Form 6-K ALPINE SUMMIT ENERGY For: Sep 30

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of November, 2021.

Commission File Number: 000-56354

Alpine Summit Energy Partners, Inc.
(Exact Name of Registrant as Specified in Charter)

2200 HSBC Building

885 West Georgia Street

Vancouver, BC V6C 3E8
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F  ☐  Form 40-F ⊠

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ____

Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ____

Note: Regulation S-T Rule 101(b)(7) only permits the submission in paper of a Form 6-K if submitted to furnish a report or other document that the registrant foreign private issuer must furnish and make public under the laws of the jurisdiction in which the registrant is incorporated, domiciled or legally organized (the registrant's "home country"), or under the rules of the home country exchange on which the registrant's securities are traded, as long as the report or other document is not a press release, is not required to be and has not been distributed to the registrant's security holders, and, if discussing a material event, has already been the subject of a Form 6-K submission or other Commission filing on EDGAR.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		ALPINE SUMMIT ENERGY PARTNERS, INC.
		(Registrant)
Date:	November 23, 2021	By:	/s/ Darren Moulds
		Name:	Darren Moulds
		Title:	Chief Financial Officer

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EXHIBIT INDEX

99.1	News Release dated November 23, 2021
99.2	Financial Statements for the three and nine months ended September 30, 2021 (unaudited and not reviewed)
99.3	Management's Discussion and Analysis for the September 30, 2021 financial statements
99.4	Form 52-109FV2, Certification of Interim Filings (CEO)
99.5	Form 52-109FV2, Certification of Interim Filings (CFO)

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ALPINE SUMMIT ENERGY PARTNERS ANNOUNCES THIRD QUARTER 2021
FINANCIAL AND OPERATING RESULTS AND INITIATION OF CAPITAL RETURN
PROGRAM

Nashville, Tennessee and Vancouver, British Columbia - November 23, 2021 (Newsfile Corp.) - Alpine Summit Energy Partners, Inc. ("Alpine Summit" or the "Company") (TSXV: ALPS.U) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2021.  Alpine Summit's unaudited interim financial statements and notes, as well as Management's Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2021 will be available at "www.sedar.com" and "www.sec.gov/edgar", as well as on our website at "www.alpinesummitenergy.com".

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

Craig Perry, Chief Executive Officer, remarked "In light of the strength of our drilling results, operational momentum and access to development capital, our Board has approved the initiation of a monthly dividend and pursuit of a buyback program as the first stage of the shareholder capital return program for 2022.  We believe the unique combination of rapid growth, deleveraging and return of capital are enabled by the strong commodity price environment and our capital velocity business model.  Additionally, we believe the market price of our stock does not reflect the underlying value, which is the impetus for initiating the NCIB."

Third Quarter 2021 Financial and Operating Highlights:

● Average gross production of ~5,400 BOE/day during the quarter

● Adj. EBITDA¹  of US$12.0 million for the quarter and Adj. EBITDA US$29.5 million for the YTD period

● Significant addition of attractive drilling locations

● Completion of Holbrook leasing activity

● Completion of RTO and listing on the TSXV and pursuit of NASDAQ Listing

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Third Quarter Review & Outlook

During the quarter, the Company had continuous rig activity in the Giddings Field.  Historically, the Company's wells in that area are modern horizontal wells with high intensity slick-water fracs and average completed lateral lengths of over 5,000 feet.  In today's environment, the well level economics are significantly in excess of the Company's return hurdles.  During the quarter, all new wells from the first development partnership ("DP1") were on production, with the last to come online during August.  Only one of the wells from the second development partnership ("DP2") contributed to production beginning in September.

Building upon the momentum generated through the Company's development partnerships, favorable inventory locations, and the strong commodity price environment, the Company anticipates continued growth in production and financial results for the fourth quarter 2021 and for the fiscal year 2022.  Alpine Summit expects production in the fourth quarter of 2021 to average ~8,300 BOE/d, an increase of ~50% compared to the third quarter 2021.  The majority of this incremental production is unhedged.

The Company reaffirms its guidance of US$110 million of EBITDA²  in 2022 and average production of 13,500 gross BOE/day, expecting production to increase by ~2,000 gross BOE/d quarterly in 2022.  The Company's production mix is expected to be ~60% liquids (Oil & NGLs) and ~40% natural gas. The Company believes it could maintain its 2022 production and EBITDA profile with US$30 million to US$50 million of annual capital spending in a flat US$60 WTI and US$3.50/MCF gas price environment.

Development Partnerships

Since the beginning of 2021, Alpine Summit has funded a significant portion of its development activity through its development partnerships. The development partnerships are jointly capitalized by Alpine Summit and external partners to develop discrete packages of wells (typically 5+ locations). During the third quarter of 2021, DP1, which was launched in March of 2021, was successfully repaid. DP2 was launched in July and generated a small contribution to third quarter 2021 results.  All production for DP2 is expected to be brought online by the end of the fourth quarter 2021. The third development partnership ("DP3") development activity is underway with initial production expected during the first quarter of 2022.

Hedging Activity

During 2020 and 2021, the global pandemic and other factors contributed to significant disruption in commodity prices and access to credit for the oil and gas industry.  In order to secure financing, the Company may enter into hedges as required by lenders and other counterparties.  In general, as part of managing its normal course financial obligations and meeting lender requirements, the Company would expect to hedge approximately 25-50% of its estimated forward 12-month production on a rolling basis. However, during the nine-month period ended September 30, 2021, the Company estimates that approximately 85% of its production was hedged at an average price of US$43.38/WTI and US$2.61/MMCF.  This outsized hedging activity relates principally to obligations associated with amortizing its first lien credit facility (the "Facility"), which was established in December 2020 in connection with the buyout of legacy partners.  The Facility has a balance of US$28.1 million and associated remaining hedging obligations of US$24.0 million as of September 30, 2021, which amortize over the remaining six years of the Facility's life.

_______________________________
² EBITDA is a non-IFRS Financial Performance Measure. Please refer to the "Non-IFRS Financial Performance Measures" at the end of this news release for further information and a reconciliation to the nearest IFRS measure.

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Longer dated hedging contracts established in December 2020, as a percent of total production, will reduce significantly over the remainder of the Facility's term. For the quarter ending December 31, 2021, it is expected that ~30% of total oil production is hedged at US$52.60 WTI/bbl and 36% of its natural gas production is hedged at US$2.77/MMCF.  For 2022, the Company estimates that ~15% of its oil production and ~10% of its natural gas production will be hedged at average prices of US$54.70/WTI and US$3.31/MMCF. 

Continued Deleveraging

Since the beginning of 2021, the Company has retired total liabilities of US$39.4 million on a consolidated basis, consisting of US$5.3 million in notes, US$4.7 million in preferred stock, US$15.1 million in first lien obligations and US$14.3 million in hedging obligations. 

The Company anticipates retiring the balance of its asset backed preferred instrument during the course of 2022 in addition to the continued amortization of its existing first lien facility and associated hedging obligations.

Additional Business Activities

Helium is a scarce, inert gas that is central to many technologies.  Global demand for helium has continued to grow, while new supply has been limited.  The Company believes there is an opportunity to develop additional helium assets at compelling returns from known basins in North America, including Arizona.

Alpine Summit's experience as a developer positions it to explore this opportunity. During the third quarter of 2021, the Company completed a leasing program in and around the Holbrook Basin of Arizona, securing 71,000 Net Mineral Acres. 

The Holbrook Basin is well known for its rich helium content which other operators have recently demonstrated.  The Company intends to run a small scale exploration program during 2022 with a budget of ~US$3.0 million.  There can be no assurances regarding the future outcome or viability of the exploratory activity.

NASDAQ Listing

As previously announced, the Company is in the process of applying for a dual listing on the NASDAQ exchange, and will continue to pursue its NASDAQ application during 2022.

Non-IFRS Financial Performance Measures

Non-GAAP Financial Performance Measures included in this news press release are references to the term "Adjusted EBITDA" and "EBITDA". Management believes these measures are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil and natural gas companies. These terms do not have any standardized meaning prescribed by IFRS and should not be considered an alternative to, or more meaningful than "profit (loss) before taxes", "profit (loss) and comprehensive income (loss)" or assets and liabilities as determined in accordance with IFRS as a measure of the Company's performance and financial position.

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Adjusted EBITDA Reconciliation

Management uses a non-IFRS metric of Adjusted EBITDA to track performance of the Company.  This measure includes the addition of hedging losses as well as other items which the Company views as "one-time" in nature in order to track the performance of the core business.  For the three months and year to date periods ended September 30, 2021, the Company generated US$12.0 million and US$29.5 million of Adjusted EBITDA, respectively, as shown below.

EBITDA Reconciliation	3 Months Ended Sept. 30, 2021	9 Months Ended Sept. 30, 2021
Net Income	$ (15,074,398)	$ (48,052,933)
(+) Depletion Expense	3,769,510	10,475,937
(+) Non-Consolidated Interest	(4,252,100)	(4,252,100)
(+) Interest Expense	10,991,673	16,751,963
(+) Non-Cash Stock Based Compensation	0	9,073,228
(+) Non-Cash Bonus Accrual	634,500	3,077,095
(+) Listing & Formations and Related Expenses	1,985,697	3,020,371
(+) Hedging Expenses	13,973,410	39,382,889
Adjusted EBITDA	$12,028,292	$29,476,450

About Alpine Summit Energy Partners, Inc.

Alpine Summit is a U.S. based company that operates and develops oil and gas assets. For additional information on the Company, please visit www.alpinesummitenergy.com.

Further Information

For further information, please contact:

Chris Nilan, Senior Managing Director

Phone: 615.475.8320

Email: [email protected]

Darren Moulds, Chief Financial Officer

Phone:  403.390.9260

Email: [email protected]

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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Forward-Looking Information and Statements

This news release contains certain "forward-looking information" within the meaning of applicable Canadian securities legislation and may also contain statements that may constitute "forward-looking statements" within the meaning of the safe harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Such forward-looking information and forward-looking statements are not representative of historical facts or information or current condition, but instead represent only Alpine Summit's beliefs regarding future events, plans or objectives, many of which, by their nature, are inherently uncertain and outside of Alpine Summit's control. Generally, such forward-looking information or forward-looking statements can be identified by the use of forward-looking terminology such as "plans", "expects", "is expected", "budget", "scheduled", "estimates", "forecasts", "intends", "anticipates", "believes", or the negative or variations of such words and phrases or may contain statements that certain actions, events or results "may", "could", "would", "might" or "will be taken", "will continue", "will occur" or "will be achieved". The forward-looking information and forward-looking statements contained herein may include, but are not limited to, statements regarding monthly dividends and implementation of the NCIB, growth in production, as well as production and financial results in the fourth quarter of 2021 and 2022, guidance and production mix for 2022, the production timing for DP2, initial production timing for DP3, future hedging activities, additional deleveraging activities, results of the Company's helium exploration initiative and the NASDAQ listing.

By identifying such information and statements in this manner, Alpine Summit is alerting the reader that such information and statements are subject to known and unknown risks, uncertainties and other factors that may cause the actual results, level of activity, performance or achievements of Alpine Summit to be materially different from those expressed or implied by such information and statements. In addition, in connection with the forward-looking information and forward-looking statements contained in this news release, Alpine Summit has made certain assumptions. Among the key factors that could cause actual results to differ materially from those projected in the forward-looking information and statements are the following: the impact of the RTO and the potential listing on NASDAQ on relationships, including with regulatory bodies, employees, suppliers, contractors and competitors, as well as the potential for Alpine Summit to fail to either meet the NASDAQ listing standards or ultimately be approved for listing by the NASDAQ; changes in general economic, business and political conditions, including changes in the financial markets; changes in applicable laws; and compliance with extensive government regulation. Should one or more of these risks, uncertainties or other factors materialize, or should assumptions underlying the forward-looking information or statements prove incorrect, actual results may vary materially from those described herein as intended, planned, anticipated, believed, estimated or expected. Although Alpine Summit believes that the assumptions and factors used in preparing, and the expectations contained in, the forward-looking information and statements are reasonable, undue reliance should not be placed on such information and statements, and no assurance or guarantee can be given that such forward-looking information and statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such information and statements. The forward-looking information and forward-looking statements contained in this news release are made as of the date of this news release, and Alpine Summit does not undertake to update any forward-looking information and/or forward-looking statements that are contained or referenced herein, except in accordance with applicable securities laws.

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Alpine Summit Energy Partners, Inc.

(formerly Red Pine Petroleum Ltd.)

Interim Consolidated Financial Statements

For the three and nine months ended September 30, 2021 and 2020

(Unaudited)

 

 

 

 

 

 

 

 

Notice to Reader

The accompanying unaudited interim consolidated financial statement of Alpine Energy Summit Partners. Inc. (the
"Company") have been prepared by and are the responsibility of management. The unaudited interim consolidated financial
statements have not been reviewed by the Company's auditors.

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Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statements of Financial Position
(unaudited)(amounts in US dollars)
As at

			September 30, 2021			December 31, 2020
	Notes
ASSETS
Current assets
Cash		$	10,017,259		$	2,889,558
Accounts receivable			12,759,868			6,121,963
Prepaid expenses			235,503			25,411
			23,012,630			9,036,932
Non-current assets
Right-of-use-assets			442,810			-
Exploration and evaluation assets	5		9,986,061			1,243,615
Property, plant and equipment	6		85,594,986			55,662,329
Total assets		$	119,036,487		$	65,942,876
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities		$	36,087,969		$	12,507,116
Current lease obligations			78,745			-
Current portion of long-term debt	9		8,465,063			17,048,509
Development partnership 1 liabilities	7		15,288,594			-
Development partnership 2 liabilities	8		29,124,221			-
Promissory notes	10		150,000			5,425,000
Commodity contracts	22(c)		14,709,808			3,158,763
			103,904,400			38,139,388
Non-current liabilities
Long-term debt	9		17,446,311			23,213,961
Asset backed preferred instrument	12		18,140,975			-
Commodity contracts	22(c)		14,917,524			1,362,620
Long-term lease obligations			407,230			-
Deferred tax liability	19		2,398,924			-
Decommissioning liabilities	11		1,275,042			864,000
			54,586,006			25,440,581
Total liabilities			158,490,406			63,579,969
SHAREHOLDERS' EQUITY (DEFICIENCY)						37,097,376
Share capital	13		43,414,147
Capital reserve	15		34,459,432			5,023,375
Accumulated deficit			(103,257,335	)		(39,757,844	)
Equity/(deficiency) attributable to Alpine						2,362,907
Summit Energy Partners, Inc. Shareholders			(25,383,756	)
Non controlling interest	14		(14,070,163	)		-
Total shareholders' equity/(deficiency)			(39,453,919	)		2,362,907
Total liabilities and Shareholders' equity		$	119,036,487		$	65,942,876

Going concern (Note 3(b))
Subsequent events (Note 23)
Approved by the Board:

"signed" Craig Perry	"signed" Stephen Schaefer
Director	Director

 

See accompanying notes to the interim consolidated financial statements.

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Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statements of Loss and Comprehensive Loss

For the three and nine months ended September 30, 2021 and 2020
(unaudited)(amounts in US dollars)

				Three months			Three months			Nine months			Nine months
				ended			ended September			ended			ended September
				September 30,			30,			September 30,			30,
				2021			2020			2021			2020
	Notes
Revenue
Revenue from petroleum and natural gas sales	17		$	23,427,075		$	1,239,879		$	55,889,227		$	1,867,790
Royalties				(6,689,789	)		(342,631	)		(15,611,640	)		(582,630	)
				16,737,286			897,248			40,277,587			1,285,160
Unrealized losses on derivative commodity contracts	22(c)			(7,534,986	)		-			(25,105,949	)		-
Realized losses on derivative commodity contracts	22(c)			(6,438,425	)		(3,344	)		(14,276,940	)		(412,523	)
Total revenue/(deficiency), net of royalties and derivative commodity contracts			$	2,763,875		$	893,904		$	894,698		$	872,637
Expenses
Operating and transportation				3,018,084			373,591			6,598,663			495,192
General and administrative				1,661,449			186,248			7,650,282			1,351,908
Listing expense	2			1,301,692			-			1,301,692			-
Transaction costs	2			1,567,967			-			1,567,967			-
Stock-based compensation	13			-			-			9,073,228			-
Impairment loss of exploration and evaluation assets				-			-			-			3,121,873
Depletion and depreciation expense	6			3,815,509			210,000			10,521,936			262,000
Finance income and expense (net)	18			10,991,673			1,000			16,751,963			65,185
Total expenses				22,356,374			770,839			53,465,731			5,296,158
Income/(Loss) before taxes and non-controlling interest:			$	(19,592,499	)	$	123,065		$	(52,571,033	)	$	(4,423,521	)
Deferred taxes	19			(2,398,924	)		-			(2,398,924	)		-
Net income/(loss) and comprehensive loss for the period before non-controlling interest			$	(21,991,423	)	$	123,065		$	(54,969,957	)	$	(4,423,521	)
Net income/(loss) and comprehensive loss attributable to non- controlling interest			$	(3,355,382	)	$	-		$	(3,355,382	)	$	-
Net income/(loss) and comprehensive loss for the period attributable to Alpine Summit Energy Inc. Shareholders			$	(18,636,041	)	$	123,065		$	(51,614,575	)	$	(4,423,521	)
Income/(loss) per share attributable to Alpine Shareholders
Income/(Loss) and comprehensive loss per share - basic and diluted	13		$	(0.42	)	$	0.00		$	(1.13	)	$	(0.08	)

See accompanying notes to the interim consolidated financial statements.

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Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statement of Changes in Shareholders' Equity/(Deficiency)
(amounts in US dollars)
(Unaudited)

			HB2 Member			SVS Shares			MVS Shares			PVS Shares												Non-controlling			Total shareholders'
	Note		Units			Number			Number			Number			Share Capital			Capital Reserve			Accumulated deficit			interest			equity/(deficiency)
Opening Balance January 1, 2020			17,083,501			-			-			-			$37,097,376			$430,734			$(32,227,666	)		$-			$5,300,444
Affiliate contribution			-			-			-			-			-			4,592,641			-			-			4,592,641
Net loss and comprehensive loss for the period			-			-			-			-			-			-			(4,423,521	)		-			(4,423,521	)
Ending Balance September 30, 2020			17,083,501			-			-			-			$37,097,376			$5,023,375			$(36,651,187	)		$-			$5,469,564
Ending Balance January 1, 2021			17,083,501			-			-			-			$37,097,376			$5,023,375			$(39,757,844	)		$-			$2,362,907
Issuance of member units for cash	13		819,215			-			-			-			8,044,700			-			-			-			8,044,700
Issuance of member units exchanged for promissory notes	13		353,870			-			-			-			3,475,000			-			-			-			3,475,000
Issuance of member units for exploration and evaluation assets	13		356,415			-			-			-			3,499,995			-			-			-			3,499,995
Issuance of member units to contractors	13		923,954			-			-			-			9,073,228			-			-			-			9,073,228
Redemption of member units	12, 13		(3,992,629	)		-			-			-			(8,680,786	)		-			(11,884,916	)		-			(20,565,702	)
Allocation of opening non-controlling interest	14		(16,168,422	)		-			-			-			(18,721,276	)		29,436,057			-			(10,714,781	)		-
Issuance of member units exchanged for promissory notes	13		234,216			-			-			-			2,300,000			-			-			-			2,300,000
Origination Unit split 1:3	2		31,557,084			-			-			-			-			-			-			-			-
Shares issued for cash, net of share issuance costs of $247,218	13		-			161,976			17,057.000			-			5,499,832			-			-			-			5,499,832
Exchange of units for SVS and MVS	13		(31,167,204	)		1,427,421			297,397.830			-			-			-			-			-			-
Proportiante Voting Shares issued for cash	2		-			-			-			15,947.292			128,213			-			-			-			128,213
Shares issued on business acquisition	2		-			534,384			-			-			1,697,865			-			-			-			1,697,865
Net loss and comprehensive loss for the period			-			-			-			-			-			-			(51,614,575	)		(3,355,382	)		(54,969,957	)
Ending Balance September 30, 2021			-			2,123,781			314,454.830			15,947.292			$43,414,147			$34,459,432			$(103,257,335	)		$(14,070,163	)		$(39,453,919	)

See accompanying notes to the interim consolidated financial statements.

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Alpine Summit Energy Partners Inc. (formerly Red Pine Petroleum Ltd.)
Interim Consolidated Statements of Cash Flows

For the three and nine months ended September 30, 2021 and 2020
(unaudited)(amounts in US dollars)

			Three months ended September 30,						Nine months ended September 30,
	Note		2021			2020			2021			2020
Operating Activities
Net income/(loss)loss for the period before non- controlling interest		$	(21,991,423	)	$	123,065		$	(54,969,957	)	$	(4,423,521	)
Items not affecting cash:
Depletion and depreciation expense	6		3,815,509			210,000			10,521,936			262,000
Stock based compensation			-			-			9,073,228			-
Deferred taxes	19		2,398,924			-			2,398,924			-
Listing expense	2		1,301,692			-			1,301,692			-
Accretion expense			4,613			1,000			13,556			3,000
Interest on lease liability			3,927			-			5,229			-
Amortization of debt issuance costs	9		236,961			-			833,260			-
Asset back preferred instrument interest	12		532,593			-			1,310,975			-
Fair value change on development partnership	7, 8		9,638,401			-			12,310,373			-
Impairment of exploration and evaluation assets			-			-			-			3,121,873
Unrealized loss on commodity contracts	22(c)		7,534,985			-			25,105,949			-
Net change in non-cash working capital	20		(13,450,912	)		(3,198,607	)		(9,095,806	)		(1,612,706	)
Cash flows from/(used in) in operating activities			(9,974,730	)		(2,864,542	)		(1,190,641	)		(2,649,354	)
Investing Activities
Expenditures on property, plant and equipment	6		(23,614,898	)		(562,636	)		(38,498,017	)		(5,402,416	)
Expenditures of exploration and evaluation assets	5		(3,294,209	)		(71,617	)		(6,763,605	)		(262,749	)
Net change in non cash working capital	20		16,062,271			3,567,952			25,828,660			7,449,929
Cash flows used in investing activities			(10,846,836	)		2,933,699			(19,432,962	)		1,784,764
Financing Activities
Issuance of shares for cash, net of issuance costs	13		5,628,045			-			13,672,745			-
Cash acquired on acquisition	2		396,173			-			396,173			-
Proceeds from development partnerships	7, 8		4,023,733			-			33,955,569			-
Repayment of development partnerships	7, 8		(1,853,127	)					(1,853,127	)
Repayment of promissory notes	10		-			-			(1,875,000	)		-
Proceeds from promissory notes	10		-			-			3,375,000			-
Repayment of long-term debt	9		(3,767,189	)		-			(15,184,356	)		-
Repayment of asset backed preferred instruments	12		-			-			(4,735,700	)		-
Net change in non-cash working capital	19		2,881,549			-			-			-
Cash flows from financing activities			7,309,184			-			27,751,304			-
Increase/(decrease) in cash			(13,512,382	)		69,157			7,127,701			(864,590	)
Cash, beginning of period			23,529,641			8,832,968			2,889,558			9,766,715
Cash, end of period		$	10,017,259		$	8,902,125		$	10,017,259		$	8,902,125

See accompanying notes to the interim consolidated financial statements.

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1. General business description

Alpine Summit Energy Partners, Inc. (formerly Red Pine Petroleum Ltd. ("Red Pine") (the "Company" or "Alpine") was incorporated on July 30, 2008 under the Business Corporations Act (British Columbia) ("BCBCA"). On April 8, 2021, the Company entered into a Business Combination Agreement ("BCA") pursuant to which the Company agreed to complete the BCA with HB2 Origination LLC ("Origination") and change its name to "Alpine Summit Energy Partners, Inc." upon completion of the BCA (refer to Note 2 for a complete description of the BCA).

The Company's registered office is located at 2200 HSBC Building, 885 West Georgia Street Vancouver BC V6C 3E8 and its principal office is located at 3322 West End Ave. Suite 450 Nashville TN 37203.

These interim consolidated financial statements were approved and authorized for issuance by the Board of Directors of the Company on November 22, 2021.

2. Business Combination Agreement and Finco Financing

On April 8, 2021, Alpine, Origination, Alpine Summit Energy Partners Finco, Inc ("Finco"), Red Pine Petroleum Subco Ltd. ("Subco") and Alpine Summit Energy Investors, Inc. ("Blocker") entered into the BCA pursuant to which the parties agreed to complete a series of transactions to effect a business combination between Alpine and Origination and that resulted in a reverse take-over of Alpine by the members of Origination.

(1) Finco issued subscription receipts for gross proceeds of approximately CDN$7.5 million (Note 13) and "The Finco Financing" later in note 2;

(2) immediately prior to the closing of the BCA:

(a) Alpine amended its articles to (i) reclassify its common shares as Subordinate Voting Shares ("SVS"), (ii) create a new class of Multiple Voting Shares ("MVS") and a new class of Proportionate Voting Shares ("PVS"), and (iii) change its name from "Red Pine Petroleum Ltd." to "Alpine Summit Energy Partners, Inc.";

(b) each outstanding membership unit of Origination ("Origination Member Unit") would be converted into three membership units of Origination;

(c) the Subscription Receipts converted into Finco Shares, with each holder of a Subordinate Voting Subscription Receipt receiving one Class A Finco Share in exchange therefor and each holder of a Multiple Voting Subscription Receipt receiving one Class B Finco Share in exchange therefor; and

(3) on closing of the BCA:

(a) the Company, Finco and Subco completed a three-cornered amalgamation under the BCBCA pursuant to which all Finco shareholders (including former holders of the Subscription Receipts) exchanged their Class A Finco shares held for SVS or their Class B Finco Shares held for Multiple Voting Shares, as applicable, in each case on a one-for-one basis, and Finco and Subco amalgamated, with the resulting entity ("Amalco") to continue as a wholly-owned subsidiary of Alpine;

(b) Amalco wound up into Alpine and the assets of Amalco (which consist of the funds invested by the holders of the Subscription Receipts, net of expenses) transferred to the Company by operation of law;

(c) certain U.S. holders of Origination Member Units (other than Blocker) contributed their Origination Member Units to the Company in exchange for MVS on a one-hundred membership units for one MVS basis;

(d) certain of the non-U.S. holders of Origination Member Units contributed their Origination Member Units to the Company in exchange for SVS on a one membership unit for one SVS basis subject to adjustment for any applicable withholding taxes;

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(e) each holder of Blocker Shares contributed their Blocker Shares to the Company in exchange for SVS on a one Blocker Share for three SVS basis;

(f) A related party, being an officer, director and shareholder of Origination pre-closing of the BCA, and of Alpine post closing of the BCA, subscribed for 15,947.292 PVS carrying voting rights that would, in the aggregate, represent approximately 32.2% (Note 13) of the voting rights of the Company upon completion of the BCA on a fully diluted basis for a purchase price equivalent to their estimated fair market value of USD$128,213;

(g) the Company used certain proceeds of the Finco Financing and the membership units of Origination received by it to subscribe for Blocker Shares, following which the proceeds of Finco Financing received by Blocker were contributed to Origination in exchange for membership units of Origination; and

(h) Origination Member Units held by Blocker were re-designated as Class A Voting Units of Origination and Origination Member Units held by other remaining members of Origination were re-designated as Class B Non-Voting Units of Origination.

The number and terms of the securities to be issued in connection with the BCA were determined pursuant to arm's length negotiations between the management of each of the Company and Origination at the time the BCA was entered into.

The reclassification of the common shares of the Company into SVS and the creation of the MVS in connection with the BCA is for the purpose of allowing the Company to maintain its status as a "foreign private issuer" as determined in accordance with Rule 3b-4(c) under the U.S. Exchange Act.

The Finco Financing

On August 18, 2021, Finco completed a brokered private placement of an aggregate of 161,976 subordinate voting subscription receipts at a subscription price of CDN$4.01 per subordinate voting subscription receipt and 17,057 multiple voting subscription receipts at a subscription price of CDN$401.29 per multiple voting subscription receipt for aggregate gross proceeds of approximately CDN$7.5 million (USD$ 5,995,461). Finco is a special purpose British Columbia company incorporated solely for the purpose of the Finco financing.

The Finco Financing was completed pursuant to the terms of an agency agreement dated August 18, 2021 among Finco, the Company and Eight Capital ("Agent"), as lead agent and sole bookrunner (the "Agency Agreement"). The subscription receipts are governed by the terms of a subscription receipt agreement (the "Subscription Receipt Agreement") dated August 18, 2021 among Finco, the Agent and Odyssey Trust Company in its capacity as subscription receipt agent.

Each subordinate voting subscription receipt and each multiple voting subscription receipt entitled the holder thereof to receive, upon automatic exchange in accordance with the terms of the Subscription Receipt Agreement, without payment of additional consideration or further act or formality on the part of the holder thereof, one Class A Finco share and one Class B Finco share, respectively, upon the satisfaction or waiver of the escrow release conditions at or before the escrow release deadline. Each Class A Finco share would then be exchanged for one SVS and each Class B Finco share would be exchanged for one MVS upon completion of the BCA.

In connection with the Finco financing, the Agent was entitled to receive a cash commission of CDN$26,525 and an advisory fee of CDN$197,500 (collectively, the "Agent's Fees"). On closing of the Finco financing, the Agent received payment of 50% of the Agent's Fees. The remaining 50% of the Agent's Fees paid to the Agent upon the satisfaction of the escrow release conditions.

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Reverse Takeover

On September 7, 2021, the Company completed the BCA (as described above).  As a result of the transaction, the former shareholders of Origination acquired control of the combined Company and, thereby constitutes a reverse takeover of Red Pine by Origination.  The BCA is considered a purchase of the Red Pine's net assets by Origination.  The transaction is accounted for in accordance with guidance provided in IFRS 2 Share-Based Payments. 

As Red Pine did not qualify as a business according to the definitions in IFRS 3, the BCA does not constitute a business combination; rather, it is treated as an issuance of Alpine shares for the net assets of Red Pine and Red Pine's listing status with Alpine as the continuing entity.  The resulting interim consolidated financial statements are presented as a continuation of Origination and comparatives figures presented in the interim consolidated financial statements of are those of Origination.

As a part of the reverse takeover the Company issued 534,384 SVS on September 7, 2021, for total consideration of $1,697,865 based on the Finco financing value of CDN$4.01/SVS or US$3.18/SVS, for the Red Pine net assets, which are made up primarily of cash valued at $396,173.  The excess of purchase consideration over net assets acquired resulted in a listing expenses of $1,301,692 and is presented in the interim consolidated statement of loss and comprehensive loss.

Acquisition related costs totalling $1,567,967 have been excluded from consideration paid and were recognized as transaction costs on the consolidated statement of loss and comprehensive loss for the period ended September 30, 2021 when the costs were incurred.

3. Basis of preparation

(a) Statement of compliance

These interim financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRSs") as issued by the International Accounting Standards Board ("IASB"). A summary of the significant accounting policies and method of computation is presented in Note 4. Management's significant accounting judgements, estimates and assumptions used in the preparation of the consolidated financial statements are included in Note 3. 

(b) Going concern

These financial statements have been prepared in accordance with IFRS applicable to a going concern, which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business.

During the nine months ended September 30, 2021, the Company generated a net loss and comprehensive loss of $51,614,575 (year ended December 31, 2020 - $7,530,178), and as at that date, the Company had a working capital deficiency of $80,891,770 (December 31, 2020 - working capital deficiency of $29,102,456) and accumulated deficit of $92,542,554 (December 31, 2020 - $39,757,844).

In order to continue operating as a going concern the Company will need to achieve profitable operations and/or secure additional sources of financing in order to satisfy its obligations, including scheduled repayments of long-term debt, as they become due.  During the nine months ended September 30, 2021 the Company issued 1,173,085 Origination Member Units in exchange for cash of $8.0 million, 161,976 SVS and 17,057 MVS for cash of $5.5 million net of issuance costs, and extinguished promissory notes of $3.5 million (Note 10). The Company formed two development partnerships to fund a portion of 2021 capital activity which raised approximately $34 million during the nine months ended September 30, 2021 and subsequent to period end (Note 7 and 8).  In addition, the Company issued convertible promissory notes in June 2021 (Note 10) for proceeds of $2.3 million and converted those convertible promissory notes into 234,216 Origination Member Units (Note 10).  The Company also repaid $15.2 million of long-term debt (Note 9) and $4.7 million of asset backed preferred instruments (Note 12). 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.

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

(c) Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis except as otherwise stated and allowed for in accordance with IFRS. 

(d) Functional and presentation currency

These interim consolidated financial statements are presented in US dollars ("$").  The Company's functional currency is Canadian dollars, however all of the Company's individual subsidiaries have functional currencies in US$ which represents the primary economic environment in which the entities operate.

(e) Management's significant accounting judgements, estimates and assumptions

The timely preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions based on currently available information that affect the application of accounting policies and reported amounts of assets and liabilities at the date of the statement of financial position and the reported amounts of income and expenses during the reporting period.  Accordingly, actual results may differ from these estimates.  Estimates and underlying assumptions and judgements are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. 

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus ("COVID-19"). The pandemic and subsequent measures intended to limit its spread, contributed to significant volatility in global financial markets. The pandemic has adversely impacted global commercial activity and has reduced worldwide demand for commodities including crude oil. The result was significant economic uncertainty and a decline in commodity prices through most of 2020. In general, the oil and gas industry reacted with reductions to capital and other spending, as well as production shut-ins, to try to manage through this price environment.  The full extent of the impact of COVID-19 on the Company's operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on financial markets on a macro-scale and any new information that may emerge concerning the effectiveness of available vaccines and the severity and spread of the virus. The pandemic presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by management in the preparation of its financial results.  The Company's financial performance, operations and business are particularly sensitive to a reduction in the demand for prices of crude oil and natural gas. The potential direct and indirect impact of the economic downturn related to COVID-19 have been considered in management's estimates and assumptions at period end and have been reflected in the Company's results with any significant changes described in the relevant financial statements notes.

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More specifically, assumptions may change that are involved in the estimates of valuation of exploration and

evaluation assets and property, plant and equipment cash generating units, the timing of decommissioning obligations, the fair value of commodity contracts, the expected credit loss provisions related to accounts receivable as well as liquidity and going concern assessments.

Significant estimates, judgements and assumptions made by management in the preparation of these interim consolidated financial statements are outlined below. 

Significant judgements in applying accounting policies:

The following are the significant judgements, and assumptions that management has made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognized in these consolidated financial statements:

(i) Identification of cash-generating units (CGU's)

The Company's oil and natural gas interests are aggregated into cash-generating units for both property and equipment and exploration and evaluation assets, for the purpose of calculating impairment, based on their ability to generate largely independent cash flows.  The classification of assets into CGU's requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, external users, shared infrastructures and the way in which management monitors the Company's operations.  The Company has identified only one CGU as at September 30, 2021. 

(ii) Valuation of oil and natural gas assets

Judgements are required to assess when impairment indicators, or reversal indicators, exist and impairment testing is required.  In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of undeveloped lands and other relevant assumptions.

(iii) Componentization

For the purposes of calculating depletion expense, the Company allocates its oil and natural gas assets to components with similar lives and depletion methods.  The grouping of assets is subject to management's judgement and is performed on the basis of geographical proximity and similar reserve life.  The Company's oil and natural gas assets are depleted on a unit of production basis.

(iv) Exploration and evaluation assets

The application of the Company's accounting policy for exploration and evaluation assets requires management to make certain judgements as to future events and circumstances as to whether economic quantities of reserves have been found in assessing economic viability and technical feasibility.

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(v) Joint operations

The Company is party to various joint interest, operating and other agreements in conjunction with its oil and natural gas activities.  The revenues and expenses allocated between partners are governed by the terms of these agreements that are subject to interpretation and judgement by the Company and audit by the appropriate parties. 

(vi) Business Combinations

Judgements are required to determine if acquisitions of assets or groups of assets constitute a business combination.  These judgements include assessing whether the acquired assets include inputs, processes and outputs that would constitute a business and whether the assets acquired meet the criteria of the optional concentration test to not be considered a business.

(vii) Taxes

The Company follows the liability method of for calculating deferred taxes.  Judgement is required in calculation of current and deferred taxes in applying tax laws and regulations estimating the timing of reversals of temporary differences and estimating the realizability of deferred tax assets.

Key sources of estimation uncertainty:

The following are the key estimates and related assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities.

(i) Reserves

The assessment of reported recoverable quantities of proved and probable reserves include estimates regarding production volumes, commodity prices, exchange rates, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows.  It also requires interpretation of geological and geophysical models in anticipated recoveries.  The economical, geological and technical factors used to estimate reserves may change from period to period.  Changes in reported reserves can impact the carrying values of the Company's oil and natural gas properties and equipment, the calculation of depletion and depreciation, and the provision for decommissioning liabilities.

The reserve assessment was completed by an external third-party engineering firm for the years ended December 31, 2020 and reserves are internally updated for interim periods.

(ii) Decommissioning liabilities

The calculation of decommissioning liabilities and related accretion expense requires estimates of future remediation costs of production facilities, wells and pipelines at different stages of development and construction of assets or facilities.  In most instances, removal of assets occurs many years into the future.  In addition, the calculation requires assumptions regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and liability-specific discount rates to determine the present value of these cash flows.

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(iii) Commodity contracts

The amounts recorded for the fair value of commodity contracts is dependent on estimates of future commodity prices, foreign exchange rates and volatility in those prices.

(iv) Valuation of accounts receivable

Certain amounts included in accounts receivable are based on management's best estimate of the lifetime expected credit loss related to these accounts.

(v)  Depletion

The amounts recorded for depletion of petroleum and natural gas assets are determined by useful life and future cash flows which are based on estimates of future production profiles and reserves for surrounding wells, commodity prices and discount rates.

(vi)  Fair value of development partnership liabilities

The amounts recorded for the fair value of the development partnerships liabilities are based on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, and other relevant assumptions.

(vii) Debt equity split from convertible promissory note

The allocation between the debt and equity components of convertible promissory notes is based on estimates of the market interest rate the Company would pay on non-convertible debt instruments with similar terms.

(viii) Control of development partnerships

The Company consolidates 100% of the operations, assets and liabilities of the development partnerships which is based on an analysis of the terms of the various partnership agreements and whether they give the Company control of the partnerships and the right to variable returns.

(ix) Current and long-term classification related to asset backed preferred instrument and development partnership liabilities

The current and long-term classification related to the asset back preferred instrument is based on management's assessment of what operational cash flow is going to be available to repay the instrument based on the terms of the underlying agreements.  The current and long-term classification related to development partnership liabilities is based on management's assessment of the future net cash flows to be generated by the wells included in the partnerships.

4.   Significant accounting policies

The accounting policies set out below have been applied consistently to all periods presented in these financial statements.

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(a) Basis of consolidation

(i) Subsidiaries

The consolidated financial statements include the accounts of the Company and its subsidiaries as at September 30, 2021, HB2 Origination, LLC (67.5%) and 100% of AIP Holdco GP, LLC AIP Holdco, LP, AIP Intermediate, LLC, AIP Borrower GP, LLC, AIP Borrower, LP, Alpine Summit Energy Investors, Inc, Alpine CapH4 LLC, Ageron Energy II, LLC, HB2 Midco, LLC, Alpine Maverick I GP, LLC, Alpine Maverick I L.P., Alpine Maverick II GP, LLC and Alpine Maverick II LP, LLC.

The Company has control of an investee entity when it is exposed, or has rights, to variable returns from its involvement in the investee and has the ability to affect those returns through its power over the investee. Subsidiaries are fully consolidated on a line-by-line basis, recognizing all their assets, liabilities, income and expenses and recording any non-controlling interest for the portion not owned by the Company from the date on which control in obtained. Intercompany transactions and balances between the Company and its subsidiaries are eliminated. Transactions with non-controlling interests that do not result in loss of control are accounted for as equity transactions. The difference between fair value of any consideration paid and the acquired share of the carrying value of nets assets of the subsidiary is recorded in equity. Gains or losses on disposals to non-controlling interests are also recorded in equity.

(ii) Joint arrangements

A portion of the Company's oil and natural gas business activities involve jointly controlled assets and are conducted under joint operating agreements. The Company has assessed the nature of its joint arrangements and determined them to be joint operations. These consolidated financial statements reflect only the Company's proportionate share of the joint operation's controlled assets and liabilities it has incurred, its share of any liabilities jointly incurred with other joint interest partners, income from the sale or use of its share of the joint operation's output, together with its share of expenses incurred by the joint operation and any expenses it incurs in relation to its interest in the joint operation and a share of production in such activities.

(b) Business Combinations

Business combinations are accounted for using the acquisition method when the acquisitions of companies and/or assets meet the definition of a business under IFRS. The cost of an acquisition is measured at the fair value of the assets given up, equity instruments issued and liabilities incurred or assumed at the date of acquisition. The acquired identifiable assets and liabilities and any contingent consideration are measured at their fair value at the date of acquisition. The fair value of property, plant and equipment is the estimated amount for which these assets could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgably, prudently and without compulsion. Any excess of the purchase price over the fair value of the identifiable assets and liabilities acquired is recognized as goodwill. If the cost of acquisition is less than fair value of the identifiable assets and liabilities, the difference is recorded as a gain in profit or loss. Associated transaction costs are expensed when incurred.

(c) Fair value determination

A number of the Company's accounting policies and disclosures require the determination of fair value for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining the fair values is disclosed in the notes specific to that asset or liability.

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The Company classifies fair values according to the following hierarchy based on the amount of observable inputs used to value the instruments:

• Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities.
• Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.
• Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

There were no transfers between levels of the hierarchy during the year.

Cash

The fair value of cash approximates its carrying value due to the short-term to maturity.

Accounts receivable, accounts payable and accrued liabilities, promissory notes, and long-term debt

The fair value of accounts receivable, accounts payable and accrued liabilities, promissory notes, and long-term debt are estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. As at September 30, 2021 and December 31, 2020, the fair value of accounts receivable, accounts payable and accrued liabilities and promissory notes approximated their carrying value due to their short term to maturity. The fair value of long-term debt approximates its carrying value as it bears a floating market rate of interest.

Derivatives - commodity contracts

The fair value of financial forward contracts and swaps is determined by discounting the difference between the contracted prices and published forward curves at the statement of financial position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate adjusted for the credit risk of the counterparty. The Company has used Level 2 to determine the fair value of its commodity contracts.

Fair value of development partnership liabilities

The amounts recorded for the fair value of the development partnerships liabilities are determined by discounting the estimated future payments required based on estimates of future cash flows to be generated by the underlying reserves in the partnerships.  The Company has used Level 3 to determine the fair value of development partnership liabilities.

Property, plant and equipment, and exploration and evaluation assets

The fair value less costs of disposal values used to determine the recoverable amounts of property, plant and equipment and exploration and evaluation assets, if it is higher than value in use, are classified as Level 3 fair value measurements as they are not based on observable market data.

(d) Foreign currency

Foreign currency translation includes the translation of foreign currency transactions and the translation of foreign operations.

Foreign currency transactions translations occur when translating transactions and balances in foreign currencies to the applicable functional currency of the Company and its subsidiaries.  Gains and losses from foreign exchange transactions are recorded as foreign exchange gains and losses in the statement of income (loss).  Foreign currency transactions translation occur as follows:

• Revenues and expenses are translated at the prevailing rates on the date of the transaction

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• Non-monetary assets and liabilities are carried at the rates prevailing on the date of the transaction
• Monetary assets and liabilities are translated at rates prevailing at the balance sheet date

Foreign operation translation occurs when translating the financial statements of the Canadian parent Company to the US dollar reporting currency.  Gains and losses from foreign operation translations are recorded in the statement of changes in shareholders equity(deficiency).  Foreign operation translation occurs as follows,

• Revenue and expenses are translated at the average exchange rate for the period
• All assets and liabilities are translated at the rates prevailing at the balance sheet date.

(e) Cash

Cash includes amounts on deposit with banks. 

(f) Financial instruments

Classification and Measurement

On initial recognition, financial instruments are measured at fair value. Measurement in subsequent periods

depends on their context within the Company's business model and the characteristics of the contractual cash flows as described below:

Financial Assets	Subsequent Measurement
Cash	Amortized cost
Accounts receivable	Amortized cost
Financial Liabilities	Subsequent Measurement
Accounts payable and accrued liabilities	Amortized cost
Derivative commodity contracts	Fair value through profit or loss
Development partnership liabilities	Fair value through profit or loss
Promissory notes	Amortized cost
Lease obligations	Amortized cost
Asset backed preferred instrument	Amortized cost
Long-term debt	Amortized cost

Debt issuance costs related to borrowings measured at amortized cost are amortized to finance expense over the term of the borrowings using the effective interest method.

Derivative Financial Instruments

The Company has entered into certain financial risk management contracts in order to manage the exposure to market risks from fluctuations in commodity prices and interest rates. The Company has not designated its financial risk management contracts as effective accounting hedges and, therefore, has not applied hedge accounting, even though the Company considers all risk management contracts to be economic hedges. As a result, all financial risk management contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in the statement of loss and comprehensive loss as incurred.

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Impairment

Impairment of financial assets is based on expected credit losses. The Company's accounts receivable are considered collectible within one year or less; therefore, these financial assets are not considered to have significant financing component and a lifetime expected credit loss ("ECL") is measured as the date of initial recognition.

The Company assesses the lifetime ECL applicable to its accounts receivable at initial recognition and re-assesses the provision at each reporting date. Lifetime ECLs are a probability-weighted estimate of all possible default events over the expected life of a financial asset and are measured as the difference between the present value of the cash flows due to the Company and the cash flows the Company expects to receive. In making an assessment as to whether the Company's financial assets are credit-impaired, the Company considers bad debts that the Company has incurred historically, evidence of a debtor's present financial condition and whether a debtor has breached certain contracts, the probability that a debtor enter bankruptcy or other financial reorganization, changes in economic conditions that correlate to increased levels of default, and the term to maturity of the specified receivable. The carrying amounts of accounts receivable are reduced by the amount of the ECL through an allowance account and losses are recognized as bad debt expense in profit or loss.

Based on industry experience, the Company considers financial assets to be in default when the receivable is more than 90 days past due. Once the Company has pursued collection activities and it has been determined that the incremental cost of collection pursuits outweigh the benefits of collection, the Company derecognizes the gross carrying amount of the asset and the associated allowance from the statement of financial position.

(g) Oil and natural gas interests

(i) Recognition and measurement

Exploration and evaluation assets:

Pre-license costs incurred before the Company has attained legal rights to explore an area are recognized in profit or loss.

Exploration and evaluation costs, including the costs of acquiring leases and licenses, technical services and studies, geophysical and geological activities, seismic acquisition, exploration drilling, testing and decommissioning costs are initially capitalized as exploration and evaluation assets. The costs are accumulated in cost centres by exploration area pending determination of technical feasibility and commercial viability.  Assets classified as exploration and evaluation are not depleted or depreciated until after these assets are reclassified to property, plant and equipment.

Exploration and evaluation assets are tested separately from property and equipment for impairment and are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. When an exploration and evaluation asset is determined not to be technically feasible or commercially viable, or the Company decides not to continue with its activity, the unrecoverable exploration and evaluation costs are charged to profit or loss.

The technical feasibility and commercial viability of extracting resources is considered to be determinable when proved reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to ascertain whether proved reserves have been discovered. Upon determination of proved reserves, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within property, plant and equipment referred to as oil and natural gas interests.

Exchanges, swaps and farm-outs that involve only exploration and evaluation assets are accounted for at cost.  Any gains or losses from the disposal of exploration and evaluation assets are recognized in profit or loss.

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Property, plant and equipment:

All costs directly associated with the development and production of oil and natural gas interests are capitalized on an area-by-area basis as oil and natural gas interests if they extend or enhance the recoverable reserves of the underlying assets. Items of property, plant and equipment, which include oil and natural gas development assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.  Development costs include expenditures for areas where technical feasibility and commercial viability has been determined. These costs include property acquisitions with proved reserves, development drilling, completion, gathering and infrastructure, decommissioning costs and transfers of exploration and evaluation assets. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

Gains and losses on disposal of property, plant and equipment, property swaps and farm-outs, are determined by comparing the proceeds or fair value of the asset received or given up with the carrying amount of property, plant and equipment and are recognized in profit or loss.  Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in profit or loss.

(ii) Depletion

The net carrying value of oil and natural gas interests included in property, plant and equipment is depleted using the unit of production method by reference to the ratio of production in the period to the related proved and probable reserves, for wells included in property, plant and equipment taking into account estimated future development costs necessary to bring those reserves into production.  Oil and natural gas interests including processing facilities and well equipment are componentized into groups of assets with similar useful lives for the purposes of performing depletion calculations. Relative volumes of reserves and production are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Future development costs are estimated taking into account the level of development required to produce the reserves.

(iii) Impairment

The carrying amounts of the Company's property, plant and equipment and exploration and evaluation assets are reviewed at each reporting date to determine whether there is any indication of impairment. These indicators include, but are not limited to, extended decreases in prices or margins for oil and natural gas commodities or products, a significant downward revision in estimated reserves, an upward revision in future development costs, significant decrease in fair values of undeveloped lands in close proximity to lands held by the Company or management's decision to no longer pursue certain evaluation projects.  If any such indication exists, then the asset's recoverable amount is estimated. 

For the purpose of impairment testing, exploration and evaluation assets and property, plant and equipment are tested separately and are grouped into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets or cash generating units ("CGU").  Geological formation, product type, geography and internal management operations and processes are key factors considered when grouping the Company's oil and natural gas interests into CGUs. 

The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs of disposal.  Fair value is determined to be the amount for which the asset could be sold in an arm's-length transaction between knowledgeable and willing parties. Unless indicated otherwise, the recoverable amount used in assessing impairment losses is value in use.  The Company estimates fair value less cost of disposal using discounted future net cash flows of proved and probable reserves for wells included in property, plant and equipment based on forecast prices and costs and including future development costs. The cash flows are discounted at an appropriate discount rate which would be applied by a market participant. Value in use is determined by estimating the present value of the future net cash flows to be derived from the continued use of the CGU in its present form. These cash flows are discounted at a rate based on the time value of money and risks specific to the CGU.

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An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount.  Impairment losses are recognized in profit or loss.  An impairment loss in respect of property, plant and equipment recognized in prior years, is assessed at each reporting date for any indications that the loss has decreased or no longer exists.  An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount.  An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized. 

(h) Provisions and Contingencies

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation.  The obligation is not recorded and is disclosed as a contingent liability if it is not probable that an outflow will be required, if the amount cannot be estimated reliably or if the occurrence of the outflow can only be confirmed by the occurrence of a future event. Provisions are not recognized for future operating losses. Contingent assets are disclosed if a future economic benefit is probable but are only recorded when recovery of the contingent asset is virtually certain.

(i) Decommissioning liabilities:

The Company's activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provisions are made for the estimated cost of site restoration and capitalized to exploration and evaluation assets or property, plant and equipment and are depleted over the useful life of the assets.

Decommissioning liabilities are measured at the present value of management's best estimate of the risk adjusted cash flows required to settle the present obligation at the statement of financial position date.  The future cash flow estimates are adjusted to reflect the risks specific to the liability. Subsequent to the initial measurement, the liability is adjusted at the end of each period to reflect the passage of time using a risk-free interest rate and changes in the estimated future cash flows underlying the liability.  The increase in the provision due to the passage of time is recognized as a finance cost whereas increases/decreases due to changes in the estimated future cash flows or timing are recognized as changes in the decommissioning liability and related asset.  Actual costs incurred upon settlement of the decommissioning liabilities are charged against the liability to the extent the liability was established.  Any differences between the recorded liability and the actual costs incurred are recorded as a gain or loss in profit or loss. 

(i) Revenue recognition

Revenue from the sale of crude oil, natural gas and natural gas liquids is recorded when control of the product is transferred to the buyer based on the consideration specified in the contracts with customers. This usually occurs when the product is physically transferred at the delivery point agreed upon in the contract and legal title to the product passes to the customer (often at terminals, pipelines, or other transportation methods).

The Company sells its production pursuant to variable-priced contracts.  The transaction price for variable-price contracts is based on commodity price, adjusted for quality, location, or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms.  Commodity prices are based on market indices that are determined on a monthly or daily basis. 

The Company evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, the Company considers if it obtains control of the product delivered or services provided, which is indicated by the Company having the primary responsibility for the delivery of the product or rendering of the service, having the ability to establish prices or having inventory risk.

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If the Company acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net-basis, only reflecting the fee, if any, realized by the Company from the transaction.

(j) Expenses

The costs associated with delivery, including the operating and maintenance costs, royalties and transportation are recognized in the same period in which the related revenue is earned and recorded.

(k) Income Taxes

Income tax expense comprises current and deferred tax. It is recognized in profit or loss except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income/(loss).

The Company has determined that interest and penalties related to income taxes, including uncertain tax treatments, do not meet the definition of income taxes, and therefore accounted for them under IAS 37 Provisions, Contingent Liabilities and Contingent Assets.

Current tax

Current tax comprised the expected tax payable or receivable on the taxable income or loss for the year and any adjustment to the tax payable or receivable in respect of previous years. The amount of current tax payable or receivable is the best estimate of the tax amount expected to be paid or received that reflects uncertainty related to income taxes, if any and is measured using tax rates enacted or substantively enacted at the reporting date.

Current tax assets and liabilities are offset only if certain criteria are met.

Deferred tax

Deferred tax is recognized in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination, on the initial recognition of goodwill or on temporary differences related to investments in subsidiaries, associates and joint arrangements to the extent that the group is able to control the timing of the reversal of the temporary differences and it is probable that they will not reverse in the foreseeable future.

Temporary differences in relation to a right-of-use asset and a lease liability for a specific lease are regarded as a net package (the lease) for the purpose of recognizing deferred tax.

Deferred tax assets are recognized for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary differences is insufficient to recognize a deferred tax asset in full, then future taxable profits, adjusted reversals of existing temporary differences, are considered, based on the business plans for individual subsidiaries in the Group. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit swill be realized; such reductions are reversed when the probability of future taxable profits improves.

The measurement of deferred tax reflects the tax consequences that would follow from the manner in which the group expects, at the reporting date, to recover or settle the carrying amount of its assets and liabilities.

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Deferred tax assets and liabilities are offset only if certain criteria are met.

(l) Finance income and expenses

Finance income, consisting of interest income, is recognized as it accrues in profit or loss using the effective interest method and/or when the Company's right to receive payments is established.

Finance expense is comprised of interest expense on borrowings, financing fees, accretion of promissory note discounts, debt issuance costs, lease liabilities, and accretion of the discount on decommissioning liabilities, and is recognized in the period in which they are incurred. 

(m) Earnings (loss) per share

Basic earnings (loss) per share is computed by dividing the income/(loss) by the weighted average number of shares outstanding during the period. Diluted earnings per share amounts are calculated by giving effect to the potential dilution that would occur if contracts to issue shares were exercised, fully vested, or converted to shares. The treasury stock method is used to determine the dilutive effect of dilutive instruments, where it is assumed that the proceeds received from the exercise price of in-the-money dilutive instruments are used to repurchase shares.  The weighted average number of shares is determined on an as converted basis, where all MVS and PVS are treated as SVS, in addition, HB2 Member Units are included as outstanding prior to the BCA (Note 2) based on the equivalent SVS. 

(n) Leases

At inception of a contract, the Company assesses whether a contract is, or contains a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To assess whether a contract conveys the right to control the use of an identified asset, the Company assesses whether: the contract involves the use of an identified asset; the Company has the right to obtain substantially all of the economic benefits from the use of the asset throughout the period of use; and, the Company has the right to direct the use of the asset.

The company has elected not to recognize right of use assets and lease liabilities for short term leases that have a term of 12 months or less and leases of low value assets. Leases to explore for or use crude oil, natural gas, minerals and similar non regenerative resources are also exempt from the standard. The Company treats lease payments for the these types of leases as an expense when incurred, over the lease term, except for lease payments related to non producing properties which are capitalized.

The Company recognizes a right of use asset and a lease liability at the commencement date of the lease contract, which is the date that the lease asset is available to the Company. The lease asset is initially measured at cost. The cost of a lease asset includes the amount of the initial measurement of the lease liability, lease payments made at or before to the commencement date less any incentives received, initial direct costs and estimates of the decommissioning liability, if any. Subsequent to initial recognition, the lease asset is depreciated using the straight-line method over the earlier of the end of the useful life of the lease asset or the lease term. A lease obligation is recognized at the commencement of the lease term at the present value of the lease payments that are not paid at that date discounted using the rate implicit in the lease or the Company's incremental borrowing rate if the implicit rate is not readily available. Lease payments that are present valued include fixed payments, less any lease incentives receivable, variable lease payments that are based on index or rate, amounts expected to be payable under residual value guarantees, the exercise price of a purchase option that is reasonably certain of exercise and payment of penalties for terminating a lease if the lease term reflects exercising that option. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation. Optional renewal periods, or periods which are cancellable by the Company, are included in the lease payments if the Company is reasonably certain to exercise the renewal option or not cancel the lease. The lease liability is measured at amortized cost using the effective interest method. The lease liability is remeasured when there is a change in the Company's assessment of the expected lease term or is there is a lease modification.

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(o) Share based payments

The Company measures share based payments to non-employees at the fair value of goods or services received at the date of receipt of the goods or services.  If the fair value of the goods and services cannot be reliably measured, the value of the share based payment will be used, measured using the Black-Scholes option pricing model.

(p) Development Partnership Liabilities

The Company has issued certain units in a development partnership that gives holders of these units certain rights as further described in (Note 7 and 8).  These units give the holders the right to receive certain variable cash flows based on the cash flows generated by the assets of the partnership.  These units also give the holder the right to put the units back to the partnership at a variable price based on the value of the assets of the partnership at certain future dates.  This put right qualifies as a derivative financial liability.  These partnership units have been designated by the Company to be measured at fair value through profit or loss using level 3 fair value measurements.

(q) Non-controlling Interest

Non-controlling interests ("NCI") represent ownership interest in consolidated subsidiaries by parties that are not shareholders of the Company.  They are shown as a component of total equity in the interim Consolidated Statements of Financial Position, and the share of income/(loss) attributable to NCI is shown as a component of net income/(loss) in the Interim Consolidated Statements of Operations and in the interim Consolidated Statement of Comprehensive Loss.  Changes to the parent company's ownership that do not result in a loss of control are accounted as equity transactions.

NCI in a subsidiary is recognized at either fair value or at the non-controlling interest's proportionate share of the subsidiary net assets, determined on an acquisition-by-acquisition basis. 

(r) Shares and Origination Member Units

Proceeds from the issuance of shares and Origination Member Units are classified as equity.  Incremental costs directly attributable to the issuance of shares or Origination Member Units are recognized as a deduction from equity.

Upon redemption of shares or Origination Member Units by the Company the excess (deficiency) of consideration paid to redeem shares or Origination Member Units over the weighted average carrying amount of member units at the time of redemption, is recorded as a charge (credit) to members' equity with no gain or loss recorded.

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5.   Exploration and evaluation ("E&E") assets

 

E&E assets consist of undeveloped lands, unevaluated seismic data and unevaluated drilling and completion costs and associated decommissioning costs on the Company's exploration projects which are pending the determination of proved reserves. Transfers are made to property, plant and equipment ("PP&E") as proved reserves are determined and technical feasibility and commercial viability is established. E&E assets are expensed due to uneconomic drilling and completion activities and lease expiries.

Additions during the nine months ended September 30, 2021 and year ended December 31, 2020, mainly relate to undeveloped lands and drilling costs on wells without assigned proved reserves prior to their transfer to property, plant and equipment.

The Company reviews many factors when determining if an impairment test should be performed.  At September 30, 2021 and at December 31, 2020, the Company conducted an assessment of impairment indicators for the Company's exploration and evaluation assets and noted no impairment indicators were present other than lands that had expired lease terms or near expiry.

For the nine months ended September 30, 2021, the Company had no impairments. For the nine months ended September 30, 2020, the Company recorded an impairment of $3,121,873 of E&E assets previously capitalized as exploration and evaluation assets as the lease term of undeveloped lands expired or were near expiry.  These amounts have been included in impairment loss on exploration and evaluation assets in the statement of loss and comprehensive loss.

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6.  Property, plant and equipment

Depletion

The depletion calculation for the nine months ended September 30, 2021 includes estimated future development costs of $34,841,744 (year ended December 31, 2020 - $36,679,400) associated with the development of the Company's proved plus probable reserves included in property, plant and equipment.

Acquisition of working interests

On December 22, 2020 the Company acquired the working interest in a series of wells from a third party who held a working interest in a number of the Company's existing wells as well as settled accounts payable owing to the third party.  The Company paid $45,700,000 in cash, and issued a promissory note in the amount of $1,800,000 (note 10) to repay joint interest payables owed to the vendor of $14,498,178 and acquire PP&E in the amount of $33,001,822.

Disposals

During the year ended December 31, 2020 the Company settled affiliate loans in the amount of $4,629,324 plus accrued interest of $730,500 through the assignment of one well to the affiliate and the assignment of $500,000 of accounts payable to affiliate. The well had a carrying value of $1,340,264 and associated decommissioning liabilities of $74,000. The difference between the carrying value of the well and the affiliate loan was recorded as affiliate contributions to capital reserves in members' equity.

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Impairment

The Company assesses many factors when determining if an impairment test should be performed. For the nine months ended September 30, 2021, the Company assessed impairment indicators for the Company's CGU and noted no indicators of impairment were present.

For the year ended December 31, 2020, the Company conducted an assessment of impairment indicators for the Company's CGU. In performing the review, management determined that the continued volatility of commodity pricing and the impact this has on the economic performance of the Company's CGU justified determination of the recoverable amounts of all CGU. The recoverable amounts were estimated at the value in use on the net present value of the before tax future net cash flows from oil and natural gas proved and probable reserves using forecasted prices and costs estimated by external and Company engineers. The future net cash flows were discounted at a rate of 15%.

There was no impairment loss required for any of the Company's CGUs for the year ended December 31, 2020.

In the year ended December 31, 2020, due to increased reserves being assigned to the Company's Austin Chalk CGU, the Company identified indicators of a possible reversal of previously recorded impairment losses.  The Company calculated the value in use of the CGU to allow for the reversal of the impairment loss recorded in 2019 (net of depletion that would have been recorded) of $4,730,000.

Key assumptions used in the determination of the recoverable amounts of each CGU includes commodity prices and discount rates applied to cash flows from proved and probable reserves. A 1% increase in the assumed discount rate over the life of the reserves independently would not have resulted in any further impairment loss or impairment loss reversal for the year ended December 31, 2020.

The Company utilized the following benchmark prices to determine the forecast prices in the value in use calculations;

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7. Development partnership 1

During the first quarter of 2021, the Company formed a Development Partnership ("DP") with 13 external limited partners and Origination as a limited partner and the general partner.  The intention of the DP is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%.  The Company has raised $13,140,240 from external limited partners of which $1,366,709 was raised from officers and directors of the Company.  Investors can choose to receive DP Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $3,243,728 in Flat Payout units and $9,896,512 in IRR based payout units. Flat Payout Units will participate in 75% of the income of the DP (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of the DP (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of the DP (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of the DP (along with Flat Payout Units).  The Company will receive 25% of the income of the DP before payout and will receive 80% and 94% of the income related to Flat and IRR based payout Units respectively after payout. 

After payout, the external limited partners will also have a put right to effectively put their DP units (with ongoing rights to 20% and 6% of the income generated by the DP) back to the Company for either i) Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company) or ii) cash, subject to certain restrictions, and with the number of shares or cash to be distributed to be calculated based on future net present values of the oil and gas reserves of the DP.

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

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments.  For the three and nine months ended September 30, 2021, an increase in the liability of $1,329,509 and $4,001,481, respectively, was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses (Note 18).

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

Refer to Note 23 for further disclosure related to the repayment of the first development partnership, subsequent to September 30, 2021.

8.  Development partnership 2

During the third quarter of 2021, the Company formed a Development Partnership ("DP") with 26 external limited partners and Origination as a limited partner and the general partner.  The intention of the DP is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%.  The Company has raised $20,815,329 from external limited partners of which $1,724,967 was raised from officers and directors of the Company.  Investors can choose to receive DP Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $7,390,362 in Flat Payout units and $13,424,967 in IRR based payout units. Flat Payout Units will participate in 75% of the income of the DP (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of the DP (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of the DP (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of the DP (along with Flat Payout Units).  The Company will receive 25% of the income of the DP before payout and will receive 80% and 94% of the income related to Flat and IRR based payout Units respectively after payout. 

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After payout, the external limited partners will also have a put right to effectively put their DP units (with ongoing rights to 20% and 6% of the income generated by the DP) back to the Company for either i) Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company) or ii) cash, subject to certain restrictions, and with the number of shares or cash to be distributed to be calculated based on future net present values of the oil and gas reserves of the DP.

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

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments.  For the three and nine months ended September 30, 2021, an increase in the liability of $8,308,892 was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses (Note 18).

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

9.  Long-term debt

On December 22, 2020, the Company entered into a credit facility with Goldman Sachs (the "Goldman Facility").    All borrowings under the facility are secured by the Company's oil and gas producing wells as well as all assets of the Company's three subsidiaries.  The Goldman Facility carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) and a maturity date of December 22, 2031.  Interest payments are required quarterly.  As at September 30, 2021, the Company had $28,144,040 (December 31, 2020 - $43,328,396) drawn under the facility.  The Company's subsidiaries including AIP Holdco, LP, AIP Borrower LP have certain financial covenants under the Golden Facility, including;

(i) Maintain a ratio of total net debt to adjusted EBITDAX of no more than 3.5 to 1.0, whereby net debt is effectively defined as all indebtedness of the Company less certain cash balances held in control accounts in which the lender holds a security interest, and adjusted EBITDAX is effectively defined as income before interest, taxes, depletion, amortization, extraordinary gains and losses and other non cash items annualized.

(ii) Maintain an unrestricted cash balance of no less than $1,000,000

(iii) Maintain a Measured Assets to Total Net Debt Ratio of at least 1.50 to 1.0, whereby Measured Assets is effectively defined as the present value of the Company's a) proved reserves, b) forward commodity contracts, c) abandonment liabilities related to proved producing reserves and d) other fixed costs associated with the proved producing reserves all discounted at 10% and Total Net Debt is defined as outlined in part i) to this note.

As at September 30, 2021, the Company was in compliance with all financial covenants.

Under the terms of the lending agreement, The Company is also required to;

i) As at the initial borrowing date, enter into certain forward commodity swap contracts included in Note 22 (c)(i) which it has done.

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ii) Within 90 days of the initial borrowing date, enter into an interest rate swap contract to effectively fix the interest rate of at least 70% of the principal outstanding on the loan, at any given time for the term of the loan.  The Company entered into these swaps during the nine months ended September 30, 2021 (Note 22 (c)(ii)).

iii) No later than December 31, 2021, establish an interest reserve account that will hold a cash balance sufficient to cover nine months of scheduled interest payments which it has not done but intends to prior to the required date of December 31, 2021.

 Repayments of principal required under the lending facility are as follows;

In addition to the required principal repayments outlined above, the Company's subsidiaries including AIP Holdco, LP, AIP Borrower LP could also be required to make additional payments of:

i) If the ratio of adjusted EBITDAX to scheduled loan principal and interest payments for the period is less than 1.50 to 1.00, the Company must make an additional principal prepayment equal to Net Income/(Loss) adjusted for all non cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement

ii)  If the Company fails to meet its ratio (as defined above) of Measured Assets to total net debt of 1.50 to 1.00, the Company must make an additional principal prepayment sufficient to meet the 1.50:1.00 ratio.

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At September 30, 2021, the Company was not subject to any other additional principal prepayments.

Details of the loan balances are as follows;

 

During the three and nine months ended September 30, 2021 the Company recorded amortization of borrowing costs of $236,961 and $833,260, respectively (Note 17).

10. Promissory and convertible promissory notes

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

i) During the nine months ended September 30, 2021, the Company issued $1,075,000 in promissory notes for cash of which $75,000 were to an officer of the Company.

ii) During the nine months ended September 30, 2021, the Company issued 353,870 Origination Member Units in exchange for $3,475,000 in promissory notes (Note 13) (2020 - Nil) of which $600,000 were held by an officer of the Company.  In addition, the Company exchanged $1,000,000 of promissory notes in connection with the asset backed preferred instrument (Note 12).

iii) During the nine months ended September 30, 2021, the Company repaid $1,605,000 of promissory notes with cash and also offset $270,000 of promissory notes with agreed upon overhead expenses paid by the Company that was outstanding at December 31, 2020, which has been shown as a reduction of general and administrative expenses.

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iv) In June 2021, the Company issued a series of unsecured, non-interest bearing convertible promissory notes to individuals in aggregate principal amount of US$2.3 million with a maturity date of sixty days from the date of issuance.  Per the terms of these convertible promissory notes, they are convertible into units of the Company at a conversion rate of $9.82/unit at the option of the noteholder or the Company.  On July 2, 2021, the Company exercised its option to convert all the existing convertible notes into 234,216 Origination Member Units effective as of July 7, 2021 (Note 13).

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

11. Decommissioning liabilities

The total future decommissioning obligations were estimated based on the Company's net ownership interest in petroleum and natural gas assets including well sites and gathering systems, the estimated costs to abandon and reclaim the petroleum and natural gas assets and the estimated timing of the costs to be incurred in future periods. As at September 30, 2021, the Company estimated the total undiscounted amount of cash flows required to settle its decommissioning obligations to be approximately $2,074,252 (December 31, 2020 $1,297,000) which will be incurred between 2025 and 2058. As at September 30, 2021, an average risk-free rate of 2.02% (December 31, 2020 - 1.65%) and an inflation rate of 2.0% (December 31, 2020 - 1.6%) were used to calculate the decommissioning obligations.

The risk-free rate used in the calculation of the net present value has a significant impact on the carrying value of decommissioning liabilities. A 1% increase in the risk-free rate at September 30, 2021 would decrease the decommissioning liability by $258,000.

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12. Asset Backed Preferred Instrument

On March 5, 2021, the Company executed a 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 HB2 Member Units at the time) along with a $1,000,000 promissory note (Note 10) for a preferred instrument (23,500,000 LP units) in a newly created limited partnership controlled by the Company ("the LP Units")  The Company was required to redeem 6,670,000 LP Units on or before May 1, 2021 at $0.71 per LP Unit, or before June 1, 2021 at $0.8809 per LP Unit, or before September 1, 2021 at $1.00 per LP Unit or would be considered in default.  The remaining 16,830,000 LP Units must be redeemed at $1.00 per LP Unit no later than March 5, 2024.  If the remaining 16,830,000 LP Units are not redeemed by this date, the redemption price increases to $1.35 per LP Unit and the Company is considered to be in default.  While outstanding, all LP Units earn a fixed rate of return of 12% per annum, which increases to 17% in any event of default.  The 6,670,000 LP units were redeemed at $0.71 per LP unit in the second quarter of 2021 for a total amount of $4,735,700.

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

For the three and nine months ended September 30, 2021, the Company recorded finance expense related to the outstanding instrument in the amount of $532,592 and $1,310,975, respectively. 

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

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13. Share Capital

Authorized share capital

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

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

During the nine months ended September 30, 2021, the Company issued 819,215 Origination Member Units for aggregate cash of $8,044,700 ($9.82/unit).  In addition, the Company issued 353,870 Origination Member Units in exchange for the retirement of $3,475,000 in promissory notes ($9.82/Unit). 

The Company entered into an agreement, with a third party, to acquire 16,201 net acres in the Eagle Ford formation, located in the Austin, Fayette, Lee and Washington counties of Texas.  In exchange for the acreage, the Company issued 203,666 Origination Member Units valued at $2,000,000 ($9.82/Unit). 

In addition, the Company issued 152,749 Origination Member Units, valued at $1,499,995 ($9.82/Unit) in exchange for approximately 630 net mineral acreage in Washington county, Texas.

In May of 2021, the Company issued 923,954 Origination Member Units to officers and consultants of the Company for services at an estimated value of $9.82 per HB2 Member Unit for total consideration of $9,073,228 in connection with the listing application.

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

Loss per share:

The Company had no options, or warrants outstanding for all periods ended September 30, 2021 and 2020.  The effect of the conversion of convertible promissory notes and NCI interest in Origination would be anti-dilutive and therefore have not been included in the calculation of diluted loss per share.

Weighted average shares are based on an as converted basis for MVS and PVS into SVS as all classes of shares are ordinary shares for purposes of these calculations.  Ordinary shares outstanding have also been adjusted to reflect the reverse takeover and three for one equity split (Note 2).

14. Non-Controlling Interest

In connection with the BCA (Note 2), 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 32.5% economic interest in Origination.

On closing the BCA, Origination's consolidated book value of net liabilities was $32,968,557, which results in an opening NCI balance of $10,714,781. This NCI balance along with the weighted average stated capital of the equity interests surrendered by the NCI holder of $18,721,276, for a total of $29,436, 057, has been credited to capital reserve.

For the 23 days of September, 2021 following the closing of the BCA, $3,355,382 was recorded to decrease net loss on the interim consolidated statement of operations and comprehensive loss, with an offset to NCI, representing NCI share of net loss for the 23 day period.

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15. Capital Reserve

a) During the year ended December 31, 2020, the Company disposed of certain wells to a company related by virtue of a common shareholder, officer and director, in exchange for the extinguishment of an affiliate loan.

Due to the relationship between the Company and the related party, differences between the carrying amount of assets disposed of and the loan balance extinguished has been recorded as affiliate contributions to the capital reserves account in members' equity. For the year ended December 31, 2020, $4,592,641 was recorded to the capital reserve account.

b) During the nine months ended September 20, 2021, an additional $29,436,057 has been added to capital reserve related to certain Origination equity holders electing to not convert their equity interests into SVS/MVS of the Company as further described in note 14.

16. Key management compensation

The remuneration of the key management personnel of the Company which includes all executive officers is set out below in aggregate:

Total personnel expenses for all employees and officers including share based compensation was $12,296,690 of which $3,223,462 is included in general and administrative expenses and $9,073,228 is included in stock based compensation (Note 13).

17. Revenue from petroleum and natural gas sales

The amount of each significant category of revenue recognized for the three and nine months ended September 30, 2021 and 2020 is as follows:

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18. Finance expenses

The amount of each significant category of finance expense recognized for the three and nine months ended September 30, 2021 and 2020 is as follows:

19. Taxes

Prior to the RTO, the Company was not subject to income taxes, because, as a Limited Liability Company it was treated as a pass-through entity for income tax purposes, as the members of the Company pay the income tax on their share of the LLC's taxable income.  As a result, the consolidated Statements of Financial Position and the consolidated Statements of Loss and Comprehensive Loss do not include items related to income taxes for the period before the RTO.  Subsequent to the RTO, the Company is taxed as a U.S. C Corporation and is subject to income tax on its share of pass-through taxable income from Origination, and any tax balances related to the Company, together with those of the acquired entity, are therefore part of these consolidated financial statements. Any income attributable to members outside the consolidated group is not reflected in the Company's consolidated Statement of Financial Position and the consolidated Statement of Loss and Comprehensive Loss.

The Company recognized the following amounts of tax expense in the income statement:

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Deferred tax assets and liabilities

The deferred tax liabilities consist of temporary differences between the carrying values for accounting versus tax values, as follows:

Deferred tax assets are recognized only to the extent that it is probable that the assets can be recovered.  As at December 31, 2020, the Company has non‐capital loss carryforwards in Canada of $1.9 million which expire between 2029 and 2040 and which were acquired mainly as part of the BCA, for which no deferred tax asset is recognized.  Non-capital losses in the United States, which have no expiration period but are subject to certain limitations on taxable income, have been recognized.

20. Supplemental cashflow information

a. Change in non-cash working capital

 

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b. Non-cash transactions

During the period ended September 30, 2021, the Company issued 356,415 HB2 Member Units in exchange for $3,499,995 of exploration and evaluation assets ($9.82/unit) (Note 13).

During the period ended September 30, 2021 the Company issued 353,870 HB2 Member Units in exchange for the retirement of promissory notes (Note 13).

During the period ended September 30, 2021 the Company redeemed 3,992,629 HB2 Member Units and converted a $1,000,000 promissory note in exchange for an asset backed preferred instrument valued at $21,565,700 (Note 12).

On July 2, 2021, the Company exercised its option to convert all the existing convertible promissory notes ($2,300,000) into 234,216 units ($9.82/unit) of the Company effective as of July 7, 2021 (Note 13).

21. Related party transactions and balances not disclosed elsewhere in the financial statements

Management services agreement

On December 22, 2020, the Company entered into a Management Services Agreement (the "MSA") with a company related by virtue of common equity holders, directors and officers.  Under this Agreement, the related Company provided management, finance, operations and administrative services.  The Agreement had an initial period of 11 years with a 90 day cancellation notice.  The Company was obligated pay for these services on a quarterly basis amounting to the lesser of; i) $2.00 per produced barrel of oil equivalent (converting natural gas to BOE equivalent of 6:1), and ii) 0.375% of measured assets as defined in the credit agreement (Note 9).

During the nine months ended September 30, 2021, the Company incurred fees of $159,665 (three and nine months ended September 30, 2020 - $Nil) and is included in general and administrative expenses, of which $159,665 is included in accounts payable as at September 30, 2021 (December 31, 2020 - $20,000).  In the second quarter of 2021, the MSA was effectively terminated by assigning the MSA to one of the Company's subsidiaries, thereby eliminating the requirement to pay any fees going forward as outlined above.

In the second quarter of 2021, the Company entered into a new Letter Agreement (the "Letter") with the same related company by virtue of common equity holders, directors and officers.  The Letter requires the Company to hire its own employees, obtain its own office lease and assume certain management obligations.  In exchange, the Company is paid an annual fee of $1,000,000 on a quarterly basis.  During the nine months ended September 30, 2021, the Company was paid $215,080 via a payroll credit and $166,667 in cash, with a corresponding decrease to general and administrative expenses in the statement of income and loss.  The Company will be paid $250,000 for services provided in the fourth quarter of 2021.

Related party balances

(i) At September 30, 2021, accounts receivable includes $80,000 (December 31, 2020 - $Nil) owed to the Company by officers of the Company and companies controlled by the officers of the Company.  These amounts are due as a result of the related parties being joint interest parties in certain wells operated by the Company.  These amounts were received subsequent to September 30, 2021.

(ii) At September 30, 2021, the accounts payable included $105,191 (December 31, 2020 - accounts receivable of $75,612) due from a company related by virtue of common equity holders, officers and directors under normal credit terms.

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22. Financial instruments and risk management

Risk management:

The Company has exposure to credit risk, liquidity and market risk from its use of financial instruments. This note presents information about the Company's exposure to each of the risks, the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital.

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.

There were no changes to the Company's risk management policies or processes during the period ended September 30, 2021.

(a) Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counter-party to a financial instrument fails to meet its contractual obligations. The maximum exposure to credit risk is as follows:

Accounts receivable

The Company's accounts receivable are subject to normal industry credit risk. The Company is the operator of the oil and gas properties. Petroleum and natural gas sales are normally collected by the Company between 30 and 60 days from deliveries. Joint interest receivables are typically collected within one to three months of the joint interest bill being issued to the partner.  However, the receivables are due from participants in the oil and gas industry and collection of outstanding amounts can be impacted by industry factors such as commodity price fluctuations, limited capital availability and success of drilling programs.

As at September 30, 2021 and December 31, 2020, the Company's accounts receivable were comprised of the following:

Accounts receivable aging as at September 30, 2021 and December 31, 2020 are as follows:

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All amounts shown as current and 31 - 60 days aging have been collected subsequent to period end.  Amounts greater than 90 days are being pursued by management and the expected credit loss is believed to be insignificant.

Cash

All of the Company's cash is held at two financial institutions as at September 30, 2021 and December 31, 2020. The Company manages its credit exposure to cash, if any, by selecting institutions with high credit ratings.

(b) 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 September 30, 2021, the Company had negative working capital of $80,891,770.  The Company expects to repay its financial liabilities in the normal course of operations and to fund future operational and capital requirements through operating cash flows and through issuance of debt and/or equity.

The Company may need to conduct asset sales, equity issues or issue debt if liquidity risk increases in a given period.  Liquidity risk may increase as a result of a change in the amounts settled monthly from the commodity contracts (Note 22 (c)). The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans/notes, asset sales, coordinating payment and revenue cycles each month, and an active commodity hedge program to mitigate commodity price risk and secure cash flows.

More specifically, in an attempt to increase liquidity, the Company has during and subsequent to the nine months ended September 30, 2021 i) issued convertible promissory notes for cash (Note 10), ii) commenced a drilling program to increase cash flows from operating activities, iii) raised significant funds through two development partnerships (Note 7, 8 and 23), iv) settled promissory notes with a combination of cash and HB2 Member Units (Note 10) and v) entered into a new revolving credit facility (Note 23).

The Company is required to meet certain financial covenants under the Goldman Facility (Note 9).  As at September 30, 2021, the Company was not in any breach of financial covenants in place.

The following table details the Company's financial liabilities and their scheduled maturities as at September 30, 2021;

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(c) Market risk

Market risk is the risk that changes in market metrics, such as commodity prices, foreign exchange rates and interest rates that will affect the Company's valuation of financial instruments, as well as its net income (loss) and cash flow from operating activities. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.

i. Commodity price risk

Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by North American and global economic events that dictate the levels of supply and demand. The nature of the Company's operations results in exposure to fluctuations in commodity prices. The Company's production is sold using "spot" pricing with prices fixed at the time of transfer of custody or on the basis of a monthly average market price. 

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As at September 30, 2021, the Company had entered into the following risk management contracts to manage commodity price risk:

Commodity	Expiry	Type	Average Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	Dec 2023	Swap	$0.20	5,347,608	NGL-Mont Belvieu
Propane (gallons)	Dec 2023	Swap	$0.52	3,287,866	NGL-Mont Belvieu
Natural gas (gallons)	Dec 2023	Swap	$0.95	2,106,699	NGL-Mont Belvieu
Iso butane (gallons)	Dec 2023	Swap	$0.56	687,956	NGL-Mont Belvieu
Nor butane (gallons)	Dec 2023	Swap	$0.57	1,599,625	NGL-Mont Belvieu
Natural gas (mmbtu)	Dec 2028	Differential Swap	$0.07	2,833,007	Henry Hub -Nymex vs East TX
Natural gas (mmbtu)	Dec 2028	Swap	$2.61	2,712,266	Henry Hub -Nymex
Crude oil (bbl)	Dec 2028	Swap	$43.38	818,006	WTI-Nymex
Crude oil (bbl)	Nov 2021	Put	$50.00	50,000	WTI-Nymex
Crude oil (bbl)	Dec 2021	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Jan 2022	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Mar 2022	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Apr 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	May 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	Jun 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	Nov 2021	Short	$70.31	50,000	WTI-Nymex
Crude oil (bbl)	Dec 2021	Short	$68.64	40,000	WTI-Nymex
Crude oil (bbl)	Jan 2022	Short	$71.11	10,000	WTI-Nymex
Crude oil (bbl)	Feb 2022	Short	$70.51	10,000	WTI-Nymex
Crude oil (bbl)	Mar 2022	Short	$69.93	8,000	WTI-Nymex
Crude oil (bbl)	Apr 2022	Short	$69.36	10,000	WTI-Nymex
Crude oil (bbl)	May 2022	Short	$68.78	30,000	WTI-Nymex
Natural gas (mmbtu)	Nov 2021	Short	$4.879	10,000	Nat Gas-Nymex
Natural gas (mmbtu)	Dec 2021	Short	$4.994	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	Jan 2022	Short	$4.916	160,000	Nat Gas-Nymex
Natural gas (mmbtu)	Feb 2022	Short	$4.810	160,000	Nat Gas-Nymex
Natural gas (mmbtu)	Mar 2022	Short	$4.656	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	Apr 2022	Short	$3.694	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	May 2022	Short	$3.578	30,000	Nat Gas-Nymex

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

The commodity contracts had a total negative fair value of $29,627,332 at September 30, 2021 (December 31, 2020 - $4,521,383) comprised of a short term commodity contract liability of $14,709,808 (December 31, 2020 - $3,158,763) and long term commodity contract liability of $14,917,524 (December 31, 2020 - $1,362,620).  The corresponding unrealized loss for the nine months ended September 30, 2021 was $25,105,950 (2020 - $Nil) and is included in the statement of loss and comprehensive loss.  Total realized losses on risk management contracts totalled $14,276, 940 (September 30, 2020 - $412,523) for the nine months ended September 30, 2021 and are also included in the statement of loss and comprehensive loss. 

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For the nine months ended September 30, 2021, a 10% increase/decrease in commodity prices would have a negative/positive impact on net income of approximately $8,015,000.

ii. Interest rate risk

The Company is exposed to interest rate risk in relation to interest expense on its Goldman Facility as future cash flow may fluctuate as a result of market interest rates. If interest rates applicable to the facility were to have increased by 100 basis points (1%) it is estimated that the Company's net income for the nine months ended September 30, 2021 would have decreased by approximately $194,000 (before effect of income taxes). A decrease in interest rates by 1% would result in an increase in net income by an equivalent amount.

The Company entered into a LIBOR rate swap which effectively fixes the interest rate on a reducing notional principal amount commencing at $28,144,040 and reducing in fixed amounts to $Nil as of September 20, 2028.  The Company will effectively pay/receive the difference between the fixed rate of 1.453% and the floating rate which is the greater of a 3 month USD LIBOR rate and 1.00%.

At September 30, 2021 the interest rate swap had a negative fair value of $57,310.  For the nine months ended September 30, 2021, the Company recognized a corresponding unrealized loss of $57,310 (2020 - $Nil).

iii. Foreign currency risk

The Company mainly trades in US dollars which is also its functional currency hence, there is nominal foreign currency exposure.

(d) Capital management

The Company's objectives when managing its capital are to safeguard its ability to continue as a going concern, to meet its capital expenditures for its continued operations, and to maintain a flexible capital structure which optimizes the cost of capital within a framework of acceptable risk. The Company manages the capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets.

There has been no change to management's approach to managing capital during the period ended September 30, 2021, with the exception of the addition of development partnership liabilities and asset back preferred instruments to the definition of managed capital.

The Company considers its capital employed to be long-term debt, promissory notes payable, affiliate loans (if any), development partnership liabilities and asset back preferred instruments and shareholder's equity/(deficiency):

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The Company makes adjustments to capital employed by monitoring economic conditions and investment opportunities. The Company generally relies on credit facilities, equity issuances and cash flows from operations to fund capital requirements. To maintain or modify its capital structure, the Company may issue new shares, issue new debt, renegotiate existing debt terms, or repay existing debt. The Company is not currently subject to any externally imposed capital requirements, other than covenants on its bank debt (Note 9).

Refer to subsequent events (Note 23) for additional information on capital management initiatives.

23. Subsequent events

Completion of DP1

On October 7, 2021, the Company repaid and paid out the reversion of the first development partnership ("DP1") that it formed during the first quarter of 2021.

DP1 funded the drilling and completion of five wells in the Giddings Field near Austin, TX and comprised a total capital program of approximately $21.3 million, with 60% funded by external partners. As part of the completion of the DP1 program, Alpine has retired liabilities of $15,288,594.

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 HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company, having a deemed value of US$3.515 per unit, or a total of approximately US$1.2 million).

On October 7, 2021, the Company formed a third Development Partnership ("DP3") with 23 external limited partners and HB2 as a limited partner and the general partner.  The intention of the DP3 is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%.  The Company has raised $21,182,826 from external limited partners of which $4,032,672 was raised from officers and directors of the Company.  Investors can choose to receive DP3 Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $10,413,322 in Flat Payout units and $10,769,504 in IRR based payout units.

The terms of the units are identical to those of the first and second development partnerships (Note 7 and 8).

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

Revolving Credit Facility

In October, 2021, the Company's operating subsidiary Origination closed on a corporate credit facility.  The facility has a maximum of $12.5 million, subject to quarterly borrowing base determinations by the lender.  The borrowing base is currently set at $6,579,750.  The loan charges interest at prime +2.25% and has a one year maturity.  A subset of certain Company working interests in producing assets have been secured in connection with the facility.

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Introduction

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

Basis of Presentation

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

Operational and Financial Results

Overview

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

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

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

Q3 2021 Highlights

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

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

• Brought two new wells onto production in the Austin Chalk.

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

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

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2021 Objectives

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

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

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

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

2022 Objectives

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

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

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2022 Guidance

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

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

• Crude Oil WTI Price: $74.01
• NGL Price: $22.94
• Natural Gas Henry Hub Price: $4.39

Results of Operations

Production and Revenue

		Three Months to September 30, 2021			Three Months to September 30, 2020			Period-over- period change			Nine Months to September 30, 2021			Nine Months to September 30, 2020			Period-over- period change
Crude oil (bbls)		263,327			31,301			232,026			615,149			46,065			569,084
Natural gas (Mcf)		686,505			34,422			652,083			2,290,594			36,747			2,253,847
NGLs (bbls)		119,006			11,047			107,959			289,582			11,545			278,037
Total (Boe)		496,751			48,085			448,666			1,286,497			63,735			1,222,762
Crude oil weighting		53.0%			65.1%						47.8%			72.3%
Natural gas weighting		23.0%			11.9%						29.7%			9.6%
NGL weighting		24.0%			23.0%						22.5%			18.1%

Average Daily Production

		Three Months to September 30, 2021			Three Months to September 30, 2020			Period-over- period change			Nine Months to September 30, 2021			Nine Months to September 30, 2020			Period-over- period change
Crude oil (bbls/d)		2,862			340			2,522			2,253			169			2,085
Natural gas (Mcf/d)		7,462			374			7,088			8,390			135			8,256
NGLs (bbls/d)		1,294			120			1,173			1,061			42			1,018
Total (Boe/d)		5,399			523			4,877			4,712			233			4,479
Crude oil weighting		53.0%			65.1%						47.8%			72.3%
Natural gas weighting		23.0%			11.9%						29.7%			9.6%
NGL weighting		24.0%			23.0%						22.5%			18.1%

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

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

Revenue from Product Sales

		Three Months to September 30, 2021			Three Months to September 30, 2020			Nine Months to September 30, 2021			Nine Months to September 30, 2020
Crude oil	$	17,825,375		$	1,071,282		$	38,363,632		$	1,696,013
Natural gas		1,013,833			55,174			10,602,674			57,934
NGLs		4,587,867			113,423			6,922,921			113,843
Total	$	23,427,075		$	1,239,879		$	55,889,227		$	1,867,790
% of Total Revenue by Product Type
Crude oil weighting		76.09%			86.40%			68.64%			90.80%
Natural gas weighting		4.33%			4.45%			18.97%			3.10%
NGL weighting		19.58%			9.15%			12.39%			6.10%

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

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

Average Selling Prices

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

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

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

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Royalties

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

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

Production and Transportation Costs

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

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

Field Operating Netbacks

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

 

General and Administrative Costs

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

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

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

Interest and Finance Costs

Finance income and expense (net)
		Three Months to			Three Months to			Nine Months to			Nine Months to
		September 30, 2021			September 30, 2020			September 30, 2021			September 30, 2020
Charge for the period		10,991,673			1,000			16,751,963			65,185
Per Boe	$	22.13		$	0.02		$	13.02		$	1.02

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

Depletion and Depreciation

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

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

Net Income / (Loss) Attributable to ALPS

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

Investment and Financing

Long-term Debt

On December 22, 2020, the Company entered into a credit facility with Goldman Sachs (the "Goldman Facility"). All borrowings under the facility are secured by certain Company oil and gas producing wells as well as all assets of the Company's three subsidiaries. The Goldman Facility carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) and a maturity date of December 22, 2031. Interest payments are required quarterly. As at September 30, 2021, the Company had $28,144,040 (December 31, 2020 - $43,328,396) drawn under the facility. The Company's subsidiaries including AIP Holdco, LP, AIP Borrower LP have certain financial covenants under the Golden Facility, including;

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(i) Maintain a ratio of total net debt to adjusted EBITDAX of no more than 3.5 to 1.0, whereby net debt is effectively defined as all indebtedness of the Company less certain cash balances held in control accounts in which the lender holds a security interest, and adjusted EBITDAX is effectively defined as income before interest, taxes, depletion, amortization, extraordinary gains and losses and other non cash items annualized.

(ii) Maintain an unrestricted cash balance of no less than $1,000,000

(iii) Maintain a Measured Assets to Total Net Debt Ratio of at least 1.50 to 1.0, whereby Measured Assets is effectively defined as the present value of the Company's a) proved reserves, b) forward commodity contracts, c) abandonment liabilities related to proved producing reserves and d) other fixed costs associated with the proved producing reserves all discounted at 10% and Total Net Debt is defined as outlined in part i) to this note.

As at September 30, 2021, the Company was in compliance with all financial covenants.

Under the terms of the lending agreement, the Company is also required to;

i) As at the initial borrowing date, enter into certain forward commodity swap contracts included in Note 22 (c)(i) of the unaudited interim consolidated financial statements which it has done.

ii) Within 90 days of the initial borrowing date, enter into an interest rate swap contract to effectively fix the interest rate of at least 70% of the principal outstanding on the loan, at any given time for the term of the loan.  The Company entered into these swaps during the nine months ended September 30, 2021 (Note 22 (c)(ii)) of the interim consolidated financial statements.

iii) No later than December 31, 2021, establish an interest reserve account that will hold a cash balance sufficient to cover nine months of scheduled interest payments which it has not done but intends to prior to the required date of December 31, 2021.

 Repayments of principal required under the lending facility are as follows;

In addition to the required principal repayments outlined above, the Company's subsidiaries including AIP Holdco, LP, AIP Borrower LP could also be required to make additional payments of:

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i) If the ratio of adjusted EBITDAX to scheduled loan principal and interest payments for the period is less than 1.50 to 1.00, the Company must make an additional principal prepayment equal to Net Income/(Loss) adjusted for all non cash charges, plus/(minus) working capital not including the current portion of debt under this facility and other adjustments required under the terms of the agreement

ii) If the Company fails to meet its ratio (as defined above) of Measured Assets to total net debt of 1.50 to 1.00, the Company must make an additional principal prepayment sufficient to meet the 1.50:1.00 ratio.

At September 30, 2021, the Company was not subject to any other additional principal prepayments.             

Details of the loan balances are as follows:

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

Promissory and Convertible Promissory Notes

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

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

i) During the nine months ended September 30, 2021, the Company issued $1,075,000 in promissory notes for cash of which $75,000 were to an officer of the Company.

ii) During the nine months ended September 30, 2021, the Company issued 353,870 Origination Member Units in exchange for $3,475,000 in promissory notes (2020 - Nil) of which $600,000 were held by an officer of the Company.  In addition, the Company exchanged $1,000,000 of promissory notes in connection with the asset backed preferred instrument.

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iii) During the nine months ended September 30, 2021, the Company repaid $1,605,000 of promissory notes with cash and also offset $270,000 of promissory notes with agreed upon overhead expenses paid by the Company that was outstanding at December 31, 2020, which has been shown as a reduction of general and administrative expenses.

iv) In June 2021, the Company issued a series of unsecured, non-interest bearing convertible promissory notes to individuals in aggregate principal amount of US$2.3 million with a maturity date of sixty days from the date of issuance.  Per the terms of these convertible promissory notes, they are convertible into units of the Company at a conversion rate of $9.82/unit at the option of the noteholder or the Company.  On July 2, 2021, the Company exercised its option to convert all the existing convertible notes into 234,216 Origination Member Units effective as of July 7, 2021.

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

Deferred tax

Prior to the RTO, the Company was not subject to income taxes, because, as a Limited Liability Company it was treated as a pass-through entity for income tax purposes, as the members of the Company pay the income tax on their share of the LLC's taxable income.  As a result, the consolidated Statements of Financial Position and the consolidated Statements of Loss and Comprehensive Loss do not include items related to income taxes for the period before the RTO.  Subsequent to the RTO, the Company is taxed as a U.S. C Corporation and is subject to income tax on its share of pass-through taxable income from Origination, and any tax balances related to the Company, together with those of the acquired entity, are therefore part of these consolidated financial statements. Any income attributable to members outside the consolidated group is not reflected in the Company's consolidated Statement of Financial Position and the consolidated Statement of Loss and Comprehensive Loss.

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

Capital Expenditures

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

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

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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 September 30, 2021 corresponds to the Company's field capital expenditure program.

Decommissioning Liability

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

Risk Management - Commodity Contracts

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

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

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

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

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

Commodity	Expiry	Type	Average Price	Remaining Notional Total Volumes (1)	Index
Ethane (gallons)	Dec 2023	Swap	$0.20	5,347,608	NGL-Mont Belvieu
Propane (gallons)	Dec 2023	Swap	$0.52	3,287,866	NGL-Mont Belvieu
Natural gas (gallons)	Dec 2023	Swap	$0.95	2,106,699	NGL-Mont Belvieu
Iso butane (gallons)	Dec 2023	Swap	$0.56	687,956	NGL-Mont Belvieu
Nor butane (gallons)	Dec 2023	Swap	$0.57	1,599,625	NGL-Mont Belvieu
Natrual gas (mmbtu)	Dec 2028	Differential Swap	$0.07	2,833,007	Henry Hub -Nymex vs East TX
Natural gas (mmbtu)	Dec 2028	Swap	$2.61	2,712,266	Henry Hub -Nymex
Crude oil (bbl)	Dec 2028	Swap	$43.38	818,006	WTI-Nymex
Crude oil (bbl)	Nov 2021	Put	$50.00	50,000	WTI-Nymex
Crude oil (bbl)	Dec 2021	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Jan 2022	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Mar 2022	Put	$40.00	35,000	WTI-Nymex
Crude oil (bbl)	Apr 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	May 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	Jun 2022	Put	$40.00	20,000	WTI-Nymex
Crude oil (bbl)	Nov 2021	Short	$70.31	50,000	WTI-Nymex
Crude oil (bbl)	Dec 2021	Short	$68.64	40,000	WTI-Nymex
Crude oil (bbl)	Jan 2022	Short	$71.11	10,000	WTI-Nymex
Crude oil (bbl)	Feb 2022	Short	$70.51	10,000	WTI-Nymex
Crude oil (bbl)	Mar 2022	Short	$69.93	8,000	WTI-Nymex
Crude oil (bbl)	Apr 2022	Short	$69.36	10,000	WTI-Nymex
Crude oil (bbl)	May 2022	Short	$68.78	30,000	WTI-Nymex
Natural gas (mmbtu)	Nov 2021	Short	$4.879	10,000	Nat Gas-Nymex
Natural gas (mmbtu)	Dec 2021	Short	$4.994	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	Jan 2022	Short	$4.916	160,000	Nat Gas-Nymex
Natural gas (mmbtu)	Feb 2022	Short	$4.810	160,000	Nat Gas-Nymex
Natural gas (mmbtu)	Mar 2022	Short	$4.656	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	Apr 2022	Short	$3.694	30,000	Nat Gas-Nymex
Natural gas (mmbtu)	May 2022	Short	$3.578	30,000	Nat Gas-Nymex

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

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

Development Partnership 1

During the first quarter of 2021, the Company formed a Development Partnership ("DP") with 13 external limited partners and Origination as a limited partner and the general partner.  The intention of the DP is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%.  The Company has raised $13,140,240 from external limited partners of which $1,366,709 was raised from officers and directors of the Company.  Investors can choose to receive DP Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $3,243,728 in Flat Payout units and $9,896,512 in IRR based payout units. Flat Payout Units will participate in 75% of the income of the DP (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of the DP (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of the DP (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of the DP (along with Flat Payout Units).  The Company will receive 25% of the income of the DP before payout and will receive 80% and 94% of the income related to Flat and IRR based payout Units respectively after payout. 

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After payout, the external limited partners will also have a put right to effectively put their DP units (with ongoing rights to 20% and 6% of the income generated by the DP) back to the Company for either i) Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company) or ii) cash, subject to certain restrictions, and with the number of shares or cash to be distributed to be calculated based on future net present values of the oil and gas reserves of the DP.

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

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments. For the three and nine months ended September 30, 2021, an increase in the liability of $1,329,509 and $4,001,481, respectively, was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses.

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

Refer to the Subsequent Event section below for further disclosure related to the repayment of the first development partnership, subsequent to September 30, 2021.

Development partnership 2

During the third quarter of 2021, the Company formed a Development Partnership ("DP") with 26 external limited partners and Origination as a limited partner and the general partner.  The intention of the DP is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%.  The Company has raised $20,815,329 from external limited partners of which $1,724,967 was raised from officers and directors of the Company.  Investors can choose to receive DP Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $7,390,362 in Flat Payout units and $13,424,967 in IRR based payout units. Flat Payout Units will participate in 75% of the income of the DP (along with IRR based Payout Units) until that income equals their invested capital and thereafter will participate in 20% of the income of the DP (along with IRR based Payout Units). IRR Based Payout Units will participate in 75% of the income of the DP (along with Flat Payout Units) until that income equals their invested capital plus a 15% annualized return on invested capital or 120% of their initial investment, whichever is greater and thereafter will participate in 6% of the income of the DP (along with Flat Payout Units).  The Company will receive 25% of the income of the DP before payout and will receive 80% and 94% of the income related to Flat and IRR based payout Units respectively after payout. 

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After payout, the external limited partners will also have a put right to effectively put their DP units (with ongoing rights to 20% and 6% of the income generated by the DP) back to the Company for either i) Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company) or ii) cash, subject to certain restrictions, and with the number of shares or cash to be distributed to be calculated based on future net present values of the oil and gas reserves of the DP.

The Company, through the structure of the DP 2 Maverick, will maintain control of the DP 2 Maverick and will continue to consolidate 100% of the operations of the DP 2 Maverick.

The Company has categorized the development partnership liability as current based on the anticipated timing of repayments. For the three and nine months ended September 30, 2021, an increase in the liability of $8,308,892 was recorded related to the change in fair value of the liability with a corresponding increase in finance expenses.

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

Shareholder Takeout and Asset Backed Preferred Instrument

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

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

For the three and nine months ended September 30, 2021, the Company recorded finance expense related to the outstanding instrument in the amount of $532,592 and $1,310,975, respectively. 

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

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Shareholders' Capital

Authorized

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

Issued

			Origination Member Units			SVS			MVS			PVS			Amount
Balance at December 31, 2020 and 2019	Note		17,083,501			-			-			-		$	37,097,376
Issuance of member units for cash	13		819,215			-			-			-			8,044,700
Issuance of member units exchanged for promissory notes	13		353,870			-			-			-			3,475,000
Issuance of member units for exploration and evaluation assets	13		356,415			-			-			-			3,499,995
Issuance of member units to contractors	13		923,954			-			-			-			9,073,228
Redemption of member units	12		(3,992,629	)		-			-			-			(8,680,786	)
Issuance of member units exchanged for promissory notes	13		234,216			-			-			-			2,300,000
Origination Unit split 1:3	2		31,557,084			-			-			-			-
Allocation of opening non-controlling interest	14		(16,168,422	)		-			-			-			(18,721,276	)
Shares issued for cash, net of issuance costs of $247,218	2		-			161,976.000			17,057.000			-			5,499,832
Exchange of units for SVS and MVS	2		(31,167,204	)		1,427,421.000			297,397.830			-			-
Proportiante Voting Shares issued for cash	2		-			-			-			15,947.292			128,213
Shares issued on reverse takeover	2		-			534,384.000			-			-			1,697,865
Balance at September 30, 2021			-			2,123,781.000			314,454.830			15,947.292		$	43,414,147

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

During the nine months ended September 30, 2021, the Company issued 819,215 Origination Member Units for aggregate cash of $8,044,700 ($9.82/unit).  In addition, the Company issued 353,870 Origination Member Units in exchange for the retirement of $3,475,000 in promissory notes ($9.82/Unit). 

The Company entered into an agreement, with a third party, to acquire 16,201 net acres in the Eagle Ford formation, located in the Austin, Fayette, Lee and Washington counties of Texas.  In exchange for the acreage, the Company issued 203,666 Origination Member Units valued at $2,000,000 ($9.82/Unit). 

In addition, the Company issued 152,749 Origination Member Units, valued at $1,499,995 ($9.82/Unit) in exchange for approximately 630 net mineral acreage in Washington county, Texas.

In May of 2021, the Company issued 923,954 Origination Member Units to officers and consultants of the Company for services at an estimated value of $9.82 per Origination Member Unit for total consideration of $9,073,228 in connection with the listing application.

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

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

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

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

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

As a part of the reverse takeover the Company issued 534,384 SVS on September 7, 2021, for total consideration of $1,697,865 based on the Finco financing value of CDN$4.01/SVS or US$3.18/SVS, for the Red Pine net assets, which are made up primarily of cash valued at $396,173.  The excess of purchase consideration over net assets acquired resulted in a listing expenses of $1,301,692 and is presented in the interim consolidated statement of loss and comprehensive loss. 

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

Loss per share:

The Company had no options, or warrants outstanding for all periods ended September 30, 2021 and 2020.  The effect of the conversion of convertible promissory notes and NCI interests in Origination would be anti-dilutive and therefore have not been included in the calculation of diluted loss per share.

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

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Non-Controlling Interest

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

On closing the BCA, Origination's consolidated book value of net liabilities was $32,968,557, which results in an opening NCI balance of $10,714,781. This NCI balance along with the weighted average stated capital of the equity interests surrendered by the NCI holder of $18,721,276, for a total of $29,436, 057, has been credited to capital reserve.

For the 23 days of September, 2021 following the closing of the BCA, $3,355,382 was recorded to decrease net loss on the interim consolidated statement of operations and comprehensive loss, with an offset to NCI, representing NCI share of net loss for the 23 day period.

Related Party Transactions

Management Services Agreement

On December 22, 2020, the Company entered into a Management Services Agreement (the "MSA") with a company related by virtue of common equity holders, directors and officers.  Under this Agreement, the related Company provided management, finance, operations and administrative services.  The Agreement had an initial period of 11 years with a 90 day cancellation notice.  The Company was obligated pay for these services on a quarterly basis amounting to the lesser of; i) $2.00 per produced barrel of oil equivalent (converting natural gas to BOE equivalent of 6:1), and ii) 0.375% of measured assets as defined in the credit agreement.

During the nine months ended September 30, 2021, the Company incurred fees of $159,665 (three and nine months ended September 30, 2020 - $Nil) and is included in general and administrative expenses, of which $159,665 is included in accounts payable as at September 30, 2021 (December 31, 2020 - $20,000).  In the second quarter of 2021, the MSA was effectively terminated by assigning the MSA to one of the Company's subsidiaries, thereby eliminating the requirement to pay any fees going forward as outlined above.

In the second quarter of 2021, the Company entered into a new Letter Agreement (the "Letter") with the same related company by virtue of common equity holders, directors and officers.  The Letter requires the Company to hire its own employees, obtain its own office lease and assume certain management obligations. In exchange, the Company is paid an annual fee of $1,000,000 on a quarterly basis.  During the nine months ended September 30, 2021, the Company was paid $215,080 via a payroll credit and $166,667 in cash, with a corresponding decrease to general and administrative expenses in the statement of income and loss. The Company expects to be paid $250,000 for services provided in the fourth quarter of 2021.

Related party balances

At September 30, 2021, accounts receivable includes $80,000 (December 31, 2020 - $Nil) owed to the Company by officers of the Company and companies controlled by the officers of the Company.  These amounts are due as a result of the related parties being joint interest parties in certain wells operated by the Company.  These amounts were received subsequent to September 30, 2021.

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At September 30, 2021, the accounts payable included $105,191 (December 31, 2020 - accounts receivable of $75,612) due from a company related by virtue of common equity holders, officers and directors under normal credit terms

Liquidity Risk 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 September 30, 2021, the Company had negative working capital of $80,891,770.  The Company expects to repay its financial liabilities in the normal course of operations and to fund future operational and capital requirements through operating cash flows and through issuance of debt and/or equity.

The Company may need to conduct asset sales, equity issues or issue debt if liquidity risk increases in a given period.  Liquidity risk may increase as a result of a change in the amounts settled monthly from the commodity contracts. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans/notes, asset sales, coordinating payment and revenue cycles each month, and an active commodity hedge program to mitigate commodity price risk and secure cash flows.

More specifically, in an attempt to increase liquidity, the Company has during and subsequent to the nine months ended September 30, 2021 i) issued convertible promissory notes for cash, ii) commenced a drilling program to increase cash flows from operating activities, iii) raised significant funds through two development partnerships, iv) settled promissory notes with a combination of cash and Origination Member Units and v) entered into a new revolving credit facility.

The Company is required to meet certain financial covenants under the Goldman Facility.  As at September 30, 2021, the Company was not in any breach of financial covenants in place.

The following table details the Company's financial liabilities and their scheduled maturities as at September 30, 2021;

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		Carrying value			Contractual cash flow			Less than one year			1 - 3 years			Greater than 3 years
Accounts payable and accrued liabilities	$	36,087,969		$	36,087,969		$	36,087,969		$	-		$	-
Commodity contracts		29,627,332			29,627,332			14,709,808			7,988,934			6,928,590
Promissory notes		150,000			150,000			150,000			-			-
Lease liability		485,975			485,975			78,745			407,230			-
Asset backed preferred instrument		18,140,975			18,140,975			-			18,140,975			-
Development partnerships liabilities		44,412,815			49,767,346			41,260,520			4,068,092			4,438,734
Long-term debt		25,911,374			28,144,040			9,185,127			11,602,604			7,356,309
Total	$	154,816,440		$	162,403,637		$	101,472,169		$	42,207,835		$	18,723,633

Going Concern

The financial statements have been prepared in accordance with IFRS applicable to a going concern, which assumes that the Company will be able to realize its assets and discharge its liabilities in the normal course of business.

During the nine months ended September 30, 2021, the Company generated a net loss and comprehensive loss of $51,614,575 (year ended December 31, 2020 - $7,530,178), and as at that date, the Company had a working capital deficiency of $80,891,770 (December 31, 2020 - working capital deficiency of $29,102,456) and accumulated deficit of $92,542,554 (December 31, 2020 - $39,757,844).

In order to continue operating as a going concern the Company will need to achieve profitable operations and/or secure additional sources of financing in order to satisfy its obligations, including scheduled repayments of long-term debt, as they become due.  During the nine months ended September 30, 2021 the Company issued 1,173,085 Origination Member Units in exchange for cash of $8.0 million, 161,976 SVS and 17,057 MVS for cash of $5.5 million net of issuance costs, and extinguished promissory notes of $3.5 million. The Company formed two development partnerships to fund a portion of 2021 capital activity which raised approximately $34 million during the nine months ended September 30, 2021 and subsequent to period end.  In addition, the Company issued convertible promissory notes in June 2021 for proceeds of $2.3 million and converted those convertible promissory notes into 234,216 Origination Member Units.  The Company also repaid $15.2 million of long-term debt and $4.7 million of asset backed preferred instruments. Although the Company has been successful in its financing activities to date, additional financing may be required to continue operations and such funding may not be available on terms that are acceptable to the Company.

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

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Subsequent Events

Completion of DP1

On October 7, 2021, the Company repaid and paid out the reversion of the first development partnership ("DP1") that it formed during the first quarter of 2021.

DP1 funded the drilling and completion of five wells in the Giddings Field near Austin, TX and comprised a total capital program of approximately $21.3 million, with 60% funded by external partners. As part of the completion of the DP1 Maverick program, Company has retired liabilities of $15,288,594.

One of the DP1 Maverick partners exercised the put right provided to such partners by DP1 Maverick regarding residual interests in their associated investment and elected to exchange the remaining interest in DP1 Maverick for 339,372 Class B non-voting units of HB2 Origination, LLC (which are exchangeable on a one-for-one basis for Subordinate Voting Shares of the Company, having a deemed value of US$3.515 per unit, or a total of approximately US$1.2 million).

On October 7, 2021, the Company formed a third Development Partnership ("DP3") with 23 external limited partners and HB2 as a limited partner and the general partner.  The intention of the DP3 is to finance the drilling and completion of 5 wells, with the external partners funding approximately 60% and the Company funding 40%.  The Company has raised $21,182,826 from external limited partners of which $4,032,672 was raised from officers and directors of the Company.  Investors can choose to receive DP3 Units that distribute profits either based on a Flat payout option or an IRR based payout option.  Investors have participated as to $10,413,322 in Flat Payout units and $10,769,504 in IRR based payout units.

The terms of the units are substantially the same compared to those of the first and second development partnerships.

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

Revolving Credit Facility

In October, 2021, the Company's operating subsidiary Origination closed on a corporate credit facility.  The facility has a maximum of $12.5 million, subject to quarterly borrowing base determinations by the lender.  The borrowing base is currently set at $6,579,750.  The loan charges interest at prime +2.25% and has a one year maturity.  A subset of certain Company working interests in producing assets have been secured in connection with the facility

Quarterly Results

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

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Quarter ended September 30, 2021

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

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

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

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

Outstanding Securities

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

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

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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;
• 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;
• 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;

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• 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 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.

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

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

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

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

Field Operating Netbacks

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.

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

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

Business Risks 

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

Crude Oil and Natural Gas Prices and General Economic Conditions

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

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

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

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

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

Property Exploration

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

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

• prospects are internally generated;

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

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

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

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

Commodity Price Fluctuations

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

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Adverse Well or Reservoir Performance

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

Field Operations

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

Retention of Key Personnel

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

Environmental

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

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

Industry Capacity Constraints

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

Capital Programs

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

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Reserve Estimates

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

Production

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

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

Financial and Liquidity Risks

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

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

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

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

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

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

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

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

Marketing Risks

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

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

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

Access to Debt and Equity

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

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

Changes in Government Regulations, Royalties and Policies

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

Cyber-Security

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

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Extraordinary Circumstances

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

Global Health Crises

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

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

Additional Information

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

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Form 52-109FV2
Certification of Interim Filings
Venture Issuer Basic Certificate

I, Craig Perry, Chief Executive Officer of Alpine Summit Energy Partners, Inc., certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the "interim filings") of Alpine Summit Energy Partners, Inc. (the "issuer") for the interim period ended September 30, 2021.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

Date: November 23, 2021

"Craig Perry"

Craig Perry Chief Executive Officer

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Form 52-109FV2
Certification of Interim Filings
Venture Issuer Basic Certificate

I, Darren Moulds, Chief Financial Officer of Alpine Summit Energy Partners, Inc., certify the following:

1. Review: I have reviewed the interim financial report and interim MD&A (together, the "interim filings") of Alpine Summit Energy Partners, Inc. (the "issuer") for the interim period ended September 30, 2021.

2. No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3. Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

Date: November 23, 2021

"Darren Moulds"

Darren Moulds Chief Financial Officer

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