Headwater Exploration : Q2 2023 MD&A

Q2 2023 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 3, 2023 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, 2023, and the MD&A and the audited financial statements and the notes thereto for the year ended December 31, 2022, copies of which are available through the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedarplus.ca. The unaudited interim condensed financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting as issued by the International Accounting Standards Board ("IASB"). 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 and reserves in the Clearwater formation in the Marten Hills, West Nipisi and Greater Peavine areas of Alberta and natural gas production and reserves 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, 2023

• Returned $23.5 million to shareholders. Since announcing the Company's inaugural dividend in November 2022, Headwater has returned a total of $70.5 million to shareholders.
• Achieved record production averaging 17,152 boe/d (consisting of 15,624 bbls/d heavy oil, 8.5 mmcf/d natural gas and 107 bbls/d natural gas liquids), representing an increase of 46% from the second quarter of 2022. The Alberta wildfires had minimal impact on Headwater's production during the period.
• Achieved an operating netback, including financial derivatives (2) of $46.88/boe and an adjusted funds flow netback (2) of $42.44/boe.
• Realized adjusted funds flow from operations (1) of $66.2 million ($0.28 per share basic) and cash flows from operating activities of $66.9 million ($0.28 per share basic).
• Recognized net income of $30.9 million ($0.13 per share basic).
• Executed a $64.1 million capital expenditure (3) program inclusive of $8.5 million of land expenditures adding a total of 90 sections of undeveloped acreage, while also focusing on development in Marten Hills West, drilling a total of 24 crude oil wells in the area at a 100% success rate.
• As at June 30, 2023, Headwater had adjusted working capital (1) of $49.0 million, working capital of $54.8 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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RESULTS OF OPERATIONS

Production and Pricing

	Three months ended		Six months ended
	June 30,	Percent	June 30,	Percent
	2023	2022	Change	2023	2022	Change
Average daily production
Heavy oil (bbls/d)	15,624	10,637	47	15,203	10,620	43
Natural gas (mmcf/d)	8.5	6.4	33	10.7	8.6	24
Natural gas liquids (bbls/d)	107	66	62	99	36	175
Barrels of oil equivalent (boe/d)	17,152	11,772	46	17,078	12,091	41
Average daily sales (1)
Heavy oil (bbls/d)	15,625	10,571	48	15,186	10,579	44
Natural gas (mmcf/d)	8.5	6.4	33	10.7	8.6	24
Natural gas liquids (bbls/d)	107	66	62	99	36	175
Barrels of oil equivalent (boe/d)	17,154	11,705	47	17,061	12,050	42
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	77.14	121.49	(37)	71.48	110.20	(35)
Natural gas ($/mcf)	2.51	7.28	(66)	4.35	12.51	(65)
Natural gas liquids ($/bbl)	75.01	113.61	(34)	71.13	113.12	(37)
Barrels of oil equivalent ($/boe)	71.98	114.34	(37)	66.75	106.03	(37)
Average Benchmark Price
WTI (US$/bbl) (4)	73.78	108.41	(32)	74.95	101.35	(26)
WCS differential to WTI (US$/bbl)	(15.13)	(12.80)	18	(19.95)	(13.67)	46
WCS (Cdn$/bbl) (5)	78.77	122.09	(35)	74.12	111.55	(34)
Condensate at Edmonton (Cdn$/bbl)	96.12	137.86	(30)	100.79	131.17	(23)
AGT (US$/mmbtu) (6)	1.90	6.49	(71)	4.32	11.88	(64)
AECO 5A (Cdn$/GJ)	2.32	6.86	(66)	2.69	5.73	(53)
NYMEX Henry Hub (US$/mmbtu)	2.10	7.17	(71)	2.76	6.06	(54)
Exchange rate (US$/Cdn$)	0.74	0.78	(5)	0.74	0.78	(5)

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, November and December.

		Three months ended		Six months ended
		June 30,	Percent	June 30,	Percent
		2023	2022	Change	2023	2022	Change
		(thousands of dollars)		(thousands of dollars)
Heavy oil sales	116,085	124,919	(7)	212,507	228,292	(7)
Blending expense	(6,407)	(8,051)	(20)	(16,046)	(17,291)	(7)
Heavy oil, net of blending (1)	109,678	116,868	(6)	196,461	211,001	(7)
Natural gas	1,947	4,249	(54)	8,384	19,501	(57)
Natural gas liquids	732	677	8	1,278	747	71
Gathering, processing and transportation	203	308	(34)	1,007	875	15
Total sales, net of blending expense (1)		112,560	122,102	(8)	207,130	232,124	(11)

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

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Heavy Oil - Alberta

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.

The WTI price has softened from prior year due to reduced oil demand out of China and elevated recessionary risks in North America. The WCS differential to WTI has widened from prior year due to reduced US Golf Coast demand primarily as a result of increased refinery maintenance and downtime. The WCS to WTI differential is expected to tighten longer term with the Trans Mountain pipeline expansion anticipated to commission in the first quarter of 2024, improving egress optionality for heavy crude oil out of western Canada.

During the three months ended June 30, 2023, Headwater's heavy oil sales, net of blending expense, decreased to $109.7 million from $116.9 million in the comparable period of 2022. This decrease was attributable to a 37% decrease in realized commodity pricing, consistent with the decrease in benchmark WCS pricing, partially offset by a 48% increase in sales volumes. Headwater's discount to WCS widened from 2022 due to higher blending costs relative to WCS pricing, while Headwater's discount to WCS narrowed from the first quarter of 2023 primarily due to reduced seasonal blending requirements going into the spring and summer months.

During the six months ended June 30, 2023, Headwater's heavy oil sales, net of blending expense, decreased to $196.5 million from $211.0 million in the comparable period of 2022. This decrease was attributable to a 35% decrease in realized commodity pricing, consistent with the decrease in benchmark WCS pricing, partially offset by a 44% increase in sales volumes.

During the three and six months ended June 30, 2023, Headwater's heavy oil sales volumes averaged 15,625 bbls/d and 15,186 bbls/d, respectively, compared to 10,571 bbls/d and 10,579 bbls/d in the comparable periods of 2022. The Company's heavy oil sales volumes have increased significantly as a result of Headwater's extensive 2022 and 2023 capital expenditure programs. Headwater drilled 97.0 total net crude oil wells during the year ended December 31, 2022, and drilled 48.0 total net crude oil wells in the first half of 2023, substantially increasing the Company's heavy oil production.

Natural Gas - New Brunswick and Alberta

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. Headwater also produces natural gas in Alberta, processing its gas through the Company's joint gas processing facility located in Marten Hills. The natural gas sales transaction price is based on the AECO 5A daily benchmark price adjusted for delivery location and heat content.

For the three months ended June 30, 2023, Headwater's natural gas sales decreased to $1.9 million from $4.2 million in the corresponding period of the prior year, due to a 66% decrease in realized commodity pricing partially offset by a 33% increase in natural gas sales volumes. For the six months ended June 30, 2023, Headwater's natural gas sales decreased to $8.4 million from $19.5 million in the corresponding period of the prior year due to a 65% decrease in realized commodity pricing partially offset by a 24% increase in natural gas sales volumes. Realized natural gas pricing decreased due to lower benchmark pricing for both AGT and AECO 5A. For the six months ended June 30, 2023, AGT saw a 64% decrease from prior year due to warmer winter weather experienced in the northeastern US natural gas market, which significantly reduced natural gas demand in the area.

During the three and six months ended June 30, 2023, Headwater's natural gas sales volumes increased to 8.5 mmcf/d and 10.7 mmcf/d, respectively, from 6.4 mmcf/d and 8.6 mmcf/d in the comparable periods of 2022 as a result of higher associated natural gas production due to growth of the Company's Marten Hills assets.

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Consistent with prior years, the Company shut-in McCully natural gas production for the summer season effective May 1, 2023.

Financial Derivative Gains (Losses)

	Three months ended		Six months ended
	June 30,	Percent	June 30,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Realized gains (losses)	329	(258)	(228)	7,569	(4,203)	(280)
Unrealized gains (losses)	(913)	(2,801)	(67)	1,090	(2,931)	(137)
Financial derivative gains (losses)	(584)	(3,059)	(81)	8,659	(7,134)	(221)
Per boe	(0.37)	(2.87)	(87)	(2.80)	(3.27)	(14)

Natural gas and crude oil commodity contracts

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

The realized financial derivative gains recognized during the three months ended June 30, 2023, of $0.3 million compared to realized losses of $0.3 million in the corresponding period of 2022, represent the Company's Alberta natural gas contracts referenced to the AECO 5A price. The Company recognized gains on its AECO 5A contracts during the three months ended June 30, 2023, as the commodity contracts to fix the AECO 5A price exceeded the settlement price in the period. The settlement price was lower than expected due to market oversupply of natural gas in western Canada.

The realized financial derivative gains recognized during the six months ended June 30, 2023, primarily relate to Headwater's first quarter McCully natural gas contracts referenced to the AGT price. A realized financial derivative gain was recorded during the six months ended June 30, 2023, of $7.6 million compared to a realized loss of $4.2 million in the corresponding period of 2022. The Company recognized gains on its AGT contracts during the six months ended June 30, 2023, as the commodity contracts to fix the AGT price exceeded the settlement price in the period. The AGT settlement price was lower than expected due to warmer winter weather experienced in the northeastern US natural gas market resulting in significantly reduced natural gas demand in the area.

The unrealized gains and losses recorded are a result of the change in fair value of the Company's outstanding financial derivative contracts over the periods. As at June 30, 2023, the fair value of Headwater's outstanding financial derivative commodity contracts was a net unrealized liability of $0.1 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, 2023, 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 June 30, 2023. For the three and six months ended June 30, 2023, Headwater recognized unrealized losses of $0.9 million and unrealized gains of $1.1 million, respectively, compared to unrealized losses of $2.8 million and $2.9 million in the corresponding periods of 2022.

As at June 30, 2023, Headwater had the following financial derivative commodity contracts outstanding:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Natural Gas	AECO 5A	Fixed	July 2023 - Oct 2023	3,000 GJ	Cdn$3.53/GJ
Crude Oil	WCS Basis	Differential	Oct 2023 - Dec 2023	3,000 bbl	US$16.12/bbl

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Foreign exchange contracts

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, 2023, Headwater had the following financial derivative foreign exchange contract outstanding:

	Buy	Sell		Notional
Type	Currency	Currency	Rate	Amount	Settlement Date
Forward contract	CAD	USD	June 2023 average (1)	US$25.8 million	July 26, 2023

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
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Heavy oil	19,583	24,853	(21)	34,061	40,893	(17)
Natural gas and natural gas liquids	134	551	(76)	988	1,349	(27)
Total royalty expense	19,717	25,404	(22)	35,049	42,242	(17)
Percentage of total sales, net of blending (1)	17.5%	20.8%	(16)	16.9%	18.2%	(7)
Per boe	12.63	23.85	(47)	11.35	19.37	(41)

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, 2023, royalty expense decreased to $19.7 million and $35.0 million, respectively, from $25.4 million and $42.2 million in the comparable periods of 2022, due to a lower average corporate royalty rate combined with a decrease in total sales, net of blending expense. For the three and six months ended June 30, 2023, Headwater's average corporate royalty rate was 17.5% and 16.9%, respectively, compared to 20.8% and 18.2% in the corresponding periods of 2022. The decrease in royalty rate is attributed to lower commodity pricing in 2023, as WCS averaged $74.12/bbl in the first half of 2023 compared to $111.55/bbl in the second half of 2022, reflecting a 34% decrease. This significant decrease in realized commodity pricing caused new production to remain on the MRF's flat 5% royalty rate longer, bringing down the average corporate royalty rate in the periods.

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