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Jadestone Energy Inc.
Intention to Admit Shares to the AIM Market of the London Stock Exchange plc
Proposed Equity Placing and Senior Debt Financing to fund the Montara Project Acquisition, Offshore Australia
16 July 2018—Singapore: Jadestone Energy Inc. (TSXV:“JSE”) (“Jadestone” or the “Company”), an independent oil and gas production, development and exploration company focused on the Asia Pacific region, is pleased to announce a placing of new common shares (the “Common Shares”) to raise gross proceeds of US$95 million (“Placing”) and its intention to apply for an additional listing of its shares on the AIM Market of the London Stock Exchange plc (“AIM”). Jadestone expects Admission to trading on AIM of the existing and new Common Shares to occur in August 2018 (“Admission”).
This follows the Company’s announcement earlier this morning that it has executed a definitive Sale and Purchase Agreement (“SPA”) with certain subsidiaries of PTT Exploration and Production Public Company Limited (“PTTEP”) to acquire a 100% interest in the Montara oil project (the “Montara Oil Project” or the “Montara Assets”) via an asset acquisition (the “Acquisition”) for a total cash consideration of US$195 million (subject to customary working capital adjustments and contingent consideration). The Acquisition will have an effective date of 1 January 2018.
As part of the financing of the acquisition Jadestone proposes to enter into a reserve based lending facility of US$120 million (the “RBL Facility”). Two existing institutional shareholders, Directors and senior management have indicated that they intend to subscribe for up to US$46 million as part of the placing.
The nominated adviser for the Admission is Stifel Nicolaus Europe Limited (“Stifel”); Stifel is also joint broker and bookrunner with BMO Capital Markets Limited (“BMO”).
Paul Blakeley, President and Chief Executive of Jadestone, commented:
“We are delighted to be pursuing a listing on AIM, at an exciting time in our Company’s growth, enhancing our corporate profile and access to a wider investor base in the near future.
“Proceeds from the Placing will be used towards funding the acquisition of the Montara Assets, delivering material scale and significant future upside for investors and to realise the value proposition across our balanced, low-risk portfolio as we grow our high value cashflow-positive production, capable of supporting the Company’s development plans and delivering dividends in the short to medium term.”
Business Introduction and Strategy
Jadestone is an independent oil and gas company focused on the Asia Pacific region. It has a balanced, low-risk, full-cycle portfolio of development, production and exploration assets in Australia, Vietnam and the Philippines.
The Company has a 100% operated working interest in Stag, offshore Australia, an oil producing field with development and exploration potential, a 100% operated working interest in three gas development blocks in Southwest Vietnam and is partnered with Total in the Philippines, where it holds a 25% working interest in the SC56 exploration block.
Jadestone’s strategic objective is to build a balanced, resilient portfolio of production and development assets with multiple reinvestment options in order to increase annual cash flows, whilst maintaining a strong balance sheet, delivering exceptional value to shareholders through both capital growth and, in the short to medium term, dividends. Jadestone will apply the following four key principles:
a) to acquire assets with production and/or discovered resources in the Asia-Pacific region;
b) to realise additional value from existing producing assets through superior operating capabilities, cost control and incremental brown field development;
c) to move its existing discoveries to production rapidly into the Asia-Pacific region’s energy-short markets; and
d) to add additional reserves and production volumes through low-risk in-field drilling and near-field exploration.
In combination with the key principles, Jadestone utilises its end-to-end technical and commercial capabilities to maximise value and returns. These capabilities include:
• a differentiated approach to subsurface interpretation and reservoir management;
• a constant drive to identify and execute on opportunities for innovative and disciplined reinvestment;
• a meticulous focus on optimising production processes and facilities management whilst maintaining a strong focus on health, safety, social and environmental matters;
• a nimble approach to decision making;
• rigorous cost control in operations and throughout the Company;
• deep in-region commercial skills; and
• utilising long standing stakeholder relationships in the region.
These core strengths enable Jadestone to add value by unlocking stalled projects, lowering operating costs, maximising production and reserves, and extending field life.
Senior management team with a track record of delivery and value creation
Jadestone’s strategy is delivered by a senior management team with a deep understanding of both the oil and gas industry and the Asia Pacific region with over 230 years’ combined industry experience and 139 years’ combined operating experience in the region. As the former Executive Vice President of Talisman Energy’s Asia Pacific & Middle East operations (2005 to 2015), Jadestone’s CEO Paul Blakeley, alongside other members of the Jadestone management team, was responsible for leading Talisman Energy, Asia Pacific from being a two-asset business with production of circa 45 mboe/d into a business generating free cash flows in excess of US$500 million per annum on production of circa 150 mboe/d, with circa 500 MMboe 2P reserves and an estimated net asset value of over US$6 billion.
Since the current management team joined the Company in June 2016, they have demonstrated their ability to identify and execute highly accretive acquisitions and realise significant value from existing assets through operational excellence. The management team has established a balanced portfolio and has made significant operational improvements, cost reductions and production stabilisation at the Group’s Stag asset.
Additionally, on 15 July 2018 the Company signed a binding SPA to acquire the Montara Assets located in shallow water offshore Australia, from PTTEP.
2P reserves attributed to Jadestone’s current assets were 17.1 MMbbls of oil and its total 2C resources were 11.8 MMbbls of oil and 465.3 Bcf of gas as of 31 December 2017.
The Montara Assets 2P reserves were 28.2 MMbbls of oil and condensate as of 31 December 2017.
Reserve numbers are from a CPR dated 15 July, 2018 prepared by ERC Equipoise Pte Ltd (“ERCE”) and (the, “CPR”), a qualified reserves evaluator, with an effective date of 31 December 2017.
The Montara Acquisition
As separately announced earlier today, Jadestone has executed a definitive SPA with certain subsidiaries of PTTEP to acquire a 100% interest in the Montara Oil Project for a total cash consideration of US$195 million, to be adjusted for working capital, with additional contingent consideration amounts payable dependent on certain production, oil price and future development milestones being achieved.
The Acquisition is in line with Jadestone’s strategic objectives. Key highlights of the transaction include:
• Acquisition of 100% operated interest in the Montara Oil Project, offshore Australia covering three oil producing fields;
• 10.3 mbbl/d of OECD production and 2P reserves of 28.2 MMbbl, more than tripling Jadestone’s production to 13.9 mbbl/d and increasing 2P reserves to 45.3 MMbbl;
• Purchase multiple 1.6x 2017 EBITDA ;
• Adds material, immediate cashflow to the portfolio, significantly strengthening the Company’s balance sheet;
• Significant upside identified, with multiple opportunities to realise incremental value through the deployment of Jadestone’s second phase technical capabilities, many of which can be delivered within the first 12 months of operatorship;
• Opportunity to realise synergies with Jadestone’s existing asset base through logistics optimisation and rationalisation of onshore support operations; and
• Acquisition is expected to payback in under two years at CPR price assumptions.
The Montara Oil Project is located in Production Licences AC/L7 and AC/L8 in the Timor Sea, approximately 690 kilometres west of Darwin, and comprises three separate fields which are Montara, Skua and Swift/Swallow, produced through a centralised FPSO, the Montara Venture, which is owned by PTTEP Australasia and will be transferred to Jadestone on Completion.
On completion of the Acquisition, including transfer of operatorship, Jadestone will hold a 100% operating interest in the Montara Assets.
 This is a non-GAAP financial measure which does not have a standardised measure under the Company’s GAAP and is basedon estimated Montara unaudited 2017 EBITDA of US$118.7 million. This amount reconciles to an unauditedloss before tax of US$(19.6) million, after deducting depletion, depreciation and amortisation charges of US$132.9 million and finance costs of US$5.4 million. The Company believes it is a useful metric to assess the economic value of the proposed acquisition.
The Directors believe that Jadestone benefits from the following key business strengths:
Proven regional management team
• Proven in-region management team with a track record of value creation and generating returns for shareholders;
• End-to-end capabilities through the upstream operating life cycle, with world class second phase specialisation and a history of safe operations; and
• Deep technical expertise in reservoir optimisation, production and facilities management, ongoing cost discipline developed at oil majors and large-cap E&P.
Focused fit-for-purpose strategy
• Focus on highly investable low cost and high margin markets in Asia-Pacific, which offer complex yet stable jurisdictions, high GDP growth rates, rising domestic gas demand and prices, and established gas infrastructure.
• Well positioned to take advantage of the retrenchment by majors and independents in the region and fill the growing vacuum for a nimble and capable operator.
• Focused strategy consistent with management’s in-region track record, operating experience, technical knowledge and relationships.
• Leveraging management’s proven track record of accretive business development and successful integration and portfolio rationalisation, to a growing opportunity set in the region.
Attractive cash generative production portfolio
• Focused and resilient production. Following completion of the Acquisition and success of the near term infill well campaign, free cashflow-positive production of approximately 12-15,000 bbl/d, even at low oil prices capable of supporting the Company’s development plans and the introduction of a dividend policy in the short to medium term.
• Stable OECD liquids exposure in a favourable tax and royalty regime.
Attractive near-term value catalysts
• Portfolio of high return quick payback investment opportunities including in-fill drilling in both Stag and Montara Assets.
• 12% increase in uptime and circa 25% decrease in operating costs at Montara Assets targeted within 12 months of assuming operatorship.
• Currently in direct and bilateral negotiations with Pertamina to enter into the new gross split Ogan Komering PSC, a 25 year heritage Talisman and Jadestone asset.
Value accretive development portfolio
• 171.3 Bscf (gross) shallow water gas development project expected to be produced via existing infrastructure into a growing and gas short power market on on an additional 31.1 Bscf from the Southern Channel at Nam Du.
• 18.7 boed peak production expected to be sold via long term fixed price and fixed escalation take or pay contracts.
Reasons for the Equity Offering and Use of Proceeds
Total cash consideration for the Acquisition is US$195 million, to be adjusted for working capital, with additional contingent consideration amounts payable dependent on certain production, oil price and future development milestones being achieved, which the Company intends to fund with a combination of debt and equity.
The Company intends to part fund the Acquisition by way of an underwritten reserve based lending facility, which has a term of 36 months to maturity and expects to enter into a facility agreement with Commonwealth Bank of Australia and Société Générale.
The balance of the Acquisition will be financed through the Placing; net proceeds of the Placing that are in excess of what is required for the Acquisition will be utilised for attractive near-term value catalysts including an infill well at the Stag field.
Gross proceeds of the Placing will be used by the Company for the following purposes:
|Equity financing for Montara acquisition||80|
|Partial funding of Stag infill well||5|
|Costs and general corporate purposes||10|
 The remainder of the anticipated US$15m cost is expected to be funded from organically generated cash flow from operations.
The Directors of Jadestone anticipate the following benefits of the additional listing:
• the admission will encourage an increase in the number of analysts providing independent investment research on the Company, in line with the current level of analyst coverage of its London-listed peers.
• U.K. and European investors have a deep knowledge base and experience investing in international E&P companies.
• Broadening the European and U.K. investor base and research coverage will drive incremental demand and ensure the value of the business is properly reflected in the share price.
In conjunction with the Offering, and in support of interest expressed by European investors, the Company is seeking to admit its Common Shares to trading on AIM in addition to its existing listing on the TSX Ventures Exchange (“TSX-V”).
|Management Roadshow||16 July – 6 August 2018|
|ITF||16 July 2018|
|Pathfinder Admission Document Published||16 July 2018|
|Pricing Date||6 August 2018|
|Completion of the Acquisition||September / October 2018|
All timings subject to change.
A summary of the Company’s assets, Montara assets and current trading prospects are provided in the Additional Information on Jadestone Energy Inc. section below. A competent persons report on the Company’s assets and the Montara assets is available on the Company’s website www.jadestone-energy.com.
|Jadestone Energy Inc.|
|Paul Blakeley, President and CEO||+65 6324 0359|
|Dan Young, CFO||+65 6324 0359|
|Investor Relations Enquiries||+1 403 975 6752|
|Nomad and Joint Broker||+44 (0) 20 7710 7600|
|Stifel Nicolaus Europe Limited:|
|BMO Capital Markets Limited:||+44 20 7236 1010|
|Public Relations Advisor||+ 44 (0) 203 757 4980|
About Jadestone Energy Inc.
Jadestone Energy Inc. is an independent oil and gas company focused on the Asia Pacific region. It has a balanced, low risk, full cycle portfolio of development, production and exploration assets in Australia, Vietnam and the Philippines.
The Company has a 100% operated working interest in Stag, offshore Australia, an oil producing field with development and exploration potential, a 100% operated working interest in three gas development blocks in Southwest Vietnam and is partnered with Total in the Philippines where it holds a 25% working interest in the SC56 exploration block.
Led by an experienced management team with a track record of delivery, who were core to the successful growth of Talisman’s business in Asia, the Company is pursuing an acquisition strategy focused on growth and creating value through identifying, acquiring, developing and operating assets throughout the Asia-Pacific region.
Jadestone Energy is currently listed on the TSX-V and headquartered in Singapore. For further information on Jadestone Energy please visit http://www.jadestone-energy.com.
ADDITIONAL INFORMATION ON JADESTONE ENERGY INC.
INFORMATION ON THE GROUP
Jadestone is an independent oil and gas production and development company focused on the Asia-Pacific region. The Company has an acquisitive strategy and is focused on growth and creating value through identifying, acquiring, developing and operating assets throughout the Asia-Pacific region.
Jadestone currently has a portfolio of oil and gas production, development and exploration assets in offshore Australia, Vietnam and the Philippines. The Company is focused on creating value through leveraging the significant experience and track-record of its management team to maximise value from Jadestone’s existing asset base through production and cost optimisation, and on identifying acquisitions that offer significant value both at the time of purchase and through potential organic development. The Directors’ objective is to create a leading independent Asia-Pacific-focused upstream oil and gas company that generates significant shareholder returns through capital growth and, in the short to medium term, dividends.
The Asia-Pacific region consists of numerous mature hydrocarbon basins with assets operated in many cases by national oil companies, oil majors and large cap independents. The Company believes that this presents an opportunity to acquire assets with significant unrealised value.
Jadestone’s management’s proven ability to extract value from oil and gas producing assets through the life cycle in the Asia-Pacific region, including a specialisation as a second phase operator, positions the Company well to take advantage of this opportunity.
The strategy also enables Jadestone to capitalise on the significant latent opportunity to monetise undeveloped gas discoveries in the region into the domestic regional markets where there is significant and growing demand and a supply shortfall, which has resulted in attractive pricing for producers.
On completion of the transfer of operatorship of the Montara Assets, Jadestone will have two 100% owned and operated developed producing assets, Montara and Stag. Combined production from the assets was 12,817 bbls/d and average opex per barrel was US$29.9 across both assets for the year ended 31 December 2017. 2P reserves were 45.3 MMbbls (gross and net) as at 31 December 2017.
Stag is currently producing at circa 3.6 mbbls/d following the workover of the 45H well.
The Montara Assets are currently producing approximately 10.3 mbbls/d after the prolonged shut-in of the Skua-10ST2 and Swift N1 subsea wells due to communication issues to these wells following the annual shutdown, causing the overall production to fall below plan. Communication, via a subsea umbilical, to these shut-in wells was restored in late June 2018 and they are now back on production at the current rates (from 7 mbbls/d when the subsea wells were shut-in). Production is still not fully optimised and stable following the start-up of the two subsea wells with not all fields fully available at all time. We expect the combined rate to increase over the next while before reaching the expected stable production rates for each field.
The Company has already identified multiple operational improvements at the Montara Assets and believes it can execute these improvements to increase production, whilst also reducing fixed operating costs by up to 20%. The Company has already made significant cost savings at Stag, reducing fixed operating costs by 35%, cutting sustaining capital expenditure and stabilising production. The Company is now focused on increasing production at Stag through drilling infill wells over the next two years and completing well workovers.
The Montara Assets comprise three separate fields which are Montara, Skua and Swift/Swallow, produced through a centralised FPSO, the Montara Venture, which is owned by PTTEP Australasia and will be transferred to Jadestone on completion of the Acquisition. On completion of the Acquisition, including transfer of operatorship, Jadestone will hold a 100% operating interest in the Montara assets. As at 31 December 2017, the Montara Assets had 2P reserves of 28.2 MMbbls of oil (gross and net) and is currently producing approximately 10.3 mbbls/d with all available wells (Montara wells, Skua-10 and Swift N1) back on production. Jadestone is acquiring the Montara Assets for consideration of US$195 million prior to customary working capital adjustments and certain contingent pay-out options. The transaction is structured as an asset acquisition, thereby limiting Jadestone’s exposure to any residual liabilities associated with the Seller’s businesses in Australia.
The limited number of qualified offshore operators in Australia looking to deploy second phase specialisation, and Jadestone’s recently proven ability to obtain regulatory approvals, in particular approval as operator, culminating in the transfer of operatorship of Stag in July 2017, proved a significant competitive advantage when engaging with the seller.
Free Cash Flow pay back of the acquisition price (before adjustment and contingent consideration) is estimated to be by quarter four of 2019 based on the assumptions used by ERCE.
Jadestone has identified numerous opportunities to unlock additional value through the application of Jadestone’s capabilities as outlined above. These identified value opportunities include cost reductions, operational efficiencies and investment programmes which are not being pursued by the current operator.
The Company plans to drill two in-fill wells targeting identified 2P reserves of 3.5 MMbbl as part of the 2019 work program. ~These wells are included in ERCE’s reserves case for the Montara Assets. A further three in-fill targets, not included in ERCE’s reserves case, have been identified by Jadestone management targeting 5.3 MMbbl. The intention is to drill these in-fill targets as part of a 2020 or 2021 work programme. The Company has also identified numerous operational improvements on the FPSO to increase efficiency, including: gas lift compressor reliability; gas lift optimisation and implementing gas lift to the well head platform wells; introducing the remote reset function on the well head platform; resetting the process parameters to prevent frequent process trips; and carrying out a safety/production critical spares review. In addition, various operating expenditure savings have been identified, such as: integrated operations planning; introduction of cargo tank washing; shared logistics contracts on supply boats and helicopters, along with the synergies of operating two assets from one support team.
Reflecting on the savings obtained at Stag to date, the Company is confident of its ability to deliver significant additional value creation at the Montara Assets following a successful transition period and subject to the required investment by the Company.
Jadestone is the 100% owner and operator of the producing Stag oil field located offshore Australia in the Carnarvon Basin. Stag and its associated infrastructure (excluding the leased FSO) were acquired by Jadestone on 11 November 2016 for a headline price of US$10 million plus customary working capital adjustments and potential contingent payments. At acquisition Stag had 2P reserves of 14.6 MMbbls oil and since that time Jadestone has increased 2P reserves to 17.1 MMbbls (gross and net), net of circa 1.6 MMbbls of production between the acquisition and the CPR date.
Since completing the Stag acquisition the focus of the Jadestone operating team has been to optimise production operations, reduce costs and identify and execute a work programme to increase production. In executing these initiatives, Stag has seen production stabilise and then increase to a current level of 3.6 mbbls/d, operating costs (excluding workover) reduce from US$43/bbl (for the first half of 2017) to US$32/bbl (for the second half of 2017, following transfer of operatorship to the Company in July 2017) and workover and other sustaining capital costs reduce by c. 50%. This uplift in production and cost reduction was seen notwithstanding the MBC incidents.
The Company has been able to achieve these gains through a re-organisation of management structures and processes; incentivisation of the workforce towards safe production operations; re-negotiation of contracts; and a reduction in workover duration and cost.
The Company is now focused on increasing production and intends drill up to five in-fill wells by the end of 2020 (being four producers and 1 water injector), targeting an average of 1.1 MMbbls of oil for each well, which also provides additional reserves from the field as a whole through field life extension. The initial production rate of each is expected be circa 1200 bbl/d before following a natural decline rate. The additional production derived from the first infill well to be drilled is expected to further reduce 2019 per unit operating costs (excluding workovers) to US$25.9/bbl and enhance cash flow resiliency, even at low oil prices.
Overview of assets:
Jadestone has a 70% operated working interest in two PSCs, Block 51 PSC and Block 46/07 PSC, both in the Malay-Tho Chu basin offshore Vietnam. The Company has made three gas/condensate discoveries on its acreage, being U Minh and Tho Chu on Block 51, and Nam Du on Block 46/07. Jadestone’s working interest in these blocks will increase to 100% once the blocks are amended for PetroVietnam’s relinquishment of its 30% interest in these blocks, effective 1 May 2017. As at 31 December 2017, these Blocks had gross 2C resources of 496.8 Bscf (347.8 Bscf net to Jadestone) of gas and 11 MMbbl (7.7 MMbbl net to Jadestone) of oil and condensate.
In November 2017, the Company submitted revised Outline Development Plans for the U Minh and Nam Du fields for approval, which was received from the Ministry of Industry and Trade in May 2018. The Company currently anticipates developing these two fields in a phased manner, with overall project sanction targeted for H2 2019. Ahead of project sanction, the Company is working on the front-end engineering and design, negotiation of commercial gas sales agreements and field development planning.
The Company intends to use an existing 18 inch pipeline, with 215 MMscf/d of capacity, owned by PetroVietnam, which is in close proximity to the fields and would be used to evacuate gas from these blocks to an existing power complex and fertiliser plant in Southern Vietnam. This pipeline currently evacuates gas from the heritage Talisman operated PM-03 CAA Block which lies immediately to the south of Block 46/07. This field is currently in decline, which is expected to result in sufficient ullage within the pipeline, which the Company intends to seek to utilise.
The U Minh and Nam Du gross 2C contingent resources are 171.3 Bscf (gross) and 119.9 Bscf (net to Jadestone) gas and 1.6 MMbbl (gross) and 1.1 MMbbl (net to Jadestone) oil and condensate. Project sanction is currently expected in H2 2019. The Tho Chu field will be subject to a later development plan.
The Company has a 25% working interest in the Block SC-56 in the Sandakan Basin in the Sulu, offshore the Philippines, in partnership with the Operator, Total. Four wells have been drilled in the licence to date resulting in two significant gas discoveries amounting to 2C resources of 469.6 Bscf gross (117.5 Bscf net to Jadestone) of natural gas and 2C resources of 5.4 MMbbl gross 1.4 MMbbl of oil and condensate. Jadestone is carried by Total for the remaining exploration commitment well on this block.
PNOC is the 100% owner of SC-57 in offshore Palawan Island in the Philippines. Jadestone has agreed to acquire a 21% working interest in this contract. CNOOC International Limited has also agreed to acquire a 51% working interest and to become an operator. Executive Order No. 556 (“EO 556”) dated 17 June 2006, effectively banned PNOC from entering into farm-in/farm-out agreements with foreign companies. Section 1 of EO 556 states that there shall be no “farm-in” or “farm-out” contracts awarded by any government agency, including the PNOC. In a letter dated 12 January 2011, DOE allowed the force majeure condition under Section 26.1 (b) of the SC-57 to be enforced starting end of Sub-phase 1 (15 March 2008) until the farm-in agreements are approved by the President.
Other business development
Jadestone acquired a 50% non-operated working interest in the Ogan Komering PSC, a heritage Talisman asset, from Repsol in March 2017. Ogan Komering is located onshore South Sumatra, Indonesia. The production rate of the block in the three months ended 31 March 2018 averaged 1,447 boe/d net to Jadestone (three months ended 31 December 2017: 1,413 boe/d net to Jadestone), with a gas-to-oil ratio of approximately 65% oil and 35% gas. The Ogan Komering PSC expired on 28 February 2018 and a temporary cooperation contract was entered into, continuing the PSC terms pending the issue of the new PSC on 20 May 2018, at which time Jadestone ceased to hold an interest in Ogan Komering. The carrying value of the Ogan Komering PSC under oil and gas propertieson the Company’s balance sheet is fully depleted.
A new gross split PSC for Ogan Komering, effective 20 May 2018, was signed by Pertamina, Indonesia’s upstream regulator SKKMIGAS, and the Minister of Energy and Mineral Resources, awarding a 100% participating interest to Pertamina. Jadestone, as the prior partner in the PSC with Pertamina, has been directed to proceed with direct negotiations for participation in the new PSC with Pertamina. Jadestone is progressing its discussions with Pertamina for participation in the new gross split PSC and, based on current negotiations, the Board expects to reach satisfactory binding terms during Q4 2018, with participation to be effective from the commencement of the new PSC on 20 May 2018. To the extent Jadestone participates in the PSC, it will not be the operator of Ogan Komering and it would have less than a 40% interest in the PSC. However, until definitive documentation is entered into, there can be no assurance that Jadestone will be successful in its negotiations for participation in the PSC or the terms on which such participation may be available to Jadestone.
Jadestone will seek an independent reserves evaluation for the Ogan Komering PSC if and once the Company’s participation is confirmed in the new PSC, expected later this year.
05-01b & c – Vietnam
The Company announced on 9 August 2016 that it had signed a SPA with Teikoku, a wholly-owned subsidiary of Inpex Corporation, as seller, for the acquisition of a 30% non-operated working interest in the Blocks 05-1 PSC.
On 22 February 2018, Teikoku delivered to Jadestone a purported notice of termination of the SPA, despite Teikoku having received a waiver from PetroVietnam, of its statutory pre-emption rights, held under Vietnamese law. The Company has not accepted Inpex’s alleged termination, and views the obligations of both parties under the SPA as continuing. The Company maintains its rights under the SPA and is assessing its options, including remedies available through legal action.
In the event that the Company is successful in asserting its rights to acquire an interest in 05-01b and c. The Company will need to raise additional funds in order to pay the consideration and related capital expenditure.
Other acquisition opportunities
Jadestone continues to evaluate inorganic growth opportunities in its core basin areas within the Asia-Pacific region in line with its strategy.
2 FINANCING OF THE ACQUISITION
The Company will finance the consideration, being US$195 million (before adjustments and contingent consideration), for the acquisition of the Montara Assets through US$95 million of equity, to be raised from the net proceeds of the Placing and US$120 million of debt under the proposed RBL Facility, underwritten by the Common Wealth Bank of Australia and Société Générale. The RBL Facility is expected to have a three year term and is priced at LIBOR plus 3%. The Company believes the debt to equity ratio of the Acquisition, being circa 62% debt to 38% equity, represents a prudent level of leverage to ensure balance sheet strength, even during a period of low oil prices. The debt is also expected to represent just 25% of the NPV10 of US$479.5 million of the Montara Assetsand will leave the group with a pro forma net debt to EBITDA ratio for the 2018E period of around 1x.
3 PROPOSED DIRECTOR
The Company intends to appoint Daniel Young (the chief financial officer of the Company) as a further executive director, based in Singapore, with effect from, and conditional on, Admission.
4 SUMMARY OF THE GROUP’S RESERVES AND RESOURCES
Table 1‑1: Summary of Oil Reserves
|Licence||Field||Gross Reverves (MMstb)||W.I.
|Net Reserves attributable to Jadestone (MMstb)||Operator|
|AC/L8||Swift / Swallow||4.2||6.4||8.4||100%||4.2||6.4||8.4||Jadestone|
Note: assuming transfer of operatorship for the Montara Assets is approved.
Table 1‑2: Summary of Net Present Values
|Field||Case||After Tax Discounted Cash Flow ($US MM)|
Table 1‑3: Summary of Oil and Condensate Contingent Resources
|Field||Licence||Country||Gross Contingent Resources (MMstb)||W.I. (%)||W.I. Contingent Resources (MMstb)||Chance of Development
|Nam Du||Block 46/07||Vietnam||–||–||–||70%||–||–||–||–||Jadestone|
|U Minh||Block 51||Vietnam||0.3||1.6||3.3||70%||0.2||1.1||2.3||85%||Jadestone|
|Tho Chu||Block 51||Vietnam||3.1||9.4||24.0||70%||2.2||6.6||16.8||40%||Jadestone|
Table 1‑4: Summary of Gas and Associated Gas Contingent Resources
|Field||Licence||Country||Gross Contingent Resources (Bscf)||W.I. (%)||W.I. Contingent Resources (Bscf)||Chance of Development
|Nam Du||Block 46/07||Vietnam||64.8||107.4||134.5||70%||45.4||75.2||94.2||85%||Jadestone|
|U Minh||Block 51||Vietnam||16.0||63.9||110.1||70%||11.2||44.7||77.1||85%||Jadestone|
|Tho Chu||Block 51||Vietnam||148.6||325.5||692.2||70%||104.0||227.9||484.5||40%||Jadestone|
The above tables are all extracted without material adjustment from the CPR. A copy of the CPR is available on the Company’s website.
5 SUMMARY FINANCINAL INFORMATION
The following information has been extracted without material adjustment from the audited financial information and unaudited quarterly financial information of the Group available on the Company’s website http://www.jadestone-energy.com/.
Prospective Investors should read the whole of this announcement and should not rely solely on the summary.
|3 months ended||9 months ended||12 months ended|
|US$ ‘000s||31 March 2018||31 March 2017||31 December 2017||31 March 2017||31 March 2016||March 2015|
|Loss from operations||(14,917)||(15,653)||(16,088)||(32,601)||(18,600)||(18,559)|
|Loss before tax||(15,897)||(15,665)||(20,392)||(34,630)||(19,207)||(27,069)|
|Loss for the year||(16,593)||(19,485)||(14,930)||(36,497)||(19,207)||(27,069)|
|US$ ‘000s||As at 31 March 2018||As at 31 March 2017||As at 31 December 2017||As at 31 March 2017||As at 31 March 2016||As at 31 March 2015|
|Cash & Equivalents||9,662||14,478||10,450||14,478||9,117||2,207|
The following information has been extracted from the unaudited Historical Financial Information of the Montara Assets contained in this announcement.
Prospective Investors should read the whole of this announcement and should not rely solely on the summary.
|12 months ended|
|US$ ‘000s||31 December 2015||31 December 2016||31 December 2017|
|Impairment of assets||(331,000)||–||–|
|Loss before tax||(482,799)||(83,601)||(19,588)|
6 CURRENT RADING AND PROSPECTS
On 30 May 2018, the Company announced its unaudited results for the quarter ended 31 March 2018 which are available on the Company’s website.
For the three months ended 31 March 2018, Stag production averaged 2,654 bbls/d, compared to 2,382 bbls/d for the three months ended 31 March 2017. This represents an increase of 11% from Q1 2017 and is the period during which potential cyclone disruption is at its highest.
During the previous three month period, ended December 31, 2017, production rates from the Stag Oilfield were adversely impacted by a series of marine breakaway coupling (“MBC”) incidents where the MBC released, disconnecting the platform from the FSO, resulting in unscheduled production stoppages. As reported in Jadestone’s December 2017 quarter results, these MBC incidents caused production to fall below budget, in essence a deferral of production, by about 53,000 bbls in the December 2017 quarter. The last of these incidents also affected production volumes in the March 2018 quarter, resulting in production falling below budget/deferred by approximately 16,000 bbls for the March 2018 quarter.
In addition, the sudden production stoppages incidents caused damage to several of the facility’s ESPs which required three well workovers during Q1 2018, to restore production rates.
The resultant ESP failures caused higher than expected well downtime, resulting in a further production deferment of approximately 51,000 barrels based on actual production versus budget. The combined production deferment of approximately 67,000 bbls resulted in production for the quarter being circa 745 bbls/d lower than budgeted.
The Company is in discussion with the operator of the vessel, in relation to the financial impact of the MBC events. Meanwhile a number of initiatives have been implemented to reduce the risk of future MBC failures and to improve operational performance. A new MBC has now been installed providing a more robust solution, following a series of stress tests and modifying the placement of the MBC to reduce future potential stress. The Company is seeking recompense from the contractor and through the contractor’s insurance.
Average first half production for the Company to 30 June 2018 comprised 4,174 boe/d, of which liquids constituted 88%, and the remainder natural gas, and noting that the existing Ogan Komering PSC expired on 19 May 2018. The average sales price for Stag oil during the first half of the year was US$70.88/bbl, while Ogan Komering liquids averaged US$63.40/bbl and natural gas was sold at an average price of US$6.34/MMbtu (both for the period to the expiry of the PSC). Revenue for the first half net of royalties but before cashflow hedges was US$34.8 million, and noting that sales volume differs from production volume due to timing of Stag liftings from the FSO. Total cash on hand at 30 June 2018 comprised US$17.3 million, including restricted cash of US$10.7 million.
Jadestone also received notification, on 30 April 2018, of the renewal of the Stag production licence for a further 21 years. This provides the Company with the opportunity to further develop and invest in the field, in order to grow future oil production and deliver additional operational efficiency initiatives.
Ogan Komering PSC (South Sumatra Basin)
For the three months ended 31 March 2018, Ogan Komering PSC production averaged 1,447 boe/d net to Jadestone compared to 1,474 boe/d net to Jadestone for the three months ended 31 March 2017. Ogan Komering PSC was acquired on 9 March 2017. Production was consistent with the business plan. The Ogan Komering PSC expired on 28 February 2018 and a temporary cooperation contract was entered into continuing the PSC terms pending the issue of the new PSC on 20 May 2018, at which time Jadestone ceased to hold an interest in Ogan Komering. Jadestone, as the prior partner in the PSC with Pertamina, has been directed to proceed with direct negotiations for participation in the new PSC with Pertamina. Jadestone is progressing its discussions with Pertamina, for participation in the new gross split PSC, and the Board expects to reach satisfactory binding terms during Q4 2018, with participation to be effective from the commencement of the new PSC on 20 May 2018. To the extent Jadestone participates in the PSC, it will not be the operator of Ogan Komering and it would have less than a 40% interest in the PSC. However, until definitive documentation is entered into, there can be no assurance that Jadestone will be successful in its negotiations for participation in the PSC or the terms on which such participation may be available to Jadestone.
The successful completion of an additional producing well Montara H5-ST2 in October 2017 increased production at the Montara Assets by 3.5 mbbl/d.
The above production rate was subsequently impacted as a result of the annual statutory facility shutdown in March 2018 and April 2018 together with the loss of production associated with the Skua and Swift/Swallow subsea tie-back wells being shut-in to June 2018 due to a failure of the subsea umbilical that provides communication to these wells. The production during this period, which was essentially entirely from the Montara field, amounted to approximately 7 mbbl/d. The successful remediation of the subsea umbilical in late June 2018 resulted in the restoration of the subsea well production and, specifically, production associated with Skua-10 and Swift N1. Production from the fields is currently approximately 10.3 mbbl/d.
In addition to the above maintenance and remediation activities, a well intervention program is planned for September 2018 which should reinstate gas lifting at the Swift 2 and Skua 11 wells, and perforation on Swallow 1. This is expected to result in the restoration of peak production by approximately 5.6 mbbl/d from these wells.
Montara crude is stored in the FPSO for lifting under a long-term crude sale contract with PTTEP. Normal cargo size is around 550,000 bbls but ongoing tank cleaning work and inspections relating to the vessel’s class has reduced storage capacity, resulting in more frequent lifting of about 350,000 bbls. The tank cleaning/inspection work is expected to complete in Q3 2018.
Operating costs in Q1 2018, excluding corporate G&A and legal fees which are for the account of the Seller, amount to $22.8/bbl. It is expected that operating costs will increase in Q2 and Q3 due to the routine annual shut down and non-routine activities referenced above, before returning to the base line or normal levels of around $22/bbl in Q4 2018and then decreasing once Jadestone starts to implement its practices.
7 STOCK OPTIONS
The Company intends to grant, at the Placing Price following Admission:
(a) A. Paul Blakeley an Option over 250,000 Common Shares;
(b) Daniel Young an Option over 250,000 Common Shares; and
(c) Options over 1,000,000 Common Shares, in aggregate, to other employees of the Company.
8 TSX-V APPROVAL
Pursuant to the rules of the TSX-V, the Acquisition and Placing are conditional on TSX-V approval. The Acquisition will constitute a “Fundamental Acquisition” under TSX-V rules and will require the filing of the following documents with the TSX-V: (i) CPR; (ii) the Acquisition Agreement; (iii) a title opinion; and (iv) a financial plan outlining how the Company proposes to fund the Acquisition. The Company has applied for the approval from TSX-V for the Acquisition and will apply for conditional approval for the Placing prior to Admission.
9 DIVIDEND POLICY
The Company is currently generating revenues and positive operating cash flow from production at the Stag Field and, following Completion of the, expects to generate revenues and positive operating cash flow from the Montara Assets.
Following the first anniversary of Completion of the Acquisition, the Company currently intends to introduce a cash dividend. This intention will be subject to the ongoing funding requirements of the business and will be reviewed on an ongoing basis.
The declaration and payment by the Company of any future dividends, and the amount of such dividends, will ultimately be dependent upon the Group’s financial condition, future prospects, profits legally available for distribution, the need to maintain an appropriate level of dividend cover, distribution restrictions and financial covenants and other factors deemed by the Board to be relevant at that time, in accordance with the Articles and subject to compliance with the Act.
10 CANADIAN CORPORATE GOVERNANCE
The Company believes in strong corporate governance and will continue to comply with comply and explain against NP 58-101 Disclosure of Corporate Governance Practices, which prescribes certain disclosure by the Company of its corporate governance practices and NP 58-201 Corporate Governance Guidelines, which provides non-prescriptive guidelines on corporate governance practices for reporting issuers such as the Company. In light of the proposed Admission, it is contemplated that the Company will also establish an HSSE committee.
11 TECHNICAL INFORMATION
The technical information contained in this announcement has been prepared in accordance with the March 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System and has been reviewed and approved by ERCE.
THE GROUP’S ASSETS
1 SUMMARY OF THE GROUP’S ASSETS AND FUTURE ASSET OPPORTUNITIES
Summary of the Group’s assets as at the date of this announcement
|Contract area||Date of Expiry||Held by||Place of Operation||Group Effective Working Interest|
|Stag Oilfield||August 25, 2039||Jadestone Energy (Australia) Pty Ltd||Australia||100|
|SC-56||Sep 1, 2020 (1)||Mitra Energy (Philippines SC-56) Ltd||Philippines||25|
|SC-57||Sept 15, 2020(2)(3)||Mitra Energy (Philippines SC-57) Ltd||Philippines||21(4)|
|51||June 11, 2035 (crude oil)
June 11, 2040 (gas)
|Mitra Energy (Vietnam Tho Chu) Pte Ltd||Vietnam||100(5)|
|46/07||June 27, 2035||Mitra Energy (Vietnam Nam Du) Pte Ltd||Vietnam||100(6)(7)|
|127||May 24, 2018||Mitra Energy (Vietnam Phu Khanh) Pte Ltd||Vietnam||60|
|Bone(8)||Nov 25, 2040||Mitra Energy (Indonesia Bone) Ltd||Indonesia||60|
(1) Should a commercial discovery be made the license period under the PSC will extend to 1 September 2055.
(2) Should a commercial discovery be made the license period under the PSC will extend to 15 September 2055.
(3) DOE has allowed a force majeure condition on SC57, until the approval by the President of the transfer of participating interests to CNOOC International Limited and Jadestone Energy Limited are obtained.
(4) In March 2006 PNOC Exploration Corporation entered into a farm-in agreement with Jadestone, which allows Jadestone to obtain a 21% interest in exchange for paying 30% of the costs during the first two exploration sub-phases in Service Contract 57. Governmental approval for the farm-in remains outstanding due to Executive Order No. 556 dated 17 June 2006, effectively banning PNOC from entering into farm-in/farm-out agreements with foreign companies, which constitutes a force majeure event under SC-57.
(5) Effective 1 May 2017, PVEP relinquished a 30% working interest in this block. The registration of this change is still pending.
(6) Effective 1 May 2017, PVEP relinquished a 30 per cent working interest in this block. The registration of this change is still pending
(7) Pursuant to a participation agreement with Mitra Energy (Vietnam Nam Du) Pte Ltd dated 3 November 2010, Petroctech Investment Corporation Pte Ltd has the right to acquire, at cost, a 5 per cent interest in any commercial discovery on 46/07.
(8) On 4 May 2017, the Company signed a Withdrawal Agreement with Azimuth Indonesia Ltd. (“Azimuth”) to transfer the Company’s 60 per cent working interest and operatorship of Bone PSC to Azimuth. The transfer was effective from April 15, 2017, but remains subject to final government approval.
In respect of the Stag Oil Field, the Company has an indefinite pipeline licence in respect of pipeline WA-6-PL.
2 NAM DU
The Nam Du discovery is located within the Block 46-07 PSC (“Block 46/07”) on the north-eastern margin of the Malay-Tho Chu Basin, approximately 200 kilometres offshore Vietnam in a water depth of 47.9 metres.
The U Minh and Tho Chu discoveries are located within the boundaries of the Block 51 PSC (“Block 51”) in the Malay-Tho Chu Basin, approximately 200 kilometres offshore Vietnam in a water depth of 64 metres.
Jadestone, through its wholly-owned subsidiaries Mitra Energy (Vietnam Nam Du) Pte Ltd and Mitra Energy (Vietnam Tho Chu) Pte Ltd, has a 70 per cent operated working interest in the two PSCs. The Company has made two gas/ condensate discoveries on its acreage, being Tho Chu on Block 51, and Nam Du on Block 46/07. The process of amending Block 51 and Block 46/07 for PVEP’s relinquishment of its 30 per cent interest and withdrawal from the blocks with effect from 1 May 2017 is continuing. This is expected to result in Jadestone having 100 per cent operated working interests.
Exploration phase two of the Block 51 PSC expired on 10 June 2016 and rather than enter exploration phase three, the PSC joint venture parties applied for suspended development area (“SDA”), status over both the U Minh and Tho Chu Fields. Jadestone was advised on 26 December 2016 that SDA status had been approved by the Prime Minister of Vietnam for the Tho Chu and U Minh Fields for a five year period from 11 June 2016. The SDA status enables the asset to be retained for up to five years, with a possible further two year extension, pending external events.
For the U Minh Field, the SDA was expected to last only until approval of the ODP, at which point it would become a development/production area. As noted below, ODP approval was granted on 21 May 2018. The Tho Chu Field will remain as an SDA pending clarity on the availability of new pipeline infrastructure which is planned for the area north west of Block 51.
Vietnamese Government compliant Reserve Assessment Reports for both the Nam Du (Block 46/ 07) and U Minh (Block 51) Fields were approved by the Prime Minister of Vietnam in January 2016.
According to the CPR, as at 31 December 2017, Block 51 and Block 46/07 PSC had gross 2C gas resources of 496.8 Bscf (347.8 Bscf net to Jadestone) and gross 2C liquids resources of 11 MMbbl (7.7 MMbbl net to Jadestone), of which the U Minh Fields and Nam Du Fields comprise gross 2C gas resources of 171.3 Bscf (119.9 Bscf net to Jadestone) and gross 2C liquids resources of 1.6 MMbbl (1.1 MMbbl net to Jadestone). Jadestone management have used the statement of contingent resources in the CPR, together with estimates for capex and opex, to calculate an aggregate NPV10 of US$246 million for the U Minh and Nam Du fields.
At present, no development plan has been submitted for the Tho Chu discovery and contingent resources are consequently classified as Development Unclarified.
Geology and sub-surface
The Nam Du Southern Channel reservoir is a fluvial channel of Lower Miocene age. It is approximately 20 metres thick and has two thin coal intervals. The wireline log character shows a coarsening-upwards sequence. The upper 10-15 metres appears to be cleaner from the Gamma Ray response and this is reflected in the interpreted porosity curve as a higher porosity interval.
The reservoir is shown to be part of a low sinuosity channel-point bar system that runs from north east to south west, and is approximately six kilometres in length along the axis and averages approximately one kilometre in width. There is an additional channel chute that splits from the main channel to the west that is approximately 2.5 kilometres long and 250 metres wide.
The U Minh H100 reservoir is a moderately sinuous channel-point bar system of Miocene age, trending downdip from northeast to southwest where it is folded over the U Minh four-way dip closure structure. The channel-point bar complex is at least 12 kilometres long and 1.3 kilometres wide. There is a fault south of Well 46/07-ND-1X which provides a separate area south of the fault. This area has not been drilled and is therefore considered to be prospective resources. The Company will refer to this as the Nam Du Southern Channel. ERCE did not provide an estimate for this volume south of the fault in the CPR.
The Tho Chu reservoirs were deposited in the Lower to Middle Miocene ages. The depositional environment ranges from fluvial to marginal marine. Reservoir sands are typically thin (1-5 metres) and are separated by flooding surfaces that are thought to act as seals. An abundance of coals deposited throughout the Lower to Middle Miocene interval allow for a robust stratigraphic correlation.
The Nam Du field was discovered in April 2013 by exploration Well 46/07-ND-1X, drilled by Mitra Energy (Vietnam Nam Du) Pte Ltd. The well 46/07-ND-1X was drilled to a total depth of 2,297 mMD and discovered gas in two main Miocene fluvial channel reservoirs. A further ten reservoir sandstone intervals were encountered and are mainly gas-bearing. Gas bearing reservoirs have a C02 content of approximately 8 per cent. Only one of these reservoirs, Nam Du Southern Channel, contains enough gas to warrant development and thus is the only reservoir with Contingent Resource estimates. Nam Du Southern Channel has a combination structural/stratigraphic trap, with the channel limits defined by seismic inversion volumes and structural control from 3-way dip closure and fault throw.
U Minh was discovered by exploration Well 51-UM-1X in January 1997, drilled by FINA Exploration Minh Hai B.V. This is the only well on the field.
The Tho Chu discovery was discovered in 2012 by exploration Well 51-TC-1X and later appraised in 2014 by Well 51-TC-2X. In October 2012, Well 51-TC-1X was drilled to a total depth of 3,185 mMD and discovered a total of 55 hydrocarbon pay reservoirs (53 gas/condensate and 2 oil) within a sequence of stacked Lower to Middle Miocene reservoirs deposited in a fluvial to marginal marine environment. Gas bearing reservoirs have a variable CO2 content, ranging from 10 to 80 per cent The discovery is located in the hanging wall of a major fault zone that defines its eastern boundary. In March 2014, Well 51-TC-2X was drilled approximately 7 kilometres to the north on a second structural crest. The well was drilled to a total depth of 3,114 mMD and penetrated 17 hydrocarbon pay reservoirs (all gas/condensate) over the same Miocene interval as Well 51-TC-1X.
Route to market and development plan
There is one remaining commitment well for Block 46/07 which is planned to be drilled as an exploration well on the Nam Du Field to test the southern channel area. This could firm up further volumes for the Nam Du development. The well is being designed to be suspended as a potential future production well or drilled from the well head platform at the time of development. Mitra Energy (Vietnam Nam Du) Pte Ltd has applied to defer the well beyond the next 12 months, and whilst formal approval to defer has not been received, the ODP, which contemplates such well being drilled as part of the overall development, was approved on 21 May 2018.
The ODPs for the Nam Du and U Minh Fields were submitted to PVEP on 8 November 2016 for endorsement and approval before submission to the MOIT. Subsequent to PVEP’s withdrawal from the Blocks and with the support of PVN, Jadestone revised the two ODPs to reflect a standalone development for the combined fields based on Jadestone having a 100 per cent working interest. Given the approvals of the ODPs, Jadestone is now commencing the Define Phase of the project (front end engineering and design, preparation of a field development plan, and preparation of a gas sales agreement).
In November 2017, the Company submitted revised ODPs for the U Minh and Nam Du fields for approval, which was received from the MOIT in May 2018. The Company currently anticipates developing these two fields in a phased manner, with overall project sanction targeted for H2 2019. Two development plans are being considered as part of this ODP approval process:
(a) The first proposal is a standalone development combining Nam Du and U Minh, comprising a Central Processing Platform (“CPP”) or leased FPSO located at Nam Du, with separation, dehydration and compression process equipment. A minimum facilities well head platform would be located over Nam Du and a WHP would be located over U Minh with a multi-phase tie-in pipeline to Nam Du. The gas export line would be via an existing pipeline and liquid export would be via tanker; and
(b) The second proposal involves an area development comprising Nam Du, U Minh and the PVEP operated Block 46/13 Khanh My and other discoveries. A minimum facilities WHP would be located on U Minh with a multi-phase tie-in pipeline to Nam Du. A minimum facilities WHP would be located on Nam Du with a multi-phase tie-in pipeline to Khanh My. A CPP would be located at Khanh My with separate gas and liquids export lines to existing infrastructure.
Ahead of project sanction, the Company is working on the front-end engineering and design, negotiation of commercial gas sales agreements and field development planning.
With the delays in the ODP approval, development drilling has been delayed. Jadestone requested a further two-year extension to exploration phase two on 31 May 2018. This extension has not yet been granted and there can be no assurance that it will be granted.
The Company intends to use an existing 18 inch pipeline with 215 MMscf/d of capacity, owned by PetroVietnam, which is in close proximity to the Nam Du and U Minh fields to evacuate gas from the fields to an existing power complex and fertiliser plant in Southern Vietnam. This pipeline currently evacuates gas from the heritage Talisman operated PM-03 CAA Block which lies immediately to the south of Block 46/07. This field is currently in decline, which is expected to result in sufficient ullage within the pipeline, which the Company intends to seek to utilise.
The Tho Chu field will be subject to a later development plan.
Total capital expenditure of the Nam Du/U Minh development is currently estimated to be in the range of US$240 million to $275 million, based on the approved ODP and third party pre-FEED studies. Jadestone management estimates for the Nam Du/U Minh wholesale well head gas price, an initially fixed price that is anticipated to have fixed escalation, is in the range of US$8.5/MMbtu to US$9/MMbtu, based on the approved ODP, recent third party gas price negotiations in Vietnam. Jadestone management estimates for operating expenditure for the Nam Du/U Minh development are in the range of US$65 million to 85 million based on the approved ODP and current pre-FEED planning.
The CPR identified the southern channel as prospective resources, but did not include any volumes estimates or further comments on this prospect. Jadestone management’s estimate for the Southern channel gives an unrisked prospective resources of 31.1Bscf and with an estimated NPV10 of US$76 million. Jadestone management considers this to be a low risk prospect based on the seismic response being similar to what is seen at the discovery well. The already planned development for Nam Du includes all the capacity needed to also produce at the Nam Du southern channel. The optimal plan would be to drill the appraisal/exploration well directly from the well head riser platform which, if successful, can then be completed as a development well. With success for southern channel, the Company’s plan would then be to drill only one further development well for Nam Du. To maintain safety of supply, two development wells for Nam Du were already assumed in the cost assumptions so there would be no incremental costs for a southern channel success case.
MONTARA ASSETS AND THE MONTARA ACQUISITION
1 MONTARA ASSETS OVERVIEW
The Montara project is located in Production Licences AC/L7 and AC/L8 in the Timor Sea, approximately 690 kilometres west of Darwin, 630 kilometres north of Broome and 250 kilometres north-west from the Kimberley coastline of Western Australia in a water depth of 77 meters. The Montara fields are situated in the prolific Vulcan Sub-basin.
The FPSO has an operational storage capacity of 900,000 barrels and accommodation space for 58 people. The FPSO is moored in the Montara field for the life of the project.
1.1.2 Ownership & Regulatory Environment
The Montara Assets are 100% operated and owned by PTTEP Australasia, a wholly owned subsidiary of PTTEP, the upstream arm of Thailand’s national oil company. The Montara Assets represents PTTEP’s only currently producing field in Australia. The field has generated significant PRRT tax credits (AUD$3.7 billion) under PTTEP which will be transferred under the asset sale. The Company does not anticipate that it will have to pay PRRT over the current projected life of the Montara Assets. The Company will, however, remain liable for Australian corporate tax which is currently charged at the rate of 30%.
PTTEP currently hold the Safety Case, Environment Plan and WOMPs required under Australian legislation.
On 21 August 2009, a blowout in Well Montara-H1ST1 resulted in an uncontrolled flow of hydrocarbons into the sea that continued for 74 days to 3 November 2009. The cause of the blowout was most likely that hydrocarbons entered Well Montara-H1ST1 through the 9 5/8” cemented casing and flowed up the inside of the 9 5/8” casing. The Montara Commission of Inquiry found that at the time Well Montara H1ST1 was suspended, not one well control barrier complied with PTTEP Australasia’s own Well Construction Standards. The casing shoe had not been pressure-tested, despite a troublesome cement job, and it is likely that the cement in the shoe had been compromised as it had been over-displaced by fluid, resulting in a ‘wet shoe’. Furthermore, although two secondary well control barriers (pressure containing anti-corrosion caps) were due to be installed, only one was installed and it was not tested and verified in-situ as required by the Well Construction Standards.
The Montara Commission of Inquiry deemed that PTTEP Australasia did not observe sensible oilfield practices in the Montara field, and that for this reason the Northern Territory Department of Resources should not have approved the Phase 1B Drilling Programme that commenced in July 2009.
After several proposed solutions including water deluge and surface capping, the blowout was eventually arrested by the drilling of a gas relief well, Montara-H1ST1-RW1. The design and execution of the relief well was regulated by the Northern Territory Department of Resources. The relief well intersected Well Montara-H1ST1 on 1 November 2009 and pumped heavy mud into the well. On 3 November 2009 the flow of hydrocarbons was completely stopped. The relief well later injected 320 barrels of cement into Well Montara-H1ST1 and on 13 January 2010, PTTEP Australasia reported that operations to plug and secure the well were complete.
1.1.3 Geology and subsurface
Producing sandstone formations include prolific Plover, Montara and Lower Vulcan formations. All producing formations have high permeability (0.5 – 4 Darcy) and high porosity (18 – 24%).
Production commenced in June 2013 and approximately 23.1 MMbbl have been produced to 31 December 2017. Successful completion of an additional producing well Montara H5-ST2 occurred in October 2017, increasing field production by 3,500 bbl/d. The asset is currently producing 10.3 mbbls/d from six wells in three fields with three further subsea wells expected back online in Q4 2018. The Montara crude is a high quality, light, low-sulphur crude with a 35.5° API, selling at a premium to Brent into Thailand refineries. Gas produced from the field is reinjected via a dedicated injection well to maintain reservoir pressure and maximise oil recovery from the reservoir. A future blow-down of the gas cap could potentially generate longer dated revenue streams and maximise asset utilisation.
Jadestone has identified numerous infill drilling candidates as well as near-field exploration opportunities that may be exploited by the Company to maximise value from the asset.
The Montara operations involve the extraction of oil using four platform production wells and one gas injector for the Montara field and five subsea production wells for Swift, Skua and Swallow fields. The oil from the subsea wells transported via subsea flowlines to an unmanned wellhead platform and then to the Floating Production Storage and Offloading (“FPSO”) facility which acts as a hub for the Montara cluster and potentially additional stranded discoveries in the region.
The offshore facilities consist of an unmanned platform (from which the Montara field wells were drilled and are accessed) with eight slots for wells (three horizontal, three tie-backs, one injector and one spare) as well as a manned FPSO facility. The subsea wells from Skua, Swift and Swallow fields as well as the Montara field platform wells all produce to the FPSO where the oil is processed, residual gas is separated and compressed to be reinjected into the Montara field.
The Montara Venture FPSO has been converted from the 140,450 deadweight tonne oil tanker MT Freeway in Jurong Shipyard, Singapore. The conversion was completed in 2009. As part of the conversion the engine, propeller and shaft were removed, the FPSO has therefore essentially been converted to a barge. The conversion also included the installation of an internal submerged turret, production and processing facilities for crude separation, gas compression, gas lift and gas reinjection giving the FPSO an oil production capacity of 40 mbbls/day with a storage capacity of 900,000 bbls.
In addition to the FPSO the Montara development includes a 4 level, 750 tonne well head platform which can fit five production wells and one gas-injection well. Normal cargo liftings taken from the FPSO are circa 550,000 bbl oil. The processing capacity of the FPSO is 40 mbbls/d of oil and 60 mbbls/d of water, where the gas processing system can dehydrate using a glycol contactor process up to 60 MMscf/d, and can reinject up to 50 MMscf/d of gas while also providing gas lift for the oil wells.
The FPSO also has gas processing and compression facilities, enabling the operator to both reinject produced gas back into the field to maintain reservoir pressure and also provide gas lift for all wells.
The FPSO is subject to continuous hull survey, which includes surveys of the cargo and ballast tanks on a five year cycle in order to maintain vessel classification. PTTEP were advised in September 2017 that class would be suspended due to failure to complete hull surveys in the required time. PTTEP was unable to start tank surveys in 2017 and as such Lloyd’s Register suspended Class on the vessel on 3 January 2018. An inspection was undertaken on 23 March 2018, following which Lloyd’s confirmed that the suspension of Class would be maintained. A work programme has been identified which, once complete, will enable the reinstatement of vessel class. Following the presentation of a detailed plan for completion of the outstanding work scope to Lloyd’s on 30 June 2018, Lloyd’s, on 2 July 2018, confirmed its agreement of the plan to return the FPSO to Class.
1.1.5 Reserves and Production
The Montara assets have gross 2P reserves of 28.2 MMbbls oil (gross and net) and 3P reserves of 38.5 MMbbls oil (gross and net), split as follows between the fields:
• the Montara field, located in production licence AC/L7 has 14.9 MMbbls of gross and net 2P reserves;
• the Skua field, located in production licence AC/L8 has 6.9 MMbbls of gross and net 2P reserves; and
• the Swift/Swallow field, located in production licence AC/L8 has 6.4 MMbbls of gross and net 2P reserves.
1.1.6 Montara Field
The Montara field was discovered in 1988 by the Montara-1 well, drilled by BHP Biliton. The field produces from the Upper Jurassic Cycle IV reservoir, which is of excellent quality. In 2009, prior to the commencement of production at the field, there was a blow-out at Well H1.
The field commenced production in June 2013 from three horizontal oil producers, with each well initially producing at rates between 3 and 4 mbbls/d.
In June 2016 the current operator began re-injecting gas into the gas cap through the well Montara G-2, to maintain reservoir pressure. As at 31 December 2017 the well was injecting at an average rate of 10 MMscf/d.
In October 2017, an additional horizontal well, Montara-H5, was brought onstream at an oil rate of 3.5 mbbls/d. The well targets unswept volumes in the southwest of the field. Current production for the Montara field is 7 mmbls/d.
A historic charge in relation to the Montara Assets was discharged and has been notified to the Australian Securities and Investments Commission, but has not yet been removed from the National Electronic Approvals Tracking System (NEATS) registry. The underlying charge is no longer valid and is in the process of being removed from the NEATS registry.
Jadestone is proposing to drill an additional horizontal production well (H6) along the western boundary fault targeting oil north of H5. This infill well will use the one remaining slot on the Montara platform.
A historic charge in relation to the Montara Assets was discharged and has been notified to the Australian Securities and Investments Commission, but has not yet been removed from the National Electronic Approvals Tracking System (NEATS) registry. The underlying charge is no longer valid and is in the process of being removed from the NEATS registry.
Although a thin oil column was intersected in Well Skua-2 in 1985, the main accumulation was not discovered until 1987 by Well Skua-3. A further 5 wells were drilled to December 1991 (Skua-4, -7A, -8, -9 and -9ST1), when the first phase of Skua production commenced.
The Skua field comprises a 48 metre oil column overlain by a small gas column of approximately 10 metres. Hydrocarbons are contained within the Early to Middle Jurassic Plover Formation, the quality of which is excellent.
First production from the Skua field came in December 1991 from three producers, Wells Skua-4, -8 and -9ST1. The field initially produced at approximately 25 mbbls/d, eventually declining to 2.4 mbbls/d. After producing 20.2 MMbbls/d, the field was shut-in in January 1997 due to it being uncommercial. Through this first development stage, the wells were connected to a dedicated FPSO.
In 2011, the then operator produced a field development plan with the intention of bringing the field back onstream, with higher oil prices making the project economic. In March 2014, the field was brought back onstream through two new horizontal wells, Skua-10ST2 and Skua-11, which achieved initial rates of approximately 4 mbbls/d and 2.5 mbbls/d respectively. The field is now produced through the Montara field infrastructure.
Current production for the Skua field is 1700 bbl/d through Skua-10 with Skua-11 expected back online at 2.5 mbbl/d in Q4 of 2018.
Jadestone is proposing to drill an additional horizontal production well (Skua-12) on the field’s crest in between the Skua-10ST2 and Skua-11 wells. The well will be tied into the existing subsea infrastructure. The Skua-12 well will have a horizontal well section of approximately 650 metres and target unswept oil between the two currently producing wells.
The Swift field was discovered in January 1985 by Well Swift-1. The well targeted the Plover Formation but found it to be water bearing. However, excellent hydrocarbon shows were found in an unexpected Rowan sandstone.
A total of four wells have been drilled on the Swift and Swallow fields. This includes one exploration well and three vertical production wells. The Swift field has two production wells, Swift-2 and Swift North-1. The Swift-2 well has had issues with gas lifting and the well is currently shut-in. The Swallow field has a single production well, Swallow-1. The well was completed close to the oil-water contact and water breakthrough occurred very early, with rapid water cut development. The well has been shut-in since April 2016 with plans to add perforation in shallower oil bearing sands.
First production from the Swift field came in October 2013 from Wells Swift-2 and Swallow-1, with Well Swift North-1 later commencing production in April 2014. The field is produced through the Montara field infrastructure.
Current production for the Swift/Swallow field is 3000 bbl/d through Swift N-1 with Swift-2 and Swallow-1 is expected to be back in Q4 of 2018, adding a combined 3000 bbl/d.
1.1.9 Future development
1.1.10 There is significant upside associated with the Montara Assets, with ERCE’s 3P reserves case including an additional 10.2 MMbbls (gross and net) and an NPV10 uplift of US$313.3 million versus the 2P reserves case. Furthermore, Jadestone has identified several different areas in which it believes it can potentially realise value in the future. Such areas are not included in ERCE’s reserves case and include.
• further infill drilling, not included in ERCE’s reserves case, have been identified by Jadestone management in the Montara and Skua fields. This includes one further platform well on the Montara field which would be a sidetrack of H4, capturing remaining volume along the northern bounding fault, and two further subsea wells on Skua capturing volumes further north along the crest. Each of these wells would have an initial rate of 3 mmbl/d and targeting a combined rate of 5.3 MMbbl in the Montara and Skua fields beyond the 2P reserves case;
• tie-back additional existing in-field and near-field discoveries as facilities become available, currently the well head facilities are either fully utilised or allocated to existing and near-term production;
• spare capacity in the FPSO means discoveries can be monetised quickly
• the Company has identified further prospects in the blocks and intends to shoot 3D seismic surveys over the blocks. This is expected to help to further define the existing prospects and identify further prospects across the blocks which the Company may target in the future;
• in the blocks neighbouring the Montara Assets there are multiple oil and gas discoveries and previously suspended fields. Many of these discoveries are currently stranded as they are not of a size that can economically justify a standalone development. Currently the Montara Assets infrastructure is the only infrastructure in the area through which these discoveries could potentially be produced. The Company may in the future explore opportunities to monetise these assets which may be through acquisition, farm-in or third party tariff arrangements; and
• within the Company’s blocks, there are currently stranded discovered gas resources which are currently not of a size which would make commercialisation economic. However, within neighbouring blocks there are also other similarly stranded gas discoveries and the Company could in the future explore joint development solutions for these discoveries. This will, however, remain subject to pricing, technology and neighbouring activities.
2 MONTARA LICENCE
2.1 Production licence AC/L7
The Production licence AC/L7 (granted on 20 March 2007) (“AC/L7”) relates to an active oil resource located offshore Australia. This licence is for an indefinite term. The grant of AC/L7 is subject to OPGGS Act and the following conditions:
(a) The licensee shall not construct any installation or install any equipment in the licence area except with and in accordance with the approval in writing of the Commonwealth – Western Australia Offshore Petroleum Joint Authority (“Joint Authority”).
(b) The licensee shall not abandon, suspend or complete any well except with and in accordance with the approval of the Joint Authority;
(c) The licensee shall at all times comply with the provisions of the OPGGS Act and of any regulations for the time being in force under the OPGGS Act, including any directions given thereunder;
(d) In carrying out its operations in the licence area the licensee must take adequate measures for the protection of the environment; and
(e) The licensee must, to the satisfaction of the Joint Authority, continue to appraise and explore the licence area to determine whether additional recoverable petroleum exists in the area and shall exploit such petroleum where economic.
2.2 Production licence AC/L8
The Production licence AC/L8 (dated 9 August 2007) (“AC/L8”) relates to an active oil resource located offshore Australia. This licence is for an indefinite term. The grant of AC/L8 is subject to the OPGGS Act and the following conditions:
(a) The licensee shall not construct any installation or install any equipment in the licence area except with and in accordance with the approval in writing of the Commonwealth – Western Australia Offshore Petroleum Joint Authority (“Joint Authority”);
(b) The licensee shall not abandon, suspend or complete any well except with and in accordance with the approval of the Joint Authority;
(c) The licensee shall at all times comply with the provisions of the OPGGS Act and of any regulations for the time being in force under the OPGGS Act, including any directions given thereunder;
(d) In carrying out its operations in the licence area the licensee must take adequate measures for the protection of the environment; and
(e) The licensee must, to the satisfaction of the Joint Authority, continue to appraise and explore the licence area to determine whether additional recoverable petroleum exists in the area and shall exploit such petroleum where economic.
3 MONTARA ACQUISITION
3.1 Acquisition Agreement
On 15 July 2018, Jadestone Energy (Eagle) Pty Ltd, a wholly-owned subsidiary of the Company, (as buyer) (the “Buyer”) entered into an acquisition agreement (the “Acquisition Agreement”) with, amongst others, the Company (as guarantor) and PTTEP Australasia (as seller) (the “Seller”). Under the terms of Acquisition Agreement, the Seller has agreed to sell certain assets, comprising the key equipment, facilities and reserves necessary for the proper operation of the Montara oil site, the Montara Assets for a purchase price of US$195 million, subject to working capital adjustments and additional contingent amounts. The Company, being the ultimate holding company of the Buyer, shall guarantee the obligations of the Buyer under the Acquisition Agreement. PTTEP Offshore Investment Company Limited, an affiliate of the Seller, shall guarantee the obligations of the Seller under the Acquisition Agreement.
On completion (“Completion”) of the Acquisition Agreement, the Seller shall sell and the Buyer shall buy:
(a) a 99% legal and 100% beneficial right, title and interest in the production licences AC/L7 and AC/L8 (the “Montara Titles”); and
(b) a 100% legal and beneficial interest in the Montara Assets (excluding the Montara Titles),
(the “Stage One Assets”).
The remaining 1% interest in the Montara Titles (the “Stage Two Asset”) shall be held on trust by the Seller, in favour of the Buyer, until the satisfaction of the Stage Two Conditions (defined and described below). The minimum consideration attributable to the Stage One Assets (the “Purchase Price”) shall be paid by the Buyer to the Seller on Completion. The amount of the Purchase Price is the aggregate of:
(a) the agreed purchase price for each Stage One Asset (the “Asset Purchase Price”); plus
(b) the value of the crude oil inventory stored at the Montara site; plus
(c) the agreed capital charge (being the amount of accrued interest (calculated on a daily basis at a rate of 3% above LIBOR) from and including 1 January 2018 (the “Effective Date”) to, but excluding the date of, Completion, on the Asset Purchase Price)); plus
(d) the amount as specified in the first cash call pursuant to the OTSA to be entered into in parallel with the Acquisition Agreement between the Buyer and the Seller, and shall be subject to an upward or downward adjustment attributable to the amount of income receipts received by the Seller, less the operating expenses paid by the Seller in relation to the Montara site, for the period between the Effective Date and Completion.
The Purchase Price shall be subject to further increases, on the occurrence of certain of the following trigger events (the “Trigger Events”):
|(a)||US$5 million||Montara 2018 Production is equal to or greater than 3.55MMbbls but less than 3.75MMbbls.|
|(b)||US$10 million||Montara 2018 Production is equal to or greater than 3.75MMbbls but less than 3.95MMbbls.|
|(c)||US$15 million||Montara 2018 Production is equal to or greater than 3.95MMbbls but less than 4.15MMbbls.|
|(d)||US$20 million||Montara 2018 Production is equal to or greater than 4.15MMbbls but less than 4.35MMbbls.|
|(e)||US$25 million||Montara 2018 Production is equal to or greater than 4.35MMbbls but less than 4.55MMbbls.|
|(f)||US$30 million||Montara 2018 Production is equal to or greater than 4.55MMbbls.|
|(g)||US$20 million||The Average Dated Brent Price in calendar year 2019 is US$80/bbl or higher.|
|(h)||US$10 million||The Average Dated Brent Price in calendar year 2020 is US$80/bbl or higher.|
|(i)||US$20 million||Total quantity of hydrocarbons produced from the Montara infill well during the first 12 month period following first commercial production (being sustained production for sale and not for testing or commissioning) from the Montara infill well is equal to or greater than 1.5 MMbbl.|
|(j)||US$20 million||First commercial gas.|
|(k)||US$60 million||Any final investment decision to approve a project development plan or development work plan and budget or similar or analogous decision to proceed with development or developments of the Montara Assets where such development or developments have 2P reserves greater than 15.0 MMbbls.|
In the table above “Average Dated Brent Price” for a particular year is calculated in accordance with the formula A/B, where:
(e) A means the sum of the average of the high and low ‘Dated Brent’ quotations (data code PCAAS00) as published on ‘Platts Sarus’ for each day on which the Dated Brent quotation is published; and
(f) B meansthe number of published days in that calendar year.
The Purchase Price shall be subject to further upward or downward adjustment following the agreement between the Buyer and the Seller of the completion statement.
Completion of the Acquisition Agreement shall be conditional on the following events occurring (the “Conditions”):
(g) the dealings evidenced by the ASA and the operator services agreement between the Buyer and the Seller being approved and registered under the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (“OPGGSA”) against each of the Montara Titles; and
(h) the Buyer receiving approval under the Foreign Acquisitions and Takeovers Act 1975 and the Buyer receiving TSX-V approval under the OPGGSA.
The Seller shall transfer the Stage Two Asset following the occurrence of the following events (the “Stage Two Conditions”):
(i) the removal of the Seller as titleholder to the Montara Titles;
(j) the removal of the Seller from the operator register in relation to the Montara site;
(k) the consent of the Commonwealth Minister for the Environment and Energy in relation to the transfer of the Seller’s Environmental Approval (defined in the ASA as the approval granted to and held by the Seller under the Environmental and Biodiversity Conservation Act 1999 on 3 September 2003); and
(l) the Seller ceasing to hold safety and environmental operational and management plans in relation to the Montara site, each of which will become effective on the same date.
The Acquisition Agreement contains customary warranties in relation to capacity and ownership of each of the Montara Assets. In addition there are also customary warranties in relation to the conduct of business of the Seller, compliance with laws and that all material contracts to the operation of the Montara site have been disclosed to the Buyer. The Acquisition Agreement contains an indemnity from the Seller in relation to any latent liabilities incurred or suffered by the Buyer as a result of the major oil and gas leakages which occurred at the Montara site in 2009 (the “Montara Incident Indemnity”).
The Acquisition Agreement also contains customary limitations on the Seller’s liability under the Acquisition Agreement including matters reviewed by the Buyer as part of its due diligence investigations, time limits and financial limitations. The maximum aggregate cap on the Seller’s liability for a breach of any of the warranties relating to the ownership of the Montara Assets is up to 100% of the Purchase Price and in the case of a breach by the Seller of any of the other warranties in the Acquisition Agreement (including tax warranties, but excluding the Montara Incident Indemnity) shall be up to 30% of the Purchase Price.
The Acquisition Agreement is governed by the laws of Western Australia.
The Buyer structured the transaction so as to receive the economic benefit of the acquisition as soon as possible. In the interim period pending Jadestone’s approval as operator, the Buyer has, through the placement of secondees and other rights under the OTSA (defined below) the ability to influence significant decisions.
3.2 Operator and Transitional Services Agreement
The Buyer and the Seller (as operator and transitional services provider) entered into an operator and transitional services agreement (the “OTSA”) to govern the operation and management of the Montara Assets and the provision of transitional services in the period from Completion (as defined in the Acquisition Agreement). The term of the OTSA shall run until the later of:
(a) the Operator Transfer Date (as defined in the Acquisition Agreement); and
(b) a date to be agreed between the parties.
Under the OTSA, the Seller is responsible for the day-to-day operations required to run the Montara site (the “Operations”). The Seller shall perform the Operations with due care and skill, in compliance with all applicable laws and in accordance the approved program and budget (set out in Schedule 3 to the TSA) for the Montara site. Under the OTSA, the Seller shall, before the tenth day of each month, submit an invoice to the Buyer for an amount equal to the Seller’s estimate of the aggregate cash requirement for the next ensuing month (each occurrence, being a “Cash Call”) in order to perform the Operations. Following a Cash Call, the Buyer shall pay the amount of the Cash Call to the Seller by the no later than the last business day of the month prior to which the Cash Call relates.
The amount of the first Cash Call shall be dependent on the completion of the Acquisition Agreement. If completion of the Acquisition Agreement occurs before the 10thday of a calendar month, the amount of the first Cash Call, shall be the Seller’s estimate of the aggregate cash requirement for the remainder of that month. If completion of the Acquisition Agreement occurs on or after the 10thday of a calendar month, the amount of the first Cash Call shall be the Seller’s estimate of the aggregate cash requirement for the remainder of that month, plus the whole of the following calendar month.
In addition to the Operations, the Seller will also provide contract procurement and novation services and network, telecoms and general infrastructure consulting services to the Buyer (the “Transitional Services”). The Seller shall provide the Transitional Services with due care and skill, in compliance with all applicable laws and in accordance with the transition plan for the Montara site.
Each party to the OTSA shall have the ability to appoint four representatives to the transition committee, which shall be established by the parties pursuant to the terms of the Acquisition Agreement, to manage the delivery of the Transitional Services.
The OTSA contains customary warranties given by both parties in relation to performance of their obligations under the OTSA. The OTSA contains an indemnity from the Buyer in favour of the Seller in relation to all damages, loss, expense or liabilities suffered by the Seller (and its affiliates, directors and employees) arising out of the delivery of the Operations or Transitional Services.
3.3 Montara Crude oil Sale AGreement
The Crude Oil Sale Agreement dated 25 March 2013 is made between PTTEP Australasia and PTT Public Company Limited (“PTT”) , as extended by a letter of extension dated (the “Crude Oil Sale Agreement”). The Crude Oil Sale Agreement relates to the sale by PTTEP Australasia to PTT of the entire crude oils, condensates, natural gas liquids and other hydrocarbons in a liquid state at standard pressure produced from the project comprising the Montara, Skua, Swallow and Swift oil fields and other fields within the Licences.
Crude is delivered on an “as is” basis. If crude differs materially from the indicative specification provided and the parties do not agree to adjust the crude price, PTT has an ability to refuse to accept crude or accept delivery of the crude subject to PTTEP Australasia being liable to pay compensation if PTT on-sells the crude at a lower price.
Either party may terminate on 30 days’ notice where force majeure events persist for a continuous period of 60 days or on 3 months’ written notice where there is a change in legislation which adversely affects a party’s rights, powers or remedies under the Crude Oil Sale Agreement and the legislation change cannot be excluded nor an agreement reached between the parties; and for insolvency or default (subject to an applicable cures period in respect of default). The Seller may also elect to terminate if PTT does not agree to a proposed change to the term price.
Term price is calculated on an FOB basis using a formula that incorporates Daily Dated Brent, an average of the Platts Premium/Discount and Rim’s Premium/Discount (for Tapis premium over dated Brent) and a premium which is based on the highest spot market price achieved during the Spot Market Period in accordance with a prescribed bidding process. The premium was fixed at USD$0.2825/bbl when the term sale was entered into in 2015. However if PTTEP Australasia considers that the term price does not adequately reflect the market price for the crude, then it may on 30 days’ notice: (i) extend or effectively re-instate the Spot Market Period so that the price is recalibrated in accordance with the spot prices achieved during a renewed period of marketing; or (ii) change the term price and, if PTT does not agree to such change, PTTEP Australasia may terminate the agreement with immediate effect.
Assignment by either party requires consent of the other party, not to be unreasonably withheld or delayed. A party will not withhold or delay its consent to an assignment if the assignee has the requisite financial, technical and operational capacity to perform the assignor’s obligations under the agreement.
Each party may grant a security interest over its rights under the agreement to a financial institution having a minimum specified credit rating (or similar) without the consent of the other party, provided the security interest does not affect the validity and enforceability of the agreement or the rights and obligations of the other party under the agreement.
The Seller provides a broad indemnity to PTT for direct loss (including demurrage) arising from PTT’s failure to observe or perform any of its obligations. PTT provides the same indemnity to PTTEP Australasia plus a number of further specific indemnities, including for pollution and for actions taken by the tanker owner and their personnel (including pollution and property damage). The agreement is governed by the laws of Western Australia.
4 OVERVIEW OF THE REGULATORY APPROVALS REQUIRED IN RELATION TO THE MONTARA ACQUISITION
The following Australian regulatory approvals are required in connection with the Acquisition:
(a) receipt of notice under the Foreign Acquisitions and Takeovers Act 1975 (Cth) (“FATA”) from the Treasurer of the Commonwealth of Australia to the effect that the Commonwealth Government of Australia does not object to the transactions contemplated by the Acquisition Agreement (“FIRB Approval”);
(b) NOPTA approval and registration of the Acquisition Agreement, OTSA and the transfer of the Production Licences AC/L7 and AC/L8 from PTTEP to Jadestone (“NOPTA Approvals”);
(c) NOPSEMA approval of Jadestone’s safety case, environment plan and a WOMP (“NOPSEMA Approvals”);
(d) transfer of the an EPBC Approval (2002/755) from PTTEP to Jadestone (“EPBC Approval”); and
(e) registration of the transfer of the FPSO from PTTEP to Jadestone (“FPSO Transfer”).
Summaries of the process for obtaining each approval are set out below.
4.2 FIRB Approval
The Australian government screens foreign investment proposals on a case-by-case basis to determine whether a particular proposal is contrary to the national interest. The main laws that regulate foreign investment in Australia are the FATA and the Foreign Acquisitions and Takeovers Regulation 2015 (Cth).
The legislation regulates foreign investment proposals by a “foreign person”. For the purposes of the Acquisition, Jadestone is considered a foreign person under section 4 of the FATA given it is a corporation in which two or more persons, each of whom is an individual not ordinarily resident in Australia, hold an aggregate substantial interest.
Once an application has been lodged (and FIRB confirms that the application fee has been paid), the general rule is that the Treasurer has 30 calendar days to make a decision and a further 10 calendar days to notify the applicant, subject to this timeframe being extended. If no decision is made then no further orders can be made (that is, the Treasurer cannot prohibit or unwind a transaction if a decision is not made in time).
FIRB Approval is a condition precedent to the Acquisition Agreement. Jadestone lodged its FIRB application on 15 June 2018 and the application fee was paid. On 5 July 2018, FIRB notified Jadestone that it would not be able to complete its assessment of Jadestone’s application by the statutory deadline. Jadestone has agreed to a request for extension of the statutory deadline to 3 August 2018.
4.3 NOPTA Approvals
NOPTA is the decision maker for transfer and dealing applications in respect of the Licences. NOPTA can either approve or refuse to approve a transfer and/or dealing and will notify the applicant of the decision by written notice pursuant to section 478 and section 493 of the OPGGS Act.
Transfer or dealings relating to the Licences are of no force until approved and registered, in relation to a particular Licence pursuant to section 472 and section 487 of the OPGGS Act.
The transfer and dealing process involves two stages:
(a) the application, accompanied by the prescribed fee for each Licence, is assessed and either approved or refused by NOPTA. If approved, a memorandum of the approval is stamped on the instruments and any related supplementary instruments; and
(b) approved instruments are registered by NOPTA. Copies of either the approved instrument (or if applicable a supplementary instrument) are placed on the National Electronic Approvals Tracking System, which is a public register.
4.3.2 Approval and registration of Acquisition Agreement and OSA as a dealing
NOPTA must approve and register the dealings in the Licences evidenced by the Acquisition Agreement and the OTSA, pursuant to section 488(4) of the OPGGS Act.
NOPTA may require information regarding the Jadestone’s technical and financial capacity to meet the obligations associated with being registered titleholder of the Licences.
The dealings evidenced by the Acquisition Agreement and the OTSA being approved and registered against each of the Licences is a condition precedent under the Acquisition Agreement.
4.3.3 Approval and registration of a transfer of the Licences
For the application to approve the transfer of each Licence, the following documentation must be provided to NOPTA:
(a) a completed application form;
(b) an instrument of transfer;
(c) a document setting out:
(i) the technical qualifications of the transferee;
(ii) details of the technical advice that is or will be available to that transferee; and
(iii) details of the financial resources that are or will be available to that transferee (section 474(b) of the OPGGS Act).
Technical qualifications and advice
NOPTA needs to be satisfied that transferee has sufficient technical capacity to meet the obligations associated with the Licences. These may include:
(a) work program commitments;
(b) capacity to explore and to progress the development of known resources; and
(c) ability to meet the requirements of an accepted field development plan.
An application for approval of a dealing or transfer must be made within 90 days after the day on which the party who last executed the instrument evidencing the dealing so executed the instrument (such as the Acquisition Agreement, OTSA and instruments of transfer), or such longer period as the NOPTA allows.
There is no stipulated time frame under the OPGGS Act by which NOPTA needs to provide its decision. However, NOPTA has indicated its assessment of a transfer or dealing application may be finalised within four to six weeks of receiving all information that is relevant for the assessment.
4.4 NOPSEMA APPROVALS
4.4.1 Safety case approval
Safety case contents
Jadestone will apply to NOPSEMA for acceptance of the safety case after execution of the SPA in order for it become operator of the Montara Facilities.
A safety case must comply with the content requirements of the Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009 (“Regulations”), which are technically complex and address each stage in the life of the facility in respect of which the Licences relate.
Jadestone, as the incoming operator, will need to demonstrate that in the development of the safety case there has been effective consultation with, and effective participation of, members of the workforce in order to facilitate informed opinions about the risks and hazards to which they may be exposed on the facility.
Safety case approvals process
(a) Pre-submission of safety case
The existing titleholders must notify NOPSEMA in writing that there will be a replacement operator.
If NOPSEMA is satisfied that the replacement operator will have day-to-day management and control of the facility, it will register the replacement operator as the new operator of a “proposed facility” (in the meantime, the existing operator will remain registered as an operator of “the facility”). The existing titleholder will then request that the existing operator be removed from the register at a specified date and time associated with the handover of the operations.
Jadestone, as the new operator, must agree with NOPSEMA on the scope of validation before submitting their new safety case.
(b) Submission of safety case
Jadestone, as the new operator, must submit a new safety case.
NOPSEMA has powers under the Regulations to require the new operator to provide further written information in respect of the contents of the safety case. The new operator will have at least 30 days in which to re-submit the safety case to address the request for additional information.
(c) Estimated timeframe to obtain NOPSEMA’s decision
Within 90 days of receiving the safety case, or after receiving the safety case that has been resubmitted to address a request for additional information, NOPSEMA must notify the operator that NOPSEMA has decided:
(i) to accept the safety case;
(ii) to reject the safety case; or
(iii) that NOPSEMA is unable to make a decision (and set out a proposed timetable for its consideration of the safety case).
A failure by NOPSEMA to comply with the above obligations does not affect the validity of a decision by NOPSEMA to accept or reject the safety case.
Once the new safety case is accepted, arrangements are to be made for the handover of operations, which will coincide with removal of the outgoing operator from the operator register.
4.4.2 Environmental plan approval
Environment plan contents
Broadly, the purpose of an environment plan is to identify the proposed petroleum activity’s impacts on and risks to the relevant environment and set out control measures to reduce the identified impacts and risks.
Division 2.3 of the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009 (“Environment Regulations”) sets out content required for the environment plan.
Environment plan approval process
Under regulation 17(7) of the Environment Regulations, a new titleholder must submit a proposed revision of the existing environment plan for an activity as soon as practicable if a change in titleholder will result in a change in the manner in which the environmental impacts and risks of an activity are managed. Whether such a change will occur is a technical question for a proposed titleholder. If the change in titleholder will not result in a change in the manner in which the environmental impacts and risks of an activity are managed, the new titleholder will only need to notify NOPSEMA of the change in titleholder.
Under Regulation 10, within 30 days of an environment plan being submitted, NOPSEMA must either accept the plan, notify the titleholder of any relevant criteria in respect of which NOPSEMA is not reasonably satisfied (and set a date by which the titleholder must resubmit the plan), or, if NOPSEMA is unable to make a decision, notify the titleholder of a proposed timetable for consideration of the plan.
Within 10 days of receiving notice that NOPSEMA has accepted an environment plan (whether in full, in part or subject to limitations or conditions), the titleholder must submit a summary of the accepted plan to NOPSEMA (compliant with the requirements under Regulation 11(4) of the Environment Regulations) for public disclosure.
4.4.3 Well operation management plan (“WOMP”) approval
Under Regulation 5.04 of the Offshore Petroleum and Greenhouse Gas Storage (Resource Management and Administration) Regulations 2011 (Cth) (“RMA Regulations”), a titleholder undertaking a well activity in a title area that does not have an accepted WOMP in force for undertaking the well activity commits an offence. Well activities include drilling, well testing, wirelines, workovers, well completion or re-completion, well maintenance and abandonment or suspension of a well.
A WOMP must comply with the contents requirement of Part 5 of the RMA Regulations, as amended by the Offshore Petroleum and Greenhouse Gas Storage Legislation Amendment (Well Operations) Regulation 2015 (Cth) and the corresponding laws of each state or territory, where powers have been conferred upon NOPSEMA.
WOMP approval process
Under Regulation 5.06(2) of the RMA Regulations, a titleholder must give a WOMP to NOPSEMA at least 30 days before the proposed start of a well activity (or such other period as NOPSEMA allows).
Under Regulation 5.07, within 30 days of the WOMP being submitted, NOPSEMA must accept the plan or one or more parts of the plan, reject the plan, or notify the titleholder in writing that it is unable to make a decision without further assessment of the plan (in which case it may request further information and must give the titleholder reasonable opportunity to resubmit the WOMP). Where NOPSEMA undertakes further assessment of the WOMP, it must accept the plan (or one or more parts of the plan) or reject the plan.
4.4.4 Financial assurance
Under section 571(2) of OPGGS Act, a titleholder must maintain financial assurance sufficient to give the titleholder the capacity to meet costs, expenses, and liabilities that may result in connection with carrying out a petroleum activity, doing any other thing for the purpose of the petroleum activity, or complying (or failing to comply) with a requirement under the OPGGS Act in relation to the petroleum activity (“Petroleum Activity Costs”).
Titleholders nominate how they will give the financial assurance, including by way of insurance, self-insurance, a bond, deposit of an amount as security with a financial institution, an indemnity or other surety, a letter of credit from a financial institution and/or a mortgage. Titleholders may use their discretion in determining the form or mix of forms for their specific requirements as long as the form or combination of forms covers the maximum financial assurance required to meet the financial assurance duty.
Provision of the financial assurance will involve quantification of Petroleum Activity Costs.
If the potential environmental consequences of an incident associated with a petroleum activity are considered by NOPSEMA to be unusually high, NOPSEMA may, at its discretion, require the titleholder to fully calculate costs, expenses and liabilities in relation to that incident rather than applying the Australian Petroleum Production and Exploration Association (APPEA) method.
4.5 EPBC Approval
PTTEP Australasia holds the EPBC Approval issued pursuant to section 133 of the Environment Protection and Biodiversity Conservation Act 1999 (Cth) (“EPBC Act”) which authorises the following action in the Commonwealth marine areas:
‘To drill and operate Montara 4, Montara 5 and Montara 6 Wells for the purposes of oil production and to re-complete and operate Montara 3 for use as a gas re-injection well in Permit Area AC/RL3, in the Timor Sea approximately 200km from the coast of Western Australia (EPBC 2002/755).’
For the EPBC Approval to be transferred to Jadestone, PTTEP Australasia and Jadestone need to make a written agreement and submit it to the Commonwealth Minister for the Environment and Energy for approval.
Under section 145B(2) of the EPBC Act, the written agreement does not take effect until the Minister consents in writing to the transfer.
The Commonwealth Department of Environment and Energy has advised that it may take approximately 2 months for the Minister to decide whether to transfer the EPBC Approval.
4.6 FPSO Transfer
For a transfer of title of the FPSO from PTTEP to Jadestone, Jadestone is required to notify the Registrar of Ships of the change of ownership within 14 days. The following steps are required to be taken:
(a) Obtain a bill of sale from the Seller
The bill of sale is proof of the transfer of ownership from PTTEP to Jadestone as the new owner. The bill of sale must be completed by PTTEP and comply with Australian Maritime Safety Authority (“AMSA”) requirements.
(b) Obtain the original registration certificate
The original registration certificate for the FPSO (issued by AMSA) must be returned to the Australian Shipping Registration Office in order for the transfer of ownership to be completed. If the original registration certificate has been lost, an application will need to be made for a replacement certificate together with a fee.
(c) Complete a declaration of transfer Form 169
In accordance with section 36(3) of the Shipping Registration Act 1981 (Cth), Jadestone will need to complete the Form 169 and submit it to the Australian Shipping Registration Office with the lodgement fee.
(d) Complete a notice of appointment of registered agent
Jadestone will need to appoint a ship manager to manage the day to day running of the ship and provide notification of the ship manager to the Australian Shipping Registration Office.
1 RISKS RELATING TO THE COMPANY’S BUSINESS
Exploration, development and production risks
Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of Jadestone depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves Jadestone may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in Jadestone’s reserves will depend not only on its ability to explore and develop any existing properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that Jadestone will be able to continue to locate satisfactory properties for acquisition or participation on economically favourable terms or at all. Moreover, if such acquisitions or participations are identified, management of Jadestone may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by Jadestone.
Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs and taxes, royalties or their equivalents. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.
While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, any of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, Jadestone is not fully insured against all of these risks, nor are all such risks insurable. Although the operators of Jadestone’s concessions are required to maintain liability insurance in an amount that they consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event Jadestone could incur significant costs that could have a material adverse effect upon its financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations, with losses resulting from the occurrence of any of these risks.
Reserve based lending is exposed to oil price fluctuation and this may have an impact on the Company’s borrowing ability
The Company is obtaining new external debt finance under a reserve based lending facility. Reserve-based lending, a type of external financing that is commonly used in the oil and gas industry, is a form of loan made against, and secured by, an oil and gas field or a portfolio of undeveloped or developed and producing oil and gas assets. The amount of the loan facility available to the borrower, and the interest rate applicable to the finance, are based on the value of the borrower’s oil and gas reserves, as adjusted from time to time. An RBL loan facility is repaid using the proceeds from sales in the field or portfolio. Oil and gas prices are volatile and can change significantly over the term of an RBL facility (typically three to five years), during which time the lender will typically re-evaluate the borrower’s reserves on a periodic basis. While lenders consider several factors to calculate the borrowing base, one of the most significant is the prevailing price of oil and gas and the lenders’ judgment on how these prices will move. The price is oil is determined by a number of factors that are beyond the control of the Company, including governmental regulations and geopolitical developments. Although the Company is confident that when entered into the RBL Facility will continue to be available for a period and in the amounts that the Company requires to further its strategic objective, there can be no guarantee that a major fluctuation in oil prices will not have a negative impact on the Company’s reserves and thus its borrowing base under the RBL Facility.
The Company has an existing Convertible Facility and, following the Acquisition and entering into the RBL Facility, the Enlarged Group will have increased borrowings and debt service obligations. The Enlarged Group expects that leverage will continue for the foreseeable future. The Directors believe that the level of leverage may reduce over time, however, the degree to which the Enlarged Group will continue to be leveraged could have important consequences for the business, including:
• making it more difficult for the Enlarged Group to satisfy its obligations with respect to its indebtedness;
• restricting the Enlarged Group’s ability to make strategic acquisitions or pursue other business opportunities;
• together with the financial and other restrictive covenants under the terms of the indebtedness, limiting the Enlarged Group’s ability to obtain additional financing, dispose of assets or pay cash dividends other than as permitted by the terms of the indebtedness;
• requiring the Enlarged Group to sell or otherwise dispose of assets used in the business in order to fund debt service obligations;
• limiting the Enlarged Groups flexibility in planning for, or reacting to, changes in the business and the industry in which it operates;
• placing the Enlarged Group at a competitive disadvantage compared to competitors that have less debt; and
• increasing the Enlarged Groups cost of borrowing.
Any of these consequences or events could have a material adverse effect on the Enlarged Group’s ability to satisfy the debt obligations. The Enlarged Groups 43 substantial leverage could materially and adversely affect the business, financial condition and results of operations and prevent the Enlarged Group from servicing payment obligations under the indebtedness. The Enlarged Group will require cash to meet obligations under its indebtedness and sustain the business operations, and the Enlarged Group’s ability to do so will depend on many factors beyond its control. The Enlarged Group’s ability to meet its obligations under its indebtedness, including making principal, interest and other payments when due, as well as its ability to fund ongoing business operations, will depend upon future operating performance and the Enlarged Group’s ability to generate cash, which, in turn, will be affected to some extent by general economic conditions and by financial, competitive, legislative, regulatory and other factors, including those factors discussed in this Part 5 and elsewhere in this document. If, on the maturity date of any of the indebtedness, the Enlarged Group does not have sufficient cash flows from operations and other capital resources to repay and redeem the debt in full or pay other debt obligations, as the case may be, the Enlarged Group may be required to undertake alternative financing plans, such as refinancing or restructuring the debt, selling assets, reducing or delaying capital investments or raising additional debt or equity financing in amounts that could be substantial or on unfavourable terms. The Enlarged Group’s access to debt, equity and other financing as a source of funding for operations and for refinancing maturing debt will also be subject to many factors, including the cash needs of the Enlarged Group and the then prevailing conditions in the financial markets, including in the corporate bond, term loan and equity markets. In the longer term, if the Enlarged Group were unable to generate sufficient cash flows to satisfy its debt obligations or to refinance its indebtedness on acceptable terms, or at all, it would materially and adversely affect its business, prospects, financial condition and results of operations, as well as its ability to pay the principal and interest on its indebtedness. Any failure to refinance its indebtedness, on or prior to the applicable maturity date, may result in the Enlarged Group defaulting on such indebtedness.
The Company has engaged in transfer pricing which may be subject to review by taxation authorities
In 2016 and 2017, Jadestone Energy Australia implemented two shareholder loans from its parent company, under the terms of which interest is chargeable by the lender. At the time these loans were entered into, external advice in the form of a transfer pricing study, was obtained to confirm an appropriate interest rate to be charged for this purpose. In light of this advice, the Company considered that the interest rate applicable to these shareholder loans was, at the time of drawdown, supportable from an Australian transfer pricing perspective. However, the Australian Taxation Office has subsequently published a practical compliance guide regarding cross-border related party financing arrangements. Jadestone has not completed a risk assessment in respect of the existing shareholder loans following the publication of this new guidance, and there is a risk, albeit low, that the existing shareholder loans to Jadestone Energy Australia, and the associated documentation, could be subject to scrutiny by the Australian Taxation Office.
Jadestone will manage a variety of small and large projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic.
Jadestone’s ability to execute projects and market oil and natural gas will depend upon numerous factors beyond Jadestone’s control, including:
• the availability of processing capacity;
• the availability and proximity of pipeline capacity;
• the availability of storage capacity;
• the supply of and demand for oil and natural gas;
• the availability of alternative fuel sources;
• the effects of inclement weather;
• the availability of drilling and related equipment;
• unexpected cost increases;
• accidental events;
• currency fluctuations;
• political uncertainty;
• the availability and productivity of skilled labour; and
• the regulation of the oil and natural gas industry by various governmental agencies, including changes in regulations.
Because of these factors, Jadestone could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that it produces.
Delays in business operations
In addition to the risk that Jadestone’s customers may make delayed payments to the Company, and the delays by operators in remitting payment to the Company, payments between these parties may be delayed due to restrictions imposed by lenders, accounting delays, delays in the sale or delivery of products, delays in the connections of wells to a gathering system, adjustment for prior periods, or recovery by the operator of expenses incurred in the operation of the properties. Any of these delays could reduce the amount of cash flow available for the business of the Company in a given period and expose the Company to additional third party credit risks.
Title to assets
Jadestone has investigated the rights to explore and exploit the various oil and gas properties it holds or proposes to participate in and, to the best of its knowledge, those rights are in good standing. Although title reviews have been or will be done according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of Jadestone which could result in a reduction of the revenue received by Jadestone. Further, no assurance can be given that applicable governments will not revoke, or significantly alter the conditions of, the applicable exploration and development authorisations and that such exploration and development authorisations will not be challenged or impugned by third parties. There is no certainty that such rights or additional rights applied for will be granted or renewed on terms satisfactory to Jadestone. There can be no assurances that claims by third parties against Jadestone’s properties will not be asserted at a future date.
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids (or similar substances) reserves and cash flows to be derived therefrom, including many factors beyond Jadestone’s control. The information concerning reserves and associated cash flow set forth in the reserves statement contained in the competent persons report by ERCE dated July 15, 2018 (the “CPR”), which is available on the Company’s website, represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, actual realized price of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary from actual results. All such estimates are to some degree speculative, and the classifications or reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. Actual production, revenues, taxes and development and operating expenditures with respect to the Company’s reserves will vary from estimates thereof and such variations could be material. Further, the evaluations are based, in part, on the assumed success of the exploitation activities intended to be undertaken in future years. The reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluation.
Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material. Some of Jadestone’s producing wells have a limited production history and thus there is less historical production on which to base the reserves estimates. In addition, a significant portion of Jadestone’s reserves may be attributable to a limited number of wells and, therefore, a variation in production results or reservoir characteristics in respect of such wells may have a significant impact upon the Company’s reserves.
In accordance with applicable securities laws, ERCE has used forecast price and cost estimates in calculating reserve quantities. Actual future net cash flows will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and cash flows derived therefrom will vary from the estimates contained in the CPR and such variations could be material. The CPR is based in part on the assumed success of activities Jadestone intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the CPR will be reduced to the extent that such activities do not achieve the level of success assumed in the CPR. The CPR is effective as at 31 December 2017 and has not been updated as at the date of this announcement, and therefore thus does not reflect changes in Jadestone’s reserves and resources since that date.
Contingent and prospective resources are unlikely to be commercially productive in the short or medium term
This announcement contains estimations of contingent and prospective resources attributable to the Group. Uncertainties exist with respect to the estimation of contingent and prospective resources in addition to those that apply to Reserves. Contingent resources are resources estimated, at a given date, to be potentially recoverable from known accumulations but are not yet considered mature enough for commercial development due to one or more contingencies. Contingent resources may include, for example, projects for which there are no visible markets, or where commercial recovery is dependent upon technology under development, the availability of export routes or where evaluation is insufficient to clearly assess commerciality. Prospective resources are resources estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Development of contingent and prospective resources, if undertaken, may involve considerable expense and may not result in the discovery of hydrocarbons in commercially viable quantities. Volumes and values associated with contingent and prospective resources should be considered highly speculative and there can be no guarantee that the Group will be able to develop these resources commercially.
Properties with no attributed reserves
The development of properties with no attributed reserves can be affected by a number of factors including, but not limited to, project economics, forecasted commodity price assumptions, cost estimates and access to infrastructure. These and other factors could lead to the delay or the acceleration of projects related to these properties.
Expiration of licences and leases
Jadestone’s properties are held in the form of licences, leases and production service agreements and the Company has working interests in these licences, leases and production services agreements. If Jadestone or the holder of the licence, lease or production services agreement fails to meet the specific requirement of a licence, lease or production services agreement, then it may terminate or expire or may not be renewed. There can be no assurance that any of the obligations required to maintain each licence, lease or production services agreement will be met. The termination or expiration of Jadestone’s licences, leases or production services agreement or the working interests or the failure to renew such licences, leases or production services agreements or the working interests therein may have a material adverse effect on Jadestone’s results of operations and business.
Other companies operate certain of the assets in which Jadestone currently has a participating interest and on completion of the Acquisition will do so for an interim period. As a result, Jadestone is dependent on such operators for the timing of activities related to such properties and will be largely unable to control the operations of those assets or their associated costs, which could adversely affect Jadestone’s financial performance. Jadestone’s return on assets operated by others will therefore depend upon a number of factors that may be outside Jadestone’s control, including the timing and amount of capital expenditures, the operator’s expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.
Reliance on management and key personnel
Jadestone’s success depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on Jadestone. Jadestone does not have any key person insurance in effect for management. The contributions of the existing management team to the immediate and near term operations of Jadestone are likely to be of central importance. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of Jadestone.
Jadestone has currently hedged part of its production from the Stag field. Under the RBL Facility, it will also be required to hedge a significant proportion of its future production from the Montara Assets. In addition, from time to time Jadestone may enter into or be required to enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, if commodity prices increase beyond the levels set in such agreements, Jadestone will not benefit from such increases on the hedged volumes. Similarly, from time to time Jadestone may enter into agreements to fix the exchange rate of Australian to United States dollars or other relevant currency in order to offset the risk of cost escalation relating to general and administrative costs if the Australian dollar increases in value compared to the United States dollar. It should be noted that in the event of declining oil prices, the Company may not be able to enter into hedging terms on acceptable terms in order to sufficiently protect against downside exposure, and as a result there is a risk that Jadestone may not be able to hedge against reduced cash inflows in such a scenario.
Third Party credit risk
Jadestone may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to Jadestone, such failures could have a material adverse effect on Jadestone and its cash flow from operations. In addition, poor credit and or liquidity conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in Jadestone’s ongoing capital programme, potentially delaying the programme and the results of such programme until Jadestone finds a suitable alternative partner.
Availability of equipment, qualified personnel and related costs
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) and qualified personnel in the particular areas where such activities will be conducted. Demand for such limited equipment and qualified personnel or access restrictions may affect the availability of such equipment and qualified personnel to Jadestone and may delay exploration and development activities. To the extent Jadestone is not the operator of its oil and gas properties, Jadestone will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators. In addition, the costs of qualified personnel and equipment in the area where Jadestone’s assets are located may be very high due to the lack of availability of, and demands for, such qualified personnel and equipment in the area.
Conflicts of interest
Certain directors of Jadestone are also directors of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions. Conflicts, if any, will be subject to the procedures and remedies of the BCBA.
Limitations of insurance risk
Jadestone’s involvement in the exploration for and development of oil and natural gas properties may result in Jadestone becoming subject to liability for pollution, blow outs, property damage, personal injury or other hazards. Although Jadestone seeks to insure itself in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to protect Jadestone against the full extent of such liabilities to which it is exposed. In addition, such risks may not in all circumstances be insurable or, in certain circumstances, Jadestone may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any such uninsured liabilities would reduce the funds available to Jadestone. The occurrence of a significant event that Jadestone is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on Jadestone’s financial position, results of operations or prospects.
As the Company is engaged in the oil and natural gas business its operations are subject to certain unique provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation relating to characterisation of costs incurred in their businesses which affects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. Jadestone will file all required income tax returns and believes that it will be in full compliance with the provisions of the Income Tax Act (Canada) and all applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of the Company, whether by re-characterization of costs or otherwise, such reassessment may have an impact on current and future taxes payable.
Jadestone will also be subject to various tax regimes in foreign countries that are subject to changes in legislation and interpretation, including Australia, Vietnam, Indonesia and the Philippines. The Company will file foreign income and other tax returns as are required and believes it will be in full compliance with the relevant foreign legislations.
In the normal course of Jadestone’s operations, it may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating to personal injuries, property damage, property taxes, land rights, the environment and contract disputes. From time to time Jadestone may enter into agreements to fund some or all of the costs associated with such litigation in exchange for a portion of the proceeds which may ultimately be received. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to Jadestone and as a result, could have a material adverse effect on Jadestone’s assets, liabilities, business, financial condition and results of operations. Even if Jadestone prevails in any legal proceeding, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from the Company’s business operations, which could adversely affect its financial condition even where Jadestone has obtained litigation funding.
Failure to realise anticipated benefits of acquisitions and disposals
Jadestone makes acquisitions and disposals of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as Jadestone’s ability to realise the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses may require substantial management effort, time and resources and may divert management’s focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of or relinquished so that Jadestone can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of Jadestone, if disposed of, could be expected to realise less than their carrying value on the financial statements of the Company.
Substantial capital requirements
Jadestone anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. Jadestone’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times or to allow it to undertake or complete future drilling programmes. The ongoing maintenance and operation of assets and equipment in the offshore oil and gas industry, in particular FPSO installations, is heavily capital intensive.
From time to time, due to changes in its circumstances or its business strategy, Jadestone may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities. In particular, the Group may need additional funds in the longer term, outside the period of the working capital statement contained in this document, in order to further fund its exploration and development programmes.
Failure to obtain such financing on a timely basis could cause Jadestone to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If Jadestone’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, Jadestone’s ability to expend the necessary capital to replace its reserves or to maintain its production will be impaired. If and to the extent that Jadestone raises new capital through an issuance of new equity in future, this may be dilutive to holders of the Company’s then existing Common Shares and could contain rights and preferences superior to those of the Common Shares. Debt financing may involve restrictions on the Group’s financing and operating activities. In either case, additional financing may not be available to the Group on acceptable terms. If the Group is unable to raise additional funds as needed, the scope of its operations may be reduced and, as a result, the Group may be unable to fulfil its long-term growth programme, or meet its contractual obligations under its contracts which may ultimately be withdrawn or terminated for non-compliance.
Failure to meet minimum expenditure commitments
Certain of the Company’s licences and concessions contain minimum expenditure commitments, the Company elects to withdraw from such licences before meeting such commitments, or is otherwise unable to meet such commitments, it may suffer financial loss associated with restricted cash sums or penalties. Furthermore, such circumstances may impact the Company’s ability to obtain new licences or concessions in the relevant country.
Extraction of financial information provided in respect of the Montara Assets
In addition, the financial information provided in respect of the Montara Assets, as provided by PTTEP Australasia, has been extracted from PTTEP Australasia’s Oracle accounting system. As a result, it may not be complete or accurate, as it is outside the control of the Company.
In addition, the financial information in the extracts provided may not be presented on a full IFRS basis and the accounting policies applied in the preparation of such information are likely to differ from those of the Group. As a result, where the information is to form part of the Group’s reporting, such information may be materially different.
The Group is subject to cyber risks
The Group is dependent upon the availability, capacity, reliability and security of its information technology infrastructure and its ability to expand and continually update this infrastructure, to conduct daily operations and to successfully integrate future acquisitions into the Group. The Group depends on various information technology systems to estimate reserve quantities, process and record financial data, manage its land base, manage financial resources, analyse seismic information, administer its contracts with its operators and communicate with employees and third-party partners. The Group is at risk of financial loss, reputational damage and general disruption from a failure of its information technology infrastructure or an attack for the purposes of espionage, extortion, terrorism or to cause embarrassment. Any failure of, or attack against, Jadestone’s information technology infrastructure may be difficult to prevent or detect, and Jadestone’s internal policies to mitigate these risks may be inadequate or ineffective. Jadestone may not be able to recover any losses that may arise from such a failure or attack.
2 RISKS RELATING TO THE INDUSTRY OR COUNTRIES IN WHICH THE COMPANY OPERATES
Volatility of commodity prices
Crude oil prices are unstable and are subject to fluctuation. The Company’s revenues, profitability and rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Prices for oil and natural gas are subject to wide fluctuations in response to changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include, but are not limited to:
• global energy policy, including (without limitation) the ability of OPEC to set and maintain production levels and influence prices for crude oil;
• political instability and hostilities;
• domestic and foreign supplies of crude oil and gas;
• the overall level of energy demand;
• weather conditions;
• weather conditions;
• government regulations;
• currency exchange rates;
• the availability of refining capacity and transportation infrastructure;
• the effect of worldwide environmental and/or energy conservation measures;
• the price and availability of alternative energy supplies; and
• the overall economic environment.
In a period of oil price decline and/or sustained low oil prices, the Company may be required to curtail or cut costs including capital development costs. This may have an impact on the Company’s ability to grow inter alia production and cash flow and thus its ability to deliver its business plan.
All of the Company’s operations are currently located in Vietnam, the Philippines, Australia and Indonesia. As such, Jadestone’s operations, financial condition and operating results could be significantly affected by risks over which it has no control. These risks may include risks related to economic, social or political instability or change, terrorism, hyperinflation, currency non-convertibility or instability and changes of laws affecting foreign ownership, interpretation or renegotiation of existing contracts, government participation, taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions, working conditions, fluctuations in rates of exchange, exchange control, exploration licensing, petroleum and export licensing and export duties, government control over domestic oil and gas pricing, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds; the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licences to operate and concession rights in countries where Jadestone currently operates; and difficulties in enforcing Jadestone’s rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Problems may also arise due to the quality or failure of locally obtained equipment or technical support, which could result in failure to achieve expected target dates for exploration operations or result in a requirement for greater expenditure. Jadestone’s operations may also be adversely affected by applicable laws and policies of Vietnam, the Philippines, Australia and Indonesia, the effect of which could have a negative impact on Jadestone, including in relation to the uncertain application of laws such as tax laws. Further, Jadestone may not be able to perform all of its obligations under a service contract in respect of Block SC-57 if it cannot be registered to transact business in the Philippines.
Jadestone’s operations may be adversely affected by political and economic circumstances in the countries in which it operates
Oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in laws and policies governing operations of foreign-based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, obtaining various approvals from regulators, foreign exchange restrictions, currency fluctuations, royalty increases and other risks arising out of foreign governmental sovereignty, as well as risks of loss due to civil strife, acts of war, guerrilla activities, terrorism, acts of sabotage, territorial (including maritime boundary) disputes and insurrection. In addition, Jadestone is subject both to uncertainties in the application of the tax laws in the countries in which it operates and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in its tax liabilities. These risks may be higher in the developing countries in which Jadestone conducts a majority of its activities.
Jadestone’s operations in these areas increase its exposure to risks of local economic conditions, political disruption, civil disturbance, expropriation, piracy and governmental policies that may:
• disrupt its operations;
• require Jadestone to incur greater costs for security;
• restrict the movement of funds or limit repatriation of profits;
• lead to U.S. government or international sanctions; or
• limit access to markets for periods of time.
Some countries in the geographic areas where Jadestone operates have experienced political instability in the past or are currently experiencing instability. Disruptions may occur in the future, and losses caused by these disruptions may occur that will not be covered by insurance. Consequently, Jadestone’s exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on Jadestone’s results of operations and financial condition. Jadestone’s operations may also be adversely affected by laws and policies of the jurisdictions, including the jurisdictions where its oil and gas operating activities are located and other jurisdictions in which it does business, that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could materially and adversely affect Jadestone’s financial position, results of operations and cash flows.
The geographic locations of Jadestone’s licences in Southeast Asia may subject Jadestone to an increased risk of loss of revenue or curtailment of production from factors specifically affecting that region
Jadestone’s current exploration licences are located in Southeast Asia. Some or all of these licences could be affected should any region experience any of the following factors (among others):
• severe weather, natural or man-made disasters or acts of God;
• delays or decreases in production, the availability of equipment, facilities, personnel or services;
• delays or decreases in the availability of capacity to transport, gather or process production;
• military conflicts or civil unrest; and/or
• international border disputes or heightened geopolitical tensions.
For example, oil and natural gas operations in Jadestone’s licence areas in Vietnam or Indonesia may be subject to higher political and security risks than those operations under the sovereignty of the United Kingdom. Jadestone plans to maintain insurance coverage for only a portion of therisks faced from doing business in these regions. There also may be certain risks covered by insurance where the policy does not reimburse for all of the costs related to a loss. Further, as many of Jadestone’s licences are concentrated in the same geographic area, a number of licences could experience the same conditions at the same time, resulting in a relatively greater impact on results of operations than they might have on other companies that have a more diversified portfolio of licences.
The development schedule of oil and natural gas projects is capital intensive and can be subject to delays and cost overruns
Projects in the oil and natural gas industry have historically experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oilfield services, as well as mechanical and technical issues. The cost to develop projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs and host government and partner cooperation. Construction and operation schedules may not proceed as planned and may experience delays or cost overruns.
The Group’s decommissioning liabilities may be onerous and cannot be accurately predicted
The Group, including following Completion, has through its licence interests assumed certain obligations in respect of the decommissioning of its licences and related infrastructure and is expected to assume additional decommissioning liabilities in the future. These liabilities are derived from legislative and regulatory requirements concerning the decommissioning of wells and production facilities and at the appropriate time will require the Group to make provisions for and/or underwrite the liabilities relating to its share of such decommissioning costs. It is difficult to forecast accurately the costs that the Group will ultimately incur in satisfying its decommissioning obligations, particularly as: (i) the costs of decommissioning are highly volatile, being linked to rig rates, as well as oil and gas capital expenditures generally; and (ii) regulations determining the decommissioning standards may change.
The Group does not currently have a sinking fund to meet the costs of decommissioning its current assets. The estimated timing of decommissioning is dependent upon a number of factors and a material reduction in asset profitability may bring forward such timing to a date earlier than originally envisaged. When its decommissioning liabilities crystallise, the Group will be jointly and severally liable for them with current licence partners and, in some jurisdictions, former licence partners. In the event that other partners default on their obligations, the Enlarged Group will remain liable and its decommissioning liabilities could be magnified significantly through such default. Any significant increase in the actual or estimated decommissioning costs that the Enlarged Group incurs may adversely affect its financial condition.
The Group and, following Completion, the Enlarged Group may not be successful in obtaining new licences and assets
Future oil and gas production will to some extent depend on the Group’s access to new reserves through exploration, development and acquisitions. The Group has in the past applied for, and been successful in receiving, licence awards in various jurisdictions and plans to continue to make such applications in the future. Failures in licence applications, exploration and development activities or in identifying and finalising transactions to access potential reserves would slow the Group’s oil and gas production growth and replacement of Reserves. This, in turn, could have a material adverse effect on the Group’s business.
The Group may be subject to financial and operational risks associated with farm-out arrangements
The Group has farmed out in the past, and intends to continue to farm-out, various commitments to third parties in circumstances where such third parties have agreed to take an assignment of an interest in one or more licences in return for paying not only the costs associated with that assigned interest but also a proportion of the costs associated with the Group’s retained interest in such licence. Often these costs are associated with the drilling of a well or a development and therefore can be material. There is a risk that the relevant third parties may not meet their obligations under the farm-out agreements, the underlying operations may not meet the conditions of the farm-out or the farm-out counterparty may not be able to fulfil its associated obligations, any of which may mean that the Group may have to re-assume those obligations and bear the full costs associated with its retained interest. This in turn could have a material adverse effect on the Group’s business and financial condition.
Ogan Komering PSC re-entry or future payments are not guaranteed and could be more costly than estimated and ultimately not in the interest of shareholders
Pertamina are currently 100% owner and operator of the Ogan Komering PSC, following the new gross split PSC which was signed, effective 20 May 2018, by Pertamina, Indonesia’s upstream regulator SKKMIGAS, and the Minister of Energy and Mineral Resources. Jadestone, as the prior partner in the PSC, with Pertamina, has been directed to proceed with direct negotiations for participation in the new PSC.
There can be no assurance that Jadestone will be successful in its negotiations for participation in the PSC or that the terms of participation are economical for Shareholders. Any changes to the timing or quantum of realised costs to re-enter the PSC or futures receipts will impact the future profitability of the Company.
Declines in oil prices will adversely affect the Company’s financial condition, liquidity and results of operations.
Oil prices have decreased significantly since mid-2014. Although prices have recovered from these lows there is no certainty that prices will not fall again and any prolonged period of low crude oil prices could result in a decision by the Company to suspend or slow exploration and development activities or reduce production levels. Any such actions could have a material adverse effect on the Company’s business, financial condition, results of operations and prospects and ultimately on the market price of the Common Shares. In addition, any bank borrowings that may be made available to the Company in the future will be in part determined by the borrowing base of the Company. A sustained material decline in prices from historical average prices could reduce the Company’s future potential borrowing base, therefore reducing the level of any bank credit that could be made available to the Company.
Volatility in oil and natural gas prices makes it difficult to estimate the value of producing properties for acquisitions and often causes disruption in the market for oil and natural gas producing properties, as buyers and sellers may have difficulty agreeing on the value of such properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
Lower commodity prices will also be a factor in the Company’s efforts to raise additional capital. Management takes the availability of investment capital into consideration as it evaluates acquisition opportunities so as to minimise the possibility of becoming illiquid by acquiring assets that may require more capital than the Company can provide.
The Montara Assets currently yield a premium to Brent crude oil
Whilst the market currently pays a premium for the oil produced at the Montara Assets due to its physical characteristics, there can be no assurances that these physical characteristics will continue to be present or that the market will continue to be willing to pay such a premium for oil demonstrating those characteristics. If either of these were to occur then it could impact the Group’s revenues which in turn could have a material adverse effect on the Group’s business, results of operations, financial condition and prospects.
Access to markets
The Company, along with all other oil and gas industry participants, may have reduced access to capital in the future. Although the business and the quality of the asset base of the Company has not deteriorated, the lending capacity of financial institutions may diminish and risk premiums may increase in the future if debt financing was sought. In addition to funds generated from internal operations, future capital expenditures may potentially be financed using external sources including bank borrowings and equity sales. The ability of the Company to access these two external sources of finance is dependent on, among other factors, the overall state of capital and debt markets and investor and bank appetite for investments and lending into the energy industry and into the Company in particular.
To the extent that external sources of capital become limited or unavailable or available only on onerous terms, the Company’s ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result.
Prices and marketability
The marketability and price of oil and natural gas that may be produced, acquired or discovered by Jadestone is and will continue to be affected by numerous factors beyond its control. Jadestone’s ability to market its oil and natural gas depends upon its ability to acquire space on pipelines that deliver natural gas to commercial markets. Jadestone is also affected by deliverability uncertainties related to the proximity of its reserves to gathering systems, pipelines and processing and storage facilities and related to operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.
Variations in foreign exchange rates and interest rates
The reporting and functional currency of the Company is United States dollars. Substantially all of the Company’s operations are in Vietnam, the Philippines, Australia and Indonesia while substantially all of its revenue is invoiced in United States dollars. As a result, the Company is exposed to foreign currency exchange rate risk on some of its activities primarily on exchange fluctuations between the CAD, Australian dollar, Indonesian Rupiah, Vietnamese Dong and the USD.
To the extent that Jadestone determines to engage in risk management activities related to foreign exchange rates in the future, there is a credit risk associated with counterparties with which Jadestone may contract.
The Group’s debt facilities are subject to a range of interest rates. Any increase in those interest rates could result in a significant increase in the amount Jadestone pays to service any future debt obligations that the Company establishes. Increased levels of interest payable could negatively impact the market price of the Company’s Common Shares.
The international oil and gas industry is highly competitive in all aspects, including the exploration for and the development of new licence areas. Jadestone operates in a highly competitive environment for acquiring exploratory licences and hiring and retaining trained personnel. Jadestone faces intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in seeking oil and gas exploration and production licences in Vietnam, the Philippines, Australia and Indonesia. These companies may be better able to withstand the financial pressures of unsuccessful drilling efforts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which could adversely affect Jadestone’s competitive position. The Company also faces competition in marketing oil and natural gas production, hiring skilled industry personnel and acquiring the equipment and expertise necessary to develop and operate properties. As a result of these and other factors, Jadestone may not be able to compete successfully in an intensely competitive industry, which could cause a material adverse effect on its results of operations and financial condition.
Jadestone may be exposed to liabilities under anti-corruption laws
Jadestone is subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage. In addition, the United Kingdom has enacted the Bribery Act 2010, and Jadestone may be subject to that legislation under certain circumstances. Jadestone currently does business and may do additional business in the future in countries in which Jadestone may face, directly or indirectly, corrupt demands by officials. Jadestone faces the risk of unauthorised payments or offers of payments by one of its employees, contractors or consultants to government officials. Jadestone has implemented policies and procedures to ensure compliance with the FCPA and other applicable legislation, but those policies may not always prevent any such unauthorised payments, and Jadestone’s employees and consultants may engage in conduct for which it might be held responsible. Violations of the FCPA may result in severe criminal or civil sanctions, and Jadestone may be subject to other liabilities, which could negatively affect its business, operating results and financial condition. In addition, the U.S. government may seek to hold Jadestone liable for successor liability for FCPA violations committed by companies in which it invests (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that it acquires.
Jadestone’s current and future operations that are conducted in Vietnam, the Philippines, Indonesia and Australia are subject to environmental regulations promulgated by the respective governments. Should Jadestone initiate operations in other countries, such operations will be subject to environmental legislation in such jurisdictions. Current environmental legislation in Vietnam, Philippines, Indonesia and Western Australia provides for restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil, condensate and natural gas operations. In addition, certain types of operations may require the submission and approval of environmental impact assessments. Jadestone’s existing operations are subject to such environmental policies and legislation. Environmental legislation and policy is periodically amended. Such amendments may result in stricter standards and enforcement and in more stringent fines and penalties for non-compliance. Environmental assessments of existing and proposed projects carry a heightened degree of responsibility for companies and their directors, officers and employees. The costs of compliance associated with changes in environmental regulations could require significant expenditures, and breaches of such regulations may result in the imposition of material fines and penalties. In an extreme case, such regulations may result in temporary or permanent suspension of production operations. There can be no assurance that these environmental costs or effects will not have a materially adverse effect on Jadestone’s future financial condition or results of operations.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require Jadestone to incur costs to remedy such discharge. No assurance can be given that the application of environmental laws to the business and operations of Jadestone will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect Jadestone’s financial condition, results of operations or prospects.
Environmental legislation in Vietnam, the Philippines, Indonesia and Australia provides for restrictions and prohibitions on releases or emissions and regulation of the storage and transportation of various substances produced or utilised in association with certain oil industry operations. This legislation and associated regulations can affect the location and operation of wells and facilities and the extent to which exploration and development is permitted. Applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures and a breach of such legislation may result in the suspension or revocation of necessary licences and authorisations, civil liability for pollution damage, the imposition of fines and penalties or the issuance of clean-up orders.
Environmental legislation and policy is periodically amended. Such amendments may result in stricter standards and enforcement and in more stringent fines and penalties for non-compliance. Environmental assessments of existing and proposed projects carry a heightened degree of responsibility for companies and their directors, officers and employees. The costs of compliance associated with changes in environmental regulations could require significant expenditures, and breaches of such regulations may result in the imposition of material fines and penalties. In an extreme case, such regulations may result in temporary or permanent suspension of production operations and associated activities.
The Group’s operations may be subject to delays or disruption due to actions by environmental or other stakeholder groups
The Group’s operations may in the future be subject to delays or disruption as a result of actions by environmental or other stakeholder groups. There can be no assurance that actions by non-governmental organisations or other stakeholder or community groups in the future will not result in the revocation of the Group’s licences or agreements and/or delays or disruption in the Group’s exploration, appraisal, development or production activities, which could have a material adverse effect on the Group’s business, results of operations, financial condition and prospects.
The Group will be subject to ongoing health, safety, environmental and security (“HSES”) risks
The Group’s HSES risks include major process safety incidents, failure to comply with approved legislation or policies, effects of natural disasters and pandemics, exposure to general operational hazards, personal health and safety, strikes, non-governmental organisation activity, terrorism and crime. The consequences of such risks materialising can include injury, loss of life, environmental harm, disruption to business activities and financial loss. Depending on cause and severity, the materialisation of such risks may have a material adverse effect on the Group’s business. In addition, failure by the Group to comply with applicable legal requirements or recognised international standards may give rise to significant liabilities. HSES laws and regulations have become more complex and stringent and/or the subject of increasingly strict interpretation or enforcement, particularly since the Montara Incident in 2009, and may become more so over time. There may also be unforeseen environmental liabilities resulting from oil and gas activities which may be costly to remedy. In particular, the acceptable level of pollution and potential clean-up costs and obligations and liability for toxic or hazardous substances for which the Group may become liable as a result of its activities may be impossible to assess against the current legal framework and current enforcement practices of the various jurisdictions. The terms of licences may include more stringent HSES requirements. The obtaining of exploration, development or production licences and permits may become more difficult and/or be the subject of delay by reason of governmental, regional or local environmental consultation, approvals or other considerations or requirements. These factors may lead to delayed or reduced exploration, development or production activity as well as to increased costs and may have a material adverse effect on the Group’s business.
Any environmental damage, loss of life, injury or damage to property caused by the Group’s operations could damage the Group’s reputation in the regions in which the Group operates. Negative sentiment towards the Group in those regions, including among the local communities and other stakeholders, could result in a lack of willingness of the relevant governmental authorities to grant the necessary licenses or permits to the Group to operate its business, and communities in the areas where the Group is doing business opposing further operations in the area by the Group. Further, the Group’s reputation could be affected by actions and activities of other corporations operating in the oil and gas industry, over which the Group has no control.
Alternatives to and changing demand for petroleum products
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other liquid hydrocarbons. Jadestone cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on Jadestone’s business, financial condition, results of operations and cash flows.
The Group may be subject to labour disturbances
Labour disturbances, such as work stoppages or lock-outs, which may involve third party contractors, suppliers and customers, may occur in the future, particularly as the workforce engaged on each of the Stag and Montara Assets is unionised and subject to collective bargaining arrangements. These collective bargaining arrangements are subject to review from time to time and the Group may not be able to negotiate acceptable new bargaining agreements for the unionised Stag and/or Montara workforces, which could result in labour disputes, work stoppages or other disturbances to the status quo. Such disturbances could have a material adverse impact on the Group’s production and development schedule and activities in the periods during which they occur. The Group or its contractors may be unable to influence acceptable collective bargaining outcomes or future restructuring agreements or the Group’s operations may become subject to material cost increases or additional work rules as a result of any new collective bargaining agreements. If occurrences of the foregoing are material and/or ongoing, they could adversely affect the Group’s business, prospects, financial condition and results of operations. In addition, material changes in the minimum wage, or other material changes in labour laws, could have a material adverse impact on the Group’s operations. Although the Group is focused on maintaining good relations with its employees and contractors, there can be no guarantee that labour disturbances will not occur.
In the event that Jadestone plans to increase production from the Montara Assets and is not successful, and Jadestone is unable to reduce unit operating costs, if there is a significant fall in the realise oil price (after hedging), the Montara Assets could become uneconomic to producers, leading to a material adverse effect on the Company’s ability to service the RBL Facility and, ultimately, continue as a going concern.
3 RISKS RELATING TO THE ACQUISITION AND THE PLACING
The level of operational performance of the Montara Assets has been historically low
The Montara Assets have historically struggled to achieve an availability performance which is acceptable for an asset of this nature and age, largely due to reliability issues and recurrent operational failures occurring on a consistent basis. The Company is of the view that the current condition of the Montara Assets leaves room for improvement in terms of operational availability of the assets. However, there can be no guarantee that the Company will be able to achieve its desired objectives as regards asset performance and operational availability.
The Montara Assets are subject to greater regulatory scrutiny following the 2009 incident
The Montara Incident in 2009 prompted increased regulatory scrutiny on the Montara Assets, primarily from the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) in Australia. This has imposed, and will likely continue to impose, an additional administrative burden on management to ensure full compliance with the existing and any new regulations. There is also a risk that the new safety case may not be accepted should even a single element be challenged by NOPSEMA. The Company is committed to ensuring full compliance with the relevant regulations and safety requirements and will be actively engaging with NOPSEMA regarding its management of the Montara Assets going forward, however there can be no assurance that NOPSEMA will provide favourable decisions.
The Montara Assets have historically incurred higher than industry standard operating costs
The operational expenditure required to maintain the performance of the Montara Assets is considered higher than regional analogues. The Company considers that it can improve general asset availability, reduce operational costs and achieve better standards of asset performance through active management and implementing its plans for the Montara Assets which it has previously successfully deployed in relation to its other assets. There remains a risk, however, that the operational performance and operating costs of the Montara Assets remain higher than optimal for some time until the Company has implemented its asset transition programme.
The acquisition of the Montara Assets by Jadestone requires the approval of NOPTA
Transfer of the legal title to the Montara Assets to Jadestone requires NOPTA to approve the Acquisition Agreement and the transfer of the title. NOPTA will wish to satisfy itself as to Jadestone’s financial capability to participate in licence operations and to discharge its licence obligations. Such approval is a condition precedent for completion of the Acquisition Agreement and, accordingly, if not received, the Acquisition will not complete. It is currently anticipated that such approval could take several months to obtain, although Jadestone can provide no assurances that such approval will be received within this anticipated timeframe or indeed be received at all.
The transfer of the operatorship of the Montara Assets to Jadestone requires the approval of NOPSEMA
Whilst Jadestone is already the approved operator of the Stag Assets, in order to become the operator of the Montara Assets, Jadestone requires approval of a new safety case by NOPSEMA and as part of this Jadestone will be required to prepare a new WOMP and EP. Such approval is a condition precedent for the operatorship to transfer to Jadestone under the Acquisition Agreement and, accordingly, if not received, operatorship of the Montara Assets will not transfer to Jadestone. It is anticipated that such approval could take some months to obtain, although Jadestone can provide no assurances that such approval will be received within this anticipated timeframe or indeed be received at all.
Jadestone will need to engage a large number of contractors to manage operations relating to the Montara Assets following transfer of operatorship
The Montara Assets require engagement of a significant number of contractors to provide services to maintain its operations and continued performance. Many of these contracts may not be assignable. Accordingly, in the period between the execution of the Acquisition Agreement and transfer of the operatorship, Jadestone will need to agree terms with new contractors to provide services in place of these existing contractors. This may be a costly and time-consuming task for Jadestone’s management which, if not managed successfully, or if the required number of contractors are not available, could result in a material adverse effect on the Enlarged Group’s results of operations, financial condition and prospects.
The Group’s future prospects will, in part, be dependent on effective integration of the Montara Assets into the Group
The Group’s future prospects will, in part, be dependent upon the Group’s ability to integrate the Montara Assets into the Group successfully and any other businesses that it may acquire in the future without material disruption to the existing business, including as a result of the integration of operational systems. A failure to successfully manage the integration of the Montara Assets could have a material adverse effect on the Enlarged Group’s results of operations, financial condition and prospects.
The Montara Venture FPSO is currently operating under Class Suspension
The Montara Venture FPSO is subject to continuous hull survey, which includes surveys of the cargo and ballast tanks on a five year cycle in order to maintain vessel classification. PTTEP was advised in September 2017 that its classification would be suspended due to failure to complete hull surveys in the required time. Lloyd’s Register suspended Class on the vessel on 3 January 2018. Jadestone and PTTEP have agreed a detailed work plan to return the FPSO vessel to Class. It is expected that these works will be completed, and the vessel returned to Class prior to completion of the Acquisition. However, if the Company and/or PTTEP are unable to execute the work programme for any reason, suspension of Class would be maintained. If Class remains suspended for a prolonged period of time, the Australian regulator NOPSEMA may require the production from the Montara fields to be shut-in pending reclassification of the vessel. A prolonged shut-in of the Montara fields could have a material impact on the production, reserves and financial position of the Company.
In addition, the terms of the RBL Facility are expected to include a condition precedent regarding the reinstatement of Class, which condition will need to be satisfied or waived prior to drawdown under the RBL Facility. If this condition precedent cannot be satisfied or waived, there is a risk that Jadestone may be unable to drawdown under the RBL Facility and have insufficient funding to complete the Acquisition. However, the Acquisition Agreement will not be capable of completion until PTTEP delivers certain documentation to Jadestone regarding the class reinstatement process.
The Montara incident indemnity may be insufficient or the Seller may be unable to satisfy any claims under the indemnity
The Acquisition Agreement contains an indemnity from the Seller in relation to any latent liabilities incurred or suffered by Jadestone Energy (Eagle) Pty Ltd (as buyer) as a result of the major oil and gas leakages which occurred at the Montara site in 2009 (the “Montara Incident Indemnity”). Although the Directors have grounds to believe that the Montara Incident Indemnity will be sufficient to cover any liabilities which the Group may incur in future, there is no guarantee that the Montara Incident Indemnity will be sufficient to cover all potential liabilities which may arise. In addition, there is no guarantee that PTTEP Australasia (as seller) and/or PTTEP Offshore Investment Company Limited (as seller’s guarantor) will be able to satisfy any claim which the Buyer successfully makes pursuant to the Montara Incident Indemnity.
The Acquisition and the Placing are subject to a number of conditions that may not be satisfied
The implementation of the Placing and Admission is subject to the satisfaction (or waiver, where applicable) of a number of conditions, including no event having arisen at any time prior to Admission which gives any party a right to terminate the Acquisition Agreement and there not having occurred any material adverse change in relation to the Group and certain approvals, including without limitation, FIRB and TSX-V. There is no guarantee that these (or any other) conditions of any placing agreement entered into will be satisfied (or waived, if applicable), in which case the Placing will not be completed. In addition, the Company proposes to enter into the RBL Facility to partially finance the consideration payable by the Company under the Acquisition Agreement. There are expected to be a number of conditions to drawdown under the RBL Facility and there is no guarantee that all such conditions precedent will be satisfied, or waived, in accordance with the terms of the RBL Facility. If the RBL Facility is not entered into or does not become unconditional in accordance with its terms, there is a risk that the Company will have insufficient funding to proceed to completion of the Acquisition Agreement.
There is no guarantee that these (or any other) conditions of the Acquisition Agreement will be satisfied (or waived, if applicable), in which case the Acquisition will not be completed.
If completion of the Placing and/or the Acquisition does not occur, the Company would nonetheless be obliged to pay certain costs (including due diligence and advisory fees) incurred in connection with the Placing and the Acquisition. In anticipation of the Placing and Completion, the Company will also have invested significant time and resources (including that of the Directors and senior management) and, in the meantime, may not have been able to capitalise on other transaction opportunities.
There is a risk that there may be circumstances where the Placing and Admission have completed, but certain of the remaining conditions under the Acquisition Agreement including, without limitation, receipt of the necessary regulatory approvals, are incapable of satisfaction and/or waiver. In this scenario, the proceeds of the Placing will not be able to be applied in connection with completion of the Acquisition and the Company will retain the proceeds of the Placing to apply to future acquisitions.
There can be no assurance that Jadestone will realise the anticipated benefits of the Acquisition
Jadestone may not realise the anticipated benefits from the Acquisition or may encounter difficulties in achieving the anticipated benefits. The Group is subject to all of the risks set forth in this “Risk Factors” section which may impact the Group’s ability to realise the benefits which the Directors believe will result from the Acquisition. In addition, if the future financial performance and cash flows generated by the Company are not in line with the Directors’ expectations, it may affect the financial performance of the Group. This could reduce the potential benefits arising from the Acquisition, adversely affect the market price of the Common Shares, or have a material adverse effect on the Group’s business, financial condition, operating results and prospects.
The due diligence carried out in respect of the Acquisition may not have revealed all relevant facts or uncovered significant liabilities
While the Company conducted due diligence in respect of the Montara Assets with the objective of identifying any material issues that may affect its decision to proceed with the Acquisition, there can be no assurance that all such issues have been identified. The Company also used information revealed during the due diligence process to formulate its business and operational planning. During the due diligence process, the Company is only able to rely on the information that was made available to it. Any information that was provided or obtained from available sources may not have been accurate at the time of delivery and/or remained accurate during the due diligence process and in the run-up to the Acquisition.
More broadly, there can be no assurance that the due diligence undertaken was adequate or accurate or revealed all relevant facts or uncovered all significant liabilities. If the Company considered certain material risks to be commercially acceptable, the Company may be forced to write-down or write-off assets in respect of the Group, which may have a material adverse effect on the Group’s business, financial condition or results of operations. In addition, following the Acquisition, the Company may be subject to significant, previously undisclosed liabilities in relation to the Montara Assets that were not known or identified during due diligence and which could have a material adverse effect on the Group’s business, financial condition and results of operations.
Acquisition and integration costs may be greater than anticipated
The Company expects to incur a number of costs in relation to the Acquisition, including integration and post-completion costs in order to successfully combine the operations of the Montara Assets into the Group, assuming the Acquisition completes. The actual costs of the acquisition and integration process may exceed those estimated and there may be further additional and unforeseen expenses incurred in connection with the Acquisition. In addition, the Group will incur legal, accounting, financial adviser and transaction fees and other costs relating to the Acquisition, some of which are payable whether or not the Acquisition reaches Completion. Although the Directors believe that the integration and Acquisition costs will be more than offset by the realisation of the benefits resulting from the Acquisition, this net benefit may not be achieved in the short-term or at all, particularly if the Acquisition is delayed or does not complete. These factors could materially adversely affect the business, financial conditions, results of operations and prospects of the Group.
4 RISKS RELATING TO THE COMMON SHARES
It may be difficult to realise an investment on AIM
It is intended that application will be made for the Common Shares to be admitted to trading on AIM. The AIM Rules are less demanding than those of the Official List and an investment in a security that is traded on AIM may carry a higher risk than an investment in securities listed on the Official List. The price of publicly traded securities can be highly volatile.
It may be more difficult for an investor to realise his or her investment in the Company than to realise an investment in a company whose shares or other securities are listed on the Official List or other similar stock exchange. Shares held on AIM are perceived to involve higher risks. AIM is a market designed for small and growing companies but its future success and liquidity as a market for Common Shares cannot be guaranteed.
Market price of Common Shares
The price at which Common Shares are traded and the price at which investors may realise their investment are influenced by a large number of factors, some specific to the Company and its operations and some which may affect growth companies or quoted companies generally. Admission to AIM does not imply that there will be a liquid market for Common Shares. Consequently, the price of Common Shares may be subject to fluctuation on small volumes, and Common Shares may be difficult to sell at a particular price, or at all.
A number of factors, including concerns about the effects of the use of fossil fuels on climate change and the environment generally, concerns about environmental damage relating to spills of petroleum products during transportation and concerns about indigenous rights, have affected certain investors’ sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they are no longer willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that publicly-listed oil and gas companies develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board and management of the Group. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Group or not investing in the Group at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, the Group, may result in limiting the Group’s access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares.
There is currently no UK market for the Common Shares, notwithstanding the Company’s intention to be admitted to trading on AIM
There is currently no UK market for the Common Shares. Although the Company’s current intention is that its securities should continue to trade on AIM, it cannot assure investors that it will always do so. In addition, an active UK trading market for the Common Shares may not develop or, if developed, may not be maintained. Investors may be unable to sell their Common Shares unless a market can be established and maintained, and if the Company subsequently obtains a further listing on an exchange in addition to, or in lieu of, the London Stock Exchange, the level of liquidity of the Common Shares may decline.
The Common Shares will be listed on two separate stock markets and investors seeking to take advantage of price differences between such markets may create unexpected volatility in the share price
The Common Shares are already listed and traded on the TSX-V and upon Admission will also be listed and traded on AIM. While the Common Shares are traded on both markets, price and volume levels could fluctuate significantly on either market, independent of the share price or trading volume on the other market. Investors could seek to sell or buy Common Shares to take advantage of any price differences between the two markets through a practice referred to as arbitrage. Any arbitrage activity could create unexpected volatility in both Common Share prices on either exchange and in the volumes of Common Shares available for trading on either market. In addition, holders of Common Shares in either jurisdiction will not immediately be able to transfer such shares for trading on the other market without effecting necessary procedures with the Company’s transfer agents/registrars. This could result in time delays and additional cost for Shareholders.
Jadestone has never paid a dividend nor made a distribution on any of its securities. Further, Jadestone may never achieve a level of profitability that would permit payment of dividends or making other forms of distributions to security holders. Any decision to pay dividends on the Common Shares will be made by the board of directors of Jadestone on the basis of Jadestone’s earnings, financial requirements and other conditions existing at such future time. In this regard, the Company currently intends to introduce a cash dividend as soon as reasonably practicable after the first anniversary of Completion of the Acquisition. However, this intention will be subject to the Group’s financial condition, future prospects, profits legally available for distribution, the need to maintain an appropriate level of dividend cover, distribution restrictions and financial covenants and other factors deemed by the Board to be relevant at that time, in accordance with the Articles and subject to compliance with the Act. Accordingly, there can be no guarantee that the Company will pay any dividend in future.
Issuance of debt
From time to time Jadestone may enter into transactions to acquire assets or the shares of other organisations. These transactions may be financed in whole or in part with debt, which may increase Jadestone’s debt levels above industry standards for oil and natural gas companies of similar size.
Depending on future exploration and development plans, Jadestone may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms. Jadestone’s articles does not limit the amount of indebtedness that Jadestone may incur. The level of Jadestone’s indebtedness from time to time, could impair Jadestone’s ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.
Dilution and future sales of Common Shares by the Company
Jadestone may, subject to applicable securities laws, its Articles, byelaws and stock exchange rules, issue additional Common Shares in the future which may dilute a shareholder’s holdings in the Company.
The Articles permit the issuance of an unlimited number of Common Shares and an unlimited number of Class B Shares and shareholders will have no pre-emptive rights in connection with such further issuances of either Common Shares or Class B Shares. The directors of the Company have the discretion to determine the terms of issue of further issuances of Common Shares or Class B Shares.
In addition, the terms of the Convertible Loan Facility give the lender the option to require the Company to obtain external debt finance in order to repay the Convertible Loan Facility. If such option was exercised by Tyrus, the Company may need to incur substantial further external borrowings to re-pay the Convertible Loan Facility, which could have a negative impact on the Company’s debt-to-equity ratio, credit rating and/or ability to service its other external debt. Alternatively, the lender may exercise its right to convert the Convertible Loan Facility into new common shares in the Company, which may have a significant dilutive impact on the Company’s then shareholders depending on the number and issue price of those new common shares.
Additional Common Shares will be issued by the Company on the exercise of options under the Company’s stock option plan.
Forward-looking information may prove inaccurate
Investors are cautioned not to place undue reliance on forward-looking information. By its nature, forward looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.
The Company has a controlling shareholder, the Tyrus Fund, which holds 49.57% of the current issued share capital and will be able to exercise significant influence over matters requiring shareholder approval, including the election of Directors and significant corporate transactions. This concentration of ownership may have the effect of delaying or deterring a change in control of the Company, could deprive investors of an opportunity to receive a premium for their Common Shares as part of a sale of the Company and might affect the value of the Common Shares. Upon expiry of this lock-in the Tyrus Fund may sell all or part of its holdings of Common Shares and any such sale may adversely affect the market price of the Common Shares.
The ability of Shareholders to bring actions or enforce judgements against the Company or the Directors may be limited
The ability of a Shareholder outside Canada to bring an action against the Company may be limited under law. The Company is a limited company incorporated in British Columbia. The rights of holders of Common Shares are governed by Canadian law and by the Company’s Articles. These rights differ from the rights of shareholders in typical English companies. A Shareholder outside the United Kingdom may not be able to enforce a judgement against the Company or some or all of the Directors and executive officers. Consequently, it may not be possible for a Shareholder outside Canada to effect service of process upon the Company or the Directors and executive officers within the Shareholder’s country of residence or to enforce against the Company or the Directors and executive officers within the Shareholder’s country of residence or to enforce against the Company or the Directors and executive officers’ judgements of courts of securities laws. There can be no assurance that a Shareholder will be able to enforce any judgements in civil and commercial matters or any judgements under the securities laws of countries other than Canada against the Company or the Directors or executive officers who are residents of the UK or countries other than those in which judgement is made. In addition, English or other courts may not impose civil liability on the Company or the Directors or executive officers in any original action based solely on foreign securities laws brought against the Company or the Directors in a court of competent jurisdiction in England or other countries.
Company not governed by the UK Takeover Code
The Company is incorporated in Canada, and, accordingly, transactions in Common Shares in the Company will not be subject to the UK Takeover Code. As a result, Shareholders will not be afforded the protections of the UK Takeover Code. However, Canadian laws applicable to the Company provide for early warning disclosure requirements in relation to potential takeover bids.
UNAUDITED HISTORIC FINANCIAL INFORMATION OF THE MONTARA ASSETS
|Year ended||Year ended||Year ended|
|31 December 2015||31 December 2016||31 December 2017|
|Depletion, depreciation and amortisation||(400,993)||(219,185)||(132,890)|
|Impairment of assets||(331,000)||–||–|
|Loss before tax||(482,799)||(83,601)||(19,588)|
Basis of preparation
Audited Financial Statements are not prepared at the Montara Assets or field level by PTTEP. Instead, individual field level financial information has been extracted from PTTEP Australasia’s Oracle system to form the above unaudited historical financial information table.
For the purposes of the Acquisition, an individual field level profit and loss account has been extracted from PTTEP Australasia’s Oracle systems by extracting expenditure based on legal entity and project code, inclusive of an appropriate allocation of corporate costs.
Costs for projects are broadly split into two categories being direct costs and indirect costs. Direct costs relate to those that benefit a project specifically such as drilling expenditure, geological and geophysical studies, etc. These have been allocated based on the project to which they relate.
Indirect costs are associated with work conducted to support the management and operation of projects, but that are not incurred specifically for a particular project, for example general and administration expenditure. These costs are allocated based on usage, for example man hours captured through time-writing.
The individual field profit and loss account is not subject to external audit and is not wholly prepared in accordance with International Financial and Report Standards (IFRS) given it is a ‘carve out’ from a larger reporting entity. For example, the profit and loss account has been prepared on a before-tax basis, given the significant challenges of preparing income tax calculations for a standalone part of a larger tax group.
The individual field level profit and loss account was then adjusted for known transactions that are outside the transaction perimeter. In particular, the impact of insurance recoveries and legal actions that relate to periods prior to those presented and are not being transferred with the assets have been excluded from the results.
Crude oil sales
Revenue predominately relates to the sale of crude oil produced through the Montara FPSO in each respective period. The Montara FPSO aggregates crude oil produced from three fields in the Timor Sea being Montara, Skua and Swift/Swallow.
Revenue is measured at the fair value of consideration received or receivable. Sales revenue is recognised when the risks and benefits of ownership have passed to the customer. Crude oil revenue represents revenue from crude oil liftings in the period.
Production costs relate mainly to changes to operating supplies, repairs and maintenance, consumables, and transport. They also reflect the impact of movements in inventory in the period.
Depletion, depreciation and amortisation
Oil and gas assets are depreciated to their residual value over the economically recoverable reserves within the area of interest relevant to the oil and gas assets. The units of production basis of depreciation results in a charge for the year that is proportional to the depletion of economically recoverable reserves.
Determining the economically recoverable reserves requires significant judgment about future oil prices, the likelihood of future capital expenditure as well as the geology of the area of interest. These, along with the assets’ residual value, are reviewed and adjusted if required at each reporting date.
Other operating expenses
Other operating expenses largely consist of general & administrative expenses. General & administrative expenses comprises of costs incurred for the day to day running of the business which may include staff expenses, fringe benefit tax, bank charges, audit and tax services, external consultants, subscriptions, etc. These costs are allocated to the permit/project either in total if wholly related to the project or based on an allocation methodology if a shared cost. Other operating expenses also includes the impact of write downs to spare parts inventory.
Finance costs represent the unwinding of discounting of the Montara Assets’ retirement obligations provision.
1 MATERIAL CONTRACTS
1.1 Convertible Facility
On 2 November 2016, the Tyrus Lender, an entity for which Tyrus acts as investment manager and adviser, (as lender) entered into a convertible note facility with Jadestone (as borrower) pursuant to which the Tyrus Lender agreed to advance up to US$28 million to Jadestone upon and subject to the terms and conditions of this facility. The minimum drawdown amount is US$5 million and integral multiples of US$1 million in excess thereof. The interest rate payable by Jadestone to the Tyrus Lender on each drawdown is 7.5%, with interest on overdue amounts at 12.5%. The Tyrus Lender may also request the Borrower to draw down any undrawn principal.
The Convertible Facility contains customary warranties in relation to capacity and compliance with laws. The Convertible Facility contains customary events of default in favour of the Tyrus Lender such as non-payment of any amounts due to the Tyrus Lender when due, breach of covenant, material adverse change and cross-default.
Any principal amount advanced under the Convertible Facility may be converted into Common Shares or non-voting Class B Shares in the capital of Jadestone, at the option of the Tyrus Lender, at a conversion price of C$0.50 per share, provided that such conversion will not result in the Tyrus Lender, together with entities controlled by or controlling the Tyrus Lender, acquiring 50% or more of the outstanding voting securities of Jadestone. The Convertible Facility is expected to be extended by six months to 31 March 2020. In connection with this extension, the Company will agree to use all commercially reasonable efforts to procure a listing of the bonds.
The Convertible Facility is governed by the laws of the Province of British Columbia and the laws of Canada. As of the date hereof, the Company has drawn down the Convertible Facility by a total of US$15 million.
In connection with the Convertible Facility, Jadestone granted security in favour of the Tyrus Lender over certain of its then producing assets.
1.2 Crude oil and condensate sale, purchase and marketing agreement
A crude oil and condensate sale, purchase and marketing agreement was entered into on 4 August 2009 between, on the one hand, Mitra Energy Limited (now called Jadestone Energy Limited), Mitra Energy (Indonesia Sibaru) Limited, Mitra Energy (Biliton) Pte Limited, Mitra Philippines, Mitra Energy (Vietnam Con Son) Limited (together, the “Mitra Parties”), and, on the other hand, BP Singapore Pte. Limited (“BPS”) (the “BP Crude Sale Agreement”).
Under the terms of the BP Crude Sale Agreement, each of the Mitra Parties and any other associated company of Mitra Energy Limited (within the meaning given by the BP Oil International Limited General Terms and Conditions for Sales and Purchases of Crude Oil) (an “Associated Party”) which holds (directly or indirectly) an interest in the specified oil production assets, have agreed to sell all present and future crude oil, condensate and natural gas products extracted from certain specified assets which at that time were located in Indonesia, Vietnam, Philippines and Thailand) (the “Products”) to BPS, which agreed to purchase and then lift and market the Products to prospective third party purchasers on the best prices and terms reasonably obtainable by BPS. BPS shall receive a marketing fee and an operating fee per oil barrel extracted and a marketing fee per tonne of natural gas extracted.
Under the terms of the BP Crude Sale Agreement, the qualifying present and future crude oil, condensate and natural gas products extracted from each new oil field asset purchased by any of the Mitra Parties and any Associated Party shall automatically become subject to terms of the BP Crude Sale Agreement, except in certain circumstances, including where such products are already committed to pre-existing marketing arrangements, where the relevant national oil company has participation rights (including back-in rights) which would override the application of the BP Crude Sale Agreement or in circumstances where the relevant Mitra Party or Associated Party would be obliged to supply those products to the domestic market in which the relevant asset is located. If a further oil field asset is purchased by an Associated Party, each such Associated Party is required to enter into a deed of adherence to the BP Crude Sale Agreement to bring the underlying asset within the remit of the BP Crude Sale Agreement (subject to the exceptions noted above). If an asset which is subject to the BP Crude Sale Agreement is proposed to be sold or otherwise transferred to a third party purchaser, the relevant Mitra Party is required to first disclose to that potential transferee or purchaser the terms of the BP Crude Sale Agreement and include a condition to any such asset sale or transfer transaction that the third party purchaser shall be required to enter into an agreement on the same terms as the BP Crude Sale Agreement with BPS with respect to the relevant asset.
The BP Crude Sale Agreement contains a number of provisions which are customary for arrangements of this nature, including quality control assurance mechanisms in favour of BPS such as vessel auditing and it also imposes obligations on the Mitra Parties to ensure compliance with various operational principles and regulations to ensure that the Products are suitable for sale. Each of the Mitra Parties and BPS have provided certain ongoing representations and warranties regarding matters such as their ongoing solvency and holding the necessary government approvals required to perform their respective obligations under the BP Crude Sale Agreement. The BP Crude Sale Agreement is governed by the laws of England and Wales.
Save as disclosed below, the Montara Assets are not and have not been the subject of any governmental, legal or arbitration proceedings which may have, or have had during the 12 months preceding the date of this announcement, a significant effect on the Montara Assets’ financial position or profitability and, so far as the Directors are aware, there are no such proceedings pending or threatened against the Montara Assets.
Following the Montara Incident, the Seller was subjected to various instances of attempted litigation from affected governments and other parties. In August 2010, the Government of Indonesia claimed an undefined amount of compensation from the Seller, which the Seller rejected at that time. In May 2017, the Government of Indonesia purported to formally launch action against the Seller for compensation in relation to the environmental damage caused by the Montara Incident, for an amount of circa US$1.9 billion, however it is understood that the Seller has not received any valid statement of claim or other valid documentation relating to this claim. In August 2016 a class action suit was filed against the Seller on behalf of a group of Indonesian seaweed farmers. The Seller has appointed legal counsel to defend this claim however it is understood that no formal evidence has yet been presented by the plaintiffs in this particular action.
Jadestone is acquiring certain assets only and will not assume any of these liabilities under the Acquisition Agreement. Further, Jadestone will receive the benefit of an indemnity from the Seller in connection with any environmental liabilities arising from the Montara Incident.
The following definitions apply throughout this announcement, unless the context otherwise requires:
“2C resources”means the unrisked best estimate scenario of Contingent Resources.
“2P reserves”means the sum of the Proved plus Probable Reserves, denotes the best estimate scenario of Reserves.
“Acquisition” means the acquisition by the Company, through its wholly-owned subsidiary, Jadestone Energy (Eagle) Pty Ltd of the Montara Assets on and subject to the terms and conditions of the Acquisition Agreement.
“AcquisitionAgreement” means the agreement dated 15 July 2018 between (among others) Jadestone Energy (Eagle) Pty Ltd, a wholly-owned subsidiary of the Company, (as buyer), the Company (as guarantor) and PTTEP Australasia (as seller) to give effect to the Acquisition.
“Admission” means the admission of the Common Shares, in issue and to be issued pursuant to the Placing, to trading on AIM becoming effective in accordance with the AIM Rules for Companies.
“AIM” means the market operated by the London Stock Exchange.
“AIM Rules for Companies” means the AIM Rules for Companies published by the London Stock Exchange from time to time.
“AIM Rules for Nominated Advisers” means the AIM Rules for Nominated Advisers published by the London Stock Exchange from time to time.
“API” means the American Petroleum Institute.
“Articles” means the articles of association of the Company.
“Block 05-1 PSC” means Blocks 05-1b and 05-1c.
“BMO” means BMO Capital Markets Limited.
“BPS” means BP Singapore Pte. Limited.
“Brent” means the worldwide benchmark assessment of the price of physical, light North Sea crude oil.
“CAD” or “C$” means Canadian Dollars, the lawful currency of Canada.
“Class B Share” means a non-voting Class B Share of Jadestone.
“Common Shares” means Common Shares of no par value each in the share capital of the Company.
“Company” or “Jadestone” means Jadestone Energy Inc., a company incorporated in Canada under the Companies Act (British Columbia).
“Convertible Facility” means the convertible note facility dated 2 November 2016 between Tyrus Capital Event S.à r.l, an entity controlled by Tyrus, (as lender) and Jadestone (as borrower).
“CPR” means the competent persons report prepared in accordance with the AIM Rules for Companies by ERCE dated 15 July 2018.
“Daily Dated Brent” means the physical cargoes of crude oil loading in the North Sea on any given day.
“Dated Brent” means physical cargoes of crude oil loading in the North Sea that have been assigned specific delivery dates.
“Directors” or “Board” means the current directors of the Company.
“DOE” means the Department of Energy of the Philippines.
“EnlargedGroup” means the Group as enlarged following completion of the Acquisition.
“EP” means environmental plan.
“ERCE” means ERC Equipoise Pte Ltd.
“ESP” means electric submersible pumps.
“FCA” means the Financial Conduct Authority of the UK.
“FCPA” means U.S. Foreign Corrupt Practices Act of 1977.
“FIRB” means the Australian Foreign Investment Review Board.
“FPSO” means the Montara Venture Floating Production Storage and Offloading facility.
“FSMA” means Financial Services and Markets Act 2000.“Group” means the Company and its subsidiary undertakings from time to time.
“HSSE Committee” means Health, Safety, Social and Environmental Committee.
“IFRS” means International Financial Reporting Standards as endorsed by the European Union.
“Joint Bookrunners” means BMO and Stifel.
“London Stock Exchange” means London Stock Exchange plc.
“MBC” means marine breakaway coupling.
“MIGAS” means the Directorate General of Oil and Gas, in Indonesia.
“Mitra Philippines” means Mitra Energy (Philippines SC-56) Ltd.
“MontaraAssets” means Production Licences AC/L7 and AC/L8 in the Timor Sea and the centralised FPSO the Montara Venture.
“Montara Incident” means the oil and gas leak which occurred in 2009 at the site of the Montara Assets.
“NOPSEMA” means the National Offshore Petroleum Safety and Environmental Management Authority of the Commonwealth of Australia.
“NOPTA” means the National Offshore Petroleum Titles Administrator of the Commonwealth of Australia.
“Official List” means the Official List of the UK Listing Authority.
“OPEC” means the Organisation of the Petroleum Exporting Countries.
“OPGGS Act” means the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth).
“Option” means a common share purchase option.
“OTSA” means the operator and transitional services agreement to be entered into between Jadestone Energy (Eagle) Pty Ltd and PTTEP Australasia in relation to the operation and management of the Montara Assets and the provision of transitional services in the period from completion of the Acquisition Agreement.
“Pertamina” means PT Pertamina Hulu Energi Ogan Komering.
“PetroVietnam” means PetroVietnam Petroleum Corp.
“Placing” means the conditional placing to be conducted by the Joint Bookrunners on behalf of the Company.
“Placing Agreement” Placing Agreement means the agreement to be entered into between (1) the Company (2) the Directors and (3) the Joint Bookrunners, relating to the Placing.
“PNOC” means Philippine National Oil Company.
“PSC” means production sharing contract.
“PTTEP” means PTT Exploration and Production Public Company Limited.
“PTTEP Australasia” means PTTEP Australasia (Ashmore Cartier) Pty Ltd.
“PVEP” means PetroVietnam Exploration Production Corporation.
“SC-56” means service contract 56 in the Philippines.
“SC-57” means service contract 57 in the Philippines.
“Shareholders” means holders of Common Shares.
“SKKMIGAS” means the Special Taskforce for Upstream Oil and Gas Business Activities, the established executive implementing body responsible for conducting supervision of upstream business activities in Indonesia.
“SPA” means the sale and purchase agreement dated 9 August 2016 entered into between the Company and Teikoku for the acquisition of a 30% non-operated working interest in the Block 05-1 PSC.
“Stifel” means Stifel Nicolaus Europe Limited.
“Stock Option Plan” means the Company’s stock option plan which was adopted by the Board on 19 August 2015 and which was approved by the shareholders of the Company on 25 September 2015.
“subsidiary undertakings” means as defined in section 1162 of the 2006 Act.
“Talisman” means Talisman Energy Inc.
“Teikoku” means Teikoku Oil (Con Son) Co., Ltd, a wholly-owned subsidiary of Inpex Corporation.
“Total” means Total E&P Philippines B.V.
“TSX-V” means the TSX Venture Exchange.
“Tyrus” means Tyrus Capital S.A.M.
“Tyrus Fund” means Tyrus Capital Event Master Fund Limited, a fund that is managed by Tyrus.
“TyrusLender” means Tyrus Capital Event S.à r.l., a Société à responsabilité limitée incorporated under the laws of Luxembourg.
“UK” or “United Kingdom” means the United Kingdom of Great Britain and Northern Ireland.
“UK Listing Authority” means the FCA acting in its capacity as the competent authority for the purposes of Part VI of the FSMA.
“UK Takeover Code” means the City Code on Takeovers and Mergers published by the Panel on Takeovers and Mergers (as amended from time to time)
“US” or “USA” or “United States” means the United States of America, its territories and possessions, any state or political sub-division of the United States of America, the District of Columbia and all other areas subject to the jurisdiction of the United States of America.
“US$” or “USD” means United States Dollars, the lawful currency of the United States.
“WOMP” means well operations management plan.
“£” and “p” means respectively pounds and pence sterling, the lawful currency of the UK.
All references to legislation in this announcement are to the legislation of England and Wales unless the contrary is indicated. Any reference to any provision of any legislation shall include any amendment, modification, re-enactment or extension thereof.
Words importing the singular shall include the plural and vice versa, and words importing the masculine gender shall include the feminine or neutral gender.
GLOSSARY OF TERMS
The following glossary of terms applies throughout this announcement, unless the context otherwise requires:
|bbl||barrel of crude oil|
|bbl/d||barrels of crude oil per day|
|boe||barrels of oil equivalent|
|boe/d||barrels of oil equivalent per day|
|Bscf||billion standard cubic feet|
|FPSO||floating production and storage offloading unit|
|mbbl||thousand barrels of crude oil|
|mbbls/d||thousand barrels of crude oil per day|
|MMbbls||million barrels of crude oil|
|MMbbls/d||million barrels of crude oil per day|
|mboe||thousand barrels of oil equivalent|
|mboe/d||thousand barrels of oil equivalent per day|
|MMboe||million barrels of oil equivalent|
|MMbtu||million British Thermal Units|
|mMD||measured depth in metres|
|MMscf||million standard cubic feet|
|MMscf/d||million standard cubic feet per day|
|PSC||production sharing contract|
|scf||standard cubic feet|
Members of the public are not eligible to take part in the Placing. This announcement (including the Appendix) is for information purposes only and is not intended to and does not constitute, or form part of, any offer or invitation to purchase, subscribe for or otherwise acquire or dispose of, or any solicitation to purchase or subscribe for or otherwise acquire or dispose of, any securities in the United States, Australia, Canada, Japan, South Africa or any other jurisdiction in which such an offer or solicitation may lead to a breach of any applicable legal or regulatory requirements. Persons needing advice should consult with an independent financial adviser authorised under the Financial Services and Markets Act 2000, as amended (FSMA), who specialises in advising on the acquisition of shares and other securities, if that person is in the United Kingdom, or any appropriately authorised person under applicable laws, if that person is located in any other jurisdiction. The information contained in this announcement is not for release, publication or distribution to persons in any jurisdiction where to do so might constitute a violation of local securities laws or regulations.
This announcement has been issued by and is the sole responsibility of the Company. The information contained in this announcement is for background purposes only and does not purport to be full or complete. The information in this announcement is subject to change without notice.
This announcement is directed only at: (a) persons in member states of the European Economic Area (the EEA) who are “qualified investors” within the meaning of Article 2(1)(e) of the Prospectus Directive (Directive 2003/71/EC, as amended by the 2010 PD Amending Directive (Directive 2010/73/EU)and including any relevant implementing directive measure in any member state of the EEA to the extent implemented in the relevant member state (the Prospectus Directive) (Qualified Investors); (b) persons in the United Kingdom who are Qualified Investors and who (i) have professional experience in matters relating to investments and who fall within the definition of “investment professionals” in Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the Order); (ii) who are high net worth companies, unincorporated associations and other persons to whom it may lawfully be communicated in accordance with Article 49(2)(a) to (d) of the Order; or (iii) other persons to whom it may lawfully be communicated (all such persons together being referred to as Relevant Persons). Any investment activity in connection with this announcement and the Placing is only available to, and will only be engaged with, Relevant Persons. Any person who is not a Relevant Person should not act or rely on this announcement or any of its contents.
This “Important Notice” section does not itself constitute an offer for sale or subscription of any securities in the Company.
The distribution of this announcement and the proposed Placing Shares as referred to in this announcement in certain jurisdictions may be restricted by law. No action has been taken by the Company, Stifel Nicolaus Europe Limited or BMO Capital Markets Limited that would permit an offering of such shares or possession or distribution of this announcement or any other offering or publicity material relating to such shares in any jurisdiction where action for that purpose is required, other than the United Kingdom. Persons into whose possession this announcement comes are required by the Company, Stifel Nicolaus Europe Limited and BMO Capital Markets Limited to inform themselves about, and to observe, such restrictions.
No undertaking, representation or warranty or other assurance express or implied, is or will be made as to, or in relation to, and, aside from the responsibilities and liabilities, if any, which may be imposed by FSMA or the regulatory regime established thereunder or any other applicable regulatory regime, no responsibility or liability is or will be accepted by the Company, Stifel Nicolaus Europe Limited or BMO Capital Markets Limited or any of their respective parent or subsidiary undertakings or the subsidiary undertakings of any such parent undertakings or any of their respective directors, proposed directors, officers, partners or employees or any other person as to or in relation to, the accuracy, completeness, sufficiency or fairness of the information or opinions contained in announcement or any other written or oral information made available to or publicly available to any interested party or its advisers in connection with the Placing, and any responsibility or liability therefore is expressly disclaimed. In addition, no duty of care or otherwise is owed by any such person to recipients of this document or any other person in relation to this announcement.
The Placing Shares to be issued or sold pursuant to the Placing will not be admitted to trading on any stock exchange other than the AIM Market of the London Stock Exchange and the TSXV.
Neither the content of the Company’s website nor any website accessible by hyperlinks on the Company’s website is incorporated in, or forms part of, this announcement.
Any forwarding, distribution, reproduction, or disclosure of any information contained in this announcement in whole or in part is unauthorised. Failure to comply with these restrictions may constitute a violation of the United States Securities Act of 1933 (as amended) (the “US Securities Act”) or the applicable laws of other jurisdictions. Subject to certain exceptions, the securities referred to in this announcement may not be offered or sold in the United States, Australia, Canada, Japan, South Africa or certain other jurisdictions or for the account or benefit of any national resident or citizen of certain jurisdictions. The securities referred to in this announcement have not and will not be registered under the US Securities Act, and may not be offered or sold in the United States absent registration or an exemption from, or a transaction not subject to, registration under the US Securities Act. There will be no public offering of the securities in the United States. Any failure to comply with these restrictions may constitute a violation of the securities law of any such jurisdictions. No prospectus will be made available in connection with the matters contained in this announcement and no such prospectus is required (in accordance with the Prospectus Directive) to be published. No undertaking, representation or warranty or other assurance express or implied, is or will be made as to, or in relation to, and, aside from the responsibilities and liabilities, if any, which may be imposed by FSMA or the regulatory regime established thereunder or any other applicable regulatory regime, no responsibility or liability is or will be accepted by Company, Stifel Nicolaus Europe Limited or BMO Capital Markets Limited or any of their respective parent or subsidiary undertakings or the subsidiary undertakings of any such parent undertakings or any of their respective directors, proposed directors, officers, partners or employees or any other person as to or in relation to, the accuracy, completeness, sufficiency or fairness of the information or opinions contained in this announcement or any other written or oral information made available to or publicly available to any interested party or its advisers in connection with the Acquisition, and any responsibility or liability therefore is expressly disclaimed. In addition, no duty of care or otherwise is owed by any such person to recipients of this announcement or any other person in relation to this announcement.
Stifel Nicolaus Europe Limited (“Stifel”) is authorised by the Financial Conduct Authority and regulated by the Financial Conduct Authority in the United Kingdom. Stifel is acting as nominated adviser and joint bookrunner exclusively for the Company and no one else in connection with the matters set out in this announcement and will not regard any other person as its client in relation to the matters in this announcement and will not be responsible to anyone other than the Company for providing the protections afforded to clients of Stifel or its affiliates, or for providing advice in relation to any matter referred to herein.
BMO Capital Markets Limited (“BMO”), is authorised and regulated in the United Kingdom by the Financial Conduct Authority. BMO is acting as joint bookrunner exclusively for the Company and no one else in connection with the matters set out in this announcement and will not regard any other person as its client in relation to the matters in this announcement and will not be responsible to anyone other than the Company for providing the protections afforded to clients of BMO or its affiliates, or for providing advice in relation to any matter referred to herein.
A barrel of oil equivalent (“boe”) is determined by converting a volume of natural gas to barrels using the ratios of six thousand cubic feet (“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. 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.
Certain statements in this press release are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, as well as other applicable international securities laws. The forward-looking statements contained in this press release are forward-looking and not historical facts.
Some of the forward-looking statements may be identified by statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “guidance”, “objective”, “projection”, “aim”, “goals”, “target”, “schedules”, and “outlook”).
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to the Company. The forward-looking information contained in this news release speaks only as of the date hereof. The Company does not assume any obligation to publicly update the information, except as may be required pursuant to applicable laws.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.