Yangarra Announces 2023 Year End Financial and Operating Results and Reserves

CALGARY, AB, March 7, 2024 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX: YGR) announces its financial and operating results and reserves for the year ended December 31, 2023.

2023 Operations Review

• Yangarra continued to refine the Company's drilling approach resulting in a dramatic reduction in drilling times and drilling costs.

• The new core area of Chambers with Cardium, Belly River and Manville potential was delineated with five Cardium wells and one Belly River well with positive results.

• The Company added 2.2 new drilling locations for every well drilled.

• Several "Smart Dart" and Plug & Perf wells were tested during the year with the Company returning to cemented, coil activated sleeves completions while monitoring the results on the "Smart Dart" and Plug & Perf wells.

• Yangarra constrained the fourth quarter capital program due to ongoing depressed natural gas prices, resulting in capital spending of $16 million in Q4.

2024 Outlook

• Yangarra's primary goal in 2024 is to hit a debt target of $80 million and then focus on shareholder returns.

• The Company has set a capital budget of $70 million for 2024.

  • Yangarra will continue to constrain the capital program into 2024 because of depressed natural gas prices with spending of $20 - $25 million in the first half, dependent on the timing of spring breakup.

  • The second half spending has been set at $45 - $50 million, however this is dependent on an improvement in commodity pricing.

  • Included in the budget is a well stimulation and optimization program targeting 20-25% of legacy wells. This stimulation strategy was initiated in 2021 and now has evolved to where the Company can apply the strategy to the entire field annually.

  • The 2024 capital budget is designed to hold production flat for 2024, while maximizing debt repayment.

• A recent Computer Modelling Group (CMG) study indicated waterflood potential in the Halo Cardium and as a result Yangarra plans to initiate a waterflood pilot in Q2 2024 in the Chedderville area. Water for the pilot will be sourced from flow back and produced water, which would have otherwise needed to be disposed of, giving the project an added benefit of approximately $800,000 per year in avoided water disposal fees.

2023 Highlights

• Average production of 11,936 boe/d (39% liquids), an increase of 8% from 2022

• Oil and gas sales of $166.5 million, a decrease of 31% from 2022

• Funds flow from operations of $99.0 million ($1.06 per share – fully diluted) a decrease of 44% from 2022

• Adjusted EBITDA of $109 million ($1.11 per share – fully diluted)

• Net income of $46.7 million ($0.47 per share – fully diluted), resulting in an income margin of 28%

• Return on capital employed of 9.5%

• Operating costs of $8.24/boe (including $1.54 /boe of transportation costs)

• Operating netback of $26.72/boe

• Operating margin of 70% and funds flow from operations margin of 59%

• G&A costs of $1.32/boe

• Royalties at 9% of oil and gas revenue

• Capital expenditures of $94.3 million

• Adjusted net debt of $118.6 million, a decrease of $15.7 million from 2022

• Retained earnings of $311.7 million

• Decommissioning liabilities of $16.0 million (discounted)

Fourth Quarter Highlights

• Funds flow from operations of $17.6 million ($0.19 per share – fully diluted), a decrease of 58% from the same period in 2022

• Oil and gas sales of $33.7 million, a decrease of 44% from the same period in 2022

• Adjusted EBITDA of $20.1 million ($0.20 per share – fully diluted), a decrease of 40% from the same period in 2022

• Net income of $12.4 million ($0.14 per share – fully diluted), a decrease of 50% from the same period in 2022

• Average production of 11,133 boe/d (38% liquids), a 5% decrease from the same period in 2022

• Operating costs of $8.39/boe (including $1.70/boe of transportation costs)

• Operating netback of $21.54/boe

• Operating margin of 66% and funds flow from operations margin of 52%

• G&A costs of $1.55/boe

• Royalties at 8% of oil and gas revenue

• All in cash costs of $15.77/boe

• Capital expenditures of $16.0 million

• Adjusted net debt to fourth quarter annualized funds flow from operations of 1.69 : 1

Reserve Report Highlights

Summary

All reserves information contained in this press release are based on the Company's 2023 NI 51-101 oil and gas reserve report as prepared by Deloitte LLP (The "2023 Reserve Report").

Proved Developed Producing ("PDP") Reserves

• 38.0 million boe (45% increase from 2022)

• Net present value before tax discounted at 10% ("NPV10") of $504 million (3% decrease from 2022)

• Yangarra's PDP finding and development ("F&D") cost is $5.85/boe resulting in a recycle ratio of 4.6 times

• PDP net asset value per fully diluted common share ("NAV per FD Share") of $3.79

• PDP Reserve Life Index ("RLI") of 9.4 years

• PDP additions replaced 370% of 2023 production

Total Proved reserves ("1P")

• 96.8 million boe (12% increase from 2022)

• NPV10 of $1.1 billion (21% decrease from 2022)

• 1P future development costs of $420 million

• Yangarra's 1P F&D cost is $7.49/boe resulting in a recycle ratio of 3.6 times

• 1P NAV per FD Share of $9.85

• RLI of 24 years

• 1P additions replaced 336% of 2023 production

Proved plus probable reserves ("2P")

• 155.7 million boe (7% increase from 2022)

• NPV10 of $1.6 billion (21% decrease from 2022)

• 2P future development costs of $632 million

• Yangarra's 2P F&D cost is $7.74/boe resulting in a recycle ratio of 3.5 times

• 2P NAV per FD Share of $14.25

• RLI of 38 years

• 2P additions replaced 349% of 2023 production

Financial Summary

	2023		2022		Year Ended
	Q4	Q3	Q4		2023	2022
Statements of Income and Comprehensive Income
Petroleum & natural gas sales	$         33,651	$        45,414	$         60,292		$       166,516	$       243,056
Income before tax	$         16,106	$        15,157	$         31,075		$         63,179	$       137,745
Net income	$         12,435	$        11,487	$         25,071		$         46,664	$       106,358
Net income per share - basic	$             0.13	$            0.12	$             0.29		$             0.50	$             1.22
Net income per share - diluted	$             0.12	$            0.11	$             0.27		$             0.47	$             1.16
Statements of Cash Flow
Funds flow from operations	$         17,552	$        28,994	$         41,808		$         99,024	$       177,194
Funds flow from operations per share - basic	$             0.19	$            0.31	$             0.48		$             1.06	$             2.03
Funds flow from operations per share - diluted	$             0.18	$            0.29	$             0.45		$             1.01	$             1.92
Cash flow from operating activities	$         16,798	$        25,995	$         40,675		$         99,033	$       169,664
Weighted average number of shares - basic	94,801	94,801	87,956		93,189	87,423
Weighted average number of shares - diluted	99,534	100,043	92,742		98,445	92,054

 

	December 31, 2023		December 31, 2022
Statements of Financial Position
Property and equipment	$	759,967	$	701,045
Total assets	$	835,217	$	768,058
Working capital deficit	$	(735)	$	(136,920)
Adjusted net debt	$	118,646	$	134,364
Shareholders equity	$	536,598	$	473,574

Company Netbacks ($/boe)

		2023				2022			Year Ended
		Q4		Q3		Q4			2023		2022
Sales price	$	32.85	$	40.76	$	55.95		$	38.22	$	60.42
Royalty expense		(2.47)		(2.77)		(5.22)			(3.27)		(4.77)
Production costs		(6.70)		(6.53)		(6.77)			(6.69)		(6.07)
Transportation costs		(1.70)		(1.68)		(1.22)			(1.54)		(1.21)
Field operating netback		21.99		29.78		42.74			26.71		48.37
Realized gain (loss) on commodity contract settlement		(0.45)		0.07		0.10			0.02		(0.73)
Operating netback		21.54		29.85		42.84			26.73		47.64
G&A		(1.55)		(1.10)		(1.21)			(1.32)		(1.01)
Cash finance expenses		(2.90)		(2.77)		(2.86)			(2.84)		(2.79)
Depletion and depreciation		(9.16)		(9.14)		(9.44)			(9.05)		(9.36)
Non Cash - finance expenses		(0.31)		(0.27)		(0.41)			(0.12)		(0.09)
Gain on settlement of lawsuit		6.79		-		-			1.60		-
Stock-based compensation		(0.39)		(0.37)		(0.11)			(0.39)		(0.16)
Unrealized gain (loss) on financial instruments		1.71		(2.59)		0.03			(0.10)		0.01
Deferred income tax		(3.58)		(3.29)		(5.57)			(3.79)		(7.80)
Net income netback	$	12.14	$	10.32	$	23.26		$	10.72	$	26.44

Business Environment

		2023				2022			Year Ended
		Q4		Q3		Q4			2023		2022
Realized Pricing (Including realized commodity contracts)
Light Crude Oil ($/bbl)	$	101.92	$	105.54	$	112.53		$	98.42	$	116.26
NGL ($/bbl)	$	32.97	$	56.47	$	51.64		$	45.72	$	61.53
Natural Gas ($/mcf)	$	2.36	$	2.80	$	5.25		$	2.79	$	5.53
Realized Pricing (Excluding commodity contracts)
Light Crude Oil ($/bbl)	$	103.51	$	107.06	$	112.53		$	99.11	$	117.78
NGL ($/bbl)	$	32.96	$	54.60	$	51.70		$	44.58	$	61.45
Natural Gas ($/mcf)	$	2.41	$	2.81	$	5.21		$	2.81	$	5.64
Oil Price Benchmarks
West Texas Intermediate ("WTI") (US$/bbl)	$	78.48	$	82.30	$	82.79		$	77.65	$	94.41
Edmonton Par ($/bbl)	$	94.77	$	107.26	$	107.43		$	99.21	$	119.40
Edmonton Par to WTI differential (US$/bbl)	$	(8.35)	$	(2.32)	$	(3.68)		$	(4.24)	$	(2.47)
Natural Gas Price Benchmarks
AECO gas ($/mcf)	$	2.18	$	2.44	$	4.85		$	2.72	$	4.99
Foreign Exchange
Canadian Dollar/U.S. Exchange		0.74		0.75		0.74			0.74		0.77

Operations Summary 

Net petroleum and natural gas production, pricing and revenue are summarized below:

	2023		2022		Year Ended
	Q4	Q3	Q4		2023	2022
Daily production volumes
Natural Gas (mcf/d)	41,283	44,451	38,971		43,426	36,702
Light Crude Oil (bbl/d)	1,913	2,138	3,077		2,288	2,798
NGL's (bbl/d)	2,339	2,563	2,140		2,411	2,106
Combined (BOE/d 6:1)	11,133	12,109	11,712		11,936	11,022
Revenue
Petroleum & natural gas sales	$         33,651	$        45,414	$         60,292		$       166,516	$       243,056
Realized gain (loss) on commodity contract settlement	(460)	78	106		88	(2,920)
Total sales	33,191	45,492	60,398		166,604	240,136
Royalty expense	(2,529)	(3,087)	(5,627)		(14,258)	(19,170)
Total Revenue - Net of royalties	$         30,662	$        42,405	$         54,771		$       152,346	$       220,966

Working Capital Summary

The following table summarizes the change in adjusted net debt for the years ended December 31, 2023 and 2022:

		Year ended		Year ended
		December 31, 2023		December 31, 2022
Adjusted net debt - beginning of period	$	(134,364)	$	(196,794)
Funds flow from operations	$	99,024		177,194
Additions to property and equipment	$	(93,950)		(109,354)
Decommissioning costs incurred	$	(488)		(291)
Additions to E&E Assets	$	(353)		(3,888)
Issuance of shares	$	15,988		1,077
Lease obligation repayment	$	(1,525)		(2,331)
Other	$	(2,978)		23
Adjusted net debt - end of period	$	(118,646)	$	(134,364)
Credit facility limit	$	135,000	$	180,000

Capital Spending

Capital spending is summarized as follows:

	2023		2022		Year Ended
Cash additions	Q4	Q3	Q4		2023	2022
Land, acquisitions and lease rentals	$                72	$             114	$                26		$              564	$              427
Drilling and completion	14,670	21,550	26,009		76,477	96,271
Geological and geophysical	2	-	94		242	571
Equipment	947	3,123	1,596		14,975	11,200
Other asset additions	246	547	305		1,692	885
	$         15,937	$        25,334	$         28,030		$         93,950	$       109,354
Exploration & evaluation assets	$               89	$                 -	$                  -		$             353	$           3,888

Oil and Gas Reserves

The following tables summarize certain information contained in the 2023 Reserve Report. The 2023 Reserve Report encompasses 100% of Yangarra's oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") by Deloitte.

Summary of Oil and Gas Reserves ⁽¹⁾⁽²⁾
(Company Share Gross volumes based on forecast price and costs)

Reserves Category
	Light and Medium Oil (Mbbl)		Natural Gas Liquids (Mbbl)			Conventional Gas   (MMcf)	Shale  Gas   (MMcf)		Total BOE 2023 (Mboe)			Total BOE 2022 (Mboe)
Proved Developed Producing	5,719		7,871			146,172	403		38,019			26,263
Proved Developed Non-Producing	134		72			1,336	0		428			835
Proved Undeveloped	10,971		11,637			209,069	5,375		58,348			59,436
Total Proved	16,824		19,579			356,577	5,778		96,796			86,533
Probable	9,986		12,310			211,833	7,780		58,898			58,303
Total Proved Plus Probable	26,810		31,890			568,410	13,557		155,694			144,836

Notes:
(1)	Total values may not add due to rounding.
(2)	BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl).

Summary of Net Present Values of Future Net Revenue (Before Tax) ⁽¹⁾⁽⁴⁾
(Based on forecast price and costs)

	As At December 31, 2023(2)					As At December 31, 2022 (3)
Reserves Category	0.0% (M$)	5.0% (M$)	10.0% (M$)	15.0% (M$)	20.0% (M$)		10.0% (M$)
Proved Developed Producing	886,575	639,771	504,078	419,575	362,165		522,096
Proved Developed Non- Producing	9,138	6,704	5,378	4,543	3,964		17,669
Proved Undeveloped	1,128,006	819,043	625,445	494,887	401,891		892,247
Total Proved	2,023,719	1,465,518	1,134,901	919,005	768,019		1,432,012
Probable	1,404,453	743,748	457,461	309,063	222,487		595,119
Total Proved Plus Probable	3,428,171	2,209,266	1,592,362	1,228,067	990,506		2,027,131

Notes:
(1)	Total values may not add due to rounding.
(2)	Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2023.
(3)	Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2022.
(4)	Cash flows are reduced for future abandonment costs and estimated capital for future development associated with the reserves.
Reserve Definitions:
(a)	"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(b)	"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(c)	"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
(d)	"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(e)	"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
(f)	"Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

Reconciliations of Changes in Reserves

The following table sets out a reconciliation of the changes in the Corporation's reserves as at December 31, 2023 against such reserves at December 31, 2022 based on forecast prices and cost assumptions:

	Light and Medium Oil					Natural Gas Liquids
	Gross Proved	Gross Probable	Gross Proved Plus Probable			Gross Proved	Gross Probable			Gross Proved Plus  Probable
	(Mstb)	(Mstb)	(Mstb)			(Mstb)	(Mstb)			(Mstb)
Opening Balance	18,529.2	12,141.0	30,670.2			17,629.6	12,287.2			29,916.8
Production	-844.6	0.0	-844.6			-876.8	0.0			-876.8
Technical Revisions	-1,797.0	-1,850.5	-3,647.5			1,918.9	211.4			2,130.3
Extensions	1,480.6	-147.8	1,332.8			1,094.6	-82.4			1,012.3
Economic Factors	-544.4	-156.8	-701.2			-187.0	-106.1			-293.1
Closing Balance	16,823.7	9,985.9	26,809.7			19,579.3	12,310.3			31,889.5
	Conventional Gas				Shale Gas
	Gross Proved	Gross Probable	Gross Proved Plus Probable		Gross Proved			Gross Probable	Gross Proved Plus Probable
	(MMcf)	(MMcf)	(MMcf)		(Mboe)			(Mboe)	(Mboe)
Opening Balance	296,461.7	195,555.1	492,016.8		5,786.3			7,692.1	13,478.4
Production	-16,050.2	0.0	-16,050.2		-70.1			0.0	-70.1
Technical Revisions	59,125.1	19,586.8	78,712.0		127.6			162.6	290.2
Extensions	20,422.3	-1,537.0	18,885.3		0.0			0.0	0.0
Economic Factors	-3,381.9	-1,772.1	-5,154.0		-66.0			-75.2	-141.2
Closing Balance	356,577.0	211,832.9	568,409.9		5,777.7			7,779.6	13,557.3
	MBOE
	Gross Proved	Gross Probable	Gross Proved Plus Probable
	(Mboe)	(Mboe)	(Mboe)
Opening Balance	86,533.5	58,302.7	144,836.2
Production	-4,408.1	0.0	-4,408.1
Technical Revisions	9,997.4	1,652.5	11,649.8
Extensions	5,978.9	-486.4	5,492.7
Economic Factors	-1,306.1	-570.8	-1,876.8
Closing Balance	96,795.5	58,898.3	155,693.7

Forecast Prices Used in Estimates

The forecast price and market forecasts prepared by Deloitte are based on information available from numerous government agencies, industry publication, oil refineries, natural gas marketers, and industry trends. The prices are Deloitte's best estimate of how the future will look, based on the many uncertainties that exist in both the domestic Canadian and international petroleum industries. Deloitte considers the current monthly trends, the actual and trends for the year to date, and the prior year actual in determining the forecast. The crude oil and natural gas forecasts are based on yearly variable factors weighted to higher percent in current data and reflecting a higher percent to the prior year historical. These forecasts are Deloitte's interpretation of current available information and while they are considered reasonable, changing market conditions or additional information may require alteration from the indicated effective date.

Inflation forecasts and exchange rates, an integral part of the forecast, have also been considered.

	Price Inflation Rate	Cost Inflation Rate	Cdn to US Exchange Rate
2024	0.0 %	0.0 %	0.74
2025	2.0 %	2.0 %	0.77
2026	2.0 %	2.0 %	0.80
2027	2.0 %	2.0 %	0.80
2028 beyond	2.0 %	2.0 %	0.80

Oil, NGL, and natural gas base case prices, utilized by Deloitte in the Deloitte Reserve Report were as follows:

	Oil		Natural Gas		Natural Gas Liquids
Year	WTI Cushing (Oklahoma)	Edmonton City Gate 40° API	Alberta Reference – Gas Prices	Alberta AECO – Gas Prices	Pentanes + Condensate Edmonton	Butanes Edmonton	Propane Edmonton
	($US/bbl)	($Cdn/bbl)	($Cdn/mcf)	($Cdn/mcf)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/bbl)
Forecast
2024	72.00	91.90	2.10	2.35	91.90	41.35	32.15
2025	71.40	88.75	3.05	3.30	88.75	44.35	35.50
2026	70.75	84.55	3.65	3.90	84.55	42.30	33.80
2027	72.15	86.20	3.70	4.00	86.20	43.15	34.50
2028	73.60	87.95	3.80	4.05	87.95	44.00	35.20
Escalation of 2.0% Thereafter

Notes:
•	All prices are in Canadian dollars except WTI which are in U.S. dollars.
•	Edmonton City Gate prices based on light sweet crude posted at major Canadian refineries (40 Deg. API <0.5% Sulphur).
•	Natural Gas Liquid prices are forecasted at Edmonton therefore an additional transportation cost must be included to plant gate sales point.
•	1 Mcf is equivalent to 1 mmbtu.
•	Alberta gas prices, except AECO, include an average cost of service to the plant gate.

Finding and Development Costs

Yangarra's F&D costs for 2023, 2022 and the five-year average are presented in the tables below. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions.

Proved Developed Producing Finding & Development Costs ($ millions)

	2023	2022	2019-2023
Capital expenditures	94	109	464
Reserve additions, net production (Mboe)	16,113	10,732	34,428
Proved Developed Producing F&D costs – including future capital ($/boe)	5.85	10.16	13.48
Proved Recycle Ratio ($26.72/boe annual operating netback)	4.57	4.73

Proved Finding & Development Costs ($ millions)

	2023	2022	2019-2023
Capital expenditures	94	109	464
Change in future capital	15	-38	27
Total capital for F&D	109	71	491
Reserve additions, net production (Mboe)	14,618	7,786	41,109
Proved F&D costs – including future capital ($/boe)	7.49	9.12	11.96
Proved F&D costs – excluding future capital ($/boe)	6.45	14.00	11.29
Proved Recycle Ratio
Including future capital	3.57	5.27
Excluding future capital	4.14	3.43

Proved plus Probable Finding & Development Costs ($ millions)

	2023	2022	2019-2023
Capital expenditures	94	109	464
Change in future capital	24	-50	25
Total capital for F&D	118	59	489
Reserve additions, net production (Mboe)	15,216	7,627	49,212
Proved plus Probable F&D costs – including future capital ($/boe)	7.74	7.78	9.94
Proved plus Probable F&D costs – excluding future capital ($/boe)	6.20	14.29	9.43
Proved plus Probable Recycle Ratio
Including future capital	3.45	6.17
Excluding future capital	4.31	3.36

Net Asset Value ("NAV")

As at December 31, 2023	PDP	Total Proved	Proved + Probable
Present Value Reserves, before tax (discounted at 10%)	504.1	1,134.9	1,592.4
Total Net Debt ($ million) (unaudited)	(118.6)	(118.6)	(118.6)
Proceeds from the exercise of options (2)	8.2	8.2	8.2
Net Asset Value	393.6	1,024.5	1,482.4
Fully diluted common shares outstanding (million)	104.0	104.0	104.0
Net asset value per share	3.79	9.85	14.25

Notes to table:
(1)	The preceding table shows what is customarily referred to as a "produce out" net asset value calculation under which the current value of Yangarra's reserves would be produced at the Deloitte forecast future prices and costs. The value is a snapshot in time as at December 31, 2023 and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. In this analysis, the present value of the proved and probable reserves is calculated at a before tax 10 percent discount rate.
(2)	The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are "in-the-money" based on the closing price of YGR of $1.28 as at December 31, 2023.
(3)	Net debt or adjusted working capital (deficit), which represent current assets less current liabilities, excluding current derivative financial instruments, are used to assess efficiency, liquidity and the general financial strength of the Company. There is no IFRS measure that is reasonably comparable to net debt or adjusted working capital (deficit).

Annual General Meeting of Shareholders

The Company's Annual General Meeting of Shareholders is scheduled for 10:00 AM on Wednesday May 1, 2024 in the Tillyard Management Conference Centre, Main Floor, 715 5th Avenue SW, Calgary, AB.

Year End Disclosure

The Company's December 31, 2023 audited consolidated financial statements, management's discussion and analysis and annual information form have been filed on SEDAR+ (www.sedarplus.ca) and are available on the Company's website (www.yangarra.ca).

Oil and Gas Advisories

Natural gas has been converted to a barrel of oil equivalent (boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore boes may be misleading if used in isolation. Figures that are presented on a boe basis herein are calculated as the total aggregate amount for the period divided by boe production volumes for the period. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas.

This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "operating netback" and "operating margins". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. For additional information regarding netbacks and operating margins, see "Non-IFRS Financial Measures".

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Yangarra's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from metrics presented in this press release, should not be relied upon for investment or other purposes.

Non-IFRS Financial Measures

This press release contains various specified financial measures that do not have standardized meanings as prescribed by International Financial Reporting Standards ("IFRS").  These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used.  Readers are cautioned that such financial measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of the Company's performance.  These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations and should not be considered in isolation.

Please refer to the management discussion and analysis for the year ended December 31, 2023, for further discussion on the Non-IFRS financial measures presented in this press release.

Funds flow from operations

Funds flow from operations ("FFO") should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with IFRS, as an indicator of Yangarra's performance or liquidity. Management uses FFO to analyze operating performance and leverage and considers FFO to be a key measure as it demonstrates the Company's ability to generate cash flow necessary to fund future capital investments and to repay debt, if applicable. FFO is calculated using cash flow from operating activities before changes in non-cash working capital and decommissioning costs incurred.

The following table reconciles FFO to cash flow from operating activities, which is the most directly comparable measure calculated in accordance with IFRS:

	2023		2022		Year Ended
	Q4	Q3	Q4		2023	2022
Cash flow from operating activities	$         16,798	$        25,995	$         40,676		$         99,033	$       169,664
Decommissioning costs incurred	488	-	291		488	291
Changes in non-cash working capital	266	2,999	841		(497)	7,238
Funds flow from operations	$         17,552	$        28,994	$         41,808		$         99,024	$       177,194

Yangarra presents FFO per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of net income per share. 

Funds from operations netback is calculated on a per boe basis.

Adjusted EBITDA

Yangarra defines Adjusted EBITDA as earnings before interest, taxes, depletion and depreciation, which represents EBITDA, excluding changes in the fair value of commodity contracts. Management believes that Adjusted EBITDA is a useful measure, which provides an indication of the results generated by the Yangarra's primary business activities prior to consideration of how those activities are financed, amortized or taxed. The most directly comparable IFRS financial measure to Adjusted EBITDA is net income (loss). The following table provides a reconciliation of Adjusted EBITDA to net income (loss). 

	2023		2022		Year Ended
	Q4	Q3	Q4		2023	2022
Net income for the Period	$         12,435	$        11,487	$         25,071		$         46,664	$       106,358
Finance	3,293	3,386	3,520		12,898	11,591
Deferred tax expense	3,671	3,670	6,004		16,515	31,387
Depletion and depreciation	9,385	10,182	10,167		39,438	37,659
Change in fair value of commodity contracts	(1,755)	2,889	(35)		449	(36)
Gain on settlemt of lawsuit	(6,957)	-	-		(6,957)	-
Adjusted EBITDA	$         20,072	$        31,614	$         44,727		$       109,007	$       186,959

Adjusted Net Debt 

Yangarra defines Adjusted net debt as the sum of our existing credit facilities, trade and other payables, and trade receivables and prepaids. Yangarra uses Adjusted net debt to assess efficiency, liquidity and the general financial strength of the Company. The most directly comparable IFRS financial measure to Adjusted net debt is Bank Debt. The following table provides a calculation of adjusted net debt.

	Dec 31, 2023	Dec 31, 2022
Bank Debt	$       121,057	$       139,405
Accounts receivable	(30,092)	(31,950)
Prepaid expenses and inventory	(8,918)	(8,809)
Accounts payable and accrued liabilities	36,599	35,718
Adjusted net Debt	$       118,646	$       134,364

Adjusted net debt to third quarter annualized FFO

Adjusted net debt to fourth quarter annualized FFO is a non-GAAP financial ratio calculated as adjusted net debt divided by fourth quarter annualized FFO.

Netbacks

The Company considers corporate netbacks to be a key measure that demonstrates Yangarra's profitability relative to current commodity prices. Corporate netbacks are comprised of operating, field operating, FFO and net income (loss) netbacks. 

Yangarra calculates Field Operating netback as the average sales price of its commodities (including realized gains (losses) on financial instruments) less royalties, operating costs and transportation expenses. Operating netback starts with Field Operating netback and subtracts realized gains (losses) on financial instruments. FFO netback starts with the Operating netback and further deducts general and administrative costs, finance expense and adds finance income. To calculate the net income (loss) netback, Yangarra takes the Operating netback and deducts share-based compensation expense as well as depletion and depreciation charges, accretion expense, unrealized gains (losses) on financial instruments, any impairment or exploration and evaluation expense and deferred income taxes.

FFO margins and operating margins

FFO margins and operating margins are calculated as the ratio of FFO netbacks to sales price and operating netback to sales price, respectively.

Forward Looking Information

This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including, but not limited to, statements on potential completion techniques being considered. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

The forward-looking information is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; benefits to shareholders of our programs and initiatives, the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labour and services; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions, ability to market oil and natural gas successfully and our ability to access capital.

Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Yangarra can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedarplus.com).

These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

All reference to $ (funds) are in Canadian dollars.

Neither the TSX nor its Regulation Service Provider (as that term is defined in the Policies of the TSX) accepts responsibility for the adequacy and accuracy of this release.  

SOURCE Yangarra Resources Ltd.

Cision

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