Interim Results

RNS Number : 5171Z

Igas Energy PLC

15 September 2022

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION

15 September 2022

IGas Energy plc (AIM: IGAS)

("IGas" or "the Company" or "the Group")

Unaudited Interim results for the six months ended 30 June 2022

IGas announces its unaudited interim results for the six months to 30 June 2022.

Commenting today Chris Hopkinson, Interim Executive Chairman, said:

"Commodity prices were exceptionally strong during the period with a resulting positive impact on income and cash generation from the underlying conventional oil and gas assets. This continues to give us financial flexibility, enabling a reduction in our net debt by over £2.5 million and allowing capital to be allocated to sustaining, and in the future, increasing our conventional production as well as to our growth businesses, geothermal and now shale.

We welcomed the Government's announcement last week on the lifting of the effective moratorium on hydraulic fracturing in England and the review of energy regulation. However, the accelerated development of this strategic natural resource, which we believe is imperative in helping with the ongoing energy and cost-of-living crisis, can only be achieved through a streamlined regulatory process, something the Government has committed to and we look forward to working constructively with the new administration.

With the submission of grant applications to the Green Heat Network Fund for our pathfinder Stoke-on-Trent geothermal project and the building of a strong pipeline of project opportunities, we are moving the geothermal business forward materially.

With strong commodity prices forecast well into 2023, we expect to continue to be able to support both growth and debt reduction in the business."

Results Summary

	Six months to 30 June 2022 £m	Six months to 30 June 2021 £m
Revenues	30.5	16.6
Adjusted EBITDA*	10.7	2.7
Profit/(loss) after tax - continuing activities	19.4	(12.2)
Operating cash flow before working capital movements and realised hedges*	16.4	6.4
Net debt* (excluding capitalised fees)	9.7	13.2
Cash and cash equivalents	2.7	2.8

*these are alternative performance measures which are further detailed in the financial review

Corporate & Financial Summary

· Cash balances as at 30 June 2022 were £2.7 million (31 December 2021: £3.3 million) with net debt of £9.7 million (31 December 2021: £12.2 million), a reduction of £2.5 million since year end.

· Operating cash flow before working capital movements and realised hedges in H1 2022 of £16.4 million (H1 2021: £6.4 million).

· £2.8 million of capex incurred during six months to 30 June 2022. Net cash capex for FY 2022 expected to be £10.2 million, primarily relating to our conventional assets. In addition, we have £1.8 million of cash outflow in 2022 for projects executed towards the end of 2021.

· Successful Reserve Based Lending facility (RBL) redetermination in July (a semi-annual recalculation), confirming US$22.0 million of debt capacity. We had headroom of US$12.0 million (£10.3 million) as at 31 August 2022.

· We are required to hedge our production under the RBL and as at 31 August 2022, we had 70,000 bbls hedged with swaps at an average price of $76.4/bbl and 35,000 bbls hedged with puts at a floor price of $44.7 for 2022. We also have 60,000 bbls hedged with swaps for H1 23 at $95.0/bbl.

· The estimated Energy Profits Levy for the period ended 30 June 2022 is £0.2 million.

· Ring fence tax losses of £263 million.

Operational Summary

· Net production averaged 1,865 boepd in H1 2022 (H1 2021: 2,005 boepd) impacted by equipment failure as a run-on consequence of COVID-19 supply chain issues.

· Full year net production is now forecast to be in the range of c.1,900-1,950 as we resolve the issues in H1 and wells come back on-line. Underlying cash operating costs per boe anticipated to be c.$40.4/boe (based on an exchange rate of £1:$1.24).

· Moratorium on shale lifted in England and Government commits to a review of energy regulation.

· We continue to mature our growth opportunities within the existing conventional assets, including our East Midlands projects at Corringham and Glentworth.

· An application to the Government's Green Heat Network Fund (GHNF) for the Stoke-on-Trent geothermal project was made on 26 August 2022.

· Applications for grant funding from the Public Sector Decarbonisation Scheme will be made in partnership with the Carbon Energy Fund to support the development of six geothermal schemes, supplying renewable heat to NHS Trusts.

A results presentation will be available at http://www.igasplc.com/investors/presentations .

Qualified Person's Statement

Ross Pearson, Technical Director of IGas Energy plc, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, March 2006, of the London Stock Exchange, has reviewed and approved the technical information contained in this announcement. Mr Pearson has 21 years oil and gas exploration and production experience.

For further information please contact:

IGas Energy plc

Tel: +44 (0)20 7993 9899

Chris Hopkinson, Interim Executive Chairman

Ann-marie Wilkinson, Director of Corporate Affairs

Investec Bank plc (NOMAD and Joint Corporate Broker)

Tel: +44 (0)20 7597 5970

Virginia Bull/Jeremy Ellis

Canaccord Genuity (Joint Corporate Broker)

Tel: +44 (0)20 7523 8000

Henry Fitzgerald-O'Connor/James Asensio

Vigo Consulting

Tel: +44 (0)20 7390 0230

Patrick d'Ancona/Finlay Thomson/Kendall Hill

Introduction and Market Backdrop

The first half of 2022 has been dominated by the tragic events in Ukraine which impacted already tight energy markets and has created an energy crisis with high prices affecting people and businesses.

Oil prices remain around the $100/bbl mark albeit subject to the vagaries of global supply and demand but European gas prices continue to be at record highs and as we look into the second half of the year gas rationing in Europe and potentially the UK is a real prospect. Never more than now has energy security been of such critical importance and has been so much in the public eye. IGas, with its decades of experience of producing energy onshore in the UK, is uniquely placed to be able to deliver domestic energy, helping with both energy security and achieving the UK's net zero targets.

The domestic and international demand for oil and gas will continue to be strong for many decades. In the transition to 2050, there is a continuing need for oil and gas, alongside renewable energy sources. On projections by the Climate Change Committee (CCC) and the National Grid Future Energy Scenarios the UK will have a significant import dependency for oil and particularly gas in the period to 2050 and beyond. This import dependency already exists and is growing with the Department for Business, Energy and Industrial Strategy (BEIS) showing that in 2021 net energy imports increased by 41 per cent to help meet demand. Gas continued to be the dominant fossil fuel, generating 123.2 TWh of electricity in 2021, an increase of 11 per cent from 2020.

The increase in the oil price in recent months has been a welcome boost to revenue and cash generation giving us greater financial flexibility. We successfully completed the scheduled six-monthly RBL facility redetermination process. The redetermination exercise confirmed c. £18 million of debt capacity.

Looking forward we anticipate an ongoing oil price volatility driven by uncertainties around the level of disruption to Russian supply, the capacity for increased OPEC+ supply, the ongoing impact of COVID-19 on demand and the impact of the conflict in Ukraine on economic growth.

IGas continues to put its efforts into the provision of responsibly sourced oil and gas to the UK domestic market, protecting security of supply, and reducing the UK's reliance on imports whilst positioning itself in the transition to a lower carbon future.

Last week, the UK Government, in response to the energy and cost-of-living crises, announced a lifting of the moratorium on shale gas in England and committed to undertake a review of energy regulation. We look forward to working constructively with Government to deliver timely shale gas production in the national interest, as well as working closely with local communities to ensure they share in the benefits of domestic shale gas development.

The decarbonisation of large scale heat remains a significant unresolved problem for the country. Some 44 per cent of the UK's energy demand is for heating homes and other buildings, which accounts for 37 per cent of the UK's greenhouse gas emissions. The CCC have stated that only decarbonisation of heat in the UK could deliver the major reduction in emissions needed to meet the 2050 net zero target. We firmly believe that deep geothermal is the only utility scale source of renewable heat suitable for deployment in urban areas. Now that specific provision has been made for drilling of geothermal wells in the Government's GHNF this gives us a clearer line of sight to development as we firm up a number of rapidly emerging opportunities. Moving to geothermal heat is not only a desire from off-takers, such as network operators and large heat users such as councils, universities and hospitals as they seek to decarbonise but has the benefit of being a truly competitive solution in a landscape of increased gas prices.

Board Changes

In a separate announcement made today, the Board of IGas announces that it has appointed Chris Hopkinson, Non-Executive Chairman, to the role of Interim Executive Chairman. Stephen Bowler, CEO, will leave IGas, by mutual consent, with immediate effect. Also announced today, Frances Ward has been appointed as Chief Financial Officer and a Board Director of the Company, with immediate effect.

Chris Hopkinson was appointed to the Board in January 2022, as a Non-executive Director and Chairman designate. At the close of the IGas Annual General Meeting in June, Chris took over the role of Chairman from Cuth McDowell who had served as Interim Non-executive Chair since October 2019 and on the Board since December 2012.

In February 2022, IGas also welcomed Kate Coppinger to the Board who took over the role of Chair of the Audit committee from Cuth McDowell in June 2022.

On 1 July 2022, Tushar Kumar resigned from the Board as a Non-executive Director.

Energy Profits Levy

The Government announced on 26 May 2022 that it would introduce an Energy Profits Levy on UK production, and this passed into legislation on 14 July 2022.

The Levy took effect from 26 May 2022, and based on current forecasts - oil price of $94/bbl and FX of $1.20:£1.00 for remainder of 2022 - we estimate a payment under the Levy of c.£0.5 million in respect of 2022, taking into account our current capital expenditure plans. Given that the Levy is part of a package that includes significant investment incentives, we are evaluating additional projects that could be brought forward to offset the impact.

Despite efforts by the industry there have been no changes to the draft legislation and expenditure for investment relief for example, in geothermal, which currently sits outside of the UK ring-fence tax regime has not been included.

Production Operations

Net production for the period averaged 1,864 boepd (H1 2021: 2,005 boepd), impacted by equipment failure as a run-on consequence of COVID-19 supply chain issues. We now anticipate net production in the range of c.1,900-1,950 boepd for the full year as we resolve the issues in H1 and wells come back on-line.

Operating cash flow before working capital movements is expected to be c.£19.7 million in 2022 based on a forecast average oil price of $94/bbl for the remainder of the year.

Operating costs are now forecast to be c. $40.4/bbl driven primarily by increased energy costs and general price increases on equipment, offset by a more favourable foreign exchange rate. However, positively, given IGas is a net exporter of electricity, there is a forecast net benefit to IGas of £1.1 million, equivalent to $1.9/boe.

Despite the challenges of the follow-on impacts of COVID-19 on the supply chain and in maintaining staffing levels across the operations, our teams have worked exceptionally hard over the last six months.

In the first quarter of 2022, work was completed to convert an existing, suspended well in the Stockbridge field to a water disposal well; this allows for the resumption of c.50 bbls/d of suspended production to be brought back on line. The project has also provided more operational flexibility in handling produced water in the Stockbridge area.

In February 2022, we announced the publication of a CPR by DeGolyer & MacNaughton (D&M), a leading international reserves and resources auditor.

The report comprised an independent evaluation of IGas conventional oil and gas interests as of 31 December 2021. The full report can be found on the IGas website www.igasplc/investors/publications-and-reports .

IGas Group Net Reserves & Contingent Resources as at 31December 2021 (MMboe)

	1P	2P	2C
Reserves & Resources as at 31 December 2020	11.74	17.12	20.34
Production during the period	(0.71)	(0.71)	-
Revision of estimates	(0.46)	(0.62)	-
Reserves & Resources as at 31 December 2021	10.57	15.79	20.34

The report values our conventional assets at c. $190 million on a 2P NPV10 basis (based on a forward oil curve of c. $67/bbl for 2022-2024 and then escalated at an average rate of 2.5% thereafter).

Development Assets

Oil and Gas

We are progressing a number of development opportunities across our portfolio. Whilst all at different stages of maturity they have, in aggregate, the potential to add, in the medium term, an initial c.900 boepd and a further c.500 boepd in subsequent phases .

Two of those development opportunities are in the East Midlands. The first is an infill drilling project at Corringham which has the potential to add c.100 bbls/d and 0.35 mmstb 2P reserves in 2023. The project has existing planning permission, we are now in the process of discharging the conditions of planning and we applied to the Environment Agency in May 2022 for the necessary permitting.

The second, is a larger appraisal/development project to extend one of our existing fields at Glentworth. Our proposal is for the construction of a new wellsite, to the west of our existing Glentworth-K oil production site. The full development is to drill an appraisal well and up to 7 horizontal development wells. This opportunity will be progressed in a phased approach, with a planning application for phase 1 to be submitted in Q4 2022.

If phase 1, the appraisal well with a horizontal side-track is successful, this will be followed by further development drilling in subsequent years. The first phase of the project is targeting an additional c.200 bbls/d and development of c.1.0 mmstb 2P reserves with the subsequent development having the potential to add an additional 500bbls/d and the addition of c.2mmstb 2P reserves.

Geothermal

In March 2022, the UK Government put its full support behind deep geothermal energy by launching the GHNF. The GHNF is a three-year £288 million capital grant fund that will support the commercialisation and construction of new low and zero carbon heat networks including the drilling of deep geothermal wells and associated works. The GHNF opened to applications in March 2022 and confirmed that it will fund up to 50 percent of a project's total combined commercialisation and construction costs. As the developer of the Stoke-on-Trent geothermal project, we have applied jointly with Scottish and Southern Energy (SSE), the developer of the associated district heat network, for a capital grant in the second round that closed on 26 August 2022.

Our discussions with SSE to finalise a Thermal Purchase Agreement on the Stoke-on-Trent project are progressing well and we expect to conclude these post decision from the GHNF on the grant application, which we expect in Q4 2022.

In addition to the GHNF, applications for grant funding from the Public Sector Decarbonisation Scheme will be made in partnership with the Carbon Energy Fund to support the development of six geothermal schemes, supplying renewable heat to NHS Trusts. The Public Sector Decarbonisation Scheme, which provides grants for public sector bodies to fund site decarbonisation, opened for applications in September 2022 for low carbon technologies including deep geothermal. Phase 3 of the Scheme will provide £1.425 billion of grant funding over the financial years 2022/2023 to 2024/2025, through multiple application windows. If successful, the funding will enable us to progress these projects through the planning and design phase and bring them to shovel ready stage.

We have continued to have positive discussions with the UK Government regarding future, longer-term financial support for the deep geothermal industry. We have had several meetings with senior ministers including the Secretary of State and a working group with the Department for Business, Energy and Industrial Strategy (BEIS) has been established to look at a financial model for the long-term support of deep geothermal heat. BEIS has now commissioned a Deep Geothermal Energy White Paper, an evidence-based assessment to help accelerate the development and deployment of deep geothermal energy projects as an opportunity to significantly contribute to the UK's net zero goals.

In July 2022, we submitted written evidence to the Environmental Audit Committee's inquiry into the role that geothermal technologies can play in the UK' s journey to net zero.

The opportunities for using deep geothermal energy for heat in the UK are significant. We continue to receive a high number of enquiries and are in discussions with 15 off takers, across 15 separate sites which equates to over 100 megawatts of installed heat generation.

Discussion continues with Manchester City Council (MCC). A site has been identified and we are currently working through commercials with MCC on the site.

A first site has now been agreed with Cornish Lithium and a work programme is being agreed prior to finalising site specific commercial terms.

Shale

On 5 April 2022, the Government announced that it had commissioned the British Geological Survey (BGS) to advise on the latest scientific evidence around shale gas extraction. This review was delivered to BEIS on 5 July 2022.

We submitted evidence to the BGS which has been shared with both BEIS and the North Sea Transition Authority (NSTA) formerly the Oil and Gas Authority. The evidence we submitted was a research report by Dr Tim Harper PhD.

As well as analysing the publicly available information from Lancashire, in late 2020 Dr Harper was provided with proprietary information from the Gainsborough Trough, information that had not previously been made available to the BGS.

Key points of the report:

1. The data collected by IGas in the Gainsborough Trough over the past 5 years demonstrates:

a. We have a world class shale gas resource in the Gainsborough Trough; and

b. That when compared with other areas of the UK, the geology of the Gainsborough Trough is much less complex.

2. There is a new method of looking at the likelihood of induced seismicity occurring, which supplements the techniques we already use. This method looks at the geomechanical history and setting of the area and analyses 11 factors which affect the likelihood of experiencing induced seismicity. Together with existing techniques, these give us a good idea of how likely we are to experience induced seismicity in a wider area and on a site by site basis.

3. Using this method to supplement already existing techniques, the Gainsborough Trough, on a qualitative basis, can be demonstrated to have a significantly lower chance of induced seismicity when compared with the Bowland Basin in Lancashire.

4. The method means that this risk of induced seismicity can be materially better understood. Further hydraulic fracturing in multiple wells is required to test and calibrate the models used.

On 8 September 2022, the UK Government announced a lifting of the moratorium on shale gas in England alongside a review of energy regulation, both parts of wider government policy addressing the future of both energy supply and demand. We have always believed the science, as well as the need for increased domestic production of gas, supports a lifting of the moratorium. The country's shale gas opportunity is enormous and aside from potentially reducing the country's dependency on imports, particularly LNG, has many benefits. LNG imports do not offer employment, tax take, business rates, community benefits, energy security or a lower carbon footprint supply. Domestically produced shale gas does. We have a world-class resource in our assets in the Gainsborough Trough and can demonstrate how shale can provide safe, secure and affordable energy for the UK in the near term.

IGas has the potential to deliver five production well pads, with each pad having up to 16 wells, which would supply three million homes with initial production within 12-18 months with the right Government support. We look forward to working constructively with the new administration to achieve a streamlined regulatory process that can deliver accelerated development of this strategic natural resource.

Polling by YouGov has revealed renewed support for shale gas extraction as the cost of living crisis bites.

YouGov's poll found that if local shale gas production meant a reduction in bills for people in the community, then, excluding don't knows, more than half of British adults (53%) would support shale development .

Financial review

Income Statement

The Group generated revenue of £30.5 million in the first six months of 2022 from sales of 316,171 barrels of oil, including sales of third party oil, 6,231 Mwh of electricity and 938,203 therms of gas (H1 2021: revenue £16.6 million, sales of 330,984 barrels of oil, 7,112 Mwh of electricity and 1,247,946 therms of gas). The higher revenue was driven by the improvement in Brent prices, which averaged $107.6/bbl during H1 2022 compared to $64.9/bbl in H1 2021 as the war in Ukraine led to disrupted Russian supply and global concerns over energy security. Limited OPEC supply increases despite higher prices and increased demand as economies started to recover from the impacts of the COVID-19 pandemic also supported prices. Revenue was also increased by a weakening of sterling versus the US dollar with an average USD/GBP rate of $1.29/£1 in H1 2022 compared to $1.39/£1 in H1 2021. The Group incurred a realised loss on oil price hedges reflecting the higher market prices.

Adjusted EBITDA for H1 2022 was £10.7 million (H1 2021: £2.7 million) and the profit after tax from continuing activities was £19.4 million (H1 2021: loss of £12.2 million). The main factors explaining the movements between H1 2022 and H1 2021 were as follows:

· Revenues of £30.5 million (H1 2021: £16.6 million) were higher than the first half of 2021 due to higher oil prices as described above;

· DD&A increased to £2.7 million (H1 2021: £2.4 million);

· Operating costs increased to £10.8 million (H1 2021: £8.6 million). We saw the impact of higher commodity prices on operating costs, particularly in electricity costs which increased by £0.4m. However, as a net electricity exporter, we had a net revenue of £0.5 million for the period. Operating costs were also higher due to higher staff costs, inflationary increases in materials and equipment costs and additional workover and maintenance activity;

· Administrative expenses increased to £2.8 million (H1 2021: £2.3 million) primarily due to higher staff and national insurance costs and a lower allocation to capital projects. This was partially offset by lower premises costs;

· Exploration and evaluation assets of £6.5 million relating to PEDL 184 were written off during the year following the rejection of planning consent on appeal for a well test of the Ellesmere Port-1 well. This licence, whilst prospective, is outside our core shale exploration area and, as the Group have no plans for further activity on the licence in the short term, the full capitalised amount has been written off (H1 2021: £10.1 million);

· An impairment reversal of £10.5 million (H1 2021: £nil) was recognised on oil and gas assets during the period due to higher oil prices. We impaired £1.5 million of past costs on our Lybster licence as these are not expected to be recovered in any future development of the site. We are currently reviewing development options for this asset;

· A loss was recognised on oil price derivatives of £7.5 million (H1 2021: £5.4 million loss). We are required to hedge our production under the RBL with hedges being executed on a rolling 12 month basis and the loss was generated due to an increase in the Brent oil benchmark;

· Increased net finance costs of £2.9 million (H1 2021: £1.8 million) were mainly due to foreign exchange losses on our US$ denominated debt offset by a lower unwinding of discount on provisions;

· A tax credit of £13.2 million was recognised in the period (H1 2021: credit £1.9 million) principally due to an increase in the deferred tax asset relating to the value of recognised tax losses available for offset against future taxable profits as a result of an increase in oil prices. No charge has been included for the 25% levy on ringfence profits subsequent to 26 May 2022 under the Energy (Oil and Gas) Profits Levy Bill, as this was not enacted before the period end. We estimate that the levy payable related the period to 30 June 2022 is c.£0.2 million; and

· IGas has ring fence tax losses of £263 million as at 30 June 2022.

Cash Flow

Net cash generated from operations after cash hedge losses and before working capital movements in the period amounted to £10.6 million (H1 2021: £3.7 million). The Group invested £2.9 million across its asset base in the period (H1 2021: £2.6 million). £2.5 million (H1 2021: £1.7 million) was invested in conventional assets, primarily to convert an existing, suspended well in the Stockbridge field to a water disposal well allowing c.50 bbls/d of suspended production to be brought back on line. The project will also provide more operational flexibility in handling produced water in the Stockbridge area. We also invested in smaller projects to upgrade existing facilities and systems and optimise production at a number of sites. £0.3 million (H1 2021: £0.8 million) was invested primarily in working up additional exploration opportunities on conventional assets.

Higher operating cashflows enabled us to repay £4.6 million ($6.0 million) of principal on borrowings under the RBL facility (H1 2021: net drawdown of £1.4 million ($2.0 million)). We continue to have significant headroom under the facility.

IGas paid £0.4 million ($0.4 million) in interest (H1 2021: £0.5 million ($0.6 million)). The impact of lower outstanding balances was partially offset by increasing interest rates and a stronger US$. Repayment of obligations under leases was £0.9 million (H1 2021: £0.8 million).

Cash and cash equivalents were £2.7 million at the end of the period (31 December 2021: £3.3 million).

Balance Sheet

Net assets were £88.5 million at 30 June 2022 (31 December 2021: £68.6 million). The increase is related primarily to the reversal of impairment of oil and gas assets offset by an impairment of exploration and evaluation assets, an increase in deferred tax assets and reductions to borrowings.

Shareholder's equity increased by £19.9 million to £88.5 million (31 December 2021 £68.6 million).

Non-IFRS Measures

The Group uses non-IFRS measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. The non-IFRS measures include net debt, adjusted EBITDA, underlying cash operating costs and operating cash flow before working capital movements and realised hedges, which are considered by the Company to be useful additional measures to help understand underlying performance.

Net Debt

Net debt, being borrowings excluding capitalised fees less cash and cash equivalents, decreased to £9.7 million at 30 June 2022 (31 December 2021: £12.2 million; 30 June 2021: £13.2 million). The Group's definition of net debt does not include the Group's lease liabilities.

	Six months ended 30 June 2022	Six months ended 30 June 2021	Year ended 31 December 2021
	£m	£m	£m
Debt (nominal value excluding capitalised expenses)	(12.4)	(16.0)	(15.5)
Cash and cash equivalents	2.7	2.8	3.3
Net Debt	(9.7)	(13.2)	(12.2)

Adjusted EBITDA

Adjusted EBITDA includes adjustments in relation to non-cash items such as share-based payment charges and unrealised gain/loss on hedges along with other one-off exceptional items, and after deducting lease rentals capitalised under IFRS 16.

	Six months ended 30 June 2022	Six months ended 30 June 2021	Year ended 31 December 2021
	£m	£m	£m
Profit/(loss) before tax	6.2	(14.2)	(12.3)
Net finance costs	2.9	1.8	3.9
Changes in fair value of contingent consideration	-	0.2	(0.6)
Depletion, depreciation & amortisation	2.7	2.5	4.9
Impairment (reversals)/write-offs	(2.5)	10.1	10.5
EBITDA	9.3	0.4	6.4
Lease rentals capitalised under IFRS 16	(0.9)	(0.8)	(1.5)
Share-based payment charges	0.6	0.5	0.9
Unrealised loss on hedges	1.7	2.6	0.1
Adjusted EBITDA	10.7	2.7	5.9

Underlying cash operating costs

	Six months ended 30 June 2022	Six months ended 30 June 2021	Year ended 31 December 2021
	£m	£m	£m
Other cost of sales	10.9	8.6	19.1
Lease rentals capitalised under IFRS 16	0.9	0.8	1.5
Underlying cash operating costs	11.8	9.4	20.6

Operating cash flow before working capital movements and realised hedges

	Six months ended 30 June 2022	Six months ended 30 June 2021	Year ended 31 December 2021
	£m	£m	£m
Operating cash flow before working capital movements	10.6	3.7	7.4
Realised loss on oil price derivatives	5.8	2.7	6.6
Operating cash flow before working capital movements and realised hedges	16.4	6.4	14.0

Principal risks and uncertainties

The Group constantly monitors the Group's risk exposures and management reports to the Audit Committee and the Board on a regular basis. The Audit Committee receives and reviews these reports and focuses on ensuring that the effective systems of internal financial and non-financial controls including the management of risk are maintained. The results of this work are reported to the Board which in turn performs its own review and assessment.

The principal risks for the Group remain as previously detailed on pages 20-21 of the 2021 Annual Report and Accounts and can be summarised as:

· Political risk such as change in Government or the effect of local or national referendums which can result in changes to the regulatory or fiscal regime;

· Strategy, and its execution, fails to meet shareholder expectations;

· Climate change risks that causes changes to laws, regulations, policies, obligations and social attitudes relating to the transition to a lower carbon economy which could have a cost impact or reduced demand for hydrocarbons for the Group and could impact our Strategy;

· Cyber security risk that gives exposure to a serious cyber-attack which could affect the confidentiality of data, the availability of critical business information and cause disruption to our operations;

· Planning, environmental, licensing and other permitting risks associated with its operations and, in particular, with drilling and production operations;

· Oil or gas production, as no guarantee can be given that they can be produced in the anticipated quantities from any or all of the Group's assets or that oil or gas can be delivered economically;

· Development of shale gas resources not successful;

· Loss of key staff;

· Pandemic that impacts the ability to operate the business effectively;

· Oil market price risk through variations in the wholesale price in the context of the production from oil fields it owns and operates;

· Gas and electricity market price risk through variations in the wholesale price in the context of its future unconventional production volumes;

· Exchange rate risk through both its major source of revenue and its major borrowings being priced in US$ while most of the Group's operating and G&A costs are denominated in UK pounds sterling;

· Liquidity risk through its operations; and

· Capital risk resulting from its capital structure, including operating within the covenants of its RBL facility.

Going concern

The Group continues to closely monitor and manage its liquidity risks. Cash flow forecasts for the Group are regularly produced based on, inter alia, the Group's production and expenditure forecasts, management's best estimate of future oil prices, management's best estimate of foreign exchange rates and the Group's available loan facility under the RBL. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices, strengthening of sterling and reductions in forecast oil and gas production rates.

The Group's operating cash flows have improved in 2022 as a result of improving commodity prices and we have successfully completed the May 2022 redetermination. However, the ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its RBL, which is redetermined semi-annually based on various parameters (including oil price and level of reserves) and is also dependent on the Group not breaching its RBL covenants. We also assumed that our existing RBL facility is amortised in line with its terms, but is not refinanced or extended, resulting a reduction in the facility to $7 million from 01 January 2024. To mitigate these risks, the Group has a hedging policy with 70,000 bbls hedged for September to December 2022 using swaps at an average price of $76/bbl and 35,000 bbls using puts with an average price, net of premiums, of $45/bbl, and a further 60,000 bbls hedged for H1 23 using swaps at an average price of $95/bbl.

Management has considered the impact of supply chain constraints on the Group's operations. We have seen some impact on production during 2022 but we have developed a number of contingency plans to mitigate this and any future COVID-19 related disruptions. Many of our sites are remotely manned and we are well equipped as a business to ensure we maintain business continuity recognising that our production comes from a large number of wells in a variety of locations and we have flexibility in our off-take arrangements.

Crude oil prices rose during 2022 as loosening pandemic-related restrictions and growing economies resulted in global petroleum demand rising faster than supply. The war in Ukraine war and sanctions imposed on Russia have led to concerns about oil and gas supply disruption also adding support to prices. Going forward, prices remain volatile with cost of living and recession concerns in many economies increasing risks on the demand side.

The Group's base case cash flow forecast was run with average oil prices of $98/bbl for the remainder of 2022, falling to an average of $90/bbl in 2023 and $80/bbl in Q1 24 based on the forward curve, and a foreign exchange rate of $1.22/£1. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility for at least 12 months from the date of approval of the financial statements. Management has also prepared a downside case with average oil prices at $88/bbl for the remainder of 2022; $80/bbl for H1 2023, falling to $75/bbl and $70/bbl for Q3 and Q4 2023,respectively, and $65/bbl for Q1 2024. We forecast an average exchange rate of $1.26/£1.00 for the remainder of 2022, an average of $1.29/£1.00 for 2023 and $1.30/£1.00 for Q1 2024. Our downside case also included an average reduction in production of 5% over the period. Management would take mitigating actions including delaying capital expenditure and additional reductions in costs in order to remain within the Group's debt liquidity covenants should such actions be necessary. All such mitigating actions are within management's control. We have not assumed any extensions or refinancing to the RBL. In this downside scenario, our forecast shows that the Group will have sufficient financial headroom to meet its financial covenants at least 12 months from the date of approval of the financial statements.

Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future and have concluded it is appropriate to adopt the going concern basis of accounting in the preparation of the financial statements.

Statement of Directors' responsibilities

The Directors confirm that these Condensed Interim Consolidated Financial Statements have been prepared in accordance with UK-adopted International Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34") and the AIM Rules for Companies; and these Unaudited Interim results include:

a) a fair review of the information required (i.e., an indication of important events and their impact and a description of the principal risks and uncertainties for the remaining six months of the financial year); and

b) a fair review of the information required on related party transactions.

By order of the Board,

Chris Hopkinson

Interim Executive Chairman

15 September 2022

Independent review report to IGas Energy plc

Report on the condensed consolidated interim financial statements

Our conclusion

We have reviewed IGas Energy plc's condensed consolidated interim financial statements (the "interim financial statements") in the Unaudited Interim Results of IGas Energy plc for the 6 month period ended 30 June 2022 (the "period").

Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with UK adopted International Accounting Standard 34, 'Interim Financial Reporting' and the AIM Rules for Companies.

The interim financial statements comprise:

· the Condensed Interim Consolidated Balance Sheet as at 30 June 2022;

· the Condensed Interim Consolidated Income Statement and Condensed Interim Consolidated Statement of Comprehensive Income for the period then ended;

· the Condensed Interim Consolidated Cash Flow Statement for the period then ended;

· the Condensed Interim Consolidated Statement of Changes in Equity for the period then ended; and

· the explanatory notes to the interim financial statements.

The interim financial statements included in the Unaudited Interim Results of IGas Energy plc have been prepared in accordance with UK adopted International Accounting Standard 34, 'Interim Financial Reporting' and the AIM Rules for Companies.

Basis for conclusion

We conducted our review in accordance with International Standard on Review Engagements (UK) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures.

A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and, consequently, does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

We have read the other information contained in the Unaudited Interim Results and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

Conclusions relating to going concern

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed. This conclusion is based on the review procedures performed in accordance with this ISRE. However, future events or conditions may cause the group to cease to continue as a going concern.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the directors

The Unaudited Interim Results, including the interim financial statements, are the responsibility of, and have been approved by the directors. The directors are responsible for preparing the Unaudited Interim Results in accordance with the AIM Rules for Companies which require that the financial information must be presented and prepared in a form consistent with that which will be adopted in the Company's annual financial statements. In preparing the Unaudited Interim Results, including the interim financial statements, the directors are responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.

Our responsibility is to express a conclusion on the interim financial statements in the Unaudited Interim Results based on our review. Our conclusion, including our Conclusions relating to going concern, is based on procedures that are less extensive than audit procedures, as described in the Basis for conclusion paragraph of this report. This report, including the conclusion, has been prepared for and only for the Company for the purpose of complying with the AIM Rules for Companies and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

PricewaterhouseCoopers LLP

Chartered Accountants

London

15 September 2022

Condensed Interim Consolidated Income Statement

	Notes	Unaudited 6 months ended 30 June 2022 £000	Unaudited 6 months ended 30 June 2021 £000	Audited year ended 31 December 2021 £000
Revenue	4	30,456	16,574	37,916
Cost of sales
Depletion, depreciation and amortisation		(2,651)	(2,379)	(4,794)
Other costs of sales		(10,850)	(8,608)	(19,105)
Total cost of sales		(13,501)	(10,987)	(23,899)
Gross profit/(loss)		16,955	5,587	14,017
Administrative expenses		(2,849)	(2,314)	(5,827)
Exploration and evaluation assets written off	9	(6,517)	(10,097)	(10,463)
Oil and gas assets net impairment reversal	10	8,977	-	-
Loss on oil price derivatives		(7,458)	(5,370)	(6,715)
Operating profit/(loss)		9,108	(12,194)	(8,988)
Finance income	5	3	135	2
Finance costs	5	(2,877)	(1,893)	(3,850)
Changes in fair value of contingent consideration	12	-	(230)	570
Profit/ (loss) from continuing activities before tax		6,234	(14,182)	(12,266)
Income tax credit	6	13,187	1,942	6,230
Profit/ (loss) after tax from continuing operations attributable to shareholders' equity		19,421	(12,240)	(6,036)
Loss after tax from discontinued operations	7	-	(106)	(203)
Net profit/ (loss) for the period/year attributable to shareholders' equity		19,421	(12,346)	(6,239)
Earnings/ (Loss) attributable to equity shareholders from continuing operations:
Basic earnings/ (loss) per share	8	15.45p	(9.78p)	(4.82p)
Diluted earnings/ (loss) per share	8	14.33p	(9.78p)	(4.82p)
Earnings/ (Loss) attributable to equity shareholders including discontinued operations:
Basic earnings/ (loss) per share	8	15.45p	(9.87p)	(4.98p)
Diluted earnings/ (loss) per share	8	14.33p	(9.87p)	(4.98p)

Condensed Interim Consolidated Statement of Comprehensive Income

	Unaudited 6 months ended 30 June 2022 £000	Unaudited 6 months ended 30 June 2021 £000	Audited year ended 31 December 2021 £000
Profit/ (loss) for the period/year	19,421	(12,346)	(6,239)
Other comprehensive income/(loss) for the period/year:
Currency translation adjustments recycled to the income statement (note 7)	-	326	326
Total comprehensive profit/ (loss) for the period/year	19,421	(12,020)	(5,913)

Condensed Interim Consolidated Balance Sheet

	Notes	Unaudited At 30 June 2022 £000	Unaudited At 30 June 2021 £000	Audited At 31December 2021 £000
Assets
Non-current assets
Intangible assets	9	32,337	37,661	38,322
Property, plant and equipment	10	84,010	73,264	74,583
Right-of-use assets		6,980	7,458	7,017
Restricted cash		410	410	410
Deferred tax asset	6	51,362	33,888	38,176
		175,099	152,681	158,508
Current assets
Inventories		1,414	1,094	1,092
Trade and other receivables		7,701	5,289	5,509
Cash and cash equivalents	13	2,681	2,755	3,289
		11,796	9,138	9,890
Total assets		186,895	161,819	168,398
Liabilities
Current liabilities
Trade and other payables		(6,948)	(4,588)	(6,863)
Derivative financial instruments	11	(3,112)	(3,897)	(1,410)
Lease liabilities		(831)	(720)	(815)
Provisions	12	(5,798)	(358)	(2,419)
		(16,689)	(9,563)	(11,507)
Non-current liabilities
Borrowings	13	(11,817)	(15,123)	(14,836)
Other creditors		(586)	(970)	(770)
Lease liabilities		(6,265)	(6,667)	(6,362)
Provisions	12	(63,016)	(67,591)	(66,307)
		(81,684)	(90,351)	(88,275)
Total liabilities		(98,373)	(99,914)	(99,782)
Net assets		88,522	61,905	68,616
Equity
Capital and reserves
Called up share capital	14	30,333	30,333	30,333
Share premium account	14	103,035	102,969	102,992
Foreign currency translation reserve		3,799	3,799	3,799
Other reserves		36,699	35,676	36,257
Accumulated deficit		(85,344)	(110,872)	(104,765)
Total equity		88,522	61,905	68,616

Condensed Interim Consolidated Statement of Changes in Equity

	Called up share capital 000	Share premium account £000	Foreign currency translation reserve** 000	Other Reserves*** 000	Accumulated deficit 000	Total Equity 000
At 1 January 2021 (audited)	30,333	102,906	3,473	35,117	(98,526)	73,303
Loss for the period	-	-	-	-	(12,346)	(12,346)
Share options issued and vested under the employee share plan (note 14)	-	63	-	559	-	622
Currency translation adjustments*	-	-	326	-	-	326
At 30 June 2021 (unaudited)	30,333	102,969	3,799	35,676	(110,872)	61,905
Profit for the period	-	-	-	-	6,107	6,107
Share options issued and vested under the employee share plan (note 14)	-	23	-	581	-	604
At 31 December 2021 (audited)	30,333	102,992	3,799	36,257	(104,765)	68,616
Profit for the period	-	-	-	-	19,421	19,421
Share options issued and vested under the employee share plan (note 14)	-	43	-	442	-	485
At 30 June 2022 (unaudited)	30,333	103,035	3,799	36,699	(85,344)	88,522

* The only other comprehensive income for the six months to 30 June 2021 comprises the currency translation adjustments recycled to the income statement. There was no other comprehensive income in the six month periods to 31 December 2021 and 30 June 2022.

** The foreign currency translation reserve represents exchange gains and losses on translation of previously held foreign currency subsidiaries' net assets and results, and on translation of those subsidiaries' intercompany balances, which formed part of the net investment of the Group. During the year ended 31 December 2021, we commenced the liquidation process for the remaining of these foreign currency subsidiaries' and control over these entities was transferred to the administrators. This process is ongoing at 30 June 2022.

*** Other reserves include: 1) EIP/MRP/LTIP/VCP/EDRP reserves which represent the cost of share options issued under the long term incentive plans; 2) share investment plan reserve which represents the cost of the partnership and matching shares; 3) treasury shares reserve which represents the cost of shares in IGas Energy plc purchased in the market and previously held by the IGas Employee Benefit Trust (EBT) to satisfy awards held under the Group incentive plans; 4) capital contribution reserve which arose following the acquisition of IGas Exploration UK Limited; and 5) merger reserve which arose on the reverse acquisition of Island Gas Limited.

Condensed Interim Consolidated Cash Flow Statement

	Notes	Unaudited 6 Months ended 30 June 2022 £000	Unaudited 6 Months ended 30 June 2021 £000	Audited year ended 31 December 2021 £000
Cash flows from operating activities:
Profit/ (Loss) from continuing activities before tax for the period/year		6,234	(14,182)	(12,266)
Depletion, depreciation and amortisation		2,664	2,475	4,903
Abandonment costs/other provisions utilised		(841)	(122)	(356)
Share-based payment charge		585	467	878
Exploration and evaluation assets written-off	9	6,517	10,097	10,463
Oil and gas assets impairment reversal	10	(10,489)	-	-
Oil and gas assets impairment	10	1,512	-	-
Change in unrealised loss on oil price derivatives	11	1,702	2,626	138
Change in unrealised loss on foreign exchange contracts		-	314	315
Changes in fair value of contingent consideration	12	-	230	(570)
Finance income	5	(3)	(135)	(2)
Finance costs	5	2,877	1,893	3,850
Other non-cash adjustments		(185)	(1)	9
Operating cash flow before working capital movements		10,573	3,662	7,362
(Increase)/decrease in trade and other receivables and other financial assets		(2,294)	(1,103)	(1,637)
(Decrease)/increase in trade and other payables		(130)	352	1,699
(Increase)/decrease in inventories		(320)	(71)	(69)
Cash from continuing operating activities		7,829	2,840	7,355
Cash used in discontinued operating activities		-	(124)	(221)
Net cash from operating activities		7,829	2,716	7,134

Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets		(263)	(794)	(734)
Purchase of property, plant and equipment		(2,500)	(1,743)	(3,905)
Purchase of intangible development assets		(88)	(35)	(167)
Interest received		3	5	2
Cash used in continuing investing activities		(2,848)	(2,567)	(4,804)
Net cash used in investing activities		(2,848)	(2,567)	(4,804)

Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital	14	22	21	40
Drawdown on Reserves Based Lending facility	13	-	1,432	1,432
Repayment on Reserves Based Lending facility	13	(4,648)	-	(756)
Repayment of principal portion of lease liability		(590)	(484)	(747)
Repayment of interest on lease liabilities		(307)	(340)	(684)
Interest paid	13	(390)	(454)	(812)
Net cash from/(used in) financing activities		(5,913)	175	(1,527)

Net increase/(decrease) in cash and cash equivalents during the period /year		(932)	324	803
Net foreign exchange difference		324	(7)	48
Cash and cash equivalents at the beginning of the period /year		3,289	2,438	2,438
Cash and cash equivalents at the end of the period /year	13	2,681	2,755	3,289

Notes to the Unaudited Condensed Interim Consolidated Financial Statements

1 Corporate information

The unaudited condensed interim consolidated financial statements of IGas Energy plc and subsidiaries (the Group) for the six months ended 30 June 2022, which are unaudited, were authorised for issue in accordance with a resolution of the Directors on 15 September 2022.

IGas Energy plc is a public limited company incorporated and domiciled in England whose shares are publicly traded on the AIM market. The Group's principal activity is exploring for, appraising, developing and producing oil and gas resources in the UK. The Group is also diversifying into the wider UK energy markets and is appraising geothermal and hydrogen projects.

2 Accounting policies

Basis of preparation

These unaudited condensed interim consolidated financial statements for the six months ended 30 June 2022 have been prepared in accordance with UK-adopted International Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34") and the AIM Rules for Companies. The unaudited condensed interim consolidated financial statements should be read in conjunction with the consolidated financial statements for the year ended 31 December 2021, which have been prepared in accordance with UK-adopted International Accounting Standards.

The financial information contained in this document does not constitute statutory accounts as defined by Section 435 of the Companies Act 2006 (England & Wales). The financial information as at 31 December 2021 is based on the statutory accounts for the year ended 31 December 2021. A copy of the statutory accounts for that year, has been delivered to the Register of Companies and is available on the Company's website at www.igasplc.com. The auditors' report in accordance with Chapter 3 Part 16 of the Companies Act 2006 in relation to those accounts was unqualified and did not contain any matters on which the auditors are required to report an exception in accordance with section 498 (2) and (3) of the Companies Act 2006.

The accounting policies adopted are consistent with those of the previous financial year and corresponding interim reporting period, except for the new and amended standards and interpretations discussed below.

Going concern

The Group's operating cash flows have improved in 2022 as a result of improving commodity prices and we have successfully completed the May 2022 redetermination. However, the ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its RBL, which is redetermined semi-annually based on various parameters (including oil price and level of reserves) and is also dependent on the Group not breaching its RBL covenants. We also assumed that our existing RBL facility is amortised in line with its terms, but is not refinanced or extended, resulting in a reduction in the facility to $7 million from 01 January 2024. To mitigate these risks, the Group has a hedging policy with 70,000 bbls hedged for September to December 2022 using swaps at an average price of $76/bbl and 35,000 bbls using puts with an average price, net of premiums, of $45/bbl, and a further 60,000 bbls hedged for H1 23 using swaps at an average price of $95/bbl.

Crude oil prices rose during 2022 as loosening pandemic-related restrictions and growing economies resulted in global petroleum demand rising faster than supply. The war in Ukraine and sanctions imposed on Russia have led to concerns about oil and gas supply disruption also adding support to prices. Going forward, prices remain volatile with cost of living and recession concerns in many economies increasing risks on the demand side.

The Group's base case cash flow forecast was run with average oil prices of $98/bbl for the remainder of 2022, falling to an average of $90/bbl in 2023 and $80/bbl in Q1 24 based on the forward curve, and a foreign exchange rate of $1.22/£1. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility for at least 12 months from the date of approval of the financial statements. Management has also prepared a downside case with average oil prices at $88/bbl for the remainder of 2022; $80/bbl for H1 2023, falling to $75/bbl and $70/bbl for Q3 and Q4 2023, respectively, and $65/bbl for Q1 2024. We forecast an average exchange rate of $1.26/£1.00 for the remainder of 2022, an average of $1.29/£1.00 for 2023 and $1.30/£1.00 for Q1 2024. Our downside case also included an average reduction in production of 5% over the period. Management would take mitigating actions including delaying capital expenditure and additional reductions in costs in order to remain within the Group's debt liquidity covenants should such actions be necessary. All such mitigating actions are within management's control. We have not assumed any extensions or refinancing to the RBL. In this downside scenario, our forecast shows that the Group will have sufficient financial headroom to meet its financial covenants for at least 12 months from the date of approval of the financial statements.

New and amended standards and interpretations

During the period, the Group adopted the following new and amended IFRSs for the first time for their reporting period commencing 1 January 2022:

Amendments to IFRS 3	Reference to the Conceptual Framework
Amendments to IAS 16	Property, Plant and Equipment-Proceeds before Intended Use
Amendments to IAS 37	Onerous Contracts-Cost of Fulfilling a Contract
Annual Improvements to IFRS Standards 2018-2020 Cycle	Amendments to IFRS 1 First-time Adoption of International Financial Reporting Standards, IFRS 9 Financial Instruments, IFRS 16 Leases, and IAS 41 Agriculture

These standards do not have a material impact on the Group in the current or future reporting periods. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods.

Estimates and judgements

The preparation of the unaudited condensed interim consolidated financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.

In preparing these unaudited condensed interim consolidated financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those applied to the consolidated financial statements for the year ended 31 December 2021.

Financial risk management

The Group's activities expose it to a variety of financial risks; market risk (including interest rate, commodity price and foreign currency risks), credit risk and liquidity risk.

The unaudited condensed interim consolidated financial statements do not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Group's annual financial statements as at 31 December 2021.

3 Basis of consolidation

The unaudited condensed interim consolidated financial statements present the results of IGas Energy plc and its subsidiaries as if they formed a single entity. The financial information of subsidiaries used in the preparation of these unaudited condensed interim consolidated financial statements are based on consistent accounting policies to those of the Company. All intercompany transactions and balances between Group companies, including unrealised profits/losses arising from them, are eliminated in full. Where shares are issued to an Employee Benefit Trust, and the Company is the sponsoring entity, it is treated as an extension of the entity.

4 Revenue

The Group derives revenue solely within the United Kingdom from the transfer of goods and services to external customers which is recognised at a point in time when the performance obligation has been satisfied by the transfer of goods. The Group's major product lines are:

	Unaudited 6 months ended 30 June 2022	Unaudited 6 months ended 30 June 2021	Audited year ended 31 December 2021
	£000	£000	£000
Oil sales	27,343	15,284	33,254
Electricity sales	1,394	550	2,048
Gas sales	1,719	740	2,614
Revenue for the period /year	30,456	16,574	37,916

5 Finance income and costs

	Unaudited 6 months ended 30 June 2022	Unaudited 6 months ended 30 June 2021	Audited year ended 31 December 2021
	£000	£000	£001
Finance income:
Interest on short-term deposits	3	1	2
Foreign exchange gains	-	134	-
Finance income for the period /year	3	135	2
Finance expense:
Interest on borrowings	(439)	(448)	(812)
Amortisation of finance fees on borrowings	(134)	(165)	(267)
Foreign exchange loss	(1,181)	-	(151)
Unwinding of discount on decommissioning provisions (note 12)	(816)	(811)	(1,659)
Unwinding of discount on contingent consideration (note 12)	-	(129)	(277)
Finance charge on lease liability for assets in use	(307)	(340)	(684)
Finance expense for the period /year	(2,877)	(1,893)	(3,850)

6 Tax on profit on ordinary activities

The Group calculates the period income tax expense using the UK corporation tax rate that would be applicable to expected total annual earnings for the 12 months ended 31 December 2022 (40% for UK ring fenced activities and 19% for all other UK activities). The effective tax rate for the period is -212% (six months ended 30 June 2021: 13%, year ended 31 December 2021: 50%), reflecting the deferred tax credit of £13.2 million in the period as a result of a higher recognition of deferred tax losses primarily due to higher forecast commodity prices. The major components of income tax expense in the unaudited condensed interim consolidated income statement are:

	Unaudited 6 months ended 30 June 2022 £000	Unaudited 6 months ended 30 June 2021 £000	Audited year ended 31 December 2021 £000
UK corporation tax
Charge on loss for the period/year	-	-	-
Total current tax charge	-	-	-
Deferred tax
Charge/(credit) relating to the origination or reversal of temporary differences	(13,187)	(1,526)	(6,360)
Credit due to tax rate changes	-	(416)	(393)
Credit in relation to prior periods	-	-	523
Total deferred tax credit	(13,187)	(1,942)	(6,230)
Tax credit on loss on ordinary activities for the period/year	(13,187)	(1,942)	(6,230)

A deferred tax asset of £51.4 million (30 June 2021: £33.9 million, 31 December 2021: £38.2 million) has been recognised in respect of tax losses and other temporary differences where the Directors believe that it is probable that these assets will be recovered based on estimated taxable profit forecast.

The Energy (Oil and Gas) Profits Levy Bill, which introduces an additional 25% levy on ringfence profit was substantially enacted in July 2022. The estimated impact of this is discussed within Note 15, Subsequent events.

7 Loss after tax from discontinued operations

The divestment of assets acquired as part of the Dart Acquisition, namely the Rest of the World segment, was completed in 2016. The Group had a presence in a small number of Australian, Indian and Singaporean registered operations and we have continued the liquidation process for the remaining of these overseas dormant subsidiaries, with control over these entities currently with administrators. The total loss after tax in respect of discontinued operations was £nil (six months ended 30 June 2021: loss after tax of £0.1 million; year ended 31 December 2021: loss after tax of £0.2 million, primarily relating to the recycling of the currency translations reserve administration costs).

Effect of liquidation/strike off on the financial statements:

	Unaudited 6 months ended 30 June 2022 £000	Unaudited 6 months ended 30 June 2021 £000	Audited year ended 31 December 2021 £000
Other receivables	-	(10)	(11)
Cash and cash equivalents	-	(20)	(118)
Other payables	-	15	15
Net assets and liabilities disposed	-	(15)	(114)
Disposal consideration	-	-	-

Translation reserve re-classification to income statement on liquidation/strike off	-	(326)	(326)
Loss on liquidation/strike off charged to the income statement	-	(341)	(440)

8 Earnings per share (EPS)

Basic EPS amounts are based on the profit from continuing operations for the period after taxation attributable to ordinary equity holders of the parent of £19.4 million (six months ended 30 June 2021: a loss after tax of £12.2 million; year ended 31 December 2021: a loss after tax of £6.0 million) and the weighted average number of ordinary shares outstanding during the period of 125.7 million (six months ended 30 June 2021: 125.1 million; year ended 31 December 2021: 125.3 million).

Diluted EPS amounts are based on the profit/ loss for the period/ year after taxation attributable to the ordinary equity holders of the parent and the weighted average number of shares outstanding during the period/ year plus the weighted average number of ordinary shares that would be issued on the conversion of all the potentially dilutive ordinary shares into ordinary shares, except where these are anti-dilutive.

There are 9.8 million potentially dilutive employee share options (six months ended 30 June 2021: 11.7 million, year ended 31 December 2021: 11.7 million). These are included in the calculation of diluted earnings per share in the current period. These were not included in the calculation in prior periods as their conversion to ordinary shares would have decreased the loss per share.

9 Intangible assets

	Unaudited 6 months ended 30 June 2022 '000			Unaudited 6 months ended 30 June 2021 '000			Audited year ended 31 December 2021 '000
	Exploration and evaluation assets	Develop- ment costs	Total	Exploration and evaluation assets	Develop- ment costs	Total	Exploration and evaluation assets	Develop- ment costs	Total
Cost
At 1 January	34,844	3,478	38,322	43,421	3,290	46,711	43,421	3,290	46,711
Additions	321	101	422	621	38	659	888	188	1,076
Changes in decommissioning (note 12)	110	-	110	388	-	388	998	-	998
Amounts written off	(6,517)	-	(6,517)	(10,097)	-	(10,097)	(10,463)	-	(10,463)
At 30 June/ 31 December	28,758	3,579	32,337	34,333	3,328	37,661	34,844	3,478	38,322

Exploration and evaluation assets

Exploration costs written off in the period to 30 June 2022 were £6.5 million (6 months to 30 June 2021: £10.1 million, year ended 31 December 2021: £10.5 million) of which £6.4 million related to the PEDL 184 (Ellesmere Port) and £0.1 million related to trailing costs on relinquished licences. The 2021 exploration costs written off substantially all related to the relinquishment of the PEDL 200 (Tinker Lane) licence.

Further analysis by location of asset is as follows:

North West: The group has £nil (H1 2021: £6.3 million, year ended 31 December 2021: £6.4 million) of capitalised exploration expenditure relating to Ellesmere Port, with the full capitalised amount of £6.4 million being written off in the period. This follows the rejection of planning consent on appeal for a well test in the Ellesmere Port-1 well. This licence, whilst prospective, is outside our core shale exploration area and, as the Group have no plans for further activity on the licence in the short term, the full capitalised amount has been written off.

East Midlands: The group has £23.5 million (H1 2020: £23.1 million, year ended 31 December 2021: £23.2 million) of capitalised exploration expenditure relating to our core area in the Gainsborough Trough which includes PEDLs 12, 139, 140, 169 and 210. The Gainsborough Trough is an area with significant shale potential. Following the moratorium on fracking, we engaged with the NSTA and the Department for Business, Energy and Industrial Strategy (BEIS) to demonstrate that we can develop shale in this area in a safe manner. Our discussions have focused on the new science that would be brought forward on a sector wide and site specific basis that would allow the moratorium to be lifted. On 5 April 2022, the Government announced that it had commissioned the British Geological Survey (BGS) to advise on the latest scientific evidence around shale gas extraction. This review, which we provided scientific evidence to, was delivered to BEIS on 5 July 2022. We believe the science, as well as the need for increased domestic production of gas, should support a lifting of the moratorium. We also have confidence that we can develop our assets in a safe manner as we firmly believe that the geo-mechanics of the Gainsborough Trough present a significantly reduced risk of induced seismicity of the type experienced elsewhere in the UK. The evidence submitted to the BGS review has been shared with both BEIS and NSTA, and we continue our engagement with NSTA, BEIS and other industry participants. As the discussions regarding the moratorium are still ongoing, the Directors consider that it is appropriate to continue to capitalise this asset.

Conventional assets: The Group has £5.2 million (six months ended 30 June 2021: £4.9 million, year ended 31 December 20201: £5.2 million) of capitalised exploration expenditure which relates to our conventional assets including PEDL 235 and PL 240.

Development costs

The development costs relate to assets acquired as part of the GT Energy acquisition in 2020. The costs relate to the design and development of deep geothermal heat projects in the United Kingdom, with the principal project being at Etruria Valley, Stoke-on-Trent.

The Group reviewed the carrying value of development costs as at 30 June 2022 and assessed it for impairment indicators. The development of the Stoke-on-Trent project has taken longer than anticipated initially due to COVID-19 and more recently on account of delays on receiving certainty on a Government support mechanism. The UK Government launched the Green Heat Network Fund (GHNF) in March 2022 which will support the commercialisation and construction of new low and zero carbon heat networks including the drilling of deep geothermal wells and associated works. The GHNF opened to applications in March 2022 and confirmed that it will fund up to 50% of a project's total combined commercialisation and construction costs. We have applied for funding for the Stoke-on-Trent project and expect to hear the outcome in Q4 2022. Our discussions with SSE to finalise a Thermal Purchase Agreement on the Stoke-on-Trent project are also progressing. The delayed timing does not adversely impact the overall economics of the project materially and a successful outcome on our grant application to the GHNF will significantly de-risk the project. On this basis, the group has concluded that there are no impairment indicators as at 30 June 2022. No impairment was required for the period ( year ended 31 December 2021 : £nil).

10 Property, plant and equipment

	Unaudited 6 months ended 30 June 2022 '000			Unaudited 6 months ended 30 June 2021 '000			Audited year ended 31 December 2021 '000
	Oil and gas assets	Other fixed assets	Total	Oil and gas assets	Other fixed assets	Total	Oil and gas assets	Other fixed assets	Total
Cost
At 1 January	215,222	2,430	217,652	209,225	2,951	212,176	209,225	2,951	212,176
Additions	2,773	-	2,773	1,152	-	1,152	3,700	-	3,700
Disposals	-	3	3	-	(518)	(518)	-	(521)	(521)
Changes in decommissioning (note 12)	(206)	-	(206)	1,591	-	1,591	2,297	-	2,297
At 30 June/ 31 December	217,789	2,433	220,222	211,968	2,433	214,401	215,222	2,430	217,652
Depreciation and Impairment
At 1 January	142,034	1,035	143,069	138,233	1,504	139,737	138,233	1,504	139,737
Charge for the period/year	2,109	8	2,117	1,879	39	1,918	3,801	52	3,853
Disposals	-	3	3	-	(518)	(518)	-	(521)	(521)
Impairment	1,512	-	1,512	-	-	-	-	-	-
Impairment reversal	(10,489)	-	(10,489)	-	-	-	-	-	-
At 30 June/ 31 December	135,166	1,046	136,212	140,112	1,025	141,137	142,034	1,035	143,069
Net book value at 30 June/ 31 December	82,623	1,387	84,010	71,856	1,408	73,264	73,188	1,395	74,583

Impairment of oil and gas properties

Cash Generating Units (CGUs) for impairment purposes are the group of fields whereby technical, economic and/or contractual features create underlying interdependence in the cash flows. The Group has identified the three main producing CGUs as: North, South, and Scotland. Due to the high oil and gas prices and favourable foreign exchange rates, management identified impairment reversal indicators for the North and South CGUs and hence performed a detailed exercise to determine the amount of reversal as at 30 June 2022. The Scotland CGU comprising the Lybster field is currently undergoing a redevelopment plan. Possible increased development costs under the plan indicated a potential impairment for this CGU.

The impairment assessment was prepared on a fair value less costs of disposal basis using discounted future cash flows based on 2P reserve profiles. The future cash flows were estimated using nominal price assumptions for Brent of between $80-100/bbl for the years 2022-2026 and $65/bbl thereafter. A foreign exchange rate of between $1.25:£1.00 and $1.35:£1.00 was used. Cash flows were discounted using a post-tax discount rate of 9%.

This resulted in a recoverable amount greater than the carrying amount by £16.0 million at the South CGU and £0.8 million at the North CGU. We have capped the impairment reversal recorded at the South CGU to £10.5 million, comprising the net book value of the full amount previously impaired, in line with the requirements in IAS 36. No impairment reversal was recorded at the North CGU as reasonable downside cases indicated that an impairment could be required if certain sensitivities were applied. Therefore, the factors that lead to the initial impairment have not fully reversed and management did not consider it appropriate to reverse a portion of the past impairment.

At the Scotland CGU, an impairment of £1.5m was recognised, as it is not expected that all past costs would be recovered through the development of the site.

Sensitivity of changes in assumptions

The principal assumptions are recoverable future production and resources, estimated Brent prices, the USD/GBP foreign exchange rate, and the discount rate. The impact on the recoverable amount that would result from changes to the key assumptions are shown below:

CGU	10% reduction in price	10% reduction in production	USD/GBP foreign exchange rate @ $1.4	Discount rate @ 10%
	£m	£m	£m	£m

North	(7.88)	(8.72)	(3.28)	(1.77)
South	(6.06)	(5.98)	(3.54)	(1.62)
Scotland	(0.91)	(0.75)	(0.41)	(0.13)
Total	(14.85)	(15.45)	(7.23)	(3.52)

The sensitivity analysis above does not take into account any mitigating actions available to management should these changes occur.

11 Financial Instruments - fair value disclosure

The Group uses the following hierarchy for determining and disclosing the fair value of the financial instruments by valuation technique:

● Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities;

● Level 2: other valuation techniques for which all inputs which have a significant effect on the recorded fair value are observable, either directly or indirectly; and

● Level 3: valuation techniques which use inputs which have a significant effect on the recorded fair value that are not based on observable market data.

There are no non-recurring fair value measurements nor have there been any transfers between levels of the fair value hierarchy.

There were no financial assets measured at fair value. The financial liabilities measured at fair value are categorised into the fair value hierarchy as at the reporting dates as follows:

	Level	Unaudited 6 months ended 30 June 2022 '000	Unaudited 6 months ended 30 June 2021 '000	Audited year ended 31 December 2021 '000
Financial liabilities:
Derivative financial instruments - oil hedges	2	(3,112)	(3,897)	(1,410)
Contingent consideration (note 12)	3	(2,731)	(3,383)	(2,731)
At 30 June /31 December		(5,843)	(7,280)	(4,141)

Fair value of derivative financial instruments

Commodity price hedges

The fair values of the commodity price options were provided by counterparties with whom the trades have been entered into. These consist of Asian style put and call options and swaps to sell/buy oil. The options are valued using a Black-Scholes methodology; however, certain adjustments are made to the spot-price volatility of oil prices due to the nature of the options. These adjustments are made either through Monte Carlo simulations or through statistical formulae. The inputs to these valuations include the price of oil, its volatility, and risk free interest rates.

Fair value of other financial assets and financial liabilities

The fair values of all other financial assets and financial liabilities are considered to be materially equivalent to their carrying values.

12 Provisions

	Unaudited 6 months ended 30 June 2022 '000			Unaudited 6 months ended 30 June 2021 '000			Audited year ended 31 December 2021 '000
	Decommis-sioning provision	Contingent consideration	Total	Decommis- sioning provision	Contingent consideration	Total	Decommis- sioning provision	Contingent consideration	Total
At 1 January	(65,995)	(2,731)	(68,726)	(61,819)	(3,024)	(64,843)	(61,819)	(3,024)	(64,843)
Acquisitions							-	-	-
Utilisation of provision	632	-	632	43	-	43	778	-	778
Unwinding of discount (note 5)	(816)	-	(816)	(811)	(129)	(940)	(1,659)	(277)	(1,936)
Reassessment of decommissioning provision (note 9 and 10)	96	-	96	(1,979)	-	(1,979)	(3,295)	-	(3,295)
Changes in fair value of contingent consideration	-	-	-	-	(230)	(230)	-	570	570
At 30 June/ 31 December	(66,083)	(2,731)	(68,814)	(64,566)	(3,383)	(67,949)	(65,995)	(2,731)	(68,726)
Less current portion	5,518	280	5,798	-	358	358	2,139	280	2,419
Non-current	(60,565)	(2,451)	(63,016)	(64,566)	(3,025)	(67,591)	(63,856)	(2,451)	(66,307)

Decommissioning provision

The Group spent £0.6 million on decommissioning activities during the period (six months ended 30 June 2021: £0.0 million; year ended 31 December 2021: £0.8 million).

Provision has been made for the discounted future cost of abandoning wells and restoring sites to a condition acceptable to the relevant authorities. This is expected to take place between 1 to 39 years from period end (30 June 2021: 1 to 37 years; 31 December 2021: 1 to 30 years). The provisions are based on the Group's internal estimate as at 30 June 2022. Assumptions are based on the current experience from decommissioning wells which management believes is a reasonable basis upon which to estimate the future liability. The estimates are based on a planned programme of abandonments but also include a provision to be spent in 2022-2025 on preparing for the abandonment campaign, abandoning wells and restoring sites which for regulatory, integrity or other reasons fall outside the planned campaign. The wells to be decommissioned in 2022 and 2023 are in line with management's discussions with the regulator. The estimates are reviewed regularly to take account of any material changes to the assumptions. Actual decommissioning costs will ultimately depend upon future costs for decommissioning which will reflect market conditions and regulations at that time. Furthermore, the timing of decommissioning is uncertain and is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend on factors such as future oil and gas prices, which are inherently uncertain.

A risk free rate range of 2.27% to 3.00% is used in the calculation of the provision as at 30 June 2022 (30 June 2021: Risk free rate range of 1.2% to 3.00%, 31 December 2021: Risk free rate range of 1.20% to 3.00%).

Management performed sensitivity analysis to assess the impact of changes to the risk free rate on the Group's decommissioning provision balance. A 0.5% decrease in the risk free rate would result in an increase in the decommissioning provision by £3.5 million.

Management also performed sensitivity analysis to assess the impact of changes to the undiscounted future cost of abandoning wells and restoring sites on the Group's decommissioning provision balance. A 10% increase in the undiscounted future cost would result in an increase in the decommissioning provision by £6.7 million.

Contingent consideration

The carrying value of contingent consideration relates to the acquisition of GT Energy. The consideration is payable in shares, and is dependent on the timing of various milestones being achieved. It is also dependent on the inputs to an agreed-form economic model which determines the level of the consideration for each milestone in accordance with the SPA. These inputs relate to targets for aspects of the Stoke-on-Trent project, including funding, amount of heat delivered, and costs and revenues achieved. In addition, there is a business development milestone relating to securing and achieving targets for a second geothermal project or generating additional capacity for the Stoke-on-Trent project. The acquisition agreement and economic model assumed the availability of the Renewable Heat Incentive (RHI), which closed to applications from 31 March 2021. In March 2022, the UK Government launched the GHNF and we have applied for funding for the Stoke-on-Trent project in the first round. The change in nature of the government support for the project is not provided for in the economic model or the SPA. Whilst the contractual implications on the acquisition agreement are being assessed, management believes that the current value provides the best estimate of the contingent consideration at this time. The estimated fair value will be reviewed as the project progresses and more information becomes available.

13 Cash and cash equivalents and other financial assets

	Unaudited As at 30 June 2022 £000	Unaudited As at 30 June 2021 £000	Audited As at 31 December 2021 £000
Cash and cash equivalents	2,681	2,755	3,289
Borrowings - including capitalised fees	(11,817)	(15,123)	(14,836)
Net debt	(9,136)	(12,368)	(11,547)
Capitalised fees	(535)	(803)	(669)
Net debt excluding capitalised fees at 30 June/31 December	(9,671)	(13,171)	(12,216)

Net debt reconciliation

	Cash and cash equivalents £000	Borrowings £000		Total £000
At 1 January 2021	2,438	(13,695)		(11,257)
Interest paid on borrowings	(454)	-		(454)
Drawdown of RBL	1,432	(1,432)		-
Foreign exchange adjustments	(7)	137		130
Other cash flows	(654)	-		(654)
Other non-cash movements	-	(133)		(133)
At 30 June 2021	2,755	(15,123)		(12,368)
Interest paid on borrowings	(358)	-	(358)
Repayment of RBL	(756)	756	-
Foreign exchange adjustments	55	(335)	(280)
Other cash flows	1,593	-	1,593
Other non-cash movements	-	(134)	(134)
At 31 December 2021	3,289	(14,836)	(11,547)
Interest paid on borrowings	(390)	-			(390)
Repayment of RBL	(4,648)	4,648			-
Foreign exchange adjustments	324	(1,494)			(1,170)
Other cash flows	4,106	-			4,106
Other non-cash movements	-	(135)			(135)
At 30 June 2022	2,681	(11,817)			(9,136)

Reserve Based Lending facility

On 3 October 2019, the Company announced that it had signed a $40.0 million RBL facility with BMO Capital Markets (BMO). In addition to the committed $40.0 million RBL, a further $20.0 million is available on an uncommitted basis, and can be used for any future acquisitions or new conventional developments. The RBL has a five-year term, an interest rate of USD LIBOR plus 4.0%, matures in June 2024 and is secured on the Company's assets. The RBL is subject to a semi-annual redetermination in May and November when the loan availability will be recalculated taking into account forecast commodity prices, remaining field reserves (assessed by an independent reserves auditor annually) and the latest forecast of operating and capital costs. On 2 August 2022, the Group announced it had successfully completed the May 2022 redetermination which confirmed an available facility limit of $22.0 million. Under the terms of the RBL, the Group is subject to a financial covenant whereby, as at 30 June and 31 December each year, the ratio of Net Debt at the period end to Earnings before Interest, Tax, Depreciation, Amortisation and Exceptional items (EBITDAX as defined in the RBL agreement) for the previous 12 months shall be less than or equal to 3.5:1. The Group complied with its covenants for the six months ended 30 June 2022.

Collateral against borrowing

A Security Agreement was executed between BMO and IGas Energy plc and some of its subsidiaries, namely; Island Gas Limited, Island Gas Operations Limited, Star Energy Weald Basin Limited, Star Energy Group Limited, Star Energy Limited, Island Gas (Singleton) Limited, Dart Energy (East England) Limited, Dart Energy (West England) Limited, IGas Energy Development Limited, IGas Energy Enterprise Limited, Dart Energy (Europe) Limited and IGas Energy Production Limited. Under the terms of this Agreement, BMO have a floating charge over all of the assets of these legal entities, other than property, assets, rights and revenue detailed in a fixed charge. The fixed charge encompasses the Real Property (freehold and/or leasehold property), the specific petroleum licences, all pipelines, plant, machinery, vehicles, fixtures, fittings, computers, office and other equipment, all related property rights, all bank accounts, shares and assigned agreements and rights including related property rights (hedging agreements, all assigned intergroup receivables and each required insurance and the insurance proceeds).

14 Share capital

	Ordinary shares		Deferred shares		Share capital	Share premium
	No.	Nominal value £000	No.	Nominal value £000	Nominal value £000	Value £000
Issued and fully paid
At 1 January 2021	124,797,169	2	303,305,534	30,331	30,333	102,906
SIP issue partnership	185,212	-	-	-	-	21
SIP issue matching	271,971	-	-	-	-	42
At 30 June 2021	125,254,352	2	303,305,534	30,331	30,333	102,969
SIP issue partnership	118,555	-	-	-	-	19
SIP issue matching	109,055	-	-	-	-	4
Shares issued in respect of MRP issues	13,543	-	-	-	-	-
At 31 December 2021	125,495,505	2	303,305,534	30,331	30,333	102,992
SIP issue partnership	154,872	-	-	-	-	22
SIP issue matching	154,272	-	-	-	-	21
Shares issued in respect of MRP issues	8,307	-	-	-	-	-
At 30 June 2022	125,812,956	2	303,305,534	30,331	30,333	103,035

15 Subsequent events

On 25 May 2022, the Government announced the introduction of the Energy Profits Levy, effective 26 May 2022. At the balance sheet date, the proposal to introduce the Energy Profits Levy had not been substantively enacted. Therefore, its effects are not included in these financial statements. However, it was subsequently substantively enacted on 11 July 2022. Had it been substantively enacted by the balance sheet date it would have decreased the deferred tax asset and credit for the period by £0.3 million and generated a current tax expense of £0.2 million.

Glossary

£ The lawful currency of the United Kingdom

$ The lawful currency of the United States of America

1P Low estimate of commercially recoverable reserves

2P Best estimate of commercially recoverable reserves

3P High estimate of commercially recoverable reserves

1C Low estimate or low case of Contingent Recoverable Resource quantity

2C Best estimate or mid case of Contingent Recoverable Resource quantity

3C High estimate or high case of Contingent Recoverable Resource quantity

AIM AIM market of the London Stock Exchange

Bbl(s)/d Barrel(s) of oil per day

boepd Barrels of oil equivalent per day

bopd Barrels of oil per day

CCUS Carbon capture usage and storage

Contingent Recoverable Resource - Contingent Recoverable Resource estimates are prepared in accordance with the Petroleum Resources Management System (PRMS), an industry recognised standard. A Contingent Recoverable Resource is defined as discovered potentially recoverable quantities of hydrocarbons where there is no current certainty that it will be commercially viable to produce any portion of the contingent resources evaluated. Contingent Recoverable Resources are further divided into three status groups: marginal, sub ‑ marginal, and undetermined. IGas' Contingent Recoverable Resources all fall into the undetermined group. Undetermined is the status group where it is considered premature to clearly define the ultimate chance of commerciality.

Drill or drop - A drill or drop well carries no commitment to drill. The decision whether or not to drill the well rests entirely with the Licensee being driven by the results of geotechnical analysis. The Licence will, however, still expire at the end of the Initial Term if the well has not been drilled.

Firm well - A firm well is classified as a firm commitment to drill a well. It is not contingent on any further geotechnical evaluation (i.e. it is a fully evaluated Prospect).

GIIP Gas initially in place

m Million

Mbbl Thousands of barrels

MMboe Millions of barrels of oil equivalent

MMscfd Millions of standard cubic feet per day

PEDL United Kingdom petroleum exploration and development licence

PL Production licence

Tcf Trillions of standard cubic feet of gas

UK United Kingdom

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