ROK Resources Inc. — Management Reports 2024

Apr 18, 2024

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MANAGEMENT’S DISCUSSION & ANALYSIS

FOR THE THREE MONTHS AND YEARS ENDED DECEMBER 31, 2023 AND 2022

Management’s Discussion & Analysis

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FINANCIAL AND OPERATING HIGHLIGHTS

FINANCIAL AND OPERATING HIGHLIGHTS
	Q4 2023	Q4 2022	Year 2023	Year 2022
Financial Highlights
Oil and natural gas sales	23,207,066	23,925,141	87,226,620	87,311,542
Realized gain on commodity contracts	1,021,804	2,336,149	6,710,873	4,124,648
Processing and other income	1,074,743	574,624	2,778,326	1,787,246
Net income (loss)	(3,713,389)	(5,556,994)	(10,986,934)	80,002,750
$ per share, basic	(0.02)	(0.03)	(0.05)	0.46
$ per share, diluted	(0.02)	(0.03)	(0.05)	0.40
Funds Flow(1)	6,163,667	12,496,785	25,790,378	39,007,318
Expenditures on property, plant & equipment	12,348,404	11,960,612	28,933,947	28,402,308
Total assets	165,067,420	192,078,125	165,067,420	192,078,125
Principal balance of long‐term debt	14,501,748	43,347,566	14,501,748	43,347,566
Net Debt(1)	14,701,454	35,341,546	14,701,454	35,341,546
Shareholders' equity	101,431,803	109,507,571	101,431,803	109,507,571
Common shares outstanding	218,418,315	211,580,484	218,418,315	211,580,484
Operating Highlights (2)
Average daily production
Crude oil (bbl/d)	2,116	2,453	2,064	1,848
NGLs (boe/d)	495	219	417	177
Natural gas (mcf/d)	9,591	5,263	8,372	4,473
Total (boe/d)	4,210	3,549	3,876	2,770
Average realized prices, before hedging
Crude oil ($/bbl)	95.23	89.07	94.18	109.35
NGLs ($/boe)	55.52	60.93	50.97	69.51
Natural gas ($/mcf)	2.42	5.37	2.79	5.56
Combined average ($/boe)	59.91	73.28	61.65	86.36
Operating Netback(1)
Oil and natural gas sales ($/boe)	59.91	73.28	61.65	86.36
Royalties ($/boe)	(10.08)	(12.67)	(10.88)	(14.17)
Operating expenses ($/boe)	(29.69)	(23.91)	(31.17)	(25.08)
Operating Netback ($/boe)	20.14	36.70	19.60	47.11
Funds from Operations ($/boe)(1)	25.56	45.63	26.31	52.96
Operating Income Profit Margin(1)	33.6%	50.1%	31.8%	54.6%
Funds from Operations Profit Margin(1)	42.7%	62.3%	42.7%	61.3%

1) “Funds Flow”, “Operating Netback”, “Funds from Operations”, “Operating Income Profit Margin”, “Funds from Operations Profit Margin”, “Net Debt” do not have standardized meanings under IFRS. Refer to “Non‐IFRS Measures” section of this MD&A.

2) Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. Refer to the section entitled “Conversion Measures” at the end of this MD&A.

For the three months and years ended December 31, 2023 and 2022

2

Management’s Discussion & Analysis

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INTRODUCTION

The following is management’s discussion and analysis (“ MD&A ”) of the operating and financial results of ROK Resources Inc. (“ ROK ” or the “ Company ”), for the three months and year ended December 31, 2023, as compared to the three months and year ended December 31, 2022, as well as information and expectations concerning the Company’s outlook based on currently available information.

This MD&A should be read in conjunction with ROK’s audited annual consolidated financial statements for the year ended December 31, 2023, as well as the audited annual financial statements for the year ended December 31, 2022 prepared in accordance with IFRS (as defined below), together with the accompanying notes.

This MD&A contains forward‐looking information about our current expectations, estimates, projections and assumptions. Additional information on the Company, its financial statements, this MD&A and other factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR+ website (www.sedarplus.ca).

All dollar values are expressed in Canadian dollars, unless otherwise indicated, and are prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by the International Accounting Standard Board (“IASB”).

This MD&A is prepared as of April 17, 2024.

NON‐IFRS MEASURES

The non‐IFRS measures and ratios referred to below do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable to similar measures used by other companies. Management uses these non‐IFRS measurements to provide its shareholders and investors with a measurement of the Company’s financial performance and are not intended to be viewed as an alternative to cash provided by operating activities, net income or other measures of financial performance calculated in accordance with IFRS. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.

Funds Flow

“Funds Flow” include all cash from (used in) operating activities and are calculated before the change in non‐cash working capital. A reconciliation of cash provided by (used in) operating activities to Funds Flow for the three months and year ended December 31, 2023 and 2022, are as follows:

	Q4 2023	Q4 2022	Year 2023	Year 2022
Cash provided by operating activities	9,451,293	14,425,693	29,158,741	38,558,851
Change in non‐cash working capital	(3,287,626)	(1,928,908)	(3,368,363)	448,467
Funds Flow	6,163,667	12,496,785	25,790,378	39,007,318

Operating Income, Operating Netback, Operating Income Profit Margin, Funds from Operations, and Funds from Operations Profit Margin

“Operating Income” is calculated by deducting operating expense from total revenue. Total revenue is comprised of oil and natural gas sales, net of royalties. The Company refers to Operating Income expressed per unit of production as an “Operating Netback”. “Operating Income Profit Margin” is calculated by the Company as Operating Income as a percentage of oil and natural gas sales. “Funds from Operations” and “Funds from Operations Profit Margin” adjust Operating Income and Operating Income Profit Margin for processing and other income and realized gains/losses from the economic hedges in place during the period. A reconciliation of the measures for the three months and year ended December 31, 2023 and 2022, are as follows:

For the three months and years ended December 31, 2023 and 2022

3

Management’s Discussion & Analysis

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	Q4 2023	Q4 2022	Year 2023	Year 2022
Oil and Natural Gas Sales	23,207,066	23,925,141	87,226,620	87,311,542
Royalties	(3,902,500)	(4,135,298)	(15,392,995)	(14,321,258)
Operating Expenses	(11,501,149)	(7,804,463)	(44,095,957)	(25,356,246)
Operating Income	7,803,417	11,985,380	27,737,668	47,634,038
Processing and other income	1,074,743	574,624	2,778,326	1,787,246
Realized gain on commodity contracts	1,021,804	2,336,149	6,710,873	4,124,648
Funds from Operations	9,899,964	14,896,153	37,226,867	53,545,932
Sales volume (boe)	387,339	326,469	1,414,890	1,010,981
Per boe
Oil and Natural Gas Sales	59.91	73.29	61.65	86.36
Royalties	(10.08)	(12.67)	(10.88)	(14.17)
Operating Expenses	(29.69)	(23.91)	(31.17)	(25.08)
Operating Netback	20.14	36.70	19.60	47.11
Funds from Operations	25.56	45.63	26.31	52.96
Operating Income Profit Margin	33.6%	50.1%	31.8%	54.6%
Funds from Operations Profit Margin	42.7%	62.3%	42.7%	61.3%

Net Debt

Throughout this MD&A, references to “Net Debt” means the principal amount of its outstanding long‐term obligations, net of Adjusted Working Capital. “Adjusted Working Capital” is calculated as current assets less current liabilities, excluding current portion of debt as presented on the statement of financial position. As at December 31, 2023, the Adjusted Working Capital includes cash and cash equivalents, accounts receivable, prepaid expenses and deposits, the current portion of risk management contracts, and accounts payable and accrued liabilities. ROK uses “Net Debt” as a measure of the Company’s financial position and liquidity, however it is not intended to be viewed as an alternative to other measures calculated in accordance with IFRS.

	December 31, 2023	December 31, 2022
Cash and cash equivalents	‐	5,258,881
Accounts receivable	13,021,111	10,862,673
Prepaid expenses and deposits	364,090	1,144,672
Current portion of risk management contracts	4,521,075	4,418,471
Accountspayable and accrued liabilities	(17,560,130)	(13,678,677)
Adjusted working capital (2)	346,146	8,006,020
Credit Facility (8.2%)(1)	14,501,748	‐
Lease obligations(1)	545,851	‐
Senior Loan Facility (15%)(1)	‐	43,347,566
Less: adjusted workingcapital(2)	(346,146)	(8,006,020)
Net debt	14,701,453	35,341,546

• 1) Represents undiscounted face value of debt balances and lease obligations outstanding as of each respective date presented.

2) Calculation of adjusted working capital excludes current portion of debt as presented on the statement of financial position. The mark‐to‐market fair value of the current portion of risk management contracts is included within adjusted working capital.

For the three months and years ended December 31, 2023 and 2022

4

Management’s Discussion & Analysis

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BUSINESS PROFILE AND STRATEGY

ROK is a public company that is engaged in oil and gas exploration and development activities in Western Canada. The Company has head offices located in Regina, Saskatchewan, Canada, and Calgary, Alberta, Canada, and the Company’s shares are traded on the TSX Venture Exchange (“ TSXV ”) under the trading symbol “ROK”. ROK continues to execute on its targeted growth strategy with a series of acquisitions and certain dispositions of non‐core assets. The Company’s assets are concentrated in Southeast Saskatchewan and Central Alberta.

The Board of Directors and management continue to develop existing properties to maximize production from existing reserves and have also continued to evaluate potential transactions available to the Company with the mission to identify opportunities that may provide the best future for the Company and the shareholders with the goal to maximize shareholder value.

2023 ACQUISITIONS

In January 2023, the Company successfully closed the acquisition of certain oil and gas assets in Southeast Saskatchewan in exchange for total consideration of: 1) cash payment of $21.9 million, after closing adjustments and the $2.5 million deposit paid in December 2022, and 2) certain oil and gas assets of the Company located in Southwest Saskatchewan that had a carrying value of $23.8 million and associated decommissioning obligations of $1.6 million. Two further acquisitions of additional oil and gas assets in Southeast Saskatchewan also closed for consideration of $0.5 million, after closing adjustments.

2023 DISPOSITIONS

In March 2023, the Company closed the disposition of ROK’s non‐operated 2.11685% interest in the Weyburn Unit for cash proceeds of $42.0 million, after closing adjustments and transaction costs. The assets had a carrying value of $37.0 million and associated decommissioning obligations of $0.5 million. The Company also closed several smaller dispositions for total proceeds of $4.1 million, after closing adjustments. The disposed assets had a carrying value of $4.3 million and associated decommissioning obligations of $0.4 million. The proceeds of these dispositions were utilized to reduce the outstanding balance of existing debt facilities (see below).

LIQUIDITY AND CAPITAL RESOURCES

The Company’s approach to managing liquidity is to ensure a balance between expenditure requirements and cash provided by operations and working capital. As at December 31, 2023, the Company had working capital of $0.2 million ($14.7 million working capital deficiency at December 31, 2022). Changes in working capital have been primarily due to proceeds from non‐core asset dispositions (see above), debt financing events (see below), the servicing of new debt obligations, and cash flows on account of oil and natural gas sales, net of royalties and operating expenses, and general and administrative costs.

In recent years, global economic conditions, financial markets, and commodity prices in particular, have experienced significant volatility and uncertainty. While the current outlook for commodity prices is relatively strong, long‐term price support from future demand remains uncertain. The scale and duration of these developments remain uncertain but could impact the Company's operations, future net earnings and cash flows given the aforementioned global events are an evolving situation that will continue to have widespread implications for the Company’s business environment and financial condition. Management cannot reasonably estimate the length or severity of these global events, or the extent to which any disruption may materially impact the Company’s financial position in fiscal 2023 and beyond.

The Company also faces uncertainties related to future environmental laws and climate‐related regulations, which could affect the Company's financial position and future earnings. A transition to a lower‐carbon society, as well as the potential impacts of climate change, could result in increased operating costs and reduced demand for oil and gas products. As a result, this could change a number of variables and assumptions used to determine the estimated

For the three months and years ended December 31, 2023 and 2022

5

Management’s Discussion & Analysis

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recoverable amounts of the Company’s oil and gas assets. The unpredictable nature, timing and extent of climate‐ related initiatives presents various risks and uncertainties.

In 2023, the Company has obtained new debt financing (see below) pursuant to the 2023 asset acquisitions and the repayment of the Senior Loan Facility. These events further enhance the Company’s oil and gas asset portfolio, increase cash flow from operations, and improve debt service requirements.

2023 Debt Financing

In January 2023, the Company entered into a non‐revolving term facility of $52.5 million with a Canadian Chartered Bank (the “ Term Loan ”) and a $22.5 million revolving credit facility with a syndicate of banks (the “ Credit Facility ”). The proceeds of these debt financings were used to pay out the Senior Loan Facility and fund the aforementioned 2023 acquisitions (see above).

The Term Loan was to mature two years from issuance, and carried monthly payments of $2 million towards principal, commencing on February 28, 2023, with the balance of the principal due at maturity. The Term Loan bore interest at the bank's prime lending or bankers' acceptance rates plus applicable margins. The applicable margin charged by the bank was dependent upon the Company's debt to cash flow ratio for the most recent quarter. The Term Loan was secured by a floating charge debenture on the assets of the Company.

Along with the scheduled $2 million monthly scheduled principal payments, the Company made voluntary principal repayments of $41.3 million and $5.1 million in March 2023 and May 2023, respectively, to settle the remaining balance and terminate the Term Loan. As a result, the Term Loan is now terminated. Repayment was funded primarily through funds from the Weyburn asset sale.

At December 31, 2023, the amount drawn on the Credit Facility was $14.5 million. A review and redetermination of the borrowing base occurs semi‐annually on or before June 30 and November 30 of each year. The facility is available on a revolving basis until June 27, 2024 (the “ Term Out Date ”), at which time the facility (and the Term Out Date) may be extended for a further one‐year period at the request of the Company and subject to the approval of the syndicate. Such one‐year extensions may continue to occur on each subsequent Term Out Date, subject to the approval of the syndicate. Alternatively, on the Term Out Date, at the Company's discretion, the facility is available on a non‐revolving basis for an additional one‐year period, at the end of which time the facility would be due and payable. As the available lending limits of the facility are based on the syndicate’s interpretation of the Company’s reserves, commodity prices and decommissioning obligations, there can be no assurance that the amount of the available facility will not decrease at the next scheduled review. In the current pricing environment, there is an increased risk that the lenders may decrease the amount available under the Credit Facility and the decreases could be material.

The Credit Facility provides that advances may be made by way of direct advances, bankers' acceptances or letters of credit/guarantees. The facility bears interest at the bank's prime lending or bankers' acceptance rates plus applicable margins. The applicable margin charged by the bank is dependent upon the Company’s debt to cash flow ratio (as defined in the lending agreement) for the most recent quarter. The bankers’ acceptances bear interest at the applicable bankers' acceptance rate plus an explicit stamping fee based upon the Company’s debt to cash flow ratio. As at December 31, 2023, the Credit Facility had an effective interest rate of 8.5% per annum. The Credit Facility is secured by a floating charge debenture on the assets of the Company.

The Company is required to maintain certain debt covenants throughout the term of the Credit Facility, as follows:

• Maintain a minimum liability management rating of 2.00 in the Provinces of Alberta and Saskatchewan and a minimum licensee liability rating of 1.00 in the Province of British Columbia.

• Maintain oil and gas price hedges on a minimum of 75% of Company oil and gas production for a period of not less than 12 months. Please refer to the “Financial Risk Management” section for oil and gas price hedges held by the Company as of the date of this MD&A.

For the three months and years ended December 31, 2023 and 2022

6

Management’s Discussion & Analysis

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• Make expenditures of not less than $2,000,000 during each fiscal year toward asset retirement and abandonment and reclamation liabilities.

• Maintain a debt to cash flow ratio (as defined in the lending agreement) of less than 2.00. As at December 31, 2023 the company’s debt to cash flow ratio was 0.48:1.

As at December 31, 2023, the Company was compliant with all restrictions and covenants for the Credit Facility.

Senior Loan Facility

In January 2023, the Senior Loan Facility was repaid with the establishment of the Revolving Credit Facility and Term Loan (see above). The termination of the Senior Loan Facility resulted in the immediate recognition of $7.3 million as loss on debt settlement for remaining unamortized issue costs and certain incurred termination costs.

PETROLEUM AND NATURAL GAS PROPERTIES

In Q1 2023, the Company completed strategic acquisitions and non‐core, non‐operated divestitures, which included Southwest Saskatchewan production and a non‐operated working interest in the Weyburn Unit. The newly acquired properties complement ROK’s existing portfolio of oil and gas assets operated in Southeast Saskatchewan. As a result, the Company’s core assets moving forward are as follows:

• Southeast Saskatchewan ‐ comprised of oil weighted conventional Frobisher and Midale prospects; and

• Kaybob Alberta ‐ a gas weighted, stacked multi‐zone reservoir with upside locations in the Cardium, Montney, Bluesky and Dunvegan formations.

Production in Q4 2023 averaged 4,210 boe/d, comprised of 2,116 bbl/d of Light/Medium Oil, 495 bbl/d of Natural Gas Liquids and 9591 Mcf/d of Natural Gas. Year ended December 2023 production averaged 3,876 boe/d, comprised of 2,064 bbl/d of Light/Medium Oil, 417 bbl/d of Natural Gas Liquids and 8,372 Mcf/d of Natural Gas. A highlight of the fourth quarter was exiting the year at 4,650 boe/d, representing over 50% growth from June 2023.

The Company’s production additions during the 2H 2023 can be attributed to:

• New production from new drills, recompletions and reactivations (1,500 boe/d)

• Restoration of production from shut‐ins due to Alberta forest fires (200 boe/d)

CORPORATE REVIEW

With the aforementioned acquisitions and divestitures, the Company significantly reduced its debt levels and eliminated the Term Loan 20 months ahead of the maturity date. This has provided capital flexibility as the Company continues its development program through 2024.

Highlights for the Company’s 2023 year include:

• Annual average production of 3,876 boe/d (64% liquids);

• Record monthly average production of 4,650 boe/d (60% liquids) in December 2023;

• Net Debt of $14.7 million as of December 31, 2023. This represents a 58%, or $20.6 million, reduction in Net Debt year over year;

• Realized net hedge gains on commodity contracts of $6.7 million; and

• Invested $2.3 million to reduce environmental liabilities which represents 10% of the Company’s estimated inactive asset retirement obligation.

For 2023, the Company’s capital expenditures were as follows:

• Drilling case equipment tie‐in (DCET): $23.6 million

For the three months and years ended December 31, 2023 and 2022

7

Management’s Discussion & Analysis

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• Land and Seismic: $2.4 million

• Facilities: $2.9 million

• Abandonment and reclamation: $2.3 million

1H 2024 CAPITAL BUDGET

Entering 2024 with the softening of the North American oil and natural gas markets, the Company is expected to utilize the first six months of 2024 to focus on: (i) debt reduction, (ii) improving operational efficiencies, (iii) strategic well reactivations and optimizations, and (iv) advancement of the lithium project. The 1H 2024 capital budget is comprised of $10.5 ‐ $11.5 million, approximately 70% of which is dedicated to the drilling of 6.0 gross (5.5 net) wells in Q2 2024 and a series of well reactivations and recompletions in core operating areas in Southeast Saskatchewan.

The Company is expected to provide second half 2024 guidance in the second quarter of 2024. Subject to a less volatile commodity price environment, the second half of 2024 is expected to include a continued active drilling program aimed at expediting growth and reducing Finding and Development (F&D) costs in core operating areas, with a continued emphasis on Frobisher drilling. Strategic Midale development may also occur, however pressure maintenance is expected to become a focus in the Company's more mature Midale pools. Within the Kaybob area, the Company is expected to remain positioned to deploy capital on its Cardium oil and Montney gas development, should economics justify an investment.

LITHIUM EXPLORATION PROJECT

In July 2021, the Company entered into an Exploration Management Agreement (the “ Lithium Agreement ”) wherein the Company was issued a 25% interest in a private entity (the “ Investee ”) which currently holds certain Subsurface Mineral Dispositions in Saskatchewan, with a focus on potential lithium resource prospects. Under the terms of the agreement, the Company earns its beneficial interest as ROK personnel will manage the following objectives of the project:

• Identify additional strategic lithium land prospects

• Complete multi‐layer perforation and flow testing of a wellbore

• Obtain samples and conduct test for lithium concentrations

• Identify a location for a pilot project

• Identify a strategic partner to negotiate a lithium extraction technology pilot project

• Obtain a third party NI43‐101 resource report

• Facilitate the completion of a preliminary economic assessment

The initial activities of this project will be wholly funded by the Company’s partner (who holds the remaining 75% interest), up to $1.5 million. Any costs that exceed this financial threshold will then be proportionally financed by each partner based on their interest in the private entity. Alternatively, either partner may elect to proportionally reduce their interest in the private entity for any portion of additional costs above the threshold. These additional costs beyond the initial $1.5 million may be voluntarily paid for by the other partner who elects to participate in additional project activities, earning a proportionally increased interest in the private entity. The Company has since satisfied all the objectives of the Lithium Agreement, and the Lithium Agreement has since terminated.

Effective January 1, 2024, the Company entered into a Management Agreement (“ Lithium Management Agreement ”) wherein the Company is paid $46,250 per month, plus GST, to provide certain services (outlined below). The Lithium Management Agreement expires in twelve (12) months.

Services include the following:

• Investigate the lithium potential of those areas, including but not limited to the property, that are considered likely to be suited to the occurrence of such resource;

For the three months and years ended December 31, 2023 and 2022

8

Management’s Discussion & Analysis

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• Recommend and target additional properties that are considered likely to be suited to the occurrence of lithium;

• Make recommendations with respect to the exploration, drilling, and testing of wells or wellbores and conduct, manage and administer such exploration, drilling, testing and development activities;

• Identify a location for a pilot project;

• Identify a joint venture partner to negotiate a lithium extraction technology pilot project; and

• Include the services of those persons set forth in the Lithium Management Agreement.

In Q1 2023, the Investee drilled a new vertical test well on the Viewfield property, with resulting lithium concentrations reaching up to 259 mg/l, the highest test results of lithium concentrations in a brine ever recorded in Canada, according to public record. In Q2 2023, a follow‐up vertical well was drilled on the Viewfield property, with resulting lithium concentrations reaching up to 237 mg/l.

The Company, alongside our partners, released a Preliminary Economic Assessment in early 2024, with highlights summarized below:

• Pre‐tax $1.49 billion USD NPV, at an 8% discount rate;

• Pre‐tax IRR of 55% which represents a payout duration of 2.1 years;

• Total capital expenditures (" CAPEX ") of $571 million USD inclusive of both direct and indirect capital costs, including $52 million USD in contingency;

• All‐in operating costs (" OPEX ") of $3,319 USD per tonne Lithium Carbonate Equivalent (LCE), $40 million USD annually, including all direct and indirect costs;

• 23‐year project‐life producing a total of 282,090 tonnes of battery‐grade lithium carbonate, an average of 12,175 tonnes LCE per year;

• Weighted average lithium concentrations of 128 mg/L from 7 target zones over the project life (range of 84 mg/L to 259 mg/L); and

• PEA encompasses approximately 11,000 net hectares, or 14% of Hub City Lithium's lands in Southern Saskatchewan.

The Investee continues to test brine with numerous direct lithium extractors and downstream refiners and, in 2023, successfully produced battery‐grade Lithium Carbonate Equivalent (LCE) from the Viewfield project. Future operations include the drilling of additional test and development wells as part of its continued evaluation. A field pilot on the Viewfield property is also underway and expected to be completed in Q3 2024.

Currently, the Investee holds approximately 200,000 acres of leased land in Saskatchewan for the project. The Company’s interest in the Investee is accounted for using the equity method. As of December 31, 2023, total expenditures since inception had reached a total of $9.4 million. The Company’s financial contribution towards project activities has equated to approximately $2.0 million.

COMMITMENT SUMMARY UPDATE

As of the date of the MD&A, the Company had no contractual commitments related to service arrangements or otherwise. Future capital expenditures may come about under joint operating agreements with operator and/or non‐operator partners on oil and gas production assets where the Company has a participating interest. As the Company elects to participate in future exploration and/or development programs under these joint operating agreements, the Company becomes contractually obligated to fulfill its financial commitment for these projects, or otherwise incur certain financial penalties for non‐compliance as is customary under standard joint operating agreements.

For the three months and years ended December 31, 2023 and 2022

9

Management’s Discussion & Analysis

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DISCUSSION OF OPERATING RESULTS

Production

Production
	Q4 2023	Q4 2022	Year 2023	Year 2022
Crude oil (bbl/d)	2,116	2,453	2,064	1,848
NGLs (boe/d)	495	219	417	177
Natural gas (Mcf/d)	9,591	5,263	8,372	4,473
Total(boe/d) (1)	4,210	3,549	3,876	2,770

1) Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. Refer to the section entitled “Conversion Measures” at the end of this MD&A.

Oil and Natural Gas Sales

Oil and Natural Gas Sales
	Q4 2023	Q4 2022	Year 2023	Year 2022
Crude Oil	18,539,732	20,097,887	70,939,616	73,746,484
NGLs	2,530,902	1,226,162	7,766,070	4,489,450
Natural gas	2,136,432	2,601,092	8,520,934	9,075,608
Total	23,207,066	23,925,141	87,226,620	87,311,542

Realized Sales Prices, before Hedging

	Q4 2023	Q4 2022	Year 2023	Year 2022
Crude oil ($/bbl)	95.23	89.07	94.18	109.35
NGLs ($/boe)	55.52	60.93	50.97	69.51
Natural gas ($/Mcf)	2.42	5.37	2.79	5.56
Total($/boe)	59.91	73.28	61.65	86.36

Increased production for 2023 when compared to the comparative period in 2022 is due to the additional producing assets that have been acquired over the 2022 year and the first quarter of 2023, net of certain dispositions, along with new production from drilled wells, which has offset natural production declines in existing production assets. Q4 2023 crude oil production was higher than Q3 2023 due primarily to new production from the Q4 drilling program completed over the period. Oil pricing over 2023 saw improved pricing from beginning to end of year, while natural gas pricing over the 2023 year decreased. Volatility in commodity pricing is still prevalent due to ongoing global economic uncertainty, increased global conflicts, and reduced global demand, causing fluctuations in revenue per boe and overall sales revenue of the Company.

Royalties

Royalties
	Q4 2023	Q4 2022	Year 2023	Year 2022
Total royalties	3,902,500	4,135,298	15,392,995	14,321,258
Total royalties (% of sales)	16.8%	17.3%	17.6%	16.4%
Total royalties($/boe)	10.08	12.67	10.88	14.17

Royalties as a percentage of total oil and natural gas sales are highly sensitive to commodity prices and adjustments to gas cost allowance. Thus, royalty rates can fluctuate from quarter‐to‐quarter and year‐to‐year. Royalties as a percentage of revenues in 2023 were 17.6 percent compared to 16.4 percent in 2022.

The increases in royalty rates were primarily attributable to varying royalty rates on production from recent acquisitions when compared to royalty rates on recent dispositions and the Company’s other producing properties. The Company has also become subject to the provincial resource surcharge in the province of Saskatchewan, which are incorporated into ROK’s royalty expenses in 2023 and moving forward. This provincial resource surcharge is imposed on Company production realized from oil and gas assets in Saskatchewan.

For the three months and years ended December 31, 2023 and 2022

10

Management’s Discussion & Analysis

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The Company expects average corporate royalty rate to decrease as new wells are drilled on its existing land base, with a focus on Crown acreage in Saskatchewan, which carries a royalty holiday for the first 37,700 bbls of oil produced from each new well.

Operating Expenses

Operating Expenses
	Q4 2023	Q4 2022	Year 2023	Year 2022
General operating	6,229,979	4,837,198	25,395,048	18,296,437
Processing and treatment	2,287,242	1,108,983	7,505,208	2,342,479
Transportation and gathering	950,747	317,653	3,246,029	920,360
Maintenance and workovers	2,033,181	1,540,629	7,949,672	3,796,970
Total operating expenses	11,501,149	7,804,463	44,095,957	25,356,246
General operating	16.08	14.82	17.95	18.10
Processing and treatment	5.91	3.40	5.30	2.32
Transportation and gathering	2.45	0.97	2.29	0.91
Maintenance and workovers	5.25	4.72	5.62	3.76
Total operatingexpenses($/boe)	29.69	23.91	31.17	25.08

Operating costs include expenses incurred to operate wells, gather, treat, and transport production volumes as well as costs to perform well and facility repairs and maintenance. The Company’s 2023 operating expenses are higher when compared to prior year due to overall inflationary effects and notable higher operating costs related to productions assets acquired in Q1 2023. An increase in water and emulsion trucking costs was also observed, a result of fluid hauling during the evaluation stages of new wells. The Company performed 7 facility turnarounds (versus 2 in the forecast) from recent acquisitions, which were overdue and contributed significantly to operating costs in the period. The Company expects operating costs to reduce through 2024 based on focused efforts to improve operating efficiencies. Uncertainty around ongoing inflationary effects on operating costs will continue to be a contributing factor.

Gains (Losses) on Commodity Contracts

Gains (Losses) on Commodity Contracts
	Q4 2023	Q4 2022	Year 2023	Year 2022
Realized gain on commodity contracts	1,021,804	2,336,149	6,710,873	4,124,648
Unrealized gain (loss) on commodity contracts	5,939,628	(8,245,591)	(464,700)	4,985,775
Total	6,961,432	(5,909,442)	6,246,173	9,110,423

For the year ended December 31, 2023, the Company recognized realized gains of $6,710,873 on risk management commodity contracts maturing in the period (2022 ‐ $4,124,648) and unrealized losses of $464,700 on existing risk management commodity contracts to mature at a future date (2022 ‐ unrealized gains of $4,985,775). The unrealized losses reflect the mark‐to‐market change in fair value of the oil and gas price hedges in December 2023 on future oil and gas production from the Company’s oil and gas assets (see below) while realized gains reflect the cash settlement on oil and gas price hedges at the time of maturity of each hedge contract. Realized net gains in 2023 includes realized losses of $184,815 due to the unwinding of certain future commodity contracts that management chose to unwind.

General and Administrative Expenses

General and Administrative Expenses
	Q4 2023	Q4 2022	Year 2023	Year 2022
Wages & Salaries	1,288,102	933,382	3,317,263	2,215,279
Professional Fees	535,998	784,523	1,180,773	1,479,629
Fees, Rent, Investor Relations and Other	91,549	610,649	1,123,559	1,535,294
Total	1,915,649	2,328,554	5,621,595	5,230,202

Increases in G&A expenses for YTD 2023 is attributable to the overall growth and expansion of the Company’s business operations since Q1 2022. Increases in relation to overhead, staff, and consultant costs has naturally occurred on account of increased operations. Increased efforts for investor relations with shareholders and investors has also increased overall G&A.

For the three months and years ended December 31, 2023 and 2022

11

Management’s Discussion & Analysis

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Stock‐Based Compensation

The Company recorded stock‐based compensation expense of $1,044,646 for the year‐ ended December 31, 2023 (2022 ‐ $1,703,002). Stock options were granted in Q1 2022 and Q3 2022, with the vesting of these new options accounting for the majority of stock‐based compensation expense in 2022. Further stock option grants occurred in Q1 2023 and Q3 2023 contributing to stock‐based compensation expense in 2023.

Depletion and Depreciation

The carrying costs for property, plant and equipment directly associated with oil and gas operations, including estimated future development costs, are recognized as depletion expense in the statements of loss and comprehensive loss on a unit of production basis over proved plus probable reserves. The carrying costs of office and computer equipment are recognized as depreciation expense in the statements of loss and comprehensive loss on a straight‐line or declining‐balance basis.

For the year ended December 31, 2023, the Company recorded depletion expense of $23,280,785 ($19,190,812 for the 2022 comparative period). Depletion is calculated based on oil and gas production on the Company’s developed properties. Depreciation expense of $49,608 on leased equipment was also recognized in 2023 ($nil in 2022).

In the fourth quarter of 2023, indicators of impairment were present in our Alberta cash‐generating unit (“ CGU ”) due a decline in gas prices which are a predominant part of our Alberta assets. As a result of the indicators of impairment, the Company performed impairment calculations on the identified Alberta CGU and the recoverable amounts were determined using fair value less costs of disposal, which considered future cash flows from all reserves at a discount rate between 12‐27% percent, dependant on the risk profile of the reserve category. Based on the results of the impairment tests completed, the Company recognized non‐cash impairment charges of $8.949 million on their Alberta CGU.

Net Finance Expenses

Net Finance Expenses
	Q4 2023	Q4 2022	Year 2023	Year 2022
Interest income	(5,512)	‐	(57,125)	(113)
Interest expense & bank charges	114,291	92,985	301,834	360,084
Debt interest expense	399,197	1,826,351	2,780,066	6,209,994
Lease liability interest expense	7,492		11,232
Accretion on debt	98,631	2,158,432	2,568,449	7,481,475
Accretion on decommissioning obligations	547,281	434,666	2,055,785	1,301,800
Total	1,161,380	4,512,434	7,660,241	15,353,240

Net finance expenses were $7,660,241 for the year ended December 31, 2023, compared to finance expenses of $15,353,240 for the comparative period in 2022. Finance expenses includes accretion on decommissioning obligations that are associated with oil and gas properties acquired, and accretion and interest expense related to existing debt in each period. Decrease in finance expenses year‐over‐year are a result of changes to debt structure.

CAPITAL EXPENDITURES

For the year ended December 31, 2023, the Company incurred $23.6 million in capital expenditures towards drilling, completion and equipping of new wells, including surface infrastructure, $2.4 million towards land and seismic acquisitions, and $2.9 million towards facilities and equipment. Further cash expenditures of $22.4 million were incurred in relation to the acquisition of Southeast Saskatchewan oil and gas assets in 2023.

For the three months and years ended December 31, 2023 and 2022

12

Management’s Discussion & Analysis

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FINANCIAL RISK MANAGEMENT

The Company has exposure to the following risks from its use of financial instruments:

• Credit risk

• Liquidity risk

• Market risk

This note presents information about the Company’s exposure to each of the above risks and the Company’s objectives, policies and processes for measuring and managing these risks, and the Company’s management of capital. The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

Credit risk

Credit risk reflects the risk of loss if counterparties do not fulfill their contractual obligations and arises principally from the Company’s receivables from joint operations partners and petroleum and natural gas customers.

In determining the recoverability of trade and other receivables, the Company considers the type and age of the outstanding receivables, the credit risk of the counterparties, and the recourse available to the Company. The maximum exposure to credit risk for accounts receivable and accruals, net of expected credit loss at the reporting date by type of customer was:

date by type of customer was:
Carrying Amount	December 31, 2023	December 31, 2022
Oil and natural gas customers	7,756,737	7,597,682
Joint operations partners	4,237,670	2,083,791
Accruals and other	1,026,704	1,181,200
Total	13,021,111	10,862,673
Aging
0 ‐ 30 days	10,011,741	9,435,073
30 ‐ 90 days	1,561,514	871,954
Greater than 90 days	1,656,763	555,646
Expected credit loss	(208,907)	‐
Total	13,021,111	10,862,673

The Company considers amounts outstanding greater than 90 days to be at greater risk of being uncollectible, unless circumstances on particular balances provide certainty of collection. Receivables normally collectible within 30 to 60 days can take longer as information requests and timing can come into effect in dealing with receivables from joint venture partners. As at December 31, 2023, there were $208,907 in receivables which were considered uncollectible (December 31, 2022 ‐ $nil).

The Company held cash and cash equivalents of $nil as at December 31, 2023 (December 31, 2022 ‐ $5,258,881). The Company manages the credit exposure related to cash and cash equivalents by selecting counter parties based on credit ratings and monitors all investments to ensure a stable return, avoiding complex investment vehicles with higher risk.

For the three months and years ended December 31, 2023 and 2022

13

Management’s Discussion & Analysis

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Liquidity risk

The following table outlines the contractual maturities of the Company’s financial liabilities as at December 31, 2023:

	Less than 1year	1‐2years	Thereafter	Total
Accounts payable	17,560,130	‐	‐	17,560,130
Credit Facility	‐	14,501,748	‐	14,501,748
Lease obligations(1)	133,501	123,780	288,570	545,851
	17,693,631	14,625,528	288,570	32,607,729

1) Reflects timing of lease payments on existing lease obligations

Commodity price risk

Commodity price risk is the risk that the fair value of the future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the US dollar, but also by world economic events that dictate the levels of supply and demand.

The Company manages risk associated with the changes in commodity prices by entering into a variety of risk management contracts. The Company assesses the effects of movement in commodity prices on income before tax. As of the date of these financial statements, the Company has the following commodity risk management contracts outstanding:

Derivative swap contracts[(1)(2) ]

	WTI Crude	WTI Crude	AECO(3)	AECO(3)	Propane	Propane
	Volumes		Volumes	USD/	Volumes
Period	(bbl/d)	USD/bbl	(mmbtu/d)	mmbtu	(gal/d)	USD/gal
Q1 2024	1,087	79.72	4,980	2.65	3,400	0.99
Q2 2024	1,099	74.26	4,338	2.63	3,176	0.78
Q3 2024	1,011	74.32	4,194	2.45	2,079	0.76
Q4 2024	980	74.52	3,991	2.23	‐	‐

1) Prices reported are the average price for the period.

2) Swaps include trades in USD and CAD. Canadian swaps are converted from CAD to USD at a rate of 0.75.

3) Includes Henry Hub swaps, AECO differential swaps and AECO swaps.

The Company entered into the following commodity risk management contracts subsequent to December 31, 2023:

Derivative swap contracts[(1)(2) ]

	WTI Crude	WTI Crude	AECO(3)	AECO(3)	Propane	Propane
	Volumes		Volumes	USD/	Volumes
Period	(bbl/d)	USD/bbl	(mmbtu/d)	mmbtu	(gal/d)	USD/gal
Q2 2024	576	78.36	2,635	1.21	‐	‐
Q3 2024	526	76.41	2,306	1.27	‐	‐
Q4 2024	559	74.41	1,406	1.83	‐	‐
Q1 2025	1,200	72.57	5,000	2.42	‐	‐
Q2 2025	378	72.05	1,648	2.14	‐	‐

For the three months and years ended December 31, 2023 and 2022

14

Management’s Discussion & Analysis

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• 1) Prices reported are the average price for the period.

• 2) Swaps include trades in USD and CAD. Canadian swaps are converted from CAD to USD at a rate of 0.75.

• 3) Includes Henry Hub swaps, AECO differential swaps and AECO swaps.

Foreign currency risk

Foreign currency risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign currency exchange rates. The majority of the Company’s administrative and operational costs will be based and paid in Canadian dollars. However, the Company is exposed to the risk of fluctuations in foreign exchange rates between the Canadian dollar and the US dollar (USD) given the Company is exposed to the risk of changes in the US/Canadian dollar exchange rate on crude oil sales based on US dollar benchmark prices and commodity contracts that are settled in US dollars (see above).

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in prevailing market interest rates. The Company is exposed to interest rate risk on the Credit Facility, with interest rates based on the bank's prime lending or bankers' acceptance rates plus applicable margins. The applicable margin charged by the bank is dependent upon the Company's debt to cash flow ratio for the most recent quarter. Fluctuations of interest rates could result in an increase or decrease in the amount ROK pays to service the variable interest rate debt.

As at December 31, 2023, if interest rates applicable to the Credit Facility were to have increased or decreased by 50 basis points, it is estimated that the Company’s income before tax would similarly change by approximately $65,000 for the twelve months ended December 31, 2023.

Fair value of financial instruments

The Company’s financial instruments as at December 31, 2023, include, accounts receivable, accounts payable and accrued liabilities, risk management contracts, and debt.

The Company’s financial instruments recorded at fair value require disclosure about how the fair value was determined based on significant levels of inputs described in accordance with the following hierarchy:

Level 1 ‐ inputs are based on quoted market prices in active markets that the Company has the ability to access at the measurement date.

Level 2 ‐ inputs are based on quoted prices in the markets that are not active or based on prices that are observable for the asset or liability.

Level 3 ‐ inputs are based on unobservable market data for the asset or liability.

The Company aims to maximize the use of observable inputs when preparing calculations of fair value. Classification of each measurement into the fair value hierarchy is based on the lowest level of input that is significant to the fair value calculation.

The fair value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to their short terms to maturity. The fair value measurement of the risk management contracts and debt have a fair value hierarchy of Level 2.

The fair values of financial derivatives are recurring measurements and are determined whenever possible based on observable market data. If not available, the Company uses third party models and valuation methodologies that utilize observable market data including forward benchmark commodity prices, forward interest rates and forward

For the three months and years ended December 31, 2023 and 2022

15

Management’s Discussion & Analysis

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foreign exchange rates to estimate the fair value of financial derivatives. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non‐performance risk. The valuation technique used has not changed in the period.

Capital management

The Company’s objectives when managing capital are to ensure the Company will have sufficient financial capacity, liquidity, and flexibility to fund the Company’s operations and potential strategic transactions for the foreseeable future. The Company is dependent upon funding these activities through a combination of available cash, debt and equity, which it considers to be the components of its capital structure as outlined below.

The Company monitors leverage and adjusts its capital structure based on its net debt level. Net debt is defined as the principal amount of its outstanding long‐term obligations less adjusted working capital. In order to facilitate the management of its net debt, the Company prepares annual budgets, which are updated as necessary depending on varying factors including current and forecast commodity prices, changes in capital structure, execution of the Company’s business plan and general industry conditions. The annual budget is approved by the Board of Directors and updates are prepared and reviewed as required.

and updates are prepared and reviewed as required.
	December 31, 2023	December 31, 2022
Cash and cash equivalents	‐	5,258,881
Accounts receivable	13,021,111	10,862,673
Prepaids and deposits	364,090	1,144,672
Current portion of risk management contracts	4,521,075	4,418,471
Accounts payable	(17,560,130)	(13,678,677)
Adjusted working capital(2)	346,146	8,006,020
Credit Facility (8.2%)(1)	14,501,748	‐
Lease obligations(1)	545,851	‐
Senior Loan Facility (15%)(1)	‐	43,347,566
Less: adjusted working capital(2)	(346,146)	(8,006,020)
Net debt	14,701,453	35,341,546

1) Represents undiscounted face value of debt balances and lease obligations outstanding as of each respective date presented. 2) Calculation of adjusted working capital excludes current portion of debt as presented on the statement of financial position. The mark‐to‐market fair value of the current portion of risk management contracts is included within adjusted working capital.

The Company regularly monitors its capital structure and, as necessary, adjusts to changing economic circumstances and the underlying risk characteristics of its assets in order to meet current and upcoming obligations and investments by the Company. The Company frequently reviews alternate financing options and arrangements to meet its current and upcoming commitments and obligations.

The Company's objectives when managing capital are: (i) to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk; and (ii) to maintain investor, creditor and market confidence in order to sustain the future development of the business. The Company’s share capital is not subject to external restrictions with the exception of lender approval on payment of dividends.

For the three months and years ended December 31, 2023 and 2022

16

Management’s Discussion & Analysis

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SHAREHOLDERS’ EQUITY

Common shares

The Company is authorized to issue an unlimited number of Class B Shares, with no par value, with holders of Class B Shares entitled to one vote per share and to dividends, if declared. Outstanding Class B Shares as of December 31, 2023, are as follows:

2023, are as follows:
	Class B shares	Amount
Balance, January 1, 2022	74,471,576	6,309,267
Prospectus Offering, March 2022	95,834,100	11,691,720
Shares issued for Debt Note conversion	15,555,550	2,075,326
Stock option exercise	495,000	71,300
Warrant exercise	25,224,258	5,705,572
Balance, December 31, 2022	211,580,484	25,853,185
Stock option exercise	603,333	146,180
Warrant exercise	6,234,498	2,052,899
Balance, December 31, 2023	218,418,315	28,052,264

Warrants

The Company has issued and outstanding warrants exercisable to acquire Class B Shares of the Company that were issued as part of particular financings carried out over time.

A summary of the changes in warrants is presented below:

The Company has issued and outstanding warrants exercisable to issued as part of particular financings carried out over time. A summary of the changes in warrants is presented below:	acquire Class B Shares	of the Company that were
		Weighted average
	Warrants	exercise price
Balance, January 1, 2022	25,538,975	0.23
Purchase warrants issued, Prospectus Offering	95,834,100	0.25
Broker warrants issued, Prospectus Offering	6,125,054	0.18
Purchase warrants issued, Debt Note Conversion	15,555,550	0.25
Purchase warrants issued upon broker warrant exercised	4,612,505	0.25
Warrant exercise	(25,224,258)	0.15
Warrant expiries	(7,500)	0.15
Balance, December 31, 2022	122,434,426	0.26
Warrant exercise	(4,721,949)	0.35
Warrant expiries	(4,570,600)	0.35
Balance, December 31, 2023	113,141,877	0.25

The following summarizes information about total warrants outstanding as at December 31, 2023:

	Number of warrants	Weighted average term to	Number of warrants
Exercise prices	outstanding	expiry (years)	exercisable
0.25	113,141,877	1.18	113,141,877

Stock options

The Company has a stock option plan whereby options can be granted from time to time to directors, officers, employees, and consultants at the discretion of the Board of Directors. The number of options that can be granted

For the three months and years ended December 31, 2023 and 2022

17

Management’s Discussion & Analysis

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is limited to 10% of the total shares issued and outstanding. A summary of the changes in stock options is presented below:

below:
		Weighted average
	Stock options	exercise price
Balance, January 1, 2022	6,590,000	0.23
Options issued	13,110,000	0.26
Options exercised	(420,000)	0.10
Options forfeited	(516,667)	0.26
Balance, December 31, 2022	18,763,333	0.25
Options issued	1,775,000	0.39
Options exercised	(603,333)	0.15
Options forfeited	(75,000)	0.40
Balance, December 31, 2023	19,860,000	0.27
Exercisable, December 31, 2023	14,290,004	0.26

The following summarizes information about stock options outstanding as at December 31, 2023:

	Number of options	Weighted average term to	Number of options
Exercise prices	outstanding	expiry (years)	exercisable
0.15	1,600,000	1.18	1,600,000
0.25	10,260,000	3.48	6,840,006
0.28	4,050,000	2.81	4,050,000
0.30	1,450,000	3.92	966,669
0.35	1,075,000	4.30	358,333
0.40	1,425,000	4.42	474,996
	19,860,000	3.30	14,290,004

As of the date of this MD&A, the Company maintained balances of 218,418,315 Class B Shares, 113,141,877 warrants, and 19,860,000 stock options.

NEW ACCOUNTING STANDARDS

The IASB has issued a number of new accounting standards, amendments to accounting standards, and interpretations that are effective for annual periods beginning on or after January 1, 2023. None of the accounting pronouncements are expected to have a material impact upon initial adoption. The Company will continue to evaluate the impact of the pronouncements which will be adopted on their respective effective dates.

USE OF ESTIMATES AND JUDGMENTS

The timely preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below.

The Company continues to assess the impact of climate change on the financial statements. The Company is currently analyzing potential internal greenhouse gas reduction initiatives and is continually monitoring regulatory initiatives that may impact its existing businesses. The impact of these changes will be assessed in future reporting periods to ensure any changes in assumptions that would impact estimates listed below are adjusted on a timely basis.

For the three months and years ended December 31, 2023 and 2022

18

Management’s Discussion & Analysis

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Critical judgments in applying accounting policies

The following are the critical judgments that management has made in the process of applying the Company’s accounting policies and that have the most significant effect on the amounts recognized in the financial statements:

i) Identification of cash‐generating units

The Company’s assets are aggregated into cash‐generating units, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company’s assets in future periods.

ii) Impairment of property, plant and equipment and

Judgments are required to assess when impairment indicators, or reversal indicators, exist and impairment testing is required. In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimates with respect to forecasted production volumes, forecasted petroleum and natural gas prices, forecasted operating costs, forecasted royalties, and forecasted future development costs, discount rates, market value of land and other relevant assumptions.

iii) Income taxes

Judgments are made by management to determine the likelihood of whether deferred income tax assets at the end of the reporting period will be realized from future taxable earnings. To the extent that assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs.

iv) Asset Acquisitions

The application of the Company’s accounting policy for business combinations requires management to make certain judgments in applying the optional concentration test under IFRS 3 Business Combinations, to determine whether the acquired assets meet the definition of a business combination or an asset acquisition. Where an acquisition involves a group of assets and liabilities, and does not constitute a business, the acquirer must identify and recognize the individual assets acquired and liabilities assumed. The cost of the transaction is allocated to the assets acquired and liabilities assumed based on their relative fair values at the date of purchase.

Key sources of estimation uncertainty

The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities, where applicable.

i) Reserves and resource assessment

The estimate of proved and probable petroleum and natural gas reserves and the related cash flows includes significant estimates and assumptions related to: 1) forecasted petroleum and natural gas commodity prices; 2) forecasted production volumes; 3) forecasted operating costs; 4) forecasted royalty costs; and 5) forecasted future development costs. Other estimates which impact the assessment of the reported recoverable quantities of proved and probable reserves and prospective resource estimates include estimates regarding exchange rates, remediation costs, timing and production, transportation and marketing costs for future cash flows.

It also requires interpretation of geological and geophysical models in anticipated recoveries and estimates with respect to production profiles. The economical, geological and technical factors used to estimate reserves and prospective resources may change from period to period. Changes in reported reserves and prospective resources can impact the carrying values of the Company’s petroleum and natural gas properties and exploration and evaluation assets and equipment, the calculation of depletion and depreciation, the provision

For the three months and years ended December 31, 2023 and 2022

19

Management’s Discussion & Analysis

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for decommissioning obligations, the recognition of deferred tax assets due to changes in expected future cash flows, and the estimated fair value of property, plant and equipment acquired in a business combination.

The Company’s petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be economically recoverable in future years from known reservoirs and which are considered commercially viable. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon (i) a reasonable assessment of the future economics of such production; (ii) a reasonable expectation that there is a market for all or substantially all the expected petroleum and natural gas production; and (iii) evidence that the necessary production, transmission and transportation facilities are available or can be made available. Reserves may only be considered proven and probable if the ability to produce is supported by either actual production or conclusive formation tests. Prospective resources are determined using an externally prepared valuation report which reflects estimated prospective resources and external pricing and costs assumptions reflective of the current market. The Company’s petroleum and gas reserves and prospective resources are determined pursuant to National Instrument 51‐101, Standard of Disclosures for Oil and Gas Activities.

The Company uses estimated proved and probable petroleum and natural gas reserves from an independent third‐party reserve evaluation to estimate the fair value of property, plant and equipment acquired and the fair value of the PP&E disposed in a business combination. Further, the Company uses estimated proved and probable petroleum and natural gas reserves to deplete its development and production assets, to assess for indicators of impairment or impairment reversal on each of the Company’s CGU and if any such indicators exist, to perform an impairment test to estimate the recoverable amount of the CGUs.

The Company engaged independent third‐party reserve evaluators to estimate proved and probable petroleum and natural gas reserves as at December 31, 2022, April 1, 2023 and December 31, 2023.

For purposes of estimating the fair value of the property, plant and equipment acquired in a business combination, the Company used the April 1, 2023, independent third‐party reserve evaluators’ estimate of proved and probable petroleum and natural gas reserves and the related future cash flows and internally updated to the acquisition date.

For purposes of estimating the fair value of PP&E disposed in a business combination, the Company used the December 31, 2022, independent third‐party reserve evaluators’ estimate of proved and probable petroleum and natural gas reserves and the related future cash flows and internally updated to the disposition date.

For the Company’s depletion calculations and impairment tests, the Company used the December 31, 2023, independent third‐party reserve evaluators estimate of proved and probable petroleum and natural gas reserves.

ii) Decommissioning obligations

The Company estimates future remediation costs of production facilities, wells and pipelines at different stages of development and construction of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires assumptions regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and liability‐specific discount rates to determine the present value of these cash flows.

iii) Business combinations

In a business combination, management makes estimates of the fair value of assets acquired and liabilities assumed as part of the acquisition transaction, which includes assessing the value of oil and gas properties based upon the estimation of recoverable quantities and cash flows from proved and probable oil and gas reserves

For the three months and years ended December 31, 2023 and 2022

20

Management’s Discussion & Analysis

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being acquired, discounted at an estimated rate that reflects a market participants view of the risks associated with the cash flows.

iv) Share‐based payments

All equity‐settled, share‐based awards issued by the Company are recorded at fair value using the Black‐Scholes option‐pricing model. In assessing the fair value of equity‐based compensation, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk‐free rate and estimated forfeitures at the initial grant date.

v) Tax provisions

Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in profit or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse.

Matters relating to economic uncertainty

Estimates are more difficult to determine, and the range of potential outcomes can be wider, in periods of higher volatility and uncertainty. The impacts of the COVID‐19 pandemic and the recovery therefrom coupled with several factors including higher levels of uncertainty due to the Russian invasion of Ukraine as well as the recent Israel‐ Hamas war and their impact on energy markets, rising interest and inflation rates, and constrained supply chains have created a higher level of volatility and uncertainty. Management has, to the extent reasonable, incorporated known facts and circumstances into the estimates made, however, actual results could differ from those estimates and those differences could be material.

Changing regulations

Emissions, carbon and other regulations impacting climate and climate related matters are dynamic and constantly evolving. With respect to environmental, social and governance (" ESG ") and climate reporting, the International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the aim to develop sustainability disclosure standards that are globally consistent, comparable and reliable. In addition, the Canadian Securities Administrators have issued a proposed National Instrument 51‐107 Disclosure of Climate‐related Matters. The cost to comply with these standards, and others that may be developed or evolve over time, has not yet been quantified by the Company.

RELATED PARTY TRANSACTIONS

In March 2022, the Company completed a Prospectus Offering for proceeds of $17,250,138 before transaction costs. Of the total proceeds, approximately $416,000 were from subscriptions by directors and officers or by investors related to directors and officers of the Company.

In March 2022, as part of the conversion of debt notes to units, the Company issued units to debt note holders at a price of $0.18 per unit on the principal of $2.8 million of debt notes on the same terms as the Prospectus Offering, resulting in the issuance of 15,555,550 units of the Company. Of the units issued, $0.5 million of the Debt Notes converted to 2,777,777 units which were issued to certain directors and officers of the Company.

PRINCIPAL BUSINESS RISKS

The Company’s business and results of operations are subject to a number of risks and uncertainties which include, but are not limited to, the following:

For the three months and years ended December 31, 2023 and 2022

21

Management’s Discussion & Analysis

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Crude Oil and Natural Gas Development

Exploration, development, production of oil and natural gas involves a wide variety of risks which include, but are not limited to, the uncertainty of finding oil and gas in commercial quantities, securing markets, commodity price fluctuations, exchange and interest rate exposure and changes to government regulations, including regulations relating to prices, taxes, royalties, and environmental protection. The oil and gas industry is intensely competitive and the Company competes with a large number of companies with greater resources.

The Company’s ability to obtain reserves in the future will depend not only on its ability to develop its current properties, but also on its ability to acquire new prospects and producing properties. The acquisition, exploration and development of new properties also require that sufficient capital from outside sources will be available to the Company in a timely manner. The availability of equity or debt financing is affected by many factors, many of which are beyond the control of the Company.

Addition of Reserves and Resources

The Company’s future crude oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Company successfully discovering and developing or acquiring new reserves and resources. The addition of new reserves and resources will depend not only on the Company’s ability to explore and develop properties but also, in the case of reserves, on its ability to select and acquire suitable producing properties or prospects. There can be no assurance that the Company’s exploration, development or acquisition efforts will result in the discovery and development of commercial accumulations of oil and natural gas.

Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the control of the Company. Estimates of reserves depend in large part upon the reliability of available geological and engineering data and require certain assumptions to be made in order to assign reserve volumes. Geological and engineering data is used to determine the probability that a reservoir of oil and/or natural gas exists at a particular location, and whether, and to what extent, such hydrocarbons are recoverable from the reservoir. Accordingly, the ultimate reserves discovered by the Company may be significantly less than the total estimates.

Exploration Risks

The exploration of the Company’s properties may from time to time involve a high degree of risk that no production will be obtained or that the production obtained will be insufficient to recover drilling and completion costs. The costs of seismic operations and drilling, completing and operating wells are uncertain to a degree. Cost overruns can adversely affect the economics of the Company’s exploration programs and projects. In addition, the Company’s seismic operations and drilling plans may be curtailed, delayed or cancelled as a result of numerous factors, including, among others, equipment failures, weather or adverse climate conditions, shortages or delays in obtaining qualified personnel, shortages or delays in the delivery of or access to equipment, necessary governmental, regulatory or other third‐party approvals and compliance with regulatory requirements.

Environmental Risks

Oil and gas exploration and production can involve environmental risks such as litigation, physical and regulatory risks. Physical risks include the pollution of the environment, climate change and destruction of natural habitat, as well as safety risks such as personal injury. The Company works hard to identify the potential environmental impacts of its new projects in the planning stage and during operations. The Company conducts its operations with high standards in order to protect the environment, its employees and consultants, and the general public. ROK maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations. Without such insurance, and if the

For the three months and years ended December 31, 2023 and 2022

22

Management’s Discussion & Analysis

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Company becomes subject to environmental liabilities, the payment of such liabilities could reduce or eliminate its available funds or could exceed the funds the Company has available and result in financial distress.

Climate Change Risks

Our exploration and production facilities and other operations and activities emit greenhouse gasses (" GHG ") which may require us to comply with federal and/or provincial GHG emissions legislation. 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 to prevent climate change or mitigate our effects. The direct or indirect costs of compliance with GHG‐related regulations may have a material adverse effect on the business, financial condition, results of operations and prospects of the Company. Some of ROK’s facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, climate change has been linked to long‐term shifts in climate patterns and extreme weather conditions both of which pose the risk of causing operational difficulties.

Key Personnel

The Company’s success depends in large part on the ability of its executive management team to deal effectively with complex risks and relationships and execute the Company’s business plan. The members of the management team contribute to the Company’s ability to obtain, generate and manage opportunities. There can be no assurance that the Company’s present key personnel and directors will remain with the Company. The departure of any such key person or director may materially affect the Company’s business, financial condition, results of operations, and the value of the Class B Shares.

Public Market Risk

There can be no assurance that an active trading market in the Company’s securities will be sustained. The market price for the Company’s securities could be subject to wide fluctuations. Factors such as commodity prices, government regulation, interest rates, share price movements of the Company’s peer companies and competitors, as well as overall market movements, may have a significant impact on the market price of the securities of the Company. The stock market from time to time has experienced extreme price and volume fluctuations, which may be unrelated to the operating performance of particular companies.

Dividends

To date, the Company has not paid regular dividends on its outstanding securities and does not anticipate paying any dividends in the foreseeable future. With the exception of lender approval, there are no restrictions in the Company’s articles or elsewhere which would prevent the Company from paying dividends. It is not contemplated that any dividends will be paid on the Class B Shares in the immediate future as it is anticipated that all available funds will be invested to finance the growth of the Company’s business. The directors of the Company will determine if, and when, dividends will be declared and paid in the future from funds properly applicable to the payment of dividends based on the Company’s earnings, financial position and other conditions at the relevant time. All of the Class B Shares are entitled to an equal share in any dividends declared and paid.

Failure to Maintain Listing of the Class B Shares

The Class B Shares are currently listed for trading on the facilities of the TSXV. The failure of the Company to meet the applicable listing or other requirements of the TSXV in the future may result in the Class B Shares ceasing to be listed for trading on the TSXV, which would have a material adverse effect on the value of the Class B Shares. There can be no assurance that the Class B Shares will continue to be listed for trading on the TSXV.

For the three months and years ended December 31, 2023 and 2022

23

Management’s Discussion & Analysis

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Structure of the Company

From time to time, the Company may take steps to organize its affairs in a manner that minimizes taxes and other expenses payable with respect to the operation of the Company and its subsidiaries. If the manner in which the Company structures its affairs is successfully challenged by a taxation or other authority, the Company and the holders of Class B Shares may be adversely affected.

Management’s Report on Internal Control over Financial Reporting

In connection with National Instrument 52‐109 ‐ Certification of Disclosure in Issuer’s Annual and Interim Filings (“ NI 52‐109 ”) adopted by each of the securities commissions across Canada, the Chief Executive Officer and Chief Financial Officer of the Company are required to file a Venture Issuer Basic Certificate with respect to the financial information contained in the unaudited interim financial statements and the audited annual financial statements and respective accompanying Management’s Discussion and Analysis. The Venture Issuer Basic Certificate does not include representations relating to the establishment and maintenance of disclosure controls and procedures and internal control over financial reporting, as defined in NI 52‐ 109.

CAUTION REGARDING FORWARD‐LOOKING INFORMATION

This MD&A offers an assessment of the Company’s future plans and operations as of the date hereof and may contain forward‐looking information. All statements other than statements of historical fact are forward‐looking statements. Such information is generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "may", "plan", "will", "project", “should", "believe" and similar expressions. Statements relating to "reserves" or "resources" are also forward‐looking statements, 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 resources and reserves described can be profitably produced in the future. All such statements involve known and unknown risks, uncertainties, and assumptions.

Management believes that the expectations reflected in the forward‐looking information are reasonable, but no assurance can be given that these expectations will prove to be correct. Such forward‐looking information included in this MD&A should not be unduly relied upon as the plans, assumptions, intentions, or expectations upon which it is based may not occur. Actual results or events may vary from the forward‐looking information.

In particular, this MD&A may contain forward‐looking information pertaining to the following:

• the potential of the Company’s assets,

• the Company’s growth strategy and opportunities,

• performance characteristics of the Company's oil properties and estimated capital commitments and probability of success,

• crude oil production and recovery estimates and targets,

• forecasted Operating Income in future periods,

• the existence and size of the oil reserves and resources,

• capital expenditure programs and estimates, including the timing of activity,

• plans for, and results of, exploration and development activities,

• projections of market prices and costs,

• the supply and demand for oil,

• expectations regarding forecasted Net Debt balances in the future and Company expectations for servicing existing debt,

• expectations regarding the ability to raise equity and debt capital on acceptable terms, including the ability to negotiate and complete any agreements contemplated,

• the timing for receipt of regulatory approvals, and

• treatment of the Company under governmental regulatory regimes and tax laws.

For the three months and years ended December 31, 2023 and 2022

24

Management’s Discussion & Analysis

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The purpose of providing any financial outlook in this MD&A is to illustrate how the business of the Company might develop without the benefit of specific historical financial information. Readers are cautioned that this information may not be appropriate for other purposes.

The forward‐looking information herein is based on certain assumptions and analysis by the management of the Company in light of its experience and perception of historical trends, current conditions and expected future developments and other factors that it believes are appropriate and reasonable under the circumstances. The forward‐looking information herein is based on a number of assumptions, including but not limited to:

• the availability on acceptable terms of funds for capital expenditures,

• the availability in a cost‐efficient manner of equipment and qualified personnel when required,

• the stability of the regulatory framework governing taxes and environmental matters in any jurisdiction in which the Company may conduct its business in the future,

• continuing strong demand for oil,

• the ability to market production of oil successfully to customers,

• future production levels and oil prices,

• the applicability of technologies for recovery and production of oil reserves,

• the existence and recoverability of any oil reserves,

• geological and engineering estimates in respect of resources and reserves in which the Company has an interest,

• the geography of the areas in which the Company has an interest, and

• the impact of increasing competition on the Company.

The actual results, performance and achievements of the Company could differ materially from those anticipated in these forward‐looking statements as a result of the risks and uncertainties set forth elsewhere in the MD&A and the following risks and uncertainties:

• global financial conditions,

• general economic, market and business conditions,

• volatility in market prices, the stock market, foreign exchange and interest rates,

• risks inherent in oil and gas operations, exploration, development and production,

• the failure by counterparties to make payments or perform their operational or other obligations to the Company in compliance with the terms of contractual arrangements between the Company and such counterparties,

• risks related to the timing of completion of the Company’s projects and plans,

• uncertainties associated with estimating oil and natural gas reserves and resources,

• competition for, among other things, capital, acquisitions of resources, and skilled personnel,

• the ability to hold existing leases through drilling or lease extensions or otherwise,

• incorrect assessments of the value of acquisitions,

• claims made in respect of the Company’s properties or assets,

• geological, technical, drilling and processing problems, including the availability of equipment and access to properties,

• environmental risks and hazards,

• the inaccuracy of third parties’ reviews, reports and projections,

• rising costs of labour and equipment,

• the failure to engage or retain key personnel,

• changes in income tax laws or changes in tax laws and incentive programs, and

• other factors discussed under “Principal Business Risks” in this MD&A.

Readers are cautioned that the foregoing lists of assumptions, risks and uncertainties are not exhaustive. Forward‐ looking information contained in this MD&A is expressly qualified by this cautionary statement. The forward‐looking information speaks only as of the date of this MD&A, and the Company does not undertake any obligation to publicly update or revise any forward‐looking information except as required by applicable securities laws.

For the three months and years ended December 31, 2023 and 2022

25

Management’s Discussion & Analysis

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KEY FINANCIAL RESULTS

The following table summarizes the Company’s key financial results over the past three years:

Annual Financial Results ($)	Year 2023	Year 2022	Year 2021
Oil and natural gas sales	87,226,620	87,311,542	3,436,882
Net income (loss)	(11,884,907)	80,002,750	(2,316,717)
Net income (loss) per share:
Basic	(0.05)	0.46	(0.03)
Diluted	(0.05)	0.40	(0.03)
Working capital (deficit)	246,336	(14,729,229)	(854,723)
Total assets	165,067,420	192,078,125	10,597,242
Total non‐current liabilities	45,975,677	46,156,628	3,808,242

The changes in year‐over‐year results are primarily the result of the Company’s ongoing efforts to increase oil and gas production, predominantly through the acquisition of producing assets. Commercial oil and gas production has continued to grow, with additional acquisitions of producing assets from 2021 to 2023, adding to both production income and total assets of the Company. With the significant expansion of operations in 2022 on account of the FCL Acquisition, oil and natural gas sales, royalties, and operating expenses drastically increased. As well, overall general and administrative expenses of the Company more than tripled in 2022 in comparison to 2021. 2023 saw even further increases in operating costs as the Company reached new records in production while general and administrative costs remained flat, The Senior Loan Facility and senior loan facility were extinguished in early 2023 in favor of a revolving credit facility with a syndicate of banks. Please refer to the “Discussion of Operating Results” section above for further details.

SELECTED QUARTERLY INFORMATION

The following table sets out selected unaudited quarterly financial information of the Company and is derived from unaudited quarterly financial data prepared by management in accordance with IFRS.

Quarterly Results ($)	Q4 2023	Q3 2023	Q2 2023	Q1 2023
Oil and natural gas sales	23,207,066	22,144,104	17,737,937	24,137,513
Oil and natural gas sales, net of royalties	19,304,566	19,213,001	13,949,930	19,366,128
Net income (loss)	(3,713,389)	(7,752,269)	(326,538)	805,262
Net income (loss) per share:
Basic	(0.02)	(0.04)	(0.00)	0.00
Diluted	(0.02)	(0.04)	(0.00)	0.00
Quarterly Results ($)	Q4 2022	Q3 2022	Q2 2022	Q1 2022
Oil and natural gas sales	23,925,141	26,554,511	28,710,012	8,121,878
Oil and natural gas sales, net of royalties	19,789,843	22,250,867	24,116,754	6,832,820
Net income (loss)	(556,994)	10,810,729	(1,460,541)	76,209,556
Net income (loss) per share:
Basic	(0.03)	0.05	(0.01)	0.73
Diluted	(0.03)	0.05	(0.01)	0.69

Over the past eight quarters, fluctuations in production volumes and realized commodity prices have impacted the Company's petroleum and natural gas revenues and funds flow. Net income (loss) has fluctuated due to effects of operating results from the acquisition of new producing assets, additional financing costs, increased general and administrative expenses, and other non‐cash items such as gains on acquisitions and dispositions as well as share‐

For the three months and years ended December 31, 2023 and 2022

26

Management’s Discussion & Analysis

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based compensation expense. Capital expenditures and production volumes have fluctuated over time as a result of the timing of acquisitions and the impact of market conditions on the Company’s development capital expenditures.

Operating results for each quarter of 2022 and 2023 continued to improve quarter‐over‐quarter when comparing the Operating Income Profit Margin of each 3‐month period, which is mainly attributable to higher overall commodity prices in 2023 and increased production from acquisitions. Quarter‐over‐quarter results also include increased general and administrative expenses and finance expenses due to the continued growth of the Company, and the costs of new debt financing in each year to help finance that growth. Beyond these factors, extraordinary or new items such as the gain on the FCL Acquisition in Q1 2022 and the gain/loss results in each quarter of 2022 and 2023 on commodity contracts and effects of deferred tax were additional contributors to quarterly net income (loss). In Q1 2023, further gains on dispositions contributed to the net income of the Company, offsetting reduced revenue per units of productions due to decreased commodity prices in the period. The continued decline of commodity prices and decreased daily production after asset dispositions executed in Q1 2023 contributed to the reduced revenue in Q2 2023. Reduced finance expenses in Q2 2023 due to the elimination of the Term Loan that carried a high interest cost soften the effects of reduced revenue on the quarter’s results. Q3 2023 operating results benefited from higher production rates, higher overall commodity prices in the market, and lower realized royalties per boe despite the countering effects of higher operating expense per boe due to cyclical annual expenses incurred in Q3 2023 and ongoing effects on operating costs due to the absorption of production assets acquired earlier in the 2023 year. Non‐cash items such as unrealized losses on the mark‐to‐market change in fair value of the oil and gas price hedges (in contrast to unrealized gains recorded in both Q1 2023 and Q2 2023) contributed significantly to the Q3 net loss. Q4 2023 saw record production levels reached and decreasing operating costs per boe compared to Q3 2023. However, overall realized commodity pricing declined from the prior quarter.

For the three months and years ended December 31, 2023 and 2022

27

Management’s Discussion & Analysis

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CONVERSION MEASURES AND SHORT‐TERM PRODUCTION RATES

Production volumes and reserves are commonly expressed on a boe basis whereby natural gas volumes are converted at the ratio of 6 thousand cubic feet to 1 barrel of oil. Although the intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants, boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1 and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value.

Short‐term production rates can be influenced by flush production effects from fracture stimulations in horizontal wellbores and may not be indicative of longer‐term production performance or ultimate recovery of reserves. Individual well performance may vary.

ABBREVIATIONS USED

bbl	barrel	AECO	Alberta Energy Company
bbl/d	barrels per day	GJ	gigajoule
boe	barrels of oil equivalent	Mcf	thousand cubic feet
boe/d	barrels of oil equivalent per day	Mcf/d	thousand cubic feet per day
bopd	barrels of oil per day	MMBtu	million British thermal units
Mbbls	thousand barrels	MMcf	million cubic feet
Mboe	thousand barrels of oil equivalent	MMcf/d	million cubic feet per day
MMboe	million barrels of oil equivalent	Bcf	billion cubic feet
NGL	natural gas liquids	WTI	West Texas Intermediate
m3	cubic metres	Cdn	Canadian
e3m3	thousand cubic metres	US	United States
CO2	Carbon dioxide	GHG	Greenhouse gas
EOR	Enhanced oil recovery	CCUS	Carbon capture, utilization & storage
Mg/l	milligrams per liter	DCET	Drill, complete, equip & tie

For the three months and years ended December 31, 2023 and 2022

28