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NORTHCOTE ENERGY LIMITED - Final Results

PR Newswire

London, June 30

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

30 June 2016

Northcote Energy Ltd (‘Northcote’ or ‘the Company’)

Final Results

Northcote (AIM: NCT) is pleased to announce its final results for the year ended 31 December 2015. The full Report and Accounts for the period under review will be available on the Company's website today at www.northcoteenergy.com.

Northcote Managing Director Randall Connally said: “Our major accomplishments in 2015 were (i) drilling and completion of the Lutcher Moore #20 well which validates the potential of the Shoats Creek Field; and, (ii) initiation of our joint venture with Gaia Ecologica and establishment of Mayan Drilling Fluids. Both of these businesses have tremendous potential to develop into major businesses for the company and to generate the kind of shareholder value our shareholders expect and deserve. In 2016 we are focused on implementing the infrastructure and adding additional revenue by exploiting the full potential of Shoats Creek even as we continue making progress toward initiating commercial operations at Mayan Drilling Fluids in Mexico”

A copy of this announcement and the Final results will be available on the Company’s website and notification has also been sent to shareholders today.

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

CHAIRMAN AND CHIEF EXECUTIVE’S STATEMENT

Northcote Energy was an early subscriber to the view that oil was staying ‘lower for longer’, quickly recognising that the extended period of oil trading in the US$90-100 per barrel range was over. The standard response to lower prices for the majority of the oil and gas sector is to batten down the hatches and ride out the downturn. Rather than simply waiting for the cyclical upturn however, the year under review saw us set about transforming Northcote from a pure play US onshore focused exploration and production group heavily exposed to the price of oil, to a broader energy company with interests across the value chain and exposure to a wide range of markets, all of which have the potential to generate revenues that are far less dependent on the oil price.

The continued sharp fall in the price of oil from the US$60 level at the half year stage to a 12 year low of US$27 in January 2016 has vindicated our decision. At the same time it has also meant that over the course of the year projects have had to be reprioritised, capital reallocated and timelines extended. Despite the challenging conditions, I am pleased to report the review period has seen much progress made towards building a diversified energy group including: the commencement of the construction of a remediation plant in Mexico; the acquisition of North American Petroleum; the successful drilling of the Lutcher Moore#20 well at the Shoats Creek field in Louisiana, which has strengthened our belief in the field’s credentials; and the securing of an agreement to participate in upstream gas and power projects in Indonesia. While much work still needs to be done, all the above provide solid foundations upon which to build standalone sustainable businesses in the year ahead and beyond, regardless of the prevailing oil price environment.

Midstream/Services

There has been much copy in the press dedicated to international oil and gas companies being allowed for the first time in decades to bid for concessions in Mexico’s vast energy sector. Acquiring and developing upstream assets in proven hydrocarbon formations offers a well-trodden path for companies looking to create significant value, one which we ourselves closely evaluated in H2 2015. At its core, the opening up of Mexico’s energy sector is targeting a step-up in production and reserves. To accommodate the higher levels of drilling activity and production volumes, Mexico requires the necessary infrastructure, as well as the relevant expertise, to be in place to ensure the sector grows efficiently while at the same time remaining compliant with the highest environmental standards. Based on the scale of Mexico’s energy sector and the ambition of the government, Mexico in our view represents a once in a generation opportunity to build a leading midstream services business, and this lay behind our decision in H1 2015 to invest in the first scalable environmental waste remediation facility ('the Facility') in the State of Tabasco via our 51% owned Mexican subsidiary, Mayan Drilling Fluids.

In line with our strategy to team up with established local businesses with excellent track records and contacts, our partner in the plant is Gaia Ecologica S.A. DE C.V ('Gaia Ecologica'), an established operator in providing waste remediation services to local oil and gas companies in Mexico. Northcote is funding 100% of the up-front expenditures associated with the implementation of Mayan's business plan and will receive (i) a US$15,000 per month administrative fee after the overhead costs of the business have been paid; and, (ii) 85% of distributable cash flow until pay-out plus a 9% internal rate of return has been achieved on the investment, after which profits will be distributed based on the relative ownership. As of June 30, 2016 commercial operations utilizing a portion of the facilities at our remediation plant have been initiated. The revenues generated will be reinvested into future expansion of the remediation plant, which can easily be scaled up to meet expected increases in demand both in Tabasco and across the country.

Upstream

US Onshore

Due to the low oil prices, upstream activity during the year focused exclusively on Shoats Creek. This proven oil and gas field in Louisiana benefits from low breakeven costs and we believe that it has the potential to produce over a thousand barrels per day. Shoats Creek’s potential was demonstrated by the successful drilling in H2 2015 of the Lutcher Moore#20 (‘LM#20’), a low cost well which produced in excess of 260 barrels of oil per day during a 24 hour test. This exceeded our pre-drill expectations and post period end the well was brought online. The operator, Shoats Creek Development, Inc., has advised Northcote that the well will consistently produce at between 100 and 120 barrels of oil per day, a rate that it believes will maximise total recovery while minimising decline and so optimising cumulative production and investment returns from the well. The positive result of LM#20 has de-risked a further three drilling locations on the field, increasing our defined new well inventory for Shoats Creek to 11, each of which demonstrate excellent economics at current prices. There is further potential to increase this well inventory further. The success we have had at Shoats Creek over the course of the year has strengthened our view that it is an asset which is capable of delivering the material increases in revenues and cash flows that Northcote needs to become a sustainably cash generative group.

As set out at the time of the Group’s interims our original intention was to maintain the momentum following the success of LM#20 by drilling another well at Shoats Creek in 2015. Funding constraints at our partner at the field, largely caused by the deteriorating sentiment towards the sector, had already led to Northcote drilling LM#20 with a 93% working interest. While we were delighted with the result, management decided it would be prudent to reduce our exposure to drilling risk for subsequent wells. As a result, partners were sought to take the project forward but a further lurch downwards in the price of oil, meant this process took longer than had originally been envisaged.

In October 2015, we announced the first of two farm-ins to Shoats Creek. Red Rock Resources plc (‘RRR’) agreed to farm-in to a 20% working interest and 14.4% net revenue interest in two offset wells targeting the Frio sands: the Lutcher Moore #21 and Lutcher Moore #22. The second farm-in was secured post period end. Gulf Coast Western, Inc. (‘GCW’), a privately owned, Dallas based exploration and production company founded in 1970, acquired a 50.0% working interest and 36.0% net revenue interest in the Lutcher Moore #20 well, the right to participate in future Frio and Cockfield wells, and a 25.0% working interest and 18.0% net revenue interest in the Wilcox formation. In return, GCW agreed to pay Northcote US$500,000.00 in cash, including US$100,000 upfront; and carry Northcote in an amount equal to 10.0% (of 100%) working interest in each of the next four wells drilled.

At the same time as the GCW transaction, Northcote entered into a joint operating agreement with SCDI, its partner and the operator of the Shoats Creek Field, which saw Northcote acquire a 20.0% working interest and 14.4% net revenue interest in the Cockfield formation for US$67,200 in new ordinary shares of Northcote Energy.

The net effect of the various transactions on Northcote’s interests in the Shoats Creek Field are summarised as follows:

Shoats Creek is just one of a number of US onshore projects that we hold. Lower for longer oil prices led us to split these into ‘focus’ and ‘non-focus’ portfolios based on the economics of developing these assets at US$40 oil. As Shoats Creek is commercial at sub US$40 oil, this has been our priority throughout the year while our portfolio of projects in Oklahama, which includes the non-core Horizon and OKE properties as well as the Zink Ranch project was put on care and maintenance. As at December 2015, daily production from the Oklahoma Portfolio averaged 16.4 barrels of oil and 135.4 mcf of natural gas or, on a 6 mcf per 1 barrel of equivalent (BOE) basis, 39 BOE/d in December 2015 net to Northcote (gross of 76 BOE/d equivalent).

We intend to sell our Oklahoma portfolio. However, the difficulty in achieving reasonable values in the current environment while sentiment towards the sector is so low has led us to evaluate other options for the projects. 

Indonesia

The year under review saw us add a third country of interest to our portfolio after we secured a participation agreement and equity investment in CEB Resources plc ('CEB'), an AIM listed investment vehicle focused on Indonesia, a premier oil and gas region in South East Asia. This was in return for introductions and assistance provided to CEB and its new management team. Under the agreement, Northcote is entitled to participate in up to 12.5% of any of CEB's investments, at its sole discretion, in Indonesia for a term of five years. CEB has since changed its name to Andalas Energy and Power and has already acquired its first asset, the Tuba Obi East Technical Assistance Contract (‘TOE’), which is located in the South Sumatran basin approximately 30km north-west of Jambi city in Jambi province, Sumatra. Andalas is farming into a 30% interest in TOE and in line with our Participation Agreement we have elected to exercise our right to acquire a 3.75% interest in TOE.

TOE is the entry point for Andalas into the attractive Indonesian gas and power sector and any future gas production from the concession may support either gas export, due to the project’s proximity to a major export route, or gas-to-power as the concession is located in an area where a significant shortfall in power generation exists. Wells drilled historically have tested gas in the key South Sumatra hydrocarbon bearing formations, namely, the Air Benakat Formation (‘ABF’) and the Talang Akar Formation (‘TAF’). Andalas’ technical analysis indicates that this reservoir zone contains potentially substantial gas resources that can be proven via the drilling and flow testing of a new well. A report dated 22 April 2016 was prepared by Gaffney Cline & Associates which estimated the prospective resources in the Air Benakat Formation within the Tuba Obi East concession based on the historical exploration and appraisal data available. Gaffney Cline & Associates reports best estimate prospective resources of approximately 22Bcf in each of two potential reservoir zones, the ABF upper and ABF lower, within the main closed structure within the boundary of the Tuba Obi East. As part of the farm-in Andalas has committed to undertake a work programme comprising technical studies and the drilling and testing of one well, TOE-2 well, which would be put into production on success. Northcote’s proportionate share of the costs, are estimated at a total gross amount of US$200,000, for which it is fully funded.

Financial Review

The Group generated a loss for the year attributable to the equity shareholders totalled US$6,137,000 (31 December 2014: $9,778,000), which was a function lower commodity prices throughout the period, the impairment of oil and gas assets totalling $1,359,000 alongside increasing activities in Mexico.

Outlook

The year under review saw us set out about transforming Northcote into a broad based energy group with interests across the value chain including upstream, midstream and downstream. While progress has been slower than hoped, largely due to the unfavourable oil price environment and associated poor sentiment towards the wider sector, Northcote Energy is no longer solely focused on US onshore formations as it was at the start of the year. Today the Group has multiple revenue and value drivers in place: an exciting midstream offering in Mexico which provides an excellent platform for future growth; a producing low cost conventional field in Louisiana; and an interest in a potential gas-to-power project in Indonesia. We believe the foundations for a sustainable business which we can build on are now in place. Our priority remains to make Northcote an EBITDA positive group irrespective of the oil price environment as soon as possible, and all our efforts both during the year under review and beyond are focused on achieving this.

I would like to take this opportunity to thank the team and all its advisers for their continued hard work on behalf of the Group, and also our shareholders for their loyal support during what during what has been a difficult year for the oil and gas sector.

NORTHCOTE ENERGY LIMITED

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

YEAR ENDED 31 DECEMBER 2015

NORTHCOTE ENERGY LIMITED

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AS AT 31 DECEMBER 2015

NORTHCOTE ENERGY LIMITED

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

NORTHCOTE ENERGY LIMITED

CONSOLIDATED CASH FLOW STATEMENT

YEAR ENDED 31 DECEMBER 2015

Major Non Cash Transactions

Details of major non-cash transactions are described in note 11 and 12, non-current assets, note 17 share capital and note 18 provisions and note 19 borrowings.

NORTHCOTE ENERGY LIMITED

NOTES TO FINANCIAL STATEMENTS

YEAR ENDED 31 DECEMBER 2015

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.

At the date of authorisation of these financial statements, the following standards and interpretations, were in issue but not yet effective, and have not been early adopted by the Group:

A number of new standards, amendments to standards and interpretations are effective for annual periods beginning on or after 1 February 2015, and have not been applied in preparing these financial statements. The Group does not plan to adopt these standards early; instead it will apply them from their effective dates as determined by their dates of EU endorsement. The Group is reviewing the upcoming standards to determine their impact.

The following standards were adopted by the Group during the year;

IFRS 10 Consolidated financial statements

IFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by IFRS 10 required management to exercise judgement to determine which entities are controlled and, therefore, are required to be consolidated. The Group has applied IFRS 10 retrospectively in accordance with the transition provisions of IFRS 10. There is no material impact on the Group as a result of applying this standard. There has been no material impact on the financial statements as a result of the adoption of IFRS 11, 12, IAS 27 and IAS 28 other than in relation to disclosure.

2 Summary of significant accounting policies

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

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 2015.

Subsidiaries are 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 entity and has the ability to affect those returns through its power over the 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.

When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with the Group's accounting policies. All intra-group assets and liabilities, equity, income, expenses and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.

A change in the ownership interest of a subsidiary, without a loss of control, is accounted for as an equity transaction. If the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest and other components of equity while any resultant gain or loss is recognised in the Statement of Comprehensive Income. Any investment retained is recognised at fair value at the date when control is lost. The group comprises of the following entities;

*An LLC is not a corporation, it is a legal form of company that provides limited liability to Northcote, its owner and general manager. **An LP is not a corporation, it is a legal form of partnership that gives the partners limited liability and is managed by a general manager.

The financial statements have been prepared assuming the Group will continue as a Going Concern. This assessment has been made on the Group’s economic prospects in its financial forecasts. In assessing whether the going concern assumption is appropriate the Directors have taken into account all available information for the foreseeable future; in particular for the 12 months from the date of approval of the financial statements. This includes future cashflows based on management prepared forecasts and if required the Group has a track record of raising funds, whether it is through new equity, farm-ins or disposals. As disclosed in note 2.3 the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future and, therefore, can continue to adopt the going concern basis of preparation in these financial statements. It should be noted, however, that the auditors have drawn attention to going concern within their audit report by way of an emphasis of matter. The Group has net current liabilities as at 31 December 2015 of £2,015,000 (2014: £3,042,000).

The Group has classified all of its financial assets as loans and receivables. The classification

depends on the purpose for which the financial assets were acquired. Management determines the classification of its financial assets at initial recognition.

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. The Group’s loans and receivables comprise trade and other receivables and cash and cash equivalents in the Statement of Financial Position.

Loans and receivables are initially recognised at fair value plus transaction costs and are subsequently carried at amortised cost using the effective interest method, less provision for impairment.

The Group assesses at the end of each reporting period whether there is objective evidence that a financial asset, or a group of financial assets, is impaired. A financial asset, or a group of financial assets, is impaired, and impairment losses are incurred, only if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset (a “loss event”), and that loss event (or events) has an impact on the estimated future cash flows of the financial asset, or group of financial assets, that can be reliably estimated.

The criteria that the Group uses to determine that there is objective evidence of an impairment loss include:

The amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred), discounted at the financial asset’s original effective interest rate. The asset’s carrying amount is reduced, and the loss is recognised in the Statement of Comprehensive Income.

If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised (such as an improvement in the debtor’s credit rating), the reversal of the previously recognised impairment loss is recognised in the Statement of Comprehensive Income.

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

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.

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 highly liquid amounts that are readily convertible to a known amount of cash.

Trade and other payables are obligations to pay for goods or services that have been acquired in the ordinary course of business. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are recognised initially at fair value, and subsequently measured at amortised cost using the effective interest method.

Equity comprises the following:

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.

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.

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.

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.

Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods supplied, stated net of discounts, returns and value added taxes. The Group recognises revenue when the amount of revenue can be reliably measured and when it is probable that future economic benefit will flow to the entity. The Group bases its estimate of return on historical results, taking into consideration the type of customer, the type of transaction and the specifics of each arrangement.

Revenue represents the sale value of the Group’s share of oil and the income from technical services to third parties if any. Revenues are recognised when crude oil has been lifted and title passed to the buyer or when services are rendered.

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 the lower of cost and net realisable value. 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.

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.

Except as described below, the acquisition of subsidiaries is accounted for using the acquisition 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.

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.

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 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 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

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:

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:

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 impairment 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.

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.

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.

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.

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%, (2014: 10%)) 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.

Compound Financial Instruments issued by the Group comprise convertible notes that can be converted to share capital at the option of the holder, and the number of shares to be issued does not vary with changes in their fair value. If the number does vary with changes in their fair value then the instrument is treated as a liability.

The liability component of a compound financial instrument is recognised initially at the fair value of a similar liability that does have an equity conversion option. The equity component is recognised initially at the difference between the fair value of the compound instrument as a whole and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts.

Subsequent to initial recognition, the liability component of a compound financial instrument is measured at amortised cost using the effective interest method. The equity component of a compound financial instrument is not re-measured subsequent to initial recognition except on conversion or expiry.

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.

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.

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.

a) 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.

b) Depreciation of oil and gas assets (note 12)

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.

2.20 Critical Accounting Estimates and Judgements (continued)

c) Decommissioning (note 18)

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.

d) Fair value assessment and acquisitions

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.

e) Share based payments

The Group has made awards of options and warrants over its unissued capital. The valuation of these options and warrants involves making a number of estimates relating to price volatility, future dividend yields, expected life and forfeiture rates.

On 13 January 2015 the Group entered into a conditional sale and purchase agreement with North American Petroleum PLC (“NAPP”) for the acquisition of NAP USA Inc, which outlined that the eventual consideration payable would be 29.9% of Northcote's enlarged issued share capital as of the date of closing (the 'Consideration Shares'). On 12 February 2015 the acquisition of NAP USA, Inc. went unconditional and the Company was committed to issuing 1,266,074,005 ordinary shares at 0.009p each, which equated to $1,695,000 of consideration.

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

If NAP USA Inc. had been consolidated for the full year prior revenue would have been increased by $91,000 and the loss for the year would have been $46,000 greater. The costs related to the acquisition totalled approximately $45,000.

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 and has initiated the construction of a remediation plant in Mexico, 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 majority of the Group’s revenue is sold by the operators of its properties to customers of the operators’ choosing in the US. Northcote then receives a revenue cheque from those operators. As the vast majority of the revenue disclosed is generated on non-operated properties no detailed customer analysis has been provided.

Basic earnings 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 as the Group is loss making.

During the year Northcote purchase investments that were sold during the period resulting in a net loss of $29,000. As the loss is considered immaterial no further information has been disclosed.

The group employed 12 members of staff, of which 5 were directors (2014: 12).

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

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 2015 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 and as a result of this not being considered material no disclosure has been made in this respect.

(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.

9. Financial risk management (continued)

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.

(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 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.

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 due to uncertainty as to when sufficient profits will be generated against which to offset the losses. The Group does not have a material deferred tax liability at the year end.

12. Property, plant & equipment (continued)

Impairment

Management review each exploration project for any indication of impairment at the year end. Such indications would include sustained changes in the oil & gas price outlook, written off wells, changes in management’s development plan and the relinquishment of development acreage. The principle influences on management’s decision to impair the properties are described below:

Oil price

The Oil price continued to be under pressure in 2015. The Company had acquired a number of properties based on valuations at the peak of the market at a time when oil prices were consistently in excess of $100/bbl.

Development plan

The value of any proven Oil & Gas asset is a function of both its current production but also in the extraction of proven but as yet unproduced reserves. The Group’s properties in Oklahoma have significant oil in place estimates but the fall in the oil price has materially affected the Group’s ability to profitably extract those reserves. The lower oil price levels at the end of December 2015 are forecast to continue for 2016 and beyond and in this lower oil price environment the vast majority of Oklahoma wells have become marginal producers or have been shut in. This impacted the net present value forecast from the existing wells by both materially reducing the free cash flow generation of the existing wells and also by reducing the free cash flow forecast to be generated to be reinvested in sustaining/growing the levels of investment necessary to extract the known hydrocarbon reserves present on the property in a profitable way.

Capital constraint

The Group only has a finite amount of capital available, management has prioritised capital allocation to Shoats Creek as that presents more attractive returns and accordingly does not plan to allocate the capital sufficient to bring the proven reserves into production to the Oklahoma portfolios.

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$.

The following is a summary of the share options and warrants outstanding and exercisable as at 31 December 2015 and 31 December 2014 and changes during the period: 

16. Share based payment (continued)

The above has been expressed in pence and not cents due to the terms of the options and warrants. The following share options or warrants were outstanding in respect of the ordinary shares:

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 $335,000 (2014: $163,358) relating to equity-settled share based payment transactions during the year, of which $335,000 (2014: $Nil) was charged to share premium, $Nil (2014: $161,648) was charged to the convertible loan note (note 18) and $Nil (2014: $56,204) was expensed. See note 22 for details of warrants entered into after the year end. For the share options and warrants outstanding as at 31 December 2015, the weighted average remaining contractual life is 1.72 years (2014: 2.42).

* Non-cash item per the consolidated cash flow statement

The provision in respect of Plug & Abandonment represents the present value of the decommissioning of up to 122 (2014: 263) existing producing and currently shut-in well bores. Decommissioning is due to take place from 2016 to 2036 (2014: 2015 to 2043). The provisions are made using the Group’s internal estimates that Management believes form a reasonable basis for the expected future costs of decommissioning.

Borrowings

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

As at the balance sheet date Northcote had a Production Payment Obligation in respect of its acquisition of the Shoats Creek Properties from Aminex USA Inc, at the balance sheet date the total sum that could potentially be payable totalled $3,150,000. Under the terms of the production payment agreement dated 2014 Northcote will make a payment based on $10 per barrel of oil produced from its working interest barrels. The payment is non-recourse and is only payable out of production from the field, as production is based on variables outside of the Company’s control no provision has been booked in respect of future barrels and each production payment will be charged through the P&L as incurred.

Furthermore on 29 September 2015 it was agreed that the production payment obligation be restructured to reflect the continued weakness in the oil price. It was agreed that the price to be paid would be defined by the trailing 30 day average WTI oil price as follows:

There were no capital commitments authorised by the Directors or contracted other than those provided for in these financial statements for at 31 December 2015 (31 December 2014: None).

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

The details of transactions with related parties are detailed in the table below:

The loan note to Randall Connally at 31 December 2015 was converted into equity subsequent to the year-end. Compensation paid to key management personnel including Directors, Executive Directors and senior management is disclosed in note 8.

On 15 March 2016 Northcote completed an asset sale to Gulf Coast Western, Inc. (‘GCW’),of a 50.0% working interest and 36.0% net revenue interest in the Lutcher Moore #20 well and the right to participate in future Frio and Cockfield wells and a 25.0% working interest and 18.0% net revenue interest in the Wilcox formation. As consideration, Northcote was entitled to US$500,000.00 in cash, including US$100,000 upfront; furthermore GCW will carry Northcote in an amount equal to 10.0% (of 100%) WI in each of the next four wells drilled and Northcote will retain a net 1.72% over-riding royalty interest (‘ORRI’) in the Cockfield and Frio formations and 0.86% ORRI in the Wilcox formation on every well in which GCW participates (including the next four wells and any subsequent wells).

Also on 15 March 2016 Northcote agreed with Shoats Creek Development, Inc. (‘SCDI’), Northcote’s partner and the operator of the Shoats Creek Field, whereby Northcote acquired an additional 20.0% WI and 14.4% NRI in the Cockfield for US$67,200 to be funded through the issuance of 80,738,178 ordinary shares of no par value each in Northcote at a price of US$0.00083 per Ordinary Share. Also Northcote issued 100,505,706 new Ordinary Shares to fund the purchase price associated with the acquisition of the additional Cockfield interest referenced herein and to re-pay US$17,063.76 in invoices due a third-party contractor.

On 23 March 2016 Northcote Energy announced it has raised £450,000 via the issue of 1,428,571,429 new ordinary shares of no par value each in the capital of the Company (‘the Placing Shares’) at a placing price of 0.0315 pence per Ordinary Share

20 April 2016 Northcote announced the issue of 1,587,301,587 new ordinary shares of no par value each in the capital of the Company at a placing price of 0.0315 pence per Ordinary Share to raise gross proceeds of £500,000. In addition, in connection with the Placing the Company has agreed to award Cornhill Capital Limited, the Company’s Broker and Placing Agent (‘Cornhill’), warrants over 158,730,159 Ordinary Shares valid for two years from the day of the Placing, which shall give Cornhill the right to acquire 158,730,159 Ordinary Shares of the Company at a price of 0.0315 pence per Ordinary Share.

On 27 April 2016 Northcote announced that it had exercised its right to acquire a 3.75% working interest in the Tuba Obi East Technical Assistance Contract.