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Corporate P Presentation November 2 2013 Discla Di laime mer Forw rward rd-lo -lookin king st stateme ments Some of the statements and information contained in this Presentation are forward-looking, including statements regarding the


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Corporate P Presentation

November 2 2013

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Page 2 2 Corporate P Present ntation n Novemb mber 2 2013

Forw rward rd-lo

  • lookin

king st stateme ments Some of the statements and information contained in this Presentation are forward-looking, including statements regarding the Company's plans with respect to development of its properties, expected drilling results from the Company's properties, statements regarding sources of financing for the Company and its development plans, estimates of the quantities of proved reserves, probable reserves, possible reserves and contingent resources, as well as estimates of the net present value of future net revenue of proved reserves, probable reserves, and possible reserves. Forward-looking statements include statements regarding the intent, belief and current expectations of Iona or its officers with respect to various matters, including reserves, production, first oil, drilling activity or otherwise. When used in this Presentation, the words "expects," "believes," "anticipate," "plans," "may," "will," "should", "scheduled", "targeted", "estimated" and similar expressions, and the negatives thereof, are intended to identify forward-looking statements. Such statements are not promises or guarantees, are based on various assumptions deemed to be reasonable by the Company's management. Some of the key assumptions include: the anticipated increase in working interest at the Company’s Trent & Tyne property from 20.0% to 37.5%, management's anticipated development timelines (which may be different from those contained in the Company's independent reserves reports), production profiles for the Company's properties, and estimated cash flow from the Company's properties. Information concerning reserves and resources are deemed to be forward-looking statements, as such estimates involve the implied assessments that the reserves or resources can be profitably produced in the future. The production profiles and cash flow estimates from the Company's existing properties are based upon the Company's independent reserves reports. Such profiles and estimates involve numerous assumptions and are subject to a number of risks and uncertainties, some of which are beyond the Company's control, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will prove inaccurate and which could cause actual results to differ from those anticipated. The forward-looking statements in this Presentation are subject to risks and uncertainties that could cause actual outcome to differ materially from those suggested by any such statements, including without limitation: the risk that the Company's development plans and timelines change as a result of new information or events, the risk that drilling results differ materially from management's current estimates, reliance on key personnel, general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, environmental risks, the risk that future terms of anticipated financings are different from those disclosed herein, competition from other industry participants, the risk that transactions identified herein do not close in a timely matter or at all, the lack of availability of qualified personnel or management, and the ability to access additional sufficient capital from internal and external sources for the Company to complete the development programs described in this document. The information contained in this Presentation may identify additional factors that could affect the operating results and performance of the Company. This Presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, future net revenue, cash flows, and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this Presentation was made as of the date of this document and was provided for the purpose of providing information about management's current expectations and plans relating to the future. The Company disclaims any intention or obligation to update or revise any forward looking statements or FOFI contained in this Presentation, whether as a result of new information, future events or

  • therwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward looking statements and FOFI contained in this Presentation should not be used for

purposes other than for which it is disclosed herein. The forward looking statements and FOFI contained in this Presentation are expressly qualified by this cautionary statement. Included in this Presentation are estimates of the Company's 2013-2018 cash flow which are based on various assumptions as to production levels, commodity prices and other assumptions and in the case of the years other than 2013 are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent such estimates constitute FOFI, they were approved by management of the Company in November 2013 and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes.

Di Discla laime mer

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Page 3 3 Corporate P Present ntation n Novemb mber 2 2013

Agend nda

  • Ove

vervie rview of Iona En Energ rgy y

  • Asse

Asset ove vervie rview

  • Fin

inancia cials ls

  • Ap

Appendix ix

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Page 4 4 Corporate P Present ntation n Novemb mber 2 2013

  • Canadian corporation listed on TSX Venture Exchange (TSX-

V:INA) with operational headquarters in Aberdeen

  • 367m basic shares outstanding
  • Pure play UK development and production focused company
  • Huntington production has shown peak rates in excess of

~34,500 boe/day

  • Trent & Tyne WI to increase upon commitment to future

drilling campaign increases production and reserves(1)

  • Orlando development sanctioned, first oil expected Q4‘15
  • Kells first oil expected 12 months after Orlando first oil
  • 36.0 MMboe 2P reserves(GCA CUR) and 56.9 MMboe net 2C

Contingent Resources(R)(2)

  • Expected exit Q4 2013 production of ~7,500 boe/day,

ramping up to ~17,000 boe/day exiting 2016 post- development of Orlando and Kells(2)

  • Experienced management team with strong track record of

value creation and in-depth asset knowledge

  • Strong institutional shareholder base, more than CAD 185m

equity raised since 2010

  • ~$303m in tax pools and no expectation of significant taxes

payable until 2017

Int Introduction t n to Io Iona na E Ene nergy Inc y Inc. .

(1) ¡Assumes ¡increase ¡of ¡Trent ¡& ¡Tyne ¡WI ¡from ¡20% ¡to ¡37.5% ¡ (2) ¡Based ¡on ¡Trent ¡& ¡Tyne ¡WI ¡of ¡37.5% ¡and ¡HunAngton ¡producAon ¡including ¡0.75% ¡ DifferenAal ¡LiHing ¡EnAtlement ¡and ¡1.8% ¡royalty ¡

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Page 5 5 Corporate P Present ntation n Novemb mber 2 2013 5 5 10 10 15 15 20 20 25 25 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019 2019

HUNTINGTON HUNTINGTON TREN ENT & & TYN YNE E ORLAN ANDO KEL KELLS S WEST EST WICK K HUNTINGTON DEEP EEP RONAN AN & & ORAN AN

Production o n outlo look

AVERAGE ANNUALIZED KBOE/DAY

  • Huntington reached full

capacity during early September ‘13

  • Long-term gas production

from Trent & Tyne

  • Further Tyne development

in ‘14

  • Orlando first oil scheduled

Q4 ‘15

  • Kells first oil Q4 ’16
  • Long-term production

potential from West Wick from 2016

  • Potential tie-in of

Huntington Deep in 2016 and beyond

  • Ronan & Oran are

additional development candidates

Notes: ¡

  • ProducAon ¡profile ¡based ¡on ¡Gaffney ¡Cline ¡& ¡Associates ¡(”GCA”) ¡2P ¡reserves ¡as ¡of ¡December ¡31st, ¡2012(GCA ¡CUR) ¡ ¡
  • Based ¡on ¡Trent ¡& ¡Tyne ¡WI ¡of ¡37.5% ¡and ¡HunAngton ¡producAon ¡including ¡0.75% ¡DifferenAal ¡LiHing ¡EnAtlement ¡and ¡1.8% ¡royalty ¡
  • 2013 ¡and ¡beyond ¡provided ¡for ¡illustraAon ¡only. ¡Budgets ¡and ¡forecasts ¡beyond ¡2013 ¡have ¡not ¡been ¡finalized ¡and ¡are ¡subject ¡to ¡a ¡variety ¡of ¡factors ¡including ¡prior ¡year's ¡results. ¡
  • Ronan ¡& ¡Oran ¡producAon ¡levels ¡portray ¡a ¡75% ¡retained ¡working ¡interest ¡in ¡the ¡asset ¡and ¡is ¡based ¡on ¡esAmates ¡of ¡Iona’s ¡non-­‑independent ¡qualified ¡reserves ¡evaluator ¡

2P Production 2P Developments 2C Contingent Resources

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Page 6 6 Corporate P Present ntation n Novemb mber 2 2013

Gr Graha ham H m Heath – h – C CFO ( (Int Interim) m) a and nd V VP C Corporate De Develo lopme ment nt

  • 15 years experience in Oil & Gas Finance, Risk, Corporate Development at EnCana and Cenovus
  • Has been key in Iona’s capital raising efforts since joining in 2010: raised CAD 185 million in equity, public

listing of INA on the TSX-V, closed USD 250m in Senior Secured Credit Facilities, structured Call sale to BP, completed USD 275m Senior Secured Callable Bond

  • B. Comm from University of Calgary

Highly q hly quali lified ma mana nageme ment nt t team m

Neill C ll Carson – n – C CEO, E , Executive Di Director

  • Founder of Iona in 2008, co-founder and former COO of Ithaca Energy Inc.
  • 32 years experience from the North Sea, Bolivia and Pakistan with Amoco Corporation, BP and Ithaca
  • Responsible for building Ithaca’s reserve base from zero to 35+ MMboe in three years from 2004
  • Geophysicist, M. Sc. from Birmingham University

Ala lan C n Curran – n – C COO

  • 30 years oil and gas experience with significant senior management experience. Joined Iona in March 2012
  • Former CEO of Wood Group Engineering (North Sea) and Managing Director of Lundin Petroleum UK
  • Mid-career with Oryx and Kerr-McGee - several years with senior responsibility for Ninian Area operations
  • Chemical Engineer, B.Sc. From Edinburgh University. First 10 years with Shell as Petroleum Engineer

Other er k key m managem emen ent t tea eam

  • Peter Campbell – VP Asset Management (Engineer, 30 years in E&P. Business Development Manager at Kerr-McGee North Sea, Maersk Oil)
  • John Baillie – VP Developments (Reservoir engineer – 28 years Dana Petroleum, Enterprise Oil, Total and Marathon)
  • Colin Tannock – VP Subsurface (Geologist, 30 years Former Exploration Manager for Talisman, Geoscience Manager for TAQA)
  • Robin Baxter – VP Business Development (Lawyer, 37 years Legal Counsel Procurement, and Commercial Manager Kerr-McGee North Sea, Maersk Oil)
  • Dave Sherrard – Reserves Advisor (Reservoir engineer – 32 years Chevron & BP. Co-founder RML/Senergy Group Limited)
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Page 7 7 Corporate P Present ntation n Novemb mber 2 2013

Busine ness mo model – l – a a lo low-r

  • risk v

k valu lue c creation c n curve

Monetize Screen & Acquire

  • Dual license strategy:

– License rounds: existing discoveries – Acquisitions: discoveries and producing assets

  • Identifying opportunities neglected by larger

companies minimizes acquisition costs

– Undeveloped discoveries – Producing assets with upside / redevelopment potential

  • Identifying “Hungry Hosts” minimizes

development and operating costs

– Infrastructure owners that wants/needs new production to extend life of infrastructure

  • Utilize strong organization to

commercialize hydrocarbons

– Mature Contingent Resources into 2P reserves – Mature undeveloped reserves into production

  • Key work streams

– Appraisal – Engineering & FDP planning – Development drilling – Subsea / topside installation & modification

  • No e

explo loration n

  • Dual monetization strategy:

– Produce: harvest cash flow – Divest: sell assets at full value following significant de-risking

  • Fully utilize significant tax pools
  • Next step: reinvest cash in new

development and production projects

Commercialize

drill ll develo lop proven n und

  • ndev. o

. oil il & & gas gas pro roduction with u h upside potent ntial l production n

reinvestme ment nt

(1) Undeveloped proven reserves and resources

  • USD 1

1 - 5

  • 5/bbl

bbl a acquisition c cost(1)

(1)

  • USD 1

15 - 2

  • 25/bbl c

capital c cost

  • USD 1

15 - 1

  • 17/bbl

bbl o

  • per

erating c costs

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Page 8 8 Corporate P Present ntation n Novemb mber 2 2013

  • Established 2008
  • Raised CAD 1m
  • Screened “Starter

Pack” assets

  • DECC Accreditation

History o y of Io Iona na

2008 2008 Inception

20 2012 12

Strong reserves growth

2013 > >>

Material producer

2009-1

  • 11

Creating platform for growth

  • Acquired assets

– Trent & Tyne gas production – 35% WI in Orlando

  • Raised CAD 73m equity
  • Completed TSX-V Qualifying

Transaction

  • YE 2011 2P reserves of 5.9

MMboe(GCA 2011)

  • Exit 2011 production of 550

boe/day

  • Approved exploration
  • perator
  • Acquired Orlando and Kells

(100%), West Wick (~59%)

  • Raised CAD 92m equity
  • YE 2012 2P reserves of 35.8

MMboe(GCA 2012)

  • 2012 production of 310 boe/

day

  • Orlando – drilled well,

submitted FDP, reserves upgrade

  • Kells – submitted FDP,

reserves upgrade

  • Acquisition of Huntington
  • 27th round awards Ronan &

Oran

  • Negotiated USD 130m RBL
  • Approved production
  • perator
  • Divested 25% of Orlando and

Kells, Orlando FDP approved

  • T&T T6 well successfully drilled,

strong production

  • Huntington on-stream
  • Significant financing activity

– CAD 23m equity – USD 250m Credit Facility – USD 60m structured derivative – Raised USD 275m in senior secured bond (subsequently repaid Credit Facility)

  • 36.0 MMboe 2P reserves (GCA CUR) (1)
  • 2013 exit production of 7,500(1)(2)

boe/day

  • Set for production of 17,000 boe/

day exiting 2016

(1) ¡Based ¡on ¡Iona’s ¡net ¡WI ¡post-­‑elecAon ¡to ¡drill ¡Tyne ¡NW ¡ (2) ¡Includes ¡0.75% ¡DLE ¡and ¡1.8% ¡royalty ¡on ¡HunAngton ¡ ¡ ¡

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Page 9 9 Corporate P Present ntation n Novemb mber 2 2013

36.0 MMBOE 56.9 MMBOE 2P RESERVES (GCA CUR) 2C CONTINGENT (R) 10 20 30 40 50 60 70 80 90 100 HUNTINGTON TRENT & TYNE ORLANDO KELLS WEST WICK RONAN & ORAN 2P RESERVES (GCA CUR) 2C CONTINGENT (R) 28.5 MMBOE 7.5 MMBOE OIL GAS

Reserves ( (31. D Dec 2 2012) 1P 1P MMboe MMboe 2P 2P MMboe MMboe 2P B BTAX AX NPV10 ( ($m)

Trent & Tyne (37.5% non-op)(T) 0.6(1) 3.6(1) $125.6(1) Huntington (15.0% non-op)(H) 3.7(2) 4.6(2) $319.0(2) Orlando Oil (75.0% op)(O) 5.9 11.5 $420.4 Kells Oil (75.0% op)(K) 3.9 6.6 $105.1 West Wick (58.0% op)(W) 5.1 9.7 $344.4

Re Reserves 19 19.1 36.0 .0 $1314.5 .5 Contingent R Resources 1C 1C MMboe MMboe 2C 2C MMboe MMboe 2C A ATAX AX NPV10 ( ($m)

Assets with reserves (R) 3.4 7.6 UNDER ENGINEERING REVIEW Ronan, Oran (operator) (R) 34.6 49.2

Cont nting ngent nt R Resources(R) 38.0 .0 56.9 .9 $TBD D

Large c certified r reserve a and nd r resource b base

(1) ¡All ¡figures ¡based ¡on ¡Iona’s ¡net ¡WI ¡of ¡37.5% ¡post-­‑elecAon ¡to ¡drill ¡Tyne ¡NW ¡ (2) ¡All ¡figures ¡including ¡0.75% ¡DLE, ¡but ¡excluding ¡1.8% ¡royalty ¡

MMBOE P50 SPLIT 2P RESERVES SPLIT

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Page 1 10 Corporate P Present ntation n Novemb mber 2 2013

200 400 600 800 1000 1200 1400 2013YE 2014YE 2015YE 2016YE 2017YE

US USDm

EXCESS CASH FLOW

  • CUM. PRE-TAX CF EXCL. CAPEX
  • CUM. CAPEX
  • 150
  • 100
  • 50

50 100 150 200 250 300 350 400 2013 2014 2015 2016 2017

US USDm

HUNTINGTON TRENT & TYNE ORLANDO KELLS

Cash h flo lows fund nd upcomi ming ng d develo lopme ment nts

  • Strong cash flow from Huntington and Trent & Tyne provides a solid backbone for the company going forward

– Pre tax cash flow of USD ~360m(1) prior to Orlando first oil

  • Orlando and Kells developments are fully funded by pre-tax cash flow from Huntington alone

– Estimated net capex of USD 172m(2) to first-oil at Orlando (USD 364m to fund full development programme at both fields) – Development solution with subsea tie-back to the existing Ninian platform effectively reduces capex risk significantly

  • No taxes expected payable until after Kells comes on production

– Tax loss carry forward of USD ~303m coupled with substantial investment program to bring Orlando and Kells on stream provides effective tax shelter

  • Self financed and repeatable business model – once Orlando and Kells are on stream cash flow from these fields will finance new

developments which again will shelter Iona from paying tax

Field ld b by f y field ld p pre t tax c cash f h flo low p profile le(1)

(1)

Accumu mula lated o

  • perationa

nal c l cash f h flo low v vs. . cape capex(1)(2)

Orlando 1st Oil Q4‘15 Kells 1st Oil Q4’16 (1) Cash ¡flows ¡based ¡on ¡GCA ¡economic ¡profiles ¡(see ¡GCA ¡CUR) ¡for ¡HunAngton, ¡Trent ¡& ¡Tyne, ¡Orlando, ¡and ¡Kells ¡with ¡Trent ¡and ¡Tyne ¡adjusted ¡for ¡37.5% ¡WI ¡and ¡GBP ¡23m ¡cost ¡of ¡Tyne ¡NW ¡well. ¡Not ¡adjusted ¡for ¡ effect ¡of ¡slower ¡than ¡expected ¡ramp-­‑up ¡on ¡HunAngton ¡or ¡temporary ¡producAon ¡curtailment ¡by ¡the ¡CATS ¡facility ¡operator ¡in ¡Q3 ¡2013 ¡ (2) Capex ¡based ¡on ¡GCA ¡esAmate ¡(GCA ¡CUR) ¡

Fr Free cash f h flo low

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Page 1 11 Corporate P Present ntation n Novemb mber 2 2013

Agend nda

  • Ove

vervie rview of Iona En Energ rgy y

  • Asse

Asset ove vervie rview

  • Fin

inancia cials ls

  • Ap

Appendix ix

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Page 1 12 Corporate P Present ntation n Novemb mber 2 2013

Hunt nting ngton - F n - Field ld s summa mmary y

(1) ¡DisproporAonate ¡LiHing ¡EnAtlement, ¡(2) ¡Includes ¡DLE ¡(3) ¡Sep ¡1st ¡2013 ¡ ¡

Hunt nting ngton - L n - Licens nse P P.1114 C CNS, B , Blo lock 2 k 22/14b

Iona working interest 15% (+ 2.55% DLE(1) and royalty) Partners E.ON (25%, op.), Premier (40%), Noreco (20%) 2P reserves (GCA CUR) Gross Net Iona(2) 29.1 MMboe; 26.3 MMbbl oil, 16.8 Bcf gas 4.6 MMboe; 4.1 MMbbl oil, 2.6 Bcf gas Expected peak production (gross) 34,500 boe/day

  • Producing oil field located in the Central North Sea

– Located in 90m water depth 230 kilometres east of Aberdeen – Developed with a leased stand alone FPSO (Voyageur Spirit) – Production start April 2013, ramp-up to peak rates of 34,500 boe/day achieved in early September – Production levels curtailed during Q3 and Q4 by CATS gas export issues – peak capacity to resume in December 2013

  • Discovered in 2007, FDP approved 2010

– Significant appraisal program carried out in 2007-08, including three appraisal wells and multiple appraisal sidetracks – Strong results from development drilling campaign reinforces pre drill resource estimates – Total gross investments of GBP 344.5m

  • Iona acquired its interest in December 2012

– Acquired from Carrizo for USD 203.6m, transaction closed Feb. ‘13 – Acquisition included tax balance of GBP 80.1m and 2.55% DLE(1) and royalties, increasing economic interest to 17.55%

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Page 1 13 Corporate P Present ntation n Novemb mber 2 2013

1 2 3 4 5 6 2013 2014 2015 2016 2017 2018 Mboe/ e/d net product ction to Iona 15% WI 2.55% DLE/ROY.

(1) Stock ¡Tank ¡Oil ¡IniAally ¡In ¡Place ¡ (2) High ¡ResisAvity ¡Zone ¡ ¡ (3) Not ¡adjusted ¡for ¡slower ¡than ¡expected ¡ramp-­‑up ¡on ¡HunAngton. ¡Including ¡0.75% ¡DLE ¡and ¡1.8% ¡royalty ¡ (4) Peak ¡rates ¡calculated ¡from ¡field ¡tests ¡

Hunt nting ngton p n production r n ramp mp-u

  • up c

comp mple lete

  • Positive results from the drilling campaign

– All four horizontal producers came in shallower than prognosis, encountering thicker than expected reservoir columns, achieved longer than expected horizontal sections and tested significantly above expectations – Estimated production capacity from the four wells of 80,000 bbl/day – Reservoir characteristics more favorable than expected – Operator calculated STOIIP(1) gain of 4% and HRZ(2) gain of 16% through drilling – Combined 2-well water injection capacity of 23,000 bopd meets produced water disposal needs

  • Commissioning nearing completion and production in line with

expectations

– Following first production on 12 April oil rate restricted to 7,000 to 10,000 bopd for three months by flaring consent – Initial gas export established on 5 June. Persistent vibration in one

  • f two parallel compression trains delayed ramp up – resolved

during August – Commissioning of primary oil storage tank blanket system in late August removed dependence on higher wind speeds – Peak rates of 34,500 boe/d now achieved with stable dual- compression operations – Six oil cargoes lifted since commencement on 16 May – Water injection commenced in late May

Comp Completi tion

  • n

Top F Forties (ft ft, T TVDSS) Gr Gross

  • ss

interval ( (ft ft) ) Test r result boe boe/d /day(4)

(4)

Well 22/14b-H4 11 Aug 2011 Prognosed Actual 8,621 8,611 2,483 3,010 10,0 ,000 23,0 ,000 Well 22/14b-H2 19 Dec 2011 Prognosed Actual 8,615 8,601 2,142 2,745 10,0 ,000 23,0 ,000 Well 22/14B-H3 12 Feb 2012 Prognosed Actual 8,629 8,604 2,300 2,935 10,0 ,000 23,0 ,000 Well 22/14B-H5 28 July 2012 Prognosed Actual 8,646 8,639 3,193 3,298 10,0 ,000 10,6 ,685

(3) ¡

De Develo lopme ment nt d drilli lling ng r result lts Hunt nting ngton p n production ( n (Net t to Io Iona na)

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Page 1 14 Corporate P Present ntation n Novemb mber 2 2013

Signi nificant nt r resources i in d n deeper H Hunt nting ngton ho n horizons ns(R

(R)

Jurassic ‘F ‘Fulma lmar’ a ’ and nd Tr Triassic ‘S ‘Skagerrak’ R k’ Reservoirs

Jurassic ‘F ‘Fulma lmar’ R ’ Reservoir (R

(R)

Triassic ‘S ‘Skagerrak’ R k’ Reservoir (R

(R)

  • Northern Area segment was discovered by well 22/14b-5 (currently

suspended) in May 2007, testing 39° API oil at up to ~4,600 bbl/day

– Significant oil in place – May be developed through the existing FPSO through use of horizontal wells and/or water injection

  • Further upside potential in the Central Area (15% WI) and Southern Area

(100% WI) segments

– 2C Contingent Resources of 5.8 MMbbl gross(R) – Prospective Resources of 12.6 MMbbl gross(R)

  • Opportunity to develop Fulmar in a phased approach as capacity

becomes available in the Huntington facilities

– Existing options to extend the five-year fixed term FPSO lease – Fulmar will benefit from low development and operating costs – Forties field life would be extended through incremental production

  • The 1987 discovery well proved a large column of light oil with

substantial in-place volumes in the Triassic formation

  • 2C Contingent Resources of 3.1 MMbbl net (21 MMbbl gross)(R)
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Page 1 15 Corporate P Present ntation n Novemb mber 2 2013

Trent nt & & T Tyne yne - F

  • Field

ld summa mmary

Iona working interest 20% at present, 37.5% post Tyne NW election Partners Perenco (80%, op.) 2P reserves (GCA CUR) Gross: Net to Iona: 9.6 MMboe: 57.2 Bcf 3.6 MMboe: 21.4 Bcf(1) Production start / peak In production since 1996, 119 MMcf/day Expected peak production (gross) 44 MMcf/day

  • Two producing gas fields acquired by Iona in 2011

– Paid GBP 21.2m for Tyne T6 development well to earn 20% WI in Trent & Tyne

  • Significant redevelopment potential identified
  • Assets virtually untouched since 1996
  • Substantial success since Iona entered in 2011 - T6 well sidetracked up-dip in

December 2012.

  • Two further drilling opportunities planned – Tyne NW and T1Z sidetrack
  • Several additional opportunities under evaluation
  • Substantial short-term production increase

– Iona will increase its interest to 37.5% after committing to drilling Tyne NW well – Will increase net production from current levels of 8.7 MMcf/day to 16.3 MMcf/day (2.7 Mboe/day) based on intended increased working interest only – Tyne NW expected to add further net 9.4 MMcf/day if successful

Trent nt & & T Tyne yne - L

  • Licens

nse P P609 & & P P685 S SNS, B , Blo lock 4 k 44/18

(1) ¡All ¡figures ¡based ¡on ¡Iona’s ¡net ¡WI ¡of ¡37.5% ¡post-­‑elecAon ¡to ¡drill ¡Tyne ¡NW ¡

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Page 1 16 Corporate P Present ntation n Novemb mber 2 2013

Prospective

5 10 15 20 25 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 Trent Tyne Tyne NW Mboe/day gross production

Tyne yne f field ld s structure

Trent nt & & T Tyne yne – – Redevelo lopme ment nt t to b boost p production n

  • Significant redevelopment potential identified
  • Assets virtually untouched since 1996
  • Substantial success since Iona entered in 201

– The T6 well was sidetracked up-dip and away from advancing water in December 2012 and brought on-stream in January following quick well tie-in engineering. Current production of 28 MMcf/day gross

  • Two further drilling opportunities planned

– Tyne NW estimated to contain 20 Bcf(R) prospective resources

  • Iona’s WI to increase to 37.5% with effect of 1 January 2013

– T1Z sidetrack contains 25 Bcf 2P(GCA CUR) expected to add 18 MMcf/day production

  • Contingent Tyne East development estimated to add 17 Bcf

& 15 MMcf/day (contingent resources) (R)

  • Further opportunities under evaluation

– Three drillable structures identified for further work: i) West of T2, ii) West of Tyne NW and iii) older reservoirs below the platform – Other new development wells, sidetracks, development of undeveloped fault blocks, low risk infrastructure led exploration

  • Annual tariff incomes from TORS and Cygnus gas fields of

USD 2-4m per year expected over next ten years

Iona acquired 20% WI

Producing

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Page 1 17 Corporate P Present ntation n Novemb mber 2 2013

  • Established hydrocarbon area in the Northern North Sea

containing multiple producing fields and significant infrastructure

– Centralized around the giant Ninian oil field (>1 billion bbl recovered to date) – Located approx. 150 kilometres east of Shetland Islands in 140m water depth

  • Iona has operatorship in four proven accumulations in the area

with net 2P reserves of 18 MMboe(GCA CUR) and discovered 2C resources of 51 MMboe(R)

  • Orlando and Kells is a “twin” development project of two satellite

fields

– Acquired by Iona through several transactions during 2011-12 – Combined reserves of 18.1 MMboe net (24.2 MMboe gross) (R) – Expected to be tied back to the Ninian Central Platform (“NCP”) – a long term hub for oil and gas export – Planned to be developed in a phased approach with production start planned 2015 and 2016 for Orlando and Kells respectively

  • Significant follow-up potential in the area from the Ronan and

Oran discoveries

– Recently awarded in the 27th Round – Significant appraisal upside and strong development and

  • perational synergies with the Orlando and Kells field

developments

Nini nian a n area d develo lopme ment nts – – Int Introduction n

NCP

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Page 1 18 Corporate P Present ntation n Novemb mber 2 2013 Iona working interest 75%, operator Partner Atlantic Petroleum (25%) 2P reserves (GCA CUR) Gross Net to Iona 15.4 MMbbl 11.5 MMbbl Expected production start 4Q 2015 Expected peak production 11,000 bbls/day (October 2015)

Nini nian a area – – O Orla land ndo f field ld s summa mmary y

Orla land ndo - L

  • Licens

nse P P.1606 N NNS, B , Blo lock 3 k 3/3b

  • Small oil field located approx. 10 kilometres north-east of the

Ninian Central Platform

– Original 35% WI acquired from Wintershall in 2010 for USD 3.15m – Acquired remaining 65% from MPX and Sorgenia in 2011-12 for USD 48.3m plus USD 29m over first three years of production (pre farm-down) – Sold 25% WI to Atlantic Petroleum in Dec. 2012 for USD 30 million plus share of future payments (USD 7.25m)

  • Well delineated field following successful appraisal program

– Originally discovered by Chevron in 1988, Orlando was re-awarded in the 25th round in 2009 – Successful two well (3/3b-13 and 3/3b-13z) appraisal program in 2011-12 confirmed reservoir quality and resulted in reserve upgrade

  • Reservoir with strong production characteristics

– Orlando, like other fields in the area, consists of a high quality Brent reservoir (18% porosity, 50mD permeability) with a high quality oil (32O API) and a large underlying aquifer for pressure support

NCP

slide-19
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Page 1 19 Corporate P Present ntation n Novemb mber 2 2013

Orla land ndo – – De Develo lopme ment nt p program m

  • Current field development plan approved in April 2013

– Expected to be developed as a subsea tie-back to NCP with one firm horizontal well – One contingent well subject to reservoir performance and prevailing economic conditions

  • Straight forward development based on well known technology

– First well will utilize suspended appraisal well and be completed near-horizontal with dual Electric Submersible Pumps – The subsea facilities will comprise Pipeline End Manifold, an insulated, trenched and buried 8” pipeline to NCP and a trenched and buried umbilical for power, controls and chemical injection

  • All long lead procurement contracts have been tendered and all

contracts are expected to be in place by 1Q 2014

  • Remaining net capex of USD 182m(1) whereof USD 139m prior

to first oil

– Flowline manufactured and subsea Xmas trees almost complete

1 2 3 4 5 6 7 8 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Kboe/ e/d net product ction to Iona

(1) ¡Issuer’s ¡latest ¡project ¡view ¡based ¡on ¡current ¡supply ¡chain ¡esAmates ¡

slide-20
SLIDE 20

Page 2 20 Corporate P Present ntation n Novemb mber 2 2013 Iona working interest 75%, operator Partner Atlantic Petroleum (25%) 2P reserves(1) (GCA CUR) Gross Net to Iona 8.8 MMboe: 4.2 MMbbl oil, 27.5 Bcf gas 6.6 MMboe: 3.2 MMbbl oil, 20.1 Bcf gas Expected production start 4Q 2016 Expected peak production 10,400 boe/day (October 2016)

Kells lls – – L Licens nse P P.1607 N NNS, B , Blo lock 3 k 3/8d

Nini nian a area – – Kells lls f field ld s summa mmary y

  • Small field located approx. 13km south-east of the NCP

– Acquired from Fairfield in October 2011 for USD 8.6m plus a contingent payment of USD 5m on FDP approval and royalty of USD 2.50/boe of production – Sold 25% WI to Atlantic Petroleum in February 2013 for USD 4 million plus share of future payments(2)

  • Re-development of the old Staffa field

– Discovered by BP in 1985 and developed as a subsea tie-back to NSP by Lasmo, Staffa produced 5.3 MMboe during 1992-94, with an initial rate of ~14,000 boe/day, before it was decommissioned due to pipeline blockages (uninsulated pipeline) and low oil prices – Strong reservoir control due to four reservoir penetrations and detailed production history from the Staffa field

  • Twin of Orlando development – subsea tie-back to NCP
  • Subsea development of high quality Brent reservoir

– Brent reservoir (11% porosity, 10-100mD permeability) with a high quality (40O API) oil

(1) ¡Plus ¡2.0 ¡MMboe ¡(1.5 ¡MMboe ¡net) ¡2C ¡resources ¡from ¡water ¡injecAon(R) ¡ (2) ¡Pro-­‑rata ¡share ¡of ¡both ¡USD ¡5m ¡at ¡FDP ¡approval ¡and ¡USD ¡2.5/boe ¡royalty ¡to ¡Fairfield ¡

slide-21
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Page 2 21 Corporate P Present ntation n Novemb mber 2 2013

Kells lls – – De Develo lopme ment nt p program m

  • FDP agreed and held by DECC pending final submission in 2014

– Expected to be developed as a subsea tie-back to NCP – Two production wells – one pre first oil and second 12 to 18 months later as producer with scope for later conversion to water injection – Near-vertical wells penetrating the Tarbert and Upper Ness zones. – Pre first oil subsea facilities will comprise Pipeline End Manifold, an insulated, trenched and buried 6” in 10” diameter pipe-in-pipe pipeline to NCP and a trenched and buried umbilical to provide controls and chemical injection

  • Flow assurance blockage issues addressed by pipeline insulation

(pipe-in-pipe) and chemical injection – both proven technologies

  • Contracts are in place for two subsea xmas trees - balance of the

work program will be tendered in 2014

– Xmas trees near completion

  • Total remaining net capex: USD 154m(1)
  • Issuer contemplating pursuit of water flood development

– Second well could be converted for water injection – Anticipated to yield additional net 3.0 MMbbl over 2P oil reserves (R) – Requires installation of WI flowline in 2017

1 2 3 4 5 6 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Kboe/ e/d net product ction to Iona

(1) Capex ¡based ¡on ¡GCA ¡esAmate(GCA ¡CUR) ¡

slide-22
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Page 2 22 Corporate P Present ntation n Novemb mber 2 2013

Nini nian A n Area – – R Rona nan & n & O Oran n

  • Ronan & Oran are two oil discoveries located 14 km south of

the NCP and 14 km south west of Kells

– Acquired through the 27th License Round – 1C – 2C – 3C Contingent Resource range of 31 – 49 – 71 MMbbl (R) – Work obligation: i) re-process 3D data and ii) by end 2014 commit to well to be drilled by end 2016 or drop licence – Likely well to test eastern extent of Oran in 2016 with possible FDP in 2017 and first oil in 2018 – Subject to further work the discoveries are expected to be developed as a cluster development with potential tie-in to the NCP via the Kells manifold and pipeline

  • Ronan discovery (3/7-3 well, Chevron 1977)

– Brent oil discovery - appraised in 1978 (3/12-2) – OWC not encountered – upside to current resource estimates – 2C Contingent Resources of 30.9 MMbbl (R)

  • Oran discovery (well 3/7-8, CNR 2005)

– Brent oil discovery – OWC (oil-water contact) not encountered – upside to current resource estimates – 2C Contingent Resources of 18.3 MMbbl (R)

Rona nan & n & O Oran ( n (100% i int nterest)

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Page 2 23 Corporate P Present ntation n Novemb mber 2 2013

  • Small heavy oil field (17o API) located 5 km west of Captain

– Acquired from Centrica in August 2012 for USD 8.2m

  • Well delineated field, but not yet flow tested

– Discovered in 1990 by Amoco well 13/21a-1A – Appraised in 1996 and 2001 with two + two wells – Lower Cretaceous Upper Captain Reservoir (30% porosity) – Analogue to nearby producing Captain field - following 10 year production history Captain has a projected 33% recovery factor

  • Several development options being screened

– Drill from Captain field – Subsea tie back to Captain – Standalone or joint development being explored – The development concept will be one or two producers powered by ESP – Wells will be dual-bore 2000 foot horizontals with sand control and artificial lift

  • Decision on export route targeted in 2014, plan to proceed to FDP

thereafter

West W Wick k

Iona working interest 58.73%, operator Partner Idemitsu (41.27%, op.) 2P reserves (GCA CUR) Gross Net to Iona 16.5 MMbbl 9.7 MMbbl Possible production start Q4 2016 Possible peak production 10,000 boe/day

West W Wick – k – L Licens nse P P.185 C CNS, B , Blo lock 1 k 13/21a

slide-24
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Page 2 24 Corporate P Present ntation n Novemb mber 2 2013

High a h activity le y level g l going ng f forward – – f fully f lly fund nded

Firm a m activity y Cont nting ngent nt a activity y

Provided ¡for ¡illustraAon ¡only. ¡Budgets ¡and ¡forecasts ¡beyond ¡2013 ¡have ¡not ¡been ¡finalized ¡and ¡are ¡subject ¡to ¡ a ¡variety ¡of ¡factors ¡including ¡prior ¡year's ¡results ¡and ¡assumed ¡increase ¡in ¡Trent ¡& ¡Tyne ¡WI ¡to ¡37.5% ¡

¡

20 2013 3 20 2014 4 20 2015 5 20 2016 6 20 2017 7 20 2018 8

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Hunt nting ngton Production Appraisal drilling

  • Hunt. Deep production

Trent nt & & T Tyne yne Tyne NW election – new W.I. of 37.5%

*

Drill Tyne NW Tyne 1z side track Production from TNW and T1z Orla land ndo Field Development Plan Platform modifications Drilling 1st well Subsea installation (production) Production Drilling 2nd well Subsea installation (2nd well) Kells lls Field Development Plan Platform modifications Drilling 1st well Subsea installation (production) Production Drilling 2nd well Subsea installation (2nd well) F First o

  • il

l

*

A Approval l

*

F First o

  • il: Q

l: Q4 ‘1 ‘15

*

A Approval l

*

F First o

  • il Q

l Q4 ‘1 ‘16

*

Approval l Commi mmit t to T TNW F First g gas: Q : Q4 ‘1 ‘14 Inc Increased W WI t I to 3 37.5 .5%

* *

slide-25
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Page 2 25 Corporate P Present ntation n Novemb mber 2 2013

Agend nda

  • Ove

vervie rview of Iona En Energ rgy y

  • Asse

Asset ove vervie rview

  • Fin

inancia cials ls

  • Ap

Appendix ix

slide-26
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Page 2 26 Corporate P Present ntation n Novemb mber 2 2013

  • On September 27th, Iona closed USD $275m in senior secured bonds

– 5-year term – 9.5% coupon issued at 97.5% OID – No bond amortizations prior to March 2016

  • Use of bond proceeds:

– Refinanced approximately USD 143m of existing bank debt – Retired 3.1m calls sold to BP for USD 33.5m – Remaining net proceeds of ~USD 90m to be spent on the Orlando and Kells development

  • Through the bond issue and cash flow from producing assets Iona is fully financed for all its committed and planned

investment activities – Comfortable funding situation post bond issue due to strong cash flow from producing fields – The bond provides added flexibility for the company to spend cash flow from the Huntington and Trent & Tyne fields

  • n its Orlando and Kells development projects

– Term and amortization profile of the bond tailor-made to match expected cash flow from Iona’s core assets

  • Capital commitments solely related to acquisition, appraisal, and development projects

– USD 34m on increased WI at Trent & Tyne and USD 7m for T1z sidetrack, USD 173m(1) at Orlando and Kells prior to 1st oil at Orlando

Io Iona na E Ene nergy f y fina nanc ncing ng

(1) Issuer’s ¡latest ¡project ¡view ¡based ¡on ¡current ¡supply ¡chain ¡esAmates ¡

slide-27
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Page 2 27 Corporate P Present ntation n Novemb mber 2 2013

50 100 150 200 250 300 350 400 2013 2014 2015 2016 2017 2018 CAPEX ¡& ¡Acq. ¡cost Debt ¡service G&A Exploration ¡costs Taxes

  • CAPEX at Orlando, Trent & Tyne, and

Kells of USD 172m(2), USD 41m, USD 154m(2) respectively (from 1.1.2013)

  • ~USD 303m existing tax pools
  • Exchange rate 1.6 USD/GBP

Strong ng f fina nanc ncial p l position p n post b bond nd i issue

Potent ntial e l expend nditure p profile le(1)

(1) (US

USDm Dm) ) Operating ng c cash f h flo low p profile le ( (US USDm Dm) )

  • Huntington reached full capacity in early

September ‘13

  • Long-term gas production from Trent &

Tyne at 37.5% WI

  • Orlando first oil scheduled Q4 ‘15
  • Kells first oil Q4 ’16
  • Oil price: USD 100/bbl (nominal)
  • Gas price: USD 10/MMcf
  • Based on independent reserve estimates

performed by GCA(GCA CUR) (1) Appraisal ¡acAviAes ¡include ¡CAPEX, ¡exploraAon ¡ investments ¡based ¡on ¡expected ¡exploraAon ¡ spending ¡ (2) Capex ¡based ¡on ¡GCA ¡esAmate(GCA ¡CUR) ¡ ¡

  • Solid operational cash flow ensures

comfortable funding situation post bond issue

  • No significant taxes estimated payable

until 2017 due to utilization of ~USD 303m tax loss and substantial investments related to Orlando and Kells field development

  • Bond structure provides flexibility for

development projects, unlocking value potential and cash flows from Orlando and Kells

  • Strong support from global oil prices and

UK gas prices

− Go-forward hedging that protects projected capital requirements − Bi-annual policy review

  • Exploration spending not a core part of

corporate strategy

  • Low G&A due to cost effective
  • rganisation

50 100 150 200 250 300 350 400 2013 2014 2015 2016 2017 2018 Huntington Trent ¡& ¡Tyne Orlando Kells

slide-28
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Page 2 28 Corporate P Present ntation n Novemb mber 2 2013

  • Conservative business profile - development

and production oriented company

  • Significant UKCS asset base with 36.0

MMboe 2P reserves (GCA CUR)

  • 2013 exit of 7,500 boe/day expected to

increase to 8,500 boe/day in early 2014

  • Exit 2016 production of 17,000 boe/day with

both Orlando and Kells in production

Executive s summa mmary y

  • Orlando and Kells developments funded through bond financing and operating cash flow –

expected 2013-15 cash flow of USD ~400m from Huntington and Trent & Tyne

  • USD ~303 million of tax losses in the UK - no significant taxes payable until 2017 due to

existing tax loss coupled with significant investments

  • Self-financing and repeatable business model – Orlando and Kells cash flows will finance

new developments which again will shelter Iona from paying tax

AVERAGE ANNUALIZED KBOE/DAY

5 5 10 10 15 15 20 20 25 25 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019 2019

HUNTINGTON HUNTINGTON TREN ENT & & TYN YNE E ORLAN ANDO KEL KELLS S WEST EST WICK K HUNTINGTON DEEP EEP RONAN AN & & ORAN AN 2P Production 2P Developments 2C Contingent Resources

slide-29
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Page 2 29 Corporate P Present ntation n Novemb mber 2 2013

Agend nda

  • Ove

vervie rview of Iona En Energ rgy y

  • Asse

Asset ove vervie rview

  • Fin

inancia cials ls

  • Ap

Appendix ix

slide-30
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Page 3 30 Corporate P Present ntation n Novemb mber 2 2013

Append ndix

  • Iona En

Energ rgy y Comp mpany y (U (UK) K) Limit imited

  • Huntin

ington

  • Tre

rent & & Tyn yne

  • Nin

inia ian are rea asse ssets s

  • Other

r asse ssets s and in informa rmatio ion

slide-31
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Page 3 31 Corporate P Present ntation n Novemb mber 2 2013

Comp mple lete li licens nse ov

  • verv

erview ew

Blo lock k Int Interest Licens nse N No. . Ent ntity y Main A n Asset Operat Operator

  • r

3/3b 75% P.1606 Iona Energy Company (UK) Limited Orlando Iona Energy Company (UK) Limited 3/8d 75% P.1607 Iona Energy Company (UK) Limited Kells Iona Energy Company (UK) Limited 3/7c (part) 100% P.1971 Iona Energy Company (UK) Limited Oran Iona Energy Company (UK) Limited 3/8c 100% P.1971 Iona Energy Company (UK) Limited Oran Iona Energy Company (UK) Limited 3/12 (part) 100% P.1971 Iona Energy Company (UK) Limited Ronan Iona Energy Company (UK) Limited 13/21a 58.73% P.185 Iona Energy Company (UK) Limited West Wick Iona Energy Company (UK) Limited 22/14b 15% P.1114 Iona UK Huntington Limited Huntington Forties E.ON Rhurgas 22/14d 100% P.1801 Iona Energy Company (UK) Limited Huntington Fulmar Iona Energy Company (UK) Limited 43/24a 20% P.685 Iona Energy Company (UK) Limited Trent Perenco UK Ltd. 44/18a Area A and B 20% P.609 Iona Energy Company (UK) Limited Tyne Perenco UK Ltd.

slide-32
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Page 3 32 Corporate P Present ntation n Novemb mber 2 2013

Io Iona na a acquisition a n and nd d divestme ment nt hi history y

Acquisitions ns Worki king ng Int Interest Selle ller Acquisition Da n Date Acquisition P n Price No Notes s Orlando 35 % Wintershall Mar 2011 USD 3m Plus 42.5% cost share of appraisal well Trent & Tyne 20 % Perenco May 2011 GBP 21.2m Paid 100% of cost-capped T6 development well to earn 20% WI Kells 100 % Fairfield Jan 2012 USD 5m Payable upon FDP approval USD 2.5/boe Royalty payment West Wick 58.73% Centrica Feb 2012 USD 8.15m Orlando 65% (to 100%) MPX/Sorgenia June 2012 USD 48m Reimbursement of past costs USD 29m Staged payments related to production(1) Huntington 15%(2) Carrizo Dec 2012 USD 203.6m Includes tax pools of GBP 80.1m(3) Trent & Tyne (pending) 17.5% (to 37.5%) Perenco 2013 GBP 23m Pay 100% of cost-capped NW Tyne well to earn additional 17.5% WI Di Divestme ment nts Worki king ng Int Interest Bu Buyer Di Divestme ment nt Da Date Di Divestme ment nt P Price No Notes s Orlando & Kells 25 % Atlantic Pet.

  • Dec. 2012

USD 34m Upfront consideration USD 7.25m Staged payments related to Orlando production(4) USD 1.25m Payable upon Kells FDP approval USD 2.5/boe Proportionate share of Kells royalty payable to Fairfield

(1) ¡Staged ¡payments ¡commencing ¡six ¡months ¡aHer ¡first ¡producAon ¡from ¡Orlando ¡of ¡USD ¡7m, ¡USD ¡7m, ¡USD ¡7m, ¡USD ¡4m ¡and ¡USD ¡4m ¡made ¡every ¡six ¡months ¡thereaHer ¡respecAvely ¡ ¡ (2) ¡Including ¡0.75% ¡DisproporAonate ¡LiHing ¡EnAtlement ¡and ¡1.8% ¡RoyalAes ¡ (3) ¡EffecAve ¡date ¡1.7.2012 ¡ ¡ (4) ¡Staged ¡payments ¡commencing ¡six ¡months ¡aHer ¡first ¡producAon ¡from ¡Orlando ¡of ¡USD ¡1.8m, ¡USD ¡1.8m, ¡USD ¡1.8m, ¡USD ¡0.925m ¡and ¡USD ¡0.925m ¡made ¡every ¡six ¡months ¡thereaHer ¡respecAvely ¡ ¡

slide-33
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Page 3 33 Corporate P Present ntation n Novemb mber 2 2013

Append ndix

  • Iona En

Energ rgy y Comp mpany y (U (UK) K) Limit imited

  • Huntin

ington

  • Tre

rent & & Tyn yne

  • Nin

inia ian are rea asse ssets s

  • Other

r asse ssets s and in informa rmatio ion

slide-34
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Page 3 34 Corporate P Present ntation n Novemb mber 2 2013

Hunt nting ngton – n – De Develo lopme ment nt s sche hema matics

slide-35
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Page 3 35 Corporate P Present ntation n Novemb mber 2 2013

  • Vessel statistics

– Sevan 300 unit previously on UKCS Shelley field – Accommodation for 57 personnel – Hydrocarbon processing, gas compression, water injection and

  • il storage and offloading

– Storage for 285,000 bbl of oil (effective capacity 235,000) – Max capacity:

  • Oil: 30,000 bbl/day
  • Gas: 38 MMcf/day
  • Produced water: 42,000 bw/day
  • Total liquids: 60,000 bbl/day
  • Water injection: 48,000 bwi/day

– Voyageur Spirit and sister vessels Piranema and Hummingbird have consistently displayed technical uptimes in excess of 97%

  • Key contract terms

– Five year fixed term with Teekay – Initial day rate USD 215k declining by USD 5 kpd per year – After 5 year fixed term joint venture has evergreen option to extend contract each year by 12 months

Hunt nting ngton: n: Voya yageur S Spirit F FPSO

slide-36
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Page 3 36 Corporate P Present ntation n Novemb mber 2 2013

Hunt nting ngton d n deep: J : Jurassic a and nd T Triassic p prospectivity y

Triassic ¡Skagerak ¡and ¡For3es ¡ Jurassic ¡Fulmar ¡and ¡For3es ¡

  • Potential satellite development tie-backs to Voyageur FPSO
  • Iona 15% and 100% WI, opportunity to rationalize interest and commercialize

FPSO FPSO

slide-37
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Page 3 37 Corporate P Present ntation n Novemb mber 2 2013

Append ndix

  • Iona En

Energ rgy y Comp mpany y (U (UK) K) Limit imited

  • Huntin

ington

  • Tre

rent & & Tyn yne

  • Nin

inia ian are rea asse ssets s

  • Other

r asse ssets s and in informa rmatio ion

slide-38
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Page 3 38 Corporate P Present ntation n Novemb mber 2 2013

Trent nt & & T Tyne yne f facili lities

  • Production facilities

– Both the Trent and the Tyne fields have been developed using a NUI(1) platform – A MOAB(2) bridge-linked to the Trent platform was installed in 2005 to provide compression facilities for Trent and Tyne as well as third party developments

  • Development wells and subsea facilities

– All production wells have dry trees (no subsea wells)

  • Trent: three wells (excludes abandoned wells)
  • Tyne five wells (excludes abandoned wells)

– A 56km dedicated gas pipeline transports gas from the Tyne field to the Trent platform for processing

  • Hydrocarbon export solutions

– From Trent, gas is shipped 165km onshore to the Bacton terminal through ETS – Tariffs payable to ETS (Iona owns 2.5% of system, rising to 4.69% following WI increase on Trent & Tyne) and the Bacton Terminal (no ownership) – Gas sold via Perenco at spot price minus a nominal management fee

  • Third party business through infrastructure ownership

– Tors currently producing ~20 MMcf/day with the Operator of the facility estimating that 30 Bcf will ultimately be recovered and processed at the facility over the next 10 years (utilizing both ETS and the compression facilities at Trent)(3) – As contemplated contractually between Perenco and GDF Suez, more than 550 Bcf of gas may be produced from Cygnus and processed at the facility (utilizes ETS) – Tariff revenues are included in GCA analysis and make up ca.15% of field value

(1) Normally ¡Unmanned ¡InstallaAon ¡ (2) (2) ¡Mobile ¡Offshore ¡ApplicaAons ¡Barge ¡ (3) ¡Source ¡Wood ¡Mackenzie ¡(not ¡independently ¡verified ¡by ¡Iona) ¡

slide-39
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Page 3 39 Corporate P Present ntation n Novemb mber 2 2013

Append ndix

  • Iona En

Energ rgy y Comp mpany y (U (UK) K) Limit imited

  • Huntin

ington

  • Tre

rent & & Tyn yne

  • Nin

inia ian are rea asse ssets s

  • Other

r asse ssets s and in informa rmatio ion

slide-40
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Page 4 40 Corporate P Present ntation n Novemb mber 2 2013

Orla land ndo d develo lopme ment nt s sche hema matic

slide-41
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Page 4 41 Corporate P Present ntation n Novemb mber 2 2013

Nini nian C n Cent ntral P l Pla latform – m – M Mino nor brownf nfield ld mo mods

  • Essential Isolation

work completed in 2012 shutdown

  • Dominant utilisation
  • f existing unused

and certified vessels and pipework

  • Catenary Platform

(IRHS) for tie-in of Orlando and Kells

  • Minimum flowline

and controls modifications in module at edge of platform

  • Well defined

75,000 manhour workscope

  • Less than 10% of

platform manpower (beds) required

slide-42
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Page 4 42 Corporate P Present ntation n Novemb mber 2 2013

Kells lls d develo lopme ment nt s sche hema matic

slide-43
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Page 4 43 Corporate P Present ntation n Novemb mber 2 2013

2 4 6 8 10 12 14 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Kboe/ e/d net product ction to Iona Orlando Kells

Kells lls – – f flo low a assuranc nce i is w well u ll und nderstood

  • Kells, formerly Staffa, was originally developed using an

uninsulated pipeline

  • As one of the first subsea tie-backs in the North Sea, flow

assurance issues were not well understood

  • The pipeline became blocked after about 15 months of production

due to wax build-up at a “cold point” on the pipeline where the pipeline was untrenched at a pipeline crossing

  • The blocked section of pipe was removed and replaced and

production resumed with more careful monitoring

  • The pipeline became partially blocked again after a year and in an

effort to clear the blockage by “bull-heading” from the well the pipeline was blocked by hydrates

  • Prevailing low oil prices (USD 10-14/bbl) made further repairs

uneconomical and the field was fully abandoned in 1995

  • Samples of Staffa crude were kept and laboratory testing has been

performed to confirm wax appearance temperature and other properties

  • Tests confirm that, with adequate insulation provided by a pipe-in-

pipe system and some chemical usage, the pipeline can operate for the life of Kells

  • The wax content of Staffa/Kells oil is similar to other Brent crudes at

around 5%

  • Pipe-in-pipe systems provide a very high level of insulation and are

now commonplace in the North Sea Staffa hi historical p l production

2 4 6 8 10 12

  • Jan. '92
  • Jul. '92
  • Jan. '93
  • Jul. '93
  • Jan. '94
  • Jul. '94
  • Jan. '95

Kbbl/d /d product ction n (100% 00% WI) blockage blockage Pipe replaced

Orla land ndo & & K Kells lls e expected c comb mbine ned p production

slide-44
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Page 4 44 Corporate P Present ntation n Novemb mber 2 2013

Iona's business is subject to numerous risk factors which may have a material effect upon its properties, results of operations and financial position. Please refer to the risk factors described in the Company's annual information form for the year ended December 31, 2012, annual management discussion & analysis for the year ended December 31, 2012 and interim management discussion & analysis for the three and nine months ended September 30, 2013, all of which are available under Iona's SEDAR profile on SEDAR at www.sedar.com.

Summa mmary o y of r risk f k factors

slide-45
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Page 4 45 Corporate P Present ntation n Novemb mber 2 2013

NOTES ES REG EGAR ARDING OIL AN AND GAS AS DISC SCLOSU SURE The reserves and resource estimates contained herein, including the corresponding estimates of future net revenues, are estimates only and the actual results may be greater than or less than the estimates provided herein. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value. The estimated values of future net revenue disclosed in this presentation, whether calculated with or without a discount rate, do not represent fair market value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. As used in this presentation, "possib ssible le re rese serve rves" are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. In this presentation, information has been provided with respect to certain reserves information for other companies with oil and gas properties in the U.K. North Sea which is "analo logous s in informa rmatio ion" as defined in applicable securities laws. This analogous information is derived from publicly available information sources which Iona believes are predominantly independent in nature. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the preparation of any estimates may not be in strict accordance with Canadian Oil & Gas Evaluation Handbook. Regardless, estimates by engineering and geotechnical practitioners may vary and the differences may be significant. Iona believes that the provision of this analogous information is relevant to Iona's activities, given its positions and operations (either ongoing or planned) in the area in question, however, readers are cautioned that there is no certainty that any of the development on Iona's properties will be successful to the extent in which operations on the lands in which the analogous reserves information is derived from were successful, or at all. "Contin ingent Reso source rces" is defined in the Canadian Oil and Gas Evaluation Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. 1C, 2C and 3C refer to the low estimate, best estimate, and high estimate, respectively, of contingent resources. The Oran, Ronan, Fulmar and Huntington Skagerrak fields are currently at an early stage of evaluation and require further analysis to confirm their economic viability. Additionally, the resources in each of these fields are currently classified as Contingent Resources rather than reserves due to the current lack of access to infrastructure in the region for each field. Additional drilling and testing are required to confirm volumetric estimates and reservoir productivity for the Contingent Resources to be classified as reserves. The Contingent Resources estimates are estimates only and the actual results may be greater than or less than the estimates provided herein. There is no certainty that it will be commercially viable or technically feasible to produce any portion of the resources. "Prospective Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. There is no certainty that any portion of the undiscovered resources will be discovered. If a discovery is made, there is no certainty that it will be commercially viable to produce any portion of the resources. The prospective resources estimates relating to Iona's properties contained in this presentation were prepared by a non-independent qualified reserves evaluator of Iona as of October 1, 2013. The well test results disclosed in this presentation represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. In this presentation, “working interest” reserves are calculated as the Corporation's share of reserves, excluding royalty interest reserves and before the deduction of royalty burdens payable. The reserves report was prepared utilizing definitions as set out under NI 51-101 – Standards of Disclosure for Oil and Gas Activities.

Summa mmary y of

  • f r

risk k factors factors

slide-46
SLIDE 46

Page 4 46 Corporate P Present ntation n Novemb mber 2 2013

  • “G

“GCA" means Gaffney Cline & Associates Ltd.

  • “G

“GCA A 2011” means Orlando and Trent & Tyne reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of December 31, 2011.

  • "GCA

A 2012" means O + T + W + K reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of 31 December 2012.

  • "GCA

A CUR" means O + T + W + K + H reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of 31 December 2012, also assuming T WI of 37.5% effective as of December 31, 2012.

  • “R” means internal Corporation estimate prepared by a non-independent qualified reserves evaluator, effective October 1, 2013
  • "O" means Orlando reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of December 31,

2012.

  • "T" means Trent & Tyne reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of December 31,

2012.

  • "W

"W" means West Wick reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of December 31, 2012.

  • "K" means Kells reserves and net present value information prepared by GCA (using forecast prices and costs) effective as of December 31, 2012.
  • "H" means Huntington reserves and net present value information (and where applicable, contingent resources estimates) prepared by GCA (using

forecast prices and costs) effective as of December 31, 2012.

End ndno notes