How many licences does Bahamas Petroleum Company have? And, does Bahamas Petroleum Company have any pending applications?
Bahamas Petroleum Company currently owns 100% equity in five exploration licences, Bain, Cooper, Donaldson and Eneas in Southern Bahamas and Miami in Northern Bahamas. Bahamas Petroleum Company has made three, 100% equity applications named Zapata, Islamorada and Andros.
How did the existing licences and the pending applications get their names?
Upon making the licences application, Bahamas Petroleum Company was required to define the applied for area of blocks and to give that area a name; the Government then decides when awarding the licences whether they accept the proposed name(s) or whether they wish for the Company to change them. After the Government confirms and accepts the names they are typed into the actual licence agreement along with all other fiscal terms and obligations.
Is there any significance to the names of the licences and applications?
The names of the licences and applications hold no significance. The names of the four Southern licences run alphabetically and reflect ‘traditional’ Bahamian family names rather than pertaining to any particular person, or persons related to the oil industry or Bahamas Petroleum Company.
What are the main components of the Maritime Agreement and how does it affect Bahamas Petroleum Company?
The agreement delimiting the maritime boundaries of The Bahamas and Cuba was signed on 3 October, 2011, by the Deputy Prime Minister and Minister of Foreign Affairs Brent Symonette. This agreement defines the dividing line between the two countries and the limits of territorial waters. Further, it defines the exclusive economic zones and continental shelves between the two nations which then also allows for cooperation in the management of living and non-living marine resources in the area. The agreement delivers on the Government assurances to protect not only the Bahamian borders but also the extent of the granted exploration licences. This affords Bahamas Petroleum Company certainty as it relates to the limits and extent of its currently held exploration licences.
What are the Act(s) governing petroleum activities in The Bahamas? What do they allow?
Bahamas Petroleum Company four southern licences, namely, Bain, Cooper Donaldson and Eneas, remains to be governed by The Petroleum Act (‘the Act’) 1971 Chp 219 and the Petroleum Regulations 1978 Chp 219.The Petroleum Act (‘the Act’) 1971 Chp 219, governs Petroleum exploration, making provisions for the granting of Permits, Licences and Leases. Additionally, the Act covers the level of Royalties and granting of all rights required by a licensee or lessee in order that petroleum may be searched for, bored for, gotten, stored, treated, converted, or carried away. The Act is further refined by the Petroleum Regulations 1978 Chp 219; which goes beyond simply defining the term of the licence to actually detailing the procedures and obligations for the licence and/or lease. For instance, where the Act speaks only to Petroleum exploration; the Regulations specifically deal with the Term and Renewal of Licences, Expenditure and Pooling of Expenditure as well as Abandonment, Completion and Suspension of wells; etc.
In 2016, that Bahamas Government recently introduced four new pieces of legislation to modernize and regulate the Petroleum Industry in the Bahamas.The Petroleum Act 2016, the Petroleum Regulations 2016, the Petroleum (Health and Safety) Regulations 2016 and the Petroleum (Environmental Protection and Pollution Control) Regulation 2016 were all passed by Parliament and became law. Though the Company four southern licences have been grandfathered to the old Petroleum Legislation; Bahamas Petroleum Company exploration project and operations will not be disadvantaged. The Company has been advised that where the provisions of the old legislation are disadvantages or silent on matters of importance to the project development and success, the Minister will rely on the updated provisions of the Petroleum Act 2016 and the Petroleum Regulations 2016.
Additionally, the new regulations that will govern exploration of Petroleum in the Bahamas are the Petroleum (Health and Safety) Regulations 2016 and the Petroleum (Offshore Environmental Protection and Pollution Control) Regulations 2016. The H&S Regulations address matters of health and safety in the operation of facilities for petroleum exploration and extraction in The Bahamas. The H&S Regulations also address different health and safety requirements and reflects best international standards and practice for the safe operations of petroleum facilities. Further, the OEPPC Regulations provides rules for offshore installations related to the monitoring and prevention of pollution and or damage to the marine environment, the Bahamas and surrounding areas.
When were the current Licences awarded? And, what are the key terms and obligations?
Bahamas Petroleum Company was awarded five licences in 26 April 2007 for a twelve (12) year term, though the currency of the licence has to be renewed every 3 years – consistent with the Act and Regulations. A 2-year extension was granted to the first 3-year period in March 2008 after Bahamas Petroleum Company was requested to hold operations until The Bahamas/Cuba Delimitation agreement was assigned. Bahamas Petroleum Company accordingly deferred commencing seismic surveys in the awarded areas, with the first 2D survey not commencing until June 2010 and the 3D a year later in July 2011. Thus the renewal of the first ‘3’ year term was extended until 26 April 2012. Subsequently, the Government provided formal renewal of the Company’s four southern licences on 8 June 2015 with a further 12 month extension being provided on 17 March 2017. These extensions were intended to reflect the delays imposed on the Company whilst the Government updated its Oil & Gas regulations, which came into force in July 2016.
The key obligation of the four southern licences is for the commencement of a single exploration well within this licence area by April 2018. Additionally, the Company is required to pay annual rental fees for each licence block of $250,000 as well as submit annual reports on the activity and expenditure that has taken place in the licences.
There are certain reporting requirements for annual submission, such as a Plan Report showing annual expenditure for each licence; an amount which the Company has exceeded by a considerable amount.
What do you mean by 'we are ready technically' to drill?
Our licences were awarded in 2007, since that time we have worked diligently to collect all available historic geological and geophysical data and where possible re-examine using modern technologies and interpretative techniques. At today’s prices the data would have cost millions of dollars to acquire. This information, especially that from the previously drilled wells, afforded us sufficient excitement and encouragement to go ahead and invest in the acquisition of new information, particularly seismic data to better understand the detail of the petroleum systems and ultimate scale potential of our licences.
Subsequently, all of the new data we have collected and interpreted confirms The Bahamas has ‘World Class’ petroleum potential, with multiple, very large traps identified. Well data confirms the reservoir potential; seismic and well information provide encouragement for sealing intervals; and, the regional geology provides evidence of the likelihood of rich source rocks in the Upper Jurassic. The geological and geophysical (G&G) studies have been completed and from a G&G standpoint we are ready to drill. With the acquisition of the recent 3D seismic survey we also have all the data necessary to be able to design a well with the best chance of success and optimised from a safety perspective.
What work remains to be done?
Much work needs to be done before we spud our first well. The Government has now put new regulations in place to oversee oil and gas activity which reflect global industry best practice. We have completed and submitted an Environmental Impact Assessment (EIA) to the Authorities.
We have completed extensive oil spill modelling to understand where we need to be ready to intercede in the unlikely event of an incident. We have completed our worst case discharge calculation and a drilling hazard study of our acquired multibeam data.
We have completed our oil spill response plan and our Environmental Management Plan (EMP) is substantially complete, we are a member of The Oil Spill Response Group, an association that can provide additional ‘clean-up’ equipment should it be necessary and plan to ensure close co-operation with the Cuban authorities in the near future to evaluate how emergency response capabilities can best be integrated. Our well planning and design has been completed, having re-engineered the well design provided by ADTI in their FEED study to incorporate additional learnings from recent technical studies, reduce the overall cost of delivery and ensure compliance with the recently revised Petroleum Regulations.
Has the 3D materially changed the conclusions reached by the Ryder Scott 'Competent Persons Report'?
It is our opinion that the 3D has enhanced the original 2D generated conclusions. However, there are some changes to our interpretation and perception of risk. Ryder Scott estimated the risked potential to be greater than 1 billion barrels from the Aptian through Top Cretaceous section, with an average risk of about 1 in 4 from three gross reservoir intervals on each of four structures. Three of the structures were each assessed to have unrisked potential in excess of 1 billion barrels of oil. Ryder Scott did not assess the potential in the younger Tertiary section nor the pre-Aptian and Jurassic section. The 3D confirms the overall integrity and size of the mapped structures. On the 3D the mapped structures at Albian and Aptian levels beneath the thrust trend closest to Cuba (designated ‘Thrust A, Fold A’ in the CPR – see page 15) appear to be velocity artefacts of the Cretaceous carbonate platform. If confirmed by completion of the 3D interpretation this would likely impact potential estimated by Ryder Scott at this location, however, we believe this is more than compensated for by modifications to the overall risking as well as the pre-Aptian section in the next thrusted structure (designated ‘Fold B’) as well as the broad Jurassic closure beneath the thrust. More importantly the 3D now shows the section below ‘Trend A’ to be dipping uniformly to the south west and providing an uninterrupted oil migration pathway from the Cuban foredeep source location.
Your licences have a variety of play types, what is your current thinking on the first well?
There are a variety of play types on our acreage; reef margin plays similar to Golden Lane in Mexico, fore reef debris and breccia plays similar to the Canterell complex, very large foreland basin structures comparable in geology and size to many fields in the Middle East and possible deeper rift basin structures.
We believe the best location for our initial well will be to test ‘Fold B’ into the upper Jurassic. The CPR indicates this feature has the potential for over 2 billion barrels of oil in the Cretaceous section alone. We will plan our initial well to a depth of approximately 22,500 feet which will take it through the thrusted anticline across the thrust fault into a broad structure in the Upper Jurassic. We believe this well will test the largest potential volumes, multiple reservoir sections and will provide definitive information on the anticipated Jurassic source. Based on previous work we anticipate the well will take about 120 days and will likely be drilled with a semisubmersible rig in water depth of about 1500 feet.
It's pretty far down the road but have you thought about development options?
There is still significant geologic risk – the chance that we will drill a dry hole, but if we are successful the final development plan would depend on the type of hydrocarbon found (oil or gas), oil gravity and wax content, and ultimately the absolute volume of hydrocarbons found. At present a phased development using subsea well heads and an FPSO would seem to be the most efficient way of ensuring early production, minimum environmental impact and providing both direct and indirect employment.
What is an Environmental Impact Assessment?
An Environmental Impact Assessment (EIA) is a systematic process to identify the baseline conditions in a project and surrounding area before it commences, predicts and evaluates the potential environmental impacts, whether positive or negative, of the proposed project actions, in order to aid decision making regarding the significant environmental consequences of the project.
What is an Environmental Management Plan?
An Environmental Management Plan (EMP) is a site specific plan outlining agreed performance criteria and all measures that are necessary in order to minimise and mitigate potential impacts to the environment while complying with all aspects of environmental legislation. It defines respective roles and responsibilities and identifies appropriate emergency preparedness and responses. The EMP serves as a measuring tool for the government to assess the environmental performance of the project.
What is an Oil Spill Contingency Plan?
An Oil Spill Contingency Plan (OSCP) is a roadmap that outlines the steps that should be taken before, during and after an accidental oil spill to control, contain and clean up the spill from the environment. The OSCP will describe the regional shoreline sensitivities, the local and international support infrastructure such as ports and airports, oil spill risk scenarios and oil spill trajectory modelling, available oil response equipment in the project and surrounding project areas (on-board and onshore), notification procedures, communications systems and the organisational structure. Obviously it is the desire and intention of all parties involved NOT to have a spill of any kind and to ensure containment is assured throughout the project, but it is an obligation for all those involved to ensure an appropriate response should there be an incident – no matter how small or apparently insignificant.
What is the difference between a blow out and a kick?
A kick is the entry of formation fluid (i.e. salt water, gas, oil or a mixture) into the well bore while drilling normally controlled by the fluid systems and equipment utilised. A blow out is when the formation fluid from a kick overpowers employed systems and equipment, resulting in surges in well bore pressure. The outcome of which means more fluids will be flowing out from the well than is being pumped into the well to overcome the pressures. At this time normal emergency procedures cut in and protection equipment is deployed.
What is a Blowout Preventer?
A Blowout Preventer (BOP) is a large, specialised valve used to control excessive wellbore pressures by either closing over an open wellbore, sealing around drill pipe and drilling string in the well or by more dramatically using steel shearing surfaces (rams) to cut through drill pipe in order to seal the wellbore. This control equipment has normally multiple fail-safe systems with two rams each operated electrically and hydraulically. More recently double BOP systems have been deployed which effectively has two BOP’s sitting above the well bore.
What are the functions of a drilling fluid?
There are multiple functions of a drilling fluid, more commonly known as mud, but most importantly it is there to: lubricate, cool and clean the drill bit; circulate cuttings out of the wellbore for identification and analysis; and, control pressures and prevent the uncontrolled inflow of formation fluids.
What type of drilling fluids will be used for the project?
The Company intends to use water (i.e. seawater) as the basis for its drilling fluids. In certain operating situations there are options to use synthetic-based drilling fluids, but currently there are no plans to use synthetic drilling fluids. If, due to technical or safety reasons its use becomes unavoidable; a strict policy of ‘total containment’ will apply for the duration of its use across the whole rig. Synthetic drilling fluids and all mud will be contained and shipped to shore to certified facilities for recycling by the vendor. It should be noted that oil-based fluids will not be used for drilling at any time. Notwithstanding these restrictions, all chemicals used during any operations will be selected on the basis that they are ‘environmentally friendly’ and low toxicity selected using the internationally recognised OSPAR classification for chemicals (OSPAR Oslo/Paris commissions emerged following a growing general awareness of the potential dangers of pollution following a number of serious oil tanker incidents.) Thus, all containers will be classified using a green and yellow designation to be tracked and accounted for. No chemicals designated as red and black under this system are intended to be used throughout the whole operation.
How would one determine what exists on the seabed near the drill site and prior to any drilling?
A high resolution sea bottom survey using Multibeam and 3D seismic techniques has been used to capture the natural and man-made sea bottom features within a wide project area. Such a survey allows the Company to determine the accurate presence of the following:
- seabed topography and relief
- sea grass beds
- communication cables
- cold water corals
- gas vents and natural oil seeps
- archaeological features
- benthic communities
- fishing spawning grounds
This work has been translated into an environmental sensitivity map to be used throughout the project to direct activity. Once a drill rig is on site, further verification and a detailed visual inspection will take place using a Remote Operated Vehicle (ROV).
How do I sell my shares?
Capita IRG Trustees offers a share dealing service which can be accessed online. For further information please visit www.capitadeal.com or telephone 0871 664 0446 (calls cost 10p per minute plus network extras. Lines are open 8am – 4.30pm, Monday – Friday , excluding public holidays).
Alternatively, contact your bank or stock broker who will also be able to assist you in selling your shares.
Share dealings and Movements. How do I place/remove a STOP on my holding?
Please contact the Registrar as soon as possible to discuss your query.
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I have lost my share certificate, how can I get a replacement?
If you have lost your share certificate please get in touch by calling the shareholder helpline to tell us the certificate is missing. If your certificate has been stolen we will need a crime reference number issued by the police. We will then issue you with a letter of indemnity to replace the missing certificate.
Depending on the value of the shares there may be an administration charge and cover may be needed to support the indemnity. We can provide cover for ourselves in which case the total fee will increase based on the current share price. If you prefer you can make your own arrangements to have the indemnity form guaranteed by a suitably authorised bank, insurance company or guarantee society.
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Once you return the letter of indemnity to us, it will be processed and the replacement share certificate(s) will be sent to you within ten working days.
If you need the share certificate(s) more quickly, we offer an express service for an extra fee. The replacement share certificate(s) will then be sent to you within two working days. When calling us please ask our Information Consultant about this service.
When we receive the letter of indemnity, we may need to carry out satisfactory security and anti-fraud checks.
What is the Annual General Meeting?
An AGM consists of routine matters, such as the election of directors, approval of reports and accounts which are put to the vote of shareholders.
Company directors can take this opportunity to put forward other matters requiring the agreement of shareholders such as setting the limits on the number of shares that can be issued in the following year.
Company Meetings. Do I have to vote?
It is not compulsory to vote, although voting does provide you with a voice to support change as a stakeholder in the company.
Company Meetings. How can I vote if I am the executor of a deceased holder?
Unfortunately, a person becoming entitled (e.g. Executor, beneficiaries etc) to shares in consequence of the death or bankruptcy of a shareholder are not entitled to the right to vote until the shares have been transferred and the beneficiaries are registered shareholders.
How can I locate up to date information relating to a company event?
Please check our Financial Calendar for the most recent information.
How can I obtain current and historical share prices of Bahamas Petroleum Company plc?
How do I notify you of a deceased shareholder?
The Registrar will require sight of an original or official copy of the Death Certificate, or a sealed or certified Grant of Representation.
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