Empyrean Regulatory News (EME)

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

17 August 2016

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

Final Results

Empyrean Energy is pleased to announce its final results for the year ended 31 March 2016.

Highlights

o profit after tax for the 12 months to 31 March 2016 of US$0.913m (2015: US$1.747m profit)

o Sugarloaf AMI production net to Empyrean (after royalties) for the 6 months to 30 September 2015 of 224,182 barrels of oil equivalent (2015: 366,469 barrels of oil equivalent)

Empyrean CEO Tom Kelly said, "The sale of our flagship Sugarloaf AMI Project in February 2016 for US$61.5m with the potential for contingency payments of up to a further US$10m if the oil price rises is an excellent deal for Empyrean under challenging market conditions. The Sale has allowed us to repay our loan facility with Macquarie Bank Limited, pay all costs associated with the Sale and be debt free with surplus cash. In addition we took advantage of the low oil price in a timely fashion as the Sale was nearing completion and closed out our hedging facility to generate a further US$1.582m. We have announced plans to complete a return of capital to shareholders, which is a priority, and will seek opportunities to maximise value for shareholders from our remaining assets. The last 12 months have been for the Company and the oil and gas industry as a whole, with a number of companies unable to raise capital or repay debts. Empyrean would like to thank its shareholders for continuing to be supportive and patient during this time."

Chairman's Statement

I am pleased to report that Empyrean has completed its eleventh year of operations, and has successfully implemented a major restructuring of its activities.

In the first half of this financial year the Company continued its growth, increasing its oil and gas production substantially, while an independent appraisal and updated reserves report by DeGolyer and MacNaughton revealed a further significant increase of our Reserves and Resources at our principal asset in the Sugarloaf AMI. Building on these consistently improving results, the Company announced on 18 January 2016 that it had secured a conditional purchase and sale agreement with Carrier Energy Partners II LLC ("CEPII"), a Delaware corporation, to dispose of its interest in the Sugarloaf AMI development for an initial cash consideration of US$61.5m. We may also receive additional contingent payments, of up to a maximum of US$10m, subject to specified increases in the oil price before 31 December 2017.

This agreement, which had an effective date of 1 October 2015, was approved by shareholders at a General Meeting on 9 February 2016, and the transaction reached financial close on 19 February 2016. The transaction crystallised the value of the Sugarloaf AMI Project at a time when there were significant challenges facing the resources sector in general and, specifically, when the additional financing required to support the Company's continued participation in the development of the asset in the prevailing low oil price environment would have incurred either an unacceptable cost or an unacceptable dilution, or both.

In line with the Board's stated strategy, in the last year the Company had continued to demonstrate the future upside potential of the Sugarloaf AMI project and to deliver significant increases to its reserves. The Board concluded that it was the right time to realise the value of the asset, and shareholders endorsed that decision. The terms secured will unlock opportunities to develop our remaining assets and others that may arise at a time when drilling and associated costs are significantly reduced, and when a number of operators and market participants are financially distressed. Empyrean will, as a debt‐free entity with sufficient working capital, be well placed to build value.

The Company also relinquished its interests in Block A on 1 March 2016. It had held a 7.5 % interest in two wells and lesser interests in another 6 wells all of which produced gas, condensate and natural gas liquids, but in declining volumes.

In conclusion, our remaining assets and, in particular the Eagle Oil Pool Development project in California will provide possible future development opportunities as energy prices recover. We have been fortunate enough to be able to repay all of our debts and have embarked upon analysis for the efficient return of capital to shareholders. We will also continue to look for suitable opportunities to increase shareholder value.

Patrick Cross

Non-Executive Chairman

17 August 2016

Operational Report

Until the sale of its 3% working interest ("WI") in Sugarloaf AMI (formerly Block B), Empyrean's operational activities had been almost solely focused on development drilling on this project. The sale of its WI took place on 19 February 2016 to CEPII with the transaction having an effective date of 1 October 2015.

Located onshore Texas in Karnes County, the Sugarloaf AMI project occupied approximately 24,300 acres. The primary objective has always been the Cretaceous Eagle Ford Shale, with the overlying Austin Chalk an important secondary objective. Marathon replaced Hilcorp Resources ("Hilcorp") as operator in 2011, and since then has maintained an accelerated drilling programme involving over this recent 12 month period an average of nine wells spudded a month.

Empyrean also relinquished its interests in Block A with an effective date of 1 March 2016. Until then it held a 7.5% WI in two producing wells and lesser interests in another six producing wells all operated by ConocoPhillips. All eight wells produced gas, condensate and natural gas liquids (NGL's).

Empyrean retains a 10% WI in the Riverbend Project located in the Tyler and Jasper counties, onshore Texas. A 58.084% WI is also held in the Eagle Oil Pool Development Project, located in the prolific San Joaquin Basin onshore, southern California and operated by Strata-X Energy.

Sugarloaf AMI (3% WI)

The Eagle Ford Shale is the primary target in the Sugarloaf AMI. The lithology is in general a calcareous, shale consisting of a variety of microfacies. The AMI is well-located geologically in a region where the organic material embedded in the shale has been subjected to the temperature -time conditions required to generate wet gas (gas-condensate). The Eagle Ford Shale is an "unconventional" play, which means that it can only be exploited by employing horizontal drilling and fraccing. The fraccing process releases hydrocarbons held in the shale microfractures by creating, under extreme pressure, larger, interconnected fractures. The horizontality exposes a greater volume of the reservoir to a lower pressure regime and hydrocarbon migration is thus made possible in what was once an impermeable source rock.

Since becoming operator, Marathon has been instrumental in improving both drilling and fraccing (including "Stack and Fracc") techniques. The results are manifest in the decreased drilling costs and substantial improvements in 30 day initial well head production. Well spacing of 60 acres has also improved productivity markedly.

During the period 1 April 2015 to 16 February 2016 (when reporting of well activity ceased), 97 wells were spudded. The rate peaked in May 2015 with a record 14 wells, while an impressive 10 wells were spudded in June and December 2015. Common pad drilling, sometimes involving up to eight wells, has greatly reduced mob - demobilisation costs. Marathon estimated a reduction in exploration and production costs per oil equivalent barrel of approximately US$8 /barrel and completion costs have fallen by approximately 15%.

The lithostratigraphic understanding of the area has evolved as more data becoming available with the increased drilling. The operator identified four distinct vertical units in the Late Cretaceous objective formations which are separated by three regional barriers. The younger Austin Chalk, with an average thickness of 100 ft, overlies the Upper Eagle Ford Shale (average thickness 45 ft). The two formations are separated by several layers of volcanic ash which can act as effective permeability barriers. The Upper Eagle Ford Shale overlies the Lower Eagle Ford Shale (average thickness 135 ft) which is divided into an upper and lower member. These two members are separated by a tight lime band which can also act as an effective, impermeable barrier to vertical hydrocarbon migration.

Of the wells spudded between April 2015 and February 2016, Kennedy 320H (ex AC 7H) had the longest measured depth at 20,445', reached on 3 September 2015 in the Lower Eagle Ford Shale. Measured depths varied depending on geographical location and stratigraphic objective of the well. The Lower Eagle Ford Shale was the primary target (47 wells) while the Upper Eagle Ford Formation (18 wells) and overlying Austin Chalk (32 wells) secondary targets. Wells completed in the Upper Eagle Ford Shale sometimes had lesser measured depths of 15,684' (Rancho Grande 501H). The Austin Chalk wells ranged between 17,758' (Urrutia AC 2H) and 19,149' (Hollman AC 12H) measured depth. In general, the measured depths for all wells averaged between 16,000' and 19,000'with horizontal distances between 4,200' and 7,900'.

Production figures have improved since 2011 when Hilcorp, the previous operator, began production from Direct Assets 1H. Since April 2015, the well May Unit 1 12H has shown the best 1P results of those reported to February 2016. It commenced production on 6 October 2015 from the Lower Eagle Ford Shale. Having reached a measured depth of 16,540' on 24 May 2015, the well produced 65,759 msc.ft of gas and 26,701 barrels of condensate during the month of October 2015. Robert Bowman 4H reached a measured depth of 16,530' in the Lower Eagle Ford Shale on 14 April 2015 and commenced producing on 3 December 2015. Well head production for December 2015 was 63,541 msc.ft of gas and 25,846 barrels of condensate. These two wells were the best producers reported during the 12 month period.

The monthly well head total production rose from 3,895,631 msc,ft of gas and 1,1068,651 barrels of condensate in October 2015 ( 260 producers) to 5,264,027 msc.ft and 1,142,962 barrels of condensate (290 Empyrean producers) at the end of January 2016. The normal depletion trend for similar fractured shale reservoirs has been counterbalanced by the continuous increase in the number of producing wells.

The Austin Chalk overlies the Eagle Ford Shale and in some instances it is difficult to distinguish between the two formations. It is a valid secondary target and Marathon has committed to appraise and pursue co-development possibilities. The formation is still in the relatively early stages of appraisal. Between April 2015 and March 2016 the number of Austin Chalk producers increased to 60 in which Empyrean was a participant. Empyrean held an interest in 27 of the 33 Austin Chalk wells that commenced producing during April 2015 to December 2015. During that period, May AC 12H, which commenced producing on 7 October 2015, was the most impressive of the Austin Chalk wells producing, 65,659 msc.ft of gas and 26,701 barrels of condensate at the wellhead.

As of 18 February 2016, 353 wells had been spudded, 290 in which Empyrean held an interest prior to the sale to CEPII.

As the number of producing wells increased during this period, so too have the recoverable reserves attributable to Sugarloaf AMI. On 13 October 2015 Empyrean published results of the independent appraisal carried out by DeGolyer and MacNaughton. These results showed an increase of more than 10% across all reserve categories despite the economic climate, which is one of the essential factors influencing the classification of reserve categories. Effective to 30 June 2015, proven reserves (1P) showed an increase of 13.84% over the results of December 2014 to 6.58 million barrels of oil equivalent ('MMBOE'). 2P (proven plus probable) showed an 11.63% increase to 14.11 MMBOE. The Upper Eagle Ford Shale was not included in the estimates.

Sugarloaf Block A (7.5% WI)

ConocoPhillips continued as operator in the adjacent Block A. Empyrean participated in the drilling of the first well as part of a farm-in agreement dating back to May 2007 (Kunde#3). This well was also the first to commence production in April 2008. Empyrean decided not to participate in further exploration drilling in Block A after the drilling of the fifth well, Marlene Olson#1 in 2008.

However, in more recent times Empyrean has elected to participate, albeit at much reduced working interests, in the drilling and completion of another seven wells which partly fall within Empyrean's acreage. These are the wells, Baker Trust 4, Marlene Olson 3, Lucille Klein A1, and Marlene Olson #4, 5, 6 and 7. The last five wells were spudded in 2014 and Marlene Olson #5, 6 and 7 commenced producing in April 2015. The more recently drilled wells have all measured total depths of greater than 20,000 ft. Production continues to be from the Lower Eagle Ford Shale and rates have been maintained at a fairly consistent level for the more recently producing Marlene Olson wells 5, 6 and 7.

Kunde Unit A B1 (formerly Lucille Klein A1), is the eighth well drilled in which Empyrean held an interest (WI 3.154661%). The well was once was the best producer. It reached a measured TD of 19,325' and commenced production on 17 July 2014. During the first complete month of production in August 2014 the well produced 48,874 msc.ft of gas and 17,100 barrels of condensate. A year later in September 2015, it produced 10,236 barrels of condensate and 37,955 msc.ft of gas. More recently, in February 2016 there has been a decline to 4,075 msc.ft of gas and 2,039 barrels of condensate. Marlene Olson 5, which commenced producing on the 8 April 2015, produced 53,667 msc.ft of gas and 10,024 barrels of condensate in February 2016 but output appears to have subsequently declined.

As of 1 March 2016, Empyrean relinquished all of its interests in the 8 producing wells and all of its rights to participate in further drilling in Block A. The total well head production for February 2016 of 65,659 msc.ft of gas and 34,289 barrels of condensate showed a marked decline from the December 2015 figures of 288,254 msc.ft of gas and 50,755 barrels of condensate.

Riverbend Project (10% WI)

The Cartwright No1 re-entry well produces from the arenaceous Wilcox Formation. Production commenced on 13 May 2013, and well head rates rapidly decreased to a monthly production in June 2014 of 2,687 msc.ft of gas and 83 barrels of condensate. Thereafter, Cartwright No1 re-entry has been shut in intermittently. The well is now virtually suspended producing only nominal amounts of gas condensate. Full production will recommence once the economic environment improves. 

Eagle Oil Pool Development Project (58.084% WI)

Located in the prolific San Joaquin Basin onshore, southern California this Development project has received little attention in the last 12 months due to the economic climate. No appraisal operations were carried out during this 12 month period. It is anticipated that a vertical well test of the primary objective, the Gatchell sands, followed by a horizontal appraisal well, would be the most likely scenario at some future time, dependent on world oil prices.

Definitions

1P Proven reserves. There should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate under existing economic and political conditions

2P Proven plus probable. There should be at least a 50 percent probability that the actual quantities recovered will equal or exceed the 2P estimate

2C Contingent resources are 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. The range of uncertainty is expressed as 1C (low), 2C (best) and 3C (high)

3P Proven plus probable plus possible. There should be at least a 10 percent probability that the actual quantities will equal or exceed the 3P estimate

MMBOE Million barrels of oil equivalent

Production Production available for sale

WTI West Texas intermediate crude, type of oil used as a benchmark in oil pricing

Frank Brophy BSc (Hons)

Executive Technical Director

17 August 2016

Statement of Comprehensive Income

For the Year Ended 31 March 2016

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

Statement of Financial Position

As at 31 March 2016

Statement of Cash Flows

For the Year Ended 31 March 2016

Statement of Changes in Equity

For the Year Ended 31 March 2016

Statement of Accounting Policies

For the Year Ended 31 March 2016

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. The financial report is presented in the functional currency, US dollars and all values are shown in thousands of US dollars (US$'000). The financial statements have been prepared on a historical cost basis and fair value for certain assets and liabilities.

Nature of business

The Company is a public limited company incorporated and domiciled in England. The address of the registered office is 200 Strand, London, WC2R 1DJ. The Company was established to finance the exploration, development and production of energy resource projects in geopolitically stable environments. The Company has typically focused on non-operating working interest positions in projects that have drill ready targets that substantially short cut the life-cycle of hydrocarbon projects by entering the project after exploration concept, initial exploration and drill target identification work has largely been completed.

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 Company had a cash balance of US$17.473m at 31 March 2016 and has repaid its Macquarie loan facility.

Basis of accounting and adoption of new and revised standards

a) New and amended standards adopted by the Company:

There were no new standards effective for the first time for periods beginning on or after 1 April 2015.

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

Any standards and interpretations that have been issued but are not yet effective, and that are available for early application, have not been applied by the Company in these financial statements. International Financial Reporting Standards that have recently been issued or amended but are not yet effective have not been adopted for the annual reporting period ended 31 March 2016:

IFRS 15 Revenue from Contracts with Customers

IFRS 15 is intended to clarify the principles of revenue recognition and establish a single framework for revenue recognition. The core principle is that an entity should recognise revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This standard is effective for periods beginning on or after 1 January 2018. IFRS 15 is not yet endorsed by the EU. As the Company no longer has significant revenue generating assets, there is currently no impact of IFRS 15 but management will continue to monitor the position.

IFRS 9 Financial Instruments

IFRS 9 Financial Instruments replaces IAS 39 Financial Instruments: Recognition and Measurement in its entirety. This standard is effective for periods beginning on or after 1 January 2018 with retrospective application. IFRS 9 is not yet endorsed by the EU. The effects of IFRS 15 Revenues from Contracts with Customers and IFRS 9 Financial Instruments are still being assessed, as these new standards may have a significant effect on the Company's future financial statements. The Company does not expect other pronouncements to have a material impact upon the primary statements and disclosure.

 Revenue recognition

Revenue is derived from sales of oil and gas to third party customers. Sales of oil and gas production are recognised 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 recognised 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 in the Statement of Financial Position 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.

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 recognise 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 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 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).

Provisions

Provisions are recognised when the Company has a present obligation as a result of a past event which it is probable will result in an outflow of economic benefits that can be reliably estimated.

Joint arrangements

Joint arrangements are arrangements in which the Company shares joint control with one or more parties. Joint control is the contractually agreed sharing of control of an arrangement, and exists only when decisions about the activities that significantly affect the arrangement's returns require the unanimous consent of the parties sharing control. Joint arrangements are classified as either joint operations or joint ventures based on the rights and obligations of the parties to the arrangement. In joint operations, the parties have rights to the assets and obligations for the liabilities relating to the arrangement, whereas in joint ventures, the parties have rights to the net assets of the arrangement.

Joint arrangements that are not structured through a separate vehicle are always joint operations. Joint arrangements that are structured through a separate vehicle may be either joint operations or joint ventures depending on the substance of the arrangement. In these cases, consideration is given to the legal form of the separate vehicle, the terms of the contractual arrangement and, when relevant, other facts and circumstances. When the activities of an arrangement are primarily designed for the provision of output to the parties, and the parties are substantially the only source of cash flows contributing to the continuity of the operations of the arrangement, this indicates the parties to the arrangements have rights to the assets and obligations for the liabilities. The Company accounts for all its joint arrangements as joint operations by recognising the assets, liabilities, and expenses for which it has rights or obligations, including its share of such items held or incurred jointly.

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 11. 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 had 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 31 March 2015 and reversed the provision upon the sale of its producing projects.

Assets held for sale and discontinued operations

Assets are classified as held for sale if their carrying value will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met if the sale is highly probable, the asset is available for sale in its present condition, being actively marketed and management is committed to the sale which should be expected to qualify for recognition as a completed sale within one year from the date of classification. A discontinued operation is a component of an entity that either has been disposed of, or that is classified as held for sale, and represents a separate major line of business or geographical area of operations; and is a part of a single coordinated plan to dispose of a separate major line of business or geographical area of operations; or is a subsidiary acquired exclusively with a view to resale. Non-current assets held for sale and discontinued operations are carried at the lower of carrying value or fair value less costs to sell. Any gain or loss from disposal of a business, together with the results of these operations until the date of disposal, is reported separately as discontinued operations. The financial information of discontinued operations is excluded from the respective captions in the financial statements and related notes for the current and comparative period and disclosed as results from discontinued operations.

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 derivative financial assets, loans and receivables, cash and cash equivalents and financial assets classified as fair value through profit or loss. All financials assets, other than the derivative financial asset and cash and cash equivalents are initially measured at fair value and subsequently at amortised cost. The derivative financial asset is measured at fair value through the profit or loss at the point of initial recognition and subsequent revised at each reporting date. Movements in the fair value of derivative financial assets are recognised in the profit or loss, unless they are designated and effective as hedging instruments. The Company doesn't not currently have any hedging instruments. 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. Financial liabilities, including trade and other payables, loans and borrowings, 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. Derivative financial liabilities are initially recognised at fair value of the date a derivative contract is entered into and subsequently re-measured at each reporting date. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Company has not designated any derivatives as hedges as at 31 March 2015 or 31 March 2016.

When the Company's borrowings are refinanced, the difference between the carrying amount of a financial liability (or part of a financial liability) extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is accelerated when the refinancing is considered to be a substantial modification of terms. The refinancing is considered a substantial modification if either the quantitative tests set out by IFRS are breached or the Directors consider the qualitative factors (coupon rate, security, term, etc.) to be a substantial modification. Upfront fees are set-off against the fair value of the liability upon initial recognition and amortised to the income statement using the effective interest method. The derivative recognised at 31 March 2016 relates to share options issued to Macquarie Bank as part of the refinancing. These options were subject to shareholder approval which was received in the post balance sheet period. This transaction falls outside of the scope of IFRS 2 and is fair valued as a derivative financial liability. The cost is recognised as a transaction cost netted off against the loan balance.

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 around future production, costs, capital expenditure, inflation and discount rates.

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.

Sale of Sugarloaf Projects and associated tax provisions

The valuation of the taxes associated with the sale of the Sugarloaf projects has been made by the Company's US tax advisors and as such, is subject to certain assumptions with respect to dealings with the IRS. The Company has assessed that the completion of the sale, through the legal process, of the Sugarloaf Block A project was effected at year end as court approval was deemed to be an administrative process and the Company has used the effective date of sale, as per the agreement. As announced on 17 May 2016, the Company had completed its assignment of interests in the Sugarloaf Block A project.

Valuation of potential contingent consideration amounts receivable

In order to calculate the fair value of the contingent consideration as a derivative financial asset, the Company makes estimates principally relating to the assumptions used in its option-pricing model as set out in Note 9.

Notes to the Financial Statements

For the Year Ended 31 March 2016

(1) Services provided by Apnea Holdings Pty Ltd

(2) Services provided by F J Brophy Pty Ltd for technical services

No UK pension benefits are provided for any UK resident Director. There has been no increase in Directors emoluments during the period. The remuneration of the highest paid Director during the year was US$337,000 (2015: US$399,000). The average number of Directors was 4 during 2016 and 2015.

**ENDS**

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