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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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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First step in reversion of LNG pricing structures

LNG has historically been priced to an oil price marker. This is because until recently, LNG has been a point-to-point business - LNG was produced in one country and shipped under a 20-30 year contract to a single destination and the LNG tanker would shuffle back-and-forth between the two end points. This underpinned the project financing for construction of liquefaction projects.

LNG prices were then linked to oil as both the LNG producing nations and importers typically had no mature domestic gas market, and hence no price discovery for the gas, but for the importing country, the LNG would have displaced oil for power generation.

Since the genesis of North American LNG, US Gulf Coast exports have been priced to Henry Hub ("HH"), with contracts being HH plus a liquefaction toll. However, buyers are starting to shift to being overweight HH contracts and the last few weeks have seen the first set of contracts away from HH linkage.

On 2^nd April, NextDecade signed a 20 year SPA to deliver LNG from its Rio Grande facility with Shell. The pricing is c.75% linked to Brent with the remainder linked to HH, on a FOB basis. First LNG is planned to be in 2023. This was the first-ever LNG contracts out of the US to be indexed to Brent and comes with full destination flexibility.

On 5^th April, Shell went one step further by agreeing to sell LNG to a Japanese utility with a linkage to coal prices and is the latest innovation to help buyers seeking to diversify risks. This contract is for 10 years and is the first ever coal-linked contract.

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Anadarko signs SPAs for Mozambique LNG

Anadarko has signed three gas Sale and Purchase Agreements (“SPAs”) with Tokyo Gas/Centrica (2.6mtpa), Shell (2mtpa) and CNOOC (1.5mtpa) for its Mozambique LNG Area 1 development. This total 6.1mtpa of the planned 12.88mtpa ahead of FID expected in mid-2019. The LNG development will challenge upcoming projects given its fortunate location in between the Asian and European markets and will compete with Australian, Middle Eastern and North American suppliers.

These SPAs are conversions of existing Heads to Terms and there could be more SPA announcements on the way. Anadarko has made clear that it expects to debt finance c.USD12 billion of the USD20 billion Phase 1 development and these SPAs will help to support that financing.

The owners of Mozambique LNG Area 1 are:

Separately, the Area 4 LNG JV between ExxonMobil and Eni is also on track for sanctioning later in 2019.

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Aphrodite gas: lover's quarrel

Aphrodite is owned by Noble (35% operator), Delek Drilling (30%) and Shell (35%). The field lies in Block 12, offshore Cyprus and was discovered in 2011. BG Group farmed into 35% from Noble Energy in November 2015 for USD165 million following declaration that the field was commercial in June 2015.

As reported earlier, Shell intends to use Aphrodite gas to supply ELNG, but this has now faced a new hurdle. Cyprus and Israel are arguing over the extension of the Aphrodite structure into Israeli waters. Given the importance of the gas, the regional governments are keen to avoid the dispute delaying the commercialisation of the field.

Despite its vicinity to and significantly earlier discovery than Zohr (2015), Aphrodite remains uncommercialised. In fact, its commercialisation was previously called into question given the resource was too small to justify export infrastructure. This is a recurring theme within East Med gas with export route remaining a key issue. Egyptian gas discoveries are lucky enough to have a short gas domestic market and the option to export via LNG.

Israeli gas has taken longer to get off the ground, but has reached sufficient scale to export into the region by pipeline beyond supplying its own domestic market.

Cypriot gas, and indeed Lebanon, face the challenge of a small domestic market and lack of gas export infrastructure. Cyprus has toyed with the idea of developing its own LNG terminal but currently lacks the scale of reserves required to do so.

It makes sense for Aphrodite to supply ELNG at Idku. Shell has ownership in both Aphrodite and ELNG and a direct pipeline to the plant would allow it to bypass the Egyptian gas grid. Furthermore, a direct pipeline could galvanise further exploration and development activity along the route.

ELNG is largely supplied by the West Delta Deep fields and has been operating at minimal levels since gas was diverted to the domestic grid in 2013. In 2017, it shipped 0.78 million tonnes in cargoes (vs. capacity of 7.2 mmtpa). This has meant the plant remains operational and ready to ramp up once gas is supplied. In contrast, the Damietta LNG plant has been idled and would require significant work to restart operations.

The partners of Aphrodite are now finalising the field development plan with the Cypriot government. The plan initially involves five wells with a combined output of 800mmcf/d and developed using a floating platform. Cost estimates are estimated at USD2.5 - 3.5 billion excluding the cost of any pipeline to ELNG at Idku.

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Venture Global doubles LNG supply contract with Shell on Calcasieu Pass

On 6^th March, Venture Global announced that it had agreed to double its gas sales with Shell North America LNG from 1mtpa to 2mtpa under an amendment to the earlier gas sales agreement for LNG from Calcasieu Pass.

This brings the total committed capacity to 3mtpa with Edison having agreed 1mtpa in September 2017. The sale contracts are for 20 years and under FOB terms. The counterparties to date provide validation of the attractiveness of the project being one of the lower cost, mid-scale liquefaction projects and shows confidence in it going ahead and being able to deliver LNG in a reasonable timescale.

The Calcasieu Pass project is for 10mtpa with easy access to the sea and more than a mile of deep water frontage. It is waiting for non-FTA export approval later in 2018 following which it will look to take FID dependent on securing of further gas sales contracts. Venture Global sees first commercial operations at the end of 2021.

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OVL to bid for South Azadegan oil development in Iran

Indian oil giant ONGC Videsh Limited ("OVL") will bid for the development rights of the giant South Azadegan in Iran. There is strong competition with the likes of Gazprom, Lukoil, Rosneft, Shell, Total, Eni Petronas, Inpex, Sinopec and CNPC. of Malaysia and Russia’s Gazprom. OVL is one of 34 companies that pre-qualified last year for development of the field which is estimated to contain 6bnboe recoverable and currently produces 80mbbl/d - with the right investment, this could reach 320mbbl/d.

The National Iranian Oil Co ("NIOC") will issue a tender for the development shortly.

Separately, OVL will also rework the Farzad B gas field at a cost of USD6.2 billion, which it had discovered a decade ago and is trying to get Iran to award rights of the field to it. Sources say that OVL had last year made its ‘best’ offer to invest USD11 billion in developing the Farzad-B field and building export infrastructure but Iran has deterred awarding the rights of the field to OVL owing to differences over pricing of the fuel. OVL has now instead offered to do just the upstream part of bringing the field to production while leaving the marketing of the fuel to Iran, which will cost USD6.2 billion.

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Norway awards record 75 exploration licences in 2017 APA

Norway has awarded a record number of 75 exploration licences in the APA 2017 licensing round to 34 companies. The licences comprised 45 in the Norwegian North Sea, 22 in the Norwegian Sea and 8 in the Barents Sea.

Statoil was the biggest winnder with 31 awards. Supermajors ConocoPhillips, ExxonMobil, Shell and Total also picked up licences.

Of the E&Ps:

• Aker BP was the winner with 23 licences (14 as operator)
• Lundin has been awarded 14 licences (5 as operator)
• DNO has been awarded in 10 licences
• Faroe Petroleum has been awarded 8 licences (four as operator)
• Cairn Energy has been awarded 5 licences

The Annual Predefined Areas or APA round was introduced in 2003 to encourage exploration and development of discoveries near existing infrastructure. Across all the awards this time, there are three licences with firm drilling commitments, with the remaining having drill or drop options in the next 12-24 months.

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Breathing new life into Tyra

The Danish Underground Consortium ("DUC") has approved an investment of DKK21 billion (USD3.4 billion) for the full redevelopment of the Tyra field.

DUC members are Total/Mærsk (31.2 %), Shell (36.8 %), Chevron (12 %) and Nordsøfonden (20 %). The development will ensure continued production from Denmark's largest field for years to come and will also rejuvenate important Danish offshore infrastructure. About 80% of the investment will be for modification of existing and construction of new facilities, with the remainder for decommissioning and removal.

The Mærsk press release noted:
"Tyra is the centre of Denmark’s national energy infrastructure, processing 90% of the nation’s gas production.

Through new development projects and third party tie-ins, the redevelopment of Tyra can be a catalyst for extending the life of the Danish North Sea – not just for Maersk Oil and the DUC, but also for Denmark."

"The new infrastructure can enable operators to pursue new gas projects in the northern part of the North Sea, where the most recent development, Tyra Southeast, delivered first gas in 2015 and is producing above expectations."

"The redeveloped Tyra is expected to deliver approximately 60.000 barrels of oil equivalent per day at peak, and it is estimated that the redevelopment can enable the production of more than 200 million barrels of oil equivalent. Approximately 2/3 of the production is expected to be gas and 1/3 to be oil."

The redevelopment has received government approval and will commence in 2019 with the field being shut-in between November 2019 and Summer 2022 for the works to take place.

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Shell sells onshore Gabon to Carlyle

On 24^th March, Shell announced the sale of its onshore Gabon assets to Assala Energy Holdings (a portfolio company backed by Carlyle Group).

Assala will pay USD587 million and assume debt of USD285 million, taking “enterprise value” to c.USD870 million. Shell will also receive up to a further USD150 million in contingent payments depending on oil prices and performance. This compares with a Wood Mackenzie NPV10 of c.USD600 million and implies that some value being placed on the gas resources.

The onshore portfolio comprises c.60mmbbl of oil (commercial) and c.160bcf of contingent gas. The gas is currently undeveloped due to a limited market, but could one day be used to supply local power generation. The portfolio produces c.35mbopd of and Shell Trading will retain lifting rights from the assets for the next five years.

The licences being acquired are a mix of PSCs and concessions with some of the concessions being converted into PSCs over the last 10-20 years when they came up for renewal. The licences are owned directly and indirectly through a JV with the Gabonese government (75% Shell, 25% State). The largest asset in the portfolio is Toucan which commenced production in 2003 – significant investment was made between 2012-2014 as part of an additional phase of development to extend the field life to c.2030.

The offshore licences (BC9 and BC10) are excluded from the same, where Shell made the large Leopard-1 discovery in 2014 which is estimated to contain close to 1tcf of recoverable gas.

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Equalising the buyer and seller: Shell and Chrysaor's oil price contingent payment structure

After a tumultuous period of oil prices with investment decisions and M&A transactions put on hold, the outlook is beginning to stabilise in 2017. With more comfort on the near term trajectory of oil prices, the corporate mind-set is shifting from balance sheet management to strategic re-focussing and growth.

Nevertheless, buyer-seller price expectation gaps still remain and a way to bridge this gap is the use of oil price contingent payments in a transaction. The last time this mechanism was seen in a major market deal was Seplat’s acquisition of Chevron’s assets in Nigeria in 2015. Today, this novel structure was seen again in Chrysaor’s acquisition of Shell’s North Sea portfolio, with an additional twist.

In the Chrysaor acquisition, the terms were as follows - Chrysaor would make payments to Shell of up to USD600 million split over the 2018-2021 period:

• First payment to be made if Brent rises above USD60/bbl in 2018 and 2019
• Second payment to be made if brent rises above USD70/bbl in 2020 and 2021
• Full payout of the USD600 million is made if Brent reaches USD95/bbl anytime in the 2018-2021 period

However, Chrysaor also managed to secure downside protection on its acquisition should oil prices fall. The transaction allows for Shell to make a payment to Chrysaor of up to USD25 million a year (totaling USD100 million) between 2018-21 should Brent fall in the range of USD47.5–52.5/bbl. Full payout of the USD25 million is made in each year if Brent falls below USD47.5/bbl.

The above structure strikes a balance in providing Shell protection from selling the assets too cheaply in a rising oil price environment and Chrysaor overpaying should oil prices fall. Given the structure of the mechanism, it is clear that the contingent consideration is based on near term rather than long term oil price performance with the size of the payments reflecting the impact on near term production cash flows depending on the direction of the oil price. The long stop date of 2021 is relatively long for an M&A transaction, but suitable for a transaction of this nature where oil prices behavior is exhibited over a longer period of time. While longer periods in which contingent payments are active are normally more beneficial to the seller, the mirroring contingent payment from Shell to Chrysaor in this instance puts both the buyer and seller on equal footing.

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Chrysaor future: Acquisition of Shell North Sea portfolio

On 31st January, Chrysaor announced that it had agreed to acquire a portfolio of North Sea assets from Shell for USD3 billion. The transaction is expected to close in H2 2017 and will transform Chrysaor into one of the largest North Sea focussed E&P companies, who will adopt 400 staff from Shell as part of the deal.

The full-cycle portfolio, which comprises exploration, near-term development and production, produced 115mboepd in 2016 and 350mmboe of 2P reserves. Chrysaor has already identified a number of growth opportunities in the portfolio including incremental recovery to extend field life and intends to implement a programme of near field drilling around key hubs.

The acquisition will be funded by:

• USD1.5 billion bank debt
• USD1 billion investment from Harbour Energy
• USD0.5 billion from existing company and shareholder funds and a financing package provided by Shell

An important component of the deal is that Shell will retain a decommissioning liability of USD1 billion, in a which mirrors EnQuest’s recent acquisition of BP’s North Sea assets. The decommissioning costs associated with the portfolio are currently expected at USD2.9 billion (2016 real terms) and USD3.9 billion in nominal terms. There are no material decommissioning costs in the near term, however, Chrysaor has provided security for its exposure to the liability through letters of credit from part of its bank credit lines (on top of the USD1.5 billion bank debt). (Further discussion in our Siccar Point article).

Harbour Energy is a private equity vehicle backed by EIG Global Energy Partners and led by Linda Cook as CEO. Ms Cook was previously at Shell for 29 years where she was in charge of Shell’s gas and renewables business. She left in 2014 after losing out to Peter Voser for the spot of Chief Executive of Shell. She will now act as Chairwoman of Chrysaor.

The transaction also allows for USD780 million in contingent payments, comprising USD180 million for future exploration success and USD600 million for higher oil prices.

The list of assets acquired are as follows:

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Shell Gulf of Mexico divestment

On 29^th August, Shell announced that it had agreed to sell 100% of its interests in the Gulf of Mexico Green Canyon Blocks 114, 158, 202 and 248 (the Brutus/Glider assets), to EnVen Energy Corporation for USD425 million in cash. These assets do not appear to form part of Shell's core strategy in the region, with recent activity focusing on the Mars/Vito/Na Kika areas to the east.

The Brutus/Glider assets include the Brutus Tension Leg Platform, and the Glider subsea production system, as well as the pipelines used to evacuate production from the platform. The assets have a combined current production of 25mboepd, although the Brutus platform has capacity to produce 130mboepd.

Given investors' key concern is around the company's debt levels (Shell has over USD75 billion in net debt following the acquisition of BG), and negative free cash flow at current oil price levels, the divestment is welcome and is a step towards the USD30 billion divestment programme mentioned last year.



Source: Shell

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Sub-Saharan Africa - newsflow update

Gabon Deepwater - Leopard discovery

• Leopard-1 was drilled on licence BCD10
• Shell 75%*, CNOOC 25%
• Encountered substantial gas column with 200m net gas pay
• Further appraisal required
• FLNG? 3-4 tcf may be required, although economics of sales into Europe are marginal
• Government is also keen to grow domestic gas market

Congo Offshore - Eni/NewAge - follow up discovery in Marine XII

• Minsala Marine discovery
• Estimated 1bnboe in place, of which 80% oil
• In same shallow water block as the Litchendjili and Nene Marine fields, both of which are currently undergoing development

Angola - first discovery in Kwanza Basin

• Pre-salt offshore Kwanza Basin - oil discovery made by Repsol
• Will evaluate commerciality of the Locosso oil field
• Located in Block 22, immediately to south of Cobalt's Block 21 which contains the play opening Cameia field
• Given remote location and water depth, Wood Mackenzie estimates will require 300mmbbl to be commercial on standalone basis

Liberia, Cote d'Ivoire - Anadarko's non-commercial wells

• Anadarko wells in West Africa all encountered non-commercial oil
• Liberia: Iroko-1 and Timbo-1
• Cote d'Ivoire: Morue-1
• http://www.anadarko.com/SiteCollectionDocuments/PDF/Operations%20Reports/APC%203Q14%20Ops%20Report%2010-28-14.pdf

Nigeria - NNPC pre-empts sale of OML25

• NNPC has pre-empted on the sale of OML25
• Post transaction, NNPC will own 100% and likely transfer the interest to NPDC
• NPDC's portfolio is already overstretched and future investment will be heavily constrained
• The winning bidder of the Shell, Eni, Total process was Crestar Integrated Natural Resources Limited
• It is believed that the pre-emption, a decision made by the Minster of Energy, is due to Crestar's Chairman being  Osten Olorunsola
• The Minister of Energy had fired Osten Olorunsola as Director of Petroleum Resources in June 2013
• http://africaoilgasreport.com/2014/11/farm-in-farm-out/nnpc-in-desperate-search-for-funds-to-pay-for-oml-25/

South Sudan - fighting likely to intensify around fields

• Government and rebels now re-arming following end of rainy season
• Sudan is providing South Sudanese Machar-led rebels with weapons and intelligence
• Rebels likely to set-up bases where they can attack oil fields
• Local self defence militia are guarding fields bolstered by Chinese peacekeepers
• Should prevent rebels gaining control of fields, but fighting likely to intensify

East African export pipeline

• World bank has pledged USD600mm funding towards Ugandan/Kenyan export pipeline
• Total cost estimated to be >USD4bn
• Project still remains in early stages - commercial structure, construction, ownership and operations all yet to be determined
• FEED contracts expected to be awarded end of 2014

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