Headwater Exploration : Q1 2024 MD&A

Q1 2024 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 May 9, 2024 and should be read in conjunction with the unaudited interim condensed financial statements as at and for the three months ended March 31, 2024, and the MD&A and the audited financial statements and the notes thereto for the year ended December 31, 2023, copies of which are available through 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/Falher formations in the Marten Hills, Greater Nipisi and Greater Peavine areas of Alberta and natural gas production and reserves in the McCully field near Sussex, New Brunswick. In 2023, Headwater began accumulating a significant land position outside of the Clearwater/Falher acreage across Western Canada. During the three months ended March 31, 2024, the Company drilled its first stratigraphic test and single-leg horizontal well, prospective for heavy oil, in Handel, Saskatchewan, with first sales realized in the second quarter of 2024.

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 MARCH 31, 2024

1. • Production averaged 19,517 boe/d (consisting of 17,512 bbls/d of heavy oil, 11.5 mmcf/d of natural gas and 87 bbls/d of natural gas liquids) representing an increase of 15% from the first quarter of 2023.
   • Realized adjusted funds flow from operations (1) of $76.4 million ($0.32 per share basic (2)) and cash flows from operations of $55.0 million ($0.23 per share basic).
   • Achieved an operating netback inclusive of financial derivatives (2) of $50.65/boe and an adjusted funds flow netback (2) of $43.17/boe.
   • Achieved net income of $37.6 million ($0.16 per share basic) equating to $21.24/boe.
   • Executed a $65.3 million capital expenditure (3) program inclusive of $11.7 million on land expenditures adding 81.4 net sections. The Company drilled 20 net crude oil wells at a 100% success rate.
   • Declared a cash dividend of $23.7 million, or $0.10 per common share.
   • As at March 31, 2024, Headwater had adjusted working capital (1) of $48.8 million, working capital of $58.3 million, and no outstanding bank debt.
2. Capital management measure 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 "Management of capital" in note 12 of the interim financial statements and to "Non-GAAP and Other Financial Measures" within this MD&A.
3. 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.
4. Non-GAAPfinancial measure 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.

1

Results of Operations

Production and Pricing

	Three months ended
	March 31,			Percent
	2024	2023		Change
Average daily production
Heavy oil (bbls/d)	17,512	14,777	19
Natural gas (mmcf/d)	11.5	12.8	(10)
Natural gas liquids (bbls/d)	87	91	(4)
Barrels of oil equivalent (boe/d)	19,517	17,004	15
Average daily sales (1)
Heavy oil (bbls/d)	17,454	14,741	18
Natural gas (mmcf/d)	11.5	12.8	(10)
Natural gas liquids (bbls/d)	87	91	(4)
Barrels of oil equivalent (boe/d)	19,459	16,968	15
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	76.04	65.41	16
Natural gas ($/mcf)	5.03	5.58	(10)
Natural gas liquids ($/bbl)	70.69	66.53	6
Barrels of oil equivalent ($/boe)	71.49	61.40	16
Average Benchmark Price
WTI (US$/bbl) (4)	76.96	76.13	1
WCS differential to WTI (US$/bbl)	(19.31)	(24.77)	(22)
WCS (Cdn$/bbl) (5)	77.77	69.45	12
Condensate at Edmonton (Cdn$/bbl)	97.36	105.88	(8)
AGT (US$/mmbtu) (6)	4.26	5.13	(17)
AECO 5A (Cdn$/GJ)	2.37	3.05	(22)
NYMEX Henry Hub (US$/mmbtu)	2.24	3.42	(35)
Exchange rate (Cdn$/US$)	0.74	0.74	-

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
		March 31,			Percent
		2024	2023		Change
		(thousands of dollars)
Heavy oil sales	127,446	96,422	32
Blending expense	(6,668)	(9,639)	(31)
Heavy oil, net of blending (1)	120,778	86,783	39
Natural gas	5,267	6,437	(18)
Natural gas liquids	557	546	2
Gathering, processing and transportation	764	804	(5)
Total sales, net of blending expense (1)		127,366	94,570	35

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

2

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 and the Cdn$/US$ foreign exchange rate were consistent over the periods, while the WCS differential to WTI narrowed during the three months ended March 31, 2024, due to increased North American demand and improved egress out of Western Canada. Headwater's discount to WCS also narrowed during the first quarter of 2024 primarily due to blending optimization and stronger realized pricing relative to WCS.

During the three months ended March 31, 2024, Headwater's heavy oil sales, net of blending expense, increased to $120.8 million from $86.8 million in the corresponding period of 2023. This increase was attributable to a 16% increase in realized commodity pricing, relatively consistent with the increase in benchmark WCS pricing, combined with an 18% increase in sales volumes.

During the three months ended March 31, 2024, Headwater's heavy oil sales volumes averaged 17,454 bbls/d compared to 14,741 bbls/d in the corresponding period of 2023. The Company's heavy oil sales volumes have increased as a result of Headwater's growth-oriented drilling program. Headwater drilled

90.0 total net crude oil wells during the year ended December 31, 2023, and drilled 20.0 total net crude oil wells in the first quarter of 2024, 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, 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.

Both AGT and AECO 5A saw a decrease in pricing over the period due to increasing storage levels resulting from the current El Nino climate pattern. Natural gas inventories are currently at the top of the historical five-year average in both the northeastern United States and Western Canada.

For the three months ended March 31, 2024, Headwater's natural gas sales decreased to $5.3 million from $6.4 million in the corresponding period of the prior year, due to a 10% decrease in realized commodity pricing and a 10% decrease in natural gas sales volumes. Realized natural gas pricing decreased due to lower benchmark pricing for both AGT and AECO 5A.

During the three months ended March 31, 2024, Headwater's natural gas sales volumes decreased to 11.5 mmcf/d from 12.8 mmcf/d in the corresponding period of the prior year as a result of lower natural gas production out of Alberta as Headwater realized declining natural gas production in the core area of Marten Hills.

Consistent with prior years, the Company shut-in McCully natural gas production for the upcoming summer season effective May 1, 2024.

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Financial Derivative Gains (Losses)

Realized gains

Unrealized gains (losses)

Financial derivative gains

Per boe ($)

Three months ended
March 31,			Percent
2024	2023		Change
(thousands of dollars)
6,114	7,240	(16)
(5,841)	2,003	(392)
273	9,243	(97)
0.15	6.05	(98)

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 March 31, 2024, represent the natural gas contracts referenced to the AGT price. A realized financial derivative gain of $6.1 million was recorded during the three months ended March 31, 2024 compared to a realized gain of $7.2 million in the corresponding period of 2023. The Company recognized gains on its AGT contracts during the three months ended March 31, 2024, 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 recorded are a result of the change in fair value of the Company's outstanding financial derivative contracts over the periods. As at March 31, 2024, the fair value of Headwater's outstanding financial derivative commodity contracts was a net unrealized liability of $2.2 million as reflected in the interim condensed 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 March 31, 2024, 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 March 31, 2024. For the three months ended March 31, 2024, Headwater recognized unrealized losses of $5.8 million compared to unrealized gains of $2.0 million in the corresponding period of 2023.

As at March 31, 2024, Headwater had the following financial derivative commodity contracts outstanding:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Natural Gas	AECO 5A	Fixed	April 2024 - Oct 2024	2,000 GJ	Cdn$2.12/GJ
Natural Gas	AECO 5A	Fixed	April 2025 - Oct 2025	2,000 GJ	Cdn$2.78/GJ
Natural Gas	AGT	Fixed	April 2024	2,500 mmbtu	Cdn$2.33/mmbtu
Natural Gas	AGT	Fixed	Dec 2024 - Mar 2025	2,500 mmbtu	Cdn$10.65/mmbtu
Crude Oil	WCS Basis	Differential	Apr 2024 - Jun 2024	5,000 bbl	US$15.18/bbl
Crude Oil	WCS Basis	Differential	Jul 2024 - Sep 2024	3,000 bbl	US$13.25/bbl

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.

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As at March 31, 2024, Headwater had the following financial derivative foreign exchange contract outstanding:

	Buy	Sell		Notional
Type	Currency	Currency	Rate	Amount	Settlement Date
Forward contract	CAD	USD	March 2024 average (1)	US$0.5 million	April 26, 2024

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
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Royalty expense	21,844	15,332	42
Percentage of total sales, net of blending (1)	17.2%	16.2%	6
Per boe ($)	12.34	10.04	23

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

Royalty expense primarily 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, 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, then royalty rates increase on a sliding scale up to 40% depending on commodity reference pricing.

For the three months ended March 31, 2024, royalty expense increased to $21.8 million from $15.3 million in the corresponding period of 2023, representing an increase of 42% which is relatively consistent with the increase in total sales (net of blending expense) over the period, of 35%. Also contributing to the increase in royalty expense is an increase in the royalty rate over the period from 16.2% to 17.2% which was driven by an increase in realized heavy oil commodity pricing.

Transportation Expense

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Transportation expense	9,468	8,397	13
Per boe ($)	5.35	5.50	(3)

Transportation expense includes clean oil trucking, terminal fees and pipeline tariffs incurred to move production to the sales point.

For the three months ended March 31, 2024, transportation expense increased to $9.5 million from $8.4 million in the corresponding period of the prior year as a result of an increase to heavy oil sales volumes.

Transportation expense per boe was consistent over the periods.

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Headwater has firm transportation service commitments in place to secure pipeline capacity to the point of sale. Refer to "Contractual Obligations and Commitments" for more information.

Production Expense

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Production expense	12,459	9,979	25
Per boe ($)	7.04	6.53	8

Production expense in the three months ended March 31, 2024, was $12.5 million compared to $10.0 million in the corresponding period of 2023. The increase in production expense reflects the increase in the Company's production volumes over the period.

For the three months ended March 31, 2024, production expense per boe increased to $7.04 from $6.53 in the corresponding period of the prior year due to substantial growth in Marten Hills West and the development of new areas in Greater Nipisi and Greater Peavine which carry higher operating costs than the initial development area of Marten Hills.

Netbacks

Operating netback reflects the Company's margin on a per-barrel of oil equivalent basis. The following table provides a reconciliation of Headwater's operating netback and operating netback, including financial derivatives. Refer to the heading "Non-GAAP and Other Financial Measures" for more information.

		Three months ended
		March 31,			Percent
		2024	2023		Change
		($/boe)
Sales	75.69	68.24	11
Royalties	(12.34)	(10.04)	23
Transportation and blending	(9.11)	(11.81)	(23)
Production expense	(7.04)	(6.53)	8
Operating netback (1)	47.20	39.86	18
Realized gains on financial derivatives	3.45	4.74	(27)
Operating netback, including financial derivatives (1)		50.65	44.60	14

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

For the three months ended March 31, 2024, the Company's operating netback, including financial derivatives increased to $50.65 per boe, from $44.60 per boe in the corresponding period of 2023, as a result of higher realized commodity pricing and lower transportation and blending, partially offset by higher royalties and production expense and lower realized gains on financial derivatives.

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General and Administrative ("G&A") Expenses

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
G&A expenses	3,645	2,904	26
Capitalized G&A	(1,044)	(841)	24
Net G&A expenses	2,601	2,063	26
Per boe ($)	1.47	1.35	9

For the three months ended March 31, 2024, net G&A expenses increased to $2.6 million from $2.1 million in the corresponding period of 2023. Increased net G&A expenses on an absolute and per boe basis were mainly a result of increased employee related costs due to the growth experienced by the Company over the period.

Interest Income and Other Expense

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Interest income	1,671	1,788	(7)
Realized and unrealized foreign exchange gains (losses)	33	(3)	(1200)
Accretion on decommissioning liability	(309)	(262)	18
Interest on repayable contribution	(214)	(117)	83
Interest on lease liability	(15)	(10)	50
Total interest income and other expense	1,166	1,396	(16)
Per boe ($)	0.66	0.91	(27)

For the three months ended March 31, 2024, interest income and other expense decreased to $1.2 million from $1.4 million in the corresponding period of the prior year due to lower interest income and higher accretion on decommissioning liability and interest on repayable contribution. The slight decrease in interest income for the three months ended March 31, 2024 is a result of carrying a lower average cash balance when compared to the same period in 2023. Interest on repayable contribution has increased due to the receipt of two additional grants in late 2023.

The Company manages fluctuations in foreign exchange gains and losses by entering into foreign exchange contracts to fix the foreign exchange rate. Refer to "Financial Derivatives Gains (Losses)" for more information.

7

Stock-Based Compensation

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Stock options	149	509	(71)
Deferred share units	1,215	665	83
Share awards	1,759	787	124
Capitalized stock-based compensation	(400)	(346)	16
Stock-based compensation	2,723	1,615	69
Per boe ($)	1.54	1.06	45

During the three months ended March 31, 2024, stock-based compensation expense increased to $2.7 million from $1.6 million in the corresponding period of the prior year. The higher expense associated with deferred share units ("DSUs") and share awards was due to new grants in the period and an increase in the Company's share price to $7.67 at March 31, 2024, from $6.25 at December 31, 2023. The expense for stock options was lower due to the majority of outstanding stock options being fully vested.

Share Awards

The Company's performance and restricted award plan ("Award Plan") provides for the grant of restricted share units ("RSUs") and performance share units ("PSUs") to officers, employees and consultants of the Company. Under the Award Plan, the aggregate number of common shares reserved for issuance may not exceed the lesser of: (i) 6.0% of the aggregate number of issued and outstanding common shares less the aggregate number of common shares reserved for issuance under the Company's stock option plans; and

1. 4.5% of the aggregate number of issued and outstanding common shares. Generally, one third of the RSUs will vest on each of the first, second and third anniversaries of the date of grant and all PSUs will vest on the third anniversary of the date of grant, unless otherwise determined by the Board of Directors of the Company (the "Board"). The common shares underlying PSUs are adjusted based on a performance multiplier ranging from 0 to 2 times, which is determined based on certain corporate performance measures, as determined by the Board.

During the year ended December 31, 2023, the Board approved the cash settlement of RSUs. Previously, these Awards had been accounted for as equity-settled. As a result of this modification to the Company's outstanding RSUs from equity-settled to cash-settled, the fair value of the awards previously expensed was reclassified from contributed surplus to stock-based compensation payable. Subsequent to this modification, the grant date fair value is used to record the cost of the RSUs and any subsequent remeasurement of the liability is also recognized in the Statement of Income and Comprehensive Income.

It is the intention of the Company to equity settle any outstanding PSUs. The Award Plan allows a holder to receive common shares upon vesting. Headwater uses the fair value method for valuing the PSUs. The fair value of PSUs is determined based on the volume weighted average trading price of the five days preceding the grant date. This fair value is recognized as stock-based compensation expense, with a portion being capitalized, over the vesting period with a corresponding increase to contributed surplus. The amount of stock-based compensation expense is reduced by an estimated forfeiture rate determined at the date of the grant and updated each period. Upon vesting of the PSUs and settlement in common shares, the previously recognized value in contributed surplus will be recorded as an increase to capital stock.

As at March 31, 2024, there were 462,803 RSUs outstanding and 2,744,817 PSUs outstanding.

Deferred Share Units

The deferred share unit plan ("DSU Plan") provides for grants of DSUs to non-management directors. Each DSU vests on the date of grant; however, settlement of the DSU occurs when the individual ceases to be

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a director of the Company. DSUs are to be settled in cash or by payment in common shares acquired through the facilities of the Toronto Stock Exchange ("TSX"). It is the intention of the Company to settle the DSUs in cash. The directors may also elect to receive all of their annual cash compensation in the form of DSUs provided that such election must be made on December 1st of the preceding calendar year (or within a certain prescribed time frame if an individual becomes a director after the commencement of a calendar year or after the initial adoption of the DSU Plan) and after such date the election will be irrevocable for such year. DSUs are measured at fair value using the Company's closing share price on March 31, 2024.

As at March 31, 2024, there were 365,507 DSUs outstanding.

Stock Options

The Company has an old and new stock option plan (the "Option Plans") under which options to purchase common shares of the Company could be granted to directors, officers, employees and consultants of the Company. The exercise price of each option granted is based on the closing price of the common shares on the TSX on the trading day prior to the date the option was granted. Options granted generally vest as to one third of the number granted on each of the first, second and third anniversaries of the date of grant over a three-year period and expire four to five years after the grant date. The Company did not grant any stock options in 2024 or 2023 and does not intend to grant any further options under the Option Plans.

As at March 31, 2024, there were 1,151,840 stock options outstanding under the Option Plans.

Depletion & Depreciation

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Depletion	30,467	28,441	7
Depreciation	61	216	(72)
Depletion & depreciation	30,528	28,657	7
Depletion - Per boe ($)	17.21	18.63	(8)
Depreciation - Per boe ($)	0.03	0.14	(79)
Depletion & depreciation per boe ($)	17.24	18.77	(8)

Depletion expense is calculated using the unit-of-production method which is based on production volumes in relation to the proved plus probable reserves base.

Depletion expense for the three months ended March 31, 2024, increased slightly to $30.5 million from $28.4 million in the corresponding period of 2023, due to an increase in the Company's production volumes over the period.

Depletion and depreciation expense per boe decreased during the three months ended March 31, 2024, when compared to the corresponding period of 2023, primarily due to significant reserve additions recorded in Headwater's 2023 year-end reserves report, resulting from successful drilling and waterflood results.

Impairment Assessment

As at March 31, 2024, there were no indicators of impairment identified for the Company's E&E (as defined herein) or property, plant and equipment ("PP&E") assets. As such, an impairment test was not performed.

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Current and Deferred Income Taxes

	Three months ended
	March 31,			Percent
	2024	2023		Change
	(thousands of dollars)
Current income tax expense	12,233	8,572	43
Deferred income tax (recovery) expense	(670)	615	(209)
Total income tax expense	11,563	9,187	26
Current income tax expense - Per boe ($)	6.91	5.61	23
Deferred income tax (recovery) expense - Per boe ($)	(0.38)	0.40	(195)
Total income tax expense - Per boe ($)	6.53	6.01	9

For the three months ended March 31, 2024, the Company recorded current income taxes of $12.2 million and a deferred income tax recovery of $0.7 million. Current income taxes increased by 43% from the prior year as a result of lower available tax pool claims, coupled with higher adjusted funds flow from operations for the three months ended March 31, 2024, compared to the corresponding period of the prior year.

Cash Flows Provided by Operating Activities and Adjusted Funds Flow from Operations

Refer to the heading "Non-GAAP and Other Financial Measures" for more information.

		Three months ended
		March 31,			Percent
		2024	2023		Change
		(thousands of dollars)
Cash flows provided by operating activities	55,047	60,201	(9)
Changes in non-cash working capital	4,628	(8,414)	(155)
Current income taxes	(12,233)	(8,572)	43
Income taxes paid	29,004	15,942	82
Adjusted funds flow from operations (1)
76,446	59,157	29

		Three months ended
		March 31,			Percent
		2024	2023		Change
		($/boe)
Cash flows provided by operating activities	31.09	39.42	(21)
Changes in non-cash working capital	2.61	(5.51)	(147)
Current income taxes	(6.91)	(5.61)	23
Income taxes paid	16.38	10.45	57
Adjusted funds flow netback (2)
43.17	38.75	11

1. Capital management measure. 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. Refer to the advisory "Non-GAAP and Other Financial Measures".

For the three months ended March 31, 2024, adjusted funds flow from operations increased to $76.4 million from $59.2 million in the corresponding period of the prior year as a result of a 16% increase in realized commodity pricing coupled with a 15% increase in sales volumes partially offset by higher overall cash costs including royalties, transportation, production expense and current income taxes.

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