Headwater Exploration : Q2 2020 MD&A

Q2 2020 Management's Discussion and Analysis

The following management's discussion and analysis ("MD&A") as provided by the management of Headwater Exploration Inc. (formerly Corridor Resources Inc.) ("Headwater" or the "Company") is dated August 5, 2020 and should be read in conjunction with the unaudited interim condensed financial statements as at and for the three and six months ended June 30, 2020, and the MD&A and the audited financial statements and the notes thereto for the year ended December 31, 2019, 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 natural gas production and reserves in the McCully Field near Sussex, New Brunswick.

On March 4, 2020, Headwater announced the completion of the Recapitalization Transaction (as defined herein), pursuant to which the Company raised aggregate gross proceeds of $50 million pursuant to two equity private placements, a new management team was appointed and the board of directors of the Company was reconstituted. In addition, concurrently with the completion of the Recapitalization Transaction, the name of the Company was changed from "Corridor Resources Inc." to "Headwater Exploration Inc." and on March 9, 2020 the common shares of the Company commenced trading under the new symbol "HWX" on the Toronto Stock Exchange ("TSX").

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

HIGHLIGHTS FOR THREE MONTHS ENDED JUNE 30, 2020

• As at June 30, 2020, Headwater has cash and short-term investments (consisting of redeemable guaranteed investment certificates) of $112.8 million, a working capital surplus of $113.7 million and no outstanding debt.
• April 2020 natural gas production averaged 7.2 mmcf/d, consistent with April 2019, before the Company shut-in its natural gas production effective May 1, 2020 pursuant to its production optimization strategy.
• Locked into financial derivative contracts for a total of 5,000 mmbtu/d at NYMEX CAD$4.05/mmbtu for the period from December 2020 to March 2021.
• Efficiently executed the integration of east coast operations with all corporate functions now being handled from the Company's head office in Calgary.

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Results of Operations

Production and Pricing

	Three months ended			Six months ended
	June 30,	Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
Average daily production
Natural gas (mmcf/d)	2.4	2.4	-	5.6	5.7	(2)
Natural gas liquids (bbl/d)	-	3	(100)	3	6	(50)
Barrels of oil equivalent (boe/d)	396	402	(1)	942	953	(1)
Headwater average sales price
Natural gas (Cdn$/mcf)	2.27	4.16	(45)	2.44	6.40	(62)
Natural gas liquids (Cdn$/bbl)	-	89.78	(100)	57.81	80.20	(28)
Barrels of oil equivalent (Cdn$/boe)	13.63	25.49	(47)	14.80	38.68	(62)
Average Benchmark Price
Algonquin city-gates (US$/mmbtu)	1.63	2.56	(36)	2.08	4.46	(53)
Henry Hub (US$/mmbtu)	1.77	2.51	(29)	1.82	2.69	(32)
Exchange rate (US$/Cdn$)	1.38	1.34	3	1.36	1.33	2

Sales

	Three months ended			Six months ended
	June 30,	Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Natural gas	491	904	(46)	2,500	6,574	(62)
Natural gas liquids	-	27	(100)	37	94	(61)
Gathering, processing and	74	83	(11)	336	355	(5)
transportation revenue
	565	1,014	(44)		2,873	7,023	(59)
Per mcf ($)	2.61	4.66	(44)	2.80	6.84	(59)
Per boe ($)	15.67	27.75	(44)	16.76	40.74	(59)

The Company sells all of its natural gas production daily from the McCully Field in New Brunswick pursuant to a long-term agreement with Repsol Oil & Gas Canada Inc. ("Repsol"). The transaction price is based on the daily benchmark price Algonquin city-gates ("AGT") adjusted for the delivery location and heat content.

Natural gas sales for the three months ended June 30, 2020 decreased to $491 thousand from $904 thousand in the corresponding period of 2019. This decrease was attributable to a decrease in commodity pricing as production in the second quarter of 2020 was consistent at 2.4 mmcf/d compared to 2.4 mmcf/d in the second quarter of 2019.

During the three months ended June 30, 2020, the AGT price decreased 36% compared to the corresponding period of 2019 due to decreased natural gas demand resulting in a decrease in the Company's realized natural gas sales price. This decline was partially offset by the physical gas contract in place for the month of April for 5,000 mmbtu/d at US$2.40/mmbtu.

Natural gas sales for the six months ended June 30, 2020 decreased to $2,500 thousand from $6,574 thousand in the comparable period due primarily to a 62% decrease in Headwater's average realized natural gas sales price to $2.44/mcf in the first half of 2020 from $6.40/mcf in the corresponding period of 2019. The decrease in Headwater's average realized natural gas sales price is consistent with the decrease

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in the AGT benchmark price over the period and is due to above average temperatures during the winter which put downward pressure on the AGT gas price.

In the six months ended June 30, 2020, natural gas production was consistent with the corresponding period averaging 5.6 mmcf/d compared to 5.7 mmcf/d for 2019. Headwater shut-in all of its natural gas production effective May 1, 2020 and May 1, 2019 to take advantage of the expected significant differential in the sales price of natural gas at AGT during the winter heating season.

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, which currently is limited to Nutrien Inc.'s ("Nutrien") share of gas from the McCully Field. This income will vary quarter over quarter depending on third party volumes.

Financial Derivatives Gains

	Three months ended			Six months ended
	June 30,	Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Realized financial derivative gains	-	53	(100)	3,937	2,899	36
Unrealized financial derivative gains	149	237	(37)	(1,332)	(189)	605
(losses)
Financial derivative gains	149	290	(49)	2,605	2,710	(4)
Per mcf ($)	0.69	1.33	(48)	2.54	2.64	(4)
Per boe ($)	4.14	7.92	(48)	15.20	15.72	(3)

A key component of Headwater's production optimization strategy is to enter into financial hedges to mitigate the risks associated with the volatility of natural gas prices during the winter months when natural gas production from the McCully Field occurs.

In the six months ended June 30, 2020, the Company realized financial derivative gains on natural gas commodity contracts referenced to the AGT price. Realized financial derivative gains were recorded during the six months ended June 30, 2020 of $3,937 thousand compared to realized gains of $2,899 thousand for the six months ended June 30, 2019. The Company recognized gains on its natural gas contracts in 2020 as the commodity contracts to fix the AGT price exceeded the actual price in the period. Headwater did not have any financial derivative contracts in place related to its Q2 2020 production.

As of June 30, 2020, the fair value of Headwater's outstanding financial derivative contracts is an unrealized asset of $149 thousand as reflected in the interim condensed financial statements. The fair value or mark to market value of these contracts is based upon the estimated amount that would have been received as at June 30, 2020, had the contracts been monetized or terminated. Subsequent changes in the fair value of the commodity contracts are recognized in the interim condensed financial statements and could be materially different than what is recorded at June 30, 2020.

In the second quarter of 2020, the Company had unrealized gains of $149 thousand compared to unrealized gains of $237 thousand in the second quarter of 2019.

In the six months ended June 30, 2020, the Company had unrealized losses of $1,332 thousand compared to unrealized losses of $189 thousand in the corresponding period of 2019.

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As at June 30, 2020, Headwater has the following financial derivative contracts in place for the 2020/2021 winter season:

Commodity	Type	Term	Volume	Price	Index
Natural Gas	Fixed	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.05/mmbtu	NYMEX
Natural Gas	Fixed	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.08/mmbtu	NYMEX
Natural Gas	Fixed	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $3.99/mmbtu	NYMEX
Natural Gas	Fixed	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.06/mmbtu	NYMEX
Natural Gas	Fixed	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.08/mmbtu	NYMEX

During Q2 2020, in order to establish a risk management facility to be able to enter into various financial derivative contracts with a new financial institution, Headwater entered into a demand debenture in the principal amount of $75 million providing for a floating charge over all assets of the Company. The risk management facility does not have any financial covenants that must be adhered to and the Company is in compliance with all other covenants.

Royalty Expense

	Three months ended			Six months ended
	June 30,	Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Royalty expense	15	19	(21)	72	178	(60)
Percent of total revenue	2.6%	1.9%	37	2.5%	2.5%	-
Per mcf ($)	0.07	0.09	(22)	0.07	0.17	(59)
Per boe ($)	0.39	0.53	(26)	0.42	1.03	(59)

Royalty expense decreased to $15 thousand in the three months ended June 30, 2020 from $19 thousand in the comparable period of 2019 primarily due to a 46% decrease in natural gas sales.

During the six months ended June 30, 2020, royalties decreased 60% to $72 thousand from $178 thousand in the comparable period. This decrease is primarily a result of a 62% decrease in natural gas sales.

The Company's royalty rate of 2.6% for the three months ended June 30, 2020 is slightly higher compared to 1.9% for Q2 2019 as a result of the physical gas contract in place and differing transportation arrangements negotiated in Q2 2020 versus the corresponding period of 2019. The Company's royalty rate of 2.5% for the six months ended June 30, 2020 is consistent with the royalty rate of 2.5% in the corresponding period of 2019.

Production Expense

	Three months ended			Six months ended
	June 30,		Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Production expense	534	608	(12)	1,181	1,354	(13)
Per mcf ($)	2.47	2.80	(12)	1.15	1.32	(13)
Per boe ($)	14.79	16.64	(11)	6.89	7.86	(12)

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Production expense decreased to $534 thousand in the three months ended June 30, 2020 from $608 thousand in the comparable period of 2019. During the six months ended June 30, 2020, production expense decreased 13% to $1,181 thousand from $1,354 thousand in the corresponding period of 2019. Production expenses were lower when compared to the same periods in the prior year primarily due to a reduction in utilities expense and repairs and maintenance expense. Additionally, one-time expenses were higher in 2019 as a result of planned workovers. Third party recoveries increased in the first half of 2020, as the Company took over operatorship of Nutrien's gas plant in December of 2019 and the Company receives a monthly operatorship fee for this service.

General and Administrative ("G&A") Expenses

	Three months ended			Six months ended
	June 30,		Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
G&A expenses - recapitalization	245	-	100	278	-	100
G&A expenses	632	595	6	1,282	1,223	5
Overhead recoveries	(35)	(14)	150		(35)	(40)	(13)
Net G&A expenses	842	581	45	1,525	1,183	29
Per mcf ($)	3.89	2.67	46	1.49	1.15	30
Per boe ($)	23.33	15.89	47	8.90	6.86	30

G&A expenses, excluding incremental recapitalization costs, for the three and six months ended June 30, 2020 were $632 thousand and $1,282 thousand, respectively, consistent with $595 thousand and $1,223 thousand recorded in the corresponding periods of 2019.

Recapitalization costs were $245 thousand for the three months ended June 30, 2020 and $278 thousand for the six months ended June 30, 2020. These expenses were incurred to facilitate the integration of east coast operations with the Company's new head office in Calgary and include legal fees, consulting fees and additional software and IT-related fees.

Transaction Costs

	Three months ended				Six months ended
	June 30,		Percent		June 30,		Percent
2020	2019		Change	2020	2019		Change
	(thousands of dollars)				(thousands of dollars)
Transaction costs	-	-	-	4,382		-	100
Per mcf ($)	-	-	-	4.28		-	100
Per boe ($)	-	-	-	25.57		-	100

The Company incurred transaction costs of $4,382 thousand pursuant to the Recapitalization Transaction that closed on March 4, 2020. Transaction costs primarily consist of severance, advisory and legal fees.

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Interest Income and Other

	Three months ended			Six months ended
	June 30,		Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Interest and other income	262	307	(15)	620	571	9
Foreign exchange gains (losses)	(44)	19	(332)	154	(41)	(476)
Accretion	(35)	(36)	(3)	(88)	(116)	(24)
Interest expense	(2)	(2)	-		(3)	(4)	(25)
Total interest income and other	181	288	(37)	683	410	67
Per mcf ($)	0.84	1.32	(36)	0.67	0.40	68
Per boe ($)	5.03	7.88	(36)	3.99	2.37	68

Interest income and other was lower during the three months ended June 30, 2020 when compared to the same period in the prior year primarily due to foreign exchange losses of $44 thousand in 2020 versus foreign exchange gains of $19 thousand in 2019. Additionally, interest and other income decreased by 15% due to a decrease in interest rates (Bank of Canada overnight rate was lower by 150 basis points in Q2 2020 versus Q2 2019), which was only partially offset by a higher average cash balance outstanding.

Interest income and other during the six months ended June 30, 2020 was $683 thousand compared to $410 thousand in the corresponding period of 2019. The increase for the six months ended June 30, 2020 is primarily due to foreign exchange gains of $154 thousand in 2020 compared to foreign exchange losses of $41 thousand in 2019. Realized foreign exchange gains and losses will vary depending on the fluctuation in the exchange rate between the timing of sales incurred which are denominated in US dollars and the timing of the settlement of the underlying receivable. Interest income increased by 9% due to the increase in the cash balance arising from the closing of the non-brokered and brokered private placements pursuant to the Recapitalization Transaction on March 4, 2020, which raised aggregate gross proceeds of $50 million.

Stock-Based Compensation

	Three months ended			Six months ended
	June 30,	Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Stock options	420	100	320	391	190	106
Deferred share units	9	(6)	(250)		19	(35)	(154)
Stock-based compensation expense	429	94	356		410	155	165
Per mcf ($)	1.98	0.43	360	0.40	0.15	167
Per boe ($)	11.90	2.58	361	2.39	0.90	166

Stock-based compensation, with respect to stock options, was higher when compared to the same periods in the prior year as a result of stock options granted to directors, officers and employees following the Recapitalization Transaction.

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Stock-based compensation relating to deferred share units ("DSUs") is due to the change in fair value of the DSUs over the period resulting from a corresponding change in the Company's share price. During the six months ended June 30, 2020, a total of $535 thousand was paid out on the redemption of DSUs pursuant to the Recapitalization Transaction and the reconstitution of the board of directors.

Stock Option Plans

The Company has a stock option plan ("Existing Option Plan") under which options to purchase common shares of the Company may be granted to directors, officers, employees and consultants of the Company. As at June 30, 2020 there were options to purchase 1,272,502 common shares of the Company outstanding under the Existing Option Plan. The exercise price of each option granted under the Existing Option Plan is based on the closing price of the common shares on the TSX on the trading day prior to the date the option was granted. Options granted under the Existing Option Plan generally vest over a three-year period and expire four to five years after the grant date. The Company does not intend to grant any additional options under the Existing Option Plan.

On March 25, 2020, the Company's board of directors approved a new share option plan ("New Option Plan") under which options to purchase common shares of the Company may be granted to directors, officers, employees and consultants of the Company. Under the terms of the New Option Plan, an aggregate number of options equal to 8.0% of the aggregate number of issued and outstanding common shares less the aggregate number of common shares issuable pursuant to outstanding options under the Existing Option Plan may be granted. The exercise price of each option granted under the New Option Plan is based on the closing price of the common shares on the TSX on the trading day prior to the date the option was granted and generally options will vest as to one third of the number of options granted on each of the first, second and third anniversaries of the date of grant, respectively, and expire four years from the date of grant.

On March 25, 2020 the board of directors of the Company approved the grant of 5,065,000 Options under the New Option Plan to certain officers, employees and service providers of the Company with 4,265,000 of such options granted on March 27, 2020 with an exercise price of $1.06 per common share, 600,000 of such options granted on April 1, 2020 with an exercise price of $1.00 per common share and 200,000 of such options granted on April 9, 2020 with an exercise price of $1.13 per common share. The New Option Plan was approved by the Company's shareholders at the Company's annual and special meeting of shareholders held on June 15, 2020. In accordance with IFRS 2, stock options previously granted under the New Option Plan were revalued on June 15, 2020.

Depletion and Depreciation

	Three months ended			Six months ended
	June 30,		Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Depletion	663	660	-	3,097	3,162	(2)
Depreciation	91	79	15		162	151	7
Depletion and depreciation	754	739	2	3,259	3,313	(2)
Depletion - Per mcf ($)	3.07	3.04	1	3.03	3.08	(2)
Depletion - Per boe ($)	18.39	18.07	2	18.07	18.34	(1)
Depreciation - Per mcf ($)	0.42	0.36	17	0.16	0.15	7
Depreciation - Per boe ($)	2.52	2.15	17	0.95	0.88	8

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Depletion expense is calculated using the unit-of-production method which is based on production volumes in relation to the proved reserves base. Depletion and depreciation for the three and six months ended June 30, 2020 is consistent with depletion and depreciation recognized for the three and six months ended June 30, 2019.

During Q2 2020, depletion per boe averaged $18.39, which is consistent with the Q2 2019 average per boe of $18.07, as there was no significant capital spending or changes to the reserves base.

Impairment Assessment

At June 30, 2020, no impairment indicators were determined to exist for the Company's New Brunswick CGU. Accordingly, an impairment test was not performed.

Exploration and Evaluation ("E&E") Expense

	Three months ended				Six months ended
		June 30,		Percent		June 30,	Percent
2020	2019		Change	2020	2019	Change
	(thousands of dollars)				(thousands of dollars)
Exploration and evaluation	-	-	-	3,821	-	100
expense
Per mcf ($)	-	-	-	3.73	-	100
Per boe ($)	-	-	-	22.29	-	100

Since May 27, 2016, the McCully assets in New Brunswick have been subject to a moratorium on hydraulic fracturing. The new management team believes there is significant uncertainty regarding the ultimate realization of the value of the E&E assets as all undeveloped wells in the McCully field require hydraulic fracture stimulation to be commercially productive. The Company does not currently have any plans to pursue exploratory capital spending in the McCully Field. As such, all E&E assets related to the Company's New Brunswick CGU were expensed.

Decommissioning Liabilities

As at June 30, 2020, the decommissioning liabilities of the Company were $11,758 thousand compared to $10,798 thousand at March 31, 2020. During Q2 2020, the Company recorded an upward revision to estimate of $875 thousand. This change in estimate is a result of a decrease in the discount rate from 1.3% at March 31, 2020 to 1.0% at June 30, 2020 and an increase in the inflation rate from 0.9% at March 31, 2020 to 1.0% at June 30, 2020.

As at March 31, 2020, the decommissioning liabilities of the Company were $10,798 thousand compared to $11,976 thousand at December 31, 2019. During Q1 2020, the Company recorded a downward revision in estimate of $1,231 thousand. This change in estimate is a result of a decrease in the inflation rate from 2.0% at December 31, 2019 to 0.9% at March 31, 2020 partially offset by a decrease in the discount rate from 1.8% at December 31, 2019 to 1.3% at March 31, 2020 and an increase in cost estimates of $190 thousand over the period.

The total undiscounted uninflated amount of estimated cash flows required to settle these obligations is $11,700 thousand (December 31, 2019 - $11,460 thousand).

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Deferred Income Taxes

Based on planned capital expenditure programs and current natural gas price assumptions, the Company does not expect to be cash taxable in the near future. At June 30, 2020, the Company had approximately $161 million of tax pools available to be applied against future taxable income. The federal tax pools are estimated as follows:

	Estimated balance at
($ thousands)	June 30, 2020
Canadian oil and gas property expense	2,679
Canadian development expense	26,639
Canadian exploration expense	100,026
Undepreciated capital cost	16,521
Non-capital losses	11,378
Other	3,446
Total	160,689

Adjusted Funds Flow from Operations and Net Income (Loss)

The Company's adjusted funds flow from operations and net income generating capability are a direct result of production and commodity prices. For the three months ended June 30, 2020, Headwater incurred a net loss of $1,679 thousand compared to a net loss of $274 thousand for the three months ended June 30, 2019 due primarily to lower natural gas sales attributed to a lower average realized natural gas sales price, higher stock-based compensation expense associated with stock option grants to directors, officers and employees of Headwater and higher G&A costs as a result of the Recapitalization Transaction. The net loss of $8,489 thousand for the six months ended June 30, 2020 is primarily a result of transaction costs of $4,382 incurred pursuant to the Recapitalization Transaction and exploration and evaluation expense of $3,821 thousand.

The Company recognized negative adjusted funds flow used in operations of $610 thousand for the three months ended June 30, 2020 down from $151 thousand from operations for the three months ended June 30, 2019 primarily due to lower natural gas sales and incremental G&A expenses associated with the Recapitalization Transaction. The Company recognized adjusted funds flow from operations of $4,803 thousand for the six months ended June 30, 2020 down from $7,705 thousand for the six months ended June 30, 2019 primarily due to lower natural gas sales and higher G&A expenses partially offset by higher realized gains on financial derivatives.

The following table summarizes the operating netback, adjusted funds flow netback and net income (loss) on a barrel of oil equivalent basis:

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		Three months ended			Six months ended
		June 30,			June 30,
				Percent				Percent
		2020	2019	Change	2020	2019	Change
		($/boe)			($/boe)
Sales	15.67	27.75	(44)	16.76	40.74	(59)
Realized gains on financial derivatives	-	1.43	(100)	22.97	16.81	37
Royalties	(0.39)	(0.53)	(26)		(0.42)	(1.03)	(59)
Net sales	15.28	28.65	(47)	39.31	56.52	(30)
Production expenses	(14.79)	(16.64)	(11)		(6.89)	(7.86)	(12)
Operating netback (1)	0.49	12.01	(96)	32.42	48.66	(33)
General and administrative expenses	(23.33)	(15.89)	47	(8.90)	(6.86)	30
Interest income and other (2)	6.00	8.46	(29)	4.50	2.96	52
Decommissioning liabilities settled	-	(0.44)	(100)		-	(0.07)	(100)
Adjusted funds flow netback (1)	(16.84)	4.14	(507)	28.02	44.69	(37)
Transaction costs	-	-	-	(25.57)	-	100
Unrealized gains (losses) on financial	4.14	6.49	(36)	(7.77)	(1.09)	613
derivatives
Stock-based compensation expense	(11.90)	(2.58)	361	(2.39)	(0.90)	166
Depletion and depreciation	(20.91)	(20.22)	3	(19.02)	(19.22)	(1)
Accretion and other expense	(0.97)	(0.58)	67	(0.51)	(0.59)	(14)
Write-off of E&E assets	-	-	-	(22.29)	-	100
Decommissioning liabilities settled	-	0.44	(100)		-	0.07	(100)
Income (loss) before income taxes	(46.48)	(12.31)	(278)	(49.53)	22.96	(316)
Deferred income tax recovery (expense)	-	4.79	(100)	-	(7.39)	(100)
Net income (loss)		(46.48)	(7.52)	518		(49.53)	15.57	(418)

1. Non-GAAPmeasure. See Non-GAAP measures advisory.
2. Excludes accretion on decommissioning liabilities.

Capital Expenditures

	Three months ended			Six months ended
	June 30,	Percent		June 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Exploration, development and	350	184	90	400	322	24
production
Capitalized overhead	35	14	150	35	40	(13)
Office and other assets	13	13	-		33	27	22
Total capital expenditures	398	211	89		468	389	20

Capital spending totaled $398 thousand for the three months ended June 30, 2020 which primarily relates to a land sale in western Canada.

The Company does not plan to incur any significant capital expenditures in New Brunswick while the moratorium on hydraulic fracturing remains in place. Future exploration and development of the Company's properties in New Brunswick, if any, will therefore depend on the termination of the moratorium in New Brunswick.

The Company is maintaining a 2020 capital expenditure budget of $500 thousand. The capital budget is expected to be funded from working capital.

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Recapitalization Transaction

On March 4, 2020, the Company completed its previously announced recapitalization transaction (the "Recapitalization Transaction"). The Recapitalization Transaction involved the following:

• A non-brokered private placement of 21,739,130 units of the Company at a price of $0.92 per unit for aggregate gross proceeds of $20.0 million. Each unit was comprised of one common share and one common share purchase warrant ("Warrant") of the Company. Each Warrant entitles the holder to purchase one common share at a price of $0.92 per common share for a period of 4 years from the issuance date. The Warrants vest and become exercisable as to one-third upon the 20-day volume weighted average price of the common shares equaling or exceeding $1.30, $1.60 and $1.90, respectively. Pursuant to the rules of the TSX, the non-brokered private placement was approved by shareholders of the Company at a special meeting of the shareholders held on March 4, 2020.
• Concurrently with the closing of the non-brokered private placement, the appointment of a new management team and reconstitution of the board of directors was completed.
• A brokered private placement of 32,608,696 subscription receipts ("Subscription Receipts") of the Company, which were sold at a price of $0.92 per Subscription Receipt through a syndicate of dealers for aggregate gross proceeds of $30.0 million, was completed on February 11, 2020. Pursuant to the terms of the Subscription Receipts, upon completion of the non-brokered private placement, reconstitution of the board of directors and appointment of the new management team on March 4, 2020, the net proceeds of the brokered private placement were released to the Company and each holder of Subscription Receipts received one common share for each Subscription Receipt held.
• The Company also changed its name to Headwater Exploration Inc., which name change was also approved by shareholders of the Company at the special meeting of the shareholders held on March 4, 2020.
• In connection with the Recapitalization Transaction, the Company incurred $4.4 million of transaction costs and $1.9 million in share issue costs.

Liquidity and Capital Resources

At June 30, 2020, the Company has sufficient liquidity and was holding cash and short-term investments (consisting of redeemable guaranteed investment certificates) of $112,791 thousand and a working capital surplus of $113,718 thousand. The Company has sufficient financial resources to undertake its planned activities in 2020. The Company does not plan to incur any significant capital expenditures in New Brunswick while the moratorium on hydraulic fracturing remains in place. Future exploration and development of the Company's properties in New Brunswick, if any, will therefore depend on the termination of the moratorium in New Brunswick.

Headwater intends to use the net proceeds from the Recapitalization Transaction for acquisition, development and drilling opportunities. To the extent that the Company's existing working capital is not sufficient to pay the cash portion of the purchase price for any 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.

Headwater's short-term investments consist of guaranteed investment certificates ("GIC's") that are highly liquid as the GIC's are redeemable on demand without penalty .

As of June 30, 2020, Headwater had the following contractual obligations and commitments:

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	Within 1 year	1 to 4 years	Beyond 4 years
	$	$	$
Accounts payable and accrued liabilities	953	-	-
Lease liability	49	38	145
Operating leases	95	375	180
Total	1,097	413	325

Given the Company's available liquid resources and the Company's current plans, management expects to have sufficient available funds to meet the current and foreseeable contractual obligations.

Common Share Information

Share Capital

	Three months ended	Six months ended
(thousands)	June 30,		June 30,
	2020	2019	2020	2019
Weighted average outstanding common shares (1)
-Basic	144,749	88,724	125,401	88,821
-Diluted	144,749	88,724	125,401	89,104
Outstanding securities at June 30, 2020
-Common shares				145,044
-Stock options - average exercise price of $1.04				6,337
-Warrants - exercise price $0.92				21,739

1. The Company uses the treasury stock method to determine the dilutive effect of stock options and warrants. Under this method, only "in-the- money" dilutive instruments impact the calculation of diluted income per common share.

Total Market Capitalization

The Company's market capitalization at June 30, 2020 was approximately $178.4 million.

(thousands)	June 30, 2020
Common shares outstanding	145,044
Share price (1)	$1.23
Total market capitalization	$178,404

(1) Represents the last price traded on the TSX on June 30, 2020.

As at August 5, 2020 the Company had 145,044,493 common shares outstanding.

(thousands)	August 5, 2020
Outstanding securities at August 5, 2020
-Common shares	145,044
-Stock options - weighted average exercise price of $1.04	6,337
-Warrants - exercise price of $0.92	21,739

The following table summarizes key quarterly financial operating information over the most recently completed financial years.

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Summary of Quarterly Information

Q2/20

Q1/20

Q4/19

Q3/19

Q2/19

Q1/19

Q4/18

Q3/18

Financial (thousands of dollars except share data)

Sales	565	2,308	2,310	-	1,014	6,009	3,525	-
Cash flows provided by (used in) operating
activities (6)	863	1,182	(192)	(342)	1,675	7,720	(1,609)	(723)
Adjusted funds flow from operations (1) (6) (8)	(610)	5,413	1,929	(1,427)	151	7,554	1,338	(938)
Per share - basic	-	0.05	0.02	(0.02)	-	0.08	0.02	(0.01)
- diluted	-	0.05	0.02	(0.02)	-	0.08	0.02	(0.01)
Net income (loss) (8)	(1,679)	(6,810)	1,447	(1,318)	(274)	2,960	6,104	(1,860)
Per share - basic	(0.01)	(0.06)	0.02	(0.02)	-	0.03	0.07	(0.02)
- diluted	(0.01)	(0.06)	0.02	(0.02)	-	0.03	0.07	(0.02)
Capital expenditures, net	398	70	227	69	211	178	724	307
Working capital	113,718	114,200	64,622	62,059	63,744	64,034	57,190	54,286
Shareholders' equity	156,386	157,235	114,310	112,792	114,148	114,768	111,700	105,478
Weighted average shares thousands)
Basic	144,749	105,436	88,147	88,172	88,724	88,919	88,799	88,689
Diluted	144,749	105,436	88,542	88,172	88,724	89,213	89,237	88,689
Shares outstanding, end of period (thousands)
Basic	145,044	144,327	88,147	88,147	88,301	88,924	88,899	88,742
Diluted(9)	151,381	145,552	89,842	88,935	89,089	90,430	91,470	89,687
Operating (6:1 boe conversion)
Average daily production
Natural gas (mmcf/d)	2.4	8.9	3.5	-	2.4	9.0	4.4	-
Natural gas liquids (bbl/d)	-	7	2	-	3	10	-	-
Barrels of oil equivalent (boe/d)(2)	396	1,487	586	-	401	1,510	726	-
Average selling prices(3)
Natural gas ($/mcf)	2.27	2.49	6.80	-	4.16	7.00	8.53	-
Natural gas liquids ($/bbl)	-	57.90	83.34	-	89.82	76.81	-	-
Barrels of oil equivalent ($/boe)(2)	13.63	15.12	40.92	-	25.49	42.22	51.20	-
Netbacks ($/boe)(2)
Operating
Sales(3)	15.67	17.06	42.84	-	27.75	44.23	52.74	-
Realized gain (loss) on financial
derivatives	-	29.09	14.70	-	1.43	20.95	12.99	-
Royalties	(0.39)	(0.42)	(0.96)	-	(0.53)	(1.17)	(1.44)	-
Production expenses	(14.79)	(4.78)	(12.19)	-	(16.64)	(5.50)	(12.13)	-
Operating netback ($/boe)(4)	0.49	40.95	44.39	-	12.01	58.51	52.16	-
General and administrative	(23.33)	(5.05)	(13.22)	-	(15.89)	(4.43)	(12.25)	-
Interest income and other (7)	6.00	4.10	4.73	-	8.46	1.49	5.30	-
Decommissioning liabilities settled	-	-	(0.13)	-	(0.44)	(0.03)	(25.20)	-
Adjusted funds flow netback(5)(6) ($/boe)	(16.84)	40.00	35.77	-	4.14	55.54	20.01	-

1. Management uses adjusted funds flow from operations to analyze operating performance and leverage. Adjusted funds flow from operations as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculation of similar measures for other entities. The reconciliation between adjusted funds flow from operations and cash flow from operating activities can be found in this MD&A.
2. Boe conversion ratio for natural gas of 1 Boe: 6 Mcf has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily 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.
3. Excludes realized and unrealized financial derivative contracts.
4. Operating netback is calculated as sales received less royalties, production and transportation costs and realized gains or losses on financial derivatives.
5. Adjusted funds flow netbacks are calculated as the operating netback less general and administrative expenses, interest income and expense (excluding accretion on decommissioning liabilities), and decommissioning liabilities settled.
6. Comparative period revised to reflect current period presentation. Decommissioning liabilities settled was previously not included in cash flow from operations (and instead was included in cash flow used in investing activities), adjusted funds flow from operations or the adjusted funds flow netback calculation.
7. Excludes accretion on decommissioning liabilities.
8. Adjusted funds flow from operations and net income (loss) on a per share basis is calculated on a consistent basis with net income (loss) per common share, using basic and diluted weighted average common shares as determined in accordance with GAAP.
9. Includes in-the-money dilutive instruments as at June 30, 2020.

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Headwater's natural gas sales are priced at AGT. The AGT market has been characterized by excess demand during the winter season resulting in significant premiums in the sale prices for natural gas during the winter season as compared to prices during other periods of the year. In response to this trend in natural gas prices, since 2015, the Company has determined to shut-in most of its producing natural gas wells in the McCully Field in New Brunswick for a portion of the summer and fall period and to time the start-up of production, and the associated recovery of flush volumes, with peak winter pricing to maximize adjusted funds flow from operations and retain Headwater's reserves for production in future years. A key component of this production optimization strategy is to enter into financial hedges to mitigate the risks associated with the volatility of natural gas prices when natural gas production resumes.

In Q2 2020, Headwater incurred a net loss of $1,679 thousand due primarily to lower natural gas sales attributed to a lower average realized natural gas sales price, higher stock-based compensation associated with stock option grants to directors, officers and employees of Headwater and higher general and administrative costs as a result of the Recapitalization Transaction and transitioning the head office from Calgary to Halifax.

In Q1 2020, Headwater incurred a net loss of $6,810 thousand due primarily to transaction costs of $4,382 thousand incurred pursuant to the Recapitalization Transaction, exploration and evaluation expense of $3,821 thousand and lower natural gas sales attributed to a lower average realized natural gas sales price.

In Q2 2018, Headwater announced its decision to suspend any further technical work and capital spending on the Old Harry prospect which resulted in impairment losses of $11,368 thousand and a net loss of $10,127 thousand in Q2 2018.

Off-Balance Sheet Arrangements

There are currently no significant off-balance sheet arrangements.

New Accounting Standard

In October 2018, the IASB issued amendments to the definition of a business in IFRS 3 "Business Combinations". The amendments are intended to assist entities to determine whether a transaction should be accounted for as a business combination or as an asset acquisition. IFRS 3 continues to adopt a market participant's perspective to determine whether an acquired set of activities and assets is a business. The amendments clarify the minimum requirements for a business; remove the assessment of whether market participants are capable of replacing any missing elements; add guidance to help entities assess whether an acquired process is substantive; narrow the definitions of a business and of outputs; and introduce an optional fair value concentration test. The concentration test is a simplified assessment that results in an asset acquisition if substantially all of the fair value of the gross assets is concentrated in a single identifiable asset or group of similar identifiable assets. If an entity chooses not to apply the concentration test, or the test is failed, then the assessment focuses on the existence of a substantive process.

The amendments to IFRS 3 are effective for annual reporting periods beginning on or after January 1, 2020 and apply prospectively.

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Non-GAAP Financial Measures

Throughout this MD&A, the Company uses the terms "operating netback", "adjusted funds flow netback", "adjusted funds flow from operations", and "adjusted funds flow per share". These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.

Operating netback is calculated as sales received less royalties, production and transportation costs and realized gains or losses on financial derivatives on a per boe basis. Operating netback is a common metric used in the oil and gas industry and is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis.

Adjusted funds flow from operations, adjusted funds flow netback and adjusted funds flow per share are used by the Company to analyze operating performance, leverage and liquidity and are included in this MD&A because such measures are believed to facilitate the understanding of the results of Headwater's operations and financial position on an absolute basis, on a per unit of production basis and on a per share basis. Adjusted funds flow from operations is calculated as cash flow provided by operating activities before changes in non-cash working capital and transaction costs. Adjusted funds flow netback is calculated as adjusted funds flow from operations on a per boe basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by the number of weighted average basic or diluted shares outstanding during the period.

Adjusted funds flow from operations represents cash flow provided by operating activities excluding the change in non-cash operating working capital and transaction costs, as follows:

	Three months ended		Six months ended
		June 30,		June 30,
	2020	2019	2020	2019
		(thousands of dollars)
Cash flow provided by operating activities	863	1,675	2,045	9,395
Changes in non - cash working capital	(1,473)	(1,524)	(1,624)	(1,690)
Transaction costs	-	-	4,382	-
Adjusted funds flow from operations	(610)	151	4,803	7,705

Internal Controls over Financial Reporting

Under National Instrument 52-109- Certification of Disclosure in Issuers' Annual and Interim Filings of the Canadian Securities Administrators, the Company is required to disclose in its MD&A any changes in our internal controls over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the period covered by such MD&A. The Company confirms that there were no changes to the Company's internal controls over financial reporting during the interim period from April 1, 2020 to June 30, 2020 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.

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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 amount 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. Actual results may differ from the estimated amounts as future confirming events occur and more information is obtained by management. The Company has identified the following areas requiring significant judgments, assumptions or estimates.

a) 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 development and production asset carrying values is subject to management judgment. Judgments are made in regard to shared infrastructure, geographical proximity, petroleum type and similar exposure to market risk and materiality. The asset composition of a CGU can directly impact the recoverability of the assets included therein. The key estimates used in the determination of cash flows from oil and natural gas reserves include the following:

1. Reserves - assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production levels or results of future drilling may change the economic status of reserves and may ultimately result in reserves being restated.
2. Oil and natural gas prices - forward price estimates are used in the cash flow model. Commodity prices can fluctuate for a variety of reasons including supply and demand fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors.
3. 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.

Judgments are required to assess when impairment indicators exist and impairment testing is required. In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land and other relevant assumptions.

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 future events and circumstances 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 the CGU level.

Deferred income taxes

The recognition of deferred income tax assets is based on the probability that future taxable profits will be sufficient to utilize the underlying taxable amounts. Changes in the estimated future taxable profits could materially impact the Company's deferred income tax assets.

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Contingencies

By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events.

1. Key Sources of Estimation Uncertainty

COVID-19 pandemic

Since December 31, 2019, the outbreak of the COVID-19 pandemic has had a significantly negative impact on economic conditions around the world. This has resulted in significant volatility of commodity prices as well as increased economic uncertainty. Estimates and judgments made by management in the preparation of the interim condensed financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period.

Recoverability of asset carrying value

At each reporting date, the Company assesses its property, plant and equipment, oil and gas properties and exploration and evaluation 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 estimates on highly uncertain matters such as future commodity prices, discount rates, production profiles, operating costs, future capital costs and reserves. Changes in circumstances may impact these estimates which may impact the recoverable amount of assets. Any change in the impairment loss or reversal of impairment loss could have a material financial impact in future periods.

Valuation of Reserves

Reserves estimates have a material impact on the depletion expense, impairment test calculation and decommissioning liability, all of which could have a material impact on financial results. The estimation of economically recoverable natural gas and oil reserves is based on a number of variable factors and assumptions, such as future production, ultimate reserve recovery, commodity prices, royalty rates, future costs and the timing and amount of capital expenditures, and the ability to undertake such expenditures in the future given the hydraulic fracturing moratorium in effect in New Brunswick. These reserve estimates are evaluated by third-party professional engineers at least annually, who work with information provided by the Company to evaluate the Company's reserves in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. Accordingly, the impact to the financial statements in future years could be material.

Decommissioning liability

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.

Valuation of derivative financial instruments

The estimated fair values of derivative financial instruments resulting in financial assets and liabilities, by their very nature are subject to measurement uncertainty.

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Measurement of share-based compensation

The estimated fair value of stock options uses pricing models such as the Black-Scholes model which is based on significant assumptions such as volatility, risk-free rate, forfeiture rates and the expected term.

Measurement of warrants

The estimated fair value of warrants uses pricing models such as the Black-Scholes model which is based on significant assumptions such as volatility, risk-free rate, forfeiture rates and the expected term.

Income taxes

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such, income taxes are subject to measurement uncertainty.

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 certain risk factors, which should not be construed as exhaustive:

• Public health risk including relating to the COVID-19 pandemic;
• Natural disasters, wars, terrorist acts, civil unrest and other disruptions and dislocations;
• Weakness and volatility in the oil and natural gas industry;
• Regulatory restrictions on, and other risks associated with, hydraulic fracturing;
• Prices, markets and marketing of the commodities the Company produces;
• Exploration, development and production risks;
• Failure to realize anticipated benefits of future acquisitions and dispositions;
• Political uncertainty;
• Labour risk to complete projects in a timely and cost efficient manner;
• Credit risk related to non-payment for sales contracts or other counterparties;
• Foreign exchange risk as commodity sales are based on US 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, 2019, dated March 25, 2020, which is available on the Company's website at www.headwaterexp.com and under the Company's profile SEDAR at www.sedar.com.

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 investment grade;

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• Implementation of cyber security protocols and procedures to reduce the risk of failure of breach of data.

Oil and Gas Metrics

Barrels of Oil Equivalent

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.

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 (including its production optimization and hedging strategies);
• Headwater's intended use of the net proceeds from the Recapitalization Transaction;
• expected operations on the Company's current properties;
• Canadian - U.S. dollar exchange rate;
• expected natural gas sales prices and premiums;
• future revenue from financial hedges;
• the Company's tax pools and ability to use such tax assets in the future;
• the expectation that the Company has sufficient financial resources to fund its expected operations;
• Headwater's expected capital expenditure budget of $500 thousand and expectation that it is funded from working capital;
• the expectation that the Company has sufficient available funds to meet the Company's current and foreseeable contractual obligations;
• the expected effects of certain accounting changes;
• the expected sources to finance future acquisitions; and
• expected future decommissioning liabilities.

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.

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Forward-looking statements are based on the Company's current beliefs as well as assumptions made by, and information currently available to, the Company; including information concerning anticipated financial performance, business prospects, strategies, regulatory developments, future natural gas and oil commodity prices, exchange rates, future natural gas production levels, the ability to obtain equipment in a timely manner to carry out development activities, the ability to market natural gas successfully to current and new customers, the impact of increasing competition, the ability to obtain financing on acceptable terms, the ability to add production and reserves through development and exploration activities and the terms of agreements with third parties (including the terms of its financial derivative contracts). Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

Unknown risks and uncertainties include, but are not limited to: risks associated with the current COVID-19 pandemic and other public health risks, risks associated with oil and gas exploration, development and production, operational risks, development and operating costs, substantial capital requirements and financing, volatility of natural gas and oil prices, government regulation, environmental, hydraulic fracturing, third party risk, dependence on key personnel, co-existence with mining operations, availability of drilling equipment and access, variations in exchange rates, expiration of licenses and leases, reserves and resources estimates, trading of common shares, seasonality, disclosure controls and procedures and internal controls over financial reporting, competition, conflicts of interest, issuance of debt, title to properties, hedging, information systems, litigation, and aboriginal land and rights claims. Further information regarding these factors and additional factors may be found under the heading "Risk Factors" in the Annual Information Form, which is available on the Company's website at www.headwaterexp.com and under the Company's profile on SEDAR at www.sedar.com. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive.

To the extent that any forward-looking information contained herein may be considered future oriented financial information or a financial outlook, such information has been included to provide readers with an understanding of management's assumptions used for budgeting and developing future plans and readers are cautioned that the information may not be appropriate for other purposes. 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.

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Corporate Information
Board of Directors		Officers
NEIL ROSZELL		NEIL ROSZELL, P. Eng.
Executive Chairman & CEO, Headwater Exploration Inc.		Executive Chairman & CEO
Calgary, Alberta
JASON JASKELA		JASON JASKELA, P. Eng.
President and COO, Headwater Exploration Inc.		President and COO
Calgary, Alberta
CHANDRA HENRY (1) (2)		ALI HORVATH, CPA, CA
CFO and Chief Compliance Officer Longbow Capital Inc.		Vice President Finance & CFO
Calgary, Alberta
STEPHEN LARKE (1) (2)		TERRY DANKU, P. Eng.
Director Vermillion Energy Inc. and Topaz Energy Corp.		Vice President Engineering
Calgary, Alberta
PHILLIP KNOLL(3)		JON GRIMWOOD, P. Geo.
Director Altagas Ltd.		Vice President Exploration
Calgary, Alberta
KEVIN OLSON (1) (3)		SCOTT RIDEOUT
President, Camber Capital Corp.	.	Vice President Land
Calgary, Alberta
DAVE PEARCE (2) (3)		BRAD CHRISTMAN
Deputy Managing Partner, Azimuth Capital Management		Vice President Production
Calgary, Alberta
		TED BROWN (Corporate Secretary)
		Burnet, Duckworth & Palmer LLP
(1) Audit Committee
(2) Corporate Governance and Sustainability Committee
(3) Reserves Committee
Website: www.headwaterexp.com
		Head Office
		Suite 1700, 500 - 4th Avenue SW
		Calgary, Alberta T2P 2V6
		Tel: [phone]
		Auditors
		KPMG LLP
		Calgary, Alberta
		Independent Reservoir Consultants
		GLJ Petroleum Consultants

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