Final Results

RNS Number : 1674S

Pantheon Resources PLC

16 November 2011

 



Final Results for the Year Ended 30 June 2011

Pantheon Resources plc ("Pantheon", the "Company" or the "Group"), the AIM-quoted oil and gas exploration company active in Louisiana and Texas, today announces its final results for the year ended 30 June 2011.

HIGHLIGHTS

·    Pantheon experienced mixed fortunes in the financial year ending 30 June 2011.

·    Plans to drill a second well, Kara Farms #1, ("KF#1H") on the Tyler County Joint Venture, were thwarted by the impact of adverse macroeconomic factors. 

·    Currently events are unfolding in a manner which may have a major positive impact on shaping Pantheon's future, both in terms of drilling activity and reserve accretion.

·    The operator, Vision Gas Resources LLC, has informed Pantheon that it is in active and advanced discussions with another company relating to a possible restructuring of the Tyler County project. Pantheon's position is not impacted.

·    Terms under discussion are understood to include a change of operatorship and an acceleration of the drilling programme for KF#1H. 

·    Pantheon has also been advised that it will be some time before the results of the current negotiations are available.

·    During the financial year under review further analyses were conducted which reinforced the JV's opinion that Tyler County was a highly attractive play.

·    The KF#1H well has two independent targets, both considered low risk and economic at current prices.

·    The Group's share of the KF#1H well is fully funded.

·    Projected economics for the Tyler County project remain positive at current natural gas price. Leverage from either a modest natural gas price increase or reduction in service costs is high. 

·    Loss for the year of £1.9 million versus £2.5 million last year. Results dominated by impairment charges of £1.2 million relating to the carrying value of the Group's Bullseye assets in Louisiana. These reflect impairments taken by operator, Golden Gate Petroleum Ltd.

·    Notwithstanding this, the Directors are of the opinion that the Bullseye acreage offers the potential for several more high quality locations in the Miogyp formation, as well as the still untested Camerina location.

Annual Report and Accounts

 The Annual Report and Accounts for the financial year ending 30 June 2011 will be posted to shareholders today, copies of which will be available shortly on the Company's website at:

www.pantheonresources.com

In accordance with the AIM Rules, the information in this announcement has been reviewed and signed off by Jay Cheatham, who has over 30 years’ relevant experience within the sector.

For further information on Pantheon Resources plc, see the website at: www.pantheonresources.com

Neither the contents of the Company's website nor the contents of any website accessible from hyperlinks on the Company's website (or any other website) is incorporated into, or forms part of, this announcement.

Further information:

Pantheon Resources plc

Jay Cheatham, CEO Justin Hondris, Director, Finance and Corporate Development

[phone]

Oriel Securities Limited (Nominated Adviser)

Michael Shaw

[phone]

CHAIRMAN'S STATEMENT FOR THE YEAR ENDED 30 JUNE 2011

Pantheon Resources plc ("Pantheon" or "the Group") experienced diverse fortunes in the financial year under review. The obvious disappointment arose with the failure to commence drilling the highly prospective Kara Farms#1H ("KF#1H") well. Recently events are unfolding in a manner which may have a major positive impact on shaping Pantheon's future, both in terms of drilling activity and reserve accretion. 

The operator of the Tyler County Joint Venture ("JV"), Vision Gas Resources LLC ("Vision") has notified the Group that a potential farm-out and restructuring is at an advanced stage of negotiations. The terms under discussion include a change of operatorship and an acceleration of the drilling programme for KF#1H. Obviously such deals are confidential and completion cannot be assured. Pantheon has also been advised that it will be some time before the results of the current negotiations are available. Pantheon will report to shareholders once these are concluded.

As the financial year progressed the JV indicated its expectation that the KF#1H well would be drilled. Preparation of the drilling site was completed and vital equipment was bought.  The explanation for the drilling impasse, which I know has been a major disappointment to our shareholders, relates to two main factors.

First the JV was unable to secure a suitable specialised rig. Already experiencing difficult conditions from a tight horizontal rig market in the U.S., the JV was further thwarted by strong gains in utilisation rates. This was in direct contrast to historic experience when a decline in U.S. natural gas prices was accompanied by a fall both in the rig count and costs. With rig costs rising, the JV's main endeavour was to minimise any adverse impact. The critical aim was and remains to drill the KF#1H well both efficiently and safely at the lowest cost. Pantheon reiterates that its share of the KF#1H well is fully funded.

The second factor was a recent shift in portfolio management from natural gas to oil by the majority participant in the JV, Kaiser Francis Oil Corporation ("KFOC"). This translated into a temporary moratorium on its natural gas exploration activities with the corollary that its decision impeded any progress on drilling KF#1H. Pantheon understands that if the proposed JV restructuring is concluded successfully KFOC would not object to early drilling on the JV's acreage.

Pantheon is restricted by two factors in reporting fully its activities to shareholders. First it has to abide by the general confidentiality arrangements of the JV Agreement. Secondly until Pantheon has concluded its three well drilling commitment as part of the terms of its farm-in, the Group is restricted in the geological information it may release publicly. However it has been agreed that to balance the rights of the JV with those of the shareholders' entitlement to be updated, certain information may be issued.

While hindered by the lack of drilling progress, the JV remained highly active elsewhere. Further extensive geological analyses were completed focusing on developing its geological understanding of the Eagleford and Woodbine plays. These are known to exist on the JV's acreage as a result of previous drilling and geophysical studies. Indeed it is the public domain that the Woodbine formation is known as a prolific producer in nearby fields, notably the Double A Wells field located some six miles to the west of the JV's acreage.

The main conclusion emanating from the analyses was an enhancement of the outlook for the Woodbine target from both a geological risk and reserve perspective.  For reasons of confidentiality, the Group is only permitted to reveal part of the economic evaluation for the Woodbine as assessed by the operator. For a single well, the operator estimates a gross NPV10 on the mean reserve case of US$48.5 million using a US$75 a barrel constant price for crude oil and US$3.60 per million BTU ("mmBTU") for natural gas rising to a constant US$4.50 per mmBTU. This falls to US$17.9 million using a P50 case for reserves.

 This analysis clearly demonstrates the substantial potential that the separate and independent Woodbine target has to augment the economic value of Pantheon's Austin Chalk project. Pantheon and the JV retain their positive view on the Austin Chalk, which remains the central focus of Tyler County. As previously disclosed the overall potential remains for an individual Austin Chalk well to have average reserves of eight billion cubic feet ("bcf"). Using the same assumptions as for the Woodbine an illustrative gross NPV10 exceeding US$12 million per well has been estimated.

The intention remains to test both formations with the KF#1H well. Although the primary target will again be the Austin Chalk, should the deeper Woodbine prove successful then the well would be completed in this formation first. Should the Woodbine not be productive, then the objective would be to complete in the Austin Chalk.

Pantheon's Board of Directors shares shareholders' understandable disappointment and frustration that have accompanied the lack of drilling of the second well on Tyler County. This hiatus should not disguise the major progress made in evaluating further the undoubted and substantial potential that remains to be unlocked at Tyler County.

Susan Graham

15 November 2011

CHIEF EXECUTIVE OFFICER'S STATEMENT AND OPERATIONAL REVIEW

FOR THE YEAR ENDED 30 JUNE 2011

In reviewing Pantheon's operations for the financial year to 30 June 2011 it was anticipated that drilling of KF#1H would have commenced, if not progressed further. This has proven not to be the case.

As shareholders know during the financial year the JV went so far as to prepare the drilling site and buy the necessary tubulars for KF#1H, but did not proceed to drill the well.  The explanation for this lack of activity, which I know has been a major disappointment to Pantheon's shareholders, is in two main parts.

First, Vision, the operator for the JV, guided by history and industry advice, considered that the falling natural gas prices encountered during the period would lead to lower rig utilisation and hence lower rig costs.  In fact, prices for the specialised rigs the JV required did not fall as anticipated. In fact rig utilisation has increased from an already high base.

Total U.S. rig utilisation has risen by 20% year-on-year.  This masks an even stronger increase in the horizontal rig market which has strengthened by almost 25%.  The latter is the critical market for Pantheon as it is within this rig pool that the operator, Vision, has been seeking a rig capable of drilling the KF#1H well.  Combined with rising service costs, this has placed pressure on overall well costs. An indication of the adverse impact may be gauged by the calculation that the original authorisation for expenditure for the Vision Rice University #1 well would have increased by more than 50% using current costs. 

A separate factor has been the recent decision by KFOC to refocus its short term efforts towards drilling oil development wells. This has led to it ceasing to participate in natural gas drilling regionally for the near term. This choice is purely a reflection of the normal industry practice of regular portfolio management based on an assessment of current conditions and is not specific to the Tyler County project. Pantheon understands that KFOC would not object to early drilling on the JV's acreage if a farm-out is concluded successfully. Negotiations for such a farm-out and restructuring are underway currently, which does not impact Pantheon's position. Both Pantheon and Vision are anxious to drill KF#1H, as the economics remain robust at current costs and prices.

The historical ratio of the oil price (West Texas Intermediate) to the natural gas price (Henry Hub) was between 10 and 12. Beginning in 2009 the ratio widened to 15, before expanding to 18-20 in 2010. It is now about 25 in 2011. Clearly crude oil and natural gas prices have decoupled from their historical relationship.

Operational Review

Tyler County

During the financial year under review further analyses were conducted which reinforced the JV's opinion that Tyler County was a highly attractive play. Vision has continued its detailed study of the Woodbine and Eagleford plays. Vision has analysed the Woodbine target and for a single well estimates a gross NPV10 on the mean reserve case of US$48.5 million using a US$75 a barrel constant price for crude oil and US$3.60 per million BTU ("mmBTU") for natural gas rising to a constant US$4.50 per mmBTU. This falls to US$17.9 million using a P50 case for reserves.

Pantheon's next well, KF#1H, has two independent targets, both considered low risk and economic at current prices. The KF#1H well is planned to test a structural nose and rollover in the Austin Chalk and the deeper Woodbine sandstone formations.  Vision plans to complete in the Woodbine formation, if successful. In the event that the Woodbine is non-productive, the intention would be to complete in the shallower Austin Chalk.

The KF#1H well offsets Vision's existing Louisiana Pacific #2 ("LP2") producing well. The LP2 well produces from the Woodbine formation and has generated in excess of US$25 million gross production revenues to date.  The LP2 well was completed as a straight well bore and thus cheaper to drill than the JV's planned horizontal wells.

Bullseye

Gross combined production at Bullseye continued to decline from an average gross 255 barrels oil equivalent per day ("boepd") in July 2010 to 112 boepd in July 2011.  The present forecast is for Jumonville #1 ("J#1") to reach its economic limit in December 2011.  While there remain two potential Miogyp development locations at Bullseye, the operator, Golden Gate Petroleum Limited, stated in a recent release that the majority of the partners were unwilling to fund a Miogyp well at this stage.  This does not include Pantheon which supports a Miogyp development well if the costs are reduced from previous wells.

The Camerina is an untested formation with much promise.  While drilling both J#1 and Jumonville #2 natural gas shows in the Camerina were encountered and logs indicated the possibility of producible hydrocarbons. Plans have been drawn up possibly to recomplete the J#1 well in the Camerina during first quarter 2012. If successful this would assist in the argument for a further Miogyp well as it would enhance the economic case by providing a secondary target.

South Texas

The Baptist gas well continues to produce small quantities of natural gas.  Gross production has declined from 176 thousand cubic feet a day ("mcfd") in July 2010 to 100 mcfd in July 2011. Baptist is expected to reach its economic limit during 2012.

Production

Pantheon continues to receive cash flow from the three producing wells in which it has a working interest, although it is modest and tracks the continued decline in our net production. The Group's net daily production is now 16.9 boepd versus 45 boepd this time last year.

Conclusion

A year ago I was eagerly anticipating the drilling of the KF#1H well. It is thus a major disappointment to me, as to Pantheon's shareholders, that drilling did not commence due primarily to adverse macroeconomic conditions.  Not all was a setback however, as further detailed analyses were undertaken which enhanced the JV's understanding of the Woodbine prospect. These also confirmed that targets in the Austin Chalk and Woodbine formations are two independent high quality geological and economic prospects which are due to be tested with the KF#1H well. Pantheon has reduced overhead costs to preserve capital for drilling KF#1H, for which it is fully funded. The Group remains committed to and optimistic for the Tyler County Venture.

Recently the operator, Vision, has informed Pantheon that it is in active and advanced discussions with another company relating to a possible farm-in and restructuring of the Tyler County project. This has provided the JV with the prospect of acceleration in the drilling of KF#1H well and a reinvigorated project. Pantheon supports fully any action that results in an early drilling programme. I remain confident in the geological potential and ultimate success for the Tyler County project.

Jay Cheatham

15 November 2011

FINANCE DIRECTOR'S REPORT FOR THE YEAR ENDED 30 JUNE 2011

Financial Review

The Group made a loss for the financial year ended 30 June 2011 of £1,900,158 (2010: £2,540,396).

Approximately £1,162,168 of this loss related to impairments taken against the carrying value of the Group's Bullseye assets in Louisiana. Whilst the Directors believe material potential remains in this project, the operator of the project has indicated that it has no plans for additional drilling of this project in the short to medium term. Accordingly, the Directors have impaired the majority of the carrying value of this project in line with the impairments put through by the operator. Notwithstanding this, the Directors are of the opinion that the Bullseye acreage offers the potential for several more high quality locations in the Miogyp formation, as well as the still untested Camerina location.

Production

The Group's net total sales production for the financial year ended 30 June 2011 amounted to 18.4 (2010: 42.7) mcfd natural gas and 10.0 (2010: 42.7) bopd oil. Average realisations for the year for natural gas and oil were $3.82 (2010: $3.87) per mcf and $87.32 (2010: $72.00) per barrel respectively. Note that these productions numbers are extracted from the sales records and are slightly lower than the gross production numbers reported in the CEO's statement primarily due to the usage of product on site.

Revenue

Revenues for the year ended 30 June 2011 were lower than the previous year at £215,493 (2010: £639,372). This primarily reflected a natural decline in production from the Jumonville #1 and #2 wells at the Bullseye project.  

Cost of sales

Cost of sales for the year ended 30 June 2011 was lower than the previous year at £241,804 (2010: £700,484), consistent with the reduction in production for the period

Impairments

The total impairment charge of £1,162,168 (2010: £1,398,794) comprised of a write down of wells and facilities at the Group's Bullseye project in Louisiana. Notwithstanding this accounting treatment, the Directors believe further potential remains at the prospect, both in the known Miogyp formation and the untested Camerina formation. Being a minority partner in the joint venture, any future drilling is subject to the timetable of the operator.

Accounting policies

There have been no major changes to accounting policies during the year.

Capital structure

The Company did not issue any new shares or options during the year.  

As at 30 June 2011 there were 102,099,770 shares in issue.

Going concern

The Group is satisfied with its ability to operate as a going concern for the next 12 months as documented further in Note 1.4.

Taxation

The Group incurred a loss for the year and has not incurred a tax charge. The directors have not considered it appropriate to recognise a deferred tax asset to reflect the potential benefit arising from these timing differences.

Risk assessment

The Group's oil and gas activities are subject to a variety of risks, both financial and operational, including but not limited to those outlined below. These and other risks have the potential to materially affect the financial performance of the Group.

Liquidity and Interest Rate Risk

Liquidity risk has increased for many companies as a result of the recent global economic crisis and the more recent economic woes in Europe in particular, for companies with smaller market capitalisations.

Interest Rate risk and the cost and availability of debt and equity finance were dramatically affected following the global economic crisis and continue to be challenging for smaller companies.

Oil & Gas Price Risk

Oil and Gas sales revenues were subject to the volatility of the underlying commodity prices throughout the year. At the present time, the US energy sector is exhibiting stronger oil prices and weaker gas prices due to a variety of reasons. Paradoxically, despite a weaker gas price, demand for drilling unconventional gas plays in the US is at or near record high levels resulting in a very high cost environment for rigs and associated drilling services. These macroeconomic factors have resulted in the Group's activities at Tyler County continuing to be delayed during the period.

The Group did not engage in any hedging activity during the year.

Currency Risk

Almost all capital expenditure and operational revenues for the year were denominated in US dollars. The Group keeps the majority of its cash resources denominated in US dollars throughout the year to minimise volatility and foreign currency risk.  The Group did not engage in any hedging activity during the year.

Financial Instruments

As this stage of the Group's activities it has not been considered appropriate or necessary to enter into any derivatives strategies or hedging strategies. Once the Group's production revenues increase substantially, such strategies will be reviewed on a more regular basis.

Justin Hondris

15 November 2011

INDEPENDENT AUDITOR'S REPORT TO THE MEMBERS OF PANTHEON RESOURCES PLC

FOR THE YEAR ENDED 30 JUNE 2011

We have audited the financial statements of Pantheon Resources plc for the year ended 30 June 2011 which comprise the Consolidated Statement of Comprehensive Income, the Consolidated and Parent Company Statements of Changes in Equity, the Consolidated and Parent Company Balance Sheets, the Consolidated and Parent Company Cash Flow Statements and the related notes. The financial reporting framework that has been applied in their preparation is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.

This report is made solely to the Company's members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the Company's members those matters we are required to state to them in an auditor's report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company's members as a body, for our audit work, for this report, or for the opinions we have formed.

Respective Responsibilities of Directors and Auditors

The Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit the financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board's (APB's) Ethical Standards for Auditors.

Scope of the audit of the financial statements

A description of the scope of an audit of financial statements is provided on the APB's web-site at www.frc.org.uk/apb/scope/private.cfm.

Opinion on financial statements

In our opinion:

·     the financial statements give a true and fair view of the state of the Group's and of the Parent Company's affairs as at 30 June 2011 and of the Group's loss for the year then ended;

·     the financial statements have been properly prepared in accordance with IFRSs as adopted by the European Union; and

·     the financial statements have been prepared in accordance with the requirements of the Companies Act 2006.

Opinion on other matters prescribed by the Companies Act 2006

In our opinion the information given in Directors' Report for the financial year for which the financial statements are prepared is consistent with the financial statements.

Matters on which we are required to report by exception

We have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:

·     adequate accounting records have not been kept by the Parent Company, or returns adequate for our audit have not been received from branches not visited by us; or

·     the Parent company financial statements are not in agreement with the accounting records and returns; or

·     certain disclosures of Directors' remuneration specified by law are not made; or

·     we have not received all the information and explanations we require for our audit.

Guy Swarbreck (Senior Statutory Auditor)

For and on behalf of

UHY Hacker Young, Statutory Auditor

Quadrant House

4 Thomas More Square

London E1W 1YW

15 November 2011

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED 30 JUNE 2011

	Notes	2011	2010
		£	£
Turnover	3	215,493	639,372
Cost of sales		(241,804)	(700,484)
Gross loss		(26,311)	(61,112)
Administrative expenses before share based payments and impairment losses		(699,757)	(779,763)
Share based payments	20	(18,445)	(84,489)
Impairment of intangible assets	12	-	(312,758)
Impairment of tangible assets	13	(1,162,168)	(1,086,036)
Total administration expenses		(1,880,370)	(2,263,046)
Operating loss	4	(1,906,681)	(2,324,158)
Interest payable	6	-	(222,074)
Interest receivable	6	6,523	5,836
Loss before taxation		(1,900,158)	(2,540,396)
Taxation	7	-	-
Loss for the year		(1,900,158)	(2,540,396)
Other comprehensive income for the year
Foreign currency movement		(583,919)	660,535
Total comprehensive income for the year		(2,484,077)	(1,879,861)
Loss per ordinary share - basic and diluted	2	(1.86)p	(3.34)p

All of the above amounts are in respect of continuing operations.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEAR ENDED 30 JUNE 2011

	Share	Share	Retained	Currency	Equity	Total
	capital	premium	earnings	reserve	reserve
	£	£	£	£	£	£
Group
At 1 July 2010	1,020,998	21,915,804	(15,647,981)	1,092,199	669,917	9,050,937
Net loss for the year	-	-	(1,900,158)	-	-	(1,900,158)
Other comprehensive income:
Foreign currency translation	-	-	-	(583,919)	-	(583,919)
Total comprehensive income for the year	-	-	(1,900,158)	(583,919)	-	(2,484,077)
Issue of shares
Share based payment- issue of options	-	-	-	-	18,445	18,445
Transfer of previously expensed share based payment on expiration of options	-	-	566,670	-	(566,670)	-
Balance at 30 June 2011	1,020,998	21,915,804	(16,981,469)	508,280	121,692	6,585,305

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEAR ENDED 30 JUNE 2010

	Share	Share	Retained	Currency	Equity	Total
	capital	premium	earnings	reserve	reserve
	£	£	£	£	£	£
Group
At 1 July 2009	398,372	14,723,365	(13,280,569)	431,664	758,412	3,031,244
Net loss for the year	-	-	(2,540,396)	-	-	(2,540,396)
Other comprehensive income:
Foreign currency translation	-	-	-	660,535	-	660,535
Total comprehensive income for the year	-	-	(2,540,396)	660,535	-	(1,879,861)
Issue of shares	622,626	7,192,439	-	-	-	7,815,065
Share based payment- issue of options	-	-	-	-	84,489	84,489
Transfer of previously expensed share based payment on cancellation of options	-	-	172,984	-	(172,984)	-
Balance at 30 June 2010	1,020,998	21,915,804	(15,647,981)	1,092,199	669,917	9,050,937

CONSOLIDATED BALANCE SHEET AS AT 30 JUNE 2011

	Notes	2011	2010
		£	£
ASSETS
Fixed assets
Intangible fixed assets	12	3,719,578	3,539,252
Tangible fixed assets	13	185,593	1,597,093
		3,905,171	5,136,345
Current assets
Trade and other receivables	9	324,465	345,572
Cash and cash equivalents	10	2,574,997	3,848,111
		2,899,462	4,193,683
Total assets		6,804,633	9,330,028
LIABILITIES
Creditors: amounts falling due within one year	11	219,328	279,091
Total liabilities		219,328	279,091
Net assets		6,585,305	9,050,937
EQUITY
Capital and reserves
Called up share capital	14	1,020,998	1,020,998
Share premium account	14	21,915,804	21,915,804
Retained losses		(16,981,469)	(15,647,981)
Currency reserve		508,280	1,092,199
Equity reserve		121,692	669,917
Shareholders' funds		6,585,305	9,050,937

The financial statements were approved by the Board on 15 November 2011

Justin Hondris

Director

Company Number 05385506

CONSOLIDATED CASH FLOW STATEMENT FOR THE YEAR ENDED 30 JUNE 2011

	Notes	2011	2010
		£	£
Net cash outflow from operating activities	15	(271,581)	(1,136,567)
Cash flows from investing activities
Interest received		6,523	5,836
Interest paid		-	(170,227)
Disposal /(acquisition) of tangible fixed assets		674	(206,047)
Funds used for drilling and exploration		(424,811)	(2,048,504)
Net cash outflow from investing activities		(417,614)	(2,418,942)
Cash flows from financing activities
Proceeds from issue of shares		-	7,843,741
Issue costs Short term loan received		- -	(377,802) 61,000
Short term loan repaid		-	(836,536)
Net cash inflow from financing activities		-	6,690,403
Net (decrease)/ increase in cash and cash equivalents		(689,195)	3,134,894
Effect of foreign currency translation		(583,919)	660,535
Cash and cash equivalents at the beginning of the year		3,848,111	52,682
Cash and cash equivalents at the end of the year	10	2,574,997	3,848,111

NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 30 JUNE 2011

1.      Accounting policies

A summary of the principal accounting policies, all of which have been applied consistently throughout the period, is set out below.

1.1.   Basis of preparation

The financial statements have been prepared using the historical cost convention. In addition, the financial statements have been prepared in accordance with the International Financial Reporting Standards ("IFRS") including IFRS 6, Exploration for and Evaluation of Mineral Resources, as adopted by the European Union ("EU") and in accordance with the provisions of the Companies Act 2006.

The Group's financial statements for the year ended 30 June 2011 were authorised for issue by the board of Directors on 15 November 2011 and the balance sheets were signed on the Board's behalf by Mr J Hondris.

The Group financial statements are presented in UK pounds sterling.

In accordance with the provisions of Section 408 of the Companies Act 2006, the Company has not presented a profit and loss account.  A loss for the year ended 30 June 2011 of £480,784 (2010: loss of £815,739) has been included in the income statement.

1.2.   Basis of consolidation

Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases. The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus costs directly attributable to the acquisition. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any minority interest. The excess of the cost of acquisition over the fair value of the Group's share of the identifiable net assets acquired is recorded as goodwill. Goodwill arising on acquisitions is capitalised and subject to impairment review, both annually and when there are indications that the carrying value may not be recoverable.

Inter-company transactions, balances and unrealised gains on transactions between group companies are eliminated.

All the companies over which the Company has control apply, where appropriate, the same accounting policies as the Company.

1.3.      Going Concern                                         

The Group incurred a loss of £1,900,158 for the year (2010: £2,540,396).

The Directors believe the Tyler County Joint Venture to be of material potential value to the Group, based upon the geological success of the VRU#1 well which confirmed the presence of hydrocarbons in the Austin Chalk formation, coupled with the very high success rates enjoyed by the drilling activity adjacent to the JV acreage. Additionally, further potential for material shareholder value arises from the independent and totally separate Woodbine target, which lies below the primary Austin Chalk target, and which is anticipated to be tested in the forthcoming KF#1H well.

The Directors believe the inherent value in the Group's projects are sufficient to ensure the going concern of the Group. However, in the event that the forthcoming KF#1H well was unsuccessful then the Group would need to raise additional capital in order to drill the third well in the Tyler County programme. In the event however that the forthcoming KF#1H well was commercially successful then the Company may or may not need to raise additional capital for the drilling of the third well in the Tyler County programme, dependent upon a number of factors including the magnitude of the success of KF#1H well, the timing of drilling the subsequent well, the cost of drilling the KF#1H well and the subsequent well, and prevailing commodity prices.

Accordingly, the Directors have prepared the financial statements on a going concern basis.

1.4.   Revenue

Oil and Gas revenue represents amounts invoiced (exclusive of sales related taxes) for the Group's share of oil and gas sales in the year.

Interest revenue is recognised on a proportional basis taking into account the interest rates applicable to the financial assets.

1.5.   Foreign currency translation

(i) Functional and presentational currency

The financial statements are presented in Pounds Sterling ("£"), which is the functional currency of the Company and is the Group's presentation currency.

Items included in the Company's subsidiary entities are measured using United States Dollars ("US$"), which is the currency of the primary economic environment in which they operate. 

 (ii) Transactions and balances

Transactions in foreign currencies are translated into Sterling at the rate of exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the rate of exchange ruling at the balance sheet date. The resulting exchange gain or loss is dealt with in the income statement.

The assets, liabilities and the results of the foreign subsidiary undertakings are translated into Sterling at the rates of exchange ruling at the year end.  Exchange differences resulting from the retranslation of net investments in subsidiary undertakings are treated as movements on reserves.

1.6.   Cash and cash equivalents

The Company considers all highly liquid investments, with a maturity of 90 days or less to be cash equivalents, carried at the lower of cost or market value.

1.7.   Deferred taxation

Deferred tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance sheet date and expected to apply when the related deferred tax is realised or the deferred liability is settled.

Deferred tax assets are recognised to the extent that it is probable that the future taxable profit will be available against which the temporary differences can be utilized.

1.8.   Exploration and development costs

The Group follows the 'successful efforts' method of accounting for exploration and evaluation costs. All costs associated with oil, gas and mineral exploration and investments are capitalised on a project by project basis, pending determination of the feasibility of the project.  Costs incurred include appropriate technical and administrative expenses but not general corporate overheads. If an exploration project is successful, the related expenditures will be transferred to Developed Oil and Gas Properties and amortised over the estimated life of the commercial reserves on a unit of production basis. Where a licence is relinquished or project abandoned, the related costs are written off. Where the Group maintains an interest in a project, but the value of the project is considered to be impaired, a provision against the relevant capitalised costs will be raised.

The recoverability of all exploration and development costs is dependent upon the discovery of economically recoverable reserves, the ability of the Group to obtain necessary financing to complete the development of the reserves and future profitable production or proceeds from the disposition thereof.  When production commences the accumulated costs for the relevant area are transferred from intangible fixed assets to tangible fixed assets as 'Developed Oil & Gas Assets' or 'Production Facilities and Equipment', as appropriate.

Amounts recorded for these assets represent historical costs and are not intended to reflect present or future values.

1.9.   Impairment of exploration and development costs and depreciation of fixed assets

Impairment reviews on development and producing assets are carried out regularly. When events or changes in circumstances indicate that the carrying amount of expenditure attributable to a successful well may not be recoverable from future net revenues from oil and gas reserves attributable to that well, a comparison between the net book value of the cost attributable to that well and the discounted future cash flows from that well is undertaken. To the extent that the carrying amount exceeds the recoverable amount, the cost attributable to that well is written down to its recoverable amount and charged as an impairment.

Exploration and development costs

In relation to the Tyler County project, pursuant to the successful efforts method of accounting, all direct costs relating to the VRU#1 well have been written off. Accordingly, the carrying value as at 30 June 2011 solely represents back costs paid in relation to the project and prepaid costs towards the forthcoming KF#1H well.

Based on estimates by a third party technical consultant, the Group estimates potential for up to or exceeding 40 wells at an average gross reserve of 8 bcfe natural gas per well from the Austin Chalk zone. Additional potential lies in the deeper, independent Woodbine structure. Based upon those estimates the directors believe the carrying values at 30 June 2011 are supported.

Developed Oil and Gas Properties

Developed Oil and Gas Properties are amortised over the estimated life of the commercial reserves on a unit of production basis.

Other tangible fixed assets

Other tangible fixed assets are stated at cost less depreciation. Depreciation is provided at rates calculated to write off the costs less estimated residual value of each asset over its estimated useful life as follows:

-      Production Facilities and Equipment are depreciated by equal instalments over their expected useful lives, being seven years.

-      Office equipment is depreciated by equal annual instalments over their expected useful lives, being four years.

1.10. Financial instruments

IFRS7 requires information to be disclosed about the impact of financial instruments on the Group's risk profile, how the risks arising from financial instruments might affect the entity's performance, and how these risks are being managed. 

The Group's policies include that no trading in derivative financial instruments shall be undertaken. These disclosures have been made in Note 19 to the accounts.

1.11. Share based payments

On occasion the Company made share-based payments to certain Directors and advisers by way of issue of share options. The fair value of these payments is calculated by the Company using the Black-Scholes option pricing model. The expense is recognised on a straight line basis over the period from the date of award to the date of vesting, based on the Company's best estimate of the number of shares that will eventually vest.

1.12. Critical accounting estimates and judgements

The preparation of financial statements in conformity with International Financial Reporting Standards requires the use of accounting estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Although these estimates are based on management's best knowledge of current events and actions, actual results ultimately may differ from those estimates. IFRS also require management to exercise its judgement in the process of applying the Group's accounting policies.

The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the financial statements are as follows: 

Impairment of tangible and intangible assets

Determining whether an asset is impaired requires an estimation of whether there are any indications that its carrying value is not recoverable.

At each reporting date, the Company reviews the carrying value of its tangible and intangible assets to determine whether there is any indication that those assets have been impaired. If such an indication exists, the recoverable amount of the asset, being the higher of the asset's fair value less costs to sell and value in use, is compared to the asset's carrying value. Any excess of the asset's carrying value over its recoverable amount is expensed to the income statement.

Developed Oil & Gas Properties

Developed Oil & Gas Properties are amortised over the life of the area according to the estimated rate of depletion of the economically recoverable reserves. If the amount of economically recoverable reserves varies, this will impact on the amount of the asset which should be carried on the balance sheet.

Share based payments

The Group records charges for share based payments.

For option based share based payments, to determine the value of the options management estimate certain factors used in the option pricing model, including volatility, vesting date, exercise date of options and the number of options likely to vest.

At each reporting date during the vesting period management estimate the number of shares that will vest after considering the vesting criteria.

If these estimates vary from actual occurrence, this will impact on the value of the equity carried in the reserves.

1.13. New standards and interpretations not applied

AS of the date of these financial statements the IASB and IFRIC have issued a number of new standards, amendments and interpretations with an effective date after the date of these financial statements. Of these, only the following are expected to be relevant to the Group:

Standard  Subject                                                                                                        Effective from

IFRS 9      Financial Instruments - Classification and Measurement                                     1 January 2013

IFRS12     Disclosure of Interests in Other Entities                                                             1 January 2013

IFRS13     Fair Value Measurement                                                                                  1 January 2013

IAS1        Presentation of Items of Other Comprehensive Income

                (Amendments to IAS1)                                                                                          1 July 2012

IAS19       Employee Benefits (2011)                                                                                1 January 2013

2.       Loss per share

The basic loss per share of 1.86p (2010: 3.34p) for the Group is calculated by dividing the loss for the year by the weighted average number of ordinary shares in issue of 102,099,770 (2010:74,876,908).

The diluted loss per share has been kept the same as the basic loss per share as the conversion of share options decreases the basic loss per share, thus being anti-dilutive.

3.       Segmental information 

The Group's activities involve production of and exploration for oil and gas. There are two reportable operating segments: USA and Head Office. Fixed Assets, income and operating liabilities are attributable to the USA, whilst most of the corporate administration is conducted through Head Office.

Each reportable segment adopts the same accounting policies.

In compliance with IFRS 8 the following tables reconcile the operational loss and the assets and liabilities of each reportable segment with the consolidated figures presented in these Financial Statements, together with comparative figures for the year ended 30 June 2010.

Year ended 30 June 2011

Geographical segment (Group)	Head Office	USA	Consolidated
	£	£	£
Turnover	-	215,493	215,493
Cost of sales	-	(241,804)	(241,804)
Interest payable	-	-	-
Interest receivable	137	6,386	6523
Impairment of assets	-	(1,162,168)	(1,162,168)
Share-based payments	(18,445)	-	(18,445)
Administration expenses	(462,476)	(237,281)	(699,757)
Loss by reportable segment	(480,784)	(1,419,374)	(1,900,158)
Developed oil & gas properties	-	26,890	26,890
Exploration and development costs	-	3,719,578	3,719,578
Tangible fixed assets	-	158,703	158,703
Trade and other receivables	49,712	274,753	324,465
Cash and cash equivalents	236,587	2,338,410	2,574,997
Intercompany balances	15,823,576	(15,823,576)	-
Total assets by reportable segment	16,109,875	(9,305,242)	6,804,633
Total liabilities by reportable segment	(24,527)	(194,801)	(219,328)
Net assets by reportable segment	16,085,348	(9,500,043)	6,585,305

Year ended 30 June 2010

Geographical segment (Group)	Head Office	USA	Consolidated
	£	£	£
Turnover	-	639,372	639,372
Cost of sales	-	(700,484)	(700,484)
Interest payable	(222,074)	-	(222,074)
Interest receivable	1,651	4,185	5,836
Impairment of assets	-	(1,398,794)	(1,398,794)
Share-based payments	(84,489)	-	(84,489)
Administration expenses	(510,828)	(268,935)	(779,763)
Loss by reportable segment	(815,740)	(1,724,656)	(2,540,396)
Developed oil & gas properties	-	1,055,932	1,055,932
Exploration and development costs	-	3,539,252	3,539,252
Tangible fixed assets	1,004	540,157	541,161
Trade and other receivables	59,122	286,450	345,572
Cash and cash equivalents	479,400	3,368,711	3,848,111
Intercompany balances	16,073,576	(16,073,576)	-
Total assets by reportable segment	16,613,102	(7,283,074)	9,330,028
Total liabilities by reportable segment	(65,415)	(213,676)	(279,091)
Net assets by reportable segment	16,547,687	(7,496,750)	9,050,937

4.      Operating loss

	2011	2010
This is stated after charging:	£	£
Auditor's remuneration
- group and parent company audit services	16,500	16,500
Auditor's remuneration for non audit services
- taxation services and compliance services	6,392	4,490
	22,892	20,990

5.         Employment costs

	2011	2010
	£	£
Wages and salaries	445,402	484,535
Social security costs	40,682	38,765
	486,084	523,300

There is one employee in addition to the Directors.

6.         Interest payable and receivable
Interest payable		2011	2010
		£	£
Interest on short term borrowings		-	222,074
Interest receivable		2011	2010
		£	£
Bank interest		6,523	5,836

7.         Taxation
	2011	2010
	£	£
Factors affecting the tax charge for the period
Loss on ordinary activities before taxation	(1,900,158)	(2,540,396)
Loss on ordinary activities before taxation
multiplied by standard rate of corporation
tax of 27.5% (2010 28.0%)	(522,543)	(711,311)
Effects of:
Non deductible expenses	325,890	415,319
Timing differences not recognised	149	11,711
Losses in the period not used	196,504	284,281
Total tax charge	-	-

Factors that may affect future tax charges

At the balance sheet date the Group has unused losses carried forward of approximately £17,800,000 (2010: £17,000,000) for offset against future suitable profits. Approximately £15,200,000 (2010: £15,000,000) of the losses were sustained in the USA. Unrecognised US tax losses expire within 20 years of the year in which they were sustained.

The Directors do not consider it appropriate to recognise a deferred tax asset in respect of such losses or in respect of accelerated tax depreciation allowances, due to the uncertainty of future profit streams. The contingent deferred tax assets are estimated to be £5.8m (2010: £5.6m) in respect of losses carried forward and £15,000 (2010: £15,000) in respect of accelerated depreciation allowances.

8.         Subsidiary entities

The Company currently has the following wholly owned subsidiaries all of which were incorporated on 3 February 2006:

                                                                         Country of        Percentage

Name                                                          Incorporation         ownership                         Activity

Hadrian Oil & Gas LLC                                  United States                   100%           Holding Company

Agrippa LLC                                                  United States                   100%           Holding Company

Pantheon Oil & Gas LP                                   United States                   100%      Oil & gas exploration

Pantheon Oil & Gas LP is 99% owned by Agrippa LLC as its limited partner and 1% by Hadrian Oil & Gas LLC as its general partner.

9.         Trade and other receivables

	Group	Group
	2011	2010
	£	£
Amounts falling due within one year:
Trade receivables	274,753	286,450
Prepayments and accrued income	36,621	46,464
Other receivables	13,091	12,658
	324,465	345,572
Amounts falling due after more than one year :
Amount due from subsidiary undertakings	-	-

An annual impairment review of the amount due from subsidiary undertakings (loan to subsidiary) is performed by comparing the expected recoverable amount of the subsidiary's underlying tangible and intangible assets to the carrying value of the loan in the Company's balance sheet.

The recoverable amount of the amount due from subsidiary undertakings is based upon value in use calculations. The use of this method requires the estimation of future cash flows from the underlying assets, discounted using a suitable pre tax discount rate. For the purposes of these calculations a discount rate of 10% has been used. The key assumptions upon which the cash flow projections were based include recoverable reserves, number of wells drilled, cost of drilling and the future prices of both oil and natural gas. For the purpose of the calculations the following assumptions were used:

Number of wells drilled	40
Average reserves per well	8 bcfe
Oil price ($/bbl)	$100
Natural gas price ($/mcf)	$4.00
Cost of drilling typical Austin Chalk well	$8m

These key assumptions have been determined by reference to a number of sources including an independent external geological consultant, information provided by the operator of the project(s), external market information, published futures pricing for oil and natural gas and management's expectations of future events that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

Management has performed sensitivity analysis on each of the key assumptions including increasing the drilling cost to as high as $11.5m, reducing commodity prices by 20% and reducing average reserves per well by 37.5%. None of these factors lead to an indication of impairment, hence the Company concluded that no impairment was required as of 30 June 2011.

10.       Cash and cash equivalents
	Group	Group
	2011	2010
	£	£
Cash at bank and in hand	2,574,997	3,848,111

11.       Trade and other payables
	Group	Group
	2011	2010
		£
Trade creditors	2,760	38,501
Accruals	216,568	240,590
	219,328	279,091

12.   Intangible fixed assets	Exploration and development costs
Group	2011 £	2010 £
Cost
At 1 July 2010	3,539,252	13,672,059
Additions	424,811	2,048,504
Retirements of previously abandoned wells	(368)	(11,775,592)
Transfer to fixed assets	-	(552,873)
Effects of foreign exchange	(244,117)	147,154
At 30 June 2011	3,719,578	3,539,252
Impairment
At 1 July 2010	-	11,469,245
Impairment during the period	-	312,758
Transfer to fixed assets	-	(6,411)
Retirements of previously abandoned wells	-	(11,775,592)
At 30 June 2011	-	-
Net book value
At 30 June 2011 and 30 June 2010	3,719,578	3,539,252
At 30 June 2010 and 30 June 2009	3,539,252	2,202,814

The Company had no intangible assets at either 30 June 2011 or 30 June 2010.

13.       Tangible fixed assets

Group	Developed Oil & Gas Properties £	Production Facilities and Equipment £	Office Equipment £	Total £
Cost
At 30 June 2010	2,654,871	639,441	5,424	3,299,736
Disposals	-	(674)	-	(674)
Retirement/impairments of assets	(901,232)	(260,936)	-	(1,162,168)
Effects of foreign exchange	(174,467)	(42,837)	-	(217,304)
At 30 June 2011	1,579,172	334,994	5,424	1,919,590
Depreciation
At 30 June 2010	1,599,969	98,254	4,420	1,702,643
Depreciation for the year	63,206	85,545	1,004	149,755
Effects of foreign exchange	(110,894)	(7,507)	-	(118,401)
At 30 June 2011	1,552,281	176,292	5,424	1,733,997
Net book value
At 30 June 2011	26,891	158,702	-	185,593
At 30 June 2010	1,054,902	541,187	1,004	1,597,093

Group	Developed Oil & Gas Properties £	Production Facilities and Equipment £		Office Equipment £			Total £
Cost
At 30 June 2009	2,492,243	-		5,424			2,497,667
Transferred from intangible assets	-	552,873		-			552,873
Additions	175,700	30,347		-			206,047
Retirement of assets	(246,495)	-		-			(246,495)
Effects of foreign exchange	233,423	56,221		-			289,644
At 30 June 2010	2,654,871	639,441		5,424			3,299,736
Depreciation
At 30 June 2009	256,093	-		3,061			259,154
Transferred from intangible assets	-	6,411		-			6,411
Depreciation for the year	406,300	86,188		1,359			493,847
Impairments for the year	1,086,036	-		-			1,086,036
Depreciation on retired assets	(237,159)	-		-			(237,159)
Effects of foreign exchange	88,699	5,655		-			94,354
At 30 June 2010	1,599,969	98,254		4,420			1,702,643
Net book value
At 30 June 2010	1,054,902	541,187		1,004			1,597,093
At 30 June 2009	2,236,150	-		2,363			2,238,513
Net book value
At 30 June 2011 and 30 June 2010			-		1,004
At 30 June 2010 and 30 June 2009			1,004		2,363
14.        Called up share capital			2011			2010
			£			£
Allotted, issued and fully paid:
102,099,770 ordinary shares of £0.01 each			1,020,998			1,020,998

	Number	Issued and fully paid Capital	Share Premium Reserve
		£	£
Movement in issued Capital:
As at 1 July 2010	102,099,770	1,020,998	21,915,804
Issue of shares	-	-	-
As at 30 June 2011	102,099,770	1,020,998	21,915,804

The ordinary shares rank pari passu in all respects including the right to receive dividends and other distributions declared, made or paid.

15.       Net cash (outflow)/ inflow from operating activities

	Group	Group
	2011	2010
	£	£
Operating loss	(1,906,681)	(2,324,158)
Impairment	1,162,168	1,398,794
Depreciation	149,755	493,846
Loss on retirement of assets	368	9,336
Cost of issuing share options	18,445	84,489
Decrease/(increase) in trade and other receivables	21,107	(266,811)
(Decrease)/increase in trade and other payables	(59,763)	(189,620)
Effect of translation differences	343,020	(342,443)
Net cash (outflow)/ inflow from operating activities	(271,581)	(1,136,567)

	Company	Company
	2011	2010
	£	£
Operating loss	(480,921)	(595,317)
Depreciation	1,004	1,358
Cost of issuing share options	18,445	84,488
Decrease/(increase) in trade and other receivables	9,410	4,738
Increase in trade and other payables	(40,888)	(196,567)
Net cash (outflow)/ inflow from operating activities	(492,950)	(701,300)

16.       Control

No one party is identified as controlling the Company.

17.       Decommissioning expenditure

The Directors have considered the environmental issues and the need for any necessary provision for the cost of rectifying any environmental damage, as might be required under local legislation.  In their view, no provision is necessary for any future costs of decommissioning or any environmental damage.

18.       Capital commitments

The Group has no obligation to drill any further wells or make any further payments in respect of any new wells in any of its joint ventures. Should the Group elect to not participate in any wells beyond the first well in the Tyler County joint venture then it would forfeit its interest over the remainder of the programme.

As at 30 June 2011, the Group has no fixed financial commitments in respect of any other programmes other than maintaining its interest in its existing joint ventures. Before any new wells are commenced in relation to these joint ventures, the Group must first elect to participate in any proposed well thereby allowing the Group to decline participation if it deems appropriate.

19.       Financial instruments

The Group's principal financial instruments comprise cash and cash equivalents, trade and other receivables and trade and other payables.

The main purpose of cash and cash equivalents financial instruments is to finance the Group's operations. The Group's other financial assets and liabilities such as receivables and trade payables, arise directly from its operations. It is, and has been throughout the entire period, the Group's policy that no trading in financial instruments shall be undertaken.

The main risk arising from the Group's financial instruments is market risk. Other minor risks are summarised below. The Board reviews and agrees policies for managing each of these risks.

Market risk

Market risk is the risk that changes in market prices, and market factors such as foreign exchange rates and interest rates will affect the entity's income or the value of its holdings of financial instruments.

The objective of market risk management is to manage and control market risk exposures within acceptable parameters while optimising the return.

The Company does not use derivative products to hedge foreign exchange risk and has exposure to foreign exchange rates prevailing at the dates when funds are transferred into different currencies.

Cash flow interest rate risk

The Group's exposure to the risks of changes in market interest rates relates primarily to the Group's cash and cash equivalents with a floating interest rate. These financial assets with variable rates expose the Group to cash flow interest rate risk. All other financial assets and liabilities in the form of receivables and payables are non-interest bearing. The Group does not engage in any hedging or derivative transactions to manage interest rate risk.

In regard to its interest rate risk, the Group continuously analyses its exposure. Within this analysis consideration is given to potential renewals of existing positions, alternative investments and the mix of fixed and variable interest rates.  The Group has no policy as to maximum or minimum level of fixed or floating instruments.

Interest rate risk is measured as the value of assets and liabilities at fixed rate compared to those at variable rate.

                                                   Weighted average                                 Fixed             Non - interest

                                                             interest rate                     interest rate                       bearing      

                                                                         2011                                  2011                           2011

Financial assets:                                                   %                                        £                                 £

Cash on Deposit                                                0.025                             2,574,997                                  -

Trade and other receivables                                      -                                          -                        324,465

Net fair value 

The net fair value of financial assets and financial liabilities approximates to their carrying amount as disclosed in the balance sheet and in the related notes.

Currency risk

The functional currency for the Group's operating activities is the Pound Sterling and for exploration activities the United States of America dollar.  The Group has not hedged against currency depreciation but continues to keep the matter under review.

Financial risk management 

The Directors recognise that this is an area in which they may need to develop specific policies should the Group become exposed to wider financial risks as the business develops.

Liquidity risk

Liquidity risk is the risk that the entity will not be able to meet its financial obligations as they fall due.

The objective of managing liquidity risk is to ensure as far as possible, that it will always have sufficient liquidity to meet its liabilities when they fall due, under both normal and stressed conditions.

The entity has established a number of policies and processes for managing liquidity risk.  These include:

-           Continuously monitoring actual and budgeted cash flows and longer term forecasting cash flows;

-           Monitoring the maturity profiles of financial assets and liabilities in order to match inflows and outflows; and

-           Monitoring liquidity ratios (working capital).

Credit risk management

Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. The Group's main counterparties are the operators of the respective projects. Funds are normally only remitted on a prepayment basis a short period before the expected commencement of drilling.  The Group has adopted a policy of only dealing with what it believes to be creditworthy counterparties and would consider obtaining sufficient collateral where appropriate, as a means of mitigating the risk of financial loss from defaults.  The Group's exposure and the credit ratings of its counterparties are continuously monitored and the aggregate value of transactions concluded is spread amongst approved counterparties. 

Trade receivables at 30 June 2011 consist primarily of revenues owed for production.  Ongoing credit evaluation is performed on the financial condition of accounts receivable.

Capital management

The Group's objective when managing capital is to ensure that adequate funding and resources are obtained to enable it to develop its projects through to profitable production, while in the meantime safeguarding the

Group's ability to continue as a going concern.  This is aimed at enabling it, once the projects come to fruition, to provide appropriate returns for shareholders and benefits for other stakeholders.  Capital will continue to be sourced from equity and from borrowings as appropriate. 

20.       Share based payments

Included within administration expenses is a charge for issuing shares and share options.

	Group	Group
	2011	2010
	£	£
Cost of issuing share options	18,445	84,489

Movements in share options in issue
Exercise price	Number of options issued as of 30 June 2010	Issued during year	Expired during year	Number of options issued  as of 30 June 2011
£0.20	340,144	-	-	340,144
£0.30	750,000	-	-	750,000
£0.40	550,000	-	-	550,000
£0.50	500,000	-	-	500,000
£0.60	300,000	-	-	300,000
£1.00	583,284	-	(483,284)	100,000
£1.25	250,000	-	(250,000)	-
£1.50	600,000	-	(500,000)	100,000
£2.00	600,000	-	(500,000)	100,000
Total	4,473,428	-	(1,733,284)	2,740,144

All shares options in existence at the year end have vested and are thus exercisable.

On 11 September 2009 the Company implemented a long term executive incentive scheme which was developed in conjunction with external executive compensation consultants, Deloitte LLP. As part of this scheme, Jay Cheatham and Justin Hondris have been granted options to acquire fully paid shares in the Company as outlined in Table 1 below. These options expire five years from date of grant and vest in three equal tranches on 11 September 2009, 30 June 2010 and 30 June 2011.  Each tranche comprises one third of the number of options at each exercise price.

Table 1

Exercise price	£0.30	£0.40	£0.50	£0.60	Total number of options issued
J Cheatham	400,000	300,000	300,000	200,000	1,200,000
J Hondris	350,000	250,000	200,000	100,000	900,000

A share based payments charge of £18,445 relating to the vesting of the third and final tranche of these options was incurred during the year.

No other options were exercised, forfeited or expired during the year.

The share options vested during the year were valued at £18,445 with reference to the Black-Scholes option pricing model taking into account the following input assumptions as outlined below:

Dates issued                                                              ranging 20 July 2009 to 11 September 2009

Share price                                                                                       ranging £0.1225 to £0.1475

Exercise Price                                                                                           ranging £0.20 - £0.60

Expected volatility                                                                                  ranging 69.2% to 83.4%

Vesting period                                                                     ranging 20 July 2009 to 30 June 2011

Expected dividends                                                                                                                Nil

Risk free interest rate                                                                                                       0.50%

Discount for illiquidity of unlisted options                                                                              30%

The volatility percentage is an estimation of the expected volatility in the share price for a junior exploration Company which is listed on AIM having regard to comparative companies, quantum of cash raised, targeted (institutional) investment group and risk profile.

All other options in existence during the year were fully expensed in prior years.

21.       Post balance sheet events

There were no material post balance sheet events.

22.       Related party transactions

There were no related party transactions during the period.

 

END

 

 

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