Energy SpA — Management Reports 2014

May 21, 2014

Iona Energy Inc. Management's Discussion and Analysis

FINANCIAL & OPERATING HIGHLIGHTS

(in United States dollars (tabular amounts in thousands) except as otherwise noted)

	Three months ended March 31, 2014	2013			Change
Financial
Crude oil and natural gas revenues Cost of sales Depletion, Depreciation & Amortization Gross Profit	\$ 35,648 (6,508) (18,928) 10,212	\$	1,858 (796) (966) 96		1,819% (718%) (1,859%) 10,538%
Gross Profit before DD&A	29,140		1,062		2,641%
Income (loss) Before Tax	717		(22,163)		103%
Income (loss) After Tax Per share – basic (\$) Per share – diluted (\$)	(338) (0.00) (0.00)		(11,945) (0.03) (0.03)		97%
Funds Flow(1)(2) Per share – basic (\$) Per share – diluted (\$)	27,088 0.07 0.07		(9,664) (0.03) (0.03)		381%
Adjusted EBITDA(1)(2) Per share – basic (\$) Per share – diluted (\$)	27,143 0.07 0.07		3,281 0.01 0.01		727%
		March 31, As at March 31			December 31,
Cash and cash equivalents Restricted cash Working capital surplus(1) Secured bonds	\$	2014 34,713 81,997 88,776 263,629		\$ \$	2013 19,808 85,114 79,075 262,450
Common shares, end of period Fully diluted, end of period(1) Weighted average common shares - basic Weighted average common shares - fully diluted		366,831 366,831 366,831 366,831			366,831 369,225 360,849 363,078
	Three months ended March 31, 2014		Three months ended December 31, 2013		Change
Operational
Crude oil and natural gas production (boepd)(3) Crude oil Natural gas Total		3,475 680 4,155		2,585 765 3,350	34% (11%) 24%
Realized sales prices Crude oil (\$/boe) Natural gas (\$/mmcf)(4) Average (\$/boe)		107.87 12.04 101.59		112.15 12.88 103.84	(4)% (7)% (2)%
Operating costs(1)(5) (\$/boe) Netback(1) (\$/boe)	\$ \$	20.01 81.58	\$ \$	24.94 78.90	(20)% 3%

(1) Non-GAAP measure – see "non-IFRS Measures" section within MD&A.

(2) See reconciliation on page 5 and 6.

(3) Based on 17.55% economic interest of volumes from Huntington.

(4) \$916,000 of Q3 revenue, which had been understated in Q3, has been included in the Company's Q4 revenue. Realized sales prices have been normalized. Revenue numbers for Q3 2013 have not been restated.

(5) \$2.1 million of operating costs, which had been understated in Q3, has been included in the Company's Q4 operating costs. Realized operating costs have been normalized. Operating costs for Q3 have not been restated.

Huntington (17.55% Economic Interest)

• Iona's Q1 2014 average production at Huntington increased 30% over Q4 2013, from 2,998 boepd to 3,896 boepd, as operational and weather-related downtime at the field continued to improve. Further, cargo schedule optimization has increased oil liftings, taking advantage of good weather windows as and when available. Huntington production for February and March was relatively unfettered with only minor interruptions due to weather and a planned maintenance related two-day shutdown of CATS.

• On March 1, 2014, the Voyageur FPSO passed its Performance & Reliability Test and as of March 31, 2014, the field had produced 4.5 million barrels of oil equivalent, with Iona's net share of production totalling 0.7 million barrels of oil equivalent.
• On April 12, 2014, Huntington production was suspended as work commenced to replace a number of straub couplings that are part of the inert gas system on the floating production, storage and offloading ("FPSO") facility. On April 24, 2014, the Operator, E.ON E&P UK Ltd, informed the partners that the replacement work had been completed ahead of schedule and that production restart had commenced. However, on April 26, 2014 the Huntington partnership was advised that due to an unplanned shutdown issue involving the Central Area Transmission System ("CATS") riser system, multiple fields producing through the system were shut in until May 10, 2014.
• As of May 9, 2014, Huntington has offloaded 24 cargos and produced 5.6 million barrels of oil equivalent with Iona's net share of production being above 1.0 million barrels of oil equivalent. The Huntington partnership continues to realize Brent prices, with an average price to date of USD\$108/bbl, and gas prices, which remain robust in the UK, above USD\$10.00/mcf.
• Since May 11, 2014, the FPSO and the Huntington reservoir have been producing, hitting gross production of 30,000 boe/d on May 14, 2014.

Trent & Tyne (20% Working Interest)

• The net average daily production rate from Trent & Tyne to Iona during the three months ended March 31, 2014 was 1.6 MMcf/d compared to 2.1 MMcf/d average during the three months ended December 31, 2013. Trent & Tyne production continues to be severely reduced due to the intermittent performance of the fresh water maker at Tyne. On April 16, 2014 the Tyne 44/18-T6 ("T6") well resumed production at 13 MMcf/d. The well has been subsequently choked back to 3 MMscfpd in order to manage salt deposition. Iona is currently investigating mitigation measures.

• In the operating envelope of the Tyne field, and in particular the T6 well, salt deposition in the wellbore tubulars is a significant risk to production. As super-saline formation water enters the wellbore tubulars it experiences a drop in both temperature and pressure. This causes salt to drop out of solution and deposit in the well. It is a well-known issue in the gas fields of the UK Southern Gas Basin and elsewhere with highly saline formation waters. Standard industry practice is to install a water washing system to the wells. Fresh water is pumped down the wells and this washes salt deposits to surface. A water maker takes seawater and, by reverse osmosis, generates fresh water for the water washing system. Salt build-up is sufficiently quick to preclude producing wells such as T6 without continual water washing. It is routine procedure to suspend production while the water maker is out of commission. Operational improvements to enhance the performance and reliability of the Tyne water maker are being implemented and should be rectified during the second half of 2014.
• Subsequent to the quarter end the Company, through its wholly owned UK subsidiary, Iona UK Developments Co Limited, entered into a Sale and Purchase Agreement ("SPA") with Perenco UK Limited ("Perenco"), to purchase Perenco's remaining 80% working interest, rights, and obligations in the Trent & Tyne fields (including the Trent East Discovery Area) (See Highlights Subsequent to Quarter End).

Orlando (75% Working Interest)

• Subsequent to March 31, 2014, the Company has determined that some items required to deliver Orlando first oil in 2015 will not be completed during 2014 and 2015, and Iona now aims to achieve first oil from Orlando as early as possible in 2016. Iona continues to be in discussion with the Operator of the Ninian Central Platform and DECC regarding specific timing of infrastructure access which drives the timing of first oil delivery.
• The manufacture of line pipe and Xmas trees is substantially complete. The copper cores for the umbilical are also complete and delivered to the umbilical assembly plant. Manufacture of the control system is ongoing and contractual arrangements for the balance of the project supply chain are in the process of being finalized. Additionally, piping tie-ins to the NCP have now been completed.

CORPORATE HIGHLIGHTS

• Iona reached a new corporate quarterly average production record of 4,155 boepd across Q1 2014, as Huntington produced at 3,896 boepd.
• The Company realized record quarterly revenue of \$35.6 million for the three month period ended March 31, 2014, and received netbacks of \$81.58/boe.
• First quarter 2014 funds flow of \$27.1 million.
• The Company has tax pools of approximately \$331 million and does not expect to pay UK taxes until 2017 or later.
• The Company's current production is not subject to any crown or third party royalties on any revenues, now or in the foreseeable future.
• The TSX Venture Exchange approved Iona's application to graduate to Tier 1 of the TSX Venture Exchange and Iona commenced trading as a Tier 1 issuer on Wednesday, January 8, 2014.
• Iona was included in the 2014 TSX Venture 50®, a ranking reserved for the strong performing companies listed on the TSX Venture Exchange.
• On March 21, 2014 the Company's Bonds commenced trading on the Nordic ABM under the ticker IEC01 PRO.

HIGHLIGHTS SUBSEQUENT TO THE QUARTER END

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

Upon satisfaction of certain conditions as set out in the SPA, the Company shall pay to Perenco the sum of \$20,000,000, as adjusted pursuant to any adjustments as per the SPA and assume all decommissioning liabilities in relation to Licenses being purchased. Payment shall be made no later than six (6) calendar months after the date of the SPA or on such later date as agreed in writing. For further information please see the Company's April 29, 2014 news release, available on the Company's website and SEDAR.

On April 29, 2014, Iona appointed Mr. Richard Ames as the Company's Executive Vice President.

On May 6, 2014 the bondholders voted in favour of amending the bond agreement to include restricted cash within the definition of cash and cash equivalents. The amendment is applied retroactively from the date of issue so that the amendment applies to the covenant calculation as at March 31, 2014 and December 31, 2013.

MANAGEMENT DISCUSSION AND ANALYSIS

Change in presentation currency

This Management discussion and Analysis is presented in United States dollars ("US dollars"). In 2013, the Company changed its presentation currency from the Canadian dollars ("CAD") to the US dollar. The change in presentation currency is to better reflect the Company's business activities and to improve investors' ability to compare the Company's financial results with other publicly traded businesses in the oil and gas industry. In making this change to the US dollar presentation currency, the Company followed the guidance in IAS 21 The Effects of Changes in Foreign Exchange Rates and have applied the change retrospectively as if the new presentation currency had always been the Company's presentation currency. In accordance with IAS 21, the financial statements for all years and periods presented have been translated to the new US dollar presentation currency. For the 2013 comparative balances, assets and liabilities have been translated into the presentation currency (US dollars) at the rate of exchange prevailing at the reporting date. Items impacting income (loss) or comprehensive income (loss) were translated at the average exchange rates for the reporting period, or at the exchange rates prevailing at the date of transactions.

Business of the Company

Iona is an oil and natural gas acquisition, appraisal, and development corporation active through its 100% wholly owned United Kingdom subsidiary Iona Energy Company (UK) Limited ("Iona UK") in the United Kingdom's Continental Shelf ("UKCS").

The Company has continued its efforts to acquire strategically aligned assets for its UK portfolio. Iona seeks low-cost, proven undeveloped acquisition targets that are proximate to infrastructure willing and able to accept its future production, and where sub-sea tiebacks can be utilized. Employing this strategy facilitates the Company's pursuit of profitable oil and gas production through the effective management of finding and development costs, initial capital expenditure, and lower long-term per barrel operating expenditure and tariffs.

The following Management's Discussion and Analysis ("MD&A") of Iona Energy Inc. ("Iona" or "the Company") have been prepared in accordance with International Financial Reporting Standards ("IFRS") and should be read in conjunction with the consolidated financial statements and accompanying notes of the Company as at and for the period ended March 31, 2013, the Annual Information Form ("AIF") for the year ended December 31, 2013, the MD&A for the year ended December 31, 2013 and the audited consolidated financial statements as at and for the year ended December 31, 2013. Copies of these documents and additional information about Iona are available on SEDAR at www.sedar.com.

This MD&A is dated May 21, 2014. All currency amounts are expressed in United States Dollars ("\$") unless otherwise stated.

Statements throughout this MD&A that are not historical facts may be considered "forward-looking statements", including without limitation, statements regarding Iona's plans and timelines for the development of its properties, statements regarding estimates of the proved reserves, probable reserves, possible reserves, as well as estimates of the net present value of future net revenue of proved reserves, probable reserves, and possible reserves, future obligations under Iona's bond agreement and hedging arrangements including the Payment Swap (as defined herein), statements regarding potential increases in working interests, and statements regarding estimated production rates. These forward-looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Company's objectives, goals or future plans are forward-looking statements. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties and actual results could differ materially from those currently anticipated. These risks and uncertainties

include, but are not limited to: the risk that Iona's development plans change as a result of new information or events, the risk that drilling results differ materially from management's current estimates, the risk that actual production rates will be significantly lower than estimated peak production rates, the risk that Iona is not able to access the proceeds of the Bond offering, changes in market conditions, law or government policy, the risk that the anticipated increase in Trent & Tyne working interest is not completed, operating conditions and costs, operating performance, demand for oil and gas and related products, price and exchange rate fluctuations, commercial negotiations or other technical and economic factors. Forward-looking statements are based on current expectations, estimates and projections of future production and capital spending as at the date of this MD&A and the Company assumes no obligation to update or revise forward-looking statements to reflect new events or circumstances, except as required by law.

Financial outlook information contained in this MD&A about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this MD&A should not be used for purposes other than for which it is disclosed herein.

Non-GAAP Financial Measures

Throughout this MD&A, the Company uses the terms "funds flow", "funds flow per share - basic". "funds flow per share – diluted", "Adjusted EBITDA", "Adjusted EBITDA per share - basic", "Adjusted EBITDA per share – diluted", "working capital" and "operating netback". These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. Management uses working capital and operating netback measures. Working capital is calculated as current assets less current liabilities, and is used to evaluate the Corporation's financial leverage. Operating netback is a benchmark common in the oil and gas industry and is calculated as total petroleum and natural gas sales, less production and transportation expenses, calculated on a per barrel equivalent ("boe") basis of sales volumes using a conversion. Operating netback is an important measure in evaluating operational performance as it demonstrates field level profitability relative to current commodity prices. Working capital and operating netback as presented do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities.

Funds flow is calculated based on cash flow from operating activities before changes in non-cash working capital. Adjusted EBITDA is calculated as net income before finance costs, derivative gains and losses, taxes, depletion, depreciation and amortization. Funds flow or Adjusted EBITDA per share - basic and funds flow or Adjusted EBITDA per share - diluted are calculated as funds flow or Adjusted EBITDA divided by the number of weighted average basic and diluted shares outstanding, respectively. Management utilizes funds flow and Adjusted EBITDA as key measures to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Funds flow and Adjusted EBITDA as presented are not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS.

The following table reconciles cash flow used in operating activities to funds flow:

	Three months ended March 31
		2014		2013
Cash flow used in operating activities	\$	27,977	\$	(8,557)
Changes in non-cash working capital balances:
Accounts receivable		(488)		(1,204)
Prepaid expenses		365		825
Inventory		127		-
Accounts payable and accrued liabilities		(893)		(728)
Funds Flow	\$	27,088	\$	(9,664)

The following table reconciles net income to Adjusted EBITDA:

	Three months ended
	March 31
		2014	\$	2013
Net income	\$	(338)		(11,945)
Income tax recovery (expenses)		1,055 (10,218)
Finance costs		7,788		799
Finance Income		(2)		(8)
Loss / (gain) on risk management contracts		(288)		23,687
Depletion, depreciation and amortization		18,928 966
Adjusted EBITDA	\$	27,143	\$	3,281

The terms "boe" and per barrel equivalent per day "boepd" are used in this MD&A. Boe and boepd may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet of natural gas to barrels of oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this MD&A we have expressed boe using a conversion standard of 6 Mcf: 1 boe which is standard in the industry.

PRODUCTION & OPERATIONS UPDATE

Producing Assets

Huntington crude oil and gas production (17.55% Economic Interest)

The Huntington Forties reservoir was brought on stream on April 12, 2013 at 7,300 bopd gross. Shortly after establishing initial gas export on June 4, 2013 from gas compression train B, a small leak in the low-pressure compression system necessitated the checking of some 400 flanges in the module. This was successfully completed on July 6. During this initial three month period of gas plant commissioning, oil production remained constrained at between 7,000 and 10,000 bopd gross by the need to stay within the gas flaring consents imposed by DECC. Through the course of July commissioning activities on train B were completed and peak oil and gas rates of 23,400 bopd and 19.6 MMcf/d gross were established. Commissioning activities on gas compression train A were hampered by persistent vibration problems. After a period of exhaustive testing and diagnostics, the source of the vibration was pinpointed in the drive unit and coupling. Replacement equipment was sourced and installed by the original equipment manufacturers.

During Q1 2014, Iona produced on average 3,896 boepd from Huntington. Production during January was lower than anticipated due to adverse weather that affected the North Sea and delayed the off-loading of crude to shuttle tanker, but operations resumed to normal before the end of the month. Huntington production for February and March was relatively unfettered with only minor interruptions due to weather and a planned maintenance related two-day shutdown of CATS.

On April 12, 2014, Huntington production was suspended as work commenced to replace a number of straub couplings that are part of the inert gas system on the floating production, storage and offloading ("FPSO") facility. On April 24, 2014, the Operator, E.ON E&P UK Ltd, informed the partners that the replacement work had been completed ahead of schedule and that production restart had commenced. However, on April 26, 2014 the Huntington partnership was advised that due to an unplanned shutdown issue involving the Central Area Transmission System ("CATS") riser system, multiple fields producing through the system were shut in until May 10, 2014.

As of May 9, 2014, Huntington has offloaded 24 cargos and produced 5.6 million barrels of oil equivalent with Iona's net share of production being above 1.0 million barrels of oil equivalent. The Huntington partnership continues to realize Brent prices, with an average to date of USD\$108/bbl, and gas prices, which remain robust in the UK, above USD\$10.00/mcf.

Since May 11, 2014, the FPSO and the Huntington reservoir have been producing, hitting gross production of 30,000 boe/d on May 14, 2014.

Effective as of December 31, 2013 GCA evaluated the reserves and net present values of future revenue associated therewith, using forecast prices and costs. The proved and probable reserves from Huntington net to Iona based on a 15.75% interest (15% working interest and 0.75% differential lifting entitlement) are 4.59 MMboe (4.02 MMbbls of oil and 3.44 Bscf of gas), not including the additional royalty interest of 1.8%. By comparison, GCA had assigned 4.58 MMboe (4.14 MMbbls and 2.64 Bscf of gas) as at December 31, 2012, prior to the field producing approximately 640,000 boe net

Iona in 2013. At this time, reserves will only be assigned to the Paleocene Forties and the Fulmar formation, which has been developed through four production and two water-injection wells to achieve the aforementioned capacity figures. The management views current reserves associated with Huntington as conservative, and believes updated static and dynamic reservoir models, to be agreed by the Huntington joint venture partnership in 2014, will see a further increase in reserves at the field.

Huntington Jurassic Fulmar ("Maxwell") (17.55% Economic Interest)

Relating to the Maxwell discovery which lies in the Fulmar horizon beneath the producing Huntington Forties field, a further phase of development has been commenced by the Huntington joint venture partners including evaluation and engineering work in 2014, with a first oil target in 2016. Further appraisal and development of the Fulmar horizon may follow depending on the geoscience evaluation of the overall extent of this reservoir including Iona's 100% owned Block 22/14d.

Trent & Tyne gas production (20% Working Interest)

The T6 well reached total depth in December 2012 and was tied-in to the production system in January 2013. The well commenced production at rates exceeding Iona's expectations, as announced by Iona in January 2013. The net average daily production rate from Trent & Tyne to Iona during the three months ended March 31, 2014 was 1.6 MMcf/d compared to 2.1 MMcf/d average during the three months ended December 31, 2013. Trent & Tyne production continues to be severely reduced due to the intermittent performance of the fresh water maker at Tyne. On April 16, 2014 the Tyne 44/18-T6 ("T6") well resumed production at 13 MMcf/d. The well has been subsequently choked back to 3MMscfpd in order to manage salt deposition. Iona is currently investigating mitigation measures.

In the operating envelope of the Tyne field, and in particular the T6 well, salt deposition in the wellbore tubulars is a significant risk to production. When super-saline formation water enters the wellbore tubulars it experiences a drop in both temperature and pressure. This causes salt to drop out of solution and deposit in the well. It is a well-known issue in the gas fields of the UK Southern Gas Basin and elsewhere with highly saline formation waters. Standard industry practice is to install a water washing system to the wells. Fresh water is pumped down the wells and this washes salt deposits to surface. A water maker takes seawater and, by reverse osmosis, generates fresh water for the water washing system. Salt build-up is sufficiently quick to preclude producing wells such as T6 without continual water washing. It is routine procedure to suspend production while the water maker is out of commission. Operational improvements to enhance the performance and reliability of the Tyne water maker are being implemented.

Effective as of December 31, 2013, GCA evaluated the reserves and net present values of future revenue associated therewith, using forecast prices and costs. The proved and probable reserves from Trent & Tyne net to Iona is 9.33 Bscf of gas based on its 20% working interest.

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

Upon satisfaction of certain conditions as set out in the SPA, the Company shall pay to Perenco the sum of \$20,000,000, as adjusted pursuant to any adjustments as per the SPA and assume all decommissioning liabilities in relation to Licenses being purchased. Payment shall be made no later than six (6) calendar months after the date of the SPA or on such later date as agreed in writing. For further information please see the Company's April 29, 2014 news release, available on the Company's website and SEDAR.

Developments

Orlando – A proven undeveloped oil discovery (75% Working Interest)

The Orlando Field Development Plan ("FDP") was approved by DECC on April 16, 2013. The development plan contemplates the re-entering and drilling of the suspended 3/3b-13z well as a 3,000 foot horizontal producer, to be completed with dual electric submersible pumps. Additionally, a subsea pipeline, power supply and control umbilical are expected to be laid between the well-head and the Ninian Central Platform ("NCP") approximately 10 km to the south west of the Orlando field. Engineering modifications at the NCP will allow tie-in and first production shortly after completion of the development well. The manufacture of line pipe and Xmas trees is substantially finished. The copper cores for the umbilical are also complete and delivered to the umbilical assembly plant. Manufacture of the control system is ongoing and contractual arrangements for the balance of the project supply chain are in the process of being finalized. Additionally, piping tie-ins to the NCP have now been done.

It was originally contemplated that field development would be completed by 2015, enabling first oil from Orlando in the second half of the year. Subsequent to March 31, 2014, the Company has determined that some deliverables will not be completed during 2014 and 2015, and Iona aims to achieve first oil from Orlando as early as possible in 2016. Iona continues to be in discussion with the Operator of the Ninian Central Platform and DECC regarding specific timing of infrastructure access which drives the exact timing of first oil delivery.

Iona is operator and holds a 75% working interest in the Orlando field. Volantis Exploration Limited, a wholly owned subsidiary of Atlantic Petroleum, owns the remaining 25% working interest following its acquisition from Iona on February 21, 2013.

Kells – Redevelopment of a proven field (75% Working Interest)

Kells is slated for development through NCP following the tie-in of Orlando to the same facility. The Kells development plan comprises two subsea production wells, an oil pipeline, a control umbilical, and some pipework modifications at NCP. A draft FDP has been prepared and project activity will be phased through 2015 and 2016, with first oil expected in the second half of 2016. A subsequent water injection project is planned to unlock additional reserves. This 2017 project will involve the laying of water injection and gas lift lines, and the conversion of the second well to water injection service.

West Wick – Oil Discovery (58.73% Working Interest)

Iona completed the acquisition of a 58.73% working interest in West Wick in August 2012 and is the operator on the block. West Wick is programmed for a three well subsea development. The development will comprise two producers and one injector. The most likely development is via offset field infrastructure; however, Iona is also considering stand-alone facilities and is in consultation with both the joint venture and the supply chain and engineering studies are ongoing. The Company expects to select a development approach and submit the associated FDP in 2014.

Ronan & Oran – Oil Discovery awaiting conversion to Reserves (100% Working Interest)

Detailed subsurface mapping has been undertaken that has confirmed the extent of the Ronan and Oran Oil Discoveries within which oil-water contacts have yet to be established. This work has also matured the potential through appraisal drilling to add significant additional resources below the existing known oil levels and the potential deeper oil-water contacts out to the mapped spill points. Development concepts are under review.

Iona is currently contemplating the drilling of an appraisal well to locate the potential deeper oil-water contact and has initiated the permitting, site survey, and procurement of a semi-submersible rig to potentially commence drilling as early as Q1 2015.

Exploration

The Company's portfolio of assets will continue to grow through acquisitions, farm-ins and participation in license rounds.

CORPORATE TRANSACTIONS

See subsequent events.

Q1 2014 RESULTS OF OPERATIONS

Revenue was generated from the Trent & Tyne gas fields and from the Huntington oil field as discussed in Key Projects Update. There was minimal revenue generated from operations in the first quarter of 2013 as Huntington commenced production on April 12, 2013, while all revenues from Trent & Tyne accrued into a restricted cash account between the economic date of the Trent & Tyne acquisition and the completion of the T6 well in January 2013. Therefore management has determined it more reasonable to use the Company's 2013 fourth quarter results for comparison purposes.

	For the Quarter Ended
		March 31,	December 31,	%
		2014	2013	Change
Total Petroleum and natural gas production by product & project
Huntington
Crude Oil	bbl	312,724	237,828	32
Natural Gas	boe	37,953	38,011	(0.6)
Trent & Tyne
Natural Gas	boe	23,228	32,310	(28)
Total petroleum and natural gas production	boe	373,905	308,149	20
Average Daily Production by product
Crude Oil	bopd	3,475	2,585	34
Natural Gas	boepd	680	765	(17)
Total average daily production	boepd	4,155	3,350	23

Average net production for the quarter ended March 31, 2014 was 4,155 boepd compared to average net production during the comparable period in 2013 of 316 boepd and 3,350 boepd during the fourth quarter ended December 31, 2013. The increase in crude oil production to 3,475 bopd during the first quarter of 2014 compared to 2,585 bopd during the fourth quarter of 2013 was a result of improved production from the Huntington field due to better weather and limited gas transportation restrictions from the operator of CATS. Natural gas production decreased during the first quarter of 2014 to 680 boepd per day compared to 765 boepd per day during the fourth quarter of 2013 as a result of the continued shut downs in the Trent & Tyne gas fields resulting from continuing issues with the T6 water maker.

Of the total revenues of \$35.6 million for the quarter ended March 31, 2014, \$28.9 million (Dec 31, 2013 - \$25.2 million) was generated from oil production, \$4.1 million (March 31, 2013 - \$1.9 million) (Dec 31, 2013 – \$5.4 million) was generated from gas production, \$244,000 (Dec 31, 2013 - \$83,000) was generated from condensate and \$2.4 million (Dec 31, 2013 - \$3.1 million) was generated through a gross overriding royalty interest in the Huntington field.

The average realized oil price for the quarter ended March 31, 2014 was \$108 per bbl (Dec 31, 2013 - \$112 per bbl) compared to average Brent oil prices in the period of \$108 per bbl. The average realized gas price for the quarter ended March 31, 2014 was \$12.04 per mcf (Dec 31, 2013 - \$12.88 per mcf) of gas compared to average gas prices in the period of \$10.00 per mcf.

REVENUE

				For the Quarter Ended
	March 31, 2014		December 31, 2013		% Change
Petroleum and natural gas sales by product
Crude oil	\$	28,914	\$	25,208	15
Natural gas		4,137		5,350	(23)
Royalty interest		2,353		3,156	(25)
Condensate		244		83	194
Total	\$	35,648	\$	33,797	6

Revenue was \$35.6 million for the first quarter ended March 31, 2014 compared to revenue recorded in the comparable quarter in 2013 of \$1.86 million and \$33.8 million in the fourth quarter ended Dec 31, 2013.

Oil sales volumes increased slightly as a result of improved production from the Huntington field during the first quarter of 2014 compared to the fourth quarter of 2013. The decrease in gas sales in the first quarter compared to the previous quarter was due to a reduction in the Trent & Tyne gas volumes due to shut downs experienced since the third quarter of 2013.

INVENTORY

Inventory for the quarter ended March 31, 2014 was \$2.5 million (Dec 31, 2013 - \$1.8 million). Inventory relates to the Company's share of stock remaining in the FPSO storage tanks at March 31, 2014. 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.

COST OF SALES

	For the Quarter Ended
	March 31, 2014	December 31 2013		% Change
Operating costs(1)	\$ 6,508	\$	9,462	(31)
Depletion and depreciation	18,928		16,206	14
Total	\$ 25,436	\$	25,668	(3)

(1) \$2.1 million of operating costs, which had been understated in Q3, has been included in the Company's Q4 operating costs. Realized operating costs have been normalized. Operating costs for Q3 have not been restated.

Cost of sales were \$25.0 million compared to \$1.8 million during the first quarter of 2013 and \$25.7 million during the fourth quarter of 2013. Operating costs were \$6.5 million compared to \$796,000 during the first quarter of 2013 and \$9.5 million during the fourth quarter of 2013. The decrease in operating costs from the fourth quarter 2013 is due to increased production at Huntington where a certain percentage of operating costs are fixed. Depletion increased during the first quarter of 2014 to \$18.9 million compared to \$966,000 during the first quarter of 2013 and \$16.2 million during the fourth quarter of 2013. The increase In depletion from the fourth quarter of 2013 is a result of increased production from the Huntington field.

The costs were generated from the Huntington and Trent & Tyne fields as discussed in Key Projects, Production and Operations Update.

OPERATING NETBACKS

		For the Quarter Ended
	March 31,	December 31,	%
	2014	2013	Change
	\$/boe	\$/boe
Average Selling Price(1)	101.59	103.84	(2)
Operating Cost(2)	(20.01)	(24.94)	(20)
Netback from Operations	81.58	78.90	3

(1) Average Selling Price is inclusive of hedging.

(2) \$2.1 million of operating costs, which had been understated in Q3, has been included in the Company's Q4 operating costs. Realized operating costs have been normalized. Operating costs for Q3 have not been restated.

Operating costs include all costs to produce and sell the commodity. Operating costs decreased during the Company's first quarter to \$20.01 per boe compared to \$24.94 per boe in the fourth quarter of 2013 due to the increased production at Huntington where a certain percentage of operating costs are fixed.

Management expects operating costs on a per boe basis to decrease as production continues to increase and stabilize at each producing field.

GENERAL AND ADMINISTRATIVE EXPENSES

	For the Quarter Ended
		March 31,		March 31,	%
		2014		2013	Change
Consulting fees / wages	\$	515	\$	1,080	(52)
Professional fees		220		360	(39)
Stock option expense		38		1,707	(98)
Depreciation		14		-	-
Insurance		3		-	-
Travel, office costs and other		556		243	129
Total	\$	1,346	\$	3,390	(60)
Per boe	\$/boe	4.14		119.2	(97)

General and administrative costs were \$1.3 million for the three months ended March 31, 2014 compared to \$3.4 million for the period ended March 31, 2013. General and administrative costs for the quarter ended March 31, 2014 decreased from the comparative period in 2013 mainly as a result of decreased consulting fees and wages, and stock based compensation. Compensation decreased due to bonuses being granted in Q1 2013 in addition to stock option grants in Q1 2013 which resulted in an increased stock based compensation expense.

The stock option charge represents the fair value of the Company's stock options amortized over the respective vesting period via the graded vesting method. Pursuant to the plan, the Board of Directors determines the vesting provisions of the stock options at the date of grant. All of the options granted to date under the plan (other than options granted to a firm providing investor relations activities) vest as follows: ¼ immediately and ¼ vesting on the first, second and third anniversary dates. All unvested options vest upon the change of control of the Company. The options are nontransferable. The minimum exercise price is based on the trading price of the common shares on the date prior to the day of the grant less any applicable discount permitted by the TSX Venture Exchange. The future expense will vary as it is dependent on the number and vesting provisions of future stock option grants.

FOREIGN EXCHANGE

	For the Quarter Ended
		March 31, 2014	March 31, 2013		% Change
Foreign exchange gain / (loss)	\$	181	\$	239	(24)

During the quarter ended March 31, 2014, the Company recognized a foreign exchange gain of \$181,000 (2013 – \$239,000). The exchange gain in the quarter arose primarily as a result of the strengthening of the GBP against the USD increasing the value of the GBP working capital balances held in Iona UK.

RELATED PARTY TRANSACTIONS

During the three months ended March 31, 2014, the Company was charged \$50,000 (2013 - \$355,000), in legal fees of which \$NIL (2013 - \$96,000) related to share issuance costs by a law firm where a director of the Company is a partner, of which \$29,000 is included in accounts payable and accrued liabilities as at March 31, 2014 and \$29,000 as at December 31, 2013.

Included in accounts receivable is \$117,483 (2013 - \$265,000) due from a former officer and director of the Company who resigned from the Company's management team and Board. Of this amount \$117,483 remains to be collected as at March 31, 2014. The amounts owing are non-interest bearing and secured. The Company expects full repayment of the remaining balances in 2014.

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

SENIOR DEBT INSTRUMENTS

On September 27, 2013, Iona UK issued \$275 million in senior secured bonds (the "Bonds"), net of discounts of \$6.9 million and transaction cost of \$8 million, for \$260 million. As at March 31, 2014 the fair value of the Bonds were \$275 million. The bonds mature on September 30, 2018. The Bonds carry an annual coupon rate of 9.5% payable semiannually, were issued at 97.5% of par and are callable in whole or in part at the option of Iona UK at any time. Commencing 30 months after September 30, 2013, the Bonds will be repaid at 15% of the face value every six months with a 25% final payment at maturity. The Bonds contain certain early redemption options under which the Company has the option to redeem all or a portion of the Bonds at various redemption prices, which include the principal amount plus accrued and unpaid interest, if any, to the applicable redemption date. The Company reviewed the terms of the Bonds and determined that certain prepayment options were an embedded derivative. The fair value of the embedded derivative at inception was \$1,146,000. At March 31, 2014 the derivative was valued at \$Nil 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. At March 31, 2014 the balance of the Bonds of \$263,629,000 represents the Bonds amortized cost net of transaction costs of \$8 million and the initial fair value of the embedded derivative.

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

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

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

• minimum liquidity (defined as the restricted group's cash and cash equivalents) of at least \$30 million;
• a leverage ratio (defined as net interest bearing debt divided by twelve months of earnings before interest, taxes, depreciation and amortization ("EBITDA")) of not more than 3.0x; and
• ensure a minimum of both the capital employed ratio (defined as equity divided by the sum of equity and net interest bearing debt) and the restricted capital employed ratio (defined as restricted group equity divided by the sum of restricted group equity and net interest bearing debt) of 40% until December 31, 2016, and a minimum of 50% thereafter.

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

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

The Company was in breach of the Leverage Ratio at December 31, 2013. At March 31, 2014, the Company was in compliance with the leverage ratio due to the amendment to the Bond Agreement dated May 6, 2014.

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

	31-March-14	Covenant
Liquidity	\$108,701	Greater than \$30,000
Restricted Group Capital Employed Ratio	55%	Greater than 40%
Group Capital Employed Ratio	55%	Greater than 40%
Leverage Ratio	2.16	Not greater than 3.0x

DERIVATIVE INSTRUMENTS – COMMODITY HEDGING

The details of the hedging contracts entered into by the Company in the quarter are included in Corporate Transactions. The Company's derivative financial instruments measured at fair value as of March 31, 2014 are presented in the table below:

	Level 1	Level 2	Level 3	Total Fair Value
Current assets
Derivative financial assets	\$ -	-	-	\$ -
Current liabilities
Derivative financial instrument liabilities	-	21,637	-	21,637
Non-current liabilities
Derivative financial instrument liabilities	\$ -	25,687	-	\$ 25,687

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

		Three Months		Three Months
		Ended		Ended
	March 31, 2014			March 31 2013
Cost of derivative options	\$	-	\$	(7,348)
Unrealized gain / (loss) on commodity hedges		288		(16,339)
Total gain / (loss) on commodity hedges	\$	288	\$	(23,687)

COMMITMENTS

In addition to the amounts recorded in the condensed consolidated financial statements, based on management's best estimate, the Company has the following contractual obligations:

	March 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	17	51	51	\$	85
UK Segment
Office lease	130	87	43	-		-
Drilling, completion, facility construction	18,013	18,013	-	-		-
Total UK Segment	18,143	18,100	43	-		-
Corporate Segment
Office lease	10	10	-	-		-
Total Contractual Obligations	\$18,357	18,127	94	51	\$	85

LIQUIDITY AND CAPITAL RESOURCES

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 shareholders' equity. The Company's strategy is to access capital, primarily through equity issuances, reserve based lending, 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.

Cashflow from operations

Cash generated from operating activities, funds flow, during the first quarter of 2014 was \$27.1 million primarily due to cash generated from the Huntington oil field and the Trent & Tyne gas field.

Cashflow from financing activities

Cash used in financing activities during the first quarter of 2014 was \$13.1 million primarily due to the Company's interest payment payable on the Bond.

Cashflow from investing activities

Cash used in investing activities in the first quarter of 2013 was \$65,000 primarily due to capital expenditures on exploration and evaluation.

The Company continues to be fully funded, with more than sufficient financial resources to cover its anticipated future commitments from its existing cash balance and forecast cash flow from operations. No unusual trends or fluctuations are expected outside the ordinary course of business.

As at March 31, 2014, the Company had net assets of \$191.8 million, working capital of \$88.8 million and \$18.1 million of commitments due in the next twelve months.

Under the senior secured bonds, capital expenditures are limited to assets within the borrowing base (currently Huntington, Trent & Tyne, Orlando, Kells and Ronan & Oran). Allowable capital expenditures include: a) all cash calls by the Operators; b) all capital costs; c) all costs of producing, lifting, transporting, storing, processing and selling associated hydrocarbons; d) all costs of reinstating damaged facilities; e) all costs of satisfying any liability in respect of seepage, pollution and well control; f) all insurance premiums and all the fees, costs and expenses; g) all exploration and appraisal expenditures; h) all costs of abandonment, and any payments to make provision for abandonment costs; i) all royalties and other amounts payable under any Petroleum production license; j) all general and administrative expenditures; k) loan repayments and finance costs; and l) any other costs, expenses or payments as agreed to by the Lenders.

FINANCIAL RISKS

Crude oil and natural gas operations involve certain risks and uncertainties. These risks include, but are not limited to, commodity prices, foreign exchange rates, credit, operational and safety.

Operational risks are managed through a comprehensive insurance program designed to protect the Company from significant losses arising from risk exposures. Risks associated with commodity prices, interest and exchange rates are generally beyond the control of the Company; however, various hedging products may be considered to reduce the volatility in these areas.

Safety and environmental risks are addressed by compliance with government regulations as well as adoption and compliance of the Company's safety and environmental standards policy.

The Company will be exposed to concentration of credit risk as substantially all of the Company's accounts receivable will be with joint venture partners in the oil and gas industry and are subject to normal industry credit risks. The Company mitigates this risk by entering into transactions with long-standing, reputable counterparts and partners. If significant amounts of capital are to be spent on behalf of a joint venture partner, the partner is "cash called" in advance of the capital spending taking place.

All derivative instruments are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale and usage exemption. All changes in their fair value are recorded in income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income until the hedged transaction is recognized in net earnings.

The Company operates on an international basis and therefore foreign exchange risk exposures arise from transactions denominated in currency other than the United States 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 Pound sterling, Euros, United States dollars and Canadian dollars and is exposed to fluctuations in exchange rates in these currencies. There are no exchange rate contracts in place as at or during the period ended December 31, 2013, or thereafter.

Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates on the foreign cash and restricted cash balances at March 31, 2014 would have impacted the comprehensive loss of the Company for the three month period ended March 31, 2014 by approximately \$87,000 (three months ended March 31, 2013 – \$347,000).

In addition at March 31, 2014, the Company held approximately \$16,049,000 (£9,625,000) (2013-\$31,812,000 (£20,884,000)) of accounts payable in Pound Sterling. Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates at March 31, 2014 would impact the comprehensive loss of the Company for the three month period ended March 31, 2014 by approximately \$160,000 (three months ended March 31, 2013 - \$320,000).

OUTSTANDING SHARE DATA

The Company has authorized an unlimited number of Common shares, without nominal or par value and unlimited number of preferred shares, issuable in series. The Company, as at the date of this MD&A had 366,830,868 Common Shares, and 29,947,500 stock options outstanding.

The following details the stock option structure as of the date of this MD&A:

Date of Grant	Number Outstanding	Exercise Price CAD\$	Weighted Average Remaining Contractual Life	Date of Expiry	Number Exercisable
May 31, 2011	7,850,000	\$0.60	1.07 years	May 31, 2015	5,887,500
November 25, 2011	75,000	\$0.60	1.55 years	November 25, 2015	75,000
April 13, 2012	13,745,000	\$0.57	2.93 years	April 12, 2017	10,327,500
January 10, 2013	175,000	\$0.59	3.68 years	January 10, 2018	175,000
March 5, 2013	5,452,500	\$0.63	3.83 years	March 5, 2018	2,747,500
July 29, 2013	700,000	\$0.59	4.23 years	July 29, 2018	175,000
October 23, 2013	600,000	\$0.63	4.46 years	October 23, 2018	150,000
May 1, 2014	1,350,000	\$0.54	5.00 years	May 1, 2019	337,500
	29,947,500				19,875,000

SUMMARY OF QUARTERLY RESULTS

(\$ thousands, except per share amounts)
	2014	2013		2012
	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Revenue	\$35,648	33,797	18,082	11,771	1,858	-	-	\$ -
Average Daily Production (boepd) Crude oil (1)
	3,475	2,585	1,799	1,179	-	-	-	-
Natural Gas	680	765	927	755	316	-	-	-
Total	4,155	3,350	2,725	1,934	316	-	-	-
Net income / (loss)	\$(338)	31,553	899	9,188	(11,945)	(4,456)	(2,258)	\$(2,854)
Income / (loss) per share – basic	(0.00)	0.09	0.00	0.02	(0.03)	(0.01)	0.01	0.01
Income / (loss) per share – diluted	(0.00)	0.09	0.00	0.02	(0.03)	(0.01)	0.01	0.01
Funds Flow	27,088	28,225	11,397	1,364	(9,664)	(1,649)	(1,448)	(797)
Funds Flow per share – basic	0.07	0.08	0.03	0.00	(0.03)	(0.01)	(0.00)	(0.00)
Funds Flow per share – diluted	0.07	0.08	0.03	0.00	(0.03)	(0.01)	(0.00)	(0.00)
Adjusted EBITDA	27,143	27,936	12,737	3,230	3,281	(4,499)	(2,321)	(2,910)
Adjusted EBITDA per share – basic	0.07	0.08	0.03	0.01	0.01	(0.01)	(0.01)	(0.01)
Adjusted EBITDA per share – diluted	0.07	0.08	0.03	0.01	0.01	(0.01)	(0.01)	(0.01)
Working capital surplus/ (deficit)	88,776	79,075	71,247	(155,367)	(47,275)	(34,897)	40,863	70,177
Total assets	\$545,159	545,079	631,690	516,606	513,002	204,566	182,253	\$164,192
Weighted average common shares - basic	366,831	360,849	366,824	377,060	342,597	324,905	324,905	302,647
Weighted average common shares–fully diluted (1) Q2 2013 production has been adjusted for start of production for Huntington on April 12, 2013.	366,831	363,078	366,824	377,060	342,597	324,905	324,905	302,647

Comparative information has been restated to reflect the change in presentation currency from Canadian to US Dollar using the average rate in each respective quarter.

Over the past eight quarters, the Company's oil and gas sales have generally increased due to a successful drilling program and two business combinations. Fluctuations in production and the Brent benchmark price have also contributed to the fluctuations in oil and gas sales.

Net income has fluctuated primarily due to changes in funds flow from operations, unrealized derivative gains and losses, which fluctuate with the changes in forward market prices, along with associated fluctuations in the deferred tax expense (recovery).

CRITICAL ACCOUNTING ESTIMATES

The Company's management made judgements, assumptions and estimates in the preparation of the financial statements. Actual results may differ from those estimates. The accounting policies applied by the Company are described in Note 3 of the audited consolidated financials statements as at and for the year-ended December 31, 2013.

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

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

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

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

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

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

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

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

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

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

CHANGE IN FUNCTIONAL AND PRESENTATION CURRENCY

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

In 2013, the Company changed its presentation currency from the Canadian dollars ("CAD") to the US dollar. These consolidated financial statements are presented in US dollars, which is the Company's presentation currency. The change in presentation currency is to better reflect the Company's business activities and to improve investors' ability to compare the Company's financial results with other publicly traded businesses in the oil and gas industry. In making this change to the US dollar presentation currency, the Company followed the guidance in IAS 21 The Effects of Changes in Foreign Exchange Rates and have applied the change retrospectively as if the new presentation currency had always been the Company's presentation currency. In accordance with IAS 21, the financial statements for all years and periods presented have been translated to the new US dollar presentation currency. For the 2013 comparative balances, assets and liabilities have been translated into the presentation currency (US dollars) at the rate of exchange prevailing at the reporting date. The statements of comprehensive income (loss) were translated at the average exchange rates for the reporting period, or at the exchange rates prevailing at the date of transactions. Exchange differences arising on translation were taken to the foreign currency translation reserve in shareholders' equity.

ACCOUNTING POLICY CHANGES

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.
• IAS 39 "Financial Instruments: Recognition and Measurement" has been amended to clarify that there would be no requirement to discontinue hedge accounting if a hedging derivative was novated, provided certain criteria are met. The retrospective adoption of the amendments does not have any impact on Iona's financial statements.
• 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

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

In February 2014, the IASB tentatively decided to require an entity to apply IFRS 9 "Financial Instruments" for annual periods beginning on or after January 1, 2018. IFRS 9 is still available for early adoption. The full impact of the standard on Iona's financial statements will not be known until changes are finalized.

RISKS AND UNCERTAINTIES

Management defines risk as the evaluation of probability that an event might happen in the future that could negatively affect the financial condition and/or results of operations of Iona. The following section describes specific and general risks that could affect the Company. The following descriptions of risk do not include all possible risks, as there may be other risks of which management is currently unaware. Moreover, the likelihood that a risk will occur or the nature and extent of its consequences if it does occur, are not possible to predict with certainty, and the actual effect of any risk or its consequences on the business could be materially different from those described below.

Reliance on Third Parties

To the extent Iona is not the operator of its oil and natural gas properties, Iona will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators including the operators with respect to the Huntington and Trent & Tyne properties.

Foreign Operations

Presently, all of Iona's oil and gas operations and assets are located in foreign jurisdictions. As a result, Iona is subject to political, economic and other uncertainties, including but not limited to changes, sometimes frequent and applied retroactively, in energy policies or the personnel administering them, nationalization, expropriation of property without fair compensation, cancellation or modification of contract rights, foreign exchange restrictions, currency fluctuations, royalty and tax increases, and other risks arising out of foreign governmental sovereignty over the areas in which Iona's operations are conducted, as well as risks of loss due to civil strife, acts of war, guerilla activities and insurrections. Changes in legislation may affect Iona's oil and natural gas exploration and production activities. Iona's international operations may also be adversely affected by laws and policies of Canada as they pertain to foreign trade, taxation and investment.

Iona's subsidiary, Iona UK, was incorporated under the laws of Scotland. In addition, substantially all of Iona's oil and gas assets are located in the U.K. North Sea. The government of Scotland has proposed terms upon which Scotland could secede from the United Kingdom. If all required governmental approvals are obtained and such proposal for secession is implemented, Iona may be subject to substantial changes in legislation, including taxation and environmental legislation. The effect upon Iona of any such proposed changes being implemented is uncertain at this time.

In the event of a dispute arising in connection with its foreign operations, Iona may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in Canada or enforcing Canadian judgments in foreign jurisdictions. In addition, Iona's existing joint ventures and its subsidiaries were formed pursuant to, and their operations are governed by, a number of complex legal and contractual relationships. The effectiveness of and enforcement of such contracts and relationships with parties in these jurisdictions cannot be assured. Consequently, Iona's foreign exploration, development and production activities could be substantially affected by factors beyond Iona's control, any of which could have a material adverse effect on Iona.

Production Concentration

The Company's anticipated revenue for 2013 and 2014 is dependent upon production rates from the Company's Huntington and the Trent & Tyne fields as well as prevailing oil and natural gas prices in the UK marketplace. The Company is dependent upon revenue from these fields to service future obligations, including future obligations relating to the Bonds. The Company's current production is concentrated to a limited number of wells which are tied back to two production platforms (one for Huntington production and one for Trent & Tyne production). A decrease in production from the Huntington field or the Trent & Tyne field for any reason, including if the actual reserves associated with such fields are lower than the Company's estimated reserves for such fields, could have an adverse impact on the Company's operating results, financial position or ability to service its obligations. Additionally, issues at either of the two production platforms which constrain, delay or limit production, including without limitation, unanticipated delays, shutdowns, mechanical problems, extreme weather conditions or production curtailments by the facility operators, could also have an adverse impact on the Company's operating results, financial position or ability to service its obligations.

Financing Requirements and Liquidity

It may take many years and substantial cash expenditures to pursue exploration activities on Iona's existing undeveloped properties. Accordingly, Iona is likely to need to raise additional funds from outside sources in order to explore and develop its properties in a timely manner. Additionally, unexpected delays may result in significant increases in the capital expenditures required to develop projects.

Iona's financing risk relates to the availability and cost of equity or debt financing and is affected by many factors,

including world and regional economic conditions, the state of international relations, the stability and the legal, regulatory, fiscal and tax policies of various governments in areas of operation, fluctuations in the world and regional price of oil and gas and in interest rates, the outlook for the oil and gas industry in general and in areas in which Iona has or intends to have operations, and competition for funds from possible alternative investment projects. Although there have been improvements in the global economy and financial markets in recent months, there continues to be restrictions on the availability of credit which may limit Iona's ability to access debt or equity financing for its development projects.

Potential investors and lenders will be influenced by their evaluations of Iona and its projects, including their technical difficulty, and comparison with available alternative investment opportunities.

Iona continuously monitors its cash position, capital commitments and future capital requirements in order to ensure sufficient liquidity and capital resources are available. In the event that adequate funds from credit/loan facilities, suitable aligned partners or cashflows are not attained; Iona may be required to scale back certain projects or to raise additional funds.

Iona is also dependent upon continued access to the proceeds of the Bond offering to fund its development projects. An inability to access the proceeds of the Bond offering for any reason, including non-compliance with the operating covenants contained in the Bond Agreement may have a material adverse effect on Iona and its operations.

Loss from Operations

Iona had retained earnings as at March 31, 2014 of \$12,395,000 and \$12,733,000 as at December 31, 2013. No assurance can be given that Iona will not experience operating losses or write-downs of its oil and gas properties in the future.

Volatility of Crude Oil and Natural Gas Prices

Crude oil and natural gas are commodities that are sensitive to numerous worldwide factors, which are beyond Iona's control, and are generally sold at contract or posted prices. Changes in world crude oil and natural gas prices may significantly affect Iona's results of operations and cash generated from operating activities. Consequently, such prices may also affect the value of Iona's oil and gas properties and the level of spending for oil and natural gas exploration and development.

Iona's crude oil prices are based on various reference prices, primarily the WTI crude oil reference price and other reference prices such as UK Brent Light. Occasionally a differential in price exists between WTI and UK Brent Light. Adjustments are made to the reference price to reflect quality differentials and transportation. WTI and other reference prices are affected by numerous and complex worldwide factors such as supply and demand fundamentals, economic outlooks, production quotas set by the Organization of Petroleum Exporting Countries ("OPEC") and political events. Occasionally quality differentials are affected by local supply and demand factors.

Any material declines in prices could result in a reduction of Iona's net production revenue. The economies of producing from some wells may change as a result of lower prices, which could result in a reduction in the volumes of Iona's reserves and Iona limiting or abandoning an exploration program on its undeveloped properties. Iona might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in Iona's net production revenue. All of Iona'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.

Hedging

From time to time the Company may enter into agreements such as the Payment Swap and the hedging agreements entered into with the lenders in the Loan Facility to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Company will not benefit from such increases and the Company may nevertheless be obligated to pay royalties on such higher prices, even though such higher prices are not received by it, after giving effect to such agreements.

Offshore Exploration

Iona faces additional risks when conducting offshore activities. In particular, drilling conditions, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity, or other geological and mechanical conditions. Sub-sea tiebacks in the UK North Sea, while common, are also affected by weather conditions. Potential pipeline tie-backs can only be conducted from April to late September. Offshore oil and gas activities can also be affected by extreme weather and ocean phenomena arising from occurrences such as hurricanes and tsunamis. Due to general industry response to the BP Macondo Gulf of Mexico, it may be that extra delays in permitting and increased costs with respect to insured operations, oil spill mitigation and clean up will be incurred.

Availability of Drilling Equipment and Access Restrictions

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to Iona and may delay exploration and development activities. Iona is subject to the relatively limited availability of offshore drilling rigs to proceed with its UK North Sea drilling program.

Access to Production Facilities and Pipelines

Access to facilities and pipelines to process field production is an important consideration when developing fields in the North Sea. Such access is not guaranteed and directly affects the economics of a project. The United Kingdom government with the assistance of DECC has introduced a policy which has been adopted by the major operators of facilities in the North Sea that should allow access to facilities at a reasonable rate.

These types of initiatives are intended to ensure that reserves that cannot support facilities on a stand-alone basis can be developed.

Conflicting Interests with Partners

Joint venture, acquisition, financing and other agreements and arrangements must be negotiated with independent third parties and, in some cases, must be approved by governmental agencies. These third parties generally have objectives and interests that may not coincide with Iona's interests and may conflict with Iona's interests. Unless the parties are able to compromise these conflicting objectives and interests in a mutually acceptable manner, agreements and arrangements with these third parties will not be consummated.

In certain circumstances, the concurrence of co-venturers may be required for various actions. Other parties influencing the timing of events may have priorities that differ from Iona's, even if they generally share Iona's objectives. Demands by or expectations of governments, co-venturers, customers, and others may affect Iona's strategy regarding the various projects. Failure to meet such demands or expectations could adversely affect Iona's participation in such projects or its ability to obtain or maintain necessary licences and other approvals.

Changes to Development Plans

Development plans for the Company's properties are based on management's estimates as of the date of this MD&A. Development plans may change as a result of new information, events or as a result of business decisions. Any such changes could have a material effect on the Company's proposed capital expenditures and the timelines associated with the development of the Company's properties.

Foreign Currency Rate Risk

A significant portion of Iona's activities is transacted in or referenced to United States dollars, Canadian dollars or British Pounds Sterling. Iona's operating costs and certain of Iona's payments, in order to maintain property interests, is incurred in the local currency of the jurisdiction where the applicable property is located. As a result, fluctuations in the Canadian dollar and British pounds sterling against the United States dollar, and each of those currencies against any other local currencies in jurisdictions where properties of Iona are located, could result in unanticipated fluctuations in Iona's financial results which are denominated in US dollars. Iona has not entered into any risk management contracts to hedge its exposure to foreign exchange rates.

Commodity Price Risk

From time to time Iona may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, Iona would not benefit from such increases.

Governmental Regulation

The petroleum industry is subject to regulation and intervention by governments in such matters as the awarding of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and possibly expropriation or cancellation of contract rights. As well, governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and gas industry could reduce demand for natural gas and crude oil, increase costs and may have a material adverse impact on Iona. Export sales are subject to the authorization of provincial and federal government agencies and the corresponding governmental policies of foreign countries. Development of reserves and rates of return are also susceptible to changes in national fiscal policy.

The UK government does not assess a crown royalty against production. The current tax regime in the UK is favorable to companies of the Iona's size in that it allows full deductions of appraisal and development expense before any tax is payable. As of January 1, 2006, the supplementary tax rate applicable to North Sea oil and gas companies rose from 10% to 20%. This change resulted in an effective rate of corporation tax of 30% of profits after all capital and operating costs have been recovered, and an effective supplementary rate of 20% on profits after all capital and operating costs (excluding finance costs) have been recovered, resulting in an effective combined base and supplementary tax rate of no less than 50%. In 2009, a number of reforms were introduced to the North Sea fiscal regime aimed at fostering developments in smaller fields as well as more complex high pressure/high temperature and heavy oil fields. The smaller field relief is granted in respect of fields less than 20 MMbbls and is a potential benefit to Iona. Further favorable tax reforms were announced in January 2010 in which the additional tax allowances were extended to gas fields in frontier areas.

On March 24, 2011, the supplementary tax rate applicable to North Sea oil and gas companies increased unexpectedly from 20% to 32%. As a result, the effective combined base and supplementary tax rate rose from 50% to 62%.

On March 21, 2012, the UK Government increased the Small Field Allowance ("SFA") tax shelter availability from the 32% Supplemental tax charge for small developments. The size of fields that qualify for full SFA was increased to include all fields with reserves of under 45 MMboe and the tax allowance available to each field has been doubled from approximately \$120 million to \$240 million. The expectation is that this change will materially reduce the future effective tax rate of the Company.

During September 2012, the UK Government announced the Brown Field Allowance ("BFA"), which is a new tax relief to encourage investment in older oil and gas fields. The BFA will shield up to £250m of income in qualifying brown field projects, or £500m for projects in fields paying Petroleum Revenue Tax, from the 32% Supplementary Charge rate (providing tax relief of up to £80m or £160m respectively). The level of relief available to an individual project will depend on its size and unit costs. A qualifying project will be an incremental project increasing expected production from an offshore oil or gas field as described in a revised consent for development which is authorized by DECC on or after September 7, 2012, and has verified expected capital costs per tonne of incremental reserves in excess of £60. The maximum level of allowance will be £50/tonne and will be available to projects with verified expected capital costs of £80/tonne or above. The Company welcomes this announcement and hopes to utilize it on its qualifying projects in the future.

Based on Iona's present stage of development, Iona is able to avail itself of tax efficiencies with respect to tax pools and small field allowances and therefore expects the supplementary tax rate changes to have a small but negative effect on the present net worth of Iona's reserves. Any further changes to these laws would impact the net present worth of Iona's reserves. No assurances can be given that such an event would not re-occur.

Strategic Partnerships

As part of its development plan in the North Sea, Iona may consider the formation of strategic partnerships, potentially sharing development costs and, where appropriate, the acquisition or exchange of working interests. There is no assurance that any such strategic transaction will be entered into. If such strategic transaction is entered into, there is no assurance that such transaction will be successful.

Write-Off of Unsuccessful Properties and Projects

In order to realize the carrying value of its oil and gas properties and ventures, Iona must produce oil and gas in sufficient quantities and then sell such oil and gas at sufficient prices to produce a profit. Iona has a number of non-producing oil and gas properties. The risks associated with successfully developing such oil and gas properties are even greater than those associated with successfully continuing development of producing oil and gas properties, since the existence and extent of commercial quantities of oil and gas in unevaluated properties have not been fully established. Iona could be required to write-off some or all of its non-producing oil and gas properties if such projects prove to be unsuccessful.

Insurance

Iona's operations are subject to the risks normally associated with the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blowouts, cratering and fires, all of which could result in personal injuries, loss of life and damage to the property of Iona and others. In accordance with customary industry practice, Iona is not fully insured against all of these risks, nor are all such risks insurable. Damages and losses occurring as a result of such risks may give rise to claims against Iona.

Although Iona believes that it, or where applicable the operator, will carry adequate insurance with respect to its operations in accordance with industry practice, in certain circumstances Iona's, or where applicable the operator's, insurance may not cover or be adequate to cover the consequences of such events. The payment of such uninsured liabilities would reduce the funds available to Iona. The occurrence of a significant event that is not covered or not fully covered by insurance, or the insolvency of the insurer of such event, could have a materially adverse effect on the business, financial condition and results of operations of Iona. Moreover, there can be no assurance that Iona will be able to maintain adequate insurance in the future at rates that it considers reasonable.

Regulatory Approvals

The further development of Iona's properties requires the approval of applicable regulatory authorities to the plans of Iona with respect to the drilling and development of such properties. A failure to obtain such approval on a timely basis or material conditions imposed by such authority in connection with the approval would materially affect the prospects of Iona.

Dilution from Further Equity Issuances

If Iona issues additional equity securities to raise additional funding or as consideration for the acquisition of a company or assets, as the case may be, such transactions may substantially dilute the interests of Iona Shareholders, and reduce the value of their respective investment.

Dividends

The Company has neither declared nor paid any dividends on its Ordinary Shares since the date of its incorporation. Any payments of dividends on the Ordinary Shares of the Company will be dependent upon the financial requirements of the Company to finance future growth, the financial condition of the Company and other factors, which the Company's board of directors may consider appropriate in the circumstance. It is unlikely that the Company will pay dividends in the immediate or foreseeable future.

For additional information regarding the Company's risks and uncertainties, please refer to the Company's annual information form for the year ended December 31, 2013, which is available on SEDAR under the Company's profile at www.sedar.com.

Notes Regarding Oil and Gas Disclosure

As used in this MD&A, "boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

It should not be assumed that the present worth of estimated future net revenue represents the fair market value of the reserves disclosed in this MD&A. The reserve and related revenue estimates set forth in this MD&A are estimates only and the actual reserves and realized revenue may be greater or less than those calculated. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

As used in this MD&A, "possible reserves" are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Additionally, this MD&A uses certain abbreviations as follows:

Oil and Natural Gas Liquids		Natural Gas
bbls	barrels	mcf	thousand cubic feet
Mbbls	thousand barrels	mcf/d	thousand cubic feet per day
MMbbls MMboe	million barrels million barrels of oil equivalent	MMcf MMcf/d	millions of cubic feet millions of cubic feet per day
boepd bopd	barrels of oil equivalent per day barrels of oil per day	Bscf	billion standard cubic feet
NGLs	natural gas liquids

Additional information relating to the Company is available on SEDAR at www.sedar.com.