MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management's discussion and analysis of financial results ("MD&A") is dated August 24, 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 six months ended June 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. The reporting currency is the United States dollar.  Comparative information is provided for the three and six months ended June 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.

Q2 2022 Highlights

•Maintained average gross production of approximately 14,631 Boe/day for the three months ended June 30, 2022 (Net 13,195 Boe/day) an increase of 48% quarter over quarter and 227% year over year.

•Reported Net Income before Non-Controlling Interest of approximately $9.2 million for the three months ended June 30, 2022 (June 30, 2021 - $24.8 million loss).  Adjusted EBITDA¹ (defined below) of approximately $40.9 million for the same period (June 30, 2021 - $3.9 million).

•Successful repayment and reversion of the third development partnership ("DP3") that was formed during the fourth quarter of 2021, along with the concurrent closing of its fifth development partnership ("DP5") in April 2022.

•Closed a new asset backed securitization of certain producing oil and gas wells (the "ABS Facility") with an initial size of $80 million.  The ABS Facility charges interest at one-month LIBOR (with a 1% floor) +6%. As at June 30, 2022, approximately $75.8 million was outstanding on the ABS Facility.

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

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

		Three Months		Three Months			Six Months			Six Months
		ended June 30,		ended June 30,			ended June 30,			ended June 30,
		2022		2021			2022			2021
Net income/(loss) before non-controlling interest:	$	9,221,988	$	(24,751,922	)	$	(3,050,990	)	$	(32,978,534	)
(+) Depletion and depreciation expense		9,782,846		2,861,427			14,381,822			6,706,427
(+) Finance and interest expense		15,487,958		4,224,249			26,036,921			5,760,290
(+) Stock based compensation expense		4,229,527		9,073,228			5,519,670			9,073,228
(+) Unrealized and realized (gains)/losses on commodity contracts		2,224,256		12,518,507			24,375,377			25,409,478
Adjusted EBITDA	$	40,946,575	$	3,925,489		$	67,262,800		$	13,970,889

2022 Objectives

Based on the current development plan, the Company anticipates bringing an additional 14 to 18 wells online during the second half of 2022. With the significant level of investment activity, the Company is on pace to realize a meaningful increase in its production profile from Q2 2022 levels throughout the balance of the year.

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

2

Q2 2022 was the Company’s first full quarter of production from wells developed within its Webb County asset base. The well results in the Webb County acreage have exceeded expectations and development of those assets are expected to take increasing priority as the Company moves into 2023.

As previously announced, the Company is in the process of applying for a dual listing on the NASDAQ exchange. While not in its control, the Company continues to work toward completing this process by the end of Q3 2022. In the meantime, the Company anticipates resuming purchases under the approved Normal Course Issuer Bid, as the Board of the Company believes that the current share price fails to reflect the business’s underlying value.

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 July and August 2022.

• In July, the Company successfully completed the repayment and reversion of its fourth development partnership and concurrently closed its sixth development partnership (“DP6”).  DP6 has an expanded capital program of approximately $56.9 million, with $34.2 million of external development capital. Refer to subsequent events section below for further discussion.

Refer to subsequent events section below for further discussion.

Results of Operations

Production and Revenue

Average Daily Production (Net)

	Three Months ended June 30, 2022	Three Months ended June 30, 2021	Period-over- period change	Six Months ended June 30, 2022	Six Months ended June 30, 2021	Period-over- period change
Crude oil (bbls/d)	4,739	1,724	3,014	4,467	1,944	2,524
Natural gas (Mcf/d)	35,888	6,979	28,909	25,400	8,862	16,538
NGLs (bbls/d)	2,475	917	1,558	2,309	942	1,367
Total (Boe/d)	13,195	3,804	3,804	11,010	4,363	6,647
Crude oil weighting	35.9%	45.3%		40.6%	44.5%
Natural gas weighting	45.3%	30.6%		38.4%	33.9%
NGL weighting	18.8%	24.1%		21.0%	21.6%

Production increased for three and six months ended June 30, 2022, as compared to the comparative periods of 2021 due to the addition of ten new wells through the final six months of 2021, and six new wells through the six months ended June 30, 2022.

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Revenue from Product Sales ¹

		Three Months		Three Months		Six Months		Six Months
		ended June 30,		ended June 30,		ended June 30,		ended June 30,
		2022		2021		2022		2021
Crude oil	$	46,680,724	$	9,958,516	$	81,802,677	$	20,538,257
Natural gas		21,324,555		1,658,534		26,178,240		9,588,841
NGLs		9,407,603		1,219,189		16,471,250		2,335,054
Total	$	77,412,882	$	12,836,239	$	124,452,167	$	32,462,152
% of Total Revenue by Product Type
Crude oil weighting		60.30%		77.58%		65.73%		63.27%
Natural gas weighting		27.55%		12.92%		21.03%		29.54%
NGL weighting		12.15%		9.50%		13.24%		7.19%

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

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

Average Selling Prices ¹

		Three Months		Three Months		Six Months		Six Months
		ended June 30,		ended June 30,		ended June 30,		ended June 30,
		2022		2021		2022		2021
Crude oil - Bbl	$	108.25	$	63.47	$	101.16	$	58.38
Natural gas - Mcf	$	6.53	$	2.61	$	5.69	$	5.98
NGL - Bbl	$	41.77	$	14.61	$	39.41	$	13.69
Per Boe	$	64.47	$	37.08	$	62.45	$	41.10

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 six months ended June 30, 2022, increased compared to the same periods of 2021, due to strengthened worldwide commodity prices. 

Royalties

		Three Months		Three Months		Six Months		Six Months
		ended June 30,		ended June 30,		ended June 30,		ended June 30,
		2022		2021		2022		2021
Charge for the period	$	21,918,895	$	3,587,815	$	34,940,865	$	8,921,851
Percentage of revenue from product sales		28.3%		28.0%		28.1%		27.5%
Per Boe	$	18.25	$	10.36	$	17.53	$	11.30

Royalties, as a percentage of revenue from product sales, increased in the three and six months ended June 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.

Production and Transportation Costs

		Three Months		Three Months		Six Months		Six Months
		ended June 30,		ended June 30,		ended June		ended June 30,
		2022		2021		30, 2022		2021
Charge for the period	$	9,780,292	$	1,830,431	$	14,339,168	$	3,580,579
Percentage of revenue from product sales		12.6%		14.3%		11.5%		11.0%
Per Boe	$	8.15	$	5.29	$	7.20	$	4.53

4

Total production and transportation costs for the three and six months ended June 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 (inflation and market availability).

Field Operating Netbacks ¹

		Three Months			Three Months			Six Months			Six Months
		ended June 30,			ended June 30,			ended June 30,			ended June 30,
($/Boe)		2022			2021			2022			2021
Revenue from product sales	$	64.47		$	37.08		$	62.45		$	41.10
Royalties		(18.25	)		(10.36	)		(17.53	)		(11.30	)
Production costs		(8.15	)		(5.29	)		(7.20	)		(4.53	)
Field operating netback	$	38.07		$	21.43		$	37.72		$	25.27

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		Six Months		Six Months
		ended June 30,		ended June 30,		ended June 30,		ended June 30,
		2022		2021		2022		2021
Charge for the period		4,767,120		3,492,504		7,909,334		5,988,833
Percentage of revenue from product sales		6.2%		27.2%		6.4%		18.4%
Per Boe	$	3.97	$	10.09	$	3.97	$	7.58

General and administrative costs for the three and six months ended June 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.

Interest and Finance Costs

		Three Months ended June 30, 2022		Three Months ended June 30, 2021		Six Months ended June 30, 2022		Six Months ended June 30, 2021
Charge for the period		15,487,958		4,224,249		26,036,921		5,760,290
Per Boe	$	12.90	$	12.20	$	13.07	$	7.29

The increase in interest and financing costs for three and six months ended June 30, 2022, as compared to the same periods of 2021 is mainly due to fair value changes associated with the development partnership liabilities of $20,992,255 (June 30, 2021 - $2,671,972)(discussed below).

Depletion and Depreciation

		Three Months		Three Months		Six Months		Six Months
		ended June 30,		ended June 30,		ended June 30,		ended June 30,
		2022		2021		2022		2021
Charge for the period	$	9,782,846	$	2,861,427	$	14,381,822	$	6,706,427
Per Boe	$	8.15	$	8.26	$	7.22	$	8.49

5

Depletion expense increased for the three and six months ended June 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.  The decrease in per BOE cost is a result of increased overall reserve base attributed to proved and probable wells.

Net Income/(Loss) Attributable to Alpine Summit Shareholders

		Three Months		Three Months			Six Months			Six Months
		ended June 30,		ended June 30,			ended June			ended June 30,
		2022		2021			30, 2022			2021
Net income/(loss)	$	6,873,817	$	(24,751,922	)	$	(2,075,148	)	$	(32,978,534	)
Per share - basic	$	0.20	$	(1.68	)	$	(0.06	)	$	(2.13	)
Per share - diluted	$	0.19	$	(1.68	)	$	(0.06	)	$	(2.13	)

Investments Activity

Capital Expenditures

In the six months ended June 30, 2022, the Company incurred capital expenditures on property, plant and equipment of $70,657,974 compared to $14,883,119 for the six months ended June 30, 2021.  The majority of activity for these periods relates to the drilling of horizontal wells in the Giddings and Hawkville Fields.

During the six months ended June 30, 2022, the Company expended $23,369,431 (June 30, 2021 - $3,469,396) 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.

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.

6

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 June 30, 2022, the Company had the following commodity contracts, with a total mark-to-market liability of $14,684,908 (December 31, 2021 - $20,381,180). 

Commodity	Expiry	Type	Fixed Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	Feb 2024	Swap	$0.13	2,794,720	NGL-Mont Belvieu
Ethane (gallons)	May 2025	Swap	$0.37	6,999,630	NGL-Mont Belvieu
Propane (gallons)	Feb 2024	Swap	$0.45	1,718,277	NGL-Mont Belvieu
Propane (gallons)	May 2025	Swap	$1.02	4,251,482	NGL-Mont Belvieu
Natural gas (gallons)	Feb 2024	Swap	$0.88	1,100,985	NGL-Mont Belvieu
Natural gas (gallons)	May 2025	Swap	$1.80	1,586,620	NGL-Mont Belvieu
Isobutane (gallons)	Feb 2024	Swap	$0.49	359,533	NGL-Mont Belvieu
Isobutane (gallons)	May 2025	Swap	$1.22	800,247	NGL-Mont Belvieu
Norbutane (gallons)	Feb 2024	Swap	$0.50	835,983	NGL-Mont Belvieu
Norbutane (gallons)	May 2025	Swap	$1.20	1,620,444	NGL-Mont Belvieu
Natural gas (mmbtu)	Feb 2024	Swap	$2.61	1,904,433	Henry Hub -Nymex vs East TX
Natural gas (mmbtu)	May 2025	Swap	$5.45	1,043,576	Henry Hub -Nymex
Natural gas (mmbtu)	Aug 2022-May 2023	Short	$3.91-5.17	1,560,000	Henry Hub -Nymex
Natural gas (mmbtu)	May 2025	Short	$5.42	110,000	Henry Hub -Nymex
Crude oil (bbl)	Aug -Dec 2022	Put	$65.00	215,970	WTI-Nymex
Crude oil (bbl)	Aug -Dec 2022	Short	$72.62-88.50	24,000	WTI-Nymex
Crude oil (bbl)	Jan -May 2023	Short	$72.00-89.18	16,000	WTI-Nymex
Crude oil (bbl)	Jun 2023	Call	$97.00	919,000	WTI-Nymex
Crude oil (bbl)	May 2027	Swap	$87.20	456,631	WTI-Nymex
Crude oil (bbl)	Dec 2028	Swap	$43.38	618,953	WTI-Nymex

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

The unrealized loss for the six months ended June 30, 2022, of $5,751,522 and realized losses of $18,623,855 (June 30, 2021 - $17,570,964 unrealized and $7,838,514 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.

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 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.

7

As at June 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 is led by an insurance company and has an initial size of $80 million with additional capacity to expand up to $150 million in total.             

All borrowings under the 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 .  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.  As at June 30, 2022, the Company had $75,883,970 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.

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

June 30, 2022
2022	$	19,158,643
2023		27,403,454
2024		29,321,873
2025		-
Thereafter		-
	$	75,883,970

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

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.

8

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 June 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.

As at June 30, 2022, the Company had drawn $17,000,000 under the credit facility (December 31, 2021 - $2,200,000), and for the three and six months ended June 30, 2022, incurred $138,070 and $495,834, respectively, of interest and finance expense related to the facility.  The borrowing base as at June 30, 2022 was $24,667,080 (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 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 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.

9

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 is $42.0 million in total size. DP4 is currently funding the drilling and completion of five wells, with the DP4 LPs funding 60% and Origination funding 40%. The DP4 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 DP4 (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of DP4 (along with IRR based Payout Units). IRR Based Payout Units will 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 will participate in 6% of the income of DP4, along with Flat Payout Units, which will participate in 20% of the income of DP4.  The DP4 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 DP4, maintains control of the DP4and consolidates 100% of the operations of the DP4.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments.  For the six months ended June 30, 2022, an increase in the DP4 liability of $12,003,751 was recorded related to the change in fair value of the liability, with a corresponding increase to finance expense. 

10

Refer to subsequent events section below for further details of DP4.

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 is $50.4 million in total size. Red Dawn 1 is currently funding the drilling and completion of five wells, with the Red Dawn 1 LPs funding 60% and Origination funding 40%. The Red Dawn 1 LPs can 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 will 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 will participate in 20% of the income of Red Dawn 1 (along with IRR based Payout Units). IRR Based Payout Units will 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 will participate in 6% of the income of Red Dawn 1, along with Flat Payout Units, which will participate in 20% of the income of Red Dawn 1.  The Red Dawn 1 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 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 six months ended June 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 second quarter of 2022, Origination formed DP5 with 25 limited partners (the "DP5 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which is $50.3 million in total size. DP5 is currently funding the drilling and completion of five 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 six months ended June 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.

During the six months ended June 30, 2022, the Company redeemed all of the LP units for $19,345,398, in connection with the ABS Facility.

For the three and six months ended June 30, 2022, the Company recorded finance expense related to the outstanding instrument in the amount of $139,293 and $658,047 (June 30, 2021 - $620,443 and $778,382)(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 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 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		-		-
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	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	-		1,114,430.000		-		-		4,633,897
Repurchase of SVS	12	-		(44,900.000	)	-		-		(282,178	)
MVS converted to SVS	12	-		158,686.000		(1,586.860	)	-		-
Balance at June 30, 2022		-		33,763,947.000		8,748.470		15,947.292	$	47,765,866

During the six months ended June 30, 2022, 1,114,430 SVS were issued as a result of settling certain restricted share units ("RSU").  Previously stock-based compensation of $4,633,897 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 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 June 2022, the Company purchased and cancelled 44,900 SVS at an average price of $6.28/share for an aggregate value of $282,178.

In January 2022, 1,586.860 MVS were converted into 158,686 SVS.

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.

13

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 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.

Income/(loss) per share:

		Six months ended June 30, 2022							Six months ended June 30, 2021
		Net Loss		Shares		Loss per share			Net Loss		Shares		Loss per share
Loss - basic	$	(2,075,148	)	33,947,937	$	(0.06	)	$	(32,978,534	)	15,514,266	$	(2.13	)
Diliutive effect of outstanding awards		-		-		-			-		-		-
Income - diluted	$	(2,075,148	)	33,947,937	$	(0.06	)	$	(32,978,534	)	15,514,266	$	(2.13	)
		Three months ended June 30, 2022							Three months ended June 30, 2021
		Net Income		Shares		Income per share			Net Loss		Shares		Loss per share
Income/(loss) - basic	$	6,873,817		34,084,148	$	0.20		$	(24,751,922	)	14,775,021	$	(1.68	)
Diliutive effect of outstanding awards		-		1,321,189		-			-		-		-
Income/(loss)  - diluted	$	6,873,817		35,405,337	$	0.19		$	(24,751,922	)	14,775,021	$	(1.68	)

The Company had share purchase options ("Options"), RSU's and deferred share units ("DSUs") outstanding for the three and six months ended June 30, 2022 (June 30, 2021 - none outstanding) (Note 15).  The effect of the conversion or exercise of Options, RSU's and DSU's (three months 1,321,189, six months 1,136,744) are included in the three months ended calculation of diluted income per share and excluded for the six months ended as they are anti-dilutive.  The Company used an average market price of $5.84 and $5.51 per share, respectively, to calculate the dilutive effect of stock options, RSUs and DSUs outstanding.

14

The Company's NCI interest, which can be freely converted SVS on a one for basis, would be anti-dilutive and therefore have not been included in the calculation of diluted loss per share (three months 17,746,901, six months 17,454,806).  There was no NCI interest for the same periods of 2021.

Normal Course Issuer Bid ("NCIB")

On June 6, 2022, the TSX Venture Exchange (“TSXV”) approved the Company to commence a NCIB to repurchase up to 1,648,783 SVS (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. 

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.

Through June 30, 2022, a total of 44,900 SVS were repurchased at an aggregate cost of $282,178 under the NCIB. All shares repurchased have been returned to treasury for cancellation.

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 six months ended June 30, 2022, with an aggregate distribution of $6,112,521.

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

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 amount to a 34.467% economic interest in Origination as at June 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 339,372 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. 

15

In January 2022, certain RSUs were settled and as a part of the tax receivable 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, $1,454,063 has been recorded as a decrease to non-controlling interest and a corresponding offset to capital reserve.

In January 2022, certain RSUs were settled 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 ($5.00/share), $1,406,250 has been recorded as a decrease to non-controlling interest and a corresponding offset to capital reserve.

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 June 2022, certain RSUs were settled 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 ($6.49/share), $5,407,338 has been recorded as a decrease to non-controlling interest and a corresponding offset to capital reserve.

During the first quarter of 2022, the Company declared and paid dividends to shareholders.  In connection with the dividend distributions from Origination, non-converting equity holders received their non-controlling interest share totalling $3,146,942, for the six months ended June 30, 2022, resulting in a decrease of non-controlling interest.

For the six months ended June 30, 2022, $975,842, was recorded to reduce net loss on the condensed interim consolidated statement of loss and comprehensive loss, with an offset to NCI, representing NCI share of net loss (2021 - $Nil).

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.

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.

16

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 six months ended June 30, 2022, the Company has been paid $250,000 and $500,000 in cash.

Related party balances

At June 30, 2022, the accounts payable included $53,716 (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 June 30, 2022, the Company had negative working capital of $165,427,098.  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 six months ended June 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 June 30, 2022:

17

		Carrying value		Contractual cash flow		Less than one year		1 - 3 years		Greater than 3 years
Accounts payable and accrued liabilities	$	56,990,432	$	56,990,432	$	56,990,432	$	-	$	-
Commodity contracts		14,684,908		14,684,908		12,451,328		1,414,660		818,920
Lease liability		462,792		482,057		129,594		352,463		-
Corporate credit facility		17,000,000		17,000,000		17,000,000		-		-
Development partnerships liabilities		94,923,358		94,923,358		94,923,358		-		-
Long term debt		73,522,333		75,883,970		34,835,900		41,048,070		-
Total	$	257,583,823	$	259,964,725	$	216,330,612	$	42,815,193	$	818,920

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 six months ended June 30, 2022, the Company generated a net loss and comprehensive loss before non-controlling interest of $3,050,990 (six months ended June 30, 2021 - $32,978,534), and as at that date, the Company had a working capital deficiency of $165,427,098 (December 31, 2021 - working capital deficiency of $80,838,833) and accumulated deficit of $89,501,774 (December 31, 2021 - $81,314,105).

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 six months ended June 30, 2022, the Company formed three development partnerships to fund a portion of 2022 capital activity which raised approximately $41.8 million and entry into a new debt facility, raising $80 million, which repaid existing debt and the asset backed preferred instrument.  Subsequent to June 30, 2022, the Company closed on one additional development partnership resulting in cash inflows of approximately $7.9 million. 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.

Subsequent Events

Dividends declared

On July 1, 2022, the Company's Board of Directors declared a dividend of $0.03 per SVS and $3.00 per MVS, for a total amount of $1,039,642, payable on July 29, 2022, to shareholders of record on the close of business on July 15, 2022.

On August 1, 2022, the Company's Board of Directors declared a dividend of $0.03 per SVS and $3.00 per MVS, for an estimated total amount of $1,039,642, payable on August 17, 2022, to shareholders of record on the close of business on August 31, 2022.

18

Completion of DP4 and creation of DP6

On July 15, 2022, the Company successfully completed the repayment and reversion of DP4 that it formed during the first quarter of 2022, along with the concurrent closing of its sixth development partnership ("DP6").

DP4 funded the drilling and completion of a total of five wells: three wells in the Giddings Field near Austin, TX and two wells in Webb County, TX; and comprised a total capital program of approximately $42 million, with 60% funded by external partners. As part of the completion of the DP4 program, Alpine has retired liabilities of approximately $34.5 million.

Nine of the DP4 partners exercised the put right provided to such partners by DP4 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 DP4 for 706,975 Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company), having a deemed value of US$5.85 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 $4.1 million.

DP6 has an expanded capital program of approximately $56.9 million, with approximately $34.2 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 June 30, 2022 appears below.

Quarter ended June 30, 2022

		2022					2021												2020
		Q2		Q1			Q4			Q3			Q2			Q1			Q4			Q3
Revenue from product sales		77,412,882		47,039,285			42,028,563			23,427,075			12,836,239			19,625,913			2,568,289			1,239,879
Net income (loss)		6,873,817		(8,948,965	)		21,943,230			(18,636,041	)		(24,751,922	)		(8,226,612	)		(3,007,192	)		123,065
Per unit - basic	$	0.20		(0.26	)	$	0.48		$	(0.42	)	$	(1.68	)	$	(0.53	)	$	(0.18	)	$	0.01
Net capital expenditures		(28,383,860	)	(42,274,114	)		(27,159,171	)		(26,909,107	)		(13,211,052	)		(5,151,463	)		(36,276,414	)		(1,901,004	)
Average daily production (Boe)		13,195		8,801			8,772			5,399			3,805			4,983			981			523
Working capital deficiency		(165,427,098	)	(151,923,864	)		(80,838,833	)		(80,891,770	)		(49,133,400	)		(24,142,999	)		(29,102,456	)		(9,512,412	)

Increased production and stable commodity prices from for the three months ended June 30, 2021, 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, 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.

19

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.

Due to reduced commodity prices, resulting from COVID-19, the Company shut in all wells during the three months ended June 30, 2020.

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 33,800,802, 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.

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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 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; 

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• 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;
• 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.

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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.

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

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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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