Calgary, June 13, 2022: Valeura Energy Inc. (TSX:VLE, LSE:VLU) (“Valeura” or the “Company”), an upstream oil and gas company with assets in the Thrace Basin of Turkey and an announced acquisition in the offshore Gulf of Thailand, is pleased to report the results of an independent third party reserves and resources assessment pertaining to its Gulf of Thailand acquisition announced April 28, 2022 and expected to close this month (the “Acquisition”).
Highlights
- Proved (1P) reserves of 2,749 Mbbl of oil;
- Proved and probable (2P) reserves of 6,456 Mbbl of oil, with an estimated future net revenue after income taxes of US$59.3 million, using a discount rate of 10%;
- Best estimate (2C) unrisked contingent resources of 4,696 Mbbl for the Rossukon oil field, classified as ‘development pending;’ and
- Additional 2C unrisked contingent resources of 8,615 Mboe relating to various other accumulations on the licences, classified as ‘development unclarified.’
The report, dated June 10, 2022, was prepared for Valeura by Netherland, Sewell & Associates, Inc. (“NSAI”) to assess reserves and contingent resources associated with licences G10/48 and G6/48, in the Gulf of Thailand, as of March 31, 2022 (the “NSAI Report”). As announced on April 28, 2022, Valeura has signed a share purchase agreement to acquire all of the shares of KrisEnergy International (Thailand) Holdings Ltd. which, through two subsidiary companies, holds an 89% operated working interest in licence G10/48 and a 43% operated working interest in licence G6/48. Unless otherwise noted, reserves and resources estimates are presented on a before royalties, working interest acquired basis.
Sean Guest, President and CEO of Valeura commented:
“This third party, independent evaluation underscores the tremendous value we are acquiring in Thailand. The externally evaluated 2P reserves associated with the Wassana field in licence G10/48 are 63% larger than we had originally estimated, meaning our deal metrics are even stronger than initially presented.
For total consideration of US$19.3 million (including initial, contingent, and facilities consideration) we are acquiring 6.5 million bbls of 2P oil reserves, valued at US$59.3 million on an after-tax basis, using a 10% discount rate. At current exchange rates of approximately 1.25 US$/C$, that equates to approximately C$0.86 per share in tangible value, demonstrating the highly accretive nature of this transaction.
In addition, 2C contingent oil resource volumes for the Rossukon field are 4.7 million bbls on an unrisked, best estimate basis, and carry an assessed 84% chance of development, reflecting the field’s status as ‘development pending.’ We will provide more details on the Rossukon field development once we take the final investment decision, anticipated in the coming months.
With these values in hand, our team is invigorated to work with our counterparties to progress and complete the transaction and thereafter to pursue both re-activation of Wassana and development of Rossukon as soon as possible. We remain on track to close the Acquisition this month and believe it will solidify significant shareholder value in both the immediate and longer term.”
Reserves and Resources Summary
The following is a summary of the NSAI Report. Unless otherwise noted, all production, reserves and resources estimates are presented on a working interest acquired basis to the Valeura-controlled special purpose vehicle corporation (“SPV”), Panthera Resources Pte. Ltd., which will serve as the buyer entity in respect of the Acquisition. Valeura holds an 85% interest in the SPV. Values may not add due to rounding.
Oil and Gas Reserves Based on Forecast Prices and Costs (Wassana field, licence G10/48)
Oil reserves on licence G10/48 are associated with the Wassana oil field, and have been presented as heavy crude oil volumes, divided amongst the proved, probable and possible reserves categories on a gross working interest (i.e. before royalties) and net working interest (i.e. after royalties) basis.
|
|
Light and Medium |
Heavy |
Conventional |
Natural Gas |
Total Oil |
|||||
|
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
|
|
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
|
Proved Developed Producing |
– |
– |
– |
– |
– |
– |
– |
– |
– |
– |
|
Proved Developed Non-Producing |
– |
– |
1,838.6 |
1,732.9 |
– |
– |
– |
– |
1,838.6 |
1,732.9 |
|
Proved Undeveloped |
– |
– |
910.7 |
858.4 |
– |
– |
– |
– |
910.7 |
858.4 |
|
Total Proved |
– |
– |
2,749.3 |
2,591.2 |
– |
– |
– |
– |
2,749.3 |
2,591.2 |
|
Total Probable |
– |
– |
3,706.9 |
3,493.7 |
– |
– |
– |
– |
3,706.9 |
3,493.7 |
|
Total Proved Plus Probable |
– |
– |
6,456.2 |
6,085.0 |
– |
– |
– |
– |
6,456.2 |
6,085.0 |
|
Total Possible |
– |
– |
949.1 |
894.5 |
– |
– |
– |
– |
949.1 |
894.5 |
|
Total Proved Plus Probable Plus Possible |
– |
– |
7,405.3 |
6,979.4 |
– |
– |
– |
– |
7,405.3 |
6,979.4 |
Net Present Values of Future Net Revenue Based on Forecast Prices and Costs (Wassana field, licence G10/48)
Net present values of future net revenue from oil reserves on licence G10/48 are based on cost estimates as of the date of the NSAI Report, and forecast Brent crude oil reference prices of US$97.50, US$87.07, US$78.25, and US$77.34 per bbl for the years ending December 31, 2022, 2023, 2024, and 2025, respectively, with 2% escalation thereafter, and assuming a differential of (US$4.34) per bbl based on historical realised prices. Given available tax pools, NSAI has anticipated no taxes payable in relation to the reserves and accordingly values are presented as both before and after deducting income taxes.
|
|
Before and After Deducting Income Taxes |
||||
|
|
Discounted At |
||||
|
|
0% |
5% |
10% |
15% |
20% |
|
|
(M US$) |
(M US$) |
(M US$) |
(M US$) |
(M US$) |
|
Proved Developed Producing |
– |
– |
– |
– |
– |
|
Proved Developed Non-Producing |
(25,890.4) |
(21,237.6) |
(17,465.6) |
(14,382.2) |
(11,842.8) |
|
Proved Undeveloped |
30,898.0 |
25,761.7 |
21,500.3 |
17,937.7 |
14,938.8 |
|
Total Proved |
5,007.5 |
4,524.1 |
4,034.7 |
3,555.5 |
3,096.0 |
|
Total Probable |
82,568.5 |
67,338.8 |
55,263.6 |
45,605.6 |
37,819.3 |
|
Total Proved Plus Probable |
87,576.1 |
71,862.8 |
59,298.3 |
49,161.1 |
40,915.3 |
|
Total Possible |
59,380.8 |
51,278.1 |
44,743.7 |
39,407.4 |
34,999.9 |
|
Total Proved Plus Probable Plus Possible |
146,956.8 |
123,140.9 |
104.041.9 |
88.568.5 |
75,915.3 |
Contingent Oil Resources, Development Pending (Rossukon oil field, licence G6/48)
Contingent oil resources for the Rossukon oil field on licence G6/48 are light and medium crude Oil classified as “Development Pending” and carry an assessed chance of development of 84%. The Company believes the unrisked best estimate provides the most appropriate indication of volumes that will become 2P oil reserves upon development sanction of the Rossukon field.
|
|
Light and Medium |
Heavy |
Conventional |
Natural Gas |
Total Oil |
|||||
|
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
|
|
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
|
Unrisked |
||||||||||
|
Low Estimate (1C) |
3,231.4 |
3,037.6 |
– |
– |
– |
– |
– |
– |
3,231.4 |
3,037.6 |
|
Best Estimate (2C) |
4,696.1 |
4,380.2 |
– |
– |
– |
– |
– |
– |
4,696.1 |
4,380.2 |
|
High Estimate (3C) |
6,438.9 |
5,958.4 |
– |
– |
– |
– |
– |
– |
6,438.9 |
5,958.4 |
|
Risked, with Chance of Development = 84% |
||||||||||
|
Low Estimate (1C) |
2,714.4 |
2,551.5 |
– |
– |
– |
– |
– |
– |
2,714.4 |
2,551.5 |
|
Best Estimate (2C) |
3,944.7 |
3,679.4 |
– |
– |
– |
– |
– |
– |
3,944.7 |
3,679.4 |
|
High Estimate (3C) |
5,408.7 |
5,005.0 |
– |
– |
– |
– |
– |
– |
5,408.7 |
5,005.0 |
The Rossukon oil field has a regulator-approved development plan which contemplates peak oil production rates of 12,000 bbls/d gross (5,160 bbls/d net working interest basis) and sets a first-oil requirement by November 2023. The development scheme evaluated by NSAI assumes a two-phase drilling programme of 10 horizontal production wells, seven water injection wells, and one water source well connected to a Mobile Offshore Production Unit. The first phase of the development aims to achieve first oil from three horizontal producers in Q4 2023. The second phase will complete the remaining scope of the development plan.
Contingent Oil and Gas Resources, Development Unclarified (licences G6/48 and G10/48)
Contingent oil resources for additional reservoir accumulations on licence G6/48 and G10/48 are heavy crude oil and conventional natural gas classified as “Development Unclarified” and carry an assessed chance of development ranging from 10% to 22%. These accumulations provide a future opportunity to access additional hydrocarbon volumes on the licence interests being acquired.
|
|
Light and Medium Crude Oil |
Heavy Crude Oil |
Conventional Natural Gas |
Natural Gas Liquids |
Total Oil Equivalent |
|||||
|
|
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net |
|
|
(Mbbl) |
(Mbbl) |
(Mbbl) |
(Mbbl) |
(MMcf) |
(MMcf) |
(Mbbl) |
(Mbbl) |
(Mboe) |
(Mboe) |
|
Unrisked |
||||||||||
|
Low Estimate (1C) |
– |
– |
6,823.7 |
n/a |
4,935.1 |
n/a |
– |
– |
7,646.2 |
n/a |
|
Best Estimate (2C) |
– |
– |
7,666.7 |
n/a |
5,692.5 |
n/a |
– |
– |
8,615.5 |
n/a |
|
High Estimate (3C) |
– |
– |
12,602.8 |
n/a |
6,608.8 |
n/a |
– |
– |
13,704.3 |
n/a |
|
Risked, with Chance of Development = 10% – 22% |
||||||||||
|
Low Estimate (1C) |
– |
– |
1,196.4 |
n/a |
987.0 |
n/a |
– |
– |
1,360.9 |
n/a |
|
Best Estimate (2C) |
– |
– |
1,383.0 |
n/a |
1,138.5 |
n/a |
– |
– |
1,572.8 |
n/a |
|
High Estimate (3C) |
– |
– |
2,153.6 |
n/a |
1,321.8 |
n/a |
– |
– |
2,373.9 |
n/a |
For further information, please contact:
Valeura Energy Inc. (General Corporate Enquiries) +1 403 237 7102
Sean Guest, President and CEO
Heather Campbell, CFO
Contact@valeuraenergy.com
Valeura Energy Inc. (Capital Markets / Investor Enquiries) +1 403 975 6752
Robin James Martin, Investor Relations Manager +44 7392 940495
Auctus Advisors LLP (Corporate Broker to Valeura) +44 (0) 7711 627 449
Jonathan Wright
CAMARCO (Public Relations, Media Adviser to Valeura) +44 (0) 20 3757 4980
Owen Roberts, Billy Clegg
Valeura@camarco.co.uk
Oil and Gas Advisories
Reserves and contingent resources disclosed in this announcement in respect of the Acquisition are based on an independent evaluation conducted by the incumbent independent petroleum engineering firm, NSAI with an effective date of March 31, 2022. The NSAI estimates of reserves and resources were prepared using guidelines outlined in the Canadian Oil and Gas Evaluation Handbook and in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. The reserves and contingent resources estimates disclosed in this announcement in respect of the Acquisition are estimates only and there is no guarantee that the estimated reserves and contingent resources will be recovered.
Reserves
Reserves are estimated remaining quantities of commercially recoverable oil, natural gas, and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are further categorised according to the level of certainty associated with the estimates and may be sub-classified based on development and production status.
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.
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.
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.
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. 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.
The estimated future net revenues disclosed in this announcement in respect of the Acquisition do not necessarily represent the fair market value of the reserves associated with the Wassana oil field.
Contingent Resources
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe.
Contingent resources are further categorised according to the level of certainty associated with the estimates and may be sub‐classified based on a project maturity and/or characterised by their economic status. There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the Canadian Oil and Gas Evaluation Handbook as the best estimate of the quantity that will be actually recovered; it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate.
The project maturity subclasses include development pending, development on hold, development unclarified and development not viable. All of the contingent resources disclosed in this announcement are classified as either development pending or development unclarified. Development pending is defined as a contingent resource where resolution of the final conditions for development is being actively pursued. Development unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until commercial considerations can be clearly defined. Chance of development is the likelihood that an accumulation will be commercially developed.
Conversion of the development pending contingent resources referred to in this announcement to reserves is dependent upon a Final Investment Decision for the oil development of the Rossukon field. The major positive factors relevant to the estimate of the development pending contingent resources are the successful appraisal of the Rossukon field through existing drilled and tested wells and the existing Thailand Government approved development plan which is economically attractive at current product prices and capital cost estimates. The major negative factor relevant to the estimate of the contingent resources is the pending nature of a finalised development plan and a Final Investment Decision required to proceed with development. If these contingencies are successfully addressed, some portion of these contingent resources may be reclassified as reserves.
Conversion of the development unclarified resources referred to in this announcement is dependent upon (1) improved economic conditions and continued development beyond what is currently planned for the Wassana field, (2) the collection of additional technical data through delineation wells and flow tests on the Mayura field to establish the size and commercial viability of the project, (3) commitment of the G10/48 license partners to develop the Mayura field resources, (4) approval of a plan to market the Rossukon field gas, and (5) completion of a Rossukon gas sales agreement. The major positive factor relevant to the estimate of the development unclarified contingent resources is the successful evaluation of resources encountered in appraisal wells within the Wassana, Rossukon and Mayura fields. The major negative factors relevant to the estimate of the development unclarified contingent resources are that (1) current economic conditions do not support certain resource development, (2) the requirement for further appraisal to reduce resource uncertainties prior to development, and (3) the requirement to enter definitive agreements to market the Rossukon gas. If these contingencies are successfully addressed, some portion of these contingent resources may be reclassified as reserves.
The NSAI estimates have been risked, using the chance of development, to account for the possibility that the contingencies are not successfully addressed. Due to the early stage of development for the development unclarified resources, NSAI did not perform an economic analysis of these resources; as such, the economic status of these resources is undetermined and there is uncertainty that any portion of the contingent resources disclosed in this announcement will be commercially viable to produce.
Barrels of Oil Equivalent
A boe is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel. Boe values 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.
Glossary
bbl barrel
boe barrel of oil equivalent
M US$ thousands of US dollars
Mbbl thousand barrels
Mboe thousand barrels of oil equivalent
Mcf thousand curbic feet
MMcf million cubic feet
Advisory and Caution Regarding Forward-Looking Information
Certain information included in this announcement constitutes forward-looking information under applicable securities legislation. Such forward-looking information is for the purpose of explaining 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, such as making investment decisions. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “target” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this announcement includes, but is not limited to: the anticipated benefits of the Acquisition and associated benefits to Valeura’s stakeholders; the completion of the Acquisition and the timing thereof; the total cash consideration for the Acquisition, including contingent payments and the timing thereof; statements with respect to the net working interest reserves and resources in the acquired assets; and statements with respect to regulatory and partner approvals for a development plan for the Rossukon field being pending. In addition, statements related to “reserves” and “resources” are deemed to be forward-looking information as they involve the implied assessment, based on certain estimates and assumptions, that the resources can be discovered and profitably produced in the future.
Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: the ability to close the Acquisition and to fund it from cash on hand and future cash flow; the ability to successfully re-start production from the Wassana field; political stability of the areas in which the Company is operating and completing transactions; continued safety of operations and ability to proceed in a timely manner future sources of funding; future economic conditions; future currency exchange rates; 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, high-pressure stimulation and other specialised oilfield equipment and service providers for onshore and offshore operations, 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 and resources 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: inability to close the Acquisition in June 2022; the ability of management to execute its business plan or realise anticipated benefits from the Acquisition; inability to integrate the Acquisition if it closes; inability to secure a new partner for the tight gas appraisal play and execute potential mergers and acquisitions; evolving impacts of the COVID-19 pandemic including disruptions in global supply chains; the Company’s ability to manage growth; the Company’s ability to manage the costs related to inflation; uncertainty in capital markets and ability to raise debt and equity, as required, particularly for companies with a small market capitalisation; the ability to finance future development and/or inorganic growth; the risks of currency fluctuations; changes in oil and gas prices and netbacks in Thailand and Turkey; potential changes in joint venture partner strategies and participation in work programmes; potential assertions of pre-emptive rights by a partner or potential disputes with a partner in connection with the Acquisition; uncertainty regarding the contemplated timelines and costs for offshore development plans in Thailand and the tight gas appraisal play evaluation in Turkey; the risks of disruption to operations and access to worksites (including the impact of the COVID-19 pandemic); the ability of the Company to maintain its directors, senior management team and employees with relevant experience; potential changes in laws and regulations, and the uncertainty regarding government and other approvals; counterparty risk; the ability of the Company to maintain effective internal control over financial reporting; counterparty risk; risks associated with weather delays and natural disasters; and the risk associated with international activity. The forward-looking information included in this announcement is expressly qualified in its entirety by this cautionary statement. See the Company’s annual information form for the year ended December 31, 2021 for a detailed discussion of the risk factors.
The forward-looking information contained in this announcement is made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this announcement is expressly qualified by this cautionary statement.
Additional information relating to Valeura is also available on SEDAR at www.sedar.com.
This Announcement contains inside information as defined in Article 7 of the Market Abuse Regulation No. 596/2014 (“MAR”) which is part of UK law by virtue of the European Union (Withdrawal) Act 2018. Upon the publication of this Announcement, this inside information is now considered to be in the public domain.
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.
