WTI $66.32 -53c, Brent $69.32 +60c, Diff -$3.00 +39c, NG $2.99 +3c, UKNG 63.36p +2.85p
As I write the Opec + meeting is still going on, oil is drifting off the days highs so there might be a 600/- b/d release as some had guessed. Comment of the day is from the KSA Oil Minister who described the IEA ‘net-zero road map’ is out of La La Land, a man after my own heart.
The rig count was up a tad, 2 overall to 457 and oil up by 3 to 359 which ain’t going to change anything. Oil was up on the week, and the month by between $2.56-2.88. The news on the virus is getting significantly better from Europe but still bad in Asia.
Prelims from SAVE on Friday afternoon in which the highlights were as follows. FY 2020 Total Revenues of US$235.9m (+23% on FY 2019 pro-forma Total Revenues of US$192.1m); Average realised gas price of US$3.96/Mscf (+11% on the 2019 average realised pro-forma gas price of US$3.56/Mscf) and an average realised liquids price of US$46.2/bbl (-30% compared to the 2019 average realised pro-forma liquids price of US$66.3/bbl). It is worth noting that gas accounts for 88% of production so there is very little oil-price linkage in revenues.
Total cash collections from the Company’s Nigerian assets of US$187.4m (+11% on FY 2019 pro-forma cash collections of US$168.8m); FY 2020 Adjusted EBITDA of US$183.6m (+19% on 2019 pro-forma Adjusted EBITDA of US$153.8m); FY 2020 Adjusted EBITDA margin remained broadly unchanged at 78%;
FY 2020 Group Operating expenses plus administrative expenses of US$46.4m (FY2020 initial guidance of US$68.0-72.0m); FY 2020 Group Depreciation, Depletion and Amortisation of US$36.3m (FY 2020 initial guidance of US$43.0-45.0m and 2019 pro-forma of US$53.7m);
Group cash balances of US$106.0m as at 31 December 2020 (+121% versus FY 2019 year-end Group cash balances of US$48.1m); Group net debt of US$408.7m as at 31 December 2020 (-16% versus FY 2019 year-end Group net debt of US$484.0m); Leverage was 2.2x, a 31% improvement from 2019 pro-forma leverage of 3.2x, and an interest cover ratio of 2.8x, a 33% increase from 2019 pro-forma ratio of 2.1x; and total Group assets amounted to US$1,207.2m at year-end (2019: US$1,145.0m).
Operationally, FY 2020 average gross daily production from the Nigerian operations was 19.5 Kboepd, a 14% increase from the average gross daily production of 17.2 Kboepd in FY 2019; Of the FY 2020 total average gross daily production of 19.5 Kboepd, 88% was gas, including a 17% increase in production from the Uquo gas field, from 88.1 MMscfpd (14.7 Kboepd) in FY 2019 to 102.8 MMscfpd (17.1 Kboepd) in FY 2020.
Achievement of an all-time gas production record from the Nigerian assets of 177 MMscfpd on 30 May 2020; All-time high peak gas contribution equivalent to 13% of the total country-wide Nigerian average grid-based generation achieved on 29 June 2020; In January 2020 Accugas entered into the first new gas sales agreement for the business in over five years with First Independent Power Limited, an affiliate company of the Sahara Group, for the provision of gas to the FIPL Afam power plant.
In December 2020 Accugas agreed a revised GSA with Lafarge Africa PLC, a wholly-owned subsidiary of Lafarge Holcim and operator of the Mfamosing cement plant in Cross River State, Nigeria. This extended the contract tenor by five years to January 2037 and raised the average life-of-contract gas price; and in February 2021, Accugas signed a new GSA with Mulak Energy Limited (“Mulak”) representing Savannah’s entry into the high-growth compressed natural gas (“CNG”) market in Nigeria.
Savannah reiterates its guidance for the full year 2021 as follows: Total Revenues1of greater than US$205.0m from upstream and midstream activities associated with the Company’s three active Nigerian gas sales agreements (excluding gas sales to FIPL and Mulak) and liquids sales from the Company’s Stubb Creek and Uquo fields. Total Revenues received from gas sales to FIPL and any new additional gas sales agreements would, therefore, be incremental to this;
Group Operating expenses plus administrative expenses of US$55.0m-US$65.0m; Group Depreciation, depletion and amortisation of US$19m fixed for infrastructure assets plus US$2.6/boe for oil and gas assets; and group capital expenditure of up to US$65.0m.
¹Total Revenues refers to the total amount of invoiced sales recorded in the financial year. This number is seen by management as more accurately reflecting the underlying cash generation capacity of the business compared to Revenue recognised in the income statement. A detailed explanation of the impact of IFRS 15 revenue recognition rules on our income statement is provided in the Financial Review section of our 2019 Annual Report. For reference FY 2020 Revenues were US$169.0 million (up 28% on FY 2019 pro-forma Revenues of US$132.3 million).
With regards to Niger, Savannah update the market as follows, during the first half of 2020, the Company agreed with the Niger Ministry of Petroleum that the R4 licence area would be combined with the R1/R2 PSC area into a new R1/R2/R4 PSC to be issued under the Petroleum Code 2017 and that the R3 PSC would continue as a stand-alone PSC area, thus retaining the full acreage position previously covered by the R1/R2 PSC and the R3/R4 PSC. Ratification of the new R1/R2/R4 PSC was subject to Council of Minister approval, and payment of the associated fee.
The Company has subsequently agreed in principle with the Ministry of Petroleum to amalgamate the four licence areas (covered by the R1/R2 PSC and the R3/R4 PSC) into a single PSC rather than the previous proposal of two PSCs. The new PSC (being a R1/R2/R3/R4 PSC) will be valid for 10 years from the date of signing the agreement. Ratification of the new PSC is subject to Council of Minister approval and the payment of the associated fee which is expected to occur by the end of July 2021.
Plans for delivering the R3 East development continue to progress with the intention to commence installation of an Early Production Scheme by the end of FY 2021, subject to market conditions and financing.
Savannah has announced its refocused Sustainability Strategy for the Group which is a state of the art policy and it appears that the company is determined to be the leaders in this field and are never likely to run into any problems specifically when compared to their peer group.
‘Following the acquisition of our Nigerian assets we have conducted a thorough review of our sustainability strategy for the enlarged group, taking into account the feedback of an extensive consultation exercise we have conducted with our key external and internal stakeholder groups. Following this exercise, we have chosen to refocus our sustainability strategy around four key strategic pillars: (1) promoting socio-economic prosperity; (2) ensuring safe and secure operations; (3) supporting and developing our people; and (4) respecting the environment. Our four strategic pillars are aligned with 13 key United Nations Sustainable Development Goals, where we believe Savannah can have the biggest economic, environmental, social and governance impact to achieve a better and more sustainable future for all.
While anchoring our strategy around the 13 most relevant UN SDGs to Savannah, we have chosen to integrate six additional sustainability reporting standards into our new performance and reporting framework. These have been selected on the basis of those most relevant for our sector and of most importance to our stakeholders and include those for: the Global Reporting Index (“GRI”); the eight International Finance Corporation Performance Standards (“IFC PS”); the International Association of Oil and Gas Producers (“IOGP”); the International Petroleum Industry Environmental Conservation Association (“IPIECA”); the Sustainability Accounting Standards Board (“SASB”); and the Task Force on Climate-related Financial Disclosures (“TCFD”). We are rolling out our new sustainability performance and reporting framework across the Group during the remainder of 2021 with a view to reporting on this from 2022 onwards’.
Andrew Knott, CEO of Savannah Energy, said:
“2020 represented our first full year of ownership since the completion of the acquisition of our Nigerian assets and our financial results show just how transformational the acquisition has been for Savannah. Against a challenging backdrop, we recorded a robust financial and operating performance. We beat all of our original financial guidance metrics. Total Revenues and cash collections rose for the fifth consecutive year on a pro-forma basis, while our Adjusted EBITDA margin at 78% remained industry leading. Operationally our daily production levels rose 14% and we achieved these results with zero recorded Lost Time Injuries for the year. Our performance against key sustainability metrics such as carbon intensity, senior management gender diversity and local employees are all equally industry leading.
Further we have sown the seeds for our future growth with three gas sales agreements (“GSAs”) signed since the beginning of 2020, two of which opened up new high-potential growth markets for our business. Our GSA to supply the FIPL Afam power station marks our entry into the potentially high-growth Port Harcourt Industrial area in Nigeria, while our GSA with Mulak Energy Limited, signed in Q1 this year, provides us with a promising opportunity in the country’s expanding compressed natural gas (“CNG”) market.
We have had a strong start to 2021, with January to April 2021 production having grown 9% year-on-year to 22 Kboepd, a new all-time high level for our assets. We are reiterating the 2021 guidance we provided on 25 January 2021. Additionally, key organic value creation milestones for this year, not contained in our 2021 guidance, include the delivery of first gas sales to the FIPL Afam power station, the re-financing of our US$371 million Accugas debt facility and the continued progression of the development of our Agadem Rift Basin oil project in Niger. We remain completely focused on the huge opportunity set we see in Africa for both organic and in-organic growth and I look forward to updating stakeholders as we continue our exciting journey.”
Savannah is really going from strength to strength and I see this continuing on an organic and inorganic basis. With market share in Nigeria of 10% but probably nearer 15% new clients are probably waiting to sign up and with such growth impending that positive stance on the dividend remains. Net debt is falling and with rising production could significantly increase the valuation that has been held back by the market.
Looking at the guidance for this year the company are on track to give them margins which at c.78% must be better than anything in the space and can only increase as they eat into the spare capacity. As to Niger the amalgamation of the PSC’s should be signed off before long and whilst there have been some, inevitable delays, the EPS is still expected this year. All in all the management is in the process of putting together a business that has the opportunity to be a huge, clean company in its space that few have seen the like of, I know I say it a lot and it has taken longer than I thought it surely should be a ten-bagger from here…
Sound has provided an update further to its announcement of 3 September 2020 that the Moroccan branch of its wholly-owned subsidiary, Sound Energy Morocco East Limited had received a written notification by the Moroccan General Tax Administration of a re-assessment in respect of Moroccan taxes pursuant to a tax audit undertaken on SEMEL by the Moroccan Tax Administration during 2020 and related to the fiscal period 2016 to 2018. The Company also announces the receipt of an additional, but related, notification from the Moroccan Tax Administration.
The Company entirely refutes the Moroccan Tax Authority’s position and having taken detailed specialist taxation and legal advice, is also liaising with Moroccan governmental authorities to seek a satisfactory conclusion of the matter, whilst the formal process related to Notification continues, with the next stage being the first local tax committee (the “LTC” ) hearing on 3 June 2021 in which SEMEL and the Moroccan Tax Administration will present their respective positions (pursuant the Notification) to the LTC. The LTC process can take up to 12 months. Thereafter, the matter may proceed to national committee stage, if not concluded, thereafter for arbitration. Regarding the Additional Notification, the Company will formally write to the Moroccan Tax Administration to formally refute the assessment and the basis thereof.
Commenting, Graham Lyon (Executive Chairman) said:
“Whilst I am satisfied that constructive dialogue is ongoing in relation to the original notification, I am exceptionally disappointed to have received the subsequent notifications from the Moroccan Tax Administration relating to Sound Energy Morocco SARL AU. Since entering Morocco in 2015, Sound Energy and its partners have invested over US$140 million, with as yet no production revenue nor capital gain. This inward investment has not only created jobs, provided subsequent employment taxation and economic stimulus in Morocco but has heightened interest in what was hitherto an often-overlooked country for upstream investments.
One of the attractive features of Morocco from an industry perspective is its fiscal code as laid out under its Hydrocarbon Code. This includes a 10-year exemption from corporation tax for upstream producers, as well as, ironically, import duty and VAT exemptions. With Sound Energy on the cusp of concluding commercial arrangements in order to sanction our Phase 1 development project at the Tendrara Production Concession, the continuation of these ill-judged tax notifications is an unwelcome distraction from our goal of delivering value to Sound Energy shareholders and delivering stakeholder value and economic benefits in Morocco.
The tax framework of the hydrocarbon sector not being applied is a poor reflection on doing business in Morocco. Hopefully the meeting held yesterday (31 May 2021), with the assistance of our State-owned partner ONHYM, at the Ministry of Finance will help to satisfactorily conclude this matter.”
Looking at this case it does appear that Sound have the arguments on their side and that the tax authorities appear to be damaging Morocco’s reputation. A solution is required if Sound are to invest further in the country and the Government should be minded to watch this very carefully.
A trading and operations update from Pharos this morning. Group working interest production for the four months to April 2021 was 9,360 boepd net with Egypt production 4,010 bopd and Vietnam production 5,350 boepd. The Vietnam TGT infill well drilling campaign due to start Q3 2021.
Group revenue for January – April 2021 was c.$40m after net hedging loss of $9m and Cash balances as at 30 April 2021 of c.$31m, net debt of c.$25m. Forecast cash capex for full year of c.$32m and 2021 working interest production guidance unchanged from 7 April 2021.
Egypt is 4,000-4,400 bopd, prior to any investment from a farm in partner and Vietnam is 5,200-6,200 boepd.
Ed Story, President and Chief Executive Officer, commented:
“As a group, we are well positioned to allocate capital this year to drive cash flow and future value.
In Vietnam, we will start the next phase of our TGT development plan when we commence infill well drilling in Q3 2021. In Egypt, good progress has been made to find the right partner to support the funding of the development plan for the discovered resource in El Fayum. In addition, modest capital is being allocated to the organic growth potential of some of our exploration assets. In Egypt, the Batran exploration well is currently operating and in Vietnam, our 3D seismic programme in the north-western part of Block 125 is planned for H2 2021.
I would like to take this opportunity to thank all stakeholders for their continued support. The key investments in oil-field developments will deliver free cash flow and significant production growth.”
Chariot Oil & Gas
Chariot, the Africa focused transitional energy group, is pleased to announce that further to the announcement on 23 March 2021 in respect of the acquisition of the business of Africa Energy Management Platform all conditions in the share purchase agreements and other related transactions agreements have now been satisfied and completion of the transaction is expected imminently.
Initial consideration payable on completion of the share purchase agreement is US$1.16 million in Chariot Ordinary Shares based on the 30-day VWAP prior to the signing of the SPAs (representing 9,196,926 shares) and US$0.09 million in cash.
Adonis Pouroulis, Acting CEO of Chariot, commented:
“I am delighted that our acquisition of AEMP will complete imminently. The launch of Chariot Transitional Power places the Company in a unique position in the market. This acquisition will see us work with our partner, Total Eren, to provide clean, sustainable, and more competitive energy to operational mines in Africa. A market of significant scale, that is largely untapped, where Chariot’s management has a deep understanding and high-level commercial networks.
The focus on transitional energy can also be seen at our Anchois gas discovery, where Chariot has the potential to provide the Kingdom of Morocco with natural gas, enabling the country to achieve its target of decarbonising its economy and reducing its dependence on imported fuels.
Following the completion of the fundraise, which is subject to shareholder approval at the forthcoming General Meeting, Chariot will occupy an exciting inflexion point in its history. The Board and management team continue to be fully aligned with our investors and we remain focused on delivering value for all our stakeholders. I look forward to keeping the market updated on the Company’s progress throughout the rest of 2021.“
PetroTal announces it secures liquidity, improves risk management position, and advances offtake optionality prior to executing an operationally focused and pivotal development plan.
In Q1 2021 Selected Operational Highlights it commenced drilling the 7D well, which was successfully completed on April 30, 2021. PetroTal started drilling well 7D on March 29, 2021, reaching a vertical depth of 2,696 meters and encountering excellent oil producing sands. The well was drilled and completed at a revised final cost of $7.6 million, or 17% below budget. After the typical clean-up period and slowly ramping up production during the following week, the 7D averaged over 4,500 bopd over a four-day period, accumulating over 115,000 barrels of oil during its first month of production, and maintaining average production rates of 4,000 bopd during the past four weeks.
It also upsized the pump on 4H and installed a new electro-submersible pump on the 4H well under budget and on time. Soon after the workover, the well was producing at 400 bopd higher than before the operation and is expected to recapture the incremental cost of the pump over the next few months at current Brent levels.
Production is materially on target, for Q1 2021 averaged 7,331 bopd which was materially on budget. Current production is 10,225 bopd, notwithstanding that two oil wells remain shut in waiting on water disposal pump enhancements which has reduced production by an estimated 1,200 bopd.
The CPF-2 on track and on budget with materials for phase two of its central processing facility continue to be installed and the project is on track for a Q3-Q4 2021 commissioning. PetroTal is reiterating 2021 guidance. The Company is reaffirming its 2021 average production target of 11,500 bopd.
The Company completed the placement of a 3-year $100 million senior secured bond with a 12% coupon and a borrowing limit of $125 million. The Company exceeded compliance with all covenants at March 31, 2021 with the newly issued bonds being the only material long term debt on the balance sheet.
It improved corporate risk management, during the quarter, the Company hedged 590,000 barrels in a put structure with a $60/bbl strike price. Subsequent to the quarter end, The Company hedged an additional 622,000 barrels at similar strike prices bringing hedged April 2021 to December 2021 production to 32% of budget.
The company is constantly de-risking and by working with Petroperu, the Company solidified, through hedging, a $31 million future true-up payment for approximately 1.8 million barrels of oil in the North Peruvian Pipeline and implemented a risk management partnership process with Petroperu for future sales into the ONP. The receipt of the $31 million is subject to the pace of oil movements through the ONP and is expected to be received by PetroTal as sales arrive in Bayovar throughout the next nine to twelve months.
It executed a third route to market strategy by selling 225,045 barrels, FOB Bretana, through Brazil with competitive commercial terms vs sales through the ONP. Enhanced existing offtake arrangement. Extended the sales agreement with Petroperu until December 2022 with improved commercial terms under low Brent scenarios.
The company has significant liquidity in hand and exited Q1 2021 with $75.8 million of total (restricted and unrestricted) cash compared to $9.6 million at the end of 2020. Higher net operating income, PetroTal generated nearly $20 million ($25.87/bbl) of NOI in the quarter, an increase of 12% over Q1 2020 despite producing 2,378 bopd less in Q1 2021 vs Q1 2020.
Operating costs for Q1 2021 were $5.5 million ($7.17/bbl) vs $6.0 million ($6.42/bbl) in Q1 2020 driven by lower production rates and offset slightly by higher than estimated one-time fuel use for the new crude oil power generation plant commissioning, which was more expensive in Q1 2021 due to a higher Brent price.
The Company invested $7.1 million on capital expenditures in the quarter vs $23.8 million in Q1 2020. The bulk of PetroTal’s 2021 development capex will occur in Q2 2021 and H2 2021 ensuring flush production from new drills is online during favourable Brent pricing months with hedging in place for downside protection.
With recent elevated Brent prices, the Company estimates it is operating materially above the original $90 million EBITDA budget for 2021 which assumed $50/bbl Brent. Excluding hedging and true-up revenue, and from June until December 2021, it is estimated that for every $1/bbl above $50/bbl Brent, EBITDA increases $2.0 to $2.5 million, making PetroTal potentially free cash flow positive for 2021.
Net income for the quarter was $30.9 million vs a net loss of $31.4 in Q1 2020 driven largely by higher commodity prices. Normalizing out derivative changes results in Q1 2021 and Q1 2020 having similar net income figures of $8.5 million and $9.0 million, respectively.
Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented
“Q1 2021 was a great quarter in many ways. From a strategy standpoint it was prudent that the Company shored up its liquidity position before undertaking material operations with pace. The Company is now on solid footing from a liquidity, risk, and safety standpoint and if firmly focused on achieving operational excellence in 2021. We are now in a Brent oil price environment where, subject to such conditions continuing, wells only need to produce approximately 280,000 – 300,000 barrels to pay-out full cycle, which in some cases, can happen in two to three months. The Company’s advancement on a risk, finance, and operational standpoint this quarter was impressive, and we will continue this positive momentum throughout 2021, to the benefit of all stakeholders.”
The CEO comments above fairly analyse how much PTAL has changed in the last few months and the board has done an exceptional job for the shareholders. It is worth reading the above comments and look at the share price with change from 15p and the market cap of some £135m and realise just how cheap these shares really are.
Proposed Farm-Ins to High Impact Drilling Programme, Proposed Fundraising and a Trading Suspension are announced by Longboat Energy, established by the former management team of Faroe Petroleum plc to build a significant North Sea-focused E&P business. LBE has announced that it has reached agreement on a bilateral basis with three separate counterparties to acquire a significant, near-term, low-risk exploration drilling programme on the Norwegian Continental Shelf structured as three farm-in transactions.
Longboat further announces its intention to carry out a proposed equity financing to raise gross proceeds of £35 million, to be conducted by means of a placing and subscription for new ordinary shares in the Company. The net proceeds from the Proposed Fundraising will be used principally to finance the consideration for the Farm-Ins and costs associated with the high-impact drilling programme, as well as the acquisition of certain seismic data and general corporate costs.
The Transactions are classified as a reverse takeover pursuant to the AIM Rules for Companies and accordingly the Company’s shares will be suspended from trading on AIM as of 7:30am today. The Company’s ordinary shares will remain suspended from trading on AIM until such time as either an Admission Document setting out details of the proposed Farm-Ins is published or confirmation is given that the Transactions are not proceeding. Completion of the Farm-Ins and Proposed Fundraising are subject to approval by Longboat’s shareholders at a general meeting to be convened in due course. The Admission Document, which will include a notice of General Meeting, is expected to be issued following pricing of the Proposed Fundraising.
A High activity level is expected with seven wells expected to be drilled in the next 18 months, with the first well expected to spud in Q3 2021 and a further three wells expected to drill before year-end. The wells have significant resource potential: initial drilling programme targeting net mean prospective resource potential of 104 MMboe with an additional 220 MMboe of upside and follow-on prospectivity.
This is a low cost, low risk portfolio, acquisition costs and drilling programme are fully eligible for 78% Norwegian tax refund and Chances of Success in the range of 25-55% for all-but-one high-impact prospect. Norway delivers outstanding exploration results: Norwegian success rates of almost double global rates in 2020, year-to-date in 2021 at 70%2.
This deal matches Longboat’s ESG objectives: a gas-weighted portfolio with all prospects within tie-back distance to existing infrastructure with the potential to reduce emissions per barrel produced and contribute positively to decarbonisation projects; and value creation. Net Asset Value creation potential of over $1 billion based on precedent transactions on the NCS for development assets.
The three separate Farm-Ins have each been negotiated on a bilateral basis to create a tailored exploration drilling portfolio with a balanced risk/reward profile. The Farm-Ins are corner-stoned with a single, multi-licence deal with a major oil & gas company which is one of the most active and successful explorers on the NCS. The Farm-Ins represent an opportunity to take advantage of cyclical budget cuts in the sector to accelerate Longboat’s first steps towards building a full-cycle E&P company. The high-quality nature of the portfolio is evidenced by the vendors retaining interests in six of the seven targets included in the Farm-Ins.
The consideration for the Farm-Ins will be settled via a cost carry by Longboat on behalf of the vendors and is fully eligible for the Norwegian tax refund system. The post-tax cost to Longboat of the carry element of the transaction is approximately $7.8 million ($35 million pre-tax), representing $0.07 per prospective boe on a post-tax basis.
Helge Hammer, Chief Executive of Longboat, commented:
“After Faroe was sold for c.$900 million in 2019, the management team formed Longboat to replicate that success. I am very pleased that Longboat is taking over where Faroe left off with a unique opportunity for shareholders to invest in a high-impact, low-risk, multi-well exploration drilling programme. Thanks to our excellent industry relationships, developed over many years of operating in the North Sea, we have negotiated three bilateral agreements to deliver a bespoke drilling programme. We look forward to a busy period of almost continuous drilling and frequent catalysts during the next 18 months.
“This represents a unique opportunity which accelerates Longboat’s ambition to build a full-cycle E&P company.”
The holders of Faroe have been waiting for quite a while for the first deal from Longboat and then three come along together. This deal looks very promising indeed, it inevitably leans on the Norwegian experience and has an interesting tax efficient portfolio which is ready to go subject to closing. I am sure that the blue chip shareholder list who did very well out of Faroe and who backed the company at the off will get their cheque books out again so the raise shouldnt pose any fears.
IGas has announced that it has received planning approval from Stoke-on-Trent City Council for the deep geothermal project in the Etruria Valley that will supply zero carbon heat to the City for decades to come.
IGas continues to have positive discussions with Government regarding future financial support for this and other geothermal projects. A new industry report, on the economic and environmental importance of UK deep geothermal resource, by the ARUP Group and the Association for Renewable Energy and Clean Technology (REA) launched recently, estimates that, with immediate government support, the UK could deliver 360 geothermal projects by 2050. This would include an estimated 12 projects being operational by 2025 with 1,300 jobs created and c.£100 million of investment flowing into the UK economy.
The Committee on Climate Change stated that only decarbonisation of heat in the UK could deliver the major reduction in emissions needed to meet the 2050 net zero target. By delivering on average 12 heat projects per year over the next three decades, the UK could expect to generate up to 15,000 GW hours (GWh) of heat from geothermal, annually by 2050. Through a growing pipeline of geothermal development opportunities, IGas is well positioned to deliver a solution to the long-term decarbonisation for heat in the UK.
As a result of this IGas will be part of the jigsaw on the Stoke project now that planning has been granted. It makes IGas one of the only small independents in this process and to have a serious shot at being a significant part of the UK energy transition in decarbonising heat.
Gareth Southgate has announced his squad to go to the Euros and those who didnt make the squad are
Godfrey, White, Watkins, Lingard, Ramsdale and Ward-Prowse who were left out.