CALGARY, AB--(Marketwired - March 07, 2017) -

NOT FOR DISTRIBUTION OR FOR DISSEMINATION IN THE UNITED STATES

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, 2016.

All amounts herein are in United States dollars ("USD") unless otherwise stated. Please note that Parex will hold a conference call on Wednesday, March 8, 2017 beginning at 9:30 AM Mountain Time to discuss the 2016 year-end and fourth quarter results.

2016 Financial and Operational Highlights

• Achieved average annual oil and natural gas production of 29,715 barrels of oil equivalent per day ("boe/d"), of which 99% was crude oil and representing a year-over-year growth of 8%;
• Generated full year funds flow from operations of $144 million ($0.95 (or CAD $1.26)¹ per share basic). Funds flow from operations increased from the comparative period of $130 million ($0.90 (or CAD $1.15)² per share basic) due to an increase in production volumes partially offset by lower average oil prices;
• Increased net working capital to $93 million at December 31, 2016 compared to a net working capital of $77 million at December 31, 2015; exited the year with no bank debt and $175 million in undrawn credit facility;
• Recorded a net loss of $46 million for the year ended December 31, 2016. The net loss was primarily driven from a non-cash impairment of exploration and evaluation assets;
• Released an updated independently evaluated reserves assessment prepared by GLJ Petroleum Consultants Ltd. ("GLJ") with proved plus probable ("2P") reserves growth of 37 percent over 2015. The Company's 2P reserves, working interest before royalties, increased to 112 million barrels of oil equivalent ("MMboe") (99% crude oil) from 82 MMboe at December 31, 2015;
• Increased 2P reserve life index to 10 years from 8 years, based on annualized fourth quarter 2016 production;
• Delivered $6.99 per boe Finding, Development and Acquisition costs ("FD&A") for proved ("1P") reserves and $3.40 per boe for 2P reserves;
• Participated in drilling 17 gross wells (11.55 net) in Colombia resulting in 13 oil wells, 3 abandoned wells, and 1 abandoned well prior to reaching target depth, for a success rate of 81 percent; and
• Accelerated the evaluation of the Aguas Blancas block by drilling four wells; expanded the assessed reserves area by over 1,300 acres and doubled 2P reserves.

Fourth Quarter Financial and Operational Highlights

• Achieved average quarterly oil and natural gas production of 31,049 boe per day, an increase of 8.6% over the prior year comparative period and 4% over the 2016 average daily production;
• Generated funds flow from operations of $52 million ($0.34 (CAD$0.45) per share basic) or $18.74³ per boe; and
• Expanded footprint in the Middle Magdalena Basin with the acquisition of the Sogamoso (100% working interest) block during Ecopetrol's 2016 Bid Round.

Fourth Quarter and 2016 Financial Summary

Fourth quarter sales volumes excluding purchased oil averaged 26,395 boe per day and the average realized sales price in Colombia was $44.84 per boe generating an operating netback of $24.40 per boe before the effects of commodity derivative contracts. On a per boe basis, in the fourth quarter transportation and operating expenses combined were $0.62 higher than in Q3 2016.

The differential between Brent oil reference pricing and the realized oil sales price was $6.29 per bbl in Q4 2016, which was lower than the prior nine months average of $7.58 per bbl.

Funds flow from operations in the fourth quarter of 2016 was $51.8 million ($0.33 per share diluted) compared to $45.1 million ($0.29 per share diluted) in the prior quarter. In the fourth quarter the Company returned 335,000 (3,649 bbl/d) of previously overlifted oil volumes to the Ocensa pipeline. Parex records funds flow margin on Company oil production when produced volumes are delivered to the pipeline.

Full year capital expenditures of $111.7 million were $32.4 million lower than full year funds flow from operations. The fourth quarter capital expenditure program of $67 million included $38 million for drilling and completion. During the fourth quarter of 2016, the level of drilling activity increased as Parex drilled 10 gross wells (6.35 net)⁴ compared to 7 gross wells in the preceding 9 months of 2016 and 1 net well in Q4 2015.

Parex preserved its balance sheet strength, exiting 2016 with $93.3 million of net working capital surplus, $175 million in undrawn credit facility and no long-term debt.

¹ Using USD-CAD Bank of Canada 2016 annual average of 1.3248

² Using USD-CAD Bank of Canada 2015 annual average of 1.2787

³ Funds flow from operations per boe: calculated based on 30,044 boe/d sales volume, which includes sales of produced oil & gas and overlift of 3,649 bbl/d

⁴ Oil wells: Boranda-1, AB-9, AB-26, AB-14, AB-32, Chiricoca-1, Tigana Sur-4, Bacano-2 & Jacana-6; abandoned well: Xorop-1

Operations Update

Production: we expect Q1 2017 production to average 32,000 boe/d compared to 31,049 boe/d in Q4 2016 and in line with our 2017 production guidance of 34,000-36,000 boe/d.

Aguas Blancas (post earning working interest ("WI") 50%): we continue to advance the assessment of the property with our key 2017 objectives being: a) identification of original oil in place and b) testing the viability of applying waterflood to increase recovery factor from 10% to 20% or higher.

To date Parex has:

• Drilled 3 delineation wells that expanded the resource area;
• Drilled 2 injection pilot wells;
• Cored over 550 feet of reservoir;
• Demonstrated primary productivity capabilities with the AB-26 well producing light oil within our expectations;
• Conducted a successful water injectivity test on the AB-26 well which was the first step in assessing the water-flood potential of the field. By the end of Q2 2017, we plan to commence our first water-flood pattern; and
• Developed a plan to drill 9 to 14 additional wells in 2017.

Due to the limited area of the existing drilling pads, we plan to drill up to 5 wells on a pad before completing and testing the drilled wells. We are currently drilling the AB-15 well on the AB-3 pad and will then mobilize the drilling rig to the AB-5 pad to permit the service rig to complete and test the AB-14, AB-32, AB-34 and AB-15 wells on the AB-3 pad.

The AB-26 well was drilled from the AB-5 pad in November 2016 and was completed in January 2017 after the drilling rig moved off location. Based on log data, the well encountered oil bearing sands in the Mugrosa B and C reservoirs and the Mugrosa C reservoir was completed and placed on production with the use of a rod pumping system. Production commenced on January 29, 2017 and to February 21, 2017 a total of 2,930 barrels of 35 API oil was recovered at an average rate of 122 bopd with an average water-cut of approximately 2% after recovery of completion load fluids. The production rate during the final week of the test averaged 117 bopd at a 2% watercut. The production rate recorded during the test was consistent with Parex' expectations for an un-stimulated well in the Aguas Blancas field.

Following the AB-26 production test, the pumping system was removed so that a water injection test could be completed. The water injection test commenced on February 26, 2017 and as of March 2, 2017 a total of 2,080 barrels of water had been injected at an average rate of 547 barrels of water per day with an average wellhead pressure of 1,650 psi. The injection rate during the last 12 hours of the test was 642 barrels of water per day at an average pressure of 1,850 psi. Bottom hole pressure recorders were installed for both the producing and injection tests and will be evaluated when the recorder information is recovered. Based on the positive result of the water injection test, we are now planning to implement a waterflood pattern that includes two producing wells for each injection well.

Llanos-34 (WI 55%): Parex continues to expand the oil productivity on LLA-34. To date in 2017, both the Chiricoca-1 and Jacana-11 exploration wells are producing oil.

A new pad was built to the south-west of the Jacana/Tigana trend to evaluate the potential for the extension of the field. The Jacana-11 well was drilled outside the 3P reserves limit of the GLJ 2016 Report (as defined under "Reserves Advisory") and is approximately 2.5 kilometers from the Jacana-6 well. The Jacana Sur-2 appraisal well is expected to spud in the next week to assess the area between Jacana-6 and Jacana-11. Additionally, a second rig is currently drilling the Jacana-7 appraisal well which will assess the area between Jacana-5 and Jacana-6.

The Jacana-11 well was drilled to a total depth of 11,618 feet approximately 2,500 meters south-west of the Jacana-6 well and 3,000 meters north-west of the Bacano-2 well to appraise the Guadalupe Formation. The Jacana-11 well encountered Guadalupe reservoir and was completed and tested with the drilling rig on location. An Electric Submersible Pump ("ESP") was installed in the well and the well commenced testing on February 27, 2017. As of March 5 2017, a total of 13,646 barrels of 18.7 API oil has been recovered over a 166-hour period for an average production rate of 1,973 bopd. Bottom hole pressure recorders indicate a producing drawdown of approximately 15% at the current production rate of 2,200 bopd and the final water-cut from the well is under 1% after recovery of completion load fluid. After completion of the 7-day short term test, the well will be shut in to record a buildup for analysis. The most downdip oil well drilled to date, Jacana-5, continues to produce at a rate of approximately 3,900 bopd with a water-cut of 1% after recovery of over 688,000 barrels of oil to March 5, 2017.

The Chiricoca-1 exploration well was tested in January 2017 and encountered oil in the Mirador Formation. The well was completed and an ESP was installed in the wellbore with production commencing on January 30, 2017. Currently, the well is producing approximately 940 bopd of 32 API oil with a watercut of 0.2%. Bottom hole pressure recorders indicate a drawdown of approximately 13% with a steady bottom hole pressure.

Cabrestero (WI 100%): The Bacano-2 well is currently producing approximately 575 bopd with a water-cut of less than 1%. Parex has completed the construction of a new drilling pad and is preparing to spud the Bacano-3 appraisal well and we expect to immediately follow up with the Bacano-4 appraisal well.

Playon (WI 50%): The Boranda-1 exploration well was drilling and completed in Q4 2016. Testing of multiple intervals is on-going.

2017 Guidance:

At current oil prices, we expect planned capital expenditures to be fully funded by funds flow from operations. Parex' guidance for 2017 is as follows:

Q4 Conference Call Information

Parex will host a conference call to discuss the 2016 Fourth Quarter and Year End results on Wednesday, March 8, 2017 beginning at 9:30 am Mountain Time. To participate in the call, please dial 1-866-696-5910 (pass code: 1277530#) from Canada and the USA.

The live audio webcast will be carried at http://bell.media-server.com/m/p/hvbm4weh

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.

Non-GAAP Terms

The Company discloses several financial measures herein that do not have any standardized meaning prescribed under International Financial Reporting Standards ("IFRS"). These financial measures include funds flow used in, or from operations, working capital, operating netback and funds flow netback. Management uses these non-IFRS 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 is a non-IFRS term that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. Management uses funds from (used in) operations to analyze operating performance and monitor financial leverage, and considers funds from (used in) operations to be a key measure as it demonstrates the Company's ability to generate cash necessary to fund future capital investments. Funds flow from operations is reconciled with net (loss) income in the consolidated statements of cash flows.

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.

Reserve Advisory

The information provided is a summary of the independent reserves report prepared by GLJ dated February 6, 2017 with an effective date of December 31, 2016 (the "GLJ 2016 Report"), with comparatives to the independent reserves report prepared by GLJ dated February 5, 2016 with an effective date of December 31, 2015 and the independent reserves report prepared by GLJ dated February 13, 2015 with an effective date of December 31, 2014 (collectively with the GLJ 2016 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"). Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR by March 31, 2017.

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, 2016 reserves presented are based on GLJ's forecast pricing effective January 1, 2017. All December 31, 2015 reserves presented are based on GLJ's forecast pricing effective January 1, 2016. All December 31, 2014 reserves presented are based on GLJ's forecast pricing effective January 1, 2015.

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% 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 Mcf: 1Bbl, utilizing a conversion ratio at 6 Mcf: 1 Bbl 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.

This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) possible locations. Proved locations, probable locations and possible locations are derived from the GLJ 2016 Report and account for drilling locations that have associated proved and/or probable and/or possible reserves, as applicable. Of the 195 drilling locations identified herein, 74 are proved locations, 83 are probable locations and 38 are possible locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.

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

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.

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", "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 anticipated 2017 capital budget, including the amount thereof; the Company's forecasted 2017 average production; the Company's 2017 capital expenditure budget, including the expected allocations of such expenditures; the Company's belief that its capital budget will be fully funded from funds flow from operations; the Company's anticipated drilling, development, exploration and other growth plans and activities for its assets, including the Company's objectives at Aguas Blancas, timing of commencement of the Company's first water-flood program at Aguas Blancas, the Company's drilling plans at Aguas Blancas and the Company's drilling plans at Cabrestero; 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; risks related to the lawsuit brought in Texas against Parex and certain foreign subsidiaries; 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; effects of regulation by governmental agencies; 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; the status of litigation; 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; anticipated operating netbacks, G&A, finance expenses and tax expenses; 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 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.

This press release and, in particular the information in respect of the Company's expected capital expenditures and funds flow from operations for 2017, 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 the press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

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