Saudi Arabia - joining the dots

A series of blog entries exploring Saudi Arabia's role in the oil markets with a brief look at the history of the royal family and politics that dictate and influence the Kingdom's oil policy

AIM - Assets In Market

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Iran negotiations - is the end nigh?

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Yemen: The Islamic Chessboard?

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Acquisition Criteria

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Valuation Series

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Showing posts with label Cairn. Show all posts
Showing posts with label Cairn. Show all posts

Wednesday 24 June 2020

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.

Friday 1 November 2019

SNE partners buy FPSO


Cairn and FAR have announced a material increase in the capex for the SNE development from USD2.2 billion to USD3.7 billion (plus USD500 million contingency) for Phase 1. This has been driven by the partners' decision to buy an FPSO rather than lease it. This does however bring the opex down, estimated form c.USD14/boe to c.USD11/boe.

FID is expected to be taken at the end of 2019 with first oil forecast for late 2022. The development will be phased with Phase 1 targeting 230mmbbl and production of 100mbopd. Phase 2 will target a further 253mmbbl oil.

This is a particularly tough week for Cairn having earlier announced a dry hole in Mexico at Alom-1 and the Indian arbitration award delayed into summer 2020, while now also being exposed to larger capex on SNE.


Tuesday 12 March 2019

Fighting the Kraken


Cairn has announced a reserves downgrade on Kraken by 6.8mmboe (net) or 19% to reflect ongoing production issues. The field has been hit by a myriad of problems since start-up in 2017 and its failure to be farmed-down by operator EnQuest in 2018 highlights the technical concerns on the field.

The field's output has been hit by poor FPSO uptime driven by system outages as well as higher water-cut than originally expected. There will be a planned shutdown later in 2019 to make improvements to the FPSO uptime.

Operator EnQuest maintains the level of 2P reserves and does not expect to recognise an impairment as it finalises its year end 2018 accounts.

The partners in Kraken are EnQuest (70.5% operator) and Cairn (29.5%).

Monday 17 December 2018

SNE partners progress to FEED for Phase 1 of the development


The SNE JV offshore Senegal (Cairn 40%, Woodside 35%, FAR 15%, Petrosen 10%) has entered FEED for Phase 1 of the SNE development. The engineering contract has been awarded to the Subsea Integration Alliance (OneSubsea, Schlumberger and Subsea 7).

First oil is being targeted for 2022 with an initial production rate of c.100mbopd. The exploitation plan had previously identified a total development of 500mmbbl of oil over a multi-phase development with the Phase 1 FEED targeting 230mmbbl from the base, thicker sand package.

Woodside noted that the Senegalese Minister of Petroleum and Energies has approved Woodside’s transition to operator of the RSSD JV (Rufisque, Sangomar and Sangomar Deep) and the SNE development. Separately, FAR continues its commercial arbitration around the initial deal between Conoco and Woodside.


Tuesday 6 March 2018

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%).

Tuesday 16 January 2018

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.

Wednesday 27 December 2017

Premier's Christmas present



Premier Oil announced today that the Catcher field achieved first oil on 23rd December, on schedule and almost 30% below budget. Initial production will be c.10mbopd as gas processing and water injection modules are commissioned. Production will be ramped up in phases through H1 2018 as the Varadero and Burgman fields are brought onstream increasing production to 60,000mboepd (gross).

The Catcher partners are Premier Oil (50% operator), Cairn Energy (20%), MOL (20%) and Dyas (10%). For Premier Oil, Catcher will account for c.25% of 2018 production with successful ramp up of the field important to deleveraging the balance sheet next year. For Cairn, this will diversify the production base following first oil at Kraken (29.5% interest) earlier this year.

Thursday 30 November 2017

Kraken emerges

In mythology, the Kraken was a giant sea monster that dwelled in the present day North Sea. Today, the Kraken field is emerging with production growing day-by-day and a target to reach 50mbopd in H1 2018.

Gross production reached 23mbopd in November (month average) and the second processing train was brought online at the end of the month. The final DC2 production well is now onstream and the DC3 wells are near completion and expected to be brought onstream ahead of schedule. DC4 drilling will commence in 2018 and once online, will bring the field production to 50mbbl/d.
Kraken breathes some new life in the UK North Sea, being one of the small number of sizeable developments in the basin for a number of years. Its start-up has been relatively smooth, with first oil achieved at the end of June 2017 and a steady ramp-up since. Despite some above surface teething issues, these appear largely resolved with the crews getting more familiar with the FPSO operation and continued tuning of equipment.

Source: OGInsights analysis

The field is important for both EnQuest (70.5% operator) and Cairn (29.5%). With the achievement of plateau production, it is expected that one or both partners will farm-down their stake, not least having inherited additional interests from former partner First Oil when it went into administration. The long-life nature of the field, albeit heavy oil, should attract interest from major North Sea players.

Friday 1 September 2017

Senegal moves ahead



Cairn Energy, the operator of the SNE field in Senegal, released a resource update on 22nd August as part of its half-year announcement.

The updated 2C resource base is 563mmbbl gross (vs. 473mmbbl in May 2016) and now brings it in line with Woodside's estimate of 560mmbbl, but is still far below that of partner FAR which carries 641mmbbl (assessed by RISC). The differing resource estimates is nothing new and we constantly see the other partners playing catch-up with FAR.

Focus is now on FEED with no further drilling planned until after FID. It is envisaged that SNE will undertake a phased development with the initial phase targeting the lower 500 series sands and core area of the upper 400 series sands. The second phase will target the remainder of the 400 series and more outreach parts of the field.

Gross capex is currently estimated at USD2.3 bn, but could come down as the engineering is defined and possibility of Woodside bringing in an existing FPSO. FID for Phase 1 is planned for the end of 2018 with first oil in 2021 and an initial plateau of 75-125mbopd.

The partners are Cairn 40%, Woodside 35%, FAR 15% and Petrosen 10% (Petrosen has the option to increase its interest to 18% during the development phase).

Monday 28 August 2017

Sail-away to Catcher

The Catcher FPSO sailed away on 26th August from Singapore. It will take around 45 days to reach the UK North Sea, following which it will be connected and commissioned, a process expected to take 60-65 days with first oil targeting December.

The project is on schedule and c.30% below budget. Development drilling results have been promising with 30% more net pay and 40% better well deliverability. Expected plateau will now increase by 20% to 60mboepd with a potential for reserves upgrade from the 96mboe 2P at sanction.
The Catcher field partners are: Premier 50% operator, Cairn Energy 20%, MOL 20% and Dyas 10%.

Tuesday 8 August 2017

SNE North is Sirius


Cairn has completed the SNE-1 North exploration well (Sirius prospect), located c.15km north of the original SNE-1 discovery. The well reach TD 2,837m and was completed ahead of schedule. A 24m gross hydrocarbon column was encountered across three intervals with 11m net condensate and gas pay in the primary objective and 4m net oil pay in the secondary objective.

A full set of oil, condensates and gas samples were recovered to surface from the 500 series sands, the same sand series that contributes the bulk of volumes in the main SNE field. The oil is slightly lighter at 35˚ API (vs. 32˚ API in SNE).

Further work will be required to establish the size and commerciality of the discovery, although FAR has assigned 294mmbbl of mean recoverable resources. The find has positive connotations for the block demonstrating further hydrocarbon potential to the north of the block. The well will now be plugged and abandoned and concludes the five well 2017 drilling campaign and the Stena DrillMAX rig will be released.

Wednesday 18 May 2016

Barents Sea licence awards


The Norwegian Ministry of Petroleum and Energy has issued ten new production licences in the Barents Sea as part of Norway’s 23rd licencing round, following applications made by 26 companies in January. This is the first time since 1994 that new exploration acreage has been made available to the industry in the southeastern Barents Sea. 
From the International E&P names:
  • Lundin has been awarded interests in five licences (three as operator)
  • Det Norske has been awarded interests in three licences (one as operator)
  • Tullow has been awarded an interest in one licence (non-operated)
  • Cairn (through its Capricorn Norge subsidiary) has been awarded three licences (one as operator)

The companies have committed to binding work programmes that primarily include a drill or drop decision to be made within two years.


Barents Sea licence areas
Source: NPD



Monday 15 February 2016

Senegal offshore reaches threshold for commerciality



On 8th February, FAR Ltd announced an updated independent resource report (by RISC) of the SNE discovery offshore Senegal (Cairn 40%, ConocoPhillips 35%, FAR 15% and Petrosen 10%). The report increases contingent resources for the discovery to 240mmbbl 1C (from 150mmbbl), 468mmbbl 2C (from 330mmbbl) and 940mmbbl (from 670mmbbl). This assessment includes the SNE-1 discovery well and subsequently reprocessed (more accurate) 3D seismic. Significantly the update does not include the successful SNE-2 appraisal well. Given the lack of major oil discoveries worldwide, SNE is an important find (largest since 2014) and on further positive appraisal drilling, will be an increasingly desirable asset.

Cairn previously indicated that around 200mmbbl is the commercial threshold to underpin a 'foundation' development offshore Senegal, where fiscal terms would yield a 20% IRR at USD45-50/bbl oil price. The resource report would imply that the discovery now has the scale to support a development and the SNE-2 appraisal well demonstrates deliverability following strong production tests (8,000bbl/d from blocky sands and 1,000bbl/d from hetrolithics). The next element of the appraisal campaign is to test for connectivity and the upcoming drilling should help to determine this. Significant further drilling needs to be completed; however results to date are encouraging.

The second appraisal well SNE-3 has now been cored and logged with production test results expected later in February. This will be followed by the Bellatrix exploration well testing a 168mmbbls P50 prospect, then deepening to test the northern extent of SNE (no production test planned). In addition to a more comprehensive resource update in mid-2016, there is the option for three further wells later this year. With drilling time currently ahead of expectations, there is scope to drill an additional well without extending timeline or budget.

Wednesday 8 October 2014

Sangomar Deep - Senegal's first offshore discovery




  • On 7 October 2014, Cairn Energy and its partners announced that a significant oil discovery had been made in the FAN-1 exploration well in the Sangomar Deep block, Senegal's first offshore discovery
    • 29m net pay
    • Gross oil interval of >500m
    • No OWC encountered
    • Distinct oil types recovered 28-41 API
  • This was followed by a second discovery in the SNE-1 well, announced on 10 November 2014
    • 36m net pay
    • Gross oil interval of 95m with gas cap
    • Oil of 32 API, oil and water recovered to surface
    • 1C: 150mmbbl, 2C:330mmbbl, 3C: 670mmbbl
  • Block is operated by Cairn (40%) - other partners are COP (35%), Far (15%), Petrosen (10%)
  • SNE-1 is potentially commercial on a standalone basis; FAN-1 economics more marginal - may be tied back to SNE-1 or warrant a stand-alone development, will need further delineation