Calgary, March 20, 2018: Valeura Energy Inc. (TSX:VLE) (“Valeura” or the “Company”) is pleased to report highlights of its financial and operating results for Q4 2017, and for the year ended December 31, 2017 and the activity plan for 2018.

• Valeura closed key transformative deals in Q1 2017 to purchase Thrace Basin Natural Gas (“TBNG”), and to partner with Statoil for the exploration of the deep, unconventional potential of its Thrace Basin lands.
• The Yamalik-1 gas-condensate discovery well was drilled to 4,196 m and encountered a 1,300 m (gross) column of highly overpressured gas that demonstrated the presence of an unconventional, Basin Centered Gas Accumulation (“BCGA”) in the Thrace Basin. The well reached total depth (“TD”) still in a gas column.
• Yamalik-1 yielded an aggregate flow of 2.9 million cubic feet per day (“MMcf/d”) from four production tests, each of which was preceded by a two-stage frac. The produced gas had a significant condensate yield that ranged between 20-70 barrels (“bbl”)/MMcf. It is estimated that less than half of the net pay was accessed with the fracing and testing program.
• In Q1 2018, the Company released an external resource evaluator’s report that assigned to Valeura 10.1 trillion cubic feet (“Tcf”) of unrisked, mean recoverable natural gas prospective resources associated with the BCGA play. (See Advisories and Definitions below.)
• In Q1 2018, Valeura completed a $60 million (gross) financing (the “Financing”) which will fully fund the Company’s planned 2018-19 appraisal program of the BCGA play.
• The Company is planning to tie in Yamalik-1 well for further testing and production in early Q3 2018.
• Valeura expects to commence a three well delineation campaign in late Q3 2018 to establish the full extent of the BCGA play across the basin and to demonstrate commerciality.

The complete quarterly reporting package has been filed on SEDAR and posted on the Company’s website at www.valeuraenergy.com. The Company will hold an audio webcast and conference call for analysts and interested listeners on March 22, 2018 at 9:30am MST (11:30am EST).  (See details below.)

 

YAMALIK-1 DISCOVERY DRIVES DEEP UNCONVENTIONAL STRATEGY

Valeura completed several strategic asset transactions in 2017 that allowed it to take operatorship of all its key assets and increase its working interest in both shallow conventional gas rights and production and sales infrastructure. At the same time, the Company brought on a world-class partner in Statoil to fund and assist in exploring deeper, unconventional opportunities within the Thrace Basin in Turkey.

“Our commercial efforts played out as planned by establishing Valeura as the operator and giving us a dominant position in the most prospective lands and the critical gas transportation and processing infrastructure.” commented Sean Guest, President and CEO, “This foundation provided the partnerships and the funding model that supported our drilling activity and led to the discovery of the deep, unconventional gas-condensate play. We delivered very positive results for our shareholders in 2017.”

The Yamalik-1 gas-condensate discovery well was drilled safely by Valeura with its partner, Statoil, in mid-2017. This well encountered almost 1,300 m of highly overpressured, gas-saturated reservoir below 2,900 m and demonstrated the presence of an unconventional BCGA. Eight slick-water fracs followed by four well tests resulted in a 24-hour aggregate production test rate of 2.9 MMcf/d of gas. “We are pleased with the results of the well,” said Sean Guest, “Yamalik-1 demonstrates that gas and condensate will flow to surface with fracture stimulation of these deep, tight sandstone reservoirs. While maturation of the play is still in its early days as long-term production characteristics need to be established by further testing and drilling, we are extremely encouraged by the results of this well which may indicate the potential for a world-class unconventional gas development.”

Subsequent to year end, on February 6, 2018, Valeura announced summary results of an independent evaluation of its prospective resources in the BCGA byDeGolyer and MacNaughton(“D&M”) of Dallas, Texas(the “D&M Resources Report”)which estimates 10.1 Tcf of Valeura working interest, unrisked, recoverable mean natural gas prospective resources, or 5.2 Tcf on a risked mean basis. (See Advisories and Definitions below.)

Given the success of Yamalik-1 and the very large potential of the BCGA, the Company is focusing its strategy and capital allocation on appraising the BCGA play through additional drilling and testing. Yamalik-1 will be tied in for further testing in early Q3 2018. Later in Q3 2018, the Company will commence a three well delineation campaign to establish the full extent of the play across the basin and to demonstrate commerciality. The Company is fully funded for this 2018 and 2019 program having completed the Financing.

Although Valeura’s primary focus has now turned to the BCGA play, the Company has continued to exploit the shallow gas potential on its lands. After completing the acquisition of TBNG in Q1 2017, Valeura immediately commenced workovers on existing producing wells and the drilling of six new exploration wells. The results of these operations allowed the Company to deliver modest production increases every quarter in 2017.

FINANCIAL AND OPERATING RESULTS SUMMARY

	Three Months Ended December 31, 2017	Three Months Ended September 30, 2017	Year Ended December 31, 2017	Three Months Ended December 31, 2016	Year Ended December 31, 2016
Financial (thousands of CDN$ except share and per share amounts)
Petroleum and natural gas revenues	3,824	3,970	14,646	3,508	16,155
Adjusted funds flow (1)	(446)	1,165	(1,205)	915	6,048
Net loss from operations	(946)	(4,911)	(8,384)	(3,189)	(6,086)
Exploration and development capital	1,856	4,992	12,791	536	9,535
Acquisitions	–	–	21,450	–	–
Dispositions	–	–	(26,288)	–	–
Net working capital surplus	3.421	5,458	3,421	2,786	3,786
Cash	11,108	2,968	11,108	1,987	1,987
Common shares outstanding Basic Diluted	73,148,321 79,518,821	73,148,321 79,518,821	73,148,321 79,518,821	58,519,321 63,433,821	58,519,321 63,433,821
Share trading High Low Close	5.02 0.43 4.35	0.72 0.49 0.49	5.02 0.43 4.35	1.15 0.81 0.95	1.44 0.60 0.95
Operations
Production
Crude oil (bbl/d)	9	11	8	12	9
Natural Gas (Mcf/d)	6,176	6,077	5,662	4,699	4,742
BOE/d (@ 6:1) (2)	1,038	1,024	952	795	799
Average reference price Brent ($ per bbl) BOTAS Reference ($ per Mcf) (3)	78.05 6.65	65.27 7.10	70.29 7.07	65.17 8.09	57.67 9.41
Average realised price Crude oil ($ per bbl) Natural gas – Turkey ($ per Mcf)	82.78 6.61	65.16 6.98	71.84 6.98	63.67 7.96	55.88 9.20
Average Operating Netback ($ per BOE @ 6:1) (1) (2)	22.35	22.66	23.76	33.43	40.41

Notes:

See the Company’s 2017 management’s discussion and analysis (“MD&A”) filed on SEDAR for further discussion.

(1) The above table includes non-IFRS measures, which may not be comparable to other companies. Adjusted funds flowis calculated as net income (loss) for the period adjusted for non-cash items in the statement of cash flows. Operating netback is calculated as petroleum and natural gas sales less royalties, production expenses and transportation costs.

(2) See Oil and Gas Advisories and Reserves and Resources Definitions below.

(3) Boru Hatlari ile Petrol Tasima Anonim Sirketi (“BOTAS”) owns and operates the national crude oil and natural gas pipeline grids in Turkey and purchases the majority of Turkey’s natural gas imports. BOTAS regularly posts prices and its Level-2 Wholesale Tariff benchmark is shown herein as a reference price. See the 2017 AIF for further discussion.

 

2018 OUTLOOK

Valeura believes that the deep, unconventional BCGA play in the Thrace Basin provides the most significant upside potential for the Company. Valeura’s primary focus for 2018 and 2019 will be the appraisal and de-risking of the BCGA play discovered by the Yamalik-1 and evaluated by D&M. The objective of the work program is to delineate the pervasiveness of the play across the Thrace Basin lands where Valeura holds an interest, and to demonstrate that commercial flow rates can be achieved. Success will allow Valeura to convert prospective resources to contingent resources and reserves,test for upside beyond the scope of the D&M Resources Report, and reduce the overall risk of the play.

The key work program activities that support this strategy are:

• complete the Yamalik-1 well and tie-in to production facilities for long-term testing and gas sales;
• drill and test BCGA Delineation Well #1 in Banarli Licenses (100% funded by Statoil);
• drill and test BCGA Delineation Well #2 in the West Thrace Lands (Valeura 31.5%);
• drill and test BCGA Delineation Well #3 in the Banarli Licenses (Valeura 50%); and
• tie-in successful wells for long-term production testing and gas sales.

Further testing and the tie-in of Yamalik-1 is planned to commence in early Q3 2018. Suitable production testing equipment is now planned to be exported from North America to Turkey to support the operation. The Yamalik-1 production testing in Q4 2017 was complicated by the inability of available test equipment to manage the flowback of sand used in the fracing. This type of post-frac flowback is standard in North American drilling and completion operations. Once this test equipment is in country, it will then be available for testing all of the wells in the delineation drilling campaign.

The delineation drilling campaign is also expected to commence in late Q3 2018 and the three wells will be drilled back-to-back. The wells have been designed to drill to 5,000 m to attempt to find the maximum depth of the BCGA play. Yamalik-1 reached 4,196 m depth and was still in an overpressured hydrocarbon column that flowed gas and condensate after fracing and testing. Each well is expected to take about three months to drill which will then be followed by a fracing and testing program.

Additionally, Valeura and its partners are evaluating the re-completion potential of Hayrabolu-10 which was drilled in 2013 in the West Thrace Lands to a depth of 4,054 m. After standard perforation, gas flowed to surface but no fracture stimulation was performed.  If it is concluded that the well design still permits re-entry fracture stimulation, the well is expected to be completed, tied-in and tested in Q4 2018.

The Company continues to progress activity on its shallow production from the TBNG JV and Banarli Licenses.  Current activity is focused on workovers of producing wells with one new well to be drilled on the West Thrace Lands in Q2 2018. The Company expects to interpret the new 500 square km Karaca 3D seismic when final processing is completed in April 2018 and review the new portfolio of opportunities prior to making further drilling decisions.

In all its activities, the Company remains committed to continuing its safe operations and ensuring that operational and administrative functions are conducted in the most cost-efficient way.

 

2017 YEAR-END CORPORATE RESERVES REPORT

The Company has completed its independent reserves evaluation as at December 31, 2017. This evaluation was conducted by D&M in its report dated March 20, 2018 (“D&M Reserves Report”). (See Advisories and Definitions below.)

Table 1summarises the Company’s reserves in Turkey and the net present value discounted at 10% (“NPV₁₀”).D&M evaluated reserves as at December 31, 2017 on the Company’s Banarli Licenses (100% working interest) and TBNG JV lands (81.5 % working interest).

Table 1 Company Gross Reserves Volumes and Values ^(1)(2)(3)(4)

	RESERVES (Mboe)			NPV10 ($ MILLIONS – $MM)
	2017	2016	% CHANGE	2017	2016	% CHANGE
Proved
Developed producing	602	470	28	5.5	9.4	-41
Developed non-producing	311	405	-23	4.7	6.9	-32
Undeveloped	1,298	692	88	7.5	4.7	60
Total Proved (1P)	2,211	1,567	41	17.7	21.0	-16
Probable	5,605	3,137	79	47.1	40.8	15
Total Proved Plus Probable (2P)	7,816	4,704	66	64.8	61.8	5
Possible	4,433	2,526	75	51.2	42.0	22
Total Proved Plus Probable Plus Possible (3P)	12,249	7,230	69	116.0	103.8	12

Notes:

(1)    See Oil and Gas Advisories and Reserves and Resources Definitions below.

(2)    D&M’s valuations for reserves in Turkey are prepared in US$ and have been converted for purposes of this illustration to Cdn$ assuming a $Cdn/$US exchange rate of 0.74 for the year-end 2016 values and 0.80 for the year-end 2017 values.

(3)    The forecast prices used in the calculations of the present value of future net revenue for year-end 2017 are included in Table 3and are based on the D&M December 31, 2017 forecast prices.

(4)    Due to rounding, summations in the table may not add.

The reserves are primarily natural gas but small oil volumes are assigned to a number of wells. The 2017 year-end reserves by principal product type are summarized in Table 2.

Table 2 2016 Year-end Company Gross Reserves Volumes by Principal Product Type ⁽¹⁾

RESERVES CATEGORY	LIGHT AND MEDIUM CRUDE OIL (Mbbl)	CONVENTIONAL NATURAL GAS (Bcf)	TOTAL OIL EQUIVALENT (Mboe)
Proved	5	13.2	2,211
Probable	3	33.6	5,605
Total Proved Plus Probable	8	46.8	7,816
Possible	5	26.6	4,433
Total Proved Plus Probable Plus Possible	13	73.4	12,249

Note:

(1) See Oil and Gas Advisories and Reserve Definitions below.

The forecast oil and natural gas prices and cost escalation rates used in the D&M Reserves Report are shown in Table 3.

Table 3 Forecast Prices and Cost Escalation Rates ⁽¹⁾

YEAR	CONVENTIONAL NATURAL GAS		LIGHT AND MEDIUM CRUDE OIL			COST ESCALATION
	TBNG (US$/Mcf)	BANARLI (US$/Mcf)		TBNG (US$/bbl)	BANARLI (US$/bbl)	%/YEAR
2018	5.99	5.57		42.00	42.00	0.0
2019	6.09	5.66		44.25	44.25	2.0
2020	6.29	5.84		45.00	45.00	2.0
2021	6.49	6.03		45.68	45.68	2.0
2022	6.68	6.21		46.43	46.43	2.0
2023	6.78	6.30		47.10	47.10	2.0
2024	6.98	6.49		47.85	47.85	2.0
2025	7.18	6.67		48.60	48.60	2.0
2026	7.39	6.86		49.38	49.38	2.0
2027	7.59	7.06		50.16	50.16	2.0
2028	7.81	7.26		50.94	50.94	2.0
2029	8.04	7.47		51.72	51.72	2.0
2030	8.27	7.68		52.50	52.50	2.0
2031+	+2.0%/year thereafter	+2.0%/year thereafter		+2.0%/year Thereafter	+2.0%/year thereafter	+2.0%/year Thereafter

Note:

(1) The forecast prices used in the calculation of the present value of future net revenue are based on the D&M December 31, 2017 forecast prices, which are included in the 2017 AIF filed on SEDAR.

Table 5 sets forth a reconciliation of reserves changes in 2016.

Table 5 2017 Year-end Company Gross Reserves Reconciliation

CHANGES	1P (Mboe)	2P (Mboe)
At December 31, 2016	1,567	4,704
Technical Revisions	-254	-710
Discoveries	0	0
Acquisitions	1,246	6,077
Economic Factors	0	0
Production	-348	-348
At December 31, 2017	2,211	7,816

 

ANNUAL AND SPECIAL MEETING MATTERS

Valeura will hold its annual and special meeting of shareholders on May 10, 2018.  The meeting materials will be mailed in the first part of April 2018.  At the meeting, five directors will be proposed for election:  Timothy Marchant, William Sean Guest, Russell Hiscock, James McFarland and Ronald Royal.  William Fanagan has decided not to stand for re-election for medical reasons.  After twelve years on the boards of Valeura and its predecessor corporation, Northern Hunter Energy Inc., Claudio Ghersinich has also decided to step-down from the board to pursue other commitments.  Over the next few months, the board plans to conduct a search for another director.

Mr. Marchant stated, “The Board wishes to thank Mr. Fanagan and Mr. Ghersinich for their significant contributions and dedication to the Company since it was founded.  They helped lead the Company through last year’s transformative transactions to the point of its recent operational and financing success.”

 

CONFERENCE CALL

The Company will hold an audio webcast and conference call for analysts and interested listeners on March 22, 2018 at 9:30am MST (11:30am EST), including a question and answer session.

Event title: Valeura Energy Fourth Quarter 2017 Results and 2018 Outlook Conference Call

Webcast link:https://event.on24.com/wcc/r/1640461-1/704F95C344ACAE885C14E13C9AD96D96 
Direct dial-in: 1-647-427-7450
Toll-free dial-in: 1-888-231-8191

 

ABOUT THE COMPANY

Valeura Energy Inc. is a Canada-based public company currently engaged in the exploration, development and production of petroleum and natural gas in Turkey.

 

OIL AND GAS ADVISORIES

D&M Resources Report and D&M Reserves Report

The D&M Resources Report and the D&M Reserves Report were prepared using guidelines outlined in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI-51-101”). Additional resources and reserves information as required under NI-51-101 is included in the Company’s 2017 annual information form (“2017 AIF”) filed on SEDAR.

Use of Unrisked Estimates

The unrisked estimates of prospective resources referred to in this news releasehave not been risked for either the chance of discovery or the chance of development. There is no certainty that any portion of the prospective resources will be discovered. See the 2017 AIFfor details regarding risked estimates. If a discovery is made, there is no certainty that it will be developed or, if it is developed, there is no certainty as to the timing of such development or that it will be commercially viable to produce any portion of the prospective resources.

BOEs

A BOE is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Further, a conversion ratio of 6 Mcf:1 BOE assumes that the gas is very dry without significant natural gas liquids. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Short Production Test Rates

The short production test rates disclosed in this news releaseare preliminary in nature and may not be indicative of stabilized on-stream production rates. Initial on-stream production rates are typically disclosed with reference to the number of days in which production has been measured. Initial on-stream production rates are not necessarily indicative of long-term performance or ultimate recovery. To date, Valeura’s shallow gas conventional wells and fraced unconventional tight gas wells have exhibited relatively high decline rates at more than 50% and 75%, respectively, in their first year of production.

There is currently no long-term flow information for the deep, unconventional BCGAplaydiscovered with Yamalik‑1. While the same geological formations that are producing gas in the shallow are being targeted in the deep, unconventional play, they are in a different depth and pressure environment and the type curves are not expected to be indicative of Yamalik-1 future production, or any other future deep, unconventional well. A pressure transient analysis or well-test interpretation has not been carried out in respect of the production tests on the Yamalik-1 well. All natural gas rates and volumes are presented net of any load fluids.

 

RESERVES AND RESOURCES DEFINITIONS

With respect to the reserves and resources data contained herein, the following terms have the meanings indicated:

“chance of development” is the estimated probability that, once discovered, a known accumulation will be commercially developed.

“chance of discovery” is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum.

“Company Gross reserves” are the Company’s working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company

“developed” reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

“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.

“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.

“mean recoverable” resources are the probability weighted average (expected value).

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

“prospective resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

“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.

“reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

“resources” are petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced. Total resources is equivalent to total petroleum initially-in-place.

“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 classification (proved, probable, possible) to which they are assigned.

 

ADVISORY AND CAUTION REGARDING FORWARD-LOOKING INFORMATION

This news release contains certain forward-looking statements and information (collectively referred to herein as “forward-looking information“) including, but not limited to: Valeura’s view that it has discovered a world-class unconventional gas play; the costs and timelines for the deep drilling and BCGA evaluation program in 2018 and 2019; the timing and cost to tie-in and conduct a long term production test and achieve natural sales from the Yamalik-1 well; the final timeline to complete the processing of the Karaca 3D seismic; the potential for a basin-centered gas play in the Thrace Basin; management’s belief regarding the potential of the Company’sdeep basin-centered gas play and shallow gas business in the Thrace Basin; Valeura’s commitment to safety and optimizing operational and administrative functions; Valeura’s business strategy and outlook; the ability to finance future developments; and the determination of the Company’s2018 shallow gas program. Forward-looking information typically contains statements with words such as “anticipate”, estimate”, “expect”, “target”, “potential”, “could”, “should”, “would” or similar words suggesting future outcomes. The Companycautions readers and prospective investors in the Company’ssecurities to not place undue reliance on forward-looking information, as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.

Statements related to “reserves” or “prospective resources” are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding “reserves” and “prospective resources” may include: estimated volumes and value of Valeura’s oil and gas reserves; estimated volumes of prospectiveresources and the ability to finance future development; and, the conversion of a portion of prospective resources into reserves.

Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: political stability of the areas in which the Companyis operating and completing transactions, and in particular the aftermath of the July 2016 failed coup attempt in Turkey and April 2017 constitutional referendum; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the prospectivity of the deep BCGA and shallow gas plays on the TBNG JV lands and Banarli licences; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licences and leases; and the Company’scontinued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programs and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, fracing and other specialized oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Companybelieves the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect.

Forward-looking information involves significant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves are speculative activities and involve a significant degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Companyincluding, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines for the timelines and costs for the deep evaluation in 2018 and 2019; the risks of disruption to operations and access to worksites, threats to security and safety of personnel and potential property damage related to political issues, terrorist attacks, insurgencies or civil unrest in Turkey; political stability in Turkey, including potential changes in Turkey’s constitution, political leaders or parties or a resurgence of a coup or other political turmoil; the uncertainty regarding government and other approvals; counterparty risk; potential changes in laws and regulations; risks associated with weather delays and natural disasters; the risk associated with international activity; and, the uncertainty regarding the ability to fulfil the drilling commitment on the West Thrace lands. The forward-looking information included in this news release is expressly qualified in its entirety by this cautionary statement. The forward-looking information included herein is made as of the date hereof and Valeura assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law. See Valeura’s 2017 AIF for a detailed discussion of the risk factors.

 

Additional information relating to Valeura is also available on SEDAR atwww.sedar.com

 

For further information please contact:

Sean Guest, President and CEO
Valeura Energy Inc.
(403) 930-1172
sguest@valeuraenergy.com

Steve Bjornson, CFO
Valeura Energy Inc.
(403) 930-1151
sbjornson@valeuraenergy.com

www.valeuraenergy.com