Capricorn Energy PLC Regulatory News (CNE)

FOR IMMEDIATE RELEASE 12 March 2019

CAIRN ENERGY PLC ("Cairn")

Full Year Results Announcement

For the year ended 31 December 2018

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

"Cairn plans a material exploration programme in 2019 targeting a billion barrels of gross resources, supported by cash flow from our production base. With active development projects within the portfolio, we look forward to additional sustained production and cash flow generation over the long term.

Cairn offers shareholders multiple catalysts for value creation. Our financial flexibility and continued focus on capital discipline ensure that the company remains strongly positioned to deliver an active programme."

2018 Summary

Ø Combined net production averaged ~17,500* boepd

Ø Oil and gas sales revenue US$396m, average realised price US$68 boe**; average production cost US$20.5 per mmboe

Ø Net cash inflow from oil and gas production US$229m

Ø Capital expenditure: cash outflow of US$252m***, remaining cash outflows post year end US$30m

Ø Year end Group cash US$66m; US$85m drawn under US$575m RBL facility

Ø Operating loss US$182m from the impairment of Kraken following downward revision in reserves; net loss after tax US$1.1bn resulting principally from write down of Cairn's investments in India

2019 Outlook

Ø Estimated net production of 19,000 to 22,000 bopd*; average production cost US$20/bbl

Ø Forecast capital expenditure US$300m***

Ø Senegal - SNE field development first phase on schedule. Targeting first oil 2022, gross production 100,000 bopd

Ø Norway - Nova field development on schedule. Targeting first oil 2021, peak gross production 50,000 bopd

Ø UK and Norway - up to four exploration wells (three Cairn operated) planned, targeting ~500 mmboe. The first well in the programme, Presto, spudded on March 1

Ø Mexico - three exploration wells (two Cairn operated) planned targeting ~500mmboe

Ø Hearings for Cairn's arbitration claim against India concluded in 2018; drafting of the award by the Tribunal is ongoing

*Before FlowStream's production entitlement of ~1,360 bopd in 2018; expected to be 1,350 to 1,575 bopd in 2019

**Before hedging costs of US$1.34 boe

***Net of Norwegian tax refund

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

Group 2P reserves increased during the year by 2.5 mmboe from 53.8 mmboe to 56.3 mmboe.

Production during the year depleted reserves by 6.4 mmboe and a downward revision of 6.8 mmboe (19%) in the Kraken reserve estimates was offset by Nova which was sanctioned during the year adding 15.2 mmboe.

Production

Catcher

Gross production from the Catcher Area (Cairn 20% WI) (comprising the Catcher, Varadero and Burgman fields) averaged 43,000 boepd in 2018. This reflected the field's ramp-up to plateau production rates in May following gas export commissioning and significantly increased plant availability during the second half of the year. Oil production from the Catcher FPSO continues to exceed nameplate capacity (60,000 bopd) and the JV has agreed with the FPSO provider to increase production from 60,000 bopd to 66,000 bopd (gross) on a reasonable endeavours basis. Reservoir performance to date has been good and analysis at year end 2018 has resulted in a slight increase in 2P reserves.

Cairn is working with the rest of the Catcher JV to optimise further investment in the Catcher area, including consideration of in-fill drilling and near-field opportunities to extend plateau production. A firm commitment has been made to drill an additional Varadero producer in 2020, with additional optional rig slots available for two further wells.

Kraken

Gross production from Kraken (Cairn 29.5% WI) averaged 30,300 boepd in 2018, which was below expectations. Production levels were most significantly affected by production system outages on the FPSO, weather-related incidents and higher water-cut than originally expected. Cairn is working with the field operator and FPSO contractor to achieve improvements in the uptime of the FPSO and a planned shut-down is scheduled later in 2019. Reservoir performance has been evaluated and at year end, Cairn's estimation of Kraken 2P reserves has been reduced to reflect current performance. This has resulted in an impairment of US$166.3m in the carrying value of the Kraken asset. The JV is evaluating further investment opportunities in the Kraken area to provide new drilling opportunities in 2020.

The DC4 subsea infrastructure was successfully installed in H2 2018. The three-well DC4 drilling programme is ongoing and remains on schedule with production onstream from the first DC4 well.

Developments

Senegal - SNE

In 2018 substantial progress was made on the SNE field multi-phase development (Cairn 40% WI) with a number of key milestones achieved. Our partner Woodside has now assumed the role of operator, as planned, and the JV is targeting a final investment decision in mid-2019 and first oil in 2022.

The SNE development concept is a stand-alone FPSO vessel facility with a capacity of ~100,000 bopd, with 23 subsea wells and supporting subsea infrastructure. It will be designed to allow subsequent SNE development phases, including options for gas export to shore and for future subsea tiebacks from other reservoirs and fields.

In January 2019, the JV received approval in principle for the technical basis of the SNE Development and Exploitation Plan and confirmation that the licence covering the SNE development area would be extended to allow for the conclusion of FEED and to mature financing activities during 2019 prior to Exploitation Licence award. Separately, the JV has submitted a request to the government for an extension of the licence area covering the FAN and SNE North/Spica exploration areas to undertake further evaluation.

The Environmental and Social Impact Assessment (ESIA) was submitted in 2018 and approved in January 2019.

Project finance has been successfully launched with detailed work underway on financing structures for the JV.

FEED activities for the subsea contract and for the FPSO facility have been awarded to Subsea Integration Alliance and MODEC International Inc, respectively. The FEED work involves undertaking activities required to finalise the costs and technical definition for the development to enable a final investment decision.

The JV is now planning to undertake a 3D high bandwidth seismic survey in Q2/3 2019. It is expected that the survey will improve reservoir definition to support development well placement.

Norway - Nova

The Nova (Cairn 20% WI) development in Norway is on schedule with first oil targeted in 2021 and expected to deliver peak production of 50,000 bopd (10,000 net to Cairn).

Cairn participated in the discovery of the Nova field in 2012, at the time known as Skarfjell. The field development is located in the Norwegian North Sea ~17km south west of the existing Gjøa field and is estimated to contain recoverable resources of ~80 mmboe.

The Plan for Development and Operation (PDO) was submitted by operator Wintershall to the Norwegian Ministry of Petroleum and Energy and approved in H2 2018.

Hydrocarbons from the Nova reservoir will be developed with a subsea tie-back connecting two templates to the nearby Gjøa platform for processing and export. Development execution activities are expected to commence mid-year 2019 for the initial modification work on the Gjøa platform.

ExplorationIn 2019 we have a programme of material exploration drilling opportunities across mature, emerging and frontier locations in Europe, West Africa and Latin America. We are planning up to seven wells targeting total gross volume of more than one billion barrels. In 2018 we acquired several new country interests in Suriname, Côte D'Ivoire and Mauritania adding further high impact volume potential to our asset base.

Mexico

Cairn holds three licences offshore Mexico, in Block 7 (Cairn 35% WI), Block 9 (Cairn operator 65% WI) and Block 15 (Cairn operator 50% WI) covering a total acreage position of 2,080 km2 in a highly prolific, yet under-explored region.

The first well in our Mexico programme will be drilled on Block 7, operated by ENI. The Operator is progressing all required permits. A site survey will compete shortly and well selection and preparations are well advanced to commence drilling in Q3 2019. An additional well is planned on Block 7 in 2020.

The second well will be on Block 9 and operated by Cairn. The exploration plan has been approved and a rig contract is in place with Maersk for the Maersk Developer Semi-Submersible Drilling Rig and a group services package with Schlumberger for onshore and supply base operations. Drilling operations are expected to commence in Q3 2019 targeting the Alom prospect, followed by an additional well targeting the Bitol prospect in Q4 2019 (also Cairn operated). This will be the third well in our Mexico programme.

On Block 15, the exploration plan was submitted in Q4 2018 and an environmental baseline survey completed in Q1 2019. Further evaluation of the block is ongoing.

UK & Norway

Cairn participated in four exploration wells in the UK & Norway region in 2018: PL682 (Cairn 30% WI) targeting the Tethys prospect in Q1, PL790 (Cairn 25% WI) containing the Raudåsen prospect in Q2, P2184 (Cairn operator 45% WI) targeting the Ekland prospect in Q4 and P1763 (Cairn 50% WI) containing the Agar discovery and Plantain prospect also in Q4.

Agar is estimated by the operator to hold recoverable resources of 15-50 mmboe. Further evaluation of the development options and broader exploration potential is ongoing. Cairn has the option to take over operatorship of future activity on the area.

Cairn was awarded three new licences in the Norwegian Petroleum Directorate's APA 2017 announced in Q1 2018, all non-operated with material equity positions, and one new non-operated licence in the APA 2018, PL418B. Cairn was also awarded five new licences, three as operator, in the UK Oil & Gas Authority's 30th Offshore Licensing Round in Q2 2018.

Plans are in place for four exploration wells in the UK/Norway region in 2019, three of which will be operated by Cairn. The first well in the programme, operated by Equinor, is Presto (Cairn 30% WI) which has commenced operations with the Transocean Spitsbergen rig on PL885 in the Norwegian North Sea.

The second well in the programme is expected to be Lynghaug, Cairn's first operated well in Norway. Lynghaug (Cairn 50% WI), licence PL758, is expected to spud in Q3 2019. Success in this well could lead to follow on exploration opportunities along the Nordland Ridge. Lynghaug will be drilled by the Transocean Arctic drilling rig.

The third well in the programme is Godalen (Cairn 40% WI) in licence PL842, Cairn's second operated well in Norway, which is expected to spud in Q4 2019. Godalen will also be drilled by the Transocean Arctic.

The fourth well in the programme is Chimera (Cairn 60% WI) in licence P2312 in the UK North Sea, Cairn's second operated well in the UK, which is expected to spud in Q4 2019. In Q4 2018, Cairn agreed to farm out a 40% WI in this licence to Suncor Energy UK.

Suriname

In 2018 Cairn was awarded an exploration agreement (Cairn operator 100% WI) on the largest block offshore Suriname by Staatsolie, the State Oil Company of Suriname. 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.

In December 2018, Cairn's ESIA was submitted and approved ahead of our initial planned 2D seismic acquisition commitment of 4,150km. 85% of this seismic programme has now been successfully completed with the remaining 15% expected to complete by the end of Q2 2019. Data processing will be ongoing for the remainder of this year.

Mauritania

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), subject to government and partner approvals. A ~7,000km2 seismic programme was completed in 2018 with final interpretation of data expected in H1 2019 after which a well decision will follow.

Côte d'Ivoire

In Côte d'Ivoire, Cairn has entered into the continental rift play with Tullow Oil. Cairn has agreed a farm-in for a 30%, non-operated, 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 2018, following which a 2D seismic survey is planned for 2019.

Republic of Ireland

In the Republic of Ireland, Cairn has an acreage position in the Porcupine Basin with an interest in two licences and two licence options over an area of ~4,000km2. Processing of the 3D seismic data set acquired in 2017 across LO 16/19 (Cairn operator 70% WI) and the adjacent LO 16/18 (Cairn 100% WI) is now complete.

India

Cairn commenced proceedings against India in 2015 following retrospective taxation actions undertaken by the Indian Income Tax Department ("IITD") in 2014. Final merits hearings for the arbitration concluded during 2018. Cairn's claim under the Treaty is for monetary compensation of ~US$1.4 billion, the sum required to reinstate the Company to the position it would have been in, but for the actions of the IITD since January 2014. The arbitration Panel is expected to issue a binding and internationally-enforceable award, and Cairn continues to have a high level of confidence in the merits of its claims in the arbitration.

Now that the merits submissions and hearings have concluded, the arbitration Panel is preparing its final award with respect to Cairn's claim under the Treaty. The Panel had originally guided the arbitration parties that it expected to issue an award expeditiously following the conclusion of the main merits hearings in The Hague held in August 2018. 

When the parties appeared before the Tribunal in December 2018, the Panel advised that it had not been able to advance the award as expected due to the number of procedural matters that had been brought before it since the August hearings, and that it is was not in a position at that time to give guidance to the parties on the expected timing of the issuance of the award. 

Cairn subsequently wrote to the Panel in February 2019 asking if it was then able to provide any guidance on timing, and the Panel has now responded that although it remains mindful of Cairn's need for a swift decision, given its workload and the number of matters before it, it is still unable to provide specific guidance on timing. As a result of this, Cairn expects that the timetable for issuing the award will be more protracted than originally anticipated and is unlikely to be before late 2019.

The Panel has said it will keep the parties updated regarding its progress. 

To date, the IITD has seized dividends due to Cairn from its shareholding in Vedanta Limited (VL) totalling approximately US$164m 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 year, the IITD seized proceeds from a 4.9% sale of Cairn's shareholding in VL, together with redemption proceeds on the VL preference shares, totalling US$713m. Following these sales, Cairn's retained holding in VL is now 0.1%. 

Board changes

Jackie Sheppard retired as a non-executive director of the Company at the year-end having served on the Board since 2010. Alexander Berger, non-executive director, has served on the Board for nine years and has advised the Company that he will not be seeking re-election at the Annual General Meeting in May 2019. He will therefore retire from the Company on that day.

Cairn would like to thank both Jackie and Alexander for their excellent contributions to the Board during their years of service to Cairn. The Company is currently engaged in a recruitment process to appoint two non-executive directors, at least one of whom will be female.

Outlook

Cairn looks forward to a number of potentially material near-term exploration drilling opportunities, supported by established cashflows from producing assets and sustained by assets entering the development phase. The Company is fully funded for all committed expenditure, and continues its focus on delivering value for its stakeholders within the constant of a responsible and safety focused strategic offering.

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 2018

Cairn has assessed the principal risks and uncertainties at the end of 2018 and concluded that the principal risks identified at H1 2018 remain relevant. The principal risks are:

· Lack of exploration success

· Volatile oil and gas prices

· Securing new venture opportunities

· Delay in Senegal development plan approval

· Kraken and Catcher operational and project performance

· Reliance on JV operators for asset performance

· Health, safety, environment and security

· Fraud, bribery and corruption

· Inability to secure or repatriate value from India

· Political and fiscal uncertainties

· Access to debt markets

The Group has also considered the potential impacts from Brexit and concluded that Cairn is unlikely to be materially affected. The Group recognises that there are a number of uncertainties around Brexit, including the potential impact on EU nationals employed by the Cairn Group. The Group continues to monitor the situation closely.

Financial Review

Key Statistics

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

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

3 Excluding hedging costs of US$1.34/boe

4 Production costs include cost of sales plus finance lease repayments on the Kraken FPSO

Production

2018 marked the first full year of production from the Group's two UK North Sea producing assets. Production on Kraken commenced in June 2017 and Catcher came on stream late December 2017. During 2018, daily gross production volumes on both assets have increased significantly, with Kraken averaging 30,300 boepd and Catcher 43,000 boepd across the year. Combined production for 2019 is expected to average 19,000 - 22,000 beopd net to Cairn, before adjusting for the FlowStream entitlement.

Revenue

Revenue from the sale of oil and gas was US$387.9m for the year ending 31 December 2018, after adjusting for hedging transactions. Release of deferred revenue of US$21.2m and royalty income in Mongolia of US$1.2m, gives total revenue to US$410.3m.

At 31 December, Cairn had hedged ~2.7 mmbbls of forecast production through 2019 using collar structures with a weighted average floor of US$67.1 per bbl and an average ceiling of US$83.1 per bbl and a further ~0.5 mmbbls of 2020 forecast production with a floor and ceiling of US$67.5 and US$87.5 per bbl respectively. With a year end oil price of US$50.7 per bbl, the fair value of the hedge options held by Cairn has increased significantly at the year end giving rise to financial assets of US$44.4m at the balance sheet date with unrealised gains of US$43.9m recorded through other comprehensive income, offset by losses on settled options.

Cost of sales

Total production costs of US$131.4m include US$59.5m of operating and variable lease payments on the Catcher and Kraken FPSOs respectively. All Catcher lease payments are charged direct to production costs as operating lease charges. Following acceptance of the Kraken FPSO in H2 2018, lease payments are separated into variable and fixed components, with the latter being calculated based on minimum charges in the lease agreement and being deducted against the lease liability on the Balance Sheet. If all lease payments are included as operating costs, production costs were US$20.49/boe. Effective 1 January, Cairn will adopt IFRS 16 resulting in recognition of Catcher minimum lease commitments as an asset and liability on the Balance Sheet, aligning the accounting with that of the Kraken FPSO.

Movements in oil inventory and underlift positions, measured at market value, of US$7.7m were charged against cost of sales in the period. The Group's accounting for revenue and the classification and measurement of underlift is unaffected by the implementation of IFRS 15.

Depletion and amortisation charges in the year were US$171.2m calculated on a unit-of-production basis on closing year end reserve estimates.

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

Net cash inflow from operating activities for the year of US$209.0m reflects net cash generated from oil and gas sales after deducting administrative costs and pre-award costs. Adding back these expenses leads to a net cash inflow from oil and gas production of US$228.9m in the year.

Net cash outflow for the Year

1Net cash flow from operations includes cash flows from sale of oil and gas and includes all lease payments (including US$7.4m repayment of the Kraken FPSO lease liability) and excludes the tax refund on operating activities.

2Exploration expenditure represents investing cash outflow of US$188m excluding US$58.6m of pre-development spend on Nova and SNE assets disclosed separately and offset by US$3.6m exploration asset disposal proceeds and US$5m of other operating income.

3Development expenditure includes investing cash outflows of US$109.5m net of finance lease reimbursements of US$4.7m.

4Cash balances of US$66.3m less drawings under the Reserve-Based Lending facility of US$85m

Cairn had net debt of US$18.7m at 31 December 2018, representing a net cash outflow of US$105.2m over the year. Borrowings under the Group's RBL facility at 31 December 2018 were US$85m, all drawn in the year, before adjusting for unamortised facility fees and accrued interest for disclosure in the Financial Statements. Closing net cash and long-term borrowings presented above exclude US$26.2m drawn under the Norwegian Exploration Finance Facility which are advances secured against tax refunds due from the Norwegian government and are not a true reflection of the Group's long-term indebtedness.

In December 2018, Cairn completed the extension of the maturity of the Group's US$575m RBL facility to 2025, increasing the borrowing base to include the Nova development in Norway. Though the terms of the extended facility are consistent with that of the original, under IFRS 9 the extension is 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. Arrangement fees associated with the original facility, which was put in place in 2014, have been fully amortised in the year. The Exploration Finance Facility in Norway was also extended in December 2018, but the application of IFRS 9 has no material impact.

Cash outflows on exploration expenditure in the year included UK & Norway costs of US$41.3m relating to the Tethys, Raudåsen and Agar-Plantain wells in Norway and US$26.1m of pre-development activities on Nova prior to approval of the development plan and subsequent transfer of costs to development assets. Senegal costs of US$38.1m include US$32.5m of pre-development exploitation costs. Transfer of operatorship of the Senegalese licences to Woodside concluded in December.

Development and producing asset cash outflows in the year related to costs on Kraken, Catcher and Nova.

Oil and Gas Assets

Analysis of additions by region is as follows:

Pre-development additions relate to the SNE asset currently classified in exploration and appraisal assets and Nova which was transferred to development/producing assets during the year. These costs are included in exploration and appraisal additions though they relate to work on the exploitation plan and development of the field. Costs are only included within development and producing assets in the Financial Statements once the field development plan has been approved.

In the UK & Norway, costs incurred in the year on the Tethys, Raudåsen, Ekland and Agar-Plantain wells were US$58.2m with a further US$18.1m of additions across the remaining exploration licences in the portfolio.

Total costs of US$39.5m were incurred on the Nova field during the year. US$25.9m are included in exploration and appraisal assets and a further US$13.6m in development and producing assets after formal approval of the development plan was received.

Remaining development and producing asset additions in the year of US$42.9m on Kraken and Catcher include the release of accruals for rig costs relating to Kraken of US$23.0m following renegotiation of the rig contract early in 2018.

Impairment charge

At year end, Cairn has reviewed its exploration and appraisal and its development and producing assets for indicators of impairment and performed impairment tests where indicators were identified. With up to 18 months of performance history now available, the remaining oil and gas reserves and production profiles have been reassessed, resulting in an impairment charge of US$166.3m arising on the UK Kraken asset. No impairment charge has been recognised in relation to the Catcher asset.

The Group's oil price assumptions remain based on the Brent forward curve for the first three years of the forecast period, followed by US$70 per barrel long term. Sensitivity analysis included in the Financial Statements includes down-side oil price sensitivities across all development and producing assets and down-side production volume sensitivities run on the Kraken asset.

Results for the year - Other operating income and expense

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

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

Unsuccessful exploration costs of US$63.6m, primarily relating to the UK & Norway region, include costs written off on Tethys, Raudåsen and Ekland unsuccessful wells of US$50.4m and US$8.0m on the Sunbeam licence where the commitment for an exploration well has been transferred and no further exploration activities are planned. These were offset by a US$15.4m credit following the release of accruals relating to relinquished licences in Morocco.

Higher administrative costs resulted principally from increased costs relating to the Indian tax arbitration, brought under the UK-India Bilateral Investment Treaty, for which the final hearings took place in The Hague during the year. Total costs, charged to the Income Statement, associated with the India tax arbitration were US$22.9m and included legal fees for submissions and the hearings as well as associated costs (2017 Indian tax arbitration costs were US$8.1m, principally relating to legal costs for pre-hearing submissions made in that year). Remaining administrative costs of US$27.5m have increased by US$2.9m year-on-year, giving total administrative costs of US$50.4m for the year.

Finance income includes exchange gains in the current year of US$17.2m. Finance costs in the period include loan interest and facility fees on the Group's RBL facility and Exploration Financing Facility of US$24.4m and finance lease interest of US$7.8m.

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 the Group's shares in Vedanta Limited in the year, instructed by the IITD, resulted in a loss on derecognition of US$713.1m following seizure of the proceeds. The resulting tax liability on the sale, for which Cairn remains liable, has been sheltered by available losses. Cairn retains an immaterial shareholding in Vedanta Limited, with a value of US$6.9m at 31 December 2018.

Dividends declared by Vedanta Limited and due to Cairn in the period of US$67m, which were also seized by the IITD, are not recorded in the results for the year. Total dividends seized by the IITD are now US$164.2m.

Following the adoption of IFRS 9 "Financial Instruments" Cairn's investment in Vedanta Limited 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 year, a fall in the market value of Vedanta Limited has resulted in a US$352.2m 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.

Under the UK-India Bilateral Investment Treaty, Cairn is seeking compensation for losses resulting from the seizure by India in 2014 of Cairn's investment in Cairn India Limited (which subsequently became the investment in Vedanta Limited).

Taxation

During 2018, Cairn made a UK ring fence profit in the period which was fully offset by brought forward losses. At 31 December 2018, Cairn had total UK ring fence losses of US$928.3m. US$810.3m of ring fence tax losses are recognised as deferred tax assets (at the applicable tax rate of 40%) to fully offset deferred tax liabilities of US$243.1m. The remaining ring fence tax losses of US$118.0m, available supplementary charge tax losses of US$855.9m and the deferred tax impact of the decommissioning liability represent an unrecognised deferred tax asset of US$168.0m at 31 December 2018.

A cash tax refund is receivable in Norway in respect of 78% of qualifying exploration and overhead spend. US$32.8m of tax refunds are recorded for amounts receivable relating to the current period. Norwegian deferred tax liabilities at 31 December 2018 of US$66.5m 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 the majority of the Group's interest in Vedanta Limited, 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 Vedanta Limited shareholding, together with movements in the share price have led to a full reversal of US$89.4m of the opening deferred tax liability in respect of the shareholding.

Glossary

bbl barrel of oil

bn billion

boe barrels of oil equivalent

boepd barrels of oil equivalent per day

bopd barrels of oil per dayESIA Environmental and Social Impact Assessment

FEED front-end engineering design

FPSO floating production storage and offloading facility

JV joint venture

m million

mmbbls million barrels of oil

mmboe million barrels of oil equivalent

RBL Reserves Based Lending facility

WI working interest 

Cairn Energy PLC

Group Income Statement

For the year ended 31 December 2018

Group Statement of Comprehensive Income

For the year ended 31 December 2018

Cairn Energy PLC

Group Balance Sheet

 As at 31 December 2018

Cairn Energy PLC

Group Statement of Cash Flows

For the year ended 31 December 2018

Cairn Energy PLC

Group Statement of Changes in Equity

For the year ended 31 December 2018

* See notes 1.1b and 1.3 for details of changes in accounting policy as a result of the adoption of IFRS 9.

Section 1 - Basis of Preparation

1.1 Significant Accounting Policies 

a) Basis of preparation

Cairn prepares its Financial Statements on a historical cost basis, unless accounting standards require an alternate measurement basis. Where there are assets and liabilities calculated on a different basis, this fact is disclosed either in the relevant accounting policy or in the notes to the Financial Statements. The Financial Statements comply with the Companies Act 2006 as applicable to companies using International Financial Reporting Standards ('IFRS').

The financial information contained in this announcement does not constitute statutory accounts as defined in Section 434 of the Companies Act 2006. However, the Financial Statements contained in this announcement are extracted from audited statutory accounts for the financial year ended 31 December 2018, which will be delivered to the Registrar of Companies. Those accounts have an unqualified audit opinion.

The Group's Financial Statements are prepared on a going concern basis.

b) Accounting standards

Cairn prepares its Financial Statements in accordance with applicable IFRS, issued by the International Accounting Standards Board ('IASB') as adopted by the EU, and interpretations issued by the International Financial Reporting Interpretations Committee ('IFRIC'), and Companies Act 2006 applicable to companies reporting under IFRS. The Group's Financial Statements are also consistent with IFRS as issued by the IASB as they apply to accounting periods ended 31 December 2018.

Effective 1 January 2018, Cairn has adopted the following amendments to standards:

- Amendments to IAS 28 'Investments in Associates and Joint Ventures'

- Amendments to IFRS 2 'Share Based Payments'

- IFRS 9 'Financial Instruments'

- IFRS 15 'Revenue from Contracts with Customers'

In addition, Cairn has early adopted the following interpretation issued by IFRIC:

- IFRIC 23 'Uncertainty over Income Tax Treatments'

The following standard, issued by the IASB and endorsed by the EU has yet to be adopted by the Group:

- IFRS 16 'Leases' (effective 1 January 2019)

IFRS 9 'Financial Instruments'

The adoption of IFRS 9 'Financial Instruments' on 1 January 2018 resulted in the re-classification of the Group's available-for-sale financial assets as financial assets held at fair value through profit or loss. Fair value gains and losses on the financial assets are now reflected through the Income Statement rather than Other Comprehensive Income. IFRS 9 also required the change in fair value relating to the time value of an option, designated for hedge accounting, to be recorded in Other Comprehensive Income; previously Cairn had recorded such movements through the Income Statement. Both these changes have been applied fully retrospectively and result in the restatement of comparative information, details of which can be found in note 1.3.

Other standards and amendments effective 1 January 2018

The 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 Financial Statements. Relevant accounting policies have been reviewed and updated to reflect adoption of IFRS 15 but given that Cairn's customers are clearly identified, the performance obligations easily identifiable and the price readily determinable, the changes to policies have no impact on the resulting accounting.

IFRIC 23 'Uncertainty over Income Tax Treatments'

Cairn has chosen to adopt IFRIC 23 in advance of its effective date of 1 January 2019. This interpretation provides guidance on how uncertain tax treatments should be addressed and requires an entity to assess the probability of an uncertain tax position being accepted by the relevant taxation authority. The interpretation has been applied in calculating Cairn's unused tax losses disclosed in the notes to the Financial Statements. The prior year impact of adoption is not material and comparative disclosure has not been amended.

IFRS 16 'Leases'

IFRS 16 introduces a single lessee accounting model and requires a lessee to recognise assets and liabilities for all leases with a term of more than 12 months, unless the underlying asset is of low value. A lessee is required to recognise a right-of-use asset representing its right to use the underlying leased asset and a lease liability representing its obligation to make lease payments.

Section 1 - Basis of Preparation (continued)

1.1 Significant Accounting Policies (continued)

b) Accounting standards (continued)

In assessing the impact of IFRS 16, Cairn has identified the following assets where right-of-use assets and lease liabilities will be recognised on adoption:

- Accounting for the FPSO on the UK Catcher development/producing asset; and

- Accounting for non-cancellable leases of the Group's office premises in Edinburgh, London, Stavanger and Mexico City.

All other leases are either for periods of less than one year or have less than one year remaining on the date of adoption or are for low-value items which have no material impact on the Group's Financial Statements. Additional disclosure will be provided in the 2019 Financial Statements relating to these leases where material.

The Catcher FPSO is classified as an operating lease under the current accounting standard. Under IFRS 16 Cairn will recognise a right-of-use asset and lease liability for the vessel based on the minimum lease commitment over the expected charter period. On initial adoption of IFRS 16, Cairn will recognise a lease liability of US$147.5m and a corresponding right-of-use asset. Forecast minimum lease payments of US$33.9m in 2019 will reduce the lease liability rather than be charged against profit as a lease charge. Forecast finance lease interest charges on the Catcher FPSO for 2019 are US$7.2m. Variable lease charges in excess of the minimum commitment will continue to be charged against profit. The right-of-use asset will be amortised on a unit-of-production basis consistent with the Group's other development/producing assets. In the Cash Flow Statement, minimum lease payments relating to the Catcher FPSO will be classified as financing cash flows; currently they are included in operating cash flows. Variable lease payments shall remain in operating cash flows.

There is no change in accounting for the Kraken FPSO which is currently accounted for as a finance lease.

The Group's leasehold property will be measured based on the lease liability remaining on adoption of IFRS 16. The Group expects to recognise lease liabilities of US$10.0m and corresponding right-of-use assets for the same amount. The assets will be amortised on a straight-line basis over the remaining life of the lease. Again, cash flows will be re-classified as financing rather than operating cash flows.

Cairn are continuing to assess accounting for leases held through joint operations, particularly where the operator enters into a lease agreement on behalf of the joint operation but where the joint operators are not direct parties to the lease agreement. Assessing whether such contracts will be treated as a lease by Cairn, as a non-operator, is likely to be highly judgemental with assumptions and other considerations based on the right of substitution by the operator and the reasonable certainty of leases being extended beyond an initial period.

Details of current finance leases can be found in note 3.4, while current operating lease commitments are disclosed in notes 2.1, 2.5 and 4.2 as they relate to operating costs, intangible exploration/appraisal assets and property, plant & equipment - development/producing assets, and administrative expenses respectively. A reconciliation of operating lease commitments at 31 December 2018 to the opening lease liabilities on adoption of IFRS 16 is as follows:

Section 1 - Basis of Preparation (continued)

1.1 Significant Accounting Policies (continued)

c) Annual report and accounts

Full accounts are due to be made available on the Company's website in April 2019 and will be available at the Company's registered office, 50 Lothian Road, Edinburgh, EH3 9BY. The Annual General Meeting is due to be held on Friday 17 May 2019 at 12 midday.

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 and Audit Committee considered the Group cash flow forecasts under various scenarios, identifying risks and mitigants and ensuring the Group has sufficient funding to meet its current 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

At 1 January 2017, the opening available-for-sale reserve has been transferred to retained earnings following the change in accounting policy for financial assets. The adoption of IFRS 9 has no other impact on the assets or liabilities recorded and presented in the Group's 2016 year end Balance Sheet.

Section 2 - Oil and Gas Assets and Operations

2.1 Gross Profit: Revenue and Cost of Sales

Revenue

Cairn receives revenue from its producing assets in the UK North Sea, Kraken and Catcher. Both assets commenced production during 2017. On Kraken, where only oil is sold, Cairn takes a full lifting of crude on a scheduled basis to reflect the Group's working interest. On Catcher, Cairn receives its working interest percentage share of each lifting of crude and the Group's working interest share of gas sales. Payment terms are within 30 days.

Sales volumes during the year averaged ~16,000 boepd for the two assets combined, realising an average sales price of US$67.99/bbl.

Commodity price hedging

During 2018, Cairn realised losses on hedge options of US$8.0m through the first 10 months of the year as the oil price exceeded the ceiling on several hedge contracts. This was offset by gains of US$0.2m as the oil price fell back in November and December below the US$60/bbl floor on one hedging contract. Hedging losses are recycled to the Income Statement from Other Comprehensive Income when the option matures.

Details on the Group's hedging position at 31 December can be found in note 3.6.

Cost of sales

Inventory of oil held at the year end is recorded at a market value of US$8.2m (2017: US$10.4m). Underlift adjustments on Kraken production volumes were US$0.1m (2017: US$5.6m) at 31 December 2018. Variable finance lease costs on the Kraken FPSO of US$22.7m (2017: US$6.0m), see note 3.4, are charged to the Income Statement with US$36.8m (2017: US$1.0m) of operating lease charges on the Catcher FPSO.

Operating lease commitment

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

Following adoption of IFRS 16 on 1 January 2019, accounting for the Catcher FPSO will change with a lease liability and right-of-use asset being recorded on the Balance Sheet. See note 1b for further detail.

Section 2 - Oil and Gas Assets and Operations (continued)

2.2 Intangible Exploration/Appraisal Assets

Senegal

All costs relating to Cairn's exploration and appraisal drilling in Senegal remain capitalised within intangible exploration/appraisal assets pending the Final Investment Decision expected during 2019.

Additions in the year, all funded through cash and working capital, include US$24.3m on exploitation and pre-development costs, with the remaining US$4.2m relating to exploration activities. The phased Field Development and Exploitation Plan has been submitted to the Government of Senegal, with first production targeted in 2022. Woodside have assumed the role of development operator as planned.

UK & Norway

In October 2018 approval was received, from the Norwegian Ministry of Petroleum and Energy, for the development and operation plan ('PDO') for the Nova development. Costs of US$115.7m were transferred from intangible exploration/appraisal assets to property, plant & equipment - development/producing assets during the year.

Additions in the current year of US$102.2m include US$25.9m incurred on Nova pre-development activities prior to re-classification as a development asset. Well costs incurred in the year were US$18.2m for the P1863 Agar-Plantain well and US$16.7m for the P2184 Ekland well in the UK North Sea. In the Norwegian North Sea US$17.1m was incurred for the PL682 Tethys well and US$6.2m for the PL790 Raudåsen well. Further costs of US$18.1m were incurred across the Group's other licences in the UK & Norway region. Total additions funded through cash and working capital were US$104.9m, offset by a release of US$2.7m of provisions for well abandonment costs.

The Tethys, Ekland and Raudåsen wells were unsuccessful and related costs of US$27.5m, US$14.6m and US$8.3m respectively were charged to the Income Statement in 2018. Remaining unsuccessful costs of US$12.2m include US$8.0m relating to the P2077 Sunbeam licence where the well commitment has been transferred and the joint operators plan to relinquish.

Portfolio turnover in the UK & Norway during the year has resulted in the addition of three new licences in Norway, with three relinquished and one disposed of; and six new licences in the UK, with two relinquished. Cairn has also entered into a farm-out agreement for a 40% non-operated interest in Licence P2312 containing the Chimera prospect. This is conditional upon regulatory consent.

The net book value of exploration/appraisal assets remaining capitalised at the year end of US$77.2m includes costs of US$35.9m relating to discovered resource across two fields: the current year Agar discovery (US$18.2m) and the Laverda discovery (US$17.7m), both in the UK North Sea. The remaining US$41.3m of costs have been incurred across further exploration licences in the UK and Norwegian North Sea, the Norwegian Sea and the Barents Sea.

Section 2 - Oil and Gas Assets and Operations (continued)

2.2 Intangible Exploration/Appraisal Assets (continued)

International

All additions in the year were funded through cash and working capital.

Ireland

During 2018 exploration additions of US$6.1m were incurred principally across two licences; LO16/18 and LO16/19. Unsuccessful costs of US$0.9m were incurred on other licences in Ireland. Total costs capitalised at the year end were US$14.8m.

Mexico

Three exploration wells are planned in shallow water in the Gulf of Mexico commencing in the second half of 2019. Two wells are planned in Block 9, with costs of US$11.9m incurred in 2018. The third well is planned to be drilled in Block 7, with costs of US$3.4m incurred during the year. A further US$2.6m was incurred on Block 15 during 2018. Total costs capitalised in Mexico were US$31.0m at the balance sheet date.

Western Sahara

Following the close out of licences, remaining accruals for US$15.4m have been released and are credited against additions and reverse prior-years' unsuccessful exploration costs charges. No costs remain capitalised.

Others

The remaining additions and carrying value within International assets of US$9.1m relates to licence acquisition and seismic costs on new licences.

Impairment review

At the year end, Cairn reviewed its intangible exploration/appraisal assets for indicators of impairment. Indicators were identified where future exploration plans remain uncertain or where the carrying value of assets relating to discovered resource may not be fully recovered through future development and production. Subsequent impairment tests performed did not identify any impairment.

2.3 Property, Plant & Equipment - Development/Producing Assets

Section 2 - Oil and Gas Assets and Operations (continued)

2.3 Property, Plant & Equipment - Development/Producing Assets (continued)

Exploration/appraisal costs relating to Nova were transferred to development assets after testing for impairment - see note 2.2. During Q4 further development costs of US$13.6m were incurred in relation to the field.

The UK Kraken and Catcher fields ramped up production during 2018 with gross production of 30,300 and 43,000 boepd respectively. Combined depletion charges for the year were US$153.0m (2017: US$17.4m).

Kraken additions represent development activity spend of US$31.8m (2017: US$100.0m), all funded through cash and working capital, which was offset by a US$23.0m reversal of accruals following the successful renegotiation of the development drilling rig contract. During 2017, there was a further US$9.6m of non-cash decommissioning asset increases. The decommissioning asset remains unchanged in 2018.

On Catcher, additions funded through cash and working capital during the year were US$28.8m (2017: US$83.9m) with further non-cash additions of US$5.3m (2017: US$19.0m) relating to the increase in the Catcher decommissioning asset.

Leased assets

During 2017, US$200.8m, the net present value of future minimum lease payments was recorded on the Balance Sheet for the Kraken FPSO, as a right-of-use producing asset. Further additions in 2017 of US$4.1m represent the recognition of a decommissioning asset associated with the FPSO. Subsequent to initial recognition, the lease agreement was amended which reduced the finance lease liability by US$36.4m and a corresponding reduction to the leased production asset.

In the second half of 2018, the lease agreement was further amended resulting in a reduction of the lease liability and right-of-use asset by US$11.5m - see note 3.4.

Amortisation of US$18.2m (2017: US$3.4m) was charged against the FPSO in the year.

Impairment review

At the year end, impairment tests were conducted on the Group's UK & Norway development/producing assets, resulting in an impairment charge of US$166.3m on the UK Kraken producing asset. No impairment arose on either Catcher or Nova. Sensitivity analysis on the Group's impairment charge can be found in note 2.6. The impairment on Kraken reflects performance of the field to the balance sheet date that is below expectations and has led to a reserves downgrade at the year end.

During 2017, impairments of US$23.0m were reversed due to an increase in the volume of oil reserves estimated to be recoverable through production on Catcher. All previous impairments recorded on the Catcher development/producing asset have been fully reversed.

2.4 Provisions - Decommissioning

The decommissioning provisions represent the present value of decommissioning costs related to the Kraken and Catcher development/producing assets. The provisions are based on operator cost estimates, subject to internal review and amendment where considered necessary and are calculated using assumptions based on existing technology and the current economic environment, with a discount rate of 2% per annum (2017: 2%). The reasonableness of these assumptions is reviewed at each reporting date to take into account any material changes required. No provision is required at the year end for development activities undertaken on Nova.

The decommissioning provisions represent management's best estimate of the obligation arising based on work undertaken at the balance sheet date. Actual decommissioning costs will depend upon the prevailing market conditions for the work required at the relevant time.

Section 2 - Oil and Gas Assets and Operations (continued)

2.4 Provisions - Decommissioning (continued)

During the year, the decommissioning estimate for Catcher increased by US$5.3m. The Kraken decommissioning estimate remained unchanged.

The decommissioning of the Group's development/producing assets is forecast to occur between 2026 and 2040.

2.5 Capital Commitments

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 include US$35.5m for operations in the UK & Norway. The remaining US$110.6m includes US$38.7m of commitments in Senegal and US$71.9m on International assets, predominantly relating to Mexico.

The capital commitments for property, plant & equipment - development/producing assets relate principally to Nova and exclude the costs of the Kraken FPSO finance lease obligations, which are disclosed in note 3.4.

Cairn enters into operating leases both at a corporate level and together with partners through its interests in joint operations. Operating lease costs for items directly attributable to oil and gas exploration and development activities, such as drilling rigs, are capitalised within intangible exploration/appraisal assets or property, plant & equipment - development/producing assets as appropriate.

At the year end, Cairn had the following operating lease commitments relating to oil and gas exploration, appraisal and development activities including commitments for leases that are yet to commence. These amounts are also included in total capital commitments above and exclude operating lease commitments relating to producing activities.

The Group has no further material capital expenditure committed at the balance sheet date.

Section 2 - Oil and Gas Assets and Operations (continued)

2.6 Impairment Testing Sensitivity Analysis

UK & Norway

At 31 December 2018, impairment tests were conducted on the Group's development/producing assets, on goodwill and on certain exploration/appraisal assets where indicators of impairment were identified.

The recoverable amount for all assets is based on fair value less costs of disposal estimated using discounted cash flow modelling. The key assumptions used in determining the fair value are often subjective, such as the future long-term oil price assumption, or the operational performance of the assets. With Cairn's two North Sea producing assets completing their first full year of production, reserve estimates have been updated to reflect the performance of fields to the balance sheet date, which have either been in line or exceeded pre-drill estimates for the Catcher asset but have been below expectations for the Kraken asset where performance issues with the FPSO have led to lower than expected daily production volumes. Following a downgrade of recoverable reserves in place at the year end, an impairment charge has been recorded on the Kraken asset of US$166.3m.

Cairn has run sensitivities on its long-term oil price assumption of US$70/boe, using alternate long-term price assumptions of US$65/boe and US$60/boe and a long-term assumption equal to the forward curve price at the end of the Group's three-year short-term assumption period (US$66.3/boe). These are considered to be reasonably possible changes for the purposes of sensitivity analysis.

There was no impairment of the Group's exploration/appraisal assets under any of the sensitivities run. The impact of these changes on the impairment recorded on the Group's development/producing assets together with the impairment that would arise on goodwill at the balance sheet date is summarised below:

All impairment arising on development/producing asset sensitivities relates to the Kraken asset and the numbers above would replace the current impairment charge of US$166.3m.

The Group's proved and probable and contingent reserve estimates are based on P50 probabilities. P10 and P90 estimates are also produced but would not provide a reasonable estimate to be used in calculating the fair value of the Group's assets. The reserve estimates are incorporated into production profiles which include assumptions on the performance of the asset. Cairn's current assumptions imply a maximum uptime for producing assets of 85%-90%.

Further sensitivity analysis was performed on the Kraken asset reducing forecast production volumes and associated operating costs by 5% and 10%, as an approximation of a reduction in the uptime of the asset, which are seen as reasonably possible alternatives. With this reduced production, the following impairment charges would arise on development/producing assets (no impairment arises on goodwill):

No sensitivities have been performed on Catcher production volumes where performance has been either in line or ahead of expectations. Therefore there is no evidence to suggest that reduced production levels would be a reasonably possible alternative assumption to apply.

Senegal

The Group's exploration assets in Senegal have been tested for impairment as a single cash generating unit. No impairment was recorded. Downside sensitivity analysis performed on reasonably possible changes in assumptions, including the Group's oil price assumption using the sensitivities above, did not identify any impairment.

Section 3 - Financial Assets, Working Capital and Long-term Liabilities

3.1 Financial Assets at Fair Value through Profit or Loss

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.

In April 2017, Cairn India Limited underwent a merger with Vedanta Limited as a result of which the Group held both equity shares and redeemable preference shares in Vedanta Limited. Prior to that date the Group held a 9.8% stake in Cairn India Limited via equity shares, the market value of which at the time of the merger was US$819.7m. The market value of the Vedanta shares on the merger date was US$786.7m, resulting in a loss on derecognition of financial assets of US$33.0m.

Between May and October 2018 the IITD instructed sales of 99% of Cairn's equity shareholding in Vedanta Limited and seized the proceeds of US$608.8m. Shares were sold in multiple transactions at prices ranging from INR 286.83 (US$4.25) per share down to INR 229.68 (US$3.23) per share. The IITD also seized the proceeds of US$104.3m on the redemption of the preference shares in October 2018. Cairn is currently restricted from selling its remaining shares in Vedanta Limited. See note 5.5.

The remaining listed equity shares held at 31 December 2018 in the ordinary share capital of Vedanta Limited, 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.

3.2 Cash and Cash Equivalents

Cash and cash equivalents earn interest at floating rates. Short-term investments are made for varying periods ranging from instant access to unlimited, but generally not more than three months depending on the cash requirements of the Group.

Cairn invests surplus funds into high-quality liquid investments, including money market funds, short-term bank deposits and tri-party repurchase transactions ('repos'). Cairn limits the placing of such funds and other investments to banks or financial institutions that have ratings of A- or above from at least two of Moody's, Standard & Poor's or Fitch, unless a sovereign guarantee is available from a AAA-rated government. The counterparty limits vary between US$50.0m and US$200.0m depending on the ratings of the counterparty. No investments are placed with any counterparty with a five-year credit default swap exceeding 250 bps. Investments in money market liquidity funds are only made with AAA rated liquidity funds and the maximum holding in any single fund is 5% of total investments. Where investments are made in repos, collateral is fixed income debt securities with a minimum rating of BBB- which is managed by Euroclear. No adjustment is made to the counterparty credit rating to reflect the collateral held when assessing investment options. The Group's Treasury function manages the credit risk associated with such investments.

Section 3 - Financial Assets, Working Capital and Long-term Liabilities (continued)

3.3 Loans and Borrowings

Cairn has two loan facilities at the year end; the Reserve-Based Lending ('RBL') facility available to several Group companies and the Norwegian Exploration Finance Facility ('EFF').

Debt arrangement fees relate to both the RBL (US$9.5m) and the EFF (US$0.9m). Foreign exchange differences related entirely to the EFF.

RBL

The Group's RBL facility had cash drawings of US$85.0m at 31 December 2018, all advanced in the year.

Cairn has signed an extension to its existing RBL facility with a syndicate of international banks. The extension became effective on 20 December 2018 and brought the Nova asset into the borrowing base. 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 31 December 2025.

Under IFRS 9, the extension of the facility to December 2025 constitutes substantially different terms from the original and as such the financial liability relating to the original facility was extinguished on the date of the extension and replaced with a new liability based on the revised terms. This resulted in the acceleration of the amortisation of borrowing costs relating to the previous facility, resulting in a charge of US$15.1m to the Income Statement in the year.

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$210.0m 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$250m.

EFF

As at 31 December 2018, US$27.1m (NOK 233.8m) was drawn under the Norwegian EFF. The maximum available amount is currently forecast to be US$59.0m (NOK 446.3m). During the year, US$32.4m was drawn under the facility and US$31.2m repaid following receipt of the tax refund.

Section 3 - Financial Assets, Working Capital and Long-term Liabilities (continued)

3.3 Loans and Borrowings (continued)

Cairn signed an extension to its existing EFF in December 2018. The extension became effective 31 December 2018 and increased total commitments to NOK 700.0m, with an accordion feature permitting additional future commitments of up to NOK 300.0m. The extension of this facility has no material impact on the results for the year.

Interest on outstanding debt is charged at the appropriate NIBOR plus an applicable margin. Debt is repayable by the final maturity date, which is now the earlier of 31 December 2022 or the date of receipt of the tax refund relating to exploration spend for 2021.

3.4 Finance Lease Liability