How many licences does Bahamas Petroleum Company have? And, does Bahamas Petroleum Company have any pending applications?
The Company’s business currently is focused on five licences for hydrocarbon exploration covering approximately 16,000 km2 (4 million acres). The Company has four exploration licences in the southern territorial waters of The Bahamas, referred to as Bain, Cooper, Donaldson, Eneas (these four licences together referred to as the “Southern Licences”) and a fifth, the Miami licence, in the northern territorial waters of The Bahamas. The main licences of interest and focus are the Southern Licences. 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?
All licences are held through wholly-owned subsidiaries of the Company, and were awarded on 26 April 2007 for an initial exploration period of three years, with up to three further exploration periods possible, subject to renewal elections, nominally every three years. Subsequently, the Company received a number of extensions of the initial three-year exploration term of each of the Southern Licences, such that the second exploration term for the Southern Licences commenced on the 8 June 2015.
On entering this second term for the Southern Licences, the Company was obliged to commence activity by April 2018 on an initial exploration well, with equipment capable of drilling to a depth of at least 18,000 feet (the “Drilling Plan”). This date was extended by agreement with the Government on various occasions, most recently in February of 2019, where the second term licence period was extended such that currently the Company’s work obligation is clear and unambiguous: to commence an initial exploration well on the Southern Licences by the end of 2020.
The Southern Licences are commercially co-joined, meaning that the drilling of an initial exploration well on one of the Southern Licences will satisfy the work obligation in respect of all of the Southern Licences. Everything we are doing as a Company, is in the single-minded pursuit of this goal: drilling an initial exploration well in the Southern Licences, in a safe and responsible manner, within the timeframe that is consistent with our obligations under the licences.
At the conclusion of the second term for the Southern Licences, the licences may be extended for two further exploration periods of up to three years each on approval of the Government (which, if BPC has met its licence obligations, may not be unreasonably withheld). At the time of extension, BPC will be required to relinquish 50% of the Southern Licence area, which obligation BPC considers may be satisfied almost entirely by relinquishment of areas in shallower waters over the Grand Bahamas Bank, which are of lesser technical interest to BPC.
On entry into a third exploration period, the minimum work obligation will be to commence the drilling of a new exploration well, essentially every two years, following the completion of the initial exploration well. At any time during this period the Company may apply for a production lease in respect of all or part of the area covered by the Southern Licences subject to submission and agreement of a development plan. As with the exploration period extensions, if BPC has met its licence obligations the grant of a production lease cannot be unreasonably withheld. Any such production lease would give the Company the right to produce petroleum from that production area for a term of 30 years (and with a renewal right on application thereafter).
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.
To enable the Company to commence drilling activity in a timely manner during 2020, as required by the licence obligations on the Southern Licences, a number of critical tasks must be addressed in advance. These include completion of detailed well planning and design work, securing access to a rig and provision of required integrated well services, procurement of long-lead time items, finalising the logistical plan along with associated supply base location and set-up, finalising pricing for other critical equipment and services, and completion of all necessary permitting processes. Many of these tasks cannot be adequately completed without first knowing the specifications of the specific rig and equipment that will be used to undertake the work, and having full access to rig specific and site specific information.
To this end, the Company has reached agreement (subject to contract) with a number of leading global equipment and service providers, fundamental to the delivery of a successful exploration well on time and within a prescribed budget. Central to that delivery is access to a suitable rig within the necessary timeframe, along with associated drilling equipment and supplies (including, for example, a bottom-hole assembly and drilling and logging services). In summary, these agreements are:
- Rig Provider: The Company has entered into a Framework Agreement with Seadrill, one of the world’s largest offshore drill rig companies, which will see the provision of a sixth-generation drilling rig during the first half of 2020, with delivery from the rig’s current working location in the nearby Gulf of Mexico. The Framework Agreement provides clarity and certainty around potential access to a suitable rig, in the timeframe required, and fixes the price for the rig (in accordance with industry practice, quoted as a day-rate in US dollars per day). Critically, with the benefit of the Framework Agreement in place, BPC (along with Seadrill’s input and support) is now able to move towards finalising detailed logistical and design work, ensure compatible equipment and supplies are available and scheduled, and to complete the associated permitting processes in good time for an orderly commencement of drilling. The Company has notified Seadrill of its desire to secure a rig for delivery by late Q1 2020. Over the coming weeks the Company and Seadrill will be working to finalize the Rig Contract, confirm the rig selection, and agree the critical drilling plan dates. It should be noted that the governing document in relation to provision of the drill rig will be the Rig Contract, which remains to be entered into and is subject to Seadrill’s Board approval process for contract commitment.
- Integrated Well Service Provider: At the same time, and following a process of extensive discussion and mutual due diligence, the Company has been able to secure the services (and agree prices for those services) of an integrated well services provider, Halliburton, a leading provider of integrated well services to the global oil and gas industry. Under this appointment, Halliburton will provide a range of essential well equipment, tools and services for the Drilling Plan. The Company has also appointed BakerHughes GE, another leading international service provider to the oil industry, as provider for wellheads and tubulars. The involvement of Halliburton and BakerHughes GE at a sufficiently early stage also allows for their participation in final well design, so as to further assure successful achievement of the objectives for the drilling of the well. The Company issued a Notice of Award to each of Halliburton and BakerHughes GE as part of this process, which notices were accepted, as a precursor to the parties concluding the necessary long-form documentation. Given the greater certainty and progress made in relation to funding, the Company has commenced the process of finalisation and entry into such long form documentation (“Call Off Contracts”), containing terms and conditions customary in the industry, whilst including the technical specifications and pricing already established in the Notices of Award. Now, following a further period of negotiation and collaborative work, BPC has entered into a Master Services Agreement (“MSA”) with BakerHughes GE for the provision of specified equipment. Further, and pursuant to the MSA entered into, BPC has now also placed a first purchase order with BakerHughes GE, for a wellhead set, a contingency well head set, and 36” conductor casing. The wellhead set is being manufactured to order for BPC’s intended well, and delivery is expected in a timeframe consistent with the current drilling schedule.
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.
As a result of this and earlier work BPC determined that the Southern Licences contained considerable oil potential, and in 2017 the Company engaged Moyes & Co, an international petroleum industry consultancy, as external technical experts to conduct an independent audit of BPC’s own assessment of the total petroleum system and prospect portfolio utilising the full range of the Company’s exhaustive database. The key findings were as follows:
- Stock Tank Oil Initially In Place (“STOIIP”) assessed for the prospect structures as 8.4 billion barrels, with an upside of up to 28 billion barrels;
- Applying a recovery factor in the range of 20% – 40% to the Moyes STOIIP volumetrics would result in an unrisked Estimated Ultimate Recoverable (“EUR”) in the range of 1.6 billion to 3.3 billion barrels (mean), and up to 11 billion barrels (upside); and,
- Moyes & Co. independently calculated the probability of success (“PoS”) factors for each of the stacked reservoirs assessed, the majority of which were calculated in the 25 – 35% range.
Based on several field developmental studies BPC believes that the minimum field size for an economic development of this nature is less than 200 million barrels (versus the resource estimates measured in billions of barrels, as noted in the independent Moyes & Co review), and that the project therefore offers robust commerciality even in a series of credible downside scenarios.
Combining all of the technical work and interpretation, the Company was able to build on earlier well design efforts to develop a range of potential well locations and well plan options, based upon in-depth reviews of wells previously drilled in The Bahamas. A particular issue affecting historical exploration well drilling performance was the slow rate of penetration (“ROP”) of the drill bit. Studies were initiated taking account of recent technology and drilling philosophy developments, whilst also adopting and implementing global standards and best practices. The results of these studies suggested that significant improvements could be made to ROP, thus substantially reducing the predicted time it would take to drill any chosen well. Based on these studies, BPC estimated that an exploration well to a depth of up to 6,500 meters (21,500 feet) would take between 40 and 60 days to drill and assess. Further, well cost updates have incorporated the substantial reduction in global rig rates and availability, to arrive at the current well cost estimates (refer to Section 5, Well Location, Historical Cost Estimates and Funding Strategy, below).
Your licences have a variety of play types, what is your current thinking on the first well?
The Company has, to date, expended in excess of US$100 million, much of it in relation to the above summarised technical work (including data acquisition, interpretation and studies). In aggregate, the Company believes this technical work has established a project with:
- stacked play systems from Late Jurassic syn-rift clastics, to Cretaceous shallow water carbonates with reefal geometries and shallower slope talus debris fields, in structures and stratigraphies mapped from 3D – totalling over 20,000 feet of stratigraphic column;
- three and four-way dip closed structures mapped at over 70 kilometres along strike length, with gross column heights up to 1,000m and areal extent ~400km2;
- the prospect of a world-scale, multi-billion barrel petroleum resource, similar in scale and size to resources encountered in more well-known petroleum producing regions, and highly analogous to the Iranian Zagros mountains and the Mexican Salinas basins both producing from fold and thrust exploration plays, with the likely source rock charging the Company structures being the same age and type as the Bossier-Smackover petroleum system that charges the deepwater fields in the Eastern US Gulf of Mexico and nearby Cuba; and
- a significant reduction in estimated well cost when compared to prior estimates, attributable to current rig rates, an anticipated improvement in ROP (principally associated with technical advances in drill bit technology) and lower estimated logistical and support costs.
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 Environmental Authorisation?
In 2012, the Government initiated a process to replace The Bahamas’ existing laws and regulation for the petroleum industry (which dated to the 1970s) with a new set of laws and regulations, in particular to include modern safety and environmental regulations consistent with global standards and best practices around the world. Such modernised regulations were, following a three and a half year process, finally promulgated in July 2016, following enactment of the updated Petroleum Act in March of the same year. These regulations for the first time include the concept of Environmental Authorisation (“EA”) as a part of the commencement of well activities, which require the submission of both an Environmental Impact Assessment (“EIA”) and an Environmental Management Plan (“EMP”) together.
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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).
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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.
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