VLU.L Regulatory News (VLU)

VALEURA ANNOUNCES SECOND QUARTER 2019 RESULTS ANDPOSITIVE PRODUCTION TEST RESULTS AT INANLI-1

Calgary, August 12, 2019: Valeura Energy Inc. (TSX:VLE, LSE:VLU) ("Valeura" or the "Company"), the upstream natural gas producer focused on appraising and developing an unconventional gas accumulation play in the Thrace Basin of Turkey in partnership with Equinor, is pleased to report its financial and operating results for the three month period ended June 30, 2019, and to report a positive production test at the Inanli-1 appraisal well, where the Company has successfully flowed natural gas from the first stimulated zone.

Highlights from Q2 2019 and beyond

·; Achieved a safety milestone of 801 days of continuous operations without a lost time incident;

·; Q2 2019 average production of 700 boe/d, down 5% from Q2 2018 and down 9% from Q1 2019;

·; Q2 2019 operating income of $1.8 million was 20% higher than Q2 2018 and 21% lower than Q1 2019;

·; Q2 2019 average realised gas price of $8.54/Mcf, 15% higher than Q2 2018 and down 7% from Q1 2019;

·; BOTAS reference gas price increased 15% on August 1, 2019, equivalent to $10.35/Mcf;

·; Net working capital surplus of $52.3 million at June 30, 2019 ($56.1 million at March 31, 2019);

·; Completed drilling operations on the Devepinar-1 appraisal well safely and well under budget.

Highlights from Inanli-1 Appraisal Well Testing

·; A 21 metre gross interval, between 4,263 and 4,284 metres was stimulated;

·; The well has been flowing since August 3, 2019 and is still cleaning up using artificial lift;

·; Gas flow is currently stable and the average rate for the first eight days of production is 643 Mcf/d;

·; Water is currently being recovered at a low rate of 44 bbls/d and has continued to decline daily;

·; Condensate-gas ratio is low in this zone at 5 bbl/MMcf.

The Company's focus for Q3 and Q4 2019 is to continue testing the flow potential of the significant, interpreted gas columns encountered in its new appraisal wells to de-risk the commerciality of its 10 Tcfe (286 BCM) of unrisked gas resource, including 236 MMbbl (32 MMTonnes) of condensate, net to Valeura. The stimulation and production testing is being conducted on a zone-by-zone basis to provide more definitive flow characteristics. Identifying specific zones that can sustain gas flow will be important to demonstrate the commerciality of the Company's Basin Centred Gas Accumulation ("BCGA") play and will underpin the work programme for the next stage of appraisal.

Sean Guest, President and CEO commented:

"I am very pleased with our second quarter results. Price realisations and operating netbacks remain strong and are getting stronger with the recent increase in BOTAS' reference price. At the same time, our team has done an excellent job offsetting natural declines and maintaining production from our conventional shallow reservoirs, which is helping to preserve our strong financial position, including our net working capital surplus of $52.3 million.

"These favourable netbacks help illuminate the long-term economics for gas production in Turkey. Meanwhile, the substantial value of our BCGA play is becoming clearer with every step of our appraisal programme. At the Inanli-1 well, we have stimulated the deepest reservoir zone ever tested in the BCGA, and initial results have been very encouraging with a good, stable gas flow and minimal water production. We are excited by the indications of potential commerciality at this depth and look forward to the results from shallower zones."

Financial and Operating Results Summary 

Notes:

See the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2019 and 2018 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) BOTAS regularly posts prices and its Level-2 Wholesale Tariff benchmark is shown herein as a reference price. See the Company's 2018 annual information form ("AIF") filed on SEDAR for further discussion.

(3) Proceeds received from Equinor to complete spending commitment for Phase 2 of the Banarli Farm-in. Recorded in the financial statements as a reduction of Exploration and Evaluation Assets.

Net petroleum and natural gas sales in Q2 2019 averaged 700 boe/d which was 5% lower than Q2 2018. Production was 9% lower when compared to Q1 2019 as a result of a one-week customer shutdown associated with the Eid holidays, no oil liftings were recorded in the quarter, and natural declines in the reservoirs.

Production revenue in Q2 2019 was $3.3 million, an increase of 11% relative to Q2 2018, but a decrease of 16% from Q1 2019. The recent decrease is primarily the result of lower production during the quarter combined with a reduction in gas price realisations when expressed in Canadian dollars.

On August 1, 2019, BOTAS increased the reference price for gas 14.7%, more than offsetting declines in the value of the Turkish Lira in the first half of 2019. In Canadian dollar terms the BOTAS reference price is $10.35/Mcf as of August 1, 2019. This realised price will vary going forward depending on changes in the Turkish Lira exchange rate.

Exploration and development capital spending was $4.1 million in Q2 2019, a decrease of 28% from Q1 2019 reflecting the end of drilling operations at the Devepinar-1 well in April 2019.

As of June 30, 2019, the Company had a net working capital surplus of $52.3 million compared to $56.1 million at March 31, 2019 primarily due to capital expenditures offset by cash flow from the business.

Testing Results on Inanli-1 First Zone

The first of a series of production tests on Inanli-1 was designed to test a single 21 metre zone between 4,263 and 4,284 metres. Petrophysical data indicate the zone is moderately fractured and has 14.2 metres of net sand (above a 3% porosity cutoff) with an average porosity of 5%. Approximately one third of the originally intended volume of proppant was successfully deployed into the reservoir, resulting in a relatively small reservoir stimulation, both in terms of the net reservoir stimulated and the amount of fluid and proppant used.

Despite the relatively small reservoir stimulation, the resulting gas flow is highly encouraging. Production tubing was installed directly after the stimulation and artificial lift was applied to accelerate the cleanup of the well and to improve the quality of the acquired data. Production through tubing commenced on August 3, 2019 and the average gas rate for the first eight days was 643 Mcf/d. The quoted gas rate is the actual gas produced from the reservoir, and does not include any of the gas used for artificial lift. The gas has no material impurities or contaminants and accordingly the majority of the test volumes are being produced into the Company's gas infrastructure and sold to customers.

The results of the test are also very positive in terms of recovered water. There has been a continual and steady decrease in the amount of water recovered during flowback. The rate on day eight of production had decreased to 44 bbl/d. Importantly, the water rate is decreasing very much in line with general expectations for the recovery of stimulation fluids from an unconventional reservoir. The current low aggregate water rate (stimulation fluids and/or formation water) is interpreted to be relatively insignificant and not a concern for commercial production.

The condensate-gas ratio ("CGR") was measured as 5 bbls/MMcf, and while the figure has varied slightly over the eight day test, the CGR in this zone is consistently lower than measured in other production tests in the Thrace BCGA. While a lower CGR is naturally expected at deeper depths, conclusions cannot be drawn on CGR variability at this time and will require further test results from both the shallower zones in the Inanli-1 well, and from the Devepinar-1 well testing. The demonstration of the commerciality of the BCGA play is not dependent on the amount of condensate. Unlike North America, gas prices are very strong in Turkey and gas production will drive the commerciality of any development.

At this time Valeura believes it has acquired all of the key data required from this zone. The Company is reviewing these data with its partner, Equinor, to confirm when to conclude the current test. While the base plan for Inanli-1 was to stimulate and test four zones, given the positive results from this test, discussions are also ongoing on whether to expand the number of stimulations and/or the number of tests in Inanli-1.

2019 Outlook

The Company's near-term work programme is focused on reservoir stimulation and production testing of the new wells drilled in the BCGA to understand the flow characteristics and the fluid compositions of the rock across the wide depth range of the BCGA. These data are key to calibrating the petrophysical and core data acquired during drilling operations, and in determining the next steps in the appraisal program to progress the project towards commerciality. The Company believes a rigorous, scientific approach is critical in this early stage of appraisal to increase the chance of a commercial development of the BCGA resource.

The completion programme has been designed to capture as much key data as possible from each individual zone, and not to maximise initial production rates. The primary objectives are to demonstrate that it is possible to achieve sustained gas flow from an individual zone, and to understand the composition of gas, condensate, and potentially any water from each zone. The testing programme will evaluate different zones both vertically down through the BCGA interval and laterally across the basin, to identify those zones which exhibit the potential for commercial development. The Inanli-1 well testing is ongoing and a notional program has been discussed with our partners for the Devepinar-1 well.

Valeura is conducting scenario planning for its next appraisal steps following the ongoing stimulation and testing campaign, which will form the basis of a 2020/2021 work programme. Assuming the Company identifies one or more zones which exhibit the potential for sustained gas flow, the Company's priority is expected to shift to maximising access to these high-graded stratigraphic intervals via horizontal wells and multi-stage reservoir stimulation, with the potential for much higher flow rates.

Valeura remains very well positioned to finance its ongoing BCGA appraisal and all corporate activities into 2020, and the Company anticipates exiting 2019 with in excess of $40 million of positive working capital. The Company's financing needs will be re-evaluated based on the results of the ongoing stimulation and testing programme and the resulting work programme selected for 2020 and beyond.

In all its activities, the Company adheres to a very high standard of environmental, social, and governance stewardship, and believes protecting the health and safety of all those affected by its business is paramount to its sustainability.

Webcast and Conference Call

Valeura's management team will host an investor and analyst conference call and question session at 09:00 (Calgary) / 11:00 (Toronto) / 16:00 (London) today, Monday August 12, 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.

Event title: Valeura Second Quarter 2019 Results Conference Call

Webcast link: https://event.on24.com/wcc/r/2047014/773994124484C6F8A38CAEB17B6BEA6FCalgary dial-in: +1 587 880 2171Toronto dial-in: +1 416 764 8688North America toll-free: +1 888 390 0546UK toll-free: +44 0800 6522435

The complete quarterly reporting package for the Company, including financial statements and associated management's discussion and analysis ("MD&A"), will be filed on SEDAR at www.sedar.com and posted on the Company's website at www.valeuraenergy.com.

About Valeura Energy

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

Since Valeura was established in 2010, the Company has executed a number of transactions and currently holds interests in 20 production leases and exploration licences in the Thrace Basin of Turkey totalling 0.46 MM acres (gross) or on a net basis 0.37 MM acres of shallow rights and 0.26 MM net acres of deep rights.

Valeura is appraising an unconventional BCGA play in the Thrace Basin on its deep rights, which has been evaluated by DeGolyer and MacNaughton to hold, effective December 31, 2018, 10.1 Tcfe of estimated working interest unrisked mean prospective resources of natural gas, which includes 236 MMbbl of condensate. By applying 3D seismic, modern reservoir stimulation technology and horizontal and deeper vertical well drilling, Valeura is aiming to achieve commercial scale operations from this tight gas resource.

In addition, the Company owns an extensive network of gas gathering and sales infrastructure to support direct marketing of natural gas to end users, and in Q2 2019, produced an average of 4.2 MMcf/d of natural gas from conventional gas accumulations in its shallower rights.

The Company is listed on both the Toronto Stock Exchange under VLE and on the Main Market of the London Stock Exchange under VLU.

Additional information relating to Valeura is also available on SEDAR at www.sedar.com and on the Company's corporate website at www.valeuraenergy.com.

For further information please contact:

Valeura Energy Inc. (General and Investor Enquiries) +1 403 237 7102Sean Guest, President and CEOSteve Bjornson, CFORobin Martin, Investor Relations ManagerContact@valeuraenergy.com, IR@valeuraenergy.com 

GMP First Energy (Financial Adviser and Joint Corporate Broker) +44 (0) 20 7448 0200Jonathan Wright, Hugh Sanderson

Canaccord Genuity Limited (Joint Corporate Broker) +44 (0) 20 7523 8000Henry Fitzgerald-O'Connor, James Asensio

CAMARCO (Public Relations, Media Adviser) +44 (0) 20 3757 4980Owen Roberts, Billy Clegg, Monique Perks, Thayson PinedoValeura@camarco.co.uk 

Oil and Gas Advisories

boe

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, utilising a conversion on a 6:1 basis may be misleading as an indication of value.

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 2018 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.

Short Production Test Rates

The short production test rates disclosed in this news release are preliminary in nature and may not be indicative of stabilised on-stream production rates, long-term performance or ultimate recovery. There is currently no long-term flow information for the deep, unconventional BCGA. 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, pressure environment and generally have a low porosity and permeability such that any type curves from the shallow are not expected to be indicative of deep, unconventional well production rates.

Prospective Resources

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.

There is no certainty that any portion of the prospective resources will be discovered. 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.

Please see the AIF, which is available under Valeura's issuer profile on SEDAR at www.sedar.com, for more information with respect to the Company's prospective resources, including details regarding risked estimates.

Forward-Looking Statements and Cautionary Statements

This news release contains certain forward-looking statements and information (collectively referred to herein as "forward-looking information") including, but not limited to: the characteristics and objectives of the Inanli-1 and Devepinar-1 completion programmes; Valeura's intention to stimulate and production test the Inanli-1 and Devepinar-1 wells; the timing to commence reservoir stimulation and testing and/or recompletion operations; the number of well tests Valeura intends to conduct; the expectation that future initial production rates and ultimate recoveries per well will increase with horizontal drilling and multi-stage reservoir stimulation; the expectation that sustained flow will increase the chance of commercial development; Valeura's expectations regarding formation water and frack fluid recovery; the Company's priorities with respect to its work programme; Valeura's expectations with respect to working capital at the end of 2019; the assessment of the resources in the test formations; the potential of the Company's unconventional basin-centered gas accumulation play in the Thrace Basin; and the Company's intention to achieve commercial scale operations. 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 "prospective resources" are deemed forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the prospective resources can be profitably produced in the future. Specifically, forward-looking information contained herein regarding "prospective resources" include 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, reservoir stimulation 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 AIF for a detailed discussion of the risk factors.

Any financial outlook or future oriented financial information in this news release, as defined by applicable securities legislation, has been approved by management of Valeura, including, but not limited to, Valeura's expectations with respect to working capital at the end of 2019. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

This announcement does not constitute an offer to sell or the solicitation of an offer to buy securities in any jurisdiction, including where such offer would be unlawful. This announcement is not for distribution or release, directly or indirectly, in or into the United States, Ireland, the Republic of South Africa or Japan or any other jurisdiction in which its publication or distribution would be unlawful.

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.

Condensed Interim Consolidated Financial Statements (unaudited)

as at June 30, 2019 and for the three and six months ended June 30, 2019 and 2018

Condensed Interim Consolidated Statements of Financial Position

See accompanying notes to the condensed interim consolidated financial statements

Condensed Interim Consolidated Statements of Loss and Comprehensive Loss

For the three and six months ended June 30, 2019 and 2018

See accompanying notes to the condensed interim consolidated financial statements

Condensed Interim Consolidated Statements of Cash Flows

For the three and six months ended June 30, 2019 and 2018

Condensed Interim Consolidated Statements of Changes in Shareholders' Equity

For the six months ended June 30, 2019 and 2018

See accompanying notes to the condensed interim consolidated financial statements

Notes to the Condensed Interim Consolidated Financial Statements

Three and six months ended June 30, 2019 and 2018

1. Reporting Entity

Valeura Energy Inc. ("Valeura" or the "Company") and its subsidiaries are currently engaged in the exploration, development and production of petroleum and natural gas in Turkey. Valeura is incorporated in Alberta, Canada and has subsidiaries in the Netherlands, British Virgin Islands and Turkey. Valeura's shares are traded on the Toronto Stock Exchange ("TSX") under the trading symbol VLE. On April 25, 2019, Valeura's shares also commenced trading on the Main Market of the London Stock Exchange ("LSE"), under the trading symbol "VLU". Valeura's head office address is 1200, 202 - 6 Avenue SW, Calgary, AB, Canada.

2. Basis of Preparation

(a) Statement of compliance

These unaudited condensed interim consolidated financial statements have been prepared in accordance with IAS 34 - Interim Financial Reporting of the International Financial Reporting Standards ("IFRS"). The unaudited condensed interim consolidated financial statements have been prepared in accordance with IFRS accounting policies and methods of computation as set forth in Valeura's audited consolidated financial statements for the year ended December 31, 2018, with the exception as noted below of certain disclosures that are normally required to be included in annual consolidated financial statements which have been condensed or omitted in the interim statements, in addition to the adoption of IFRS 16 - Leases. The attached unaudited condensed interim consolidated financial statements should be read in conjunction with Valeura's audited consolidated financial statements and MD&A for the year ended December 31, 2018.

Operating, transportation and marketing expenses in profit or loss are presented as a combination of function and nature in conformity with industry practices. Depletion and depreciation and finance expenses are presented in a separate line by their nature, while net administrative expenses are presented on a functional basis. The use of estimates and judgements is also consistent with the December 31, 2018 financial statements.

The unaudited condensed interim consolidated financial statements were authorised for issue by the Board of Directors on August 9, 2019.

(b) Basis of measurement

These unaudited condensed interim consolidated financial statements have been prepared on the historical cost basis except for certain financial and non-financial assets and liabilities, which have been measured at fair value. The methods used to measure fair value are consistent with the Company's December 31, 2018 audited consolidated financial statements.

The Company's unaudited condensed interim consolidated financial statements include the accounts of Valeura and its subsidiaries and are expressed in thousands of Canadian Dollars, unless otherwise stated.

(c) Functional and presentation currency

The unaudited condensed interim consolidated financial statements are presented in Canadian Dollars which is Valeura's reporting currency. Valeura's foreign subsidiaries transact in currencies other than the Canadian Dollar and have a Turkish Lira ("TL") functional currency. The functional currency of a subsidiary is the currency of the primary economic environment in which the subsidiary operates. Transactions denominated in a currency other than the functional currency are translated at the prevailing rates on the date of the transaction. Any monetary items held in a currency which is not the functional currency of the subsidiary are translated to the functional currency at the prevailing rate as at the date of the balance sheet. All exchange differences arising as a result of the translation to the functional currency of the subsidiary are recorded in net earnings.

Translation of all assets and liabilities from the respective functional currencies to the reporting currency are performed using the rates prevailing at the statement of financial position date. The differences arising upon translation from the functional currency to the reporting currency are recorded as currency translation adjustments in Other Comprehensive Income or loss ("OCI") and are held within Accumulated Other Comprehensive Income or loss ("AOCI") until a disposal or partial disposal of a subsidiary. A disposal or partial disposal will then give rise to a realised foreign exchange gain or loss which is recorded in net earnings.

(d) Changes in Significant Accounting Policies

(i) IFRS 16 Leases

Valeura adopted IFRS 16, Leases, on January 1, 2019 on a modified retrospective basis.

In January 2016, the IASB issued the complete IFRS 16 Leases ("IFRS 16") which replaces IAS 17, Leases. Under IFRS 16, a single recognition and measurement model applies for lessees which will require recognition of assets and liabilities for most leases. Valeura has elected to use the modified retrospective approach upon adoption and therefore the comparative information has not been restated. The Company has elected to apply the optional exemptions for short-term and low-value leases. The lease payments associated with these leases are recognised as expenses as incurred over the lease term.

The Company recognises a right-of-use asset (''ROU") and a lease liability at the lease commencement date. The ROU asset is initially measured at cost based on the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received. The assets are depreciated to the earlier of the end of the useful life of the ROU asset or the lease term using the straight-line method as this most closely reflects the expected pattern of consumption of the future economic benefits. Valeura presents ROU as its own line item on the consolidated statement of financial position. The lease term includes periods covered by an option to extend if the Company is reasonably certain to exercise that option. In addition, the ROU is periodically reduced by impairment losses, if any, and adjusted for certain re-measurements of the lease liability. The average depreciation term is 1.5 to 2 years.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate.

The lease liability is measured at amortised cost using the effective interest method. It is re-measured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the Company's estimate of the amount expected to be payable under a residual value guarantee, or if the Company changes its assessment of whether it will exercise a purchase, extension or termination option. When the lease liability is re-measured in this way, a corresponding adjustment is made to the carrying amount of the ROU asset, or is recorded in profit or loss if the carrying amount of the ROU asset has been reduced to zero. Lease payments are applied against the lease obligation, with a portion reflected as interest expense using the effective interest rate method. Valeura presents the lease liability as its own line item on the consolidated statement of financial position.

The effect of initially applying the standard was a $0.2 million increase to the lease liability, with a corresponding ROU asset recorded. The ROU asset was measured at the amount equal to the lease liability on January 1, 2019 with no impact on deficit. The lease liability was measured at the present value of the remaining lease payments, discounted using Valeura's incremental borrowing rate as at January 1, 2019. The weighted average incremental borrowing rate used to determine the lease obligation on adoption was approximately 28% percent. The ROU assets and lease liabilities recognised relate to leases on the Company's offices and facilities in Turkey.

The preparation of the condensed interim consolidated financial statements in accordance with IFRS requires management to make judgments, estimates, and assumptions that affect the reported amount of assets, liabilities, income, and expenses. Actual results could differ significantly from these estimates. Key areas where management has made judgments, estimates, and assumptions related to the application of IFRS 16 include:

Incremental borrowing rate: The incremental borrowing rates are based on judgments including economic environment, term, currency, and the underlying risk inherent to the asset. The carrying balance of the ROU assets, lease obligations, and the resulting interest and depletion and depreciation expense, may differ due to changes in the market conditions and lease term.

Lease term: Lease terms are based on assumptions regarding extension terms that allow for operational flexibility and future market conditions.

The table below shows the impact on the consolidated statement of loss upon adoption of IFRS 16 for the three and six months ended June 30, 2019 is a reduction to loss for the period as follows:

Cash flow from financing activities for the six months ended June 30, 2019 was $0.06 million lower due to the deduction of the lease payments reflected in this section while cash flow from operating activities increased $0.06 million.

(e) Use of estimates

The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. The ability to make reliable estimates is further influenced by political and economic factors. Management has based its estimates with respect to the Company's operations in Turkey based on information available up to the date these condensed interim consolidated financial statements were approved by the Board of Directors. Significant changes could occur which could materially impact the assumptions and estimates made in these consolidated financial statements. Changes in assumptions are recognised in the financial statements prospectively.

3. Restricted Cash and Licence Deposits

The Company has restricted cash in the amount of $0.3 million (December 31, 2018 - $0.3 million) that is securing licence deposits with the General Directorate of Mining and Petroleum Affairs of the Republic of Turkey ("GDMPA"), and a further $0.1 million (December 31, 2018 - $0.1 million) on deposit with the GDMPA. This restricted cash and deposit is security for decommissioning or abandonment obligations and ongoing work programmmes on the Company's Turkish licences. These deposits and restricted cash equal the amount to satisfy the underlying commitments with the GDMPA and there are no other outstanding commitments. As the expected abandonment date and work programmmes for these assets is more than one year from June 30, 2019, this restricted cash and deposit have been classified as non-current in the Company's financial statements.

Effective April 10, 2019, the Company renewed its Account Performance Security Guarantee ("APSG") facility with Export Development Canada ("EDC"). The APSG, which was issued to National Bank of Canada ("NBC") allows the Company to use the APSG as collateral for certain letters of credit issued by NBC. The facility is effective from April 10, 2019 to March 31, 2020 with a limit of US$4.5 million and can be renewed on an annual basis. The Company has issued approximately US$2.5 million in letters of credit under the APSG facility.

4. Exploration and Evaluation Assets

Exploration and evaluation ("E&E") assets consist of the Company's exploration projects which are pending the determination of proved or probable reserves. Additions represent the Company's share of costs incurred on E&E assets during the period. 

Phase 2 of the Banarli Farm-in was a commitment to complete a 3D seismic programme with a minimum cost of at least US$10 million. The final cost total for the Karaca 3D seismic programme, agreed by partners in Q1 2019 totaled US$8.5 million, requiring an additional payment from Equinor to Valeura of US$1.5 million ($1.9 million), which is recorded as an additional farm-in payment against exploration and evaluation assets.

In circumstances where the Company has entered into farm-in arrangements whereby the farm-in partner ("partner") will earn a working interest on certain properties through payment of a pre-determined portion of the costs of exploration or development activities, Valeura recognises a disposal of the partner's working interest once the commitment has been met and the difference between the proceeds received and the carrying amount of the asset are recognised as a gain or loss in earnings for Property, Plant and Equipment assets and as a reduction of Exploration and Evaluation Assets for instances where the farm-in is on undeveloped land.

5. Property, Plant and Equipment

(a) Contingencies

Although the Company believes that it has title to its oil and natural gas properties, it cannot control or completely protect itself against the risk of title disputes or challenges.

(b) Depletion - future development costs

For the purposes of calculating depletion, petroleum and natural gas properties in Turkey include estimated future development costs of $149.2 million (December 31, 2018 - $155.0 million) associated with development of the Company's proved plus probable reserves.

The ultimate recovery of property, plant and equipment and exploration and evaluation costs in Turkey is dependent upon the Company obtaining government approvals, obtaining and maintaining licences in good standing, the existence and commercial exploitation of petroleum and natural gas reserves and undeveloped lands, and other uncertainties.

6. Decommissioning Obligations

The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years. The change in estimate is due to a decrease in the inflation rate, and an increase to the discount rate.

7. Share Capital

(a) Issued

(b) Per share amounts

Per share amounts have been calculated using the weighted average number of common shares outstanding. The weighted average number of common shares outstanding for the three and six months ended June 30, 2019 is 86,584,989 and 86,514,649 respectively (June 30, 2018 - 85,608,412 and 81,681,140 respectively). The average number of common shares outstanding was not increased for outstanding stock options as the effect would be anti-dilutive.

(c) Stock options

Valeura has an option programme that entitles officers, directors, and employees to purchase shares in the Company. Options are granted at the market price of the shares at the date of grant, have a 7 year term and vest over 3 years.

The number and weighted average exercise prices of share options are as follows:

The following table summarises information about the stock options outstanding and exercisable at June 30, 2019:

The fair value, at the grant date during the period, of the stock options issued was estimated using the Black-Scholes model with the following weighted average inputs:

8. Leases

All leases disclosed above have terms between 14 and 18 months.

In addition to the leases disclosed above the Company has a number of leases with terms of 12 months or less. Total commitments under these short term leases at June 30, 2019 are $0.5 million. Total lease expenses included in the financial statements related to these contracts are as follows:

9. Revenue

The Company sells its production pursuant to fixed price sales contracts in the country of Turkey, in which natural gas prices for all of the Company's production are linked to the BOTAS benchmark price in TL. Tracking of the BOTAS price, converted to US$, suggests that the price trends similar to the EU natural gas price. This is expected, as the gas sources are similar for both BOTAS and the EU. The Company is paid for its Turkish natural gas production in TL. The BOTAS price is a reference price fixed by the Ministry of Energy and Natural Resources.

Under the contracts, the Company is required to deliver a variable volume of natural gas to the contract counter party. Revenue is recognised when a unit of production is delivered to the contract counterparty. The amount of revenue recognised is based on the agreed transaction price, whereby any variability in revenue relates specifically to the Company's efforts to transfer production or the customer's demand for natural gas, and therefore the resulting revenue is allocated to the production delivered in the period during which the variability occurs. As a result, none of the variable revenue is considered constrained.

The Company's contracts have a term of one year or less, whereby delivery takes place throughout the contract period. Revenues are typically collected between the 12th and 25th day of the month following production.

The Company produces a small amount of crude oil that is sold on a spot basis as volumes warrant. Oil is delivered by truck to customers and revenue is recognised in the period in which the delivery occurs.

In addition to selling natural gas that the Company produces, the Company sells natural gas that it purchases from other producers in the area. This purchased natural gas is sold to the same customers, using the same contracts, through the same distribution network as natural gas the Company produces. The Company purchases natural gas from other producers under contracts that are typically one year or less in length at a discount of between 12.5% and 15% to the BOTAS price. These contracts require the Company to deliver the purchased natural gas to customers. The Company does not have the right, nor the ability, to store the purchased natural gas. Since the Company does not have the ability to influence the decision making process for the purchased natural gas volumes or the discretion to set prices, does not experience any inventory risk, does not perform any processing of the product and does not remit royalties to the Turkish government for the product, it considers itself an agent in these transactions. Revenue for this purchased gas is included net of purchase cost in Other income.

Interest and other revenue is comprised mainly of interest on cash in hand.

All of the Company's natural gas is sold in Turkey, in the Thrace Basin, which is the same area in which it is produced.

10. Supplemental Cash Flow Information

11. Transaction Costs

During the three and the six months ended June 30, 2019 the Company recorded transaction costs of $0.2 million and $1.2 million respectively. The 2019 transaction costs are fees related to the Company's listing on the London Stock Exchange and a final success fee payment for the Banarli Farm-in.

12. Financial Risk Management

The Company's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as:

·; Credit risk

·; Market risk

·; Liquidity risk

This note presents information about the Company's exposure to each of the above risks, the Company's objectives, policies and processes for measuring and managing risk, and the Company's management of capital.

The Board of Directors oversees managements' establishment and execution of the Company's risk management framework. Management has implemented and monitors compliance with risk management policies. The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.

(a) Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company's receivables from joint venture partners and oil and natural gas marketers. The maximum exposure to credit risk is as follows:

Trade and other receivables:

Substantially all of the Company's petroleum and natural gas production is marketed under standard industry terms that are specific by country. The Company's policy to mitigate credit risk associated with the balances is to establish marketing relationships with credit worthy purchasers. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers. Joint venture receivables are typically collected within one to three months of the joint venture invoice being issued to the partner. The Company mitigates the risk from joint venture receivables by obtaining partner approval of significant capital expenditures.

Receivables from participants in the petroleum and natural gas sector, and collection of the outstanding balances can be impacted by industry factors such as commodity price fluctuations, limited capital availability and unsuccessful drilling programmmes. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however the Company can cash call for major projects and does have the ability, in most cases, to withhold production from joint venture partners in the event of non-payment, or withhold accounts payable remittances.

(b) Market risk

Market risk is the risk that changes in market conditions, such as commodity prices, foreign exchange rates and interest rates will affect the Company's income or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while maximising the Company's return.

Foreign currency exchange rate risk:

Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. Historically, any devaluation in the TL has been followed by a legislated increase in the posted BOTAS Reference Price for natural gas. However, devaluation of the TL without a corresponding increase in the natural gas reference price will have a negative impact on adjusted funds flow and could affect the ability of the Company to fund its capital programme in the future. Devaluation of the TL will also result in decreases in royalties, and operating expenses, all other things being equal.

The Company's seismic and drilling operations and related contracts in Turkey are predominantly based in USD for BGCA operations. Material increases in the value of the USD against the TL or CAD will negatively impact the Company's costs of drilling and completions activities. Future CAD/USD and CAD/TL exchange rates could accordingly impact the future value of the Company's reserves as determined by independent evaluators.

Changes to the TL/CAD exchange rate would have had the following impact on revenues, royalties and production costs for the three months and six months ended June 30, 2019:

Changes to the TL/USD exchange rate, which are impacted by the TL/CAD exchange rate upon conversion to the Company's Canadian Dollar presentation currency, would have had the following impact on capital expenditures for the three months and six months ended June 30, 2018:

Interest rate risk:

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is not currently exposed to interest rate risk as it has no debt.

Commodity price risk:

Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by the relationship between the Canadian Dollar and Turkish Lira, the Canadian Dollar and United States Dollar, global economic events and Turkish government policies.

The natural gas reference price in Turkey is in part correlated to contract prices for natural gas imports into Turkey and also government policy with respect to subsidies to consumers. Natural gas sales for Valeura are under direct sales contracts to industrial buyers and power generation companies in the area and each contract is at a negotiated discount or premium to the BOTAS benchmark price.

The government has continued to increase the BOTAS reference price thereby offsetting the decline in the value of the TL and reflecting the increase in regional gas prices, resulting in 5 price increases over 2018. The Company's average realised natural gas price in Turkey for the first six months of 2019 was $8.88/mcf which represents a 2.5% discount to the BOTAS price. BOTAS recently announced a 15% increase to the reference price effective August 1, 2019, the first increase in 2019, to an equivalent of $10.35/mcf.

Liquidity risk:

Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with the financial liabilities. The Company's financial liabilities consist of accounts payable. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities and capital expenditures. The Company processes invoices within a normal payment period. Accounts payable have contractual maturities of less than one year. The Company maintains and monitors a certain level of cash which is used to finance all operating and capital expenditures.

Capital management:

The Company's objective when managing capital is to maintain a flexible capital structure which allows it to execute itsgrowth strategy through expenditures on exploration and development activities while maintaining a strong financialposition. The Company's capital structure includes working capital and shareholders' equity. Currently, total capital resources available include working capital and funds flow from operations.

The Company's capital expenditures include expenditures in oil and gas activities which may or may not be successful. The Company makes adjustments to the capital structure in light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. In order to maintain or adjust the capital structure, the Company may, from time to time, issue shares, adjust its capital spending or issue debt instruments. The Company is not currently subject to any externally imposed capital requirements while it maintains operatorship over all of its lands in the Thrace Basin. An exception to this statement could occur at the end of 2019 or beginning of 2020 if Equinor elects to complete Phase 3 under the Banarli farm-in and thereby earns a 50 percent working interest in the deep rights at Banarli. Phase 3 of the Banarli Farm-in can be completed by the drilling and testing of the Inanli-1, which spud on October 8, 2018 and completed drilling in January 2019. The completion and testing programme began in Q2 2019. Once drilling and testing of Inanli-1 is complete, Equinor may exercise its option under the Banarli Farm-in to take over operatorship of the deep rights and propose a more significant drilling programme including a more extensive pilot project, for which the Company would have to contribute its participating interest (50% for Banarli and 31.5% for West Thrace). The Company has working capital of approximately $52.3 million at June 30, 2019 in order to meet commitments of the current capital programme. If a more significant programme is proposed, the Company will be required to assess alternatives including the availability of equity and debt capital to fund the programme.

The successful future operations of the Company are dependent on the ability of the Company to secure sufficient funds through operations, bank financing, equity offerings or other sources and there are no assurances that such funding will be available when needed. Failure to obtain such funding on a timely basis could cause the Company to reduce capital spending and could lead to the loss of exploration licences due to failure to meet drilling deadlines, lower production volumes and associated revenues or default under the Company's joint operating agreements. Valeura has not utilised bank loans or debt capital to finance capital expenditures to date.