ROK Resources Inc. - Management Reports 2023

==> picture [305 x 147] intentionally omitted <==

MANAGEMENT’S DISCUSSION & ANALYSIS

FOR THE THREE MONTHS AND YEAR ENDED DECEMBER 31, 2022 AND 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

FINANCIAL AND OPERATING HIGHLIGHTS

FINANCIAL AND OPERATING HIGHLIGHTS
	Q4 2022	Q4 2021	Year 2022	Year 2021
Financial Highlights
Oil and natural gas sales	23,925,141	1,211,817	87,311,542	3,436,882
Realized gain on commodity contracts	2,336,149	‐	4,124,648	‐
Processing and other income	574,624	‐	1,787,246	‐
Net income (loss)	(5,556,994)	(639,279)	80,002,750	(2,316,717)
$ per share, basic	(0.03)	(0.01)	0.46	(0.03)
$ per share, diluted	(0.03)	(0.01)	0.40	(0.03)
Funds Flow(1)	14,416,121	(151,093)	45,577,283	(510,559)
Expenditures on property, plant & equipment	11,960,612	41,612	28,402,308	1,691,946
Total assets	192,078,125	10,597,242	192,078,125	10,597,242
Principal balance of long‐term debt	43,347,566	4,000,000	43,347,566	4,000,000
Net Debt(1)	35,341,546	3,521,390	35,341,546	3,521,390
Shareholders' equity	109,507,571	4,030,895	109,507,571	4,030,895
Common shares outstanding	211,580,484	74,471,576	211,580,484	74,471,576
Operating Highlights (2)
Average daily production
Crude oil (bbl/d)	2,453	126	1,848	105
NGLs (boe/d)	219	37	177	37
Natural gas (mcf/d)	5,263	186	4,473	208
Total (boe/d)	3,549	194	2,770	177
Average realized prices, before hedging
Crude oil ($/bbl)	89.07	88.67	109.35	78.37
NGLs ($/boe)	60.93	31.50	69.51	22.13
Natural gas ($/mcf)	5.37	3.06	5.56	1.80
Combined average ($/boe)	73.28	66.49	86.36	53.24
Operating Netback(1)
Oil and natural gas sales ($/boe)	73.28	66.49	86.36	53.24
Royalties ($/boe)	(12.67)	(11.81)	(14.17)	(9.86)
Operating expenses ($/boe)	(23.91)	(22.62)	(25.08)	(21.04)
Operating Netback ($/boe)	36.70	32.06	47.11	22.34
Operating Netback, after Hedging ($/boe)(1)	43.87	32.06	51.20	22.34
Operating Income Profit Margin(1)	50.1%	48.2%	54.6%	42.0%
OperatingIncome Profit Margin,after Hedging (1)	59.9%	48.2%	59.3%	42.0%

(1) “Funds Flow”, “Operating Netback”, “Operating Netback, after Hedging”, “Operating Income Profit Margin”, Operating Income Profit Margin, after Hedging”, “Net Debt” do not have standardized meanings under IFRS. Refer to “Non‐GAAP 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 years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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, 2022, as compared to the three months and year ended December 31, 2021, 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, 2022, as well as the audited annual financial statements for the year ended December 31, 2021 (collectively, the “ Financial Statements ”) 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.sedar.com).

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

This MD&A is prepared as of April 13, 2023.

NON‐IFRS MEASURES

The non‐IFRS measures 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 for (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, 2022 and 2021, are as follows:

	Q4 2022	Q4 2021	Year 2022	Year 2021
Cash provided by (used in) operating activities	16,345,029	647,510	45,128,816	(1,473)
Change in non‐cash working capital	(1,928,908)	(798,603)	448,467	(509,086)
Funds Flow	14,416,121	(151,093)	45,577,283	(510,559)

Operating Income, Netback, and Operating 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. “Operating Income, after Hedging” and “Operating Income Profit Margin, after Hedging” adjust Operating Income and Operating Income Profit Margin for 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, 2022 and 2021, are as follows:

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

	Q4 2022	Q4 2021	Year 2022	Year 2021
Oil and Natural Gas Sales	23,925,141	1,211,817	87,311,542	3,436,882
Royalties	(4,135,298)	(210,907)	(14,321,258)	(636,733)
Operating Expenses	(7,804,463)	(403,950)	(25,356,246)	(1,358,527)
Operating Income	11,985,380	596,960	47,634,038	1,441,622
Realized gain on commodity contracts	2,336,149	‐	4,124,648	‐
OperatingIncome,after hedging	14,321,529	596,960	51,758,686	1,441,622
Sales volume (boe)	326,469	17,860	1,010,981	64,554
Per boe
Oil and Natural Gas Sales	73.28	66.49	86.36	53.24
Royalties	(12.67)	(11.81)	(14.17)	(9.86)
Operating Expenses	(23.91)	(22.62)	(25.08)	(21.04)
Operating Netback per boe	36.70	32.06	47.11	22.34
Operating Netback per boe, after hedging	43.87	32.06	51.20	22.34
OperatingIncome Profit Margin	50.1%	48.2%	54.6%	42.0%
OperatingIncome Profit Margin,after hedging	59.9%	48.2%	59.3%	42.0%

Net Debt

Throughout this MD&A, references to “Net Debt” include Debt Notes and the Senior Loan Facility (defined further below), 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, 2022, the Adjusted Working Capital surplus includes cash and cash equivalents, accounts receivable, prepaid expenses and deposits, 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.

	Dec 31, 2022	Dec 31, 2021
Senior Loan Facility (15%)(1)	43,347,566	‐
Debt Notes (14%)(1)	‐	4,000,000
Less: adjusted workingcapital(2)	8,006,020	478,610
Net debt	35,341,546	3,521,390

(1) Represents undiscounted face value of debt balances outstanding as of each respective date presented.

(2) Calculation of working capital excludes current portion of debt as presented on the statement of financial position.

BUSINESS PROFILE AND STRATEGY

ROK is a public company that is primarily 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 acquisitive growth strategy with a series of acquisitions of producing assets in 2021, 2022, and early 2023. The Company’s assets are concentrated in Southern 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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

2023 ASSET ACQUISITION

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 $22.9 million, after closing adjustments and the $2.5 million deposit paid in December 2022, and 2) the disposition of certain oil & gas assets of the Company located in Southwest Saskatchewan to the selling party. The cash component of the consideration paid was funded through proceeds from the 2023 Senior Loan Facility (see below).

2023 ASSET DISPOSITIONS

In March 2023, the Company successfully closed the divestures of certain non‐core oil and gas assets in Saskatchewan for total combined proceeds of $47.25 million, which includes the sale of ROK’s non‐operated 2.11685% interest in the Weyburn Unit for total proceeds of approximately $44.5 million, before closing adjustments. The majority of the proceeds of the divestitures were utilized to reduce the outstanding balance of the recently established 2023 Senior Term Facility (see below).

FCL ACQUISITION

On March 7, 2022, the Company successfully closed the acquisition (the " FCL Acquisition ") of certain oil and gas assets in Saskatchewan and Alberta (the " Assets "), from Federated Co‐operatives Limited and its wholly‐owned subsidiary, 2214896 Alberta Ltd. (collectively, " FCL "). Total consideration paid for the FCL Acquisition was approximately $71.7 million, prior to a purchase price adjustment of $13.8 million in favor of the Company. The FCL Acquisition was funded through a combination of proceeds from the Prospectus Offering and the Senior Loan Facility (see below). The acquisition has contributed revenues of $81.1 million and operating income (revenue less royalties and operating costs) of $44.1 million since March 7, 2022.

LIQUIDITY AND CAPITAL RESOURCES

The Company’s approach to managing liquidity is to ensure a balance between expenditure requirements and cash used in operations and working capital. As at December 31, 2022, the Company had a working capital deficiency of $14.7 million ($0.8 million working capital deficiency at December 31, 2021). Changes in working capital have been primarily due to proceeds from equity and 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, as well as general and administrative costs, business development expenses, and acquisition costs of the Company incurred during the period.

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 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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

In 2022, the Company obtained additional equity and debt financing (see below) pursuant to the FCL Acquisition consisting of producing oil and gas assets with cash flow positive operations. These events significantly improved the financial position of the Company.

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

2023 Senior Loan Facility

In January 2023, the Company entered into a senior secured loan facility with a Canadian Chartered Bank for an aggregate principal amount of $75 million (the “ 2023 Senior Loan Facility ”). The proceeds of the 2023 Senior Loan Facility were used to pay out the existing Senior Loan Facility and fund the aforementioned 2023 asset acquisition (see above). The 2023 Senior Loan Facility is comprised of a non‐revolving two‐year term loan of $52.5 million, and a revolving credit facility of $22.5 million. The term loan carries monthly combined payments of $2 million towards principal, plus interest accrued through the two‐year term of the loan, with the balance of the principal due at maturity, as well as additional quarterly “excess cash flow” payments based upon a prescribed formula wherein 50% of excess cash flow from the recently completed quarter is paid directly against the principal of the term loan, with no penalty assessed with early repayment of any portion of the term loan principal. The term loan carries an interest rate constituted of current posted bankers’ rates plus a set margin, resulting in a current combined rate of approximately 11.2%. The revolving credit facility carries an interest rate constituted of current posted bankers’ rates plus a sliding scale margin based on a debt‐to‐cash flow ratio, resulting in a current combined rate of approximately 8.4% as of the date of this MD&A.

The Company is required to maintain certain debt covenants throughout the term of the 2023 Senior Loan Facility, as follows:

Maintain a minimum liability management rating of 2.00 in the Province of Alberta and a minimum licensee liability rating of 1.00 in the Province of Saskatchewan.
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, and on 65% of oil and gas production for a period of not less than 12 months thereafter. Please refer to “Commodity Price Risk” section below for oil and gas price hedges held by the Company as of the date of this MD&A.
Make expenditures of not less than $2,000,000 during each fiscal year toward asset retirement and abandonment and reclamation liabilities.

The 2023 Senior Loan Facility is secured by the assets of the Company and is senior to all other indebtedness of the Company.

Prospectus Offering

In March 2022, the Company completed a bought deal public offering (the “ Prospectus Offering ”) for total gross proceeds of approximately $17.3 million, whereby 95,834,100 units of the Company were issued at a price of $0.18 per unit. Each unit consisted of one Class B Share in the capital of the Company and one purchase warrant. Each purchase warrant is exercisable for one Class B Share at an exercise price of $0.25 per purchase warrant for a period of three years.

Senior Loan Facility

In March 2022, the Company entered into a senior secured loan facility with Anvil Channel Energy Solutions (“ ACES ”) for an aggregate principal amount of $65 million (the “ Senior Loan Facility ”), denominated as $51.35 million US dollars. The Senior Loan Facility bore interest at a rate of US prime interest rate plus 8% (December 31, 2022 – 15%)

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

and was being amortized over a four‐year period, with monthly combined payments of principal and interest as well as additional quarterly “excess cash flow” payments based upon a prescribed formula wherein 25% of excess cash flow from the recently completed quarter is paid directly against the principal of the Senior Loan Facility. Under the terms of the Senior Loan Facility, the Company also granted an overriding royalty to ACES on the future oil and natural gas sales from the existing oil and gas properties of the Company. The overriding royalty is 2.5% of oil and natural gas production on certain assets until the maturity date of the loan facility, and 1.5% thereafter. The Company is required to maintain certain debt covenants and other financial terms throughout the term of the Senior Loan Facility. One such covenant includes the requirement for the Company to maintain three months of debt service reserve (interest only) into a deposit account subject to a blocked account control agreement satisfactory to the Agent (the “ Debt Service Reserve ”), which ACES may withdraw from the deposit account in the event of a payment default. The initial Debt Service Reserve deposit held by the Company is $1.8 million, which was classified as restricted cash. Further financial covenants included compliance each quarter with certain financial ratios commencing for the three months ended June 30, 2022, until the maturity date of the Senior Loan Facility. Such financial ratio covenants included the following:

a minimum consolidated current ratio (consolidated current assets including restricted cash to consolidated current liabilities excluding current portion of any long‐term indebtedness of the Company) of 1:1 over the term of the Senior Loan Facility;
a minimum consolidated debt service coverage ratio (sum of interest expense payable and scheduled principal amortization payable for a certain period to consolidated earnings before interest, taxes, depreciation and amortization (“ EBITDA ”) for same such period) of a graduating range of 1.15:1 to 1.50:1 over the term of the Senior Loan Facility;
a minimum collateral coverage ratio (sum of proved developed producing reserve value (discounted at 10%) to total unpaid principal and interest balance) of a graduating range of 1.25:1 to 2.50:1 over the term of the Senior Loan Facility;
a maximum consolidated leverage ratio (consolidated total debt to consolidated annualized EBITDA) of a graduating range of 2:1 to 1:1 over the term of the Senior Loan Facility; and
a minimum liability management rating of 2.00 in the Province of Alberta and a minimum licensee liability rating of 1.00 in the Province of Saskatchewan.

As of December 31, 2022, the Company was in compliance with each of the aforementioned financial ratios, as follows:

follows:
	Required	Actual
Consolidated current ratio (minimum)	1.00	1.73
Consolidated debt service coverage ratio (minimum)	1.25	1.51
Collateral coverage ratio (minimum)	1.25	2.62
Consolidated leverage ratio (maximum)	1.50	0.75
Alberta Liability management rating (minimum)	2.00	2.94
Saskatchewan Licensee liability rating (minimum)	1.00	1.45

The Company was also required, under the terms of the loan, to enter into oil and gas price hedges on 75% of Company oil and gas production for a period of not less 24 months, and on 50% of oil and gas production for a period of not less than 12 months thereafter. Please refer to “Commodity Price Risk” section below for oil and gas price hedges held by the Company as of December 31, 2022. The Senior Loan Facility is secured by the assets of the Company and is senior to all other indebtedness of the Company.

In January 2023, the Senior Loan Facility was repaid with the establishment of the 2023 Senior Loan Facility (see above). As a result, the Debt Service Reserve deposit also became unrestricted.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Debt Note Financing

In June 2021, the Company completed the first tranche of $3,500,000 of senior secured notes of the Company (" Debt Notes "), with each Debt Note consisting of a principal amount of $1,000 and with interest payable thereon at a rate of 14% per annum over a term of three years from the date of issuance thereof (the "Note Financing"). In July 2021, a second tranche of $500,000 of Debt Notes was closed by the Company under the same terms. The maturity date of the Debt Notes was May 28, 2024; however, the Company had the option to fully repay the Debt Notes at no penalty after two years from the date of issuance. Similarly, the debtholders could demand repayment after two years from the date of issuance. Payments of interest only of approximately $150,000 per quarter were to be made during the first year of the term of the Debt Notes and blended payments of interest and principal of approximately $520,000 per quarter were to be made during the second and third year of the term of the Debt Notes. The Debt Notes were secured by the assets of the Company and were senior to all other indebtedness of the Company.

In addition, 500 purchase warrants were issued to participants in the Note Financing for each $1,000 principal amount of Debt Notes purchased, with each purchase warrant being exercisable for one Class B Share at an exercise price of $0.35 per warrant for a period of two years.

In March 2022, in connection with the FCL Acquisition and the Senior Loan Facility, the Company converted $2.8 million principal amount of the Debt Notes into units of the Company on the same terms as the Prospectus Offering. The remaining $1.2 million principal amount of the Debt Notes were fully repurchased by the Company, pursuant to the applicable terms of the Debt Notes. Interest outstanding on all Debt Notes as of the date of conversion and/or repurchase was paid in cash. This settlement on Debt Notes resulted in a loss on settlement of $320,170.

PETROLEUM AND NATURAL GAS PROPERTIES

At year end 2021, ROK had an approximate acreage position of 7,300 gross (6,500 net) acres within the Glen Ewen, Florence and Carnduff areas of Southeast Saskatchewan. This acreage has production from both the Midale and Frobisher beds.

With an additional 333,347 gross acres of land within Saskatchewan and Alberta on account of the FCL Acquisition, ROK had an approximate acreage position of 339,847 gross acres as of December 31, 2022. Subsequent to the aforementioned transactions carried out in Q1 2023, the Company’s approximate acreage position is now 355,051 gross acres with over 100 booked drilling locations (gross). Producing zones include the Midale, Frobisher, Alida and Tilston within Southeast Saskatchewan, the Viking in Southwest Saskatchewan, and the Cardium, Dunvegan, Bluesky, Gething and Montney formations within the Kaybob area of Alberta. Of significant importance within the current properties portfolio are the booked drilling locations (gross), as well as undeveloped lands that provide future growth opportunities for ROK.

Production in the fourth quarter of 2022 averaged 3,549 boe/d, which was comprised of 2,453 bbl/d of Light/Medium Oil, 219 bbl/d of Natural Gas Liquids and 5,263 Mcf/d of Natural Gas.

CORPORATE REVIEW

ROK achieved several new milestones in 2022, and continues to set new targets for the Company’s growth potential through 2023. With the aforementioned 2022 and Q1 2023 transactions, the strength of the in‐place commodity hedge portfolio, and recent reductions of Company debt levels, ROK’s financial and operational strength has greatly improved since the commencement of 2022. Management maintains its focus on light oil assets in Southeast Saskatchewan and light oil and gas assets in the Kaybob area of Alberta. As of the date of this MD&A, the Company has completed its Southeast Saskatchewan drilling program of 9 gross (8.55 net) wells, and Phases 1 & 2 of its Kaybob reactivation and workover program, with Phase 3 expected to be completed in 2023. ROK also participated in 2 gross (0.6 net) wells in the Kaybob area. Prior to divesting of Southwest Saskatchewan oil assets in Q1 2023, the Company drilled a total of 7 gross (1.5 net) non‐operated wells.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Highlights for the Company’s fourth quarter include:

Record production of 3,549 boe/d (75% liquids) for Q4 2022, an increase of 50 boe/d when compared to Q3 2022;
Net Debt of $35.3 million as of December 31, 2022. An increase of only $4.6 million from Q3 2022 end after Q4 2022 capital expenditures of $12.0 million;
Drilled the highest producing well in Saskatchewan during the month of July in the Florence area with average production rate over the first 30 days of production of approximately 300 boe/d;
Achieved 2022 capital efficiencies of just under $18,000 per boe/d on 22 gross (12.9 net) drill, complete, equip and tie‐in (“ DCET ”) and 7 gross (4.2 net) reactivation and workover capital projects, which averaged gross IP30 production of 112 boe/d (53 boe/d, net); and
Realized an annual hedge gain on commodity contracts of $4.1 million.

In 2022, the Company’s capital expenditures were as follows:

DCET: $22.6 million
Reactivations & Workovers: $2.1 million
Land and Seismic: $2.2 million
Facilities: $1.5 million

2023 CAPITAL BUDGET

The 2023 capital budget is currently estimated at $29 to $31 million, which includes 13 gross (12.2 net) wells DCET projects. The bulk of the program (10 gross (9.52 net) wells) will be drilled in the second half of 2023 within the Company’s core operating areas in Southeast Saskatchewan. The Company will also evaluate re‐entry and re‐ completion opportunities in both Saskatchewan and Alberta.

The Company will also continue to focus on reduction of abandonment and has allocated approximately $2 million to abandonments and reclamations in 2023. This will include both downhole abandonment work in addition to well and facility site reclamations in Saskatchewan and Alberta.

LITHIUM EXPLORATION PROJECT

In July 2021, the Company entered into an exploration management 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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

In 2022, the Company participated in two well testing operations on the Mansur property, resulting in sample concentrations up to 148 mg/l. In Q1 2023, ROK participated in the drilling of a new vertical well on the Viewfield property, with resulting lithium sample 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. Future operations include the drilling of additional test wells within the area as part of its continued evaluation. Further work will be done to identify surface drilling pads large enough to allow for the production of multiple horizontal wellbores within the pilot project area. Currently, the Investee holds approximately 192,000 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, 2022, expenditures reported by the Company’s partner for project activities had reached a total of $4.6 million, with the Company’s financial contribution towards the project activities equating to $787,239.

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.

DISCUSSION OF OPERATING RESULTS

Production

Production
	Q4 2022	Q4 2021	Year 2022	Year 2021
Crude oil (bbl/d)	2,453	126	1,848	105
NGLs (boe/d)	219	37	177	37
Natural gas (Mcf/d)	5,263	186	4,473	208
Total(boe/d) (1)	3,549	194	2,770	177

(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 2022	Q4 2021	Year 2022	Year 2021
Crude Oil	20,097,887	1,027,286	73,746,484	2,998,071
NGLs	1,226,162	125,359	4,489,450	302,640
Natural gas	2,601,092	59,172	9,075,608	136,171
Total	23,925,141	1,211,817	87,311,542	3,436,882

Realized Sales Prices, before Hedging

	Q4 2022	Q4 2021	Year 2022	Year 2021
Crude oil ($/bbl)	89.07	88.67	109.35	78.37
NGLs ($/boe)	60.93	31.50	69.51	22.13
Natural gas ($/Mcf)	5.37	3.06	5.56	1.80
Total($/boe)	73.28	66.49	86.36	53.24

Increases in revenue are a combination of both increased petroleum and natural gas production and improving commodity prices. Increased production is due to the additional producing assets that have been acquired over the 2021 year and the first quarter of 2022, as described above, which has offset natural production declines in the production assets that were acquired in 2020. Commodity pricing has been steadily increasing since the significant declines in global prices in March 2020 on account of the COVID‐19 pandemic, with substantial increases in Q1 2022.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Realized sales prices on petroleum and natural gas volumes sold have continued to increase as global prices have increased.

Royalties

Royalties
	Q4 2022	Q4 2021	Year 2022	Year 2021
Total royalties	4,135,298	210,907	14,321,258	636,733
Total royalties (% of sales)	17.3%	17.8%	16.4%	18.5%
Total royalties($/boe)	12.67	11.81	14.17	9.86

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 Year 2022 were 16.4 percent compared to 18.5 percent in Year 2021.

The decreases in royalty rates were primarily attributable to varying royalty rates on production from recent acquisitions when compared to royalty rates on the Company’s other producing properties.

Operating Expenses

Operating Expenses
	Q4 2022	Q4 2021	Year 2022	Year 2021
General operating	4,837,198	320,322	18,296,437	955,077
Processing and treatment	1,108,983	24,012	2,342,479	148,653
Transportation and gathering	317,653	19,307	920,360	53,343
Maintenance and workovers	1,540,629	40,308	3,796,970	201,454
Total operating expenses	7,804,463	403,949	25,356,246	1,358,527
General operating	14.82	17.94	18.10	14.79
Processing and treatment	3.40	1.34	2.32	2.30
Transportation and gathering	0.97	1.08	0.91	0.83
Maintenance and workovers	4.72	2.26	3.76	3.12
Total operatingexpenses($/boe)	23.91	22.62	25.08	21.04

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. Operating expenses in Year 2022 increased when compared to Year 2021 due to increased fixed and variable costs associated with acquired production assets. The Company’s Q4 2022 and 2021 operating expenses present costs per boe that more closely resemble average costs per boe for each respective full year. The Company estimates 2023 annualized operating expenses to be approximately $26 to $27 per boe. With a focus on improvement of operating efficiencies as the Company grows its production base, the Company’s objective is to achieve reduced operating costs over time. However, uncertainty around ongoing inflationary effects on operating costs will continue to be a contributing factor.

Gains on Commodity Contracts

Gains on Commodity Contracts
	Q4 2022	Q4 2021	Year 2022	Year 2021
Realized gain on commodity contracts	2,336,149	‐	4,124,648	‐
Unrealized gain (loss) on commodity contracts	(8,245,591)	‐	4,985,775	‐
Total	(5,909,442)	‐	9,110,423	‐

For the year ended December 31, 2022, the Company recognized realized gains of $4,124,648 on risk management commodity contracts maturing in the period and unrealized gains of $4,985,775 on existing risk management commodity contracts to mature at a future date. The unrealized gains reflect the mark‐to‐market fair value of the oil and gas price hedges in December 2022 on future oil and gas production from the Company’s oil and gas assets (see below) while realized gains/losses reflect the cash settlement on oil and gas price hedges at the time of maturity of each hedge contract. No such risk management contracts were maintained by the Company prior to Q1 2022.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Gain on Acquisition

For the year ended December 31, 2022, the Company recognized a gain on acquisition of $66.8 million in relation to the FCL Acquisition that closed in March 2022. The acquisition has been accounted for as a business combination under IFRS 3. As such, the net assets from the acquisition are to be recorded at fair value as of the closing date of the acquisition. The significant increase in fair value of the net assets when compared to the purchase price paid by the Company is primarily a result of commodity price volatility between effective and closing date of the acquisition. The original gain of $57.9 million recognized as of the closing date was adjusted for 1) reduction of $4.7 million to estimated deferred income tax liability as at the date of the acquisition, and 2) further purchase price adjustments of $4.2 million in favor of the Company as of December 31, 2022. These adjustments are being recognized retrospectively as of the closing date of the acquisition.

General and Administrative Expenses

General and Administrative Expenses
	Q4 2022	Q4 2021	Year 2022	Year 2021
Wages & Salaries	933,382	144,546	2,215,279	591,414
Professional Fees	784,523	199,060	1,479,629	385,393
Fees, Rent, Investor Relations and Other	610,649	126,847	1,535,294	570,259
Total	2,328,554	470,453	5,230,202	1,547,066

Increases in G&A expenses for Q4 2022 and Year 2022 is attributable to the overall growth and expansion of the Company’s business operations in 2022 in comparison to 2021. With the FCL Acquisition, an increase in relation to overhead, staff, and consultants costs has naturally occurred on account of increased operations. Increased efforts for investor relations with shareholders and investors has also increased overall G&A.

Business Development Expenses

Business development expenses relate to business initiatives towards the promotion, development, and growth of the Company’s operations and assets outside the normal course of the Company’s day‐to‐day endeavours. For the year ended December 31, 2022, the Company incurred business development expenses of $2,383,106 relating to efforts towards strategic acquisitions, including the FCL Acquisition (December 31, 2021 ‐ $343,066).

	Q4 2022	Q4 2021	Year 2022	Year 2021
Costs related to the FCL Acquisition	‐	‐	1,818,139	‐
Other business development expenses	96,786	228,501	564,967	343,066
Total	96,786	228,501	2,383,106	343,066

Stock‐Based Compensation

For the year ended December 31, 2022, the Company recorded stock‐based compensation expense of $1,703,002 ($369,702 for the year ended December 31, 2021). 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.

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 years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

For the year ended December 31, 2022, the Company recorded depletion expense of $19,190,812 ($759,674 for the comparative period to December 31, 2021). Depletion is calculated based on oil and gas production on the Company’s developed properties.

Net Finance Expenses

Net Finance Expenses
	Q4 2022	Q4 2021	Year 2022	Year 2021
Interest income	‐	(94)	(113)	(404)
Interest expense & bank charges	92,985	1,921	360,084	4,451
Debt interest expense	1,826,351	141,151	6,209,994	318,740
Accretion on debt	2,158,432	27,325	7,481,475	62,083
Accretion on decommissioning obligations	434,666	47,538	1,301,800	167,072
Total	4,512,434	217,841	15,353,240	551,942

Finance expenses were $15,353,240 for the year ended December 31, 2022, compared to finance expenses of $551,942 for the comparative period up to December 31, 2021. Finance expenses includes accretion on decommissioning obligations that are associated with oil and gas properties acquired, and accretion and interest expense related to Debt Notes and the Senior Loan Facility.

CAPITAL EXPENDITURES

For the year ended December 31, 2022, the Company incurred $28.4 million in capital expenditures towards drilling, completion and equipping of new wells, including surface infrastructure. In the first quarter of 2022, the Company was focused on the closing of the FCL Acquisition, with an acquisition price of $71.7 million prior to purchase price adjustments.

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.

Receivables from petroleum and natural gas marketers are normally collected on the 25[th] day of the month following production. When production is not taken in kind, payment comes from the common stream operator and facility operator in which payment is typically received on the 25[th] day of the month following production. The Company’s approach to mitigate credit risk associated with these balances is to maintain marketing relationships with established and reputable customers, common stream operators and facility operators that are considered to be creditworthy. The Company has not experienced any collection issues with its current common stream and facility operators.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Joint operations receivables are typically collected within two to three months of the joint operations billing being issued to the partner. The Company mitigates collection risk from joint operations receivables by obtaining partner approval of significant capital and operating expenditures prior to expenditure and, in certain circumstances, may collect cash deposits in advance of incurring financial obligations on behalf of joint operations partners. Joint operations receivables are from partners in the petroleum and natural gas industry who are subject to the risks and conditions of the industry. Significant changes in industry conditions and risks that negatively impact partners’ ability to generate cash flow will increase the risk of not collecting joint operations receivables.

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:

maximum exposure to credit risk for accounts re date by type of customer was:	ceivable and accruals, net of expected cr	edit loss at the reportin
Carrying Amount	December 31, 2022	December 31, 2021
Oil and natural gas customers	7,597,682	502,827
Joint operations partners	2,083,791	50,812
Accruals and other	1,181,200	‐
Total	10,862,673	553,639

The Company applies the simplified approach to providing for expected credit losses as prescribed by IFRS 9, which permits the use of lifetime expected loss provision for all accounts receivable and accrued receivables. The expected credit losses below also incorporate forward looking information.

Aging	December 31, 2022	December 31, 2021
0 ‐ 30 days	9,435,073	505,019
30 ‐ 90 days	871,954	28,536
Greater than 90 days	555,646	20,084
Expected credit loss	‐	‐
Total	10,862,673	553,639

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. At December 31, 2022 there were no material receivables which were considered uncollectible (December 31, 2021 ‐ $nil).

The Company held cash and cash equivalents of $5,258,881 as at December 31, 2022 (December 31, 2021 ‐ $1,208,776). 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.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due and describes the Company’s ability to access cash. The Company’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient cash resources in order to finance operations, fund capital expenditures, and to repay debt and other liabilities of the Company as they come due, without incurring unacceptable losses or risking harm to the Company’s reputation. The Company’s processes for managing liquidity risk include preparing and monitoring capital and operating budgets, coordinating and authorizing project expenditures, and authorization of contractual agreements. Management and the Board of Directors use budgets and forecasts to direct and monitor the strategy, operations and liquidity of the Company as well as the ongoing ability of the Company to remain in compliance with its commitments and the terms and covenants associated with its Senior Loan Facility (see above)

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

and subsequent to year end with the new 2023 Senior Loan Facility (see above). The budgets are updated when required as conditions change.

The following table outlines the contractual maturities of the Company’s financial liabilities at December 31, 2022:

	Less than 1year	1‐2years	Thereafter	Total
Accounts payable	13,678,677	‐	‐	13,678,677
Senior Loan Facility ‐ principal(1)	22,168,565	14,344,366	6,834,635	43,347,566
Senior Loan Facility‐ interest	4,965,480	2,100,481	348,430	7,414,391
	40,812,722	16,444,847	7,183,065	64,440,634

(1) Principal payments outlined above only reflects minimum principal payments required on a monthly basis.

Volatility in commodity prices in the oil and gas sector creates inherent challenges with the preparation of financial forecasts and may ultimately lead to adverse changes in the Company’s future cash flows, working capital levels and/or debt balances. These and other factors may adversely affect the Company’s liquidity and the ability to generate profits and cash flows in the future as well as the ability of the Company to remain in compliance with the terms and covenants of its Senior Loan Facility.

Market risk

Market risk is the risk or uncertainty that changes in price, such as commodity prices, foreign exchange rates, and interest rates will affect the Company’s net earnings and the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. From time to time, the Company may utilize financial derivative contracts to manage market risks in accordance with the risk management policy that has been approved by the Board of Directors. The Company’s consolidated balance sheet at December 31, 2022 includes risk management assets for crude oil, natural gas and liquids derivative contracts recorded at a net positive fair market value of $5.0 million. The Company’s consolidated statement of comprehensive income (loss) for the year ended December 31, 2022, includes unrealized gains on risk management contracts of $5.0 million.

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:

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Derivative swap contracts[(1)(2) ]

			Crude Edmonton	Crude Edmonton
	WTI Crude		Light Differential		AECO(3)		Propane
	Volumes		Volumes		Volumes	US$/	Volumes
Period	(bbl/d)	US$/bbl	(bbl/d)	US$/bbl	(mmbtu/d)	mmbtu	(gal/d)	US$/gal
Q1 2023	1,488	89.70	1,102	(4.31)	4,178	3.26	4,038	1.25
Q2 2023	1,825	85.14	1,057	(4.09)	5,507	2.20	3,924	1.05
Q3 2023	1,762	82.73	1,017	(4.25)	5,267	2.13	3,712	1.01
Q4 2023	1,710	80.50	981	(4.48)	5,165	2.48	3,586	1.02
Q1 2024	1,647	77.60	‐	‐	4,980	2.65	3,400	0.99
Q2 2024	1,380	73.77	‐	‐	4,338	2.63	3,176	0.78
Q3 2024	1,344	72.06	‐	‐	4,176	2.62	2,079	0.76
Q4 2024	1,300	69.92	‐	‐	4,000	2.61	‐	‐
Q1 2025	1,255	68.95	‐	‐	4,000	2.62	‐	‐

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

(2) Swaps include trades in US$ and CAD. Canadian swaps are converted from CAD to US$ 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, during the year ended December 31, 2022, the Company was exposed to the risk of changes in the US dollar/Canadian dollar exchange rate on the US denominated Senior Loan Facility, with debt service payments denominated in US dollars. As of the date of these financial statements, the US denominated Senior Loan Facility had been repaid in full through the Canadian dollar denominated 2023 Senior Loan Facility (see above).

The Company is exposed to the risk of fluctuations in foreign exchange rates between the Canadian dollar and the US dollar (US$) 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). As of December 31, 2022, the Company had not entered into any foreign currency derivatives. However, subsequent to December 31, 2022, the Company entered into the following foreign currency derivatives to manage its exposure to currency fluctuations:

Derivative US$/CAD average rate variable rate collar contracts

Period	US$ (millions)	Floor	Reset	Trigger
Q1 2023	3.7	1.32	1.34	1.37
Q2 2023	10.2	1.32	1.34	1.37
Q3 2023	9.6	1.32	1.34	1.37
Q4 2023	9.0	1.32	1.34	1.37

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. As at December 31, 2022, the Company was exposed to interest rate risk on the Senior Loan Facility, with interest at US prime interest rate plus 8% per annum. Subsequently in 2023, the Senior Loan Facility has been

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

replaced by the 2023 Senior Loan Facility (see above). 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, 2022, if interest rates applicable to the floating US prime interest rate 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 $178,000 for the year ended December 31, 2022. This assumes that the change in interest rate is effective from the beginning of the Senior Loan Facility on March 7, 2022.

Fair value of financial instruments

The Company’s financial instruments as at December 31, 2022, include cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities, risk management contracts, and Senior Loan Facility.

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 the Senior Loan Facility 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 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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

	Dec 31, 2022	Dec 31, 2021
Senior Loan Facility (15%)(1)	43,347,566	‐
Debt Notes (14%)(1)	‐	4,000,000
Less: adjusted workingcapital(2)	8,006,020	478,610
Net debt	35,341,546	3,521,390

(1) Represents undiscounted face value of debt balances outstanding as of each respective date presented.

(2) Calculation of working capital excludes current portion of debt as presented on the statement of financial position.

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.

SHAREHOLDERS’ EQUITY

Common shares

At December 31, 2022, the Company was authorized to issue an unlimited number of Class B Shares, with no par value, with holders of Class B Shares entitled to two votes per share and to dividends, if declared. Outstanding Class B Shares as of December 31, 2022, are as follows:

value, with holders of Class B Shares entitled to two votes per B Shares as of December 31, 2022, are as follows:	share and to dividends, if declared	. Outstanding Class
	Class B shares	Amount
Balance, December 31, 2020	58,996,576	3,607,761
Shares issued for asset acquisitions	4,250,000	785,000
Private placement	11,000,000	1,875,359
Stock option exercise(1)	225,000	41,147
Balance, December 31, 2021	74,471,576	6,309,267
Prospectus Offering, March 2022	95,834,100	11,691,720
Shares issued for Debt Note conversion (Note 9)	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

(1) Of the 300,000 stock options exercised during the year ended December 31, 2021, common shares were issued for 225,000 of those stock options prior to December 31, 2021. Shares for the remaining 75,000 stock options were issued during the year ended December 31, 2022.

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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

A summary of the changes in warrants is presented below:

A summary of the changes in warrants is presented below:
		Weighted average
	Warrants	exercise price
Balance, December 31, 2020	17,758,975	0.18
Purchase warrants issued, private placement	5,500,000	0.35
Broker warrants issued, private placement	280,000	0.35
Purchase warrants issued, Note Financing	2,000,000	0.35
Balance, December 31, 2021	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 exercise	4,612,505	0.25
Warrant exercised	(25,224,258)	0.15
Warrant expiries	(7,500)	0.15
Balance, December 31, 2022	122,434,426	0.26

The following summarizes information about total purchase warrants outstanding as at December 31, 2022:

	Number of warrants	Weighted average term to	Number of warrants
Exercise prices	outstanding	expiry (years)	exercisable
0.18	1,512,549	2.18	1,512,549
0.25	113,141,877	2.18	113,141,877
0.35	7,780,000	0.25	7,780,000
	122,434,426	2.06	122,434,426

Subsequent to December 31, 2022, a total of 375,000 warrants expiring in April 2023, 325,000 warrants expiring in May 2023, and 250,000 warrants expiring in June 2023 were exercised resulting in the issuance of 950,000 common shares. Gross proceeds of $332,500 were received by the Company on account of these warrant exercises.

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

		Weighted average
	Stock options	exercise price
Balance, December 31, 2020	2,740,000	0.13
Options issued	4,150,000	0.28
Options exercised(1)	(300,000)	0.10
Balance, December 31, 2021	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
Exercisable, December 31, 2022	9,006,675	0.24

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

The following summarizes information about stock options outstanding as at December 31, 2022:

	Number of options	Weighted average term to	Number of options
Exercise prices	outstanding	expiry (years)	exercisable
0.10	420,000	0.55	420,000
0.15	1,600,000	1.93	1,600,000
0.25	10,343,333	4.23	3,503,339
0.28	4,050,000	3.56	2,699,997
0.30	1,550,000	4.67	516,672
0.35	800,000	4.84	266,667
	18,763,333	3.87	9,006,675

As of the date of this MD&A, the Company maintained balances of 212,613,817 Class B Shares, 121,484,426 warrants, and 18,680,000 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, 2022. 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.

Financial derivative instruments policy

Financial derivative instruments are included in current assets and liabilities except for those with maturities greater than 12 months after the end of the reporting period, which are classified as non‐current assets and liabilities. The Company has not designated any of its financial derivative contracts as hedging instruments. The Company's financial derivative instruments are classified as financial assets or liabilities at fair value through profit or loss and are reported at fair value with changes in fair value recorded in net income or loss. The Company accounts for its forward physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non‐financial items, in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the consolidated balance sheet. Realized gains or losses from physically settled commodities sales contracts are recognized in petroleum and natural gas sales as the contracts are settled.

Voluntary change in accounting policy

Under the Company’s previous accounting policy, ROK used a risk‐free rate based on the Bank of Canada published bond rates in the measurement of the present value of its decommissioning obligations. Effective January 1, 2022, the Company has now elected to change its policy for the measurement of decommissioning obligations to utilize a credit‐adjusted rate. The use of a credit‐adjusted rate results in reliable and more relevant information for the readers of the financial statements as this methodology provides a more accurate representation of the value at which such liabilities could be transferred to a third party, provides a better indication of the risk associated with such obligations, and increases the comparability of the Corporation’s financial statements to those of its peers.

Management has applied the voluntary change in accounting policy retrospectively, including the restatement of certain comparative amounts with the Financial Statements. The impact of the change in accounting policy is presented within Note 4 of the audited annual financial statements for the year ended December 31, 2022.

With the exception of the aforementioned, there were no material changes in the Company’s significant accounting policies from those disclosed in the 2021 audited annual financial statements.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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.

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) Exploration and evaluation assets

The application of the Company’s accounting policy for exploration and evaluation assets requires management to make certain judgments as to future events and circumstances as to whether economic quantities of reserves have been found in assessing economic and technical feasibility.

iii) Impairment of property, plant and equipment and exploration and evaluation assets

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 oil and natural gas prices, forecasted operating costs, royalties, and future development costs, discount rates, market value of land and other relevant assumptions.

iv) 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.

v) 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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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 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 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 in a business combination. Further, the Company uses estimated proved and probable petroleum and natural gas reserves to deplete property, plant and equipment, to assess for indicators of impairment or impairment reversal on each of the Company’s cash generating units (“CGU”) and if any such indicators exist, to perform an impairment test to estimate the recoverable amount of a cash generating unit. For purposes of estimating the fair value of the property, plant and equipment acquired in a business combination (see above) and the Company’s depletion calculations, the Company used the April 1, 2022, and December 31, 2022, 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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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 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 and its 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 the aforementioned 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 (see above), 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 were issued to certain directors and officers of the Company.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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:

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

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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 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. 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

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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.

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

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

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.

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.

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

Readers are cautioned that the foregoing lists of assumptions, risks and uncertainties are not exhaustive. The 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.

KEY FINANCIAL RESULTS

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

Annual Financial Results ($)	Year 2022	Year 2021	Year 2020
Total revenue	87,311,542	3,436,882	598,488
Net income (loss)	80,002,750	(2,316,717)	(1,168,993)
Net income (loss) per share:
Basic	0.46	(0.03)	(0.03)
Diluted	0.40	(0.03)	(0.03)
Working capital (deficit)	(14,729,229)	(854,723)	1,596,525
Total assets	192,078,125	10,597,242	4,405,470
Total non‐current liabilities	46,156,628	3,808,242	1,110,784

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 commenced in the Q2 2020, with additional acquisitions of producing assets in both 2021 and 2022, 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. The addition of the Senior Term Facility in Q1 2022 also significantly increased the overall liabilities and finance expenses of the Company in comparison to previous years. 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 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)	(5,556,994)	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

Quarterly Results ($)	Q4 2021	Q3 2021	Q2 2021	Q1 2021
Oil and natural gas sales	1,211,817	1,075,829	709,209	440,027
Oil and natural gas sales, net of royalties	1,000,910	870,472	572,932	355,835
Net loss	(639,279)	(919,222)	(386,530)	(371,687)
Net loss per share (basic & diluted)	(0.01)	(0.01)	(0.01)	(0.01)

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

For the years ended December 31, 2022 and 2021

Management’s Discussion & Analysis

==> picture [62 x 30] intentionally omitted <==

operating results from the acquisition of new producing assets, additional financing costs, and share‐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 2021 and 2022 have 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 2022 and increased production from recent 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 2021 and 2022 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 on commodity contracts and effects of deferred tax were additional contributors to quarterly net income (loss).

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

For the years ended December 31, 2022 and 2021

AI assistant

ROK Resources Inc. — Management Reports 2023

45743_rns_2023-04-13_d3515d06-06d5-40f5-9315-48466c9051b3.pdf

MANAGEMENT’S DISCUSSION & ANALYSIS

FINANCIAL AND OPERATING HIGHLIGHTS

INTRODUCTION

NON‐IFRS MEASURES

Funds Flow

Operating Income, Netback, and Operating Profit Margin

Net Debt

BUSINESS PROFILE AND STRATEGY

2023 ASSET ACQUISITION

2023 ASSET DISPOSITIONS

FCL ACQUISITION

LIQUIDITY AND CAPITAL RESOURCES

2023 Senior Loan Facility

Prospectus Offering

Senior Loan Facility

Debt Note Financing

PETROLEUM AND NATURAL GAS PROPERTIES

CORPORATE REVIEW

2023 CAPITAL BUDGET

LITHIUM EXPLORATION PROJECT

COMMITMENT SUMMARY UPDATE

DISCUSSION OF OPERATING RESULTS

Production

Oil and Natural Gas Sales

Realized Sales Prices, before Hedging

Royalties

Operating Expenses

Gains on Commodity Contracts

Gain on Acquisition

General and Administrative Expenses

Business Development Expenses

Stock‐Based Compensation

Depletion and Depreciation

Net Finance Expenses

CAPITAL EXPENDITURES

FINANCIAL RISK MANAGEMENT

Credit risk

Liquidity risk

Market risk

Commodity price risk

Foreign currency risk

Interest rate risk

Fair value of financial instruments

Capital management

SHAREHOLDERS’ EQUITY

Common shares

Warrants

Stock options

NEW ACCOUNTING STANDARDS

Financial derivative instruments policy

Voluntary change in accounting policy

USE OF ESTIMATES AND JUDGMENTS

Critical judgments in applying accounting policies

i) Identification of cash‐generating units

iii) Impairment of property, plant and equipment and exploration and evaluation assets

iv) Income taxes

v) Asset Acquisitions

Key sources of estimation uncertainty

i) Reserves and resource assessment

ii) Decommissioning obligations

iii) Business combinations

iv) Share‐based payments

v) Tax provisions

Matters relating to economic uncertainty

Changing regulations

RELATED PARTY TRANSACTIONS

PRINCIPAL BUSINESS RISKS

Crude Oil and Natural Gas Development

Addition of Reserves and Resources

Reserve Estimates

Exploration Risks

Environmental Risks

Climate Change Risks

Key Personnel

Public Market Risk

Dividends

Failure to Maintain Listing of the Class B Shares

ROK Resources Inc. Management Reports 2023