CALGARY, Alberta, Feb. 29, 2024 (GLOBE NEWSWIRE) — Parex Resources Inc. (“Parex” or the “Company”) (TSX: PXT) is pleased to announce its financial and operating results for the three- and twelve-month periods ended December 31, 2023, as well as the results of its independent reserves assessment as at December 31, 2023. Additionally, the Company announces that it has resumed full operations at its Capachos and Arauca Blocks in the Northern Llanos, as well as the declaration of its Q1 2024 regular dividend of C$0.375 per share.

All amounts herein are in United States dollars (“USD”) unless otherwise stated.

“In 2023, we achieved record production, successfully replaced 100% of PDP reserves, and delivered excellent safety performance – thanks to the collective efforts of the Parex team,” commented Imad Mohsen, President & Chief Executive Officer.

“While we encountered some headwinds during the year, we approach 2024 with confidence in base production from our core SOCA assets, optimism about near-term growth and upside potential in Arauca, and continue to be focused on high grading our portfolio and delivering meaningful exploitation and exploration volumes.”

Key Highlights

• Generated annual funds flow provided by operations (“FFO”) of $668 million⁽¹⁾ and free funds flow (“FFF”) of $184 million⁽²⁾ in 2023.
• Achieved record production per share, up 12% compared to 2022⁽⁶⁾.
• Replaced approximately 100% of proved developed producing (“PDP”) reserves and grew PDP reserves per share (on a boe basis) by 5% over 2022⁽³⁾.
• Resumed full operations at Capachos⁽⁴⁾ and Arauca⁽⁵⁾ on February 25, 2024; FY 2024 average production guidance midpoint of 57,000 boe/d is unchanged.
• Returned $224 million to shareholders in 2023; cumulatively, returned over C$1.5 billion to shareholders over the past five years through dividends and share repurchases.
• Declared a Q1 2024 regular dividend of C$0.375 per share⁽⁶⁾ or C$1.50 per share annualized; current dividend yield is roughly 6.8%⁽⁶⁾.
• Commenced a current normal course issuer bid (“NCIB”) on January 22, 2024; in 2023, the Company repurchased roughly 5% of its outstanding shares.

2023 Fourth Quarter Results

• Record average production of 57,329 boe/d⁽⁷⁾, an increase of 6% over Q4 2022 and 5% over Q3 2023.
• Realized net income of $134 million or $1.28 per share basic⁽⁸⁾.
• Generated FFO of $193 million⁽¹⁾ and FFO per share of $1.85⁽⁸⁾⁽⁹⁾.
• Produced an operating netback of $41.79/boe⁽⁹⁾ and an FFO netback of $36.81/boe⁽⁹⁾ from an average Brent price of $82.90/bbl.
• Incurred $91 million⁽²⁾ of capital expenditures, participating in the drilling of 11 gross (8.30 net) wells.
• As at December 31, 2023, cash was $140 million and working capital surplus $79 million⁽¹⁾; working capital was supplemented by the Company’s secured credit facility that had $90 million drawn as at year-end due to the timing of vendor payments and oil sale collections at the end of the quarter.

2023 Full-Year Results

• Record average production of 54,356⁽⁷⁾ boe/d, up 4% over 2022.
• Realized net income of $459 million or $4.32 per share basic⁽⁸⁾.
• Generated FFO of $668 million⁽¹⁾ and FFO per share of $6.29⁽⁸⁾⁽⁹⁾.
• Produced an operating netback of $44.84/boe⁽⁹⁾ and an FFO netback of $33.59/boe⁽⁹⁾ from an average Brent price of $82.18/bbl.
• Incurred $483 million⁽²⁾ of capital expenditures, participating in the drilling of 59 gross (43.6 net) wells.
• Paid $119 million or C$1.50 per share⁽⁶⁾⁽⁸⁾ in regular dividends and repurchased $105 million worth of shares.

2023 Year-End Corporate Reserves Report: Highlights⁽³⁾

For the year ended December 31, 2023, the Company:

• Generated a PDP reserves replacement ratio of approximately 100%, with 2023 production of approximately 19.8 mmboe and reserve additions of 19.7 mmboe.
• Grew PDP reserves per share (on a boe basis) by 5% compared to 2022.
• Attained growth in PDP after-tax net asset value (“NAV”) per share to C$22.40^(9)(10), which was 5% higher than 2022.
• Increased Q4 2023 average production by approximately 6% over the comparative quarter and maintained a year-over-year PDP reserve life index of approximately four years.
• Proved (“1P”) and proved plus probable (“2P”) reserve volumes were down 14% and 16%, respectively, compared to 2022.
  • Reserves were lower primarily due to technical revisions, which were focused on asset impairment on non-core blocks in the middle Magdalena, as well as LLA-34⁽¹¹⁾ on delineation underperformance.
• Added approximately four million of 2P reserves from the Arauca-8 well⁽⁵⁾; in 2024, Parex plans to test the remaining zones of the well and conduct appraisal drilling on the block to better understand the extent of the reservoir.
• Grew PDP, 1P and 2P after-tax NAV per boe by 2%^(9)(10), 8%^(9)(10) and 6%^(9)(10), respectively, when compared to 2022.

(1) Capital management measure. See “Non-GAAP and Other Financial Measures Advisory.”
(2) Non-GAAP financial measure. See “Non-GAAP and Other Financial Measures Advisory.”
(3) See “2023 Year-End Corporate Reserves Report: Discussion of Reserves” for additional information.
(4) Capachos: 50% W.I.
(5) Arauca: Business Collaboration Agreement with Ecopetrol S.A. (Parex 50% Participating Share); Ecopetrol S.A. currently holds 100% of the working interest in the Convenio Arauca while the assignment procedure is pending.
(6) Supplementary financial measure. See “Non-GAAP and Other Financial Measures Advisory.”
(7) See “Operational and Financial Highlights” for a breakdown of production by product type.
(8) Based on weighted-average basic shares for the period.
(9) Non-GAAP financial ratio. See “Non-GAAP and Other Financial Measures Advisory.”
(10) Discounted at 15% and using the GLJ Brent forecast.
(11) LLA-34: 55% W.I.

Operational and Financial Highlights	Three Months Ended						Year Ended
	Dec. 31,		Dec. 31,		Sep. 30,		December 31,
	2023		2022		2023		2023		2022		2021
Operational
Average daily production
Light Crude and Medium Crude Oil (bbl/d)	9,700		10,511		8,837		8,417		7,471		6,831
Heavy Crude Oil (bbl/d)	46,760		42,746		44,779		45,163		43,008		38,449
Crude oil (bbl/d)	56,460		53,257		53,616		53,580		50,479		45,280
Conventional Natural Gas (mcf/d)	5,214		6,000		5,742		4,656		9,420		10,308
Oil & Gas (boe/d)(1)	57,329		54,257		54,573		54,356		52,049		46,998
Operating netback ($/boe)
Reference price – Brent ($/bbl)	82.90		88.63		85.92		82.18		99.04		70.95
Oil and gas sales(4)	71.12		74.81		75.98		71.00		86.88		60.97
Royalties(4)	(12.12	)	(12.88	)	(13.72	)	(12.31	)	(17.68	)	(9.12	)
Net revenue	59.00		61.93		62.26		58.69		69.20		51.85
Production expense(4)	(13.67	)	(7.14	)	(9.73	)	(10.42	)	(6.90	)	(6.29	)
Transportation expense(4)	(3.54	)	(3.50	)	(3.56	)	(3.43	)	(3.24	)	(3.03	)
Operating netback ($/boe)(2)	41.79		51.29		48.97		44.84		59.06		42.53
Funds flow provided by operations netback ($/boe)(2)	36.81		17.02		31.28		33.59		38.50		33.56
Financial ($000s except per share amounts)
Net income	133,783		249,958		119,736		459,309		611,368		303,105
Per share – basic(6)	1.28		2.29		1.13		4.32		5.38		2.42
Funds flow provided by operations(5)	193,377		85,194		157,839		667,782		724,890		577,545
Per share – basic(2)(6)	1.85		0.78		1.49		6.29		6.38		4.61
Capital expenditures(3)	91,419		147,746		156,747		483,343		512,252		272,234
Free funds flow(3)	101,958		(62,552	)	1,092		184,439		212,638		305,311
EBITDA(2)	110,653		213,604		221,271		650,364		953,210		633,280
Adjusted EBITDA(2)	201,345		244,637		225,784		816,815		1,066,040		689,177
Long-term inventory expenditures	(866	)	56,415		(374	)	39,430		140,266		5,001
Dividends paid	29,505		20,108		29,239		118,676		75,491		47,631
Per share – Cdn$(4)(6)	0.375		0.25		0.375		1.50		0.89		0.50
Shares repurchased	22,453		3,206		24,273		105,068		221,464		218,491
Number of shares repurchased (000s)	1,220		220		1,240		5,628		11,821		12,869
Outstanding shares (end of period) (000s)
Basic	103,812		109,112		105,014		103,812		109,112		120,266
Weighted average basic	104,394		109,107		105,621		106,247		113,572		125,210
Diluted(8)	104,502		109,939		105,722		104,502		109,939		121,600
Working capital surplus(5)	79,027		84,988		(57,511	)	79,027		84,988		325,780
Bank debt(7)	90,000		—		—		90,000		—		—
Cash	140,352		419,002		34,548		140,352		419,002		378,338

(1)  Reference to crude oil or natural gas in the above table and elsewhere in this press release refer to the light and medium crude oil and heavy crude oil and conventional natural gas, respectively, product types as defined in National Instrument 51-101 – Standard of Disclosure for Oil and Gas Activities.
(2)  Non-GAAP ratio. See “Non-GAAP and Other Financial Measures Advisory”.
(3)  Non-GAAP financial measure. See “Non-GAAP and Other Financial Measures Advisory” for the composition of such measure.
(4)  Supplementary financial measure. See “Non-GAAP and Other Financial Measures Advisory” for the composition of such measure.
(5)  Capital management measure. See “Non-GAAP and Other Financial Measures Advisory”.
(6)  Per share amounts (with the exception of dividends) are based on weighted average common shares.
(7)  Borrowing limit of $200.0 million as of December 31, 2023.
(8)  Diluted shares as stated include the effects of common shares and stock options outstanding at the period-end. The December 31, 2023 closing stock price was C$24.95 per share.

Guidance Update

Parex’s FY 2024 average production guidance of 54,000 to 60,000 boe/d (57,000 boe/d midpoint) and capital expenditures of $390 to $430 million ($410 million midpoint) remain unchanged.

Operational Update

Northern Llanos – Capachos and Arauca Update⁽¹⁾⁽²⁾

Parex has resumed activity in the Northern Llanos following social protests that required the Company to shut in its Capachos Block and halt drilling and testing operations at the Arauca Block. Full operations are proceeding with:

• Arauca-8 well currently testing the remaining zones in the Guadalupe formation;
• Drilling the Arauca-15 sidetrack; and
• Capachos average production is roughly 3,800 boe/d (net) and is expected to further increase throughout the remainder of the current quarter.

Corporately, the shut-ins were limited to the Capachos and Arauca Blocks and are expected to affect Parex’s Q1 2024 results. The net production of Capachos was approximately 5,000 boe/d before the suspension of operations. Additionally, there is an Arauca impact from the delayed pace of drilling and testing operations.

(1) Capachos: 50% W.I.
(2) Arauca: Business Collaboration Agreement with Ecopetrol S.A. (Parex 50% Participating Share); Ecopetrol S.A. currently holds 100% of the working interest in the Convenio Arauca while the assignment procedure is pending.

Cabrestero and LLA-34 – Waterflood Injection Performance and Polymer Pilot Update⁽¹⁾⁽²⁾

The waterflood injection programs are advancing successfully at both Cabrestero and LLA-34, affirming their effectiveness in improving reservoir recovery. So far in 2024, the blocks are demonstrating strong base production and outperforming Management’s expectations.

In late 2023, polymer injection began at Cabrestero. The polymer injection process has been successfully completed and the Company has implemented a comprehensive monitoring program for two well patterns. This program is designed to capture the reservoir response and validate the technology’s efficacy in accelerating oil production and enhancing sweep efficiency. The Company expects preliminary results in H2 2024.

(1) Cabrestero: 100% W.I.
(2) LLA-34: 55% W.I.

Big ‘E’ Exploration – High-Impact Targets with Transformational Potential

The Arantes well at LLA-122⁽¹⁾ is targeting gas and condensate in the high-potential Foothills trend of Colombia, where historical pool sizes have been significant. This prospect was spud in early January 2024 and is expected to reach a total depth of approximately 18,000 feet in Q2 2024.

Parex continues to progress the pre-drill work for the Hydra well at VIM-1⁽²⁾, which is expected to spud mid-year 2024.

(1) LLA-122: 50% W.I.
(2) VIM-1: 50% W.I.

Sustainability Update

Parex continues to be recognized as a top-tier ESG performer:

• ESG industry top-rated company by Sustainalytics;
• In the Jantzi Social Index;
• One of three Canadian-listed exploration and production companies included in the 2024 Bloomberg Gender-Equality Index; and
• Maintained a rating of “AA” through Morgan Stanley Capital International (“MSCI”).

Notably in 2023, the Company made significant social investments through both direct community investment and the Colombian national government’s Work for Taxes program. The Work for Taxes program enables corporations to undertake infrastructure projects for a direct reduction in their tax liabilities to support local communities and to date, Parex has been granted approximately $70 million of projects under this program. In 2023, over $15 million was invested through the Work for Taxes initiative, with an additional approximately $5 million invested directly in communities.

Parex plans to issue its tenth annual sustainability report, alongside its third integrated Task Force on Climate-Related Financial Disclosures (“TCFD”), in early Q3 2024.

Tax Update

Starting with the 2023 tax year, Colombia introduced an income surtax that is linked to the historical Brent oil price over 10 years. Following December 31, 2023, the income surtax to be used for the 2023 tax year was confirmed. For Parex’s 2023 current tax expense, the Company’s forecast and tax provisions were completed at 15%, and came in lower than expected at 10%, which positively benefited 2023 current tax expense.

For 2024, the Company is currently assuming a 10% income surtax based on current commodity prices.

Return of Capital

Q1 2024 Dividend

Parex’s Board of Directors has approved a Q1 2024 regular dividend of C$0.375 per share to be paid on March 28, 2024, to shareholders of record on March 15, 2024.

This quarterly dividend payment to shareholders is designated as an “eligible dividend” for purposes of the Income Tax Act (Canada).

Normal Course Issuer Bid Update

As at February 28, 2024, Parex has repurchased approximately 0.5 million shares under its current NCIB at an average price of C$21.88 per share, for a total consideration of roughly C$12 million.

In 2023, Parex repurchased 5.6 million shares, representing approximately 5% of the public float and a return of C$142 million to shareholders.

2023 Year-End Corporate Reserves Report: Discussion of Reserves

The following tables summarize information contained in the independent reserves report prepared by GLJ Ltd. (“GLJ”) dated February 29, 2024 with an effective date of December 31, 2023 (the “GLJ 2023 Report”). All December 31, 2023 reserves presented are based on GLJ’s forecast pricing effective January 1, 2024; all December 31, 2022 reserves presented are based on GLJ’s forecast pricing effective January 1, 2023 and all December 31, 2021 reserves presented are based on GLJ’s forecast pricing effective January 1, 2022. GLJ pricing is available on their website at www.gljpc.com.

All reserves are presented as Parex working interest before royalties and in certain tables set forth below, the columns may not add due to rounding. Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2023 fiscal year, which will be filed on SEDAR+ by March 1, 2024.

Gross Reserves Volumes

		Dec. 31
		2021	2022	2023	Change over Dec. 31,
Reserve Category		Mboe	Mboe	Mboe(1)	2022
Proved Developed Producing (PDP)		80,559	82,788	82,628	—	%
Proved Developed Non-Producing		9,685	11,767	7,252	(38	%)
Proved Undeveloped		35,022	36,100	22,647	(37	%)
Proved (1P)		125,266	130,655	112,528	(14	%)
Proved + Probable (2P)		198,825	200,704	168,625	(16	%)
Proved + Probable + Possible (3P)		286,927	281,595	231,299	(18	%)

(1) 2023 net reserves after royalties are: PDP 70,893 Mboe, proved developed non-producing 6,571 Mboe, proved undeveloped 19,932 Mboe, 1P 97,396 Mboe, 2P 146,385 Mboe and 3P 201,245 Mboe.

Gross Reserves Reconciliation Company

		Total 1P		Total 2P		Total 3P
		Mboe		Mboe		Mboe
December 31, 2022		130,655		200,704		281,595
Technical Revisions(1)		(4,092	)	(18,277	)	(38,553	)
Discoveries(2)		3,594		5,516		7,802
Infill Drilling(3)		1,636		—		—
Extensions and Improved Recovery(4)		575		521		295
Production		(19,840	)	(19,840	)	(19,840	)
December 31, 2023(5)		112,528		168,625		231,299

(1) Reserves technical revisions are associated with the evaluations of Aguas Blancas, Fortuna, LLA-34, Arauca, Cabrestero, and VIM-1.
(2) Discoveries are associated with the evaluations of Arauca, Cabrestero, and LLA-81.
(3) Infill drilling is associated with the evaluation of LLA-34.
(4) Reserve extensions and improved recovery are associated with the evaluation of Capachos.
(5) The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Reserves Net Present Value After Tax Summary – GLJ Brent Forecast⁽¹⁾⁽²⁾

		NPV15		NPV15		NAV
		December 31,		December 31,		December 31,		CAD/sh Change over
			2022		2023		2023	Dec. 31,
Reserve Category		(000s)(2)		(000s)(2)		(CAD/sh)(3)		2022
Proved Developed Producing (PDP)		$	1,637,116	$	1,679,078	$	22.40	5	%
Proved Developed Non-Producing			167,478		112,298	$	2.44	(22	%)
Proved Undeveloped			338,167		201,380	$	3.57	(32	%)
Proved (1P)		$	2,142,761	$	1,992,757	$	26.40	(5	%)
Proved + Probable (2P)		$	2,877,365	$	2,556,169	$	33.57	(9	%)
Proved + Probable + Possible (3P)		$	3,641,269	$	3,191,329	$	41.67	(10	%)

(1) Net present values (“NPV”) are stated in USD and are discounted at 15 percent. The forecast prices used in the calculation of the present value of future net revenue are based on the GLJ January 1, 2023 and GLJ January 1, 2024 price forecasts, respectively. The GLJ January 1, 2024 price forecast will be included in the Company’s Annual Information Form for the 2023 fiscal year.
(2) Includes future development capital (“FDC”) as at December 31, 2022 of $40 million for PDP, $492 million for 1P, $620 million for 2P and $707 million for 3P and FDC as at December 31, 2023 of $27 million for PDP, $346 million for 1P, $537 million for 2P and $609 million for 3P.
(3) NAV is calculated, as at December 31, 2023, as after tax NPV15 plus estimated working capital of USD$79M (converted at USDCAD=1.3226), divided by 104 million basic shares outstanding as at December 31, 2023. NAV per share is a Non-GAAP ratio.

Q4 2023 and FY 2023 Results – Conference Call & Video Webcast

Parex will host a conference call and video webcast to discuss its Q4 2023 and FY 2023 results on Friday, March 1, 2024, beginning at 9:30 am MT (11:30 am ET). To participate in the conference call or video webcast, please see the access information below:

Conference ID:		1 335 335
Participant Toll-Free Dial-In Number:		1-888-550-5584
Participant International Dial-In Number:		1-646-960-0157
Webcast:		https://events.q4inc.com/attendee/294536382

2023 Annual General Meeting

Parex anticipates holding its Annual General and Special Meeting of Shareholders on Thursday, May 9, 2024.

About Parex Resources Inc.

Parex is the largest independent oil and gas company in Colombia, focusing on sustainable, conventional production. Parex’s corporate headquarters are in Calgary, Canada, and the Company has an operating office in Bogotá, Colombia. Parex is a member of the S&P/TSX Composite ESG Index and its shares trade on the Toronto Stock Exchange under the symbol PXT.

For more information, please contact:

Mike Kruchten
Senior Vice President, Capital Markets & Corporate Planning
Parex Resources Inc.
403-517-1733
[email protected]
Steven Eirich
Investor Relations & Communications Advisor
Parex Resources Inc.
587-293-3286
[email protected] 

NOT FOR DISTRIBUTION OR FOR DISSEMINATION IN THE UNITED STATES

Reserves Advisory

The recovery and reserve estimates of crude oil reserves provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may eventually prove to be greater than, or less than, the estimates provided herein. All December 31, 2023 reserves presented are based on GLJ’s forecast pricing effective January 1, 2024. All December 31, 2022 reserves presented are based on GLJ’s forecast pricing effective January 1, 2023. All December 31, 2021 reserves presented are based on GLJ’s forecast pricing effective January 1, 2022.

Comparatives to the independent reserves report prepared by GLJ dated February 2, 2023 with an effective date of December 31, 2022 (the “GLJ 2022 Report”), and the independent reserves report prepared by GLJ dated February 3, 2022 with an effective date of December 31, 2021 (“GLJ 2021 Report”, and collectively with the GLJ 2023 Report and the GLJ 2022 Report, the “GLJ Reports”). Each GLJ Report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves.

“Proved 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.

“Proved 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.

“Proved Undeveloped Reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. 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 category (proved, probable, possible) to which they are assigned.

“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.

“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.

“Possible” reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

The term “Boe” means a barrel of oil equivalent on the basis of 6 Mcf of natural gas to 1 barrel of oil (“bbl”). Boe’s may be misleading, particularly if used in isolation. A boe conversation ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio at 6:1 may be misleading as an indication of value.

Light crude oil is crude oil with a relative density greater than 31.1 degrees API gravity, medium crude oil is crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity, and heavy crude oil is crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity.

With respect to F&D 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 F&D costs related to reserve additions for that year. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

This press release contains several oil and gas metrics, including reserve replacement, reserve additions including acquisitions, and reserve life index (“RLI”). In addition, the following non-GAAP financial measures and non-GAAP ratios, as described below under “Non-GAAP and Other Financial Measures”, can be considered to be oil and gas metrics: F&D costs, FD&A costs, F&D recycle ratio, FD&A recycle ratio, operating netback, funds flow provided by operations, funds flow provided by operations netback, reserve replacement and NAV.   Such oil and gas metrics have been prepared by management and do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metric should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide security holders with measures to compare the Company’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes. A summary of the calculations of reserve replacement and RLI are as follows, with the other oil and gas metrics referred to above being described herein under “Non-GAAP and Other Financial Measures”:

• Reserve replacement is calculated by dividing the annual reserve additions by the annual production.

• Reserve additions including acquisitions is calculated by the change in reserves category and adding current year annual production.

• RLI is calculated by dividing the applicable reserves category by the annualized fourth quarter average production.

2023 Year-End Corporate Reserves Report: Supplemental Reserves Tables

All reserves are presented as Parex working interest before royalties and in certain tables set forth below, the columns may not add due to rounding.

Gross Reserves by Area⁽¹⁾

		1P	2P	3P
Area		Mboe(1)	Mboe(1)	Mboe(1)
LLA-34		64,621	96,078	125,520
Southern Llanos		22,474	29,242	36,144
Northern Llanos		17,493	25,885	35,297
Magdalena		7,940	17,420	34,338
Total		112,528	168,625	231,299

(1) The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Gross Reserves Volumes by Product Type

Product Type		PDP	1P	2P	3P
Light & Medium Crude Oil (Mbbl)		9,984	26,352	43,683	65,611
Heavy Crude Oil (Mbbl)		70,759	80,871	114,199	145,933
Natural Gas Liquids (Mbbl)		200	1,375	1,963	2,618
Conventional Natural Gas (MMcf)		10,114	23,577	52,677	102,821
Oil Equivalent (Mboe)		82,628	112,528	168,625	231,299

Gross Reserves Volumes Per Share⁽¹⁾

		Dec. 31			Change over Dec. 31, 2022
		2021	2022	2023(1)
Year-End Basic Outstanding Shares (000s)		120.3	109.1	103.8	(5	%)
Proved Developed Producing (PDP) (boe/share)		0.67	0.76	0.80	5	%
Proved (1P) (boe/share)		1.04	1.20	1.08	(10	%)
Proved + Probable (2P) (boe/share)		1.65	1.84	1.62	(12	%)
Proved + Probable + Possible (3P) (boe/share)		2.39	2.58	2.23	(14	%)

(1) 2023 net reserves after royalties are: PDP 70,893 Mboe, proved developed non-producing 6,571 Mboe, proved undeveloped 19,932 Mboe, 1P 97,396 Mboe, 2P 146,385 Mboe and 3P 201,245 Mboe.

Reserve Life Index (“RLI”)

		Dec. 31, 2021(1)	Dec. 31, 2022(2)	Dec. 31, 2023(3)
Proved Developed Producing (PDP)		4.4 years	4.2 years	3.9 years
Proved (1P)		6.9 years	6.6 years	5.4 years
Proved Plus Probable (2P)		10.9 years	10.1 years	8.1 years

(1) Calculated by dividing the amount of the relevant reserves category by average Q4 2021 production of 49,779 boe/d annualized (consisting of 6,376 bbl/d of light crude oil and medium crude oil, 41,534 bbl/d of heavy crude oil and 11,214 mcf/d of conventional natural gas).
(2) Calculated by dividing the amount of the relevant reserves category by average Q4 2022 production of 54,257 boe/d annualized (consisting of 10,511 bbl/d of light crude oil and medium crude oil, 42,746 bbl/d of heavy crude oil and 6,000 mcf/d of conventional natural gas).
(3) Calculated by dividing the amount of the relevant reserves category by estimated average Q4 2023 production of 57,329 boe/d annualized (consisting of 9,700 bbl/d of light crude oil and medium crude oil, 46,760 bbl/d of heavy crude oil and 5,214 mcf/d of conventional natural gas).

Future Development Capital (“FDC”) (000s) – GLJ 2023 Report⁽¹⁾

Reserve Category		2024		2025		2026		2027	2028+		Total FDC		Total FDC/boe
PDP	$	26,788	$	—	$	—	$	—	$	—	$	26,788	$	0.32
1P	$	171,733	$	75,795	$	57,427	$	37,989	$	2,926	$	345,870	$	3.07
2P	$	207,291	$	158,793	$	78,839	$	53,984	$	37,608	$	536,515	$	3.18

(1) FDC are stated in USD, undiscounted and based on GLJ January 1, 2024 price forecasts.

Summary of Reserve Metrics – Company Gross

	2023		3-Year
	PDP	1P	PDP	1P
F&D Costs ($/boe)(1)	23.87	197.09	19.25	33.39
FD&A Costs ($/boe)(1)	23.87	197.09	19.23	32.52
Recycle Ratio – F&D(1)	1.9 x	0.2 x	2.6 x	1.5 x
Recycle Ratio – FD&A(1)	1.9 x	0.2 x	2.6 x	1.5 x

(1) Non-GAAP ratio. See “Non-GAAP and Other Financial Measures Advisory”.

Non-GAAP and Other Financial Measures Advisory

This press release uses various “non-GAAP financial measures”, “non-GAAP ratios”, “supplementary financial measures” and “capital management measures” (as such terms are defined in NI 52-112), which are described in further detail below. Such measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. Investors are cautioned that non-GAAP financial measures should not be construed as alternatives to or more meaningful than the most directly comparable GAAP measures as indicators of Parex’s performance.

These measures facilitate management’s comparisons to the Company’s historical operating results in assessing its results and strategic and operational decision-making and may be used by financial analysts and others in the oil and natural gas industry to evaluate the Company’s performance. Further, management believes that such financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities.

Set forth below is a description of the non-GAAP financial measures, non-GAAP ratios, supplementary financial measures and capital management measures used in this press release.

Non-GAAP Financial Measures

Capital expenditures, is a non-GAAP financial measure which the Company uses to describe its capital costs associated with oil and gas expenditures. The measure considers both property, plant and equipment expenditures and exploration and evaluation asset expenditures which are items in the Company’s statement of cash flows for the period.

	For the three months ended									For the year ended
	December 31,						September 30,			December 31,
($000s)		2023			2022			2023			2023			2022			2021
Property, plant and equipment expenditures	$	50,753		$	111,512		$	93,957		$	310,933		$	389,979		$	212,153
Exploration and evaluation expenditures		40,666			36,234			62,790			172,410			122,273			60,081
Capital expenditures	$	91,419		$	147,746		$	156,747		$	483,343		$	512,252		$	272,234

Free funds flow, is a non-GAAP measure that is determined by funds flow provided by operations less capital expenditures. The Company considers free funds flow or free cash flow to be a key measure as it demonstrates Parex’s ability to fund return of capital, such as the NCIB and dividends, without accessing outside funds and is calculated as follows:

	For the three months ended											For the year ended
	December 31,								September 30,			December 31,
($000s)		2023				2022				2023			2023			2022				2021
Cash provided by operating activities	$	194,242			$	297,569			$	87,568		$	376,471		$	983,602				534,301
Net change in non-cash working capital		(865	)			(212,375	)			70,271			291,311			(258,712	)			43,244
Funds flow provided by operations		193,377				85,194				157,839			667,782			724,890				577,545
Capital expenditures		91,419				147,746				156,747			483,343			512,252				272,234
Free funds flow	$	101,958			$	(62,552	)		$	1,092		$	184,439		$	212,638			$	305,311

EBITDA, is a non-GAAP financial measure that is defined as net income adjusted for finance income and expenses, income tax expense (recovery) and depletion, depreciation and amortization.

Adjusted EBITDA, is a non-GAAP financial measure defined as EBITDA adjusted for non-cash impairment charges, unrealized foreign exchange gains (losses), unrealized gains (losses) on risk management contracts and share-based compensation expense. The Company considers EBITDA and Adjusted EBITDA to be key measures as they demonstrates Parex’s profitability before finance income and expenses, taxes, depletion, depreciation and amortization and other non-cash items. A reconciliation from net income to EBITDA and Adjusted EBITDA is as follows:

	For the three months ended												For the year ended
	December 31,								September 30,				December 31,
($000s)		2023				2022				2023				2023				2022				2021
Net income	$	133,783			$	249,958			$	119,736			$	459,309			$	611,368			$	303,105
Adjustments to reconcile net income to EBITDA:
Finance income		(2,274	)			(4,724	)			(2,496	)			(14,520	)			(9,015	)			(1,608	)
Finance expense		3,240				1,542				5,219				16,416				9,708				9,677
Income tax (recovery) expense		(81,929	)			(77,339	)			49,995				(5,070	)			191,798				200,710
Depletion, depreciation and amortization		57,833				44,167				48,817				194,229				149,351				121,396
EBITDA	$	110,653			$	213,604			$	221,271			$	650,364			$	953,210			$	633,280
Non-cash impairment charges		85,330				26,494				2,189				142,540				103,394				27,000
Share-based compensation expense		7,674				5,101				4,642				30,364				19,128				27,682
Unrealized foreign exchange (gain) loss		(2,312	)			(562	)			(2,318	)			(6,453	)			(9,692	)			1,215
Adjusted EBITDA	$	201,345			$	244,637			$	225,784			$	816,815			$	1,066,040			$	689,177

Non-GAAP Financial Ratios

Operating netback per boe
The Company considers operating netback per boe to be a key measure as they demonstrate Parex’s profitability relative to current commodity prices. Parex calculates operating netback per boe as operating netback divided by the total equivalent sales volume including purchased oil volumes for oil and natural gas sales price and transportation expense per boe and by the total equivalent sales volume and excludes purchased oil volumes for royalties and operating expense per boe.

Funds flow provided by operations netback, is a non-GAAP ratio that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by produced oil and natural gas sales volumes. The Company considers funds flow provided by operations netback to be a key measure as it demonstrates Parex’s profitability after all cash costs relative to current commodity prices.

Finding & Development Costs (F&D costs) per boe and Finding, Development and Acquisition Costs (FD&A costs) per boe, is a non-GAAP ratio that helps to explain the cost of finding and developing additional oil and gas reserves. F&D costs are determined by dividing capital expenditures plus the change in FDC in the period divided by BOE reserve additions in the period. FD&A costs per boe are determined by dividing capital expenditures in the period plus the change in FDC plus acquisition costs divided by BOE reserve additions in the period.

F&D and FD&A Costs(1)	2023					3-Year
($000s)	PDP		1P		PDP	1P
Capital Expenditures(2)	483,343		483,343		1,267,829	1,267,829
Capital Expenditures – change in FDC	(13,650	)	(145,727	)	5,269	7,502
Total Capital	469,693		337,616		1,273,098	1,275,331
Net Acquisitions	—		—		—	—
Net Acquisitions – change in FDC	—		—		1,000	39,800
Total Net Acquisitions	—		—		1,000	39,800
Total Capital including Acquisitions	469,693		337,616		1,274,098	1,315,131
Reserve Additions	19,680		1,713		66,131	38,191
Net Acquisitions Reserve Additions	—		—		116	2,246
Reserve Additions including Acquisitions (Mboe)	19,680		1,713		66,247	40,437
F&D Costs ($/boe)	23.87		197.09		19.25	33.39
FD&A Costs ($/boe)	23.87		197.09		19.23	32.52

(1) All reserves are presented as Parex working interest before royalties.
(2) Calculated using capital expenditures for the period ended December 31, 2023.

Recycle ratio, is a non-GAAP ratio that ratio that measures the profit per barrel of oil to the cost of finding and developing that barrel of oil. The recycle ratio is determined by dividing the annual operating netback per boe by the F&D costs and FD&A costs in the period.

	2023		3-Year
	PDP	1P	PDP	1P
Operating netback ($/boe)	45.00	45.00	49.24	49.24
F&D Costs(2) ($/boe)	23.87	197.09	19.25	33.39
FD&A Costs(2) ($/boe)	23.87	197.09	19.23	32.52
Recycle Ratio – F&D(1)	1.9 x	0.2 x	2.6 x	1.5 x
Recycle Ratio – FD&A(1)	1.9 x	0.2 x	2.6 x	1.5 x

(1) Recycle ratio is calculated as operating netback per boe divided by F&D or FD&A as applicable. Three-year operating netback on a per boe basis is calculated using weighted average sales volumes.

Net Asset Value (“NAV”) per share, is a non-GAAP ratio that combines the 51-101 NPV15 value after tax with the Company’s estimated working capital at the period end date divided by common shares outstanding at the period end date. The Company uses the NAV per share as a way to reflect the Company’s value considering both existing working capital on hand plus the NPV15 after tax value on Oil and Gas Reserves. NAV per share is stated in CAD dollars using an exchange rate of USDCAD=1.3226. NAV is defined as total assets less total liabilities.

Net Asset Value (“NAV”) per boe, is a non-GAAP ratio that combines the 51-101 NPV15 value after tax with the Company’s estimated working capital at the period end date divided by reserve volumes at the period end date. The Company uses the NAV per boe as a way to reflect the Company’s value considering both existing working capital on hand plus the NPV15 after tax value on Oil and Gas Reserves. Net asset value is defined as total assets less total liabilities.

Basic funds flow provided by operations per share is calculated by dividing funds flow provided by operations by the weighted average number of basic shares outstanding. Parex presents basic funds flow provided by operations per share whereby per share amounts are calculated using weighted-average shares outstanding, consistent with the calculation of earnings per share.

Capital Management Measures

Funds flow provided by operations, is a non-GAAP capital management measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows:

	For the three months ended											For the year ended
	December 31,								September 30,			December 31,
($000s)		2023				2022				2023			2023			2022				2021
Cash provided by operating activities	$	194,242			$	297,569			$	87,568		$	376,471		$	983,602			$	534,301
Net change in non-cash working capital		(865	)			(212,375	)			70,271			291,311			(258,712	)			43,244
Funds flow provided by operations	$	193,377			$	85,194			$	157,839		$	667,782		$	724,890			$	577,545

Working capital surplus, is a non-GAAP capital management measure which the Company uses to describe its liquidity position and ability to meet its short term liabilities. Working Capital Surplus is defined as current assets less current liabilities.

	For the three months ended										For the year ended
	December 31,							September 30,			December 31,
($000s)		2023			2022			2023				2023			2022			2021
Current assets	$	337,175		$	593,602		$	240,559			$	337,175		$	593,602		$	574,038
Current liabilities		258,148			508,614			298,070				258,148			508,614			248,258
Working capital surplus (deficit)	$	79,027		$	84,988		$	(57,511	)		$	79,027		$	84,988		$	325,780

Supplementary Financial Measures

“Oil and natural gas sales per boe” is determined by sales revenue excluding risk management contracts, as determined in accordance with IFRS, divided by total equivalent sales volume including purchased oil volumes.

“Royalties per boe” is comprised of royalties, as determined in accordance with IFRS, divided by the total equivalent sales volume and excludes purchased oil volumes.

“Production expense per boe” is comprised of production expense, as determined in accordance with IFRS, divided by the total equivalent sales volume and excludes purchased oil volumes.

“Transportation expense per boe” is comprised of transportation expense, as determined in accordance with IFRS, divided by the total equivalent sales volumes including purchased oil volumes.

“Dividends paid per share” is comprised of dividends declared, as determined in accordance with IFRS, divided by the number of shares outstanding at the dividend record date.

“Dividend yield” is defined as annualized dividends per share dividend by Parex’s share price.

“Production per share growth” is comprised of the Company’s total oil and natural gas production volumes divided by the weighted average number of basic shares outstanding, whereby per share amounts are calculated using weighted-average shares outstanding, consistent with the calculation of earnings per share. Growth is determined in comparison to the comparative year.

Dividend Advisory

The Company’s future shareholder distributions, including but not limited to the payment of dividends and the acquisition by the Company of its shares pursuant to an NCIB, if any, and the level thereof is uncertain. Any decision to pay further dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) or acquire shares of the Company will be subject to the discretion of the Board of Directors of Parex and may depend on a variety of factors, including, without limitation the Company’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on the Company under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the Board. There can be no assurance that the Company will pay dividends or repurchase any shares of the Company in the future.

Advisory on Forward-Looking Statements

Certain information regarding Parex set forth in this document contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words “plan”, “expect”, “prospective”, “project”, “intend”, “believe”, “should”, “anticipate”, “estimate”, “forecast”, “guidance”, “budget” or other similar words, or statements that certain events or conditions “may” or “will” occur are intended to identify forward-looking statements. Such statements represent Parex’s internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. These statements are only predictions and actual events or results may differ materially. Although the Company’s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Parex’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Parex.

In particular, forward-looking statements contained in this document include, but are not limited to, statements with respect to the Company’s operational and financial position; the Company’s plan, strategy and focus; the anticipated terms of the Company’s Q1 2024 quarterly dividend including its expectation that it will be designated as an “eligible dividend”; the Company’s average annual 2024 production guidance; Parex’s anticipated production at the Capachos Block; the anticipated effects of well shut-ins in the Capachos and Arauca Blocks on Parex’s Q1 2024 results; the Company’s expectations of the results of spudding the Arantes well at LLA-122; the anticipated timing of when the Hydra well at VIM-1 will spud; the anticipated timing of when the Company plans to issue its annual sustainability report and TCFD disclosure; Parex’s assumption of income surtax for 2024; the Company’s plans to conduct testing and drilling on the Arauca-8 exploration well; the Company’s expectation that it will continue to utilize its current NCIB; the anticipated timing of when Company will receive preliminary results on the monitoring programs for wells in the Cabrestero Block; anticipated future development capital; the anticipated date and time of Parex’s 2024 Annual General and Special Meeting of Shareholders and the release of its 2023 Annual Information Form; and the anticipated date of Parex’s conference call. In addition, statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. The recovery and reserve estimates of Parex’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to, the impact of general economic conditions in Canada and Colombia; determinations by OPEC and other countries as to production levels; volatility in commodity prices; industry conditions including changes in laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced, in Canada and Colombia; competition; lack of availability of qualified personnel; the results and timelines of exploration and development drilling, test, monitoring and work programs and related activities; obtaining required approvals of regulatory authorities, in Canada and Colombia; risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates; environmental risks; changes in income tax laws or changes in tax laws and incentive programs relating to the oil industry; changes to pipeline capacity; ability to access sufficient capital from internal and external sources; risk that Parex’s evaluation of its existing portfolio of development and exploration opportunities is not consistent with its expectations; that production test results may not necessarily be indicative of long term performance or of ultimate recovery; the risk that the Company may not release its Annual Information Form, sustainability report, TCFD disclosure report or hold its 2024 Annual General and Special Meeting of Shareholders when anticipated; the risk that the Company’s average annual 2024 production (including its production at the Capachos Block) may be less than anticipated; the risk that the well shut-ins in the Capachos and Arauca Blocks may have a greater effect on Parex’s Q1 2024 results than anticipated; the risk that the Hydra well at VIM-1 may not spud when anticipated, or at all; the risk that the Company may not conduct testing and drilling on the Arauca-8 exploration well when anticipated, or at all; the risk that Parex may not have sufficient financial resources in the future to provide distributions to its shareholders; the risk that the Board may not declare dividends in the future or that Parex’s dividend policy changes; and other factors, many of which are beyond the control of the Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Parex’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR+ website (www.sedarplus.ca).

Although the forward-looking statements contained in this document are based upon assumptions which the management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this document, Parex has made assumptions regarding, among other things: current and anticipated commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil, including anticipated Brent oil prices; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; receipt of partner, regulatory and community approvals; royalty rates; effective tax rates on FFO; future operating costs; effects of regulation by governmental agencies; effects of environmental legislation on the Company’s operations and the Company’s ability to comply with such legislation; uninterrupted access to areas of Parex’s operations and infrastructure; recoverability of reserves and future production rates; timing of drilling and completion of wells; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; that Parex will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that Parex’s conduct and results of operations will be consistent with its expectations; that Parex will have the ability to develop its oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of Parex’s reserves and production volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that Parex will be able to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; the impact of community unrest on the Company’s operations; that the Company’s recent actions to help address the heightened security concerns in Colombia will be successful; that Parex will have sufficient financial resources to pay dividends and acquire shares pursuant to its NCIB in the future; and other matters.

Management has included the above summary of assumptions and risks related to forward-looking information provided in this document in order to provide shareholders with a more complete perspective on Parex’s current and future operations and such information may not be appropriate for other purposes. Parex’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Parex will derive. These forward-looking statements are made as of the date of this document and Parex disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

This press release contains information that may be considered a financial outlook under applicable securities laws about the Company’s potential financial position, including, but not limited to: the anticipated terms of the Company’s Q1 2024 quarterly dividend including its expectation that it will be designated as an “eligible dividend”; anticipated future development capital; and the Company’s expectation that it will continue to utilize its current NCIB; all of which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results of operations of the Company and the resulting financial results will vary from the amounts set forth in this press release and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligation to update such financial outlook. The financial outlook contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about the Company’s potential future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.

The following abbreviations used in this press release have the meanings set forth below:

bbl one barrel
bbls barrels
bbls/d barrels per day
boe barrels of oil equivalent of natural gas; one barrel of oil or natural gas liquids for six thousand cubic feet of natural gas
boe/d barrels of oil equivalent of natural gas per day
mbbl thousands of barrels
mboe thousand barrels of oil equivalent
mcf thousand cubic feet
mcf/d thousand cubic feet per day
mmboe one million barrels of oil equivalent
mmcf one million cubic feet
W.I. working interest

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