PETRUS RESOURCES LTD.
ANNUAL REPORT
December 31, 2024
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, 2024.
Q4 2024 HIGHLIGHTS:
•
Dividends – Throughout the fourth quarter Petrus paid a dividend of $0.01 per share per month, totaling $3.7 million. Including the
dividend declared on March 3, 2025 payable on March 31, 2025, Petrus will have cumulatively paid $0.18 per share, or $22.4
million in dividends since the Company began paying dividends in Q4 2023. Based on the average closing share price at March 24,
2025 of $1.36 per share, the current dividend yield is approximately 9% annually.
•
Production – Production for the fourth quarter of 2024 averaged 9,066 boe/d(1), which was relatively flat compared to 9,215 boe/d
in the third quarter of 2024, as natural declines were largely offset by new wells that were brought on production in December
2024.
•
Natural Gas Liquids (NGL) production(1) – NGL production increased to 1,810 bbl/d in the fourth quarter of 2024, up 24% compared
to 1,465 bbl/d in the third quarter of 2024. Strategic efforts to improve NGL recoveries resulted in the NGL yield increasing by 25%,
from 40 bbl/mmcf of gas in Q4 2023 to 50 bbl/mmcf of gas in Q4 2024.
•
Commodity prices – Total realized price was $26.45/boe in the fourth quarter of 2024, up 10% from $24.07/boe in the third
quarter of 2024. Increases were seen across all commodities, with the most notable change in realized natural gas pricing, which
was up 101% compared to the prior quarter.
•
Funds flow(2) – Petrus generated funds flow of $12.5 million in the fourth quarter of 2024 compared to $10.7 million in the third
quarter of 2024. The 17% increase is due to the higher natural gas prices combined with higher NGL production volumes.
•
Net debt(2) – Net debt was $60.1 million at the end of Q4 2024, which was down $0.3 million compared to the end of the prior
quarter.
2024 ANNUAL HIGHLIGHTS:
•
Commodity prices – Total realized price was $27.24/boe in 2024, a decrease of 18% from $33.31/boe in 2023. Realized natural gas
prices declined by 47% from $3.01/mcf in 2023 to $1.60/mcf in 2024.
•
Capital expenditures – Total capital expenditures were $31.8 million in 2024, down from $86.8 million in 2023 as the Company
reduced its capital expenditures program in response to lower natural gas prices.
•
Natural Gas Liquids (NGL) production(1) – NGL production was higher by 3% in 2024, increasing to 1,623 bbl/d compared to 1,575
bbl/d in 2023.
•
Production – Production for 2024 averaged 9,382 boe/d(1), as compared to 10,301 boe/d in 2023. The 9% decrease was primarily
due to natural declines and a reduced capital program.
•
Funds flow(2) – Petrus generated funds flow of $50.1 million in 2024 compared to $78.0 million in 2023. The 36% decrease was due
to a combination of lower natural gas prices and reduced production.
•
Net debt(2) – Petrus reduced net debt by $2.5 million from $62.6 million at year end 2023 to $60.1 million at year end 2024.
2025 OUTLOOK(3)
In 2025, Petrus will continue to execute its strategy of disciplined capital investment, focusing on projects that sustain production, increase
liquids weighting, enhance capital efficiency, and drive free funds flow. On February 12, 2025, we announced our 2025 capital budget and
guidance, available under the 'News & Events' section of our website.
The 2025 capital program began early in the year with a return to drilling in Ferrier. Completion operations were carried out in February
and new wells were brought on before the end of the first quarter of 2025. Additionally, construction of the 12-kilometer expansion of the
North Ferrier pipeline was completed in March. This infrastructure investment will further improve access to undeveloped lands and allow
the Company to transport both its own and third-party natural gas to the Petrus’ operated Ferrier gas plant, providing cost-effective
processing and the opportunity to generate additional revenue through third-party fees.
For 2025, the Company has hedged approximately 53% of forecasted production at an average of $2.67/GJ for natural gas and CAD$94.81/
bbl for oil. The Company is well-positioned to carry out its 2025 capital program and achieve guidance targets. As always, Petrus will closely
monitor market conditions and is prepared to adjust its capital program as needed, guided by its commitment to delivering sustainable
returns to shareholders.
(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 & Product Type Information" for further details.
(2)Non-GAAP financial measure or non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures".
(3)Refer to "Advisories - Forward-Looking Statements".
PRESIDENT’S MESSAGE
In 2024, Petrus continued to prove its strength and resiliency, generating strong cash flow and instituting a monthly dividend all while
enduring record low gas prices and slashing capital. Following the special dividend paid in Q4 2023, in January of 2024 we established a
regular monthly dividend of $0.01 per month or $0.12 per year. We were able to provide a market leading dividend yield and fund our
capital program all from cash flow. We started the year with a capital budget that was lower than the prior few years and as natural gas
prices continued to deteriorate, we responded by cutting planned 2024 capital spending by an additional 30%. This response highlights our
unique ability to be dynamic and respond quickly to constantly evolving market conditions. With the need for reduced investment, we
strategically prioritized projects with the highest rates of return and focused on technical innovations that significantly improved well
results. Consequently, we were still able to successfully deliver our initially projected production guidance and forecasted free cash flow.
Looking ahead, Petrus will continue paying an industry leading, high-yielding dividend to our shareholders while investing remaining cash
flow in high return wells and strategic infrastructure projects. During periods of low prices, we will maintain production and cash flow and
ensure the company is positioned to quickly pivot to a growth strategy when pricing is more constructive. Over the past few years, our
results have demonstrated both the quality of our assets and our ability to effectively manage and execute the disciplined development of
those assets. These strengths will continue to serve the company and our shareholders well as we navigate the constant changes and
challenges inherent in this business.
Thank you for your continued support.
Ken Gray
President & CEO
RESERVES
Petrus’ 2024 year end reserves were evaluated by its independent reserves evaluator, 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, 2024 ("2024 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, 2024, which will be available
under the Company's profile on SEDAR (the System for Electronic Document Analysis and Retrieval) at www.sedarplus.ca.
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 2024 Insite Report.
The following table provides a summary of the Company’s before tax reserves as evaluated by Insite:
As at December 31, 2024
Total Company Interest (1)(3)
Reserve Category
Conventional
Natural Gas
(mmcf)
Light and
Medium
Crude Oil
(mbbl)
NGL
(mbbl)
Total
(mboe)
NPV 0%(2)
($000s)
NPV 5%(2)
($000s)
NPV 10%(2)
($000s)
Proved Developed Producing
72,283
764
4,661
17,472
300,947
242,886
206,936
Proved Developed Non-Producing
1,434
19
67
325
3,397
2,821
2,335
Proved Undeveloped
120,479
3,060
7,235
30,375
425,388
255,976
155,680
Total Proved
194,196
3,843
11,963
48,172
729,733
501,683
362,616
Proved + Probable Producing
86,694
913
5,598
20,960
382,364
291,613
238,115
Total Probable
96,481
3,434
5,405
24,919
499,146
294,964
192,562
Total Proved Plus Probable
290,677
7,277
17,368
73,091
1,228,879
796,647
555,178
(1)Tables may not add due to rounding.
(2)NPV 0%, NPV 5% and NPV 10% refer to the risked net present value of the future net revenue of the Company's reserves, discounted by 0%, 5% and 10%, respectively
and is presented before tax and based on Insite's pricing assumptions.
(3)Total company interest reserve volumes presented herein are presented as the Company's total working interest before the deduction of royalties (but after including
any royalty interests of Petrus).
The Company produced 3.4 mmboe during 2024 and ended the year with 17.5 mmboe of Proved Developed Producing ("PDP") reserves (31%
oil and liquids).
Petrus ended 2024 with $206.9 million, $362.6 million and $555.2 million of PDP, Total Proved ("TP"), and Proved plus Probable (“P+P”),
reserve value before-tax, respectively, discounted at 10%, based on the 2024 Insite Report. In 2024, the Company realized Finding and
Development (“F&D”)(1)(2) costs of $12.58/boe for PDP reserves.
Based on the 2024 Insite Report, the Company’s PDP reserve value before-tax, discounted at 10% is $1.32 per share (134,918,886 fully-diluted
common shares outstanding at December 31, 2024). On the same basis, the Company's P+P reserve value before-tax, discounted at 10% is
$3.90 per share.
(1) Refer to "Oil and Gas Disclosures"
(2) While F&D costs are commonly used in the oil and nature gas industry and have been prepared by management, these terms do not have a standardized meaning and
may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons.
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 2024 Insite Report:
Future Development Cost ($000s)
Total Proved
Total Proved + Probable
2025
44,349
44,349
2026
138,485
138,485
2027
151,518
164,611
2028
83,030
147,282
Thereafter
—
130,453
Total FDC, Undiscounted
417,381
625,179
Total FDC, Discounted at 10%
345,611
489,942
PERFORMANCE RATIOS
The following table highlights annual performance ratios for the Company from 2020 to 2024(2):
December 31, 2024
December 31, 2023
December 31, 2022
December 31, 2021
December 31, 2020
Proved Producing
FD&A ($/boe) (1)
12.58
19.67
12.58
15.64
4.83
F&D ($/boe) (1)
12.58
19.67
12.70
8.90
4.83
Reserve Life Index (yr) (1)
5.24
5.27
5.31
5.41
5.20
Reserve Replacement Ratio (1)
0.74
1.15
3.20
0.78
1.20
FD&A Recycle Ratio (1)
1.28
1.06
2.91
1.58
2.60
Proved Developed
FD&A ($/boe) (1)
12.63
19.34
12.50
14.54
4.71
F&D ($/boe) (1)
12.63
19.34
12.61
8.53
4.71
Reserve Life Index (yr) (1)
5.33
5.36
5.39
5.50
5.20
Reserve Replacement Ratio (1)
0.73
1.17
3.22
0.84
1.20
FD&A Recycle Ratio (1)
1.28
1.08
2.93
1.70
2.70
Total Proved
FD&A ($/boe) (1)
17.53
14.50
18.24
10.51
1.29
F&D ($/boe) (1)
17.53
14.50
33.99
9.24
1.29
Reserve Life Index (yr) (1)
14.4
13.85
12.18
15.30
10.90
Reserve Replacement Ratio (1)
0.97
2.98
3.79
4.50
(1.00)
FD&A Recycle Ratio (1)
0.92
1.44
2.01
2.35
9.80
Future Development Cost
(undiscounted) ($000s)
417,381
391,058
313,786
233,684
156,815
Total Proved + Probable
FD&A ($/boe) (1)
33.63
14.00
15.66
10.57
0.37
F&D ($/boe) (1)
33.63
14.00
36.12
8.36
0.37
Reserve Life Index (yr) (1)
21.9
21.62
19.68
23.29
17.70
Reserve Replacement Ratio (1)
0.33
3.49
6.63
5.10
(1.30)
FD&A Recycle Ratio (1)
0.48
1.50
2.34
2.33
33.70
Future Development Cost
(undiscounted) ($000s)
625,179
618,437
519,823
343,489
252,335
(1)Refer to "Oil and Gas Disclosures"
(2) 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 natural 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.
NET ASSET VALUE
The following table shows the Company's Net Asset Value ("NAV"), calculated using the 2024 Insite Report and Insite's December 31,
2024 price forecast. The reader is cautioned that these amounts may not be directly comparable to other companies, as the term "Net
Asset Value" does not have a standardized meaning under GAAP or NI 51-101. Management believes that net asset value provides a
useful measure to analyze the comparative change in the Company's estimated value on a normalized basis.
As at December 31, 2024 ($000s except per share)
Proved Developed
Producing
Total Proved
Proved + Probable
Present Value Reserves, before tax (discounted at 10%) (1)
206,936
362,616
555,178
Undeveloped Land Value (2)
30,758
30,758
30,758
Net Debt (3)
(60,080)
(60,080)
(60,080)
Net Asset Value
177,614
333,294
525,856
Fully Diluted Shares Outstanding
134,919
134,919
134,919
Estimated Net Asset Value per Fully Diluted Share
$1.32
$2.47
$3.90
(1)Based on the 2024 Insite Report, using the forecast future prices and costs.
(2)Based on the exploration and evaluation assets as per the Company's December 31, 2024 audited consolidated financial statements.
(3) Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures" .
MANAGEMENT'S DISCUSSION & ANALYSIS
December 31, 2024
MANAGEMENT’S DISCUSSION & ANALYSIS
The following is Management’s Discussion and Analysis ("MD&A") of the financial and operating results of Petrus Resources Ltd. ("Petrus"
or the "Company") as at and for the three and twelve months ended December 31, 2024. This MD&A is dated March 24, 2025 and should
be read in conjunction with the Company's audited consolidated financial statements for the years ended December 31, 2024 and 2023.
The Company’s consolidated financial statements are prepared in compliance with International Financial Reporting Standards ("IFRS
Accounting Standards"). 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 1110, 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.sedarplus.ca.
Page |9
SELECTED FINANCIAL INFORMATION
OPERATIONS
Twelve months
ended
Dec. 31, 2024
Twelve months
ended
Dec. 31, 2023
Three months
ended
Dec. 31, 2024
Three months
ended
Sept. 30, 2024
Three months
ended
Jun. 30, 2024
Three months
ended
Mar. 31, 2024
Average Production
Natural gas (mcf/d)
38,149
42,779
36,178
37,368
38,908
40,174
Oil and condensate(1) (bbl/d)
1,400
1,595
1,226
1,522
1,322
1,529
NGLs (bbl/d)
1,623
1,575
1,810
1,465
1,664
1,557
Total (boe/d)
9,382
10,301
9,066
9,215
9,471
9,783
Total (boe)(1)
3,433,994
3,760,004
834,111
847,760
861,838
890,267
Liquids weighting
32 %
31 %
33 %
32 %
32 %
32 %
Realized Prices
Natural gas ($/mcf)
1.60
3.01
1.61
0.80
1.41
2.54
Oil and condensate(1) ($/bbl)
94.35
95.61
93.60
90.80
103.77
90.38
NGLs ($/bbl)
38.44
39.31
36.90
36.81
37.25
43.09
Total realized price ($/boe)
27.24
33.31
26.45
24.07
26.81
31.42
Royalty income
0.05
0.09
0.03
0.05
0.05
0.07
Royalty expense
(3.66)
(4.59)
(3.85)
(3.06)
(3.83)
(3.89)
Gain (loss) on risk management activities
—
0.40
—
—
—
—
Net oil and natural gas revenue ($/boe)
23.63
29.21
22.63
21.06
23.03
27.60
Operating expense
(5.93)
(6.25)
(5.89)
(6.10)
(4.96)
(6.76)
Transportation expense
(1.55)
(1.63)
(1.44)
(1.46)
(1.46)
(1.81)
Operating netback(2) ($/boe)
16.15
21.33
15.30
13.50
16.61
19.03
Realized gain (loss) on financial derivatives
2.02
2.14
3.04
2.49
(0.36)
2.90
Other cash income (expense)
0.34
0.02
1.19
0.09
0.05
0.05
General & administrative expense
(1.54)
(1.11)
(2.10)
(1.43)
(1.34)
(1.32)
Cash finance expense
(1.87)
(1.28)
(1.83)
(1.95)
(1.91)
(1.78)
Decommissioning expenditures
(0.52)
(0.37)
(0.61)
(0.12)
(0.72)
(0.61)
Funds flow & corporate netback(2) ($/boe)
14.58
20.73
14.99
12.58
12.33
18.27
FINANCIAL (000s except $ per share)
Twelve months
ended
Dec. 31, 2024
Twelve months
ended
Dec. 31, 2023
Three months
ended
Dec. 31, 2024
Three months
ended
Sept. 30, 2024
Three months
ended
Jun. 30, 2024
Three months
ended
Mar. 31, 2024
Oil and natural gas sales
93,721
125,605
22,085
20,446
23,150
28,039
Net income (loss)
(1,246)
50,731
(4,004)
5,302
2,789
(5,333)
Net income (loss) per share
Basic
(0.01)
0.41
(0.03)
0.04
0.02
(0.04)
Fully diluted
(0.01)
0.40
(0.03)
0.04
0.02
(0.04)
Funds flow(2)
50,058
78,024
12,493
10,665
10,628
16,272
Funds flow per share(2)
Basic
0.40
0.63
0.10
0.09
0.09
0.13
Fully diluted
0.40
0.62
0.10
0.08
0.08
0.13
Capital expenditures
31,814
86,843
7,705
4,859
6,907
12,343
Weighted average shares outstanding
Basic
124,389
123,469
124,497
124,372
124,290
124,299
Fully diluted
124,389
126,436
124,497
126,686
126,559
124,299
As at period end
Common shares outstanding
Basic
125,113
124,266
125,113
124,372
124,372
124,259
Fully diluted
134,919
134,542
134,919
134,952
134,919
134,484
Total assets
420,124
437,842
420,124
421,196
419,584
427,574
Non-current liabilities
65,475
60,926
65,475
62,869
59,511
59,995
Net debt(2)
60,080
62,596
60,080
60,423
61,848
63,114
(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 financial measure or non-GAAP ratio. Refer to "Non-GAAP and Other Financial Measures".
RESULTS OF OPERATIONS
FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES
Twelve months
ended
Dec. 31, 2024
Twelve months
ended
Dec. 31, 2023
Three months
ended
Dec. 31, 2024
Three months
ended
Sept. 30, 2024
Three months
ended
Jun. 30, 2024
Three months
ended
Mar. 31, 2024
Average production
Natural gas (mcf/d)
38,149
42,779
36,178
37,368
38,908
40,174
Oil and condensate(1) (bbl/d)
1,400
1,595
1,226
1,522
1,322
1,529
NGLs (bbl/d)
1,623
1,575
1,810
1,464
1,664
1,557
Total (boe/d)(1)
9,382
10,301
9,066
9,215
9,471
9,783
Total (boe)(1)
3,433,994
3,760,004
834,111
847,760
861,838
890,267
Revenue ($000s)
Natural gas
22,365
46,972
5,357
2,734
4,984
9,290
Oil and condensate(1)
48,338
55,676
10,561
12,714
12,483
12,579
NGLs
22,848
22,603
6,144
4,958
5,639
6,107
Royalty revenue
170
354
23
40
44
63
Oil and natural gas sales
93,721
125,605
22,085
20,446
23,150
28,039
Average realized prices
Natural gas ($/mcf)
1.60
3.01
1.61
0.80
1.41
2.54
Oil and condensate(1) ($/bbl)
94.35
95.61
93.60
90.80
103.77
90.38
NGLs ($/bbl)
38.44
39.31
36.90
36.81
37.25
43.09
Total realized price ($/boe)
27.24
33.31
26.45
24.07
26.81
31.42
Realized gain (loss) on financial derivatives
2.02
2.14
3.04
2.49
(0.36)
2.90
Gain on risk management
—
0.40
—
—
—
—
Total price including hedging ($/boe)
29.26
35.85
29.49
26.56
26.45
34.32
Average benchmark prices
Twelve months
ended
Dec. 31, 2024
Twelve months
ended
Dec. 31, 2023
Three months
ended
Dec. 31, 2024
Three months
ended
Sept. 30, 2024
Three months
ended
Jun. 30, 2024
Three months
ended
Mar. 31, 2024
Natural gas
AECO 5A (C$/GJ)
1.38
2.51
1.40
0.65
1.12
2.36
AECO 7A (C$/GJ)
1.36
2.78
1.38
0.77
1.36
1.94
Crude oil
Mixed Sweet Blend Edm (C$/bbl)
98.03
99.75
92.87
98.48
105.97
94.79
WTI (US$/bbl)
75.60
77.63
69.79
75.09
80.57
76.96
Foreign exchange
US$/C$
0.73
0.73
0.72
0.73
0.73
0.74
(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.
Page |11
FUNDS FLOW AND NET INCOME (LOSS)
Petrus generated funds flow of $12.5 million in the fourth quarter of 2024 compared to $16.5 million in the fourth quarter of 2023. The 24%
decrease is due to the decline in natural gas prices combined with lower production volumes. In the fourth quarter of 2024, Petrus realized
a hedging gain of $2.5 million, compared to a realized hedging gain of $1.7 million in the fourth quarter of the prior year comparative
period. In the fourth quarter Petrus' total realized price (before realized hedging and risk management) was $26.45/boe compared to
$30.60/boe in the fourth quarter of 2023.
For the year ended December 31, 2024, Petrus generated funds flow of $50.1 million compared to $78.0 million the prior year. The
reduced funds flow is due to both lower pricing and decreased production volumes.
Petrus reported a net loss of $4.0 million in the fourth quarter of 2024, compared to net income of $39.7 million in the fourth quarter of
2023. The change to a net loss in the fourth quarter of 2024 was primarily due to lower deferred tax recovery of $1.7 million (2023 - $19.6
million). Also, there was a $3.9 million hedging loss in the fourth quarter of 2024 compared to a $17.0 million hedging gain in the fourth
quarter of 2023.
The Company generated a net loss of $1.2 million for the twelve months ended December 31, 2024 compared with net income of $50.7
million in the prior year. The change to a net loss in 2024 was primarily due to lower deferred tax recovery of $1.2 million (2023 - $19.6
million). Also, there was a $0.5 million hedging loss in the fourth quarter of 2024 compared to a $17.0 million hedging gain in the fourth
quarter of 2023.
($000s except per share)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Funds flow
12,493
16,525
50,058
78,024
Funds flow per share - basic
0.10
0.13
0.40
0.63
Funds flow per share - fully diluted
0.10
0.13
0.40
0.62
Net income (loss)
(4,004)
39,708
(1,246)
50,731
Net income (loss) per share - basic
(0.03)
0.32
(0.01)
0.41
Net income (loss) per share - fully diluted
(0.03)
0.32
(0.01)
0.40
Common shares outstanding (000s)
Basic
125,113
124,266
125,113
124,266
Fully diluted
134,919
134,542
134,919
134,542
Weighted average shares outstanding (000s)
Basic
124,497
123,812
124,389
123,469
Fully diluted
124,497
124,840
124,389
126,436
OIL AND NATURAL GAS SALES
Fourth quarter 2024 average production was 9,066 boe/d (14% light oil), 4% lower than the fourth quarter of 2023 (9,474 boe/d; 13% light
oil). Fourth quarter 2024 oil and natural gas sales revenue was $22.1 million compared to $26.7 million in 2023. The 17% decrease is due
to lower natural gas prices combined with lower production volumes resulting in a 47% decline in natural gas revenue from the fourth
quarter of 2023. The lower production volumes were primarily due to natural declines combined with a reduced capital program.
Average production for the year ended December 31, 2024 was 9,382 boe/d (68% natural gas), 9% lower than 2023 (10,301 boe/d, 69%
natural gas). Total oil and natural gas revenue decreased from $125.6 million in 2023 to $93.7 million in 2024 due to both lower pricing and
lower volumes.
The following table provides a breakdown of composition of the Company's production volume by product:
Production Volume by Product
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Natural gas (mcf/d)
36,178
39,891
38,149
42,779
Crude oil and condensate (bbl/d)
1,226
1,218
1,400
1,595
Natural gas liquids (bbl/d)
1,810
1,607
1,623
1,575
Total production
9,066
9,474
9,382
10,301
Page |12
The following table presents oil and natural gas sales by product and the change from the prior comparative periods:
Oil and Natural Gas Sales ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
% Change
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
% Change
Natural gas
5,357
10,114
(47) %
22,365
46,972
(52) %
Crude oil and condensate
10,561
11,049
(4) %
48,338
55,676
(13) %
Natural gas liquids
6,144
5,508
12 %
22,848
22,603
1 %
Royalty income
23
76
(70) %
170
354
(52) %
Total oil and natural gas sales
22,085
26,747
(17) %
93,721
125,605
(25) %
The following table provides the average benchmark commodity prices and the Company's average realized commodity prices (before
hedging and risk management gains/losses):
Three months ended
December 31, 2024
Three months ended
December 31, 2023
% Change
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
% Change
Average benchmark prices
Natural gas
AECO 5A (C$/GJ)
1.40
2.18
(36) %
1.38
2.51
(45) %
AECO 7A (C$/GJ)
1.38
2.52
(45) %
1.36
2.78
(51) %
Crude oil
Mixed Sweet Blend Edm (C$/bbl)
92.87
96.60
(4) %
98.03
99.75
(2) %
WTI (US$/bbl)
69.79
78.39
(11) %
75.60
77.63
(3) %
Average realized prices
Natural gas ($/mcf)
1.61
2.76
(42) %
1.60
3.01
(47) %
Oil and condensate ($/bbl)
93.60
98.63
(5) %
94.35
95.61
(1) %
NGLs ($/bbl)
36.90
37.26
(1) %
38.44
39.31
(2) %
Total average realized price
26.45
30.60
(14) %
27.24
33.31
(18) %
Natural gas
Natural gas sales for the three months ended December 31, 2024 decreased by 47% to $5.4 million, compared to sales of $10.1 million in
the prior year comparative period. This decrease is primarily due to lower natural gas prices. Natural gas accounted for 24% of total oil and
gas sales for the quarter, lower than the 38% in the fourth quarter of 2023. Fourth quarter 2024 average realized natural gas price was
$1.61/mcf, compared to $2.76/mcf in the fourth quarter of 2023, a 42% decrease. The decrease in realized price is due to the significant
decline in natural gas prices (AECO 5A down 36% and AECO 7A down 45% in the fourth quarter of 2024) from the prior year comparative
period. Natural gas production of 36,178 mcf/d was down 9% from the prior year comparative period production of 39,891 mcf/d.
Natural gas sales for the year ended December 31, 2024 was $22.4 million, which decreased 52% from the prior year ($47.0 million). The
average realized price for the year ended December 31, 2024 decreased 47% to $1.60/mcf from $3.01/mcf in the prior year. Natural gas
production of 38,149 mcf/d decreased 11% over the prior year comparative of 42,779 mcf/d. Natural gas sales accounted for 24% of oil
and natural gas sales in 2024, compared with 38% in the prior year.
Crude oil and condensate
Oil and condensate sales for the three months ended December 31, 2024 decreased 4% to $10.6 million, compared to $11.0 million in the
prior year comparative period; this decrease is due to lower realized prices. Oil and condensate accounted for 48% of total oil and gas sales
for the quarter. The average realized price of light oil and condensate was $93.60/bbl for the fourth quarter of 2024 compared to $98.63/
bbl in the fourth quarter of 2023, a decrease of 5%. Oil and condensate production of 1,226 bbl/d was higher by 1% over the prior year
comparative period production of 1,218 bbl/d.
Oil and condensate sales for the year ended December 31, 2024 was $48.3 million, which decreased 13% from the prior year ($55.7
million). The average realized price for the year ended December 31, 2024 of $94.35/bbl was flat, compared to $95.61/bbl in the prior year.
Oil and condensate production of 1,400 bbl/d decreased 12% over the prior year comparative of 1,595 bbl/d. Oil and condensate sales
accounted for 52% of oil and natural gas sales in 2024, compared to 44% in the prior year.
Page |13
Natural gas liquids (NGLs)
NGL sales for the three months ended December 31, 2024 increased 12% to $6.1 million, compared to $5.5 million in the prior year
comparative period. NGL production increased by 13% in the fourth quarter of 2024 to 1,810 bbl/d, compared to 1,607 bbl/d in the prior
year comparative period. Higher production volumes are due to improved liquid recoveries. NGLs accounted for 28% of total oil and
natural gas sales for the quarter, up from 21% in the fourth quarter of 2023. In the fourth quarter of 2024, the Company's realized blended
NGL price averaged $36.90/bbl, compared to $37.26/bbl in the prior year comparative period.
NGL sales for the year ended December 31, 2024 were $22.8 million, which increased 1% from the prior year ($22.6 million). The average
realized price for the year ended December 31, 2024 of $38.44/bbl was flat, compared to $39.31/bbl from the prior year. NGL production
of 1,623 bbl/d increased 3% over the prior year comparative of 1,575 bbl/d. NGL sales accounted for 24% of oil and natural gas sales in
2024, compared to 18% in the prior year.
The Company’s NGL production mix consists of ethane, propane, butane and pentane. The pricing received for NGL production is based on
annual contracts effective the first of April each year. The contract prices are based on the product mix, the fractionation process required
and the demand for fractionation facilities.
OPERATIONS UPDATE
Fourth quarter average production by area was as follows:
For the three months ended December 31, 2024
Ferrier & North
Ferrier
Foothills
Central Alberta
Total
Natural gas (mcf/d)
31,052
539
4,587
36,178
Oil and condensate (bbl/d)
928
54
244
1,226
NGLs (bbl/d)
1,665
7
138
1,810
Total (boe/d)(1)
7,768
151
1,147
9,066
Production for the fourth quarter of 2024 averaged 9,066 boe/d, as compared to 9,474 boe/d in the fourth quarter of 2023. The 4%
decrease was primarily due to natural declines and strategic shut-ins due to low natural gas prices, and was partially offset by new wells
that commenced production in December 2024.
For the twelve months ended December 31, 2024
Ferrier & North
Ferrier
Foothills
Central Alberta
Total
Natural gas (mcf/d)
32,736
905
4,508
38,149
Oil and condensate (bbl/d)
1,088
73
239
1,400
NGLs (bbl/d)
1,487
5
131
1,623
Total (boe/d)(1)
8,032
228
1,122
9,382
(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.
Production for the twelve months ended December 31, 2024 averaged 9,382 boe/d(1) , as compared to 10,301 boe/d for the twelve months
ended December 31, 2023. The 9% decline was primarily due to natural declines, strategic shut-in due to low natural gas prices, and less
new well production from a reduced capital program.
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)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Crown
1,702
2,507
6,815
10,132
Percent of production revenue
8 %
9 %
7 %
8 %
Gross overriding
1,510
1,660
5,757
7,123
Total
3,212
4,167
12,572
17,255
Page |14
Fourth quarter royalty expense (net of royalty allowances and incentives) decreased from $4.2 million in 2023 to $3.2 million in 2024. On a
twelve month basis, total royalty expense (net of royalty allowances and incentives) decreased from $17.3 million in 2023 to $12.6 million
in 2024.
Gross overriding royalties decreased from $1.7 million in the fourth quarter of 2023 to $1.5 million in the fourth quarter of 2024. For the
twelve months ended December 31, 2024, gross overriding royalties decreased from $7.1 million in 2023 to $5.8 million in 2024.
OTHER INCOME
During the year ended December 31, 2024, the Company recorded $0.3 million (2023 - $1.3 million) as other income. In 2023, the Company
recorded non-cash income of $1.2 million related to carbon credits earned from installing emission reduction equipment. In 2024, the
Company sold $1.0 million of these carbon credits for cash and recorded the proceeds in funds flow for the year.
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, dividend payments 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.
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
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Realized hedging gain
2,539
1,737
6,930
8,051
Unrealized hedging gain (loss)
(6,466)
15,233
(7,466)
4,938
Net gain (loss) on financial derivatives
(3,927)
16,970
(536)
12,989
For the fourth quarter of 2024, the Company recognized a realized hedging gain of $2.5 million in comparison to a realized hedging gain of
$1.7 million in the fourth quarter of 2023. The realized gain is due to the decrease in both oil and natural gas prices relative to the
respective contracts settled. The realized gain on gas hedge contracts was $2.7 million, offset by a realized loss on oil hedge contracts of
$0.2 million. The realized hedging gain in the fourth quarter of 2024 increased the Company’s corporate netback by $3.04/boe.
For the twelve months ended December 31, 2024, the Company recognized a realized hedging gain of $6.9 million in comparison to a gain
of $8.1 million in the comparable period of 2023.
During the fourth quarter of 2024, the Company recorded an unrealized loss of $6.5 million compared to an unrealized gain of $15.2 million
in the fourth quarter of 2023. Between September 30, 2024, and December 31, 2024, natural gas prices improved, leading to a reduction of
the mark-to-market value of the financial derivative contracts leading to an unrealized loss. By comparison, natural gas prices declined
during Q4 2023 resulting in an unrealized gain in the mark-to-market value of the outstanding financial derivative contracts in Q4 2023.
During the twelve months ended December 31, 2024, the Company recorded a net loss on financial derivatives of $0.5 million compared to
a net gain on financial derivatives of $13.0 million in the comparative period of 2023, due to the effect of changes in commodity prices to
financial derivative values.
During the three and twelve months ended December 31, 2024, the Company did not realize any gain or loss on physical hedge commodity
contracts as there were no contracts in place during these periods and none outstanding as at December 31, 2024. The three and twelve
months ended December 31, 2023 was $nil and $1.5 million gain, respectively.
The Company’s risk management contracts provide protection from significant changes in crude oil and natural gas commodity prices out to
2026. The Company endeavors to hedge approximately half of its forecasted production for up to 12 months forward, and approximately
25% of its forecasted production for 12 to 24 months forward. The Company's hedging strategy is intended to provide stability and
sustainability to the Company's economic returns, funds flow, dividend payments and capital development plans. A summary of Petrus’ risk
Page |15
management contracts as at December 31, 2024 is included in note 9 of the Company’s consolidated financial statements as at and for the
year ended December 31, 2024.
The table below summarizes Petrus’ quarterly average crude oil and natural gas hedged volumes and average cap and floor prices through
financial derivative contracts that are outstanding as at the date of this MD&A:
2025
2026
Q1
Q2
Q3
Q4
Avg.(1)
Q1
Q2
Q3
Q4
Avg.(1)
Oil hedged (bbl/d)
1,700
1,600
1,500
1,300
1,525
1,200
1,000
600
300
775
Avg. WTI price ($C/bbl)
93.42
95.04
95.26
94.14
94.45
92.14
92.36
91.63
91.33
92.03
Natural gas hedged (GJ/d)
21,000 19,000 19,000 16,333 18,833 15,000 11,000 11,000
4,333 10,333
Avg. AECO 7A cap price ($C/GJ)
3.19
2.56
2.56
3.09
2.85
3.36
2.50
2.51
3.02
2.87
Avg. AECO 7A floor price ($C/GJ)
3.14
2.48
2.48
3.03
2.78
3.31
2.50
2.51
3.02
2.85
(1)The volumes and prices reported are the weighted average volumes and prices for the period.
OPERATING EXPENSE
The following table shows the Company’s operating expense for the reporting periods shown:
Operating Expense ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Fixed and variable operating expense
4,170
3,263
17,137
19,833
Processing, gathering and compression charges
1,048
1,458
4,568
5,068
Total gross operating expense
5,218
4,721
21,705
24,901
Overhead recoveries
(303)
(302)
(1,329)
(1,396)
Total net operating expense
4,915
4,419
20,376
23,505
Operating expense, net ($/boe)
5.89
5.07
5.93
6.25
For the three months ended December 31, 2024, net operating expense totaled $4.9 million, an 11% increase from $4.4 million during the
prior year comparative period. Q4 2023 operating expenses were lower due to adjustments in emission expense estimates and higher
equalization expense recoveries from a third-party-operated gas plant. On a per boe basis, net operating expense was 11% higher at $5.89/
boe in the fourth quarter of 2024 compared to $5.07/boe in the fourth quarter of 2023.
For the twelve months ended December 31, 2024, net operating expense totaled $20.4 million, a 13% decrease from the prior year
comparative period. The decrease in total net operating expense is primarily due to reduced power costs and offsets to operating expense
from an increase in processing and transportation fees received from third parties. On a per boe basis, net operating expense was 5%
lower at $5.93/boe in the twelve months ended December 31, 2024 compared to $6.25/boe in the 2023 comparative period.
TRANSPORTATION EXPENSE
The following table shows transportation expense paid in the reporting periods:
Transportation Expense ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Transportation expense
1,203
1,271
5,316
6,115
Transportation expense ($/boe)
1.44
1.46
1.55
1.63
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, 2024,
transportation expense was $1.2 million or $1.44/boe compared to $1.3 million or $1.46/boe in the prior year comparative period.
For the twelve months ended December 31, 2024, transportation expense was $5.3 million or $1.55/boe compared to $6.1 million or
$1.63 /boe in the prior year comparative period. The decrease in total transportation expense is due to lower production volumes.
Page |16
GENERAL AND ADMINISTRATIVE EXPENSE
The following table illustrates the Company’s general and administrative ("G&A") expense which is shown net of capitalized costs directly
related to exploration and development activities:
General and Administrative Expense ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Personnel, consultants and directors
1,473
1,360
4,152
4,012
Administrative expenses
662
569
2,191
2,046
Regulatory and professional expenses
240
200
835
1,079
Gross general and administrative expense
2,375
2,129
7,178
7,137
Capitalized general and administrative expense
(426)
(391)
(1,161)
(1,136)
Overhead recoveries
(197)
(1,418)
(726)
(1,818)
General and administrative expense
1,752
320
5,291
4,183
General and administrative expense ($/boe)
2.10
0.37
1.54
1.11
For the three months ended December 31, 2024, gross G&A expense (before capitalization and overhead recoveries) was $2.4 million
compared to $2.1 million in the prior year comparative period. Fourth quarter G&A expense (net) in 2024 was $1.8 million compared to
$0.3 million in the prior year comparative period. During the fourth quarter of 2023, there was a prior period adjustment recorded for
overhead recoveries resulting in an unusually low net G&A expense.
For the twelve months ended December 31, 2024, gross G&A expense (before capitalization and overhead recoveries) was $7.2 million
compared to $7.1 million in the prior year comparative period. Net G&A expense on a twelve month basis was $5.3 million or $1.54/boe, an
increase from the $4.2 million or $1.11/boe for the twelve months ended December 31, 2023. The primary reason for the higher net G&A
expense is due to greater capital activity during 2023 resulting in a higher provision for overhead recoveries.
SHARE-BASED COMPENSATION EXPENSE
The following table illustrates the Company’s share-based compensation expense which is shown net of capitalized costs directly related to
exploration and development activities:
Share-Based Compensation Expense ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Gross share-based compensation expense
647
560
2,924
2,640
Capitalized share-based compensation expense
(161)
(153)
(792)
(777)
Share-based compensation expense
486
407
2,132
1,863
For the three months ended December 31, 2024, net share-based compensation expense was $0.5 million compared to $0.4 million in the
prior year comparative period. For the twelve months ended December 31, 2024, net share based compensation expense was $2.1 million,
compared to $1.9 million in 2023.
FINANCE EXPENSE
The following table illustrates the Company’s finance expense which includes cash and non-cash expenses:
Finance Expense ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Interest expense
1,369
1,117
5,796
4,205
Finance fees
161
129
622
596
Deferred financing costs
99
66
373
376
Accretion on decommissioning obligations
290
321
1,167
1,277
Total finance expense
1,919
1,633
7,958
6,454
The increase in total finance expense from the prior year comparative periods is due to higher loan balances from capital activity and lower
funds flow.
Page |17
DEPLETION AND DEPRECIATION
The following table compares depletion and depreciation expense recorded in the reporting periods shown:
Depletion and Depreciation Expense ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Depletion and depreciation expense
10,140
10,292
41,263
46,623
Depletion and depreciation expense ($/boe)
12.16
11.81
12.02
12.40
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 costs. Such costs are segregated and depleted on an area by area basis relative to the respective underlying relevant
reserve base.
For the three months ended December 31, 2024, the Company recorded depletion and depreciation of $10.1 million or $12.16/boe,
compared to $10.3 million or $11.81/boe in the prior year comparative period. For the twelve months ended December 31, 2024, the
Company recorded depletion and depreciation of $41.3 million or $12.02/boe, compared to $46.6 million or $12.40/boe in the prior year
comparative period. The decrease in depletion and depreciation expense is attributed to lower production volumes.
DEFERRED TAX
For the three months ended December 31, 2024, there was a deferred tax recovery of $1.7 million compared to a deferred tax recovery of
$19.6 million in the prior year comparative period. The comparative period included a valuation allowance reversal to recognize the benefit
of approximately $200 million of non-capital losses.
For the year ended December 31, 2024, there was a deferred tax recovery of $1.2 million compared to a deferred tax recovery of $19.6
million in the prior year.
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)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
Weighted average common shares outstanding
Basic
124,497
123,812
124,389
123,469
Fully diluted
124,497
124,840
124,389
126,436
Common shares outstanding
Basic
125,113
124,266
125,113
124,266
Fully diluted
134,919
134,542
134,919
134,542
Stock options outstanding
8,482
8,617
8,482
8,617
Restricted shares units outstanding
470
—
470
—
Deferred share units outstanding
1,812
1,659
1,812
1,659
At December 31, 2024 the Company had 125,113,129 (126,787,879 as at the MD&A date) common shares, 8,482,331 stock options, 470,000
RSU's and 1,811,963 DSUs outstanding.
Dividends
During the three and twelve months ended December 31, 2024, the Company paid monthly dividends of $0.01 per common share totaling
$3.7 million and $14.9 million, respectively.
Normal Course Issuer Bid ("NCIB")
On June 25, 2024, the Company announced the approval of its renewed NCIB by the Toronto Stock Exchange ("the TSX"). The 2024 NCIB
allows the Company to purchase up to 6,218,596 common shares over a period of twelve months (expiring no later than June 27, 2025).
Page |18
Purchases are made on the open market through the TSX or alternative Canadian trading platforms at the market price of such common
shares. All common shares purchased under the NCIB are cancelled. The total cost paid, including commissions and fees, is first charged to
share capital to the extent of the average carrying value of the Company’s common shares and the excess paid is recorded to retained
earnings and any shortfall is recorded to contributed surplus.
During the three months ended December 31, 2024, no shares were repurchased for cancellation. During the twelve months ended
December 31, 2024, the Company repurchased 396,100 shares for cancellation at an average price of $1.30 per share totaling $0.5
million .
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, 2024 and the date of this MD&A, 1,811,963 DSUs were issued and outstanding (December 31, 2023 – 1,658,837). 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.
On each date that a dividend payment is made, holders of DSUs are credited with additional DSUs; the number of additional DSUs is
calculated by dividing the dividends that would have been paid to such holder if the DSUs held at the record date of the cash dividend had
been common shares, by the fair market value of the common shares on the date on which the dividends are paid on the common shares.
Restricted share units
The Company has a restricted share unit plan in place whereby it may issue restricted share units to officers, employees and consultants of
the Company. Each RSU 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 RSUs unless otherwise determined by the Board, vest as to one-third
(1/3) annually over three years from the grant date. At December 31, 2024, 470,000 RSUs were issued and outstanding (December 31,
2023 – Nil).
CAPITAL EXPENDITURES
Capital expenditures (excluding acquisitions and dispositions) totaled $7.7 million in the fourth quarter of 2024, compared to $32.0 million
in the prior year comparative period. The majority of the capital spent in the fourth quarter of 2024 is related to the drilling of 3 (1.3 net)
wells and also includes some costs related to the equipping of wells drilled earlier in 2024.
Capital expenditures total $31.8 million in the year ended December 31, 2024 compared to $86.8 million in 2023. There were lower capital
expenditures in response to lower natural gas prices.
The following table shows capital expenditures for the reporting periods indicated. All capital is presented before decommissioning
obligations.
Capital Expenditures ($000s)
Three months ended
December 31, 2024
Three months ended
December 31, 2023
Twelve months
ended
December 31, 2024
Twelve months
ended
December 31, 2023
Drill and complete
5,470
16,910
24,288
58,678
Oil and gas equipment
1,323
14,470
5,752
25,747
Geological
—
—
—
545
Land and lease
364
411
485
628
Office
122
—
128
109
Capitalized general and administrative expense
426
238
1,161
1,136
Total capital expenditures
7,705
32,029
31,814
86,843
Gross (net) wells drilled
3 (1.3)
2 (2.0)
13 (6.6)
15 (12.4)
Page |19
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2024, 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, 2024, the RLF was comprised of a $60.0 million operating facility payable on demand by the lender and has an interest
rate of Canada Prime plus 2.5%. 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, 2025.
At December 31, 2024, the Company had a $0.7 million letter of credit outstanding against the RLF (December 31, 2023 – $0.7 million) and
had drawn $32.7 million against the RLF (December 31, 2023 – $24.2 million).
Second Lien Facility
At December 31, 2024 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, 2027) with a fixed interest rate of 11% per annum and can be repaid at the discretion of the
Company. The Second Lien Facility is a related party transaction with a major shareholder who owns approximately 21% of the outstanding
shares of the Company. The total interest paid during the three months ended December 31, 2024 to the major shareholder, related to the
Second Lien facility, was $0.7 million. Total interest for the year ended December 31, 2024 to the major shareholder was $2.8 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, less any amounts outstanding
under the Company's RLF.
The key financial covenant as at December 31, 2024 is summarized in the following table. At December 31, 2024 the Company is in
compliance with all financial covenants.
Financial Covenant Description
Required Ratio
As at December 31, 2024
Working Capital Ratio
Over 1.0
2.26
Liquidity
The following are the contractual maturities of financial liabilities as at December 31, 2024:
$000s
Total
< 1 year
1-5 years
Accounts payable and accrued liabilities
17,287
17,287
—
Long term debt
31,638
2,750
28,888
Revolving Loan Facility
34,779
34,779
—
Lease obligations (discounted)
993
164
829
Total
84,697
54,980
29,717
Page |20
At December 31, 2024, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $36.3
million, primarily due to the $32.7 million drawn on the RLF, which is classified as a current liability. The RLF has a credit limit of $60 million
and is payable upon demand, with the borrowings classified as current liabilities as of December 31, 2024. Excluding the RLF, the working
capital deficit would have been $3.5 million. The Company expects the working capital deficiency to diminish over the next 12 months as
the RLF is paid down by the cash flow from operations.
The commitments for which the Company is responsible are as follows:
$000s
Total
< 1 year
1-5 years
> 5 years
Firm service transportation
6,587
2,799
3,788
—
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, inflation 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. Petrus is also exposed to risks related to the imposition of tariffs or other trade related measures by the
United States and Canada on one another.
For a more in-depth discussion of risk management, see notes 9 and 14 of the Company’s December 31, 2024 audited consolidated
financial statements.
Page |21
SUMMARY OF QUARTERLY RESULTS
($000s unless otherwise noted)
Dec. 31,
2024
Sept. 30,
2024
Jun. 30,
2024
Mar. 31,
2024
Dec. 31,
2023
Sept. 30,
2023
Jun. 30,
2023
Mar. 31,
2023
Average Production
Natural gas (mcf/d)
36,178
37,368
38,908
40,174
39,891
42,045
44,010
45,237
Oil and condensate (bbl/d)
1,226
1,522
1,322
1,529
1,218
1,316
1,670
2,192
NGLs (bbl/d)
1,810
1,465
1,664
1,557
1,607
1,556
1,486
1,654
Total (boe/d)
9,066
9,215
9,471
9,783
9,474
9,880
10,492
11,385
Total (boe)
834,111 847,760 861,838 890,267 871,567 908,985 954,738 1,024,645
Financial Results
Oil and natural gas sales
22,085
20,446
23,150
28,039
26,747
28,273
29,266
41,319
Royalty expense
(3,212)
(2,593)
(3,305)
(3,461)
(4,167)
(3,061)
(3,492)
(6,534)
Gain (loss) on risk management activities
—
—
—
—
—
—
32
1,490
Net oil and natural gas revenue
18,873
17,853
19,845
24,578
22,580
25,212
25,806
36,275
Transportation expense
(1,203)
(1,239)
(1,259)
(1,615)
(1,271)
(1,401)
(1,341)
(2,102)
Operating expense
(4,915)
(5,172)
(4,271)
(6,018)
(4,419)
(6,086)
(5,566)
(7,434)
Operating netback(1)
12,755
11,442
14,315
16,945
16,890
17,725
18,899
26,739
Realized gain (loss) on financial derivatives
2,539
2,115
(307)
2,583
1,737
1,102
3,398
1,814
Other income (expense)
991
77
40
48
(161)
34
37
169
General and administrative expense
(1,752)
(1,209)
(1,152)
(1,178)
(319)
(1,158)
(1,476)
(1,230)
Cash finance expense
(1,530)
(1,657)
(1,650)
(1,581)
(1,246)
(1,148)
(1,269)
(1,140)
Decommissioning expenditures
(510)
(103)
(618)
(545)
(376)
(312)
(549)
(136)
Corporate netback and funds flow(1)
12,493
10,665
10,628
16,272
16,525
16,243
19,040
26,216
Oil and natural gas sales
22,085
20,446
23,150
28,039
26,747
28,273
29,266
41,319
Per share - basic
0.18
0.16
0.19
0.23
0.22
0.23
0.24
0.33
Per share - fully diluted
0.18
0.16
0.18
0.23
0.21
0.23
0.23
0.32
Net income (loss)
(4,004)
5,302
2,789
(5,333)
39,708 (11,293)
5,043
17,273
Per share - basic
(0.03)
0.04
0.02
(0.04)
0.32
(0.09)
0.04
0.14
Per share - fully diluted
(0.03)
0.04
0.02
(0.04)
0.32
(0.09)
0.04
0.14
Common shares outstanding (000s)
Basic
125,113 124,372 124,372 124,259 124,266 123,867 123,849 123,711
Fully diluted
134,919 134,952 134,919 134,484 134,542 134,436 134,423 133,916
Weighted average shares outstanding (000s)
Basic
124,497 124,372 124,290 124,299 123,812 123,743 123,752 123,416
Fully diluted
124,497 126,686 126,559 124,299 124,840 123,743 127,040 127,358
Total assets
420,124 421,196 419,584 427,574 437,842 380,100 383,231 403,276
(1)Non-GAAP measure. Refer to "Non-GAAP and Other Financial Measures".
The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and
corporate netback are affected by commodity prices, exchange rates, Canadian commodity price differentials and production levels. Petrus’
average quarterly production has fluctuated between 9,066 boe/d in the fourth quarter of 2024 and 11,385 boe/d in the first quarter of
2023. Petrus has made a conscious effort to limit its capital activity to its existing funds flow and available credit facilities.
Page |22
SELECTED ANNUAL INFORMATION
($000s unless otherwise noted)
For the year ended,
December 31, 2024
December 31, 2023
December 31, 2022
Oil and natural gas revenue
93,721
125,605
152,350
Per share - basic
0.75
1.02
1.32
Per share - fully diluted
0.75
0.99
1.27
Net income (loss)
(1,246)
50,731
60,868
Per share - basic
(0.01)
0.41
0.53
Per share - fully diluted
(0.01)
0.40
0.51
Common shares outstanding (000s)
Basic
125,113
124,266
123,239
Weighted avg. shares outstanding (000s)
Basic
124,389
123,469
115,189
Fully diluted
124,389
126,436
119,525
Total assets
420,124
437,842
381,057
Non-current liabilities
65,475
60,926
63,021
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. 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, 2024.
OTHER FINANCIAL INFORMATION
Material accounting policies
The Company’s material 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, 2024.
New standards and interpretations
The Company has not adopted any new standards and interpretations for the year ended December 31, 2024.
In April, 2024 the International Accounting Standards Board issued IFRS 18 "Presentation and Disclosure in Financial Statements", which
provides presentation and disclosure requirements for the primary financial statements and related notes, replacing IAS 1 "Presentation
of Financial Statements". IFRS 18 introduces defined categories for income and expenses and requires disclosure of new defined
subtotals, including operating profit. The new standard also requires additional notes for management performance measures and
disclosure of certain expenses by nature. There are some associated changes to the statement of cash flows, including the starting point
for the calculation of cash flows from operating activities and the categorization of interest and dividends. IFRS 18 is effective January 1,
2027, with early adoption permitted. The new standard is required to be adopted retrospectively. The Company is assessing the impact
of IFRS 18 on the Company's consolidated financial statements.
Disclosure Controls and Procedures
Petrus’ Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure
controls and procedures ("DC&P"), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim
Filings (“NI 52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the
Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual filings are
being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or
submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities
legislation. The Chief Executive Officer and Chief Financial Officer of Petrus have evaluated, or caused to be evaluated under their
supervision, the effectiveness of the Company's DC&P as at December 31, 2024 and have concluded that the Company's DC&P are
effective at December 31, 2024 for the foregoing purposes.
Internal Controls 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, 2024, 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, 2024 and ended on December 31, 2024 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, 2024. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that as at December 31, 2024, 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 report 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 $/boe basis), and "net debt". These non-GAAP and other
financial measures are not recognized measures under GAAP (IFRS) and do not have a standardized meaning prescribed by GAAP (IFRS).
Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. These
non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in
accordance with IFRS as indicators of our performance. Management uses these non-GAAP and other financial measures for the reasons set
forth below.
Operating Netback
Operating netback is a common non-GAAP financial measure used in the oil and natural gas industry which is a useful supplemental
measure to evaluate the specific operating performance by product type at the oil and natural gas lease level. The most directly comparable
GAAP measure to operating netback is oil and natural gas sales. Operating netback is calculated as oil and natural gas sales less royalty
expenses, gain (loss) on risk management activities, operating expenses and transportation expenses. See below and under "Summary of
Quarterly Results" for a reconciliation of operating netback to oil and natural gas sales.
Operating netback ($/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 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 and
decommissioning expenditures, plus or minus other income (expense) and the realized gain (loss) on financial derivatives. See below and
under "Summary of Quarterly Results" for a reconciliation of funds flow and corporate netback to oil and natural gas sales.
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.
Three months ended
Dec. 31, 2024
Three months ended
December 31, 2023
Twelve months ended
December 31, 2024
Twelve months ended
December 31, 2023
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
Oil and natural gas sales
22,085
26.48
26,747
30.70
93,721
27.29
125,605
33.41
Royalty expense
(3,212)
(3.85)
(4,167)
(4.78)
(12,572)
(3.66)
(17,255)
(4.59)
Gain (loss) on risk management activities
—
—
—
—
—
—
1,522
0.40
Net oil and natural gas revenue
18,873
22.63
22,580
25.92
81,149
23.63
109,872
29.22
Transportation expense
(1,203)
(1.44)
(1,271)
(1.46)
(5,316)
(1.55)
(6,115)
(1.63)
Operating expense
(4,915)
(5.89)
(4,419)
(5.07)
(20,376)
(5.93)
(23,505)
(6.25)
Operating netback
12,755
15.30
16,890
19.39
55,457
16.15
80,252
21.34
Realized gain (loss) on financial derivatives
2,539
3.04
1,737
1.99
6,930
2.02
8,051
2.14
Other income (expense)
991
1.19
(161)
(0.18)
1,156
0.34
79
0.02
General & administrative expense
(1,752)
(2.10)
(319)
(0.37)
(5,291)
(1.54)
(4,183)
(1.11)
Cash finance expense
(1,530)
(1.83)
(1,246)
(1.43)
(6,418)
(1.87)
(4,801)
(1.28)
Decommissioning expenditures
(510)
(0.61)
(376)
(0.43)
(1,776)
(0.52)
(1,374)
(0.37)
Funds flow and corporate netback
12,493
14.99
16,525
18.97
50,058
14.58
78,024
20.74
Three months ended
Dec. 31, 2024
Three months ended
Sept. 30, 2024
Three months ended
Jun. 30, 2024
Three months ended
March 31, 2024
$000s
$/boe
$000s
$/boe
$000s
$/boe
$000s
$/boe
Oil and natural gas sales
22,085
26.48
20,446
24.12
23,150
26.86
28,039
31.50
Royalty expense
(3,212)
(3.85)
(2,593)
(3.06)
(3,305)
(3.83)
(3,461)
(3.89)
Net oil and natural gas revenue
18,873
22.63
17,853
21.06
19,845
23.03
24,578
27.61
Transportation expense
(1,203)
(1.44)
(1,239)
(1.46)
(1,259)
(1.46)
(1,615)
(1.81)
Operating expense
(4,915)
(5.89)
(5,172)
(6.10)
(4,271)
(4.96)
(6,018)
(6.76)
Operating netback
12,755
15.30
11,442
13.50
14,315
16.61
16,945
19.04
Realized gain (loss) on financial derivatives
2,539
3.04
2,115
2.49
(307)
(0.36)
2,583
2.90
Other income (expense)
991
1.19
77
0.09
40
0.05
48
0.05
General & administrative expense
(1,752)
(2.10)
(1,209)
(1.43)
(1,152)
(1.34)
(1,178)
(1.32)
Cash finance expense
(1,530)
(1.83)
(1,657)
(1.95)
(1,650)
(1.91)
(1,581)
(1.78)
Decommissioning expenditures
(510)
(0.61)
(103)
(0.12)
(618)
(0.72)
(545)
(0.61)
Funds flow and corporate netback
12,493
14.99
10,665
12.58
10,628
12.33
16,272
18.28
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 and decommissioning 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)
As at Dec. 31, 2024
As at Sept. 30, 2024
As at Jun. 30, 2024
As at March 31, 2024
As at Dec. 31, 2023
Long-term debt
25,000
25,000
25,000
25,000
25,000
Current assets
(17,583)
(20,258)
(16,333)
(21,081)
(30,805)
Current liabilities
51,268
48,458
52,379
61,099
61,755
Current financial derivatives
2,632
7,690
1,276
(716)
8,374
Current portion of lease obligation
(164)
(230)
(237)
(263)
(258)
Current portion of decommissioning obligation
(1,073)
(237)
(237)
(925)
(1,470)
Net debt
60,080
60,423
61,848
63,114
62,596
OIL AND GAS DISCLOSURES
Our oil and gas reserves statement for the year ended December 31, 2024, 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 Company's Annual Information Form for the year
ended December 31, 2024 (the "AIF"), which will be filed on SEDAR+ at www.sedarplus.ca. It should not be assumed that the present worth
of estimated future amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the
forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates contained
herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or
less than the estimates provided herein.
This report contains metrics commonly used in the oil and natural gas industry which 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.
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 report, should not be relied upon for investment or other purposes.
F&D Costs and FD&A Costs
FD&A cost is defined as capital costs for the time period including change in FDC divided by change in reserves including revisions and
production for that same time period. F&D cost is defined as capital costs for the time period including change in FDC divided by change in
reserves including revisions and production for that same time period, excluding acquisitions and dispositions. Both F&D costs and FD&A
costs take into account reserves revisions during the year on a per boe basis. The methodology used to calculate F&D costs includes
disclosure required to bring the proved undeveloped and probable reserves to production. Annually, changes in forecast FDC occur as a
result of Petrus' development, acquisition and disposition activities, undeveloped reserve revision and capital cost estimates. These values
reflect the independent evaluator's best estimate of the cost to bring the proved and probable undeveloped reserves to production.
Reserve Life Index
Reserve life index is defined as total reserves by category divided by the annualized fourth quarter production.
Reserve Replacement Ratio
The reserve replacement ratio is calculated by dividing the yearly change in reserves net of production by the actual annual production for
the year.
FD&A Recycle Ratio
The FD&A recycle ratio is calculated by dividing operating netback by FD&A costs.
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,
2024. 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 report 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 report include, but are not limited to statements with respect to: that in 2025, Petrus will continue to execute its strategy of
disciplined capital investment, focusing on projects that sustain production, increase liquids weighting, enhance capital efficiency, and drive
free funds flow; that the Company is well-positioned to carry out its 2025 capital program and achieve guidance targets; that Petrus will
closely monitor market conditions and is prepared to adjust its capital program as needed, guided by its commitment to delivering
sustainable returns to shareholders; the estimated future development costs to bring our undeveloped reserves on production; that we
have a unique ability to be dynamic and respond quickly to constantly evolving market conditions; that Petrus will continue paying an
industry leading, high-yielding dividend to our shareholders while investing remaining cash flow in high return wells and strategic
infrastructure projects; that during periods of low prices, we will maintain production and cash flow and ensure the Company is positioned
to quickly pivot to a growth strategy when pricing is more constructive; that our strengths will continue to serve the Company and our
shareholders well as we navigate the constant changes and challenges inherent in this business; that 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, dividend payments and capital development plans; that the Company's risk management
contracts provide protection from significant changes in crude oil and natural gas commodity prices out to 2026; that the Company
endeavors to hedge approximately half of its forecasted production for up to 12 months forward, and approximately 25% of its forecasted
production for 12 to 24 months forward; that the Company's hedging strategy is intended to provide stability and sustainability to the
Company's economic returns, funds flow, dividend payments and capital development plans; that the Company does not intend to settle its
DSUs for cash; and that the Company expects the working capital deficiency to diminish over the next 12 months as the RLF is paid down by
cash flow from operations. 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 risk that (i) negotiations between the U.S. and Canadian governments are not successful and one or both of such
governments implements announced tariffs, increases the rate or scope of announced tariffs, or imposes new tariffs on the import of goods
from one country to the other, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or
prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed
by the U.S., Canada, China and other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global
economies, and by extension the Canadian oil and natural gas industry and the Company; 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 and/or increase our costs, decrease our production, or otherwise
impede our ability to operate our business; extreme weather events, such as wild fires, floods, drought and extreme cold or warm
temperatures, each of which could result in substantial damage to our assets and/or increase our costs, decrease our production, or
otherwise impede our ability to operate our business; stock market volatility; ability to access sufficient capital from internal and external
sources; that the amount of dividends that we pay may be reduced or suspended entirely; that we reduce or suspend the repurchase of
shares under our NCIB; and the other risks and uncertainties described in our AIF. With respect to forward-looking statements contained in
this report, Petrus has made assumptions regarding: that the tariffs that have been publicly announced by the U.S. and Canadian
governments (but which are not yet in effect) do not come into effect, but that if such tariffs do come into effect, the potential impact of
such tariffs, and that other than the tariffs that have been announced, neither the U.S. nor Canada (i) increases the rate or scope of such
tariffs, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes
any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and
natural gas; the amount of dividends that we will pay; the number of shares that we will repurchase under our NCIB; 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 costs and 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 report 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.
This report contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Petrus' prospective
results of operations including, without limitation, the percentage of our forecast production for the 2025 that is hedged, which are subject
to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in
the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such,
undue reliance should not be placed on FOFI. Petrus' actual results, performance or achievement could differ materially from those
expressed in, or implied by, these FOFI, or if any of them do so, what benefits Petrus will derive therefrom. Petrus has included the FOFI in
order to provide readers with a more complete perspective on Petrus' future operations and such information may not be appropriate for
other purposes.
These forward-looking statements and FOFI are made as of the date of this report and the Company disclaims any intent or obligation to
update any forward-looking statements and FOFI, whether as a result of new information, future events or results or otherwise, other than
as required by applicable securities laws.
BOE Presentation
The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent ("boe") basis whereby
natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas
measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the
6:1 boe measure which is the approximate energy equivalence of the two commodities at the burner tip. Boe's do not represent an
economic value equivalence at the wellhead and therefore may be a misleading measure if used in isolation.
Production & Product Type Information
References to crude oil (or oil), natural gas liquids ("NGLs"), natural gas and average daily production in this document refer to the light and
medium crude oil, conventional natural gas, and NGLs product types, as applicable, as defined in National Instrument 51-101 ("NI 51-101"),
except as noted below.
NI 51-101 includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and
separately from other NGLs since the price of condensate as compared to other NGLs is currently significantly higher and the Company
believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom.
Crude oil therefore refers to light oil, medium oil, and condensate. NGLs refers to ethane, propane, butane and pentane combined. Natural
gas refers to conventional natural gas.
Abbreviations
$000’s
thousand dollars
$/bbl
dollars per barrel
$/boe
dollars per barrel of oil equivalent
$/GJ
dollars per gigajoule
$/mcf
dollars per thousand cubic feet
bbl
barrel
mbbl
thousand barrels
bbl/d
barrels per day
boe
barrel of oil equivalent
mboe
thousand barrel of oil equivalent
mmboe
million barrel of oil equivalent
boe/d
barrel of oil equivalent per day
GJ
gigajoule
GJ/d
gigajoules per day
mcf
thousand cubic feet
mcf/d
thousand cubic feet per day
mmcf/d
million cubic feet per day
NGLs
natural gas liquids
WTI
West Texas Intermediate
CONSOLIDATED ANNUAL FINANCIAL STATEMENTS
As at and for the years ended December 31, 2024 and 2023
PricewaterhouseCoopers LLP
Suncor Energy Centre, 111 5th Avenue South West, Suite 3100, Calgary, Alberta, Canada T2P 5L3
T.: +1 403 509 7500, F.: +1 403 781 1825, Fax to mail: ca_calgary_main_fax@pwc.com
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.
Independent auditor’s report
To the Audit Committee of Petrus Resources Ltd.
Our opinion
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects,
the financial position of Petrus Resources Ltd. and its subsidiaries (together, the Company) as at
December 31, 2024 and 2023, and its financial performance and its cash flows for the years then ended in
accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board
(IFRS Accounting Standards).
What we have audited
The Company’s consolidated financial statements comprise:
the consolidated balance sheets as at December 31, 2024 and 2023;
the consolidated statements of net income (loss) and comprehensive income (loss) for the years then
ended;
the consolidated statements of changes in shareholders’ equity for the years then ended;
the consolidated statements of cash flows for the years then ended; and
the notes to the consolidated financial statements, comprising material accounting policy information
and other explanatory information.
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 believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for
our opinion.
Independence
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. We have fulfilled our other ethical responsibilities
in accordance with these requirements.
Key audit matters
Key audit matters are those matters that, in our professional judgment, were of most significance in our
audit of the consolidated financial statements for the year ended December 31, 2024. These matters were
addressed in the context of our audit of the consolidated financial statements as a whole, and in forming
our opinion thereon, and we do not provide a separate opinion on these matters.
Key audit matter
How our audit addressed the key audit matter
The impact of proved and probable reserves on
property, plant & equipment (PP&E) of the
Ferrier cash generating unit (CGU)
Refer to note 2 – Basis of Presentation, note 3 –
Material Accounting Policies and note 5 – Property,
Plant and Equipment to the consolidated financial
statements.
The Company has $350.9 million of PP&E as at
December 31, 2024 and recorded depletion and
depreciation (D&D) expense of $41.3 million for the
year then ended. Petroleum and natural gas assets
within PP&E are depleted using the unit of
production method based on either proved
developed producing or proved and probable
reserves. The majority of the petroleum and natural
assets relate to the Ferrier CGU and are depleted
based on proved and probable reserves. PP&E is
aggregated into CGUs for purposes of impairment
testing. Management assesses its CGUs for
indicators of impairment each quarter. If indicators
of impairment exist, management estimates the
recoverable amounts of impacted CGUs. If the
carrying amount of a CGU exceeds the recoverable
amount, the CGU is written down with an
impairment recognized in net income. As at
December 31, 2024, management identified
indicators of impairment for its Ferrier CGU and
conducted an impairment test. No impairment was
recognized by management as a result of this
impairment test. Management determined the
recoverable amount of the Ferrier CGU based on
its fair value less costs to disposal using a
Our approach to addressing the matter included the
following procedures, among others:
The work of management’s experts was used
in performing the procedures to evaluate the
reasonableness of the proved and probable
reserves used to determine D&D expense and
the recoverable amount of the Ferrier CGU. As
a basis for using this work, the competence,
capabilities and objectivity of management’s
experts were evaluated, the work performed
was understood and the appropriateness of the
work as audit evidence was evaluated. The
procedures performed also included evaluation
of the methods and assumptions used by
management’s experts, tests of the data used
by management’s experts and an evaluation of
their findings.
Tested how management determined the
recoverable amount of the Ferrier CGU and
proved and probable reserves, which included
the following:
Evaluated the appropriateness of the
methods used by management in making
these estimates.
Tested the data used in determining these
estimates.
Evaluated the reasonableness of key
assumptions used in developing these
estimates:
Key audit matter
How our audit addressed the key audit matter
discounted after-tax future cash flow model based
on proved and probable reserves. Proved and
probable reserves are evaluated by the Company’s
independent reservoir engineers (management’s
experts). Key assumptions used by management to
determine the recoverable amount of the Ferrier
CGU and the proved and probable reserves include
expected future production volumes, forecasted
commodity prices, future development costs, future
operating costs and the discount rate, as
applicable.
We considered this a key audit matter due to (i) the
significant judgment by management, including the
use of management’s experts, when estimating
proved and probable reserves and developing the
expected future cash flows used to determine the
recoverable amount of the Ferrier CGU; (ii) a high
degree of auditor judgment, subjectivity and effort in
performing procedures relating to the significant
assumptions; and (iii) the audit effort that involved
the use of professionals with specialized skill and
knowledge in the field of valuation.
o
Expected future production volumes,
future development costs and future
operating costs by considering the past
performance of the Ferrier CGU, and
whether these assumptions were
consistent with evidence obtained in
other areas of the audit.
o
Forecasted commodity prices by
comparing those forecasts with other
reputable third party industry forecasts.
o
The discount rate, with the assistance
of professionals with specialized skill
and knowledge in the field of valuation.
Recalculated the unit-of-production rates used
to calculate D&D expense for the Ferrier CGU.
Other information
Management is responsible for the other information. The other information comprises the Management’s
Discussion and Analysis and the information, other than the consolidated financial statements and our
auditor’s report thereon, included in the 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 identified above 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.
If, based on the work we have performed, we conclude that there is a material misstatement of this other
information, we are required to report that fact. We have nothing to report in this regard.
Responsibilities of management and those charged with governance for the
consolidated financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial
statements in accordance with IFRS Accounting Standards, 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.
Plan and perform the group audit to obtain sufficient appropriate audit evidence regarding the financial
information of the entities or business units within the Company as a basis for forming an opinion on
the consolidated financial statements. We are responsible for the direction, supervision and review of
the audit work performed for purposes of the group audit. We remain solely responsible for our audit
opinion.
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 McKay.
/s/PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta
March 24, 2025
CONSOLIDATED BALANCE SHEETS
(Presented in 000’s of Canadian dollars)
As at
December 31, 2024
December 31, 2023
ASSETS
Current
Cash
68
375
Carbon credits
590
1,842
Deposits and prepaid expenses (note 21)
2,740
2,536
Accounts receivable
11,553
17,282
Risk management asset (note 9)
2,632
8,770
Total current assets
17,583
30,805
Non-current
Risk management asset (note 9)
—
1,685
Exploration and evaluation assets (note 4)
30,758
30,628
Property, plant and equipment (note 5)
350,937
355,103
Deferred income taxes (note 22)
20,846
19,621
Total non-current assets
402,541
407,037
Total assets
420,124
437,842
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Bank indebtedness
—
208
Revolving loan facility (note 6)
32,744
24,175
Accounts payable and accrued liabilities
17,287
34,003
Dividends payable
—
1,245
Risk management liability (note 9)
—
396
Lease obligations (note 7)
164
258
Current portion of decommissioning obligation (note 8)
1,073
1,470
Total current liabilities
51,268
61,755
Non-current liabilities
Long term debt (note 6)
25,000
25,000
Lease obligations (note 7)
829
105
Decommissioning obligation (note 8)
39,607
35,821
Risk management liability (note 9)
39
—
Total liabilities
116,743
122,681
Shareholders’ equity
Share capital (note 10)
491,875
492,205
Contributed surplus
35,325
31,848
Deficit
(223,819)
(208,892)
Total shareholders' equity
303,381
315,161
Total liabilities and shareholders' equity
420,124
437,842
Commitments (note 18)
See accompanying notes to the consolidated financial statements
Approved by the Board of Directors,
(signed) “Don T. Gray”
(signed) “Donald Cormack”
Don T. Gray
Donald Cormack
Chairman
Director
CONSOLIDATED STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
(Presented in 000’s of Canadian dollars, except per share amounts)
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
REVENUE
Oil and natural gas sales (note 19)
93,721
125,605
Royalty expense
(12,572)
(17,255)
Gain on risk management activities
—
1,522
81,149
109,872
Other income
318
1,302
Net gain (loss) on financial instruments
(536)
12,989
Total revenue and other income
80,931
124,163
EXPENSES
Operating (note 12)
20,376
23,505
Transportation
5,316
6,115
General and administrative (note 13)
5,291
4,183
Share-based compensation (note 10)
2,132
1,863
Finance (note 16)
7,958
6,454
Exploration and evaluation (note 4)
265
4,706
Depletion and depreciation (note 5)
41,263
46,623
Unrealized loss (gain) on foreign exchange
388
(396)
Writedown of carbon credits
413
—
Total expenses
83,402
93,053
INCOME (LOSS) BEFORE INCOME TAX
(2,471)
31,110
Income tax recovery (note 22)
1,225
19,621
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(1,246)
50,731
Net income (loss) per common share
Basic (note 11)
(0.01)
0.41
Diluted (note 11)
(0.01)
0.40
See accompanying notes to the consolidated financial statements
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(UNAUDITED)
(Presented in 000’s of Canadian dollars)
Share
Capital
Contributed
Surplus
Deficit
Total
Balance, December 31, 2022
492,241
29,061
(254,661)
266,641
Net income
—
—
50,731
50,731
Common shares repurchased
(789)
—
—
(789)
Issuance of common shares
753
147
—
900
Share-based compensation
—
2,640
—
2,640
Dividends
—
—
(4,962)
(4,962)
Balance, December 31, 2023
492,205
31,848
(208,892)
315,161
Net loss
—
—
(1,246)
(1,246)
Common shares issued for dividend reinvestment
459
—
—
459
Common shares repurchased
(1,568)
1,054
—
(514)
Issuance of common shares on exercise of stock options
779
(501)
—
278
Share-based compensation
—
2,924
—
2,924
Dividends
—
—
(13,681)
(13,681)
Balance, December 31, 2024
491,875
35,325
(223,819)
303,381
See accompanying notes to the consolidated financial statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(Presented in 000’s of Canadian dollars)
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
OPERATING ACTIVITIES
Net income (loss)
(1,246)
50,731
Adjust items not affecting cash:
Share-based compensation (note 10)
2,132
1,863
Unrealized loss/(gain) on financial derivatives (note 9)
7,466
(4,938)
Non-cash finance expenses (note 16)
1,540
1,653
Depletion and depreciation (note 5)
41,263
46,623
Exploration and evaluation expense (note 4)
265
4,706
Writedown of carbon credits
293
(1,223)
Unrealized loss (gain) on foreign exchange
388
(396)
Deferred income tax recovery (note 22)
(1,225)
(19,621)
Proceeds from carbon credit sale
958
—
Decommissioning expenditures (note 8)
(1,776)
(1,374)
Funds flow
50,058
78,024
Change in operating non-cash working capital (note 17)
8,669
(3,654)
Cash flows from operating activities
58,727
74,370
FINANCING ACTIVITIES
Shares repurchased (note 10)
(514)
(285)
Stock options exercised (note 10)
278
772
Cash dividends paid
(14,368)
(3,716)
Draw down of revolving loan facility
8,181
20,623
Decrease in bank indebtedness
(208)
(451)
Transaction costs on debt
(457)
(315)
Repayment of lease liabilities (note 7)
(277)
(277)
Change in financing non-cash working capital (note 17)
30
—
Cash flows from (used in) financing activities
(7,335)
16,351
INVESTING ACTIVITIES
Property, plant and equipment acquisitions (note 5)
—
(50)
Property, plant and equipment dispositions (note 5)
—
150
Exploration and evaluation asset acquisitions (note 4)
(485)
(1,064)
Petroleum and natural gas property expenditures (note 5)
(31,329)
(85,495)
Exploration and evaluation asset expenditures (note 4)
—
(284)
Change in investing non-cash working capital (note 17)
(19,885)
(3,643)
Cash flows used in investing activities
(51,699)
(90,386)
Increase (decrease) in cash
(307)
335
Cash, beginning of year
375
40
Cash, end of year
68
375
Cash interest paid (note 16)
6,418
4,801
See accompanying notes to the consolidated financial statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2024 and 2023
1. NATURE OF THE ORGANIZATION
Petrus Resources Ltd. (the “Company” or "Petrus") was incorporated under the laws of the Province of Alberta, Canada 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 1110, 240
- 4th Avenue SW, Calgary, Alberta, Canada.
These consolidated financial statements for the years ended December 31, 2024 and 2023 were approved by the Company’s Audit Committee and Board of
Directors on March 24, 2025.
2. BASIS OF PRESENTATION
Statement of Compliance
These consolidated financial statements have been prepared by management in accordance with IFRS Accounting Standards as issued by the
International Accounting Standards Board (“IFRS Accounting Standards”).
Measurement Basis
These consolidated financial statements were prepared on the basis of historical cost unless otherwise required. This method is consistent with the method
used in prior years. These consolidated financial statements are presented in Canadian dollars.
Consolidation
These 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 developed producing
reserves or proved and probable reserves determined in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas
Activities (“NI 51-101”). For assets depleted based on proved and probable reserves, the calculation incorporates the estimated future cost of
developing and extracting those reserves. Reserves are estimated using independent reservoir engineering reports and represent the estimated
quantities of crude oil, natural gas and natural gas liquids for which recoverability in future years from known reservoirs is deemed to be
technically feasible 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.
An independent qualified reserves evaluator (“IQRE”) performs 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 including expected future production volumes,
forecasted commodity prices, future operating costs and future development costs, 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 ("VIU") and fair value less
costs of disposal (FVLCOD). These calculations require the use of estimates and assumptions, including expected future production volumes,
forecasted commodity prices, future operating costs, future development costs and the discount rate . 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 assets and
economical reserves recoverable and may require a material adjustment to the carrying value of exploration and evaluation assets and petroleum
and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets.
iii.
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.
iv.
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.
v.
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.
vi.
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. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary
differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an
evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to
offset the tax assets when the reversal occurs and the application of tax laws.
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.
3. MATERIAL 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. Payments are normally received from customers within 30 days following the end of the production month. The
Corporation does not have any long-term contracts with unfulfilled performance obligations and does not disclose information about remaining
performance obligations with an expected duration of 12 months or less.
(b) Exploration & evaluation assets
Capitalization
All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of exploration
(drilling, testing and evaluating the technical feasibility and commercial viability of extraction) and appraisal and including any directly attributable
general and administration costs and share-based payments, are accumulated and capitalized as exploration and evaluation assets.
Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss).
Depletion & depreciation
Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical
feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation asset will be
reclassified as a property, plant and equipment asset into the CGU to which it relates, but only after the carrying value of the relevant exploration and
evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial viability
are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that technical feasibility and
commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other associated costs are written down
to the recoverable amount in net income (loss).
Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net income
(loss) upon expiry and are considered prior to expiry. Management considers upcoming land lease expiries and may recognize the costs in advance of
expiry.
Impairment
Indicators of impairment of exploration and evaluation assets are assessed at each reporting date which can include upcoming land lease expiries,
third party land valuations and other information. When there are such indications, an impairment test is carried out and any resulting impairment
loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs of disposal, or value-in-use.
(c) Property, plant and equipment
The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets.
Capitalization
Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any.
Petroleum and natural gas assets consists of the purchase price and costs directly attributable to bringing the asset to the location and condition
necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions, geological and
geophysical costs, facility and production equipment, including any directly attributable general and administration costs and share-based payments
and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing
petroleum and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such
capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves, and are
accumulated on a field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in
income or loss as incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are expected to
arise from the continued use of the asset. Any gain or loss arising from the disposal of an asset, determined as the difference between the net disposal
proceeds and the carrying amount of the asset, is recognized in net income or loss.
Depletion and depreciation
The costs for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a unit-of-production method based on
the commercial proved and probable reserves.
Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the period
and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs plus estimated
future development costs necessary to bring those reserves into production. Relative volumes of reserves and production (before royalties) are
converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.
Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil,
natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be
recoverable in future years from known reservoirs and which are considered commercially producible.
Corporate assets are recorded at cost less accumulated depreciation. Depreciation is calculated on a declining balance method so as to write off the
cost of these assets, less estimated residual values, over their estimated useful lives consistent with the treatment used for tax purposes.
Impairment
The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value, less costs
of disposal, and value in use. Petrus’ property, plant and equipment are grouped into CGUs based on separately identifiable and largely independent
cash inflows considering geological characteristics, shared infrastructure and exposure to market risks. Estimates of future cash flows used in the
calculation of the recoverable amount are based on reserve evaluation reports prepared by independent reservoir engineers.
The CGU’s are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying
amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU
exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss).
The recoverable amount is the higher of fair value, less costs of disposal, and the value-in-use. Fair value, less costs of disposal, is derived by
estimating the discounted after-tax future net cash flows. Discounted future net cash flows are based on forecast commodity prices and costs over
the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with
the assets. Value-in-use is assessed using the expected future cash flows discounted at a pre-tax rate.
Impairments of property, plant and equipment are reversed when there is significant evidence that the impairment has been reversed, but only to the
extent of what the carrying amount would have been had no impairment been recognized.
(d) Decommissioning obligations
The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are
estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current
technology in accordance with existing legislation and industry practices.
Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting
date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the
carrying amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as
a finance expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of
the related petroleum and natural gas assets.
Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The
carrying amount capitalized in petroleum and natural gas assets is depleted in accordance with the Company’s depletion policy. The Company reviews
the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or
decrease to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as
an increase or reduction in income.
(e) Finance expenses
Finance expense may be comprised of interest expense on borrowings, acquisition related (transaction) costs, foreign exchange expenses and accretion
of the discount on decommissioning obligations.
(f) Financial instruments
Financial instruments are recognized initially at fair value. Fair value is the price that would be received when selling an asset or paid to transfer a
liability in an orderly transaction between market participants in its principal or most advantageous market at the measurement date.
All assets and liabilities for which fair value is measured or disclosed in the financial statements are further categorized using a three-level hierarchy that
reflects the significance of the lowest level or inputs used in determining fair value:
•
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
At each reporting date, the Company determines whether transfers have occurred between levels in the hierarchy by reassessing the level of
classification for each financial asset and financial liability measured or disclosed at fair value in the financial statements based on the lowest level of
input that is significant to the fair value measurement as a whole. Assessment of the significance of a particular input to the fair value measurement
requires judgement and may affect the placement within the fair value hierarchy.
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) 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.
(i) 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.
(j) Share-based compensation plans
The Company's award plans consist of grants of stock option units and restricted share units ("RSUs") to officers and employees pursuant to an award
plan as well as grants of deferred share units ("DSUs") to non-executive Directors.
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.
(k) 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.
(l) 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.
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.
(m) 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.
(n) 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.
(o) New standards and interpretations
IAS 1 - Presentation of Financial Statements
In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements ("IAS 1"), to clarify its requirements for the presentation of
liabilities as current or non-current in the statement of financial position. The amendments were adopted on January 1, 2024 and had no impact on the
Company's consolidated financial statements.
New Accounting Standards
In April 2024, the IASB issued IFRS 18 "Presentation and Disclosure in Financial Statements" , which provides presentation and disclosure requirements
for the primary financial statements and related notes, replacing IAS 1 "Presentation of Financial Statements". IFRS 18 introduces defined categories for
income and expenses and requires disclosure of new defined subtotals, including operating profit. The new standard also requires additional notes for
management performance measures and disclosure of certain expenses by nature. There are some associated changes to the statement of cash flows,
including the starting point for the calculation of cash flows from operating activities and the categorization of interest and dividends. IFRS 18 is
effective January 1, 2027, with early adoption permitted. The new standard is to be adopted retrospectively. The Company is assessing the impact of
IFRS 18 on the Company's consolidated financial statements.
In May, 2024, the IASB issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures to clarify the date of
recognition and derecognition of financial assets and liabilities and provide further clarification on the classification of certain financial assets. The
amendments are effective January 1, 2026 and are to be applied retrospectively. The Company is evaluating the impact that the amendments will have
on the consolidated financial statements.
4. EXPLORATION AND EVALUATION ASSETS
The components of the Company’s exploration and evaluation ("E&E") assets are as follows:
$000s
Balance, December 31, 2022
34,837
Additions
1,064
Exploration and evaluation expense
(4,706)
Capitalized G&A
284
Capitalized share-based compensation
194
Transfers to property, plant and equipment (note 5)
(1,045)
Balance, December 31, 2023
30,628
Additions
485
Exploration and evaluation expense
(265)
Transfers to property, plant and equipment (note 5)
(90)
Balance, December 31, 2024
30,758
During the year ended December 31, 2024, the Company incurred exploration and evaluation expenses of $0.3 million which relates to expired and nearly
expired undeveloped, non-core land (year ended December 31, 2023 – $4.7 million).
During the year ended December 31, 2024, the Company did not capitalize any of its general and administrative expenses (“G&A”) (year ended December
31, 2023 – $0.3 million) nor its non-cash share-based compensation as the Company did not have any exploration activities during the periods (year ended
December 31, 2023 – $0.2 million).
The Company did not identify any indicators of impairment at December 31, 2024.
5. PROPERTY, PLANT AND EQUIPMENT
The components of the Company’s property, plant and equipment ("PP&E") assets are as follows:
$000s
Cost
Accumulated
DD&A
Net book value
Balance, December 31, 2022
962,616
(646,864)
315,752
Additions
85,220
—
85,220
Property acquisitions
50
—
50
Property dispositions
(150)
—
(150)
Capitalized G&A
852
—
852
Capitalized share based compensation
583
—
583
Transfer from exploration and evaluation assets (note 4)
1,045
—
1,045
Depletion & depreciation
—
(46,623)
(46,623)
Decrease in decommissioning provision (note 8)
(1,626)
—
(1,626)
Balance, December 31, 2023
1,048,590
(693,487)
355,103
Additions
30,168
—
30,168
Addition of right of use asset
888
—
888
Capitalized G&A
1,161
—
1,161
Capitalized share-based compensation (note 10)
792
—
792
Transfers from exploration and evaluation assets (note 4)
90
—
90
Depletion & depreciation
—
(41,263)
(41,263)
Increase in decommissioning provision (note 8)
3,998
—
3,998
Balance, December 31, 2024
1,085,687
(734,750)
350,937
At December 31, 2024, estimated future development costs of $487.5 million (December 31, 2023 – $507.0 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, 2024, the
Company capitalized $1.2 million of general and administrative expenses (“G&A”) (year ended December 31, 2023 – $0.9 million) and non-cash share-based
compensation of $0.8 million, (year ended December 31, 2023 – $0.6 million), directly attributable to development activities.
For the year ended December 31, 2024, due to the decrease in natural gas prices, the Company identified indicator of impairment and conducted an
impairment test on the Ferrier CGU. No impairment was recorded as the carrying amount exceeded the recoverable amount. The Company did not identify
any indicators of impairment or impairment reversal on the Foothills and Central Alberta CGUs for the twelve months ended December 31, 2024.
The recoverable amount, a level 3 input on the fair value hierarchy, was estimated at its fair value less costs of disposal, using an after-tax discount rate of
11.0%. A increase or decrease of one percent in the discount rate or five per cent in the cash flow estimates would not result in any impairment. The
Company uses the following forward commodity price estimates:
Year
WTI in CAD$
AECO $/MMbtu
2025
101.41
2.35
2026
102.07
3.42
2027
102.01
3.60
2028
104.05
3.67
2029
106.13
3.75
2030
108.26
3.82
2031
110.42
3.90
2032
112.63
3.98
2033
114.88
4.05
2034
117.18
4.14
2035
119.52
4.22
Escalation rate of 2.0% thereafter.
At December 31, 2024, the carrying balance of the right of use assets was $1.0 million, net of accumulated depreciation of $1.4 million.
6. DEBT
At December 31, 2024, 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, 2024, the RLF was comprised of a $60.0 million operating facility payable on demand by the lender and has an interest rate of Canada
Prime plus 2.5%. 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, 2025.
At December 31, 2024, the Company had a $0.7 million letter of credit outstanding against the RLF (December 31, 2023 – $0.7 million) and had drawn $32.7
million against the RLF (December 31, 2023 – $24.2 million).
Second Lien Facility
At December 31, 2024 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, 2027) with a fixed interest rate of 11% per annum and can be repaid at the discretion of the Company. The Second Lien
Facility is a related party transaction with a major shareholder who owns approximately 21% of the outstanding shares of the Company. The total interest
paid during the year ended December 31, 2024 to the major shareholder, related to the Second Lien facility, was $2.8 million.
Financial Covenants
The Company's RLF agreement contains various positive covenants in the normal course of business, including 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, less any amounts outstanding under the
Company's RLF.
The Company's RLF is subject to certain financial covenants. The key financial covenant as at December 31, 2024 is summarized in the following table. At
December 31, 2024 the Company is in compliance with all financial covenants.
Financial Covenant Description
Required Ratio
As at December 31, 2024
Working Capital Ratio (as defined in the RLF agreement)
Over 1.00
2.26
7. LEASES
The Company's lease obligations are as follows:
$000s
Balance, December 31, 2023
363
Additions
888
Finance expense
19
Lease payments
(277)
Balance, December 31, 2024
993
The Company's future commitments associated with its lease obligations are as follows:
$000s
As at December 31, 2024
Less than 1 year
164
1 to 3 years
432
4 to 5 years
591
Total lease payments
1,187
Amounts representing finance expense
(194)
Present value of lease obligation
993
Current portion of lease obligation
164
Non-current portion of lease obligation
829
In July, 2024, the Company entered into a new office lease. The Company has recognized a right of use asset of $0.9 million. The asset was measured at
amounts equal to the present value of the lease obligation. The weighted average incremental borrowing rate used to determine the lease obligation at
adoption was 8%.
8. DECOMMISSIONING OBLIGATION
The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon and
reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted
using an average risk free rate of 3.32% and an inflation rate of 2.0% (3.05% and 2.0%, respectively at December 31, 2023). Changes in estimates in 2023
and 2024 are due to the changes 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 $40.7 million as at December 31, 2024 ($37.3 million at
December 31, 2023). The undiscounted, uninflated total future liability at December 31, 2024 is $50.1 million ($44.3 million at December 31, 2023). The
payments are expected to be incurred over the operating lives of the assets with the majority expected to settle between 2023 and 2057.
The following table reconciles the decommissioning liability:
$000s
Balance, December 31, 2022
39,015
Liabilities incurred
525
Liabilities settled
(1,374)
Change in estimates or discount rate
(2,152)
Accretion expense
1,277
Balance, December 31, 2023
37,291
Liabilities incurred
299
Liabilities settled
(1,776)
Change in estimates or discount rate
3,699
Accretion expense
1,167
Balance, December 31, 2024
40,680
Current portion of decommissioning obligation
1,073
Non-current portion of decommissioning obligation
39,607
9. FINANCIAL RISK MANAGEMENT
The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility.
The following table summarizes the financial derivative contracts Petrus had outstanding at December 31, 2024:
Contract Period
Type
Total Daily Volume (GJ)
Average Price (CDN$/GJ)
Natural Gas Swaps
Jan. 1, 2025 to Mar. 31, 2025
Fixed price
19,000
$3.12
Apr. 1, 2025 to Oct. 31, 2025
Fixed price
14,000
$2.62
Nov. 1, 2025 to Mar. 31, 2026
Fixed price
11,000
$3.45
Apr. 1, 2026 to Oct. 31, 2026
Fixed price
6,000
$2.51
Natural Gas Collars
Jan. 1, 2025 to Mar 31, 2025
Costless collar
1,000
$3.25-4.12
Jan. 1, 2025 to Mar 31, 2025
Costless collar
1,000
$3.42-3.62
Apr. 1, 2025 to Oct. 31, 2025
Costless collar
1,000
$3.10-3.83
Apr. 1, 2025 to Oct. 31, 2025
Costless collar
1,000
$2.50-3.16
Nov. 1, 2025 to Mar. 31, 2026
Costless collar
1,000
$3.30-4.08
Contract Period
Type
Total Daily Volume (Bbl)
Average Price (CDN$/Bbl)
Crude Oil Swaps
Jan. 1, 2025 to Mar. 31, 2025
Fixed price
500
$92.64
Jan. 1, 2025 to Jun. 30, 2025
Fixed price
500
$93.38
Jan. 1, 2025 to Dec. 31, 2025
Fixed price
700
$94.01
Apr. 1, 2025 to Sept. 30, 2025
Fixed price
100
$94.05
Jul. 1, 2025 to Sept. 30, 2025
Fixed price
100
$95.25
Jul. 1, 2025 to Dec. 31, 2025
Fixed price
300
$93.32
Jan. 1, 2026 to Mar. 31, 2026
Fixed price
200
$91.05
Jan. 1, 2026 to Jun. 30, 2026
Fixed price
300
$92.32
Jan. 1, 2026 to Dec. 31, 2026
Fixed price
100
$90.05
Jul. 1, 2026 to Sept. 30, 2026
Fixed price
100
$87.25
The following is a summary of Petrus's financial assets and financial liabilities that are subject to offsetting as December 31, 2024 and December 31, 2023:
$000s At December 31, 2023
Gross Amounts of
Recognized Financial
Assets (Liabilities)
Gross Amounts of
Recognized Financial
Assets (Liabilities) Offset
on Balance Sheets
Net Amounts of
Financial Assets
(Liabilities) Recognized
on Balance Sheets
Risk management contracts
Current asset
9,767
(996)
8,771
Long-term asset
2,093
(408)
1,685
Current liabilities
(396)
—
(396)
Net position
11,464
(1,404)
10,060
$000s At December 31, 2024
Risk management contracts
Current asset
5,630
(2,998)
2,632
Long-term asset
—
—
Current liability
564
(603)
(39)
Net position
6,194
(3,601)
2,593
Earnings impact of realized and unrealized gains (losses) on financial derivatives:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Realized gain on financial derivatives
6,930
8,051
Unrealized gain/(loss) on financial derivatives
(7,466)
4,938
Net gain/(loss) on financial derivatives
(536)
12,989
10. SHARE CAPITAL
Authorized
The authorized share capital consists of an unlimited number of common voting shares without par value and an unlimited number of preferred shares.
Issued and Outstanding
Common shares ($000s)
Number of Shares
Amount
Balance, December 31, 2022
123,238,528
492,241
Common shares repurchased
(198,700)
(789)
Common shares issued on exercise of stock options
1,226,542
753
Balance, December 31, 2023
124,266,370
492,205
Common shares repurchased
(396,100)
(1,568)
Common shares issued on exercise of stock options
842,614
779
Common shares issued for dividend reinvestment plan
400,245
459
Balance, December 31, 2024
125,113,129
491,875
Dividends
On October 10, 2023, the Company declared a special dividend of $0.03 per common share totaling $3.7 million that was paid in November 2023. During
the year ended December 31, 2023, the Company declared a monthly dividend of $0.01 per common share totaling $1.2 million, with the first paid in
January 2024. During the twelve months ended December 31, 2024 the Company declared dividends of $13.7 million and paid $14.9 million (including $0.5
million in shares as dividend reinvestment).
Normal Course Issuer Bid ("NCIB")
On June 25, 2024, the Company announced the approval of its renewed NCIB by the Toronto Stock Exchange ("the TSX"). The 2024 NCIB allows the
Company to purchase up to 6,218,596 common shares over a period of twelve months (expiring no later than June 27, 2025).
Purchases are made on the open market through the TSX or alternative Canadian trading platforms at the market price of such common shares. All
common shares purchased under the NCIB are cancelled. The total cost paid, including commissions and fees, is first charged to share capital to the extent
of the average carrying value of the Company’s common shares and the excess paid is recorded to retained earnings and any shortfall is recorded to
contributed surplus.
During the year ended December 31, 2024, the Company repurchased 396,100 shares for cancellation at an average price of $1.30 per share totaling 0.5
million .
SHARE-BASED COMPENSATION
Stock Options
The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate
number of shares that may be acquired upon exercise of all options granted pursuant to the plans shall, at any date or time of determination, be equal to
ten percent (10%) of the number that is equal to (i) the number of the Company’s basic common shares then issued and outstanding; minus (ii) a number
equal to five (5) times the number of common shares that are issuable upon exercise of the then outstanding Performance Warrants, if any, minus (iii) a
number equal to fifty percent (50%) of the number of common shares that have previously been issued upon the exercise of Performance Warrants, if any.
At December 31, 2024, 8,482,331 (December 31, 2023 – 8,616,900) stock options were outstanding. The summary of stock option activity is presented
below:
Number of stock
options
Weighted average
exercise price
Balance, December 31, 2022
8,519,709
$1.56
Granted
3,245,000
$1.67
Forfeited
(447,501)
$0.59
Expired
(1,207,500)
$2.12
Exercised
(1,492,808)
$0.61
Balance, December 31, 2023
8,616,900
$1.74
Granted
4,173,001
$1.50
Forfeited
(550,000)
$2.09
Expired
(2,081,256)
$2.20
Exercised
(1,676,314)
$0.77
Balance, December 31, 2024
8,482,331
$1.57
Exercisable, December 31, 2024
2,018,920
$1.65
The following table summarizes information about the stock options granted and outstanding:
Range of Exercise Price
Stock Options Outstanding
Number granted
Weighted average
exercise price
Weighted average
remaining life (years)
$0.75
449,171
$0.75
0.13
$0.89
120,908
$0.89
0.13
$1.26
1,147,000
$1.26
1.38
$1.33
929,001
$1.33
1.90
$1.37-$1.78
4,117,910
$1.46
1.51
$2.09
340,000
$2.09
0.91
$2.25
755,000
$2.25
0.63
$2.81
623,341
$2.81
0.63
8,482,331
$1.57
1.28
During the year ended December 31, 2024 the Company granted 4,173,001 options which vest equally over three years, and upon vesting, expire within 90
days thereafter. The weighted average fair value of each option granted during the twelve months ended December 31, 2024 of $0.51 was estimated on
the date of grant using the Black-Scholes pricing model with the following weighted average assumptions:
2024
2023
Risk free interest rate
3.23% - 4.79%
3.54% - 5.04%
Expected life (years)
1.00 - 3.00
1.13 - 3.13
Estimated volatility of underlying common shares (%)
72.62% - 77.90%
100% to 113%
Estimated forfeiture rate
5 %
33 %
Expected dividend yield (%)
9 %
— %
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.
Restricted Share Unit ("RSU") Plan
The Company has a restricted share unit plan in place whereby it may issue restricted share units to officers, employees and consultants of the Company.
Each RSU 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 RSUs unless otherwise determined by the Board, vest as to one-third (1/3) annually over three years from the grant
date. At December 31, 2024, 470,000 RSUs were issued and outstanding (December 31, 2023 – Nil).
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. 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 as equity using the fair value method based on the trading price of the Company's shares on the grant date. At
December 31, 2024, 1,811,963 DSUs were issued and outstanding (December 31, 2023 – 1,658,837).
On each date that a dividend payment is made, holders of DSUs are credited with additional DSUs; the number of additional DSUs is calculated by dividing
the dividends that would have been paid to such holder if the DSUs held at the record date of the cash dividend had been common shares, by the fair
market value of the common shares on the date on which the dividends are paid on the common shares.
Share-based Compensation
The following table summarizes the Company’s share-based compensation costs:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Expensed
2,132
1,863
Capitalized to exploration and evaluation assets
—
194
Capitalized to property, plant and equipment
792
583
Total share-based compensation
2,924
2,640
11. NET INCOME (LOSS) PER SHARE
Net income (loss) 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.
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Net income (loss) for the period ($000s)
(1,246)
50,731
Weighted average number of common shares – basic (000s)
124,389
123,469
Weighted average number of common shares – diluted (000s)
124,389
126,436
Net income (loss) per common share – basic
($0.01)
$0.41
Net income (loss) per common share – diluted
($0.01)
$0.40
In computing diluted income per share for the twelve months ended December 31, 2024, no outstanding stock options, DSUs, or RSUs were included as they
were considered anti-dilutive. For the twelve months ended December 31, 2023 – 8,616,900 outstanding stock options, 1,658,837 DSUs, and nil RSUs were
considered in computing dilutive earnings per share.
12. OPERATING EXPENSES
The Company’s operating expenses consisted of the following expenditures:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Fixed and variable operating expenses
17,137
19,833
Processing, gathering and compression charges
4,568
5,068
Total gross operating expenses
21,705
24,901
Overhead recoveries
(1,329)
(1,396)
Total net operating expenses
20,376
23,505
13. GENERAL AND ADMINISTRATIVE EXPENSES
The Company’s general and administrative expenses consisted of the following expenditures:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Salaries
4,152
4,012
Other general and administrative expenses
3,026
3,125
Gross general and administrative expense
7,178
7,137
Capitalized general and administrative expense
(1,161)
(1,136)
Overhead recoveries
(726)
(1,818)
General and administrative expense
5,291
4,183
14. FINANCIAL INSTRUMENTS
At December 31, 2024, the Company's financial instruments include cash, accounts receivable, risk management contracts, accounts payable and accrued
liabilities, revolving loan facility, lease obligations, and long-term debt.
The Company's Risk management contracts are carried at fair value on the balance sheets. These contracts are classified as Level 2 measurements in the
three-level fair value measurement hierarchy. The approximate fair value of the Company's long term debt is disclosed in Note 6.
The carrying value of accounts receivable, accounts payable and accrued liabilities, and revolving loan facility as at December 31, 2024 approximate their
fair values due to the short term nature of these instruments.
Risks associated with financial instruments
Credit risk
The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal
credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound purchasers
under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating to
the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $11.6 million of accounts receivable outstanding
at December 31, 2024 (December 31, 2023 – $17.3 million), $5.4 million is owed from 2 parties (December 31, 2023 – $5.8 million from 2 parties), and the
balances were received subsequent to the year end. The Company considers accounts receivable outstanding past 120 days to be 'past due'. At
December 31, 2024, the Company had an expected credit loss of $0.1 million (December 31, 2023 – $0.1 million). At December 31, 2024, 99.2% of Petrus’
accounts receivable were aged less 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
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company actively manages its liquidity
through continuously monitoring forecast and actual cash flows activities and available credit and working capital facilities under existing banking
arrangements. The Company believes that future cash flows generated from these sources will be adequate to settle Petrus's financial liabilities.
At December 31, 2024, the Company had a $60.0 million RLF, of which $32.7 million was drawn (December 31, 2023 – $24.4 million). For the year ended
December 31, 2024, the Company generated cash flow from operating activities of $58.7 million.
The following are the contractual maturities of financial liabilities as at December 31, 2024:
$000s
Total
< 1 year
1-5 years
Accounts payable and accrued liabilities
17,287
17,287
—
Long term debt
31,638
2,750
28,888
Revolving Loan Facility
34,779
34,779
—
Lease obligations (discounted)
993
164
829
Total
84,697
54,980
29,717
At December 31, 2024, the Company had a working capital deficiency (excluding non-cash risk management assets and liabilities) of $36.3 million, primarily
due to the $32.7 million drawn on the RLF, which is classified as a current liability. The RLF has a credit limit of $60 million and is payable upon demand, with
the borrowings classified as current liabilities as of December 31, 2024. Excluding the RLF, the working capital deficit would have been $3.5 million.
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 twelve months ended December 31, 2024 and holding all other factors constant, would
have increased/decreased net income by approximately $0.3 million, which relates to interest expense on the average outstanding RLF during the periods
assuming that all other variables remain constant (December 31, 2023 – $0.1 million).
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 RLF 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 9). 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, holding all other
factors constant.
At December 31, 2024, it was estimated that a $0.25/GJ decrease in the price of natural gas would have increased income before income taxes by $2.1
million (December 31, 2023 – $2.1 million). An opposite change in commodity prices would result in an opposite impact on net income before income
taxes. At December 31, 2024, it was estimated that a $5.00/CDN WTI/bbl decrease in the price of oil would have increased income before income taxes by
$3.0 million (December 31, 2023 – $3.6 million). An opposite change in commodity prices would result in an opposite impact on net income before income
taxes.
Foreign Exchange Risk
The Company is exposed to the risk of changes in the U.S./Canadian dollar exchange rate on crude oil sales based on U.S. dollar benchmark prices and
commodity contracts that are settled in U.S. dollars. Foreign exchange risk is mitigated by entering into Canadian dollar denominated commodity risk
management contracts.
15. 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.
The Company's net debt is as follows:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Long-term debt
25,000
25,000
Current assets
(17,583)
(30,805)
Current liabilities
51,268
61,755
Current financial derivatives
2,632
8,374
Current portion of lease obligation
(164)
(258)
Current portion of decommissioning obligation
(1,073)
(1,470)
Net debt
60,080
62,596
16. FINANCE EXPENSES
The components of finance expenses are as follows:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Cash:
Interest
5,796
4,205
Finance fees
622
596
Foreign exchange
—
—
Total cash finance expenses
6,418
4,801
Non-cash:
Deferred financing costs
373
376
Accretion on decommissioning obligations (note 8)
1,167
1,277
Total non-cash finance expenses
1,540
1,653
Total finance expenses
7,958
6,454
17. SUPPLEMENTAL CASH FLOW INFORMATION
The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Source (use) in non-cash working capital:
Deposits and prepaid expenses
(227)
(505)
Transaction costs on debt
30
60
Carbon credits
—
(630)
Accounts receivable
5,729
4,966
Accounts payable and accrued liabilities
(16,718)
(11,188)
(11,186)
(7,297)
Operating activities
8,669
(3,654)
Financing activities
30
—
Investing activities
(19,885)
(3,643)
The following table reconciles the changes in liability resulting from financing activities:
$000s
Bank Indebtedness
Revolving Credit
Facility
Term Loan Total Liabilities from
Financing Activities
Balance, December 31, 2023
208
24,175
25,000
49,383
Cash flows
(208)
8,181
—
7,973
Non-cash changes
—
388
—
388
Balance, December 31, 2024
—
32,744
25,000
57,744
18. COMMITMENTS AND CONTINGENCIES
Commitments
The commitments for which the Company is responsible as at December 31, 2024 are as follows:
$000s
Total
< 1 year
1-5 years
> 5 years
Firm service transportation
6,587
2,799
3,788
—
The commitments for which the Company was responsible as at December 31, 2023 were as follows:
$000s
Total
< 1 year
1-5 years
> 5 years
Firm service transportation
9,386
2,799
6,587
—
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.
19. REVENUE
The following table presents Petrus' oil and natural gas revenue disaggregated by product type:
$000s
Year ended
Dec. 31, 2024
Year ended
Dec. 31, 2023
Oil and condensate sales
48,338
55,676
Natural gas sales
22,365
46,972
Natural gas liquids sales
22,848
22,603
Royalty revenue
170
354
Total oil and natural gas sales
93,721
125,605
Royalty expense
(12,572)
(17,255)
Gain (loss) on risk management activities
—
1,522
81,149
109,872
20. RELATED PARTY TRANSACTIONS
The Company considers its directors and officers to be key management personnel. The following table outlines transactions with key management
personnel:
$000s
Year ended
December 31, 2024
Year ended
December 31, 2023
Salaries, consulting fees, benefits and director fees, gross
1,485
1,348
Share based compensation, gross
1,080
1,135
2,565
2,483
21. DEPOSITS AND PREPAID EXPENSES
The components of the Company’s deposits and prepaid expenses for the periods indicated are as follows:
$000s
As at December 31, 2024
As at December 31, 2023
Prepaid interest and bank fees
146
169
Prepaid insurance
380
202
Prepaid operating expenses
19
19
Prepaid software
206
154
Deposits
1,989
1,992
Deposits and prepaid expenses
2,740
2,536
22. DEFERRED INCOME TAXES
$000s
2024
2023
Income (loss) before income taxes
(2,471)
31,110
Combined federal and Alberta tax rate
23 %
23 %
Computed “expected” tax recovery (expense)
568
(7,155)
Increase/(decrease) in taxes resulting from:
Share based payments
(530)
(429)
True up and other
1,187
19
Unrecognized deferred income tax asset
—
27,186
Deferred tax expense recovery
1,225
19,621
The components of the Company’s deferred tax position at December 31, 2024 and 2023 are as follows:
$000s
2024
2023
Exploration and evaluation assets and property, plant and equipment
(42,308)
(37,305)
Asset retirement obligations
9,356
8,577
Non capital loss carry-forwards
54,099
50,608
Unrealized hedging loss
(605)
(2,314)
Other
304
55
Deferred tax asset
20,846
19,621
The Company had non-capital losses of approximately $240.4 million (2023 – $221.4 million) which may be applied against future income for Canadian tax
purposes. These non-capital losses expire in 2032 and onwards.
CORPORATE INFORMATION
OFFICERS & VICE PRESIDENTS
DIRECTORS
SOLICITOR
Ken Gray, P.Eng
President and
Chief Executive Officer
Don T. Gray
Chairman
Scottsdale, Arizona
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
Mathew Wong, CPA, CFA, CPA (WA, USA)
Chief Financial Officer
Ken Gray
Calgary, Alberta
AUDITOR
PricewaterhouseCoopers LLP (PwC)
Chartered Professional Accountants
Calgary, Alberta
Matt Skanderup
Chief Operating Officer
Patrick Arnell
Calgary, Alberta
Lindsay Hatcher
Vice President, Commercial & Corporate
Development
Donald Cormack
Calgary, Alberta
INDEPENDENT RESERVE EVALUATORS
InSite Petroleum Consultants Ltd.
Calgary, Alberta
Peter Verburg
Calgary, Alberta
BANKERS
ATB Financial
Calgary, Alberta
TRANSFER AGENT
Odyssey Trust Company
Calgary, Alberta
HEAD OFFICE
1110, 240 – 4th Avenue S.W.
Calgary, Alberta T2P 4H4
Phone: 403-984-9014
Fax: 403-984-2717
WEBSITE
www.petrusresources.com