Kiwetinohk reports year-end 2024 results and reserves report
CALGARY, AB, March 5, 2025 /CNW/ - Kiwetinohk Energy Corp. (TSX: KEC) (Kiwetinohk or the Company) today reported its fourth quarter 2024 financial and operational results and updated reserve report. As companion documents to this news release, please review the Company's year-end 2024 management discussion and analysis (MD&A), consolidated financial statements and annual information form (available on kiwetinohk.com or www.sedarplus.ca) for additional details.
"I am extremely pleased with the team's performance throughout 2024. In Upstream, we delivered strong financial and operational results, meeting or exceeding our annual guidance expectations. In Power, we successfully positioned our development projects for sale or third-party financing and completed our first project sale shortly after year-end," said Pat Carlson, Chief Executive Officer.
"In Upstream, our success in 2024 is highlighted by a 19% annual production increase to 26,875 boe/d, the largest capital program in our history, and a 10% growth in total proved plus probable (2P) reserves, capable of sustaining current production for nearly 25 years. We also achieved a 17% reduction in per barrel annual operating costs while growing both production and reserves. Our annual adjusted operating netback of $31.62/boe remains strong and consistent, averaging $30.52/boe over the last eight quarters. Our asset continues to deliver top-tier production rates in the Duvernay, while our underdeveloped Simonette Montney resource has shown strong potential, now representing approximately 14% of our total 2P reserves.
"In Power, we continued to focus on the sale and/or financing efforts for the projects within our development portfolio. This resulted in the successful sale of our Opal gas-fired power project which closed in the first quarter of 2025.
"Recent transactions involving comparable assets, along with our reserve value, projected cash flow, and current trading multiple compared to our peers, suggest to us that our assets could be very attractive to buyers at a price well in excess our current market value. While we have a strong foundation of high-quality producing assets, we also have numerous value-enhancing investment opportunities in both our oil and gas and power businesses—opportunities that exceed our available funding capacity. One of the most straightforward ways to address this challenge is to explore the sale of all or part of one or both businesses. To ensure a thorough evaluation of all potential alternatives, we are considering engaging advisors to support this process. Any alternatives pursued as a result of such process could take anywhere from several quarters to a year or two to complete. In the meantime, we intend to continue to profitably grow our upstream business and opportunistically sell or otherwise monetize our power development projects."
Financial and operating results
For the three months ended |
For the year ended December 31, |
|||
2024 |
2023 |
2024 |
2023 |
|
Production |
||||
Oil & condensate (bbl/d) |
8,627 |
8,407 |
8,396 |
7,183 |
NGLs (bbl/d) |
4,132 |
3,507 |
3,936 |
2,769 |
Natural gas (Mcf/d) |
89,385 |
76,756 |
87,260 |
75,810 |
Total (boe/d) |
27,657 |
24,707 |
26,875 |
22,587 |
Oil and condensate % of production |
31 % |
34 % |
31 % |
32 % |
NGL % of production |
15 % |
14 % |
15 % |
12 % |
Natural gas % of production |
54 % |
52 % |
54 % |
56 % |
Realized prices |
||||
Oil & condensate ($/bbl) |
95.38 |
95.66 |
95.76 |
96.90 |
NGLs ($/bbl) |
44.96 |
51.44 |
43.86 |
53.07 |
Natural gas ($/Mcf) |
3.39 |
3.32 |
3.04 |
3.76 |
Total ($/boe) |
47.44 |
50.17 |
46.22 |
49.95 |
Royalty expense ($/boe) |
(3.11) |
(4.84) |
(3.53) |
(4.72) |
Operating expenses ($/boe) |
(7.74) |
(8.55) |
(7.04) |
(8.52) |
Transportation expenses ($/boe) |
(5.21) |
(5.49) |
(5.44) |
(5.61) |
Operating netback 1 ($/boe) |
31.38 |
31.29 |
30.21 |
31.10 |
Realized (loss) gain on risk management ($/boe) 2 |
(0.18) |
0.23 |
0.64 |
1.50 |
Realized gain (loss) on risk management - purchases ($/boe) 2 |
0.11 |
1.20 |
0.31 |
1.69 |
Net commodity sales from purchases (loss) ($/boe) 1 |
0.87 |
(0.51) |
0.46 |
(0.80) |
Adjusted operating netback 1 |
32.18 |
32.21 |
31.62 |
33.49 |
Financial results ($000s, except per share amounts) |
||||
Commodity sales from production |
120,721 |
114,038 |
454,598 |
411,826 |
Net commodity sales from purchases (loss) 1 |
2,239 |
(1,152) |
4,519 |
(6,642) |
Cash flow from operating activities |
59,921 |
58,946 |
263,203 |
240,760 |
Adjusted funds flow from operations 1 |
71,708 |
63,697 |
272,115 |
241,311 |
Per share basic |
1.64 |
1.46 |
6.23 |
5.49 |
Per share diluted |
1.61 |
1.44 |
6.11 |
5.43 |
Net debt to annualized adjusted funds flow from operations 1 |
1.00 |
0.77 |
1.00 |
0.77 |
Free funds flow deficiency from operations (excluding acquisitions/dispositions) 1 |
(27,767) |
(12,713) |
(64,632) |
(65,674) |
Net (loss) income |
(16,024) |
48,302 |
1,065 |
111,896 |
Per share basic |
(0.37) |
1.11 |
0.02 |
2.54 |
Per share diluted |
(0.37) |
1.09 |
0.02 |
2.52 |
Capital expenditures prior to acquisitions (dispositions) 1 |
99,475 |
76,410 |
336,747 |
306,985 |
Net acquisitions (dispositions) |
— |
(18,000) |
(318) |
(19,995) |
Capital expenditures and net acquisitions (dispositions) 1 |
99,475 |
58,410 |
336,429 |
286,990 |
1 – Non-GAAP and other financial measures that do not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. See Non-GAAP and Other Financial Measures section herein. |
2 – Realized (loss) gain on risk management contracts includes settlement of financial hedges on production and foreign exchange, with gain (loss) on contracts associated with purchases presented separately. |
3 – Oil and natural gas reserves are as determined by the Company's independent qualified reserve evaluator with an effective date of December 31 for the years shown in accordance with the Canadian Oil and Gas Evaluation Handbook and are shown as gross working interest reserves before royalties. |
2024 |
2023 |
|
Balance sheet ($000s, except share amounts) |
||
Total assets |
1,215,575 |
1,085,615 |
Long-term liabilities |
388,452 |
305,735 |
Net debt 1 |
272,764 |
186,523 |
Adjusted working capital (deficit) surplus 1 |
(22,862) |
7,565 |
Weighted average shares outstanding |
||
Basic |
43,760,116 |
43,971,108 |
Diluted |
44,547,688 |
44,467,348 |
Shares outstanding end of period |
43,781,748 |
43,662,644 |
Return on average capital employed ("ROACE") 1 |
3 % |
21 % |
Reserves |
||
Proved reserves (MMboe) 3 |
130.7 |
123.2 |
Proved reserves per share (boe) 3 |
3.0 |
2.8 |
Proved plus probable reserves (MMboe) 3 |
246.4 |
224.5 |
Proved plus probable reserves per share (boe) 3 |
5.6 |
5.1 |
1 – Non-GAAP and other financial measures that do not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. See Non-GAAP and Other Financial Measures section herein. |
2 – Realized (loss) gain on risk management contracts includes settlement of financial hedges on production and foreign exchange, with gain (loss) on contracts associated with purchases presented separately. |
3 – Oil and natural gas reserves are as determined by the Company's independent qualified reserve evaluator with an effective date of December 31 for the years shown in accordance with the Canadian Oil and Gas Evaluation Handbook and are shown as gross working interest reserves before royalties. |
Fourth Quarter and Annual Highlights
- Annual production of 26,875 boe/d, fourth quarter production of 27,657 boe/d, and 2024 exit rates >30,000 boe/d (54% natural gas + 46% condensate and NGLs). Production growth continued into January with new production taking monthly average production to just under 32,500 boe/d.
- Four new Duvernay wells and one Simonette Montney well brought on stream in the fourth quarter, with one additional well brought on stream early in January 2025.
Average peak 30-day production rates from new wells are summarized below:
Pad |
On-stream |
# wells |
Natural gas + (MMcf/d) |
Condensate (bbl/d) |
Average production (boe/d) |
% Condensate |
8-23 (Simonette) |
November |
2 Duvernay |
10.0 |
1,200 |
2,860 |
42 % |
8-23 (Simonette) |
November |
1 Montney |
1.2 |
450 |
650 |
69 % |
9-11 (Simonette) |
December1 |
3 Duvernay |
7.5 |
1,600 |
2,850 |
56 % |
____________________________ |
1 Two wells were brought on-stream in December 2024, with the third well on the pad brought on-stream in January 2025. |
The Company more recently brought two Duvernay wells and one Simonette Montney well at the 14-29 pad on-stream late in February 2025. The wells are still in the initial flow back stage, performing as expected.
- Strong operating netback2 of $31.38/boe drove adjusted funds flow from operations2 of $71.7 million. On an annual basis, the Company achieved an operating netback of $30.21/boe which led to record annual adjusted funds flow from operations2 of $272.1 million or $6.23/share.
- Annual operating costs of $7.04/boe were ahead of plan, declining 17% year-over-year. In 2024, annual operating costs on a per barrel basis reached their lowest levels since Kiwetinohk acquired its primary assets, declining 27% from the time the Company went public in 2022, demonstrating fixed plant cost economies of scale and the value of owned and operated infrastructure as the Company moves towards filling its plant capacity.
- Annual transportation costs of $5.44/boe were ahead of plan during 2024, with approximately 95% of natural gas production delivered to the Chicago market through the Alliance pipeline system. This provided access to premium pricing with the Chicago City Gate daily index averaging approximately double AECO 5A pricing in Alberta during the year.
- Capital expenditures (before acquisitions/dispositions)2 of $99.5 million brought full year expenditures to $336.7 million. This represents the largest annual capital program in the Company's history and it was executed within 1% of the midpoint of annual guidance targets.
- Finished the year with a 1.00x net debt to annualized adjusted funds flow from operations ratio2. The Company expects to generate free cash flow and apply proceeds to repay debt during 2025 (see guidance update for current projected ratios of net debt to annualized adjusted funds flow from operations).
_____________________________ |
2 Non-GAAP measures that do not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Please refer to the section "Non-GAAP and other financial measures" herein for further information. |
Guidance update
Kiwetinohk has updated its sensitivity analysis for expected adjusted funds flow from operations and the projected net debt-to-adjusted funds flow from operations ratio. These updates reflect actual year-to-date realized commodity pricing, a stronger forward strip for natural gas, the anticipated impact of U.S. import tariffs on gas volumes sold via the Alliance Pipeline to Chicago (estimated at approximately $15–$25 million if they remain in place), the $21 million Opal disposition in February 2025, and an expected $8.4 million payment related to the Homestead Solar power development project.
Despite the potential impact of U.S. import tariffs, these revisions have resulted in increased expected adjusted funds flow from operations and lower projected net debt-to-adjusted funds flow from operations ratio sensitivities. This reflects the strength of Kiwetinohk's business, which benefits from strong production with low operating costs, high-liquids-content production, and critical access to the Chicago natural gas market for natural gas sales, which continues to offer premium pricing compared to Alberta.
All other financial and operational guidance remains as previously presented on December 16, 2024.
2025 Financial & Operational Guidance |
Current March 4, 2025 |
Previous December 16, 2024 |
|
2025 Adjusted Funds Flow from Operations commodity pricing sensitivity 1 |
|||
US$60/bbl WTI & US$3.50/MMBtu HH & $0.70 USD/CAD |
CAD$MM |
$335 - $375 |
$300 - $335 |
US$70/bbl WTI & US$5.00/MMBtu HH & $0.70 USD/CAD |
CAD$MM |
$405 - $450 |
$360 - $400 |
US$ WTI +/- $1.00/bbl 2 |
CAD$MM |
+/- $4.3 |
+/- $4.3 |
US$ Chicago +/- $0.10/MMBtu 2 |
CAD$MM |
+/- $4.7 |
+/- $4.7 |
CAD$ AECO 5A +/- $0.10/GJ 2 |
CAD$MM |
+/- $0.1 |
+/- $0.1 |
Exchange Rate (USD/CAD) +/- $0.01 2 |
CAD$MM |
+/- $3.6 |
+/- $3.6 |
2025 Net debt to Adjusted Funds Flow from Operations sensitivity 1 |
|||
US$60/bbl WTI & US$3.50/MMBtu HH & $0.70 USD/CAD |
X |
0.5x - 0.7x |
0.8x - 1.0x |
US$70/bbl WTI & US$5.00/MMBtu HH & $0.70 USD/CAD |
X |
0.3x - 0.4x |
0.5x - 0.6x |
1 – Non-GAAP and other financial measures that do not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Please refer to the section "Non-GAAP Measures" herein. |
2 – Assumes US$65/bbl WTI, US$3.25/mmbtu HH, US$2.60/mmbtu HH - AECO basis diff, 0.70 USD/CAD. |
A detailed breakdown of current full-year guidance, can be found in the MD&A for this quarter available on SEDAR+ at www.sedarplus.ca. The revised sensitivities incorporate updated information relevant to expectations for financial and operational results. This corporate guidance is based on commodity price assumptions and economic conditions and readers are cautioned that guidance estimates may fluctuate and are subject to numerous risks and uncertainties. Kiwetinohk will update guidance if and as required throughout the year.
2024 year-end reserves highlights
- Conversions to proved developed producing (PDP) replaced approximately 128% of 2024 production; total proved plus probable (2P) reserve replacement was 323%.
- 2P reserves grew by 10% or approximately 22.0 MMboe after annual production.
- 2P net present value (NPV10 BT) grew by 4% year over year to $2.9 billion.
- The 2024 Reserve Report demonstrates significant reserve value per share: PDP NPV10 (BT) $17.90/share; Total Proved (1P) NPV10 (BT) $38.09/share; and 2P NPV10 (BT) $65.34/share compared to a December 31, 2024 share price of $16.35.
- PDP reserve life index (RLI) of 4.3, 1P of 12.9 and 2P of 24.3 years.
- Finding and development costs (F&D) for undeveloped resources are $20.84/boe for 1P F&D (future development capital divided by proved undeveloped reserves) and $15.50/boe for 2P F&D (future development capital divided by total undeveloped reserves).
- Since listing as a public company in early 2022, 4-year finding, development and acquisition (FD&A) recycle ratios were 2.0x for PDP, 1.7x for 1P and 2.2x for 2P based on the four year average operating netback of $36.46/boe.
- The Company has now booked 31 of 158 potential inventory locations within the Simonette Montney formation, with booked reserves now representing ~14% of our total 2P reserves.
Reserves update
McDaniel & Associates conducted an independent reserves evaluation and prepared the Company's reserve report dated March 4, 2025 and effective December 31, 2024 in accordance with National Instrument 51-101 standards and the requirements of the Society of Petroleum Evaluation Engineers (SPEE) and the Canadian Oil and Gas Evaluation Handbook (COGEH).
The reserves evaluation was based on the average forecast pricing of McDaniel's, GLJ Petroleum Consultants and Sproule Associates Limited and foreign exchange rates at January 1, 2025 which is available on McDaniel's website at www.mcdan.com. Reserves included below are presented on a Company gross basis and reflect the Company's total working interest reserves before the deduction of any royalties and do not include any royalty interests payable to or by the Company.
Future development costs (FDC) reflect McDaniel's best estimate of the future cost to bring Kiwetinohk's proved and probable developed and undeveloped reserves on production. Actual costs may be greater than or less than the estimates contained in the McDaniel Report and referenced in this news release and FDC will be re-forecast on an annual basis to account for changes in development activities, new well design or performance, inflation expectations and various other estimates.
Additional details of Kiwetinohk's 2024 year end reserves can be found in the Company's AIF available on the Company website and on the Company's profile on SEDAR+ at www.sedarplus.ca.
The following reserve summary table details the Company's 2024 gross volumetric and valuation reserve results:
Tight oil |
Shale gas |
Natural gas liquids |
2024 Total |
2023 Total |
|
Proved producing |
691 |
147,892 |
18,663 |
44,003 |
41,222 |
Proved developed non-producing |
— |
5,316 |
578 |
1,464 |
54 |
Proved undeveloped |
— |
263,099 |
41,351 |
85,201 |
81,908 |
Total proved |
691 |
416,307 |
60,592 |
130,668 |
123,184 |
Probable |
148 |
378,270 |
52,512 |
115,705 |
101,271 |
Total proved plus probable |
839 |
794,577 |
113,104 |
246,373 |
224,455 |
Net present value before tax summary:
$ Thousands |
0 % |
5 % |
10 % |
15 % |
20 % |
Proved developed producing |
995,821 |
895,776 |
783,868 |
698,307 |
633,368 |
Proved developed non-producing |
24,335 |
20,379 |
17,142 |
14,604 |
12,613 |
Proved undeveloped |
1,852,467 |
1,242,569 |
866,522 |
621,467 |
454,148 |
Total proved |
2,872,623 |
2,158,724 |
1,667,532 |
1,334,378 |
1,100,129 |
Probable |
3,404,591 |
1,905,106 |
1,193,179 |
812,223 |
588,388 |
Total proved plus probable |
6,277,214 |
4,063,830 |
2,860,711 |
2,146,601 |
1,688,517 |
PDP value / share 1 |
$ 22.75 |
$ 20.46 |
$ 17.90 |
$ 15.95 |
$ 14.47 |
1P value / share 1 |
$ 65.61 |
$ 49.31 |
$ 38.09 |
$ 30.48 |
$ 25.13 |
2P value / share 1 |
$ 143.38 |
$ 92.82 |
$ 65.34 |
$ 49.03 |
$ 38.57 |
1 - based on 43,781,748 shares outstanding as of December 31, 2024 |
Future development costs ("FDC")
The following is McDaniel's estimate of FDC required to bring total proved and total proved plus probable reserves onto production:
Year |
Total proved |
Total proved plus |
2025 |
282.3 |
282.3 |
2026 |
326.5 |
326.5 |
2027 |
352.4 |
352.4 |
2028 |
381.5 |
381.5 |
2029 |
394.0 |
394.0 |
Thereafter |
39.2 |
1,211.8 |
Total FDC, Undiscounted |
1,775.9 |
2,948.5 |
Total FDC, Discounted at 10% |
1,369.2 |
1,987.3 |
1P/2P Future Undeveloped F&D Costs:
Proved Undeveloped |
1P |
2P |
|
FDC |
$MM |
1,776 |
2,948.5 |
Proved undeveloped reserves |
Mboe |
85,201 |
190,198 |
F&D |
$/boe |
$ 20.84 |
$ 15.50 |
Power development update
During 2024, the Company invested $7.1 million on its power development portfolio, including capitalized costs, project development expenses, and the Generating Unit Owner's Contribution (GUOC) payment made on the Opal project.
As previously announced, the Company has recently closed the sale of its proposed 101-MW Opal natural gas-fired power project for proceeds of $21 million. In addition, on February 28, 2025, the Homestead Solar project advanced to AESO Stage 5, thereby becoming fully permitted and licensed. This requires an $8.4 million Generating Unit Owner's Contribution payment to be made in March of 2025. The Company is pursuing a sale of Homestead and approved this payment in expectation of a future transaction.
Year-end conference call, 2024 ESG report and first quarter 2025 reporting date
Kiwetinohk management will host a conference call on March 6, 2025, at 8 AM MT (10 AM ET) to discuss results and answer questions. Participants can listen to the conference call by dialing 1-888-510-2154 (North America toll free) or 437-900-0527 (Toronto and area). A replay of the call will be available until March 13, 2025, at 1-888-660-6345 (North America toll free) or 646-517-4150 (Toronto and area) by using the code 65191.
Kiwetinohk plans to release its first quarter 2025 results and its report on 2024 environment, social and governance performance after TSX close on May 7, 2025.
About Kiwetinohk
Kiwetinohk produces natural gas, natural gas liquids, oil and condensate and is a developer of renewable and natural gas power projects, and early stage carbon capture and storage opportunities, in Alberta.
Kiwetinohk's common shares trade on the Toronto Stock Exchange under the symbol KEC. Additional details are available within the year-end documents available on Kiwetinohk's website at kiwetinohk.com and SEDAR+ at www.sedarplus.ca.
Oil and gas advisories
For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. The term barrel of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio for gas of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from an energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value.
This news release includes references to sales volumes of "crude oil" "oil and condensate", "NGLs" and "natural gas" and revenues therefrom. National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and separately from other NGLs since the price of condensate as compared to other NGLs is currently significantly higher, and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom. Crude oil therefore refers to light oil, medium oil, tight oil, and condensate. NGLs refers to ethane, propane, butane, and pentane combined. Natural gas refers to conventional natural gas and shale gas combined.
References to "initial wellhead rates", "initial results", "peak rates" and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter, and are therefore not indicative of long term performance or recovery. Investors are encouraged not to place reliance on such rates when assessing the Company's aggregate production.
This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. The metrics are F&D cost, FD&A cost, recycle ratio, reserves replacement ratio (excl A&D), and reserve life index. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon. Refer to the "Non-GAAP Financial Ratios" section of this news release for a description of the calculation and use of F&D cost, FD&A cost, recycle ratio.
F&D reserve replacement (excl A&D) is calculated by dividing: (i) the net changes to reserves in such reserves category from the prior period from extensions & improved recovery, technical revisions, economic factors, acquisitions, and dispositions, expressed in boe; by (ii) the actual annual production for the year. Reserves replacement ratio is a measure commonly used by management and investors to assess the rate at which reserves depleted by production are being replaced.
Reserve life index is calculated by dividing: (i) the reserves by category, expressed in boe; by (ii) the annualized Q4 average production rate, expressed in boe/d.
Reserves Data
Reserves data set forth in this news release is based upon an evaluation of the Company's reserves prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") dated March 4, 2025 and effective December 31, 2024 (the "McDaniel Report"). The reserves referenced in this news release are gross reserves. The price forecast used in the McDaniel Report is the three consultant average forecast prices of McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited as of January 1, 2025 ("Jan 2025 Consultant Avg.") price forecast. The estimates of reserves contained in the McDaniel Report and referenced in this news release are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates contained in the McDaniel Report and referenced in this news release. There is no assurance that the forecast prices and costs assumptions used in the McDaniel Report will be attained, and variances could be material. Estimated future net revenue does not represent fair market value. Readers should refer to the Company's annual information form for the year ended December 31, 2024, available on Kiwetinohk's website at www.kiwetinohk.com and the Company's profile on SEDAR+ at www.sedarplus.ca, for a complete description of the McDaniel Report (including reserves by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil) and the material assumptions, limitations and risk factors pertaining thereto.
Forward looking information
Certain information set forth in this news release contains forward-looking information and statements including, without limitation, management's business strategy, management's assessment of future plans and operations. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "project", "potential", "may" or similar words suggesting future outcomes or statements regarding future performance and outlook. Readers are cautioned that assumptions used in the preparation of such information may prove to be incorrect. Events or circumstances may cause actual results to differ materially from those predicted as a result of numerous known and unknown risks, uncertainties and other factors, many of which are beyond the control of the Company.
In particular, this news release contains forward-looking statements pertaining to the following:
- drilling and completion activities on certain wells and pads and the expected timing for certain pads to be brought on-stream;
- the timing and release of the Company's 2024 environment, social and governance performance report;
- the potential sale of the Homestead Solar Project and the anticipated timing thereof;
- the Company's revised 2025 financial and operational guidance and adjustments to the previously communicated 2025 guidance, including operations sensitivities;
- expectations of continued premiums in the Chicago natural gas benchmark pricing when compared to Alberta markets;
- estimated impact of United States import tariffs;
- the Company's operational and financial strategies and plans;
- the Company's business strategies, objectives, focuses and goals and expected or targeted performance and results;
- the expectation of engagement of strategic advisors and the associated timeline of any process;
- the anticipated reserve life index of the Company's reserves;
- the ability to generate free cash flows and reduce debt levels in the future; and
- the timing of the release of the Company's first-quarter 2025 results.
Statements relating to reserves are also deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
In addition to other factors and assumptions that may be identified in this news release, assumptions have been made regarding, among other things:
- the Company's belief that development projects will create opportunities to provide reliable, dispatchable and affordable energy;
- the Company's ability to execute on its revised 2025 budget priorities;
- the timing and costs of the Company's capital projects, including drilling and completion of certain wells;
- the impact of the federal government's draft clean electricity regulations on the portfolio and uncertainties regarding same;
- the impact of the provincial government's restructured energy market on the portfolio and uncertainties regarding same;
- the timing and costs of the Company's capital projects, including drilling and completion of certain wells;
- the Company's ability to negotiate deal structures and terms on the Company's power projects;
- the impact of increasing competition;
- the general stability of the economic and political environment in which the Company operates;
- general business, economic and market conditions;
- the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner;
- future commodity and power prices;
- currency, royalty, exchange and interest rates;
- near and long-term impacts of tariffs or other changes in trade policies in North America, as well as globally;
- the regulatory framework regarding royalties, taxes, power, renewable and environmental matters in the jurisdictions in which the Company operates;
- the ability of the Company to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations;
- the ability of the Company to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;
- the impact of war, hostilities, civil insurrection, pandemics (including Covid-19), instability and political and economic conditions (including the ongoing Russian-Ukrainian conflict and conflict in the Middle East) on the Company;
- the ability of the Company to successfully market its products;
- the ability to fund power projects through third parties;
- expectations regarding access of oil and gas leases in light of caribou range planning; and
- the Company's operational success and results being consistent with current expectations.
Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions that have been used. Although the Company believes that the expectations reflected in such forward- looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements as the Company can give no assurance that such expectations will prove to be correct.
Forward-looking statements or information involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties include, among other things:
- those risks set out in the Annual Information Form (AIF) under "Risk Factors";
- the ability of management to execute its business plan;
- general economic and business conditions;
- the ability of the Company to proceed with the power generation projects as described, or at all;
- global economic, financial and political conditions, including the results of ongoing trade negotiations in North America, as well as globally;
- risks of war, hostilities, civil insurrection, pandemics (including Covid-19), instability and political and economic conditions (including the ongoing Russian-Ukrainian conflict and conflict in the Middle East) in or affecting jurisdictions in which the Company operates;
- the risks of the power and renewable industries;
- operational and construction risks associated with certain projects;
- the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;
- risks relating to regulatory approvals and financing;
- the ability to market in Alberta for power projects;
- uncertainty involving the forces that power certain renewable projects;
- the Company's ability to enter into or renew leases;
- potential delays or changes in plans with respect to power and solar projects or capital expenditures;
- risks associated with rising capital costs and timing of project completion;
- fluctuations in commodity and power prices, foreign currency exchange rates and interest rates;
- risks inherent in the Company's marketing operations, including credit risk;
- health, safety, environmental and construction risks;
- risks associated with existing and potential future lawsuits and regulatory actions against the Company;
- uncertainties as to the availability and cost of financing;
- the ability to secure adequate processing, transportation, fractionation and storage capacity on acceptable terms;
- processing, pipeline and fractionation infrastructure outages, disruptions and constraints;
- financial risks affecting the value of the Company's investments;
- risks related to the interpretation of, and/or potential claims made pursuant to, the Government of Canada amendments to the deceptive marketing practices provisions of the Competition Act (Canada) regarding greenwashing; and
- other risks and uncertainties described elsewhere in this document and in Kiwetinohk's other filings with Canadian securities authorities.
Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties.
The forward-looking statements and information contained in this news release speak only as of the date of this news release and the Company undertakes no obligation to publicly update or revise any forward-looking statements or information, except as expressly required by applicable securities laws.
Non-GAAP and other financial measures
This news release uses various specified financial measures including "non-GAAP financial measures", "non-GAAP financial ratios" and "capital management measures", as defined in National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure and explained in further detail below. These non-GAAP and other financial measures presented in this news release should not be considered in isolation or as a substitute for performance measures prepared in accordance with IFRS and should be read in conjunction with the Financial Statements and MD&A. Readers are cautioned that these non-GAAP measures do not have any standardized meanings and should not be used to make comparisons between Kiwetinohk and other companies without also taking into account any differences in the method by which the calculations are prepared.
Please refer to the Company's MD&A as at and for the year ended December 31, 2024, under the section "Non-GAAP and other financial measures" for a description of these measures, the reason for their use and a reconciliation to their closest GAAP measure where applicable. The Company's MD&A is available on Kiwetinohk's website at kiwetinohk.com or its SEDAR+ profile at www.sedarplus.ca.
Non-GAAP Financial Measures
Capital expenditures, capital expenditures and net acquisitions (dispositions), operating netback, adjusted operating netback, and net commodity sales from purchases (loss), are measures that are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other companies.
The most directly comparable GAAP measure to capital expenditures and capital expenditures and net acquisitions (dispositions) is cash flow used in investing activities. The most directly comparable GAAP measure to operating netback and adjusted operating netback is commodity sales from production. The most directly comparable GAAP measure to net commodity sales from purchases (loss) is commodity sales from purchases.
Capital Management Measures
Adjusted funds flow from operations, free funds flow (deficiency) from operations, adjusted working capital surplus (deficit), net debt, net debt to annualized adjusted funds flow from operations and net debt to adjusted funds flow from operations are capital management measures that may not be comparable to similar financial measures presented by other companies. These measures may include calculations that utilize non-GAAP financial measures and should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.
Capital expenditures, capital expenditures and net acquisitions, F&D cost, FD&A cost, and recycle ratio, each presented on a $/boe basis are non-GAAP ratios as they each have a non-GAAP financial measure as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other companies. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.
F&D costs are calculated by dividing: (i) capital expenditures, excluding power projects (a non-GAAP financial measure) for the applicable reserves category and period; by (ii) the net changes to reserves in such reserves category from the prior period from extensions & improved recovery, technical revisions, and economic factors, expressed in boe. F&D costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions.
FD&A costs are calculated by dividing: (i) capital expenditures and net acquisitions, excluding power acquisitions (a non-GAAP financial measure) for the applicable reserves category and period; by (ii) the net changes to reserves in such reserves category from the prior period from extensions & improved recovery, technical revisions, economic factors, acquisitions, and dispositions, expressed in boe. FD&A costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects, acquisitions net of dispositions, and reserve additions.
Recycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per boe for the period by the F&D costs or the FD&A costs for the period. Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production.
Readers should refer to the information under the heading "Statement of Reserves Data – Reserves Reconciliation" in the Company's Annual Information Forms ("AIF") for the year ended December 31, 2024, which is available on Kiwetinohk's website at www.kiwetinohk.com and SEDAR+ at www.sedarplus.ca, for a description of the net changes to reserves in each reserves category from the prior year.
Supplementary Financial Measures
This news release contains supplementary financial measures expressed as: (i) cash flow from operating activities, adjusted funds flow on a per share – basic and per share – diluted basis, (ii) realized prices, petroleum and natural gas sales, adjusted funds flow, revenue, royalties, operating expenses, transportation, realized loss on risk management, and net commodity sales from purchases on a $/bbl, $/Mcf or $/boe basis and (iii) royalty rate.
Cash flow from operating activities, adjusted funds flow and free cash flow on a per share – basic and diluted basis are calculated by dividing the cash flow from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average basic or diluted shares outstanding during the period determined under IFRS.
Metrics presented on a $/bbl, $/Mcf or $/boe basis are calculated by dividing the respective measure, as applicable, over the referenced period by the aggregate applicable units of production (bbl, Mcf or boe) during such period.
Royalty rate is calculated by dividing royalties by petroleum and natural gas sales less royalty and other revenue.
This news release also includes reference to net present value ("NPV 10"), which does not have a standardized meaning or a standard method of calculation, may not be comparable to similar measures used by other companies and should not be used to make such comparisons. This metric has been included to provide investors with an additional measure to evaluate the Company's performance. Future performance may not compare to the performance in previous periods, and therefore this metric should not be unduly relied upon. NPV 10 is the difference between the present value of cash inflows and the present value of cash outflows over a period of time at a 10% discount rate. Management uses this metric for its own performance measurements and to provide users with a measure to compare the Company's economic returns and operations over time. Readers are cautioned that the information provided by this metric, or that can be derived from this metric as presented in this news release, should not be relied upon for investment or other purposes.
Future oriented financial information
Financial outlook and future-oriented financial information referenced in this news release about prospective financial performance, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. These projections contain forward-looking statements and are based on a number of material assumptions and factors set out above and are provided to give the reader a better understanding of the potential future performance of the Company in certain areas. Actual results may differ significantly from the projections presented herein. These projections may also be considered to contain future oriented financial information or a financial outlook. The actual results of the Company's operations for any period will likely vary from the amounts set forth in these projections, and such variations may be material. See "Risk Factors" in the Company's AIF published on the Company's profile on SEDAR+ at www.sedarplus.ca for a further discussion of the risks that could cause actual results to vary. The future oriented financial information and financial outlooks contained in this news release have been approved by management as of the date of this news release. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein.
Abbreviations
$/bbl |
dollars per barrel |
$/boe |
dollars per barrel equivalent |
$/Mcf |
dollars per thousand cubic feet |
AESO |
Alberta Electric Systems Operator |
AIF |
Annual Information Form |
AUC |
Alberta Utilities Commission |
bbl/d |
barrels per day |
boe |
barrel of oil equivalent, including crude oil, condensate, natural gas liquids, and natural gas (converted on the basis of one boe per six Mcf of natural gas) |
Mboe |
thousand barrels of oil equivalent |
MMboe |
million barrels of oil equivalent |
boe/d |
barrel of oil equivalent per day |
DCET |
Drill, Complete, Equip and Tie-in |
FID |
Final Investment Decision |
Mcf |
thousand cubic feet |
Mcf/d |
thousand cubic standard feet per day |
MD&A |
Management Discussion & Analysis |
MMcf/d |
million cubic feet per day |
MW |
one million watts |
NGLs |
natural gas liquids, which includes butane, propane, and ethane |
For more information on Kiwetinohk, please contact:
Investor Relations
email: [email protected]
phone: (587) 392-4395
Pat Carlson, Chief Executive Officer
Jakub Brogowski, Chief Financial Officer
SOURCE Kiwetinohk Energy
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