The financial and operational information contained below is based on the Company’s unaudited expected results for the year ended
2019 Year-End Corporate Reserves Report
On a debt adjusted basis, production per share grew 34% and proved plus probable (“2P”) reserves per share increased by 18%. We exited 2019 with working capital of approximately
For the year ended
- Added 27.6 million barrels of oil equivalent ("MMboe") proved developed producing reserves (“PDP”), 36.4 MMboe proved (“1P”) reserves, and 33 MMboe 2P reserves replacing respectively 143%, 189% and 171% of total 2019 production (19.23 MMboe);
- Increased PDP reserves by 13% year-over-year, from 63 MMboe to 71 MMboe (98% crude oil);
- Grew 2P reserves 7% from 185 MMboe to 198 MMboe (97% crude oil);
- Realized PDP finding, development & acquisition (“FD&A”) costs of
$7.63 per barrel of oil equivalent (“boe”), resulting in a 3.8 times funds flow from operations netback recycle ratio using the unaudited 2019 funds flow from operations of$29.30 /boe; - Achieved 2P finding & development costs and 2P FD&A costs of
$7.57 /boe. Using the unaudited 2019 funds flow from operations of$29.30 /boe, the 2P FD&A funds flow from operations netback recycle ratio was 3.9 times; - Realized an after tax 1P net asset value (“NAV”) per share of
C$27.15 and 2P NAV ofC$35.58 per share, discounted at 10% and using the 2019 GLJ Report price forecast; - Using a constant
$60 /bbl Brent oil price, achieved an after tax 1P NAV per share ofC$22.45 and 2P NAV ofC$28.80 per share, discounted at 10%; and - Produced on average approximately 52,687 barrels of oil equivalent per day (“boe/d”), representing a 19% increase over the 2018 daily average production using a conversion of six mcf of gas to barrel of oil. Production consisted of 51,708 barrels of oil per day (“bopd”) and 5,874 Mcf per day (“Mcf/d) of natural gas.
We estimate Q4 2019 production at approximately 54,221 boe/d, up ~2% from Q3 2019, consisting of 53,086 bopd and 6,810 Mcf/d of natural gas.
2019 Year-End Reserves Report: Discussion of Reserves
The following tables summarize information contained in the independent reserves report prepared by
The recovery and reserve estimates provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. In certain of the tables set forth below, the columns may not add due to rounding.
All
Parex’ reserves are located in Colombia’s Llanos and Middle Magdalena basins. Reserve additions in the GLJ 2019 Report were primarily generated from a successful oil exploration and appraisal drilling program.
The Company recorded material reserve increases due to the following corporate activities:
- Exploration discoveries on Boranda, Capachos, LLA-32 and LLA-34; and
- Appraisal and development drilling on Cabrestero, Capachos and LLA-34.
2019 Year-End Gross Reserves Volumes
Change | |||||
Reserves Category | 2017 Mboe(1) | 2018 Mboe(1) | 2019 Mboe (1)(2) | over | |
Proved Developed Producing (PDP) | 50,506 | 62,612 | 70,946 | 13 | % |
Proved Developed Non-Producing | 2,089 | 7,246 | 6,699 | -8 | % |
Proved Undeveloped | 42,930 | 51,835 | 61,180 | 18 | % |
Proved (1P) | 95,525 | 121,693 | 138,825 | 14 | % |
Probable | 66,711 | 62,982 | 59,599 | -5 | % |
Proved + Probable (2P) | 162,236 | 184,674 | 198,423 | 7 | % |
Possible(3) | 78,698 | 77,392 | 62,661 | -19 | % |
Proved + Probable + Possible (3P) | 240,934 | 262,066 | 261,085 | 0 | % |
(1) Mboe is defined as thousand barrels of oil equivalent.
(2) All reserves are presented as
(3) Please refer to the “Reserve Advisory” section for a description of each reserve category. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities recovered will equal or exceed the sum of proved plus probable plus possible reserves.
2019 Gross Reserves by Block
Block | Proved Mboe(1) | Proved+ Probable Mboe(1) | Proved + Probable + Possible(1) Mboe |
Aguas Blancas | 4,005 | 6,792 | 13,615 |
Cabrestero | 17,775 | 27,560 | 34,310 |
Capachos | 7,716 | 11,840 | 16,666 |
LLA-34 | 103,487 | 142,666 | 181,326 |
Other Blocks | 5,842 | 9,565 | 15,168 |
Total | 138,825 | 198,423 | 261,085 |
(1) All reserves are presented as
2019 Gross Year-End Reserves Volumes by Product Type (1) | ||||
Product Type | Proved Developed Producing | Total Proved | Total Proved + Probable | Total Proved+ Probable + Possible |
Light & Medium Crude Oil (Mbbl)(2) | 8,065 | 13,922 | 24,312 | 42,093 |
Heavy Crude Oil (Mbbl) | 61,787 | 121,648 | 169,124 | 212,363 |
Natural Gas Liquids (Mbbl) | 277 | 369 | 593 | 732 |
4,898 | 17,313 | 26,368 | 35,381 | |
Oil Equivalent (Mboe) | 70,946 | 138,825 | 198,423 | 261,085 |
(1) All reserves are presented as
(2) Mbbl is defined as thousands of barrels
(3) MMcf is defined as one million cubic feet
Reserve Life Index ("RLI")
Proved Developed Producing (PDP) | 3.5 years | 3.5 years | 3.6 years |
Proved (1P) | 6.7 years | 6.8 years | 7.0 years |
Proved Plus Probable (2P) | 11.4 years | 10.3 years | 10.0 years |
(1) Calculated by dividing the amount of the relevant reserves category by average Q4 2017 production of 39,007 boe/d annualized.
(2) Calculated by dividing the amount of the relevant reserves category by average Q4 2018 production of 49,300 boe/d annualized.
(3) Calculated by dividing the amount of the relevant reserves category by estimated average Q4 2019 production of 54,221 boe/d annualized.
Five Year Crude Oil Price Forecast – GLJ Report (
2019 | 2020 | 2021 | 2022 | 2023 | 2024 | ||
ICE Brent (USD$/bbl) - | 63.25 | 68.50 | 71.25 | 73.00 | 75.50 | 78.00 | |
ICE Brent (USD$/bbl) - | 64.21(1) | 67.00 | 68.00 | 71.00 | 73.00 | 75.00 |
(1) Actual 2019 ICE Brent average price
Reserves Category | 2020 | 2021 | 2022 | 2023 | 2024 | 2025+ | Total FDC | Total FDC/boe | ||||||||
PDP | $ | 14,948 | $ | 3,927 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 18,875 | $ | 0.27 |
1P | $ | 158,940 | $ | 111,991 | $ | 70,102 | $ | 19,303 | $ | 649 | $ | 1,098 | $ | 362,084 | $ | 2.61 |
2P | $ | 171,050 | $ | 136,211 | $ | 102,669 | $ | 37,837 | $ | 649 | $ | 4,731 | $ | 453,147 | $ | 2.28 |
(1) FDC are stated in USD, undiscounted and based on GLJ
Reserves Net Present Value Before Tax Summary – GLJ Brent Forecast (1)(2)
Reserves Category | NPV10 December 31, 2018 (000s)(2) | NPV10 December 31, 2019 (000s)(2) | NPV10 December 31, 2019 (CAD/sh)(3) | |
Proved Developed Producing (PDP) | $ | 1,742,166 | 2,000,514 | 18.14 |
Proved Developed Non-Producing | 202,417 | 183,610 | ||
Proved Undeveloped | 1,134,017 | 1,320,420 | ||
Proved (1P) | $ | 3,078,600 | 3,504,544 | 31.79 |
Probable | 1,473,489 | 1,347,556 | ||
Proved + Probable (2P) | $ | 4,552,089 | 4,852,099 | 44.01 |
Possible(4) | 1,731,041 | 1,478,283 | ||
Proved + Probable + Possible (3P) | $ | 6,283,130 | 6,330,382 | 57.41 |
(1) Net present values (“NPV10”) are stated in USD and are discounted at 10 percent. Please refer to the “Reserve Advisory” section for a description of each reserve category. 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) NPV10 per share is calculated, as at
(4) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Reserves Net Present Value After Tax Summary – GLJ Brent Forecast (1)(2)
Reserves Category | NPV10 December 31, 2018 (000s)(2) | NPV10 December 31, 2019 (000s)(2) | NAV December 31, 2019 (CAD/sh)(3) | |
Proved Developed Producing (PDP) | $ | 1,508,154 | 1,630,512 | 17.87 |
Proved Developed Non-Producing | 138,364 | 126,764 | ||
Proved Undeveloped | 768,025 | 896,013 | ||
Proved (1P) | $ | 2,414,543 | 2,653,289 | 27.15 |
Probable | 1,014,349 | 929,239 | ||
Proved + Probable (2P) | $ | 3,428,892 | 3,582,528 | 35.58 |
Possible(4) | 1,194,881 | 1,022,739 | ||
Proved + Probable + Possible (3P) | $ | 4,623,773 | 4,605,267 | 44.85 |
(1) Net present values are stated in USD and are discounted at 10 percent. All reserves are presented as
(2) Includes FDC as at
(3) NAV is calculated, as at
(4) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities recovered will equal or exceed the sum of proved plus probable plus possible reserves.
Net Asset Value at
Proved Developed Producing | Proved | Proved+ Probable | Proved+ Probable+ Possible | ||
After Tax NPV10% (CAD/Share) | 12.45 | 19.37 | 25.72 | 32.73 | |
Working Capital (CAD/Share) | 3.08 | 3.08 | 3.08 | 3.08 | |
NAV (CAD/Share) | 15.53 | 22.45 | 28.80 | 35.81 |
(1) NAV is calculated as at
(2) At Parex’ request, the GLJ 2019 Report was calculated using a constant
2019
Total Proved | Total Proved + Probable | Total Proved + Probable + Possible | ||||
Mboe | Mboe | Mboe | ||||
121,693 | 184,674 | 262,066 | ||||
Technical Revisions | 5,643 | (2,461 | ) | (22,609 | ) | |
Discoveries(1) | 3,814 | 6,526 | 12,300 | |||
Extensions & Improved Recovery(2) | 26,874 | 28,579 | 28,121 | |||
Improved Recovery | 31 | 335 | 437 | |||
Production | (19,230 | ) | (19,230 | ) | (19,230 | ) |
138,825 | 198,423 | 261,085 | ||||
(1) Reserve discoveries are associated with the evaluations of the Boranda, Capachos, LLA-32, and LLA-34 blocks. The evaluation of La Belleza well on VIM-1 block was not included in the 2019 report. (2) Reserve extensions & improved recovery are associated with the evaluations of the Cabrestero and LLA-34 blocks (3) Subject to final reconciliation adjustments. All reserves are presented as |
Calculation of Reserve Metrics – Company Gross(1) | ||||||
2019 | 3 Year | |||||
USD$ ('000) | Proved Developed Producing | Proved | Proved+ Probable | Proved+ Probable | ||
Capital Expenditures(1) | 208,200 | 208,200 | 208,200 | 717,192 | ||
Capital Expenditures – change in FDC | 2,074 | 64,655 | 41,414 | 106,651 | ||
Total Capital | 210,274 | 272,855 | 249,614 | 823,843 | ||
Net Acquisitions | - | - | - | 5,697 | ||
Net Acquisitions – change in FDC | - | - | - | - | ||
Total Net Acquisitions | - | - | - | 5,697 | ||
Total Capital including Acquisitions | 210,274 | 272,855 | 249,614 | 829,540 | ||
Reserve Additions | 27,565 | 36,363 | 32,980 | 133,841 | ||
Net Acquisition Reserve Additions | - | - | - | 1,090 | ||
Reserve Additions including Acquisitions(2) (Mboe) | 27,565 | 36,363 | 32,980 | 134,931 | ||
F&D Costs(2) ($/boe) | 7.63 | 7.50 | 7.57 | 6.16 | ||
FD&A Costs(2) ($/boe) | 7.63 | 7.50 | 7.57 | 6.15 | ||
Estimated 2019FY funds flow per boe(1)(3) ($/boe) | 29.30 | 29.30 | 29.30 | 25.31 | ||
Recycle Ratio - F&D(2)(3) | 3.8x | 3.9x | 3.9x | 4.1x | ||
Recycle Ratio - FD&A(2)(3) | 3.8x | 3.9x | 3.9x | 4.1x |
(1) Calculated using unaudited estimated capital expenditures and unaudited estimated funds flow from operations as at
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
(3) Recycle ratio is calculated as funds flow from operations per boe divided by F&D or FD&A as applicable. 3 Year funds flow from operations on a per boe basis is calculated using weighted average sales volumes.
Operational Update
VIM-1 (Parex WI 50% Operator, Frontera Energy WI 50%): The La Belleza-1 exploration well was drilled to a total depth of 11,680 feet. A total of 179 feet (155 feet total vertical depth) of potential hydrocarbon bearing reservoir was encountered in the Cienaga De Oro formation and drilling operations were stopped to allow testing of the 179 feet open hole section. The well was tested under natural flowing conditions and over a 328-hour period, the well produced a total of 32,728 barrels of 43 API oil, 147 MMCF of natural gas and 3,996 barrels of water. The average flow rate during the test was 2,395 bopd and 10.7 MMcfd of gas (4,183 boe/d combined) at an average water cut of 12%. The flow rate during the final 24 hours of the test was 2,696 bopd and 11.8 MMcfd of gas (4,663 boe/d combined) at an average watercut of 10%. The initial shut in wellhead pressure recorded at the start of the test was 4,700 psi and the wellhead pressure during the test period remained relatively flat at 3,700 psi with the producing rate during the test limited by the testing facilities on location. Bottom hole flowing pressures during the test remained relatively stable at approximately 6,000 psi indicating an average drawdown of 14%. The initial bottom hole pressure recorded at the start of the test was 7,031 psi and the final extrapolated pressure at the end of the 174-hour buildup was 7,011 psi. The well will be flow tested for one additional week followed by an extended 30-day buildup period which will provide additional information on the final reservoir pressure. Note that the La Belleza test results were not included in the GLJ 2019 Report.
Aguas Blancas (WI 50%): AB-24 and AB-11 were drilled on a new pad to evaluate a southern extension of the field.
CPO-11 (WI 50%): The Daisy-1 exploration well was drilled, tested and abandoned.
NCIB Share Purchase Plan
As of
2019 Year-end Results Conference Call & Webcast
We anticipate holding a conference call and webcast for investors, analysts and other interested parties on Wednesday, March 11, 2020 at
Toll-free dial number ( | 1-800-806-5484 |
International dial-in number | Click to access the dial-in number of your location |
Passcode | 8822777# |
Webcast | TBC |
For more information, please contact:
Sr. Vice President, Capital Markets & Corporate Planning Phone: (403) 517-1733 investor.relations@parexresources.com |
This news release does not constitute an offer to sell securities, nor is it a solicitation of an offer to buy securities, in any jurisdiction.
Not for distribution or for dissemination in
Reserve 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
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 finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
References to initial production test rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for
This press release contains several oil and gas metrics, including F&D costs, FD&A costs, recycle ratio, reserve replacement, NAV and RLI. These 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 such metrics are as follows:
- Finding and development (“F&D”) costs are calculated by dividing capital expenditures by the change in reserves within the applicable reserves category. F&D costs, including FDC, include all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.
- Finding, development and acquisition ("FD&A”) costs represent the costs of property acquisition, exploration, and development incurred. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
- FD&A costs are calculated as capital expenditures plus net acquisition costs plus change in FDC. FD&A per boe is calculated as FD&A costs divided by reserves additions for the applicable period.
- Recycle ratio is calculated as funds flow from operations netback divided by F&D or FD&A, as applicable.
- Funds flow from operations, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital.
- Funds flow from operations netback or funds flow from operations per boe is calculated by dividing funds flow from operations by sales volumes for the period.
- Reserve replacement is calculated by dividing the annual reserve additions by the annual production.
- Net asset value (“NAV”) per share is calculated as before or after tax NPV10 plus estimated year-end working capital, converted from USD to CAD as applicable, divided by basic shares outstanding at
December 31, 2019 . - Reserves life index is calculated by dividing the applicable reserves category by the annualized fourth quarter production.
Unaudited Financial Information
Certain financial and operating results included in this news release, including capital expenditures, production information, funds flow from operations and operating costs are based on unaudited estimated results. These estimated results are subject to change upon completion of the Company’s audited financial statements for the year ended
The information contained in this press release in respect of the Company's expected capital expenditures, funds flow from operations and operating costs for 2019 may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed in this press release. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments. FOFI contained in this press release was made as of the date of this press release and
Funds flow from operations and funds flow netback are not recognized measures under International Financial Reporting Standards ("IFRS") and do not have a standardized meaning. 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. Investors should be cautioned that such measures should not be construed as an alternative to other measures of financial performance as determined in accordance with IFRS. The Company's method of calculating funds from operations may differ from other companies, and accordingly, may not be comparable to similar measures used by other companies. See the heading “Reserves Advisory” for how to calculate funds flow from operations and funds flow from operations netback.
Advisory on Forward Looking Statements
Certain information regarding
In addition, forward-looking statements contained in this document include, statements relating to "reserves", which 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
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 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
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