Final Results

Cairn Energy PLC
7 March 2002



EMBARGOED UNTIL 0700

                                                                    7 March 2002

CAIRN ENERGY PLC

PRELIMINARY UNAUDITED RESULTS ANNOUNCEMENT

Successful exploration programme has added significant value

HIGHLIGHTS


Financial



•         Average production 20,115 boepd (2000: 20,206 boepd)



•         Average price received per boe $21.05 (2000: $23.49)



•         Turnover £107.4m (2000: £116.1m)



•         Profit after tax £33.6m (2000: £41.6m)



•         Operating cash flow £64.9m (2000: £75.8m)



Operational



•         Nine exploration discoveries from eleven wells drilled



•         Approximately 300 mmboe gross unrisked reserves from discoveries



•         Over 1.6 billion boe of additional gross unrisked exploration
          potential identified in the KG Basin



•         Lakshmi development progressing and two Gas Sales Contracts concluded



•         Heads of Agreement signed with GAIL for gas sales to the Andhra
          Pradesh market



Bill Gammell, Chief Executive, commented:



'Cairn completed a very successful exploration programme during 2001 with a
total of nine discoveries from eleven exploration wells, adding significant
value to the Group's portfolio. Our unique strategic position and competitive
edge in the Indian sub-continent means that we are ideally placed to
commercialise these discoveries.'



Enquiries to:

Cairn Energy PLC:
Bill Gammell, Chief Executive                               Tel: [phone]
Mike Watts, Exploration Director                            Tel: [phone]
Kevin Hart, Finance Director                                Tel: [phone]

Brunswick Group Limited:
Patrick Handley, Mark Antelme, Catherine Bertwistle         Tel: [phone]


CHAIRMAN'S STATEMENT


The Group's excellent performance in 2001 has been primarily driven by continued
exploration success. Cairn's strategy of adding value through exploration in the
Indian subcontinent resulted in nine hydrocarbon discoveries from the eleven
exploration wells drilled throughout the year. These discoveries have added
significantly to the Group's portfolio of assets in its core area, with
approximately 300 mmboe of gross unrisked reserves discovered. Financially, the
Group continues to perform well against a backdrop of lower product prices.


Results

Average daily production was 20,115 boepd (2000: 20,206 boepd). Lower product
prices during the second half of 2001 resulted in an average price achieved per
boe of $21.05 (2000: $23.49 per boe). As a result, Group turnover decreased 7%
year on year to £107.4m (2000: £116.1m). Production costs were $4.93 per boe
(2000: $5.28 per boe). Operating profit and operating cash flow were £51.4m and
£64.9m respectively (2000: £65.8m and £75.8m). Profit after tax was down 19%
year on year to £33.6m (2000: £41.6m).



Strategy

It is our vision to establish commercial reserves from strategic positions in
high potential exploration plays resulting in the creation and delivery of
shareholder wealth.  We focus on material opportunities that are capable of
providing real growth to the Cairn Group.  Our edge is the ability to exploit
our commercial and technical expertise to leverage value from such
opportunities.  Every part of the Cairn Group is concentrated on supporting that
expertise to ensure that we are creating and realising value from the successful
implementation of this strategy.



As a direct result of this strategy, Cairn has developed a pre-eminent position
in the Indian sub-continent with material exploration and production positions
in Bangladesh and both the west and east coasts of India.


In Bangladesh, the implementation of this strategy has seen the initial
successful discovery and development of the Sangu gas field combined with a
realisation of value through the disposal of equity interests to Halliburton and
Shell.  In the event of export, Cairn's position is ideally situated to supply
the Indian energy markets.


In the Cambay basin offshore Western India, Cairn made a number of oil and gas
discoveries on Block CB/OS-2 in 2000 and 2001, of which the Lakshmi gas field is
currently under development with first gas sales targeted for Q3 2002.


During 2001, in the Krishna-Godavari basin offshore Eastern India, Cairn made
five oil and gas discoveries in Block KG-DWN-98/2.  These discoveries are
currently under evaluation prior to considering forward appraisal and
development plans.


The cycle and implementation of the Cairn strategy is clear.  Cairn seeks to
create value through high potential exploration plays and to realise value
through sales in the development and production phases.


India

India has been the sole focus of the Group's extensive exploration programme
during 2001. The resulting nine hydrocarbon discoveries comprise three offshore
and one onshore Western India and five offshore Eastern India.


In Western India, the Lakshmi field development project is progressing, with
first production expected in Q3 2002. To date, the Group has booked only the
Lakshmi committed reserves of 103 bcf on a net entitlement basis. It is
anticipated that additional reserve upside and gas sales will be accessed
through further appraisal and development phases at Lakshmi.


Two GSCs have been concluded for the sale of gas from Lakshmi to the
industrialised Gujarat market and the Group is pursuing opportunities for the
sale of additional gas from its neighbouring fields Ambe and Gauri, both of
which were discovered early in 2001. The development drilling underway at
Lakshmi has also confirmed the potential for significant oil in place volumes
below the gas reservoirs. An oil test is planned for the end of March 2002 as
part of the oil evaluation programme, and if successful will help confirm the
reserve potential which is currently estimated at 30 to 60 mmboe.


In November 2001, Cairn made its second consecutive oil discovery onshore
Western India with an exploration well drilled on Block RJ-ON-90/1 located in
Rajasthan. Further exploration and appraisal drilling is planned on the block,
subject to the grant of a licence extension.


In Eastern India, Cairn experienced material success in its drilling programme
on Block KG-DWN-98/2, leading to three oil and two gas discoveries during 2001
which have an associated unrisked recoverable reserve of at least 200 mmboe. The
ongoing technical evaluation is highlighting significant additional potential
around the initial discoveries and in nearby prospects. Further exploration and
appraisal drilling is planned for 2003. In addition, Cairn has signed a Heads of
Agreement with GAIL for the sale of gas by Cairn to GAIL for the Andhra Pradesh
market.


At Ravva, a successful workover and development programme was undertaken during
2001 and early 2002 to maintain plateau production of 50,000 bopd until Q1 2005.
In addition, a satellite gas development has been completed doubling total gas
production to approximately 65 mmsfcd.



A 3D seismic survey was acquired over the entire Ravva block in 2000 and 2001
which has identified a number of exploration prospects. Whilst detailed
evaluation of the seismic data is still ongoing, the Ravva joint venture has
taken the opportunity to add an exploration well at the end of the current
development well and workover drilling programme. This exploration well will
target approximately 50 mmboe of unrisked reserve potential.



Bangladesh

The market in Bangladesh continues to be restricted by the modest growth in
domestic demand. There is however an increasing and open dialogue regarding the
potential benefits of gas export from Bangladesh to India. In this connection,
the Government has commissioned reports by international energy specialists to
assess the reserve potential of the country and has formed two Government
committees to report specifically on the viability of gas export.



In addition to the existing PSCs for Blocks 5 and 10, signed in July 2001, Cairn
and Shell are currently in the process of negotiating extensions to Blocks 15
and 16. It has been agreed with the Government that commitment exploration wells
will not have to be drilled on the new blocks until there is a demonstrable
market for any hydrocarbons that may be discovered.



Offtake from the Sangu gas field on Block 16 increased to an average 138 mmscfd
(2000: 123 mmscfd). However, during 2001 the Sangu joint venture experienced an
increased delay in the receipt of payments from Petrobangla, such that payments
were six months in arrears at the year end. The Sangu GSPA has in place a
Government of Bangladesh Sovereign Guarantee which can be invoked by the joint
venture if the delay in receipt of payments becomes unacceptable. There are
signs that the payment situation may be improving.




North Sea

I am pleased to report that our interests offshore the UK and The Netherlands
have added value during 2001 through a combination of incremental developments
and third party business.



Outlook

The Group's focus in 2002 will be the demonstration of value added through its
drilling successes. A key objective in this regard will be achieving first
production from the Lakshmi gas field in Q3 2002. In addition, a number of
technical employees previously based in India have been relocated to the Group's
Head Office in Edinburgh to review and process the large volumes of technical
and geological data acquired in the KG Basin deep water exploration campaign.
Their knowledge will be combined with that of the existing technical and
commercial teams in assessing ways of maximising the value of our exploration
success.



Employees

Cairn's achievements have only been made possible by the expertise and hard work
of all of its employees. I would therefore like to record the Board's
appreciation of each individual's contribution during 2001 and to date.



Chairman

As announced in December 2001 I will be retiring as Chairman and as a
Non-Executive Director at the next Annual General Meeting of the Company on 1
May 2002. I have been a Director for 13 years and Chairman for 10 years and my
association with the Company has seen many positive developments over this
period. I will be succeeded as Chairman by my colleague Norman Murray and would
like to take this opportunity to wish Cairn every success under his
Chairmanship.



Website

Cairn's website is currently being redesigned and updated and it is intended
that the new version of the site will be launched on 2 April 2002, the date of
posting of the 2001 Annual Report & Accounts. The Annual Report & Accounts and
HSE & Social Review will both be available on the new website.





Norman Lessels CBE
Chairman, 7 March 2002


OPERATIONAL REVIEW



INDIA



During 2001, Cairn drilled 15 wells in India, comprising exploration, appraisal
and development wells. The wells were drilled in a variety of operating
environments including onshore, shallow and deep water.  The total weather
downtime in 11 months of continuous drilling was only three days.



The exploration discoveries have found approximately 300 mmboe of gross unrisked
reserves on the Group's Indian acreage, namely:-


Block KG-DWN-98/2            200 mmboe in the 'N', 'M', 'P' and Annapurna  oil and gas discoveries


Block CB/OS-2                75 mmboe in the Gauri and Ambe gas discoveries and the Lakshmi, Gauri and
                             Parvati oil discoveries


Block RJ-ON-90/1             30 mmboe in the 'H' oil discovery



In addition, over 1.6 billion boe of gross unrisked reserve potential has been
identified in the KG Basin deep water acreage. An intensive exploration
evaluation programme is currently underway at the company's Edinburgh office
reviewing all the well and seismic data acquired to date. This work is
anticipated to lead to further exploration and appraisal drilling in 2003.



Eastern India - Krishna-Godavari ('KG') Basin



Production



Ravva  (Cairn 22.5% and operator)


Ravva remains on plateau production and averaged 47,725 bopd and 34.4 mmscfd
during 2001 (2000: 48,800 bopd and 24.5 mmscfd). Ravva cumulative production at
31 December 2001 was 83 mmbbls.


Processing of the block-wide Ravva 3D seismic survey, acquired during the 2000
and 2001 field seasons, was completed in August 2001. This survey was designed
to define the existing producing area as well as aid mapping of the exploration
upside. Initial interpretation of the 3D focused on support of a drilling
programme required to maintain plateau production until Q1 2005. The well
programme commenced in August 2001 and is due to be completed in March 2002. It
comprised three workovers as well as the drilling and completion of two
additional oil producers, and drilling and completion of two satellite gas
wells.



The current estimate of the additional gross unrisked reserve potential on the
Ravva block is over 200 mmboe. This is based on a preliminary interpretation of
the new 3D seismic and a number of previous oil and gas discoveries made by
ONGC. The Ravva joint venture recently decided to extend the contract for the
rig currently being used for the development work in order to drill an
exploration well prior to the May monsoon. The exploration well is expected to
spud in March 2002 and targets an oil prospect in the extreme north east of the
Ravva block. The results of this exploration well will be important in planning
further exploration wells which are anticipated in 2003, once the interpretation
for the whole 3D survey is complete.




Additional production from the recently developed non-associated (dry gas)
satellite gas fields at Ravva commenced in September 2001 and reached a plateau
delivery rate of approximately 30 mmscfd early in 2002. This incremental
production combined with existing gas production currently averages 65 mmscfd.
All gas is sold to GAIL under two long term GSCs.



Exploration



Block KG-OS/6 (Cairn 50% and operator)



Two exploration wells were drilled on this block during 2001. The first well,
located on prospect 'A',  an Eocene rollover, was plugged and abandoned as a dry
hole. Drilling operations on the second well, located on prospect '6', were
terminated following several failed attempts to continue drilling after
encountering shallow over-pressured  reservoirs which prevented running the top
hole casing. Prospect '6' is a Miocene tilted fault block, similar to those
producing at Ravva and remains a viable exploration target. A well engineering
solution is required before returning to this location.



As a consequence of the delay caused by the shallow drilling problems
encountered in the prospect '6' well, an extension request for the current
exploration phase on the block has been submitted to the Government of India.



Block KG-DWN-98/2  (Cairn 100% and operator)



The PSC for this deep water block was signed in April 2000. A 1,500 km2 3D
seismic survey was acquired in the northern area in Q2 2000, on which a number
of prospects with associated direct hydrocarbon indicators were initially
identified. A further 2,386 line km of reconnaissance 2D seismic data were
acquired early in 2001.



The Group completed a very successful initial exploration programme on the block
in November 2001 with five hydrocarbon discoveries from five exploration wells
drilled during the year. These comprise the 'N' and Annapurna gas discoveries
and the 'P', 'M' and 'Q' oil and gas discoveries. The small 'Q' discovery
encountered only a thin oil and gas column, although it extended the occurrence
of known oil further into the offshore basin.



In December 2001, Cairn signed a HoA with GAIL for the sale of gas by Cairn to
GAIL for the Andhra Pradesh market, with a view to signing a gas sales agreement
by the end of 2002. The HoA also provides that the parties will cooperate in the
sharing of information with respect to the market for natural gas in specified
southern Indian states and such other areas of India as they may mutually agree.
This is with a view to finalising additional gas sales agreements and/or a joint
marketing agreement for such markets.



The results and information from the drilling programme in the deep water
offshore Eastern India require to be calibrated with existing seismic data and
fully evaluated by the technical team prior to any further exploration and
appraisal drilling on Block KG-DWN-98/2. The potential for an alliance with a
value-adding partner in this region is also being considered as a means of
facilitating deep water operations in the Krishna-Godavari Basin.



Western India



Block CB/OS-2, Cambay Basin



Cairn holds a 75% interest in exploration Block CB/OS-2 and is operator for the
joint venture, which includes TATA (15%) and ONGC (10%). ONGC has a right to
increase its stake by 30% in the event of a commercial discovery on the block
and has exercised this right in respect of the ring-fenced Lakshmi development
area. The equity holdings for the Lakshmi development area are therefore Cairn
50%, TATA 10% and ONGC 40%.



Exploration (Cairn 75% and operator)



Exploration drilling by the joint venture on the block has resulted in four
hydrocarbon discoveries - Lakshmi, Ambe, Gauri and Parvati. Lakshmi was
discovered in May 2000 and Ambe, Gauri and Parvati were discovered early in
2001. Excluding the committed reserves booked on Lakshmi at the year end, and
the possible gas reserves at Lakshmi, the additional gross unrisked reserves for
all four discoveries are 75 mmboe.



Lakshmi Development and Gas Sales Contracts ('GSCs') (Cairn 50% and operator)

The Lakshmi gas field was successfully appraised by the CB-A-2 well in December
2000, which encountered multiple hydrocarbon pay zones between 750 and 1,250
metres. Four zones were tested with a cumulative flow rate of 103 mmscfd. The
installation of two offshore jackets was completed in March 2001 and development
drilling commenced in October 2001. Development drilling operations are on
schedule and are expected to be completed in April 2002. Every Lakshmi gas
development well drilled through the gas zones has penetrated deeper oil bearing
sands. Evaluation is continuing but gross oil reserves potential at Lakshmi are
currently estimated at 30 to 60 mmbbls or STOIIP 90 to 180 mmbbls. The planned
Lakshmi oil test planned will be an important step in confirming this potential.



As a result of a delay in receiving final approval from the relevant Government
authorities for Cairn to purchase land for onshore processing facilities, the
contractual first gas delivery date of 1 July 2002 has been delayed to 15 August
2002.



During the second half of 2001, two GSCs were signed by the CB/OS-2 co-venturers
with GPEC and GGCL respectively, for the sale of gas from Lakshmi into the
industrialised Gujarat market. The Lakshmi facilities will initially have a
maximum processing capacity of 150 mmscfd of sales gas.



Gas from the field is contracted to be sold under a combination of oil-indexed
(with a contractual floor and ceiling) and fixed pricing. The provisions in the
individual GSCs in respect of pricing are confidential however, the composite
floor price is above the Ravva dry gas ceiling price of $3.30/mmbtu.



The two GSCs are specific to Lakshmi and exclude the other gas discoveries on
the block, namely Ambe and Gauri. Cairn anticipates additional gas sales
arrangements being entered into in due course in respect of these other
discoveries.



Block RJ-ON-90/1, Rajasthan Basin (Cairn 50% and operator)



Between June 2000 and March 2001, a 2D seismic survey comprising 1,266 line km
was completed across the block and a 647 km2 3D seismic survey was also acquired
over the central basin structural trend. The 1999 Guda-2 oil discovery was
drilled on this structural trend. In November 2001, Cairn made a second oil
discovery on the block with an exploration well on prospect 'H' located towards
the basin flank. Initial gross reserve estimates for the discovery are 30
mmbbls, however the 'H' structure will require additional exploration and
appraisal before any decision on development can be taken. The final exploration
period of the Block RJ-ON-90/1 PSC expires in May 2002. A request for an
extension of the exploration term will be submitted to the Government.




BANGLADESH



Cairn transferred the operatorship of its interests in Bangladesh to Shell in
1999. Future investment in exploration depends on a market for gas, which in the
absence of a domestic market requires an export market.



The Sangu gas field has the capacity to supply 250 to 300 mmscfd although
production is constrained by  local demand. As a consequence, daily offtake from
Sangu fluctuates significantly as the field is being used by Petrobangla as a
swing producer to balance supply shortfalls elsewhere in the Bangladeshi system.



Production



Sangu (Shell operator, Cairn 37.5%)



During 2001, offtake from the Sangu gas field averaged 138 mmscfd, an increase
of 12% on the 123 mmscfd achieved during 2000. The highest daily offtake to date
was 223 mmscf, taken on 13 February 2001. Sangu cumulative production at 31
December 2001 was 145 bcf. The average realised gas price for Sangu during 2001
was $2.909/mcf (2000: $2.885/mcf).



On 5 March 2001 an expert appointed under a dispute resolution article in the
Sangu GSPA opined that the estimated recoverable reserves for the field were 935
bcf. The operator has subsequently stated that the new DCQ for the field is 192
mmscfd effective from 5 March 2001. The operator's view remains that Sangu
ultimate recoverable reserves are 1.38 tcf, with further unproven GIIP potential
of up to 1.7 tcf in the 'thin bed' reservoirs. The Sangu joint venture has no
plans to appraise these additional potential pay zones whilst the local domestic
market is saturated and there is no Government decision on export.



Exploration



Block 16 (Shell operator, Cairn 50.0%)


Following the completion of testing operations in the Sangu Deep exploration
well during 2001, no further exploration or appraisal work was carried out
during the year. The final exploration period of the Block 16 PSC expired in May
2001. The operator has sought an extension of the exploration term and is
awaiting the consent of Petrobangla and the Government.



Block 15 (Shell operator, Cairn 50.0%)



The first extension of the exploration period of the Block 15 PSC expired in
December 2000 and the parties did not enter into the second extension of the
exploration period at that time. The operator is continuing discussions with
Petrobangla and the Government regarding entering the final extension of the
exploration period.



Blocks 5 and 10 (Shell operator, Cairn 45.0%)



Cairn and Shell signed PSCs for Blocks 5 and 10 with the Government of
Bangladesh in July 2001 and each holds a 45% interest in these blocks, the
remaining 10% being held by Bapex. It has been agreed with the Government that
commitment exploration wells will not have to be drilled on the blocks until
there is a demonstrable market for any gas that may be discovered.


Shell Carries

Under the terms of the original farm-in agreement between Cairn and Shell up to
$25m of Cairn's net exploration and appraisal expenditure on acreage outwith
Blocks 15 and 16 will be carried by Shell. Cairn has previously utilised a $25m
net exploration carry on Blocks 15 and 16. In the event of any new Cairn/Shell
development project in Bangladesh, up to $27.5m of Cairn's net development
expenditure will be carried by Shell.



Export

The Bangladesh Government has stated it would consider pipeline export of gas
once sufficient domestic reserves have been secured to supply the needs of the
domestic market for the medium and long term. Titas, the country's largest gas
field, has recently had an official reserves upgrade from 3 tcf to over 5 tcf.
During its tenure in 2000 and 2001 the Awami League Government commissioned an
independent assessment by the USGS and Petrobangla to determine the additional
reserve potential of the country. Similarly, the present BNP Government
commissioned the Norwegian Petroleum Department to conduct an independent study,
which was completed in February 2002. Both independent assessments conclude that
Bangladesh is highly prospective for gas and has substantial potential reserves.



NORTH SEA



Cairn holds small non-operated interests in the Gryphon field in the UK North
Sea and several producing properties in the Dutch North Sea. Average net
production for these two areas during 2001 was 3,064 boepd (2000: 3,203 boepd).
Value continues to be added to these properties through a combination of
incremental developments and third party tariff agreements.



A horizontal development well was successfully drilled in the central part of
the South Gryphon accumulation (Cairn 7.5%) in June 2001. The well was completed
in July 2001 and commenced oil production in August 2001.



In November 2001, the Gryphon owners reached agreement with the operator of the
Maclure field to develop Maclure via a tieback to the Gryphon floating
production, storage and offloading facility. First oil through Gryphon from
Maclure is expected in the second half of 2002. Discussions are also ongoing
with other operators in respect of routing additional potential third party
business through Gryphon.



In the Dutch North Sea the P6-D satellite gas field commenced production from a
single development well in October 2001, with gas being evacuated to the P6 main
platform. A second development well may be required in 2002/2003, depending on
reservoir performance. The Markham gas field continues to derive third party
tariff income from the Windermere and K4a-D fields and a further field, K1a,
will commence production as a satellite to Markham in 2002.



RESERVES



The table below shows reserves information on an entitlement basis for the
Group.


                                                        Reserves as at                 Reserves as at
                                                      31 December 2001               31 December 2000
                                                           mmboe                          mmboe


North Sea                                                     5.2                            6.1
South Asia                                                   96.7                           87.1
Total                                                       101.9                           93.2

On a direct working interest basis, reserves as at 31 December 2001 totalled
136.7 mmboe (2000: 127.6 mmboe). Net booked  reserves attributed to the Lakshmi
gas field as at 31 December 2001 were 103 bcf. This represents the contracted
volumes associated with an anticipated three year plateau period of 75 mmscfd
with GPEC and a five year plateau period of 45 mmscfd with GGCL, and related
short decline periods.



The booked reserves do not include additional gas reserves at Lakshmi,
undeveloped gas reserves at Gauri and Ambe, nor potential oil reserves at
Lakshmi, Ambe, Gauri and Parvati. Likewise, the booked reserves do not reflect
the significant upside potential associated with the oil and gas discoveries in
the Krishna-Godavari Basin deep water and in Rajasthan.



After accounting for production of 7.3 mmboe in 2001, Cairn's proved plus
probable booked reserves have increased by 8.7 mmboe.

FINANCIAL REVIEW



The Group's financial position has remained robust throughout a period of
significant capital expenditure and against a backdrop of weakening product
prices.


                                                                                           % Increase/
Key Statistics                                                2001                2000      (Decrease)


Production (boepd)                                          20,115              20,206        (0.5)
Average price per boe ($)                                    21.05               23.49         (10)
Turnover (£m)                                                107.4               116.1         (7)
Average production costs per boe ($)                          4.93                5.28         (7)
Operating profit (£m)                                         51.4                65.8         (22)
Profit after tax (£m)                                         33.6                41.6         (19)
Operating cashflow (£m)                                       64.9                75.8         (14)



PROFIT AND LOSS



Turnover

Total production for the year was 7.3 mmboe (2000: 7.4 mmboe). The Group
realised an average price of $21.05 per boe during 2001 (2000: $23.49 per boe).
Primarily due to the deterioration in the product price environment during the
second half of 2001, turnover decreased by 7% year on year to £107.4m (2000:
£116.1m).



Operating Profit

The Group generated an operating profit of £51.4m (2000: £65.8m).



Total cost of sales for the year was £45.6m (2000: £41.1m). Cost of sales per
barrel were £6.22 ($9.24), comprised of production costs of £3.37, depletion of
£2.82 and abandonment of £0.03. The depletion charge of £2.82 per barrel
represents a 73% increase over the comparative figure for 2000 (£1.63 per
barrel). This increase is almost entirely due to the inclusion for the first
time of Lakshmi development costs, and certain historic Bangladesh exploration
expenditure relating to potentially relinquished acreage, in the depletable cost
pool.



Profit for the Year

Administrative expenses for the year were £10.4m (2000: £8.9m). This includes a
charge of £1.9m (2000: £1.2m) in respect of the amortisation of Cairn's Long
Term Incentive Plan. Net interest received was £0.6m (2000: £0.6m), including a
foreign currency exchange loss of £0.1m (2000: gain of £0.2m).



The majority of the £18.4m tax charge (2000: £24.2m) arises on profits in India.
This resulted in profit after tax of £33.6m (2000: £41.6m). Cairn currently has
no unprovided Indian deferred tax. The introduction of FRS19 Deferred Taxation
will therefore effect only the UK tax charge.



BALANCE SHEET



Capital Expenditure

Capital expenditure during 2001 was £125.6m (2000: £48.3m). Approximately two
thirds of this related to exploration activities with the remaining one third
related to development and other activities.



Net Funds/Debt and Net Assets

The significantly increased capital expenditure programme during the year
resulted in Group net debt at 31 December 2001 of £33.8m (2000: net funds
£13.7m). Net assets at 31 December 2001 were £335.9m (2000: £297.3m), a 13%
increase year on year.



Payments for Sangu Gas

Due in part to the events of 11 September 2001, which have impacted on
Bangladesh's foreign exchange reserve position and a 'familiarisation' period
following the recent change of Government, the Sangu joint venture has
experienced a worsening delay in the receipt of payments from Petrobangla for
Sangu gas.



As at 31 December 2001, payments were six months in arrears, equating to a net
amount overdue to Cairn of £22.7m. Since the year end a further two payments
have been received, maintaining the position at six months in arrears. The net
amount overdue to Cairn is currently £23.4m.



The Sangu GSPA has in place a Government of Bangladesh Sovereign Guarantee
whereby all sums remaining due must be paid in full to the Sangu joint venture
by the Government. Invoking the Guarantee requires unanimous approval of the
joint venture.



In view of the existence of the Sovereign Guarantee, the Board does not consider
it appropriate to make a general provision against the overdue amount. A
specific provision of £6.1m has been charged through production costs since
inception, of which £2.4m was charged in 2001.



CASH FLOW



Net Cash Inflow, Tax and Interest

Group net cash inflow from operations was £64.9m (2000: £75.8m).



Tax refunds during 2001 were £6.2m resulting in a net credit on the Group
Statement of Cash Flows of £1.7m (2000: payment £11.1m). The refunds were in
respect of corporation tax in the UK and India.

Net interest received was £1.1m (2000: £0.6m).



Capital Expenditure

Cash outflow from capital expenditure during 2001 was £116.1m comprising £77.3m
exploration expenditure, £37.7m development expenditure and £1.1m other
expenditure (2000: £49.9m - £35.0m exploration, £7.5m development and £7.4m
other). The Group had a net cash outflow before financing of £48.3m during 2001
(2000: net inflow £30.3m).



Financing

The Group had a net cash inflow after financing of £2.6m (2000: net cash outflow
of £6.5m). As a consequence of the capital expenditure programme during 2001,
the Group had drawn $57.8m under its existing facilities at 31 December 2001.



Due to the additional development capital expenditure required to bring Lakshmi
onstream, Cairn is in the process of increasing its banking facilities such that
it will have access to a circa $100m three year revolving credit facility and a
circa $50m 364 day revolving credit facility, both of which are committed and
unsecured. The Group's cash flow position and financing continue to provide the
financial strength and flexibility to allow the Group to pursue further
opportunities in its chosen strategic areas.



Kevin Hart

Finance Director, 7 March 2002


GLOSSARY OF TERMS


The following are the main terms and abbreviations used in the Chairman's
Statement, Operational Review and Financial Review:-


Corporate
Bapex                Bangladesh Exploration Petroleum Co. Ltd.
Cairn                the Company and/or its subsidiaries as appropriate
GAIL                 Gas Authority of India Limited
GGCL                 Gujarat Gas Company Limited
GPEC                 Gujarat Powergen Energy Corporation Limited
HBR/Halliburton      HBR Energy, Inc. (a subsidiary of Halliburton Company)
ONGC                 Oil & Natural Gas Company Ltd. (Indian state oil and gas company)
Petrobangla          Bangladesh Oil, Gas & Mineral Corporation (Bangladesh state oil and gas company)
Shell                Shell Bangladesh Exploration and Development B.V.
TATA                 TATA Petrodyne Limited
The Board            the Board of Directors of Cairn Energy PLC
The Company          Cairn Energy PLC
The Group            the Company and its subsidiaries
Unocal               Unocal Bangladesh Block Seven, Ltd. (a subsidiary of Unocal Corporation)


Technical
2D                   two dimensional
3D                   three dimensional
bcf                  billion cubic feet of gas
boe                  barrel of oil equivalent
boepd                barrels of oil equivalent per day
bopd                 barrels of oil per day
DCQ                  Daily Contract Quantity
FRS                  Financial Reporting Standard
GIIP                 Gas initially in place
GSC(s)               Gas Sales Contract(s)
GSPA                 Gas Sales & Purchase Agreement
HoA                  Heads of Agreement
km                   kilometres
km2                  square kilometres
mmbbls               million barrels of oil
mmboe                million barrels of oil equivalent
/mcf                 per thousand cubic feet of gas
/mmbtu               per million British thermal units
mmscf                million standard cubic feet of gas
mmscfd               million standard cubic feet of gas per day
PSC(s)               Production Sharing Contract(s)
STOIIP               stock tank oil initially in place
USGS                 United States Geological Survey



Note:

This press release contains forward looking statements that reflect Cairn's
expectations regarding future events. Forward looking statements involve risks
and uncertainties. Actual events could differ materially from those projected
herein and depend on a number of factors including the uncertainties relating to
oil and gas exploration and production and sale of oil and gas.


Group Profit and Loss Account (Unaudited)

For the year ended 31 December 2001



                                                                                    Total              Total
                                                                                     2001               2000
                                                                                    £'000              £'000

Turnover
Producing                                                                         107,427            114,574
Rig                                                                                     -              1,529
                                                                                  107,427            116,103
Cost of sales
Production costs                                                                 (24,708)           (25,678)
Rig operating costs                                                                     -            (1,092)
Depletion                                                                        (20,704)           (12,074)
Decommissioning charge                                                              (225)              (337)
Depreciation of rig                                                                     -            (1,966)


Gross profit                                                                       61,790             74,956


Write-down of oil and gas assets                                                        -              (260)
Administrative expenses                                                          (10,406)            (8,893)

Operating profit                                                                   51,384            65,803

Loss on disposal of rig                                                                 -              (666)

Profit on ordinary activities before interest                                      51,384             65,137


Interest receivable and similar income                                              1,835              1,690
Interest payable and similar charges                                              (1,193)            (1,064)

Profit on ordinary activities before taxation                                      52,026             65,763


Taxation on profit on ordinary activities                                         
-     current                                                                     (3,601)           (21,268) 
-     deferred                                                                   (14,815)            (2,912)
                                                                                 (18,416)           (24,180)

Profit for the year                                                                33,610             41,583


Earnings per ordinary share - basic                                                23.29p             28.59p

Earnings per ordinary share - diluted                                              23.10p             28.42p
                                                                   



Group Statement of Total Recognised Gains and Losses (Unaudited)
For the year ended 31 December 2001



                                                                                     2001               2000
                                                                                    £'000              £'000

Profit for the year                                                                33,610             41,583

Unrealised foreign exchange differences                                             3,924             12,765

Total recognised gains and losses for the year                                     37,534             54,348



Reconciliation of Movements in Shareholders' Funds (Unaudited)
For the year ended 31 December 2001



                                                                                     2001               2000
                                                                                    £'000              £'000

Total recognised gains and losses for the year                                     37,534             54,348

New shares issued in respect of employee share options                              1,044                194
                                                                                        
Repurchase of shares                                                                    -            (6,283)


Net additions to shareholders' funds                                               38,578             48,259

Opening shareholders' funds                                                       297,277            249,018

Closing shareholders' funds                                                       335,855            297,277



Balance Sheets (Unaudited)
As at 31 December 2001


                                                         Group       Group        Company          Company
                                                          2001        2000           2001             2000
                                                         £'000       £'000          £'000            £'000

Fixed assets
Exploration assets                                     212,262     171,681         29,451           67,936
Development/producing assets                           186,365     115,149         44,411           20,020
Other fixed assets                                       2,167       2,273            737              900
Investments                                              3,473       5,521        181,704          183,653
                                                       404,267     294,624        256,303          272,509

Current assets
Debtors                                                 73,646      50,711         44,861           23,196
Cash at bank                                             5,927      13,653             14            5,444
                                                        79,573      64,364         44,875           28,640

                                                                             
Creditors: amounts falling due within one year          96,403      31,755         42,588           57,473

Net current (liabilities)/assets                      (16,830)      32,609          2,287         (28,833)

                                                                           
Total assets less current liabilities                  387,437      327,233       258,590          243,676
Provisions for liabilities and charges                  12,159        7,067             -              845
Deferred taxation                                       39,423       22,889             -            1,000
                                                                                        

Net assets                                             335,855     297,277        258,590          241,831

Capital and reserves - equity interests
Called-up share capital                                 14,817      14,714         14,817           14,714
Share premium                                           73,553      72,612         73,553           72,612
Capital reserves - non distributable                    50,487      50,487         27,025           27,025
Capital reserves - distributable                        35,254      35,254         35,254           35,254
Profit and loss account                                161,744     124,210        107,941           92,226

Shareholders' funds                                    335,855     297,277        258,590          241,831




N Lessels CBE, Chairman
W B B Gammell,  Chief Executive
7 March 2002




Group Statement of Cash Flows (Unaudited)
For the year ended 31 December 2001




                                                                                   2001                 2000
                                                                                  £'000                £'000

Net cash inflow from operating activities                                        64,883               75,837

Returns on investments and servicing of finance
Interest received                                                                 1,844                1,460
Interest paid                                                                     (700)                (894)
                                                                                  1,144                  566

Taxation                                                                          1,711             (11,094)

Capital expenditure and financial investment
Expenditure on exploration assets                                              (77,310)             (35,037)
Expenditure on development/producing assets                                    (37,722)              (7,451)
Purchase of other fixed assets                                                  (1,139)              (1,389)
Purchase of fixed asset investments                                                   -              (5,987)
Sale of fixed asset investments                                                     102                    -
Sale of other fixed assets (including EEIV)                                          29               14,844
                                                                              (116,040)             (35,020)

Equity dividends paid                                                                 -                    -

Net cash (outflow)/inflow before use of liquid resources and                   (48,302)               30,289
financing

Management of liquid resources*
Cash on short term deposit                                                        9,932             (12,607)

Financing
Issue of shares                                                                   1,044                  194
Repurchase of shares                                                                  -              (6,283)
Debt drawn down                                                                  39,962                    -
Repayment of debt                                                                     -             (18,070)
                                                                                 41,006             (24,159)

Increase/(decrease) in cash in the year                                           2,636              (6,477)



*  Short term deposits of less than one year are disclosed as liquid resources




Reconciliation of Operating Profit to Operating Cash Flows (Unaudited)

For the year ended 31 December 2001


                                                                                        2001          2000
                                                                                       £'000         £'000

Operating profit                                                                      51,384        65,803

Depletion and depreciation                                                            21,985        15,229
Decommissioning charge                                                                   225           337
Amortisation of Long Term Incentive Plan                                               1,948         1,157
Exceptional write-down of oil and gas assets                                               -           260
Exceptional administrative expenses                                                        -           514
Debtors movement                                                                    (10,029)       (5,192)
Creditors movement                                                                       910       (2,032)
Other provisions                                                                     (1,128)         (536)
(Gain)/loss on sale of other fixed assets                                                (5)           202
Foreign exchange differences                                                           (407)         1,214
                                                                                      64,883        76,956

Cash outflow on transfer of operatorship and the Group restructuring                       -       (1,119)

Net cash inflow from operating activities                                             64,883        75,837


NOTES:



1.     No dividend has been declared (2000: nil).

2.     The earnings per ordinary share is calculated on a profit of
£33,610,000 (2000: profit of £41,583,000) and on a weighted average of
144,310,214 ordinary shares (2000: 145,438,032).  The weighted average of
ordinary shares excludes shares held under the Long Term Incentive Plan - the
shares are held by The Cairn Energy PLC Employees' Share Trust as the Company
cannot hold its own shares.

The diluted earnings per ordinary share is calculated on a profit of £33,610,000
(2000: profit of £41,583,000) and on 145,520,492 ordinary shares (2000:
146,306,523 ordinary shares), being the basic weighted average of 144,310,214
ordinary shares (2000: 145,438,032 ordinary shares) and the dilutive potential
ordinary shares of 1,210,278 ordinary shares (2000: 868,491 ordinary shares)
relating to share options.

3.     Cairn follows the full cost method of accounting for oil and gas
assets. Under this method, all expenditure incurred in connection with the
acquisition, exploration, appraisal and development of oil and gas assets which
is directly attributable to the asset, including interest payable and exchange
differences incurred on borrowings directly attributable to development
projects, is capitalised in two geographical cost pools: North Sea and South
Asia. The Other International pool was fully written off in 2000.

4.     The financial information contained in this announcement does
not constitute statutory accounts as defined in Section 240 of the Companies Act
1985.  The comparative financial information is based on the statutory accounts
for the year ended 31 December 2000. Those accounts, upon which the auditors
issued an unqualified opinion, have been delivered to the Registrar of
Companies.  The statutory accounts for the financial year ended 31 December 2001
will be delivered to the Registrar.

5.     Full accounts are due to be posted to shareholders on 29 March
2002 and will be available at the Company's registered office, 50 Lothian Road,
Edinburgh, EH3 9BY, from that date.

6.     The Annual General Meeting is due to be held in the Glamis Room
at the Caledonian Hilton Hotel, Princes Street, Edinburgh, EH1 2AB on Wednesday
1 May 2002 at 12 noon.




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