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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Nova development could face delays with Gjøa tie-back challenges

Nova (formerly Skarfjell) is planning to submit the field development plan to the Norwegian authorities in H1 2018. The selected development concept is four production wells and three injection wells from two subsea templates tied back to the Gjøa platform. Neptune which operates Gjøa has raised concerns about the potential tie-back which it has now raised with the Ministry of Petroleum.

Nova is an oil and gas field operated by Wintershall and this would make it the company’s second development in Norway after Maria. The field is estimated to contain c.100mmboe of resources with c.70% oil. In December, the Ministry ruled that field that tie-back to existing infrastructure only need to cover the direct incremental costs of the host platform and not any of the existing operational costs. This was intended to boost activity in Norway. However, Neptune claims that the tie-back could increase overall costs for Neptune as well as impact its ability to tie-back its own discoveries including Cara and 35/9-3 in the vicinity.

A response from the Ministry is now pending and the ruling could determine how the Nova development plan filing will proceed.

The Nova partners are Wintershall/DEA (35% operator/10%), Cairn (20%), Spirit Energy (20%) and Edison (15%).

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Petronas makes offshore discovery in Gabon

PETRONAS has made the Boudji-1 discovery in deepwater Gabon. The discovery is located in Block F14 or Likuale in which PETRONAS holds 50% as an operator, Woodside holds 30% and the government holds 20%. The block lies in deepwater between depths of 2,500-3,200m.

Exploration activity in the deepwater has been slow with the country previously focussing in the onshore and coastal areas. Gabon has held ad-hoc licensing rounds for the offshore with PETRONAS’ block awarded in 2014. The 11th round held in 2015 is the most recent – the deadline for bids was extended, however in the end no awards were made with the timing coinciding with the collapse in the oil price.

PETRONAS is building ups its international presence again after a series of failed investments such as in Canadian and Egyptian LNG. Last week saw the company farm-in to 40% of FAR Energy’s blocks in The Gambia.

Full announcement of the Gabon discovery below.

PETRONAS ANNOUNCES DEEPWATER OIL AND GAS DISCOVERY OFFSHORE GABON

PETRONAS’ subsidiary, PC Gabon Upstream S.A. (PCGUSA) today announced new oil and gas discovery from its Boudji-1 exploration well in Block F14 (Likuale), located in South Gabon.  

The ultra-deepwater exploration well, drilled in water depths of 2,800 metres, encountered 90 metres of gross high quality hydrocarbon-bearing pre-salt sands.

The discovery marks a significant milestone for PETRONAS as it expands upstream growth in West Africa, demonstrating its frontier exploration and deepwater operational capabilities.

“The discovery in Gabon is an encouraging development for PETRONAS, as we continue to pursue growth activities beyond Malaysia, in line with the strategy to expand our core oil and gas business by growing our resource base,” said PETRONAS Executive Vice President & Upstream CEO, Datuk Mohd Anuar Taib.

“Aside from boosting Gabon’s oil and gas industry, this discovery will also spur further growth activities in the region, and complements our achievements towards building a significant deepwater portfolio globally,” he added.

PETRONAS, together with the Ministry of Petroleum & Hydrocarbons, Gabon, will conduct an assessment to further determine the commerciality of the resource volume.

PCGUSA is the operator for Block F14 (Likuale), with Australia’s Woodside holding a 30 per cent participating interest.

To-date, PETRONAS’ deepwater portfolio includes partnerships in the Gumusut-Kakap, Malikai and Kikeh deepwater fields located offshore Sabah. Additionally, there are two new upcoming deepwater development projects in the portfolio – the Limbayong field in Sabah and the Kelidang Cluster in Brunei.

PETRONAS’ global upstream reach continues to expand to Mexico with the winning of six deepwater blocks in bidding round 2.4, positioning PETRONAS as the second largest gross acreage holder in offshore Mexico with a total of nine blocks.

Further strengthening the company’s presence in West Africa, PETRONAS has recently signed a farm-out agreement (FOA) with Australia’ FAR Ltd for a 40 percent interest in the offshore petroleum licenses of Blocks A2 and A5 located offshore Gambia.

Source: http://www.petronas.com.my/media-relations/media-releases/Pages/article/PETRONAS-ANNOUNCES-DEEPWATER-OIL-AND-GAS-DISCOVERY-OFFSHORE-GABON.aspx

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SOCO terminates merger talks with Kuwait Energy

Soco has formally terminated merger talks with Kuwait Energy over valuation differences. Full press release from Soco below.

On 8 January 2018, SOCO International plc (“SOCO”) announced that it was in preliminary discussions with the newly-constituted Board of Directors of Kuwait Energy plc (“Kuwait Energy”) regarding a potential transaction.

SOCO confirms that it has terminated these discussions because it could not reach agreement with Kuwait Energy on the basis for an acceptable transaction.

SOCO’s Board remains committed to its strategy of shareholder value creation through sustainable cash returns to shareholders and growth of the business. The SOCO team, which has a track record of delivering shareholder value through asset acquisition and monetisation, delivering large scale developments, and returning capital to shareholders, evaluates M&A opportunities with reference to strict strategic, financial and operational criteria and only pursues transactions if they are determined by SOCO’s Board to be in the best interest of shareholders. SOCO’s Board continues to evaluate opportunities in accordance with these criteria.

Source: https://www.socointernational.com/statement-on-discussions-with-kuwait-energy-plc

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US Gulf Coast claims strategic trading hub title

The US Gulf Coast has inadvertently become a strategic trading hub for global oil flows in the rapidly evolving oil market marked by North American short cycle shale production. The region is blessed with access to premium upstream acreage linked by a strong network of infrastructure and ports which have been converted from import to import/export terminals following the lifting of the crude export ban two years ago.

Source: EIA

The PADD 3 region also houses close to 60 refiners with c.10 mbopd of complex refining capacity which can cater to a wide range of product slate demands. This has been increasing important as refining centres in Latin and South Americas have become challenged in recent years with the collapse in oil price leaving them financially imperilled. Mexican refineries are currently running at a utilisation rate of below 50% and Venezuela is on the verge of collapse.

The US has stepped up as the de-facto refiner – importing a range of blends from across the world and exporting refined products globally. Crude oil once destined for Europe for refining has also been making its way to the US with the closure of troubled refineries in Europe which started long before the recent oil price crash.

Over the last decade, the US has gone from a net refined products importer to the largest exported in the world. In this time period, the world has become more reliant on the US as the US itself has become more energy independent. At the moment, over half of refined product exports are destined for Latin America, displacing the lost refining capacity there. Asia is also a growing market for US crude and refined products with the Gulf Coast having easy access to Asia through the Panama Canal.

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Marathon fully exits Libyan operations to Total for USD450 million

Marathon announced this morning that it had sold its Libyan upstream operations to Total for USD450 million. Marathon had a 16.33% in the Waha licence area which covers a series of blocks in northern Libya and encapsulates a large number of fields and discoveries. Although Waha predominantly produces oil, there are significant undeveloped gas discoveries as well.

Waha licence acreage
Source: Wood Mackenzie

The divestment represents a full exit of Libya by Marathon as it makes a continued shift back to the US where it has a high margin, short cycle shale portfolio. The sale makes it the seventh country exit by Marathon since 2013 as part of its ongoing portfolio streamlining exercise.

Marathon has been lucky to find a buyer for its Libyan operations, with the country mired in civil war and competing factions fighting for power to rule. Waha and other Libyan production has been subject to halts in production for the past few years as conflict and destruction of infrastructure has heavily impacted the oil & gas industry. Libyan production has been recovering of late but risk of intermittent outages remain high.

Libyan oil production and exports
Source: Bloomberg

For Total, this deal shows its continued and relentless drive for growth as it looks to pick up assets near the bottom of the cycle, topping up a list of recent acquisitions including ENGIE’s LNG business for USD1.5 billion in November 2017 and Maersk’s E&P business for USD7.4 billion in August 2017. The geopolitical and above ground risk presented by Libya does not seem to have scared of Total.

The other partners in Waha are ConocoPhillips (16.33%), Hess (8.16%) and the state oil company NOC (59.18%)

Main oil & gas fields in Libya
Source: IEA

Related post: Waha resumes production - a brief history of the Waha fields

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Papua New Guinea LNG force majeure a week after expansion plans announced

ExxonMobil has declared force majeure on PNG LNG after Papua New Guinea was hit by a 7.5 magnitude earthquake on Monday. The partners in the plant, which exported 7.8 million tonnes last year, are ExxonMobil (33.2% operator), Oil Search (29%), State of Papua New Guinea (16.8%), Santos (13.5%), JX Nippon (4.7%) and Mineral Resources Development Company of Papua New Guinea (2.8%). Latest reports are that the pipeline and liquefaction plant sustained minimal damage, but could potentially be another six weeks before it can be restarted.

This comes a week after the announcement by the upstream partners in Papua New Guinea’s giant gas resources to more than double the country’s liquefaction capacity to 16mmtpa at a cost of USD13 billion. The partners are planning to help add a further three trains in the country – one to support growth at ExxonMobil’s P’nyang field, and two to service new gas from Total’s Elk-Antelope development. FEED is planned to start later this year, but will require agreement of terms with the PNG government first including domestic supply obligations.

Given this is a brownfield expansion, it is significantly cheaper than the original USD19.5 billion construction cost of the project. The partners were previously toying with the idea of having a separate facility for Elk-Antelope gas as Total and ExxonMobil could not reach agreement. ExxonMobil was pushing for the gas to go through PNG LNG supported by train expansions, while Total was considering a new plant (Papua LNG). While the details on the new three trains remain high level and could still see a separate Papua LNG project, this agreement thaws the development discussions which have been frozen for more than a year. The separate trains supporting the different upstream gas sources will also be conducive to structuring and financing of the proposed project – avoiding the complexity involved with unitisations and co-mingled gas marketing. The new LNG could come onstream by the early 2020s and would arrive in time for an emerging LNG supply gap that is foreseen by the industry.

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