MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management's discussion and analysis of financial results ("MD&A") is dated November 14, 2022 and should be read in conjunction with Alpine Summit Energy Partners, Inc.'s ("Alpine Summit" or the "Company") (formerly Red Pine Petroleum Ltd.) unaudited condensed interim consolidated financial statements for the three and nine months ended September 30, 2022 (the "Consolidated Financial Statements") and the audited consolidated year end financial statements.  These documents appear under the SEDAR profile of Alpine Summit Energy Partners, Inc. All amounts expressed in U.S. dollars unless otherwise stated.

BASIS OF PRESENTATION

Throughout this MD&A and in other materials disclosed by the Company, Alpine Summit adheres to generally accepted accounting principles ("GAAP"), however the Company also employs certain non-GAAP and other financial measures to analyze financial performance, financial position, and cash flow including, "field netback", "capital expenditures" and "adjusted EBITDA". These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other companies. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net earnings (loss), cash flow generated by operating activities, and cash flow used in investing activities, as indicators of the Company's performance.

Readers are cautioned that the MD&A should be read in conjunction with the Company's disclosure in the sections entitled "Non-GAAP Measurements" and "Forward-Looking Statements" included at the end of this MD&A.

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 audited consolidated financial statements for the years ended December 31, 2021, and 2020.  Comparative information is provided for the three and nine months ended September 30, 2021.

Where applicable, 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.

Unless otherwise stated, all production volumes and realized product prices information is presented on a "net" basis (after deduction of royalty obligations and non-operated working interest) consistent with IFRS oil and gas reporting standards and thus, may not be comparable to information provided by other entities.

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 continuing its drilling activity in the Austin Chalk and Eagle Ford formations in the Giddings and Hawkville (Webb County) Fields. 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.

1

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.

Q3 2022 Highlights

•Maintained average gross production of approximately 17,324 Boe/day for the three months ended September 30, 2022 (Net 15,882 Boe/day) an increase of 18% quarter over quarter and more than tripled year over year, despite extensive downtime during the month of July to enable completion activity.

•Reported Net Income before Non-Controlling Interest of approximately $22.5 million for the three months ended September 30, 2022 (September 30, 2021 - $22.0 million loss). Adjusted EBITDA¹ (defined below) of approximately $38.5 million for the same period (September 30, 2021 - $9.7 million).

•Brought eight new wells onto production during the third quarter of 2022.

•Successful repayment and reversion of the fourth development partnership ("DP4") that was formed during the first quarter of 2022, along with the concurrent closing of the Company's sixth development partnership ("DP6") in July 2022.

•Expanded the size of the asset backed securitization facility (the "ABS Facility") to a total size of $135 million. The ABS Facility charges interest at one-month LIBOR (with a 1% floor) + 8.0%. As of September 30, 2022, approximately $120.6 million was outstanding on the ABS Facility.

•Expanded the size of the corporate credit facility (the "Corporate Facility") to a maximum size of $65 million. The Corporate Facility charges interest at greater of 5.00% and Prime + 1.75%. As of September 30, 2022 approximately $17.4 million was available under the Corporate Facility with zero drawn.

•Listing on the Nasdaq Global Market ("Nasdaq") of the Company's Class A Subordinate Voting Shares ("SVS") on September 28, 2022, trading under the ticker symbol "ALPS".

•Paid monthly dividend of $0.03 per SVS ($3.00 per Multiple Voting Share and $0.03 per Proportionate Voting Share) during each month of the third quarter of 2022.

The following table provides a reconciliation of Net Income/(Loss) before Non-Controlling Interest to Adjusted EBITDA:

		Three Months ended September 30, 2022			Three Months ended September 30, 2021			Nine Months ended September 30, 2022		Nine Months ended September 30, 2021
Net income/(loss) before non-controlling interest:	$	22,537,836		$	(21,991,423	)	$	19,486,846	$	(54,969,957	)
(+) Depletion and depreciation expense		13,121,973			3,815,509			27,503,795		10,521,936
(+) Finance and interest expense		5,966,790			10,991,673			32,003,711		16,751,936
(+) Stock based compensation expense		3,978,831			-			9,498,501		9,073,228
(+) Listing expense		-			1,301,692			-		1,301,692
(+) Transaction costs		-			1,567,967			-		1,567,967
(+) Unrealized and realized (gains)/losses on commodity contracts		(7,129,464	)		13,973,411			17,245,913		39,382,889
	$	38,475,966		$	9,658,829		$	105,738,766	$	23,629,691

__________________________________

¹ This is a non-GAAP financial measure. Refer to the "Non-GAAP Financial Measures" section of this MD&A for further information and the detailed reconciliation to the most directly comparable measure under IFRS.

2

2023 Objectives

The Company anticipates maintaining its current investment pace of 20 to 30 wells per year for the remainder of 2022 and throughout 2023 with a focus on attractive locations in the Hawkville and Giddings Fields, where expected well returns remain in excess of its internal investment hurdles. The Company anticipates that these investments will continue to drive meaningful growth in production and cash flow in 2023.

Subsequent Event Highlights

• The Company has continued with its monthly dividend program, $0.03 per SVS ($3.00 per MVS and $0.03 per PVS) for October and November 2022.
• In November, the Company successfully completed the repayment and reversion of its Red Dawn 1 development partnership ("Red Dawn 1") and concurrently closed its Red Dawn 2 development partnership ("Red Dawn 2"). Red Dawn 2 has an expanded capital program of approximately $57.7 million, with $38.5 million of external development capital. Refer to subsequent events section below for further discussion.
• The Company amended and expanded its Corporate Credit Facility ("Corporate Facility") from an initial size of $30 million up to $65 million, with a current borrowing base of $20.5 million. 

Results of Operations

Production and Revenue

Average Daily Production (Net)

	Three Months ended September 30, 2022	Three Months ended September 30, 2021	Period-over- period change	Nine Months ended September 30, 2022	Nine Months ended September 30, 2021	Period-over- period change
Crude oil (bbls/d)	2,914	2,862	52	3,944	2,253	1,691
Natural gas (Mcf/d)	66,065	7,462	58,603	39,104	8,390	30,714
NGLs (bbls/d)	1,957	1,294	663	2,191	1,061	1,130
Total (Boe/d)	15,882	5,399	3,804	12,652	4,712	7,940
Crude oil weighting	18.3%	65.1%		31.2%	47.8%
Natural gas weighting	69.3%	11.9%		51.5%	29.7%
NGL weighting	12.3%	23.0%		17.3%	22.5%

Production increased for three and nine months ended September 30, 2022, as compared to the comparative periods of 2021 due to the addition of four new wells through the final three months of 2021, and sixteen new wells through the nine months ended September 30, 2022.

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Revenue from Product Sales ¹

		Three Months		Three Months		Nine Months		Nine Months
		ended		ended		ended		ended
		September 30,		September 30,		September 30,		September 30,
		2022		2021		2022		2021
Crude oil	$	24,713,099	$	17,825,375	$	106,515,776	$	38,363,632
Natural gas		47,467,929		2,185,538		73,646,169		10,602,674
NGLs		6,181,810		3,416,162		22,653,060		6,922,921
Total	$	78,362,838	$	23,427,075	$	202,815,005	$	55,889,227
% of Total Revenue by Product Type
Crude oil weighting		31.54%		76.09%		52.52%		68.64%
Natrual gas weighting		60.57%		9.33%		36.31%		18.97%
NGL weighting		7.89%		14.58%		11.17%		12.39%

1 - before realized gains and losses on risk management contracts.

Revenue from product sales increased for three and nine months ended September 30, 2022, as compared to the comparative periods due to the impact of new wells brought online in late 2021 and throughout 2022 (see below for impact of average selling prices). 

Average Selling Prices ¹

		Three Months		Three Months		Nine Months		Nine Months
		ended		ended		ended		ended
		September 30,		September 30,		September 30,		September 30,
		2022		2021		2022		2021
Crude oil - Bbl	$	92.19	$	67.69	$	98.93	$	62.36
Natural gas - Mcf	$	7.81	$	3.18	$	6.90	$	4.63
NGL - Bbl	$	34.33	$	38.55	$	37.88	$	23.91
Per Boe	$	53.63	$	47.16	$	58.72	$	43.44

1 - before realized gains and losses on risk management contracts.

On a per-Boe basis, the Company's average realized price for the three and nine months ended September 30, 2022, increased compared to the same periods of 2021, due to strengthened worldwide commodity prices. 

Royalties

		Three Months		Three Months		Nine Months		Nine Months
		ended		ended		ended		ended
		September 30,		September 30,		September 30,		September 30,
		2022		2021		2022		2021
Charge for the period	$	20,650,728	$	6,689,789	$	55,591,593	$	15,611,640
Percentage of revenue from product sales		26.4%		28.6%		27.4%		27.9%
Per Boe	$	14.13	$	13.47	$	16.10	$	12.14

Royalties, as a percentage of revenue from product sales, decreased in the three and nine months ended September 30, 2022, compared to the same periods in 2021; 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.

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Operating and Transportation Costs

		Three Months ended September 30, 2022		Three Months ended September 30, 2021		Nine Months ended September 30, 2022		Nine Months ended September 30, 2021
Charge for the period	$	15,381,299	$	3,018,084	$	29,720,467	$	6,598,663
Percentage of revenue from product sales		19.6%		12.9%		14.7%		11.8%
Per Boe	$	10.53	$	6.08	$	8.60	$	5.13

Total operating and transportation costs for the three and nine months ended September 30, 2022, increased when compared to the same periods of 2021 due to overall increased production noted above. The increase in production and transportation costs per Boe is due to higher initial operating costs for wells brought online in 2022 primarily related to higher water disposal, fuel and trucking costs and overall market increases for service costs due primarily to inflation and market availability.

Field Operating Netbacks ¹

		Three Months			Three Months			Nine Months			Nine Months
		ended			ended			ended			ended
		September 30,			September 30,			September 30,			September 30,
($/Boe)		2022			2021			2022			2021
Revenue from product sales	$	53.63		$	47.16		$	58.72		$	43.44
Royalties		(14.13	)		(13.47	)		(16.10	)		(12.14	)
Production costs		(10.53	)		(6.08	)		(8.60	)		(5.13	)
Field operating netback	$	28.97		$	27.61		$	34.02		$	26.17

1 - Field operating netback is a non-GAAP financial measure that is not a standardized measure under the IFRS financial reporting framework.

General and Administrative Costs

		Three Months		Three Months		Nine Months		Nine Months
		ended		ended		ended		ended
		September 30,		September 30,		September 30,		September 30,
		2022		2021		2022		2021
Charge for the period	$	3,854,845	$	1,661,449	$	11,764,179	$	7,650,282
Percentage of revenue from product sales		4.9%		7.1%		5.8%		13.7%
Per Boe	$	2.64	$	3.34	$	3.41	$	5.95

General and administrative costs for the three and nine months ended September 30, 2022, increased as compared to the same periods of 2021 primarily due to employee salaries and benefits, which began in the second half of 2021, and which had previously been compensated under a management service agreement.  Offsetting the increase was a reduction in professional, legal and advisory costs, which was reduced due to lower transaction and contract costs.  The reduction in per BOE costs is the result of increased production levels noted above.

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Interest and Finance Costs

		Three Months ended September 30, 2022		Three Months ended September 30, 2021		Nine Months ended September 30, 2022		Nine Months ended September 30, 2021
Charge for the period	$	5,966,790	$	10,991,673	$	32,003,711	$	16,751,963
Per Boe	$	4.08	$	22.13	$	9.27	$	13.02

The increase in interest and financing costs for the nine months ended September 30, 2022, as compared to the same period of 2021 is mainly due to additional development partnerships created and on going in the current period, with fair value changes associated with the development partnership liabilities of $24,100,765 (September 30, 2021 - $12,310,373) (discussed below).  The reduction in interest and finance costs for the three months ended September 30, 2022 as compared to the same period of 2021 is due to reduced fair value changes in development partnerships, due to timing of drilling activities and identified associated results, offset by higher interest costs on long-term debt facilities (from higher outstanding borrowings).

Depletion and Depreciation

		Three Months ended September 30, 2022		Three Months ended September 30, 2021		Nine Months ended September 30, 2022		Nine Months ended September 30, 2021
Charge for the period	$	13,121,973	$	3,815,509	$	27,503,795	$	10,521,936
Per Boe	$	8.98	$	7.68	$	7.96	$	8.18

Depletion expense increased for the three and nine months ended September 30, 2022, as compared to the same periods of 2021 as a result of an increase in producing wells in 2022, and associated depletion base of property, plant and equipment.

Net Income/(Loss) Attributable to Alpine Summit Shareholders

		Three Months ended September 30, 2022		Three Months ended September 30, 2021			Nine Months ended September 30, 2022		Nine Months ended September 30, 2021
Net income/(loss)	$	14,584,258	$	(18,636,041	)	$	12,509,110	$	(51,614,575	)
Per share - basic	$	0.42	$	(0.42	)	$	0.37	$	(1.13	)
Per share - diluted	$	0.40	$	(0.42	)	$	0.35	$	(1.13	)

Investments Activity

Capital Expenditures

In the nine months ended September 30, 2022, the Company incurred capital expenditures on property, plant and equipment of $133,790,292 compared to $38,498,017 for the nine months ended September 30, 2021.  The majority of activity for these periods relates to the drilling of horizontal wells in the Giddings and Hawkville Fields.

During the nine months ended September 30, 2022, the Company expended $31,693,118 (September 30, 2021 - $6,763,605) 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.

6

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.

Historically, the markets for oil, natural gas and NGL have been volatile, and they are likely to continue to be volatile. During the first half of 2020, oil prices dramatically collapsed due to the impact of the COVID-19 pandemic and other conditions.  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 was a significant demand shock worldwide which created downward pressure on oil prices. There was also increased supply due to the dispute between Saudi Arabia and Russia which had a further adverse impact on oil prices. After the severe price drop in 2020, oil prices rebounded and increased from levels immediately preceding the pandemic. In addition to recovering demand, 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. 

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

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

At September 30, 2022, the Company had the following commodity contracts, with a total mark-to-market liability of $4,386,106 (December 31, 2021 - $20,381,180). 

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Commodity	Expiry	Type	Fixed Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	2022-2024	Swap	$0.13	2,371,199	NGL-Mont Belvieu
Ethane (gallons)	2022-2025	Swap	$0.35	6,437,511	NGL-Mont Belvieu
Ethane (gallons)	2022-2025	Swap	$0.38	2,858,171	NGL-Mont Belvieu
Propane (gallons)	2022-2024	Swap	$0.43	1,457,884	NGL-Mont Belvieu
Propane (gallons)	2022-2025	Swap	$0.91	1,588,684	NGL-Mont Belvieu
Propane (gallons)	2022-2025	Swap	$0.96	3,913,519	NGL-Mont Belvieu
Natural gas (gallons)	2022-2024	Swap	$0.83	934,138	NGL-Mont Belvieu
Natural gas (gallons)	2022-2025	Swap	$1.52	715,221	NGL-Mont Belvieu
Natural gas (gallons)	2022-2025	Swap	$1.70	1,484,085	NGL-Mont Belvieu
Isobutane (gallons)	2022-2024	Swap	$0.46	305,048	NGL-Mont Belvieu
Isobutane (gallons)	2022-2025	Swap	$0.97	308,623	NGL-Mont Belvieu
Isobutane (gallons)	2022-2025	Swap	$1.15	738,487	NGL-Mont Belvieu
Norbutane (gallons)	2022-2024	Swap	$0.47	709,296	NGL-Mont Belvieu
Norbutane (gallons)	2022-2025	Swap	$0.96	653,694	NGL-Mont Belvieu
Norbutane (gallons)	2022-2025	Swap	$1.14	1,500,921	NGL-Mont Belvieu
Natural gas (mmbtu)	2022-2025	Swap	$2.47	1,262,598	Henry Hub -Nymex
Natural gas (mmbtu)	2022-2025	Swap	$5.15	1,043,576	Henry Hub -Nymex
Natural gas (mmbtu)	2022-2025	Swap	$5.99	7,116,633	Henry Hub -Nymex
Crude oil (bbl)	2022-2025	Swap	$40.99	375,326	WTI-Nymex
Crude oil (bbl)	2022-2025	Swap	$78.80	229,406	WTI-Nymex
Crude oil (bbl)	2022-2025	Swap	$82.40	413,076	WTI-Nymex

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

The unrealized gain for the nine months ended September 30, 2022, of $14,358,774 and realized losses of $31,604,687 (September 30, 2021 - $25,105,949 unrealized and $14,276,939 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.

8

Financing, Liquidity and Capital Resources

Liquidity describes a company's ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs that maintain and increase production and reserves, to acquire strategic oil and gas assets, to repay current liabilities and debt and ultimately to provide a return to shareholders. The Company's capital programs are funded by existing working capital, various lending facilities (discussed below) and cash provided from operating activities.  The Company expects to fund its remaining 2022 exploration and development program through the use of working capital and cash flow from operations. Fluctuations in commodity prices, product demand, interest rates and various other risks may impact capital resources and capital expenditures.

As at September 30, 2022 all of the Company's cash is on deposit with high credit-quality financial institutions. The Company incurs an approximate 30-day collection cycle on oil and natural gas sales.

Long-term Debt

a.Asset backed securitization facility

On April 27, 2022 the Company entered into an asset backed securitization of certain producing oil and gas wells (the "ABS Facility"). The ABS Facility is led by an insurance company and had an initial size of $80 million ("Tranche 1") with additional capacity to expand up to $150 million in total. 

All borrowings under Tranche 1 of the ABS Facility are secured by working interests in a subset of the Company's producing assets, which are held by a subsidiary of its operating subsidiary, HB2 Origination, LLC.  Tranche 1 of the ABS Facility carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) for the initial year, LIBOR +12% for the second year and an ultimate maturity date of May 2024.  Interest payments are required monthly. 

On September 12, the ABS Facility was increased by $55 million ("Tranche 2"), to a total size of $135 million. All borrowings under Tranche 2 of the ABS Facility are secured by working interests in a subset of the Company's producing assets, which are held by a subsidiary of its operating subsidiary, HB2 Origination, LLC.  Tranche 2 of the ABS Facility carries an interest rate of LIBOR+8% (with a 1% LIBOR floor) for the initial year, LIBOR +14% for the second year and an ultimate maturity date of August 2024.  Interest payments are required monthly.             

As at September 30, 2022, the Company had $120,597,912 outstanding under the ABS Facility. 

The Company's subsidiaries have certain financial covenants under the ABS Facility, including maintaining a debt service coverage ratio of no less that 1.1 to 1.0. 

Under the terms of the ABS Facility, the Company is also required to;

i)  As at the initial borrowing date, enter into certain forward commodity swap contracts, which it has done.

ii)  Maintain an interest reserve account that will hold a cash balance sufficient to cover three months of scheduled interest payments.

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Repayments of principal required under the ABS Facility are as follows:

September 30, 2022
2022	$	10,615,235
2023		61,630,567
2024		48,352,110
2025		-
Thereafter		-
	$	120,597,912

In addition to the required principal repayments outlined above, the Company's subsidiaries could also be required to make additional payments:

i)  if the debt service coverage ratio is less than 1.20 to 1.00, the Company must make an additional principal prepayment equal to net income/(loss) adjusted for all non-cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement.

ii)  if the production tracking ratio is less than 80%, the Company must make an additional principal prepayment equal to net income/(loss) adjusted for all non-cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement.

iii)  if the loan to value is above 85%, the Company must make an additional principal prepayment equal to net income/(loss) adjusted for all non-cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement.

At September 30, 2022, the Company was not subject to any other additional principal prepayments.

b.Goldman facility

On December 22, 2020, the Company entered into a credit facility with Goldman Sachs (the "Goldman Facility").  All borrowings under the Goldman Facility were secured by the Company's oil and gas producing wells as well as all assets of three of the Company's subsidiaries.  The Goldman Facility carried an interest rate of LIBOR+6% (with a 1% LIBOR floor) and a maturity date of December 22, 2031.  Interest payments were required quarterly. 

In April 2022, in connection with the ABS Facility (above), the Company repaid the Goldman Facility in full and amortized the remaining unamortized borrowing costs.

Corporate Credit Facility

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

During the first quarter of 2022, Origination closed a new corporate credit facility to replace the previous facility. The new corporate credit facility has a total size of $30 million. The corporate credit facility is secured by working interests in a subset of the Company's producing assets and charges interest at the greater of 5.00% and Prime +1.75% and has a one-year maturity.

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As at September 30, 2022, the Company had drawn $Nil under the Corporate Facility (December 31, 2021 - $2,200,000), and for the three and nine months ended September 30, 2022, incurred $477,155 and $972,989, respectively, of interest and finance expense related to the facility.  The borrowing base as at September 30, 2022 was $17,373,964 (December 31, 2021- $6,579,750).

Development Partnerships

The Company, through its 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.

Refer to the Consolidated Financial Statements for additional disclosures related to previously formed, repayments and reversions of development partnerships.

During the fourth quarter of 2021, Origination formed the third development partnership ("DP3") with 23 limited partners (the "DP3 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $35.3 million in total size. DP3 partially funded the drilling and completion of five wells, with the DP3 LPs funding 60% and Origination funding 40%. The DP3 LPs chose to receive development partnership units ("DP Units") that distributed profits either based on a Flat payout option or an IRR based payout option.  Flat Payout Units participated in 75% of the income of DP3 (along with IRR based Payout Units) until that income equaled their invested capital and thereafter participated in 20% of the income of DP3 (along with IRR based Payout Units). IRR Based Payout Units participated in 75% of the income of DP3 (along with Flat Payout Units) until that income equaled their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever was greater, and thereafter participated in 6% of the income of DP3, along with Flat Payout Units, which participated in 20% of the income of DP3.  The DP3 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.

The Company, through the structure of DP3, maintained control of DP3and consolidated 100% of the operations of DP3.

In April 2022, the Company repaid and paid out the reversion of DP3.  As part of the completion of the DP3 program, the Company retired liabilities of $30,171,337.

Twelve of the DP3 partners exercised the put right provided to such partners by DP3 regarding residual interests in their associated investment and, elected to exchange the remaining interest in DP3 for 894,929 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$5.70 per unit, or a total of $5,127,229.

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

During the first quarter of 2022, Origination formed its fourth development partnership ("DP4") with 29 limited partners (the "DP4 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $42.0 million in total size. DP4 partially funded the drilling and completion of five wells, with the DP4 LPs funding 60% and Origination funding 40%. The DP4 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 DP4 (along with IRR based Payout Units) until that income equals their invested capital and thereafter participate in 20% of the income of DP4 (along with IRR based Payout Units). IRR Based Payout Units participate in 75% of the income of DP4 (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 DP4, along with Flat Payout Units, which participate in 20% of the income of DP4.  The DP4 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.

11

The Company, through the structure of the DP4, maintains control of the DP4and consolidates 100% of the operations of the DP4.

In July 2022, the Company repaid and paid out the reversion of DP4.  As part of the completion of the DP4 program, the Company retired liabilities of $31,734,290.

Nine of the DP4 partners exercised the put right provided to such partners by DP4 regarding residual interests in their associated investment and, elected to exchange the remaining interest in DP4 for 706,975 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$5.85 per unit, or a total of $4,135,804.  Two of the DP4 partners elected to retain their ongoing rights of working interest in the DP4 wells and as a result, the fair value of their liability related to working interest was settled with an offset disposition from PP&E.

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

During the first quarter of 2022, Origination formed development partnership Red Dawn 1 with 37 limited partners (the "Red Dawn 1 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $50.4 million in total size. Red Dawn 1 partially funded the drilling and completion of five wells, with the Red Dawn 1 LPs funding 60% and Origination funding 40%. The Red Dawn 1 LPs could choose to receive development partnership units ("Red Dawn 1 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 Red Dawn 1 (along with IRR based Payout Units) until that income equals their invested capital and thereafter participate in 20% of the income of Red Dawn 1 (along with IRR based Payout Units). IRR Based Payout Units participate in 75% of the income of Red Dawn 1 (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 Red Dawn 1, along with Flat Payout Units, which participate in 20% of the income of Red Dawn 1.  The Red Dawn 1 LPs 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 Red Dawn 1, maintains control of Red Dawn 1and consolidates 100% of the operations of Red Dawn 1.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments.  For the three and nine months ended September 30, 2022, an increase in the Red Dawn 1 liability of $6,305,770 was recorded related to the change in fair value of the liability, with a corresponding increase to finance expense.  Refer to Subsequent Event section for more details.

12

During the second quarter of 2022, Origination formed the fifth development partnership ("DP5") with 25 limited partners (the "DP5 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $50.3 million in total size. DP5 is partially funding the drilling and completion of six wells, with the DP5 LPs funding 60% and Origination funding 40%. The DP5 LPs can choose to receive development partnership units ("DP5 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 DP5 (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of DP5 (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of DP5 (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 DP5, along with Flat Payout Units, which will participate in 20% of the income of DP5.  The DP5 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 DP5, maintains control of DP5and consolidates 100% of the operations of DP5.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments.  For the three and nine months ended September 30, 2022, 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.

During the third quarter of 2022, Origination formed DP6 with 39 limited partners (the "DP6 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $56.9 million in total size. DP6 is partially funding the drilling and completion of ten wells, with the DP6 LPs funding 60% and Origination funding 40%. The DP6 LPs can choose to receive development partnership units ("DP6 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 DP5 (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of DP6 (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of DP6 (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 DP6, along with Flat Payout Units, which will participate in 20% of the income of DP5.  The DP6 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 DP6, maintains control of DP6and consolidates 100% of the operations of DP6.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments.  For the three and nine months ended September 30, 2022, 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.

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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.

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.

In the second quarter of 2022, the Company redeemed all of the LP units for $19,345,398, in connection with the ABS Facility.

For the nine months ended September 30, 2022, the Company recorded finance expense related to the outstanding instrument in the amount of $658,047 (September 30, 2021 - $1,310,975) (above). 

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 Subordinate Voting Shares ("SVS") is entitled to one vote per share, each Multiple Voting Shares ("MVS") is convertible, at the option of the holder, into 100 SVS and entitles the holder to 100 votes per share and each Proportionate Voting Shares ("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 Business Combination Agreement ("BCA").

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Issued

		Origination Member Units		SVS		MVS		PVS		Amount
Balance at January 1, 2021	Note	17,083,501		-		-		-	$	37,097,376
Issuance of member units for cash	12	819,215		-		-		-		8,044,700
Issuance of member units exchanged for promissory notes	12	353,870		-		-		-		3,475,000
Issuance of member units for exploration and evaluation assets	12	356,415		-		-		-		3,499,995
Issuance of member units to contractors	12	923,954		-		-		-		9,073,228
Redemption of member units	12	(3,992,629	)	-		-		-		(8,680,786	)
Issuance of member units exchanged for promissory notes	12	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		-		-
Proportionate 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	12	-		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
RSU settlement	12	-		2,024,401.000		-		-		9,685,555
Repurchase of SVS	12	-		(265,900.000	)	-		-		(1,456,566	)
Accrued liability for automatic share purchase plan commitment	12	-		-		-		-		(8,297,298	)
MVS converted to SVS	12	-		195,541.000		(1,955.410	)	-		-
Balance at September 30, 2022		-		34,489,773.000		8,379.920		15,947.292	$	43,345,838

2022 Activity

During the nine months ended September 30, 2022, 1,955.410 MVS were converted into 195,541 SVS on a 100 to 1 basis. 

During the nine months ended September 30, 2022, 2,024,401 SVS were issued as a result of settling certain restricted share units ("RSU") (Note 15).  Previously stock-based compensation of $9,685,555 has been removed from contributed surplus and has been reclassified to share capital to reflect the impact of settlement.

On June 10, 2022, the TSX Venture Exchange ("TSXV") approved the Company's normal course issuer bid ("NCIB").  Under the NCIB, the Company may purchase, for cancellation, up to 1,648,783 SVS of the Company (representing approximately 5% of its issued and outstanding SVS as of June 6, 2022) over a 12-month period commencing on June 10, 2022. The NCIB will expire no later than June 9, 2023.  During 2022, the Company purchased and cancelled 265,900 SVS at an average price of $5.48/share for an aggregate value of $1,456,566.

On September 27, 2022, the TSXV approved an amendment to the Company's NCIB, which permits the Company to enter into an automatic share purchase plan ("ASPP") to facilitate the purchase of SVS under the NCIB during times when the Company would not ordinarily be permitted to purchase such shares due to regulatory restrictions of self imposed black-out periods.  The Company recorded an accrual of $8.3 million representing the contractual maximum share purchases remaining under the ASPP.

15

2021 Activity

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). 

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 $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 expense 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 NCI 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.

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Income/(loss) per share:

		Nine months ended September 30, 2022					Nine months ended September 30, 2021
		Net Income	Shares		Income per share		Net Loss		Shares		Loss per share
Income/(loss) - basic	$	12,509,110	34,268,827	$	0.37	$	(51,641,575	)	45,632,956	$	(1.13	)
Diliutive effect of outstanding awards		-	1,115,435		-		-		-		-
Income/(loss) - diluted	$	12,509,110	35,384,262	$	0.35	$	(51,641,575	)	45,632,956	$	(1.13	)
		Three months ended September 30, 2022					Three months ended September 30, 2021
		Net Income	Shares		Income per share		Net Loss		Shares		Loss per share
Income/(loss) - basic	$	14,584,258	34,900,145	$	0.42	$	(18,636,041	)	43,882,747	$	(0.42	)
Diliutive effect of outstanding awards		-	1,138,385		-		-		-		-
Income/(loss) - diluted	$	14,584,258	36,038,530	$	0.40	$	(18,636,041	)	43,882,747	$	(0.42	)

The Company had share purchase options ("Options"), RSUs and deferred share units ("DSUs") outstanding for the three and nine months ended September 30, 2022 (September 30, 2021 - none outstanding) (Note 15).  The effect of the conversion or exercise of Options, RSU's and DSU's (three months 1,138,385, nine months 1,115,435) are included in the three months ended calculation of diluted income per share and excluded for the nine months ended as they are anti-dilutive.  The Company used an average market price of $5.33 and $5.45 per share, respectively, to calculate the dilutive effect of stock options, RSUs and DSUs outstanding.

The Company's NCI interest, which can be freely converted to SVS on a one-for-one basis, would have no dilutive impact and therefore has not been included in the calculation of diluted income per share (2022 - three months 18,735,964, nine months 17,886,552) (2021 - three months 4,042,106 nine months 1,362,175).

Normal Course Issuer Bid ("NCIB")

Refer to Shareholders' Capital - 2022 Activity for additional discussion.

All purchases made pursuant to the NCIB will be made through the facilities of the TSXV. The NCIB will be made in accordance with the applicable rules and policies of the TSXV and applicable Canadian securities laws. The price that Alpine Summit will pay for SVS in open market transactions will be the market price at the time of purchase. Any SVS that are purchased under the NCIB will be cancelled.  A copy of the related Notice of Intention to Make a NCIB will be provided to shareholders, at no charge, upon receipt of written request to the Company at ir@alpsummit.com.

Dividends

On December 14, 2021, the Company announced that its Board of Directors had declared a dividend distribution policy, beginning in January 2022.  Monthly dividends of $0.03 per SVS and $3.00 per MVS were declared and paid for each month ended during the nine months ended September 30, 2022, with an aggregate distribution of $9,260,948.

The Company utilizes Odyssey Transfer, Inc. as the paying agent for dividend distributions.

17

Non-Controlling Interest

2022 Activity

In connection with the BCA, certain Origination equity holders elected not to convert their equity holdings in Origination into SVS/MVS of the Company.  The non-converting equity holders hold 18,935,761 Class B non-voting units of Origination, which amount to a 34.886% economic interest in Origination as at September 30, 2022 (December 31, 2021 - 32.954%).

In January 2022, 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 826,063 Class B non-voting units of Origination.  As a result, a credit to NCI for the fair value of the put right for DP2 of $3,159,706 was recorded to settle liabilities. 

During the nine months ended September 30, 2022, certain RSUs were settled (Note 15) and as a part of the amended and restated LLC agreement between Origination and the Company, an equivalent number of Origination Units were issued.  Based on the fair value of shares issued on the date of settlement $11,609,135 has been recorded as a decrease to non-controlling interest and a corresponding offset to capital reserve.  The RSU settlements are outlined below:

September 30, 2022
Date		Share Price		Fair value
January 18, 2022	$	5.00	$	1,406,250
June 6, 2022		6.49		5,407,338
September 1, 2022		5.27		4,795,547
	$	5.59	$	11,609,135

In May 2022, twelve of the DP3 partners exercised the put right provided to such partners by DP3 regarding residual interests in their associated investment and elected to exchange the remaining interest in DP3 for 894,929 Class B non-voting units of Origination.  As a result, a credit to NCI for the fair value of the put right for DP3 of $5,127,229 was recorded to settle liabilities. 

In July 2022, nine of the DP4 partners exercised the put right provided to such partners by DP4 regarding residual interests in their associated investment and elected to exchange the remaining interest in DP4 for 706,975 Class B non-voting units of Origination.  As a result, a credit to NCI for the fair value of the put right for DP4 of $4,135,804 was recorded to settle liabilities. 

Beginning in the first quarter of 2022, the Company declared and paid monthly dividends to shareholders.  In connection with the dividend distributions from Origination, non-converting equity holders received their NCI share totalling $4,829,951, for the nine months ended September 30, 2022, resulting in a decrease of NCI.

For the nine months ended September 30, 2022, $6,977,736, was recorded to reduce net income on the condensed interim consolidated statement of income and comprehensive income, with an offset to NCI, representing NCI share of net loss (2021 - $3,355,382).

2021 Activity

On closing the BCA, Origination's consolidated book value of net liabilities was $32,968,557, which resulted 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.

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For the 23 days of September, 2021 following the closing of the BCA, $3,355,382 was recorded to decrease net loss on the interim consolidated statements 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, 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

In the second quarter of 2021, the Company entered into a new Letter Agreement (the "Letter") with a company related by virtue of common equity holders, directors, and officers. The Letter requires the Company to hire its own employees, obtain its own office lease, and assume certain management obligations. In exchange, the Company is paid an annual fee of $1,000,000 on a quarterly basis. During the three and nine months ended September 30, 2022, the Company has been paid $250,000 and $750,000 in cash.

Related party balances

At September 30, 2022, the accounts payable included $89,107 (December 31, 2021 - accounts payable of $120,501) 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 financial liabilities as they become due.  The Company's financial liabilities consist of accounts payable and accrued liabilities and promissory notes, all of which are due within a year, commodity contract liabilities which will all be settled over the life of their contract terms (see below), lease liabilities which will be settled over the life of the lease, asset backed preferred instruments which will be repaid based on available cash flows, development partnership liabilities that will be repaid based on cash flows generated by the wells included in the partnership and a credit facility with portions due in the following year. The Company also maintains and monitors a certain level of cash flow which is used to partially finance all operating and capital expenditures.  The Company also attempts to match its payment cycle with collection of oil and natural gas sales which are usually collected within 30 to 60 days.

At September 30, 2022, the Company had negative working capital of $191,937,275.  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.

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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 effort to increase liquidity, the Company has during and subsequent to the nine months ended September 30, 2022: (i) continued its drilling program to increase cash flows from operating activities, (ii) raised significant funds through development partnerships, (iii) entered into a new revolving corporate credit facility, and iv) refinanced indebtedness.

The following table details the Company's financial liabilities and their scheduled maturities as at September 30, 2022:

		Carrying value		Contractual cash flow		Less than one year		1 - 3 years		Greater than 3 years
Accounts payable and accrued liabilities	$	74,510,929	$	74,510,929	$	74,510,929	$	-	$	-
Commodity contracts		6,972,796		6,972,796		6,972,796		-		-
Lease liability		430,854		430,854		131,462		299,392		-
Corporate credit facility		-		-		-		-		-
Development partnerships liabilities		100,904,095		100,904,095		100,904,095		-		-
Long term debt		117,157,168		120,597,912		59,337,758		61,260,154		-
Total	$	299,975,842	$	303,416,586	$	241,857,040	$	61,559,546	$	-

Subsequent Events

Dividends declared

On October 1, 2022, the Company's Board of Directors declared a dividend of $0.03 per SVS/PVS and $3.00 per MVS, for a total amount of $1,060,311, payable on October 31, 2022, to shareholders of record on the close of business on October 17, 2022.

On November 1, 2022, the Company's Board of Directors declared a dividend of $0.03 per SVS/PVS and $3.00 per MVS, for an estimated total amount of $1,052,763, payable on November 30, 2022, to shareholders of record on the close of business on November 16, 2022.

Corporate credit facility amendment

In October 2022, the Company amended and expanded its Corporate Facility (Note 9) from an initial size of $30.0 million up to $65.0 million, with a current borrowing base of $20.5 million.  The Corporate Facility's maturity and interest rates remain unchanged.

Completion of Red Dawn 1 and creation of Red Dawn 2

On November 9, 2022, the Company successfully completed the repayment and reversion of Red Dawn 1 that it formed during the first quarter of 2022, along with the concurrent closing of its Red Dawn 2 development partnership.

20

Red Dawn 1 partially funded the drilling and completion of a total of five wells and comprised a total capital program of approximately $50.4 million, with 60% funded by external partners. As part of the completion of the Red Dawn 1 program, Alpine Summit has retired liabilities of approximately $38.5 million.

Twelve of the Red Dawn 1 partners exercised the put right provided to such partners by Red Dawn 1 regarding residual interests in their associated investment and, subject to the approval of the TSX Venture Exchange (the "TSXV"), elected to sell their remaining interest in Red Dawn 1 for 617,103 Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company), having a deemed value of $5.16 per unit (which was calculated with reference to the trailing 30 day share price and the allowable discounts permitted by the policies of the TSXV), or a total of approximately $3.2 million.

Red Dawn 2 has an expanded capital program of approximately $57.7 million, with approximately $34.6 million of external development capital, and is expected to continue to develop assets within the Company's existing operational footprint.

Quarterly Results

Summarized information by quarter for the previous two years ended September 30, 2022 appears below.

		2022									2021												2020
		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Revenue from product sales		78,362,838			77,412,882			47,039,285			42,028,563			23,427,075			12,836,239			19,625,913			2,568,289
Net income (loss)		14,584,258			6,873,817			(8,948,965	)		21,943,230			(18,636,041	)		(24,751,922	)		(8,226,612	)		(3,007,192	)
Per unit - basic	$	0.42		$	0.20		$	(0.26	)	$	0.48		$	(0.42	)	$	(1.68	)	$	(0.53	)	$	(0.18	)
Net capital expenditures		(63,132,318	)		(28,383,860	)		(42,274,114	)		(13,689,074	)		(23,614,898	)		(9,836,725	)		(5,046,394	)		(36,276,414	)
Average daily production (Boe)		15,882			13,195			8,801			8,772			5,399			3,805			4,983			981
Working capital deficiency		(191,937,275	)		(165,427,098	)		(151,923,864	)		(80,838,833	)		(80,891,770	)		(49,133,400	)		(24,142,999	)		(29,102,456	)

Increased production and stable commodity prices for the three months ended June 30, 2022 and September 20, 2022, compared to March 31, 2022 led to increased revenue and cash flows from operations.  These increased operating results led to net income increases versus prior periods.

The Company maintained consistent production for the three months ended March 31, 2022, compared to the prior quarter however, improved realized commodity prices led to increased revenue.  The increased commodity prices noted also increased realized and unrealized commodity contract losses in the period, leading to the decrease in first quarter net losses.

In 2021, the formation of the three development partnerships resulted in the drilling of ten wells that came on production in the second half of the year increasing the operating results.  These additional wells 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.

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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, audited 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 34,116,573, 8,379.92, and 15,947.292 for current SVS, MVS 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.

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, economic, business and political conditions, including commodity price volatility, interest rates and currency exchange, OPEC actions, ongoing global economic concerns, Russia's military invasion of Ukraine, and rising civil unrest and activism globally;
• changes in supply and demand for the Company's products;

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• 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 execute the NCIB
• the ability of the Company to obtain a dual listing on the NASDAQ exchange;
• 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;
• 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);

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• 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;
• 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.

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. The Company's Management uses these non-GAAP supplemental measures to benchmark operations against prior periods and peer group companies and believes they provide useful supplemental information that can be used by investors, lenders, analysts and other parties to analyze the Company's performance and financial results.

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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.

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 supplement 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 NCI. 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 Company's identified business risks have been described in the MD&A as at December 31, 2021.

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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