Management's Responsibility for Financial Statements	2
Independent Auditor's Report	3
Consolidated Statements of Financial Position	4
Consolidated Statements of Operations and Comprehensive Loss	5
Consolidated Statements of Changes in Shareholders' Equity	6
Consolidated Statements of Cash Flows	7
Notes to the Consolidated Financial Statements	8 – 35
Corporate Information	36

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The consolidated financial statements and accompanying notes to the consolidated financial statements are the responsibility of the management of the Company. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS").

Preparation of consolidated financial statements is an integral part of management's broader responsibilities for the ongoing operations of the Company. Management maintains a system of internal accounting controls to ensure that properly approved transactions are accurately recorded on a timely basis and result in reliable consolidated financial statements.

The Board of Directors, through its Audit Committee, monitors management's financial and accounting policies and practices and the preparation of these consolidated financial statements. The Audit Committee meets periodically with external auditors and management to review the financial results and discharge their responsibilities. Specifically, the Audit Committee reviews with management and the external auditors the consolidated financial statements and related management discussion and analysis of the Company prior to submission to the Board of Directors for final approval. The external auditors have full and free access to the Audit Committee to discuss auditing and financial reporting matters.

The shareholders have appointed Deloitte LLP as external auditors of the Company and, in that capacity they have examined the consolidated financial statements and the accompanying notes to the consolidated financial statements for the years ended December 31, 2013 and 2012. The Independent Auditor's Report to the shareholders follows.

"Neill Carson" "Graham Heath"

Neill Carson Graham Heath President and CEO Interim CFO April 29, 2014

INDEPENDENT AUDITOR'S REPORT

To the Shareholders of Iona Energy Inc.:

We have audited the accompanying consolidated financial statements of Iona Energy Inc., and its subsidiaries, which comprise the consolidated statements of financial position as at December 31, 2013, December 31, 2012 and January 1, 2012 and the consolidated statements of operations and comprehensive income (loss), consolidated statements of changes in shareholders' equity and consolidated statements of cash flows for the years ended December 31, 2013 and December 31, 2012, and a summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Iona Energy Inc., and its subsidiaries, as at December 31, 2013, December 31, 2012, and January 1, 2012 and its financial performance and its cash flows for the years ended December 31, 2013 and December 31, 2012 in accordance with International Financial Reporting Standards.

"Deloitte LLP"

Chartered Accountants

April 29, 2014 Calgary, Canada

Iona Energy Inc. Consolidated Statements of Financial Position

(In thousands of US dollars)	Notes	December 31, 2013	December 31, 2012 (Note 20)	January 1,, 2012 (Note 20)
ASSETS
Current Assets Cash and cash equivalents Accounts receivable Prepaid expenses Restricted cash Inventory	8	\$ 19,808 15,126 551 78,024 1,802	\$ 15,579 3,230 1,272 710 -	\$ 40,914 381 205 1,271 -
Derivative instruments	17	293	-	-
Total Current Assets		115,604	20,791	42,771
Restricted cash Deferred costs Exploration and evaluation assets Property and equipment Goodwill	8 9 9 10 4	7,090 - 134,163 274,164 14,058	9,098 38,552 136,048 71 -	51 310 27,763 20 -
Total Non-Current Assets		429,475	183,769	28,144
Total Assets		\$ 545,079	\$ 204,560	\$ 70,915
LIABILITITES AND SHAREHOLDERS' EQUITY
Current Liabilities Accounts payable and accrued liabilities Current derivative liabilities	8 17	\$ 19,662 16,867	\$ 55,688 -	\$ 6,929
Total Current Liabilities		36,529	55,688	6,929
Non-Current Liabilities Secured bonds Decommissioning liabilities Derivative liabilities Deferred tax liability	12 11 17 14	262,450 17,763 31,038 5,111	- 659 - -	- 167 - -
Total Non-Current Liabilities		316,362	659	167
Total Liabilities		352,891	56,347	7,096
Shareholders' Equity
Share capital Contributed surplus Accumulated other comprehensive income Retained earning (deficit)	13	177,359 10,151 (8,055) 12,733	156,599 6,208 2,139 (16,733)	70,449 1,699 (2,177) (6,152)
Total Shareholders' Equity		192,188	148,213	63,819
Total Liabilities and Shareholders' Equity		\$ 545,079	\$ 204,560	\$ 70,915

The accompanying notes are an integral part of these consolidated financial statements.

Approved by: Approved by:

"Rod Maxwell" "Neill Carson"

Director Director

Rod Maxwell Neill A. Carson

Iona Energy Inc. Consolidated Statements of Operations and Comprehensive Income (Loss)

(In thousands of US dollars, except for per share amounts)	Notes		Year Ended December 31 2013		Year Ended December 31 2012 (Note 20)
Revenues Cost of sales, including DD&A Gross Profit	5 6	\$	65,508 (53,388) 12,120	\$	- - -
Expenses General and administrative Exploration and evaluation costs Impairment Transaction costs Gain on acquisition Total Expenses	9 10 4		(12,087) (531) (23,580) (910) 6,605 (30,503)		(8,767) (355) - - - (9,122)
Income (loss) before other expenses			(18,383)		(9,122)
Loss on risk management contracts Other finance costs Finance income Foreign exchange gain/(loss) Net loss before tax	17 18		(30,917) (23,172) 20 6,991 (65,461)		- (1,491) 184 (152) (10,581)
Income tax recovery Net Income / (Loss)	14		94,927 29,466		- (10,581)
Unrealized foreign exchange gain on net investments			5,791		2,564
Exchange differences loss on re-translation of foreign operations Comprehensive Income / (Loss) for the Year		\$	(15,985) 19,272	\$	(1,752) (9,769)
Net income / (loss) per share - basic - diluted		\$ \$	0.08 0.08	\$ \$	(0.04) (0.04)
Weighted average shares outstanding - basic - diluted			360,848,912 363,077,760		273,611,114 273,611,114

The accompanying notes are an integral part of these consolidated financial statements.

Iona Energy Inc. Consolidated Statements of Changes in Shareholders' Equity

				Accumulated Other
(In thousands of US dollars)	Notes	Share Capital	Contributed Surplus	Comprehensive Income/(Loss)	Deficit	Total Equity
Balance December 31, 2012		\$ 156,599	\$ 6,208	\$ 2,139	\$ (16,733)	\$ 148,213
Net income for the year		-	-	-	29,466	29,466
Share based payments		-	3,943	-	-	3,943
Exchange differences (loss) / gain on re-translation of foreign operations		-	-	(15,985)	-	(15,985)

Unrealized foreign exchange gain / (loss) on net investments		-	-	5,791	-	5,791
Issue of shares (net of issue costs)	13	20,760	-	-	-	20,760
Balance December 31, 2013		\$ 177,359	\$ 10,151	\$ (8,055)	\$ 12,733	\$ 192,188

				Accumulated Other
(In thousands of US dollars)	Notes	Share Capital	Contributed Surplus	Comprehensive Income/(Loss)	Deficit	Total Equity
Balance December 31, 2011		\$ 70,449	\$ 1,699	\$ (2,177)	\$ (6,152)	\$ 63,819
Net loss for the year		-	-	-	(10,581)	(10,581)
Share based payments		-	4,509	-	-	4,509
Unrealized foreign exchange gain / (Loss) on net investments		-	-	2,564	-	2,564
Issue of shares (net of issue costs)	13	86,150	-	-	-	86,150
Change in presentation currency		-	-	1,752	-	1,752
Balance December 31, 2012		\$ 156,599	\$ 6,208	\$ 2,139	\$ (16,733)	\$ 148,213

The accompanying notes are an integral part of these consolidated financial statements.

Iona Energy Inc. Consolidated Statements of Cash Flows

		Year Ended	Year Ended
		December 31	December 31
(In thousands of US dollars)	Notes	2013	2012
Cash flows from / (used in) operating activities Net income / (loss) for the year Items not involving cash:	\$	29,466	\$ (10,581)
Depreciation		34,805	28
Gain on acquisition	4	(6,605)	-
Unrealized loss on risk management contracts Income tax recovery	17	17,937 (94,927)	- -
Impairment		23,580	-
Share based payments	13c	3,896	4,509
Finance costs		23,172	1,491
		31,324	(4,553)
Changes in non-cash working capital balances:
Accounts receivable		(11,896)	(1,547)
Prepaid expenses		722	106
Inventory		(581)	-
Accounts payable and accrued liabilities		(4,275)	833
Cash flow used in operating activities		15,294	(5,161)
Cash flows from / (used in) financing activities
Issue of common shares, net of issue costs		20,760	86,150
Offset of derivative call options purchased	17	(33,500)	-
Put-options – credit facility		(7,186)
Derivative call options sold Bank loan draw down, net of costs	17 12	60,000 134,300	- -
Repayment of credit facility	12	(139,700)	-
Proceeds from issuance of bond, net of costs	12	260,082	-
Repayment of subsidiary loans and derivatives	4	(55,889)	-
Bank fees and other charges		(5,735)	(1,491)
Interest on credit facility		(3,726)	-
Cash flow from financing activities		229,406	84,659
Cash flows from / (used in) investing activities
Expenditures on property and equipment		(6,127)	(80)
Recovery of drilling expenditures		3,600	-
Expenditures on exploration and evaluation Expenditure on acquisition of Orlando interest	9	(16,068) (45,300)	(61,693)
Purchase of Huntington oil field	4	(137,572)	-

Proceeds from disposal of exploration and
evaluation assets	9	36,800	-
Deferred costs Restricted cash		- (75,306)	(36,539) (8,455)
Cash flow used in investing activities		(239,973)	(106,767)

Effect of exchange rate changes on cash		(498)	1,934
Increase in cash and cash equivalents		4,229	(25,335)
Cash and cash equivalents, beginning of year		15,579	40,914
Cash and cash equivalents, end of year	\$	19,808	\$ 15,579

The accompanying notes are an integral part of these interim consolidated financial statements.

(As at December 31, 2013 and December 31, 2012, and years ended December 31, 2013 and 2012, all tabular amounts are expressed in thousands of United States dollars, except per share amounts or as otherwise noted.)

1. Corporate Information

Iona Energy Inc. ("Iona" or "the Company") is a publicly traded junior oil and gas Company on the TSX Venture Exchange ("TSX-V") under the symbol INA engaged in the evaluation, acquisition, exploration and development of oil and gas properties in the United Kingdom's North Sea and in Alaska.

The registered office of the Company is located at 1600, 333-7th Avenue S.W., Calgary, Alberta, T2P 2Z1.

The following sets out the subsidiaries of the Company and the Company's ownership interest in those subsidiaries:

Name of Subsidiary	Jurisdiction of Incorporation	Ownership
Iona Energy Company (US) Limited	Delaware, USA	100%
Iona Energy Company (UK) Limited	United Kingdom	100%
Iona UK Huntington Ltd.	United Kingdom	100%

2. Basis of Presentation

Statement of compliance

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board and were prepared using accounting policies consistent with IFRS.

A summary of Iona's significant accounting policies under IFRS is presented in Note 3.

These consolidated financial statements were approved and authorized for issuance by the Board of Directors on April 29, 2014.

Basis of measurement

The consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due, accordingly, these consolidated financial statements have been prepared on the historical cost basis, except for certain financial instruments that have been measured at fair value.

Change in functional and presentation currency

These consolidated financial statements are presented in United States dollars ("US dollars"). The functional currency of Iona Energy Inc. is Canadian dollars. The functional currencies of the Company's foreign subsidiaries are US dollars. The Company changed the functional currency of Iona Energy Company (UK) Limited ("Iona UK") from Pounds Sterling to US dollars with effect from October 1, 2013. This change was triggered by the commencement of oil and gas production and the issuance of \$275 million of US denominated debt by Iona UK. The statement of financial position of Iona UK was translated to US dollars at the October 1, 2013 rate of 1.6204 GBP per 1 USD. Transactions impacting the statement of operations and comprehensive income were translated to US dollar using rates which approximate the rates at the date of transaction. The resulting gains and losses were recorded in the statement of comprehensive income.

In 2013, the Company changed its presentation currency from the Canadian dollars ("CAD") to the US dollar. These consolidated financial statements are presented in US dollars, which is the Company's presentation currency. The change in presentation currency is to better reflect the Company's business activities and to improve investors' ability to compare the Company's financial results with other publicly traded businesses in the oil and gas industry. In making this change to the US dollar presentation currency, the Company followed the guidance in IAS 21 The Effects of Changes in Foreign Exchange Rates and have applied the change retrospectively as if the new presentation

(As at December 31, 2013, December 31, 2012 and January 1, 2012, and years ended December 31, 2013 and 2012, all tabular amounts are expressed in thousands of United States dollars, except per share amounts or as otherwise noted.)

2. Basis of Presentation - continued

currency had always been the Company's presentation currency. In accordance with IAS 21, the financial statements for all years and periods presented have been translated to the new US dollar presentation currency. For the 2012 comparative balances, assets and liabilities have been translated into the presentation currency (US dollars) at the rate of exchange prevailing at the reporting date. The statements of comprehensive income (loss) were translated at the average exchange rates for the reporting period, or at the exchange rates prevailing at the date of transactions. Exchange differences arising on translation were taken to the foreign currency translation reserve in shareholders' equity. The Company has presented a third statement of financial position as at January 1, 2012 without the related notes except for the disclosure requirements outlined in IAS 8 accounting policies, changes in accounting estimates and errors. The resulting effect of the change in presentation currency of \$158,000 on the comparative figures is reflected in the foreign exchange reserve at December 31, 2012.

Use of estimates and judgments

The preparation of financial statements requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future periods could require a material change in the financial statements. Accordingly, actual results may differ from the estimated amounts as future confirming events occur. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are as follows:

The operations of the Company are complex, and regulations and legislation affecting the Company are continually changing.

The financial statements include accruals based on the terms of existing joint venture agreements. Due to varying interpretations of the definition of terms in these agreements the accruals made by management in this regard may be different from those determined by the Corporation's joint venture partners. The effect on the consolidated financial statements resulting from such adjustments, if any, will be reflected prospectively.

The Company's operations change significantly each reporting period, this change can impact the functional currencies of the Company and its subsidiaries. Management makes judgements each reporting period as to the appropriateness of the existing functional currencies and makes changes when the facts and circumstances warrants. These changes could have material impact on the consolidated financial statements in future periods.

Amounts that will be recorded for depletion and depreciation and amounts used for impairment calculations are based on estimates of petroleum and natural gas reserves. By their nature, the estimates of reserves, including the estimates of future prices, costs, discount rates and the related future cash flows, are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.

Oil and natural gas assets are aggregated into cash-generating units based on their ability to generate largely independent cash flows and are used for impairment testing. The determination of the Company's cash-generating units is subject to Management's judgment.

The decision to transfer assets from exploration and evaluation to property, plant and equipment is based on the estimated recoverable reserves used in the determination of an area's technical feasibility and commercial viability. As such there is judgment in determining the timing of these transfers.

Compensation costs recognized for share based compensation plans are subject to the estimation of what the ultimate payout will be using pricing models such as the Black-Scholes model which is based on significant assumptions such as volatility, dividend yield and expected term. These are recognized over the vesting term and the underlying options.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such income taxes are subject to measurement uncertainty.

3. Summary of Significant Accounting Policies

Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, unless otherwise indicated. The accounting policies have been applied consistently by Company's entities.

Basis of consolidation:

(i) Subsidiaries:

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

The acquisition method of accounting is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of closing. Transaction costs are expensed as incurred in accordance with IFRS. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of the acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill when a business is acquired.

If the cost of the acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in the statement of operations and comprehensive loss.

(ii) Jointly controlled operations and jointly controlled assets:

Many of the Company's oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Company's share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs.

(iii) Transactions eliminated on consolidation:

Intercompany balances and transactions, and any unrealized income or loss arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

Financial instruments:

(i) Financial instruments:

Financial instruments comprise of cash, cash equivalents, restricted cash, accounts receivable, and accounts payable and accrued liabilities. These financial instruments are recognized initially at fair value net of any directly attributable transaction costs. Subsequent to initial recognition financial instruments are measured as described below.

Financial assets at fair value through earnings:

An instrument is classified at fair value through earnings if it is held for trading or is designated as such upon initial recognition. Financial instruments are designated at fair value through earnings if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company's risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in earnings when incurred. Financial instruments at fair value through earnings are measured at fair value, and changes therein are recognized in earnings.

3. Summary of Significant Accounting Policies - continued

Other:

Other financial instruments, such as cash, cash equivalents, restricted cash, senior secured bonds, accounts receivable, and accounts payable and accrued liabilities are measured at amortized cost using the effective interest method, less any impairment losses.

(ii) Derivative financial instruments:

The Company may in the future enter into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices or foreign exchange. These instruments will not be used for trading or speculative purposes. Financial derivative contracts, not designated as effective hedges are classified as fair value through earnings and are recorded on the statement of financial position at fair value. Transaction costs are recognized in earnings when incurred.

Embedded derivatives will be separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through earnings. Changes in the fair value of separable embedded derivatives are recognized immediately in earnings.

(iii) Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.

(iv) Cash, cash equivalents and restricted cash classified as current include cash on hand and deposits held with banks with maturities of less than 90 days.

Property and equipment and exploration and evaluation assets:

Exploration and evaluation expenditures (E&E):

Exploration and evaluation (pre-license) costs are recognized in the consolidated statement of operations and comprehensive loss as incurred. E&E costs, including the costs of acquiring undeveloped land and drilling costs are initially capitalized until the drilling of the well is complete and the results have been evaluated. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proved or probable reserves are determined to exist. If proved and or probable reserves are found, the drilling costs and associated undeveloped land are transferred to development and production assets once the Company has obtained Field Development approval ("FDP") and after completing an impairment assessment. The cost of undeveloped land that expires or any impairment of capitalized E&E expenditures recognized during a period is charged to the consolidated statement of operations and comprehensive loss.

E&E assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units ("CGU's").

Property and Equipment:

Items of property and equipment currently consists of office equipment and oil and gas development and production assets. Property & equipment assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. The cost of development and production assets will include; transfers from E&E assets, which generally include the cost to drill the well and the cost of the associated land upon determination of technical feasibility and commercial viability; the cost to complete and tie-in the wells; facility costs; the cost of recognizing provisions for future restoration and decommissioning; geological and geophysical costs; and directly attributable overheads.

Development and production assets are grouped into CGU's for impairment testing.

When significant parts of an item of property, and equipment, including oil and natural gas interests, have different

3. Summary of Significant Accounting Policies - continued

useful lives, they are accounted for as separate items (major components).

Gains and losses on disposal of an item of property and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in the statement of operations and comprehensive loss.

Subsequent costs of development and production assets:

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of development and production assets are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in earnings as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property and equipment are recognized in operating expenses as incurred.

Depletion and depreciation:

The net carrying value of development and production assets will be depleted using the unit of production method by reference to the ratio of production in the period to the related estimate of recoverable reserves, taking into account estimated future development costs necessary to bring those reserves into production and the estimated salvage value of the assets at the end of their useful lives. Future development costs are estimated taking into account the level of development required to produce the reserves.

Recoverable reserves will be estimated annually by independent qualified reserve evaluators and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.

Leased assets will be depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

Deferred Costs:

For expenditures that have been incurred for property acquisitions where certain conditions required for the transaction to close have yet to be completed the expenditures are held in deferred costs and transferred to E&E or property and equipment.

Farmouts:

Under IFRS, farmouts are considered a disposition of a partial interest in a property. The proceeds on the disposition is generally the capital spent, or estimated to be spent, by the farmee in order to earn the interest. Farmout transactions in the exploration stage do not have any gain or losses recorded. A gain or loss would be recognized for farmout transactions on developed properties where the proceeds would be measured at fair value unless the transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable.

Impairment:

(i) Financial assets:

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

3. Summary of Significant Accounting Policies - continued

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in the statement of operations and comprehensive loss.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in the statement of operations and comprehensive loss.

(ii) Non-financial assets:

The carrying amounts of the Company's non-financial assets, other than deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet available for use an impairment test is completed annually. E&E assets are assessed for impairment when they are transferred to property and equipment, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (CGU). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.

Fair value less cost to sell is determined as the amount that would be obtained from the sale of a CGU in an arm's length transaction between knowledgeable and willing parties. The fair value less cost to sell of oil and gas assets is generally determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted by an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU.

Value in use is determined as the net present value before tax of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. Value in use is determined by applying assumptions specific to the Company's continued use and can only take into account approved future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management's forecasts of commodity prices and expected production volumes. The latter takes into account assessments of field reservoir performance and includes expectations about proved and unproved volumes, which are risk-weighted utilizing geological, production, recovery and economic projections.

The goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to the CGU's that are expected to benefit from the synergies of the combination. E&E assets are allocated to related operating units when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets (oil and natural gas interests in property and equipment).

An impairment loss is recognized if the carrying amount exceeds its estimated recoverable amount. Impairment losses are recognized in depletion and depreciation expense in the statement of operations and comprehensive loss. Impairment losses recognized in CGU's are allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date, if facts and circumstances indicate that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and

3. Summary of Significant Accounting Policies - continued

depreciation, if no impairment loss had been recognized.

Inventory:

Inventories of crude oil are valued at the lower of cost, using the average cost method, and net realizable value. Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location.

Revenue:

The Company recognizes revenue when the title transfers to the customer as the commodity is loaded on to vessels for shipping and is based on volumes delivered to customers at contractual delivery points and rates.

Share based compensation:

The Company has established a share based compensation plan (the "Plan") comprised of a Stock Option Plan (refer to Note 13 (c) for further details of the Plan). The Company uses the fair value method for valuing share based compensation. Under this method, the compensation cost attributed to stock options granted are measured at the fair value at the grant date and expensed over the vesting period with a corresponding increase to a category within equity referred to as contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of option or units that vest. Upon the exercise of the stock options the previously recognized value in contributed surplus and cash proceeds are recorded as an increase to shareholders' capital.

Provisions:

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax "risk-free" rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

Decommissioning obligations:

The Company's activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of abandonment and site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value of management's best estimate of the expenditure required to settle the present obligation as at the reporting date using a risk free interest rate. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as accretion (within finance expense) whereas increases/decreases due to changes in the estimated future cash flows or changes in the discount rate are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established.

Foreign currencies:

The functional currency for each entity is the currency of the primary economic environment in which it operates. Foreign currency denominated transactions are translated into the entity's functional currency as follows; monetary items denominated in foreign currencies are translated into its functional currency at the rates of exchange at the period end date. Non-monetary items are translated to the functional currency at the historical exchange rate. Any gains or losses are recorded in the consolidated statement of net income (loss).

For the purpose of the consolidated financial statements, the results and financial position of each group entity are expressed in US dollars. For the accounts of Canadian operations, assets and liabilities are translated to US dollars at rates prevailing at the period end date. Revenues and expenses are translated to Canadian dollars using the average rate over the period. Translation gains or losses relating to the foreign operations are included in the consolidated statement of comprehensive income (loss) and accumulated in shareholders' equity on the balance sheet.

3. Summary of Significant Accounting Policies - continued

Income tax:

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in the statement of operations and comprehensive loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill.

Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Earnings per share:

Basic earnings per share is calculated by dividing the net earnings or loss attributable to common shares of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the net earnings or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted.

Changes in accounting policies

Effective January 1, 2013, the Company adopted IFRS 10 "Consolidated Financial Statements", IFRS 11 "Joint Arrangements, IFRS 12 "Disclosure of Interests in Other Entities", and the amendments to IAS 28 "Investments in Associates and Joint Ventures."

There were no changes to the consolidated financial statements or the consolidation process as a result of adoption of IFRS 10. IFRS 11 classifies interests in joint arrangements as joint ventures or joint operations depending on the rights and obligations of the parties in the arrangement. The Company performed a review of interests in joint arrangements and concluded that shared wells operate as joint operations and accordingly there is no change in the accounting for these assets as a result of adoption of this standard. As a result, there were no changes as a result of the adoption of IFRS 12 as well. Furthermore the Company was also required to adopt IFRS 13 "Fair Value Measurements," amendments to IAS 1 "Presentation of Financial Statements," amendments to IFRS 7 "Financial Instruments: Disclosures." There were no material changes as a result of the adoption of these standards.

On 1 October 2013 the Company changed its presentation currency to US dollars. Comparative figures have been restated to US dollars, the resulting effect of the change in presentation currency of \$158,000 on the comparative figures is reflected in the foreign exchange reserve at December 31, 2012.

Future Changes in Accounting Policies:

Iona has reviewed new and revised accounting pronouncements that have been issued but are not yet effective. The Company is currently evaluating the impact of the adoption of these standards and amendments. The adoption of these standards and amendments are not expected to significantly impact the Company.

In May 2013, the IASB issued amendments to IAS 36 "Impairment of Assets" which reduce the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an

3. Summary of Significant Accounting Policies - continued

impairment loss has been recognized or reversed in the period. The amendments are required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. These amendments will be applied by Iona on January 1, 2014 and the adoption will only impact Iona's disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.

In May 2013, the IASB issued IFRIC 21 "Levies," which was developed by the IFRS Interpretations Committee ("IFRIC"). IFRIC 21 clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that no liability should be recognized before the specified minimum threshold to trigger that levy is reached. IFRIC 21 is required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. IFRIC 21 will be applied by Iona on January 1, 2014 and the adoption is not expected to have a material impact on Iona's consolidated financial statements.

The IASB has undertaken a three-phase project to replace IAS 39 "Financial Instruments: Recognition and Measurement" with IFRS 9 "Financial Instruments." In November 2009, the IASB issued the first phase of IFRS 9, which details the classification and measurement requirements for financial assets. Requirements for financial liabilities were added to the standard in October 2010. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value.

In November 2013, the IASB issued the third phase of IFRS 9 which details the new general hedge accounting model. Hedge accounting remains optional and the new model is intended to allow reporters to better reflect risk management activities in the financial statements and provide more opportunities to apply hedge accounting. Iona does not employ hedge accounting for its risk management contracts currently in place. In July 2013, the IASB deferred the mandatory effective date of IFRS 9 and has left this date open pending the finalization of the impairment and classification and measurement requirements. IFRS 9 is still available for early adoption. The full impact of the standard on Iona's financial statements will not be known until the project is complete.

4. Business Combinations

During 2013 Iona completed two business combinations.

a) Acquisition of Trent & Tyne Assets

Consideration transferred on acquisition (1) \$ 32,812

(1) Amounts were previously included in deferred costs

On November 8, 2010, Iona, through its subsidiary, Iona UK entered into a sale and purchase agreement with Perenco Oil and Gas for a 20% interest in Trent Field Block 43/24 Licence P.685, a 20% interest in Tyne Field Block 44/18 Licence P.609, together with certain assets and facilities relating thereto, as well as a right of first refusal to certain assets, in exchange for Iona agreeing to fund a work program, on the T6 well for an aggregate amount of up to £21.2 million. On January 14, 2013, the T6 well was completed. As a result the Company obtained control of its 20% interest and therefore has concluded that this transaction represents a business combination with an acquisition date of January 14, 2013. The Company began consolidating the operating results, cash flows and net assets of Trent & Tyne from January 14, 2013. The revenues and cost of sales as disclosed in Note 5 and Note 6 relate to the Huntington and the Trent & Tyne assets. The net loss amounts have not been disclosed separately as it is impracticable to do so as the operations were consolidated beginning on the acquisition date.

4. Business Combinations - continued

reserve report effective as of December 31, 2012, prepared by an independent reservoir engineering firm on Iona's acquired interest in the Trent & Tyne field. The fair value of the identifiable assets and liabilities of Trent & Tyne exceeded the consideration transferred and a gain on acquisition has been recognized and recorded in the statement of operations. The gain on acquisition is a result of an increase in the fair value of the acquired reserves of Trent & Tyne from the time when the sale and purchase agreement was negotiated to the acquisition date.

Total Costs to Allocate Consideration transferred	32,812
Allocation of Fair Values to Iona's Assets
Property, plant and equipment	55,923
Total assets	55,923
Deferred income tax liabilities	10,776
Decommissioning liabilities	5,730
Total liabilities	16,506
Net assets acquired	39,417
Gain on acquisition	(6,605)
	32,812

As a result of technical difficulties and a lower gas price index at year-end, an impairment of these assets was recognized (Refer Note 10).

b) Acquisition of Huntington Oil Field

Consideration transferred:
Cash paid on acquisition	119,572
Deposits paid (1)	6,000
Deferred consideration paid subsequent	18,000
	143,572

(1) Amounts were previously included in deferred costs

Iona UK completed the acquisition of 100% of the issued and outstanding shares of Carrizo UK Huntington Limited ("Carrizo UK"). The Transaction was completed by way of a sale and purchase agreement dated December 27, 2012 among Iona, Iona UK and Carrizo Oil & Gas Inc. ("Carrizo Oil"), pursuant to which Iona UK purchased all of the Carrizo UK Shares from Carrizo Oil. The Transaction was completed on February 22, 2013. The acquisition consisted of a 15% non-operated working interest in License P1114 of UK North Sea Block 22/14b covering the Huntington oil field ("Huntington"), royalties equivalent to 2.55% of total gross oil and gas production payable to Carrizo UK from the other Huntington Joint Venture Partners and a 100% interest in that part of Block 22/14d that contains the 3D seismically mapped extension of the Jurassic discovery. Under the terms of the sale and purchase agreement, total consideration transferred as of the acquisition date on February 22, 2013 by Iona UK to Carrizo Oil was \$143,572,000, including an additional deferred payment of \$18,000,000 which was paid to Carrizo Oil upon receipt of first oil revenues from the Huntington field. Also on closing Iona UK repaid Carrizo UK's debt and deferred hedging premiums at the completion date, which was \$55,889,000.

4. Business Combinations - continued

The Company has determined that this transaction represents a business combination with Iona identified as the acquirer. The Company began consolidating the operating results, cash flows and net assets of Carrizo UK from February 22, 2013. These amounts have not been disclosed separately as it is impracticable to do so as the operations were consolidated beginning on the acquisition date.

The estimated fair value currently allocated to property and equipment is based on pre-tax net present value of future revenue from the proved and probable reserve values, discounted at a rate of 25%, and derived from an independent reserve report effective as of December 31, 2012, prepared by an independent reservoir engineering firm on Iona's acquired interest in the Huntington Field.

Carrizo UK was a private company with interests in the Huntington field located in the United Kingdom continental shelf. None of the goodwill recognized is expected to be deductible for income tax purposes.

Total Costs to Allocate
Consideration transferred	143,572
Allocation of Fair Values
Current assets	176
Exploration and evaluation assets	14,461
Property and equipment	274,409
Total assets	289,046
Current liabilities	7,532
Borrowings and financial liabilities	55,889
Decommissioning liabilities	6,849
Deferred tax liabilities	89,262
Total liabilities	159,532
Net assets acquired	129,514
Goodwill	14,058
	143,572

5. Revenue

	2013	2012
Oil sales	\$ 50,778	-
Gas sales	14,730	-
	\$ 65,508	-

6. Cost of sales

	2013
Operating expenses	\$ (18,620)	-
Depletion	(34,768)	-
	\$ (53,388)	-

7. Segmented Information

The Company's reportable segments and geographical segments are the United Kingdom (North Sea) and the United States. The corporate reportable segment includes the Company's corporate and financing activities.

The accounting policies used for the reportable segments are the same as the Company's accounting policies. For the purposes of monitoring segment performance and allocating resources between segments, the Company's executive officers monitor the tangible, intangible and financial assets attributable to each segment. All assets are allocated to reportable segments. The following tables show information regarding the Company's segments.

			Year ended December 31, 2013
	United Kingdom	United States	Corporate	Total
Revenue	\$ 65,508	\$ -	\$ -	\$ 65,508
Cost of sales, including DD&A	(53,388)	-	-	(53,388)
Gross profit	12,120	-	-	12,120
Other expenses, gain on acquisition, net finance costs	(71,896)	-	(5,685)	(77,581)
Taxation - recovery	94,927	-	-	94,927
Net income (loss)	35,151	-	(5,685)	29,466
			Year ended December 31, 2013
Total assets	\$ 542,049	\$ 938	\$ 2,092	\$ 545,079
Total liabilities	352,098	-	793	352,891
			Year ended December 31, 2012
	United Kingdom	United States	Corporate	Total
Depreciation	\$ 28	\$ -	\$ -	\$ 28
Expenses before finance income	(4,862)	-	(4,412)	(9,274)
Net finance income / (expense)	(1,396)	-	89	(1,307)
Net loss	(6,258)	-	(4,323)	(10,581)
			Year ended December 31, 2012
Total assets	\$ 194,827	\$ 932	\$ 8,801	\$ 204,560
Total liabilities	55,929	-	418	56,347

8. Restricted Cash

Current

At December 31, 2013, the Company had a current asset of \$78,024,000 of restricted cash related to bond proceeds. The bond proceeds can be utilized to retire tranches of call options sold to Britannic Trading Limited and capital expenditure on the development of Orlando and Kells (Note 12). Upon confirmation that both Orlando and Kells have reached first oil any remaining funds will become unrestricted.

At December 31, 2012, the Company had a current asset of \$710 of restricted cash related to the drilling commitment of Trent & Tyne properties. The commitment was fulfilled in January 2013 and the cash was released at that point.

As per the terms of the Bond Agreement, \$6,400,000 of the \$19,662,000 in accounts payable can be paid out of restricted cash.

Non-Current

At December 31, 2013 and December 31, 2012, the Company had \$52,000 of cash held as deposits for work

8. Restricted Cash - continued

commitment guarantees contained in exploration contracts in Alaska in the United States.

At December 31, 2013, the Company had \$7,038,000 of restricted cash (December 31, 2012 - \$6,928,000) held for the Company's decommissioning liabilities on the Trent & Tyne properties, \$nil (December 31, 2012 – \$2,012,000) held for the completion of long lead items, and \$nil (December 31, 2012 - \$106,000) held as security against Company credit cards.

9. Exploration and Evaluation Assets and Deferred Costs

	Total E&E	Deferred Costs
Cost	\$000	\$000
As at December 31, 2011	27,763	310
Additions	106,237	37,894
Effect of changes in exchange rates	2,048	348
As at December 31, 2012	136,048	38,552
Additions Acquisitions (Note 4 b)	22,041 14,461	- -
Deposit on business combination (Note 4 b)	-	(6,000)
Transfers to property, plant and equipment	(293)	(32,819)
Exchange differences	(1,294)	267
Disposals	(36,800)	-
As at December 31, 2013	134,163	-

The Company's exploration and evaluation assets consist of costs pertaining to Alaska and the United Kingdom.

General E&E

During the year, the Company expensed \$531,000 (2012 - \$355,000) of exploration and evaluation costs.

The additions to general E&E relates to development expenditure on both the Orlando and Kells fields.

Property payments and disposals

On January 19, 2012, the Company's UK Subsidiary, Iona UK, acquired full ownership and operatorship from Fairfield Cedrus Limited ("Fairfield") of a 100% interest in Block 3/8d containing the Kells Oil Field. Iona UK reimbursed Fairfield on closing for \$8.5 million in pre-development expenditures related to the Kells field. In addition, upon the approval by DECC of a field development plan in respect of Kells, Iona will be obligated to make a cash payment of \$5.0 million to Fairfield and pay a net royalty of \$2.50 per barrel of production from the Kells Oil Field.

On February 3, 2012, Iona UK entered into a sale and purchase agreement to acquire from Centrica Venture Production Company ("CVPC") a 58.73 % interest in Block 13/21a of the West Wick Oil Field. Under the terms of the agreement Iona UK paid CVPC a holding deposit of \$3.15 million on April 15, 2011 and on completion paid \$5.0 million on September 13, 2012.

On July 9, 2012, the Iona UK completed the purchase of its partners' interests, MPX North Sea Limited ("MPX") (30%) and Sorgenia E&P (UK) Ltd ("Sorgenia") (35%), in the Orlando Oil field in exchange for the payment of historical costs and future payments out of production. Pursuant to the terms of the sale and purchase agreements with MPX and Sorgenia, payment of GBP29.3 million (\$45.3 million) became payable on December 30, 2012 and

9. Exploration and Evaluation Assets and Deferred Costs - continued

was paid in Q1 2013. Additionally, future staged payments will be made by Iona to Sorgenia and MPX commencing six months after first production from Orlando. The first payment will be \$7.0 million with additional payments of \$7.0 million, \$7.0 million, \$4.0 million, and \$4.0 million made every six months thereafter respectively, amounting to a total payment of \$29.0 million over 3 years.

On February 21, 2013, the Company completed the sale of a 25% working interest in its UK North Sea Orlando and Kells fields to Volantis Exploration for total gross proceeds of \$36.8 million on close and pro-rata share of future staged payment obligations.

Drilling Costs

On July 22, 2013, Iona UK resolved disputed historic drilling costs and received a cash payment of \$3.6 million, which has been netted against additions in the year.

Deferred Costs

On December 28, 2012 Iona UK entered into a definitive Sale and Purchase Agreement with Carrizo to acquire the entire share capital of its wholly owned subsidiary Carrizo UK, including its interest in the Huntington Field. Under the terms of the agreement, Iona UK paid to Carrizo a \$6 million non-refundable deposit upon signing the Sale and Purchase Agreement. On completion of the deal in February 2013, Iona UK paid a cash consideration of \$137.6 million. As the deal did not complete until 2013, the non-refundable deposit of \$6 million is reflected in deferred costs.

The remaining additions to deferred costs relates to the net production revenue and T6 drilling costs on the Trent and Tyne assets. The costs are held in deferred costs as the Trent and Tyne acquisition is not considered complete until the drilling of the T6 well is complete and the risk and rewards have passed to Iona. The T6 well was completed in January 2013.

Due to the business combinations as detailed in Note 4, the amounts held in deferred costs in relation to Carrizo UK and Trent & Tyne were transferred to property and equipment.

10. Property and Equipment

	Development & Production Oil and Gas Assets	Other Fixed Assets	Total
Cost
At December 31, 2011	\$ -	28	\$ 28
Additions	-	80	80
At December 31, 2012	-	108	108
Additions	1,294	62	1,356
Transfers from E&E	293	-	293
Acquisitions (Note 4)(1)	330,332	-	330,332
At December 31, 2013	331,919	170	332,089
Depletion, depreciation and amortization
At December 31, 2011	-	9	9
Charge for the period	-	28	28
At December 31, 2012	-	37	37
Charge for the period	34,768	37	34,805
At December 31, 2013	\$ 34,768	74	34,842
Impairment(2)	\$ 23,580	-	23,580
Exchange differences during 2013	497	-	497
Carrying value at December 31, 2012	-	71	71
Carrying value at December 31, 2013	\$ 274,068	96	\$ 274,164

(1) Note transfers from deferred costs are included in Acquisitions.

(2) Upon acquisition, the Company's T6 well, located in the Tyne North Field, which came on stream in early 2013, had originally used the production history for the T5 well as an analogue for the T6 well as the standoff perforations in the T6 well contact was about the same as in the T5 well when it was first drilled. During late 2013 and early 2014 the T6 well began experiencing technical difficulties and a gas water contact was detected in the T6 well. Therefore the Companies initial estimates for the T6 well have been refined based on analysis of the most recent production and pressure data. This along with a lower gas price index has resulted in indicators of impairment of the Company's Trent & Tyne assets. In the fourth quarter of 2013, the Company recognized an impairment charge of \$23.6 million with respect to these producing assets. The CGU was written down to the estimated recoverable amount based on fair value less cost of disposal. The estimated fair value was determined using future cash flows adjusted for risks specific to the asset and discounted using an before tax discount rate of 25%. The key assumptions in estimating the future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes and future operating and development costs. A 1% change in the discount rate would not significantly change the estimated recoverable amount.

11. Decommissioning Liabilities

Balance December 31, 2011	\$ 167
Additions	481
Accretion	7
Exchange movements	4
Balance December 31, 2012	659
Acquisitions (Note 4)	12,579
Additions	4,220
Exchange movements	(133)
Accretion	438
Balance December 31, 2013	\$ 17,763

The total future decommissioning liability was calculated by management based on its net ownership interest in the

11. Decommissioning Liabilities – continued

Orlando and Huntington fields and the estimated costs to be incurred in future periods to reclaim and abandon the wells. The decommissioning liability was measured at the end of the year using a pre-tax, risk-free discount rate of 1.87 percent and an inflation rate of 2.00% percent over the estimated life of the asset to calculate the present value of the decommissioning liability. The costs are expected to be incurred over the next 18 years.

12. Senior Debt Instruments

On September 27, 2013, Iona UK issued \$275 million in senior secured bonds (the "Bonds"), net of discounts of \$6.9 million and transaction cost of \$8 million, for \$260 million. As at December 31, 2013 the fair value of the Bonds were \$275 million. The bonds mature on September 30, 2018. The Bonds carry an annual coupon rate of 9.5% payable semi-annually, were issued at 97.5% of par and are callable in whole or in part at the option of Iona UK at any time. Commencing 30 months after September 30, 2013, the Bonds will be repaid at 15% of the face value every six months with a 25% final payment at maturity plus a specified premium. The Bonds contain certain early redemption options under which the Company has the option to redeem all or a portion of the Bonds at various redemption prices, which include the principal amount plus accrued and unpaid interest, if any, to the applicable redemption date. The Company reviewed the terms of the Bonds and determined that certain prepayment options were an embedded derivative. The fair value of the embedded derivative at inception was \$1,146,000. At December 31, 2013 the derivative was valued at \$262,000 and will be fair valued at each subsequent reporting period. The fair value of the derivative is the residual of the value of similar debt without the derivative less the current fair value of the bonds. The embedded derivative is presented separately from the bonds in statement of financial position as a current derivative instrument.

Payment date	Nominal instalment amount	Premium on nominal instalment
March 2016	41,250,000	5%
September 2016	41,250,000	4%
March 2017	41,250,000	4%
September 2017	41,250,000	3%
March 2018	41,250,000	3%
September 2018 (Maturity)	68,750,000	2%

Under the Bond Agreement, capital expenditures are limited to assets within the borrowing base (currently Huntington, Trent & Tyne, Orlando, Kells, Ronan and Oran). Under the Bond Agreement a working interest of at least fifty percent must be maintained in Orlando and Kells. Additionally no sale or disposal of any (direct or indirect) ownership interest in the Huntington Asset shall be permitted during the term of the Bonds as long as any call options are outstanding under the BP Structured Energy Derivative.

Under the Bond Agreement the Company must maintain, as calculated quarterly:

liquidity (defined as the restricted group's cash and cash equivalents) of at least \$30 million.
a leverage ratio (defined as net interest bearing debt divided by twelve months of earnings before interest, taxes, depreciation and amortization ("EBITDA") of not more than 3.0x, and
ensure a minimum of both the capital employed ratio (defined as equity divided by the sum of equity and net interest bearing debt) and the restricted capital employed ratio (defined as restricted group equity divided by

12. Senior Debt Instruments - continued

the sum of restricted group equity and net interest bearing debt) of 40% until from December 31, 2016, and minimum 50% thereafter.

The restricted group is defined as Iona UK and Iona UK Huntington Ltd.

Under the Bond Agreement an event of default constitutes two consecutive quarterly covenant violations. The quarter ended December 31, 2013 is the first quarter that the Company is required to maintain the leverage ratio.

The Company was in breach of the Leverage Ratio at December 31, 2013. At March 31, 2014, the Company is not in compliance with the leverage ratio covenant primarily due to the definition of cash and cash equivalents not including restricted cash accounts. The Company is currently in the process of amending the Bond Agreement to clarify the definition of cash and cash equivalents to include restricted cash accounts as originally intended. The amendment of the Bond Agreement contemplates the revision to the definition to be effective on the issue date of the Bond Agreement. Subsequent to the amendment the Company expects to be in compliance with all Bond covenants.

The table below delineates the Company's position with respect to the Bond covenants at December 31, 2013.

	31-Dec-13(1)	Covenant
Liquidity	\$104,922	Greater than \$30,000
Restricted Group Capital Employed Ratio	67%	Greater than 40%
Group Capital Employed Ratio	58%	Greater than 40%
Leverage Ratio (1) Includes restricted cash	3.86	Not greater than 3.0x

The Bonds are secured against the assets of the Company and its subsidiaries.

At December 31, 2013 the balance of the Bonds of \$262,450,000 represents the Bonds amortized cost net of transaction costs of \$8 million and the initial fair value of the embedded derivative.

The effective interest rate on the bond at December 31, 2013 was 12.16%.

Par value of bonds	\$ 275,000
Discount	(6,875)
Issue at discount	\$268,125
Transaction costs Fair value adjustment on embedded derivative Initial amortized cost at September 27, 2013	(8,043) 1,146 261,228
Amortization of discount and transaction costs	1,222
As at December 31, 2013	\$ 262,450

On February 21, 2013, Iona UK entered into a \$150 million facility ("Loan Facility") with a group of three banks led by Bank of America Merrill Lynch, Lloyds TSB Bank, and BNP Paribas. As of December 31, 2013 the Loan Facility has been repaid in full and permanently closed. The Loan Facility would have matured on the earlier of: (i) the date which is five (5) years from the closing date; and (ii) the date on which the remaining oil and gas reserves (as determined by management) associated with the borrowing base assets fell below 25% of the initial oil and gas reserve quantities

12. Senior Debt Instruments - continued

attributed to the borrowing base assets (being Iona UK's Huntington assets and T&T assets). Amounts drawn under the Loan Facility bore interest at a rate equal to the London Interbank Offered Rate plus a margin of 3.20% - 3.95% per annum plus an additional rate to compensate the lenders for certain compliance costs with UK or European regulatory requirements, if any. In conjunction with the Loan Facility, the Company provided a guarantee of Iona UK's obligations under the Loan Facility.

The Loan Facility was subject to redetermination on September 30, 2013 and, as a direct consequence of the Huntington field's later than anticipated start-up and the slower production ramp up to full capacity, the Company did not satisfy certain financial conditions in the terms of the Loan Facility regarding its short-term liquidity coverage requirements during the three and six months ending June 30, 2013. The lenders granted the Company two waivers to September 27, 2013 in relation to compliance with these conditions. The cost of obtaining the waivers was \$4.5 million and is included in finance costs.

On September 27, 2013, upon closing of the Bonds, the Company repaid the Company's Loan Facility in full. The carrying amount on the date of the Bond closure was \$145.4 million, inclusive of waivers.

Additionally, on September 27, 2013, the Company offset 3.1 million of the 7.4 million outstanding call options previously sold to Britannic Trading Limited, a subsidiary of BP Oil International Limited, in February 2013 by purchasing 3.1 million call options effective between October 2014 and September 2016 (defined as the Tranche 1 Call Options under the Bond Agreement) for \$33.5 million.

13. Share Capital

(a) Authorized

Unlimited number of Common Shares without nominal or par value Unlimited number of Preferred shares, issuable in series

(b) Issued

		2013
Common shares	Shares	Amounts	Shares	Amounts
Opening balance Issued for cash (i) Share issue costs	324,904,965 \$ 41,925,903 -	156,599 22,356 (1,596)	140,860,565 \$ 184,044,400 -	70,449 92,102 (5,952)
Balance end of year	366,830,868 \$	177,359	324,904,965 \$	156,599
Warrants Opening balance(ii) Exercised (ii) Expired	220,100 \$ (107,300) (112,800)	23 (11) (12)	264,500 \$ (44,400)	28 (5)
Balance end of year	- \$	-	220,100 \$	23

(i) On February 21, 2013 the Company issued 41,818,603 common shares pursuant to a public offering at a price of CAD\$0.55 per share for gross proceeds of CAD\$23,000,232. On April 11, 2012 the Company issued 184,044,400 common shares pursuant to a public offering at a price of CAD\$0.50 per share for gross proceed of CAD\$92,022,200.

(ii) On March 13, 2013 and August 2, 2013 the Company had 87,300 and 20,000 warrants exercised, respectively, for gross proceeds of \$22,921. The warrants were issued to brokers who assisted with the Company's private placements in 2010. The warrants were exercisable into a common share of the Company at a strike price of CAD\$0.22 per warrant, in August 2013, the 112,800 outstanding warrants expired. The warrants were valued at \$28,000 using the Black Scholes option pricing model, recorded as a share issuance costs with the following assumptions: dividend yield – Nil, expected volatility 75%, risk free rate of return 1.53%, weighted average life – 3 years, forfeiture rate – Nil.

13. Share Capital - continued

(c) Stock options

During the year \$3,896,000 of share based compensation expense was included in general and administrative expenses (December 31, 2012: \$4,509,000).

The Company has a stock option plan, approved by its Board of Directors on May 27, 2011, that provides for the issuance to its directors, officers, employees and consultants options to purchase from treasury a number of common shares not exceeding 10% of the common shares that are outstanding from time to time which is the number of shares reserved for issuance under the plan. The options are non-transferable if not exercised. The exercise price can be no less than the market price of the Company's common shares prior to the day of the grant, which may be different from the closing price of such shares on the day of grant for options granted to date. Pursuant to the plan, the vesting provisions of the stock options are determined by the Board of Directors at the date of grant. All of the options granted to date under the plan vest as follows: 25% immediately and 25% vesting on the first, second and third anniversary dates. A summary of the status of the Company's stock options is presented below:

		December 31, 2013	December 31, 2012
		Weighted		Weighted
		Average		Average
	Number of	Exercise Price	Number of	Exercise Price
Stock Options	Options	CAD\$	Options	CAD\$
Beginning of year	27,080,000	\$0.58	9,650,000 \$		0.60
Granted	11,395,000	\$0.63	17,430,000		0.57
Exercised	-	-	-		-
Forfeited	(3,725,000)	\$0.54	-		-
End of year	34,750,000	\$0.59	27,080,000 \$		0.58
Exercisable, end of year	18,167,500	\$0.59	9,182,500 \$		0.58

Date of Grant	Number Outstanding	Exercise Price CAD\$	Weighted Average Remaining Contractual Life	Date of Expiry	Number Exercisable Dec 31, 2013
May 31, 2011	9,550,000	\$0.60	1.42 years	May 31, 2015	7,162,500
November 25, 2011	100,000	\$0.60	1.90 years	November 25, 2015	75,000
April 13, 2012	16,220,000	\$0.57	3.28 years	April 12, 2017	8,110,000
January 10, 2013	175,000	\$0.59	4.03 years	January 10, 2018	175,000
March 5, 2013	6,780,000	\$0.63	4.18 years	March 5, 2018	1,695,000
July 29, 2013	700,000	\$0.59	4.58 years	July 29, 2018	175,000
October 3, 2013	625,000	\$0.63	4.76 years	October 3, 2018	625,000
October 23, 2013	600,000	\$0.63	4.81 years	October 23, 2018	150,000
	34,750,000				18,167,500

The fair value of the options was estimated using the Black Scholes option pricing model with the following assumptions:

	Year ended December 31, 2013
Fair value at grant date:	CAD\$	0.24 - 0.37	CAD\$	0.24 - 0.36
Exercise price	CAD\$	0.38 - 0.63	CAD\$	0.38 - 0.57
Dividend yield		Nil	Nil
Expected volatility		54% - 75%	75%
Risk-free rate		1.72% - 3.50%	3.50%
Expected life		5 years		5 years

13. Share Capital - continued

An estimated forfeiture rate of 5% (2012 – 5%) is used when recording share-based payments. The expected volatility was determined via a peer comparison due to the Company's limited trading history.

(d) Escrowed shares

As at December 31, 2013 the Company has 2,001,391 (2012 – 6,004,099) common shares remaining in escrow which were all released from escrow on January 8, 2014 when the Company graduated to Tier 1 of the TSX Venture Exchange.

14. Taxation

Reconciliation of effective tax rate for the years ended December 31:

	2013	2012
Loss before tax from continuing operations	\$ (65,461)	\$ (10,581)
Rate of corporation tax (parent)	62.0%	62.0%
	\$ (40,585)	(6,560)
Small field allowance Gain on acquisition	(20,862) (4,095)	-
Other permanent differences	11,061	710
Foreign tax rate difference	2,104	1,600
Change in unrecognized deferred tax asset	(42,550)	4,250
Tax expense / (recovery)	\$ (94,927)	\$ -

Reconciliation of Deferred Tax Liabilities

	2013	2012
Balance beginning of year	\$ -	\$ -
Deferred tax liability created on business combination	100,038	-
Deferred tax expense / (recovery)	(94,927)	-
Ending deferred tax liability	\$ 5,111	\$ -

Unrecognized Deferred Tax Assets

Deferred tax assets have not been recognized in respect of the following items:

Year ended December 31, 2013

	United Kingdom	United States	Canada	Total
Other temporary differences	\$ -	\$ (315)	\$ 1,480	\$ 1,165
Tax losses	-	304	2,982	3,286
Total unrecognized deferred tax asset	\$ -	\$ (11)	\$ 4,462	\$ 4,451

14. Taxation - continued

Year ended December 31, 2012

	United Kingdom	United States	Canada	Total
Other temporary differences	\$ 1,183	\$ (315)	\$ 2,064	\$ 2,932
Tax losses	14,872	304	1,998	17,174
Total unrecognized deferred tax asset	\$ 16,055	\$ (11)	\$ 4,062	\$ 20,106

Movements of the Company's temporary differences for the year ended December 31, 2013 is as follows:

	31-Dec-12	Recognized in net income	Acquired in business combination	31-Dec-13
Tax loss carry forwards	(102,624)	(11,665)	(89,806)	(204,095)
Property and equipment	103,301	(59,840)	195,572	239,033
Decommissioning	(654)	(2,618)	(5,696)	(8,968)
Other Change in unrecognized	(23)	57	(32)	2
deferred tax asset	-	(20,861)	-	(20,861)
	-	(94,927)	100,038	5,111

A deferred tax asset has not been recognized as it is not probable at the year end that the asset is recoverable. The asset is recoverable if there are future suitable taxable profits from which the future reversal of the underlying temporary differences can be deducted. It is likely that with further development of the assets in the United Kingdom that a deferred tax asset will be recognized. The probability of recoverability will be reviewed at the end of each reporting period.

The Company has incurred cumulative non-capital losses at December 31, 2013 of approximately \$11,928,000 (December 31, 2012 - \$6,365,000) for Canadian income tax purposes, which are available to reduce taxable income in future years. If not utilized, these losses will expire in the years ending December 31, 2026 to 2032. The unrecognized UK deferred tax asset relates to pre-trading expenditure which if capital in nature can be carried on indefinitely. Currently all pre-trading expenditure in the UK is considered capital in nature.

15. Related Party Transactions

The Company had the following related party transactions:

(a) During the year ended December 31, 2013, the Company was charged \$716,000 (2012 - \$391,000), in legal fees of which \$97,000 (2012 - \$220,000) related to share issuance costs by a law firm where a director of the Company is a partner, of which \$29,000 (2012 - \$70,000) is included in accounts payable and accrued liabilities as at December 31, 2013.

15. Related Party Transactions - continued

(b) Compensation of key management personnel:

Key management personnel include all Directors, the Chief Executive Officer, the Chief Financial Officer and the Interim Chief Financial Officer. Compensation paid to and share-based compensation attributable to the key management personnel consists of the following:

	Year ended	Year ended
	December 31, 2013		December 31, 2012
Short-term benefits	\$ 2,239	\$	721
Share based payments (1)	2,344		2,495
Termination benefits	\$ 71	\$	-

(1) Represents amount of the non-cash share-based compensation expense estimated on grant date associated with share options (note 13). This amount may not be equal to the fair value ultimately received on exercise.
(c) Included in accounts receivable is \$117,483 (2012 \$265,000) due from a former officer and director of the Company who resigned from the Company's management team and Board. Of this amount \$117,483 remains to be collected as at December 31, 2013. The amounts owing are non-interest bearing and secured. The Company expects full repayment of the remaining balances in 2014.

Except as disclosed, all related party transactions are in the normal course of operations and have been measured at the agreed to exchange amounts, which is the amount of consideration established and agreed to by the related parties and approximates fair value.

16. Commitments and Contingencies

In addition to accounts payable and accrued liabilities, and based on management's best estimate, the Company has the following contractual obligations:

Contractual Obligations			December 31, 2013
			Payments Due in Period
	Total	Less than 1 Year	1 to 3 Years	3 to 5 Years	More than 5 Years
U.S. Segment
Exploration leases	\$ 204	17	51	51	\$	85
UK Segment
Office lease	130	87	43	-		-
Drilling, completion, facility construction	17,465	17,465	-	-		-
Total UK Segment	17,595	17,552	43	-		-
Corporate Segment
Office lease	15	15	-	-		-
Total Contractual Obligations	\$ 17,814	17,584	94	51	\$	85

The above table does not include property payments due pursuant to property acquisition agreements as disclosed in Note 9.

17. Financial Instruments and Risk Management Contracts

To estimate fair value of the risk management contracts, the Company uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilize observable market data. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. The Company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

The three levels of the fair value hierarchy are as follows:

• Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchangetraded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 - inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates, and volatility factors, which can be observed or corroborated in the marketplace.

• Level 3 - inputs that are less observable, unavailable or where the observable data does not support the majority of the instruments fair value.

In forming estimates, the Company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement. The valuation of commodity put and call options, and the prepayment option (Note 17) is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorized as Level 2 and are designated as held-for-trading.

The following table presents the Company's material financial instruments measured at fair value for each hierarchy level as of December 31, 2013:

	Level 1	Level 2	Level 3	Total Fair Value
Current assets Derivative financial instrument assets (embedded derivative)	-	\$ 262	-	\$ 262
Derivative financial instrument assets (put options)	-	31	-	31
Current liabilities Derivative financial instrument liabilities (call options)	-	16,867	-	16,867
Non-current liabilities Derivative financial instrument liabilities (call options)	-	\$ 31,038	-	\$ 31,038

17. Financial Instruments and Risk Management Contracts - continued

The table below presents the total loss on financial instruments that has been disclosed through the consolidated statement of comprehensive income:

	2013	2012
Cost of derivative options	\$ 7,186 \$	-
Unrealized loss on call options	17,937	-
Realized loss on call options	5,794	-
Total loss on call options	\$ 30,917 \$	-

All other financial assets are classified as loans and receivables and are accounted for on an amortized cost basis. All financial liabilities are classified as other liabilities. The fair value of the Bonds is \$275 million based on market rates available to the Company. The carrying amount of the other financial assets and liabilities approximates the fair value due to its short maturities.

i) Commodity Risk

The table above presents the total loss on risk management contracts that has been disclosed through the statement of net and comprehensive income. Commodity price risk related to crude oil prices is the Company's most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Company is also exposed to natural gas price movements on un-contracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Company's expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation.

The Company may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.

In conjunction with the loan facility detailed in Note 12, the Company also entered into derivative contracts with the loan facility banks on February 21, 2013 for the option to sell a total of 1,330,791 barrels of oil over the period of April 1, 2013 to March 31, 2014 at a strike price of \$100 per barrel of oil.

On February 21, 2013, the Company completed a payment swap whereby Iona received \$60 million in exchange for granting BTL, the option to purchase 8.1 MMbbl of Brent blend crude from Iona's Orlando, Kells and Huntington fields for a period of five (5) years at an average price of \$95.84 per barrel. In conjunction with the payment swap, Iona also entered into a marketing and offtake agreement with BP Oil International Limited in respect of certain quantities of oil expected to be produced from the Company's Orlando and Kells properties.

On September 27, 2013, the Company offset the risk with respect to the 7.4 million remaining call options previously sold to BTL (as noted above) by purchasing 3.1 million call options effective between October 2014 and September 2016 for \$33.5 million.

17. Financial Instruments and Risk Management Contracts - continued

The table below shows Iona's net position on a quarterly basis of the call option structures sold to and bought from BTL on February 21, 2013 and September 30, 2013 respectively.

			Call Options (bbls)		Strike (\$/bbl)
		Sold	Bought	Net Position
2014	Q1	\$ 334,687	-	\$ 334,687	100
	Q2	338,407	-	338,407	95
	Q3	342,125	-	342,125	95
	Q4	762,818	496,901	265,917	95
2015	Q1	478,397	274,396	204,001	95
	Q2	483,711	334,045	149,666	95
	Q3	489,027	377,830	111,197	95
	Q4	489,027	394,678	94,349	95
2016	Q1	470,470	390,723	79,747	95
	Q2	470,468	401,251	69,217	95
	Q3	475,639	418,356	57,283	95
	Q4	475,639	-	475,639	95
2017	Q1	316,429	-	316,429	95
	Q2	319,946	-	319,946	95
	Q3	323,461	-	323,461	95
	Q4	323,461	-	323,461	95
2018	Q1	187,206	-	187,206	95
Total		\$ 7,080,918	3,088,180	\$ 3,992,738

ii) Interest Risk

Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in market interest rates. The Company currently does not use interest rate hedges. The Company has a fixed interest rate on the Bonds of 9.5 percent per annum, which is not linked to any market variables.

iii) Credit Risk

Credit risk is the risk that arises when a party to a financial instrument will be unable to discharge cash, restricted cash and accounts receivable. Cash and restricted cash is placed with major financial institutions. The maximum exposure to credit risk is approximate to the carrying value of such financial instruments. The Company does not have an allowance for doubtful accounts as at December 31, 2013, and did not provide for any doubtful accounts nor was it required to write-off any receivables during the period ended December 31, 2013 or 2012. All third party receivables have been outstanding less than 60 days and have been settled subsequent to the quarter end apart from the amounts due from an officer as disclosed in Note 15.

iv) Foreign Currency Exchange Risk

The Company operates on an international basis and therefore foreign exchange risk exposures arise from transactions denominated in currency other than the US Dollar. The Company is exposed to foreign currency fluctuations as it holds cash and incurs expenditures in property and equipment in foreign currencies. The Company incurs expenditures in British Pound Sterling, Euros, US dollars and Canadian dollars and is exposed to fluctuations in exchange rates in these currencies. There are no exchange rate contracts in place as at or during the period ended December 31, 2013, or thereafter.

Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates on the foreign cash and restricted cash balances at December 31, 2013 would have impacted the comprehensive loss of the Company for the year ended December 31, 2013 by \$21,000 (December 31, 2012 – \$507,000).

In addition at December 31, 2013, the Company held \$11,629,030 (£7,035,957) (2012 \$54,963,000 (£33,991,000)) of

17. Financial Instruments and Risk Management Contracts - continued

accounts payable in British Pound Sterling. Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates at December 31, 2013 would impact the comprehensive loss of the Company for the year ended December 31, 2013 by \$116,290 (December 31, 2012 - \$550,000).

v) Liquidity Risk

Liquidity risk includes the risk that, as a result of the Company's operational liquidity requirements:

The Company will not have sufficient funds to settle commitments as they become due;
The Company will be forced to sell financial assets at a value which is less than what they are worth; or
The Company may be unable to settle or recover a financial asset.

As the Company's industry is very capital intensive, the majority of the spending is related to the Company's capital programs. The Company's goal is to prudently spend its capital. As circumstances change, liquidity risks may necessitate the Company to issue equity, obtain debt financing, or sell assets. The Company's contractual obligations, in addition to those recorded in the condensed consolidated financial statements, are included in Note 16 and further details of liquidity are discussed in Note 19.

18. Finance Costs

	2013	2012
Interest on credit facility	\$ 3,803	\$ -
Interest and amortization on senior bonds	7,880	-
Bank fees	9,615	-
Accretion of decommissioning liabilities	438	-
Other costs	1,436	1,491
	\$ 23,172	\$ 1,491

19. Capital Risk Management

The Company manages its capital with the prime objectives of safeguarding the business as a going concern, creating investor confidence, maximizing long-term returns and maintaining an optimal structure to meet its financial commitments and to strengthen its working capital position. At present, the capital structure of the Company is primarily composed of senior secured bonds and shareholders' equity. The Company's strategy is to access capital primarily through equity issuances and other alternative forms of debt financing. The Company actively manages its capital structure and makes adjustments relative to changes in economic conditions and the Company's risk profile. In order to uphold its capital structure and to meet the liquidity and sufficient funding tests of the senior secured bonds, the Company may from time to time issue shares and adjust its capital spending to manage current working capital levels.

As at December 31, 2013, the Company has net assets of \$192.2 million, working capital of \$79.1 million and commitments due in the next 12 months as further detailed in Note 16. The Company intends to finance its obligations as they come due from current working capital supplemented by future cash flow generated from operations.

20. Adjustment of previously reported financial information due to change in presentation currency

For comparative purposes, the statement of financial position as at December 31 2012 and January 1, 2012 includes adjustments to reflect the change in accounting policy resulting from the change in presentation currency to US dollars. The amounts previously reported in Canadian Dollars as shown below have been translated into US dollars at the December 31 2012 and January 1, 2012 exchange rate of 1.005 USD:CAD and 0.9833 USD:CAD respectively. The effect of the translation is as follows:

As at January 1, 2012

	As previously reported CAD\$000	As translated at rate of 0.9833 \$000
Current assets	\$ 43,498	\$ 42,771
Non-current assets	28,622	28,144
TOTAL ASSETS	72,120	70,915

Current liabilities	7,046	6,929
Non-current liabilities	170		167
TOTAL LIABILITIES	\$ 7,216	\$ 7,096
As at December 31, 2012
	As previously reported	As translated at
	CAD\$000	rate of 1.005 \$000
Current assets	\$ 20,686	\$ 20,791
Non-current assets	182,837	183,769
TOTAL ASSETS	203,523	204,560

Current liabilities	55,406	55,688

Non-current liabilities 656 659 TOTAL LIABILITIES \$ 56,062 \$ 56,347

20. Adjustment of previously reported financial information due to change in presentation currency – continued

For comparative purposes, the Consolidated Statements of Operations and Comprehensive Loss for the year ended December 31 2012 includes adjustments to reflect the change in accounting policy resulting from the change in presentation currency to US dollars. The amounts previously reported in Canadian Dollars as shown below have been translated into US dollars at the average 2012 exchange rate of 1.001 USD: CAD. The effect of the translation is as follows:

For the year ended December 31, 2012	As previously reported CAD\$000	As translated at rate of 1.001 \$000
General and administrative	\$ (8,771)	\$ (8,767)
Exploration and evaluation costs Other finance costs*	(355) (1,477)	(355) (1,491)
Finance income	184	184
Foreign exchange gain /(loss)	(152)	(152)
Net Loss	(10,571)	(10,581)
Unrealized foreign exchange gain / (loss) on net investments Foreign exchange gain / (loss) due to	2,561	2,564
change in presentation currency	-	(1,752)
Comprehensive loss for the year	\$ (8,010)	\$ (9,769)
Net income / (loss) per share
Basic diluted	\$ (0.04) (0.04)	\$ (0.04) (0.04)

*Note Other finance costs were included in general and administrative expense in the December 31, 2012 consolidated financial statements and has been reclassified for comparative purposes to be consistent with the presentation in the December 31, 2013 consolidated financial statements.

21. Subsequent Events

Subsequent to the year-end the Company, through its wholly owned UK subsidiary, Iona UK Developments Co Limited, entered into a Sale and Purchase Agreement ("SPA") with Perenco UK Limited ("Perenco"), to purchase Perenco's remaining 80% working interest, rights, and obligations in the Trent & Tyne fields (including the Trent East Discovery Area).

Upon satisfaction of certain conditions as set out in the SPA, the Company shall pay to Perenco the sum of \$20,000,000, as adjusted pursuant to any adjustments as per the SPA and assume all decommissioning liabilities in relation to Licenses being purchased. Payment shall be made no later than six (6) calendar months after the date of the SPA or on such later date as agreed in writing.

Iona Energy Inc.

CORPORATE INFORMATION

DIRECTORS OFFICERS OFFICES

Jay Zammit (1)(2)(4) Colin Tannock

Richard Ames(3) John Baillie Charleston, South Carolina VP Developments

(3)Member of Reserve Committee Calgary, Alberta, Canada (4)Member of the Governance Committee

Neill A. Carson (3)(5) Neill A. Carson Calgary, Canada Aberdeen, Scotland President and Chief Executive Officer Banker's Hall

Donald Copeland (1)(2)(3) Graham A. Heath Calgary, AB, T2P 5C5 Calgary, Alberta Interim Chief Financial Officer TEL: +403.444.541

Calgary, Alberta Chief Operating Officer Lower Ground Suite

Calgary, Alberta VP Asset Manager United Kingdom

(1)Member of Audit Committee Robin Baxter REGISTER AND (2)Member of Compensation VP Business Development TRANSFER AGENT

Suite 1000, 888-3rd St SW

Roger Laing (2)(4) Alan Curran(5) Aberdeen, United Kingdom 3 Queen's Gate Rod Maxwell (1)(3) Peter F. Campbell(5) Aberdeen AB15 5Yl TEL: +44.1224.228400

Calgary, Alberta Chief of Subsurface WEBSITE: www.ionaenergy.com EMAIL: [email protected]

Committee Olympia Trust

(5)Member of the Health, Safety EXCHANGE LISTINGS

and Environment Committee The Toronto Stock Exchange TSX-V: INA

SECURITIES FILINGS

www.sedar.com

Information requests and other Investor relations inquiries can be directed to:

[email protected] or by telephone at +403.444.5416

AI assistant

Energy SpA — Audit Report / Information 2013

4100_rns_2014-04-30_a3d01f96-21ba-48a3-9b5a-f0b5495938b8.pdf

Contents

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

INDEPENDENT AUDITOR'S REPORT

Management's Responsibility for the Consolidated Financial Statements

Auditor's Responsibility

Opinion

"Deloitte LLP"

Iona Energy Inc. Consolidated Statements of Operations and Comprehensive Income (Loss)

Iona Energy Inc. Consolidated Statements of Changes in Shareholders' Equity

Iona Energy Inc. Consolidated Statements of Cash Flows

1. Corporate Information

2. Basis of Presentation

Statement of compliance

Basis of measurement

Change in functional and presentation currency

2. Basis of Presentation - continued

Use of estimates and judgments

3. Summary of Significant Accounting Policies

Basis of consolidation:

Financial instruments:

3. Summary of Significant Accounting Policies - continued

Other:

(iii) Share capital

Property and equipment and exploration and evaluation assets:

Exploration and evaluation expenditures (E&E):

Property and Equipment:

3. Summary of Significant Accounting Policies - continued

Subsequent costs of development and production assets:

Depletion and depreciation:

Deferred Costs:

Farmouts:

Impairment:

(i) Financial assets:

3. Summary of Significant Accounting Policies - continued

(ii) Non-financial assets:

3. Summary of Significant Accounting Policies - continued

Inventory:

Revenue:

Share based compensation:

Provisions:

Decommissioning obligations:

Foreign currencies:

3. Summary of Significant Accounting Policies - continued

Income tax:

Earnings per share:

Changes in accounting policies

Future Changes in Accounting Policies:

3. Summary of Significant Accounting Policies - continued

4. Business Combinations

a) Acquisition of Trent & Tyne Assets

4. Business Combinations - continued

b) Acquisition of Huntington Oil Field

4. Business Combinations - continued

5. Revenue

6. Cost of sales

7. Segmented Information

8. Restricted Cash

Current

Non-Current

8. Restricted Cash - continued

9. Exploration and Evaluation Assets and Deferred Costs

General E&E

Property payments and disposals

9. Exploration and Evaluation Assets and Deferred Costs - continued

Drilling Costs

Deferred Costs

10. Property and Equipment

11. Decommissioning Liabilities

11. Decommissioning Liabilities – continued

12. Senior Debt Instruments

12. Senior Debt Instruments - continued

12. Senior Debt Instruments - continued

13. Share Capital

(a) Authorized

(b) Issued

13. Share Capital - continued

(c) Stock options

Energy SpA Audit Report / Information 2013