Noreco: Tyra redevelopment project delayed from 2022 into Q2 2023

Norwegian Energy Company ASA (“Noreco” or “the Company”) announces today the following update on the Tyra Redevelopment Project:

• As a consequence of the ongoing COVID-19 pandemic, first production from the Tyra Redevelopment is expected in Q2 2023 instead of 2022 as previously communicated
• The project remains on track to be delivered within budget

Due to COVID-19, local governmental imposed restrictions at the fabrication yards have impacted the schedule of the new Tyra topsides, including through the global supply chain delivering key components for the topsides. As a direct consequence of this impact the installation of the four new topsides is rescheduled from 2021 to a 2022 installation-window. 

First production from the redeveloped Tyra is then expected in Q2 2023.

 Facts:  

• Noreco is a North Sea E&P company and the second largest producer in Denmark with a 36.8% ownership in The Danish Underground Consortium (“DUC”).
• The DUC is a partnership between the operator Total (43.2%), Noreco (36.8%) and Nordsøfonden (20%).
• The Tyra Field is the largest gas condensate field in the Danish Sector of the North Sea. Its facilities process more than 90% of the gas produced in Denmark, as well as the entire gas production of the DUC.
• Due to seabed subsidence, the Tyra field required a redevelopment, a project that was sanctioned by the DUC in 2017.
• The Tyra Redevelopment consists of three main elements: Removal and decommissioning of the prior Tyra platforms, reuse and 13 meters extension of the current jackets at six platforms that will have new topsides and a new process platform and a new accommodation platform. The project is, to date, the largest project carried out on Danish Continental Shelf. 
• When back in operation, Tyra is expected to reach peak production of approximately 60,000 boepd.

Original article link:

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Impact farms out South African offshore to Shell

Impact Oil & Gas Limited (“Impact” or the “Company”), a privately-owned, African-focused, exploration company, is pleased to announce that its wholly-owned subsidiary, Impact Africa Ltd has entered into an agreement with BG International Limited, a wholly owned subsidiary of Royal Dutch Shell plc (“Shell”) for the farm-out of a 50% working interest and operatorship in the Transkei & Algoa exploration right, offshore South Africa (Exploration Right reference 12/3/252).

Under the terms of the farm-out agreement, Shell will acquire a 50% working interest in the Transkei & Algoa blocks and operatorship. Shell has also been granted the option to acquire an additional 5% working interest should the joint venture elect to move into the Third Renewal Period, which is expected to be approximately 2024.

Siraj Ahmed, CEO of Impact Oil & Gas, commented:

“We are delighted to have secured a farm-out partner of Shell’s calibre, highlighting the significant value potential of our exceptional South African exploration portfolio. Shell joins the Transkei & Algoa licence at a very exciting time for exploration drilling in South Africa. They bring substantial exploration expertise, with particular understanding of the potential of offshore South Africa, and an agreed strategy to accelerate the work programme to build upon the considerable work already undertaken by Impact and the previous JV partnership.”

Whilst part of the same licence, the Transkei & Algoa blocks have different geological settings. The Algoa block is situated in the South Outeniqua Basin, a short distance east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total has recently announced a further significant gas condensate discovery, following the successful drilling of the Luiperd-1X exploration well, which it is currently testing. The Transkei block is situated north-east of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which this joint venture will explore with focused 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the first quarter of 2022.

Closing of the transaction is subject to customary conditions, including the approval of the Government of South Africa.

The participating interests in the Transkei & Algoa blocks following completion of the farm-out by Impact will be as follows: Shell (Operator), 50% and Impact, 50%.

Transkei & Algoa, offshore South Africa

Exploration Right 12/3/252, Transkei & Algoa is located offshore eastern South Africa and covers approximately 45,838km² in water depths up to 3,000 metres. The licence was initially awarded to Impact as a Technical Cooperation Permit in 2012, followed by an application for an Exploration Right, which was granted in 2014.

Original article link: https://impactoilandgas.com/farm-out-of-transkei-algoa-to-shell/

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Idemitsu Petroleum Norge to sell part of participating interests of Production Licenses in Barents Sea

20^th October 2020

Idemitsu Kosan Co.,Ltd. (Head Office: Chiyoda-ku, Tokyo; Representative Director and CEO: Shunichi Kito, the “Company”) is pleased to announce that Idemitsu Petroleum Norge AS^*1 (Head Office: Oslo Norway; Managing Director: Futoshi Tsuneyama), a wholly owned subsidiary of Idemitsu Snorre Oil Development Co., Ltd. (Head Office: Chiyoda-ku, Tokyo; President: Jun Miki)^*2, has entered into an agreement with Lundin Energy Norway AS (Head Office: Oslo Norway), to sell a 10% participating interest in production licences PL 537 & PL 537B including Wisting discovery and a 15% participating interest in production licences PL 609, PL 609B, PL 609C, PL 609D and PL 851 including Alta discovery in the Barents Sea, Norway.

*1: Shareholders: Idemitsu Snorre Oil Development Co., Ltd. (100 %)

*2: Shareholders: Idemitsu Kosan Co.,Ltd. (50.5 %), Osakagas Summit Resources Co., Ltd. (49.5 %)

Idemitsu Petroleum Norge AS acquired a 20% participating interest in PL537 & PL537B, and a 30% participating interest in PL 609, PL 609B, PL 609C, PL 609D and PL 851 through the Norwegian licensing rounds. The Wisting and Alta discoveries were made in PL 537 in 2013 and PL 609 in 2014 respectively. Studies are ongoing with a view to progressing these discoveries to development.

The transaction is part of the Company’s long-term business strategy, and capital and cash management plan. It will reduce development cost exposure in future. A cash consideration of USD125 million is to be paid on completion of the transaction. (The transaction is subject to Norwegian authority approvals.)

【Change of licence share in the production licenses in Barents Sea】

Original article link:

https://www.idemitsu.com/news/2020/201020.html

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TOTAL delivers its first carbon neutral LNG cargo

TOTAL has delivered its first shipment of carbon neutral liquefied natural gas (LNG) to the Chinese National Offshore Oil Corporation (CNOOC). The loading operation was carried out at the Ichthys liquefaction plant in Australia, and the shipment was delivered on September 29 to the Dapeng terminal, China.

“We are proud to have completed this first shipment of carbon neutral LNG with CNOOC, a long-standing partner of TOTAL. This first LNG shipment, whose carbon emissions have been offset throughout the value chain, represents a new step as we seek to support our customers towards carbon neutrality,” explains Laurent Vivier, President for Gas at TOTAL. “The development of LNG is essential to meet the growth in global demand for energy while reducing the carbon intensity of the energy products consumed.”

The carbon footprint of the LNG shipment was offset with VCS (Verified Carbon Standards) emissions certificates financing two projects: 

• Hebei Guyuan Wind Power Project, which aims to reduce emissions from coal-based power generation in northern China
• Kariba REDD+ Forest Protection Project, which aims to protect Zimbabwe's forests

The term “carbon neutral” indicates that TOTAL and CNOOC have offset the amount of carbon dioxide equivalent associated with the whole carbon footprint of the LNG Cargo (including the production, liquefaction, shipping, regasification, and end-use) through VCS certified emission reduction projects.

TOTAL: Second Largest Private Global LNG Player

TOTAL has made natural gas, the least pollutant of all fossil fuels, a cornerstone of its strategy to meet a growing global demand for energy while helping to mitigate climate change. We are focusing in particular on LNG, which can be easily transported and delivered as close as possible to consumer markets.

TOTAL is present across the entire LNG value chain, from production and liquefaction of natural gas to LNG shipping and trading, regasification using terminals and floating storage regasification units (FSRUs) and contributes to the development of the LNG sector for maritime transportation.

TOTAL is the second-largest global LNG stakeholder in the private industry, with an overall portfolio of nearly 50 Mt/year by 2025 and a worldwide market share of 10%. With over 34 Mt of LNG sold in 2019, the Group has solid and diversified positions across the LNG value chain. TOTAL sells LNG in all world markets via its stakes in liquefaction plants in Qatar, Nigeria, Russia, Norway, Oman, Egypt, the United Arab Emirates, the United States, Australia and Angola.

Original article link

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FAR from a solution

FAR has defaulted on its most recent development cash call on Phase 1 of the Sangomar/SNE development.

Under the Sangomar Joint Operating Agreement, any party that defaults on its financial obligations and cash calls have a six month rectification period, during which time it will pay LIBOR+2% on the unpaid amounts. FAR will also not be able to participate in any of the operating committee meetings or participate in any voting on JV issues.

If FAR fails to rectify on its default, it will forfeit its entire interest in Sangomar with no compensation - i.e. FAR will lose the asset and the value of it will be zero.

In the meantime, FAR is investigating a sale of a stake and will have a race against time to find a solution.

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The Kurdish Crush

The Kurdistan producers are in a tough spot brought about by COVID-19 and the collapse in oil prices. Earlier this year, the KRG said it would delay payments in respect of October 2019 to February 2020 deliveries as its cash to pay producers was stuck in a Lebanese bank account with the bank itself facing liquidity issues.

The KRG had struck a deal to pay producers for the backlog later in 2020. Payments in respect sales from March 2020 were not affected and continue to be paid. However at the current low oil prices, payments to producers have slumped.

Tawke: Received USD8.5 million for April deliveries split between partners DNO and Genel. This compares to the March payment of USD34.6 million.

Taq Taq: Received USD1.9 million, down from USD4.6 million in March with Genel's net share of the payment being USD1.1 million.

Shaikan: Gulf Keystone had submitted an invoice to the KRG for a nil amount as the realised price was negative with the Shaikan crude/transportation discount being below Brent.

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Oil companies' COVID-19 response testing

OGInsights has connected with over 50 offshore operators since March 2020 to review how operations have adapted to ensure the health and safety of their workforces. As soon as the seriousness of COVID-19 came to light oil, companies on the whole have been massively responsive in prioritising the implementation of COVID-19 measures above all else.

When the outbreak first happened there was definitely a scramble to secure helicopter space to transport people back onshore. However it was not an easy start with many helicopter providers refusing to take any personnel that showed even remote symptoms of COVID-19 - luckily this was quickly resolved by the installation of screens between the pilot and passengers. This was a huge issue at the time as one infection offshore would have quickly spread across an entire platform. During this scramble, some companies even resorted to chartering dedicated private helicopters in order to ensure ability to transport personnel.

Rig rotas have now been revised to minimise the frequency of crew changes - this does mean some staff have been offshore for much longer than original planned. Some rotas now even incorporate an extra week once personnel arrive onshore to enable self-isolation before starting the clock on the normal onshore stint. On the other end of the cycle, majority of companies are now requiring staff to arrive up to a week early before going offshore to allow time for thorough testing and results.

On the whole, the industry has reacted and adapted well in managing COVID-19 with only a handful of instances where entire fields or crews have been infected.

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CNOOC confirms that it will not pre-empt the sale of Tullow’s assets in Uganda to Total

On 23 April 2020, Tullow announced that it had agreed the sale of its assets in Uganda to Total and that CNOOC had rights of pre-emption to acquire 50% of these assets on the same terms and conditions as Total. CNOOC has now informed Tullow and Total that it has elected not to exercise its pre-emption rights. Accordingly, there are no changes to the previously announced transaction or timeline and Tullow continues to expect the transaction to complete in the second half of 2020. 

The transaction remains subject to a number of conditions, including approval by Tullow’s shareholders, customary government and other approvals and the execution of a binding tax agreement with the Government of Uganda and the Uganda Revenue Authority that reflects the agreed tax principles previously announced.  Tullow will now look to progress the tax agreement following CNOOC’s decision not to pre-empt. 

Source: https://www.tullowoil.com/media/press-releases/cnooc-elects-not-pre-empt-sale-assets-uganda/

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Hurricane receives extension from OGA for Lincoln commitment well at Greater Warwick Area

Hurricane Energy, the UK based oil and gas company focused on hydrocarbon resources in naturally fractured basement reservoirs, has provided an update in relation to planned activities on the Lincoln subarea of Licence P1368, part of the Greater Warwick Area ('GWA').

In light of the COVID-19 pandemic, Hurricane has requested extensions to certain licence commitments pertaining to Lincoln.

The Oil and Gas Authority has responded positively to these requests, extending the deadline for commencement of the GWA joint venture’s commitment well on Lincoln to 30 June 2022 and extending the deadline for plugging and abandoning well 205/26b-14 (Lincoln Crestal) to 30 June 2021.


Dr Robert Trice, Chief Executive of Hurricane, commented:
'We would like to thank the Oil and Gas Authority for their flexibility regarding the timing of activities planned at Lincoln during these challenging times.'

Greater Warwick Area

The Greater Warwick Area comprises licences P2294 (Blocks 204/30b & 205/26d) and P1368 South (Blocks 205/26b, 204/30b & 205/26d) is being appraised/developed through a joint venture between Hurricane energy (50%) and Spirit Energy (50%). The joint venture believes that the Greater Warwick Area (GWA) is a single hydrocarbon accumulation comprising the Lincoln discovery and the yet to be drilled Warwick prospect. The joint venture undertook a three well drilling program on the GWA during 2019 and is currently evaluating the results.

Source: https://www.hurricaneenergy.com/application/files/4915/9052/6429/20200526_-_HUR_RNS_-_Lincoln_Deferments_vF.pdf

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Hurricane Lancaster shuts-in production

On 22^nd May 2020, Hurricane announced that it would be shutting in the 205/21a-7Z well at Lancaster. This follows an attempt to increase production at the well to test the viability of reaching 20,000bopd across both wells on the field.

However this attempt had led to unstable production at 205/21a-7Z caused by interference between the existing two wells. Production will now continue at 205/21a-6 only and current production is at 10,300bopd.

Hurricane will be discarding its production target of 18,000bopd for 2021 and has suspended putting out new guidance.

This is disappointing news for those who had placed bets on the risky fractured basement reservoir proposition of the company and now facing another setback.

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Neptune Energy announces completion of seismic survey offshore Egypt

Neptune Energy has announced the successful completion of an ocean bottom nodes (OBN) multiclient survey in the North West El Amal block, offshore Egypt, delivering promising results for further analysis.

The project, prefunded by Neptune, was carried out by WesternGeco, the seismic and geophysical data solutions division of Schlumberger, under a contract with the Egyptian General Petroleum Corporation (EGPC), sponsored by the Egyptian Ministry for Petroleum and Mineral Resources. WesternGeco acquired the survey using third-party vessels.

The survey employed innovative OBN technology to overcome the challenge of acquiring improved imaging in the complex salt geometries of the Gulf of Suez. It was the first ever OBN seismic survey to be conducted in Egypt and the most detailed survey of the block since the first acquisition in 1988, providing an in-depth data set for processing, image analysis, and planning for potential exploratory wells in the future.

The North West El Amal offshore concession covers 365 km2 and is located in the central part of the Gulf of Suez, approximately 42 km south of Ras Gharib and 105 km north of Hurghada. Neptune was awarded the exploration licence in February last year, including the acquisition of 100 km2 of 3D seismic data.

Egypt Managing Director, Gamal Kassem said: “Egypt is important for Neptune and we are pleased to build on our strong relationships with the Ministry of Petroleum and Egyptian General Petroleum Corporation.

“The safe and successful completion of the seismic acquisition is an important achievement and is testament to the careful planning and professional execution by Neptune, EGPC and WesternGeco.”
The project involved placing large numbers of autonomous sensors on the seabed to acquire seismic data, then retrieving them for analysis. The process acquires more detailed data than standard technologies and is less sensitive to weather conditions which can impact traditional seismic survey vessels.

Neptune’s VP Exploration & Development, Gro Haatvedt added: “It’s very exciting to have been involved in the OBN seismic survey, the first time the technology has been deployed in Egyptian waters. Given the geographically-diverse nature of our global portfolio, Neptune is accustomed to working with innovative digital and subsurface technologies to tackle a variety of geological challenges.

“Obtaining subsalt imaging is particularly tough and the OBN technology was well-suited for this purpose. The next step is to analyse the data which has greatly improved our understanding of the block and will support our future plans including potential exploratory wells.”

Source: https://www.neptuneenergy.com/media/press-releases/year/2020/neptune-energy-completes-seismic-survey-offshore-egypt


About North West El Amal
Operated offshore concession in the central part of the Gulf of Suez

Block 4 - North West El Amal Offshore Concession

Status:
Neptune will acquire 100 km2 of 3D seismic data and drill one exploration well in the first phase, with two further wells planned in phase two.

North West El Amal facts:
Neptune was awarded its first operated concession in Egypt in 2019 and signed the concession agreement in 2020 with Minister of Petroleum Tarek El-Molla
The concession covers 365 km2 and is located in the central part of the Gulf of Suez
The area is 42 km south of Ras Gharib and 105 km north of Hurghada

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Oil giants posturing

Since the collapse of the OPEC+ meetings and in the wake of seismic demand destruction from COVID-19, both Saudi Arabia and Russia have been in a battle of who will blink first with commitments to increase production in the hopes of forcing the other back to the table to recommence production cut discussions. However as of today, there has been no face saving solution for either to MBS or Putin to back down and even Trump's calls to OPEC/Russia to (ironically) help lift oil prices have been ignored.

Despite the strong stance and hard talk by MBS and Putin, neither Saudi or Russia have actually significantly ramped up oil production to date. State-controlled oil companies in the two countries have reportedly hesitated before ramping up production in a show of careful navigation to avoid sending the entire oil & gas industry into oblivion in the potential absence of a winner-takes-all outcome which is becoming more and more apparent.

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Shell acts to reinforce business resilience and financial strength

Shell acts to reinforce business resilience and financial strength

23 March 2020

Press release as follows:

As the COVID-19 virus spreads across the world - seriously impacting people’s health, our way of life and global markets - Shell is putting the safety and health of our people and customers first, along with the safe operations of all our businesses.

At the same time, we are taking decisive action to reinforce the financial strength and resilience of our business so that we are well-positioned for the eventual economic recovery.

“As well as protecting our staff and customers in this difficult time, we are also taking immediate steps to ensure the financial strength and resilience of our business,” said Ben van Beurden, Chief Executive Officer of Royal Dutch Shell. “The combination of steeply falling oil demand and rapidly increasing supply may be unique, but Shell has weathered market volatility many times in the past.”

“In these very tough conditions, I am very proud of our staff and contractors across the world for maintaining their focus on safe and reliable operations while also ensuring their own health and welfare and that of their families, communities and our customers.”

In order to deliver sustainable cash flow generation, Shell is actively managing all our operational and financial levers – from focusing on maintaining safe and reliable operations each day to reducing capital spend and operating expenses.

Today, we are announcing that we have embarked on a series of operational and financial initiatives that are expected to result in:

• reduction of underlying operating costs by $3-4 billion per annum over the next 12 months compared to 2019 levels; 
• reduction of cash capital expenditure to $20 billion or below for 2020 from a planned level of around $25 billion; and 
• material reductions in working capital. 

Together, these initiatives are expected to contribute $8 - 9 billion of free cash flow on a pre-tax basis. Shell is still committed to its divestment programme of more than $10 billion of assets in 2019-20 but timing depends on market conditions.

The Board of Royal Dutch Shell has decided not to continue with the next tranche of the share buyback programme following the completion of the current share buyback tranche.

We will continue to review the dynamically evolving business environment and are prepared to take further strategic decisions and consider changes to the overall financial framework as necessary.

In the current environment, Shell’s financial resilience is fundamental to continued investment in our strategic priorities. Shell seeks to maintain strong financial credit metrics and ensure it has a robust balance sheet to manage volatility. Shell’s liquidity remains strong, with around $20 billion in cash and cash equivalents, $10 billion of undrawn credit lines under our revolving credit facility and access to our extensive commercial paper programmes.

Read about Shell’s global response to COVID-19 at https://www.shell.com/covid19.html

Shell will publish its next quarterly update note on 31 March 2020 and release its Q1 2020 results on 30 April 2020.

Notes to editor

• Divestments of around $5 billion of assets were completed in 2019 
• Current share buyback tranche refers to the $1 billion share buybacks announced on 30 January 2020 
• Shell is rated AA- with negative outlook by S&P and Aa2 with stable outlook by Moody’s 

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COVID-19 North Sea Recovery by end 2020

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Which hydrocarbon sources are the highest Greenhouse Gas emitters?

The main culprit we are familiar with as a Greenhouse Gas ("GHG") is Carbon Dioxide CO2. However Methane CH4 is a worse polluter with 25 times the potency as a GHG than CO2.

Below is a comparison of GHG emissions intensity by hydrocarbon source. This includes CO2 and CH4 emissions. Unsurprisingly, energy intensity processes needed to extract hydrocarbons are high on the emissions list.

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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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Forcing regime change in Venezuela

US attempts to force regime change in Venezuela continues despite the huge humanitarian crisis it is causing.

The sanctions on the Maduro government have been absolutely crippling with oil output down from 2.5mmbbl/d down to sub-1mmbbl/d and falling - due to inability to invest to maintain production, striking PDVSA staff with pay uncertainty, inexperienced generals taking over and running over PDVSA as well and shrinking importer base for its crude. On this note, the situation is worsened with the US' latest sanctions of Russian Rosneft which was a key buyer of Venezuelab crude on 18th February. In the meantime, Rosneft has continued purchases from a PDVSA subsidiary under US granted waivers which expire in April 2020.

In 2019 the IMF forecasts the country's GDP fell by 35% and inflation increased by 200,000%. Clutching at straws, President Maduro has launched a new Bolivar currency and cryptocurrency called Petro although many doubt this will solve anything apart from being smoke and mirrors.

The longer the crisis continues, the stronger the support for the topple of Maduro, paving the way for the internationally-backed pro-democratic Juan Guaido to come to power.

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Lest we forget

With coverage of Iranian tensions diminishing and more recently overshadowed by COVID-19, we review the likely direction of travel in light of recent events.

On 23rd February 2020, the country held its 11th parliamentary elections with Conservatives securing all 30 parliamentary seats in Tehran and winning control overt most branches of the State. This will continue the Conservatives run in parliament but does set the stage for a more extreme Presedential candidate from the Iranian Revolutionary Guards to win in 2021.

The country has been drastically crippled by the reinstatement of US sanctions with oil production down to c.400mbbl/d from pre-sanction highs of >2mmbbl/d. The public resentment grows stronger both against the US but also its own government after the shooting down of the passenger jet at the beginning of this year. We could well see the path to an escalation in conflict with the US together with further refinement of its nuclear stockpile, although this will only be a real threat and take maximum effect in a tight oil market. With current weak trajectory of oil prices during COVID-19, the US reaction could very well be so what...?

At the same time, COVID-19 has claimed over 200 lives in Iran and question is whether we could see it seek assistance in the international arena if things worsen.

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Premier announces landmark acquisitions with BP and Dana for USD816 million

Premier announced the below this morning.

Premier is pleased to announce the proposed acquisitions of the Andrew Area and Shearwater assets from BP for US$625 million, and an additional 25 per cent. interest in the Premier operated Tolmount Area from Dana for US$191 million plus contingent payments of up to US$55 million (together the “Acquisitions”). Premier is also pleased to announce the proposed extension of its existing credit facilities to 30 November 2023.

In addition, Premier today provides a separate trading update ahead of its 2019 Full Year Results including the proposed farm-out of part of its Sea Lion and Tuna assets.

Rationale and benefits of the Acquisitions

• Add c.23 kboepd of cash generative production in 2019 with development upside; acquired assets forecast to generate over US$1 billion of free cash flow to end 2023
• Add 82 mmboe of reserves and contingent resources at an implied cost of less than US$10/boe
• Contribute to rising Group production out to 2024 with pro forma 2019 production in excess of 100 kboepd
• Add low cost, low carbon emission assets with combined opex of less than US$20/boe
• Accelerate the use of Premier’s US$4.2bn tax losses
• Materially strengthen Premier’s financial position
• Additional free cash flow accelerates debt reduction
• Significantly reduce forward covenant leverage ratio towards 1x by 2022
• Extension of existing, non-amortising facilities to late 2023

Asset highlights

• Andrew Area (50%-100% interests in 5 fields, operatorship): currently producing c.18 kboepd (net to BP) with material near term upside through further development of the Andrew Lower Cretaceous reservoir
• Shearwater (27.5% interest): significant producing and infrastructure hub, adding 25 mmboe of reserves and resources with incremental investment opportunities and tariff income
• Tolmount (25% interest): consolidates interest in existing high return development, which is on schedule to deliver first gas by end-2020, with significant upside following recent drilling success at Tolmount East

The proposed Acquisitions will be funded via a US$500m equity raise (net of expenses) which has been fully underwritten on a standby basis, existing cash resources and, if required, an Acquisition Bridge Facility of US$300 million. Premier expects that the equity raise will include both a placing and rights issue component with any shares issued under the placing qualifying for the subsequent pre-emptive rights issue. It expects to confirm the structure and terms in Q1 2020 following consultation with major shareholders.

RBC Capital Markets and Jefferies are acting as Joint Corporate Brokers and Joint Underwriters.

RBC Capital Markets is also acting as Financial Adviser and Sponsor.

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