense, net ($/boe)
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2022
December 31, 2021
December 31, 2022
December 31, 2021
5,173
878
6,051
(298)
5,753
6.86
2,182
745
2,927
(212)
2,715
5.02
16,954
4,853
21,807
(1,142)
20,665
7.45
11,134
2,719
13,853
(939)
12,914
5.89
For the three months ended December 31, 2022, net operating expense totaled $5.8 million, a 112% increase from $2.7 million during the
prior year comparative period. Total operating expense is higher for three months ended December 31, 2022 due to higher production. On
a per boe basis, net operating expense was 37% higher at $6.86/boe in the fourth quarter of 2022 compared to $5.02/boe in 2021.
For the year ended December 31, 2022, net operating expense totaled $20.7 million, a 60% increase from the $12.9 million incurred in the
prior year comparative period. Total operating expense for the year ended December 31, 2022 is mainly due to higher production. On a per
boe basis, net operating expense was 27% higher at $7.45/boe in 2022 compared to $5.89/boe in 2021.
On a per boe basis, the increase in net operating expense for the quarter and year ended December 31, 2022, is mainly attributable to
inflationary pressures including the growing costs of power, fuel, trucking, and contract operating. Carbon tax expense was higher than the
prior year comparative periods as well. The cost of gas gathering, compression and processing was also higher in 2022 as the Company had
more volumes processed through third party facilities in the Foothills, Kakwa and North Ferrier areas. In addition, there was a decrease in
third-party production flowing through Petrus' operated facilities, reducing fee recoveries.
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
1,743
2.08
1,010
1.87
5,772
2.08
3,920
1.79
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, 2022
transportation expense was $1.7 million or $2.08/boe compared to $1.0 million or $1.87/boe in the prior year comparative period. On a
twelve month basis, transportation expense totaled $5.8 million, or $2.08/boe for 2022, which is 49% and 16% higher, respectively, than
the $3.9 million of costs incurred (or $1.79/boe) in the prior year. The increase in transportation expense on a per boe basis is due to
higher fuel surcharge and higher trucking costs due to increased fuel prices and volumes.
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:
Page |16
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
1,750
407
223
2,380
(507)
(947)
926
1.10
1,070
491
112
1,673
(289)
(171)
1,213
2.24
4,103
1,733
879
6,715
(1,179)
(2,147)
3,389
1.22
3,529
1,613
688
5,830
(878)
(678)
4,274
1.95
G&A expense (net of capitalized G&A expense and overhead recoveries) for the fourth quarter of 2022 totaled $0.9 million or $1.10/boe,
compared to $1.2 million or $2.24/boe in the fourth quarter of 2021. Gross G&A expense (before capitalized G&A expense and overhead
recoveries) was higher than the the prior year ($2.4 million in the fourth quarter of 2022 compared to $1.7 million in the fourth quarter of
2021) due to increased staffing costs (additional staff required to support capital program).
For the year ended December 31, 2022, net G&A expense was $3.4 million or $1.22/boe which is lower than the $4.3 million or $1.95/boe
for the prior year comparative period (37% decrease on a per boe basis). For the year ended December 31, 2022 gross G&A expense was
$6.7 million compared to $5.8 million in the prior year. The 16% increase is mainly due to increased staffing costs (additional staff required
to support capital program).
Net G&A is lower, on a per boe and total basis, due to the increased overhead recovery related to the higher production and capital activity
in 2022 in comparison to the prior year comparative periods.
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
614
(184)
430
164
(48)
116
1,630
(489)
1,141
355
(96)
259
Share-based compensation expense (net of capitalized portion) was $0.43 million for the fourth quarter of 2022, which is 258% higher than
the $0.12 million recognized in the fourth quarter of the prior year. For the year ended December 31, 2022, net share-based compensation
expense was $1.14 million, which is 340% higher than the $0.26 million in the prior year comparative period. The increase in stock based
compensation expense for the current period and year-end compared to the prior year comparative periods is due to the Company's
improved stock price resulting in higher value of stock options and a higher staffing level.
FINANCE EXPENSE
The following table illustrates the Company’s finance expense which includes cash and non-cash expenses:
Finance Expense ($000s)
Interest expense
Foreign exchange loss (gain)
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
809
—
177
137
—
310
1,433
811
—
45
61
—
198
1,115
2,175
3
993
430
—
1,066
4,667
4,108
—
1,025
365
2,573
707
8,778
Fourth quarter total finance expense was $1.4 million in 2022, comprised of $0.3 million of non-cash accretion of its decommissioning
obligations, $0.14 million of deferred financing costs, $0.8 million of cash interest expense and $0.18 million of finance fees. In the fourth
Page |17
quarter of 2021, the Company incurred total finance expense of $1.1 million, comprised of $0.2 million in non-cash accretion of its
decommissioning obligation, $0.8 million cash interest expense, $0.05 million of finance fees, and $0.06 million of deferred financing fee
amortization. The increase in finance fees in the fourth quarter of 2022 is mainly due to the increase in accretion and finance fees.
The Company incurred total finance expense of $4.7 million for the year ended December 31, 2022, which is 47% lower than the $8.8
million for the prior year. The decrease in total finance expense is due to a lower first lien loan balance throughout 2022 as well as the
elimination of non-cash term loan interest payment-in-kind upon settlement of the term loan in 2021.
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
10,658
12.71
5,508
10.18
33,277
11.99
22,992
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 2022 of $10.7 million or $12.71/boe, compared to the fourth
quarter of 2021, when $5.5 million or $10.18/boe was recorded.
For the year ended December 31, 2022, the Company recorded $33.3 million or $11.99/boe, compared to $23.0 million or $10.43 per boe
for the prior year comparative period.
The increase in the depletion expense for the fourth quarter of 2022 and year ended December 31, 2022 compared to the prior year
comparative periods is due to higher production in 2022.
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
—
—
(103,220)
(103,220)
—
—
(103,220)
(103,220)
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 and Comprehensive Income.
For more information, refer to notes 6 and 7 of the December 31, 2022 audited consolidated financial statements.
Page |18
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, 2022
December 31, 2021
December 31, 2022
December 31, 2021
122,545
127,600
123,239
133,377
8,520
96,660
102,868
96,708
103,889
5,563
115,189
119,525
123,239
133,377
8,520
62,557
65,207
96,708
103,889
5,563
At December 31, 2022, the Company had 123,238,528 common shares and 8,519,709 stock options outstanding. As at the date of this
MD&A, the Company had 123,711,355 common shares and 8,620,017 stock options outstanding.
Deferred share units
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, 2022 and the date of this MD&A, 1,618,702 DSUs were issued and outstanding (December 31, 2021 – 1,618,702). 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.
Rights Offering
During the second quarter of 2022, the Company completed a rights offering (the “Rights Offering”) where the Company issued
approximately 14.8 million common shares at $1.35 per share for aggregate gross proceeds to the Company of approximately $20.0 million.
The issuance costs were estimated to be $0.4 million and the net proceeds of $19.6 million were utilized for debt repayment and towards
working capital.
The Company entered into a standby purchase agreement with each of Don Gray, Stuart Gray and Glen Gray (collectively, the "Stand-By
Guarantors"). The Rights Offering was oversubscribed by 84% and as a result, the Stand-By Guarantors did not acquire any common shares
in connection with the Rights Offering pursuant to their stand-by commitments. The Company had approximately 121.7 million shares
outstanding following the Rights Offering with the Stand-By Guarantors owning approximately 71% of the outstanding shares.
Property Acquisition
During the first quarter of 2022, the Company completed an asset acquisition. The assets were acquired for share consideration of $15.2
million (10 million common shares of Petrus at $1.52 per share on closing date).
Private placement
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.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2022, Petrus had two debt instruments outstanding; a reserve-based, secured operating revolving loan facility with an
Alberta-based financial institution (the “Revolving Loan Facility” or “RLF”) and a second lien secured term facility (the "Second Lien
Facility").
Page |19
Revolving Loan Facility
At December 31, 2022, the RLF was comprised of a $30.0 million operating facility payable on demand by the lender. The amount of the RLF
is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices
estimated by the lenders as well as other factors. The next semi-annual review is due on May 31, 2023.
At December 31, 2022, the Company had a $0.6 million letter of credit outstanding against the RLF (December 31, 2021 – $0.6 million on
the previous revolving credit facility) and had drawn $4.6 million against the RLF (December 31, 2021 – $57.7 million on the previous
revolving credit facility).
Second Lien Facility
At December 31, 2022 the Company had $25.0 million outstanding on the $25 million Second Lien Facility. The Second Lien Facility is a
three-year term facility (maturity date May 31, 2025 with an option to extend by an additional two years) with a fixed interest rate of 11%
per annum and can be repaid at the discretion of the Company after the first year. The Second Lien Facility is a related party transaction
with a major shareholder who owns approximately 21% of the outstanding shares of the Company (see note 20 of the Company's
December 31, 2022 audited consolidated financial statements). The total interest paid in 2022 to the major shareholder, related to the
Second Lien facility, was $1.1 million.
Debt Settlement - Term Loan & Revolving Credit Facility
During 2022, the Company entered into agreements with new lenders to the Company, providing two new credit facilities, as described
above, (the “New Credit Facilities”) totaling $55 million. The New Credit Facilities, together with the net proceeds of the Company's Rights
Offering (described above), were used to repay in full all amounts owing under the Company's previous revolving credit facility. The New
Credit Facilities closed in May 2022.
Prior to December 31, 2021, Petrus had 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 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).
Financial Covenants
The Company's RLF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt
instrument:
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 RLF, 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 key financial covenants as at December 31, 2022 are summarized in the following table. At December 31, 2022 the Company is in
compliance with all financial covenants.
Financial Covenant Description
Working Capital Ratio
Required Ratio
Over 1.0
As at December 31, 2022
1.1
Liquidity
At December 31, 2022, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $26.0
million as the company had $45.2 million in current accounts payable due to the substantial increase in capital activity during the third and
fourth quarters of 2022.
Page |20
Contractual Maturities
The following are the contractual maturities of financial liabilities as at December 31, 2022:
$000s
Accounts payable and accrued liabilities
Bank indebtedness
Lease obligations
Long term debt
Total
Total
45,191
4,606
603
25,000
75,400
< 1 year
45,191
4,606
240
—
50,037
Commitments
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
11,240
< 1 year
2,582
1-5 years
8,658
1-5 years
—
—
363
25,000
25,363
> 5 years
—
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 11 and 16 of the Company’s December 31, 2022 audited consolidated
financial statements.
Page |21
SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)
Dec. 31,
2022
Sept. 30,
2022
Jun. 30,
2022
Mar. 31,
2022
Dec. 31,
2021
Sept. 30,
2021
Jun. 30,
2021
Mar. 31,
2021
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
Loss on risk management activities
Net oil and natural gas revenue
Transportation expense
Operating expense
Operating netback(1)
Realized gain (loss) on financial derivatives
Other income (cash)
General and administrative expense
Cash finance expense
Decommissioning expenditures
Corporate netback and funds flow(1)
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
(1)Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures".
33,201
28,107
30,913
29,530
23,494
23,942
24,291
22,985
2,458
1,121
9,113
957
997
6,639
1,073
1,055
7,280
1,250
1,207
7,379
1,002
962
5,880
937
1,010
5,937
1,214
1,046
6,309
923
1,158
5,912
838,375
610,722
662,456
664,010
540,924
546,227
574,084
532,099
48,590
28,701
42,119
32,940
25,070
20,306
19,553
16,339
(6,636)
(7,228)
(5,721)
(4,576)
(3,429)
(2,150)
(2,794)
(1,989)
(1,056)
(497)
(4,476)
—
—
—
—
—
40,898
20,976
31,922
28,364
21,641
18,156
16,759
14,350
(1,743)
(1,155)
(1,434)
(1,440)
(1,010)
(991)
(1,057)
(863)
(5,753)
(5,171)
(5,249)
(4,492)
(2,715)
(3,042)
(3,903)
(3,254)
33,402
14,650
25,239
22,432
17,916
14,123
11,799
10,233
2,421
186
(926)
(987)
21
610
30
—
28
(4,632)
(5,148)
(3,504)
(1,843)
(1,215)
47
21
12
1,018
23
(793)
(1,127)
(543)
(1,213)
(804)
(1,381)
(876)
(528)
(180)
(969)
(689)
(856)
(1,803)
(1,444)
(1,029)
37
(14)
(302)
(150)
(79)
(143)
34,117
13,789
23,208
16,601
10,418
7,874
8,070
6,993
48,590
28,701
42,119
32,940
25,070
20,306
19,553
16,339
0.40
0.38
0.24
0.23
0.38
0.36
0.33
0.32
0.26
0.24
0.37
0.35
0.39
0.39
0.33
0.33
22,097
9,822
18,046
10,903
114,633
7,343
(4,265)
(3,155)
0.18
0.17
0.08
0.08
0.16
0.15
0.11
0.11
1.19
1.11
0.14
0.13
(0.09)
(0.09)
(0.06)
(0.06)
123,239
122,197
122,017
106,907
96,708
96,603
49,559
49,469
133,377
131,482
131,302
113,883
103,889
100,074
49,559
49,469
122,545
122,058
111,795
99,189
96,660
54,167
49,513
49,469
127,600
126,822
117,203
103,250
102,868
57,638
49,513
49,469
381,057
356,050
302,472
308,744
290,492
173,101
176,629
177,587
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 increased from 5,912 boe/d in the first quarter of 2021 to 9,113 boe/d in the fourth quarter of 2022. The
54% production increase is attributable to Petrus' shift in focus back to production growth and an increased capital program.
Page |22
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, 2022
December 31, 2021
December 31, 2020
152,350
1.32
1.27
60,868
0.49
0.46
123,239
133,377
115,189
119,525
381,057
63,021
81,268
1.30
1.25
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
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, 2022.
Russian/Ukrainian Conflict
In February 2022, Russian military forces invaded Ukraine. The outcome of the ongoing war is uncertain and is likely to have wide-ranging
consequences on the peace and stability of the region and the world economy. In addition, certain countries including Canada, have
imposed strict financial and trade sanctions against Russia which may have far reaching effects on the global economy. Disruption of
supplies of commodities from Russia could have a significant impact on worldwide commodity prices. The long-term impacts of the conflict
and the sanctions imposed on Russia remain uncertain. Any negative impact on economic conditions and global markets from these
developments could adversely affect our business, financial condition and liquidity including our ability to access capital and the related
costs. The Company does not have sales, production, or operations within Russia or Ukraine, and the conflict has not directly impacted its
operations (and is not expected to). Nevertheless, the ongoing war induces greater uncertainties in global financial markets and supply
chain systems which could lead to volatility in oil prices, inflation rates, interest rates, financing costs, and shortage or delays for certain
goods or services. The Company continues assessing its exposure.
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, 2022.
New standards and interpretations
The Company has not adopted any new standards and interpretations for the year ended December 31, 2022.
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
Page |23
Filings (“NI 52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the
Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are being
prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or
submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities
legislation. The Chief Executive Officer and Chief Financial Officer of Petrus have evaluated, or caused to be evaluated under their
supervision, the effectiveness of the Company's DC&P as at December 31, 2022 and have concluded that the Company's DC&P are
effective at December 31, 2022 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, 2022, 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 October 1, 2022 and ended on December 31, 2022 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, 2022. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that as at December 31, 2022, 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" (on an absolute and $/boe basis), "corporate netback" (on an absolute and
$/boe basis), "funds flow" (on an absolute, per share (basic and fully diluted) and $/boe basis) and "net debt". These non-GAAP and other
financial measures are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed by GAAP (IFRS).
Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies.
These non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are
determined in accordance with IFRS as indicators of our performance. Management uses these non-GAAP and other financial measures
for the reasons set forth below.
Operating Netback
Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a useful supplemental
measure to evaluate the specific operating performance by product type at the oil and natural gas lease level. The most directly
comparable GAAP measure to operating netback is oil and natural gas revenue. Operating netback is calculated as oil and natural gas
revenue less royalty expenses, operating expenses, transportation expenses and loss on risk management activities. See below and under
"Summary of Quarterly Results" for a reconciliation of operating netback to oil and natural gas revenue.
Operating netback ($/boe) is a non-GAAP ratio 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 . It is calculated as operating netbacks divided by
weighted average daily production on a per boe basis. See below.
Corporate Netback and Funds Flow
Corporate netback or funds flow 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 and funds flow are used interchangeably. Petrus analyzes these
measures on an absolute value and on a per unit (boe) and per share (basic and fully diluted) basis as non-GAAP ratios. Management
Page |24
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, cash finance
expense, decommissioning expenditures, plus other income and the net realized gain (loss) on financial derivatives and risk management
activities. See below and under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural
gas revenue.
Corporate netback ($/boe) or funds flow ($/boe) is a non-GAAP ratio used in the oil and natural gas industry which evaluates the
Company’s profitability at the corporate level. Management believes that funds flow ($/boe) or corporate netback ($/boe) provide
information to assist a reader in understanding the Company's profitability relative to current commodity prices. It is calculated as
corporate netbacks or funds flow divided by weighted average daily production on a per boe basis. See below.
Funds flow per share (basic and fully diluted) is comprised of funds flow divided by basic or fully diluted weighted average common shares
outstanding.
Oil and natural gas revenue
Royalty expense
Loss on risk management activities
Net oil and natural gas revenue
Transportation expense
Operating expense
Operating netback
Realized gain (loss) on financial derivatives
Other income(1)
General & administrative expense
Cash finance expense(2)
Decommissioning expenditures
Funds flow and corporate netback
Three months ended
Three months ended
Twelve months ended
Twelve months ended
December 31, 2022
December 31, 2021
December 31, 2022
December 31, 2021
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
48,590
57.96
25,070
46.35
152,350
54.89
81,268
(6,636)
(1,056)
(7.92)
(1.26)
(3,429)
(6.34)
(24,161)
(8.70)
(10,361)
—
—
(6,029)
(2.17)
—
40,898
48.78
21,641
40.01
122,160
44.02
70,907
(1,743)
(5,753)
33,402
2,421
186
(926)
(987)
21
34,117
(2.08)
(6.86)
39.84
2.89
0.22
(1.10)
(1.18)
0.03
40.70
(1,010)
(2,715)
17,916
(5,148)
21
(1,213)
(856)
(302)
(1.87)
(5,772)
(2.08)
(3,920)
(5.02)
(20,665)
(7.45)
(12,914)
33.12
(9.52)
0.04
(2.24)
(1.58)
(0.56)
95,723
(1,601)
291
(3,389)
(3,171)
(137)
34.49
(0.58)
0.10
(1.22)
(1.14)
(0.05)
54,073
(11,713)
1,075
(4,274)
(5,133)
(674)
10,418
19.26
87,716
31.60
33,354
37.04
(4.72)
—
32.32
(1.79)
(5.89)
24.64
(5.34)
0.49
(1.95)
(2.34)
(0.31)
15.19
(1)Excludes non-cash government grant related to decommissioning expenditures.
(2)Excludes non-cash Term Loan interest payment-in-kind.
Net Debt
Net debt is a non-GAAP financial measure and is calculated as the sum of long term debt and working capital (current assets and current
liabilities), excluding the current financial derivative contracts and current portion of the lease obligation. Petrus uses net debt as a key
indicator of its leverage and strength of its balance sheet. Net debt is reconciled, in the table below, to long-term debt which is the most
directly comparable GAAP measure.
($000s)
Long-term debt
Current assets
Current liabilities
Current financial derivatives
Current portion of lease obligation
Net debt
As at December 31, 2022 As at September 30, 2022
As at June 30, 2022
As at March 31, 2022
25,000
(29,849)
51,395
4,502
(240)
50,808
22,000
(29,905)
51,102
5,503
(235)
48,465
12,000
(18,783)
18,785
2,124
(231)
13,895
—
(17,356)
67,625
—
(225)
50,044
Net debt to funds flow ratio is a non-GAAP ratio used as a key indicator of our leverage and strength of our balance sheet. It is calculated as
net debt divided by funds flow for the relevant period.
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2022, 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, which will be filed on SEDAR at www.sedar.com.
Page |25
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.
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 audited consolidated financial statements as at and for the twelve months ended December 31,
2022. 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, 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: the Company's
risk management and hedging strategy and its objectives, including our ability to mitigate commodity price risk and provide stability and
sustainability to our economic returns, funds flow and capital development plan; our belief that our risk management contracts are
effective economic hedges of our underlying business transactions; that our risk management contracts provide protection from significant
changes in crude oil and natural gas commodity prices for 2023 and 2024; and the Company's intention not to settle its DSUs for cash. 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; industry conditions;
currency fluctuation; changes in interest rates and inflation rates; 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; and the other risks and uncertainties described in the AIF. 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; 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; the effects of inflation on our profitability; future interest rates; 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 investors 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.
These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any
forward-looking statements, 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
Page |26
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
mbbl
bbl/d
boe
mboe
mmboe
boe/d
GJ
GJ/d
mcf
mcf/d
mmcf/d
bcf
NGLs
WTI
thousand dollars
dollars per barrel
dollars per barrel of oil equivalent
dollars per gigajoule
dollars per thousand cubic feet
barrel
thousand 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
billion cubic feet
natural gas liquids
West Texas Intermediate
Page |27
CONSOLIDATED ANNUAL FINANCIAL STATEMENTS
As at and for the years ended December 31, 2022 and 2021
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, 2022 and 2021, and the consolidated
statements of net income and comprehensive income, 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, 2022 and 2021, 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.
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. 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, 2022, the carrying values of
PP&E and E&E assets were $315.8 million and
$34.8 million, respectively. Refer to Note 7 and 6
of the consolidated financial statements for the
Company’s PP&E and E&E disclosures,
respectively, and Note 3 for Company’s policy on
impairment assessment. Cash-generating units
(“CGUs”) are assessed by management for
indicators of impairment or impairment reversal at
each reporting date. The Company concluded that
no indicators of impairment or impairment reversal
were present as at December 31, 2022.
To test the Company's assessment of indicators of
impairment or impairment reversal, we performed the
following procedures, among others:
- Evaluated the impact of the change in observable
forecasted commodity prices relative to prices
used in previous impairment test.
- Assessed the competency and objectivity of the
Company’s external reserve engineer.
- Compared significant reserve report data to
historical results, third party sources, and the
Company’s development plan.
Auditing the Company’s assessment of indicators
of impairment or impairment reversal involved
significant judgement due to forecast commodity
prices and increase in the market interest rates.
- We involved our valuation specialists to assist in
evaluating discount rates and cash flow multiples
for certain CGU’s based on observable market
inputs and recent comparable transactions
- Assessed the market capitalization of the
Company against its net book value and
investigated any contrary information.
- Evaluated the adequacy of the disclosure
included in Note 6 & 7 of the accompanying
consolidated financial statements in relation to
this matter.
Other Information
Management is responsible for the other information. The other information comprises:
• 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:
•
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.
• 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.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by management.
• Conclude on the appropriateness of management’s use of the going concern basis of accounting and,
based on the audit evidence obtained, whether a material uncertainty exists related to events or
conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If
we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s
report to the related disclosures in the consolidated financial statements or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to
the date of our auditor’s report. However, future events or conditions may cause the Company to
cease to continue as a going concern.
• Evaluate the overall presentation, structure and content of the consolidated financial statements,
including the disclosures, and whether the consolidated financial statements represent the underlying
transactions and events in a manner that achieves fair presentation.
We communicate with those charged with governance regarding, among other matters, the planned
scope and timing of the audit and significant audit findings, including any significant deficiencies in
internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant
ethical requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
From the matters communicated with those charged with governance, we determine those matters that
were of most significance in the audit of the consolidated financial statements of the current period and
are therefore the key audit matters. We describe these matters in our auditor’s report unless law or
regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we
determine that a matter should not be communicated in our report because the adverse consequences of
doing so would reasonably be expected to outweigh the public interest benefits of such communication.
The engagement partner on the audit resulting in this independent auditor’s report is Ryan MacDonald.
Ernst & Young LLP
Chartered Professional Accountants
Calgary, Canada
March 14, 2023
CONSOLIDATED BALANCE SHEETS
(Presented in 000’s of Canadian dollars)
As at
December 31, 2022
December 31, 2021
ASSETS
Current
Cash
Inventory (note 24)
Deposits and prepaid expenses (note 25)
Accounts receivable (note 16)
Risk management asset (note 11)
Total current assets
Non-current
Risk management asset (note 11)
Exploration and evaluation assets (note 6)
Property, plant and equipment (note 7)
Total non-current assets
Total assets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank loan (note 8)
Accounts payable and accrued liabilities (note 16)
Risk management liability (note 11)
Decommissioning obligation (note 10)
Lease obligations (note 9)
Total current liabilities
Non-current liabilities
Long term debt (note 8)
Lease obligations (note 9)
Decommissioning obligation (note 10)
Total liabilities
Shareholders’ equity
Share capital (note 12)
Contributed surplus
Deficit
Total shareholders' equity
Total liabilities and shareholders' equity
Commitments and contingencies (note 20)
Related party transactions (note 22)
See accompanying notes to the consolidated financial statements
Approved by the Board of Directors,
(signed) “Don T. Gray”
Don T. Gray
Chairman
40
1,197
1,862
22,248
4,502
29,849
619
34,837
315,752
351,208
381,057
4,607
45,191
—
1,357
240
51,395
25,000
363
37,658
114,416
492,241
29,061
(254,661)
266,641
381,057
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
(signed) “Donald Cormack”
Donald Cormack
Director
Page |33
CONSOLIDATED STATEMENTS OF NET INCOME AND COMPREHENSIVE INCOME
(Presented in 000’s of Canadian dollars, except per share amounts)
REVENUE
Oil and natural gas revenue (note 21)
Royalty expense
Loss on risk management activities (notes 11 and 21)
Net oil and natural gas revenue
Other income (note 26)
Net gain (loss) on financial derivatives (note 11)
Total income
EXPENSES
Operating (note 14)
Transportation
General and administrative (note 15)
Share-based compensation (note 12)
Finance (note 18)
Exploration and evaluation (note 6)
Depletion and depreciation (note 7)
Gain on sale of assets
Impairment (reversal) (notes 6 and 7)
Total expenses
INCOME BEFORE INCOME TAX
Income tax recovery (note 23)
NET INCOME AND COMPREHENSIVE INCOME
Net income per common share
Basic (note 13)
Diluted (note 13)
See accompanying notes to the consolidated financial statements
Year ended
Year ended
December 31, 2022
December 31, 2021
152,350
(24,161)
(6,029)
122,160
1,351
6,008
129,519
20,665
5,772
3,389
1,141
4,667
421
33,277
(681)
—
68,651
60,868
—
60,868
0.53
0.51
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
Page |34
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Presented in 000’s of Canadian dollars)
Balance, December 31, 2020
Net income
Deferred Share Unit settlement
Issuance of common shares
Share issue costs
Share-based compensation
Balance, December 31, 2021
Net income
Common shares issued for property acquisition (note 5)
Common shares issued for rights offering (note 12)
Issuance of common shares (note 12)
Share issue costs (note 12)
Share-based compensation (note 12)
Balance, December 31, 2022
See accompanying notes to the consolidated financial statements
Share
Capital
430,119
—
—
25,900
(111)
—
455,908
—
15,200
20,003
1,427
(297)
—
492,241
Contributed
Surplus
9,596
—
(223)
18,119
—
354
27,846
—
—
—
(415)
—
1,630
29,061
Deficit
(430,085)
114,556
—
—
—
—
(315,529)
60,868
—
—
—
—
—
(254,661)
Total
9,630
114,556
(223)
44,019
(111)
354
168,225
60,868
15,200
20,003
1,012
(297)
1,630
266,641
Page |35
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Presented in 000’s of Canadian dollars)
OPERATING ACTIVITIES
Net income
Adjust items not affecting cash:
Share-based compensation (note 12)
Unrealized (gain) loss on financial derivatives (note 11)
Non-cash finance expenses (note 18)
Non-cash term loan interest payment-in-kind (note 18)
Depletion and depreciation (note 7)
Impairment (reversal) (notes 6 and 7)
Exploration and evaluation expense (note 6)
Gain on sale of assets (note 7)
Recovery of income taxes on debt settlement (note 23)
Other income (note 21)
Decommissioning expenditures (note 10)
Funds flow
Change in operating non-cash working capital (note 19)
Cash flows from operating activities
FINANCING ACTIVITIES
Deferred Share Unit payment (note 12)
Issuance of shares (note 12)
Repayment of revolving credit facility
Repayment of bank indebtedness
Transaction costs on debt
Repayment of lease liabilities (note 9)
Proceeds from long term debt (note 8)
Change in financing non-cash working capital (note 19)
Cash flows used in financing activities
INVESTING ACTIVITIES
Property and equipment acquisitions (note 7)
Property and equipment dispositions (note 7)
Exploration and evaluation asset expenditures (note 6)
Petroleum and natural gas property expenditures (note 7)
Other capital expenditures
Change in investing non-cash working capital (note 19)
Cash flows used in investing activities
Increase (decrease) in cash
Cash, beginning of year
Cash, end of year
Cash interest paid (note 18)
See accompanying notes to the consolidated financial statements
Page |36
Year ended
Year ended
December 31, 2022
December 31, 2021
60,868
1,141
(7,609)
1,496
—
33,277
—
421
(681)
—
(1,060)
(137)
87,716
12,891
100,607
—
21,132
(53,094)
—
(518)
(217)
25,000
—
(7,697)
243
—
(1,645)
(94,921)
(175)
(1,300)
(97,798)
(4,888)
4,928
40
3,171
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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2022 and 2021
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, 2022 and 2021, were approved by the Company’s Audit Committee and Board
of Directors on March 14, 2023.
2. BASIS OF PRESENTATION
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
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
Page |37
iii.
iv.
v.
vi.
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.
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.
Business Combinations
The acquisition method of accounting is used to account for acquisitions of entities and assets that meet the definition of a business under IFRS.
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the
acquisition date. The excess of the cost of acquisition over the fair value of the identifiable assets acquired and liabilities and contingent liabilities
assumed is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized
immediately in profit or loss. Business combination associated transaction costs are expensed when incurred.
Within the IFRS Business Combinations guidance, there is an optional fair value concentration test. The concentration test is a simplified assessment that
results in an asset acquisition if substantially all of the fair value of the gross assets is concentrated in a single identifiable asset or a group of similar
identifiable assets. If an entity chooses not to apply the concentration test, or the test is failed, then the assessment focuses on the existence of a
substantive process, and the acquisition is accounted for as a business combination. The cost of an acquisition that does not meet the definition of a
business under IFRS and does not qualify as a business combination is measured as the fair value of the consideration given and liabilities incurred or
assumed at the date of exchange. No goodwill arises on an asset acquisition and the cost of the assets acquired and liabilities assumed are allocated to
the assets and liabilities on the basis of their relative fair values at the date of purchase. Asset acquisition associated transaction costs are capitalized as a
cost of the acquisition.
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.
Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss).
Page |38
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 net
income or net 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.
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
Page |39
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
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.
Page |40
(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.
(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 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.
Carbon credits
Carbon credits that are held for sale in the ordinary course of business are recognized as inventory in the year credits are verified and are measured at
the lower of cost or net realizable value. The cost of emission credits is determined at the market value of the credits in the year credits are verified.
Upon sale of the carbon credits, the carrying amount is derecognized from inventory on the Consolidated Balance Sheet, recording any gain or loss on
the Statements of Net Income and Comprehensive Income.
Page |41
(o) New standards and interpretations
IFRS 17 Insurance Contracts
IFRS 17 requires insurance liabilities to be measured at a current fulfillment value and provides a more uniform measurement and presentation
approach for all insurance contracts. These requirements are designed to achieve the goal of a consistent, principle-based accounting for insurance
contracts. IFRS 17 supersedes IFRS 4 Insurance Contracts as of January 1, 2023.
Amendments to IAS 1
On October 31, 2022, the International Accounting Standards Board (IASB) published "Non-current Liabilities with Covenants (Amendments to IAS 1)" to
clarify how conditions with which an entity must comply within twelve months after the reporting period affect the classification of a liability. The
amendments are effective for reporting periods beginning on or after January 1, 2024.
The Company does not expect any impact to the financial statements due to these amendments.
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.
5. ACQUISITIONS
On March 14, 2022, Petrus completed the acquisition of certain oil and liquids rich natural gas weighted properties within its Ferrier core area from a
privately owned limited partnership and its general partner. The acquired partnership was managed and directed by an officer and director of Petrus and
two of Petrus' major shareholders owned or controlled, in aggregate, approximately 69.5% and 50% of the acquired partnership's units and shares,
respectively.
Page |42
Given the close proximity of the acquired properties to the Company's existing assets and infrastructure, the acquired properties are synergistic to existing
operations and complementary to current development plans. The assets were acquired for share consideration of $15.2 million (10 million common shares
of Petrus at $1.52 per share on closing date). The Company applied the optional concentration test permitted under IFRS 3 to the acquisition which resulted
in the acquired assets being accounted for as an asset acquisition. As such the purchase price was allocated to the identifiable assets and liabilities based on
their relative fair values at the date of acquisition. Assets acquired in the transaction will be included in the Ferrier CGU. Asset acquisition transaction costs
of $0.3 million were capitalized as a cost of the asset.
The amounts recognized on the date of acquisition to identifiable net assets were as follows:
$000s (except share and per share amounts)
Net assets acquired:
Cash & cash equivalents
Accounts receivable & other assets
Accounts payable & accrued liabilities
Property, plant and equipment
Decommissioning obligation
Net assets acquired
Purchase consideration:
Common shares issued to partners
Price of Petrus common shares ($ per share) on close date
Total purchase consideration
6. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s exploration and evaluation ("E&E") assets are as follows:
$000s
Balance, December 31, 2020
Additions
Disposition
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation
Transfers to property, plant and equipment (note 7)
Impairment reversal
Balance, December 31, 2021
Acquisitions
Exploration and evaluation expense
Capitalized G&A
Capitalized share-based compensation (note 12)
Transfers to property, plant and equipment (note 7)
Balance, December 31, 2022
434
496
(406)
16,765
(2,089)
15,200
10,000,000
$1.52
15,200
17,568
401
(18)
(108)
220
24
(5,093)
22,640
35,634
1,349
(421)
295
122
(2,142)
34,837
During the year ended December 31, 2022, the Company incurred exploration and evaluation expense of $0.4 million which relates to expired and nearly
expired undeveloped, non-core land (year ended December 31, 2021 – $0.11 million).
During the year ended December 31, 2022, the Company capitalized $0.3 million of general and administrative expenses (“G&A”) (year ended December 31,
2021 – $0.2 million) and $0.12 million of non-cash share-based compensation directly attributable to exploration activities (year ended December 31, 2021
– $0.02 million).
During the year ended December 31, 2022, the Company transferred $2.1 million from E&E assets to PP&E assets, related to the Ferrier and North Ferrier
Cash Generating Units ("CGUs").
At December 31, 2022, the Company did not identify any indicators of impairment or impairment reversals, related to its E&E assets, in any of its CGUs.
Page |43
2021 Impairment Reversal
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. The impairment reversal amount reflects all of the original impairment charges
recorded on March 31, 2020 and December 31, 2014, less associated depletion. No impairment or impairment reversal for E&E assets was recorded on
other CGUs of the Company.
7. PROPERTY, PLANT AND EQUIPMENT
The components of the Company’s property, plant and equipment ("PP&E") assets are as follows:
$000s
Balance, December 31, 2020
Additions
Property dispositions
Capitalized G&A
Capitalized share based compensation
Transfer from exploration and evaluation assets (note 6)
Depletion & depreciation
Increase in decommissioning expenses
Impairment reversal
Balance, December 31, 2021
Additions
Property acquisition (note 5)
Property dispositions
Capitalized G&A
Capitalized share-based compensation (note 12)
Transfers from exploration and evaluation assets (note 6)
Depletion & depreciation
Changes in decommissioning provision (note 10)
Balance, December 31, 2022
Cost
835,583
25,593
(14,495)
658
73
5,093
—
329
—
852,834
94,145
16,765
(71)
884
367
2,142
—
(4,450)
962,616
Accumulated
DD&A
(683,614)
—
12,439
—
—
—
(22,992)
—
80,580
(613,587)
—
—
—
—
—
—
(33,277)
—
(646,864)
Net book value
151,969
25,593
(2,056)
658
73
5,093
(22,992)
329
80,580
239,247
94,145
16,765
(71)
884
367
2,142
(33,277)
(4,450)
315,752
At December 31, 2022, estimated future development costs of $519.8 million (December 31, 2021 – $343.5 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, 2022, the
Company capitalized $0.9 million of general and administrative expenses (“G&A”) (year ended December 31, 2021 – $0.7 million) and non-cash share-based
compensation of $0.37 million (year ended December 31, 2021 – $0.07 million), directly attributable to development activities.
During the year ended December 31, 2022, the Company recorded a gain of $0.7 million on the disposition of certain PP&E assets in the Foothills and
Central Alberta CGUs related to the disposal of ARO associated with these assets.
During the year ended December 31, 2022, the Company transferred $2.1 million from E&E assets to PP&E assets, related to the Ferrier and North Ferrier
CGUs.
During 2022, Petrus recorded minor disposition transactions for petroleum and natural gas properties and equipment for total net cash consideration of
$0.07 million.
At December 31, 2022, the carrying balance of the right of use asset was $0.5 million.
At December 31, 2022, the Company did not identify any indicators of impairment or impairment reversals, related to its PP&E assets, in any of its CGUs.
2021 Impairment Reversal
At December 31, 2021, in its Ferrier CGU, the Company identified an 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 indicators of impairment or impairment reversal.
Page |44
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 used the following forward commodity price estimates:
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.
8. DEBT
At December 31, 2022, Petrus had two debt instruments outstanding; a reserve-based, secured operating revolving loan facility with an Alberta-based
financial institution (the “Revolving Loan Facility” or “RLF”) and a second lien secured term facility (the "Second Lien Facility").
Revolving Loan Facility
At December 31, 2022, the RLF was comprised of a $30.0 million operating facility payable on demand by the lender. The amount of the RLF is subject to a
borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices estimated by the lenders as well
as other factors. The next semi-annual review is due on May 31, 2023.
At December 31, 2022, the Company had a $0.6 million letter of credit outstanding against the RLF (December 31, 2021 – $0.6 million on the previous
revolving credit facility) and had drawn $4.6 million against the RLF (December 31, 2021 – $57.7 million on the previous revolving credit facility).
Second Lien Facility
At December 31, 2022 the Company had $25.0 million outstanding on the $25 million Second Lien Facility. The Second Lien Facility is a three-year term
facility (maturity date May 31, 2025 with an option to the borrower to extend by an additional two years) with a fixed interest rate of 11% per annum and
can be repaid at the discretion of the Company after the first year. The Second Lien Facility is a related party transaction with a major shareholder who owns
approximately 21% of the outstanding shares of the Company (see note 22). The total interest paid in 2022 to the major shareholder, related to the Second
Lien facility, was $1.1 million.
Debt Settlement - Term Loan & Revolving Credit Facility
During 2022, the Company entered into agreements with new lenders to the Company, providing two new credit facilities, as described above, (the “New
Credit Facilities”) totaling $55 million. The New Credit Facilities, together with the net proceeds of the Company's recently closed $20 million rights offering,
were used to repay in full all amounts owing under the Company's previous revolving credit facility (the "Revolving Credit Facility" or "RCF"). The New
Credit Facilities closed in May 2022.
Prior to December 31, 2021, Petrus had 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 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).
Financial Covenants
The Company's RLF is subject to certain financial covenants. The following definitions are used in the covenant calculations for the debt instrument:
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 RLF, 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.
Page |45
The key financial covenants as at December 31, 2022 are summarized in the following table. At December 31, 2022 the Company is in compliance with all
financial covenants.
Financial Covenant Description
Working Capital Ratio
9. LEASES
The Company's lease obligations are as follows:
$000s
Balance, December 31, 2021
Finance expense
Lease payments
Balance, December 31, 2022
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
10. DECOMMISSIONING OBLIGATION
Required Ratio
Over 1.0
As at December 31, 2022
1.1
820
54
(271)
603
As at December 31, 2022
277
369
646
(43)
603
240
363
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 3.31 percent and an inflation rate of 3.00 percent (1.66 percent and 2.0 percent, respectively, at December 31, 2021).
Changes in estimates in 2021 and 2022 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 $39.0 million as at December 31, 2022
($41.6 million at December 31, 2021). The undiscounted, uninflated total future liability at December 31, 2022 is $41.7 million ($38.3 million at
December 31, 2021). The payments are expected to be incurred over the operating lives of the assets.
The following table reconciles the decommissioning liability:
$000s
Balance, December 31, 2020
Property dispositions
Other adjustments
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2021
Property acquisitions (note 3)
Property dispositions
Other adjustments
Liabilities incurred
Liabilities settled
Change in estimates
Accretion expense
Balance, December 31, 2022
Page |46
44,456
(2,876)
(373)
489
(674)
(160)
707
41,569
2,089
(681)
(441)
1,231
(137)
(5,681)
1,066
39,015
11. FINANCIAL RISK MANAGEMENT
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table
summarizes the financial derivative contracts Petrus had outstanding as at December 31, 2022:
Contract Period
Natural Gas Swaps
Jan. 1, 2023 to Mar. 31, 2023
Apr. 1, 2023 to Oct. 31, 2023
Nov. 1, 2023 to Mar. 31, 2024
Apr. 1, 2024 to Oct. 31, 2024
Contract Period
Crude Oil Swaps
Jan 1, 2023 to Jun 30, 2023
Jan. 1, 2023 to Dec 31 2023
Jul. 1, 2023 to Dec 31 2023
Oct. 1, 2023 to Dec 31, 2023
Jan. 1 2024 to Jun 30, 2024
Contract Period
Crude Oil Collars
Jan. 1 2023 to Dec 31, 2023
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Fixed price
Fixed price
Fixed price
Fixed price
6,000
13,000
11,000
3,000
$6.67
$4.35
$4.91
$3.52
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Fixed price
Fixed price
Fixed price
Fixed price
Fixed price
600
200
500
100
800
$110.57
$104.15
$101.94
$102.15
$99.83
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Costless collar
300
$90.00-120.95
The following table summarizes the physical commodity contracts in place at December 31, 2022:
Contract Period
Natural Gas
Jan. 1, 2023 to Mar. 31, 2023
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Fixed price
14,000
$4.25
During the year ended December 31, 2022, the Company realized a loss on risk management activities of $6.0 million (year ended December 31, 2021 - nil).
Risk management asset and liability:
$000s At December 31, 2022
Current commodity derivatives
Non-current commodity derivatives
$000s At December 31, 2021
Current commodity derivatives
Non-current commodity derivatives
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s
Realized loss on financial derivatives
Unrealized gain (loss) on financial derivatives
Net gain (loss) on financial derivatives
Asset
4,502
619
5,121
—
—
—
Liability
—
—
—
2,488
—
2,488
Year ended
Year ended
December 31, 2022
(1,601)
7,609
6,008
December 31, 2021
(11,713)
(2,409)
(14,122)
Page |47
12. SHARE CAPITAL
Authorized
The authorized share capital consists of an unlimited number of common voting shares without par value and an unlimited number of preferred shares.
Issued and Outstanding
Common shares ($000s except number of shares)
Balance, December 31, 2021
Common shares issued for property acquisition
Common shares issued in a rights offering
Common shares issued on exercise of stock options
Share issue costs
Balance, December 31, 2022
Number of shares
96,707,912
10,000,000
14,817,347
1,713,269
—
123,238,528
Amount
455,908
15,200
20,003
1,427
(297)
492,241
Rights Offering
During the year ended December 31, 2022, the Company completed a rights offering (the “Offering”). Pursuant to the Offering, the Company issued 14.8
million common shares at $1.35 per share for aggregate gross proceeds to the Company of $20.0 million. The issuance costs were $0.3 million and the net
proceeds of $19.6 million were utilized for debt repayment and towards working capital.
The Company entered into a standby purchase agreement with three investors (collectively, the "Stand-By Guarantors") who each own more than 20% of
the outstanding shares of the Company. As a result of the exercise of the basic subscription privilege and additional subscription privilege by the holders of
rights (including the Stand-By Guarantors), the Stand-By Guarantors did not acquire any Common Shares in connection with the Rights Offering pursuant to
their stand-by commitments. The basic and additional subscriptions totaled 184% of the common shares of the Company available through the Rights
Offering. The Company had approximately 121.7 million shares outstanding following the rights offering with the Stand-By Guarantors owning
approximately 71% of the outstanding shares.
Property Acquisition
During the first quarter of 2022, the Company completed an asset acquisition. The assets were acquired for share consideration of $15.2 million (10 million
common shares of Petrus at $1.52 per share on closing date).
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, 2022, 8,519,709 (December 31, 2021 – 5,562,549) stock options were outstanding. The summary of stock option activity is presented
below:
Balance, December 31, 2020
Granted
Forfeited
Expired
Exercised
Balance, December 31, 2021
Granted
Expired
Exercised
Balance, December 31, 2022
Exercisable, December 31, 2022
Number of stock
options
2,276,923
4,637,500
(623,513)
(198,780)
(529,581)
5,562,549
4,677,500
(7,071)
(1,713,269)
8,519,709
498,958
Weighted average
exercise price
$0.40
$0.75
$0.36
$1.68
$0.28
$0.67
$2.27
$0.74
$0.60
$1.56
$0.64
Page |48
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 - $0.89
$1.78
$2.25
$2.81
Number granted
Weighted average
exercise price
Weighted average
remaining life (years)
392,204
2,653,335
796,670
1,020,000
2,602,500
1,055,000
8,519,709
$0.24
$0.71
$0.89
$1.78
$2.25
$2.81
$1.56
0.6
1.8
2.0
2.8
2.5
3.0
2.3
During the year ended December 31, 2022, the Company granted 4,677,500 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, 2022 of $0.91 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 (%)
2022
2.46% - 4.34%
1.08 - 3.25
100% to 113%
33 %
— %
2021
0.15% - 0.49%
1.08 - 3.08
100% to 113%
33 %
— %
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, 2022, 1,618,702 DSUs were issued and outstanding (December 31, 2021 – 1,618,702).
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
Total share-based compensation
13. EARNINGS PER SHARE
Year ended
Year ended
December 31, 2022
1,141
122
367
1,630
December 31, 2021
259
24
73
356
Earnings per share amounts are calculated by dividing the net income for the period attributable to the common shareholders of the Company by the
weighted average number of common shares outstanding during the period.
Page |49
Net income for the year ($000s)
Weighted average number of common shares – basic (000s)
Weighted average number of common shares – diluted (000s)
Net income per common share – basic
Net income per common share – diluted
Year ended
Year ended
December 31, 2022
60,868
115,189
119,525
$0.53
$0.51
December 31, 2021
114,556
62,557
65,207
$1.83
$1.76
In computing diluted earnings per share for the year ended December 31, 2022, 8,519,709 outstanding stock options and 1,618,702 DSUs were considered
(December 31, 2021 – 5,562,549 and 1,618,702 respectively). 2,717,962 stock options and 1,618,702 DSUs were included in calculating the number of
diluted common shares. There were 5,801,747 stock options that were anti-dilutive as the exercise price was higher than the average share price during the
year ended December 31, 2022.
14. 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
15. 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
16. FINANCIAL INSTRUMENTS
Risks associated with financial instruments
Year ended
Year ended
December 31, 2022
16,954
December 31, 2021
11,134
4,853
21,807
(1,142)
20,665
2,719
13,853
(939)
12,914
Year ended
Year ended
December 31, 2022
6,715
(1,179)
(2,147)
December 31, 2021
5,830
(878)
(678)
3,389
4,274
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 $22.2 million of accounts receivable outstanding
at December 31, 2022 (December 31, 2021 – $9.7 million), $15.3 million is owed from 2 parties (December 31, 2021 – $7.4 million from 3 parties), and the
balances were received subsequent to December 31, 2022. At December 31, 2022, the Company had an allowance for doubtful accounts of $0.1 million
(December 31, 2021 – $0.5 million). The Company considers accounts receivable outstanding past 120 days to be 'past due'. At December 31, 2022, 99.8%
of Petrus’ accounts receivable were aged less than 120 days and 0.2% 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, 2022, the Company had a $30.0 million RLF, of which $4.6 million was drawn (December 31, 2021 – $57.7 million on the previous RCF
which has been repaid in full). For the year ended December 31, 2022, the Company generated cash flow from operating activities of $100.6 million.
During the year ended December 31, 2022, the Company entered into agreements with new lenders and repaid the previous RCF in full (see note 8).
Page |50
The following are the contractual maturities of financial liabilities as at December 31, 2022:
$000s
Accounts payable and accrued liabilities
Bank indebtedness
Lease obligations (discounted)
Long term debt
Total
Total
45,191
4,606
603
25,000
75,400
< 1 year
45,191
4,606
240
—
50,037
1-5 years
—
—
363
25,000
25,363
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 RLF 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. A 1% increase in the Canadian prime interest rate during the year ended December 31, 2022 would have decreased net income by approximately $0.3
million, which relates to interest expense on the average outstanding RLF, assuming that all other variables remain constant (December 31, 2021 – $0.8
million). A 1% decrease in the Canadian prime interest rate during the year would result in an opposite impact on net income for 2022 and 2021.
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 11). 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, 2022, it was estimated that a $0.25/GJ decrease in the price of natural gas would have increased net income by $1.4 million
(December 31, 2021 – $0.2 million). An opposite change in commodity prices would result in an opposite impact on net income for the period. As at
December 31, 2022, it was estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased net income by $3.1 million (December 31,
2021 – $0.3 million). An opposite change in commodity prices would result in an opposite impact on net income for the period.
17. 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.
18. FINANCE EXPENSES
The components of finance expenses are as follows:
$000s
Cash:
Interest and finance fees
Finance fees
Foreign exchange
Total cash finance expenses
Non-cash:
Deferred financing costs
Non-cash term loan interest payment-in-kind
Accretion on decommissioning obligations (note 10)
Total non-cash finance expenses
Total finance expenses
Year ended
Year ended
December 31, 2022
December 31, 2021
2,175
993
3
3,171
430
—
1,066
1,496
4,667
4,108
1,025
—
5,133
365
2,573
707
3,645
8,778
Page |51
19. 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
Inventory and others
Accounts receivable
Accounts payable and accrued liabilities
Operating activities
Financing activities
Investing activities
Year ended
Year ended
December 31, 2022
December 31, 2021
(362)
(518)
(515)
(12,515)
25,501
11,591
12,891
—
(1,300)
199
(178)
—
(3,455)
11,982
8,548
(366)
(179)
9,089
The following table reconciles the changes in liability resulting from financing activities:
$000s
Balance, December 31, 2021
Cash flows
Balance, December 31, 2022
Bank Indebtedness
Revolving Credit
Facility
Term Loan
Total Liabilities from
Financing Activities
—
—
—
57,700
(53,093)
4,607
—
—
—
57,700
(28,093)
29,607
20. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
The commitments for which the Company is responsible are as follows:
$000s
Firm service transportation
Total
11,240
< 1 year
2,582
1-5 years
8,658
> 5 years
—
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.
21. REVENUE
The following table presents Petrus' oil and natural gas revenue disaggregated by product type:
$000s
Production & royalty revenue
Oil and condensate sales
Natural gas sales
Natural gas liquids sales
Royalty revenue
Total oil and natural gas revenue
Royalty expense
Loss on risk management activities
Net oil and natural gas revenue
22. RELATED PARTY TRANSACTIONS
Page |52
Year ended
Year ended
December 31, 2022
December 31, 2021
59,348
67,025
25,267
710
152,350
(24,161)
(6,029)
122,160
29,322
34,833
16,793
320
81,268
(10,361)
—
70,907
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
Year ended
Year ended
December 31, 2022
1,245
December 31, 2021
1,307
445
1,690
85
1,392
During the year ended December 31, 2022, the Company completed its debt restructuring transactions, which included the Second Lien Facility in the form
of a promissory note held by a major shareholder, owning approximately 21% of the outstanding shares of the Company (see note 8).
During the year ended December 31, 2022, the Company closed an asset acquisition that was considered a related party transaction (see note 5).
During the year ended December 31, 2022, the Company entered into a standby purchase agreement with three investors (collectively, the "Stand-By
Guarantors") who each own more than 20% of the outstanding shares of the Company. The Company entered into a standby purchase agreement with each
of Don Gray, Stuart Gray and Glen Gray (collectively, the "Stand-By Guarantors"). The Rights Offering was oversubscribed by 84% and as a result, the Stand-
By Guarantors did not acquire any Common Shares in connection with the Rights Offering pursuant to their stand-by commitments. The Company had
approximately 121.7 million share outstanding following the Rights Offering with the Stand-By Guarantors owning approximately 71% of the outstanding
shares.
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.
23. DEFERRED INCOME TAXES
$000s
Income 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
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, 2022 and 2021 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
Year ended
Year ended
December 31, 2022
December 31, 2021
60,868
23.0 %
14,000
1
306
(80)
1,059
(15,286)
—
— %
2022
27,439
(8,661)
(184)
(19,771)
1,178
—
109,132
23.0 %
25,100
1
82
—
1,615
(32,222)
(5,424)
(5) %
2021
19,116
(9,561)
—
(8,983)
(572)
—
The company has unrecognized deductible temporary differences in the form of non-capital loss carry-forward of approximately $120.7 million (2021 -
$224.8 million). The Company had non-capital losses of approximately $206.7 million (2021 – $263.9 million) which may be applied against future income
for Canadian tax purposes. These non-capital losses expire in 2028 and onwards.
Page |53
At December 31, 2022, the Company has determined it is currently not probable that future taxable profits will be available against which the tax benefits
will be utilized.
24. INVENTORY
The components of the Company’s inventory at December 31, 2022 and 2021 are as follows:
$000s
Oil and gas equipment inventory
Carbon credits
Inventory
25. DEPOSITS AND PREPAID EXPENSES
The components of the Company’s deposits and prepaid expenses as at December 31, 2022 and 2021 are as follows:
2022
578
619
1,197
2022
229
414
19
172
1,028
1,862
2021
—
—
—
2021
150
12
18
118
652
950
Year ended
Year ended
December 31, 2022
619
441
291
December 31, 2021
—
—
1,448
1,351
1,448
$000s
Prepaid interest and bank fees
Prepaid insurance
Prepaid operating expenses
Prepaid software
Deposits
Deposits and prepaid expenses
26. OTHER INCOME
The following table presents Petrus' other income by category:
$000s
Carbon credits
Government grant for decommissioning activities
Other
Other income
During the year ended December 31, 2021, the Company recorded $1.4 million as other income. The amount was related to the settlement of an
outstanding dispute associated with the transportation and marketing of condensate volume in the Company's Ferrier area.
Page |54
CORPORATE INFORMATION
OFFICERS & VICE PRESIDENTS
DIRECTORS
SOLICITOR
OFFICERS
Ken Gray, P.Eng
President and
Chief Executive Officer
DIRECTORS
Don T. Gray
Chairman
Scottsdale, Arizona
Mathew Wong, CPA, CFA, CPA (WA, USA)
Chief Financial Officer
Ken Gray
Calgary, Alberta
Matt Skanderup
Chief Operating Officer
Lindsay Hatcher
Vice President, Commercial & Corporate
Development
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
ATB Financial
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
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