Headwater Exploration : Q1 2021 MD&A

Q1 2021 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 12, 2021 and should be read in conjunction with the unaudited interim condensed financial statements as at and for the three months ended March 31, 2021, and the MD&A and the audited financial statements and the notes thereto for the year ended December 31, 2020, copies of which are available through the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com. The unaudited interim condensed financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") and in accordance with IAS 34 Interim Financial Reporting. All dollar amounts are referenced in Canadian dollars unless otherwise stated.

Description of the Company

Headwater is a Canadian junior resource company engaged in the exploration for and development and production of petroleum and natural gas in Canada. Headwater currently has heavy oil production in the Clearwater formation in the Marten Hills area of Alberta and natural gas production in the McCully field near Sussex, New Brunswick.

Unless otherwise indicated herein, all production information presented herein has been presented on a gross basis, which is the Company's working interest prior to deduction of royalties and without including any royalty interests.

HIGHLIGHTS FOR THREE MONTHS ENDED MARCH 31, 2021

• Generated average production of 4,805 boe/d representing an increase of 192% over the fourth quarter of 2020.
• Achieved adjusted funds flow from operations (1) of $14.5 million ($0.07 per share basic), representing an increase of 201% over the fourth quarter of 2020. Cash flows from operating activities were $12.8 million in the first quarter of 2021.
• Achieved an operating netback of $35.46/boe and an adjusted funds flow netback of $33.75/boe.
• Achieved adjusted net income (1) of $6.4 million ($0.03 per share basic). The Company's net loss was $12.8 million in the first quarter of 2021 inclusive of the remeasurement loss on the warrant liability of $19.2 million.
• Successfully executed a $37.3 million exploration and development capital program in the Marten Hills area inclusive of drilling 12, 8-legmulti-lateral producing wells, 5 horizontal injection wells, 2 source water wells and 1 stratigraphic test well.
• Executed an agreement with another area operator to construct a joint gas processing facility. The facility is currently under construction and is on track to be commissioned by early July 2021. This facility will allow Headwater to achieve gas conservation from production in the core area of Marten Hills.
• The Company's McCully asset performed strongly through the quarter contributing $5.0 million in operating cash flow (1). Consistent with prior years and to optimize cash flow, Headwater shut-in production May 1, 2021 to await next winter's premium pricing season. Approximately 40% of next winter's volumes are hedged at an average price of US$7.39/mmbtu.

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1. • As at March 31, 2021, Headwater had adjusted working capital (1) of $58.4 million and no outstanding debt. The Company's working capital, inclusive of financial derivatives and the warrant liability, was $28.7 million as at March 31, 2021.
2. Non-IFRSmeasure. See "Non-IFRS Financial Measures" advisory.

Results of Operations

Operating netback

The components of Headwater's operating netback for the three months ended March 31, 2021, for both of its Marten Hills assets and McCully assets are summarized below.

Marten Hills Assets

	Three months ended
	March 31,				Percent
	2021	2020			Change
	($/boe)
Sales, net of blending (1)	55.72		-	100
Royalties	(7.08)		-	100
Transportation expense	(8.60)		-	100
Production expense	(6.13)		-	100
Operating netback (2)	33.91		-	100
Heavy oil sales (bbls/d) (3) (4)	3,347		-	100
Heavy oil production (bbls/d) (3)	3,385		-	100

1. Realized heavy oil prices are calculated based on sales, net of blending expense.
2. Operating metric. See "Operating Metrics" advisory. Netbacks are calculated using average unblended sales volumes.
3. The Company's heavy oil sales and production volumes differ due to changes in inventory.
4. Presented as unblended sales excluding the impact of purchased condensate.

McCully Assets

	Three months ended
	March 31,			Percent
	2021	2020		Change
	($/boe)
Sales	49.56	17.06	191
Royalties	(1.74)	(0.42)	314
Production expense	(4.45)	(4.78)	(7)
Realized gain (loss) on financial derivatives	(4.32)	29.09	(115)
Operating netback	39.05	40.95	(5)
Natural gas and NGL production (boe/d)	1,420	1,487	(5)
Total Assets
	Three months ended
	March 31,			Percent
	2021	2020		Change
	($/boe)
Sales, net of blending	53.89	17.06	216
Royalties	(5.49)	(0.42)	1207
Transportation expense	(6.04)	-	100
Production expense	(5.62)	(4.78)	18
Realized gain (loss) on financial derivatives	(1.28)	29.09	(104)
Operating netback	35.46	40.95	(13)
Average daily sales (boe/d)	4,768	1,487	221
Average daily production (boe/d)	4,805	1,487	223

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Production and Pricing

	Three months ended
	March 31,			Percent
	2021	2020		Change
Average daily production
Heavy oil (bbls/d)	3,385	-	100
Natural gas (mmcf/d)	8.5	8.9	(4)
Natural gas liquids (bbls/d)	5	7	(29)
Barrels of oil equivalent (boe/d)	4,805	1,487	223
Average daily sales (1)	4,768	1,487	221
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	55.72	-	100
Natural gas ($/mcf)	7.48	2.49	200
Natural gas liquids ($/bbl)	66.55	57.90	15
Barrels of oil equivalent ($/boe)	52.51	15.12	247
Average Benchmark Price
WTI (US$/bbl) (4)	57.84	46.17	25
WCS differential to WTI (US$/bbl)	(12.47)	(20.53)	(39)
WCS (Cdn$/bbl) (5)	57.43	34.12	68
Condensate at Edmonton ($Cdn/bbl)	72.92	60.39	21
AGT (US$/mmbtu) (6)	5.56	2.22	150
NYMEX Henry Hub (US$/mmbtu)	2.69	1.95	38
Exchange rate (US$/Cdn$)	0.79	0.74	7

1. Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. 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

Sales

	Three months ended
	March 31,			Percent
	2021	2020		Change
	(thousands of dollars)
Heavy oil, net of blending	16,785	-	100
Natural gas	5,718	2,009	185
Natural gas liquids	31	37	(16)
Total product sales, net of blending	22,534	2,046	1001
Gathering, processing and transportation revenue	588	262	124
Total sales, net of blending	23,122	2,308	902

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.

Headwater's sales volumes averaged 3,347 bbls/d and its heavy oil sales net of blending expense were $16,785 thousand in the first quarter of 2021, attributable to revenue earned from its recently acquired Marten Hills assets. The Company's heavy oil realized price for the three months ended March 31, 2021 was $55.72/bbl, reflecting a discount to WCS of $1.71/bbl.

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The Company sells its natural gas production daily from the McCully field in New Brunswick. The transaction price is based on the AGT daily benchmark price adjusted for the delivery location and heat content. In recent years, the AGT market has been characterized by excess demand during the winter season resulting in significant premiums in the sales price for natural gas during the winter season as compared to prices during other periods of the year. Consistent with prior years, the Company shut-in production for the upcoming summer season effective May 1, 2021.

During the three months ended March 31, 2021, natural gas production averaged 8.5 mmcf/d consistent with the corresponding period of 2020 which averaged 8.9 mmcf/d.

Natural gas sales for the three months ended March 31, 2021 increased to $5,718 thousand from $2,009 thousand in the corresponding period of 2020, due primarily to a 200% increase in Headwater's average realized natural gas sales price to $7.48/mcf from $2.49/mcf. The increase in Headwater's average realized natural gas sales price was consistent with the increase in the AGT benchmark price over the period and was due to a surge in cold weather from the polar vortex experienced in late January into February, driving up natural gas demand in the Northeastern United States.

Headwater owns the midstream facilities which process and transport gas from the McCully field to the Maritimes & Northeast Pipeline ("M&NP"). Gathering, processing and transportation revenue primarily relates to income earned on third party gas flowing through these facilities. This revenue will vary quarter over quarter depending on third party volumes processed.

Financial Derivatives Gains (Losses)

Realized financial derivative gains (losses) Unrealized financial derivative losses Financial derivative gains (losses)

Per boe ($)

Three months ended
March 31,			Percent
2021	2020		Change
(thousands of dollars)
(551)	3,937	(114)
(254)	(1,481)	(83)
(805)	2,456	(133)
1.87	18.15	(90)

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

The realized financial derivative losses represent the natural gas contracts settled during the three months ended March 31, 2021. Natural gas commodity contracts are referenced to the AGT price and the associated realized gains and losses fluctuate based on changes in the AGT price. A realized financial derivative loss was recorded during the three months ended March 31, 2021 of $551 thousand compared to a realized gain of $3,937 thousand for the three months ended March 31, 2020. The Company recognized losses on its natural gas contracts in 2021 as the commodity contracts to fix the AGT price were lower when compared to the AGT settlement price in the period. The below average temperatures from the polar vortex in February 2021 caused increased natural gas demand driving up actual realized pricing above Headwater's fixed contract pricing.

As of March 31, 2021, the fair value of Headwater's outstanding financial derivative contracts is an unrealized liability of $180 thousand as reflected in the unaudited 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, 2021, 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, 2021.

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As at March 31, 2021, Headwater has the following financial derivative commodity contracts outstanding:

Commodity	Index
Natural Gas	AGT
Natural Gas	AGT Basis
Crude Oil	WCS Basis

(1)

(2)

Type	Term	Daily Volume	Contract Price
Fixed	Apr 1- Apr 30, 2021	5,000 mmbtu	Cdn$3.88/mmbtu
Differential	Dec 1- Mar 31, 2022	2,500 mmbtu	Cdn$4.16/mmbtu
Differential	Oct 1- Dec 31, 2021	2,000 bbls	US$13.16/bbl

1. Headwater pays on AGT while counterparty pays on NYMEX plus Cdn$4.16/mmbtu
2. Headwater pays on WCS while counterparty pays on WTI less US$13.16/bbl

The Company is exposed to fluctuations of the Canadian to U.S. dollar exchange rate given realized pricing is directly influenced by U.S. dollar denominated benchmark pricing and from exposure to its U.S. dollar denominated heavy oil and natural gas marketing arrangements.

Headwater mitigates this risk by entering into commodity contracts in Canadian dollars and entering into short term foreign exchange contracts.

As at March 31, 2021, Headwater has the following financial derivative foreign exchange contract outstanding:

Type	Buy Currency	Sell Currency	Rate	Notional Amount	Settlement Date
Forward contract	CAD	US	1.2619	US$5,000,000	Apr 26- Apr 30, 2021

Royalty Expense

	Three months ended
	March 31,			Percent
	2021	2020		Change
	(thousands of dollars)
Heavy oil	2,133	-	100
Natural gas and natural gas liquids	222	57	289
Total royalty expense	2,355	57	4032
Percentage of total product sales, net of blending expense	10.5%	2.8%	275
Per boe ($)	5.49	0.42	1207

Royalty expense consists of crown royalties payable to the Alberta and New Brunswick provincial governments and the gross overriding royalty ("GORR") payable to a subsidiary of Cenovus Energy Inc. ("Cenovus").

Headwater's average corporate royalty rate was 10.5% during the first quarter of 2021 compared to an average royalty rate of 2.8% in 2020, reflecting crown and GORR royalties incurred on the recently acquired Marten Hills assets.

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