Introduction

Set out below is management's discussion and analysis ("MD&A") of financial and operating results for Alpine Summit Energy Partners, Inc. ("Alpine Summit" or the "Company") (formerly Red Pine Petroleum Ltd.) for the three months and year ended December 31, 2021. It should be read in conjunction with the Company's audited consolidated financial statements for the year ended December 31, 2021, and 2020 (the "Consolidated Financial Statements").  These documents appear under the SEDAR profile of Alpine Summit Energy Partners, Inc. This MD&A is dated April 25, 2022. See discussion related to "Forward-Looking Statements", "Boe Presentation" and "Non-GAAP Measurements".

Basis of Presentation

Financial data presented below has largely been derived from the Consolidated Financial Statements, which were prepared in accordance with International Financial Reporting Standards ("IFRS"). Accounting policies adopted by the Company are referred to in Note 3 to the Consolidated Financial Statements. The reporting currency is the United States dollar.  Comparative information is provided for the three months and year ended December 31, 2020.

Operational and Financial Results

Overview

The Company is a United States 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 and Hawkville Fields, premier acreage locations which have produced substantial amounts of oil and gas for decades.  The Austin Chalk directly overlies the oil-sourcing Eagle Ford formation. Oil and gas migrate into the chalk through microfractures which fill the tectonic fractures and porous matrix. 

The Company plans to focus 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 the Company's shareholders.

Q4 2021 Highlights

• Maintained average gross production of approximately 9,594 Boe/day and 6,387 Boe/day for the three months and year ended December 31, 2021 (Net 8,581 Boe/day and 5,688 Boe/day, respectively).
• Brought four new wells onto production during the fourth quarter of 2021.
• The Company reported Adjusted EBITDA (defined below) of approximately $22.2 million and $48.2 million for the three months and year ended December 31, 2021, respectively. Net Income/(Loss) before Non-Controlling Interest was approximately US$15.8 and US$(39.2) million for the comparable periods, respectively.
• Successful repayment and reversion of the first development partnership ("DP1") that was formed during the first quarter of 2021, along with the concurrent closing of its third development partnership ("DP3").  Alpine Summit and third-party investors capitalized DP3 with $34.7 million of drilling capital for forward drilling plans.
• Closed a new corporate credit facility (the "Corporate Facility") in October 2021.  The Corporate Facility was undrawn at close and had a total size of up to $12.5 million with a one-year maturity and is secured by working interests in a subset of the Company's producing assets.  After year end, the Corporate Facility was replaced and upsized to $30.0 million with a new lender, refer to subsequent events discussion below.  As of December 31, 2021, approximately $2.2 million was drawn on the Corporate Facility.

1

2022 Objectives

During 2022, the Company plans on continuing to grow production through further development of its controlled acreage and additional farm-in locations. 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 and newly leased acreage. The Company also expects to look for additional development areas to add to its drilling inventory and to opportunistically evaluate investments in other industries outside of oil and gas.

The Company has started 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 commenced 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 ("Origination"), which intends to distribute approximately $0.03 per share each month or US$1.45 million per month to the Company's shareholders and Origination's other unitholders (which represents approximately 50.1 million Subordinate Voting Shares ("SVS"), on a fully converted basis, as of December 31, 2021).  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 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.

Reserves at December 31, 2021

The Company's year-end reserve evaluation as of December 31, 2021, was prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") in a report dated March 11, 2022 (the "Reserves Report"). McDaniel has evaluated all of the Company's crude oil, natural gas and natural gas liquids ("NGL") reserves. The McDaniel price forecast at December 31, 2021 was used to determine estimates of net present value.

Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. These standards are different from the practices used to report production and to estimate reserves in reports and other materials filed with the United States Securities and Exchange Commission (the "SEC") by United States companies.

The McDaniel Reserves Report was prepared in United States dollars.

Summary

• Proven developed producing reserves ("PDP") were 4,575,182 Boe. Total proved plus probable reserves ("2P") were 12,402,350 Boe.
• The PDP reserves are 63% Oil weighted, 37% Natural Gas and NGL weighted. The 2P reserves are 28% Oil weighted, 76% Natural Gas and NGL weighted.
• All 2P reserves are in the Giddings and Hawkville Fields.
• Wells drilled in 2021 were assigned an average of 486,731 Boe per well.

2

• Future development costs ("FDC") were $85.6 million for PDP and are fully financed from forecast cash flow within two years which complies with the Canadian Oil and Gas Evaluation ("COGE") Handbook.
• Future PDP and 2P drilling locations total 13 gross locations in the Giddings and Hawkville Fields.
• The full corporate decommissioning liability for all PDP wells and facilities was included in this year's evaluation and totaled $1.9 million on an undiscounted basis.

Information Regarding Disclosure on Oil and Gas Reserves and Resources

All amounts related to reserve and resources below are stated in United States dollars. Where applicable, natural gas has been converted to barrels of oil equivalent ("Boe") based on 6 Mcf:1 Boe. The Boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not recognize a value equivalent at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Production volumes and revenues are reported on a Company gross basis, before deduction of royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes are based on "company gross reserves" using forecast prices and costs.

Net Present Value Summary (after tax) as of December 31, 2021 ('000s)

	Undiscounted	Discounted @ 5%	Discounted @ 10%	Discounted @ 15%	Discounted @ 20%
Proved Producing	130,350	112,788	101,244	93,021	86,805
Proved Non-Producing	837	791	745	702	661
Total Proved Developed	131,187	113,579	101,989	93,723	87,466
Proved Undeveloped	81,764	55,844	39,571	28,416	20,250
Total Proved	212,951	169,423	141,560	122,139	107,716
Probable Additional	300,406	199,273	140,163	102,104	75,796
Total Proved Plus Probable	513,357	368,696	281,723	224,243	183,512

	As at December 31,
	2021	2021
	Prices	Henry Hub Prices
	Oil, $/bbl	Gas, $/Mmbtu
2022	72.83	3.85
2023	68.78	3.44
2024	66.76	3.17
2025	68.09	3.24
2026	69.45	3.30
2027	70.84	3.37
2028	72.26	3.44
2029	73.70	3.50
2030	75.18	3.58
2031	76.68	3.65
2032	78.21	3.72

3

Results of Operations

Production and Revenue

Average Daily Production (Net)

	Three Months to	Three Months to	Period-over-	Year Ended	Year Ended	Period-over-
	December 31, 2021	December 31, 2020	period change	December 31, 2021	December 31, 2020	period change
Crude oil (bbls/d)	4,490	554	3,936	2,817	266	2,551
Natural gas (Mcf/d)	11,158	1,214	9,944	9,088	407	8,682
NGLs (bbls/d)	2,231	225	2,006	1,356	88	1,267
Total (Boe/d)	8,581	981	7,600	5,688	422	5,266
Crude oil weighting	52.3%	56.4%		49.5%	63.0%
Naural gas weighting	21.7%	20.6%		26.6%	16.1%
NGL weighting	26.0%	23.0%		23.8%	21.0%

Production increased for three months and year ended December 31, 2021 as compared to the comparative periods of 2020 due to the impact of increased working interest from December 22, 2020 related to the acquisition of working interests from an affiliate of Colony Capital, Inc ("Colony Capital").  In addition, four new wells were added to production during the second quarter of 2021, an additional two new wells were added to production during the third quarter of 2021 and four new wells were added in the fourth quarter of 2021.

Revenue from Product Sales

		Three Months to		Three Months to		Year Ended		Year Ended December
		December 31, 2021		December 31, 2020		December 31, 2021		31, 2020
Crude oil	$	31,992,098	$	2,082,905	$	70,355,730	$	3,895,275
Natural gas		3,624,996		226,827		14,227,670		315,374
NGLs		6,411,469		258,557		13,334,390		225,430
Total	$	42,028,563	$	2,568,289	$	97,917,790	$	4,436,079
% of Total Revenue by Product Type
Crude oil weighting		76.12%		81.10%		71.85%		87.81%
Natural gas weighting		8.63%		8.83%		14.53%		7.11%
NGL weighting		15.26%		10.07%		13.62%		5.08%

(1) before realized gains and losses on risk management contracts.

Revenue from product sales increased for three months and year ended December 31, 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 an affiliate of Colony Capital.  In addition, production from 10 wells was brought online as part of the DP 1 and DP 2 (as defined below) partnerships. 

Due to the impact of reduced commodity prices from the impacts of SARS-CoV-2 ("COVID-19"), the Company shut in all wells from March 2020 to July 2020.

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Average Selling Prices

		Three Months to		Three Months to		Year Ended		Year Ended December
		December 31, 2021		December 31, 2020		December 31, 2021		31, 2020
Crude oil - Bbl	$	77.44	$	40.88	$	68.42	$	40.15
Natural gas - Mcf	$	3.53	$	2.03	$	4.29	$	2.13
NGL - Bbl	$	31.24	$	12.47	$	26.95	$	6.98
Per Boe	$	53.24	$	28.44	$	47.17	$	28.80

(1) before realized gains and losses on risk management contracts.

On a per-Boe basis, the Company's average realized price for the three months and year ended December 31, 2021, increased compared to the same periods of 2020, when market prices decreased due in large part to effects of COVID-19. 

Royalties

		Three Months to		Three Months to		Year Ended		Year Ended
		December 31, 2021		December 31, 2020		December 31, 2021		December 31, 2020
Charge for the period	$	11,509,360	$	508,740	$	27,121,000	$	1,190,835
Percentage of revenue from product sales		27.4%		19.8%		27.7%		26.8%
Per Boe	$	14.58	$	5.63	$	13.06	$	7.73

Royalties, as a percentage of revenue from product sales, increased in the three months and year ended December 31, 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.

Operating and Transportation Costs

		Three Months to		Three Months to		Year Ended		Year Ended
		December 31, 2021		December 31, 2020		December 31, 2021		December 31, 2020
Charge for the period	$	5,488,560	$	701,552	$	12,087,223	$	1,196,744
Percentage of revenue from product sales		13.1%		27.3%		12.3%		27.0%
Per Boe	$	6.95	$	7.77	$	5.82	$	7.77

Total operating and transportation costs for the three months and year ended December 31, 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.

Field Operating Netbacks

		Three Months to			Three Months to			Year Ended			Year Ended December
($/Boe)		December 31, 2021			December 31, 2020			December 31, 2021			31, 2020
Revenue from product sales	$	53.24		$	28.44		$	47.17		$	28.80
Royalties		(14.58	)		(5.63	)		(13.06	)		(7.73	)
Production costs		(6.95	)		(7.77	)		(5.82	)		(7.77	)
Field operating netback	$	31.71		$	15.04		$	28.29		$	13.30

5

General and Administrative Costs

		Three Months to		Three Months to		Year Ended		Year Ended
		December 31, 2021		December 31, 2020		December 31, 2021		December 31, 2020
Charge for the period		2,817,958		270,962		13,337,899		1,622,870
Percentage of revenue from product sales		6.7%		10.6%		13.6%		36.6%
Per Boe	$	3.57	$	3.00	$	6.42	$	10.54

General and administrative costs for the three and twelve months ended December 31, 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 twelve months ended December 31, 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 1.60% of revenue or, $0.76 per Boe for the twelve months ended December 31, 2021.

Interest and Finance Costs

		Three Months to		Three Months to Year Ended December				Year Ended December
		December 31, 2021		December 31, 2020		31, 2021		31, 2020
Charge for the period		281,488		301,501		17,033,451		366,686
Per Boe	$	0.36	$	3.34	$	8.21	$	2.38

The increase in interest and financing costs for year ended December 31, 2021, as compared to the same period of 2020 is mainly due to the execution of the Goldman Sachs credit facility (the "Goldman Facility") and associated long-term debt balances and fair value changes associated with the development partnership liabilities.  The decrease in interest and finance costs for the three months ended December 31, 2021, as compared to the prior period is the result of development partnership fair value recoveries in 2021.

Depletion and Depreciation

		Three Months to		Three Months to		Year Ended		Year Ended December
		December 31, 2021		December 31, 2020		December 31, 2021		31, 2020
Charge for the period	$	6,186,751	$	769,000	$	16,708,687	$	1,031,000
Per Boe	$	7.84	$	8.52	$	8.05	$	6.69

Depletion expense increased for the three months and year ended December 31, 2021, as compared to the prior periods as a result of an increase in producing wells in 2021, and associated depletion base of Property, Plant and Equipment.  For the year ended December 31, 2020, all existing wells were shut in from March 2020 to July 2020 and minimal depletion was recorded.

Net Income / (Loss) Attributable to Alpine Summit Shareholders

		Three Months to		Three Months to			Year Ended			Year Ended December
		December 31, 2021		December 31, 2020			December 31, 2021			31, 2020
Net Income/(Loss)	$	21,943,230	$	(3,007,192	)	$	(29,671,345	)	$	(7,530,178	)
Per basic and diluted unit	$	0.48	$	(0.18	)	$	(0.70	)	$	(0.44	)

6

Investment and Financing

Long-term Debt

On December 22, 2020, the Company's subsidiaries including AIP Intermediate, LLC and AIP Borrower, LP (together "AIP Borrower") entered into the Goldman Facility.    All borrowings under the Goldman Facility are secured by AIP Borrower's oil and gas producing wells.  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 December 31, 2021, the Company had $25,237,408 (December 31, 2020 - $43,328,396) drawn under the Goldman Facility.  AIP Borrower has certain financial covenants under the Goldman Facility, including:

• 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 AIP Borrower 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.
• maintain an unrestricted cash balance and minimum interest reserve of no less than $1.8 million.
• 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 AIP Borrower'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 above.

As at December 31, 2021, the AIP Borrower were in compliance with all financial covenants.

Under the terms of the Goldman Facility, AIP Borrower is also required to:

• As at the initial borrowing date, enter into certain forward commodity swap contracts included below and which it had been done.
• 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.  AIP Borrower entered into these swaps during the year ended December 31, 2021.
• 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 been done as at December 31, 2021.

The required principal repayments under the Goldman Facility are as follows:

2022		7,722,206
2023		4,564,814
2024		3,347,998
2025		2,892,873
Thereafter		6,709,518
	$	25,237,409

7

In addition to the required principal repayments outlined above, AIP Borrower could also be required to make additional payments of:

• If the ratio of adjusted EBITDAX to scheduled loan principal and interest payments for the period is less than 1.50 to 1.00, AIP Borrower 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.
• If AIP Borrower fails to meet its ratio (as defined above) of Measured Assets to total net debt of 1.50 to 1.00, AIP Borrower must make an additional principal prepayment sufficient to meet the 1.50:1.00 ratio.

At December 31, 2021, AIP Borrower was not subject to any other additional principal prepayments.             

Details of the Goldman Facility balances are as follows:

December 31, 2021		Current			Long-term			Total
Drawn balance	$	7,722,206		$	17,515,203		$	25,237,409
Borrowing costs		(662,372	)		(1,375,896	)		(2,038,268	)
Total	$	7,059,834		$	16,139,307		$	23,199,141
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 year ended December 31, 2021, AIP Borrower recorded amortization of borrowing costs of $1,058,759.

Corporate Credit Facility

In October 2021, the Company's operating subsidiary Origination closed on the Corporate Facility.  The Corporate Facility has a maximum of $12.5 million credit limit, subject to quarterly borrowing base determinations by the lender.  The borrowing base at December 31, 2021 was $6,579,750.  The Corporate Facility 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 Corporate Facility.  As at December 31, 2021 the Company had $2,200,000 drawn on the Corporate Facility.  Refer to the Subsequent Events section below for changes to the Corporate Facility subsequent to December 31, 2021.

Promissory and Convertible Promissory Notes

A continuity of the Company's promissory notes is included below:

		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		(2,025,000	)
Issued for Cash		2,300,000
Converted to Origination Member Units		(2,300,000	)
December 31, 2021	$	-

8

During the twelve months ended December 31, 2021, Origination issued $1,075,000 in promissory notes for cash of which $75,000 were to an officer of the Company.

During the twelve months ended December 31, 2021, Origination 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, Origination exchanged $1,000,000 of promissory notes in connection with the asset backed preferred instrument.

During the twelve months ended December 31, 2021, Origination 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.

During the year ended December 31, 2020, the Company issued discounted promissory notes including the $1,800,000 issued on the acquisition of working interests totalling a face value of $5,425,000 for proceeds of $5,352,500.  The promissory notes had maturity dates throughout 2021 and interest rates between 15% and 17% and are unsecured.  Of the amounts, $1,600,000 face value were issued to parties related by virtue of significant equity holdings in the Company and/or officers and directors of the Company under the same terms as comparable notes issued to third parties.  During the year ended December 31, 2020, $229,227 was recorded to finance expenses related to interest on the outstanding promissory notes, including the amortization of the $72,500 discount, of which $97,245 and $32,000 was with regards to related party holders.

In June 2021, Origination 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 Origination at a conversion rate of $9.82/unit at the option of the noteholder or Origination.  On July 2, 2021, Origination exercised its option to convert all the existing convertible notes into 234,216 Origination Member Units effective as of July 7, 2021.

At December 31, 2021, the Company has no outstanding promissory notes payable.

Deferred tax

Prior to the RTO, Origination was not subject to U.S. income taxes, because, as a limited liability company classified as a partnership for U.S. federal income tax purposes, it was treated as a pass-through entity for income tax purposes, and the members of Origination were subject to income tax with respect to each such members' allocable share of Origination'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, while Origination remains classified as a partnership for U.S. federal income tax purposes, the Company is taxed as a United States corporation and is subject to U.S. federal income tax on its allocable share of pass-through taxable income from Origination, 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 Origination's members outside the Company is not reflected in the Company's Consolidated Statement of Financial Position and the Consolidated Statement of Loss and Comprehensive Loss.

During the year ended December 31, 2021, Origination recorded a deferred tax liability and a correlating deferred tax expense of $2,832,215 (2020 - $Nil) to reflect temporary difference between the carrying value for accounting versus tax values.

9

Capital Expenditures

In the year ended December 31, 2021, the Company incurred capital expenditures on property, plant and equipment of $52.2 million compared to $42.9 million for the year ended December 31, 2020.  The majority of activity for these periods relates to the drilling of horizontal wells in the Giddings Field.

During the year ended December 31, 2021, the Company expended $20.2 million on 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

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 December 31, 2021 corresponds to the Company's field capital expenditure program.

Decommissioning Liability

The Company's decommissioning liability of $1,502,131 represents the present value of estimated future costs to be incurred to plug, abandon and reclaim wells and facilities, drilled, constructed or purchased by the Company. The undiscounted and inflated amount of the liability at December 31, 2021 was approximately $1.3 million. The liability for all wells covered under this liability are expected to be incurred between 2025 and 2053.

Risk Management - Commodity Contracts

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 periods.

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During the first half of 2020, oil prices dramatically collapsed due to the impact of the COVID-19 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 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. Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. For example, the recent conflict between Russia and Ukraine has contributed to significant increases and volatility in the price for oil and natural gas. Wide fluctuations in oil, natural gas and NGL prices may result from relatively minor changes in the supply of or demand for oil, natural gas and NGL market uncertainty.  These and other factors have 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.

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 December 31, 2021, the Company had the following commodity contracts, with a total mark-to-market liability of $20,381,180 (2020 - $4,521,383). 

Commodity	Expiry	Type	Average Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	Jan 2022 - Dec 2023	Swap	$0.20	4,044,242	NGL-Mont Belvieu
Propane (gallons)	Jan 2022 - Dec 2023	Swap	$0.52	2,486,520	NGL-Mont Belvieu
Natural gas (gallons)	Jan 2022 - Dec 2023	Swap	$0.95	1,593,236	NGL-Mont Belvieu
Isobutane (gallons)	Jan 2022 - Dec 2023	Swap	$0.56	520,281	NGL-Mont Belvieu
Norbutane (gallons)	Jan 2022 - Dec 2023	Swap	$0.57	1,209,751	NGL-Mont Belvieu
Natural gas (mmbtu)	Jan 2022 - Dec 2028	Differential Swap	$0.07	2,494,923	Henry Hub -Nymex vs East TX
Natural gas (mmbtu)	Jan 2022 - Dec 2028	Swap	$2.61	2,396,296	Henry Hub -Nymex
Crude oil (bbl)	Jan 2022 - Dec 2028	Swap	$43.38	740,533	WTI-Nymex
Crude oil (bbl)	Jan - Jun 2022	Put	$40.00	700,000	WTI-Nymex
Crude oil (bbl)	Jan - Nov 2022	Short	$68.78-77.42	84,000	WTI-Nymex
Natural gas (mmbtu)	Feb - Oct 2022	Short	$3.58-4.98	390,000	Nat Gas-Nymex

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

The unrealized loss for the year ended December 31, 2021, of $15,859,796 and realized losses of $17,622,236 (2020 - $4,521,383 unrealized and $405,404 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.

Development Partnerships

The Company, through its wholly owned subsidiary Origination, sponsors and manages development programs to participate in its drilling initiatives and accelerate its growth. Most of Origination's drilling programs are limited partnerships structured to minimize drilling risks on repeatable prospects and optimize tax advantages for private investors. At the commencement of operations, Origination assigns drilling rights for specified wells to an operating partnership.

During the first quarter of 2021, Origination formed DP1 with 13 limited partners (the "DP1 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $21.8 million in total size. DP1 funded the drilling and completion of five wells, with the DP1 LPs funding 60% and Origination funding 40%. The DP1 LPs could choose to receive development partnership units ("DP1 Units") that distribute profits either based on a Flat payout option or an IRR based payout option.  Flat Payout Units participate in 75% of the income of DP1 (along with IRR based Payout Units) until that income equals their invested capital and thereafter participate in 20% of the income of the DP1 (along with IRR based Payout Units). IRR Based Payout Units participate in 75% of the income of the First Development Partnership (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 participate in 6% of the income of DP1, along with Flat Payout Units, which participate in 20% of the income of DP1.  DP1 LPs also had a put right to effectively sell their remaining interest for Subordinate Voting Shares or Multiple Voting Shares or cash, subject to the consent of Origination and certain other restrictions, for an amount calculated at the net future present values on oil and gas reserve estimates.

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During the year ended December 31, 2021, the Company distributed $1,853,127 to the external DP1 partners.

The Company, through the structure of the DP1, will maintain control of the DP1 and will continue to consolidate 100% of the operations of the DP1.

For the year ended December 31, 2021, an increase in the liability of $4,001,481, was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses.

On October 7, 2021, the Company repaid and paid out the reversion of DP1.  As part of the completion of the DP1 program, Alpine has retired liabilities of $15,288,594.

One of the DP1 LPs 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 Origination (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 $1,192,893.

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

During the second quarter of 2021, Origination formed a second development partnership ("DP2") with 25 limited partners (the "DP2 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which is US$35.2 million in total size. DP2 fundedthe drilling and completion of five wells, with DP2 LPs funding 60% and Origination funding 40%. DP2 LPs could choose to receive development partnership units ("DP Units") that distribute profits either based on a Flat payout option or an IRR based payout option.  Flat Payout Units participate in 75% of the income of DP2 (along with IRR based Payout Units) until that income equals their invested capital and thereafter participate in 20% of the income of DP2 (along with IRR based Payout Units). IRR Based Payout Units participate in 75% of the income of DP2 (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 participate in 6% of the income of DP2, along with Flat Payout Units, which participate in 20% of the income of DP2.  The DP2 LPs also had a put right to effectively sell their remaining interest for Subordinate Voting Shares or Multiple Voting Shares or cash, subject to the consent of Origination and certain other restrictions, for an amount calculated at the net future present values on oil and gas reserve estimates.

During the year ended December 31, 2021, the Company distributed $4,535,743 to external DP2 partners.

The Company, through the structure of the DP2, will maintain control of the DP2and will continue to consolidate 100% of the operations of the DP2.

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The Company has categorized the DP2 liability as current based on the anticipated timing of repayments.  For the year ended December 31, 2021, an increase in the liability of $7,232,232 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 Note 24 of the accompanying audited Consolidated Financial Statements, for discussion regarding the closing of DP2 subsequent to year end.

During the fourth quarter of 2021, Origination formed DP3 with 23 limited partners (the "DP3 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which is US$34.7 million in total size. DP3 is currently funding the drilling and completion of five wells, with the DP3 LPs funding 60% and Origination funding 40%. The DP3 LPs can choose to receive development partnership units ("DP Units") that distribute profits either based on a Flat payout option or an IRR based payout option.  Flat Payout Units will participate in 75% of the income of DP3 (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of DP3 (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of DP3 (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 DP3, along with Flat Payout Units, which will participate in 20% of the income of DP3.  The DP3 LPs will also have a put right to effectively sell their remaining interest for Subordinate Voting Shares or Multiple Voting Shares or cash, subject to the consent of Origination and certain other restrictions, for an amount calculated at the net future present values on oil and gas reserve estimates.

The Company, through the structure of the DP3, will maintain control of the DP3and will continue to consolidate 100% of the operations of the DP3.

The Company has categorized the DP3 liability as current based on the anticipated timing of repayments.  For the year ended December 31, 2021, there was no increase in the liability related to the change in fair value of the liability as no associated drilling or reserve results were completed.

Shareholder Takeout and Asset Backed Preferred Instrument

On March 5, 2021, Origination 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").  Origination 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.

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For the three months and year ended December 31, 2021, the Company recorded finance expense related to the outstanding instrument in the amount of $546,376 and $1,857,351, respectively. 

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

Shareholders' Capital

Authorized

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.

Issued

		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
MVS converted to SVS		-		30,411,950.000	(304,119.500	)	-		-
Balance at December 31, 2021		-		32,535,731.000	10,335.330		15,947.292	$	43,414,147

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

During the twelve months ended December 31, 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). 

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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 acres 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/Unit for total consideration of $9,073,228 in connection with preparing for the Company's listing on the TSX-V.

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

During the year ended December 31, 2021, 304,119.500 MVS shares were converted into 30,411,950 SVS.

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 preparing for 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 RTO 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 Petroleum Ltd.'s 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 consolidated statement of loss and comprehensive loss. 

A full exchange of all non-voting units of 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 as of December 31, 2021.

Loss per share:

		Year ended December 31, 2021							Year ended December 31, 2020
		Net Loss		Shares		Loss per Share			Net Loss		Shares		Loss per Share
Income/(loss) - basic	$	(29,671,345	)	42,596,264	$	(0.70	)	$	(7,530,178	)	17,083,501	$	(0.44	)
Diliutive effect of outstanding awards		-		-		-			-		-		-
Loss - diluted	$	(29,671,345	)	42,596,264	$	(0.70	)	$	(7,530,178	)	17,083,501	$	(0.44	)

The Company had share purchase options ("Options"), restricted share units ("RSUs") and deferred share units ("DSUs") outstanding for the year ended December 31, 2021 (2020 - none outstanding).  The effect of the conversion or exercise of convertible promissory notes and NCI interest in would be anti-dilutive (15,470 dilutive shares) and therefore have not been included in the calculation of diluted loss per share.  The Company used an average market price of $3.32 per share to calculate the dilutive effect of stock options, RSUs and DSUs outstanding.

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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.

Non-Controlling Interest

In connection with the Business Combination Agreement ("BCA") (refer to Note 2 of the 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 consolidated statement of loss and comprehensive loss, with an offset to NCI, representing NCI share of net loss for the 23 day period.

In October, 2021, 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 Origination.  As a result of the unit issuance the NCI economic interest increased to 32.954%.  As a result a credit to NCI, for the fair value of DP1 liabilities settled has been recorded.

For the fourth quarter of 2021, $6,136,766 was recorded to reduce net loss on the consolidated statement of loss and comprehensive loss, with an offset to NCI, representing NCI share for the three month period.

Related Party Transactions

Management Services Agreement

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 the MSA, the related company provided management, finance, operations and administrative services. The MSA had an initial period of 11 years with a 90 day cancellation notice. The Company was obligated to 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 Goldman Facility. During the year ended December 31, 2021, the Company incurred and paid fees of $287,126 (2020 - $20,000) and is included in general and administrative expenses.

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.

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During the year ended December 31, 2021, the Company was paid $215,080 via a payroll credit and $451,587 in cash, with a corresponding decrease to general and administrative expenses in the consolidated statement of loss and comprehensive loss.

Related party balances

At December 31, 2021, the accounts payable included $120,501(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 and Going Concern

Liquidity risk

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 December 31, 2021, the Company had negative working capital of $80,838,833.  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 year ended December 31, 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 December 31, 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 December 31, 2021:

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		Carrying value		Contractual cash flow		Less than one year		1 - 3 years		Greater than 3 years
Accounts payable and accrued liabilities	$	48,245,677	$	48,245,677	$	48,245,677	$	-	$	-
Commodity contracts		20,381,180		20,381,180		6,479,508		7,988,934		5,912,738
Promissory notes		-		-		-		-		-
Lease liability		489,943		485,975		78,745		407,230		-
Asset backed preferred instrument		18,687,351		18,687,351		18,687,351		-		-
Development partnerships liabilities		46,894,643		46,894,643		46,894,643		-		-
Long-term debt		23,199,141		25,237,409		7,722,206		10,805,685		6,709,518
Total	$	157,897,935	$	159,932,235	$	128,108,130	$	19,201,849	$	12,622,256

Going Concern

The Consolidated 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 twelve months ended December 31, 2021, the Company generated a net loss and comprehensive loss of $29,671,345 (year ended December 31, 2020 - $7,530,178), and as at that date, the Company had a working capital deficiency of $80,838,833 (December 31, 2020 - working capital deficiency of $29,102,456) and accumulated deficit of $81,134,105 (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 year ended December 31, 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 three development partnerships to fund a portion of 2021 capital activity which raised approximately $55 million during the year ended December 31, 2021.  Subsequent to year-end, the Company closed on two additional development partnerships resulting in cash inflows of approximately $35.7 million, and also expanded its corporate credit facility with availability up to $30 million.  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 $18.1 million of long-term debt and $4.8 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 Consolidated 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.

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Subsequent Events

Completion of DP2 and creation of DP4

On January 10, 2022, the Company repaid and paid out the reversion of the second development partnership, DP2, that it formed during the third quarter of 2021.  DP2 funded the drilling and completion of five wells in the Giddings Field near Austin, TX and comprised a total capital program of approximately $35.2 million, with 60% funded by external partners. As part of the completion of the DP2 program, Alpine has retired liabilities of approximately $23.5 million.

Ten of the DP2 partners exercised the put right provided to such partners by DP2 regarding residual interests in their associated investment and, elected to exchange the remaining interest in DP2 for 826,024 Class B non-voting units of Origination (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company, having a deemed value of US$3.825 per unit, or a total of approximately US$3.2 million).

On January 10, 2022, the Company formed a fourth Development Partnership ("DP4") with 36 external limited partners and Origination as a limited partner and the general partner.  The intention of the DP4 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 $25,225,079 from external limited partners of which $1,984,256 was raised from officers and directors of the Company.  Investors can choose to receive DP4 Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $10,831,937 in Flat Payout units and $14,393,141 in IRR based payout units.

The terms of the units are substantial identical to those of DP1, DP2 and DP3.

The Company, through the structure of the DP4, will maintain control of DP4 and will continue to consolidate 100% of the operations of the DP4.

Creation of Red Dawn Development Partnership

On March 10, 2022, the Company formed a new Development Partnership - Red Dawn ("Red Dawn") with 42 external limited partners and Origination as a limited partner and the general partner.  The intention of the Red Dawn 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 $30,269,097 from external limited partners of which $1,270,717 was raised from officers and directors of the Company.  Investors can choose to receive Red Dawn Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $16,692,201 in Flat Payout units and $13,576,896 in IRR based payout units.

The terms of the units are identical to those of the DP1, DP2 and DP3.

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

Expanded Credit Facility

The Company's operating subsidiary Origination closed a new corporate credit facility with a new lender to replace the Corporate Facility.  The new corporate credit facility has a total size of $30 million. The new corporate credit facility is secured by working interests in a subset of the Origination's producing assets and charges interest at the greater of 5.00% and Prime +1.75%. The new corporate credit facility, which has a one year maturity, is expected to provide the Company with additional working capital flexibility.

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Quarterly Results

Summarized information by quarter for the previous two years ended December 31, 2021 appears below.

Quarter ended December 31, 2021

		2021												2020
		Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Revenue from product sales		42,028,563			23,427,075			12,836,239			19,625,913			2,568,289			1,239,879			40			627,871
Net income (loss)		21,943,230			(18,636,041	)		(24,751,922	)		(8,226,612	)		(3,007,192	)		123,065			(4,664,592	)		118,006
Per unit - basic and diluted	$	0.48		$	(0.42	)	$	(1.68	)	$	(0.53	)	$	(0.18	)	$	0.01		$	(0.27	)	$	0.01
Net capital expenditures		(27,159,171	)		(26,909,107	)		(13,211,052	)		(5,151,463	)		(36,276,414	)		(1,901,004	)		(2,596,577	)		(2,434,335	)
Average daily production (Boe)		8,581			5,399			3,805			4,983			981			523			-			170
Working capital deficiency		(80,838,832	)		(80,891,770	)		(49,133,400	)		(24,142,999	)		(29,102,456	)		(9,512,412	)		(10,313,550	)		(5,198,785	)

In 2021, the formation of the two development partnerships resulted in the drilling of ten wells that came on production in the second half of the year increasing the operating results.  AIP Borrower 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 quarters of 2021.

Off-Balance-Sheet Arrangements

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

Critical Accounting Judgments, Estimates and Policies

The Company's critical accounting judgements, estimates and policies are described in notes 3 and 4 to the December 31, 2021, 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.

Outstanding Securities

As of the date of this MD&A, the Company has 8,748.47, 32,975,667 and 15,947.292 for current MVS, SVS and PVS issued and outstanding.

Limitations

Forward-Looking Statements

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 the remainder of 2022 and 2023, 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.

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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:

• changes in general, market and business conditions including commodity prices, interest rates and currency exchange;
• changes in supply and demand for the Company's products;
• a global public health crisis including the recent outbreak of the novel coronavirus (COVID-19) which causes volatility and disruptions in the supply, demand and pricing for natural gas, crude oil and NGL, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people;
• the ability to obtain regulatory, stakeholder and third-party approvals and satisfy any associated conditions that are not within the Company's control for exploration and development activities and projects;
• the ability of the Company to obtain TSXV approval of the NCIB
• successful and timely implementation of capital expenditures;
• risks associated with the development and execution of major project;
• risk that projects and opportunities intended to grow funds flow and/or reduce costs may not achieve the expected results in the time anticipated or at all;
• access to third-party pipelines and facilities and access to sales markets;
• volatility of commodity prices and the related effects of changing price differentials;
• the Company's ability to operate and access to facilities to meet forecast production;
• the ability of the Company to pay dividends to its shareholders;
• the timing of repayments in respect of the various development partnerships;

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• the Company's ability 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;
• the stability of royalty rates in future periods;
• operational risks and uncertainties associated with crude oil and gas activities including unexpected formations or pressures, reservoir performance, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of natural gas and wellbore fluids, pollution and other environmental risks;
• changes in costs including production, royalty, transportation, general and administrative, and finance;
• ability to finance planned activities including infrastructure expansions which are required to meet future growth targets;
• adverse weather conditions which could disrupt production and affect drilling and completions resulting in increased costs and/or delay adding production;
• actions by government authorities including changes to taxes, fees, royalties, duties and government imposed compliance costs;
• changes to laws and government policies including environmental (and climate change), royalty, and tax laws and policies;
• counter-party risk with third parties to perform their obligations with whom the Company has material relationships;
• unplanned facility maintenance or outages or unavailability of third-party infrastructure which could reduce production or prevent the transportation of products to processing plants and sales markets;
• a major outage or environmental incident or unexpected event such as fires (including forest fires), hurricanes or equipment failures or similar events that would affect the Company's facilities or third-party infrastructure used by the Company;
• environmental risks (including climate change) and the cost of compliance with current and future environmental laws, including climate change laws along with risks relating to increased activism and opposition to fossil fuels;
• ability to access capital from internal and external sources (including the corporate credit facility);
• the risk that competing business objectives may exceed the Company's capacity to adapt and implement change;
• the potential for security breaches of the Company's information technology systems by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches;
• risks with transactions including closing an asset or property acquisition or disposition and the failure to realize anticipated benefits from any transaction;
• finding new crude oil and gas reserves that can be developed economically to replace reserves depleted by production;
• the accuracy of estimating reserves and future production and the future value of reserves;
• risk associated with commodity price hedging activities using derivatives and other financial instruments;
• maintaining debt levels at a reasonable multiple of funds flow;
• risk that the Company may be subject to litigation;

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• the accuracy of cost estimates, some of which are provided at an early stage and before detailed engineering has been completed;
• risk associated with partner or joint arrangements to which the Company is a party;
• inability to secure labour, services or equipment on a timely basis or on favourable terms;
• increased competition from other industry participants for, among other things, capital, acquisitions of assets or undeveloped lands, and skilled personnel; and
• increased competition from companies that provide alternative sources of energy.

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. The Company 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", "adjusted EBITDA", 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

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.

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Adjusted EBITDA

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: Adjusted earnings before interest, taxes, depletion and amortization ("Adjusted 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 Adjusted 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 Adjusted EBITDA is net income/(loss) adding back interest, non-cash financing expenses, depletion, depreciation, accretion, amortization, impairment, non-recurring costs and expenses and realized/unrealized commodity contract gains/(losses).

Business Risks 

There are a number of risks facing participants in the 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.

Crude Oil and Natural Gas Prices and General Economic Conditions

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.

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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: the Russian invasion of the Ukraine, actions taken by OPEC, Russia's withdrawal from OPEC, sanctions against Russia, 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.

Property Exploration

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;
• prospects are internally generated;
• 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; and
• 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.

Commodity Price Fluctuations

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.

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Adverse Well or Reservoir Performance

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.

Field Operations

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.

Retention of Key Personnel

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. Shareholders 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.

Environmental

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

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

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• Methane and hydrocarbon gases recapture: The Company 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.

Industry Capacity Constraints

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. The Company'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 Programs

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.

Reserve Estimates

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.

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Production

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.

Financial and Liquidity Risks

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.

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Transportation Risk

The marketability of production depends in part on the availability, proximity and capacity of gathering and transportation pipeline facilities, rail cars and trucks. These facilities and equipment may be temporarily unavailable to the Company due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. If any pipelines, rail cars, or trucks become unavailable, the Company would, to the extent possible, be required to find a suitable alternative to transport crude oil and condensate, NGLs and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of production. A pipeline shutdown could also have an impact on safety because it would require the use of additional trucks, rail cars and personnel. In addition, both the cost and availability of pipelines, rail cars, or trucks to transport production could be adversely impacted by new state or federal regulations relating to transportation of crude oil. Any significant change in market, regulatory or other conditions affecting access to, or the availability of, these facilities and equipment, including due to failure or inability to obtain access to these facilities and equipment on terms acceptable to the Company or at all, could materially and adversely affect business and, in turn, financial condition and results of operations.

Water Disposal Risk

The Company may be subject to regulation that restricts ability to discharge water produced as part of production operations. Productive zones frequently contain water that must be removed in order for the oil and natural gas to produce, and ability to remove and dispose of sufficient quantities of water from the various zones will determine whether the Company can produce oil and natural gas in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from wells may affect the ability to produce wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce profitability. Where water produced from projects fails to meet the quality requirements of applicable regulatory agencies, wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or the Company is unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, the Company may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur;

• The Company cannot obtain future permits from applicable regulatory agencies;
• Water of lesser quality or requiring additional treatment is produced;
• Wells produce excess water;
• New laws and regulations require water to be disposed in a different manner; or
• Costs to transport the produced water to the disposal wells increase.

The disposal of fluids gathered from oil and natural gas producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. Several states have adopted or are considering adopting laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. While the Company cannot predict the ultimate outcome of these actions, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other oilfield fluids may increase costs or have other adverse impacts on operations.

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Marketing Risks

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.

Access to Debt and Equity

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.

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.

Changes in Government Regulations, Royalties and Policies

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.

Cyber-Security

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.

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Extraordinary Circumstances

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.

Global Health Crises

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.

Foreign Private Issuer Status under United States Securities Laws

The Company is a "foreign private issuer", as defined in Rule 405 under the United States Securities Act of 1933, as amended (the "Securities Act"), and Rule 3b-4 under the United States Securities Exchange Act of 1934, as amended (the "Exchange Act"). It is therefore, not subject to the same requirements that are imposed upon United States domestic issuers by the SEC. Under the Exchange Act, the Company is subject to reporting obligations that, in certain respects, are less detailed and less frequent than those of United States domestic reporting companies. As a result, the Company does not file the same reports that a United States domestic issuer would file with the SEC, although the Company is required to file with or furnish to the SEC the continuous disclosure documents that it is required to file in Canada under Canadian securities laws. In addition, the Company's officers, directors, and principal shareholders are exempt from the reporting and short-swing profit recovery provisions of Section 16 of the Exchange Act. Therefore, the Company's shareholders may not know on as timely a basis when the Company's officers, directors and principal shareholders purchase or sell Common Shares, as the reporting periods under the corresponding Canadian insider reporting requirements are longer.

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As a foreign private issuer, the Company is exempt from the rules and regulations under the Exchange Act related to the furnishing and content of proxy statements. The Company is also exempt from Regulation FD, which prohibits issuers from making selective disclosures of material non-public information. While the Company complies with the corresponding requirements relating to proxy statements and disclosure of material non-public information under Canadian securities laws, these requirements differ from those under the Exchange Act and Regulation FD and shareholders should not expect to receive the same information at the same time as such information is provided by United States domestic companies. In addition, the Company may not be required under the Exchange Act to file annual and quarterly reports with the SEC as promptly as United States domestic companies whose securities are registered under the Exchange Act.

Loss of Foreign Private Issuer Status under United States Securities Laws

The Company may lose its status as a foreign private issuer if, as of the last business day of the Company's second fiscal quarter for any year, more than 50% of the Company's outstanding voting securities (as determined under Rule 405 of the Securities Act) are directly or indirectly held of record by residents of the United States. Loss of foreign private issuer status may have adverse consequences on the Company's ability to raise capital in private placements or Canadian prospectus offerings. The 3 regulatory and compliance costs under United States federal securities laws as a United States domestic issuer may be significantly more than the costs incurred as a Canadian foreign private issuer eligible to use the multi-jurisdictional disclosure system adopted by the securities regulatory authorities in United States and Canada ("MJDS"). If the Company is not a foreign private issuer, it would not be eligible to use the MJDS or other foreign issuer forms and would be required to file periodic and current reports and registration statements on United States domestic issuer forms with the SEC, which are more detailed and extensive than the forms available to a foreign private issuer. Further, should the Company seek to list on a securities exchange in the United States, loss of Foreign Private Issuer status may increase the cost and time required for such a listing. These increased costs may have a material adverse effect on the business, financial condition or results of operations of the Company.

"Emerging Growth Company" Status under United States Securities Laws

The Company is an "emerging growth company" as defined in section 3(a) of the Exchange Act (as amended by the JOBS Act, enacted on April 5, 2012), and the Company will continue to qualify as an emerging growth company until the earliest to occur of: (a) the last day of the fiscal year during which the Company has total annual gross revenues of US$1,070,000,000 (as such amount is indexed for inflation every five years by the SEC) or more; (b) the last day of the fiscal year of the Company following the fifth anniversary of the date of the first sale of common equity securities of the Company pursuant to an effective registration statement under the Securities Act; (c) the date on which the Company has, during the previous three year period, issued more than US$1,000,000,000 in non-convertible debt; and (d) the date on which the Company is deemed to be a "large accelerated filer", as defined in Rule 12b-2 under the Exchange Act. The Company will qualify as a large accelerated filer (and would cease to be an emerging growth company) at such time when on the last business day of its second fiscal quarter of such year the aggregate worldwide market value of its common equity held by non-affiliates will be US$700,000,000 or more.

For so long as the Company remains an emerging growth company, it is permitted to and intends to rely upon exemptions from certain disclosure requirements that are applicable to other public companies that are not emerging growth companies. These exemptions include not being required to comply with the auditor attestation requirements of Section 404 of the JOBS Act. The Company takes advantage of some, but not all, of the available exemptions available to emerging growth companies. The Company cannot predict whether investors will find the Common Shares less attractive because the Company relies upon certain of these exemptions. If some investors find the Common Shares less attractive as a result, there may be a less active trading market for the Common Shares and the Common Share price may be more volatile. On the other hand, if the Company no longer qualifies as an emerging growth company, the Company would be required to divert additional management time and attention from the Company's development and other business activities and incur increased legal and financial costs to comply with the additional associated reporting requirements, which could negatively impact the Company's business, financial condition and results of operations.

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Proposed Tax Legislation

Changes to U.S. tax laws (which changes may have retroactive application) could adversely affect the Company or holders of shares of its stock. In recent years, many changes to U.S. federal income tax laws have been proposed and made, and additional changes to U.S. federal income tax laws are likely to continue to occur in the future. The U.S. Congress is currently considering numerous items of legislation which may be enacted prospectively or with retroactive effect, which legislation could adversely impact the Company's financial performance and the value of shares of its stock. In particular, new proposed legislation known as the "Build Back Better Act" is under consideration within both houses of U.S. Congress. The proposed legislation includes, without limitation, new corporate minimum income taxes. If enacted, most of the proposals would be effective for 2022 or later years. The proposed legislation remains subject to change, and its impact on the Company and holders of shares of its stock is uncertain.

Additional Information

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

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