Parex Resources Announces 2017 Fourth Quarter and Full Year Results

CALGARY, Alberta, March 05, 2018 (GLOBE NEWSWIRE) -- Parex Resources Inc. (“Parex” or the “Company”) (TSX:PXT) is pleased to announce its financial and operating results for the year ended and the three months ended (“Fourth Quarter” or “Q4”) December 31, 2017. 

All amounts herein are in United States dollars (“USD”) unless otherwise stated.  Please note that Parex will hold a conference call on Tuesday, March 6, 2018 beginning at 9:30 AM Mountain Time to discuss the 2017 year-end and fourth quarter results.

2017 Financial and Operational Highlights

• Annual oil and natural gas production in 2017 averaged 35,541 barrels of oil equivalent per day ("boe/d"), of which 99% was crude oil, an increase of 20 percent over 2016;
• Released proved plus probable reserves growth of 45 percent over 2016, increasing to 162.2 million barrels of oil equivalent ("MMboe")(net company working interest, 99% crude oil) at December 31, 2017 from 111.9 MMboe (net company working interest) at December 31, 2016 and achieved proved plus probable reserve replacement of 488 percent with total 2017 gross reserve additions of 63.3 MMboe, as per the independently evaluated reserves assessment prepared by GLJ Petroleum Consultants Ltd ("GLJ");
• Finding, Development and Acquisition costs (“FD&A”) for the year ended December 31, 2017 were $7.46/boe for proved developed producing reserves and $4.71/boe for proved plus probable reserves including future development capital;
• Recorded net income of $155.1 million ($1.01 per share basic) for the year ended December 31, 2017 as compared to a $46.4 million net loss ($0.31 net loss per share basic) in the year ended December 31, 2016;
• Generated  full year funds flow from operations of $279.5 million ($1.81 per share basic), a 94 percent increase from the year ended December 31, 2016 of $144.1 million ($0.95 per share basic) with a 21 percent increase in Brent reference pricing year over year;
• Capital expenditures including property acquisitions were $212.3 million compared to $111.7 million for the year ended December 31, 2016. Capital expenditures were funded from funds flow from operations, with excess funds flow from operations increasing working capital;
• Increased net working capital to $163.4 million at December 31, 2017 compared to a working capital position of $93.3 million at December 31, 2016, and exited 2017 with no bank or term debt; and
• Participated in drilling 38 gross wells in Colombia resulting in 30 oil wells, 2 disposal wells, 5 abandoned wells and 1 untested well, for a success rate of 86 percent.

 Fourth Quarter Financial and Operational Highlights

• Achieved a record quarterly oil and natural gas production of 39,007 boe/d, an increase of 26% over the fourth quarter of 2016 and 10% higher than the 2017 average oil and natural gas production; 
• Earned net income of $55.9 million ($0.36 per share basic) compared to a net loss of $45.4 million ($0.30 net loss per share basic) in the fourth quarter of 2016;
• Generated funds flow from operations of $93.9 million ($0.61 per share basic) a 81 percent increase compared to $51.8 million ($0.34 per share basic) in the fourth quarter of 2016; and
• Utilized a portion of funds flow from operations in excess of capital expenditures to purchase 539,100 of the Company's common shares at an average price of Cdn$16.53 pursuant to the Company's normal course issuer bid program.

Fourth Quarter and 2017 Financial Summary

Fourth quarter sales volumes excluding purchased oil averaged 38,657 boe/d and the average Brent price  was $61.46 per barrel ("bbl") generating an operating netback of $35.39/boe before the effects of commodity derivative contracts. On a per boe basis, in the fourth quarter transportation and operating expenses combined were $0.30 lower than in the third quarter of 2017.

The differential between Brent oil reference pricing and the realized oil and gas sales price was $4.56/boe in the fourth quarter of 2017, which was in line with the prior nine months average of $4.67/boe.

Funds flow from operations in the fourth quarter of 2017 was $93.9 million ($0.61 per share) compared to $66.0 million ($0.43 per share) in the third quarter of 2017.

Full year capital expenditures including property acquisitions of $212.3 million were $67.2 million lower than full year funds flow from operations. The fourth quarter capital expenditure program of $60.6 million included $59.1 million for drilling and completion.  During the fourth quarter of 2017, the level of drilling activity increased as Parex drilled 10 gross wells (6.35 net) consisting of 8 oil wells (Capachos-2, Tigana Sur Oeste-7, Tigana Sur Oeste-3, Tigana Sur Oeste-2, Tigana Norte-3, Tigana Norte-4, Tigana Norte-5 and Jacana-17) and 2 abandoned wells  (Niagara-1 and Iguazu-1) compared to 28 gross wells in the preceding nine months of 2017 and 10 gross well in the fourth quarter 2016.

Parex strengthened its balance sheet, exiting 2017 with $163.4 million of net working capital surplus, $100 million in undrawn credit facility and no long-term debt.

The table above contains Non-GAAP measures.  See “Non-GAAP Terms” for further discussion.
(1) Borrowing limit of $100 million as of December 31, 2017, was $175 million at December 31, 2016.
(2) Diluted shares as stated include the effects of common shares and in-the-money stock options outstanding at the period-end. The December 31, 2017 closing stock price was Cdn$18.16 per share.

Operations Update

Aguas Blancas (WI 50%): During March 2018, Parex will be mobilizing a drilling rig to begin a 6 well development program and a 4 well exploration program.  The objective of the exploration program is to test the southern extent of the field, whilst the development program intends to build on the initial success of the first waterflood pilot and add 2 other water flood patterns.

Cabrestero (WI 100%): The exploration well Totoro-1 was spud on January 19, 2018  and drilled  to a total measured depth of 12,050 feet to evaluate the northern area of the block.  The well encountered Guadalupe reservoir and was completed and production tested with the use of an Electric Submersible Pump (ESP).  Over a 154 hour period the well produced a total of 2,565 barrels of 17 API oil with a final water-cut of less than 2%.  The water produced during the test was completion load fluid and no formation water was recovered during the test.    The average production rate during the test was 400 barrels of oil per day and the test rate during the final 12 hours of the test was 490 bopd at an estimated drawdown of 55%.  The production rate was lower than forecast as the reservoir pressure was approximately 25% lower than the expected original pressure.  The lower reservoir pressure indicates that the Totoro discovery is likely connected to either the Bacano field (1.5 kilometers southwest) or the Jacana field (2.6 kilometers north).  Additional delineation of both Bacano and Jacana fields will likely be required to determine the extent of the Totoro discovery.

Capachos (WI 50%): After consultations with the local communities and federal authorities, Parex has resumed operations that were previously suspended due to security concerns.  The Capachos Sur-2 well has been cased to approximately 15,360 feet and we plan to continue drilling to a planned total depth of 16,700 feet.  Following Capachos Sur-2, we plan to drill the Andina-1 (Capchos Norte) exploration prospect.  Parex has re-started production of the Capachos-2 well at a gross restricted rate of approximately 1,000 bopd and we continue to advance the engineering and procurement of the gas processing facility that would provide gross oil production capacity of 10,000 bopd by year-end 2018.

De Mares (WI 50%): A drilling rig is mobilizing to drill the Coyote-2 exploration well with a target depth of approximately 7,500 feet.  Previously Parex re-entered a standing well, Coyote-1, to re-complete the La Paz formation.  The test produced light oil and we intend to drill a new well to specifically target the La Paz formation.

LLA-30 (WI 100%): The Company has begun mobilizing a drilling rig for the Cocoa-1 exploration prospect.  We expect to spud the well during March 2018 and the well has a target depth of approximately 5,000 feet.

VIM-1 (WI 100%): The Company has begun mobilizing a drilling rig for the Apure-1 exploration prospect which is our first exploration well to be drilled on the block.  We expect to spud the well during March 2018 and reach the target depth of approximately 12,550 feet in May 2018.

LLA-34 (WI 55%): The Company continues to drill delineation and development wells along the Tigana and Jacana trend.  Additionally, the exploration well Chachalaca Sur-1 was spud on February 4, 2018 and the well was cased.  A service rig will be mobilized to test the prospective formations.

Production: We expect the first quarter of 2018 average production to exceed 40,000 boe/d and second quarter of 2018 production to average approximately 42,000 boe/d.

Q4 Conference Call Information

Parex will host a conference call to discuss the 2017 Fourth Quarter and Year End results on Tuesday, March 6, 2018 beginning at 9:30 am Mountain Time.  To participate in the call, please dial 1-866-696-5910
(pass code: 9220113) from Canada and the USA.

The live audio webcast will be carried at http://bell.media-server.com/m/p/t43bye9v

Individuals located outside of Canada and the USA are invited to access this event via webcast or by calling their respective location dial-in number available through this link.

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.

For more information, please contact:
         
Mike Kruchten
Vice-President, Capital Markets and Corporate Planning
Phone: (403) 517-1733
Investor.relations@parexresources.com

Not for distribution or for dissemination in the United States

Non-GAAP Terms Advisory

The Company discloses financial measures ("non-GAAP measures") herein that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS"). These financial measures include operating netback per boe and funds flow from operations per boe. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company’s efficiency and its ability to fund a portion of its future capital expenditures.

Funds flow from operations per boe is a non-GAAP term 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 operating netbacks per boe to be a key measure as they demonstrate Parex’ profitability relative to current commodity prices. Below is a description of each component of the Company's operating netback per boe and how it is determined:

Oil and natural gas sales per boe is determined by sales revenue excluding risk management contracts less non-cash oil revenue from overlifted Ocensa pipeline volumes divided by total equivalent sales volume including purchased oil volumes.

Royalties per boe is determined by dividing royalty expense by the total equivalent sales volume plus overlifted Ocensa volumes returned in the period and excludes purchased oil volumes.

Production expense per boe is determined by dividing production expense by the total equivalent sales volume plus overlifted Ocensa volumes returned in the period and excludes purchased oil volumes.

Transportation expense per boe is determined by dividing the transportation expense by the total equivalent sales volumes including purchased oil volumes plus overlifted Ocensa volumes returned in the period.

Shareholders and investors should be cautioned that these measures should not be construed as an alternative to net income or other measures of financial performance as determined in accordance with IFRS. Parex' method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Please see the Company's most recent Management’s Discussion and Analysis, which is available at www.sedar.com for additional information about these financial measures.

Oil & Gas Matters Advisory

The independent reserves report prepared by GLJ referred to herein is dated February 2, 2018 with an effective date of December 31, 2017 (the "GLJ 2017 Report"), with comparatives to the independent reserves report prepared by GLJ dated February 6, 2017 with an effective date of December 31, 2016 (collectively with the GLJ 2017 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 and National Instrument 51-101- Standards of Disclosure for Oil and Gas Activities ("NI 51-101").

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, 2017 reserves presented are based on GLJ's forecast pricing effective January 1, 2018. All December 31, 2016 reserves presented are based on GLJ's forecast pricing effective January 1, 2017. "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. Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form for the year ended December 31, 2017, which will be filed on SEDAR by March 30, 2018.

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 Mcf: 1Bbl, utilizing a conversion ratio at 6 Mcf: 1 Bbl may be misleading as an indication of value.

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.

This press release contains a number of oil and gas metrics, including  FD&A costs, reserve replacement and reserve additions. 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.

Reserves replacement is calculated as 63.3 million barrels of oil equivalent gross proved plus probable reserve additions (including acquisitions) during the year ended December 31, 2017 divided by current annual production of 35,541 barrels per day and expressed as a percentage. Reserve additions is calculated as the change in proved plus probable reserves from December 31, 2016 (111.904 million barrels of oil equivalent (net company working interest)) to December 31, 2017 (162.236 million barrels of oil equivalent (net company working interest)) excluding production of approximately 13.0 million barrels of oil equivalent (net company working interest).

References in this press release to 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 of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Parex. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.

Forward Looking Statements Advisory

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”, “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' 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' 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 performance characteristics of the Company's oil properties; the Company's forecasted first quarter 2018 and second quarter 2018 average production; the Company's anticipated drilling, development, exploration and other growth plans and activities for its assets, including the Company's objectives at Aguas Blancas and timing of mobilization of a rig at Aguas Blancas, the Company's beliefs as to the connected fields and additional delineation requirements at Cabrestero, the Company's drilling plans and advancement of a gas processing facility at Capachos (including the expected capacity of the gas processing facility and the anticipated timing of reaching such capacity), drilling plans (including targeted depth of drilling certain wells and the expected timing that certain wells will be spud) at De Mares, LLA-30 and VIM-1 and the mobilization of a rig at LLA-34; results of drilling and testing; and activities to be undertaken in various areas. 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 resources described can be profitably produced in the future.  The recovery and reserve estimates of Parex' 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; prolonged 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 of exploration and development drilling 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; failure of counterparties to perform under contracts; risk that Brent oil prices are lower than anticipated; risk that Parex' evaluation of its existing portfolio of development and exploration opportunities is not consistent with its expectations; that production test results may not necessarily indicative of long term performance or of ultimate recovery; 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' operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

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, 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 the anticipated Brent oil price; 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, future operating costs; effects of regulation by governmental agencies; uninterrupted access to areas of Parex’ 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' 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' 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; 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' current and future operations and such information may not be appropriate for other purposes. Parex' 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.