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." Chairmans 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 Baytexs 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 Empyreans 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 Companys 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 years 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 IPs (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 MDs 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.

Empyreans 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
2014
Restated 2013
Notes
US$000
US$000
Revenue
13,884
9,181
Cost of sales
Operating costs
(1,398)
(833)
Gain/(loss) on hedge contract
(199)
-
Amortisation - oil and gas properties
9
(3,926)
(3,515)
Total cost of sales
(5,523)
(4,348)
Gross profit
8,361
4,833
Administrative expenses
Other Administrative expenses
2
(515)
(650)
Directors remuneration
(816)
(752)
Compliance fees
(445)
(525)
Total expenditure
(1,776)
(1,926)
Operating profit
6,585
2,906
Finance expense
3
(1,364)
(59)
Profit on ordinary activities before taxation
5,221
2,847
Taxation on profit on ordinary activities
6
-
-
Profit for the financial year
5,221
2,847
Other comprehensive income
-
-
Total comprehensive income for the year
5,221
2,847
Attributable to:
Equity shareholders of the Company
5,221
2,847
Earnings per share
- Basic (cents)
7
2.37
1.32
- Diluted (cents)
7
2.36
1.32
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
2014
Restated 2013
Restated 2012
Notes
US$000
US$000
US$000
Assets
Non-current assets
Oil and gas properties - Exploration and evaluation
8
8,929
9,007
6,575
Oil and gas properties - Development and production
9
33,325
26,176
12,255
Total non-current assets
42,254
35,183
21,830
Current assets
Trade and other receivables
10
1,887
1,978
1,388
Cash and cash equivalents
1,513
1,067
2,460
Total current assets
3,400
3,045
3,848
Liabilities
Current liabilities
Trade and other payables
11
1,643
113
1,030
Bank borrowings
11
2,575
5,000
-
Total current liabilities
4,218
5,113
1,030
Net current assets / (liabilities)
(818)
(2,068)
2,818
Non-current liabilities
Bank Borrowings
12
7,222
4,470
700
Provision for decommissioning costs 13
218
-
-
Total non-current liabilities
7,440
28,645
700
Net assets
33,996
27,594
23,948
Shareholders equity
Share capital
16
709
706
682
Share premium
40,202
40,075
39,388
Share based payment reserves
17
2,946
2,946
1,806
Retained losses
(9,861)
(15,082)
(17,928)
Total equity
33,996
28,645
23,948
Statement of Cash Flows For the Year Ended 31 March 2014
2014
Restated 2013
Notes
US$000
US$000
Net cash inflow from operating activities
14
11,805
4,959
Investing activities
Purchase of exploration assets
(2,379)
(2,526)
Purchase of oil and gas properties
(8,487)
(14,341)
Net cash outflow from investing activities
(10,866)
(16,868)
Financing activities
Issue of ordinary share capital
130
710
Proceeds from borrowings Interest Paid
5,150 (773)
9,804
Repayment of borrowings
(5,000)
-
Net cash (outflow)/inflow from financing activities
(493)
10,514
Increase / (decrease) in net cash and cash equivalents
446
(1,393)
Cash and cash equivalents at the start of the year
1,067
2,460
Cash and cash equivalents at the end of the year
1,513
1,067
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
Share capital
Share premium reserve
Share based payment reserve
Retained deficit
Total equity
US$000
US$000
US$000
US$000
US$000
Balance At 1 April 2012
682
39,389
1,806
(17,928)
23,949
Share capital issued
24
686
-
-
710
Cost of shares issued
-
-
-
-
-
Share based payments (Macquarie Bank)
-
-
1,140
-
1,140
Profit for the year
-
-
-
2,846
2,846
Comprehensive profit for the year
-
-
-
2,846
2,846
Balance At 31 March 2013
706
40,075
2,946
(15,082)
28,645
Share capital issued
3
127
-
-
130
Profit for the year
-
-
-
5,221
5,221
Other comprehensive income
-
-
-
-
-
Comprehensive profit for the year
-
-
-
5,221
5351
Balance At 31 March 2014
709
40,202
2,946
(9,861)
33,996
Notes to the Financial Statements For the Year Ended 31 March 2014
1.

Accounting policies, significant judgements, estimates and assumptions
Basis of preparation The Companys 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 banks 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:
Standard
Impact on initial application
Effective date
IAS 1 (Amendment)
Presentation of items of other comprehensive income
1 July 2012
IFRS 13
Fair value measurement
1 January 2013
IAS 19 (Amendment 2011)
Employee benefits
1 January 2013
IFRS 7 (Amendment 2011)
Disclosures - offsetting financial assets and financial liabilities
1 January 2013
IAS 16 (improvements)
Classification of servicing equipment
1 January 2013
b) Standards, amendments and interpretations that are not yet effective and have not been early adopted:
Standard
Impact on initial application
Effective date
IAS 32 (Amendment 2011)
Offsetting financial assets and financial liabilities
1 January 2014
IFRS 11
Joint arrangements
1 January 2014*
IFRS 10
Consolidated financial statements
1 January 2014*
IFRS 12
Disclosure of interest in other entities
1 January 2014*
IAS 27 (Amendment 2011)
Separate financial statements
1 January 2014*
IAS 28 (Amendment 2011)
Investments in associates and joint ventures
1 January 2014*
IFRIC 21
Levies
1 January 2014
IFRS 9
Financial instruments
TBC
* Effective date 1 January 2014 for the EU.
The Company does not expect the pronouncements to have a material impact on the Companys 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 Companys 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 Companys 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 entitys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 entitys 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.
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 two business being the exploration for, development and production of oil and gas properties.
There is one geographical trading segment being North America which is involved in the exploration for, development and production of oil and gas properties.

The Companys registered office is located in the United Kingdom.
Details
Exploration
Production
Corporate
Total
31 Mar 14
31 Mar 13
31 Mar 14
31 Mar 13
31 Mar 14
31 Mar 13
31 Mar 14
31 Mar 13
US$000
US$000
US$000
US$000
US$000
US$000
US$000
US$000
Revenue
-
-
13,884
9,181
-
-
13,884
9,181
Cost of sales
(54)
-
(5,469)
(4,348)
-
-
(5,523)
(4,348)
Gross profit
(54)
-
8,415
4,833
-
-
8,361
4,833
Exploration expenditure impairment
(86)
(105)
-
-
(86)
(105)
Segment result
(140)
(105)
8,415
4,833
8,275
4,728
Unallocated corporate expenses
(1,690)
(1,821)
(1,690)
(1,821)
Operating profit
6,585
2,906
Finance expense
(1,364)
(59)
Profit on ordinary activities before taxation
5,221
2,847
Taxation
-
-
Profit for the financial year
5,221
2,847
Total comprehensive profit for the financial year
5,221
2,847
Segment assets
8,930
9,007
33,325
26,175
42,037
35,182
Unallocated corporate assets
3,400
2,328
3,400
2,328
Total assets
45,655
37,510
Segment liabilities
(1,212)
(8)
(1,246)
(8)
Unallocated corporate liabilities
(11,068)
(9,908)
(11,068)
(9,908)
Total liabilities
(12,314)
(9,916)
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
2014
Restated 2013
US$000
US$000
2.

Administrative expenses
The operating profit is stated after charging:
Bank charges
(156)
(304)
Audit fees Communications
(15) (8)
(55) (17)
Insurance
(85)
(53)
Travel
(88)
(82)
Other
(77)
(34)
(429)
(545)
3.

Finance expense
Amortisation of finance costs
(395)
-
Interest paid
(969)
(59)
(1,364)
(59)
4.

Share based payments
The Company had no employees during the year, other than Directors and the Company Secretary who are either directly employed or employed on a consultancy basis or a combination.
The Companys equity settled share based payments comprise options granted to Macquarie Bank.

The option value per security is being spread over the expected life of the facility.
During the year ended 31 March 2014, there were no options were granted to Directors and the Company Secretary.

Options were Issued to Macquarie in relation to the loan facility.

These are disclosed in detail under Note 16.
5.

Directors emoluments
Fees and salary paid
Fees and salary paid
2014
2013
2014
2013
US$000
US$000
�000
�000
Non-Executive Directors:
Patrick Cross
71
57
44
36
John Laycock
53
41
33
26
Executive Directors:
Thomas Kelly(1)
394
393
247
250
Frank Brophy(2)
298
261
187
165
816
752
491
477
(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:
Grant date
Options held 31 March 2013
Options granted during year
Options expired during year
Options exercised during year
Options held 31 March 2014
Exercise price (�)
Expiry date
Patrick Cross
28 May 2010
500,000
-
(500,000)
-
-
�0.06
28 May 2013
23 March 2011
650,000
-
-
-
650,000
�0.08
2014*
2 March 2012
750,000
-
-
-
750,000
�0.08
2 March 2015
Thomas Kelly
28 May 2010
4,400,000
-
(4,400,000)
-
-
�0.06
28 May 2013
23 March 2011
6,000,000
-
-
-
6,000,000
�0.08
2014*
2 March 2012
7,500,000
-
-
-
7,500,000
�0.08
2 March 2015
Frank Brophy
28 May 2010
2,450,000
-
(2,450,000)
-
-
�0.06
28 May 2013
23 March 2011
4,000,000
-
-
-
4,000,000
�0.08
2014*
2 March 2012
5,000,000
-
-
-
5,000,000
�0.08
2 March 2015
John Laycock
28 May 2010
-
-
-
-
-
�0.06
28 May 2013
23 March 2011
650,000
-
-
(200,000)
450,000
�0.08
2014*
2 March 2012
750,000
-
-
-
750,000
�0.08
2 March 2015
32,650,000
-
(7,350,000)
(200,000)
25,100,000
*As announced on 20 March 2014, these options had their expiry date extended to four months following the publication of the Companys Annual Report & Accounts for the period to 31 March 2014.
2014
Restated 2013
US$000
US$000
6.

Taxation
Current year taxation
UK corporation tax at 23% (2013: 24%) - -
Factors affecting the tax charge for the year
Profit on ordinary activities before tax 5,221 2,847
Profit on ordinary activities at the UK standard rate of 23% (2013: 24%) Effect of different Tax Rate in US
1,201 835
683 427
Add back disallowable expense 2,833 1,371
Effects of accelerated capital allowances (4,234) (2,481)
Utilisation of tax losses brought forward (635) (-)
Current year taxation - -
The Company has considered whether to create a deferred tax asset and has considered that sufficient taxable profits will not be generated in the near future to utilise the losses carried forward in the US due to forecast future capital spend.
Tax losses of approximately US$43.1m are available to be claimed going forward.
7.

Earnings per share
The basic earnings per share is derived by dividing the profit for the year attributable to ordinary shareholders by the weighted average number of shares in issue.
2014
2013
Profit for the year
$5,220,102
$2,846,890
Weighted average number of ordinary shares of �0.002 on issue
220,587,000
216,090,000
Earnings per share - basic
2.37 cents
1.32 cents
Profit adjusted for dilutive effects
$5,220,102
$2,846,890
Weighted average number of ordinary shares of �0.002 on issue inclusive of outstanding options
220,826,194
217,799,000
Earnings per share - diluted
2.36 cents
1.31 cents
2014
Restated 2013
US$000
US$000
8.

Oil and gas properties: Properties, exploration and evaluation
At 1 April 2013
9,007
6,679
Additions
2,379
2,527
Reclassified to oil and gas properties (Note 9)
(2,370)
(94)
Impairment - intangible assets
(86)
(105)
At 31 March 2014
8,929
9,007
9.

Oil and gas properties: Development and production
At 1 April 2013
26,176
15,255
Additions
8,487
14,341
Reclassified from intangible assets (Note 8)
2,370
94
Oil and gas decommissioning asset
218
-
Amortisation - oil and gas properties
(3,926)
(3,514)
At 31 March 2014
33,325
26,176
10.

Trade and other receivables
Trade and other receivables
161
161
Accrued revenue
1,607
1,589
Prepayments
112
224
VAT receivable
7
4
1,887
1,978
11.

Current trade and other payables
Trade payables
1,362
68
Accrued expenses
176
45
Hedge instrument payable
105
-
Borrowing(1)
2,575
5,000
4,218
5,113
(1) Refer to Note 12 for the non-current Macquarie Bank Facility.
2014
Restated 2013
US$000
US$000
12.

Non-current trade and other payables
Borrowing(1)
7,222
4,470
Total noncurrent trade and other payables
7,222
4,470
The Macquarie Bank Facility totaling US$10,671,000 was entered into on 30 May 2012, drawn down on twice during the year and is repayable at an interest rate of 9% pa plus LIBOR.

The first repayment was on 28 June 2013 and 3 repayments have been made subsequently.

Refer to Note 11 for the current Macquarie Bank Facility.

The Macquarie Bank Facility is secured by a fixed and floating charge over the Company, a Company guarantee and a specific charge over the Sugarloaf AMI asset.
13.

Provision for decommissioning costs
The provision for decommissioning costs is calculated on the following assumptions: - decommissioning cost of $70,000 per well (gross) - US CPI rate of 2% and long term bond rate of 3% - Average life of 19 years
14.

Reconciliation of operating profit to operating cash flows
Profit for the year before tax
5,221
2,847
Amortisation - oil and gas properties
3,926
3,515
Loss on hedging liability
199
-
Finance costs
1,364
-
Impairment - intangible assets
86
105
Decrease / (increase) in receivables
(416)
(590)
Increase / (decrease) in payables
1,425
(916)
Net cash inflow from operating activities
11,805
4,959
15.

Called up share capital
The authorised share capital of the Company and the called up and fully paid amounts at 31 March 2014 were as follows:
Authorised
1,000,000,000 ordinary shares of 0.2p each
�2,000
�2,000
Issued and fully paid
221,433,853 (2013: 220,433,853) ordinary shares of 0.2p each
�443 $709
�426 $706
On 14 August 2013, 200,000 fully paid ordinary shares of 0.2p each were issued as a result of option conversions for cash at a price of �0.08 per share.
On 10 February 2014, 150,000 fully paid ordinary shares of 0.2p each were issued as a result of option conversions for cash at a price of �0.08 per share.
On 28 March 2014, 650,000 fully paid ordinary shares of 0.2p each were issued as a result of option conversions for cash at a price of �0.08 per share.
Share options and warrants
The following equity instruments have been issued by the Company and have not been exercised at 31 March 2014:
Option class
Grant date
Options / warrants held 31 March 2013
Options / warrants granted during year
Options / warrants expired during year
Options / warrants exercised during year
Options / warrants held 31 March 2014
Exercise price (�)
Expiry date
Value per security
Weighted average contractual life remaining (years)
Broker options
9 April 2010
500,000
-
(500,000)
-
-
�0.06
16 April 2013
�0.0145
Director and Company Secretary options
28 May 2010
8,575,000
-
(8,575,000)
-
-
�0.06
28 May 2013
�0.0141
Director and Company Secretary options
23 March 2011
12,100,000
-
-
(1,000,000)
11,100,000
�0.08
2014(2)
�0.0239
See note (2)
Director and Company Secretary options
2 March 2012
14,800,000
-
-
-
14,800,000
�0.08
2 March 2015
�0.0311
0.92
Financier options
19 July 2012
15,000,000
-
-
-
15,000,000
�0.08
19 July 2016
�0.018(1)
0.92
Financier options
19 July 2012
15,000,000
-
-
-
15,000,000
�0.10
19 July 2016
�0.014(1)
2.30
Financier options
25 March 2013
15,000,000
-
-
-
15,000,000
�0.12
25 March 2017
�0.016(1)
2.30
Warrants
1 March 2012
4,000,000
-
-
-
4,000,000
�0.0875
1 March 2015
N/A(3)(4)
0.92
84,975,000
-
(9,075,000)
(1,000,000)
74,900,000
(1)The value of these options is being expensed over a period of 4 years. (2)As announced on 20 March 2014, these options had their expiry date extended to four months following the publication of the Companys Annual Report & Accounts for the period to 31 March 2014 (3)Subsequent to year end, the exercise price of the warrants was converted to USD0.147175 (4)On issue of the warrants in 2012, nil value was attributed to the securities.
The weighted average exercise price of options on issue at 31 March 2014 is �0.092.
The fair value of the granted options in 2013 was estimated using a Black Scholes model with the following inputs:
Grant date 19-Jul-12 19-Jul-12 25-Mar-13 Share price at grant date 0.065p 0.065p 0.0588p Exercise price 0.08p 0.1p 0.12p Volatility 50% 50% 50% Expected option life 4.00 years 4.00 years 4.00 years Dividend yield - - - Risk free interest rate 0.439% 0.439% 0.439%
2014
Restated 2013
US$000
US$000
16.

Reserves
Share based payments reserve
2,947
2,947
Total reserves
2,947
2,947
17.

Commitments
As at 31 March 2014, the Company had no material capital commitments, other than Authority For Expenditures ("AFEs") received from the operator of the Sugarloaf AMI in the normal course of business for operations, including future wells and facilities, that the Company intends to participate.
18.

Related party transactions
There were no related party transactions during the year ended 31 March 2014 other than disclosed in Note 5.
19.

Financial instruments
The Board of Directors determine, as required, the degree to which it is appropriate to use financial instruments to mitigate risk.

Currently the Companys principal financial instruments comprise cash and the Macquarie Bank Facility at an interest rate of 9%pa plus LIBOR.

Refer to Notes 11 and 12 for further details.

Together with the issue of equity share capital, the main purpose of these is to finance the Companys operations.

The Company has other financial instruments such as short-term receivables and payables which arise directly from normal trading.
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.
Short-term receivables and payables are not exposed to interest rate risk.

The companys borrowing with Macquarie is subject to the 9% plus LIBOR rate.

The company is therefore exposed to the premium paid above market rates and if market rates were to fall they would not realize the benefit of this.
The following table illustrates sensitivities to the Companys exposures to changes in interest rates.

The tables indicates the impact of how profit at balance date would have been affected by changes in the relevant risk variable that management considers to be reasonably possible.

These sensitivities assume that the movement in a particular variable is independent of other variables.
At 31 March 2014, the effect on profit as a result of changes in the interest rate on the Macquarie borrowing facility ($10,671,000), with all other variable remaining constant would be as follows:
Change in profit Change $000 Adjusted 2014 $000
Profit before taxation
5,221 Increase in interest rate by 100 basis points (107) 5,114 Increase in interest rate by 200 basis points (213) 5,008
Credit risk Credit risk is the risk of financial loss to the Company if a customer or a counter party to a financial instrument fails to meet its contractual obligations.

The Company is mainly exposed to credit risk through cash and cash equivalents and deposits with banks and financial institutions.
Credit risk in relation to the amount that can be borrowed against the Companys producing assets is predominantly determined by the level of proven reserves.

Cash flow risk is mitiga