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1 8 December 2014 Company Announcements Office ASX Limited 4 th Floor 20 Bridge Street Sydney NSW 2000 Cambay-77H Successful Well Test Commercial development of Cambay Field feasible Oilex Ltd (ASX: OEX, AIM: OEX) is pleased to announce the preliminary results of the flowback and production testing of Cambay-77H. All proof-of-concept objectives have been achieved and the commercial development of Cambay Field using multi-stage frac technology is feasible. Summary Cambay-77H was designed as a Proof-of-Concept well with a short 350m lateral Initial production over a 24 hour period of 2.03MMscfe/d, 55% hydrocarbon liquids An oil to gas ratio ( OGR ) of ~100 bbls per MMscf of gas in the Cambay-77H area remains valid some 250% higher than extrapolated from Cambay-73 Increased OGR adds ~40% revenue per MMscf of produced gas using price assumptions of US$8.00/Mscf and US$70/bbl for gas and oil respectively Total production during flowback and testing 62.3MMscfe Total operations water recovered 23,732 bbls (88%) no formation water has been identified during flowback and testing Managing Director of Oilex, Ron Miller, said; Oilex is very pleased with the results of Cambay-77H flowback and test. With all the proofof-concept objectives having been achieved, a significant milestone has been reached towards creating a profitable and sustainable business. It is also a first step for India, towards improving its domestic petroleum supply by using multiple fracture treatments in horizontal wells that have transformed the energy equation in North America. Oilex is proud of its first mover position, competitive advantage and achievement in initiating development of tight oil and gas using this technology in India. Results The key field results from Cambay-77H flowback and production testing are encouraging. The sustained initial 24 hour rate during flowback was 2.03MMscfe/d, comprising 55% light oil/condensate with concurrent operations water production of 1,867bbls/d. Flowing wellhead pressure was 1,261 psig. Rates are presented in energy equivalents converted at 5,800 scf of gas per bbl of oil because the well was originally designed as a gas and condensate producer. Total hydrocarbon production was 43MMscf of gas and 3,372bbls of light oil/condensate (sold to a local refinery), giving an energy equivalent figure of 62.3MMscfe. The maximum liquid hydrocarbon to gas ratio was 349bbls/MMscf with an average of 77bbls/MMscf, likely governed by the well bore tubular size impacting the flow regime. ABN Level 1, 660 Newcastle Street, Leederville WA 6007 Australia; PO Box 38 Leederville WA 6902 Australia Telephone: (+61 8) Facsimile: (+61 8) oilex@oilex.com.au Web:

2 Cambay-77H Successful Well Test A total of 27,631bbls of operations water (frac water and coil tubing operations water) was used with 23,732bbls, or 88% recovered. The maximum recovery rate was 3,101 bwpd and no formation water was identified during flowback and testing. Use of data Oilex has the first, and currently the only model to be successfully calibrated using actual production and compositional data from a multistage frac d horizontal well in the Cambay Basin. The flowback and production test data has been used to analyse the performance of Cambay- 77H, refine the calibration of the production model used to assess Y zone deliverability, predict ongoing recovery of oil and gas from Cambay-77H, review preliminary well designs and generate forecast type curves for the next drilling campaign. The results clearly indicate recovery of significant volumes of oil and gas can readily be achieved. Importantly, Cambay-77H and the model confirm that the tight Eocene formation in the Cambay Field is amenable to this form of fracture treatment, leading to the conclusion that the Y zone can be commercially developed with this technology. All proof-of-concept activities have been successfully completed and the objectives achieved. A full data package for Cambay-77H is being compiled and combined with other Cambay Field production data for an independent reserves and resource assessment update. This update may result in conversion of some current Contingent Resources to Reserves and the results will be disclosed to the market at that time. Additional information is contained in the Explanatory Note appended to this announcement. For and on behalf of Oilex Ltd Ron Miller Managing Director For further information, please contact: Oilex Ltd Ron Miller, Managing Director oilex@oilex.com.au Tel: Australia Strand Hanson Limited Nominated Adviser and AIM Broker Rory Murphy/Ritchie Balmer oilex@strandhanson.co.uk Tel: UK Tavistock Communications Ed Portman eportman@tavistock.co.uk Tel: UK Qualified Petroleum Reserves and Resources Evaluator statement Pursuant to the requirements of Chapter 5 of the ASX Listing Rules, the information in this report relating to petroleum reserves and resources is based on and fairly represents information and supporting documentation prepared by or under the supervision of Mr. Peter Bekkers, Chief Geoscientist employed by Oilex Ltd. Mr. Bekkers has over 17 years experience in petroleum geology and is a member of the Society of Petroleum Engineers and AAPG. Mr. Bekkers meets the requirements of a qualified petroleum reserve and resource evaluator under Chapter 5 of the ASX Listing Rules and consents to the inclusion of this information in this report in the form and context in which it appears. Mr. Bekkers also meets the requirements of a qualified person under the AIM Note for Mining, Oil and Gas Companies and consents to the inclusion of this information in this report in the form and context in which it appears. 2

3 The technical evaluation of the flowback and test data has been completed by RISC, a specialist oil & gas consulting company, with reservoir engineering personnel experienced in the Canadian Montney tight/shale gas play. The Montney Formation is a major productive unit and possible analogue for the Y Zone reservoir of the Cambay Field due to its hybrid siltstone and shale content. RISC designed the test programme to supplement the flowback data and acquire critical information that could be incorporated into a comprehensive production and deliverability model. Key observations from the analyses of Cambay-77H flowback and test data are: Oil to Gas Ratio (OGR) Analysis of the data confirms that an OGR of ~100 bbls of liquids per MMscf of gas in the Cambay-77H area remains valid. This ratio is 250% higher than expected, which was based upon Cambay-73 performance. The significantly higher OGR has a material positive impact on the revenue stream from future Cambay horizontal wells. Increased OGR adds ~40% revenue per MMscf of produced gas using price assumptions of US$8.00/Mscf and US$70/bbl for gas and oil respectively. The high value and extensive gas market proximal to the Cambay PSC allows the Cambay JV to easily market the gas to accelerate oil production. Dual products, which are readily sold into a premium energy market, cushion the economic impact of one product decreasing in value. The upcoming Independent Reserves and Resource Certification will review this important parameter in the context of Cambay-77H well results. Well Bore Configuration and Frac efficiency Efficient lifting of additional oil to surface can be resolved by appropriately sized production tubulars and/or the use of artificial lift techniques. Artificial lift techniques are common industry practice and already widely used in India. With the appropriately sized tubulars in-place, the calibrated model predicted an initial production rate of 3.2MMscfe/d for Cambay-77H inclusive of the higher OGR. The production test results confirm Frac stim operational data is correct, and all fracs were successfully executed That despite successful execution of the fracs, overall frac efficiency is ~25% according to the calibrated model Partial impairment of the wellbore connection with the reservoir still exists and is currently being investigated That mitigations, including core acquisition, should be incorporated into future well designs Cambay-77H future production The calibrated model forecasts ~360MMscfe to be recovered over ~3 years 3

4 Development Implications for the Cambay PSC Contract Area Cambay-77H results provide a strong foundation for moving forward with development of the Cambay Contract Area and plans for the next drilling campaign are in progress. The longer horizontal wells forming part of the next drilling campaign have been reassessed using the calibrated model and preliminary predictions of gas recovery are robust: 700m lateral with a frac spacing of ~80m is estimated to recover ~3.5Bcf gas in 10 years 1400m lateral with the same frac spacing is estimated to recover ~5.9Bcf gas in 10 years This frac spacing is approximately double that in Cambay-77H and leads to significant cost reduction and risk mitigation Indicative economics for these wells are very robust at current market prices for oil and gas Analysis continues to achieve a suitable production history match for light oil/condensate Reservoir data results The Y zone permeability has been confirmed to be ~0.02mD and within the expected range. This property has now been validated by 3 independent analyses. This permeability is significantly better than classical shale plays in North America. The reservoir pressure of ~4,330 psig has again been validated by the production test. The overpressure has now been confirmed by a minimum of 3 different sources of data providing high confidence of its accuracy. Oil and gas properties Light oil/condensate averaged API 49.4º during the entire flow period. It appears to be light sweet crude but further analysis of the latest samples is required to distinguish oil vs. condensate. Stabilisation is readily achievable via simple separation after which it can be easily transported by truck to local refineries where it attracts a slight discount to Bonny Light crude oil. Laboratory analysis indicates Cambay-77H gas has total inerts of ~3% including CO2 and no H2S has been detected. Both of these results are very positive. The same analysis also reports ~13% of the reservoir stream is Ethane, Propane and Butane (LPG s). Recovery of LPG s for sale as separate products will be evaluated as part of expanding the production from Cambay field. LPG s generally sell at a premium to the price of natural gas on an energy equivalent basis. Subject to further engineering design work, minimal processing is anticipated to make the natural gas suitable for entry into the pipeline grid. 4

5 Key lessons Oil and gas recovery started on the first day of flowback and gas sales during flowback operations in future wells is possible. Planning for integrated flowback and production facilities has commenced to ensure immediate gas sales lead to faster payback. Revenue during Cambay-77H flowback and testing would have been approximately US$750,000 with facilities in-place to sell gas. Acquisition of geotechnical core data from the Cambay-77H area in a future well will form an essential part of the next drilling campaign. Operations to date have been conducted without the benefit of modern core. The detailed core analysis has been found to be very beneficial for optimisation of fracture treatments and production in North America. The Plug and Perf completion method is appropriate for deployment in the Cambay Contract Area. Larger diameter perforations are seen as part of the optimization strategy to minimise impairment of the connection between the reservoir and the well bore. Operations water recovery is likely to be at the high end of expectation and North American experience and large water handling facilities are essential given operations water recovery rates exceeding 3000bwpd from a short 350m lateral section in Cambay-77H. 5

6 LIST OF ABBREVIATIONS AND DEFINITIONS API Associated Gas Bbls BBO BCF BCFE BOE BOPD bwpd Condensate Core Analysis CO 2 A unit of measurement established by the American Petroleum Institute (API) that indicates the density of a liquid. Fresh water has an API density of 10. Natural gas found in contact with or dissolved in crude oil in the reservoir. It can be further categorized as Gas-Cap Gas or Solution Gas. Barrels of oil or condensate. Billion standard barrels of oil or condensate Billion Cubic Feet of gas at standard temperature and pressure conditions Billion Cubic Feet Equivalent of gas at standard temperature and pressure conditions. Barrels of Oil Equivalent. Converting gas volumes to the oil equivalent is customarily done on the basis of the nominal heating content or calorific value of the fuel. Common industry gas conversion factors usually range between 1 barrel of oil equivalent (BOE) = 5,600 standard cubic feet (scf) of gas to 1 BOE = 6,000 scf. Oilex currently uses 5,800 scf = 1 BOE Barrels of oil per day. Abbreviation for barrels of water per day, a common unit of measurement for the daily volume of produced water. A natural gas liquid with a low vapor pressure compared with natural gasoline and liquefied petroleum gas. Condensate is mainly composed of propane, butane, pentane and heavier hydrocarbon fractions. The condensate is not only generated into the reservoir, it is also formed when liquid drops out, or condenses, from a gas stream in pipelines or surface facilities. Laboratory study of a sample of a geologic formation, usually reservoir rock, taken during or after drilling a well. Economic and efficient oil and gas production is highly dependent on understanding key properties of reservoir rock, such as porosity, permeability, and wettability. Geoscientists have developed a variety of approaches, including log and core analysis techniques, to measure these properties. Core analysis is especially important in shale reservoirs because of the vertical and lateral heterogeneity of the rocks. Core analysis can include evaluation of rock properties and anisotropy; organic matter content, maturity, and type; fluid content; fluid sensitivity; and geomechanical properties. This information can be used to calibrate log and seismic measurements and to help in well and completion design, well placement, and other aspects of reservoir production. Carbon dioxide 6

7 Contingent Resources Hydraulic Fracturing OGR H 2S LPG md MSCFD MMscfd MMbbls MMBO MMSCFD MMscfe/d MMscfe PSC psig MD Prospective Resources Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterised by their economic status. Oil to gas ratio in an oil field, calculated using measured natural gas and crude oil volumes at stated conditions. The gas/oil ratio may be the solution gas/oil, symbol Rs; produced gas/oil ratio, symbol Rp; or another suitably defined ratio of gas production to oil production. Volumes measured in scf and bbls. Hydrogen sulphide. An extraordinarily poisonous gas with a molecular formula of H2S. At low concentrations, H2S has the odor of rotten eggs, but at higher, lethal concentrations, it is odorless. H2S is hazardous to workers and a few seconds of exposure at relatively low concentrations can be lethal, but exposure to lower concentrations can also be harmful (Liquefied Petroleum Gas) Gas mainly composed of propane and butane, which has been liquefied at low temperatures and moderate pressures. The gas is obtainable from refinery gases or after the cracking process of crude oil. Liquefied petroleum gas is also called bottle gas. At atmospheric pressure, it is easily converted into gas and can be used industrially or domestically. The term is commonly abbreviated as LPG. (Millidarcy) A darcy (or darcy unit) and millidarcy (md or md) are units of permeability, named after Henry Darcy. They are not SI units, but they are widely used in petroleum engineering and geology. Like other measures of permeability, a darcy has dimensional units in length². Thousand standard cubic feet (of gas) per day Million standard cubic feet of gas per day. Million barrels of oil or condensate. Million standard barrels of oil or condensate Million standard cubic feet (of gas) per day Million standard cubic feet equivalent of gas a day (~172.4 bbls of oil per day using 5,800 scf per bbl) Million standard cubic feet equivalent of gas (~172.4 bbls of oil using 5,800 scf per bbl) Production Sharing Contract pounds per square inch gauge Measured Depth. Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. 7

8 Plug and Perf Reserves SCF/BBL Tight Gas Reservoir Undiscovered in place volume The wellbore for a plug and perf job is generally composed of standard steel casing, cemented or uncemented, set in the drilled hole. Once the drilling rig has been removed, a coiled tubing unit or wireline truck is used to perforate near the bottom of the well, and then fracturing fluid is pumped. Then the coiled tubing unit or wireline truck sets a plug in the well to temporarily seal off that section so the next section of the wellbore can be treated. Another stage is pumped, and the process is repeated along the horizontal length of the wellbore. Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods and government regulations. Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. P90 refers to the quantity for which it is estimated there is at least a 90% probability the actual quantity recovered will equal or exceed. P50 refers to the quantity for which it is estimated there is at least a 50% probability the actual quantity recovered will equal or exceed. P10 refers to the quantity for which it is estimated there is at least a 10% probability the actual quantity recovered will equal or exceed. Standard cubic feet (of gas) per barrel (of oil). The reservoir cannot be produced at economic flow rates or recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores. Is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered 8