EXECUTIVE SUMMARY

Iona Energy Inc. (TSX-V: INA) announces its financial and operating results for the three and six months ended June 30, 2015.

Q2 2015 Highlights

Operating

Q2 2015 average net production of 3,303 barrels of oil equivalent per day ("boepd") (2014: 2,382 boepd).
Following constraints to Huntington production due to unavailability of the Central Area Transmission System ("CATS") gas export system, full production resumed from the Huntington field during April 2015.
o Huntington Q2 2015 average production of 20,607 boepd (gross), 3,091 boepd (net to the Company's 15% working interest (1)).
o Trent & Tyne Q2 2015 average production of 1,060 boepd (gross), 212 boepd (net to the Company's 20% working interest).
Orlando development remains on track for first production in Q4 2016. (1) Iona also benefits from a 0.75% differential lifting entitlement and a 1.8% royalty interest in the Huntington field.

Financial

Q2 2015 revenues of US\$16.3 million (2014: US\$27.1 million), Funds Flow of US\$7.9 million (2014: US\$3.3 million) and Adjusted EBITDA of US\$6.4 million (2014: US\$12.2 million).
Loss after tax of US\$47.6 million for Q2 2015 (2014: US\$28.0 million loss) following an impairment of the Huntington asset (US\$13.4 million) driven by a reduction in oil price expectations and related reduction in the deferred tax asset (US\$18.6 million).
Cash and restricted cash US\$74.0 million at the end of Q2 2015 (2014: US\$95.7 million) (US\$55.0 million (2014: US\$55.0 million) restricted for purposes of Orlando development).

Q2 2015 Operations Update

Huntington

Q2 2015 net production of 3,091 boepd.
Unconstrained production resumed during April 2015 following production constraints linked to access to CATS.
During Q2 2015 the Huntington partners finalized commercial amendments to the Huntington gas transportation agreement which are expected to deliver an improvement in certainty of gas export volumes.
The Huntington field partners continue to review how to maximize recovery from the field. Subsurface studies are ongoing which may support further capital investment in the field in the form of a sidetracked water-injection well in 2016.

Trent & Tyne

• Q2 2015 net production of 212 boepd.

Orlando

• Substantially all planned works relating to Orlando reception facilities on Ninian Central Platform ("NCP") were completed as planned during the summer shutdown period in June 2015 supporting the Company's objective of delivering first oil from Orlando in Q4 2016.

Post Period Highlights

Huntington production has remained robust with the CATS summer slowdown having limited impact following commercial amendments to the transportation agreements.
o July 2015 average Huntington production was 1,881 bbls of oil per day and 298 boe of associated gas per day exported into CATS (14,527 boe/day gross, 2,179 boe/day net to the Company's 15% working interest (1)).
o August 2015 (to August 24th) average for the Huntington field was 1,936 bbls of oil per day and 220 boe of associated gas per day exported into CATS (14,371 boe/day gross, 2,156 boe/day net to the Company's 15% working interest (1)).
Orlando 2015-2016 project costs budget reduced from US\$215 million to US\$192 million (gross).
o Iona has been able to take advantage of the favourable contracting environment for 2016 oilfield services and secured material further cost savings to the Orlando project.
o The revised budget represents an overall saving of US\$36 million, or 16%, versus the budget of US\$228 million when the management team joined in late 2014.
o In addition, as discussed below, certain industry counterparties have also agreed to defer payment or provide loans to fund certain of these capital expenditures.
Orlando development remains on track for first production in Q4 2016.
o Integrated riser hang off structure loaded onto supply vessel in August 2015 with installation
expected to be completed in September 2015. (1) Iona also benefits from a 0.75% differential lifting entitlement and a 1.8% royalty interest in the Huntington field.

Funding & Review Update

On July 1, 2015 Iona's UK subsidiary, Iona Energy Company (UK) plc, entered into a definitive sale and purchase agreement with GDF SUEZ E&P UK Ltd (part of the ENGIE Group) in respect of the Company's 2.5% interest in the Esmond Transportation System which includes Iona's associated interest in the EAGLES pipeline. The transaction completed in August 2015 and Iona received cash at closing of £1.3 million (approximately US\$2.0 million).

On July 30, 2015, the Company announced the details of a proposed restructuring (the "Restructuring") of Iona. The Restructuring comprises the following inter-conditional elements:

Farm out of Orlando and Ronan & Oran to a highly competent financial and technical partner, an upstream subsidiary of a global energy company.
o Sale of a 25% working interest in Orlando for US\$25.5 million development cost carry plus cash payments to Iona of US\$10.8 million after Orlando first oil.
o Partner would pay full costs of Ronan & Oran technical studies to earn an option to earn a 66.67% working interest in return for funding full costs of an appraisal well with a drill-or-drop decision required by end of 2015.
Funding arrangements agreed with a number of industry counterparties who would defer payment or provide loans to fund capex related to the Orlando field.
o All financing provided by industry counterparties at zero interest rate.
Senior secured bond debt (the "Bonds") to be reduced to US\$120 million.
o A cash repayment to bondholders of US\$24 million.
o Bondholders reducing the aggregate amount of outstanding Bonds to US\$120 million.
o Remaining Bonds in excess of US\$120 million being exchanged for new common shares in the Company representing 87% of the pro forma issued and outstanding common shares. The remaining Bonds are being exchanged at a conversion price of approximately CAD\$0.08 per share(2) .
o Interest payments to be payment-in-kind at a coupon rate of 10% until repayment of the industry
funding (reverting to cash interest at 9.5% once the industry funders have been repaid). (2) Assumes conversion takes place on September 30, 2015 and includes accrued interest to that date. The exact conversion price will depend on the date conversion occurs and the total level of accrued interest at that time.

On August 6, 2015, the Company announced that bondholders had approved the Restructuring.

All of the elements of the Restructuring described above are in agreed form but remain subject to negotiation and execution of final documentation. Some transactions or arrangements are subject to final Board approvals of counterparties, confirmatory legal due diligence and third party, co-venturer and regulatory consents. The Company envisages implementing all arrangements or transactions by the end of September 2015. There remains significant uncertainty with regard to the implementation of the Restructuring. In the event that the Restructuring is not implemented by September 30, 2015 then the Company will likely default under the terms of the Bonds.

FINANCIAL & OPERATING HIGHLIGHTS

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

	2015	Three months ended June 30, 2014 %		2015	Six months ended June 30, 2014	%
			Change			Change
Financial
Crude oil and natural gas revenues Cost of sales Depletion, Depreciation & Amortization Gross (Loss) / Profit	16,336 (5,928) (13,378) (2,970)	27,100 (11,103) (16,670) (673)	(40%) (47%) (20%) 341%	24,425 (13,491) (19,431) (8,497)	62,748 (17,611) (35,598) 9,539	(61%) (23%) (45%) (189%)
Gross Profit before DD&A	10,408	15,997	(35%)	10,934	45,137	(76%)
(Loss) / Income Before Tax	(28,936)	(24,065)	20%	(31,994)	(23,348)	37%
(Loss) After Tax Per share – basic (\$) Per share – diluted (\$)	(47,573) (0.13) (0.13)	(28,027) (0.08) (0.08)	70%	(61,122) (0.16) (0.16)	(28,365) (0.08) (0.08)	115%
Funds Flow(1)(2)	7,862	3,345	135%	10,025	30,433	(67%)
Adjusted EBITDA(1)(2)	6,392	12,166	(47%)	4,643	39,942	(88%)
Cash and cash equivalents Restricted cash Working capital surplus(1) Senior debt instrument			Asat June 30, , 31 2015 10,275 63,762 73,137 289,288			December 31, 2014 31,565 64,090 73,670 267,493
Common shares, end of period ('000) Fully diluted, end of period(1) ('000) Weighted average common shares – basic ('000) Weighted average common shares - fully diluted ('000)			370,581 430,562 370,581 370,581			370,581 403,929 368,105 368,105
	Three months ended June 30,				Six months ended June 30,
	2015	2014	%	2015	2014	%
Operational			Change			Change
Crude oil and natural gas production (boepd)(3) Crude oil Natural gas Total	2,653 650 3,303	1,952 430 2,382	36% 51% 39%	2,001 509 2,510	2,458 521 2,979	(19%) (2%) (16%)
Realized sales prices Crude oil (\$/boe) Natural gas (\$/mmcf) Average (\$/boe)	57.35 5.83 52.82	109.12 4.81 96.67	(47%) 21% (45%)	54.39 6.30 51.05	108.48 9.11 99.53	(50%) (31%) (49%)
Operating costs(1) (\$/boe) Netback(1) (\$/boe)(4)	20.57 32.25	44.88 51.79	(54%) (38%)	30.08 20.97	31.58 67.95	(5%) (69%)

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

(2) See reconciliation on page 5 & 6.

(3) Based on 15.0% direct working interest volumes from Huntington.

Huntington (15.0% Working Interest)

Iona's net Huntington average production for the three and six months ended June 30, 2015 was 3,091 boepd and 2,289 boepd respectively.
Production during Q2 2015 was constrained by availability of the CATS gas export infrastructure driven by repairs to equipment on the CATS riser platform. Normal service resumed in the second half of April 2015.
During Q2 2015 the Huntington partners finalized commercial amendments to the Huntington gas transportation agreement which are expected to deliver an improvement in certainty of gas export volumes on a long term basis.
Following receipt from the operator of a decommissioning plan in relation to the Huntington field, Iona is expecting to post a letter of credit for up to £7.5 million (US\$11.8 million) (net to its 15% interest) during Q4 2015 to provide against future decommissioning costs for the field.
The Huntington field partners continue to review how to maximize recovery from the field. Subsurface studies are on going which may support further capital investment in the field in the form of a sidetracked water-injection well in 2016.
In the second quarter of 2015, the Company has recognized an impairment charge of \$13.4 million with respect to the Huntington producing assets as a result of a reduction in commodity price expectations. A partial derecognition of deferred tax asset of \$18.6 million was also recognized as a result of the reduction in estimated future taxable profits available to offset the Company's accumulated tax losses.

Trent & Tyne (20% Working Interest)

• Iona's net Trent & Tyne average production for the three and six months ended June 30, 2015 was 212 boepd and 220 boepd, respectively.

Orlando (75% Working Interest)

Substantially all planned works relating to Orlando reception facilities on Ninian Central Platform ("NCP") were completed as planned during the summer shutdown period in June 2015 supporting the Company's objective of delivering first oil from Orlando in Q4 2016.
Integrated riser hang off structure loaded onto supply vessel in August 2015 with installation expected to be completed in September 2015.
The development plan for Orlando comprises the re-entering of the suspended 3/3b-13z well to drill a 3,000 foot horizontal production well which will be completed with dual Electric Submersible Pumps ("ESPs"). A subsea pipeline, power supply and control umbilical will be laid between the well-head and NCP approximately 10 km to the south west of the Orlando field.
The Company's latest capex estimate for the project has reduced from \$215 million to \$192 million (gross) for 2015 – 2016. In addition, certain industry counterparties have also agreed to defer payment or provide loans to fund certain of these capital expenditures.
Post period end Iona announced it had conditionally agreed to sell a 25% interest in the Orlando project to the upstream subsidiary of European energy company with an investment grade credit rating (the "Farm-Out Partner").
o The consideration payable to Iona will be a \$25.5 million development cost carry plus cash payments to Iona of \$10.8 million after Orlando first oil.
o The transaction is subject to final board approval of the Farm-Out Partner, confirmatory legal due diligence, execution of definitive transaction documentation and co-venturer and regulatory consents.
Initial production rates from the field are estimated by Iona at c. 10,500 bopd (gross) with year one decline in the range of 50 – 60% and year 2 decline in the range of 30 - 40%.

Ronan & Oran (100% Working Interest)

• Post period end Iona announced that the Farm-Out Partner had conditionally agreed to pay 100% of the costs of technical studies (capped at £350,000 (approximately US\$550,000)) relating to a potential appraisal well on the Ronan & Oran asset. Following completion of the studies, the Farm-Out Partner shall earn an option to acquire a 66.67% interest in the project in return for funding 100% of the costs (including sidetrack and testing programme) of an appraisal well.

MANAGEMENT DISCUSSION AND ANALYSIS

Business of the Company

Iona is an oil and natural gas production, appraisal, and development corporation focused on the United Kingdom's Continental Shelf ("UKCS").

The following Management's Discussion and Analysis ("MD&A") of Iona Energy Inc. ("Iona" or "the Company") is based on and should be read in conjunction with the condensed consolidated financial statements and accompanying notes of the Company as at and for the period ended June 30, 2015 which have been prepared in accordance with International Financial Reporting Standards ("IFRS") and should be read in conjunction with the Annual Information Form ("AIF") for the year ended December 31, 2014, the MD&A for the year ended December 31, 2014 and the audited consolidated financial statements as at and for the year ended December 31, 2014. Copies of these documents and additional information about Iona are available on SEDAR at www.sedar.com.

This MD&A is dated August 25, 2015. All currency amounts are expressed in United States Dollars (thousands) unless otherwise stated.

Forward Looking Statements

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 assuming completion of the Restructuring, statements regarding the material terms, anticipated effects and anticipated timing of the Restructuring, future obligations under Iona's Amended and Restated Bond Agreement (as defined herein) and hedging arrangements. 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. Such statements are based on various assumptions by Iona's management, including assumptions regarding future contractual terms relating to the Restructuring and the assumption that Iona will have 370,580,868 common shares outstanding immediately prior to the Restructuring. 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 the Restructuring is not implemented for any reason, the risk that the final terms of the definitive agreements implementing the Restructuring (or portions thereof) are different than those anticipated, the risk that the Restructuring is delayed or does not have the anticipated positive effect upon the Company, changes in market conditions, law or government policy, operating conditions and costs, operating performance, demand for oil and gas and related products, commodity 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

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.

Throughout this MD&A, the Company uses the terms "funds flow", "Adjusted EBITDA", "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 Company'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 generated from operating activities before changes in non-cash working capital. Adjusted EBITDA is calculated as net income before finance costs, finance income, transaction costs, derivative gains and losses, taxes, impairment, depletion, depreciation and amortization. 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:

	Period ended
	June 30,
	2015	2014
Cash flow (used in) / generated from operating
activities	(5,841)	27,101
Changes in non-cash working capital balances:
Accounts receivable	2,210	5,185
Prepaid expenses	1,766	593
Inventory	1,385	(561)
Accounts payable and accrued liabilities	10,505	(1,885)
Funds Flow	10,025	30,433

The following table reconciles net (loss) for the period to Adjusted EBITDA:

	Three months ended		Six months ended
	June 30,		June 30,
	2015 2014		2015	2014
Net (loss) for the period	(47,573)	(28,027)	(61,122)	(28,365)
Income tax expense	18,637	3,962	29,128	5,017
Finance costs	8,001	8,284	16,008	16,072
Finance income	(2)	(4)	(5)	(6)
Loss / (gain) on risk management contracts	481	8,762	(12,267)	8,474
Depletion, depreciation and amortization	13,378	16,670	19,431	35,598
Impairment of oil and gas properties	13,398	-	13,398	-
Transaction costs	72	2,519	72	3,152
Adjusted EBITDA	6,392	12,166	4,643	39,942

PRODUCTION AND PRICING

		Three months ended June 30,		Six months ended June 30,
		2015	2014	% Change	2015	2014	% Change
Total petroleum and natural gas production (net) by product & project
Huntington(1)
Crude Oil	bbl	241,432	177,663	36%	362,099	444,949	(19%)
Natural Gas	boe	39,888	21,173	88%	52,250	53,163	(2%)
Trent & Tyne
Natural Gas	boe	19,272	17,927	8%	39,810	41,155	(3%)
Total petroleum and natural gas
production (net)	boe	300,592	216,763	39%	454,159	539,267	(16%)
Average Daily Production (net) by product
Crude Oil	bopd	2,653	1,952	36%	2,001	2,458	(19%)
Natural Gas	boepd	650	430	51%	509	521	(2%)
Total average daily production	boepd	3,303	2,382	39%	2,510	2,979	(16%)

(1) Based on 15.0% direct working interest volumes from Huntington.

(2) For consistency Huntington 2014 production has been re-stated from 17.55% to 15.0%.

Average net daily production for the three and six months ended June 30, 2015 was 3,303 boepd and 2,510 boepd respectively compared to average net daily production during the comparable periods in 2014 of 2,382 boepd and 2,979 boepd respectively. Production during the three month period ended June 30, 2015 increased versus the comparable period in 2014 driven by performance of the Huntington field during Q2 2014 when issues with the FPSO and access to the CATS export route significantly constrained production. Production during the six month period ended June 30, 2015 decreased versus the comparable period in 2014 driven by the production issues experienced during Q1 2015 at the Huntington field.

		Three months ended June 30,		Six months ended June 30,
		2015	2014	% Change	2015	2014	% Change
Total petroleum and natural gas sales (net) by product & project
Huntington(1)
Crude Oil	bbl	229,012	208,289	10%	356,460	463,315	(23%)
Natural Gas	boe	39,888	21,173	88%	52,250	53,163	(2%)
Trent & Tyne
Natural Gas	boe	19,272	17,927	8%	39,810	41,155	(3%)
Total petroleum and natural gas sales (net)	boe	288,172	247,389	16%	448,520	557,633	(20%)
Average Daily Sales by product (net)
Crude Oil	bopd	2,517	2,289	10%	1,969	2,559	(23%)
Natural Gas	boepd	650	430	51%	509	521	(2%)
Total average daily sales (net)	boepd	3,167	2,719	16%	2,478	3,080	(20%)
Realized sales prices (net)
Crude oil	\$/boe	57.35	109.12	(47%)	54.39	108.48	(50%)
Natural gas	\$/mmcf	5.83	4.81	21%	6.30	9.11	(31%)
Average	\$/boe	52.82	96.67	(45%)	51.05	99.53	(49%)

(1) Based on 15.0% direct working interest volumes from Huntington.

Average net daily sales for the three and six months ended June 30, 2015 was 3,167 boepd and 2,478 boepd respectively compared to net average daily sales during the comparable period in 2014 of 2,719 boepd and 3,080 boepd respectively.

The average realized oil price for the three and six months ended June 30, 2015 was \$57.35 per boe and \$54.39 per boe respectively compared to \$109.12 and \$108.48 respectively in the comparable period in 2014. The average realized gas price for the three and six months ended June 30, 2015 was \$5.83 per mmcf and \$6.30 per mmcf compared to \$4.81 per mmcf and \$9.11 per mmcf respectively for the three and six months ended June 30, 2014.

REVENUE

	Three months ended June 30,		Six months ended June 30,
	2015	2014	% Change	2015	2014	% Change
Petroleum and natural gas sales by product Crude oil (1)	13,790	23,860	(42%)	20,358	52,775	(61%)
Natural gas (1)	2,140	1,160	84%	3,580	5,298	(32%)
Royalty interest (2) Condensate	364 42	2,080 -	(83%) -	415 72	4,434 241	(91%) (70%)
Total	16,336	27,100	(40%)	24,425	62,748	(61%)

(1) Huntington revenue recorded at 15.75% - 15.0% direct working interest plus 0.75% differential lifting entitlement.

(2) Reflects 1.8% royalty interest in the Huntington field.

Revenue from two major customers exceeded 10% of group consolidated revenue and amounted to \$12.9 million and \$7.5 million for the three and six months ended June 30, 2015 (2014: two major customers amounting to \$33.1 million and \$13.9 million) arising from sales of crude oil.

Of the total revenues of \$16.3 million and \$24.4 million for the three and six months ended June 30, 2015 (\$27.1 million and \$62.7 million for the three and six months ended June 30, 2014), \$13.8 million, 85% of total revenue and \$20.4 million, 83% of total revenue, was generated from oil production (2014 - \$23.9 million, 88% of total revenue and \$52.8 million, 84% of total revenue), respectively, \$2.1 million, 13% of total revenue and \$3.6 million, 15% of total revenue, was generated from gas production (2014 - \$1.1 million, 4% of total revenue and \$5.5 million, 9% of total revenue), respectively, and \$0.4 million, 2% of total revenue and \$0.4 million, 2% of total revenue, was generated through the Company's royalty interests in the Huntington field (2014 - \$2.1 million, 8% of total revenue and \$4.4 million, 7% of total revenue), respectively.

INVENTORY

Inventory for the quarter ended June 30, 2015 was \$2.3 million (2014 - \$943,000). Inventory relates to the Company's share of stock remaining in the FPSO storage tanks at June 30, 2015. 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

		Three months ended June 30,			Six months ended June 30,
	2015	2014	% Change	2015	2014	% Change
Operating costs	5,928	11,103	(47%)	13,491	17,611	(23%)
Depletion, depreciation and amortization	13,378	16,670	(20%)	19,431	35,598	(45%)
Total	19,306	27,773	(30%)	32,922	53,209	(38%)

Operating costs for the three and six months ended June 30, 2015 were \$5.9 million and \$13.5 million respectively compared to \$11.1 million and \$17.6 million during the three and six months ended June 30, 2014 respectively. Depletion, depreciation and amortization decreased during the three and six months ended June 30, 2015 to \$13.4 million and \$19.4 million respectively compared to \$16.7 million and \$35.6 million respectively during the three and six months ended June 30, 2014. The decrease in depletion, depreciation and amortization for the three and six months ended June 30, 2015 is a result of decreased production during the first quarter of 2015 and reduced carrying values for Huntington and Trent and Tyne fields in 2015 following impairment charges taken during Q3 and Q4 2014.

The costs were generated from the Huntington and Trent & Tyne fields as discussed in Key Asset Updates.

OPERATING NETBACKS

		Three months ended June 30,		Six months ended June 30,
	2015	2014	% Change	2015	2014	% Change
	\$/boe	\$/boe		\$/boe	\$/boe
Average Selling Price	52.82	96.67	(45%)	51.05	99.53	(49%)
Operating Cost Netback from Operations(1)	(20.57) 32.25	(44.88) 51.79	(54%) (38%)	(30.08) 20.97	(31.58) 67.95	(5%) (69%)

(1) Based on 15.0% direct working interest volumes from Huntington

Operating costs include all costs to produce and sell the commodity. Operating costs decreased during the three months ended June 30, 2015 to \$20.57 compared to \$44.88 during the comparable period in 2014 and decreased to \$30.08 per boe compared to \$31.58 during the six months ended June 30, 2014.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended June 30,			Six months ended June 30,
		2015	2014	% Change	2015	2014	% Change
Consulting fees / wages		1,040	2,139	(51%)	1,612	2,654	(39%)
Professional fees		335	(158)	(312%)	538	62	768%
Stock option expense		(96)	81	(219%)	64	119	(46%)
Depreciation		48	11	336%	95	25	280%
Insurance		48	246	(80%)	55	249	(78%)
Travel, office costs and other		559	895	(38%)	972	1,451	(33%)
Recurring G&A expense		1,934	3,214	(40%)	3,336	4,560	(27%)
Per boe	\$/boe	6.71	12.99	(48%)	7.44	8.18	(9%)
Financing & bond restructuring fees		1,766	-	-	2,632	-	-
Total		3,700	3,214	15%	5,968	4,560	31%
Per boe	\$/boe	12.84	12.99	(1%)	13.31	8.18	63%

Recurring general and administrative costs were \$1.9 million and \$3.3 million for the three and six months ended June 30, 2015, respectively, compared to \$3.2 million and \$4.6 million for the three month and six months ended June 30, 2014, respectively and total general and administrative costs were \$3.7 million and \$6.0 million for the three and six months ended June 30, 2015, respectively, compared to \$3.2 million and \$4.6 million for the three and six months ended June 30, 2015, respectively.

The increase in total general and administration costs for the three months ended June 30, 2015 is a result of bond restructuring fees and related professional advisor costs of \$1.8 million and an increase in professional fees in Q2 2015 offset by a decrease in consulting fees and wages, stock option expense, insurance, travel, office costs and other costs.

The increase in total general and administration costs for the six months ended June 30, 2015 is a result of bond restructuring fees and related professional advisor costs of \$2.6 million and an increase in professional fees in Q2 2015 offset by a decrease in consulting fees and wages, stock option expense, insurance, travel, office costs and other costs.

FOREIGN EXCHANGE

		Three months ended June 30,			Six months ended June 30,
	2015	2014	% Change	2015	2014	% Change
Foreign exchange loss	(316)	(533)	(41%)	(323)	(352)	(8%)

During the three and six months ended June 30, 2015, the Company recognized a foreign exchange loss of \$316,000 and \$323,000 (2014 – Loss of \$533,000 and \$352,000). The exchange loss in the quarter arose primarily as a result of the strengthening of the GBP against the USD increasing the value of the GBP payable working capital balances held in Iona UK.

RELATED PARTY TRANSACTIONS

During the three and six months ended June 30, 2015, the Company was charged \$95,000 (2014 - \$65,000) and \$130,000 (2014 - \$99,000) respectively, in legal fees by a law firm where a director of the Company is a partner, of which \$38,000 is included in accounts payable and accrued liabilities as at June 30, 2015 and \$49,000 as at June 30, 2014.

Included in accounts receivable is \$94,092 (2014 - \$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 in the future.

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%. These notes are secured by 1,250,000 outstanding common shares and 1,250,000 warrants issued on August 29, 2014. At June 30, 2015 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 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 March 27, 2015, Iona UK amended the terms of the Bond Agreement as follows:

Full waiver of financial covenants through to first oil at Orlando including net debt/EBITDA and minimum capitalization ratios.
Conversion of interest payments to payment-in-kind (i.e. added to principal, therefore non-cash) for 2015 and 2016.
Increase in the coupon rate from 9.5% to 12.5% until first oil at Orlando at which time the coupon rate will return to 9.5%.
Scheduled 2016 amortization payments (\$85 million in aggregate) deferred until bond maturity in September 2018.
Bondholders received a fee in the form of non-transferable warrants (the "Warrants") to purchase common shares of the Company representing in aggregate 10% of the existing common shares of the Company. The Warrants have an exercise price of CAD\$0.05 per warrant. The Warrants are exercisable until September 27, 2018 and will be subject to a hold period of four months and a day from issuance.

The revised maturity schedule is as per the table below:

Payment date	Nominal instalment amount	Premium on nominal instalment
The later of 90 days after first oil from Orlando and March 2017	41,250	5%
September 2017	41,250	4%
March 2018	41,250	3%
September 2018 (Maturity)	The remaining Outstanding Bonds	2%

As required by IAS 32 and 39 the Company assessed if the amendments resulted in a substantial modification of terms and future cash flow (defined as a greater than 10% change). The Company determined that the amendments were not significant and therefore all costs relating to the amendments have been deferred and amortized using the effective interest rate method.

The Warrants were issued on May 8, 2015. The fair value of the Warrants was estimated using the Black Scholes option pricing model with the following assumptions:

	March 27, 2015
Stock price	CAD\$ 0.07
Exercise price	CAD\$ 0.05
Dividend yield	Nil
Expected volatility	51%
Risk-free rate	0.63%
Expected life	3.5 years

The effective interest rate on the bond at June 30, 2015 was 12.02%.

As at December 31, 2014	267,493
Amortization of discount and transaction costs	932
Paid in kind interest	21,849
Amendment Fee (Warrants)	(986)
As at June 30, 2015	289,288

As at June 30, 2015 the fair value of the Bonds was \$79.1 million (2014: \$212 million). The Bonds mature on September 30, 2018.

On April 17, 2015, the Company executed an amended and restated Bond agreement (the "Amended and Restated Bond Agreement") among the Issuer and Nordic Trustee ASA, as bond trustee, setting out the terms and conditions of the Bond amendments governing the Bonds. Full details of the amendments can be found in the Amended and Restated Bond Agreement which was filed on SEDAR.

On July 30, 2015, the Company announced the details of a proposed Restructuring of Iona. The Restructuring comprises the following inter-conditional elements:

Farm out of Orlando and Ronan & Oran to a highly competent financial and technical partner, an upstream subsidiary of a global energy company.
o Sale of a 25% working interest in Orlando for US\$25.5 million development cost carry plus cash payments to Iona of US\$10.8 million after Orlando first oil.
o Partner would pay full costs of Ronan & Oran technical studies to earn an option to earn a 66.67% working interest in return for funding full costs of an appraisal well with a drill-or-drop decision required by end of 2015.
Funding arrangements agreed with a number of industry counterparties who would defer payment or provide loans to fund capex related to the Orlando field.
o All financing provided by industry counterparties at zero interest rate.
Bond debt to be reduced to US\$120 million.
o A cash repayment to bondholders of US\$24 million.
o Bondholders reducing the aggregate amount of outstanding Bonds to US\$120 million.
o Remaining Bonds in excess of US\$120 million being exchanged for new common shares in the Company representing 87% of the pro forma issued and outstanding common shares.
o Interest payments to be payment-in-kind at a coupon rate of 10% until repayment of the industry funding (reverting to cash interest at 9.5% once the industry funders have been repaid).

On August 6, 2015, the Company announced that bondholders had approved the Restructuring.

DERIVATIVE INSTRUMENTS – COMMODITY HEDGING

The Company's derivative financial instruments measured at fair value as of June 30, 2015 are presented in the table below:

	Level 1	Level 2	Level 3	Total Fair Value
Current assets
Derivative financial assets	-	2,533	-	2,533
Current liabilities
Derivative financial instrument liabilities	-	-	-	-
Non-current liabilities
Derivative financial instrument liabilities	-	8,711	-	8,711

The table below presents the total (loss) / gain on financial instruments that has been disclosed through the consolidated statement of profit or loss and comprehensive loss:

		Three Months Ended		Six Months Ended
		June 30, 2015		June 30, 2015
	2015	2014	2015	2014
Unrealized (loss) / gain on derivative instruments	(2,108)	(2,832)	7,025	(2,544)
Realized gain / (loss) on derivative instruments	1,627	(5,930)	5,242	(5,930)
Total (loss) / gain on derivative instruments	(481)	(8,762)	12,267	(8,474)

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. At June 30, 2015, the fair value of the Bonds was \$79.1 million (December 31, 2014: \$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 their short maturities.

COMMITMENTS

In addition to accounts payable, accrued liabilities and senior debt instrument obligations (see above) and based on management's best estimate, the Company has the following contractual obligations:

	June 30, 2015 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	68	51	68
UK Segment
Office lease	3,921	451	1,128	903	1,439
Equipment leases	29,947	8,403	21,544	-	-
Drilling, completion, facility construction	42,385	19,219	23,166	-	-
Total UK Segment	76,253	28,073	45,838	903	1,439
Total Contractual Obligations	76,457	28,090	45,906	954	1,507

During the six month period \$224,000 (2014: \$219,000) of office rent was charged through general and administrative expense and \$5,566,000 (2014: \$5,702,000) relating to the rental of the FPSO was charged through operating expense.

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 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.

Cashflow from operations

Funds Flow, during the second quarter of 2015 was \$7.9 million an increase from \$3.3 million generated in the second quarter of 2014 primarily due to unconstrained production from Huntington in Q2 2015. Cash generated from operating activities in the second quarter of 2015 was \$5.5 million and increase from \$876,000 generated in the second quarter of 2014.

Cashflow from financing activities

Cash used in financing activities during the second quarter of 2015 was (\$94,000) compared to (\$324,000) in the second quarter of 2014.

Cashflow from investing activities

Cash used in investing activities in the second quarter of 2015 was (\$5.4 million) compared to cash used in investing activities of (\$818,000) in the second quarter of 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. On April 17, 2015, the Company executed the Amended and Restated Bond Agreement among the Issuer and Nordic Trustee ASA, as bond trustee, setting out the terms and conditions of the Bond amendments governing the Bonds. Further details are explained in Note 12 and full details of the amendments can be found in the Amended and Restated Bond Agreement which was filed on SEDAR.

Related to the terms of those amendments, the Company 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.

On July 30, 2015, the Company announced the details of a proposed Restructuring of Iona. The Restructuring comprises the following inter-conditional elements:

Farm out of Orlando and Ronan & Oran to a highly competent financial and technical partner, an upstream subsidiary of a global energy company.
o Sale of a 25% working interest in Orlando for US\$25.5 million development cost carry plus cash payments to Iona of US\$10.8 million after Orlando first oil.
o Partner would pay full costs of Ronan & Oran technical studies to earn an option to earn a 66.67% working interest in return for funding full costs of an appraisal well with a drill-or-drop decision required by end of 2015.
Funding arrangements agreed with a number of industry counterparties who would defer payment or provide loans to fund capex related to the Orlando field.
o All financing provided by industry counterparties at zero interest rate.
Bond debt to be reduced to US\$120 million.
o A cash repayment to bondholders of US\$24 million.
o Bondholders reducing the aggregate amount of outstanding Bonds to US\$120 million.
o Remaining Bonds in excess of US\$120 million being exchanged for new common shares in the Company representing 87% of the pro forma issued and outstanding common shares.
o Interest payments to be payment-in-kind at a coupon rate of 10% until repayment of the industry funding (reverting to cash interest at 9.5% once the industry funders have been repaid).

On August 6, 2015, the Company announced that bondholders had approved the Restructuring.

There remains significant uncertainty with regard the implementation of the Restructuring. In the event that the Restructuring is not implemented by September 30, 2015 then the Company will likely default under the terms of the Bonds. 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.

As at June 30, 2015, the Company had net assets of \$15.4 million, working capital of \$73.1 million and \$28.1 million of commitments due in the next twelve months.

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 may be "cash called" in advance of the capital spending taking place. See also "Risks and Uncertainties – Conflicting Interests with Partners."

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 expenditure in property and equipment in foreign currencies. The Company incurs expenditure in Pound sterling, Euros, Norwegian krone, 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 June 30, 2015, 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 June 30, 2015 would have impacted the comprehensive loss of the Company for the six month period ended June 30, 2015 by approximately \$19,000 (six months ended June 30, 2014: \$26,000).

In addition at June 30, 2015, the Company held approximately \$6,198,000 (£3,941,000) (2014: \$16,049,000 (£9,625,000)) of accounts payable in Pound Sterling. Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates between Pound Sterling and US dollar at June 30, 2015 would impact the comprehensive loss of the Company for the six month period ended June 30, 2015 by approximately \$62,000 (six months ended June 30, 2014 - \$151,000).

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 June 30, 2015 had 370,580,868 Common Shares, 40,808,086 warrants and 19,172,500 stock options outstanding.

The following details the stock option structure as at June 30, 2015:

		Weighted
	Number of	Average
Stock Options	Options	Exercise Price CAD\$
Opening balance, December 31, 2014	29,597,500	\$0.56
Granted	-	-
Exercised	-	-
Expired	(6,900,000)	\$0.60
Forfeited	(3,525,000)	\$0.58
Ending balance, June 30, 2015	19,172,500	\$0.54
Exercisable, end of period	14,870,000	\$0.57

Date of Grant	Number of Options Outstanding	Exercise Price CAD\$	Weighted Average Remaining Contractual Life	Date of Expiry	Number Exercisable June 30, 2015
April 12, 2012	9,900,000	\$0.57	1.79 years	April 12, 2017	9,900,000
March 5, 2013	4,110,000	\$0.63	2.68 years	March 5, 2018	3,307,500
October 23, 2013	300,000	\$0.63	3.32 years	October 23, 2018	300,000
April 30, 2014	300,000	\$0.54	3.84 years	April 30, 2019	175,000
July 1, 2014	62,500	\$0.49	3.97 years	June 19, 2019	62,500
September 1, 2014	4,500,000	\$0.40	3.18 years	September 1, 2019	1,125,000
	19,172,500				14,870,000

The Company's share options granted vest as follows: ¼ immediately and ¼ vesting on the first, second and third anniversary dates and expire five years from the date of issue.

The following details the share warrants structure as at June 30, 2015:

Date of Grant	Number of Warrants Outstanding	Exercise Price CAD\$	Weighted Average Remaining Contractual Life	(i) Date of Expiry	Number Exercisable June 30, 2015
August 29, 2014		3,750,000\$0.48 - \$1.00	4.17 years	September 1, 2019	3,750,000
April 17, 2015	37,058,086	\$0.05		3.24 years September 27, 2019	37,058,086
	40,808,086				40,808,086

SUMMARY OF QUARTERLY RESULTS

(\$ thousands, except per share amounts)
	2015		2014				2013
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Revenue	16,336	8,089	5,367	22,403	27,100	35,648	33,797	18,010
Average Daily Production (boepd)
Crude oil (1)	2,653	1,341	379	1,940(3)	1,952(3)	2,970(3)	2,209(3)	1,537(3)
Natural Gas	650	366	243	422(3)	430(3)	614(3)	745(3)	914(3)
Total	3,303	1,707	622	2,362(3)	2,382(3)	3,584(3)	2,954(3)	2,451(3)
Net (loss) / income	(47,573)	(13,549)	(48,598)	(42,487)	(28,027)	(338)	31,395	899
(Loss) / income per share – basic	\$(0.13)	\$(0.04)	(0.13)	(0.12)	(0.08)	(0.00)	0.09	0.00
(Loss) / income per share – diluted	\$(0.13)	\$(0.04)	(0.13)	(0.12)	(0.08)	(0.00)	0.09	0.00
Funds Flow(4)	7,862	2,163	(2,807)	(19,277)	3,345	27,088	24,181	4,983
Adjusted EBITDA(2) (4)	6,392	(1,748)	(6,275)	10,082	12,166	27,776	23,321	18,263
Working capital surplus(4)	73,137	72,706	73,670	85,924	88,847	88,776	79,075	71,247
Total assets	386,969	425,312	460,158	482,169	544,072	545,159	545,079	631,690
Weighted average common shares basic ('000s)	370,581	370,581	368,105	368,054	366,831	366,831	360,849	366,824
Weighted average common shares– diluted ('000s)	370,581	370,581	368,105	368,054	366,831	366,831	363,078	366,824

(1)

Q2 2013 production has been adjusted for start of production for Huntington on April 11, 2013. (2) Q3 and Q4 2013 EBITDA has been adjusted for the restatement of Q3 2013 finance costs. See Note 16 of the Q3 2014 interim condensed financial statements. (3)

For consistency Huntington production has been restated from 17.55% to 15% working interest. (4)

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

Comparative information has been restated to reflect the change in presentation currency from Canadian to US Dollar using the average rate for income statement and cash flow data and the rate at the end of the period for balance sheet data in each respective quarter.

Revenue, Funds Flow and Adjusted EBITDA increased during Q2 2015 versus Q1 2015 as a result of the Huntington field resuming full production during April 2015.

The net loss in Q2 2015 has increased against Q1 2015 as result of the impairment of the Huntington asset and the movement in the recognition of deferred tax assets.

CRITICAL ACCOUNTING JUDGMENTS AND ESTIMATES

The Company's management made judgments, assumptions and estimates in the preparation of the consolidated 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, 2014.

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 a material impact on the consolidated financial statements in future periods.

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 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.

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. 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.

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. 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 production and 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 valuein-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.

Decommissioning Obligations

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.

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.

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.

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.

ACCOUNTING POLICY CHANGES

Changes in accounting policies

As of January 1, 2015, the Company adopted several new IFRS interpretations and amendments in accordance with the transitional provisions of each standard. The adoption of these standards and amendments did not impact the Company.

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

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.

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:

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

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.

Risks Related to the Senior Debt Instruments

During the lifetime of the Bonds, Iona will be required to make payments on the Bonds. Additionally, Iona is required to undertake certain other actions under the terms of the Bond amendments. The ability to generate cash flow from operations and to make scheduled payments on indebtedness, including the Bonds, will depend on future financial performance. The future performance of Iona will be affected by a range of economic, competitive, governmental, operating and other business factors, many of which cannot be controlled, such as general economic and financial conditions in the industry or the economy at large. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition or other events could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on the business, financial condition or results of operations, as well as Iona's ability to service its debt, including the Bonds, and other obligations. If Iona is unable to service its indebtedness or fulfil its other obligations under the Amended and Restated Bond Agreement, it will be forced to adopt an alternative strategy that may include actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing indebtedness or seeking equity capital. In addition, any failure to make scheduled payments of interest and principal on outstanding indebtedness is likely to result in a reduction of credit rating, which could harm the ability to incur additional indebtedness on acceptable terms. Iona cannot assure investors that any of these alternative strategies could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on the Bonds and our other indebtedness.

On July 30, 2015, the Company announced the details of a proposed Restructuring of Iona. The Restructuring comprises the following inter-conditional elements:

Farm out of Orlando and Ronan & Oran to a highly competent financial and technical partner, an upstream subsidiary of a global energy company.
o Sale of a 25% working interest in Orlando for US\$25.5 million development cost carry plus cash payments to Iona of US\$10.8 million after Orlando first oil.
o Partner would pay full costs of Ronan & Oran technical studies to earn an option to earn a 66.67% working interest in return for funding full costs of an appraisal well with a drill-or-drop decision required by end of 2015.
Funding arrangements agreed with a number of industry counterparties who would defer payment or provide loans to fund capex related to the Orlando field.
o All financing provided by industry counterparties at zero interest rate.
Bond debt to be reduced to US\$120 million.
o A cash repayment to bondholders of US\$24 million.
o Bondholders reducing the aggregate amount of outstanding Bonds to US\$120 million.
o Remaining Bonds in excess of US\$120 million being exchanged for new common shares in the Company representing 87% of the pro forma issued and outstanding common shares.
o Interest payments to be payment-in-kind at a coupon rate of 10% until repayment of the industry funding (reverting to cash interest at 9.5% once the industry funders have been repaid).

On August 6, 2015, the Company announced that bondholders had approved the Restructuring.

There remains significant uncertainty with regard to the implementation of the Restructuring. In the event that the Restructuring is not implemented by September 30, 2015 then the Company will likely default under the terms of the Bonds. 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.

In addition, if the Issuer defaults on its obligations to make payments in respect of the Bonds, the amount of proceeds that ultimately would be distributed in respect of the Bonds upon a foreclosure or other enforcement action may not be sufficient to satisfy the obligation under the Bonds. There can be no assurance that the proceeds from any sale or liquidation of the collateral used to secure the Bonds will be sufficient to meet the obligations under the Bonds.

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.

Production Concentration

The Company's anticipated revenue 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 installations (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 achieve revenues from 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. 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. See further details provided in the Senior Debt Instruments section above.

Loss from Operations

Iona had a retained deficit as at June 30, 2015 of \$167,839,000 and a retained deficit of \$106,717,000 as at December 31, 2014. 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 primarily in UK Brent. Brent 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 economics 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 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.

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 typically can only be conducted from April to late September. Offshore oil and gas activities can also be affected by extreme weather. 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 the Oil and Gas Authority has introduced a policy which has been adopted by the major operators of facilities in the North Sea that are aimed at allowing 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 licenses and other approvals.

The success of Iona's oil and gas projects, including the Orlando development and potential future capital expenditures relating to the Huntington development, will depend upon the financial strength and views of Iona and its joint venture partners at the time that decisions for development are made. Iona or its joint venture partners may be unable or unwilling to commit funding to particular phases of development projects. Iona's partner in the Orlando development, Atlantic Petroleum UK Limited, has announced that it is undertaking a strategic review process and, absent successful completion of the process, will not be fully funded for 2016. In circumstances where partners are unable or unwilling to commit funding, Iona's ability to develop its projects may be adversely affected which may have a material adverse effect on Iona's business, prospects and financial condition.

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, are 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.

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 in that it allows full deductions of appraisal and development expense before any tax is payable. Iona's fields are subject to ring fence corporation tax and supplementary charge. The current prevailing corporation tax rate in the UK is 30% of profits after all capital and operating costs have been recovered, and the supplementary charge rate is 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%.

Effective January 1, 2015 the UK Government amended the tax legislation to introduce a new investment allowance (the "Investment Allowance") to reduce the amount of adjusted ring fence profits subject to the supplementary charge. The portion of profits reduced by the allowance will be dependent on a company's investment expenditure and will be generated at 62.5% of that spend.

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 a reduction to the supplementary tax rate from 32% to 20% on January 1, 2015 had a 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.

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.

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.

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, 2014, which is available on SEDAR under the Company's profile at www.sedar.com.

Notes Regarding Oil and Gas Disclosure

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.

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.

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Energy SpA — Management Reports 2015

4100_rns_2015-08-25_6ecf0b27-930b-437b-9cc8-f89c2edbb355.pdf

EXECUTIVE SUMMARY

Q2 2015 Highlights

Operating

Financial

Q2 2015 Operations Update

Post Period Highlights

Funding & Review Update

FINANCIAL & OPERATING HIGHLIGHTS

Huntington (15.0% Working Interest)

Trent & Tyne (20% Working Interest)

Orlando (75% Working Interest)

Ronan & Oran (100% Working Interest)

MANAGEMENT DISCUSSION AND ANALYSIS

Business of the Company

Forward Looking Statements

Non-GAAP Financial Measures

PRODUCTION AND PRICING

REVENUE

INVENTORY

COST OF SALES

OPERATING NETBACKS

GENERAL AND ADMINISTRATIVE EXPENSES

FOREIGN EXCHANGE

RELATED PARTY TRANSACTIONS

SENIOR DEBT INSTRUMENTS

DERIVATIVE INSTRUMENTS – COMMODITY HEDGING

COMMITMENTS

LIQUIDITY AND CAPITAL RESOURCES

Cashflow from operations

Cashflow from financing activities

Cashflow from investing activities

FINANCIAL RISKS

OUTSTANDING SHARE DATA

SUMMARY OF QUARTERLY RESULTS

CRITICAL ACCOUNTING JUDGMENTS AND ESTIMATES

Functional currencies

Depletion, depreciation and amortization amounts

Share based compensation plans

Joint arrangements

Funding arrangements

Exploration and Evaluation Assets

Determination of Cash Generating Units

Impairment Indicators

Decommissioning Obligations

Derivative Financial Instruments

Commitments

Contingent Liabilities

Recognition of Deferred Tax Assets

ACCOUNTING POLICY CHANGES

Changes in accounting policies

Future Changes in Accounting Policies:

RISKS AND UNCERTAINTIES

Risks Related to the Senior Debt Instruments

Reliance on Third Parties

Production Concentration

Financing Requirements and Liquidity

Loss from Operations

Volatility of Crude Oil and Natural Gas Prices

Hedging

Offshore Exploration

Availability of Drilling Equipment and Access Restrictions

Access to Production Facilities and Pipelines

Conflicting Interests with Partners

Changes to Development Plans

Foreign Currency Rate Risk

Governmental Regulation

Write-Off of Unsuccessful Properties and Projects

Regulatory Approvals

Dilution from Further Equity Issuances

Notes Regarding Oil and Gas Disclosure

More from Energy SpA

Energy SpA Management Reports 2015