Q1 2025 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 1, 2025 and should be read in conjunction with the unaudited interim condensed financial statements ("interim financial statements") as at and for the three months ended March 31, 2025, and the MD&A and the audited financial statements and the notes thereto for the year ended December 31, 2024, 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 year ended December 31, 2024, the Company drilled its first stratigraphic test and single-leg horizontal well, prospective for heavy oil, in Saskatchewan.

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, 2025

Achieved record production of 22,066 boe/d representing an increase of 13% from the first quarter of 2024.
Realized record adjusted funds flow from operations (1) of $92.4 million ($0.39 per share basic (2)), cash flows from operations of $69.9 million ($0.29 per share basic) and free cash flow (3) of $29.5 million.
Achieved an operating netback inclusive of financial derivatives (2) of $52.94/boe and an adjusted funds flow netback (2) of $46.61/boe.
Achieved net income of $50.0 million ($0.21 per share basic) equating to $25.23/boe.
Executed a $62.8 million capital expenditure (3) program inclusive of development and exploration tests in the Marten Hills West, Greater Nipisi and Greater Peavine areas.
Declared a cash dividend of $26.2 million, or $0.11 per common share. To date, Headwater has paid out a cumulative dividend of $239.0 million to shareholders ($1.01 per common share).
As at March 31, 2025, Headwater had adjusted working capital (1) of $63.6 million, working capital of $72.1 million, and no outstanding bank debt.

HIGHLIGHT SUBSEQUENT TO MARCH 31, 2025

> Subsequent to March 31, 2025, the Toronto Stock Exchange ("TSX") approved Headwater's Normal Course Issuer Bid ("NCIB") application to purchase for cancellation up to 19,020,755 common shares during the period commencing on May 6, 2025, and terminating on the earlier of: (i) the date on which the Company has acquired all common shares sought pursuant to the NCIB; or (ii) to May 5, 2026, unless earlier terminated at the option of the Company, upon prior notice being given to the TSX.

(1) 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.
(2) Non-GAAP ratio 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-GAAP financial 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.

Results of Operations

Production and Pricing

	Three months ended March 31,		Percent Change
	2025	2024
Average daily production
Heavy oil (bbls/d)	19,511	17,512	11
Natural gas (mmcf/d)	14.5	11.5	26
Natural gas liquids (bbls/d)	142	87	63
Barrels of oil equivalent (boe/d)	22,066	19,517	13
Average daily sales (1)
Heavy oil (bbls/d)	19,464	17,454	12
Natural gas (mmcf/d)	14.5	11.5	26
Natural gas liquids (bbls/d)	142	87	63
Barrels of oil equivalent (boe/d)	22,019	19,459	13
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	83.76	76.04	10
Natural gas ($/mcf)	11.22	5.03	123
Natural gas liquids ($/bbl)	80.82	70.69	14
Barrels of oil equivalent ($/boe)	81.94	71.49	15
Average Benchmark Price
WTI (US$/bbl) (4)	71.42	76.96	(7)
WCS differential to WTI (US$/bbl)	(12.67)	(19.31)	(34)
WCS (Cdn$/bbl) (5)	84.30	77.77	8
Condensate at Edmonton (Cdn$/bbl)	99.64	97.36	2
AGT (US$/mmbtu) (6)	11.83	4.26	178
AECO 5A (Cdn$/GJ)	2.05	2.37	(14)
NYMEX Henry Hub (US$/mmbtu)	3.65	2.24	63
Exchange rate (Cdn$ to US$)	0.70	0.74	(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.

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Heavy oil sales	153,684	127,446	21
Blending expense	(6,967)	(6,668)	4
Heavy oil, net of blending (1)	146,717	120,778	21
Natural gas	14,623	5,267	178
Natural gas liquids	1,032	557	85
Gathering, processing and transportation	816	764	7
Total sales, net of blending expense (1)	163,188	127,366	28

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

Heavy Oil – Western Canada

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.

WTI pricing has weakened year over year, due to softer supply and demand fundamentals driven by global recession fears following the recent imposition of U.S. tariffs and retaliatory tariffs from trade partners, along with the expectation of increased OPEC+ output in the near term. Offsetting the impact of lower WTI pricing was the narrowing of the WCS differential to WTI due to lower Western Canadian heavy oil inventories and a weaker Canadian dollar. Headwater's discount to WCS narrowed during the three months ended March 31, 2025, compared to the corresponding period of the prior year, primarily due to blending optimization and stronger realized pricing relative to WCS.

During the three months ended March 31, 2025, Headwater's heavy oil sales, net of blending expense, increased to $146.7 million from $120.8 million in the corresponding period of the prior year. This increase was attributable to a 12% increase in heavy oil sales volumes combined with a 10% increase in realized heavy oil commodity pricing, consistent with the increase in benchmark WCS pricing.

During the three months ended March 31, 2025, Headwater's heavy oil sales volumes averaged 19,464 bbls/d compared to 17,454 bbls/d in the corresponding period of 2024. The Company's heavy oil sales volumes have increased as a result of Headwater's growth-oriented drilling programs. Headwater drilled 11.0 total net crude oil wells during the three months ended March 31, 2025, and drilled 76.0 total net crude oil wells during the year ended December 31, 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 a premium contract adder. Headwater also produces natural gas in Alberta. In December 2024, a third-party gathering system in Marten Hills West was commissioned, increasing the Company's sales volumes out of the Marten Hills area. 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 March 31, 2025, natural gas sales increased to $14.6 million from $5.3 million in the corresponding period of the prior year, primarily driven by an increase in McCully natural gas sales over the period. AGT benchmark pricing increased significantly in the first quarter of 2025 driven by cooler U.S. winter temperatures and declining natural gas storage levels in the northeastern U.S. Natural gas sales out of Alberta also increased due to higher sales volumes partially offset by lower AECO 5A benchmark pricing.

During the three months ended March 31, 2025, Headwater's natural gas sales volumes increased to 14.5 mmcf/d from 11.5 mmcf/d in the corresponding period of the prior year, primarily as a result of incremental sales volumes from the newly constructed third-party gathering system in Marten Hills West.

Consistent with prior years, the Company shut-in McCully natural gas production for the upcoming summer season effective May 1, 2025.

Financial Derivative Gains (Losses)

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Realized gains (losses)	(3,166)	6,114	(152)
Unrealized losses	(2,486)	(5,841)	(57)
Financial derivative gains (losses)	(5,652)	273	(2170)
Per boe ($)	(2.85)	0.15	(2000)

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 losses recognized during the three months ended March 31, 2025, primarily represent the Company's natural gas contracts referenced to the AGT price. A realized financial derivative loss of $3.2 million was recorded during the three months ended March 31, 2025, compared to a realized gain of $6.1 million in the corresponding period of 2024. Headwater recognized losses on its AGT contracts during the three months ended March 31, 2025, as the commodity contracts to fix the AGT price were lower than the settlement price in the period. The AGT settlement price was higher than expected due to by cooler U.S. winter temperatures and declining natural gas storage levels in the northeastern U.S.

The unrealized financial derivative losses 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, 2025, the fair value of Headwater's outstanding financial derivative commodity contracts was a net unrealized liability of $2.6 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 March 31, 2025, 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, 2025. For the three months ended March 31, 2025, Headwater recognized unrealized losses of $2.5 million compared to unrealized losses of $5.8 million in the corresponding period of 2024.

As at March 31, 2025, Headwater had the following financial derivative commodity contracts outstanding:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Natural Gas	AGT	Fixed	Apr 2025	5,000 mmbtu	Cdn$4.64/mmbtu
Natural Gas	AGT	Fixed	Dec 2025 – Jan 2026	2,500 mmbtu	Cdn$17.60/mmbtu
Natural Gas	AGT	Fixed	Dec 2025 - Mar 2026	2,500 mmbtu	Cdn$13.75/mmbtu
Natural Gas	AECO 5A	Fixed	Apr 2025 - Oct 2025	4,000 GJ	Cdn$2.46/GJ
Natural Gas	AECO 5A	Fixed	Apr 2025 - Dec 2025	2,000 GJ	Cdn$2.16/GJ
Crude Oil	WCS Basis	Differential	Apr 2025 – Dec 2025	3,000 bbl	US$13.28/bbl

Foreign exchange contracts

The Company is exposed to fluctuations in 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 WCS commodity contracts. Headwater may decide to mitigate a portion of this risk by periodically entering into foreign exchange contracts. As at March 31, 2025, Headwater did not have any foreign exchange contracts outstanding.

Royalty Expense

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Royalty expense	28,665	21,844	31
Average royalty rate (1)	17.6%	17.2%	2
Per boe ($)	14.47	12.34	17

(1) Non-GAAP ratio. 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. The GORR is associated with production out of the Company's Marten Hills development assets.

Under the Alberta Modernized Royalty Framework, the Company pays 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 reference commodity pricing.

For the three months ended March 31, 2025, royalty expense increased to $28.7 million from $21.8 million in the corresponding period of the prior year, representing an increase of 31%, which is relatively consistent with the increase in total sales, net of blending expense over the period of 28%. The average corporate royalty rate was consistent period over period.

Transportation Expense

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Transportation expense	10,727	9,468	13
Per boe ($)	5.41	5.35	1

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, 2025, transportation expense increased to $10.7 million from $9.5 million in the corresponding period of the prior year as a result of a 10% increase to heavy oil sales volumes.

Transportation expense per boe was consistent period over period.

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 Change
	2025	2024
	(thousands of dollars)
Production expense	15,706	12,459	26
Per boe ($)	7.93	7.04	13

Production expense in the three months ended March 31, 2025, was $15.7 million compared to $12.5 million in the corresponding period of 2024. The increase in production expense reflects the 13% increase in the Company's production volumes over the period.

For the three months ended March 31, 2025, production expense per boe increased to $7.93 from $7.04 in the corresponding period of the prior year, due to costs associated with the newly commissioned Marten Hills West natural gas gathering system.

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 Change
	2025	2024
	($/boe)
Sales	85.87	75.69	13
Royalties	(14.47)	(12.34)	17
Transportation and blending	(8.93)	(9.11)	(2)
Production expense	(7.93)	(7.04)	13
Operating netback (1)	54.54	47.20	16
Realized gains (losses) on financial derivatives	(1.60)	3.45	(146)
Operating netback, including financial derivatives (1)	52.94	50.65	5

(1) Non-GAAP ratio. Refer to the advisory "Non-GAAP and Other Financial Measures".

For the three months ended March 31, 2025, the Company's operating netback, including financial derivatives increased to $52.94 per boe, from $50.65 per boe in the corresponding period of 2024, as a result of higher realized commodity pricing, partially offset by higher royalties and production expense and higher realized losses on financial derivatives.

General and Administrative ("G&A") Expenses

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
G&A expenses	3,864	3,645	6
Capitalized G&A	(1,015)	(1,044)	(3)
Net G&A expenses	2,849	2,601	10
Per boe ($)	1.44	1.47	(2)

For the three months ended March 31, 2025, net G&A expenses increased to $2.8 million from $2.6 million in the corresponding period of 2024. Increased net G&A expenses on an absolute basis were mainly a result of higher employee related costs due to the growth experienced by the Company over the period. G&A expenses per boe were consistent period over period.

Interest Income and Other Expense

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Interest income	1,155	1,671	(31)
Foreign exchange gains (losses)	(1)	33	(103)
Accretion on decommissioning liability	(404)	(309)	31
Interest on repayable contribution	(228)	(214)	7
Interest on lease liability	(50)	(15)	233
Total interest income and other expense	472	1,166	(60)
Per boe ($)	0.24	0.66	(64)

For the three months ended March 31, 2025, interest income and other expense decreased to $0.5 million from $1.2 million in the corresponding period of the prior year mainly due to lower interest income and higher accretion on decommissioning liability. The decrease in interest income for the three months ended March 31, 2025, is a result of carrying a lower average cash balance, when compared to the same period in 2024, coupled with a decrease in the average interest rate earned over the period, driven by a series of prime rate cuts in the second half of 2024 and into 2025. Accretion on decommissioning liability has increased due to the Company's 2024 and 2025 drilling programs.

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.

Stock-Based Compensation

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Stock options	-	149	(100)
Deferred share units	790	1,215	(35)
Share awards	2,054	1,759	17
Capitalized stock-based compensation	(480)	(400)	20
Stock-based compensation	2,364	2,723	(13)
Per boe ($)	1.19	1.54	(23)

During the three months ended March 31, 2025, stock-based compensation expense decreased to $2.4 million from $2.7 million in the corresponding period of the prior year, driven by lower expense for deferred share units ("DSUs") due to a decrease in Headwater's share price from $6.61 at December 31, 2024 to $6.45 at March 31, 2025, partially offset by higher expense for share awards due to new grants in the period. The expense for stock options was $nil due to all outstanding stock options being fully vested.

Share Awards (Cash-Settled)

The Company has an incentive awards plan (the "Award Plan") that 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 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"). For PSUs, the amount of stock-based compensation payable and related expense is adjusted based on a performance multiplier ranging from 0 to 2 times, which is based on certain corporate performance measures, as determined by the Board.

During the fourth quarter of 2024, the Board approved the cash settlement of the Company's outstanding PSUs. Previously, PSUs had been accounted for as equity-settled. As a result of this modification to the Company's outstanding PSUs from equity-settled to cash-settled, the fair value of the PSUs 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 PSUs and any subsequent remeasurement of the liability is also recognized in the Statement of Income and Comprehensive Income.

As at March 31, 2025, there were 483,193 RSUs outstanding and 3,736,260 PSUs outstanding.

Deferred Share Units (Cash-Settled)

The Company also has a DSU plan (the "DSU Plan") that 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 a director of the Company. DSUs are to be settled in cash or by payment in common shares acquired through the facilities of the 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, 2025.

As at March 31, 2025, there were 525,259 DSUs outstanding.

Stock Options

As at March 31, 2025, there were 130,002 stock options outstanding. The Company did not grant any stock options in 2025, 2024 or 2023 and does not intend to grant any further options under the Company's stock option plans.

Depletion & Depreciation

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Depletion	32,284	30,467	6
Depreciation	231	61	279
Depletion & depreciation	32,515	30,528	7
Depletion – Per boe ($)	16.29	17.21	(5)
Depreciation – Per boe ($)	0.12	0.03	300
Depletion & depreciation per boe ($)	16.41	17.24	(5)

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, 2025, increased slightly to $32.1 million from $30.5 million in the corresponding period of 2024, due to an increase in the Company's production volumes over the period.

Depletion expense per boe decreased during the three months ended March 31, 2025, when compared to the corresponding period of 2024, primarily due to significant reserve additions recorded in Headwater's 2024 year-end reserves report, resulting from successful drilling and waterflood results.

Impairment Assessment

As at March 31, 2025, 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.

Current and Deferred Income Taxes

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Current income tax expense	10,770	12,233	(12)
Deferred income tax (recovery) expense	4,408	(670)	(758)
Total income tax expense	15,178	11,563	31
Current income tax expense – Per boe ($)	5.43	6.91	(21)
Deferred income tax (recovery) expense – Per boe ($)	2.22	(0.38)	(684)
Total income tax expense – Per boe ($)	7.65	6.53	17

For the three months ended March 31, 2025, the Company recorded current income taxes of $10.8 million and deferred income tax expense of $4.4 million, respectively, compared to current income taxes of $12.2 million and a deferred income tax recovery of $670 thousand in the corresponding period of the prior year.

Current income taxes decreased as a result of lower forecast adjusted funds flow from operations for the year ended December 31, 2025, compared to the prior year due to lower forecast commodity pricing. Deferred income tax expense increased due to higher expense recognized for the Company's PSUs, following the PSU payout in March 2025.

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 Change
	2025	2024
	(thousands of dollars)
Cash flows provided by operating activities	69,935	55,047	27
Changes in non-cash working capital	6,888	4,628	49
Current income taxes	(10,770)	(12,233)	(12)
Income taxes paid	26,306	29,004	(9)
Adjusted funds flow from operations (1)	92,359	76,446	21
	Three months ended March 31,		Percent Change
---	---	---	---
	2025	2024
	($/boe)
Cash flows provided by operating activities	35.29	31.09	14
Changes in non-cash working capital	3.48	2.61	33
Current income taxes	(5.43)	(6.91)	(21)
Income taxes paid	13.27	16.38	(19)
Adjusted funds flow netback (2)	46.61	43.17	8

(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-GAAP ratio. Refer to the advisory "Non-GAAP and Other Financial Measures".

For the three months ended March 31, 2025, adjusted funds flow from operations increased to $92.4 million from $76.4 million in the corresponding period of the prior year as a result of a 15% increase in realized commodity pricing coupled with a 13% increase in sales volumes, partially offset by higher overall cash costs including realized losses on financial derivatives, royalties, blending and transportation and production expense.

Capital Expenditures

	Three months ended March 31,		Percent Change
	2025	2024
	(thousands of dollars)
Land acquisition, retention and geological & geophysical	9,047	11,729	(23)
Site preparation	7,181	5,875	22
Drilling and completions	34,529	37,152	(7)
Equipping and facilities	12,090	10,511	15
Capital expenditures (1)	62,847	65,267	(4)

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

During the three months ended March 31, 2025, the Company invested a total of $62.8 million on capital expenditures including $34.5 million on drilling and completions, $12.1 million on equipping and facilities, $9.1 million on land acquisition and geological & geophysical costs and $7.2 million on site preparation including road construction.

Drilling Activity

The following table summarizes the Company's drilling results:

	Three months ended March 31,
	2025		2024
	Gross	Net	Gross	Net
Heavy crude oil	12	11.0	20	20.0
Natural gas	-	-	-	-
Injection	4	4.0	3	3.0
Source/stratigraphic test	4	4.0	3	3.0
Total	20	19.0	26	26.0

(1) Wells included in the above table were rig released during the quarters.

Decommissioning Liabilities

As at March 31, 2025, the decommissioning liability of the Company was $53.1 million. The Company recorded an increase of $4.5 million in the obligation from the decommissioning liability of $48.6 million as at December 31, 2024. This increase of $4.5 million is due to additions of $2.1 million, an upward change in estimate of $2.1 million and accretion expense of $0.4 million, partially offset by settlements of $0.1 million. The change in estimate is a result of a decrease to the risk-free rate from 3.3% at December 31, 2024 to 3.2% at March 31, 2025, coupled with an increase to the inflation rate from 1.8% at December 31, 2024 to 1.9% at March 31, 2025. The total undiscounted uninflated amount of estimated cash flows required to settle these obligations is $79.1 million (December 31, 2024 - $76.1 million).

2025 Guidance

Headwater is reconfirming its guidance as reported on March 13, 2025.

| | 2025 Guidance
March 13, 2025
and May 1, 2025 |
| --- | --- |
| Average Daily Production | |
| Annual (boe/d) | 22,250 |
| Pricing | |
| Crude oil - WTI (US$/bbl) | 70.00 |
| Crude oil - WCS (Cdn$/bbl) | 79.40 |
| Exchange rate (Cdn$ to US$) | 0.72 |
| Natural gas - AGT (US$/mmbtu) | 9.00 |
| Financial Summary ($millions) | |
| Estimated capital expenditures (1) | 225 |
| Estimated adjusted funds flow from operations (2) | 320 |
| Quarterly dividend (3) | $0.11/common share |
| Estimated exit adjusted working capital (2) (4) | 45 |

(1) Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.
(2) 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.
(3) Refer to "Dividend Policy" within this MD&A.
(4) Exit adjusted working capital will be reduced to the extent that the Company purchases common shares pursuant to the NCIB.
(5) For assumptions utilized in respect of the above guidance, see "Forward Looking Information" within this MD&A.

Liquidity and Capital Resources

The Company's objectives when managing capital are to i) deploy capital to provide an appropriate return on investment to its shareholders; ii) maintain financial flexibility in order to preserve the Company's ability to meet financial obligations; and iii) maintain a capital structure that provides financial flexibility to execute strategic acquisitions. To aid in managing the capital structure, the Company monitors adjusted working capital and adjusted funds flow from operations, supplemented as necessary by equity and debt financings.

During the years ended December 31, 2024 and 2023, the Company declared dividends of $95.0 million and $94.4 million, respectively, related to its quarterly cash dividend ($0.10 per common share per quarter or $0.40 per common share annualized).

The Company increased its quarterly cash dividend to $0.11 per common share ($0.44 per common share annualized) effective for the dividend to be paid on April 15, 2025 to shareholders of record at the close of business on March 31, 2025.

As at March 31, 2025, the Company had cash of $125.6 million, adjusted working capital of $63.6 million and no outstanding bank debt. The Company expects to have adequate liquidity to fund its 2025 capital expenditure budget of $225 million, quarterly cash dividends and contractual obligations in the near term through existing working capital and forecasted adjusted funds flow from operations. Headwater anticipates that it will make use of debt or equity financing for any substantial expansion of its capital program or to finance any significant acquisitions.

To the extent that the Company's existing working capital is not sufficient to pay the cash portion of the purchase price for any future acquisition, Headwater anticipates that it will make use of additional equity or debt financings as available. Alternatively, the Company may issue equity as consideration to complete any future acquisition.

Subsequent to March 31, 2025, Headwater announced TSX approval of the NCIB to purchase for cancellation up to 19,020,755 common shares during the period commencing on May 6, 2025.

Credit Facilities

The Company has a senior secured revolving syndicated credit facility with the National Bank of Canada and the Bank of Montreal ("the Lenders"). The credit facility is comprised of extendible revolving credit facilities consisting of a $20.0 million operating facility and an $80.0 million syndicated facility. Headwater also has an uncommitted accordion feature that provides the Company with the ability to access an incremental $100.0 million, subject to certain conditions including approval from the Lenders.

As at March 31, 2025, Headwater had not drawn on the credit facility.

The credit facilities have a revolving period of 364 days, extendible annually at the request of the Company, subject to approval of the Lenders. If not extended, the credit facilities will automatically convert to a term loan and all outstanding obligations will be repayable one year after the expiry of the revolving period. The borrowing base is subject to semi-annual redeterminations occurring by May 31st and by November 30th of each year. The credit facilities are secured by a demand debenture in the amount of $500 million.

Repayments of principal are not required until the maturity date, provided that the borrowings do not exceed the authorized borrowing base and the Company is in compliance with all covenants, representations and warranties.

The credit facility bears interest at a floating market rate with margins charged by the Lenders linked to the Company's senior debt to EBITDA ratio. EBITDA, for the purposes of calculating the senior debt to EBITDA ratio, is calculated as net income adjusted for non-cash items, interest expense and income taxes. Senior debt, for the purposes of calculating the senior debt to EBITDA ratio, is calculated as any debt of the Company excluding the financial derivative liability and repayable contribution.

The credit facility is not subject to any financial covenants. Additionally, distributions are permitted subject to compliance with a Board approved distributions policy.

Contractual Obligations and Commitments

As at March 31, 2025, the Company is committed to future payments under the following agreements:

(thousands)	Total	2025	2026	2027	2028	2029	Thereafter
	$	$	$	$	$	$	$
Transportation and operating (1)	165,154	15,393	25,876	27,348	27,775	26,627	42,135
Lease (2)	2,025	339	460	468	476	282	-
Government grant (3)	14,168	1,417	4,675	8,076	-	-	-

(1) At March 31, 2025, Headwater has the following transportation commitments:

a. 6-year take-or-pay transportation agreement with a minimum volume commitment of 10,000 boe/d.
b. 6-year financial commitment at $1.9 million per year adjusted for inflation.
c. 6-year take-or-pay transportation agreement with a current minimum volume commitment of 9,750 boe/d, increasing to 12,500 boe/d in 2026.
d. 4-year take-or-pay transportation agreement with a current minimum volume of 191 m³/d, increasing to 318 m³/d mid-2025 and increasing to 398 m³/d for the remaining 3 years.
e. Long-term fixed take-or-pay contract with a daily minimum volume commitment of 5,000 mcf/d and a cumulative minimum volume commitment of 21.9 bcf.
f. 5.5-year take-or-pay transportation agreement with a minimum volume commitment of 4,000 boe/d.

(2) Relates to variable operating costs, which are a non-lease component of the Company's head office lease.

(3) Relates to scheduled undiscounted re-payments of federal government funding under the terms of the repayable contribution agreement with Natural Resources Canada.

(4) Excludes leases accounted for under IFRS 16.

Common Share Information

Share Capital

(thousands)	Three months ended March 31,
	2025	2024
Weighted average outstanding common shares (1)
-Basic	237,772	235,742
-Diluted	237,813	237,552
Outstanding securities at March 31, 2025
-Common shares		237,774
-Stock options – weighted average strike price of $4.56		130
-Restricted share units		483
-Performance share units		3,736
-Deferred share units		525

(1) The Company uses the treasury stock method to determine the dilutive effect of stock options, RSUs and PSUs. Under this method, only "in-the-money" dilutive instruments impact the calculation of diluted income per common share. This method also assumes that the proceeds received from the exercise of all "in-the-money" dilutive instruments are used to repurchase shares at the average market price.

Changes to share capital during the three months ended March 31, 2025, were the following:

47 thousand stock options were exercised for 17 thousand common shares on a cashless basis. Contributed surplus related to the options exercised of $85 thousand was transferred to capital stock.

Changes to share capital during the three months ended March 31, 2024, were the following:

1.3 million stock options were exercised for 0.7 million common shares on a cashless basis, and 33 thousand stock options were exercised for 33 thousand common shares for total proceeds of $35 thousand. Contributed surplus related to the options exercised of $1.9 million was transferred to capital stock.

Total Market Capitalization

The Company's market capitalization at March 31, 2025 was approximately $1.5 billion.

(thousands)	March 31, 2025
Common shares outstanding	237,774
Share price (1)	$ 6.45
Total market capitalization	$1,533,642

(1) Represents the closing price on the TSX on March 31, 2025.

As at May 1, 2025 the Company had 237,774,464 common shares outstanding.

(thousands)	May 1, 2025
Outstanding securities at May 1, 2025
-Common shares	237,774
-Stock options – weighted average strike price of $4.56	130
-Restricted share units	479
-Performance share units	3,736
-Deferred share units	525

Environmental, Social and Governance ("ESG") Update

The following is an update on environmental, social and governance matters:

On December 17, 2024, a third-party natural gas gathering system in Marten Hills West was commissioned resulting in a meaningful amount of Headwater's natural gas in the area being conserved, while also significantly reducing Headwater's carbon tax obligations in the area.
On March 21, 2024, the Board approved a new Human Rights Policy. All Headwater employees have been provided with the policy and are required to signoff on it and abide by its principles.
Headwater has received total funding of $17.7 million from Natural Resources Canada ("NRCan") in connection with four claim submissions to the Emissions Reduction Fund program. NRCan has provided financial assistance by way of a partially repayable interest-free loan to the Company for its working interest in the joint Marten Hills natural gas processing plant and gathering system, as well as for gas conservation equipment associated with the Company's wholly owned oil processing facility in Marten Hills (the "Project"). Headwater will repay 80% of the financial assistance pursuant to the terms and conditions of the agreement,

with the remaining 20% being non-repayable. The Project is intended to partially eliminate venting and flaring of methane rich natural gas from existing and future oil wells in the Company's core area of Marten Hills. The repayable portion of the funds received are to be repaid as follows: 10% on June 30, 2025, 33% on June 30, 2026, and 57% on June 30, 2027.

In addition to the Environment, Safety and Sustainability Committee, the Board has also established the Audit Committee, Reserves Committee and Corporate Governance and Compensation Committee which are all comprised of independent members of the Board. The Audit Committee and the Reserves Committee ensure the integrity of the financial and reserves reporting of the Company, while the Corporate Governance and Compensation Committee is charged with independent oversight of the director nomination process, executive compensation decisions and other corporate governance matters. For additional information relating to the governance policies and structure of the Company see the Company's management information circular dated March 25, 2025 for the annual meeting of the shareholders to be held on May 8, 2025, which is available on SEDAR+ at www.sedarplus.ca and the information under the heading Corporate Responsibility on the Company's website at www.headwaterexp.com.

Summary of Quarterly Information

	Q1/25	Q4/24	Q3/24	Q2/24	Q1/24	Q4/23	Q3/23	Q2/23
Financial (thousands of dollars except share data)
Total sales	170,155	163,107	158,382	164,281	134,034	138,426	149,632	118,967
Total sales, net of blending (1)(2)	163,188	156,475	151,740	157,057	127,366	131,690	144,003	112,560
Adjusted funds flow from operations (3)	92,359	87,903	84,185	88,023	76,446	81,983	80,887	66,235
Per share - basic (4)	0.39	0.37	0.35	0.37	0.32	0.35	0.34	0.28
- diluted (4)	0.39	0.37	0.35	0.37	0.32	0.34	0.34	0.28
Cash flows provided by operating activities	69,935	76,016	95,272	90,402	55,047	90,690	85,568	66,857
Net income	50,004	48,907	47,634	53,868	37,619	45,469	49,677	30,947
Per share - basic	0.21	0.21	0.20	0.23	0.16	0.19	0.21	0.13
- diluted	0.21	0.21	0.20	0.22	0.16	0.19	0.21	0.13
Capital expenditures (2)	62,847	48,686	58,196	50,717	65,267	30,050	70,208	64,094
Depletion and depreciation	32,515	31,382	32,015	30,958	30,528	31,476	30,723	29,341
Adjusted working capital (3)	63,616	67,578	64,411	62,381	48,841	63,526	35,921	48,968
Working capital	72,107	78,735	74,925	72,404	58,336	78,610	43,496	54,765
Shareholders' equity	723,431	699,459	684,486	658,448	625,675	610,498	587,380	559,779
Dividends declared	26,155	23,776	23,767	23,765	23,729	23,658	23,638	23,586
Per share	0.11	0.10	0.10	0.10	0.10	0.10	0.10	0.10
Weighted average shares (thousands)
Basic	237,772	237,512	237,484	237,275	235,742	236,408	236,191	235,631
Diluted (5)	237,813	237,569	239,735	239,452	237,552	238,872	239,167	237,913
Shares outstanding, end of period (thousands)
Basic	237,774	237,757	237,665	237,654	237,290	236,580	236,384	235,864
Diluted (6)	237,904	237,934	241,115	241,075	241,356	241,138	241,175	241,240
Operating (6:1 boe conversion)
Average daily production
Heavy oil (bbls/d)	19,511	20,304	19,718	18,825	17,512	18,514	16,902	15,624
Natural gas (mmcf/d)	14.5	7.2	3.4	5.5	11.5	8.0	6.1	8.5
Natural gas liquids (bbls/d)	142	51	64	67	87	93	103	107
Barrels of oil equivalent (boe/d) (7)	22,066	21,559	20,342	19,805	19,517	19,939	18,027	17,152
Average daily sales (8)	22,019	21,543	20,329	19,754	19,459	20,134	17,862	17,154
Average selling prices
Heavy oil ($/bbl)	83.76	80.26	83.35	90.89	76.04	74.69	92.05	77.14
Natural gas ($/mcf)	11.22	8.91	0.25	2.04	5.03	3.00	2.36	2.51
Natural gas liquids ($/bbl)	80.82	77.84	79.95	93.25	70.69	73.53	86.65	75.01
Barrels of oil equivalent ($/boe)	81.94	78.76	81.09	87.26	71.49	70.94	87.56	71.98
Netbacks ($/boe) (9)
Operating
Sales, net of blending (1)(2)	82.35	78.95	81.13	87.37	71.93	71.09	87.63	72.11
Realized gain (loss) on financial derivatives	(1.60)	(0.35)	0.18	(0.44)	3.45	3.35	0.18	0.21
Royalties	(14.47)	(13.81)	(15.74)	(16.49)	(12.34)	(12.91)	(16.26)	(12.63)
Transportation	(5.41)	(5.26)	(5.90)	(5.54)	(5.35)	(5.12)	(5.32)	(5.48)
Production	(7.93)	(7.64)	(7.46)	(7.24)	(7.04)	(7.34)	(7.43)	(7.33)
Operating netback, including financial derivatives ($/boe) (4)	52.94	51.89	52.21	57.66	50.65	49.07	58.80	46.88
General and administrative	(1.44)	(1.53)	(1.42)	(1.50)	(1.47)	(1.51)	(1.52)	(1.49)
Interest income and other expense (10)	0.59	0.60	0.76	0.81	0.95	0.84	0.85	0.96
Current income taxes	(5.43)	(6.62)	(6.54)	(8.01)	(6.91)	(4.14)	(8.91)	(3.91)
Settlement of decommissioning liability	(0.05)	-	-	-	(0.05)	-	-	-
Adjusted funds flow netback ($/boe) (4)	46.61	44.34	45.01	48.96	43.17	44.26	49.22	42.44

(1) Heavy oil sales are netted with blending expense to compare the realized price to benchmark. In the interim financial statements, blending is recorded in blending and transportation expense.
(2) Non-GAAP financial measure. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.
(3) 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.
(4) Non-GAAP ratio. Refer to the advisory "Non-GAAP and Other Financial Measures".
(5) Diluted weighted average shares outstanding includes the impact of any stock options, RSUs and PSUs that would be outstanding as dilutive instruments using the treasury stock method. The number of outstanding RSUs and PSUs have been adjusted for dividends.
(6) Includes in-the-money dilutive instruments as at March 31, 2025 which include 0.1 million stock options with a weighted average exercise price of $4.56. RSUs and PSUs have been excluded as the Company intends to cash settle these awards.
(7) See barrels of oil equivalent under "Oil and Gas Measures".
(8) Includes sales of unblended heavy crude oil. The Company's heavy oil sales volumes and production volumes differ due to changes in inventory.
(9) Netbacks are calculated using average sales volumes.
(10) Excludes unrealized foreign exchange gains/losses, accretion on decommissioning liabilities, interest on repayable contribution and interest on the lease liability.

Headwater has experienced significant quarterly growth over the past two years as a result of its significant capital expenditure programs. The Company has grown production from 17,152 boe/d in the second quarter of 2023 to 22,066 boe/d in the first quarter of 2025, representing a 29% increase, while maintaining a significant positive working capital balance and distributing a quarterly dividend since announcing its dividend policy in the fourth quarter of 2022. This production growth is attributed to successful drilling and waterflood results in the Company's Marten Hills core and west areas, as well as discoveries in newer areas including Greater Peavine and Greater Nipisi. Record production in the first quarter of 2025 contributed to record adjusted funds flow from operations of $92.4 million, funding capital expenditures of $62.8 million, while generating free cashflow of $29.5 million. Subsequent to March 31, 2025, Headwater announced TSX approval of its NCIB to purchase for cancellation up to 19,020,755 common shares.

Off-Balance Sheet Arrangements

All off-balance sheet arrangements are in the normal course of business. Refer to the commitments under the heading "Contractual Obligations and Commitments".

Subsequent Events

NCIB

Subsequent to March 31, 2025, the TSX approved Headwater's NCIB application to purchase for cancellation up to 19,020,755 common shares during the period commencing on May 6, 2025, and terminating on the earlier of: (i) the date on which the Company has acquired all common shares sought pursuant to the NCIB; or (ii) to May 5, 2026, unless earlier terminated at the option of the Company, upon prior notice being given to the TSX.

Dividend

Subsequent to March 31, 2025, the Company declared a cash dividend of $0.11 per common share. The dividend will be paid on July 15, 2025, to shareholders of record at the close of business on June 30, 2025.

Financial Derivative Contracts

Subsequent to March 31, 2025, Headwater entered into the following commodity contracts:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Crude Oil	WCS Basis	Differential	Oct 2025 – Dec 2025	1,000 bbl	US$13.90/bbl
Natural Gas	AECO 5A	Fixed	Apr 2026 – Oct 2026	1,000 GJ	Cdn$2.90/GJ

Non-GAAP and Other Financial Measures

Throughout this MD&A, the Company uses various non-GAAP and other financial measures to analyze operating performance and financial position. These non-GAAP and other financial measures do not have standardized meanings prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities.

Non-GAAP Financial Measures

Free cash flow

Management utilizes free cash flow to assess the amount of funds available for future capital allocation decisions. It is calculated as adjusted funds flow from operations net of capital expenditures.

	Three months ended March 31,
	2025	2024
	(thousands of dollars)
Adjusted funds flow from operations	92,359	76,446
Capital expenditures	(62,847)	(65,267)
Free cash flow	29,512	11,179

Heavy oil sales, net of blending

Management utilizes heavy oil sales, net of blending expense to compare realized pricing to WCS benchmark pricing. It is calculated by deducting the Company's blending expense from heavy oil sales. In the interim financial statements blending expense is recorded within blending and transportation expense.

	Three months ended March 31,
	2025	2024
	(thousands of dollars)
Heavy oil sales	153,684	127,446
Blending expense	(6,967)	(6,668)
Heavy oil sales, net of blending expense	146,717	120,778

Total sales, net of blending

Management utilizes total sales, net of blending expense to compare realized pricing to benchmark pricing. It is calculated by deducting the Company's blending expense from total sales. In the interim financial statements blending expense is recorded within blending and transportation expense.

	Three months ended March 31,
	2025	2024
	(thousands of dollars)
Total sales	170,155	134,034
Blending expense	(6,967)	(6,668)
Total sales, net of blending expense	163,188	127,366

Capital expenditures

Management utilizes capital expenditures to measure total cash capital expenditures incurred in the period. Capital expenditures represents capital expenditures – E&E and capital expenditures – PP&E in the statement of cash flows in the Company's interim financial statements.

	Three months ended March 31,
	2025	2024
	(thousands of dollars)
Cash flows used in investing activities	63,103	51,580
Proceeds from government grant	-	177
Change in non-cash working capital	(256)	13,510
Capital expenditures	62,847	65,267

Capital Management Measures

Adjusted funds flow from operations

Management considers adjusted funds flow from operations to be a key measure to assess the Company's management of capital. Adjusted funds flow from operations is an indicator as to whether adjustments are necessary to the level of capital expenditures. For example, in periods where adjusted funds flow from operations is negatively impacted by reduced commodity pricing, capital expenditures may need to be reduced or curtailed to preserve the Company's capital structure and return of capital policy. Management believes that by excluding the impact of changes in non-cash working capital and adjusting for current income taxes in the period, adjusted funds flow from operations provides a useful measure of Headwater's ability to generate the funds necessary to manage the capital needs of the Company.

	Three months ended March 31,
	2025	2024
	(thousands of dollars)
Cash flows provided by operating activities	69,935	55,047
Changes in non-cash working capital	6,888	4,628
Current income taxes	(10,770)	(12,233)
Current income taxes paid	26,306	29,004
Adjusted funds flow from operations	92,359	76,446

Adjusted working capital

Adjusted working capital is a capital management measure which management uses to assess the Company's liquidity. Financial derivative receivable/liability have been excluded as these contracts are subject to a high degree of volatility prior to settlement and relate to future production periods. Financial derivative receivable/liability are included in adjusted funds flow from operations when the contracts are ultimately realized. Management has included the effects of the repayable contribution to provide a better indication of Headwater's net financing obligations.

	March 31, 2025	December 31, 2024
	(thousands of dollars)
Working capital	72,107	78,735
Repayable contribution	(11,118)	(10,916)
Financial derivative receivable	(149)	(3,088)
Financial derivative liability	2,776	2,847
Adjusted working capital	63,616	67,578

Non-GAAP Ratios

Adjusted funds flow netback, operating netback and operating netback, including financial derivatives

Adjusted funds flow netback, operating netback and operating netback, including financial derivatives are non-GAAP ratios and are used by management to better analyze the Company's performance against prior periods on a more comparable basis.

Adjusted funds flow netback is defined as adjusted funds flow from operations divided by sales volumes in the period.

Operating netback is defined as sales less royalties, transportation and blending costs and production expense divided by sales volumes in the period. Sales volumes exclude the impact of purchased condensate and butane. Operating netback, including financial derivatives is defined as operating netback plus realized gains (losses) on financial derivatives.

Adjusted funds flow per share

Adjusted funds flow per share is a non-GAAP ratio used by management to better analyze the Company's performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding during the applicable period on a basic or diluted basis.

Average royalty rate

The Corporate average royalty rate is a non-GAAP ratio used by management to better analyze the Company's performance against prior periods on a more comparable basis and are calculated as total royalties divided by total sales, net of blending expense, expressed as a percentage.

Supplementary Financial Measures

Per boe numbers

This MD&A represents various results on a per boe basis including financial derivatives gains (losses) per boe, royalty expense per boe, transportation expense per boe, transportation and blending expense per boe, production expense per boe, sales per boe, realized gain (loss) on financial derivatives per boe, general and administrative expenses per boe, interest income and other expense per boe, stock-based compensation expense per boe, depletion expense per boe, depreciation expense per boe, depletion and depreciation expense per boe, current income tax expense per boe, deferred income tax expense per boe, total income tax expense per boe, cash flows provided by operating activities per boe, changes in non-cash working capital per boe and settlement of decommissioning liabilities per boe. These figures are calculated using sales volumes.

Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures as defined in National Instrument 52-109 of the Canadian Securities Administrators, to provide reasonable assurance that (i) material information relating to the Company is made known to the Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted

by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation.

Internal Controls over Financial Reporting

The Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting as defined in National Instrument 52-109 of the Canadian Securities Administrators, in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

The Company confirms that there were no changes to Headwater's internal controls over financial reporting during the interim period from January 1, 2025 to March 31, 2025 that have materially affected, or are reasonably likely to affect, the Company's internal control over financial reporting.

It should be noted that while Headwater's Chief Executive Officer and Chief Financial Officer believe that the Company's internal controls and procedures provide a reasonable level of assurance and that they are effective, they do not expect that these controls will prevent all errors or fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Critical Accounting Estimates

Use of estimates and judgments

The preparation of the Company's financial statements in accordance with IFRS requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Such estimates and assumptions are evaluated at each reporting date and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Estimates are more difficult to determine, and the range of potential outcomes can be wider, in periods of higher volatility and uncertainty. The impacts of various events such as the Russian invasion of Ukraine and the threat/imposition of United States tariffs on Canadian imported goods and their impact on energy markets and general market conditions, increased interest and inflation rates and supply chain uncertainties have created a higher level of volatility and uncertainty. Management has, to the extent reasonable, incorporated known facts and circumstances into the estimates made however, actual results could differ from those estimates and those differences could be material. The Company has identified the following areas requiring significant judgments, assumptions or estimates.

Tariffs

Since the inauguration of Donald Trump as president of the United States, the United States has made a number of announcements relating to imposing tariffs on exports from Canada to the United States. In response, the Canadian federal and provincial governments have announced a number of retaliatory actions including potential tariffs on certain goods exported from the United States to Canada. The U.S. has also announced tariffs on goods imported from Mexico and China. The United States government has also made several announcements pausing the imposition of tariffs. At the present time, it is unclear whether tariffs will be imposed or not and on what goods such tariffs will apply to. If imposed, it is unclear whether such tariffs will be permanent or temporary. If imposed, these tariffs, and any changes to these tariffs or imposition of any new tariffs, taxes or import or export restrictions or prohibitions, could have a material adverse effect on the Canadian economy, the Canadian oil and natural gas industry and the Company. Furthermore, there is a risk that the tariffs imposed by the U.S. on other countries will trigger a

broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company. The Company will continue to monitor the impact of this evolving situation.

Climate change

The following provides certain disclosures as to the impact of climate change on the amounts recorded in the financial statements as at and for the three months ended March 31, 2025. The below is not a comprehensive list or analysis of all climate change impacts and risks.

Emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. With respect to climate reporting, the Canadian Sustainability Standards Board ("CSSB"), in December of 2024, finalized two climate-related reporting standards, Canadian Sustainability Disclosure Standard 1 ("CSDS S1") – General Requirements for Disclosure of Sustainability-Related Financial Information and Canadian Sustainability Disclosure Standard 2 ("CSDS S2") – Climate-Related Disclosures. At this stage, companies can choose whether or not to report in accordance with CSDS S1 and S2 as such standards are completely voluntary. The Canadian Securities Administrators ("CSA") had begun their own consultation process to determine how CSDS S1 and S2 would be translated into reporting requirements for reporting issuers and the timing for the implementation of such mandatory reporting requirements; however, on April 23, 2025, the CSA announced that it would be pausing work on the development of new climate related reporting requirements due to current global economic and geopolitical uncertainty and rising competitive concerns for Canadian issuers. The CSA has noted that it expects to revisit the adoption of climate related disclosures in the future. To the extent that any new climate or sustainability related standards are adopted in the future, the Company would incur additional costs to comply with such standards.

The Company has considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in its assessment as a possible indication of impairment of its oil and gas properties. The Company completed the analysis of triggers for impairment as at March 31, 2025 and climate risk/climate change, in of itself, did not result in the Company completing an impairment test. The Company has considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in its assessment of depletion on its oil and gas properties. Depletion of the Company's oil and gas properties was based on proved and probable reserves, the life of which is generally less than 30 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain, however, the majority of the Company's proved and probable reserves per the 2024 reserve report should be realized prior to the elimination of carbon-based energy. At this time, the Company has not capped its reserve life for purposes of calculating depletion expense, however, this estimate will be monitored as the energy evolution continues.

The Company engages a third-party external reserve engineer to prepare the reserve report. The reserve report includes anticipated impacts from emissions related taxes, most notably the reserve report includes estimated carbon tax related to the Company's operations consistent with the Emissions Management and Climate Resilience Act (Alberta).

The evolving energy transition and general public sentiment to the oil and gas industry may result in reduced access to capital markets. Management will continue to adjust the capital structure as necessary in response to changing industry conditions.

The Company maintains insurance coverage that provides a level of insurance for certain events that may arise due to climate change factors; however, the Company's insurance program is subject to limits and various restrictions. No claims were made under the Company's insurance policies in the three months ended March 31, 2025 with respect to climate related matters.

Critical Judgments in Applying Accounting Policies

Determination of cash-generating units ("CGU") and impairment

The determination of what constitutes a CGU used to test the recoverability of the carrying values of the Company's oil and gas properties is subject to management's judgment. Judgments are made in regard to shared infrastructure, geographical proximity, petroleum type and similar exposure to market risks and materiality. The asset composition of a CGU can directly impact the recoverability of the assets included therein.

Judgments are required to assess when impairment or impairment reversal indicators exist and impairment testing is required.

Exploration and evaluation ("E&E") assets

The application of the Company's accounting policy for E&E assets requires management to make certain judgments as to whether economic quantities of reserves have been found. Judgment is also required to determine the level at which E&E is assessed for impairment; for Headwater, the recoverable amount of E&E assets is assessed at a CGU level.

Key Sources of Estimation Uncertainty

Recoverability of asset carrying value and the impact of reserves on depletion and the evaluation of the recoverable amount of a CGU

At each reporting date, the Company assesses its PP&E and E&E assets to determine if there is any indication that the carrying amount of the assets may not be recoverable. An assessment is also made at each reporting date to determine whether there is any indication that previously recognized impairment losses no longer exist or have decreased. Determination as to whether and how much an asset is impaired, or no longer impaired, involves management's estimates on highly uncertain matters. The key estimates used in the determination of cash flows from crude oil and natural gas reserves and the volume of proved and probable crude oil and natural gas reserves include the following:

Reserves and forecasted production – assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in future price estimates, production levels or results of future drilling may change the economic status of reserves and may ultimately result in reserve revisions.
Forecasted crude oil and natural gas prices – commodity prices can fluctuate for a variety of reasons including supply and demand fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors.
Discount rate – the discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate.
Forecasted operating and royalty costs and future development costs – estimates concerning future drilling and infrastructure costs and production costs required to operate the assets are used in the cash flow model.

Changes in circumstances may impact these estimates which could have a material financial impact in future periods.

Reserves estimates also have a material financial impact on depletion expense and decommissioning liabilities, all of which could have a material impact on financial results. These reserve estimates are evaluated by third-party reserve evaluators at least annually, who work with information provided by the Company to establish reserve determinations in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Changes in circumstances may impact these estimates which could have a material financial impact in future periods.

Decommissioning liabilities

The decommissioning costs which will ultimately be incurred by the Company are uncertain and estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing can also change in response to changes in reserves or changes in laws and regulations. As a result, there could be significant adjustments to the provisions established which could materially affect future financial results. Judgments include the most appropriate discount rate to use, which management has determined to be a risk-free rate.

Valuation of financial instruments

The estimated fair values of the Company's financial derivative commodity contracts are subject to measurement uncertainty due to the estimation of future crude oil and natural gas commodity prices and volatility.

Valuation of PSUs

The estimate of stock-based compensation in respect of the Company's PSUs is dependent on the performance multiplier estimated by management.

Recently announced accounting pronouncements

IFRS 18 "Presentation and disclosure in financial statements" has been issued which will replace IAS 1 "Presentation of financial statements". The new standard establishes a revised structure for the statements of comprehensive profit with the intention to improve comparability across entities. IFRS 18 is effective for annual periods beginning on or after January 1, 2027 and will be applied retroactively. The Company is currently evaluating the impact of adopting IFRS 18 on the financial statements.

Amendments to IFRS 9 "Financial instruments and IFRS 7 Financial instruments: disclosures" have been issued with the intention to clarify the date of recognition and derecognition of some financial assets and liabilities. The amendments are effective January 1, 2026, with early adoption permitted. The Company is currently evaluating the impact of these amendments on the financial statements.

Changing regulation

On June 26, 2023, the ISSB issued IFRS S1 - General Requirements for Disclosure of Sustainability Related Financial Information ("IFRS S1"), and IFRS S2 - Climate Related Disclosures ("IFRS S2").

On December 18, 2024, the CSSB released final versions of CSDS S1 and CSDS S2, following which the Canadian Securities Administrators have begun their own consultation process to determine how the reporting standards will be translated into reporting requirements for reporting issuers and the timing for the implementation of such mandatory reporting requirements. At this stage, companies can choose whether or not to report in accordance with CSDS S1 and CSDS S2 as the standards are completely voluntary. The CSDS S1 and CSDS S2 are effective for annual reporting periods beginning on or after January 1, 2025. The sustainability standards provide for further transition relief that allow for: (i) two additional years of relief for the start of aligned reporting, with such reporting being required within the first six months following the

second- and third-year end respectively, (ii) three years of relief for only the quantitative aspects of scenario analysis data reporting (not qualitative aspects), and (iii) an additional year of transition relief for scope 3 GHG emissions reporting. The CSA had begun their own consultation process to determine how CSDS S1 and S2 would be translated into reporting requirements for reporting issuers and the timing for the implementation of such mandatory reporting requirements; however, on April 23, 2025, the CSA announced that it would be pausing work on the development of new climate related reporting requirements due to current global economic and geopolitical uncertainty and rising competitive concerns for Canadian issuers. The CSA has noted that it expects to revisit the adoption of climate related disclosures in the future. To the extent that any new climate or sustainability related standards are adopted in the future, the Company would incur additional costs to comply with such standards.

The Company intends to actively evaluate the potential effects of the new sustainability standards and any steps taken by the Canadian Securities Administrators to adopt the new standards as reporting requirements for reporting issuers; however, at this time, the Company is not able to determine the impact on future financial statements, nor the potential costs to comply with these sustainability standards.

The Canadian federal government recently made certain amendments to the Competition Act (Canada), which create new potential liability for Canadian companies relating to disclosure of their environmental goals and performance, including their climate change mitigation efforts. On December 23, 2024, the Competition Bureau published updated guidelines with respect to the amendments; however, there remain uncertainties in how these new amendments will be interpreted and applied. Until such time as further guidance is provided, the Company has decided to restrict public access to the majority of its environmental-related communications. The Company intends to continue to evaluate the amendments to the Competition Act (Canada) and any further guidance provided to determine how to provide future disclosure on its environmental goals and performance in the future.

Business Conditions and Risks

There are numerous factors both known and unknown, that could cause actual results or events to differ materially from forecast results. The following is a summary of such risk factors, which should not be construed as exhaustive:

Volatility in the market conditions for the oil and natural gas industry may affect the value of the Company's reserves and restrict its cash flow and ability to access capital to fund the development of its properties;
the risk that (i) the U.S. and/or Canadian governments implement, maintain or increase the rate or scope of new tariffs, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed by the U.S. on other countries and responses thereto could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company;
Various factors may adversely impact the marketability of oil and natural gas, affecting net production revenue, production volumes and development and exploration activities;
The anticipated benefits of acquisitions may not be achieved and the Company may dispose of non-core assets for less than their carrying value on the financial statements as a result of weak market conditions;

The impact of the Russian Ukrainian conflict and the middle east conflicts on commodity prices and the world economy could affect the Company's results, business, financial conditions or liquidity;
Natural disasters, terrorist acts, civil unrest, war, pandemics and other disruptions and dislocations may affect the Company's results, business, financial conditions or liquidity;
The Company's business may be adversely affected by political and social events and decisions made in Canada, the United States, Europe and elsewhere;
Lack of capacity and/or regulatory constraints on gathering and processing facilities and pipeline systems may have a negative impact on the Company's ability to produce and sell its oil and natural gas;
The Company competes with other oil and natural gas companies, some of which have greater financial and operational resources;
The Company's ability to successfully implement new technologies into its operations in a timely and efficient manner will affect its ability to compete;
Changes to the demand for oil and natural gas products and the rise of petroleum alternatives may negatively affect the Company's financial condition, results of operations and cash flow;
Modification to current, or implementation of additional, regulations (including environmental regimes) or royalty regimes may reduce the demand for oil and natural gas, impact the Company's cash flows and/or increase the Company's costs and/or delay planned operations;
Taxes on carbon emissions may affect the demand for oil and natural gas, the Company's operating expenses and may impair the Company's ability to compete;
Liability management programs enacted by regulators in the western provinces may prevent or interfere with the Company's ability to acquire properties or require a substantial cash deposit with the regulator;
The Company may require additional financing, from time to time, to fund the acquisition, exploration and development of properties and its ability to obtain such financing in a timely fashion and on acceptable terms may be negatively impacted by the current economic and global market volatility;
Changing investor sentiment towards the oil and natural gas industry may impact the Company's access to, and cost of, capital;
Oil and natural gas operations are subject to seasonal weather conditions and, if applicable to the Company's operations in the future, the Company may experience significant operational delays as a result;
Regulatory water use restrictions and/or limited access to water or other fluids may impact the Company's future production volumes from any future waterflood of the Company;
Credit risk related to non-payment for sales contracts or other counterparties;
Foreign exchange risk as commodity sales are based on U.S. dollar denominated benchmarks; and
The risk of significant interruption or failure of the Company's information technology systems and related data and control systems or a significant breach that could adversely affect the Company's operations.

Additional risks and information on risk factors are included in the Annual Informational Form for the year ended December 31, 2024, dated March 13, 2025, which is available on the Company's website at www.headwaterexp.com and under the Company's profile on SEDAR+ at www.sedarplus.ca.

The Company uses a variety of means to help mitigate or minimize these risks including the following:

Attracting and retaining a team of highly qualified and motivated professionals who have a vested interest in the success of the Company;

> Employing risk management instruments to minimize exposure to volatility of commodity prices;
> Maintaining a strong financial position;
> Maintaining strict environmental, safety and health practices;
> Maintaining a comprehensive insurance program;
> Managing credit risk by entering into agreements with counterparties that are highly credit worthy or investment grade; and
> Implementation of cyber security protocols and procedures to reduce to risk of failure of breach of data.

Oil and Gas Metrics

The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. Per boe amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. This equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

References to heavy oil, natural gas, and natural gas liquids in the MD&A refer to heavy crude oil, conventional natural gas and natural gas liquids, respectively, product types as defined in NI 51-101.

Dividend Policy

The amount of future cash dividends paid by the Company, if any, will be subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including, among other things, adjusted funds flow from operations, fluctuations in commodity prices, production levels, capital expenditure requirements, acquisitions, debt service requirements and debt levels, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the Board will adjust the Company's return of capital policy from time to time and, as a result, future cash dividends could be reduced or suspended entirely.

Forward Looking Information

This MD&A contains certain forward-looking statements and forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of Canadian securities laws. All statements other than statements of historical fact are forward-looking statements. Forward-looking information typically contains statements with words such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", "should" or similar words suggesting future outcomes. In particular, this MD&A contains forward-looking statements pertaining to the following:

business plans and strategies;
expectations of increased OPEC+ output in the near term;
anticipated terms of the NCIB including the expected timing for termination of the NCIB;
the anticipated advantages to shareholders of the NCIB;
the anticipated benefits to be derived from Headwater's financial derivative commodity contracts;

the Company's intent to manage fluctuations in foreign exchange gains and losses by entering into foreign exchange contracts to fix the foreign exchange rate;
the Company's intent to settle PSUs, RSUs and DSUs in cash;
the Company's intent to not grant any further options under the Option Plans;
2025 crude oil and natural gas pricing assumptions;
2025 Canadian – U.S. dollar exchange rates;
2025 budget and guidance related to annual production, capital expenditures, dividends, adjusted funds flow from operations and adjusted working capital;
the Company's objectives for managing its capital, the anticipated benefits to be derived therefrom and the anticipated means of achieving such objectives;
the expectation that the Company has adequate liquidity to fund its 2025 capital expenditure budget, future dividend payments and contractual obligations in the near term through existing working capital and forecasted adjusted funds flow from operations;
the expectation that Headwater could make use of additional equity or debt financings to fund any substantial expansion of its capital program or for future acquisitions;
the Company's future contractual obligations and commitments;
the estimated undiscounted uninflated amount of cash flows required to settle the Company's decommissioning liabilities;
the anticipated terms of the Company's quarterly dividend, including its expectation that it will be designated as an "eligible dividend";
the expectation that the majority of the Company's proved and probable reserves per the 2024 reserve report should be realized prior to the elimination of carbon-based energy;
the expectation that the energy transition and general public sentiment to oil and gas may reduce access to capital markets and the expectation that the Company will adjust its capital structure as necessary in response to changing industry conditions;
the Company's intent to evaluate the potential effects of CSDS S1 and S2 and any steps taken by the Canadian Securities Administrators to adopt the new standards as reporting requirements for reporting issuers;
the Company's intent to evaluate the amendments to the Competition Act (Canada) and any guidance provided to determine how to provide future disclosure on its environmental goals and performance in the future; and
the Company's dividend policy;
The Company's intent to use the NBIC and cancel shares.

Statements relating to "reserves" are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described, as applicable, exist in the quantities predicted or estimated and can profitably be produced in the future. Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward-looking statements will not occur. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based, will in fact be realized. Actual results will differ, and the difference may be material and adverse to the Company and its shareholders.

The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, receipt of required regulatory approval, the success of future drilling, development and waterflooding activities, the performance of existing wells, the performance of new wells, Headwater's growth strategy, general economic conditions including inflationary pressures, availability of required equipment and services, prevailing equipment and services costs and prevailing commodity prices. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct.

This MD&A contains information that may be considered a financial outlook or future-oriented financial information under applicable securities laws about the Company's potential financial position, including but not limited to: the Company's 2025 budget and guidance related to capital expenditures, dividends, adjusted funds flow from operations and adjusted working capital; the Company's future contractual obligations and commitments; and the estimated amount to settle the Company's decommissioning liabilities. Any financial outlook or future-oriented financial information in this MD&A, as defined by applicable securities legislation, has been approved by management of the Company as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for the periods specified herein has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. The assumptions used in the 2025 guidance include the assumptions identified above and the following: annual average production of 22,250 boe/d, WTI of US$70.00/bbl, WCS of Cdn$79.40/bbl, AGT US$9.00/mmbtu, AECO of Cdn$2.20/GJ, foreign exchange rate of Cdn$ to US$ of 0.72, blending expense of WCS less $1.90/bbl, royalty rate of 18.3%, operating and transportation costs of $13.95/boe, G&A and interest income and other expense of $1.30/boe and cash taxes of $4.70/boe. The AGT price is the average price for the winter producing months in the McCully field which include January to April and November to December. 2025 annual production guidance comprised of: 20,050 bbls/d of heavy oil, 60 bbls/d of natural gas liquids and 12.9 mmcf/d of natural gas.

Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks identified under the heading "Business Conditions and Risks". In addition, the actual number of common shares that will be repurchased under the NCIB, and the timing of any such purchases, will be determined by the Company on management's discretion, subject to applicable securities laws. There cannot be any assurances as to how many common shares, if any, will ultimately be acquired by the Company. Further information regarding these factors and additional factors may be found under the heading "Risk Factors" in the Annual Informational Form for the year ended December 31, 2024, dated March 13, 2025, which is available on the Company's website at www.headwaterexp.com and under the Company's profile on SEDAR+ at www.sedarplus.ca. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive.

The forward-looking statements contained in this MD&A are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Corporate Information

Board of Directors

NEIL ROSZELL
Executive Chairman, Headwater Exploration Inc.
Calgary, Alberta

JASON JASKELA
President and CEO, Headwater Exploration Inc.
Calgary, Alberta

CHANDRA HENRY (1) (2)
CFO and Chief Compliance Officer, Longbow Capital Inc.
Calgary, Alberta

STEPHEN LARKE (2) (4)
Director, Vermillion Energy Inc. and Topaz Energy Corp.
Calgary, Alberta

PHILLIP KNOLL (3) (4)
Director, Altagas Ltd.
Calgary, Alberta

KEVIN OLSON (1) (3)
Independent Businessman
Calgary, Alberta

DAVE PEARCE (2) (3)
Deputy Chairman, Azimuth Capital Management
Calgary, Alberta

KAM SANDHAR (1)
Executive Vice President and CFO, Cenovus Energy Inc.
Calgary, Alberta

ELENA DUMITRASCU (4)
Cofounder and Chief Technology Officer, Credivera
Calgary, Alberta

DEVERY CORBIN (4)
Former Chief of Staff for the Mayor of the City of Calgary
Calgary, Alberta

(1) Audit Committee
(2) Corporate Governance and Compensation Committee
(3) Reserves Committee
(4) Environment, Safety and Sustainability Committee

Website: www.headwaterexp.com

Officers

NEIL ROSZELL, P. Eng.
Executive Chairman

JASON JASKELA, P. Eng.
President and CEO

ALI HORVATH, CPA, CA
Chief Financial Officer

TERRY DANKU, P. Eng.
Executive Vice President

BRAD CHRISTMAN
Chief Operating Officer

DIETER DEINES
Vice President Exploration

SCOTT RIDEOUT
Vice President Land

GEORGIA LITTLE, CPA, CA
Vice President Finance

WADE HEIN
Vice President Operations

JEFF MAGEE
Vice President Engineering

TED BROWN (Corporate Secretary)
Burnet, Duckworth & Palmer LLP

Head Office

Suite 1400, 215 – 9th Avenue SW
Calgary, Alberta T2P 1K3
Tel: (587) 391-3680

Auditors

KPMG LLP
Calgary, Alberta

Independent Reservoir Consultants

McDaniel & Associates Consultants Ltd.