Headwater Exploration : Q2 2022 MD&A

Q2 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 August 4, 2022 and should be read in conjunction with the unaudited interim condensed financial statements as at and for the three and six months ended June 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 JUNE 30, 2022

• Realized record adjusted funds flow from operations (1) of $79.4 million ($0.35 per share basic) and cash flows from operating activities of $84.7 million ($0.37 per share basic) representing an increase of 243% and 265%, respectively, over the second quarter of 2021.
• Recognized net income of $48.4 million ($0.21 per share basic) representing an increase of over 950% from the second quarter of 2021.
• Generated free cash flow (3) of $48.6 million.
• Achieved a record operating netback (2) of $81.05/boe and an adjusted funds flow netback (2) of $74.57/boe representing an increase of 103% and 95%, respectively, over the second quarter of 2021.
• Production averaged 11,772 boe/d (consisting of 10,637 bbls/d of heavy oil, 6.4 mmcf/d of natural gas and 66 bbls/d of natural gas liquids) representing an increase of 79% from the second quarter of 2021.
• Executed a $30.9 million capital expenditure (3) program including 5 successful Clearwater A wells in Marten Hills West plus 9 injection wells and 4 water source wells in Marten Hills as part of
  Headwater's enhanced oil recovery acceleration project.
• Headwater has been approved for total funding of up to $18.5 million from Natural Resources
  Canada ("NRCan") associated with the Emissions Reduction Fund ("ERF") program for infrastructure spend related to the elimination of venting and flaring of methane rich natural gas in the Company's core area of Marten Hills.
• As at June 30, 2022, Headwater had adjusted working capital (1) of $130.2 million, working capital of $127.1 million and no outstanding bank debt.

1

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.

RESULTS OF OPERATIONS

Production and Pricing

	Three months ended		Six months ended
	June 30,	Percent	June 30,	Percent
	2022	2021	Change	2022	2021	Change
Average daily production
Heavy oil (bbls/d)	10,637	6,185	72	10,620	4,793	122
Natural gas (mmcf/d)	6.4	2.3	178	8.6	5.4	59
Natural gas liquids (bbls/d)	66	5	1220	36	5	620
Barrels of oil equivalent (boe/d)	11,772	6,565	79	12,091	5,690	112
Average daily sales (1)
Heavy oil (bbls/d)	10,571	6,273	69	10,579	4,818	120
Natural gas (mmcf/d)	6.4	2.3	178	8.6	5.4	59
Natural gas liquids (bbls/d)	66	5	1220	36	5	620
Barrels of oil equivalent (boe/d)	11,705	6,653	76	12,050	5,715	111
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	121.49	64.20	89	110.20	61.27	80
Natural gas ($/mcf)	7.28	2.76	164	12.51	6.48	93
Natural gas liquids ($/bbl)	113.61	73.99	54	113.12	70.14	61
Barrels of oil equivalent ($/boe)	114.34	61.52	86	106.03	57.79	83
Average Benchmark Price
WTI (US$/bbl) (4)	108.41	66.07	64	101.35	61.96	64
WCS differential to WTI (US$/bbl)	(12.80)	(11.49)	11	(13.67)	(11.98)	14
WCS (Cdn$/bbl) (5)	122.09	66.99	82	111.55	62.21	79
Condensate at Edmonton (Cdn$/bbl)	137.86	81.00	70	131.17	76.96	70
AGT (US$/mmbtu) (6)	6.49	2.33	179	11.88	4.68	154
AECO 5A (Cdn$/GJ)	6.86	2.93	134	5.73	2.96	94
NYMEX Henry Hub (US$/mmbtu)	7.17	2.83	153	6.06	2.76	120
Exchange rate (US$/Cdn$)	0.78	0.81	(4)	0.78	0.80	(2)

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

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		Three months ended		Six months ended
		June 30,	Percent	June 30,	Percent
		2022	2021	Change	2022	2021	Change
		(thousands of dollars)		(thousands of dollars)
Heavy oil sales	124,919	39,257	218	228,292	58,412	291
Blending expense	(8,051)	(2,609)	209	(17,291)	(4,978)	247
Heavy oil, net of blending (1)	116,868	36,648	219	211,001	53,434	295
Natural gas	4,249	566	651	19,501	6,284	210
Natural gas liquids	677	31	2084	747	62	1105
Gathering, processing and transportation	308	184	67	875	772	13
Total sales, net of blending expense (1)		122,102	37,429	226	232,124	60,552	283

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 June 30, 2022, Headwater's heavy oil sales, net of blending expense, increased to $116.9 million from $36.6 million in the comparable period of 2021. This increase was attributable to an 89% increase in realized commodity pricing and a 69% increase in sales volumes. During the six months ended June 30, 2022, Headwater's heavy oil sales, net of blending expense, increased to $211.0 million from $53.4 million in the comparable period of 2021. This increase was attributable to an 80% increase in realized commodity pricing and a 120% increase in sales volumes.

The WTI crude price has strengthened significantly over both the three and six months ended June 30, 2022, due to increased demand for crude oil following the global recovery from the COVID-19 pandemic in addition to international energy supply concerns associated with the Russia-Ukraine war. The WCS differential to WTI remained narrow due to improved market access out of western Canada. The Company's heavy oil realized price for the three months ended June 30, 2022, was $121.49/bbl, reflecting a discount to WCS of $0.60/bbl, while the Company's heavy oil realized price for the six months ended June 30, 2022, was $110.20/bbl, reflecting a discount to WCS of $1.35/bbl. The discount to WCS narrowed during the three months ended June 30, 2022, due to selling more volumes at higher commodity pricing in the month of June, in addition to blending more heavy crude oil volumes with butane versus condensate. The realized price for butane was approximately 40% less than the realized price for condensate in the quarter.

During the three months ended June 30, 2022, Headwater's heavy oil sales volumes averaged 10,571 bbls/d compared to 6,273 bbls/d in the same period of 2021, while Headwater's heavy oil sales volumes averaged 10,579 bbls/d during the six months ended June 30, 2022, compared to 4,818 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 first half 2022 capital expenditure programs. Headwater drilled 51.0 total net crude oil wells during the year ended December 31, 2021, and drilled 41.0 total net crude oil wells in the first half of 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 4.6 mmcf/d with natural gas sales of $3.0 million in the three months ended June 30, 2022, while natural gas sales volumes were 3.8 mmcf/d with natural gas sales of $4.2 million in the six months ended June 30, 2022. Headwater's associated liquids production averaged 62 bbls/d with sales of $0.6 million in the three months ended June 30, 2022.

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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 upcoming summer season effective May 1, 2022.

During the six months ended June 30, 2022, Headwater's natural gas sales out of its McCully field increased to $15.3 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.

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		Six months ended
	June 30,	Percent	June 30,	Percent
	2022	2021	Change	2022	2021	Change
	(thousands of dollars)		(thousands of dollars)
Realized gains (losses)	(258)	146	(277)	(4,203)	(405)	938
Unrealized losses	(2,801)	(1,458)	92	(2,931)	(1,712)	71
Financial derivative losses	(3,059)	(1,312)	133	(7,134)	(2,117)	237
Per boe	(2.87)	(2.17)	32	(3.27)	(2.05)	60

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 six months ended June 30, 2022, represent the Company's natural gas contracts referenced to the AGT price.

A realized financial derivative loss was recorded during the three and six months ended June 30, 2022, of $0.3 million and $4.2 million, respectively, compared to a realized gain of $0.1 million in the three months ended June 30, 2021, and a realized loss of $0.4 million in the six months ended June 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 three and six months ended June 30, 2022, due to increased natural gas demand following the global recovery from the COVID-19 pandemic. North American east coast temperatures and natural gas storage levels are the main variables impacting the AGT settlement price.

As at June 30, 2022, the fair value of Headwater's outstanding financial derivative contracts was a net unrealized liability of $6.6 million as reflected in the 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 June 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

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as at June 30, 2022. For the three and six months ended June 30, 2022, Headwater recognized unrealized losses of $2.8 million and $2.9 million, respectively, compared to unrealized losses of $1.5 million and $1.7 million in the corresponding periods of 2021.

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

	Buy	Sell		Notional
Type	Currency	Currency	Rate	Amount	Settlement Date
Forward contract	USD	CAD	June 2022 average (1)	US$42.0 million	July 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		Six months ended
	June 30,	Percent	June 30,	Percent
	2022	2021	Change	2022	2021	Change
	(thousands of dollars)		(thousands of dollars)
Heavy oil	24,853	5,334	366	40,893	7,467	448
Natural gas and natural gas liquids	551	17	3141	1,349	239	464
Total royalty expense	25,404	5,351	375	42,242	7,706	448
Percentage of total sales, net of blending (1)	20.8%	14.3%	45	18.2%	12.7%	43
Per boe	23.85	8.84	170	19.37	7.45	160

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 until the well's total revenue exceeds the Drilling and Completion Cost Allowance (C*), then royalty rates increase on a sliding scale up to 40% depending on commodity reference pricing.

For the three and six months ended June 30, 2022, royalty expense increased to $25.4 million and $42.2 million, respectively, from $5.4 million and $7.7 million in the comparable periods of 2021, due to a significant increase in heavy oil sales volumes and commodity pricing.

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