Alpine Summit Energy Partners, Inc.: Exhibit 99.3

Set out below is management's discussion and analysis ("MD&A") of financial and operating results for Alpine Summit Energy Partners, Inc. ("ALPS" or the "Company")( formerly Red Pine Petroleum Ltd.) for the three and nine months ended September 30, 2021. It should be read in conjunction with the Company's unaudited interim consolidated financial statements for the three and nine months ended September 30, 2021 and 2020. These documents appear under the SEDAR profile of Alpine Summit Energy Partners, Inc. This MD&A is dated November 22, 2021. See discussion related to "Forward-Looking Statements", "Boe Presentation" and "Non-GAAP Measurements".

Financial data presented below have largely been derived from the Company's unaudited interim, consolidated financial statements for the three and nine months ended September 30, 2021 and 2020 (the "financial statements"), prepared in accordance with International Financial Reporting Standards ("IFRS"). Accounting policies adopted by the Company are referred to in Note 3 to the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2021, and September 30, 2020. The reporting currency is the United States dollar. Comparative information is provided for the three and nine months ended September 30, 2020 and the year ended December 31, 2020.

The Company is a U.S. energy developer and financial company focused on maximizing growth and return on equity. The Company is currently focusing its drilling activity in the Austin Chalk and Eagle Ford formations in the Giddings Field, a premier acreage location which has produced substantial amounts of oil and gas for decades. Oil migrates into the chalk through microfractures and fills the tectonic fractures and the Austin Chalk, which directly overlies the oil-sourcing Eagle Ford formation through micro fractures and fills the tectonic fractures and the porous matrix.

The Company plans on focusing on developing its existing and adjacent footprint over the next several years while also evaluating additional development projects that fit its investment criteria.

The Company's capital allocation strategy is designed to optimize return on capital and cash flow available for distribution to shareholders.

• Maintained average gross production of approximately 5,400 boe/day and 4,700 boe/day for the three and nine months ended September 30, 2021.

• ALPS and third-party investors capitalized the second development partnership with $20.8 million of drilling capital for forward drilling plans.

• Closed a business combination agreement and began listing on the TSXV under the ticker symbol ALPS.U.

• Formation of a new strategic partnership with Ageron Energy, LLC ("Ageron") and the signing of leases on nearly 8,000 net acres in Webb County, Texas. As part of this partnership and transaction, the Company will gain access to 35 to 40 attractive natural gas drilling locations in South Texas and will further strengthen its drilling capabilities by working alongside the experienced Ageron operating team.

Consistent with its stated strategy to maximize both efficiency and velocity of capital, the Company completed a Reverse Takeover transaction with Red Pine Petroleum Ltd. This listing event is intended to facilitate growth by enabling novel capital solutions and liquidity for shareholders. Refer to Note 2 of the unaudited interim consolidated financial statements for specific details of the transaction.

Prior to executing the definitive agreement, the Company entered into a series of transactions to simplify its capital structure and solidify its balance sheet. First, it used the proceeds of the Goldman Sachs facility to reacquire working interests in producing wells from Colony Capital (2020). Next, it entered into a re-purchase agreement with one of its significant legacy stakeholders, the purchase of which was financed through a combination of a new asset-backed preferred instrument along with cash received through an additional equity issuance. Finally, it retired and/or extended some short-term debt maturities in order to ensure appropriate funding was in place.

During the first half of 2021, the Company also formed its first Development Partnership ("DP1 Maverick"). The Company and partners capitalized this partnership to develop a discrete set of drilling locations. During the three months ended September 30, 2021, the Company formed its second development partnership ("DP 2 Maverick"). The Company and its partners capitalized this partnership to develop a discrete set of drilling locations.

The Company's base case development plan is to drill and complete approximately 10 to 12 wells during Calendar year 2021. The development schedule is concentrated around the Company's existing acreage position and activity area. The Company intends, and expects, to use lending facilities to leverage those wells once online, and refinance forward development capital (see Note 23, of the interim consolidated financial statements).

During 2022 the Company plans on continuing to grow production through further development of its controlled acreage. The Company expects to continue to use the development partnership structure to facilitate drilling activity and plans on drilling 20 to 30 wells during 2022 in previously leased acreage. The Company also expects to look for additional development areas to add to its drilling inventory

The Company also plans on starting a capital return program for 2022, which consists of i) launch of a monthly dividend and ii) a share buyback program. The dividend policy approved by the Board, and expected to commence in January 2022, provides for the Company to distribute to its shareholders a portion of the funds received by the Company from its operating subsidiary, HB2 Origination, LLC ("HB2"), which intends to distribute US$1.45 million per month to the Company's shareholders and HB2's other unitholders (which represents approximately 50.1 million Subordinate Voting Shares ("SVS"), on a fully converted basis, as of the date of this news release). The Company also intends to apply to the TSX Venture Exchange (the "TSXV") for approval to implement a normal course issuer bid ("NCIB") to repurchase up to $17.5 million of its SVS through the facilities of the TSXV at market prices during calendar year 2022 (subject to the 5% limit governing the NCIB). The NCIB is subject to the review and approval of the TSXV.

The Company's guidance for 2022 is based upon completion of our development partnership 3 ("DP3") along with two additional wells funded from the Company's balance sheet - for a total of seven wells completed and brought online in 2022. It also assumes well results from existing and new production in line with third party engineering forecasts. As previously disclosed, the Company's guidance for 2022 is for production of 13,500 gross BOE/day and $110MM of EBITDA (refer to Non-GAAP disclosures).

Guidance is based on forward strip pricing at the time of issuance, for 2022 an average price of:

Production increased for three and nine months ended September 30, 2021 as compared to the comparative periods due to the impact of increased working interest from December 22, 2020 related to the acquisition of working interests from Colony Capital. After the acquisition, the average working interest of six of the new wells brought onto production was 95.49%, previously 8.12%.

In addition, four new wells were added to production in the three months ended June 30, 2021, and an additional two new wells were added to production during the three months ended September 30, 2021.

Revenue from product sales increased for three and nine months ended September 30, 2021 as compared to the comparative periods due to the impact of increased working interest from December 22, 2020 related to the acquisition of working interests from Colony Capital. In addition, production from six wells was brought online as part of the DP 1 Maverick and DP 2 Maverick partnerships. After the acquisition, the average working interest of six of the new wells brought onto production was 95.49%, previously 8.12%.

Due to the impact of reduced commodity prices from impacts of COVID-19, the Company shut in all wells from March 2020 to July 2020.

On a per-Boe basis, the Company's average realized price for the three and nine months ended September 30, 2021 increased compared to the same periods of 2020, when market prices decreased due in large part to effects of COVID-19. Regional natural gas price increases in February 2021 also created a larger than normal price increase for the nine months ended September 30, 2021.

Royalties, as a percentage of revenue from product sales, increased in the three months ended September and increased for the nine months ended September 30, 2021 compared to the same periods in 2020; this is primarily due to changes to the weighted average production from wells with variable royalty rates. The Company anticipates these rates to remain relatively consistent with current results in future periods.

Total production and transportation costs for the three and nine months ended September 30, 2021 increased when compared to the same periods of 2020 due to increased production noted above. The decrease in total production and transportation costs per Boe is due to well maturity and economies of scale.

General and administrative costs for the three and nine months ended September 30, 2021 increased as compared to the same periods of 2020 primarily due to higher professional and legal fees. The Company also brought on employees in the nine months ended September 30, 2021, which were previously compensated under a management service agreement.

Over the course of the Company's completion of its listing on the TSXV during the nine months ended September 30, 2021, it incurred $1,567,967 in expenses related to the listing. These expenses were 2.81% of revenue, $1.22 per BOE for the nine months ended September 30, 2021.

The increase in interest and financing costs for three and nine months ended 2021 as compared to the same periods of 2020 is mainly due to the execution of the Goldman Sachs credit facility and associated long-term debt balances and fair value changes associated with the development partnership liabilities.

Depletion expense increased for the three and nine months ended September 30, 2021 as compared to the comparative prior period as a result of increase producing wells in 2021, and associated depletion base of Property, Plant and Equipment. For the nine months ended September 30, 2020 all existing wells were shut in from March 2020 to July 2020 and minimal depletion was recorded.

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 certain Company 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) of the unaudited interim consolidated financial statements 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)) of the interim consolidated financial statements.

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.

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

December 31, 2020		Current			Long-term			Total
Drawn balance	$	18,090,987		$	25,237,409		$	43,328,396
Borrowing costs		(1,042,478	)		(2,023,448	)		(3,065,926	)
Total	$	17,048,509		$	23,213,961		$	40,262,470

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

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 (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.

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.

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

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.

During the three and nine months ended September 30, 2021, the Company recorded a deferred tax liability and a correlating deferred tax expense of $2,398,924 (2020 - $Nil) to reflect temporary difference between the carrying value for accounting versus tax values.

In the nine months ended September 30, 2021 the Company incurred capital expenditures on property, plant and equipment of $38.5 million compared to $5.4 million in the nine months ended September 30, 2020. The majority of activity for these periods relates to the drilling of horizontal wells in the Giddings Field.

During the nine months ended September 30, 2021, the Company expended $6.8 million related exploration and evaluation assets. Additions relate mainly to undeveloped lands and drilling costs without assigned reserves prior to their transfer to Property, Plant and Equipment.

Accounts payable and accrued liabilities include operating, royalty, general and administrative and capital costs payable. When appropriate, net payables in respect of cash calls issued to partners regarding capital projects and estimates of amounts owing but not yet invoiced to the Company are included in accounts payable. The level of accounts payable and accrued liabilities at September 30, 2021 corresponds to the Company's field capital expenditure program.

The Company's decommissioning liability of $1,275,042 represents the present value of estimated future costs to be incurred to abandon and reclaim wells and facilities, drilled, constructed or purchased by the Company. The undiscounted and inflated amount of the liability at September 30, 2021 was approximately $2,074,252. The liability for all wells covered under this liability are expected to be incurred between 2025 and 2058.

The Company's cash flow is highly variable, in large part because oil and natural gas are commodities whose prices are determined by worldwide and/or regional supply and demand, transportation constraints, weather conditions, availability of alternative energy sources and other factors, all of which are beyond the Company's control. World prices for oil and natural gas have fluctuated widely in recent months.

During the first half of 2020, oil prices dramatically collapsed due to the impact of the Coronavirus pandemic and other conditions, only starting to stabilize and recover slightly in the third quarter of 2020. On January 30, 2020, the World Health Organization declared the Coronavirus outbreak (COVID-19) a "Public Health Emergency of International Concern" and on March 11, 2020 declared COVID-19 a pandemic. As a result, there has been a significant demand shock worldwide which created downward pressure on oil prices. There had also been increased supply due to the dispute between Saudi Arabia and Russia which had a further adverse impact on oil prices. These factors combined to result in oil prices never before seen, at one point during the second quarter of 2020, prices in North America for oil were briefly negative. Oil prices slightly recovered in second half of 2020 but remained well below 2019 comparative prices with benchmark crude oil prices for the fourth quarter of 2020 down 30% compared to the fourth quarter of 2019. At September 30, 2021, commodity prices have increased approximately 25% over their January 31, 2020 pre-pandemic values.

Management of cash flow variability is an integral component of the Company's business strategy. Business conditions are monitored regularly and reviewed with Management to establish risk management guidelines used by management in carrying out the Company's strategic risk management program.

The Company has elected not to use hedge accounting and, accordingly, the fair value of the financial contracts is recorded at each period-end. The fair value may change substantially from period to period depending on commodity forward strip prices for the financial contracts outstanding at the balance sheet date. The change in fair value from period-end to period-end is reflected in the income for that period. As a result, income may fluctuate considerably.

At September 30, 2021 the Company had the following commodity contracts, with a total mark-to-market liability of $29,627,322.

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

The unrealized loss for the nine months ended September 30, 2021 of $25,105,950 and realized losses of $14,276,939 (2020 - $Nil unrealized and $412,523 realized loss) was a result of an increase in future strip prices from the date the commodity contracts were entered into and actual commodity prices during the period. There were no unrealized losses during the nine months September 30, 2020.

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 1 Maverick, will maintain control of the DP 1 Maverick and will continue to consolidate 100% of the operations of the DP 1 Maverick.

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.

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 the Subsequent Event section below 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 2 Maverick, will maintain control of the DP 2 Maverick and will continue to consolidate 100% of the operations of the DP 2 Maverick.

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.

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 March 5, 2021, the Company executed an 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 Origination Member Units at the time) along with a $1,000,000 promissory note 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.

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 Origination 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.

In connection with the BCA and reverse takeover, 16,168,422 Origination Member Units elected to not convert. Refer to Non-controlling Interest ("NCI") discussion below.

161,976 SVS and 17,057 MVS were issued in connection with the BCA Finco raise for approximate proceeds of $5.5 million, net of issuance costs.

Remaining Origination Unit Holders converted their holdings into 1,427,421 SVS and 297,397.830 MVS in conjunction with the BCA and reverse takeover

15,947.292 PVS were issued to a non converting Origination Unit Holder for proceeds of $128,213

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.

A full exchange of all non-voting units of HB2 Origination (refer to Non-Controlling Interest discussion below) and conversion of all MVS and PVS into SVS would result in approximately 50.1 million SVS outstanding.

		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 interests 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.

In connection with the Business Combination Agreement ("BCA") (refer to Note 2 of the unaudited interim consolidated financial statements), certain Origination equity holders elected not to convert their shareholdings in Origination into SVS/MVS of the Company. The non-converting equity holders amount to a 32.5% economic interest of 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.

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.

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 expects to be paid $250,000 for services provided in the fourth quarter of 2021.

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.

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

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. 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, ii) commenced a drilling program to increase cash flows from operating activities, iii) raised significant funds through two development partnerships, iv) settled promissory notes with a combination of cash and Origination Member Units and v) entered into a new revolving credit facility.

The Company is required to meet certain financial covenants under the Goldman Facility. 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;

The 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. 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. In addition, the Company issued convertible promissory notes in June 2021 for proceeds of $2.3 million and converted those convertible promissory notes into 234,216 Origination Member Units. The Company also repaid $15.2 million of long-term debt and $4.7 million of asset backed preferred instruments. 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.

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 Maverick program, Company has retired liabilities of $15,288,594.

One of the DP1 Maverick partners exercised the put right provided to such partners by DP1 Maverick regarding residual interests in their associated investment and elected to exchange the remaining interest in DP1 Maverick 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 substantially the same compared to those of the first and second development partnerships.

The Company, through the structure of the DP3 Maverick, will maintain control of DP3 Maverick 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

Summarized information by quarter for the two years ended September 30, 2021 appears below.

The Company acquired additional working interests in producing oil and gas properties during the fourth quarter of 2020 in an attempt to increase operating results. These increased working interest have increased overall revenue from product sales and cash flows from operating activities.

The impact of unrealized commodity contracts and financing expenses related to fair value changes and associated development partnership liabilities created the increase in net loss for the quarter.

The Company does not have any special-purpose entities nor is it a party to any arrangements that would be excluded from the balance sheet.

The Company's critical accounting judgements, estimates and policies are described in notes 3 and 4 to the September 30, 2021 interim unaudited consolidated financial statements. Certain accounting policies are identified as critical because they require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain, and because the estimates are of material magnitude to revenue, expenses, funds flow from operations, income or loss and/or other important financial results. These accounting policies could result in materially different results should the underlying conditions change or the assumptions prove incorrect.

As of the date of this MD&A, the Company has 10,335.33, 32,535,731 and 15,947.292 for current MVS, SVS and PVS.

Certain forward-looking information and statements are set forth in this document, including management's assessment of the Company's future plans and operations specifically in relation to 2021 and 2022, and contain forward-looking information within the meaning of applicable Canadian securities legislation. Such statements or information are generally identifiable by words such as "anticipate", "believe", "intend", "plan", "expect", "schedule", "indicate", "focus", "outlook", "propose", "target", "objective", "priority", "strategy", "estimate", "budget", "forecast", "would", "could", "will", "may", "future" or other similar words or expressions and include statements relating to or associated with individual wells, facilities, regions or projects as well as timing of any future event which may have an effect on the Company's operations and financial position. Forward-looking statements are based on expectations, forecasts, and assumptions made by the Company using information available at the time of the statement and historical trends which includes expectations and assumptions concerning: the accuracy of reserve estimates and valuations; performance characteristics of producing properties; access to third-party infrastructure; government policies and regulation; future production rates; accuracy of estimated capital expenditures; availability and cost of labour and services and owned or third-party infrastructure; royalties; development and execution of projects; the satisfaction by third parties of their obligations to the Company; and the receipt and timing for approvals from regulators and third parties. All statements and information concerning expectations or projections about the future and statements and information regarding the future business plan or strategy, timing or scheduling, production volumes with splits by commodity, production declines, expected and future activities and capital expenditures, commodity prices, costs, royalties, schedules, operating or financial results, future financing requirements, and the expected effect of future commitments are forward-looking statements.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, but are not limited to:

Statements relating to "reserves" or "resources" are forward-looking statements, including financial measurements such as net present value, as they involve the assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.

Readers are advised that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Origination disclaims any intention or obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required under securities law.

Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Boe Presentation - Natural gas is converted to a barrel of oil equivalent ("Boe") using six thousand cubic feet ("Mcf") of natural gas equal to one barrel of crude oil unless otherwise stated. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one barrel ("Bbl") is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe measurements and conversions in this report are derived by converting natural gas to crude oil in the ratio of six thousand cubic feet of natural gas to one barrel of crude oil.

Non-GAAP Measurements - Within this MD&A, references are made to terms which are not recognized under Generally Accepted Accounting Principles ("GAAP"). Specifically, "field operating netbacks", "field operating netbacks including hedging", and measurements "per commodity unit" and "per Boe" do not have any standardized meaning as prescribed by GAAP and are regarded as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar amounts for other entities and readers are cautioned that use of such measures to compare enterprises may not be valid. Non-GAAP terms are used to benchmark operations against prior periods and peer group companies and are widely used by investors, lenders, analysts and other parties.

Field operating netbacks and field operating netbacks including hedging are common non-GAAP measurements applied in the crude oil and natural gas industry and are used by management to assess operational performance of assets. Field operating netbacks are calculated by deducting royalties, production and transportation expenses from revenue from product sales and are presented on a per-Boe basis.

The Company uses measures primarily based on IFRS and also uses some secondary non-GAAP measures. The non-GAAP measure included in this presentation is: Earnings before interest, taxes, depletion and amortization ("EBITDA"). This measure is used to enhance the Company's reported financial performance or position. This is a useful complementary measure that is used by management in assessing the Company's financial performance, efficiency and liquidity, and they may be used by the Company's investors for the same purpose. The non-GAAP measure does not have standardized meanings prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application.

The Company believes that EBITDA, considered along with net earnings (loss), is a relevant indicator of trends relating to our operating performance and provides management and investors with additional information for comparison of our operating results to the operating results of other companies. All figures presented do not reflect any potential impact of Non-Controlling Interest. The Company's calculation of EBITDA is net income/(loss) adding back interest, non-cash financing expenses, depletion, depreciation, accretion, amortization, impairment and non-recurring costs and expenses.

There are a number of risks facing participants in the Canadian crude oil and natural gas industry. Some risks are common to all businesses while others are specific to the industry. The following reviews a number of the identifiable business risks faced by the Company. Business risks evolve constantly and additional risks emerge periodically. The risks below are those identified by management at the date of completion of this MD&A, and may not describe all of the material business risks, identifiable or otherwise, faced by the Company.

The Company's financial results are largely dependent on the prevailing prices of crude oil and natural gas. Crude oil and natural gas prices are subject to fluctuations in supply, demand, market uncertainty and other factors that are beyond the Company's control. This can include but is not limited to: the global and domestic supply of and demand for crude oil and natural gas; global and North American economic conditions; the actions of OPEC or individual producing nations; government regulation; political stability; the ability to transport commodities to markets; developments related to the market for liquefied natural gas; the availability and prices of alternate fuel sources; and weather conditions. In addition, significant growth in crude oil and natural gas production in the United States has resulted in pressure on transportation and pipeline capacity which contributes to fluctuations in prices. All of these factors are beyond the Company's control and can result in a high degree of price volatility.

Fluctuations in the price of commodities and associated price differentials affect the value of the Company's assets and the Company's ability to pursue its business objectives. Prolonged periods of low commodity prices and volatility may also affect the Company's ability to meet guidance targets and its financial obligations as they come due. Any substantial and extended decline in the price of crude oil and natural gas could have an adverse effect on the Company's reserves, borrowing capacity, revenues, profitability and funds flow and may have a material adverse effect on the Company's business, financial condition, results of operations, prospects and the level of expenditures for the development of crude oil and natural gas reserves. This may include delay or cancellation of existing or future drilling or development programs or curtailment in production as the economics of producing from some wells may become impaired.

In addition, bank borrowings available to the Company are, in part, determined by the value of the Company's assets. A sustained material decline in commodity prices from historical average prices could reduce the value of the Company's assets, therefore reducing the bank credit available to the Company which could require that a portion, or all, of the Company's bank debt be repaid, as well as curtailment of the Company's investment programs.

The Company conducts regular assessments of the carrying amount of its assets in accordance with IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of time, the carrying amount of the Company's assets may be subject to impairment.

Market conditions which include global crude oil and natural gas supply and demand and global events including actions taken by OPEC, Russia's withdrawal from OPEC, sanctions against Iran and Venezuela, slowing growth in China and emerging economies, weakening global relationships, isolationist and punitive trade policies, shale production in the United States, sovereign debt levels and political upheavals in various countries including growing anti-fossil fuel sentiment, the outbreak of COVID-19 and the price war between Saudi Arabia and Russia have caused significant volatility in commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks, including attacks on crude oil infrastructure in crude oil producing nations, in the United States or other countries could adversely affect the economies of the United States and other countries. These events and conditions have caused a significant reduction in the valuation of crude oil and natural gas companies and a decrease in confidence in the future of the crude oil and natural gas industry.

The Company's exploration programs require sophisticated and scarce technical skills as well as capital and access to land and oilfield service equipment. The Company endeavours to minimize the associated risks by ensuring that:

• activity is focused in core regions where internal expertise and experience can be applied;

• development drilling is in areas where there is immediate or near-term access to facilities, pipelines and markets or where construction of necessary infrastructure is within the Company's financial capacity;

• the Company seeks to act as operator and to maintain a 100% or high working interest. The Company can thus control the timing, cost and technical content of its exploration and development programs.

Nevertheless, drilling and completing a well may not result in the discovery of economic reserves, or a well may be rendered uneconomic by commodity price declines or an increasing cost structure.

In addition, the Company's investment program is currently focused on development of the Austin Chalk/Eagle Ford properties, resulting in asset concentration risk.

When the Company identifies hydrocarbons of sufficient quantity and quality and successfully brings them on stream, it faces a pricing environment which is volatile and subject to a myriad of factors, largely out of the Company's control. Low prices for the Company's expected primary products will have a material effect on the Company's funds flow and profitability and thus re-investment capacity, and ultimate growth potential. Low prices also limit access to capital, both equity and debt. The Company in part mitigates the risk of pricing volatility through the use of risk management contracts, such as fixed priced sales, swaps, collars and similar contracts. However, access to such commodity price protection instruments may not be available in future periods, or available only at a cost considered to be uneconomic.

Changes in productivity in wells and areas developed by the Company could result in termination or limitation of production, or acceleration of decline rates, resulting in reduced overall corporate volumes and revenues. In addition, wells drilled by the Company tend to produce at high initial rates followed by rapid declines until a flattening decline profile emerges. There is a risk that the decline profile which eventually emerges for newly drilled wells is subeconomic.

The Company's current and future exploration, development and production activities involve the use of heavy equipment and the handling of volatile liquids and gases. Catastrophic events, regardless of cause or responsibility, such as well blowouts, explosions and fires within pipeline, gathering, or facility infrastructure, as well as failure of gathering systems or mechanical equipment, could lead to releases of liquids or gases, spills of contaminants, personal injuries and death, damage to the environment, as well as uncontrolled cost escalation. With support from suitably qualified external parties, the Company has developed and implemented policies and procedures to mitigate environmental, health and safety risks. These policies and procedures include the use of formal corporate policies, emergency response plans, and other policies and procedures reflecting what management considers to be best oilfield practices. These policies and procedures are subject to periodic review. The Company also manages environmental and safety risks by maintaining its operations to a high standard and complying with all state and federal environmental and safety regulations. Nevertheless, application of best practices to field operations serves only to mitigate, not eliminate, risk. The Company maintains industry-specific insurance policies, including environmental damage and control of well, on important owned drilled locations and specific equipment. Although the Company believes its current insurance coverage corresponds to industry standards, there is no guarantee that such coverage will be available in the future, and if it is, at a cost acceptable to the Company, or that existing coverage will necessarily extend to all circumstances or incidents resulting in loss or liability.

A loss in key personnel of the company could delay the completion of certain projects or otherwise have a material adverse effect on the Company. Member unit holders are dependent on the Company's management and staff in respect of the administration and management of all matters relating to the Company's assets.

The Company seeks to follow best practices to minimize environmental impact of its operations, including:

• Focus on water efficiency: Origination utilizes recycled water for well completion and workover operations to minimize use of fresh water.

• Methane and hydrocarbon gases recapture: Origination uses vapor recovery systems to reduce methane and other hydrocarbon gases emissions at its production facilities.

• Minimizing inactive wells, a major source of methane off-gasses.

The Company also seeks innovative solutions to steward environmental resources, including use of solar powered lights on our locations during drilling and completion operations, using smaller operational location areas to minimize disturbance and restoring ground cover through planting grass on construction and operation areas.

The recent collapse in prices for crude oil and natural gas, in a historical context, has reduced field activity and thus concerns over access to equipment and services. Further, service costs have fallen in recent years and remain relatively stable. Nevertheless, periods of high field activity can result in shortages of services, products, equipment, or manpower in many or all of the components of the development cycle. Increased demand leads to higher land and service costs during peak activity periods. In addition, access to transportation and processing facilities may be difficult or expensive to secure. Origination's competitors include companies with far greater resources, including access to capital and the ability to secure oilfield services at more favourable prices and to build out operations on a scale which lowers the economic threshold for exploitation of a resource. The Company competes by maintaining a large inventory of self-generated exploration and development locations, by acting as operator where possible, and through facility access and ownership. The Company also seeks to carefully manage key supplier relationships. Declines in commodity prices should, in principle, result in lower service costs; however, this may be offset by service providers choosing to retire equipment rather than operate at sub-optimum prices, or ceasing business altogether.

Capital expenditures are designed to accomplish two main objectives, namely the generation of short and medium-term funds flow from development activities, and the expansion of future funds flow from the identification of or further development of reserves. The Company focuses its activity in core areas, which allows it to leverage its experience and knowledge, and acts as operator wherever possible. The Company may use farmouts to minimize risk on certain acreage it considers higher risk or where total capital invested exceeds an acceptable level. In addition, the Company may enter into risk management contracts in support of capital programs, and to manage future debt levels. Generally, capital programs are financed from funds flow and disciplined use of debt, and occasionally, equity. Failure to develop producing wells or to sell production at a reasonable price and thus maintain an acceptable level of funds flow, will result in the exhaustion of available financial resources and will require the Company to seek additional capital which may not be available, or only available on unacceptable terms, or terms highly dilutive to existing member unit holders. In addition, credit availability from the Company's bankers is also necessary to support capital programs and any changes to credit arrangements may have an effect on both the size of the Company's future capital programs and the timing of expenditures. As the banking facility available to the Company is based on future funds flows from existing production, falling commodity prices will likely have an effect on borrowing availability.

Estimates of economically recoverable crude oil, natural gas reserves and natural gas liquids, and related future net cash flows, are based upon a number of variable factors and assumptions. These include commodity prices, production, future operating, transportation, development and facility as well as decommissioning costs, access to market, and potential changes to the Company's operations or to reserve measurement protocols arising from regulatory or fiscal changes. All of these estimates may vary from actual circumstances, with the result that estimates of recoverable crude oil and natural gas reserves attributable to any property are subject to revision. In future, the Company's actual production, revenues, royalties, transportation, operating expenditures, finding, development, facility and decommissioning costs associated with its reserves may vary from such estimates, and such variances may be material.

Production of crude oil and natural gas reserves at an acceptable level of profitability may not be possible during periods of low commodity prices. The Company will attempt to mitigate this risk by focusing on higher netback opportunities and will act as operator where possible, thus allowing the Company to manage costs, timing, method and marketing of production. Production risk is also addressed by concentrating field activity in regions where infrastructure is readily accessible at an acceptable cost. In periods of low commodity prices the Company may shut in production, either temporarily or permanently, if netbacks are sub-economic.

Production is also dependent in part on access to third-party facilities and pipelines with the result that production may be reduced by outages, accidents, maintenance programs, prorationing and similar interruptions outside of the Company's control.

The Company faces a number of financial risks over which it has no control, such as commodity prices, exchange rates, interest rates, access to credit and capital markets, as well as changes to government regulations and tax and royalty policies. The Company uses the guidelines below to address financial exposure. Although these guidelines result in conservative management of the Company's finances, they cannot eliminate the financial risks the Company faces.

• Internal funds flow provides the initial source of funding on which the Company's capital expenditure program is based.

• Debt, if available, may be utilized to expand capital programs, including acquisitions, when it is deemed appropriate and where debt retirement can be controlled. The Company measures debt levels against current or near-term funds flow. If the debt-to-funds-flow ratio becomes unacceptably high, capital programs will be postponed, assets sold or farmed out or other measures taken to bring debt levels down.

• Interest rate contracts, if available, may be used to manage fluctuations in interest rate.

• Equity, if available on acceptable terms, may be raised to fund acquisitions and capital programs.

• Farm-outs of projects may be arranged if management considers that the capital requirements of a project are excessive in the context of the Company's resources, or where the project affects the Company's risk profile, or where the project is of lower priority.

• Risk management contracts, if available, may be used to manage commodity price volatility when the Company has capital programs, including acquisitions, whose cost exceeds near-term projected funds flow and where capital programs involve longer-term commitments.

• The Company will also sell assets at an acceptable price if the proceeds can be redeployed in properties offering a higher netback or greater development potential.

Markets for future production of crude oil and natural gas are outside the Company's capacity to control or influence and can be affected by events such as weather, climate change, regulation, regional, national and international supply and demand imbalances, facility and pipeline access, geopolitical events, currency fluctuation, introduction of new or termination of existing supply arrangements, as well as downtime due to maintenance or damage, either to owned or third-party facilities and pipelines. The Company will attempt to mitigate these risks as follows:

• Properties are developed in areas where there is access to processing and pipeline or other transportation infrastructure, and, where possible, owned by the Company.

• The Company will delay drilling or tie-in of new wells or shut-in production if acceptable pricing cannot be realized.

The Company assesses its funds flow and borrowing capacity is sufficient to fund its existing capital budget. Nevertheless, funding is finite and investment must result in production being brought on stream, followed by the generation of funds flow and the identification of proved plus probable reserves. The Company entered into a secured credit facility with Goldman Sachs in late 2020 and may make additional draws from facility, upon successful drilling and completion efforts in the future.

Although equity is another source of financing, the Company is exposed to changes in the equity markets, which could result in equity not being available, or only available under conditions which are unacceptably dilutive to existing member unit holders. The inability of the Company to develop profitable operations, with the consequent exclusion from debt and equity markets, may result in the Company curtailing or suspending operations.

In the United States, the energy industry is subject to scrutiny, frequently hostile, by political and environmental groups. This may lead to increased regulation and increased compliance costs. In particular, there is a risk that existing royalty incentive programs could be terminated or amended, royalty or income tax rates could be increased, rules and regulations around well licensing or surface access could be changed, horizontal drilling and hydraulic fracturing could be subject to increased oversight or regulation.

The Company is dependent on information technology, such as computer hardware and software systems, in order to properly operate its business. These systems have the potential for information security risks, which could include potential breakdown, virus, invasion, cyber-attack, cyber-fraud, security breach and destruction or interruption of information technology systems by third parties or insiders. Unauthorized access to these systems could result in interruptions, delays, loss of critical and/or sensitive data or similar effects, which could have a material adverse effect on the protection of intellectual property and confidential and proprietary information, and on the Company's business, financial condition, results of operations and fund flow.

The Company's operations and its financial condition may be affected by uncontrollable, unpredictable and unforeseeable circumstances such as weather patterns, changes in contractual, regulatory or fiscal terms, actions by governments at various levels, both domestic and other, termination of access to third-party pipelines or facilities, actions by industry organizations, local communities, exclusion from certain markets or other undeterminable events.

The Company's business, operations and financial condition could be materially adversely affected by the outbreak of epidemics or pandemics or other health crises. In December 2019, COVID-19 was reported to have surfaced in Wuhan, China; on January 30, 2020, the WHO declared the outbreak a global health emergency; and on March 11, 2020 the WHO declared the outbreak of COVID-19 a global pandemic. The outbreak has spread exponentially throughout the world and despite the development and early-stage deployment of vaccines, a second wave is underway with numerous variants that have since emerged. The spread of COVID-19 has led companies and various jurisdictions to impose restrictions such as quarantines, business closures and domestic and international travel restrictions. The duration of the business disruptions internationally and related financial effect cannot be reasonably estimated at this time. Similarly, the Company cannot estimate whether or to what extent this pandemic and the potential financial effect may extend to countries outside of those currently affected.

Such public health crises can result in volatility and disruptions in the supply, demand and pricing for crude oil and natural gas, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people, all of which could affect commodity prices, interest rates, credit ratings, credit risk and inflation. In particular, crude oil prices significantly weakened in 2020 in response to the outbreak of COVID-19. The risks to the Company of such public health crises also include risks to employee health and safety and a slowdown or temporary suspension of operations in geographic locations affected by an outbreak. This could include the Company's wells and facilities and/or third-party facilities and pipelines used by the Company. While there had been disruption on the Company's operations in 2020, the extent to which COVID-19 may affect the Company in the future is uncertain; it is possible that COVID-19 may have a material adverse effect on the Company's business, results of operations and financial condition.

Additional information relating to the Company is contained in the Listing Application which may be viewed under the SEDAR profile of Alpine Summit Energy Partners, Inc. (formerly Red Pine Petroleum, Inc.) at www.sedar.com.

		Three Months to September 30, 2021		Three Months to September 30, 2020		Nine Months to September 30, 2021		Nine Months to 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
NGLs		4,587,867		113,423		6,922,921		113,843
Total	$	23,427,075	$	1,239,879	$	55,889,227	$	1,867,790
% of Total Revenue by Product Type
Crude oil weighting		76.09%		86.40%		68.64%		90.80%
Natural gas weighting		4.33%		4.45%		18.97%		3.10%
NGL weighting		19.58%		9.15%		12.39%		6.10%

Average Selling price (1)
		Three Months to September 30, 2021		Three Months to September 30, 2020		Nine Months to September 30, 2021		Nine Months to September 30, 2020
Crude oil - Bbl	$	67.69	$	34.23	$	62.36	$	36.82
Natural gas - Mcf	$	1.48	$	1.60	$	4.63	$	1.58
NGL - Bbl	$	38.55	$	10.27	$	23.91	$	9.86
Per Boe	$	47.16	$	25.79	$	43.44	$	29.31

Royalties
		Three Months to September 30, 2021		Three Months to September 30, 2020		Nine Months to September 30, 2021		Nine Months to September 30, 2020
Charge for the period	$	6,689,789	$	342,631	$	15,611,640	$	582,630
Percentage of revenue from product sales		28.6%		27.6%		27.9%		31.2%
Per Boe	$	13.47	$	7.13	$	12.14	$	9.14

Production Costs
		Three Months to September 30, 2021		Three Months to September 30, 2020		Nine Months to September 30, 2021		Nine Months to September 30, 2020
Charge for the period	$	3,018,084	$	373,591	$	6,598,663	$	495,192
Percentage of revenue from product sales		12.9%		30.1%		11.8%		26.5%
Per Boe	$	6.08	$	7.77	$	5.13	$	7.77

Field Operating Netbacks
($/Boe)		Three Months to September 30, 2021			Three Months to September 30, 2020			Nine Months to September 30, 2021			Nine Months to September 30, 2020
Revenue from product sales	$	47.16		$	25.79		$	43.44		$	29.31
Royalties		(13.47	)		(7.13	)		(12.14	)		(9.14	)
Production costs		(6.08	)		(7.77	)		(5.13	)		(7.77	)
Field operating netback	$	27.61		$	10.89		$	26.17		$	12.40

General and Administrative Costs
		Three Months to September 30, 2021		Three Months to September 30, 2020		Nine Months to September 30, 2021		Nine Months to September 30, 2020
Charge for the period		1,661,449		186,248		7,650,282		1,351,908
Percentage of revenue from product sales		7.1%		15.0%		13.7%		72.4%
Per Boe	$	3.34	$	3.87	$	5.95	$	21.21

Depletion and Depreciation
		Three Months to September 30, 2021		Three Months to September 30, 2020		Nine Months to September 30, 2021		Nine Months to September 30, 2020
Charge for the period	$	3,815,509	$	210,000	$	10,521,936	$	262,000
Per Boe	$	7.68	$	4.37	$	8.18	$	4.11

Net Income / (Loss)
		Three Months to			Three Months to		Nine Months to			Nine Months to
		September 30, 2021			September 30, 2020		September 30, 2021			September 30, 2020
Net Income/(Loss)	$	(19,592,499	)	$	123,065	$	(52,571,033	)	$	(4,423,521	)
Per basic and diluted unit	$	(0.42	)	$	-	$	(1.13	)	$	(0.08	)


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

		Amount (000s)
December 1, 2020	$	5,425,000
Issued for cash		1,075,000
Converted to Origination Member Units		(4,475,000	)
Repayment of notes		(1,875,000	)
Issued for Cash		2,300,000
Converted to Origination Member Units		(2,300,000	)
September 30, 2021	$	150,000

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
Natrual 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

		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

		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

					2021						2020												2019
		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Revenue from product sales		23,427,075			12,836,239			19,625,913			2,568,289			1,239,879			40			627,871			756,974
Net income (loss)		(18,636,041	)		(24,751,922	)		(8,226,612	)		(3,007,192	)		123,065			(4,664,592	)		118,006			(19,456,117	)
Per unit - basic and diluted	$	(0.42	)	$	(1.68	)	$	(0.53	)	$	(0.18	)	$	0.01		$	(0.27	)	$	0.01		$	(1.14	)
Net capital expenditures		(26,909,107	)		(13,211,052	)		(5,151,463	)		(36,276,414	)		(1,901,004	)		(2,596,577	)		(2,434,335	)		(7,163,913	)
Average daily production (Boe)		5,399			3,805			4,983			981			523			-			170			150
Working capital deficiency		(80,891,770	)		(49,133,400	)		(24,142,999	)		(29,102,456	)		(9,512,412	)		(10,313,550	)		(5,198,785	)		(9,506,551	)