EXECUTIVE SUMMARY

Iona Energy Inc. (TSX-V: INA) announces its financial and operating results for the three and nine months ended September 30, 2014.

Highlights

Q3 2014 average production of 2,736 boepd
Revenues of \$22.4 million and Adjusted EBITDA of \$10.1 million
New management team appointed and led by Iain McKendrick, Executive Chairman, Tom Reynolds, Chief Executive Officer and Robert Gair, Chief Financial Officer
Re-focussed strategy based on "Production, Scale, Yield"
o Seeking growth through acquisition to build scale, increase production, reserves and cash flow and utilise the Company's tax loss pools more effectively
o Ultimate goal to move towards paying a sustainable and progressive dividend
Significant operational progress at the Orlando development with offtake agreements finalised with Canadian Natural Resources ("CNR") for export via Ninian Central Platform ("NCP")
End of quarter cash \$96.7 million (\$61.7 million restricted for purposes of Orlando development)

Operations Update

Huntington

Q3 2014 net production of 2,583 boepd
Production during the quarter was impacted by issues with the CATS infrastructure which is used to offtake gas production from the Huntington field
o Production shut-in for most of August 2014 and constrained for October 1, 2014 October 18, 2014
o Production shut-in since October 18, 2014 for CATS maintenance and is expected to recommence on December 5, 2014
o Field operator continues to work on other gas disposal options with gas reinjection test expected during December 2014

Orlando

Full suite of offtake agreements finalized with CNR, the operator of the NCP infrastructure
Significant milestone to keep the project on track for first oil production at the end of 2016 and add significant production and value

Trent & Tyne

Q3 2014 net production of 153 boepd
Production during the quarter was severely reduced by planned and unplanned maintenance outages at the fields and at the Bacton terminal, in addition to continued intermittent well performance
Since the period end, the Company has announced that its proposed acquisition of the remaining 80% interest in the Trent & Tyne fields will not complete and that operator, Perenco, has indicated it plans to raise a claim against the Company which the Company will vigorously defend
Perenco as operator is unlikely to sanction further investment and therefore the assets are being fully written down with a US\$27.8 million impairment charge taken during the quarter

Outlook

The production challenges the Company has faced during the third quarter demonstrate the need to strengthen and diversify its production base
The outlook for 2015 is encouraging with Huntington expected to resume full production in December 2014, further progress expected at our important Orlando development and the Company continues to review and progress multiple acquisition opportunities with the support and assistance of major North Sea lending banks

FINANCIAL & OPERATING HIGHLIGHTS

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

		Three months ended September 30,			Nine months ended September 30,
	2014	2013	Change	2014	2013	Change
Financial
Crude oil and natural gas revenues	\$ 22,403	\$ 18,082	24%	\$ 85,151	\$ 31,783	168%
Cost of sales Depletion, depreciation & amortization Gross Profit	(8,363) (14,271) (231)	(3,431) (12,532) 2,119	144% 14% (111%)	(25,974) (49,869) 9,308	(9,836) (17,949) 3,998	164% 178% 133%
Gross Profit before DD&A	14,040	14,651	(4%)	59,177	21,947	170%
Income (loss) Before Tax	(42,659)	(13,475)	(217%)	(66,007)	(26,225)	(152%)
Income (loss) After Tax Per share – basic (\$) Per share – diluted (\$)	(42,487) (0.12) (0.12)	899 0.00 0.00	(4,826%)	(70,852) (0.19) (0.19)	(1,929) (0.01) (0.01)	3,573%
Funds Flow(1)(2) Per share – basic (\$) Per share – diluted (\$)	(19,277) (0.05) (0.05)	4,983 0.01 0.01	(487%)	11,156 0.03 0.03	7,143 0.01 0.01	56%
Adjusted EBITDA(1)(2) Per share – basic (\$) Per share – diluted (\$)	10,082 0.03 0.03	18,261 0.05 0.05	(45%)	50,024 0.14 0.14	25,492 0.07 0.07	96%
			September 30,			December 31,
Cash and cash equivalents Restricted cash Working capital surplus(1) Secured bonds		\$	2014 28,029 68,689 85,924 266,124		\$ \$	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			368,054 368,054 367,270 367,270			366,831 369,225 360,849 363,078
		Three months ended September 30,			Nine months ended September 30,
	2014	2013	Change	2014	2013	Change
Operational
Crude oil and natural gas production (boepd)(3) Crude oil Natural gas Total	2,269 467 2,736	1,799 927 2,726	26% (50%) 0%	2,672 536 3,208	1,512 635 2,147	77% (16%) 49%
Realized sales prices Crude oil (\$/boe) Natural gas (\$/mmcf) Average (\$/boe)	86.20 7.84 78.80	110.00 10.00 92.96	(22%) (22%) (15%)	98.64 9.45 89.19	107.00 10.00 93.10	(8%) (5%) (4%)
Operating costs(1) (\$/boe) Netback(1) (\$/boe)	36.76 42.04	24.51 68.45	50% (39%)	30.83 58.36	58.38 34.72	(47%) 68%

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

(2) See reconciliation on page 5 & 6.

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

Huntington (17.55% Economic Interest)

Iona's Huntington Q3 2014 average production of 2,583 boepd was impacted by a planned shutdown of the Voyageur FPSO for the month of August 2014.
Huntington production during the quarter was impacted by issues at the CATS infrastructure which is used to export the field's gas production:
o Following remedial work on the Voyageur FPSO in early July, Huntington resumed full production on July 8, 2014 with relatively stable albeit restricted production due to CATS. As per instructions from the CATS operator Huntington production was shut in on July 31, 2014. Planned maintenance was completed at Huntington during the shut in with production resuming on August 26, 2014. During the shut in, significant scale deposits were removed from the first stage separator and the inlet pipework;
o Huntington production was constrained from October 1, 2014 through to October 18, 2014 due to issues with CATS and was then suspended for scheduled maintenance of CATS which is expected to be concluded on 5th December 5, 2014;
o The Huntington operator continues to explore whether there is any possibility for some gas export through CATS during the shutdown. Options to dispose of produced gas after October 18th to allow limited oil production are actively being considered, which may include gas re-injection;
o The operator continues to work on a number of options to maximize recovery from the field and is expected to propose a work programme in support of this prior to year end;
o Based on current data the Company does not consider that any write down on its Huntington reserve base is justified.
The Huntington partnership has commenced its final engineering phase of the Maxwell development: Maxwell is a deeper discovery in the Fulmar horizon which lies below the producing Huntington field. Iona supports the drilling of Maxwell.

Orlando (75% Working Interest)

During the quarter, Iona's Orlando Development project team continued to implement the project activities for the subsea tie back to the Ninian Central platform.
On October 8, 2014 the Company announced that all necessary agreements have been signed with CNR, the Operator of the NCP infrastructure, securing the offtake arrangements for the Orlando field development. The Construction and Tie-in Agreement describes how the parties will work together to deliver first oil from the Orlando development and states a joint objective target of end of 2016. Integrated planning is already at an advanced stage to commence the installation of brownfield equipment on NCP in 2015. Subsea installation and drilling activities are planned to commence in spring 2016.
The development plan for Orlando comprises the re-entering of the suspended 3/3b-13z well, drilling a 3,000 foot horizontal production well, and completion 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.

Trent & Tyne (20% Working Interest)

3rd quarter 2014 production at Trent & Tyne continued to be severely reduced resulting from planned and unplanned maintenance outages at the fields and at the Bacton terminal, in addition to continued intermittent well performance. The net average daily production rate from Trent & Tyne to Iona during the three and nine months ended September 30, 2014 was 0.92 MMcf/d and 1.2 MMcf/d.
During the 2nd quarter of 2014 the Company, through its wholly owned UK subsidiary, Iona UK Developments Co Limited, entered into a Sale and Purchase Agreement ("SPA") with Perenco UK Limited ("Perenco"), to purchase Perenco's remaining 80% working interest, rights, and obligations in the Trent & Tyne fields (including the Trent East Discovery Area).
On October 8, 2014, the Company announced that as per the terms of the SPA detailed above, a number of conditions which were required to be satisfied by October 28, 2014, were not anticipated to complete. Perenco has disagreed with the position of the Company and has now written to Iona attempting to terminate the SPA on the grounds of the Company's alleged breach of contract, stating that it was entitled to retain the deposit of US\$2 million and reserving its rights to claim damages. The Company strongly believes that it has complied with its obligations under the SPA and accordingly is entitled to the repayment of the deposit and will robustly defend any action raised by Perenco.
Perenco as operator is unlikely to sanction further investment and therefore the assets are being fully written down with a US\$27.8 million impairment charge taken during the quarter.

CORPORATE HIGHLIGHTS

The Company completed a private placement on August 29, 2014 for a total of 3,750,000 units ("Units") pursuant to a non-brokered private placement financing (the "Private Placement") at a price of \$0.40 per Unit, being above the closing price of the Company's common shares ("Common Shares") on Friday, August 29, 2014. Each Unit shall be comprised of one Common Share and one warrant to purchase Common Shares (each a "Warrant"). Proceeds from the Private Placement will be used for general corporate purposes. The Warrants shall have a term of five years and will have an exercise price of \$0.48 in the first year following closing, and an exercise price of \$0.58, \$0.69, \$0.83 and \$1.00 in each year thereafter.
On September 2, 2014 the Company announced that Mr. Iain McKendrick had joined the Company as Executive Chairman and Mr. Tom Reynolds had joined the Company as Chief Executive Officer and President replacing the former Chief Executive Officer and President of the Company effective September 1, 2014. The Company also announced that Mr. McKendrick and Mr. Reynolds had been appointed to the Company's board of directors.
On November 3, 2014 the Company announced a number of senior management appointments:
o Robert Gair, Chief Financial Officer
o Kevin Holley, Corporate Controller
o James Lund, Head of Operations and Development
o Gregor Maxwell, Head of Business Development

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") 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 September 30, 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 November 28, 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 and contingent and prospective resources, 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 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, 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

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", "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, transaction 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:

	Nine months ended
		September 30,
	2014 2013
Cash flow generated (used) in operating activities Changes in non-cash working capital balances:	\$	25,592	(1,024)
Accounts receivable		3,152	6,774
Prepaid expenses		433	(372)
Inventory		89	2,323
Accounts payable and accrued liabilities		(18,110)	(558)
Funds Flow	\$	11,156	7,143

The following table reconciles net income to Adjusted EBITDA:

	Three months ended		Nine months ended
	September 30,			September 30,
	2014 2013			2014	2013
Net income	\$ (14,710)	899	\$	(43,075)	(1,929)
Income tax recovery (expenses)	(172)	(14,374)		4,845	(24,296)
Finance costs	8,514	10,371		24,586	14,170
Finance Income	(3)	(18)		(9)	(30)
Loss / (gain) on risk management contracts	(1,263)	8,851		7,211	18,675
Transaction costs	3,445	-		6,597	953
Depletion, depreciation and amortization	14,271	12,532		49,869	17,949
Adjusted EBITDA	\$ 10,082	18,261	\$	50,024	25,492

CORPORATE TRANSACTIONS

On August 15, 2014, the Company, through its wholly owned subsidiary Iona UK, retired the remaining 3,658,051 calls (effective April 2014 through March 2018) sold to Britannic Trading Limited ("BTL"), a subsidiary of BP Oil International Limited, in February of 2013. The Company will settle this transaction through two equal payments of \$13,250,000, paid on August 18, 2014 and February 10, 2015. Simultaneously, the company entered into a Zero Cost Producer Collar with BTL, whereby Iona UK purchased 458,352 puts (effective August 2014 through July 2015) at a strike price of \$90.00 per barrel, and sold to BTL 1,650,000 calls (effective October 2018 through March 2020) at a strike price of \$90.00 per barrel. The payment of the settlement costs will be substantially funded from restricted cash. Under the Bond agreement, restricted cash drawn to settle the BP derivatives has to be re-transferred into restricted cash from Huntington cash flows.

On October 8, 2014, the Company announced that as per the terms of the SPA detailed above, a number of conditions which were required to be satisfied by October 28, 2014, were not going to complete. Perenco has disagreed with the position of the Company and has now written to Iona attempting to terminate the SPA on the grounds of the Company's alleged breach of contract, stating that it was entitled to retain the deposit of US\$2 million and reserving its rights to claim damages. The Company strongly believes that it has complied with its obligations under the SPA and accordingly is entitled to the repayment of the deposit and will robustly defend any action raised by Perenco. Perenco as operator is unlikely to sanction further investment in Trent & Tyne and therefore the assets are being fully written down with a US\$27.8 million impairment charge taken during the quarter.

On October 27, 2014 Iona UK closed out the 361,976 outstanding put options (effective October 2014 – July 2015) realizing proceeds of \$1.9 million. Simultaneously, the Company put in place "costless collar" arrangements over 396,197 barrels (effective December 2014 – December 2015) with a floor price of US\$80.00 per barrel and a ceiling price of US\$92.75 per barrel.

PRODUCTION AND PRICING

			Three months ended September 30,			Nine months ended September 30,
		2014	2013	% Change	2014	2013	% Change
Total Petroleum and natural gas production by product & project
Huntington
Crude Oil Natural Gas	bbl boe	208,749 28,895	165,464 24,393	26% 18%	729,339 90,918	258,604 25,855	182% 252%
Trent & Tyne
Natural Gas	boe	14,075	60,875	(77)%	55,232	147,540	(63)%
Total petroleum and natural gas production	boe	251,719	250,732	0%	875,489	431,999	103%
Average Daily Production by product
Crude Oil Natural Gas	bopd boepd	2,269 467	1,799 927	26% (50%)	2,672 536	1,512 635	77% (16)%
Total average daily production	boepd	2,736	2,726	0%	3,208	2,147	49%
Realized sales prices
Crude oil	\$/boe	86.20	110.00	(22%)	98.64	107.00	(8%)
Natural gas	\$/mmcf	7.84	10.00	(22%)	9.45	10.00	(5%)
Average	\$/boe	78.80	92.96	(15%)	89.19	93.10	(4%)

Average net production for the three and nine months ended September 30, 2014 was 2,736 boepd and 3,208 boepd respectively compared to average net production during the comparable periods in 2013 of 2,726 boepd and 2,147 boepd respectively. The increase in crude oil production to 2,269 bopd during the three months and 2,672 bopd during the nine months ending September 30, 2014 compared to 1,799 bopd during the three months and 1,512 bopd during the six and nine months ended September 30, 2013 was a result of a full period of production from the Huntington field in 2014 compared to production beginning on April 11 in 2013, offset by planned and unplanned shutdowns in Q2 and Q3 respectively.

Quarter over quarter average production at Huntington remained comparable with Q3 2014 production of 2,583 boepd compared to 2,563 boepd in Q2. The production in Q3 2014 was negatively impacted by a planned shutdown of the Voyageur FPSO in Q3. Natural gas production was comparable during the third quarter of 2014 producing 467 boepd per day compared to 475 boepd per day in Q2 2014.

The average realized oil price for the three and nine months ended September 30, 2014 was \$86.20 and \$98.64 respectively per bbl (three and nine months ended September 30, 2013 - \$110.00 and \$107.00 respectively). The average realized gas price for the three and nine months ended September 30, 2014 was \$7.84 per mcf and \$9.45 per mcf respectively (three and six months ended September 30, 2013 - \$10.00 per mcf and \$10.00 per mcf respectively).

REVENUE

	Three months ended September 30,				Nine months ended September 30,
	2014	2013	% Change		2014	2013	% Change
Petroleum and natural gas sales by product	\$			\$
Crude oil	15,907	14,179	122%		68,682	22,550	205%
Natural gas	2,992	2,742	(10)%		8,290	7,633	9%
Royalty interest	1,501	1,000	50%		5,935	1,368	334%
Condensate	2,003	161	1,144		2,244	232	867%
Total	\$ 22,403	18,082	24%	\$	85,151	31,783	168%

Revenue was \$22.4 million and \$85.2 million for the three and nine months ended September 30, 2014 (September 30, 2013 - \$18.1 and \$31.8), respectively.

Oil sales volumes increased from the same period in the previous year as a result of a full period of production from the Huntington field in 2014 compared to production beginning on April 11 in 2013, offset by planned and unplanned shutdowns in Q2 and Q3 respectively. Gas sales in the three and nine months ended September 30, 2014 was comparable to the same period in the previous year.

Of the total revenues of \$22.4 million and \$85.2 million for the three and nine months ended September 30, 2014 (\$18.1 million and \$31.8 million for the three and nine months ended September 30, 2013), \$15.9 million, 71% of total revenue and \$68.7 million, 81% of total revenue, was generated from oil production (2013 - \$14.2 million, 78% of total revenue and \$22.6 million, 71% of total revenue), respectively, \$3.0 million, 13% of total revenue and \$8.3 million, 10% of total revenue, was generated from gas production (2013 - \$2.7 million, 15% of total revenue and \$7.6 million, 24% of total revenue), respectively, \$2.0 million, 9% of total revenue and \$2.2 million, 2% of total revenue from condensate (2013 - \$161,000 and \$232,000 respectively) and \$1.5 million, 7% of total revenue and \$5.9 million, 7% of total revenue, was generated through a gross overriding royalty interest in the Huntington field (2013 - \$1 million, 5% of total revenue and \$1.4 million, 4% of total revenue), respectively.

INVENTORY

Inventory for the quarter ended September 30, 2014 was \$1.9 million (Dec 31, 2013 - \$1.8 million). Inventory relates to the Company's share of stock remaining in the FPSO storage tanks at September 30, 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

	Three months ended September 30,				Nine months ended September 30,
	2014	2013	% Change	2014	2013	% Change
Operating costs	\$ 8,363	3,431	144%	\$ 25,974	9,836	164%
Depletion and depreciation	14,271	12,532	14%	49,869	17,949	178%
Total	\$ 22,634	15,963	42%	\$ 75,843	27,785	173%

Operating expenses were \$22.6 million and \$75.8 million for the three and nine months ended September 30, 2014 compared to \$16.0 million and \$27.8 million during the three and nine months ended September 30, 2013. The increase in operating costs from the third quarter 2013 is a result of a full period of production from the Huntington field in 2014 compared to production beginning on April 11 in 2013. Depletion increased during the three and nine months ended September 30, 2014 to \$14.3 million and \$49.9 million respectively compared to \$12.5 million and \$17.9 million respectively during the three and nine months ended September 30, 2013. The increase in depletion for the three and nine months ended September 30, 2014 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.

OPERATING NETBACKS

	Three months ended September 30,			Nine months ended September 30,
	2014	2013	% Change		2014	2013	% Change
	\$/boe	\$/boe			\$/boe	\$/boe
Average Selling Price	\$ 78.80	92.96	(15%)	\$	89.19	93.10	(4%)
Operating Cost	(36.76)	(24.51)	50%		(30.83)	(58.38)	(47%)
Netback from Operations	\$ 42.04	68.45	(39%)	\$	58.36	34.72	68%

Operating costs include all costs to produce and sell the commodity. Operating costs for the third quarter of 2014 increased to \$36.76 per boe compared to \$24.51 per boe in the third quarter of 2013 as a result of the Huntington shutin during the month of August where a certain percentage of operating costs are fixed. Operating costs for the nine month period ended September 30, 2014 decreased to \$30.83 per boe compared to \$58.38 in the same period in 2013 as a result of increased production at Huntington averaging down the fixed operating costs.

GENERAL AND ADMINISTRATIVE EXPENSES

		Three months ended September 30,			Nine months ended September 30,
		2014	2013	% Change	2014	2013	% Change
Consulting fees / wages	\$	975	872	12%	\$ 3,629	2,346	55%
Professional fees		366	24	(1,425%)	428	873	(51%)
Stock option expense		947	502	(89)	1,066	2,974	(64%)
Depreciation		95	-	-	120	-	-
Insurance		17	-	-	266	-	-
Travel, office costs and other		821	735	12%	2,272	2,421	(6%)
Total	\$	3,221	2,133	52%	\$ 7,781	8,614	(10%)
Per boe	\$/boe	14.07	10.28	(37%)	9.25	22.91	(60%)

General and administrative costs were \$3.2 million and \$7.8 million for the three and nine months ended September 30, 2014 compared to \$2.1 million and \$8.6 million for the three and nine months ended September 30, 2013. General and administrative costs increased from the three month comparative period in 2013 as a result of increased professional fees, stock option expense and travel. Professional fees and travel increased due to increased corporate activity. Stock option expense increased due to stock options issued in the quarter to new employees, this was offset slightly due to a natural decline in expense due to graded vesting.

General and administrative costs decreased from the nine month comparative period in 2013 mainly as a result of decreased professional fees and stock option expense offset by an increase in consulting fees and wages due to the Company's move towards operatorship relating to the T&T 80% acquisition. Professional fees include legal, audit and tax fees which were higher in 2013 due to the acquisition of Huntington. As noted above stock option expense decreased due a natural decline in expense due to graded vesting, this was offset in the third quarter of 2013 as a result of stock option grants to new employees.

The Company is seeking to reduce general and administrative costs to be more appropriate to a low cost operator. Since the quarter end a number of organizational changes have been implemented to reduce costs and cessation of handover of Trent & Tyne operatorship will also reduce costs.

FOREIGN EXCHANGE

	Three months ended September 30,		Nine months ended September 30,
	2014	2013	% Change	2014	2013	% Change
Foreign exchange gain / (loss)	\$ (728)	5,748	(113)%	\$ (1,080)	6,611	116%

During the three and nine months ended September 30, 2014, the Company recognized a foreign exchange loss of \$728,000 and \$1,080,000 (2013 – Gains of \$5,748,000 and \$6,611,000). 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 nine months ended September 30, 2014, the Company was charged \$288,000 (2013 - \$239,000) and \$390,000 (2013 - \$640,000) respectively, in legal fees of which \$NIL (2013 - \$95,000) related to share issuance costs by a law firm where a director of the Company is a partner, of which \$26,000 is included in accounts payable and accrued liabilities as at September 30, 2014 and \$29,000 as at December 31, 2013.

Included in accounts receivable is \$117,483 (2013 - \$114,000) 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 September 30, 2014. The amounts owing are non-interest bearing and secured. The Company expects full repayment of the remaining balances in 2014.

On September 12, 2014 the Company entered into an agreement for two Demand Promissory Notes in the amount of \$480,000 (\$500,000 CAD) bearing interest at 3.25% with two members of senior management. These notes are secured by 1,250,000 outstanding common shares and 1,250,000 warrants issued on August 29, 2014. At September 30, 2014 these promissory notes remained outstanding. 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 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 in net proceeds. As at September 30, 2014 the fair value of the Bonds were \$258.50 million (December 31, 2013 - \$275 million. The bonds mature on September 30, 2018. The Bonds carry an annual coupon rate of 9.5% payable semi-annually, were issued at 97.5% of par and are callable in whole or in part at the option of Iona UK at any time. 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 \$1.1 million. At September 30, 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 September 30, 2014 the balance of the Bonds of \$266.1 million 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.

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.

At September 30, 2014, the Company was in compliance with all covenants as detailed in the table below.

	30-September-14	Covenant
Liquidity as defined	\$89,284	Greater than \$30,000
Restricted Group Capital Employed Ratio	48%	Greater than 40%
Group Capital Employed Ratio	48%	Greater than 40%
Leverage Ratio	2.27	Not greater than 3.0x

The above calculation includes restricted cash in the definition of cash as changed in the amendment to the Bond Agreement effected May 6, 2014.

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 September 30, 2014 are presented in the table below:

	Level 1	Level 2	Level 3	Total Fair Value
Current assets
Derivative financial assets	\$ -	581	- \$	581
Current liabilities
Derivative financial instrument liabilities	-	-	-	-
Non-current liabilities
Derivative financial instrument liabilities	\$ -	22,975	-	22,975

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

	Three Months Ended September 30		Nine Months Ended September 30
	2014	2013	2014	2013
Cost of derivative options Realized gain / (loss) on commodity hedges Unrealized gain / (loss) on commodity	- (26,500)	- (6,538)	- (32,430)	(7,293) (6,556)
hedges	27,763	(2,313)	25,219	(4,880)
Total gain / (loss) on commodity hedges	1,263	(8,851)	(7,211)	(18,675)

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.

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:

			September 30, 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	4,822	495	1,485	1,485	1,357
Equipment leases	41,309	11,408	21,930	7,971	-
Drilling, completion, facility construction	21,339	21,339	-	-	-
Total UK Segment	67,470	33,242	23,415	9,456	1,357
Total Contractual Obligations	67,674	33,259	23,466	9,507	1,442

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

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

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 and the Bonds. 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 used in operating activities, funds flow, during the third quarter of 2014 was (\$19.3 million) reduced from \$5.0 million in the third quarter of 2013 primarily due to an increase in operating expenses and the settlement of the commodity hedges.

Cashflow from financing activities

Cash used in financing activities during the third quarter of 2014 was (\$12.2) million compared to \$110.9 million in the third quarter of 2013 primarily due to the Company's issuance of the Bond and repayment of the credit facility in the third quarter of 2013.

Cashflow from investing activities

Cash used in investing activities in the third quarter of 2014 was (\$7.0) million compared to \$108.5 million in the third quarter of 2013 primarily due to the increase in restricted cash due to the issuance of the bonds.

The Company continues to be fully funded, with more than sufficient financial resources to cover its anticipated immediate 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 September 30, 2014, the Company had net assets of \$123.4 million, working capital of \$85.9 million and \$33.3 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 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 September 30, 2014, 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 September 30, 2014 would have impacted the net loss and comprehensive loss of the Company for the nine month period ended September 30, 2014 by approximately \$46,000 (nine months ended September 30, 2013 – \$353,000).

In addition at September 30, 2014, the Company held approximately \$7,347,327 (£4,532,000) (2013 - \$53,014,000 (£32,769,000)) of accounts payable in Pound Sterling. Assuming all other variables remain constant, a 1% increase or decrease in foreign exchange rates at September 30, 2014 would impact the net loss and comprehensive loss of the Company for the nine month period ended September 30, 2014 by approximately \$73,000 (nine months ended September 30, 2013 - \$530,000).

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 370,580,868 Common Shares, 3,750,000 warrants and 30,672,500 stock options outstanding.

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

Date of Grant	Number Issued	Forfeited Options	Exercise Price CAD\$	Weighted Average Remaining Contractual Life	Date of Expiry	Number Exercisable September 30, 2014
May 31, 2011	9,550,000	(1,950,000)	\$0.60	0.92 years	May 31, 2015	7,600,000
November 25,		(100,000)
2011	100,000		\$0.60	-	-	-
April 13, 2012	17,070,000	(5,305,000)	\$0.57	2.79 years	April 12, 2017	8,362,500
June 17, 2012	210,000	(210,000)	\$0.47	-	-	-
August 29, 2012	150,000	(150,000)	\$0.38	-	-	-
January 10, 2013		-			January 10,
	175,000		\$0.59	3.53 years	2018	175,000
March 5, 2013	7,420,000	(3,225,000)	\$0.63	3.68 years	March 5, 2018	2,405,000
July 29, 2013	700,000	(700,000)	\$0.59	4.08 years	July 29, 2018	-
October 3, 2013	2,500,000	(2,500,000)	\$0.63	-		-
October 23, 2013		-			October 23,
	600,000		\$0.63	4.32 years	2018	150,000
May 1, 2014	1,350,000	(262,500)	\$0.54	-	-	337,500
July 1, 2014	750,000	-	\$0.49	-	-	187,500
September 1, 2014	4,500,000	-	\$0.40	4.84 years	May 1, 2019	1,125,000
	45,075,000	(14,402,500)				20,342,500

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

On July 1, 2014 and September 1, 2014 Iona Energy issued 750,000 and 4,500,000 stock options respectively, to purchase 5,250,000 common shares of the Company, to employees of the Company. The options were issued with an exercise price of \$0.49 and \$0.40 per share respectively, vest as to one quarter immediately and one quarter on each of the first, second and third anniversaries of the date of grant and have a five year and four year term, respectively, from the date of issuance.

The Company's share options granted, other than the 175,000 share options granted to a person retained to provide investor relations activities, which vest as to ¼ immediately and ¼ on each of the dates three months, six months and nine months thereafter, 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.

SUMMARY OF QUARTERLY RESULTS

(\$ thousands, except per share amounts)

		2014				2013		2012
	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Revenue	\$22,403	\$27,100	\$35,648	33,797	18,082	11,843	1,858	-
Average Daily Production (boepd)
Crude oil (1)	2,269	2,284	3,475	2,585	1,799	1,179	-	-
Natural Gas	467	475	680	765	927	655	316	-
Total	2,736	2,759	4,155	3,350	2,726	1,834	316	-
Net income / (loss)	\$(42,487)	\$(28,027)	\$(338)	31,553	899	9,117	(11,945)	(4,456)
Income / (loss) per share – basic	(0.12)	(0.08)	(0.00)	0.09	0.00	0.02	(0.03)	(0.01)
Income / (loss) per share – diluted	(0.12)	(0.08)	(0.00)	0.09	0.00	0.02	(0.03)	(0.01)
Funds Flow	(19,277)	3,345	27,088	28,225	4,983	3,911	(1,751)	(1,649)
Funds Flow per share – basic	(0.05)	0.01	0.07	0.08	0.01	0.01	(0.01)	(0.01)
Funds Flow per share – diluted	(0.05)	0.01	0.07	0.08	0.01	0.01	(0.01)	(0.01)
Adjusted EBITDA	10,082	9,647	27,143	27,936	18,263	3,001	3,281	(4,499)
Adjusted EBITDA per share – basic	0.03	0.03	0.07	0.08	0.05	0.01	0.01	(0.01)
Adjusted EBITDA per share – diluted	0.03	0.03	0.07	0.08	0.05	0.01	0.01	(0.01)
Working capital surplus/ (deficit)	85,924	88,847	88,776	79,075	71,247	(155,367)	(47,275)	(34,897)
Total assets	\$482,169	\$544,072	\$545,159	545,079	631,690	516,606	513,002	204,566
Weighted average common shares - basic	368,054	366,831	366,831	360,849	366,824	377,060	342,597	324,905
Weighted average common shares–fully diluted	368,054	366,831	366,831	363,078	366,824	377,060	342,597	324,905

(1) Q2 2013 production has been adjusted for start of production for Huntington on April 12, 2013.

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.

The significant decrease in net income from Q3 2014 over Q2 2014 is primarily due to the \$27.8 million of impairment recognized in Q3 2014.

Revenue, Funds Flow and Adjusted EBITDA increased substantially throughout 2013, due to a successful drilling program and two business combinations (Huntington and Trent & Tyne) with the Huntington Field sustaining peak production for significant periods in Q4 2013 and Q1 2014. Revenue declined in Q2 and Q3 2014 as a result of unplanned shutdowns of the Voyageur FPSO and within the Central Area Transmission System ("CATS"). This decrease in revenue significantly impacted net income in Q2 and Q3 2014. Q3 2014 net income was also impacted by a planned shutdown of the Voyageur FPSO and CATS. Fluctuations in production and the Brent benchmark price have also contributed to the fluctuations in oil and gas sales.

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 condensed 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 achievement of plateau oil and gas production in the Huntington field and the issuance of \$275 million of US denominated debt by Iona UK. Oil and gas prices received by the Company are benchmarked against the US Dollar Brent oil standard. 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.

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 2014 and 2015 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 facilities (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.

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. Specifically, should Iona be in breach of the operating covenants for two consecutive quarters this would constitute an event of default and the Bond would be due for immediate repayment.

Loss from Operations

Iona had a deficit as at September 30, 2014 of \$58,119,000 and retained earnings of \$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 primarily on 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 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 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 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.

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 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 nonproducing 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

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.

This MD&A uses certain abbreviations as follows:

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.