Nighthawk Energy Regulatory News (HAWK)

26 May 2017

 NIGHTHAWK ENERGY PLC

("Nighthawk" or "the Company")

Final Results for the year ended 31 December 2016

Nighthawk, the US focused oil development and production company (AIM: HAWK and OTCQX: NHEGY), announces its final results for the year ended 31 December 2016.

Operational Summary

· Sales volumes

o Gross oil sales for 2016 of 483,195 bbls (394,424 bbls net to Nighthawk's net revenue interest1), down from 2015 sales volumes of 653,431 gross bbls (536,972 bbls net)

o Gross average daily oil sales for 2016 of 1,320 bbls/day (1,077 bbls day net) (2015: 1,791 bbls gross, 1,471 bbls net)

· Implemented and commenced operations of the Company's Arikaree Creek water flood Pilot Project

Financial Summary

· Group revenues decreased 30.8% to US$18.0 million in 2016 from US$29.6 million in 2015; mainly due to the 26.5% decrease in net sales volumes and a $4.9 million decrease in gains on hedging instruments

· Normalised EBITDA2 for 2016 of $5.8 million or US$ 12.10 per gross barrel sold as compared to US$14.5 million or US$22.17 per gross barrel sold for 2015

· Non-cash impairment of $7.1 million attributable to exploration costs included in intangible assets

· Obtained bank waivers of all debt non-compliance through 30 June 2017, the maturity date of the Company's reserve based loan facility. The Company is in negotiations over an extension to the maturity date and believe an equitable arrangement can be reached with the bank prior to that time.

The audited report and accounts for the year ended 31 December 2016 will be available on the Company's website at www.nighthawkenergy.com later today and will be posted to Shareholders, as applicable, together with the notice of Annual General Meeting and Form of Proxy shortly.

The financial information in this announcement does not constitute the Company's complete statutory financial statements for the year ended 31 December 2016 or 2015 within the meaning of section 434 of the Companies Act 2006, but is extracted from those financial statements. References to 'financial statements' in this announcement should not be considered to refer to the complete statutory financial statements. The Group's Auditor has reported on those financial statements; its reports were unqualified, but did contain an emphasis of matter paragraph in respect of the material uncertainty in respect of the going concern disclosure set out in Note 2.

The Auditor's Report did not contain statements under sections 498(2) or (3) of the Companies Act 2006. The emphasis of matter is set out below:

Emphasis of matter - Going concern

The audited statutory financial statements include an emphasis of matter (without modification of the audit opinion) concerning the group's ability to continue as a going concern. The Group's and Company's cash flow forecasts indicate that its ability to meet its liabilities as they fall due for next 12 months is dependent upon successfully extending the Commonwealth Bank of Australia ('CBA') existing loan facility which matures on 30 June 2017 on terms acceptable to the Company whilst alternative funding is secured. The ability to secure alternative funding is expected to depend on the success of the waterflood project and associated oil reserves upgrade. Whilst the Directors are confident that extensions to the CBA loan facility can be obtained, that alternative funding can be secured and that the waterflood project will prove successful and deliver the necessary increase in oil reserves, the outcomes of these negotiations and the waterflood project are unknown. These conditions indicate the existence of a material uncertainty which may cast significant doubt as to the Group's and Company's ability to continue as a going concern. The financial statements do not include the adjustments that would result if the Group or the Company was unable to continue as a going concern.

Notes and Definitions:

1. Net revenue interest (NRI) - Nighthawk's share of oil, gas, and associated hydrocarbons produced, saved, and marketed, after satisfaction of all royalties, overriding royalties, or other similar burdens on or measured by production of oil, gas, and associated hydrocarbons

2. Normalised EBITDA is operating profit adjusted for depreciation, amortisation, and contribution from test revenue, exceptional expenses.

"Group" Nighthawk Energy plc and its subsidiaries

"Parent Company" Nighthawk Energy plc

Enquiries:

This announcement contains inside information under the Market Abuse Regulation (EU) No. 596/2014. Upon the publication of this announcement, this inside information is now considered to be in the public domain.

Chairman's Statement

(all amounts are shown in US$)

When we wrote you a year ago, the oil market was in a much different position. The price of oil at West Texas Intermediate ("WTI") had reached a low price below $27 per barrel; there was uncertainty as to where OPEC and the oil and gas industry would go; and Nighthawk was facing significant challenges with our bank and future projects. Today, oil is near $50 per barrel and showing some signs of improvement and we have an exciting project in progress heading into 2017. Looking back over the past year, I am proud of the way our team responded positively and creatively to the challenges that faced the Company. We maintained our disciplined business approach and navigated this challenging time, emerging stronger than before.

Our focus remained on creating shareholder value. We continued to focus our efforts within one of the top-tier economic basins in the United States, the Denver-Julesburg basin. Although we did not drill any new wells during 2016, the Company completed its Water Flood Pilot Project in our Arikaree Creek field ("Pilot Project"). This project, if successful, is expected to provide increased reserves in the range of 1.5 Mmbbls to 2.3 Mmbbls. The Pilot Project covers roughly 700 of the total 1,400 acres in the Arikaree Creek field. The Company raised the required project financing in July from supportive stakeholders and began construction and implementation of the project. In November, injection commenced into the first well. We have started to see results and, based upon initial estimates, believe that there is significant upside both in reserves and production to be realized later this year. The remaining 700 acres provide an opportunity for development and the Company expects that in 2017, an application will be filed with the Colorado Oil and Gas Conservation Commission for development of the Arikaree Creek Northern acreage as a water flood project. Once approval is received, the Company expects to be able to capitalize on additional water flood volumes at a reduced price, as much of the infrastructure already exists within the Pilot Project. In addition, management continues to research, evaluate and investigate existing acreage for high quality, low risk development opportunities. The Company has over 70 miles of 3-D seismic and, with available cash flows, could exploit potential resources.

From a financial standpoint, fiscal 2016 was a year managing assets, opportunities and expectations. Heading into the year, oil prices in January averaged $31.78 per barrel. This low pricing created an environment where asset preservation, mainly cash, became a focal point for most oil and gas companies, including Nighthawk. The Company entered 2016 with approximately $6.0 million in cash but due to debt covenant violations, had to pay down $4.0 million of our reserve based loan in January 2016. Fortunately, the Company's hedging program had 197,000 bbls of oil hedged at an average price per barrel of $61.41. Through headcount and salary reductions, improved efficiencies in operations and a level of dedication by our team, Nighthawk was able to survive this period and emerged 2016 with $5.6 million in cash on hand.

As we look ahead, the future looks promising for Nighthawk and expectations continue to be high. With the potential of two water flood projects, over 150,000 net acres of undeveloped acreage and oil prices currently stabilizing, increased value creation is within reach. With the successful implementation of our water flood Pilot project, we have begun planning the Northern water flood project and evaluating our acreage position for potential drilling locations with reduced risk from 3-D seismic. Challenges still lie ahead including the refinancing of our existing debt facility, however, we believe we are well positioned to overcome these.

I speak for the Board of Directors and all the employees of the Company in expressing our gratitude for your support.

Rick McCullough

Executive Chairman

26 May 2017

Chief Financial Officer's Statement

(all amounts are shown in US$)

The following information relates to the accounts of Nighthawk Energy plc and its wholly-owned subsidiaries, collectively "Nighthawk" or the "Company".

As shown in the information that follows, 2016 was a year of challenges, uncertainty and volatility for the oil and gas industry and for Nighthawk. We began the year with oil prices being in a depressed state with the January 2016 realized oil price being $31.78. Fortunately, the oil market rebounded slightly and the Company realized an average sales price of $38.10 for the year 2016. This compares to $40.47 for 2015 and $82.16 for 2014. The low-price environment also impacted our Reserve Based Loan ("RBL") with our primary lender, Commonwealth Bank of Australia ("CBA"). Due to a decrease in reserve values, Nighthawk was required to pay down its RBL facility by $4.0 million in January 2016 and renegotiate its credit facility. The Company was able to amend the credit agreement with CBA to provide relief for many of the loan covenants and to extend the loan's maturity date until 30 June 2017. See Note 2 in the Notes to the Consolidated Financial Statements for further discussion.

From a financing side, the Company secured financing from existing loan and shareholders in the amount of $3.0 million to fund the Arikaree Creek Water Flood Pilot Project. As part of this financing, certain of the Company's existing loan note holders agreed to defer their interest until July 2017. In return for this consideration, the deferred interest earns a 15% coupon rate and the opportunity to convert the deferred interest into net shares of the Company. On 5 April 2017, the shareholders of the Company approved the authorities to permit the issuance of new shares in lieu of deferred interest, should the noteholders so elect.

 The Company reported a Net Loss of $14.2 million for the year ended 31 December 2016 as compared to a net loss of $70.3 million for the year ended 31 December 2015. The decrease in net loss was due primarily to reduced non-cash impairments, which for the year ended 31 December 2016 were $7.1 million versus $75.1 million for the year ended 31 December 2015, as well as the release of contingent consideration provision of $2.7 million in 2015. The 2016 impairment charges relate to the assessment of the recoverability of the Company's undeveloped assets. This assessment is based upon factors such as market conditions, current spot and forward prices of oil, and future exploration and development plans. Due primarily to the continued depressed oil prices and no current plans to pursue an aggressive drilling program, $7.1 million was written off or impaired relating to the undeveloped assets as at 31 December 2016 as compared to $40.5 million at 31 December 2015.

Of the total impairment recorded at 31 December 2015 of $75.1 million, $38.5 million was attributable to exploration costs included in intangible assets and a $36.1 million was attributable to property, plant and equipment. Of the total impairment for property, plant and equipment, $11.5 million was related to leasehold land, $10.2 million was related to plant and equipment and $14.4 million related to production assets. The remainder of $0.5 million was attributable to costs incurred on wells previously fully impaired.

Net loss was also impacted by an $11.6 million reduction of total revenue to $18.0 million for the year ended 31 December 2016 as compared to $29.6 million for the year ended 31 December 2015. This decrease is primarily due to a 26.5% decrease in net sales volumes and a $4.9 million reduction in revenue from hedging.

A more detailed discussion of the results is presented below.

Financial Results

Revenue

The following is a comparative summary of net oil sales volumes, prices and revenues, including the impact of commodity derivative settlements:

The $6.7 million or 30.8% decline in oil revenues is the result of the 26.5% decrease in net sales volumes, due primarily to the natural decline of the Company's reservoirs, and a $2.37 or 5.8% per barrel decline in the price received. The Company, as part of its hedging program, also realised $3.7 million of gains resulting from hedging instruments settled during the year and a loss of $744,000 resulting from mark-to-market derivative instruments.

Sales Volume

The results of the Company's sales are shown in the following table:

The decline in net sales volumes of 142,548 or 26.5% is indicative of normal depletion of the Company's reserves offset by the workover and production enhancement projects performed in 2016.

Cost of Sales

The following is a comparative summary of cost of sales:

The increase in lease operating costs per barrel is primarily due to the decrease in sales volumes. The fixed charges associated with the operation of the Company's wells has lower volumes by which to be spread across. With decreased sales revenue, there have also been corresponding reductions to severance taxes, contribution from test revenue, and production profit shares and royalties. Depreciation shown above only includes the depreciation related to operating related assets and excludes office equipment and vehicle depreciation, which is recorded as part of general and administrative expenses. Depreciation has increased as compared to prior year as a result of a decline to the reserve base as at 31 December 2015, which resulted in the depreciation rate being higher on a per barrel rate than in 2015. The decline in reserve base as at 31 December 2015 was adversely impacted by a decline in oil prices and the corresponding reduction in well economics.

Administrative Expenses

Administrative expenses decreased $1.7 million or 23.2% to $5.8 million for the year ended 31 December 2016 from $7.5 million for the year ended 31 December 2015 primarily due to reductions in legal costs, reduction of headcount and overall salary reductions.

Financing Costs

Financing costs increased $3.1 million or 60.9% to $8.2 million for the year ended 31 December 2016 from $5.1 million for the year ended 31 December 2015 due primarily to the write off of deferred loan costs of $710,000, an increase in total interest expense of $678,000 and increase in the exchange rate losses on financial liabilities of $1.4 million.

Normalised EBITDA

Normalised EBITDA ("NEBITDA") is presented to provide an analysis of the Company's operations, excluding certain non-cash related items. NEBITDA is defined as operating profit or loss adjusted for interest, income taxes, depreciation, amortisation, test revenue contribution adjustments, and exceptional administrative expenses. For the year ended 31 December 2016, NEBITDA was $5.9 million as compared to $14.5 million for the year ended 31 December 2015. This decline in NEBITDA reflected the decline in the price of crude oil, a decrease in production volumes and a decrease in revenue from the Company's commodity derivatives. NEBITDA per gross and net barrel sold was $12.10/bbl and $14.83/bbl for the year ended 31 December 2016, respectively, as compared to $22.17/bbl and $26.98/bbl, respectively, for the year ended 31 December 2015.

 The following table reflects the calculation to reconcile the net loss under IFRS to NEBITDA for 2016 and 2015.

The following table provides the consolidated income statement to arrive at normalised operating profit and NEBITDA.

1. Normalised operating profit is operating profit adjusted for DD&A, contribution from test revenue and exceptional administrative expenses.

 Cash flows

The following is a comparative summary of cash flow from operating, investing and financing activities:

Cash flows from operating activities

For the year ended 31 December 2016, cash flow from operating activities was $6.8 million as compared to cash flows of $16.7 million for the year ended 31 December 2015 reflecting the decrease in NEBITDA discussed above.

Net Cash flow from investing activities

For the year ended 31 December 2016, net cash flow used in investing activities was $3.5 million and comprised principally of capital expenditures for the Pilot Project. For the year ended 31 December 2015, net cash flow used in investing activities was $26.4 million and comprised principally of capital expenditures in the drilling and completion of new wells. The decline in spending in 2016 as compared to 2015 of 86.8% was a result of reduced cash available commensurate with the decline in economics within the oil and gas industry.

Net cash flow from financing activities

For the year ended 31 December 2016, net cash from financing activities during the year totalled $3.4 million and comprised principally of $3.0 million raised via debt facilities offset by $4.0 million in debt repayments and $2.3 million in interest payments. For the year ended 31 December 2015, net cash flow from financing activities totalled $10.7 million and was comprised of $16.7 million proceeds from debt facilities, offset by $3.0 million in debt repayments and $3.1 million in interest payments.

Debt Facilities

The Company had the following outstanding debt at 31 December 2016:

The above table only includes the outstanding principal and coupon interest rate and does not include the effect of account discounting or deferred interest rate. During 2016, two significant debt related activities occurred. On 8 January 2016, the Company completed negotiations with CBA to include a reduction to the net borrowing base from $27.0 million to $23.0 million. As part of these negotiations, the Company was required to pay $4.0 million in January 2016 to reduce the outstanding loan balance to the net borrowing base amount. The CBA facility covenants were amended to revise the leverage ratio and eliminate the minimum liquidity requirement. At the end of the first quarter of 2016, CBA notified the Company that the borrowing base had been further reduced from $23.0 million to $13.0 million. On 30 June 2016, Nighthawk entered into an amendment, which among other modifications, changed the maturity date of the outstanding loan balance to 30 June 2017.

Also, on 28 July, 2016, the Company entered into a $3.0 million second lien note, with certain existing debt holders, for the purpose of funding the Pilot Project. The notes bear interest at 15% and a one per cent overriding royalty on the incremental volume realised from the Pilot Project. As part of negotiations with CBA to allow for this new secured loan instrument, the Company also agreed to amend the terms of the existing interest bearing unsecured facility agreements issued in 2013 and loan notes under which interest was being paid. This interest is to be deferred during the amended term of the CBA agreement that expires on 30 June 2017, unless extended by CBA at their sole discretion. The loan notes under which the interest was deferred have the option to receive shares or cash for the amounts deferred. See Note 19 in the Notes to the Consolidated Financial Statements for more detailed discussion.

Hedging

As at 31 December 2016, the Company held the following oil commodity derivative hedge positions:

Note: All commodity hedge prices are WTI NYMEX, averaged across the total contracts for swap contracts.

One of the commodity hedging swap contracts, entered into during 2015, is accounted under IFRS hedge accounting in respect of the Company's commodity derivative hedge positions and represents a total of 17,350 remaining bbls. Under hedge accounting, the change in fair value is recorded as an equity movement in the cash flow hedge reserve rather than through the income statement. Upon utilisation of the oil swap when the oil sales take place, the amounts held in equity are recycled to revenue. All other derivative instruments are accounted for as a mark-to-market hedge instrument through profit or loss.

Shareholders' equity

As at 31 December 2016 there were 964,076,330 ordinary shares of 0.25 pence each in issue. Additionally, as at 31 December 2016, a total of up to 911,066,081 new ordinary shares may be issued pursuant to the exercise of 38,750,000 share options, 130,000,000 warrants, 477,033,333 on convertible loan notes and up to 265,282,748 on conversion of deferred interest payments added during 2016.

As at 31 December 2015 there were 964,076,330 ordinary shares of 0.25 pence each in issue. Additionally, as at 31 December 2015, a total of up to 652,383,333 new ordinary shares may be issued pursuant to the exercise of share options, warrants or convertible loan notes.

Dividends

The Directors do not recommend the payment of a dividend for the year ended 31 December 2016.

Cautionary Statement

This Annual Report contains certain judgements, forward-looking statements and assumptions that are subject to the normal risks and uncertainties associated with the exploration, development and production of hydrocarbons. Whilst the Directors and management believe that expectations reflected throughout this Annual Report are reasonable based on the information available at the time of approval of this Annual Report, actual outcomes and results may be materially different due to factors either beyond the Company's reasonable control or within the Company's control but, for example, following a change in project plans or corporate strategy. Therefore, absolute reliance should not be placed on these judgements, assumptions and forward-looking statements.

Kurtis Hooley

Chief Financial Officer

26 May 2017

Consolidated Income Statement

all amounts are shown in US$

Consolidated Statement of Comprehensive Income and Expenditure

all amounts are shown in US$

Consolidated Balance Sheet

all amounts are shown in US$

The financial statements were approved by the Board of Directors on 26 May 2017 and were signed on its behalf by:

Rick McCullough,

Executive Chairman 

Consolidated Statement of Changes in Equity 

for the year ended 31 December 2016

all amounts are shown in US$

Consolidated Cash Flow Statement

all amounts are shown in US$

Notes to the Consolidated Financial Statements

Year ended 31 December 2016

all amounts are shown in US$

1. General Information

Nighthawk Energy PLC (the "Parent") is a company incorporated in England and Wales, under the Companies Act 2006. The address of the registered office is given on the back cover. The nature of the Company's operations and its principal activities are the exploration for, development and sale of, hydrocarbons. The Company operates solely in the state of Colorado USA where it currently owns interests in over 150,000 net mineral acres in and around Lincoln County.

The accompanying financial statements cover the year to 31 December 2016 for the Parent and its subsidiaries (the "Company" or "Nighthawk"). 

2. Significant accounting policies

Basis of accounting

The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union and therefore the Company financial statements comply with Article 4 of the EU Regulations and applied in accordance with those provisions of the Companies Act 2006 applicable to companies reporting under IFRS.

The financial statements have been prepared on the historical cost basis except for derivatives and certain royalty instruments. Historical cost is generally based on the fair value of the consideration given in exchange for the assets at the date of transaction. The principal accounting policies adopted are set out below.

The principal accounting policies set out below have been consistently applied to all periods presented.

Going Concern

The Directors have reviewed cash forecasts, the current operations of the Group and Company and plans for the next 12 months and consider that the use of the going concern basis of accounting and preparation of the financial statements is appropriate however, there is a material uncertainty related to events or conditions that may cast significant doubt about the ability of the Group and Company to continue as a going concern. Currently, the Group and Company are meeting its day-to-day operational working capital requirements and oil prices have stabilized. Successful implementation of the water flood Pilot Project is expected to provide adequate cash flow for the foreseeable future to meet operating cash flow requirements and debt service costs. However, the Directors note there is a material liquidity risk related to the outstanding loan with Commonwealth Bank of Australia ("CBA") given the 30 June 2017 maturity date. The Group's and Company's ability to meet its liabilities as they fall due for next 12 months is dependent upon successfully extending the existing loan facility on terms acceptable to the Group whilst securing alternative funding.

Based on the discussions with CBA and previous extensions, the Board remains confident that necessary extensions can be secured whilst the debt is refinanced. The Board has held discussions with potential alternative lenders and are confident that the requisite funding can be secured on acceptable terms. Whilst the ability to secure alternative funding is expected to depend on the success of the waterflood project and associated oil reserves upgrade the Board remains confident that the project will deliver the required level of production and PDP reserves based on its status.

The financial statements do not include the adjustments that would result if the Group and Company were unable to continue as a going concern.

Basis of Consolidation

Where the Company has control over an investee, it is classified as a subsidiary. The Company controls an investee if all three of the following elements are present: power over the investee, exposure to variable returns from the investee, and the ability of the investor to use its power to affect those variable returns. Control is reassessed whenever facts and circumstances indicate that there may be a change in any of these elements of control.

The consolidated financial statements present the results of the Company as if they formed a single entity. Intercompany transactions and balances between companies are therefore eliminated in full.

Intracompany transactions with subsidiaries are eliminated on consolidation. Transactions, balances, income and expenses with Joint Operations are eliminated to the extent of the Company's interest in these entities.

In accordance with the exemption in IFRS 1, where merger accounting has been used prior to the transition date the accounting method has not been restated.

Any difference between the nominal value of the shares acquired by the Company and those issued by the Company to acquire these shares is accounted for as merger reserve.

Segmental Reporting

The Company has only one operating segment: the production of, exploration for and investment in hydrocarbons in one geographical area, the United States of America.

Significant Customer

The Company sell all its oil production to an independent third party. The Company has alternative buyers available in the event the existing agreement is discontinued

New and amended IFRS standards in interpretations

The following new or revised Standards and Interpretations have been adopted during the year.

At the date of authorisation of these financial statements, the following Standards and interpretations which have not been applied in these financial statements were in issue but not yet effective (and, in some cases, had not yet been adopted by the European Union) (standards not expected to have any impact on the Company are not included):

IFRS 15 is intended to introduce a single framework for revenue recognition and clarify principles of revenue recognition. This standard modifies the determination of when to recognize revenue and how much revenue to recognize. The core principle is that an entity recognizes revenue to depict the transfer of promised goods and services to the customer of an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Management are currently assessing the impact of this standard.

IFRS 16 introduces a single lease accounting model. This standard requires lessees to account for all leases under a single on-balance sheet model. Under the new standard, a lessee is required to recognize all lease assets and liabilities on the balance sheet; recognize amortization of leased assets and interest on lease liabilities over the lease term; and separately present the principal amount of cash paid and interest in the cash flow statement. Management are currently assessing the impact of this standard.

IFRS 9 "Financial instruments" addresses the classification and measurement of financial assets and financial liabilities. The complete version of IFRS 9 was issued in July 2014. It replaces the guidance in IAS 39 that relates to the classification and measurement of financial instruments. IFRS 9 retains but simplifies the mixed measurement model and establishes three primary measurement categories for financial assets: amortized cost, fair value through other comprehensive income (OCI) and fair value through profit or loss. The basis of classification depends on the entity's business model and the contractual cash flow characteristics of the financial asset. Investments in equity instruments are required to be measured at fair value through profit or loss with the irrevocable option at inception to present changes in fair value in OCI. There is now a new expected credit loss model that replaces the incurred loss impairment model used in IAS 39. For financial liabilities, there were no changes to classification and measurement except for the recognition of changes in credit risk in other comprehensive income, for liabilities designated at fair value through profit or loss. Contemporaneous documentation is still required but is different to that currently prepared under IAS 39. Management are currently assessing the standard's full impact.

Joint Operations

The Company participates in Joint Operations, which involve the joint control of assets used in the Company's oil and gas exploration and producing activities.

The Company accounts for its share of assets, liabilities, income and expenditure of Joint Operations in which it holds an interest, classified in the appropriate Balance Sheet and Income Statement headings.

Details of the Company's interests in unincorporated Joint Operations are given in Note 14.

Revenues

Oil revenue represents the sales value of the Company oil production during the year and is recognised when sales transactions can be reasonably measured and the risks and rewards of ownership have transferred substantially to the buyer, which occurs at transfer of the hydrocarbons from the Company's facilities to the purchaser's tanker or infrastructure. Revenue is measured at the Company's share of fair value of the consideration received or receivable and represents amounts receivable for oil products in the normal course of business, net discounts and sales related taxes. Royalty interests are recognised on an accruals basis, in accordance with the substance of the relevant agreement.

Oil and gas assets - exploration and evaluation assets (intangibles)

The Company follows a successful-efforts based accounting policy for oil and gas assets. During the geological and geophysical exploration phase, expenditures are charged against income as incurred. Once the legal right to explore has been acquired, expenditures directly associated with exploration and evaluation are capitalised as intangible assets and are reviewed at each reporting date to confirm that there is no indication of impairment and that development is in progress or planned. If no future exploration or development activity is planned in the leased area, the exploration licence and leasehold property acquisition costs are written off. Pre-leasing expenditures on oil and gas assets are recognised as an expense within the income statement when incurred.

Oil and gas assets - development and production assets

Once a well or project is commercially feasible and technically viable, which in practice is when results indicate that hydrocarbon reserves exist in adequate quantity and there is reasonable evidence that the reserves are commercially viable, the carrying values of the associated exploration license and property acquisition costs and the related cost of exploration wells are transferred to development oil and gas properties after an impairment test. Development and production assets are accumulated generally on a well-by-well basis and represent the cost of developing the commercial reserves discovered and bringing them into production. The cost of development and production assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads, finance costs

capitalised, and the cost of recognising provisions for future restoration and decommissioning. If a drilled well does not show commercially viable reserves, the capitalized costs are written off upon completion of the well.

Property, Plant and Equipment

Property, plant and equipment are stated at historical cost less depreciation and recognised impairment losses. Cost includes expenditure that is directly attributable to the acquisition or construction of these items.

Subsequent costs are included in the asset's carrying amount only when it is probable that future economic benefits associated with the item will flow to the Company and the costs can be measured reliably. All other costs, including repairs and maintenance costs, are charged to the income statement in the period in which they are incurred.

Depreciation is provided on all property, plant and equipment and is calculated on a straight-line basis or unit of production basis as follows:

Assets held under finance leases are depreciated over their expected useful lives on the same basis as owned assets. However, when there is no reasonable certainty that ownership will be obtained by the end of the lease term, assets are depreciated over the shorter of the lease term and their useful lives.

Depreciation of producing assets

The net book values of producing assets are depreciated on a well-by-well basis using the unit-of-production method by reference to the ratio of production in the year and the related economic commercial reserves of the well, taking into account future development expenditures necessary to bring those reserves into production.

Where property, plant and equipment has been acquired for the purposes of exploration, and technical feasibility of the project has yet to be established, the depreciation on the property, plant and equipment is added back to the cost of the intangible assets within exploration costs.

The gain or loss arising on disposal or scrapping of an asset is determined as the difference between the sales proceeds, net of selling costs, and the carrying amount of the asset and is recognised in the income statement.

Impairment of development and production assets

An impairment test is performed at least twice a year or whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. The cash flows are discounted using a pre-tax discounted rate adjusted for risks specific to the assets. The cash generating unit applied for impairment test purposes is generally at the well level, except that a number of individual well interests may be combined as a single cash generating unit where the cash inflows of each well are interdependent, as in a unit. Commercial reserves consist of proved and probable oil, which are defined as the estimated quantities of crude oil where geological, geophysical and engineering data has demonstrated, with a specified degree of certainty, to be recoverable in future years from known reservoirs and which are considered commercially viable. There should be at least a 50% statistical probability that the actual quantity of recoverable reserves will be equal to or more than the amount estimated as proved and probable reserves. Any impairment identified is charged to the income statement. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any depreciation that would have been charged since the impairment.

Impairment of Exploration costs

The Company's intangible exploration cost assets are assessed for impairment when facts and circumstances suggest that the carrying amount of the exploration cost assets may exceed the assets recoverable amount. In accordance with IFRS 6, the Company firstly considers the following facts and circumstances in their assessment of whether the Company's exploration and appraisal assets may be impaired:

• Whether the period for which the Company has the right to explore in a specific area has expired during the period or will expire in the near future, and is not expected to be renewed;

• Whether substantive expenditure on further exploration for and appraisal of mineral resources in a specific area is neither budgeted nor planned;

• Whether exploration for and evaluation of oil in a specific area has not led to the discovery of commercially viable quantities of oil and the Company has decided to discontinue such activities in the specific area; and

• Whether sufficient data exists to indicate that, although a development in a specific area is likely to proceed, the carrying amount of the exploration and evaluation assets is unlikely to be recovered in full from successful development or by sale.

If any such facts or circumstances are noted, the Company, as a next step, performs an impairment test in accordance with the provisions of IAS 36 as set out above.

Asset Retirement Obligation

An asset retirement obligation provision for plugging, abandonment and reclamation costs has been included within the exploration costs intangible assets and production assets and within liabilities based on management's assessment of asset retirement costs that will be incurred at the end of each project's life. The estimated current date cash flows are adjusted for inflation and are discounted at a risk-free rate. The cash flows used in the provision are risk adjusted.

Cash and Cash Equivalents

Cash and cash equivalents comprise cash on hand, deposits held at call with banks and other short-term highly liquid investments with original maturities of three months or less.

Inventories

Inventories are stated at the lower of cost and net realisable value. Costs of inventories are determined on a first-in-first-out basis. Cost comprises direct materials, and where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Net realisable value represents the estimated selling price less all estimated costs of completion and costs necessary to make the sale.

Provisions

Provisions are recognised when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that the Company will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material).

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, a receivable is recognised as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.

Contingent consideration

The Company was party to a deferred contingent consideration agreement in respect of its acquisition of an addition 25% working interest in the Jolly Ranch and Smoky Hill Project in 2012, under which the Company acquired operatorship of the joint operation and increased its interest from 50% to 75%. The Company initially recorded the

fair value of the deferred contingent consideration as part of the acquisition and the obligation is classified as a provision and subsequently carried at the best estimate of the payment that will be required to settle the obligation. Subsequent changes in fair value are recorded in profit or loss. As the contingent consideration provision has expired in January 2017, no amounts are included on the accompanying balance sheet as at 31 December 2016.

Equipment leases

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. The interest element of finance lease payments is charged to profit or loss as finance costs over the period of the lease. All other leases are classified as operating leases.

Operating lease payments are recognised as an expense on a straight-line basis over the lease term, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed.

In the event that lease incentives are received to enter into operating leases, such incentives are recognised as a liability. The aggregate benefit of incentives is recognised as a reduction of rental expense on a straight-line basis, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed.

Foreign Currency

For the purpose of the consolidated financial statements, the results and financial position of each company are expressed in US Dollars, which is the reporting currency for the consolidated financial statements. The functional currency of the Company's subsidiaries is US Dollars. Foreign currency transactions, by company, are recorded in their functional currencies at the exchange rate at the date of the transaction. Monetary assets and liabilities have been translated at rates in effect at the balance sheet date, with any exchange adjustments being charged or credited to the Income Statement.

The Parent Company's functional currency is the British Pound Sterling. On consolidation, the assets and liabilities of the Parent Company are translated into the Company's reporting currency at the exchange rate at the balance sheet date and the income and expenditure account items are translated at the average rate for the reporting period. The exchange difference arising on the translation from functional currency to presentational currency of the Parent Company is classified as other comprehensive income and is accumulated within equity as a translation reserve.

Taxation

Current Taxation

Current tax for each taxable entity in the Company is based on the statutory tax rate enacted or substantively enacted at the balance sheet date and includes adjustments to taxes payable or recoverable in respect of previous periods.

Taxes that arise from production are recorded as cost of sales and accrue as production arises. A deferred tax asset is recorded when there is sufficient certainty that production taxes paid will give rise to tax deductions in future periods.

Deferred Taxation

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. 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.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rate that is expected to apply in the period when the liability is settled or the asset is realised based on tax laws, and rates that have been enacted or substantively enacted at the balance sheet date.

Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited in other comprehensive income, in which case the deferred tax is also dealt with in other comprehensive income.

Financial Instruments

Financial assets and financial liabilities are recognised on the Balance Sheet when the Company becomes a party to the contractual provisions of the instrument.

Trade and other receivables

Trade receivables are measured on initial recognition at fair value, and are subsequently measured at amortised cost using the effective interest method. A provision is established when there is objective evidence that the Company will not be able to collect all amounts due. The amount of any provision is recognised in the income statement.

Trade and other payables

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

Borrowings and equity

Debt and equity instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangement. Borrowings are initially recorded at fair value and subsequently measured at amortised cost using the effective interest method. If the terms of borrowings are modified, the Company determines whether the modification represents a substantial modification under IFRS. A modification is considered substantial if the discounted present value of the cash flows under the new terms, including any fees paid, net of any fees received and discounted using the original effective interest rate, is at least 10% different from the discounted present value of the remaining cash flows of the original financial liability. Borrowings that are considered to be substantially modified

are derecognised and transaction costs associated with such loan modifications, are written off to the income statement. Transaction costs arising from modifications of borrowings that do not qualify as substantially modified are deducted from the liability and amortised prospectively through the effective interest rate method.

Royalty or profit share interests associated with loans are recorded at fair value through profit or loss, unless the royalty terminates upon disposal of the wells or a change in control, when such events form part of the Company's strategy. In such circumstances the royalty is recorded on an accrual basis as production arises. Where royalties are issued in conjunction with debt financing, the initial fair value is treated as a transaction cost and deducted from the loan liability and subsequently amortised through the effective interest rate. The royalty liability is subsequently revalued.

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

Compound instruments

The component parts of compound instruments (convertible notes and loans with detachable warrants) issued by the Company are classified separately as financial liabilities and equity in accordance with the substance of the contractual arrangements and the definitions of a financial liability and an equity instrument. A conversion option that will be settled by the exchange of a fixed amount of cash for a fixed number of the Company's own equity instruments is an equity instrument.

At the date of issue, the fair value of the liability component is estimated using the prevailing market interest rate for similar non-convertible instruments. This amount is subsequently recorded as a liability on an amortised cost basis using the effective interest method until extinguished upon conversion or at the instrument's maturity date.

The conversion option or detachable warrant classified as equity is determined by deducting the amount of the liability component from the fair value of the compound instrument as a whole. This is recognised and included in equity, net of income tax effects, and is not subsequently re-measured. No gain or loss is recognised in profit or loss upon conversion or expiration of the conversion option.

Transaction costs that relate to the issue of the compound instruments are allocated to the liability and equity components in proportion to the fair value of the debt and equity components. Transaction costs relating to the equity component are recognised directly in equity. Transaction costs relating to the liability component are included in the carrying amount of the liability component and are amortised over the lives of the compound instruments using the effective interest method.

If the terms of a compound financial instrument are modified the Company determines whether the modification represents a substantial modification under IFRS. A modification is considered substantial if the discounted present value of the cash flows under the new terms, including any fees paid net of any fees received and discounted using the original effective interest rate, is at least 10% different from the discounted present value of the remaining cash flows of the original financial instrument. Compound financial instruments that are substantially modified are derecognised and transaction costs incurred as part of the loan modifications are recorded to the income statement and equity accounts in proportion to the relative fair value of the debt and equity component at the time of extinguishment. If the transaction costs can be specifically attributed to the new instrument, the portion attributable to the debt component is amortised prospectively through the effective interest rate.

Incremental fair value changes arising from the modification of warrants originally issued as part the compound financial instrument are considered to represent transaction costs and are determined using the Black-Scholes valuation model.

Derivative financial instruments

The Company enters into derivative financial instruments in the form of oil price swaps and costless collars to manage its exposure to oil price risk. Derivatives are initially recognised at fair value at the date the derivative contracts are

entered into and are subsequently re-measured to their fair value at the end of each reporting period. Fair value is determined inclusive of adjustments for the Company's own credit risk and the credit risk of counterparty to the derivative. The resulting gain or loss is recognised in profit or loss immediately, unless the instrument has been designated as a hedging instrument.

Hedge accounting

The Company designates certain hedging instruments, which are derivatives, in respect of commodity price risk, as cash flow hedges. At the inception of the hedge relationship, the Company documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. The Company enters into such derivatives to manage the risk associated with oil price fluctuations and therefore the impact of credit risk adjustments are excluded from the hedging relationship. Furthermore, at the inception of the hedge and on an on-going basis, the Company documents whether the hedging instrument is highly effective in offsetting cash flows of the hedged item attributable to the hedged risk. The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated in a cash flow hedging reserve. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss. The portion of the change in fair value of the derivative attributable to credit risk adjustments is recognised immediately in profit and loss. Amounts previously recognised in other comprehensive income and accumulated in equity are reclassified to profit or loss in the periods when the hedged volumes affects profit or loss, and recorded in the same line as the recognised hedge item.

Hedge accounting is discontinued when the Company revokes the hedging relationship; when the hedging instrument expires or is sold, terminated or exercised; or when it no longer qualifies for hedge accounting. Any gain or loss recognised in other comprehensive income and accumulated in equity at that time remains in equity and is recognised

when the forecast transaction is ultimately recognised in profit or loss. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in equity is recognised immediately in profit or loss.

Finance expenses

Interest is recognised using the effective interest method which calculates the amortised cost of a financial liability and allocates the interest expense over the relevant period. The effective interest rate is the rate that discounts estimated future cash payments, through the expected life of the financial liability to the net carrying amount of the financial liability.

Share-Based Payments

Equity settled share-based payments are measured at the fair value of the equity instruments at the date of grant. The fair value includes the effect of market-based vesting conditions. Details regarding the determination of the fair value of equity settled share-based transactions are set out in Note 23.

The fair value determined at the date of grant of the equity-settled share-based payment is expensed on a straight-line basis over the vesting period, based on the Company's estimate of the number of equity instruments that will eventually vest. At each balance sheet date, the Company revises its estimated number of equity instruments expected to vest as a result of the effect of non-market-based vesting conditions. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to equity reserves. Where an equity-settled award is forfeited, the cumulative charge expensed up to the date of forfeiture is credited to the Income Statement.

Warrants

Share warrants have been issued in lieu of interest on certain convertible loans in the prior years; as such the associated cost of these is accounted for as a finance cost.

The fair value of the warrants is measured at the grant date. The Black Scholes valuation model is used to assess the fair value, taking into account the terms and conditions attached to the warrants. The finance costs recorded are measured by reference to the fair value of warrants.

Share warrants are recognised as an increase in equity immediately on issue as warrants vest immediately. The expense associated with the share warrants is recognised in accordance with the substance of the transaction, either as an immediate expense in the income statement or as a transaction cost associated with the issue or extension of loan notes.

Employment Benefits

Provisions are made in the financial statements for all employee benefits. Liabilities for wages and salaries, including non-monetary benefit and annual leave obliged to be settled within 12 months of the balance sheet date, are recognised as accrued liabilities.

The Company's contributions to defined contribution pension plans are charged to the income statements in the period to which the contributions relate.

3. Critical accounting judgements and estimates

In the application of the Company's accounting policies, which are described in Note 2, the Directors and management are required to make critical accounting judgments and assumptions. The assumptions are based on historical experience and other factors that are considered to be relevant.

Estimates and judgments are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the prevailing circumstances.

The following are the critical judgements that the Directors have made in the process of applying the Company's accounting policies, and that have the most significant effect on the amounts recognised in the financial statements.

Exploration and Evaluation Costs

The Company's accounting policy leads to the capitalisation of tangible (Note 13) and intangible (Note 12) fixed assets, where it is considered likely that the amount capitalized will be recoverable by future exploitation, sale or, alternatively, where the activities have not reached a stage which permits a reasonable assessment of the existence of reserves. This requires management to make estimates and assumptions as to the future events and circumstances, especially in relation to whether an economically viable extraction operation can be established. Such estimates are subject to change and, should it become apparent that recovery of the expenditure is unlikely following initial capitalisation, the relevant capitalised amount will be written off to the Income Statement.

Judgment is further required in determining the date at which exploration assets achieve commercial production and commence depreciation. In forming that assessment, the Company considers factors such as the availability of economically recoverable reserves and the production rates delivered by wells.

Carrying value of exploration, development and producing properties

Management reviews intangible exploration cost assets (Note 12) for indicators of impairment under IFRS 6 at the end of each reporting period. This review of assets for potential indicators of impairment requires judgment including whether renewal of licences is planned, interpretation of the results of exploration activity and the extent to which the Company plans to continue substantive expenditure on the assets. In determining whether substantive expenditure remains in the Company's plan, management considers factors including future oil prices, plans for lease renewal and development and future drilling plans. If impairment indicators exist, the assets are then tested for impairment and carried at the lower of the estimated recoverable amount and net book value.

The carrying value of development and producing oil and gas assets (Note 13) is subject to judgement as to their recoverable value. The calculation of recoverable value requires estimates of future cash flows within complex value-in-use models. At each balance sheet date the Directors review the carrying amounts of the Company's development and producing properties to determine whether there is any indication that those assets have suffered an impairment loss.

For development and producing oil and gas properties, the following are examples of the indicators used:

• A significant and unexpected decline in the asset's market value or likely future revenue;

• A significant change in the asset's reserves assessment;

• Significant changes in the technological, market, economic or legal environments for the asset; or

• Evidence is available to indicate obsolescence or physical damage of an asset, or that it is underperforming expectations.

The assessment of impairment indicators requires the exercise of judgement. If an impairment indicator exists, then the recoverable amount of the cash-generating unit and/or individual asset is determined based on the higher of value-in-use and fair value less cost of disposal calculations. This requires the use of estimates and assumptions, such as: future oil prices, life of field/well, discount rates, operating costs, future capital requirements, exploration potential, recompletion potential, oil reserves and operating performance.

The key estimates were as follows:

· Oil prices - determined based on the market WTI forward curve as at year end, together with a discount to reflect the terms of sales contracts.

· Oil reserve quantities - determined based on estimated economically recoverable reserves, based on external competent person assessments.

· Production Costs-costs incurred to produce oil

· Transportation costs

· Discount rate - pre-tax discount rate specific to the risks associated with the assets determined at 12%.

· Capital development costs

In addition, wells which have been plugged and abandoned during the year, or wells for which a decision has been taken during the year to plug and abandon the well, have been impaired.

These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or Cash Generating Units (CGUs).

The Company has recorded an impairment of $7.1 million in 2016 as compared to $75.1 million in 2015, in respect of exploration costs and property, plant and equipment as detailed in Note 9. A 10% decrease in realised oil prices would increase the impairment by $nil million. An increase in the discount rate to 15% would increase impairment by $nil million. The Directors consider the inputs used to be appropriate best estimates.

Reserve Estimates

Reserves are estimates of the amount of oil that can be economically and legally extracted from the Company's properties. In order to calculate the reserves, estimates and assumptions are required for a range of geological, technical and economic factors, including those detailed above.

Estimating the quantity and/or grade of reserves requires the size, shape and depth of fields to be determined by analysing geological data such as drilling samples and 3D seismic. This process may require complex and difficult geological judgements and calculations to interpret the data.

Given that economic assumptions used to estimate reserves may change from year to year, and because additional geological data is generated during the course of operations, estimates of reserves may change from year to year.

Changes in reported reserves may affect the Company's financial results and financial position in a number of ways, including the following:

• Asset carrying values, detailed in Notes 12 and 13, may be affected by possible impairment due to adverse changes in estimated future cash flows and the commercial viability of reserves.

• Depreciation, depletion and amortisation (detailed in Note 5) that is charged in the Income Statement may change where such charges are determined by the unit of production basis, or where the useful economic life of asset changes.

· Provisions for plugging and abandoning a well may change as a result of revisions to the timing of such plugging and abandonment efforts.

Judgments associated with debt finance

During the year, the Company obtained a new loan as detailed in Note 19 and modifications to existing instruments. The accounting requires judgments and estimates which are set out in the note including the valuation of the royalty associated with the new loan and assessments as to the valuation of conversion rights associated with the modified debt.

Derivative valuations

The Company's oil swaps and costless collars are carried at fair value. The fair value is determined based on mark-to-market valuations provided by third parties, which in turn is dependent on estimates regarding risk free discount rates and oil prices. Additionally, when material, the mark-to-market valuations are adjusted for credit risk associated with the Company and counterparty which are determined based on credit spreads applicable to the Company and the counterparty. Refer to Note 17 for details.

4. Revenue

An analysis of the Company's revenue is as follows:

5. Operating loss

The operating loss before taxation for the years has been arrived at after charging:

6. Auditor's remuneration

The analysis of auditor's remuneration is as follows:

7. Staff Costs

The aggregate payroll costs of the employees, including both management and executive Directors, were as follows:

Average number of persons employed by the Company during the year was as follows:

The number of Directors during 2016, accruing benefits under money purchase pension scheme arrangements was one in 2016 as compared to two during 2015.

During the year no Directors exercised any share options.

During 2015 Steve Gutteridge, who retired from the Board of Directors on 30 September 2014, exercised share options to acquire 1,700,000 ordinary shares.

Details of each director's remuneration and share options granted are included in the Remuneration Report.

8. Finance Costs

Finance costs include certain non-cash transactions in respect of effective interest rate charges and losses on loan rescheduling.

9. Exceptional administrative expenses

The Company assessed the recoverability of its undeveloped exploration assets based upon factors such as market conditions, current spot and forward prices of oil, and future exploration and development plans. Due primarily to the continued depressed oil prices, and with no plans to pursue an aggressive drilling program, $7.1 million, was written off as at 31 December 2016 as compared to $40.5 million as at 31 December 2015. No other impairment were made for 2016.

During 2015, the Company drilled five wells that did not result in commercial economic reserves. As a result, the costs to drill and complete these wells were written off as of 31 December 2015, and totalled $5.2 million. In addition, an impairment charge of $28.9 million was taken to the income statement and represented an impairment of certain wells which mainly arose from a reduction in the spot and forward oil price assumptions used in estimating the future discounted cash flows for each well.

Of the total 2015 impairment of $75.1 million, $38.5 million was attributable to exploration costs included in intangible assets, and $11.5 million, $10.2 million and $14.4 million were attributable to leasehold land, plant and equipment and production assets, respectively, or a total of $36.1 million included in property, plant and equipment. An additional $0.5 million was recorded as impairments for costs incurred during the current period for wells which had been fully impaired in prior periods.

During 2016, the Company released $333,500 of the contingent consideration provision as compared to $2.7 million during 2015. Refer to Note 30.

10. Taxation

The Parent Company is subject to taxation in the United Kingdom at an estimated rate of 20% for 2016 and 20.25% in 2015, and the Company's subsidiaries are subject to taxation in the United States at an estimated rate of 38.00% for 2016 and 2015.

As of 31 December 2016, there was a current tax credit of $Nil arising in the US in the financial year (2015: $394,858 current tax credit). No tax charge arose in the UK for either 2016 or 2015.

The reasons for the differences between the actual tax charge for the year and the standard rate of corporation tax in the United Kingdom applied losses for the year are as follows:

No deferred tax asset has been recognised at 31 December 2016 and 2015, for the net federal tax operating loss carry forwards of $172.1 million and $163.6 million, respectively, which are available under US tax statutes, due to uncertainty over the timing of future profits as well as the fact that the Company's ability to utilise some of these tax losses is restricted under Section 382 of the Internal Revenue Code to an amount of $0.4 million per annum. The unrecognized taxable losses in the U.S. can be carried forward for U.S. Federal and Colorado State income tax purposes for up to 20 years. These losses, if not utilized, will expire in the years 2026 through 2033.

A deferred tax asset in respect of $13.2 million at 31 December 2016 and $20.4 million at 31 December 2015 of taxable losses available in the UK has not been recognised due to the uncertainty over timing of future profits. The taxable losses available in the UK can be carried forward indefinitely.

11. Loss Per Share

Loss per share is calculated by dividing the loss attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.

The Company has 911,066,081 potentially dilutive shares in issue, in respect of options to acquire 38,750,000 shares of the Company, warrants to acquire 130,000,000 shares of the Company, loan conversion rights to acquire 477,033,333 shares of the Company and deferred interest conversion rights to acquire 265,282,748 shares of the Company. Due to the Company's reported losses, share options and warrants were not taken into account when determining the weighted average number of ordinary shares in issue during the year as the options and warrants were anti-dilutive. Subsequent to the balance sheet date, no shares were issued.

The loss and weighted average number of ordinary shares used in the calculation of basic and diluted net loss per share are as follows:

12. Intangible Assets

Management reviews each exploration project for indication of impairment at each balance sheet date based on IFRS 6 criteria. Indicators of impairment were considered, which included expiring leases, future development plans for the leases, abandoned leases/wells and the estimated fair value less cost to sell of the underlying assets.

Due to these indicators being present at 31 December 2016 and 2015, and the resultant impairment test, impairments were recorded in the 2016 and 2015 financial year. Consequentially, certain full and partial impairments, as appropriate, of the remaining values were recognised, as disclosed in Note 9.

13. Property, Plant and Equipment

Impairments during the 2015 financial year relate to 1) the decision taken to plug and abandon certain wells and 2) a reduction in the net present value of the producing assets of the Company due primarily to the decline in oil prices used to estimate the value of wells. Consequentially, certain impairments have been recognised, as disclosed in Note 9. The Company determines the recoverable amount for individual assets on a well-by-well basis. 

For the year ended 31 December 2016, depreciation charges of $4,083,814 and $193,531 relating to leasehold land and plant and equipment, respectively, have been capitalised within intangible assets additions. For the year ended 31 December 2015, depreciation charges of $5.3 million have been capitalised within intangible assets additions.

14. Investment in Jointly Controlled Operations

As at 31 December 2016, the Company was involved in a joint development agreement ("JDA") with an unrelated third party. The El Dorado Joint Development area covers 40,372 net mineral acres around the Company's existing acreage. As the owner of a 15% working interest, the Company has the right, but is not obligated, to participate in the drilling of any well in the Joint Development area.

As at 31 December 2015, the Company also was involved in a second JDA. The Monarch Joint Development area is operated by the Company, covers 23,619 net mineral acres southwest from the Arikaree Creek field and Snow King Project. To earn its 50% working interest in the underlying acreage, the Company bore 100% of the $3.4 million in costs to drill four wells prior to 31 December 2015, three of which were dry holes, and one of which was completed to produce a minimal amount of crude oil, rendering it uneconomic. All of the costs to drill the four wells were impaired at 31 December 2015. In addition, the Company was to bear 100% of the costs to drill two additional wells on or before 30 June 2016, with estimated dry hole costs of $0.60 million per well, and completed well costs of $0.6 million per well. During 2016, the Company renegotiated the JDA with its partner whereby Nighthawk would: 1) make a payment to JDA partner of US$500,000; 2) Nighthawk would complete an up-hole zone in the Monarch 10-15 well, at the Company's expense; 3)Nighthawk would assign an increased revenue share from the Monarch 10-15 well and a 2% net overriding revenue interest in the land section surrounding the Monarch 10-15 wellbore; and 4) in exchange for the above consideration, the Company received from the JDA partner, an assignment of their working interest in all remaining acreage in the JDA.

During 2015, a 3D seismic program over the entire area was completed, covering both the Monarch and El Dorado Joint Development acreage. By the terms of the JDA, the Company bore 100% of the $2.3 million cost of the seismic in exchange for a proportional percentage ownership in the data within the Monarch Joint Development area. This cost is included in Intangible Assets.

15. Inventory

Inventory includes oil held in tanks at year end in addition to casing, tubing and equipment to be used in existing and future wells. The inventories are held at the lower of cost or net realisable value.

16. Trade and Other Receivables

The Directors consider the carrying value of trade and other receivables to approximate to their fair value.

17. Derivative Financial Assets and Liabilities

18. Trade and Other Payables

Trade and other payables principally comprise amounts outstanding for trade purchases and ongoing costs. The Directors consider that the carrying amounts of trade and other payables are approximate to their fair values.

19. Borrowings

The following table sets out the carrying values of the loans and borrowings: