UK Offshore Wind CFD Strike Prices for AR6/2024

The UK has increased offshore wind maximum strike prices to £73/MWh for fixed-bottom offshore wind installations for the 2024 AR6 Allocation Round.

This is a substantial increase from the £44/MWh set for the AR5 round in 2023 which was too low to attract bids with no capacity being awarded to offshore wind.

The higher price is designed to compensate for a higher cost and interest rate environment.

Source: S&P

https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/uk-raises-offshore-wind-ceiling-price-by-66-for-2024-auction-78470125

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Jersey Oil & Gas next in line to be Canned?

 

Following the UK Government's rejection to approve the Cambo development in the West of Shetlands, leading to Shell's exit from the field, and the scrapping of the Rosebank development by Equinor, it is clear that the UK Government is increasingly turning its focus away from North Sea Oil & Gas. The UK Government is laser focused on the Energy Transition and is supporting the renewable energy development, hydrogen and carbon capture.

Against this backdrop, it is highly possible that the political (and public) support for Jersey Oil & Gas to develop its North Sea portfolio will not be there. And even Jersey Oil & Gas' attempt to "greenify" its developments through electrification will not be enough to keep the project alive against the country's accelerating green agenda.

Beyond this, the company faces two other key issues:

• Attempts to find a farm-in partner to share risk has failed - an extensive search process was run last year with no success. No-one is looking to participate in such a large, billion dollar development with the political uncertainty that lies ahead
• Financing is becoming increasingly difficult - the original plan involved seeking bank financing for the development, but this will be challenging as more banks back away from the sector

The chances of a revival for Buchan and Verbier are viewed as very slim.

Disclaimer: this is an opinion piece by OGInsights

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Hibiscus acquires 85% interest in Eagle to consolidate around Anasuria

Hibiscus has announced that its indirect wholly-owned subsidiary, Anasuria Hibiscus UK ('AHUK') has executed a Sale & Purchase Agreement ('SPA') with EnQuest in respect of certain interests in the UK Continental Shelf Petroleum Production Licence Number P238 Block 21/19a, Eagle Pre-Producing Area ('Eagle Field'). The Eagle Field is located approx. 6.4 km to 15 km from various Anasuria facilities, and due to its proximity, facilitates a potential subsea tie back to the Anasuria FPSO which could extend the latter’s economic life.

Under the terms of the SPA, the consideration for AHUK’s acquisition of 85% in the Eagle Field from EnQuest is a nominal USD1 due to EnQuest on SPA completion plus the the cost representing AHUK’s carry of EnQuest’s remaining 15% from completion of the SPA through to first oil. Such costs of the carry are presently estimated to be approx. USD7.5 million. The conditions precedent to completion are subject to customary regulatory and third party approvals. In addition, the terms of the deal include the transfer of operatorship of the licence to AHUK, according to the provisions to be contained in a Joint Operating Agreement between AHUK and EnQuest, which shall be signed at SPA completion

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Long awaited deal finally announced: NEO acquires ExxonMobil UK

NEO Energy and HitecVision have announced the signing of a transaction that puts NEO Energy among the top five oil and gas companies in the UK.

NEO Energy is acquiring a major portfolio of non-operated oil and gas assets in the Central and Northern North Sea from ExxonMobil. Following completion, NEO’s expected proforma 2021 production will be circa 70,000 barrels of oil equivalent per day (boepd), growing organically to more than 80,000 boepd in 2024 through ongoing field developments. NEO is acquiring a substantial, cash generative portfolio that will significantly increase and diversify its producing asset base. Adding close to 40,000 boepd and more than 140 million boe of reserves, it represents a major step towards NEO’s near-term target of producing 120,000 boepd.

The acquisition is an important milestone for NEO, supporting the company’s strategy of being a leading full-cycle E&P company on the UKCS. On completion of the transaction, NEO will have a strong presence in the key hubs in the Central and Northern North Sea, with total reserves and resources of around 300 million boe. The company will have a total of 35 fields both producing and under development.

The agreement is valued at more than USD 1 billion. There may be additional contingent considerations of approx. USD 300 million based on the potential for increases in commodity prices.

The assets include several organic growth opportunities, including ongoing development projects such as the Penguins field, infill wells and life extension opportunities. The total number of employees in NEO at closure of the transaction will be circa 160.

The fields being acquired are operated by some of the largest and most experienced offshore operators in the world including Shell, BP and Total. NEO will become Shell’s largest partner in the UK Central and Northern North Sea.

Russ Alton, CEO of NEO Energy, said:

'This acquisition builds on NEO’s existing North Sea portfolio and towards delivering on our ambition to be a leading producer on the UKCS. NEO is well placed, together with its operating partners, to extract value from this and other opportunities, while at the same time focusing on improved environmental performance.'

John Knight, Senior Partner at HitecVision, added:

'HitecVision is a leading investor in the European offshore energy industry with USD 6.7 billion in assets under management. We have built one of Norway’s largest oil and gas companies, through our joint venture with ENI, in Vår Energi. We believe that NEO has the potential to achieve a similar position in the UK sector to that held by Vår Energi in Norway. We will continue to fund NEO’s growth in the UK through more acquisitions and, where appropriate, mergers. This will be the first UK investment for our most recent fund, The  North Opportunity Fund, which we closed in March 2020.'

The transaction, which is subject to approvals from the relevant authorities and regulatory consents, is expected to complete by the middle of 2021.

The portfolio to be acquired consists of 21 assets, including 14 fields and a number of infrastructure positions. The fields can be divided into the following hubs:

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Total Makes a New Gas and Condensates Discovery in the North Sea

Total, Operator, and its partners have made an encouraging discovery with the Isabella 30/12d-11 well on the license P1820, located in the Central North Sea offshore UK, about 40 kms south of the Elgin-Franklin field and 170 kms east of Aberdeen.

The well was drilled in a water depth of about 80 meters and encountered 64 meters net pay of lean gas and condensate and high-quality light oil, in Upper Jurassic and Triassic sandstone reservoirs. The analysis of the data and results are ongoing to assess the discovered resources and to determine the appraisal program required to confirm commerciality.

'The initial results at Isabella are encouraging. This demonstrates that our exploration strategy in the North Sea to explore for value adding prospects nearby to our infrastructure is working.' commented Kevin McLachlan, Senior Vice President Exploration at Total.

The P1820 license is operated by Total with a 30% working interest, alongside Neptune Energy (50%), Ithaca Energy (10%) and the wholly owned subsidiary of Edison, Euroil Exploration (10%).

Source: https://www.total.com/en/media/news/press-releases/uk-total-makes-new-gas-and-condensates-discovery-north-sea

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Blackrock and GIC acquires critical North Sea gas infrastructure

Blackrock and GIC have announced the acquisition of Kellas Midstream from Antin. Antin was expected to launch an auction process for Kellas Midstream at the end of the year and it appears that Blackrock and GIC moved quickly and were able to agree a deal ahead of the formal auction. No sale price was disclosed but believed to be in the range of £1.4-2.0 billion.

There will be a number of disappointed parties out there who were lining themselves up for the process including the runners-up on the NSMP sale of last year - widely reported as KKR, Macquarie, Partners Group and numerous pension funds.

Kellas owns the CATS pipeline and terminal, a majority stake in the ETS pipeline and is building the new HGS pipeline that serves Premier Oil's Tolmount Area. All of this is critical infrastructure for UK North Sea gas production, without which, the country would be crippled from a shortage of gas. Some of the key hubs that the infrastructure serves include the Cygnus Area (the largest and newest gas field in the Southern North Sea), the Culzean Area (another critical new gas field in the Central North Sea) and the up and coming Tolmount Area.

Kellas systems
Source: Kellas Midstream

CATS system
Source: Kellas Midstream

In addition, the CATS pipeline appears to be a key contender for export from the massive Glengorm field that was discovered at the beginning of this year and will become an important source of gas for the UK in the decades to come (see UK North Sea gets shot in the arm with Glengorm).

The advisers to Blackrock and GIC were listed as:

- RBC Capital Markets and Scotiabank as financial advisers

- Herbert Smith Freehills as legal advisers

- Xodus as technical advisers

The full press release below:

Antin sells Kellas Midstream to BlackRock and GIC

Antin Infrastructure Partners, a private equity firm focused on infrastructure investments, announced today that it had signed an agreement to sell Kellas Midstream to BlackRock’s Global Energy & Power Infrastructure Funds (GEPIF III) and GIC, a leading global institutional investor, in a joint venture.

Kellas Midstream owns and operates key gas infrastructure in the UK Central and Southern North Sea. Kellas Midstream comprises: (1) the Central Area Transmission System (‘CATS’): a major gas transportation and processing system which takes gas from the Central North Sea to the CATS reception and processing terminal at Teesside in the North East of England; (2) the Esmond Transportation System (“ETS”): a key subsea pipeline in the Southern North Sea connecting four producing fields to the Bacton gas terminal on the North Sea coast; and (3) the Humber Gathering System (“HGS”): a first-of-its-kind greenfield project to build the infrastructure required for the development of the large Tolmount gas field in the Southern North Sea.

Antin initially acquired a 63% stake in CATS from BG (now Shell) in 2014, later acquiring a 36% stake from BP in 2015. Having fully carved out the business and established a standalone entity, Kellas Midstream grew substantially both via organic growth with connection to new major gas fields such as Stella, Caley & Shaw, Culzean and Vorlich, and by expansion in the UK Southern North Sea with the ETS acquisition and the HGS development. Throughout Antin’s period of ownership, it focused on achieving outstanding operational performance whilst maintaining a clear focus on Health & Safety. Kellas Midstream maintained a perfect safety record with zero Lost Time Incidents for 16 consecutive years. The transaction is expected to close in early 2020.

“We are proud of the significant growth and strategic transformation accomplished during Antin’s ownership over the past five years. We are also grateful for the strong partnership and outstanding performance of Kellas Midstream’s talented management team and dedicated employees. We wish them continued success with their new owners” said Mark Crosbie, Antin’s Managing Partner.

Andy Hessell, Kellas Midstream’s Managing Director, said: “We thank Antin for their significant support over the past five years. GIC and the BlackRock GEPIF team recognise the growth potential of the business we have built and share our strategy to continue to invest, grow and build our portfolio of midstream assets and serve all our customers in the North Sea. We look forward to working with our new partners.”

Mark Florian, Group Head of the Global Energy & Power Infrastructure Funds Team at BlackRock, added: “A growing number of institutional investors are seeking exposure to energy and power investments. Within the sector, energy from gas is viewed as a necessary component of the energy transition as we move towards a lower carbon economy. This investment in Kellas Midstream reflects the focus of GEPIF III on making strong equity investments in mid-market energy and power infrastructure and partnering with outstanding management teams.”

Ang Eng Seng, Chief Investment Officer of Infrastructure at GIC, said: “We are pleased to invest in Kellas, a leading provider of high-quality midstream infrastructure with a strong track record. As a long-term investor, we look forward to partnering with BlackRock and Kellas’ management to support the future growth of the company.”

Bank of America Securities and Citi acted as financial advisers to Antin, and Weil, Gotshal & Manges acted as its legal adviser. RBC Capital Markets and Scotiabank acted as financial advisers to BlackRock Real Assets and GIC, and Herbert Smith Freehills and Xodus acted as their legal and technical advisers respectively.

Source: https://www.gic.com.sg/news-and-resources/antin-sells-kellas-midstream-to-blackrock-and-gic/

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Mediocre week for UK exploration

This week saw a disappointing well result in Rowallan and a mediocre result in Verbier.

Rowallan
The keenly watched wildcat drilled at the Rowallan prospect "was not found to be hydrocarbon-bearing”. The 22/19c-7 well was targeting 143mmbbl in a structural fault and dip-closed trap analogous to Total’s Culzean field 20km away.

The well encountered a 182m section of sandstone and shale after being drilled to a depth of 4,641m .

The Dundonald and Sundrum prospects, which are geologically similar to Rowallan, have previously been identified as potential drilling targets in the block but will now be “re-evaluated in the light of the drilling results”, Serica said.

Serica, with a 15% interest in the block, did not incur any costs for the well as it was fully carried following an earlier farm-out. Eni operates the block with a 32% stake, with remaining partners JX Nippon (25%), Mitsui (20%) and Equinor (8%).

Verbier

Equinor (70%), Jersey Oil & Gas (18%) and CIECO (12%) completed appraisal well 20/05b-14 on the Verbier discovery last week. The well did not encounter Upper Jurassic sands as anticipated, and the contingent resources have been revised towards the lower end of initial resource estimates to 25mmboe.

Further upside potential exists in the area at deeper horizons and an additional prospect at Cortina. This will continue to be matured. At 25mmboe, Verbier is viewed to be commercial and development planning will now commence as part of a wider area development plan, which could include the Buchan Area.

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Maria, you've gotta see her!

Wintershall has shut-in the Maria field since February, approximately a year after first production, following poor production performance. It is understood that reserves have been downgraded from 207mmbbl to c.60 mmbbl.

The field is now undergoing testing and monitoring to see how best to produce the remaining reserves the recover the lost reserves whilst managing the reservoir. It is understood that the NPD has to review plans and sign off on the field's restart for fear unintended reservoir damage. There is currently uncertainty on whether the field will start up again.

The cause is believed to be poor connectivity between zones. Water injection is provided to the zone below for pressure support. However analysis is now showing low connectivity between the geological layers in the reservoir, and thus the water injection is not working effectively.

Wintershall started production from the Maria oil field on Haltenbanken in the Norwegian Sea in December 2017, one year ahead of schedule and with 20% reduction in costs. Maria was Wintershall’s first own-operated field in Norway.

Wintershall chose an innovative subsea concept to develop the field. Two subsea templates were installed on the seabed above the Maria reservoir and connected via a pipeline network to the existing Kristin, Heidrun, and Åsgard B platforms.

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Cluff extends farm-out exclusivity in Southern North Sea to Major

Cluff Natural Resources press release
Further to its announcement on 28 November 2018, Cluff Natural Resources Plc, the AIM quoted natural resources investing company with a high impact exploration and appraisal portfolio focused on the Southern North Sea gas basin, provides an update regarding its exclusivity agreement with a major oil and gas company for its Southern North Sea Gas licence P2252.

As previously announced, the Company signed an exclusivity agreement (the "Agreement") on Licence P2252 with a major international oil and gas company (the "Counterparty"), whereby exclusivity was granted to the Counterparty subject to a definitive farm out agreement being entered into by 31 January 2019 (the "Exclusivity Period").

The Company announces that discussions with the Counterparty regarding a definitive farm out agreement are at an advanced stage, though have not yet concluded.  As a result, the Exclusivity Period has been extended by one week. Therefore, exclusivity continues to be granted to the Counterparty, subject to a definitive farm out agreement being entered into by 7 February 2019

Source: https://www.cluffnaturalresources.com/wp-content/uploads/2019/02/Extension-to-exclusivity1.2.19.pdf

Cluff Natural Resources licence map

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UK North Sea gets shot in the arm with Glengorm

CNOOC, Total and Edison have made one of the biggest finds in the UK North Sea in recent years. The Glengorm discovery is estimated to contain recoverable resources of 250mmboe which is even bigger than Total’s recent success in the West of Shetlands at Glendronach which had 1tcf of gas (c.160mmboe). Glengorm sits on licence P2215 and in the vicinity of both the Culzean and Elgin & Franklin gas fields which could act as future hosts for Glengorm.

Glengorm is operated by CNOOC (50%) with Total (25%) and Edison (25%) as partners. The exploration well (22/21c-13) was spud on 26^th August 2018 with the Prospctor 5 jack-up rig targeting the Upper Jurrasic Fulmar and Heather formations. The HPHT prospect was challenging to drill but persistence has paid off. CNOOC tried to drill the prospect twice in 2017 but failed to do so following technical problems.

Maersk, Premier Oil and Centrica had relinquished the licence in which the field is contained back in 2014 when it was deemed too small and complex to commercialise. Glengorm has clearly exceeded all expectations with unrisked recoverable resources estimated at c.65mmboe back in 2014 (41mmbbl oil and 128bcf gas). The 2014 relinquishment report also highlights a number of prospects in the vicinity and CNOOC, Total and Edison have expectations of further prospectivity in the area for future growth.

Source: Maersk 2014 relinquishment report

Source: Maersk 2014 relinquishment report

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INEOS swoops in for Conoco North Sea

As widely reported over the weekend, INEOS is the front-runner for the ConocoPhillips’ UK North Sea portfolio. ConocoPhillips had a buyer for the portfolio back in 2015, but pulled the deal citing that it had no desire to sell-out at the bottom of oil price cycle,

INEOS has beaten other likely UK North Sea focussed contenders which could include Ithaca Energy, Premier Oil, Neptune Energy, Chrysaor and SiccarPoint. The sale, estimated to be around USD3 billion, will exclude the Teeside Norsea terminal and London trading business.

INEOS existing North Sea portfolio
Source: The Times

The below was originally published on 24^th June 2018:

------------------------------------------------------------------------

ConocoPhillips' is one of the largest operators in the UK North Sea, being the operator of the Britannia area, the J-Area and large swathes of the Southern North Sea. ConocoPhillips is also a non-operated partner in the giant Clair field.

Clair is one of the largest oil fields in the UK offshore and located in the West of Shetlands which is making a name for being the last frontier of the UK and is increasingly attracting further exploration activity. The Clair field was brought onstream in 2005 and is currently undergoing a second phase of development (Clair Ridge). Clair Ridge is planned to come onstream in Q4 2018 with operator BP targeting an additional 640mmbbl which will extend the life of the Clair Area beyond 2050. As soon as Clair Ridge is onstream, the partners will be planning for the Phase 3 of the development known as Clair South.

On the operated assets, Britannia is one of the largest gas fields in the UK which has acted as a hub for various tie-backs over the years. The J-Area, although now beginning to mature, has been a highly successful gas hub in the Central North Sea where more infill drilling and exploration activity is planned into 2019 and 2020.

The Southen North Sea assets are the most mature with some going into decommissioning. ConocoPhillips has widely announced the closure of the Theddlethorpe gas processing plant which is the terminus for its CMS pipeline. This will lead to early/forced decommissioning of all the fields which currently utilise the CMS pipeline as the export route including the Faroe and Tullow Schooner and Ketch fields which will cease production in August 2018.

The ConocoPhillips' UK portfolio is concentrated around a few hubs and excluding the Southern North Sea, has a good amount of life remaining with current production at c.80mboe/d.

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PGNiG expands footprint in Norway

On 18^th October PGNiG announced that it had agreed to acquire Equinor's interest in the Tommeliten Alpha gas and condensate field in the Norwegian North Sea. This continues PGNiG's strategy of diversifying its gas supply away from Russia.

PGNiG has always had an interest in Norwegian gas seeing it as as logical and accessible source of gas for Poland. As the long term Russian gas supply contracts come to expiry, PGNiG is making bold moves to secure new sources of gas and LNG. See PGNiG shuns Russian gas.

The operator of the discovery is ConocoPhilips (28.26%), and current partners are Total (20.23%), Eni Norge (9.13%) and Equinor (42.38%) which will sell its entire working interest to PGNiG. The agreed price for Equinor's stake was USD220 million at 1 January 2018 effective date.

The Tommeliten Alpha discovery is located in the vicinity of large, existing fields, most notably the giant Ekofisk field. According to current plans, production is expected to commence in 2024, and the development concept assumes a subsea tie-back to the existing infrastructure on Ekofisk.

Tommeliten Alpha is a gas and condensate field with estimated recoverable resources of 52 mmboe (net to PGNiG's 42.38%). PGNiG believes in an upside potential in the field reserves as well as significant exploration upside in the area.

The field was originally planned to start production in 2019, but development plans were shelved by operator ConocoPhillips in 2016 due to low oil prices.

#PGNiG #NorthSea #TommelitenAlpha # Equinor #Conoco

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PGNiG shuns Russian gas

PGNiG is increasingly boldening its signals on shunning Russian gas as it turns to the west. The Polish state has historically been dependent on gas imports from its eastern neighbour but is looking to loosen its reliance to the communist state.

Poland consumes around 17 bcm of gas annually, more than half of which comes from Gazprom under a long-term contract that expires in 2022. It is seeing the upcoming expiry as the opportunity to diversify its gas supply ahead of time and has consistently stressed that Gazprom is charging Poland too much for the gas noting that Russia has taken advantage of the historic lack of other sources of gas which is now changing with the advent of LNG.

Poland has also vehemently opposed plans by Russia to build a new gas pipeline across the Baltic Sea which is aimed at strengthening its dominant market position into Europe. Instead Poland is looking to sanction the Baltic gas pipeline later this year or beginning of 2019 which will bring gas directly from Norway.

The last month has seen a flurry of newsflow around PGNiG’s activity in sourcing new gas.

In mid-October, PGNiG finalised terms with Venture Global for 2mtpa of LNG. It will buy LNG for 20 years on a FOB basis with supplies commencing under two contracts for 2022 and 2023. The FOB contracts are deemed attractive for PGNiG as it can choose to take the LNG to Poland or use it in its trading portfolio. The terms are not disclosed but understood to be in line with other Gulf Coast LNG contracts being 115% x Henry Hub plus a toll of c.USD2.50/mmbtu. Venture Global is currently developing the Calcasieu Pass LNG terminal on the US Gulf Coast.

This has been followed by a 24 year LNG deal with Cheniere Energy at the beginning of November. PGNiG has signed up a 1.45mtpa deal with LNG supplied by Cheniere’s Sabine Pass, Louisiana and Corpus Cristi, Texas liquefaction plants. The contract is for delivery on a DES basis directly to the 5Bcm/year Swinoujscie terminal in Poland. Poland is also looking to expand the import terminal to 7.5Bcm/year in part of the countries grander ambitions to become a LNG and gas trading hub.

PGNiG also farmed-in to the Tommeliten Alpha in the Norwegian North Sea on the upstream side at the end of October. See PGNiG expands footprint in Norway.

#PGNiG #LNG #Russia #Gazprom #VentureGlobal #Cheniere

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EnQuest acquires remaining Magnus stake

EnQuest has exercised its option to acquire the remaining 75% interest in Magnus from BP, together with an increase in the interests of the Sullom Voe Terminal (to 15.1%), Ninian Pipeline System (to 18.0%) and Northern Leg Gas Pipeline (to 41.9%). The transaction will add c.60mmboe of 2P reserves and 10mmboe of 2C resources.

To fund the transaction, EnQuest is looking to raise USD138 million in a 3-for-7 rights issue at 21p/share, which represents a 46% discount to the closing share price of 6 September 2018.

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Total sells Norweigian assets to AkerBP for USD205 million

Total has agreed to sell interests in a portfolio of 11 licences in Norway to AkerBP for a cash consideration of USD205 million. The portfolio includes four discoveries with net recoverable resources of 83mmboe.

The acquisition allows AkerBP to consolidate its position around the Alvheim, NOAKA and Skarv hubs as well as adding exploration acreage near its operated Ula field (AkerBP 80%). Increasing stakes in fields and discoveries and having control of tie-backs will help improve the economics of hubs for AkerBP.

For example two of the discoveries, Trell and Trine, are located near the AkerBP-operated Alvheim field (AkerBP 65% operated interest) and are expected to be produced through the low-cost Alvheim FPSO.

One important part of this transaction is the NOAKA area (North of Alvheim and Krafla Askja) where AkerBP and Equinor are pursuing the development for this complex with FID scheduled for 2020. Resources in NOAKA remain stranded until the partners agree a development concept and export route, but adding acreage and discoveries builds further critical mass on the path to bolstering the case for project sanction. Note that NOAKA is estimated to contain over 500mmboe in resources, but scattered across 15 discoveries hence the complexity of the development. Nevertheless this deal shows further intent by AkerBP to maximise recovery from the area.

Separately the Alve Nord discovery is located north of the AkerBP-operated Skarv field (23.8%) in the Norwegian Sea, and can be produced through the Skarv FPSO as another example of synergy.

The transaction is subject to regulatory approval. The full list of licences being transferred is as follows:

Source: Wood Mackenzie

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ConocoPhillips' mix of a North Sea portfolio

ConocoPhillips' is one of the largest operators in the UK North Sea, being the operator of the Britannia area, the J-Area and large swathes of the Southern North Sea. ConocoPhillips is also a non-operated partner in the giant Clair field.

Clair is one of the largest oil fields in the UK offshore and located in the West of Shetlands which is making a name for being the last frontier of the UK and is increasingly attracting further exploration activity. The Clair field was brought onstream in 2005 and is currently undergoing a second phase of development (Clair Ridge). Clair Ridge is planned to come onstream in Q4 2018 with operator BP targeting an additional 640mmbbl which will extend the life of the Clair Area beyond 2050. As soon as Clair Ridge is onstream, the partners will be planning for the Phase 3 of the development known as Clair South.

On the operated assets, Britannia is one of the largest gas fields in the UK which has acted as a hub for various tie-backs over the years. The J-Area, although now beginning to mature, has been a highly successful gas hub in the Central North Sea where more infill drilling and exploration activity is planned into 2019 and 2020.

The Southen North Sea assets are the most mature with some going into decommissioning. ConocoPhillips has widely announced the closure of the Theddlethorpe gas processing plant which is the terminus for its CMS pipeline. This will lead to early/forced decommissioning of all the fields which currently utilise the CMS pipeline as the export route including the Faroe and Tullow Schooner and Ketch fields which will cease production in August 2018.

The ConocoPhillips' UK portfolio is concentrated around a few hubs and excluding the Southern North Sea, has a good amount of life remaining with current production at c.80mboe/d.

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RockRose acquires Dyas' Netherlands portfolio for €107 million

RockRose has announced the acquisition of Dyas' Dutch portfolio for €107 million.

Press release follows:

RockRose Energy plc is pleased to announce that it has signed a Sale and Purchase Agreement to acquire the entire issued and to be issued share capital of Dyas B.V. (the "Acquisition"), which owns the non-operated, Netherlands gas and condensate producing assets of the Dyas group of companies, for a total consideration of EUR €107 million. The Dyas group of companies is wholly owned by SHV Holdings N.V., a family-owned Dutch multinational.

The Acquisition, which has an effective date of 1st January 2018, will be funded from existing cash resources with no debt or equity issuance or shareholder approval required. There will be a significant working capital adjustment at completion.

The Acquisition adds a further 13 MMboe net developed reserves (with material undeveloped and prospective resource upside) and over 5,000 boepd of production to the Group. Post completion RockRose estimates combined Group 1P reserves of approximately 23 MMboe and 2018 pro-forma production in excess of 10,000 boepd. The Group's production will be circa 60% gas and 40% oil.

Both the existing asset base and those assets to be acquired have incremental opportunities which the Board believe could add significantly to the Group's reserve base and maintain current production for at least the next five years, with Rockrose's portion of the associated capex to be funded from the Group's operating cash flow.

Andrew Austin, Executive Chairman of RockRose Energy said:
"On completion this acquisition grows our North Sea business to a level of production that is over 10,000 boepd and in addition to providing significant free cash flow diversifies the portfolio and strengthens the Company's position. Management sees significant upside in the combined portfolio and is confident RockRose can organically maintain or grow profitable production from these levels without necessitating additional funding."

Robert Baurdoux, CEO of Dyas, said:
"After a presence of over 50 years in the Netherlands, the divestment of our Dutch entities is part of a strategic refocussing of our business. RockRose Energy is well placed to take-on the stewardship of the Dutch assets, allowing Dyas to pursue new investment opportunities in the UK, Norway, Denmark and Malaysia."

Link: https://ir.euroinvestor.com/Tools/newsArticleHTML.aspx?solutionID=2446&customerKey=rockroseenergyplc&storyID=13931066&language=en

The Dyas Dutch portfolio comprises the following (offshore unless specified otherwise):

Concession	Operator	Dyas % Interest
Alkmaar Peak Gas Installation (onshore)	TAQA	12.00
Bergen-II (onshore)	TAQA	12.00
A12a,d	Petrogas	14.63
A18a,c	Petrogas	14.63
B10a,A12b	Petrogas	14.63
B10c,B 13a	Petrogas	14.63
B16a	Petrogas	14.63
F2a Hanze	Dana	20.00
F2a Pilocene	Dana	12.00
F6b	Dana	14.00
F15a,d	Total	7.50
F15a (B-Field)	Total	8.82
J3b,J6	Centrica	7.50
Markham Unit	Centrica	4.43
J3-C Unit	Total	1.73
K4b,K5a	Total	11.66
K4b,K5a-Unit	Total	6.98
K5C-EC2Unit	Total	7.67
K5-F Unit	Total	8.86
L16b	Oranje-Nassau	30.00
K18b,L16a	Wintershall	10.00
P6-D	Wintershall	30.60
P6 Main Field	Wintershall	15.00
P6-South	Wintershall	24.38
P9a,b	Wintershall	15.58
P9 A+B Unit	Wintershall	11.61
P9c	Wintershall	9.88
P12 (Part Area)	Wintershall	23.61
Q1-B Unit	Wintershall	2.59
Q4-A Field	Wintershall	10.35
Q4-B Unit	Wintershall	10.25
Q5d	Wintershall	5.62
P15a,b	TAQA	8.99
P15c	TAQA	9.71
P15 Rijnfield	TAQA	45.69
P15-9 Unit	TAQA	5.30
P18a,c Unit	TAQA	0.68
P18c	TAQA	3.75
P18-6A7 Unit	TAQA	2.82

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Bidders pull out of Alba sale by Statoil and Mitsui

Deloitte has launched the sale of Endeavour Energy UK. The US parent company of Endeavour Energy UK is going through bankruptcy proceedings and Deloitte has been appointed to monetise the company’s UK unit.

Endeavour Energy UK owns a 25.7% in Alba amongst other North Sea assets. This is larger than Statoil’s 17% or Mitsui’s 13.3% stake which is being marketed.

Although Statoil and Mitsui have been trying to sell their stakes since the end of last year, the unusually lengthy process signals the challenges with the asset.

The sale being run by Deloitte will be a bankruptcy sale which will allow buyers to pick up the asset on the cheap. As a result, sources involved in running the Statoil and Mitsui sale say that the Endeavour Energy UK route presents a much cheaper way to pick up the same asset, as well as it being a larger, more meaningful stake.

Challenges which bidders had come to appreciate with Alba include:

• Limited upside
• Expensive and near-term decommissioning
• Bankruptcy of Endeavour Energy which would have left the buyer with larger exposure to future costs

Being able to pick up Alba through the Endeavour Energy proceedings at a lower price therefore makes the risks and challenges of owning Alba much more palatable, another bidder said.

Challenges raised by a number of parties who looked at Alba are discussed in depth here: 

Endeavour endangers Alba sale for Statoil and Mitsui

Related links:

• Endeavour Energy kicks off North Sea assets sale (external – Reuters)
• Chevron shuts in Alba platform as Mitsui and Statoil try to sell the field

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Chevron shuts in Alba platform as Mitsui and Statoil try to sell the field

Chevron the operator of the Alba field in the UK North Sea has announced at the end of last week that it had been forced to shut down production at the field. This follows a power outage at the platform. Emergency back-up power is in place and the crew continues to try and restore power. The mature heavy oil field which was brought onstream in 1994 is exploited from a fixed platform tied to a floating storage unit.

Endeavour had tried to sell its interest in the field in the past without success and is currently going through bankruptcy proceedings and could lose its stake with the other partners picking up pro rata. Statoil and Mitsui are trying to sell their stakes, but the prospect of unintentionally picking up additional interests from an Endeavour bankruptcy has scared off some potential buyers as this comes with an increased exposure to near-term decommissioning costs which are high for a development of this kind.

The partners in Alba are Chevron (23.37% operator), Endeavour (25.68%), Statoil (17%), Mitsui (13%), Spirit Energy née Centrica (12.65%), EnQuest (8%).

Further issues raised by parties considering the Alba stakes from Statoil and Mitsui include the non-operated interest, limited upside and decommissioning and is detailed in an earlier article compiled from interviews with various potential buyers who looked in the data room: Endeavour endangers Alba sale for Statoil and Mitsui.

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EnQuest agrees Thistle decommissioning with BP

Following on from last year's acquisition from BP, EnQuest has agreed with BP to undertake the management of the decommissioning activities for Thistle and Deveron.

EnQuest will receive USD30 million in cash for management of the decommissioning and for taking on 3.7% of the gross decommissioning costs of the Thistle and Deveron fields, subject to a cap of USD80 million. EnQuest estimates its exposure to costs is currently less than the cash being received.

EnQuest also has an option, exercisable over a 12-month period, to receive a further USD20 million in return for taking on a further 2.4% of the gross decommissioning costs of these fields, subject to a cap of USD59 million.

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