FOR IMMEDIATE RELEASE                                                                                   10 March 2020

CAIRN ENERGY PLC ("Cairn")

Full Year Results Announcement

For the year ended 31 December 2019

Simon Thomson, Chief Executive Officer, Cairn Energy PLC said:

"Cairn's strong operational performance in 2019 was delivered through production and cash flow generation at the top end of guidance and the Group ended the year with an increased net cash position and undrawn debt facilities.

A significant milestone was achieved in Senegal with a Final Investment Decision taken for the Sangomar development. Reserve additions were made in both Senegal and the North Sea and the Company encountered exploration success alongside Eni in Mexico.

The sale of Cairn's Norwegian business, combined with exits from exploration positions in Ireland and Nicaragua, demonstrate continued focus on capital allocation as the company seeks to generate further value for shareholders on a sustainable basis."

 2019 Summary

Ø Net oil production averaged ~23,000 bopd, at upper end of guidance (2018: 17,500 bopd)

Ø Oil and gas sales revenue US$504m (2018: US$396m), average realised oil price US$65.70/bbl; average production cost US$17.4/boe

Ø Net cash inflow from oil and gas production US$390m

Ø Capital expenditure was US$242m*

Ø Year end Group cash US$147m, excludes proceeds from sale of Capricorn Norge of ~US$108m, completed in February 2020

Ø Operating profit US$155m (2018: Operating loss US$129m)

Ø Net impairment reversal of US$68m (2018: charge of US$166m): Reversal of US$147m Kraken impairment, offset by US$79m goodwill impairment

Ø Increase 2P reserves by 150% to 142 mmboe

2020 Outlook

Ø Estimated net production of 19,000 to 23,000 bopd; targeting average production cost <US$20/boe

Ø Forecast capital expenditure ~US$615m

Ø Senegal - Sangomar field development targeting first oil 2023, gross production 100,000 bopd

Ø Mexico - two further non-operated exploration wells planned

Ø India Arbitration - Tribunal indicated it expects to be in a position to issue the Award in summer 2020; Cairn continues to have a high level of confidence in merits of its claims

*Net of US$27m tax refund and US$21m Nova working capital reimbursement

Webcast

There will be a live audio webcast of the results presentation available to view on the website (www.cairnenergy.com) at 9am GMT. 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 7:00am GMT.

Conference call

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

Dial-in details:

Transcript

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

Operational review

Reserves

After accounting for production in the period, Group 2P reserves increased during the year by 86 mmboe from 56 mmboe to 142 mmboe, following promotion of the Sangomar phase 1 contingent resources to reserves (+91.4 mmboe), increases on the main Catcher (+1.9 mmboe) and Kraken (+6.4 mmboe) fields  and movement of Worcester (+1.5 mmboe) and Catcher satellites (+0.8 mmboe) from Contingent Resources to Reserves following JV commitment to these incremental projects.
 

Production

Both Catcher and Kraken delivered good production performance in 2019, with annual production of ~23,000 bopd at the top end of our guidance.  Catcher and Kraken are at peak rates and the focus is on optimising existing wells and maturing new opportunities to help sustain production in forthcoming years.

Catcher

Gross production from the Catcher Area (Cairn 20% WI) averaged 63,600 bopd in 2019.  The Area, comprising the Catcher, Varadero and Burgman fields, continued to outperform during 2019 achieving excellent operating efficiency from the FPSO.

2020 drilling will deliver three new production wells.  Development of two Catcher Area satellite oil fields, Catcher North and Laverda, is progressing to plan.  The two development wells are scheduled to be drilled in mid-2020, along with an additional Varadero production well.  First oil from Catcher North and Laverda is targeted for H1 2021 and together with the Varadero infill well, will help to offset natural decline of the Catcher Area as the existing wells come off plateau.

The JV continues to work up additional well targets within the Catcher area and nearby discoveries to maximise economic recovery. Two Burgman infill wells are under-evaluation for 2021.

In addition, a 4D seismic survey across the Catcher Area is scheduled to take place mid-year to identify further infill opportunities as well as to improve the imaging of already identified near field prospects and discoveries. Planned shut-downs for maintenance and tie-ins of new satellite wells will occur during 2020.

Kraken

Gross production from Kraken (Cairn 29.5% WI) averaged 35,600 bopd in 2019. FPSO performance was significantly improved during H2 2019 and this has continued into 2020.  Water cut levels have stabilised and more regular well testing has provided additional insight and improved confidence in long-term production forecasts. 

Drilling of two wells, a producer and an injector pair on the western flank of the Kraken field (Worcester accumulation) is expected to commence in H1 and tied in and onstream in H2 2020.    This development will utilise spare capacity in the existing DC2 sub-sea infrastructure.

The western flank area provides further opportunities and the Pembroke, Antrim and Barra areas are being evaluated.    

Developments

Senegal - Sangomar

Cairn's discoveries offshore Senegal from the country's first deep water wells opened up a new basin on the Atlantic Margin.  Cairn operated three successful drilling programmes from 2014 to 2017 and laid the foundations for Senegal's first multi-phase oil and gas development with first oil targeted in H1 2023. 

The JV will be working with all stakeholders to ensure that the Sangomar development delivers enduring benefits to the people of Senegal as a project of national significance and an anchor for economic and social development.

In January 2020, the JV made the Final Investment Decision following receipt of the 25-year Exploitation Authorisation from the Government of Senegal.

The Sangomar field (formerly SNE), located 100km offshore to the south of Dakar, is within the Sangomar Deep Offshore permit area.  Phase 1 of the development will target oil reserves from the lower reservoirs and an initial pilot phase in the upper reservoirs.  Over the life of the field, total recoverable oil reserves of are estimated to be ~500mmbbls with the development also including plans to export gas to shore for the domestic market.

The funding plan to allow the Group to meet its share of development costs is well progressed.   Cairn remains confident that it will be able to meet its share of expenditure and maintain current equity levels in the project.

The project has now entered the development execution phase of activities and Operator Woodside has completed the purchase contract for the FPSO facility and issued full notices to proceed for the drilling and subsea construction and installation contracts. 

The key contractors for the development are:

In addition to Phase 1, the JV continues to work with the Ministry of Petroleum and Energy and Petrosen to progress subsequent oil opportunities, including the other discoveries located in the Rufisque Offshore and Sangomar Offshore blocks. This work also includes planning for the provision of Sangomar gas to supply Senegal's domestic needs and Gas to Power initiative.

Norway asset disposals

In line with Cairn's consistent strategy to realise value and redeploy capital within our portfolio, two attractive transactions were announced in the year.

In August 2019, Cairn entered into a farm-out agreement with ONE-Dyas Norge AS for the sale of 10% interest in the Nova development offshore Norway for a consideration of US$59.5m plus working capital adjustments from the effective date of 1 January 2019. Following the transaction Cairn retained a participating interest of 10%. The transaction was completed in Q4 2019. 

In November 2019, Cairn entered into an agreement with Sval Energi AS (formerly Solveig Gas Norway AS) to dispose of the entire share capital of its Norwegian subsidiary, Capricorn Norge, for a consideration of US$100m plus working capital adjustments, from the effective date of 1 January 2020.  The transaction completed in late February 2020.

Following these transactions, Cairn has disposed of all its assets in Norway and reduced its committed exploration and development expenditure by US$210m.  We would like to express our gratitude and best wishes to our employees in Stavanger who are joining Sval Energi AS.

Exploration
Mexico

Cairn has interests in four blocks in the Gulf of Mexico, two as operator (Blocks 9 and 15) and two as non-operator (Blocks 7 and 10).* Mexico provides an exciting opportunity to discover commercial quantities of hydrocarbons in a highly prolific, yet under-explored region and has been a focus for Cairn's exploration drilling activities in late 2019 and early 2020.   

In its Operated Block 9 (50% WI), Cairn completed the first well of a two well programme in Q4 2019. The exploration objectives of the Alom-1 well was to prove hydrocarbons in stacked Pleistocene targets, these were found to be dry and the well was permanently plugged and abandoned.  Preliminary analysis indicated that the well encountered over 500m of high-quality water bearing sands across multiple targets.  This information is helping to calibrate Cairn's seismic data and geological models and is being integrated to improve our understanding of the petroleum system offshore Mexico.

In Q1 2020, an oil discovery was confirmed on the non-operated Saasken-1 exploration well (15% WI)* in Block 10 in the Sureste Basin.  Preliminary estimates by the Operator, Eni, indicate the discovery may contain 200 to 300 million barrels of oil in place. Eni estimate that Saasken-1 discovered 80m of net pay of good quality oil in the Lower Pliocene and Upper Miocene sequences with excellent petrophysical properties.  An intensive data collection has been carried out on the well and Eni has indicated that a production capacity for the well of more than 10,000bopd may be possible. This first discovery across Cairn's Sureste acreage interest opens the potential for a development hub, allowing tie-back of future discoveries across Blocks 9 and 10. Cairn has identified a number of prospects and leads across Blocks 9 and 10 that could be possible future exploration targets and tie-back candidates.

Cairn completed its second operated well in Q1 2020.  The exploration objective of the Bitol-1 well on Block 9 was to prove hydrocarbons in stacked Pliocene and Miocene targets. The objectives were found to be dry and the well is being permanently plugged and abandoned.  Some oil shows were encountered in good quality, water-bearing sandstones. 

The information gathered will help calibrate the seismic data and geological models and is being integrated to evaluate further prospectivity. Bitol-1 was drilled by the Maersk Developer semi-submersible to a vertical depth of 5,210m below the sea surface and was terminated in the Miocene section. The well was drilled ~120 kilometres northwest of Villahermosa. Cairn holds a 50% WI with JV partners Citla Energy (35% WI) and ENI (15%WI)*

On Block 7 (30% WI) the Ehecatl-1 well commenced in February 2020, targeting stacked objectives in the Lower Miocene. This well, operated by Eni, is being drilled with the Ensco Valaris 8505 semi-submersible rig in a water depth of 426m.

In Block 15 in the Tampico-Misantla Basin, an environmental baseline survey was completed in Q1 2019 and technical evaluation of the block is progressing.

*The National Hydrocarbon Commission (CNH) approved the 15% share of Capricorn Energy Mexico in Block 10 (contract CNH-R02-L01-A10.CS/2017). At the same time CNH approved the acquisition of a 15% share of Eni Mexico in the adjacent Block 9 (contract CNH-R02-L01-A09.CS/2017) operated by Capricorn Energy Mexico. The signature process of the revised Production Sharing Contracts to reflect the change in the JV working interest is ongoing. Capricorn Energy Mexico is a wholly owned subsidiary of Cairn Energy PLC.

UK & Norway

Cairn participated in four exploration wells in the UK & Norway region in 2019:  PL885 (Cairn 30% WI) in the Norwegian North Sea, containing the Presto prospect; PL758 (Cairn Operated 50% WI) in the Norwegian Sea, containing the Lynghaug prospect; PL842 (Cairn Operated, 40% WI) in the Norwegian Sea containing the Godalen prospect; and P2312 (Cairn Operated, 60% WI) in the UK North Sea containing the Chimera prospect.  All four wells were reported as dry and plugged and abandoned.

In early March 2020, Cairn entered into an asset exchange agreement with Shell UK Limited in which Cairn transferred a 50% WI in P2379 in exchange for 50% WI of P2380. Each licence contains a firm commitment to drill an exploration well (with both wells planned to be drilled in the period from H2 2020 to H1 2021).

Suriname
Cairn has an exploration agreement (Cairn operator 100% WI) on the largest block offshore Suriname.  The licence covers an area of ~13,000 km² on the Demerara plateau in the Guyana-Suriname basin, conjugate to the West Africa Margin which includes the Sangomar field in Senegal.  In H1, 4,500 km of 2D seismic data was acquired and has been fully processed.  Block-wide interpretations and an update of the prospect inventory are ongoing, with a decision on future 3D seismic acquisition to be made later this year with a view to potential drilling activity thereafter. Several projects supporting local initiatives are in early stage development, including industry capacity-building through training and education and a project focused on the coastal environment.

Israel
In H2 2019, Cairn was awarded eight licences offshore Israel in the country's second offshore bid round.  Cairn is Operator of the licences with a 33.34% WI alongside two JV partners: Ratio Oil Exploration (33.33% WI) and Pharos Energy plc (33.33% WI). The JV is planning to re-process existing 3D seismic in order to better assess the prospectivity within the awarded licences.

Mauritania

Cairn has exercised its 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 acquired a 40% WI (Total Operator 50% WI and Societé Mauritanienne des Hydrocarbures 10% WI), subject to government approval.  Final interpretation of ~7,000km² seismic data was completed in H1 2019 with a possible well planned in H2 2021.

Côte d'Ivoire

Cairn has a 30%, non-operated, interest in all seven of the Tullow-operated onshore licences (CI -301, CI-302, CI-518, CI-519, CI-520, CI-521 and CI-522).  A 2D seismic acquisition programme including passive seismic acquisition is being conducted in four phases and the approvals are being phased accordingly.  The programme commenced on the eastern blocks (C1-520-C1-522) in early 2020 with approval for the next phase expected in Q1 and a possible well drilling in 2021.

Nicaragua

Cairn is in the process of withdrawing from the 35.1% working interest in four exploration blocks in the Sandine Basin.  Cairn participated in the seismic acquisition and evaluation phase but concluded not to proceed to the planned drilling phase.

Republic of Ireland

In the year, Cairn, along with partners, withdrew from FEL 2/14 and the licence was terminated at the year end.  We also withdrew from two applications to convert Licence Options 16/18 and 16/19 to Frontier Exploration Licences.   

India

The Arbitral Tribunal has indicated that it expects to be in a position to issue an Award in the summer of this year relating to the Bilateral Investment Treaty arbitration claim brought against the Government of India.  Cairn continues to have a high level of confidence in the merits of its claims in the arbitration and is seeking full restitution for losses of more than US$1.4 billion resulting from: the expropriation of its investments in India in 2014; continued attempts to enforce retrospective tax measures; and the failure to treat the Company and its investments fairly and equitably. The Treaty affords strong provisions to enforce a successful award and the decision of the Tribunal binding on both parties.  

Board changes

Cairn appointed two new independent non-executive directors, with Catherine Krajicek and Alison Wood joining the Board in H2 2019. Cairn today announced the appointment of Erik B Daugbjerg as an independent non-executive director with effect from 14 May 2020. Following this appointment, Todd Hunt will retire as a non-executive director immediately following the Company's Annual General Meeting on 14 May 2020.

Outlook

In the year ahead, Cairn looks forward to continuing its near-term exploration drilling programme offshore Mexico whilst progressing the first phase of development execution offshore Senegal.  These activities are supported by strong cash flow from our producing assets and a continued fiscal discipline on balancing expenditure. In addition, we anticipate resolution of the proceedings against the Government of India under the UK-India Investment Treaty.  Cairn will continue to focus on executing and delivering its strategy efficiently and responsibly as it seeks to add further value for shareholders.

Principal risks and uncertainties

Managing the Group's key risks and associated opportunities is essential to Cairn's long-term success and sustainability. The Group endeavours to pursue investment opportunities which offer an appropriate level of return whilst ensuring the level of associated political, commercial and technical risk remain within the defined risk appetite of the Group.

The Group's risk management framework provides a systematic process for the identification and management of the key risks and opportunities which may affect the delivery of the Group's strategic objectives. Key Performance Indicators are set annually and determining the level of risk the Group is willing to accept in the pursuit of these objectives is a fundamental component of the Group's risk management framework. 

Overall responsibility for the system of risk management and internal control and reviewing the effectiveness of such systems rests with the Board. Principal risks, as well as progress against key risk projects, are reviewed at each Board meeting and at least once a year the Board undertakes a risk workshop to review the Group's principal risks. This integrated approach to risk management has been and continues to be critical to the delivery of strategic objectives

Responding to Changing Risks during 2019

Cairn has assessed the principal risks and uncertainties at the end of 2019 and concluded that the majority of principal risks identified at H1 2019 remain relevant. Two new principal risks were added relating to the energy transition and the Senegal development project. The Senegal funding risk is captured in the diminished access to debt markets risk. The principal risks are:

·      Lack of exploration success

·      Volatile oil and gas prices

·      Failure to secure new venture opportunities

·      Delay in Senegal production start-up schedule

·      Underperformance on Kraken and Catcher assets

·      Misalignments with JV operators

·      Lack of adherence to health, safety, environment and security policies

·      Fraud, bribery and corruption

·      Climate change policy and its impacts on energy transition

·      Inability to secure or repatriate value from India

·      Political and fiscal uncertainties

·      Diminished access to debt markets

As part of the embedded risk management process, the Group actively considers emerging risks and threats which could impact on the business. The Group identified the increasing threat from cyber security attacks, the continued uncertainty around Brexit and the potential direct and indirect impacts from the Coronavirus as potential emerging risks which will be actively assessed and monitored.

Financial Review

Key Statistics

¹ Based on 20% Catcher production and 29.5% of Kraken production before deducting FlowStream's entitlement to Kraken volumes during the year of 1,460 boepd (2018: 1,360 boepd)

² Working interest share of cargoes sold during the period, net of FlowStream entitlement

³ Excluding hedging gains of US$1.42/bbl (2018 : loss of US$1.34/bbl)

⁴ Based on total production costs of US$150.5m (2018: US$131.1m), including total lease payments; see table below

Production

During 2019, daily production volumes on both assets have increased significantly.  Catcher production averaged ~67,200 boepd (2018: ~42,500 boepd) gross for the year and Kraken averaged ~35,600 bopd (2018: ~30,000 bopd).  Net to Cairn, combined production for 2019 averaged ~23,800 boepd before adjusting for FlowStream entitlement.

Revenue

Revenue from the sale of oil and gas was US$504.2m (2018: US$395.7m), before adjusting for hedging gains of US$10.9m (2018: hedging loss of US$7.8m).  Oil sales realised US$65.70/bbl against an average Brent price of US$64.36/bbl for the year reflecting the strong pricing of both Catcher and Kraken crudes.  Release of deferred revenue of US$17.2m (2018: US$21.2m) and royalty income in Mongolia of US$1.1m (2018: US$1.2m), increased total revenue to US$533.4m (2018: US$410.3m).

At 31 December 2019, Cairn has hedged 2.8m barrels of forecast production through to December 2020.  1.9m barrels have been hedged using collar structures with a weighted average floor of US$62.09 per bbl and an average ceiling of US$74.89 per bbl, and 0.9m barrels hedged using swaps with a weighted average strike price of US$61.85 per bbl. 

Cost of sales

Total production costs of US$150.5m (2018: US$131.1m) include US$25.6m of variable lease payments (2018: US$59.5m variable and operating lease payments) on the Catcher and Kraken FPSOs respectively.  Following adoption of IFRS 16, both the Kraken and Catcher FPSOs are recorded as right-of-use assets in the Balance Sheet with lease liabilities recognised representing fixed lease payments due over the expected life of the lease contract.  Previously, Catcher was accounted for as an operating lease, with all payments charged directly to production costs. Comparative information in the financial statements has not been adjusted on adoption of IFRS 16.

Production costs included in the table above are calculated as follows:

¹Fixed lease costs for FPSOs are included in total lease costs disclosed in note 3.3

²Total lease cost per boe are included in total production costs per boe

Movements in oil inventory and underlift positions, measured at market value, of US$20.6m (2018: charge of US$7.7m) were credited against cost of sales in the year. 

The increased depletion and amortisation cost per boe arise from the capitalisation and subsequent amortisation of the right-of-use asset in relation to the Catcher FPSO.

Sale of Capricorn Norge AS

Cairn has disposed of its interests in Norway through two transactions.  A sale of a 10% Working Interest in the Nova development asset to Dyas for consideration of US$59.5m plus working capital adjustments from the effective date of 1 January 2019, completed in November 2019. 

Subsequently, Cairn has sold the entire share capital of Capricorn Norge AS to Sval Energi for consideration of US$100m plus a working capital adjustment.  This transaction completed in February 2020.  As a result of this transaction being agreed, the Group's assets and liabilities in Norway, including goodwill allocated to Capricorn Norge AS, have been reclassified as held-for-sale at the balance sheet date and the financial performance of the Norwegian business disclosed as discontinued operations, including the gain on sale from the earlier part-disposal of Nova.  Prior to re-classification as held-for-sale, the remaining deferred tax provision US$26.9m has been reversed as the disposal will not result in a chargeable gain. 

The combined effect of the 10% Nova farm down and subsequent Capricorn Norge disposal is a small book loss of US$2.7m, included within the loss from discontinued operations.   The 10% farm down resulted in a book profit after tax of US$36.1m but, as this was an asset sale only, it did not include any derecognition of goodwill associated with the wider Norway business. All goodwill associated with the Norway business was derecognised on the reclassification of the Capricorn Norge business as held-for-sale which resulted in an impairment, net of the deferred tax reversal, of US$38.8m.

Net cash inflow for the Year

¹ Cash outflows on new venture activities of US$8.5m not relating to pre-award activities are reallocated from administration expenses

²US$48.1m of Senegal pre-development expenditure categorised as exploration expenditure in the Statutory Cash Flow Statement has been reallocated to "pre-development" in this table and US$7.0m of lease reimbursements have been deducted from development expenditure

³Includes cash balance of US$7.2m held by Capricorn Norge AS

Reconciliation of statutory cash flow to cash inflow from operations:

Cairn had cash balances of US$153.7m at 31 December 2019, representing a net cash inflow of US$87.4m over the year.  Borrowings under the Group's Reserve-Based Lending facility, US$85.0m at 31 December 2018 (before adjusting for unamortised facility fees and accrued interest) were repaid during the year.

Cash outflows on exploration expenditure in the year include US$49.8m of UK & Norway costs, primarily relating to the unsuccessful wells Lynghaug, Godalen and Presto wells in Norwegian waters and the unsuccessful UK Chimera well, US$37.7m on completion of farm-ins to new acreage in LATAM and East Atlantic and US$45.3m on drilling in Mexico with the balance of US$13.7m on the Group's remaining exploration licence and licence options  in Suriname, Ireland and Mauritania.

Development and pre-development cash outflows in the period primarily relate to costs on Kraken, Nova and Senegal.  On Kraken, cash spend of US$18.3m included the completion of final development drilling on Drill Centre 4 and on Nova cash expenditure of US$52.3m was incurred, net of working capital refunded by Dyas, prior to the asset being reclassified as held-for-sale.    Cash outflows in relation to Senegal pre-development of US$48.1m included FEED costs prior to FID formally approved in January 2020.

Capital expenditure on Oil and Gas Assets

* after opening IFRS 16 adjustment

Analysis of additions:

Exploration and appraisal asset additions in the UK & Norway include US$28.1m of costs for the four exploration wells that were completed in the year.  In LATAM, US$70.3m of costs relate to Mexico including drilling costs of the Alom-1 and Bitol-1 wells incurred during the year and US$7.5m were incurred in Suriname following the 2018 farm-in to the B61 licence.  The remaining LATAM additions were costs incurred in Nicaragua, though Cairn has subsequently withdrawn from the licences.

In the East Atlantic segment, US$15.2m was incurred following the completion of the farm-in to seven non-operated licences in Cote d'Ivoire and the balance on licence options in Mauritania and Ireland.

Senegal activities reflect the continuing work on development planning following the transfer of the operatorship of the licence to Woodside, with a small amount of exploration in the year as the Group acquired additional seismic.  Following development plan approval by the joint venture partners, volumes associated with the Phase I development have been promoted to reserves at the year end.  Accordingly, exploration and pre-development costs relating to the development area have been transferred to development assets at 31 December 2019.  Formal Government approval was received early January 2020. 

Development additions in the year totalling US$84.7m include the completion of development drilling on Kraken and related increases to the decommissioning asset and costs incurred on the Nova development.  Spend on Catcher was minimal during the period. 

Impairment reversal on Kraken producing asset

During 2019, production performance on Kraken has improved significantly and in addition the Operator has conducted more regular well testing to improve reservoir monitoring.   Consequently, Cairn has revised production profile estimates upward to reflect this improvement while also incorporating new volumes associated with the Worcester satellite field to be developed in 2020.  The upward revision of production profiles is an indicator that the impairment recorded in 2018 may have reversed or decreased.  Cairn has therefore run impairment tests and, despite a reduction in Group's long-term oil price assumption, down from US$70/bbl to US$65/bbl, the revised valuation of the Kraken asset is sufficient to reverse the prior-year impairment charge in full (after adjusting for the depletion charge avoided in the intervening period). Impairment tests conducted on the Catcher asset following the reduction in the long-term price assumption did not identify any impairment.

Impairment reviews were undertaken on the Group's remaining exploration/appraisal assets but no indicators of impairment were identified. 

A formal impairment test was performed on Senegal exploration/appraisal asset prior to transfer to development assets at the year end, as required under IFRS, but no impairment arose.  Cairn's impairment test assumes that full funding is in place to meet its net share of the development expenditure through to project completion. At the date of this report the Company is well progressed in agreeing terms for an expanded senior debt facility and is in discussions regarding additional sources of funding to support its Senegal development costs; however if these were to fail to conclude and the Group could not fully fund its share of the expenditure through to completion then the value of its investment in the project and/or its rights to participate in the project at its current equity levels may be affected which could trigger an impairment.

Impairment of Goodwill

Impairment tests on individual assets are performed before testing a cash-generating unit containing goodwill for impairment.  Therefore, the reversal of impairment on Kraken is recorded prior to the impairment test on the UK & Norway operating segment containing goodwill.  As a result of the Kraken reversal together with the reduction in the long-term oil price assumption and the lack of exploration success during the year, the impairment test performed annually on goodwill identified an impairment charge of US$79.0m on continuing operations.

Results for the year - Other operating income and expense

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

Pre-award costs reflects ongoing activity as Cairn seeks new opportunities to add to its portfolio of assets.  During the year, Cairn was awarded eight licences offshore Israel and is progressing further opportunities globally.

Norwegian unsuccessful exploration and appraisal costs are included within discontinued operations.  Unsuccessful exploration costs of US$38.7m include costs written off on the Lynghaug, Presto and Godalen wells offshore Norway of US$35.8m.  The balance of US$2.9m was expensed on other licences where no further exploration activities are planned. 

Unsuccessful exploration costs in continuing operations include the costs of the operated Chimera well in the UK North Sea of US$7.6m, partially offset by credits of US$1.7m on 2018 wells, and US$54.2m on the operated Alom-1 and Bitol wells offshore Mexico.  Further exploration costs written off include US$47.1m in Nicaragua and Ireland where Cairn has elected not to pursue exploration activities further.

Administration costs have reduced year-on-year, largely due to the prior year costs of the International arbitration relating to the Indian Tax dispute, where an award is currently expected in the summer of 2020. The loss on financial assets in 2019 reflects the mark-to-market valuation of Cairn's residual shareholding in Vedanta Limited.  No further share sales were instructed during the year.

Tax credits relating to operational and administration expenses reflect Norwegian current tax refunds receivable on qualifying exploration and administrative expenses and a small tax charge in Mexico.

Net finance costs of US$40.0m in 2019 include an exchange loss of US$9.1m (2018: exchange gain of US$17.0m), loan interest and charges of US$12.0m (2018:US$24.4m) on the RBL and EFF facilities and lease interest of US$15.3m (2018: US$7.8m) with the year-on-year increase on the latter reflecting the adoption of IFRS 16 and leases which were previously operating lease, now recognised as discounted liabilities on the balance sheet.

Taxation

The Group's opening deferred tax provision of US$66.5m at 1 January 2019 related entirely to the Norwegian assets.  On completion of the sale of a 10% working interest in Nova to Dyas, a deferred tax provision of US$35.4m was released.  Following the announcement of the sale of the entire share capital of Capricorn Norge the remaining provision of US$26.9m (after adjusting for exchange movements) was released in full, reflecting the change in the nature of recovery of the carrying value of the underlying assets from continued use to sale and the related tax consequence of this change. 

During the year, Cairn made a UK ring fence profit which was fully offset by brought forward losses. At 31 December 2019, Cairn had total UK ring fence losses of US$601.0m. All of the UK ring fence losses (at the applicable tax rate of 30%) and US$516.7m of supplementary charge tax losses (at the applicable tax rate of 10%, and activated UK investment allowance and decommissioning liabilities of US$577.5m and US$34.6m respectively) are recognised as deferred tax assets only to the extent they fully offset the deferred tax liabilities of US$303.6m. The remainder of the decommissioning liability represents an unrecognised deferred tax asset of US$105.2m at 31 December 2019.  

Resilience testing

In 2018 we retained an independent consultant, Critical Resource, to assess the resilience of economic returns from the Group's asset base under different climate change policy scenarios. For 2019 we have expanded the scope of work for Critical Resource in order to more fully assess the existing portfolio and our ongoing investment decisions under scenarios where demand for oil is significantly reduced over time in response to policies to reduce carbon emissions and minimise global warming. 

Critical Resource is an independent consultant advising on political, stakeholder and sustainability issues.  Based in London they specialise in provision of Group-level strategy and engagement services including climate change to extractive industries.  They maintain a network of over 200 experts and issue specialists drawing on intelligence from over 80 countries, from industry, investor, government, academic and NGO sectors with a strategic Senior Advisory Panel to provide input to them on emerging sustainable business issues.  

Using the International Energy Agency's climate modelling framework, Critical Resource has created multiple scenarios, including a Sustainable Development Scenario (SDS) which envisages a transition to a lower carbon economy well beyond current stated government policies, in order to meet the United Nations Sustainable Development Agenda and limit long term temperature rises to 1.5°C. The SDS sees global CO2 emissions at roughly half current levels by 2040, and global oil demand gradually falling from now to below half of current levels by 2050. 

Under the SDS, Critical Resource has also assessed the expected impact of different transition patterns: a smooth transition over time; a less disciplined transition that results in a steady oversupply of hydrocarbon energy sources; and a market shock scenario with a near term significant oversupply as a result of accelerated government policy changes. 

Critical Resource has translated each of these scenarios into an oil price impact, a country risk impact and a cost of capital impact, and we have modelled the effects on Cairn's existing asset base and future investment decisions. The results have then been compared with economic evaluations using the Group's base planning assumptions which are based on three year forward curve pricing for Brent followed by $65/bbl long term, as well as the group's downside case which tests all investment decisions for a base internal rate of return of at least 10% at long term $50bbl Brent. 

Under all of the SDSs prepared by Critical Resource, each of Cairn's existing assets is modelled to deliver returns in excess of our downside case of 10% internal rate of return threshold. We therefore remain confident that the Group's portfolio is resilient to energy transition policy changes and will remain relevant in a global economy that is expected to transition to lower carbon sources of energy. 

Investment decisions in our exploration acreage are also tested against the SDSs to ensure that successful discoveries will be viable under the projected oil demand and pricing scenarios at the time of expected development. Each of our current exploration commitments meets these criteria and all future drilling decisions will be tested against these scenarios to ensure we are targeting resources that can play a part in the global energy mix and will continue to attract capital in a world where demand for hydrocarbons may be materially below today's levels.