Final Results

For immediate release 26 November 2010

Leed Petroleum PLC

("Leed" or the "Company")

Final Results

For the year ended 30 June 2010

Leed Petroleum PLC (AIM:LDP) the oil and gas exploration and production company focused on the Gulf of Mexico, is pleased to announce its Final Results for the year ended 30 June 2010.

Highlights

Operational

·; Recommenced drilling programme in February 2010 encountering 65 feet of net pay sand in the Ship Shoal 201 A-6 well. Independent reservoir auditing firm attributed initial net 1P reserves of 1.1 MMBOE and net 2P reserves of 1.3 MMBOE (84% natural gas) to the reservoir. Following completion of facilities during calendar Q2 2010, daily production for the Company more than doubled from previous level as a result of adding the A-6 well.

·; Proved developed producing reserves at year end were 70% higher than at mid-year and 25% higher year-on-year.

·; Higher-capacity natural gas compressor installed at Eugene Island 184 platform.

·; Installed gas lift supply line in Main Pass 64 oil field during August 2009, approximately doubling well production capability.

·; East Cameron 317 field returned to production during December 2009 after being shut in for approximately 15 months following Hurricane Ike in 2008.

·; For the twelve months ended 30 June 2010, net oil, natural gas and natural gas liquids production sold was lower in comparison to the twelve month period ended 30 June 2009 (447 MBOE versus 738 MBOE respectively). However, a significant upward trend in oil, natural gas and natural gas liquids production began during May 2010 with the commencement of production from the Ship Shoal 201 A-6 well. Recent production rates for that well include a curtailed rate of approximately 1,148 gross (920 net) BOEPD for the month of October 2010.

Financial

·; Raised ￡20.0 million (￡19.3 million net after expenses) from the issuance of 400 million Ordinary Shares at 5 pence. Cash on hand of $10.8 million at 30 June 2010.

·; Amended bank credit facility and deleveraged the balance sheet by reducing outstanding bank debt to $26.5 million at period end.

·; Revenue of $23.3 million earned in the twelve months ended 30 June 2010.

Post period update

·; Sidetracked the Main Pass 64 #1 well which was drilled to a total measured depth of 8,086 feet on 19 September 2010. Leed owns a 25% working interest and a 19.18% net revenue interest in the well which encountered 71 net feet of true vertical thickness pay. The well was placed on production during November 2010.

·; During November 2010, the borrowing base on the Company's revolver facility was re-determined at $23.0 million, a reduction of $2.0 million which is payable on or before 31 March 2011. In addition, the Company reached an agreement with its bank, UniCredit Bank AG, whereby the bank agreed to waive certain conditions of default concerning the Company's credit facility that were expected to occur at the 31 December 2010 measurement date in return for an additional principal payment of $10.0 million on or before 31 March 2011 and a 1% increase in the credit facility interest rate effective 15 December 2010.

·; Leed is now exploring additional alternatives to re-finance the Company. These alternatives include, but are not limited to, selling all or part of the Company's oil and natural gas assets in order to pay off some or all of its bank debt by 31 March 2011, merging with another company, re-financing with another bank or another potential transaction.

The information set out herewith has been extracted from the Annual Report and Accounts 2010, which is being posted to shareholders today and is available to download from the company's website at www.leedpetroleum.com.

Chairman's statement:

Leed Petroleum PLC is pleased to report progress in developing its resources and reserves in the shallow offshore waters of the Gulf of Mexico. After beginning the period with our drilling programme suspended due to low commodity prices, conditions improved and in November 2009 the Company was able to raise net proceeds of £19.3 million through the placing of 400 million Ordinary Shares to institutional and other shareholders to recommence our drilling campaign. I am grateful for the continuing support of our shareholders.

We began applying funds from the share placing in January 2010 with the acquisition of an existing platform at Ship Shoal Block 202. In early February we successfully drilled the Ship Shoal A-6 well from that platform and placed the well on production in early May 2010, more than doubling the Group's production rate at that time. Our success at Ship Shoal demonstrates that our strategy is still relevant, repeatable and scalable.

In April 2010, Leed was awarded Grand Isle Block 96 at the federal lease sale. We believe that Grand Isle 96 will complement our leasehold position and upside reserve potential in the Grand Isle area. Most of the Group's oil and natural gas reserves are undrilled as reported in Leed's recent reserve auditor's report, which indicates 78 % of our proved and probable (2P) reserves remain undeveloped at the end of this financial year.

Like many other Gulf of Mexico companies, our planned activities were severely impacted as a result of the BP Macondo well blow-out whilst drilling and other activities were suspended as the US Department of the Interior reorganised and began promulgating new rules. Energy is the lifeblood of the industrialised world, but it comes with certain risks. Leed identifies and manages risk by employing hard working seasoned professionals who pay attention to detail, do things right, and follow strict standards and procedures to produce the Group's oil and natural gas reserves. After period end, we began moving forward with the development of our property portfolio taking advantage of improved oil prices by participating in the drilling of a non-operated oil well at Main Pass 64.

Leed had a very challenging year financially, with EBITDAX ("earnings before interest, taxes, depreciation, depletion, amortisation, exploration costs and impairments") for the year falling to a negative $1.0 million from a positive $23.9 million in the prior year. An after tax loss of $18.1 million was incurred on revenue of $23.2 million for this financial year. This was after an impairment of $23.5 million lowered the carrying value of its East Cameron 317/318 filed (a non-operated, non-core asset) during the restated 2009 financial year and de-recognising $7.2 million of deferred tax assets at financial year end 2010. Revenues and cash flows began to improve towards the end of the financial year as a result of new production from the Ship Shoal A-6 well.

As a result of adverse well performance and production delays, most notably the delay in recompleting the Eugene Island A-8 well to the more prolific T-1 sand reservoir, we have agreed to reduce our bank debt by $12.0 million on or before 31 March 2011. With that in mind, your Board of Directors is considering a broad range of strategic alternatives including, but not limited to, divesting some or all of the Company's oil and natural gas assets, securing a new bank credit facility and/or other potential transactions, such as a merger with another company. In choosing a strategic option, the Board will carefully consider whether the Company has adequate financial resources to continue to develop its resource base.

After two years as a Non-executive Director, Stephen Fleming announced he will stand down from the Board at the Annual General Meeting ("AGM") in December 2010 and Anthony Stalker will be nominated in his stead as a Non-executive Director and representative of our largest shareholder, ADM Galleus Fund Limited through their wholly owned subsidiary Asia Special Situations GJP1. We thank Stephen for his service and wish him all the best.

I thank management, staff and Directors for their hard work and efforts in what has been a challenging year for the Company and for the industry in the Gulf of Mexico. After the strategic options available to the Company are analysed, the Board will decide on the path forward to maximize shareholder value. We thank all of our shareholders and employees for their support.

Robert Adair

Non-executive Chairman

25 November 2010  

Oil and natural gas reserves

Leed owns a diversified portfolio of assets ranging from high impact exploratory prospects to lower risk undeveloped proved reserves.

Proved and probable reserves (also referred to as "2P reserves") are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. The figures are estimated on the basis that there should be a 90% probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and there should be a 50% probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable. Leed's proved and probable reserves are evaluated by independent petroleum engineers.

At 1 July 2010, the Group's proved and probable reserves comprised the following:

A substantial amount of Leed's oil and natural gas reserves are currently categorised as undeveloped. There can be no assurance that Leed will be able to fund the future capital required to fully develop its portfolio of undeveloped oil and natural gas reserves. In addition, the economics of developing such reserves are very sensitive to commodity prices. As such, future adverse movements in commodity prices could in turn have an adverse impact on the economics of developing Leed's undeveloped oil and natural gas reserves.

Chief Executive and operational report

The Company has continued to make progress in implementing its strategy of developing a diverse portfolio across the Gulf of Mexico region.

Asset base

With the spudding of the Ship Shoal A-6 well in February 2010, the Company recommenced development activity on its portfolio of seventeen offshore properties in the US waters of the Gulf of Mexico and one onshore Louisiana property. Numerous high quality projects with excellent potential have been identified and planned, which have the capacity to increase proved developed producing reserves and thereby our cash flows. All of the Company's offshore properties are located in shallow waters of the Outer Continental Shelf of the Gulf of Mexico.

The operational focus for the Group has been to maximise production from its producing fields and, following the side-by-side equity fund raising and credit facility amendment during late 2009, the Group successfully drilled the Ship Shoal 201 A-6 well. Leed's technical staff approach evaluation of each field from different but complementary professional perspectives that allow a full understanding of each project.

Production

For the year ended 30 June 2010 the Company's total net production averaged 1,224 BOEPD (37% crude oil, 56% natural gas and 7% natural gas liquids), as compared to 2,022 BOEPD (43% crude oil, 49% natural gas and 8% natural gas liquids), in the prior year. The Company experienced several well performance issues during the 2010 financial year, as monthly production rates ranged from a high of 1,943 BOEPD in July 2009, declined to a low of 610 BOEPD in April 2010, and rebounded to 1,862 BOEPD during June 2010 as a result of placing the Ship Shoal 201 A-6 well into production.

Reserves

Leed's resumption in drilling has resulted in proven developed producing reserves have increased period-to-period. As of 1 July 2010, the Group had net proved producing reserves of 1,726 MBOE an increase of 25%, as compared to 1,386 MBOE a year earlier. The Company has an independent oil and natural gas reserves assessment prepared at least annually.

Ship Shoal

Leed's success in developing its Ship Shoal 201 licence, where it is the operator and holds a 100% working interest, was one of the most significant events during the past year. Leed is also the operator of two adjacent blocks (Ship Shoal 197 and Ship Shoal 202), where it holds a 75% working interest.

Following the Group's equity fundraising in late November 2009, Leed acquired an existing platform on Ship Shoal 202 during January 2010 and successfully drilled the Ship Shoal 201 A-6 well during February 2010. The Ship Shoal opportunity developed a downthrown fault closure with oil and natural gas reserves in a Pleistocene sand stone. After reaching a measured depth of 13,341 feet, the Company logged 65 feet of net pay sand in one reservoir and flow tested the Ship Shoal 201 A-6 well at an initial rate of 10.4 MMCFPD and 423 BOPD (approximately 2,156 gross BOEPD equating to 1,729 net BOEPD). Following refurbishment and completion of the facilities, the well was placed online on 6 May 2010, a mere 94 days after the well had been spudded, demonstrating the advantage of operating in the Gulf of Mexico where there is a wealth of existing infrastructure to support new production.

Commencement of production from this well more than doubled the entire Company's production at the time. During the month of October 2010, production from the Ship Shoal 201 A-6 well was curtailed and averaged approximately 1,148 BOEPD gross (920 BOEPD net). We believe this is a clear demonstration that Leed's approach is relevant, repeatable and scalable to other projects in the Leed portfolio.

Eugene Island

Leed's Eugene Island field is located approximately 50 miles south of Morgan City, Louisiana in approximately 80 feet of water. The property comprises three licences: Eugene Island 172, 183 and 184. Leed operates the property and owns an average working interest of 75% across the three licences.

The field was originally discovered by a major oil company in 1955 with the original wells drilled adjacent to the salt dome which straddles blocks 172 and 184. Several low risk development and exploration opportunities have been identified and these comprise the upside potential of these under exploited assets. The Company's A-6, A-7 and A-8 wells at Eugene Island during 2007 and 2008 further confirmed the region's geology and allowed further refinement of our understanding of the potential.

The much anticipated recompletion of the A-8 well from the Mid-Tex sand reservoir to the more prolific T-1 sand reservoir has yet to occur. Production from the A-8 well continued to decline during the past year, but has yet to decline to rate that would justify approval from the BOEMRE ("Bureau of Ocean Energy Management, Regulation and Enforcement") to recomplete the well into the T-1 reservoir. It is possible that the reservoir will not deplete to a level sufficient to obtain regulatory approval of the well recompletion for some time.

Assuming there are no regulatory road blocks during financial year 2011 and adequate financial resources, the Company is considering an alternative plan of drilling a sidetrack well into the T-1 sand in lieu of waiting for the A-8 well to deplete its current producing zone. Leed looks forward to the possibility of exploiting and unlocking the cash flow from the T-1 sand at Eugene Island which is estimated to contain 2,892 net mboe of proved developed reserves. During 2010, the Company installed additional natural gas compression to enhance long-term field deliverability.

At period end, the A-6 and A-7 wells were not producing due to sand control issues. The Group is currently evaluating the best approach to economically attempt to place these wells back on production. During October 2010, production from the Eugene Island field averaged approximately 441 BOEPD gross (266 BOEPD net).

Main Pass

Main Pass 64/65 field is a non-operated property located in federal waters approximately 18 miles east of Venice, Louisiana in about 30 feet of water. Leed holds a working interest averaging approximately 25% across the Main Pass 64/65 field, which was discovered in 1982 and consists of two licences: all of Main Pass block 64 and the federal water portion of Main Pass block 65. The field sits atop a large deep seated structural high which sets up a combination of four-way and stratigraphic closures which trap both oil and natural gas. Natural gas produced in the field is utilised for operations and to gas lift oil, the only product being sold.

Main Pass 64/65 oil production comes predominately from two sands, the 6,900-foot and 7,300-foot sands. The majority of the field's historical production and remaining proved oil reserves are contained in the 7,300-foot sand which is subject to a successful waterflood pressure maintenance program utilising a "dump flood" in which water is crossflowed directly from a shallower higher pressure water sand to the oil bearing 7,300-foot sand.

In addition to the producing reservoirs, exploration and exploitation potential exists in the intermediate and deep intervals. Wells in the non-operated Main Pass 64/65 field were restored to full production capability during the past financial year by installing a gas lift supply line from an offset operator's field. However, production was hampered whilst the owner of the third party oil sales line serving the field made repairs to its line. At year end the field was shut in. However, during August 2010 the operator of the field began barging oil prior to the recommencement of pipeline service, which occurred during early November 2010. During October 2010 oil production from the Main Pass 64/65 field averaged approximately 824 BOEPD gross (158 BOEPD net).

After year end, the operator of the field sidetracked the Main Pass 64 #1 well, reaching a total measured depth of 8,086 feet on 19 September 2010. Leed owns a 25% working interest and a 19.18% net revenue interest in the well which encountered approximately 71 feet of true vertical thickness pay. The well was placed on production during November 2010.

In addition to its interests in Main Pass 64 field, Leed was awarded Main Pass block 115 in MMS lease sale 205 in 2007. The block is located approximately 83 miles southeast of New Orleans, Louisiana in 50 feet of water. The Company has identified several exploratory opportunities on the licence and owns 100% working interest in the property subject to Byron Energy Pty. Ltd.'s right to acquire up to 25% of Leed's working interest in the block.

East Cameron

The non-operated East Cameron 317/318 field is located offshore approximately 112 miles south of Cameron, Louisiana in about 224 feet of water. Both licences produce from Upper and Lower Pleistocene progradational deltaic sandstones. Leed owns a 25% working interest in the East Cameron 317/318 field.

The field returned to production during December 2009 after being shut in for approximately 15 months following Hurricane Ike in 2008. The field has since flowed natural gas at a steady rate, including approximately 2.0 gross (0.4 net) MMCFPD during October 2010.

Grand Isle

Grand Isle 95, 96 and 100 sit in approximately 200 feet of water about 100 miles south of New Orleans, Louisiana and form part of a large field discovered by a major oil company in 1974. Leed is operator and holds a 100% working interest subject to a working interest election of up to 25% by Byron Energy Pty, Ltd. The Grand Isle 95 field is located on the upthrown side of a large regional fault which trends northeast to southwest with hydrocarbons trapped in several sand intervals. It is believed that salt migration was responsible for creating the fault system, setting up the structural trap which crests in the northwestern corner of Grand Isle 95. Sediments dip to the southeast, with hydrocarbon accumulations generally trending northeast to southwest and are comprised of a complex series of enechelon bar sands. Hydrocarbons are trapped either stratigraphically or by fault bound structural closures or a combination thereof. Producing horizons provide strong analogies for Leed's exploration prospects in Grand Isle blocks 95 and 96.

Leed acquired its Grand Isle licences over blocks 95 and 100 in May 2006 (expires May 2011) and block 96 in April 2010 (expires April 2015). Assuming the Company is successful in funding this project during early 2011 and natural gas prices are at sufficient levels to justify the investment, Leed plans to drill a well on Grand Isle 95 prior to its expiration date.

Together the Grand Isle block 95 and 96 licences provide Leed with a material working interest in a range of prospects from pure exploration resources to a proved reserve development opportunity. Should Leed's drilling campaign prove successful, the Company would need to install a platform and facilities on its leasehold.

South Marsh Island

South Marsh Island consists of two licences, South Marsh Island 8 and Eugene Island 133, both of which are located in approximately 60 feet of water about 90 miles south-southeast of Lafayette, Louisiana. South Marsh Island 8 was initially developed by a major oil and natural gas company and was acquired by Leed in August 2008. Leed is operator and holds a 100% working interest subject to a working interest election of up to 25% by Byron Energy Pty, Ltd. in South Marsh Island 8 and a 75% working interest in Eugene Island 133.

The Company has identified numerous opportunities in the field with 3-D seismic, subsurface well control, and by matching historical production data. The opportunities lie on the southeast flank of a large salt dome. The field has produced from numerous sands at depths ranging from 10,000 feet to 15,000 feet.

Oil and natural gas were trapped in structural closures bound on the west by salt, the north and south by radial faults, and the east by structural dip. The opportunities consist of proved undeveloped, probable undeveloped, and possible undeveloped locations targeting numerous pay sands.

The proved undeveloped locations are well defined and updip to previously producing wells. The probable undeveloped locations are predominately in undrilled fault blocks adjacent to production and updip to wells which logged oil and or natural gas. The numerous prospects at South Marsh Island will enable Leed to drill wells with multiple objectives. Should Leed's drilling campaign prove successful, the Company will have to install a platform and facilities on its lease.

Sorrento

Leed's only onshore property is located in a field created by a salt dome structure in Ascension Parish, Louisiana approximately 50 miles northwest of New Orleans. Leed is the operator and holds a 100% working interest. It contains both proved reserves and exploratory prospects as confirmed by the Company's reserves auditor. The field was discovered by a major oil company in 1929 and Leed holds a 100% working interest in its acreage which is located on the eastern and northern flanks of the Sorrento salt dome. Proved reserves are located in the Lower Miocene Marg A Sand and Planulina Sands. The trapping mechanisms are both structural and stratigraphic. Leed's acreage is located at the eastern edge of the productive Oligocene Marg Vag trend, which the Company believes has additional untapped exploration potential.

As of the date of this report, the Sorrento field, comprised of one legacy well and a saltwater disposal well, was shut in.

West Cameron

West Cameron block 106 is a promising exploration prospect located in approximately 30 feet of water offshore Louisiana and is owned 100% by the Company, subject to Byron Energy Pty. Ltd.'s right to acquire up to 25% of Leed's working interest in the block. There are no proved or probable reserves associated with the prospect. The licence drew multiple bids at the federal auction in which Leed acquired the prospect.

Outlook

During the second half of the financial year the Company significantly increased production. We are excited about progressing forward with development of Leed's resource base. Our staff have worked diligently to prepare a high quality line up of projects that provide the capacity for strong growth in reserves and production once we have overcome the financial hurdles and other hurdles that we currently face.

Howard Wilson

Chief Executive Officer

25 November 2010

Financial review

The Company's period under review is the financial year ended 30 June 2010. The financial year ended 30 June 2009, which has been restated for a non-cash property impairment (refer to Note 30 "Restatement of prior period" within the current year financial statements), is also presented to aid with comparison.

Consolidated statement of income

The 2010 financial year presented many challenges, both operationally and financially. The Company incurred a loss of $18.1 million during the 2010 financial year, as compared to a restated loss of $18.5 million for the prior year.

Revenues declined 31% to $23.2 million, principally as a result of adverse well performance issues and pipeline shut ins that resulted in an overall drop in production of 40% (447 MBOE for the 2010 financial year, as compared to 738 MBOE for the prior year). The Group's daily production rate during the 2010 financial year began at 1,943 BOEPD in July 2009 and declined to 610 BOEPD in April 2010 before rebounding to 1,862 BOEPD in June 2010 after the Ship Shoal 201 A-6 well was placed online in May 2010. Oil and natural gas commodity price movements included a 26% increase in average oil prices ($73.92 per bbl in the 2010 financial year, as compared to $58.88 per bbl in the prior year) and a decrease in average natural gas prices of 18% ($4.64 per MCF in the 2010 financial year, as compared to $5.67 per MCF in the prior year). Gas processing fees were $2.7 million for the 2010 financial year, an increase of $2.2 million over the prior year, due to a favourable ownership adjustment regarding the Group's interest in the N. Terrebonne gas processing plant and Tebone gas fractionation plant, which is based on the percentage of natural gas production from our Eugene Island field, as compared to total overall natural gas production processed by the plants.

Production costs per BOE increased to $16.87 per BOE in the 2010 financial year, as compared to $7.44 per BOE for the prior year. The increase per BOE was a reflection of lower production rates coupled with higher production costs. A majority of the higher production costs were applicable to Eugene Island, where the A-6 and A-7 wells were shut in at period end due to sand control issues.

Depletion (per BOE of proved/probable reserves produced) was $24.89 per BOE for the 2010 financial year, as compared to $27.61 per BOE for the prior year. The depletion rate per BOE was reflective of the level of oil and natural gas reserves and the mix of production from each producing field during each financial year.

Administrative costs were $15.2 million in the 2010 financial year, as compared to $12.2 million for the prior year. The year-on-year increase of $3.0 million included increased insurance costs of $2.5 million, which was a result of industry-wide insurance premium increases experienced by most oil and gas companies operating in the Gulf of Mexico during the past year. The number of employees and Directors receiving wages or fees averaged 29 for the periods ended 30 June 2010 and 2009. No management bonuses were accrued for or paid during either financial year.

The Group adjusts the fair value movements of its derivatives through other gains and losses at the end of each financial period. Changes in the fair value of the Group's derivatives outstanding at each financial period end resulted in an unrealised loss of $1.0 million for the 2010 financial year and a gain of $6.5 million for the prior year. Realised gains and losses on oil and natural gas commodity contracts that closed in the current year were also included in other gains and losses and included a gain of $1.7 million in each of the 2010 and 2009 financial years.

During the year, the Group carried out a thorough review of its impairment testing procedures and concluded that the single cash generating unit that previous reviews had been based on was inappropriate to the current business structure. Cash generating units are now based on individual fields in distinct geographical locations with proved and probable reserves, unless cash flows are directly linked to another field. As a result of this more detailed and rigorous assessment of impairment, an impairment was identified with respect to the East Cameron 317/318 field (a non-core and non-operated property for which the Group has a 25% working interest) which was offline from August 2008 until December 2008 due to third party pipeline damage from Hurricane Ike. Upon further analysis, it was determined that this field was impaired at 30 June 2009 due to low natural gas prices coupled with negative volumetric reserve adjustments. As a result, the Group recorded before tax non-cash impairment expense of $23.5 million for the 2009 financial year. Accordingly, the Group's financial statements for the 2009 financial year have been restated to reflect the aforementioned adjustment.

As noted in the Report of the Directors, EBITDAX for the 2010 financial year included a loss of $1.0 million, as compared to income of $23.9 million for the prior year. The variance between years was principally due to a combined $17.9 million decrease in revenues and other gains and losses, coupled with a $6.2 million decrease in the amount of depreciation, depletion and amortisation added back as an adjustment to EBITDAX for the 2010 financial year, as compared to the prior year.

Statement of financial position

In the year ended 30 June 2010, carrying value of the Group's property plant and equipment increased by a net of $3.4 million to $127.0 million. During the year, the Company recorded gross asset additions of $15.7 million (including $13.1 million to drill and complete the Ship Shoal 201 A-6 well).

In the current year, the Group also expended $0.7 million towards exploration and evaluation assets, including a 100% working interest in Grand Isle 96 for $0.4 million at the federal lease sale. Grand Isle 96 is adjacent to Grand Isle 95, where the Company holds a 100% working interest subject to an election of up to a 25% working interest by Byron Energy Pty, Ltd.

Cash flows and funding

During November 2009, the Company completed an additional equity fund raising pursuant to which it issued 400 million Ordinary Shares (5p) at 5 pence each to raise net proceeds of $31.6 million. The Group used the net equity proceeds primarily to re-commence its drilling programme and to reduce its credit facility.

Also during November 2009, the Group entered into an amended and restated credit facility with its bank, which was further modified during November 2010 and is more fully described in Note 15 "Borrowings" of the financial statements within this annual report. At 30 June 2010, the amended and restated credit facility comprised two tranches: a revolver loan ($25.0 million principal balance) and a term loan ($1.5 million principal balance). The effect of the November 2010 modification to the Group's credit facility resulted in the following:

·; the Group will be required to make a principal payment of $12.0 million on or before 31 March 2011;

·; the interest rate on the revolver and term tranches of the credit facility will increase by 1% effective 15 December 2010. As a result, the interest rate will be at three month LIBOR plus 7.25% for the revolver facility and three month LIBOR plus 8.0% for the term facility as of that date; and

·; the maximum credit facility will be set at $30.0 million as of 15 December 2010 and will be reduced by $6.0 million in a semi-annual basis thereafter.

As of the date of this report the Group is exploring several alternatives including divesting some or all of its oil and natural gas assets in order to raise $12.0 million or more to pay off some or all of its bank borrowings prior to 31 March 2011. Additional alternatives under consideration include, but are not limited to, securing a new bank credit facility and/or other potential transactions such as a merger with another company.

Going concern

The Directors have prepared cash flow forecasts (including selected sensitivities) for the Company covering a twelve month period from the authorisation of these financial statements. The cash flow forecasts reflect the Company's plan for the coming year, including expected net proceeds from divestitures, projected production rates, commodity prices, capital expenditure levels, principal payments, interest rates and expected compliance with loan covenants. Based on these assumptions, which the Board believes are reasonable, these cash flow forecasts show that the Group should have sufficient liquidity to continue as a going concern. Nevertheless, possible adverse future events or circumstances are beyond the control of the Company and seriously influence doubt on the Company's ability to continue as a going concern. Moreover, the regulatory environment in the Gulf of Mexico post the BP oil spill at Macondo is in flux and some regulatory changes under consideration in the US Congress could imperil the Company's business model. Clearly, it is impossible to predict the regulatory changes that may come about on account of governmental initiatives.

Future growth of the Group during the next twelve months and beyond is heavily dependent upon the Group's ability to raise enough capital to continue the development of its undeveloped oil and natural gas reserve portfolio, which represents approximately 78% of its oil and natural gas reserves calculated on a BOE basis at 1 July 2010. The cash flow forecasts assume the Group will be successful in raising sufficient capital to further develop these oil and natural gas reserves.

After carefully considering the aforementioned factors, cash flow forecasts and material uncertainties set forth within Note 2.20 "Significant accounting policies - going concern" within the financial statements for the 2010 financial year, the Directors' assessment is that Leed is a going concern. Clearly, we will face challenges in the period ahead.

James Slatten

Chief Operating Officer

25 November 2010

Report of the Directors

for the year ended 30 June 2010

The Directors of Leed Petroleum PLC ( "Leed", "the Company" or "Parent Company") present to shareholders this report and the audited consolidated financial statements as of and for the year ended 30 June 2010. The year ended 30 June 2009 is also presented for comparative purposes. The Company is listed on AIM part of the London Stock Exchange ("AIM") and trades under the symbol LDP.

Principal activity

The principal activity of the Company and its subsidiaries (together, the "Group" or "Leed") is exploring, developing, producing and operating oil and natural gas properties from onshore and offshore locations within the Gulf Coast region of the United States. As of 30 June 2010, the Group has working interests in seventeen offshore blocks (including eight producing and nine non-producing) and one onshore field. The Group also holds a small interest in a gas processing plant and a fractionation plant located onshore in Louisiana. In the current period, the Group acquired one new offshore block from the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE"). Leed believes the interests it owns in its non-producing assets have significant potential for future production.

Business review

The financial year ended 30 June 2010 presented many challenging issues, both operational and financial:

Operational review

Production performance was hampered throughout the year ended 30 June 2010, primarily at the Eugene Island field, where the Eugene Island 183 A-8 well continued to decline at a steady rate, but not in sufficient quantity to obtain regulatory approval for the recompletion into the more prolific T-1 sand. Two other wells in the field, the Eugene Island 183 A-6 and Eugene Island 183 A-7, each experienced significant downtime due principally to sand control issues and were not producing at period end. The Company's Main Pass 64/65 field also experienced significant downtime during the year ended 30 June 2010 due to ongoing pipeline repair issues and was shut in at period end. The East Cameron 317/318 field came back online during December 2009 after being offline for fifteen months while hurricane damage to the third party pipeline serving the field was repaired. During May 2010, the Group commenced production from the Ship Shoal 201 A-6 well (drilled during the first calendar quarter of 2010) at an average rate of approximately 1,295 net BOEPD, which was the primary contributor to the higher BOEPD rate for May 2010 and June 2010.

During the year ended 30 June 2010, the average net BOE produced per day reached a high of 1,943 net BOEPD during July 2009 and dipped to a low of 610 net BOEPD in April 2010, before rebounding to 1,862 net BOEPD at the end of June 2010.

Financial review

The Group recorded a loss after taxation of $18.1 million for the period ended 30 June 2010, as compared to a restated loss of $18.5 million for the prior year. Components of the $18.1 million loss for the period ended 30 June 2010 comprised the following:

Revenues: Revenues were $23.2 million for the period ended 30 June 2010, a decrease of 31% as compared to the prior year. Oil, natural gas, and natural gas liquids production for the period ended 30 June 2010 was 447 MBOE, a decrease of 40% (49% crude oil production decrease and 39% natural gas production decrease), as compared to 738 MBOE for the prior year. Average crude oil prices were 26% higher ($73.92 per bbl for 2010 as compared to $58.88 per bbl for 2009), while average natural gas prices for 2010 were 18% lower than 2009 ($4.64 per mcf during the year ended 30 June 2010, as compared to $5.67 per mcf during the year ended 30 June 2009). Gas plant processing fees included a year-on-year increase of $2.2 million, as the Group's ownership interest in the N. Terrebonne gas processing plant and Tebone gas fractionation plant increased from 0.6% to 2.5% as a result of a favourable ownership adjustment which was based on the percentage of natural gas production from our Eugene Island field, as compared to total overall natural gas production processed by the plants.

Cost of sales: The Group's cost of sales was $22.2 million for the period ended 30 June 2010, a decrease of $2.2 million as compared to the prior year. The year-on-year decrease was principally due to a $6.2 million reduction in depletion costs, which were partially offset by $4.0 million of higher production costs, which include both lease operating costs and gas plant processing costs. Lease operating costs were $2.0 million higher for the year ended 30 June 2010 as compared to the prior year, primarily as a result of higher work over costs associated with adverse well performance issues at the Eugene Island field. Gas plant processing costs also included a year-on-year increase of $2.0 million, primarily due from the Group's aforementioned annual ownership adjustment in the N. Terrebonne gas processing plant and fractionation plant that was effective 1 January 2010.

Administrative expenses: The Group's administrative costs were $15.2 million for the period ended 30 June 2010, an increase of $3.0 million over the prior year. Insurance expenses, which are included within administrative costs, were $6.1 million, an increase of $2.5 million over the prior year.

Other losses and gains: The Group's other gains and losses were comprised of net gains of $0.8 million for the year ended 30 June 2010, as compared to a net gain of $8.1 million that was principally the result of commodity hedging activity during the prior year. During the year ended 30 June 2010, forward commodity prices were substantially higher as compared to the prior year, which in turn resulted in lower unrealised gains pertaining to the fair value of its commodity hedges at period end.

Non-cash impairment of oil and natural gas properties: The Group did not have any non-cash impairment expense or recovery during the period ended 30 June 2010, as compared to a restated non-cash impairment expense of $25.1 million during the period ended 30 June 2009, which included a non-cash impairment of $23.5 million pertaining to its East Cameron 317/318 field (a non-core and non-operated property for which the Group has a 25% working interest). The East Cameron 317/318 field non-cash impairment was the result of a change in application of accounting policy pertaining to identified cash generating units for impairment testing purposes that was instituted for the period ended 30 June 2010. The Group now tests each field for impairment as an individual cash generating unit, as compared to grouping all fields as a single cash generating unit in prior periods, since such an application provides more relevant information. Changing application of this policy required the financial statements for the period ended and as of 30 June 2009 to be restated. See Note 30 "Restatement of prior period" within the Group's financial statements included in this report.

Loss on sale of assets: The Group did not record any gains or losses from the sale of assets during the period ended 30 June 2010. During the prior year, the Group recorded a loss on the sale of assets of $2.5 million pertaining to sale of a 25% working interest in the Group's Eugene Island field.

Finance income and finance costs: The Group's net finance income and finance costs for the period ended 30 June 2010 of $3.6 million were broadly flat, as compared to $3.8 million for the prior year.

During November 2009, the Company issued 400,000,000 new Ordinary Shares at 5 pence par value to raise a net amount of $31.6 million, which was inter-conditional on amending its credit facility. After the share placement, the Group paid down its credit facility from $41.0 million to $35.0 million. The Group made additional principal payments during the remainder of the year ended 30 June 2010 of $8.5 million, resulting in an overall principal balance of $26.5 million at period end pertaining to its bank credit facility. On 30 June 2010, the Group's bank granted a waiver of certain defaults and the interest rate applicable to its credit facility increased 2% effective 15 June 2010. During November 2010, the Company reached an agreement with the Group's bank whereby the Company would make and additional principal payment of $12.0 million on or before 31 March 2011 and the interest rate on its credit facility would increase by 1% effective 15 December 2010 in return for waiving certain conditions of default that may exist at the 31 December 2010 measurement date.

Key performance indicators

Leed focuses on four key performance indicators:

(1) Growth of hydrocarbon reserves;

(2) Production of oil and natural gas reserves;

(3) Cash flows and earnings growth; and

(4) Material adverse health, safety and environmental events.

Oil and natural gas reserves

The Group's oil, natural gas and natural gas liquids reserves, as quantified by an independent reserves auditor, are recapped below:

Proved reserves were relatively flat between the above referenced independent reserve reports. A recap of the Group's 2P reserves at 1 July 2010 follows:

A substantial amount of the Group's oil and natural gas reserves are currently categorised as undeveloped. There can be no assurance that the Group will be able to fund the future capital required to fully develop its portfolio of undeveloped oil and natural gas reserves. In addition, the economics of developing such reserves are very sensitive to commodity prices. As such, future adverse movements in commodity prices could in turn have an adverse impact on the economics of developing the Group's undeveloped oil and natural gas reserves.

Oil, natural gas and natural gas liquids production

Details of the Group's net oil and natural gas volumes produced and sold are as follows:

Financial year-on-year production volumes were lower due to the natural production declines of existing wells, sand control issues at the Eugene Island field and the postponement of the Group's drilling program in calendar year 2009 due to the global financial crisis that began in late 2008. During the first half of 2010, the Group re-commenced its drilling programme by drilling the Ship Shoal 201 A-6 well, which began producing during May 2010 at a rate of approximately 1,295 net BOEPD, effectively reversing the trend of declining production experienced in prior months.

Cash flows and earnings

The Group measures its cash flow and earnings growth by utilising the metric earnings before interest, taxes, depreciation, depletion, amortisation, exploration costs and impairments ("EBITDAX"). EBITDAX for the years ended 30 June 2010 and 2009, respectively, was comprised of the following items:

During the years ended 30 June 2010 and 2009, the Group's loss before taxation was $16.9 million, a $9.1 million decrease, as compared to a loss of $26.0 million for the prior year (see "Business review"). The decrease of $6.2 million in depreciation, depletion and amortisation for the year ended 30 June 2010 over the prior year was principally due to lower year-on-year oil and natural gas production. During the year ended 30 June 2010, the Group had no non-cash impairment expense or recovery, as compared to a restated non-cash impairment expense of $25.1 million for the prior year. Net financing expense was relatively flat year-on-year. The Group did not sell any oil and natural gas assets during the period ended 30 June 2010, while it incurred a $2.5 million loss on the sale of oil and natural gas assets of $2.5 million during the prior year.

Health, safety and environmental

During the years ended 30 June 2010 and 2009, the Group did not experience any material adverse health, safety or environmental events.

Substantial interests

The following shareholders have reported to the Company that they own more than 3% of the issued Ordinary Shares of 5 pence each in the share capital of the Company as at 30 June 2010:

Principal risks and uncertainties facing the Group

Going concern

During the past financial year, the Group's financial performance was affected by adverse production performance issues. In the Eugene Island field, the Eugene Island 183 A-8 well continued to decline at a steady rate, but not in sufficient quantity to obtain regulatory approval for the recompletion into the more prolific T-1 sand. Two other wells in the field, the Eugene Island 183 A-6 and Eugene Island 183 A-7, each failed to produce at anticipated production levels, principally due to sand control issues, and were not producing at period end. The Group's Main Pass 64/65 field also experienced significant downtime during the year ended 30 June 2010 due to ongoing pipeline repair issues and was shut in at period end. The aforementioned items were the primary contributors to a 31% decrease in year-on-year revenues, resulting in a $1.0 million negative EBITDAX for the 2010 financial year, as compared to positive $23.9 million EBITDAX for the 2009 financial year.

The Group's banking facility is subject to financial covenants and other conditions which the Group monitors regularly. These covenants and conditions are sensitive to changes in EBITDAX, interest rates, commodity prices, production levels, net assets and estimated oil and natural gas reserves. The Group's ability to comply with such covenants and conditions in future periods is a key element in the ability of the Company to continue as a going concern. During June 2010, the Group disclosed certain defaults on the credit facility to its bank, UniCredit Bank AG, that were projected to exist at the 30 June 2010 review date. The defaults related to EBITDAX ratios pertaining to the period ended 30 June 2010 that were projected to be deficient at period end, principally due to oil and natural gas production performance issues incurred during the aforementioned twelve month period that negatively affected EBITDAX. Following discussions with UniCredit Bank AG, the Group agreed to an interest rate increase of 2% on its credit facility effective 15 June 2010 in exchange for waiving the projected defaults to ensure the Group would be in full compliance with the terms and conditions of its banking facilities at 30 June 2010. During November 2010, the Group reached an agreement with the Group's bank whereby the Group would make an additional principal payment of $12.0 million on or before 31 March 2011 and the interest rate on its credit facility would increase by 1% effective 15 December 2010 in return for waiving certain conditions of default that may exist at the 31 December 2010 measurement date. The Group is uncertain of the bank's stance post 31 March 2011 and this could therefore represent a significant risk to the Group.

As of the date of this report the Group is exploring several alternatives including divesting some or all of its oil and natural gas assets in order to raise $12.0 million or more in order to pay off some or all of its bank borrowings prior to 31 March 2011. Additional alternatives under consideration include, but are not limited to, securing a new bank credit facility and/or other potential transactions, such as a merger with another company. In anticipation of executing one or a combination of the aforementioned alternatives during the 2011 financial year and the accompanying measurement uncertainty thereof, the Company wrote off its net deferred tax balances of $7.2 million during the period ended 30 June 2010.

The Directors have prepared cash flow forecasts (including selected sensitivities) for the Company covering a twelve month period from the authorisation of these financial statements. The cash flow forecasts reflect the Company's plan for the coming year, including expected net proceeds from divestitures, projected production rates, commodity prices, capital expenditure levels, principal payments, interest rates and expected compliance with loan covenants. Based on these assumptions, which the Board believes, are reasonable, these cash flow forecasts show that the Group should have sufficient liquidity to continue as a going concern. Nevertheless, possible adverse future events or circumstances are beyond the control of the Company and could seriously influence the Company's ability to continue as a going concern. Moreover, the regulatory environment in the Gulf of Mexico post the BP oil spill at Macondo is in flux and some regulatory changes under consideration in the US Congress could imperil the Company's business model. Clearly, it is impossible to predict the regulatory changes that may come about on account of governmental initiatives.

Future growth of the Group during the next twelve months and beyond is heavily dependent upon the Group's ability to raise enough capital to continue the development of its undeveloped oil and natural gas reserve portfolio, which represents approximately 78% of its oil and natural gas reserves calculated on a barrels oil equivalent ("BOE") basis at 1 July 2010. The cash flow forecasts assume the Group will be successful in raising sufficient capital to further develop these oil and natural gas reserves.

The Directors' assessment of the Group's ability to continue as a going concern involves making a judgement about inherently uncertain future outcomes of events and conditions based upon available information at the time of assessment. Subsequent events and additional information may result in outcomes that are inconsistent with judgements that were reasonable at the time they were made. The Directors have concluded that the combination of these circumstances represents a material uncertainty that casts significant doubt upon the Group's ability to continue as a going concern and that, therefore, the Group may be unable to realise its assets and discharge its liabilities in the normal course of business. Nevertheless, after making enquiries and considering the uncertainties described above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. For these reasons, they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

Commodity price risks

The Group derives substantially all of its income from the sale of oil, natural gas and natural gas liquids. Commodity prices are highly volatile and the Group's income will drop significantly with a material decline in the prices of crude oil, natural gas and/or natural gas liquids. The Group has derivative commodity contracts in place to offset to a small degree commodity price declines and the Group could defer capital expenditures if the pricing environment becomes unfavourable. However, without a viable drilling programme, the Group will come under financial pressure to reduce its debt and, in such an environment, growth would be difficult to achieve.

Technical performance

Finding, developing and producing oil and natural gas is a highly technical endeavour. Large sums of capital expenditures must be spent to search for and produce hydrocarbons. Drilling disappointments can occur and engineering challenges can result in incurring higher than expected costs. Oil and natural gas reserve estimates can misstate the quantity of hydrocarbons in place, resulting in reserve revisions. The Group's drilling and production projects are evaluated on rigorous technical standards using state-of-the-art technology and the Group regularly accesses leading industry service providers to advise it on technical issues relating to its operations. Estimated oil and natural gas reserves are reviewed and updated twice annually and are audited by an independent reserve auditor at least once each year. Such reserve reports are also utilised as a basis to periodically determine the Group's available borrowing base under the terms of its bank credit facility and for impairment testing purposes. Due to numerous assumptions, including commodity prices, volumetric decline curves, operating costs, capital expenditures and other factors, actual results could vary materially from estimates contained within the reserve report prepared by the independent reserve auditor.

Infrastructure limitations

A well developed oil and natural gas production and transportation infrastructure exists in the onshore and offshore Gulf Coast region of the United States. Nevertheless, the Group is dependent on production, transportation and refining facilities owned by third parties to bring its oil, natural gas and natural gas liquid production to market. The Group manages these risks through contractual relationships with third parties and to some extent certain risks of loss of access to transportation facilities are mitigated by open access laws. Disruption of third party transportation service can arise from a variety of circumstances including weather damage, accidents and obsolescence. In the financial year under review, the Company did experience a disruption in its East Cameron field as the sales pipeline owned by a third party was damaged and went out of service following a hurricane during 2008 and did not come back online until December 2009. In addition, the Main Pass field was shut in at period end due to repairs to its third party sales pipeline, which did not come back online until October 2010.

Asset concentration risk

The Eugene Island and Ship Shoal assets are the Group's core producing assets and hence its core cash flow source. The Group plans to diversify its production base through a combination of future acquisitions and drilling on its assets over time in other areas in future periods. In the near future, however, asset concentration risk may increase if the Group drills additional wells in the proximity of its existing infrastructure in order to expedite production and near-term cash flows.

Capital development risk

Continued development of the Group's portfolio of oil and natural gas properties with proved and probable reserves will require substantial future outlays of capital. If the Group is unable to finance its share of such expenditures from existing cash flows and/or capital resources, the Group will have to raise capital from other sources such as additional debt financing, placement of additional Ordinary Shares in an equity offering, selling all or partial property interests or a combination thereof. There can be no assurance that the Group would be able to obtain such financing. In addition, there can be no assurance that existing partners in the Group's projects will be able to carry their pro-rata share of future capital costs, which could in turn lead to delays and other adverse financial issues. Further, the Group does not control the timing or scope of future capital projects on the Main Pass 64/65 and East Cameron 317/318 fields, where it holds a minority non-operated 25% working interest.

Exposure to casualties and other events

Substantially all of the Group's oil and natural gas assets are located in the shallow waters of the US Gulf of Mexico, where they may be subjected to blow-outs, hurricanes, unstable sea floor conditions, fire and explosion, collision with moving vessels, pipeline and facility outages, terrorist attacks and other casualties. Following the blow-out of an exploratory well drilled by BP offshore in the deep water of the Gulf of Mexico in April 2010, BOEMRE issued a six month drilling moratorium in offshore waters in excess of 500 feet. BOEMRE in effect cancelled all existing drilling permits regardless of water depth by requiring all permits to include additional information and plans covering safety and environmental concerns. As such, the deep water drilling moratorium resulted in a de facto moratorium in shallow federal waters, where the Group has all of its offshore projects. Due to the current uncertainty surrounding the issuance of drilling permits, there can be no assurance as to the timing and scope of future drilling operations on the Group's offshore projects. Other potential future changes in the political and regulatory environment could also adversely impact the Group's performance.

The Group carries insurance on its assets that, when balanced against the cost, it believes is prudent and within industry norms, but this insurance does not protect the Group from all casualty risks. By monitoring regulatory and political developments and participating in industry trade groups and forums, the Group reviews legal and regulatory matters that affect its business and revises its operating plans in order to remain in compliance with existing regulations.

Changing regulatory environment

The majority of the Group's asset base is located within federal waters offshore in the Gulf of Mexico and is subject to the jurisdiction of BOEMRE, a federal agency within the US Department of the Interior. Pursuant to the Oil Pollution Act of 1990, as amended, the US Department of the Interior sets rules for demonstrating financial responsibility in the event of an oil spill. The Company currently satisfies its financial responsibility requirement through the use of insurance. Should the US Department of the Interior require higher levels of financial responsibility or should the Company be unable to acquire insurance to satisfy such requirements, the Company would likely experience adverse effects.

The Company utilises over the counter derivative commodity contracts (see Note 16 "Financial Instruments" in the consolidated financial statements) to hedge against changes in oil and natural gas commodity prices and may be subject to new regulations to be promulgated by the US Commodity Futures Trading Commission under the Dodd-Frank Wall Street Reform and Consumer Protection Act enacted during July 2010, which may in turn adversely affect the Group's commodity price hedging programme and bank credit facility.

Surety bonding

BOEMRE regulations require surety bonding for operators in the Gulf of Mexico and for future decommissioning obligations. There is a risk the Group may not be able to obtain sufficient bonding and may have to collateralise obligations with cash. If the Group was unable to provide such bonds, it would not be able to proceed with its operating plans.

Personnel constraints

The market for organisational talent in the US oil and natural gas industry is extremely competitive. Since the Group employs only 22 full time employees (at 30 June 2010), the Group would suffer materially if it lost the services of any of its key personnel. The Group strives to retain its most precious resource - its people - by offering its employees a pleasant and challenging work environment, significant opportunities for growth and contribution, competitive salaries, and long-term incentive compensation tied to share performance.

The Group has contractual relationships with over 500 suppliers and vendors who provide necessary services to the Group's business. The market for these services is very competitive and operational inefficiencies can arise because service provider personnel lack deep experience. In addition to quality concerns, costs can escalate. The Group is selective about whom it hires to provide services and constant monitoring and evaluation of third party services will continue to be a priority.

Health, safety and the environment

Health, safety and the environment continues to be a top concern for the Group. Exploration and production of oil and natural gas in the Gulf of Mexico presents many health, safety and environmental challenges. As a result of the BP Macondo oil spill during April 2010 in the deep water of Gulf of Mexico, BOEMRE regulations covering health, safety and the environment have become more stringent and continue to evolve. The Group has policies and procedures in place to protect people and property from harm in areas in which it operates and this will continue to be a management focus area. The Group's policy with regards to the environment is to ensure that the Company understands and effectively manages the actual and potential environmental impact of its activities. The Group's operations are conducted such that the Company seeks to comply with all legal requirements relating to health, safety and the environment in all areas where the Company carries out its business. Over the past year, the Group had no material health, safety or environmental incidents and did not incur any fines or penalties for violating any BOEMRE regulations.

Other matters

Financial instruments

The Group's financial instruments include cash balances, trade receivables and payables, bank debt and commodity contracts on oil and natural gas swaps and puts, and interest rate swaps. Financial risk management is more fully discussed in Note 4 "Financial risk management" of the financial statements.

Employees

Employees' performance is aligned to Group goals through an annual performance review process that is carried out with all employees and through an incentive bonus programme administered by the Board that is tied in part to the Group's performance. No performance bonuses were paid to executives or management during the financial year ended 30 June 2010.

Dividends

The Company does not have plans to pay dividends at this time.

Third party indemnity provisions for Directors

During the year and continuing to date the Company has maintained third party indemnity insurance for its Directors and Officers.

Donations

The Company encourages and supports its management and employees in supporting and giving of their time to local charitable and other non-profit organisations. The Group made charitable contributions of $6,000 in the year ended 30 June 2010 and $2,000 in the year ended 30 June 2009.

Supplier payment policy

It is the Group's payment policy to pay its suppliers in conformance with industry norms. Trade payables are paid in a timely manner within contractual terms, which is generally 30 to 45 days from the date an invoice is received.

Events since date of statement of financial position

Details of significant post statement of financial position events are set out in Note 31 "Post-statement of financial position events" in the consolidated financial statements.

Directors

The Directors of the Company are set out below:

At 30 June 2010 the interest of the Directors in Company shares was:

Additional information regarding director compensation is contained in Note 21 "Employees, Directors and auditor remuneration" of the consolidated financial statements within this report.

Statement of Directors' responsibilities for the financial statements

The Directors are responsible for preparing the annual report and the financial statements in accordance with applicable laws and regulations.

Company law requires the Directors to prepare financial statements for each financial year. Under that law the Directors have elected to prepare the financial statements in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union. The financial statements are required by law to give a true and fair view of the state of affairs of the Company and the Group, and of the profit or loss of the Group for that period. In preparing these financial statements, the Directors are required to:

The Directors are responsible for keeping adequate accounting records which disclose with reasonable accuracy at any time the financial position of the Company and the Group and enable them to ensure that the financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the Company and the Group and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

The Directors are responsible for the maintenance and integrity of the corporate and financial information on Leed's website. Legislation in the United Kingdom governing the preparation and dissemination of the financial statements and other information included in annual reports may differ from legislation in other jurisdictions.

Disclosure of information to auditor

At the date of making this report each of the Company's Directors, who are identified above in this report, confirm the following:

Auditor

Grant Thornton UK LLP ("Grant Thornton") serves as the Company's and Group's auditor and has expressed a willingness to continue in office. In accordance with Section 489(4) of the Companies Act 2006, a resolution to reappoint Grant Thornton as auditor of the Group may be proposed at the Annual General Meeting to be held on 20 December 2010.

Approval

The report of the Directors was authorised and approved by the Board and signed on 25 November 2010 on its behalf by:

James Slatten

Chief Operating Officer

Report of the independent auditor

to the members of Leed Petroleum PLC (Registered number 06034226)

We have audited the financial statements of Leed Petroleum PLC for the year ended 30 June 2010 which comprise the consolidated statement of comprehensive income, the Group and Parent Company statements of changes in equity, the Group and Parent Company statements of financial position, the Group and Parent Company statement of cash flows and the related notes. The financial reporting framework that has been applied in their preparation is applicable law and IFRS as adopted by the European Union and, as regards the Parent Company financial statements, as applied in accordance with the provisions of the Companies Act 2006.

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

As explained more fully in the Statement of Directors' responsibilities for the financial statements, set out on page 28, 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

The APB's website at www.frc.org.uk/apb/scope/UKNP provides a description of the scope of an audit of financial statements.

Opinion on financial statements

In our opinion:

Emphasis of matter - going concern

In forming our opinion, which is not qualified in this respect, we have considered the adequacy of the disclosure made in Note 2.20 "Significant accounting policies - going concern" to the financial statements concerning the Company's ability to continue as a going concern.

As explained in Note 2.20, the Directors are seeking to raise additional finance to repay certain borrowings, provide working capital and progress the development of the Group's oil and natural gas assets. These conditions, along with other matters explained in Note 2.20 to the financial statements, indicate the existence of a material uncertainty which may cast significant doubt on the Company's ability to continue as a going concern. The financial statements do not include the adjustments that would result if the Company was unable to continue as a going concern.

Separate opinion in relation to IFRS

As explained in Note 2.1 "Significant accounting policies - basis of preparation" to the Group financial statements, the Group, in addition to complying with its legal obligation to comply with IFRS as adopted by the European Union, has also complied with IFRS as issued by the International Accounting Standards Board (IASB).

In our opinion the Group financial statements comply with IFRS as issued by the IASB.

Opinion on other matter prescribed by the Companies Act 2006

In our opinion the information given in the Report of the Directors 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:

John Corbishley

Senior Statutory Auditor

for and on behalf of Grant Thornton UK LLP

Statutory Auditor, Chartered Accountants

Milton Keynes

25 November 2010

Consolidated statement of comprehensive income

for the year ended 30 June 2010

Leed Petroleum PLC (Company number: 06034226)

Statements of changes in equity

for the year ended 30 June 2010

Statements of changes in equity

for the year ended 30 June 2010

Statements of financial position

as at 30 June 2010

The financial statements on pages 31 to 66 were authorised and approved by the Board of Directors and were signed on 25 November 2010 on its behalf by:

James Slatten

Executive Director

Company number: 06034226

Statements of cash flow

for the year ended 30 June 2010

Notes to the financial statements

for the year ended 30 June 2010

1. General information

Leed Petroleum PLC (LDP LN) is a publicly listed company registered in the United Kingdom. The address of its registered office is 110 Cannon Street, London, EC4N 6AR.

The Leed Petroleum PLC Group (collectively, "Leed" or the "Group") comprises one operating segment which acquires, explores, develops, produces and operates oil and natural gas properties offshore and onshore of the Gulf Coast region of the United States. At 30 June 2010, Leed owned mineral interests in 17 blocks located in federal waters offshore of the Louisiana coastline, one onshore field in Louisiana and a small interest in a gas processing plant and a fractionation plant located onshore in Louisiana.

The Company's functional currency is the Pound Sterling. As substantially all of the Group's activity and financial transactions occur in the United States, US Dollars is used as a presentation currency for both the Group and the Parent Company. At 30 June 2010 and 2009, the exchange rate of the US Dollar to the Pound Sterling was $0.6635 and $0.6053, respectively. Foreign operations are consolidated in accordance with the policies set out in Note 2.11 "Significant accounting policies - foreign currencies" below.

2. Significant accounting policies

2.1 Basis of preparation

The Group and Parent Company financial statements have been prepared in accordance with EU adopted IFRS, and International Financial Reporting Interpretations Committee ("IFRIC") interpretations. All accounting standards and interpretations issued by the International Accounting Standards Board and the IFRIC effective for the periods covered by these financial statements have been applied.

The financial statements for the period ended and as at 30 June 2009 have been restated to reflect the change in the application of an accounting policy related to identification of cash generating units for impairment testing purposes. The financial statements as at and for the period ended 30 June 30 2008 were not affected by this restatement. In accordance with IAS 1 "Presentation of financial statements", the statement of financial position as at 30 June 2008 is included herein for comparative purposes only (Note 30 "Restatement of prior period").

The Group reports its proportional interests in joint oil and natural gas exploration, development, and production activities. A summary of the significant Group accounting policies adopted in the preparation of the financial statements is set out below. These policies have been consistently applied to all the periods presented, unless otherwise stated.

The preparation of financial statements in conformity with IFRS requires the use of estimates and assumptions and for management to exercise its judgement in the process of applying the Group's accounting policies. Critical judgements and key estimates and assumptions are disclosed in Note 3 "Critical accounting judgements and key sources of estimation uncertainty" below. The following new standards and amendments to standards are applicable for the financial year commencing 1 July 2009:

IAS 1 "Presentation of Financial Statements"

The Group applies revised IAS 1 "Presentation of Financial Statements", which became effective for the Group as of 1 July 2009. As a result, the Group presents in the statement of changes in equity all owner changes in equity, whereas all non-owner changes in equity are presented in the consolidated statement of comprehensive income. This presentation has been applied within these financial statements. In accordance with IAS 1, the Group has elected to present the combined consolidated statement of income and the statement of comprehensive income. Comparative information has been re-presented so that it also is in conformity with the revised standard. Since the change in accounting policy only impacts presentation aspects, there is no impact on earnings per share.

IFRS 8 "Operating Segments"

IFRS 8 "Operating Segments" replaces IAS 14 "Segment Reporting". The chief operating decision maker has been identified as the Group's Board of Directors. The Board of Directors reviews the Group's internal reporting in order to assess performance and allocate resources. The information provided to the chief operating decision maker is measured in a manner which is consistent with the financial statements and management has determined the Group has one operating segment, the "exploration and production" segment, based on these reports and other factors. The Group's exploration and production segment consists of the acquisition, exploration, development, production and operation of oil and natural gas properties in the Gulf Coast region of the United States and comprises multiple cash generating units ("CGUs"). The Group's CGUs within its exploration and production segment are generally classified at the field level, which is based on the physical location of the asset and the independence of cash inflows from other assets within the segment. The exploration and production segment derives all of its revenues from external customers (Note 5 "Operating segments").

The adoption of IFRS 8 did not result in changes to the statement of financial position at 30 June 2008. Accordingly, the statement of financial position at 30 June 2008 has not been included in these financial statements.

IAS 23 "Borrowing Costs"

The Group early adopted IAS 23 "Borrowing Costs" for the financial year beginning 1 July 2008, which is mandatory for financial years beginning on or after 1 January 2009. In accordance with IAS 23, the Group capitalises borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset as part of the cost of that asset (Note 2.16 "Significant accounting policies - borrowing and other finance costs").

Other new accounting standards and interpretations

The Company has reviewed additional new standards and interpretations currently in issue but not effective as of 30 June 2010 and determined that none of these new standards and interpretations will have significant impact on reported results. Those new standards and interpretations include: IFRS 9 "Financial instruments"; IFRS 24 (revised 2009) "related party disclosures"; and "Group cash-settled share-based payment transactions - amendment to IFRS 2".

2.2 Basis of consolidation

The consolidated financial statements incorporate the results, assets, liabilities and cash flows of the Company and each of its subsidiaries for the years ended 30 June 2010 and 2009, respectively.

Subsidiaries are entities controlled by Leed Petroleum PLC. Control is deemed to exist when Leed Petroleum PLC has the power, directly or indirectly, to govern the financial and operating policies of an entity so as to obtain benefits from its activities. The results of subsidiaries are included in the consolidated financial statements from the date control commences until the date that control ceases.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used in line with those used by Leed Petroleum PLC.

Unless there is an indication of impairment, intra group balances and transactions are eliminated on consolidation.

2.3 Business combinations

Merger accounting involving entities under common control is outside the scope of IFRS 3 "Business combinations". In applying IAS 8 "Accounting Policies, Changes in Accounting Estimates and Errors," to determine an appropriate accounting policy, the Group follows UK GAAP for business combinations. The purchase method is applied to other combinations under the scope of IFRS 3. None of the aforementioned items are relevant to these financial statements.

2.4 Goodwill

Goodwill on acquisition of subsidiaries represents the excess of the cost of an acquisition over the fair value of the Group's share of the identifiable net assets of the acquired subsidiary. Goodwill is not amortised, but tested at least annually for impairment, and carried at cost less accumulated impairment losses (Note 2.17 "Significant accounting policies - impairment of property, plant and equipment and intangible assets").

2.5 Oil and natural gas assets

The Group follows the successful efforts method of accounting for its oil and natural gas properties. The Group's interests in oil and natural gas exploration and production joint ventures are proportionately consolidated.

Exploration and evaluation ("E&E") assets

E&E assets comprise the cost of rights to extract minerals ("leases") for fields with no known proven oil and/or natural gas reserves and are held at cost unless impaired. Each E&E asset is reviewed on an annual basis to confirm that drilling activity is planned and that it is not impaired. Geological and geophysical costs pertaining to E&E assets are expensed as incurred. Other direct costs related to the pursuit of an E&E asset are capitalised. If, through geological and geophysical studies, proven commercial reserves are discovered, the cost of the E&E asset is transferred to property, plant and equipment. Otherwise, such costs are expensed in the period it is ascertained that there are no commercial reserves. Initial terms for offshore leases in the federal waters of the Gulf of Mexico are five years, but are indefinite if there is production occurring in commercial quantities. Initial terms for leases onshore usually range from three to five years and, in some cases, include optional lease extensions from one to five years. Onshore leases or unitised portions of onshore leases also continue indefinitely with production in commercial quantities. Other direct costs related to the pursuit of a potential lease are capitalised as part of the cost of the E&E asset. Once it is decided a lease will not or cannot be obtained, such pursuit costs are expensed.

The costs that are directly associated with an exploration well are capitalised as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include the use of materials and fuel, directly related employee remuneration, rig costs and payments made to contractors. As discussed above and in Note 2.16 "Significant accounting policies - borrowing and other finance costs", as of 1 July 2008 the Group commenced the capitalisation of borrowing costs related to its construction and drilling projects. If it is found that hydrocarbons are not present, the exploration expenditure is written off. If hydrocarbons are discovered and are likely to be capable of commercial development, subject to further appraisal activity, which may include the drilling of further wells (exploration or exploratory type test wells), the costs continue to be carried as an asset. All such carried costs are subject to technical, commercial and management review at least once a year to confirm the continued intent to develop or otherwise extract value from the well. If it is found that value can no longer be extracted, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to property, plant and equipment.

Development expenditures

Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within property, plant and equipment. With the early adoption of IAS 23 "Borrowing Costs (revised 2007)" as of July 2008, borrowing costs attributable to development expenditure are included with the amount capitalised.

2.6 Amortisation and depletion of tangible oil/gas assets

The Group depletes the costs of its oil and natural gas assets on a field by field basis using the unit of production method. Assets arising from the recording of a decommissioning obligation are amortised as described in Note 2.9 "Significant accounting policies - decommissioning obligation".

2.7 Property, plant and equipment - other non-oil/gas assets

Property, plant and equipment are stated at cost less accumulated depreciation and any impairment losses. Cost comprises the purchase price of property, plant and equipment together with any directly attributable costs. Subsequent costs are included in an asset's carrying value or recognised as a separate asset, when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. All other costs are charged to profit and loss when incurred.

Depreciation commences when an asset is available for use and is charged so as to write off the depreciable amount of assets other than land to their residual values, over their estimated useful lives, using a method that reflects the pattern in which the assets' future economic benefits are expected to be consumed by the Group.

Depreciation is charged in equal annual instalments as follows:

Methods of depreciation, residual values and useful lives are reviewed and adjusted, if appropriate, at each statement of financial position date. Assets held under finance leases are depreciated over the shorter of their expected useful lives or the term of the relevant lease, when there is no reasonable certainty that title will be obtained at the end of the lease term. The gain or loss arising from the disposal or retirement of an item of property, plant and equipment is determined as the difference between the net disposal proceeds and the carrying amount of the item, and is included in profit and loss.

2.8 Taxation

The tax expense represents the sum of tax currently payable and deferred tax.

Current tax

Tax currently payable is based on taxable profit for the year and is calculated using tax rates enacted or substantively enacted at the statement of financial position date. Taxable profit differs from accounting profit either because items are taxable or deductible in periods different to those in which they are recognised in the accounts or because they are never taxable or deductible.

Deferred tax

Deferred tax on temporary differences at the statement of financial position date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes is accounted for using the balance sheet liability method, which assumes that such amounts will be expended or recovered in future periods (Note 18 "Deferred tax").

Using the balance sheet liability method, deferred tax liabilities are recognised in full for all taxable temporary differences, and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Deferred tax assets for share-based payments are re-calculated at each statement of financial position date based on the closing price of the Company's share price. However, if the deferred tax asset or liability arises from the initial recognition of goodwill or the initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit, it is not recognised.

Deferred taxation is measured at the tax rates that are expected to apply when the asset is realised or the liability settled based on tax rates and laws enacted or substantively enacted at the statement of financial position date. No provision is made for deferred tax on the unremitted earnings of foreign subsidiaries because such remittances are not probable as the Group's policy is to reinvest profits to fund growth in the US. Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax amounts and when they relate to the same tax authority and the Group intends to settle its current tax amounts on a net basis. Current and deferred tax are recognised in profit and loss except when they relate to items recognised directly in equity, when they are similarly taken to equity.

2.9 Decommissioning obligation

The Group recognises the present value of decommissioning obligations in the financial statements in the period in which the obligation arises. Upon initial recognition of the liability, an asset retirement cost is capitalised by increasing the carrying amount of the long lived asset by the same amount as the liability. In periods subsequent to initial measurement, the capitalised asset retirement cost is allocated to depreciation/amortisation expense using the straight line basis over the asset's useful life. Changes in the liability for decommissions are recognised for the passage of time by charges to accretion expense and classified as finance costs in profit and loss. Annually, the Group reassesses the liability in accordance with IFRIC 1 "Changes in Existing Decommissioning, Restoration and Similar Liabilities"; the cost of the applicable asset to which the liability relates is offset by the amount of the adjustment to the liability. If the obligation is ultimately settled for other than the carrying amount, then a gain or loss is recognised upon settlement.

2.10 Revenue

Revenue is measured at the fair value of the consideration received or receivable and represents the amounts receivable for goods provided in the normal course of business, net of all related discounts and sales tax. Revenue from the Group's crude oil, natural gas and natural gas liquids production is recognised on the date sold, which coincides with physical delivery. The Group follows the net method of accounting for royalties; the royalty owner's share of sales or production does not appear in profit loss. Gas processing fees are recognised on the date the physical gas processing occurs.

2.11 Foreign currencies

Transactions in foreign currencies are translated at the exchange rate ruling at the date of each transaction. Foreign currency monetary assets and liabilities are retranslated using the exchange rates at the statement of financial position date. Gains and losses arising from changes in exchange rates after the date of the transaction are recognised in profit and loss. Non-monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated at the exchange rate at the date of the original transaction.

In the Group and Company financial statements, the net assets of the Company are translated into its presentation currency at the rate of exchange at the statement of financial position date. Income and expense items are translated at the date of the transaction. The resulting exchange differences are recognised in equity and included in translation reserve.

2.12 Finance leases

Leases are classified as finance leases where the terms of the lease transfer substantially all the risks and rewards of ownership to the Group. All other leases are classified as operating leases.

Property, plant and equipment held under finance leases are recognised as assets in the statement of financial position at their fair values or, if lower, at the present value of the minimum lease payments, both determined at the inception of the lease. The corresponding obligation is recorded as amounts payable under finance leases. The interest element of leasing payments represents a constant proportion of the capital balance outstanding and is charged to profit and loss over the period of the lease.

2.13 Operating leases

The costs of all operating leases are charged against operating profit on a straight line basis at existing rental levels. Incentives to sign operating leases are recognised in profit and loss in equal instalments over the term of the lease.

2.14 Financial instruments

The Group classifies its financial instrument assets, or their component parts, on initial recognition into two categories: a financial asset at fair value through profit or loss, or loans and receivables. Financial instrument liabilities are classified as either a financial liability at fair value through profit or loss, or as another financial liability. Financial assets and financial liabilities are recognised on the Group's statement of financial position when the Group becomes party to the contractual provisions of the instrument. The particular recognition and measurement methods adopted for trade and other receivables, bank and cash, trade and other payables, borrowings and derivatives are disclosed below:

Cash and cash equivalents

Cash and cash equivalents include cash in hand and cash at bank; these financial instruments are classified with loans and receivables.

Trade and other receivables

Trade and other receivables are measured initially at fair value and subsequently at amortised cost using the effective interest rate method. These financial instruments are categorised with loans and receivables. The receivables do not carry interest; the carrying value of the receivables, as presented, is reduced by appropriate allowances for estimated irrecoverable amounts. A provision for impairment of trade receivables is established when there is evidence that the Group will not be able to collect all amounts due according to the original terms of these receivables. The amount of the provision is the difference between the carrying value and the present value of estimated future cash flows, discounted using the effective interest rate method. Impairment losses are recognised in profit and loss.

Trade and other payables

Trade and other payables are measured initially at fair value and subsequently at amortised cost using the effective interest rate method. These financial instruments are categorised with other financial liabilities.

Borrowings and other finance obligations

Borrowings and other finance obligations are recognised initially at the fair value of proceeds received, net of transaction costs. Subsequent measurement is at amortised cost using the effective interest rate method. (Borrowing and other finance costs are discussed at Note 2.16 "Significant accounting policies - borrowing and other financing costs" on page 40). These financial instruments are categorised with other financial liabilities.

Borrowings and other finance obligations are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least twelve months after the statement of financial position date.

Derivative contracts

The Company's derivative contracts consist of commodity contracts and interest rate swaps, which are carried at fair value. Changes in the fair value of such contracts are recognised in profit and loss as they arise. The Company has elected to not to qualify for hedge accounting treatment.

Equity instruments

An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all its liabilities. Equity instruments issued by the Company are recorded at the amount of proceeds received, net of direct issue costs.

Fair value determination

The Group establishes fair value by utilising valuation techniques, including the use of information from recent arm's length market transactions between knowledgeable willing parties, if available, reference to the current fair value of similar instruments, and discounted cash flow analysis. The valuation technique used incorporates factors that market participants would consider in setting a price and is consistent with accepted economic methodologies for pricing financial instruments.

Embedded derivative

The fair value of an option granted to a provider of finance has been determined based on the difference between the rate of (higher) interest charged by the bank on those loans with and without the option attached. The additional interest that would have been charged is charged to finance cost in profit and loss, with the offset being a credit to equity.

2.15 Dividends

Final dividends are recognised as a liability in the period in which they are approved by the Company's shareholders. Interim dividends are recognised when they are paid.

2.16 Borrowing and other finance costs

Borrowing and finance charges, including any premiums payable on settlement or redemption and direct issue costs, are generally recognised in profit and loss as incurred. Commencing 1 July 2008 with the early adoption of IAS 23 (revised 2007), borrowing costs incurred during the construction period and attributable to constructed assets are capitalised as a part of the asset. The transitional provisions of IAS 23 (revised 2007) allow capitalisation of interest only on projects that commenced in the period the standard is adopted. The Company early adopted IAS 23 and capitalised $21,000 and $119,000 for the periods ended 30 June 2010 and 2009, respectively. The average borrowing rate was 4.6% for the period ended 30 June 2010 and 4.9% for the period ended 30 June 2009.

2.17 Impairment of property, plant and equipment and intangible assets

At each statement of financial position date, the Group assesses whether there is any indication that its property, plant and equipment and intangible assets have been impaired.

Exploration and evaluation assets

Impairment testing for the Group's E&E assets are conducted on an asset-by-asset level on an annual basis or when circumstances arise which indicate that the carrying value of an E&E asset may be impaired. E&E assets are also tested for impairment when reclassified to property, plant and equipment. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment, if any.

Field cash generating units

Development costs pertaining to the Group's oil and natural gas assets classified as property, plant and equipment are grouped by individual CGUs ("Field CGUs") for impairment testing purposes. At 30 June 2010, each Field CGU was comprised of a grouping of wells within a distinct geographical location which contain proven and probable oil and natural gas reserves, but no interconnected cash inflows with other fields. In the prior annual report for the year ended 30 June 2009, the Group classified all of its oil and natural gas wells with proven and probable reserves as one operating segment and one CGU. The change in application of the policy year-on-year was a result of re-examining the assets within the Group's exploration and production operating segment and determining that components (multiple CGUs) with separately identifiable cash inflows existed. Since the change in application of policy provides more relevant information which is also reliable, the change was adopted (Note 30 "Restatement of prior period").

The recoverable amount of a Field CGU is the higher of its fair value less costs to sell or its value in use. The value in use is the present value of the future cash flows expected to be derived from the Field CGU. This present value is discounted using a pre-tax rate that reflects current market assessments of the time value of money and of the risks specific to the asset, for which future cash flow estimates have not been adjusted. If the recoverable amount of the Field CGU is less than its carrying amount, the carrying amount of the Field CGU is reduced to its recoverable amount and an impairment loss is recognised. If an impairment loss subsequently reverses because of changing circumstances, the carrying amount of the Field CGU is increased to the revised estimate of its recoverable amount, but limited to the carrying amount that would have been determined had no impairment loss been recognised in prior years. A reversal of an impairment loss is recognised in profit and loss.

Goodwill

Goodwill is tested for impairment at the operating segment level at least annually and whenever there is an indication the asset may be impaired. Impairment losses on goodwill are not subsequently reversed in accordance with IFRS.

2.18 Share-based payments

The Group has issued Stock Appreciation Rights ("SARs") and Restricted Stock Units ("RSUs") of the Company's stock as additional compensation to its Directors, executives, management and other employees with the offset being a share-based cost credit to equity. The Company has the choice of settling these amounts with cash or by issuing stock. The share-based payments are accounted for as equity settled share-based payments as it is expected the amounts will be settled by the issuance of Company stock. Equity settled share-based payments are measured at fair value at the date of grant as determined by an independent appraiser with assumptions that the Directors consider as reasonable. The fair value is expensed on a straight line basis over the vesting period, which is based on the Group's estimate of shares that will eventually vest and adjusted for the effect of non-market based vesting conditions.

2.19 Reserves of equity

The Group and Company's reserves of equity include a translation reserve. The translation reserve is the offsetting account for the adjustment of the Company's accounts from its functional currency (the Pound Sterling) to the presentation currency (the US Dollar). In addition to the foregoing, the Company's reserves of equity also include an other reserve. The other reserve is the offsetting account for share-based payments.

2.20 Going concern

The Group's business activities, together with factors likely to affect its future developments, performance and financial position are set out in the Chairman's statement on page 2 and the Report of the Director's on page 21. Financial risks to the Company are set out in Note 4 "Financial Risk Management".

During the past financial year, the Group's financial performance was affected by adverse production performance issues. In the Eugene Island field, the Eugene Island 183 A-8 well continued to decline at a steady rate, but not in sufficient quantity to obtain regulatory approval for the recompletion into the more prolific T-1 sand. Two other wells in the field, the Eugene Island 183 A-6 and Eugene Island 183 A-7, each failed to produce at anticipated production levels, principally due to sand control issues, and were not producing at period end. The Group's Main Pass 64/65 field also experienced significant downtime during the year ended 30 June 2010 due to ongoing pipeline repair issues and was shut in at period end. The aforementioned items were the primary contributors to a 31% decrease in year-on-year revenues, resulting in a $1.0 million negative earnings before interest, taxes, depreciation, depletion, amortisation, exploration costs and impairments ("EBITDAX") for the 2010 financial year, as compared to positive $23.9 million EBITDAX for the 2009 financial year.

The Group's banking facility is subject to financial covenants and other conditions which the Group monitors regularly. These covenants and conditions are sensitive to changes in EBITDAX, interest rates, commodity prices, production levels, net assets and estimated oil and natural gas reserves. The Group's ability to comply with such covenants and conditions in future periods is a key element in the ability of the Group to continue as a going concern. During June 2010, the Group disclosed certain defaults on the credit facility to its bank, UniCredit Bank AG, that were projected to exist at the 30 June 2010 review date. The defaults related to EBITDAX ratios pertaining to the period ended 30 June 2010 that were projected to be deficient at period end, principally due to oil and natural gas production performance issues incurred during the aforementioned twelve month period that negatively affected EBITDAX. Following discussions with UniCredit Bank AG, the Group agreed to an interest rate increase of 2% on its credit facility effective 15 June 2010 in exchange for waiving the projected defaults to ensure the Group would be in full compliance with the terms and conditions of its banking facilities at 30 June 2010. Since the default provisions are reviewed every six months and are based on actual results from the prior twelve month period, the Group expects to seek a similar waiver at the next measurement date, which is 31 December 2010. During November 2010, the Group reached an agreement with the Group's bank whereby the Group would make an additional principal payment of $12.0 million on or before 31 March 2011 and the interest rate on its credit facility would increase by 1% effective 15 December 2010 in return for waiving certain conditions of default that may exist at the 31 December 2010 measurement date.

As of the date of this report the Group is exploring several alternatives including divesting some or all of its oil and natural gas assets in order to raise $12.0 million or more in order to pay off some or all of its bank borrowings prior to 31 March 2011. Additional alternatives under consideration include, but are not limited to, securing a new bank credit facility and/or other potential transactions, such as a merger with another company. In anticipation of executing one or a combination of the aforementioned alternatives during the 2011 financial year and the accompanying measurement uncertainty thereof, the Company wrote off its period end net deferred tax balances of $7.2 million for the period ended 30 June 2010 (Note 18 "Deferred tax"). The Group is uncertain of the bank's stance post 31 March 2011 and this could therefore represent a significant risk to the Group.

The Directors have prepared cash flow forecasts (including selected sensitivities) for the Company covering a twelve month period from the authorisation of these financial statements. The cash flow forecasts reflect the Company's plan for the coming year, including expected net proceeds from divestitures, projected production rates, commodity prices, capital expenditure levels, principal payments, interest rates and expected compliance with loan covenants. Based on these assumptions, which the Board believes are reasonable, these cash flow forecasts show that the Group should have sufficient liquidity to continue as a going concern. Nevertheless, possible adverse future events or circumstances are beyond the control of the Company and could seriously influence the Company's ability to continue as a going concern. Moreover, the regulatory environment in the Gulf of Mexico post the BP oil spill at Macondo is in flux and some regulatory changes under consideration in the US Congress could imperil the Company's business model. Clearly, it is impossible to predict the regulatory changes that may come about on account of governmental initiatives.

Future growth of the Group during the next twelve months and beyond is heavily dependent upon the Group's ability to raise enough capital to continue the development of its undeveloped oil and natural gas reserve portfolio, which represents approximately 78% of its oil and natural gas reserves calculated on a barrels of oil equivalent ("BOE") basis at 1 July 2010. The cash flow forecasts assume the Group will be successful in raising sufficient capital to further develop these oil and natural gas reserves.

The Directors' assessment of the Group's ability to continue as a going concern involves making a judgement about inherently uncertain future outcomes of events and conditions based upon available information at the time of assessment. Subsequent events and additional information may result in outcomes that are inconsistent with judgements that were reasonable at the time they were made. The Directors have concluded that the combination of these circumstances represents a material uncertainty that casts significant doubt upon the Group's ability to continue as a going concern and that, therefore, the Group may be unable to realise its assets and discharge its liabilities in the normal course of business. Nevertheless, after making enquiries and considering the uncertainties described above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. For these reasons, they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

3. Critical accounting judgements and key sources of estimation uncertainty

Key assumptions concerning the future and other key sources of estimation uncertainty that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities are as follows:

3.1 Estimated oil and natural gas reserves

At least annually the Group obtains an independent audit of its oil and natural gas reserves. The total amount of oil and natural gas reserves is a critical estimate for the purpose of determining the carrying value of oil and natural gas assets, the depletion rate utilising the unit of production method, estimated future production rates, net present value of future cash flows utilised for impairment testing purposes and credit available under the Company's bank credit facility. Due to numerous assumptions, including commodity prices, volumetric decline curves, operating costs, capital expenditures and other factors, actual results could vary materially from estimates contained within the reserve report prepared by the independent reserve auditor.

3.2 Fair value of oil and natural gas derivatives

The Group obtains valuations of its oil and natural gas commodity contracts from the counterparties to the contracts. The Group then reviews those valuations for reasonableness using published market information for similar contracts and the expertise of an independent consultant. The value of the derivatives is a critical estimate in determining the financial position of the Group (Note 16 "Financial instruments").

3.3 Intangible assets acquired in a business combination

Intangible assets acquired in a business combination, including leases and exploration assets, are recognised when they are identifiable or arise from contractual or other legal rights and their fair value can be reliably measured. Fair value is estimated using risk adjusted future cash flows. Significant assumptions are made in estimating future cash flows about future events, including future market conditions and future growth rates. Changes in these assumptions could affect fair values.

3.4 Decommissioning obligation

Provisions for asset retirement obligations are recognised when management is satisfied that an outflow of economic benefits is probable and a reliable estimate can be made of the obligation and when a present obligation exists. The Group obtains an independent fair market valuation of the obligation at the time an affected asset is placed in service. The carrying amount of the asset that has such a retirement obligation and the liability related to the future obligation to decommission the asset, and the resulting expense from the amortisation of the added cost of the asset and accretion of the liability are significant estimates in the Group's accounts.

3.5 Treatment of overriding royalty interests (ORRIs)

Overriding royalty interests ("ORRIs") may be granted to third parties. An ORRI is an immovable property right (akin to a real right in a common law jurisdiction). As an immovable property right, an ORRI has the same legal standing as does a working interest in a mineral lease or an interest in land.

Scouting Agreement with Byron Energy Pty, Ltd. ("Byron")

In December 2005, the Group granted Byron a contractual right to receive ORRIs of 2% in certain properties in exchange for scouting services. Under terms of the agreement (the "scouting agreement"), Byron was to be granted a 2% ORRI relative to the Group's ownership interest at the time when the Group acquired its working interests in each relevant property under terms of the scouting agreement. Byron had earned the right to receive these ORRIs by virtue of the scouting services which they had performed. The Group considers that Byron holds a 2% ORRI interest in the property, with the remaining 98% share, less other royalty interests, representing the asset of the Group. The scouting agreement provides that Byron will receive each ORRI prior to the commencement of production. Once these properties reach production, any cash received by the Group in relation to Byron's ORRIs will not be regarded as revenue, as the Group reports only its proportional interests in its oil and natural gas exploration, development, and production activities. The Group would recognise a financial liability for any funds received on behalf of Byron, and that liability would then be extinguished on a short-term basis by remitting the funds to Byron. Payments which may be made in the future in respect of future production would not be considered to be a financial liability. Under further terms of the scouting agreement, the Group also granted a written option to Byron which gives Byron the option to purchase up to 25% of the Group's working interest in certain fields. The exercise of this option would involve Byron paying a pro-rata exercise price equivalent to the Group's original purchase price plus all subsequent costs incurred with respect to the property, together with the relinquishment of the 2% ORRI to the Group. The exercise date commences upon notice from the Group that it is preparing to spud a well and expires on the earlier of 30 business days or the day before the expected spud date. The option represents a financial liability. In the opinion of the Directors, the fair value of this financial liability is not significant to the financial statements (Note 26 "Related party transactions").

4. Financial risk management

The Group's business activities expose it to a variety of financial risks that include oil and natural gas price risk, liquidity risk, interest rate risk, credit risk and currency risk.

4.1 Liquidity risk

Liquidity risk is the risk arising from the Group not being able to meet its obligations. The Group manages its liquidity needs by monitoring scheduled debt servicing payments for its borrowings as well as forecast cash flows and inflows due in day-to-day business. The Group's objective is to maintain cash and cash equivalents to meet its liquidity requirements for a minimum of 30 days.

The Group finances its operations through a combination of bank borrowings, finance leases and cash generated from operations. Besides operations, the Group's principal source of funding is bank borrowings secured by property assets. Liquidity is maintained through committed bank credit facilities (Note 15 "Borrowings").

The Group currently satisfies its financial responsibility requirements under the Oil Pollution Act of 1990, as amended, through the use of insurance. As a result of the BP oil spill at its Macondo prospect in the deep water of the Gulf of Mexico, legislative initiatives are currently under consideration that may increase the level of responsibility the Group would be required to demonstrate. If such legislative initiatives are enacted, the Company would likely experience adverse effects.

There is a risk the Group may not be able to obtain future surety bonding as required by the Bureau of Ocean Energy Management, Regulation and Enforcement ("BOEMRE") for Gulf of Mexico operators and lessees (related to future decommissioning obligations). In the event the Company's operating subsidiary does not qualify for future surety bonding, it may have to post cash collateral before obtaining BOEMRE approval of future operations.

There is a risk that the Group may be called upon by the surety provider which has issued surety bonds related to expected future decommissioning activities to the US Department of the Interior to collateralise previously issued surety bonds pursuant to the agreement of indemnity between the parties.

A summary of the Group's maturities for its liabilities (excluding derivative financial instruments, decommissioning obligations and deferred taxes) follows:

4.2 Price risk

Volatility of oil and natural gas prices can have considerable impact on the Group's results. To mitigate such risks, the Group regularly enters into oil and natural gas commodity derivative contracts. Currently, the Group has a number of such contracts in place as a part of the credit facility with its primary banker (Note 16 "Financial instruments").

4.3 Credit risk

Currently, the Company receives payment from five entities for most of its revenue. The revenue is derived from the Company's pro-rata share of the production of oil, natural gas, and natural gas liquids from its producing properties and from gas plant processing fees pertaining to a gas plant where the Company holds a minority interest. The Gulf Coast area of the United States has an extensive, well maintained infrastructure and market for producers with many potential buyers (Note 13 "Trade and other receivables").

4.4 Currency risk

The Company is exposed to currency risk with the Pound Sterling relative to maintaining the Company's United Kingdom domicile. That cost is a minimal portion of the Company's overall operations and as such it is not material. Accordingly, the Group does not hedge this risk.

4.5 Interest rate risk

The Company is exposed to a cash flow interest rate risk on bank borrowings, which are arranged at floating rates. As part of the credit facility with its primary banker, the Group uses interest rate swaps to hedge a portion of its exposure to interest rate fluctuations (Note 16 "Financial instruments").

4.6 Capital maintenance

The Board of Directors' policy with regards to capital maintenance includes an objective to maintain a strong capital base consisting of appropriate borrowings that comply with its credit facility in order to maintain investor and creditor confidence and sustain future development of the business. The Group endeavours to maintain a capital structure that will maximise shareholder value while employing only a level of debt that the Board of Directors considers prudent for an oil and natural gas company of the Group's size and on terms that the Board of Directors believes to be reasonable after taking into account the Group's capital needs and considering other alternatives. The Board of Directors directs and monitors the allocation of cash resources against projects to maximise the return on asset value within the Group. Day-to-day working capital requirements and medium-term funding requirements are managed through use of internally generated funds and the Group's bank facility. Periodically, the Board of Directors will consider raising additional equity when the Group has access to opportunities, which in the opinion of the Board of Directors will increase shareholder value if acted upon. The Board of Directors also determines the timing and level of dividends to Ordinary Shareholders with the objective of maximising shareholder value.

4.7 Treasury management

Daily reports are generated showing the volumes of oil and natural gas produced. This information, combined with published market prices, becomes the basis for estimating the revenues included in a monthly cash flow report circulated for use by management and the Board. Additionally, a schedule of the expected receipts and disbursements by category expected in the next eight to twelve weeks is maintained for managing cash flows. The Group also prepares a formal budget for adoption by the Board on an annual basis.

As a part of the credit facility with its principal bank (Note 15 "Borrowings"), the Group has an independent audit of its oil and natural gas reserves done on a periodic basis (at least annually). This audit provides an unbiased third party estimate of the expected future cash flows from the proved, probable and possible reserves, using certain expected future commodity prices, oil and natural gas production rates and other related cost assumptions.

4.8 Fair value estimation

The fair values of cash and cash equivalents, receivables, payables and borrowings with a maturity of less than one year are assumed to approximate their book values. The fair value of forward contracts (oil and natural gas hedges and interest rate swaps) has been determined based on market forward rates at the statement of financial position date (Note 16 "Financial instruments"). The Group's borrowings due in more than one year bear interest at prevailing market rates and their fair values are assumed to approximate their book values.

5. Operating segments

The chief operating decision maker has been identified as the Group's Board of Directors. The Board of Directors reviews the Group's internal reporting in order to assess performance and allocate resources. The information provided to the chief operating decision maker is measured in a manner which is consistent with the financial statements and management has determined the Group has one operating segment (exploration and production) based on these reports and other factors. The exploration and production segment consists of the acquisition, exploration, development, production and operation of oil and natural gas properties in the Gulf Coast region of the United States. The exploration and production segment derives all of its revenues from external customers. External customers exceeding 10% of total revenues during the period ended 30 June 2010 included two oil purchasers ($11.5 million), two gas purchasers ($6.9 million) and the operator of the natural gas liquids processing plant ($2.7 million).

Results of operations by segment

Restated results of operations by segment

Total assets by segment

6. Finance income

The Company's interest income on bank and other deposits during the years ended 30 June 2010 and 2009, respectively, were as follows:

Finance income

7. Finance costs

The Company's finance costs during the years ended 30 June 2010 and 2009, respectively, were as follows:

Finance costs

8. Loss for the period

Selected items comprising the loss for the periods ended 30 June 2010 and 2009, respectively, along with selected metrics, are as follows:

Selected items comprising loss

Professional fees were substantially higher for the year ended 30 June 2010, as compared to the prior year, due to additional contract engineering costs incurred throughout the year and higher costs pertaining to technical advisory services associated with the Company's continued listing on AIM following its successful equity raising and the amendment of its credit facility during November 2009.

9. Taxation

A summary of taxation charges, and components thereof, incurred during the years ended 30 June 2010 and 2009, respectively, are set out in the tables below based on a tax rate of 36% pertaining to the US subsidiaries.

Taxation for period

Taxation components

10. Goodwill

Goodwill of $29.0 million arose from the acquisition of Leed Petroleum LLC (formerly Darcy Energy, Ltd.) by Darcy Energy Holdings, LLC on 8 December 2005 and has been allocated to the Group's exploration and production segment, which comprises all of the Group's CGUs. The key assumptions utilised in the annual goodwill impairment test at 30 June 2010 included a weighted average cost of capital rate of 11.64% used to discount to future net cash flows covering the life expectancy of the proved and probable reserves of assets comprising the exploration and production segment. Commodity prices used in the impairment test were the average 1 July 2010 NYMEX light sweet crude oil strip (starting at $72.95 per bbl on 1 July 2010, rising to $89.00 per bbl on 1 December 2018 and held constant thereafter) and the average Henry Hub natural gas price strip (starting at $4.72 per mmbtu on 1 July 2010, rising to $8.25 per mmbtu on 1 January 2021 and held constant thereafter). Additional assumptions included expected future production volumes, capital costs, fixed operating costs and variable operating costs. The resulting total net cash flows were then further reduced by a total of 15% for unexpected additional down time. Based on the impairment test conducted at 30 June 2010 utilising the aforementioned components, goodwill was not impaired at 30 June 2010.

The goodwill testing at 30 June 2010 indicated sensitivities primarily to the pricing of oil and natural gas, which historically have been very volatile. A sensitivity to the test indicated that there would be an impairment of goodwill of approximately $9.4 million if commodity prices fell 35% (average of $49.65 per bbl and $4.00 per mmbtu) over the life expectancy of the cash flows.

The majority of the Group's proved and probable reserves (78% calculated on a BOE basis per the 1 July 2010 reserve report) are currently undeveloped and will require substantial future capital expenditures to develop. The reserves utilised for goodwill impairment testing Field CGU impairment testing and calculating depletion expense assume the Group will be able to fund the future development costs necessary fully develop such non-producing reserves.

11. Intangible exploration and evaluation assets

A summary of the Group's intangible exploration and evaluation assets follows:

Reconciliation of intangible exploration and evaluation assets

The impairment of $1.7 million during the year ended 30 June 2009 relates to the abandonment of undeveloped properties. Delay rentals for evaluation properties were $539,000 and $339,000 for the years ended 30 June 2010 and 2009, respectively. Delay rental expense, unsuccessful acquisition costs and impairment are included with administrative expenses in profit and loss.

12. Property, plant and equipment

A summary of the Group's property plant and equipment follows:

The depreciation charge for oil and natural gas assets is disclosed separately within profit and loss. The oil and natural gas assets are mortgaged as security for the Group's bank credit facility (Note 15 "Borrowings"). Included within other fixed assets is equipment acquired under financing leases with a carrying value of $4,000 and $6,000 at 30 June 2010 and 2009, respectively.

Non-cash impairment of non-core property

Due to a change in the application of accounting policy which resulted from a more detailed and rigorous examination of assets within the Group's single operating segment, a determination was made that multiple CGUs exist. When the carrying value of assets was reviewed on a multi-CGU basis as compared to the single CGU approach previously utilised, a non-cash impairment was identified with respect to the East Cameron 317/318 field (a non-core and non-operated property for which the Group has a 25% working interest, which was offline from August 2008 until December 2009 due to third party pipeline damage from Hurricane Ike). Upon further analysis, it was determined that this field was initially impaired at 30 June 2009 ($23.5 million before tax non-cash impairment expense based on a calculated net present value of future net cash flows discounted at a weighted average cost of capital rate of 11.19% at that date), due primarily to falling natural gas prices. Natural gas prices utilised for the 1 July 2010 reserve report improved slightly, as compared to the 1 July 2009 reserve report, and the Group's weighted average cost of capital rose to 11.64% as a result of the equity raise and debt re-financing accomplished during the 2010 financial year. The net impact of the two aforementioned factors resulted in no additional impairment expense or recovery for the period ended 30 June 2010. No amounts relating to any components of the property, plant and equipment balances as of 30 June 2008 were affected by this restatement. Accordingly, the Company has restated the affected amounts within the financial statements as appropriate for the period ended and as of 30 June 2009 as per IAS 8 "Accounting policies, changes in accounting estimates and errors" (Note 30 "Restatement of prior period").

Possible sale of oil and natural gas property assets during financial year 2011

Due to changes in circumstances since the end of the 2010 financial year, the Group is exploring a strategic alternative that includes divesting some or all of its oil and natural gas assets. The primary purpose of such a transaction would be to provide funds necessary to reduce the Group's borrowings by at least $12.0 million on or before 31 March 2011, when a $12.0 million principal payment is due on the Company's credit facility. Should the Company consummate such a transaction, there can be no assurance that the net proceeds will exceed the Company's carrying value of such assets. (Note 31 "Post-statement of financial position events - revision to the credit facility with UniCredit Bank AG").

13. Trade and other receivables

The Directors consider that the carrying amount of trade and other receivables approximates their fair value:

Trade receivables, joint interest receivables, other receivables and prepayments represent the primary exposure to credit risk. As discussed in Note 4.3 "Financial risk management - credit risk", credit risk is concentrated particularly to five customers within the trade receivables category in the above table. As is the industry practice, the sale of oil, natural gas and natural gas liquids is remitted by purchasers on a monthly basis. The Company's pro-rata share of gas plant processing fees is also remitted on a monthly basis. At each statement of financial position date presented there are no material amounts that are past due.

At 30 June 2010, a receivable for gas production pertaining to the Group's 25% working interest share of natural gas production from its East Cameron 317/318 field covering the production periods of December 2009 to June 2010 in the amount of $340,000 was included within trade receivables. Of that amount $262,000 represented the Group's share of December 2009 through April 2010 natural gas production revenues and was delinquent. Effective May 2010, the operator dedicated the proceeds from its 75% working interest share of natural gas production from the East Cameron 317/318 field towards payment of the outstanding amount owed to the Group. The Group received payments during July and August 2010 that covered the delinquent amount. Accordingly, the Group did not provide a bad debt allowance for this receivable at 30 June 2010.

At 30 June 2010, 2009 and 2008, respectively, the Company had an outstanding note receivable from its US operating subsidiary with an outstanding principal balance of $1.0 million that is due in 2015. As it bears interest at floating rates, which represent prevailing market rates, the Directors consider the carrying amount of the note approximates its fair value at each statement of financial position date.

14. Trade and other payables

The Directors consider that the carrying amount of trade and other payables approximates to their fair value and is generally payable within 30 to 45 days of the relevant period end:

15. Borrowings

A summary of the borrowings at 30 June 2010 and 2009, respectively, follows:

At 30 June 2010, the Group did not have any of its insurance policies financed. During the year ended 30 June 2009, the Group financed renewals of its insurance policies with a finance company ("other finance obligations"). In total $4.6 million was financed, after a 30% down payment, in three contracts. The balance for each was due in nine monthly, fixed instalments. The interest rates for the three contracts ranged from 3.8% to 5.5%.

Bank loans are denominated in US Dollars and bear interest based on LIBOR. The credit facility is secured by a mortgage on the Group's oil and natural gas properties, a security interest in the proceeds from the sale of hydrocarbons as they are produced, a guaranty by the Company and by a security interest in the shareholding of the Company's subsidiaries, Leed Petroleum Inc. and Leed Petroleum LLC (the Group's operating subsidiary) (Note 23 "Investments in subsidiaries").

As the Group's bank borrowings bear interest at floating rates, which represent prevailing market rates, the Directors consider the carrying amount of these borrowings approximates their fair value.

The weighted average interest rates on the Group's borrowings at 30 June 2010 and 2009, respectively, follow:

Weighted average interest rates

For the year ended 30 June 2010, the median bank floating rate was 0.59% and ranged from 0.38% to 1.28%. Assuming a movement of 45 basis points to the ending balances to the bank at 30 June 2010, such movement would increase or decrease post-tax net income by $763,000 for the year. For the year ended 30 June 2009, the median bank floating rate was 2.75% and ranged from 1.10% to 4.40%. Assuming a movement of 165 basis points to the ending balances to the bank at 30 June 2009, such movement would increase or decrease post-tax net income by $433,000 for the year.

Maturity of bank loans

The maturity profile of the Group's non-current bank loans at 30 June 2010 and 2009, respectively, follows:

Amended credit facility

During the year ended 30 June 2010, the Group placed 400,000,000 new Ordinary Shares of 5 pence par value at 5 pence to raise £20 million before expenses (the "Fundraising"), which was inter-conditional with amending its existing credit facility (the "Amended Facility") between Leed Petroleum LLC (a wholly owned subsidiary of the Company) and UniCredit Bank AG. The Group expensed fees of $0.5 million in conjunction with the amendment. Primary terms of the amended facility as of 30 June 2010 are as follows:

Prior to 30 June 2010, the Group requested a waiver from UniCredit Bank AG for certain defaults which management expected to exist at 30 June 2010. In exchange for granting the waiver request, the Group agreed to a 2% margin increase on its credit facility effective 15 June 2010. In addition, on 30 June 2010, the Group made a principal payment of $3.0 million, reducing the overall principal balance of its credit facility to $26.5 million ($1.5 million for the term and $25.0 million for the revolver) as of that date. During November 2010, the Group reached an agreement with the Group's bank whereby the Group would make additional principal payment of $12.0 million on or before 31 March 2011 and the interest rate on its credit facility would increase by 1% effective 15 December 2010 in return for waiving certain conditions of default that may exist at the 31 December 2010 measurement date (Note 31 "Post-statement of financial statement events - revision of credit facility with UniCredit Bank AG").

At 30 June 2009, the Group's bank credit facility was comprised of an $80.0 million facility that expired in $8.0 million increments semi-annually commencing December 2009 through December 2013. At 30 June 2009, there was $185,000 of unamortised arrangement fees netted to drawn amounts which were being amortised and reported with interest expense over the expected life of the loans. The $185,000 of unamortised arrangement fees were expensed when the facility was amended during the year ended 30 June 2010, resulting in no such amounts outstanding at 30 June 2010. At 30 June 2009, the Group had borrowed $40.8 million of the $45.2 million available to be borrowed under the $80.0 million credit facility. The summary of the Group's committed borrowing facilities are as follows:

Maximum borrowing facility

Minimum payments for finance obligations

Minimum payments that are due under other finance obligations at 30 June 2010 and 2009, respectively, follow:

16. Financial instruments

A summary of financial assets and liabilities by category at 30 June 2010 and 2009, respectively, follows:

Financial instruments

Derivative financial instruments

The Group manages its financial risks with derivatives, including hedging for changes in future oil and natural gas prices. The instruments purchased are denominated in US Dollars, the Group's functional currency.

Other gains and losses

Gains and losses on derivative financial instruments that close in each period are realised gains and losses. Changes in the movement of the fair value of derivative financial instruments that are still open at each statement of financial position date are unrealised gains and losses. Both are included in profit and loss for each period and shown as other gains and losses (Note 8 "Loss for period"). A recap of those gains and losses for each period is shown in the table below:

Commodity contracts

As a part of its bank credit facility (Note 15 "Borrowings"), the Group entered into crude oil and natural gas commodity contracts, with staggered effective and termination dates to manage its price risk to oil and natural gas. Such contracts were entered into only at the US subsidiary level. A summary of the open contracts at 30 June 2010 and 2009, respectively, follows:

Valuations levels in the above table are categorised as follows:

At 30 June 2009, there were no crude oil and natural gas commodity contracts classified as level 3 and there were no significant movements between level 1 and level 2 during the years ended 30 June 2010 and 2009, respectively. For the year ended 30 June 2010, average end of month prices of NYMEX/Henry Hub futures for the open contract periods above ranged from $4.38 to $6.06 per mmbtu for natural gas and average end of month prices of NYMEX/WTI futures for the open contracts for crude oil ranged from $75.80 to $81.09 per barrel. Considering the unrealised gain at 30 June 2010 and these movements to the volumes and fixed prices of the contracts then open, a post-tax increase of $2,539,000 or a post-tax increase of $1,699,000 could have resulted.

For the year ended 30 June 2009, average end of month prices of NYMEX/Henry Hub futures for the open contract periods above ranged from $3.64 to $12.58 per mmbtu for natural gas and average end of month prices of NYMEX/WTI futures for the open contracts for crude oil ranged from $49.82 to $123.87 per barrel. Considering the unrealised gain at 30 June 2009 and these movements to the volumes and fixed prices of the contracts then open, a post-tax increase of $479,000 or a post-tax decrease of $4,663,000 could have resulted.

Interest rate swaps

In December 2005, as a part of its bank credit facility (Note 15 "Borrowings"), the Group entered into interest rate swaps, with staggered effective and termination dates, to manage its exposure to interest rate movements on its bank borrowings. Such contracts were entered into only at the US subsidiary level. The swaps are compared to the variable six month British Banker Association rates for US Dollar denominated loans and close semi-annually. At 30 June 2010 the remaining swaps, their effective dates, notional amounts and fixed rates are as follows:

For the year ended 30 June 2010, forward interest rates had a movement of 17 basis points over the effective dates of the contracts then open. An increase or decrease of this amount in the forward interest rate at 30 June 2010 would have resulted in a post-tax change of $64,000 in net income. For the year ended 30 June 2009, forward interest rates had a movement of 215 to 216 basis points over the effective dates of the contracts then open. An increase or decrease of this amount in the forward interest rate at 30 June 2009 would have resulted in a post-tax increase of $49,000 or a post-tax decrease of $29,000.

17. Decommissioning obligations

A summary of the Group's decommissioning obligations follows:

The costs associated with decommissioning an asset are recorded as a liability and as a part of the cost of the asset when it is acquired. The decommissioning costs are recorded at the present value of future obligations when initially incurred and then adjusted for inflation. These estimates are reviewed regularly to consider material changes that may have occurred. At 30 June 2010, a revaluation in accordance with IFRIC 1 "Changes in existing decommissioning, restoration and similar liabilities" was undertaken, resulting in a net decrease of $807,000 to the present value of the expected obligation. The revaluation offset was to property, plant and equipment. It is expected that the obligations, all on Gulf of Mexico oil and natural gas interests, will not be incurred before 15 to 25 years from 30 June 2010, and are thus presented as non-current. Prior to the 30 June 2010 revaluation, the previous revaluation was undertaken at 30 June 2009 and resulted in a net decrease of $1,797,000 to the obligation.

18. Deferred tax

As per Note 2.20 "Significant accounting policies - going concern", the Company reversed all deferred tax asset and liability balances at 30 June 2010. The movement on the net deferred taxes of both jurisdictions in which the Company operates is as per the following:

Net deferred taxes

Due to changes in UK tax legislation, it is expected that the Company will not be subject to UK taxes on future dividends it receives from its US subsidiary. As such, the Company has no deferred tax assets or liabilities related to activities in the UK. At 30 June 2010 net US deferred taxes of $7.2 million were unrecognised.

The movements in US deferred tax assets and liabilities (prior to the offsetting of balances within the same jurisdiction as permitted by IAS 12 "Income taxes") during the period are shown below. With the exception of share-based costs, they are calculated in full on temporary differences under the liability method using a tax rate of 36%, which is the effective tax rate applicable to the Group's operating entity in the US. As the Company's stock price at 30 June 2010 was below the exercise price of the outstanding SARs awards, none of the current year share-based payments related to the SARs was recognised in the current year.

Deferred tax assets (US)

Deferred tax liabilities (US)

19. Issued capital

A recap of issued capital follows:

A recap of movement in issued shares follows:

On 24 November 2009, the Company issued an additional 400,000,000 Ordinary Shares at 5 pence par value at 5 pence per share, resulting in net proceeds of $31.6 million. The following Directors of the Company participated in the offering:

In addition to the above, IB Daiwa Corporation ("IBD"), the Company's largest shareholder, participated in the offering by purchasing 89,080,545 Ordinary Shares, or 22.27% of the total offering, through one of its affiliates. Also, certain members of the Group's management team purchased 2,920,000 Ordinary Shares, or 0.73% of the total offering (Note 26 "Related party transactions").

Options

During the year ended 30 June 2010, 1,147,288 options issued prior to 30 June 2009 expired unexercised, leaving no options outstanding at 30 June 2010. As a part of its agreement with its nominated adviser Matrix Corporate Capital LLP ("Matrix") for services rendered relative to the August 2007 public listing, Matrix received an option to acquire 1,147,288 Ordinary Shares at 47 pence. At that time, an independent appraiser valued the option at $387,000, with assumptions that the Directors consider as reasonable. The option expired unexercised in August 2009.

A summary of movement in options to the Ordinary Shares of 5 pence follows:

20. Cash flows from operating activities

Cash flows from continuing operations

A summary of the components of cash flows generated from continuing operations follows:

Cash and cash equivalents for the statement of cash flows

21. Employees, Directors and auditor remuneration

A summary of total employee and Director costs follows:

Employee and Director costs

The average number of personnel was as follows:

Key management (part of employee and Director costs above)

The Company has two Executive and five Non-executive Directors. In addition, the Company has a Chief Financial Officer ("CFO") who is not a Director. These eight individuals are the key management of the Company (in accordance with IAS 24 "Related Party Disclosures"). The Executive Directors and the CFO receive no remuneration or fees specific to their role as Directors and Officers of the Company; they are employees of the operating subsidiary.

Key management costs