Bahamas Petroleum Company, since prior to licensing in 2007, has engaged in a dedicated effort to locate and secure all available geological, geochemical and geophysical data related to the hydrocarbon potential of The Bahamas. This dataset now comprises three essential parts (i) the physical core material (rock matter) and cuttings (rock particles), (ii) the accumulated electronic data (mainly comprising seismic surveys), and (iii) the paper data, comprising reports, analysis, maps, interpretations and conclusions. The physical core material (rock matter) and cuttings (rock particles) are appropriately stored in secure company premises.

The major asset of the Company and that which comprises the majority of the $46.4 million capitalised exploration spend to date is the acquisition and processing of 3,074 km2 of 3D seismic data in the Southern Licence area. These data were collected by CGGVeritas using their ‘BroadSeis’ technology – the first time 3D seismic has been acquired and this technique was used in The Bahamas. Two data volumes were delivered, ‘Fast Track’ and the final Pre-Stack Depth Migration (PSDM). Sample spacing on
the PSDM volume is 12.5 meters in the x, y direction and 4 meters vertically. The data are of high quality and being used to advance understanding of the hydrocarbon systems.

The 3D (Figure 1) confirms and better defines the prospective structures (Folds B and C) previously mapped on the 2D and evaluated in the Competent Person’s Report (CPR), whilst removing structures mapped on the 2D underneath Trend A, which were confirmed as velocity artefacts. Significantly, the new data provides insight into the residual risks
with encouragement regarding source potential and fetch area, indicating the basement to be deeper than previously mapped implying a thicker, deeper Upper Jurassic (source rock) interval. Furthermore, the interpretation shows a uniform south west dip under the Cretaceous platform (Trend A) indicating access to a larger than previously mapped fetch area toward the Cuban mainland under the North Cuban basin. Faulting continues to display a distinct overthrust character potentially turning horizontal in the interpreted organic-rich facies of the late Jurassic, though there is also clear evidence of reverse faulting penetrating deep into the Jurassic section. The seismic displays good correlation across faults giving high confidence in the fault picks.

The folding shows distinct rollover above the fault plane creating significant attic volumes above any migration entry or exit point to the structure.

As in any frontier exploration province where there is inadequate well control, geological and reservoir properties that lead to prospect definition must be estimated or inferred using detailed models and regional data, as much local data as possible and analogues. The Company has integrated the seismic facies interpretation undertaken by the University of Texas, Bureau of Economic Geology reservoir Characterisation Research Lab (RCRL), the petrophysical data from the Doubloon Saxon (DS) well, various internal reports on the cuttings and core descriptions, the tie of the DS to the 3D seismic volume completed by iReservoir, the reservoir summary in the CPR, and the C & C Reservoirs Digital Analogue Knowledge System (DAKS) of world wide oil fields.

This synthesis allows the Company to report on its understanding of five (5) gross prospective intervals from deepest (oldest) to shallowest (youngest):

1.    Lower Cretaceous anhydrite-dolomite interval, Main play target.
2.    Lower Albian and Aptian Megabank, Main play target.
3.    Albian reef and platform, Main play target.
4.    Mid-Cenomanian reef and platform, Analogue play target.
5.    ‘Pre-MCU’ Albian and Cenomanian basinal and forereef, Analogue play target.

Intervals 1 and 2 can be directly tied to the Doubloon Saxon well and the reservoir data is based on the petrophysical interpretation from that well. Intervals 3, 4 and 5 are not directly tied to the Doubloon Saxon well as much of this drill section is either missing or subject to significant drilling problems – due to collapse.

Figure 2 summarises the regionally significant stratigraphic events. As the continental margin subsided following the breakup of the continents in the Jurassic the initial sediments were deposited in a restricted marine environment (gray and purple). It is in the first layer (gray) and possibly below that the company believes source rocks were potentially deposited. The purple layer records a regionally extensive evaporite basin where anhydrite (seal) and dolomite (reservoir) were deposited sequentially. As the water  depth deepened an extensive carbonate platform, or ‘megabank’, was created (green through light blue – Aptian through lower Albian). As the water depth continued to deepen the megabank divided into distinct reef and platform areas separated by deeper water channels. This lasted until mid- Cenomanian (top of the light orange) when the water depth became too deep for the reef and platform facies and the shallow water carbonates were buried by a pelagic drape. During the overall trend of deepening water depth there were times when sea level dropped and the reef and platform areas were exposed and caves and caverns (karst) developed (dark orange). This seismic facies framework is used to help better interpret rock types from the seismic and apply the appropriate geologic models for estimating reservoir properties.

Lower Cretaceous anhydrite-dolomite interval

The deepest interval anticipated to contain reservoir facies in the mapped structures is the lower Cretaceous anhydrite dolomite interval. This play type is the primary focus of the Company in the Southern licence area. Seismically this interval is characterised by continuous high frequency high amplitude reflections as shown below in Figure 3. The peaks (blue) are interpreted as anhydrite the troughs (yellow) are interpreted as porous dolomite. This section/interval also contained oil shows in the previously drilled wells and is considered the Company primary target for exploration.This interpretation is based not only on the seismic character, but also on regional geology and synthetic tie to the Doubloon Saxon well (interpreted from various reports by RCRL and iReservoir).

In the Doubloon Saxon well the interbedded anhydrite-dolomite interval extends from 17,000 feet to well TD at over 21,000 feet; a gross interval in excess of 3,400 feet. In the Competent Person’s Report (CPR), Ryder Scott calculated 1,220 feet of gross reservoir over this interval but did not include any potential resource volumes for these horizons in its analysis.

Lower Albian and Aptian ramp (Megabank)

Geologically this interval is expected to  be similar to the interval for most of the Doubloon Saxon well across an 8,000 feet gross interval. Depositional environments throughout this interval range from restricted to semi restricted to open low to high-energy environments. Due to the shallow water nature through this interval there were likely times of sub-areal exposure. Ryder Scott calculated 13 gross reservoir intervals in the Doubloon Saxon well denoted as a ‘megabank’ facies.

Upper Albian Platform and Mid Cenomanian Platform

The Upper Albian platform represents the first segmentation of the megabank represented by an east-facing reef separated from the Great Bahamas Bank and the site of the Doubloon Saxon well by a deeper water channel. The Mid Cenomanian platform steps to the southwest and represents the last platform facies in the southern portion of the Old Bahamas Channel. While similar facies intervals may be present in the Doubloon Saxon well there is no direct connection of this margin to the rocks seen in that well.

In Figure 4 the smooth contours to the north east (top) represent the deeper water sediments in front of the platform.The irregular contours to the south  west are an expression of the karsted surface on the platform – shown in section in Figure 5. The total length of Fold B is some 78 kilometres. The trap  at the Albian level is created by the structural dip to the southwest and the stratigraphic change from reef and platform to basinal sediments to the north east. The trap occurs off structure at the north end of Fold B and reaches  a culmination on the crest of Fold B to the south.

Above the Albian platform a younger, Cenomanian age, isolated platform developed (denoted as Trend A in Figure 1). This platform is characterised by chaotic low frequency character on the platform margin and continuous higher frequency reflections to the south and west. The higher frequency reflections are interpreted to be an intrashelf basin similar to the Golden Lane in the Mexican Gulf of Mexico.

Pre-MCU Cenomanian and Albian foreslope and basinal reservoirs

This is the shallowest reservoir interval evaluated. This section would not have been seen in the previously drilled wells and control for reservoir parameters comes primarily from analogue fields. Analogue reservoirs are concentrated in the North Sea and Mexico; depositional environments and lithology ranges from pelagic chalks to debris flow and turbidites, limestones and dolomites.

Structurally the in Mexican Campeche Basin is very similar to Folds B and C. These 3 fields produce from the Cantarell reservoir interval and have a combined estimated ultimate recovery (EUR) of close to six billion barrels.

All of this stratigraphic information has been integrated with the latest geophysical interpretation to derive a series of prospect maps defined by
stratigraphic horizon, shown in Figure 6.

Utilising a specialist software package various reservoir parameters and rock properties were input including analysis by Ryder-Scott of the Doubloon Saxon well and analogue data from similar dolomitic reservoirs and global platform carbonates to derive deterministic volumetric scenarios. This then allows comparison of the merits of different play types across the 3D acquisition area. The key determining variable in cases run is the degree of fill – the extent to which the individually identified structures are full of oil (as a percentage). It remains  the conclusion though that billion barrel reserve potential is present. Large upside cases exist in the Megabank where Fold B North and South can combine into a single, large structure at Aptian/Pre-MCU (BMAX in Figure 6), and Folds B and C can converge into  a giant closure at the Pre-MCU level (BCMAX in Figure 6). There is potential in these scenarios for multiple billion barrel reserves. In most cases, for individual reservoirs, a 30% fill scenario is potentially commercial.

In March, the Government ofThe Bahamas announced a cancellation of any need for a referendum allowing exploration drilling to proceed, deciding to first acquire data required to make  an informed decision on energy development prior to any public consultation. This decision removed crucial uncertainties and provided clarity for future decisions by the Government, the Company, and potential partners closely watching the timing of operations.

In July, BPC received notification that  the statutory term for the five licences held by the Company had each been renewed and that the new licences term would be for a further three years with an obligation to commence drilling of an exploration well by April 2015. It is anticipated that this obligation will be met with an exploration well in the southern licences. A second exploration well is required to be commenced nominally by April 2017. Significantly, as a further part of this renewal, the southern boundaries of the four southern licences are to be adjusted to conform to the maritime boundary between The Bahamas and Cuba, thus providing clear tenure over the full extent of the existing mapped structures.

Together, these milestones paint a very clear mandate for the Company to proceed with drilling preparations and funding plans. Notably, the mandate  will be carried out within full compliance of updated environmental and safety regulations developed by the Government with continued support from the Company. These regulations, which will provide a modern framework to manage and govern industry activities consistent with current attitudes, recent experiences and technologies are now before Cabinet for consideration by the government. It should therefore be anticipated that these will soon be available to both the company and for public consultation.

The company has applied for two additional licenses in the Santaren Channel and had also applied for a further three licences in joint partnership with Statoil. In the joint-venture with Statoil an Environmental Feasibility Study (EFS) has already been submitted and is currently under review by The Bahamas Environmental, Science and Technology (BEST) Commission and their consultants. Statoil, in February 2014, decided not to continue with the new joint applications and therefore they have reverted into BPC’s sole name. A decision on all the applications is expected post the release of new regulations.

The previous three offshore wells, drilled by Repsol, Petronas and PDVSA during 2012, on the Western side of Cuba were plugged and abandoned as dry holes though each reportedly encountered hydrocarbon shows in both the Tertiary and the Cretaceous sections. It is important to note the geology where these wells were drilled is considerably different from the geology in Bahamian waters, with the Mesozoic carbonate rocks buried beneath a deep Tertiary basin. A 15,000 feet exploratory well at these locations would need to drill through as much as 13,000 feet of Tertiary cover in order to simply penetrate the uppermost portion of the carbonate platform rocks. Additionally, the trap styles are considerably different and considered higher risk than the structures found in The Bahamas. The Company has a sound understanding of why these wells did notfind commercial hydrocarbons and is confident that these well results do not reflect negatively on the assessment of the hydrocarbon exploration potential within Bahamian waters.

Immediately adjacent to the Company’s Licences the Russian company, Zarubezhneft, completed drilling an exploration well in 2013. The rig was drilling in Block L, the easternmost of four blocks the company leased in 2009. Located approximately 15 miles from The Bahamas – Cuba border, 45 miles from Bahamas Petroleum’s proposed well location and 50 miles from the last well drilled in the waters of The Bahamas in 1987. Drilling was expected to reach depths of over 21,000 feet; the deepest well to be drilled during the recent spate of drilling offshore Cuba, though similar depths have been drilled previously in The Bahamas in 1987 and comparable to those to be targeted by Bahamas Petroleum Company in its obligation well. The drilling campaign, in 500m of water located off the keys of Villa Clara province, near Cayo Santa María – an expanding beach tourism destination Cuba has been developing over the past 10 years – emphasising the belief that active tourism and safe exploration can responsibly co-exist. Bahamas Petroleum Company staff were able to visit Cuba to ensure effective liaison.

The rig being used, the Songa Mercur, chartered from the Norwegian – owned drilling operator Songa Offshore, despite being under contract for 200 days was unable to come even close to its objectives. Zarubezhneft is not a listed company and therefore is under no obligation to make public announcements concerning progress and outcome, though it is believed Zarubezhneft reached a depth of about 2,000 meters before experiencing problems with the blowout preventer (‘BOP’) and cancelled the drilling contract significantly short of their target depth and well above any potential reservoirs likely to be of commercial interest. Rumours continue that having released the rig they intend to return to complete drilling in 2014 possibly after the hurricane season.

Bahamas Petroleum continues to seek an industry partner to join in the drilling and opened a data room where selected, potential industry partners were invited to view the extensive paper as well as online database. Discussions remain ongoing with a number of interested parties, but the basis for these discussions has benefited significantly from the renewed clarity provided by the Government regarding a clear mandate to carry out an exploratory drilling programme.

Utilising the 3D data, the seismic facies mapping, detailed prospect inventory work, the multibeam data collected in 2011 and incorporating data from previous drilling in the area, Advanced Drilling Technologies (ADTI) have provided initial well designs and drilling plans, as well as specifically identified long lead time items to discharge licence obligations. For this initial well design, these long lead items are identified as the large bore wellhead with H2S resistant metallurgy (and appropriate running tools).
The plan has safety and environmental components consistent with international waste and emissions standards as well as response plans for emergency situations. This initial well plan – named Perseverance – is designed to target  the Jurassic at or around a TD of 22,500 feet located on the crest of Fold B at the south-eastern end of the structure. This location would fully evaluate those resources identified in the Competent Person’s Report at the late Cretaceous, Albian and late Aptian horizons but significantly is also designed to target the additional prospectivity now the focus of the Company’s attention in the inter bedded anhydrite, dolomite and limestone reservoir sequences in the Early Aptian and below.

Drilling is anticipated to be in approximately 1,500 feet of water, which by modern standards is relatively modest (Figure 8) and to take 120 days to execute and log. The ultimate well cost is highly dependent on spread rates but the anticipated well cost is being dramatically impacted by the current falling rig rates and a significant reduction in the estimated well cost is being targeted.

Technical studies and projects currently underway or the Company expects to detail in the next annual report are:

1. Site specific exploration well design.
2. Detailed drilling plans for obligation well.
3. Procurement plans for drilling execution.
4. Contracting strategies.
5. Emergency Management Plans (EMP) for possible drill sites.
6. Exploration economics for desired well.
7. Health, safety and security programmes for safe, responsible drilling.
8. Pre-drilling inspections (as necessary).
9. Lay-down, support and logistics plans.
10. Training requirements.