Alpine Summit Energy Partners, Inc.: Exhibit 99.2

The accompanying unaudited interim consolidated financial statement of Alpine Energy Summit Partners. Inc. (the
"Company") have been prepared by and are the responsibility of management. The unaudited interim consolidated financial
statements have not been reviewed by the Company's auditors.

Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statements of Financial Position
(unaudited)(amounts in US dollars)
As at

Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statements of Loss and Comprehensive Loss

For the three and nine months ended September 30, 2021 and 2020
(unaudited)(amounts in US dollars)

Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statement of Changes in Shareholders' Equity/(Deficiency)
(amounts in US dollars)
(Unaudited)

Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statements of Cash Flows

For the three and nine months ended September 30, 2021 and 2020
(unaudited)(amounts in US dollars)

Alpine Summit Energy Partners, Inc. (formerly Red Pine Petroleum Ltd)
Notes to the interim consolidated financial statements
For the three and nine months ended September 30, 2021 and 2020
(amounts in US dollars)(Unaudited)

Alpine Summit Energy Partners, Inc. (formerly Red Pine Petroleum Ltd. ("Red Pine") (the "Company" or "Alpine") was incorporated on July 30, 2008 under the Business Corporations Act (British Columbia) ("BCBCA"). On April 8, 2021, the Company entered into a Business Combination Agreement ("BCA") pursuant to which the Company agreed to complete the BCA with HB2 Origination LLC ("Origination") and change its name to "Alpine Summit Energy Partners, Inc." upon completion of the BCA (refer to Note 2 for a complete description of the BCA).

The Company's registered office is located at 2200 HSBC Building, 885 West Georgia Street Vancouver BC V6C 3E8 and its principal office is located at 3322 West End Ave. Suite 450 Nashville TN 37203.

These interim consolidated financial statements were approved and authorized for issuance by the Board of Directors of the Company on November 22, 2021.

On April 8, 2021, Alpine, Origination, Alpine Summit Energy Partners Finco, Inc ("Finco"), Red Pine Petroleum Subco Ltd. ("Subco") and Alpine Summit Energy Investors, Inc. ("Blocker") entered into the BCA pursuant to which the parties agreed to complete a series of transactions to effect a business combination between Alpine and Origination and that resulted in a reverse take-over of Alpine by the members of Origination.

(1) Finco issued subscription receipts for gross proceeds of approximately CDN$7.5 million (Note 13) and "The Finco Financing" later in note 2;

(a) Alpine amended its articles to (i) reclassify its common shares as Subordinate Voting Shares ("SVS"), (ii) create a new class of Multiple Voting Shares ("MVS") and a new class of Proportionate Voting Shares ("PVS"), and (iii) change its name from "Red Pine Petroleum Ltd." to "Alpine Summit Energy Partners, Inc.";

(b) each outstanding membership unit of Origination ("Origination Member Unit") would be converted into three membership units of Origination;

(c) the Subscription Receipts converted into Finco Shares, with each holder of a Subordinate Voting Subscription Receipt receiving one Class A Finco Share in exchange therefor and each holder of a Multiple Voting Subscription Receipt receiving one Class B Finco Share in exchange therefor; and

(a) the Company, Finco and Subco completed a three-cornered amalgamation under the BCBCA pursuant to which all Finco shareholders (including former holders of the Subscription Receipts) exchanged their Class A Finco shares held for SVS or their Class B Finco Shares held for Multiple Voting Shares, as applicable, in each case on a one-for-one basis, and Finco and Subco amalgamated, with the resulting entity ("Amalco") to continue as a wholly-owned subsidiary of Alpine;

(b) Amalco wound up into Alpine and the assets of Amalco (which consist of the funds invested by the holders of the Subscription Receipts, net of expenses) transferred to the Company by operation of law;

(c) certain U.S. holders of Origination Member Units (other than Blocker) contributed their Origination Member Units to the Company in exchange for MVS on a one-hundred membership units for one MVS basis;

(d) certain of the non-U.S. holders of Origination Member Units contributed their Origination Member Units to the Company in exchange for SVS on a one membership unit for one SVS basis subject to adjustment for any applicable withholding taxes;

(e) each holder of Blocker Shares contributed their Blocker Shares to the Company in exchange for SVS on a one Blocker Share for three SVS basis;

(f) A related party, being an officer, director and shareholder of Origination pre-closing of the BCA, and of Alpine post closing of the BCA, subscribed for 15,947.292 PVS carrying voting rights that would, in the aggregate, represent approximately 32.2% (Note 13) of the voting rights of the Company upon completion of the BCA on a fully diluted basis for a purchase price equivalent to their estimated fair market value of USD$128,213;

(g) the Company used certain proceeds of the Finco Financing and the membership units of Origination received by it to subscribe for Blocker Shares, following which the proceeds of Finco Financing received by Blocker were contributed to Origination in exchange for membership units of Origination; and

(h) Origination Member Units held by Blocker were re-designated as Class A Voting Units of Origination and Origination Member Units held by other remaining members of Origination were re-designated as Class B Non-Voting Units of Origination.

The number and terms of the securities to be issued in connection with the BCA were determined pursuant to arm's length negotiations between the management of each of the Company and Origination at the time the BCA was entered into.

The reclassification of the common shares of the Company into SVS and the creation of the MVS in connection with the BCA is for the purpose of allowing the Company to maintain its status as a "foreign private issuer" as determined in accordance with Rule 3b-4(c) under the U.S. Exchange Act.

On August 18, 2021, Finco completed a brokered private placement of an aggregate of 161,976 subordinate voting subscription receipts at a subscription price of CDN$4.01 per subordinate voting subscription receipt and 17,057 multiple voting subscription receipts at a subscription price of CDN$401.29 per multiple voting subscription receipt for aggregate gross proceeds of approximately CDN$7.5 million (USD$ 5,995,461). Finco is a special purpose British Columbia company incorporated solely for the purpose of the Finco financing.

The Finco Financing was completed pursuant to the terms of an agency agreement dated August 18, 2021 among Finco, the Company and Eight Capital ("Agent"), as lead agent and sole bookrunner (the "Agency Agreement"). The subscription receipts are governed by the terms of a subscription receipt agreement (the "Subscription Receipt Agreement") dated August 18, 2021 among Finco, the Agent and Odyssey Trust Company in its capacity as subscription receipt agent.

Each subordinate voting subscription receipt and each multiple voting subscription receipt entitled the holder thereof to receive, upon automatic exchange in accordance with the terms of the Subscription Receipt Agreement, without payment of additional consideration or further act or formality on the part of the holder thereof, one Class A Finco share and one Class B Finco share, respectively, upon the satisfaction or waiver of the escrow release conditions at or before the escrow release deadline. Each Class A Finco share would then be exchanged for one SVS and each Class B Finco share would be exchanged for one MVS upon completion of the BCA.

In connection with the Finco financing, the Agent was entitled to receive a cash commission of CDN$26,525 and an advisory fee of CDN$197,500 (collectively, the "Agent's Fees"). On closing of the Finco financing, the Agent received payment of 50% of the Agent's Fees. The remaining 50% of the Agent's Fees paid to the Agent upon the satisfaction of the escrow release conditions.

On September 7, 2021, the Company completed the BCA (as described above). As a result of the transaction, the former shareholders of Origination acquired control of the combined Company and, thereby constitutes a reverse takeover of Red Pine by Origination. The BCA is considered a purchase of the Red Pine's net assets by Origination. The transaction is accounted for in accordance with guidance provided in IFRS 2 Share-Based Payments.

As Red Pine did not qualify as a business according to the definitions in IFRS 3, the BCA does not constitute a business combination; rather, it is treated as an issuance of Alpine shares for the net assets of Red Pine and Red Pine's listing status with Alpine as the continuing entity. The resulting interim consolidated financial statements are presented as a continuation of Origination and comparatives figures presented in the interim consolidated financial statements of are those of Origination.

As a part of the reverse takeover the Company issued 534,384 SVS on September 7, 2021, for total consideration of $1,697,865 based on the Finco financing value of CDN$4.01/SVS or US$3.18/SVS, for the Red Pine net assets, which are made up primarily of cash valued at $396,173. The excess of purchase consideration over net assets acquired resulted in a listing expenses of $1,301,692 and is presented in the interim consolidated statement of loss and comprehensive loss.

Acquisition related costs totalling $1,567,967 have been excluded from consideration paid and were recognized as transaction costs on the consolidated statement of loss and comprehensive loss for the period ended September 30, 2021 when the costs were incurred.

These interim financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRSs") as issued by the International Accounting Standards Board ("IASB"). A summary of the significant accounting policies and method of computation is presented in Note 4. Management's significant accounting judgements, estimates and assumptions used in the preparation of the consolidated financial statements are included in Note 3.

These financial statements have been prepared in accordance with IFRS applicable to a going concern, which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business.

During the nine months ended September 30, 2021, the Company generated a net loss and comprehensive loss of $51,614,575 (year ended December 31, 2020 - $7,530,178), and as at that date, the Company had a working capital deficiency of $80,891,770 (December 31, 2020 - working capital deficiency of $29,102,456) and accumulated deficit of $92,542,554 (December 31, 2020 - $39,757,844).

In order to continue operating as a going concern the Company will need to achieve profitable operations and/or secure additional sources of financing in order to satisfy its obligations, including scheduled repayments of long-term debt, as they become due. During the nine months ended September 30, 2021 the Company issued 1,173,085 Origination Member Units in exchange for cash of $8.0 million, 161,976 SVS and 17,057 MVS for cash of $5.5 million net of issuance costs, and extinguished promissory notes of $3.5 million (Note 10). The Company formed two development partnerships to fund a portion of 2021 capital activity which raised approximately $34 million during the nine months ended September 30, 2021 and subsequent to period end (Note 7 and 8). In addition, the Company issued convertible promissory notes in June 2021 (Note 10) for proceeds of $2.3 million and converted those convertible promissory notes into 234,216 Origination Member Units (Note 10). The Company also repaid $15.2 million of long-term debt (Note 9) and $4.7 million of asset backed preferred instruments (Note 12). Although the Company has been successful in its financing activities to date, additional financing may be required to continue operations and such funding may not be available on terms that are acceptable to the Company.

Due to the factors mentioned above, there is a material uncertainty that may cast significant doubt on the Company's ability to continue as a going concern. These financial statements do not include necessary adjustments to reflect the recoverability and classification of recorded assets and liabilities and related expenses that might be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and liquidate its liabilities and commitments in other than the normal course of business and such adjustments could be material.

The consolidated financial statements have been prepared on the historical cost basis except as otherwise stated and allowed for in accordance with IFRS.

These interim consolidated financial statements are presented in US dollars ("$"). The Company's functional currency is Canadian dollars, however all of the Company's individual subsidiaries have functional currencies in US$ which represents the primary economic environment in which the entities operate.

(e) Management's significant accounting judgements, estimates and assumptions

The timely preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions based on currently available information that affect the application of accounting policies and reported amounts of assets and liabilities at the date of the statement of financial position and the reported amounts of income and expenses during the reporting period. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions and judgements 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.

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus ("COVID-19"). The pandemic and subsequent measures intended to limit its spread, contributed to significant volatility in global financial markets. The pandemic has adversely impacted global commercial activity and has reduced worldwide demand for commodities including crude oil. The result was significant economic uncertainty and a decline in commodity prices through most of 2020. In general, the oil and gas industry reacted with reductions to capital and other spending, as well as production shut-ins, to try to manage through this price environment. The full extent of the impact of COVID-19 on the Company's operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on financial markets on a macro-scale and any new information that may emerge concerning the effectiveness of available vaccines and the severity and spread of the virus. The pandemic presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by management in the preparation of its financial results. The Company's financial performance, operations and business are particularly sensitive to a reduction in the demand for prices of crude oil and natural gas. The potential direct and indirect impact of the economic downturn related to COVID-19 have been considered in management's estimates and assumptions at period end and have been reflected in the Company's results with any significant changes described in the relevant financial statements notes.

More specifically, assumptions may change that are involved in the estimates of valuation of exploration and

evaluation assets and property, plant and equipment cash generating units, the timing of decommissioning obligations, the fair value of commodity contracts, the expected credit loss provisions related to accounts receivable as well as liquidity and going concern assessments.

Significant estimates, judgements and assumptions made by management in the preparation of these interim consolidated financial statements are outlined below.

The following are the significant judgements, and assumptions 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 these consolidated financial statements:

The Company's oil and natural gas interests are aggregated into cash-generating units for both property and equipment and exploration and evaluation assets, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows. The classification of assets into CGU's requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, external users, shared infrastructures and the way in which management monitors the Company's operations. The Company has identified only one CGU as at September 30, 2021.

Judgements 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 of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of undeveloped lands and other relevant assumptions.

For the purposes of calculating depletion expense, the Company allocates its oil and natural gas assets to components with similar lives and depletion methods. The grouping of assets is subject to management's judgement and is performed on the basis of geographical proximity and similar reserve life. The Company's oil and natural gas assets are depleted on a unit of production basis.

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

The Company is party to various joint interest, operating and other agreements in conjunction with its oil and natural gas activities. The revenues and expenses allocated between partners are governed by the terms of these agreements that are subject to interpretation and judgement by the Company and audit by the appropriate parties.

Judgements are required to determine if acquisitions of assets or groups of assets constitute a business combination. These judgements include assessing whether the acquired assets include inputs, processes and outputs that would constitute a business and whether the assets acquired meet the criteria of the optional concentration test to not be considered a business.

The Company follows the liability method of for calculating deferred taxes. Judgement is required in calculation of current and deferred taxes in applying tax laws and regulations estimating the timing of reversals of temporary differences and estimating the realizability of deferred tax assets.

The following are the key estimates and related 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.

The assessment of reported recoverable quantities of proved and probable reserves include estimates regarding production volumes, commodity prices, exchange rates, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact the carrying values of the Company's oil and natural gas properties and equipment, the calculation of depletion and depreciation, and the provision for decommissioning liabilities.

The reserve assessment was completed by an external third-party engineering firm for the years ended December 31, 2020 and reserves are internally updated for interim periods.

The calculation of decommissioning liabilities and related accretion expense requires estimates of 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. In addition, the calculation 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.

The amounts recorded for the fair value of commodity contracts is dependent on estimates of future commodity prices, foreign exchange rates and volatility in those prices.

Certain amounts included in accounts receivable are based on management's best estimate of the lifetime expected credit loss related to these accounts.

The amounts recorded for depletion of petroleum and natural gas assets are determined by useful life and future cash flows which are based on estimates of future production profiles and reserves for surrounding wells, commodity prices and discount rates.

The amounts recorded for the fair value of the development partnerships liabilities are based on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, and other relevant assumptions.

The allocation between the debt and equity components of convertible promissory notes is based on estimates of the market interest rate the Company would pay on non-convertible debt instruments with similar terms.

The Company consolidates 100% of the operations, assets and liabilities of the development partnerships which is based on an analysis of the terms of the various partnership agreements and whether they give the Company control of the partnerships and the right to variable returns.

(ix) Current and long-term classification related to asset backed preferred instrument and development partnership liabilities

The current and long-term classification related to the asset back preferred instrument is based on management's assessment of what operational cash flow is going to be available to repay the instrument based on the terms of the underlying agreements. The current and long-term classification related to development partnership liabilities is based on management's assessment of the future net cash flows to be generated by the wells included in the partnerships.

The accounting policies set out below have been applied consistently to all periods presented in these financial statements.

The consolidated financial statements include the accounts of the Company and its subsidiaries as at September 30, 2021, HB2 Origination, LLC (67.5%) and 100% of AIP Holdco GP, LLC AIP Holdco, LP, AIP Intermediate, LLC, AIP Borrower GP, LLC, AIP Borrower, LP, Alpine Summit Energy Investors, Inc, Alpine CapH4 LLC, Ageron Energy II, LLC, HB2 Midco, LLC, Alpine Maverick I GP, LLC, Alpine Maverick I L.P., Alpine Maverick II GP, LLC and Alpine Maverick II LP, LLC.

The Company has control of an investee entity when it is exposed, or has rights, to variable returns from its involvement in the investee and has the ability to affect those returns through its power over the investee. Subsidiaries are fully consolidated on a line-by-line basis, recognizing all their assets, liabilities, income and expenses and recording any non-controlling interest for the portion not owned by the Company from the date on which control in obtained. Intercompany transactions and balances between the Company and its subsidiaries are eliminated. Transactions with non-controlling interests that do not result in loss of control are accounted for as equity transactions. The difference between fair value of any consideration paid and the acquired share of the carrying value of nets assets of the subsidiary is recorded in equity. Gains or losses on disposals to non-controlling interests are also recorded in equity.

A portion of the Company's oil and natural gas business activities involve jointly controlled assets and are conducted under joint operating agreements. The Company has assessed the nature of its joint arrangements and determined them to be joint operations. These consolidated financial statements reflect only the Company's proportionate share of the joint operation's controlled assets and liabilities it has incurred, its share of any liabilities jointly incurred with other joint interest partners, income from the sale or use of its share of the joint operation's output, together with its share of expenses incurred by the joint operation and any expenses it incurs in relation to its interest in the joint operation and a share of production in such activities.

Business combinations are accounted for using the acquisition method when the acquisitions of companies and/or assets meet the definition of a business under IFRS. The cost of an acquisition is measured at the fair value of the assets given up, equity instruments issued and liabilities incurred or assumed at the date of acquisition. The acquired identifiable assets and liabilities and any contingent consideration are measured at their fair value at the date of acquisition. The fair value of property, plant and equipment is the estimated amount for which these assets could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgably, prudently and without compulsion. Any excess of the purchase price over the fair value of the identifiable assets and liabilities acquired is recognized as goodwill. If the cost of acquisition is less than fair value of the identifiable assets and liabilities, the difference is recorded as a gain in profit or loss. Associated transaction costs are expensed when incurred.

A number of the Company's accounting policies and disclosures require the determination of fair value for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining the fair values is disclosed in the notes specific to that asset or liability.

The Company classifies fair values according to the following hierarchy based on the amount of observable inputs used to value the instruments:

The fair value of cash approximates its carrying value due to the short-term to maturity.

Accounts receivable, accounts payable and accrued liabilities, promissory notes, and long-term debt

The fair value of accounts receivable, accounts payable and accrued liabilities, promissory notes, and long-term debt are estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. As at September 30, 2021 and December 31, 2020, the fair value of accounts receivable, accounts payable and accrued liabilities and promissory notes approximated their carrying value due to their short term to maturity. The fair value of long-term debt approximates its carrying value as it bears a floating market rate of interest.

The fair value of financial forward contracts and swaps is determined by discounting the difference between the contracted prices and published forward curves at the statement of financial position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate adjusted for the credit risk of the counterparty. The Company has used Level 2 to determine the fair value of its commodity contracts.

The amounts recorded for the fair value of the development partnerships liabilities are determined by discounting the estimated future payments required based on estimates of future cash flows to be generated by the underlying reserves in the partnerships. The Company has used Level 3 to determine the fair value of development partnership liabilities.

The fair value less costs of disposal values used to determine the recoverable amounts of property, plant and equipment and exploration and evaluation assets, if it is higher than value in use, are classified as Level 3 fair value measurements as they are not based on observable market data.

Foreign currency translation includes the translation of foreign currency transactions and the translation of foreign operations.

Foreign currency transactions translations occur when translating transactions and balances in foreign currencies to the applicable functional currency of the Company and its subsidiaries. Gains and losses from foreign exchange transactions are recorded as foreign exchange gains and losses in the statement of income (loss). Foreign currency transactions translation occur as follows:

Foreign operation translation occurs when translating the financial statements of the Canadian parent Company to the US dollar reporting currency. Gains and losses from foreign operation translations are recorded in the statement of changes in shareholders equity(deficiency). Foreign operation translation occurs as follows,

On initial recognition, financial instruments are measured at fair value. Measurement in subsequent periods

depends on their context within the Company's business model and the characteristics of the contractual cash flows as described below:

Debt issuance costs related to borrowings measured at amortized cost are amortized to finance expense over the term of the borrowings using the effective interest method.

The Company has entered into certain financial risk management contracts in order to manage the exposure to market risks from fluctuations in commodity prices and interest rates. The Company has not designated its financial risk management contracts as effective accounting hedges and, therefore, has not applied hedge accounting, even though the Company considers all risk management contracts to be economic hedges. As a result, all financial risk management contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in the statement of loss and comprehensive loss as incurred.

Impairment of financial assets is based on expected credit losses. The Company's accounts receivable are considered collectible within one year or less; therefore, these financial assets are not considered to have significant financing component and a lifetime expected credit loss ("ECL") is measured as the date of initial recognition.

The Company assesses the lifetime ECL applicable to its accounts receivable at initial recognition and re-assesses the provision at each reporting date. Lifetime ECLs are a probability-weighted estimate of all possible default events over the expected life of a financial asset and are measured as the difference between the present value of the cash flows due to the Company and the cash flows the Company expects to receive. In making an assessment as to whether the Company's financial assets are credit-impaired, the Company considers bad debts that the Company has incurred historically, evidence of a debtor's present financial condition and whether a debtor has breached certain contracts, the probability that a debtor enter bankruptcy or other financial reorganization, changes in economic conditions that correlate to increased levels of default, and the term to maturity of the specified receivable. The carrying amounts of accounts receivable are reduced by the amount of the ECL through an allowance account and losses are recognized as bad debt expense in profit or loss.

Based on industry experience, the Company considers financial assets to be in default when the receivable is more than 90 days past due. Once the Company has pursued collection activities and it has been determined that the incremental cost of collection pursuits outweigh the benefits of collection, the Company derecognizes the gross carrying amount of the asset and the associated allowance from the statement of financial position.

Pre-license costs incurred before the Company has attained legal rights to explore an area are recognized in profit or loss.

Exploration and evaluation costs, including the costs of acquiring leases and licenses, technical services and studies, geophysical and geological activities, seismic acquisition, exploration drilling, testing and decommissioning costs are initially capitalized as exploration and evaluation assets. The costs are accumulated in cost centres by exploration area pending determination of technical feasibility and commercial viability. Assets classified as exploration and evaluation are not depleted or depreciated until after these assets are reclassified to property, plant and equipment.

Exploration and evaluation assets are tested separately from property and equipment for impairment and are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. When an exploration and evaluation asset is determined not to be technically feasible or commercially viable, or the Company decides not to continue with its activity, the unrecoverable exploration and evaluation costs are charged to profit or loss.

The technical feasibility and commercial viability of extracting resources is considered to be determinable when proved reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to ascertain whether proved reserves have been discovered. Upon determination of proved reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within property, plant and equipment referred to as oil and natural gas interests.

Exchanges, swaps and farm-outs that involve only exploration and evaluation assets are accounted for at cost. Any gains or losses from the disposal of exploration and evaluation assets are recognized in profit or loss.

All costs directly associated with the development and production of oil and natural gas interests are capitalized on an area-by-area basis as oil and natural gas interests if they extend or enhance the recoverable reserves of the underlying assets. Items of property, plant and equipment, which include oil and natural gas development assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development costs include expenditures for areas where technical feasibility and commercial viability has been determined. These costs include property acquisitions with proved reserves, development drilling, completion, gathering and infrastructure, decommissioning costs and transfers of exploration and evaluation assets. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

Gains and losses on disposal of property, plant and equipment, property swaps and farm-outs, are determined by comparing the proceeds or fair value of the asset received or given up with the carrying amount of property, plant and equipment and are recognized in profit or loss. Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in profit or loss.

The net carrying value of oil and natural gas interests included in property, plant and equipment is depleted using the unit of production method by reference to the ratio of production in the period to the related proved and probable reserves, for wells included in property, plant and equipment taking into account estimated future development costs necessary to bring those reserves into production. Oil and natural gas interests including processing facilities and well equipment are componentized into groups of assets with similar useful lives for the purposes of performing depletion calculations. Relative volumes of reserves and production are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Future development costs are estimated taking into account the level of development required to produce the reserves.

The carrying amounts of the Company's property, plant and equipment and exploration and evaluation assets are reviewed at each reporting date to determine whether there is any indication of impairment. These indicators include, but are not limited to, extended decreases in prices or margins for oil and natural gas commodities or products, a significant downward revision in estimated reserves, an upward revision in future development costs, significant decrease in fair values of undeveloped lands in close proximity to lands held by the Company or management's decision to no longer pursue certain evaluation projects. If any such indication exists, then the asset's recoverable amount is estimated.

For the purpose of impairment testing, exploration and evaluation assets and property, plant and equipment are tested separately and are grouped into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets or cash generating units ("CGU"). Geological formation, product type, geography and internal management operations and processes are key factors considered when grouping the Company's oil and natural gas interests into CGUs.

The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs of disposal. Fair value is determined to be the amount for which the asset could be sold in an arm's-length transaction between knowledgeable and willing parties. Unless indicated otherwise, the recoverable amount used in assessing impairment losses is value in use. The Company estimates fair value less cost of disposal using discounted future net cash flows of proved and probable reserves for wells included in property, plant and equipment based on forecast prices and costs and including future development costs. The cash flows are discounted at an appropriate discount rate which would be applied by a market participant. Value in use is determined by estimating the present value of the future net cash flows to be derived from the continued use of the CGU in its present form. These cash flows are discounted at a rate based on the time value of money and risks specific to the CGU.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. An impairment loss in respect of property, plant and equipment recognized in prior years, is assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. The obligation is not recorded and is disclosed as a contingent liability if it is not probable that an outflow will be required, if the amount cannot be estimated reliably or if the occurrence of the outflow can only be confirmed by the occurrence of a future event. Provisions are not recognized for future operating losses. Contingent assets are disclosed if a future economic benefit is probable but are only recorded when recovery of the contingent asset is virtually certain.

The Company's activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provisions are made for the estimated cost of site restoration and capitalized to exploration and evaluation assets or property, plant and equipment and are depleted over the useful life of the assets.

Decommissioning liabilities are measured at the present value of management's best estimate of the risk adjusted cash flows required to settle the present obligation at the statement of financial position date. The future cash flow estimates are adjusted to reflect the risks specific to the liability. Subsequent to the initial measurement, the liability is adjusted at the end of each period to reflect the passage of time using a risk-free interest rate and changes in the estimated future cash flows underlying the liability. The increase in the provision due to the passage of time is recognized as a finance cost whereas increases/decreases due to changes in the estimated future cash flows or timing are recognized as changes in the decommissioning liability and related asset. Actual costs incurred upon settlement of the decommissioning liabilities are charged against the liability to the extent the liability was established. Any differences between the recorded liability and the actual costs incurred are recorded as a gain or loss in profit or loss.

Revenue from the sale of crude oil, natural gas and natural gas liquids is recorded when control of the product is transferred to the buyer based on the consideration specified in the contracts with customers. This usually occurs when the product is physically transferred at the delivery point agreed upon in the contract and legal title to the product passes to the customer (often at terminals, pipelines, or other transportation methods).

The Company sells its production pursuant to variable-priced contracts. The transaction price for variable-price contracts is based on commodity price, adjusted for quality, location, or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Commodity prices are based on market indices that are determined on a monthly or daily basis.

The Company evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, the Company considers if it obtains control of the product delivered or services provided, which is indicated by the Company having the primary responsibility for the delivery of the product or rendering of the service, having the ability to establish prices or having inventory risk.

If the Company acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net-basis, only reflecting the fee, if any, realized by the Company from the transaction.

The costs associated with delivery, including the operating and maintenance costs, royalties and transportation are recognized in the same period in which the related revenue is earned and recorded.

Income tax expense comprises current and deferred tax. It is recognized in profit or loss except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income/(loss).

The Company has determined that interest and penalties related to income taxes, including uncertain tax treatments, do not meet the definition of income taxes, and therefore accounted for them under IAS 37 Provisions, Contingent Liabilities and Contingent Assets.

Current tax comprised the expected tax payable or receivable on the taxable income or loss for the year and any adjustment to the tax payable or receivable in respect of previous years. The amount of current tax payable or receivable is the best estimate of the tax amount expected to be paid or received that reflects uncertainty related to income taxes, if any and is measured using tax rates enacted or substantively enacted at the reporting date.

Deferred tax is recognized in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, on the initial recognition of goodwill or on temporary differences related to investments in subsidiaries, associates and joint arrangements to the extent that the group is able to control the timing of the reversal of the temporary differences and it is probable that they will not reverse in the foreseeable future.

Temporary differences in relation to a right-of-use asset and a lease liability for a specific lease are regarded as a net package (the lease) for the purpose of recognizing deferred tax.

Deferred tax assets are recognized for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary differences is insufficient to recognize a deferred tax asset in full, then future taxable profits, adjusted reversals of existing temporary differences, are considered, based on the business plans for individual subsidiaries in the Group. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit swill be realized; such reductions are reversed when the probability of future taxable profits improves.

The measurement of deferred tax reflects the tax consequences that would follow from the manner in which the group expects, at the reporting date, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax assets and liabilities are offset only if certain criteria are met.

Finance income, consisting of interest income, is recognized as it accrues in profit or loss using the effective interest method and/or when the Company's right to receive payments is established.

Finance expense is comprised of interest expense on borrowings, financing fees, accretion of promissory note discounts, debt issuance costs, lease liabilities, and accretion of the discount on decommissioning liabilities, and is recognized in the period in which they are incurred.

Basic earnings (loss) per share is computed by dividing the income/(loss) by the weighted average number of shares outstanding during the period. Diluted earnings per share amounts are calculated by giving effect to the potential dilution that would occur if contracts to issue shares were exercised, fully vested, or converted to shares. The treasury stock method is used to determine the dilutive effect of dilutive instruments, where it is assumed that the proceeds received from the exercise price of in-the-money dilutive instruments are used to repurchase shares. The weighted average number of shares is determined on an as converted basis, where all MVS and PVS are treated as SVS, in addition, HB2 Member Units are included as outstanding prior to the BCA (Note 2) based on the equivalent SVS.

At inception of a contract, the Company assesses whether a contract is, or contains a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether: the contract involves the use of an identified asset; the Company has the right to obtain substantially all of the economic benefits from the use of the asset throughout the period of use; and, the Company has the right to direct the use of the asset.

The company has elected not to recognize right of use assets and lease liabilities for short term leases that have a term of 12 months or less and leases of low value assets. Leases to explore for or use crude oil, natural gas, minerals and similar non regenerative resources are also exempt from the standard. The Company treats lease payments for the these types of leases as an expense when incurred, over the lease term, except for lease payments related to non producing properties which are capitalized.

The Company recognizes a right of use asset and a lease liability at the commencement date of the lease contract, which is the date that the lease asset is available to the Company. The lease asset is initially measured at cost. The cost of a lease asset includes the amount of the initial measurement of the lease liability, lease payments made at or before to the commencement date less any incentives received, initial direct costs and estimates of the decommissioning liability, if any. Subsequent to initial recognition, the lease asset is depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term. A lease obligation is recognized at the commencement of the lease term at the present value of the lease payments that are not paid at that date discounted using the rate implicit in the lease or the Company's incremental borrowing rate if the implicit rate is not readily available. Lease payments that are present valued include fixed payments, less any lease incentives receivable, variable lease payments that are based on index or rate, amounts expected to be payable under residual value guarantees, the exercise price of a purchase option that is reasonably certain of exercise and payment of penalties for terminating a lease if the lease term reflects exercising that option. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation. Optional renewal periods, or periods which are cancellable by the Company, are included in the lease payments if the Company is reasonably certain to exercise the renewal option or not cancel the lease. The lease liability is measured at amortized cost using the effective interest method. The lease liability is remeasured when there is a change in the Company's assessment of the expected lease term or is there is a lease modification.

The Company measures share based payments to non-employees at the fair value of goods or services received at the date of receipt of the goods or services. If the fair value of the goods and services cannot be reliably measured, the value of the share based payment will be used, measured using the Black-Scholes option pricing model.

The Company has issued certain units in a development partnership that gives holders of these units certain rights as further described in (Note 7 and 8). These units give the holders the right to receive certain variable cash flows based on the cash flows generated by the assets of the partnership. These units also give the holder the right to put the units back to the partnership at a variable price based on the value of the assets of the partnership at certain future dates. This put right qualifies as a derivative financial liability. These partnership units have been designated by the Company to be measured at fair value through profit or loss using level 3 fair value measurements.

Non-controlling interests ("NCI") represent ownership interest in consolidated subsidiaries by parties that are not shareholders of the Company. They are shown as a component of total equity in the interim Consolidated Statements of Financial Position, and the share of income/(loss) attributable to NCI is shown as a component of net income/(loss) in the Interim Consolidated Statements of Operations and in the interim Consolidated Statement of Comprehensive Loss. Changes to the parent company's ownership that do not result in a loss of control are accounted as equity transactions.

NCI in a subsidiary is recognized at either fair value or at the non-controlling interest's proportionate share of the subsidiary net assets, determined on an acquisition-by-acquisition basis.

Proceeds from the issuance of shares and Origination Member Units are classified as equity. Incremental costs directly attributable to the issuance of shares or Origination Member Units are recognized as a deduction from equity.

Upon redemption of shares or Origination Member Units by the Company the excess (deficiency) of consideration paid to redeem shares or Origination Member Units over the weighted average carrying amount of member units at the time of redemption, is recorded as a charge (credit) to members' equity with no gain or loss recorded.

		September 30, 2021			December 31, 2020
Balance, beginning of period	$	1,243,615		$	7,549,852
Additions		6,763,605			318,982
Acquisition for members units (note 13)		3,499,995			-
Transfers (Note 6)		(1,521,154	)		(426,021	)
Impairment		-			(6,199,198	)
Balance, end of period	$	9,986,061		$	1,243,615

E&E assets consist of undeveloped lands, unevaluated seismic data and unevaluated drilling and completion costs and associated decommissioning costs on the Company's exploration projects which are pending the determination of proved reserves. Transfers are made to property, plant and equipment ("PP&E") as proved reserves are determined and technical feasibility and commercial viability is established. E&E assets are expensed due to uneconomic drilling and completion activities and lease expiries.

Additions during the nine months ended September 30, 2021 and year ended December 31, 2020, mainly relate to undeveloped lands and drilling costs on wells without assigned proved reserves prior to their transfer to property, plant and equipment.

The Company reviews many factors when determining if an impairment test should be performed. At September 30, 2021 and at December 31, 2020, the Company conducted an assessment of impairment indicators for the Company's exploration and evaluation assets and noted no impairment indicators were present other than lands that had expired lease terms or near expiry.

For the nine months ended September 30, 2021, the Company had no impairments. For the nine months ended September 30, 2020, the Company recorded an impairment of $3,121,873 of E&E assets previously capitalized as exploration and evaluation assets as the lease term of undeveloped lands expired or were near expiry. These amounts have been included in impairment loss on exploration and evaluation assets in the statement of loss and comprehensive loss.

Cost		September 30, 2021			December 31, 2020
Balance, beginning of period	$	56,955,325		$	25,478,575
Additions		38,498,017			11,687,526
Acquisitions		-			33,001,822
Transfers from E&E assets (Note 5)		1,521,154			426,021
Decommissioning obligations (Note 11)		397,486			685,000
Disposal		-			(14,323,619	)
Balance, end of period	$	97,371,982		$	56,955,325

Accumulated depletion and impairment		September 30, 2021			December 31, 2020
Balance, beginning of period	$	(1,292,996	)	$	(17,974,432	)
Reversal of impairment		-			4,730,000
Disposal		-			12,982,436
Depletion		(10,484,000	)		(1,031,000	)
Balance, end of period	$	(11,776,996	)	$	(1,292,996	)

Carrying amount	$	85,594,986		$	55,662,329

The depletion calculation for the nine months ended September 30, 2021 includes estimated future development costs of $34,841,744 (year ended December 31, 2020 - $36,679,400) associated with the development of the Company's proved plus probable reserves included in property, plant and equipment.

On December 22, 2020 the Company acquired the working interest in a series of wells from a third party who held a working interest in a number of the Company's existing wells as well as settled accounts payable owing to the third party. The Company paid $45,700,000 in cash, and issued a promissory note in the amount of $1,800,000 (note 10) to repay joint interest payables owed to the vendor of $14,498,178 and acquire PP&E in the amount of $33,001,822.

During the year ended December 31, 2020 the Company settled affiliate loans in the amount of $4,629,324 plus accrued interest of $730,500 through the assignment of one well to the affiliate and the assignment of $500,000 of accounts payable to affiliate. The well had a carrying value of $1,340,264 and associated decommissioning liabilities of $74,000. The difference between the carrying value of the well and the affiliate loan was recorded as affiliate contributions to capital reserves in members' equity.

The Company assesses many factors when determining if an impairment test should be performed. For the nine months ended September 30, 2021, the Company assessed impairment indicators for the Company's CGU and noted no indicators of impairment were present.

For the year ended December 31, 2020, the Company conducted an assessment of impairment indicators for the Company's CGU. In performing the review, management determined that the continued volatility of commodity pricing and the impact this has on the economic performance of the Company's CGU justified determination of the recoverable amounts of all CGU. The recoverable amounts were estimated at the value in use on the net present value of the before tax future net cash flows from oil and natural gas proved and probable reserves using forecasted prices and costs estimated by external and Company engineers. The future net cash flows were discounted at a rate of 15%.

There was no impairment loss required for any of the Company's CGUs for the year ended December 31, 2020.

In the year ended December 31, 2020, due to increased reserves being assigned to the Company's Austin Chalk CGU, the Company identified indicators of a possible reversal of previously recorded impairment losses. The Company calculated the value in use of the CGU to allow for the reversal of the impairment loss recorded in 2019 (net of depletion that would have been recorded) of $4,730,000.

Key assumptions used in the determination of the recoverable amounts of each CGU includes commodity prices and discount rates applied to cash flows from proved and probable reserves. A 1% increase in the assumed discount rate over the life of the reserves independently would not have resulted in any further impairment loss or impairment loss reversal for the year ended December 31, 2020.

The Company utilized the following benchmark prices to determine the forecast prices in the value in use calculations;

	As at December 31,
	2020	2020
	W TI Crude Prices	Henry Hub Prices
	Oil, $/bbl	Gas, $/Mmbtu
2021	47.17	2.83
2022	50.17	2.87
2023	53.17	2.90
2024	54.97	2.96
2025	56.07	3.02
2026	57.19	3.08
2027	58.34	3.14
2028	59.50	3.20
2029	60.69	3.26
2030	61.91	3.33
2031	63.15	3.39

During the first quarter of 2021, the Company formed a Development Partnership ("DP") with 13 external limited partners and Origination as a limited partner and the general partner. The intention of the DP is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $13,140,240 from external limited partners of which $1,366,709 was raised from officers and directors of the Company. Investors can choose to receive DP Units that distribute profits either based on a Flat payout option or an IRR based payout option. Investors have participated as to $3,243,728 in Flat Payout units and $9,896,512 in IRR based payout units. Flat Payout Units will participate in 75% of the income of the DP (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of the DP (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of the DP (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of the DP (along with Flat Payout Units). The Company will receive 25% of the income of the DP before payout and will receive 80% and 94% of the income related to Flat and IRR based payout Units respectively after payout.

After payout, the external limited partners will also have a put right to effectively put their DP units (with ongoing rights to 20% and 6% of the income generated by the DP) back to the Company for either i) Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company) or ii) cash, subject to certain restrictions, and with the number of shares or cash to be distributed to be calculated based on future net present values of the oil and gas reserves of the DP.

The Company, through the structure of the DP, will maintain control of the DP and will continue to consolidate 100% of the operations of the DP.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments. For the three and nine months ended September 30, 2021, an increase in the liability of $1,329,509 and $4,001,481, respectively, was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses (Note 18).

Fair value was determined by present valuing the expected cash flows to be received by the unit holders at a discount rate of 15%.

Refer to Note 23 for further disclosure related to the repayment of the first development partnership, subsequent to September 30, 2021.

During the third quarter of 2021, the Company formed a Development Partnership ("DP") with 26 external limited partners and Origination as a limited partner and the general partner. The intention of the DP is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $20,815,329 from external limited partners of which $1,724,967 was raised from officers and directors of the Company. Investors can choose to receive DP Units that distribute profits either based on a Flat payout option or an IRR based payout option. Investors have participated as to $7,390,362 in Flat Payout units and $13,424,967 in IRR based payout units. Flat Payout Units will participate in 75% of the income of the DP (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of the DP (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of the DP (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of the DP (along with Flat Payout Units). The Company will receive 25% of the income of the DP before payout and will receive 80% and 94% of the income related to Flat and IRR based payout Units respectively after payout.

The Company, through the structure of the DP, will maintain control of the DP and will continue to consolidate 100% of the operations of the DP.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments. For the three and nine months ended September 30, 2021, an increase in the liability of $8,308,892 was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses (Note 18).

Fair value was determined by present valuing the expected cash flows to be received by the unit holders at a discount rate of 15%.

On December 22, 2020, the Company entered into a credit facility with Goldman Sachs (the "Goldman Facility"). All borrowings under the facility are secured by the Company's oil and gas producing wells as well as all assets of the Company's three subsidiaries. The Goldman Facility carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) and a maturity date of December 22, 2031. Interest payments are required quarterly. As at September 30, 2021, the Company had $28,144,040 (December 31, 2020 - $43,328,396) drawn under the facility. The Company's subsidiaries including AIP Holdco, LP, AIP Borrower LP have certain financial covenants under the Golden Facility, including;

(i) Maintain a ratio of total net debt to adjusted EBITDAX of no more than 3.5 to 1.0, whereby net debt is effectively defined as all indebtedness of the Company less certain cash balances held in control accounts in which the lender holds a security interest, and adjusted EBITDAX is effectively defined as income before interest, taxes, depletion, amortization, extraordinary gains and losses and other non cash items annualized.

(iii) Maintain a Measured Assets to Total Net Debt Ratio of at least 1.50 to 1.0, whereby Measured Assets is effectively defined as the present value of the Company's a) proved reserves, b) forward commodity contracts, c) abandonment liabilities related to proved producing reserves and d) other fixed costs associated with the proved producing reserves all discounted at 10% and Total Net Debt is defined as outlined in part i) to this note.

As at September 30, 2021, the Company was in compliance with all financial covenants.

i) As at the initial borrowing date, enter into certain forward commodity swap contracts included in Note 22 (c)(i) which it has done.

ii) Within 90 days of the initial borrowing date, enter into an interest rate swap contract to effectively fix the interest rate of at least 70% of the principal outstanding on the loan, at any given time for the term of the loan. The Company entered into these swaps during the nine months ended September 30, 2021 (Note 22 (c)(ii)).

iii) No later than December 31, 2021, establish an interest reserve account that will hold a cash balance sufficient to cover nine months of scheduled interest payments which it has not done but intends to prior to the required date of December 31, 2021.

In addition to the required principal repayments outlined above, the Company's subsidiaries including AIP Holdco, LP, AIP Borrower LP could also be required to make additional payments of:

i) If the ratio of adjusted EBITDAX to scheduled loan principal and interest payments for the period is less than 1.50 to 1.00, the Company must make an additional principal prepayment equal to Net Income/(Loss) adjusted for all non cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement

ii) If the Company fails to meet its ratio (as defined above) of Measured Assets to total net debt of 1.50 to 1.00, the Company must make an additional principal prepayment sufficient to meet the 1.50:1.00 ratio.

At September 30, 2021, the Company was not subject to any other additional principal prepayments.

During the three and nine months ended September 30, 2021 the Company recorded amortization of borrowing costs of $236,961 and $833,260, respectively (Note 17).


December 31, 2020	$	5,425,000
Issued for cash (note 10 (i))		1,075,000
Converted to Origination Member Units (note 10 (ii))		(4,475,000	)
Repayment of notes (note 10 (iii))		(1,875,000	)
Issued for cash (note 10 (iv))		2,300,000
Converted to Origination Member Units (note 10 (iv))		(2,300,000	)
September 30, 2021	$	150,000

i) During the nine months ended September 30, 2021, the Company issued $1,075,000 in promissory notes for cash of which $75,000 were to an officer of the Company.

ii) During the nine months ended September 30, 2021, the Company issued 353,870 Origination Member Units in exchange for $3,475,000 in promissory notes (Note 13) (2020 - Nil) of which $600,000 were held by an officer of the Company. In addition, the Company exchanged $1,000,000 of promissory notes in connection with the asset backed preferred instrument (Note 12).

iii) During the nine months ended September 30, 2021, the Company repaid $1,605,000 of promissory notes with cash and also offset $270,000 of promissory notes with agreed upon overhead expenses paid by the Company that was outstanding at December 31, 2020, which has been shown as a reduction of general and administrative expenses.

iv) In June 2021, the Company issued a series of unsecured, non-interest bearing convertible promissory notes to individuals in aggregate principal amount of US$2.3 million with a maturity date of sixty days from the date of issuance. Per the terms of these convertible promissory notes, they are convertible into units of the Company at a conversion rate of $9.82/unit at the option of the noteholder or the Company. On July 2, 2021, the Company exercised its option to convert all the existing convertible notes into 234,216 Origination Member Units effective as of July 7, 2021 (Note 13).

At September 30, 2021, the Company has outstanding $150,000 of notes payable bearing interest at 17% and due on demand.

		September 30, 2021		December 31, 2020
Balance, beginning of period	$	864,000	$	247,000
Liabilities incurred and acquired		386,074		685,000
Disposals		-		(74,000	)
Accretion (note 18)		13,556		6,000
Change in estimates		11,412		-
Balance, end of period	$	1,275,042	$	864,000

The total future decommissioning obligations were estimated based on the Company's net ownership interest in petroleum and natural gas assets including well sites and gathering systems, the estimated costs to abandon and reclaim the petroleum and natural gas assets and the estimated timing of the costs to be incurred in future periods. As at September 30, 2021, the Company estimated the total undiscounted amount of cash flows required to settle its decommissioning obligations to be approximately $2,074,252 (December 31, 2020 $1,297,000) which will be incurred between 2025 and 2058. As at September 30, 2021, an average risk-free rate of 2.02% (December 31, 2020 - 1.65%) and an inflation rate of 2.0% (December 31, 2020 - 1.6%) were used to calculate the decommissioning obligations.

The risk-free rate used in the calculation of the net present value has a significant impact on the carrying value of decommissioning liabilities. A 1% increase in the risk-free rate at September 30, 2021 would decrease the decommissioning liability by $258,000.

On March 5, 2021, the Company executed a Origination Member Units buy back structure, in which a member exchanged 100% of their holdings (3,992,629 Origination Member Units representing approximately 23.4% of the outstanding HB2 Member Units at the time) along with a $1,000,000 promissory note (Note 10) for a preferred instrument (23,500,000 LP units) in a newly created limited partnership controlled by the Company ("the LP Units") The Company was required to redeem 6,670,000 LP Units on or before May 1, 2021 at $0.71 per LP Unit, or before June 1, 2021 at $0.8809 per LP Unit, or before September 1, 2021 at $1.00 per LP Unit or would be considered in default. The remaining 16,830,000 LP Units must be redeemed at $1.00 per LP Unit no later than March 5, 2024. If the remaining 16,830,000 LP Units are not redeemed by this date, the redemption price increases to $1.35 per LP Unit and the Company is considered to be in default. While outstanding, all LP Units earn a fixed rate of return of 12% per annum, which increases to 17% in any event of default. The 6,670,000 LP units were redeemed at $0.71 per LP unit in the second quarter of 2021 for a total amount of $4,735,700.

As a result of the transaction, the Company recorded a reduction to Origination Member Units of $8,680,786 (weighted average issue price to date of $2.17/unit) a reduction in promissory note liability of $1,000,000, a liability at an initial fair value of $21,565,700 and a reduction to accumulated deficit of $11,884,914. The fair value of the liability was determined by discounting the expected cash flows related to the instrument at a market based rate of 12% per annum.

For the three and nine months ended September 30, 2021, the Company recorded finance expense related to the outstanding instrument in the amount of $532,592 and $1,310,975, respectively.

The Company has presented the entire liability as long-term based on estimates of cash flows available to repay the units in the coming twelve months.

The Company is authorized to issue an unlimited number of Subordinate Voting, Multiple Voting and Proportionate Voting Shares. Subject to certain restriction set out in the Company's articles, each SVS is entitled to one vote per share, each MVS is convertible, at the option of the holder, into 100 SVS and entitles the holder to 100 votes per share and each PVS is convertible into 1 SVS and entitles the holder to 1,000 votes per share. Each PVS will automatically convert to one SVS upon the holders equity interest in Origination reducing to less than 75% of the interest held on the date of the closing of the BCA.

		Origination Member Units		SVS	MVS	PVS		Amount
Balance at December 31, 2020 and 2019	Note	17,083,501		-	-	-	$	37,097,376
Issuance of member units for cash	13	819,215		-	-	-		8,044,700
Issuance of member units exchanged for promissory notes	13	353,870		-	-	-		3,475,000
Issuance of member units for exploration and evaluation assets	13	356,415		-	-	-		3,499,995
Issuance of member units to contractors	13	923,954		-	-	-		9,073,228
Redemption of member units	12	(3,992,629	)	-	-	-		(8,680,786	)
Issuance of member units exchanged for promissory notes	13	234,216		-	-	-		2,300,000
Origination Unit split 1:3	2	31,557,084		-	-	-		-
Allocation of opening non-controlling interest	14	(16,168,422	)	-	-	-		(18,721,276	)
Shares issued for cash, net of issuance costs of $247,218	2	-		161,976.000	17,057.000	-		5,499,832
Exchange of units for SVS and MVS	2	(31,167,204	)	1,427,421.000	297,397.830	-		-
Proportiante Voting Shares issued for cash	2	-		-	-	15,947.292		128,213
Shares issued on reverse takeover	2	-		534,384.000	-	-		1,697,865
Balance at September 30, 2021		-		2,123,781.000	314,454.830	15,947.292	$	43,414,147

During the year ended December 31, 2020 there were no issuances of Origination Member Units.

During the nine months ended September 30, 2021, the Company issued 819,215 Origination Member Units for aggregate cash of $8,044,700 ($9.82/unit). In addition, the Company issued 353,870 Origination Member Units in exchange for the retirement of $3,475,000 in promissory notes ($9.82/Unit).

The Company entered into an agreement, with a third party, to acquire 16,201 net acres in the Eagle Ford formation, located in the Austin, Fayette, Lee and Washington counties of Texas. In exchange for the acreage, the Company issued 203,666 Origination Member Units valued at $2,000,000 ($9.82/Unit).

In addition, the Company issued 152,749 Origination Member Units, valued at $1,499,995 ($9.82/Unit) in exchange for approximately 630 net mineral acreage in Washington county, Texas.

In May of 2021, the Company issued 923,954 Origination Member Units to officers and consultants of the Company for services at an estimated value of $9.82 per HB2 Member Unit for total consideration of $9,073,228 in connection with the listing application.

On July 2, 2021, the Company exercised its option to convert all the existing convertible promissory notes ($2,300,000) into 234,216 units ($9.82/unit) of the Company effective as of July 7, 2021.

		Nine months ended September 30, 2021							Nine months ended September 30, 2020
		Net Loss		Shares		Loss per Share			Net Loss		Shares		Loss per Share
Income/(loss) - basic	$	(51,614,575	)	45,632,956	$	(1.13	)	$	(4,423,521	)	51,250,503	$	(0.08	)
Diliutive effect of outstanding awards		-		-		-			-		-		-
Loss - diluted	$	(51,614,575	)	45,632,956	$	(1.13	)	$	(4,423,521	)	51,250,503	$	(0.08	)

		Three months ended September 30, 2021							Three months ended September 30, 2020
		Net Loss		Shares		Loss per Share			Net Income		Shares		Loss per Share
Income/(loss) - basic	$	(18,636,041	)	43,882,747	$	(0.42	)	$	123,065		51,250,503	$	0.00
Diliutive effect of outstanding awards		-		-		-			-		-		-
Loss - diluted	$	(18,636,041	)	43,882,747	$	(0.42	)	$	123,065		51,250,503	$	0.00

The Company had no options, or warrants outstanding for all periods ended September 30, 2021 and 2020. The effect of the conversion of convertible promissory notes and NCI interest in Origination would be anti-dilutive and therefore have not been included in the calculation of diluted loss per share.

Weighted average shares are based on an as converted basis for MVS and PVS into SVS as all classes of shares are ordinary shares for purposes of these calculations. Ordinary shares outstanding have also been adjusted to reflect the reverse takeover and three for one equity split (Note 2).

In connection with the BCA (Note 2), certain Origination equity holders elected not to convert their equity holdings in Origination into SVS/MVS of the Company. The non-converting equity holders amount to a 32.5% economic interest in Origination.

On closing the BCA, Origination's consolidated book value of net liabilities was $32,968,557, which results in an opening NCI balance of $10,714,781. This NCI balance along with the weighted average stated capital of the equity interests surrendered by the NCI holder of $18,721,276, for a total of $29,436, 057, has been credited to capital reserve.

For the 23 days of September, 2021 following the closing of the BCA, $3,355,382 was recorded to decrease net loss on the interim consolidated statement of operations and comprehensive loss, with an offset to NCI, representing NCI share of net loss for the 23 day period.

a) During the year ended December 31, 2020, the Company disposed of certain wells to a company related by virtue of a common shareholder, officer and director, in exchange for the extinguishment of an affiliate loan.

Due to the relationship between the Company and the related party, differences between the carrying amount of assets disposed of and the loan balance extinguished has been recorded as affiliate contributions to the capital reserves account in members' equity. For the year ended December 31, 2020, $4,592,641 was recorded to the capital reserve account.

b) During the nine months ended September 20, 2021, an additional $29,436,057 has been added to capital reserve related to certain Origination equity holders electing to not convert their equity interests into SVS/MVS of the Company as further described in note 14.

The remuneration of the key management personnel of the Company which includes all executive officers is set out below in aggregate:

Three months
ended
September 30,
2021

Three months
ended September
30, 2020

Nine months
ended
September 30,
2021

Nine months ended
September 30,
2020

Salaries and bonuses

1,023,781

3,261,349

Share based compensation (note 13)

8,230,054

Balance, end of period

1,023,781

11,491,403

Total personnel expenses for all employees and officers including share based compensation was $12,296,690 of which $3,223,462 is included in general and administrative expenses and $9,073,228 is included in stock based compensation (Note 13).

The amount of each significant category of revenue recognized for the three and nine months ended September 30, 2021 and 2020 is as follows:

		Three months ended September 30, 2021		Three months ended September 30, 2020		Nine months ended September 30, 2021		Nine months ended September 30, 2020
Crude oil	$	17,825,375	$	1,071,282	$	38,363,632	$	1,696,013
Natural gas		1,013,833		55,174		10,602,674		57,934
Natural gas liquids		4,587,867		113,423		6,922,921		113,843
	$	23,427,075	$	1,239,879	$	55,889,227	$	1,867,790

The amount of each significant category of finance expense recognized for the three and nine months ended September 30, 2021 and 2020 is as follows:

		Three months ended September 30, 2021		Three months ended September 30, 2020		Nine months ended September 30, 2021		Nine months ended September 30, 2020
Accretion of decommissioning liabilities (note 11)	$	4,613	$	1,000	$	13,556	$	3,000
Interest on asset back preferred liability (note 12)		532,592		-		1,310,975		-
Fair value change in development partnership liabilities (note 7, 8)		9,638,401		-		12,310,373		-
Interest on affiliate loan		-		-		-		62,185
Amortization of debt issuance costs (note 9)		236,961		-		833,260		-
Interest on promissory notes (note 10)		4,323		-		295,230		-
Accretion on lease liability		3,927		-		5,229		-
Interest on long-term debt (note 9)		570,856		-		1,983,340		-
	$	10,991,673	$	1,000	$	16,751,963	$	65,185

Prior to the RTO, the Company was not subject to income taxes, because, as a Limited Liability Company it was treated as a pass-through entity for income tax purposes, as the members of the Company pay the income tax on their share of the LLC's taxable income. As a result, the consolidated Statements of Financial Position and the consolidated Statements of Loss and Comprehensive Loss do not include items related to income taxes for the period before the RTO. Subsequent to the RTO, the Company is taxed as a U.S. C Corporation and is subject to income tax on its share of pass-through taxable income from Origination, and any tax balances related to the Company, together with those of the acquired entity, are therefore part of these consolidated financial statements. Any income attributable to members outside the consolidated group is not reflected in the Company's consolidated Statement of Financial Position and the consolidated Statement of Loss and Comprehensive Loss.

The Company recognized the following amounts of tax expense in the income statement:

The deferred tax liabilities consist of temporary differences between the carrying values for accounting versus tax values, as follows:

Deferred tax assets are recognized only to the extent that it is probable that the assets can be recovered. As at December 31, 2020, the Company has non‐capital loss carryforwards in Canada of $1.9 million which expire between 2029 and 2040 and which were acquired mainly as part of the BCA, for which no deferred tax asset is recognized. Non-capital losses in the United States, which have no expiration period but are subject to certain limitations on taxable income, have been recognized.

		Three months ended September 30, 2021			Three months ended September 30, 2020			Nine months ended September 30, 2021			Nine months ended September 30, 2020

Accounts receivable	$	(4,106,455	)	$	(4,741,412	)	$	(6,637,905	)	$	(1,058,992	)
Prepaid assets		(146,211	)		-			(210,092	)		-
Accounts payable and accrued liabilities		9,745,574			5,110,757			23,580,851			6,896,215

Change in non-cash working capital operating activities	$	5,492,908		$	369,345		$	16,732,854		$	5,837,223

Changes in non-cash working capital related to		Three months ended September 30, 2021			Three months ended September 30, 2020			Nine months ended September 30, 2021			Nine months ended September 30, 2020

Operating activities	$	(13,450,912	)	$	(3,198,607	)	$	(9,095,806	)	$	(1,612,706	)
Investing activities		16,062,271			3,567,952			25,828,660			7,449,929
Financing activties		2,881,549			-			-			-

	$	5,492,908		$	369,345		$	16,732,854		$	5,837,223

Cash interest paid	$	575,178		$	-		$	2,278,570		$	62,185
Taxes paid	$	-		$	-		$	-		$	-

During the period ended September 30, 2021, the Company issued 356,415 HB2 Member Units in exchange for $3,499,995 of exploration and evaluation assets ($9.82/unit) (Note 13).

During the period ended September 30, 2021 the Company issued 353,870 HB2 Member Units in exchange for the retirement of promissory notes (Note 13).

During the period ended September 30, 2021 the Company redeemed 3,992,629 HB2 Member Units and converted a $1,000,000 promissory note in exchange for an asset backed preferred instrument valued at $21,565,700 (Note 12).

On July 2, 2021, the Company exercised its option to convert all the existing convertible promissory notes ($2,300,000) into 234,216 units ($9.82/unit) of the Company effective as of July 7, 2021 (Note 13).

21. Related party transactions and balances not disclosed elsewhere in the financial statements

On December 22, 2020, the Company entered into a Management Services Agreement (the "MSA") with a company related by virtue of common equity holders, directors and officers. Under this Agreement, the related Company provided management, finance, operations and administrative services. The Agreement had an initial period of 11 years with a 90 day cancellation notice. The Company was obligated pay for these services on a quarterly basis amounting to the lesser of; i) $2.00 per produced barrel of oil equivalent (converting natural gas to BOE equivalent of 6:1), and ii) 0.375% of measured assets as defined in the credit agreement (Note 9).

During the nine months ended September 30, 2021, the Company incurred fees of $159,665 (three and nine months ended September 30, 2020 - $Nil) and is included in general and administrative expenses, of which $159,665 is included in accounts payable as at September 30, 2021 (December 31, 2020 - $20,000). In the second quarter of 2021, the MSA was effectively terminated by assigning the MSA to one of the Company's subsidiaries, thereby eliminating the requirement to pay any fees going forward as outlined above.

In the second quarter of 2021, the Company entered into a new Letter Agreement (the "Letter") with the same related company by virtue of common equity holders, directors and officers. The Letter requires the Company to hire its own employees, obtain its own office lease and assume certain management obligations. In exchange, the Company is paid an annual fee of $1,000,000 on a quarterly basis. During the nine months ended September 30, 2021, the Company was paid $215,080 via a payroll credit and $166,667 in cash, with a corresponding decrease to general and administrative expenses in the statement of income and loss. The Company will be paid $250,000 for services provided in the fourth quarter of 2021.

(i) At September 30, 2021, accounts receivable includes $80,000 (December 31, 2020 - $Nil) owed to the Company by officers of the Company and companies controlled by the officers of the Company. These amounts are due as a result of the related parties being joint interest parties in certain wells operated by the Company. These amounts were received subsequent to September 30, 2021.

(ii) At September 30, 2021, the accounts payable included $105,191 (December 31, 2020 - accounts receivable of $75,612) due from a company related by virtue of common equity holders, officers and directors under normal credit terms.

The Company has exposure to credit risk, liquidity and market risk from its use of financial instruments. This note presents information about the Company's exposure to each of the risks, the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital.

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.

There were no changes to the Company's risk management policies or processes during the period ended September 30, 2021.

Credit risk is the risk of financial loss to the Company if a customer or counter-party to a financial instrument fails to meet its contractual obligations. The maximum exposure to credit risk is as follows:

The Company's accounts receivable are subject to normal industry credit risk. The Company is the operator of the oil and gas properties. Petroleum and natural gas sales are normally collected by the Company between 30 and 60 days from deliveries. Joint interest receivables are typically collected within one to three months of the joint interest bill being issued to the partner. However, the receivables are due from participants in the oil and gas industry and collection of outstanding amounts can be impacted by industry factors such as commodity price fluctuations, limited capital availability and success of drilling programs.

As at September 30, 2021 and December 31, 2020, the Company's accounts receivable were comprised of the following:

Accounts receivable aging as at September 30, 2021 and December 31, 2020 are as follows:

All amounts shown as current and 31 - 60 days aging have been collected subsequent to period end. Amounts greater than 90 days are being pursued by management and the expected credit loss is believed to be insignificant.

All of the Company's cash is held at two financial institutions as at September 30, 2021 and December 31, 2020. The Company manages its credit exposure to cash, if any, by selecting institutions with high credit ratings.

Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with the financial liabilities as they become due. The Company's financial liabilities consist of accounts payable and accrued liabilities and promissory notes, all of which are due within a year, commodity contract liabilities which will all be settled over the life of their contract terms (see below), lease liabilities which will be settled over the life of the lease, asset backed preferred instruments which will be repaid based on available cash flows, development partnership liabilities that will be repaid based on cash flows generated by the wells included in the partnership and a credit facility with portions due in the following year. The Company also maintains and monitors a certain level of cash flow which is used to partially finance all operating and capital expenditures. The Company also attempts to match its payment cycle with collection of oil and natural gas sales which are usually collected within 30 to 60 days.

At September 30, 2021, the Company had negative working capital of $80,891,770. The Company expects to repay its financial liabilities in the normal course of operations and to fund future operational and capital requirements through operating cash flows and through issuance of debt and/or equity.

The Company may need to conduct asset sales, equity issues or issue debt if liquidity risk increases in a given period. Liquidity risk may increase as a result of a change in the amounts settled monthly from the commodity contracts (Note 22 (c)). The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans/notes, asset sales, coordinating payment and revenue cycles each month, and an active commodity hedge program to mitigate commodity price risk and secure cash flows.

More specifically, in an attempt to increase liquidity, the Company has during and subsequent to the nine months ended September 30, 2021 i) issued convertible promissory notes for cash (Note 10), ii) commenced a drilling program to increase cash flows from operating activities, iii) raised significant funds through two development partnerships (Note 7, 8 and 23), iv) settled promissory notes with a combination of cash and HB2 Member Units (Note 10) and v) entered into a new revolving credit facility (Note 23).

The Company is required to meet certain financial covenants under the Goldman Facility (Note 9). As at September 30, 2021, the Company was not in any breach of financial covenants in place.

The following table details the Company's financial liabilities and their scheduled maturities as at September 30, 2021;

		Carrying value		Contractual cash flow		Less than one year		1 - 3 years		Greater than 3 years
Accounts payable and accrued liabilities	$	36,087,969	$	36,087,969	$	36,087,969	$	-	$	-
Commodity contracts		29,627,332		29,627,332		14,709,808		7,988,934		6,928,590
Promissory notes		150,000		150,000		150,000		-		-
Lease liability		485,975		485,975		78,745		407,230		-
Asset backed preferred instrument		18,140,975		18,140,975		-		18,140,975		-
Development partnerships liabilities		44,412,815		49,767,346		41,260,520		4,068,092		4,438,734
Long-term debt		25,911,374		28,144,040		9,185,127		11,602,604		7,356,309

Total	$	154,816,440	$	162,403,637	$	101,472,169	$	42,207,835	$	18,723,633

Market risk is the risk that changes in market metrics, such as commodity prices, foreign exchange rates and interest rates that will affect the Company's valuation of financial instruments, as well as its net income (loss) and cash flow from operating activities. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by North American and global economic events that dictate the levels of supply and demand. The nature of the Company's operations results in exposure to fluctuations in commodity prices. The Company's production is sold using "spot" pricing with prices fixed at the time of transfer of custody or on the basis of a monthly average market price.

As at September 30, 2021, the Company had entered into the following risk management contracts to manage commodity price risk:

(1) remaining notional volumes decrease on a monthly basis until expiry of the contracts

The commodity contracts had a total negative fair value of $29,627,332 at September 30, 2021 (December 31, 2020 - $4,521,383) comprised of a short term commodity contract liability of $14,709,808 (December 31, 2020 - $3,158,763) and long term commodity contract liability of $14,917,524 (December 31, 2020 - $1,362,620). The corresponding unrealized loss for the nine months ended September 30, 2021 was $25,105,950 (2020 - $Nil) and is included in the statement of loss and comprehensive loss. Total realized losses on risk management contracts totalled $14,276, 940 (September 30, 2020 - $412,523) for the nine months ended September 30, 2021 and are also included in the statement of loss and comprehensive loss.

For the nine months ended September 30, 2021, a 10% increase/decrease in commodity prices would have a negative/positive impact on net income of approximately $8,015,000.

The Company is exposed to interest rate risk in relation to interest expense on its Goldman Facility as future cash flow may fluctuate as a result of market interest rates. If interest rates applicable to the facility were to have increased by 100 basis points (1%) it is estimated that the Company's net income for the nine months ended September 30, 2021 would have decreased by approximately $194,000 (before effect of income taxes). A decrease in interest rates by 1% would result in an increase in net income by an equivalent amount.

The Company entered into a LIBOR rate swap which effectively fixes the interest rate on a reducing notional principal amount commencing at $28,144,040 and reducing in fixed amounts to $Nil as of September 20, 2028. The Company will effectively pay/receive the difference between the fixed rate of 1.453% and the floating rate which is the greater of a 3 month USD LIBOR rate and 1.00%.

At September 30, 2021 the interest rate swap had a negative fair value of $57,310. For the nine months ended September 30, 2021, the Company recognized a corresponding unrealized loss of $57,310 (2020 - $Nil).

The Company mainly trades in US dollars which is also its functional currency hence, there is nominal foreign currency exposure.

The Company's objectives when managing its capital are to safeguard its ability to continue as a going concern, to meet its capital expenditures for its continued operations, and to maintain a flexible capital structure which optimizes the cost of capital within a framework of acceptable risk. The Company manages the capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets.

There has been no change to management's approach to managing capital during the period ended September 30, 2021, with the exception of the addition of development partnership liabilities and asset back preferred instruments to the definition of managed capital.

The Company considers its capital employed to be long-term debt, promissory notes payable, affiliate loans (if any), development partnership liabilities and asset back preferred instruments and shareholder's equity/(deficiency):

		September 30, 2021			December 31, 2020
Long-term debt (note 9)	$	25,911,374		$	40,262,470
Promissory notes (note 10)		150,000			5,425,000
Development partnership liabilities (note 7 and 8)		44,412,815			-
Asset backed preferred instrument (note 12)		18,140,975			-
Shareholder's Equity/(Deficiency)excluding NCI		(25,383,756	)		2,362,907
Capital Employed	$	63,231,408		$	48,050,377

The Company makes adjustments to capital employed by monitoring economic conditions and investment opportunities. The Company generally relies on credit facilities, equity issuances and cash flows from operations to fund capital requirements. To maintain or modify its capital structure, the Company may issue new shares, issue new debt, renegotiate existing debt terms, or repay existing debt. The Company is not currently subject to any externally imposed capital requirements, other than covenants on its bank debt (Note 9).

Refer to subsequent events (Note 23) for additional information on capital management initiatives.

On October 7, 2021, the Company repaid and paid out the reversion of the first development partnership ("DP1") that it formed during the first quarter of 2021.

DP1 funded the drilling and completion of five wells in the Giddings Field near Austin, TX and comprised a total capital program of approximately $21.3 million, with 60% funded by external partners. As part of the completion of the DP1 program, Alpine has retired liabilities of $15,288,594.

One of the DP1 partners exercised the put right provided to such partners by DP1 regarding residual interests in their associated investment and, elected to exchange the remaining interest in DP1 for 339,372 Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company, having a deemed value of US$3.515 per unit, or a total of approximately US$1.2 million).

On October 7, 2021, the Company formed a third Development Partnership ("DP3") with 23 external limited partners and HB2 as a limited partner and the general partner. The intention of the DP3 is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $21,182,826 from external limited partners of which $4,032,672 was raised from officers and directors of the Company. Investors can choose to receive DP3 Units that distribute profits either based on a Flat payout option or an IRR based payout option. Investors have participated as to $10,413,322 in Flat Payout units and $10,769,504 in IRR based payout units.

The terms of the units are identical to those of the first and second development partnerships (Note 7 and 8).

The Company, through the structure of the DP3, will maintain control of DP3 and will continue to consolidate 100% of the operations of the DP3.

In October, 2021, the Company's operating subsidiary Origination closed on a corporate credit facility. The facility has a maximum of $12.5 million, subject to quarterly borrowing base determinations by the lender. The borrowing base is currently set at $6,579,750. The loan charges interest at prime +2.25% and has a one year maturity. A subset of certain Company working interests in producing assets have been secured in connection with the facility.

			September 30, 2021			December 31, 2020
	Notes
ASSETS
Current assets
Cash		$	10,017,259		$	2,889,558
Accounts receivable			12,759,868			6,121,963
Prepaid expenses			235,503			25,411
			23,012,630			9,036,932
Non-current assets
Right-of-use-assets			442,810			-
Exploration and evaluation assets	5		9,986,061			1,243,615
Property, plant and equipment	6		85,594,986			55,662,329

Total assets		$	119,036,487		$	65,942,876
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities		$	36,087,969		$	12,507,116
Current lease obligations			78,745			-
Current portion of long-term debt	9		8,465,063			17,048,509
Development partnership 1 liabilities	7		15,288,594			-
Development partnership 2 liabilities	8		29,124,221			-
Promissory notes	10		150,000			5,425,000
Commodity contracts	22(c)		14,709,808			3,158,763
			103,904,400			38,139,388
Non-current liabilities
Long-term debt	9		17,446,311			23,213,961
Asset backed preferred instrument	12		18,140,975			-
Commodity contracts	22(c)		14,917,524			1,362,620
Long-term lease obligations			407,230			-
Deferred tax liability	19		2,398,924			-
Decommissioning liabilities	11		1,275,042			864,000
			54,586,006			25,440,581

Total liabilities			158,490,406			63,579,969

SHAREHOLDERS' EQUITY (DEFICIENCY)						37,097,376
Share capital	13		43,414,147			37,097,376
Capital reserve	15		34,459,432			5,023,375
Accumulated deficit			(103,257,335	)		(39,757,844	)
Equity/(deficiency) attributable to Alpine						2,362,907
Summit Energy Partners, Inc. Shareholders			(25,383,756	)		2,362,907
Non controlling interest	14		(14,070,163	)		-
Total shareholders' equity/(deficiency)			(39,453,919	)		2,362,907
Total liabilities and Shareholders' equity		$	119,036,487		$	65,942,876

			Three months			Three months			Nine months			Nine months
			ended			ended September			ended			ended September
			September 30,			30,			September 30,			30,
			2021			2020			2021			2020
	Notes

Revenue
Revenue from petroleum and natural gas sales	17	$	23,427,075		$	1,239,879		$	55,889,227		$	1,867,790
Royalties			(6,689,789	)		(342,631	)		(15,611,640	)		(582,630	)
			16,737,286			897,248			40,277,587			1,285,160

Unrealized losses on derivative commodity contracts	22(c)		(7,534,986	)		-			(25,105,949	)		-
Realized losses on derivative commodity contracts	22(c)		(6,438,425	)		(3,344	)		(14,276,940	)		(412,523	)
Total revenue/(deficiency), net of royalties and derivative commodity contracts		$	2,763,875		$	893,904		$	894,698		$	872,637
Expenses
Operating and transportation			3,018,084			373,591			6,598,663			495,192
General and administrative			1,661,449			186,248			7,650,282			1,351,908
Listing expense	2		1,301,692			-			1,301,692			-
Transaction costs	2		1,567,967			-			1,567,967			-
Stock-based compensation	13		-			-			9,073,228			-
Impairment loss of exploration and evaluation assets			-			-			-			3,121,873
Depletion and depreciation expense	6		3,815,509			210,000			10,521,936			262,000
Finance income and expense (net)	18		10,991,673			1,000			16,751,963			65,185

Total expenses			22,356,374			770,839			53,465,731			5,296,158

Income/(Loss) before taxes and non-controlling interest:		$	(19,592,499	)	$	123,065		$	(52,571,033	)	$	(4,423,521	)

Deferred taxes	19		(2,398,924	)		-			(2,398,924	)		-
Net income/(loss) and comprehensive loss for the period before non-controlling interest		$	(21,991,423	)	$	123,065		$	(54,969,957	)	$	(4,423,521	)
Net income/(loss) and comprehensive loss attributable to non- controlling interest		$	(3,355,382	)	$	-		$	(3,355,382	)	$	-
Net income/(loss) and comprehensive loss for the period attributable to Alpine Summit Energy Inc. Shareholders		$	(18,636,041	)	$	123,065		$	(51,614,575	)	$	(4,423,521	)

Income/(loss) per share attributable to Alpine Shareholders
Income/(Loss) and comprehensive loss per share - basic and diluted	13	$	(0.42	)	$	0.00		$	(1.13	)	$	(0.08	)

			Three months ended September 30,						Nine months ended September 30,
	Note		2021			2020			2021			2020

Operating Activities
Net income/(loss)loss for the period before non- controlling interest		$	(21,991,423	)	$	123,065		$	(54,969,957	)	$	(4,423,521	)
Items not affecting cash:
Depletion and depreciation expense	6		3,815,509			210,000			10,521,936			262,000
Stock based compensation			-			-			9,073,228			-
Deferred taxes	19		2,398,924			-			2,398,924			-
Listing expense	2		1,301,692			-			1,301,692			-
Accretion expense			4,613			1,000			13,556			3,000
Interest on lease liability			3,927			-			5,229			-
Amortization of debt issuance costs	9		236,961			-			833,260			-
Asset back preferred instrument interest	12		532,593			-			1,310,975			-
Fair value change on development partnership	7, 8		9,638,401			-			12,310,373			-
Impairment of exploration and evaluation assets			-			-			-			3,121,873
Unrealized loss on commodity contracts	22(c)		7,534,985			-			25,105,949			-
Net change in non-cash working capital	20		(13,450,912	)		(3,198,607	)		(9,095,806	)		(1,612,706	)
Cash flows from/(used in) in operating activities			(9,974,730	)		(2,864,542	)		(1,190,641	)		(2,649,354	)

Investing Activities

Expenditures on property, plant and equipment	6		(23,614,898	)		(562,636	)		(38,498,017	)		(5,402,416	)
Expenditures of exploration and evaluation assets	5		(3,294,209	)		(71,617	)		(6,763,605	)		(262,749	)
Net change in non cash working capital	20		16,062,271			3,567,952			25,828,660			7,449,929
Cash flows used in investing activities			(10,846,836	)		2,933,699			(19,432,962	)		1,784,764

Financing Activities
Issuance of shares for cash, net of issuance costs	13		5,628,045			-			13,672,745			-
Cash acquired on acquisition	2		396,173			-			396,173			-
Proceeds from development partnerships	7, 8		4,023,733			-			33,955,569			-
Repayment of development partnerships	7, 8		(1,853,127	)					(1,853,127	)
Repayment of promissory notes	10		-			-			(1,875,000	)		-
Proceeds from promissory notes	10		-			-			3,375,000			-
Repayment of long-term debt	9		(3,767,189	)		-			(15,184,356	)		-
Repayment of asset backed preferred instruments	12		-			-			(4,735,700	)		-
Net change in non-cash working capital	19		2,881,549			-			-			-
Cash flows from financing activities			7,309,184			-			27,751,304			-

Increase/(decrease) in cash			(13,512,382	)		69,157			7,127,701			(864,590	)

Cash, beginning of period			23,529,641			8,832,968			2,889,558			9,766,715

Cash, end of period		$	10,017,259		$	8,902,125		$	10,017,259		$	8,902,125

Financial Assets	Subsequent Measurement
Cash	Amortized cost
Accounts receivable	Amortized cost
Financial Liabilities	Subsequent Measurement
Accounts payable and accrued liabilities	Amortized cost
Derivative commodity contracts	Fair value through profit or loss
Development partnership liabilities	Fair value through profit or loss
Promissory notes	Amortized cost
Lease obligations	Amortized cost
Asset backed preferred instrument	Amortized cost
Long-term debt	Amortized cost


2021	$	2,937,732
2022		7,722,206
2023		4,564,814
2024		3,347,998
2025		2,892,873
Thereafter		6,678,417
	$	28,144,040

"signed" Craig Perry	"signed" Stephen Schaefer
Director	Director

		HB2 Member		SVS Shares	MVS Shares	PVS Shares						Non-controlling		Total shareholders'
	Note	Units		Number	Number	Number	Share Capital		Capital Reserve	Accumulated deficit		interest		equity/(deficiency)
Opening Balance January 1, 2020		17,083,501		-	-	-	$37,097,376		$430,734	$(32,227,666	)	$-		$5,300,444
Affiliate contribution		-		-	-	-	-		4,592,641	-		-		4,592,641
Net loss and comprehensive loss for the period		-		-	-	-	-		-	(4,423,521	)	-		(4,423,521	)
Ending Balance September 30, 2020		17,083,501		-	-	-	$37,097,376		$5,023,375	$(36,651,187	)	$-		$5,469,564

Ending Balance January 1, 2021		17,083,501		-	-	-	$37,097,376		$5,023,375	$(39,757,844	)	$-		$2,362,907

Issuance of member units for cash	13	819,215		-	-	-	8,044,700		-	-		-		8,044,700
Issuance of member units exchanged for promissory notes	13	353,870		-	-	-	3,475,000		-	-		-		3,475,000
Issuance of member units for exploration and evaluation assets	13	356,415		-	-	-	3,499,995		-	-		-		3,499,995
Issuance of member units to contractors	13	923,954		-	-	-	9,073,228		-	-		-		9,073,228
Redemption of member units	12, 13	(3,992,629	)	-	-	-	(8,680,786	)	-	(11,884,916	)	-		(20,565,702	)
Allocation of opening non-controlling interest	14	(16,168,422	)	-	-	-	(18,721,276	)	29,436,057	-		(10,714,781	)	-
Issuance of member units exchanged for promissory notes	13	234,216		-	-	-	2,300,000		-	-		-		2,300,000
Origination Unit split 1:3	2	31,557,084		-	-	-	-		-	-		-		-
Shares issued for cash, net of share issuance costs of $247,218	13	-		161,976	17,057.000	-	5,499,832		-	-		-		5,499,832
Exchange of units for SVS and MVS	13	(31,167,204	)	1,427,421	297,397.830	-	-		-	-		-		-
Proportiante Voting Shares issued for cash	2	-		-	-	15,947.292	128,213		-	-		-		128,213
Shares issued on business acquisition	2	-		534,384	-	-	1,697,865		-	-		-		1,697,865
Net loss and comprehensive loss for the period		-		-	-	-	-		-	(51,614,575	)	(3,355,382	)	(54,969,957	)
Ending Balance September 30, 2021		-		2,123,781	314,454.830	15,947.292	$43,414,147		$34,459,432	$(103,257,335	)	$(14,070,163	)	$(39,453,919	)

September 30, 2021		Current			Long-term			Total
Drawn balance	$	9,185,127		$	18,958,913		$	28,144,040
Borrowing costs		(720,064	)		(1,512,602	)		(2,232,666	)
Total	$	8,465,063		$	17,446,311		$	25,911,374

		Nine months ended		Nine months ended
		September 30, 2021		September 30, 2020
Current tax expenses	$	-	$	-
Deferred tax expense		2,398,924		-
	$	2,398,924	$	-

		September 30, 2021		December 31, 2020
Trade receivables from sales of crude oil and natural gas	$	12,375,005	$	5,593,956
Joint interest billing receivables and other	$	384,863		528,007
Balance, end of period	$	12,759,868	$	6,121,963

		September 30, 2021		December 31, 2020
Current	$	10,676,766	$	4,907,872
31 - 60 days		2,083,102		686,084
61 - 90		-		-
Greater than 90 days		-		528,007
Balance, end of period	$	12,759,868	$	6,121,963

Commodity	Expiry	Type	Average Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	Dec 2023	Swap	$0.20	5,347,608	NGL-Mont Belvieu
Propane (gallons)	Dec 2023	Swap	$0.52	3,287,866	NGL-Mont Belvieu
Natural gas (gallons)	Dec 2023	Swap	$0.95	2,106,699	NGL-Mont Belvieu
Iso butane (gallons)	Dec 2023	Swap	$0.56	687,956	NGL-Mont Belvieu
Nor butane (gallons)	Dec 2023	Swap	$0.57	1,599,625	NGL-Mont Belvieu
Natural gas (mmbtu)	Dec 2028	Differential Swap	$0.07	2,833,007	Henry Hub -Nymex vs East TX
Natural gas (mmbtu)	Dec 2028	Swap	$2.61	2,712,266	Henry Hub -Nymex
Crude oil (bbl)	Dec 2028	Swap	$43.38	818,006	WTI-Nymex
Crude oil (bbl)	Nov 2021	Put	$50.00	50,000	WTI-Nymex
Crude oil (bbl)	Dec 2021	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Jan 2022	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Mar 2022	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Apr 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	May 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	Jun 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	Nov 2021	Short	$70.31	50,000	WTI-Nymex
Crude oil (bbl)	Dec 2021	Short	$68.64	40,000	WTI-Nymex
Crude oil (bbl)	Jan 2022	Short	$71.11	10,000	WTI-Nymex
Crude oil (bbl)	Feb 2022	Short	$70.51	10,000	WTI-Nymex
Crude oil (bbl)	Mar 2022	Short	$69.93	8,000	WTI-Nymex
Crude oil (bbl)	Apr 2022	Short	$69.36	10,000	WTI-Nymex
Crude oil (bbl)	May 2022	Short	$68.78	30,000	WTI-Nymex
Natural gas (mmbtu)	Nov 2021	Short	$4.879	10,000	Nat Gas-Nymex
Natural gas (mmbtu)	Dec 2021	Short	$4.994	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	Jan 2022	Short	$4.916	160,000	Nat Gas-Nymex
Natural gas (mmbtu)	Feb 2022	Short	$4.810	160,000	Nat Gas-Nymex
Natural gas (mmbtu)	Mar 2022	Short	$4.656	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	Apr 2022	Short	$3.694	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	May 2022	Short	$3.578	30,000	Nat Gas-Nymex