Headwater Exploration : 2019 Management Discussion & Analysis

2019 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 March 25, 2020 and should be read in conjunction with the audited financial statements for the years ended December 31, 2019 and 2018 and the notes thereto. The audited financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). All dollar amounts are referenced in Canadian dollars. In addition, readers are also directed to the Company's Annual Information Form for the year ended December 31, 2019, dated March 25, 2020, which is available on the Company's website at www.headwaterexp.comand under the Company's profile on The System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.

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 onshore in New Brunswick. Headwater currently has natural gas production and reserves in the McCully Field near Sussex, New Brunswick. In addition, Headwater has a shale gas prospect in New Brunswick.

On March 4, 2020, Headwater announced the completion of the Recapitalization Transaction (as defined below), 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"). Additional information relating to the Recapitalization Transaction can be found under the heading "Subsequent Events" in this MD&A.

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 YEAR ENDED DECEMBER 31, 2019

• As at December 31, 2019, Headwater had cash and cash equivalents of $60.9 million, net working capital of $64.6 million and no outstanding debt. Pro forma the Recapitalization Transaction the Company had estimated working capital of approximately $110 million and no outstanding debt.
• Achieved funds flow from operations of $8.2 million and generated net income of $2.8 million.
• Total proved and proved developed producing reserves stayed flat year over year at 3.0 mmboe due to positive technical revisions which offset production during 2019.
• Proved plus probable reserves stayed flat year over year at 3.7 mmboe due to positive technical revisions which offset production during 2019. 100% of the proved plus probable reserves at year end are producing reserves.
• The net present value of future net revenues discounted at 10% after taxes of the proved producing reserves inclusive of all future abandonment and reclamation costs is $46.7 million.

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• The net present value of future net revenues discounted at 10% after taxes of the proved plus probable reserves inclusive of all future abandonment and reclamation costs is $55.6 million.
• On a pro forma basis after giving effect to the Recapitalization Transaction based on the net present value of future net revenues discounted at 10% after taxes of Headwater's proved developing producing reserves and proved plus probable reserves as presented and proforma positive working capital of $110 million, the Company's net asset value as at December 31, 2019 equates to $1.09 per basic Common Share on a proved developed producing basis and $1.15 per basic Common Share on a proved plus probable basis based on approximately 144.3 million Common Shares outstanding.

Guidance Update

Prior to completion of the Recapitalization Transaction, the Company provided guidance for a period from April 1 to March 31 of the following year. Going forward Headwater intends to issue guidance on a calendar year basis using certain different financial metrics than the Company used historically, and, as a result, all previous guidance issued by the Company is withdrawn.

The Company previously released guidance on November 12, 2019. Although the Company is on track to meet guidance volumes of 3.7 mmcf/d for the period from April 1, 2019 to March 31, 2020 as set out in such previous guidance, as a result of an abnormally warm winter, the Company realized lower than forecast commodity prices than assumed for the purposes of such previous guidance. The lower commodity prices are expected to result in approximately $1.9 million lower operating cash flow (previously referenced to as field operating netback in the November 12th, 2019 guidance) for the period from April 1, 2019 to March 31, 2020 than what was assumed for the previous guidance. In addition, capital expenditures for the year ended December 31, 2019 were $685 thousand compared to $1.1 million as set out in the previous guidance.

For 2020, the Board of Directors has approved the following guidance:

• 2020 average production of 4.1 mmcf/d (approximately 99% conventional natural gas and 1% natural gas liquids) (assumes all productionshut-in from May 1 to November 1, 2020).
• Operating cash flow of $6.8 million (inclusive of realized financial derivatives).
• 2020 funds flow from operations of $5.5 million.
• Capital expenditures on base assets of $0.5 million.
• 2020 exit working capital (assuming no other acquisitions or development) of $115 million.

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Results of Operations

Production and pricing

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
Average daily production
Natural gas (mmcf/d)	3.5	4.4	(20)	3.7	4.2	(12)
Natural gas liquids (bbl/d)	2	-	100	4	3	33
Barrels of oil equivalent (boe/d)	586	726	(19)	620	709	(13)
Headwater average sales price
Natural gas ($/mcf)	6.80	8.53	(20)	6.49	10.57	(39)
Natural gas liquids ($/bbl)	83.34	-	100	80.56	83.76	(4)
Barrels of oil equivalent ($/boe)	40.92	51.20	(20)	39.21	63.50	(38)
Average Benchmark Price
Algonquin city-gates (US$/mmbtu)	3.19	5.02	(36)	3.17	4.85	(35)
Exchange rate (US$/Cdn$)	0.76	0.76	-	0.75	0.77	(3)

Sales

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	(thousands of dollars)				(thousands of dollars)
Natural gas	2,193	3,422	(36)	8,767	16,360	(46)
Natural gas liquids	13	-	100	107	77	39
Gathering processing and
transportation fees	104	103	1		459	507	(10)
	2,310	3,525	(34)		9,333	16,944	(45)

Natural gas sales for Q4 2019 decreased to $2,193 thousand from $3,422 thousand in Q4 2018 due primarily to a 20 percent decrease in the average natural gas production to 3.5 mmcf/d in Q4 2019 from 4.4 mmcf/d in Q4 2018 and the decrease in natural gas price to $6.80/mcf in Q4 2019 from $8.53/mcf in Q4 2018.

For the year ended December 31, 2019, natural gas sales decreased to $8,767 thousand from $16,360 thousand for the year ended December 31, 2018, due to the 12 percent decrease in the average daily natural gas production to 3.7 mmcf/d in 2019 from 4.2 mmcf/d in 2018 and a decrease in Headwater's average realized natural gas sales price to $6.49/mcf in 2019 from $10.57/mcf in 2018. Management had determined in each of 2019 and 2018 to shut-in producing natural gas wells to take advantage of the expected significant differential in the sale price of natural gas at Algonquin city-gates ("AGT") for the summer and fall relative to the winter.

Headwater owns the midstream facilities which process and transport gas from the McCully Field to the Maritimes & Northeast Pipeline ("M&NP"). Third party gas flowing through these facilities, which currently is limited to Nutrien Inc.'s ("Nutrien") (formerly Potash Corporation of Saskatchewan Inc.) share of gas from the McCully Field, is charged a cost of service. The decrease in the gathering, processing and transportation fees to $459 thousand for the year ended December 31, 2019 from $507 thousand for the year ended December 31, 2018 is due to a decrease in Nutrien's share of natural gas production as a result of the decrease in natural gas production at the McCully Field in 2019.

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Financial Derivatives Gains

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

Three months ended				Year ended
December 31,		Percent		December 31,		Percent
2019	2018		Change	2019	2018		Change
(thousands of dollars)				(thousands of dollars)
793	868	(9)	3,691	(530)	(796)
810	2,432	(67)		485	2,508	(81)
1,603	3,300	(51)		4,176	1,978	111

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 when natural gas production resumes at the McCully Field after a shut-in period.

The realized gain/loss represents the natural gas contracts settled during the three and twelve months ended December 31, 2019. Natural gas commodity contracts are referenced to the AGT price and the realized gains and losses fluctuate based on changes in the AGT price. Realized financial derivative gains were recorded during the three and twelve months ended December 31, 2019 of $793 thousand and $3,691 thousand respectively, compared to a realized gain of $868 thousand in the three months ended December 2018 and a realized loss of $530 thousand in the twelve months ended December 31, 2018. The Company recognized gains on its natural gas contacts in 2019, as the commodity contacts to fix the AGT price exceeded the actual price in the period.

Unrealized financial derivative gains were recorded during the three and twelve months ended December 31, 2019 of $810 thousand and $485 thousand respectively, compared to $2,432 thousand and $2,508 thousand in the corresponding periods of 2018.

As of December 31, 2019, the fair value of Headwater's outstanding natural gas contracts was an unrealized asset of $1,481 thousand as reflected in the annual 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 December 31, 2019, had the contracts been monetized or terminated.

As of December 31, 2019, Headwater had the following financial derivative contracts in place:

Type	Period	Daily Volume		Price			Index
Swap	Jan. 1, 2020 to Mar. 31, 2020	2,500 mmbtu		$US9.00/mmbtu	AGT-daily
Swap	Jan. 1, 2020 to Mar. 31, 2020	2,500 mmbtu		$US7.12/mmbtu	AGT-daily
Royalty Expense
		Three months ended				Year ended
		December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
		(thousands of dollars)				(thousands of dollars)
Royalty expense	52	96	(46)	230	506	(55)
Percent of total revenue	2.3%	2.7%	(15)	2.5%	3.0%	(17)
Per mcf ($)	0.16	0.24	(33)	0.17	0.33	(48)
Per boe ($)	0.96	1.44	(33)	1.02	1.95	(48)

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Headwater's royalty expense for Q4 2019 decreased to $52 thousand from $96 thousand for Q4 2018 and to $230 thousand for the year ended December 31, 2019 from $506 thousand for the year ended December 31, 2018 due to the decrease in natural gas sales in 2019.

Production Expense

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	(thousands of dollars)				(thousands of dollars)
Gross production expense	791	889	(11)	3,036	3,076	(1)
Third party recoveries	(134)	(78)	72		(425)	(337)	26
Net production expense	657	811	(19)	2,611	2,739	(5)
Per mcf ($)	2.04	2.02	1	1.93	1.77	9
Per boe ($)	12.19	12.13	1	11.54	10.58	9

Gross production expense decreased to $791 thousand for Q4 2019 from $889 thousand for Q4 2018 due to field employee bonuses expensed in Q3 2019 as compared to Q4 2018. Third party recoveries for the three and twelve months ended December 31, 2019 increased to $134 thousand and $425 thousand, respectively, as the Company took over operatorship of Nutrien's gas plant.

General and Administrative Expenses

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	(thousands of dollars)				(thousands of dollars)
General and administrative	713	861	(17)	3,046	2,740	11
Overhead recoveries	-	(31)	(100)	(44)	(123)	(64)
Third party recoveries	-	(11)	(100)		-	(12)	(100)
Net general and administrative expense	713	819	(13)	3,002	2,605	15
Per mcf ($)	2.21	2.04	8	2.22	1.68	32
Per boe ($)	13.22	12.25	8	13.26	10.06	32

Gross general and administrative expenses decreased to $713 thousand in Q4 2019 from $861 thousand in Q4 2018 due primarily to the payment of employee bonuses in Q3 2019 as compared to Q4 2018. Gross general and administrative expenses increased to $3,046 thousand for the year ended December 31, 2019 from $2,740 thousand for the year ended December 31, 2018 due in part to an increase in technical consulting costs and a one-time severance payment.

5

Interest income and other

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	(thousands of dollars)				(thousands of dollars)
Interest and other income	296	261	13	1,147	889	29
Foreign exchange gains (losses)	(40)	94	(143)	(83)	634	(113)
Accretion	(50)	(70)	(29)	(219)	(267)	(18)
Interest on lease liability	(1)	-	100		(15)	-	100
Total interest income and other	205	285	(28)		830	1,256	(34)
Per mcf ($)	0.63	0.71	(11)	0.61	0.81	(25)
Per boe ($)	3.80	4.26	(11)	3.67	4.85	(24)

Interest income and other during Q4 and the year ended December 31, 2019 was $205 thousand and $830 thousand, respectively, compared to $285 thousand and $1,256 thousand in the corresponding periods of 2018. The decrease for the year ended December 31, 2019 is primarily due to foreign exchange losses of $83 thousand in 2019 compared to a foreign exchange gains of $634 thousand in 2018. 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.

Share-based Compensation

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	(thousands of dollars)				(thousands of dollars)
Stock options	71	55	29	326	171	91
Deferred share units	32	56	(43)		11	179	(94)
Stock-based compensation expense	103	111	(7)	337	350	(4)
Per mcf ($)	0.32	0.28	14	0.25	0.23	9
Per boe ($)	1.90	1.66	14	1.49	1.35	10

Stock-based compensation expense during Q4 and year ended December 31, 2019 was $103 thousand and $337 thousand respectively, compared to $111 thousand and $350 thousand in the corresponding periods of 2018. Stock-based compensation relating to stock options increased in both the fourth quarter and year ended December 31, 2019, due to recognising a full period of expense from stock options granted late in 2018 combined with additional stock options granted in 2019. The decrease in stock-based compensation relating to deferred share units ("DSUs") in both the fourth quarter and year ended December 31, 2019, is due to fewer DSU's granted in 2019 compared to 2018.

6

Depletion, Depreciation and Amortization

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	thousands of dollars				thousands of dollars
Depletion, depreciation and amortization	1,375	1,247	10	4,762	4,871	(2)
Per mcf ($)	4.26	3.11	37	3.53	3.15	12
Per boe ($)	25.50	18.67	37	21.04	18.82	12

Depletion expense is calculated using the unit-of-production method which is based on production volumes in relation to the proved reserves base. The decrease in depletion, depreciation and amortization expense to $4,762 thousand for the twelve months ended December 31, 2019 from $4,871 thousand for the same period in 2018 is primarily due to the decrease in natural gas production in 2019 partially offset by the depreciation on right-of-use assets that commenced on January 1, 2019.

Impairment Losses (Reversal)

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	thousands of dollars				thousands of dollars
Impairment losses (reversal)	(322)	(530)	(39)	(322)	(530)	(39)
Impairment - Old Harry prospect	-	-	-		-	11,408	(100)
	(322)	(530)	(39)		(322)	10,878	(103)
Per mcf ($)	(1.00)	(1.32)	(24)	(0.24)	7.03	(103)
Per boe ($)	(5.97)	(7.93)	(25)	(1.42)	42.03	(103)

The Company recognized a reversal of impairment losses of $322 thousand for the year ended December 31, 2019 and $530 thousand for the year ended December 31, 2018 relating to the Company's New Brunswick cash generating unit ("CGU") which includes the McCully Field. The reversal of impairment losses for the year ended December 31, 2019 is due to additions in proved plus probable reserves of 1.3 bcf due to increased well recovery estimates in the 2019 GLJ Reserves Report (as defined below) which largely replaced the decrease resulting from the current year's production of 1.4 bcf and a decrease in expected future natural gas prices by GLJ (as defined below). GLJ's estimate of proved plus probable natural gas reserves in the 2019 GLJ Reserves Report decreased by only 0.1 bcf to 22.1 bcf from GLJ's estimate of 22.2 bcf effective as at December 31, 2018.

The calculations of the reversal of impairment losses for the year ended December 31, 2019 and 2018 were based on the difference between the carrying value of the New Brunswick CGU and its recoverable amount. The recoverable amount was determined using fair value less costs to sell based on after-tax future net cash flows of proved plus probable reserves using forecast prices and costs and discounted using 10%.

For the year ended December 31, 2019, the Company utilized the following forecast prices in the fair value calculation:

	2020	2021	2022	2023	2024	2025-2029	Thereafter
AGT ($US/mmbtu)	3.40	3.65	3.86	4.05	4.15	4.23- 4.67	+2%/year
McCully ($CDN/mcf)	4.36	4.65	4.85	5.10	7.18	7.82- 8.41	+2%/year
Exchange rate ($US/$CDN)	0.76	0.77	0.79	0.79	0.79	0.79	0.79
							7

The forecast McCully natural gas prices were calculated by adjusting the AGT natural gas prices to reflect the expected premiums received at Headwater's delivery point, transportation costs, if applicable, and heat content.

For the year ended December 31, 2018, the Company utilized the following forecast prices in the fair value calculation:

	2019	2020	2021	2022	2023	2024-2028	Thereafter
AGT ($US/mmbtu)	4.40	4.55	4.55	4.50	4.63	4.70- 5.00	+2%/year
McCully ($CDN/mcf)	6.14	5.87	5.72	5.51	5.61	7.55- 8.24	+2%/year
Exchange rate ($US/$CDN)	0.75	0.77	0.79	0.81	0.82	0.825	0.83

In Q4 2018, the Company recognized a reversal of impairment losses of $530 thousand relating to the Company's New Brunswick CGU, which includes the McCully Field. The reversal of impairment losses for the year ended December 31, 2018 was due to additions in proved plus probable reserves of 1.1 bcf due to increased well recovery estimates in GLJ's evaluation of the Company's reserves as at December 31, 2018 which largely replaced the decrease resulting from 2018 annual production of 1.5 bcf. As a result, GLJ's estimate of proved plus probable natural gas reserves as at December 31, 2018 decreased by only 0.3 bcf to 22.2 bcf from GLJ's estimate of 22.5 bcf effective as at December 31, 2017.

In 2018, Headwater recognized impairment losses of $11,408 thousand relating to costs incurred to date on the Old Harry prospect. The recognition of impairment losses resulted from the Company's decision to suspend any further technical and capital spending on the Old Harry prospect after a comprehensive review revealed more complexity in the Old Harry prospect than previous analysis had suggested, which included the results of an integrated geotechnical analysis of the controlled source electro-magnetic ("CSEM") survey and reprocessed 2D seismic.

Other Write-downs and Losses

Management wrote down its sand inventory by $151 thousand in 2019 (2018 - $52 thousand) to reflect a decrease in the net realizable value of such inventory.

Decommissioning Liabilities

As at December 31, 2019, the decommissioning liabilities of the Company were $11,976 thousand. The Company recorded an increase of $876 thousand in the obligation from the decommissioning liability of $11,100 thousand as at December 31, 2018. This increase of $876 thousand is primarily due to the decrease in the discount rate to 1.8% used at December 31, 2019 as compared to 2.2% used at December 31, 2018.

Deferred Income Taxes

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	thousands of dollars				thousands of dollars
Deferred income tax expense (recovery)	(58)	(1,600)	(96)	753	(1,609)	(147)
Canadian statutory income tax rate	29.0%	29.3%	(1)	29.0%	29.3%	(1)

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During Q4 and year ended December 31, 2019, the Company recorded a deferred income tax recovery of $58 thousand and deferred income tax expense of $753 thousand respectively, compared to deferred income tax recoveries of $1,600 thousand and $1,609 thousand in the corresponding periods of 2018. The Company's effective tax provision rate in 2019 is 29%.

As at December 31, 2019, the Company has a deferred income tax asset of $3,286 thousand. The Company has $100 million of deductible timing differences for which no deferred income tax asset is recognized as it is not probable that there will be sufficient taxable profits and reversal of deductible temporary differences in the future to facilitate the utilization by the Company of the underlying tax- deductible amounts.

Based on planned capital expenditure programs and current natural gas price assumptions, the Company does not expect to be cash taxable in the future. At December 31, 2019, the Company had approximately $159 million of tax pools available to be applied against future taxable income. The federal tax pools are estimated as follows:

	Estimated balance at
($ thousands)	January 1, 2020
Canadian oil and gas property expense	2,528
Canadian development expense	38,848
Canadian exploration expense	99,999
Undepreciated capital cost	17,269
Other	352
Total	158,996

Funds Flow from Operations and Net Income (Loss)

The Company's funds flow from operations and net income generating capability are a direct result of production and commodity prices. For the year ended December 31, 2019, Headwater's net income increased to $2,815 thousand from a net loss of $314 thousand for the year ended December 31, 2018 due primarily to the reversal of impairment losses of $322 thousand during the year ended December 31, 2019 as compared to the recognition of impairment losses of $10,878 thousand for the year ended December 31, 2018. This was partially offset by the decrease in sales from the decline in the production and natural gas pricing.

Funds flow from operations decreased to $8,206 thousand for the year ended December 31, 2019 from $10,232 thousand for the year ended December 31, 2018 primarily due to lower natural gas sales partially offset by realized financial derivatives gains of $3,691 thousand in 2019 and a decrease of $1,731 thousand in decommissioning liabilities settled in 2019.

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

	Three months
	ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	($/boe)				($/boe)
Sales	42.84	52.74	(19)	41.24	65.46	(37)
Realized gains (losses) on financial derivatives	14.70	12.99	13	16.31	(2.05)	(896)
Royalties	(0.96)	(1.44)	(33)		(1.02)	(1.95)	(48)
Net sales	56.58	64.29	(12)	56.53	61.46	(8)
Production expenses	(12.19)	(12.13)	1	(11.54)	(10.58)	9
Transportation expenses	-	-	-		-	(0.39)	(100)
Operating netback (1)	44.39	52.16	(15)	44.99	50.49	(11)
General and administrative expenses	(13.22)	(12.25)	8	(13.26)	(10.06)	32
Interest income and other (2)	4.73	5.30	(11)	4.64	5.88	(21)
Decommissioning liabilities settled	(0.13)	(25.20)	(99)		(0.11)	(6.78)	(98)
Funds flow netback (1) (3)	35.77	20.01	79	36.26	39.53	(8)
Unrealized gains on financial derivatives	15.02	36.39	(59)	2.14	9.69	(78)
Stock-based compensation expense	(1.90)	(1.66)	14	(1.49)	(1.35)	10
Decommissioning liabilities settled	0.13	25.20	(99)	0.11	6.78	(98)
Depletion, depreciation and amortization	(25.50)	(18.67)	37	(21.04)	(18.82)	12
Accretion and other expense	(0.93)	(1.04)	(11)	(0.97)	(1.03)	(6)
Impairment reversal (losses)	5.97	7.93	(25)	1.42	(42.03)	(103)
Other write-downs and losses	(2.80)	(0.77)	264		(0.67)	(0.20)	235
Income (loss) before income taxes	25.76	67.38	(62)	15.76	(7.43)	(312)
Deferred income tax recovery (expense)	1.08	23.94	(95)		(3.33)	6.22	(154)
Net income (loss)	26.84	91.32	(71)	12.43	(1.21)	(1,128)

1. Non-GAAPmeasure. See Non-GAAP measures advisory.
2. Excludes accretion on decommissioning liabilities.
3. Comparative period revised to reflect current period presentation. Decommissioning liabilities settled was previously not included in the funds flow netback calculation.

Capital Expenditures

	Three months ended				Year ended
	December 31,		Percent		December 31,		Percent
	2019	2018		Change	2019	2018		Change
	(thousands of dollars)				(thousands of dollars)
Exploration, development and production	224	564	(60)	597	1,937	(69)
Capitalized overhead	-	31	(100)	44	123	(64)
Office and other assets	3	129	(98)		44	194	(77)
Total capital expenditures	227	724	(69)		685	2,254	(70)

Capital expenditures were $227 thousand and $685 thousand for the three and twelve months ended December 31, 2019, respectively, from $724 thousand and $2,254 thousand for the comparable periods of 2018. Capital expenditures in 2018 primarily relate to costs incurred on the CSEM survey and 2D seismic reprocessing over the Newfoundland and Labrador portion of the Old Harry prospect incurred Q1 2018. The capital expenditures in 2019 primarily relate to costs associated with the geoscience study completed in the Frederick Brook shale prospect.

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Liquidity and Capital Resources

Headwater's liquidity depends upon cash flow provided by operating activities, supplemented as necessary by equity and debt financings. At December 31, 2019, the Company was holding cash and cash equivalents of $60,957 thousand and working capital of $64,622 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 will therefore depend on the termination of the moratorium in New Brunswick.

Subsequent to year-end, the Company completed the Recapitalization Transaction raising aggregate gross proceeds of $50 million. Headwater intends to use the net proceeds from the Recapitalization Transaction for acquisition, development and drilling opportunities. Additional information relating to the Recapitalization Transaction can be found under the heading "Subsequent Events" in this MD&A. Pro forma the Recapitalization Transaction the Company had estimated working capital of approximately $110 million and no outstanding debt.

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 bank deposits with 90 days or less to maturity.

As of December 31, 2019, Headwater had the following contractual obligations and commitments:

(thousands of dollars)	Total	2020	2021	2022	2023	2024	Thereafter
Accounts payable and accrued liabilities	1,378	1,378	-	-	-	-	-
Lease liability	285	90	28	15	6	6	140
Operating leases	679	123	97	93	93	92	181
	2,342	1,591	125	108	99	98	321

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	Year ended
(thousands)	December 31,	December 31,
	2019	2018	2019	2018
Weighted average outstanding common shares (1)
-Basic	88,147	88,799	88,472	88,700
-Diluted	88,542	89,237	88,757	89,095
Outstanding securities at December 31, 2019
-Common shares				88,147
-Stock options - average strike price of $0.79				3,490

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

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On August 23, 2018, the Company implemented a normal course issuer bid ("NCIB") under the Toronto Stock Exchange that allowed the Company to purchase, for cancellation, up to 6,803,118 common shares. The NCIB expired on August 22, 2019.

During the year ended December 31, 2019, the Company purchased and cancelled 777 thousand common shares for total consideration of $549 thousand. The total cost paid, including commissions and fees, was recognized directly as a reduction in shareholders' equity. Under the NCIB, all common shares purchased were cancelled.

Total Market Capitalization

The Company's market capitalization at December 31, 2019 was approximately $63.5 million.

(thousands)	December 31, 2019
Common shares outstanding	88,147
Share price (1)	$0.72
Total market capitalization	$63,466

(1) Represents the last price traded on the TSX on December 31, 2019.

As at March 25, 2020 the Company had 144,326,994 common shares outstanding.

(thousands)	March 25, 2020
Outstanding securities at March 25, 2020
-Common shares	144,327
-Stock options - weighted average exercise price of $0.63	1,225
-Warrants(1)- exercise price of $0.92	21,739

(1) See "Subsequent Events" for additional information relating to the Warrants.

Related Party Transactions

Key management personnel of the Company include its directors and senior management. In 2019, the Company recorded $1,228 thousand (2018 - $1,281 thousand) relating to compensation of key management personnel. In 2019, share-based compensation costs relating to compensation of key management personnel were $232 thousand (2018 - $108 thousand).

Selected Annual Financial Information

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

	2019	2018	2017
(thousands of dollars except share data and production volumes)
Average production volumes (mmcf/d)	3.7	4.2	2.5
Sales	9,333	16,944	7,674
Net income (loss)	2,815	(314)	17,739
Net income (loss) per share
-basic and diluted	0.03	-	0.20
Cash flow provided by operating activities	8,861	10,115	1,077
Funds flow from operations (1)	8,206	10,232	2,441
Working capital	64,622	57,190	46,918
Capital expenditures	685	2,254	3,029
Total assets	128,271	125,301	124,360
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1. "Funds flow from operations" is anon-IFRS financial measure, see "Non-IFRS Financial Measures"

Summary of Quarterly Information

	Q4/19	Q3/19	Q2/19	Q1/19	Q4/18	Q3/18	Q2/18	Q1/18
Financial(thousands of dollars except share data)
Sales	2,310	-	1,014	6,009	3,525	-	1,583	11,835
Cash flows provided by operating activities (6)	(192)	(342)	1,675	7,720	(1,609)	(723)	2,336	10,111
Funds flow from operations (1) (6)	1,929	(1,427)	151	7,554	1,338	(938)	187	9,645
Per share - basic	0.02	(0.02)	-	0.08	0.02	(0.01)	-	0.11
- diluted	0.02	(0.02)	-	0.08	0.02	(0.01)	-	0.11
Net income (loss)	1,447	(1,318)	(274)	2,960	6,104	(1,860)	(10,127)	5,569
Per share - basic	0.02	(0.02)	-	0.03	0.07	(0.02)	(0.11)	0.06
- diluted	0.02	(0.02)	-	0.03	0.07	(0.02)	(0.11)	0.06
Capital expenditures, net	227	69	211	178	724	307	502	721
Working capital	64,622	62,059	63,744	64,034	57,190	54,286	56,219	56,992
Shareholders' equity	114,310	112,792	114,128	114,768	111,700	105,478	107,207	117,327
Weighted average shares thousands)
Basic	88,147	88,172	88,724	88,919	88,799	88,689	88,655	88,655
Diluted	88,542	88,406	88,995	89,213	89,237	89,029	89,040	89,107
Shares outstanding, end of period (thousands)
Basic	88,147	88,147	88,301	88,924	88,899	88,742	88,655	88,655
Diluted	89,842	88,935	89,089	90,430	91,470	89,687	89,687	89,687
Operating(6:1 boe conversion)
Average daily production
Natural gas (mmcf/d)	3.5	-	2.4	9.0	4.4	-	2.8	9.9
Natural gas liquids (bbl/d)	2	-	3	10	-	-	6	4
Barrels of oil equivalent (boe/d)(2)	586	-	401	1,510	726	-	472	1,657
Average selling prices(3)
Natural gas ($/mcf)	6.80	-	4.16	7.00	8.53	-	5.63	12.90
Natural gas liquids ($/bbl)	83.34	-	89.82	76.80	-	-	87.94	77.41
Barrels of oil equivalent ($/boe)(2)	40.92	-	25.49	42.22	51.20	-	34.50	77.36
Netbacks ($/boe)(2)
Operating
Sales(3)	42.84	-	27.75	44.23	52.74	-	36.88	79.38
Realized gain (loss) on financial
derivatives	14.70	-	1.43	20.95	12.99	-	(7.44)	(7.24)
Royalties	(0.96)	-	(0.53)	(1.17)	(1.44)	-	(0.59)	(2.58)
Production expenses	(12.19)	-	(16.64)	(5.50)	(12.13)	-	(16.34)	(4.71)
Transportation expenses	-	-	-	-	-	-	(0.52)	(0.52)
Operating netback ($/boe)(4)	44.39	-	12.01	58.51	52.16	-	11.99	64.33
General and administrative	(13.22)	-	(15.89)	(4.43)	(12.25)	-	(14.08)	(4.08)
Interest income and other (7)	4.73	-	8.46	1.49	5.30	-	6.45	4.43
Decommissioning liabilities settled	(0.13)	-	(0.44)	(0.03)	(25.20)	-	-	-
Funds flow netback(5)(6)($/boe)	35.77	-	4.14	55.54	20.01	-	4.36	64.68

1. Management uses funds flow from operations to analyze operating performance and leverage. 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 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 unrealized financial derivative contracts.
4. Operating netback is calculated as sales received less royalties, operating and transportation costs and realized gains or losses on financial derivatives.
5. 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, funds flow from operations or the funds flow netback calculation.
7. Excludes accretion on decommissioning liabilities.

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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 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 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.

Subsequent Events

1. Natural gas contracts Financial derivative

Subsequent to December 31, 2019, the Company entered into a commodity contract for 2,500 mmbtu/d at a fixed price of US$5.45/mmbtu for February 2020.

Physical trade

Subsequent to December 31, 2019, the Company entered into a physical natural gas contract with Repsol for 5,000 mmbtu/d at US$2.40/mmbtu for April 2020.

1. Stock options Stock option exercises
   Subsequent to December 31, 2019, 1.8 million stock options were exercised for proceeds of $1.7 million. Stock option grants

At a meeting of the Board of Directors held on March 25, 2020 the directors approved a grant of 1,200,000 stock options to purchase common shares to the non-management directors of the Company under the existing stock option plan of the Company (the "Existing Option Plan"). Pursuant to the stock option grant, each non-management director will be granted 200,000 stock options on March 27, 2020 with an exercise price based on the closing price of the common shares of the Company on the Toronto Stock Exchange on March 26, 2020. The stock options granted to the non-management directors vest as to one third of the number of stock 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.

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In addition, at the meeting of the Board of Directors held on March 25, 2020 the directors also approved a new stock option plan (the "New Option Plan"). Under the terms of the New Option Plan, an aggregate number of stock options equal to 8.0% of the aggregate number of issued and outstanding common shares less the aggregate number of options outstanding under the Existing Option Plan may be granted. No stock options granted under the New Option Plan will be exercisable until the Company receives approval of the New Option Plan from the shareholders of the Company in accordance with the rules of the Toronto Stock Exchange. A grant of an aggregate of 5,065,000 stock options to purchase common shares to certain officers, employees and contractors of the Company under the New Option Plan was also approved on March 25, 2020. The effective date of the grant of the majority of the stock options granted under the New Option Plan will be March 27, 2020 with an exercise price based on the closing price of the common shares of the Company on the Toronto Stock Exchange on March 26, 2020; provided that grants to certain new officers and employee will be deferred until the start date of such officers and employees with the exercise price based on the closing price on the trading day immediately prior to such start date. The stock options will vest as to one third of the number of stock 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.

c) Recapitalization transaction

On March 4, 2020, the Company completed its previously announced recapitalization transaction (the "Recapitalization Transaction"), as further described in the Company's management information circular dated February 3, 2020. The Recapitalization Transaction involved the following:

• Anon-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 Toronto Stock Exchange, the non- brokered private placement was approved by shareholders of the Company at a special meeting held on March 4, 2020.
• Concurrently with the closing of thenon-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 thenon-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 held on March 4, 2020.

Headwater intends to use the proceeds of the private placements for acquisition, development and drilling opportunities. A total of approximately $4.4 million of transaction costs and approximately $1.9 million of share issue costs were incurred in relation to the Recapitalization Transaction. Included in transaction costs is approximately $1.2 million related to severance and $0.5 million related to the settlement of DSU's.

d) Commodity price volatility

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Subsequent to year-end significant declines in the spot price for oil and gas and significant declines in the stock market have occurred for various reasons linked to the COVID 19 pandemic and other conditions impacting worldwide oil prices.

The Company determines the recoverable amount of its oil and gas properties using a fair value less costs to sell model. Subsequent declines in oil and gas prices have not been reflected in the determination of the recoverable amount of oil and gas properties at December 31, 2019 in accordance with IFRS. In particular, pricing assumptions used in the determination of the recoverable amount were based on forward expectations at December 31, 2019.

Impairment indicators for our oil and gas properties could exist at March 31, 2020, if current conditions persist.

.

Non-GAAP Financial Measures

Throughout this MD&A, the Company uses the terms "operating cash flow", "operating netback", "funds flow netback", "funds flow from operations" and "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 cash flow is calculated as sales, less royalties, operating and transportation expenses and realized gains or losses on financial derivatives. Operating netback is calculated as operating cash flow on a boe basis. Operating cash flow and 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.

Funds flow from operations is calculated as cash flow provided by operating activities before changes in non-cash working capital. Funds flow from operations is used by the Company to analyse operating performance, leverage and liquidity and is included in this MD&A because it is believed to facilitate the understanding of the results of Headwater's operations and financial position. Funds flow netback is calculated as funds flow from operations on a boe basis. Funds flow per share is calculated as funds flow from operations divided by the number of weighted average basic or diluted shares outstanding.

Funds flow from operations represents cash flow provided by operating activities excluding the change in non-cash operating working capital, as follows:

Cash flow provided by operating activities Changes in non - cash working capital Funds flow from operations

Three months ended	Year ended,
December 31,	December 31,
2019	2018	2019	2018
	(thousands of dollars)
(192)	(1,609)	8,861	10,115
2,121	2,947	(655)	117
1,929	1,338	8,206	10,232

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") of the Company have designed, or caused to be designed under their supervision, disclosure controls and procedures as defined in National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings("NI 52-109") of the Canadian Securities Administrators, to provide reasonable assurance that: (i) information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities

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legislation is accumulated and communicated to the Company's management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation.

The CEO and the CFO have evaluated the effectiveness of Headwater's disclosure controls and procedures as at December 31, 2019 and have concluded that such disclosure controls and procedures were effective as at such date.

The CEO and the CFO of Headwater have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR") as defined in NI 52-109. The control framework Headwater's officers used to design the Company's ICFR is the COSO Framework published by The Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). The CEO and CFO have concluded that the Company's ICFR were effective as of December 31, 2019. There have been no changes in the ICFR during the period from January 1, 2019 to December 31, 2019 that have materially affected, or are reasonably likely to materially affect the Company's ICFR.

It should be noted that while Headwater's CEO and CFO 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. 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

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fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors.

1. 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.

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.

b) Key Sources of Estimation Uncertainty

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 establish reserve determinations in accordance with National Instrument (NI) 51-101,

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"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.

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, 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.

Change in Accounting Policy

Headwater's audited financial statements for the year ended December 31, 2019 have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board, and in accordance with IAS 34 - Interim Financial Reporting.

The following accounting standard was adopted in 2019:

IFRS 16 "Leases"

On January 1, 2019, the Company adopted IFRS 16 "Leases" ("IFRS 16") which replaced IAS 17 "Leases" ("IAS 17"). The Company applied the modified retrospective approach which does not require restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is recorded as an adjustment to opening retained earnings. IFRS 16 requires the recognition of a right-of-use asset and lease liability on the Statement of Financial Position for most leases, however, leases relating to the exploration of natural gas and oil resources are excluded.

On transition to IFRS 16, the Company elected not to reassess whether a contract is, or contains, a lease and IFRS 16 was therefore only applied to contracts that were previously classified as operating leases under IAS 17. The Company did not have any leases that were classified as finance leases under IAS 17 at December 31, 2018. The Company also applied the permitted practical expedient relating to the use of hindsight in determining the lease term when the contract contains options to extend or terminate the lease.

The reconciliation of lease commitments from December 31, 2018 to the lease liabilities at January 1, 2019 is as follows:

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	January 1, 2019
	(thousands of dollars)
Operating lease commitments disclosed as at December 31, 2018	1,211
Exclusion for leases to explore for natural gas	(972)
Practical expedient relating to lease term extension	219
Discounting, using weighted average incremental borrowing rate of 4.4%	(104)
Lease liabilities at January 1, 2019	354

Management has identified right-of-use assets related to office space, vehicles and land surface rights relating to producing facilities. The Company elected to measure right-of-use assets at an amount equal to the lease liability of $354 thousand at January 1, 2019 and therefore the adoption of IFRS 16 had no impact on the retained earnings at January 1, 2019.

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 of such risk factors, which should not be construed as exhaustive:

• Public health risk including relating to theCOVID-19 pandemic;
• Natural disasters, terrorist Acts, civil unrest, pandemics and other disruptions and dislocations;
• Weakness and volatility in the oil and natural gas industry;
• Hydraulic fracturing;
• Prices, markets and marketing;
• Exploration, development and production risks;
• Market price;
• 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 tonon-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 on The System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.which can be found 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 to 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.

Net Asset Value

The term net asset value does not have a standardized meaning or standard method of calculation and therefore such measure may not be comparable to similar measures used by other companies. Such metric has been included herein to provide readers with additional measures to evaluate the value of the Company's assets; however, such measure is not a reliable indicator of the Company's future performance or value of the common shares. The inputs for the calculation of net asset value are identified in the body of this MD&A.

Pro Forma Disclosure

The Pro Forma calculations reflect the issuance of an aggregate of 54,347,826 Common Shares (as defined under the heading "Subsequent Events" in this MD&A) and 21,739,130 Warrants (as defined under the heading "Subsequent Events" in this MD&A) for gross proceeds of $50 million, stock option proceeds of $1.67 million and transaction costs and share issue costs of $6.3 million pursuant to the Recapitalization Transaction.

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:

• 2020 expected annual average production;
• 2020 expected operating cash flow;
• 2020 expected funds flow from operations;
• 2020 expected capital expenditures on base assets;
• 2020 expected exit working capital;
• business plans and strategies (including its production optimization and hedging strategies);
• Headwater's intended use of the net proceeds from the Recapitalization Transaction;
• Canadian - U.S. dollar exchange rate;
• expected natural gas sales prices and premiums;
• future revenue from financial hedges;

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• 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;
• 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.

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 hedging 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 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.

Reserves Information

Reserves information as at December 31, 2019 as presented herein is based on a report (the ("2019 GLJ Reserves Report") prepared by GLJ Petroleum Consultants Ltd. ("GLJ") assessing the Company's reserves

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effective December 31, 2019 which were prepared in accordance with standards of the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activitiesand is based on the average forecast prices as at December 31, 2019 of three independent reserves evaluation firms. Additional information regarding reserves data and other oil and gas information is included in Headwater's Annual Information Form for the year ended December 31, 2019, dated March 25, 2020, which is available on the Company's website at www.headwaterexp.comand under the Company's profile on The System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.

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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
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
Director Vermillion Energy Inc. and Topaz Energy Corp.		Vice President Engineering
Calgary, Alberta
PHILLIP KNOLL(3)		JON GRIMWOOD
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)		TED BROWN (Corporate Secretary)
Deputy Managing Partner, Azimuth Capital Management		Burnet, Duckworth & Palmer LLP
Calgary, Alberta
MARTIN FRASS-EHRFELD
Chairman AVE Capital Ltd.
London, United Kingdom
(1) Audit Committee
(2) Corporate Governance Committee
(3) Reserves Committee
Website: www.headwaterexp.com
		Head Office
		Suite 1700, 500 - 4thAvenue SW
		Calgary, Alberta T2P 2V6
		Tel: [phone]
		Auditors
		PricewaterhouseCoopers LLP
		Halifax, Nova Scotia
		Independent Reservoir Consultants
		GLJ Petroleum Consultants

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