Headwater Exploration : 2023 Year End MD&A

2023 Management's Discussion and Analysis

The following management's discussion and analysis ("MD&A") as provided by the management of Headwater Exploration Inc. ("Headwater" or the "Company") is dated March 7, 2024 and should be read in conjunction with the audited annual financial statements for the years ended December 31, 2023 and 2022 and the notes thereto. The audited annual financial statements have been prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board ("IFRS"). All dollar amounts are referenced in Canadian dollars unless otherwise stated. In addition, readers are also directed to the Company's Annual Information Form for the year ended December 31, 2023, dated March 7, 2024, which is available on the Company's website at www.headwaterexp.comand through SEDAR+ at www.sedarplus.ca.

Description of the Company

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

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

FOURTH QUARTER 2023 HIGHLIGHTS

• Achieved record average production of 19,939 boe/d (consisting of 18,514 bbls/d of heavy oil, 8.0 mmcf/d of natural gas and 93 bbls/d of natural gas liquids), an increase of 28% over 2022 fourth quarter production of 15,546 boe/d (1).
• Realized record adjusted funds flow from operations (2) of $82.0 million ($0.35 per basic share (3)), cash flows from operating activities of $90.7 million ($0.38 per basic share) and free cash flow (4) of $51.9 million.
• Achieved an operating netback, including financial derivatives, (3) of $49.07/boe and an adjusted funds flow netback (3) of $44.26/boe.
• Generated net income of $45.5 million ($0.19 per basic share) equating to $24.55/boe.
• Executed a $30.1 million capital expenditure (4) program including 13 net crude oil wells in Marten Hills West, at a 100% success rate.
• Returned $0.10 per common share to shareholders.
• As at December 31, 2023, Headwater had working capital of $78.6 million, adjusted working capital
  (2) of $63.5 million and no outstanding bank debt.

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YEAR ENDED DECEMBER 31, 2023 HIGHLIGHTS

• Returned a total of $0.40 per common share or $94.4 million to shareholders.
• Achieved average production of 18,038 boe/d (consisting of 16,466 bbls/d of heavy oil, 8.8 mmcf/d of natural gas and 98 bbls/d of natural gas liquids), an increase of 40% over 2022 annual production of 12,841 boe/d (1).
• Realized adjusted funds flow from operations (2) of $288.3 million ($1.22 per basic share (3)) and cash flows from operating activities of $303.3 million ($1.29 per basic share).
• Achieved an operating netback, including financial derivatives, (3) of $49.95/boe and an adjusted funds flow netback (3) of $43.78/boe.
• Generated net income of $156.1 million ($0.66 per basic share) equating to $23.71/boe.
• Executed a $233.8 million capital expenditure (4) program:

• • Drilled 71 net crude oil wells in Marten Hills West, at a 100% success rate, establishing Marten Hills West as the Company's largest producing area with production levels exceeding 10,500 bbls/d in the fourth quarter;
  • Drilled two successful Stingwray wells in Seal and Marten Hills West proving a new technology to increase reservoir exposure;
  • Brought 2.5 sections within Marten Hills Core and a pilot section within Marten Hills West under secondary recovery resulting in oil rate stabilization and reduced gas-oil-ratios; and
  • Headwater continued its pursuit of organic growth opportunities in and beyond the boundaries of the Clearwater acreage adding 198 net sections to the Corporation's land base in 2023.
• Executed a successful hedging strategy realizing $14.1 million in total hedging gains primarily related to natural gas hedging gains in McCully, validating Headwater's strategy of opportunistic hedging in this highly volatile gas market.
• Entered into an agreement to construct natural gas tie-in infrastructure in Marten Hills West. Once the $22.5 million project is completed, Headwater will be reimbursed for the construction costs and enter into a long-termtake-or-pay contract. The project will allow the Company to conserve a meaningful amount of its natural gas production in the area aligning with the Company's environment, social and governance ("ESG") strategy and significantly reducing Headwater's future carbon tax obligations.

1. 2022 fourth quarter production consisted of 13,536 bbls/d heavy oil, 11.5 mmcf/d natural gas and 99 bbls/d natural gas liquids. 2022 annual production consisted of 11,411 bbls/d heavy oil, 8.2 mmcf/d natural gas and 57 bbls/d natural gas liquids.
2. Capital management measure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation. Refer to "Management of capital" in note 16 of the audited annual financial statements and to "Non-GAAP and Other Financial Measures" within this MD&A.
3. Non-GAAPratio that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.
4. Non-GAAPfinancial measure that does not have any standardized meaning under IFRS and therefore may not be comparable with the calculation of similar measures of other entities. Refer to "Non-GAAP and Other Financial Measures" within this MD&A.

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Results of Operations

Production and Pricing

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
Average daily production
Heavy oil (bbls/d)	18,514	13,536	37	16,466	11,411	44
Natural gas (mmcf/d)	8.0	11.5	(30)	8.8	8.2	7
Natural gas liquids (bbls/d)	93	99	(6)	98	57	72
Barrels of oil equivalent (boe/d)	19,939	15,546	28	18,038	12,841	40
Average daily sales (boe/d) (1)
Heavy oil (bbls/d)	18,709	13,558	38	16,465	11,413	44
Natural gas (mmcf/d)	8.0	11.5	(30)	8.8	8.2	7
Natural gas liquids (bbls/d)	93	99	(6)	98	57	72
Barrels of oil equivalent (boe/d)	20,134	15,568	29	18,038	12,843	40
Headwater average sales price (2)
Heavy oil ($/bbl) (3)	74.69	73.10	2	77.67	94.79	(18)
Natural gas ($/mcf)	3.00	10.15	(70)	3.69	10.60	(65)
Natural gas liquids ($/bbl)	73.53	73.02	1	75.78	91.29	(17)
Barrels of oil equivalent ($/boe)	70.94	71.60	(1)	73.12	91.44	(20)
Average Benchmark Price
WTI (US$/bbl) (4)	78.32	82.64	(5)	77.62	94.23	(18)
WCS differential to WTI (US$/bbl)	(21.89)	(25.66)	(15)	(18.67)	(18.22)	2
WCS (Cdn$/bbl) (5)	76.96	77.42	(1)	79.56	98.52	(19)
Condensate at Edmonton (Cdn$/bbl)	102.83	111.82	(8)	102.11	123.20	(17)
AGT (US$/mmbtu) (6)	3.23	9.90	(67)	4.10	11.21	(63)
AECO 5A (Cdn$/GJ)	2.18	4.85	(55)	2.50	5.06	(51)
NYMEX Henry Hub (US$/mmbtu)	2.88	6.26	(54)	2.74	6.64	(59)
Exchange rate (Cdn$/US$)	0.73	0.74	(1)	0.74	0.77	(4)

1. Includes sales of heavy crude oil excluding the impact of purchased condensate and butane. The Company's heavy oil sales volumes and production volumes differ due to changes in inventory.
2. Average sales prices are calculated using average sales volumes.
3. Realized heavy oil prices are based on sales, net of blending expense.
4. WTI = West Texas Intermediate
5. WCS = Western Canadian Select
6. AGT = Algonquin city-gates. The AGT price is the average for the winter producing months in the McCully field which include January - April, November and December.

Sales

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Heavy oil sales	135,302	97,584	39	495,177	423,211	17
Blending expense	(6,736)	(6,403)	5	(28,411)	(28,332)	-
Heavy oil, net of blending (1)	128,566	91,181	41	466,766	394,879	18
Natural gas	2,207	10,706	(79)	11,921	31,876	(63)
Natural gas liquids	626	662	(5)	2,723	1,891	44
Gathering, processing and
transportation	291	425	(32)	1,413	1,401	1
Total sales, net of blending expense (1)	131,690	102,974	28	482,823	430,047	12

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

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Heavy Oil - Alberta

The Company's realized price received for its heavy crude oil is determined by the quality of crude compared to the benchmark price of WCS. Headwater's heavy crude oil production (average 18 - 22˚ API) is blended with diluent in order to meet pipeline transportation specifications.

WTI pricing trended lower during the year ended December 31, 2023, due to global recessionary risks, while the year ended December 31, 2022, saw a price risk premium due to international energy supply concerns associated with the Russia-Ukraine war. WTI pricing experienced some recovery in the third quarter of 2023 due to OPEC+ production cuts, but then pulled back in the fourth quarter of 2023 due to concerns related to market oversupply.

The WCS differential to WTI averaged comparably year over year, while the differential widened into the fourth quarter, from the first nine months of 2023, due to record supply out of Western Canada, pipeline apportionment and mild winter weather. Weaker WCS pricing is expected into 2024 until commissioning of the Trans Mountain pipeline expansion, which is anticipated to improve egress optionality for heavy crude oil out of Western Canada.

During the three months ended December 31, 2023, Headwater's heavy oil sales, net of blending expense, significantly increased to $128.6 million from $91.2 million in the corresponding period of the prior year. This increase was attributable to a 38% increase in heavy oil sales volumes, with commodity pricing remaining flat as lower WTI pricing was offset by a weaker Canadian dollar and the narrowing of the WCS differential to WTI in the quarter. During the year ended December 31, 2023, Headwater's heavy oil sales, net of blending expense, increased to $466.8 million from $394.9 million in the prior year. This increase was attributable to a 44% increase in heavy oil sales volumes, partially offset by an 18% decrease in realized commodity pricing, consistent with the decrease in benchmark WCS pricing.

For the three months and year ended December 31, 2023, Headwater's discount to WCS improved to $2.27/bbl and $1.89/bbl, respectively, from $4.32/bbl and $3.73/bbl, in the corresponding periods of 2022, due to blending optimization and stronger realized pricing relative to WCS.

During the three months and year ended December 31, 2023, Headwater's heavy oil sales volumes averaged 18,709 bbls/d and 16,465 bbls/d, respectively, compared to 13,558 bbls/d and 11,413 bbls/d in the corresponding periods of 2022. The Company's heavy oil sales volumes have increased significantly as a result of Headwater's extensive 2022 and 2023 capital expenditure programs. Headwater drilled 90.0 total net crude oil wells during the year ended December 31, 2023, and drilled 97.0 total net crude oil wells during the year ended December 31, 2022, substantially increasing the Company's heavy oil production.

Natural Gas - New Brunswick and Alberta

The Company produces natural gas out of the McCully field in New Brunswick. The transaction price is based on the AGT daily benchmark price adjusted for delivery location and heat content. Headwater also produces natural gas in Alberta, as the Company commissioned its Marten Hills joint gas processing facility and started generating sales from its associated natural gas production in the third quarter of 2021. The natural gas sales transaction price is based on the AECO 5A daily benchmark price adjusted for delivery location and heat content.

Both AGT and AECO 5A saw a significant decrease in pricing year over year due to increasing storage levels resulting from the current El Nino climate pattern. Natural gas inventories are currently at the top of the historical five-year average in both the northeastern United States and Western Canada.

For the three months ended December 31, 2023, Headwater's natural gas sales decreased to $2.2 million from $10.7 million in the corresponding period of the prior year, due to a 70% decrease in realized commodity pricing and a 30% decrease in natural gas sales volumes. For the year ended December 31, 2023, Headwater's natural gas sales decreased to $11.9 million from $31.9 million in the prior year due to

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a 65% decrease in realized commodity pricing partially offset by a 7% increase in natural gas sales volumes. Realized natural gas pricing decreased due to lower benchmark pricing for both AGT and AECO 5A.

During the three months ended December 31, 2023, Headwater's natural gas sales volumes decreased to

8.0 mmcf/d from 11.5 mmcf/d in the corresponding period of the prior year as a result of lower natural gas production out of both Marten Hills and McCully. Headwater realized declining natural gas production in the core area of Marten Hills, while a portion of McCully production was deferred into 2024 due to mild weather in December. Headwater's natural gas sales volumes were fairly consistent year over year.

Consistent with prior years, the Company shut-in McCully natural gas production for the summer season effective May 1, 2023 and resumed operations December 1, 2023, to take advantage of the AGT market's premium winter pricing.

Financial Derivatives Gains

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Realized gains	6,203	4,240	46	14,066	37	na
Unrealized gains	1,868	5,516	(66)	4,863	2,184	123
Financial derivative gains	8,071	9,756	(17)	18,929	2,221	752
Per boe	4.36	6.81	(36)	2.88	0.47	513

Natural gas and crude oil commodity contracts

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

The realized financial derivative gains recognized during the three months ended December 31, 2023, of $6.2 million compared to $4.2 million in the corresponding period of the prior year, represent primarily both the Company's McCully natural gas contracts referenced to the AGT price and its Marten Hills' heavy oil contracts referenced to the WCS differential to WTI. The Company recognized $3.1 million of gains on its AGT contracts during the three months ended December 31, 2023, as the commodity contracts to fix the AGT price exceeded the settlement price in the period. The settlement price was lower than expected due to weather-driven market oversupply of natural gas. Headwater recognized $3.0 million of gains on its WCS differential contracts during the three months ended December 31, 2023, as the commodity contracts to fix the WCS to WTI spread were more favorable than the settlement differential. The settlement differential was wider than expected due to record supply out of Western Canada, pipeline apportionment and mild winter weather.

The realized financial derivative gains recognized during the year ended December 31, 2023, primarily relate to Headwater's first quarter McCully natural gas contracts referenced to the AGT price, in addition to the fourth quarter gains previously mentioned. A realized financial derivative gain was recorded during the year ended December 31, 2023, of $14.1 million compared to a realized gain of $37 thousand in the prior year.

The unrealized gains recorded are a result of the change in fair value of the Company's outstanding financial derivative commodity contracts over the periods. As at December 31, 2023, the fair value of Headwater's outstanding financial derivative commodity contracts was a net unrealized asset of $3.7 million as reflected in the audited financial statements. The fair value or mark to market value of these contracts is based upon the estimated amount that would have been receivable/payable as at December 31, 2023, had the contracts

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been monetized or terminated. Subsequent changes in the fair value of the contracts are recognized in each reporting period and could be materially different than what is recorded as at December 31, 2023. For the three months and year ended December 31, 2023, Headwater recognized unrealized gains of $1.9 million and $4.9 million, respectively, compared to unrealized gains of $5.5 million and $2.2 million in the corresponding periods of 2022.

As at December 31, 2023, Headwater had the following financial derivative commodity contracts outstanding:

Commodity	Index	Type	Term	Daily Volume	Contract Price
Natural Gas	AGT	Fixed	Jan	2024	2,500 mmbtu	Cdn$18.95/mmbtu
Natural Gas	AGT	Fixed	Jan 2024	- Mar 2024	5,000 mmbtu	Cdn$16.98/mmbtu
Natural Gas	AECO 5A	Fixed	Apr 2024	- Oct 2024	1,000 GJ	Cdn$2.50/GJ
Natural Gas	WCS Basis	Differential	Apr 2024	- Jun 2024	1,000 bbl	US$15.95/bbl

Subsequent to December 31, 2023, the Company entered into additional financial derivative commodity contracts. Refer to the heading "Subsequent Events".

Foreign exchange contracts

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

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

As at December 31, 2023, Headwater had the following financial derivative foreign exchange contract outstanding:

	Buy	Sell
Type	Currency	Currency	Rate	Notional Amount	Settlement Date
			WMR noon rate,
Forward contract	CAD	USD	December 2023 average (1)	US$900,000	January 26, 2024

(1) WM/Reuters Intraday Spot Rate as of Noon EST

Subsequent to December 31, 2023, the Company entered into additional foreign exchange contracts. Refer to the heading "Subsequent Events".

Royalty Expense

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Total royalty expense	23,916	19,352	24	85,686	85,162	1
Percentage of total sales, net of	18.16%	18.80%	(3)	17.75%	19.80%	(10)
blending (1)
Per boe ($)	12.91	13.51	(4)	13.01	18.17	(28)

1. Non-GAAPratio. Refer to the advisory "Non-GAAP and Other Financial Measures".

Royalty expense consists of crown oil and natural gas royalties payable to the Alberta and New Brunswick provincial governments and the gross overriding royalty payable to Topaz Energy Corp. Under the Alberta

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Modernized Royalty Framework, the Company will pay a flat royalty of 5% on a well's production until the well's total revenue exceeds the drilling and completion cost allowance, then royalty rates increase on a sliding scale up to 40% depending on commodity reference pricing.

For the three months ended December 31, 2023, royalty expense increased to $23.9 million from $19.4 million in the corresponding period of 2022, representing an increase of 24% which is consistent with the increase in total sales (net of blending expense) over the period, of 28%. The royalty rate of 18.16% in the fourth quarter of 2023 is comparable with the royalty rate of 18.80% in the corresponding period of the prior year, as realized heavy oil commodity pricing was consistent over the same period.

Royalty expense of $85.7 million for the year ended December 31, 2023, is consistent with royalty expense of $85.2 million in the prior year. The increase in total sales (net of blending expense) year over year of 12% was offset by a decrease in the royalty rate of 10% over the same period. The decrease in royalty rate to 17.75% for the year ended December 31, 2023, from 19.80% in the prior year is relatively consistent with the decrease in realized heavy oil commodity pricing over the year.

Transportation Expense

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Transportation expense	9,493	6,025	58	35,196	20,067	75
Per boe ($)	5.12	4.21	22	5.35	4.28	25

Transportation expense includes clean oil trucking, terminal fees and pipeline tariffs incurred to move heavy crude oil production to the sales point.

For the three months and year ended December 31, 2023, transportation expense increased to $9.5 million and $35.2 million, respectively, from $6.0 million and $20.1 million in the corresponding periods of the prior year due to a significant increase in heavy oil sales volumes and higher trucking fees.

For the three months and year ended December 31, 2023, transportation expense per boe increased to $5.12 and $5.35, respectively, from $4.21 and $4.28 in the corresponding periods of the prior year. Downstream pipeline apportionment starting in early 2023 forced clean oil volumes, normally transported via pipeline, to be trucked out of the area resulting in higher transportation costs.

The Company expects transportation expense per boe to remain relatively flat into 2024. While Headwater expects additional pipeline capacity to reduce apportioned volumes going forward, an increase in clean oil volumes trucked out of the Company's newer areas is anticipated to offset the impact of lower apportionment.

Headwater has firm transportation service commitments in place to secure pipeline capacity to the point of sale. Refer to "Contractual Obligations and Commitments" for more information.

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Production Expense

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Production expense	13,602	8,954	52	47,227	27,814	70
Per boe ($)	7.34	6.25	17	7.17	5.93	21

For the three months and year ended December 31, 2023, production expense increased to $13.6 million and $47.2 million, respectively, from $9.0 million and $27.8 million in the corresponding periods of the prior year due to a significant increase in production volumes.

For the three months and year ended December 31, 2023, production expense per boe increased to $7.34 and $7.17, respectively, from $6.25 and $5.93 in the corresponding periods of the prior year. Increased costs were due to substantial growth in Marten Hills West and the development of new areas in Greater Peavine which carry higher operating costs than the initial development area of Marten Hills. Production out of Marten Hills West grew significantly to 10,605 bbls/d of heavy oil in the fourth quarter of 2023 from 2,408 bbls/d of heavy oil in the same period of the prior year driving an increase in emulsion and water hauling costs. Higher carbon taxes also contributed to increased production expense for both the three months and year ended December 31, 2023.

Netbacks

Operating netback reflects the Company's margin on a per-barrel of oil equivalent basis. The following table provides a reconciliation of Headwater's operating netback and operating netback, including financial derivatives. Refer to the heading "Non-GAAP and Other Financial Measures" for more information.

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	($/boe)			($/boe)
Sales	74.73	76.37	(2)	77.65	97.78	(21)
Royalties	(12.91)	(13.51)	(4)	(13.01)	(18.17)	(28)
Transportation and blending	(8.76)	(8.68)	1	(9.66)	(10.32)	(6)
Production expense	(7.34)	(6.25)	17	(7.17)	(5.93)	21
Operating netback (1)	45.72	47.93	(5)	47.81	63.36	(25)
Realized gains on financial derivatives	3.35	2.96	13	2.14	0.01	na
Operating netback, including financial
derivatives (1)	49.07	50.89	(4)	49.95	63.37	(21)

1. Non-GAAPratio. Refer to the advisory "Non-GAAP and Other Financial Measures".

For the three months ended December 31, 2023, the Company recorded an operating netback, including financial derivatives of $49.07 per boe, which is consistent with the Company's operating netback, including financials derivatives of $50.89 per boe in the corresponding period of 2022. Higher production expense on a per boe basis was offset by higher realized gains on financial derivatives, while realized heavy oil pricing was comparable over the periods.

For the year ended December 31, 2023, the Company recorded a lower operating netback, including financial derivatives of $49.95 per boe compared to $63.37 per boe in the prior year, primarily as a result of lower realized commodity pricing and higher production expense per boe partially offset by lower royalties per boe and higher realized gains on financial derivatives driven by lower commodity pricing.

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General and Administrative ("G&A") Expenses

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Gross G&A expenses	3,905	2,251	73	13,479	9,662	40
Capitalized G&A	(1,116)	(617)	81	(3,804)	(3,187)	19
Net G&A expenses	2,789	1,634	71	9,675	6,475	49
Per boe ($)	1.51	1.14	32	1.47	1.38	7

For the three months and year ended December 31, 2023, net G&A expenses increased to $2.8 million and $9.7 million, respectively, from $1.6 million and $6.5 million in the corresponding periods of 2022. Increased net G&A expenses on an absolute and per boe basis were mainly a result of increased employee related costs and professional fees due to the significant growth experienced by the Company over the periods.

Interest Income and Other Expense

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Interest income	1,633	1,833	(11)	6,519	3,844	70
Foreign exchange gains (losses)	166	205	(19)	(354)	(538)	(34)
Accretion on decommissioning liability	(361)	(225)	60	(1,183)	(709)	67
Interest on repayable contribution	(128)	(32)	300	(490)	(106)	362
Interest on lease liability	(16)	(17)	(6)	(49)	(74)	(34)
Total interest income and other
expense	1,294	1,764	(27)	4,443	2,417	84
Per boe ($)	0.70	1.23	(43)	0.67	0.52	29

For both the three months and year ended December 31, 2023, Headwater generated significant interest income as a result of increasing interest rates in combination with carrying a large cash balance. This passive income was partially offset by realized and unrealized foreign exchange losses, accretion on the decommissioning liability and interest on repayable contribution and lease liability.

The increase in interest income to $6.5 million for the year ended December 31, 2023, from $3.8 million in the prior year, is a result of increasing interest rates. The current year opened with the prime rate at 6.45%, increasing to 7.20% mid-year where it held for the remainder of 2023, compared to entering 2022 with a prime rate of 2.45% and exiting the year at 6.45%. Interest income for the three months ended December 31, 2023, of $1.6 million is fairly consistent with interest income of $1.8 million in the corresponding period of the prior year.

The Company manages fluctuations in foreign exchange gains and losses by entering into foreign exchange contracts to fix the foreign exchange rate. Refer to "Financial Derivatives Gains" for more information.

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Stock-based Compensation

	Three months ended		Year ended
	December 31,	Percent	December 31,	Percent
	2023	2022	Change	2023	2022	Change
	(thousands of dollars)		(thousands of dollars)
Stock options	249	635	(61)	1,280	2,883	(56)
Deferred share units	(161)	138	(217)	916	629	46
Share awards	1,283	670	91	4,748	2,102	126
Capitalized stock-based compensation	(469)	(369)	27	(1,704)	(1,529)	11
Stock-based compensation expense	902	1,074	(16)	5,240	4,085	28
Per boe ($)	0.49	0.75	(35)	0.80	0.87	(8)

During the three months ended December 31, 2023, stock-based compensation expense decreased to $0.9 million from $1.1 million in the corresponding period of 2022, as a result of lower expense associated with deferred share units ("DSUs") and restricted share units ("RSUs") due to the Company's share price decreasing to $6.25 at December 31, 2023, from $7.16 at September 30, 2023. The expense for stock options was also lower due to the majority of outstanding stock options being fully vested.

During the year ended December 31, 2023, stock-based compensation expense increased to $5.2 million from $4.1 million in the prior year, primarily due to grants of RSUs and performance share units ("PSUs" and collectively with the RSUs, the "Awards") under the Company's incentive awards plan (the "Award Plan") and grants of DSUs under the Company's DSU plan (the "DSU Plan").

Share Awards

The Award Plan provides for the grant of RSUs and PSUs to officers, employees and consultants of the Company. Under the Award Plan, the aggregate number of common shares reserved for issuance may not exceed the lesser of: (i) 6.0% of the aggregate number of issued and outstanding common shares less the aggregate number of common shares reserved for issuance under the Company's stock option plans; and (ii) 4.5% of the aggregate number of issued and outstanding common shares. Generally, one third of the RSUs will vest on each of the first, second and third anniversaries of the date of grant and all PSUs will vest on the third anniversary of the date of grant, unless otherwise determined by the Board of Directors of the Company (the "Board"). The common shares underlying PSUs are adjusted based on a performance multiplier ranging from 0 to 2 times, which is determined based on certain corporate performance measures, as determined by the Board.

During the year ended December 31, 2023, the Board approved the cash settlement of RSUs. Previously, these Awards had been accounted for as equity-settled. As a result of this modification to the Company's outstanding RSUs from equity-settled to cash-settled, the fair value of the awards previously expensed was reclassified from contributed surplus to stock-based compensation payable. Subsequent to this modification, the grant date fair value is used to record the cost of the RSUs and any subsequent remeasurement of the liability is also recognized in the Statement of Income and Comprehensive Income.

It is the intention of the Company to equity settle any outstanding PSUs. The Award Plan allows a holder to receive common shares upon vesting. Headwater uses the fair value method for valuing the PSUs. The fair value of PSUs is determined based on the volume weighted average trading price of the five days preceding the grant date. This fair value is recognized as stock-based compensation expense, with a portion being capitalized, over the vesting period with a corresponding increase to contributed surplus. The amount of stock-based compensation expense is reduced by an estimated forfeiture rate determined at the date of the grant and updated each period. Upon vesting of the PSUs and settlement in common shares, the previously recognized value in contributed surplus will be recorded as an increase to capital stock.

As at December 31, 2023, there were 376,563 RSUs outstanding and 1,917,474 PSUs outstanding.

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