Kiwetinohk provides fourth quarter 2023 financial and operational results and year-end reserves report

• Adjusted funds flow (AFF)¹ of $5.49/share
• Record annual production of 22,587 boe / day (27% increase over 2022)
• Return on average capital employed (ROACE)¹ of 21%
• Increased total proved plus probable Net Present Value by 9% year-over-year to $2.8 billion (NPV10)
• 2024 guidance reaffirmed

CALGARY, AB, March 6, 2024 /CNW/ - Kiwetinohk Energy Corp. (TSX: KEC) today reported its 2023 financial and operational results and year-end reserves evaluation. As companion documents to this news release, please review the Company's year end 2023 management discussion and analysis (MD&A), consolidated financial statements and annual information form (available on kiwetinohk.com or www.sedarplus.ca) for additional financial and operational details.

Message to shareholders 

"I am extremely pleased with the team's performance throughout 2023. Kiwetinohk delivered robust financial and operational results, meeting or exceeding corporate expectations," said Pat Carlson, Chief Executive Officer.

"This success is underscored by 27% annual production growth culminating in a record annual production level of 22,587 boe/d and year-end monthly exit production of approximately 30,150 boe/d. Equally important, our commitment to safety remained unwavering with the team executing a significant capital program with zero lost time incidents or reportable spills. The strength of the Company's reserves continues to demonstrate the inherent value of our asset base. Our updated reserves report confirms a notable share price value gap. As of December 31, 2023, our proved developed producing (PDP) reserves alone are estimated to have a before tax net present value discounted at 10% (NPV10) of $15.70/share exceeding the year end trading price of $11.35/share by approximately 38%. Total proved (1P) and total proved plus probable (2P) NPV 10 values are estimated at $35.79/share and $63.10/share, respectively, reinforcing the underlying value of our upstream development program which is further bolstered by our current portfolio of gas fired and renewable power development projects which continue to progress.

"Kiwetinohk is executing on its 2024 budget priorities with a focus on financial discipline given anticipated ongoing volatility in commodity prices. Since year end, three Duvernay wells at the 8-23 pad have been brought on production and we have finished drilling our first two wells of our 2024 program at the 1-27 pad; one in the Duvernay and one in the Montney. Looking forward, the upstream development program is on track, production is substantially hedged at favourable prices over the balance of the year and our operating and financial outlook remains in-line with our guidance provided last December.

"We continue to make progress against project milestones across our power portfolio and are encouraged by the Alberta government's February 28, 2024 announced new policy direction for renewable energy development which we believe brings clarity to solar developments going forward and which our projects are well positioned to address. We continue to pro-actively engage with federal and provincial governments to get better clarity on the broader evolving electricity policy and regulation and its potential impact on power development. In January 2024, extreme cold weather led to peak energy demand in Alberta, demonstrating electricity supply challenges that we believe will persist into the future. Kiwetinohk's power development portfolio would provide a combination of power sources that would help Alberta address these supply challenges through clean, reliable, dispatchable and affordable power."

_______________________________

¹  Non-GAAP and other financial measure that does 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 of the Company's MD&A for the year ended December 31, 2023.

Financial and operating results for the quarter

	Q4 2023	Q4 2022	2023	2022
Production
Oil & condensate (bbl/d)	8,407	8,423	7,183	6,197
NGLs (bbl/d)	3,507	2,664	2,769	2,012
Natural gas (Mcf/d)	76,756	81,949	75,810	57,859
Total (boe/d)	24,707	24,745	22,587	17,852
Oil and condensate % of production	34 %	34 %	32 %	35 %
NGL % of production	14 %	11 %	12 %	11 %
Natural gas % of production	52 %	55 %	56 %	54 %
Realized prices
Oil & condensate ($/bbl)	95.66	104.96	96.90	115.82
NGLs ($/bbl)	51.44	68.82	53.07	74.06
Natural gas ($/Mcf)	3.32	8.12	3.76	8.69
Total ($/boe)	50.17	70.04	49.95	76.72
Royalty expense ($/boe)	(4.84)	(5.72)	(4.72)	(6.78)
Operating expenses ($/boe)	(8.55)	(7.20)	(8.52)	(9.70)
Transportation expenses ($/boe)	(5.49)	(5.27)	(5.61)	(5.31)
Operating netback ^1 ($/boe)	31.29	51.85	31.10	54.93
Realized gain (loss) on risk management ($/boe) ^2	0.23	(6.58)	1.50	(13.33)
Realized gain (loss) on risk management - purchases ($/boe) ^2	1.20	(2.36)	1.69	(5.23)
Net commodity sales from purchases (loss) ($/boe) ^1	(0.51)	3.16	(0.80)	7.07
Adjusted operating netback ^1	32.21	46.07	33.49	43.44
Financial results ($000s, except per share amounts)
Commodity sales from production	114,038	159,457	411,826	499,898
Net commodity sales from purchases (loss) ^1	(1,152)	7,174	(6,642)	46,069
Cash flow from operating activities	58,946	87,028	240,760	242,850
Adjusted funds flow from operations ^1	63,697	101,506	241,311	264,082
Per share basic	1.46	2.30	5.49	6.00
Per share diluted	1.44	2.26	5.43	5.92
Net debt to annualized adjusted funds flow from operations ^1	0.77	0.46	0.77	0.46
Free funds flow deficiency from operations (excluding acquisitions/dispositions) ^1	(12,713)	(1,202)	(65,674)	(5,647)
Net income (loss)	48,302	115,308	111,896	190,989
Per share basic	1.11	2.61	2.54	4.34
Per share diluted	1.09	2.57	2.52	4.28
Capital expenditures prior to (dispositions) acquisitions ^1	76,410	102,708	306,985	269,729
Net (dispositions) acquisitions	(18,000)	—	(19,995)	57,323
Capital expenditures and net (dispositions) acquisitions ^1	58,410	102,708	286,990	327,052
Balance sheet ($000s, except share amounts)
Total assets	1,085,615	932,650	1,085,615	932,650
Long-term liabilities	305,735	221,731	305,735	221,731
Net debt ^1	186,523	122,304	186,523	122,304
Adjusted working capital surplus (deficit) ^1	7,565	(3,105)	7,565	(3,105)
Weighted average shares outstanding
Basic	43,710,734	44,168,157	43,971,108	44,045,613
Diluted	44,172,101	44,887,920	44,467,348	44,593,528
Shares outstanding end of period	43,662,644	44,176,710	43,662,644	44,176,710
Return on average capital employed ("ROACE") ^1			21 %	30 %
Reserves
Proved reserves (MMboe) ^3			123.2	125.5
Proved reserves per share (boe) ^3			2.8	2.9
Proved plus probable reserves (MMboe) ^3			224.5	214.5
Proved plus probable reserves per share (boe) ^3			5.1	4.9

1 – Non-GAAP and other financial measure that does 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 of the Company's MD&A.

2 – Realized gain (loss) on risk management contracts includes settlement of financial hedges on production and foreign exchange, with gains 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 net working interest reserves before royalties.

Fourth quarter highlights

• Record annual production of 22,587 boe/d, a 27% increase year-over-year. Fourth quarter production of 24,707 boe/d, grew 16.4% over the third quarter of 2023; year-end exit production for the month of December 2023 was approximately 30,150 boe/d.
• Strong quarterly operating netback² of $31.29/boe drove adjusted funds from operations during the fourth quarter of $63.7 million, or $1.46/share. This represents a 14% increase over the third quarter of 2023 and results in annual adjusted funds from operations² of $241.3 million or $5.49/share.
• Fourth quarter capital expenditures (before acquisitions/dispositions)² of $76.4 million brought full year capital expenditures to $307.0 million. The capital program was executed while maintaining a strong balance sheet; the ratio of net debt to annualized adjusted funds flow from operations[2] was 0.77x at December 31, 2023.
• Disposed of non-core assets for proceeds of $18.0 million in the fourth quarter bringing annual disposition total proceeds to $21.3 million in 2023 and related gains on sale of $7.6 million. The disposition of non-core assets reflects the Company's current focus on the development of its core Simonette and Placid development assets.
• Return on average capital employed² of 21% in 2023 demonstrating a strong return while significantly expanding gas processing infrastructure. Including 2022 return on average capital employed of 30%, Kiwetinohk's ROACE has averaged approximately 26% over the last two years through the development of its high quality Duvernay and Montney assets.
• Exited 2023 with $165.6 million or 37% of capacity remaining under existing credit facilities which is available to support continued growth in 2024.

______________________

²  Non-GAAP and other financial measure that does 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 of the Company's MD&A for the year ended December 31, 2023.

Kiwetinohk continues to execute on its upstream and power development plans and is maintaining guidance provided on December 13, 2023 with no changes to expectations. The Company has provided updated sensitivities on adjusted funds flow from operations² (see below) to reflect a lower outlook for natural gas pricing. Despite this reduction, we have increased the low end of the projected range of adjusted funds flow as a result of strong early first quarter results, the Company's hedging program, and a decision in late 2023 to extract more natural gas liquids from the Company's processing plants. This adjustment demonstrates the robustness of the Duvernay and Montney assets in Fox Creek and the Company's ability to manage its owned infrastructure to protect returns for shareholders.

The Company continues to protect the cash flows required to execute our program and manage commodity price risk and volatility through a prudent  management program. For 2024, approximately ~50% of condensate production is hedged against WTI with an average floor price of approximately US$70.00 /bbl and structures that allow for upside participation to approximately $80.00/bbl. In addition, approximately 45% of natural gas production is hedged at an average floor price of approximately $3.20/MMbtu with structures that allow for upside price participation to approximately $4.00/MMbtu. Our strategy provides protection to the downside while maximizing upside exposure. Additional details of the current hedges in place can be found in the Company's MD&A for the year ended December 31, 2023.

For a detailed breakdown of guidance for 2024 please refer to the Company's MD&A for the year ended December 31, 2023.

Select 2024 Financial & Operational Guidance
2024 Adjusted Funds Flow from Operations commodity pricing sensitivities^1
US$70/bbl WTI & US$2.00/MMBtu HH	CAD$MM	$260 - $290
US$80/bbl WTI & US$3.00/MMBtu HH	CAD$MM	$305 - $340
US$ WTI +/- $1.00/bbl ^2	CAD$MM	+/- $3.5
US$ Chicago +/- $0.10/MMBtu ^2	CAD$MM	+/- $1.4
CAD$ AECO 5A +/- $0.10/GJ ^2	CAD$MM	+/- $0.9
Exchange Rate (CAD$/US$) +/- $0.01 ^2	CAD$MM	+/- $3.1
2024 Net debt to Adjusted Funds Flow from Operations sensitivities ^1
US$70/bbl WTI & US$2.00/MMBtu HH	X	0.7x - 0.8x
US$80/bbl WTI & US$3.00/MMBtu HH	X	0.4x - 0.5x

1.	Non-GAAP measure that does 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$75/bbl WTI, US$2.50/mmbtu HH, US$0.80/mmbtu HH - AECO basis diff, $0.74 USD/CAD.

2023 year-end reserves highlights

• Conversions to PDP replaced approximately 119% of 2023 production with total proved plus probable (2P) reserve replacement of 550%.
• Grew 2P reserves by 5% or ~10.0 MMboe after dispositions (~27.1 MMboe) and annual production. Within the Company's core development areas of Simonette and Placid, 2P reserves grew by 20% or ~37.1 MMboe after annual production.
• 2P net present value (NPV10) grew by 9% year over year to $2.8 billion (net of $0.2 billion in dispositions) with lower average year over year commodity prices.
• Improved plant liquids recovery and increased total liquids share of production from 43% to 48% in Simonette in response to redeployment of capital to liquids rich inventory.
• Underlying reserve base highlights significant value relative to today's share price: PDP NPV10 (BT) $15.70/share; Total Proved (1P) NPV10 (BT) $35.79/share; and 2P NPV10 (BT) $63.10/share compared to a December 31, 2023 share price of $11.35.
• PDP reserve life index (RLI) of 4.60, 1P of 13.70 and 2P of 24.90 years.
• 2P finding and development costs (F&D) of $19.84. Over the life of the reserves, the reserve report estimates undeveloped 1P F&D costs of $18.74/boe (future development capital divided by proved undeveloped reserves) and undeveloped 2P F&D cost of $13.97/boe.
• 3-year finding, development and acquisition (FD&A) recycle ratios were 2.4x for PDP, 2.1x for 1P and 2.6x for 2P based on the three year average operating netback of $39.81/boe.

Upstream operational update

In mid-November, Kiwetinohk began production from its new 14-29 four-well Duvernay pad. These wells combined to produce approximately 11,900 boe/d on average in December 2023 and contributed to a record year-end exit production of approximately 30,150 boe/d. The 14-29 pad continues to provide strong production in the new year. In addition, three wells at the Company's 8-23 Duvernay pad in Simonette have recently been completed and were brought on stream at the end of February, slightly ahead of schedule. Since the first number of days where the wells were cleaning up, they have been averaging wellhead rates of between 8-10 mmcf/d of natural gas and associated liquids in addition to between 1,000-1,200 bbls/day of condensate per well. The wells continue to be choked back and while it is very early days, the early production rates appear to be in-line with the Company's expectations in this core Simonette development area.

Kiwetinohk has finished drilling the first two wells of its 2024 capital program, including one Duvernay well and the first of two Montney wells scheduled to be drilled in Simonette. This Montney well is the first that Kiwetinohk is drilling in the Simonette area since acquiring the assets. It is in a different part of the Montney than the Placid wells that were drilled last year and has a significant amount of inventory to exploit. The second Montney well is scheduled to be drilled in the third quarter. Kiwetinohk has also recently commenced drilling a three well Duvernay pad in the liquids rich area at Tony Creek, and is in the process of moving a second rig into Tony Creek for another three well pad. These wells are all scheduled to come on-stream in the third quarter of this year. This is part of an overall capital program that includes plans to drill twelve Duvernay wells and three Montney wells. Flexibility has been retained to accelerate three additional Duvernay wells with an investment decision anticipated in the second quarter of 2024. 

There are no changes to previously disclosed upstream operating guidance, which can be referenced in the fourth quarter MD&A and the news release originally dated December 13, 2023. Kiwetinohk is targeting average production to grow to an average of 24.0 - 27.0 thousand boe/d for calendar 2024, while continuing to reduce unit operating costs by increasing volumes flowing through owned and operated infrastructure.

Power update

In August 2023 the Alberta government enacted the Generation Approvals Pause Regulation, which immediately paused AUC approval of new renewable energy projects greater than one megawatt until February 29, 2024. The Alberta government also directed the AUC to conduct an inquiry regarding the policy and procedures for the development of renewable electricity generation. On February 28, 2024, the Alberta government announced new policy direction for  renewable development going forward.

"We support the Alberta government's renewable power policy updates as it provides consistent high standards for developers. Kiwetinohk has assessed the impact of this announcement on our solar portfolio and we currently believe our projects are well positioned and will not be impacted. Our planned solar projects are on Class 3 lands and incorporate best practices outlined by the government such as agrivoltaics. We will continue to evaluate our overall power strategy in light of recent announcements,"  said Fareen Sunderji, President Power Division. 

During the fourth quarter, Kiwetinohk advanced four power development projects through the AESO regulatory queue, with the Black Bear (NGCC) project advancing to Stage 3. The Company believes that its development portfolio remains competitively well positioned within the Alberta market and is currently seeking external non-dilutive capital to finance power projects. Kiwetinohk has engaged a financial advisor to help in sourcing potential financing partners and/or acquirers of the Company's two most advanced projects, Homestead Solar and Opal Firm Renewable which together provide 500MW of generation capacity. Transactions may include a partial or outright sale of a project with proceeds helping to fund ongoing development of the remaining portfolio.

Capital cost estimates for the Homestead Solar project continue to be refined as Kiwetinohk advances through detailed engineering work. The Company has continued to optimize the design and development plan for its 400 MW Homestead solar project and is reducing capital cost estimates by $50.0 million to a revised Class 2 cost estimate of approximately $675.0 million. We already have the AUC power plant approval and continue to advance power purchase agreement discussions and work on obtaining a transmission line approval with an anticipated FID in the second half of 2024. 

Capital cost estimates and timelines for Opal and the remaining portfolio continue to be evaluated and updated through the normal course and are expected to reflect increases related to general inflationary conditions and supply chain challenges. Pricing for Opal will be determined and disclosed as we finalize estimates in conjunction with a FID decision. 

Reserves update

McDaniel & Associates conducted an independent reserves evaluation and prepared the Company's reserve report according to National Instrument 51-101 standards as outlined by 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, 2024 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 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 2023 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 2023 gross volumetric and valuation reserve results:

	Tight oil (Mbbl)	Shale gas (MMcf)	Natural gas liquids (Mbbl)	2023 Total (Mboe)	2022 Total (Mboe)
Proved producing	827	132,612	18,293	41,222	40,399
Proved developed non-producing	—	175	25	54	413
Proved undeveloped	—	250,336	40,185	81,908	84,731
Total proved	827	383,123	58,503	123,184	125,543
Probable	161	314,809	48,642	101,271	88,924
Total proved plus probable	988	697,932	107,145	224,455	214,467

Net present value before tax summary:

$ Millions	0 %	5 %	10 %	15 %	20 %
Proved developed producing	879,351	797,511	685,480	599,039	534,060
Proved developed non-producing	574	602	564	511	458
Proved undeveloped	1,988,682	1,288,371	876,795	616,435	441,787
Total proved	2,868,607	2,086,484	1,562,839	1,215,985	976,305
Probable	3,285,837	1,862,022	1,192,487	832,003	617,405
Total proved plus probable	6,154,444	3,948,506	2,755,326	2,047,988	1,593,710
PDP value / share ^1	$              20.14	$              18.27	$              15.70	$              13.72	$              12.23
1P value / share ^1	$              65.70	$              47.79	$              35.79	$              27.85	$              22.36
2P value / share ^1	$            140.95	$              90.43	$              63.10	$              46.90	$              36.50

1 - based on 43,662,644 shares outstanding as of December 31, 2023

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 ($MM)	Total  proved plus probable ($MM)
2024	212.3	212.3
2025	334.4	334.4
2026	330.9	330.9
2027	342.0	342.0
2028	298.0	298.5
Thereafter	17.2	992.6
Total FDC, Undiscounted	1,534.8	2,510.7
Total FDC, Discounted at 10%	1,206.7	1,720.7

1P/2P Future Undeveloped F&D Costs:

Proved Undeveloped		1P	2P
FDC	$MM	1,535	2,510.7
Proved undeveloped reserves	Mboe	81,908	179,720
F&D	$/boe	$           18.74	$           13.97

Sustainability update

Kiwetinohk joined the Oil & Gas Methane Partnership 2.0 (OGMP 2.0), the flagship oil and gas reporting and mitigation program of the United Nations Environment Programme (UNEP). Kiwetinohk is the first Canadian member to join OGMP 2.0, the only comprehensive, measurement-based reporting framework for the oil and gas industry. In 2023 Kiwetinohk took steps towards improving the accuracy and transparency associated with its methane emissions reporting through installation of continuous emissions monitoring at most of its sites and set a 50% vented methane reduction target (from 2022 levels).

Kiwetinohk supports the Government of Alberta's announced policy direction to support the sustainability of solar projects in the province including integration of agrivoltaics and reclamation security best practices that Kiwetinohk has already adopted.

Conference call, annual general meeting and first quarter 2024 reporting date

Kiwetinohk management will host a conference call on March 7, 2024, at 8 AM MT (10 AM ET) to discuss results and answer questions. Participants will be able to listen to the conference call by dialing 1-888-664-6383 (North America toll free) or 416-764-8650 (Toronto and area). A replay of the call will be available until March 14, 2024, at 1-888-390-0541 (North America toll free) or 416-764-8677 (Toronto and area) by using the code 519452.

Kiwetinohk plans to release its first quarter 2024 results prior to TSX opening on May 9, 2024 and hold its annual general meeting later that same day.

About Kiwetinohk

We, at Kiwetinohk, are passionate about addressing climate change and the future of energy. Kiwetinohk's mission is to build a profitable energy transition business providing clean, reliable, dispatchable, affordable energy. Kiwetinohk develops and produces liquids-rich natural gas and related products and is in the process of developing renewable and natural gas-fired power generation projects with a vision of also incorporating carbon capture technology and hydrogen production, all as part of a broader, integrated portfolio of clean energy assets that will support energy transition in the markets that it serves. We view climate change with a sense of urgency, and we want to make a difference. 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.

This news release includes references to sales volumes of "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.

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 5, 2024 and effective December 31, 2023 (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, 2024 ("Jan 2024 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, 2023, 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;
• expectations regardiing the Company's reserves, including the reserve life index, recycle ratios and future development costs of such reserves;
• electricity supply challenges faced by Alberta and the combination of projects required to address the challenge through clean, reliable, dispatchable and affordable power;
• receipt of regulatory approvals, including AUC transmission line approval, for the Company's power projects, including the Homestead Solar and Opal Firm Renewable projects and the timing thereof;
• the Company's ongoing engagement with federal and provincial governments with respect to regulations affecting the Company's operations;
• the timing for various projects, including the Company's Homestead Solar project, reaching FID;
• the Company's 2024 financial and operational guidance;
• 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 Company's target to reduce vented methane emissions by 50% and the timing thereof; and
• the timing of the release of the Company's first quarter 2024 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 ability to generate a pathway to achieve additional value for shareholders through its future development program and power development portfolio;
• the Company's ability to execute on its 2024 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 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 Company's expectations on value generation related to its power portfolio;
• the impact that the Company's projects under development will have on the power grid, including its ability to create a stable and sustainable power supply;
• the Company's expectation of a competitive position in the Alberta power market;
• the Company's unique position to deliver additional value to shareholders;
• the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner;
• future commodity and power prices;
• the Company's expectations and ability to execute solar projects and the level of risk associated with curtailment;
• currency, royalty, exchange and interest rates;
• 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;
• power project debt will be held at the project level;
• power projects will be funded by third parties, as currently anticipated;
• 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;
• 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; 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 Corporation's MD&A as at and for the year ended December 31, 2023, 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 Corporation'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, 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, 2023, 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 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 from operating activities, adjusted funds flow and free cash flow on a per share – basic and diluted basis are calculated by dividing the cash 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.

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
IR email: [email protected]
IR phone: [phone]

Pat Carlson, CEO
Jakub Brogowski, CFO

SOURCE Kiwetinohk Energy