26 August 2021

1H 2021 Interim Results

IOG plc ("IOG" or the "Company" or "Group") (AIM: IOG.L), the Net Zero UK gas and infrastructure operator focused on high return projects, is pleased to present its unaudited interim results for the six months ended 30 June 2021.

Corporate and Operational Highlights

·      Core Project and associated Thames infrastructure renamed as the Saturn Banks Project and Saturn Banks Pipeline System ("SBPS"), a reference to local seabed features in the Southern North Sea ("SNS")

·      Fabrication, transportation and installation of both the Saturn Banks Phase 1 Normally Unmanned Installations ("NUIs") at Blythe and Southwark successfully completed

·      Key subsea installation activities include laying of 12" Blythe line and 6" Elgood line, which are to be connected to the Blythe platform and Elgood wellhead ahead of First Gas  

·      Phase 1 development drilling campaign kicked off with spud of Elgood well 48/22c-7 in April 2021 by the Noble Hans Deul jack-up rig, with Petrofac as Well Operator and Schlumberger as key drilling services contractor

·      ODE Asset Management awarded the Phase 1 Duty Holder contract for Installation and Pipeline Operator, as well as facilities operations and maintenance ("O&M")

·      Refurbishment and recommissioning process for the co-owned Saturn Banks Reception Facilities continued to progress at the Bacton Gas Terminal ("BGT") to prepare for First Gas

·      3D seismic reprocessing to Pre-Stack Depth Migration ("PSDM") significantly improved the potential for two new incremental high-return gas hubs, a northern hub in P2438 and a southern hub in P2442

o  In licence P2438, gross management estimated 2C contingent resources at Goddard increased from 108 billion cubic feet equivalent¹ ("Bcfe") to 132 Bcfe, with Southsea prospect also identified  

o  In licence P2442, gross management estimated 2C contingent resources at Abbeydale increased from 6 Bcfe to 23 Bcfe

o  Kelham North and Kelham Central structures in licence P2442 with gross management estimated prospective resources of 36 Bcfe and 42 Bcfe, with 80% and 70% Geological Chance of Success ("GCoS"), respectively

o  Thornbridge prospect also identified in licence P2442 with gross management estimated prospective resources of 58 Bcfe and 32% GCoS

o  Both the P2438 and P2442 licences are held 50:50 between IOG and its Joint Venture ("JV") partner CalEnergy Resources Limited ("CER"), and operated by IOG      

·      Further organisational strengthening in key positions, notably Chief Operating Officer David Gibson

Financial Highlights

·      Cash balance at period end of £59.0 million (31 December 2020: £80.4 million), including restricted cash of £3.4 million (31 December 2020: £67.0 million)

·      Post-tax profit for the period of £0.2 million (30 June 2020: £3.6 million loss)

·      Group net debt² at period end of £32.2 million (31 December 2020: £14.1 million)

·      Phase 1 development carry from JV partner CER fully utilised in Q2 2021

·      Further €65.8 million (£59.2 million equivalent) drawdowns made from the senior secured bond ("Bond") escrow account for development expenditure, against operational milestones as planned, completing the full drawdown of the escrow account

·      These interim results are presented on a Going Concern basis further to management's reasonable expectation that the Company continues to have sufficient funding to deliver First Gas

Post-Period End Highlights

·    Elgood subsea well flowed successfully on clean-up at a maximum rate of 57.8 mmscf/d gas and 959 bbl/d condensate through an 80/64^th inch choke

·    Blythe well spudded on 2 August 2021 and is expected to be completed within three months

·    Gas sales agreement ("GSA") signed with Gazprom Marketing & Trading ("GM&T") for the first two years of Elgood and Southwark production, plus Nailsworth and Elland, after a competitive offtake process 

·    Commitment to Scope 1 & 2 Net Zero from 2021 with Emissions Assessment demonstrating the very low emissions profile of the Saturn Banks Project Phase 1

·    Elgood umbilical laid as part of ongoing summer 2021 subsea installation campaign 

·    Safety Cases for the Blythe and Southwark platforms accepted by the UK Health and Safety Executive ("UK HSE")

Expected Future Activity

·      Phase 1 First Gas expected in Q4 2021 on completion of the Blythe well and onshore recommissioning activities

·      Pipelay campaign to install 6km extension of the 24" Saturn Banks pipeline to the Southwark field expected in Q1 2022, ahead of Southwark first gas expected in Q2 2022

^{1 Billion cubic feet equivalent ("Bcfe") incorporates gas plus condensate based on a ratio of 5.8 thousand cubic feet (mcf) per barrel of condensate}    

^{2 Net debt is defined as restricted cash (£3.4 million) plus cash and cash equivalents (£55.6 million) plus financial assets (£1.4 million), less outstanding loans (£92.6 million)}

Andrew Hockey, CEO of IOG, said:

"Over 2021 to date we have delivered a series of key Phase 1 progress milestones on the path to First Gas in Q4. To reach this target two years after FID amid a prolonged global pandemic will be a fantastic achievement by the IOG team. I would like to thank them for their continued hard work and dedication in delivering on our ambition to be a safe, efficient, low-carbon developer and producer of high-value gas, whilst also recognising the support and collaboration of our Joint Venture partner CER, contractors and regulators.

Having installed the Blythe and Southwark platforms and successfully tested the Elgood well at 57.8 mmscf/d gas and 959 bbl/d condensate, the Blythe development well is now progressing to plan, with Southwark to follow. Beyond Phase 1, we are working up the excellent potential to expand our Saturn Banks Pipeline System with further high-return gas hubs. Alongside this, we were very pleased to confirm our very low emissions operating model and commitment to Scope 1 and 2 Net Zero from 2021."

This announcement contains inside information for the purposes of Article 7 of the Market Abuse Regulation (EU) 596/2014 as it forms part of UK domestic law by virtue of the European Union (Withdrawal) Act 2018 ("MAR"), and is disclosed in accordance with the company's obligations under Article 17 of MAR.

Enquiries:

Notes

About IOG:

IOG owns and operates a 50% stake in substantial low risk, high value gas reserves in the UK Southern North Sea. The Company's Saturn Banks Project targets a gross 2P peak production rate of 140 MMcfe/d (c. 24,000 Boe/d) from gross 2P reserves of 302 Bcfe³ and management estimated 2C contingent resources of 132 Bcfe, via an efficient hub strategy based on co-owned infrastructure. In addition to its 2P reserves at Blythe, Elgood, Southwark, Nailsworth and Elland and 2C contingent resources at Goddard, it has management estimated gross 2C contingent resources of 23 Bcfe at Abbeydale and gross unrisked mid-case prospective resources of 36 Bcfe at Kelham North, 42 Bcfe at Kelham Central, 58 Bcfe at Thornbridge, 31 Bcfe at Southsea, 28 Bcfe and 19 Bcfe in the two Goddard flank structures, and 21 Bcfe at Harvey. IOG also holds a 50% operated stake in Licence P2589 containing the Panther and Grafton gas discoveries with management estimated gross mid-case contingent resources of 46 Bcfe and 35 Bcfe respectively. In addition IOG continues to pursue value accretive acquisitions to help generate significant shareholder returns.

³ ERC Equipoise Competent Persons Report: October 2017, adjusted by Management to account for updated project timing and compression

Further information can be found at www.iog.co.uk 

The Directors present their interim report of operations and unaudited consolidated financial statements of IOG plc ("the Company") and its subsidiaries ("the Group") for the six months ended 30 June 2021. All amounts are shown in Pounds Sterling, unless otherwise stated.

This interim financial report is the responsibility of and has been approved by the Directors. The Directors are responsible for preparing the Interim Report which has been reviewed, but not been audited by the Company's auditors. In addition to the results for the first six months of 2021 ("1H 2021"), comparative information is provided for the six months ended 30 June 2020 ("1H 2020"). Comparative information for the Group's financial position is also provided for the year ended 31 December 2020 ("FY 2020").

As disclosed in note 1, the annual financial statements of the Group are prepared in accordance with International Financial Reporting Standards ("IFRSs") as adopted for use in the UK.

Chief Executive Review

I am very pleased to release our interim report for the half-year period to 30 June 2021, during which we delivered a number of further key milestones for the business. It was an exciting period for IOG as we move ever closer to our first production later this year.

As we breathe new economic life into the former Thames area of the Southern North Sea ("SNS"), we have given what was hitherto referred to as the "Core Project" a fresh new identity as the "Saturn Banks Project". The name pays tribute to a series of seabed sandbank features in this part of the SNS. The former Thames Pipeline and associated onshore facilities, which we are recommissioning as the backbone of our production system, will therefore be known as the "Saturn Banks Pipeline System". In closing out the previous Thames chapter we are inaugurating a new era with an economic life stretching over the next two decades.

Over the first half of 2021 my team have continued to work incredibly hard on the successful execution of the Saturn Banks Project Phase 1, consisting of the Blythe, Elgood and Southwark fields. First Gas is expected in Q4 2021, just two years after taking Final Investment Decision ("FID"). I sincerely commend the whole team's efforts to continue executing on such a demanding schedule despite the challenges and disruptions the Covid-19 pandemic has imposed on both internal and external collaboration. Driven by our three fundamental priorities - protecting our people, delivering the project and ensuring business continuity - we have continued to respond dynamically to the restrictions that have lasted in various forms through most of the Phase 1 development period.

Since joining us as Chief Operating Officer in February of this year, David Gibson has quickly made a very positive impact on project execution. Over more than 30 years in North Sea engineering and project management roles, David has built up extensive relevant experience in development and execution of business plans focused on safe, environmentally responsible and economically sustainable operations, and we are now seeing the benefit of this at IOG. Importantly, we have also fulfilled our plans to transition to a high calibre team of full-time employees across the complete range of technical and operational disciplines, who are all working very effectively together under David's guidance to expedite Phase 1 delivery.

Thanks to a period of intense activity we have progressed Phase 1 a long way in a short time. In April, we reached mechanical completion of our two NUI platforms at Blythe and Southwark, swiftly followed by the safe and successful offshore installation of both facilities at their field locations by early June. Putting these key facilities in place was another important milestone for IOG, not just for Phase 1 but also as part of the foundations for further phases of growth. They are an integral part of our infrastructure-led hub strategy, forming pivotal links between the pipeline network that comprises our co-owned and operated Saturn Banks Pipeline System and associated onshore facilities at Bacton Gas Terminal. As small, remotely-operated installations with forecast average unmanned power demand as low as 33kW (comparable to an electric car), the Blythe and Southwark platforms also help to minimise both operating costs and carbon intensity as we scale up the business.

I congratulate HSM Offshore on an excellent job, in collaboration with our engineering team, in maintaining the fabrication, transportation and installation schedule despite the various challenges. Moving on to the operations and maintenance (O&M), in May we were pleased to award the Phase 1 Duty Holder contract for Installation and Pipeline Operator, as well as facilities O&M, to ODE Asset Management ("ODE AM"). ODE AM have a well-established track record in these roles in SNS gas projects including Babbage and Tolmount. Their focus on safe, efficient and cost-effective management will be integral to delivering low cost and low carbon intensity production operations.

During 2021 to date we have also been very busy procuring and installing connector lines and related subsea equipment to execute the Phase 1 Subsea, Umbilicals, Risers and Flowlines ("SURF") scope, in collaboration with our lead SURF contractor Subsea 7. We now have the 12" line from Blythe to the main 24" Saturn Banks Pipeline, 6" line from Elgood to Blythe, and the Elgood umbilical all in place. The remaining subsea equipment is being installed as part of the ongoing campaign on the lead-in to First Gas from the Blythe Hub this year.

In April we also kicked off the Phase 1 drilling campaign by spudding our first development well at Elgood, which will be produced as a subsea tie-back to the Blythe platform. The drilling campaign will last over a year and its success will be driven by strong collaboration between the IOG drilling, subsurface, subsea and HSE teams, our main drilling contractors Noble Corporation, Petrofac and Schlumberger, ODE AM and our partner CER, and we expect there should be some efficiency gains over the course of the campaign.

Completing the Elgood well, post period-end in July, was a significant milestone for IOG. The well was drilled horizontally through the reservoir section to a Total Depth of 15,472 ft Measured Depth (MD), intersecting 1,080 ft of high-quality Permian Leman Sandstone reservoir. Encountering some technical challenges was to be expected on the first well of the campaign drilled on the smallest and only subsea tie-back field in Phase 1. What was most important was how my team responded proactively and resourcefully to these challenges, culminating in a successful completion.

Whilst the reservoir was encountered 39 ft deep to prognosis, it was encouraging to see clean-up flow rates were ahead of expectations, with a maximum rate of 57.8 mmscf/d of gas and 959 bbl/d condensate through an 80/64^th inch choke, constrained by surface facilities on the Noble Hans Deul jack-up rig. A full technical review of the field based on new modelling and analysis of early months of production will help to determine an updated range of ultimate recoverable gas from Elgood. Combined with the very high forward gas pricing environment, with both UK NBP spot and Winter 2021 prices currently exceeding £1/therm, this suggests that early Elgood cashflows should exceed our planning base case.

Meanwhile, the Noble Hans Deul jack-up rig went on to spud the Blythe development well in early August, which is being drilled through the Blythe platform. This well has been meticulously planned with a clear collective focus on ensuring safe and efficient performance and integrating learnings from the Elgood well. It is expected to take under three months to complete, leading to First Gas in Q4 2021  

As we transition into being a material gas producer, we also remain very focused on generating further growth via incremental investments. We expect Nailsworth to be the first Phase 2 asset to be sanctioned for development and the team is progressing the necessary technical and pre-engineering work to expedite the Final Investment Decision at the earliest feasible time.

Alongside this, advancing our subsurface understanding of our Pre-Development Assets (PDAs) is crucial to this as it helps us to allocate capital appropriately, select suitable development concepts, optimise drilling designs, and ultimately to generate best shareholder value. After interpreting and mapping 1,200km² of 3D seismic data newly reprocessed to PSDM, in March we issued a technical update on our P2438 (Goddard, Southsea) and P2442 (Kelham, Abbeydale, Thornbridge) licences, operated by IOG and jointly held 50:50 with CER.

This work demonstrated enhanced potential to create two new incremental high-return gas hubs, a northern hub in P2438 and a southern hub in P2442. In line with our infrastructure-led hub strategy, these would be both be within tie-back scope of the Saturn Banks Pipeline, providing direct access to the market and helping to drive up returns. In the P2438 licence our 2C contingent resource estimates at the Goddard discovery increased from 108 Bcfe in the 2018 CPR to 132 Bcfe. Gross mid-case prospective resources on the two Goddard flank structures were revised up to 27 Bcfe and 16 Bcfe, with GCoS increased from 48% (CPR) to 71%, while the Southsea prospect was identified close by to the southeast of Goddard with management estimated gross mid-case prospective resources of 31 Bcfe and 48% GCoS.

Identification of the Kelham North and Kelham Central structures, with management estimated gross mid-case prospective resources of 36 Bcfe (70% GCos) and 43 Bcfe (80% GCoS) respectively, likewise shows the potential for a valuable multi-field gas hub in the P2442 licence. These are in addition to the gross 2C contingent resources increased to 23 Bcfe at Abbeydale, the partly on-block Orrell (previously Camlan) discovery and other prospects on the licence, notably Thornbridge with gross mid-case prospective resources of 58 Bcfe and 32% GCoS.

Post-period end we were also very pleased to confirm gas offtake arrangements for Elgood and Southwark with GM&T after a competitive process. Delivering gas into the Bacton terminal, the main import hub for the UK southeast, puts IOG in a relatively advantageous position and the gas market is currently exceptionally strong. At the time of writing, UK NBP pricing for the coming winter is at well over £1/therm and the forward curve has strengthened considerably. This is down to several factors but above all it reflects the renewed appeal of gas as the lowest-carbon fossil fuel and a fundamental pillar of our modern existence: heating homes, fuelling power stations and driving industrial activity. All the evidence suggests that, alongside the growth of renewable energies, gas will play a central role on the transition to Net Zero by 2050 or before. In an increasingly globalised gas market, healthy demand growth looks set to support pricing in Europe over coming years.

Recognising the pivotal role of gas in the energy transition, we have also been very active on the environmental front as well. In line with our ambition to be a safe, efficient and low-carbon developer and producer of high-value gas, our comprehensive Emissions Assessment (EA), led by our Environmental, Social and Governance (ESG) Taskforce, projected the cumulative average intensity of the Phase 1 Blythe and Southwark platforms at just 0.4 kgCO₂e/boe. Phase 1 lifetime Scope 1 and 2 average emissions intensity are estimated at 3.97 kgCO₂e/boe versus a North Sea average of 20.2 kgCO₂e/boe, potentially saving close to 1 million tonnes of CO₂e emissions versus a weighted average of gas imports (based on OGA/BEIS data). Our emissions work will also help us to design out emissions from future developments, but most importantly, it enabled us to take the immediate step of committing to Scope 1 & 2 Net Zero status as of 2021, putting IOG at the forefront of the OGA's strategic vision for the UK upstream industry.

As we look towards the rest of 2021 and beyond, IOG has several core strengths: a broad but geographically focused portfolio of UK gas assets with room for organic and inorganic growth, strong expertise across the organisation, an outstanding partner in CER, ownership of key offshore and onshore infrastructure, and an exceptionally low emissions profile coupled with a Net Zero policy, and an advantageous strategical position supplying gas into an import-dependent UK amid a very strong gas market. We remain as focused and committed as ever to safe and successful Phase 1 execution, working closely with our partners, contractors, regulators and other stakeholders. We also look forward to building further shareholder value on the foundations established in Phase 1 with successive phases of sustainable growth.

Andrew Hockey

Chief Executive Officer

26 August 2021

Operational Review

Saturn Banks Project Phase 1

The first half of 2021 saw material progression of our Phase 1 development, comprising the Blythe, Elgood and Southwark gas fields, with First Gas expected in Q4 2021.

The strengthening of our technical and operational capability has greatly assisted in our progress through the first half of 2021. Through the period we have built on our relationships with our contractor partnerships and have delivered on our commitments for the first half of the year. In the period we awarded a contract with ODE AM to operate and maintain our assets and together have built on our relationships with regulators and stakeholders, gaining the necessary Environmental and HSE approvals to complete the installations and operate the facilities.

In Q2 2021 our Blythe and Southwark unmanned platforms were completed and installed by HSM and their subcontractor Seaway 7. At installation both platforms had negligible carry over scope and once installed on location, they were powered up and put in communication with our onshore control room, manned by our operations contractor ODE AM.

In April we spudded Elgood, our first development well. There were a number of technical and mechanical challenges with the well which resulted in an extension to the planned duration. However, the broader drilling team, including key IOG personnel together with the teams from Noble, Petrofac Well Management and Schlumberger, worked diligently through the issues, resulting in successful completion of the well, cementing a collaborative approach that makes us prepared for the further drilling to come. The Blythe well was subsequently spudded in early August and is progressing to plan at the time of writing. 

During Q1 2021, the 6" and 12" pipelay scopes that commenced in 2020 were successfully completed. In Q2 our subsea hook-up phase recommenced and, at the time of writing, the Elgood umbilical has been installed and the 24" Saturn Banks Pipeline has been cut ready for installation of the manifold for connection to the Blythe 12" pipeline. Regulatory approval for the 24" pipeline extension to Southwark is progressing and that installation is anticipated to commence in Q1 2022 to coincide with completion of Southwark drilling and gas production in Q2 2022.

At the Saturn Banks Reception Facilities at Bacton terminal, the removal of old or obsolete equipment and integrity inspection are complete as part of preparation for recommissioning. Through Q2 2021 construction activity has gathered pace with detailed design coming to an end and materials and fabricated items coming available.

It is important to deliver a development that is as low impact and environmentally sustainable as reasonably possible. With a projected carbon intensity of less than 4kg kgCO₂e/boe over its full life, Phase 1 has a fraction of the impact of the average North Sea project and this is an advantage we aim to further enhance when executing future IOG developments.

Pre-Development Assets

Nailsworth and Elland

IOG UK Limited has a 50% working interest and is operator of the P039, P130 and P2342 licences, which contain the Elland and Nailsworth gas discoveries. These fields are intended to be part of Phase 2 of the Saturn Banks Project. In their 2017 Competent Persons Report (CPR), ERC Equipoise assessed gross 1P/2P/3P gas reserves to be 40/55/73 billion cubic feet ("BCF") in Elland, and 60/99/147 BCF in Nailsworth.

The discoveries are under evaluation in stage two of IOG's Project Governance Process, which assesses the optimal development concept for the fields within the context of the Phase 1 Saturn Banks Project infrastructure and the wider PDA portfolio. Based on this work, IOG will seek to submit and obtain approvals for an Environmental Impact Assessment and a Field Development Plan for the fields, where supported, at the earliest opportunity.

The remaining work programme commitment under the Nailsworth licences with the OGA is the submission and approval of a Field Development Plan prior to the end of 2021.

Goddard and Southsea

IOG North Sea Limited has a 50% working interest and is operator of licence P2438, which contains the Goddard field, an undeveloped gas discovery, and the Southsea gas exploration prospect. The discovery is intended to be part of the planned Phase 2 of the Saturn Banks Project.

Interpretation of Pre-Stack Depth Migration reprocessing of 3D seismic data was completed over the licence in Q1 2021, and substantially enhanced IOG's technical view of the Goddard discovery and the surrounding area, with a clearer subsurface image indicating a larger Goddard structure than previously mapped. As a result of this work, IOG management assess gross 1C/2C/3C resources in Goddard to be 57/132/258 Bcfe, representing a 22% increase in the 2C number versus the 2018 ERC Equipoise CPR.

The Q1 2021 subsurface interpretation of the two Goddard flank structures adjacent to the main discovery indicate a gross unrisked Low/Mid/High prospective resource range of 14/28/68 Bcfe and 8/19/44 Bcfe respectively with 71% GCoS in each case. The Southsea prospect as mapped indicates a gross unrisked Low/Mid/High prospective resource range of 13/31/76 Bcfe with 48% GCoS. Further technical work will be required to confirm these initial estimates.

In addition to seismic reprocessing, the terms of the licence include a firm work programme commitment to drill an appraisal well on the Goddard structure to 3,140m TD by 30 September 2021. In early 2021, IOG North Sea Limited formally requested a 12-month extension to the well commitment to 30 September 2022, in order that sufficient analysis and planning be undertaken based on the new seismic interpretation, prior to drilling. The outcome of the extension request is pending at the time of this report.

Abbeydale, Kelham Central, Kelham North and Thornbridge

IOG North Sea Limited has a 50% working interest and is operator of licence P2442, which contains the Abbeydale undeveloped gas discovery, the Kelham group of prospective gas accumulations (Kelham North and Kelham Central), part of the Orrell (Camlan) gas discovery and the Thornbridge exploration prospect.

Under the terms of the licence, a firm work programme commitment was made to reprocess 150 km2 of seismic data within two years, and to either drill and complete a well on the licence prior to 30 September 2023 or surrender the licence.

Interpretation of Pre-Stack Depth Migration reprocessing of 3D seismic data was completed over the licence in Q1 2021. Based on this new data, IOG management's deterministic estimate of gross 1C/2C/3C contingent resources at Abbeydale is 19/23/27 Bcfe. Gross recoverable Low/Mid/High gas volumes at Kelham North and Kelham Central are assessed by IOG management as 14/36/68 Bcfe (80% GCoS) and 38/42/47 Bcfe (70% GCoS) respectively. More detailed mapping and reservoir modelling of the Kelham group of prospective accumulations, including Kelham Central and Kelham South, will further clarify the wider area resource potential.

IOG has also identified an exploration prospect west of Abbeydale named Thornbridge, with gross management estimated Low/Mid/High prospective resources of 3/58/115 Bcfe and 32% GCoS. Further detailed mapping is required to fully capture the prospective resource range of the structure, with the key geological risk considered to be the quality of the Zechstein salt seal.

The technical work to date on the P2442 licence has identified the potential for a "Southern Hub" development that could be tied back to the Saturn Banks Pipeline. Any potential developments within the licence will be assessed within the context of IOG's development opportunities hopper, and the IOG Project Governance Process, in order to optimise the development concept within the context of the Phase 1 Saturn Banks Project infrastructure and the wider PDA portfolio.

Panther and Grafton

IOG North Sea Limited has a 50% working interest and is operator of licence P2589, which contains the Panther and Grafton gas discoveries. The licence was awarded in the 32nd Licensing Round, formally commencing on 1 December 2020, with a firm work programme commitment to reprocess 79 km2 of seismic data within three years, and to drill and complete a well on the licence by 30 November 2025 or to surrender the licence.

IOG management estimated gross 'Most Likely' contingent gas resources in 2019 to be 46 Bcfe at Panther and 35 Bcfe at Grafton. Reprocessing of seismic data is targeted to commence in 2021.

Harvey

IOG North Sea Limited has a 100% working interest and is operator of licence P2085, which contains the Harvey structure, an undeveloped gas discovery. A firm work programme commitment was fulfilled by the reprocessing of seismic data over the licence and the drilling and completion of the 48/24b-6 Harvey appraisal well in 2019. The remaining work programme commitment under the licence is to submit a Field Development Plan by 19 December 2021, or to surrender the licence.

IOG management currently estimate gross Minimum, Most Likely and Maximum contingent gas resources in Harvey at 12/21/35 Bcfe. A commercial assessment of Harvey is currently ongoing, evaluating the value of a potential "Elgood lookalike" development concept. This entails a single subsea well, tied back to the Blythe platform, which has been designed to have a spare 10-inch riser and J-tube. The Harvey discovery will then be assessed in line with IOG's Project Governance Process and ranked against the wider opportunities in the PDA portfolio for further investment.

David Gibson

Chief Operating Officer

26 August 2021

Financial Review 

The first half of 2021 saw further continued use of the capital put in place during the Company's funding activities in 2019, primarily comprising the Farm-out to CER ("Farm-out"), the £60 million Phase 1 development carry arrangement, and the €100 million senior secured bond ("Bond").

The Company started the period with a cash balance of £13.4 million plus £67.0 million of restricted cash, and a net debt1 position of £14.1 million. It ended the period with a cash balance of £55.6 million plus restricted cash of £3.4 million, and a net debt position of £32.2 million.

Over the period the Company invested £88.7 million on gross Phase 1 capital expenditures, of which £32.8 million was net to IOG. In the period the Company also received £51.3 million in partner cash calls from CER against Phase 1 capital expenditures, including £11.7 million of Phase 1 development carry, which fully drew and extinguished the remaining available amounts under the carry. 

The net expenditures for the Company of £32.8 million plus an additional £4.0 million of capitalised interest and £9.9 million of capitalised leases totalled the £46.4 million increase in PP&E and intangible assets.

On achieving the relevant operational milestones during the half-year period the Company also made three further drawdowns from the Bond escrow account, totalling €65.8 million (£59.2 million equivalent), which fully extinguished the account.

It also drew down a total of €4.8 million (£4.0 million equivalent) during the period from the Debt Service Reserve Account ("DSRA") to make two quarterly interest payments, leaving a further €2.4 million (£2.0 million equivalent) in the DSRA, representing one further quarterly interest payment.

^{1 Net debt is defined as restricted cash (£3.4 million) plus cash and cash equivalents (£55.6 million) plus financial assets (£1.4 million), less outstanding loans (£92.6 million)}

Income statement

The profit for the first six months of 2021 was £0.2 million (0.0p per share undiluted, 0.0p per share fully diluted), compared to a loss of £3.6 million for the first six months of 2020 (0.8p per share undiluted, 0.8p per share fully diluted). 

The current period profit includes £1.8 million of net administration expenses (1H 2020: £3.6 million), finance expenses of £1.8 million (1H 2020: £1.1 million) offset by interest income of £nil million (1H 2020: £0.1 million), foreign exchange profit of £1.9 million (1H 2020: loss of £0.8 million) and fair value gain of £0.2 million (1H 2020: loss of £0.3 million) on bonds held as financial assets. €4.8 million of bond coupon payments were made in the period and were capitalised to the Phase 1 development assets to which they relate.

The foreign exchange profit of £1.9 million for the current period reflect fluctuations in exchange rates on the valuation of non-GBP denominated balances.

Finance expenses of £1.8 million include £1.0 million of finance fees and charges, consisting of £0.5 million unwinding of convertible loan from London Oil and Gas Ltd ("LOG") and £0.2 million of amortisation of bond issuance fees, plus £0.1 million of interest paid on the bond escrow and DSRA accounts.

Statement of financial position

Non-current assets at 30 June 2021 of £114.1 million (31 December 2020: £71.4 million) include development and production assets of £99.6 million (31 December 2020: £53.4 million), representing the Group's capital expenditures attributable to the Saturn Banks Pipeline infrastructure and the Southwark, Blythe and Elgood development assets; exploration and evaluation assets of £1.5 million (31 December 2020: £1.3 million), representing capital expenditures attributable to the Elland, Nailsworth, Harvey, Goddard and Abbeydale pre-development assets; other property, plant and equipment of £12.8 million (31 December 2020: £16.5 million); and other intangible assets of £0.1 million (31 December 2020: £0.2 million).

Current assets at 30 June 2021 of £61.6 million (31 December 2020: £82.8 million) include cash and cash equivalents of £55.6 million (31 December 2020: £13.4 million), restricted cash of £3.4 million (31 December 2020: £67.0 million), financial assets (IOG bonds) of £1.4 million (31 December 2020: £1.3 million), and other receivables and prepayments of £1.2 million (31 December 2020: £1.1 million).

Current liabilities comprise trade and other payables of £46.4 million (31 December 2020: £22.1 million). Non-current liabilities of £105.6 million include £85.9 million due on the senior secured bond issued in 2019 and the debt element of the LOG convertible loan. In addition, provisions of £13.0 million represent deferred consideration amounts payable following first gas due in 2H 2021 from the Southwark field, as well as abandonment liabilities for both the Elland suspended well and the Saturn Banks Pipeline offshore infrastructure. 

Cash flow

After adjustment for non-cash items cash generated from operations, including working capital movements, for the first six months of 2021 was £19.0 million (1H 2020: generated £15.9 million). Cash generated from investing activities, which includes the purchase and acquisition of oil and gas properties and receipts from restricted cash funds, amounted to £21.7 million (1H 2020: used £9.3 million). Cash used in financing activities, which is primarily coupon payments on the Bonds, amounted to £4.4 million (1H 2020: used £4.6 million primarily Bond coupon payments). The cash balance at the end of the period was £55.6 million (31 December 2020: £13.4 million).

Funding and liquidity

The Board has reviewed the Group's cash flow forecasts having regard to its current financial position and operational objectives.

The Consolidated Statement of Financial Position at 30 June 2021 details a net debt position for the Group of £32.2 million (31 December 2020: £14.1 million). Net debt is defined as total loans, less restricted cash and cash equivalents, adding back the financial asset being the Company's holding in its own bonds.

In assessing the Group's and Parent Company's current financial position and reaching its conclusion as to going concern status up until February 2023, the Board has utilised a set of reasonable assumptions and sensitivities around activities, costs, timings, asset performance and other relevant economic factors including the potential impact of Covid-19, in order to develop an accurate perspective.

The Phase 1 capital cost and schedule assumptions underlying the going concern assessment flow from the baseline project plan as recently reviewed and reaffirmed by lead project managers and the COO. The risked mid-case forecast of final outturn Phase 1 capital expenditure profile finishes in mid-2022, consistent with the 2020 Annual Report. Each key discipline area within the project revises their forecast relevant Phase 1 cost estimates based on existing commitments and on better defined future spend as the project progresses through execution. These updated cost estimates are in turn interrogated and subsequently approved at both executive and Board level. Similarly, operating cost assumptions, which include both offshore O&M costs, onshore reception facilities costs and Bacton processing tariff costs, have been established using the latest and most accurate available estimates provided by internal operational personnel and relevant external parties, including IOG's O&M contractor ODE AM and Bacton terminal operator Perenco UK Limited (PUK). Decommissioning cost assumptions are drawn directly from the independent Competent Persons Report (CPR) undertaken by reserve auditor ERC Equipoise in 2017 and also the approved Phase 1 FDP, allowing that in the period considerable works have taken place both on and offshore.

In terms of project performance and timing assumptions, based on the latest management assessments of project readiness and current expectations of the development drilling programme, the timing of field start-ups for Phase 1 are as follows: Elgood and Blythe in Q4 2021, and Southwark in Q2 2022. The Phase 1 schedule has also been reviewed and approved by the executive and the Board based on detailed planning schedules managed by our dedicated project planner who has the full collaboration and oversight of the wider project team.

The gas price assumptions underlying the base case economic assessment are based on actual current forward UK NBP gas market pricing over the period assessed, with an appropriate level of reduction for the sake of conservatism. Longer-term gas pricing assumptions are based on an average realised price of 45p/therm, adjusted for the regular seasonal variations which are a well-established characteristic of UK NBP pricing (higher prices over October-March, lower prices over April-September). Management confirms this to be a sensible baseline in the context of average realised UK gas prices over the past decade and most likely future realised prices.

For pre-development assets and General and Administrative (G&A) costs, all assumptions are based on approved internal budgets, which in turn are based on reasonable estimates derived from comparable activities and relevant past actual costs. G&A budgets are constructed with an iterative methodology that factors in historical expenditure trends adjusted with appropriate forward-looking modifications and expected trends in underlying activity (e.g. changes in organisation headcount). Forecasts are reviewed by the senior finance team and the CFO on a monthly basis in order to assess the appropriateness of budget versus actual outturn and are reviewed and discussed at Board level. The Group's holding in its own bonds is assumed to be sold by the end of 2021 at a price no higher than the market value, which at period end was £1.4 million. Since its listing in Q4 2019 the bond has seen active trading and therefore the Board consider this to be a reasonable assumption. Finally, prudent assumptions have been taken in respect of the Group's management of foreign exchange exposure risk.

Foreign exchange exposures are forecast and compared to the available currency held as cash balances, JV cash calls and Bond drawdowns which allows any exposure to be actively managed.

As demonstrated above, the Group uses prudent assumptions to develop its view of most likely outcomes. In its detailed financial modelling it also stress tests a number of different possible future scenarios to evaluate the likely impacts of potential schedule and cost overruns. The stress test scenarios run by management and reviewed by the Board include changes in first gas timing, production levels, gas pricing and cost levels. Of these stress test scenarios the one that has most impact on the Group's liquidity during the period reviewed is first gas timing as revenues following first gas (across a range of production, cost and gas price assumptions) are expected be more than the Group's costs. Under the base case scenarios the Group is expected to be able to stay within its current cash resources.

The nature of the Group's operations, particularly at this stage of development of its Phase 1 project, presents the Group with an inherent risk around funding and covenant compliance that requires the Board to consider a range of potential outcomes and in that context the Group has identified a range of measures to mitigate or eliminate potential risks that may affect delivery of first gas. Not all potential outcomes or mitigations are fully within the control of the Group and therefore some uncertainty over the funding status of the group does arise.

After a review of these forecasts the Board have a reasonable expectation that the Group has adequate resources to continue in operational existence for the period under review and therefore consider it appropriate to continue to adopt the going concern basis in preparing the consolidated financial statements. However, the Directors acknowledge that at the date of approval of this interim financial information, the potential future impact of the reverse stress test scenarios noted above and the sensitivity of the delivery schedule, indicate the existence of a material uncertainty which may cast significant doubt about the Group's and Parent Company's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business. The Board has also assessed any foreseeable negative impact on the Bond covenants and are comfortable that the current forecast would not lead to any breaches of said covenants.

The financial statements do not include any adjustments that would result if the Group and the Parent Company were unable to continue as a going concern. The cash resources of the Group will be used over the coming months to deliver the Phase 1 project which will then generate cash flow from gas production.

Risks and uncertainties  

The Group operates in the oil and gas industry, an environment subject to a range of inherent risks and uncertainties. Key risks and associated mitigation are set out below.

Key performance indicators

The Group's main business is the acquisition, development and production of gas reserves and resources in a safe, efficient and environmentally responsible manner. This is undertaken by assembling and managing a carefully selected portfolio of licence interests containing a range of prospective, contingent and proven reserves, working these up from a technical perspective, planning, designing and executing appropriate appraisal, pre-development and development activities and, in due course, ensuring effective ongoing production operations. Non-financial performance is tracked through the calibration of progress on these activities on an ongoing basis. The Company also carefully monitors HSE KPIs, foremost of which are to sustain no Lost Time Incidents or environmental releases. Financial performance is tracked against established value metrics and budgets which are set according to carefully assessed cost estimates and the availability of funds raised from capital providers, with the overriding objective of creating value per share. Financial KPIs also include maintaining full compliance with terms of debt facilities and maintaining constructive relationships with debt providers and equity investors.

Rupert Newall

Chief Financial Officer

26 August 2021