Headwater Exploration : 2022 Year End MD&A

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 March 9, 2023 and should be read in conjunction with the audited annual financial statements for the years ended December 31, 2022 and 2021 and the notes thereto. The audited annual financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). All dollar amounts are referenced in Canadian dollars unless otherwise stated. In addition, readers are also directed to the Company's Annual Information Form for the year ended December 31, 2022, dated March 9, 2023, which is available on the Company's website at www.headwaterexp.comand under the Company's profile on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.

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 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.

FOURTH QUARTER 2022 HIGHLIGHTS

• Headwater declared its inaugural quarterly cash dividend of $0.10 per common share and returned $23.4 million to shareholders in January 2023.
• Achieved average production of 15,546 boe/d (consisting of 13,536 bbls/d of heavy oil, 11.5 mmcf/d of natural gas and 99 bbls/d of natural gas liquids), an increase of 49% from the fourth quarter of 2021.
• Generated significant cash flows provided by operating activities of $66.4 million ($0.29 per basic share), representing an increase of 39% from the fourth quarter of 2021. Adjusted funds flow from operations (1) was $71.8 million ($0.31 per basic share), representing an increase of 47% from the fourth quarter of 2021.
• Achieved an operating netback (2) of $47.93/boe and an adjusted funds flow netback (2) of $50.15/boe.
• Recognized net income of $39.8 million, $0.17 per share (basic).
• Executed a $60.7 million capital expenditure (3) program including 27 net crude oil wells in Marten Hills and the Company's first 3 successful exploration wells in West Nipisi.
• As at December 31, 2022, Headwater had working capital of $109.4 million, adjusted working capital
  (1) of $104.9 million and no outstanding bank debt.
• The Company entered into a $100.0 million credit facility agreement comprised of a $20.0 million operating facility and an $80.0 million syndicated facility.
• Headwater released its inaugural Environmental, Social and Governance ("ESG") report in November 2022.

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YEAR ENDED DECEMBER 31, 2022 HIGHLIGHTS

• Achieved average production of 12,841 boe/d (consisting of 11,411 bbls/d of heavy oil, 8.2 mmcf/d of natural gas and 57 bbls/d of natural gas liquids), an increase of 74% from 2021 annual production of 7,393 boe/d.
• Cash flows provided by operating activities was $283.9 million ($1.25 per basic share), representing an increase of 154% from 2021. Adjusted funds flow from operations (1) was $279.7 million ($1.23 per basic share), representing an increase of 137% from 2021.
• Achieved an operating netback (2) of $63.36/boe and an adjusted funds flow netback (2) of $59.68/boe.
• Generated significant net income of $162.1 million, $0.71 per basic share, an increase of 254% from the comparable period in 2021.
• Executed a $244.5 million capital expenditure (3) program including:

1. Added 112 net sections of unburdened land in the Falher/Clearwater plays in Greater

Peavine and West Nipisi establishing the Company's next exploration focus areas.

1. Drilled 97 net crude oil wells which included 94 wells in the Marten Hills area of which 18 were subsequently converted to injection and 3 successful exploration wells in West Nipisi.

• 1. Commissioned the Company's 15,000 bbls/d oil processing facility and associated pipelines in Marten Hills.
• 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. To date, Headwater has received $11.0 million of funding.
• The Company's McCully asset realized strong winter pricing and contributed $20.1 million in free cash flow (3).

1. Refer to "Management of capital" in note 16 of the audited annual 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.

SUBSEQUENT TO THE YEAR ENDED DECEMBER 31, 2022

• The Board of Directors (the "Board") of Headwater declared a quarterly cash dividend to shareholders of $0.10 per common share payable on April 17, 2023, to shareholders of record at the close of business on March 31, 2023 (see "Subsequent Events").

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Results of Operations

Production and Pricing

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2022	2021		Change	2022	2021		Change
Average daily production
Heavy oil (bbls/d)	13,536	9,377	44	11,411	6,665	71
Natural gas (mmcf/d)	11.5	6.4	80	8.2	4.4	86
Natural gas liquids (bbls/d)	99	-	100	57	2	2750
Barrels of oil equivalent (boe/d)	15,546	10,449	49	12,841	7,393	74
Average daily sales (boe/d) (1)
Heavy oil (bbls/d)	13,558	9,388	44	11,413	6,661	71
Natural gas (mmcf/d)	11.5	6.4	80	8.2	4.4	86
Natural gas liquids (bbls/d)	99	-	100	57	2	2750
Barrels of oil equivalent (boe/d)	15,568	10,459	49	12,843	7,390	74
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	73.10	75.12	(3)	94.79	68.69	38
Natural gas ($/mcf)	10.15	8.46	20	10.60	7.18	48
Natural gas liquids ($/bbl)	73.02	-	100	91.29	70.14	30
Barrels of oil equivalent ($/boe)	71.60	72.62	(1)	91.44	66.18	38
Average Benchmark Price
WTI (US$/bbl) (4)	82.64	77.19	7	94.23	67.91	39
WCS differential to WTI (US$/bbl)	(25.66)	(14.64)	75	(18.22)	(13.04)	40
WCS (Cdn$/bbl) (5)	77.42	78.72	(2)	98.52	68.73	43
Condensate at Edmonton (Cdn$/bbl)	111.82	99.65	12	123.20	85.47	44
AGT (US$/mmbtu) (6)	9.90	8.09	22	11.21	5.49	104
AECO 5A (Cdn$/GJ)	4.85	4.41	10	5.06	3.44	47
NYMEX Henry Hub (US$/mmbtu)	6.26	5.83	7	6.64	3.84	73
Exchange rate (US$/Cdn$)	0.74	0.79	(6)	0.77	0.80	(4)

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 - April, November and December.

Sales

		Three months ended				Year ended
		December 31,		Percent		December 31,		Percent
		2022	2021		Change	2022	2021		Change
		(thousands of dollars)				(thousands of dollars)
Heavy oil sales	97,584	70,038	39	423,211	178,434	137
Blending expense	(6,403)	(5,162)	24		(28,332)	(11,423)	148
Heavy oil, net of blending (1)	91,181	64,876	41	394,879	167,011	136
Natural gas	10,706	5,005	114	31,876	11,416	179
Natural gas liquids	662	-	100	1,891	62	2950
Gathering, processing and
transportation	425	244	74		1,401	1,028	36
Total sales, net of blending expense (1)		102,974	70,125	47		430,047	179,517	140

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.

Higher commodity pricing realized during the year ended December 31, 2022, is a result of stronger WTI pricing partially offset by a wider WCS differential to WTI. WTI strengthened 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. Crude oil prices pulled back in the fourth quarter of 2022 due to reduced oil demand in China and elevated recessionary risks. The WCS differential to WTI widened during both the three and twelve months ended December 31, 2022, due to reduced US Golf Coast demand primarily as a result of increased refinery maintenance and downtime.

During the three months ended December 31, 2022, Headwater's heavy oil sales, net of blending expense, significantly increased to $91.2 million from $64.9 million in the corresponding period of the prior year. This increase was attributable to a 44% increase in heavy oil sales volumes partially offset by a 3% decrease in realized commodity pricing. Headwater's discount to WCS widened during the fourth quarter of 2022 primarily due to strong condensate pricing, increased seasonal blending requirements and the Keystone pipeline outage which caused significant apportionment and weaker realized pricing relative to WCS during the month of December.

During the year ended December 31, 2022, Headwater's heavy oil sales, net of blending expense, increased to $394.9 million from $167.0 million in 2021. This increase was attributable to a 71% increase in heavy oil sales volumes combined with a 38% increase in realized commodity pricing.

During the three months ended December 31, 2022, Headwater's heavy oil sales volumes averaged 13,558 bbls/d compared to 9,388 bbls/d in the same period of 2021, while Headwater's heavy oil sales volumes averaged 11,413 bbls/d during the year ended December 31, 2022, compared to 6,661 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 capital expenditure program. Headwater drilled 97.0 total net crude oil wells in the year ended December 31, 2022, substantially increasing the Company's heavy oil production in the Marten Hills area.

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, as the Company commissioned its Marten Hills joint gas processing facility and started generating sales from its associated natural gas production in the third quarter of 2021. 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 December 31, 2022, Headwater's natural gas sales increased to $10.7 million from $5.0 million in the corresponding period of the prior year due to an 80% increase in natural gas sales volumes and a 20% increase in realized commodity pricing. For the year ended December 31, 2022, Headwater's natural gas sales increased to $31.9 million from $11.4 million in the corresponding period of the prior year due to an 86% increase in natural gas sales volumes and a 48% increase in realized commodity pricing. Natural gas sales volumes increased to 11.5 mmcf/d and 8.2 mmcf/d, respectively, for the three and twelve months ended December 31, 2022, from 6.4 mmcf/d and 4.4 mmcf/d, respectively, for the corresponding periods of the prior year, as a result of higher associated natural gas production from the Company's Marten Hills assets. Realized natural gas pricing increased due to higher benchmark pricing for both AGT and AECO 5A.

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Financial Derivatives Gains (Losses)

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2022	2021		Change	2022	2021		Change
	(thousands of dollars)				(thousands of dollars)
Realized financial derivative gains	4,240	1,360	212	37	955	(96)
Unrealized financial derivative gains (losses)	5,516	5,830			2,184	(3,228)	(168)
	(5)
Financial derivative gains (losses)	9,756	7,190	36		2,221	(2,273)	(198)
Per boe	6.81	7.47	(9)	0.47	(0.84)	(156)

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 both the three and twelve months ended December 31, 2022, represent both the natural gas contracts referenced to the AGT price and the crude oil contracts referenced to the WCS differential.

A realized financial derivative gain was recorded during the three months ended December 31, 2022, of $4.2 million compared to a realized gain of $1.4 million in the corresponding period of 2021. The Company realized a gain of $3.0 million relating to its AGT contracts and a $1.2 million gain on its WCS differential contract. The Company recognized gains on its AGT contracts during the three months ended December 31, 2022, as the commodity contracts to fix the AGT price exceeded the settlement price in the period. A realized gain was recognized on the WCS differential contract as the WCS differential widened in the period.

A realized financial derivative gain was recorded during the year ended December 31, 2022, of $37 thousand compared to a realized financial derivative gain of $1.0 million in the same period of 2021. The Company's realized losses on its fixed AGT contracts in the first quarter of 2022 were offset by realized gains recognized in the fourth quarter of 2022 on both its AGT contracts and WCS differential contract.

The unrealized gains recorded are a result of the change in fair value of the Company's outstanding financial derivative contracts over the periods. As at December 31, 2022, the fair value of Headwater's outstanding financial derivative commodity contracts was a net unrealized liability of $1.2 million as reflected in the audited annual 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 December 31, 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 December 31, 2022. For the three and twelve months ended December 31, 2022, Headwater recognized unrealized gains of $5.5 million and $2.2 million, respectively, compared to unrealized gains of $5.8 million and unrealized losses of $3.2 million in the corresponding periods of 2021.

As at December 31, 2022, Headwater had the following financial derivative commodity contracts outstanding:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Natural Gas	AGT	Fixed	Jan 2023- Mar 2023	2,500 mmbtu	Cdn$17.91/mmbtu
Natural Gas	AGT	Fixed	Jan 2023- Feb 2023	2,500 mmbtu	Cdn$32.71/mmbtu
Natural Gas	AGT	Fixed	Mar 2023	2,500 mmbtu	Cdn$19.36/mmbtu
Natural Gas	AECO 5A	Fixed	Apr 2023- Oct 2023	2,000 GJ	Cdn$3.83/GJ
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