All amounts herein are in
"In 2023, we achieved record production, successfully replaced 100% of PDP reserves, and delivered excellent safety performance – thanks to the collective efforts of the
"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 overC$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) orC$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 orC$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
- 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. (
(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 | ||||||||||
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 | ||||||
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
(8) Diluted shares as stated include the effects of common shares and stock options outstanding at the period-end. The
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
Operational Update
Northern Llanos - Capachos and Arauca Update(1)(2)
- 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
(1) Capachos: 50% W.I.
(2) Arauca: Business Collaboration Agreement with Ecopetrol S.A. (
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
(1) LLA-122: 50% W.I.
(2) VIM-1: 50% W.I.
Sustainability Update
- 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,
Tax Update
Starting with the 2023 tax year,
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
This quarterly dividend payment to shareholders is designated as an “eligible dividend” for purposes of the Income Tax Act (
Normal Course Issuer Bid Update
As at
In 2023,
2023 Year-End Corporate Reserves Report: Discussion of Reserves
The following tables summarize information contained in the independent reserves report prepared by
All reserves are presented as
Gross Reserves Volumes
2021 | 2022 | 2023 | Change over | |||
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.
Total 1P | Total 2P | Total 3P | |||||
Mboe | Mboe | Mboe | |||||
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 | ) | |
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 | |||||||
CAD/sh Change over | |||||||||
2022 | 2023 | 2023 | |||||||
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
(2) Includes future development capital ("FDC") as at
(3) NAV is calculated, as at
Q4 2023 and FY 2023 Results - Conference Call & Video Webcast
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
About
For more information, please contact:
Senior Vice President, Capital Markets & Corporate Planning
403-517-1733
investor.relations@parexresources.com
Investor Relations & Communications Advisor
587-293-3286
investor.relations@parexresources.com
NOT FOR DISTRIBUTION OR FOR DISSEMINATION IN
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
Comparatives to the independent reserves report prepared by GLJ dated
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
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 | |
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)
Change over | ||||||
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")
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).
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
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
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 | ||||||||||||||||
($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 | |||||||||||||||||||
($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 | ||||||||||||||||||||||
($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.
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 ($/boe) | 23.87 | 197.09 | 19.23 | 32.52 |
(1) All reserves are presented as
(2) Calculated using capital expenditures for the period ended
Recycle ratio, is a non-GAAP ratio that ratio that measures the profit per barrel of oil to the cost of finding and developing that barrel of oil. The recycle ratio is determined by dividing the annual operating netback per boe by the F&D costs and FD&A costs in the period.
2023 | 3-Year | |||
PDP | 1P | PDP | 1P | |
Operating netback ($/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.
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 | |||||||||||||||||||
($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 | |||||||||||||||||
($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
Advisory on Forward-Looking Statements
Certain information regarding
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;
These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to, the impact of general economic conditions in
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,
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
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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