Final Results

MAGNOLIA PETROLEUM PLC - Final Results

PR Newswire

London, June 27

Magnolia Petroleum Plc / Index: AIM / Epic: MAGP / Sector: Oil & Gas

27 June 2016

Magnolia Petroleum Plc (‘Magnolia’ or ‘the Company’)

Final Results

Magnolia Petroleum Plc, the AIM quoted US focused oil and gas exploration and production company, announces its final results for the year ended 31 December 2015.

Operational Overview

- 21% year on year increase in number of producing wells to 213 in proven US onshore formations such as the Bakken/Three Forks Sanish, North Dakota, and the Mississippi Lime, Woodford/Hunton, Oklahoma, (2014: 176)

- Elected to participate in 38 new wells – 12 wells currently at various stages of development

- Post period end daily production of 242 boepd as at 31 March 2016 compared to 281 boepd as at 1 January 2015 due to a combination of natural decline rates and also lower drilling activity across the sector in response to volatile global oil and gas markets

Financial Overview

- 2015 revenues of US$1,991,021(2014: US$3,851,905) – reflects a more than 50% year on year reduction in the oil price

- EBITDA of (US$292,180) (2014: US$2,596,658)

- Tangible assets of US$7,294,470 (2014: US$11,294,373) – reflecting lower price of oil, natural decline rates and reduced drilling activity

- 31% reduction in full year operating costs compared to costs in previous year

- US$400,000 paid towards credit facility which will result in significant reduction in financing costs

- £1 million raised via a placing to fund new drilling

Magnolia CEO, Steven Snead said, “Even with oil trading at sub US$50 per barrel, Magnolia Petroleum remains a cashflow generative, low cost, oil and gas producer focused on proven US onshore formations. Thanks to the action we have taken over the course of the year, specifically a 31% and 25% reduction in operating costs and net debt respectively, the Company’s significantly lower outgoings allow a higher proportion of our production based revenues to be reinvested into further drilling activity. We are therefore confident that despite the current downturn, the year ahead will continue to see Magnolia participate with leading operators such as Continental Resources in drilling new wells where it makes commercial sense to do so. 

“As at year end, the Company’s tangible assets stood at US$7,294,470, the majority of which comprise proven developed reserves which were independently estimated post period end at 138.63 Mbbl of oil and condensate and 352.38 MMcf gas as at 1 January 2016. This estimate coincided with WTI trading at close to 12 year lows of sub US$30 per barrel and therefore has been made at what could prove to be the low point of the current cycle. When combined with the reduction in debt over the period, Magnolia has considerable asset backing, particularly when compared with our current market capitalisation. We are working hard to close this disconnect and I look forward to providing further updates on our progress during the year ahead.”

Chief Executive’s Statement

Magnolia Petroleum is an oil and gas production and exploration company focused on acquiring and developing leases in proven US onshore formations, such as the Bakken in North Dakota and the Mississippi Lime and Woodford in Oklahoma. 

The year under review has seen the unbroken sequence of double digit year on year percentage growth in our producing well count maintained, an achievement which is all the more impressive when set against the backdrop of sharply lower oil prices. With West Texas Intermediate (“WTI”) averaging US$48.66 per barrel over the course of the year, the extended period of WTI trading in a tight range around the US$95 per barrel level has been brought to an abrupt end. Like all US onshore operators, such a sharp retrenchment in such a short space of time has necessitated a realignment of Magnolia’s operations to the lower oil price environment, and I am pleased to report this is what we have done.

Significant reductions in the Group’s capital expenditure, operating costs and reserve based debt facility have all been achieved over the last 12 months. Restricting our participation in drilling only those wells which offer attractive returns at US$30-US$40 oil prices or lower has cut our capital investment requirements for the year; a comprehensive review of corporate overheads including salaries and directors’ fees has resulted in full year operating costs being reduced by 31% compared to the previous year; while a part repayment of our credit facility will see financing costs sharply reduced going forward. Magnolia was always a low cost, cash flow generative business, and thanks to the action we have taken, it is even more so today.

The focus on outgoings however has not stopped us from continuing the roll-out of our strategy to drill new wells in proven US onshore formations alongside established operators. As at 31 December 2015 our producing well count stood at 213 compared to 176 as at 1 January 2015, a 21% year on year increase. Bearing in mind our focus has been on participating in those new wells which make commercial sense at prevailing oil and gas prices, this strong performance serves to highlight the low break-even costs associated with our US onshore acreage.

Once a well has been drilled and commences production it is by no means forgotten. Instead we actively manage our portfolio of interests, constantly monitoring each individual well’s performance and importantly its commerciality. With this in mind, post year end we announced in our Q1 2016 update the divestment of 46 uneconomic wells with little or no value to free up our internal accounting resources. The carrying value of these wells have been impaired through profit and loss down to their net realisable value as at 31 December 2015 We have since divested a further 21 wells, bringing our total producing well count to 146. These 146 wells continue to generate meaningful production for us. As at 31 March 2016, 242 boepd were recovered net to Magnolia, which compares to 309 boepd on 1 August 2015 and 281 boepd as at 1 January 2015. The reduction in production largely reflects natural decline rates and also lower drilling activity across the sector over the period in response to volatile global oil and gas markets. 

Even at lower oil prices, our net production generated revenues of US$1,991,021 for the year ended 31 December 2015. As expected our revenues were lower than last year. However the 31% reduction in corporate overheads and operating costs over the last 12 months allows a higher proportion of our cash flows to drop to the bottom line and become available for reinvestment into further drilling. Not only does this bode well for Magnolia’s progress in the current market environment, but also for future profitability, particularly when global supply and demand for oil and gas returns to equilibrium. 

From the outset, management has viewed the current downturn in oil and gas markets as cyclical in nature rather than structural: one that has been caused by excess supply coinciding with a slowdown in demand growth, particularly in previously buoyant areas of the world. As with all cycles, supply and demand will rebalance and while this will take time, we are already seeing signs of this happening: in April 2016 the number of active rigs in the US stood at a multi-year low of 420, a fraction of the 2,000 or so which were regularly reported in recent years. In the US, the rebalancing process is clearly underway. Combined with hundreds of millions of dollars’ worth of new projects across the world being put on the backburner, the point of equilibrium could be closer than most interested observers currently anticipate. 

In the meantime, the current downturn has levelled the playing field, at least in the US onshore sector. Technological advances along with the cutting edge drilling/completing techniques which have transformed the US energy sector are here to stay and continue to be improved on. What has changed is that operators of all sizes are retrenching fast with leases being relinquished or allowed to expire. As a result, acreage which is located in highly productive areas where we have been looking to increase our exposure to, or gain a foothold in, is becoming available. This is where management’s nearly four decades of experience and expertise in leasing US onshore acreage comes into its own. We are therefore highly confident that we can take advantage of today’s market conditions to effectively high grade Magnolia’s portfolio of US onshore leases.

Financial Review

During the 12 months to 31 December 2015, net production generated revenues of US$1,991,021, compared to US$3,851,905 the previous year. The sharp fall in the price of oil, which has effectively halved over the last twelve months, is responsible for the drop in revenues, both directly by lowering sales prices achieved and indirectly through operators shutting in wells to curtail production. In view of this, the Group has quickly taken steps to reduce overheads to help accommodate the revenue decline. 

Property, plant and equipment (comprising producing properties) as at end December 2015 stood at US$7,294,470, (2014: US$11,294,373) while intangible assets (comprising new leases and wells that are drilling but not yet completed) stood at US$1,830,773 (2014: US$6,481,872). Non-cash impairments totalling US$8,511,709 million have been provided for in the results for the year ended 31 December 2015. 

This includes write-downs associated with the cost of mineral leases which have expired; and a markdown in the value of the Group’s interest in producing properties that Moyes has identified as non-economic at today’s low oil prices. Management expects the value of its interests in producing wells to be written back, either in part or in full, as and when the oil price recovers.

In addition, an impairment of US$225,230 for the Magnolia operated Shimanek #2 vertical well (‘Shimanek’) in Oklahoma has been taken in the full year results. Shimanek encountered hydrocarbons in the targeted conventional zones, including the Lower Skinner, Redfork Sand and Mississippi Lime/Chat, in line with the pre-drill geological model. However, high salt water saturation levels and the high costs associated with the disposal of the salt water, led to the decision to plug rather than complete the well and to cap the total cost of operations.

Direct operating expenses during the year totalled US$2,784,769 (2014: US$2,784,759). US$1,547,313 (2014: US$1,298,759) of this total is a non-cash item covering depreciation costs. A further US$990,854 (2014: US$794,903) was due to lease operating expenses, while production tax and marketing fees came in at US$246,602 (2014: US$309,161).

During the year, US$1.5 million (£1 million) was raised via a placing to fund new drilling operated by a number of leading operators including Chesapeake Energy, Continental Resources and BP America. As a result, 142,857,143 new ordinary shares in the Company were issued.

In June 2015, we appointed Mr. Thomas Wagenhofer to the Board as a Non-Executive Director. Mr. Wagenhofer, who is a highly respected petroleum engineer and oil and gas investment specialist with over 20 years’ experience in the global E&P sector, has elected to receive the majority of his annual fee in new ordinary shares of the Company. Accordingly a further 3,285,713 new ordinary shares were issued to Mr. Wagenhofer upon taking a position on the Board and a further 857,142 shares were issued in January 2016 in settlement of his director’s fees.

Post period end, we further bolstered the Board with the appointment of Mr. Leonard Wallace, a highly experienced oil and gas engineer, as a Non-Executive Director of the Company. Mr. Wallace is an experienced management professional specialising in drilling engineering, well construction and rig operation with 50 years’ experience within the oil and gas exploration and production industry.

Outlook

Magnolia’s senior management has been actively involved in the US onshore oil and gas sector for four decades. During this time we have collectively experienced six cyclical downturns of varying degrees of severity. Downturns are followed by upswings and we intend to be at the forefront of the next one. With this in mind over the last twelve months we have taken steps to ensure we can do just that: we have significantly cut costs and reduced debt; high graded our portfolio of interests in producing wells and leases which are economic at current oil prices; and we have bolstered our Board so that it has a complementary skillset covering all aspects of the oil and gas sector. While volatile oil markets have pushed out timelines for all companies, our objective and ambition remain the same: to build a leading US onshore focused oil and gas group. I look forward to providing further updates on our progress. 

Finally, I would like to thank the Board, management team and all our advisers for their hard work over the last twelve months and also to our shareholders for their continued support.

Steven Snead

Chief Executive Officer

24 June 2016

Chief Operations Officer’s Report

The Bakken / Three Forks Sanish Formations, North Dakota

During the twelve months to 31 December 2015, a total of four wells targeting the Bakken and Three Forks Sanish (‘TFS’) formations in North Dakota commenced production, bringing the total number of producing wells in these formations in which Magnolia has an interest to 41. Of the wells reported during the period, two are producing from the Bakken, a reservoir which is estimated to hold 3.65 billion barrels of undiscovered, technically recoverable oil (2013 US Geological Survey). Gross initial production rates for these two wells were:

Gross initial production rates for the two wells which commenced production from the TFS, a separate reservoir lying directly below the Bakken which is estimated to hold as much as 3.73 billion barrels of recoverable oil (2013 US Geological Survey), were as follows:

Boepd: Barrels of oil equivalent per day

Bopd: Barrels of oil per day 

As at 1 January 2016, Moyes & Co. (‘Moyes’) estimated Magnolia’s Bakken Proven Developed Reserves (‘PDP’) at 49,000 barrels of oil and condensate and 24MMcf of natural gas to which Moyes assigned a value of US$0.829 million. Meanwhile, Magnolia’s PDP (“proved”) reserves in the TFS formation were estimated at 15,000 barrels of oil and condensate and 9MMcf of natural gas which Moyes has assigned a value of US$0.267 million. 

Mississippi Lime Formation, Oklahoma

The Mississippi Lime is an historic oil and gas system that has been producing at depths ranging from 4,500 to 7,000 feet from several thousand vertical wells for over 50 years. Gross initial production rates for eight producing wells targeting the Mississippi Lime were reported during the twelve month period ending 31 December 2015:

Magnolia holds leases covering approximately 5,500 net mineral acres in the Mississippi Lime. The acreage includes leases with working interests of up to 100%. In a Reserves Report dated 1 January 2016, Moyes estimated the Group’s Mississippi Lime PDP reserves at 61,000 barrels of oil and condensate and 139MMcf of natural gas with a value of US$1.414 million.

Woodford Formation, Oklahoma

The Woodford lies below and is the source rock to the Mississippi Lime formation in Oklahoma. As a result much of Magnolia’s leases in Oklahoma are prospective for both the Woodford and the Mississippi Lime. During 2015, Magnolia reported gross initial production rates for the following eight wells:

In the updated Reserves Report dated 1 January 2016, Moyes estimated the Group’s Woodford PDP reserves at 8,000 barrels of oil and condensate and 125MMcf of natural gas with a value of US$0.299 million. As the Woodford is at an earlier stage of development compared to the Mississippi Lime, the Reserves Report does not fully reflect the potential of the formation. This is expected to change as more wells are drilled to the Woodford.

Other Formations in Oklahoma

During the period, four wells in which Magnolia has an interest commenced production from other formations in Oklahoma, the details of which are as follows:

In the updated Reserves Report dated 1 January 2016, Moyes estimated the Group’s PDP reserves in other formations in Oklahoma at 6,000 barrels of oil and condensate and 20MMcf of natural gas with a value of US$0.93 million.

Summary

During the year under review, the Group elected to participate in 38 new wells in proven US onshore formations in which Magnolia has an interest. The decision to participate in the drilling of these wells was only taken after they demonstrated attractive economics when modelled at oil prices at or below current levels. This in turn highlights the quality and low break-even cost of Magnolia’s existing acreage. Management is actively taking advantage of the prevailing oil price environment to further high grade Magnolia’s portfolio of producing wells and leases. Combined with a comprehensive review of corporate overheads and operating costs, the Group is well placed to emerge from the current downturn with an excellent revenue generative and reserves backed platform which we will use to take the business forward.

Rita Whittington

Chief Operations Officer

24 June 2016

consolidated Statement of Comprehensive Income

Year ended 31 December 2015

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 $203,635 (2014: $315,229).

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 31 December 2015

These Financial Statements were approved by the Board of Directors on 24 June 2016 and were signed on its behalf by:

Thomas Wagenhofer

Director

Company STATEMENT OF FINANCIAL POSITION

As at 31 December 2015

These Financial Statements were approved by the Board of Directors on 24 June 2016 and were signed on its behalf by:

Thomas Wagenhofer

Director

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

Year ended 31 December 2015

COMPANY STATEMENT OF CHANGES IN EQUITY

Year ended 31 December 2015

CONSOLIDATED STATEMENT OF CASH FLOWS

Year ended 31 December 2015

COMPANY Statement of Cash Flows

Year ended 31 December 2015

NOTES TO THE FINANCIAL STATEMENTS

Year ended 31 December 2015

1 GENERAL INFORMATION

The Consolidated Financial Statements of Magnolia Petroleum plc (“the Company”) consists 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 of the London Stock Exchange and incorporated and domiciled in England and Wales. Its registered office address is Suite 321, 19-21 Crawford Street, London, W1H 1PJ.

2 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.

2.1 Basis of preparation of Financial Statements

The consolidated Financial Statements of Magnolia Petroleum plc have been prepared in accordance with International Financial Reporting Standards (IFRS) and IFRIC interpretations (IFRS IC) as adopted by the European Union and 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.

2.2 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 2015.

Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated 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. had 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 inter-company transactions and balances between Group entities are eliminated on consolidation.

2.3 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 23 to the Financial Statements disclose the Group’s and Company’s objectives, policies and processes for managing financial risks and capital.

At the year end the Group was in discussion with Bank SNB, the lenders of the Group’s $6 million revolving credit facility, with regards to agreeing certain waivers of, and amendments to, the Group’s facility due to non-compliance at that date of financial and other covenants. Discussions also included an extension to the facility’s maturity date that was originally due to end on 7 September 2016. At 31 December 2015 the Group’s borrowings under the facility amounted to $3,154,784 and Bank SNB agreed to the following:

On 20 April 2016, as a result of the lower oil prices during the year to 31 December 2015 and receipt of the Group’s updated reserves report, the borrowing base limit under the Group’s revolving credit facility was formally reduced from $3,284,210 to $1,604,565.

On 1 June 2016, the Group and Bank SNB, effective 31 December 2015, signed and executed an agreement to extend the maturity date for the borrowing base element from 7 September 2016 to 7 March 2017. A $400,000 principal payment reduction in 2016 leaves a current principal balance of $2,754,784 of which $1,150,219 will be repaid in equal monthly instalments over a 5 year period. The borrowing base limit liability of $1,604,565 is due for repayment in full on 7 March 2017, however the Directors are confident that this will be further deferred based upon the value of its proven development producing properties. The decision to extend is however at Bank SNB’s discretion.

With the exception of the Current Ratio covenant, which has been waived until further notice by Bank SNB, all covenants were satisfied. Funding future growth will however be via the Group’s own generated cash-flow, wherever possible. The Group’s cash flow forecasts and projections prepared up to 30 June 2017 show that the Group has sufficient funds and facilities to fund its ongoing operating costs and the scheduled principal repayments plus interest of the borrowings in excess of the borrowing base of £1,150,219. Additional funds will be required if Bank SNB require repayment of the borrowing base liability on 7 March 2017. 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.

REPORT OF THE INDEPENDENT AUDITOR

Emphasis of matter – going concern

In forming our opinion on the Financial Statements, which is not modified, we have considered the adequacy of the disclosure made in note 2.3 to the Financial Statements concerning the Group and Company’s ability to continue as a going concern. The Group incurred a net loss of £9,793,276 during the year ended 31 December 2015 and, at that date, the Group’s had net current liabilities of $53,964. These conditions, along with the other matters explained in note 2.3 to the Financial Statements, indicate the existence of a material uncertainty which may cast significant doubt on the Group and Company’s ability to continue as a going concern. The Financial Statements do not include the adjustments that would result if the Group and Company were unable to continue as a going concern .

2.4 Changes in accounting policy and disclosure

a) New and amended standards adopted by the Group

There were no IFRSs or IFRIC interpretations that were effective for the first time for the financial year beginning 1 January 2015 that had a material impact on the Group or Company.

b) New and amended standards and interpretations issued but not yet effective or endorsed and not early adopted

The standards and interpretations that are relevant to the Group and Company, issued, but not yet effective, up to the date of issuance of the Financial Statements are listed below. The Group and Company intends to adopt these standards, if applicable, when they become effective. Unless stated below, there are no IFRSs or IFRIC interpretations that are not yet effective that would be expected to have a material impact on the Group and Company.

*Subject to EU endorsement

2.5 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. Other income is recognised in the accounting period in which the services are rendered, in accordance with the terms of the underlying contractual agreements.

2.6 Foreign Currency Translation

(a) Functional and presentation currency

Items included in each of 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 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 the statement of comprehensive income.

(c) Group companies

The results and financial position of all the Group entities that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

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 Statement of Comprehensive Income as part of the gain or loss on sale.

2.7 Property, plant and equipment

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 ‘producing properties’ 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 the Statement of Comprehensive Income.

The net book values of ‘producing properties’ 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 ‘drilling costs and equipment’ 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 the Income Statement.

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 Group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the Statement of Comprehensive Income during the financial period in which they are incurred.

Depreciation is charged so as to allocate the cost of assets, over their estimated useful lives, on a straight line basis as follows:

Drilling costs and equipment – 10 years

Motor vehicles and office equipment – 4 years

Oil and gas producing properties 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 the Income Statement.

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 property, plant and equipment asset 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 non-current asset.

2.8 Intangible assets

a. Goodwill

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.

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.

b. Drilling costs and mineral leases

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 the Statement of Comprehensive Income.

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 mineral leases 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 drilling costs. Drilling costs are initially capitalised on a well by well basis until the success or otherwise has been established. 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. Drilling costs are subsequently transferred into ‘Drilling costs and equipment’ within property, plant and equipment and depreciated over their estimated useful economic life. 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 to the Statement of Comprehensive Income.

Impairment of Non-Financial Assets

Assets not ready for use are not subject to amortisation and are tested annually for impairment. Assets that are subject to amortisation or depreciation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units). Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

2.9 Financial assets

Classification

Financial assets are recognised when the Group becomes a party to the contractual provisions of the instrument. At initial recognition, the Group classifies its financial assets as loans and receivables which comprise ‘trade and other receivables’ and ‘cash and cash equivalents’.

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than 12 months after the end of the reporting period.

Recognition and measurement

Loans and receivables are initially recognised at the amount expected to be received, less where material, a discount to reduce the loans and receivables to fair value. Subsequently, loans and receivables are measured at amortised cost using the effective interest method less a provision for impairment.

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.

Impairment of financial assets

At each Statement of Financial Position 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 amortised cost) with similar risk characteristics. When a subsequent event causes the amount of impairment loss to decrease, the impairment loss is reversed through the Income Statement.

2.10 Trade and other receivables

Trade and other 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.

2.11 Cash and cash equivalents

Cash and cash equivalents comprise cash at bank and in hand and demand deposits with banks.

2.12 Trade and other payables

Trade and other payables are initially measured at fair value and are subsequently measured at amortised cost using the effective interest method.

2.13 Borrowings

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the Income Statement over the period of the borrowings, using the effective interest method.

Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the end of the reporting period.

2.14 Borrowing costs

Borrowing costs are recognised in the Income Statement in the period in which they are incurred.

2.15 Share capital

Ordinary 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.

2.16 Share based payment

The Group operates equity-settled, share-based compensation plans under which the entity receives services from employees and suppliers as consideration for equity instruments (options and warrants) of the Company. The fair value of the services received in exchange for the grant of options and 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 options and warrants granted using the Black-Scholes pricing model. When the options are exercised, the Company issues new shares. The proceeds received, net of any directly attributable transaction costs, are credited to share capital (nominal value) and share premium.

2.17 Taxation

The tax expense or credit comprises current and deferred tax. It is calculated using tax rates that have been enacted or substantively enacted by the Statement of Financial Position 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.

2.18 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 the Income Statement on a straight-line basis over the period of the lease.

2.19 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.

2.20 Pension Obligations

The Group makes contributions to defined contribution pension plans. The Group has no legal or constructive obligations to pay further contributions if the plans do not hold sufficient assets to pay all employees the benefits relating to employee service in the current or prior periods. The contributions are recognised as employee benefit expense when they are paid.

2.21 Exceptional items

Exceptional items are disclosed separately in the Financial Statements where it is necessary to do so to provide further understanding of the financial performance of the Group. They are material items of income or expense that have been shown separately due to the significance of their nature or amount.

3 FINANCIAL RISK MANAGEMENT

The Group’s activities expose it to a variety of financial risks: market risk (including currency risk and cash flow and interest rate 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.

a) Currency 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.

b) Cash flow and interest rate risk

The Group’s interest rate risk arises from long-term borrowings. Borrowings issued at variable rates expose the Group to cash flow interest rate risk, which is partially offset by cash held at variable rates. During 2015, the Group’s borrowings at variable rates were denominated in US dollars.

At 31 December 2015, if variable interest rates on borrowings are 10 basis points higher/lower with all other variables held constant, the annual interest expense will be $145,120 higher / $138,810 lower.

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. 

Where the Group is not an operator of wells, 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

Cash flow forecasting is performed in the operating entities of the Group, and aggregated by Group Finance. Group Finance monitors rolling forecasts of the Group’s liquidity requirements to ensure it has sufficient cash to meet operational needs, while seeking to maintain sufficient headroom on its undrawn committed borrowing facilities (Note 19) at all times, so that the Group does not breach borrowing limits or covenants (where applicable) on any of its borrowing facilities. Such forecasting takes into consideration the Group’s debt financing plans, covenant compliance, compliance with internal Statement of Financial Position ratio targets, and, if applicable, external regulatory or legal requirements (for example, currency restrictions).

The table below analyses the Group’s non-derivative financial liabilities and net-settled derivative financial liabilities into relevant maturity groupings, based on the remaining period at the Statement of Financial Position to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows.

4 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.

Estimated impairment of producing properties and capitalised drilling costs & equipment

At 31 December 2015, mineral leases and capitalised drilling costs & equipment on producing properties have a total carrying value of $7,288,003 (2014: $11,285,037) (Note 13). Management tests annually whether the assets have future economic value in accordance with the accounting policies. These assets are also subject to an annual impairment review by an independent consultant.

The recoverable amount of each property has been determined based on a value in use calculation which requires the use of certain estimates and assumptions such as long term commodity prices (i.e. oil and gas prices), discount rates, operating costs, future capital requirements and mineral resource estimates. These estimates and assumptions are subject to risk and uncertainty and therefore a possibility that changes in circumstances will impact the recoverable amount.

In assessing the carrying amounts of its producing properties and related drilling and equipment costs, the Directors have used an updated reserves report (“The Report”) and have concluded that an impairment charge of $3,538,523 should be recognised to write down the value of the assets. The Report has identified certain wells to be non-economic, based on the current and projected oil and gas prices.

Recoverability of non-producing mineral leases and capitalised drilling costs & equipment

Mineral leases and drilling costs on non-producing properties have a carrying value at 31 December 2015 of $1,490,520 (2014: $6,122,650). Management tests annually whether non-producing mineral leases have future economic value in accordance with the accounting policy stated in Note 2.8. 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 an impairment charge of $4,973,181 should be recognised.

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 2015 of $340,253 (2014: $359,222). The Group tests annually whether goodwill has suffered any impairment in accordance with the accounting policy stated in Note 2.8. 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 producing properties, the Group’s considerations include the lease period of the agreement, estimated levels of proven and probable reserves and the estimated future cost of developing and extracting those reserves. Management review property, plant and equipment at each Statement of Financial Position 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. The Directors have reviewed the estimated value of each property and do not consider any further impairment to be necessary.

5 SEGMENTAL INFORMATION

The Executive Directors are the Group’s chief operating decision-makers.

The Group operates in two geographical areas, the United Kingdom and the United States of America. Activities in the UK are mainly administrative in nature whilst the activities in the USA relate to exploration and production from oil and gas wells. The reports reviewed by the Board of Directors that are used to make strategic decisions are based on these geographical segments.

A reconciliation of the operating loss to loss before taxation is provided as follows:

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:

Information about major customers/operating partners

In the year ended 31 December 2015 revenues of $586,842 and $401,168 are derived from two operators. These revenues were all generated in the USA.

In the year ended 31 December 2014 revenues of $834,903 and $663,105 are derived from two operators. These revenues were all generated in the USA.

6 EXPENSES BY NATURE

7 AUDITOR REMUNERATION

Services provided by the Company’s auditor and its associates

During the year, the Group (including its overseas subsidiaries) obtained the following services from the Company’s auditor:

8 STAFF COSTS

The Group and Company incurred the following staff costs (including Directors):

Directors’ Emoluments

The Directors’ emoluments in respect of qualifying services were:

The average monthly number of staff, including the Directors, during the financial year was as follows:

9 OTHER INCOME

10 INCOME TAX

Tax charge for the period

The tax charge for the year is $Nil (2014: $Nil).

Factors affecting the tax charge for the period

The tax charge for each year is explained below:

The Group has UK tax losses of approximately $1,284,000 (2014: $1,205,000) and US tax losses of approximately $9,146,000 (2014: losses of approximately $8,280,000) available to carry forward against future taxable profits. A potential deferred tax asset of approximately $260,000 (2014: $241,000) on the UK losses and $3,659,000 (2014: $3,312,000) 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.

11 FINANCE INCOME AND FINANCE COSTS

12 EARNINGS PER SHARE

The calculation of earnings per share of loss of 0.98 cents per share (2014 profit per share: 0.19 cents) is calculated by dividing the loss attributable to ordinary shareholders of $9,793,276 (2014 profit: $1,693,012) by the weighted average number of ordinary shares of 995,081,516 (2014: 910,672,851) in issue during the period.

In accordance with IAS 33, there is no difference between the basic and diluted earnings per share.

Details of share options and warrants that could potentially dilute earnings per share in future periods are set out in Note 18. None of the share options and warrants were dilutive as at 31 December 2015.

13 PROPERTY, PLANT AND EQUIPMENT

Group

Transfers from intangible assets represent licence areas where production has commenced together with drilling costs associated with these licences.

Producing properties and drilling costs depreciation expense of $1,547,313 (2014: $1,298,759) has been charged in cost of sales.

Motor vehicles and office equipment depreciation expense of $5,927 (2014: $5,037) has been charged in administrative expenses.

14 INTANGIBLE ASSETS

Drilling costs and mineral leases represent acquired intangible assets with an indefinite useful life and are tested annually for impairment. 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.

Impairment review – Property, plant and equipment and Intangible assets

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.

- The Group has disposed of the licence in 2016 therefore the asset has been written down to net realisable value.

Following their assessment the Directors recognised an impairment charge totalling US$8,511,704 for the year ended 31 December 2015 (2014: $249,232). This is comprised of write-downs associated with the cost of mineral leases which have expired and a markdown in the value of its interests in producing properties identified as non-economic at today’s low oil prices. Management expects the value of its interests in producing wells to be written back, either in part or in full, as and when the oil price recovers.

The Directors believe that no impairment is necessary on the carrying value of goodwill. Goodwill arose on the reverse acquisition of Magnolia Petroleum Plc. The goodwill represents the value of the parent company being an AIM listed entity to Magnolia Petroleum Inc.

15 INVESTMENTS

Investments in subsidiaries

Investments in group undertakings are recorded at cost, which is the fair value of the consideration paid.

Principal subsidiaries

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. 

16 TRADE AND OTHER RECEIVABLES

Trade receivables comprise customer receivables. Trade receivables are neither past due nor impaired and relate to existing customers with no defaults in the past. The Group retains all risks associated with these receivables until fully recovered.

The fair value of all receivables is the same as their carrying values stated above.

As at 31 December 2015, trade receivables of $254,461 (2014: $311,105) were fully performing.

Group

The carrying amounts of the Group’s trade and other receivables are denominated in the following currencies:

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.

Company

The carrying amounts of the Company’s trade and other receivables are denominated in UK pound sterling.

17 CASH AND CASH EQUIVALENTS

At 31 December 2015, the Group held cash of $44,210 (2014: $3,661) in a bank with a Fitch credit rating of A (Stable) and $601,549 (2014: $430,087) in a bank where no Fitch credit rating is available.

18 SHARE CAPITAL AND PREMIUM

Each ordinary share has a nominal value of 0.1 pence per share.

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:

The options and warrants are exercisable starting immediately from the date of grant other than those expiring on 24 January 2017, which were exercisable from 24 January 2014. The Company and Group have no legal or constructive obligation to settle or repurchase the warrants or options in cash.

A reconciliation of options granted and lapsed during the year ended 31 December 2015 is shown below.

The warrants and options outstanding at 31 December 2015 had a weighted average remaining contractual life of 3.2 years (2014: 4.2 years).

No options or warrants were exercised, granted or cancelled during the year.

19 BORROWINGS

As at 31 December 2015 the Group had a $6 million revolving credit facility with, subject to certain conditions being met, a maturity date of 7 March 2017 (originally 7 September 2016). The borrowing base is reassessed on a six monthly basis and adjusted in line with the level of the Group’s proven developed producing reserves. Interest is charged on credit drawn down at the Wall Street Journal Prime rate (currently 3.25%) +0.75%. The credit facility is secured against the producing leases and operating equipment owned by the Group, together with sales contracts and farm-out agreements. Note 2.3 provides details of amendments to the terms of the revolving credit facility subsequent to the year end.

The fair value of borrowings equals their carrying amount. All borrowings are denominated in US dollars. The Group has the following undrawn borrowing facilities:

20 TRADE AND OTHER PAYABLES

21 FINANCIAL INSTRUMENTS BY CATEGORY

22 TREASURY POLICY

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 Group has financed its activities by raising funds through the placing of shares and through bank borrowings set out in Note 19 above. There are no material differences between the book value and fair value of the financial assets.

23 CAPITAL MANAGEMENT POLICIES

The Group and Company’s capital management objectives are:

In order to maintain or adjust the capital structure, the Group may issue new shares or sell assets to reduce debts.

The current $6 million revolving credit facility maturity date (see Note 19) has subsequent to the year-end been extended from 7 September 2016 to 7 March 2017. The Group will start making principal reduction payments, along with interest payments in accordance with financial and non-financial loan covenants.

24 CAPITAL COMMITMENTS

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.

As at 31 December 2015 or 2014 the Group had no capital commitments for drilling and equipment costs contracted but not provided for.

25 RELATED PARTY TRANSACTIONS

Transactions with Group undertakings

During the year ended 31 December 2015 the Company charged management fees of $43,504 (2014: $123,780) to Magnolia Petroleum Inc, the Company’s wholly owned subsidiary for the provision of administrative and management services. $43,504 (2014: $123,780) in relation to these fees was outstanding at the year end date and is included within Trade and other receivables. As at 31 December 2015, the amount due to the Company from Magnolia Petroleum Inc was $12,654,385 (2014: $12,076,229).

All Group transactions were eliminated on consolidation.

Transactions with Enerlex Inc

Steven Snead and his wife have a 100% interest in the issued share capital of Enerlex Inc. (“Enerlex”). The rental agreement between Enerlex and Magnolia Petroleum Inc was revised on 30 September 2014 whereby Enerlex agreed to provide Magnolia Petroleum Inc on a month to month basis with office premises and services for $3,500 per month. A charge of $42,000 (2014: $33,000) was recognised during the year under the former and revised agreement. Subsequently, a reduced rate of $2,500 per month was agreed on effective February 2016 until further notice.

Enerlex gave an undertaking to Magnolia Petroleum Inc dated 15 November 2011 whereby Enerlex undertakes that if any of the mineral 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.

Transaction with Thomas Wagenhofer

Thomas Wagenhofer was appointed to the Board as a Non-Executive Director on 29 June 2015. Mr. Wagenhofer has elected to receive the majority of his annual fee in new ordinary shares of the Company. On 30 June 2015, 428,571 and 2,857,142 new ordinary shares of 0.1 pence per share were issued to Mr. Wagenhofer, in settlement of his fees due of £3,000 and his initial joining fee of £20,000, respectively.

26 ULTIMATE CONTROLLING PARTY

As at the Statement of Financial Position date, the Directors do not consider there is an ultimate controlling party.

27 EVENTS AFTER THE REPORTING PERIOD

On 12 January 2016 a further 428,571 ordinary shares of 0.1 pence per share were issued to Mr. Wagenhofer, in settlement of his fees due of £3,000.

On 15 February 2016 the Company raised £300,000 (gross) through the issue of 214,285,714 ordinary shares at a price of 0.14 pence per share.

On 13 April 2016 Bank SNB formally signed and executed a waiver and consent letter allowing the Group to be in breach of certain financial covenants from 1 July 2015 onwards and until further written notice is provided by Bank SNB.

On 20 April 2016, as a result of the lower oil prices during the year to 31 December 2015 and receipt of the Group’s updated reserves report, the borrowing base limit under the Group’s revolving credit facility was decreased from $3,284,210 to $1,604,565.

On 22 April 2016 the Company issued 4,500,000 new ordinary shares, at a price of 0.2 pence per share, to the Directors of the Company: Steven Snead; Rita Whittington; and Ronald Harwood, in settlement of their fees for the period from 1 January 2016 to 31 March 2016.

On the same date, the Company also cancelled certain existing share options and granted a further 84,677,737 new share options to staff and Directors. The details relating to Directors are as follows:

On 1 June 2016, the Group and Bank SNB, effective 31 December 2015, signed and executed an agreement to extend the maturity date for the borrowing base element from 7 September 2016 to 7 March 2017. A $400,000 principal payment reduction in 2016 leaves a current principal balance of $2,754,784 of which $1,150,219 will be repaid in equal instalments over a 5 year period. Interest payments will be made monthly on the balance of $1,604,565.

NOTICE OF AGM AND POSTING OF ANNUAL REPORT

Notice is given that the Annual General Meeting of Magnolia Petroleum plc will be held at 10.00am on 22 July 2016 at 18452 E 111th, Broken Arrow, Oklahoma, OK 74011. The Company's Annual Report, together with a Notice of Annual General Meeting will be sent to shareholders shortly which will also be available on the Company's website http://www.magnoliapetroleum.com/.

ENDS

For further information on Magnolia Petroleum Plc visit www.magnoliapetroleum.com or contact the following: