22nd May 2012 07:00
Magnolia Petroleum Plc / Index: AIM / Epic: MAGP / Sector: Oil & Gas
22 May 2012 Magnolia Petroleum Plc (`Magnolia' or `the Company') Final Results for the year to 31 December 2011
Magnolia Petroleum Plc, the AIM quoted US focused oil and gas exploration and production company, announces its final audited results for the year ended 31 December 2011.
Highlights
* AIM IPO in November 2011 * £2.5 million of new capital raised to fund participation in new wells and increases in acreage * Targeting the Bakken and Three Forks Sanish plays in North Dakota, and the Mississippi Lime, Woodford / Hunton formations in Oklahoma * Now participating in 74 producing wells, with a further 10 either being drilled or waiting to spud * Current average monthly revenues show a 75% increase on 2011, excluding several new producing wells * Strong pipeline of opportunities across all formations both as participant and operator
Magnolia CEO, Steven Snead said, "This has been a fantastic period for the Company which has laid the foundations for future growth. Net production and revenues are expected to continue to grow substantially as we increase the number of producing wells in which we are participating, and also raise the average level of our working interests. Since the year end, the number of producing properties in which Magnolia has an interest in has already risen to 74; we have elected to participate in a further 10 properties and have many more proposals to review. In addition, we intend to operate our first well later this year on the hugely exciting Mississippi Lime formation in Oklahoma which we, along with others in the industry, believe is where the prolific Bakken play was just a few years ago. With only five months of the year passed, we believe we are on course for achieving our target of participating in 100 producing wells by the end of 2012."
Chief Executive's Statement
The year under review has seen considerable progress made towards achieving our goal of transforming Magnolia into a significant US onshore oil and gas company. 2012 promises to be a year in which material increases in production and revenues attributable to the Company will be made.
Magnolia offers shareholders the opportunity to participate in the booming US onshore oil and gas industry, which has the potential to transform the US into a net exporter of oil and gas by the end of the decade. The Company's disciplined focus on proven, producing plays, where modern techniques such as horizontal drilling and fracture stimulation can be applied to improve recovery rates, lowers exploration risk and increases returns. Meanwhile, participating in numerous wells with leading operators such as Marathon Oil and ExxonMobil reduces execution risk. Finally, prioritising oil over gas plays enables higher prices and revenues to be realised.
In October 2011, the AIM Admission document laid out the Company's two pronged growth strategy: to continue to increase net production by participating in wells with established operators on our existing acreage in the Bakken and Three Forks Sanish plays in North Dakota, and the Woodford / Hunton formations in Oklahoma; and to acquire leases to drill and operate horizontal wells in the reopening Mississippi Lime formation in Oklahoma.
We have made excellent progress delivering on key objectives in order to fulfil our investment strategy. 31 out of 32 wells in which Magnolia has participated since the Company's inception in 2008 have produced a positive return on capital. This tremendous success rate goes some way towards validating our low risk / high return business model and gives us confidence for the year ahead, as we scale up our activities by increasing the number of wells in which we participate, as well as raise our average level of working interests. Magnolia now has interests in 74 producing properties and we are awaiting the results of a further three wells which are in drilling and completion phases. A number of these wells have larger working interests that Magnolia has secured historically, including the Thomason well in which Magnolia has a 9.375% net revenue interest. We expect these to add materially to our daily production and revenues in the current year.
At the same time, Magnolia remains on track to operate its first well in 2012. A licence to operate wells in Oklahoma was secured during the year, as well as exclusive rights over five prospects targeting the reopening Mississippi Lime formation in Oklahoma. Since the year end, we have acquired 3,540 net mineral acres located within the boundaries of the oil play with an average net revenue interest of 11.1%.
Around the time of our listing last year, we commissioned Moyes & Co to undertake a Competent Person's Report (`CPR') on our existing interests. The CPR assigned a Net Present Value after applying a 10% discount rate of approximately £11m to our 2P reserves at the time, a figure that stands at a premium to our current market capitalisation.
In the CPR, a low rating was assigned to our Three Forks Sanish ("TFS") reserves due to our lack of participation in drilling this emerging play in North Dakota that, due to excellent well results, is increasingly being viewed on a par with the headline grabbing Bakken that lies above it. Aside from generating our best ever initial production rate of 2,303 bopd (received in March 2012), Skunk Creek, our first well targeting TFS, was singled out in our CPR as the trigger for an upgrade in the status of our TFS reserves. We intend to commission a follow-up CPR in the first quarter of 2013 which is expected to incorporate a TFS reserves upgrade as well as our newly acquired Mississippi Lime acreage. The directors expect this updated CPR to materially increase our net asset value.
By the end of the twelve month period, Magnolia had interests in 64 producing properties, generating revenues of approximately US$20,000 per month and $241,038 total revenues for the year as a whole. As mentioned earlier, further progress has been made since the year end, with the number of Magnolia's producing properties rising to 74. Average monthly revenues in the first three months of the year have increased to approximately $35,000 but this excludes several new wells, including the two Eckelberg wells and the Thomason well. Costs continue to be tightly managed, allowing the vast majority of additional revenues generated to be recycled into further wells or acquiring additional leases.
The current financial year is already proving to be tremendously exciting. The months ahead will continue to see Magnolia participating in wells on our existing acreage with leading operators but, crucially, we remain on track to drill our first well as operator in Oklahoma with a larger working interest than has historically been the case. We therefore expect to see a step up in production, revenues and reserves in 2012, all of which are required ingredients for Magnolia to become a significant oil and gas company.
Finally, I would like to thank the management team, directors and all our advisors for their dedication and hard work over the last twelve months and also our shareholders for their active and continued support. The year just passed has seen much activity and the year ahead promises much of the same.
Steven SneadChief Executive OfficerOperations Report
The Bakken / Three Forks Sanish Formations, North Dakota
During the year under review, the Company elected to participate in seven wells targeting the Bakken and TFS formations, North Dakota, bringing the total number of wells in which Magnolia has an interest in these two formations to 21, all of which are now producing.
Oil was first discovered in the Bakken shale in 1951. The advent of horizontal drilling in the 1980s, together with improved hydraulic fracturing techniques, led to the shale becoming a significant target for oil and gas, and post 2000, activity has significantly increased. Daily production is estimated to exceed 700,000 bopd by 2013 and to top 1.2 MMbopd by 2019. The 2008 US Geological Survey (`USGS') estimates that mean undiscovered recoverable volumes of 3.65 Bbbls and 1.85 Tcf are contained in the Bakken Shale of Montana and North Dakota. The latter is the main centre of Bakken Shale activity, where there are over 4,000 active wells.
The results of our participated wells targeting the Bakken have highlighted the potential prolific nature of this formation. For example, in November 2011, we received the initial production rates for the Drone#1 -34H well, which came in at 1,199 bopd and 441mcf per day, resulting in a major uplift in net daily production. Post year end, we reported an initial production rate of 1,263 bopd and 625 mcf for the Eckelberg 14-23H also targeting the Bakken.
The period under review also saw Magnolia participate in a first well, the Skunk Creek 15H, targeting the TFS. A state study evaluating oil reserves in this formation in western North Dakota concluded that there could be as much as 2 billion barrels of recoverable oil in the TFS. The projection is based on more than 200 well measurement logs and 85 sets of testimony from technical experts. At 2,303 bopd, the Skunk Creek 15H well reported the best ever initial production rate for the Company. Significantly, Skunk Creek is expected to lead to a TFS reserves upgrade in an updated CPR to be commissioned in Q1 2013.
Magnolia holds leases in respect of 33,920 gross acres across 28 sections, equating to 557 net mineral acres within the boundaries of the Bakken / TFS formations. The Company's acreage includes 197 proven development locations, 92 on the Bakken and the remaining 105 on the TFS acreage.
Mississippi Lime Formation, Oklahoma
The directors identified the Mississippi Lime formation in Oklahoma as having the potential to be the next big US onshore oil play. The Mississippi is a proven commercial oil and gas system that has been producing at shallow depths ranging from 4,500 to 7,000 feet below the surface from several thousand vertical wells for more than 50 years. New technology and horizontal drilling has reopened the oil play. Due to the relatively shallow depths and less tight rock formation, drilling costs at between $2.4 and $3.5 million are considerably lower than those in the Bakken. Horizontal wells generally have shorter lateral lengths of between 2,500ft and 5,000ft and are fracture stimulated in 6-12 stages - less than those in the Bakken play. Drilling times are relatively short at between 17 and 28 days from spud to total depth.
In October 2011, the Company executed an agreement with a local geologist to develop five prospects covering an area of approximately 80 square miles. Post year end, Magnolia has acquired 3,540 net mineral acres in the play with average net revenue interests of 11.1%, considerably higher than historical levels. One of the five prospects identified by the geologist is included in this acreage.
During the year, Magnolia was granted a licence to operate wells in Oklahoma, which confers to the Company control of timing the proposing, drilling, and producing of wells. Among the acreage acquired post year end in the play are leases with working interests of up to 100% which have the right to operate wells. The Company intends to drill and operate its first well on this acreage in the current year.
Since the year end, Magnolia has elected to participate in nine wells targeting the Mississippi formation. On one of these, the Thomason operated by Chesapeake Energy, Magnolia holds a 12.5% working interest. The well has been completed and is currently producing with initial production rates awaited. Three more are in drilling and five are waiting to spud.
Woodford / Hunton Formations, Oklahoma
Like the Bakken, the Woodford / Hunton formations in Oklahoma are established reservoirs that have been reopened following the introduction of horizontal drilling and stimulation technology. As a result the Woodford oil play in particular is increasingly being drilled by leading operators. Magnolia holds leases in respect of approximately 57,600 gross mineral acres (702 net mineral acres), giving rights to participate in the drilling of wells in 87 sections located in 26 counties in central Oklahoma.
During the year under review, Magnolia participated in the drilling of five wells in the formation, bringing the overall total to 19. Since the year end, five new wells were completed and the company has elected to participate in a further two wells with Cimarex.
Summary
In total the Company has 74 producing wells, for which the Company hope to announce average production rates in the second quarter 2012, with three wells in drilling / awaiting completion and seven wells waiting to spud. The Company is reviewing a large number of additional well proposals which, if the Company elected participate, could result in the company achieving its target of 100 producing wells by the end of 2012.
Rita WhittingtonChief Operations OfficerMAGNOLIA PETROLEUM PLC
consolidated Statement of Comprehensive Income
Year ended 31 December 2011 Note Year ended Year ended 31 December 31 December 2011 2010 $ $ Continuing Operations Revenue 241,038 238,097 Operating expenses (145,365) (90,224) Gross Profit 95,673 147,873 Impairment of mineral leases 10 (224,892) - Administrative expenses 16 (213,228) (206,987) Operating Loss 6 (342,447) (59,114) Finance income - - Finance costs - - Loss before Tax (342,447) (59,114) Taxation 8 - - Loss for the year (342,447) (59,114) Other Comprehensive Income:
Exchange differences on translating (10,931) (1,536) foreign operations
Other Comprehensive Income for the (10,931) (1,536) Year, Net of Tax
Total Comprehensive Income for the (353,378) (60,650) Year
Loss per share for loss attributable to the equity holders of the Company during the year Basic and diluted (cents per share) 17 (0.09) (0.02)
The Company has elected to take the exemption under Section 408 of the Companies Act 2006 from presenting the Parent Company Statement of Comprehensive Income.
The loss for the Parent Company for the year was $80,574 (2010 - $8,708).
MAGNOLIA PETROLEUM PLCCONSOLIDATED BALANCE SHEETAs at 31 December 2011 Note As at As at 31 December 31 December 2011 2010 $ $ ASSETS Non-Current Assets
Property, plant and equipment 9 861,975 615,908
Intangible assets 10 1,111,634 1,109,988 Total Non-Current Assets 1,973,609 1,725,896 Current Assets Trade and other receivables 12 70,308 66,200 Cash and cash equivalents 13 874,037 97,523 Total Current Assets 944,345 163,723 TOTAL ASSETS 2,917,954 1,889,619 EQUITY AND LIABILITIES Equity attributable to Owners of Parent Ordinary shares 14 926,128 587,336 Share premium 14 2,218,877 1,347,983 Warrants and options reserve 66,603 66,603 Merger reserve 1,975,950 1,867,790 Reverse acquisition reserve (2,250,672) (2,250,672) Translation reserve (126,624) (115,693) Retained losses (502,718) (160,271) Total Equity - Capital and 2,307,544 1,343,076 Reserves Non-Current Liabilities Trade and other payables 15 278,431 - 278,431 - Current Liabilities Trade and other payables 15 331,979 546,543 Total Current Liabilities 331,979 546,543 TOTAL EQUITY AND LIABILITIES 2,917,954 1,889,619
These Financial Statements were approved by the Board of Directors on 21 May 2012 and were signed on its behalf by:
Steven SneadChief Executive OfficerRita WhittingtonChief Operating OfficerMAGNOLIA PETROLEUM PLCCompany balance sheetAs at 31 December 2011Registered number 05566066 Note As at As at 31 December 31 December 2011 2010 $ $ ASSETS Non-Current Assets Investments in subsidiaries 11 3,615,907 3,662,897 Total Non-Current Assets 3,615,907 3,662,897 Current Assets Trade and other receivables 12 1,057,957 79,443 Cash and cash equivalents 13 193,788 94,226 Total Current Assets 1,251,745 173,669 TOTAL ASSETS 4,867,652 3,836,566 EQUITY AND LIABILITIES Shareholders' Equity Ordinary shares 14 926,128 587,336 Share premium 14 2,218,877 1,347,983 Warrants and options reserve 66,603 66,603 Merger reserve 1,975,950 1,867,790 Translation reserve (425,334) (372,117) Retained losses (234,852) (154,278) Total Equity - Capital and Reserves 4,527,372 3,343,317 Non-Current Liabilities Trade and other payables 15 243,431 - Total Non-Current Liabilities 243,431 - Current Liabilities Trade and other payables 15 96,849 493,249 Total Current Liabilities 96,849 493,249 TOTAL EQUITY AND LIABILITIES 4,867,652 3,836,566
These Financial Statements were approved by the Board of Directors on 21 May 2012 and were signed on its behalf by:
Steven SneadChief Executive OfficerRita WhittingtonChief Operating OfficerMAGNOLIA PETROLEUM PLC
CONSOLIDATED Statement of Changes in Equity
Year ended 31 December 2011
Group ($) Share Share Merger Share Reverse Translation Retained Total capital Premium reserve option acquisition reserve earnings equity reserve reserve Balance at 587,336 1,347,983 1,867,790 66,603 (2,250,672) (114,157) (101,157) 1,403,72631 December 2009 Comprehensive Income Loss for the - - - - - - (59,114) (59,114) period Other Comprehensive Income Currency - - - - - (1,536) - (1,536) translation differences Total - - - - - (1,536) (59,114) (60,650) Comprehensive Income for the Year Balance at 587,336 1,347,983 1,867,790 66,603 (2,250,672) (115,693) (160,271) 1,343,07631 December 2010 Comprehensive Income Loss for the - - - - - - (342,447) (342,447)period Other Comprehensive Income Currency - - - - - (10,931) - (10,931) translation differences Total - - - - - (10,931) (342,447) (353,378)Comprehensive Income for the Year Transaction with Owners Proceeds from 338,792 1,524,567 - - - - - 1,863,359share issue Share issue - (653,673) - - - - - (653,673)costs Movements in - - 108,160 - - - - 108,160 the year Total 338,792 870,894 108,160 - - - - 1,317,846Transactions with Owners
Balance at 926,128 2,218,877 1,975,950 66,603 (2,250,672) (126,624) (502,718) 2,307,544 31 December
2011
The movement in the merger reserve during the year consisted of the partial write back of a liability and the recovery of input VAT in respect of certain share issue costs incurred in the year ended 31 December 2009.
MAGNOLIA PETROLEUM PLC
COMPANY Statement of Changes in Equity
Year ended 31 December 2011
Company ($) Share Share Merger Share Translation Retained Total capital Premium reserve option reserve earnings equity reserve Balance at 587,336 1,347,983 1,867,790 66,603 (313,712) (145,570) 3,410,430 31 December 2009 Comprehensive Income Loss for the - - - - - (8,708) (8,708) period Other Comprehensive Income Currency - - - - (58,405) - (58,405) translation differences Total - - - - (58,405) (8,708) (67,113) Comprehensive Income for the Year Balance at 587,336 1,347,983 1,867,790 66,603 (372,117) (154,278) 3,343,317 31 December 2010 Comprehensive Income Loss for the - - - - - (80,574) (80,574) period Other Comprehensive Income Currency - - - - (53,217) - (53,217) translation differences Total - - - - (53,217) (80,574) (133,791)Comprehensive Income for the Year Transactions with Owners Proceeds from 338,792 1,524,567 - - - - 1,863,359share issue Share issue costs - (653,673) - - - - (653,673) Movements in the - - 108,160 - - - 108,160 year Total 338,792 870,894 108,160 - - - 1,317,846Transactions with Owners
Balance at 926,128 2,218,877 1,975,950 66,603 (425,334) (234,852) 4,527,372
31 December 2011 MAGNOLIA PETROLEUM PLC
CONSOLIDATED Statement of Cash Flows
Year ended 31 December 2011 Year ended Year ended 31 December 31 December Note 2011 2010 $ $ Cash Flows from Operating Activities Loss before tax (342,447) (59,114) Impairment of mineral leases 224,892 - Depreciation 101,284 83,916 Foreign exchange (781) -
Decrease in trade and other receivables 19,619 6,257
Increase/(Decrease) in trade and other 147,892 (136,205) payables
Net Cash generated from/(used in) 150,459 (105,146) Operating Activities Cash Flows from Investing Activities Purchases of intangible assets (364,998) (24,447) Purchases of property, plant and (213,593) (12,927) equipment Net Cash generated used in Investing (578,591) (37,374) Activities Cash Flows from Financing Activities Proceeds from issue of ordinary shares 1,863,359 - Issue costs (653,673) - Net Cash generated from Financing 1,209,686 - Activities Net Increase/(Decrease) in Cash and 781,554 (142,520) Cash Equivalents Movement in Cash and Cash Equivalents
Cash and cash equivalents at the 13 97,523 245,581 beginning of the period
Exchange loss on cash and cash (5,040) (5,538) equivalents Net increase/(decrease) in cash and 781,554 (142,520) cash equivalents
Cash and Cash Equivalents at the End of 13 874,037 97,523 the Period
MAGNOLIA PETROLEUM PLC
COMPANY Statement of Cash Flows
Year ended 31 December 2011 Year Year ended 31 December ended 31 December Note 2011 2010 $ $ Cash Flows from Operating Activities Loss before tax (80,574) (8,708)
Increase/(decrease) in trade and other 5,384 (294) receivables
Decrease in trade and other payables (43,942) (71,763)
Net Cash used in Operating Activities (119,132) (80,765)
Cash Flows from Financing Activities Proceeds from issue of ordinary shares 1,863,359 - Issue costs (597,139) - Increase in funding subsidiary (1,042,485) (44,741) undertaking Net Cash from Financing Activities 223,735 (44,741) Net Increase/(Decrease) in Cash and 104,603 (125,506) Cash Equivalents Movement in Cash and Cash Equivalents
Cash and cash equivalents at the 13 94,226 225,270 beginning of the period
Exchange loss on cash and cash (5,040) (5,538) equivalents Net decrease in cash and cash 104,603 (125,506) equivalents
Cash and Cash Equivalents at the End of 13 193,788 94,226 the Period
Share issue costs of $56,534 were paid by the subsidiary undertaking.
MAGNOLIA PETROLEUM PLC
NOTES TO THE FINANCIAL STATEMENTS
Year ended 31 December 2011
* GENERAL INFORMATION
The consolidated Financial Statements of Magnolia Petroleum plc ("the Company") consist of the following companies; Magnolia Petroleum plc and Magnolia Petroleum Inc. (together "the Group").
The Company is a public limited company which is listed on the AIM market and incorporated and domiciled in England and Wales. Its registered office address is The Fitzpatrick Building, 188-194 York Way, London, N7 9AS.
* Summary of significant accounting policieS
The principal accounting policies applied in the preparation of these consolidated Financial Statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.
1. Basis of preparation of Financial Statements
The consolidated Financial Statements have been prepared in accordance with EU-endorsed International Financial Reporting Standards (IFRSs) and IFRIC interpretations and the parts of the Companies Act 2006 applicable to companies reporting under IFRS.
The Financial Statements have been prepared under the historical cost convention.
The preparation of Financial Statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated Financial Statements, are disclosed in Note 4.
2. Basis of consolidation
The consolidated Financial Statements consolidate the Financial Statements of Magnolia Petroleum plc and the audited Financial Statements of its subsidiary undertaking made up to 31 December 2011.
Subsidiaries are entities over which the Group has control. Control is the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. The Group obtains and exercises control through voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Group controls another entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases.
The Company acquired Magnolia Petroleum Inc. on 23 October 2009 through a share exchange. As the shareholders of Magnolia Petroleum Inc. have control of the legal parent, Magnolia Petroleum plc, the transaction was accounted for as a reverse acquisition in accordance with IFRS 3 "Business Combinations". The following accounting treatment has been applied in respect of the reverse acquisition:
* the assets and liabilities of the legal subsidiary Magnolia Petroleum Inc. are recognised and measured in the Consolidated Financial Statements at their pre-combination carrying amounts, without restatement to fair value; and * the equity structure appearing in the Consolidated Financial Statements reflects the equity structure of the legal parent, Magnolia Petroleum plc, including the equity instruments issued to effect the business combination.
The cost of acquisition was measured as the fair value of the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus certain costs directly attributable to the acquisition.
In accounting for the acquisition of Magnolia Petroleum Inc., the Company has taken advantage of Section 612 of the Companies Act 2006 and accounted for the transaction using merger relief.
Investments in subsidiaries are accounted for at cost less impairment. Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used into line with those used by other members of the Group. All significant inter-company transactions and balances between Group entities are eliminated on consolidation.
1. Goodwill
Goodwill arising on consolidation represents the excess of the cost of acquisition over the Group's interest in the fair value of the identifiable assets and liabilities of a subsidiary, associate or jointly controlled entity at the date of acquisition. Goodwill is initially recognised as an asset at cost and is subsequently measured at cost less any impairment. Goodwill which is recognised as an asset is reviewed for impairment at least annually. Any impairment is recognised immediately and is not subsequently reversed.
Under the reverse acquisition, goodwill represents the excess of the cost of the combination over the acquirer's interest in the net fair values of the legal parent. The fair value of the equity instruments of the legal subsidiary issued to effect the combination was not available and therefore the fair value of all the issued equity instruments of the legal parent prior to the business combination was used as the basis for determining the cost of the combination.
2. Going concern
The Group's business activities, together with the factors likely to affect its future development and performance are set out in the Chief Executive Officer's Statement. In addition, notes 3 and 22 to the Financial Statements disclose the Group's and Company's objectives, policies and processes for managing financial risks and capital.
The Company raised $1,266,220 after expenses via a placing in the year and, as detailed in note 21, a further £1.3 million before expenses was raised on 2 March 2012. The Group's cash flow forecasts and projections prepared up to June 2013 show that the Group has sufficient funds to fund its ongoing operating costs. The Directors have a reasonable expectation that the Company and Group has adequate resources to continue in operational existence for the foreseeable future. For this reason, the Directors continue to adopt the going concern basis of accounting in preparing the Financial Statements.
3. Changes in accounting policy and disclosure
(a) New and amended standards adopted by the Group
There are no IFRSs or IFRIC interpretations that are effective for the first time for the financial year beginning 1 January 2011 that would be expected to have a material impact on the Group.
(b) New and amended standards, and interpretations mandatory for the first time for the financial year beginning 1 January 2011 but not currently relevant to the Group
The following standards and amendments to existing standards have been published and are mandatory for the Group's accounting periods beginning on or after 1 January 2011, but are not currently relevant to the Group.
A revised version of IAS 24 ``Related Party Disclosures" simplified the disclosure requirements for government-related entities and clarified the definition of a related party. This revision was effective for periods beginning on or after 1 January 2011.
An amendment to IFRS 1 ``First-time Adoption of International Financial Reporting Standards" relieved first-time adopters of IFRSs from providing the additional disclosures introduced in March 2009 by ``Improving Disclosures about Financial Instruments" (Amendments to IFRS 7). This amendment was effective for periods beginning on or after 1 July 2010.
Amendments to IAS 32 ``Financial Instruments: Presentation" addressed the accounting for rights issues that are denominated in a currency other than the functional currency of the issuer. These amendments were effective for periods beginning on or after 1 February 2010.
IFRIC 19 ``Extinguishing Financial Liabilities with Equity Instruments" clarified the treatment required when an entity renegotiates the terms of a financial liability with its creditor, and the creditor agrees to accept the entity's shares or other equity instruments to settle the financial liability fully or partially. This interpretation was effective for periods beginning on or after 1 July 2010.
An amendment to IFRIC 14 ``IAS 19 - The Limit on a Defined Benefit Asset, Minimum Funding Requirements and their Interaction", on prepayments of a minimum funding requirement, applies in the limited circumstances when an entity is subject to minimum funding requirements and makes an early payment of contributions to cover those requirements. The amendment permitted such an entity to treat the benefit of such an early payment as an asset. This amendment was effective for periods beginning on or after 1 January 2011.
(c) New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2011 and not early adopted
The Group and Company's assessment of the impact of these new standards and interpretations is set out below.
IFRS 10 ``Consolidated Financial Statements" builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company. The standard provides additional guidance to assist in the determination of control where this is difficult to assess. This standard is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of this standard on the Group's and Parent Company's Financial Statements.
IFRS 11 ``Joint Arrangements" provides for a more realistic reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form (as is currently the case). The standard addresses inconsistencies in the reporting of joint arrangements by requiring a single method to account for interests in jointly controlled entities. This standard is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of this standard on the Group's and Parent Company's Financial Statements.
IFRS 12 ``Disclosure of Interests in Other Entities" is a new and comprehensive standard on disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special purpose vehicles and other off balance sheet vehicles. This standard is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of this standard on the Group's and Parent Company's Financial Statements.
IFRS 13 ``Fair Value Measurement" improves consistency and reduces complexity by providing, for the first time, a precise definition of fair value and a single source of fair value measurement and disclosure requirements for use across IFRSs. It does not extend the use of fair value accounting, but provides guidance on how it should be applied where its use is already required or permitted by other standards. This standard is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of this standard on the Group's and Parent Company's Financial Statements.
IAS 27 ``Separate Financial Statements" replaces the current version of IAS 27 ``Consolidated and Separate Financial Statements" as a result of the issue of IFRS 10 (see above). This revised standard is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of this standard on the Group's and Parent Company's Financial Statements.
IAS 28 ``Investments in Associates and Joint Ventures" replaces the current version of IAS 28 ``Investments in Associates" as a result of the issue of IFRS 11 (see above). This revised standard is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of this standard on the Group's and Parent Company's Financial Statements.
Amendments to IAS 1 ``Presentation of Financial Statements" require items that may be reclassified to the profit or loss section of the income statement to be grouped together within other comprehensive income (OCI). The amendments also reaffirm existing requirements that items in OCI and profit or loss should be presented as either a single statement or two consecutive statements. These amendments are effective for periods beginning on or after 1 July 2012, subject to EU endorsement. The Directors are assessing the possible impact of these amendments on the Group's and Parent Company's Financial Statements.
Amendments to IAS 19 ``Employment Benefits" eliminate the option to defer the recognition of gains and losses, known as the ``corridor method"; streamline the presentation of changes in assets and liabilities arising from defined benefit plans, including requiring remeasurements to be presented in other comprehensive income; and enhance the disclosure requirements for defined benefit plans, providing better information about the characteristics of defined benefit plans and the risks that entities are exposed to through participation in those plans. These amendments are effective for periods beginning on or after 1 January 2013, subject to EU endorsement, and are not expected to have an impact on the Group's or Parent Company's Financial Statements.
IFRIC 20 ``Stripping Costs in the Production Phase of a Surface Mine" clarifies when stripping costs incurred in the production phase of a mine's life should lead to the recognition of an asset and how that asset should be measured, both initially and in subsequent periods. This interpretation is effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors do not expect any impact on the Group's or Parent Company's Financial Statements.
Amendments to IFRS 7 "Financial Instruments: Disclosures" require disclosure of information that will enable users of financial statements to evaluate the effect or potential effect of netting arrangements, including rights of set-off associated with the entity's recognised financial assets and recognised financial liabilities, on the entity's financial position. These amendments are effective for periods beginning on or after 1 January 2013, subject to EU endorsement. The Directors are assessing the possible impact of these amendments on the Group's and Parent Company's Financial Statements.
Amendments to IFRS 9 "Financial Instruments" and IFRS 7 "Financial Instruments: Disclosures" require entities to apply IFRS 9 for annual periods beginning on or after 1 January 2015 instead of on or after 1 January 2013. Early application continues to be permitted. The amendments also require additional disclosures on transition from IAS 39 "Financial Instruments: Recognition and Measurement" to IFRS 9. The Directors are assessing the possible impact of these amendments on the Group's and Parent Company's Financial Statements.
Amendments to IAS 32 "Financial Instruments: Presentation" add application guidance to address inconsistencies identified in applying some of the criteria when offsetting financial assets and financial liabilities. This includes clarifying the meaning of "currently has a legally enforceable right of set-off" and that some gross settlement systems may be considered equivalent to net settlement. These amendments are effective for periods beginning on or after 1 January 2014, subject to EU endorsement, and are not expected to have an impact on the Group's and Parent Company's Financial Statements.
4. Revenue recognition
Revenue represents the amounts receivable from operators for the Group's share of oil and / or gas revenues less any royalties payable to the lessor or assignor of the mineral rights. Revenue is recognised in the period to which the declarations from the operators relate.
5. Foreign currencies
(a) Functional and presentation currency
Items included in the Financial Statements of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (the `functional currency'). The functional currency of the UK parent entity is sterling and the functional currency of the subsidiary is US Dollars. The Financial Statements are presented in US Dollars, rounded to the nearest Dollar, which is the Group's functional and Company's presentation currency.
(b) Transactions and balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions or valuation where such items are re-measured. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in profit or loss.
(c) Group companies
The results and financial position of all the Group entities (none of which has the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:
* assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet; * income and expenses for each statement of comprehensive income are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and * all resulting exchange differences are recognised in other comprehensive income.
On consolidation, exchange differences arising from the translation of the net investment in foreign entities, and of monetary items receivable from foreign subsidiaries for which settlement is neither planned nor likely to occur in the foreseeable future are taken to other comprehensive income. When a foreign operation is sold, such exchange differences are recognised in the income statement as part of the gain or loss on sale.
1. Commercial reserves
Proven and probable oil and gas reserves are estimated quantities of commercially producible hydrocarbons which the existing geological, geophysical and engineering data show to be recoverable in future years from known reservoirs. The proven and probable reserves included therein conform to the definition approved by the Society of Petroleum Engineers (SPE) and the World Petroleum Council (WPC).
2. Exploration costs
The Group applies the successful efforts method of accounting for oil and gas assets, having regard to the requirements of IFRS 6 `Exploration for and Evaluation of Mineral Resources'. Costs incurred prior to obtaining the legal rights to explore an area are expensed immediately to profit or loss.
Expenditure incurred on the acquisition of a licence interest is initially capitalised within intangible assets on a licence by licence basis. Costs are held, unamortised, within exploration costs until such time as the exploration phase of the licence area is complete or commercial reserves have been discovered. The cost of the licence is subsequently transferred into "Producing Properties" within property, plant and equipment and depreciated over its estimated useful economic life.
Exploration expenditure incurred in the process of determining exploration targets is capitalised initially within intangible assets as exploration costs. Exploration costs are initially capitalised on a well by well basis until the success or otherwise has been established. The success or failure of each exploration effort is judged on a well by well basis. Drilling costs are written off on completion of a well unless the results indicate that hydrocarbon reserves exist and there is a reasonable prospect that these reserves are commercially viable. All such costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop or otherwise extract value from the discovery. Where this is no longer the case, the costs are immediately expensed.
Following evaluation of successful exploration wells, if commercial reserves are established and the technical feasibility of extraction demonstrated, and once a project is sanctioned for commercial development, then the related capitalised exploration costs are transferred into a single field cost centre within development/producing assets within property, plant and equipment after testing for impairment. Where results of exploration drilling indicate the presence of hydrocarbons which are ultimately not considered commercially viable, all related costs are written off to profit or loss.
The net book values of development/producing assets are depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves.
All costs incurred after the technical feasibility and commercial viability of producing hydrocarbons has been demonstrated are capitalised within development /producing assets on a well by well basis. Subsequent expenditure is capitalised only where it either enhances the economic benefits of the development/producing asset or replaces part of the existing development/ producing asset. Any costs remaining associated with the part replaced are expensed.
Net proceeds from any disposal of an exploration asset are initially credited against the previously capitalised costs. Any surplus proceeds are credited to profit or loss.
3. Decommissioning
Where a material liability for the removal of production facilities and site restoration at the end of the production life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. The cost of the relevant tangible assets is increased with an amount equivalent to the provision and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed asset.
4. Property, plant and equipment
All property, plant and equipment other than oil and gas assets are stated at historical cost less depreciation. Historical cost includes expenditure that is directly attributable to the acquisition of the items.
Subsequent costs are included in the asset's carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Company and the cost of the item can be measured reliably. All other repairs and maintenance are charged to profit or loss during the financial period in which they are incurred.
Depreciation is charged so as to write off the cost of assets, over their estimated useful lives, on a straight line basis as follows:
Drilling Costs and Equipment - 10 years
Oil and gas producing assets held in property, plant and equipment are mainly depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves.
The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each financial year-end.
Gains and losses on disposal are determined by comparing proceeds with carrying amount. These are included in profit or loss.
5. Trade receivables
Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of receivables.
6. Cash and cash equivalents
Cash and cash equivalents comprise cash at bank and in hand and demand deposits with banks.
7. Share capital
Shares are classified as equity when there is no obligation to transfer cash or other assets. Incremental costs directly attributable to the issue of equity instruments are shown in equity as a deduction from the proceeds, net of tax. Incremental costs directly attributable to the issue of equity instruments as consideration for the acquisition of a business are included in the cost of acquisition.
8. Taxation
The charge for current tax is based on the results of the Group for the year as adjusted for items which are non-assessable or disallowed. It is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is accounted for using the balance sheet liability method in respect of temporary differences arising from differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax basis used in the computation of taxable profit. In principle, deferred tax liabilities are recognised 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. Such assets and liabilities are not recognised if the temporary difference arises from goodwill (or negative goodwill) or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction, which affects neither the tax profit nor the accounting profit.
Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred tax is calculated at the tax rates that are expected to apply to the period when the asset is realised or the liability is settled. Deferred tax is charged or credited in the Statement of Comprehensive Income, except when it relates to items credited or charged directly to equity, in which case the deferred tax is also dealt with in equity. Deferred tax assets and liabilities are offset when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.
9. Leasing
Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to profit or loss on a straight-line basis over the period of the lease.
10. Financial assets and liabilities
Financial assets comprise trade and other receivables and cash and cash equivalents in the balance sheet. They are classified as loans and receivables. Financial liabilities comprise trade and other payables in the balance sheet, and are held at amortised cost.
Derecognition
The Group derecognises a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of the ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Group is recognised as a separate asset or liability.
Derecognition also takes place for certain assets when the Group writes-off balances pertaining to the assets deemed to be uncollectible.
The Group derecognises a financial liability when its contractual obligations are discharged or cancelled or expire.
Identification and measurement of impairment
At each balance sheet date, the Group assesses whether there is objective evidence that financial assets are impaired. Financial assets are impaired when objective evidence demonstrates that a loss event has occurred after the initial recognition of the asset, and the loss event has an impact on the future cash flows of the asset that can be estimated reliably.
The Group considers the evidence of impairment at both a specific asset and collective level. All individually significant financial assets are assessed for specific impairment. All significant assets found not to be specifically impaired are then collectively assessed for any impairment that has been incurred but not yet identified. Assets that are not individually significant are then collectively assessed for impairment by grouping together financial assets (carried at amortized cost) with similar risk characteristics.
When a subsequent event causes the amount of impairment loss to decrease, the impairment loss is reversed through profit or loss.
11. Share based incentive
The fair value of the services received in exchange for the grant of warrants is recognised as an expense and as a component of equity, if material. The total amount to be expensed over the vesting period is determined by reference to the fair value of the warrants granted using the Black-Scholes option pricing model.
12. Segment Information
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-makers, who are responsible for allocating resources and assessing performance of the operating segments and making strategic decisions.
* Financial risk management
The Group's activities expose it to a variety of financial risks to include market risk (including currency risk), credit risk and liquidity risk.
Market risk
The Group operates in an international market for hydrocarbons and is exposed to risk arising from variations in the demand for and price of the hydrocarbons. Oil and gas prices historically have fluctuated widely and are affected by numerous factors over which the Group has no control, including world production levels, international economic trends, exchange rate fluctuations, speculative activity and global or regional political events.
Credit risk
Credit risk represents the risk of loss the Group would incur if operators and counterparties fail to fulfil their credit obligations. The maximum exposure to credit risk is represented by the carrying amount of each financial asset.
The Group's trade receivables and accrued income result from contractual amounts due from third party operators. The risk is concentrated between a relatively small group of operators given the small number of parties involved in oil and gas exploration and production activities. The Group seeks to mitigate this risk where possible by assessing the credit quality of the operators and by establishing ongoing and long term relationships.
Liquidity risk
Prudent liquidity risk management implies maintaining sufficient cash and marketable securities to finance the Group's operations. The Group monitors its cash flow position and overall liquidity risk. The Group maintains a level of cash deemed sufficient to finance operations to mitigate the effects of fluctuations in cash flows. The Group negotiates its payment terms in its sales agreements so as to minimize any periods of negative cash flows in any agreement.
Foreign exchange risk
The majority of the Group's sales and purchase transactions are denominated in US dollars. The Company's expenditure is predominantly denominated in sterling The currencies are stable and any exchange risk is managed by maintaining bank accounts denominated in those currencies.
* Critical accounting estimates and judgements
Use of estimates and judgements
The preparation of Financial Statements in conformity with IFRSs requires management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis of making the judgements about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods. In particular, information about significant areas of estimation uncertainty and critical judgements in applying accounting policies that have the most significant effect on the amount recognised in the financial statements are described below:
Recoverability of mineral leases
Mineral leases and drilling costs on non producing properties have a carrying value at 31 December 2011 of $755,418 (2010: $749,070). Management tests annually whether non producing mineral leases have future economic value in accordance with the accounting policy stated in note 2.9. This assessment takes into consideration the likely commerciality of the asset, the future revenues and costs pertaining and the discount rates to be applied for the purposes of deriving a recoverable value. In the event that a lease does not represent an economic drilling target and results indicate that there is no additional upside, the mineral lease and drilling costs will be impaired. The Directors have reviewed the estimated value of the licences and have concluded that no additional impairment charge is necessary above that recognised in the year.
Decommissioning
Where the Group has decommissioning obligations in respect of its assets, the full extent to which the provision is required depends on the legal requirements at the time of decommissioning, the costs and timing of any decommissioning works and the discount rate applied to such costs.
Estimated impairment of goodwill
Goodwill has a carrying value at 31 December 2011 of $356,216 (2010: $360,918). The Group tests annually whether goodwill has suffered any impairment in accordance with the accounting policy stated in Note 2.3. Management have concluded that there is no impairment charge necessary to the carrying value of goodwill.
Estimated useful lives of property, plant and equipment
Useful lives are based on industry standards and historical experience which are subjected to yearly evaluation. For leasehold improvements, the Group's considerations include the lease period of the agreement. Management review property, plant and equipment at each balance sheet date to determine whether there are any indications of impairment. If any such indication exists, an estimate of the recoverable amount is performed, and an impairment loss is recognised to the extent that the carrying amount exceeds the recoverable amount.
Share based payments
The Group has made awards of options and warrants over its unissued capital. The valuation of these options and warrants involves making a number of estimates relating to price volatility, future dividend yields, expected life and forfeiture rates.
* segmental information
The Group operates in two geographical areas, the United Kingdom and the UnitedStates of America. Activities in the UK are mainly administrative in naturewhilst the activities in the United States of America relate to exploration andproduction from oil and gas wells. The reports reviewed by the Board ofDirectors that are used to make strategic decisions are based on thesegeographical segments. Year ended 31 December 2011 USA UK Intra-segment Total balances $ $ $ $ Revenue from external 241,038 - - 241,038 customers Gross profit 95,673 - - 95,673 Operating loss (261,873) (80,574) - (342,447) Impairment - expired leases 224,892 - - 224,892 Depreciation 101,284 - - 101,284 Capital expenditure 578,593 - - 578,593 Total assets 2,314,906 4,867,652 (4,620,820) 2,561,738 Total liabilities 1,275,042 340,280 (1,004,912) 610,410 Year ended 31 December 2010 USA UK Intra-segment Total balances $ $ $ $ Revenue from external 238,097 - - 238,097 customers Gross profit 147,873 - - 147,873 Operating loss (50,406) (8,708) - (59,114) Depreciation 83,916 - - 83,916 Capital expenditure 37,375 - - 37,375 Total assets 1,399,773 3,836,566 (3,707,638) 1,528,701 Total liabilities 98,036 493,248 (44,741) 546,543 A reconciliation of the operating loss to loss before taxation is provided asfollows: Year ended Year ended 31December 31December 2011 2010 $ $ Operating loss for reportable segments (342,447) (59,114) Finance income - - Finance costs - - Loss before tax (342,447) (59,114)
The amounts provided to the Board of Directors with respect to total assets are measured in a manner consistent with that of the Financial Statements. These assets are allocated based on the operations of the segment and physical location of the asset. Goodwill recognised by the Group is managed centrally and is not considered to be a segmental asset.
Reportable segments' assets are reconciled to total assets as follows:
Year ended Year ended 31December 31December 2011 2010 $ $
Segmental assets for reportable segments 2,561,738 1,528,701
Unallocated: goodwill 356,216 360,918 Total assets per balance sheet 2,917,954 1,889,619
Information about major customers
Revenues of $94,649 and $30,768 are derived from two external operators. These revenues were all generated in the USA.
* operating loss 2011 2010 $ $ Loss from operating activities is stated after charging/(crediting): Auditors' remuneration 16,044 20,077 * audit of parent company and consolidated 8,423 16,988 financial statements * other services in relation to accountancy and tax Depreciation 101,284 83,916 Impairment of mineral leases 224,892 - Differences due to foreign exchange (10,988) -
Fees payable to the auditors of $72,196 for work undertaken on the placing at the date of admission to AIM have been charged to share premium.
* STAFF COSTS
The Group and Company incurred no staff costs during 2011 and 2010.
Directors' Emoluments
The Directors' emoluments in respect of qualifying services were:
Group Company 2011 2010 2011 2010 $ $ $ $ Directors' salary and 6,582 - (6,918) - fees
Directors' fees for 2010 and for the period up to AIM admission have been waived. The accrual as at 31 December 2010 has been released in 2011.
2011 2010 $ $ J M Cubitt 1,604 - S O Snead 1,604 - R F Whittington 13,500 - R S Harwood 1,604 - G J Burnell 1,604 - Total 19,916 -
The average monthly number of staff, including the Directors, during the financial year was as follows:
Group 2011 2010 No, No.
Administrative and managerial 5 5
* taxation
Tax charge for the period
The tax charge for the period is $Nil (2010: $Nil).
Factors affecting the tax charge for the period
The tax charge for each period is explained below:
2011 2010 $ $ Loss for the period before (342,447) (59,114) taxation Loss for the period before tax multiplied by the standard rate of UK corporation tax of 26.5% (2010: 28%) (90,748) (16,552) Tax losses carried forward - US 132,198 5,246 Tax losses carried forward - UK 21,352 2,438 IFRS adjustments 13,778 8,868 US tax permanent and timing (76,580) - differences - -
The Group has UK tax losses of approximately $225,000 (2010: losses of approximately $148,000) and US tax losses of approximately $817,000 (2010: losses of approximately $266,000) available to carry forward against future taxable profits. A potential deferred tax asset of approximately $56,250 on the UK losses and $135,000 on the US losses has not been recognised because of uncertainty over the timing of future taxable profits against which the losses may be offset.
* Property, plant and equipment
Group Producing Drilling Total properties costs and equipment $ $ $ Cost At 1 January 2010 133,055 86,923 219,978 Additions - 12,928 12,928
Transferred from intangible assets 190,835 298,755 489,590
At 31 December 2010 323,890 398,606 722,496 Additions - 213,593 213,593 Transferred from intangible assets 133,758 - 133,758 At 31 December 2011 457,648 612,199 1,069,847 Depreciation At 1 January 2010 17,741 4,931 22,672 Charge for the period 30,046 53,870 83,916 At 31 December 2010 47,787 58,801 106,588 Charge for the period 50,171 51,113 101,284 At 31 December 2011 97,958 109,914 207,872
Net Book Amount at 1 January 2010 115,314 81,992 197,306
Net Book Amount at 31 December 2010 276,103 339,805 615,908
Net Book Amount at 31 December 2011 359,690 502,285 861,975
Transfers from intangible assets represent licence areas where production has commenced together with drilling costs associated with these licences.
Depreciation expense of $50,171 (2010: $30,046) has been charged in cost of sales and $51,113 (2010: $53,870) in administrative expenses.
* intangible assets GroupCost Goodwill Drilling Mineral Total $ costs leases $ $ $ At 1 January 2010 367,051 287,196 927,017 1,581,264 Additions - 11,559 12,888 24,447 Transferred to property, plant and - (298,755) (190,835) (489,590) equipment Exchange movements (6,133) - - (6,133) At 31 December 2010 360,918 - 749,070 1,109,988 Additions - 364,998 - 364,998 Transferred to property, plant and - - (133,758) (133,758) equipment Exchange movements (4,702) - - (4,702) Impairment - - (224,892) (224,892) As at 31 December 2011 356,216 364,998 390,420 1,111,634 Amortisation At 1 January 2010 - - - - Charge for the period - - - - At 31 December 2010 - - - - Charge for the period - - - - At 31 December 2011 - - - -
Net Book Amount at 1 January 2010 367,051 287,196 927,017 1,581,264
Net Book Amount at 31 December 2010 360,918 - 749,070 1,109,988
Net Book Amount at 31 December 2011 356,216 364,998 390,420 1,111,634
Impairment review
Drilling costs and mineral leases represent acquired intangible assets with an indefinite useful life and are tested annually for impairment. As disclosed within Accounting Policies, expenditure incurred on the acquisition of mineral leases is capitalised within intangible assets until such time as the exploration phase is complete or commercial reserves have been discovered. Exploration expenditure including drilling costs are capitalised on a well by well basis if the results indicate the existence of a commercially viable level of reserves.
The directors have undertaken a review to assess whether circumstances exist which could indicate the existence of impairment as follows:
* The Group no longer has title to the mineral lease. * A decision has been taken by the Board to discontinue exploration due to the absence of a commercial level of reserves. * Sufficient data exists to indicate that the costs incurred will not be fully recovered from future development and participation.
Following their assessment the directors recognised an impairment charge to the cost of mineral leases of $224,892 (2010 - $Nil) in respect of expired mineral leases.
The directors believe that no impairment is necessary on the carrying value ofgoodwill. Goodwill arose on the reverse acquisition of Magnolia Petroleum Plc.The goodwill represents the value of the parent company being a quoted entityto Magnolia Petroleum Inc. * INVESTMENTS Investments in subsidiaries 2011 2010 $ $ Shares in group undertakings At 1 January 3,662,897 3,725,899 Exchange movements (46,990) (63,002) At 31 December 3,615,907 3,662,897Investments in group undertakings are recorded at cost, which is the fair valueof the consideration paid.Principal subsidiariesName Country of Nature of Registered Proportion of equity incorporation business capital shares held by Company and residence Magnolia United States of Oil and gas Ordinary 100% Petroleum America exploration shares US$1 Inc.
This subsidiary undertaking is included in the consolidation. The proportion of the voting rights in the subsidiary undertaking held directly by the Parent Company does not differ from the proportion of ordinary shares held.
* TRADE AND OTHER RECEIVABLES * 2011 2010 2011 2010 $ $ $ $ Trade receivables 16,820 31,498 - - Other receivables 47,670 29,438 47,227 29,438 Amounts due from Group - - 1,004,912 44,741undertakings Prepayments 5,818 5,264 5,818 5,264 Total 70,308 66,200 1,057,957 79,443
Trade receivables comprise customer receivables in credit. The Group retains all risks associated with these receivables until fully recovered.
As at 31 December 2011, trade receivables of $16,820 (2010: $31,498) were fully performing.
Group
The carrying amounts of the Group's trade and other receivables are denominatedin the following currencies: 2011 2010 $ $ UK Pounds 53,044 34,702 US Dollar 17,264 31,498 70,308 66,200
The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable mentioned above. The Group does not hold any collateral as security.
The carrying amounts of the Company's trade and other receivables are denominated in UK pound sterling.
* CASH AND CASH EQUIVALENTS Group Company 2011 2010 2011 2010 $ $ $ $ Cash at bank 874,037 97,523 193,788 94,226
Cash and cash equivalents 874,037 97,523 193,788 94,226
At 31 December 2011, the Group held cash of $193,788 in a bank with a Fitch credit rating of A (Stable) and $680,249 in a bank with a credit rating of AA-minus.
* SHARE CAPITAL AND PREMIUM
Allotted, called-up and fully paid
Ordinary shares Share Premium Number Nominal Nominal Nominal Nominal value value value value £ $ £ $
At 1 January 2010 & 341,038,441 341,039 587,336 731,391 1,347,983
31 December 2010 - shares of 0.1p each
Issued in the year 218,181,820 218,181 338,792 560,682 870,894
At 31 December 2011 559,220,261 559,220 926,128 1,292,073 2,218,877 - shares of 0.1p
each
On 25 November 2011, the Company issued 218,181,280 new ordinary shares of 0.1p each fully paid at 0.55p per share.
Group Number of shares Ordinary Share shares premium $ $ At 1 January 2010 341,038,441 587,336 1,347,983 At 31 December 2010 341,038,441 587,336 1,347,983 Placing shares 218,181,820 338,792 1,524,567 Issue costs - - (653,673) At 31 December 2011 559,220,261 926,128 2,218,877
Under reverse acquisition accounting, the equity structure appearing in the consolidated Financial Statements reflects the equity structure of the legal parent, including the equity instruments issued by the legal parent to effect the combination.
Share options and warrants
Share options and warrants outstanding and exercisable at the end of the year have the following expiry dates and exercise prices:
No. Options/warrants Expiry date Exercise price in 2011 2010 pence per share 23 April 2011 2.00 - 10,980,759 25 November 2016 0.55 9,545,454 - 25 November 2018 1.30 52,820,768 52,820,768 62,366,222 63,801,527
The options and warrants are exercisable starting immediately from the date of grant. The Company and Group have no legal or constructive obligation to settle or repurchase the warrants or options in cash.
Year ended Year ended 31 December 2011 31 December 2010 No. of Weighted No. of Weighted options and average options and average warrants exercise warrants exercise price price (in pence) (in pence) Outstanding at beginning of 63,801,527 1.42 63,801,527 1.42period Granted during the period 9,545,454 0.55 - - Expired during the period (10,980,759) 2.00 - -
Outstanding at end of period 62,366,222 1.19 63,801,527 1.42
Exercisable at end of period 62,366,222 1.19 63,801,527 1.42
The warrants and options outstanding at 31 December 2011 had a weighted average remaining contractual life of 6.57 years.
No options or warrants were exercised during the period. On 25 November 2011, 9,545,454 warrants were granted as part of the placing and AIM admission. The warrants have an exercise price of 0.55 pence and an expiry date of 25 November 2016.
As part of the arrangements for the AIM admission, 52,820,768 options and warrants with an original expiry date of 23 October 2014 had their expiry date extended to 25 November 2018. The exercise price remained unchanged at 1.3 pence. The financial effect of the modification is not material.
* Trade and other payables * Group Company 2011 2010 2011 2010 $ $ $ $ Non Current Trade 278,431 - 243,431 -and other payables 278,431 - 243,431 - Current Trade 227,907 332,431 41,604 305,279and other payables Social 122 124 122 124security and other taxes Accrued 103,950 213,988 55,123 187,846expenses
331,979 546,543 96,849 493,249
Under the terms of the Deferral Amendment Agreement dated 15 November 2011, non-current trade and other payables of $243,431 are repayable on 23 April 2013. Under the terms of the Enerlex Loan Agreement dated 15 November 2011, non-current other payables of $3,500, $6,500 and $25,000 are repayable on demand to Enerlex Inc. on a date on or after 11 April 2013, 14 September 2013 and 17 October 2013 respectively.
* EXPENSES BY NATURE * Group 2011 2010 $ $ Directors' fees 6,582 - Management fees - 51,000 Consulting fees 24,350 151
Legal, professional and compliance costs 90,762 76,669
Difference due to foreign exchange (10,988) - Depreciation 51,113 53,870 Other Costs 51,409 25,297 Total administrative expenses 213,228 206,987 * Loss per Share
The calculation of the basic loss per share of 0.09 cents per share (31 December 2010 loss per share: 0.02 cents) is based on the loss attributable to ordinary shareholders of $342,447 (31 December 2010 loss: $59,114) and on the weighted average number of ordinary shares of 363,155,502 (31 December 2010: 341,038,441) in issue during the period.
In accordance with IAS 33, no diluted earnings per share are presented as the effect on the exercise of share options would be to decrease the loss per share.
Details of share options and warrants that could potentially dilute earnings per share in future periods are set out in Note14.
* Treasury Policy and Financial Instruments
The Company and Group operate informal treasury policies which include ongoing assessments of interest rate management and borrowing policy. The Board approves all decisions on treasury policy.
The Company has financed its activities by the raising of funds through the placing of shares. There are no material differences between the book value and fair value of the financial assets.
* Related Party Transactions
Transactions with Group undertakings
During the year ended 31 December 2011 the Company charged management fees of $17,632 (2010: $44,741) to Magnolia Petroleum Inc, the Company's wholly owned subsidiary for the provision of administrative and management services. $17,632 (2010: $44,741) in relation to these fees was outstanding at the balance sheet date and is included within Trade and other receivables. As at 31 December 2011, the amount due to the Company from Magnolia Petroleum Inc was $1,004,912 (2010: $44,741).
All Group transactions were eliminated on consolidation.
Transactions with Enerlex Inc
Steven Snead and his wife are interested in 100 per cent of the issued share capital of Enerlex Inc. ("Enerlex"). Under the Enerlex Services Agreement dated 23 October 2009, Enerlex agreed to provide executives, staff, premises and business services to Magnolia Petroleum Inc. to enable it to acquire, manage and develop its drilling and working interests business. In addition, Enerlex provided 50 per cent of the working time of Steven Snead as Chief Executive Officer, of Rita Whittington as Operations Manager and of Ronald Harwood as Chairman and Chief Financial Officer, as well as the use of other unnamed personnel required for the performance of the above services. The Enerlex Services Agreement ran for a fixed period of one year and was renewable in the twelfth month of each year for a further year by agreement.
A Services Termination Agreement dated 15 November 2011 between Enerlex, Magnolia Petroleum Inc and the Company terminated the Enerlex Services Agreement with effect from 31 October 2011. A rental agreement between Enerlex and Magnolia Petroleum Inc was signed on 15 November 2011 whereby Enerlex agreed to provide Magnolia Petroleum Inc on a month to month basis with office premises and services for $2,500 per month. A charge of $2,500 was recognised during the year under this agreement.
At 31 December 2011 accrued interest of $26,143 (2010: $26,143) was due to Enerlex in relation to a loan granted to the Company which was repaid in full in October 2010. No interest was charged by Enerlex during the year (2010: $Nil).
Enerlex gave an undertaking to Magnolia Petroleum Inc dated 15 November 2011 whereby Enerlex undertakes that if any of the leases granted to Magnolia Petroleum Inc on any of the mineral interests in the Woodford/Hunton play in Oklahoma expires at the end of the primary period because of non-drilling, Enerlex will at Magnolia Petroleum Inc's request grant a further three year lease on the same terms as the expired lease.
Other Transactions
At 31 December 2011 the total accrued remuneration to Directors was $18,137 (2010: $11,212).
Under the Deferral Amendment Agreement dated 15 November 2011, all Directors agreed to waive their services fees up to the date of AIM admission.
* Ultimate controlling party
As at the Balance Sheet date, the Directors do not consider there is an ultimate controlling party.
* POST BALANCE SHEET EVENTS
On 20 January 2012, 4,545,455 share warrants over ordinary shares of 0.1p each were exercised for a total consideration of £25,000.
On 27 January 2012, 4,999,999 share warrants over ordinary shares of 0.1p each were exercised for a total consideration of £27,500.
On 2 March 2012, the Group raised approximately £1.3 million before expenses via a placing of 100,115,270 new ordinary shares at a price of 1.3p per share.
* Capital management polices
The Group and Company's capital management objectives are:
* to ensure the Group's and Company's ability to continue as a going concern; and * to provide an adequate return to shareholders.
The Group and Company monitor capital on the basis of the carrying amount of equity less cash and cash equivalents as presented on the face of the balance sheet.
Although the Group and Company are not constrained by any externally imposed capital requirements, its goal is to maximise their capital-to-overall financing structure ratio.
The Group and Company set the amount of capital in proportion to its overall financing structure and manage their capital structure and make adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying assets.
* CAPITAL COMMITMENTS
The Group has capital commitments for drilling and equipment costs contracted but not provided for of approximately $433,000 at the balance sheet date.
* * ENDS * *
For further information on Magnolia Petroleum Plc visit www.magnoliapetroleum.com or contact the following:
Steven Snead Magnolia Petroleum Plc +01 918 449 8750 Rita Whittington Magnolia Petroleum Plc +01 918 449 8750
Antony Legge / James Thomas Daniel Stewart & Company Plc +44 (0) 20 7776 6550
John Howes / John-Henry Northland Capital Partners +44 (0) 20 7796 8800Wicks Limited Lottie Brocklehurst St Brides Media and Finance +44 (0) 20 7236 1177 Ltd Frank Buhagiar St Brides Media and Finance +44 (0) 20 7236 1177 Ltd Notes
Magnolia Petroleum Plc is an AIM quoted, US focussed, oil and gas exploration and production company. Its portfolio includes interests in 74 producing and non-producing assets, primarily located in the highly productive Bakken/Three Forks Sanish hydrocarbon formations in North Dakota as well as the substantial and proven Woodford and Hunton formations and the oil rich Mississippi formation, in Oklahoma.
As Magnolia currently participates in drilling with leading oil and gas companies, management does not have control over the timing of well proposals or drilling. As a result, management rely on receiving confirmation of field activity such as date of spudding or completion from the relevant operator. Expected timings of activity provided by the Company are therefore to be treated as estimations. Magnolia intends to operate its first well later this year and as operator the Company will be in a position to provide more accurate information regarding the timing of drilling.
Related Shares:
Magnolia Petroleum