Headwater Exploration : Q3 2022 MD&A

Q3 2022 Management's Discussion and Analysis

The following management's discussion and analysis ("MD&A") as provided by the management of Headwater Exploration Inc. ("Headwater" or the "Company") is dated November 3, 2022 and should be read in conjunction with the unaudited interim condensed financial statements as at and for the three and nine months ended September 30, 2022, and the MD&A and the audited financial statements and the notes thereto for the year ended December 31, 2021, copies of which are available through the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com. The unaudited interim condensed financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and in accordance with IAS 34 Interim Financial Reporting. All dollar amounts are referenced in Canadian dollars unless otherwise stated.

DESCRIPTION OF THE COMPANY

Headwater is a Canadian resource company engaged in the exploration for and development and production of petroleum and natural gas in Canada. Headwater currently has heavy oil production in the Clearwater formation in the Marten Hills area of Alberta and natural gas production in the McCully field near Sussex, New Brunswick.

Unless otherwise indicated herein, all production information presented herein has been presented on a gross basis, which is the Company's working interest prior to deduction of royalties and without including any royalty interests.

HIGHLIGHTS FOR THREE MONTHS ENDED SEPTEMBER 30, 2022

• Realized adjusted funds flow from operations (1) of $58.4 million ($0.25 per share basic) and cash flows from operating activities of $72.1 million ($0.31 per share basic) representing an increase of 85% and 158%, respectively, over the third quarter of 2021.
• Recognized net income of $31.5 million ($0.14 per share basic) representing an increase of 21% from the third quarter of 2021.
• Achieved an operating netback (2) of $56.54/boe and an adjusted funds flow netback (2) of $54.39/boe representing an increase of 22% and 21%, respectively, over the third quarter of 2021.
• Production averaged 11,612 boe/d (consisting of 10,842 bbls/d of heavy oil, 4.3 mmcf/d of natural gas and 55 bbls/d of natural gas liquids) representing an increase of 51% from the third quarter of 2021.
• Executed a $71.0 million capital expenditure (3) program including 9 successful exploration wells in Marten Hills West plus 8 injection wells in Marten Hills as part of Headwater's enhanced oil recovery project. The Company added 8.25 sections of additional crown lands prospective for Clearwater oil in the Greater Peavine Area.
• As at September 30, 2022, Headwater had adjusted working capital (1) of $118.0 million, working capital of $113.4 million and no outstanding bank debt.

1. Refer to "Management of capital" in note 12 of the interim financial statements and to "Non-GAAP and Other Financial Measures" within this MD&A.
2. Non-GAAPratio that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.
3. Non-GAAPmeasure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.

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HIGHLIGHTS SUBSEQUENT TO SEPTEMBER 30, 2022

• Subsequent to September 30, 2022, the Company declared its inaugural quarterly cash dividend of $0.10 per common share. The dividend will be payable on January 16, 2023, to shareholders of record at the close of business on December 30, 2022. This dividend is designated as an eligible dividend for Canadian income tax purposes.
• Headwater has executed a commitment letter for a credit facility in the amount of $100.0 million with a senior lender and expects to have a credit facility agreement executed in the fourth quarter of 2022. Headwater does not intend to draw on the credit facility at current commodity pricing.

RESULTS OF OPERATIONS

Production and Pricing

	Three months ended		Nine months ended
	September 30,	Percent	September 30,	Percent
	2022	2021	Change	2022	2021	Change
Average daily production
Heavy oil (bbls/d)	10,842	7,637	42	10,695	5,751	86
Natural gas (mmcf/d)	4.3	0.3	1333	7.2	3.7	95
Natural gas liquids (bbls/d)	55	-	100	43	3	1333
Barrels of oil equivalent (boe/d)	11,612	7,688	51	11,929	6,363	87
Average daily sales (1)
Heavy oil (bbls/d)	10,910	7,562	44	10,690	5,743	86
Natural gas (mmcf/d)	4.3	0.3	1333	7.2	3.7	95
Natural gas liquids (bbls/d)	55	-	100	43	3	1333
Barrels of oil equivalent (boe/d)	11,680	7,613	53	11,925	6,355	88
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	92.35	70.00	32	104.06	65.15	60
Natural gas ($/mcf)	4.23	4.49	(6)	10.84	6.43	69
Natural gas liquids ($/bbl)	95.54	-	100	105.51	70.14	50
Barrels of oil equivalent ($/boe)	88.27	69.71	27	100.17	62.60	60
Average Benchmark Price
WTI (US$/bbl) (4)	91.56	70.56	30	98.09	64.82	51
WCS differential to WTI (US$/bbl)	(19.86)	(13.58)	46	(15.73)	(12.51)	26
WCS (Cdn$/bbl) (5)	93.54	71.81	30	105.55	65.41	61
Condensate at Edmonton (Cdn$/bbl)	118.78	86.78	37	127.04	80.23	58
AGT (US$/mmbtu) (6)	-	-	-	11.88	4.68	154
AECO 5A (Cdn$/GJ)	3.95	3.41	16	5.14	3.11	65
NYMEX Henry Hub (US$/mmbtu)	8.20	4.01	104	6.77	3.18	113
Exchange rate (US$/Cdn$)	0.77	0.79	(3)	0.78	0.80	(3)

1. Includes sales of heavy crude oil excluding the impact of purchased condensate and butane. The Company's heavy oil sales volumes and production volumes differ due to changes in inventory.
2. Average sales prices are calculated using average sales volumes.
3. Realized heavy oil prices are based on sales, net of blending expense.
4. WTI = West Texas Intermediate
5. WCS = Western Canadian Select
6. AGT = Algonquin city-gates. The AGT price is the average for the winter producing months in the McCully field which include January to April.

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		Three months ended		Nine months ended
		September 30,	Percent	September 30,	Percent
		2022	2021	Change	2022	2021	Change
		(thousands of dollars)		(thousands of dollars)
Heavy oil sales	97,335	49,984	95	325,627	108,396	200
Blending expense	(4,638)	(1,282)	262	(21,929)	(6,261)	250
Heavy oil, net of blending (1)	92,697	48,702	90	303,698	102,135	197
Natural gas	1,669	127	1214	21,170	6,411	230
Natural gas liquids	482	-	100	1,229	62	1882
Gathering, processing and transportation	101	12	742	976	784	24
Total sales, net of blending expense (1)		94,949	48,841	94	327,073	109,392	199

1. Non-GAAPmeasure. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.

Marten Hills

The Company's realized price received for its heavy crude oil is determined by the quality of crude compared to the benchmark price of WCS. Headwater's heavy crude oil production (average 18 - 22˚ API) is blended with diluent in order to meet pipeline transportation specifications.

During the three months ended September 30, 2022, Headwater's heavy oil sales, net of blending expense, increased to $92.7 million from $48.7 million in the comparable period of 2021. This increase was attributable to a 32% increase in realized commodity pricing and a 44% increase in sales volumes. During the nine months ended September 30, 2022, Headwater's heavy oil sales, net of blending expense, increased to $303.7 million from $102.1 million in the comparable period of 2021. This increase was attributable to a 60% increase in realized commodity pricing and an 86% increase in sales volumes.

The WTI crude price has strengthened significantly over both the three and nine months ended September 30, 2022, due to increased global demand for crude oil following the recovery from the COVID-19 pandemic in addition to international energy supply concerns associated with the Russia-Ukraine war. The WCS differential to WTI widened during the three months ended September 30, 2022, due to reduced US Gulf Coast demand primarily as a result of increased refinery maintenance and outages. The Company's heavy oil realized price for the three months ended September 30, 2022, was $92.35/bbl, reflecting a discount to WCS of $1.19/bbl, while the Company's heavy oil realized price for the nine months ended September 30, 2022, was $104.06/bbl, reflecting a discount to WCS of $1.49/bbl. The discount to WCS narrowed during the three months ended September 30, 2022, due to blending more heavy crude oil volumes with butane versus condensate. The realized price for butane was approximately 39% less than the realized price for condensate in the third quarter of 2022.

Headwater expects to see continued widening of the WCS differential to WTI into the fourth quarter of 2022, due to weaker US Gulf Coast demand associated with increased supply and refinery maintenance and outages.

During the three months ended September 30, 2022, Headwater's heavy oil sales volumes averaged 10,910 bbls/d compared to 7,562 bbls/d in the same period of 2021, while Headwater's heavy oil sales volumes averaged 10,690 bbls/d during the nine months ended September 30, 2022, compared to 5,743 bbls/d in the same period of 2021. The Company's heavy oil sales volumes have increased significantly as a result of Headwater's extensive 2021 and 2022 capital expenditure programs. Headwater drilled 51.0 total net crude oil wells during the year ended December 31, 2021, and drilled 67.0 total net crude oil wells in the nine months ended September 30, 2022, substantially increasing the Company's heavy oil production in the Marten Hills area.

Headwater processes its natural gas production through its Marten Hills joint natural gas processing facility which was commissioned in the third quarter of 2021. The natural gas transaction price is based on the AECO 5A daily benchmark price adjusted for delivery location and heat content. Headwater's natural gas sales volumes averaged 4.3 mmcf/d with natural gas sales of $1.7 million in the three months ended

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September 30, 2022, while natural gas sales volumes were 4.0 mmcf/d with natural gas sales of $5.8 million in the nine months ended September 30, 2022. Headwater's associated natural gas liquids production averaged 55 bbls/d with sales of $0.5 million in the three months ended September 30, 2022.

McCully

The Company produces natural gas out of the McCully field in New Brunswick. The transaction price is based on the AGT daily benchmark price adjusted for delivery location and heat content. In recent years, the AGT market has been characterized by excess demand during the winter season resulting in a significant premium in the sales price as compared to prices during other periods of the year. Consistent with prior years, the Company shut-in production for the summer season effective May 1, 2022.

During the nine months ended September 30, 2022, Headwater's natural gas sales out of its McCully field increased to $15.4 million from $6.3 million in the same period of the prior year due to a significant increase in realized prices. The increase in Headwater's average realized natural gas sales price was consistent with the increase in the AGT benchmark price over the period. AGT benchmark pricing has increased as a result of lower than average natural gas storage levels and closer ties to Europe LNG pricing.

Headwater owns the midstream facilities which process and transport natural gas from the McCully field to the Maritimes & Northeast Pipeline. Gathering, processing and transportation revenue primarily relates to income earned on third party gas flowing through these facilities. This revenue will vary quarter over quarter depending on the amount of third-party volumes processed.

Financial Derivative Losses

	Three months ended		Nine months ended
	September 30,	Percent	September 30,	Percent
	2022	2021	Change	2022	2021	Change
	(thousands of dollars)		(thousands of dollars)
Realized losses	-	-	-	(4,203)	(405)	938
Unrealized losses	(401)	(7,346)	(95)	(3,332)	(9,058)	(63)
Financial derivative losses	(401)	(7,346)	(95)	(7,535)	(9,463)	(20)
Per boe	(0.37)	(10.49)	(96)	(2.31)	(5.45)	(58)

Headwater enters into financial derivative commodity contracts to manage the risks associated with fluctuations in commodity prices.

The realized financial derivative losses incurred during the three and nine months ended September 30, 2022, represent the Company's natural gas contracts referenced to the AGT price.

A realized financial derivative loss was recorded during the nine months ended September 30, 2022, of $4.2 million compared to a realized loss of $0.4 million in the nine months ended September 30, 2021, for the Company's natural gas contracts settled. The Company recognized losses on its natural gas contracts as the commodity contracts to fix the AGT price were lower when compared to the AGT settlement price in the periods. The AGT settlement price exceeded the contract price during the nine months ended September 30, 2022, due to increased natural gas demand following the global recovery from the COVID- 19 pandemic and closer ties to Europe LNG pricing. North American east coast temperatures and natural gas storage levels are the main variables impacting the AGT settlement price.

The unrealized losses recorded are a result of the change in fair value of the Company's outstanding financial derivative contracts over the periods. As at September 30, 2022, the fair value of Headwater's outstanding financial derivative contracts was a net unrealized liability of $8.1 million as reflected in the

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interim financial statements. The fair value or mark to market value of these contracts is based upon the estimated amount that would have been payable as at September 30, 2022, had the contracts been monetized or terminated. Subsequent changes in the fair value of the contracts are recognized in each reporting period and could be materially different than what is recorded as at September 30, 2022. For the three and nine months ended September 30, 2022, Headwater recognized unrealized losses of $0.4 million and $3.3 million, respectively, compared to unrealized losses of $7.3 million and $9.1 million in the corresponding periods of 2021.

As at September 30, 2022, Headwater had the following financial derivative commodity contracts outstanding:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Natural Gas	AGT	Fixed	Dec 2022	2,500 mmbtu	Cdn$39.22/mmbtu
Natural Gas	AGT	Fixed	Dec 2022- Mar 2023	2,500 mmbtu	Cdn$17.91/mmbtu
Natural Gas	AGT	Fixed	Jan 2023- Feb 2023	2,500 mmbtu	Cdn$32.71/mmbtu
Crude Oil	WCS Basis	Differential	Oct 2022- Dec 2022	1,000 bbls	US$15.75/bbl

The Company is exposed to fluctuations of the Canadian to U.S. dollar exchange rate given realized pricing is directly influenced by U.S. dollar denominated benchmark pricing and from exposure to its U.S. dollar denominated heavy oil and natural gas marketing arrangements.

Headwater mitigates this risk by entering into commodity contracts in Canadian dollars and entering into short-term foreign exchange contracts.

As at September 30, 2022, Headwater had the following financial derivative foreign exchange contract outstanding:

	Buy	Sell		Notional Amount
Type	Currency	Currency	Rate		Settlement Date
Forward contract	CAD	USD	September 2022 average (1)	US$28.0 million	October 26, 2022

1. WM/Reuters Intraday Spot Rate as of Noon EST
2. Unrealized change in fair value related to the Company's foreign exchange contracts is included in interest income and other expense in the interim financial statements.

Royalty Expense

	Three months ended		Nine months ended
	September 30,	Percent	September 30,	Percent
	2022	2021	Change	2022	2021	Change
	(thousands of dollars)		(thousands of dollars)
Heavy oil	22,952	7,303	214	63,845	14,771	332
Natural gas and natural gas liquids	616	20	2980	1,965	258	662
Total royalty expense	23,568	7,323	222	65,810	15,029	338
Percentage of total sales, net of blending (1)	24.8%	15.0%	65	20.1%	13.7%	47
Per boe	21.93	10.46	110	20.21	8.66	133

1. Non-GAAPratio. Refer to the advisory "Non-GAAP and Other Financial Measures".

Royalty expense consists of crown royalties payable to the Alberta and New Brunswick provincial governments and the gross overriding royalty ("GORR") payable to Topaz Energy Corp. Under the Alberta Modernized Royalty Framework ("MRF"), the Company will pay a flat royalty of 5% on a well's production

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