Alpine Summit Energy Partners, Inc.: Exhibit 99.3

EX-99.3 4 exhibit99-3.htm EXHIBIT 99.3 Alpine Summit Energy Partners, Inc.: Exhibit 99.3 - Filed by newsfilecorp.com

Introduction

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

Basis of Presentation

Financial data presented below has largely been derived from the Consolidated Financial Statements, which were prepared in accordance with International Financial Reporting Standards ("IFRS"). Accounting policies adopted by the Company are referred to in Note 3 to the 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 months ended March 31, 2021.

Operational and Financial Results

Overview

The Company is a United States energy developer and financial company focused on maximizing growth and return on equity. The Company is currently focusing its drilling activity in the Austin Chalk and Eagle Ford formations in the Giddings and Hawkville Fields, premier acreage locations which have produced substantial amounts of oil and gas for decades. The Austin Chalk directly overlies the oil- sourcing Eagle Ford formation. Oil and gas migrate into the chalk through microfractures which fill the tectonic fractures and porous matrix.

The Company plans to focus on developing its existing and adjacent footprint over the next several years while also evaluating additional development projects that fit its investment criteria. The Company's capital allocation strategy is designed to optimize return on capital and cash flow available for distribution to the Company's shareholders.

Q1 2022 Highlights

Maintained average gross production of approximately 9,891 Boe/day for the three months ended March 31, 2022 (Net 8,801 Boe/day) an increase of 3% quarter over quarter and 79% year over year.
Brought 6 new wells onto production during the first quarter of 2022.
Reported Adjusted EBITDA (defined below) of approximately $26.3 million for the three months ended March 31, 2022 (March 31, 2021 - $10.0 million). Net Loss before Non-Controlling Interest was approximately $12.3 million for the same period (March 31, 2021 - $8.2 million loss).
Successful repayment and reversion of the second development partnership ("DP2") that was formed during the third quarter of 2021, along with the concurrent closing of its fourth development partnership ("DP4").
Closed Alpine Red Dawn 1 ("Red Dawn 1") development partnership during the first quarter of 2022. Red Dawn 1 consists of $50.4 million of drilling capital and supports the addition of a third rig to the existing two rig drilling program.
Closed a new corporate credit facility (the "Corporate Facility") in March 2022 with a total size of $30 million. The 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%. As of March 31, 2022, approximately $12.9 million was drawn on the Corporate Facility.
Paid monthly dividend of $0.03 per SVS ($3.00 per MVS and $0.03 per PVS) during each month of the first quarter of 2022.

2022 Objectives

During the remainder of 2022, the Company plans on continuing to grow production through further development of its controlled acreage and additional farm-in locations. To that end, the Company has averaged in excess of 15,000 gross Boe/day since the start of the second quarter of 2022. The Company expects to continue to use the development partnership structure to facilitate drilling activity and plans on drilling 20 to 30 wells during 2022 in previously and newly leased acreage. The Company also expects to look for additional development areas to add to its drilling inventory and to opportunistically evaluate investments in other industries outside of oil and gas.

As previously announced, the Company is in the process of applying for a dual listing on the NASDAQ. Subject to meeting the initial listing standards and receiving all relevant approvals, the Company would hope to begin trading on the NASDAQ by the end of the third quarter of 2022.

Results of Operations

Production and Revenue

Average Daily Production (Net)

	Three Months to March 31, 2022	Three Months to March 31, 2021
Crude oil (Bbls/d)	4,193	2,166
Natural gas (Mcf/d)	14,797	10,767
NGLs (Bbls/d)	2,142	968
Total (Boe/d)	8,801	4,928
Crude oil weighting	47.6%	43.9%
Naural gas weighting	28.0%	36.4%
NGL weighting	24.3%	19.6%

Production increased for three months ended March 31, 2022, as compared to the comparative period of 2021 due to the addition of ten new wells through the final nine months of 2021, and six new wells through the three months ended March 31, 2022.

Revenue from Product Sales

		Three Months to March 31, 2022		Three Months to March 31, 2021
Crude oil	$	35,121,953	$	10,579,741
Natural gas		4,853,685		7,351,953
NGLs		7,063,647		1,694,219
Total	$	47,039,285	$	19,625,913
% of Total Revenue by Product Type
Crude oil weighting		74.67%		53.91%
Natural gas weighting		10.32%		37.46%
NGL weighting		15.02%		8.63%

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

Revenue from product sales increased for three months ended March 31, 2022, as compared to the comparative period 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

		Three Months to March 31, 2022		Three Months to March 31, 2021
Crude oil - Bbl	$	93.06	$	54.28
Natural gas - Mcf		3.64		7.59
NGL - Bbl		36.65		19.45
Per Boe	$	59.39	$	44.25

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

On a per-Boe basis, the Company's average realized price for the three months ended March 31, 2022, increased compared to the same period of 2021, due to strengthened worldwide commodity prices.

Royalties

		Three Months to March 31, 2022		Three Months to March 31, 2021
Charge for the period	$	13,021,970	$	5,334,036
Percentage of revenue from product sales		27.7%		19.8%
Per Boe	$	16.44	$	12.03

Royalties, as a percentage of revenue from product sales, increased in the three months ended March 31, 2022, compared to the same period 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.

Operating and Transportation Costs

		Three Months to March 31, 2022		Three Months to March 31, 2021
Charge for the period	$	4,558,876	$	1,750,148
Percentage of revenue from product sales		9.7%		27.3%
Per Boe	$	5.76	$	3.95

Total operating and transportation costs for the three months ended March 31, 2022, increased when compared to the same period of 2021 due to increased production noted above. The increase in total production and transportation costs per Boe is due to higher initial operating costs for wells brought online in 2022 and overall market increases for services.

Field Operating Netbacks

($/Boe)		Three Months to March 31, 2022			Three Months to March 31, 2021
Revenue from product sales	$	59.39		$	44.25
Royalties		(16.44	)		(12.03	)
Production costs		(5.76	)		(3.95	)
Field operating netback	$	37.19		$	28.27

General and Administrative Costs

		Three Months to March 31, 2022		Three Months to March 31, 2021
Charge for the period	$	3,142,214	$	2,487,329
Percentage of revenue from product sales		6.7%		10.6%
Per Boe	$	3.97	$	5.61

General and administrative costs for the three months ended March 31, 2022, increased as compared to the same period of 2021 primarily due to employee salaries and benefits, which began in the second half of 2021, which were previously compensated under a management service agreement. Offsetting the increase, was a reduction in professional, legal and advisory costs, which 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 to March 31, 2022		Three Months to March 31, 2021
Charge for the period	$	10,548,963	$	1,536,041
Per Boe	$	13.32	$	3.46

The increase in interest and financing costs for three months ended March 31, 2022, as compared to the same period of 2021 is mainly due to fair value changes associated with the development partnership liabilities $8,988,504 (March 31, 2021 - $Nil)(discussed below).

Depletion and Depreciation

		Three Months to March 31, 2022		Three Months to March 31, 2021
Charge for the period	$	4,598,976	$	3,854,000
Per Boe	$	5.81	$	8.69

Depletion expense increased for the three months ended March 31, 2022, as compared to the same period 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 Loss Attributable to Alpine Summit Shareholders

		Three Months to March 31, 2022			Three Months to March 31, 2021
Net Loss	$	(8,948,965	)	$	(8,226,612	)
Per basic and diluted unit	$	(0.26	)	$	(0.51	)

Investment and Financing

Long-term Debt

On December 22, 2020, the Company's subsidiaries including AIP Intermediate, LLC and AIP Borrower, LP (together "AIP Borrower") entered into the Goldman Facility (see subsequent events section below). All borrowings under the Goldman Facility are secured by AIP Borrower's oil and gas producing wells. The Goldman Facility carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) and a maturity date of December 22, 2031. Interest payments are required quarterly. As at March 31, 2022, the Company had $22,798,178 (December 31, 2021 - $25,237,408) drawn under the Goldman Facility (refer to subsequent event section below for additional information). AIP Borrower has certain financial covenants under the Goldman Facility, including:

maintain a ratio of total net debt to adjusted EBITDAX of no more than 3.5 to 1.0, whereby net debt is effectively defined as all indebtedness of AIP Borrower less certain cash balances held in control accounts in which the lender holds a security interest, and adjusted EBITDAX is effectively defined as income before interest, taxes, depletion, amortization, extraordinary gains and losses and other non-cash items annualized.
maintain an unrestricted cash balance and minimum interest reserve of no less than $1.8 million.
maintain a Measured Assets to Total Net Debt Ratio of at least 1.50 to 1.0, whereby Measured Assets is effectively defined as the present value of AIP Borrower's a) proved reserves, b) forward commodity contracts, c) abandonment liabilities related to proved producing reserves and

d) other fixed costs associated with the proved producing reserves all discounted at 10% and Total Net Debt is defined as outlined above.

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

As at the initial borrowing date, enter into certain forward commodity swap contracts included below and which it had been done.
Within 90 days of the initial borrowing date, enter into an interest rate swap contract to effectively fix the interest rate of at least 70% of the principal outstanding on the loan, at any given time for the term of the loan. AIP Borrower entered into these swaps during the year ended December 31, 2021.
No later than December 31, 2021, establish an interest reserve account that will hold a cash balance sufficient to cover nine months of scheduled interest payments which it has been completed.

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

2022		5,282,976
2023		4,564,814
2024		3,347,998
2025		2,892,873
Thereafter		6,709,517
	$	22,798,178

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

If the ratio of adjusted EBITDAX to scheduled loan principal and interest payments for the period is less than 1.50 to 1.00, AIP Borrower must make an additional principal prepayment equal to Net Income/(Loss) adjusted for all non cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement.
If AIP Borrower fails to meet its ratio (as defined above) of Measured Assets to total net debt of 1.50 to 1.00, AIP Borrower must make an additional principal prepayment sufficient to meet the 1.50:1.00 ratio.

The Company is required to meet certain financial covenants under the Goldman Facility. As at March 31, 2022, the Company was not in any breach of financial covenants in place and was not subject to any other additional principal prepayments. Refer to subsequent event section below.

Details of the Goldman Facility balances are as follows:

March 31, 2022		Current			Long-term			Total
Drawn balance	$	6,592,234		$	16,205,944		$	22,798,178
Borrowing costs		(604,850	)		(1,245,425	)		(1,850,275	)
Total	$	5,987,384		$	14,960,519		$	20,947,903

December 31, 2021		Current			Long-term			Total
Drawn balance	$	7,722,206		$	17,515,203		$	25,237,409
Borrowing costs		(662,372	)		(1,375,896	)		(2,038,268	)
Total	$	7,059,834		$	16,139,307		$	23,199,141

During the three months ended March 31, 2022, AIP Borrower recorded amortization of borrowing costs of $187,993 (March 31, 2021 - $321,742).

Corporate Credit Facility

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

During the first quarter of 2022, Origination closed a new Corporate Facility to replace the previous facility. The new Corporate Facility has a total size of $30 million. The Corporate 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 March 31, 2022, the Company had drawn $12,929,339 under the Corporate Facility (December 31, 2021 - $2,200,000), and incurred $39,506 of interest expense on outstanding borrowings. The borrowing base as at March 31, 2022 was $30,000,000 (December 31, 2021- $6,579,750).

Deferred tax

Prior to the RTO, Origination was not subject to U.S. income taxes, because, as a limited liability company classified as a partnership for U.S. federal income tax purposes, it was treated as a pass-through entity for income tax purposes, and the members of Origination were subject to income tax with respect to each such members’ allocable share of Origination’s taxable income. Subsequent to the RTO, while Origination remains classified as a partnership for U.S. federal income tax purposes, the Company is taxed as a United States corporation and is subject to U.S. federal income tax on its allocable share of pass-through taxable income from Origination, any tax balances related to the Company, together with those of the acquired entity, are therefore part of these consolidated financial statements. Any income attributable to Origination’s members outside the Company is not reflected in the Company’s consolidated statement of financial position and the consolidated statement of loss and comprehensive loss.

The income tax expense (benefit) for the first quarter of 2022 is computed based on our estimated annual effective tax rate for the full calendar year. Our estimated annual effect tax rate is 0% and when applied to pre-tax book income results in zero tax expense (benefit) being recorded for the quarter.

Capital Expenditures

In the three months ended March 31, 2022, the Company incurred capital expenditures on property, plant and equipment of $42,274,114 compared to $5,046,394 for the three months ended March 31, 2021. The majority of activity for these periods relates to the drilling of horizontal wells in the Giddings and Hawkville Fields.

During the three months ended March 31, 2022, the Company expended $3,335,373 (March 31, 2021 - $95,069) on related exploration and evaluation assets. Additions relate mainly to undeveloped lands and drilling costs without assigned reserves prior to their transfer to property, plant and equipment.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities include operating, royalty, general and administrative and capital costs payable. When appropriate, net payables in respect of cash calls issued to partners regarding capital projects and estimates of amounts owing but not yet invoiced to the Company are included in accounts payable. The level of accounts payable and accrued liabilities at March 31, 2022 corresponds to the Company's field capital expenditure program.

Decommissioning Liability

The Company's decommissioning liability of $2,611,061 represents the present value of estimated future costs to be incurred to plug, abandon and reclaim wells and facilities, drilled, constructed or purchased by the Company. The undiscounted and inflated amount of the liability at March 31, 2022 was approximately $1.7 million (December 31, 2021 - $1.3 million). The liability for all wells covered under this liability are expected to be incurred between 2025 and 2053.

Risk Management - Commodity Contracts

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

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 March 31, 2022, the Company had the following commodity contracts, with a total mark-to-market liability of $28,854,096 (December 31, 2021 - $20,381,180).

Commodity	Expiry	Type	Average Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	Apr 2022 - Dec 2023	Swap	$0.20	3,506,055	NGL-Mont Belvieu
Propane (gallons)	Apr 2022 - Dec 2023	Swap	$0.52	2,155,627	NGL-Mont Belvieu
Natural gas (gallons)	Apr 2022 - Dec 2023	Swap	$0.95	1,381,216	NGL-Mont Belvieu
Isobutane (gallons)	Apr 2022 - Dec 2023	Swap	$0.56	451,045	NGL-Mont Belvieu
Norbutane (gallons)	Apr 2022 - Dec 2023	Swap	$0.57	1,048,764	NGL-Mont Belvieu
Natural gas (mmbtu)	Apr 2022 - Dec 2028	Differential Swap	$0.07	2,215,364	Henry Hub -Nymex vs East TX
Natural gas (mmbtu)	Apr 2022 - Dec 2028	Swap	$2.61	2,131,914	Henry Hub -Nymex
Crude oil (bbl)	Apr 2022 - Dec 2028	Swap	$43.38	675,425	WTI-Nymex
Crude oil (bbl)	May - Jun 2022	Put	$40.00	70,000	WTI-Nymex
Crude oil (bbl)	Jun - Dec 2022	Put	$65.00	317,000	WTI-Nymex
Crude oil (bbl)	Jan - Mar 2023	Short	$68.78-94.55	200,000	WTI-Nymex
Natural gas (mmbtu)	Feb - Mar 2023	Short	$1.36-5.01	840,000	Nat Gas-Nymex

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

The unrealized loss for the three months ended March 31, 2022, of $13,815,573 and realized losses of $8,335,548 (March 31, 2021 - $9,181,887 unrealized and $3,709,084 realized loss) was a result of an increase in future strip prices from the date the commodity contracts were entered into and actual commodity prices during the period.

Development Partnerships

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

During the first quarter of 2021, Origination formed DP1 with 13 limited partners (the "DP1 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which was $21.8 million in total size. DP1 funded the drilling and completion of five wells, with the DP1 LPs funding 60% and Origination funding 40%. The DP1 LPs could choose to receive development partnership units ("DP1 Units") that distribute profits either based on a Flat payout option or an IRR based payout option. Flat Payout Units participate in 75% of the income of DP1 (along with IRR based Payout Units) until that income equals their invested capital and thereafter participate in 20% of the income of the DP1 (along with IRR based Payout Units). IRR Based Payout Units participate in 75% of the income of the First Development Partnership (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter participate in 6% of the income of DP1, along with Flat Payout Units, which participate in 20% of the income of DP1. DP1 LPs also had a put right to effectively sell their remaining interest for Subordinate Voting Shares or Multiple Voting Shares or cash, subject to the consent of Origination and certain other restrictions, for an amount calculated at the net future present values on oil and gas reserve estimates.

The Company, through the structure of the DP1, maintained control of the DP1 and consolidates 100% of the operations of the DP1.

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

One of the DP1 LPs exercised the put right provided to such partners by DP1 regarding residual interests in their associated investment and, elected to exchange the remaining interest in DP1 for 339,372 Class B non-voting units of Origination (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company), having a deemed value of $3.515 per unit, or a total of $1,192,893.

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

During the second quarter of 2021, Origination formed DP2 with 25 limited partners (the "DP2 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which is $35.2 million in total size. DP2 funded the drilling and completion of five wells, with DP2 LPs funding 60% and Origination funding 40%. DP2 LPs could choose to receive development partnership units ("DP Units") that distribute profits either based on a Flat payout option or an IRR based payout option. Flat Payout Units participate in 75% of the income of DP2 (along with IRR based Payout Units) until that income equals their invested capital and thereafter participate in 20% of the income of DP2 (along with IRR based Payout Units). IRR Based Payout Units participate in 75% of the income of DP2 (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter participate in 6% of the income of DP2, along with Flat Payout Units, which participate in 20% of the income of DP2. The DP2 LPs also had a put right to effectively sell their remaining interest for Subordinate Voting Shares or Multiple Voting Shares or cash, subject to the consent of Origination and certain other restrictions, for an amount calculated at the net future present values on oil and gas reserve estimates.

The Company, through the structure of the DP2, maintained control of the DP2 and consolidates 100% of the operations of the DP2.

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

In January 2022, the Company repaid and paid out the reversion of DP2. As part of the completion of the DP2 program, Alpine Summit retired liabilities of $23,511,818.

Ten of the DP2 LPs 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 826,023 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 $3.825 per unit, or a total of $3,159,695.

During the fourth quarter of 2021, Origination formed DP3 with 23 limited partners (the "DP3 LPs") and certain wholly-owned subsidiaries of Origination as limited partners and the general partner, which is $34.7 million in total size. DP3 is currently funding the drilling and completion of five wells, with the DP3 LPs funding 60% and Origination funding 40%. The DP3 LPs can choose to receive development partnership units ("DP Units") that distribute profits either based on a Flat payout option or an IRR based payout option. Flat Payout Units will participate in 75% of the income of DP3 (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of DP3 (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of DP3 (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of DP3, along with Flat Payout Units, which will participate in 20% of the income of DP3. The DP3 LPs will also have a put right to effectively sell their remaining interest for Subordinate Voting Shares or Multiple Voting Shares or cash, subject to the consent of Origination and certain other restrictions, for an amount calculated at the net future present values on oil and gas reserve estimates.

The Company, through the structure of the DP3, maintains control of the DP3 and consolidates 100% of the operations of the DP3.

The Company has categorized the DP3 liability as current based on the anticipated timing of repayments (refer to subsequent events section below).

During the first quarter of 2022, Origination formed DP4 with 33 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 DP4 and 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 three months ended March 31, 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.

As at March 31, 2022, $2,242,226 of funding from DP4 is recorded as accounts receivable and has been subsequently received.

During the first quarter of 2022, Origination formed development partnership Red Dawn 1 with 42 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 DP3 (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of 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 1 and consolidates 100% of the operations of Red Dawn 1.

As at March 31, 2022, $839,140 of funding from Red Dawn 1 is recorded as accounts receivable and has been subsequently received.

Shareholder Takeout and Asset Backed Preferred Instrument

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

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

During the three months ended March 31, 2022, the Company redeemed 3,063,582 LP units for $3,063,583 (March 31, 2021 - Nil). The Company has presented the entire liability as short-term in 2022, based on management estimates of cash flows available to redeem the LP Units in the coming twelve months (see subsequent events section below).

For the three months ended March 31, 2022, the Company recorded finance expense related to the outstanding instrument in the amount of $518,754 (March 31, 2021 - $208,877).

Subsequent to March 31, 2022, all outstanding amounts related to this liability were paid in full. Refer to subsequent event section below for additional information.

Shareholders' Capital

Authorized

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

Issued

		Origination Member Units		SVS	MVS		PVS		Amount
Balance at 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	11	(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	-		281,250.000	-		-		1,001,250
MVS converted to SVS	12	-		158,686.000	(1,586.860	)	-		-
Balance at March 31, 2022		-		32,975,667.000	8,748.470		15,947.292	$	44,415,397

During the three months ended March 31, 2022, 281,250 RSUs were settled and a corresponding issuance of SVS were issued (December 31, 2021 - Nil). As a result, $1,001,250 was added to Common Stock with a corresponding decrease to Contributed Surplus in the consolidated statements of changes in shareholders' equity/(deficiency).

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.

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 expenses of $1,301,692 and is presented in the consolidated statement of loss and comprehensive loss.

A full exchange of all non-voting units of Origination (refer to Non-Controlling Interest discussion below) and conversion of all MVS and PVS into SVS would result in approximately 50.1 million SVS outstanding as of December 31, 2021.

Loss per share:

		Three months ended March 31, 2022							Three months ended March 31, 2021
		Net Loss		Shares		Loss per Share			Net Loss		Shares		Loss per Share
Loss - basic	$	(8,948,965	)	33,810,211	$	(0.26	)	$	(8,226,612	)	16,217,363	$	(0.51	)
Diliutive effect of outstanding awards		-		-		-			-		-		-
Loss - diluted	$	(8,948,965	)	33,810,211	$	(0.26	)	$	(8,226,612	)	16,217,363	$	(0.51	)

The Company had share purchase options ("Options"), restricted share units ("RSUs") and deferred share units ("DSUs") outstanding for the three months ended March 31, 2022 (March 31, 2021 - none outstanding). The effect of the conversion or exercise of convertible promissory notes and NCI interest in would be anti-dilutive (15,470 dilutive shares) and therefore have not been included in the calculation of diluted loss per share. The Company used an average market price of $3.32 per share to calculate the dilutive effect of stock options, RSUs and DSUs outstanding.

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

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 three months ended March 31, 2022, with an aggregate distribution of $3,072,050.

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 33.855% economic interest in Origination as at March 31, 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.

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.

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 $1,527,572 resulting in a decrease of non-controlling interest.

For the first quarter of 2022, $3,324,013 was recorded to reduce net loss on the consolidated statement of operations and comprehensive loss, with an offset to NCI, representing NCI share of net loss for the three month period (March 31, 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.

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 months ended March 31, 2022, the Company has been paid $250,000 in cash.

Related party balances

At March 31, 2022, the accounts payable included $116,252 (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 the financial liabilities as they become due. The Company's financial liabilities consist of accounts payable and accrued liabilities and promissory notes, all of which are due within a year, commodity contract liabilities which will all be settled over the life of their contract terms (see below), lease liabilities which will be settled over the life of the lease, asset backed preferred instruments which will be repaid based on available cash flows, development partnership liabilities that will be repaid based on cash flows generated by the wells included in the partnership and a credit facility with portions due in the following year. The Company also maintains and monitors a certain level of cash flow which is used to partially finance all operating and capital expenditures. The Company also attempts to match its payment cycle with collection of oil and natural gas sales which are usually collected within 30 to 60 days.

At March 31, 2022, the Company had negative working capital of $151,923,864. 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 three months ended March 31, 2022: i) continued a drilling program designed/intended to increase cash flows from operating activities, ii) raised significant funds through two development partnerships, iii) entered into a new revolving corporate credit facility, and iv) refinanced a portion of indebtedness (see subsequent event section below).

The Company is required to meet certain financial covenants under the Goldman Facility. As at March 31, 2022, the Company was not in any breach of financial covenants in place.

The following table details the Company's financial liabilities and their scheduled maturities as at March 31, 2022:

		Carrying value		Contractual cash flow		Less than one year		1 - 3 years		Greater than 3 years
Accounts payable and accrued liabilities	$	56,832,319	$	56,832,319	$	56,832,319	$	-	$	-
Commodity contracts		28,854,096		28,854,096		12,823,054		11,755,023		4,276,019
Lease liability		493,935		485,975		78,745		407,230		-
Asset backed preferred instrument		-		18,687,351		18,687,351		-		-
Development partnerships liabilities		88,382,731		88,382,731		88,382,731		-		-
Long-term debt		20,947,903		22,798,178		5,282,976		10,805,685		6,709,517
Total	$	195,510,984	$	216,040,650	$	182,087,176	$	22,967,938	$	10,985,536

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 three months ended March 31, 2022, the Company generated a net loss and comprehensive loss of $8,948,965 (three months ended March 31, 2021 - $8,226,612), and as at that date, the Company had a working capital deficiency of $151,923,864 (December 31, 2021 - working capital deficiency of $80,838,833) and accumulated deficit of $93,335,120 (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 three months ended March 31, 2022, the Company formed two development partnerships to fund a portion of 2022 capital activity which raised approximately $37.9 million of external capital during the three months ended March 31, 2022. Subsequent to March 31, 2022, the Company closed on one additional development partnerships resulting in cash inflows of approximately $6.5 million, and also entered into a new credit facility to refinance the Company's balance sheet. The Company also repaid $2.4 million of long-term debt and $3.1 million of asset backed preferred instruments. Although the Company has been successful in its financing activities to date, additional financing may be required to continue operations and such funding may not be available on terms that are acceptable to the Company.

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

Subsequent Events

New Securitized Financing

On May 2, 2022, the Company announced the successful closing of an asset backed securitization of certain producing oil and gas wells (the "Facility"). The Facility is being led by an insurance company and has an initial size of $80 million with additional capacity to expand up to $150 million in total. The Facility is secured by working interests in a subset of the Company's producing assets, which are held by an affiliate of its operating subsidiary, HB2 Origination, LLC, and charges interest at 7.00%.

In connection with the closing of the Facility, the Company fully repaid the outstanding long-term debt (“Goldman Facility”) and the Asset Backed Preferred Instrument.

Completion of DP3 and creation of DP5

On April 27, 2022, the Company successfully completed the repayment and reversion of DP3 that it formed during the fourth quarter of 2021, along with the concurrent closing of DP5.

DP3 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 $35.3 million, with 60% funded by external limited partners. As part of the completion of the DP3 program, the Company has retired liabilities of approximately $30.2 million.

Twelve of the DP3 partners exercised the put right provided to such partners by DP3 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 DP3 for 894,929 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 $5.70 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 $5.1 million.

Dividends declared

On April 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 $1,015,994, payable on April 29, 2022, to shareholders of record at the close of business on April 14, 2022.

On May 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 $1,015,994, payable on May 31, 2022, to shareholders of record at the close of business on May 17, 2022.

Quarterly Results

Summarized information by quarter for the previous two years ended March 31, 2022 appears below.

Quarter ended March 31, 2022

		2022			2021												2020
		Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Revenue from product sales		47,039,285			42,028,563			23,427,075			12,836,239			19,625,913			2,568,289			1,239,879			40
Net income (loss)		(8,948,965	)		21,943,230			(18,636,041	)		(24,751,922	)		(8,226,612	)		(3,007,192	)		123,065			(4,664,592	)
Per unit - basic and diluted	$	(0.26	)	$	0.48		$	(0.42	)	$	(1.68	)	$	(0.51	)	$	(0.18	)	$	0.01		$	(0.27	)
Net capital expenditures		(42,274,114	)		(27,159,171	)		(26,909,107	)		(13,211,052	)		(5,046,394	)		(36,276,414	)		(1,901,004	)		(2,596,577	)
Average daily production (Boe)		8,801			8,772			5,399			3,805			4,928			981			523			-
Working capital deficiency		(151,923,864	)		(80,838,832	)		(80,891,770	)		(49,133,400	)		(24,142,999	)		(29,102,456	)		(9,512,412	)		(10,313,550	)

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.

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 32,975,667, 8,748.47, 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, market and business conditions including commodity prices, interest rates and currency exchange;
changes in supply and demand for the Company's products;
a global public health crisis including the recent outbreak of the novel coronavirus (COVID-19) which causes volatility and disruptions in the supply, demand and pricing for natural gas, crude oil and NGL, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people;

the ability to obtain regulatory, stakeholder and third-party approvals and satisfy any associated conditions that are not within the Company's control for exploration and development activities and projects;
the ability of the Company to obtain TSXV approval of the NCIB
successful and timely implementation of capital expenditures;
risks associated with the development and execution of major project;
risk that projects and opportunities intended to grow funds flow and/or reduce costs may not achieve the expected results in the time anticipated or at all;
access to third-party pipelines and facilities and access to sales markets;
volatility of commodity prices and the related effects of changing price differentials;
the Company's ability to operate and access to facilities to meet forecast production;
the ability of the Company to pay dividends to its shareholders;
the timing of repayments in respect of the various development partnerships;
the Company's ability to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans/notes, asset sales, coordinating payment and revenue cycles each month, and an active commodity hedge program to mitigate commodity price risk and secure cash flows;
the stability of royalty rates in future periods;
operational risks and uncertainties associated with crude oil and gas activities including unexpected formations or pressures, reservoir performance, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of natural gas and wellbore fluids, pollution and other environmental risks;
changes in costs including production, royalty, transportation, general and administrative, and finance;
ability to finance planned activities including infrastructure expansions which are required to meet future growth targets;
adverse weather conditions which could disrupt production and affect drilling and completions resulting in increased costs and/or delay adding production;
actions by government authorities including changes to taxes, fees, royalties, duties and government imposed compliance costs;
changes to laws and government policies including environmental (and climate change), royalty, and tax laws and policies;
counter-party risk with third parties to perform their obligations with whom the Company has material relationships;
unplanned facility maintenance or outages or unavailability of third-party infrastructure which could reduce production or prevent the transportation of products to processing plants and sales markets;
a major outage or environmental incident or unexpected event such as fires (including forest fires), hurricanes or equipment failures or similar events that would affect the Company's facilities or third-party infrastructure used by the Company;
environmental risks (including climate change) and the cost of compliance with current and future environmental laws, including climate change laws along with risks relating to increased activism and opposition to fossil fuels;
ability to access capital from internal and external sources (including the corporate credit facility);
the risk that competing business objectives may exceed the Company's capacity to adapt and implement change;

the potential for security breaches of the Company's information technology systems by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches;
risks with transactions including closing an asset or property acquisition or disposition and the failure to realize anticipated benefits from any transaction;
finding new crude oil and gas reserves that can be developed economically to replace reserves depleted by production;
the accuracy of estimating reserves and future production and the future value of reserves;
risk associated with commodity price hedging activities using derivatives and other financial instruments;
maintaining debt levels at a reasonable multiple of funds flow;
risk that the Company may be subject to litigation;
the accuracy of cost estimates, some of which are provided at an early stage and before detailed engineering has been completed;
risk associated with partner or joint arrangements to which the Company is a party;
inability to secure labour, services or equipment on a timely basis or on favourable terms;
increased competition from other industry participants for, among other things, capital, acquisitions of assets or undeveloped lands, and skilled personnel; and
increased competition from companies that provide alternative sources of energy.

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

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

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

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

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

Field Operating Netbacks

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

Adjusted EBITDA

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

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

Business Risks

There are a number of risks facing participants in the crude oil and natural gas industry. Some risks are common to all businesses while others are specific to the industry. The 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.