Empyrean Regulatory News (EME)

3 Jun 2008 14:42



Empyrean Energy PLC 

("Empyrean" or the "Company"; Ticker: (EME))

Final Results

For the period 1 April 2007 to 31 March 2008

Chairman's Statement

It is with pleasure that I am able to report that Empyrean Energy Plc ("Empyrean" or "the Company") is entering a new and exciting phase in its development. Since the last AGM held in May 2007, we have continued to concentrate on projects within politically stable regions. 

A major discovery was confirmed in April 2008 at the Sugarloaf Project in Texas, USA.  Empyrean is part of this discovery and has been able to increase its interest in this project where further upside exists. Appraisal wells continue to reduce uncertainty, and two deeper potential pay zones provide exceptional upside potential should flow rates respond well to the completion techniques presently being implemented by the two operators.

The confirmed discovery at the TCEI JV Block A-3 well is supported by the unexpected flow at the TCEI JV Block A-1 well, prior to it being fracture stimulated. Since these initial flows, the TCEI JV Block A-1 well has been fracture stimulated successfully resulting in spectacular commercial flow rates. There are three further wells at the Sugarloaf Project, which are drilled to total depth, but are yet to be tested. The flows from the Block A wells have come from the shallowest of three potential pay zones, and the two deeper zones could provide significant upside. The operator currently expects a further 39 wells to be drilled on Empyrean's acreage based on the uppermost productive zone alone, resulting in a 44 well development case. Empyrean's net recoverable production is estimated to be at least 32.5 bcfe ("billions cubic feet equivalent"), valued (at today's oil and gas prices) at circa US$325m.

In addition to this success, the 6 well programme at the Margarita Project has resulted in four discovery wells being completed for commercial production, and three of those wells remain in production today providing useful cashflow. 

Empyrean also retains a 38.5% interest in the Eagle Oil Pool Development Project, which has very attractive potential oil and gas reserves. The operator of this project is in the process of farming out its interest in the project and Empyrean looks forward to a fresh well being drilled on the project when the operator's farm-out negotiations are resolved.

Empyrean's initial project, the Glantal Project in Germany, remains an exciting opportunity with multi TCF gas potential. We have been considering with Pannonian International Ltd, the operator, the relative merits of a seismic acquisition programme focussed either on Glantal or the related Lautertal structure, or of drilling another well on one or other of these structures without further seismic. It has been our recommendation to conduct further seismic over the Lautertal prospect prior to drilling. 

Overall Empyrean has maintained the momentum that has characterised its operations since its commencement in 2005. We continue to focus on geopolitically stable regions. Our projects are close to existing infrastructure and markets, enabling discoveries to be brought into profitable production very quickly. The strategy of using Joint Ventures has provided access to extensive technical data sources relatively cheaply, and Empyrean's experienced management team has demonstrated an ability to identify, evaluate and negotiate substantial energy projects efficiently. We have also chosen projects with drill ready targets, such that there has been drilling programmes soon after negotiating our interest in projects. The management and staff remain dedicated to growing Empyrean into a substantial player in the oil and gas sector while keeping overhead costs to a minimum to generate maximum value for shareholders.

With a portfolio of projects which balance risks and rewards, and which now includes a major discovery with substantial upside, the existing strategy of seeking additional attractive opportunities will continue to be followed with vigour. The next year will see Empyrean move into substantial production and onto the next step of the growth ladder. It will be an even more exciting time than we have experienced so far!

Patrick Cross

Chairman

Operations Report

Empyrean Energy Plc ("Empyrean" or "the Company") is at present involved in four projects, with a fifth project being drilled during the year being abandoned. Four of these were located onshore in the USA, with one in onshore Germany. The last 12 months have seen a continuation of the operational momentum that has characterised the progress of Empyrean since its inception in July 2005. Empyrean brought its first project into production in 2007 with discovery success at the Margarita Project in Texas providing modest but useful cashflow. More recently Empyrean has confirmed it is part of a major gas/condensate discovery at the Sugarloaf Project, located in onshore Texas. It is towards this play that Empyrean has been directing a greater part of its focus of late. 

The operational momentum of Empyrean is manifest in the increased working interest it has been able to negotiate after consummating a second farm-in agreement with Houston based Texas Crude Energy Inc ("TCEI"). This second farm-in agreement is over an area divided into Blocks A and B. Empyrean started with a 6% working interest in the whole of Block B acreage, and subsequently drilled the Sugarloaf-1 well. The additional farm-in covers the next 16 wells to be drilled on either Block A or B, after Sugarloaf-1. The deal earns Empyrean a 7.5% working interest where these wells are drilled on Block A and an additional 12% working interest where these wells are drilled on Block B (i.e. the original 6% plus a further 12% resulting in 18%). Following the successful flow testing of two wells on Block A, a drilling programme is being designed to appraise and develop this exciting new field that has been named the Sugarkane Field.

Horizontal drilling is proving to be the preferred option to optimise completion in these types of limestone reservoirs because it ensures both increased recovery factor and enhanced productivity.

Just recently, on 14 April 2008, Empyrean was able to announce for the first time that an un-stimulated flow rate of 6.6 mmcfgepd ("million cubic feet of gas equivalent per day") and subsequent increase in flow rate to 7.8 mmcfgepd had been measured at TCEI JV Block A-3, the third well assigned to Block A in the 16 well deal. This news was followed by the unexpected flow of the TCEI JV Block A-1 well prior to it being fracture stimulated at a rate of 2.0 mmcfgepd. Further excitement and de-risking of the project came with the news that following a successful fracture stimulation the flow rate at the TCEI JV Block A-1 well had increased by a factor of 6 times to approximately 12 mmcfgepd. These initial test results augur well for the remaining wells already drilled in Blocks A and B which have yet to be tested and which have all given encouraging hydrocarbon shows during drilling.

In the meantime, the Margarita Project onshore Texas has continued to generate revenue from the 3 shallow producing wells where Empyrean has a 44% working interest. The option to participate in the drilling of a "Deep Prospect" under the same Margarita farm-in terms has not been exercised to date. Instead, Empyrean elected to participate in what it considered to be a more attractive deep play being offered under more favourable terms by Texon Petroleum Limited, a recently created oil exploration company active in the USA.

The following provides a more detailed update on each of the projects in which Empyrean has been involved with during the year.

Glantal Gas Project, Germany (Empyrean Interest 40%)

Following the results of Glantal -1, the operator Pannonian International Ltd ("Pannonian") and Empyrean had to decide which of the following alternatives offered the best opportunity to properly assess the play.

The perceived alternatives were:

a) drill a second well updip of Glantal -1 without acquiring further seismic;

b) proceed with a seismic acquisition programme focussed on the Glantal area;

c) embark on a seismic acquisition programme focussed on the Lautertal structure to the east; or

d) drill Lautertal without further seismic.

The third option was finally decided upon after much consideration. It was agreed that the same high maturation readings encountered at Glantal-1 risked being encountered in an updip well (Poltzberg Anticline).  And even though the Glantal prospectivity remains intact, Lautertal presented a more attractive potential target. The results of the 2D vibroseis seismic programme of approximately 125 km, will need to be analysed prior to choosing locations for drilling at Lautertal.

Eagle Oil Pool Development Project, California, USA (Empyrean Interest 38.5%)

Since mid 2007, the operator Victoria Petroleum Ltd  ("VicPet") has been attempting to reduce its interest in the project and find a replacement for its operatorship. This development has been the result of a VicPet internal corporate decision, and in no way reflects a change in perception of the prospectivity of the Eagle Oil Pool project. 

It still has not been decided by partners whether the Eagle North-1 will be re-entered and sidetracked to test the 177m of Lower Mary Bellocchi Gatchell oil sand or whether a new well should be drilled in close vicinity. It would currently be Empyrean's intention to participate in the drilling of a new well. Empyrean currently holds a 38.5% interest in the project and awaits results of negotiations with the potential new operator. 

Margarita Project, Gulf Coast Texas, USA (Empyrean Interest 44%)

Empyrean farmed into this project in November 2006. It earned a 44% Working Interest by its participation in the drilling of 6 shallow wells that were drilled in two phases of 3 wells each.

The results of phase one were reported in the 2006/2007 Annual Report.

Milagro, the second well drilled in phase one, commenced gas sales on 3 April 2007 and peaked at 532 mcfgpd ("thousand cubic feet of gas per day") with 2 bopd ("barrels of oil per day"), up from an initial rate of 350 mcfgpd. In September 2007 production from this well became oil dominant peaking at 135 bopd with 62 mcfgpd. Since the end of October 2007 it has been producing oil only and production has been choked back to approximately 40 bopd and 25 bwpd ("barrels of water per day").

Dos Dedos, the third well drilled in phase one, commenced gas production in late April 2007 and reached a peak of 420 mcfgpd during the following month when problems began to arise. In June 2007 the well had watered out prematurely having produced only 2.1 million cft ("cubic feet") of gas. 

Phase two involved the drilling of 3 wells Dona Carlota, Agavero and Climaco, which resulted in two commercial gas discoveries.

Dona Carlota:

Dona Carlota was drilled to a total depth 1,524m and showed a net gas pay of 5.6m in the primary target Frio sands. On completion and cleanup the well flowed 1.024 mmcfgpd ("million cubic feet of gas per day") with no water. A calculated Absolute Open Flow Rate of 20.5 mmcfgpd day attests the excellent gas deliverability potential of the reservoir. The well is at present producing approximately 900 mcfgpd.

Agavero:

Agavero was drilled to a total depth of 1,341m and intercepted gas filled Frio sands over a 5.5m interval. On completion and clean up the well flowed 707 mcfgpd with no water and was then shut in awaiting permission for a tie in pipeline. Gas production commenced on 4 October 2007 at 375 mcfgpd and is at present producing approximately 300 mcfgpd. 

Climaco:

Climaco reached a total depth of 1,858m and despite having good gas shows in the primary objective, was plugged and abandoned as a non-commercial gas well.

Phase 2 drilling was concluded in early August 2007 with 2 out of the 3 wells proving commercial quantities of gas. Overall, the 6 well programme was highly rewarding for Empyrean as it resulted in gas being discovered in all 6 wells. 4 wells were originally completed for commercial production, and only one of these, Dos Dedos, terminated because of water production problems. This premature termination was compensated by the Milagro well transforming into an oil producer only 5 months after commencing as a gas producer. 

Texon Farm-in, Texas, USA (Empyrean Interest 15%)

The Bondi prospect was considered to have the possibility of containing estimated gas reserves of between 30 and 76 billion cft, based on 3D seismic character and empirical data from nearby fields.

The target was the prolific Upper Wilcox Formation and the original total depth was 13,500 ft. Raun#1 was spudded in early November 2007 and halted at 12,500 ft because no obvious lithological or petrophysical anomalies were found which correlated with the seismic bright spot. In fact, because the sediment velocities were much slower than anticipated at the well, the bright spot actually fell within a thick Jackson Shale section. Two potential gas-bearing sands with a total thickness of 50 ft were tested, but to no avail, and the well was finally plugged and abandoned in February 2008.

Empyrean retains the right to participate in any wells drilled by Texon Petroleum Limited at a 15% working interest anywhere in the area of mutual interest of approximately 25 km2.

Sugarloaf Hosston Project, Texas, USA (Empyrean Interest between 6%-18%)

The original farm-in agreement with TCEI was announced by Empyrean on 6 April 2006. Although the Sugarloaf-1 well was successfully drilled to a total depth of 20,896 ft, the primary objective reservoir, the Hosston sandstones, proved to have insufficient permeability to provide economic gas production.

However, significant gas shows and fluorescence were encountered higher in the section in the secondary objective. Electric log analysis indicated the presence of a 92 ft gross column of gas in fractured limestones of the Austin Chalk.

The gas discoveries in this carbonate reservoir had two immediate effects. Firstly, the operator increased the land acquisition programme within the area of mutual interest (which stood at approximately 19,500 acres in April 2007); and secondly, it activated negotiations which resulted in the conclusion of a second farm-in agreement between Empyrean and TCEI.

This second agreement involved the division of the prospective area into Blocks A and B and pertained only to the next 16 wells to be drilled on Blocks A or B (subsequent to Sugarloaf-1). TCEI remains the operator in Block B. A major oil and gas company (name undisclosed for confidentiality purposes and to protect competitive advantage) is the operator in Block A. In Block B, which contains Sugarloaf-1, Empyrean had already earned a 6% working interest in Sugarloaf-1 and wells drilled thereafter in Block B. Under the terms of the second agreement announced on 10 May 2007, Empyrean earns a further 12% in Block B for each well drilled after Sugarloaf-1. 

In Block A Empyrean earns 7.5% under the terms of the new farm-in agreement. 

These respective interests will be earned by Empyrean only in wells drilled in Blocks A and B which form part of the 16 well deal. The results to date are as follows.

BLOCK B

Sugarloaf-1 Well (Empyrean Interest 6%)

Remedial cementation was required prior to the fraccing operations of the lower part of the gas-bearing chalk interval in which there are at least three separate intervals of enhanced porosity development. Testing operations began on 11 September 2007.

The first fracc attempt was unsuccessful due to premature screen out of the proppant with only 6% entering the formation; all of which required redesigning a second fracc attempt which was executed on 19 October 2007.

Despite initial gas flows of 387mcfgpd with associated condensate, the flow rate declined. Following the completion of swabbing operations and the setting of production tubing, the well was shut in until results from wells already being drilled and tested in Block A could be used to modify the continued testing programme of the remaining porous zones of the Austin Chalk. 

Kennedy-1H Well (Empyrean Interest 6% - 12%)

This well was originally called Sugarloaf-2 and is the second well to be spudded in the 16 well deal mentioned above. It is located 1.6 km from Sugarloaf-1 well. The zone targeted in the horizontal section of approximately 5,000 ft of Austin Chalk reservoir is believed to correlate with the producing section in the Sugarkane Field discovery well located 8 km to the west of Kennedy-1H well.

Backround gas readings increased significantly on entering the Austin Chalk. 

The rig was released on 8 December 2007 following the emplacement of a 4 ½" liner in the horizontal part of the well. On 15 February 2008 it was announced that fraccing and testing procedures were necessarily dependent on the results of the operations in the adjacent Block A, and it was not until 16 April 2008 that Empyrean received notification of the details of the final completion programme. 

The fraccing operation was carried out on 14 May 2008. A total of 95,000 lbs of sand and 5182 barrels of fluid were injected under pressure into four sets of perforations over an approximate 600ft horizontal interval. Initial flow results of gas condensate and fracc fluid recovery were announced on 25 May 2008, and since then the well has been slowly expelling the fracc fluids prior to the measuring of full gas condensate flow.

 The result is particularly relevant to the overall prospectivity of the area as it has shown that the so-called "middle pay zone" contains gas condensate and could therefore add 150% to the recoverable reserves attributed to the "upper pay zone".

As of 29 May 2008 the plan was to run pressure gauges while the well was continuing to flow, then shut in the well for a prolonged pressure build up. There still remained approximately 4,120 barrels of fracc fluid to recover.

BLOCK A

TCEI JV Block A-1 Well (Empyrean Interest 7.5%)

TCEI JV Block A-1, a horizontal appraisal well, was spudded on 22 May 2007.

Two sidetrack operations were required to get the well to total depth. A total depth of 14,586 ft (measured depth) was finally reached on 29 August 2007. 

Gas shows were encountered over the whole horizontal length of approximately 2,500 ft. Multiple gas flares measuring up to 65' were recorded over approximately a 1,000 ft horizontal length, including an interval of about 600 ft that produced a constant gas flare.

A 4 ½" liner was cemented to 14,586 ft on 3 September 2007 which again was an operation not without its problems. Fraccing and testing operations were put on hold until the adjacent the TCEI JV Block A-2 well could be made available for seismic monitoring purposes. This technique enables the operator to determine the efficacy of the fracc operation at the TCEI JV Block A-1 well. The first attempt to fracc on 13 December 2007 resulted in the fracc being unable to be injected into the reservoir, as did a second attempt on 20 December 2007. Sufficient injection rates required to fracc could not be achieved without exceeding the 7" casing limitations, and on 17 January 2008 Empyrean announced that 4 ½" casing was being tied to the top of the liner and being run to surface to enable higher injection pressures. Three further attempts to pump the fracc sand to the reservoir under high pressure were unsuccessful.

The operator made the decision to shut down the well on 9 Feb 2008 and initiate a detailed reservoir engineering post-mortem which includes a 3-D simulation study. This study was performed to re-evaluate the options on offer.

Operations recommenced on site on 14 April 2008. On 21 April 2008 Empyrean announced to shareholders that "the well unexpectedly began to flow commercial quantities of gas and condensate during operations to prepare the well for a fracture stimulation and flow test programme". Initial flows of 2.0 mmcfepd were measured which increased to 2.4mmcfepd before the well was shut in to obtain pressure build up measurements. 

An acid fracc was successfully completed over a 900ft horizontal interval through five sets of perforations on 28 May 2008.

TCEI JV Block A-2 Well (Empyrean Interest 7.5%)

The operation resulted in a six fold increase in deliverability. On 28 May 2008 Empyrean was able to report an average gas flow of 2.5mmcfgpd accompanied by 950 bcpd and no water through a 14/64" choke. This equates to approximately 12 mmcfgepd based on present gas and condensate prices. 

On the same day the well was shut in to measure pressure build up as part of the normal reservoir and production engineering procedures. This well already has a sales line connected to it enabling all production to be sold soon after flowing.

TCEI JV Block A-2 well, located between the Sugarkane discovery well and the TCEI JV Block A-1 well, is the third well to be drilled in the 16 well deal. It is a vertical well and may test any of the three Austin Chalk intervals that were intercepted at Sugarloaf-1 well.

The TCEI JV Block A-2 well was spudded on 16 August 2007 and was in fact a re-entry of a well previously drilled in 2006. In that well an electric wireline tool had become stuck permanently and the TCEI JV Block A-2 was designed to avoid the fish by drilling a directional leg. 

A total depth of 12,084 ft was reached and 5 ½" production casing set at 12,068 ft. Since then the well has been used to monitor fraccing operations in the TCEI JV Block A-1 well located to the south. During drilling, the gas backround increased to 350 units in the Austin Chalk and this zone will be fracced and tested, most likely after operations at the TCEI JV Block A-1 are completed.

TCEI JV Block A-3 Well (Empyrean Interest 7.5%)

The TCEI JV Block A-3 well is the fourth well in the 16 well deal and the third located in Block A in which Empyrean is a participant. It lies southwest of the TCEI JV Block A-1 well and has as its target the same producing interval of the Austin Chalk that was intercepted at the Sugarkane No1 well gas-condensate discovery.

The well was spudded on 24 October 2007 and on 12 November 2007 reached a total depth of 12,457 ft in an 8 ½" vertical pilot hole. Gas shows over a 185 ft interval rose to a maximum of 350 units, almost 10 times the backround. After electric logs were run the well was kicked off at 11,480 ft to begin horizontal drilling in the Austin Chalk reservoir. A 7" casing shoe was set at 12,272 ft. 

During the horizontal drilling operation, three sidetracks were made to precisely target high permeability pay zones. The third and final sidetrack spanned 13,230 to 15,100 ft. Significant shows and flares were recorded while drilling the entire 2,800 ft of open hole. The well continually tried to flow despite the high mud weights being used. This persuaded the operator to stop drilling at 15,100 ft, short of the original 17,800 ft, and attempt a natural open hole test. A plug was set at the base of the 7" casing and the rig released and replaced by a smaller and less expensive workover rig.

Workover operations commenced on 29 January 2008. The operator was forced to leave in the open hole a fish made up of a length of 2 7/8" tubing and a 5 7/8" rock bit. It is permanently lodged in the horizontal part of the open hole in the interval 12,676 ft to 13,097 ft.

On 2 April 2008 a production packer was emplaced in the 7" casing at 11,720' to begin the open hole testing procedure. On 14 April 2008, Empyrean was finally able to announce the initial test results of a significant gas-condensate discovery. Initial flows through a 12/64" choke were measured at 1.9mmcfgpd with 460 barrels of condensate per day. Based on present day prices for gas and condensate this would be equivalent to 6.6 mmcfepd. 

This open hole test has been conducted without stimulation. It compares favourably with other similar fields in the region which exploit the Austin Chalk. The Brookeland Field in Tyler County, for example, has an approximate equivalent rate of 1.4 mmcfepd ("million cubic feet of equivalent per day") per thousand feet of horizontal. The TCEI JV Block A-3 well produces comparatively at 2.4 mmcfepd. A typical well for one operator in the Brookeland Field has approximately 12,000 ft of horizontal with average initial rates of over 16 mmcfepd. The TCEI JV Block A-3 well provides evidence that longer horizontal completions targeting the natural fracture swarms that exist intermittently in the reservoir should result in even better deliverability.

The TCEI JV Block A-3 well will be flow tested then shut in as part of the normal reservoir and production engineering procedure. During the shut in period the operator will be supervising the construction of production facilities and pipeline connection. Condensate will be separated in situ and trucked to the appropriate markets.

FJ Brophy BSc (Hons)

Technical Director

Empyrean Energy Plc

2 June 2008

Income Statement for the year ended 31 March 2008

All financial results presented are from continued operations.

No dividends were proposed or paid during the period. 

A separate Statement of Recognised Income and Expense is not required.

Balance Sheet as at 31 March 2008

Cashflow Statement for the year ended 31 March 2008

Statement of Changes in Equity for the year ended 31 March 2008

Statement of Accounting Policies for the year ended 31 March 2008

The financial statements of Empyrean Energy Plc for the year ended 31 March 2008 were authorised for issue by the Board on 2 June 2008 and the balance sheets signed on the Board's behalf by Mr Patrick Cross and Mr Thomas Kelly.

The Company's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union. The principal accounting policies are summarised below. They have all been applied consistently throughout the year.

Basis of accounting

These financial statements have been prepared under the historical cost convention, modified for certain items carried at fair value, in accordance with International Financial Reporting Standards and IFRIC interpretations and with those parts of the Companies Act, 1985 applicable to companies reporting under IFRS. 

The financial report is presented in Sterling and all values are shown in pounds (£).

Going concern

The financial statements have been prepared on a going concern basis.

Adoption of new and revised International Financial Reporting Standards

The following new standards, amendments and interpretations to existing standards have been published, which are mandatory for the Company's accounting periods beginning on or after 1 January 2008, which the Company's has not early adopted:

IFRS 8, "Operating Segments" (effective for accounting periods beginning on or after 1 January 2009).

IAS 23 (Amendment), "Borrowing Costs" (effective for accounting periods beginning on or after 1 January 2009). 

IAS 1 (Amendment), "Presentation of Financial Statements" (effective for accounting periods beginning on or after 1 January 2009).

IFRS 3(Amendment), "Business Combinations" (effective for accounting periods beginning on or after 1 July 2009). 

IFRS 2 (Amendment), "Share-Based Payments: Vesting Conditions and Cancellations" (effective for accounting periods beginning on or after 1 January 2009). 

The following new standards, amendments and interpretations to existing standards have been published, which are mandatory for the Company but will not impact on the Company's financial statements or are not relevant:

IFRIC 8, "Scope of IFRS 2" (effective for accounting periods beginning on or after 1 January 2007).

IFRIC 9, "Reassessment of embedded derivatives" (effective for accounting periods beginning on or after 1 January 2007).

IFRIC 10, "Interim Financial Reporting and Impairment" (effective for accounting periods beginning on or after 1 January 2007).

IFRIC 11, IFRS 2 - "Group and Treasury Share Transactions" (effective for accounting periods beginning on or after 1 March 2007).

IFRIC 12, "Service Concession Arrangements" (effective for accounting periods beginning on or after 1 January 2008).

IFRIC 14, IAS 19, "The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction" (effective for accounting periods beginning on or after 1 January 2008). 

IFRIC 13, "Customer Loyalty Programmes" (effective for accounting periods beginning on or after 1 July 2008). 

IAS 32 (Amendment), "Financial Instruments: Presentation" and IAS 1, "Presentation of Financial Statements - Puttable Financial Instruments and Obligations Arising on Liquidation" (effective for accounting periods beginning on or after 1 January 2009).

IAS 27 Amendment, "Consolidated and Separate Financial Statements", (effective for periods beginning 1 January 2009). 

Revenue Recognition

Net revenues from crude oil and natural gas sales are recognised when the oil and gas has been lifted and the risk of loss transferred to a third-party purchaser. The Company uses the entitlement method to account for its revenue from sales of crude oil and gas production, which is presented in the accounts as net of production expenditure incurred prior to the product receipt by a third-party purchaser.

Finance Revenue

Finance Revenue is recognised as interest accrues.

Cash and cash equivalents

Cash and short-term deposits in the balance sheet comprise cash at bank and in hand and short-term deposits with an original maturity of three months or less.

For the purposes of the Cash Flow Statement, cash and cash equivalents consist of cash and cash equivalents as defined above, net of outstanding bank overdrafts.

Deferred tax

Current tax assets and liabilities for the current and prior periods are measured as the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantially enacted by the balance sheet date.

No deferred tax asset has been recognised because there is insufficient evidence of the timing of suitable future profits against which they can be recovered.

Foreign currencies

Transactions denominated in foreign currencies are translated into sterling at contracted rates or, where no contract exists, at average monthly rates. Monetary assets and liabilities denominated in foreign currencies which are held at the year-end are translated into sterling at year-end exchange rates. Exchange differences on monetary items are taken to the Income Statement.

Trade and other receivables

Trade receivables, which generally have 30 day terms, are recognised and carried at original invoice amount less any allowance for any uncollectible amounts.

Trade and other payables

Trade payables and other payables are carried at amortised cost and represent liabilities for goods and services provided to the company prior to the end of the financial year that are unpaid and arise when the company becomes obliged to make future payments in respect of the purchase of these goods and services.

Tangible fixed assets

Tangible fixed assets are included in the balance sheet at cost, less accumulated depreciation and any provision for impairment. Tangible fixed assets are depreciated on a straight line basis at rates sufficient to write off the cost, less estimated residual values, of individual assets over their estimated useful lives.

Office systems, equipment and furniture: 2.5 - 6 years

Intangible Fixed Assets

 - exploration and development expenditure

Exploration, evaluation and development expenditure incurred is accumulated in respect of each identifiable area of interest. Restoration, rehabilitation and environmental costs necessitated by exploration and evaluation activities are expensed as incurred and treated as exploration and evaluation expenditure. These costs are only carried forward to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage which permits reasonable assessment of the existence of economically recoverable reserves. Accumulated costs in relation to an abandoned area are written off in full against the profit in the year in which the decision to abandon the area is made.

A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward the exploration and development costs in relation to that area of interest.

- oil and gas properties

Investments in unevaluated properties and development projects are not reclassified from exploration and development expenditure to oil and gas properties, until commercial production associated with the projects can be determined or until impairment occurs. The capitalised costs of intangible oil and gas assets are subject to amortisation when they are determined to have commercial production, at which point the capitalised costs plus the estimated future costs to develop the underlying commercial reserves are amortised using the unit-of-production method using total estimated reserves. 

Judgements and estimates

The Group makes judgements and assumptions concerning the future that impact the application of policies and reported amounts. The resulting accounting estimates calculated using these judgements and assumptions will, by definition, seldom equal the related actual results but are based on historical experience and expectations of future events. The judgements and key sources of estimation uncertainty that have a significant effect on the amounts recognised in the financial statements are discussed below.

- impairment of assets

Financial and non-financial assets are subject to impairment reviews based on whether current or future events and circumstances suggest that their recoverable amount may be less than their carrying value. Recoverable amount is based on a calculation of expected future cash flows which includes management assumptions and estimates of future performance.

- share-based payments

Certain Directors of the Company receive remuneration in the form of equity-settled share-based payment transactions, whereby services are rendered in exchange for rights over shares ("equity-settled transactions").

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted. The fair value is determined using the Black-Scholes pricing model, further details of which are given in Note 5 to the Financial Statements. 

The cost of equity-settled transactions with parties other than employees is measured at the fair value of the services received at the date of receipt, with a corresponding increase in equity.

Financial instruments

The Company's financial assets consist of current account or short-term deposits at variable interest rates, loans and other receivables. 

Any interest earned is accrued and classified as interest. 

Trade and other receivables are stated at cost.

The Company's financial liabilities consist of trade and other payables. All are non-derivative assets. The trade and other payables are stated at cost. 

Notes to the Financial Statements for the year ended 31 March 2008

1. Turnover and Segmental Analysis

The primary segmental reporting format is determined to be the geographical segment according to the location of the asset. The Directors consider the Company to have a single business being the exploration for, development and production of oil and gas properties.

There are three geographical segments being Continental Europe and North America which are involved in exploration and production, and the United Kingdom which is where head office is located.

2. Operating Loss

The operating loss is stated after charging:

3. Interest Receivable

4. Staff Costs (including Directors)

The Company had no employees during the year, other than Directors. 

The Company's equity-settled share based payments comprise incentive options granted to the Company's Directors. The amount and details of share options subject to equity-settled share based payments are set out in Note 14. 

Options were issued to Directors and Employees on 28 June 2007 and 27 February 2008. The fair value of the options issued has been fully expensed during the year, based on a Black-Scholes model. 

Under this model options issued on 28 June 2007 assumed a risk free rate of 4.75% and expected volatility of 60%. The value per option was 11.16 pence. Options issued on 27 February 2008 assumed a risk free rate of 4.71% and expected volatility of 60%. The value per option was 5.07 pence. There are no performance measures attached to either option issue.

In addition 50,000 options exercisable at 50 pence, expiring on 31 October 2009, were cancelled due to an employee ceasing employment with the Company, resulting in a write back of £6,536.

5. Directors' Emoluments

(1) Services provided by F J Brophy Pty Ltd 

(2) Services provided by Apnea Holdings Pty Ltd. 

No pension benefits are provided for any Director. 

The Executive Directors are remunerated for consultancy services provided to the Company in relation to its exploration operations as disclosed above. These payments are capitalised to exploration expenditure as set out in Note 8. 

Malcolm James was a director of Claridge House Services Limited, for which there is a contract for the provision of administrative and office services to the Company.

At 31 March 2008, consultancy fees and expenses totalling £15,633 were payable to Frank Brophy, as included in accounts payable at Note 12.

Directors' Share Options

The interest of Directors in office during the year ended 31 March 2008 were as follows: 

6. Taxation

No deferred tax asset has been recognised because there is insufficient evidence of the timing of suitable future profits against which they can be recovered.

Tax losses of approximately £2,734,000 (2007: £1,480,000) are available to be claimed going forward, which are inclusive of the exploration expenditure impairment write off of £830,000 (2007: nil).

7. Loss Per Share

The basic loss per share is derived by dividing the loss for the year attributable to ordinary shareholders by the weighted average number of shares in issue.

As the inclusion of the potential ordinary shares would result in a decrease in the loss per share they are considered to be anti-dilutive and, as such, a diluted loss per share is not included.

8. Intangible Assets

(1) During the period ended 31 March 2008, exploration expenditure of £830,000 was written off due to impairment. This included a £525,000 write off for the Raun#1 well, Bondi Prospect, Texas which the Directors determined had no obvious lithological or petrophysical anomalies after having tested two zones. This well was plugged and abandoned in February 2008. In addition two wells at the Margarita prospect, Texas (El Viejito well and Climaco well) were plugged and abandoned after testing resulted in no commercial oil discoveries, resulting in a £305,000 exploration impairment write off.

9. Oil and Gas Properties

10. Plant and Equipment

11. Trade and Other Receivables

12. Trade and Other Payables

13. Reconciliation of Operating Loss to Operating Cash Flows

14. Called Up Share Capital

The authorised share capital of the Company and the called up and fully paid amounts at 31 March 2008 were as follows:-

On 27 July 2007 a further 949,524 shares were allotted for cash on exercise of warrants over ordinary shares of 0.2p at a price of 35p per share.

Share Options and Warrants

The following equity instruments have been issued by the Company and have not been exercised at 31 March 2008:

During the year 223,809 warrants exercisable at 35 pence, expired on 27 July 2007. In addition 50,000 options exercisable at 50 pence, expiring on 31 October 2009, were cancelled due to an employee ceasing employment with the Company.

15. Commitments

As at 31 March 2008, the Company had no material capital commitments.

16. Related Party Transactions

Other than those disclosed in Note 5 there were no other related party transactions during the year.

17. Financial instruments

The Board of Directors determine, as required, the degree to which it is appropriate to use financial instruments to mitigate risk. Current the Company's principal financial instruments comprise cash. Together with the issue of equity share capital, the main purpose of these is to finance the Company's operations. The Company has other financial instruments such as short-term receivables and payables which arise directly from normal trading.

The Company has not entered into any derivative of other hedging instruments.

The main risk affecting the groups financial instruments are interest rate risk, foreign currency risk and liquidity risk, which are discussed below. 

Throughout the period ending 31 March 2008 no trading in financial instruments was undertaken (2006: nil).

There is no material difference between the book value and fair value of the Company cash balances, short-term receivables and payables.

Interest rate risk

The Company finances its operations through the use of cash deposits at variable rates of interest for a variety of short-term periods, depending on cash requirements. These rates are reviewed regularly and the best rate obtained in the context of the Company's needs. Short-term receivables and payables are not exposed to interest rate risk.

Currency risk

The Company has potential currency exposures in respect of items denominated in foreign currencies comprising transactional exposure in respect of operating costs and capital expenditure incurred in currencies other than the functional currency of operations.

At times the Company may hold cash deposits in foreign currency to meet needs of commitments required for international operations. 

Liquidity risk

The Company's policy throughout the year has been to ensure that it has adequate liquidity by careful management of its working capital. Amount held at bank amounted to £ 1.5 million (2006: £4.9 million).

Capital

In managing its capital, the Company's primary objective is to maintain a sufficient funding base to enable the Company to meet its working capital and strategic investment needs. In making decisions to adjust its capital structure to achieve these aims, through new share issues, the Company considers not only its short-term position but also its long-term operational and strategic objectives.

18. Post Balance Sheet Date Events

On 28 May 2008, the Company announced that following fracture stimulation testing at the TCEI JV Block A-1 well on Block A at the Sugarloaf Project in Texas, the well had spectacular condensate and gas flows. The reports showed that well was flowing at an average rate of over 950 barrels of condensate with an average rate of over 2.5 million cubic feet of gas being an equivalent of around 12 million cubic feet equivalent gas per day.

On 27 May 2008, the Company announced that after production tubing has been successfully installed in the Kennedy #1 well on Block B at the Sugarloaf Project in Texas, the well has been flowed and placed back on well test flowed gas and condensate from a new pay zone which was 120 feet thick versus 80 feet thick upper zone already producing from two wells in Block A. This new pay zone had the potential to more than double the potential recoverable reserves from the project

On 17 April 2008, the Company announced that flow rates at the TCEI JV Block A-3 well on Block A at the Sugarloaf Project in Texas, had increased by approximately 20% since testing began to the most recent rate of 7.8 million cubic feet of gas equivalent per day, without stimulation. Condensate is making up over 70% of the flow in terms of value, and with the oil price reaching record highs this condensate to gas ratio is healthy for the economics of the project.

For further information 

Empyrean Energy plc 

Tel: +44(0) 207 182 1746 

Rod Venables / Cecil Jordaan 

HB Corporate 

Tel: +44(0) 207 510 8600 

Jonathan Charles / Ed Portman 

Conduit PR 

Tel: +44 (0) 207 429 6611 / +44 (0) 7791 892 509