Calgary, March 14, 2019: Valeura Energy Inc. (TSX:VLE) (“Valeura” or the “Company”), the upstream natural gas producer focused on appraising and developing an unconventional gas accumulation in the Thrace Basin of Turkey, is pleased to report its financial and operating results for the three month period ended December 31, 2018 and the year ended December 31, 2018, and year-end 2018 reserves and prospective resources.

The complete quarterly reporting package for the Company, including the audited financial statements and associated management’s discussion and analysis (“MD&A”) and the 2018 annual information form (“AIF”), have been filed on SEDAR at www.sedar.comand posted on the Company’s website at

2018 Financial and Operating Results Highlights

  • Average Q4 2018 realised gas prices of $9.06/Mcf, up 36% from Q3 2018
  • Q4 2018 average production of 623 boe/d, 2018 exit rate of 777 boe/d
  • Q4 2018 operating netbacks of $32.48/boe, up 37% from Q3 2018
  • Net working capital surplus at year-end of $59.5 million
  • Total Proved Plus Probable Reserves of 7,350 Mboe at year-end, down 6% from the prior year
  • Total Proved Plus Probable Reserves value of $87.5 million, up 35% from the prior year
  • Prospective Resources of 10.1 Tcf of unrisked natural gas remains unchanged at year end 2018

Ongoing Operations and Corporate Highlights

  • Devepinar-1 has been drilled to its intermediate casing point at 3,375 metres and is currently being readied for logging. Clear indication of overpressured gas prior to section TD.
  • Operations are ongoing at Yamalik-1 with preparations for Production Logging Tool (“PLT”) zonal analysis which is planned for the coming weeks.
  • Operations are ongoing at Inanli-1 for a Diagnostic Fracture Injectivity Test (“DFIT”) in the coming weeks to assist in planning for reservoir stimulation and testing operations in Q2 2019.
  • Preparation and filing of documents for listing of the Company’s common shares on the London Stock Exchange is ongoing, with timing of announcement driven by final approval from the UK Listing Authority.

Sean Guest, President and CEO commented:

“Our financial results from 2018 reflect the high value of gas in Turkey and reiterates why we have built a portfolio of scale in this optimally located market. With prices continuing to track the broader European markets, we have seen price realisations of more than $9/Mcf, and coupled with our focus on managing production costs, we generated strong operating netbacks of $32.48/boe in Q4. These results bode well for the long-term value of our unconventional resource in Turkey, and underscore just how valuable our Basin Centered Gas Accumulation (“BCGA”) play could be for Valeura shareholders.

We are progressing our deep appraisal programme on all fronts. The Inanli-1 well accomplished all its drilling objectives earlier this year, including encountering two intervals interpreted to be reservoir sweet spots, which correlate to Yamalik-1. We are about to embark on an exciting completion programme at Inanli.  Meanwhile, the Devepinar-1 well is drilling ahead at a location 20km to the west and will test the lateral extent of our play. Already we have seen early indications of over-pressured gas, which confirms our mapping on the breadth of the play. At Yamalik-1, we continue to monitor the production and will re-enter the wellbore to conduct some zone-by-zone production analysis aimed at gathering as much data as possible.

Financially, we are in a strong position. With approximately $60 million cash on hand, we are fully funded through our 2019 capital programme. And with our upcoming listing of the Company’s common shares in London, we are looking forward to attracting more market interest, to bolster value for our shareholders.”

Table 1 Financial and Operating Results Summary

Three Months Ended December 31, 2018 Three Months Ended September 30, 2018 Year Ended December 31, 2018 Three Months Ended December 31, 2017 Year Ended December 31, 2017
(thousands of CDN$ except share and per share amounts)
Petroleum and natural gas revenues 3,150 2,401 11,969 3,824 14,646
Adjusted funds flow (used) (1) 3,078 (430) 3,655 (446) (1,205)
Net loss from operations (634) (2,647) (7,120) (946) (8,384)
Exploration and development capital 3,282 2,739 8,023 1,856 12,791
Acquisitions 21,450
Dispositions (26,288)
Net working capital surplus 59,520 56,337 59,520 3,421 3,421
Cash 62,380 56,522 62,380 11,108 11,108
Common shares outstanding
Share trading
   Crude oil (barrels (“bbl”)/d) 8 8 9 8
   Natural Gas (one thousand cubic feet (“Mcf”)/d) 3,689 3.931 4,257 6,176 5,662
Average reference price
Brent ($ per bbl)
BOTAS Reference ($ per Mcf) (2)
Average realised price
Crude oil ($ per bbl)
Natural gas ($ per Mcf)

Average Operating Netback
($ per boe @ 6:1) (1)
32.48 23.63 25.79 22.35 23.76


See the 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 flow is 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.

(2)     Boru Hatlari ile Petrol Tasima Anonim Sirketi (“BOTAS”) owns and operates the national crude oil and natural gas pipeline grids in Turkeyand 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 AIFfiled on SEDAR for further discussion.

Net petroleum and natural gas sales in Q4 2018 averaged 623 boe/d, which was 5% lower than Q3 2018.  This reflects natural declines in producing conventional reservoirs. Production was increased in late Q4 2018 as a result of workover activities and the exit rate for the last week of the quarter was 777 boe/d. The Company is continuing an active workover and maintenance programme intended to minimise the natural declines, despite most of the Company’s operational effort being applied to the appraisal of its deeper unconventional gas resource.

Production revenue in Q4 2018 was $3.2 million, an increase of 31% over Q3 2018. This reflects markedly higher realised commodity prices in Q4, driven mainly by increases in Turkey’s BOTAS Reference price. The increased realised prices resulted in much higher average operating netbacks of $32.48/boe, an increase of 37% over the $23.63/boe recorded in Q3 2018.

Exploration and development capital spending was $3.3 million in Q4 2018, increased from $2.7 million in the prior quarter, reflecting spending related to the tie-in and testing of the Yamalik-1 well and procurement of long-lead items associated with the ongoing appraisal drilling and testing programme planned for 2019.

As of December 31, 2018, the Company had a net working capital surplus of $59.5 million, which is more than adequate to fund its planned forward capital expenditure programme throughout 2019.



Valeura is fully focused on appraising and de-risking its BCGA play in the Thrace Basin. The objective of the Company’s work program for 2019 is to demonstrate that over-pressured gas is pervasive across Valeura’s Thrace Basin lands and to show that commercial flow rates can be achieved. The key activities to support this objective include ongoing data-capture from the Yamalik-1 exploration well, and the Company’s continuing appraisal drilling and testing programme.

Valeura is continuing to gather data from the Yamalik-1 exploration well, which was drilled and flow-tested in 2017, and subsequently recompleted and tied into the Company’s production infrastructure in 2018.  In 2019, the Company intends to re-enter the well to conduct production logging testing as a way to understand zone-by-zone fluid composition and production rates, thereby refining target intervals for future drilling and completion operations.

The Company concluded the drilling of Inanli-1 to a total depth of 4,885 metres in January 2019.  Valeura announced positive results that the well had encountered a 1,615 metre gross column of high net-to-gross, gas-bearing sandstone, and identified at least four zones interpreted to contain greater natural fracturing than previously observed. The well has been cased and left in a state ready for production testing.  Fracking and testing operations are expected to commence in early Q2 2019 and could extend throughout the quarter.  The Company is constructing a pipeline to tie in the well to its infrastructure in anticipation of a long-term production test. Costs for the Inanli-1 testing will be carried by Equinor Turkey B.V. (“Equinor”) and completion will fulfill their earning obligations under the Banarli farm-in agreement.

Valeura began drilling the second appraisal well, Devepinar-1, in February 2019.  The well is a substantial step-out from prior BCGA wells, approximately 20 km from Inanli-1, and accordingly, will test the lateral extent of the BCGA play to the western side of the basin.  If drilling and logging results are positive, the Company intends to complete, frack, and production test the well. Costs for Devepinar-1 are being shared proportionately by the working interest share of each partner, with Valeura’s share being 31.5%.

A third appraisal well is envisaged for 2019, and Valeura and its partners will select a location based on drilling and testing data gathered from Yamalik-1, Inanli-1, and Devepinar-1.

Valeura remains very well positioned to finance its ongoing BCGA appraisal and all corporate activities through to 2020. The Company’s working capital position is more than adequate to fund its working interest share of the two appraisal wells post Inanli-1 and all of the expected fracking and testing. In all its activities, the Company remains committed to continuing its safe and environmentally responsible operations and ensuring that operational and administrative functions are conducted in the most cost-efficient way.



The Company has completed its independent reserves evaluation as at December 31, 2018. This evaluation was conducted by DeGolyer and MacNaughton (“D&M”) in its report dated March 13, 2019 (“D&M Reserves Report”).

Table 2summarises the Company’s reserves in Turkey and the before tax net present value discounted at 10% (“NPV10”).D&M evaluated reserves as at December 31, 2018 on the Company’s Banarli licenses (100% working interest shallow/50% deep) and TBNG JV lands (81.5 % working interest shallow / 31.5% deep).

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



Before Tax NPV10


2018 2017 %


2018 2017 %


Developed producing 502 602 -17 9.6 5.5 75
Developed non-producing 204 311 -34 4.1 4.7 -13
Undeveloped 1256 1,298 -3 12.6 7.5 68
Total Proved (1P) 1,962 2,211 -11 26.3 17.7 49
Probable 5,388 5,605 -4 61.1 47.1 30
Total Proved Plus Probable (2P) 7,350 7,816 -6 87.5 64.8 35
Possible 4213 4,433 -5 61.0 51.2 19
Total Proved Plus Probable Plus Possible (3P) 11,563 12,249 -6 148.5 116.0 28


(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 0.80 for the year-end 2017 values and 0.73 for the year-end 2018 values.

(3)    The forecast prices used in the calculations of the present value of future net revenue for year-end 2018 are included in Table 4 and are based on the D&M December 31, 2018 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 2018 year-end reserves by principal product type are summarised in Table 3.


Table 3 2018 Year-end Company Gross Reserves Volumes by Principal Product Type (1)









Proved 15 11.7 1,962
Probable 6 32.3 5,388
Total Proved Plus Probable 21 44.0 7,350
Possible 10 25.2 4,213
Total Proved Plus Probable Plus Possible 31 69.2 11,563


(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 4.

Table 4 Forecast Prices and Cost Escalation Rates (1)(2)



(US$/Mcf)  (US$/bbl) %/YEAR
2019 7.24 57.35 0.0
2020 7.33 58.08 2.0
2021 7.39 58.52 2.0
2022 7.44 58.88 2.0
2023 7.46 59.07 2.0
2024 7.61 60.25 2.0
2025 7.76 61.46 2.0
2026 7.92 62.69 2.0
2027 8.07 63.94 2.0
2028 8.24 65.22 2.0
2029 8.40 66.52 2.0
2030 8.57 67.85 2.0
2031+ +2.0%/year







(1)      The forecast prices used in the calculation of the present value of future net revenue are based on the D&M December 31, 2018 forecast prices, which are included in the AIF filed on SEDAR.

The Conventional Natural Gas price forecast in Table 3 is for the TBNG assets. The Conventional Natural Gas price for the Banarli assets is approximately 97% of the TBNG forecast, reflecting a 15% discount in sale to TBNG with Valeura interest in TBNG at 81.5%.

Table 5sets forth a reconciliation of reserves changes in 2018.

Table 5 2018 Year-end Company Gross Reserves Reconciliation





At December 31, 2017 2,211 7,816
Technical Revisions -12 -243
Discoveries 27 41
Acquisitions 0 0
Economic Factors 0 0
Production -265 -265
At December 31, 2018 1,961 7,349



There were no substantial changes to the Company’s prospective resources in Turkey as at December 31, 2018 versus December 31, 2017. In preparing their report (the “D&M Resources Report”), D&M reviewed the flow data from the Yamalik-1 long-term production test, and drilling data from a portion of the Inanli-1 well, which was being drilled at year end. Based on the limited new information available as of December 31, 2018, neither the volumes nor the risking were changed. Like the prior year’s resources report, the D&M Resources Report indicates 10.1 Tcf of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate.

Table 6 Valeura Working Interest Natural Gas Prospective Resources at December 31, 2018(1)

Valeura Working Interest Lands Unrisked Chance of Commerciality % Risked
Mean Estimate
High Estimate Mean Estimate
Conventional Natural Gas – Bcf
Total 3,229 7,652 20,077 10,137 51.1 5,182


(1) See Notes to Prospective Resources Table (Table 6) below.



Valeura will hold its annual general meeting of shareholders on May 9, 2019. The meeting materials will be mailed in the first part of April 2019.



The management team will host an investor and analyst conference call and question session at 9:00 a.m. (Calgary), 11:00 a.m. (Toronto), 3:00 p.m. (London) today, Thursday, March 14, 2019.

Interested listeners can connect via live webcast or dial-in conference call, as indicated below. Please register approximately 15 minutes prior to the start of the call. The results will be made available on the Company’s website at:

Event title: Valeura Fourth Quarter 2018 Results Conference Call

Webcast link:
Calgary dial-in: +1 587 880 2171
Toronto dial-in: +1 416 764 8688
North America toll-free: +1 888 390 0546
UK toll-free: +44 (0) 800 652 2435



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



D&M Reserves Report and D&M Resources Report
The D&M Reserves Report and the D&M Resources 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 reserves and resources information as required under NI 51-101 is included in the AIF filed on SEDAR.

Use of Unrisked Estimates
The unrisked estimates of prospective resources referred to in this news release have 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 AIF for 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.

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 naturalgas is significantly different from the energy equivalency of 6:1, utilising a conversion on a 6:1 basis may be misleading as an indication of value.



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.



 “Valeura Working Interest Lands” Valeura’s working interest in the lands (exploration licences and production leases) that are encompassed (all or a portion thereof) in the basin-centered gas prospect in the Teslimkoy/Kesan formation is as follows: Banarli 50%, West Thrace 31.5% and South Thrace 81.5%.

“Low Estimate” The low estimate is the P90 quantity. P90 means there is a 90% chance that the estimated quantity will be equaled or exceeded.

“Best Estimate” The best estimate is the P50 quantity. P50 means there is a 50% chance that the estimated quantity will be equaled or exceeded.

“High Estimate” The high estimate is the P10 quantity. P10 means there is a 10 % chance that the estimated quantity will be equaled or exceeded.

“Mean Estimate” The mean estimate is the probability-weighted average (expected value).

“Chance of Commerciality” The chance of commerciality is defined as the product of the chance of discovery and the chance of development.

Chance of discovery in the D&M Resources Report is referred to as the probability of geologic success (Pg), which is defined as the probability of discovering reservoirs that flow hydrocarbons at a measurable rate. The Pg is estimated by quantifying with a probability, each of the following geologic chance factors: trap, source, reservoir and migration. The product of the probabilities of these four chance factors is Pg. Pg is predicated and correlated to the minimum case prospective resources gross recoverable volume(s). Consequently, the Pg is not linked to economically viable volumes, economic flow rates or economic field size distributions.

In the D&M Resources Report, two factors have been considered in determining the chance of development as follows:

Chance of development = Ptefs (probability of threshold economic field size) x Pd (probability of development)

D&M defines Ptefs as the probability of discovering an accumulation that is large enough to be economically viable. Ptefs is estimated by using the prospective resources potential recoverable quantities distribution in conjunction with the threshold economic field size (TEFS). TEFS is the minimum amount of the producible petroleum required to recover the total capital and operating expenditure used to establish the potential accumulation as having a potential present worth at 10% equal to zero using the most likely price scenario.

D&M defines Pd as the probability that a given discovery will be a viable development project. It takes into account the chance that the discovered target zone will flow the predicted hydrocarbon phase(s) at a commercial rate. It also considers the chance that the target zone can be mechanically completed and appraised in a reasonable time and in compliance with the projected cost schedule. The Pd is estimated by the quantification and product of these two chance factors.

“Risked Mean Estimate” The risked mean estimate of conventional natural gas prospective resources = the unrisked mean estimate x chance of discovery x chance of development.

Note, the Unrisked Low Estimate, Best Estimate, and High Estimate are arithmetic summations of all prospects.



This news release contains certain forward-looking statements and information (collectively referred to herein as “forward-looking information”) including, but not limited to: the potential of a basin-centered gas play in the Thrace Basin; management’s belief regarding the potential of the Company’s deep basin-centred gas play and shallow gas business in the Thrace Basin; the Company’s belief in the pervasiveness of over-pressured gas across the Company’s Thrace Basin lands; the intention of the Company to appraise and de-risk its BCGA in the Thrace Basin; the objective of the 2019 work program and the key activities anticipated to support such objective; the costs and timelines for the deep drilling and BCGA evaluation programme and the adequacy of its financial resources to fund forward appraisal operations; the ability to use Yamalik-1 data to refine target intervals for future drilling; the Company’s intention to re-enter the Yamalik-1 wellbore to conduct zone-by-zone production analysis; the intention of the Company and timing to conduct fracking, flow-testing and completion on Inanli-1 and Devepinar-1; the Company’s expectation that there will be a third appraisal well in 2019; the Company’s expectation of a long-term production test with respect to Inanli-1; and the potential listing of the Company’s common shares in London and that such potential listing may bolster value for the Company’s shareholders. 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 Company cautions readers and prospective investors in the Company’s securities 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 prospective resources 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: continued political stability of the areas in which the Company is operating; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from the Turkish government and regulators in a manner consistent with past conduct; future seismic and drilling activity on the expected timelines; the continued favourable pricing and operating netbacks in Turkey; future production rates and associated operating netbacks and cash flow; decline rates; future sources of funding; future economic conditions; future currency exchange rates; the ability to meet drilling deadlines and other requirements under licenses and leases; and the Company’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programmes 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, fracking and other specialised oilfield equipment and service providers, changes in partners’ plans and unexpected delays and changes in market conditions. Although the Company believes 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 degree of risk. A number of factors could cause actual results to differ materially from those anticipated by the Company including, but not limited to: the risks of currency fluctuations; changes in gas prices and netbacks in Turkey; uncertainty regarding the contemplated timelines and costs for the deep evaluation; 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 or civil unrest in Turkey; potential changes in laws and regulations, the uncertainty regarding government and other approvals; counterparty risk; risks associated with weather delays and natural disasters; and the risk associated with international activity. 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 the 2018 AIF for a detailed discussion of the risk factors.

The proposed admission of the Company’s common shares to the Standard Segment of the Official List of the Financial Conduct Authority and trading on the Main Market of the London Stock Exchange is subject (inter alia) to the approval of the UK Listing Authority (“UKLA”) and the publication by the Company of a prospectus approved by the UKLA. It is not intended that there will be any issue of common shares in conjunction with such admission and listing.

Additional information relating to Valeura is also available on SEDAR at


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


For further information, please contact:

Valeura Energy Inc. (General and Investor Enquiries)                   +1 403 237 7102
Sean Guest, President and CEO
Steve Bjornson, CFO
Robin Martin, Investor Relations Manager,

CAMARCO (Public Relations, Media Advisor)                                  +44 (0) 20 3757 4980
Billy Clegg
Owen Roberts