Daniel Slater, CFA [email protected] 020 7614 5947 3 November 2017 Oil & Gas Producers (AIM) IOG.L Independent Oil and Gas# Buy CPR and project funding update Current 24p Target 55p (from 60p) IOG recently released a new CPR for its Southern North Sea Key Data development project, and struck a number of important cost Market Capitalisation £25.8m Shares in Issue 110m deferral agreements with services companies. Development Free Float 77.1% funding is increasingly the focus, and we expect further cost Average Daily Volume 858,936 deferrals to be announced. Beyond this, we see a string of 12-Months Trading Range 12.5p to 25.6p catalysts as the project is developed and brought on to production to provide impetus for the shares. Financial Forecasts Yr to 31 December 2016A 2017E 2018E (cid:1) CPR updates. The CPR allocates 2P reserves across IOG’s five field Sales £0.0m £0.0m £0.0m development of 300bcf. It also takes a view on onstream timing (over June Operating Profit (£1.0m) (£2.7m) (£2.8m) 2019-March 2020), peak rate (>200mmcf/d) and total CAPEX (£449m). Adjusted PBT (£1.9m) (£3.6m) (£4.9m) Adjusted EPS (2.0p) (3.3p) (4.5p) (cid:1) Updated model. We have updated our model based on the CPR and EPS Growth - - - company guidance, using the 300bcf 2P reserves (we had used 389bcf of P/E - - - 2P/2C), a CAPEX number of £418m (assuming some savings versus the EV/EBITDA - - - CPR, we had used £296m), and the same onstream timings/production Dividend - - - Yield - - - assumptions. We also update our UK gas price to 42p/therm. Total risked Dividend Cover - - - NAV moves from 62.2p to 57.3p, unrisked NAV from 138.6p to 99.7p. Net Cash/(Debt) (£14.3m) (£20.5m) (£24.1m) (cid:1) LOIs show funding progress, more to come. IOG has been Interest Cover - - - making important progress on funding, announcing LOIs with Schlumberger, Heerema and ODE that we expect to lead to cost deferrals Price Performance until after first gas of 50% or above. We expect further agreements for the 1 Month +54.6% 3 Months +55.8% SURF and drilling parts of the project. 12 Months +35.8% (cid:1) Developments not yet fully funded. IOG’s plan is for cash flows from the fields that come onstream earlier (Blythe, Elgood, Southwark) to Price Performance (p) help fund the later fields (Nailsworth, Elland). Our analysis shows that if 40 existing and additional cost deferrals plus phase 1 cash flows fully fund 35 phase 2, additional external funding of £94m is still likely to be required. 30 This could come from offtake prepay, other debt, or equity. 25 20 (cid:1) Forward plans drive catalysts. Over the coming months, in addition 15 to progressing its technical work, IOG will be looking to complete funding 10 for its projects, targeting FID at the end of Q1 2018. We then expect 5 periodic development updates, followed by first gas in June 2019 and 0 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 ramp up thereafter. There is also the potential for production acquisitions. Source: Bloomberg. (cid:1) Buy recommendation. Attribution of reserves in the CPR is an important step, with the confidence around these and the other project parameters making up for lower overall gas volumes and higher CAPEX versus our previous assumptions. The project is increasingly taking shape, funding is progressing well, and we can see a string of potential catalysts over the next two years. Buy, 55p price target (from 60p). *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. Arden Partners plc is authorised and regulated by the Financial Conduct Authority and is a member of the London Stock Exchange. www.arden-partners.co.uk 3 November 2017 CPR and model updates The recent CPR for the Blythe/Elgood and Vulcan Satellites hubs contained three key updates: the graduation of contingent resources into reserves, a view on onstream timing and production assumptions, and a view on CAPEX. Upgrade of contingent resources into reserves There was significant graduation of resources into reserves, with a concurrent reduction in overall volumes. The Blythe field has already been allocated reserves, and these were revised down in the CPR. IOG’s other development assets, Elgood and the Vulcan Satellites, all had reserves allocated, alongside the removal of their entire contingent resource allocation. The upgrade from contingent resources to reserves is significant, as it shows the confidence added by the extensive seismic interpretation, geological and reservoir modelling work IOG has now carried out on the assets, as well as demonstrating third party verification from ERC Equipoise. This should all help contribute to the achievement of FID, which is planned for the end of Q1 2018. IOG CPR Reserves and Resources Updates Asset Previous Assumed Position 2P Reserves from CPR Blythe 42bcf 2P reserves 33bcf Elgood 27bcf 2C resources 21bcf Nailsworth 131bcf 2C resources 98bcf Elland 77bcf 2C resources 54bcf Southwark 112bcf 2C resources 93bcf Source: ERCE, TRACS, IOG. IOG has also released a CPR on its Harvey structure, confirming P50 prospective resources of 114bcf (we had assumed 113bcf previously), of which 90bcf are on currently licensed IOG acreage. The company has now committed to the OGA to drill a well on the structure within two years (planned for 2019), and on success we would expect the company to request the whole structure is licensed to IOG. Expected peak production rate of >200mmcf/d The production forecast assumptions used in the CPR across IOG’s five development assets aggregate to a peak production rate in excess of 200mmcf/d, above the 160mmcf/d that we had been assuming. While this rate swiftly declines (more so now given the lower total gas number), it nevertheless brings expected cash flows forward, increasing the value of these for IOG. CPR CAPEX estimate of £449m The CPR also includes ERC Equipoise’s estimate of the total CAPEX for IOG’s Blythe/Elgood and Vulcan Satellites projects, which aggregates to £449m. For comparison, we had been assuming a total CAPEX bill of £296m, and are now moving this to £418m. IOG’s current plan is to execute the project in two phases – Blythe, Elgood and Southwark as phase 1, followed by Elland and Nailsworth as phase 2. This is in line with the scheduling in the CPR. The total CAPEX bill would be split broadly evenly across these, with initial cash flows from phase 1 helping cover the CAPEX for phase 2. We discuss this further below. 2 Independent Oil and Gas# – CPR and project funding update | Oil & Gas Producers (AIM) 3 November 2017 Model updates We have updated our IOG model based on the CPRs and IOG guidance. We have replaced the 389bcf of 2P reserves/2C resources we had been using across Blythe/Elgood and the Vulcan Satellites with the 300bcf of 2P reserves in the CPR. We have updated our £296m overall CAPEX estimate for the project to £418m, updated our OPEX assumptions, and also our CAPEX distribution and onstream timing assumptions based on the CPR. We have also increased our risking factors on the five fields to 70%. Onstream Timing Assumptions Field Onstream Timing Blythe June 2019 Elgood September 2019 Nailsworth December 2019 Elland March 2020 Southwark June 2019 Source: Arden Partners Research. In addition, we have upgraded our long-term UK NBP gas price deck from 40p/therm to 42p/therm based on the move in the forward curve over the last few months. UK NBP Gas Prices and Forward Curve 100 95 90 85 80 75 70 65 60 bl 55 /b 50 S$ 45 U 40 35 30 25 20 15 10 5 0 Source: Bloomberg. These changes have the combined effect of reducing our total risked NAV from 62.2p/share to 57.3p/share, and total unrisked NAV from 138.6p/share to 99.7p/share. The reduced overall bcf gas number and higher CAPEX are counteracted by the higher risking factors and increased gas price. Our NAV uses a fully diluted number of shares of 260m, which assumes the £10m LOG debt converts at 8p/share. Were this to happen, along with other dilutive instruments, it could give LOG over 50% of plc equity. We discuss this further, and provide a fuller analysis of the company and its strategy, in our Initiating Coverage note of 26 May 2017. Oil & Gas Producers (AIM) | Independent Oil and Gas# – CPR and project funding update 3 3 November 2017 Net Asset Valuation – 42p/therm Gross Gross Gross Net Net Net Unrisked Unrisked Unrisked Unrisked Risked Risked Risked Class Liquids Gas Pet’m WI Liquids Gas Pet’m Value Value Value Value Risk Value Value Value Field mmbbl bcf mmboe mmbbl bcf mmboe US$/boe US$m £m p/sh US$m £m p/sh Net Cash/(Debt) (18.6) (14.3) (5.5) Admin Costs (7.0) (5.4) (2.1) CORE NAV (25.6) (19.7) (7.6) Development Blythe 2P 0.3 33 6 100% 0.3 33 6 4.1 24.2 18.6 7.2 70% 16.9 13.0 5.0 Elgood 2P 0.2 21 4 100% 0.2 21 4 4.2 15.9 12.2 4.7 70% 11.1 8.5 3.3 Nailsworth 2P 1.0 98 17 100% 1.0 98 17 6.4 110.1 84.7 32.6 70% 77.1 59.3 22.8 Elland 2P 0.0 54 9 100% 0.0 54 9 3.3 29.5 22.7 8.7 70% 20.7 15.9 6.1 Southwark 2P 0.1 93 16 100% 0.1 93 16 6.2 96.7 74.4 28.6 70% 67.7 52.1 20.0 Total Development 2 300 52 2 300 52 276.4 212.6 81.9 193.4 148.8 57.3 Appraisal Skipper 2C 26 -- 26 100% 26 -- 26 0.1 1.4 1.1 0.4 10% 0.1 0.1 0.0 Harvey PR -- 114 19 100% -- 114 19 4.5 84.6 65.1 25.0 30% 25.4 19.5 7.5 Total Appraisal 26 114 45 26 114 45 86.0 66.1 25.5 25.5 19.6 7.6 TOTAL NAV 336.7 259.0 99.7 193.3 148.7 57.3 Source: Arden Partners’ Research. Valuation scenarios We have used our model to run a number of scenarios, based on changes to project timing, CAPEX quantum, and gas prices. IOG Valuation Scenarios Scenario Long-Term Gas Onstream CAPEX Risked Unrisked Price Timing NAV NAV Base Case 42p/therm As above £418m 57.3p 99.7p Downside Case 35p/therm 6 month delay +20% 13.6p 32.3p all fields Upside Case 50p/therm As above -10% 92.5p 156.1p Source: Arden Partners’ Research. Funding progress – LOIs with oil services contractors IOG is progressing its development programmes holding 100% of its projects. The company is looking for funding from a range of sources, and has made a number of announcements in this regard in recent weeks. These have concerned the signing of letters of intent (LOI) with several oil services contractors aimed at deferring a substantial portion of project CAPEX until after cash flows from the fields actually come through. Depending on exact terms (which have not been announced), this is effectively a form of debt funding. So far IOG has signed three LOIs. The first was with Schlumberger, and included a Consultancy Master Services Agreement for the developments, though no details of any 4 Independent Oil and Gas# – CPR and project funding update | Oil & Gas Producers (AIM) 3 November 2017 actual funding deferral have been given. We assume the services piece that Schlumberger would likely be responsible for would likely be around 18% of total project CAPEX. The second was with platform fabricator Heerema for the FEED and EPCI work for up to four platforms, with 100% of FEED costs and 50% of EPCI costs to be deferred until first gas. We expect these costs to comprise around 27% of total project CAPEX. The third was with Offshore Design Engineering (ODE) for technical and operational support in the development phase and operations and maintenance services in the production phase, with 100% of related pre-FID costs to be deferred until first gas, and 50% of post-FID (and pre-first gas) costs. We expect these costs to make up around 1% of total project CAPEX. The cost deferrals already agreed apply to total project CAPEX, with deferred costs beginning to be paid down on first gas from phase 1, but with new deferrals for phase 2 costs helping to offset this. Forward funding strategy IOG has already had good success in agreeing its LOIs, and we expect that more of these could come through, principally for the SURF (around 25% of total) and drilling (around 29% of total) pieces. We expect that IOG would then essentially split its development of the five fields into two phases, with five development wells in each phase. Blythe, Elgood and Southwark will form the first phase, coming onstream over June to September 2019. Cash flows from these are then planned to be recycled to help finance the second phase, which will consist of Nailsworth and Elland, and these two fields are planned onstream over December 2019 to March 2020. These dates are in-line with the CPR. This plan should help reduce the amount of external funding required, but it does create risk to funding phase 2 of the project if the cash flows from phase 1 are not as expected. IOG Development Funding Position CAPEX Item % of Contractor Phase 1 Phase 2 Assumed Cost Quantum Quantum Total CAPEX CAPEX % Deferred Deferred Deferred (£m) (£m) Deferred Assumption Phase 1 Phase 2 Services 18% Schlumberger 39 36 85% Arden/LOI £33m £31m Platforms 27% Heerema 59 54 50% LOI £29m £27m Technical/Operational 1% ODE 2 2 50% LOI £2m £2m Support SURF 25% TBC 54 50 50% Arden £27m £25m Drilling 29% TBC 63 58 50% Arden £31m £29m Phase 1 Phase 2 Total Existing Deferral (including Schlumberger) £65m £60m Total Assumed Deferral £123m £114m Total CAPEX £217m £202m CAPEX Gap Post Existing Deferral £152m £141m CAPEX Gap Post Assumed Total Deferral £94m £87m Source: Arden Partners’ Estimates. Notes: Assumes pre-FID costs are minimal relative to the total CAPEX bill. The table above calculates that post all assumed cost deferrals, the company is likely to need further external development funding in the region of £94m for phase 1. The current plan is then for a combination of cost deferrals and phase 1 cash flows to fully Oil & Gas Producers (AIM) | Independent Oil and Gas# – CPR and project funding update 5 3 November 2017 fund phase 2 (in our table this would mean phase 1 cash flows funding the £87m phase 2 CAPEX gap). To help meet this phase 1 requirement, IOG is looking at securing funding via offtake prepay: selling its gas production forward to a trader in return for cash upfront that can then be used to fund project CAPEX – again essentially a form of debt funding. This would also be likely to begin being paid off on first gas from phase 1. We could see news on an offtake prepay agreement in the coming months. To complete its development funding requirements, we also expect that IOG may require some conventional project debt (possibly in place of the offtake prepay) and/or equity, depending on the exact magnitude of phase 1 CAPEX and cost deferrals. Short-term funding position IOG has no existing revenues, and held £0.2m of cash at the end of June 2017. Overheads are running at £1.5m per year. Remaining headroom on debt facilities was an implied £4.2m at the end of June, providing ongoing liquidity to support the company’s development programmes. The deferral of pre-FID costs under the various LOIs with oil services contractors is also likely to help here. Total debt at the end of June was £15.3m, of which £6.6m was debt and contractor payables relating to the 2016 Skipper well which are due at the end of 2017. We expect that IOG is likely to be seeking a rescheduling and part conversion into IOG plc equity of its Skipper contractor payables. The intelligent pigging operations to confirm integrity of the Thames pipeline are also coming up in Q1 2018, and are expected to cost £4.3m (£1.7m for site surveys, and £2.6m for the actual pigging operation – some or all of these could potentially also be up for deferral). As such, IOG may need a measure of additional short-term liquidity, alongside its long-term funding arrangements. Forward work programme and upcoming catalysts IOG’s current work plan is targeting first gas towards the end of Q2 2019, with all five fields onstream by Q1 2020. Between now and then there is a string of potential catalysts, with FID for the entire project targeted for the end of Q1 2018, prior to which we would expect to see the key catalyst of the securing of full funding for the developments. There will also be the results of the intelligent pigging of the Thames pipeline, likely to be a formality but nevertheless very important to confirm the integrity of this offtake route for the project. Post FID there would then be periodic updates on development, which we would expect to provide steady share price progress, with further, steeper upside on first gas at the end of Q2 2019. During this period there is also the potential for the addition of further resources via appraisal drilling of the 114bcf Harvey structure (resources for which were confirmed in another recent CPR). We could also potentially see production acquisitions. In this way, IOG has an identified route to becoming a significant producing E&P company, but also a full newsflow schedule to support positive share price performance while it pursues this. In our view, securing full funding remains the key to unlocking the potential of the company’s asset position. 6 Independent Oil and Gas# – CPR and project funding update | Oil & Gas Producers (AIM) 3 November 2017 IOG Planned Work Programme Source: IOG. Oil & Gas Producers (AIM) | Independent Oil and Gas# – CPR and project funding update 7 3 November 2017 Project summary IOG’s upcoming project consists of development of five gas fields in the UK southern North Sea, via two newbuild hubs. The Blythe hub is planned to develop the Blythe and Elgood fields (with the potential to tie-in the Harvey prospect once this is appraised), and the Vulcan Satellites hub to develop the Nailsworth, Elland and Southwark fields. These are all then planned to be tied-in to the 24 inch Thames pipeline, which IOG is in the process of acquiring from Perenco. The Thames pipeline was shut down in 2015 due to decline of the fields connected to it (as opposed to reaching the end of its life). IOG expects that the pipeline will be able to last for the life of its developments, and that it will have capacity well in excess of the company’s peak production rate. Intelligent pigging operations are planned to confirm all of this. The pipeline will take the gas to the Bacton terminal on the Norfolk coast, which has total capacity of 1,900mmcf/d, of which 270mmcf/d was utilised in 2016 according to Woodmac. Since then the 660bcf Cygnus development has come onstream, but IOG remains confident there will be enough capacity at Bacton for its projects (particularly given that these quickly peak to 200mmcf/d before declining). IOG also holds 100% in the 114bcf Harvey structure. This requires appraisal (a well is planned for 2019), but on success it could also be tied in and commercialised via the Thames pipeline. Harvey hence represents a source of upside beyond current development plans. IOG Asset Map Source: IOG. 8 Independent Oil and Gas# – CPR and project funding update | Oil & Gas Producers (AIM) 3 November 2017 Financial forecasts Our financial forecasts are unchanged. 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 99 60 44 50 55 UK NBP Average Spot Price p/therm 50 43 35 40 42 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 -- -- 0.5 -- -- Reported PBT £m (12.1) 5.3 (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) 5.3 (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) 6.5 (23.2) (3.3) (4.5) Average Number of Shares m 63.3 71.5 92.5 109.3 109.3 Average Dilutive Shares m 13.1 10.1 41.9 49.5 49.5 Source: Arden Partners’ Research. Oil & Gas Producers (AIM) | Independent Oil and Gas# – CPR and project funding update 9 3 November 2017 Balance Sheet Year 2014A 2015A 2016A 2017E 2018E Non-Current Assets Exploration and Evaluation Assets £m 7.5 14.8 5.8 7.1 7.1 Development/Producing Assets £m -- -- 7.5 10.0 10.0 Total Non-current Assets £m 7.5 14.8 13.4 17.1 17.1 Current Assets Receivables £m 0.0 1.5 0.3 0.3 0.3 Derivative Financial Asset £m 0.3 -- -- -- -- Cash and Cash Equivalents £m 0.4 0.0 0.2 -- -- Total Current Assets £m 0.7 1.5 0.5 0.3 0.3 TOTAL ASSETS £m 8.2 16.3 13.9 17.4 17.4 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 0.7 0.8 1.1 1.1 1.1 Share Premium Account £m 17.2 17.6 20.6 20.6 20.6 Convertible Debt Option Reserve £m -- -- -- -- -- Share-based Payment Reserve £m 1.8 3.3 2.9 4.1 5.4 Retained (Deficit)/Earnings £m (13.6) (8.3) (28.9) (32.5) (37.3) Total Shareholders' Equity £m 6.0 13.5 (4.3) (6.7) (10.3) TOTAL LIABILITIES AND EQUITY £m 8.2 16.3 13.9 17.4 17.4 Source: Arden Partners’ Research. 10 Independent Oil and Gas# – CPR and project funding update | Oil & Gas Producers (AIM)