Tamarack Valley Energy : 2024 Q1 Financial Report

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") provides a review of the operations, financial results and outlook for Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") for the three months ended March 31, 2024 and 2023. This MD&A is dated as at May 7, 2024 and should be read in conjunction with the unaudited condensed interim consolidated financial statements for the three months ended March 31, 2024 and 2023 ("Interim Financial Statements") and the audited consolidated financial statements for the year ended December 31, 2023. Additional information relating to Tamarack, including the Company's Annual Information Form for the year ended December 31, 2023, is available on SEDAR+ at www.sedarplus.ca and Tamarack's website at www.tamarackvalley.ca.

The Company uses certain Non-GAAP Financial Measures, Non-GAAP Financial Ratios, Capital Management Measures and Capital Management Ratios in this MD&A. Certain Supplemental Financial Measures are also presented on a per boe, per share or on a percentage basis. For additional information regarding these measures, refer to the "Advisories and guidance" section of this MD&A. Unless otherwise indicated, all references to dollar amounts are in Canadian ("CAD") currency.

About Tamarack Valley Energy Ltd.

Tamarack is a corporation engaged in the sustainable exploration, development, production and sale of oil and natural gas in the Western Canadian Sedimentary Basin. The Company is currently developing two core projects in Northern Alberta - a Clearwater heavy oil position at Nipisi, Marten Hills and South Clearwater and a Charlie Lake light oil position at Valhalla, Wembley and Pipestone. Tamarack also manages an EOR portfolio of diverse assets across Alberta. The Company is committed to the advancement of ESG practices, including GHG emissions management and partnerships with local communities.

As of December 31, 2023, the Company held over 650 sections of acreage across the Clearwater fairway with 112.5 million boe of total gross proved plus probable reserves(1). The Clearwater formations are characterized by strong economics supported by a low cost structure, low production declines and multiple payouts on initial investment. The formation also has enhanced recovery potential. Tamarack produced over 38,000 boe per day of heavy oil and natural gas from Clearwater in the first quarter of 2024.

Tamarack holds over 250 sections of Charlie Lake acreage with 67.4 million boe of total gross proved plus probable reserves(1) providing the Company with extensive light oil development opportunities through multi-well pad drilling with extended horizontal reach. The Charlie Lake formations are characterized by short payout periods and low break-even economics. The Company produced over 15,000 boe per day of oil and natural gas from Charlie Lake in the first quarter of 2024.

Tamarack has 103 employees at the corporate head office and eight employees at field level operations. The Company is incorporated and domiciled in Alberta, Canada with the head office located at Suite 1700, 525 - 8th Avenue S.W., Calgary, Alberta, T2P 1G1. Tamarack is a publicly traded company on the Toronto Stock Exchange ("TSX") and is traded under the symbol "TVE".

Q1 2024 in review

Tamarack delivered strong results in the first quarter of 2024 generating free funds flow(2) of $53.3 million, underpinned by steady production of 62,022 boe/d, robust heavy oil price realizations and capital discipline. These operational results allowed the Company to execute its capital management strategy of reducing net debt and growing shareholder returns. In Q1, Tamarack delivered $46.4 million to shareholders through base dividends and share buybacks. The Company also repaid the remaining balance of the DAP Notes and Term Facility, two instruments that were issued to help fund the Company's transformative acquisitions in 2022. In May 2024, the Company also amended the SLL Facility to extend the tenure and add an uncommitted accordion for $125.0 million.

1. Based upon the independent reserves evaluations conducted by McDaniel & Associates Consultants Ltd. ("McDaniel") and GLJ Ltd. ("GLJ"), as at December 31, 2023. Refer to "Advisories and guidance" for additional information about the independent reserves evaluations conducted by McDaniel and GLJ.
2. Refer to "Advisories and guidance" for more information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

1

Q1 2024 operational and financial highlights

				Three months ended
			March 31,			December 31,
		2024		2023	% change		2023	% change
($ thousands, except per share amounts)
Oil and natural gas sales, before blending expense	$	393,336	$	378,546	4	$	418,864	(6)
Cash provided by operating activities		165,201		59,624	177		215,981	(24)
Per share - basic		0.30		0.11	173		0.39	(23)
Per share - diluted		0.30		0.11	173		0.39	(23)
Adjusted funds flow(1)		181,556		157,271	15		194,771	(7)
Per share - basic(1)		0.33		0.28	18		0.35	(6)
Per share - diluted(1)		0.33		0.28	18		0.35	(6)
Free funds flow(1)		53,335		9,109	486		67,067	(20)
Per share - basic(1)		0.10		0.02	490		0.12	(20)
Per share - diluted(1)		0.10		0.02	491		0.12	(20)
Net income (loss)		(32,744)		2,505	nm		57,322	nm
Per share - basic		(0.06)		-	nm		0.10	nm
Per share - diluted		(0.06)		-	nm		0.10	nm
Net debt(1)		984,768		1,374,068	(28)		983,585	0
Investments in oil and natural gas assets		128,221		148,162	(13)		127,704	0
Weighted average shares outstanding (thousands)
Basic		552,345		556,548	(1)		556,699	(1)
Diluted		555,595		560,503	(1)		560,008	(1)
Average daily production
Heavy oil (bbls/d)		36,255		34,399	5		37,447	(3)
Light oil (bbls/d)		15,270		17,035	(10)		14,928	2
NGL (bbls/d)		1,925		4,122	(53)		2,769	(30)
Natural gas (mcf/d)		51,431		74,293	(31)		58,419	(12)
Total (boe/d)		62,022		67,938	(9)		64,881	(4)
Average sale prices
Heavy oil, net of blending expense ($/bbl)(1)	$	75.75	$	61.60	23	$	74.09	2
Light oil ($/bbl)		86.52		94.97	(9)		99.79	(13)
NGL ($/bbl)		42.54		45.91	(7)		42.31	1
Natural gas ($/mcf)		2.93		3.50	(16)		2.82	4
Total ($/boe)		69.34		61.61	13		70.07	(1)
Benchmark pricing
West Texas Intermediate (US$/bbl)		76.96		76.13	1		78.32	(2)
Western Canadian Select (WCS/Hardisty Heavy) (Cdn$/bbl)		77.77		69.30	12		76.96	1
WCS differential (US$/bbl)		19.31		24.88	(22)		21.89	(12)
Edmonton Par (Cdn$/bbl)		92.15		99.01	(7)		99.69	(8)
Edmonton Par differential (US$/bbl)		8.65		2.88	200		5.19	67
Foreign Exchange (USD to CAD)		1.35		1.35	-		1.36	(1)
Operating netback ($/Boe)
Realized sales price, net of blending(1)		69.34		61.61	13		70.07	(1)
Royalty expenses		(13.46)		(11.99)	12		(13.81)	3
Net production expenses(1)		(9.43)		(10.49)	(10)		(8.89)	(6)
Transportation expenses		(4.18)		(3.90)	7		(3.56)	(17)
Carbon tax		(0.62)		-	nm		(2.53)	nm
Operating field netback ($/Boe)(1)		41.65		35.23	18		41.28	1
Realized commodity hedging gain (loss)		0.37		(1.06)	(135)		0.80	(54)
Operating netback ($/Boe)(1)	$	42.02	$	34.17	23	$	42.08	(0)
Adjusted funds flow ($/Boe)(1)	$	32.17	$	25.72	25	$	32.63	(1)

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

2

Highlights for the three months ended March 31, 2024

Production - Production in the first quarter of 2024 averaged 62,022 boe per day. The 9% quarter-over-quarter decline in production compared to Q1 2023 was primarily due to the non-core Cardium asset disposition in November 2023, partially offset by new production from ongoing drilling and development activities in both the Clearwater and Charlie Lake. The Company's oil and liquids weighting also grew to 86% compared to 82%. Highlights of the first quarter program included strong well rates in West Nipisi and West Marten Hills along with encouraging activity in the Charlie Lake which included two wells brought on stream at Wembley that exhibited the highest oil rates relative to other Charlie Lake oil wells.

Realizations - Tamarack has continued to attain higher margins through improved heavy oil price realizations from ongoing marketing initiatives and an improved commodity price environment. In the first quarter of 2024, the Company's heavy oil price differential, net of transportation expenses(1) relative to the Hardisty Heavy benchmark price was $6.34 per boe, compared to the first quarter 2023 differential of $13.49 per boe, reflecting a 53% quarter-over-quarter improvement. Higher realized heavy oil prices were primarily due to improved netbacks resulting from the Nipisi pipeline and blending terminal as well as optimized sales points for trucked heavy oil production. Overall, the Company's average realized price of $69.34 per boe in the first quarter of 2024 improved by 13% compared the same period in the prior year, primarily due to the higher commodity prices and improved heavy oil differentials. The Company expects heavy oil differentials to continue to narrow as the TMX oil pipeline ramps up in Q2 2024.

Cash Flows - Tamarack delivered cash provided by operating activities of $165.2 million during the three months ended March 31, 2024. The Company also delivered first quarter adjusted funds flow(1) of $181.6 million supported by strong benchmark commodity prices and heavy oil price realizations and was primarily utilized to fund the Company's winter drilling and development program and return capital to shareholders. Tamarack's free funds flow(1) of $53.3 million in Q1 2024 reflects a $44.2 million improvement compared to the same quarter in the prior year.

Investments in Oil and Natural Gas Assets - Tamarack invested $128.2 million in Q1 2024 for ongoing development of the Clearwater and Charlie Lake plays. The Company's first quarter winter drilling program included 32.9 net Clearwater heavy oil wells and 5.4 net Charlie Lake light oil wells. Capital investments also included $7.3 million of gas conservation projects for the Clearwater Infrastructure Partnership. These targeted infrastructure investments have facilitated production growth, net production expense(1) reductions and the increased abatement of greenhouse gas emissions. Upon completion of these projects, Tamarack is entitled to the remaining proceeds from the Clearwater Infrastructure Partnership formation of $15.0 million, which is currently held in a trust subject to the completion of the projects.

Debt Renewal - During the first quarter of 2024, the Company repaid its Term Facility and DAP Notes which was primarily funded utilizing available capacity under the Company's SLL Facility. Repayment of these instruments has eased covenant restrictions under the Company's Syndicated Credit Facility and reduced Tamarack's average borrowing costs for the remainder of the year. In May 2024, Tamarack also amended the SLL Facility primarily to extend the maturity date by one year to 2027 and to add an uncommitted accordion feature that provides the Company with the ability to access an incremental $125.0 million of secured debt subject to certain conditions, including syndicate approval for a total potential capacity of $1.0 billion. As at March 31, 2024, Tamarack had undrawn capacity of $227.6 million under the Company's $875.0 million revolving credit facility.

Shareholder Returns - The Company exited 2023 having reduced net debt by $373.0 million in the year and achieving its first debt threshold within its pre-established return of capital framework. In response, Tamarack accelerated its enhanced return initiative by renewing its normal course issuer bid, with TSX approvals received in January 2024 to reacquire up to 54.6 million common shares until January 18, 2025. During the first quarter of 2024, the Company purchased and cancelled 7.6 million common shares for $25.6 million. Tamarack also declared base dividends to shareholders of $20.7 million ($0.0375 per share). Since 2022, Tamarack has now returned over $185.0 million to shareholders in the form of dividends and share buybacks.

Third-party facility service interruption

In early April, there was an unplanned service disruption at a third-party gas plant at Mitsue, Alberta that processes Tamarack's solution gas from various batteries in the Nipisi area. Due to flaring limitations set by the Alberta Energy Regulator, Tamarack temporarily shut-in approximately 6,200 boe per day of production. The Company is in the process of implementing several strategies to restore the majority of the production back on-stream ahead of the operator returning the facility to operation. As of May 7, 2024, the Company has been able to restore all but 1,050 - 1,250 boe per day of production (60% natural gas). The Company's full-year guidance remains unchanged with average production of 61,000 - 63,000 boe per day.

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

3

Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

Annual guidance

2024 Outlook	Guidance	Presentation	Revised guidance
	(Feb. 27, 2024)	change	(May 7, 2024)
For the year ended December 31	2024		2024
Capital investments ($ millions)(1)	390 - 440	-	390 - 440
Annual average production (boe/d)	61,000 - 63,000	-	61,000 - 63,000
Average oil & NGL weighting (%)	84 - 86	-	84 - 86
Royalty rate (%)	20 - 22	-	20 - 22
Corporate wellhead price differential - Oil	2.50 - 3.50	(0.50)	2.00 - 3.00
Net production ($/boe)(2)	8.75 - 9.25	-	8.75 - 9.25
Transportation ($/boe)	3.25 - 3.60	0.50	3.75 - 4.10
Carbon tax ($/boe)	0.50 - 1.00	-	0.50 - 1.00
General and administrative ($/boe)	1.35 - 1.50	-	1.35 - 1.50
Interest ($/boe)	3.80 - 4.20	-	3.80 - 4.20
Income taxes (% of Adjusted Funds flow)	9 - 11	-	9 - 11

1. Capital investments reflected in the table above reflects Tamarack's base 2024 budget and excludes the impact of the incremental CSV Albright expansion budget of $40 - $50 million. Amounts also exclude decommissioning obligation expenditures, acquisitions and dispositions and Clearwater Infrastructure Partnership gas conservation projects.
2. Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

Including the anticipated impact of the non-core Redwater disposition and third-party Mitsue gas processing facility service interruptions in April, the Company's full-year guidance remains unchanged with average production of 61,000 - 63,000 boe per day. Based on discussions with the counterparty and Tamarack's ongoing mitigation efforts to divert restricted volumes from the affected third-party facility, the Company currently anticipates being able to maintain annual production guidance, which is subject to change and dependent upon, among other things, certain regulatory approvals, successful execution of these ongoing mitigation initiatives and execution of the remaining 2024 capital program.

First quarter net production expenses on a per boe basis exceeded the annual guidance primarily due to seasonality and inclement weather. Production expense guidance for the full year remains unchanged. The Company's transportation expense guidance was increased by $0.50 per boe to reflect the Nipisi heavy oil transportation contract as a gross transportation expense rather than reduction of the realized heavy oil wellhead price. The revised guidance format does not impact Tamarack's operating netbacks or cash flows for the year ended December 31, 2024 as the update reflects an offsetting reclass between the Company's revenues and transportation expenses.

4

Tamarack's capital guidance balances maximizing free funds flow generation with a significant amount being directed towards shareholder returns. The Company's capital investments guidance is maintained at $390 - $440 million focused primarily on Clearwater and Charlie Lake drilling and development activities. 2024 investments include secondary recovery expansion of Clearwater waterflood projects at Nipisi and Marten Hills. Other capital projects consist of infrastructure expansions in the Clearwater area to support ongoing production growth and emissions reduction initiatives. The Company anticipates G&A costs for the full year to be within the guidance range of $1.35-$1.50.

Production

	Three months ended
March 31	2024	2023	% change
Production
Heavy oil (bbls/d)	36,255	34,399	5
Light oil (bbls/d)	15,270	17,035	(10)
Natural gas liquids (bbls/d)	1,925	4,122	(53)
Natural gas (mcf/d)	51,431	74,293	(31)
Total (boe/d)	62,022	67,938	(9)
Total (boe)	5,644,033	6,114,404	(8)
Percentage of oil and NGLs	86%	82%	5

Tamarack's production in the first quarter of 2024 decreased 9% compared to the same period in 2023, primarily due to the disposition of the non-core Cardium assets in the fourth quarter of 2023 and base declines, partially offset by higher production from the Company's ongoing drilling and development programs. The Company's oil and NGL weighting for the three months ended March 31, 2024 increased by 5% compared to the same period in 2023, primarily due to the dispositions in Q4 2023 and Q1 2024.

Petroleum and natural gas sales

($ thousands, except per unit)		Three months ended
March 31		2024		2023	% change
Revenue
Heavy oil, net of blending expense(1)	$	249,926	$	190,693	31
Light oil		120,223		145,613	(17)
Natural gas		13,728		23,382	(41)
Natural gas liquids		7,454		17,032	(56)
Total, net of blending expense(1)	$	391,331	$	376,720	4
Average realized price:
Heavy oil, net of blending expense ($/bbl)(1)	$	75.75	$	61.60	23
Light oil ($/bbl)		86.52		94.97	(9)
Natural gas ($/mcf)		2.93		3.50	(16)
Natural gas liquids ($/bbl)		42.54		45.91	(7)
Combined average oil and NGL ($/boe)		77.63		70.67	10
Revenue, net of blending expense ($/boe)(1)	$	69.34	$	61.61	13

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

For the three months ended March 31, 2024, revenues increased by $14.6 million compared to the same period in 2023, due to higher realized prices of $47.2 million, partially offset by lower production of $32.6 million. The Company's realized price improved by 13% in the first quarter of 2024 compared the same period in the prior year, primarily due to improved benchmark commodity prices and heavy oil differentials.

5

		Three months ended
March 31		2024		2023	% change
Benchmark pricing
West Texas Intermediate (US$/bbl)	$	76.96	$	76.13	1
Western Canadian Select (WCS/Hardisty Heavy) (Cdn$/bbl)		77.77		69.30	12
WCS differential, relative to WTI (US$/bbl)		19.31		24.88	(22)
Edmonton Par (light sweet) (Cdn$/bbl)		92.15		99.01	(7)
Edmonton Par differential, relative to WTI (US$/bbl)		8.65		2.88	200
NYMEX monthly settlement (US$/mmbtu)		2.24		3.42	(35)
AECO daily index (Cdn$/mcf)		2.48		3.20	(23)
AECO monthly index (Cdn$/mcf)	$	2.04	$	4.32	(53)
Foreign exchange (USD to CAD)		1.35		1.35	(0)

The price of West Texas Intermediate ("WTI") for crude oil sales at Cushing, Oklahoma is the primary benchmark for crude oil pricing in North America. The differential price between Western Canadian crude and WTI is impacted by multiple factors including domestic production, inventory levels, pipeline capacity, US refinery intake capacity and storage constraints in Canada. The price that Tamarack receives for the sale of its crude oil is discounted for delivery points in Alberta and also adjusted for quality based on the density of the oil relative to the quoted benchmark.

During the three months ended March 31, 2024, the WTI benchmark price remained relatively flat, compared to the same period in 2023, as commodity price pressures stemming from supply disruptions due to ongoing regional conflicts in Ukraine and the middle east, persistent production restrictions imposed by OPEC+ and replenishments of the US strategic oil reserve, were mostly offset by growth in North American production, quarter-over-quarter.

				Three months ended
March 31		2024		2023		$/bbl change	% change
Heavy oil wellhead price realization ($/bbl)
Hardisty Heavy benchmark price	$	77.77	$	69.30	$	8.47	12
Less: Tamarack's heavy oil realized price, net of blending		(75.75)		(61.60)		(14.15)	23
Heavy oil wellhead price differential(1)	$	2.02	$	7.70	$	(5.68)	(74)
Add: Transportation expenses - heavy oil		4.32		5.79		(1.47)	(25)
Heavy oil differential, including transportation expenses(1)	$	6.34	$	13.49	$	(7.15)	(53)
Light oil wellhead price realization ($/bbl)
Edmonton Par benchmark price	$	92.15	$	99.01	$	(6.86)	(7)
Less: Tamarack's light oil realized price		(86.52)		(94.97)		8.45	(9)
Light oil wellhead price differential(1)		5.63		4.04		1.59	39
Add: Transportation expenses - light oil		4.86		2.08		2.78	133
Light oil differential, including transportation expenses(1)	$	10.49	$	6.12	$	4.37	71

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

Tamarack has continued to drive higher margins through improved heavy oil price realizations from ongoing marketing initiatives and an improved commodity price environment. During the first quarter of 2024, the Company's heavy oil differential including transportation expenses improved by 53% compared to the first quarter of 2023, primarily due to improved netbacks resulting from the commencement of new oil transportation contracts on the Nipisi pipeline and blending terminal as well as optimized sales points for trucked heavy oil production.

During the first quarter of 2024, Tamarack's realized light oil prices were relatively consistent with the decline in light oil benchmark commodity prices. Relative to the WTI benchmark price, the Edmonton Par light oil differential widened by 200% compared to the same period in 2023, primarily due to a surplus in supply of light sweet at Edmonton, unplanned refinery outages and higher than normal pipeline apportionment.

In the first quarter of 2024, the Company's light oil differential including transportation expenses widened by 71% compared to the same period in the prior year, due to pipeline adjustments in the first quarter. The Company expects light oil differentials to improve in the second quarter of 2024.

6

Risk management

($ thousands, except per boe)		Three months ended
March 31		2024		2023
Realized gain (loss)	$	2,080	$	(6,504)
Unrealized loss		(55,590)		(2,349)
Total risk management contracts	$	(53,510)	$	(8,853)
Realized gain (loss) ($/boe)	$	0.37	$	(1.06)

Changes in crude oil benchmarks and price differentials can have a significant impact on Tamarack's oil and natural gas sales, cash provided by operating activities and adjusted funds flow. Tamarack enters into risk management contracts on a prudent, non- speculative basis in order to reduce liquidity risk and stabilize near-term cash flows which allows the Company to fund capital investment programs, net debt reduction and the return of capital to shareholders.

Risk management instruments are measured at their estimated fair market value at each reporting period. An unrealized gain on commodity risk management contracts reflects a non-cash increase in value resulting from a decline in future estimated commodity prices relative to Tamarack's contract positions. A realized commodity risk management contract gain generally reflects the actual cash settlement of the Company's fixed price position relative to a lower actual underlying market price at the maturity date. Realized and unrealized losses generally result from increases in actual and future estimated commodity prices, respectively.

As at March 31, 2024, Tamarack's outstanding risk management contracts had a net liability value of $22.2 million (December 31, 2023 - $30.7 million net asset). Tamarack's derivative contracts can be found in note 6 of the Interim Financial Statements.

Royalties

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
Royalty expenses	$	75,969	$	73,292	4
$/boe		13.46		11.99	12
Percentage of sales, net of blending (%)		19		19	-

Royalties as a percentage of sales, net of blending expense, for the three months ended March 31, 2024 was consistent with the same period in the prior year. Gross royalty expense increased by 4% in the first quarter of 2024, compared to the same period in 2023, due to higher commodity prices partially offset by lower production.

Net production expenses

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
Production expenses	$	54,940	$	65,040	(16)
Less: processing income		(1,701)		(909)	87
Total net production expenses(1)	$	53,239	$	64,131	(17)
Total ($/boe)(1)	$	9.43	$	10.49	(10)

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

For the three months ended March 31, 2024, per unit net production expenses declined by 10% compared to the same period in 2023, primarily due to the new gas-gathering facilities brought on-line in the second half of 2023, the commissioning of the Wembley gas plant at Charlie Lake and the realization of synergies across the Clearwater asset areas at Nipisi and Marten Hills.

Transportation expenses

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
Transportation expense - oil	$	21,006	$	21,128	(1)
Transportation expense - gas		2,571		2,710	(5)
Total transportation expenses	$	23,577	$	23,838	(1)
Total ($/boe)	$	4.18	$	3.90	7

1. Pipeline tariffs are generally classified as transportation expenses when the Company has firm commitments or contractual arrangements on the pipeline. Pipeline tariffs may also be included indirectly as a deduction from the base price paid by a purchaser of Tamarack's oil, NGL and gas sales. In the latter case, the tariffs are reflected as a reduction of revenue rather than a transportation expense.

7

For the three months ended March 31, 2024, oil transportation expenses were relatively flat compared to the same period in 2023, as lower transportation expenses incurred from the start-up of the Secure-Pembina Nipisi pipeline and lower production volumes were mostly offset by the impacts of new pipeline transportation contracts. Transportation expenses for natural gas declined by 5% during the three months ended March 31, 2024, compared to the same period in the prior year, primarily due to lower natural gas production following the disposition of the non-core Cardium assets.

On a per boe basis, transportation expenses increased by 7% in the first quarter of 2024, primarily due to lower production and the impact of new oil pipeline transportation contracts. The Company's transportation expense increased by approximately $0.50 per boe due to the commencement of a Nipisi heavy oil transportation contract (reflected as gross transportation expense instead of a revenue deduct). These transportation contracts have contributed to improved heavy oil price realizations in the first quarter of 2024 with the heavy differential, including transportation expenses declining by 53%, quarter-over-quarter (refer to the "Petroleum and natural gas sales" section for further details).

Operating netback

($/boe)		Three months ended
March 31		2024		2023	% change
Realized sales price, net of blend expense(1)	$	69.34	$	61.61	13
Royalty expenses		(13.46)		(11.99)	12
Net production expenses(1)		(9.43)		(10.49)	(10)
Transportation expenses		(4.18)		(3.90)	7
Carbon tax		(0.62)		-	nm
Operating field netback(1)	$	41.65	$	35.23	18
Realized hedging gain (loss)		0.37		(1.06)	(135)
Operating netback(1)	$	42.02	$	34.17	23
($ thousands)		Three months ended
March 31		2024		2023	% change
Realized sales price, net of blend expense(1)	$	391,331	$	376,720	4
Royalty expenses		(75,969)		(73,292)	4
Net production expenses(1)		(53,239)		(64,129)	(17)
Transportation expenses		(23,577)		(23,838)	(1)
Carbon tax		(3,525)		-	nm
Operating field netback(1)	$	235,021	$	215,461	9
Realized hedging gain (loss)		2,080		(6,504)	(132)
Operating netback(1)	$	237,101	$	208,957	13

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

For the three months ended March 31, 2024, the operating netback per boe increased by 23% compared to the same period in 2023 primarily due to a higher heavy oil commodity price and lower net production expenses partially offset by higher royalties, transportation expenses and carbon taxes.

The operating netback for the three months ended March 31, 2024 increased 13% compared to the same period in 2023 due to higher heavy oil commodity prices and lower net production expenses partially offset by lower production and carbon taxes.

General and administrative ("G&A") expenses

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
G&A costs	$	12,319	$	10,602	16
Less: capitalized costs and recoveries		(3,352)		(2,803)	20
G&A expenses	$	8,967	$	7,799	15
Total ($/boe)	$	1.59	$	1.28	24

For the three months ended March 31, 2024, G&A costs per boe increased by 24% compared to the same period in 2023, primarily due to higher legal and other expenses in the first quarter. G&A guidance for the year remains unchanged.

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Stock-based compensation expense

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
Equity-settled plans	$	2,703	$	2,404	12
Cash-settled plans		3,846		1,685	128
Stock-based compensation costs		6,549		4,089	60
Less: capitalized costs		(2,007)		(1,303)	54
Stock-based compensation expense	$	4,542	$	2,786	63
Total ($/boe)	$	0.80	$	0.46	74

Stock-based compensation expense for the three months ended March 31, 2024, increased by 63% compared to the same period in 2023, primarily due to new grants issued in the first quarter, higher staff counts and an increase in Tamarack's share price.

Finance expense

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
Syndicated Facility	$	12,186	$	13,065	(7)
SL Notes		5,423		5,364	1
Clearwater infrastructure liability		3,596		-	nm
DAP Notes		792		3,679	(78)
Other interest and fees		156		2,132	(93)
Cash interest expense	$	22,153	$	24,240	(9)
Deferred borrowing costs and loan accretion		2,098		1,860	13
Unrealized foreign exchange loss (gain) on debt		2,690		(8,810)	(131)
Unrealized loss (gain) on cross-currency swaps		(2,699)		8,242	(133)
Accretion of decommissioning obligations		1,672		2,253	(26)
Finance expense	$	25,914	$	27,785	(7)
Total finance expense ($/boe)		4.59		4.54	1
Total cash interest expense ($/boe)		3.93		3.96	(1)
Average draw on Syndicated Facility	$	631,951	$	717,690	(12)
Average outstanding SL Notes	$	300,000	$	300,000	-
Average outstanding DAP Notes	$	56,667	$	256,111	(78)

For the three months ended March 31, 2024, cash interest expense decreased by 9% compared to the same period in the prior year, primarily due to the lower average balances of the Syndicated Facility and DAP Notes, partially offset by interest expense on the Clearwater infrastructure liability that was issued in the fourth quarter of 2023.

The Company amortizes capitalized issuance costs over the term of its corresponding debt instrument and incurs standby fees on the undrawn portion of the Syndicated Facility. Financing expenses include the realized and unrealized gains and losses resulting from the revaluation of outstanding US dollar denominated credit facility draws at each reporting period, as well as the corresponding foreign exchange cross-currency swap contracts that are notionally aligned with these hedged credit facility draws. Offsetting realized gains and losses from the net settlement of these financial instruments are reflected net in the table above.

Income taxes

($ thousands)		Three months ended
March 31		2024		2023	% change
Current income tax expense	$	24,225	$	20,289	19
Deferred income tax recovery		(35,806)		(12,098)	196
Total income tax expense (recovery)	$	(11,581)	$	8,191	(241)
Statutory tax rate		23%		23%	-
Effective tax rate		26%		77%	(66)

Current income tax expenses for the three months ended March 31, 2024 increased by 19% compared to the same period in the prior year, primarily due to higher adjusted funds flow. The increase in deferred income tax recoveries during the first quarter of 2024 was primarily due to the net losses incurred. Tamarack's effective tax rate for accounting purposes in Q1 2024 was 26%, compared to the statutory tax rate of 23%, primarily due to the amortization of unrecognized tax assets and liabilities acquired from business combinations in prior years that were subject to the initial recognition exemption at the time of purchase.

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Depletion, depreciation and amortization ("DD&A")

($ thousands, except per boe)		Three months ended
March 31		2024		2023	% change
Depletion and depreciation	$	147,324	$	157,537	(6)
Amortization of undeveloped leases		877		769	14
Total	$	148,201	$	158,306	(6)
Total ($/boe)	$	26.26	$	25.89	1

For the three months ended March 31, 2024, DD&A expense per boe increased by 1% compared to 2023, primarily due to the disposition of the non-core Cardium CGU in the fourth quarter of 2023 which carried lower average depletion rates relative to the Company's corporate average on the core asset areas. Gross DD&A expense in the first quarter of 2024 decreased 6% compared to the first quarter of 2023 due to lower production volumes partially offset by higher depletion rates.

Dispositions

In the first quarter of 2024 the Company sold certain non-core oil and natural gas assets in the Redwater area to a third-party for nominal consideration and recorded a loss on disposition of $38.0 million. As part of the disposition, the Company de-recognized uninflated, undiscounted decommissioning obligations of $14.2 million.

Adjusted funds flow and net income (loss)

($ thousands, except per share amounts)		Three months ended
March 31		2024		2023	% change
Cash provided by operating activities	$	165,201	$	59,624	177
Decommissioning expenditures		1,524		875	74
Changes in non-cash working capital		14,831		96,772	(85)
Adjusted funds flow (1)		181,556		157,271	15
Per share - basic (1)		0.33		0.28	18
Per share - diluted (1)		0.33		0.28	18
Net income (loss)	$	(32,744)	$	2,505	nm
Per share - basic		(0.06)		-	nm
Per share - diluted		(0.06)		-	nm

(1) Refer to "Advisories and guidance" for information on Capital Management Measures and Ratios, Non-GAAP Financial Measures and Ratios and Supplemental Financial Measures.

Cash provided by operating activities increased by 177% in the first quarter of 2024, compared to the same period in the prior year, primarily due to a full year of 2022 tax instalments remitted to the Government in the first quarter of 2023 (reflected through non- cash working capital). Adjusted funds flow for the three months ended March 31, 2024 increased by 15% compared to the prior year, primarily due to higher realized commodities prices, partially offset by lower production.

The Company recorded a net loss of $32.7 million during the three months ended March 31, 2024, compared to net income of $2.5 million in the same period in 2023. The net loss was primarily due to an unrealized loss on risk management contracts and the loss on disposition of non-core Redwater assets, partially offset by higher operating netbacks.

Investments in oil and natural gas assets

($ thousands)		Three months ended
March 31		2024		2023	% change
Drilling, completion and equipping	$	96,530	$	96,571	(0)
Facilities		27,375		50,001	(45)
Land, seismic and other		4,316		1,590	171
Exploration and development expenditures	$	128,221	$	148,162	(13)
Acquisitions	$	-	$	2,939	(100)
Dispositions	$	1,797	$	(180)	nm

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