Buy. Independent Oil and Gas # Initiating coverage. 18p

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1 Daniel Slater May 2017 Independent Oil and Gas # Initiating coverage Oil & Gas Producers (AIM) IOG.L Buy 18p IOG is a UK E&P company focused on the southern North Sea. It has established a 389bcf portfolio of development-ready assets, and recently agreed to acquire the nearby Thames pipeline, which connects to the Bacton terminal. The development could be onstream in Q2 2019, though significant funding will be required. There is a risk/reward balance in the asset position versus the funding, and overall we initiate coverage with a speculative Buy recommendation. Development-ready assets. IOG holds five development-ready gas fields in the UK southern North Sea, with combined 2P/2C resources of 389bcf. The company is advancing plans to bring these onstream over the next two years, with first gas planned for Q Hub strategy in action. IOG is pursuing a hub strategy, aimed at tying smaller fields together to make up economic developments. Its Blythe/Elgood and Vulcan Satellites clusters follow this principle, with shared infrastructure and a shallow water location helping to keep costs down and boost returns. Pipeline ownership gives control. IOG recently agreed to acquire the Thames gas pipeline, which it can use to transport gas from its developments to shore. This, and 100% ownership of its assets, gives IOG control of its developments and offtake route going forward. Experienced management and technical team. IOG has, and continues to augment, a team with strong North Sea and acquisition experience. Upside from other assets, acquisitions. The Harvey asset provides follow-on development potential close to IOG s other projects. IOG is also targeting new acquisitions, including production. Supportive operating environment. UK regulator the OGA has been supportive of IOG, and the history of the North Sea means there is significant expertise and services capacity for the company to draw on. Funding required. IOG will need significant funding ( 296m) to progress development. Existing debt from partner LOG is, we believe, also likely to be highly dilutive ( 10m facility plus interest converts at 8p/share). Key Data Market Capitalisation 20.0m Shares in Issue 109m Free Float 72% Average Daily Volume 1.0m 12-Months Trading Range 11.9p 34.8p Financial Forecasts Yr to 31 December 2016A 2017E 2018E Sales 0.0m 0.0m 0.0m Operating Profit ( 1.0m) ( 2.7m) ( 2.8m) Adjusted PBT ( 1.9m) ( 3.6m) ( 4.9m) Adjusted EPS (2.0p) (3.3p) (4.5p) EPS Growth nm nm nm P/E nm nm nm EV/EBITDA nm nm nm Dividend Yield Dividend Cover Net Cash/(Debt) ( 14.3m) ( 20.5m) (24.1m) Interest Cover nm nm nm Price Performance 1 Month -2.7% 3 Months +5.9% 12 Months +37.1% Price Performance (p) May 14 Nov 14 May 15 Nov 15 May 16 Nov 16 May 17 Source: Bloomberg. Valuation and recommendation. At 40p/therm and fully diluted, our IOG NAV is 62.2p/share risked, 138.6p/share unrisked. IOG has a strong asset portfolio, but the financing position creates risk. We initiate with a speculative Buy recommendation. * Arden Partners acts as corporate broker to this company. # This company is a research client of Arden Partners. This research material is a marketing communication and has not been prepared in accordance with legal requirements designed to promote the independence of research and is not subject to any legal prohibition on dealing ahead of dissemination. A r d e n P a r t n e r s p l c i s a u t h o r i s e d a n d r e g u l a t e d b y t h e F i n a n c i a l C o n d u c t A u t h o r i t y a n d i s a m e m b e r o f t h e L o n d o n S t o c k E x c h a n g e. w w w. a r d e n - p a r t n e r s.co.uk

2 Contents Investment case 3 Investment risks 5 Upcoming activity 7 Company history 7 Current shareholders 9 Company strategy 9 Asset position 11 Blythe and Elgood Hub 1 11 Vulcan Satellites Hub 2 13 Regional pipeline acquisition agreed 15 Potential third Southern North Sea development Harvey 16 Skipper oil discovery 17 Next steps development plans 18 Funding and capital structure 18 Current funding position 18 Cash burn rate 20 Potential dilutive shares 20 Upcoming cash requirements acquisitions and CAPEX 20 What is LOG? 21 North Sea M&A environment 22 UK gas prices 25 Board, management and technical team 27 Valuation and financial forecasts 30 Valuation 30 Financial forecasts 36 2 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

3 Investment case Development ready asset position and material gas resources IOG has assembled a material portfolio of southern North Sea gas assets across the Blythe, Elgood and Vulcan Satellites fields. These contain gross 2P/2C of 389bcf, and IOG holds all of the assets 100%. The fields are development ready, and planning is well advanced a draft development plan for Blythe was submitted in Q IOG is currently targeting first gas from the fields in Q2 2019, ramping up to a total peak rate in excess of 150mmcf/d. At a 40p/therm gas price, this could generate peak annualised revenues of 219m for IOG. This would represent huge growth for a company that currently has a market cap of 20m. The development ready nature of the assets and their shallow water location also help reduce the risk of achieving this. Hub strategy designed to extract value from smaller discoveries The North Sea contains numerous small oil and gas discoveries that struggle to be economic as standalone developments. They can often be commercialised by tying in to existing processing and transport infrastructure, but this can create problems if host platforms are large relative to the new fields, potentially meaning higher US$/boe costs and the risk of early shutdown. Negotiations with existing infrastructure owners can also be lengthy. IOG is aiming to solve this by developing several small fields itself, using its own newbuild platforms and export infrastructure. By sharing the cost of new facilities over a number of small fields, this can render these developments more economic. Ownership of facilities and transport infrastructure (in this case all the way to the UK coast) removes the risk of early shutdown by third party owners. This is exactly what IOG is moving into a position to achieve on its Blythe/Elgood and Vulcan Satellites hub developments. Pipeline ownership gives control of offtake to the UK coast IOG recently signed a sale and purchase agreement to acquire the Thames pipeline, which was decommissioned in 2015 for lack of available production to make use of it. This is located to the south of the company s Blythe/Elgood and Vulcan Satellites developments, and IOG plans to use it for production from both. The pipeline has capacity of 300mmcf/d, meaning it should be able to support peak production of 150mmcf/d from the existing planned developments, and still have capacity for the potential development of the 113bcf Harvey field, and any other assets IOG may be able to acquire nearby. Not only does the pipeline give IOG an offtake route, but it gives the company 100% control of that route. This should mean that it remains available for as long as IOG requires it, that IOG can dictate maintenance schedules to suit the company, and allow IOG to capture margin that would otherwise be paid to the pipeline owner (including potential for use by third parties). Shallow water location helps control costs IOG s Blythe/Elgood and Vulcan Satellites developments are all located in the UK southern North Sea. This is a shallow water region, with no field at greater water depth than 30m. This is expected to allow development using unmanned fixed platforms, helping reduce both upfront CAPEX and ongoing OPEX. We estimate total CAPEX for the Blythe/Elgood and Vulcan Satellites developments of 296m, or 4.6/boe. This compares favourably to CAPEX elsewhere in the North Sea, and helps increase NPV and reduce commerciality thresholds of the developments. First gas by mid 2019, fast ramp up thereafter IOG is planning to develop its assets on an aggressive timetable, targeting first gas from Vulcan South, Vulcan North West and Blythe in Q The other fields would then come on in the following months, such that they would all be producing by Q The company s 100% ownership of all its assets should help it keep to this timetable, driving significant cash flows for the company within two years. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 3

4 Experienced management team building capability to execute IOG is led by CEO Mark Routh, who founded CH4 Energy in 2002 and sold it to Venture Production in 2006 for 154m. Mark joined IOG in 2011 soon after it was founded by Head of Business Origination Peter Young, where the initial focus was assembling the company s portfolio. The team has now been grown substantially with the addition of further expertise (most recently Andrew Hockey as Deputy CEO, Hywel John as CFO and Graham Cox as SNS Project Manager) aimed at giving the company the ability to run its upcoming development projects. The team now has considerable and varied experience of North Sea developments, giving comfort that it has the capabilities that will be required going forward. Upside potential in addition to upcoming developments In addition to the fields expected to be developed in its upcoming projects, IOG holds 100% of the Harvey discovery. This is subject to appraisal, and holds P50 resources of 113bcf. Harvey lies close to Blythe, and could be developed and directly tied in to the Thames pipeline at a later date. If proved up, this would rank among the largest of IOG s Southern North Sea fields, and could provide a further phase of growth beyond the upcoming development projects. Potential for further acquisitions, including production IOG has recently shown itself adept at adding to its portfolio, acquiring the Vulcan Satellites fields in 2016, and recently signing an agreement to acquire the Thames pipeline. The company has a stated aim of continuing with acquisitions, including targeting producing assets. These could provide cash flow to the company (augmented by the 32.9m of tax losses held), taking some of the burden off the existing debt funding lines and helping to support the company going forward. It could also improve IOG s position in discussions to finance its upcoming developments. Supportive regulator in the UK s Oil and Gas Authority The UK recently undertook an overhaul of the way it administers and regulates the UK North Sea. On the back of the Wood Review published in 2014, responsibility for this passed to a new body: the Oil and Gas Authority (OGA). The central aim of this body is the maximisation of economic recovery of oil and gas in the UK North Sea (the MER UK strategy). This aim speaks directly to IOG s business, which is aimed at developing fields previously deemed too small to be developed economically, and finding a solution for this via hub developments and (where appropriate) the use of existing infrastructure. The OGA has already been helpful to IOG in extending the timelines for its various licences as the company pulls its development projects together, and we would hope this support would continue as the projects move forward. North Sea a politically stable environment with good access to services The North Sea has been a major oil and gas province for over 50 years, and continues to exhibit considerable activity. This has allowed not only a significant build-up of knowledge and expertise in the region (which IOG is already taking advantage of with its current team), but also means oil services companies have considerable capability there too. The UK is a politically stable country from the point of view of oil and gas (despite recent noise around Brexit and the potential for a second Scottish independence referendum IOG s southern North Sea assets are all within English jurisdiction), and the fiscal regime has seen tax cuts in recent years aimed at allowing operators to make new investments. If you can put together a position like IOG, where you are not reliant on other companies for infrastructure, then the North Sea is an attractive area in which to operate. 4 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

5 Numerous upcoming catalysts over the rest of 2017 IOG has a number of catalysts coming up over the rest of this year that could positively impact the share price. The biggest of these is achieving funding for its upcoming development projects, and we know this is currently a key focus for management. Timing is uncertain, but this will have to come through this year if IOG is to keep to its development schedule. Otherwise, there is completion of the Thames pipeline acquisition (Q2 2017) and follow up work to assess this, a new CPR (H2 2017) submission of the Blythe/Elgood development plan (Q2 2017) and Vulcan Satellites development plan (Q3 2017), and FID on the developments (Q1 2018). There could also be further acquisitions. Valuation and recommendation We have valued IOG using field DCF models for each of its assets. Using a 40p/therm gas price, this returns a risked NAV of 169.5m, going to 378.1m unrisked. If we assume that the 10m LOG loan (plus an assumed 1m accrued interest) converts to equity at 8p/share, this would imply 62.2p/share risked, 138.6p/share unrisked. Were LOG not to convert and the loan remain as debt, this would imply 125.8p/share risked, 280.7p/share unrisked. Subject to full drawdown of its loan facilities, LOG could be in a position to take a stake of over 50% in IOG were it to convert, and this is hence an important consideration for investors. Nevertheless, even if LOG were to convert, on a per share basis IOG would remain substantially undervalued at current levels. IOG holds a substantial resource position in the UK southern North Sea. The company is strongly progressing development of these resources, with the recent pipeline acquisition agreement an important step forward here. IOG has assembled a strong team to execute its developments, and could achieve peak annualised revenues of 219m (at 40p/therm) in two to three year s time on success. Risks remain, principally development funding (which is being actively pursued) and the potential dilution on conversion of the LOG loan. On balance there is much to recommend IOG, and though it is somewhat speculative, we initiate coverage with a Buy recommendation. Investment risks Development funding IOG is likely to require 296m of funding for its upcoming Blythe/Elgood and Vulcan Satellites developments. This could come from diverse sources (including offtake prepay and CAPEX deferral), but if it does not come through it could create delays and potentially put IOG s assets in jeopardy. Potential dilution from 10m LOG loan IOG has a 10m loan facility (with additional accrued interest) with LOG, which can convert at 8p/share (at LOG s option). This is currently strongly in-the-money. Were this to occur, it would likely give LOG over 50% of plc equity depending on accrued interest and exercise of its warrants. This creates not only potential dilution in the share price, but could also give LOG a controlling stake in the company. It could even result in a mandatory offer for the company, potentially at 8p/share if LOG had not acquired other shares above this level. Any changes to this structure, potentially as part of development funding, will be important going forward. Closure of acquisition of pipeline and reception infrastructure, pipeline integrity IOG recently signed a sale and purchase agreement for the Thames pipeline, and completion is expected in due course. Onshore reception facilities connected to the line are also expected to be acquired. Post pipeline acquisition, intelligent pigging work is required to test pipeline integrity. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 5

6 The pipeline is key to IOG s current development plans, and failure to acquire it or the reception facilities, or not to be able to cost effectively bring them back on line, would be a significant setback. The acquisition process is already well progressed, however, the pipeline was operational until 2015, and IOG carried out significant feasibility work prior to acquisition, so risks here are mitigated. Bacton gas terminal availability The Thames pipeline connects to the Bacton gas terminal, which will then allow IOG s gas into the UK national grid. We note that Bacton has capacity of 1,000mmcf/d, and over 25% of this was available over 2014 to 2018 (as of the last update from owner Perenco in June 2014). Figures from Woodmac (which also include the 900mmcf/d Shell Bacton terminal) report throughput across the two of 270mmcf/d for Engie/Centrica/Bayerngas 660bcf Cygnus development came onstream in late 2016, is connected to Bacton and expected to contribute 5% of UK gas supply at peak. IOG is confident there will be sufficient capacity at Bacton to accommodate its developments, but were this not to be the case it could impact the commerciality of the developments. Development approvals IOG still needs to secure full UK government approvals for its developments. As long as the other elements required (funding, the pipeline etc) fall into place, this should be relatively straightforward. Licence expiry The Blythe licence expires at the end of 2017, Elgood is in the process of being extended to January 2018, and two of the licences related to the Vulcan Satellites also currently expire at the end of Approval of development plans are required in order to secure these for the long term, and FDPs are to be submitted in order to achieve this. The OGA has been helpful in extending licences for IOG in the past, so if there are any delays, this risk should be limited. Gas price sensitivity Our modelling shows all of IOG s fields to be economic (strongly in most cases) at a gas price of 40p/therm (average over last 12 months 39p/therm). The valuation has a level of sensitivity here, though the Vulcan Satellites still return a positive NPV down to around 18p/therm, and current forward pricing could allow hedging at or above 40p/therm. CAPEX and OPEX levels IOG expects to develop and operate its assets at CAPEX and OPEX levels that look very attractive. This is based in part on their shallow water location, acquisition of the Thames pipeline at minimal cost, and the current state of the oil services market post the downturn. Were the company to experience upward pressure on costs from the levels we have assumed, it could affect the value of the assets. Requirement for reservoir stimulation on Vulcan Satellites fields Previous wells and nearby fields mean that it is expected that reservoir in the Vulcan Satellites fields will be of lower permeability, and require fracking in order to be successfully developed. Stimulation has been carried out successfully on other nearby gas fields (notably Clipper South, amongst others). IOG expects to carry out tests in order to define its stimulation programme as part of its development programme for the fields (i.e. no further work is required for development sign-off), and this gives comfort that this is not expected to be a significant issue. It is worth investors being aware of, however. 6 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

7 Upcoming activity IOG s immediate focus is submitting its Blythe/Elgood and Vulcan Satellites development plans, securing funding for these projects, and completing its pipeline acquisition. As long as the company is successful here, it is set for a busy period as it proceeds to develop these projects and establish cash flows. IOG Planned Activity Timetable Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Blythe/Elgood Development Planning Blythe/Elgood FDP Submission Vulcan Satellites Development Planning Vulcan Satellites FDP Submission Development Funding Discussions Pipeline Acquisition Closure Pipeline Testing Pipeline Reception Infrastructure Acquisition Blythe/Elgood and Vulcan Satellites FID Blythe/Elgood Development Blythe Onstream Elgood Onstream Vulcan Satellites Development Vulcan South Onstream Vulcan North West Onstream Vulcan East Onstream Source: IOG. Company history IOG was established by Peter Young (current Head of Business Origination) in 2010, who was then joined in 2011 by Mark Routh (current CEO and interim Chairman). Mark had previously founded CH4 Energy in 2002, growing this to 3.6mboe/d of North Sea gas production and selling to Venture for 154m in IOG originally held 50% of the Blythe field and 50% of the Skipper discovery, as a result of an all-share combination of the UK assets of MOST and Ebor Energy in Early funding was provided by management and previous MOST and Ebor shareholders. IOG was subsequently awarded the P2085 licence (which contains the Harvey discovery) in 2013, and the P2260 licence (which contains the Elgood field) in The Vulcan Satellite fields were then acquired from Verus in After funding problems at Blythe and Skipper partner Alpha Petroleum (which had bought the interests from ATP Oil and Gas), IOG acquired 100% interests in these licences in IOG went through a period of uncertainty in 2014 and 2015 as it tried to finance development of its assets. The Skipper well was eventually financed largely by contractors, and debt was secured from LOG to continue funding company overheads and acquisitions. Management has generally taken a significant proportion of salaries as share options to reduce cash burn. IOG has done well to retain and progress its assets during what has been a very difficult period for E&P companies, and is now at the point of needing to secure significant development funding. In March 2017 IOG announced a number of board/management changes. David Peattie resigned as Chairman to take over as CEO of the UK Nuclear Decommissioning Authority, with CEO Mark Routh also becoming Interim Chairman. Andrew Hockey Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 7

8 joined as Deputy Chief Executive and a board director. CFO Peter Young was moved over to Head of Business Origination to focus on acquisitions (leaving the board), being replaced as CFO and board director by Hywel John. Charles Hendry joined the board as the second LOG nominee, and Graham Cox also joined as Southern North Sea Project Manager. Date November 2010 October 2011 Event IOG founded IOG Company Timeline Acquisition of 50% of Blythe and 50% of Skipper completed May 2013 Skipper West awarded (IOG 100%) September 2013 AIM IPO raising 2m at 24p/share December 2013 P2085 licence including Harvey discovery awarded (IOG 100%) February 2014 March 2014 March 2014 June 2014 September 2014 November 2014 Agreement for gas sales from Blythe to BP announced Agreement for acquisition of Cronx discovery (nearby Blythe) US$50m debt facility with a US financial institution announced (closure deferred) Darwin Strategic 1.8m equity swap (at 24p/share) and 0.5m loan entered into AGR taken on for drilling planning services 0.5m placing at 11p/share November 2014 P2260 licence including Elgood awarded (IOG 100%) June 2015 June 2015 May 2015 August 2015 Partial drawdown of Darwin equity swap Baker Hughes taken on for work on Skipper Discussions on significant debt and equity development funding announced US$10m equity, US$80m debt and further 400m debt deal abandoned August 2015 Contractor funding sought for Skipper appraisal drilling planned for late 2015 September 2015 October 2015 October 2015 November 2015 December 2015 December 2015 December 2015 December 2015 January 2016 February 2016 April 2016 Contractor funding for Skipper drilling progressed Conversion of remainder of Darwin equity swap and loan 150k placing at 7p/share Further agreements for Skipper contractor funding, including 2m GE loan Full Skipper funding secured, largely from loans, deferred payments and equity (AGR) to contractors; 2.75m loan agreed with LOG 0.8m loan agreed with LOG Skipper rig contract signed with Transocean IOG assumes 100% interest of Skipper Skipper well delayed 10m debt facility secured from LOG, convertible at 8p/share Deal to acquire balance 50% of Blythe announced June 2016 Skipper appraisal well rescheduled for July 2016 June 2016 June 2016 June 2016 July 2016 August 2016 September 2016 October 2016 November 2016 December 2016 January 2017 March 2017 April 2017 Source: IOG. Acquisition of Vulcan Satellites fields announced Blythe acquisition of balance 50% closes New Skipper rig contract signed with Transocean Skipper well spudded Skipper initial well result Skipper sample testing oil higher viscosity than anticipated, new reservoir modelling required Vulcan Satellites acquisition closes Cronx acquisition abandoned to focus on Vulcan Satellites and Blythe/Elgood Blythe draft FDP submitted Pipeline acquisition announced Management changes Pipeline acquisition sale and purchase agreement signed 8 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

9 Current shareholders IOG Current Key Shareholders Holder Shares (m) Percentage Hargreaves Lansdown (Nominee) % TD Direct (Nominee) % Hargreaves Lansdown (Nominee) % Barclayshare (Nominee) % Hargreaves Lansdown (Nominee) % Huntress Nominees % JIM Nominees % Tom Haselton % Viola Ltd % Wealth Nominees % As part of the above Peter Young (Head of Business Origination) 13.8m 12.7% Mark Routh (CEO and Interim Chairman) 4.3m 3.9% Source: Bloomberg. IOG s shareholder register is relatively opaque, being made up of shares in nominee accounts. Historically, management has taken significant compensation in the form of equity. Debt holder LOG is not currently a shareholder. Company strategy IOG s overarching strategy is to build a portfolio of producing assets in the UK North Sea. The company plans to achieve this by acquiring existing discoveries and developing them via a hub and spoke methodology. IOG has already built a significant portfolio of gas discoveries in the Southern North Sea via acquisition, and is also in the process of buying the Thames pipeline to take production to the UK coast. Funding is planned to come from a number of sources, including prepayments for offtake and deferred payments for services from oil services companies, alongside the potential for conventional debt and equity. Hub development focus The hub development strategy is based on the thesis that there are numerous existing small discoveries in the North Sea which are challenging to develop on a standalone basis. The idea is that if enough small fields are tied into one set of infrastructure, they can, in aggregate, make up enough production to justify the cost, allowing them all to be economically developed. One solution is to develop these as tiebacks to existing infrastructure. This can be a very attractive option providing it can be guaranteed that the infrastructure (generally platforms and pipelines) will remain in place long enough to produce the new field. If infrastructure (which was typically put in place for large fields which have now declined) is shut down early, or the new tie-in fields are forced to shoulder a larger proportion of infrastructure operating costs in the future, then this can negatively impact the economics of the new fields. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 9

10 Full ownership of production and offtake infrastructure IOG has chosen to pursue an independent solution, and is planning to install its own newbuild platforms to commercialise its Southern North Sea assets. The company is also in the process of acquiring an old pipeline (which was previously shut down due to a lack of production for it to carry), which will give IOG control of transport for its gas to processing facilities on the UK coast at Bacton. This approach will allow IOG to design platforms specifically for its own fields (and potential future developments), planning for costs in a way to suit the company. It will also give IOG full control of these platforms and the route to market, meaning a third party cannot leave the company s developments stranded by shutting them down earlier than IOG would like. The positive economics of this approach can be seen in our modelling (detailed elsewhere in this note). In our base case, we value Blythe at US$4.7/boe, but Elgood at US$7.5/boe. This is because the cost of the platform for Blythe impacts returns, but allows better returns for fields tied back to it, demonstrating the logic of the hub approach. Significant funding and expertise will be required If control of its own destiny is the upside of IOG s strategy, the downside is a requirement for significant funding and North Sea operational expertise. Whatever the eventual field economics, construction of newbuild platforms is going incur a significant amount of upfront CAPEX. We estimate a total CAPEX bill of 296m for the company s planned Southern North Sea developments, and IOG will be liable for 100% of this. Historically, IOG has made use of funding from diverse sources including convertible debt and deferred payments to oil services companies (employed on the Skipper well in 2016). For its developments, it could look at prepayment for offtake (there is an existing agreement with BP Gas Marketing for offtake of Blythe production), further deferred payments to oil services companies (this is an avenue IOG is keenly pursuing, and could potentially include using plc equity), project debt, further convertibles, or a plc equity raise. Securing development financing is currently the next big step forward IOG needs to make. While there is work to do on funding, IOG has made headway increasing its capabilities as an operator. The company has added significantly to its board and management/technical team over the last 12 months, augmenting the existing strong team (details elsewhere in this note). In addition to securing financing, the task now is completing and submitting development plans, having development licences awarded, and implementing the developments. 10 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

11 Asset position IOG has assembled a material portfolio of gas discoveries in the Southern North Sea. This was largely built (in terms of resources) in 2016, when the company bought the 50% of Blythe it did not already own (42bcf gross 2P) and also acquired 100% in three fields known as the Vulcan Satellites (321bcf of gross 2C). IOG is also in the process of closing the acquisition of the nearby Thames pipeline, which will allow it to deliver gas production from all its Southern North Sea fields to processing facilities at Bacton on the UK coast. IOG Southern North Sea Assets Source: IOG. Blythe and Elgood Hub 1 The first of IOG s upcoming hub developments is planned to be based on the Blythe and Elgood gas discoveries. There will be an unmanned platform at Blythe, with Elgood tied back to this subsea. Gas will then be piped from Blythe via a connector to IOG s pipeline, which will then take it into the national grid at Bacton. Peak initial combined rates of 85mmcf/d are targeted from the two fields combined (though these are likely to decline from this level relatively quickly), with an onstream target of Q for Blythe and Q for Elgood. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 11

12 Blythe (IOG 100%, operator) Blythe is located c.25km to the north west of the Hewett field in licence P1736. The field was originally discovered by the 48/22-1 well, drilled in This intersected gas in Rotliegend reservoir, and flowed at 0.9mmcf/d on test. The 48/22-2 appraisal well was then drilled in 1968, but this tested only water, from below the gas water contact. ARCO then drilled the 48/23-3 well in This well found a 141ft gas column and tested at 15.2mmcf/d. The 48/23a-4 horizontal well was then drilled by ARCO in 1990 with the aim of developing the field. This tested at rates of between 11.6mmcf/d and 15.0mmcf/d, but these rates were seen to decline. Development was not progressed given expected field size and prevailing gas prices. Further reservoir modelling studies have now been completed, and IOG is pursuing development based on a single, high angle (near horizontal) well. This is to be drilled into a single interval, lower down than the ARCO horizontal and which is expected to deliver significantly better production rates. Blythe and Elgood Field Map Source: IOG. The field comprises reservoir in Rotliegend Leman sandstone overlain with Kupferschiefer shale which provides the seal. The structure is a four way dip closure, with faulting down the sides and in the overburden (complicating seismic imaging). 12 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

13 Source: IOG. Blythe Reserves (bcf, gross) 2P 42 Elgood (IOG 100%, operator) Elgood lies next door to Blythe in the P2260 licence. It was discovered in 1991 by Enterprise Oil via the 48/22-4 well. This found gas in Rotliegend Leman sandstones (as with Blythe), testing at 17.6mmcf/d. Development was not progressed given perceived size and contemporary gas prices. IOG carried out the reprocessing and interpretation of 3D seismic in 2016, increasing Elgood P50 recoverable resources from 15bcf to 22bcf, and reservoir modelling work now puts this at 27bcf. This, along with the opportunity to be tied back to Blythe, now justifies development of Elgood. The initial development plan is for one production well at Elgood. Source: IOG. Elgood Resources (bcf, gross) 2C 27 Vulcan Satellites Hub 2 IOG s second hub is planned to be based on the Vulcan North West, East and South fields (collectively known as the Vulcan Satellites - they are near the larger Vulcan field). The fields lie 30-45km to the east of IOG s Blythe/Elgood fields. This development is planned to proceed broadly concurrently with Blythe/Elgood, with at least one unmanned platform (at Vulcan South, which will carry the majority of hub infrastructure), and potentially up to three. This is also to be tied in to the Thames pipeline by IOG. Peak rates of 100mmcf/d are targeted across the three fields combined, with onstream targets of Q for Vulcan South and Vulcan North West, and Q for Vulcan East. Vulcan North West, East and South (IOG 100%, operator) The Vulcan Satellites were discovered over the period 1987 to Vulcan North West was discovered by the 48/25a-4 well drilled by Shell and Exxon in ConocoPhillips also operates the nearby Vulcan field. Vulcan South was then discovered by the 49/21-8a well drilled by Conoco in 2000, and Vulcan East by 49/21b-10a drilled by Verus Petroleum in 2006 (from which IOG acquired all three fields in 2016). The Vulcan Satellite fields are all in Rotliegend Leman sandstone reservoir (as on Blythe and Elgood), with overlying Zechstein evaporites and carbonates providing seal. Reservoir is expected to be tight, with multiple-fracked, horizontal wells expected to be required in order to achieve commercial flow rates for development. This has been achieved successfully on similar Rotliegend reservoir in nearby fields including Clipper South, Babbage, Ensign and Victoria. Frack testing is planned to form part of initial development work, and no further appraisal or testing is expected to be required for development sign off. The development is planned to consist of seven wells across the three fields. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 13

14 Vulcan Satellites Field Map Source: IOG. The Vulcan Satellites are located across a series of licences, some of which expire by the end of IOG is expecting to submit development plans in advance of this, allowing subsequent award of long-term development licences (on government approval). Vulcan Satellites Licence Deadlines Field Licence Current Expiry Vulcan North West P December 2017 Vulcan East P039 Extant (September 2030) Vulcan East P December 2017 Vulcan South P January 2020 Source: IOG. Resources on the Vulcan Satellites are substantial, and have multiplied IOG s previous Southern North Sea position based on Blythe and Elgood. Vulcan Satellites Resources (bcf, gross) Field 1C 2C 3C Vulcan North West Vulcan East Vulcan South Source: IOG TRACS Technical Review April Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

15 Regional pipeline acquisition agreed IOG is currently in the process of acquiring the dormant Thames pipeline in the Southern North Sea, that it is planning to use to commercialise Blythe, Elgood, the Vulcan Satellites and any other fields it develops in the area. The deal also includes infrastructure at Bacton on the Norfolk coast, allowing IOG to have direct access to the Bacton terminal for its gas production, which can then pass into the UK national grid. IOG recently signed a sale and purchase agreement for the pipeline, and the reception facilities are to be acquired subsequently. Thames Pipeline Map Source: IOG. The line being acquired is the 24inch Thames-Bacton pipeline. This is currently out of use due to a lack of availability of gas production to utilise it. Post acquisition, IOG plans to carry out an intelligent pigging operation to assess pipeline integrity, followed by any remedial work required. The pipeline s capacity is 300mmcf/d enough for the planned Blythe/Elgood and Vulcan Satellites developments, and potentially development of Harvey if this is progressed too. We note that the Perenco Bacton terminal on the UK coast has capacity of 1,000mmcf/d, and over 25% of this was available over 2014 to 2018 (as of the last update from owner Perenco in June 2014). Figures from Woodmac (which also include the 900mmcf/d Shell Bacton terminal) report throughput across the two of 270mmcf/d for Engie/Centrica/Bayerngas 660bcf Cygnus development came onstream in late 2016, is connected to Bacton and expected to contribute 5% of UK gas supply at peak. IOG is confident there will be sufficient capacity at Bacton to accommodate its developments. Acquisition costs are for a nominal upfront sum, with the assumption of decommissioning liabilities. Decommissioning costs are likely to be negligible, not least because on cessation of production operators are allowed to flood and leave pipelines like Thames in situ rather than having to remove them. As part of the deal, IOG will post security to Perenco for pipeline integrity surveys of 0.5m on completion, and a further 2.5m three months before first gas from the developments. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 15

16 There are three principle advantages for IOG from owning the pipeline. First, it is expected to provide a secured export route for IOG s Southern North Sea gas developments, checking off this requirement in the development plan. Second, it gives the company full control over the export route for its developments, preventing any issues that could arise from relying on a third party, such as the availability of capacity, the volume available, the timing of this, pipeline tariffs and the timing of maintenance work. Third, it allows IOG to capture the margin that would otherwise be paid away to infrastructure owners, improving the economics of its development projects. IOG could also earn tariff income from third party use of the line. Potential third Southern North Sea development Harvey The Harvey discovery (IOG 100%, operator) is located to the south east of Blythe/Elgood. It was drilled by the 48/23-2 well in 1984 (Arco), which was interpreted to have encountered a 6m gas transition zone. Difficulties in obtaining good seismic resolution coupled with low resource estimates led to Harvey not being progressed historically. Harvey was awarded to IOG in 2013, and in 2016 the company carried out 3D seismic reprocessing and interpretation, including acquiring new existing data covering an area east of the 48/23-2 well. It is now IOG s view that what were considered to be two prospects (Harvey and Truman) are actually one, to which the company has assigned 113bcf of P50 prospective resources. Reservoir is expected to be in the same Rotliegend Leman sandstone as IOG s other Southern North Sea assets. Harvey Discovery Map Source: IOG. The P2085 licence that contains Harvey has been extended to 20 December 2017, and a commitment to drill an appraisal well is required to extend this further. IOG expects to make this commitment later this year. On success, IOG could commercialise Harvey via the same Thames pipeline that it is planning to use for Blythe/Elgood and the Vulcan Satellites. 16 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

17 Source: IOG. Harvey Prospective Resources (bcf, gross) P90 P50 P Skipper oil discovery In addition to its Southern North Sea assets, IOG also holds the Skipper field (IOG 100%, operator) in the Northern North Sea to the east of the Orkney Islands. This is a heavy oil discovery, originally drilled in IOG drilled a follow up well in 2016, recovering high viscosity 11 degree API oil. The reservoir was not cored, but is believed to have high permeability of 10 Darcies. The heavy nature of the oil has meant IOG has needed to go back and review its reservoir modelling of the field, in an attempt to establish whether or not it can be commercially developed. This process is ongoing. Subsequent analysis of the oil samples has also found a high total acid number which, when combined with the high viscosity, means produced oil would be expected to trade at a significant discount to Brent (perhaps 10%). The licence currently runs to 11 February Skipper Contingent Resources (mmbbl, gross) 1C 2C 3C Source: IOG - TRACS CPR September Skipper Map Source: IOG. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 17

18 Next steps development plans This year There are four key workstreams that we expect to see pursued by IOG over the course of Blythe/Elgood development plan. IOG submitted a draft development plan to the government in December The final development plan is now expected to be submitted during Q Blythe currently runs until 31 December 2017 and Elgood is in the process of being extended to January First gas is targeted for Q from Blythe and Q for Elgood. Vulcan Satellites development plan. A full development plan for the Vulcan Satellites is being worked on, and is expected to be submitted before the end of 2017, prior to two of the relevant licences expiring. First gas is targeted for Q for Vulcan South and Vulcan North West, and Q for Vulcan East. Pipeline acquisition and testing. IOG is in the process of closing the acquisition of the Thames pipeline in the region of its Southern North Sea gas assets. This is a key element of the Blythe/Elgood and Vulcan Satellites development plans. Post acquisition, initial work will be intelligent pigging to assess pipeline integrity and define any remedial work requirement. The onshore reception facilities are also to be acquired. Development funding. Submission of development plans and (to a large extent) securing the pipeline are largely under IOG s control. The other major ingredient for developing the company s assets is funding. This will need to be progressed in the coming months, and could come from a diverse range of sources including upfront production offtake payments and deferred payments to services companies, alongside traditional debt and equity. Next year Based on current plans, 2018 would see a significant ramp up in development activity and CAPEX spend across IOG s Blythe/Elgood and Vulcan Satellites development hubs. First gas is targeted from Blythe in Q2 2019, from Elgood in Q4 2019, and on the Vulcan Satellites over Q to Q We would expect CAPEX spend to continue well into Funding and capital structure The central issue for IOG over the coming months is likely to be funding. In order to progress the Blythe/Elgood and Vulcan Satellites developments, development plans will have to be submitted and the pipeline secured and assessed. These elements are reasonably well within IOG s control. Funding requires the agreement of what is likely to be a number of counterparties, and here there is a level of risk. Current funding position In its early years from 2010 to 2014, IOG generally relied for funding on equity from management and other shareholders, including an equity drawdown facility and 0.5m loan from Darwin Strategic (now fully drawn and repaid). Over the course of 2015 and 2016, IOG took on a number of debt facilities in order to fund drilling of the Skipper well, progress acquisitions and fund corporate overheads 18 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

19 (which are minimal, given significant management share compensation). In addition, IOG also managed to secure a level of payment deferrals from oil services companies, principally in respect of Skipper. As of the end of 2016, IOG s funding position was as below. Item Capacity End 2016 Position IOG End 2016 Forecast Funding Position Headroom GE Loan 2.0m 2.1m 0.0m End 2017 LOG Loan 1 2.8m 7.8m end H LOG Loan 2 0.8m 6.7m 2016, 4.8m H LOG Loan m end May 2017 From H Weatherford Payable Skipper Contractors Payables Due n/a 2.0m n/a May 2017 n/a 3.8m n/a End 2017 Cash Holding n/a 0.2m n/a n/a Net Debt Source: IOG, Arden Partners Estimates. Debt facility/payables details 14.3m - GE 2.0m loan: This facility is from services company GE Oil and Gas, agreed in December Interest is charged at LIBOR +9% and rolls up. The lender has charge over IOG s North Sea assets. The loan is due at the end of London Oil and Gas (LOG) 2.8m and 0.8m loans: These were both agreed in December Interest is charged at LIBOR +9% and rolls up. The lender has charge over IOG s North Sea assets. The loans are due in H Warrants were awarded as part of the deal. - LOG 10.0m convertible loan: This was agreed in January 2016, and can be drawn in tranches. Interest is charged at LIBOR +9%, and rolls up. The lender has charge over IOG s North Sea assets, and loans are due from H Of the 10m total, 3m is earmarked for corporate overheads and licence fees to July 2018, and 7m is for acquisitions. The loan is convertible into IOG shares at 8p/share, at any time at LOG s option. This is currently strongly in-the-money. This implies potential additional shares of 125m without accounting for accrued interest (compared to 109m currently in issue), which would be substantially dilutive and likely to give LOG over 50% of the company depending on accrued interest and exercise of its warrants. The loan also gives LOG the right to nominate two directors to the board (currently Martin Ruscoe and Charles Hendry). - Weatherford payable: This was due to Weatherford for past work, and has been fully repaid as of May 2017, utilising funds from the LOG facilities. This dates from 2009, prior to the formation of IOG and was originally incurred by MOST. - Skipper contractors payables: These are deferred payments to contractors for services relating to the Skipper well, drilled in They are due by the end of 2017, and the payables holders have charge over IOG s North Sea assets. IOG is attempting to get them converted to plc equity. Cash holding IOG tends to keep its cash holding to a minimum, drawing down its debt facilities as required to fund overheads, acquisitions and CAPEX. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 19

20 Cash burn rate We forecast 1.5m of cash corporate overheads for 2017 given the expectation of a ramp up in activity as IOG s developments progress. In the near term these should be covered by existing debt facilities, but longer term these costs will need to be accounted for in the wider funding IOG will need for its developments. Potential dilutive shares IOG has issued a number of warrants and options in relation to management compensation and its debt facilities. The LOG 10m facility (plus accrued interest) is also convertible (at LOG s option) into shares at 8p. Given the 109m shares currently in issue, the LOG convertible in particular represents substantial dilution potential, particularly given that it is currently strongly in-the-money. Shares in Issue Potential Dilutive Shares Warrants Options IOG Shares and Potential Dilution LOG Convertible (assuming 11m gross debt value, including accrued interest) Potential Total Shares 109m 14m 12m 138m 260m Implied Potential Dilution to Existing Equity 60% Source: IOG. Upcoming cash requirements acquisitions and CAPEX In addition to the debt maturities and admin costs detailed above, IOG s upcoming cash requirements are focused on acquisitions and project CAPEX. IOG made two acquisitions in 2016 the Vulcan Satellites, and the balance 50% of Blythe. The company is also in the process of acquiring the Thames pipeline in the Southern North Sea. Payments for these are staged, as set out in the table below. IOG will also need to meet the CAPEX requirements for its Blythe/Elgood and Vulcan Satellites developments. The company holds all of these 100%, and total CAPEX is currently expected to be 296m. Upcoming CAPEX and Acquisition Payment Requirements Item Timing Quantum Vulcan Satellites Acquisition Payments On completion October m Nine months after completion July m On development approval Current target by end m On first gas Current target Q m Blythe Acquisition Payments On completion June m On first gas Current target Q US$5.0m Pipeline Security on completion Q m Security before first gas Q m Project CAPEX Estimates 2017 Estimate m* Blythe 2018/ m Elgood 2018/ m Vulcan North West 2018/ m Vulcan East 2018/ m Vulcan South 2018/ m Source: IOG, Arden Partners Estimates. Note: *As part of total 296m CAPEX on development projects. 20 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

21 In the near term we expect cash requirements to be met by existing loan facilities. If IOG s development projects are to go ahead, significant further financing will be required. This could come from a diverse range of sources including upfront production offtake payments and deferred payments to services companies, alongside traditional debt and equity. What is LOG? IOG has taken on significant debt funding from London Oil and Gas (LOG) over the past two years. This has also included warrants and a convertible element, which gives LOG significant influence and could result in it becoming a majority equity holder (detailed elsewhere in this note). LOG is part of the wider London Group. This is an investment company split between real estate and oil and gas. The real estate segment is focused on the acquisition and turnaround of tourist sites globally. The group s activities on the oil and gas side (represented by LOG) are described on its website as below. London Oil and Gas was formed by Eric Bosshard in 1992 as a consultancy firm to international oil companies. This activity continued until 2014 when the company decided to extend its activities. Initial steps have been; increasing its capital, extending its Board, and management team. It has a clear strategy to acquire oil and gas producing assets in North America, the Caspian region, and West Africa. As part of the capital re-organisation the company became a member of The London Group LLP. With a paid up group capital of c. $80,000,000 a firm financial base has been established. The company has engaged the services of a number of highly experienced individuals from the global oil and gas sector and international finance. Furthermore London Oil and Gas has entered into a series of detailed strategic arrangements and with highly influential organisations within the oil and gas industry. These arrangements are intended to provide the company with the opportunity to acquire, finance, operate and sell the oil and gas production of small to medium sized oil fields up to an aggregate value of initially $1,000,000,000. Within the terms of its agreements London Oil and Gas has commenced the process of reviewing and offering to acquire a number of prime assets which have become available due to the necessity of some operating groups needing to dispose of their assets, originally acquired at far higher prices, due to the fall in the price of oil and gas. Additionally, a number of senior officers of the company and their partners have significant experience in monetising otherwise valueless gas production. This has been achieved through constructing gas to liquid plants. To this end, London Oil and Gas is interested in acquiring assets where a National or Regional Government will permit the construction and operation of suitable plants (we are focussed on methanol and diesel). London Oil and Gas has agreed outline terms with a Chinese state-owned company with experience in manufacturing and assembling such plant. They have provided a format within which they would be willing to provide finance to London Oil and Gas for the construction. Source: Under the terms of its debt facilities with IOG, LOG has two representatives on the IOG board: Martin Ruscoe (non exec) and Charles Hendry (non exec). Were the 10m facility to be converted into IOG equity, LOG would likely end up owning over 50% of IOG equity depending on accrued interest and exercise of its warrants. LOG does not currently hold any IOG shares. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 21

22 North Sea M&A environment IOG has built its portfolio largely via M&A, significantly augmenting this in 2016 with the addition of the Vulcan Satellites. The company now has plenty of development projects to keep it busy, but we could still see some further acquisitions, particularly aimed at buying production. The stabilised oil price post the OPEC production cuts in late 2016 (which seems to still be holding despite recent volatility) has seen increasing deal activity in the North Sea since the beginning of Larger companies are high-grading portfolios and reducing exposure to what are relatively smaller assets. This is the case with the majors selling larger packages (Shell/Chrysaor, Total/Kufpec, ExxonMobil/Point Resources) but also the larger E&Ps selling to smaller peers (Tullow/Pandion and Tullow/Hague and London Oil). Details are in the table below. This creates an environment in which assets could increasingly become available from either the majors directly, or perhaps more likely E&Ps, either directly from their existing portfolios or as part of a pass-through of assets contained in a larger deal. This creates an M&A environment that IOG could take advantage of going forward, in tandem with its core development strategy. 22 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

23 Buyer Seller Date Announced INEOS DONG May 2017 OKEA (Seacrest backed) DNO Hague and London Oil Recent North Sea E&P Deals Country Assets US$1.1bn, further US$250m contingent UK, Norway, Denmark 100mboe/d, 570mmboe reserves, including stakes in Ormen Lange, Laggan-Tormore and Syd Arne Total May 2017 US$350m Norway 34mmboe reserves, 15% Gina Krog Origo (Temasek, Riverstone, GNRI backed) May 2017 Tullow April 2017 Assumption of liabilities EUR10m, further EUR20m contingent Norway, UK 7 Norway licences, 4 UK Netherlands 2.9mboe/d, Netherlands assets INEOS BP April m UK Forties pipeline system Point Resources (HitecVision PEH) ExxonMobil March 2017 US$935m Norway Delek Group Ithaca Energy Feb m UK Pandion Energy (Kerogen Capital backed) 100% Balder, Ringhorne, Ringhorne East (all producing, c.54mbbl/d) and Forseti (development), 90% Jotun, exploration assets Producing assets including Stella Area, 76mmboe 2P, 19-22mboe/d forecast 2017 production Tullow Jan 2017 Undisclosed Norway Several licences including Cara project Kufpec Total Jan 2017 US$300m Norway Chrysaor (EIG backed) Shell Jan 2017 US$3bn UK Enquest BP Jan 2017 US$85m UK Siccar Point (Blackstone, Bluewater, GIC backed) Aker BP OMV Nov 2016 Tullow October 2016 US$875m, additional US$125m contingent UK 46mmboe 2P, 9mboe/d. 9.4% Sleipner West, 10% Sleipner East, 15% GinaKrog, 6% Utgard and 22% Eirin 350mmboe 2P, 115mboe/d. 22% Buzzard, 39% Beryl, 18% Bressay, 14% Elgin- Franklin, 31% J-Block, 76% the Greater Armada cluster excluding Gaulpe, 100% Everest, 100% Lomond, 32% Erskine and 10% Schiehallion 25% of Magnus, 3% Sullem Voe terminal all cash to be paid from field revenues. 16mmboe 2P and 4.2mboe/d 22 licences including 5.6% Jade, 12% Schiehallion redevelopment, 20% Rosebank, Cambo, Tornado, Suilven, Jackdaw Undisclosed Norway Collection of assets including 15% in Ula Petoro OMV Sept 2016 Undisclosed Norway 20% Zidane Statoil Tullow Sept 2016 Undisclosed Norway Several assets including stake in 241mmboe Wisting discovery RockRose Energy Maersk Sept 2016 Undisclosed UK Siccar Point (Blackstone, Bluewater, GIC backed) Suncor OMV Aug 2016 Ithaca 7.4% of Wytch Farm (pre-empted by JV), 5.2% Scott and 2.4% Telford fields JX Nippon Aug 2016 Undisclosed UK 8.9% of Mariner development Engie, INEOS, Maersk US$50m initially, up to US$165m more on FID UK Aug 2016 US$6m UK Faroe Petroleum DONG Energy Jul m Norway Delek Enquest July m loan, pro rata CAPEX from Jan 2016 UK 30% in Rosebank project (in FEED, 100mbbl/d and 80mmcf/d planned) 4mmboe 2P, 16% Vorlich and 75% Austen discoveries 20mmboe 2P, 8mboe/d. 20% Ula, 45% Tambar, 55% Oselvar, 50% Trym 20% Kraken development, 28mmboe 2P. Did not complete Independent O&G Verus Petroleum June m UK 100% in Vulcan Satellites fields Bridge Petroleum Iona Energy June 2016 Undisclosed UK 75% Orlando and Kells Independent O&G Alpha Petroleum June m UK 50% Blythe project BP JX Nippon May 2016 Undisclosed UK 16% Culzean (net resources 40-50mmboe) Lundin Statoil May m Norway 2P reserves 31mmboe, 15mboe/d (development). 15% Edvard Greig Kerogen Capital Hurricane Energy Apr m UK Direct plc equity investment M Vest Energy Atlantic Petroleum Source: Companies, Press, Mergermarket. March 2016 Assumption of liabilities Norway Collection of Norwegian assets Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 23

24 Buyer Seller Date Announced Recent North Sea E&P Deals Country Assets Aker BP Noreco March 2016 Undisclosed Norway Zennor Petroleum (Kerogen Capital backed) First Oil Feb 2016 Undisclosed UK Enquest First Oil Feb 2016 Nominal UK Kraken project Cairn Energy First Oil Feb 2016 Nominal UK Kraken project 7 Norway licences including 20% Gotha, 4% Enoch Mungo and Monan, Bacchus, Cormorant East, and Causeway (all producing); Glenn, Platypus Statoil Lundin Jan 2016 EUR496m Norway 12% stake in Lundin Premier Oil E.ON Jan 2016 US$120m UK 15mboe/d, 64mmboe 2P+2C, includes Elgin- Franklin, Huntington, Babbage, Tolmount OKEA (Seacrest backed) North Energy Repsol Jan 2016 Undisclosed Norway 60% Yme Explora Petroleum Dec 2015 US$2.5m Norway Whole company, including net 4mmboe from stakes in Skarfjell and Grosbeak discoveries Repsol Statoil Dec m Norway 20mmboe 2P, 11mboe/d. 15% Gudrun Aker BP Premier Oil Nov m Norway 50% Vette, Mackerel, Herring, Froy LOTOS ExxonMobil Oct 2015 US$185m Norway 21mmboe, 16mboe/d. 15% Sleipner East, Sleipner West, Gugne, Loke Tellus Petroleum Total Oct m Norway 33mmboe 2P. 15% Gina Krog Aker BP Svenska Petroleum Oct 2015 US$75m Norway 17 Norway licences INEOS DEA/LetterOne Oct m UK Petrogas Van Dyke Energy Sept 2015 Undisclosed Netherlands 12 assets including Breagh, Clipper South, Cavendish, Windermere and Topaz gas fields 8mmboe reserves. 40% Block P8a - Horizon West Faroe Petroleum Roc Oil Sept 2015 US$14m UK 0.5mboe/d, 2mmboe of 2P. Blane and Enoch ArcLight Capital Total Aug m UK Hibiscus Petroleum/Ping Petroleum Shell/ExxonMobil Aug m UK SSE Total July m UK Tellus Petroleum Wintershall June 2015 US$602m Norway Premier Oil Chrysaor June 2015 US$100m future payments UK 100% FUKA and SIRGES pipelines, 67% St Fergus terminal 4mboe/d. 100% Anasuria FPSO, Teal, Teal South, Guillemot A fields; 39% Cook field 20% Laggan-Tormore, Edradour gas field, Glenlivet gas field, Shetland gas plant 59mmboe 2P. 20% Knarr, 15% Maria, 6.5% Ivar Aasen, 4.5% Vaslefrikk, several exploration assets 52mmboe of 2P. 40% Solan project MOL Ithaca Energy April 2015 US$90m Norway 14 Norway licences Oranje-Nassau Shell/ExxonMobil Dec 2014 Undisclosed UK 8mboe/d. 50% Sean field PGNiG Total Oct m Norway 8% Gina Krog, 24% Vilje, 24% Vale, 6% Morvin Dyas Cairn Energy Sept m UK 10% in Catcher project Petrogas Chevron Sept 2014 Undisclosed Netherlands 9mboe/d. 11 Netherlands blocks 170mmboe 2P+2C, 20mboe/d. 5% Gjoa, Wintershall Statoil Sept 2014 US$1.25bn Norway 25% Vega and Vega South, 24% Aasta Hansteen, 13% Polarled pipeline project AU Energy Tullow Sept 2014 EUR64m Netherlands 1.5mboe/d. L12/L15, Q block Total Faroe Petroleum Sept m UK Glenlivet discovery, undeveloped Source: Companies, Press, Mergermarket. 24 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

25 UK gas prices UK gas prices experienced a slow decline from the second half of 2014, with winter 2015/16 failing to show the usual recovery during this period. Indeed the fall simply continued, touching levels as low as 21p/therm in summer Winter 2016/17 has been substantially better, with prices recovering to levels as high as 60p/therm. These have now fallen back given the recent warmer weather, but they are still well ahead of May 2016 levels at c.40p/therm versus c.34p/therm last year. The forward curve also supports prices in excess of the 40p/therm that we have used in our IOG modelling. p/therm UK NBP Gas Prices and Forward Curve Source: Bloomberg. The fall in sterling is likely to have had a part to play here, making gas imports relatively more expensive and therefore putting pressure on domestic prices. The UK has been increasing reliance on gas imports over the last ten years, particularly from Norway, the Netherlands and international LNG. 700,000 UK Gas Imports 600, , , , , , Gas Imports (GWh) Interconnector via Belgium Netherlands Norway (by pipe) LNG Source: DUKES. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 25

26 UK demand is likely to continue to rise well beyond domestic supplies over the next 20 years, according to OGA projections. There are a number of potential LNG projects to come onstream in the coming years globally, but overall the world is likely to see increasing demand for energy, pushing up costs and by implication both international and UK gas prices. 12,000 UK Gas Supply/Demand 10,000 8,000 mmcf/d 6,000 4,000 2, A 1999A 2000A 2001A 2002A 2003A 2004A 2005A 2006A 2007A 2008A 2009A 2010A 2011A 2012A 2013A 2014A 2015A 2016E 2017E 2018E 2019E 2020E 2021E 2022E 2023E 2024E 2025E 2026E 2027E 2028E 2029E 2030E 2031E 2032E 2033E 2034E 2035E UK Gas Production UK Gas Demand Source: OGA. It s also worth mentioning here the recent Conservative party manifesto pledge to introduce a cap on energy prices, which would presumably include both electricity and gas. It is early days to determine what might actually happen here, and whatever is done with consumer prices the gas will still need to be bought from somewhere (including LNG and pipeline imports, which will be competing with other markets), but it is nevertheless worth being aware of in the context of wholesale UK gas prices going forward. We use a 40p/therm annual average gas price forecast in our modelling for IOG. The company s Vulcan Satellites developments break even on an NPV basis around 18p/therm (with the 10% discount rate implying a 10% IRR at this level). 26 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

27 Board, management and technical team Mark Routh CEO and Interim Executive Chairman Entrepreneur, founder and MD of CH4 Energy Ltd a private equity backed Oil and Gas Company which became a North Sea operator. CH4 was formed with 1 million funding from management and 3i in 2002 and sold to Venture Production plc in 2006 for million, providing 3i a with a record 7.3 multiple return on its investment. Over 30 years experience in the oil & gas industry, in executive management, commercial management, and Petroleum Engineering. Prior to founding CH4 Energy served 10 years with Hess, 6 years with BP and 5 years with Schlumberger in South East Asia and the North Sea. MSc in Petroleum Engineering, Imperial College. Non-executive Chairman of Warrego Energy Limited a company with onshore gas assets in Western Australia. Andrew Hockey Deputy CEO Having worked in the industry for 35 years, Andrew Hockey has significant sector experience. He has a technical background with a degree in geology from Oxford University and a Master's Degree in petroleum geology from Imperial College London. Until the end of 2015 Andrew was General Manager of Business Development at UKCS oil and gas exploration and production company Fairfield Energy Limited which he helped to found in Andrew led the team to acquire Clipper South as an undeveloped discovery from Shell and Esso and then subsequently managed its development via farm down and funding through to first gas in Andrew is now a non-executive director of Fairfield Energy and a founder of its parent company, Decom Energy Limited. Andrew has also served on the board of AIM-listed Sound Energy plc, an upstream company with onshore interests in Italy and Morocco, where he was a Non- Executive Director from and Chairman from Hywel John CFO Hywel John has 30 years of experience in the industry. He is a qualified chartered accountant with significant public company board level experience having served as CEO of Bayfield Energy, CFO of Candax Energy, a TSX listed company and Company Secretary / Legal and Commercial Director at Burren Energy. Andrew Hay Senior Independent Non-Executive Director Currently a senior adviser to Edmond de Rothschild in London. Between 1999 and 2014 Andrew ran the corporate finance team at Edmond de Rothschild Securities, specialising in public and private company M & A transactions and capital raising. Prior to this, Andrew held senior positions at both Schroders and ING Barings. Until recently, senior independent director at Aminex plc, the London Stock Exchange listed East African focused production and development company, Andrew was on Aminex s audit and remuneration committees. Andrew is Senior Independent Director and chairs IOG s Audit Committee. Martin Ruscoe - Non-Executive Director (LOG Nominee) Martin has over 40 years' experience in the Financial Services Industry. Martin initially worked for a top 20 life office for 25 years, the last 9 years as Chief Investment Officer being involved in all forms of investment, taxation and new product development within the company. Following a takeover he left to move to the broking side of the investment community working for Swiss Bank, Citicorp and Smith New Court. Martin Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 27

28 then spent 12 years with Charterhouse Securities who were voted number one in the small cap market and the spent 6 years with Seymour Pierce, at the time the largest Aim Broker in London. Martin has vast experience and has overseen in excess of 200 institutional fundraisings including new listings, placings and rights issues. He currently holds the following Non-Executive Director positions: Surrey Save Credit Union, London Oil & Gas, Modular Airspace Systems, London Group PLC and Independent Oil and Gas. Charles Hendry - Non-Executive Director (LOG Nominee) Charles Hendry was Minister of State for Energy from May 2010 until September Since leaving ministerial office he has undertaken a wide range of roles, including as President of the British Institute of Energy Economics, chair of the Forewind Consortium from , and in 2016 he was appointed by the UK Government to lead a review into the strategic case for tidal lagoons and their role in the UK energy mix. Charles Hendry is a nominee of London Oil and Gas Limited, a committed funding partner of IOG. Peter Young Head of Business Origination 15 years' experience in banking and finance, encompassing structured and project finance, energy derivatives structuring and sales and trade execution, mostly focused on the mid-cap E&P sector before moving into industry. Former Director and Chairman of MOST Inc and Director of Ebor Energy Inc and founder of IOG. Peter has an economics degree and an MSc in Corporate and International Finance. Peter has driven the M&A activities of IOG to date. Richard Jameson COO 30 years experience in Project Management and Engineering, with the last ten years in Production Operations Management. Including design, engineering, construction and project implementation, commissioning and decommissioning both on and offshore in the upstream Oil and Gas industry with Hess, Petro Canada, Foster Wheeler and others. Qualifications in Business Administration (MBA), Mechanical and Production Engineering (HND), Marketing (Dip.M). Member of the Chartered Institute of Marketing. Background in civil and mechanical engineering. Impressive track record of safely implementing numerous successful major projects and optimising production operations for Blue Chip Companies. Strategic insight, innovation, creativity and versatility in a variety of senior positions with technical and commercial responsibility where motivation and management of people is paramount. James Chance Commercial Director James Chance spent five years as an oil and gas banker with Standard Chartered, most recently as a director managing the bank s relationships with E&P companies and integrated energy companies across corporate finance, advisory, financial markets and transaction banking. He previously held an equivalent role at Standard Bank. Prior to that he was co-director of the MENA Division at EA, a leading risk advisory firm that is now part of IHS, where he consulted to financial and energy clients on commercial risks and opportunities in the region and was a regular commentator on financial news networks. He was previously a speechwriter and advisor to Prince Hassan of Jordan. He holds an MBA from London Business School, a 1st from Oxford and an MA and PhD from London. 28 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

29 Gavin Milne Group Financial Controller Gavin has been with the Company since October 2016 and has over 25 years of finance, accounting and tax experience in the E&P Oil and Gas industry sector. Prior to joining the Company, Gavin has held several positions in the industry with companies including Sterling Energy plc, Faroe Petroleum plc, Celtique Energie, Valiant Petroleum plc, Newfield Petroleum, E.ON, Caledonia Oil & Gas, RWE, Highland Energy and initially nine years with BP Exploration. Gavin is a member of the Institute of Chartered Management Accountants and holds a BSc degree in Mathematics & Statistics from Heriot-Watt University. Doug Fenwick Technical Director Geologist and petrophysicist with 35 years oil & gas industry experience, 23 of which as a technical manager or director of an operating company. Extensive track record in leading multi-disciplinary teams, either in Exploration, Development Geoscience or in Exploration New Ventures. Founder and former CEO of MPX Energy Ltd, turning the company into an established North Sea Operator returning up to eight times initial investment for shareholders. Former MD of Serica Energy (UK) Ltd and founder technical manager of ATP Oil and Gas (UK) Ltd. Ten years in a variety of senior technical roles with Arco (now part of BP), primarily focused on the UK North Sea. Treasurer of the PESGB and PETEX over and currently Chairman of the Audit Committee of The Geological Society. Graduated from Imperial College with a M.Sc. (Distinction) in Petroleum Geology and a B.Sc. in Geology from Exeter University. Graham Cox Southern North Sea Project Manager Graham Cox has 32 years' experience in oil and gas having worked on several large developments. Graham was the Clipper South project manager and was instrumental in establishing the design and operational basis for the Clipper South offshore platform. At the point of sale to RWE he was transferred with the asset where he became the engineering manager through all phases of engineering and project completion. Colin Jones Chief Petroleum Engineer 28+ years worldwide experience, currently with DNO International on heavy oil developments. Ten years with Norsk Hydro before starting independent consultancy. Founding director of MOST Inc. Former Chairman of the Society of Petroleum Engineers, Oslo. Active in M&A, company restructuring, asset valuations, reserves auditing, on and offshore field operations and field development studies. Experience in many FSU countries and also in South America, North Africa, the Middle East and Europe. John Boyle Drilling Manager Forty years worldwide oil industry experience in both the operator and service sectors. Drilling & operational experience with Shell in Holland, Qatar and Brunei. BNOC/Britoil/BP Wells team leader for major North Sea projects and Colombia. Served as VP for two leading oil service companies in the US and a non-executive for Varel International. Joined Cairn Energy 2009 as a consultant in a senior drilling management role as part of high profile frontier exploration programme offshore Greenland. Thereafter involved in Cairn's broadening exploration programme with emphasis on the North Atlantic region. Source: IOG website and RNS 21 March Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 29

30 Valuation and financial forecasts Valuation We have valued IOG using asset level DCFs, building models on a field-by-field basis and applying risking to these individually. We then sum these together for our total company valuation, subtracting net debt and allowance for corporate administrative costs. We are broadly in line with IOG guidance for its upcoming developments on peak production, CAPEX and OPEX, and onstream timings. On a per share basis, we have allowed for full dilution from outstanding options and warrants, but also from the 10m LOG loan (with an additional 1m of accrued interest allowed for), which is currently in-the-money and convertible at 8p/share. This gives a fully diluted number of shares of 273m, versus 109m currently in issue. Were the LOG loan to fully convert, it would create significant dilution for existing shareholders, with the potential for LOG to end up with over 50% of the company depending on accrued interest and exercise of its warrants. Whether or not LOG converts the 10m loan is moot, and we include a scenario below considering the per share valuation if it does not. 30 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

31 Long-Term Oil Price General Assumptions for IOG Model US$60/bbl Onstream Timing Assumptions Blythe May 2019 Elgood October 2019 Vulcan North West June 2019 Vulcan East August 2019 Vulcan South June 2019 Harvey January 2022 Skipper January 2023 Peak Production Assumptions Blythe (Initial Level) Elgood (Initial Level) Vulcan North West Vulcan East Vulcan South Harvey Skipper 50mmcf/d 38mmcf/d 48mmcf/d 25mmcf/d 42mmcf/d 40mmcf/d 10mbbl/d CAPEX Assumptions Blythe Elgood Vulcan North West Vulcan East Vulcan South Harvey Skipper US$12.8/boe US$8.5/boe US$4.4/boe US$4.1/boe US$5.8/boe US$7.5/boe US$15.0/boe OPEX Assumptions Variable Blythe Elgood Vulcan North West Vulcan East Vulcan South Harvey Skipper OPEX Assumptions Fixed Blythe Elgood Vulcan North West Vulcan East Vulcan South Harvey Skipper US$1.6/boe US$1.6/boe US$1.6/boe US$1.6/boe US$1.6/boe US$1.6/boe US$25.0/boe US$3.5m/year US$1.9m/year US$3.5m/year US$1.9m/year US$3.5m/year US$3.5m/year US$0.0m/year Corporation Tax Rate 30% Supplementary Charge Rate 10% UKCS Investment Allowance 62.5% Inflation 2.0% Long-Term US$/ 1.3 Discount Rate (Nominal) 10% Discount as of End 2017 Source: Arden Partners Research. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 31

32 We have run our NAV on four different scenarios, sensitising for gas price, CAPEX and onstream timing. We also run a scenario where LOG does not convert its 10m loan (but all options and warrants are still considered dilutive), though we note that at 8p/share this is currently strongly in-the-money. These return risked values ranging from 125.8p/share to 35.1p/share, demonstrating the sensitivity to gas price and LOG debt conversion in particular. Long-Term Gas Price Onstream Timing CAPEX NOSH Source: Arden Partners Research. Scenario 1 40p/therm As general assumptions As general assumptions 273m Net Asset Valuation Scenario 1 Field Class Gross Liquids mmbbl Gross Gas bcf Gross Pet m mmboe WI Net Liquids mmbbl Net Gas bcf Net Pet m mmboe Unrisked US$/boe Unrisked US$m Unrisked m Unrisked p/sh Risk Risked US$m Risked m Risked p/sh Net Cash/(Debt) (18.6) (14.3) (5.3) Admin Costs (7.0) (5.4) (2.0) CORE NAV (25.6) (19.7) (7.2) Development Blythe 2P % % Elgood 2C % % Vulcan NW 2C % % Vulcan East 2C % % Vulcan South 2C % % Total Development Appraisal Skipper 2C % % Harvey PR % % Total Appraisal TOTAL NAV Source: Arden Partners Research. Scenario 1 - Risked NAV Sensitivity to Gas Price and Discount Rate Long Term Gas Price (p/therm) % % % % % Source: Arden Partners. 32 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

33 Long-Term Gas Price Onstream Timing CAPEX NOSH Source: Arden Partners Research. Scenario 2 45p/therm As general assumptions Minus 10% from our general assumptions 273m Net Asset Valuation Scenario 2 Field Class Gross Liquids mmbbl Gross Gas bcf Gross Pet m mmboe WI Net Liquids mmbbl Net Gas bcf Net Pet m mmboe Unrisked US$/boe Unrisked US$m Unrisked m Unrisked p/sh Risk Risked US$m Risked m Risked p/sh Net Cash/(Debt) (18.6) (14.3) (5.3) Admin Costs (7.0) (5.4) (2.0) CORE NAV (25.6) (19.7) (7.2) Development Blythe 2P % % Elgood 2C % % Vulcan NW 2C % % Vulcan East 2C % % Vulcan South 2C % % Total Development Appraisal Skipper 2C % % Harvey PR % % Total Appraisal TOTAL NAV Source: Arden Partners Research. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 33

34 Long-Term Gas Price Onstream Timing CAPEX NOSH Source: Arden Partners Research. Scenario 3 35p/therm Six months later than our general assumptions Plus 20% from our general assumptions 273m Net Asset Valuation Scenario 3 Field Class Gross Liquids mmbbl Gross Gas bcf Gross Pet m mmboe WI Net Liquids mmbbl Net Gas bcf Net Pet m mmboe Unrisked US$/boe Unrisked US$m Unrisked m Unrisked p/sh Risk Risked US$m Risked m Risked p/sh Net Cash/(Debt) (18.6) (14.3) (5.3) Admin Costs (7.0) (5.4) (2.0) CORE NAV (25.6) (19.7) (7.2) Development Blythe 2P % % Elgood 2C % % Vulcan NW 2C % % Vulcan East 2C % % Vulcan South 2C % % Total Development Appraisal Skipper 2C % (1.2) (31.9) (24.5) (9.0) 10% (3.2) (2.5) (0.9) Harvey PR % % Total Appraisal TOTAL NAV Source: Arden Partners Research. 34 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

35 Long-Term Gas Price Onstream Timing CAPEX NOSH Source: Arden Partners Research. Scenario 4 40p/therm As general assumptions As general assumptions 135m Net Asset Valuation Scenario 4 Field Class Gross Liquids mmbbl Gross Gas bcf Gross Pet m mmboe WI Net Liquids mmbbl Net Gas bcf Net Pet m mmboe Unrisked US$/boe Unrisked US$m Unrisked m Unrisked p/sh Risk Risked US$m Risked m Risked p/sh Net Cash/(Debt) (18.6) (14.3) (10.6) Admin Costs (7.0) (5.4) (4.0) CORE NAV (25.6) (19.7) (14.6) Development Blythe 2P % % Elgood 2C % % Vulcan NW 2C % % Vulcan East 2C % % Vulcan South 2C % % Total Development Appraisal Skipper 2C % % Harvey PR % % Total Appraisal TOTAL NAV Source: Arden Partners Research. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 35

36 Financial forecasts Our financial forecasts are focused on IOG s funding position and how we expect this to evolve going forward. At the end of 2016, IOG held 0.2m of cash, with debt and payables of 14.6m and debt headroom of 5.8m. The amount of spending in 2017 will be highly dependent on the funding secured for IOG s Blythe/Elgood and Vulcan Satellites developments. Our forecasts currently only allow for the payments that will be due on the Vulcan Satellites acquisition and for the Thames pipeline, along with a contained level of CAPEX for licence fees and pre development work. This, and increased corporate overheads as development work ramps up, drive our end 2017 net debt number of 20.5m. This included a run down in payables as bills for Skipper and historic debt due to Weatherford are paid. We expect existing debt facilities to be exhausted during 2017, and for further requirements to be folded into IOG s wider development financing. In terms of cash corporate overheads, we expect these to rise to 1.5m in 2017 as work on IOG s developments ramps up. Historically the company has been able to keep cash overheads at a controlled level as management have taken large portions of salaries in share options. This has in part been based on management making up a significant portion of the staff and themselves already having significant equity stakes. It will be more difficult to sustain this as the staff grows. Profit and Loss Year 2014A 2015A 2016A 2017E 2018E Net Oil Production mbbl/d Net Gas Production mmcf/d Total Net Production mboe/d Brent Oil Price US$/bbl UK NBP Average Spot Price p/therm Sales m OPEX m Depreciation m Gross Profit m Administrative Costs m (0.7) (0.5) 0.1 (1.5) (1.5) Share Based Payments m (1.3) (0.3) (0.4) (1.2) (1.3) Exploration Expense m (0.6) (0.0) (0.7) Operating Profit m (2.7) (0.8) (1.0) (2.7) (2.8) Finance Costs m (1.1) 0.1 (0.9) (0.9) (2.0) Finance Income m Adjusted PBT m (3.8) (0.8) (1.9) (3.6) (4.9) FX Loss/(Gain) m (0.1) (0.1) (0.3) Impairment m (8.3) 6.2 (19.7) Exceptionals m Reported PBT m (12.1) 5.32 (21.4) (3.6) (4.9) Tax m Adjusted PAT m (3.8) (0.8) (1.9) (3.6) (4.9) Reported PAT m (12.1) 5.32 (21.4) (3.6) (4.9) Basic Adjusted EPS p (6.0) (1.1) (2.0) (3.3) (4.5) Basic Reported EPS p (19.2) 7.44 (23.2) (3.3) (4.5) Adjusted EPS p (6.0) (1.1) (2.0) (3.3) (4.5) Diluted Reported EPS p (19.2) 6.52 (23.2) (3.3) (4.5) Average Number of Shares m Average Dilutive Shares m Source: Arden Partners Research. 36 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

37 Balance Sheet Year 2014A 2015A 2016A 2017E 2018E Non-Current Assets Exploration and Evaluation Assets m Development/Producing Assets m Total Non-Current Assets m Current Assets Receivables m Derivative Financial Asset m Cash and Cash Equivalents m Total Current Assets m TOTAL ASSETS m Non-Current Liabilities Loans m (4.1) (4.1) (4.1) Trade and Other Payables m (1.6) (0.3) (5.8) Total Non-Current Liabilities m (1.6) (0.3) (9.9) (4.1) (4.1) Current Liabilities Loan Notes m (0.5) -- (4.7) (16.4) (20.0) Trade and Other Payables m (0.2) (2.6) Provision m (3.6) (3.6) (3.6) Total Current Liabilities m (0.7) (2.6) (8.3) (20.0) (23.6) TOTAL LIABILITIES m (2.2) (2.9) (18.2) (24.1) (27.6) Equity Called Up Equity Share Capital m Share Premium Account m Convertible Debt Option Reserve m Share Based Payment Reserve m Retained (Deficit)/Earnings m (13.6) (8.3) (28.9) (32.5) (37.3) Total Shareholders' Equity m (4.3) (6.7) (10.3) TOTAL LIABILITIES AND EQUITY m Source: Arden Partners Research. Oil & Gas Producers (AIM) Independent Oil and Gas# Initiating coverage 37

38 Cash Flow Year 2014A 2015A 2016A 2017E 2018E Operating Cash Flow Reported PAT m (12.1) 5.3 (21.4) (3.6) (4.9) Adjustments m (0.1) (0.0) Share Based Payments m Impairment/Writeoffs m 8.3 (6.2) Exceptionals m (0.5) FX m Net Interest m 1.1 (0.1) EBITDA m (1.5) (0.5) (0.6) (1.5) (1.5) Change in Receivables m 0.1 (0.1) Change in Payables m (5.8) -- Operating Cash Flow m (1.2) (0.5) 5.3 (7.3) (1.5) Investing Cash Flow Exploration/Appraisal CAPEX m (0.5) (0.5) (10.6) Development CAPEX m (0.8) (2.5) -- Acquisitions (Net) m (3.6) (1.3) -- Investing Cash Flow m (0.5) (0.5) (15.0) (3.8) -- Financing Cash Flow Net Equity Issue m 0.5 (0.4) Loan Note Issue m 0.5 (0.2) Derivatives m Net Cash Interest m Financing Cash Flow m 1.0 (0.1) Net Change in Cash m (0.7) (1.1) 0.2 (0.2) -- Source: Arden Partners Research. Net Debt Year 2014A 2015A 2016A 2017E 2018E Cash and Cash Equivalents m Non Current Trade Payables m (1.6) (0.3) (5.8) Current Trade Payables m (0.2) (2.6) Non Current Loans m (4.1) (4.1) (4.1) Current Loans m (0.5) -- (4.7) (16.4) (20.0) Net Cash/(Debt) m (1.8) (2.8) (14.3) (20.5) (24.1) Source: Arden Partners Research. 38 Independent Oil and Gas# Initiating coverage Oil & Gas Producers (AIM)

39 General disclosure This research material is a marketing communication and has not been prepared in accordance with legal requirements designed to promote the independence of research and is not subject to any legal prohibition on dealing ahead of dissemination. We do not hold out this research material as an impartial assessment of the values or prospects of the company. Research comment and recommendations have been independently produced by our research department unless otherwise attributed. The material regarding the subject company is based on data obtained from sources we deem to be reliable; it is not guaranteed as to accuracy and does not purport to be complete. This report is solely for informational purposes and is not intended to be used as the primary basis of investment decisions. Arden Partners has not assessed the suitability of the subject company for any person. 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40 Arden Partners plc 125 Old Broad Street London EC2N 1AR Tel: Fax: Arden Partners plc Arden House Highfield Road Birmingham B15 3DU Tel: Fax: Arden Partners plc Broad Quay House Prince Street Bristol BS1 4DJ Tel: Fax: Distribution Sales Trading Research Donald Brown Matthew Groves Jonathan Keeling James Reed-Daunter Charlotte Ridler Sarah-Jane Woodcock Dean Appleby Paul Brotherhood Marc Downes Chris Rylands Market Making Alan Jones James McAuslan Ian Berry Daniel Slater Ben Thefaut Chris Thomas Trade Support Marcus Gehling Arden Partners plc is authorised and regulated by the Financial Conduct Authority and is a member of the London Stock Exchange. Registered in England: no Registered Office: Arden House, 17, Highfield Road, Edgbaston, Birmingham, B15 3DU.