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Cairn Energy PLC (CNE)

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Tuesday 11 September, 2018

Cairn Energy PLC

Half-year Report

RNS Number : 3375A
Cairn Energy PLC
11 September 2018
 

 

EMBARGOED FOR RELEASE AT 0700                                                  11 September 2018

 

 

 

CAIRN ENERGY PLC ("Cairn" or "Company" or "Group")

 

Half-Year Report Announcement

 

 

Simon Thomson, Chief Executive, Cairn Energy PLC said:

 

"Cairn has made strong progress across its balanced portfolio. Cash flow from the North Sea is now established and development projects in Senegal and Norway are well advanced to support the production base over the long term.

 

We are also delighted to have enhanced our exploration portfolio with potentially high impact opportunities across frontier and emerging basins. This additional acreage supplements our existing active programmes in the UK, Norway and Mexico.

 

This continued strategic delivery, together with our strong balance sheet, ensures Cairn remains well-positioned to access material value growth potential."

 

HIGHLIGHTS

 

Production

Ø Catcher (Cairn 20% working interest (WI)) averaged ~27,000 barrels of oil equivalent per day (boepd) (gross) in H1, reflecting constrained production as commissioning was completing and ramp up continued. Producing up to 60,000 barrels of oil per day (bopd) (gross) in August.

Ø Kraken (Cairn 29.5% WI) averaged ~30,700 bopd (gross) in H1, primarily as a result of planned and unplanned production downtime. Producing 35,000 - 40,000 bopd (gross) in August.

Ø Combined net production to Cairn from the fields in H1 averaged ~14,400 boepd with production in June averaging ~19,700 boepd (respectively ~13,000 boepd and ~18,200 boepd, net of FlowStream entitlement).

Ø Combined net production in H2 is expected to average ~20,500 - 22,000 boepd net to Cairn (~18,500 - 20,000 boepd net of FlowStream entitlement).

 

Developments 

Senegal

Ø Delivered key milestones for the SNE field development plan (Cairn Operator 40% WI):

Ø Evaluation Report submitted to the Government of Senegal

ØMulti-phase development plans for ~500 million of barrels of oil (mmbbls)

ØProduction 100,000 bopd (gross) 

Ø Assessing tender responses for the Floating Production Storage and Offloading (FPSO) facility and subsea infrastructure ahead of the front end engineering and design (FEED) planned for Q4 2018

Ø Development and Exploitation Plan submission and approval targeted for H2 2018 with the Final Investment Decision (FID) to follow in 2019

Ø Formal Transfer of Operatorship (TOO) to Woodside expected in Q4 2018; key work streams already delegated

Ø Detailed work underway on project financing

 

Norway

Ø Nova development (Cairn 20% WI) in Norwegian North Sea, Plan for Development and Operation (PDO) submitted in H1.  Expected to deliver plateau production of 50,000 bopd (10,000 bopd net to Cairn) from 2021

 

Exploration

International

Ø New country interests acquired across frontier and emerging basins in Suriname, Côte d'Ivoire and Mauritania:

Ø Suriname - awarded an operated exploration agreement (Cairn 100% WI) by the State Oil Company of Suriname (Staatsolie) on acreage in the offshore Demerara plateau with 2D seismic activity planned from Q4 2018

Ø Côte d'Ivoire - farm-in agreement with Tullow Oil for a 30% WI in seven onshore licences* with seismic activity planned in 2019

Ø Mauritania - option agreement to acquire 30% WI from Total to enter a large offshore exploration block** upon a well decision following ongoing seismic acquisition and evaluation programme

Ø Mexico - plans to progress the first two exploration wells on Block 9 (Cairn Operator, 65% WI) and one exploration well on Block 7 (Cairn 35% WI, ENI Operator) in H2 2019.  Plans  to evaluate 3D seismic over the newly acquired Block 15 in the Tampico Mislanta basin

 

*subject to Government approvals
**subject to Government and partner approvals

 

UK & Norway

Ø Exploration campaign underway with plans to drill up to ten wells (subject to partner approvals) in 2018-19 across a variety of play types:

Ø Two wells are currently operating: P2184 licence (Cairn Operator 45% WI) targeting the Ekland prospect in the UK North Sea using the Ensco 101 drilling rig and P1763 licence targeting the Plantain prospect and potentially the Agar discovery (Cairn 50% WI) in the UK North Sea using the Transocean Leader. (Cairn farmed into the licence (25% WI) with Azinor Catalyst  in H1)

Ø Completed drilling in H1 on Tethys and Raudåsen prospects with a small oil discovery regarded as non-commercial and a dry well, respectively

Ø Upcoming Stjerneskudd well on PL885 (Cairn 30% WI) in the Norwegian Sea expected to spud in Q4 

Ø Awarded five licences (three operated and two non-operated) in the UK 30th Licensing Round in H1 in existing core central North Sea areas

Ø Plans for 2019 exploration programme maturing with material prospects and equity interests; three to four wells expected, subject to partner approvals   

 

Finance

Ø Oil sales revenue of US$172 million (m) at an average realised price of US$66.97/barrel (bbl) (US$67.81/bbl before hedging costs)

Ø Group cash at 30 June 2018 US$75m

Ø Reserves Based Lending (RBL) facility US$65m drawn at 30 June 2018

Ø Extension of existing US$575m RBL maturity from 2021 - 2025 agreed in order to incorporate expected Nova cashflows into the debt capacity calculation and create additional flexibility

Ø Norway exploration tax receivable of US$62m at 30 June 2018, US$59m drawn under the Norway Exploration Finance Facility

Ø Cash outflow on Kraken, Catcher, Senegal and Nova developments of US$86m in H1 and forecast at ~US$124m for H2 2018

Ø Exploration cash outflow across the portfolio of US$48m in H1 2018 and forecast at ~US$72m in H2 2018 (net of Norwegian exploration tax rebate)

Ø SNE project finance launch expected Q4 2018

 

India Tax Dispute

Ø Final hearing of Cairn's claim under the UK-India Bilateral Investment Treaty (the Treaty) took place in August in The Hague; the Tribunal has stated that it will make appropriate arrangements to progress with the drafting of the award as expeditiously as possible   

Ø During H1, the India Income Tax Department (IITD) instructed the sale of ~2% shareholding in Vedanta Limited (VL) held by Cairn, seizing proceeds of US$231m.  Subsequent to H1, a further ~1% of shares were sold. The IITD has also seized US$162m dividends due from the VL shareholding plus a US$234m tax refund due.

Ø Following the disposal of the shareholding in VL and seizure of proceeds by the IITD, Cairn has recorded a loss on de-recognition of the shares sold of US$231m

Ø Cairn remains confident of its legal position; the Treaty affords strong provisions to enforce a  successful award

 

 

Enquiries to:

Analysts / Investors

 

David Nisbet, Corporate Affairs

Tel: 0131 475 3000

 

 

Media

 

Linda Bain/Christian Goodbody, Corporate Affairs                                               
Cairn Energy PLC

Tel: 0131 475 3000

 

 

Patrick Handley, Will Medvei

Brunswick Group LLP

 

Tel: 0207 404 5959

Webcast

There will be a live audio webcast of the results presentation available to view on the website (www.cairnenergy.com) at 9am BST. This can be viewed on PC, Mac, iPad, iPhone and Android mobile devices.

An 'on demand' version of the webcast will be available on the website as soon as possible after the event. This can be viewed on PC, Mac, iPad, iPhone and Android mobile devices.

Presentation

The results presentation slides will be available on the website from 7am BST.

Conference all

You can listen to the results presentation by dialling in to a listen only conference call at 9am BST using the below dial-in details.

Dial-in Details:

United Kingdom (Local): 020 3059 5868                                                           

All other locations:  +44 (0)20 3059 5868        

Access code: Cairn Energy PLC Half-Yearly Results 2018             

A recording of the conference call will be available from 11 September 2018 until 18 September 2018.

 

Recording Dial-in Details:

Replay number: +44 (0)121 260 4862                                                                                            

Conference code: 677557                                                            

Transcript

A transcript of the presentation will be available on the website as soon as possible after the event.

 

Corporate & Finance Overview

Cairn's strategy is to create, add and deliver value for shareholders from a balanced portfolio of exploration, development and production assets. We seek to deliver consistent material growth through our exploration portfolio, which is primarily in frontier and emerging acreage with the greatest potential value impact. Cashflow realised from our production assets enables us to sustain our exploration and development activity.

 

In the first half of 2018, we made excellent progress in building and diversifying the exploration portfolio as we seek to participate in a range of exploration opportunities from material high impact prospects in frontier and emerging basins to short cycle time prospects in more mature basins.  We have focused on geologies where Cairn has the greatest knowledge and ability to manage an active exploration programme over the next three years with a meaningful number of operated and non-operated wells.

 

Cairn continues to maintain financial flexibility with a strong balance sheet and cash flow from production to fund an attractive portfolio of exploration and appraisal opportunities.  Our sustainable business model provides the ability to leverage success, and we continue to optimise and where appropriate expand the asset base.

 

Current sources of funding include cash of US$75m at the half year end, the US$575m RBL bank facility which was drawn US$65m at 30 June and the Norway Exploration Finance Facility, which is available to finance tax rebates on Norwegian exploration expenditure. During H1 we were pleased to see production from Catcher and Kraken steadily increase, generating oil sales of US$172m and operating cashflow of US$112m (adjusted for oil sales receivables).  Near-term uses of capital to the end of the year include US$124m anticipated expenditure on the Kraken, Catcher, Senegal and Nova developments and forecast Exploration and Appraisal (E&A) expenditure of US$72m across the portfolio.

 

Operational Review

Production

In the UK and Norway we have made good progress in our non-operated producing assets during H1, with ongoing project commissioning on both fields now essentially complete. In addition, the non-operated Nova development in Norway reached FID in H1 2018 and is expected to deliver first oil in 2021 with peak net production to Cairn of 10,000 bopd.  The three projects can be expected to provide production and cash flow to Cairn through to the period when the Senegal development comes on stream.  Further tie-back and infill opportunities exist in the vicinity of all three fields under development or in production.

Catcher
The Catcher Area averaged ~27,000 boepd (gross) in H1, reflecting constrained production before commissioning of the gas and the water injection plants was completed. However, plateau production rates of ~60,000 bopd (gross) have been achieved since May with reductions when there have been issues with the gas export, following the start-up of gas export into the SEGAL gas pipeline, or unplanned shutdowns. 

Since first production, more than eight million barrels of oil have been produced and 16 cargoes lifted.

Production data from the three Catcher Area fields (Catcher, Varadero and Burgman) continues to demonstrate good pressure support and connectivity between the reservoirs.  Delivery potential from the available wells remains significantly in excess of the FPSO design capacity and the Joint Venture (JV) sees opportunities for extension of the plateau production rates of 60,000 bopd.

Post H1, the DSV Falcon successfully tied into production four development wells, further increasing deliverability from the Catcher Area.  The 17th well, a Burgman producer, was complete in August and the 18th well, also a Burgman producer, is scheduled to complete in October. This will mark completion of this project phase of the Catcher Area development.  Both wells will be available for production from November.

Several near field discoveries have been identified as potential subsea tie-backs to the Catcher Area FPSO to maintain and extend plateau production.  In particular, the development concepts for the Laverda and Catcher North oil accumulations have been selected and will comprise two development wells drilled from a common drill centre tied back to the Varadero manifold. Project sanction is targeted for Q1 2019.

In addition, potential infill well locations targeting resources beyond the reach of the initial development wells have been identified with plans to acquire 4D seismic to help define future infill drilling locations.   One of the new blocks awarded in the UK 30th Offshore Licensing Round lies to the South of the Catcher field and contains the Bonneville discovery, a potential future tie-back to the Catcher Area.

Kraken

Average gross production in the six months to June 2018, which includes the impact of the planned maintenance shutdown in March, was slightly below expectations at ~30,700 bopd. The production level in H1 was impacted by both planned and unplanned production downtime, watercut development slightly higher than expectations and not fully maintaining reservoir voidage due to restricted availability of water injection in the period.  

 

Following completion of the required filter maintenance, water injection rates increased significantly and gross production has improved, reaching levels of 35,000 - 40,000 bopd in August and FPSO performance has stabilised.

 

Since first production, more than ten million barrels of oil have been produced and 20 cargoes lifted, with 16 in 2018, of which five were for Cairn. Demand for cargoes continues to be strong and pricing relative to Brent is in line with expectations.

 

The DC4 manifold is in position and flowlines have been installed in Q3. The drilling programme is now expected to commence in late September, following a rig contract re-negotiation the Transocean Leader drilling rig is scheduled to relocate from a third-party exploration well.

 

First production from DC4 is expected in early 2019. Additional potential in the Kraken area is being reviewed for further possible drilling options in 2019 - 2020.

 

Developments

Senegal - SNE

The SNE field covers a large area of ~350km2 and has two distinct horizons with a stacked series of S400 upper reservoirs overlying S500 lower reservoirs. It is proposed that the SNE field will be developed in a series of phases with the first phase principally targeting the S500 resource with up to 26 subsea oil production, water injection and gas injection wells tied back to an FPSO. The FPSO, with proposed ~100,000 bopd production capacity, will be located towards the eastern edge of the SNE field in ~800m water depth. 

 

The subsea facilities will be designed to expand to accommodate future phases of SNE development, as well as providing a hub for developing other oil discoveries on the block.  First oil is targeted in 2022, with an expectation of up to ~40,000 bopd production net to Cairn on plateau.

 

In H1 there has been ongoing progress in the delivery of key milestones for the field development plan: the Evaluation Report outlining the basis of commerciality of the project was submitted to the Government in July; the tender responses for the FPSO facility and supporting subsea infrastructure have been received and are under evaluation and short-listing ahead of FEED planned for Q4; in parallel with the detailed engineering work, an Environmental and Social Impact assessment study has been submitted and detailed work is underway on the project financing.

 

The JV is targeting submission and approval of the Development and Exploitation Plan in H2, this will outline the full multi-phase development plans and options, including a detailed definition of the first phase. At the same time, TOO to Woodside is planned in Q4 this year with FID expected to follow in 2019. 

 

Cairn (Operator) has a 40% WI in three blocks offshore Senegal (Sangomar Deep, Sangomar Offshore and Rufisque Offshore) alongside partners, Woodside 35% WI, FAR Ltd 15% WI and the Senegal National Oil Company, Petrosen 10% WI (Petrosen has the right to increase its equity to 18% on development).

 

Nova

In H1, the Operator (Wintershall) awarded contracts for the rig as well as the subsea production systems, subsea umbilicals, risers and flowlines and host topsides modification, which allowed the project to progress towards the execution phase and submit the PDO to the Norwegian Ministry of Petroleum and Energy.  Nova will be developed as a subsea tie-back connecting two templates to the nearby Gjøa platform for processing and export.  Gjøa will also provide lift gas to the field and water injection for pressure support.  Power for the Nova field comes via the Gjøa platform from shore.  The Operator awarded a rig contract to Seadrill, which will operate the West Mira drilling rig and drill six subsea wells on the field commencing in H1 2020 to deliver first oil in 2021. 

 

Total investment in the Nova development is estimated to be ~US$1.2 billion (gross). Expanded debt funding from Cairn's existing RBL facility is expected to be available to fund the development.  Nova is anticipated to deliver plateau production of 50,000 bopd (10,000 bopd net to Cairn).

 

International Exploration

In Mexico, where Cairn now holds three licences, we opened an office in Mexico City in H1 and  established a local team as plans progress for the first two exploration wells on Block 9 (Cairn Operator, 65% WI) and an initial one exploration well on Block 7 (Cairn 35% WI, ENI Operator) in H2 2019. These licences provide an exciting opportunity to build a portfolio over time in this highly prolific, yet under-explored region.

 

A rig tendering process is underway along with the approval process to commence operations, and Exploration Plans have been submitted to the Government of Mexico.  Following approvals, the four year period of each licence will commence.  Blocks 7 and 9 cover an area of ~1,200km2 and are located in shallow water Gulf of Mexico, directly analogous to recent world class discoveries. 

 

Cairn was delighted to secure a third licence interest in the Mexico offshore bid round in H1 2018.  The Operated licence (50% WI) with Citla as partner is on Block 15 in the shallow water Tampico-Misantla Basin, located north-west of Cairn's existing interests. At this early stage, there is a commitment to purchase 3D seismic information on the block.  Environmental baseline survey plans are in progress.

 

In Ireland, Cairn has an acreage position in the Porcupine Basin with an interest in five licences over an area of more than 4,000km2.  In H1, activity focused on processing the large 3D seismic data set acquired in 2017 and developing a lead and prospect inventory across LO 16/19 (Cairn 70% WI, Operatorship) and the adjacent LO 16/18. 

 

In Suriname, a frontier area with multiple wells currently drilling in the region, Cairn was awarded an operated exploration agreement (Cairn 100% WI) by Staatsolie on the largest offshore block.  The licence covers an area of ~13,000 km2 in the Demerara plateau in the Guyana-Suriname basin which has a conjugate margin to the SNE field in Senegal. Cairn has an initial 2D seismic acquisition commitment with 4,150km planned for Q4 2018. 

 

In Côte d'Ivoire, Cairn has entered into the continental rift play with Tullow Oil.  Cairn has agreed a farm-in for a 30% interest in all seven of Tullow's onshore licences (CI -301, CI-302, CI-518, CI-519, CI-520, CI-521 and CI-522), subject to obtaining the necessary Government approvals. Tullow completed a full tensor gravity gradiometry survey covering 8,600 km2 in H1 and this data is currently being interpreted and will be used to optimise the location for a 2D seismic survey planned for 2019.

 

In Mauritania, Cairn has an option agreement with Total to enter block C7, targeting a turbidite fan play in a large offshore exploration block in a proven oil province.  Cairn has a right to acquire a 30% WI (Total Operator, 60% WI and Societé Mauritanienne des Hydrocarbures, 10% WI), upon a well decision following completion of the ~7,000km2 seismic programme for which acquisition, processing and interpretation in ongoing. The transaction is subject to Government and partner approvals.

 

UK & Norway Exploration

The UK & Norway is a core region for Cairn and the company has built a strong position with a balanced portfolio of exploration and production assets. Cairn has qualified as an Operator in both the UK and Norway and has a material exploration drilling campaign currently underway with up to ten wells planned across a variety of plays in 2018-19, subject to partner approval.

 

Two exploration wells were completed in H1: PL682 containing the Tethys prospect close to the Gjøa field in the Norwegian North Sea made a minor oil discovery but this was deemed as non-commercial; and the wildcat well on PL790 close to the Knarr field also in the Norwegian North Sea containing the Raudåsen prospect was classified as dry with only traces of petroleum.

 

Cairn is currently operating a well on P2184, targeting the Ekland prospect which is the Company's first operated well in the UK North Sea. Ekland is within an established play and the primary well objective is the Triassic Skagerrak sandstones and secondary objective is the Upper Jurassic Fulmar sandstones. The well is being drilled by the Ensco 101 and operations are expected to complete shortly.

 

Cairn farmed into the P1763 licence in the UK North Sea with Azinor Catalyst in H1. Cairn joins Azinor Catalyst for 50% of the sole risk drilling activity on the Agar discovery and Plantain prospect and 25% of the wider licence with existing partners.  Agar and Plantain have estimated combined mid-case resources of 60 million barrels of oil equivalent (mmboe), with an upside case of 98 mmboe.  The exploration well is currently drilling with the Transocean Leader semi-submersible. Cairn has the option to take over Operatorship with respect to the Agar Plantain project.   

 

In Q4, Cairn expects the Stjerneskudd well (Cairn 30% WI) to spud on PL885 in the Norwegian Sea with Equinor as Operator.  Stjerneskudd represents a material prospect of more than 100 mmboe gross with stand-alone potential and significant follow on opportunity in the event of success. 

 

Cairn participated in five applications in the UK 30th Licence Round and in H1 was offered all five licences (three as operator and two as non-operator), incorporating most of the prospectivity we had identified prior to bidding. 

 

In 2019, Cairn will continue an exploration campaign across the UK & Norway region with a potential further three to four wells targeting material prospects with significant equity interests.

 

India

The final arbitration hearings were held in August in The Hague and involved testimony by expert and fact witnesses and addressed Cairn's claims under the UK-India Bilateral Investment Treaty, India's defences and issues of jurisdiction.

 

The IITD has continued to enforce its retrospective tax claim against Cairn whilst the Treaty arbitration has been ongoing. To date the IITD has seized dividends due to Cairn from its shareholding in VL totalling approximately US$162m and it has offset a tax rebate of US$234m due to Cairn as a result of overpayment of capital gains tax on a separate matter. During the period, the IITD seized proceeds from a ~2% sale of Cairn's shareholding in VL, realising US$231m.  Subsequent to H1, a further ~1% shares were sold. Following these sales, Cairn's retained holding in VL is now ~2%. 

 

The reparation sought by Cairn in the arbitration is the monetary value required to restore Cairn to the position it would have enjoyed in 2014 but for the Government of India's actions in breach of the Treaty.  Accordingly, the status of Cairn's assets seized in India does not affect the merits of Cairn's claims, the amount of relief sought, or the enforceability of the arbitral award.

 

The Arbitral Tribunal is expected to issue a binding and internationally-enforceable award, the drafting and issuance of such an award typically takes several months.  In this case, taking into account the delays already suffered by Cairn, the Tribunal has stated that it will endeavour to issue its award as expeditiously as possible.  Cairn continues to have a high level of confidence in the merits of its claims in the arbitration. Cairn is seeking full restitution for losses totalling more than US$1.4bn resulting from India's expropriation of its investments in India in 2014, and India's unfair and inequitable treatment of those investments, due to the imposition of retrospective tax measures.

 

 

Financial Review

Key Statistics

 

H1 2018

Production - net WI share (boepd)1

14,377

Production - net WI share, post FlowStream (boepd) 2

12,995

Sales volumes (boepd)3

14,205

Average price per boe (US$)3

66.97

Revenue from production (US$m)

172.1

Average production costs per boe (US$)1

24.30

Depletion and amortisation costs per boe (US$)

25.29

Cash generated from oil and gas production (US$m)4

94.1

Net cash inflow from oil and gas production

57.3

Net cash inflow from operating activities

30.7

1 Production volumes and costs per boe based on Kraken WI share of 29.5%, Catcher WI 20%

2 Production volumes and costs per boe based on Kraken WI share post FlowStream of 25%, Catcher WI 20%

3 Sales and revenue per boe based on Kraken WI share of 25%, Catcher WI 20%

4 gross profit less deferred revenue, royalty income and depletion and amortisation

 

Production

Production from Kraken commenced in June 2017 and Catcher came on stream in late December 2017.  During H1 2018, daily production volumes on both assets have increased significantly.  Kraken is currently producing up to 40,000 boepd gross with Catcher operating up to 60,000 boepd gross. Combined production for the remainder of 2018 is expected to average 20,500 - 22,000 beopd net to Cairn (18,500 - 20,000 boepd net excluding FlowStream entitlement).

Revenue

Revenue from the sale of oil and gas was US$172.1m to June 2018, after adjusting for hedging transactions.  Release of deferred revenue of US$9.6m and royalty income in Mongolia of US$0.7m, increased total revenue to US$182.4m.

At 30 June, Cairn had hedged ~2.8 mmbbls of forecast production through to September 2019 using collar structures with a weighted average floor of US$61.6 per bbl and an average ceiling of US$75.9 per bbl. 

Cost of sales

Total production costs of US$63.2m include US$32.3m of operating and variable lease payments on the Catcher and Kraken FPSOs respectively.  All Kraken FPSO lease payments were classified as variable lease payments in the period.  Movements in oil inventory and overlift/underlift positions, measured at market value, of US$14.8m were charged against cost of sales in the period.  The Group's accounting for revenue and the classification and measurement of overlift/underlift is unaffected by the implementation of IFRS 15.

 

Net cash inflow from operating activities and cash generated from oil and gas production

Net cash inflow from operating activities for the period of US$30.7m reflects net cash generated from oil and gas sales after deducting administrative costs.  Adding back these expenses leads to a net cash inflow from oil and gas production of US$57.3m which, after adjusting for timing differences in working capital through trade receivables and inventory, overlift and underlift movements, represents underlying cash generated from operations of US$94.1m in the first half of 2018. 

Net cash outflow for the Period

 

               US$m

Opening cash at 1 January 2018

86.5

 

 

Net cash inflow from operations

57.3

Pre-award costs

(11.2)

Exploration expenditure

(73.5)

Development expenditure

(61.0)

Administration expenses, finance costs and equity transactions

(19.2)

Drawings under Exploration Finance Facility

29.4

Foreign exchange movements

1.5

 

 

Closing net cash and long-term borrowings at 30 June 2018

9.8

 

Cairn had net cash of US$9.8m at 30 June 2018, representing a net cash outflow of US$76.7m over the six month period.  Borrowings under the Group's RBL facility at 30 June 2018 were US$65.0m, all drawn in the period, before adjusting for unamortised facility fees and accrued interest. Closing net cash and long-term borrowings presented above exclude US$58.6m drawn under the Norwegian Exploration Finance Facility. This working capital advance is secured against tax refunds due from the Norwegian government within the next 18 months, and do not reflect the Group's current long-term indebtedness.

Cairn agreed an extension of the Group's US$575.0m RBL facility to June 2025, increasing the borrowing base to include the planned production of the Nova asset in Norway.  The terms of the extended facility are consistent with that of the original.  Under IFRS 9 the extension will be accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability due to the extended period over which the facility is available.  The accounts disclosure includes all amounts drawn under the RBL facility as short-term debt.

Cash outflows on exploration expenditure in the period included UK & Norway costs of US$31.8m relating to the Tethys and Raudåsen wells in Norway and pre-development activities on the Nova asset. 

Development cash outflows in the period related to costs on Kraken and Catcher. 

 

Capital expenditure on Oil and Gas Assets

 

               US$m

Opening oil and gas assets at 1 January 2018

1,825.9

 

 

Exploration and appraisal additions

 

Senegal

12.1

UK & Norway

44.8

International

7.7

Development additions

 

UK & Norway

9.3

 

 

Unsuccessful exploration costs - UK & Norway

(45.9)

Depletion and amortisation - UK & Norway

(65.7)

Other movements

(6.8)

Foreign exchange movements

1.4

 

 

Closing oil and gas assets at 30 June 2018

1,782.8

 

Exploration and appraisal asset additions in Senegal reflect the continuing work on the Development and Exploitation plan and TOO of the licence to Woodside.  In the UK & Norway costs incurred in the year on the Tethys and Raudåsen wells were US$22.5m with a further US$22.3m of additions across remaining licences in the portfolio.  This includes US$10.9m of the Nova field where formal approval of the development plan by the Norwegian authorities is awaited.   

Development additions in the period totalling US$9.3m include the release of accruals for rig costs relating to Kraken of US$22.7m following renegotiation to the rig contract. 

At the half year, Cairn has reviewed its exploration/appraisal and development/producing assets for indicators of impairment and performed impairment tests where indicators were identified.  No impairment arose from any of the tests performed.  Impairment tests will be re-run at the year end to reflect a further six months production history and anticipated well testing on Kraken. The Group's long-term oil price assumption remains unchanged at US$70 per barrel.

 

 

 

 

 

Results for the period - Other operating income and expense

Other operating income and costs, administrative expenses and net finance costs

 

Period ended

30 June

2018

US$m

Period ended

30 June

2017

US$m

Year ended

31 December 2017

US$m

 

 

 

 

Pre-award costs

(12.0)

(33.8)

(43.8)

Unsuccessful exploration costs

(46.8)

(15.2)

(60.7)

Administrative expenses and other income/costs

(14.4)

(13.5)

(30.3)

Related tax credits

30.6

25.0

30.4

Operational and administrative expenses

(42.6)

(37.5)

(104.4)

 

 

 

 

Net finance (costs)/income, excl. dividends

(18.2)

14.9

14.2

 

Pre-award costs reflect the increase in Cairn's portfolio of assets, with further acreage added in the UK & Norway and new country entries in Cote D'Ivoire and Suriname.

Unsuccessful exploration costs, primarily relating to the UK & Norway region, include costs written off on Tethys and Raudåsen of US$34.9m and US$11.9m on other licences relinquished or where no further exploration activities are planned.

Administrative costs remain consistent year-on-year and include US$3.2m of costs in preparation for the Indian Tax arbitration.

Finance costs in the period include exchange losses and facility fees on the Group's RBL facility.  Exchange gains in 2017 drive the additional year-on-year change. 

Related tax credits reflect Norwegian current tax refunds receivable on qualifying exploration and administrative expenses.

Gains and losses on Financial Asset - Investment in Vedanta Limited

The sale of shares in the period results in a loss on derecognition of US$230.8m following seizure of the proceeds by the IITD. Cairn held a ~3% shareholding in VL, with a value of US$522.0m at 30 June 2018. Sales subsequent to the balance sheet date, as disclosed in the post balance sheet event note 6.1, reduce this holding to ~2%.   

Dividends declared by VL and due to Cairn in the period of US$64.5m were also seized by the IITD are not recorded in the results for the period.  Total dividends now seized by the IITD are US$161.9m.

Following the adoption of IFRS 9 "Financial Instruments" Cairn's financial asset is now classified as a financial asset at fair value through profit or loss and therefore all periodic fair value gains and losses are reflected through the Income Statement rather than other comprehensive income.  In the current period, a fall in the market value of Vedanta has resulted in a US$319.4m charge to the Income Statement. Comparative results, including a 2017 full year gain of US$449.1m, have been restated to reflect adoption of the new standard.

Taxation

With a full six months of production on both the Group's UK producing assets, Cairn made a UK ring fence profit in the period which was fully offset by brought forward losses. At 30 June 2018, Cairn had total UK ring fence losses of US$980.0m. US$818.8m of losses are recognised as deferred tax assets (at the applicable UK tax rate of 40%) to fully offset deferred tax liabilities of US$327.5m. The remaining US$161.2m of losses together with the deferred tax impact of the decommissioning liability represent an unrecognised deferred tax asset of US$111.2m at 30 June 2018.  Probable future profits, based on low-case production sensitivities do no support the recognition of a deferred tax asset at this time.

A cash tax refund is receivable in Norway in respect of 78% of qualifying exploration and overhead spend. US$24.4m of tax credits are recorded for amounts receivable relating to the current period.  Norwegian deferred tax liabilities at 30 June 2018 of US$67.2m reflect timing differences on the carrying value of exploration assets where either a tax refund has been claimed or an uplift is available on capital spend.

The sale of part of the Group's interest in VL, instructed by the IITD, has not led to a taxable capital gain either in India or the UK at the price range achieved.  The reduction in the VL shareholding, together with movements in the share price have led to a US$69.1m reduction in the deferred tax liability in respect of the shareholding at 30 June 2018.  The remaining deferred tax liability in India of US$20.3m predominantly relates to the Vedanta preference shares held at the Balance Sheet date which are due for redemption in October this year.

 

 

 

 

Contents

 

Group Income Statement

 

Group Statement of Comprehensive Income

 

Group Balance Sheet

 

Group Statement of Cash Flows

 

Group Statement of Changes in Equity

 

 

 

Section 1 - Basis of Preparation

 

1.1 Accounting Policies

 

1.2 Going Concern

1.3 Restatement of Comparative Financial Statements

 

 

 

Section 2 - Oil and Gas Assets

 

2.1 Intangible Exploration/Appraisal Assets

 

2.2 Property, Plant & Equipment - Development/Producing Assets

 

2.3 Capital Commitments

 

 

 

Section 3 -  Other Assets and Liabilities: Financial Assets, Cash and Borrowings, Lease liabilities and Working Capital

3.1 Financial Asset at Fair Value through Profit or Loss

 

3.2 Cash and Cash Equivalents

 

3.3 Loans and Borrowings

 

3.4 Finance Lease Liabilities

 

3.5 Trade and Other Receivables

 

3.6 Trade and Other Payables

 

3.7 Deferred Revenue

 

 

 

Section 4 - Results for the Period

 

4.1 Segmental Analysis

 

4.2 Revenue and Cost of Sales

 

4.3 Finance Costs

 

4.4 Earnings per Ordinary Share

 

 

 

Section 5 - Taxation

 

5.1 Tax Credit on Loss for the Period

 

5.2 Income Tax Asset

 

5.3 Deferred Tax Assets and Liabilities

 

5.4 Contingent Liability - Indian Tax Assessment

 

 

 

Section 6 - Other Disclosures

 

6.1 Post Balance Sheet Events

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cairn Energy PLC    

Group Income Statement

For the six months ended 30 June 2018

 

Note

Six months ended 30 June 2018

(unaudited)

US$m

Six months ended 30 June 2017

(unaudited)

 (restated)

US$m

Year ended

 31 December 2017

(audited)

(restated)

US$m

 

 

 

 

 

Continuing operations

 

 

 

 

 

 

 

 

 

Revenue

4.2

182.4

10.8

33.3

 

 

 

 

 

Cost of sales

4.2

(78.0)

(0.4)

(5.9)

Depletion and amortisation

2.2

(65.7)

(0.3)

(20.8)

 

 

 

 

 

Gross profit

 

38.7

10.1

6.6

 

 

 

 

 

Pre-award costs

 

(12.0)

(33.8)

(43.8)

Unsuccessful exploration costs

2.1

(46.8)

(15.2)

(60.7)

Loss on disposal of intangible exploration/appraisal assets

 

(4.5)

-

-

Other operating income

 

5.0

1.4

2.4

Administrative expenses

 

(14.9)

(14.9)

(32.7)

Reversal of impairment of property, plant & equipment -  development/producing assets

2.2

-

-

23.0

 

 

 

 

 

Operating loss

 

(34.5)

(52.4)

(105.2)

 

 

 

 

 

Loss on derecognition of financial assets

3.1

(230.8)

(33.0)

(33.0)

(Loss)/gain on fair value of financial assets

3.1

(319.4)

200.5

449.1

Finance income

 

5.9

70.9

77.0

Exceptional provision against finance income receivable

 

-

(104.7)

(104.7)

Finance costs

4.3

(24.1)

(3.6)

(10.4)

 

 

 

 

 

(Loss)/profit before taxation from continuing operations

 

(602.9)

77.7

272.8

 

 

 

 

 

Tax credit/(charge)

5.1

102.4

(6.8)

(55.0)

 

(Loss)/profit for the period attributable to equity holders of the parent

 

(500.5)

70.9

217.8

 

 

 

 

 

(Loss)/profit per ordinary share - basic (cents)

4.4

(86.20)

12.31

37.72

(Loss)/profit per ordinary share - diluted (cents)

4.4

(86.20)

12.11

36.84

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cairn Energy PLC    

Group Statement of Comprehensive Income

For the six months ended 30 June 2018

 

 

Six months ended

 30 June 2018

(unaudited)

US$m

Six months ended

 30 June

2017

(unaudited)

(restated)

US$m

Year ended

 31 December 2017

(audited)

(restated)

US$m

 

 

 

 

 

 

(Loss)/profit for the period

 

(500.5)

70.9

217.8

 

 

 

 

 

Other comprehensive income - items that may be recycled to the income statement

 

 

 

 

Fair value on hedge options

 

(13.4)

-

(2.9)

Currency translation differences

 

(0.8)

40.1

76.1

 

Other comprehensive income for the period

 

(14.2)

40.1

73.2

 

 

 

 

 

Total comprehensive income for the period attributable to equity holders of the parent

 

(514.7)

111.0

291.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cairn Energy PLC

Group Balance Sheet

 As at 30 June 2018

 

 

30 June

2018

(unaudited)

30 June

2017

(unaudited)

(restated)

31 December 2017

(audited)

(restated)

 

Note

US$m

US$m

US$m

Non-current assets

 

 

 

 

Intangible exploration/appraisal assets

2.1

632.7

560.8

619.4

Property, plant & equipment - development/producing assets

2.2

1,150.1

1,070.3

1,206.5

Intangible assets - goodwill

 

128.6

124.6

128.2

Other property, plant & equipment and intangible assets

 

9.3

2.8

10.8

Financial asset at fair value through profit or loss

3.1

-

823.6

1,072.2

 

 

 

1,920.7

2,582.1

3,037.1

 

Current assets

 

 

 

 

Financial asset at fair value through profit or loss

3.1

522.0

-

-

Cash and cash equivalents

3.2

74.8

253.7

86.5

Trade and other receivables

3.5

132.3

129.3

83.1

Inventory

 

9.1

0.3

10.4

Income tax asset

5.2

62.2

54.9

38.4

 

 

 

800.4

438.2

218.4

 

Total assets

 

2,721.1

3,020.3

3,255.5

 

 

 

 

 

Current liabilities

 

 

 

 

Loans and borrowings

3.3

92.9

21.7

29.8

Finance lease liabilities

3.4

5.1

17.1

1.5

Trade and other payables

3.6

168.3

212.8

199.2

Deferred revenue

3.7

21.5

28.7

24.3

Provisions - other

 

2.8

-

2.8

 

 

 

290.6

280.3

257.6

 

 

 

 

 

Non-current liabilities

 

 

 

 

Loans and borrowings

3.3

28.3

-

-

Finance lease liabilities

3.4

169.8

183.1

168.2

Deferred revenue

3.7

42.9

45.5

49.7

Deferred tax liabilities

5.3

87.5

102.6

164.4

Provisions - decommissioning

 

121.0

98.6

121.1

Provisions - other

 

-

2.7

-

 

 

 

449.5

432.5

503.4

 

Total liabilities

 

740.1

712.8

761.0

 

Net assets

 

1,981.0

2,307.5

2,494.5

 

 

 

 

 

Equity attributable to equity holders of the parent

 

 

 

 

Called-up share capital

 

12.6

12.5

12.5

Share premium

 

489.5

488.0

488.0

Shares held by ESOP/SIP Trusts

 

(15.7)

(10.9)

(10.2)

Foreign currency translation

 

(175.7)

(210.0)

(174.9)

Capital reserves - non-distributable

 

40.8

40.8

40.8

Merger reserve

 

255.9

255.9

255.9

Hedge reserve

 

(16.3)

-

(2.9)

Retained earnings

 

1,389.9

1,731.2

1,885.3

 

Total equity

 

1,981.0

2,307.5

2,494.5

 

Cairn Energy PLC

Group Statement of Cash Flows

For the six months ended 30 June 2018

 

 

 

Six months ended 30 June 2018

(unaudited)

US$m

Six months ended 30 June 2017

(unaudited)

 (restated)

US$m

Year ended

 31 December 2017

(audited)

(restated)

US$m

Cash flows from operating activities 

 

 

 

 

(Loss)/profit before taxation from continuing operations

(602.9)

77.7

272.8

 

 

 

 

Unsuccessful exploration costs

46.8

15.2

60.7

Depreciation, depletion and amortisation

67.5

0.8

23.4

Share-based payments charge

8.5

10.4

17.5

Reversal of impairment of property, plant & equipment -  development/producing assets

-

-

(23.0)

Loss on derecognition of financial assets

230.8

33.0

33.0

Loss/(gain) on fair value of financial assets

319.4

(200.5)

(449.1)

Loss on disposal of intangible exploration/appraisal assets

4.5

-

-

Finance income

(5.9)

(70.9)

(77.0)

Exceptional provision against finance income receivable

-

104.7

104.7

Finance costs

24.1

3.6

10.4

Interest paid

(2.4)

(0.2)

(0.6)

Income tax received from operating activities

-

-

2.8

Movement on inventory

1.3

-

(10.4)

Trade and other receivables movement

(66.4)

(17.2)

(10.5)

Trade and other payables movement

5.4

10.8

(0.5)

Deferred revenue received

-

74.6

74.6

 

Net cash inflows from operating activities

30.7

42.0

28.8

 

 

 

 

Cash flows from investing activities

 

 

 

Expenditure on intangible exploration/appraisal assets

(73.5)

(68.9)

(186.6)

Expenditure on property, plant & equipment -  development/producing assets

(61.0)

(71.0)

(145.6)

Income tax received from investing activities

-

-

27.6

Purchase of other property, plant & equipment and intangible assets

(0.8)

(4.7)

(7.9)

Interest received and other finance income

0.6

4.2

15.3

 

Net cash used in investing activities

(134.7)

(140.4)

(297.2)

 

 

 

 

Cash flows from financing activities

 

 

 

Facility fees, arrangement fees and bank charges

(4.3)

(2.8)

(8.3)

Proceeds from borrowings

94.4

21.7

29.2

Cost of shares purchased

(3.7)

(3.8)

(3.9)

Shares issued for cash

1.6

-

-

Finance lease reimbursement

2.8

-

1.4

 

 

 

 

Net cash inflows from financing activities

90.8

15.1

18.4

 

 

 

 

Net decrease in cash and cash equivalents

(13.2)

(83.3)

(250.0)

Opening cash and cash equivalents at beginning of period

86.5

334.9

334.9

Foreign exchange differences

1.5

2.1

1.6

 

Closing cash and cash equivalents (note 3.2)

74.8

253.7

86.5

 

 

 

 

 

 

Cairn Energy PLC

Group Statement of Changes in Equity

For the six months ended 30 June 2018

 

 

 Equity share  capital and share premium

 Shares held by ESOP/ SIP Trust

 Foreign currency translation

 Merger and capital reserves

Hedge reserves

(restated)

Retained earnings

(restated)

 Total equity

 

 US$m

US$m

US$m

US$m

 US$m

 US$m

US$m

 

 

 

 

 

 

 

 

At 1 January 2017

500.4

(10.2)

(250.1)

296.7

-

1,653.1

2,189.9

 

 

 

 

 

 

 

 

Profit for the year

-

-

-

-

-

217.8

217.8

Fair value on hedge options

-

-

-

-

(2.9)

-

(2.9)

Currency translation differences recycled on disposal of subsidiary

-

-

(0.9)

-

-

0.9

-

Currency translation differences

-

-

76.1

-

-

-

76.1

 

Total comprehensive income

-

-

75.2

-

(2.9)

218.7

291.0

Share-based payments

-

-

-

-

-

17.5

17.5

Shares issued for cash

0.1

(0.1)

-

-

-

-

-

Cost of shares purchased

-

(3.9)

-

-

-

-

(3.9)

Cost of shares vesting

-

4.0

-

-

-

(4.0)

-

 

At 31 December 2017

500.5

(10.2)

(174.9)

296.7

(2.9)

1,885.3

2,494.5

 

 

 

 

 

 

 

 

Loss for the period

-

-

-

-

-

(500.5)

(500.5)

Fair value on hedge options

-

-

-

-

(13.4)

-

(13.4)

Currency translation differences

-

-

(0.8)

-

-

-

(0.8)

 

Total comprehensive income

-

-

(0.8)

-

(13.4)

(500.5)

(514.7)

Share-based payments

-

-

-

-

-

8.5

8.5

Shares issued for cash

1.6

-

-

-

-

-

1.6

Cost of shares purchased

-

(8.9)

-

-

-

-

(8.9)

Cost of shares vesting

-

3.4

-

-

-

(3.4)

-

 

At 30 June 2018

502.1

(15.7)

(175.7)

296.7

(16.3)

1,389.9

1,981.0

 

 

For the six months ended 30 June 2017

 

 

 Equity share  capital and share premium

 Shares held by ESOP/ SIP Trust

 Foreign currency translation

 Merger and capital reserves

Retained earnings

(restated)

 Total equity

 

 US$m

US$m

US$m

US$m

 US$m

US$m

 

 

 

 

 

 

 

At 1 January 2017

500.4

(10.2)

(250.1)

296.7

1,653.1

2,189.9

 

 

 

 

 

 

 

Profit for the period

-

-

-

-

70.9

70.9

Currency translation differences

-

-

40.1

-

-

40.1

 

Total comprehensive income

-

-

40.1

-

70.9

111.0

Share-based payments

-

-

-

-

10.4

10.4

Shares issued for cash

0.1

(0.1)

-

-

-

-

Cost of shares purchased

-

(3.8)

-

-

-

(3.8)

Cost of shares vesting

-

3.2

-

-

(3.2)

-

 

At 30 June 2017

500.5

(10.9)

(210.0)

296.7

1,731.2

2,307.5

 

 

 

 

Section 1 - Basis of Preparation

 

1.1     Accounting Policies 

 

Basis of preparation

 

The half-yearly condensed consolidated financial statements for the six months ended 30 June 2018 have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority and with IAS 34, 'Interim financial reporting', as adopted by the European Union. They should be read in conjunction with the annual financial statements for the year ended 31 December 2017, which have been prepared in accordance with International Financial Reporting Standards ('IFRSs') as adopted by the European Union.

 

This half-yearly report was approved by the Directors on 10 September 2018.

 

The disclosed figures, which have been reviewed but not audited, are not statutory accounts in terms of Section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2017, on which the auditors gave an unqualified audit report, which did not contain an emphasis of matter paragraph or any statement under section 498 of the Companies Act 2006, have been filed with the Registrar of Companies. 

 

This half-yearly report has been prepared on a basis consistent with the accounting policies expected to be applied for the year ending 31 December 2018, and uses the same accounting and financial risk management policies and methods of computation as those applied for the year ended 31 December 2017, other than changes to accounting policies resulting from the adoption of new or revised accounting standards. 

 

Adoption of IFRS 9 "Financial Instruments" on 1 January 2018 has resulted in re-classification of the Group's available-for-sale financial asset as a financial asset held at fair value through profit or loss.  Fair value gains and losses on the financial asset are now reflected through the Income Statement rather than Other Comprehensive Income.  IFRS 9 also requires the change in fair value relating to the time value of an option, designated for hedge accounting, to be recorded in Other Comprehensive Income, whereas previously Cairn had recorded such movements through the Income Statement.    Both these changes have resulted in the restatement of comparative information, details of which can be found in note 1.3.  Audited comparative information for the year ended 31 December 2017 has been restated, though the restatement itself has yet to be audited which will be done in conjunction with the audit of the Group's 31 December 2018 financial statements. 

 

Comparative information to June 2017 has also been restated to reflect the expected timing of the release of the deferred revenue provision between less than and greater than one year.  Previously this was classified wholly within one year.  December 2017 comparative information is unaffected.

 

Other changes to IFRS effective 1 January 2018, including the adoption of IFRS 15 "Revenue from Contracts with Customers", have no significant impact on Cairn's accounting policies or financial statements.

 

Changes to accounting policies and the impact on financial statements resulting from new accounting standards and amendments to existing standards that have been issued, but are not yet effective, including IFRS 16 "Leases" are currently being assessed.  The most significant change under IFRS 16, shall be Cairn's interests in the Catcher FPSO being recorded as a right-of-use asset with a corresponding lease liability being the present value of future minimum payments, estimated to be US$163.0m had IFRS 16 been implemented at the Balance Sheet date.  Currently the Catcher FPSO is accounted for as an operating lease, with all costs being charged directly to the Income Statement. 

 

Significant key estimates and assumptions are unchanged from those applied in the year ended 31 December 2017 and the same have accordingly been applied here, other than a change of functional currency of the Group's subsidiary undertaking Nautical Petroleum Limited, which holds the Group's interests in the UK Catcher and Kraken producing assets.  The functional currency of the subsidiary has been changed with effect from 1 January 2018 from GB£ to US$, reflecting the significant revenue streams now being received by the entity.

 

 

1.2     Going Concern

 

The directors have considered the factors relevant to support a statement of going concern. 

 

In assessing whether the going concern assumption is appropriate, the Board considered the Group cash flow forecasts under various scenarios, identifying risks and mitigating factors and ensuring the Group has sufficient funding to meet its current and contracted commitments as and when they fall due for a period of at least 12 months from the date of signing these financial statements.

 

The directors have a reasonable expectation that the Group will continue in operational existence for this 12-month period and have therefore used the going concern basis in preparing the financial statements. 

 

 

 

 

 

 

 

Section 1 - Basis of Preparation (continued)

 

1.3     Restatement of Comparative Financial Statements on adoption of IFRS 9

 

Six months ended 30 June 2017

Issued

Financial Statements

IFRS 9 restatement - Financial asset

IFRS 9 restatement - hedge option

Restated

June

2017

 

US$m

US$m

US$m

US$m

Income Statement

 

 

 

 

Net gain/(loss) on derecognition of financial asset

402.6

(435.6)

-

(33.0)

Gain on fair value of financial assets

-

200.5

-

200.5

Profit before taxation from continuing operations

312.8

(235.1)

-

77.7

Tax credit/(charge)

1.2

(8.0)

-

(6.8)

Profit for the period attributable to equity holders of the parent

314.0

(243.1)

-

70.9

Profit per ordinary shares - basic (cents)

54.49

(42.18)

-

12.31

Profit per ordinary shares - diluted (cents)

53.62

(41.51)

-

12.11

 

 

 

 

 

Group Statement of Comprehensive Income

 

 

 

 

Profit for the period

314.0

(243.1)

-

70.9

Surplus on valuation of financial assets

200.5

(200.5)

-

-

Deferred tax charge on valuation of financial assets

(42.8)

42.8

-

-

Surplus on valuation recycled to the Income Statement

(435.6)

435.6

-

-

Deferred tax charge on surplus on valuation recycled to the Income Statement

34.8

(34.8)

-

-

Other comprehensive (expense)/income for the period

(203.0)

243.1

-

40.1

Total comprehensive income for the period

111.0

-

-

111.0

 

 

 

 

 

Balance Sheet

 

 

 

 

Available-for-sale reserve

29.0

(29.0)

-

-

Retained earnings

1,702.2

29.0

-

1,731.2

Total equity

2,307.5

-

-

2,307.5

 

Year ended 31 December 2017

Issued Financial Statements

IFRS 9 restatement - Financial asset

IFRS 9 restatement - hedge option

Restated December 2017

 

US$m

US$m

US$m

US$m

Income Statement

 

 

 

 

Net gain/(loss) on derecognition of financial asset

402.6

(435.6)

-

(33.0)

Gain on fair value of financial assets

-

449.1

-

449.1

Finance costs

(13.3)

-

2.9

(10.4)

Profit before taxation from continuing operations

256.4

13.5

2.9

272.8

Tax credit/(charge)

6.7

(61.7)

-

(55.0)

Profit for the year attributable to equity holders of the parent

263.1

(48.2)

2.9

217.8

Profit per ordinary shares - basic (cents)

45.58

(8.37)

0.51

37.72

Profit per ordinary shares - diluted (cents)

44.52

(8.17)

0.49

36.84

 

 

 

 

 

Group Statement of Comprehensive Income

 

 

 

 

Profit for the year

263.1

(48.2)

2.9

217.8

Surplus on valuation of financial assets

449.1

(449.1)

-

-

Deferred tax charge on valuation of financial assets

(96.5)

96.5

-

-

Surplus on valuation recycled to the Income Statement

(435.6)

435.6

-

-

Deferred tax charge on surplus on valuation recycled to the Income Statement

34.8

(34.8)

-

-

Fair value on hedge options

-

-

(2.9)

(2.9)

Other comprehensive (expense)/income for the year

27.9

48.2

(2.9)

73.2

Total comprehensive income for the year

291.0

-

-

291.0

 

 

 

 

 

Balance Sheet

 

 

 

 

Hedge reserve

-

-

(2.9)

(2.9)

Available-for-sale reserve

223.9

(223.9)

-

-

Retained earnings

1,658.5

223.9

2.9

1,885.3

Total equity

2,494.5

-

-

2,494.5

 

 

Section 2 - Oil and Gas Assets

 

2.1     Intangible Exploration/Appraisal Assets

 

 

Senegal

 UK & Norway

International

Total

 

US$m

US$m

US$m

US$m

Cost

 

 

 

 

At 1 January 2017

330.3

172.6

32.7

535.6

Foreign exchange

-

7.7

0.5

8.2

Additions

77.3

10.5

11.5

99.3

Unsuccessful exploration costs

-

(3.5)

(11.7)

(15.2)

 

 

 

 

 

At 30 June 2017

407.6

187.3

33.0

627.9

Foreign exchange

-

4.3

0.2

4.5

Additions

26.9

23.2

51.6

101.7

Unsuccessful exploration costs

-

(4.6)

(47.4)

(52.0)

 

At 31 December 2017

434.5

210.2

37.4

682.1

Foreign exchange

-

1.4

-

1.4

Additions

12.1

44.8

7.7

64.6

Disposals

-

(5.9)

-

(5.9)

Unsuccessful exploration costs

-

(45.9)

(0.9)

(46.8)

 

At 30 June 2018

446.6

204.6

44.2

695.4

 

 

 

 

 

 

Impairment

 

 

 

 

At 1 January 2017

-

43.9

20.4

64.3

Foreign exchange

-

2.3

0.5

2.8

 

 

 

 

 

At 30 June 2017

-

46.2

20.9

67.1

Foreign exchange

-

1.9

0.2

2.1

Unsuccessful exploration costs

-

-

(6.5)

(6.5)

 

At 31 December 2017

-

48.1

14.6

62.7

 

 

 

 

 

At 30 June 2018

-

48.1

14.6

62.7

 

 

 

 

 

Net book value

 

 

 

 

At 30 June 2017

407.6

141.1

12.1

560.8

At 31 December 2017

434.5

162.1

22.8

619.4

At 30 June 2018

446.6

156.5

29.6

632.7

 

Additions in the current period in the UK & Norway region of US$44.8m, include US$22.5m of costs relating to the two exploration wells completed in the period on the Tethys and Raudåsen prospects and US$10.9m incurred on Nova pre-development activities.  Remaining additions of US$11.4m are spread across the remaining portfolio of assets in the region.

 

Unsuccessful exploration costs charged in the period include costs of the two wells above, neither of which were commercially successful, and further costs were written off licences which have either been relinquished or where no further exploration is planned.  

 

Impairment review

 

At 30 June 2018, Cairn reviewed its intangible exploration/appraisal assets for indicators of impairment and where indicators were identified, performed impairment tests.  No impairment was recorded.

  

 

Section 2 - Oil and Gas Assets (continued)

 

2.2     Property, Plant & Equipment - Development/Producing Assets 

 

 

UK & Norway

UK & Norway leased asset

Total

 

US$m

US$m

US$m

Cost

 

 

 

At 1 January 2017

756.1

-

756.1

Foreign exchange

44.8

3.3

48.1

Additions

87.5

200.8

288.3

 

 

 

 

At 30 June 2017

888.4

204.1

1,092.5

Foreign exchange

36.8

5.6

42.4

Additions

125.0

4.1

129.1

Re-measurement of leased assets  

-

(36.4)

(36.4)

 

 

 

 

At 31 December 2017

1,050.2

177.4

1,227.6

Additions

9.3

-

9.3

 

At 30 June 2018

1,059.5

177.4

1,236.9

 

 

 

 

Depletion, amortisation and impairment

 

 

 

At 1 January 2017

21.0

-

21.0

Foreign exchange

0.9

-

0.9

Depletion and amortisation

0.3

-

0.3

 

 

 

 

At 30 June 2017

22.2

-

22.2

Foreign exchange

1.3

0.1

1.4

Depletion and amortisation

17.1

3.4

20.5

Reversal of impairment

(23.0)

-

(23.0)

 

 

 

 

At 31 December 2017

17.6

3.5

21.1

Depletion and amortisation

57.8

7.9

65.7

 

 

 

 

At 30 June 2018

75.4

11.4

86.8

 

 

 

 

Net book value

 

 

 

At 30 June 2017

866.2

204.1

1,070.3

At 31 December 2017

1,032.6

173.9

1,206.5

At 30 June 2018

984.1

166.0

1,150.1

 

Additions during the period of US$9.3m include the release of accruals of US$22.7m due to the renegotiation of rig contracts.  Non-cash additions relating to increases in the decommissioning estimate were US$1.5m.

 

Impairment review

 

Impairment reviews on the Group's development/producing assets are conducted at the each reporting date. The Group's development/producing assets were reviewed for indicators of impairment at 30 June and impairment tests performed.  No impairment was recorded.  There have been no significant changes in market conditions or management's estimates and assumptions used in impairment testing at the December 2017 year end.

  

 

Section 2 - Oil and Gas Assets (continued)

 

2.3     Capital Commitments

 

 

30 June

 2018

30 June

2017

31 December

2017

 

US$m

US$m

US$m

Oil and gas expenditure:

 

 

 

Intangible exploration/appraisal assets

178.7

101.2

63.2

Property, plant & equipment - development/producing assets

51.0

346.1

120.8

 

Contracted for

229.7

447.3

184.0

 

Capital commitments represent Cairn's share of obligations in relation to its interests in joint operations.  These commitments include Cairn's share of the capital commitments of the joint operations themselves. 

 

The capital commitments for intangible exploration/appraisal assets as at 30 June 2018 include US$98.7m relating to operations in the UK & Norway. Capital commitments for operations in Mexico account for US$62.9m and other international operations total to US$12.1m. The balance represents remaining commitments in Senegal.  

 

The capital commitments for property, plant & equipment - development/producing assets, which relate entirely to the Group's UK North Sea producing assets, exclude costs of the Kraken FPSO finance lease obligations, which are disclosed in note 3.4.

 

At 30 June 2018, Cairn had the following operating lease commitments relating to oil and gas exploration, appraisal and development activities.  These amounts are also included in total capital commitments above and exclude operating lease commitments relating to producing activities:

 

 

30 June

2018

30 June

 2017

31 December

2017

 

US$m

US$m

US$m

Intangible exploration/appraisal assets

 

 

 

Not later than one year

3.6

1.4

3.1

 

 

 

 

Property, plant & equipment - development/producing assets

 

 

 

Not later than one year

5.1

42.1

34.5

After one year but no more than five years

-

24.0

10.3

 

5.1

66.1

 

44.8

 

 

Section 3 - Assets and Liabilities: Financial Assets, Cash and Borrowings, Lease liabilities and Working Capital

3.1     Financial Asset at Fair Value through Profit or Loss

 

 

 

Listed equity shares

US$m

7.5% Redeemable preference shares of INR10

US$m

Total

US$m

Fair Value

 

 

 

As at 1 January 2017

656.1

-

656.1

Surplus on valuation of Cairn India Limited shares prior to merger

163.6

-

163.6

Disposal of shares in Cairn India Limited on merger

(819.7)

-

(819.7)

Addition of shares in Vedanta Limited on merger

671.8

114.9

786.7

Surplus on valuation of Vedanta Limited shares after merger

37.8

(0.9)

36.9

 

 

 

 

As at 30 June 2017

709.6

114.0

823.6

Surplus on valuation of Vedanta Limited shares

241.9

6.7

248.6

 

As at 31 December 2017

951.5

120.7

1,072.2

Deficit on valuation of Vedanta Limited shares

(307.9)

(11.5)

(319.4)

Derecognition of shares in Vedanta Limited

(230.8)

-

(230.8)

 

As at 30 June 2018

412.8

109.2

522.0

 

Following adoption of IFRS 9 on 1 January 2018, fair value movements during the period are recognised in the income statement and comparative information has been restated accordingly, see note 1.3.  There is no change to the valuation of the asset following the adoption of IFRS 9.

At 1 January 2018, Cairn held 4.9% of the listed equity shares in VL. During late May and early June 2018 the IITD instructed the sale of 1.7% of Cairn's shareholding seizing the resultant proceeds.  See note 5.4.  This has resulted in a loss on derecognition of US$230.8m during the six month period to 30 June 2018.  Further sales of 1.1% were instructed in August and September 2018, reducing Cairn's shareholding in the listed equity shares to 2.1%. See note 6.1.  Cairn continues to be restricted from selling its remaining shares in VL pending conclusion of the ongoing arbitration proceedings.  As timing of the arbitration award is expected to be within one year from the balance sheet date, the financial asset has been classified as current at 30 June 2018.

 

The listed equity shares held at 30 June 2018 in the ordinary share capital of VL, listed in India, have by their nature no fixed maturity or coupon rate. These listed equity securities present the Group with an opportunity for return through dividend income and trading gains and are Level 1 assets measured at fair value.  The redeemable preference shares have a coupon of 7.5%, a term of 18 months and will be cash settled in October 2018.  These too are Level 1 assets measured at fair value.

 

The Group is exposed to equity price risks arising from the listed equity investments it holds in VL.

3.2     Cash and Cash Equivalents

 

 

30 June

2018

30 June

2017

31 December

 2017

 

US$m

US$m

US$m

 

 

 

 

Cash at bank

16.4

13.5

24.7

Short-term bank deposits

-

14.4

24.0

Money market funds

58.4

180.6

19.5

Tri-party repurchase transactions

-

45.2

18.3

 

Cash and cash equivalents

74.8

253.7

86.5

 

 

 

Section 3 - Other Assets and Liabilities: Financial Assets, Cash and Borrowings, Lease liabilities and Working Capital (continued)

3.3     Loans and Borrowings

 

Reconciliation of opening and closing liability to cash flow movements:

30 June

2018

30 June

 2017

31 December

2017

 

US$m

US$m

US$m

 

 

 

 

Opening liability

29.8

-

-

Loans advanced recognised in cash flow statement

94.4

21.7

29.2

Borrowing costs and interest payable

(2.4)

-

-

Foreign exchange differences

(0.6)

-

0.6

 

 

 

 

Closing liabilities

121.2

21.7

29.8

 

 

Amounts due less than one year:

 

 

 

Reserve-based lending facility

62.6

-

-

Exploration financing facility

30.3

21.7

29.8

 

 

 

 

 

92.9

21.7

29.8

Amounts due greater than one year:

 

 

 

Exploration financing facility

28.3

-

-

 

 

 

 

 

121.2

21.7

29.8

 

 

Reserve-based lending facility

 

The Group's reserve-based lending facility had cash drawings of US$65.0m at 30 June 2018. 

 

Cairn have signed an extension to its existing RBL facility with a syndicate of international banks. The extension is expected to be effective by 31 October and brings the Nova asset into the borrowing base, subject to approval of the development plan which is expected by the end of 2018. Interest on outstanding debt is charged at the appropriate LIBOR for the currency drawn plus an applicable margin. The facility remains subject to bi-annual redeterminations, has a market standard suite of covenants and is cross-guaranteed by all Group companies' party to the facility. Debt is repayable in line with the amortisation of bank commitments over the period from 1 July 2022 to the extended final maturity date of 30 June 2025. 

 

Under IFRS 9, the extension of the facility to June 2025 constitutes substantially different terms from the original and as such the financial liability relating to the original facility shall be extinguished on the date of the extension and replaced with a new liability based on the revised terms.

 

Total commitments remain unchanged at US$575.0m under the revised facility, but an accordion feature permits additional future commitments of up to US$425.0m.  The maximum available drawdown is currently forecast to be US$525.0m during the life of the facility. The facility can also be used for general corporate purposes and may also be used to issue letters of credit and performance guarantees for the Group of up to US$175.0m.

 

 

Exploration Financing Facility

 

As at 30 June 2018, US$58.6m (NOK 477.4m) was drawn under the Norwegian Exploration Financing Facility. The maximum available amount is currently forecast to be US$59.0m (NOK 481m).

 

Interest on outstanding debt is charged at the appropriate NIBOR plus an applicable margin. Debt is repayable by the final maturity date, which is the earlier of 31 December 2019 or the date of receipt of the tax refund relating to exploration spend for 2018.

 

 

 

Section 3 - Other Assets and Liabilities: Financial Assets, Cash and Borrowings, Lease liabilities and Working Capital (continued)

3.4     Finance Lease Liabilities

 

 

Minimum lease payments

Present value of minimum lease payments

 

30 June 2018

30 June 2017

31 December 2017

30 June

 2018

30 June

 2017

31 December 2017

 

US$m

US$m

US$m

US$m

US$m

 

 

 

 

 

 

Not later than one year

12.9

17.5

1.6

5.1

17.1

1.5

After one year but no more than five years

90.5

94.2

88.5

65.5

82.9

77.2

After five years

118.6

139.8

130.5

104.3

100.2

91.0

Total future minimum rentals payable

222.0

251.5

 

220.6

174.9

200.2

169.7

 

 

 

 

 

 

 

Less future finance charges

(47.1)

(51.3)

(50.9)

 

 

 

Present value of minimum lease payments

174.9

200.2

169.7

 

 

 

 

Finance lease liabilities relate to the Kraken FPSO.

 

3.5     Trade and Other Receivables

 

 

30 June

2018

30 June

2017

31 December

2017

 

US$m

US$m

US$m

 

 

 

 

Trade receivables

55.5

-

0.2

Other receivables

12.6

28.1

12.7

Accrued income - underlift adjustments

-

-

5.6

Prepayments

5.2

26.7

18.8

Financial assets

1.8

-

-

Joint operation receivables

57.2

74.5

45.8

 

 

132.3

129.3

83.1

 

Following the draw-down on the RBL facility, facility fees of US$15.1m, held in prepayments at 31 December 2017, are now netted against the loan balance. The fees are amortised over the estimated useful life of the loan.

 

Joint operation receivables include Cairn's working interest share of the receivables relating to joint operations and amounts recoverable from partners in joint operations.  

 

  

Section 3 - Other Assets and Liabilities: Financial Assets, Cash and Borrowings, Lease liabilities and Working Capital (continued)

3.6     Trade and Other Payables

 

30 June

2018

30 June

2017

31 December

2017

 

US$m

US$m

US$m

 

 

 

 

Trade payables

18.3

9.2

6.9

Deferred income - overlift adjustments

7.9

-

-

Other taxation and social security

2.5

1.9

2.5

Accruals and other payables

29.6

32.7

22.6

Financial liabilities  

14.6

-

1.4

Joint operation payables

95.4

169.0

165.8

 

 

168.3

212.8

199.2

 

Joint operation payables include Cairn's share of the trade and other payables of joint operations in which the Group participates.  Where Cairn is operator of the joint operation, joint operation payables also include amounts that Cairn will settle to third parties on behalf of joint operation partners.  The amount to be recovered from partners for their share of such liabilities are included within joint operation receivables. 

 

The increase in trade payables is mainly due to costs incurred on Kraken and Catcher development/producing assets. The increase in accruals and other payables largely relates to overlift on production, amounts due to FlowStream and the purchase of shares for the ESOP Trust. The mark-to-market loss on oil price options has created the financial liability as at 30 June 2018.

 

 

3.7     Deferred Revenue

 

 

30 June

2018

US$m

30 June

2017

(restated)

US$m

31 December

2017

US$m

 

 

 

 

Opening deferred revenue

74.0

-

-

Fair value of proceeds received

-

74.6

74.6

Released during the year (note 4.2)

(9.6)

-

(3.0)

Foreign exchange differences

-

(0.4)

2.4

 

 

 

 

Closing deferred revenue

64.4

74.2

74.0

 

 

 

 

Amounts expected to be released within one year

21.5

28.7

24.3

Amounts expected to be released after one year

42.9

45.5

49.7

 

 

 

 

 

64.4

74.2

74.0

 

Deferred revenue relates to the stream agreement with FlowStream entered into in 2017. 

  

 

Section 4 - Results for the Period

 

4.1     Segmental Analysis

Operating segments

The Group's portfolio of exploration and development/producing assets are managed through regional business units. Each business unit is headed by a regional director (a regional director may be responsible for more than one business unit) and the Board monitors the results of each segment separately for the purposes of making decisions about resource allocation and performance assessment.   

 

The Senegal business unit's focus is to have a government-approved exploitation plan by the end of 2018, with first oil expected between 2021 and 2023. The UK & Norway business unit includes exploration activities in the North Sea, Norwegian Sea and Barents Sea and management of the Group's producing assets in the UK North Sea. The International business unit consists of all other regions where Cairn currently holds (or held during the year) exploration licences, including Mexico, Ireland, Western Sahara and the Mediterranean.  The Other Cairn Energy Group segment exists to accumulate the activities and results of the holding company, other unallocated expenditure and net assets/liabilities, including amounts of a corporate nature, not specifically attributable to any of the business units.

 

Non-current assets as analysed on a segmental basis consist of intangible exploration/appraisal assets; property, plant & equipment - development/producing assets; intangible assets - goodwill; and other property, plant & equipment and intangible assets.

 

The segment results for the six months ended 30 June 2018 are as follows:

 

Senegal

UK & Norway

International

Other Cairn

Energy

Group

Total

 

US$m

US$m

US$m

US$m

US$m

 

 

 

 

 

 

Revenue

-

181.7

-

0.7

182.4

 

 

 

 

 

 

Cost of sales

-

(78.0)

-

-

(78.0)

Depletion and amortisation

-

(65.7)

-

-

(65.7)

 

 

 

 

 

 

Gross profit

-

38.0

-

0.7

38.7

 

 

 

 

 

 

Pre-award costs

-

(2.1)

(0.7)

(9.2)

(12.0)

Unsuccessful exploration costs

-

(45.9)

(0.9)

-

(46.8)

Depreciation

-

(0.4)

-

(0.3)

(0.7)

Amortisation

-

-

-

(1.1)

(1.1)

Loss on disposal of intangible exploration/appraisal assets

-

(4.5)

-

-

(4.5)

Other operating income

-

-

5.0

-

5.0

Other administrative expenses

(0.1)

(0.5)

(0.4)

(12.1)

(13.1)

 

 

 

 

 

 

Operating (loss)/profit

(0.1)

(15.4)

3.0

(22.0)

(34.5)

 

 

 

 

 

 

Loss on derecognition of financial assets

-

-

-

(230.8)

(230.8)

Loss on fair value of financial assets

-

-

-

(319.4)

(319.4)

Interest income

-

-

-

0.6

0.6

Other finance income and costs

-

(19.2)

-

0.4

(18.8)

 

 

 

 

 

 

(Loss)/profit before taxation

(0.1)

(34.6)

3.0

(571.2)

(602.9)

 

 

 

 

 

 

Tax credit

-

33.3

-

69.1

102.4

 

 

 

 

 

 

(Loss)/profit for the period

(0.1)

(1.3)

3.0

(502.1)

(500.5)

 

 

 

 

 

 

Capital expenditure

12.1

54.2

7.8

0.2

74.3

 

 

 

 

 

 

Total assets

459.0

1,692.4

53.5

516.2

2,721.1

 

 

 

 

 

 

Total liabilities

13.7

660.7

26.5

39.2

740.1

 

 

 

 

 

 

Non-current assets

446.7

1,437.4

29.7

6.9

1,920.7

 

 

Section 4 - Results for the Period (continued)

 

4.1     Segmental Analysis (continued)

All transactions between the segments are carried out on an arm's length basis, other than where inter-group loans are made interest-free or at interest rates below market value.

 

The segment results for the six months ended 30 June 2017 after restatement (see note 1.3) were as follows:

 

 

Senegal

UK & Norway

International

Other Cairn

Energy

Group

(restated)

Total

(restated)

 

US$m

US$m

US$m

US$m

US$m

 

 

 

 

 

 

Revenue

-

-

10.8

-

10.8

 

 

 

 

 

 

Cost of sales

-

(0.4)

-

-

(0.4)

Depletion and amortisation

-

(0.3)

-

-

(0.3)

 

 

 

 

 

 

Gross (loss)/profit

-

(0.7)

10.8

-

10.1

 

 

 

 

 

 

Pre-award costs

-

(27.0)

(2.5)

(4.3)

(33.8)

Unsuccessful exploration costs

-

(3.5)

(11.7)

-

(15.2)

Depreciation

-

(0.2)

-

(0.1)

(0.3)

Amortisation

-

-

-

(0.2)

(0.2)

Other income and administrative expenses

-

(1.8)

0.4

(11.6)

(13.0)

 

 

 

 

 

 

Operating loss

-

(33.2)

(3.0)

(16.2)

(52.4)

 

 

 

 

 

 

Loss on derecognition of financial assets

-

-

-

(33.0)

(33.0)

Gain on fair value of financial asset

-

-

-

200.5

200.5

Interest income

-

0.1

-

9.4

9.5

Other finance income and costs

(0.3)

(7.9)

-

66.0

57.8

Exceptional provision against finance income receivable

-

-

-

(104.7)

(104.7)

 

 

 

 

 

 

(Loss)/profit before taxation

(0.3)

(41.0)

(3.0)

122.0

77.7

 

 

 

 

 

 

Tax credit/(charge)

-

28.9

-

(35.7)

(6.8)

 

 

 

 

 

 

(Loss)/profit for the period

(0.3)

(12.1)

(3.0)

86.3

70.9

 

 

 

 

 

 

Capital expenditure

77.5

299.4

11.5

0.6

389.0

 

 

 

 

 

 

Total assets

460.0

1,539.4

27.4

993.5

3,020.3

 

 

 

 

 

 

Total liabilities

83.6

561.2

16.6

51.4

712.8

 

 

 

 

 

 

Non-current assets

407.7

1,336.9

12.1

1.8

1,758.5

 

  

Section 4 - Results for the Period (continued)

 

4.1     Segmental Analysis (continued)

 

The segment results for the year ended 31 December 2017 after restatement (see note 1.3) were as follows:

 

 

Senegal

UK & Norway

International

Other Cairn

Energy

Group

(restated)

Total

(restated)

 

US$m

US$m

US$m

US$m

US$m

 

 

 

 

 

 

Revenue

-

22.9

10.4

-

33.3

 

 

 

 

 

 

Cost of sales

-

(5.9)

-

-

(5.9)

Depletion and amortisation

-

(20.8)

-

-

(20.8)

 

 

 

 

 

 

Gross (loss)/profit

-

(3.8)

10.4

-

6.6

 

 

 

 

 

 

Pre-award costs

-

(30.2)

(8.5)

(5.1)

(43.8)

Unsuccessful exploration costs

-

(8.1)

(52.6)

-

(60.7)

Depreciation

-

(0.6)

-

(0.5)

(1.1)

Amortisation

-

-

-

(1.5)

(1.5)

Other income and administrative expenses

-

(2.2)

0.3

(25.8)

(27.7)

Reversal of impairment of property, plant & equipment - development/producing assets

-

23.0

-

-

23.0

 

 

 

 

 

 

Operating loss

-

(21.9)

(50.4)

(32.9)

(105.2)

 

 

 

 

 

 

Loss on derecognition of financial assets

-

-

-

(33.0)

(33.0)

Gain on fair value of financial asset

-

-

-

449.1

449.1

Interest income

0.1

0.6

-

3.2

3.9

Other finance income and costs

(0.7)

0.7

-

62.7

62.7

Exceptional provision against finance income receivable

-

-

-

(104.7)

(104.7)

 

 

 

 

 

 

(Loss)/profit before taxation

(0.6)

(20.6)

(50.4)

344.4

272.8

 

 

 

 

 

 

Tax credit

-

34.4

-

(89.4)

(55.0)

 

 

 

 

 

 

(Loss)/profit for the year

(0.6)

13.8

(50.4)

255.0

217.8

 

 

 

 

 

 

Capital expenditure

104.2

416.8

63.1

8.6

592.7

 

 

 

 

 

 

Total assets

463.3

1,674.2

40.3

1,077.7

3,255.5

 

 

 

 

 

 

Total liabilities

34.6

592.4

26.5

107.5

761.0

 

 

 

 

 

 

Non-current assets

434.5

1,499.4

22.8

8.2

1,964.9

 

  

Section 4 - Results for the Period (continued)

 

4.2     Revenue and Cost of Sales

 

 

Six months ended

 30 June

2018

US$m

Six months ended

 30 June

 2017

US$m

Year ended

31 December

2017

US$m

 

 

 

 

Oil and gas sales

174.3

-

19.9

Loss on hedge options

(2.2)

-

-

Release of deferred revenue (note 3.7)

9.6

-

3.0

Revenue from oil sales

181.7

-

22.9

 

 

 

 

Royalty income

0.7

10.8

10.4

 

Revenue

182.4

10.8

33.3

 

 

 

 

Production and other costs

(30.9)

(0.1)

(15.3)

Oil inventory and overlift/underlift movements

(14.8)

(0.3)

16.4

Variable and operating lease charges

(32.3)

-

(7.0)

 

 

 

 

Cost of sales

(78.0)

(0.4)

(5.9)

 

 

 

 

Depletion and amortisation (note 2.2)

(65.7)

(0.3)

(20.8)

 

 

 

 

Gross profit

38.7

10.1

6.6

 

 

During the period, Cairn achieved oil and gas sales of 10.4mmboe from the Kraken and Catcher fields, realising US$172.1m after hedging settlements.   Deferred revenue is released on a unit-of-production basis on based estimated future quantities to which FlowStream are entitled.

 

Operating lease commitments

 

At the year end, Cairn had the following operating lease commitment relating to the Catcher FPSO:

 

 

30 June

2018

US$m

30 June

2017

US$m

31 December

2017

US$m

 

 

 

 

Production costs - operating lease charges

 

 

 

Not later than one year

33.9

13.9

33.9

After one year but no more than five years

119.7

127.5

124.0

After five years

35.1

61.0

47.4

 

 

188.7

 

202.4

205.3

 

 

 

Section 4 - Results for the Period (continued)

 

4.3     Finance Costs

 

 Six months ended

 30 June

2018

 

Six months ended

30 June

2017

Year ended

31 December

2017

(restated)

 

 

 

 

Loan interest and facility fee amortisation

15.3

0.2

0.6

Other finance charges

3.9

2.5

4.8

Loss on mark-to-market financial instruments

-

-

0.3

Unwinding of discount - provisions

1.1

0.9

2.2

Finance lease interest

3.8

-

2.5

 

 

 

 

 

24.1

3.6

10.4

 

Loan interest and facility fee amortisation includes US$12.9m of facility fees relating to the RBL facility, which are amortised over the expected useful life of the facility.

 

4.4     Earnings per Ordinary Share

Basic and diluted earnings per share are calculated using the following measures of (loss)/profit:

 

 

 Six months ended

 30 June

2018

Six months ended

30 June

2017

(restated)

Year ended

31 December

2017

(restated)

 

US$m

US$m

US$m

(Loss)/profit and diluted (loss)/profit attributable to equity holders of the parent

(500.5)

70.9

217.8

 

Refer to note 1.3 concerning the restatement of profit comparatives on adoption of IFRS 9.

 

The following reflects the share data used in the basic and diluted earnings per share computations:

 

 

 Six months ended

 30 June

2018

Six months ended

30 June

2017

Year ended

31 December

2017

 

'000

'000

'000

 

 

 

 

Weighted average number of shares

586,547

581,015

582,134

Less weighted average shares held by ESOP and SIP Trusts

(5,838)

(4,817)

(4,933)

 

Basic weighted average number of shares

580,709

576,198

577,201

 

 

 

 

Potential dilutive effect of shares issuable under employee share plans:

 

 

 

LTIP awards

-

7,628

11,027

Approved and unapproved plans

-

508

346

Employee share awards

-

1,244

2,442

 

 

 

 

Diluted weighted average number of shares

580,709

585,578

591,016

 

 

 

 

Potentially issuable shares, anti-dilutive not included above:

 

 

 

LTIP awards

28,019

19,328

16,665

Approved and unapproved plans

3,393

169

169

Employee share awards

4,141

1,804

842

 

Number of potentially issuable shares

35,553

21,301

17,676

 

2018 potentially issuable shares were all anti-dilutive due to the loss for the period.

  

Section 5 - Taxation

5.1     Tax Credit on Loss for the Period

 

Analysis of tax credit on loss for the period

 

 

 

Six months ended

 30 June

 2018

US$m

Six months ended

 30 June

2017

(restated)

US$m

Year ended

31 December

2017

(restated)

US$m

Current tax credit:

 

 

 

Norwegian tax refunds receivable

(24.4)

(27.4)

(39.9)

 

 

(24.4)

(27.4)

(39.9)

 

Deferred tax (credit)/charge:

 

 

 

Norwegian deferred tax (credit)/charge

(8.9)

2.0

9.0

Release of provision on carried interests due to change in tax rate

-

(3.5)

(0.7)

UK deferred tax credits realised

-

-

(2.8)

Deferred tax on derecognition of financial assets

-

(7.1)

(7.1)

Deferred tax on valuation of financial assets

(69.1)

42.8

96.5

 

Total deferred tax (credit)/charge

(78.0)

34.2

94.9

 

Total tax (credit)/charge on (loss)/profit

(102.4)

6.8

55.0

            

The tax charge for prior periods has been restated following the adoption of IFRS 9 (note 1.3) which has resulted in tax previously included in other comprehensive income now included in the tax charge in the income statement.

 

5.2     Income Tax Asset

 

The income tax asset of US$62.2m (30 June 2017: US$54.9m; 31 December 2017: US$38.4m) relates to cash tax refunds due from the Norwegian authorities on the tax value of exploration and other qualifying expenses incurred in Norway.

  

Section 5 - Taxation (continued)

5.3     Deferred Tax Assets and Liabilities

 

Reconciliation of movement in deferred tax assets/(liabilities):

 

 

Temporary difference in respect of non-current assets

Losses

Other temporary differences

Total

 

US$m

US$m

US$m

US$m

Deferred tax assets

 

 

 

 

At 1 January 2017

(205.6)

205.6

-

-

Exchange differences arising

(12.3)

12.3

-

-

Deferred tax charge through income statement

(24.9)

28.4

-

3.5

Other deferred tax movements

(3.5)

-

-

(3.5)

 

At 30 June 2017

(246.3)

246.3

-

-

Exchange differences arising

(15.2)

15.2

-

-

Deferred tax charge through income statement

(87.5)

87.5

-

-

 

At 1 January 2018

(349.0)

349.0

-

-

Deferred tax credit through income statement

21.5

(21.5)

-

-

 

At 30 June 2018

(327.5)

327.5

-

-

 

 

 

 

 

Deferred tax liabilities

 

 

 

 

At 1 January 2017

(74.3)

11.6

-

(62.7)

Exchange differences arising

(2.6)

0.4

-

(2.2)

Deferred tax charge through income statement (restated)

(38.9)

1.5

(0.3)

(37.7)

 

At 30 June 2017

(115.8)

13.5

(0.3)

(102.6)

Exchange differences arising

(1.3)

0.2

-

(1.1)

Deferred tax charge through income statement (restated)

(62.8)

1.6

0.5

(60.7)

 

 

 

 

 

At 1 January 2018

(179.9)

15.3

0.2

(164.4)

Exchange differences arising

(1.1)

-

-

(1.1)

Deferred tax credit through income statement

75.9

1.8

0.3

78.0

 

At 30 June 2018

(105.1)

17.1

0.5

(87.5)

 

 

Deferred tax liabilities analysed by country:

30 June

2018

US$m

30 June

2017

US$m

31 December

2017

US$m

 

 

 

 

India

(20.3)

(35.7)

(89.4)

Norway

(67.2)

(66.9)

(75.0)

 

 

 

 

Total deferred tax liability

(87.5)

(102.6)

(164.4)

 

  

Section 5 - Taxation (continued)

5.4     Contingent Liability - Indian Tax Assessment

The final hearing of Cairn's claim under the UK-India Bilateral Investment Treaty took place in August in The Hague; the tribunal has stated that it will make appropriate arrangements to progress with the drafting of the award as expeditiously as possible.

 

Based on detailed legal advice, Cairn is confident that it will be successful in this arbitration and accordingly no provision has been made for any of the tax or penalties assessed by the IITD.

 

The Group also has legal advice confirming that the maximum amount that could ultimately be recovered from Cairn by the IITD is limited to the value of the assets of Cairn UK Holdings Limited ("CUHL"), a direct subsidiary of Cairn Energy PLC and the assessee in respect of tax demanded.   CUHL's assets are principally the remaining ordinary and preference shares in VL disclosed in note 3.1.  The IITD would also retain seized dividends and sales proceeds, including those seized during the current period, and a tax refund from 2011, which are currently not reflected on the Group Balance Sheet.

  

 

 

Section 6 - Other Disclosures

 

6.1  Post Balance Sheet Events - Sale of shares in VL

In August and September 2018, the IITD instructed the further sales of 1.1% of Cairn's remaining 3.3% holding in the listed equity shares of VL, seizing the proceeds realised.  These shares had a value of US$148.3m recorded in the Balance Sheet as at 30 June 2018. 

 

Following this sale, Cairn now holds 2.1% in the listed equity shares of VL.

 

 

 

 

 

 

 

 

 


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