30 March 2023

IGas Energy plc (AIM: IGAS)

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

Full year results for the year ended 31 December 2022

Commenting today Chris Hopkinson, Interim Executive Chairman, said:

"The production drive we initiated in October last year proved that we can overcome technical and operational challenges and I am delighted that we continue to maintain the momentum into the new financial year.

The higher oil and gas prices have been a welcome boost to revenue and cash generation giving us greater financial flexibility and enabling us to repay debt.   However, we believe now is the right time, given the prevailing price environment, to focus on driving opportunities for production, that pay back in a short time frame, and to that end we will seek to finance these near-term projects.  

It is also critical that we maximise the value of our oil and gas assets to facilitate a "just transition" to a renewable energy future through the growth of our geothermal heat business. Momentum is building in the geothermal business and we look forward to achieving financial close for the Stoke-on-Trent geothermal project and moving into the execution phase of that project during the year."   

Financial Performance

* Adjusted EBITDA, Net Debt (borrowings less cash and cash equivalents excluding capitalised fees) and Underlying Operating Profit are used by the Group, alongside IFRS measures for both internal performance analysis and to help shareholders, lenders and other users of the Annual Report to better understand the Group's performance in the period in comparison to previous periods and to industry peers

Corporate and Financial Summary

·    Higher operating cash flow resulted in a significant reduction in the Group's net debt to £6.1 million. Cash balances as at 31 December 2022 were £3.1 million

·    The Group made a loss after tax of £11.8 million. This was after deducting a £30.0 million impairment of our shale assets following the reimposition of the moratorium on hydraulic fracturing

·    Net cash capex of £7.9 million in 2022 primarily on our conventional assets 

·    Successful RBL redetermination confirming $17.0 million (£14.0 million) of debt capacity

·    We remain focused on maintaining a strong balance sheet and funding to support our strategy. We will continue to assess funding opportunities to optimise our capital structure and manage our debt facilities effectively

·    60,000 bbls hedged for H1 23 at an average swap price of $94.9/bbl (we are no longer required to hedge under the terms of the RBL)

·    Energy Profit Levy charge for 2022 of £nil

·    Ring fence tax losses at 31 December 2022 were c.£260 million

·    As the Company has been reshaping its strategic direction to reflect the transition to a lower carbon economy, the Board is proposing a change in the Company's name to Star Energy Group PLC (subject to shareholder approval at the AGM in June 2023)

Operational Performance

·    Restructuring and reorganisation of the business to enable improved strategic planning and more efficient decision making

·    Net production, averaged 1,898 boepd for the year, heavily impacted in the first half by equipment failure caused by supply chain issues, which was subsequently resolved

·    A production drive was initiated in October leading to a strong recovery in H2 resulting in peak production (averaged across 5 days) of 2,432 boepd and December production averaged 2,221 boepd (net to IGas)

·    Reserves and Resources updated CPR values 1P NPV10 of $144 million (2021: $139 million): 2P NPV10 of $215 million (2021: $190 million)⁺

·    Planning permission submitted and validated for Glentworth Phase I - potential for additional 200 bbls/d

·    The drilling of a new well in Corringham is planned for H2 2023 with both planning and permitting in place, which, if successful, is anticipated to add 110 bbls/d peak production

·    Awaiting imminent outcome of the Green Heat Network Fund grant application for Stoke-on-Trent geothermal project

·    We anticipate notification as to our success in the five NHS tenders through the Carbon and Energy Fund in Q2 2023

Outlook

·    We anticipate net production of c.2,000 boepd and operating costs of c.$41/boe (assuming an average exchange rate of £1:$1.23) in 2023

·    2023 abandonment costs of c.£6.5 million as we ramp up the abandonment and restoration of old and uneconomic fields, in line with our licence obligations and to focus on profitable fields.

·    In the process of purchasing a rig as part of setting up a dedicated abandonment division

·    We expect cash capex of £15.3m in 2023

o This includes £5.9 million for near-term incremental projects to generate c.150-170 boepd and £4.0 million to develop the Bletchingley gas-to-wire project which is expected to generate circa 47 GWh of power from late 2024/early 2025, subject to financing, and £1.0 million to progress developments at Singleton and Bletchingley

o The remaining capex will be spent on the maintenance and optimisation of our existing conventional sites

⁺Oil price assumption of c.$75/bbl for 5 years, then inflated at 2% p.a. from 2031 (capped at $118/bbl) see D&M Report

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

Ross Pearson, Technical Director of IGas Energy plc, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009 and as updated 21 July 2019, of the London Stock Exchange, has reviewed and approved the technical information contained in this announcement. Mr Pearson has 22 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, Chief Communications Officer

Investec Bank plc (NOMAD and Joint Corporate Broker) Tel: +44 (0)20 7597 5970

Virginia Bull/Chris Sim/Charles Craven

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

Interim Executive Chairman's Statement

2022 has been a year of change and refocus for the Company against a mixed set of challenges both domestic and global.

The weaponisation of energy by Russia driving already high prices in Europe to an unprecedented level has demonstrated that traditional energy sources will continue to be a fundamental part of the overall energy equation for many years to come. Given this backdrop, the national and local benefits of indigenous oil and gas supplies remain clear and even more compelling, with a positive impact on emissions versus imports and Liquified Natural Gas, energy security, the balance of payments through tax and business rates and employment.

As a British company operating onshore in the UK, we believe we have an important role to play in providing the UK's own domestic resources to give greater security of supply; something the UK Government in its British Energy Security Strategy has recognised. 

With a cost-of-living and energy crisis unfolding, the UK Government responded by lifting the moratorium on hydraulic fracturing in England on 8 September, 2022 and committed to review energy regulation, paving the way for the timely development of shale in the UK providing jobs, tax revenue, energy security and significant community benefits. Disappointingly, just a few weeks later, this decision was reversed on 27 October 2022.

Having taken advice, and reflected on our strategic goals as a business, we have decided not to pursue legal recourse further in respect to the reimposition of the moratorium on hydraulic fracturing and have fully impaired our remaining shale assets.  We continue to believe and assert that fracking for shale gas can and will be done safely and in an environmentally responsible manner.  There is a significant recoverable gas resource in the Gainsborough Trough, the equivalent of up to 19 years of the UK's gas demand, that could provide this country both energy security for years to come as well as providing billions of pounds of investment into the East Midlands and the creation of thousands of skilled jobs. It is unfortunate that this strategic resource is unlikely to be realised.

Board Changes

There have been a number of changes to the Board during the year.  Stephen Bowler, Chief Executive Officer, left IGas by mutual consent in September 2022.  Frances Ward, who joined IGas in 2017, was appointed as Chief Financial Officer and a Board Director in September 2022.

I 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, I took over the role of Chairman from Cuth McDowell who had served as Interim Non-executive Chair since October 2019 and a member of the Board since December 2012.  Following Stephen's departure in September, I assumed the role of Interim Executive Chairman.

In February 2022, we welcomed Kate Coppinger to the Board who then took over the role of Chair of the Audit committee from Cuth McDowell in June 2022. Tushar Kumar resigned from the Board as a Non-executive Director in July 2022.

Most recently, in January 2023, we welcomed Doug Fleming as a Non-executive Director.  Doug brings 27 years of senior experience working in oil and gas exploration and production, corporate banking and venture capital.

Our Performance in 2022

When I was appointed Interim Executive Chairman in September I indicated there would be necessary changes in the business to make it more efficient to ensure operational excellence in our conventional assets, that we expedite growth in our nascent geothermal business and we have a structure that correctly reflects the size and shape of the current business.   Furthermore, after a thorough review of the business, we undertook a restructuring and rightsizing of the Executive Committee  that will enable improved strategic planning and more efficient decision making, as the business looks to create a strong and relevant future for its investor base. 

The higher oil and gas prices have been a welcome boost to revenue and cash generation giving us greater financial flexibility enabling us to repay debt and invest in our assets.

Our operational performance was a year of two halves.  The first half was beset with equipment failure caused by supply chain issues and rig downtime due to staffing constraints, that resulted in a number of wells being offline. In October 2022, we introduced a series of initiatives to expedite a work programme to get us back on track and during Q4 the production drive resulted in us bringing online a significant number of wells and returning production to the forecast levels.  I want to thank everyone involved for all of the hard work and continued focus in delivering operational outperformance in Q4 and beyond.

There is no doubt that geothermal technology can provide a near-term, green solution to the decarbonisation of large scale heat in Britain bringing with it significant economic benefits.  As we transition from fossil fuels to renewable alternatives, the core skills deployed in the oil and gas sector, such as sub-surface geology, well engineering and drilling, are highly transferable to geothermal.

Outlook                                                  

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 through the expansion of its geothermal business. 

I am excited to be leading IGas at this important stage in its development.  We are now firmly focussed on maximising the value of our oil and gas assets to facilitate a "just transition" to a renewable energy future through the growth of our geothermal heat business. I look forward to working with the reinvigorated team as we grow the business, deliver operational excellence and create value for our investors, staff and communities.

Operating Review

Production

Net production for the period averaged 1,898 boepd (2021: 1,962) and was heavily impacted by equipment failure in the first half of the year.  The equipment failure was primarily caused by sub-standard material quality, largely as a run-on consequence of COVID-19 supply chain issues.  This resulted in a backlog of well repair work, which itself was delayed due to COVID-19 outbreaks amongst rig crews.

In October 2022, a production drive was initiated to ensure wells, plant and equipment had the maximum uptime, going from one to five fully operational rigs, returning 18 offline wells to production, converting two wells from jet pump to beam pumps, lowering operating costs and significantly increasing water injection capacity across our asset base.  We also introduced a production dashboard that tracks performance and provides a summary of our weekly priority work activities. As a result of these initiatives, Q4 2022 saw some of the highest production levels in recent times and on 14 December 2022, we produced 2,864 boe, including returns from hotwashes.  At peak production (averaged across five days) we produced 2,432 boepd and December production averaged 2,221 boepd (net to IGas).

In 2023, we will move the focus from bringing on any and all production to putting the business on a resilient and sustainable footing, able to withstand a wider range of commodity prices.  We will focus on maintaining and increasing production on more profitable fields, whilst attempting to drive down costs across the portfolio.  Given this focus and the annual average, underlying production decline of c.7%, we anticipate net production in 2023 of c.2,000 boepd.

Operating costs were $41.5/bbl driven primarily by increased energy costs and general price increases on equipment, offset by a more favourable foreign exchange rate. The largest component of increased energy costs was the price of electricity. However,  given IGas is a net exporter of electricity, there is a net benefit to IGas of £0.5 million, equivalent to $0.93/boe. Increased costs are being observed with most goods and services alongside extended delivery times for equipment. To try and mitigate some of these factors, critical items are being bulk ordered for stock resulting in higher spend levels.

We continue to focus our technical and operational expertise on offsetting the underlying natural decline in our fields.  This is achieved through the execution of incremental production opportunities that demonstrate commercial benefit via our delivery assurance processes.

During 2022, we completed the abandonment of three wells, two on the Stockbridge field and one on the Egmanton field. 

As we look to the future, part of our transition strategy is the abandonment and restoration of old and uneconomic fields, in line with our licence obligations.  Our abandonment programme will be accelerated consistent with this strategy, and to support our focus on profitable fields.  As part of that strategy, we are moving to campaign style abandonment and to support this, have created a dedicated abandonment division within the business. We are in the process of purchasing a rig to service the abandonments, which will bring the additional benefit of being utilised for workovers that will ultimately drive down third-party costs.

We continue to work closely with all our regulators to ensure we at least meet, if not exceed, our responsibilities as a responsible operator. 

Reserves and resources

CPR

In February 2023, IGas announced the publication of the full and final results of the Competent Persons Report (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 2022. The full report can be found on the IGas website www.igasplc/investors/publications-and-reports

IGas Group Net Reserves & Contingent Resources as at 31 Dec 2022 (MMboe).

*Oil price assumption of c.$75/bbl for 5 years, then inflated at 2% p.a. from 2031 (capped at $118/bbl)

1P NPV10 of $144 million(2021: $139 million): 2P NPV10 of $215 million (2021: $190 million)*

Development

Conventional oil and gas

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 allowed c.200 bbls/d of suspended production to be brought back online.  The project also provides more operational flexibility in handling produced water in the Stockbridge area. 

During the year, we continued to mature our growth opportunities in the East Midlands at Corringham and Glentworth submitting applications for planning and permitting and in the Weald, submitting permit applications for Bletchingley. 

On the infill drilling project at Corringham, which has the potential to add c.110 bbls/d and 0.35 mmstb 2P reserves, we have now discharged all our planning conditions and we received environmental permits in March 2023.  Execution of this project, along expected timelines, should add production at the end of 2023.

There is a mature opportunity to install 6MW of electrical generation capability at the Bletchingley Central site fuelled by gas from the Bletchingley 2 well, which is currently suspended.  This will generate circa 47GWh of electricity delivered into the local distribution network.  First power export from this project is expected in late 2024/early 2025.

Glentworth, is a larger appraisal/development project to extend one of our existing fields. We submitted a planning application to Lincolnshire County Council for the construction of a new wellsite, to the west of our existing Glentworth-K oil production site in December 2022. The application was validated by the Council in December 2022.  It is currently scheduled to be heard at the April 2023 Planning Committee meeting.  Phase I has the potential to add c.200 bbls/d and development of c.1.0 mmstb 2P reserves (currently 2P undeveloped).

If phase I is successful, this will be followed by further development drilling in subsequent years with the subsequent development having the potential to add an additional 500bbls/d and the addition of c.2mmstb 2P reserves from 2C.

As well as executing the Corringham, Bletchingley and Glentworth projects, we look forward to bringing back production at our shut-in Avington field and continue to mature our portfolio of opportunities, particularly around the Singleton and Welton fields. 

Shale

The Group holds a significant portfolio of shale licences, totalling 292,100 net acres with estimated Mean volumes of undiscovered GIIP of 93 TCF (net to IGas, independently assessed by D&M in 2016).

Following a concerted effort from the UK onshore oil and gas industry, on 5 April 2022 the Government announced that it had commissioned the British Geological Survey to advise on the latest scientific evidence around shale gas extraction. This report was delivered to BEIS on 5 July 2022.

On 8 September 2022, the Government announced a lifting of the effective moratorium on hydraulic fracturing in England and a review of energy regulation. On 27 October 2022, the Government, under the leadership of Rishi Sunak, as Prime Minister, reintroduced the moratorium on hydraulic fracturing for shale gas.

We have fully impaired our remaining shale assets and the Springs Road well will be fully abandoned and restored by Q1 2024.

Geothermal Heat

We have made significant progress during the year in bringing our vision for decarbonisation of large-scale heat using geothermal energy, in the UK, closer to fruition.  We have been working closely with the Government, academia and commercial partners to accelerate support for, and understanding of, this proven technology.

Launched in March 2022 the GHNF opened up for the drilling of geothermal wells. The GHNF Transition Scheme 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 deep geothermal wells and associated works.  We submitted an application with SSE for the Stoke-on-Trent district heat network project and await a decision on the grant award.

In December 2022, we made applications for grant funding from the Public Sector Decarbonisation Scheme in partnership with the Carbon Energy Fund (CEF) for the development of five geothermal schemes, supplying renewable heat to NHS Trusts.  We anticipate notification as to our success in Q2 2023.  Subject to our success in one or more of the schemes, a further five or more NHS sites are likely to be put forward in H2 2023.

The Public Sector Decarbonisation Scheme, which provides grants for public sector bodies to fund site decarbonisation, launched its Phase 3 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.

As awareness grows of the potential for geothermal we are being approached by numerous end-users - public sector and commercial - in search of low carbon solutions to replace higher carbon sources of heat provision.

Our project pipeline continues to grow and mature and we are in active discussions with potential customers for 35 projects. 

The Government is also actively working on longer term support for geothermal with the Department for Energy Security and Net Zero commissioning ARUP and the British Geological Survey to produce 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. 

Outlook

During 2023, we expect to start delivering on the organisation's diversification strategy.  We expect to achieve financial close for the Stoke-on-Trent geothermal project and move into the execution phase of that project.  This will be a fundamental step forward for the company and for the wider geothermal sector in the UK.  We will continue to grow and mature our pipeline of geothermal opportunities across the UK.

Financial Review

Commodity prices remained strong during the year, with Brent averaging c.$108/bbl in the first half of the year before falling to an average of c.$95/bbl in the second half, resulting in  strong operational cash flow from our  conventional oil and gas assets. Natural gas prices remained volatile, reaching peaks of over 500p/therm and 700p/therm in March and August, respectively, and averaging 262p/therm for the year. Sterling weakened during the year, declining to a low of £1:$1.07 before recovering to £1:$1.22 towards the end of the year. Average  GBP/USD rates were £1:$1.23 in 2022 compared to £1:$1.38 in 2021, which also had a favourable impact on our revenues.

Production for the year averaged 1,898 boepd (2021: 1,962 boepd) meeting our guidance for the year despite supply chain and staffing challenges which impacted our ability to perform well interventions as quickly as planned in the first half of the year. However, good results from our Stockbridge water injection well, production enhancement and optimisation expenditure  and a production initiative in the fourth quarter meant we were able to mitigate these issues and offset the natural declines from our fields. Whilst volumes declined from last year, the improved pricing and weakening of sterling resulted in increased revenues of £59.2 million for the year (2021: £37.9 million) which was partially offset by a realised loss on hedging of £8.0 million (2021: £6.6 million). Operating costs increased to £24.0 million (2021: £19.1 million) reflecting  inflationary increases in materials and equipment costs, supply chain disruptions, additional workover and maintenance activity and an increase in electricity costs. Operating costs also include an increase of £1.5 million relating to the purchase of third party oil volumes which is offset by higher revenue from their sale. Depreciation, depletion and amortisation (DD&A) increased to £6.3 million (2021: £4.8 million) mainly due to the increase in the carrying value of assets following the reversal of impairment to oil and gas properties recorded in June 2022. Underlying operating costs per boe, excluding third party oil but including costs relating to leases capitalised under IFRS 16, were £33.4 ($41.5) per boe for the year (2021: £27.1 ($37.4) per boe.

A net impairment reversal was recognised on oil and gas assets in the year of £0.03 million (2021: Nil). An impairment reversal of £10.5 million was recorded  in the South Cash Generating Unit (CGU) as a result of higher commodity prices. In the North CGU, an impairment charge of £8.9 million was recognised due to the increase in discount rates, higher operating costs and the impact of the Energy Profit Levy.  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. Exploration and evaluation assets of £30.0 million were also written off during the year which included £6.0 million related to PEDL 184 following the rejection of planning consent on appeal for a well test of the Ellesmere Port-1 well and £23.8 million related to PEDLs 12, 139, 140, 169 and 210 in our core Gainsborough Trough area, following the reimposition of the moratorium on hydraulic fracturing for shale gas by the UK Government in October 2022. 

Adjusted EBITDA was £21.1 million (2021: £5.9 million) and the underlying operating profit was £16.1 million (2021: £2.0 million), with the increases resulting primarily from improved revenues and gross margin.

Higher operating cash flows resulted in a significant reduction in the Group's net debt to £6.1 million as at 31 December 2022 (31 December 2021: £12.2 million). The Group's RBL is subject to a semi-annual redetermination which confirmed an available facility limit of £14.0 million ($17.0 million) as at 1 January 2023.

Income Statement

The Group recognised revenues of £59.2 million for the year (2021: £37.9 million). Group production for the year averaged 1,898 boepd (2021: 1,962 boepd). Revenues included £2.7 million (2021: £1.1 million) relating to the sale of third party oil, the bulk of which is processed through our gathering centre at Holybourne in the Weald Basin. 

The average pre-hedge realised price for the year was $98.6/bbl (2021: $68.5/bbl) and post-hedge $82.7/bbl (2021: $54.3/bbl). A loss of £8.0 million was realised on hedges due to an increase in oil prices during the year (2021: £6.6 million).  The average GBP/USD exchange rate for the year was £1: $1.23 (2021: £1: $1.38).

Cost of sales for the year were £30.3 million (2021: £23.9 million) including DD&A of £6.3 million (2021: £4.8 million), and other costs of sales of £24.0 million (2021: £19.1 million). The DD&A charge has increased by £1.5 million in the year due to the increase in the carrying amount of the underlying oil and gas assets as a result of the reversal of impairment on the South CGU in June 2022. Other costs of sales were £4.9 million higher than the prior year. £1.5 million of the increase related to the purchase of third party oil which was offset by higher revenue from related sales. The remaining increase was due to inflationary increases in materials and equipment costs, supply chain disruptions, additional workover and maintenance activity and an increase in electricity costs.  

Underlying operating costs per barrel of oil equivalent (boe), excluding third party oil but including costs relating to leases capitalised under IFRS 16, increased to £33.4 ($41.5), (2021: £27.1 ($37.4) per boe), as a result of the higher operating costs in the year.

Adjusted EBITDA in the year was £21.1 million (2021: £5.9 million).  The gross profit for the year was £28.8 million (2021: £14.0 million). 

Administrative costs increased by £0.5 million to £6.3 million (2021: £5.8 million). The increase was due to higher staff costs arising as a result of inflation increases and redundancy costs incurred during the year. This was partially offset by lower legal and professional costs and a higher allocation to capital projects.

A net impairment reversal of £0.03 million was recorded on oil and gas assets during the year (2021: £nil). The impairment assessment at year end was based on a discounted cash flow model prepared using price assumptions for Brent of $70-80/bbl for the years 2023-2027 and $65/bbl thereafter. Management also performed sensitivity analysis on the key assumptions. Whilst the impairment assessment supported a reversal of the previously recorded impairment of £10.5 million for the South CGU, an impairment charge of £8.9 million was recognised in the North CGU as a result of the impact of an increase in the discount rate, higher operating costs and the expansion of the Energy Profits Levy scheme, which  more than offset the benefits from higher oil price forecasts for that CGU. In addition, an impairment charge of £1.5 million was recorded against the Scotland CGU in respect of past costs as these are not expected to be recovered in any future development of the site.

Exploration and evaluation assets impairments during the year were £30.0 million. This included £6.0 million relating to PEDL 184 following the rejection of planning consent on appeal for a well test of the Ellesmere Port-1 well and, as the Group have no plans for further activity on the licence, the full capitalised amount has been written off (2021: £10.5 million). In addition, £23.8 million was written off primarily related to PEDLs 12, 139, 140, 169 and 210 in the Gainsborough Trough area following the reimposition of the moratorium on hydraulic fracturing for shale gas by the UK Government in October 2022, a month after it was temporarily lifted. The Board assessed that, given the broad political consensus in the UK on this issue, the moratorium is unlikely to be lifted in the near to medium-term and therefore that the Group is unlikely to be able to proceed with the commercial development of this asset, hence the full capitalised value was written off.

Net finance costs were £5.1 million (2021: £3.9 million). Interest and amortisation of finance fees on borrowings were £1.2 million (2021: £1.1 million) with the impact of a reduction in the amount drawn being offset by higher interest rates. Finance costs also included the unwinding of discount on provisions of £1.7 million (2021: £1.9 million) and a foreign exchange loss of £1.4 million (2021: £0.2 million) due to the revaluation of our USD denominated loan at a stronger USD/GBP rate. Interest on leases was £0.7 million (2021: £0.7 million).

The increase in oil prices during the year generated a net loss on oil price derivatives of £6.0 million (2021: £6.7 million).

A net tax credit of £6.6 million (2021: £6.2 million) was recognised during the year, mainly due to the increase in a deferred tax asset relating to tax losses following an improved short term oil price and foreign exchange environment (£14.1 million), partially offset by a deferred tax charge arising as a result of the Energy Profits Levy (£4.6 million) and accelerated capital allowances of (£3.0 million).

Cash Flow

Net cash generated from operating activities for the year was £18.1 million (2021: £7.1 million). The increase was primarily due to higher revenue partially offset by a realised hedge loss, higher operating costs and working capital movements. We also spent £2.2 million on our abandonment programme during the year related to wells in the Stockbridge and Egmanton fields (2021: £0.4 million).

The Group invested £7.9 million across its asset base during the year (2021: £4.8 million). £7.2 million was invested in our conventional assets primarily to convert an existing, suspended well in the Stockbridge field to a water disposal well allowing c.200 bbls/d of suspended production to be brought back on line and in smaller projects to generate near-term production and offset field declines by upgrading existing facilities and systems and optimising production at a number of sites. £0.5 million was spent on working up additional exploration opportunities on conventional assets as well as maintenance costs relating to shale licences.

The Group made a repayment of £8.0 million ($10 million) (2021: £0.7 million ($1.0 million)) under the RBL and paid £1.0 million ($1.2 million) in loan interest (2021: £0.8 million ($1.0 million)).

To protect against the volatile oil price and in accordance with the requirements of our RBL facility, the Group placed commodity hedges for a period of up to 12 months. As at 31 December 2022, the Group had hedged a total of 60,000 bbls for 2023, using fixed price swaps at an average fixed price of $94.93/bbl.

Cash and cash equivalents were £3.1 million at the end of the year (2021: £3.3 million).

Balance Sheet

Net assets reduced by £10.3 million to £58.3 million at 31 December 2022 (2021: £68.6 million), primarily due to the impairment of capitalised exploration costs related to our shale assets, offset by a reduction in borrowings and in our decommissioning provision.

Property, plant and equipment increased by £0.1 million during the year as a result of capital expenditure of £7.8 million, offset by a DD&A charge of £5.0 million  and a reduction in the value of decommissioning assets of £2.7 million.

Intangible assets reduced by £29.1 million following an impairment of shale assets of £30.0 million. Additions to oil and gas exploration and evaluation assets and geothermal development assets were £0.7 million and £0.2 million, respectively.

The provision for decommissioning costs decreased by £3.2 million (2021: increase of £3.3 million) as a result of abandonment activity during the year (£2.3 million), an increase in discount rates and a change in inflation assumptions and the expected timing of abandonments (£2.7 million), offset by the unwinding of the discount on the provision of £1.7 million.

At 31 December 2022, right-of-use assets were £7.4 million (2021: £7.0 million) and related lease liabilities were £7.8 million (2021: £7.2 million).

We repaid $10.0 million (£8.0 million) on our RBL loan facility during the year reducing net debt to £6.1 million by year end (2021: £12.2 million).

2023 Capital Expenditure

We are forecasting cash capex of £15.3 million in 2023, subject to financing. This includes £5.7 million for near-term incremental projects to generate c.150-170 boepd, including 110 bbls/d from our Corringham project which is expected to be online at the end of 2023. The remaining expenditure includes £4.0 million to develop the Bletchingley gas-to-wire project which is expected to generate circa  47 GWh of power from late 2024/early 2025, £1.0 million to progress development projects at Singleton and Glentworth,  and expenditure on the maintenance and optimisation of our existing conventional sites.

We expect a cash outflow of c.£6.5 million for our abandonment programme in 2023 to be spent primarily in carrying out abandonment works in the Egmanton field and abandoning two shale wells. We are also in the process of purchasing a rig as part of setting up a dedicated abandonment division.

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 and 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.

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 while 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 whereas China's relaxing of COVID-19 restrictions and resumption of normal economic activity will support prices.

The Group's operating cash flows have improved in 2022 as a result of improving commodity prices and we have successfully completed the November 2022 redetermination. A successful production drive and reorganisation was undertaken in the last quarter of 2022, which resulted in a significant increase in production and we have seen the benefit of this extending into 2023, putting the business on a resilient and sustainable footing, able to withstand a wider range of commodity prices. 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.

The Group's base case cash flow forecast was run with average oil prices of $84/bbl for H1 2023 and $83/bbl for H2 2023, falling to $80/bbl for H1 2024 and $77/bbl for Q3 2024, and a foreign exchange rate of an average $1.23/£1 for 2023 and $1.25/£1 for 2024. 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 $nil million from 30 June 2024. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility for a period of 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 $80/bbl for H1 2023, $72/bbl for Q3 2023 and $68/bbl for Q4 2023, falling further to $65/bbl for H1 2024 and $62/bbl for Q3 2024. We used an average exchange rate of $1.25/£1 for the remainder of H1 2023, $1.27/£1 for H2 2023 and  H1 2024 and $1.30/£1 for Q3 2024. Our downside case also included an average reduction in production of 5% over the period. In the event of the downside scenario, management would take mitigating actions including delaying capital expenditure and reducing costs, in order to remain within the Group's debt liquidity covenants over the remaining facility period, 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 the 12 months from the date of approval of the financial statements. Management remain focused on maintaining a strong balance sheet and funding to support our strategy. As part of this financial policy, management continue to assess funding opportunities and plan to refinance the existing RBL before its expiry date.

Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue as a going concern for at least the next twelve months from the date of the approval of the Group financial statements and have concluded it is appropriate to adopt the going concern basis of accounting in the preparation of the financial statements.

Frances Ward

Chief Financial Officer

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 and underlying operating profit.

These non-IFRS measures are used by the Group, alongside IFRS measures, for both internal performance analysis and to help shareholders, lenders and other users of the Annual Report to better understand the Group's performance in the period in comparison to previous periods and to industry peers.

Net debt is defined as borrowings excluding capitalised fees less cash and cash equivalents and does not include the Group's lease liabilities.

Adjusted EBITDA and underlying operating profit includes adjustments in relation to non-cash items such as share-based payment charges and unrealised gain/ loss on hedges.

Lease costs for the period which have been capitalised under IFRS 16 have been added to underlying operating costs and deducted in the calculation of adjusted EBITDA to be consistent with previous periods.