AOGL.L Regulatory News (AOGL)

Northcote Energy Ltd / Index: AIM / Epic: NCT / ISIN: VGG6622A1057 / Sector: Oil & Gas

30 June 2014

Northcote Energy Ltd ('Northcote' or 'the Company')

Final Results

Northcote (AIM: NCT) is pleased to provide its final results for the year ended 31 December 2013. In addition, the Company gives notice that its Annual General Meeting (`AGM') will be held at 10.00am on Thursday 10 July 2014 at the offices of Kerman & Co LLP, 200 Strand, London, WC2R 1DJ. The Notice of AGM will be posted to shareholders and will be available on the Company's website today at www.northcoteenergy.com, where the full Report and Accounts for the period under review can also be found.

Highlights

Year under review:

· Multiple milestones met towards delivering long term success in the onshore US oil and gas industry.

o Increased acreage to over 5,000 net acres during the period;

o 2013 Northcote grew through low cost land acquisitions, expanding and diversifying the inventory of scalable development opportunities;

o Ideally positions Northcote for near, mid and long term production, revenues and reserves growth; and

o Current reserves of 2.49 million BOE.

· Operator status in Osage County gained across three of eight core properties - enables Northcote to control capital expenditure and rapidly take advantage of value accretive opportunities

· Production increased to 100BOEPD ahead of schedule with 2013 and 2014 operational initiatives underway to deliver 250BOEPD

Post period end:

· Commenced a continuous and diverse work programme across Osage County portfolio post period end, including low cost recompletions/ workovers, new wells

· Focussed on increasing daily production levels, to achieve sustainable cash flow generation from operations over forthcoming 12 months and broadening available funding options

Northcote Chairman Ross Warner said, "In Northcote's first year of listing, the management team have increased revenues and reduced the importance of single wells in its portfolio through accretive acquisitions and field development, improved field level margins on various of its assets through farm-out and operational gains which have also enabled it to recycle capital, and added additional potential upside in existing and new projects.

Northcote has a dynamic and enterprising management team and it is now primed for growth. In the coming year we expect to deliver significant growth in the Company's value which we believe should be reflected in our share price."

NORTHCOTE ENERGY LIMITED

CHAIRMAN'S STATEMENT

Northcote has transformed its revenues and asset base in the period under review. This activity has established a strong platform for growth and we expect to deliver significant gains across a number of measures in the forthcoming year.

Northcote's strategy is simple:

• Deliver revenue growth through a combination of asset acquisitions and field development;

• Improve operating margins by operating its assets and farming out interests on promoted terms; and

• Access additional non-dilutive capital through commercial bank debt.

Northcote has acquired a number of assets since listing. We believe each of these assets has significant undeveloped potential but each was purchased at a price which reflected the estimated present value of future cash flows from existing proven and producing reserves. This represents a cheap option on the undeveloped potential. As a consequence of these acquisitions, we have grown reserves and revenues, acquired a significant inventory of development opportunities and the Company's revenues are now generated from a large number of wells across a number of projects and States.

Whilst we will continue to review acquisition opportunities in the coming year, the Company has entered into a new phase of its development and we expect a greater contribution to revenue growth to come from field development. The field development programme will continue to include workovers and recompletions but will also include a new well drilling programme. We have a large inventory of drilling opportunities ranging from US$200,000 low risk shallower opportunities to US$5 million high impact deeper opportunities. This inventory will provide significant opportunities which Northcote can scale to fit its capital expenditure capacity for many years to come.

Northcote has entered into a number of farm-out arrangements in the period under review. The Company seeks to farm out on promoted terms which have the net effect of improving our operating margins on these assets. The full year benefits of the current initiatives will be seen in subsequent accounts. These arrangements enable us to allocate and recycle capital and we will continue to undertake this activity in the coming year.

The Company has increased its capacity to operate assets in the period under review and will continue to do so in the forthcoming year. Northcote seeks to control its assets by either operating or owning a majority interest in them. This enables the Company to control the pace of development and schedule its capital commitments to reflect its capital expenditure capacity. In addition, operating the asset improves operating margins as it enables us to re-charge a proportion of the operating costs to non-operated interests. This initiative has had short term cost implications. However, from this point on, the Company's operating capacity will be a key component in generating future revenues and controlling costs.

The reported loss for the year of $3,755,000 reflects the high level of acquisition activity and the costs associated with the listing. The adjusted EBITDA loss of $1,769,000, removing certain non-recurring costs, is further detailed in the financial report. We expect substantial improvements in 2014 as we move from the acquisition to development phase and towards a sustainable E&P business through the development of Zink Ranch and our other properties, which are being funded through the issue in 2014 of the convertible loan notes, farm-outs and internally generated cash flows.

In summary, in the period under review Northcote has increased revenues and reduced the importance of single wells in its portfolio through accretive acquisitions and field development, improved field level margins on various of its assets through farm-out and operational gains which have also enabled it to recycle capital, and added additional potential upside in existing and new projects.

Northcote has a dynamic and enterprising management team and it is now primed for growth. In the coming year we expect to deliver significant growth in the Company's value which we believe should be reflected in our share price.

Ross Warner

Executive Chairman

27 June 2014

NORTHCOTE ENERGY LIMITED

CHIEF EXECUTIVE'S REPORT

Northcote Energy is focused on building a U.S. onshore focused oil and gas company with a portfolio of projects that provides a strong base of production and includes an inventory of multiple development opportunities that will support production and reserves growth in the near and intermediate term.

Underpinning Northcote's strategy is our fundamental belief that having a full set of operating capabilities is essential to achieving long term success in the onshore U.S. oil and gas industry. As a small E&P company, it is critical to model our business so that we may gain control over timings of major expenditures, minimise costs in the long term and position ourselves so that we may take advantage of opportunities to generate incremental revenues. During 2013 Northcote was aggressive in implementing this business model.

To this end the Company achieved its objective of securing 5,000 net acres of oil and gas leases, mostly concentrated in our core area of Osage County, Oklahoma and the neighbouring Kay County, Oklahoma. Northcote now has an interest in eight properties in a range of US states, with its core assets, namely Zink Ranch, Horizon, Mathis, East Blackwell and OKE (Libby and Tinker), lying in Oklahoma. This portfolio has provided the Company with a deep project inventory ranging from low cost workover opportunities to add profitable, if modest, production to high impact drilling opportunities that will provide production growth for several years. This therefore positively impacts their payback credentials.

Additionally, the portfolio that we have assembled has allowed us to take steps toward implementation of our operating business model. At the year end the Company was operating three of its eight leases and intends to transition others in-house over time. Northcote has the capabilities through its experienced team to confidently operate oil and gas properties in our core area.

We are pleased with what has been accomplished during our first year as a listed company. We hit our production target of 100BOEPD ahead of schedule, demonstrating our ability to deliver on our objectives, increased our reserves to where they currently stand at 2.49 million BOE, and gained critical mass through the acquisition of quality projects, which is key when building a long term production position in the US. Our achievements also include increasing the efficiency and production profile of a number of wells across our Osage County portfolio through the completion of low cost, high impact workover programmes.

We also recognise that we have a lot of work to do and acknowledge that not everything went to plan in 2013. Our fracture stimulation programme on the Horizon leases met with mixed results on the first three fracture stimulations. We are relatively happy with the last of the three wells, West Little Drum, but given the disappointing results over the six months following stimulation of the first two, we chose to observe the West Little Drum well and not rush into additional capital projects of this nature until we were satisfied that we would realise a positive return on your investment capital.

The completion of the fracture stimulation programme is still very much a part of Northcote's long term development campaign and we will include the stimulation of these wells into a broader, more diverse programme on an opportunistic basis.

The OKE project (Libby & Tinker leases) which was our first acquisition on listing, continues to have excellent long term development potential. We acquired this property intending to explore vertical Mississippian potential which we still believe to be attractive for future development. We accelerated several infrastructure related projects on the property in the fall of 2013 both to support long term development in an efficient manner, but also to ensure that our properties were operated in a manner that is environmentally responsible and not at risk of oil or salt water spills, which could be both environmentally and financially damaging.

The Company also made three relatively small acquisitions during the year, two of which, Mathis and East Blackwell, are expected to become important properties for future drilling and exploitation. The third was a non-operated interest in a south Texas gas field, South Weslaco Gas Unit, which has become a solid financial contributor, should generate an attractive and low risk return for the Company and offers considerable upside should natural gas prices increase in coming years as some observers and the Company believes is likely.

The capstone transaction for 2013 was the Zink Ranch property which has become the centrepiece for our 2014 work programme and will receive the largest portion of our effort and capital in 2014 and, quite possibly, in 2015. When evaluating an oil and gas property, Northcote looks at a number of aspects including historical and current production; unexploited potential in existing well bores; opportunity for drilling of additional well bores; economic terms of the leases and potential secondary recovery (water flood) opportunities. A property does not necessarily have to be ideal on all of these (and other) criteria to be attractive. Indeed, finding a property that does meet all or nearly all of our criteria is a rare find. We found Zink Ranch at a time when our share price was already under pressure and had to re-enter the market to close this transaction at a time and in a manner that we would have preferred to avoid. That said, Northcote continues to believe that the Zink Ranch property is such an inherently attractive oil and gas development opportunity that, if we had it to do over, we would make the same decision today .

Subsequent to year-end we, along with other industry partners, announced an acquisition whereby Northcote will initially acquire a 70.0% working interest in the Shoats Creek project, Louisiana from Aminex plc, of which we plan to farm-out 50% of our interest (35%) to North American Petroleum. The transaction includes a modest share component and a production payment providing for a payment of $10.00 per barrel of oil production from Shoats Creek up to a maximum of $4.5 million for the 100% interest. We are very excited about Shoats Creek, which has considerable upside potential from new drill opportunities in multiple objectives including the Frio, Cockfield and Wilcox formations and anticipate this becoming a substantial part of our 2015 development plans.

Outlook

2014 will be the first year that we are able to demonstrate that the Company we assembled in 2013, both in terms of projects and leases as well as operational capabilities, was well planned. This is Northcote's focus in 2014 and likely, well into 2015. With the inventory of projects that the Company has, we can continuously create value across a range of projects that offers diversification at the geographical, target formation, risk and expenditure levels.

The organisation that we built in 2013 has coalesced into a team with each person understanding their role and how that fits into the big picture of what we are trying to achieve for our shareholders, as well as building a company that will be recognised within the industry as a smart and capable operator. We worked hard in 2013 to build out both our team as well as our leases. We did this because we believe that it is a capable and focused team working hard to exploit an attractive set of properties that will create long term value for our shareholders.

In March 2014, Northcote commenced a continuous work programme which will see a range of initiatives phased through the year. The campaign will include:

• The drilling of 4 to 5 new wells;

• The workover or recompletion of up to 31 existing well bores; and

• The fracture stimulation of 2 to 3 existing horizontal wells (the fourth 2013 frack has been incorporated into the 2014 schedule.)

The 2014 work programme is the first continuous programme that Northcote has executed, highlighting its evolution since listing in 2013. On reaching our 100BOEPD target, we set a new one of reaching 250 BOEPD by 31 July 2014. The ongoing work programme features extensive development on our Zink Ranch property, which is focused on both re-entry of existing well bores and new drill opportunities. Additionally the programme will focus on infrastructure upgrades and exploitation opportunities at the OKE properties (Libby & Tinker leases); Mathis and East Blackwell projects. We remain confident that the items in the programme critical to achieving 250 BOEPD will have been completed prior to end of July 2014 with substantial work and potential production additions remaining as we move into fall 2014.

The continuous pace of development, facilitated by having a large, synergistic land position across a locality, will allow for improved access to equipment and services and result in more timely execution of projects and cost efficiencies, in line with our stated objectives outlined above.

As 2014 progresses we believe that these efforts will be reflected in our daily production levels; in our financials, by achieving a sustainably cash flow positive position during the course of the year; and by increasing funding options through access to commercial bank finance.

Conclusion

We appreciate our shareholders support in 2013. Certainly the downward share price performance in 2013 was not satisfactory to the Board or to me personally. Northcote however is strong and continues to grow stronger. We believe the work programme underway in 2014 will highlight the strengths we believe are inherent in the Company and we look forward to reporting progress from our efforts.

Randall Connally

Chief Executive Officer

27 June 2014

**ENDS**

For further information visit www.northcoteenergy.com or contact the following:

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

YEAR ENDED 31 DECEMBER 2013

The Statement of Comprehensive Income has been prepared on the basis that all operations are continuing operations.

NORTHCOTE ENERGY LIMITED

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

YEAR ENDED 31 DECEMBER 2013

The Financial Statements were approved and authorised for issue by the Board of Directors on 27 June 2014 and were signed on its behalf by

Daniel Jorgensen

Finance Director 

NORTHCOTE ENERGY LIMITED

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

YEAR ENDED 31 DECEMBER 2013

NORTHCOTE ENERGY LIMITED

CONSOLIDATED CASH FLOW STATEMENT

YEAR ENDED 31 DECEMBER 2013

Major Non Cash Transactions

Details of major non-cash transactions are described in note 18 share capital and note 20 borrowings.

NORTHCOTE ENERGY LIMITED

NOTES TO FINANCIAL STATEMENTS

YEAR ENDED 31 DECEMBER 2013

1. General Information

The principal activity of Northcote Energy Limited ('The Company') during the year was as an Oil & Gas exploration and production business focussed in the United States of America. The Company was incorporated in the British Virgin Islands on 13 May 2010 as a private limited company with the name Everest Energy Limited. As at the year end, the Company was domiciled in the British Virgin Islands and listed on the AIM market of the London Stock Exchange.

2 Summary of significant accounting policies

2.1. Basis of Preparation

The consolidated financial statements are presented in thousands of US Dollars ($'000).

The Consolidated Financial Statements have been prepared under the historical cost convention, as modified for financial assets and financial liabilities (including derivative instruments) at fair value through profit or loss and in accordance with International Financial Reporting Standards (IFRSs) and International Financial Reporting Interpretations Committee (IFRIC) interpretations, as adopted by the EU.

The preparation of the consolidated financial statements in conformity with IFRSs 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 judgements or where estimates and assumptions are significant are disclosed below.

2.2. Basis of Consolidation

The consolidated Financial Statements consolidate the Financial Statements of Northcote Energy Limited and the audited Financial Statements of its subsidiary undertakings made up to 31 December 2013.

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.

On 14 January 2013 the Company acquired 100% of the issued share capital of Northcote Energy Limited, Cayman Islands ("Northcote CI"), a US focussed on-shore oil and gas company. The Company acquired Northcote CI through a share exchange. As the shareholders of Northcote CI had control of the legal parent, Northcote Energy Limited, 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 Northcote CI 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, Northcote Energy Limited, 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.

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.

*An LLC is not a corporation, it is a legal form of company that provides limited liability to Northcote USA Inc, its owner and general manager.

2.3. Changes in accounting policies and disclosure

The EU IFRS financial information has been drawn up on the basis of accounting policies consistent with those applied in the financial statements for the prior year to 31 December 2012, except for the following:

• Amendment to IAS 1, 'Presentation of Financial Statements - Presentation of items of other comprehensive income'

• Amendment to IAS 12', Income taxes' on deferred tax

• IAS 19 (revised 2011), 'Employee Benefits'

• Amendments to IFRS 7, 'Financial instruments: Disclosures' - 'Offsetting Financial Assets and

Financial Liabilities'

• IFRS 13, 'Fair Value Measurement'

• Amendment to IFRS 1 on hyperinflation and fixed dates

• Annual improvements 2009-2011 (IAS 1, IFRS 1, IAS 16, IAS 32, IAS 34)

• IFRIC 20 - Stripping costs in the production phase of a surface mine

The Group has not applied the following pronouncements which are not mandatory for 2013:

Mandatory for accounting periods beginning on or after 1 January 2014 and endorsed by the EU:

• IAS 28 (revised 2011), 'Investments in Associates and Joint Ventures'

• IAS 27 (2011) 'Separate Financial Statements'

• IFRS 10, 'Consolidated Financial Statements'

• IFRS 11, 'Joint Arrangements'

• IFRS 12, 'Disclosures of Interests in Other Entities'

• Amendments to IAS 32 'Financial instruments: Presentation' - 'Offsetting Financial Assets and

Financial Liabilities'

• Transition Guidance (Amendments to IFRS 10, IFRS 11 and IFRS 12)

• Amendment to IAS 36, 'Impairment of assets' on recoverable amount disclosures

• IFRS 14 Regulatory deferral accounts

• IFRIC 21: Levies

• Amendment to IFRS 10, IFRS 12 and IAS 27, 'Investment Entities'

• Amendments to IFRS 1, 'First time adoption - government loans' 

• Amendment to IAS 39 - Novation of derivatives & continuation of hedge accounting

The Directors are in the process of assessing the impact of these standards on the financial statements.

2.4. Going Concern

In forming its opinion as to preparing the financial statements on the going concern basis, the Board prepared a working capital forecast based upon its assumptions as to trading and current available cash resources.

The Board prepared a number of alternative scenarios modelling the business variables and key risks and uncertainties. Based upon these, the Board remains confident that the Group's current cash on hand, current production and future anticipated revenues from the wells to be drilled, recompleted, fracked or worked over under the Group's development programme, will enable the Group to fully finance its future working capital and discretionary expenditures beyond 12 months of the date of this report.

However whilst the Board takes the necessary steps to reduce the key risks associated with oil development activity, there can be no guarantee of the success of future wells; consequently further capital may be required in the event that the Group's expectations are not achieved. The Board believes that, despite the lack of guarantees, the Group will continue in the foreseeable future and therefore continues to adopt the going concern basis for preparing the Financial Statements.

2.5. Operating segments

Operating segments are reported in a manner consistent with the internal reporting provided to the Chief Operating Decision Maker. The Chief Operating Decision Maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive and Non-Executive Directors of the Group that make the strategic decisions.

2.6. Financial instruments

Financial assets and financial liabilities are recognised in the consolidated statement of financial position when the Group becomes party to the contractual provisions of the instrument.

- Borrowings

Borrowings are initially measured at fair value, net of transaction costs and are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period.

The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period.

- Trade and other receivables

Trade and other receivables are recognised initially at fair value and are subsequently measured at amortised cost, reduced by any 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.

Indicators of impairment would include financial difficulties of the debtor, likelihood of the debtor's insolvency, default in payment or a significant deterioration in credit worthiness. Any impairment is recognised in the consolidated statement of comprehensive income within 'Administrative expenses'.

- Loans and receivables

Loans and receivables, comprising trade and other receivables and cash and cash equivalents, are non-derivative financial instruments which have a fixed or easily determinable value. They are recognised at cost, less any provisions for impairment in their value.

- Cash and cash equivalents

Cash and cash equivalents comprise cash in hand and current balances with banks and similar institutions, which are readily convertible to known amounts of cash. Cash equivalents are short-term with an original maturity of less than 3 months.

- 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 rate method if the time value of money is significant.

- Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Company are recorded at the proceeds received net of direct issue costs.

2.7. Equity

Equity comprises the following:

· "Share premium" represents the premium paid on Ordinary Shares issued of no par value

· "Foreign currency translation reserve" includes movements that relate to the retranslation of the subsidiaries whose functional currencies are not the US Dollar.

· "Reverse acquisition reserve" - the reserve is created in respect of the reverse acquisition difference between the equity structure of the legal parent and the acquired entity.

· "Retained earnings" represents retained profits or losses.

The Equity share option reserve has been included within the retained earnings reserve. The reserve relates to the fair value of the share options that have been expensed through the consolidated statement of comprehensive income since adoption of IFRS less amounts, if any, that have been transferred to the retained earnings upon exercise.

2.8. Related Parties

Parties are considered to be related to the Group if the Group has the ability, directly or indirectly, to control the party or exercise significant influence over the party in making financial and operating decisions, or vice versa, or where the Group and the party are subject to common control or common significant influence. Related parties may be individuals (being members of key management personnel, significant shareholders and/or their close family members) or other entities and include entities which are under significant influence of related parties of the Group where those parties are individuals, and post-employment benefit plans which are for the benefit of employees of the Group or of any entity that is a related party of the Group.

2.9. Foreign Currency Translation

· Functional and presentational currency

Items included in the financial statements are measured using the currency of the primary economic environment in which the entity operates ("the functional currency"). The Financial Statements are presented in US Dollars ($). The parent company's functional currency is Pounds Sterling (£) and the subsidiary entities functional currency is US Dollars (US$)

On consolidation of entities with a non US Dollar presentational currency, their statements of financial position are translated into US Dollar at the closing rate and income and expenses at the average monthly rate. Share capital is translated into the presentational currency of the Group ($) using the exchange rate prevailing at the dates of the transactions.

All resulting exchange differences arising in the period are recognised in other comprehensive income, and cumulatively in the Group's translation reserve. Such translation differences are reclassified to profit or loss in the period in which any such foreign operation is disposed of.

· Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions, and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies, are recognised in the Consolidated Statement of Comprehensive Income.

2.10. Share Based Payments

The Group issues equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant. The equity-settled share-based payments are expensed to the consolidated statement of comprehensive income or capitalised to investments or intangibles in the consolidated statement of financial position on a straight line basis over the vesting period based on the Group's estimate of shares that will eventually vest.

Where equity instruments are granted to persons other than employees, the consolidated statement of comprehensive income is charged with the fair value of goods and services received on a straight line basis over the vesting period based on the Group's estimate of shares that will eventually vest, except where it is in respect to costs associated with the issue of securities, in which case it is charged to the share premium account.

2.11. Taxation

Income tax expense represents the sum of the current tax payable and deferred tax. The current tax payable is based on taxable profit for the year. Taxable profit differs from net profit as reported in the consolidated statement of comprehensive income because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Tax is charged or credited in the consolidated statement of comprehensive income, except when it relates to items charged or credited directly to equity or in other comprehensive income, in which case the tax is also dealt with in equity or other comprehensive income respectively. Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax base used in the computation of taxable profit. Deferred tax liabilities are generally 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 from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, 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.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the asset to be recovered. Any such reduction shall be reversed to the extent that it becomes probable that sufficient taxable profit will be available.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset realised based on tax rates and laws substantively enacted by the reporting date. Deferred tax assets and liabilities are offset when there exists a legal and enforceable right to offset and 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.

2.12. Revenue recognition

Sales of hydrocarbons are recognised when the significant risks and rewards of ownership are transferred to the buyer. Other income is recognised on an accruals basis, in accordance with the substance of the relevant agreement.

2.13. Inventories

Inventories comprise produced oil and gas or certain materials and equipment that are acquired for future use. The oil and gas is valued at the lower of average production cost and net realisable value; the materials and equipment inventory is valued at purchase cost. Cost comprises direct materials and, where applicable, direct labour costs plus attributable overheads based on a normal level of activity and other costs associated in bringing the inventories to their present location and condition. Cost is calculated using the weighted average method. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution and any provisions for obsolescence.

2.14. Business combinations

The acquisition of subsidiaries is accounted for using the purchase method. The cost of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed and equity instruments issued by the Group in exchange for control of the acquiree. The acquiree's identifiable assets, liabilities and contingent liabilities

that meet the criteria for recognition under IFRS 3 (Revised) are recognised at their fair value at the acquisition date. Acquisition costs are expensed.

2.15. 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. Any impairment is recognised immediately and is not subsequently reversed.

Under the reverse acquisition (note 3), 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.

On disposal of a subsidiary or jointly controlled entity, the attributable amount of unamortised goodwill, which has not been subject to impairment, is included in the determination of the profit or loss on disposal.

2.16. Intangible assets - evaluation and exploration assets

The Group accounts for Evaluation and Exploration ("E&E") activity in accordance with the provisions of IFRS 6. The Group will continue to monitor the application of its policy with respect to any future guidance on accounting for oil activities which may be issued.

Capitalisation of E&E Assets

All costs (other than payments to acquire the legal right to explore, evaluate or appraise an area, which are expensed) incurred during the Pre-licensing Phase are charged directly to the consolidated statement of comprehensive income. All costs incurred during the Evaluation and Exploration Phases, such as Geological & Geophysical ("G&G") costs, other direct costs of exploration and appraisal are accumulated and capitalised as intangible E&E assets in accordance with the principles of full cost accounting.

At the completion of the Exploration Phase, if technical feasibility is demonstrated and commercial reserves are discovered then, following the decision to continue into the development phase, the carrying value of the relevant E&E asset will be reclassified as a Development and Production ("D&P") asset, but only after the carrying value of the asset has been assessed for impairment in accordance with the Impairment of E&E Assets policy. E&E costs are not amortised prior to reclassification to the D&P Phase.

Impairment of E&E Assets

Upon reclassification of a project from the E&E phase to the D&P phase, an impairment review of the affected E&E assets is performed. The E&E impairment test is performed by comparing the carrying value of the costs against the estimated recoverable value of the reserves (proved plus probable) related to these assets. Any resulting impairment loss is charged to the consolidated statement of comprehensive income. The recoverable value is determined as the higher of a) its fair market value less costs of disposal or b) the sum of related cash flows, on a net present value basis.

Further, if at any time when indicators or circumstances exist which suggest the E&E assets may be impaired such as:

-- the licence to explore a particular area has expired or will expire soon and will not be renewed; or

-- further exploration or evaluation work in a particular area is not budgeted or planned; or

-- Evaluation and Exploration work has concluded that commercially viable amounts of oil are not available in a particular area and the Group has decided to discontinue Evaluation and Exploration in that area; or

-- data shows that, although development of an area will continue, the carrying amount of the E&E asset is unlikely to be recovered in full from successful development, indicating the possibility that the carrying value of an E&E asset may exceed its recoverable amount;

The E&E impairment test is carried out by adding the value of the E&E assets being evaluated to the D&P assets at a ratio of sales/ geographical area to determine the relevant Cash Generating Unit ("CGU").

The combined carrying value of the E&E and D&P assets in the CGU is compared against the estimated recoverable value, and any resulting impairment loss is charged to the consolidated statement of comprehensive income.

2.17. Property, plant and equipment - Development & Production assets

The Group accounts for D&P assets in accordance with the provisions of IAS 16 following the full cost accounting principles. The Group will continue to monitor the application of its policy with respect to any future guidance on accounting for oil and gas activities which may be issued.

Capitalisation

Development and production assets are accumulated into single field cost centres and represent the cost of developing the commercial reserves and bringing them into production together with the E&E expenditures incurred in finding commercial reserves previously transferred from E&E assets as outlined in the policy above. From time to time different scenarios occur that call for specific policy guidance.

The following specific policies are applied by the Group:

-- CGUs - The Group has defined its CGUs as assets or groups of assets representing the smallest identifiable segments generating cash flows that are largely independent of cash flows from other assets or groups of assets. As defined, each CGU includes the relevant properties, wells, facilities, pipelines and other key components of the included operations.

-- Dry Hole Costs - Dry hole costs are included in the capitalised costs of the field and would therefore be included in any impairment tests conducted, as described below.

-- Water Injection/Disposal Wells - The Group may convert an existing well into a water injection or disposal well. At the time of conversion, all costs associated with the asset are transferred to facility costs. Any capitalisable costs incurred thereafter will be included as facility costs.

-- Allocated Costs - Costs such as G&G, Seismic, Capitalised General and Administrative costs, Financing costs, etc. which may cover multiple countries, business segments, CGUs or other assets will be allocated to the appropriate CGUs during the period in which the costs were incurred.

Depreciation, Depletion and Amortisation (DDA)

Asset costs relating to each CGU as defined above, which include the components of properties, wells, facilities, pipelines and other, are depreciated, depleted or amortised ("DDA") on a unit of production method based on the commercial proven and probable reserves for that CGU. Development and Production assets are depreciated over the relevant net production within the corresponding CGU. As noted above, asset costs associated with E&E projects, even though those assets may or may not have reserves associated with them and are within a CGU with active producing operations, are not amortised until such costs are analysed for impairment and then transferred to D&P phase. The DDA calculation takes into account the estimated future costs of development for recognised proven and probable reserves for each field based on current price levels and escalated annually based on projected cost inflation rates. Changes in reserve quantities and cost estimates are recognised prospectively from the last reporting date.

Impairment of D&P Assets

A review is performed for any indication that the value of the Group's D&P assets may be impaired such as:

-- significant changes with an adverse effect in the market or economic conditions; or

-- obsolescence or physical damage of an asset; an asset becoming idle or plans to dispose of the asset before the previously expected date; or

-- evidence is available from internal reporting that indicates that the economic performance of an asset is or will be worse than expected.

For D&P assets when there are such indications, an impairment test is carried out on the CGU. CGUs are identified in accordance with IAS 36 'Impairment of Assets', where cash flows are largely independent of other significant assets groups and are normally, but not always, single development or production areas. When an impairment is identified, the depletion is charged through the statement of comprehensive income if the net book value of capitalised costs relating to the cash generating unit exceeds the associated estimated future discounted cash flows of the related commercial oil reserves.

Workovers/overhauls and maintenance

From time to time a workover or overhaul or maintenance of existing D&P assets is required, which normally fall into one of two distinct categories. The type of workover dictates the accounting treatment and recognition of the related costs:

Capitalisable costs

Costs will be capitalised where the performance of an asset is improved, where an asset being overhauled is being changed from its initial use, the assets useful life is being extended, or the asset is being modified to assist the production of new reserves. The asset will then be subject to depreciation.

-- If the workover is being performed on an asset which has been the subject of a previous workover, the net book value of costs previously capitalised will be derecognised and charged to cost of sales at the same time as the subsequent capitalisable workover expenditures are being recognised as part of the asset's revised carrying value.

-- If the workover replaces parts, equipment or components of an asset or group of assets, and these replacement items qualify for capitalisation, then the original cost of those parts or equipment, including related installation and set up costs that were capitalised as part of the original asset, will be derecognised and charged to cost of sales in the consolidated statement of comprehensive income. In the event that the original cost of parts, equipment or components being replaced are not reasonably identifiable, the cost of the new items, adjusted for inflation, may be deemed adequate for consideration as the original cost.

Non-capitalisable costs

Expense type workover costs are costs incurred such as maintenance type expenditures, which would be considered day-to-day servicing of the asset. These types of expenditures are recognised within cost of sales in the consolidated statement of comprehensive income as incurred. Expense workovers generally include work that is maintenance in nature and generally will not increase production capability through accessing new reserves, producing from a new zone or significantly extend the life or change the nature of the well from its original production profile.

2.18. Decommissioning

Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability (the discount rate used currently being at 10%, (2012: n/a)) for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field.

A corresponding item of property, plant and equipment is also created at an amount equal to the provision. This is subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision and property, plant and equipment. The unwinding of the discount is recognised as a finance cost.

2.19. Critical Accounting Estimates and Judgements

Use of Estimates and Judgements

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

a) Recoverability of tangible oil and gas assets and intangible oil and gas costs (note 12 and 13)

Costs capitalised as oil and gas assets in property, plant and equipment, and intangible assets are assessed for impairment when circumstances suggest that the carrying value may exceed its recoverable value. As part of this assessment, management has carried out an impairment test (ceiling test) on the oil and gas assets classified as property, plant and equipment. This test compares the carrying value of the assets at the reporting date with the expected discounted cash flows from each project. For the discounted cash flows to be calculated, management has used a production profile based on its best estimate of proven and probable reserves of the assets and a range of assumptions, including an internal oil and gas price profile benchmarked to mean analysts' consensus and a discount rate which, taking into account other assumptions used in the calculation, management considers to be reflective of the risks.

This assessment involves judgement as to

(i) the likely commerciality of the asset;

(ii) proven, probable and possible ('P') reserves which are estimated using standard recognised evaluation techniques;

(iii) future revenues and estimated development costs pertaining to the asset;

(iv) the discount rate to be applied for the purposes of deriving a recoverable value; and

(v) the value ascribed to contingent resources associated with the asset.

b) Carrying value of intangible exploration and evaluation expenditure

The amounts for intangible exploration and evaluation assets represent the costs of active exploration projects, the commerciality of which is unevaluated until reserves can be appraised. Where a project is sufficiently advanced, the recoverability of intangible exploration assets is assessed by comparing the carrying value to estimates of the present value of projects. The present values of intangible exploration assets are inherently judgemental. Exploration and evaluation costs will be written off to the consolidated statement of comprehensive income unless commercial reserves are established or the determination process is not completed and there are no indications of impairment. The outcome of ongoing exploration, and therefore whether the carrying value of exploration and evaluation assets will ultimately be recovered, is inherently uncertain.

c) Depreciation of oil and gas assets (note 13)

Oil and gas assets held in property, plant and equipment are mainly depreciated on a unit of production basis at a rate calculated by reference to proved plus probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells, future production facilities and operating costs; together with assumptions on oil and gas realisations.

d) Decommissioning (note 19)

The Group has decommissioning obligations in respect of its interests. 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. The decommissioning provision is updated each year to reflect management's best estimates based on the current economic environment of the key assumptions used. Actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

e) Fair value assessment and acquisitions (note 3 and 4)

The Group has made certain judgements in connection with assessing the fair values of consideration, assets and liabilities at acquisition, which include assessment of their ongoing value, independent valuations and assessment of any adjustments or impairment to the acquired Companies book values.

In respect of Goodwill management have performed an impairment test as at the date of the reverse acquisition and have concluded that there is no residual value to support the goodwill and accordingly it has been impaired in full.

f) Share based payments (note 7)

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.

3. Reverse acquisition of Northcote Energy Limited

On 14 January 2013 the Company acquired 100% of the issued share capital of Northcote Energy Limited, Cayman Islands ("Northcote CI"), a US focussed on-shore oil and gas Group, for a consideration of $10.4 million to be satisfied by the issue of 645,084,519 new Shares to the Sellers. Northcote Energy Limited was incorporated as an investment vehicle focussed on the completion of a natural resources acquisition. The Directors identified and completed the acquisition of Northcote CI in line with this strategy and to further the business interests of the Group.

In accordance with IFRS 3 (Revised) the acquisition represents a reverse acquisition and the details of the reverse acquisition are below:

In a reverse acquisition, the acquisition date fair value of the consideration transferred by Northcote Energy Limited is based on the number of equity instruments that Northcote CI would have had to issue to the owners of Northcote Energy Limited to give the owners of Northcote Energy Limited the same percentage of equity interests that result from the reverse acquisition.

The cost of the combination was calculated using the fair value of all the pre-acquisition issued equity instruments of Northcote Energy Limited at the date of acquisition. The fair value of the share consideration was based on the latest share transaction of Northcote Energy CI from October 2012 of £0.17 immediately prior to the acquisition. Goodwill of $1,273,000 was expensed immediately on acquisition and all the acquisition related costs were also expensed in accordance with IFRS 3 (Revised).

The costs of the reverse acquisition of Northcote CI totalled $690,000; of this amount $333,000 was recorded in the period under review, with the remaining amount being recorded in the prior period ended 31 December 2012.

No revenue or profits attributable to Northcote Energy Limited prior to acquisition were included in the Consolidated Statement of Comprehensive Income to 31 December 2013. Had Northcote Energy Limited been consolidated from 1 January 2013 the Consolidated Statement of Comprehensive Income would show the same levels of revenue and profits.

4. Acquisition of Oklahoma Energy

On 1 April 2013 the Group acquired a 100% interest in Oklahoma Energy LLC ("OKE"), a US company with Oil & Gas assets in Oklahoma. The Group agreed to pay BlueRock $400,000 (a third party) at completion which has been treated as part of the consideration:

In accordance with IFRS 3 (Revised) the details of the acquisition are below:

No revenue or profits attributable to Oklahoma Energy LLC prior to acquisition were included in the Consolidated Statement of Comprehensive Income to 31 December 2013. Had Oklahoma Energy LLC been consolidated from 1 January 2013 the Consolidated Statement of Comprehensive Income would have reported additional revenues of $14,891 and additional losses of $17,267. There were no material acquisition related costs to disclose.

5. Finance income and Finance expense

6. Segmental analysis

In the opinion of the Directors, the operations of the Group comprise one single operating segment comprising production, development and sale of hydrocarbons and related activities. The Group operates in one geographic area, the USA. The Group has some head office operations in the UK but the quantitative thresholds of IFRS 8 are only met for the USA, which is therefore the Group's one reportable segment and the Directors consider that the primary financial statements presented substantially reflect all the activities of this single operating segment.

The Group has four main customers, representing 100% of the oil sales revenue, which are generated in the USA.

7. Loss per Share

Basic loss per Share is calculated by dividing the loss attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

In accordance with International Accounting Standard 33 'Earnings per share', no diluted earnings per share is presented for the effect of potentially dilutive shares or options because their effect would be anti-dilutive.

8. Expenses by nature

9. Staff Costs (only Directors)

The only employees during the year were the 5 directors (2012: 4). The Group employed a number of people in the US as consultants during the year. Since the year end some of these consultants are now employed by the Group.

Key management of the Group are considered to be the Directors of the Company and their remuneration of those in office during the year was as follows:

10. Financial Risk Management

The Group's activities expose it to a variety of financial risks: market risk, credit risk and liquidity risk. The Group's overall risk management programme seeks to minimise potential adverse effects on the Group's financial performance.

Risk management is carried out by the Board.

(a) Market Risk

Foreign exchange risk

The Group operates principally in the US, but is exposed to foreign exchange risk arising from currency exposures, primarily with respect to the British Pound. Foreign exchange risk arises from future commercial transactions and recognised assets and liabilities.

As at 31 December 2013 the exposure to this risk is not considered material to the Group's operations and thus the Directors consider that, for the time being, no hedging or other arrangements are necessary to mitigate this risk.

(b) Credit Risk

The Group has policies in place to ensure that sales of products are made to customers with appropriate credit worthiness. The Group limits credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated.

Where appropriate, the use of prepayment for product sales limits the exposure to credit risk. There is no difference between the carrying amount of trade and other receivables and the maximum credit risk exposure.

Credit risk also arises from cash and cash equivalents. The Group considers the credit ratings of banks in which it holds funds in order to reduce exposure to credit risk. The Group will only keep its holdings of cash and cash equivalents with institutions which have a minimum credit rating of 'B'.

 (c) Liquidity Risk

Management of liquidity risk is achieved by monitoring budgets and forecasts against actual cash flows. Where the group entered into borrowings during the year management monitored the repayment and servicing of these arrangements against the contractual terms and reviewed cash flows to ensure that sufficient cash reserves were maintained. The loans were fully repaid in the year evidencing that management had sufficient liquidity risk management policies in place.

(d) Capital Risk Management

The Directors determine the appropriate capital structure of the Group, specifically, how much is raised from shareholders (equity) and how much is borrowed from financial institutions (debt), in order to finance the Group's business strategy.

The Group's policy as to the level of equity capital and reserves is to ensure that it maintains a strong financial position and low gearing ratio which provides financial flexibility to continue as a going concern and to maximise shareholder value. The capital structure of the Group consists of shareholders' equity together with net debt (where relevant). The Group's funding requirements are met through a combination of debt, equity and operational cash flow.

11. Taxation

Taxation reconciliation

The charge for the year can be reconciled to the loss per the consolidated statement of comprehensive income:

 The deferred tax asset has not been provided for in accordance with IAS 12. The Group does not have a material deferred tax liability at the year end.

12. Intangible assets

Impairment

Management reviews each exploration project for any indication of impairment at each year end. Such indications would include written off wells and relinquishment of development acreage. During the year the Group impaired the Goodwill related to the reverse acquisition in full. Aside from the impairment of the Goodwill there were no other indications of impairment in respect of any of the ongoing projects at the year date.

13. Property, plant & equipment

Impairment

Management review each exploration project for any indication of impairment at the year end. Such indications would include written off wells and relinquishment of development acreage. At the year end there were no indications of impairment in respect of any of the projects.

14. Inventories

15. Trade and other receivables

The fair values are as stated above, which equate to their carrying values as at the year end. The financial assets were not past due and were not impaired and were all denominated in US$.

16. Trade and other payables

17. Share based payment

The following is a summary of the share options and warrants outstanding and exercisable as at 31 December 2013 and 31 December 2012 and changes during the period:

At 31 December 2013 (2012: Nil) the following share options or warrants were outstanding in respect of the ordinary shares:

1) Vests after 31.12.13 on condition that the Director is employed at that date and that net production is greater than 100 boepd;

2) Vests after 31.12.13 on condition that the Director is employed at that date and that net production is greater than 250 boepd;

3) Vests after 30.06.14 on condition that the Director is employed at that date and that net production is greater than 400 boepd;

The new options and warrants have been valued using the Black-Scholes valuation method and the assumptions used are detailed below. The expected future volatility has been determined by reference to the historical volatility:

The Group recognised $344,898 (2012: $Nil) related to equity-settled share based payment transactions during the year, of which $158,000 (2012: $Nil) was charged to share premium and $193,527 (2012: $Nil) was expensed. There is a further $54,792 (2012: $Nil) to be recognised in the subsequent financial period, in relation to the above issue of options. See note 24 for details of warrants entered into after the year end. For the share options and warrants outstanding as at 31 December 2013, the weighted average remaining contractual life is 3.6 years (2012: n/a).

18. Share capital

* Non-cash item per the consolidated cash flow statement

19. Provisions

The provision in respect of Plug & Abandonment represents the present value of the decommissioning of up to 247 existing producing and currently shut-in well bores. Decommissioning is due to take place from 2014 to 2043 (2012: n/a). The provisions are made using the Group's internal estimates that Management believes form a reasonable basis for the expected future costs of decommissioning.

The environmental provision relates to Management's estimate of the fair value of the environmental costs to be incurred at the Group's Oklahoma Energy project. Since the year end the provision has been fully settled. The deferred consideration is payable in cash within one year to the vendor of the EBSSU lease acquired in December 2013.

20. Loans and borrowings

*non-cash item

The convertible loan note was advanced to the Group by Randall Connally. The loan carried a nil coupon was unsecured and was converted into shares at a price of 1pence per share on admission of the Group to AIM.

Principal terms and the debt repayment schedule of the Group's unsecured loans and borrowings during the year were as follows:

The Group has no exposure at the year end to interest rate changes, and is not subject to any contractual re-pricing, as the Group has $nil borrowings or undrawn borrowings as at the year end. See note 24 for details of loans entered into after the year end. As at the 31 December 2012 the fair values of the loans and borrowings equated to their carrying values.

21. Capital Commitments

There were no capital commitments authorised by the Directors or contracted for at 31 December 2013 (31 December 2012: None).

22. Related party transactions

Riverbend and Horizon are associated entities each with significant shareholdings in the Group. The details of transactions with related parties are detailed in the table below:

The loan note to Randall Connally was converted into equity in the year; see note 20 for further details. Compensation paid to key Management personnel including Directors, Executive Directors and senior management is disclosed in note 9.

23. Ultimate Controlling party

As at the Consolidated Statement of Financial Position date, the Directors believe that there is no ultimate controlling party.

24. Events after the reporting date

Zink Ranch

On 28 February 2014 the Group entered into an agreement to purchase an additional interest in its Zink Ranch project for a cash consideration of $850,000.

Subsequently on 14 March 2014 the Group announced that it had agreed a farm-out with North American Petroleum plc ("NAP"). Northcote has entered into a farm-out agreement pursuant to which NAP may earn a 30% working interest and 23.4% net revenue interest in workovers of existing wells and the drilling of subsequent wells targeting various Pennsylvanian objectives at the Zink Ranch project. To earn the interest, NAP must fund $600,000 of the Group's development costs at Zink Ranch.

Convertible loan note and warrants

On 26 February 2014 the Group entered an agreement for up to £1,500,000 ($2,473,200) (gross) zero coupon convertible bonds ('Note') with Darwin Strategic Limited ('Darwin'). The Note is divided into 30 individual bonds with a par value of £50,000 ($82,440) each; the Group issued 24 of these bonds (£1,200,000 or US$1,978,560) on 26 February 2014.

The Group, at its option, has the right to redeem one or all of the outstanding bonds in cash at 105% of the par value. From August 2014 the Group is committed to redeem one unit of £50,000 ($82,440) per month until 31 August 2015 (the redemption date) and furthermore from 1 August 2014, the bonds shall be convertible into Ordinary Shares at 1.1p per share or, if lower 94% of the market share price at the relevant conversion date.

In addition Darwin has been issued with warrants over 54,545,455 shares at a price of 1.1pence per share. The warrants can be exercised over a 3 year period.

SHOATS CREEK

The Group signed on 5 June 2014 the sale and purchase agreement with Aminex PLC and Springer Oil & Gas LLC to acquire a 70% interest in the Shoats Creek Field. The acquisition will be the purchase of an oil & gas asset only and will be satisfied as follows:

o The issue of Northcote ordinary shares valued at US$350,000 (to be issued); and

o A production payment of $10.00 per barrel up to a maximum of US$3.15 million