Empyrean Regulatory News (EME)

Empyrean Energy Plc / Index: AIM / Epic: EME / Sector: Oil & Gas

8 September 2014

Empyrean Energy PLC ('Empyrean' or 'the Company')

Final Results

Empyrean Energy, the profitable US onshore oil, gas and condensate exploration, development and production company with assets in Texas and California, is pleased to announce its final results for the year ended 31 March 2014. A full copy of the Empyrean Annual Report and Accounts will be posted to shareholders and can be found on the Company website www.empyreanenergy.com.

Highlights

· Record financial results and production following a significant step-up in production at flagship Marathon Oil operated Sugarloaf AMI project (EME 3% working interest) targeting formations including the prolific Eagle Ford Shale and Austin Chalk in Texas

o 51% increase in revenues for the 12 months to 31 March 2014 to US$13,883,854 (2013: US$9,180,544)

o 83% increase in net profit after tax for the 12 months to 31 March 2014 to US$5,221,102 (2013: US$2,846,890)

o 50% increase in production net to Empyrean (before royalties) for the 12 months to 31 March 2014 to 335,305 barrels of oil equivalent (2013: 223,500 barrels of oil equivalent)

· Substantial increase in activity at Sugarloaf with 43 wells spudded and 39 wells brought into production during the period

o Well spacing initiatives - 90% of wells drilled in 2013 at 60 acre spacing or less resulting in an approximate 45% increase in 30 day initial production rates over wells previously drilled at greater than 60 acre spacing

o Reduction in drilling costs following improvement in drilling techniques and introduction of drill pads

· Intensive drilling programme planned with 100 wells targeted in calendar year 2014

o Funding available for current drilling schedule

· Significant potential from the overlying Austin Chalk formation

o Early Austin Chalk wells drilled to date performing similarly to the Eagle Ford Shale wells

o Further development of the Austin Chalk anticipated to require in the order of a further 300 wells, with down spacing potential of approximately 235 further wells

· Updated reserves report to 31 December 2013 on Sugarloaf AMI released in May 2014 showed:

o 54% increase in 1P Reserves to 3.54 Mmboe

o 48% increase in 2P reserves to 6.53 Mmboe

o 2C Contingent Resource for the Austin Chalk formation of 3.87 Mmboe

· Piloting 30 acre well spacing during 2014 in selected areas of the Eagle Ford Shale

· Further repayments to Macquarie Bank reducing debt to US$10.67m as at 31 March 2014 and to US$9.17m as at 29 August 2014

· Formal Sales Process and Strategic Review announced 10 July 2014

Empyrean CEO Tom Kelly said, "This has been a year of tremendous growth for Empyrean. Marathon continues to ramp up drilling at our primary asset, and we believe potentially significant reserves upside exists within both the Eagle Ford Shale and the Austin Chalk, with the latter showing signs of being a transformational pay-zone for the Company and its partners following recent successful appraisal wells. Empyrean has chosen to undertake a Formal Sales Process and Strategic Review with highly regarded advisors in Cenkos and Macquarie Bank advising and coordinating the process, against the backdrop of recent increased levels of corporate activity and industry interest in the region, and in order to maximise value for its shareholders."

Chairman's Statement

I am pleased to report that Empyrean Energy Plc ('the Company') has completed its ninth year of operations and enjoyed its best financial result since its AIM IPO. This has been achieved following a significant increase in oil and gas production, particularly from the de-risked flagship US onshore asset, the Sugarloaf AMI Project in Texas ('Sugarloaf'). As described in more detail below, Empyrean continues to benefit from an aggressive work programme being undertaken at two objectives available at Sugarloaf and the board of directors are pleased with the demonstrable increase in value both during the period and post period end. 

In terms of unlocking value, an updated report by DeGolyer and MacNaughton into the reserves at Sugarloaf as at 31 December 2013 has revised the 1P Reserves upwards by 54% to 3.54 million barrels of oil equivalent ('MMboe') and the 2P reserves upwards by 48% to 6.53 MMboe, over previously reported reserves. Of particular importance is a new 2C Contingent Resource for the Austin Chalk formation of 3.87 MMboe that provides additional short term potential for further Reserve increases and value creation should further drilling continue to show promising results.

The operator of this field, Marathon Oil Corporation (NYSE: MRO) ('Marathon' or the 'Operator'), has continued to demonstrate excellent expertise across all technical and operational areas, and has succeeded with initiatives to improve efficiencies and optimise performance across a number of key areas. These include reduced drilling times, improved stimulation and completion techniques, reduced well spacing and reduced spud to production cycle times. As a result, well productivity has improved substantially, and drilling and completion costs have reduced and are forecast by Marathon to continue to improve through 2014. Marathon has declared its intention to pursue the co-development of the Austin Chalk simultaneously with the Eagle Ford Shale. Early Austin Chalk wells are performing similarly to the Eagle Ford Shale, and the Company is confident that the 2C Contingent Resource allocated by DeGolyer MacNaughton can be moved into 2P Reserves with further drilling and appraisal in the short term.

This aggressive development at Sugarloaf has had a very positive effect on our financials for the year. Revenue in the year to 31 March 2014 was $13.88 million, 51% above the previous year ($9.18 million). Net profit, at $5.221 million was 83% higher than the same period last year. 

The Eagle Ford Shale is one of the most prolific onshore US plays. This is evidenced by the impressive production of wells targeting the formation resulting in extensive corporate activity amongst partners in Sugarloaf, with acquisition prices demonstrating the quality of the liquids rich acreage, most recently Baytex's acquisition of Aurora, one of our partners at Sugarloaf, at a price of A$4.20 per share and an implied market capitalisation of A$1.84 billion.

Reflecting Empyrean's development into a substantial and profitable energy producer, this year has also seen a number of organisational changes. Most obvious has been the change to its accounting functional currency from Sterling to US dollars, to mirror the fact that almost all the Company's revenues and expenditures are in that currency. The Company has also appointed a new Nominated Advisor ('NOMAD') in Cenkos, new Auditor in BDO and a new Public Relations team in St Brides Media & Finance, as reported in the half year Interim Results.

Outside of Sugarloaf, which continues to demonstrate substantial upside potential through the future co-development of the Austin Chalk alongside the Eagle Ford Shale, Empyrean has holdings in the contiguous Sugarloaf Block A, the Riverbend project, and the Eagle Oil Pool Development project in California, providing it with an appropriate mix of advanced exploration through to development projects. On 10 July 2014, the Company announced a Strategic Review and Formal Sales Process with the goal of maximising value for shareholders. Macquarie Capital has been appointed to assist with this process. The Company looks forward to updating shareholders on this process in due course. In conclusion, the Company has enjoyed an excellent year's growth in production, revenue and profits, and is confident it can continue to deliver better value for shareholders.

Patrick Cross

Non-Executive Chairman

5 September 2014

Operational Review

Empyrean has continued to focus its operational activities during the past 12 months on the development of the Sugarloaf AMI Project, which lies within the greater Eagle Ford Shale play in onshore Texas. The Sugarloaf AMI Project is located onshore East Texas in Karnes County. The company holds a 3% working interest in approximately 24,000 acres. Marathon Oil Corporation ("Marathon" NYSE: MRO), replaced Hillcorp as operator in late 2011 and has since maintained an accelerated drilling programme targeting as the primary objective, the Cretaceous Eagle Ford Shale.

In the adjacent Block A, Empyrean holds a 7.5% working interest in 4 producing wells in addition to a lesser interest in another 2 recently drilled wells, one of which commenced production in late 2013. Block A is operated by ConocoPhillips, and Empyrean will have the opportunity to participate in further wells if they are proposed on acreage covered by the existing producing wells that Empyrean already has an interest in.

The Riverbend Project onshore Texas is the third area of interest, where Empyrean first became involved in 2009. After several unsuccessful attempts to produce economic quantities of gas and condensate from 2 wells targeting the Austin Chalk, Empyrean agreed with the newly appointed operator, Krescent Energy Partners II,LP ( KEP II), to re-enter Cartwright -1 well and test the shallower Wilcox Formation. The operation was successful and the well commenced the production of gas and minor condensate in May 2013.

The fourth Empyrean project located onshore California in the San Joaquin Basin is the Eagle Oil Pool Development Project. Empyrean has an increased working interest of 57.2 % and the operator remains Strata-X Energy (TSX.V:SXE). There have been no operations carried out during the past 12 months.

Sugarloaf AMI Project( Block B) ( 3% WI)

The Eagle Ford Shale play is the primary target in the Sugarloaf AMI Project. It is termed "unconventional" because shale, being impermeable, has traditionally been the necessary barrier to fluid migration in porous, permeable reservoirs resulting in the eventual accumulation of hydrocarbons in a so-called petroleum "trap".

Shale can also be a hydrocarbon source rock in addition to being a barrier. The Eagle Ford Shale is rich in organic material, and has in the area of the Sugarloaf AMI Project been subjected to the time duration and temperature requirements for in situ hydrocarbons generation. However, the entrapped hydrocarbons can only be released by increasing the density, size and connectivity of microfractures within the shale. This can best be accomplished by combining fraccing operations with horizontal drilling. The fraccing releases the hydrocarbons by creating permeability, while the horizontal drilling exposes much greater volumes of "unconventional" reservoir to the fraccing process. 

132 wells have been spudded since the drilling of the first producing well, Kennedy 1H, in 2007 (which did not commence producing until January 2010). Marathon has spudded 107 wells to the end of March 2014 since becoming operator at the end of 2011 and plan to spud approximately 100 wells during the 2014 calendar year.

During the year to 31 March 2014 there have been 43 wells spudded and 39 wells brought on production, which is a commendable achievement. The drilling and completion operations are highly sophisticated, technically difficult and have the potential to be time consuming and expensive when problems arise. Logistical considerations are equally challenging. Sugarloaf AMI partners have profited from the fact that Marathon has had access to 12 different rigs during the period mentioned and at no time has there been time lost due to rig unavailability. Nor have any of the wells been unsuccessful as producers or plugged and abandoned.

As mentioned in previous reports, the operator has from the beginning embarked on a programme of technical initiatives aimed at achieving optimum productivity with maximum economic efficiency. These initiatives fall into 2 categories: firstly stimulation and completion design, and secondly well spacing.

Improvements in stimulation and completion design have had a marked positive effect on well performance. Fraccing is complex and there are many variables involved. Perforation clusters, gel loading, propane size, fluids and volumes all play a part, and the object of improving and refining the operation continues to be an ongoing process. The results have been impressive. Marathon reports an approximate 97% improvement in 30 day IP's (initial production measured in barrels of oil equivalent per day) between 2011 and 2014 wells to date. The record shows a large variation in the early days of production for many of the wells and this does not seem to be dependent necessarily on well location. Kennedy 5H has been one of the more impressive producers. It commenced production on the 16 March 2013 and produced 101,976 msc.ft (thousand standard cubic feet) of gas and 23,078 barrels of condensate in the following month (wellhead measurements). Eight months later, in December 2013, it produced 62,507 msc.ft of gas and 8,438 barrels of condensate. A more recent well, St. Christoval Ranch G2H, commenced production on the 31 August 2013 and in the following month produced 95,199 msc.ft of gas and 22,905 barrels of condensate. These 2 wells were among the better producers.

The second category, well spacing, has also shown positive results in productivity due to application of denser well distribution. 80 acre spacing equates to approximately 750ft between the horizontal branches of each well. Wells drilled in the early stages of development in 2010-11 were usually located within an 80 acre, or greater, spacing. In contrast, 90% of the Marathon wells drilled in 2013 were located on a 60 acre, or less, spacing. The results show an impressive 45% improvement between 2011 and 2013 when comparing the 30 day IP (initial production) rates. A comparison of the first 180 days of cumulative production over the same period also shows a 34% increase. These encouraging results strongly support the continuation of infill development and Marathon has commenced piloting 30 acre infills during 2014.

In addition to the initiatives taken to increase productivity, Marathon has been successful in reducing drilling costs by developing improved drilling techniques and adopting the practice of common pad drilling. Common pad drilling reduces mobilization expenses and minimises the time taken between the spudding of consecutive wells. Time lost is also minimised during fraccing and completion operations. Most of the wells are now being drilled from common pads. Recently drilled Mobil B AC 1H, for example, is located on an 8 well pad, while the May B unit 2H-5H wells drilled in January and March 2014 are located on a 4 well pad. The practice of using multi-well pads has no effect on the vertical or horizontal limitations of a well. Of the 43 wells spudded in the recent 12 months, measured depths have ranged between 16,296ft (well May B 4H) and 19,473 ft at Morgan 5H. Horizontal distances ranged between 4,250 ft and 7,900ft with an average distance of 5,755 ft.

The effects of improved drilling techniques are manifest in the drill time comparisons with wells drilled only 2 years ago. The time taken in the last 12 months to drill a well to 18,000ft MD (measured depth) varied between 12-15 days. For the well MD's in the vicinity of 16,500ft the drill time was reduced to 11 days. The well May B 5H reached a TD of 16,492 ft in an impressive 9 days in March 2014. The well drill costs are invariably less than the fraccing and completion costs, but overall the operator is aiming to reduce total costs to US$ 6.5-7.5 million per well during 2014.

In summary, the rate of drilling new development wells in the AMI is increasing. The operator plans to drill approximately 100 wells in 2014 alone. The productivities have improved markedly through technical innovation, and drilling and completion costs have decreased. There are at present 5 central facilities operating with total existing capacity of 117,000 mscfd and 30,000 barrels of condensate per day. The capacities are planned to be increased to 320,000 mscfd and 80,000 barrels of condensate respectively. This capacity increase will be necessary to include the volumes expected with the additional development of the Austin Chalk. Three wells only were drilled specifically to test this formation in the recent 12 months (Weston Gas Unit 1 10H, 12H and Children Weston 4H). The 10H and 12H wells produced approximately 85,000 msc.ft of gas and 8,000 barrels of condensate in the first month of production, comparable with some of the better Eagle Ford Shale wells. It is anticipated that full development of the Austin Chalk could involve the drilling of approximately 300 further wells, based on 60 acre spacing with down spacing potential of approximately 235 further wells. These would be in addition to the Eagle Ford Shale wells, for which 330 further wells will be required for full development with down spacing potential of a further 200 wells. Much will depend on the eventual spacing.

Sugarloaf Block A (7.5% WI)

Empyrean has held in Sugarloaf Block A 7.5 % WI in 4 producing wells for some time. Production of gas and condensate from the first of the wells commenced on 13 November 2008. The remaining 3 wells commenced producing in February 2009. The 4 wells are referred to as TCEI Block A-1 (Kunde No3), A-3 (Baker Trust No1), A-4 ( Baker Trust No2) and A-5 ( Marlene Olson No1).

Empyrean had elected against participation in further drilling in Block A for almost 5 years to late August 2013. The decision had been made to focus on the development of the Sugarloaf AMI (Block B). In September 2013 Empyrean announced its decision to accept participation in 2 Eagle Ford Shale wells in Block A. Baker Trust No 4 was drilled to a measured depth of 17,948ft with a lateral of approximately 5,000ft. It commenced producing gas condensate on the 29 December 2013, and Empyrean holds an approximate 2.45% WI.

Marlene Olson No 3, the second well in which Empyrean has an approximate 0.85% WI, was drilled to a measured T.D of 20,601 ft. on the 3 October 2013. The well has a lateral length of approximately 7,000 ft. and is at present undergoing completion operations.

Both wells are being drilled from the same pad along with a third well to be completed in acreage in which Empyrean holds no interest. Empyrean's interest in the 2 wells is less than the previous 7.5% WI because parts of each well traverse acreage in which no WI is held; the resulting interest being based on a pro rata share.

Riverbend Project (10% WI)

The new operator of the project, Krescent Energy Partners 11,LP ( "KEP11") proposed re-entering Cartwright No1 and testing a fresh interval between 9,584ft.-9,590ft in the Wilcox Formation. The previous attempts to produce from the older Austin Chalk had failed due to obstructions in the production tubing. 

Empyrean agreed to participate in the re-entry and the formation was successfully perforated and tested. The Wilcox Formation had previously exhibited encouraging hydrocarbon "shows" during the initial drilling of the well. 

The early production from this new zone of 30-40 barrels of condensate and 755 msc.ft of gas per day was above expectations. The well is currently producing 15 barrels of condensate and 400,000 c.ft of gas per day with minimal operating cost.

Eagle Oil Pool Development Project (57.2% WI)

Empyrean increased its interest from 48.5% to 57.2% at no extra cost to the Company. Although no tangible operations were performed during the recent 12 months, a vertical well test of the Gatchell sands, and possibly the Kreyenhagen Shale, would appear to be the next logical step. The results of such a vertical well would have a strong bearing on the emplacement of a horizontal well if required.

Frank Brophy BSc (Hons)

Executive Technical Director

5 September 2014

Statement of Comprehensive Income

For the Year Ended 31 March 2014

All financial results presented are from continuing operations. The accompanying accounting policies and notes form an integral part of these financial statements.

Statement of Financial Position

As at 31 March 2014

Statement of Cash Flows

For the Year Ended 31 March 2014

The accompanying accounting policies and notes form an integral part of these financial statements.

Statement of Changes in Equity

For the Year Ended 31 March 2014

Notes to the Financial Statements

For the Year Ended 31 March 2014

Basis of preparation

The Company's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union and Companies Act 2006. The principal accounting policies are summarised below. They have all been applied consistently throughout the year. The financial report is presented in the functional currency, US dollars and all values are shown in thousands of US dollars (US$'000) for the first time this year.

These financial statements have been prepared under the historical cost convention modified by the revaluation of certain financial assets and liabilities.

Going concern

The Directors consider that the Company has adequate resources to continue in operational existence for the foreseeable future and that it is therefore appropriate to adopt the going concern basis in preparing its financial statements. The net current liabilities of US$817,259 (2013: US$2,068,000 net current liabilities) are alleviated with the Macquarie Bank Facility. Empyrean has reached certain Reserve hurdles under Tranche B of the Macquarie Bank Facility to obtain further drawdowns if required. Any further draw downs on the Macquarie Bank Facility are subject to the bank's normal credit department approvals for draw downs under the facility. In addition, the Company has in the money options and warrants that will further reduce the net current liabilities position if they are exercised before expiry. These options and warrants are detailed note 15 to the Financial Statements.

Basis of accounting and adoption of new and revised standards

a) Standards, amendments and interpretations effective in 2013:

The following new standards and amendments to standards are mandatory for the first time for the company for the financial year beginning 1 April 2013. Except as noted, the implementation of these standards did not have a material effect on the Company:

b) Standards, amendments and interpretations that are not yet effective and have not been early adopted:

* Effective date 1 January 2014 for the EU.

The Company does not expect the pronouncements to have a material impact on the Company's earnings or shareholders' funds.

Revenue recognition

Revenue is derived from sales of oil and gas to third party customers. Sales of oil and gas production are recognized at the time of delivery of the product to the purchaser which is when the risks and rewards of ownership pass and are included in the statement of comprehensive income as Revenue. Revenue is recognized net of local ad valorem taxes.

Interest revenue is accrued on a time basis, by reference to the principal outstanding at the effective interest rate applicable.

Cash and cash equivalents

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

Tax

The major components of tax on profit or loss include current and deferred tax. Current tax is based on the profit or loss adjusted for items that are non-assessable or disallowed and is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Tax is charged or credited to the income statement, except when the tax relates to items credited or charged directly to equity, in which case the tax is also dealt with in equity.

Deferred tax

Deferred tax assets and liabilities are recognised where the carrying amount of an asset or liability in the statement of financial position differs to its tax base.

Recognition of deferred tax assets is restricted to those instances where it is probable that taxable profit will be available, against which the difference can be utilised. The amount of the asset or liability is determined using tax rates that have been enacted or substantively enacted by the reporting date and are expected to apply when the deferred tax liabilities/(assets) are settled/(recovered).

The Company has considered whether to recognize a deferred tax asset and has determined that this is not appropriate in line with IAS 12 as the conditions for recognition are not satisfied.

Royalties

Royalties or taxes based on production quantities or calculated as a percentage of revenue taken out of net revenue proceeds received.

Foreign currencies

Transactions denominated in foreign currencies are translated into US dollars at the spot rate on the date of the transaction 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 US dollars at year-end exchange rates. Exchange differences on monetary items are taken to the Statement of Comprehensive Income.

Items included in the financial statements are measured using the currency of the primary economic environment in which the Company operates (the functional currency). This is the first year then the financial statements are presented in USD, which is also the functional currency of the Company.

Change in functional currency and presentation currency

Prior to 31 March 2014 the Company's financial statements were presented in UK Sterling and the functional currency of the Company was also assumed to also be UK sterling. As at 31 March 2014 the directors have reviewed the transactions that underpin the Company's operations and have noted that the majority of these are denominated in US Dollars. The Directors have decided that US Dollar is more reflective of the underlying operations of the Group and as such a change in functional currency has been enacted. Given the trigger for change occurred prior to the 31 March 2014 reporting period the adjustment has been retrospectively applied from 31 March 2012.

In line with the requirements of IAS 21 the Directors have chosen to change the presentational currency of the Company to US Dollars. The change in presentation currency is a change in accounting policy, as if the new presentation currency has always been the entity's presentation currency and therefore requires a retrospective change. The Directors retrospectively adjusted the presentation currency from the earliest practical point which has been deemed the opening period for the 31 March 2014 financial statements, being 1 April 2012.

Oil and gas assets: exploration and evaluation

The Company applies the full cost method of accounting for Exploration and Evaluation ('E&E') costs, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources'. Under the full cost method of accounting, costs of exploring for and evaluating oil and gas properties are accumulated and capitalised by reference to appropriate cash generating units ('CGUs'). Such CGUs are based on geographic areas such as a concession and are not larger than a segment.

E&E costs are initially capitalised within 'Intangible assets'. Such E&E costs may include costs of license acquisition, third party technical services and studies, seismic acquisition, exploration drilling and testing, but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the income statement as they are incurred.

Plant, Property and Equipment ('PPE') acquired for use in E&E activities are classified as property, plant and equipment. However, to the extent that such PPE is consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded as part of the cost of the intangible E&E asset.

Intangible E&E assets related to exploration licenses are not depreciated and are carried forward until the existence (or otherwise) of commercial reserves has been determined. The Company's definition of commercial reserves for such purpose is proven and probable reserves on an entitlement basis.

If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a CGU basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production assets within property, plant and equipment and are amortised on a unit of production basis over the life of the commercial reserves of the pool to which they relate. Intangible E&E assets that relate to E&E activities that are not yet determined to have resulted in the discovery of commercial reserves remain capitalised as intangible E&E assets at cost, subject to meeting impairment tests as set out below.

E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist. Where the E&E assets concerned fall within the scope of an established CGU, the E&E assets are tested for impairment together with all development and production assets associated with that CGU, as a single cash generating unit. The aggregate carrying value is compared against the expected recoverable amount of the pool. The recoverable amount is the higher of value in use and the fair value less costs to sell. Value in use is assessed generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. Where the E&E assets to be tested fall outside the scope of any established CGU, there will generally be no commercial reserves and the E&E assets concerned will generally be written off in full. Any impairment loss is recognised in the income statement.

Oil and gas assets: development and production

Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the decommissioning asset (see below) and the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above. They are presented as oil and gas properties in Note 9.

The net book values of producing assets are depreciated on units of production basis. The depletion rate was calculated using the proven 1P reserves.

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit. The recoverable amount is the higher of value in use and the fair value less costs to sell. Value in use is assessed generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash generating unit where the cash flows of each field are interdependent.

The Company has potential decommissioning obligations in respect of its producing interests. The extent to which a provision is required in respect of these potential obligations depends, inter alia, on the legal requirements at the time of decommissioning, the cost and timing of any necessary decommissioning works, and the discount rate to be applied to such costs. The Company recognised a provision in its accounts at March 31, 2014.

Financial assets

Financial assets are recognised at initial recognition at fair value plus, in the case of financial assets not recorded at fair value through profit and loss, transaction costs that are attributable to the acquisition of the financial asset. The Company's financial assets consist of loans and receivables, cash and cash equivalents and financial assets classified as fair value through profit or loss.

All financials assets, other than cash and cash equivalents are initially measured at fair value and subsequently at amortised cost.

Cash and cash equivalents comprise cash on hand or held on current account or on short-term deposits (up to 90 days) at variable interest rates. Any interest earned is accrued monthly and classified as finance income.

Financial liabilities

All financial liabilities are recognised initially at fair value and, in the case of loans and borrowings and payables, net of directly attributable transaction costs. The Company's financial liabilities include trade and other payables, loans and borrowings including bank loans and derivative financial liabilities.

All financial liabilities are initially stated at their fair value and subsequently at amortised cost. Interest and other borrowing costs are recognised on a time-proportion basis using the effective interest method and expensed as part of financing costs in the statement of comprehensive income.

Share-based payments

The Company issues equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant. The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Company's estimate of shares that will eventually vest.

Where equity instruments are granted to persons other than employees, the income statement is charged with the fair value of goods and services received.

Significant accounting judgements, estimates and assumptions

The Company 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.

Exploration and evaluation expenditure

The Company's policy for E&E expenditure requires an assessment of both the future likely economic benefits from future exploitation or sale and whether the activities are at a stage that permit a reasonable assessment of the existence of reserves. Any such assessment may change as new information becomes available. If after capitalisation, information becomes available suggesting that the recovery of the carrying amount is unlikely, the relevant capitalised amount is written off in the statement of comprehensive income in the period when the new information becomes available.

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

Change in accounting policies

In line with the requirements of IAS 21 the Directors have chosen to change the presentational currency of the company to US dollar. The change in presentation currency is a change in accounting policy, as if the new presentation currency has always been the entity's presentation currency and therefore requires a retrospective change. The Directors retrospectively adjusted the presentation currency from the earliest practical point which has been deemed the opening period for the 31 March 2014 financial statements, 1 April 2012.

Management has undertaken to amortise developed wells on a units of production basis and as required by IAS 8 the change has been applied retrospectively. As a result adjustments were made to prior year for the value of Amortisation in the books of the accounts. The retrospective change in prior years amounted to a $340,940 increase in the book value of the assets as at 1 April 2013. Retained earnings were adjusted accordingly.

Revenue by Customer

Customer Revenue 2014 US$'000 Revenue 2013 US$'000

Marathon oil $ 13,380 $ 8,741

Conoco Philips $ 504 $ 440

$ 13,884 $ 9,181

(1) Services provided by Apnea Holdings Pty Ltd

(2) Services provided by F J Brophy Pty Ltd

No UK pension benefits are provided for any UK resident Director.

Directors' share options

The terms of the share option interests of Directors in office during the year ended 31 March 2014 were as follows:

*As announced on 20 March 2014, these options had their expiry date extended to four months following the publication of the Company's Annual Report & Accounts for the period to 31 March 2014.

**ENDS**

For further information please visit www.empyreanenergy.com or contact the following: