Tamarack Valley Energy : 2023 Q3 Financial Report

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL RESULTS

The following Management's Discussion and Analysis ("MD&A") is a review of the operational and financial results and outlook for Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") for the three and nine months ended September 30, 2023 and 2022. This MD&A is dated and based on information available as at October 25, 2023 and should be read in conjunction with the unaudited condensed consolidated interim financial statements ("financial statements") and the notes thereto for the three and nine months ended September 30, 2023 and 2022 and the audited consolidated financial statements for the year ended December 31, 2022. Additional information relating to Tamarack, including Tamarack's Annual Information Form for the year ended December 31, 2022, is available on SEDAR+ at www.sedarplus.caand Tamarack's website at www.tamarackvalley.ca.

The financial statements have been prepared in accordance with International Accounting Standards 34 "Interim Financial Reporting". The Company uses certain Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures in this MD&A. Certain financial measures are also presented on a per bbl, per boe, per mcf or per share basis that results in those measures considered as Supplemental Financial Measures. For a discussion of those measures, including the method of calculation, please refer to the section titled "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" beginning on page 22. Unless otherwise indicated, all references to dollar amounts are in Canadian ("CAD") currency.

Highlights for the Three and Nine Months Ended September 30, 2023

Production - Average daily production reached a record 68,597 boe/d in the quarter, 58% higher than 2022 due to a successful 2023 development program in the Clearwater and Charlie Lake and acquisitions that closed in 2022. Liquids weighting of 82% oil and NGLs was 8% higher than last year. Year to date production of 67,760 boe/d is also 58% higher than prior year.

Realizations - Tamarack's average realized price was $80.22/boe in the quarter, 22% higher than the second quarter of 2023 and consistent with the same period in 2022. Global crude oil prices rallied in the summer of 2023 and Canadian oil differentials narrowed. The Company's realized heavy oil price, net of blending expense, of $92.85/bbl in the quarter was only $0.24/bbl under the Hardisty benchmark price compared to a $4.22 differential in the same quarter of 2022. Tamarack achieved stronger than historical oil price realizations as transportation and logistics improvements enabled production to move to more competitive sales points.

Lifting Costs - Net production expenses dropped to $8.47/boe during the third quarter compared to $10.25 in the second quarter as a result of the Company's new Wembley facilities being brought online in the Charlie Lake light oil play, additional infrastructure development in the Clearwater area and higher production.

Capital - Capital investments of $122.8 million in the quarter and $388.8 million year to date were focused on the Company's core development programs. Year to date, Tamarack drilled, completed and equipped 93 (91.6 net) Clearwater heavy oil wells and 14 (13.8 net) Charlie Lake light oil wells. Major infrastructure investments included work in the Clearwater Nipisi on a gas conservation and an oil treating and water injection facility, as well as the construction of the Wembley gas plant. Targeted infrastructure investment facilitated production growth, operating cost reductions and greenhouse gas emissions abatement.

1

Adjusted Funds Flow & Free Cash Flow- Record production and strong Canadian oil prices generated Adjusted Funds Flow of $255.2 million in the third quarter of 2023, which was 44% higher than the same quarter in 2022. Free funds flow of $132.4 million was $53.0 million, or 67%, higher than the same quarter last year.

Debt & Return of Capital - With Free Funds Flow, combined with the $39.5 million non-core disposals in July 2023 and $100.2 million Cardium net assets held for sale, net debt was reduced to $1,128.0 million at September 30, 2023, down $246.0 million (17%) from June 30, 2023. $20.9 million of base dividends were paid to shareholders in the quarter. The second half of 2023 is a step change for the Company's profitability and returns as free cash flow generation ramps up and net debt approaches the enhanced return threshold of $1.1 billion.

The third quarter results demonstrate positive change in the business through focusing on top tier plays, margin enhancing infrastructure investments and improved price realizations.

Annual Guidance

The Company's exploration and development capital guidance range remains unchanged at $425 million to $475 million. Tamarack continues to focus on maximizing free funds flow for debt repayment and enhancing shareholder returns as debt thresholds are met. Fourth quarter 2023 free funds flow is expected to reflect increased oil weighting with lower operating expenses driving improved netback realizations through the Company's infrastructure initiatives.

Tamarack has updated its 2023 production guidance to reflect the west central non-core Cardium asset disposition previously announced on1 October 19, 2023. Updated full year 2023 production is expected to be in the range of 65,500 to 69,500 boe/d with fourth quarter volumes of 65,000 to 66,000 boe/d. Production guidance reflects the strong performance from the Clearwater and Charlie Lake drilling programs and the impact of the non-core Cardium disposition of ~4,500 boe/d for the fourth quarter. Tamarack expects to provide the 2024 budget and guidance on December 6, 2023.

	Prior guidance	Updated current guidance
	for the year ended	for the year ended
	December 31, 2023	December 31, 2023
	As presented	As presented
	May 10, 2023	October 25, 2023
Capital expenditures ($mm)(1)	$425 - $475	$425 - $475
Annual average production (boe/d)(5)	67,000 - 71,000	65,500 - 69,500
Average oil & NGL weighting	81% - 83%	82% - 84%
Expenses:
Royalty rate (percent of sales - %)	19% - 21%	19% - 21%
Net production ($/boe)(2)	$9.00 - $9.50	$9.00 - $9.50
Transportation ($/boe)	$3.50 - $4.00	$3.50 - $4.00
General and administrative ($/boe)	$1.25 - $1.35	$1.25 - $1.35
Interest ($/boe)	$3.80 - $4.00	$3.80 - $4.00
Taxes ($/boe)(3)(4)	$3.75 - $4.10	$3.75 - $4.50
Leasing expenditures ($mm)	$3.5 - $4.5	$3.5 - $4.5

1. Capital E&D budget includes exploration and development capital, environmental, social and governance ("ESG") initiatives, and facilities but excludes asset acquisitions and dispositions, ARO, land and seismic.
2. Refer to the section "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures".
3. Tax costs per boe are particularly sensitive to changes in commodity pricing and are represented in the guidance under the Company's best outlook of budget and strip pricing but may change significantly under alternate price conditions throughout the year.
4. Tax guidance has been updated from percentage of net operating income to cost per boe for the prior and updated guidance for the year ended December 31, 2023.
5. Prior guidance Annual Average Production is comprised of 16,500-17,500 bbl/d light and medium oil, 34,750-36,500 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 71,000-75,000 mcf/d natural gas. Current guidance Annual Average Production 16,400-16,900 bbl/d light and medium oil, 34,700-36,500 bbl/d heavy oil, 3,230- 4,260 bbl/d NGL and 67,000-71,000 mcf/d natural gas.

2

Q3 2023 Operational and Financial Highlights

	Three months ended	Nine months ended
	September 30,		September 30,
	2023	2022	%	2023	2022	%
	change	change
($ thousands, except per share)
Total oil, natural gas revenue	506,365	327,910	54	1,284,066	1,033,135	24
Cash flow from operating activities	199,756	299,927	(13)	415,645	577,488	(28)
Per share - basic	$ 0.36	$ 0.52	(31)	$ 0.75	$ 1.34	(44)
Per share - diluted	$ 0.36	$ 0.52	(31)	$ 0.74	$ 1.33	(44)
Adjusted funds flow (1)	255,199	177,834	44	569,723	530,315	7
Per share - basic (3)	$ 0.46	$ 0.40	15	$ 1.02	$ 1.23	(17)
Per share - diluted (3)	$ 0.46	$ 0.40	15	$ 1.02	$ 1.22	(16)
Net income	8,634	124,793	(93)	36,874	294,757	(87)
Per share - basic	$ 0.02	$ 0.28	(93)	$ 0.07	$ 0.68	(90)
Per share - diluted	$ 0.02	$ 0.28	(93)	$ 0.07	$ 0.68	(90)
Net debt (1)	(1,128,030)	(286,762)	293	(1,128,030)	(286,762)	293
Capital expenditures (1)	122,759	98,451	25	388,752	333,301	17
Weighted average shares outstanding (thousands)
Basic	556,708	440,388	26	556,399	431,672	29
Diluted	558,569	443,351	26	559,958	435,053	29
Share Trading
High	$ 4.12	$ 4.62	(11)	$ 4.88	$ 6.48	(25)
Low	$ 3.19	$ 3.28	(3)	$ 2.99	$ 3.28	(9)
Average daily share trading volume (thousands)	1,975	3,745	(47)	2,457	3,890	(37)
Average daily production
Light oil (bbls/d)	16,974	16,229	5	16,797	17,437	(4)
Heavy oil (bbls/d)	35,900	13,183	172	35,229	10,524	235
NGL (bbls/d)	3,623	3,659	(1)	3,795	3,769	1
Natural gas (mcf/d)	72,597	62,428	16	71,633	66,839	7
Total (boe/d)	68,597	43,476	58	67,760	42,870	58
Average sale prices
Light oil ($/bbl)	107.83	111.80	(4)	98.30	119.53	(18)
Heavy oil, net of blending expense(2) ($/bbl)	92.85	89.30	4	76.15	99.48	(23)
NGL ($/bbl)	41.46	49.18	(16)	41.51	56.23	(26)
Natural gas ($/mcf)	2.60	6.27	(59)	2.84	6.59	(57)
Total ($/boe)	80.22	81.98	(2)	69.29	88.28	(22)
Operating netback ($/Boe)
Average realized sales, net of blending expense (2)	80.22	81.98	(2)	69.29	88.28	(22)
Royalty expenses	(13.38)	(14.06)	(5)	(12.70)	(16.49)	(23)
Net production expenses (2)	(8.47)	(10.24)	(17)	(9.72)	(10.25)	(5)
Transportation expenses	(4.13)	(2.88)	43	(4.00)	(2.49)	61
Operating field netback ($/Boe) (2)	54.24	54.80	(1)	42.87	59.05	(27)
Realized commodity hedging loss	(2.52)	(2.90)	(13)	(1.89)	(5.46)	(65)
Operating netback ($/Boe) (2)	51.72	51.90	-	40.98	53.59	(24)
Adjusted funds flow ($/Boe) (3)	40.44	44.46	(9)	30.80	45.31	(32)

1. Capital Management Measure; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.
2. Non-IFRSFinancial Ratio; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.
3. Supplemental Financial Measure; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.

3

Production

	Three months ended		Nine months ended
		September 30,		September 30,
				%			%
	2023		2022	change	2023	2022	change
Production
Light oil (bbls/d)	16,974		16,229	5	16,797	17,437	(4)
Heavy oil (bbls/d)	35,900		13,183	172	35,229	10,524	235
Natural gas liquids (bbls/d)	3,623		3,659	(1)	3,795	3,769	1
Natural gas (mcf/d)	72,597		62,428	16	71,633	66,839	7
Total (boe/d)	68,597		43,476	58	67,760	42,870	58
Percentage of oil and NGL	82%		76%	8	82%	74%	11

Average production for Q3 2023 and the nine months ended September 30, 2023 increased 58% compared to the same periods in 2022 due to the acquisitions that closed in the second half of 2022 and the 2023 development program, partially offset by expected declines of existing base production. Full year 2023 production guidance has been updated to be in the range of 65,500 to 69,500 boe/d to reflect the west central non-core Cardium asset disposition announced subsequent to Q3 2023.

The Company's oil and NGL weighting for the three and nine months ended September 30, 2023 was 82%, higher by 8% and 11%, respectively, as compared to the same periods in 2022 due to the acquisitions in the oil focused Clearwater play.

Petroleum and Natural Gas Sales

	Three months ended	Nine months ended
	September 30,		September 30,
			%			%
	2023	2022	change	2023	2022	change
Revenue ($ thousands)
Light oil	$168,379	$167,023	1	$450,757	$569,281	(21)
Heavy oil, net of blending expense (1)	306,663	108,308	183	732,392	285,804	156
Natural gas liquids	13,820	16,551	(17)	43,004	57,853	(26)
Natural gas	17,391	36,028	(52)	55,594	120,197	(54)
Total, net of blending expense (1)	$506,253	$327,910	54	$1,281,747	$1,033,135	24
Average realized price:
Light oil ($/bbl)	107.83	111.80	(4)	98.30	119.53	(18)
Heavy oil, net of blending expense ($/bbl) (2)	92.85	89.30	4	76.15	99.48	(23)
Natural gas liquids ($/bbl)	41.46	49.18	(16)	41.51	56.23	(26)
Combined average oil and NGL ($/boe)	94.05	95.93	(2)	80.46	105.39	(24)
Natural gas ($/mcf)	2.60	6.27	(59)	2.84	6.59	(57)
Revenue, net of blending expense ($/boe) (2)	80.22	81.98	(2)	69.29	88.28	(22)
Benchmark pricing:
West Texas Intermediate (US$/bbl)	82.26	91.55	(10)	77.39	98.09	(21)
Edm Par Differential (US$/bbl)	1.85	2.05	(10)	2.61	1.84	42
WCS differential (US$/bbl)	12.88	19.86	(35)	17.63	15.73	12
Edmonton Par (Cdn$/bbl)	107.90	116.79	(8)	100.63	123.41	(18)
Hardisty Heavy (Cdn$/bbl)	93.09	93.52	-	80.38	105.54	(24)
NYMEX monthly settlement (US$/mmbtu)	2.55	8.20	(69)	2.69	6.77	(60)
AECO daily index (Cdn$/mcf)	3.40	4.00	(15)	3.00	5.24	(43)
AECO monthly index (Cdn$/mcf)	2.37	5.77	(59)	3.01	5.55	(46)

1. Non-IFRSFinancial Measure; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.
2. Non-IFRSFinancial Ratio; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.

4

Revenue per boe from oil, natural gas and NGL sales, net of blending expense, was $80.22 per boe for Q3 2023 and $69.29 per boe for YTD 2023 compared to $81.98 per boe in Q3 2022 and $88.28 per boe for YTD 2022. Quarter over quarter the net revenue held flat due to lower WTI being offset by a weaker Canadian dollar and improved heavy oil differentials. Canadian heavy and light oil differentials narrowed in the third quarter tied to higher North American refinery demand and seasonality. The YTD decrease in revenue per boe is primarily due to the lower WTI benchmark price, wider WCS and Edmonton Par differentials, as well as lower natural gas prices year over year. Oil's strength in Q3 compared to Q2 was driven by tight physical markets as a result of strong demand from high refinery utilization coupled with constrained supply from OPEC+, notably Saudi Arabia and Russia.

Comparing the Company's realized heavy oil price, net of blending expense, of $92.85 per bbl for Q3 2023, to the Hardisty Heavy benchmark of $93.09 per bbl, the Company has realized a tighter differential to previous periods. This change is due to an updated marketing approach, selling directly into the Edmonton market, which lead to improved netbacks and a shift of transportation costs from a revenue deduction to a transportation expense. Similarly, comparing the Company's realized heavy oil price, net of blending expense, of $76.15 per bbl for YTD 2023, to the Hardisty Heavy benchmark of $80.38 per bbl, is also an improvement over the same period in 2022 for the same reasons listed above. The WCS heavy oil differential strengthened year over year to an average of US$12.88 per bbl in Q3 2023 compared to US$19.86 per bbl due to the reduction of OPEC's production. Conversely, the WCS heavy oil differential weakened to US$17.63 per bbl for YTD 2023 compared to US$15.73 per bbl for the same period in 2022.

Comparing the Company's realized light oil price of $107.83 per bbl for Q3 2023, to the Edmonton Light benchmark of $107.90 per bbl, the Company has realized a tighter differential to previous periods. This change is due to improved netbacks and a shift of transportation costs from a revenue deduction to a transportation expense. Similarly, comparing the Company's realized light oil price of $98.30 per bbl for YTD 2023, to the Edmonton Light benchmark of $100.63 per bbl, is also an improvement over the same period in 2022 for the same reasons listed above. The Edmonton Par light oil differential strengthened to an average of US$1.85 per bbl for Q3 2023 compared to US$2.05 per bbl in Q3 2022. Conversely, the Edmonton Par light oil differential weakened to an average of US$2.61 per bbl YTD 2023 compared to US$1.84 per bbl in 2022 due to more overall light sweet supply in the 9 months of 2023.

The Company's realized NGL pricing decreased 16% and 26% for Q3 2023 and YTD 2023, respectively, compared to the same periods in 2022 largely due to the drop in WTI. The WTI benchmark price decreased 10% and 21% for Q3 2023 and YTD 2023, respectively, compared to the same periods in 2022.

Tamarack's realized natural gas price decreased to $2.60 per mcf in Q3 2023 from $6.27 per mcf in Q3 2022. The Company's YTD 2023 realized natural gas price decreased to $2.84 per mcf from $6.59 per mcf realized in 2022. Decreases in realized natural gas prices are consistent with decrease in AECO and NYMEX benchmarks.

5

Risk Management

The Company may use both financial derivatives and physical delivery contracts to manage fluctuations in commodity prices, foreign exchange rates and interest rates. All such transactions are conducted within risk management tolerances that are reviewed quarterly by Tamarack's Board of Directors. At September 30, 2023, the Company held derivative commodity, foreign exchange and interest rate contracts as noted in the tables below.

Crude Oil Derivatives:

	Q4 2023	Q1 2024	Q2 2024	Q3 2024	Q4 2024
WTI 2-way Collar
Volume (bbls/d)	20,000	21,000	19,500	11,500	3,000
Average Put/Call	67.00	87.54	66.93	86.30	69.36		89.39	68.85	93.13	67.50		92.09
Premium (USD/bbl)		1.93		0.93		1.00		1.38		1.33
Volume (bbls/d)		850		-		-			-		-
Average Put/Call (CAD/bbl)	80.44	108.64	-	-	-		-	-	-	-		-
WTI Fixed Price
Volume (bbls/d)		200		-		-			-		-
Average Fixed Price (CAD/bbl)	91.75		-		-			-		-
MSW Differential
Volume (bbls/d)	2,500	2,500	3,000	4,000	4,000
Average Fixed Price (USD/bbl)	(2.55)	(2.69)	(2.73)	(2.63)	(2.63)
WCS Differential
Volume (bbls/d)	14,000	4,500	4,000		500		500
Average Fixed Price (USD/bbl)	(16.57)	(14.76)	(13.57)	(13.75)	(13.75)
Volume (bbls/d)		700		-		-			-		-
Average Fixed Price (CAD/bbl)	(19.29)		-		-			-		-

Natural Gas Derivatives:

			Summer 23(1)	Sept/Oct 23		Winter 23/24(2)	Summer 24(1)
AECO - NYMEX Basis
	Volume (mmbtu/d)			17,500	-			25,000		2,500
	Average Fixed Price (USD/mmbtu)			(1.87)	-			(1.10)		(1.11)
	AECO 5A Swap
	Volume (GJ/d)			-		25,000			-			1,000
	Average Fixed Price (CAD/GJ)			-		2.36			-			2.80
	NYMEX Collar
	Volume (mmbtu/d)			17,500	-			25,000		2,500
Average Put/Call (USD/mmbtu)	4.56		6.98	-		3.08		4.28	3.05	3.50

1. Summer runs from April 1 to October 31 of the given year.
2. Winter runs from November 1 to March 31 of the given year.

6

Foreign Exchange Derivatives:

	Q4 2023		Q1 2024	Q2 2024	Q3 2024	Q4 2024
CAD/USD Collar
Amount (USD/month)	$12,000,000	$3,000,000	$3,000,000		-		-
Average Put/Call (CAD/USD)	1.3254		1.3909		1.3333	1.3885	1.3333		1.3885	-	-	-		-
CAD/USD Variable Rate Collar
Amount (USD/month)	$11,500,000	$18,500,000	$18,500,000	$6,000,000	$6,000,000
Average Put/Call (CAD/USD)(1)	1.33		1.41		1.33	1.41	1.33		1.41	1.33	1.41	1.33		1.41
Knockout Rate (CAD/USD) (1)	1.36	1.36	1.36		1.36		1.36
CAD/USD Variable Rate Collar
(Extendable Option)(2)
Amount (USD/month)	$12,500,000	$4,500,000	$4,500,000	$2,000,000	$2,000,000
Average Put/Call (CAD/USD)(1)	1.33		1.41		1.33	1.41	1.33		1.41	1.32	1.40	1.32		1.40
Knockout Rate (CAD/USD)(1)	1.36	1.36	1.36		1.38		1.38
CAD/USD Swap
Amount (USD/month)	$6,000,000	$5,000,000	$5,000,000	$3,000,000	$3,000,000
Average Fixed Price (CAD/USD)	1.3399	1.3539	1.3539	1.3553	1.3553
Put Deferred Premium
Amount (USD/month)		-		$3,000,000		-			-		-
Average Put (CAD/USD)		-		1.32		-			-		-
Average Premium (CAD/USD)		-		0.01		-			-		-

1. If the average rate for the month exceeds the call, Tamarack receives an average rate forward equivalent to the knockout rate.
2. Includes an extension option at the end of the collar, at the counterparty's option, for an equivalent term at an average rate forward fixed price equal to the call.

Interest Rate Derivatives:

	2023	2024
CDOR Swap
Amount (million CAD$/year)	30.0	6.3
Average Interest Rate	1.047%	1.045%

At September 30, 2023, the derivative commodity, foreign exchange and interest rate contracts were fair valued with a net liability value of $24.2 million (December 31, 2022 - $10.3 million net liability) recorded on the balance sheet. The Company recorded an unrealized loss of $20.1 million and a realized loss of $15.9 million in earnings for the three months ended September 30, 2023, compared to an unrealized gain of $47.8 million and a realized loss of $11.6 million during the same period in 2022. The Company recorded an unrealized loss of $13.9 million and a realized loss of $34.9 million in earnings for the nine months ended September 30, 2023, compared to an unrealized gain of $32.1 million and a realized loss of $63.9 million during the same period in 2022. The unrealized and realized losses for the three and nine months ended September 30, 2023 were primarily due to the strength of WTI pricing. The Company manages credit risk for these contracts by engaging with a variety of counterparties, all of which are investment-grade banking institutions or large purchasers of commodities. All counterparties have been assessed for credit worthiness.

All physical commodity contracts are considered executory contracts and are not recorded at fair value on the balance sheet. On settlement, the realized benefit or loss is recognized in oil and natural gas revenue.

At September 30, 2023, the Company held no physical commodity contracts.

7

Royalties

	Three months ended		Nine months ended
		September 30,			September 30,
				%				%
	2023		2022	change	2023		2022	change
Royalty expenses ($ thousands)	$84,443		$56,256	50	$234,875		$192,990	22
$/boe	13.38		14.06	(5)	12.70		16.49	(23)
Percent of sales (%)	17		17	-	18		19	(5)

Royalties as a percentage of revenue for the three and nine months ended September 30, 2023 were consistent with the same periods in 2022. YTD royalty rates of 18% are under the guidance range due to lower reference commodity prices for most of the year. The Company expects royalty rates as a percentage of revenue to be in the 19% to 21% range for Q4 2023 based on current forecast commodity pricing levels and increased production from lands subjected to GORRs.

On an absolute basis, royalty expense was higher in Q3 2023 and the nine months ended September 30, 2023 compared to the same periods in 2022 due to an increase in production and GORRs, partially offset by decreased commodity prices.

Net Production Expenses

	Three months ended		Nine months ended
		September 30,			September 30,
				%				%
($ thousands, except per boe)	2023		2022	change	2023		2022	change
Production expenses	$54,602		$42,347	29	$181,072		$122,255	48
Less: processing income	1,156		1,394	(17)	1,229		2,259	(46)
Total net production expenses (1)	$53,446		$40,953	31	$179,843		$119,996	50
Total ($/boe) (2)	$8.47		$10.24	(17)	$9.72		$10.25	(5)

1. Non-IFRSFinancial Measure; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.
2. Non-IFRSFinancial Ratio; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.

For the three and nine months ended September 30, 2023, per unit net production expenses (see "Non-IFRS Financial Ratios") were lower compared to the same periods in 2022 due to our new facilities being brought on-line in Q3 2023 in conjunction with further synergies being realized across our Clearwater assets in the Nipisi and Marten Hills area as a result of the Deltastream acquisition. 2023 production expense outlook remains in line with our previous guidance of $9.00 to $9.50 per boe.

For the three and nine months ended September 30, 2023, on an absolute basis, gross and net production expenses were higher compared to the same periods in 2022 due to higher production.

8

Transportation Expense

	Three months ended		Nine months ended
		September 30,			September 30,
			%				%
($ thousands, except per boe)	2023	2022	change	2023		2022	change
Transportation expense - gas	$3,144	$2,890	9	$8,093		$8,737	(7)
Transportation expense - oil	22,890	8,621	166	65,969		20,406	223
Total transportation expense	$26,034	$11,511	126	$74,062		$29,143	154
Total ($/boe)	$4.13	$2.88	43	$4.00		$2.49	61

1. Pipeline tariffs are 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 the Company's oil, NGL and gas sales. In the latter case, the pipeline tariffs are included as a reduction of revenue rather than a transportation expense.

For the three months ended September 30, 2023, per unit transportation expenses were higher compared to the same period in 2022. The increase in oil transportation was driven by higher heavy oil trucking costs in order to optimize netbacks, increased pipeline tariffs and transportation costs shifting from a revenue deduction to a transportation expense due to new contractual arrangements. These factors result in an increase in realized pricing compared to Benchmark pricing which can be seen in the Petroleum and Natural Gas Sales section in this MD&A (page 4).

For the nine months ended September 30, 2023, per unit transportation expenses were higher compared to the same period in 2022 due to the 2022 acquisitions. Starting in Q2 2023, pipeline tariffs from light oil production have also been included as a transportation expense due to new contractual terms.

Total transportation expense for gas increased during the three months ended September 30, 2023 due to unplanned downtime and increases in tolls on the Nova Gas Transmission System. The YTD 2023 decrease in transportation costs for gas compared to the same period in 2022 was driven by the lower fuel costs in the first half of 2023. Total transportation expense for oil is inline with the increase in total production of heavy oil for both the third quarter of 2023 and YTD 2023.

Blending Expense

Blending expense includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil to meet pipeline specifications. The blending expense represents the difference between the cost of purchasing and transporting the diluent and the realized price of the blended product sold. In this MD&A, blending expense is recognized as a reduction to heavy oil revenues (see "Non-IFRS Financial Measures").

Blending expense for the three and nine months ended September 30, 2023 was $0.1 million and $2.3 million, respectively, compared to $nil in the same periods in 2022. Blending expense was lower in Q3 2023 compared to previous quarters in 2023 due to lower diluent requirements during the warmer summer months. The Company recognized blending expense for the first time in Q4/22 as a result of the Deltastream acquisition which closed in October 2022.

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Operating Netback

		Three months ended				Nine months ended
			September 30,							September 30,
							%									%
($/boe)		2023		2022		change		2023		2022			change
Average realized sales, net of		$80.22		$81.98		(2)			$69.29		$88.28			(22)
blending expense (1)
Royalty expenses		(13.38)		(14.06)		(5)			(12.70)		(16.49)			(23)
Net production expenses (1)		(8.47)		(10.24)		(17)			(9.72)		(10.25)			(5)
Transportation expense		(4.13)		(2.88)		43			(4.00)		(2.49)			61
Operating field netback (1)		$54.24		$54.80		(1)			$42.87		$59.05			(27)
Realized hedging loss		(2.52)		(2.90)		(13)			(1.89)		(5.46)			(65)
Operating netback (1)		$51.72		$51.90		-		$40.98		$53.59			(24)
		Three months ended					Nine months ended
			September 30,							September 30,
							%										%
		2023		2022			change		2023			2022		change
Average realized sales, net of		$506,253		$327,910			54			$1,281,747			$1,033,135		24
blending expense (2)
Royalty expenses		(84,443)		(56,256)			50			(234,875)			(192,990)		22
Net production expenses (2)		(53,446)		(40,953)			31			(179,843)			(119,996)		50
Transportation expense		(26,034)		(11,511)			126			(74,062)			(29,143)		154
Operating field netback (2)		$342,330		$219,190			56			$792,967			$691,006		15
Realized hedging loss		(15,922)		(11,615)			37			(34,892)			(63,916)		(45)
Operating netback (2)		$326,408		$207,575			57			$758,075			$627,090		21

1. Non-IFRSFinancial Ratio; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.
2. Non-IFRSFinancial Measure; See "Non-IFRS Financial Measures, Non-IFRS Financial Ratios and Capital Management Measures" section of this MD&A.

For the three and nine months ended September 30, 2023 operating netback per boe (see "Non-IFRS Financial Ratios") was lower than the same periods in 2022 primarily due to a decrease in commodity prices and higher transportation expenses partially offset by lower net production expenses.

On an absolute basis, operating netback (see "Non-IFRS Financial Measures") was higher for Q3 2023 compared to the same period in 2022 due to higher production from the acquisitions that closed in 2022 partially offset by lower commodity prices, higher royalties, higher net production expenses and higher transportation expenses.

For the nine months ended September 30, 2023 operating netback (see "Non-IFRS Financial Measures") on an absolute basis was higher compared to the same period in 2022 due to higher production from the Deltastream acquisition and a lower realized hedging loss, partially offset by lower commodity prices, higher royalties, higher net production expenses and higher transportation expenses.

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