6-K 1 d63653_6-k.htm REPORT OF A FOREIGN PRIVATE ISSUER
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 6-K
 
REPORT OF A FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 UNDER
THE SECURITIES ACT OF 1934
   
For the month of April 2005
   
Commission File Number 000-17729
   
FORUM ENERGY CORPORATION
(Address of principal executive office)
 
7002 nd st s.w. suite 1400 Calgary, AB, TZP4VS CANADA
(Translation of principal executive offices)
 
Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.
Form 20-F x Form 40-F o
   
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(l) o
   
Indicate by check mark the registrant urnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934. Yes o No x
   
If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82- ______



SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
  FORUM ENERGY CORPORATION
                    (Registrant)
     
  By: /s/ David M. Thompson
 
Date: May 03, 2005 Name:  David M. Thompson
  Title:    CFO



           PGS Reservoir Limited
PGS Thames House
17 Marlow Road
Maidenhead
Berks
SL6 7AA
 
The Directors
Forum Energy Plc
6th Floor
One London Wall
London
EC2Y 5EB
 
and
 
The Directors
Noble & Company Limited
76 George Street
Edinburgh
EH2 3BU
15 April 2005
 

Dear Sirs,

 
  Re: The Petroleum Interests of Forum Energy Plc
 

In response to your request, we have reviewed the proposed petroleum interests of Forum Energy Plc (“Forum”). Following the signing of the Transaction Agreement mentioned below, and the conditions being met or waived, Forum will have an interest in two contract areas in the Philippines, one currently owned by Forum Energy Corporation (“FEC”) and the other by Sterling Energy Plc (“Sterling”). These areas are highlighted on a map of the Philippine archipelago in Figure 1 (attached). The contract areas encompass undeveloped discoveries and unexplored and untested exploration prospects.

Our evaluation of those interests is based on a review of information provided to PGS by FEC and Sterling during March 2005. PGS has performed an independent review and evaluation of the interpreted data and in preparing this report PGS have used maps, reports and other pertinent data supplied by FEC and Sterling. Where possible, PGS have substantiated the




existence of oil and gas resources from well information and other evidence supplied by the Directors of Forum, FEC and Sterling.

Summary of Interests

FEC and Sterling are to enter into a Transaction Agreement in April 2005, whereby will FEC transfer its 66.7 per cent. interest in Forum Exploration, Inc., (“FFI”) a Philippine registered company, which has a 100 per cent. interest in the SC 40 (Cebu) contract area, and Sterling will contribute its 100 per cent. interest in the GSEC 101 (Reed Bank) contract area offshore Palawan island to a newly incorporated UK Plc, Forum Energy Plc. The contract areas are shown plotted on a map of the Philippine archipelago in Figure 1. GSEC 101 (Reed Bank) covers an offshore area to the west of Palawan Island, known as the Reed Bank.

The FEC contract area is a service contract (SC) area known as SC 40 (Cebu), which covers the northern half of Cebu Island plus part of the Visayan sea offshore to the west of the island. Several exploration prospects and leads have been identified by FEI within the service contract area, both onshore Cebu, and offshore in the Visayan Sea. A small gas field named Libertad has been discovered and appraised onshore Cebu, but its small size has meant that so far it has not been developed. FEI is currently undertaking a feasibility study aimed at developing Libertad to provide gas for on-site electricity generation.

The prospects and fields identified within the two contract areas are summarised in the table below, and discussed in more detail in the following sections.




Prospect and Discovery Summary  
                       
Prospect   Primary Target
Formation
  Target
Depth ft
  Water
Depth ft
  Chance of
Discovery1
  Potential Reserves
Oil(mmbbl)/Gas(bscf)
 

 
 
 
 
 
 
Central Tañon   Barili Limestone   3700   650   0.115   265/660  
Jibitnil Island   Maingit   4100   Onshore   0.115   85/450  
    Limestone                  
South   Maingit   6000   100   0.099   70/330  
Guintacan   Limestone                  
West   Maingit   2900   120   0.115   80/185  
Malapascua   Limestone                  
West Toledo2   Malubog Sand   7500   350   0.113   97/332  
Agojo   Maingit   4700   250   0.1   60/210  
    Limestone                  
North Bantayan   Cebu Limestone   7600   300   0.08   250/1000  
Sampaguita3   Late Paleocene   10300   260   1   - /2329  
Libertad   Barili Limestone   650   Onshore   1   - /0.5  
CMB4   Malubog Sand   1500   Onshore   1   0.14/0.64  
                       
1  Prospect chances of success are not independent. Failure to discover commercial hydrocarbons in one prospect is likely to reduce the chance of success in the others.
   
2  As currently mapped, only a small part of these potential reserves may be under SC 40 (Cebu).
   
3  Potential gas reserves assume a recovery factor of 0.85
   
4  Potential oil reserves are limited to primary recovery. Recovery factors for oil and gas are assumed to be 0.05 and 0.85 respectively.
 

GSEC 101 (Reed Bank)

The GSEC 101 (Reed Bank) licence is located in the South China Sea to the west of Palawan in the Reed Bank area and covers an area of 4,023 square miles (10,420 km2). This licence contains the Sampaguita gas discovery and a number of leads as illustrated in Figure 2. Sampaguita is located in 250-270 feet (ca. 75-85 metres) of water, approximately 150 miles (250 kilometres) southwest of the Malampaya Gas Field and a similar distance northwest of Palawan. The Malampaya Gas Field produced first gas in October 2001. Figure 3 shows the location of the GSEC (Reed Bank) area in relation to the Malampaya field, and its associated gas export infrastructure, which consists of a 504 kilometer long 24 inch diameter pipeline delivering gas to landfall on Luzon island.

The Reed Bank area consists of two main highs, which are referred to as the ‘North Bank’ and ‘South Bank’, separated by a deeper area. The structure is strongly influenced by a series of northwest – southeast orientated faults formed as a result of the opening of the South China Sea. The Sampaguita gas discovery is located at the southwestern end of the smaller ‘South Bank’.




Exploration in the GSEC 101 (Reed Bank) area commenced in 1970 with the acquisition of 2D seismic data. At present 340 miles (ca. 550 kilometres) of seismic data are available over the South Bank area, which includes the Sampaguita gas discovery. Exploration drilling during the 1970-80s was focused on exploration for oil, with gas being considered non-commercial at that time. The first well, Sampaguita-1, was drilled in 1976 by Salen. This tested gas in the Late Paleocene sand section. This was followed by well Sampaguita-2 (Salen, 1978; gas shows not tested), Sampaguita 3 (Salen, 1982; failed to reach target, abandoned) and Sampaguita-3A (Denison Mines, 1984; gas tested in Late Paleocene sandstone).

The Sampaguita gas discovery is contained within a large faulted four-way dip closure. This structure is dissected by a series of poorly defined northeast – southwest orientated faults. All wells drilled to date on this structure are located at the southwestern end of the structure, with Sampaguita-1, -3 and -3A located in crestal positions, whilst Sampaguita-2 is located on the southeastern flank. The current estimate of structural closure is 110 square miles (ca. 290 km2).

The current structural interpretation of the Block is based upon reprocessed 1980 2D seismic data and limited 2D data acquired during the mid-1990s. These data are of moderate to poor quality, particularly at the reservoir level, and provide broad structural control. Data quality and quantity precludes the imaging and interpretation of faults in detail. Modern 3D seismic data would be expected to provide significantly improved imaging and structural detail leading to significantly reduced risk in reserve estimation and potential development planning.

The oldest rocks penetrated by drilling within the Sampaguita gas discovery are Early Cretaceous. These typically consist of terrestrial to shallow marine sandstones, conglomerates and mudstones, overlain by a distinctive limestone horizon. The sandstones and conglomerates of the Early Cretaceous potentially form a secondary reservoir within the Sampaguita gas discovery, but have not been successfully tested. These sandstones have effective porosity values of 10 – 20 per cent. and have significantly lower interbedded shale content. Shows are recorded in most of the sandstones at depths greater than 850 feet (250 metres) below the distinctive limestone horizon. No shows are recorded in the 660 foot (200 metre) or greater thickness of silty shale and sands between the distinctive limestone and the base late Paleocene sandstones, suggesting this interval provides a regional topseal. Whether or not the silt and shale units interbedded with the sandstones provide effective intra-formational seals is unclear.

The early Cretaceous is erosionally overlain by late Paleocene sandstones and mudstones deposited in a deep marine fan system, which forms the principal reservoir horizon within the Sampaguita gas discovery. These sandstones are informally referred to as the ‘Main Sandstone’ and ‘S1 Sandstone’. These sands consist of thinly interbedded sandstones and mudstones which in the Sampaguita-2 well are approximately 100 feet (ca. 30 metres) and approximately 70 feet (ca. 20 metres) thick respectively. These sands are correlatable between the three wells drilled on the structure. The ‘Main Sandstone’ encountered within the Sampaguita 3A well is only 40 feet (ca. 12 metres) thick, interpreted to be the result of fault truncation. The sandstones have moderate reservoir quality with 12 – 20 per cent. porosity, being reduced by clay matrix material and cementation. The thin-bedded nature of the sands suggests that individual sandstone bodies could be of limited lateral extent. As a result, vertical and horizontal communication within the discovery may be impaired. The wireline log response from the old logging tools provides poor resolution of these thin interbedded sands, leading to some uncertainty in the estimation of the reservoir parameters.

The Late Paleocene sandstones are overlain by early to earliest middle Eocene deep marine mudstones, which will form an effective seal for both the ‘S1 Sandstone’ and ‘Main Sandstone’. These are followed by late Eocene to early Oligocene sandstones and mudstones. The uppermost part of the stratigraphic section consists of late Oligocene to Plio-/Pleistocene limestones.




To date a clearly defined source rock interval has not been identified within the wells on the Sampaguita structure. Geochemical analysis of the Paleocene, Eocene and Early Cretaceous shales in the Sampaguita-1 well indicates that these are unlikely to represent good source beds. The shales are generally organically lean and although containing gas-prone organic material, are unlikely to be a major gas source. Not withstanding this, testing of the Sampaguita-1 & -3A wells indicates that a gas source is present. It is presumed that this must be located within deeper intervals (?Jurassic – early Cretaceous) located either within the structure or the deeper areas to the northwest and southeast of South Banks.

Wells Sampaguita-1 and -3A successfully tested gas from the Main and S1 sands, respectively, at rates of 3.6 and 3.2 MMscf/d. However, these tests were conducted over short time periods and one showed significant depletion; therefore long term productivity and the effect of compartmentalisation remains uncertain.

The Sampaguita gas discovery demonstrates the presence of an active hydrocarbon system and producible gas. The previous Operator (Sterling) estimated the presence of several TCF of gas in place. PGS estimate the gas initially in place to be approximately 2.7 Tscf, which makes Sampaguita comparable in size to the nearby Malampaya Gas Field. The application of modern technology (seismic, logging and testing) is required to confirm the size, productibility and commerciality of this discovery.

Eight additional leads and prospects have been identified by various studies, and these are depicted in Figure 2, although the supporting data for some of these interpretations is no longer available. The majority of the prospects and leads are located on the ‘North Bank’, with one located on a small high to the northeast of the ‘South Bank’. Three additional wells have been drilled in the Reed Bank area, wells Reed Bank-A1 & -B1 and Kalamansi-1. None of these wells tested the leads/prospects as they are presently mapped.

SC 40 (Cebu)

The SC 40 (Cebu) area was originally awarded as a GSEC to a consortium including one of FEC’s predecessor companies in February 1994. In February 1995, the contract was upgraded to a service contract, and part of the original GSEC area was relinquished to leave the area now shown in Figure 4. As of 1st January 2003, the title to SC 40 (Cebu) rests 100 per cent. with FEI, the other co-venturers in the original consortium having relinquished their interests.

The terms of a service contract allow for extensions from the original 7 years to 10 years if required, and in the case of SC 40 (Cebu) an extension has been granted, on condition that the work commitments for the contract are fulfilled. FEI has received an extension to the term of SC 40 (Cebu) until the end of September 2006, subject to a specified work programme being adhered to. This work programme includes the acquisition of 250 kilometres of seismic data, plus the drilling of two wells in 2005 and a further two in 2006.

FEI is in the process of investigating development options for the small Libertad gas field, and for development to proceed, the field will first have to be declared commercial. Such a declaration triggers a requirement to relinquish all but 12.5 per cent of the current SC 40 (Cebu) area. This can be achieved without relinquishing any of the prospect areas discussed below.




Geological Setting

The SC 40 (Cebu) contract area is located in the Visayan Basin, in the central part of the Philippines archipelago. It is an intra-arc basin characterised by a series of north to northeast trending troughs and ridges. The basin comprises five main depocentres, the Tañon, Bantayan, Cadiz graben, Northwest Leyete thrust belt and Asid Gulf basins. Numerous narrow and elongate ridges separate the basins and are exposed in part on the present islands. The key basin that underlies the SC 40 (Cebu) licence is the Tañon sub-basin, a narrow northeast trending asymmetric trough filled with a thick Tertiary section (up to 8 kilometres).

Exploration in the Visayan Basin began over 100 years ago and since then approximately 130 wells have been drilled. The majority of the wells were very shallow tests and drilled outside of structural closure. Oil and gas shows have been encountered in a number of wells with oil and gas discoveries made onshore Cebu Island. Since 1994 fifteen wells have been drilled in the offshore Visayan Basin, thirteen of which lie within the SC 40 (Cebu) licence. Of these thirteen wells, nine targeted Miocene reef plays defined on 2D seismic data and good reservoir quality was established by 9 wells. Hydrocarbon seeps are also common in the area indicating an active and mature petroleum system. The most likely source rock intervals are the carbonaceous shales of the Oligocene to Lower Miocene Malubog Formation and the Cretaceous Pandan formation, they contain TOC values of 1 to 5.9 per cent.

The majority of the wells are interpreted to have failed due to the integrity of the trap, although recent results also point to uncertainty in the extent of reservoir quality sands. Poor top seals, leaky faults and poorly defined closures are believed to be the main reasons for failure. Drilling results to date demonstrate the carbonates of the Middle to Upper Miocene Maingit and Upper Miocene to Pliocene Barili Formations have excellent reservoir characteristics. The Maingit Formation has been found to have good porosities averaging between 15 per cent. and 20 per cent, and frequently mud losses have been reported during the drilling of the Maingit, which may be indicative the presence of natural fractures. The underlying lower to middle Miocene Malubog formation provides an additional target in the Central Maya Bulge (“CMB”) area.

The Barili Limestone has excellent reservoir qualities with porosities typically exceeding 20 per cent., with vuggy porosity often developed. The reservoir for the Libertad gas field onshore Cebu is the Barili limetone. Other potential reservoirs include the Middle Miocene Uling Limestone and the Upper Oligocene to Lower Miocene Cebu Limestone. These secondary targets are generally tight although occasional patch reefs may provide areas of improved reservoir quality.

A brief description of each of the main prospects and leads within the SC 40 (Cebu) area is given below, and their location is shown on the map included as Figure 4.

Libertad Gas Field

The Libertad Gas Field lies to the southeast of Bogo town in northern Cebu, approximately 100 kilometres north of Cebu City. It was discovered in the late 1950s during an exploration drilling campaign by the Acoje Oil and Mineral Development Corporation of Manila, (“Acoje”), but it has never been developed, due to its very modest size, and the fact that exploration effort has historically been concentrated on discovering oil, not gas. Of the twenty-two wells drilled in the Libertad area by Acoje during their exploration campaign, two were completed as gas wells, but apart from some tapping of minor amounts of gas for cooking purposes in a nearby elementary school, there has never been any commercial production. Acoje subsequently relinquished their interests in Cebu in the 1970s.




During the 1990s, there was renewed interest in Libertad as a potential source of gas for power generation, and a testing programme was performed on the two available gas wells in 1993. Five additional wells were drilled in the Libertad field area during 1994/95 by the Cophil Exploration Corporation (Cophil – later to become FEI), one of which tested gas, and it was subsequently completed as a gas well.

The gas bearing horizon in the Libertad Gas Field is the Upper Miocene Barili Limestone, which is encountered at shallow depth, approximately 600 – 700 feet below ground level, or around 300 feet below mean sea level. The gas is predominantly (> 95 per cent.) methane, with some nitrogen and carbon dioxide, plus around 400 ppm of hydrogen sulphide. This latter contaminant represents a health and safety risk, due to its toxicity. Reservoir pressure is approximately 150 psia, which is low, due to the shallow reservoir depth. Nevertheless, two of the three currently completed gas wells in the field are each capable of flowing in excess of 1.2 mmscfd, the highest recorded rate being almost 2 mmscfd. The third well has a tendency to produce water if the gas production rate exceeds more than a few hundred mscfd.

A top Barili Limestone structure map in depth is included as Figure 5. It can be seen that the field is divided by a south-west to north-east trending fault. The division of the field into two parts is reinforced by the results of an interference test carried out by FEI in 2000. There appeared to be no response detectable in pressure gauges set in the one accessible well in the northern fault block to a protracted production period of several days from one of the two completed wells in the southern block. There was, however, an overall pressure drop of approximately 1.5 psia in the southern fault block in response to a produced gas volume of just over 5.5 mmscf. This pressure drop suggests that the initial gas in place in the southern fault block is of the order of 550 mmscf, although volumetrically derived estimates are almost twice this value.

Old well records report several occurrences of lost circulation whilst drilling through the Barili Limestone, which suggests that the formation is probably fractured. The high gas deliverabilities observed on well tests would lend support to this conclusion.

Maya Area

The Maya area lies at the northern tip of Cebu Island (Figure 4), and it has been the subject of sporadic exploration activity since the late 1920’s when oil shows were encountered during the drilling of a shallow water well. Several exploration wells were drilled in the 1960s and early 1970s by the American Asiatic Oil Company, and by the Chinese Petroleum Company in the area known as the Central Maya Bulge (“CMB”). Some of these wells were reported to have flowed oil on test, but sustained production at commercial rates was never established, and interest in the area waned. Nevertheless, there is anecdotal evidence that residents local to the Maya area harvested up to 80,000 litres of oil from one of the old Maya wells before the authorities put a stop to the practice.

The oil-bearing horizon encountered by the Maya wells was the late Miocene Maingit sandstone trapped within a domal closure. As part of its work commitment under the service contract, FEI drilled an exploration well (MST 11A) at Maya in October 2000, but although oil shows were detected in the Maingit sandstones, the well was terminated at a relatively shallow depth, (300 feet) and only limited data was gathered from the well. The only data available for the discovery well is that the well flowed 540 barrels of 44 deg. API oil in a 203 hour test.

A second prospect on the Maya anticline is the deeper lower Miocene Malubog sandstone, which was oil and gas bearing in a well drilled by the Chinese Petroleum Corporation in the early 1970s. Well CMB-2 was drilled on the west flank of the structure and tested 70-100 mscf/d and 106 bopd from a middle Miocene sandstone. The extent of the sand is poorly constrained with few




wells penetrating this deeper reservoir. CMB-3 was subsequently drilled down-dip and was dry. The up-dip Well CMB-4 was drilled to target the CMB-2 reservoir but found the sand to be tight or absent with oil shows.

During 2003 FEI renewed its drilling activity in the CMB area, and drilled a further three wells to test the anticlinal structure identified from the drilling of the MST-11A well. The locations of the three wells, Forum-1XA, -2X and -3X are shown on the map included as Figure 6, and a synopsis of the results from these wells is included below.

Well Forum-1XA was drilled approximately 400 metres northwest of CMB-2 to test the crestal portion of the CMB. The primary target was the 480 metre (Malubog) sand encountered in CMB-2, although secondary objectives occurred in the Maingit sands and limestones of the Lower Maingit. The well suffered a series of gas kicks whilst operating resulting in loss of the drill string and a fish in the hole, and as a result the well could not be tested.

Well Forum-2X was drilled 15 metres to the southeast of the Forum-1XA well to establish the presence of hydrocarbons in the crest of the structure. Well Forum-2X did encounter numerous oil and gas shows whilst drilling; gas shows were recorded at a depth of 900 feet in a limestone of the Maingit formation, and further oil and gas shows were recorded between the depths of 1,576 and 1,606 feet in sands of the Malubog formation. However, the level of shows was less than in the Forum-1XA well, probably due to the higher mud weights employed as a precaution against the kicks suffered during the drilling of the earlier well. The Forum-2X well confirmed the existence of an active hydrocarbon system in the SC 40 (Cebu) permit, but unfortunately various operational difficulties and equipment shortcomings conspired to frustrate attempts to determine definitively the nature of the hydrocarbons present in the prospective zones, and also to determine the ability these zones to produce hydrocarbons at sustained commercial rates.

Figure 7 shows a display of the wireline logs from the Malubog sand interval encountered in the Forum-2X well over the interval 1,576 ft to 1,606 ft. The calliper log confirms the presence of mud cake over this interval, which is a positive indicator of permeable formation. FEI interpret that the neutron-density cross over evident across the interval is indicative of the presence of gas, and that the interval between 1,603 ft and 1,606 ft at the base of the section may be oil bearing. PGS agree with the former interpretation, but consider that overall there is insufficient information to be able to confirm the latter.

Nevertheless, the presence of oil was noted in the drilling mud whilst drilling. This oil was reported to be waxy, with a high pour point, and it is unclear how this description fits with the 44 deg. API oil described as being produced from the test of the MST-11A well.

An attempt to perform a drill stem test (DST) on the well produced small quantities of gas and a trace of oil, but there was also evidence that the formation collapsed. This problem has been recognised in other test attempts in the area, and any future developments focussed on the Malubog should take this into consideration.

Well Forum-3X was drilled approximately 265 metres to the southwest of the 2X well as a downflank appraisal of the CMB structure. The well encountered only minor gas shows in the interval from 900 feet down to 1,600 feet, and consequently the well was not tested. The Malubog reservoir sand appears to be only poorly developed at this location, and although present, it was thinner and of much poorer quality than the same interval encountered in the 2X well. Wireline log data from Forum-3X confirms that the interval has a high shale content and virtually no effective porosity. This indicates that there is a lateral facies change in this direction away from the crest of the structure, which causes the unit to thin and grade to shale.

Taken together with the results of the CMB-2 well (200m to the northwest of Forum-3X) which tested 105 bopd, and other hydrocarbon indications from the thirty years of exploration activity in the CMB area, PGS conclude that the oil initially in place of 6.0 mm bbl estimated to be




contained in the CMB structure by FEI is at the upper end of any likely range of outcomes. PGS estimate a most likely volume of oil initially in place of the order of 2.8 mmbbl, or approximately 750 mmscf of gas if the zone were to be gas-bearing. This would represent a development opportunity of similar size to the Libertad Gas Field.

It should be noted that oil recoveries from shallow onshore fields could be very low if they are exploited by simple pressure depletion, as reservoir pressures are low in shallow reservoirs, and consequently so are the volumes of gas dissolved in the oil. Without pressure support, either by water injection or natural water influx, the production characteristics of the field would involve a short-lived rush of oil production, which would decline very rapidly, and be accompanied by increasing volumes of associated gas. Illustrative scoping calculations suggest simple depletion of a shallow oil reservoir at 1,500 feet would only recover between 2 and 6 per cent. of the oil initially in place.

By contrast, waterflood recoveries could be much higher, potentially above 30 per cent., but at the expense of additional wells and equipment. Also, the reservoirs need to be homogeneous and continuous for such methods to be effective. Fractured carbonates can present particular challenges to the implementation of successful secondary recovery techniques, and in general recovery factors tend to be lower than they are in sandstone reservoirs.

There remain many uncertainties regarding the potential of the CMB area, both in terms of volumes and nature of the hydrocarbons present, and the ability of the hydrocarbon bearing zones to produce at sustained commercial rates. FEI plan to re-enter the Forum-2X well during 2005, in order to evaluate and test the Malubog sand interval. Nevertheless, significant uncertainties will still remain in the formation characteristics at large, and the lateral controls on formation properties, and these make evaluation of the Maya area problematic. However, looked at from another perspective, since the expected drilling costs are very modest, the volumes of oil needed to repay the cost of the wells are also very modest. At current oil prices, less than 10,000 barrels of oil production will yield enough gross revenue to pay for a well, plus the additional costs of some oil storage capacity and a gas disposal system.

Central Tañon Prospect

The Central Tañon prospect is located within the Tañon sub-basin of the Visayan Basin offshore west Cebu. It is an elongate anticlinal structure trending approximately north-south with three culminations mapped on a sparse grid of 2D seismic data. The structure has been mapped at the Upper Miocene to Lower Pliocene Top Barili / Dingle carbonate level, the postulated reservoir horizon. The structure lies up-dip of Well Tuburan A-1X which encountered moderate to good oil shows in the Maingit Limestone. The Barili Limestone has been mapped as on-lapping the Maingit to the east of Tuburan A-1X enabling a possible migration pathway to the Central Tañon prospect. The structure also lies to the east and up-dip of Well Bangus-1 which had oil and gas shows in the Barili Limestone. Evidence for charge to the Barili Formation at the Central Tañon prospect is therefore encouraging. The top seal for the Barili Limestone is the Barili marl, a claystone interval composed predominantly of greenish grey calcareous and foraminiferal mudstones which are extensive over the region.

The reservoir at the Central Tañon prospect is the Barili/Dingle Limestone, bedded platform carbonates. The prognosed top reservoir depth is 3,700 ft with a total depth below the Maingit Limestone to assess this secondary objective. Reservoir quality at Well Bangus-1 was generally good with porosities of 15 to 25 per cent. Local enhancement of porosity by fracturing and dolomitization may improve reservoir properties. Potential source rocks in the Tañon sub-basin are believed to be the carbonaceous shales of the oligocene to Lower Miocene Malubog




Formation and the Cretaceous Pandan Formation. Uncertainty concerning the effectiveness of the source rock is because these intervals have not been penetrated in the Tañon Strait. They are however believed to exist and in the central parts of the basin are expected to be buried sufficiently as to be mature.

Very limited technical data was available to make an assessment of reserves. A time map of the Top Barili Limestone and an outline of the Operator’s reserves calculation provided sufficient data to calculate a deterministic value. The area of closure is over 9,000 acres with a vertical closure mapped of 820 feet. A total field deterministic value for recoverable reserves of 265 mm bbls of oil was calculated assuming a recovery factor of 20 per cent. If the structure was gas bearing, a deterministic gas reserve volume would be 660 bscf. The key risks associated with the prospect are the integrity of the mapped trap and the presence and effectiveness of the Barili/Dingle Limestone reservoir. PGS have assigned a chance of success of 11.5 per cent. to the Central Tañon prospect.

A seismic survey will be performed over the Central Tañon prospect area during 2005, in fulfilment of the work programme obligations associated with the contract area. A total of 250 line kilometres of 2D seismic will be acquired, and it is planned that part of the survey will cover the area around Jibitnil Island.

Jibitnil Island Prospect

The Jibitnil Island prospect as its name implies lies beneath the island of Jibitnil in the Central Tañon Strait, flanking the western side of the Daanbantayan Island, northern Cebu. The prospect is a complicated positive flower structure between two approximately north-northwest trending wrench faults. A small domal closure underlies the island with an areal closure of 925 acres and a vertical closure of 650 feet mapped on sparse 2D data around the island. The primary target at the Jibitnil Island prospect is the Maingit Limestone which was penetrated by Well Bakyad-1 2.5 kilometres to the west. At Bakyad-1 a tilted Maingit carbonate build-up was penetrated with no structural closure. Reservoir properties were good with porosities up to 28 per cent. Secondary targets include the Upper Miocene to Pliocene Barili Formation, the Maingit sands, Middle Miocene Uling limestone and the Upper Oligocene to Lower Miocene Cebu Limestone and Malubog sands. Well Jibitnil-1 was drilled 4 kilometres to the east of the island and encountered gas shows in the sandstone and limestone units of the Middle to Upper Miocene section, and oil shows in the Lower Miocene Malubog Formation. The well targeted a valid structure mapped at the Top Maingit Limestone interval but failed due to a lack of reservoir and charge.

At the Jibitnil Island prospect the primary reservoir objective, the Maingit Limestone is prognosed at 4,100 feet TVD SS. At Bakyad-1 the interval was chalky with occasional vuggy porosity, and is developed to a thickness of approximately 1,200 feet. Volumes have been calculated by the operator and with the limited data available verified. The potential recoverable reserves are 85 mm bbls in an oil case and 450 Bscf in a gas case. The key risks associated with the prospect are the presence of a working trap and the presence and effectiveness of the Maingit Limestone reservoir. PGS have assigned a chance of success of 11.5 per cent. to the Jibitnil Island prospect.

During 2005, 5 seismic lines will be acquired around Jibitnil Island as part of the proposed Central Tañon seimic survey.




West Malapascua Prospect

The West Malapascua prospect is located approximately 10 kilometres north of Cebu Island. It is a wrench induced fault and dip closed structure mapped at Top Middle Miocene Maingit Limestone. The structure has 1,950 acres of areal closure and 600 feet of vertical closure. The primary objective is the Middle Miocene Maingit Limestone penetrated elsewhere in the Visayan Basin and established as a viable reservoir. As with other prospects located in the Visayan Basin the most probable source beds are within the Lower Miocene and older. The top of the Maingit Limestone is prognosed to be at a depth of 2,900 ft TVDSS.

Volumes have been calculated by the Operator but with the limited data available cannot be verified. The potential recoverable reserves are reported to be 80 mm bbls in an oil case and 185 Bscf in a gas case. The key risks associated with the prospect are the presence of a working trap and the presence and effectiveness of the Maingit Limestone reservoir. PGS have assigned a chance of success of 11.5 per cent. to the West Malapascua prospect.

South Guintacan Prospect

The South Guintacan prospect is located to the southwest of Guintacan Island along the northwestern flank of the Tañon Strait sub-basin. The prospect is a faulted anticline trending northeast-southwest. The domal structure has been mapped at Top Maingit Limestone and has an areal closure of 1,700 acres and a vertical closure of 475 feet. Wells drilled in the vicinity for example Guintacan-1 and Guintacan-2 have had shows in the shallower Barili Limestone. As with other prospects located in the Visayan Basin the most probable source beds are within the Lower Miocene and older. The top of the Maingit Limestone is prognosed to be at a depth of 6,000 ft TVDSS.

Volumes have been calculated by the Operator but with the limited data available cannot be verified. The potential recoverable reserves are reported to be 70 mm bbls in an oil case and 330 Bscf in a gas case. The key risks associated with the prospect are the presence of a working trap and the presence and effectiveness of the Maingit Limestone reservoir. PGS have assigned a chance of success of 9.9 per cent. to the South Guintacan prospect.

West Toledo Prospect

The West Toledo prospect lies in the offshore Tañon Strait approximately 15 kilometres southwest of Toledo City, Cebu. The prospect is defined by only three seismic lines and lies in shallow water, approximately 300 feet at a potential well location. The structure has been mapped at an Early Miocene seismic event interpreted to approximate to the Top Malubog Formation. Closure is the result of reverse and strike-slip movement on a north east trending splay off a major north-south wrench system. The prospect is further bisected by two normal faults and closure also exists at the shallower Upper Miocene Maingit and Toledo clastic units providing a secondary target.

Onshore Cebu two oil discoveries were made by Wells Reina Regente-1AX and Villalon-4. The former produced 250 bbls per day in 1959 and currently produces 30 gallons a day from the Malubog sands. Well Villalon-4 also produced oil on test from the Malubog sands. It encountered approximately 150 feet of net sand with porosities in the range from 18 to 30 per cent. Work done in 1994 postulated that improved sand quality may be expected offshore where Late Oligocene to




Early Miocene palaeogeography indicates that sand provenance was from the west and the East Panay platform. As a result sand quality and permeabilities might be improved to the west where they are more proximal.

Secondary targets include the sands of the Maingit and Toledo Formations, these intervals are more speculative but do have reservoir quality and hydrocarbon indications elsewhere in the basin. Thick shale sections throughout the Miocene are believed to provide adequate intra-formational seals for the Malubog and the secondary targets. The critical risk concerns the sealing capacity on the bounding fault to the east. As yet there is no evidence to support sealing faults in the basin but the low net to gross section through the Miocene and presence of considerable argillaceous sections may enable a membrane seal to develop. The source for the prospect is the same as discussed for the Central Tañon prospect. Thermal maturity modelling carried out in 1994 indicates that the West Toledo prospect may be expected to be in communication with mature source rocks.

The areal closure is in excess of 3,700 acres and has a vertical closure of 3,000 feet. Volumetric estimates were performed during 1994 and have been verified with the limited data available. The deterministic recoverable reserves are 97 mm bbls for the oil case and 332 Bscf for the gas case. However, as can be seen from Figure 4, a relatively small part of the prospect lies within SC 40, and FEI’s interest in any successful development of a discovery on this prospect would most likely be as a participant in a unit operated by another party.

PGS consider that the critical risk factors for the West Toledo prospect are the presence of a sealing fault to control closure and the reservoir effectiveness of the Malubog sands, in particular the validity of the paleo-geographic model to predict sand quality. The overall chance of success for the West Toledo prospect is 11.3 per cent. A number analogous leads have been identified in the vicinity of the West Toledo prospect which would become interesting given success.

The Agojo Prospect

The Agojo prospect lies in the northern part of the Central Tañon Strait, to the northeast of Cebu Island. The trap is a 4-way dip closed structure developed due to wrench movements on a series of approximately north-south trending faults. Closure is defined by five sparse 2D lines and is a north-south elongate dome. The structure has been mapped on the Middle to Upper Miocene Maingit Limestone horizon and has an areal closure of 1,400 acres with a vertical closure of 650 feet. The top of the Maingit Limestone is prognosed to be at a depth of 4,700 ft TVDSS.

The Maingit reservoir in the area has been established by nearby Bakyad-1 drilled in 1978 which encountered excellent reservoir quality and gas shows. As with other prospects located in the Visayan Basin the most probable source beds are within the Lower Miocene and older.

Volumes have been calculated by the Operator but with the limited data available cannot be verified. The potential recoverable reserves are reported to be 60 mm bbls in an oil case and 210 Bscf in a gas case. The key risks associated with the prospect are the presence of a working trap and the presence and effectiveness of the Maingit Limestone reservoir. PGS have assigned a chance of success of 10 per cent. to the Agojo prospect.

The North Bantayan Prospect

The North Bantayan prospect lies in the Bantayan sub-basin of the Visayan Sea. The trap is a fault and dip closed structure located in the footwall of an extensional fault down-throwing to




the east.  A sparse grid of 2D lines define the north-south striking structure. The structure has been mapped on the near top early Miocene approximating to the Cebu Limestone horizon and has an areal closure of 5,000 acres with a vertical closure of 1,800 feet. The top of the Cebu Limestone is prognosed to be at a depth of 7,600 ft TVDSS.

The Cebu Limestone reservoir in the area has been established by nearby Philipino-1. The well encountered a unit believed to be equivalent to the onshore Cebu Limestone. The unit was a thin-bedded fine to medium grained dolomitized limestone. It was generally tight but in places had porosity developed to 10 per cent.

As with other prospects located in the Visayan Basin the most probable source beds are within the Lower Miocene and older.

Volumes have been calculated by the Operator but with the limited data available cannot be verified. The potential recoverable reserves are reported to be 250 mm bbls in an oil case and 1 TCF in a gas case. The key risks associated with the prospect are the presence of a working trap and the presence and effectiveness of the Cebu Limestone reservoir. PGS have assigned a chance of success of 8 per cent. to the North Bantayan prospect.

Conclusions

Both the GSEC-101 (Reed Bank) area offshore Palawan Island previously operated by Sterling, and the SC 40 (Cebu) contract area covering northern Cebu and part of the Visayan Sea each contain confirmed petroleum discoveries, plus an inventory of prospects and leads which are estimated to have a finite chance of containing commercial volumes of hydrocarbons.

The GSEC 101 (Reed Bank) area contains two wells which have successfully tested gas, although at rates which are not sufficiently high to be economic in an offshore environment. When interpreted, a 3-D seismic survey over the Sampaguita gas discovery area, planned to be accomplished during 2005, should provide much improved structural information which can be used as input to future appraisal drilling efforts, and should also assist in the estimation of gas initially in place volumes. The existence of the producing Malampaya Gas Field in the area could provide access to existing gas export infrastructure should commercial volumes of reserves be proved.

The SC 40 (Cebu) contract area also contains proven active hydrocarbon systems. The onshore discoveries are modest in size, and PGS consider that the Libertad Gas Field is marginally economic to develop at the lower reserves estimate assumed by FEI. However, its development should safeguard the other prospects and leads in SC 40 (Cebu) from relinquishment in 2006.

The Central Maya Bulge area requires additional data to be gathered to confirm the nature and extent of the hydrocarbon accumulations encountered by the wells to date, and the proposed reentry and testing of the Forum-2X well should clarify whether or not sustained production at commercial rates is possible from the Maingit and/or Malubog reservoir horizons. From the limited information available, it is likely that the size of any hydrocarbon accumulations in these reservoirs will be modest, and recoveries will be similarly modest. However, onshore operations are relatively inexpensive compared to offshore activities, and the development of small accumulations can be economic at current oil prices.

The prospects within the SC 40 (Cebu) area are predominantly offshore, but of potentially much larger size than the discoveries onshore. Seismic acquisition and exploration drilling costs will be high for such prospects. The chances of success for the best two prospects have been estimated to be around 11 per cent. The chances of success for the identified prospects in SC 40 (Cebu) are not




independent of one another. Failure to discover commercial hydrocarbons in one prospect is likely to reduce the chance of success in the others.

The following table summarises the prospects and discoveries within the two contract areas.

 
Prospect and Discovery Summary  
                       
Prospect   Primary Target
Formation
  Target
Depth ft
  Water
Depth ft
  Chance of
Discovery 1
  Potential Reserves
Oil(mmbbl)/Gas(bscf)
 

 
 
 
 
 
 
Central Tañon   Barili Limestone   3700   650    0.115   265/660  
Jibitnil Island   Maingit   4100   Onshore   0.115   85/450  
    Limestone                  
South   Maingit   6000   100    0.099   70/330  
Guintacan   Limestone                  
West   Maingit   2900   120    0.115   80/185  
Malapascua   Limestone                  
West Toledo 2   Malubog Sand   7500   350    0.113   97/332  
Agojo   Maingit   4700   250    0.1   60/210  
    Limestone                  
North Bantayan   Cebu Limestone   7600   300    0.08   250/1000  
Sampaguita 3   Late Paleocene   10300   260    1    - /2329  
Libertad   Barili Limestone   650   Onshore   1    - /0.5  
CMB 4   Malubog Sand   1500   Onshore   1    0.14/0.64  
                       

1  Prospect chances of success are not independent. Failure to discover commercial hydrocarbons in one prospect is likely to reduce the chance of success in the others.

 
2  As currently mapped, only a small part of these potential reserves may be under SC 40 (Cebu)..
 
3  Potential gas reserves assume a recovery factor of 0.85
 

4  Potential oil reserves are limited to primary recovery. Recovery factors for oil and gas are assumed to be 0.05 and 0.85 respectively.

Property Title and Participating Interest

PGS is not in a position to attest to property title, financial interest relationships or encumbrances related to the properties reviewed in the evaluation.

A full summary of the properties examined in the course of the review is included in the table above. The chances of success estimated for these prospects are not mutually independent; chances for remaining prospects will be impacted by the results from earlier exploration activities.




Professional Qualifications

PGS Reservoir Limited (“PGS”) is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, PGS does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this letter.

This evaluation has been supervised by Mr. J. R. Thompson, Manager of Reserves Evaluations at PGS Reservoir Limited. Mr. Thompson has 31 years of varied petroleum and reservoir engineering experience. He has an MA in Natural Sciences, and is a Chartered Engineer, and a member of the Society of Petroleum Engineers. Other PGS employees involved in this work hold at least a bachelor degree (or its equivalent) in geology, geophysics, petroleum engineering or a related subject and have at least five years’ relevant experience in the practice of geology, geophysics or petroleum engineering.

Basis of Opinion

The evaluation presented in this letter reflects our informed judgements based on accepted standards of professional investigation, but is subject to generally recognised uncertainties associated with the interpretation of geological, geophysical and engineering data. The valuation has been conducted within our understanding of the effects of petroleum legislation, taxation, and other regulations that currently apply to the Forum Energy’s proposed interests in the Philippines.

It should be understood that any evaluation of hydrocarbon resources is subject to government policies and market conditions prevailing at the time of the evaluation. Future changes can cause the total quantities of petroleum recovered to vary from those endorsed in this letter.

This letter as been written for the Directors of Forum Energy plc and its financial advisers, Noble & Company Limited. Information contained in this letter should not be disclosed in part or in whole to third parties without the approval of PGS. Such permission shall not be unreasonably withheld.

 
Yours faithfully
   
For PGS Reservoir Limited.
 
 
Jeremy R. Thompson  M.A., C.Eng., M.I.M.M.
 
Manager of Evaluations



 
Definitions
   
“Petroleum” means oil and/or gas.
“Barrel” or “bbl” refers to a volume of 42 US gallons, or 5.615 cubic feet.
“TD” refers to total depth (of a well).
“TVDSS” refers to true vertical depth sub-sea.
“TOC” means Total Organic Content
“scf” refers to standard cubic feet.
“BThU” refers to British Thermal Units.
 
The prefixes “m” and “mm” refer to thousands and millions respectively.
The prefix “b” as in “Bscf” refers to billions, one billion being 1,000 million (109).
The prefix “T” as in “Tscf” refers to trillions, one trillion being 1,000,000 million (1012).
 
PGS Reservoir Ltd   Tel: +44 1628 641 000   Registered Office:
PGS Thames House   Fax: +44 1628 641 200   PGS Reservoir Limited
17 Marlow Road       PGS Court, Halfway Green
Maidenhead, Berks SL6 7AA    Walton-On-Thames, Surrey KT12 1RS
England       Company Registration: 3177228
        Registered in England & Wales



     
 
 
     
 
Petroleum Interests of Forum Energy Corporation
Location Map of Forum’s Interests in the Philippines
 
   
Figure 1



     
 
 
     
 

Petroleum Interests of Forum Energy Corporation
Lead Location Map – GSEC 101

 
 
Figure 2



     
 
 
     
 
Petroleum Interests of Forum Energy Corporation
Location Map of GSEC 101 and Malampaya Field Gas Export Pipeline
 
 
Figure 3



     
 
 
     
 
Petroleum Interests of Forum Energy Corporation
Prospect Location Map – Service Contract 40 Area
 
 
Figure 4



     
 
 
     
 
Petroleum Interests of Forum Energy Corporation
Structure Map in Depth to Top Barili Limestone, Libertad Gas Field
 
 
Figure 5



     
 
 
     
 

Petroleum Interests of Forum Energy Corporation
Gelogical Map - Maya Area

 
 
Figure 6



     
 
 
     
 

Petroleum Interests of Forum Energy Corporation
Forum-2X “480m Sand”

 
 
Figure 7