Headwater Exploration : Q3 2020 MD&A

Q3 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. ("Corridor")) ("Headwater" or the "Company") is dated November 6, 2020 and should be read in conjunction with the unaudited condensed interim financial statements as at and for the three and nine months ended September 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 condensed interim 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 SEPTEMBER 30, 2020

• As at September 30, 2020, Headwater had cash and cash equivalents of $112.7 million, a working capital surplus of $112.5 million and no outstanding debt.
• The Company's natural gas production was shut-in during the quarter to take advantage of higher pricing in the winter months. The Company resumed production on October 30, 2020.
• Locked into a financial derivative contract for 2,500 mmbtu/d at AGT Fixed Cdn $5.00/mmbtu for November 2020.
• To appropriately manage the volatility in our natural gas pricing Headwater has now entered a cumulative hedge position for the December 2020 through March 2021 period of 5,000 mmbtu/d that provides for an average fixed price of Cdn $7.81/mmbtu.

SUBSEQUENT EVENT HIGHLIGHT

• Subsequent to September 30, 2020, the Company's board of directors approved Headwater entering into a definitive agreement with Cenovus Energy Inc. ("Cenovus") to acquire the entirety of Cenovus' position in the Marten Hills area of Alberta. Additional information is provided under the heading "Subsequent Event".

1

Results of Operations

Production and Pricing

	Three months ended			Nine months ended
	September 30,		Percent		September 30,	Percent
	2020	2019		Change		2020	2019	Change
Average daily production (1)
Natural gas (mmcf/d)	-	-	-	3.7	3.8	(3)
Natural gas liquids (bbl/d)	-	-	-	2	4	(50)
Barrels of oil equivalent (boe/d)	-	-	-	625	632	(1)
Headwater average sales price (1)
Natural gas (Cdn$/mcf)	-	-	-	2.44	6.40	(62)
Natural gas liquids (Cdn$/bbl)	-	-	-	57.81	80.20	(28)
Barrels of oil equivalent (Cdn$/boe)	-	-	-	14.80	38.68	(62)
Average Benchmark Price (1)
Algonquin city-gates (US$/mmbtu)	-	-	-	2.08	4.46	(53)
Henry Hub (US$/mmbtu)	-	-	-	1.82	2.69	(32)
Exchange rate (US$/Cdn$)	-	-	-	1.36	1.33	2

(1) Production and prices shown for the Company's operational period from January 1 to April 30.

Sales

	Three months ended			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Natural gas	-	-	-	2,500	6,574	(62)
Natural gas liquids	-	-	-	37	94	(61)
Gathering, processing and	-	-	-
transportation revenue					336	355	(5)
	-	-	-		2,873	7,023	(59)
Per mcf ($)	-	-	-	2.80	6.84	(59)
Per boe ($)	-	-	-	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 AGT adjusted for the delivery location and heat content.

No sales were recorded during the three months ended September 30, 2020 and the corresponding period of 2019. The Company shut-in production effective May 1, 2020 and May 1, 2019 to take advantage of higher natural gas pricing during the winter months. The Company resumed operations at the end of October 2020.

Natural gas sales for the nine months ended September 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 2020 from $6.40/mcf in the prior year. The decrease in Headwater's average realized natural gas sales price is consistent with the decrease 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.

2

In the nine months ended September 30, 2020, natural gas production was consistent with the corresponding period averaging 3.7 mmcf/d compared to 3.8 mmcf/d for 2019.

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			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Realized financial derivative gains	-	-	-	3,937	2,898	36
Unrealized financial derivative losses	(280)	(137)	104	(1,612)	(325)	396
Financial derivative gains (losses)	(280)	(137)	104	2,325	2,573	(10)
Per mcf ($)	-	-	-	2.27	2.50	(9)
Per boe ($)	-	-	-	13.56	14.93	(9)

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 nine months ended September 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 nine months ended September 30, 2020 of $3,937 thousand compared to realized gains of $2,898 thousand for the nine months ended September 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.

As of September 30, 2020, the fair value of Headwater's outstanding financial derivative contracts is an unrealized liability of $131 thousand as reflected in the condensed 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 September 30, 2020, had the contracts been monetized or terminated. Subsequent changes in the fair value of the commodity contracts are recognized in the condensed interim financial statements and could be materially different than what is recorded at September 30, 2020.

In the third quarter of 2020, the Company had unrealized losses of $280 thousand compared to unrealized losses of $137 thousand in the third quarter of 2019.

In the nine months ended September 30, 2020, the Company had unrealized losses of $1,612 thousand compared to unrealized losses of $325 thousand in the corresponding period of 2019.

As at November 6, 2020, Headwater has the following financial derivative contracts in place for the 2020/2021 winter season:

3

Commodity	Type (1) (2)	Term	Volume	Price
Natural Gas	NYMEX fixed price swap	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.05/mmbtu
Natural Gas	NYMEX fixed price swap	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.08/mmbtu
Natural Gas	NYMEX fixed price swap	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $3.99/mmbtu
Natural Gas	NYMEX fixed price swap	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.06/mmbtu
Natural Gas	NYMEX fixed price swap	Dec 2020- Mar 2021	1,000 mmbtu/d	Cdn $4.08/mmbtu
Natural Gas	AGT floating price swap (3)	Dec 2020- Mar 2021	2,500 mmbtu/d	NYMEX plus
				Cdn $3.82/mmbtu
Natural Gas	AGT floating price swap (4)	Dec 2020- Mar 2021	2,500 mmbtu/d	NYMEX plus
				Cdn $3.69/mmbtu
Natural Gas	AGT fixed price swap	Nov 2020	2,500 mmbtu/d	Cdn $5.00/mmbtu

1. NYMEX = NYMEX Henry Hub
2. AGT = Algonquin city-gates
3. Headwater pays on AGT while counterparty pays on NYMEX plus Cdn $3.82/mmbtu
4. Headwater pays on AGT while counterparty pays on NYMEX plus Cdn $3.69/mmbtu

During the second quarter of 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			Nine months ended
	September 30,		Percent		September 30,	Percent
2020	2019		Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Royalty expense	-	-	-	72	178	(60)
Percent of total revenue	-	-	-	2.5%	2.5%	-
Per mcf ($)	-	-	-	0.07	0.17	(59)
Per boe ($)	-	-	-	0.42	1.03	(59)

No royalty expense was incurred during the three months ended September 30, 2020 and the corresponding period of 2019. The Company shut-in production effective May 1, 2020 and May 1, 2019 to take advantage of higher natural gas sales pricing during the winter months.

During the nine months ended September 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 2.5% for the nine months ended September 30, 2020 is consistent with the royalty rate of 2.5% in the corresponding period of 2019.

4

Production Expense

	Three months ended			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Production expense	519	600	(14)	1,700	1,954	(13)
Per mcf ($)	-	-	-	1.66	1.90	(13)
Per boe ($)	-	-	-	9.92	11.33	(12)

Production expense decreased to $519 thousand in the three months ended September 30, 2020 from $600 thousand in the comparable period of 2019. During the nine months ended September 30, 2020, production expense decreased to $1,700 thousand from $1,954 thousand in the corresponding period of 2019. Production expenses were lower when compared to the same periods in the prior year primarily due to lower salaries and wages as a result of the Canada Emergency Wage Subsidy ("CEWS") program.

Additionally, third party recoveries increased in 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			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
G&A expenses - recapitalization	-	-	-	278	-	100
G&A expenses	614	1,110	(45)	1,895	2,333	(19)
Overhead recoveries	(7)	(4)	75		(41)	(44)	(7)
Net G&A expenses	607	1,106	(45)		2,132	2,289	(7)
Per mcf ($)	-	-	-	2.08	2.23	(7)
Per boe ($)	-	-	-	12.44	13.28	(6)

G&A expenses, excluding incremental recapitalization costs, for the three and nine months ended September 30, 2020 were $614 thousand and $1,895 thousand, respectively, compared to $1,110 thousand and $2,333 thousand recorded in the corresponding periods of 2019. G&A expenses were higher in 2019 as a result of increased technical consulting costs, a one-time severance payment and the payment of bonuses in the third quarter of 2019.

Salaries and wages were lower in 2020 as a result of the CEWS program. Under the CEWS program, Canadian employers affected by COVID-19 can apply for a subsidy for eligible employees provided that certain criteria are met. A total of $358 thousand has been claimed by the Company under the CEWS program to September 30, 2020 (a portion of which has been recognized in production expenses).

Recapitalization costs were $278 thousand for the nine months ended September 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.

5

Transaction Costs

	Three months ended				Nine months ended
	September 30,		Percent		September 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.

Interest Income and Other

	Three months ended			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Interest and other income	288	279	3	908	850	7
Foreign exchange gains (losses)	(1)	(2)	(50)	153	(43)	(456)
Accretion	(29)	(53)	(45)	(117)	(169)	(31)
Interest expense	(8)	(9)	(11)		(11)	(13)	(15)
Total interest income and other	250	215	16		933	625	49
Per mcf ($)	-	-	-	0.91	0.61	49
Per boe ($)	-	-	-	5.45	3.63	50

Interest income and other was higher during the three months ended September 30, 2020 when compared to the same period in the prior year primarily due to lower accretion expense. Accretion expense incurred on the Company's decommissioning liabilites decreased for the three months ended September 30, 2020 as a result of a decline in the risk-free interest rate.

Interest income and other during the nine months ended September 30, 2020 was $933 thousand compared to $625 thousand in the corresponding period of 2019. The increase for the nine months ended September 30, 2020 is primarily due to foreign exchange gains of $153 thousand in 2020 compared to foreign exchange losses of $43 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 7% 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.

6

Stock-Based Compensation

	Three months ended			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Stock options	485	65	646	876	255	244
Deferred share units	7	14	(50)		26	(21)	(224)
Stock-based compensation expense	492	79	523		902	234	285
Per mcf ($)	-	-	-	0.88	0.23	283
Per boe ($)	-	-	-	5.26	1.36	287

Stock-based compensation, with respect to stock options, was higher when compared to the same periods in the prior year as a result of the 6.3 million stock options granted during the nine months ended September 30, 2020 to directors, officers and employees following the Recapitalization Transaction. The stock options granted had a weighted average fair value of $0.55 per option estimated using the Black Scholes option pricing model.

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 nine months ended September 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 September 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.

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. As at September 30, 2020, there were options to purchase 5,065,000 common shares of the Company outstanding under the New Option Plan.

7

Depletion and Depreciation

	Three months ended			Nine months ended
	September 30,	Percent		September 30,	Percent
2020		2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Depletion	-	-	-	3,097	3,162	(2)
Depreciation		75	74	1		237	225	5
Depletion and depreciation	75	74	1	3,334	3,387	(2)
Depletion - Per mcf ($)	-	-	-	3.03	3.08	(2)
Depletion - Per boe ($)	-	-	-	18.07	18.34	(1)
Depreciation - Per mcf ($)	-	-	-	0.23	0.22	5
Depreciation - Per boe ($)	-	-	-	1.39	1.31	6

Depletion expense is calculated using the unit-of-production method which is based on production volumes in relation to the proved reserves base. No depletion expense was recorded during the three months ended September 30, 2020 and the corresponding period of 2019. The Company shut-in production effective May 1, 2020 and May 1, 2019 to take advantage of higher natural gas sales pricing during the winter months.

Depletion and depreciation for the nine months ended September 30, 2020 is consistent with depletion and depreciation recognized for the nine months ended September 30, 2019. Depletion per boe averaged $18.07, which is consistent with the 2019 average per boe of $18.34, as there was no significant capital spending or changes to the reserves base.

Impairment Assessment

At September 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				Nine months ended
	September 30,		Percent		September 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.

8

Decommissioning Liabilities

As at September 30, 2020, the decommissioning liabilities of the Company were $12,384 thousand compared to $11,758 thousand at June 30, 2020 and $11,976 thousand at December 31, 2019. During the quarter, the Company recorded an upward revison to estimate of $597 thousand. This change in estimate is a result of an increase in the inflation rate to 1.3% from 1.0% at June 30, 2020. During the nine months ended September 30, 2020, the Company recorded an upward revision to estimate of $241 thousand as a result of a decrease to the risk-free rate from 1.8% to 1.0% partially offset by a decrease in the inflation rate from 2.0% to 1.3%.

The total undiscounted uninflated amount of estimated cash flows required to settle these obligations is $11,700 thousand.

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 September 30, 2020, the Company had approximately $162 million of tax pools available to be applied against future taxable income. The federal tax pools are estimated as follows:

	Estimated balance at
($ thousands)	September 30, 2020
Canadian oil and gas property expense	2,608
Canadian development expense	24,278
Canadian exploration expense	100,080
Undepreciated capital cost	16,196
Non-capital losses	15,174
Other	3,266
Total	161,602

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. During the three months ended September 30, 2020 and September 30, 2019, the Company shut-in production pursuant to its production optimization strategy and therefore recognized a net loss and negative adjusted funds flow for the periods.

For the three months ended September 30, 2020, Headwater incurred a net loss of $1,723 thousand compared to a net loss of $1,318 thousand for the three months ended September 30, 2019. A deferred income tax recovery of $463 thousand was recognized in Q3 2019, while there was no corresponding recovery recognized in Q3 2020. The net loss of $10,212 thousand for the nine months ended September 30, 2020 is primarily a result of transaction costs of $4,382 thousand incurred pursuant to the Recapitalization Transaction, a $4,074 thousand decline in natural gas sales period over period and exploration and evaluation expense of $3,821 thousand.

The Company recognized adjusted funds flow used in operations of $837 thousand for the three months ended September 30, 2020 compared to $1,427 thousand for the three months ended September 30, 2019 primarily due to lower general and administrative expenses. The Company recognized adjusted funds flow from operations of $3,966 thousand for the nine months ended September 30, 2020, a decline from $6,278 thousand for the nine months ended September 30, 2019 primarily due to lower natural gas sales partially offset by higher realized gains on financial derivatives.

9

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

		Three months ended			Nine months ended
		September 30,			September 30,
				Percent				Percent
		2020	2019	Change	2020	2019	Change
		($/boe)				($/boe)
Sales	-	-	-	16.76	40.74	(59)
Realized gains on financial derivatives	-	-	-	22.97	16.81	37
Royalties	-	-	-		(0.42)	(1.03)	(59)
Net sales	-	-	-	39.31	56.52	(30)
Production expenses	-	-	-		(9.92)	(11.33)	(12)
Operating netback (1)	-	-	-	29.39	45.19	(35)
General and administrative expenses	-	-	-	(12.44)	(13.28)	(6)
Interest income and other (2)	-	-	-	6.19	4.62	34
Decommissioning liabilities settled	-	-	-		-	(0.10)	(100)
Adjusted funds flow netback (1)	-	-	-	23.14	36.43	(36)
Transaction costs	-	-	-	(25.57)	-	100
Unrealized losses on financial derivatives	-	-	-	(9.41)	(1.88)	401
Stock-based compensation expense	-	-	-	(5.26)	(1.36)	287
Depletion and depreciation	-	-	-	(19.46)	(19.65)	(1)
Accretion and other expense	-	-	-	(0.74)	(0.99)	(25)
Write-off of E&E assets	-	-	-	(22.29)	-	100
Decommissioning liabilities settled	-	-	-		-	0.10	(100)
Income (loss) before income taxes	-	-	-	(59.59)	12.65	(571)
Deferred income tax expense	-	-	-	-	(4.71)	(100)
Net income (loss)		-	-	-		(59.59)	7.94	(851)

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

Capital Expenditures

	Three months ended			Nine months ended
	September 30,	Percent		September 30,	Percent
	2020	2019	Change	2020	2019	Change
	(thousands of dollars)			(thousands of dollars)
Exploration, development and	54	51	6	456	373	22
production
Capitalized overhead	7	4	75	41	44	(7)
Office and other assets	-	14	(100)		32	41	(22)
Total capital expenditures	61	69	(12)		529	458	16

Capital spending totaled $61 thousand for the three months ended September 30, 2020 compared to $69 thousand for the corresponding period of the prior year.

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.

10

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 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 September 30, 2020, the Company has sufficient liquidity and was holding cash and cash equivalents of $112,672 thousand and a working capital surplus of $112,536 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. Refer to "Subsequent Event" for additional information on the announced property acquisition.

Headwater's cash and cash equivalents include guaranteed investment certificates ("GIC's") that are highly liquid as the GIC's are redeemable on demand without penalty.

As of September 30, 2020, Headwater had the following financial liabilities outstanding:

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	Within 1 year	1 to 4 years	Beyond 4 years
	$	$	$
Accounts payable and accrued liabilities	911	-	-
Financial derivatives	131	-	-
Total	1,042	-	-

During the three months ended September 30, 2020, 7.2 million Warrants vested and became exercisable with potential proceeds of $6.7 million to the Company. There were no exercises related to the vested Warrants during the three months ended September 30, 2020.

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

Common Share Information

Share Capital

	Three months ended	Nine months ended
(thousands)		September 30,		September 30,
	2020	2019	2020	2019
Weighted average outstanding common shares (1)
-Basic	145,044	88,172	131,997	88,602
-Diluted	145,044	88,172	131,997	88,861
Outstanding securities at September 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 September 30, 2020 was approximately $203.1 million.

(thousands)	September 30, 2020
Common shares outstanding	145,044
Share price (1)	$1.40
Total market capitalization	$203,062

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

As at November 6, 2020 the Company had 145,044,493 common shares outstanding.

(thousands)	November 6, 2020
Outstanding securities at November 6, 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

Q3/20

Q2/20

Q1/20

Q4/19

Q3/19

Q2/19

Q1/19

Q4/18

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)	(364)	863	1,182	(192)	(342)	1,675	7,720	(1,609)
Adjusted funds flow from operations (1) (6) (8)	(837)	(610)	5,413	1,929	(1,427)	151	7,554	1,338
Per share - basic	(0.01)	-	0.05	0.02	(0.02)	-	0.08	0.02
- diluted	(0.01)	-	0.05	0.02	(0.02)	-	0.08	0.02
Net income (loss) (8)	(1,723)	(1,679)	(6,810)	1,447	(1,318)	(274)	2,960	6,104
Per share - basic	(0.01)	(0.01)	(0.06)	0.02	(0.02)	-	0.03	0.07
- diluted	(0.01)	(0.01)	(0.06)	0.02	(0.02)	-	0.03	0.07
Capital expenditures, net	61	398	70	227	69	211	178	724
Working capital	112,536	113,718	114,200	64,622	62,059	63,744	64,034	57,190
Shareholders' equity	155,148	156,386	157,235	114,310	112,792	114,148	114,768	111,700
Weighted average shares (thousands)
Basic	145,044	144,749	105,436	88,147	88,172	88,724	88,919	88,799
Diluted	145,044	144,749	105,436	88,542	88,172	88,724	89,213	89,237
Shares outstanding, end of period (thousands)
Basic	145,044	145,044	144,327	88,147	88,147	88,301	88,924	88,899
Diluted(9)	158,627	151,381	145,552	89,842	88,935	89,089	90,430	91,470
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 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 September 30, 2020 which include 6.3 million stock options with a weighted average exercise price of $1.04 and 7.2 million warrants with an exercise price of $0.92.

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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 contracts to mitigate the risks associated with the volatility of natural gas prices when natural gas production resumes.

In Q3 2020, Headwater incurred a net loss of $1,723 thousand. There were no sales recognized in the quarter as the Company shut-in production pursuant to its production optimization strategy. The Company resumed operations in late October 2020.

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.

Off-Balance Sheet Arrangements

There are currently no significant off-balance sheet arrangements.

New Accounting Policy

Government Grants

Since commencement of the Canada Emergency Wage Subsidy ("CEWS") program on March 15, 2020, Headwater has claimed a monthly subsidy for its eligible employees. Government grants are recognized when there is reasonable assurance that the grant will be received, and all conditions associated with the grant are met. Claims under government grant programs related to income are deducted in reporting the related expense and are recorded in the period in which the eligible expenses were incurred.

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 constitute 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

14

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. The adoption of the amendments to IFRS 3 did not impact the condensed interim financial statements, however the guidance will be incorporated into the Company's assessment of business combinations that occur after January 1, 2020.

Subsequent Event

Transformational Property Acquisition

On November 6, 2020, the board of directors has approved Headwater entering into a definitive agreement with Cenovus Energy Inc. ("Cenovus") and Cenovus Marten Hills Partnership ("CMHP"), an affiliate of Cenovus, to acquire the entirety of Cenovus' position in the Marten Hills area of Alberta (the "Transaction"). Pursuant to the Transaction, Headwater will acquire a 100% working interest in approximately 2,800 barrels per day of oil production and 270 net sections of Clearwater rights. The consideration will consist of $35 million of cash (subject to customary closing adjustments), 50 million common shares of Headwater and 15 million warrants, each exercisable into one common share of Headwater at an exercise price of $2.00. The warrants will be exercisable at any time following the closing date of the Transaction (the "Closing Date") and will expire three years from the Closing Date.

Concurrently with the closing of the Transaction, Headwater will enter into an investor agreement (the "Investor Agreement") with CMHP through which Cenovus will be entitled to nominate representatives to the Headwater board based on its ownership in Headwater. Cenovus will be entitled to nominate to Headwater's board of directors, two representatives if it owns greater or equal to 20% of the issued and outstanding common shares, or one representative, if it owns greater or equal to 10% but less than 20% of the issued and outstanding common shares. On the Closing Date and pursuant to the Investor Agreement, Headwater will cause two representatives from Cenovus to be appointed as directors of the Company. The Investor Agreement will also provide Cenovus with certain rights of participation in future offerings of equity securities of Headwater (based on Cenovus' pro rata ownership in the Company).

In connection with the Transaction, the Company and Cenovus have agreed that Cenovus will reserve from the acquired lands, a gross overriding royalty on the core development area and on the exploratory lands.

Further, Headwater has agreed to enter into a development agreement with CMHP (the "Development Agreement") concurrently with the closing of the Transaction, under which the Company will commit to spend $100 million in capital expenditures ("Expenditures") on the acquired lands by December 31, 2022 unless otherwise extended by Cenovus (the "Development Term"). The Company has agreed that if it fails to satisfy the Expenditures within the Development Term, the Company will pay to Cenovus, as a penalty, the balance of any remaining Expenditures and Headwater will have no further obligations under the Development Agreement.

The Transaction is subject to the approval under the Competition Act (Canada) and by the TSX, the shareholders of Headwater and certain regulatory and other authorities. In addition, the Transaction is subject to the satisfaction or waiver of other customary closing conditions. The Transaction will have an effective date of October 1, 2020 and is expected to close on December 22, 2020. Pursuant to the execution of the definitive agreement, Headwater will pay a $10 million deposit to Cenovus which will be credited against the consideration on closing.

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The following table sets forth the capitalization of Headwater after giving effect to the Transaction.

		Securities
	Weighted	outstanding as at	Pro forma securities
	average	November 6, outstanding on close of
(thousands)	exercise price	2020	the Transaction
Common shares issued		145,044	195,044
Stock options(1)	$1.04	6,338	6,338
Common share purchase warrants(1)	$0.92	21,739	21,739
Warrants issued to Cenovus	$2.00	-	15,000
Fully diluted common shares outstanding	$1.31	173,121	238,121

(1) Capitalization table assumes none of the stock options and common share purchase warrants are exercised prior to the closing of the Transaction.

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	Nine months ended
		September 30,		September 30,
	2020	2019	2020	2019
		(thousands of dollars)
Cash flow provided by operating activities	(364)	(342)	1,681	9,053
Changes in non - cash working capital	(473)	(1,085)	(2,097)	(2,775)
Transaction costs	-	-	4,382	-
Adjusted funds flow from operations	(837)	(1,427)	3,966	6,278

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

16

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 July 1, 2020 to September 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.

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.

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.

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

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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 condensed interim 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 such 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 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

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.

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.

18

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;
• 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

19

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 instruments;
• 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 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;
• expected future decommissioning liabilities;
• the expected closing date of the Transaction;
• Cenovus' ownership position in Headwater following the completion of the Transaction;
• Headwater's pro forma capitalization following completion of the Transaction;
• the number of director nominees on the board of directors of Headwater from time to time following the Transaction;
• the cash consideration to be paid to Cenovus by Headwater;
• the amount of expenditures to be made on the acquired lands by Headwater over the next two calendar years;
• the participation of Cenovus in the Company's future financings;
• the receipt of all regulatory and other approvals required for the Transaction, including approval under the Competition Act (Canada), the TSX, the shareholders of Headwater, as applicable; and
• the outcome of the U.S. election and the impacts on the economy and the oil and gas industry generally.

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

20

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.

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 Ltd.

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