	Management's Responsibility for Financial Statements 2
Independent Auditor's	Report 3
Consolidated Statements of Financial Position	5
Consolidated Statements of Profit or Loss	and Comprehensive Loss 6
	Consolidated Statements of Changes in Shareholders' Equity 7
Consolidated Statements of Cash Flows	8
Notes to the Consolidated Financial Statements	9 – 42
Corporate Information	43

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 the external auditor and management to review the financial results and discharge their responsibilities. Specifically, the Audit Committee reviews with management and the external auditor 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 auditor has full and free access to the Audit Committee to discuss auditing and financial reporting matters.

The shareholders have appointed Deloitte LLP, an independent firm of UK chartered accountants, as external auditor 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 year ended December 31, 2014. The Independent Auditor's Report to the shareholders follows.

"Tom Reynolds" "Robert Gair"

Tom Reynolds Robert Gair April 28, 2015

President and CEO Chief Financial Officer

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, 2014 and the consolidated statements of profit or loss and comprehensive income (loss), consolidated statements of changes in shareholders' equity and consolidated statements of cash flows for the year ended December 31, 2014, and a summary of significant accounting policies and other explanatory information in notes 1 to 21.

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 audit. 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 audit 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, 2014 and December 31, 2013 and its financial performance and its cash flows for the years ended December 31, 2014 and December 31, 2013 in accordance with International Financial Reporting Standards.

Emphasis of matter – going concern

In forming our opinion which is not modified, we have considered the adequacy of the disclosure in Note 2 to the consolidated financial statements concerning the Company's ability to continue as a going concern.

Huntington, the key producing asset of Iona UK Huntington Limited, a wholly owned subsidiary of the Company, has suffered numerous production interruptions in recent months, largely linked to the availability of the CATS gas offtake system. These interruptions, coupled with the recent rapid decline in oil prices, mean that cash flows were lower than previously forecast and the Company was in breach of certain covenants under its US\$275 million senior secured bonds (the "Bonds") (issued by the Company's wholly owned subsidiary Iona Energy Company (UK) plc) as at December 31, 2014.

The Company initiated discussions with its largest bondholders in late 2014 to increase financial flexibility for the Company. On March 27, 2015, bondholders approved a range of amendments to the bond agreement which provide Iona with significant additional financial flexibility including a waiver of financial covenants

through 2015 and 2016, conversion of interest to payment-in-kind and a deferral of scheduled 2016 amortization payments.

The Company has also initiated a review process to consider all options to (i) ensure the business is fully funded to first oil from Orlando, and/or (ii) enable the refinancing of the Bonds. The review will result in a transaction proposal (the "Proposal") being made to bondholders for their approval by June 30, 2015 and if the Proposal is approved, then it is required to be implemented by September 30, 2015. If Iona does not provide a Proposal or the Proposal is not supported by the bondholders, then the Company shall use its reasonable endeavors to arrange for the issue of a new super senior debt funding (the "Super Senior Funding") to be made available by no later than September 30, 2015.

Both implementation of the Proposal and the Super Senior Funding are subject to bondholders approval at a bondholders' meeting. There can be no guarantee that bondholders will vote in favour of either the Proposal or the Super Senior Funding. If neither the Proposal nor the Super Senior Funding are supported by bondholders, then the Company will likely default under the terms of the Bonds during 2015. In an event of default, bondholders could require immediate repayment of the Bonds. These conditions indicate the existence of a material uncertainty which would cast significant doubt as to the Company's ability to continue as a going concern and the Company might be unable to realize its assets and discharge its liabilities in the normal course of business.

Nevertheless, after making enquiries and considering the uncertainties described above, the Directors have a reasonable expectation that the Company will have adequate resources to continue in operational existence for the foreseeable future. For these reasons, they continue to adopt the going concern basis of accounting in preparing the consolidated financial statements and these consolidated financial statements do not include the adjustments that would result if the Company was unable to continue as a going concern.

Other matter

The consolidated financial statements as at December 31, 2013 which comprise the consolidated statements of financial position as at December 31, 2013 and the consolidated statements of profit or loss and comprehensive income (loss), consolidated statements of changes in shareholders' equity and consolidated statements of cash flows for the year then ended were audited by another auditor who issued an unmodified opinion on April 28, 2014.

"Deloitte LLP"

Chartered Accountants

April 28, 2015 Aberdeen, Scotland

Iona Energy Inc. Consolidated Statements of Financial Position

ASSETS Current Assets Cash and cash equivalents Accounts receivable Prepaid expenses Restricted cash 7 Inventory 10 Derivative instruments 18 Total Current Assets Restricted cash 7 Deferred tax asset 15 Exploration and evaluation assets 8 Property and equipment 9 Goodwill 4 Total Non-Current Assets Total Assets LIABILITITES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable and accrued liabilities Current derivative liabilities 18 Total Current Liabilities Non-Current Liabilities Senior debt instrument 12 Decommissioning provision 11 Provision for contingent payments 13 Derivative liabilities 18 Deferred tax liability 15 Total Non-Current Liabilities Total Liabilities Shareholders' Equity Share capital 14 Contributed surplus Accumulated other comprehensive loss Retained (deficit) / earnings	December 31, 2014	December 31, 2013


	31,565	19,808
	6,643	15,126
	3,467	551
	55,478 943	78,024 1,802
	7,817	293
	105,913	115,604
	8,612	7,090
	54,200	-
	40,934	134,163
	250,499	274,164
	-	14,058
	354,245	429,475
	460,158	545,079


	32,243	19,662
	-	16,867
	32,243	36,529

	267,493	262,450
	36,158	17,763
	27,743	-
	21,020	31,038

	- 352,414	5,111 316,362
	384,657	352,891


	178,717	177,359
	11,351	10,151
	(7,850)	(8,055)
	(106,717) 75,501	12,733 192,188
Total Shareholders' Equity
Total Liabilities and Shareholders' Equity	460,158	545,079

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

Approved by: Approved by:

"Rod Maxwell" "Tom Reynolds"

Rod Maxwell Tom Reynolds Director Director

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

(In thousands of US dollars, except for per share amounts)	Notes	Year Ended December 31 2014		Year Ended December 31 2013
Revenue Operating costs Depletion, depreciation and amortization Gross Profit	5	90,518 (34,928) (52,977) 2,613		65,508 (18,620) (34,768) 12,120
Expenses General and administrative Pre-license costs Impairment of goodwill Impairment of oil and gas properties Preacquisition transaction costs Gain on acquisition Total Expenses Loss before other expenses Gain / (loss) on derivative instruments	8 4 9 9 4 18	(9,629) (283) (14,058) (120,112) (6,579) - (150,661) (148,048) 3,916		(12,087) (531) - (23,580) (910) 6,605 (30,503) (18,383) (30,917)
Finance costs Finance income Foreign exchange (loss) / gain Net loss before tax	19	(32,713) 13 (1,929) (178,761)		(23,172) 20 6,991 (65,461)
Income tax credit Net (Loss) / Income for the Year	15	59,311 (119,450)		94,927 29,466
Other comprehensive income Other comprehensive income to be reclassified to profit or loss in subsequent periods (net of tax): Unrealized foreign exchange gain on net investments Exchange loss on retranslation of foreign operations Net other comprehensive income / (loss) to be reclassified to profit or loss in subsequent periods		12,926 (12,721) 205		5,791 (15,985) (10,194)
Total Comprehensive (Loss) / Income for the Year		(119,245)		19,272
Net (loss) / income per share - basic - diluted	\$ \$	(0.32) (0.32)	\$ \$	0.08 0.08
Weighted average shares outstanding - basic - diluted	14c & 14d	368,104,841 368,104,841		360,848,912 363,077,760

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

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

(In thousands of US dollars)	Notes	Share Capital	Contributed Surplus	Accumulated Other Comprehensive Income / (Loss)	Retained Earnings / (Deficit)	Total Equity
Balance December 31, 2013		177,359	10,151	(8,055)	12,733	192,188
Net loss for the year		-	-	-	(119,450)	(119,450)
Share based payments	14(c)(d)	-	1,200	-	-	1,200
Exchange differences (loss) on re translation of foreign operations		-	-	(12,721)	-	(12,721)
Unrealized foreign exchange on net investments		-	-	12,926	-	12,926
Issue of shares (net of issue costs)	14(b)	1,358	-	-	-	1,358
Balance December 31, 2014		178,717	11,351	(7,850)	(106,717)	75,501

(In thousands of US dollars)	Notes	Share Capital	Contributed Surplus	Accumulated Other Comprehensive Income / (Loss)	Retained Earnings / (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	14(c)(d)	-	3,943	-	-	3,943
Exchange differences (loss) on re translation of foreign operations		-	-	(15,985)	-	(15,985)
Unrealized foreign exchange on net investments		-	-	5,791	-	5,791
Issue of shares (net of issue costs)	14(b)	20,760	-	-	-	20,760
Balance December 31, 2013		177,359	10,151	(8,055)	12,733	192,188

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

Iona Energy Inc. Consolidated Statements of Cash Flows

(In thousands of US dollars)	Notes	Year Ended December 31 2014	Year Ended December 31 2013

Cash flows from / (used in) operating activities Net (loss) / income for the year		(119,450)	29,466
Items not involving cash: Depletion, depreciation and amortization Unrealized foreign exchange (gain) / loss		53,133 304	34,805 -
Gain on acquisition Unrealized (gain) / loss on fair value of derivative instruments	4 18	- (34,410)	(6,605) 17,937
Income tax credit	15	(59,311)	(94,927)
Impairment of goodwill Impairment of oil and gas properties	4 9	14,058 120,112	- 23,580
Share based payments	14(c)(d)	1,200	3,896
Finance costs		32,713	23,172
		8,349	31,324
Changes in non-cash working capital balances:
Accounts receivable		10,483	(11,896)
Prepaid expenses		(64)	722
Inventory Accounts payable and accrued liabilities		229 15,799	(581) (4,275)
Cash flow generated from operating activities		34,796	15,294

Cash flows (used in) / from financing activities
Issue of common shares, net of issue costs Offset of derivative call options purchased	18	1,358 -	20,760 (33,500)
Put-options – credit facility		-	(7,186)
Derivative call options sold	18	-	60,000
Bank loan draw down, net of costs		-	134,300
Repayment of credit facility		-	(139,700)
Proceeds from issuance of bond, net of costs Interest on debt	12	- (26,125)	260,082 (3,726)
Bank fees and other charges		(1,114)	(5,735)
Repayment of subsidiary loans and derivatives	4	-	(55,889)
Cash flow (used in) / from financing activities		(25,881)	229,406
Cash flows from / (used in) investing activities
Expenditures on property and equipment		(4,041)	(6,127)
Recovery of drilling expenditures Expenditures on exploration and evaluation		- (14,042)	3,600 (16,068)
Expenditure on acquisition of Orlando interest	8	-	(45,300)
Purchase of Huntington oil field	4	-	(137,572)
Proceeds from disposal of exploration and evaluation assets		-	36,800
Decrease / (increase) in restricted cash Cash flow from / (used in) investing activities	7	21,024 2,941	(75,306) (239,973)

Effect of exchange rate changes on cash		(99)	(498)
Increase in cash and cash equivalents		11,757	4,229
Cash and cash equivalents, beginning of year		19,808	15,579
Cash and cash equivalents, end of year		31,565	19,808

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

(As at December 31, 2014 and December 31, 2013, and years ended December 31, 2014 and 2013, 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:

Jurisdiction of Incorporation	Ownership
Delaware, USA	100%
United Kingdom	100%
United Kingdom	100%
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 28, 2015.

Basis of measurement

The consolidated financial statements have been prepared on a going concern basis (see below), 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 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) plc ("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 Dollar 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.

Going Concern

2. Basis of Presentation - continued

previously forecast and the Company was in breach of certain covenants under its US\$275 million senior secured bonds (the "Bonds") (issued by the Company's wholly owned subsidiary Iona Energy Company (UK) plc as at December 31, 2014.

The Company has also initiated a review process to consider all options to (i) ensure the business is fully funded to first oil at Orlando, and/or (ii) enable the refinancing of the Bonds. The review will result in a transaction proposal (the "Proposal") being made to bondholders for their approval by June 30, 2015 and if the Proposal is approved then it is required to be implemented by September 30, 2015. If Iona does not provide a Proposal or the Proposal is not supported by the bondholders then the Company shall use its reasonable endeavors to arrange for the issue of a new super senior debt funding (the "Super Senior Funding") to be made available by no later than September 30, 2015.

Both implementation of the Proposal and the Super Senior Funding are subject to bondholders approval at a bondholders' meeting. There can be no guarantee that bondholders will vote in favour of either the Proposal or the Super Senior Funding. If neither the Proposal nor the Super Senior Funding are supported by bondholders then the Company will likely default under the terms of the Bonds during 2015. In an event of default, bondholders could require immediate repayment of the Bonds. These conditions indicate the existence of a material uncertainty which would cast significant doubt as to the Company's ability to continue as a going concern and the Company might be unable to realize its assets and discharge its liabilities in the normal course of business.

Use of estimates and judgments

The preparation of consolidated 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:

Functional currencies

The Company's operations change significantly each reporting period, this change can impact the functional currencies of the Company and its subsidiaries. Management makes judgments 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. See above for further details.

Depletion, depreciation and amortization amounts

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

2. Basis of Presentation - continued

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.

Share based compensation plans

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. See Note 14 for further details.

Joint arrangements

Judgment is required to determine when the Company has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. The Company has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, including the approval of the annual capital and operating expenditure work program and budget for the joint arrangement, and the approval of chosen service providers for any major capital expenditure as required by the joint operating agreements applicable to the entity's joint arrangements.

Judgment is also required to classify a joint arrangement. Classifying the arrangement requires the Company to assess their rights and obligations arising from the arrangement. Specifically, the Company considers:

The structure of the joint arrangement whether it is structured through a separate vehicle
When the arrangement is structured through a separate vehicle, the Company also considers the rights and obligations arising from:
o The legal form of the separate vehicle;
o The terms of the contractual arrangement; and
o Other facts and circumstances, considered on a case by case basis.

This assessment often requires significant judgment. A different conclusion about both joint control and whether the arrangement is a joint operation or a joint venture, could materially impact the accounting.

Funding arrangements

The accounting for funding arrangements requires management to make certain estimates and assumptions on whether a liability exists at the time of the funding. Specifically, the Company considers the terms of the contract and applies the concepts of obligating events, probabilities and providing for future events. An assessment of any contract will consider factors such as:

the stage of any asset in its development life cycle;
the allocation of any proven or probable recoverable reserves to that asset;
an assessment as to whether the arrangement results in the transfer of the risks, rewards and obligations associated with funding on that asset;
requirements of when any future payments would first arise, for example on reaching commercial production and the likelihood of achieving this;
the period over which the payment or repayment of monies received under the arrangement; and
whether legal title to the asset passes but also the economic substance of transactions, other events and conditions, and not merely the legal form.

This assessment requires the exercise of judgment.

Exploration and Evaluation Assets

The accounting for exploration and evaluation ("E&E") assets requires management to make certain estimates and assumptions, including whether exploratory wells have discovered economically recoverable quantities of reserves.

2. Basis of Presentation - continued

Designations are sometimes revised as new information becomes available. If an exploratory well encounters hydrocarbons, but further appraisal activity is required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalized as long as sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and regulatory matters. The concept of "sufficient progress" is an area of judgment, and it is possible to have exploratory costs remain capitalized for several years while additional drilling is performed or the Company seeks government, regulatory or partner approval of development plans.

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.

Further information on Exploration and Evaluation Assets judgments and estimates are provided in note 8.

Determination of Cash Generating Units

The Company's E&E assets and development oil and gas properties are grouped into Cash Generating Units ("CGUs"). CGUs are defined as the lowest level of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations. Factors considered in the classification include the integration between assets and the way in which management monitors the operations, as well as the planned development for the field or licence. The recoverability of the Company's E&E assets and development oil and gas properties is assessed at the CGU level and therefore the determination of a CGU could have a significant impact on impairment losses or impairment reversals.

Impairment Indicators

The Company monitors internal and external indicators of impairment relating to E&E assets and property, plant and equipment and goodwill (see Note 4 for further details). For E&E assets the following are examples of the types of indicators used:

The entity's right to explore in an area has expired or will expire in the near future without renewal;
No further exploration or evaluation is planned or budgeted;
The decision to discontinue exploration and evaluation in an area because of the absence of commercial reserves; or
Sufficient data exists to indicate that the book value will not be fully recovered from future development and production.

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

A significant and unexpected decline in the asset's market value or likely future revenue;
A significant change in the asset's reserves assessment;
Significant changes in the technological, market, economic or legal environments for the asset; or
Evidence is available to indicate obsolescence or physical damage of an asset, or that it is underperforming expectations.

The assessment of impairment indicators requires the exercise of judgment. If an impairment indicator exists, then the recoverable amounts of the cash-generating units and/or individual assets are determined based on the higher of value-in-use and fair values less costs of disposal calculations. These require the use of estimates and assumptions, such as future oil and natural gas prices, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves and operating performance. These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs. See Notes 4, 8, and 9 for further details.

2. Basis of Presentation - continued

Decommissioning Obligation

Decommissioning obligations will be incurred by the Company at the end of the operating life of wells. The ultimate asset decommissioning costs and timing are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements and their interpretation, the emergence of new restoration techniques, the prevailing rig rates or experience at other production sites. As a result, there could be significant adjustments to the provisions established which could materially affect future financial results. See Note 11 for further details.

Derivative financial instruments

The Company has in place risk management contracts in the form of commodity put and call options. The fair value assigned to the derivative financial instruments uses level II assumptions with the main inputs to the valuation being the quoted forward prices for commodities, market interest rates, and volatility factors. See Note 18 for further details.

Commitments

Commitment disclosure includes estimates of the total cost of long-term projects in which there are many contingent factors and which could be revised either upwards or downwards based on the actual results of operations. See Note 17 for further details.

Contingent Liabilities

Accounting for contingent liabilities requires the Company to make assumptions regarding the likelihood that a future event will occur. This assessment often requires significant judgment. A different conclusion regarding the likelihood of the future event, could materially impact the accounting.

Recognition of Deferred Tax Assets

Accounting for income and profit taxes is a complex process requiring management to interpret frequently changing laws and regulations and make judgments related to the application of tax law, estimate the timing of temporary difference reversals, and estimate the realization of tax assets. All tax filings are subject to subsequent government audits and potential reassessment. These interpretations and judgments and changes related to them can potentially impact current and deferred tax provisions, deferred income tax assets and liabilities and net post-tax profit or loss.

Accordingly, in common with other international oil and gas companies conducting their business through government licences to operate, the provision for income tax, profits tax and other tax liabilities is subject to a degree of measurement uncertainty. The recognition of deferred tax assets requires a determination of the likelihood that the Company will generate sufficient taxable earnings in future periods, in order to utilize recognized deferred tax assets. Assumptions about the generation of future taxable profits depend on management's estimates of future cash flows. These estimates of future taxable income are based on forecast cash flows from operations (which are impacted by production and sales volumes, oil and natural gas prices, reserves, operating costs, decommissioning costs, capital expenditure and other capital management transactions) and judgment about the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the net deferred tax assets recorded at the reported date could be impacted. See Note 15 for further details.

3. Summary of Significant Accounting Policies

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 profit or loss and comprehensive loss.

(ii) Jointly controlled operations and jointly controlled assets:

Under IFRS11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor.

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 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 profit or loss:

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 profit or loss 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 profit or loss are measured at fair value, and changes therein are recognized in the statement of profit or loss and comprehensive loss.

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.

3. Summary of Significant Accounting Policies - continued

(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 the statement of profit or loss and comprehensive loss 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 the statement of profit or loss and comprehensive loss.

(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 profit or loss 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 profit or loss 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 consist 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 useful lives, they are accounted for as separate items (major components).

3. Summary of Significant Accounting Policies - continued

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 profit or loss 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 the statement of profit or loss and comprehensive loss 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 by 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 disposal of a partial interest in a property. The proceeds on the disposal 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. 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

3. Summary of Significant Accounting Policies - continued

losses are recognized in the statement of profit or loss 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 profit or loss 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 of disposal.

Fair value less cost of disposal 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 of disposal 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 as an expense in the statement of profit or loss 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 depreciation, if no impairment loss had been recognized.

3. Summary of Significant Accounting Policies - continued

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:

Oil, gas, condensate and royalty revenues associated with the sale of the Company's crude oil and natural gas are recognized where it is probable that the economic benefits will flow to the Company and the revenue can be reliably measured, which is when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe, terminal or other delivery mechanism. Revenues from the production of oil and natural gas properties in which the Company has an interest with joint venture partners are recognized on the basis of the Company's working interest in those properties (the entitlement method). Differences between the production sold and the Company's share of production are recognized within cost of sales at market value. Interest income is recognized on an accruals basis and is separately recorded on the face of the statement of income.

Leases:

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

Finance leases are capitalized at the commencement of the lease at the inception date fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognized in finance costs in the statement of profit or loss.

A leased asset is depreciated over the useful life of the asset. However, if there is no reasonable certainty that the Group will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.

Operating lease payments are recognized as an operating expense in the statement of profit or loss on a straight-line basis over the lease term.

Share based compensation:

The Company has established a share based compensation plan (the "Plan") comprised of a Stock Option Plan (refer to 14(d) 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.

Warrants:

Periodically the Company issues warrants to certain individuals providing services to Company. These warrants are accounted for as share based compensation under IFRS 2. The Company uses the fair value method for valuing share based compensation. Under this method, the compensation cost attributed to warrants 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 warrants 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

3. Summary of Significant Accounting Policies - continued

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 liabilities:

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.

Any reduction in the decommissioning liability and, therefore, any deduction from the asset to which it relates, may not exceed the carrying amount of that asset. If it does, any excess over the carrying amount is taken immediately to the statement of profit or loss and other comprehensive loss.

If the change in estimate results in an increase in the decommissioning liability, and therefore, an addition to the carrying value of the asset, the Group considers whether this is an indication of impairment of the asset as a whole, and if so, tests for impairment.

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 profit or loss and comprehensive 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.

Income tax:

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in the statement of profit or loss 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

3. Summary of Significant Accounting Policies - continued

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

As of January 1, 2014, the Company adopted several new IFRS interpretations and amendments in accordance with the transitional provisions of each standard. A brief description of each new accounting policy and its impact on the Company's financial statements follows below:

IAS 36 "Impairment of Assets" has been amended to reduce the circumstances in which the recoverable amount of cash generating units "CGUs" is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The retrospective adoption of these amendments will only impact Iona's disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized.

IFRIC 21 "Levies" was developed by the IFRS Interpretations Committee ("IFRIC") and is applicable to all levies imposed by governments under legislation, other than outflows that are within the scope of other standards (e.g., IAS 12 "Income Taxes") and fines or other penalties for breaches of legislation. The interpretation clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. It also clarifies that a levy liability is accrued progressively only if the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. Lastly, the interpretation clarifies that a liability should not be recognized before the specified minimum threshold to trigger that levy is reached. The retrospective adoption of this interpretation does not have any impact on Iona's financial statements.

Future Changes in Accounting Policies:

The Company 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 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. The standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2017, with earlier adoption permitted. IFRS 15 will be applied by Iona on January 1, 2017 and the Company is currently evaluating the impact of the standard on Iona's financial statements.

In July 2014, the IASB completed the final elements of IFRS 9 "Financial Instruments." The Standard supersedes earlier versions of IFRS 9 and completes the IASB's project to replace IAS 39 "Financial Instruments: Recognition and Measurement." IFRS 9, as amended, includes a principle-based approach for classification and measurement of financial assets, a single 'expected loss' impairment model and a substantially-reformed approach to hedge accounting. The Standard will come into effect for annual periods beginning on or after January 1, 2018, with earlier adoption permitted. IFRS 9 will be applied by Iona on January 1, 2018 and the Company is currently evaluating the impact of the standard on Iona's financial statements.

3. Summary of Significant Accounting Policies - continued

Other future standards and interpretations, and amendments to standards and interpretations resulting from improvements to IFRS that did not have any impact on the accounting policies, financial position or performance of the Company are:

IAS 19 Employee contributions amendments effective January 1, 2015
IFRS 2 Definitions of vesting conditions amendments effective January 1, 2015
IFRS 8 Aggregation of operating segments amendments effective January 1, 2015
IFRS 8 Reconciliation of the total reportable segments' assets to the entity's assets amendments effective January 1, 2015
IAS 16 and IAS 38 Revaluation method proportionate restatement of accumulated depreciation/amortization amendments effective January 1, 2015
IAS 24 Key management personnel amendments effective January 1, 2015
IFRS 3 scope exceptions for joint ventures amendments effective January 1, 2015
IFRS 13 portfolio exception amendments effective January 1, 2015
IAS 40 ancillary services amendments effective January 1, 2015
IFRS 10 and IAS 28 Sale or Contribution of Assets between an Investor and its Associate or Joint Venture - amendments effective January 1, 2016
IFRS 10, IFRS 12 and IAS 28 Investment Entities amendments effective January 1, 2016
IFRS 11 Accounting for Acquisitions of Interests in Joint Operations amendments effective January 1, 2016
IFRS 14 Regulatory Deferral Accounts amendments effective January 1, 2016
IAS 1 Disclosure Initiative amendments effective January 1, 2016
IAS 16 and IAS 38 Clarification of Acceptable Methods of Depreciation and Amortization amendments effective January 1, 2016
IAS 16 and IAS 41 Bearer Plants amendments effective January 1, 2016
IAS 27 Equity Method in Separate Financial Statements amendments effective January 1, 2016
IFRS 5 Non-current Assets Held for Sale and Discontinued Operations amendments effective January 1, 2016
IFRS 7 Servicing Contracts amendments effective January 1, 2016
IFRS 7 Applicability of the offsetting disclosures to condensed interim financial statements amendments effective January 1, 2016
IAS 19 Discount Rate amendments effective January 1, 2016
IAS 34 Disclosure of information 'elsewhere in the interim financial report amendments effective January 1, 2016

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 License P.685, a 20% interest in Tyne Field Block 44/18 License 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

4. Business Combinations - continued

date of January 14, 2013. The Company began consolidating its share of the operating results, cash flows and net assets of Trent & Tyne from January 14, 2013. The revenues disclosed in Note 5 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.

The fair value allocated to property and equipment was 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, 2013, 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 of \$6.6 million was recognized and recorded in the statement of profit or loss. The gain on acquisition was 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 Decommissioning provision	10,776 5,730
Total liabilities	16,506
Net assets acquired Gain on acquisition	39,417 (6,605)
	32,812

The Trent & Tyne asset acquired was subsequently fully impaired during 2014 following lower than expected production performance and an expectation that the field would generate break-even or negative cash flows for its remaining life (Refer to Note 9).

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 (see Note 8).

In the prior year, 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 previously determined that this transaction represented a business combination with Iona UK identified as the acquirer. The Company began consolidating its share of 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.

Carrizo UK was a private company with interests in the Huntington field located in the United Kingdom continental shelf. None of the goodwill recognized was 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 provision	6,849
Deferred tax liabilities	89,262
Total liabilities	159,532
Net assets acquired	129,514
Goodwill	14,058
	143,572

During the fourth quarter of 2014, and as further detailed in Note 9, the Company undertook an assessment of the fair value of the Huntington producing asset. In assessing the fair value of the CGU, the Company recognized an impairment charge of \$14.1 million related to goodwill acquired in relation to the Huntington acquisition. The goodwill was written down to nil as the estimated recoverable amount of the CGU was unable to support any goodwill. The estimated recoverable amount was determined using future cash flows adjusted for risks specific to the asset and discounted using a before tax discount rate of 10%.

5. Revenue

	2014	2013
Crude oil	68,894	44,090
Natural gas	9,642	14,398
Royalty interest	9,759	6,688
Condensate	2,223	332
	90,518	65,508

6. Segmental 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 revenue, profitability and attributable assets of each segment. All assets are allocated to reportable segments. The following tables show information regarding the Company's segments.

	Year ended December 31, 2014
	United
	Kingdom	United States	Corporate	Total
Revenue	90,518	-	-	90,518
Operating costs	(34,928)	-	-	(34,928)
Depletion, depreciation and amortization	(52,977)	-	-	(52,977)
Gross profit	2,613	-	-	2,613
Impairment of goodwill	(14,058)	-	-	(14,058)
Impairment of oil and gas properties	(120,112)	-	-	(120,112)
Other expenses, gain on acquisition, net
finance costs	(43,177)	(32)	(3,995)	(47,204)
Taxation - credit	59,311	-	-	59,311
Net (loss)	(115,423)	(32)	(3,995)	(119,450)
		Year ended December 31, 2014
Exploration and evaluation asset	39,996	938	-	40,934
Property, plant and equipment	250,499	-	-	250,499
Total assets	458,825	938	395	460,158
Total liabilities	383,794	-	863	384,657

Year ended December 31, 2013

	United
	Kingdom	United States	Corporate	Total
Revenue	65,508	-	-	65,508
Operating costs	(18,620)	-	-	(18,620)
Depletion, depreciation and amortization	(34,768)	-	-	(34,768)
Gross profit	12,120	-	-	12,120
Impairment of oil and gas properties	(23,580)	-	-	(23,580)
Other expenses, gain on acquisition, net
finance costs	(48,316)	-	(5,685)	(54,001)
Taxation - credit	94,927	-	-	94,927
Net income / (loss)	35,151	-	(5,685)	29,466
		Year ended December 31, 2013
Exploration and evaluation asset	133,225	938	-	134,163
Property, plant and equipment	274,164	-	-	274,164
Total assets	542,049	938	2,092	545,079
Total liabilities	352,098	-	793	352,891

7. Restricted Cash

Current

At December 31, 2014, the Company had a current asset of \$55,478,000 (2013: \$78,024,000) of restricted cash related to bond proceeds. The bond proceeds can only be utilized for capital expenditure on the development of Orlando and Kells. Upon confirmation that both Orlando and Kells have reached first oil any remaining funds will become unrestricted.

As per the terms of the Bond Agreement, \$14,277,000 (2013: \$6,400,000) of the \$32,243,000 (2013: \$19,662,000) in accounts payable can be paid out of restricted cash (Note 12).

Non-Current

At December 31, 2014 and December 31, 2013, the Company had \$52,000 of cash held as deposits for work commitment guarantees contained in exploration contracts in Alaska in the United States.

At December 31, 2014, the Company had \$8,560,000 (2013: \$7,038,000) of restricted cash held for the Company's decommissioning liabilities on the Trent & Tyne properties.

8. Exploration and Evaluation Assets and Deferred Costs

		Deferred
	E&E	Costs
As at December 31, 2012	136,048	38,552
Additions	22,041	-
Acquisitions (Note 4b)	14,461	-
Deposit on business combination (Note 4b)	-	(6,000)
Transfers to property, plant and equipment (Note 9)	(293)	(32,819)
Exchange differences	(1,294)	267
Disposals	(36,800)	-
As at December 31, 2013	134,163	-
Additions	8,609	-
Transfer to PP&E (Note 9)	(101,838)	-
As at December 31, 2014	40,934	-

The Company's exploration and evaluation assets ("E&E") consist of costs pertaining to United Kingdom and the United States.

During the year, the Company expensed \$283,000 (2013: \$531,000) of pre-license expenditures.

The additions relate to development expenditures on both the Orlando and Kells fields.

The current Kells license agreement requires submission of a field development plan by August 2015. This will not be achieved and Iona is currently in discussions with the Department of Energy and Climate Change ("DECC") to seek an extension to the license. Whilst there is a risk that DECC may not be willing to extend the license management remain confident that such an extension will be provided and hence continue to hold the associated costs as capitalized E&E assets.

West Wick is classified as a Fallow B Rescued license and Iona is required to report to DECC by the end of April 2015 with progress. Whilst there is a risk that DECC may not be willing to extend the license management remain in dialogue with DECC and hence continue to hold the associated costs as capitalized E&E assets.

8. Exploration and Evaluation Assets and Deferred Costs - continued

Property payments and disposals

Upon the approval by DECC of a field development plan in respect of the Kells Oil Field, 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 21, 2013, the Company completed the sale of a 25% working interest in its UK North Sea Orlando and Kells fields to Volantis Exploration (a subsidiary of Atlantic Petroleum) 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 previously paid for the Orlando asset and received a cash payment of \$3.6 million, which has been netted against additions in the year ended December 31, 2013.

Deferred Costs

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 upon completion of the transactions in 2013.

9. Property, Plant and Equipment

	Development & Production Oil and Gas Assets	Other Fixed Assets	Total
Cost
At December 31, 2012	-	108	108
Additions	1,294	62	1,356
Transfers from E&E (Note 8)	293	-	293
Acquisitions (Note 4)(1)	330,332	-	330,332
At December 31, 2013	331,919	170	332,089
Additions	18,544	780	19,324
Transfers from E&E (Note 8)	101,838	-	101,838
Provision for contingent payments (Note 13)	27,743	-	27,743
At December 31, 2014	480,044	950	480,994
Depletion, depreciation, amortization and impairment At December 31, 2012 Charge for the period depletion, depreciation and	-	37	37
amortization	34,768	37	34,805
Charge for the period impairment	23,580	-	23,580
At December 31, 2013	58,348	74	58,422
Charge for the period depletion, depreciation and
amortization	52,302	156	52,458
Charge for the period impairment	120,112	-	120,112
At December 31, 2014	230,762	230	230,992
Exchange differences	497	-	497
Carrying value at December 31, 2013	274,068	96	274,164
Carrying value at December 31, 2014	249,779	720	250,499

(1) Note transfers from deferred costs (see Note 8) are included in Acquisitions.

Trent & Tyne

On April 28, 2014, 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). This acquisition would have constituted a business combination. The SPA had a number of conditions, which were required to be satisfied by October 28, 2014. These conditions could not be satisfied by October 28, 2014 and therefore the SPA has been terminated. The Company strongly believes that it has complied with its obligations under the SPA and accordingly is entitled to the repayment of the deposit and will robustly defend any action raised by Perenco. On this basis, the Company has recognized the full amount of \$2 million within Accounts Receivable as at December 31, 2014. In 2014, the Company expensed \$6.6 million of costs relating to the acquisition.

In the third quarter of 2014, the Company determined that the Trent & Tyne producing assets would continue to generate break-even or negative cash flows for the remaining life of the field and as such has recognized an impairment charge of \$27.8 million with respect to the Trent & Tyne producing assets. An additional impairment of

9. Property, Plant and Equipment - continued

\$3.4 million was recognized in the fourth quarter of 2014 (2013: \$23.6 million). 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 a before tax discount rate of 10%. 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.

Huntington

In the fourth quarter of 2014, the Company also recognized an impairment charge of \$88.9 million with respect to the Huntington producing assets. The CGU was written down to the estimated recoverable amount of \$120.2 million 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 (level 3 hierarchy) and discounted using a before tax discount rate of 10%. The key assumptions in estimating the future cash flows over the remaining economic life of field (expected Q4 2018) 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 impact the estimated recoverable amount by approximately \$2 million. Relating to this an impairment was taken against goodwill, see Note 4(b).

Orlando

At December 31, 2014 Orlando was considered to have met the commercial viability and technical feasibility criteria for the associated capitalized costs as of the date of \$101.8 million to be transferred to Property and Equipment from E&E as assets under construction (see Note 8).

10. Inventory

	2014	2013
Inventory at cost	2,488	1,802
Write-down of inventory	(1,545)	-
Total	943	1,802

Inventory entirely relates to crude oil inventory in the storage tank at December 31, 2014 and December 31, 2013. Inventory is valued at the lower of cost, defined as operating expenses per boe plus depletion per boe multiplied by the crude stock on hand in bbls, and selling price less costs to sell. At December 31, 2014 inventory was recorded at selling price less costs to sell and at December 31, 2013 inventory was recorded at cost.

11. Decommissioning Provision

Balance December 31, 2012	659
Acquisitions (Note 4)	12,579
Additions	4,220
Exchange movements	(133)
Accretion (Note 19)	438
Balance December 31, 2013	17,763
Additions	17,646
Exchange movements	319
Accretion (Note 19)	430
Balance December 31, 2014	36,158

11. Decommissioning Provision - continued

The total future decommissioning liability was calculated by management based on its net ownership interest in the Orlando, Huntington and Trent & Tyne 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 pre-tax, risk-free discount rates of 1.16 to 2.36% 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 at various intervals over the next 17 years. The majority of the additions during the period were due to revisions in the expected costs of the Huntington and Trent & Tyne decommissioning assets. These cost revisions resulted from an independent decommissioning report completed by the operator of the Huntington asset in June 2014. A further update on decommissioning cost estimates is expected from the Huntington operator during 2015.

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 net proceeds of \$260 million. As at December 31, 2014 the fair value of the Bonds was \$212 million (2013: \$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. Under the original Bond's terms, 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 at issuance 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, 2014 the derivative was valued at \$Nil (2013: \$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	5%
September 2016	41,250	4%
March 2017	41,250	4%
September 2017	41,250	3%
March 2018	41,250	3%
September 2018 (Maturity)	68,750	2%

Under the Bond Agreement, capital expenditures are limited to assets within the restricted group which is defined as Iona UK and Iona Huntington Ltd. (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 original terms of 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,

12. Senior Debt Instruments - continued

a leverage ratio (defined as net interest bearing debt divided by twelve months of earnings before finance costs, transaction costs, derivative gains and losses, taxes, impairment, depletion, 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 the sum of restricted group equity and net interest bearing debt) of 40% until December 31, 2016, and minimum 50% thereafter.

Under the Bond agreement, "net interest bearing debt" is defined as the book value of the interest bearing financial indebtedness less the cash and cash equivalents. "Restricted group equity" is defined as the aggregate book value of the restricted group's total equity treated as equity in accordance with IFRS (including subordinated loans), excluding any fair value adjustment attributable to the BP structured energy derivatives.

The Company was in breach of the Leverage Ratio at December 31, 2014. Given under the Bond Agreement an event of default constitutes two consecutive quarterly covenant violations the amounts in respect of the senior debt facility continue to be classified as non-current liabilities as at December 31, 2014.

The table below delineates the Company's position with respect to the Bond covenants at December 31, 2014.

	31-Dec-14(1)	Covenant
Liquidity (In thousands of US dollars)	\$86,809	Greater than \$30,000
Restricted Group Capital Employed Ratio	36%	Greater than 40%
Group Capital Employed Ratio	36%	Greater than 40%
Leverage Ratio	4.07	Not greater than 3.0x

(1) Includes restricted cash

The Bonds are secured against the assets of the Company and its subsidiaries. At December 31, 2014 the balance of the Bonds of \$267,493,000 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, 2014 was 12.16%.

Par value of bonds Discount	\$ 275,000 (6,875)
Issue at discount	268,125
Transaction costs Fair value adjustment on embedded derivative	(8,043) 1,146
Initial amortized cost at September 27, 2013 Amortization of discount and transaction costs	261,228 6,265
As at December 31, 2014	\$ 267,493

On March 27, 2015 bondholders approved a range of amendments to the Bond agreement which provide the Company with significant additional financial flexibility including:

• Full waiver of financial covenants through to first oil at Orlando including net debt/EBITDA and minimum capitalization ratios.

12. Senior Debt Instruments - continued

Conversion of interest payments to payment-in-kind (i.e. added to principal, therefore non-cash) for 2015 and 2016.
Scheduled 2016 amortization payments (\$85 million in aggregate) deferred until bond maturity in September 2018.
New independent director to be appointed to the Board of the Company, which is anticipated to be reduced to not more than six directors.
Bondholders to receive a fee in the form of non-transferable warrants to purchase common shares of the Company representing in aggregate 10% of the existing common shares of the Company. The warrants shall have an exercise price of CAD\$0.05 per warrant. The warrants shall be exercisable until September 27, 2018 and will be subject to a hold period of four months and a day from issuance.

13. Provision for Contingent Payments

On June 7, 2012, Iona UK entered into a sale and purchase agreement to acquire from Sorgenia E&P (UK) Limited and MPX North Sea Limited a 65% interest in P.1606 Block 3/3b of the Orlando Field and a 65% interest in P.1607 Block 3/8d of the Kells Field. Under the terms of the agreement, future staged payments will be made by Iona UK to Sorgenia and MPX commencing six months after first production from Orlando or Kells. 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.

At December 31, 2014, in conjunction with the determination of the commercial viability and technical feasibility of the Orlando project as discussed in Note 9, the Company determined that the criteria for recognition of a provision for these amounts had been met on the basis that it was considered probable that a cash outflow would be required to settle the contractual obligation. The total amount payable of \$29.0 million has been discounted over the period which the above payments are expected to be made based on management's best estimate of first production from Orlando in Q4 2016 using a pre tax risk free interest rate of 1.16% giving a net present value of \$27.7 million which will accrete over the life of the provision. The effective interest rate of this provision is 1.33%. The Company has recognized a corresponding asset addition of \$27.7 million in respect of Orlando (see Note 9).

On February 21, 2013, the Company completed the sale of a 25% working interest in the Orlando and Kells fields to Volantis Exploration (a subsidiary of Atlantic Petroleum) for total gross proceeds of \$36.8 million on close and a prorata share of the future staged payment obligations referred to above. An asset has not been recognized at this stage.

14. Share Capital

(a) Authorized

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

(b) Issued

		2014		2013
Common shares	Shares	Amounts	Shares	Amounts
Opening balance Issued for cash (i)(ii) Share issue costs	366,830,868 3,750,000 -	177,359 1,358 -	324,904,965 41,925,903 -	156,599 22,356 (1,596)
Balance end of year	370,580,868	178,717	366,830,868	177,359

(i) On August 29, 2014, the Company completed a non-brokered private placement for \$1,358,000 (CAD\$1,500,000) with the Company's Executive Chairman and President & CEO. Pursuant to the terms of the non-brokered private placement financing the Company issued 3,750,000 units ("Units") at a price of CAD\$0.40 per Unit. Each Unit shall be comprised of one common share and one warrant ("Warrants") to purchase common shares of the Company. The Warrants shall have a term of five years and will have an exercise price of CAD\$0.48 in the first year following closing, and an exercise price of CAD\$0.58, CAD\$0.69, CAD\$0.83 and CAD\$1.00 in each year thereafter.
(ii) 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 \$22,333,000 (CAD\$23,000,232). In addition, 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

(c) Warrants

During the year \$556,000 (2013: Nil) of share based compensation expense, relating to the warrants, was included in general and administrative expenses.

		2014		2013
	Warrants	Amounts	Warrants	Amounts
Warrants
Opening balance	-	-	220,100	23
Issued (i)	3,750,000	-	-	-
Exercised (ii)	-	-	(107,300)	(11)
Expired (ii)	-	-	(112,800)	(12)
Balance end of year	3,750,000	-	-	-

Date of Grant	Number of Warrants Outstanding	Exercise Price CAD\$	Weighted Average Remaining Contractual Life	Date of Expiry	Number Exercisable Dec 31, 2014
August 29, 2014	3,750.000	\$0.48 - \$1.00	4.66 years	September 1, 2019	3,750,000
	3,750,000				3,750,000

⁽i) On August 29, 2014, the Company completed a non-brokered private placement for \$1,358,000 (CAD\$1,500,000) with the Company's Executive Chairman and President & CEO. Pursuant to the terms of the non-brokered private placement financing the Company issued 3,750,000 units ("Units") at a price of CAD\$0.40 per Unit. Each Unit shall be comprised of one common share and one warrant ("Warrants") to purchase common shares of the Company. The Warrants shall have a term of five years and will have an exercise price of CAD\$0.48 in the first year following closing, and an exercise price of CAD\$0.58, CAD\$0.69, CAD\$0.83 and CAD\$1.00 in each year thereafter.

⁽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.

14. Share Capital - continued

The fair value of the warrants issued in the year was estimated using the Black Scholes option pricing model with the following assumptions:

	Year ended December 31, 2014	Year ended December 31, 2013
Fair value at grant date:	CAD\$ 0.15	-
Exercise price	CAD\$ 0.48	-
Dividend yield	Nil	-
Expected volatility	49%	-
Risk-free rate	1.42%	-
Expected life	5 years	-

The expected volatility was determined via the Company's historical averages.

(d) Stock options

During the year \$644,000 (2013: \$3,943,000) of share based compensation expense was included in general and administrative expenses.

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, 2014		December 31, 2013
			Weighted		Weighted
		Number of	Average Exercise Price	Number of	Average Exercise Price
Stock Options		Options	CAD\$	Options	CAD\$
Beginning of year		34,750,000	\$0.59	27,080,000	\$0.58
Granted		6,600,000	\$0.44	11,395,000	\$0.63
Exercised		-	-	-	-
Forfeited		(11,752,500)	\$0.59	(3,725,000)	\$0.54
End of year		29,597,500	\$0.56	34,750,000	\$0.59
Exercisable, end of year		20,167,500	\$0.58	18,167,500	\$0.59
			Weighted Average		Number
	Number of	Exercise	Remaining		Exercisable
Date of Grant	Options Outstanding	Price CAD\$	Contractual Life	Date of Expiry	Dec 31, 2014
May 31, 2011	7,600,000	\$0.60	0.42 years	May 31, 2015	7,600,000
April 12, 2012	10,900,000	\$0.57	2.28 years	April 12, 2017	8,362,500
March 5, 2013	4,610,000	\$0.63	3.18 years	March 5, 2018	2,405,000
October 23, 2013	600,000	\$0.63	3.81 years	October 23, 2018	300,000
April 30, 2014	637,500	\$0.54	4.33 years	April 30, 2019	187,500
July 1, 2014	750,000	\$0.49	4.47 years	June 19, 2019	187,500
September 1, 2014	4,500,000	\$0.40	3.67 years	September 1, 2019	1,125,000
	29,597,500				20,167,500

14. Share Capital - continued

On April 30, 2014, the Company issued 1,350,000 stock options to purchase 1,350,000 common shares of the Company to employees of the Company (of which 712,500 stock options were forfeited during the year). The options were issued with an exercise price of \$0.54 per share, vest as to one quarter immediately and one quarter on each of the first, second and third anniversaries of the date of grant and have a five year term from the date of issuance.

On July 1, 2014 and September 1, 2014 Iona Energy issued 750,000 and 4,500,000 stock options respectively to purchase 2,100,000 common shares of the Company to employees of the Company. The options were issued with an exercise price of \$0.49 and \$0.40 per share respectively, vest as to one quarter immediately and one quarter on each of the first, second and third anniversaries of the date of grant and have a five year and four year term, respectively, from the date of issuance.

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

	Year ended December 31, 2014	Year ended December 31, 2013
Fair value at grant date:	CAD\$ 0.15 – 0.24	CAD\$ 0.24 - 0.37
Exercise price	CAD\$ 0.40 – 0.54	CAD\$ 0.38 - 0.63
Dividend yield	Nil	Nil
Expected volatility	49% - 51%	54% - 75%
Risk-free rate	1.35% - 1.47%	1.72% - 3.50%
Expected life	5 years	5 years

An estimated forfeiture rate of 5% (2013: 5%) is used when recording share-based payments. The expected volatility was determined via the Company's historical averages.

(e) Escrowed shares

As at December 31, 2014 the Company has Nil (2013: 2,001,391) common shares remaining in escrow. All common shares were released from escrow on January 8, 2014 when the Company graduated to Tier 1 of the TSX Venture Exchange.

(f) The share options and warrants were all anti-dilutive in the current year and therefore, have not been included in the calculation of diluted earnings per share for the year.

15. Taxation

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

	2014	2013
Loss before tax from continuing operations	(178,761)	(65,461)
Rate of corporation tax	62.0%	62.0%
	\$ (110,832)	(40,585)
Gain on acquisition Other permanent differences	- 7,532	(4,095) 11,061
Foreign tax rate difference	1,478	2,104
Change in unrecognized deferred tax asset Tax credit	42,511 (59,311)	(63,412) (94,927)

Reconciliation of Deferred Tax (asset) / liabilities

2014	2013
5,111	-
-	100,038
(59,311)	(94,927)
(54,200)	5,111

Unrecognized Deferred Tax Assets

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

Year ended December 31, 2014

	United Kingdom	United States	Canada	Total
Other temporary differences	4,942	(328)	-	4,614
Tax losses	4,134	336	4,177	8,647
Small field allowance	56,189	-	-	56,189
Total unrecognized deferred tax asset	65,265	8	4,177	69,450

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
Small field allowance	38,639	-	-	38,639
Total unrecognized deferred tax asset	38,639	(11)	4,462	43,090

15. Taxation - continued

Movements of the Company's temporary differences for the year ended December 31, 2014 is as follows:

	2013	Recognized in net income	2014
Tax loss carry forwards	(204,095)	(12)	(204,107)
Property and equipment	239,033	(89,128)	149,905
Decommissioning	(8,968)	8,968	-
Other	2	-	2
Small field allowance	(20,861)	20,861	-
	5,111	(59,311)	(54,200)

A deferred tax asset has been recognized to the extent 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. Following the Company's acquisition of Iona UK Huntington Limited on 22 February 2013, management of the Company considered the way in which oil and gas operations are undertaken in the Group. As a result of this consideration management of the Company intends that Iona UK Huntington Limited's interest in the Huntington field is transferred to Iona Energy Company (UK) plc for operational purposes. Following the transfer, it is considered probable that the Company will have future taxable profits available to utilize \$87.4 million (2013: \$nil) of the Company's accumulated tax losses and as such a deferred tax asset has been recognized on the basis of future cash flow forecasts consistent with the impairment calculations on Huntington (refer to Note 9). The probability of recoverability of a deferred tax asset will be reviewed at the end of each reporting period.

The Company has incurred cumulative non-capital losses at December 31, 2014 of approximately \$16,710,000 (2013: \$11,928,000) 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 2034. The unrecognized UK deferred tax asset relates to pre-trading expenditure which if capital in nature can be carried on indefinitely.

Deferred tax balances have been measured at the rate of corporation tax substantively enacted at the balance sheet date of 62%. A 2% reduction of the supplementary charge rate was announced in the Autumn Statement and a further 10% reduction was announced in Budget 2015. These rate reductions were substantively enacted on March 26, 2015 and apply to accounting periods beginning on or after 1 January 2015. Had this been in effect at December 31, 2014 the Company would have recorded a deferred tax asset of \$43.7 million instead of \$54.2 million.

16. Related Party Transactions

The Company had the following related party transactions:

(a) During the year ended December 31, 2014, the Company was charged \$451,000 (2013: \$716,000), in legal fees of which \$Nil (2013: \$97,000) related to share issuance costs by a law firm where a director of the Company is a partner, of which \$70,000 (2013: \$29,000) is included in accounts payable and accrued liabilities as at December 31, 2014.

16. 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 Executive Vice President. Compensation paid to and share-based compensation attributable to the key management personnel consists of the following:

	Year ended December 31, 2014	Year ended December 31, 2013
Short-term benefits	\$ 2,071	\$ 2,239
Share based payments (1)	\$ 1,393	\$ 2,344
Termination benefits(2)	\$ 1,358 \$	71

(1) Represents amount of the non-cash share-based compensation expense estimated on grant date associated with share options (Note 14(d)). This amount may not be equal to the fair value ultimately received on exercise.

(2) Includes provisions for settlement costs for two former employees that may become payable.

(c) Included in accounts receivable is \$101,169 (2013: \$117,483) due from a former officer and director of the Company who resigned from the Company's management team and Board. The amounts owing are non-interest bearing and secured by 559,524 common shares. The Company expects full repayment of the remaining balances in 2015.
(d) On September 12, 2014 the Company provided loans to two members of senior management via Demand Promissory Notes for a total amount of \$480,000 (CAD\$500,000) bearing interest at 3.25% with two members of senior management. These notes are secured by 1,250,000 outstanding common shares and 1,250,000 warrants issued on August 29, 2014. At December 31, 2014 these promissory notes remained outstanding and are included in Accounts Receivable. The Company expects full repayment of the Demand Promissory Notes in the future.

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.

17. 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:

			December 31, 2014
			Payments Due in Period
Contractual Obligations	Total	Less than 1 Year	1 to 3 Years	3 to 5 Years	More than 5 Years
U.S. Segment
Exploration leases	204	-	68	51	85
UK Segment
Office lease	4,147	451	1,354	903	1,439
Equipment leases	35,513	11,224	24,289	-	-
Drilling, completion, facility construction	49,919	27,759	22,160	-	-
Total UK Segment	89,579	39,434	47,803	903	1,439
Total Contractual Obligations	89,783	39,434	47,871	954	1,524

The above table does not include property payments due pursuant to property acquisition agreements as disclosed in Note 13.

18. 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.

18. Financial Instruments and Risk Management Contracts - continued

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 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, 2014:

	Level 1	Level 2	Level 3	Total Fair Value
Current assets Derivative financial instrument assets (embedded derivative)	-	-	-	-
Derivative financial instrument assets (put options)	-	7,817	-	7,817
Current liabilities Derivative financial instrument liabilities (call options)	-	-	-	-
Non-current liabilities Derivative financial instrument liabilities (call options)	-	21,020	-	21,020

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

	2014	2013
Cost of derivative options	-	(7,186)
Unrealized gain / (loss) on call options	34,410	(17,937)
Realized loss on call options	(30,494)	(5,794)
Total gain / (loss) on call options	3,916	(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 \$212 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.

On August 14, 2014, Iona UK settled the remaining 3,658,051 calls (effective April 2014 through March 2018) for two equal payments of \$13,250,000, due on August 18, 2014, paid, and February 10, 2015, included in Accounts

18. Financial Instruments and Risk Management Contracts - continued

Payable. Simultaneously, the Company entered into a Zero Cost Producer Collar with BTL, whereby Iona UK purchased 458,352 puts (effective August 2014 through July 2015) at a strike price of \$90.00 per barrel, and sold to BTL 1,650,000 calls (effective October 2018 through March 2020) at a strike price of \$90.00 per barrel. On October 27, 2014 Iona UK closed out the 361,976 outstanding put options (effective October 2014 – July 2015) realizing proceeds of \$1.9 million. Simultaneously, the Company put in place "costless collar" arrangements over 396,197 barrels (effective December 2014 – December 2015) with a floor price of US\$80.00 / bbl and a ceiling price of US\$92.75 / bbl.

The table below shows Iona's net position on a quarterly basis as at December 31, 2014 of the outstanding call and put option structures sold to and bought from BTL on August 14, 2014 and October 27, 2014 respectively.

			Call Options (bbls)		Put Options (bbls)
		Sold	Strike (\$/bbl)	Bought	Strike (\$/bbl)
2015	Q1	107,487	92.75	107,487	80.00
	Q2	90,017	92.75	90,017	80.00
	Q3	80,715	92.75	80,715	80.00
	Q4	74,254	92.75	74,254	80.00
2018	Q4	274,998	90.00	-	-
2019	Q1	274,998	90.00	-	-
	Q2	274,998	90.00	-	-
	Q3	274,998	90.00	-	-
	Q4	274,998	90.00	-	-
2020	Q1	275,010	90.00	-	-
		2,002,473		352,473

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, 2014, and did not provide for any doubtful accounts nor was it required to write-off any receivables during the period ended December 31, 2014 or 2013.

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, 2014, or thereafter.

Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates on the foreign

18. Financial Instruments and Risk Management Contracts - continued

cash and restricted cash balances at December 31, 2014 would have impacted the comprehensive loss of the Company for the year December 31, 2014 by \$30,000 (2013: \$21,000).

In addition at December 31, 2014, the Company held \$8,606,524 (£5,514,174) (2013: \$11,629,030 (£7,035,957)) of accounts payable in British Pound Sterling. Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates at December 31, 2014 would impact the comprehensive loss of the Company for the year by \$86,065 (2013: \$116,290).

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.

The Company's principal liquidity risk relates to its Bonds. As further outlined in Notes 2, 12 and 20, the Company has initiated a review process to consider all options to (i) ensure the business is fully funded to first oil from Orlando, and/or (ii) enable the refinancing of the Bonds. This review is expected to conclude with the Company presenting either a Proposal or a Super Senior Funding alternative to bondholders at a bondholders' meeting by September 30, 2015. There can be no guarantee that bondholders will vote in favour of either the Proposal or the Super Senior Funding. If neither the Proposal nor the Super Senior Funding are supported by bondholders then the Company will likely default under the terms of the Bonds during 2015. In an event of default, bondholders could require immediate repayment of the Bonds which would cast significant doubt as to the Company's ability to continue as a going concern and the Company might be unable to realize its assets and discharge its liabilities in the normal course of business.

However, at the date of approving the financial statements, the Directors are confident that it will secure bondholder support for a Proposal or a Super Senior Funding to ensure that the Company has sufficient liquidity and capital resources available to settle and meet its obligations as they fall due.

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 17 and further details of liquidity are discussed in Note 20.

19. Finance Costs

	2014	2013
Interest on credit facility	-	3,803
Interest and amortization on senior bonds (Note 12)	31,168	7,880
Bank fees	358	9,615
Accretion of decommissioning provision (Note 11)	430	438
Other finance costs	757	1,436
	32,713	23,172

20. 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, 2014, the Company had net assets of \$75.5 million, working capital of \$73.7 million and commitments due in the next 12 months as further detailed in Note 17.

The Company initiated discussions with its largest bondholders in late 2014 to increase financial flexibility for the Company. On March 27, 2015 bondholders approved a range of amendments to the bond agreement which provide Iona with significant additional financial flexibility including a waiver of financial covenants through 2015 and 2016, conversion of interest to payment-in-kind and a deferral of scheduled 2016 amortization payments.

The Company has also initiated a review process to consider all options to enable (i) the business is fully funded to first oil at Orlando, and/or (ii) the refinancing of the Bonds. The review will result in a transaction proposal (the "Proposal") being made to bondholders for their approval by June 30, 2015 and if the Proposal is approved then it is required to be implemented by September 30, 2015. If Iona does not provide a Proposal or the Proposal is not supported by the bondholders then the Company shall use its reasonable endeavors to arrange for the issue of a new super senior debt funding (the "Super Senior Funding") to be made available by no later than September 30, 2015.

Both implementation of the Proposal and the Super Senior Funding are subject to bondholder approval at a bondholders' meeting. There can be no guarantee that bondholders will vote in favour of either the Proposal or the Super Senior Funding. If neither the Proposal nor the Super Senior Funding are supported by bondholders then the Company will likely default under the terms of the Bonds during 2015. In an event of default, Bondholders could require immediate repayment of the Bonds which would cast significant doubt as to the Company's ability to continue as a going concern and the Company might be unable to realize its assets and discharge its liabilities in the normal course of business (see Note 2).

21. Subsequent Events

On March 27, 2015, the bondholders approved amendments to the bond agreement, specifically, full waiver of financial covenants through to first oil at Orlando including net debt / EBITDA and minimum capitalization ratios.

Further details are explained in Note 12 and full details of the amendments can be found in the Summons which is available on the Company's website at www.ionaenergy.com.

Iona Energy Inc.

CORPORATE INFORMATION

DIRECTORS OFFICERS OFFICES

Donald Copeland (1)(3)(4) Aberdeen, United Kingdom Calgary, Alberta 20 Queens Road

Jay Zammit (1)(2)(4)

Bill McCall (1)(2)(3)(4) Stirlingshire, Scotland

(1)Member of Audit Committee REGISTER AND (2)Member of Compensation TRANSFER AGENT

Committee Olympia Trust

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

Committee AUDITOR

Iain McKendrick Tom Reynolds Calgary, Canada Aberdeen, Scotland President and Chief Executive Officer Registered Office

Tom Reynolds Robert Gair Calgary, AB, T2P 2Z1 Aberdeen, Scotland Chief Financial Officer TEL: +587.889.8959

Suite 1600, 333-7th Ave SW

Aberdeen AB15 4ZT Rod Maxwell (1)(2)(3)(4) United Kingdom Calgary, Alberta TEL: +44.1224.228400

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

Deloitte LLP Aberdeen, Scotland

EXCHANGE LISTINGS

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 2014

4100_rns_2015-04-29_3beb92e0-f253-4a2e-b9de-2e2b923bf521.pdf

Contents

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

INDEPENDENT AUDITOR'S REPORT

Management's Responsibility for the Consolidated Financial Statements

Auditor's Responsibility

Opinion

Emphasis of matter – going concern

Other matter

"Deloitte LLP"

Iona Energy Inc. Consolidated Statements of Financial Position

Iona Energy Inc. Consolidated Statements of Profit or Loss 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 currency

Going Concern

2. Basis of Presentation - continued

Use of estimates and judgments

Functional currencies

Depletion, depreciation and amortization amounts

2. Basis of Presentation - continued

Share based compensation plans

Joint arrangements

Funding arrangements

Exploration and Evaluation Assets

2. Basis of Presentation - continued

Determination of Cash Generating Units

Impairment Indicators

2. Basis of Presentation - continued

Decommissioning Obligation

Derivative financial instruments

Commitments

Contingent Liabilities

Recognition of Deferred Tax Assets

3. Summary of Significant Accounting Policies

Basis of consolidation:

(ii) Jointly controlled operations and jointly controlled assets:

Financial instruments:

Financial assets at fair value through profit or loss:

3. Summary of Significant Accounting Policies - continued

(ii) Derivative financial instruments:

(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:

3. Summary of Significant Accounting Policies - continued

(ii) Non-financial assets:

3. Summary of Significant Accounting Policies - continued

Inventory:

Revenue:

Leases:

Share based compensation:

Warrants:

Provisions:

3. Summary of Significant Accounting Policies - continued

Decommissioning liabilities:

Foreign currencies:

Income tax:

3. Summary of Significant Accounting Policies - continued

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

Energy SpA Audit Report / Information 2014