ANNUAL REPORT
AS AT AND FOR THE YEAR ENDED
DECEMBER 31, 2024
[THIS PAGE IS INTENTIONALLY BLANK]
(1) Refer to advisories regarding non-GAAP and other financial measures.
(2) The three year average ROACE at December 31, 2024 was 14%. Refer to additional information under “Non-GAAP and Other Financial Measures”.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
Three months ended
December 31
Year ended
December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
FINANCIAL
Petroleum and natural gas sales
125,064
129,000
-3
468,432
495,580
-5
Cash provided by operating activities
48,067
62,477
-23
209,145
283,224
-26
Adjusted funds from operations (1)
69,406
66,618
4
221,978
276,200
-20
Basic ($/common share) (1)
0.35
0.34
3
1.13
1.43
-21
Diluted ($/common share) (1)
0.35
0.33
6
1.11
1.40
-21
Net income and comprehensive income
13,800
23,729
-42
45,423
85,974
-47
Basic ($/common share)
0.07
0.12
-42
0.23
0.45
-49
Diluted ($/common share)
0.07
0.12
-42
0.23
0.44
-48
Capital expenditures, net of A&D (1)
97,046
62,695
55
333,147
282,646
18
Total assets
1,450,679
1,260,292
15
1,450,679
1,260,292
15
Bank debt
108,993
-
-
108,993
-
-
Net debt (1)
124,883
12,997
861
124,883
12,997
861
Shareholders' equity
1,063,004
1,003,663
6
1,063,004
1,003,663
6
Return on average capital employed (%) (1)(2)
6
12
-50
Weighted average shares outstanding (000s)
Basic
196,557
194,359
1
195,719
193,116
1
Diluted
200,801
199,223
1
199,631
197,063
1
OPERATIONS
Average daily production
Oil (bbls/d)
9,297
8,832
5
8,623
7,979
8
NGLs (bbls/d)
5,052
3,422
48
3,675
3,759
-2
Gas (mcf/d)
132,608
120,541
10
124,902
112,634
11
Combined (BOE/d)
36,450
32,344
13
33,115
30,510
9
Production per million common shares (BOE/d) (1)
185
166
11
169
158
7
Net realized prices, before derivative financial instruments (1)
Oil ($/bbl)
92.53
95.68
-3
94.46
97.90
-4
NGLs ($/bbl)
38.50
49.79
-23
47.56
49.27
-3
Gas ($/mcf)
2.02
2.75
-27
1.97
3.08
-36
Operating netbacks ($/BOE) (1)
Petroleum and natural gas sales
37.30
43.35
-14
38.66
44.51
-13
Cost of purchases
(0.99)
(1.66)
-40
(1.35)
(1.50)
-10
Combined net realized price, before derivative financial instruments(1)
36.31
41.69
-13
37.31
43.01
-13
Realized gain on derivative financial instruments
0.70
0.09
678
0.35
1.35
-74
Combined net realized price, after derivative financial instruments(1)
37.01
41.78
-11
37.66
44.36
-15
Royalties
(2.85)
(6.03)
-53
(4.52)
(5.31)
-15
Production expense
(8.72)
(8.62)
1
(10.01)
(9.83)
2
Transportation expense
(3.64)
(3.64)
-
(3.52)
(3.48)
1
Operating netback (1)
21.80
23.49
-7
19.61
25.74
-24
Land holdings
Gross acres
790,918
796,519
-1
790,918
796,519
-1
Net acres
588,527
581,553
1
588,527
581,553
1
Reserves – proved plus probable
Crude oil and liquids (Mbbls) (2)
173,779
149,163
17
173,779
149,163
17
Gas (MMcf)
1,568,229
1,583,515
-1
1,568,229
1,583,515
-1
Combined (MBOE)
435,151
413,082
5
435,151
413,082
5
KELT EXPLORATION LTD.
1
ANNUAL REPORT
MESSAGE TO SHAREHOLDERS
Kelt Exploration Ltd. (“Kelt” or the “Company”) reports its financial and operating results to shareholders for the fourth
quarter and year ended December 31, 2024.
Average production for the three months ended December 31, 2024 was 36,450 BOE per day, up 13% compared to
average production of 32,344 BOE per day during the fourth quarter of 2023. Average production for 2024 was 33,115
BOE per day, an increase of 9% from an average production of 30,510 BOE per day in 2023. Production for the three
months ended December 31, 2024 was weighted 39% to oil and NGLs and 61% to gas.
Petroleum and natural gas sales during the fourth quarter of 2024 decreased 3% to $125.1 million, down from $129.0
million in the same period of the previous year. Petroleum and natural gas sales for the year were $468.4 million, down
5% from $495.6 million in 2023. Kelt’s net realized average oil price during the fourth quarter of 2024 was $92.53 per
barrel, down 3% from $95.68 per barrel in the fourth quarter of 2023. The Company’s net realized average NGLs price
during the fourth quarter of 2024 was $38.50 per barrel, down 23% from $49.79 per barrel in the fourth quarter of 2023.
Kelt’s net realized average gas price for the fourth quarter of 2024 was $2.02 per Mcf, down 27% from $2.75 per Mcf
in the fourth quarter of 2023.
For the three months ended December 31, 2024, adjusted funds from operations was $69.4 million ($0.35 per share,
diluted), compared to $66.6 million ($0.33 per share, diluted) in the fourth quarter of 2023. Year over year, adjusted
funds from operations decreased 20% to $222.0 million ($1.11 per share, diluted) from $276.2 million ($1.40 per share,
diluted) in 2023. During 2024, Kelt recorded net income of $45.4 million ($0.23 per share, diluted) compared to $86.0
million ($0.44 per share, diluted) in the previous year.
Kelt’s three-year average ROACE is 14% and the three-year average recycle ratio based on proved plus probable
reserves added was 2.3 times, showing favourable returns on capital employed as the Company has been transitioning
from exploration and resource delineation to development and multi-well pad drilling.
At December 31, 2024, Kelt had net debt of $124.9 million compared to $13.0 million at December 31, 2023. At a year-
end net debt to adjusted funds from operations ratio of 0.6 times, Kelt continues to maintain a strong financial position.
Capital expenditures, net of A&D incurred during the three months ended December 31, 2024 were $97.0 million, up
55% compared to net capital expenditures of $62.7 million during the fourth quarter of 2023. During the fourth quarter
of 2024, the Company spent $63.1 million on drill and complete operations; $30.4 million on well equipment, facilities
and pipelines; and Kelt also completed a complementary Montney acquisition for $3.5 million.
OPERATIONS UPDATE
Kelt’s planned 2025 capital expenditure program remains unchanged at $328.0 million. Kelt’s previous guidance for
2025 production to average between 44,000 and 48,000 BOE per day also remains unchanged.
At Wembley/Pipestone, in January 2025, Kelt completed a 3-well Montney pad (14-2 surface). These three wells
were brought forward and drilled in the fourth quarter of 2024.
At Wembley/Pipestone, during January and February, the Company drilled a 4-well Montney pad (9-17 surface).
These four wells are expected to be completed in April 2025.
Also, at Wembley/Pipestone, Kelt drilled and completed two Charlie Lake wells (62% working interest).
Kelt continues to have significant production volumes shut-in at Wembley/Pipestone as it awaits construction
completion of a new third-party gas plant where the Company has 50 MMcf per day of raw gas firm processing
service. Start-up of the new gas plant, after facing unexpected additional repairs to certain equipment, is still
expected to commence in the second quarter of 2025.
At Progress, the Company is currently drilling four Charlie Lake wells (50% working interest). These four wells are
expected to be completed during May 2025.
KELT EXPLORATION LTD.
2
ANNUAL REPORT
At Pouce Coupe West, Kelt is currently drilling two Montney wells and it expects to complete these wells by the
end of the first quarter.
In its Pouce Coupe/Progress/Spirit River division, a new third-party gas plant located at Gordondale West where
Kelt will initially have 25 MMcf per day of raw gas firm processing service, is expected to finish construction and
start-up in May 2025. This will provide Kelt with the opportunity to bring its newly drilled wells in the area on-stream.
At Oak, the Company is currently conducting a 3-D seismic shoot covering approximately 110 sections of land.
With the start-up of the two new third-party gas processing plants in the second quarter, Kelt expects to ramp up
production significantly leading into the third quarter of 2025.
Management looks forward to updating shareholders with 2025 first quarter results on or about May 8, 2025.
On behalf of the Board of Directors,
[signed]
David J. Wilson
President and Chief Executive Officer
March 12, 2025
KELT EXPLORATION LTD.
3
ANNUAL REPORT
MANAGEMENT’S DISCUSSION & ANALYSIS
Kelt Exploration Ltd. (“Kelt” or the “Company”) is an oil and gas company based in Calgary, Alberta, focused on the
exploration, development and production of crude oil and natural gas resources in Western Canada. Kelt’s business
plan is for long-term profitable growth by implementing a full cycle exploration and development program, with emphasis
on low-cost land accumulation with the potential for high rates of return on capital invested. Kelt has an active
exploration and development drilling program that it may complement with acquisitions and dispositions that optimize
its asset base.
The Company was incorporated under the Business Corporations Act (Alberta) on October 11, 2012. Kelt’s assets are
comprised of three core operating divisions, namely: (1) Wembley/Pipestone in Alberta; (2) Pouce
Coupe/Progress/Spirit River in Alberta; and (3) Oak/Flatrock in British Columbia. The Company’s British Columbia
assets are operated by Kelt Exploration (LNG) Ltd. (“Kelt LNG”), a wholly owned subsidiary of Kelt. The head office of
the Company is located at Suite 300, 311 - 6th Avenue S.W., Calgary, Alberta T2P 3H2. The Company’s common
shares are listed on the Toronto Stock Exchange (“TSX”) under the symbol “KEL”. Additional information relating to
Kelt can be found on SEDAR+ at www.sedarplus.ca.
This Management’s Discussion and Analysis (“MD&A”) is dated March 12, 2025 and should be read in conjunction with
the Company’s consolidated financial statements and related notes as at and for the year ended December 31, 2024.
The accompanying financial statements have been prepared in accordance with International Financial Reporting
Standards, as issued by the International Accounting Standards Board (“IFRS Accounting Standards”). The Company’s
Board of Directors approved and authorized the consolidated financial statements on March 12, 2025.
GENERAL ADVISORY
This MD&A contains certain specified financial measures consisting of non-GAAP measures, capital management
measures, and supplementary financial measures. These non-GAAP and other financial measures include “funds from
operations”, “adjusted funds from operations”, “adjusted funds from operations per common share”, “petroleum and
natural gas sales after cost of purchases”, “operating income”, “operating netback”, “capital expenditures, before A&D”,
“capital expenditures, net of A&D”, “net debt (surplus)”, “net realized prices”, “combined net realized prices”, and “net
debt (surplus) to adjusted funds from operations ratio” which do not have standardized meanings prescribed by
generally accepted accounting principles (“GAAP”) and therefore may not be comparable to similar measures
presented by other companies where similar terminology is used. For further information and reconciliation to Canadian
generally accepted accounting principles “GAAP” measures, see “Non-GAAP and Other Financial Measures” in this
MD&A.
This MD&A contains forward-looking information within the meaning of applicable Canadian securities laws. The use
of and of the words “will”, “expects”, “believe”, “plans”, potential”, “forecasts” and similar expressions are intended to
identify forward-looking statements. Such forward-looking information is based upon certain expectations and
assumptions and actual results may differ materially from those expressed or implied by such forward-looking
information. For further information regarding the forward-looking information contained herein, including the
assumptions underlying such forward-looking information, see “Advisories Regarding Forward-Looking Statements” in
this MD&A.
BASIS OF PRESENTATION
All dollar amounts are referenced in thousands of Canadian dollars, except when noted otherwise. This MD&A contains
various references to the abbreviation BOE which means barrels of oil equivalent. Where amounts are expressed on a
BOE basis, natural gas volumes have been converted to oil equivalence at six thousand cubic feet per barrel and
sulphur volumes have been converted to oil equivalence at 0.6 long tons per barrel. The term BOE may be misleading,
particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the
wellhead and is significantly different than the value ratio based on the current price of crude oil and natural gas. This
conversion factor is an industry accepted norm and is not based on either energy content or current prices. Such
abbreviation may be misleading, particularly if used in isolation.
KELT EXPLORATION LTD.
4
ANNUAL REPORT
FINANCIAL AND OPERATING SUMMARY
Three months ended
December 31
Year ended
December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
FINANCIAL PERFORMANCE
Petroleum and natural gas sales
125,064
129,000
-3
468,432
495,580
-5
Cash provided by operating activities
48,067
62,477
-23
209,145
283,224
-26
Adjusted funds from operations (1)
69,406
66,618
4
221,978
276,200
-20
Diluted ($/common share) (1)
0.35
0.33
6
1.11
1.40
-21
Net income and comprehensive income
13,800
23,729
-42
45,423
85,974
-47
Diluted ($/common share)
0.07
0.12
-42
0.23
0.44
-48
Capital expenditures, net of A&D (1)
97,046
62,695
55
333,147
282,646
18
Bank debt
108,993
-
-
108,993
-
-
Net debt (1)
124,883
12,997
861
124,883
12,997
861
Return on average capital employed (%) (1)
6
12
-50
OPERATIONAL PERFORMANCE
Average daily production (BOE/d)
36,450
32,344
13
33,115
30,510
9
Combined net realized price, before derivative financial instruments (1)
36.31
41.69
-13
37.31
43.01
-13
Combined net realized price, after derivative financial instruments (1)
37.01
41.78
-11
37.66
44.36
-15
Operating netback (1)
21.80
23.49
-7
19.61
25.74
-24
Reserves – proved plus probable (MBOE)
435,151
413,082
5
435,151
413,082
5
(1) Refer to advisories regarding non-GAAP and other financial measures.
Kelt’s key financial and operating results in the fourth quarter of 2024 are highlighted by the following:
Production – Fourth quarter 2024 production averaged 36,450 BOE per day (39% oil/NGLs), an increase of 13%
from 32,344 BOE per day (38% oil/NGLs) in the fourth quarter of 2023 and an increase of 13% from 32,378 BOE
per day (37% oil/NGLs) in the third quarter of 2024.
Petroleum and natural gas sales – For the three months ended December 31, 2024, petroleum and natural gas
sales was $125.1 million, a decrease of 3% from $129.0 million in the fourth quarter of 2023. Kelt’s combined net
realized price, before derivative financial instruments of $36.31 per BOE decreased 13% from the fourth quarter
of 2023.
Operating netback – Kelt’s operating netback of $21.80 for the quarter ended December 31, 2024 decreased by
7% from the fourth quarter of 2023. The decrease in the operating netback was primarily due to lower petroleum
and natural gas sales in 2024.
Cash provided by operating activities and adjusted funds from operations – Cash provided by operating
activities decreased to $48.1 million in the fourth quarter of 2024 compared to $62.5 million in the fourth quarter of
2023. Adjusted funds from operations of $69.4 million during the three months ended December 31, 2024 ($0.35
per common share, diluted) increased 4% from the fourth quarter of 2023 primarily due to a 13% production
increase.
Net income – Kelt reported net income of $13.8 million ($0.07 per common share, diluted) for the three months
ended December 31, 2024, compared to net income of $23.7 million ($0.12 per common share, diluted) in the
comparative period in 2023.
Capital investments – During the fourth quarter of 2024, capital expenditures, net of A&D, was $97.1 million and
included the drilling of 3.0 net wells and completion of 12.0 net wells. Facilities, pipeline and well equipment spend
was $30.4 million.
KELT EXPLORATION LTD.
5
ANNUAL REPORT
Liquidity – The Company ended the quarter with net debt of $124.9 million (0.6 times trailing 12-month adjusted
funds from operations).
Reserves - The Company increased its oil and gas reserves at December 31, 2024:
o
Proved developed producing reserves of 78.9 million BOE (38% oil and NGLs), an increase of 11%
from December 31, 2023;
o
Total proved reserves of 266.3 million BOE (40% oil and NGLs), an increase of 4% from December
31, 2023; and
o
Total proved plus probable reserves of 435.2 million BOE (40% oil and NGLs), an increase of 5%
from December 31, 2023.
PRODUCTION
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Average daily production:
Oil (bbls/d)
9,297
8,832
5
8,623
7,979
8
NGLs (bbls/d)
5,052
3,422
48
3,675
3,759
-2
Gas (mcf/d)
132,608
120,541
10
124,902
112,634
11
Combined (BOE/d)
36,450
32,344
13
33,115
30,510
9
Oil and NGLs weighting
39%
38%
3
37%
38%
-3
Average production for the three months ended December 31, 2024, increased 13% from the three months ended
December 31, 2023. Average production for the year ended December 31, 2024 increased 9% from the year ended
December 31, 2023. Production increased in the fourth quarter of 2024 due to additional wells coming on-stream in
BC, and third-party facility optimization work resulting in higher gas processing run times in Alberta. The Company also
obtained capacity at a third-party natural gas deep cut processing plant in BC in the fourth quarter of 2024 resulting in
higher overall NGLs recoverability. Oil and NGLs weighting was 39% in the fourth quarter of 2024 and 37% for the year
ended December 31, 2024, versus 38% for both the fourth quarter and year ended December 31, 2023.
24%
27%
25%
27%
27%
25%
27%
26%
15%
12%
12%
11%
11%
10%
9%
14%
61%
60%
62%
62%
63%
65%
63%
61%
31,833
29,705
28,179
32,344
32,910
30,693
32,378
36,450
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Q1 2024
Q2 2024
Q3 2024
Q4 2024
Kelt Quarterly Production (BOE/D)
Oil Production (BBLS/D)
NGLs Production (BBLS/D)
Natural Gas Production (BOE/D)
KELT EXPLORATION LTD.
6
ANNUAL REPORT
PETROLEUM AND NATURAL GAS SALES (“P&NG SALES”)
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Oil
79,109
77,652
2
297,920
284,867
5
NGLs
17,893
15,677
14
63,970
67,598
-5
Gas
24,724
30,637
-19
89,969
126,299
-29
Marketing revenue (1)
3,338
5,034
-34
16,573
16,816
-1
P&NG Sales
125,064
129,000
-3
468,432
495,580
-5
Cost of purchases (2)
(3,305)
(4,952)
-33
(16,365)
(16,565)
-1
P&NG Sales after cost of purchases (3)(5)
121,759
124,048
-2
452,067
479,015
-6
Combined net realized price ($/BOE) (4)(5)
36.31
41.69
-13
37.31
43.01
-13
(1) Marketing revenue includes the sale of third-party volumes related to the Company's oil blending operations and natural gas activities.
(2) Cost of purchases includes costs for the purchase of third-party volumes related to the Company's oil blending operations and natural gas activities.
(3) P&NG sales after cost of purchases includes petroleum and natural gas sales, net of the cost of the third-party volumes purchased.
(4) Combined net realized price ($/BOE) equals P&NG sales after cost of purchases divided by total production.
(5) Refer to advisories regarding Non-GAAP and Other Financial Measures.
Petroleum and natural gas sales for the fourth quarter of 2024 was $125.1 million, down 3% from $129.0 million in the
fourth quarter of 2023. Petroleum and natural gas sales for the year ending December 31, 2024 was $468.4 million,
down 5% from the comparable period in 2023. The decrease in P&NG sales from 2023 was primarily due to a decrease
in net realized natural gas, NGLs and crude oil prices, which was partially offset by higher production in 2024.
50%
63%
59%
60%
57%
65%
71%
63%
17%
12%
13%
12%
13%
14%
13%
14%
30%
23%
24%
24%
26%
17%
13%
20%
139,571
110,061
116,948
129,000
126,391
109,093
107,884
125,064
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Q1 2024
Q2 2024
Q3 2024
Q4 2024
Kelt Quarterly Petroleum and Natural Gas Sales ($000)
Oil Revenue
NGLs Revenue
Natural Gas Revenue
Marketing Revenue
KELT EXPLORATION LTD.
7
ANNUAL REPORT
(1) Net realized prices are calculated based on Petroleum and Natural Gas Sales, less the cost of purchases of third-party volumes and reflect Kelt’s
realized commodity prices plus the net benefit of oil blending and natural gas marketing activities. Net realized prices exclude both realized and unrealized
gains and losses on risk management contracts. Refer to additional information under the heading of “Non-GAAP and Other Financial Measures”.
Three months ended December 31
Year ended December 31
2024
2023
%
2024
2023
%
Net realized prices (9)
Oil ($/bbl)
92.53
95.68
-3
94.46
97.90
-4
NGLs ($/bbl)
38.50
49.79
-23
47.56
49.27
-3
Gas ($/Mcf)
2.02
2.75
-27
1.97
3.08
-36
Combined ($/BOE)
36.31
41.69
-13
37.31
43.01
-13
Average benchmark prices
Oil and NGLs
WTI Cushing Oklahoma (US$/bbl) (1)
70.69
78.42
-10
76.56
77.63
-1
Mixed Sweet Blend Edmonton (“MSW”) ($/bbl) (2)
95.48
99.77
-4
98.70
100.40
-2
Edmonton Pentane ($/bbl) (3)
98.83
104.11
-5
100.55
102.75
-2
Edmonton Butane ($/bbl) (3)
55.70
47.95
16
48.39
45.55
6
Edmonton Propane ($/bbl) (3)
34.42
28.17
22
30.39
29.58
3
Edmonton Ethane ($/bbl) (3)
4.11
6.37
-35
3.84
7.33
-48
Natural Gas
NYMEX Henry Hub (US$/MMBtu) (6)
2.42
2.74
-12
2.25
2.53
-11
AECO 5A (CA$/MMBtu) (4)
1.48
2.30
-36
1.46
2.64
-45
Chicago Alliance, into Interstates (CA$/MMBtu) (5)
3.08
3.08
-
2.82
3.10
-9
Dawn (CA$/MMBtu) (5)
3.13
3.11
1
2.70
3.15
-14
Malin (CA$/MMBtu) (5)
3.48
4.95
-30
3.00
6.33
-53
Sumas (CA$/MMBtu) (5)
3.03
4.38
-31
2.74
5.68
-52
Station 2 (CA$/MMBtu) (7)
0.90
2.05
-56
1.19
2.25
-47
Marcellus (TZ4 L300) (CA$/MMBtu) (5)
2.79
2.20
27
2.25
2.12
6
Average exchange rate (CA$/US$) (8)
1.3990
1.3615
3
1.3700
1.3495
2
(1) Source: U.S Energy Information Administration, Canadian dollar equivalent price WTI price (“CA$WTI”) is calculated based on the monthly average
US dollar WTI price and the monthly average CA$/US$ exchange rate (8).
(2) Source: Tidal Energy Marketing.
(3) Source: Sproule Associates Limited.
(4) Source: Canadian Gas Price Reporter converted to CA$/MMBtu using monthly average CA$/US$ exchange rate (8).
(5) Source: S&P Global Platts (US$/MMBtu) Daily Midpoint Average converted to CA$/MMBtu using monthly average CA$/US$ exchange rate (8).
(6) Source: S&P Global Platts (US$/MMBtu) Daily Midpoint Average
(7) Source: S&P Global Platts (CA$/GJ) Daily Midpoint Average converted to CA$/MMBtu
(8) Source: Bank of Canada.
(9) Net realized prices are calculated based on Petroleum and Natural Gas Sales, less the cost of purchases of third-party volumes and reflect Kelt’s
-
2.00
4.00
6.00
8.00
$0
$20
$40
$60
$80
$100
$120
$140
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Q1 2024
Q2 2024
Q3 2024
Q4 2024
$/MCF
$/BBL
Kelt Quarterly Realized Prices (1)
Oil
NGLs
Natural gas
KELT EXPLORATION LTD.
8
ANNUAL REPORT
realized commodity prices plus the net benefit of oil blending and natural gas marketing activities. Net realized prices exclude both realized and unrealized
gains and losses on derivative financial instruments. Refer to additional information under the heading of “Non-GAAP and Other Financial Measures”.
Combined Net Realized Price
Kelt’s combined net realized price decreased 13% to $36.31 per BOE and 13% to $37.31 per BOE in the three months
and twelve months ended December 31, 2024, respectively, versus the comparable periods in 2023. The decrease in
the average realized price was primarily due to a decrease in benchmark natural gas and crude oil prices, which was
partially offset by an increase in the USD/CAD foreign exchange rate.
Oil prices
The mixed sweet blend benchmark crude oil price decreased 4% for the quarter ended December 31, 2024 and
decreased 2% for the year ended December 31, 2024 versus the comparable periods in 2023. Continued OPEC+
production curtailments and higher global demand was generally balanced by increases in non-OPEC+ supply growth
in 2024.
NGL prices
NGLs prices are impacted by benchmark WTI prices, the NGLs product mix and localized market supply and demand
issues. For the three months and year ended December 31, 2024, realized NGLs price decreased 23% and 3%,
respectively, as compared to the same period in 2023. The decrease in the average NGLs price in the fourth quarter
of 2024 was primarily due to additional capacity at a third-party natural gas deep cut processing plant in BC resulting
in additional recoverability of Ethane volumes which resulted in a decrease in the average NGLs price.
Benchmark pentane prices closely follow the mixed sweet blend benchmark crude oil price, with the decrease in
pentane prices in 2024 in-line with the decrease in benchmark crude oil prices. Benchmark ethane prices are closely
tied to the natural gas benchmark price, which both significantly decreased in 2024 versus the comparable periods in
2023.
Edmonton propane prices increased 22% in the fourth quarter of 2024 and increased 3% for the year ended December
31, 2024 versus comparable periods in 2023. The increase in the fourth quarter of 2024 was a result of colder than
average US weather and expectations for a colder winter resulting in increased US exports and declining propane
inventory balances.
Edmonton butane prices increased 16% in the fourth quarter of 2024 and 6% for the year ended December 31, 2024
versus comparable periods in 2023. Western Canadian butane inventory levels have trended below the five-year
average in the fourth quarter of 2024 resulting in an increase in the overall benchmark butane price, however western
Canadian butane prices remained depressed for the year ended December 31, 2024 compared to the year ended
December 31, 2023.
Natural gas prices
Realized natural gas prices decreased by 27% to $2.02 per Mcf in the fourth quarter of 2024 and by 36% to $1.97 per
Mcf for the year ended December 31, 2024 versus comparable periods in 2023. Canadian benchmark natural gas
prices decreased significantly in 2024 as Western Canadian natural gas storage levels were significantly above the
five-year average and nearing the maximum estimated storage capacity by the end of the third quarter. The AECO
benchmark natural gas price decreased by 36% and the Station 2 benchmark natural gas price decreased by 56% in
the fourth quarter of 2024 compared to the fourth quarter of 2023.
RISK MANAGEMENT AND HEDGING ACTIVITIES
The Company may enter into fixed price contracts and derivative financial instruments for commodity prices, currency
exchange and interest rates in order to secure future cash flows or to protect a desired level of capital spending. Fair
value accounting for derivative financial instruments may cause significant fluctuations in the reported amounts of
derivative financial instrument assets and liabilities and the resultant magnitude of unrealized gains and losses.
KELT EXPLORATION LTD.
9
ANNUAL REPORT
The table below summarizes realized and unrealized gains (losses) on derivative financial instrument contracts:
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Realized gain
2,353
259
808
4,253
15,057
-72
Unrealized gain (loss)
(6,909)
838
-924
(5,186)
(23,805)
-78
Gain (loss) on derivative financial instruments
(4,556)
1,097
-515
(933)
(8,748)
-89
$ per BOE
(1.36)
0.37
-458
(0.08)
(0.79)
-90
Commodity price risk
Inherent to the business of producing oil and gas, the Company’s cash provided by operating activities is subject to
commodity price risk. Commodity price risk is the risk that future cash flows will fluctuate from changes in commodity
prices. Commodity prices are impacted by world economic events that dictate the levels of supply and demand as well
as the currency exchange rate relationship between the Canadian and US dollar.
As of March 12, 2025, the following commodity price derivative financial instrument contracts are outstanding:
Crude oil derivative financial instrument swap contracts
Contract Type (1)
Notional Volume
Contract Price
Remaining Term
WTI fixed price swap
1,000 bbl/d
CAD$101.00/bbl
Jan 25 – Feb 25
WTI fixed price swap
2,000 bbl/d
CAD$103.73/bbl
Mar 25 – Jun 25
WTI fixed price swap
2,000 bbl/d
USD$69.66/bbl
Jan 25 – Dec 25
WTI option (2)
500 bbl/d
Settles monthly if WTI price >
USD$70.50/bbl
Jan 25 – Dec 25
(1) West Texas Intermediate (“WTI”)
(2) The WTI option is settled monthly at USD$70.50/bbl if the average WTI price is above USD$70.50/bbl.
NGL derivative financial instrument swap contracts
Contract Type
Notional Volume
Contract Price
Remaining Term
OPIS-Conway propane fixed price
swap
250 bbl/d
USD$34.44/bbl
Jan 25 – Mar 25
OPIS-Conway propane basis
swap
250 bbl/d
Monthly OPIS-Conway basis calculated
at 43.5% of the floating monthly WTI
price
Jan 25 – Mar 25
OPIS-Conway propane fixed price
swap
250 bbl/d
USD$33.60/bbl
Apr 25 – Mar 26
OPIS-Conway propane basis
swap
250 bbl/d
Monthly OPIS-Conway basis calculated
at 46% of the floating monthly WTI
price
Apr 25 – Mar 26
Natural gas derivative financial instrument contracts
Contract Type (1)
Notional Volume
Contract Price $/MMBtu
Remaining Term
NYMEX-AECO 7A basis swap
10,000 MMBtu/d
NYMEX less USD$1.06
Jan 25 – Mar 25
NYMEX-AECO 5A basis swap
30,000 MMBtu/d
NYMEX less USD$1.10
Jan 25 – Mar 25
NYMEX swap
20,000 MMBtu/d
CAD$6.405/MMBtu
Apr 25 – Dec 25
AECO 7A swap
5,000 GJ/d
CAD$1.85/GJ
Apr 25 – Jul 25
AECO 7A swap
5,000 GJ/d
CAD$2.005/GJ
May 25 – Jul 25
NYMEX costless collar
10,000 MMBtu/d
Floor: CAD$5.00/MMBtu
Ceiling: CAD$10.00/MMBtu
Apr 25 – Dec 25
KELT EXPLORATION LTD.
10
ANNUAL REPORT
(1) NYMEX Henry Hub (“NYMEX”)
Natural gas embedded derivative
Contract Type
Notional Volume
Contract Price (1)
Remaining Term
Physical delivery contract
2,513 GJ/d
Floating AESO power pool price
(CAD/MWh) divided by the Fixed Heat
Rate of 17.95 GJ/MWh
Jan 25 – Dec 26
Physical delivery contract
2,475 GJ/d
Floating AESO power pool price
(CAD/MWh) divided by the Fixed Heat
Rate of 16.50 GJ/MWh
Jan 26 – Dec 26
(1) Alberta Electric System Operator (“AESO”)
The Company has an outstanding natural gas physical supply agreement to deliver gas to the Nova Inventory Transfer
point, which contains an embedded derivative. Under the terms of the agreement, the Company receives a price equal
to the Floating AESO Power Pool Price divided by a fixed heat rate.
The fair value of the embedded derivative is calculated by the difference between the forecasted Floating AESO Power
Pool Price divided by the fixed heat rate, less the forecasted AECO 5A price, for the remaining term of the contract.
In addition to the derivative contracts above, the Company has the following sales contracts for physical delivery:
Natural gas physical delivery contracts
Contract Type
Notional Volume
Contract Price
Remaining Term
AECO - Station 2 basis differential
5,000 GJ/d
AECO 7A less CAD$0.15/GJ
Jan 25 – Mar 25
AECO 7A (physical) collar
10,000 GJ/d
Ceiling – $3.65/GJ; Floor – $1.00/GJ
Jan 25 – Mar 25
Interest rate risk
The Company is exposed to interest rate risk as changes in market interest rates will impact the Credit Facility which
is subject to a floating interest rate. Based on bank debt balance as of December 31, 2024 of $109.0 million, an increase
(decrease) in the market rate of interest by 25 basis points would have an insignificant impact. As of March 12, 2025,
there are no interest rate risk management contracts outstanding.
Foreign exchange risk
Kelt is exposed to fluctuations of the Canadian to U.S. dollar exchange rate given realized pricing is directly influenced
by U.S. dollar denominated benchmark pricing and from exposure from certain U.S. dollar denominated natural gas
marketing arrangements.
As of March 12, 2025, the following foreign exchange derivative financial instrument contracts are outstanding:
Foreign exchange derivative financial instrument swap contracts
Contract Type
Notional Volume
Contract/Exercise Price
Remaining Term
CAD/USD swap
USD$7.0 million/month
$1.3796 CAD/USD
Jan 25 – Jun 25
CAD/USD swap
USD$6.0 million/month
$1.3795 CAD/USD
Jul 25 – Dec 25
Foreign exchange derivative financial instrument option contracts
Contract Type
Notional Volume
Contract/Exercise Price
Exercise/
expiration date
Term if exercised
Sold call option
USD$2.0 million/month
$1.3820 CAD/USD
Dec 31, 2025
Jan 26 – Dec 26
Sold call option
USD$2.0 million/month
$1.3800 CAD/USD
Dec 31, 2025
Jan 26 – Dec 26
KELT EXPLORATION LTD.
11
ANNUAL REPORT
ROYALTIES
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Royalties
9,552
17,938
-47
54,737
59,170
-7
Average royalty rate (1)
7.8%
14.5%
-46
12.1%
12.4%
-2
$ per BOE
2.85
6.03
-53
4.52
5.31
-15
(1) The average royalty rate is calculated based on total royalties as a percentage of “P&NG Sales, before marketing revenue” which excludes sales
related to the sale of third-party production volumes used in oil blending operations (see table under the heading of “Petroleum and Natural Gas Sales”).
Kelt’s average royalty rate was 7.8% during the fourth quarter of 2024, compared to 14.5% during the fourth quarter of
2023. In the fourth quarter of 2024, Kelt was approved for a second phase of an infrastructure royalty program in BC
resulting in additional infrastructure royalty credits of $2.4 million. In addition, the average royalty rate in the fourth
quarter of 2024 decreased due to lower natural gas prices and the addition of new Alberta wells that are eligible for an
initial low royalty rate of five percent.
As a result of lower royalties in the fourth quarter Kelt’s average royalty rate for the year ended December 31, 2024
decreased to 12.1% compared to 12.4% for the year ended December 31, 2023.
PRODUCTION EXPENSES
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Production expense
29,235
25,662
14
121,355
109,422
11
$ per BOE
8.72
8.62
1
10.01
9.83
2
Production expenses were $29.2 million during the fourth quarter of 2024, up 14% compared to the fourth quarter in
2023. Production expenses on a per BOE basis remained relatively consistent at $8.72 per BOE during the fourth
quarter of 2024 compared to $8.62 per BOE in the fourth quarter of 2023. Equalization adjustments in both the fourth
quarters of 2024 and 2023 resulted in production expenses per BOE that were lower than the annual averages.
Production expenses for the year ended December 31, 2024 increased 11% from the year ended December 31, 2023
primarily due to higher production volumes. Production expenses per BOE were relatively consistent year over year,
increasing by two percent.
0.00
2.00
4.00
6.00
8.00
10.00
12.00
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Q1 2024
Q2 2024
Q3 2024
Q4 2024
$/BOE
($000)
Quarterly Production Expenses
Operating Expenses
Per BOE
KELT EXPLORATION LTD.
12
ANNUAL REPORT
TRANSPORTATION EXPENSES
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Transportation expense (1)
12,198
10,830
13
42,625
38,808
10
$ per BOE
3.64
3.64
-
3.52
3.48
1
(1) Pipeline tariffs are classified as transportation expenses when the Company has firm commitments or contractual arrangements on the pipeline.
Pipeline tariffs may also be incurred indirectly by way of deduction from the base price paid by the purchasers of the Company’s oil, NGLs and gas sales.
In the latter case, and in the absence of a firm contractual obligation on the pipeline, the pipeline tariffs are presented as a reduction of revenue rather
than as transportation expense.
Transportation expenses remained consistent at $3.64 per BOE and $3.52 per BOE during the fourth quarter and year
ended 2024 compared to the same periods in 2023.
FINANCING EXPENSES
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Total interest expense
1,457
344
324
3,674
1,310
180
Accretion of decommissioning obligations
809
741
9
3,082
2,880
7
Financing expense
2,266
1,085
109
6,756
4,190
61
Interest expense per BOE (1)
0.43
0.12
258
0.30
0.12
150
(1) Interest expense used in the calculation of “Interest expense per BOE” includes interest and fees on bank debt.
At December 31, 2024, $109.0 million was drawn under the Company’s credit facility, with outstanding letters of credit
of $2.7 million. Total interest expense for the year ended December 31, 2024 was $3.7 million.
Additional information regarding the credit facility is provided under the heading of “Capital Resources and Liquidity”.
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Q1 2024
Q2 2024
Q3 2024
Q4 2024
$/BOE
($000)
Quarterly Transportation Expenses
Transportation Expense
Per BOE
KELT EXPLORATION LTD.
13
ANNUAL REPORT
GENERAL AND ADMINISTRATIVE (“G&A”) EXPENSES
The following table summarizes significant components of the Company’s G&A expenses:
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Salaries and benefits
3,763
3,743
1
14,855
13,349
11
Other G&A expenses
1,219
1,061
15
6,250
5,292
18
Gross G&A expenses
4,982
4,804
4
21,105
18,641
13
Overhead recoveries
(2,496)
(1,756)
42
(8,833)
(8,257)
7
Net G&A expenses
2,486
3,048
-18
12,272
10,384
18
Gross G&A ($ per BOE)
1.49
1.61
-7
1.74
1.67
4
Net G&A ($ per BOE)
0.74
1.02
-27
1.01
0.93
9
Gross G&A expenses increased 4% in the fourth quarter of 2024 and 13% for the year ended December 31, 2024
compared to the same periods in 2023. Gross G&A increased primarily due to employee-related costs and consulting
fees. Net G&A expenses per BOE decreased 27% in the fourth quarter of 2024 and increased 9% during the year
ended December 31, 2024. The decrease in net G&A expenses per BOE in the fourth quarter of 2024 was primarily
due to higher overhead recoveries and production increasing at a higher rate than G&A expense.
G&A expenses are reported net of overhead recoveries; however, Kelt does not capitalize any direct G&A expenses.
SHARE BASED COMPENSATION (“SBC”)
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Stock options
1,376
1,389
-1
5,266
5,359
-2
Restricted share units (“RSUs”)
973
763
28
3,580
2,503
43
Total SBC expense
2,349
2,152
9
8,846
7,862
13
$ per BOE
0.70
0.72
-3
0.73
0.71
3
The increase in SBC expense for the three months and year ended December 31, 2024 compared to the same periods
in 2023 is primarily due to the higher fair value associated with recent option and RSU grants.
As at December 31, 2024, stock options and RSUs outstanding represent 6.0% of total shares outstanding (December
31, 2023 – 5.9%).
DEPLETION AND DEPRECIATION
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Depletion and depreciation
40,539
32,839
23
141,494
125,813
12
$ per BOE
12.09
11.04
10
11.67
11.30
3
Depletion and depreciation expense of $40.5 million for the quarter ended December 31, 2024 increased by 23% from
$32.8 million in the comparable period in 2023. Depletion and depreciation expense for the year ended December 31,
2024 increased by 12% as compared to the prior year.
Based on its assessment as of December 31, 2024, the Company determined that there were no indicators of
impairment for the Alberta CGU and BC CGU and there are no previous impairments available for reversals.
KELT EXPLORATION LTD.
14
ANNUAL REPORT
INCOME TAXES
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Deferred income tax expense
4,931
7,895
-38
17,733
28,503
-38
Net income before taxes
18,731
31,624
-41
63,156
114,477
-45
Effective tax rate
26.3%
25.0%
5
28.1%
24.9%
13
Kelt’s consolidated combined federal and provincial statutory tax rate averaged 23% during the three months ended
December 31, 2024 and 2023.
Kelt was not required to pay income taxes in the current or prior year. Tax pools and losses available to reduce taxable
income as of December 31, 2024 are estimated to be approximately $896.7 million as summarized in the table below.
(CA$ thousands, except as otherwise indicated)
Rate
December 31
2024
December 31
2023
%
Canadian oil and gas property expenses (COGPE)
10%
58,536
60,905
-4
Canadian development expenses (CDE)
30%
301,401
241,162
25
Canadian exploration expenses (CEE)
100%
1,019
407
150
Undepreciated capital cost (1) (UCC)
25%
262,970
230,290
14
Non-capital losses (2) (NCL)
100%
272,819
247,657
10
Estimated tax deductions available, end of period
896,745
780,421
15
(1) The majority of the Company’s undepreciated capital cost deductions relate to Class 41 assets, which are deductible at a rate of 25% per year.
(2) The Company’s non-capital losses expire in years 2033 to 2043.
ADJUSTED FUNDS FROM OPERATIONS
The following table provides a continuity of income and expenses included in the Company’s calculation of operating
income, operating netback and adjusted funds from operations generated during the three months and year ended
December 31, 2024 and 2023 respectively.
Three months ended
December 31
Year ended
December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Petroleum and natural gas sales
125,064
129,000
-3
468,432
495,580
-5
Cost of purchases
(3,305)
(4,952)
-33
(16,365)
(16,565)
-1
Realized gain on derivative financial instruments (1)
2,353
259
808
4,253
15,057
-72
Royalties
(9,552)
(17,938)
-47
(54,737)
(59,170)
-7
Production expense
(29,235)
(25,662)
14
(121,355)
(109,422)
11
Transportation expense
(12,198)
(10,830)
13
(42,625)
(38,808)
10
Operating Income (2)
73,127
69,877
5
237,603
286,672
-17
Financing expense (3)
(1,457)
(344)
324
(3,674)
(1,310)
180
G&A expense
(2,486)
(3,048)
-18
(12,272)
(10,384)
18
Gain (loss) on foreign exchange
219
(102)
-315
204
(104)
-296
Other income
3
235
-99
117
1,326
-91
Adjusted funds from operations (2)
69,406
66,618
4
221,978
276,200
-20
Basic ($ per common share) (4)
0.35
0.34
3
1.13
1.43
-21
Diluted ($ per common share) (4)
0.35
0.33
6
1.11
1.40
-21
KELT EXPLORATION LTD.
15
ANNUAL REPORT
Three months ended
December 31
Year ended
December 31
($ per BOE)
2024
2023
%
2024
2023
%
Petroleum and natural gas sales
37.30
43.35
-14
38.66
44.51
-13
Cost of purchases
(0.99)
(1.66)
-40
(1.35)
(1.50)
-10
Realized gain on derivative financial instruments (1)
0.70
0.09
678
0.35
1.35
-74
Royalties
(2.85)
(6.03)
-53
(4.52)
(5.31)
-15
Production expense
(8.72)
(8.62)
1
(10.01)
(9.83)
2
Transportation expense
(3.64)
(3.64)
-
(3.52)
(3.48)
1
Operating Netback (2)
21.80
23.49
-7
19.61
25.74
-24
Financing expense (3)
(0.43)
(0.12)
258
(0.30)
(0.12)
150
G&A expense
(0.74)
(1.02)
-27
(1.01)
(0.93)
9
Gain (loss) on foreign exchange
0.07
(0.03)
-333
0.02
(0.01)
-300
Other income
-
0.08
-100
0.01
0.12
-92
Adjusted funds from operations (2)
20.70
22.40
-8
18.33
24.80
-26
(1) Includes realized gains (losses) on commodity price and foreign exchange derivative financial instruments.
(2) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
(3) Excludes non-cash accretion of decommissioning obligations.
(4) Adjusted funds from operations (2) per common share is calculated on a consistent basis with net income per common share, using basic and diluted
weighted average common shares as determined in accordance with GAAP.
During the three months ended December 31, 2024, adjusted funds from operations of $69.4 million ($0.35 per common
share, diluted) increased by 4% from $66.6 million ($0.33 per common share, diluted) in the fourth quarter of 2023. The
increase in adjusted funds from operations in the fourth quarter of 2024 compared to 2023 was primarily due to a
decrease in royalty expense, and a decrease in G&A expenses, partially offset by lower petroleum and natural gas
sales and transportation expenses.
During the year ended December 31, 2024, adjusted funds from operations of $222.0 million ($1.11 per common share,
diluted) decreased by 20% from $276.2 million ($1.40 per common share, diluted) during the year ended December
31, 2023. The decrease in adjusted funds from operations year ended December 31, 2024 compared to the same
periods in 2023 was primarily due to a decrease in petroleum and natural gas sales, a decrease in the realized gain on
derivative financial instruments, an increase in production and transportation expenses, and an increase in financing
and G&A expenses, partially offset by lower royalty expenses.
NET INCOME AND COMPREHENSIVE INCOME
$10.8
$7.8
$4.4
$(5.0)
$(15.7)
$(15.8)
$(27.1)
$86.0
$45.4
0
20
40
60
80
100
120
2023
Deferred income
taxes
Derivative
financial
instruments
Royalties
Other (1)
DD&A
Operating &
transportation
P&NG sales
2024
$ Millions
Change in Net Income
Year ended December 31, 2024
KELT EXPLORATION LTD.
16
ANNUAL REPORT
(1) Other includes changes in net income related primarily to G&A expense, finance expense, other income and foreign exchange gain (loss).
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Net income and comprehensive income
13,800
23,729
-42
45,423
85,974
-47
$ per common share, basic
0.07
0.12
-42
0.23
0.45
-49
$ per common share, diluted (1)
0.07
0.12
-42
0.23
0.44
-48
$ per BOE
4.12
8.01
-49
3.76
7.71
-51
Wtd avg. shares outstanding, basic (000s)
196,557
194,359
1
195,719
193,116
1
Wtd avg. shares outstanding, diluted (000s) (1)
200,801
199,223
1
199,631
197,063
1
(1) The Company uses the treasury stock method to determine the dilutive effect of stock options and RSUs. Under this method, only “in-the-money”
dilutive instruments impact the calculation of diluted net income per common share.
Net income was $13.8 million ($0.07 per common share, diluted) for the three months ended December 31, 2024,
compared to a net income of $23.7 million ($0.12 per common share, diluted) in the same three month period of 2023.
Net income was $45.4 million ($0.23 per common share, diluted) for the year ended December 31, 2024, compared to
a net income of $86.0 million ($0.44 per common share, diluted) in the same period of 2023. The decrease in net
income was primarily driven by a reduction in petroleum and natural gas sales, and overall higher production expenses
in 2024 which was offset by a positive change in the Company’s commodity derivative financial instrument contracts.
INVESTING ACTIVITIES
CAPITAL EXPENDITURES
The Company’s capital expenditures, before and net of acquisitions and dispositions (“A&D”), are summarized in the
following table:
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Capital expenditures:
Lease acquisition and retention
93
141
-34
2,345
1,668
41
Geological and geophysical
23
77
-70
610
1,162
-48
Drilling and completion of wells
63,061
26,545
138
212,141
193,175
10
Facilities, pipeline and well equipment
30,394
35,918
-15
112,738
85,834
31
Corporate assets
75
54
39
1,140
755
51
74%
73%
78%
42%
54%
78%
59%
67%
24%
24%
21%
57%
45%
19%
40%
32%
2%
3%
1%
1%
1%
3%
1%
1%
$76,681
$44,891
$98,287
$62,735
$79,512
$73,706
$82,110
$93,646
Q1 2023
Q2 2023
Q3 2023
Q4 2023
Q1 2024
Q2 2024
Q3 2024
Q4 2024
Capital Expenditures before A&D ($000)
Drilling and completion of wells ($000)
Facilities, pipeline and well equipment ($000)
Other ($000)
KELT EXPLORATION LTD.
17
ANNUAL REPORT
Three months ended December 31
Year ended December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
%
2024
2023
%
Capital expenditures, before A&D (1)
93,646
62,735
49
328,974
282,594
16
Property acquisitions
3,500
6,510
-46
4,816
7,022
-31
Property dispositions
(100)
(6,550)
-98
(643)
(6,970)
-91
Capital expenditures, net of A&D (1)
97,046
62,695
55
333,147
282,646
18
(1) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
Capital expenditures, before A&D, increased 49% in the fourth quarter of 2024 and increased 16% from the year ended
December 31, 2024 versus the comparable period in 2023.
In the fourth quarter of 2024, drilling and completion costs of $63.1 million included the drilling of 3.0 net wells and
completion of 12.0 net wells. Kelt’s facility, pipeline and well equipment spending in the fourth quarter of 2024 of $30.4
million focused on well equipment, pipeline construction and facility optimization.
For the year ended December 31, 2024, drilling and completion costs of $212.1 million included the drilling of 31.3 net
wells and completion of 31.3 net wells. The wells drilled included 26 gross (25.2 net) Montney wells and 9 gross (7.1
net) Charlie Lake wells.
Three months ended December 31
Year ended December 31
Gross Wells
2024
2023
%
2024
2023
%
Drilling
3
4
-25
34
28
21
Completion
12
6
100
34
25
36
Service
-
-
1
2
-50
Three months ended December 31
Year ended December 31
Net Wells
2024
2023
%
2024
2023
%
Drilling
3.0
4.0
-25
31.3
27.0
16
Completion
12.0
6.0
100
31.3
24.0
30
Service
-
-
1.0
2.0
-50
LAND HOLDINGS
The table below sets-out Kelt’s significant Montney and Charlie Lake land holdings across British Columbia and Alberta
as at December 31, 2024.
MONTNEY RIGHTS
Net Acres
Net Sections
British Columbia
193,607
303
Alberta
154,725
242
Total
348,332
544
CHARLIE LAKE RIGHTS
Alberta
84,847
132
CAPITAL RESOURCES AND LIQUIDITY
Kelt’s objective is to maintain a flexible capital structure that provides sufficient liquidity for the Company to meet its
obligations when due and to execute on its capital investment program. The Company manages its capital structure in
response to changes in economic conditions and the risk characteristics of its underlying oil and natural gas assets.
The Company has a $150.0 million credit facility from a syndicate of financial institutions. At December 31, 2024, $109.0
million was drawn under the Credit Facility, with outstanding letters of credit of $2.7 million. The Credit Facility may be
extended annually at Kelt’s option and subject to lender approval, with a 364 day term-out period if not renewed.
KELT EXPLORATION LTD.
18
ANNUAL REPORT
Repayments of principal are not required provided that the borrowings under the facility do not exceed the authorized
borrowing amount. The credit facility is subject to semi-annual redeterminations on or before June 30 and November
30 of each year. There are no financial covenants under the Credit Facility and Kelt is in compliance with all other
covenants. Covenants include industry standard positive and negative covenants including reporting requirements,
permitted indebtedness, permitted risk management activities, permitted encumbrances and other standard business
operating covenants. Security is provided for by a demand debenture with a floating charge over all assets in the
amount of $800.0 million.
Interest is payable monthly for borrowings through direct advances. Interest rates fluctuate based on the prime rate
plus the applicable margin. The applicable margin ranges from 175 basis points to 375 basis points depending upon
the Net Debt to Cash Flow ratio of between less than 0.5 times and three times. Under the Credit Facility, borrowings
through the use of CORRA term loans are also available. Stamping fees fluctuate based on a pricing grid and range
from 2.75% to 4.75%, depending upon the Net Debt to Cash Flow ratio of between less than 0.5 times and three times.
December 31,
2024
December 31,
2023
Bank debt
108,993
-
Accounts payable and accrued liabilities
80,463
85,171
Cash and cash equivalents
(228)
(14,340)
Accounts receivable and accrued sales
(60,236)
(52,646)
Prepaid expenses and deposits
(4,109)
(5,188)
Net debt (1)
124,883
12,997
Adjusted funds from operations (1)
221,978
276,200
Net debt to adjusted funds from operations ratio (1)
0.6
0.0
(1) Refer to advisories regarding Capital Management Measures.
The Company monitors its capital structure and short-term financing requirements using a net debt to adjusted funds
from operations ratio, which is a non-GAAP financial measure. Kelt targets a net debt to adjusted funds from operations
ratio of less than 2.0 times.
The Company may adjust its future capital structure and capital expenditures according to market conditions to maintain
flexibility to achieve its objectives. In doing so, the Company may increase or decrease capital expenditures including
acquisitions and dispositions, issue new shares, issue new debt or repay existing debt.
The table below outlines a contractual maturity analysis for Kelt’s financial liabilities as at December 31, 2024:
Within 1 Year
1 to 5 Years
More than 5 Years
Total
Accounts payable and accrued liabilities
80,463
-
-
80,463
Derivative financial instruments
7,936
-
-
7,936
Lease liability
1,655
419
-
2,074
Bank debt and estimated interest (1)
6,758
108,993
-
115,751
Total
96,812
109,412
-
206,224
(1) Estimated interest for future years related to the Credit Facility was calculated using the weighted average interest rate of 6.2% for the year ended
December 31, 2024, applied to the principal balance outstanding as at that date.
COMMITMENTS
As of December 31, 2024, the Company is committed to future payments under the following agreements:
2025
2026
2027
2028
2029
Thereafter
Firm processing commitments
51,990
72,132
72,240
74,713
73,606
406,080
Firm transportation commitments
42,363
43,935
39,001
37,751
34,018
123,762
Total commitments
94,353
116,067
111,241
112,464
107,624
529,842
KELT EXPLORATION LTD.
19
ANNUAL REPORT
SHARE INFORMATION
The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred
shares. At December 31, 2024 there were 196.8 million common shares issued and outstanding. There are no preferred
shares issued or outstanding.
At December 31, 2024, officers, directors, and employees have been granted options to purchase 10.0 million common
shares of the Company at an average exercise price of $4.42 per common share. In addition, there are 1.8 million
RSUs outstanding.
The following table outlines Kelt’s common share trading activity during 2024 and 2023:
SHARE TRADING ACTIVITY (KEL)
2024
2023
High ($)
7.20
8.16
Low ($)
5.01
4.29
Close ($)
7.02
5.72
Volume traded (thousands)
77,630
111,257
Value traded ($ thousands)
476,702
638,458
Weighted average trading price ($)
6.14
5.74
RELATED PARTY TRANSACTIONS
The Company has engaged a law firm where the corporate secretary of Kelt is a partner, and Kelt has engaged the
services of a registrar and transfer agent where an officer of Kelt is a director of the company. During the year ended
December 31, 2024, the Company incurred $0.4 million (December 31, 2023 – $0.4 million) in disbursements to related
parties in the normal course of business.
Key management personnel are those persons having authority and responsibility for planning, directing and controlling
the activities of the Company. The following table summarizes compensation paid or payable to officers and directors
of the Company:
Year ended December 31
2024
2023
Salaries, bonuses and other benefits
3,509
3,250
Share based compensation
3,870
4,056
Total compensation
7,379
7,306
During the year ended December 31, 2024, key management personnel were granted 935,000 stock options with an
exercise price of $6.06 per share and 173,000 RSUs. During the year ended December 31, 2023, key management
personnel were granted 621,000 stock options with an exercise price of $4.56 per share and 529,000 RSUs.
OFF-BALANCE SHEET TRANSACTIONS
The Company did not engage in any off-balance sheet transactions during the periods ended December 31, 2024 and
2023.
RESERVES
Kelt retained McDaniel & Associates Consultants Ltd (“McDaniel”), an independent qualified reserve evaluator to
prepare a report on its oil and gas reserves (the “McDaniel Report”). The Company has a Reserves Committee which
oversees the selection, qualifications and reporting procedures of the independent engineering consultants. Reserves
as at December 31, 2024 and at December 31, 2023 were determined using the guidelines and definitions set out
under National Instrument 51-101 (“NI 51-101”). The McDaniel Report is effective as of December 31, 2024. More
information on the Company’s reserves are included in the Annual Information Form as at December 31, 2024, dated
March 12, 2025, which can be found at www.sedarplus.ca.
KELT EXPLORATION LTD.
20
ANNUAL REPORT
At December 31, 2024, Kelt’s proved plus probable reserves were 435.2 million BOE, up 5% from 413.1 million BOE
at December 31, 2023. The Company’s net present value of proved plus probable reserves at December 31, 2024,
discounted at 10% before-tax, was $3.5 billion, a decrease of 23% from $4.5 billion at December 31, 2023. McDaniel’s
forecast commodity prices for 2025 which were used to determine the present value of the Company’s reserves at
December 31, 2024, are US$71.58 per barrel for WTI oil and US$3.31 per MMBtu for NYMEX Henry Hub.
At December 31, 2024, the weighting of proved plus probable reserves was 40% oil/NGLs and 60% natural gas. At
December 31, 2023, the weighting of proved plus probable reserves was 36% oil/NGLs and 64% natural gas.
The following table outlines a summary of the Company’s reserves volumes at December 31, 2024:
SUMMARY OF RESERVE VOLUMES
Crude Oil
(Mbbls)
Liquids(1)
(Mbbls)
Natural Gas
(MMcf)
Combined
(MBOE)
FDC Costs
($ thousands)
Proved developed producing
14,421
15,320
294,727
78,862
-
Proved
55,284
50,063
965,789
266,312
1,839,868
Proved plus Probable
95,531
78,248
1,568,229
435,151
2,837,358
(1) “Liquids” include field condensate and NGLs.
CHANGE IN RESERVES – YEAR OVER YEAR (MBOE)
December 31
2024
December 31
2023
% Change
Proved developed producing
78,862
71,081
11
Proved
266,312
256,584
4
Proved plus Probable
435,151
413,082
5
The following table outlines forecasted future prices that McDaniel has used in their evaluation of the Company’s
reserves at December 31, 2024:
FUTURE COMMODITY PRICE FORECAST
WTI Cushing
Oklahoma
US$/bbl
Canadian
Light Sweet
CA$/bbl
NYMEX
Henry Hub
US$/MMBtu
AECO-C
Spot
CA$/GJ
USD/CAD
Exchange
US$/CA$
2025
71.58
94.79
3.31
2.24
1.40
2026
74.48
97.04
3.73
3.16
1.37
2027
75.81
97.37
3.85
3.30
1.35
2028
77.66
99.80
3.93
3.50
1.35
2029
79.22
101.79
4.01
3.57
1.35
Five year average
75.75
98.16
3.77
3.15
1.36
The following table summarizes the net present value of the Company’s reserves (before-tax) as at December 31,
2024:
NET PRESENT VALUE (BEFORE-TAX)
(CA$ millions)
Undiscounted
NPV 5% BT
NPV 10% BT
Proved developed producing
1,085,217
1,003,829
882,521
Proved
3,863,149
2,840,663
2,154,375
Proved plus Probable
7,310,595
4,872,652
3,471,756
NET ASSET VALUE
The Company estimates its net asset value to be $3.5 billion or $16.85 per common share as at December 31, 2024
based on the present value of its 2P reserves before-tax, discounted at 10%. The components of Kelt’s net asset value
calculation are set-forth in the table below. 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.
The net present value of petroleum and natural gas (“P&NG”) reserves was determined by McDaniel in their year-end
KELT EXPLORATION LTD.
21
ANNUAL REPORT
evaluation reports, based on a discount rate of 10% before-tax. Undeveloped land at December 31, 2024 was internally
valued at an average price of $326 per acre (2024 – $381 per acre). Management believes that the “Net asset value”
provides a useful measure to analyze the comparative change in the Company’s estimated value on a normalized
basis.
(CA$ thousands, except per share amounts)
December 31, 2024
December 31, 2023
Present value of 2P P&NG reserves, discounted at 10% before-tax (1)
3,471,756
4,515,374
Undeveloped land (2)
121,273
140,191
Net debt (3)
(124,883)
(12,997)
Proceeds from exercise of stock options (3)(4)
42,605
33,767
Net asset value
3,510,751
4,676,335
Common shares, RSU’s and “in the money” stock options (000s) (4)
208,358
205,590
Net asset value ($ per common share) (3)
16.85
22.75
(1) As estimated by McDaniel at December 31, 2024. The present value of 2P reserves includes undiscounted future development capital of $2.8 billion.
(2) The undeveloped land value is based on internal estimates of Kelt’s undeveloped lands which do not have assigned reserves
(3) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
(4) The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are
“in-the-money” based on the closing price of KEL of $7.02 on December 31, 2024. All outstanding RSUs are included in diluted common shares
outstanding.
SUMMARY OF QUARTERLY RESULTS
The following tables summarize the Company’s financial and operating results over the past eight quarters:
(CA$ thousands, except as otherwise indicated)
Q4 2024
Q3 2024
Q2 2024
Q1 2024
Q4 2023
Q3 2023
Q2 2023
Q1 2023
Revenue
115,512
94,985
91,849
111,349
111,062
101,480
102,589
121,279
Cash provided by operating activities
48,067
52,166
46,419
62,493
62,477
52,424
68,163
100,160
Adjusted funds from operations (1)
69,406
48,939
42,457
61,176
66,618
58,772
58,810
92,000
Per share – basic ($/common share) (1)
0.35
0.25
0.22
0.31
0.34
0.30
0.31
0.48
Per share – diluted ($/common share) (1)
0.35
0.24
0.21
0.31
0.33
0.30
0.30
0.47
Net income and comprehensive net income
13,800
8,871
10,905
11,847
23,729
20,060
25,799
16,336
Per share – basic ($/common share)
0.07
0.05
0.06
0.06
0.12
0.10
0.13
0.09
Per share – diluted ($/common share)
0.07
0.04
0.05
0.06
0.12
0.10
0.13
0.08
Capital expenditures, net of A&D (1)
97,046
82,110
73,810
80,181
62,695
98,287
45,035
76,629
Total assets
1,450,679
1,378,621
1,328,148
1,282,456
1,260,292
1,222,412
1,174,609
1,174,489
Bank debt
108,993
45,428
12,611
-
-
-
-
-
Net debt (surplus) (1)
124,883
95,889
63,084
31,961
12,997
15,917
(18,580)
(4,899)
Shareholders’ equity
1,063,004
1,046,142
1,033,204
1,018,604
1,003,663
976,146
948,215
919,809
Average daily production (BOE/d)
36,450
32,378
30,693
32,910
32,344
28,179
29,705
31,833
Combined net realized price ($/BOE) (1)(2)
37.01
35.86
37.18
40.59
41.78
42.68
38.64
54.00
Operating netback ($/BOE) (1)
21.80
17.91
16.55
21.69
23.49
23.36
22.55
33.27
Operating netback % of combined net realized
price (2)
59%
50%
45%
53%
56%
55%
58%
62%
(1) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
(2) In this table, combined net realized prices are after derivative financial instruments.
In 2023 and 2024, crude oil demand and supply remained relatively balanced, resulting in a range bound crude oil
benchmark price.
North American benchmark natural gas prices in 2023 were impacted by higher than historical average inventory levels
which continued into 2024 with a warmer than average 2023/2024 winter and record high North American natural gas
production. 2024 ended with expectations of a colder than average 2024/2025 winter, which, combined with additional
KELT EXPLORATION LTD.
22
ANNUAL REPORT
LNG export capacity in the US coming on-stream in 2025, resulted in rising US national gas prices. Canadian
benchmark natural gas prices in 2024 were lower than historical norms as natural gas inventory levels remained
elevated.
Kelt’s business objective is for long-term profitable growth by implementing a full cycle exploration and development
program. Over the past eight quarters, Kelt has focused its cash provided from operating activities on its development
capital program which has resulted in higher average daily production and adjusted funds from operations.
Refer to the “Financial and Operating Summary” section of this MD&A for further discussion. Additional information
relating to Kelt, including the Company’s MD&A for previous quarters, is filed on SEDAR+ and can be viewed at
www.sedarplus.ca.
SELECTED ANNUAL INFORMATION
The following table summarizes key annual financial and operating information over the three most recently completed
financial years.
(CA$ thousands, except as otherwise indicated)
2024
2023
2022
Revenues
413,695
436,410
547,791
Cash provided by operating activities
209,145
283,224
306,022
Adjusted funds from operations (1)
221,978
276,200
326,992
Per share – basic ($/common share) (1)
1.13
1.43
1.71
Per share – diluted ($/common share) (1)
1.11
1.40
1.67
Net income and comprehensive income
45,423
85,974
158,758
Per share – basic ($/common share)
0.23
0.45
0.83
Per share – diluted ($/common share)
0.23
0.44
0.81
Capital expenditures, net of A&D (1)
333,147
282,646
317,540
Total assets
1,450,679
1,260,292
1,128,104
Bank debt
108,993
-
11,300
Net debt (1)
124,883
12,997
9,789
Shareholders’ equity
1,063,004
1,003,663
901,424
Return on average capital employed (%) (1)
6
12
25
Average daily production (BOE/d)
33,115
30,510
27,236
Combined net realized price ($/BOE) (1)(2)
37.66
44.36
53.86
Operating netback ($/BOE) (1)
19.61
25.74
33.98
Operating netback as a % of combined net realized price (2)
52%
58%
63%
(1) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
(2) In this table, average realized prices are after derivative financial instruments.
KELT EXPLORATION LTD.
23
ANNUAL REPORT
OUTLOOK AND GUIDANCE
The table below compares the Company’s previously forecasted assumptions and expected financial and operating
results for 2024 to actual 2024 results:
(CA$ millions, except as otherwise indicated)
2024 Actuals
2024 Budget
% Change (2)
Average Production
Oil and NGLs (bbls/d)
12,298
11,900 – 12,600
-
Gas (MMcf/d)
124.9
120.6 – 125.4
2
Combined (BOE/d)
33,115
32,000 – 33,500
1
Forecasted Average Commodity Prices
WTI oil price (US$/bbl)
76.56
76.75
-
Canadian Light Sweet ($/bbl)
98.70
98.71
-
NYMEX natural gas price (US$/MMBtu)
2.25
2.30
-2
AECO natural gas price ($/GJ)
1.38
1.49
-7
Station 2 natural gas price ($/GJ)
1.13
1.30
-13
Average Exchange Rate (US$/CA$)
0.7299
0.7315
-
Capital expenditures, net of A&D (1)
333.1
325.0
3
Petroleum and natural gas sales
468.4
478.4
-2
Adjusted funds from operations (1)
222.0
221.5
-
Per common share, diluted (1)
1.11
1.11
-
Net debt (surplus), at year end (1)
124.9
117.0
7
Weighted average common shares outstanding (millions) (1)
195.7
195.6
-
(1) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
(2) Percent change for production is calculated using the mid-point of each production range.
2025 BUDGET
The table below outlines the Company’s forecast for 2025 Budget, which was included in Kelt’s press release dated
January 6, 2025, compared to 2024 actuals:
(CA$ millions, except as otherwise indicated)
2025 Budget
2024 Actuals
% Change (2)
Average Production
Oil and NGLs (bbls/d)
16,500 – 18,000
12,298
40
Gas (MMcf/d)
165 – 180
124.9
38
Combined (BOE/d)
44,000 – 48,000
33,115
39
Forecasted Average Commodity Prices
WTI oil price (US$/bbl)
69.00
76.56
-10
Canadian Light Sweet ($/bbl)
91.55
98.70
-7
NYMEX natural gas price (US$/MMBtu)
3.25
2.25
44
AECO natural gas price ($/GJ)
2.27
1.38
64
Station 2 natural gas price ($/GJ)
2.14
1.13
90
Average Exchange Rate (US$/CA$)
0.7100
0.7299
-3
KELT EXPLORATION LTD.
24
ANNUAL REPORT
(CA$ millions, except as otherwise indicated)
2025 Budget
2024 Actuals
% Change (2)
Capital Expenditures, net of A&D (1)
328.0
333.1
-2
Petroleum and natural gas sales
671.2
468.4
43
Adjusted funds from operations (1)
345.0
222.0
55
Per common share, diluted (1)
1.70
1.11
53
Net debt (surplus), at year end (1)
100.0
124.9
-20
Weighted average common shares outstanding (millions) (1)
198.7
195.7
2
(1) Refer to advisories regarding “Non-GAAP and Other Financial Measures”.
(2) Percent change for production is calculated using the mid-point of each production range.
SIGNIFICANT JUDGMENTS AND ESTIMATES
The material accounting policies applied by the Company are disclosed in note 3 of the consolidated financial
statements as at and for the year ended December 31, 2024. The timely preparation of the financial statements requires
management to make judgments, estimates and assumptions that affect the application of accounting policies and the
reported amount of assets, liabilities, income and expenses. Actual results may differ materially 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 reviewed and for any future years affected. Significant judgments,
estimates and assumptions made by management in the consolidated annual financial statements are discussed
below.
Estimates are used in the evaluation of proved and proved plus probable reserves. Reserve estimates are
based on production forecasts, future production costs, forecasted commodity prices and future development
capital. Proved reserves and future development capital are used to deplete the net carrying value of property,
plant, and equipment (“PP&E”). Proved plus probable reserves are used to measure the fair value less cost
of disposal (“FVLCD”) in calculating impairment of PP&E. Reserves also impact the assessment of the
commercial viability and technical feasibility of an exploration project which impacts the decision to transfer
exploration and evaluation assets (“E&E”) to PP&E or whether an impairment exists;
The determination of CGUs requires judgment in defining a group of assets that generate cash inflows that
are largely independent of the cash inflows from other assets or groups of assets. The FVLCD is calculated
on a CGU basis to determine whether there is an impairment of PP&E;
The determination of the value of decommissioning liabilities depends upon estimates of future costs, timing
of expenditures, the risk-free rate and inflation rate;
Tax interpretations, regulations and legislation in the jurisdictions in which the Company operates are subject
to change. As such, deferred income taxes are subject to measurement uncertainty; and
Estimates and assumptions are used in the Black-Scholes option pricing model to calculate the stock option
expense.
For more details regarding the Company’s use of estimates and judgements, refer to note 2c) of the consolidated
financial statements as at and for the year ended December 31, 2024.
DISCLOSURE CONTROLS AND PROCEDURES
The Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”) have designed, or caused to be designed
under their supervision, disclosure controls and procedures as defined in National Instrument 52-109 of the Canadian
Securities Administrators, to provide reasonable assurance that: (i) material information relating to the Company is
made known to the CEO and the CFO by others, particularly during the period in which the annual and interim 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 periods specified in securities legislation.
KELT EXPLORATION LTD.
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ANNUAL REPORT
The CEO and the CFO have evaluated the effectiveness of Kelt’s disclosure controls and procedures as at December
31, 2024 and have concluded that such disclosure controls and procedures are effective. The assessment was based
on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The CEO and the CFO have designed, or caused to be designed under their supervision, internal controls over financial
reporting as defined in National Instrument 52-109 of the Canadian Securities Administrators, in order to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with IFRS.
There were no significant changes to the Company’s internal controls over financial reporting during the interim period
from October 1, 2024 to December 31, 2024 and year ended December 31, 2024. The CEO and the CFO have
evaluated the effectiveness of Kelt’s internal controls over financial reporting as at December 31, 2024 and have
concluded that such internal controls over financial reporting are effective. The assessment was based on the
framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission.
Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. In
addition, projections of any evaluation relating to the effectiveness in future periods are subject to the risk that controls
may become inadequate as a result of changes in conditions, or that the degree of compliance with policies and
procedures may deteriorate.
BUSINESS RISKS
The Company is exposed to various operational and financial risks inherent in the exploration, development, production
and marketing of crude oil, NGLs and natural gas liquids. These inherent risks include, but are not limited to, the
following:
Reservoir quality and the uncertainty of reserves estimates;
Volatility in the prevailing prices of crude oil, NGLs and natural gas;
Inflation and its impact on the cost of services and capital projects;
The actions of OPEC+ on global oil supply and its impact on price;
Regulatory risk related to the approval for exploration and development activities, which can add to costs or
cause delays in projects;
Environmental impact risk associated with exploration and development activities, including GHG emissions;
Shifts in demand as global energy markets transition to a lower carbon-based economy.
Future legislative and regulatory developments related to environmental regulation;
Geopolitical risks associated with changing governments or governmental policies, social instability and other
political, economic or diplomatic developments in the regions where the Company has its operations;
The ability to find, produce and replace reserves at a reasonable cost, including the risk of reserve revisions
due to economic and technical factors. Reserve revisions can have a positive or negative impact on asset
valuations, asset retirement obligations, lending capacity and depletion rates;
Access to labor, equipment and services to complete projects in a timely and cost efficient manner;
Operating hazards inherent in the exploration, development, production and sale of crude oil and natural gas;
Credit risk related to non-payment for sales contracts or other counterparties;
Interest rate risk associated with the Company’s cost to borrow and ability to secure financing on commercially
KELT EXPLORATION LTD.
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ANNUAL REPORT
acceptable terms;
Foreign exchange risk as commodity sales are predominantly based on US dollar denominated benchmarks;
Business interruptions because of unexpected events such as fires or explosions whether caused by human
error or nature, severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or
equipment failures of facilities and infrastructure and other similar events affecting the Company or other
parties whose operations or assets directly or indirectly impact the Company and that may or may not be
financially recoverable;
Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or
restrictions in the jurisdictions where the Company has operations;
Increasing carbon tax and changing royalty regimes;
The ability to secure adequate transportation for products which could be affected by pipeline and storage
constraints, the construction by third parties of new or expansion of existing pipeline capacity and other factors;
Potential limitations on the volumes of water required for completion activities due to drought, conditions of
low river flow, government restrictions or other factors;
The access to markets for the Company’s products;
The scope and duration of export tariffs, export restrictions, or import tariffs on commodities that Kelt sells, or
products that Kelt uses in its supply chains; and
The risk of significant interruption or failure of the Company's information technology systems and related
data and control systems or a significant breach that could adversely affect the Company's operations.
Indigenous Claims
On January 18, 2023, the Government of British Columbia and the Blueberry River First Nation (the “BRFN”) signed
the Blueberry River First Nations Implementation Agreement (the “BRFN Agreement”). The BRFN Agreement aims to
address the cumulative effects of development on BRFN’s claim area through restoration work, establishment of areas
protected from industrial development, and a constraint on development activities. Such measures will remain in place
while a long-term cumulative effects management regime is implemented. Specifically, the BRFN Agreement includes,
among other measures, the establishment of a $200-million restoration fund by June 2025, an ecosystem-based
management approach for future land- use planning in culturally important areas, limits on new petroleum and natural
gas development, and a new planning regime for future oil and gas activities. The BRFN will receive $87.5 million over
three years, with an opportunity for increased benefits based on petroleum and natural gas revenue sharing and
provincial royalty revenue sharing in the next two fiscal years.
In late January 2023, the Government of British Columbia and four Treaty 8 First Nations, Fort Nelson, Salteau, Halfway
River and Doig River First Nations reached consensus on a collaborative approach to land and resource planning (the
“Consensus Agreement”). The Consensus Agreement implements various initiatives including a “cumulative effects”
management system linked to natural resource landscape planning and restoration initiatives, new land-use plans and
protection measures, and a new revenue-sharing approach to support the priorities of Treaty 8 First Nations
communities.
In July 2022, Duncan’s First Nation filed a lawsuit against the Government of Alberta claiming in its lawsuit that Alberta
has failed to uphold its treaty obligations by authorizing development without considering the cumulative impacts on
the First Nation’s treaty rights.
The Company does not currently expect that there will be a significant impact to Kelt’s 2024 guidance as a result of the
BRFN Agreement, the Consensus Agreement, or the Duncan’s First Nation lawsuit. However the long-term impacts on
the Canadian oil and gas industry remain uncertain therefore the Company awaits additional information on these
agreements to assess what the future impact will be on the overall development of oil and gas resources in British
Columbia and Alberta.
KELT EXPLORATION LTD.
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ANNUAL REPORT
Environmental Risks
All phases of the oil and natural gas business present environmental risks and hazards and are subject to federal,
provincial and municipal laws and regulations. Environmental legislation provides for restrictions and prohibitions on
spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation
also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of
applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach
may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving
in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased
capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water
may give rise to liabilities to governments and third parties and may require Kelt to incur costs to remedy such discharge.
Kelt employs an environmental management system to manage these risks through a set of processes and practices
to collect, monitor and report on the environmental impact of its operations.
No assurance can be given that the application of environmental laws to the business and operations of Kelt will not
result in a curtailment of production or a material increase in the costs of production, development or exploration
activities or otherwise adversely affect Kelt’s financial condition, results of operations or prospects.
Climate Change Risks
Climate change policy is evolving at regional, national and international levels, and political and economic events may
significantly affect the scope and timing of climate change measures that are ultimately put in place. The federal and
provincial governments have implemented legislation aimed at incentivizing the use of alternatives fuels and reducing
carbon emissions. This legislation along with taxes placed on carbon emissions may have the effect of decreasing the
demand for oil and natural gas products and at the same time, increasing the Corporation’s operating expenses, each
of which may have a material adverse effect on the Corporation’s profitability and financial condition. Further, the
imposition of carbon taxes puts the Corporation at a disadvantage with the Corporation’s counterparts who operate in
jurisdictions where there are less costly carbon regulations. Currently enacted carbon pricing costs are included in the
Company’s report on its oil and gas reserves.
Adverse impacts to the Corporation’s business as a result of comprehensive carbon emission legislation or regulation
applied to the Corporation’s business in Alberta or any jurisdiction in which the Corporation operates, may include, but
are not limited to: (i) increased compliance costs; (ii) permitting delays; (iii) substantial costs to reduce emissions or
generate or purchase emission credits or allowances; and (iv) reduced demand for crude oil and certain refined
products. Emission allowances or offset credits may not be available for acquisition or may not be available on an
economic basis. Required emission reductions may not be technically or economically feasible to implement, in whole
or in part, and failure to meet such emission reduction requirements or other compliance mechanisms may have a
material adverse effect on the Corporation’s business resulting in, among other things, fines, permitting delays,
penalties and the suspensions of operations.
In addition to climate policy risk, the industry faces physical risks attributable to a changing climate. Climate change is
expected to increase the frequency of severe weather conditions, including high winds, heavy rainfall, extreme
temperatures, flooding and wildfires, which may result in damage to the Corporation’s assets, disruptions in operations
or transportation interruptions which may lead to increased capital expenditures or reduced revenues. Further
information is available on the Company’s ESG report which can be found on the Company’s website.
Cybersecurity
The Company has implemented cyber security protocols and procedures to reduce the risk of failure or a significant
breach of the Company’s information technology systems and related data and control systems. To manage this risk,
the Company maintains a system of internal controls and purchases insurance coverage against general risks
associated with cybersecurity. During the year ended December 31, 2024, the Company has not experienced a
cybersecurity breach that had a material impact on the business.
Risk Mitigation
The Company uses a variety of means to help mitigate or minimize these risks. The Company maintains a
comprehensive insurance program to reduce risk. Operational control is enhanced by focusing on large core areas with
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ANNUAL REPORT
high working interests and operatorship of drilling and completion operations. Product mix is diversified between natural
gas, NGLs and oil which reduces price risk in certain market conditions. Accounts receivable from the sale of crude oil
and natural gas are mainly with customers in the crude oil and natural gas industry and are subject to normal industry
credit risks. The Company manages these risks by monitoring exposure to individual customers, contractors, suppliers
and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit
are in place, and as applicable, taking other mitigating actions to minimize the impact in the event of a default. The
Company is exposed to possible losses in the event of non-performance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by primarily entering into agreements with counterparties
that are investment grade financial institutions, and reviews its counterparties on an on-going basis.
Tariffs
Increased tariffs on Canadian energy exports, restrictions on cross-border supply chains, or additional regulatory
barriers could impact Kelt’s ability to access international markets and conduct business efficiently. Restrictive trade
measures or countermeasures, implemented for any period of time, could have a significant impact on the market for
crude oil, NGLs, natural gas and refined petroleum products in Canada and internationally and could result in, among
other things, a high degree of both cost and price volatility, a relative weakening of the Canadian dollar, widening
differentials, and decreased demand for Kelt’s products and services. The impact of the Tariffs on Kelt’s business,
results of operations and financial condition is unknown and may be material and adverse.
A more detailed description of the Company’s risks is included in the Annual Information Form as at December 31,
2024, dated March 12, 2025 which can be found at www.sedarplus.ca.
NON-GAAP AND OTHER FINANCIAL MEASURES
This MD&A contains certain non-GAAP financial measures and other specified financial measures, as described below,
which do not have standardized meanings prescribed by GAAP and do not have standardized meanings under the
applicable securities legislation. As these non-GAAP, and other specified financial measures are commonly used in
the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that
these amounts may not be directly comparable to measures for other companies where similar terminology is used
NON-GAAP FINANCIAL MEASURES
P&NG sales after cost of purchases
Throughout this MD&A, reference is made to “P&NG sales” and “P&NG sales after cost of purchases”. P&NG sales is
as reported in the consolidated financial statements in accordance with GAAP and is before realized gains or losses
on derivative financial instruments. P&NG sales after cost of purchases includes P&NG sales (in accordance with
GAAP), net of the cost of third-party volumes purchases. P&NG sales after cost of purchases are used by management
to assess the Company’s sales from its core operations, which the Company believes may be a better indicator of
historical and future performance.
See the “Petroleum and Natural Gas Sales” section of this MD&A which provides a reconciliation of “P&NG sales after
cost of purchases to P&NG sales.
Net realized price
Net realized price is a non-GAAP measure and is calculated by dividing the Company’s P&NG sales after cost of
purchases by the Company’s production and reflects Kelt’s realized selling prices plus the net benefit of oil blending
and third-party natural gas sales. In addition to using its own production, the Company may purchase butane and crude
oil from third parties for use in its blending operations, with the objective of selling the blended oil product at a premium.
Marketing revenue from the sale of third-party volumes is included in P&NG sales as reported in the Consolidated
Statement of Net Income and Comprehensive Net Income in accordance with GAAP. Given the Company’s per unit
operating statistics disclosed throughout this MD&A are calculated based on Kelt’s production volumes, and excludes
the sale of third-party marketing volumes, management believes that disclosing its net realized prices based on P&NG
sales after cost of purchases is more appropriate and useful, because the cost of third-party volumes purchased to
generate the incremental marketing revenue has been deducted.
KELT EXPLORATION LTD.
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ANNUAL REPORT
Combined net realized prices referenced throughout this MD&A are before derivative financial instruments, except as
otherwise indicated as being after derivative financial instruments.
See the “Petroleum and Natural Gas Sales” section of this MD&A which provides a reconciliation of the net realized
price to P&NG sales, which is a GAAP measure.
Operating income and operating netback
Operating income is a non-GAAP measure calculated by deducting royalties, production expenses and transportation
expenses from petroleum and natural gas sales, net of the cost of purchases and after realized gains or losses on
derivative financial instruments. The Company also presents operating income on a per BOE basis, referred to as
“operating netback” or “operating income per BOE”, which allows management to better analyze performance against
prior periods, on a comparable basis, and is a key industry performance measure of operational efficiency.
See the “Adjusted Funds from Operations” section of this MD&A which provides a reconciliation of the operating income
and operating netback from P&NG sales, which is a GAAP measure.
Capital expenditures
“Capital expenditures, before A&D” and “Capital expenditures, net of A&D” are measures the Company uses to monitor
its investment in exploration and evaluation, investment in property plant and equipment, and net investment in
acquisition and disposition activities. The most directly comparable GAAP measure is “Cash used in investing
activities”, and is calculated as follows:
Three months ended
December 31
Year ended
December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
2024
2023
Cash used in investing activities
112,062
82,324
336,569
265,485
Change in non-cash investing working capital
(15,016)
(19,629)
(3,422)
17,161
Capital expenditures, net of A&D
97,046
62,695
333,147
282,646
Property acquisitions (1)
(3,400)
(10)
(4,173)
(102)
Property dispositions (1)
-
50
-
50
Capital expenditures, before A&D
93,646
62,735
328,974
282,594
(1) Property acquisitions and property dispositions for the year ended December 31, 2024 includes $0.6 million of non-cash consideration and for the
year ended December 31, 2023 includes $6.9 million of non-cash consideration.
Adjusted earnings before interest and taxes
Kelt calculates adjusted earnings before interest and taxes (“EBIT”) as net income and comprehensive income plus
financing, less accretion of decommissioning obligations, plus deferred income tax expense. Kelt uses adjusted EBIT
as a measure of long-term operating performance and as a component in the calculation for return on average capital
employed (“ROACE”). The following table contains a reconciliation of adjusted EBIT to the most directly comparable
GAAP measure, net income and comprehensive income.
(CA$ thousands, except as otherwise indicated)
December 31,
2024
December 31,
2023
December 31,
2022
Net income and comprehensive income
45,423
85,974
158,758
Financing expenses
6,756
4,190
3,911
Accretion of decommissioning obligations
(3,082)
(2,880)
(2,451)
Deferred income tax expense
17,733
28,503
51,441
Adjusted EBIT
66,830
115,787
211,659
Average capital employed
Kelt calculates average capital employed as the total of net debt plus the short and long term lease obligations and
shareholders equity. Kelt uses average capital employed as a measure of long-term capital management and operating
KELT EXPLORATION LTD.
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ANNUAL REPORT
performance, and as a component in the calculation for ROACE. The table below provides a reconciliation of average
capital employed to the most directly comparable GAAP measures of shareholders equity.
(CA$ thousands, except as otherwise indicated)
December 31,
2024
December 31,
2023
December 31,
2022
Net debt – beginning of period
12,997
9,789
28,220
Current portion of lease obligations
1,125
505
609
Long-term portion of lease obligations
332
543
399
Shareholders' equity - beginning of period
1,003,663
901,424
722,724
Opening capital employed (A)
1,018,117
912,261
751,952
Net debt – end of period
124,883
12,997
9,789
Current portion of lease obligations
1,655
1,125
505
Long-term portion of lease obligations
419
332
543
Shareholders' equity - end of period
1,063,004
1,003,663
901,424
Closing capital employed (B)
1,189,961
1,018,117
912,261
Average capital employed (A+B)/2
1,104,039
965,189
832,107
Return on average capital employed
Kelt calculates ROACE, expressed as a percentage, as adjusted EBIT divided by the average capital employed. The
components adjusted EBIT and average capital employed are non-GAAP financial measures. Kelt uses ROACE as a
measure of long-term financial performance.
(CA$ thousands, except as otherwise indicated)
Three-year
Average
December 31,
2024
December 31,
2023
December 31,
2022
Adjusted EBIT
66,830
115,787
211,659
Average capital employed
1,104,039
965,189
832,107
ROACE (%)
14%
6%
12%
25%
CAPITAL MANAGEMENT MEASURES
Funds from operations and adjusted funds from operations
Management considers funds from operations and adjusted funds from operations as a key capital management
measure as it demonstrates the Company’s ability to meet its financial obligations and cash flow available to fund its
capital program. Funds from operations and adjusted funds from operations are not standardized measures and
therefore may not be comparable with the calculation of similar measures by other entities. The most comparable GAAP
measure is “Cash provided by operating activities”. Funds from operations and adjusted funds from operations are
calculated as follows:
Three months ended
December 31
Year ended
December 31
(CA$ thousands, except as otherwise indicated)
2024
2023
2024
2023
Cash provided by operating activities
48,067
62,477
209,145
283,224
Change in non-cash working capital
19,471
1,697
7,797
(11,562)
Funds from operations
67,538
64,174
216,942
271,662
Settlement of decommissioning obligations
1,868
2,444
5,036
4,538
Adjusted funds from operations
69,406
66,618
221,978
276,200
Net debt (surplus) and net debt (surplus) to adjusted funds from operations ratio
Management considers net debt (surplus) and net debt (surplus) to adjusted funds from operations ratio as key capital
management measures to assess the Company’s liquidity at a point in time and to monitor its capital structure and
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ANNUAL REPORT
short-term financing requirements. The “net debt (surplus) to adjusted funds from operations ratio” is also indicative of
the “net debt to cash flow ratio” calculation used to determine the applicable margin for a quarter under the Company’s
Credit Facility agreement (though the calculation may not always be a precise match, it is representative).
“Net debt (surplus)” is equal to bank debt, accounts payable and accrued liabilities, net of cash and cash equivalents,
accounts receivables and accrued sales and prepaid expenses and deposits. The Company believes that using a “Net
debt (surplus)” non-GAAP measure, which excludes non-cash derivative financial instruments, non-cash lease
liabilities, and non-cash decommissioning obligations, provides investors with more useful information to understand
the Company’s cash liquidity risk.
See the “Capital Resources and Liquidity” section of this MD&A for calculation of the Net debt and net debt to adjusted
funds from operations ratio.
SUPPLEMENTARY FINANICAL MEASURES
“Production per common share” is calculated by dividing total production by the basic weighted average number of
common shares outstanding, as determined in accordance with GAAP.
P&NG sales, cost of purchases, gain (loss) on financial instruments, royalties, production expenses, transportation
expenses, financing expenses, gross and net G&A expenses, realized loss (gain) on foreign exchange, other income
(expense), share based compensation expense, and depletion and depreciation expense on a $/BOE basis is
calculated by dividing the amounts by the Company’s total production over the period.
Adjusted funds from operations per share (basic and diluted), and net income and comprehensive net income per share
(basic and diluted) is calculated by dividing the amounts by the basic weighted average common shares outstanding.
Net asset value
“Net asset value” is calculated by adding the present value of proved plus probable petroleum and natural gas reserves
discounted at 10% before-tax (as estimated by McDaniel effective December 31, 2024), undeveloped land value,
proceeds from exercise of stock options, and net bank debt (surplus). “Net asset value per common share” is calculated
by dividing the “Net asset value” by the diluted number of common shares outstanding. The calculation of proceeds
from exercise of stock options and the diluted number of common shares outstanding only include stock options that
are “in-the-money” based on the closing price of Kelt common shares as at the calculation date. Management believes
that the “Net asset value” provides a useful measure to analyze the comparative change in the Company’s estimated
value on a normalized basis.
See the “Net asset value” section of this MD&A which provides a reconciliation of the net asset value to Kelt’s Present
value of 2P P&NG reserves, discounted at 10% before-tax.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS
The information set out herein is “financial outlook” within the meaning of applicable securities laws. The purpose of
this financial outlook is to provide readers with disclosure regarding Kelt’s reasonable expectations as to the anticipated
results of its proposed business activities for the calendar year 2025. Readers are cautioned that this financial outlook
may not be appropriate for other purposes.
Certain information with respect to Kelt contained herein, including management’s assessment of future plans and
operations, contains forward-looking statements. These forward-looking statements are based on assumptions and are
subject to numerous risks and uncertainties, many of which are beyond Kelt’s control, including the impact of general
economic conditions, the scope and duration of export tariffs, export restrictions, or import tariffs on commodities that
Kelt sells, or products that Kelt uses in its supply chains, industry conditions, volatility of commodity prices, currency
exchange rate fluctuations, imprecision of reserve estimates, environmental risks, competition from other explorers,
stock market volatility and ability to access sufficient capital.
Any forward-looking information or financial outlook set out herein does not include any potential impact of tariffs or
trade-related regulations that have been announced by the U.S. and Canada, including the tariffs announced by the
U.S. on Canada in 2025, and the retaliatory tariffs announced by Canada.
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ANNUAL REPORT
As a result, Kelt’s 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 events anticipated by the
forward-looking statements will transpire or occur.
In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. The
forward-looking statements contained herein are made as of the date hereof and the Company does not intend, and
does not assume any obligation, to update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise unless expressly required by applicable securities laws.
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves, and the future
net revenue attributed to such reserves, including many factors beyond the control of Kelt. The reserves and associated
future net revenue information set forth in this MD&A are estimates only. In general, estimates of economically
recoverable oil, natural gas and NGLs reserves and the future net revenue therefrom are based upon a number of
variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserves
recovery, the timing and amount of capital expenditures, marketability of oil, natural gas and NGLs, royalty rates, the
assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially
from actual results. For these reasons, estimates of the economically recoverable oil, natural gas and NGLs reserves
attributable to any particular group of properties, the classification of such reserves based on risk of recovery and
estimates of future net revenue associated with reserves prepared by different engineers, or by the same engineer at
different times, may vary.
Kelt’s actual production, revenue, taxes and development and operating expenditures with respect to its reserves will
vary from estimates thereof and such variations could be material. It should not be assumed that the undiscounted or
discounted net present value of future net revenue attributable to the Corporation’s reserves estimated by the
Corporation’s independent qualified reserves evaluators represent the fair market value of those reserves. There is no
assurance that the forecast prices and costs assumptions will be attained, and variances could be material. Actual oil,
natural gas and NGLs reserves may be greater than or less than the estimates provided herein, and variances could
be material.
With respect to the disclosure of reserves contained herein relating to portions of Kelt’s properties, the estimates of
reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of
reserves and future net revenue for all properties, due to the effects of aggregation. Unless otherwise stated all
references to “reserves” are to Kelt’s gross company reserves before deduction of royalties and without including and
royalty interests of Kelt. It should not be assumed that the undiscounted or discounted net present value of the
Company’s reserves, as determined by McDaniel, represents the fair value of those reserve estimates.
This MD&A contains forward-looking statements and forward-looking information within the meaning of applicable
securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”,
“will”, “project”, “should”, “believe”, “plans”, “intends”, “potentially” and similar expressions are intended to identify
forward-looking information or statements. In particular, this MD&A contains forward-looking statements pertaining to
the following: Kelt’s expected price realizations and future commodity prices; its expected oil and NGLs weighting; the
cost and timing of future capital expenditures and expected results; the expected timing of wells brought on-production;
the expected timing of production additions from capital expenditures; the ability to show significant production growth;
the expected timing for well completions; the expected timing and processing capacity from the start-up of a new third
party facility at Wembley/Pipestone and from the start-up of a new third party facility at Gordondale West; the ability to
access sufficient capital from internal sources and bank and equity markets, the performance of existing wells, the
effect of regulatory agencies including environmental regulations, taxes and royalties, and the Company's expected
future financial position and operating results..
References herein to the IP30 and IP365 production rates are useful in confirming the presence of hydrocarbons,
however the production rates are over a short period of time and, therefore, are not necessarily indicative of average
daily production, long-term performance or of ultimate recovery from the wells. Readers are cautioned not to place
reliance on such rates in calculating aggregate production for the assets for which such rates are provided.
Statements relating to "reserves" or “resources” are deemed to be forward looking statements, as they involve the
implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities
KELT EXPLORATION LTD.
33
ANNUAL REPORT
predicted or estimated and that the reserves can be profitably produced in the future. Actual reserves may be greater
than or less than the estimates provided herein.
Although Kelt believes that the expectations and assumptions on which the forward-looking statements are based are
reasonable, undue reliance should not be placed on the forward-looking statements because Kelt cannot give any
assurance that they will prove to be correct. Since forward-looking statements address future events and conditions,
by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those
currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated
with the oil and gas industry in general, operational risks in development, exploration and production; delays or changes
in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve
estimates; the uncertainty of estimates and projections relating to production, costs and expenses; failure to obtain
necessary regulatory approvals for planned operations; health, safety and environmental risks; uncertainties resulting
from potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
volatility of commodity prices, currency exchange rate fluctuations; imprecision of reserve estimates; as well as general
economic conditions, stock market volatility; the ability to access sufficient water or other fluids needed for completion
operations; and the ability to access sufficient capital. We caution that the foregoing list of risks and uncertainties is not
exhaustive.
ADDITIONAL INFORMATION
Additional information relating to Kelt, including the Company’s Annual Information Form (“AIF”) dated March 12, 2025
is filed on SEDAR+ and can be viewed on their website at www.sedarplus.ca. Copies of the AIF can also be obtained
by contacting Sadiq H. Lalani, Vice President and Chief Financial Officer at Kelt Exploration Ltd., Suite 300, 311 Sixth
Avenue SW, Calgary, Alberta, Canada, T2P 3H2. Further information relating to Kelt is also available on its website at
www.keltexploration.com.
KELT EXPLORATION LTD.
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ANNUAL REPORT
MANAGEMENT’S REPORT
The accompanying consolidated financial statements of Kelt Exploration Ltd. (the “Company”) are the responsibility of
management. The consolidated financial statements have been prepared by management in Canadian dollars in
accordance with International Financial Reporting Standards, as issued by the International Accounting Standards
Board (“IFRS Accounting Standards”) and include certain estimates that reflect management’s best judgments. When
alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances.
Management has the overall responsibility for internal controls and maintains a system of internal controls over financial
reporting that provides reasonable assurance that the financial information is relevant, reliable and accurate and that
the Company’s assets are properly accounted for and adequately safeguarded.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and
internal control. The Board exercises this responsibility with the assistance of the Audit Committee. This Committee,
consisting of non-management directors, meets with management and independent auditors to ensure that each group
is properly discharging its responsibilities and to discuss adequacy of internal controls, accounting policies and financial
reporting matters. The Audit Committee has reviewed the financial statements and has reported thereon to the Board
of Directors. The Board of Directors has approved the consolidated financial statements and authorized them for
issuance to shareholders.
PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, has been engaged, as
approved by the shareholders of the Company, to provide an independent audit opinion on the Company’s consolidated
financial statements. Their report, contained herein, outlines the nature of their audit and expresses an unqualified
opinion on the consolidated financial statements.
[signed]
David J. Wilson
President and Chief Executive Officer
March 12, 2025
[signed]
Sadiq H. Lalani
Vice President and Chief Financial Officer
March 12, 2025
KELT EXPLORATION LTD.
35
ANNUAL REPORT
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 Shareholders of Kelt Exploration Ltd.
Our opinion
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects,
the financial position of Kelt Exploration Ltd. and its subsidiary (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 International Financial Reporting 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 statements of financial position as at December 31, 2024 and 2023;
the consolidated statements of net income and comprehensive net income 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.
KELT EXPLORATION LTD.
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ANNUAL REPORT
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 crude oil and natural gas proved
reserves on net development and production
(D&P) assets
Refer to note 2(c) – Significant judgments and
estimates, note 3 – Material accounting policies and
note 6 – Property, plant and equipment to the
consolidated financial statements
The Company has $1,358 million of net D&P assets
as at December 31, 2024. Depletion and
depreciation (D&D) expense for the D&P assets
was $140 million for the year then ended. D&P
assets are depleted using the unit of production
method by reference to the ratio of production in the
year to the related proved reserves, taking into
account future development cost estimates
necessary to bring those reserves into production.
The significant assumptions used by management
to determine the proved reserves of the Company’s
D&P assets include production forecasts, future
production costs, forecasted commodity prices and
future development costs. The proved reserves are
determined by the Company’s independent
qualified reserve evaluators (management’s
experts).
We considered this a key audit matter due to (i) the
significant judgments made by management,
including the use of management’s experts, when
estimating the proved reserves; and (ii) a high
degree of auditor judgment, subjectivity and effort in
performing procedures relating to the significant
assumptions.
Our approach to addressing the matter included the
following procedures, among others:
Tested how management determined the
proved reserves, which included the following:
‒
The work of management’s experts was
used in performing the procedures to
evaluate the reasonableness of the proved
reserves. As a basis for using this work, the
competence, capabilities and objectivity of
management’s experts was 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.
‒
Evaluated the reasonableness of significant
assumptions used, including production
forecasts, future production costs and
future development costs by considering
the current and past performance and
whether these assumptions were
consistent with evidence obtained in other
areas of the audit, as applicable.
‒
Evaluated the reasonableness of
forecasted commodity prices by comparing
them to third party industry forecasts.
Recalculated the unit-of-production rates used
to calculate depletion and depreciation expense
for the D&P assets.
KELT EXPLORATION LTD.
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ANNUAL REPORT
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.
KELT EXPLORATION LTD.
38
ANNUAL REPORT
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.
KELT EXPLORATION LTD.
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ANNUAL REPORT
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 Alexandra Arnell.
/s/PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta
March 12, 2025
KELT EXPLORATION LTD.
40
ANNUAL REPORT
KELT EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS AT DECEMBER 31, 2024 AND DECEMBER 31, 2023
(CA$ thousands)
[Notes]
December 31, 2024
December 31, 2023
ASSETS
Current assets
Cash and cash equivalents
228
14,340
Accounts receivable and accrued sales
[11]
60,236
52,646
Prepaid expenses and deposits
4,109
5,188
Derivative financial instruments
[11]
6,709
3,974
Total current assets
71,282
76,148
Derivative financial instruments
[11]
-
570
Exploration and evaluation assets
[5]
18,092
17,162
Property, plant and equipment
[6]
1,361,305
1,166,412
Total assets
1,450,679
1,260,292
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
[11]
80,463
85,171
Derivative financial instruments
[11]
7,936
585
Decommissioning obligations
[8]
3,552
4,360
Lease liability
[9]
1,655
1,125
Total current liabilities
93,606
91,241
Bank debt
[7]
108,993
-
Decommissioning obligations
[8]
97,423
95,555
Lease liability
[9]
419
332
Deferred income tax liability
[12]
87,234
69,501
Total liabilities
387,675
256,629
SHAREHOLDERS' EQUITY
Shareholders' capital
[10]
1,184,065
1,175,465
Contributed surplus and reserve
(6,692)
(12,010)
Deficit
(114,369)
(159,792)
Total shareholders' equity
1,063,004
1,003,663
Total liabilities and shareholders' equity
1,450,679
1,260,292
Commitments
[15]
The accompanying notes form an integral part of these consolidated financial statements.
On behalf of the Board of Directors:
[signed]
[signed]
David J. Wilson, Director
Neil G. Sinclair, Director
KELT EXPLORATION LTD.
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ANNUAL REPORT
KELT EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF NET INCOME AND COMPREHENSIVE NET INCOME
FOR THE YEARS ENDED DECEMBER 31, 2024 AND DECEMBER 31, 2023
Year ended December 31
(CA$ thousands, except per share amounts)
[Notes]
2024
2023
Revenue
Petroleum and natural gas sales
[13]
468,432
495,580
Royalties
(54,737)
(59,170)
413,695
436,410
Expenses
Production
121,355
109,422
Transportation
42,625
38,808
Cost of purchases
16,365
16,565
Financing
[14]
6,756
4,190
General and administrative
[16]
12,272
10,384
Share based compensation
[10]
8,846
7,862
Exploration and evaluation
[5]
214
1,413
Depletion and depreciation
[6]
141,494
125,813
349,927
314,457
Loss on derivative financial instruments
[11]
(933)
(8,748)
Gain (loss) on foreign exchange
204
(104)
Gain on sale of assets
[4]
-
50
Other income
117
1,326
Net income before taxes
63,156
114,477
Deferred income tax expense
[12]
(17,733)
(28,503)
Net income and comprehensive income
45,423
85,974
Net income per common share
Basic
[10]
0.23
0.45
Diluted
[10]
0.23
0.44
The accompanying notes form an integral part of these consolidated financial statements.
KELT EXPLORATION LTD.
42
ANNUAL REPORT
KELT EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2024 AND DECEMBER 31, 2023
Shareholders’ capital
Contributed
surplus and
reserve
Retained
earnings (deficit)
Total
shareholders’
equity
(CA$ thousands)
[Notes]
Number of
Shares (000s)
Amount
($ thousands)
Balance at December 31, 2022
192,014
1,162,650
(15,460)
(245,766)
901,424
Net income and comprehensive income
-
-
-
85,974
85,974
Exercise of stock options
[10]
2,145
11,832
(3,429)
-
8,403
Vesting of restricted share units
[10]
347
983
(983)
-
-
Share based compensation
[10]
-
-
7,862
-
7,862
Balance at December 31, 2023
194,506
1,175,465
(12,010)
(159,792)
1,003,663
Net income and comprehensive income
-
-
-
45,423
45,423
Exercise of stock options
[10]
1,836
7,175
(2,103)
-
5,072
Vesting of restricted share units
[10]
414
1,425
(1,425)
-
-
Share based compensation
[10]
-
-
8,846
-
8,846
Balance at December 31, 2024
196,756
1,184,065
(6,692)
(114,369)
1,063,004
The accompanying notes form an integral part of these consolidated financial statements.
KELT EXPLORATION LTD.
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ANNUAL REPORT
KELT EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2024 AND DECEMBER 31, 2023
Year ended December 31
(CA$ thousands)
[Notes]
2024
2023
Operating activities
Net income and comprehensive income
45,423
85,974
Items not affecting cash:
Accretion of decommissioning obligations
[14]
3,082
2,880
Share based compensation
[10]
8,846
7,862
Exploration and evaluation
[5]
214
1,413
Depletion and depreciation
[6]
141,494
125,813
Unrealized loss on derivative financial instruments
[11]
5,186
23,805
Gain on sale of assets
[4]
-
(50)
Deferred income tax expense
[12]
17,733
28,503
Settlement of decommissioning obligations
[8]
(5,036)
(4,538)
Change in non-cash operating working capital
[17]
(7,797)
11,562
Cash provided by operating activities
209,145
283,224
Financing activities
Increase (decrease) in bank debt
[7]
108,993
(11,300)
Proceeds on exercise of stock options
[10]
5,072
8,403
Repayment of lease liability principal
[9]
(753)
(627)
Cash provided by (used in) financing activities
113,312
(3,524)
Investing activities
Exploration and evaluation assets
[5]
(2,961)
(6,115)
Property, plant and equipment
[6]
(326,013)
(276,479)
Property acquisitions
[4]
(4,173)
(102)
Property dispositions
[4]
-
50
Change in non-cash investing working capital
[17]
(3,422)
17,161
Cash used in investing activities
(336,569)
(265,485)
Net change in cash and cash equivalents
(14,112)
14,215
Cash and cash equivalents, beginning of year
14,340
125
Cash and cash equivalents, end of year
228
14,340
The accompanying notes form an integral part of these consolidated financial statements.
KELT EXPLORATION LTD.
44
ANNUAL REPORT
KELT EXPLORATION LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023
(All tabular amounts in thousands of Canadian dollars, except as otherwise indicated)
1. DESCRIPTION OF THE BUSINESS
Kelt Exploration Ltd. (“Kelt” or the “Company”) is an oil and gas company based in Calgary, Alberta, focused on the
exploration, development and production of crude oil and natural gas resources in northwestern Alberta and
northeastern British Columbia. The Company’s British Columbia assets are operated by Kelt Exploration (LNG) Ltd.
(“Kelt LNG”), a wholly owned subsidiary of Kelt. The Company’s common shares are listed on the Toronto Stock
Exchange (“TSX”) under the symbol “KEL”.
The head office of Kelt is located at Suite 300, 311 - 6th Avenue S.W., Calgary, Alberta T2P 3H2.
2. BASIS OF PRESENTATION
The Company’s Board of Directors approved and authorized these consolidated financial statements on March 12,
2025.
a) Statement of compliance
The Company prepares its consolidated financial statements (the “financial statements”) in accordance with
International Financial Reporting Standards, as issued by the International Accounting Standards Board (“IFRS
Accounting Standards”).
b) Basis of measurement
All references to dollar amounts in these financial statements and related notes are thousands of Canadian dollars,
unless otherwise indicated.
The financial statements have been prepared on a historical cost basis, except for certain financial instruments which
are recorded at fair value. The methods used to measure fair values are described in note 11 of these financial
statements.
c) Significant judgments and estimates
The timely preparation of the financial statements requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and the reported amount of assets, liabilities, income and
expenses. Actual results may differ materially 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 reviewed and for any future years affected. Significant judgments, estimates and assumptions made by
management in these financial statements are discussed below.
Depletion, depreciation and reserves
The net carrying value of property, plant, and equipment (“PP&E”) is depleted using total proved reserves and future
development costs, as determined by the Company’s independent qualified reserve evaluators. This evaluation of
proved and proved plus probable reserves is prepared in accordance with the reserves definitions as set up by the
Canadian Securities Administrators in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities
and the Canadian Oil and Gas Evaluation Handbook (“COGEH”). Future profit (loss) can be affected as a result of the
methodology of depleting the net carrying value of property, plant and equipment.
Reserves (proved and probable) are also used in measuring the fair value less costs of disposal (“FVLCD”) of property,
plant and equipment for impairment calculations and for determining the fair value of PP&E acquired in a business
combination. The reserve estimates are based on production forecasts, future production costs, forecasted commodity
prices and future development costs. Reserves also impact the assessment of the commercial viability and technical
feasibility of an exploration project which impacts the decision to transfer exploration and evaluation assets (“E&E”) to
KELT EXPLORATION LTD.
45
ANNUAL REPORT
PP&E.
Although reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation can be impacted
by subjective decisions, new geological or production information and a changing environment. In addition, revisions
to reserve estimates can arise from changes in forecast oil and gas prices and reservoir performance. Such revisions
can be either positive or negative.
Exploration and evaluation assets
Judgment is required to determine the level at which E&E is assessed for impairment. The carrying value of E&E assets
is assessed for overall impairment at the operating segment level and on a specific identification basis prior to
transferring E&E assets to PP&E. The decision to transfer assets from E&E to PP&E requires judgment as it is based
on whether the E&E investments have a sufficient amount of economically recoverable reserves to ensure a projects
technical feasibility and commercial viability.
E&E assets remain capitalized as long as sufficient progress is being made by the Company in assessing the technically
feasible and commercially viable of these assets. Changes to project economics, forecasted commodity prices,
expected capital investment costs and production costs are important factors considered in assessing the technically
feasible and commercially viable of these assets.
Determination of Cash Generating Units (“CGUs”)
The determination of CGUs requires judgment in defining a group of assets that generate cash inflows that are largely
independent of the cash inflows from other assets or groups of assets. CGUs are determined by similar geological
structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risks and
materiality. As at December 31, 2024, the Company has one CGU for its assets located in the province of British
Columbia and one CGU for its assets located in the province of Alberta.
Impairment of non-financial assets
Significant judgment is required to assess non-financial assets, namely E&E and PP&E, for indicators of impairments.
Management must first determine whether indicators of impairment exist that suggest the carrying value may not be
recoverable through the asset’s continued use or sale.
Significant assumptions used to estimate the recoverable amount of PP&E in the impairment test include proved and
probable reserve volumes, commodity price forecasts, future production volumes, future production costs, future
development capital expenditures and the discount rate.
Management calculates the recoverable amount of each CGU based on its FVLCD, using an after-tax discounted cash
flow analysis derived from proved plus probable reserves. Reserve estimates and expected future cash flows from
production of reserves are subject to measurement uncertainty as discussed above and are subject to variability due
to changes in forecasted commodity prices. In addition, the present value of forecast future cash flows is highly sensitive
to the discount rate. Judgment is required to determine an appropriate discount rate that reflects current market
assessments of the time value of money and the risks specific to the asset.
Decommissioning obligations
The Company estimates the decommissioning obligations for oil and gas wells and their associated production facilities
and infrastructure. In most instances, dismantling of assets and remediation occurs many years into the future. The
future value of the decommissioning obligation can fluctuate in response to many factors including changes to legal
requirements, the emergence of new restoration techniques, experience at other production sites, changes to the risk-
free discount rate and changes to inflation. The expected timing and amount of expenditure may be adjusted in
response to revisions in reserves or changes in laws and regulations and could be impacted by the rate the markets
transition to a lower carbon-based economy. Judgments include the most appropriate discount rate to use, which
management has determined to be a risk-free rate. Key assumptions are disclosed in note 8 of these financial
statements.
Kelt estimates abandonment and reclamation costs based on a combination of publicly available industry benchmarks
and internal site specific information. For producing wells and facilities, the expected timing of settlement is estimated
KELT EXPLORATION LTD.
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ANNUAL REPORT
based on the proved plus probable period to abandonment for each depletable area, as per the independent reserve
report. For non-producing wells, the expected timing of settlement is estimated to be between four and ten years, unless
the timing to abandon and reclaim a specific well site or facility is known based on budgeted expenditures.
Deferred income taxes
The liability method is used for calculating deferred income taxes. Tax interpretations, regulations and legislation in the
jurisdictions in which the Company operates are subject to change. As such, deferred income taxes are subject to
measurement uncertainty.
Share based compensation
The fair value method of accounting is used for its long-term incentive plans, which include an Incentive Stock Option
Plan and a Restricted Share Unit Plan. Judgments include which valuation model is most appropriate for the grant of
the award to estimate its fair value. Estimates and assumptions are then used in the valuation model to determine fair
value.
For stock options, the Black-Scholes option pricing model is used, which requires that management make assumptions
for the expected life of the option, the anticipated volatility of the share price over the life of the option, the risk-free
interest rate for the life of the option, and the number of options that will ultimately vest. These assumptions are
disclosed in note 10 of these financial statements.
The fair value of restricted share units is estimated based on the volume weighted average trading price (“VWAP”) on
the TSX over three trading days immediately prior to the date of grant. Judgment is also required to estimate the rate
of forfeiture, or number of restricted share units that will ultimately vest.
3. MATERIAL ACCOUNTING POLICIES
New Accounting Policies
The IASB issued amendments to IAS 1 "Presentation of financial statements" which is effective for annual periods
beginning on or after January 1, 2024. The amendments clarified how an entity classifies debt and other financial
liabilities as current or non-current in certain circumstances. These amendments to IAS 1 did not have any impact on
the Company’s financial statements.
In April 2024, the IASB issued IFRS 18 'Presentation and Disclosure in Financial Statements' which will replace IAS 1
'Presentation of Financial Statements'. The standard introduces a new defined structure to the Consolidated Statements
of Net Income and Comprehensive Net Income with new categories for income and expenses and new totals and
subtotals. In addition, there are additional disclosures around management defined performance measures and
additional requirements regarding the aggregation and disaggregation of certain information. IFRS 18 is effective
January 1, 2027, and are required to be adopted retrospectively with early adoption permitted. The Company is
assessing the impact of IFRS 18 on the Company's consolidated financial statements.
In May 2024, the IASB issued amendments IFRS 9 'Financial Instruments' and IFRS 7 'Financial Instruments:
Disclosures' to clarify the date of recognition and derecognition of financial assets and liabilities including the settling
of financial liabilities using an electronic payment system and assessing contractual cash flow characteristics of financial
assets. These amendments are effective January 1, 2026, and are required to be adopted retrospectively with early
adoption permitted. The Company is assessing the impact of the amendments on the Company's consolidated financial
statements.
Joint interests
A portion of the Company’s exploration, development and production activities is conducted jointly with others through
unincorporated joint ventures. These financial statements reflect only the Company’s proportionate interest of these
jointly controlled assets and the proportionate share of the relevant revenue and related costs.
Foreign currency translation
The financial statements are presented in Canadian dollars, which is the Company’s functional and presentation
KELT EXPLORATION LTD.
47
ANNUAL REPORT
currency. Transactions in U.S. dollars are initially recorded at the exchange rate in effect at the time of the transactions.
Monetary assets and liabilities denominated in U.S. dollars are translated to Canadian dollars using the closing
exchange rate at the Consolidated Statement of Financial Position date. The resulting exchange rate differences are
included in the Consolidated Statement of Net Income and Comprehensive Net Income.
Principles of consolidation
As at December 31, 2024, the Company has one wholly-owned subsidiary, Kelt LNG. Subsidiaries are entities
controlled by the Company. Control exists when there is power to govern the financial and operating policies of an
entity to obtain benefits from its activities. The consolidated financial statements include the accounts of Kelt and Kelt
LNG. The financial statements of Kelt LNG are prepared for the same reporting period as Kelt using uniform accounting
policies. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the
date there is a loss of control. All intercompany balances, transactions, revenue and expenses are eliminated on
consolidation.
Financial instruments
Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the
instrument. Financial assets are derecognized when the rights to receive cash flows from the assets have expired or
have been transferred and all risks and rewards of ownership have substantially transferred.
Financial assets and liabilities are offset and the net amount is reported in the Consolidated Statement of Financial
Position when there is a legally enforceable right to offset the recognized amounts and there is an intention to settle on
a net basis, or realize the asset and settle the liability simultaneously.
At initial recognition, financial instruments are measured at fair value plus any directly attributable transaction costs.
Subsequent to initial recognition, financial instruments are measured at amortized cost or at fair value through profit or
loss (“FVTPL”) depending on the purpose for which the instruments were acquired.
ii) Derivative financial instruments
The Company may use derivative financial instruments for risk management purposes. All derivatives have been
classified at FVTPL. Financial instruments are included on the Consolidated Statement of Financial Position within
derivative financial instruments and are classified as current or non-current based on the contractual terms specific to
the instrument. Gains and losses on re-measurement of derivatives are included in profit or loss in the period in which
they arise.
Embedded derivatives are separated from the host contract and accounted for separately if the economic
characteristics and risks of the host contract and the embedded derivative are not closely related. Gains and losses on
re-measurement of embedded derivatives are included in profit or loss in the period in which they arise.
Physical commodity contracts are entered into and held for the purpose of receipt or delivery of non-financial items.
These contracts are not considered to be derivative financial instruments and have not been recorded at fair value on
the statement of financial position, unless it is determined that an embedded derivative exists within the contract.
Realized gains or losses from physically settled commodities sales contracts are recognized in petroleum and natural
gas sales as the contracts are settled.
Exploration and evaluation assets and property, plant and equipment
i) Recognition and measurement
Pre-license costs
Costs incurred prior to acquiring the legal rights to explore an area are charged directly to profit or loss as exploration
expense in the period incurred. The Company did not incur pre-license costs in the current or prior period.
Exploration and evaluation assets
All costs directly associated with the exploration and evaluation of petroleum and natural gas reserves are initially
capitalized. Exploration and evaluation costs include unproved property acquisition costs such as undeveloped land
KELT EXPLORATION LTD.
48
ANNUAL REPORT
and mineral leases, geological and geophysical costs, and costs associated with exploratory drilling and appraisals.
Such costs are not subject to depletion or depreciation until they are reclassified from E&E to PP&E.
The costs are accumulated by exploration area pending determination of technical feasibility and commercial viability.
The technical feasibility and commercial viability is considered to be achieved when a sufficient amount of economically
recoverable reserves relative to the estimated potential resources is estimated to exist, combined with available
infrastructure to support commercial development. Prior to being transferred to PP&E, E&E costs are first tested for
impairment. If proved/probable reserves have not been established through exploration and evaluation activities, and
there are no future plans for activity in that exploration area, then the costs are determined to be impaired and the
amounts are expensed to the Consolidated Statement of Net Income and Comprehensive Net Income.
Property, plant and equipment
Property, plant, and equipment primarily consists of petroleum and natural gas development and production assets,
and is measured at cost less accumulated depletion and depreciation and accumulated impairment losses. These costs
include property acquisitions, development drilling, completion, gathering and infrastructure, estimated
decommissioning costs and transfers from E&E.
ii) Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of
replacing components of equipment are recognized as property, plant and equipment only when they increase the
future economic benefits embodied in the specific asset to which they relate. All other expenditures are expensed as
incurred. Such capitalized amounts generally represent costs incurred in developing proved and/or probable reserves
and bringing in or enhancing production from such reserves. The carrying amount of any replaced or sold component
is derecognized.
The gain or loss from the sale of property, plant and equipment is recognized in the Consolidated Statement of Net
Income and Comprehensive Net Income. In addition, agreements in which the Company cedes a portion of its working
interest to a third-party are generally considered to be disposals of property, plant and equipment, potentially resulting
in a gain or loss on disposition.
Exchanges of property, plant and equipment are measured at fair value unless the exchange transaction lacks
commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable.
Unless the fair value of the asset received is more clearly evident, the cost of the acquired asset is measured at the
fair value of the asset given up. Where fair value is not used, the cost of the acquired asset is measured at the carrying
amount of the asset given up. The gain or loss on derecognition of the asset given up is recognized in profit or loss.
Property, plant and equipment is 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 on derecognition of the asset (calculated as the
difference between the net disposal proceeds and the carrying value of the asset) is included in profit or loss in the
period in which the item is derecognized.
iii) Depletion and depreciation
Development and production costs are accumulated on an area basis (“depletion units”). The net carrying value of each
depletion unit is depleted using the unit of production method by reference to the ratio of production in the year to the
related proved reserves, taking into account estimated future development costs necessary to bring those reserves into
production. Proved reserves and future development cost estimates are reviewed by independent reserve engineers
at least annually. Where significant components of development and production (“D&P”) assets have different useful
lives, they are accounted for and depreciated as separate items of property, plant and equipment.
iv) Major maintenance expenditures
The costs of major maintenance associated with turnaround activities that benefit future years of operations are
capitalized and depreciated over the period to the next major maintenance turnaround. All other maintenance costs are
expensed as incurred.
KELT EXPLORATION LTD.
49
ANNUAL REPORT
Impairment of assets
Non-financial assets
The carrying value of non-financial assets, including PP&E and E&E, is reviewed on a quarterly basis to determine
whether there is any indication of impairment. For the purpose of impairment testing, assets are grouped together into
the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash
inflows of other assets or CGUs. The recoverable amount of an asset or a CGU is the greater of its value in use and
its FVLCD. E&E assets are assessed for overall impairment at the operating segment level and individual E&E assets
are assessed for impairment prior to transferring to PP&E.
FVLCD is defined as the amount obtainable from the sale of an asset or cash generating unit in an arm’s length
transaction between knowledgeable, willing parties, less the costs of disposal. FVLCD is calculated by reference to the
after-tax future cash flows expected to be derived from production of proved plus probable reserves, less estimated
selling costs. The estimated after-tax future cash flows are discounted to their present value using a discount rate that
reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is
generally computed by reference to the present value of the future cash flows expected to be derived from production
of proved and probable reserves. The timing of when the global energy markets transition to a lower carbon-based
economy is highly uncertain and may impact the FVLCD.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable
amount. Impairment losses are recognized in the Consolidated Statement of Net Income and Comprehensive Net
Income. Impairment losses recognized in respect of CGUs are allocated to reduce the carrying amounts of the assets
in the CGU on a pro rata basis.
Financial assets
A financial asset measured at amortized cost is assessed at each reporting date using an expected credit loss (“ECL”)
model to determine whether it is impaired. The simplified approach is applied to calculating the ECLs, as prescribed by
IFRS 9, which permits the use of the lifetime expected loss provision for all trade receivables. A combination of historical
and forward looking information is used to determine the appropriate loss allowance provision. ECLs are a probability-
weighted estimate of all possible default events over the expected life of the financial asset which is based on credit
quality since initial recognition.
All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal can be related
objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized
cost, the reversal is recognized in profit or loss.
Provisions and contingencies
Provisions are recognized when there is a present obligation as a result of a past event, if it is probable that an outflow
of resources will be required and if a reliable estimate can be made of the amount of the obligation. Provisions are
measured based on the best estimate of discounted future cash outflows.
Decommissioning obligations
The Company’s activities give rise to dismantling, decommissioning and site remediation activities. An obligation is
accrued for the estimated cost of site restoration and the corresponding amount is included in the cost of the assets to
which the obligations relate. Decommissioning obligations are measured at the present value of the estimated
expenditures required to settle the present obligation at the Consolidated Statement of Financial Position date.
Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of
time and changes in the estimated future cash flows underlying the obligation, changes to the expected timing of site
restoration, as well as any changes in the risk-free discount rate and inflation rate. Increases in the provision due to the
passage of time are recognized as a financing expense in the Consolidated Statement of Net Income and
Comprehensive Net Income whereas increases/decreases due to changes in the estimated future cash flows are
capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision
to the extent the provision is established.
KELT EXPLORATION LTD.
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ANNUAL REPORT
Contingencies
Contingent liabilities are possible obligations whose existence will only be confirmed by future events not wholly within
the control of the Company. When a contingency is substantiated by confirming events, can be reliably measured and
will likely result in an economic outflow, a liability is recognized in the financial statements as the best estimate required
to settle the obligation. A contingent liability is disclosed where the existence of an obligation will only be confirmed by
future events, or where the amount of a present obligation cannot be measured reliably or will likely not result in an
economic outflow.
Contingent assets are only disclosed when the inflow of economic benefits is probable. When the economic benefit
becomes virtually certain, the asset is no longer contingent and is recognized in the financial statements.
Income taxes
Total income tax expense is composed of both current and deferred income taxes.
Current tax is the expected tax payable on taxable income for the year, using tax rates enacted or substantively enacted
at the reporting date, and any adjustment to tax payable in respect of previous years.
The liability method is used for accounting for income taxes. Under this method, deferred income tax is recognized on
the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for taxation purposes. Deferred taxes are allocated between income and equity depending on the
nature of the account balance or transaction that gives rise to the temporary difference.
Deferred tax liabilities are recognized for taxable temporary differences. Deferred tax assets are recognized for
deductible temporary differences, unused tax losses and unused tax credits only if it is probable that sufficient future
taxable income will be available to utilize those temporary differences and losses and at the time of the transaction,
does not give rise to equal taxable and deductible temporary differences. Such deferred tax liabilities and assets are
not recognized if the temporary difference arises from goodwill or from the initial recognition of an asset or liability in a
transaction which is not a business combination and, at the time of the transaction, affects neither accounting profit nor
taxable income. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences
when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. The
effect of a change in income tax rates on deferred tax assets and liabilities is recognized in the Consolidated Statement
of Net Income and Comprehensive Net Income in the period that the change occurs. Deferred tax assets and liabilities
are recorded on a non-discounted basis.
Revenue recognition
Revenue is recognized at a point in time when control of the product has been transferred to the customer and
performance obligations have been satisfied. This is generally met when the customer obtains legal title to the product
and physical delivery at a delivery point has taken place. Revenue is measured based on the consideration specified
in the contracts with the customers.
Arrangements are evaluated with third parties and partners to determine if a principal or agent relationship exists. In
making this evaluation, management considers if it maintains control of the product, which is indicated by the primary
responsibility for the delivery of the product, having the ability to establish prices or having inventory risk. If management
determines that it does not maintain control of the product, then revenue is recognized net of fees, if any, realized by
the party from the transaction.
Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.
Share based compensation
The Company has an Incentive Stock Option Plan and Restricted Share Unit Plan (collectively, the “Plans”). Pursuant
to the Plans, stock options and restricted share units (“RSUs”) may be granted to officers, directors, employees and
certain consultants, which call for settlement through the issuance of new common shares.
The fair value method is applied to the accounting for stock options, whereby each tranche in an award is valued
separately on the grant date using the Black-Scholes option pricing model. The fair value of RSUs is calculated based
KELT EXPLORATION LTD.
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ANNUAL REPORT
on the volume weighted average trading price over three trading days immediately prior to the date of grant. The total
fair value associated with stock options and RSUs is recognized over the service period using graded vesting, as share
based compensation expense with a corresponding increase to contributed surplus. An estimated forfeiture rate is
applied against the total fair value on the grant date and is adjusted to reflect the actual number of options that ultimately
vest each period. The consideration received on the exercise of stock options is recorded as an increase in
shareholders’ capital, together with the corresponding amounts previously recognized in contributed surplus.
Earnings per share amounts
Basic net income per common share is calculated by dividing net income for the period attributable to common
shareholders by the weighted average number of common shares outstanding during the period. Common shares
issued as part of the consideration transferred in a business combination or common control transaction are included
in the weighted average number of common shares starting from the acquisition date.
Diluted net income per common share is calculated giving effect to the potential dilution that would occur if all
outstanding “in-the-money” stock options were exercised or converted to common shares. The weighted average
number of common shares outstanding during the period is adjusted by the incremental number of shares calculated
in accordance with the treasury stock method. The treasury stock method assumes that the proceeds received from
the exercise of all potentially dilutive instruments are used to repurchase common shares at the volume weighted
average market price during the period.
4. PROPERTY ACQUISITIONS AND DISPOSITIONS
The following table summarizes the fair value of net assets acquired pursuant to property acquisitions during the year
ended December 31, 2024 and the prior year ended December 31, 2023:
Acquisitions
December 31, 2024 December 31, 2023
Exploration and evaluation assets
-
150
Property, plant and equipment
5,115
7,137
Decommissioning obligations
(299)
(265)
Total assets (liabilities) acquired
4,816
7,022
Consideration
Cash consideration
(4,173)
(102)
Non-cash consideration
(643)
(6,920)
Total consideration
(4,816)
(7,022)
Dispositions
December 31, 2024 December 31, 2023
Property, plant and equipment
(705)
(6,920)
Decommissioning obligations
62
-
Carrying value of net (assets) liabilities disposed
(643)
(6,920)
Consideration
Cash consideration, after closing adjustments
-
50
Non-cash consideration
643
6,920
Total consideration
643
6,970
Gain (loss) on sale of assets
-
50
In the fourth quarter of 2024, the Company closed a $3.5 million acquisition which included property plant and
equipment of $3.8 million and decommissioning obligations of $0.3 million. In the fourth quarter of 2023, the Company
closed a non-cash property plant and equipment swap transaction for $6.5 million.
52
5. EXPLORATION AND EVALUATION ASSETS
The following table reconciles movements of exploration and evaluation assets:
December 31, 2024
December 31, 2023
Balance, beginning of year
17,162
16,843
Additions
2,961
6,115
Property acquisitions [note 4]
-
150
Transfers to property, plant and equipment
(1,817)
(4,533)
Exploration and evaluation expense
(214)
(1,413)
Balance, end of year
18,092
17,162
The Company concluded that there are no indicators of potential impairment of its E&E assets at December 31, 2024.
6. PROPERTY, PLANT AND EQUIPMENT
Net carrying value
December 31, 2024
December 31, 2023
Development and production assets
1,358,231
1,164,248
Right-of-use assets
2,227
1,589
Corporate assets
847
575
Total net carrying value of property, plant and equipment
1,361,305
1,166,412
The following table reconciles movements of property, plant and equipment during the year:
Property, plant and equipment, at cost
D&P Assets
Corporate
Assets
ROU Assets
Total PP&E
Balance at December 31, 2022
1,764,843
7,153
3,581
1,775,577
Additions
275,724
755
1,036
277,515
Property acquisitions
7,137
-
-
7,137
Property dispositions
(6,920)
-
-
(6,920)
Change in decommissioning obligations
12,676
-
-
12,676
Transfers from E&E
4,533
-
-
4,533
Balance at December 31, 2023
2,057,993
7,908
4,617
2,070,518
Additions
324,190
1,140
1,967
327,297
Transfers from ROU assets
683
-
(683)
-
Property acquisitions
5,115
-
-
5,115
Property dispositions
(705)
-
-
(705)
Change in decommissioning obligations
2,777
-
-
2,777
Transfers from E&E
1,817
-
-
1,817
Balance at December 31, 2024
2,391,870
9,048
5,901
2,406,819
Accumulated depletion, depreciation and
impairment
D&P Assets
Corporate
Assets
ROU Assets
Total PP&E
Balance at December 31, 2022
769,379
6,522
2,392
778,293
Depletion and depreciation expense
124,366
811
636
125,813
Balance at December 31, 2023
893,745
7,333
3,028
904,106
Depletion and depreciation expense
139,894
868
732
141494
Dispositions
-
-
(86)
(86)
Balance at December 31, 2024
1,033,639
8,201
3,674
1,045,514
53
Future capital costs required to develop proved reserves in the amount of $1,839.9 million (December 31, 2023 –
$1,768.4 million) are included in the depletion calculation for development and production assets.
Based on its assessment as of December 31, 2024, the Company determined that there were no indicators of
impairment for the Alberta CGU and BC CGU and there are no previous impairments available for reversals.
7. BANK DEBT
At December 31, 2024, the Company has a $150.0 million credit facility from a syndicate of financial institutions. As at
December 31, 2024, $109.0 million was drawn under the Credit Facility, with outstanding letters of credit of $2.7 million.
The Credit Facility may be extended annually at Kelt’s option and subject to lender approval, with a 364 day term-out
period if not renewed.
Repayments of principal are not required provided that the borrowings under the facility do not exceed the authorized
borrowing amount. The credit facility is subject to semi-annual redeterminations on or before June 30 and November
30 of each year. There are no financial covenants under the Credit Facility and Kelt is in compliance with all other
covenants. Covenants include industry standard positive and negative covenants including reporting requirements,
permitted indebtedness, permitted risk management activities, permitted encumbrances and other standard business
operating covenants. Security is provided for by a demand debenture with a floating charge over all assets in the
amount of $800.0 million.
Interest is payable monthly for borrowings through direct advances. Interest rates fluctuate based on the prime rate
plus the applicable margin. The applicable margin ranges from 175 basis points to 375 basis points depending upon
the Net Debt to Cash Flow ratio of between less than 0.5 times and three times. Under the Credit Facility, borrowings
through the use of benchmark loans are also available. Stamping fees fluctuate based on a pricing grid and range from
2.75% to 4.75%, depending upon the Net Debt to Cash Flow ratio of between less than 0.5 times and three times.
8. DECOMMISSIONING OBLIGATIONS
Decommissioning obligations arise as a result of the Company’s net ownership interests in petroleum and natural gas
assets including well sites, processing facilities and infrastructure. The following table provides a reconciliation of the
carrying amount of the obligation associated with the retirement of oil and gas properties:
December 31, 2024 December 31, 2023
Balance, beginning of year
99,915
88,632
Obligations incurred
3,247
1,927
Obligations acquired
299
265
Obligations disposed
(62)
-
Obligations settled
(5,036)
(4,538)
Changes in discount rate
(6,954)
6,308
Revisions to estimates
6,484
4,441
Accretion expense
3,082
2,880
Balance, end of year
100,975
99,915
Decommissioning obligations – current
3,552
4,360
Decommissioning obligations – non-current
97,423
95,555
Key assumptions
Risk free rate
3.3%
3.0%
Inflation rate
2.0%
2.0%
The underlying cost estimates are derived from a combination of published industry benchmarks and site-specific
information. As at December 31, 2024 the undiscounted amount of the estimated cash flows required to settle the
obligation is $144.3 million (December 31, 2023 – $131.2 million) and is expected to be incurred over the next 50 years.
The undiscounted amount of the estimated future cash flows required to settle the obligation is $274.4 million at
54
December 31, 2024 (December 31, 2023 – $242.3 million). The inflated future cost estimates are discounted based on
a risk-free rate to determine the carrying amounts presented in the table above.
Accretion of the decommissioning obligation due to the passage of time is presented within financing expenses in the
Consolidated Statements of Net Income and Comprehensive Net Income (note 14).
9. LEASE LIABILITY
December 31, 2024 December 31, 2023
Balance, beginning of year
1,457
1,048
Additions
1,967
1,036
Disposals
(597)
-
Interest expense
167
96
Lease payments
(920)
(723)
Balance, end of year
2,074
1,457
Lease liability – current
1,655
1,125
Lease liability – non-current
419
332
Lease liabilities include commercial office space, field equipment and vehicle leases. The weighted average discount
rate for new leases entered in the period ended December 31, 2024 was 8.9% (December 31, 2023 – 10.0%). Payments
under short-term leases were $13.0 million for the year ended December 31, 2024 (December 31, 2023 – $12.9 million),
which primarily related to short term drilling rigs and field equipment rentals.
10. SHARE CAPITAL
Authorized
The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred
shares, each without par value.
Issued and outstanding
The following table summarizes the change in common shares issued and outstanding. There are no preferred shares
issued or outstanding as of December 31, 2024 (December 31, 2023 – nil).
Number of
Shares (000s)
Amount
($ thousands)
Balance at December 31, 2022
192,014
1,162,650
Issued on exercise of stock options
2,145
8,403
Transfer from contributed surplus on exercise of stock options
-
3,429
Released upon vesting of restricted share units
347
983
Balance at December 31, 2023
194,506
1,175,465
Issued on exercise of stock options
1,836
5,072
Transfer from contributed surplus on exercise of stock options
-
2,103
Released upon vesting of restricted share units
414
1,425
Balance at December 31, 2024
196,756
1,184,065
Stock options
The Incentive Stock Option Plan (the “Option Plan”) includes stock options which may be granted to directors, officers,
employees and certain consultants. The stock options granted pursuant to the Option Plan are to be settled through
the issuance of new common shares of the Company which vest in equal tranches over a three year period and have
a maximum term of five years to expiry.
55
The following table summarizes the change in stock options outstanding:
Number of
Options (000s)
Average Exercise
Price ($/share)
Balance at December 31, 2022
10,532
3.71
Granted
2,005
4.94
Exercised (1)
(2,145)
3.92
Forfeited
(428)
5.53
Expired
(267)
7.35
Balance at December 31, 2023
9,697
3.74
Granted
2,315
6.09
Exercised (1)
(1,836)
2.76
Forfeited
(205)
6.19
Balance at December 31, 2024
9,971
4.41
(1) The average share price on the date stock options were exercised during the year ended December 31, 2024 was $6.19 per common share ($6.54
per common share on average during the year ended December 31, 2023).
The total fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing
model with weighted average assumptions as follows:
Year ended December 31
2024
2023
Risk free interest rate
3.83%
3.32%
Expected life (years)
3.5
3.4
Expected volatility (1)
52.2%
65.8%
Expected dividend yield
0.0%
0.0%
Expected forfeiture rate
5.1%
5.1%
Fair value of options granted during the year ($/share)
2.51
2.36
(1) The expected volatility for options granted is estimated based on Kelt’s historical volatility over the expected life.
The following table summarizes information regarding stock options outstanding at December 31, 2024:
Range of
exercise prices
per common share
Number of
options
outstanding
(000s)
Weighted
average
remaining
term (years)
Weighted average
exercise price for
options outstanding
($/share)
Number of
options
exercisable
(000s)
Weighted average
exercise price for
options
exercisable
($/share)
$0.00 to $2.00
1,246
0.3
1.00
1,245
1.00
$2.01 to $4.00
1,833
1.2
2.74
1,833
2.74
$4.01 to $6.00
4,435
2.6
5.08
2,316
5.18
$6.01 to $8.00
2,457
4.2
6.19
117
6.74
Total
9,971
2.4
4.41
5,511
3.46
Restricted share units
The restricted share unit plan includes restricted share units (“RSUs”) that may be granted to officers, employees and
certain consultants. The RSUs granted under the RSU Plan are to be settled through the issuance of new common
shares upon vesting. RSUs vest in two equal tranches with the first half vesting after two years and the second half
after three years.
56
The following table summarizes the change in RSUs outstanding:
Number of
RSUs (000s)
Balance at December 31, 2022
873
Granted
1,284
Released upon vesting
(347)
Forfeited
(68)
Balance at December 31, 2023
1,742
Granted
558
Released upon vesting
(414)
Forfeited
(58)
Balance at December 31, 2024
1,828
The total fair value associated with stock options and RSUs is recognized over the service period using graded vesting,
resulting in share based compensation expense as follows:
Year ended December 31
2024
2023
Stock options
5,266
5,359
Restricted share units
3,580
2,503
Total share based compensation expense
8,846
7,862
Per share amounts
The table below summarizes the weighted average number of common shares outstanding used in the calculation of
basic and diluted net income per common share:
Year ended December 31
(000s of common shares)
2024
2023
Weighted average common shares outstanding, basic
195,719
193,116
Effect of dilution from stock options and RSUs
3,912
3,947
Weighted average common shares outstanding, diluted
199,631
197,063
The treasury stock method is used to determine the dilutive effect of stock options and RSUs. Under this method, only
“in-the-money” dilutive instruments impact the calculation of diluted net income per common share.
11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial instruments of the Company include cash and cash equivalents, accounts receivable and accrued sales,
deposits, accounts payable and accrued liabilities, derivative financial instruments, lease liabilities and bank debt. The
Company is exposed to financial risks arising from its financial assets and liabilities that include credit and liquidity risk
in addition to the market risks associated with commodity prices, and interest and foreign exchange rates. Net income,
cash flows and the fair value of financial assets and liabilities may fluctuate due to movement in market prices or as a
result of the Company’s exposure to credit and liquidity risks.
The objective of the Company’s risk management is to manage and control market risk exposures within acceptable
limits, while maximizing long-term returns. All such transactions are conducted in accordance with the Company’s risk
management policy that permits management to enter into commodity price agreements, provided that:
i) the contracts are not entered into for speculative purposes;
ii) the total notional quantity hedged, at the time of entering into the contract, does not exceed 65% of average
daily production; and
57
iii) the contracted term does not exceed 36 months.
Commodity price risk
Inherent to the business of producing oil and gas, cash provided by operating activities is subject to commodity price
risk. Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in commodity prices.
Commodity prices are impacted by economic events that dictate the levels of supply and demand as well as the
currency exchange rate relationship between the Canadian and U.S. dollar.
As of December 31, 2024, the following commodity price derivative financial instrument contracts are outstanding:
Crude oil derivative financial instrument swap contracts
Contract Type (1)
Notional Volume
Contract Price
Remaining Term
WTI fixed price swap
1,000 bbl/d
CAD$101.00/bbl
Jan 25 – Mar 25
WTI fixed price swap
1,500 bbl/d
USD$69.51/bbl
Jan 25 – Jun 25
WTI fixed price swap
1,000 bbl/d
USD$69.27/bbl
Jul 25 – Dec 25
WTI option (2)
500 bbl/d
Settles monthly if WTI price >
USD$70.50/bbl
Jan 25 – Dec 25
(1) West Texas Intermediate (“WTI”)
(2) The WTI option is settled monthly at USD$70.50/bbl if the average WTI price is above USD$70.50/bbl.
NGL derivative financial instrument swap contracts
Contract Type
Notional Volume
Contract Price
Remaining Term
OPIS-Conway propane fixed
price swap
250 bbl/d
USD$34.44/bbl
Jan 25 – Mar 25
OPIS-Conway propane basis
swap
250 bbl/d
Monthly OPIS-Conway basis
calculated at 43.5% of the floating
monthly WTI price
Jan 25 – Mar 25
Natural gas derivative financial instrument contracts
Contract Type (1)
Notional Volume
Contract Price $/MMBtu
Remaining Term
NYMEX-AECO 7A basis swap
10,000 MMBtu/d
NYMEX less USD$1.06
Jan 25 – Mar 25
NYMEX-AECO 5A basis swap
30,000 MMBtu/d
NYMEX less USD$1.10
Jan 25 – Mar 25
(1) NYMEX Henry Hub (“NYMEX”)
Natural gas embedded derivative
Contract Type
Notional Volume
Contract Price (1)
Remaining Term
Physical delivery contract
2,513 GJ/d
Floating AESO power pool price
(CAD/MWh) divided by the Fixed
Heat Rate of 17.95 GJ/MWh
Jan 25 – Dec 26
(1) Alberta Electric System Operator (“AESO”)
The Company has an outstanding two-year natural gas physical supply agreement, with a term from January 1, 2025
to December 31, 2026, to deliver 2,513 GJ/d of gas to the Nova Inventory Transfer point, which contains an embedded
derivative. Under the terms of the agreement, the Company receives a price equal to the Floating AESO Power Pool
Price divided by the fixed heat rate of 17.95 GJ/MWh.
The fair value of the embedded derivative is calculated by the difference between the forecasted Floating AESO Power
Pool Price divided by the fixed heat rate of 17.95 GJ/MWh, less the forecasted AECO 5A price, for the remaining term
of the contract.
Subsequent to December 31, 2024, the Company entered into the following commodity price derivative financial
instrument contracts:
58
Crude oil derivative financial instrument swap contracts
Contract Type (1)
Notional Volume
Contract Price
Remaining Term
WTI fixed price swap
500 bbl/d
USD$70.10/bbl
Jan 25 – Jun 25
WTI fixed price swap
1,000 bbl/d
USD$70.05/bbl
Jul 25 – Dec 25
WTI fixed price swap
1,000 bbl/d
CAD$106.46/bbl
Mar 25 – Jun 25
(1) West Texas Intermediate (“WTI”)
NGL derivative financial instrument swap contracts
Contract Type
Notional Volume
Contract Price
Remaining Term
OPIS-Conway propane fixed
price swap
250 bbl/d
USD$33.60/bbl
Apr 25 – Mar 26
OPIS-Conway propane basis
swap
250 bbl/d
Monthly OPIS-Conway basis
calculated at 46% of the floating
monthly WTI price
Apr 25 – Mar 26
Natural gas derivative financial instrument contracts
Contract Type (1)
Notional Volume
Contract Price
Remaining Term
NYMEX swap
20,000 MMBtu/d
CAD$6.405/MMBtu
Apr 25 – Dec 25
AECO 7A swap
5,000 GJ/d
CAD$1.85/GJ
Apr 25 – Jul 25
AECO 7A swap
5,000 GJ/d
CAD$2.005/GJ
May 25 – Jul 25
NYMEX costless collar
10,000 MMBtu/d
Floor: CAD$5.00/MMBtu
Ceiling: CAD$10.00/MMBtu
Apr 25 – Dec 25
(1) NYMEX Henry Hub (“NYMEX”)
Natural gas embedded derivative
Contract Type
Notional Volume
Contract Price (1)
Remaining Term
Physical delivery contract
2,475 GJ/d
Floating AESO power pool price
(CAD/MWh) divided by the Fixed
Heat Rate of 16.50 GJ/MWh
Jan 26 – Dec 26
(1) Alberta Electric System Operator (“AESO”)
Interest rate risk
The Company is exposed to interest rate risk as changes in market interest rates will impact the Credit Facility which
is subject to a floating interest rate. Based on bank debt balance as of December 31, 2024 of $109.0 million, an increase
(decrease) in the market rate of interest by 25 basis points would have an insignificant impact. As of December 31,
2024, there are no interest rate risk management contracts outstanding.
Foreign exchange risk
Kelt is exposed to fluctuations of the Canadian to U.S. dollar exchange rate given realized pricing is directly influenced
by U.S. dollar denominated benchmark pricing and from exposure from certain U.S. dollar denominated marketing
arrangements.
As at December 31, 2024, the following foreign exchange derivative financial instrument contracts are outstanding:
Foreign exchange derivative financial instrument swap contracts
Contract Type
Notional Volume
Contract/Exercise Price
Remaining Term
CAD/USD swap
USD$7.0 million/month
$1.3796 CAD/USD
Jan 25 – Jun 25
CAD/USD swap
USD$6.0 million/month
$1.3795 CAD/USD
Jul 25 – Dec 25
59
Foreign exchange derivative financial instrument option contracts
Contract Type
Notional Volume
Contract/Exercise Price
Exercise/
expiration date
Term if exercised
Sold call option
USD$2.0 million/month
$1.3820 CAD/USD
Dec 31, 2025
Jan 26 – Dec 26
Sold call option
USD$2.0 million/month
$1.3800 CAD/USD
Dec 31, 2025
Jan 26 – Dec 26
Gains and losses on derivative financial instrument contracts
The table below summarizes realized and unrealized gains (losses) on derivative financial instrument contracts:
Year ended December 31
2024
2023
Realized gain (loss)
Derivative financial instrument contracts
4,253
11,490
Natural gas embedded derivative
-
3,567
Total realized gain
4,253
15,057
Unrealized gain (loss)
Derivative financial instrument contracts
(5,920)
(15,416)
Natural gas embedded derivative
734
(8,389)
Total unrealized loss
(5,186)
(23,805)
Loss on derivative financial instruments
(933)
(8,748)
Fair value measurements
The Company classifies fair value measurements using a hierarchy that reflects the significance of the inputs used in
making the measurements. The Company maximizes the use of observable inputs when preparing calculations of fair
value, where possible. Assessment of the significance of a particular input to the fair value measurement requires
judgment and may affect the placement within the fair value hierarchy. The fair value hierarchy has the following levels:
Level 1 - Values are based on unadjusted quoted prices available in active markets for identical assets or liabilities
as of the reporting date.
Level 2 - Values 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. Prices in Level 2 are either directly
or indirectly observable as of the reporting date.
Level 3 - Values are based on prices or valuation techniques that are not based on observable market data.
The fair value of cash and cash equivalents, accounts receivable and accrued sales, deposits, accounts payable and
accrued liabilities approximate their carrying value due to the short term to maturity of these instruments. Bank debt
bears interest at a floating market rate and accordingly the fair market value of bank debt approximates the carrying
amount. Derivative financial instruments are classified as Level 2.
The fair value of financial assets and liabilities, excluding working capital, is attributable to the following fair value
hierarchies:
Carrying Value (“CV”)
Fair Value
Balance as at December 31, 2024
Gross
Netting (1)
Net CV
Level 1
Level 2
Level 3
Financial assets
Natural gas embedded derivative
734
-
734
-
734
-
Derivative financial instrument
5,975
-
5,975
-
5,975
-
Financial liabilities
Derivative financial instrument
7,936
-
7,936
-
7,936
-
60
Carrying Value (“CV”)
Fair Value
Balance as at December 31, 2023
Gross
Netting (1)
Net CV
Level 1
Level 2
Level 3
Financial assets
Derivative financial instrument
4,544
-
4,544
-
4,544
-
Financial liabilities
Derivative financial instrument
585
-
585
-
585
-
(1) Financial assets and liabilities are only offset if there is a legal right to offset and intends to settle on a net basis or settle the asset and liability
simultaneously. Kelt offsets derivative contracts assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same.
Credit risk
As at December 31, 2024, the carrying amount of cash and cash equivalents, accounts receivable and accrued sales,
deposits, and derivative financial instruments represent the Company’s maximum credit exposure. Potential losses are
mitigated from this credit exposure by holding cash and cash equivalents with a Canadian chartered bank, and
restricting derivative financial instrument transactions to counterparties that are all investment grade. The remaining
credit risk exposure arises primarily from receivables from oil and gas marketers and joint venture partners.
The composition of accounts receivable is set out in the following table:
December 31, 2024
December 31, 2023
Joint venture partners
5,893
3,803
Oil and gas marketers
45,708
42,950
GST input tax credits
4,036
2,399
Derivative financial instrument contracts
1,314
59
Other
3,638
3,951
Expected credit loss provision
(353)
(516)
Accounts receivable and accrued sales
60,236
52,646
During the year ended December 31, 2024, sales to two oil and gas marketers accounted for approximately 29% and
31%, of total sales. During the year ended December 31, 2023, sales to three oil and gas marketers accounted for
approximately 10%, 24%, and 42% of total sales. Credit risk from oil and gas marketers is mitigated through transacting
with investment grade rating counterparties in the majority of its oil and gas marketing transactions.
The oil and gas industry has a pre-arranged monthly clearing day for payment of revenues from all buyers of oil and
natural gas; this occurs on the 25th day following the month of sale. As a result, oil and gas marketers revenues are
current. All other accounts receivable are generally contractually due within 30-90 days.
The balance of accounts receivable outstanding for more than 90 days relates primarily to receivables from joint venture
partners. Credit risk related to joint venture receivables is mitigated by obtaining partner approval of significant capital
expenditures prior to expenditure and in certain circumstances may require cash deposits in advance of incurring
financial obligations on behalf of joint venture partners. The Company has the ability to withhold production from joint
venture partners in the event of non-payment or may be able to register security on the assets of joint venture partners.
As of December 31, 2024, the collection risk on outstanding accounts receivable balances is considered low as
approximately 1.0% of the accounts receivable balance are outstanding for more than 90 days (December 31, 2023 –
less than 1.0%).
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. Financial
obligations include accounts payable, derivative financial instruments, lease liabilities and bank debt. Liquidity risk is
managed through the budgeting process, which sets out expected debt levels, capital expenditures and funds from
operations. In addition, derivative financial instrument contracts may be used to protect future sales. The Board of
Directors approves an annual capital expenditure budget, which is regularly monitored and updated as necessary in
response to changing capital requirements and expected sales.
61
The capital intensive nature of Kelt’s operations may create a working capital deficiency position during periods with
high levels of capital investment. However, the Company targets to maintain sufficient unused bank credit lines or other
liquidity to satisfy such working capital deficiencies.
The table below outlines a contractual maturity analysis for Kelt’s financial liabilities as at December 31, 2024:
Within 1 Year
1 to 5 Years
More than 5 Years
Total
Accounts payable and accrued liabilities
80,463
-
-
80,463
Derivative financial instruments
7,936
-
-
7,936
Lease liability
1,655
419
-
2,074
Bank debt and estimated interest (1)
6,758
108,993
-
115,751
Total
96,812
109,412
-
206,224
(1) Estimated interest for future years related to the Credit Facility was calculated using the weighted average interest rate of 6.2% for the year ended
December 31, 2024, applied to the principal balance outstanding as at that date.
Capital Management
The Company’s capital structure is comprised of shareholders’ capital, bank debt and working capital. The Company’s
objective when managing its capital structure is to maintain financial flexibility in order to meet financial obligations, as
well as finance future capital expenditures relating to exploration, development and acquisition activities.
The Company may increase or decrease capital expenditures including acquisitions and dispositions, issue new
shares, issue new debt or repay existing debt, if any, according to market conditions in order to maintain its financial
flexibility.
Adjusted funds from operations
Management considers adjusted funds from operations as a key capital management measure that demonstrates the
Company’s ability to meet its financial obligations and cash flow available to fund its capital program. Adjusted funds
from operations are not a standardized measure and therefore may not be comparable with the calculation of similar
measures by other entities.
Adjusted funds from operations are calculated as follows:
Year ended December 31
2024
2023
Cash provided by operating activities
209,145
283,224
Change in non-cash working capital
7,797
(11,562)
Settlement of decommissioning obligations
5,036
4,538
Adjusted funds from operations
221,978
276,200
Net debt and net debt to adjusted funds from operations ratio
Management considers net debt and a net debt to adjusted funds from operations ratio as key capital management
measures to assess the Company’s liquidity at a point in time and to monitor its capital structure and short-term
financing requirements. The Company targets a net debt to adjusted funds from operations ratio of less than 2.0 times.
Net debt and a net debt to adjusted funds from operations ratio are not standardized measures and therefore may not
be comparable with the calculation of similar measures by other entities.
62
Net debt and net debt to adjusted funds from operations ratio are calculated as follows:
December 31, 2024
December 31, 2023
Bank debt
108,993
-
Accounts payable and accrued liabilities
80,463
85,171
Cash and cash equivalents
(228)
(14,340)
Accounts receivable and accrued sales
(60,236)
(52,646)
Prepaid expenses and deposits
(4,109)
(5,188)
Net debt
124,883
12,997
Adjusted funds from operations
221,978
276,200
Net debt to adjusted funds from operations ratio
0.6
0.0
As described in note 7, there are no financial covenants under the Credit Facility agreement and Kelt is in compliance
with all other covenants.
12. INCOME TAXES
Kelt was not required to pay income taxes in the current or prior year. Tax pools and losses available to reduce taxable
income as of December 31, 2024 are estimated to be approximately $896.7 million (December 31, 2023 – $780.4
million).
The following table reconciles income taxes calculated at the weighted average Canadian statutory rate with the actual
provision for deferred income taxes per the Consolidated Statement of Net Income and Comprehensive Net Income:
Year ended December 31
2024
2023
Net income before income taxes
63,156
114,477
Canadian statutory tax rate
23.0%
23.3%
Expected income tax expense
14,535
26,673
Increase resulting from:
Non-deductible expenses (1)
2,048
1,830
Valuation allowance (2)
1,150
-
Deferred income tax expense
17,733
28,503
(1) Non-deductible expenses primarily include share based compensation.
(2) The valuation allowance is a result of a financial statement write-off of an investment in securities of a third-party company.
The Canadian statutory tax rate per the rate reconciliation above represents the weighted average combined federal
and provincial corporate tax rate. The federal corporate tax rate is 15.0% and the annual average provincial tax rate in
Alberta and British Columbia is 8.0% and 12.0% respectively.
The movement in deferred income tax assets and liabilities, without taking into consideration the offsetting balances
within the same tax jurisdiction are as follows:
Deferred income tax asset (liability)
Balance at
December 31, 2023
Recognized in
profit and CI(1)
Recognized in
balance sheet
Balance at
December 31, 2024
Derivative financial instruments
(911)
1,193
-
282
PP&E and E&E
(152,736)
(24,965)
-
(177,701)
Decommissioning obligations
23,204
248
-
23,452
Lease liability
286
186
-
472
Non-capital losses (2)
60,656
5,605
-
66,261
Net deferred tax liability
(69,501)
(17,733)
-
(87,234)
63
Deferred income tax asset (liability)
Balance at
December 31, 2022
Recognized in
profit and CI(1)
Recognized in
balance sheet
Balance at
December 31, 2023
Derivative financial instruments
(6,386)
5,475
-
(911)
PP&E and E&E
(122,738)
(29,998)
-
(152,736)
Decommissioning obligations
20,586
2,618
-
23,204
Lease liability
194
92
-
286
Non-capital losses (2)
67,346
(6,690)
-
60,656
Net deferred tax liability
(40,998)
(28,503)
-
(69,501)
(1) Comprehensive income has been abbreviated as “CI”.
(2) The Company’s non-capital losses expire in years 2033 to 2043.
The amount and timing of reversals of temporary differences will be dependent upon a number of factors, including
future capital expenditures and future operating results.
13. PETROLEUM AND NATURAL GAS SALES
Kelt sells its oil, natural gas, and NGLs production under variable price contracts. The transaction price is based on a
benchmark commodity price, adjusted for quality, location or other factors, whereby each component of the pricing
formula (apart from the benchmark commodity price) can be either fixed or variable, depending on the contract terms.
Sales are typically collected on the 25th day of the month following the prior month’s production, with sales being
recorded once the product is delivered to a contractually agreed upon delivery point.
Kelt generates oil treating, gas processing, and other services income from fees charged to third parties provided at
facilities where Kelt has an ownership interest. Marketing revenue is generated from the sales of third-party volumes
related to its oil blending and natural gas operations, with the production being sold under the same terms as the
variable price contracts discussed above.
Kelt sells some of its natural gas outside of Alberta and British Columbia where title transfer occurs prior to the market
location where the benchmark commodity price is determined. For the year ended December 31, 2024, the
transportation costs that occurred after title transfer takes place, and which is included in gas production sales, was
$15.0 million (December 31, 2023 – $13.3 million).
The following table presents Kelt’s production disaggregated by sales source:
December 31, 2024
December 31, 2023
Oil production
296,999
283,892
Oil treating and other
921
975
NGLs production
63,970
67,598
Gas production
87,425
122,978
Gas processing and other
2,544
3,321
Marketing revenue
16,573
16,816
Total petroleum and natural gas sales
468,432
495,580
Included in accounts receivable at December 31, 2024 is $45.7 million (December 31, 2023 - $43.0 million) of accrued
oil and gas sales related to Kelt’s December 2024 oil and gas production.
14. FINANCING EXPENSES
Year ended December 31
2024
2023
Total interest expense
3,674
1,310
Accretion of decommissioning obligations [note 8]
3,082
2,880
Total financing expense
6,756
4,190
64
15. COMMITMENTS
As of December 31, 2024, the Company is committed to future payments under the following agreements:
2025
2026
2027
2028
2029
Thereafter
Firm processing commitments
51,990
72,132
72,240
74,713
73,606
406,080
Firm transportation commitments
42,363
43,935
39,001
37,751
34,018
123,762
Total annual commitments
94,353
116,067
111,241
112,464
107,624
529,842
16. GENERAL AND ADMINISTRATIVE (“G&A”) EXPENSES
The following table summarizes significant components of G&A expenses:
Year ended December 31
2024
2023
Salaries and benefits (1)
14,855
13,349
Other G&A expenses
6,250
5,292
G&A expenses before recoveries
21,105
18,641
Overhead recoveries
(8,833)
(8,257)
G&A expense
12,272
10,384
(1) Refer to additional information regarding salaries and benefits paid to key management personnel in note 18 of these financial statements.
17. SUPPLEMENTAL CASH FLOW INFORMATION
Year ended December 31
Changes in non-cash working capital
2024
2023
Accounts receivable and accrued sales
(7,590)
28,429
Prepaid expenses and deposits
1,079
(1,589)
Accounts payable and accrued liabilities
(4,708)
1,883
Change in non-cash working capital
(11,219)
28,723
Relating to:
Operating activities
(7,797)
11,562
Investing activities
(3,422)
17,161
Change in non-cash working capital
(11,219)
28,723
During the reporting period, the following cash outlays were made in respect of interest and taxes:
Year ended December 31
Cash outlays in respect of interest and taxes
2024
2023
Interest and standby fees on bank debt
3,070
1,069
Taxes (1)
-
-
(1) Kelt was not required to pay cash income taxes as there were sufficient income tax deductions available to shelter taxable income (note 12).
18. RELATED PARTY TRANSACTIONS
The Company has engaged a law firm where the corporate secretary of Kelt is a partner and has engaged the services
of a registrar and transfer agent where an officer of Kelt is a director of the company. During the year ended December
31, 2024, the Company incurred $0.4 million (December 31, 2023 – $0.4 million) in disbursements to related parties.
Key management personnel are those persons having authority and responsibility for planning, directing and controlling
the activities of the Company. The following table summarizes compensation paid or payable to officers and directors
of the Company:
65
Year ended December 31
2024
2023
Salaries, bonuses and other benefits
3,509
3,250
Share based compensation
3,870
4,056
Total compensation
7,379
7,306
During the year ended December 31, 2024, key management personnel were granted 935,000 stock options with an
exercise price of $6.06 per share and 173,000 RSUs. During the year ended December 31, 2023, key management
personnel were granted 621,000 stock options with an exercise price of $4.56 per share and 529,000 RSUs.
19. SUBSEQUENT EVENT
In 2025, the government of the United States of America has announced tariffs on goods imported from Canada,
including a 10% tariff on Canadian energy imports. These tariffs and the Canadian government’s response to them
could adversely affect market prices for crude oil and natural gas or demand for the Company’s Canadian production
in addition to the cost of goods imported directly or indirectly from the U.S. The impact of these tariffs on the Company’s
financial results cannot be quantified at this time.
66
ABBREVIATIONS
A&D
Acquisitions and dispositions
NGX
Natural Gas Exchange Inc. (Canada)
AECO
Alberta Energy Company “C” Meter Station of the
NOVA Pipeline System
NGTL
Nova Gas Transmission Line
NIT
NOVA Inventory Transfer (“AB-NIT”), being the reference
price at the AECO Hub
AT
After income taxes
bbls
barrels
NYMEX
New York Mercantile Exchange
bbls/d
barrels per day
Oil
Oil includes crude oil and field condensate
bcf
billion cubic feet
OPEC+
The Organization of Petroleum Exporting Countries along
with 10 additional oil-producing countries
BOE
barrels of oil equivalent
BOE/d
barrels of oil equivalent per day
P&NG
Petroleum and Natural Gas
BT
Before income taxes
Q1
First quarter ended March 31st
CA$/CAD
Canadian Dollar
Q2
Second quarter ended June 30th
Dawn
Gas traded at Union Gas' Dawn Hub in Dawn
Township, Ontario
Q3
Third quarter ended September 30th
Q4
Fourth quarter ended December 31st
E&E
Exploration and Evaluation
SBC
Share Based Compensation
FDC
Future Development Capital
SEDAR+
System for Electronic Document Analysis and Retrieval
G&A
General and Administration
Station 2
Spectra Energy receipt location
GJ
gigajoules
TSX
Toronto Stock Exchange
LNG
Liquefied Natural Gas
US$/USD
United States dollar
Mbbls
thousand barrels
WTI
West Texas Intermediate
MBOE
thousand barrels of oil equivalent
YTD
Year to date
Mcf
thousand cubic feet
1P
Proved reserves
MD&A
Management’s Discussion and Analysis
2P
Proved plus probable reserves
MMBtu
million British Thermal Units
IP30
the daily average post cleanup production rate (for each
well), measured at the wellhead over 720 producing hours,
excluding hours when the well did not produce continuously.
MMcf
million cubic feet
MMcf/d
million cubic feet per day
MSW
Mountain sweet blend crude oil
IP365
the daily average post cleanup production rate (for each
well), measured at the wellhead over 8,760 producing hours,
excluding hours when the well did not produce.
NGLs
Natural Gas Liquids
CONVERSION OF UNITS
Imperial = Metric
1 Mcf = 28.2 cubic metres
Natural gas is equated to oil on the basis
of 6 Mcf = 1 BOE
1 acre = 0.4 hectares
0.035 Mcf = 1 cubic metre
2.5 acres = 1 hectare
1 mile = 1.61 kilometres
Sulphur is equated to gas on the basis of
1LT = 10 Mcf (1 BOE = 0.6 LT)
1 bbl = 0.159 cubic metres
0.62 miles = 1 kilometre
6.29 bbls = 1 cubic metre
1 MMBtu = 1.054 GJ
1 foot = 0.3048 metres
0.949 MMBtu = 1 GJ
3.281 feet = 1 metre
67
CORPORATE INFORMATION
BOARD OF DIRECTORS
William C. Guinan 8, 9
Board Chair, Independent
Jennifer Haskey 2, 6
Director, Independent
Michael R. Shea 5, 7, 8
Director, Independent
Neil G. Sinclair 1, 9, 10
Director, Independent
Janet E. Vellutini 3, 6, 7
Director, Independent
David J. Wilson 4, 10
President & Chief Executive Officer,
Kelt Exploration Ltd.
1 chair, audit committee
2 chair, reserves committee
3 chair, compensation and corporate governance committee
4 chair, health, safety, environment and sustainability committee
5 chair, nominating committee
6 member, audit committee
7 member, reserves committee
8 member, compensation and corporate governance committee
9 member, health, safety and environment and sustainability committee
10 member, nominating committee
HEAD OFFICE
Suite 300, East Tower, 311 Sixth Avenue S.W.
Calgary, Alberta T2P 3H2
Phone: 403.294.0154
Fax: 403.291.0155
www.keltexploration.com
REGISTRAR AND TRANSFER AGENT
Odyssey Trust Company
350-300 5th Avenue S.W.
Calgary, Alberta T2P 3C4
LEGAL COUNSEL
Borden Ladner Gervais LLP
Centennial Place, East Tower,
Suite 1900, 520 Fourth Avenue S.W.
Calgary, Alberta T2P 0R3
OFFICERS
David J. Wilson
President & Chief Executive Officer
Sadiq H. Lalani
Vice President & Chief Financial Officer
Douglas J. Errico
Senior Vice President, Land and Corporate
Development
Alan G. Franks
Vice President, Production
Bruce D. Gigg
Vice President, Engineering
David A. Gillis
Vice President, Finance
Douglas O. MacArthur
Vice President, Operations
Patrick W.G. Miles
Vice President, Exploration
Louise K. Lee
Corporate Secretary
AUDITORS
PricewaterhouseCoopers LLP
Suite 3100, 111 Fifth Avenue S.W.
Calgary, Alberta T2P 5L3
EVALUATION ENGINEERS
McDaniel & Associates Consultants Ltd
2000, 525 8th Ave SW
Calgary, Alberta T2P 1G1
STOCK EXCHANGE LISTING
Toronto Stock Exchange
Common shares “KEL”
68
SUITE 300, EAST TOWER
311 SIXTH AVENUE SOUTH WEST
CALGARY, ALBERTA T2P 3H2