JKX Oil & Gas Investor presentation London March 2017 - - PowerPoint PPT Presentation

JKX Oil & Gas

Investor presentation

London March 2017

Disclaimer

The information contained in these presentation materials (the “Presentation”) has been prepared by JKX Oil & Gas plc (the “Company”). This Presentation is being made for information purposes only and does not constitute an offer or invitation for the sale or purchase of securities in the Company or any of the assets described in it nor shall they nor any part of them form the basis of or be relied on in connection with, or act as any inducement to enter into, any contract or commitment whatsoever or otherwise engage in any investment activity (including within the meaning specified in section 21 of the Financial Services and Markets Act 2000 as amended). The information in this Presentation does not purport to be comprehensive and has not been independently verified. While this information has been prepared in good faith, no representation or warranty, express or implied, is or will be made and no responsibility or liability is or will be accepted by the Company or any of its officers, employees, agents or advisers as to, or in relation to, the accuracy or completeness

• f this Presentation, and any such liability is expressly disclaimed. In particular, but without prejudice to the generality of the foregoing, no

representation or warranty is given as to the achievement or reasonableness of any management estimates or prospects contained in this Presentation. Such statements, estimates and forecasts reflect various assumptions made by the management of the Company and their current beliefs, which may or may not prove to be correct. A number of factors could cause actual results to differ materially from the potential results discussed in such forward-looking statements, estimates and forecasts including: changes in general economic and market conditions, changes in the regulatory environment, business and operational risks and other risk factors. Past performance is not a guide to future

• performance. Statements contained in this document regarding past trends or activities should not be taken as a representation or warranty,

express or implied, that such trends or activities will continue in the future. No statement in this document is intended to be a profit forecast. You should not place reliance on forward-looking statements, which speak only as of the date of this document. The Presentation is not a prospectus nor has it been approved by the London Stock Exchange plc or by any authority which could be a competent authority for the purposes of the Prospectus Directive (Directive 2003/71/EC). This Presentation has not been approved by an authorised person for the purposes of section 21 of the Financial Services and Markets Act 2000. The information contained in this Presentation is subject to change, completion or amendment without notice and is subject to verification. Recipients of this Presentation in jurisdictions outside the UK should inform themselves about and observe any applicable legal

• requirements. This Presentation does not constitute an offer to sell or an invitation to purchase securities in any jurisdiction.

You will be taken to have represented, warranted and undertaken to the Company that: (i) you have read and agree to comply with the contents and restrictions of this disclaimer; and (ii) you will conduct your own analysis or other verification of the data and information set

• ut in this Presentation and will bear the responsibility for all or any costs incurred in doing so.

2

JKX Oil & Gas (JKX LN)

E&P growth portfolio across Central/Eastern Europe and Russia

• Ukraine: large-scale field development
• pportunity
• Russia: Stable cash-generating
• perations
• Hungary/Slovakia: Significant

exploration potential

• Team: New board and executive

management focused on modern development approach

*Source: Company data, Reserves and Contingent Resources are DeGolyer and MacNaughton estimates as of 31 December 2016 Country Licenses Prod Expl Infrastructure 2016 Production Reserves mmboe Contingent Resources mmboe Gas mmcf/d Oil mbbl/d Total mboe/d 1P 2P 3C Ukraine Ignativske Elyzavetivske Rudenkivske Novomykolaivske Movchanivske Zaplavska ✓ ✓ ✓ ✓ ✓ ✓ 2 Processing Facilities 1 LPG Plant 18.6 0.9 4.0 15 29 457 Russia Koshekhablskoye ✓ 1 Gas Processing 36.1 0.1 6.1 43 80 108 Hungary 6 Licenses ✓ 1 Gas Processing

• 1

Slovakia 3 Licenses (25% WI) ✓

• Total

54.7 1.0 10.1 58 109 565 3

Progress & Priorities

Progress provides launch pad for growth

2016 Progress

• Completed detailed field development plans (FDPs) for all core assets, identified growth opportunities,

and started their implementation

• Increased production with minimum capital expenditure
• Reduced operating costs and overheads, resulting in an increase in cash flow and profitability
• Eliminated short-term financial liabilities (bond repurchase and restructuring)
• Completed international arbitration procedure, while actively engaging in dialogue with the Government of

Ukraine.

• Built a technical team

2017 Priorities

Ukraine: Execute development plan Hungary/Slovakia: Appraisal and Exploration Resolve legal issues with Ukraine Russia: Maintain base and consider strategic monetization

1 2 3 4 5 6

4

Strategic Growth Priorities

Leading Central/Eastern European focused E&P

• Increase production
• Explore and appraise Hungary & Slovakia

upside potential

• Improve market profile for retail and

institutional investors

Production growth underpinned by transparency and western technology

• Leverage existing resource base and local

expertise

• Introduce modern technology and practices

targeting world-class performance

• Strengthen corporate culture with focus on

transparency, inclusivity and individual responsibility

Production, boepd Capital Expenditures, $ million

0.0 5.0 10.0 15.0 20.0 2014 2015 2016

k boepd 5

10 20 30 40 50 2014 2015 2016

$ million

Capital Investment Projects

Ukraine re-investment drives future growth

* Indicative full-cycle project capital expenditures (CAPEX) subject to Final Investment Decision (FID) and/or Board authorization.

Project Country Scope Indicative CAPEX* $mn Year 1 Production mboepd EUR mmboe Well enhancements Ukraine Enhancement projects on existing wells and rig-less interventions (ESPs, velocity strings & perforations) 2.4 1.7 1.4 Fracking of existing wells Rudenkivske field Ukraine Fracking of up to 11 existing wells 17.7 4.4 4.1 Ignativske waterflood Ukraine Oil-focused enhanced recovery project 7.5 1.5 0.6 Well 5 workover Russia Workover of existing non-producing wells 3.0 6.4 1.8 Sidetrack Hungary Sidetrack of existing wells 1.8 0.1 0.3 Rudenkivske full field development (Phase 1) Ukraine 2 pads with 12 wells each 153.7 16.4 9.2 Callovian well Russia New well to de-risk predicted porous Callovian reservoirs 15.0 7.2 4.0 Other Various Other projects and base / maintenance CAPEX for 2017-2018 13.1 TOTAL 214.1 37.7 21.5

Project priority / phasing

6

24.3 32.5 39.0 7.7 14.9 9.9 22.5 14.0 0.9 4.9 34.2 55.0 53.0 8.6 19.8 10 20 30 40 50 60

Gas Condensate Oil Gas Condensate

$/boe

Capital Allocation Prioritized for Returns

Across the project portfolio of the Group and potential targets

Indicative product sales prices, $/boe Prioritizing capital projects – scale vs. returns

Ukraine Russia Gas $4.6/mcf ($27.5/boe) Oil $50/boe European oil and gas benchmark prices Ukraine - enhancements Ukraine - Rud fracs Ukraine - Rud drilling (24 wells) Ukraine - Ignativske Russia well 5 Russia - Callovian well 2 4 6 8 10 12 14 16 18 5 10 15 20 25 EUR, mmboe Project net revenue/CAPEX, $/$

Initial stages of Rudenkivske development in Ukraine have the highest impact for JKX

• JKX has a variety of projects in Ukraine and Russia
• Rudenkivske project provides good balance of scale and returns with additional upside with

decreased royalty rates

7

Ticker JKX LN Share price (01/25/2017), GBp 25.5 Shares outstanding 171,723,145 Market cap, GBPmn 43.8 GBPUSD (03/17/2017) 1.24 Market cap, USDmn 54.3 Net debt, USDmn 2.5 EV, USDmn 56.8

Financial results: Reversing the Trend

JKX Oil & Gas plc share information

JKX Oil & Gas plc trades with a premium Listing on London Stock Exchange

8

5.74 4.20 2.95

30%

$2.95

2014 2015 2016 2014 2015 2016

8.70 7.45 5.38

$5.38

28%

(22.4)%

(23,0) (35,8) (22,4) 2014 2015 2016

Key Financials

($m) 2015 2016 Change % Group revenue 88.5 73.8 (16.6) Loss from operations before exceptional items (10.7) (3.9) 63.6 Exceptional items (64.9) (30.8) 52.5 Loss from operations after exceptional items (75.6) (34.8) 54.0 Cash from operations 12.8 17.0 32.8 Capital expenditure 8.7 5.6 (35.6) Realised gas price ($ per Mcf) 4.20 2.95 (29.8) Realised oil price ($ per bbl) 49.75 45.94 (7.7)

5 10 15 20 25 20 40 60 80 100

Volume Price, GBp

Volume Price

2016: Building a Sound Platform for Growth

Positive operating cash flow despite environment

• Operating cash flow in 2016 was $30.0mn vs. $18.0mn in 2015 due to lower costs
• Legal, professional, and restructuring costs increased from $5.2mn in 2015 to $13.0mn in 2016 due to international

arbitration costs ($3.9mn), settling of previously incurred claims against major shareholders ($3.2mn), severance and redundancy costs ($3.2mn), professional advisory fees related to Board replacement ($0.5mn), and other legal fees

• Other costs include convertible bond repayments and repurchases which increased significantly in 2016
• Upon successful completion of the bond restructuring $16.0 million of bonds are outstanding which will be repaid in

roughly equal installments in 2018-2020 YE 2014 – YE 2016 cash position, $ million

9

25.4 25.9 14.1 18.0 6.2 5.2 6.0 30.0 7.5 13.0 21.5 0.0 10.0 20.0 30.0 40.0 50.0 60.0 31 December 2014 Cash from

• perations

CAPEX Legal, professional, restructuring Financing /

• ther

31 December 2015 Cash from

• perations

CAPEX Legal, professional, restructuring Financing /

• ther

31 December 2016

New Board and Executive Management

Enhancing governance and driving an operational re-set

Name Position Experience Paul Ostling Non-executive Chairman Independent Tom Reed CEO, Executive Director Russell Hoare CFO, Executive Director Alan Bigman Non-executive Director Independent Bernie Sucher Non-executive Director Independent Vladimir Tatarchuk Non-executive Director Vladimir Rusinov Non-executive Director

RAVEN RUSSIA

10

Science Driven Organizational Structure

Darcy’s Law incorporated into the E&P philosophy

𝑟 = 𝑙ℎ 𝐻𝜈𝐶 𝐾𝐸 ∆𝑞

Field Development Well Construction Production Operations

geological & petro-physical properties inherent in the rock – permeability, oil viscosity, thickness of the oil bearing zone

𝑙ℎ 𝐻𝜈𝐶 ∆𝑞 𝐾𝐸

Completion – mathematically the radius of the well bore in relation to the oil bearing formation the pressure differential between the reservoir & the well bore at the perforations

Name Position Background Andrew Spencer Head of Field Development Planning Ritchie Wayland Exploration Manager Robert Glaser Geologist Amar Dosanjh Geologist Nick De’Ath Geologist Name Position Background Roman Galchenko Completions Engineer Micah Spencer Petroleum Engineer Calvin Yao Reservoir Engineer Iskander Diyashev Reservoir Engineer Name Position Background Mike Stolte Operations Director Thomas Rut Operations Director Paul Wood Group Operations Manager

11

Why Ukraine?

Integrated developed European gas market with premium pricing

• 4th largest European producer after Norway,

Netherlands and the UK

• Premium pricing to Europe & US
• Developed pipeline and natural gas infrastructure
• Import dependent EU and Ukraine supports pricing

and fiscal policies

• Ukraine imports 35% of its demand
• Ukraine Government strategic target for energy

independence by 2021

Source: IHS, BP, Naftogaz of Ukraine, Bloomberg

Import dependent Europe’s 4th largest gas producer Europe’s premium pricing underpins supply & imports Developed infrastructure supports market access Ukraine’s Attractive Natural Gas Market

0.00 2.00 4.00 6.00 8.00 10.00 12.00 14.00 2009 2010 2011 2012 2013 2014 2015 2016 Price, $/Mcf Henry Hub NBP Ukraine

0.0 10.0 20.0 30.0 40.0 50.0 60.0 BCF/D Other UnitedKingdom Netherlands Norway Ukraine Total ConsumptionEurope

DEMAND IMPORTS EURO PRODUCTION

12

Ukraine’s Natural Gas Resources Support Growth

4Th Largest European supplier with significant scope for growth

13

Ukraine targets energy independence with 27bcm by 2020... Ukraine production stable but down 70% since Soviet peak Long reserve life of ~3x EU highlights resources… Development scope supports doubling of production

5 10 15 20 25 30 35 40 45 50 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

R/P Ratio, years

Ukraine Norway EU (WgtAvg)

R/P ratios Ukraine 35 yrs Norway 16 yrs EU 10 yrs

Source: BPStatistical Review

• f

World Energy 2016.

500 1,000 1,500 2,000 2,500 3,000 1940 1950 1960 1970 1976 1980 1985 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015

Bcf

706 1,348 33,697 150,000+ 350,000+

1 10 100 1,000 10,000 100,000 1,000,000

Production 2016 Production R/P 25 years Reserves Conventional resources Unconventional resources

Bcf

0.0 0.5 1.0 1.5 2.0 2.5 3.0 2016 2017 2018 2019 2020 Production,Bcm Base Brownfields Greenfields

• Dramatic gas sector reforms in 2015-2016

– Gas price unified for all consumers (residential prices increased 5-6 times to market rates) – Legislation passed mandating implementation of sector unbundling and restructuring based on EU’s Third Energy Package which separates generation and transmission assets

• Energy independence by 2020

– Ukraine still imports 35% of gas consumed – New gas production plan calls for 40% increase in production from current levels to meet expected demand

• Lower royalties critical to achieving this goal

– Initiative to introduce 12% production tax for new wells widely supported, but failed to pass in 2016

Ukraine’s Gas Sector Reforms

Government objective for energy independence by 2020

0.0 0.5 1.0 1.5 2.0 2.5 3.0 2016 2017 2018 2019 2020 Base Brownfields Greenfields

Ukraine’s Official Gas Production Target (Bcf/d)

14

45% 29% 18% 16% 15% 13% 12% 10% 10% 8% 5% 4% 4% 1% 0% 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% Ukraine Condensate Ukraine Gas US Romania Albania Turkey Hungary Croatia Lithuania Bulgaria Slovakia Ireland Netherlands Poland Greece

• Ukraine needs an attractive, simple and

stable tax regime to make outside investors take serious notice

• Ukraine’s current tax rates are not

competitive internationally

• Greenfield projects are currently not

feasible b/c full-cycle costs exceed netbacks to producers

• A single 12% royalty rate calculated on the

basis of a transparent European hub price will make Ukraine an immediate destination for external investment

Pace of Growth Driven by Gas Taxation

Key piece of the puzzle for energy independence by 2020

Royalty rates in Ukraine are significantly higher than peers

Proposal: 12%

Sources: Deloitte, Ministry of Finance of Ukraine, Company analysis Reducing royalty rates will allow for faster development 15

• JKX’s Ukraine licenses located on the southern edge of the

prolific Dnieper-Donetsk Basin (DDB)

• DDB has already produced over 70 Tcf of gas and retains

significant potential across Carboniferous and Devonian reservoirs (3000-5000 m depth) − 35 Tcf recoverable conventional reserves − 120 Tcf recoverable conventional resources − 100-400 Tcf unconventional potential

• Production of 7 bcf/d in 1960s before Soviet focus shifted to

West Siberia more than double current production

• Largest fields (e.g. Shebelinka) in terminal decline, but hundreds
• f smaller fields and geological prospects remain

− 90% of Ukraine’s current gas production comes from DDB − Gas 85% of total resources; oil (10%) concentrated in the north west part of the basin − Hydrocarbons tend to be high quality (low percentage of inert gases, no H2S)

Ukraine’s Dnieper-Donets Basin

A world class petroleum province

16

JKX Ukraine Reserves & Resources

Source: Company data, DeGolyer & MacNaughton Elyzavetivske and West Mashivske Licenses ‘NovoNik’ Complex of Licenses

Production and Reserves in Ukraine 2016 Production Reserves and resources, mmboe boepd 1P 2P 3C Rudenkivske 120 9.5 22.2 381.8 Ignativske 1,364 2.8 3.9 50.1 Elyzavetivske 1,448 1.3 1.7 20.8 Movchanivske 651 0.5 0.6 2.8 Novomykolaivske 396 0.6 0.7 0.1 Zaplavska 1.4 Total 3,979 14.6 29.1 457.0

• Growth focused on

Rudenkivske license

• Protect the base

production with EGR, EOR, workovers and enhancements

• Monitor the market

and seek

• pportunities for

further growth

17

UKRAINE

Rudenkivske Field Potential

Large in place gas volumes in thick clastic reservoirs

18

Rudenkivske target horizons Rudenkivske project summary

UKRAINE

Mid-term Full Field Activity Wells # 24 110 Workovers # 9

• CAPEX

$mn 154 500 EUR mmboe 20.9 60 Year 1 production mboepd 13.4 nm

• Largest hydrocarbon potential with 2.8 tcf in

place, up to 600 bcf recoverable volumes and incremental production of up to 24k boepd

• Development began in Soviet period (1970)

with 32 wells drilled with up to 70mmscf/d IP rates, albeit with very low recovery rates due to limits of technology

• Full Field Development includes manufacture-

style drilling and multistage fracture of vertical / deviated wells with scope for 25-50% recovery rates

• Isolated sand ‘lenses’ to be connected

horizontally and vertically by large fracks

• Activity plan includes 135 wells with

anticipated capex of ~$660mn

Rudenkivske Analogues

Transferring success to Ukraine

• Williams Fork formation in Piceance Basin in Colorado

close analog for the Rudenkivske field

• The field was discovered in the 1970s but abandoned

due to economics until 1990s as application of multi- stage fracturing reduced costs

• Learning curve and advances in technology allowed

for 2x increases in recovery

• Cost reduction through adoption of manufacturing-

style approach to drilling and completion essential for economic development of the field

19

Parameter Rudenkivske, Dnieper Donets basin Williams-Fork, Piceance basin Utica, Appalachian basin Deep Bossier, East Texas Basin Lance Pool, Pinedale/Jonah Field, Green River Basin Gas saturation 55-80% 35-55% 40-65% 50-95% 65-75% Clay Content 10-20% 5-21% 20-40% 10-22% 10-15% Total Porosity 6-17% 6-8.5% 3-10% 5-14% 6-12% Permeability >0.1mD <0.1mD 0.0001mD <0.5mD <0.1mD Pressure (psi) 5600-8900 3000-7000 3100-8600 >10,000 3000-7800 Gross Thickness (metres) 300-800m 600-1000m 50-300m 300-760m 700-1000m+ Depth (metres) 3000-4500m 2000-3500m 600-4000m >5000m 2600-4400m Average IP rates 10 – 12MMscf/d 1 – 2MMscf/d 5 – 47MMscf/d 2 – 15MMscf/d 6 – 7.5MMscf/d Average EUR (per well) 4 – 5Bcf 1 – 2Bcf 2.5 – 5Bcf 5 – 7Bcf 4 – 9Bcf

UKRAINE

Sources: Companies’ public data

• Full field development will start around well R104 (Mid-term) and

later graduate towards other areas (Full-field). R104 mid-case and type well mid-case production profiles and associated well economics are provided below

• Mid-term development wells are assumed to have higher CAPEX

($5.7mn) which will be reduced to $4.5mn for full-field development wells with efficiency improvements

• Gas price of $5.7 / mmcf ($200 / mcm), 29% gas royalty rate, and

$2.5 / boe OPEX cost were used for economic evaluation

Rudenkivske Economics

Compelling returns with investment scale

20

Indicative monthly R 104 area well (Mid- term) and type well production profiles (log scale), boepd and cumulative, mboe Indicative pre-tax economics for mid-term and type well profiles

UKRAINE

Mid-term Full-field Production unlocked, EUR15, mboe 687 716 30-day IP, boepd 2,496 551 1-year decline, %

• 85%
• 49%

Well cost, $mn 5.7 4.5 NPV10, $mn 6.1 5.2 IRR 234% 51% P/I 2.0 2.1 Simple payback, months 6 23 Discounted payback, months 7 26 Unit development cost, $ / boe of EUR 8.3 6.3 CAPEX per flowing barrel, $k / boepd 29.0 26.1

Rudenkivske Lessons Learned

Comparison between R103 and Future Development

21

• Guar cross-linked will be replaced by HCFR as it is a cleaner fluid and leaves less damaging residue in

the reservoir.

• Large variation in frac parameters witnessed in R103 which can in part be attributed to lack of Dipole

Sonic data which will be recorded in all new wells.

• R103 only targeted the Devonian so could be horizontal. 19R twin will be vertical to enable the

simultaneous fracturing of 3 intervals – Devonian, Tournaisian and V26.

• Vertical wells are likely to be replaced by horizontal wells once the recovery by zone is better understood.
• Fracturing costs significantly less now than when R103 was fractured which dramatically improves the

economics and allows for time to progress along the learning curve prior to the increase in costs.

• New wells to be drilled with Top Drive as opposed to rotary drilling which historically was used. Potential

to dramatically reduce drilling time.

UKRAINE

R103 R19 Twin Well type Horizontal Vertical # of reservoirs 1 3 # of fracs 10 8 Fluid type Guar cross-linked Polyacrylamide HCFR Proppant type 20/40 High Strength 30/50 Lightweight frac length, m 100-300 100 frac width, mm 10 20 Initial production, MMscf/d 2.9 11.1 Total recovery, Bcf 1.1 5.4

22

Rudenkivske FDP

Field Development Plan Summary

Preparation (2016-2017 Initial development (2017-2018) Full-field development (2018+)

• Select wells from existing

well stock for interventions and fracturing

• Execute well

enhancements (perforations) to gain experience working over

• ld wells, test hypotheses

and gather data

• Approvals, commercial

agreements and of the preparations for fracturing legacy wells

• Secure rig and frack fleet
• Continue well workovers and

enhancements

• Design & Test fracture and

completions technology

• Fracture preselected legacy

wells

• Execute contracts for

manufacturing-style, pad- based development

• Drill initial wells and

implement data acquisition program

• Delineation and development

drilling (135 wells w. multiple fracks) using manufacturing- style approach

• Reservoir management
• G&G studies

UKRAINE

Rudenkivske FDP – Mid-term

Existing well stimulation and pad drilling

23

Appraisal well selection Existing well review, workover and stimulation

• 30 shut-in and abandoned wells have been reviewed to identify candidates for workover and stimulation

− Up to 9 wells to be worked over and/or fractured (50+ stages total) were identified − Total mid-term production potential: 10-15 bcf − ~700 mm well perforations of existing wells provide insight into what may be achieved with up to 100m frac - well NN16 tested at 14 MMcf/d rate (watered out in December) and NN47 tested at 16.9 MMcf/d rate (declined to 11.5 MMcf/d in January 2017).

• This will allow to improve understanding of the field and generate cash flow to support full field

development

• Building on data generated from workovers and stimulation, pad-based development to be launched

with two 12-well pads around wells R104 and R19 (locations are being confirmed)

UKRAINE

• FFD focuses on drilling and multistage fracture of

vertical / deviated wells

• Economies of scale to be achieved via

manufacturing-style drilling and fracking process

• Isolated sand ‘lenses’ to be connected horizontally

and vertically by large fracks

• FFD (including mid-term development):

− Recoverable reserves: up to 500-600 bcf − Total number of wells: 135 − Total CAPEX ~$650 million

Schematic drilling locations at Rudenkivske field

Rudenkivske FDP – Full Field

“North-American style” manufacturing approach

24

UKRAINE

Rudenkivske Sensitivities

Type well indicative economics sensitivities

25

Effect of 30% change in key value drivers on 5-year single well NPV10, $mn

• Chart below shows effect of 30% change of key value drivers on total single-well NPV10 ($5.2 million in the base case based on

full-field type curve)

• Change in gas price, IP rate, royalty rate, and well cost have the greatest impact

5.2

UKRAINE

• 3.2
• 2.9

+2.6 +1.3 +.3 +3.2 +2.9

• 1.3
• .3
• 4.0
• 3.0
• 2.0
• 1.0

+1.0 +2.0 +3.0 +4.0

Gas price - $4.0/$7.4 / mmcf Rud IP rate - 3.0/5.5 mmcf/d 12% royalty Rud well cost - $3.2m/$5.9m Opex - $1.8/$3.3 / boe

Decrease Increase

Ignativske Waterflood Enhancements

Waterflood potential for enhanced oil recovery

26

• Isolated southern carbonate oil block identified

as a target for enhanced oil recovery via

• waterflood. The pilot area has 3 wells (IG-124,

IG-126 and IG-138) drilled to date

• Target injection rate is 10,000 bbl/d using two

injection wells (~10x increase from current rate)

• An additional 0.5 – 1.8 mmboe of incremental oil

can be recovered from this isolated block as a result of successful waterflood campaign

• Additional oil recovery could potentially be

added once analysis on Devonian clastic reservoir’s waterflood potential is completed

Top of structure map of Lower Carboniferous carbonate reservoir in Ignativske field showing isolated waterflood pilot area Ignativske project summary

UKRAINE

Mid-term Full Field Activity Wells # 2 EOR CAPEX $mn 9 EUR mmboe 1.5 Year 1 production mboepd 0.6

Elyzavetivske Infill Projects

Accelerating natural gas production from base assets

27

• Production acceleration from producing A-2

reservoir − The A2 interval is a Lower Permian carbonate-evaporite deposit. This interval has both high porosity and high permeability, and is the primary productive facies of the A2 reservoir − The FDP’s objective is to drill and complete two infill wells (E-308 then E- 305) to accelerate gas production and increase ultimate gas recovery within Elyzavetivske

• Appraisal of West Mashivske area of the

license − West Mashivske area to the West of main producing area has production potential in the A carbonates and lower G sands totaling up to 50 bcf − A redevelopment of a previously drilled and producing well to begin appraisal phase − Up to 5 wells for FFD

Elyzavetivske project summary

UKRAINE

Mid-term Full Field Activity Wells # up to 5 CAPEX $mn 20.0 EUR mmboe 2.5 Year 1 production mboepd nm

Koshekhablskoye Workovers Support Cash Flow

Existing production and well workover potential

• A producing gas field with significant proved reserves

located in Southern Russia (Republic of Adygeya -- East Kuban Depression)

• Production from Upper Jurassic (Oxfordian) biohermal

carbonates (4,800-5,000 m). Approximately 130 bcf of gas has been produced from the Oxfordian reservoirs since

• nset in 1982 (including about 88 bcf produced before JKX

acquired the field)

• Since JKX acquired the field in 2007, a brand new

production facility with capacity of up to 60 mmscf/d was installed

• Historically JKX developed Oxfordian gas reserves.

Several well workovers are planned to increase production from this reservoir in 2017-2018, including workover of currently non-producing well-5

28

Well-5 workover project summary

RUSSIA

Mid-term Full Field Activity Wells # Workovers # 1 CAPEX $mn 3.0 EUR mmboe 6.4 Year 1 production mboepd 1.8 Top Oxfordian B Depth Structure Map Oxfordian Gas Producers

Proposed Callovian well location

Callovian Growth Opportunity

Unlocking significant natural gas resources

• Callovian reservoirs, not tapped yet by

existing wells, provide significant growth opportunity

• Total 2C original gas in place (OGIP)

from all five Callovian reservoirs estimated to be approximately 630 bcf. It is estimated that a 2P gas recovery

• f 34 to 43 bcf of gas can be obtained

from a single well in the Callovian reservoirs, over 15 years

• The recommended vertical well

location intersects predicted porous reservoir within the Lower Callovian (V), Upper Callovian (I-IV), and Oxfordian reservoirs. Good well control and seismic data provided high confidence that at least one gas target will be productive

29

Callovian project summary

RUSSIA

Mid-term Full Field Activity Wells # 1 10 Workovers #

• CAPEX

$mn 15 100-125 EUR mmboe 7.2 60 Year 1 production mboepd 4.0 nm

Hajdúnánás IV MP 0.5-1.5 Bcf gas 1-2 MMboe oil Hajdúnánás V MP 5-7 Bcf prospect Tiszavasvári IV MP 20 Bcf appraisal 100-200 Bcf upside Emőd V MP (Mezo) 1-1.5 MMboe appraisal 5-10 MMboe expl upside Pély I MP 5-10 Bcf prospect Jászkisér II MP 4-7 Bcf prospect

• Six mining licenses (100% net) and processing facilities with 18 mmcf/d of capacity
• Production from Hn-2 well restarted after successful sidetrack at an initial rate of 1.8

MMcf/d after a production and sales break of more than three years

• Development planning is underway and future work may include a workover of the

existing Hn-1 well to add production from the Lower Pannonian reservoir interval

30

Hungary: Sidetrack Result Highlights Opportunity

Recent Hn-2 well returns Hajdunanas field to production HUNGARY

• Tisza IV: Tight gas appraisal project with very large

upside potential − Tiv- 6 Discovery: 300 meter gas column − 2% Royalty (unconventional terms)

• Mezo (Emőd V): Shallow (1200-1400m) oil field

redevelopment with significant exploration upside − Apply 3D seismic and EOR to old oil field (10 MMboe in place, 1 MMboe produced, 1-1.5 mmboe remaining recoverable potential) − 5-10 MMboe of additional recoverable oil from 2 leads on the 100km^2 license − No royalty for EOR projects

• Haj IV: Shut-in gas field redevelopment with deeper oil

appraisal − Remaining shallow (1000m) gas in the formerly producing Hajdúnánás field (0.5-1 Bcf) − Miocene oil potential (1.5-3 MMboe) in satellite exploration projects

• Haj V: Additional gas exploration prospect near gas

plant − Will require Tisza IV production facility

31

JKX Projects in Hungary

Highlights

LICENCE Phase 1 Phase 2 Full-field Tiszavasvári IV Farm-out 1 well 10-20 wells Emőd V 3D Farm-out 2 wells 5-6 wells Hajdúnánás IV 1 well 1 well 3-4 wells Hajdúnánás V 1-2 wells CAPEX $mn 2.5 – 3.0 8.0 - 10.0 40.0 - 80.0

HUNGARY

Hungary projects summary

4th Bid Round – Concessions

• Government Bid round 4

International Activity in Hungary

• Six international and two domestic companies control

>95% of exploration & production acreage.

• Full spectrum – exploration to field redevelopment (MOL)

JKX Strategy

• Near term appraisal and development
• Field redevelopment

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Hungary Bid Round Activity

Concession rounds to field redevelopment HUNGARY

• JKX owns 25% non operating working interest
• DiscoveryGeo (Operator) using Magneto Telluric

survey data to calibrate expensive but low resolution 2D seismic data

• The prospective resource sizes (up to 20 MMboe

OOIP and 30 Bcf IGIP) are material

• Smilno -1 well

– Site under construction, Conductor driven, well spud expected Dec 2016 – 12 bcfe recoverable resource (mid case)

• Other wells Poruba -1 and Kriva Ol’ka -1 have

estimated EUR of 1.5 MMboe net to JKX

• Delays in permitting and activist environmental

protestors are delaying site construction

Slovakian Operations

Prospective resource enhancement through technology

33

SLOVAKIA

Appendix

Reserves & Resources (PRMS Basis)

DeGolyer & MacNaughton reports

35

Reserves & Resources Range of Commerciality Range of Uncertainty PRMS Category Reserves (Net) Contingent Resources (Net) Prospective Resources PRMS Classification 1P 2P 3P 1C 2C 3C Low Best High Proved P Probable P+P Possible P+P+P

Oil & Cond Natural Gas Total Total Oil & Cond Natural Gas Total Total Oil & Cond Natural Gas Total Total Total Total Total 1000 bbl MMcf KBoe KBoe 1000 bbl MMcf KBoe KBoe 1000 bbl MMcf KBoe KBoe KBoe KBoe KBoe

Ignativske 1 082 10 133 2 771 2 771 680 2 789 1 145 3 916 1 361 2 176 1 724 5 639 11 975 17 533 50 097 Movchanivske (Main/North/Wedge) 264 1 266 475 475 65 242 105 580 75 252 117 697

• 1 254

2 760 Novomykolaivske 242 2 176 605 605 60 422 130 735 26 291 75 810

• 147

Rudenkivske 311 54 989 9 476 9 476 378 73 784 12 675 22 151 718 94 780 16 515 38 666 9 334 101 432 381 766 Zaplavska

• 33

376 1 406 Elyzavetivske 23 7 428 1 261 1 261 6 2 408 407 1 668 27 10 869 1 839 3 507

• 6 204

20 828 UKRAINE 1 922 75 992 14 587 14 587 1 189 79 645 14 463 29 051 2 207 108 368 20 268 49 319 21 342 126 798 457 003

• Koshekhablskoye

413 255 007 42 914 42 914 354 221 941 37 344 80 258 383 236 307 39 768 120 026 24 120 74 772 107 528

• RUSSIA

413 255 007 42 914 42 914 354 221 941 37 344 80 258 383 236 307 39 768 120 026 24 120 74 772 107 528

• Hadjunanas (100% WI)
• 13

867 158 158

• Tiszavasvari 6 (100% WI)
• 235

276 677 HUNGARY

• 13

867 158 158 235 276 677 TOTAL 2 335 330 999 57 502 57 502 1 543 301 586 51 807 109 309 2 603 345 542 60 193 169 502 45 697 201 846 565 208 Source: as per DeGolyer & MacNaughton Report December 31, 2016 Total Petroleum Initially-In-Place (PIIP) Discovered PIIP Undiscovered PIIP Commercial Sub-Commercial

Technical, Engineering and Operations Team

Global geo-market technical experience applied locally

Name Position Experience Background

Andrew Spencer Head of Field Development Planning

Over 12 years of experience in well test analysis, production forecasting, classical reservoir engineering and simulation, nodal analysis, artificial lift design, stimulation, production optimization, workover/well planning, field development planning and reserves evaluation.

Roman Galchenko Completions Engineer

Completions engineer with 15 years experience in Russia and in the U.S. with Marathon and BP focused on unconventional developments involving multi-stage fracturing with conventional, slick-water, hybrids and utilizing sliding-sleeve and plug-and-perf systems.

Mike Stolte Operations Director

34 years management and execution experience. Diversified management knowledge in drilling, subsurface, completions, production and reservoir engineering. Extensive on-site field supervision in completions, workovers and operations across 1000s of wells in the U.S. and internationally. Broad unconventional development and logistics expertise.

Thomas Rut Operations Director

Over 25 years of upstream E&P experience in the U.S. and internationally in major IOC’s and NOC’s in both

• nshore and offshore environments. Technical expertise in development planning, production optimization, well

interventions and reservoir management.

Paul Wood Group Operations Manager

Following engineering roles with Schlumberger in Europe and Russia, joined JKX Oil & Gas in 1995 initially as PPC Ukraine Engineering Manager and since 1997 responsible for PPC operations, process and facilities engineering.

Ritchie Wayland Exploration Manager

Over 35 years of geoscience expertise in West Africa Deepwater, onshore Nigeria, UKCS Gas Basin, Australia and UK North Sea. Exploration and field development projects in Central and Eastern Europe and Russia.

Micah Spencer Petroleum Engineer

Petroleum engineer with 7 years experience in design, production and completions engineering experience from unconventional and conventional reservoirs in Texas, Louisiana, North Dakota, Gulf of Mexico shelf and internationally in China, Angola and Kazakhstan.

Calvin Yao Reservoir Engineer

Reservoir Engineer with about 25 years of experience in integrated reservoir modelling and simulation, reservoir performance analysis and prediction, waterflooding and CO2 EOR, field development planning. Calvin has extensive hands-on experience with conventional, unconventional, deepwater reservoirs.

Robert Glaser Geologist

Over 10 years of experience in evaluation and drilling carbonate reservoirs in the Permian Basin and offshore Brazil, clastic fields in the deepwater Gulf of Mexico, Midcontinent, and onshore Gulf Coast, in addition to unconventional (shale and chert) plays in the Permian, San Joaquin, and Appalachian basins.

Amar Dosanjh Geologist

Technical geoscientist experienced in petroleum systems modeling, geological modelling, seismic and well log interpretation and regional geological synthesis. Regional basin expertise in the British Isles and Wyoming and unconventional project work undertaken in the Canning basin, Australia.

Nick De’Ath Geologist

Over 40 years management experience in exploration and development including at BP as Chief Geologist in the North Sea and General Manager of Colombia. As VP at Triton Energy, developed the multi Tcf gas reserves in the Malaysia Thailand JDA. Regional expertise as Yukos Chief Reservoir Geologist and subsurface lead for TNK-BP in Moscow.

Iskander Diyashev Reservoir Engineer

Over 25 years of reservoir engineering experience including reserves evaluation, engineering and management, FDPs, integration of engineering and geological data and application of geostatistics, engineering design and production forecasts of horizontal and stimulated wells.

36

Highlights:

• 1994: Poltava Petroleum Company, first
• il and gas company with private
• wnership established in Ukraine
• 1995: successful IPO on the London

Stock Exchange

• 2005: Entry into Eastern Europe
• 2007: Entry into Russia
• 2012: Production in Russia launched
• 2015: Six new production licences in

Hungary

• 2016: New Board and Senior

Management team with mandate to return company to growth and restore shareholder value

• 2016: restart of development with

completion of the new Field Development Plan

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0

1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015

JKX history

Over 20 years of independent E&P experience in Central/Eastern Europe

JKX production history, 1995-1H2016

37

Eclairs Group Ltd 27.5% Proxima Capital Group 19.9% Neptune Invest & Finance Corp 13.0% Keyhall Holding 11.4% Others 28.2%

Shareholder Structure

Shareholder Share, % Brief information Shareholding since Eclairs Group Ltd 27.5% The beneficial owners of Eclairs are Ukrainian businessmen Igor Kolomoiskiy and Gennady Bogolyubov which have a wide range

• f business interests including the

Privatbank Group (one of Ukraine’s largest banking groups), ferrous and non-ferrous metals, media, aviation, petrochemicals etc. 2007 Proxima Capital Group 19.9% Proxima Capital Group is an independent investment firm focusing

• n investments in Russia, Ukraine

and the CIS. Proxima Capital Group

• ffers M&A advice, fund raising and

debt restructuring and also invests in assets and asset portfolios with a focus on Russia, Ukraine and CIS countries that are at an early stage of development and which will benefit from effective management and proven sector experience 2015 Neptune Invest & Finance Corp 13.0% Neptune, a Moscow-based investment fund, is beneficially-owned by Turkish businessman Burak Özdoğan 2015 Keyhall Holding 11.4% The sole beneficial owner of Keyhall is Mr Oleksandr Ratskevych who is a partner of Alexander Zhukov (who

• wned 11.4% of shares through

Glengary Overseas ltd since 2004) 2016 38