Final Results for the Year Ended 31 December 2010

RNS Number : 4234C

Petrofac Limited

07 March 2011

Press Release

7 MARCH 2011

PETROFAC LIMITED

FINAL RESULTS FOR THE YEAR ENDED 31 DECEMBER 2010

FINANCIAL HIGHLIGHTS

· Net profit⁽¹⁾ up 58% to US$557.8 million (2009: US$353.6 million); net profit up 26% on a like-for-like basis⁽²⁾

· Earnings per share (diluted) up 57% to 162.46 cents (2009: 103.19 cents)

· Revenue up 19% to US$4.4 billion (2009: US$3.7 billion)

· Year-end backlog⁽³⁾ up 45% at US$11.7 billion (2009: US$8.1 billion)

· Final dividend 30.00 cents (18.42 pence⁽⁴⁾); full year dividend up 22% to 43.80 cents (2009: 35.80 cents)

· As part of the EnQuest demerger in April 2010, distribution of one EnQuest share for every Petrofac share with a fair value of 160.08 cents per share

· Gross cash balances at 31 December 2010 of US$1.1 billion (2009: US$1.4 billion), augmented by receipt of US$0.7 billion of cash advances in January 2011

· Medium-term Engineering & Construction net margin guidance raised 100 bps

Commenting on the outlook, Ayman Asfari, Petrofac's group chief executive, said:

"I am delighted to present another excellent set of results. 2010 has been an exceptional year for us, with a record intake of new orders, which gives us outstanding revenue visibility and brings exciting opportunities for us to develop our capability and to deliver it into new markets.

"With this strong financial underpinning, our differentiated and competitive offering and our proven excellence in project execution, we are confident that we will continue to deliver superior value for our customers and sector-leading returns for our shareholders, with like-for-like net profit growth in 2011 of at least 15%."

2010 OPERATIONAL HIGHLIGHTS

Engineering & Construction

· Excellent operational performance, including the substantial completion of 5 large EPC projects

· Order intake of US$6.0 billion, including the US$3.4 billion EPC phase of the South Yoloten project in Turkmenistan and our first major project in Iraq

Offshore Engineering & Operations

· Awarded our first predominantly lump-sum EPC project in the UKCS, the Laggan Tormore gas processing plant for Total on Shetland, worth in excess of £500 million

· Expanded our international operations with the award of a 5 year duty holder contract for the Government of Sharjah in the United Arab Emirates

Engineering, Training Services and Production Solutions

· Acquired TNEI, a specialist consultancy providing services in the areas of power transmission and distribution, planning and environmental consent and energy management

· Established new training facilities in Syria and Algeria to help develop local workforces

· Successfully transitioned to assume full operational responsibility for the Ticleni fields in Romania under a 15 year production enhancement contract

· Acquired a 15% equity stake in Seven Energy, a Nigerian production and development company, and entered into a strategic alliance agreement to assist in developing its assets

Energy Developments

· Completed EnQuest demerger with Don investment generating an IRR from inception to demerger of approximately 35%

· Field Development Programme approved for the second phase of the Cendor field in Malaysia

· Secured US$800 million Risk Services Contract (Petrofac share 50%) to develop the Berantai field, offshore Malaysia

· Acquired CO₂Deepstore, a developer of CO2 storage projects, and partnering with Shell on the Goldeneye CO2 storage prospect

PROSPECTS FOR 2011

The significant political changes across the Middle East and North Africa have, to date, had a minimal impact on our day to day operations. Of the countries substantially affected, Tunisia is the only one in which Petrofac has current operations and production at our Chergui facility has returned to normal after short periods of being shut-in. Managing country risk has always been an important part of operating in the region and we continue to monitor the evolving political situation closely to ensure that the interests of our employees, stakeholders and investors are safeguarded.

Engineering & Construction

We entered 2011 with a record backlog in Engineering & Construction of US$9.0 billion, which has been augmented by the award of the US$1.2 billion In Salah Gas project in Algeria in January, giving us outstanding revenue visibility for the coming year and beyond. As a result, our immediate focus is on ensuring that we continue our excellent operational performance across our portfolio of projects. Given the terms of our existing backlog, our confidence in our execution capability, and our competitive positioning in our core and developing markets, we are raising our medium-term net margin guidance from around 10% to around 11%.

Offshore Engineering & Operations

Our recent awards in Offshore Engineering & Operations should underpin strong revenue growth in 2011. We expect recent high levels of bidding activity, both in the UK and internationally, to continue, which should present us with further opportunities for growth. Notwithstanding the improvement in net margin achieved in 2010, we see opportunities to improve net margins further over the medium-term.

Engineering, Training Services and Production Solutions

As well as supporting the group's wider activities, we expect Engineering Services to see more opportunities with external customers in 2011. Delegate numbers in Training Services improved as 2010 progressed and we expect this trend to continue throughout the course of this year. We continue to review strategic opportunities for establishing new training facilities and developing local workforces. Following the award of the Ticleni production enhancement contract in July 2010, and an improvement in general market conditions for our consultancy and technology businesses, we expect to deliver strong revenue growth in Production Solutions in 2011. Given the change in scope of our services on Dubai's offshore oil & gas assets (now accounted for through Offshore Engineering & Operations), and given that we do not expect to recognise profit on the Ticleni contractuntil next year due to the long-term nature of the contract, we forecast a reduction in overall net profit for this reporting segment in 2011.

Energy Developments

With the award of the risk services contract for the development of the Berantai field and delivery of the FPSO, and commencement of the second phase of the Cendor field, we expect a significant increase in capital expenditure in 2011. Our current capital commitments are around US$500 million for 2011.

Ends

Analyst presentation:

A presentation for analysts will be held at 9.30am today, which will be webcast live via http://www.investorcalendar.com/IC/CEPage.asp?ID=163402.

For further information, please contact:

Petrofac Limited +44 (0) 20 7811 4900

Jonathan Low, Head of Investor Relations

Tulchan Communications Group Ltd +44 (0) 20 7353 4200

James Bradley

David Allchurch

Martin Robinson

petrofac@tulchangroup.com

Notes to Editors

Petrofac is a leading international provider of facilities solutions to the oil & gas production and processing industry, with a diverse customer portfolio including many of the world's leading integrated, independent and national oil & gas companies. Petrofac is quoted on the London Stock Exchange (symbol: PFC) and is a constituent of the FTSE 100 Index.

The group delivers services through seven business units: Engineering & Construction, Engineering & Construction Ventures, Engineering Services, Offshore Engineering & Operations, Training Services, Production Solutions and Energy Developments.

Through these businesses Petrofac designs and builds oil & gas facilities; operates, maintains and manages facilities and trains personnel; enhances production; and, where it can leverage its service capability, develops and co-invests in upstream and infrastructure projects. Petrofac's range of services meets its customers' needs across the full life cycle of oil & gas assets.

With around 14,000 employees, Petrofac operates out of six strategically located operational centres, in Aberdeen, Sharjah, Woking, Chennai, Mumbai and Abu Dhabi and a further 20 offices worldwide. The predominant focus of Petrofac's business is on the UK Continental Shelf (UKCS), the Middle East and Africa, the Commonwealth of Independent States (CIS) and the Asia Pacific region.

For additional information, please refer to the Petrofac website at www.petrofac.com.

(The attached is an extract from the group's Annual Report and Accounts for the year ended 31 December 2010.)

Review of operations

Our operations are organised into seven business units, which report under four segments:

Business unit		Reporting segment
Engineering & Construction	>	Engineering & Construction
Engineering & Construction Ventures	>	Engineering & Construction
Offshore Engineering & Operations	>	Offshore Engineering & Operations
Engineering Services	>	Engineering, Training Services and Production Solutions
Training Services
Production Solutions
Energy Developments	>	Energy Developments

We present below an update on each of the group's reporting segments:

US$ millions	Revenue		Operating profit(1)		Net profit(2)		EBITDA
	2010	2009	2010	2009 restated	2010	2009	2010	2009 restated

Engineering & Construction	3,253.9	2,509.0	438.9	312.4	373.0	265.1	474.3	337.3
Offshore Engineering & Operations	721.9	626.7	24.5	17.8	17.2	12.8	27.3	19.7
Engineering, Training Services and Production Solutions	355.3	349.7	26.6	34.5	27.6	32.4	34.7	42.6
Energy Developments	188.2	248.7	191.2	77.4	156.4	46.2	241.0	160.9
Corporate, consolidation & elimination	(165.1)	(78.7)	(17.7)	(10.1)	(16.4)	(2.9)	(17.9)	(10.8)
	────────	────────	──────	──────	──────	──────	──────	──────
Group	4,354.2	3,655.4	663.5	432.0	557.8	353.6	759.4	549.7
	════════	════════	══════	══════	══════	══════	══════	══════

Growth/margin analysis %	Revenue growth		Operating margin		Net margin		EBITDA margin
	2010	2009	2010	2009	2010	2009	2010	2009

Engineering & Construction	29.7	25.9	13.5	12.5	11.5	10.6	14.6	13.4
Offshore Engineering & Operations	15.2	(19.3)	3.4	2.8	2.4	2.0	3.8	3.1
Engineering, Training Services and Production Solutions	1.6	(31.5)	7.5	9.9	7.8	9.3	9.8	12.2
Energy Developments	(24.3)	62.1	101.6	31.1	83.1	18.6	128.0	64.7
	────────	────────	──────	──────	──────	──────	──────	──────
Group	19.1	9.8	15.2	11.8	12.8	9.7	17.4	15.0
	════════	════════	══════	══════	══════	══════	══════	══════

1 Profit from operations before tax and finance costs.

2 Profit for the year attributable to Petrofac Limited shareholders.

Engineering & Construction

The Engineering & Construction reporting segment includes the group's Sharjah-based Engineering & Construction business unit and Engineering & Construction Ventures, which has been established to target new markets, such as Abu Dhabi, Saudi Arabia, and Turkmenistan. Engineering & Construction generally undertakes engineering, procurement and construction projects on a lump-sum basis, with a typical duration of between two to four years, and is focused on markets in the Middle East, Africa, Asia-Pacific and the Commonwealth of Independent States, particularly the Caspian region.

Order intake in 2010 exceeded US$6.0 billion. This includes our largest ever award, of US$3.4 billion, for the second phase of our contract with Turkmengas on the South Yoloten project in Turkmenistan, as well as contracts in Qatar, Kuwait and Malaysia.

We have delivered good progress on our current portfolio of contracts including the handover or substantial completion of the following:

· in Syria, we completed and commissioned the Ebla gas plant for PetroCanada in April 2010, two months ahead of schedule, earning an early completion bonus. We have also completed and commissioned the Jihar gas plant for the Hayan Petroleum Company (a joint venture between the state-owned Syrian Petroleum Company and INA Industrija Nafte d.d.-Naftaplin of Croatia)

· in Oman, we completed the Harweel cluster development project for Petroleum Development Oman (PDO), achieving the introduction of hydrocarbons in January 2011

· in Kuwait, we substantially completed the Mina Al-Ahmadi refinery pipelines project for Kuwait Oil Company (KOC), which was awarded in November 2008

· in Algeria, we made good progress on the In Salah gas compression project for Sonatrach, BP and Statoil. Two of the three fields are now in operation and the compression facility and power generation on the Krechbah field were substantially completed by the end of the year

We were awarded the following principal contracts during the year, on which initial progress has been in line with our expectations:

Gas sweetening facilities, Qatar

In March 2010, we were successful in securing an award for gas sweetening facilities in Qatar from Qatar Petroleum. The contract, for more than US$600 million, includes the engineering, procurement, installation and commissioning of gas sweetening facilities in Qatar's Messaieed and Dukhan industrial districts. The project includes a sulphur recovery upgrade in Messaieed and an acid gas recovery plant in Dukhan. Work on the projects is due for completion within 38 months.

Pipelines from Mina Al-Ahmadi to power stations, Kuwait

In July 2010, we were awarded a US$400 million contract by Kuwait Oil Company for EPC services for the installation of fuel gas and gas oil pipelines from Mina Al-Ahmadi to the Azzour and Shuaiba Power Stations in Kuwait. The project follows on from the pipelines contract referred to above and is expected to last approximately two years.

Water injection project, Kuwait

In August 2010, we were awarded a further EPC project by KOC for US$430 million for effluent water and sea water injection facilities. The project involves the installation of a new central injection pumping facility and modifications to three existing gathering centres and seawater treatment plant. When completed, both effluent water and sea water will be fed into a central injection pumping facility and injected into the wells with the objective of increasing oil recovery from the Raudhatain and Sabriyah fields. Completion is estimated within 36 months.

South Yoloten development, Turkmenistan

In December 2010, we commenced the second phase of the South Yoloten contract, worth US$3.4 billion, for Turkmengas, the state-owned national gas company of Turkmenistan. This followed the completion of the first phase of the project, which involved a front end engineering and design (FEED) study and early engineering work for the gas processing development. The second phase of the contract is scheduled to last 31.5 months, during which time we will provide engineering, procurement and commissioning work on a lump-sum basis for a 10 bcma gas processing plant along with the infrastructure and pipelines for the entire 20 bcma development. The structuring of this contract in two phases was important for risk mitigation and the work completed in phase one gives us a higher level of confidence that we can execute the project in accordance with our high standards.

SEPAT offshore early production system, Malaysia

In December 2010, we secured an award for the engineering, procurement, construction, installation and commissioning of an offshore early production system on the east coast of Peninsular Malaysia. The contract, worth approximately US$280 million, was awarded by Petronas Carigali Sdn Bhd. First oil is expected by the end of 2011 and the project is estimated to be completed by April 2012.

Results

High activity levels, due principally to projects won in 2009 and late 2008, resulted in Engineering & Construction growing revenues strongly by 29.7% to US$3,253.9 million (2009: US$2,509.0 million). The main contributors to revenue were: the El Merk central processing facility in Algeria; the Asab project in Abu Dhabi; the Kauther gas compression project in Oman; the Mina Al-Ahmadi refinery pipelines project in Kuwait, and the Karan utilities package in Saudi Arabia.

Net profit increased by 40.7% to US$373.0 million (2009: US$265.1 million), representing a net margin of 11.5% (2009: 10.6%). The increase in net margin is due to continued strong operational performance, including the delivery of a number of projects during the year, and first time profit recognition on a number of projects. A variation order on a project agreed in the first half of 2010 was not reflected in the interim results, leading to an understatement of revenue by US$35 million and net profit by US$32 million. These amounts have been recognised in the second half of 2010 and therefore there is no overall financial impact on the reported results for the year ended 31 December 2010.

Over the year, Engineering & Construction grew its headcount from 4,200 to 5,400, in response to the record intake in 2009 and in anticipation of our largest ever award, in Turkmenistan. In addition, headcount in our engineering offices in Mumbai and Chennai, which principally support our Engineering & Construction activities - although they are reported within our Engineering, Training Services and Production Solutions segment - also grew strongly. At 31 December 2010, we had approximately 1,600 employees in our Indian offices (2009: 1,300).

At 31 December, the Engineering & Construction backlog stood at a record US$9.0 billion (2009: US$6.2 billion), reflecting the high level of order intake during the year.

Offshore Engineering & Operations

Offshore Engineering & Operations provides engineering and construction services at all stages of greenfield and brownfield offshore projects. In addition, through the provision of operations management services, we deliver production and maintenance support and extend field life. Offshore Engineering & Operations' activities are primarily in the UKCS and are predominantly provided on a reimbursable basis, but often with incentive income linked to the successful delivery of performance targets. Many of our operations contracts are long-term (typically three to five years) and in the case of the provision of Duty Holder services⁽⁵⁾ are often open-ended.

Activity levels in Offshore Engineering & Operations improved in 2010 due to the commencement of work on major contracts awarded in 2009, good bidding success and a general improvement in market conditions. Our strong record of operational performance, company-wide capability and established presence in core markets helped us achieve an order intake of US1.6 billion, taking backlog to record levels of US$2.4 billion. The key awards secured were:

Sharjah Government Duty Holder contract, UAE

In October 2010, we secured a Duty Holder contract to provide a full range of facilities management services to the Government of Sharjah on the Sajaa Gas Plant and related assets. This contract, which furthers our aim to grow the Offshore Engineering & Operations business internationally, will run for five years and is worth more than US$250 million.

Laggan Tormore EPC contract, UK

In October 2010, we won an engineering, procurement, supply, construction, commissioning and start-up contract with Total for the development of a gas processing plant on the Shetland Islands. Offshore Engineering & Operations will develop this facility, supported by Engineering & Construction. This is the first time that we have secured a predominantly lump-sum EPC contract in the UK. The contract is worth more than £500 million, with first gas expected in Q2 2014.

Maersk Oil engineering services contract, UK

In November 2010, we were awarded a contract worth £40 million over three years for the provision of engineering services to the UKCS assets of Maersk Oil. The contract includes three one-year options for extension, and broadens Petrofac's scope of services for these assets, building upon the offshore operations and support services we have been providing since 2000.

In addition to securing these new awards, we have been successful in extending a number of our operations and maintenance contracts with both oil majors and independents. These include a five-year agreement with BHP Billiton to provide operations and maintenance personnel support for the Liverpool Bay Development in the Irish Sea and a five-year extension to our operations and maintenance support contract with CNR International in the North Sea.

From October 2010, the technical services agreement with the Government of Dubai was reported through the Offshore Engineering & Operations reporting segment (having previously been reported through Engineering, Training Services and Production Solutions). The transition from having operational control over these assets to the new technical services agreement was effected smoothly.

Acquisitions

We successfully completed two small acquisitions in 2010 which broaden our capability: Scotvalve Services Limited, which provides servicing and repair for oilfield pressure control equipment, and Stephen Gillespie Consultants Limited, which designs and manufactures metering systems (see note 10 to the financial statements).

Results

Reported revenue for the year increased by 15.2% to US$721.9 million (2009: US$626.7 million) and revenue excluding 'pass-through' revenue⁽⁶⁾ increased by 20.6% to US$526.4 million (2009: US$436.4 million), reflecting the commencement of major contracts secured in the second half of 2009 and a general improvement in the operating environment. Approximately 90% of Offshore Engineering & Operations' revenue is generated in the UKCS, with these revenues generally denominated in sterling. The average US dollar to sterling exchange rate for 2010 was broadly similar to the rate for 2009.

Net profit increased by 34.5% to US$17.2 million (2009: US$12.8 million), again reflecting increased activity levels. Net margin on revenue excluding pass-through revenue increased to 3.3%, compared to 2.9% in 2009, driven by new higher margin contracts.

Over the year, Offshore Engineering & Operations grew its headcount from 4,100 to 4,400, mostly attributable to the staff added on new contracts, including Laggan Tormore and the Sharjah Government Duty Holder contract.

Backlog for Offshore Engineering & Operations increased to a record high of US$2.4 billion at 31 December 2010 (2009: US$1.6 billion). This includes approximately half of the backlog booked in relation to the Total EPC contract awarded in October 2010. The remainder of the backlog has been booked by Engineering & Construction, as it will support Offshore Engineering & Operations on the project.

Engineering, Training Services and Production Solutions

The Engineering Services, Training Services and Production Solutions business units are reported together within this segment.

Engineering Services provides early stage engineering studies, including conceptual studies and FEED studies, primarily on a reimbursable basis. Engineering Services has two offices in India - in Mumbai and Chennai - which primarily support Engineering & Construction and a UK office in Woking which is more externally focused. Activity levels were significantly higher at our Indian offices in 2010, reflecting Engineering & Construction's increased demand for the unit's services, resulting from the reporting segment's record backlog entering into 2010 and its contract wins throughout the year. At our Woking office activity levels were marginally lower. Utilisation rates rose across all three offices throughout 2010.

Training Services provides competence-led training services, consultancy and managed solutions which are designed to increase competence and minimise risk. Services are provided primarily on a reimbursable basis. Delegate numbers were slightly higher than in 2009, and we saw strong growth from international markets, including our facilities at Sakhalin Island, Russia, and Baku, Azerbaijan. In October 2010, our training centre located near Homs in Syria was opened at a ceremony attended by the Syrian Prime Minister. The facility, which Petrofac will operate for five years, will deliver operations and maintenance training for Syrian graduates joining the oil & gas industry.

Training Services remains focused on strategic business development opportunities, both in the UK and internationally. Demand for our Training Services business is driven by a number of factors, including the 'nationalisation' of government workforces, the ageing of the industry's personnel and the potential increase in industry regulation in the wake of the Gulf of Mexico incident; these provide us with interesting medium to long-term opportunities.

Production Solutions provides customers with a wide range of services to help improve production, profitability, operational efficiency, asset integrity and the recovery of their reserves. In addition to providing these specialist services on a stand-alone basis, we are increasingly offering customers these services packaged together where we are remunerated on a tariff or quasi-equity basis. We were awarded our first such 'production enhancement' contract by Petrom in early July 2010. Under the terms of the 15-year contract, which includes an option for extension by a further ten years, Petrofac will provide production enhancement services to Petrom as the concession holder for the Ticleni oilfield and its eight satellite fields in Romania. We will be paid a tariff per barrel of oil produced, including an enhanced tariff for incremental production. Petrofac successfully completed the transition to assume full operational responsibility for these fields in November 2010: average oil production volumes from the first two months of operation were around 2.3% above baseline production.

In November 2010, Production Solutions entered into a strategic alliance with Seven Energy International Limited ('Seven Energy'), a Nigerian production and development company. Under the terms of the agreement Petrofac agreed to invest US$100 million to acquire a 15% interest in Seven Energy (12.6% on a fully diluted basis) and will assist Seven Energy with the development of its production, processing and transportation assets. Seven Energy has also issued warrants which, subject to the satisfaction of certain performance conditions and milestones in relation to project execution, will enable us to invest up to a further US$52 million, and take our interest to 19.2% on a fully diluted basis. Petrofac is providing experienced personnel to Seven Energy and is represented on its Board and management committees. The opportunity to co-invest and co-develop with Seven Energy, while deploying some of our own people, will give us the platform to establish a local presence in Nigeria, a high growth market where we have been seeking commercial opportunities for some years.

In October 2010, following a successful three and a half years of our service operator contract for Dubai Petroleum's offshore oil & gas assets, we successfully completed the transition to a technical services agreement with the Government of Dubai. The technical services agreement will be reported through Offshore Engineering & Operations.

Acquisitions

Within Engineering Services, the acquisition of TNEI represents the first step in positioning Petrofac in the renewable energy sector. TNEI was acquired in June 2010 for a total consideration of £6.1 million (see note 10 to the financial statements). TNEI is a specialist consultancy providing services in the areas of power transmission and distribution, particularly in relation to offshore wind projects, planning and environmental consent and energy management. TNEI has 50 staff in Newcastle and Manchester. The acquisition further broadens Petrofac's technical consulting capacity.

Results

Reported revenue for the year was slightly higher at US$355.3 million (2009: US$349.7 million) as was revenue excluding 'pass-through' revenue at US$322.8 million (2009: US$309.7 million), with an increase in revenues in both Engineering Services and Training Services being partially offset by lower revenues in Production Solutions as a consequence of the transition of our role on the Dubai Petroleum contract from service operator to a technical services agreement (and now accounted for in Offshore Engineering & Operations).

Net profit was 14.8% lower at US$27.6 million (2009: US$32.4 million), principally reflecting the change in scope on the Dubai Petroleum contract. This was also the primary driver for net margin on revenue excluding pass-through revenue falling to 8.5% (2009: 10.4%).

At 31 December 2010, headcount - including long-term contractors - was higher at 3,400 (2009: 2,900).The addition of approximately 900 Romanian workers on the Ticleni oilfield more than offset the reduction in headcount that followed the transfer of Dubai Petroleum staff to the Government of Dubai. We also continued to grow our Mumbai and Chennai offices, which are reported through Engineering Services but predominantly support the businesses in our Engineering & Construction reporting segment. We have recently decided to open a third Indian office in Delhi, and expect to accomplish this during 2011.

Backlog for the Engineering, Training Services and Production Solutions reporting segment was unchanged at year-end, at US$0.3 billion (2009: US$0.3 billion). The main factors affecting backlog related to Production Solutions, which saw order intake - primarily arising from the Ticleni contract - offset by the change in scope on the Dubai Petroleum contract.

Energy Developments

Where we can leverage our service capabilities to realise value, mitigate risks and reduce costs, Energy Developments provides a fully integrated service for resource holders under flexible commercial models that are aligned to their requirements. Projects cover upstream developments, both greenfield and brownfield, and related energy infrastructure projects, and can include the provision of capital.

In the first demonstration of our 'build and harvest' strategy, we completed the demerger of Energy Developments' UKCS assets, including its investments in the Don fields, in April 2010. These assets were demerged to create EnQuest PLC, an independent company which subsequently listed on the London and Stockholm stock exchanges. Our investment in the Don project generated a capital gain of US$124.9 million and an internal rate of return from inception to demerger of approximately 35%. We believe this transaction demonstrates the value of our 'build and harvest' strategy.

During the year, good progress was made on Energy Developments' portfolio of operational assets (Cendor, Ohanet, Chergui and the Kyrgyz Petroleum Company (KPC) refinery), as explored below:

Cendor PM304, Malaysia

Energy Developments operates the Cendor field, in Block PM304, offshore Peninsular Malaysia, in which it holds a 30% interest. This interest was acquired in 2004 and is held by way of a production sharing contract (PSC). Energy Developments' partners on this field are PETRONAS, Kuwait Foreign Petroleum Exploration Company (KUFPEC) and PetroVietnam, which hold interests of 30%, 25% and 15% respectively.

The Cendor field had another year of good performance, producing an average of 13,300 bpd of oil (2009: 14,400 bpd) and achieving production uptime of over 99%. Production is now in decline as a result of the natural decrease in field pressure. Energy Developments received approval for the Field Development Programme (FDP) for the second phase of development of Block PM304 in November 2010. This second phase will involve the replacement of the existing Mobile Offshore Production Unit (MOPU) and Floating Storage and Offloading (FSO) vessel with a Floating Production, Storage and Offloading (FPSO) vessel and fixed wellhead structures, designed to increase production capacity to 35,000 bopd. Preparations for this second phase are progressing well with the aim of beginning work in the first half of 2011.

Ohanet, Algeria

Energy Developments, in a joint venture with BHP Billiton (as joint venture operator), Japan Ohanet Oil & Gas Co and Woodside Energy (Algeria), has invested more than US$100 million for a 10% share in a RSC with Sonatrach, Algeria's national oil company. Through Engineering & Construction, we undertook the EPC contract for the gas processing facilities in joint venture with ABB Lummus and were responsible for part of the on-site commissioning works. As part of the RSC, the joint venture contractors are reimbursed for development costs and their share of the project's operating costs. The joint venture contractors' return for undertaking this investment is earned by way of remuneration equivalent to a percentage of the eligible development costs and our entitlement is paid from the monthly liquids production; hence any changes in production will vary the number of days over which the entitlement is earned.

Overall production was slightly lower than in 2009, averaging approximately 113,000 bpd of oil equivalent (2009: 123,100 bpd of oil equivalent). On average, we earned our share of the monthly liquids production by the 11^th day of the month (2009: 15^th), reflecting higher average oil & gas prices, partly offset by slightly lower production rates. The RSC contract is due to expire at the end of October 2011; eight years from first gas, over which time we expect to have earned our defined return.

Chergui field, Tunisia

In Tunisia, Energy Developments has a 45% operating interest in the Chergui gas plant. This interest was obtained in 2007 from Entreprise Tunisienne d'Activités Pétrolières (ETAP), the Tunisian national oil company, which holds the remaining 55% interest. Energy Developments' interest is held through a Concession. The commercial export of gas commenced in August 2008. Produced gas is sold to the national gas company, Société Tunisienne de Lélectricité et du Gaz (STEG), under a gas pricing formula fixed by existing law, in which the price of gas is linked to free-on-board Mediterranean (FOB Med) fuel oil prices.

The Chergui gas plant produced an average of 27.77 million standard cubic feet per day (mmscfd) of gas during the year (2009: 26.5 mmscfd), above the original nameplate design capacity of 20 mmscfd. A third production well was tied into the plant in early July 2010 to boost the production rate and increase gas recovery: production in December 2010 was the highest recorded rate since the start-up of the gas plant in June 2008. The development programme for 2011 includes the commitment to drill two to three wells to increase reserves and to explore the production of oil, as well as gas, from the field. Following recent civil unrest in Tunisia, we have had some short unplanned shut-ins of production, but generally the plant is operating normally. We continue to keep the situation under review.

KPC refinery, Kyrgyzstan

Energy Developments owns a 50% share in the Kyrgyz Petroleum Company (KPC) which is engaged in the refining of crude oil and the marketing of oil products from the 10,000 bpd capacity KPC refinery. KPC is jointly owned by Petrofac and Kyrgyzneftegaz, the state-owned oil & gas company in the Kyrgyz Republic. Petrofac has managed KPC's facilities and operations since 1998.

During 2010, the refinery performed in line with expectations, producing an average of approximately 1,700 bpd (2009: 2,000 bpd), principally of gasoline, diesel and fuel oil. The decrease in throughput was primarily due to civil unrest in the country, which shut down operations and halted processing at the refinery in April and June 2010. On both occasions the demobilisation of expatriate and local staff was deemed necessary.

FPF1 Floating Production Facility, undeployed

In July 2009, Energy Developments acquired a floating production facility, AH001 (subsequently renamed the FPF1), from Hess and Endeavour Energy UK. The FPF1 had been deployed on the Hess-operated Ivanhoe and Rob Roy Fields, in the UK North Sea, from 1989, with the Renee and Rubie Fields produced over it since 1999. The vessel has a processing capacity of 45,000 bpd of oil and 56 mmscfd of gas with water injection capability of 90,000 bpd and water treatment of 40,000 bpd.

The vessel remains quayside at the McNulty offshore facility in Newcastle-upon-Tyne, while options for its redeployment on fields, including those where Energy Developments has or can take an interest, are considered. Several options for deployment, including in the UK North Sea, have been identified and are being pursued with conceptual engineering and proposal preparation work. We expect that a redeployment contract for the vessel will be secured in 2011. We are currently completing general repair and upgrade work on the vessel, which will be followed by planned specific dry-dock work to satisfy external verification requirements to obtain a class certificate. This will enable the FPF1 continued operation in the harsh environment of the UK North Sea for ten years, without the need for a special survey.

Gateway Storage Company Limited, UK

In December 2010, Energy Developments acquired a 20% interest in Gateway Storage Company Limited (Gateway), to progress and develop the Gateway Gas Storage project in the East Irish Sea. This project would add nearly 30% to the current gas storage capacity in the UK market, and has secured the first gas storage licence from the UK Department of Energy & Climate Change in February 2010. Petrofac joined Gateway as the technical project operator and is represented on Gateway's board.

Berantai field development and East Fortune FPSO, Malaysia

In January 2011, Energy Developments signed a RSC to lead the development of the Berantai field, offshore Peninsular Malaysia, for PETRONAS, Malaysia's national oil company. Petrofac has a 50% interest in the RSC, alongside our Malaysian partners Kencana Energy Sdn Bhd and Sapura Energy Ventures Sdn Bhd, both of which hold a 25% interest (together known as the 'Berantai partners'). The Berantai partners will develop the field and will subsequently operate the field for a period of seven years after first gas production.

The capital budget for the full field development, excluding delivery of the FPSO, is approximately US$800 million, of which Petrofac's share is 50%. Under the terms of the RSC, the Berantai partners are expected to receive a rate of return linked to their performance against an agreed incentive structure, including project costs, timing to first gas and sustained gas delivery measured six months after project completion, with an ongoing incentive structure based on operational uptime.

Acquisitions

Petrofac completed the acquisition of CO₂DeepStore in April 2010, a UK-based CO2 storage company (see note 10 to the financial statements). The combination of CO₂DeepStore and Petrofac establishes a leading development capability for CO2 storage projects, providing a complete service for power generators and other CO2 emitters.

In October 2010, CO₂DeepStore signed an agreement with Shell U.K. Limited (Shell) for the re-development of the Goldeneye gas field in the North Sea as a potential CO2 storage facility. The agreement will see CO₂DeepStore and Shell work together to develop the potential CO2 storage solution for the ScottishPower Carbon Capture and Storage (CCS) project. Work on the initial design phase for the project is due to complete in the first half of 2011 and, subject to satisfactory contract negotiations, achieve contract award later in the year.

Results

Energy Developments' revenue was lower at US$188.2 million in 2010 (2009: US$248.7 million), primarily due to the disposal of the Don assets following the April 2010 demerger. On a like-for-like basis (excluding the contribution of the Don assets), Energy Developments' revenue was marginally higher at US$172.8 million this year (2009: US$170.4 million).

Including the gain on the EnQuest demerger, net profit for Energy Developments rose by 238% to US$156.4 million (2009: US$46.2 million). Excluding this gain, despite the higher average oil price in 2010⁽⁷⁾ and notwithstanding the non-recurring NT/P68 write-off of US$3.7 million in the prior year, the loss of contribution from the Don assets as well as lower production on Cendor meant that profit was lower at US$31.5 million (2009: US$46.2 million). On a like-for-like basis (excluding the contribution of the Don assets and the gain on the EnQuest demerger), trading net profit for Energy Developments was US$29.4 million in 2010 (2009: US$33.5 million).

At 31 December 2010, headcount had grown to 600 (2009: 500).

An analysis of Energy Developments' oil & gas reserve entitlements is presented on page 186.

Financial review

Revenue

Group revenue increased by 19.1% to US$4,354.2 million (2009: US$3,655.4 million) due to strong growth in Engineering & Construction and Offshore Engineering & Operations, partly offset by a decrease in Energy Developments following the EnQuest demerger in April 2010. The strong growth in the Engineering & Construction reporting segment (up 29.7%), which accounted for approximately three-quarters of the group's revenue, was as a result of high levels of activity on lump-sum EPC contracts, particularly on those contracts awarded in 2009 and late 2008. The increase in revenues in Offshore Engineering & Operations (up 15.2%) was as a result of activity on major contracts awarded in the second half of 2009 and 2010 and a general improvement in market conditions.

Operating profit

Group operating profit for the year was US$663.5 million (2009 restated: US$432.0 million), an increase of 53.6%. Excluding the gain on the EnQuest demerger, group operating profit increased by 24.7% to US$538.6 million (2009 restated: US$432.0 million) and operating margins increased to 12.4% (2009 restated: 11.8%). The increase in operating margin was predominantly due to an increase in the operating margin in Engineering & Construction, but also higher operating margins in Energy Developments and Offshore Engineering & Operations, partially offset by a reduction in operating margin in the Engineering, Training Services and Production Solutions reporting segment and a decrease in the proportion of group operating margin generated by the high margin Energy Developments reporting segment following the EnQuest demerger.

Net profit

Reported profit for the year attributable to Petrofac Limited shareholders increased 57.8% to US$557.8 million (2009 restated: US$353.6 million). Excluding the gain on the EnQuest demerger of US$124.9 million (2009: nil), profit for the year attributable to Petrofac Limited shareholders increased to US$433.0 million (2009: US$353.6 million), an increase of 26.4% on a like-for-like basis⁽²⁾. The increase was driven primarily by strong revenue growth in Engineering & Construction along with an increase in net margin due to excellent operational performance, with good progress on our portfolio of projects, including the completion or substantial completion of five large EPC projects during the year and first time profit recognition on a number of projects. The net margin for the group, excluding the gain on the EnQuest demerger, increased to 9.9% (2009: 9.7%), due to net margin improvement in Engineering & Construction and Offshore Engineering & Operations, offset by net margin reduction in the Engineering, Training Services and Production Solutions and Energy Developments reporting segments and an increase in net corporate and other costs. Net corporate and other costs increased due to a reduction in intra-group interest income earned as a result of Petrofac Limited capitalising a loan to Energy Developments as part of the EnQuest demerger, corporate support costs incurred in relation to the demerger and an increase in other shareholder related costs.

EBITDA

Reported EBITDA increased 38.1% to US$759.4 million (2009 restated: US$549.7 million). Excluding the gain on the EnQuest demerger of US$124.9 million (2009: nil), EBITDA increased by 15.4% to US$634.5 million (2009 restated: US$549.7 million), representing an EBITDA margin of 14.6% (2009 restated: 15.0%). Despite an increase in EBITDA margins in the Engineering & Construction and Offshore Engineering & Operations reporting segments, only partially offset by lower margins in the Engineering, Training Services and Production Solutions and Energy Developments reporting segments, the group EBITDA margin was lower due to a reduction in the share of group EBITDA, excluding the effect of corporate, consolidation and elimination adjustments, from the higher margin Energy Developments reporting segment following the EnQuest demerger (from 28.7% in 2009 (restated) to 17.8% in 2010). Engineering & Construction's share of group EBITDA, excluding the effect of corporate, consolidation and elimination adjustments, and the gain on the EnQuest demerger, increased to 72.7% (2009 restated: 60.2%) due to strong revenue and margin growth in the Engineering & Construction reporting segment and the relative decrease in Energy Developments' contribution.

Backlog

The group's combined backlog at the end of 2010 stood at record levels of US$11.7 billion (2009: US$8.1 billion), reflecting high levels of order intake during the year, both in Engineering & Construction (US$6.0 billion) and Offshore Engineering & Operations (US$1.6 billion).

Exchange rates

The group's reporting currency is US dollars. A significant proportion of Offshore Engineering & Operations' revenue is generated in the UKCS and those revenues and associated costs are generally denominated in sterling; however, there was little change in the average exchange rate for the US dollar against sterling for the years ended 31 December 2010 and 2009 and therefore little exchange rate impact on our US dollar reported results. The table below sets out the average and year-end exchange rates for the US dollar and sterling as used by the group for financial reporting purposes.

Financial reporting exchange rates

US$/Sterling

2010

2009

Average rate for the year

1.54

1.56 Year-end rate

1.56

1.62

Interest

Net finance income for the year was lower at US$5.1 million (2009: US$6.4 million) due to lower average net cash balances compared to the prior year (see 'Operating cash flow and liquidity').

Taxation

An analysis of the income tax charge is set out in note 6 to the financial statements. The income tax charge for the year as a percentage of profit before tax was 16.5%. Excluding the gain from the EnQuest demerger (upon which there was no chargeable gain for UK corporate tax purposes), the income tax charge for the year as a percentage of profit before tax was marginally higher than the prior year at 20.3% (2009 restated: 19.3%). The increase was due to Energy Developments' effective tax rate (excluding the gain from the EnQuest demerger) which increased to 50.3% (2009: 30.8%) due to ring fence expenditure supplement no longer being available for claim following the EnQuest demerger. Notwithstanding the adjustments made in the prior year in respect of the applicability of the lower tax rate to the group's projects in Oman, the Engineering & Construction effective tax rate decreased to 16.8% (2009 restated: 18.8%) due to material changes in the jurisdictions in which profits were earned.

Earnings per share

Fully diluted earnings per share increased to 162.46 cents per share (2009: 103.19 cents), an increase of 57.4%, in line with the group's increase in profit for the year attributable to Petrofac Limited shareholders. Excluding the gain on the EnQuest demerger, fully diluted earnings per share increased by 22.2% to 126.09 cents per share (2009: 103.19 cents).

Operating cash flow and liquidity

The net cash generated from operations was US$207.3 million (2009: US$1,276.3 million), representing 32.7% of EBITDA excluding the gain on the EnQuest demerger (2009: 228.3%). The lower net cash inflow compared to the prior year was due principally to an unwinding of advance payments received from customers in relation to Engineering & Construction projects, with the 20% advance payment on our major award in Turkmenistan not being received until after the year-end, and a build up of in work in progress. Much of the increase in work in progress related to one Engineering & Construction project, where billing was delayed pending contractual amendments. The work in progress position on this project began to improve during the second half of 2010 following finalisation of the contractual amendments and we expect it to normalise over the coming months.

At 31 December 2010, the group's net cash was lower at US$975.3 million (2009: US$1,300.1 million) as the net result of cash generated from operating profits before working capital and other non-current changes of US$667 million, less:

· net working capital outflows of US$451 million, including a reduction in advance payments received from customers and an increase in work in progress in relation to Engineering & Construction projects, totalling US$491 million (in 2009 the group received net working capital inflows of US$714 million, including US$439 million of advance payments on Engineering & Construction projects)

· investing activities of US$254 million, including:

o the investment of US$100 million to acquire a 15% stake in Seven Energy (12.6% on a fully diluted basis; see page 30 for details)

o the acquisition of TNEI, CO₂Deepstore, Scotvalve and Stephen Gillespie Consultants at a cost of US$15 million and the investment of an initial US$8 million for a 20% stake in Gateway Gas Storage (see page 12)

o capital expenditure of US$59 million in relation to Energy Developments' portfolio of assets, including US$26 million on the Don fields prior to the EnQuest demerger and US$16 million on Cendor PM304 near field development

o capital expenditure on other property, plant and equipment of US$72 million, including temporary project camp facilities, office equipment and furniture and site-based vehicles, predominantly in Engineering & Construction

· financing activities of US$201 million, including:

o payment of the 2009 final dividend and 2010 interim dividend totalling US$132 million

o repayment of interest-bearing loans and borrowings of US$32 million

o financing the purchase of treasury shares for the purpose of making awards under the group's share schemes of US$36 million

· taxes paid of US$99 million

The group reduced its levels of interest-bearing loans and borrowings to US$87.7 million (2009: US$117.3 million) following scheduled loan repayments in 2010. Despite a reduction in the net assets of the group as a result of the EnQuest demerger, the group's gross gearing ratio fell to 11.3% (2009 restated: 13.1%) reflecting the reduction in interest-bearing loans and borrowings.

Gearing ratio	2010	2009 restated
	US$ millions (unless otherwise stated)
Interest-bearing loans and borrowings (A)	87.7	117.3
Cash and short term deposits (B)	1,063.0	1,417.4
Net cash/(debt) (C = B - A)	975.3	1,300.1
Total net assets (D)	779.1	897.5
Gross gearing ratio (A/D)	11.3%	13.1%
Net gearing ratio (C/D)	Net cash position	Net cash position

The group's total gross borrowings before associated debt acquisition costs at the end of 2010 were US$91.8 million (2009: US$123.1 million), of which 39.5% was denominated in US dollars (2009: 51.0%) and 60.5% was denominated in sterling (2009: 49.0%).

As detailed in note 33 to the financial statements, the group maintained a balanced borrowing profile at 31 December 2010 with 51.7% of borrowings maturing within one year and 48.3% maturing between one and five years (2009: 47.2% and 52.8%). The borrowings repayable within one year include US$28.9 million of bank overdrafts (representing 31.5% of total gross borrowings), which are expected to be renewed during 2011 in the normal course of business (2009: US$46.6 million and 37.9% of total gross borrowings repayable within one year, including US$20.0 million of revolving credit facilities).

None of the Company's subsidiaries are subject to any material restrictions on their ability to transfer funds in the form of cash dividends, loans or advances to the Company.

Capital expenditure

Capital expenditure on property, plant and equipment was lower during the year ended 31 December 2010 at US$116.2 million (2009: US$375.4 million), as almost three-quarters of the capital expenditure in the prior year was in relation to the now demerged Don assets. The principal elements of capital expenditure during the year were:

· investment in temporary project camps, office improvements, equipment and furniture and vehicles in Engineering & Construction, reflecting the increase in activity levels and personnel, of US$60.1 million

· additions to Energy Developments' oil & gas assets, including:

o development expenditure on the Don assets prior to demerger of US$26.1 million

o upgrade works on the FPF1 floating production facility of US$7.3 million

Capital expenditure on intangible oil & gas assets during the year was US$15.6 million (2009: US$29.2 million) in respect of capitalised expenditure on near field appraisal wells in relation to Energy Developments' interest in Block PM304, offshore Malaysia.

Shareholders' funds

Total equity at 31 December 2010 was US$779.1 million (2009 restated: US$897.5 million). The main elements of the net movement were: net profit for the year of US$557.9 million, less dividends paid in the year of US$132.0 million, the distribution on the EnQuest demerger of US$544.5 million (see note 11 to the financial statements) and the purchase of treasury shares of US$36.5 million, which are held in the Petrofac Employees Benefit Trust for the purpose of making awards under the group's share schemes (see note 23 to the financial statements).

Return on capital employed⁽⁸⁾

The group's return on capital employed, including the gain on the EnQuest demerger, for the year ended 31 December 2010 was 65.2% (2009: 46.9%).

Dividends and distribution

The Company proposes a final dividend of 30.00 cents per share for the year ended 31 December 2010 (2009: 25.10 cents), which, if approved, will be paid to shareholders on 20 May 2011 provided they were on the register on 26 April 2011. Shareholders who have not elected (before 4 March 2011) to receive dividends in US dollars will receive a sterling equivalent of 18.42 pence per share.

Together with the interim dividend of 13.80 cents per share (2009: 10.80 cents), equivalent to 8.91 pence, this gives a total dividend for the year of 43.80 cents per share (2009: 35.80 cents), an increase of 22.3%.

In addition to the interim and final dividends, the Company made a non-cash distribution of one EnQuest share for every one Petrofac Limited share held immediately prior to the demerger, which for accounting purposes had a total fair value of US$553.3 million, equivalent to 160.08 cents per share.

Forward-looking statements

The Business Review (pages 1 to 41) contains forward-looking statements with respect to the financial condition, results, and operations of the group. By their nature, forward-looking statements involve a number of risks, uncertainties or assumptions that could cause actual results or events to differ materially from those expressed or implied by the forward-looking statements. These risks, uncertainties or assumptions could adversely affect the outcome and financial effects of the plans and events described herein. Forward-looking statements contained in the Business Review regarding past trends or activities should not be taken as representation that such trends or activities will continue in the future. Petrofac Limited undertakes no obligation to update the forward-looking statements contained in this review or any other forward-looking statements made.

Notes

⁽¹⁾Net profit for the year attributable to Petrofac Limited shareholders.

⁽²⁾Like-for-like net profit growth excludes the gain of US$124.9 million on the EnQuest demerger and the trading net profit from Energy Developments' demerged assets of US$12.7 million for the year ended 31 December 2009 and US$2.1 million for the year ending 31 December 2010.

⁽³⁾Backlog consists of the estimated revenue attributable to the uncompleted portion of lump-sum engineering, procurement and construction contracts and variation orders plus, with regard to engineering services and facilities management contracts, the estimated revenue attributable to the lesser of the remaining term of the contract and, in the case of life-of-field facilities management contracts, five years. The group uses this key performance indicator as a measure of the visibility of future earnings. Backlog is not an audited measure.

⁽⁴⁾The group reports its financial results in US dollars and, accordingly, will declare any dividends in US dollars together with a Sterling equivalent. Unless shareholders have made valid elections to the contrary, they will receive any dividends payable in Sterling. Conversion of the 2010 final dividend from US dollars into Sterling is based upon an exchange rate of US$1.6290:£1, being the Bank of England Sterling spot rate as at midday on 4 March 2011.

⁽⁵⁾Contracts where the group takes full responsibility for managing a customer's asset and is responsible for the safety case of the asset, reporting to the UK Department of Energy and Climate Change.

⁽⁶⁾Pass-through revenue refers to the revenue recognised from low or zero margin third-party procurement services provided to customers.

⁽⁷⁾ For example, Brent, a benchmark crude oil, averaged US$79.50 per barrel for 2010 (2009: US$61.67 per barrel).

⁽⁸⁾ROCE is calculated as EBITA (earnings before interest, tax, amortisation and impairment charges, calculated as EBITDA less depreciation per note 3 to the financial statements) divided by average capital employed (being total equity and non-current liabilities per the consolidated balance sheet).

Petrofac Limited

CONSOLIDATED INCOME STATEMENT

For the year ended 31 December 2010

		2010	2009
	Notes	US$'000	US$'000
			Restated


Revenue	4a	4,354,217	3,655,426

Cost of sales	4b	(3,595,142)	(3,038,250)

Gross profit		759,075	617,176

Selling, general and administration expenses	4c	(221,449)	(186,293)
Gain on EnQuest demerger	11	124,864	-
Other income	4f	5,013	4,075
Other expenses	4g	(4,053)	(2,998)

Profit from operations before tax
and finance income/(costs)		663,450	431,960

Finance costs	5	(5,131)	(5,582)
Finance income	5	10,209	11,942
Share of loss of associate	14	(131)	-

Profit before tax		668,397	438,320

Income tax expense	6	(110,545)	(84,515)

Profit for the year		557,852	353,805

Attributable to:

Petrofac Limited shareholders		557,817	353,603
Non-controlling interests		35	202

		557,852	353,805






Earnings per share (US cents)	7

- Basic (excluding gain on EnQuest demerger)		127.76	104.78
- Diluted (excluding gain on EnQuest demerger)		126.09	103.19

- Basic (including gain on EnQuest demerger)		164.61	104.78
- Diluted (including gain on EnQuest demerger)		162.46	103.19

The attached notes 1 to 35 form part of these consolidated financial statements.

Petrofac Limited

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2010


		2010	2009
	Notes	US$'000	US$'000
			Restated


Profit for the year		557,852	353,805

Foreign currency translation	25	(908)	15,087

Foreign currency translation recycled to income statement in the year on EnQuest demerger	11	45,818	-

Net gains on maturity of cash flow hedges
recycled in the period	25	(16,612)	(4,303)

Net changes in fair value of derivatives and
financial assets designated as cash flow hedges	25	(18,958)	29,229

Net changes in the fair value of available-for-sale
financial assets	25	70	-

Disposal of available-for-sale financial assets	25	(74)	-

Other comprehensive income		9,336	40,013


Total comprehensive income for the period		567,188	393,818

Attributable to:

Petrofac Limited shareholders		567,153	393,616
Non-controlling interests		35	202

		567,188	393,818

The attached notes 1 to 35 form part of these consolidated financial statements.

Petrofac Limited CONSOLIDATED STATEMENT OF FINANCIAL POSITION At 31 December 2010		2010	2009
	Notes	US$'000	US$'000
			Restated
ASSETS
Non-current assets
Property, plant and equipment	9	287,158	677,996
Goodwill	12	105,832	97,922
Intangible assets	13	85,837	73,107
Investment in associates	14	16,349	-
Available-for-sale financial assets	16	101,494	539
Other financial assets	17	2,223	12,535
Deferred income tax assets	6c	26,301	49,726
		625,194	911,825

Current assets
Inventories	18	7,202	9,798
Work in progress	19	803,986	333,698
Trade and other receivables	20	1,056,759	878,670
Due from related parties	32	327	18,260
Other financial assets	17	42,350	30,957
Income tax receivable		2,525	-
Cash and short-term deposits	21	1,063,005	1,417,363
		2,976,154	2,688,746

TOTAL ASSETS		3,601,348	3,600,571


EQUITY AND LIABILITIES
Equity attributable to Petrofac Limited shareholders
Share capital	22	6,914	8,638
Share premium		992	69,712
Capital redemption reserve		10,881	10,881
Shares to be issued		994	1,988
Treasury shares	23	(65,317)	(56,285)
Other reserves	25	34,728	25,394
Retained earnings		787,270	834,382
		776,462	894,710
Non-controlling interests		2,592	2,819

TOTAL EQUITY		779,054	897,529

Non-current liabilities
Interest-bearing loans and borrowings	26	40,226	59,195
Provisions	27	45,441	92,103
Other financial liabilities	28	11,453	27,485
Deferred income tax liabilities	6c	48,086	42,192
		145,206	220,975

Current liabilities
Trade and other payables	29	1,021,436	977,017
Due to related parties	32	11,710	57,326
Interest-bearing loans and borrowings	26	47,435	58,071
Other financial liabilities	28	37,054	3,634
Income tax payable		105,559	88,219
Billings in excess of cost and estimated earnings	19	178,429	461,144
Accrued contract expenses	30	1,275,465	836,656
		2,677,088	2,482,067

TOTAL LIABILITIES		2,822,294	2,703,042

TOTAL EQUITY AND LIABILITIES		3,601,348	3,600,571

The financial statements on pages 108 to 167 were approved by the Board of Directors on 4 March 2011 and signed on its behalf by Keith Roberts - Chief Financial Officer.

The attached notes 1 to 35 form part of these consolidated financial statements.

Petrofac Limited CONSOLIDATED STATEMENT OF CASH FLOWS For the year ended 31 December 2010
		2010		2009
	Notes	US$'000		US$'000

OPERATING ACTIVITIES
Profit before tax including gain on EnQuest demerger		668,397		438,320
Gain on EnQuest demerger		(124,864)		-
		543,533		438,320
Non-cash adjustments to reconcile profit before tax to net cash flows:
Depreciation, amortisation, impairment and write off	4b, 4c	95,903		117,780
Share-based payments	4d	14,784		13,263
Difference between other long-term employment benefits paid and amounts recognised in the
income statement		6,074		7,905
Net finance income	5	(5,078)		(6,360)
Loss/(gain) on disposal of property, plant and equipment	4b,4f,4g	315		(784)
Gain on disposal of intangible assets	4f	(2,338)		-
Other non-cash items, net		13,319		(3,233)

		666,512		566,891
Working capital adjustments:
Trade and other receivables		(266,757)		(176,773)
Work in progress		(470,288)		(81,003)
Due from related parties		17,933		(15,353)
Inventories		(2,982)		(5,721)
Other current financial assets		(12,661)		(4,775)
Trade and other payables		167,707		479,902
Billings in excess of cost and estimated earnings		(282,715)		175,617
Accrued contract expenses		438,809		284,795
Due to related parties		(45,616)		56,767
Other current financial liabilities		6,045		177

		215,987		1,280,524
Other non-current items, net		(8,720)		(4,265)

Cash generated from operations		207,267		1,276,259
Interest paid		(1,948)		(3,351)
Income taxes paid, net		(99,030)		(87,714)

Net cash flows from operating activities		106,289		1,185,194

INVESTING ACTIVITIES
Purchase of property, plant and equipment		(115,345)	(317,174)
Acquisition of subsidiaries, net of cash acquired	10	(15,110)	-
Purchase of other intangible assets	13	(153)	(10,375)
Purchase of intangible oil & gas assets	13	(15,644)	(29,230)
Cash outflow on EnQuest demerger (including transaction costs		(17,783)	-
Investment in associates	14	(8,459)	-
Purchase of available-for-sale financial assets	16	(101,494)	(106)
Proceeds from disposal of property, plant and equipment		3,219	1,333
Proceeds from disposal of available-for-sale financial assets		539	95
Proceeds from sale on intangible assets		6,018	-
Interest received		10,257	12,158

Net cash flows used in investing activities		(253,955)	(343,299)

The attached notes 1 to 35 form part of these consolidated financial statements.

		2010	2009
	Notes	US$'000	US$'000

FINANCING ACTIVITIES
Repayment of interest-bearing loans and borrowings		(32,458)	(9,958)
Proceeds from capital injection by non-controlling interest		-	2,408
Treasury shares purchased	23	(36,486)	-
Equity dividends paid		(132,244)	(98,995)

Net cash flows used in financing activities		(201,188)	(106,545)


NET DECREASE IN CASH AND CASH EQUIVALENTS		(348,854)	735,350

Net foreign exchange difference		(7,793)	6,235

Cash and cash equivalents at 1 January		1,390,744	649,159

CASH AND CASH EQUIVALENTS AT 31 DECEMBER	21	1,034,097	1,390,744

The attached notes 1 to 35 form part of these consolidated financial statements.

Petrofac Limited

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2010

Attributable to shareholders of Petrofac Limited

	Issued		Capital						Non- controlling interests
	share	Share	redemption	Shares to	*Treasury	Other	Retained			Total
	capital	premium	reserve	be issued	shares	reserves	earnings	Total		Equity
For the year ended	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
31 December 2010					(note 23)	(note 25)

Balance at 1 January 2010 as restated	8,638	69,712	10,881	1,988	(56,285)	25,394	834,382	894,710	2,819	897,529

Net profit for the year	-	-	-	-	-	-	557,817	557,817	35	557,852
Other comprehensive income	-	-	-	-	-	9,336	-	9,336	-	9,336

Total comprehensive income
for the year	-	-	-	-	-	9,336	557,817	567,153	35	567,188

Shares issued as payment of
consideration of acquisition	4	2,452	-	(994)	-	-	-	1,462	-	1,462

Share-based payments charge (note 24)	-	-	-	-	-	14,784	-	14,784	-	14,784

Shares vested during the year (note 23)	-	-	-	-	27,454	(26,170)	(1,284)	-	-	-

Transfer to reserve for share-based payments (note 24)	-	-	-	-	-	12,750	-	12,750	-	12,750

Treasury shares purchased
(note 23)	-	-	-	-	(36,486)	-	-	(36,486)	-	(36,486)

Deferred tax on share based payment reserve	-	-	-	-	-	(1,366)	-	(1,366)	-	(1,366)

EnQuest demerger share split
and redemption (note 11)	(1,728)	-	-	-	-	-	1,728	-	-	-

Distribution on EnQuest
demerger (note 11)	-	(71,172)	-	-	-	-	(473,325)	(544,497)	-	(544,497)

Dividends (note 8)	-	-	-	-	-	-	(132,048)	(132,048)	-	(132,048)

Movement in non-controlling
interest	-	-	-	-	-	-	-	-	(262)	(262)

Balance at 31 December 2010	6,914	992	10,881	994	(65,317)	34,728	787,270	776,462	2,592	779,054

* Shares held by Petrofac Employee Benefit Trust.

The attached notes 1 to 35 form part of these consolidated financial statements.

Attributable to shareholders of Petrofac Limited

	Issued		Capital						Non- controlling interests
	share	Share	redemption	Shares to	*Treasury	Other	Retained			Total
	capital	premium	reserve	be issued	shares	reserves	earnings	Total		equity
For the year ended	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
31 December 2009					(note 23)	(note 25)

Balance at 1 January 2009	8,636	68,203	10,881	1,988	(69,333)	(39,292)	577,739	558,822	209	559,031

Net profit for the year as reported	-	-	-	-	-	-	353,603	353, 603	9,428	363,031
Other comprehensive income as reported	-	-	-	-	-	35,813	-	35,813	4,200	40,013

Total comprehensive income
for the year as reported	-	-	-	-	-	35,813	353, 603	389,416	13,628	403,044

Restatement	-	-	-	-	-	4,200	-	4,200	(13,426)	(9,226)

Total comprehensive income
for the year as restated	-	-	-	-	-	40,013	353, 603	393,616	202	393,818

Shares issued on acquisition	2	1,509	-	-	-	-	-	1,511	-	1,511

Share-based payments charge (note 24)	-	-	-	-	-	13,263	-	13,263	-	13,263

Shares vested during the year (note 23)	-	-	-	-	13,048	(12,617)	(431)	-	-	-

Transfer to reserve for share-based payments (note 24)	-	-	-	-	-	10,942	-	10,942	-	10,942

Deferred tax on share based payment reserve	-	-	-	-	-	13,085	-	13,085	-	13,085

Capital injection by non-controlling interests	-	-	-	-	-	-	-	-	2,408	2,408

Dividends (note 8)	-	-	-	-	-	-	(96,529)	(96,529)	-	(96,529)

Balance at 31 December 2009 as restated	8,638	69,712	10,881	1,988	(56,285)	25,394	834,382	894,710	2,819	897,529

* Shares held by Petrofac Employee Benefit Trust.

The attached notes 1 to 35 form part of these consolidated financial statements.

Petrofac Limited

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the year ended 31 December 2010

1 CORPORATE INFORMATION

The consolidated financial statements of Petrofac Limited (the "Company") for the year ended 31 December 2010 were authorised for issue in accordance with a resolution of the directors on 4 March 2011.

Petrofac Limited is a limited liability company registered and domiciled in Jersey under the Companies (Jersey) Law 1991 and is the holding company for the international group of Petrofac subsidiaries (together "the group"). The Company's 31 December 2010 financial statements are shown on pages 108 to 167. The group's principal activity is the provision of facilities solutions to the oil & gas production and processing industry.

A full listing of all group companies, and joint venture companies, is contained in note 35 to these consolidated financial statements.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of preparation

The consolidated financial statements have been prepared on a historical cost basis, except for derivative financial instruments and available-for-sale financial assets which have been measured at fair value. The presentation currency of the consolidated financial statements is United States Dollars and all values in the financial statements are rounded to the nearest thousand (US$'000) except where otherwise stated. The directors have re-considered the nature of the contractual commitments to a joint venture on a lump sum construction contract in the Engineering & Construction reporting segment and as a result, the amount of US$9,226,000 shown as part of non-controlling interest in December 2009 in the income statement has been reclassified to Cost of Sales. Similarly US$4,200,000 shown within Other Comprehensive Income has been shown as attributable to Petrofac. US$9,226,000 in the statement of financial position has been reclassified as trade and other payables.

Statement of compliance

The consolidated financial statements of Petrofac Limited and its subsidiaries have been prepared in accordance with International Financial Reporting Standards (IFRS) and applicable requirements of Jersey law.

Basis of consolidation

The consolidated financial statements comprise the financial statements of Petrofac Limited and its subsidiaries. The financial statements of its subsidiaries are prepared for the same reporting year as the Company and where necessary, adjustments are made to the financial statements of the group's subsidiaries to bring their accounting policies into line with those of the group.

Subsidiaries are consolidated from the date on which control is transferred to the group and cease to be consolidated from the date on which control is transferred out of the group. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. All intra-group balances and transactions, including unrealised profits, have been eliminated on consolidation.

Non-controlling interests in subsidiaries consolidated by the group are disclosed separately from the group's equity and income statement. Prior to 1 January 2010 losses incurred by the group were attributed to non-controlling interests until the balance is reduced to nil. Any further excess losses were attributed to the parent, unless there was a binding obligation on the part of the non-controlling interest to cover these. Losses prior to 1 January 2010 were not reallocated between non-controlling interests and the parent shareholders.

New standards and interpretations

The group has adopted new and revised Standards and Interpretations issued by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) of the IASB that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2010. The principal effects of the adoption of these new and amended standards and interpretations are discussed below:

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

IFRS 3 'Business Combinations (Revised)' the revised standard increases the number of transactions to which it must be applied including business combinations of mutual entities and combinations without consideration. IFRS 3 (revised) introduces significant changes in the accounting for business combinations such as valuation of non-controlling interest, business combination achieved in stages, the initial recognition and subsequent measurement of a contingent consideration and the accounting for transaction costs. These changes will have a significant impact on profit or loss reported in the period of an acquisition, the amount of goodwill recognised in a business combination and profit or loss reported in future periods.

IAS 27 'Consolidated and Separate Financial Statements (Amendments)' the amended standard requires that a change in the ownership interest of a subsidiary (without loss of control) is accounted for as a transaction with owners in their capacity as owners and these transactions will no longer give rise to goodwill or gains and losses. The standard also specifies the accounting when control is lost and any retained interest is remeasured to fair value with gains or losses recognised in profit or loss.

IFRIC 17 'Distributions of Non-cash Assets to owners' this interpretation provides guidance in respect of accounting for non-cash asset distributions to shareholders. This interpretation is effective for periods beginning on or after 1 July 2009. See note 11 for distributions in respect of EnQuest demerger.

IFRS 8 'Operating Segments'the amendment clarifies that segment assets and liabilities need not be reported if they are not used as a measure by the chief operating decision maker. As segment assets and liabilities are not reviewed by the chief operating decision maker for operational and financial decisions, the group has opted not to disclose segment assets and liabilities in note 3.

IAS 36 'Impairment of assets' the amendment clarifies that operating segments as defined in IFRS 8 prior to aggregation for reporting purposes, are the largest unit for allocating goodwill on acquisitions. The amendment has no impact on the group as goodwill impairment testing is performed on cash generating units before aggregation.

Certain new standards, amendments to and interpretations of existing standards have been issued and are effective for the group's accounting periods beginning on or after 1 January 2011 or later periods which the group has not early adopted. The following are applicable to the group for which the impact on the group's operating results or financial position of the will be assessed on adoption of these standards and interpretations:

i) IFRS 9 'Financial Instruments' effective for annual periods beginning on or after 1 January 2013, reflects the first phase of the IASB's work on the replacement of IAS 39 and applies to the classification and measurement of financial assets. It specifies that all financial assets should be initially measured at fair value and gives further guidance on the measurement of debt instruments and equity instruments. In subsequent phases, the IASB will address the classification and measurement of financial liabilities, hedge accounting and derecognition. The completion of this project is expected in early 2011. The management believes that this standard will not have a significant effect on the group's financial position.

ii) IAS 24 'Related party disclosures (Revised)' effective for annual periods beginning on or after 1 January 2011. The revision simplifies the identification of related party relationships, particularly in relation to significant influence and joint control. The management believes that this standard will not have a significant effect on the group's financial position.

Other amendments resulting from improvements to IFRS to the following standards and interpretations did not have any impact on the accounting policies, financial position or performance of the group:

IAS 1 'Presentation of Financial Statements'

IAS 32 'Financial Instruments: Presentation - Classification of Rights Issues (Amendment)'

IFRIC 14 'Prepayments of a Minimum Funding Requirement (Amendment)'

IFRIC 19 'Extinguishing Financial Liabilities with Equity Instruments'

Significant accounting judgements and estimates

Judgements

In the process of applying the group's accounting policies, management has made the following judgements, apart from those involving estimations, which have the most significant effect on the amounts recognised in the consolidated financial statements:

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Significant accounting judgements and estimates (continued)

· Revenue recognition on fixed-price engineering, procurement and construction contracts: the group recognises revenue on fixed-price engineering, procurement and construction contracts using the percentage-of-completion method, based on surveys of work performed. The group has determined this basis of revenue recognition is the best available measure of progress on such contracts.

Estimation uncertainty

The key assumptions concerning the future and other key sources of estimation uncertainty at the statement of financial position date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below:

· Project cost to complete estimates: at each statement of financial position date the group is required to estimate costs to complete on fixed price contracts. Estimating costs to complete on such contracts requires the group to make estimates of future costs to be incurred, based on work to be performed beyond the statement of financial position date.

· Onerous contract provisions: the group provides for future losses on long-term contracts where it is considered probable that the contract costs are likely to exceed revenues in future years. Estimating these future losses involves a number of assumptions about the achievement of contract performance targets and the likely levels of future cost escalation over time.

· Impairment of goodwill: the group determines whether goodwill is impaired at least on an annual basis. This requires an estimation of the value in use of the cash-generating units to which the goodwill is allocated. Estimating the value in use requires the group to make an estimate of the expected future cash flows from each cash-generating unit and also to determine a suitable discount rate in order to calculate the present value of those cash flows. The carrying amount of goodwill at 31 December 2010 was US$105,832,000 (2009: US$97,922,000) (note 12).

· Deferred tax assets: the group recognises deferred tax assets on all applicable temporary differences where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the amount of deferred tax that can be recognised based on the magnitude and likelihood of future taxable profits. The carrying amount of deferred tax assets at 31 December 2010 was US$26,301,000 (2009: US$49,726,000).

· Income tax: the Company and its subsidiaries are subject to routine tax audits and also a process whereby tax computations are discussed and agreed with the appropriate authorities. Whilst the ultimate outcome of such tax audits and discussions cannot be determined with certainty, management estimates the level of provisions required for both current and deferred tax on the basis of professional advice and the nature of current discussions with the tax authority concerned.

· Recoverable value of intangible oil & gas and other intangible assets: the group determines at each statement of financial position date whether there is any evidence of indicators of impairment in the carrying value of its intangible oil & gas and other intangible assets. Where indicators exist, an impairment test is undertaken which requires management to estimate the recoverable value of its intangible assets for example by reference to quoted market values, similar arm's length transactions involving these assets or value in use calculations.

· Units of production depreciation: estimated proven plus probable reserves are used in determining the depreciation of oil & gas assets such that the depreciation charge is proportional to the depletion of the remaining reserves over their life of production. These calculations require the use of estimates including the amount of economically recoverable reserves and future oil & gas capital expenditure.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Interests in joint ventures

The group has a number of contractual arrangements with other parties which represent joint ventures. These take the form of agreements to share control over other entities ('jointly controlled entities') and commercial collaborations ('jointly controlled operations'). The group's interests in jointly controlled entities are accounted for by proportionate consolidation, which involves recognising the group's proportionate share of the joint venture's assets, liabilities, income and expenses with similar items in the consolidated financial statements on a line-by-line basis. Where the group collaborates with other entities in jointly controlled operations, the expenses the group incurs and its share of the revenue earned is recognised in the consolidated income statement. Assets controlled by the group and liabilities incurred by it are recognised in the statement of financial position. Where necessary, adjustments are made to the financial statements of the group's jointly controlled entities and operations to bring their accounting policies into line with those of the group.

Investment in associates

The group's investment in associates is accounted for using the equity method where the investment is initially carried at cost and adjusted for post acquisition changes in the group's share of net assets of the associate. Goodwill on the initial investment forms a part of the carrying amount of the investment and is not individually tested for impairment.

The group recognises its share of the net profits after tax and non-controlling interest of the associates in its consolidated income statement. Share of associate's changes in equity is also recognised in the group's consolidated statement of changes in equity. Any unrealised gains and losses resulting from transactions between the group and the associate are eliminated to the extent of the interest in associates.

The financial statements of the associate are prepared using same accounting policies and reporting periods as that of the group.

The carried value of investment is tested for impairment at each reporting date. Impairment, if any, is determined by the difference between the recoverable amount of the associate and its carried value and is reported within the share of income of an associate in the group's consolidated income statement.

Foreign currency translation

The Company's functional and presentational currency is United States Dollars. In the financial statements of individual subsidiaries, joint ventures and associates, transactions in currencies other than a company's functional currency are recorded at the prevailing rate of exchange at the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the statement of financial position date. Non-monetary assets and liabilities that are measured at historical cost in a foreign currency are translated using the rate of exchange as at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to the consolidated income statement with the exception of exchange differences arising on monetary assets and liabilities that form part of the group's net investment in subsidiaries. These are taken directly to statement of changes in equity until the disposal of the net investment at which time they are recognised in the consolidated income statement.

The statement of financial positions of overseas subsidiaries, joint ventures and associates are translated into US dollars using the closing rate method, whereby assets and liabilities are translated at the rates of exchange prevailing at the statement of financial position date. The income statements of overseas subsidiaries and joint ventures are translated at average exchange rates for the year. Exchange differences arising on the retranslation of net assets are taken directly to other reserves within statement of changes in equity.

On the disposal of a foreign entity, accumulated exchange differences are recognised in the consolidated income statement as a component of the gain or loss on disposal.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Property, plant and equipment

Property, plant and equipment is stated at cost less accumulated depreciation and any impairment in value. Cost comprises the purchase price or construction cost and any costs directly attributable to making that asset capable of operating as intended. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Depreciation is provided on a straight-line basis other than on oil & gas assets at the following rates:

Oil & gas facilities 10% - 12.5%

Plant and equipment 4% - 33%

Buildings and leasehold improvements 5% - 33% (or lease term if shorter)

Office furniture and equipment 25% - 100%

Vehicles 20% - 33%

Tangible oil & gas assets are depreciated, on a field-by-field basis, using the unit-of-production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves.

Each asset's estimated useful life, residual value and method of depreciation are reviewed and adjusted if appropriate at each financial year end.

No depreciation is charged on land or assets under construction.

The carrying amount of an item of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal. The gain or loss arising from the derecognition of an item of property, plant and equipment is included in profit or loss when the item is derecognised. Gains are not classified as revenue.

Non-current assets held for sale

Non-current assets or disposal groups are classified as held for sale when it is expected that the carrying amount of an asset will be recovered principally through sale rather than continuing use. Assets are not depreciated when classified as held for sale.

Borrowing costs

Borrowing costs directly attributable to the construction of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. All other borrowing costs are recognised as interest payable in the consolidated income statement in the period in which they are incurred.

Goodwill

Goodwill acquired in a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually, or more frequently if events or changes in circumstances indicate that such carrying value may be impaired. All transaction costs associated with business combinations post 1 January 2010 are charged to the consolidated income statement in the year of such combination.

For the purpose of impairment testing, goodwill acquired is allocated to the cash-generating units that are expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the group at which the goodwill is monitored for internal management purposes and is not larger than an operating segment determined in accordance with IFRS8 'Operating Segments'.

Impairment is determined by assessing the recoverable amount of the cash-generating units to which the goodwill relates. Where the recoverable amount of the cash-generating units is less than the carrying amount of the cash-generating units and related goodwill, an impairment loss is recognised.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Where goodwill has been allocated to cash-generating units and part of the operation within those units is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash-generating units retained.

Deferred consideration payable on acquisition

When, as part of a business combination, the group defers a proportion of the total purchase consideration payable for an acquisition, the amount provided for is the acquisition date fair value of the consideration. The unwinding of the discount element is recognised as a finance cost in the income statement. For business combinations prior to 1 January 2010, all changes in estimated deferred consideration payable on acquisition is adjusted against the carried goodwill. For business combinations after 1 January 2010, changes in estimated deferred consideration payable on acquisition are recognised in the consolidated income statement unless they are measurement period adjustment which are as a result of additional information obtained after the acquisition date about the facts and circumstances existing at the acquisition date, which are adjusted against carried goodwill.

Intangible assets - non oil & gas assets

Intangible assets acquired in a business combination are initially measured at cost being their fair values at the date of acquisition and are recognised separately from goodwill where the asset is separable or arises from a contractual or other legal right and its fair value can be measured reliably. After initial recognition, intangible assets are carried at cost less accumulated amortisation and any accumulated impairment losses. Intangible assets with a finite life are amortised over their useful economic life using a straight line method unless a better method reflecting the pattern in which the asset's future economic benefits are expected to be consumed can be determined. The amortisation charge in respect of intangible assets is included in the selling, general and administration expenses line of the consolidated income statement. The expected useful lives of assets are reviewed on an annual basis. Any change in the useful life or pattern of consumption of the intangible asset is treated as a change in accounting estimate and is accounted for prospectively by changing the amortisation period or method. Intangible assets are tested for impairment whenever there is an indication that the asset may be impaired.

Oil & gas assets

Capitalised costs

The group's activities in relation to oil & gas assets are limited to assets in the evaluation, development and production phases.

Oil & gas evaluation and development expenditure is accounted for using the successful efforts method of accounting.

Evaluation expenditures

Expenditure directly associated with evaluation (or appraisal) activities is capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written-off in the income statement. When such assets are declared part of a commercial development, related costs are transferred to tangible oil & gas assets. All intangible oil & gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the consolidated income statement.

Development expenditures

Expenditure relating to development of assets which include the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells, is capitalised within property, plant and equipment.

Changes in unit-of-production factors

Changes in factors which affect unit-of-production calculations are dealt with prospectively, not by immediate adjustment of prior years' amounts.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Decommissioning

Provision for future decommissioning costs is made in full when the group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditure. An amount equivalent to the discounted initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset on a unit-of-production basis over proven and probable reserves. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the oil & gas asset.

The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the income statement.

Available-for-sale financial assets

Investments classified as available-for-sale are initially stated at fair value, including acquisition charges associated with the investment.

After initial recognition, available-for-sale financial assets are measured at their fair value using quoted market rates or in the absence of market data other fair value calculation methodologies. Gains and losses are recognised as a separate component of equity until the investment is sold or impaired, at which time the cumulative gain or loss previously reported in equity is included in the consolidated income statement.

Impairment of assets (excluding goodwill)

At each statement of financial position date, the group reviews the carrying amounts of its tangible and intangible assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, the group makes an estimate of the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. An impairment loss is recognised immediately in the consolidated income statement, unless the relevant asset is carried at a revalued amount, in which case the impairment loss is treated as a revaluation decrease.

Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years. A reversal of an impairment loss is recognised immediately in the consolidated income statement, unless the relevant asset is carried at a revalued amount, in which case the reversal of the impairment is treated as a revaluation increase.

Inventories

Inventories are valued at the lower of cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business, less estimated costs of completion and the estimated costs necessary to make the sale. Cost comprises purchase price, cost of production, transportation and other directly allocable expenses. Costs of inventories, other than raw materials, are determined using the first-in-first-out method. Costs of raw materials are determined using the weighted average method.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Work in progress and billings in excess of cost and estimated earnings

Fixed price lump sum engineering, procurement and construction contracts are presented in the statement of financial position as follows:

· for each contract, the accumulated cost incurred, as well as the estimated earnings recognised at the contract's percentage of completion less provision for any anticipated losses, after deducting the progress payments received or receivable from the customers, are shown in current assets in the statement of financial position under "Work in progress".

· where the payments received or receivable for any contract exceed the cost and estimated earnings less provision for any anticipated losses, the excess is shown as "Billings in excess of cost and estimated earnings" within current liabilities.

Trade and other receivables

Trade receivables are recognised and carried at original invoice amount less an allowance for any amounts estimated to be uncollectable. An estimate for doubtful debts is made when there is objective evidence that the collection of the full amount is no longer probable under the terms of the original invoice. Impaired debts are derecognised when they are assessed as uncollectable.

Cash and cash equivalents

Cash and cash equivalents consist of cash at bank and in hand and short-term deposits with an original maturity of three months or less. For the purpose of the cash flow statement, cash and cash equivalents consists of cash and cash equivalents as defined above, net of outstanding bank overdrafts.

Interest-bearing loans and borrowings

All interest-bearing loans and borrowings are initially recognised at the fair value of the consideration received net of issue costs directly attributable to the borrowing.

Interest-bearing loans and borrowings

After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the effective interest rate method. Amortised cost is calculated by taking into account any issue costs, and any discount or premium on settlement.

Provisions

Provisions are recognised when the group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised in the consolidated income statement as a finance cost.

Derecognition of financial assets and liabilities

Financial assets

A financial asset (or, where applicable a part of a financial asset) is derecognised where:

· the rights to receive cash flows from the asset have expired;

· the group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third party under a 'pass-through' arrangement; or

· the group has transferred its rights to receive cash flows from the asset and either a) has transferred substantially all the risks and rewards of the asset, or b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Derecognition of financial assets and liabilities

Financial liabilities

A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expires.

If an existing financial liability is replaced by another from the same lender, on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability such that the difference in the respective carrying amounts together with any costs or fees incurred are recognised in the consolidated income statement.

Pensions and other long-term employment benefits

The group has various defined contribution pension schemes in accordance with the local conditions and practices in the countries in which it operates. The amount charged to the consolidated income statement in respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the statement of financial position.

The group's other long-term employment benefits are provided in accordance with the labour laws of the countries in which the group operates, further details of which are given in note 27.

Share-based payment transactions

Employees (including directors) of the group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares ('equity-settled transactions').

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. In valuing equity-settled transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of Petrofac Limited ('market conditions'), if applicable.

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the 'vesting period'). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the group's best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not recognised for the award at that date is recognised in the income statement.

Petrofac Employee Benefit Trust

The Petrofac Employee Benefit Trust was established on 7 March 2007 to warehouse ordinary shares purchased to satisfy various new share scheme awards made to the employees of the Company, which will be transferred to the members of the scheme on their respective vesting dates subject to satisfying the performance conditions of each scheme. The trust has been presented as part of both the Company and group financial statements in accordance with SIC 12 'Special Purpose Entities'. The cost of shares temporarily held by Petrofac Employee Benefit Trust is reflected as treasury shares and deducted from equity.

Leases

The determination of whether an arrangement is, or contains a lease is based on the substance of the arrangement at inception date of whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys the right to use the asset.

The group has entered into various operating leases the payments for which are recognised as an expense in the consolidated income statement on a straight-line basis over the lease terms.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Revenue recognition

Revenue is recognised to the extent that it is probable economic benefits will flow to the group and the revenue can be reliably measured. The following specific recognition criteria also apply:

Engineering, procurement and construction services (Engineering & Construction)

Revenues from fixed-price lump-sum contracts are recognised on the percentage-of-completion method, based on surveys of work performed once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenues are recognised only to the extent of costs incurred that are expected to be recoverable.

Revenues from cost-plus-fee contracts are recognised on the basis of costs incurred during the year plus the fee earned measured by the cost-to-cost method.

Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

Provision is made for all losses expected to arise on completion of contracts entered into at the statement of financial position date, whether or not work has commenced on these contracts.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Claims and variation orders are only included in revenue when negotiations have reached an advanced stage such that it is probable the claim / variation orders will be accepted and can be measured reliably.

Facilities management, engineering and training services (Offshore Engineering & Operations, Engineering, Training Services and Production Solutions)

Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

Revenues from fixed-price contracts are recognised on the percentage-of-completion method, measured by milestones completed or earned value once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenues are recognised only to the extent of costs incurred that are expected to be recoverable.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified

performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Claims are only included in revenue when negotiations have reached an advanced stage such that it is probable the claim will be accepted and can be measured reliably.

Oil & gas activities (Energy Developments)

Oil & gas revenues comprise the group's share of sales from the processing or sale of hydrocarbons on an entitlement basis, when the significant risks and rewards of ownership have been passed to the buyer.

Pre-contract/bid costs

Pre-contract/bid costs incurred are recognised as an expense until there is a high probability that the contract will be awarded, after which all further costs are recognised as assets and expensed out over the life of the contract.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Income taxes

Income tax expense represents the sum of current income tax and deferred tax.

Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to the taxation authorities. Taxable profit differs from profit as reported in the consolidated income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the statement of financial position date.

Deferred income tax is recognised on all temporary differences at the statement of financial position date between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, with the following exceptions:

· where the temporary difference arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss;

· in respect of taxable temporary differences associated with investments in subsidiaries, associates and joint ventures, where the timing of reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future; and

· deferred income tax assets are recognised only to the extent that it is probable that a taxable profit will be available against which the deductible temporary differences, carried forward tax credits or tax losses can be utilised.

The carrying amount of deferred income tax assets is reviewed at each statement of financial position date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax assets to be utilised. Unrecognised deferred income tax assets are reassessed at each statement of financial position date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.

Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when the asset is realised or the liability is settled, based on tax rates and tax laws enacted or substantively enacted at the statement of financial position date.

Current and deferred income tax is charged or credited directly to other comprehensive income or equity if it relates to items that are credited or charged to respectively, other comprehensive income or equity. Otherwise, income tax is recognised in the consolidated income statement.

Derivative financial instruments and hedging

The group uses derivative financial instruments such as forward currency contracts, interest rate collars and swaps and oil price collars and forward contracts to hedge its risks associated with foreign currency, interest rate and oil price fluctuations. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.

Any gains or losses arising from changes in the fair value of derivatives that do not qualify for hedge accounting are taken to the consolidated income statement.

The fair value of forward currency contracts is calculated by reference to current forward exchange rates for contracts with similar maturity profiles. The fair value of interest rate cap, swap and oil price collar contracts is determined by reference to market values for similar instruments.

For the purposes of hedge accounting, hedges are classified as:

· fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability; or

· cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability or a highly probable forecast transaction.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Derivative financial instruments and hedging (continued)

The group formally designates and documents the relationship between the hedging instrument and the hedged item at the inception of the transaction, as well as its risk management objectives and strategy for undertaking various hedge transactions. The documentation also includes identification of the hedging instrument, the hedged item or transaction, the nature of risk being hedged and how the group will assess the hedging instrument's effectiveness in offsetting the exposure to changes in the hedged item's fair value or cash flows attributable to the hedged risk. The group also documents its assessment, both at hedge inception and on an ongoing basis, of whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values or cash flows of the hedged items.

The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging relationship, as follows:

Cash flow hedges

For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognised directly in statement of changes in equity, while the ineffective portion is recognised in the income statement. Amounts taken to equity are transferred to the income statement when the hedged transaction affects the consolidated income statement.

If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as

a hedge is revoked, any cumulative gain or loss existing in equity at that time remains in equity and is recognised when the forecast transaction is ultimately recognised in the consolidated income statement. When a forecast transaction is no longer expected to occur, the cumulative gain or loss that was reported in statement of changes in equity is immediately transferred to the consolidated income statement.

Embedded derivatives

Contracts are assessed for the existence of embedded derivatives at the date that the group first becomes party to the contract, with reassessment only if there is a change to the contract that significantly modifies the cash flows. Embedded derivatives which are not clearly and closely related to the underlying asset, liability or transaction are separated and accounted for as standalone derivatives.

3 SEGMENT INFORMATION

For management purposes Petrofac is organised into seven main types of business unit activities which have been split into four reportable segments below. Whilst Engineering, Training Services and Production Solutions are three fairly diverse businesses none have ever met the quantitative thresholds set by IFRS 8 'Operating Segments' for determining reportable segments.

The four reportable segments shown below consist of:

· Engineering and Construction which provides engineering, procurement and construction project execution services to the onshore oil & gas industry.

· Offshore Engineering Operations which provides operations management services to the offshore oil & gas industry.

· Energy Developments which co invests with partners in oil & gas production, processing and transportation assets.

· Engineering, Training Services and Production Solutions activities consist of the provision of early stage engineering services such as conceptual FEED studies, oil & gas related technical competency training and consultancy services and production improvement services under value aligned commercial structures.

Management separately monitors the trading results of its seven business units for the purpose of making an assessment of their performance and making decisions about how resources are allocated to them. Each business unit/segment performance is measured based on its profitability which is reflected in a manner consistent with the results shown below. However, certain shareholder services related overheads, group financing and consolidation adjustments are managed at a corporate level and are not allocated to operating segments.

The following tables represent revenue and profit information relating to the group's reporting segments for the year ended 31 December 2010.

Year ended 31 December 2010

			Engineering,
	Engineering	Offshore	Training Services &			Consolidation
	&	Engineering &	Production	Energy	Corporate	adjustments &
	Construction	Operations	Solutions	Developments	& others	eliminations	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

Revenue
External sales	3,232,174	710,080	223,748	188,215	-	-	4,354,217
Inter-segment sales	21,732	11,821	131,538	-	-	(165,091)	-

Total revenue	3,253,906	721,901	355,286	188,215	-	(165,091)	4,354,217

Segment results	438,867	24,506	26,590	66,290	(900)	(3,362)	551,991
Gain on EnQuest demerger	-	-	-	124,864	-	-	124,864
Unallocated corporate costs	-	-	-	-	(13,405)	-	(13,405)

Profit / (loss) before tax and
finance income / (costs)	438,867	24,506	26,590	191,154	(14,305)	(3,362)	663,450

Share of loss of associate	-	-	-	(131)	-	-	(131)
Finance costs	-	(968)	(696)	(3,121)	(3,659)	3,313	(5,131)
Finance income	9,741	209	525	348	2,699	(3,313)	10,209

Profit / (loss) before
income tax	448,608	23,747	26,419	188,250	(15,265)	(3,362)	668,397

Income tax (expense) / income	(75,550)	(6,519)	1,144	(31,895)	2,275	-	(110,545)

Non-controlling interests	(35)	-	-	-	-	-	(35)

Profit / (loss) for the year attributable to Petrofac Limited shareholders	373,023	17,228	27,563	156,355	(12,990)	(3,362)	557,817

3 SEGMENT INFORMATION (continued)

Year ended 31 December 2010

			Engineering,
	Engineering	Offshore	Training Services &			Consolidation
	&	Engineering &	Production	Energy	Corporate	adjustments &
	Construction	Operations	Solutions	Developments	& others	eliminations	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Other segment information
Capital expenditures:
Property, plant and equipment	62,088	2,785	6,857	41,112	4,575	(1,178)	116,239
Intangible oil & gas assets	-	-	-	15,644	-	-	15,644

Charges:
Depreciation	34,340	2,238	7,206	49,816	367	(575)	93,392
Amortisation	1,044	597	870	-	-	-	2,511
Other long-term employment benefits	10,435	613	1,581	54	87	-	12,770
Share-based payments	7,693	1,167	1,896	1,121	2,907	-	14,784

Year ended 31 December 2009 (restated)

			Engineering,
	Engineering	Offshore	Training Services &			Consolidation
	&	Engineering &	Production	Energy	Corporate	adjustments &
	Construction	Operations	Solutions	Developments	& others	eliminations	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
	Restated						Restated
Revenue
External sales	2,508,951	616,542	281,225	248,708	-	-	3,655,426
Inter-segment sales	-	10,178	68,431	-	-	(78,609)	-

Total revenue	2,508,951	626,720	349,656	248,708	-	(78,609)	3,655,426

Segment results	312,374	17,830	34,483	77,395	(1,615)	(326)	440,141

Unallocated corporate costs	-	-	-	-	(8,181)	-	(8,181)

Profit / (loss) before tax and
finance income / (costs)	312,374	17,830	34,483	77,395	(9,796)	(326)	431,960

Finance costs	-	(258)	(1,582)	(10,702)	(5,705)	12,665	(5,582)
Finance income	14,087	94	313	64	10,049	(12,665)	11,942

Profit / (loss) before
income tax	326,461	17,666	33,214	66,757	(5,452)	(326)	438,320

Income tax (expense) / income	(61,328)	(4,853)	(672)	(20,566)	3,095	(191)	(84,515)

Minority interests	(14)	-	(188)	-	-	-	(202)

Profit / (loss) for the year attributable to Petrofac Limited shareholders	265,119	12,813	32,354	46,191	(2,357)	(517)	353,603

Other segment information
Capital expenditures:
Property, plant and equipment	51,821	3,400	6,682	309,824	4,686	(1,014)	375,399
Intangible oil & gas assets	-	-	-	29,230	-	-	29,230

Charges:
Depreciation	24,525	1,887	7,482	78,677	251	(918)	111,904
Amortisation	415	-	668	-	-	-	1,083
Impairment	-	-	-	4,793	-	-	4,793
Other long-term employment benefits	7,779	833	1,736	52	38	-	10,438
Share-based payments	6,213	1,263	2,258	1,337	2,192	-	13,263

3 SEGMENT INFORMATION (continued)

Geographical segments

The following tables present revenue from external customers based on their location and non-current assets by geographical segments for the years ended 31 December 2010 and 2009.

Year ended 31 December 2010

		United Arab	United				Saudi	Other
	Algeria	Emirates	Kingdom	Kuwait	Oman	Syria	Arabia	countries	Consolidated
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

Revenues from external customers	1,037,966	798,328	753,842	360,624	350,313	277,196	235,936	540,012	4,354,217

United

United Arab

Other

Kingdom

Emirates

Tunisia

Algeria

Malaysia

Indonesia

countries

Consolidated

US$'000

Non-current assets:

Property, plant and equipment

54,326

94,292

52,031

30,737

14,836

1,555

39,381

287,158

Intangible oil & gas assets

69,532

Other intangible assets

9,365

6,940

16,305

Goodwill

90,093

15,240

499

105,832

Year ended 31 December 2009

	United	United Arab						Other
	Kingdom	Emirates	Oman	Tunisia	Algeria	Syria	Kazakhstan	countries	Consolidated
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

Revenues from external customers	705,281	695,118	530,269	492,378	380,601	203,577	184,305	463,897	3,655,426

United

United Arab

Other

Kingdom

Tunisia

Emirates

Algeria

Malaysia

countries

Consolidated

US$'000

Non-current assets:

Property, plant and equipment

447,591

57,078

74,093

55,229

25,279

18,726

677,996

Intangible oil & gas assets

53,888

Other intangible assets

11,654

7,565

19,219

Goodwill

85,155

12,099

668

97,922

Revenues disclosed in the above tables are based on where the project is located. Revenue from two customers amounted to US$1,422,410,000 (2009: US$801,723,000) in the Engineering & Construction segment.

4 REVENUES AND EXPENSES

a. Revenue

	2010	2009
	US$'000	US$'000

Rendering of services	4,202,371	3,446,037
Sale of crude oil & gas	146,075	202,770
Sale of processed hydrocarbons	5,771	6,619
	4,354,217	3,655,426

Included in revenues from rendering of services are Offshore Engineering & Operations, Engineering, Training Services and Production Solutions revenues of a 'pass-through' nature with zero or low margins amounting to US$227,974,000 (2009: US$230,262,000).

4 REVENUES AND EXPENSES (continued)

b. Cost of sales

Included in cost of sales for the year ended 31 December 2010 is US$154,000 (2009: US$908,000 gain) gain on disposal of property, plant and equipment used to undertake various engineering and construction contracts. In addition depreciation charged on property, plant and equipment of US$85,186,000 during 2010 (2009: US$104,997,000) is included in cost of sales (note 9).

Also included in cost of sales are forward points and ineffective portions on derivatives designated as cash flow hedges and loss on maturity of undesignated derivatives of US$3,409,000 (2009: US$19,508,000 gain). These amounts are an economic hedge but do not meet the criteria within IAS39 and are most appropriately recorded in cost of sales.

c. Selling, general and administration expenses

	2010	2009
	US$'000	US$'000

Staff costs	126,475	94,583
Depreciation	8,206	6,907
Amortisation (note 13)	2,511	1,083
Impairment	-	4,793
Other operating expenses	84,257	78,927
	221,449	186,293

Other operating expenses consist mainly of office, travel, legal and professional and contracting staff costs.

d. Staff costs

	2010	2009
	US$'000	US$'000

Total staff costs:
Wages and salaries	828,439	708,684
Social security costs	31,809	27,877
Defined contribution pension costs	12,621	11,155
Other long-term employee benefit costs (note 27)	12,770	10,438
Expense of share-based payments (note 24)	14,784	13,263
	900,423	771,417

Of the US$900,423,000 (2009: 771,417,000) of staff costs shown above, US$773,948,000 (2009: US$676,834,000) are included in cost of sales, with the remainder in selling, general and administration expenses.

The average number of persons employed by the group during the year was 12,807 (2009: 11,628).

e. Auditors' remuneration

The group paid the following amounts to its auditors in respect of the audit of the financial statements and for other services provided to the group:

	2010	2009
	US$'000	US$'000

Audit of the group financial statements	1,209	1,369
Other fees to auditors:
Local statutory audits of subsidiaries	812	546
Tax services	520	178
All other services	93	15
	2,634	2,108

4 REVENUES AND EXPENSES (continued)

f. Other income

	2010	2009
	US$'000	US$'000

Foreign exchange gains	720	2,342
Gain on sale of property, plant and equipment	8	-
Gain on sale of intangible assets	2,338	-
Other income	1,947	1,733
	5,013	4,075

g. Other expenses

	2010	2009
	US$'000	US$'000

Foreign exchange losses	3,452	2,675
Loss on sale of property, plant and equipment	477	124
Other expenses	124	199
	4,053	2,998

5 FINANCE (COSTS) / INCOME

	2010	2009
	US$'000	US$'000

Interest payable:
Long-term borrowings	(2,908)	(3,171)
Other interest, including short-term loans and overdrafts	(581)	(310)
Unwinding of discount on deferred consideration and decommissioning provisions	(1,642)	(2,101)
Total finance cost	(5,131)	(5,582)

Interest receivable:
Bank interest receivable	9,945	11,487
Other interest receivable	264	455
Total finance income	10,209	11,942

6 INCOME TAX

a. Tax on ordinary activities

The major components of income tax expense are as follows:

	2010	2009
	US$'000	US$'000

Current income tax
Current income tax charge	115,199	100,985
Adjustments in respect of current income tax of previous years	(2,843)	(31,448)

Deferred income tax
Relating to origination and reversal of temporary differences	907	5,570
Adjustments in respect of deferred income tax of previous years	(2,718)	9,408
Income tax expense reported in the income statement	110,545	84,515

6 INCOME TAX (continued)

b. Reconciliation of total tax charge

A reconciliation between the income tax expense and the product of accounting profit multiplied by the Company's domestic tax rate is as follows:

	2010	2009
	US$'000	US$'000

Accounting profit before tax (including gain on EnQuest demerger)	668,397	438,320

At Jersey's domestic income tax rate of 0% (2009: 0%)	-	-
Expected tax charge in higher rate jurisdictions	116,199	107,320
Expenditure not allowable for income tax purposes	1,073	14,706
Income not taxable	-	(396)
Adjustments in respect of previous years	(5,561)	(22,040)
Tax effect of utilisation of tax losses not previously recognised	(568)	(252)
Unrecognised tax losses	1,634	618
Other permanent differences	(2,157)	(15,441)
Effect of change in tax rates	(75)	-
At the effective income tax rate of 16.5% (2009: 19.3%)	110,545	84,515

The group's effective tax rate for the year ended 31 December 2010, including the US$124,864,000 gain on the demerger of Energy Development's UKCS business is 16.5% and excluding this gain, the effective tax rate is 20.3% (2009: 19.3%).

On 5 April 2010, the group completed the demerger of its UKCS business to EnQuest Plc, an independent company which is listed on the London and Stockholm stock exchanges. No chargeable gain arose on the transaction for UK corporate tax purposes. This decreased the group's effective tax rate for the period.

Excluding the gain from the demerger, there has been a small increase in the group's effective tax rate. Factors contributing to this increase compared to 2009 include ring fence expenditure supplement no longer being available for claim following the demerger of Petrofac Energy Development Limited, no additional adjustments being made in respect of the applicability of the lower tax rate to the group's Project in Oman, material changes in jurisdictions in which profits are expected to be earned by the Engineering & Construction reporting segment and due to recent acquisitions. There has also been an increase in reportable profit within taxable jurisdictions. In June 2010, the UK government announced its intention to propose to the Parliament to reduce the UK corporation tax rate from 28% to 24% over the course of 4 years. From 1 April 2011 the UK corporate rate is 27% and will impact the reversal of the temporary difference from this date onwards, reducing the UK tax assets and liabilities. This UK tax rate change has been substantively enacted at the statement of financial position date.

6 INCOME TAX (continued)

c. Deferred income tax

Deferred income tax relates to the following:

	Consolidated Statement of Financial Position		Consolidated Income Statement
	Consolidated Statement of Financial Position		Consolidated Income Statement
	2010	2009	2010	2009
	US$'000	US$'000	US$'000	US$'000

Deferred income tax liabilities
Fair value adjustment on acquisitions	1,412	2,599	(597)	(139)
Accelerated depreciation	36,580	27,515	14,630	15,472
Other temporary differences	10,094	12,078	(4,336)	(1,441)
Gross deferred income tax liabilities	48,086	42,192

Deferred income tax assets
Losses available for offset	2,259	18,413	(14,135)	(11,130)
Decelerated depreciation for tax purposes	2,404	7,596	327	9,409
Share scheme	15,721	18,636	(230)	(1,142)
Other temporary differences	5,917	5,081	2,530	3,949
Gross deferred income tax assets	26,301	49,726

Deferred income tax (credit)/charge			(1,811)	14,978

d. Unrecognised tax losses and tax credits

Deferred income tax assets are recognised for tax loss carry-forwards and tax credits to the extent that the realisation of the related tax benefit through future taxable profits is probable. The group did not recognise deferred income tax assets of US$18,366,000 (2009: US$15,452,000).

	2010	2009
	US$'000	US$'000

Expiration dates for tax losses
No earlier than 2022	9,466	11,451
No expiration date	6,384	3,360
	15,850	14,811
Tax credits (no expiration date)	2,516	641
	18,366	15,452

7 EARNINGS PER SHARE

Basic earnings per share amounts are calculated by dividing the net profit for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.

Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary shareholders, after adjusting for any dilutive effect, by the weighted average number of ordinary shares outstanding during the year, adjusted for the effects of ordinary shares granted under the employee share award schemes which are held in trust.

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

7 EARNINGS PER SHARE (continued)

	2010	2009
	US$'000	US$'000

Net profit attributable to ordinary shareholders for basic and diluted earnings per share excluding gain on EnQuest demerger	432,953	353,603

Net profit attributable to ordinary shareholders for basic and diluted earnings per share including gain on EnQuest demerger

557,817

353,603

	2010	2009
	Number	Number
	'000	'000

Weighted average number of ordinary shares for basic earnings per share	338,867	337,473
Effect of diluted potential ordinary shares granted under share-based payment schemes	4,493	5,187
Adjusted weighted average number of ordinary shares for diluted earnings per share	343,360	342,660

8 DIVIDENDS PAID AND PROPOSED

	2010	2009
	US$'000	US$'000
Declared and paid during the year
Equity dividends on ordinary shares:
Final dividend for 2008: 17.90 cents per share	-	60,332
Interim dividend 2009: 10.70 cents per share	-	36,197
Final dividend for 2009: 25.10 cents per share	85,291	-
Interim dividend 2010: 13.80 cents per share	46,757	-
	132,048	96,529

	2010	2009
	US$'000	US$'000
Proposed for approval at AGM
(not recognised as a liability as at 31 December)
Equity dividends on ordinary shares
Final dividend for 2010: 30.00 cents per share (2009: 25.10 cents per share)	103,715	86,729

9 PROPERTY, PLANT AND EQUIPMENT

			Land,
			buildings			Office
			and			furniture	Assets
	Oil & gas	Oil & gas	leasehold	Plant and		and	under
	assets	facilities	improvements	equipment	Vehicles	equipment	construction	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

Cost
At 1 January 2009	279,103	125,371	83,088	22,235	6,574	69,047	-	585,418
Additions	276,798	32,612	32,632	4,273	4,907	17,663	6,514	375,399
Disposals	-	-	(1,474)	(4,631)	(789)	(3,366)	-	(10,260)
Exchange difference	-	-	1,296	1,103	204	3,745	165	6,513

At 1 January 2010	555,901	157,983	115,542	22,980	10,896	87,089	6,679	957,070
Additions	32,252	7,602	44,114	1,445	4,755	19,238	6,833	116,239
Acquisition of subsidiaries	-	-	-	2,081	46	43	-	2,170
Disposals	(470,447)	-	(1,847)	(2,344)	(854)	(17,268)	-	(492,760)
Transfers	-	-	881	4	-	(885)	-	-
Exchange difference	-	-	(462)	(712)	(158)	(809)	(132)	(2,273)

At 31 December 2010	117,706	165,585	158,228	23,454	14,685	87,408	13,380	580,446

Depreciation
At 1 January 2009	(16,187)	(87,026)	(7,983)	(16,512)	(4,235)	(40,411)	-	(172,354)
Charge for the year	(60,984)	(15,254)	(14,998)	(3,571)	(2,254)	(14,843)	-	(111,904)
Disposals	-	-	1,330	4,516	740	3,150	-	9,736
Exchange difference	-	-	(379)	(1,051)	(37)	(3,085)	-	(4,552)

At 1 January 2010	(77,171)	(102,280)	(22,030)	(16,618)	(5,786)	(55,189)	-	(279,074)
Charge for the year	(32,204)	(15,993)	(23,981)	(2,734)	(3,462)	(15,018)	-	(93,392)
Disposals	59,592	-	1,400	538	769	16,072	-	78,371
Transfers	-	-	(83)	-	-	83	-	-
Exchange difference	-	-	71	327	28	381	-	807

At 31 December 2010	(49,783)	(118,273)	(44,623)	(18,487)	(8,451)	(53,671)	-	(293,288)

Net carrying amount:
At 31 December 2010	67,923	47,312	113,605	4,967	6,234	33,737	13,380	287,158

At 31 December 2009	478,730	55,703	93,512	6,362	5,110	31,900	6,679	677,996

No interest has been capitalised within oil & gas facilities during the year (2009: nil) and the accumulated capitalised interest, net of depreciation at 31 December 2010, was US$432,000 (2009: US$931,000).

Additions to oil & gas assets in 2009 mainly comprise development expenses capitalised on the group's interest in the Don area assets of US$274,114,000. During the year, the Don assets were demerged and as a result oil & gas assets with a net book value of US$410,855,000 were disposed of (note 11).

Included in oil & gas assets are US$2,196,000 (2009: US$50,726,000) of capitalised decommissioning costs net of depreciation provided on the PM304 asset in Malaysia and the Chergui asset in Tunisia. The decrease in the 31 December 2010 oil & gas asset's balance is due to the demerger of the Don area assets in the United Kingdom (note 11).

Of the total charge for depreciation in the income statement, US$85,186,000 (2009: US$104,997,000) is included in cost of sales and US$8,206,000 (2009: US$6,907,000) in selling, general and administration expenses.

Assets under construction comprises of expenditures incurred in relation to the group ERP project.

10 BUSINESS COMBINATIONS

Scotvalve Services Limited

On 14 January 2010, the group acquired a 100% interest in the share capital of Scotvalve Services Limited (Scotvalve), a United Kingdom based company, involved in the servicing and repair of oilfield pressure control equipment. The Scotvalve acquisiton will enhance the group's mechanical services offering and expand its geographical footprint. The consideration for the acquisition was Sterling 4,630,000 (equivalent US$7,512,000) comprising of Sterling 2,801,000 (equivalent US$4,545,000) as an initial cash payment, Sterling 150,000 (equivalent US$243,000) to be settled in cash during the year and the balance being the discounted value of deferred consideration amounting to Sterling 1,679,000 (equivalent US$2,724,000) payable based on the estimated future profitability of Scotvalve. The range of deferred consideration payable is from zero to a maximum of Sterling 2,000,000 (equivalent US$3,122,000) over a three year period.

The fair values of the identifiable assets and liabilities of Scotvalve on completion of the acquisition are analysed below:

	Recognised on	Carrying
	acquisition	value
	US$'000	US$'000

Property, plant and equipment	1,891	1,978
Investments in associates (note 14)	777	777
Intangible assets (note 13)	1,107	-
Trade and other receivables	2,606	2,606
Cash and short-term deposits	410	410
Total assets	6,791	5,771

Less:
Deferred tax liability	(325)	(16)
Income tax liability	(279)	(279)
Trade and other payables	(1,220)	(1,220)
Total liabilities	(1,824)	(1,515)

Fair value of net assets acquired	4,967	4,256
Goodwill arising on acquisition	2,545
Consideration at acquisition	7,512

			US$'000
Cash outflow on acquisition:
Cash acquired with subsidiary			410
Cash paid on acquisition			(4,545)
Net cash outflow on the acquisition of subsidiary			(4,135)

Intangible assets recognised on acquisition comprise equipment manufacturer warranty repair licenses which are being amortised over their remaining economic useful lives of five years on a straight-line basis.

The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the group.

From the date of acquisition, Scotvalve has contributed revenues of US$6,903,000 and net income of US$1,020,000 to the net profit of the group. If the above combination had taken place at the beginning of the year, net profit of Scotvalve would have been US$1,020,000 and revenue would have been US$6,903,000.

The transaction costs of Sterling 102,000 (equivalent US$154,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

The deferred consideration payable was re-assessed at year end in light of latest financial projections for the business and the current carried amount was reduced by Sterling 135,000 (equivalent US$208,000) with a corresponding increase in other income within the consolidated income statement.

10 BUSINESS COMBINATIONS (continued)

Stephen Gillespie Consultants Limited

On 1 April 2010, the group acquired a 100% interest in the share capital of Stephen Gillespie Consultants Limited (SGC), a United Kingdom based provider of software consultancy to flow metering control system manufacturers for a consideration of Sterling 4,523,000 (equivalent US$6,853,000) comprising of Sterling 3,178,000 (equivalent US$4,815,000) paid upfront in cash and the balance being the discounted value of deferred consideration amounting to Sterling 1,345,000 (equivalent US$2,038,000) payable based on the estimated future revenue of the company. This acquisition will enhance the group's existing metering service offering and also its ability to provide turnkey metering solutions to both brownfield and greenfield international oil & gas projects. The range of deferred consideration payable is from Sterling 600,000 (equivalent US$937,000) to a maximum of Sterling 1,200,000 (equivalent US$1,873,000) based on future revenue of SGC over a two year period.

The fair values of the identifiable assets and liabilities of SGC on completion of the acquisition are analysed below:

	Recognised on	Carrying
	acquisition	value
	US$'000	US$'000

Property, plant and equipment	61	61
Intangible assets (note 13)	2,065	-
Trade and other receivables	1,424	1,424
Cash and short-term deposits	1,920	1,920
Total assets	5,470	3,405

Less:
Deferred tax liability	(579)	-
Income tax liability	(383)	(383)
Trade and other payables	(1,126)	(1,254)
Total liabilities	(2,088)	(1,637)

Fair value of net assets acquired	3,382	1,768
Goodwill arising on acquisition	3,471
Consideration at acquisition	6,853

		US$'000

Cash outflow on acquisition:
Cash acquired with subsidiary		1,920
Cash paid on acquisition		(4,815)
Net cash outflow on the acquisition of subsidiary		(2,895)

Intangible assets recognised on acquisition comprise of software related to metering technology which is being amortised over its remaining economic useful lives of five years on a straight-line basis.

The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the group.

From the date of acquisition, SGC has contributed revenues of US$6,549,000 and net income of US$165,000 to the net profit of the group. If the above combination had taken place at the beginning of the year, net profit of SGC would have been US$205,000 and revenue would have been US$7,412,000.

The transaction costs of Sterling 65,000 (equivalent US$99,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

The deferred consideration payable was re-assessed at year end in light of latest financial projections for the business and the current carried amount was reduced by Sterling 188,000 (equivalent US$293,000) with a corresponding increase in other income within the consolidated income statement.

10 BUSINESS COMBINATIONS (continued)

CO2DeepStore Limited

On 27 April 2010, the group acquired a 100% interest in the share capital of CO2DeepStore Limited (CO2Deepstore), a United Kingdom based company focused on the CO2 geological storage sector of the carbon capture and storage market for a cash consideration of Sterling 220,000 (equivalent US$340,000). This acquisition represents the group's first step into the strategically important emerging low carbon energy sector.

The fair values of the identifiable assets and liabilities of CO2Deepstore on completion of the acquisition are analysed below:

	Recognised on	Carrying
	acquisition	value
	US$'000	US$'000

Property, plant and equipment	3	3
Trade and other receivables	134	134
Cash and short-term deposits	263	263
Total assets	400	400

Less:
Income tax liability	(31)	(31)
Trade and other payables	(29)	(29)
Total liabilities	(60)	(60)

Fair value of net assets acquired	340	340
Goodwill arising on acquisition	-
Consideration at acquisition	340


		US$'000

Cash outflow on acquisition:
Cash acquired with subsidiary		263
Cash paid on acquisition		(340)
Net cash outflow on the acquisition of subsidiary		(77)

From the date of acquisition, CO2Deepstore has contributed revenues of US$88,000 and a net loss of US$823,000 to the net profit of the group. If the above combination had taken place at the beginning of the year, net profit of CO2Deepstore would have been US$573,000 and revenue would have been US$905,000.

The transaction costs of Sterling 17,000 (equivalent US$26,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

Under the terms of the acquisition agreement, costs of up to Sterling 200,000 (equivalent US$312,000) will be payable to the former owners of CO2Deepstore 3 three years from the date of completion based on the estimated future profitability of the company and will be recognised as an expense in the income statement over this period. The charge for the current year is Sterling 44,000 (equivalent US$68,000).

10 BUSINESS COMBINATIONS (continued)

TNEI Services Limited

On 14 June 2010, the group acquired a 100% interest in the share capital of TNEI Services Limited (TNEI) through the acquisition of its holding company New Energy Industries Limited for a cash consideration of Sterling 6,123,000 (equivalent US$ 8,913,000). TNEI provides services in the areas of power transmission and distribution, planning and environmental consent and energy management. The acquisition of TNEI further broadens the group's technical consulting services offering in the rapidly developing power and renewable energy markets.

The fair values of the identifiable assets and liabilities of TNEI on completion of the acquisition are analysed below:

	Recognised on	Carrying
	acquisition	value
	US$'000	US$'000

Property, plant and equipment	215	215
Acquired goodwill	881	881
Trade and other receivables	1,779	1,779
Cash and short-term deposits	910	910
Total assets	3,785	3,785

Less:
Trade and other payables	(1,198)	(1,198)
Total liabilities	(1,198)	(1,198)

Fair value of net assets acquired	2,587	2,587
Goodwill arising on acquisition	6,326
Consideration at acquisition	8,913


		US$'000

Cash outflow on acquisition:
Cash acquired with subsidiary		910
Cash paid on acquisition		(8,913)
Net cash outflow on the acquisition of subsidiary		(8,003)

The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the group.

From the date of acquisition, TNEI has contributed revenue of US$3,898,000 and a net loss of US$5,000 to the group. If the above combination had taken place at the beginning of the year, net profit of TNEI would have been US$301,000 and revenue would have been US$6,296,000.

The transaction costs of Sterling 38,000 (equivalent US$58,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

Under the terms of the acquisition agreement, Sterling 1,538,000 (equivalent US$2,370,000) will be payable 50% in Petrofac shares and 50% in cash to the former owners of TNEI who remain as employees of the Petrofac group in three equal tranches over 3 years from the date of completion which will be recognised as an expense in the income on a straight line basis over the 3 years. The charge for the current year is Sterling 278,000 (equivalent US$428,000).

11 GAIN ON ENQUEST DEMERGER

On 5 April 2010, the group's interests in the Don area oil assets were demerged via a transfer of three of its subsidiaries, Petrofac Energy Developments Limited (PEDL), Petrofac Energy Developments Oceania Limited (PEDOL) and PEDL Limited (PEDLL) to EnQuest PLC for a deemed consideration for accounting purposes of US$553,300,000 which was settled by the issue of EnQuest PLC shares directly to Petrofac Limited shareholders*. The gain on the demerger transaction has been computed as follows:

	US$'000	US$'000

Fair value of consideration		553,300
Less:
Property, plant and equipment	(410,855)
Deferred tax asset	(27,394)
Inventories	(5,578)
Trade and other receivables	(107,039)
Cash and bank	(16,147)
Total book value of assets transferred	(567,013)

Provision for decommissioning	55,967
Trade and other payables	130,348
Translation reserve	(3,308)
Total book value of liabilities transferred	183,007
Net assets transferred		(384,006)
Transaction costs		(1,636)
Release of foreign currency translation reserve		(45,818)
Allocated goodwill written off (note 12)		(1,146)
Other consolidation adjustments		4,170

Gain on demerger		124,864

*In order to effect the demerger of the PEDL sub group to EnQuest, the existing issued ordinary share capital of Petrofac Limited was subdivided and converted into new ordinary Petrofac shares with a nominal value of US$0.02 each and Petrofac B shares of US$0.005 each and subsequent to this share split the B shares were purchased and cancelled in exchange for an allotment and issue of EnQuest ordinary shares directly to holders of Petrofac B shares.

As a result of this capital re-organisation and purchase of Petrofac B shares US$1,728,000 of Petrofac issued ordinary share capital was extinguished and transferred to retained earnings and the non-cash distribution to Petrofac shareholders for accounting purposes of US$553,300,000 was made via the utilisation of the existing share premium account balance of US$71,172,000 with the remaining amount of US$482,128,000 being transferred out of retained earnings. In addition US$8,803,000 of proceeds generated by the Petrofac Employee Benefit Trust selling its holding of EnQuest shares arising from the demerger have been credited to retained earnings leaving a net impact on retained earnings of US$473,325,000.

12 GOODWILL

A summary of the movements in goodwill is presented below:

	2010	2009
	US$'000	US$'000

At 1 January	97,922	97,534
Acquisitions during the year (note 10)	13,223	-
Reassessment of deferred consideration payable	(1,313)	(8,992)
Write off on EnQuest demerger (note 11)	(1,146)	-
Exchange difference	(2,854)	9,380
At 31 December	105,832	97,922

Reassessment of deferred consideration payable mainly comprise of the reduction in deferred consideration payable on Caltec Limited of US$4,285,000 (2009: US$2,929,000 decrease) and an increase in deferred consideration payable on SPD Group Limited of US$3,141,000 (2009: US$4,351,000 decrease).

12 GOODWILL (continued)

Goodwill acquired through business combinations has been allocated to five groups of cash-generating units, which are operating segments, for impairment testing as follows:

· Offshore Engineering & Operations

· Engineering Services

· Production Solutions

· Training Services

· Energy Developments

These represent the lowest level within the group at which the goodwill is monitored for internal management purposes.

Offshore Engineering & Operations, Engineering Services, Production Solutions and Training cash-generating units

The recoverable amounts for the Offshore Engineering & Operations, Engineering Services, Production Solutions and Training units have been determined based on value in use calculations, using discounted pre-tax cash flow projections. Management has adopted a ten year projection period to assess each unit's value in use as it is confident based on past experience of the accuracy of long-term cash flow forecasts that these projections are reliable. The cash flow projections are based on financial budgets approved by senior management covering a five year period, extrapolated for a further five years at a growth rate of 5% for Offshore Engineering & Operations, Engineering Services and Training cash-generating units and 2.5% per annum for Production Solutions cash-generating unit since it includes newly acquired businesses where there is less historic track record of achieving financial projections.

Energy Developments cash-generating unit

The recoverable amount of the Energy Developments unit is also determined on a value in use calculation using discounted pre-tax cash flow projections based on financial budgets and economic assumptions for the unit approved by senior management and covering a five year period, as referred to in IAS 36.

Carrying amount of goodwill allocated to each group of cash-generating units

	2010	2009
	US$'000	US$'000

Offshore Engineering & Operations unit	27,992	22,975
Engineering Services	7,728	-
Production Solutions unit	49,739	52,496
Training Services unit	19,302	20,234
Energy Developments unit	1,071	2,217
	105,832	97,922

Key assumptions used in value in use calculations

The calculation of value in use for the Offshore Engineering & Operations, Engineering Services, Production Solutions and Training Services units is most sensitive to the following assumptions:

Market share: the assumption relating to market share for the Offshore Engineering & Operations unit is based on the unit re-securing those existing customer contracts in the UK which are due to expire during the projection period; for the Training Services unit, the key assumptions relate to management's assessment of maintaining the unit's market share in the UK and developing further the business in international markets.

Growth rate: estimates are based on management's assessment of market share having regard to macro-economic factors and the growth rates experienced in the recent past by each unit. A growth rate of 5% per annum has been applied for Offshore Engineering & Operations, Engineering Services and Training Services cash-generating units for the remaining five years of the ten year projection period and 2.5% per annum for Production Solutions cash-generating unit since it includes newly acquired businesses where there is less historic track record of achieving financial projections.

Net profit margins:estimates are based on management's assumption of achieving a level of performance at least in line with the recent past performance of each of the units.

12 GOODWILL (continued)

Discount rate: management has used a pre-tax discount rate of 14.6% per annum for each of Offshore Engineering & Operations (2009: 14.5%), Engineering Services (2009: n/a) Production Solutions (2009: 14.5%) and Training (2009: 14.5%) cash-generating units which are derived from the estimated weighted average cost of capital of the group. This discount rate has been calculated using an estimated risk free rate of return adjusted for the group's estimated equity market risk premium and the group's cost of debt.

The calculation of value in use for the Energy Developments unit is most sensitive to the following assumptions:

Discount rate: management has used an estimate of the pre-tax weighted average cost of capital of the group plus a risk premium to reflect the particular risk characteristics of each individual asset. The discount rate used for 2010 was 13.4% for each asset (2009: 10.5%).

Oil & gas prices:management has used an oil price assumption of US$75.00 (2009: US$70.00) per barrel and a gas price of US$8.73 (2009: US$8.30) per mcf for the impairment testing of its individual oil & gas investments.

Reserve volumes and production profiles: management has used its internally developed economic models of reserves and production as a basis of calculating value in use.

Sensitivity to changes in assumptions

Other than the assumed success of the Ticleni contract in Production Solutions with regard to the assessment of value in use of the cash generating units, management believes that no reasonably possible change in any of the above key assumptions would cause the carrying value of the relevant unit to exceed its recoverable amount, after giving due consideration to the macro-economic outlook for the oil & gas industry and the commercial arrangements with customers underpinning the cash flow forecasts for each of the units.

13 INTANGIBLE ASSETS

	2010	2009
	US$'000	US$'000
Intangible oil & gas assets
Cost:
At 1 January	53,888	43,137
Additions	15,644	29,230
Disposal	-	(18,479)
At 31 December	69,532	53,888

Accumulated impairment:
At 1 January	-	(13,686)
Impairment	-	(4,793)
Disposal	-	18,479
At 31 December	-	-

Net book value of intangible oil & gas assets at 31 December	69,532	53,888

Other intangible assets
Cost:
At 1 January	25,476	13,892
Additions on acquisition (note 10)	3,172	-
Additions	153	10,375
Disposal	(4,220)	-
Exchange difference	(43)	1,209
At 31 December	24,538	25,476

Accumulated amortisation:
At 1 January	(6,257)	(4,990)
Amortisation	(2,511)	(1,083)
Disposal	540	-
Exchange difference	(5)	(184)
At 31 December	(8,233)	(6,257)

Net book value of other intangible assets at 31 December	16,305	19,219

Total intangible assets	85,837	73,107

Intangible oil & gas assets

Oil & gas asset (part of the Energy Development segment) additions above comprise of US$15,644,000 (2009: US$29,230,000) of capitalised expenditure on the group's assets in Malaysia.

There were investing cash outflows relating to capitalised intangible oil & gas assets of US$15,644,000 (2009: US$29,230,000) in the current period arising from pre-development activities.

Other intangible assets

Other intangible assets comprising customer contracts, proprietary software, LNG intellectual property and patent technology are being amortised over their remaining estimated economic useful life of three, six, eight and ten years respectively on a straight-line basis and the related amortisation charges included in selling, general and administrative expenses (note 4c). During the year, proprietary software was disposed of with a resulting gain disclosed in other income (note 4f).

14 INVESTMENT IN ASSOCIATES

	2010	2009
	US$'000	US$'000

Investment in Gateway Storage Company Limited	15,795	-
Associates acquired through acquisition of Scotvalve (note 10)	777	-
Share of associate loss	(131)	-
Exchange difference	(92)	-
	16,349	-

Gateway Storage Company Limited

On 6 December 2010, the group acquired a 20% equity interest in Gateway Storage Company Limited (Gateway), an unlisted entity, to progress and develop the Gateway Gas Storage project in the East Irish Sea. The initial cost of the investment was Sterling 5,000,000 (equivalent US$ 7,795,000) together with, transaction costs of US$664,000 and contracted value of free services to be provided by the group of Sterling 500,000 (equivalent US$ 780,000). Additional contingent payments may become payable under the terms of the investment, subject to key project development milestones being achieved, including the outcome of further successful equity sales. Deferred consideration of Sterling 4,160,000 (equivalent US$6,556,000) has been estimated as payable using a discounted storage project cash flow model assuming certain project scenarios to which estimated probabilities were assigned by management. The deferred consideration in no event will exceed an additional amount of Sterling 28,000,000 (equivalent US$43,705,000). The share of the associate's statement of financial position is as follows:

	2010
	US$'000

Non-current assets	123
Current assets	3,050
Non-current liabilities	-
Current liabilities	(795)
Equity	2,378

Transaction costs incurred	664
Fair value of free services to be provided	780
Deferred consideration payable	6,556
Exchange on deferred consideration payable	(63)
Residual goodwill	5,417
Share of loss	(131)
Carrying value of investment	15,601

Share of associates revenues and net loss:
Revenue	-
Net loss	(131)

15 INTEREST IN JOINT VENTURES

In the normal course of business, the group establishes jointly controlled entities for the execution of certain of its operations and contracts. A list of these joint ventures is disclosed in note 35. The group's share of assets, liabilities, revenues and expenses relating to jointly controlled entities is as follows:

	2010	2009
	US$'000	US$'000

Revenue	194,848	31,573
Cost of sales	(171,233)	(28,293)
Gross profit	23,615	3,280
Selling, general and administration expenses	(14,286)	(16,374)
Other (expense)/income, net	(6,553)	47
Finance income, net	643	5
Profit/(loss) before income tax	3,419	(13,042)
Income tax	(263)	(268)
Net profit/(loss)	3,156	(13,310)

Current assets	94,935	61,677
Non-current assets	27,634	4,830
Total assets	122,569	66,507

Current liabilities	120,892	64,619
Non-current liabilities	1,658	3,686
Total liabilities	122,550	68,305
Net assets/(liabilities)	19	(1,798)

16 AVAILABLE-FOR-SALE FINANCIAL ASSETS

	2010	2009
	US$'000	US$'000

Seven Energy International Limited	101,251	-
Shares - listed	243	-
Units in a mutual fund	-	539
	101,494	539

On 25 November 2010, the group paid US$101,251,000 for 15% (12.6% on a fully diluted basis) of the share capital of Seven Energy International Limited (Seven Energy), a leading Nigerian gas development and production company. The group also has the option to subscribe for 148,571 of additional warrants in Seven Energy at a cost of a further US$52,000,000, subject to the satisfaction of certain performance conditions and milestones in relation to project execution. These warrants have been fair valued as derivative financial instruments under IAS 39 using a Black Scholes Model and are included in other financial assets (note 17) with a corresponding entry in trade and other payables representing deferred revenue relating to the performance conditions. This will be recognised as a gain once the warrants become exercisable.

17 OTHER FINANCIAL ASSETS

	2010	2009
	US$'000	US$'000
Other financial assets - non-current
Fair value of derivative instruments (note 33)	12	9,655
Restricted cash	266	2,880
Other	1,945	-
	2,223	12,535

Other financial assets - current
Seven Energy warrants (note 16)	11,969	-
Fair value of derivative instruments (note 33)	9,183	22,306
Interest receivable	731	845
Restricted cash	19,196	7,431
Other	1,271	375
	42,350	30,957

Restricted cash comprises deposits with financial institutions securing various guarantees and performance bonds associated with the group's trading activities (note 31). This cash will be released on the maturity of these guarantees and performance bonds.

18 INVENTORIES

	2010	2009
	US$'000	US$'000

Crude oil	2,119	5,272
Processed hydrocarbons	90	31
Stores and spares	4,083	2,943
Raw materials	910	1,552
	7,202	9,798

Included in the consolidated income statement are costs of inventories expensed of US$28,840,000 (2009: US$37,306,000).

19 WORK IN PROGRESS AND BILLINGS IN EXCESS OF COST AND ESTIMATED EARNINGS

	2010	2009
	US$'000	US$'000

Cost and estimated earnings	7,812,897	3,918,368
Less: billings	(7,008,911)	(3,584,670)
Work in progress	803,986	333,698

Billings	2,144,252	3,406,412
Less: cost and estimated earnings	(1,965,823)	(2,945,268)
Billings in excess of cost and estimated earnings	178,429	461,144

Total cost and estimated earnings	9,778,720	6,863,636

Total billings	9,153,163	6,991,082

20 TRADE AND OTHER RECEIVABLES

	2010	2009
	US$'000	US$'000

Trade receivables	785,383	614,837
Retentions receivable	26,297	8,772
Advances	179,101	139,550
Prepayments and deposits	34,059	35,143
Other receivables	31,919	80,368
	1,056,759	878,670

Trade receivables are non-interest bearing and are generally on 30 to 60 days' terms. Trade receivables are reported net of provision for impairment. The movements in the provision for impairment against trade receivables totalling US$785,383,000 (2009: US$614,837,000) are as follows:

	2010			2009
	Specific	General		Specific	General
	Impairment	impairment	Total	impairment	impairment	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

At 1 January	4,875	1,754	6,629	3,698	1,296	4,994
Charge for the year	2,189	1,796	3,985	6,309	1,320	7,629
Amounts written off	(2,197)	(67)	(2,264)	(343)	(198)	(541)
Unused amounts reversed	(1,738)	(893)	(2,631)	(4,798)	(661)	(5,459)
Transfers	(326)	326	-	-	-	-
Exchange difference	(13)	19	6	9	(3)	6
At 31 December	2,790	2,935	5,725	4,875	1,754	6,629

At 31 December, the analysis of trade receivables is as follows:

	Neither past	Number of days past due
	due nor
	impaired	< 30	31-60	61-90	91-120	121-360	> 360
		days	days	days	days	days	days	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

Unimpaired	599,661	125,821	34,562	10,897	7,324	834	164	779,263
Impaired	-	3,230	1,085	157	1,633	4,023	1,717	11,845
	599,661	129,051	35,647	11,054	8,957	4,857	1,881	791,108
Less: impairment provision	-	(1,211)	(391)	(244)	(774)	(2,295)	(810)	(5,725)
Net trade receivables 2010	599,661	127,840	35,256	10,810	8,183	2,562	1,071	785,383

Unimpaired	434,159	116,197	28,835	13,365	3,431	5,977	2,138	604,102
Impaired	-	3,177	2,148	386	2,510	6,220	2,923	17,364
	434,159	119,374	30,983	13,751	5,941	12,197	5,061	621,466
Less: impairment provision	-	(585)	(243)	(332)	(305)	(3,421)	(1,743)	(6,629)
Net trade receivables 2009	434,159	118,789	30,740	13,419	5,636	8,776	3,318	614,837

The credit quality of trade receivables that are neither past due nor impaired is assessed by management with reference to externally prepared customer credit reports and the historic payment track records of the counterparties.

Advances represent payments made to certain of the group's sub-contractors for projects in progress, on which the related work had not been performed at the statement of financial position date. The increase in advances during 2010 relates to new contract awards in the Engineering & Construction business partly offset by the unwinding of advances on more mature contracts.

Included in other receivables are US$ nil (2009: US$46,697,000) recoverable from venture partners on the Don assets being their share of accrued expenses.

All trade and other receivables are expected to be settled in cash.

Certain trade and other receivables will be settled in cash using currencies other than the reporting currency of the group, and will be largely paid in Sterling and Kuwaiti Dinars.

21 CASH AND SHORT-TERM DEPOSITS

	2010	2009
	US$'000	US$'000

Cash at bank and in hand	244,018	203,105
Short-term deposits	818,987	1,214,258
Total cash and bank balances	1,063,005	1,417,363

Short-term deposits are made for varying periods of between one day and three months depending on the immediate cash requirements of the group, and earn interest at respective short-term deposit rates. The fair value of cash and bank balances is US$1,063,005,000 (2009: US$1,417,363,000).

For the purposes of the consolidated cash flow statement, cash and cash equivalents comprise the following:

	2010	2009
	US$'000	US$'000

Cash at bank and in hand	244,018	203,105
Short-term deposits	818,987	1,214,258
Bank overdrafts (note 26)	(28,908)	(26,619)
	1,034,097	1,390,744

22 SHARE CAPITAL

The share capital of the Company as at 31 December was as follows:

	2010	2009
	US$'000	US$'000
Authorised
750,000,000 ordinary shares of US$0.020 each
(2009: 750,000,000 ordinary shares of US$0.025 each)	15,000	18,750

Issued and fully paid
**345,715,053 ordinary shares of US$0.020 each
(2009: 345,532,388 ordinary shares of US$0.025 each)	6,914	8,638

The movement in the number of issued and fully paid ordinary shares is as follows:

	Number
Ordinary shares:
Ordinary shares of US$0.025 each at 1 January 2009	345,434,858
Issued during the year as further deferred consideration payable for the acquisition of a subsidiary	97,530

Ordinary shares of US$0.025 each at 1 January 2010	345,532,388
Issued during the year as further deferred consideration payable for the acquisition of subsidiaries	182,665

Ordinary shares of US$0.020 each at 31 December 2010	345,715,053

The share capital comprises only one class of ordinary shares. The ordinary shares carry a voting right and the right to a dividend.

**In order to effect the demerger of the PEDL sub group to EnQuest, the existing issued ordinary share capital of Petrofac Limited was subdivided and converted into new ordinary Petrofac shares with a nominal value of US$0.02 each and Petrofac B shares of US$0.005 each and subsequent to this share split the B shares were purchased and cancelled in exchange for an allotment and issue of EnQuest ordinary shares directly to holders of Petrofac B shares.

23 TREASURY SHARES

For the purpose of making awards under its employee share schemes, the Company acquires its own shares which are held by the Petrofac Employee Benefit Trust. All these shares have been classified in the statement of financial position as treasury shares within equity.

The movements in total treasury shares are shown below:

	2010		2009
	Number	US$'000	Number	US$'000

At 1 January	7,210,965	56,285	9,540,306	69,333
Acquired during the year	2,122,960	36,486	-	-
Vested during the year	(2,576,586)	(27,454)	(2,329,341)	(13,048)
At 31 December	6,757,339	65,317	7,210,965	56,285

During the year 5,467,852 Petrofac shares previously held in a Lehman Brothers custody account pending the finalisation of their legal administration were released to the Employee Benefit Trust.

Shares vested during the year include dividend shares of 120,504 (2009: 76,931) with a cost of US$1,284,000 (2009: US$431,000).

24 SHARE-BASED PAYMENT PLANS

Performance Share Plan (PSP)

Under the Performance Share Plan of the Company, share awards are granted to executive Directors and a restricted number of other senior executives of the group. The shares cliff vest at the end of three years subject to continued employment and the achievement of certain pre-defined non-market and market based performance conditions. The non-market based condition governing the vesting of 50% of the total award, is subject to achieving between 10% and 20% earning per share (EPS) growth targets over a three year period. The fair values of the equity-settled award relating to the EPS part of the scheme are estimated based on the quoted closing market price per Company share at the date of grant with an assumed vesting rate per annum built into the calculation (subsequently trued up at year end based on the actual leaver rate during the period from award date to year end) over the three year vesting period of the plan. The fair value and assumed vesting rates of the EPS part of the scheme are shown below:

	Fair value per share	Assumed vesting rate

2010 awards	1,103p	95.0%
2009 awards	545p	93.6%
2008 awards	522p	89.1%
2007 awards	415p	94.3%

The remaining 50% market performance based part of these awards is dependent on the total shareholder return (TSR) of the group compared to an index composed of selected relevant companies. The fair value of the shares vesting under this portion of the award is determined by an independent valuer using a Monte Carlo simulation model taking into account the terms and conditions of the plan rules and using the following assumptions at the date of grant:

	2010 awards	2009 awards	2008 awards	2007 awards
Expected share price volatility (based on median of comparator group's three year volatilities)	50.0%	49.0%	32.0%	29.0%
Share price correlation with comparator group	39.0%	36.0%	22.0%	17.0%
Risk-free interest rate	1.50%	2.10%	3.79%	5.20%
Expected life of share award	3 years	3 years	3 years	3 years
Fair value of TSR portion	743p	456p	287p	245p

24 SHARE-BASED PAYMENT PLANS

Performance Share Plan (PSP) (continued)

The following shows the movement in the number of shares held under the PSP scheme outstanding but not exercisable:

	2010	2009
	Number	Number

Outstanding at 1 January	1,432,680	1,298,809
Granted during the year	390,278	576,780
Vested during the year	(407,316)	(418,153)
Forfeited during the year	(65,453)	(24,756)
Outstanding at 31 December	1,350,189	1,432,680

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger (82,594 shares) and any rolled up declared dividends (64,264 shares) (2009: 60,830). The 8% uplift adjustment compensated the existing share plan holders for the loss in market value of Petrofac shares on flotation of EnQuest and employees have no legal right to receive dividend shares until the shares ultimately vest.

The number of awards still outstanding but not exercisable at 31 December 2010 is made up of 390,278 in respect of 2010 awards (2009: nil), 538,602 in respect of 2009 awards (2009: 576,780), 421,309 in respect of 2008 awards (2009: 431,843), and nil in respect of 2007 awards (2009: 424,057).

The charge recognised in the current year amounted to US$3,208,000 (2009: US$2,727,000).

Deferred Bonus Share Plan (DBSP)

Executive directors and selected employees were originally eligible to participate in this scheme although the Remuneration Committee decided in 2007 that executive directors should no longer continue to participate. Participants are required, or in some cases invited, to receive a proportion of any bonus in ordinary shares of the Company ("Invested Awards"). Following such an award, the Company will generally grant the participant an additional award of a number of shares bearing a specified ratio to the number of his or her invested shares ("Matching Shares").

A change in the rules of the DBSP scheme was approved by shareholders at the Annual General Meeting of the Company on 11 May 2007 such that the 2007 share awards and for any awards made thereafter, the invested and matching shares would, unless the Remuneration Committee of the Board of Directors determined otherwise, vest 33.33% on the first anniversary of the date of grant, a further 33.33% on the second anniversary of the date of grant and the final 33.34% of the award on the third anniversary of the date of grant.

At the year end the values of the bonuses settled by shares cannot be determined until all employees have confirmed the voluntary portion of their bonus they wish to be settled by shares rather than cash and until the Remuneration Committee has approved the mandatory portion of the employee bonuses to be settled in shares. Once the voluntary and mandatory portions of the bonus to be settled in shares are determined, the final bonus liability to be settled in shares is transferred to the reserve for share-based payments. The costs relating to the matching shares are recognised over the relevant vesting period and the fair values of the equity-settled Matching Shares granted to employees are based on the quoted closing market price at the date of grant adjusted for the trued up percentage vesting rate of the plan. The details of the fair values and assumed vesting rates of the DBSP scheme are below:

	Fair value per share	Assumed vesting rate

2010 awards	1,185p	94.4%
2009 awards	545p	93.9%
2008 awards	522p	90.9%
2007 awards	415p	89.6%

24 SHARE-BASED PAYMENT PLANS (continued)

Deferred Bonus Share Plan (DBSP) (continued)

The following shows the movement in the number of shares held under the DBSP scheme outstanding but not exercisable:

	2010		2009
	Number*		Number*

Outstanding at 1 January	4,694,191	3,755,383
Granted during the year	1,397,094	2,773,020
Vested during the year	(1,792,895)	(1,743,372)
Forfeited during the year	(216,079)	(90,840)
Outstanding at 31 December	4,082,311	4,694,191

* Includes Invested and Matching Shares.

The numbers of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger (327,058 shares) and rolled up declared dividends of 184,599 (2009: 169,836).

The number of awards still outstanding but not exercisable at 31 December 2010 is made up of 1,313,894 in respect of 2010 awards (2009: nil), 1,948,340 in respect of 2009 awards (2009: 2,696,752), 820,077 in respect of 2008 awards (2009: 1,237,786), and nil in respect of 2007 awards (2009: 759,653).

The charge recognised in the 2010 income statement in relation to matching share awards amounted to US$9,195,000 (2009: US$8,064,000).

Share Incentive Plan (SIP)

All UK employees, including UK resident directors, are eligible to participate in the scheme. Employees may invest up to Sterling 1,500 per tax year of gross salary (or, if lower, 10% of salary) to purchase ordinary shares in the Company. There is no holding period for these shares.

Restricted Share Plan (RSP)

Under the Restricted Share Plan scheme, selected employees are granted shares in the Company over a discretionary vesting period which may or may not be, at the direction of the Remuneration Committee of the Board of Directors, subject to the satisfaction of performance conditions. At present there are no performance conditions applying to this scheme nor is there currently any intention to introduce them in the future. The fair values of the awards granted under the plan at various grant dates during the year are based on the quoted market price at the date of grant adjusted for an assumed vesting rate over the relevant vesting period. For details of the fair values and assumed vesting rate of the RSP scheme, see below:

	Weighted average fair value per share	Assumed vesting rate

2010 awards	990p	95.8%
2009 awards	430p	69.4%
2008 awards	478p	88.0%
2007 awards	456p	94.3%

The following shows the movement in the number of shares held under the RSP scheme outstanding but not exercisable:

	2010	2009
	Number	Number

Outstanding at 1 January	1,082,461	1,184,711
Granted during the year	203,384	86,432
Vested during the year	(176,360)	(167,053)
Forfeited during the year	(105,773)	(21,629)
Outstanding at 31 December	1,003,712	1,082,461

24 SHARE-BASED PAYMENT PLANS (continued)

Restricted Share Plan (RSP) (continued)

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger (78,156 shares) and rolled up declared dividends of 48,474 (2009: 33,691).

The number of awards still outstanding but not exercisable at 31 December 2010 is made up of 195,580 in respect of 2010 awards (2009: nil), 36,658 in respect of 2009 awards (2009: 86,432), 665,542 in respect of 2008 awards (2009: 786,826), and 105,932 in respect of 2007 awards (2009: 209,203).

During the year the Company recognised a charge of US$2,381,000 (2009: US$2,472,000) in relation to the above.

The group has recognised a total charge of US$14,784,000 (2009: US$13,263,000) in the consolidated income statement during the year relating to the above employee share-based schemes (see note 4d) which has been transferred to the reserve for share-based payments along with US$12,750,000 of the bonus liability accrued for the year ended 31 December 2009 which has been settled in shares granted during the year (2009: US$10,942,000).

For further details on the above employee share-based payment schemes refer to pages 92 to 96 of the directors' remuneration report.

25 OTHER RESERVES

	Net unrealised
	gains/(losses) on	Net unrealised
	available-for-	(losses) /	Foreign	Reserve for
	sale-financial	gains on	currency	share-based
	assets	derivatives	translation	payments	Total
	US$'000	US$'000	US$'000	US$'000	US$'000

Balance at 1 January 2009	74	7,847	(79,415)	32,202	(39,292)

Foreign currency translation	-	-	15,087	-	15,087

Net gains on maturity of cash flow
hedges recycled in the year	-	(4,303)	-	-	(4,303)

Net changes in fair value of derivatives and financial assets
designated as cash flow hedges	-	29,229	-	-	29,229

Share-based payments charge (note 24)	-	-	-	13,263	13,263

Transfer during the year (note 24)	-	-	-	10,942	10,942

Shares vested during the year (note 24)	-	-	-	(12,617)	(12,617)

Deferred tax on share based payments reserve	-	-	-	13,085	13,085

Balance at 1 January 2010	74	32,773	(64,328)	56,875	25,394

Foreign currency translation	-	-	(908)	-	(908)

Foreign currency translation recycled to consolidated income
statement in the year on EnQuest demerger (note 11)	-	-	45,818	-	45,818

Net gains on maturity of cash flow
hedges recycled in the year	-	(16,612)	-	-	(16,612)

Net changes in fair value of derivatives and financial assets
designated as cash flow hedges	-	(18,958)	-	-	(18,958)

Net changes in fair value of available-for-sale
financial assets	70	-	-	-	70

Disposal of available-for-sale financial assets	(74)	-	-	-	(74)

Share-based payments charge (note 24)	-	-	-	14,784	14,784

Transfer during the year (note 24)	-	-	-	12,750	12,750

Shares vested during the year (note 24)	-	-	-	(26,170)	(26,170)

Deferred tax on share based payments reserve	-	-	-	(1,366)	(1,366)

Balance at 31 December 2010	70	(2,797)	(19,418)	56,873	34,728

Nature and purpose of other reserves

Net unrealised gains / (losses) on available-for-sale financial assets

This reserve records fair value changes on available-for-sale financial assets held by the group net of deferred tax effects. Realised gains and losses on the sale of available-for-sale financial assets are recognised as other income or expenses in the consolidated income statement.

Net unrealised gains / (losses) on derivatives

The portion of gains or losses on cash flow hedging instruments that are determined to be effective hedges are included within this reserve net of related deferred tax effects. When the hedged transaction occurs or is no longer forecast to occur, the gain or loss is transferred out of equity to the consolidated income statement. Realised net gains amounting to US$16,764,000 (2009: US$5,161,000) relating to foreign currency forward contracts and financial assets designated as cash flow hedges have been recognised in cost of sales, realised net losses of US$ nil (2009: US$1,470,000 loss) relating to interest rate derivatives have been classified as a net interest expense and a realised net loss of US$152,000 (2009: US$611,000 gain) was added to revenues in respect of oil derivatives.

25 OTHER RESERVES (continued)

Net unrealised gains / (losses) on derivatives (continued)

The forward currency points element and ineffective portion of derivative financial instruments relating to forward currency contracts and gains on the maturity of un-designated derivatives amounting to a net loss of US$3,409,000 (2009: US$19,508,000 gain) have been recognised in the cost of sales.

Foreign currency translation reserve

The foreign currency translation reserve is used to record exchange differences arising from the translation of the financial statements in foreign subsidiaries. It is also used to record exchange differences arising on monetary items that form part of the group's net investment in subsidiaries.

Reserve for share-based payments

The reserve for share-based payments is used to record the value of equity settled share-based payments awarded to employees and transfers out of this reserve are made upon vesting of the original share awards.

The transfer during the year reflects the transfer from accrued expenses within trade and other payables of the bonus liability relating to the year ended 2009 of US$12,750,000 (2008 bonus of US$10,942,000) which has been voluntarily elected or mandatorily obliged to be settled in shares during the year (note 24).

26 INTEREST-BEARING LOANS AND BORROWINGS

The group had the following interest-bearing loans and borrowings outstanding:

		31 December 2010	31 December 2009	Effective
		Actual interest rate%	Actual interest rate%	interest rate%	Maturity	2010	2009
						US$'000	US$'000
Current
Revolving credit facility	(i)	n/a	US LIBOR + 1.50%	US LIBOR + 1.50%	-	-	20,000
Bank overdrafts	(ii)	UK LIBOR + 1.50%, US LIBOR + 1.50%	UK LIBOR + 1.50%, US LIBOR + 1.50%	UK LIBOR + 1.50%, US LIBOR + 1.50%	on demand	28,908	26,619
Other loans:
Current portion of term loan	(iii)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	3.26% to 4.14% (2009: 3.14% to 3.71%)		14,241	10,489
Current portion of term loan	(iv)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	2.01% to 3.91% (2009: 2.65% to 3.44%)		4,286	963
						47,435	58,071
Non-current
Term loan	(iv)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	2.01% to 3.91% (2009: 2.65% to 3.44%)	2010-2013	13,809	18,291
Term loan	(iii)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	3.26% to 4.14% (2009: 3.14% to 3.71%)	2010-2013	30,576	46,694
						44,385	64,985
Less:
Debt acquisition costs net of accumulated amortisation and effective rate adjustments						(4,159)	(5,790)
						40,226	59,195

Details of the group's interest-bearing loans and borrowings are as follows:

(i) Revolving credit facility

This facility has been repaid on 31 December 2010.

(ii) Bank overdrafts

Bank overdrafts are drawn down in US dollars and Sterling denominations to meet the group's working capital requirements. These are repayable on demand.

26 INTEREST-BEARING LOANS AND BORROWINGS (continued)

(iii) Term loan

This term loan at 31 December 2010 comprised drawings of US$23,057,000 (2009: US$28,877,000) denominated in US$ and US$21,760,000 (2009: US$28,306,000) denominated in Sterling. Both elements of the loan are repayable over a period of three years ending 30 September 2013.

(iv) Term loan

This term loan is to be repaid over a period of three years ending 30 September 2013. The drawings at 31 December 2010 comprised US$13,203,000 (2009: US$13,900,000) denominated in US$ and US$4,892,000 (2009: US$5,354,000) denominated in Sterling.

The group's credit facilities and debt agreements contain covenants relating to interest and net borrowings cover. None of the Company's subsidiaries is subject to any material restrictions on their ability to transfer funds in the form of cash dividends, loans or advances to the Company.

27 PROVISIONS

	Other long- term		Provision for
	employment	Provision for	insurance
	benefits provision	decommissioning	claims	Total
	US$'000	US$'000	US$'000	US$'000

At 1 January 2010	34,130	57,973	-	92,103
Additions during the year	12,770	984	1,561	15,315
Don assets demerger (note 11)	-	(55,967)	-	(55,967)
Unused amounts reversed/paid in the year	(6,696)	(90)	-	(6,786)
Unwinding of discount	-	776	-	776
At 31 December 2010	40,204	3,676	1,561	45,441

Other long- term employment benefits provision

Labour laws in certain countries in which the group operates require employers to provide for other long-term employment benefits. These benefits are payable to employees on being transferred to another jurisdiction or on cessation of employment.

Provision for decommissioning

The decommissioning provision primarily relates to the group's obligation for the removal of facilities and restoration of the site at the PM304 field in Malaysia and at Chergui in Tunisia. The liability is discounted at the rate of 3.80% on PM304 (2009: 3.80%), 5.25% on Chergui (2009: 5.25%) and nil% (2009: 4.50%) on demerged Don assets. The unwinding of the discount is classified as finance cost (note 5). The group estimates that the cash outflows against these provisions will arise in 2014 on PM304 and in 2018 on Chergui.

Provision for insurance claims

The provision for insurance claims relates to the amount set aside to cover potential future insurance claims against the group which will be settled by the captive insurance company Jermyn Insurance Company Limited.

28 OTHER FINANCIAL LIABILITIES

	2010	2009
	US$'000	US$'000
Other financial liabilities - non-current
Deferred consideration payable	11,279	27,438
Fair value of derivative instruments (note 33)	174	-
Other	-	47
	11,453	27,485
Other financial liabilities - current
Deferred consideration payable	24,595	1,622
Interest payable	9	22
Fair value of derivative instruments (note 33)	12,197	1,813
Other	253	177
	37,054	3,634

Included in deferred consideration payable above is an amount payable of US$3,918,000 (2009: US$ 4,890,000) relating to the group's purchase of a floating platform and US$6,556,000 (2009: US$ nil) relating to the group's investment in an associate (note 14).

29 TRADE AND OTHER PAYABLES

	2010	2009
	US$'000	US$'000
		Restated

Trade payables	278,383	292,414
Advances received from customers	412,044	379,684
Accrued expenses	251,512	260,290
Other taxes payable	12,755	14,699
Other payables	66,742	29,930
	1,021,436	977,017

Trade payables are non-interest bearing and are normally settled on terms of between 30 and 60 days.

Advances from customers represent payments received for contracts on which the related work had not been performed at the statement of financial position date.

Included in other payables are retentions held against subcontractors of US$6,170,000 (2009: US$938,000). Also included in other payables above is U$11,969,000 deferred revenue relating to the provision of services required to earn the right to subscribe for the additional Seven Energy warrants (note 16).

Certain trade and other payables will be settled in currencies other than the reporting currency of the group, mainly in Sterling, Euros and Kuwaiti Dinars.

30 ACCRUED CONTRACT EXPENSES

	2010	2009
	US$'000	US$'000

Accrued contract expenses	1,272,942	832,503
Reserve for contract losses	2,523	4,153
	1,275,465	836,656

The reserve for contract losses is to cover costs in excess of revenues on certain contracts.

31 COMMITMENTS AND CONTINGENCIES

Commitments

In the normal course of business the group will obtain surety bonds, letters of credit and guarantees, which are contractually required to secure performance, advance payment or in lieu of retentions being withheld. Some of these facilities are secured by issue of corporate guarantees by the Company in favour of the issuing banks.

At 31 December 2010, the group had letters of credit of US$2,984,000 (2009: US$91,042,000) and outstanding letters of guarantee, including performance, advance payments and bid bonds, of US$2,951,553,000 (2009: US$2,124,134,000) against which the group had pledged or restricted cash balances of, in aggregate, US$19,462,000 (2009: US$2,675,000).

At 31 December 2010, the group had outstanding forward exchange contracts amounting to US$188,561,000 (2009: US$351,803,000). These commitments consist of future obligations to either acquire or sell designated amounts of foreign currency at agreed rates and value dates (note 33).

Leases

The group has financial commitments in respect of non-cancellable operating leases for office space and equipment. These non-cancellable leases have remaining non-cancellable lease terms of between one and seventeen years and, for certain property leases, are subject to renegotiation at various intervals as specified in the lease agreements. The future minimum rental commitments under these non-cancellable leases are as follows:

	2010	2009
	US$'000	US$'000

Within one year	18,031	35,796
After one year but not more than five years	41,239	57,127
More than five years	76,914	73,030
	136,184	165,953

Included in the above are commitments relating to the lease of an office building extension in Aberdeen, United Kingdom of US$49,232,000 (2009: US$39,735,000), lease of mobile operating production unit and floating storage and offloading unit US$15,619,000 (2009: US$35,665,000) in Block PM304, offshore Malaysia and mobile drilling rig for the Don Southwest project of US$ nil (2009: US$10,089,000).

Minimum lease payments recognised as an operating lease expense during the year amounted to US$35,625,000 (2009: US$33,063,000).

Capital commitments

At 31 December 2010, the group had capital commitments of US$90,416,000 (2009: US$18,786,000) excluding the above lease commitments.

Included in the above are commitments to refurbish the floating production, storage and offloading unit for East Fortune of US$52,800,000 (2009: US$ nil), further appraisal and development of wells as part of the Cendor project in Malaysia amounting to US$7,269,000 (2009: US$14,572,000), commitments in respect of the Ticleni Production Enhancement contract in Romania US$21,046,000 (2009: US$ nil) and commitments in respect of IT projects of US$9,281,000 (2009: US$ 3,300,000).

32 RELATED PARTY TRANSACTIONS

The consolidated financial statements include the financial statements of Petrofac Limited and the subsidiaries listed in note 35. Petrofac Limited is the ultimate parent entity of the group.

The following table provides the total amount of transactions which have been entered into with related parties:

		Sales to related	Purchases from	Amounts owed	Amounts owed
		parties	related parties	by related parties	to related parties
		US$'000	US$'000	US$'000	US$'000

Joint ventures	2010	101,370	88,796	327	11,098
	2009	27,337	15,434	17,773	56,925

Key management	2010	-	1,688	-	612
personnel interests	2009	-	1,405	487	401

All sales to and purchases from joint ventures are made at normal market prices and the pricing policies and terms of these transactions are approved by the group's management.

All related party balances will be settled in cash.

Purchases in respect of key management personnel interests of US$1,601,000 (2009: US$1,336,000) reflect the market rate based costs of chartering the services of an aeroplane used for the transport of senior management and directors of the group on company business, which is owned by an offshore trust of which the Group Chief Executive of the Company is a beneficiary.

Also included in purchases in respect of key management personnel interests is US$ 87,000 (2009: US$ 69,000) relating to client entertainment provided by a business owned by a member of the group's key management.

Amounts owed by key management personnel comprises of a temporary loan of US$ nil (2009: US$ 487,000) provided in respect of income tax payable on vesting of Restricted Share Plan shares pending disposal of shares to meet this liability once the close period for trading Petrofac shares ends.

Compensation of key management personnel

The following details remuneration of key management personnel of the group comprising of executive and non-executive directors of the Company and other senior personnel. Further information relating to the individual directors is provided in the directors' remuneration report on pages 101 to 103.

	2010	2009
	US$'000	US$'000

Short-term employee benefits	11,870	11,209
Other long-term employment benefits	142	129
Share-based payments	3,827	3,368
Fees paid to non-executive directors	581	506
	16,420	15,212

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk management objectives and policies

The group's principal financial assets and liabilities, other than derivatives, comprise available-for-sale financial assets, trade and other receivables, amounts due from/to related parties, cash and short-term deposits, work-in-progress, interest-bearing loans and borrowings, trade and other payables and deferred consideration.

The group's activities expose it to various financial risks particularly associated with interest rate risk on its variable rate cash and short-term deposits, loans and borrowings and foreign currency risk on both conducting business in currencies other than reporting currency as well as translation of the assets and liabilities of foreign operations to the reporting currency. These risks are managed from time to time by using a combination of various derivative instruments, principally interest rate swaps, caps and forward currency contracts in line with the group's hedging policies. The group has a policy not to enter into speculative trading of financial derivatives.

The Board of Directors of the Company has established an Audit Committee and Risk Committee to help identify, evaluate and manage the significant financial risks faced by the group and their activities are discussed in detail on pages 78 to 83.

The other main risks besides interest rate and foreign currency risk arising from the group's financial instruments are credit risk, liquidity risk and commodity price risk and the policies relating to these risks are discussed in detail below:

Interest rate risk

Interest rate risk arises from the possibility that changes in interest rates will affect the value of the group's interest-bearing financial liabilities and assets.

The group's exposure to market risk arising from changes in interest rates relates primarily to the group's long-term variable rate debt obligations and its cash and bank balances. The group's policy is to manage its interest cost using a mix of fixed and variable rate debt. The group's cash and bank balances are at floating rates of interest.

Interest rate sensitivity analysis

The impact on the group's pre-tax profit and equity due to a reasonably possible change in interest rates on loans and borrowings at the reporting date is demonstrated in the table below. The analysis assumes that all other variables remain constant.

	Pre-tax profit		Equity
	100 basis	100 basis	100 basis	100 basis
	point increase	point decrease	point increase	point decrease
	US$'000	US$'000	US$'000	US$'000

31 December 2010	(710)	710	-	-
31 December 2009	(1,096)	1,096	-	-

The following table reflects the maturity profile of these financial liabilities and assets:

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

Interest rate risk (continued)

Year ended 31 December 2010

	Within	1-2	2-3	3-4	4-5	More than
	1 year	years	years	years	years	5 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Financial liabilities
Floating rates
Bank overdrafts (note 26)	28,908	-	-	-	-	-	28,908
Term loans (note 26)	18,527	23,823	20,562	-	-	-	62,912
	47,435	23,823	20,562	-	-	-	91,820

Financial assets
Floating rates
Cash and short-term deposits (note 21)	1,063,005	-	-	-	-	-	1,063,005
Restricted cash balances (note 17)	19,196	266					19,462
	1,082,201	266	-	-	-	-	1,082,467

Year ended 31 December 2009

	Within	1-2	2-3	3-4	4-5	More than
	1 year	years	years	years	years	5 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Financial liabilities
Floating rates
Revolving credit facility (note 26)	20,000	-	-	-	-	-	20,000
Bank overdrafts (note 26)	26,619	-	-	-	-	-	26,619
Term loans (note 26)	11,452	18,901	24,221	21,863	-	-	76,437
	58,071	18,901	24,221	21,863	-	-	123,056

Financial assets
Floating rates
Cash and short-term deposits (note 21)	1,417,363	-	-	-	-	-	1,417,363
Restricted cash balances (note 17)	7,431	226	-	-	-	2,654	10,311
	1,424,794	226	-	-	-	2,654	1,427,674

Financial liabilities in the above table are disclosed gross of debt acquisition costs and effective rate adjustments of US$4,159,000 (2009: US$5,790,000).

Interest on financial instruments classified as floating rate is re-priced at intervals of less than one year. The other financial instruments of the group that are not included in the above tables are non-interest bearing and are therefore not subject to interest rate risk.

Derivative instruments designated as cash flow hedges

At 31 December 2010, the group held no derivative instruments, designated as cash flow hedges in relation to floating rate interest-bearing loans and borrowings.

Foreign currency risk

The group is exposed to foreign currency risk on sales, purchases, and translation of assets and liabilities that are in a currency other than the functional currency of its operating units. The group is also exposed to the translation of the functional currencies of its units to the US dollar reporting currency of the group. The following table summarises the percentage of foreign currency denominated revenues, costs, financial assets and financial liabilities, expressed in US dollar terms, of the group totals.

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

Foreign currency risk (continued)

	2010	2009
	% of foreign currency denominated items	% of foreign currency denominated items

Revenues	41.6%	39.5%
Costs	62.2%	50.1%
Current financial assets	34.8%	35.3%
Non-current financial assets	0.0%	1.0%
Current financial liabilities	51.2%	42.3%
Non-current financial liabilities	59.4%	34.6%

The group uses forward currency contracts to manage the currency exposure on transactions significant to its operations. It is the group's policy not to enter into forward contracts until a highly probable forecast transaction is in place and to negotiate the terms of the derivative instruments used for hedging to match the terms of the hedged item to maximise hedge effectiveness.

Foreign currency sensitivity analysis

The income statements of foreign operations are translated into the reporting currency using a weighted average exchange rate of conversion. Foreign currency monetary items are translated using the closing rate at the reporting date. Revenues and costs in currencies other than the functional currency of an operating unit are recorded at the prevailing rate at the date of the transaction. The following significant exchange rates applied during the year in relation to US dollars:

	2010		2009
	Average rate	Closing rate	Average rate	Closing rate

Sterling	1.54	1.56	1.56	1.62
Kuwaiti Dinar	3.49	3.55	3.47	3.48
Euro	1.32	1.34	1.40	1.44

The following table summarises the impact on the group's pre-tax profit and equity (due to change in the fair value of monetary assets, liabilities and derivative instruments) of a reasonably possible change in US dollar exchange rates with respect to different currencies:

	Pre-tax profit		Equity
	+10% US dollar rate increase	-5% US dollar rate decrease	+10% US dollar rate increase	-5% US dollar rate decrease
	US$'000	US$'000	US$'000	US$'000

31 December 2010	(3,750)	1,875	6,272	(3,136)
31 December 2009	(10,238)	5,141	7,980	(3,990)

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

Foreign currency risk (continued)

Derivative instruments - undesignated and designated as cash flow hedges

At 31 December 2010, the group had foreign exchange forward contracts as follows:

								Net unrealised
	Contract value			Fair value (undesignated)		Fair value (designated)		gain/(loss)
	2010		2009	2010	2009	2010	2009	2010	2009
	US$'000		US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

Euro currency purchases	171,072		101,909	(1,794)	5,017	(2,046)	24,479	(1,827)	28,430
Sterling currency purchases	14,405		38,700	(135)	-	1,583	4,703	1,695	4,966
Yen currency purchases (sales)		1,721	(160)	128	-	76	(942)	117	(862)
Swiss Francs purchases	1,363		-	-	-	175	-	14	-
Kuwaiti Dinars sales	-		(211,034)	-	53	-	(1,349)	-	266
								(1)	32,800

The above foreign exchange contracts mature and will affect income between January 2011 and July 2013 (2009: between January 2010 and July 2013).

At 31 December 2010, the group had cash and short-term deposits designated as cash flow hedges with a fair value loss of US$1,633,000 (2009: US$1,786,000 gain) as follows:

			Net unrealised
	Fair value		gain/(loss)
	2010	2009	2010	2009
	US$'000	US$'000	US$'000	US$'000

Euro currency cash and short-term deposits	15,730	91,660	(1,798)	1,163
Sterling currency cash and short-term deposits	2,086	5,264	(120)	772
Yen currency cash and short-term deposits	4,510	-	278	-
Swiss Francs cash and short-term deposits	660	-	7	-
Kuwaiti Dinars cash and short-term deposits	-	19,146	-	(149)
			(1,633)	1,786

During 2010, changes in fair value loss of US$19,456,000 (2009: loss US$28,043,000) relating to these derivative instruments and financial assets were taken to equity and US$16,764,000 gain (2009: US$5,161,000 gain) were recycled from equity into cost of sales in the income statement. The forward points and ineffective portion of the above foreign exchange forward contracts and loss on maturity of un-designated derivatives of US$3,409,000 (2009: US$19,508,000 gains) was recognised in the income statement (note 4b).

Commodity price risk - oil prices

The group is exposed to the impact of changes in oil & gas prices on its revenues and profits generated from sales of crude oil & gas. The group's policy is to manage its exposure to the impact of changes in oil and gas prices using derivative instruments, primarily swaps and collars. Hedging is only undertaken once sufficiently reliable and regular long term forecast production data is available.

During the year the group entered into various crude oil swaps hedging oil production of 176,400 bbl (2009: 96,000 bbl) with maturities ranging from 1 April 2010 to 31 December 2011. In addition, fuel oil swaps were also entered into for hedging gas production of 43,750MT (2009: 27,000MT) with maturities from 1 April 2010 to 31 December 2011.

The fair value of oil derivatives at 31 December 2010 was US$1,163,000 liability (2009: US$1,813,000 liability) with a loss recognised in equity of US$1,163,000 (2009: US$1,813,000 loss). During the year, a loss of US$152,000 (2009: US$611,000 gain) was recognised in the consolidated income statement on the occurrence of the hedged transactions.

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

Commodity price risk - oil prices (continued)

The following table summarises the impact on the group's pre-tax profit and equity (due to a change in the fair value of oil derivative instruments and the underlifting asset/overlifting liability) of a reasonably possible change in the oil price:

	Pre-tax profit		Equity
	+10 US$/bbl increase	-10 US$/bbl decrease	+10 US$/bbl increase	-10 US$/bbl decrease
	US$'000	US$'000	US$'000	US$'000

31 December 2010	(194)	194	(802)	802
31 December 2009	82	(82)	(861)	861

Credit risk

The group trades only with recognised, creditworthy third parties. Business Unit Risk Review Committees (BURRC) have been set up by the Board of Directors to evaluate the creditworthiness of each individual third party at the time of entering into new contracts. Limits have been placed on the approval authority of the BURRC above which the approval of the Board of Directors of the Company is required. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. At 31 December 2010, the group's five largest customers accounted for 72.0% of outstanding trade receivables and work in progress (2009: 57.5%).

With respect to credit risk arising from the other financial assets of the group, which comprise cash and cash equivalents, available-for-sale financial assets and certain derivative instruments, the group's exposure to credit risk arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments.

Liquidity risk

The group's objective is to maintain a balance between continuity of funding and flexibility through the use of overdrafts, revolving credit facilities, project finance and term loans to reduce its exposure to liquidity risk. The maturity profiles of the group's financial liabilities at 31 December 2010 are as follows:

Year ended 31 December 2010

						Contractual
	6 months	6-12	1-2	2-5	More than	undiscounted	Carrying
	or less	months	years	years	5 years	cash flows	amount
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Financial liabilities
Interest-bearing loans and borrowings	37,776	9,659	23,823	20,562	-	91,820	87,661
Trade and other payables (excluding advances from customers)	551,233	58,159	-	-	-	609,392	609,392
Due to related parties	11,710	-	-	-	-	11,710	11,710
Deferred consideration	24,595	-	11,279	-	-	35,874	35,874
Derivative instruments	11,034	1,163	174	-	-	12,371	12,371
Interest payable	9	-	-	-	-	9	9
Interest payments	421	388	632	206	-	1,647	-
	636,778	69,369	35,908	20,768	-	762,823	757,017

Year ended 31 December 2009

						Contractual
	6 months	6-12	1-2	2-5	More than	undiscounted	Carrying
	or less	months	years	years	5 years	cash flows	amount
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Financial liabilities
Interest-bearing loans and borrowings	31,863	26,208	18,901	46,084	-	123,056	117,266
Trade and other payables (excluding advances from customers)	585,490	11,843	-	-	-	597,333	597,333
Due to related parties	44,496	12,830	-	-	-	57,326	57,326
Deferred consideration	1,622	-	20,519	11,356	-	33,497	29,060
Derivative instruments	907	906	-	-	-	1,813	1,813
Interest payable	22	-	-	-	-	22	22
Interest payments	816	1,148	2,094	2,291	-	6,349	-
	665,216	52,935	41,514	59,731	-	819,396	802,820

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

The group uses various funded facilities provided by banks and its own financial assets to fund the above mentioned financial liabilities.

Capital management

The group's policy is to maintain a healthy capital base to sustain future growth and maximise shareholder value.

The group seeks to optimise shareholder returns by maintaining a balance between debt and capital and monitors the efficiency of its capital structure on a regular basis. The gearing ratio and return on shareholders' equity is as follows:

	2010	2009
	US$'000	US$'000
		Restated +

Cash and short-term deposits	1,063,005	1,417,363
Interest-bearing loans and borrowings (A)	(87,661)	(117,266)
Net cash (B)	975,344	1,300,097

Equity attributable to Petrofac Limited shareholders (C)	776,462	894,710

Profit for the year attributable to Petrofac Limited shareholders (D)	557,817	353,603

Gross gearing ratio (A/C)	11.3%	13.1%
Net gearing ratio (B/C)	Net cash position	Net cash position
Shareholders' return on investment (D/C)	71.8%	39.5%

Fair values of financial assets and liabilities

The fair value of the group's financial instruments and their carrying amounts included within the group's statement of financial position are set out below:

	Carrying amount		Fair value
	2010	2009	2010	2009
	US$'000	US$'000	US$'000	US$'000
Financial assets
Cash and short-term deposits	1,063,005	1,417,363	1,063,005	1,417,363
Restricted cash	19,462	10,311	19,462	10,311
Available-for-sale financial assets	101,494	539	101,494	539
Seven Energy warrants	11,969	-	11,969	-
Forward currency contracts-designated as cash flow hedge	7,961	26,891	7,961	26,891
Forward currency contracts-undesignated	1,234	5,070	1,234	5,070

Financial liabilities
Interest-bearing loans and borrowings	87,661	117,266	87,661	117,266
Deferred consideration	35,874	30,178	35,874	30,178
Oil derivative	1,163	1,813	1,163	1,813
Forward currency contracts-designated as cash flow hedge	8,173	-	8,173	-
Forward currency contracts-undesignated	3,035	-	3,035	-

33 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

Fair values of financial assets and liabilities

Market values have been used to determine the fair values of available-for-sale financial assets, forward currency contracts and oil derivaties. Seven Energy warrant's fair value has been calculated using a Black Scholes option valuation model (note 16). The fair values of long-term interest-bearing loans and borrowings are equivalent to their amortised costs determined as the present value of discounted future cash flows using the effective interest rate. The Company considers that the carrying amounts of trade and other receivables, work-in-progress, trade and other payables, other current and non-current financial assets and liabilities approximate their fair values and are therefore excluded from the above table.

Fair value hierarchy

The following financial instruments are measured at fair value using the hierarchy below for determination and disclosure of their respective fair values:

Tier 1: Unadjusted quoted prices in active markets for identical financial assets or liabilities

Tier 2: Other valuation techniques where the inputs are based on all observation data (directly or indirectly)

Tier 3: Other valuation techniques where the inputs are based on unobservable market data

Assets measured at fair value

Year ended 31 December 2010

	Tier 1	Tier 2	2010
	US$'000	US$'000	US$'000
Financial assets
Available-for-sale financial assets	243	101,251	101,494
Seven Energy warrants	-	11,969	11,969
Forward currency contracts-designated as cash flow hedge	-	7,961	7,961
Forward currency contracts-undesignated	-	1,234	1,234

Financial liabilities
Interest-bearing loans and borrowings	-	87,661	87,661
Forward currency contracts-designated as cash flow hedge	-	8,173	8,173
Forward currency contracts-undesignated	-	3,035	3,035
Oil derivative	-	1,163	1,163

Year ended 31 December 2009

	Tier 1	Tier 2	2009
	US$'000	US$'000	US$'000
Financial assets
Available-for-sale financial assets	-	539	539
Forward currency contracts-designated as cash flow hedge	-	26,891	26,891
Forward currency contracts-undesignated	-	5,070	5,070

Financial liabilities
Interest-bearing loans and borrowings	-	117,266	117,266
Oil derivative	-	1,813	1,813

34 EVENTS AFTER THE REPORTING DATE

On 31 January 2011, Energy Developments signed a risk sharing contract (RSC) to lead the development of the Berantai field, offshore Peninsular Malaysia for Petronas, the Malaysian national oil company. Petrofac has 50% interest in the RSC alongside our two local partners who each hold a 25% interest and the joint venture will develop the field and subsequently operate it for seven years after first gas production. As part of the fast track development of the field, the group has committed as at 31 December 2010 to acquire an FPSO vessel which will be jointly owned by Berantai joint venture partners (see note 31 for details).

35 SUBSIDIARIES AND JOINT VENTURES

At 31 December 2010, the group had investments in the following subsidiaries and incorporated joint ventures:

		Proportion of nominal
		value of issued shares
Name of company	Country of incorporation	controlled by the group

Trading subsidiaries		2010	2009

Petrofac Inc.	USA	*100	*100
Petrofac International Ltd	Jersey	*100	*100
Petrofac Energy Development UK Limited	England	*100	-
Petrofac Energy Developments Limited	England	-	*100
Petrofac Energy Developments International Limited	Jersey	*100	*100
Petrofac UK Holdings Limited	England	*100	*100
Petrofac Facilities Management International Limited	Jersey	*100	*100
Petrofac Services Limited	England	*100	*100
Petrofac Services Inc.	USA	*100	*100
Petrofac Training International Limited	Jersey	*100	*100
Petroleum Facilities E & C Limited	Jersey	*100	*100
Petrofac ESOP Trustees Limited	Jersey	*100	*100
Jermyn Insurance Company Limited	Guernsey	*100	-
Atlantic Resourcing Limited	Scotland	100	100
Petrofac Algeria EURL	Algeria	100	100
Petrofac Engineering India Private Limited	India	100	100
Petrofac Engineering Services India Private Limited	India	100	100
Petrofac Engineering Limited	England	100	100
Petrofac Offshore Management Limited	Jersey	100	100
Petrofac FZE	United Arab Emirates	100	100
Petrofac Facilities Management Group Limited	Scotland	100	100
Petrofac Facilities Management Limited	Scotland	100	100
Petrofac International Nigeria Ltd	Nigeria	100	100
Petrofac Pars (PJSC)	Iran	100	100
Petrofac Iran (PJSC)	Iran	100	100
Plant Asset Management Limited	Scotland	100	100
Petrofac Nuigini Limited	Papua New Guinea	100	100
PFMAP Sendirian Berhad	Malaysia	100	100
Petrofac Caspian Limited	Azerbaijan	100	100
Petrofac (Malaysia-PM304) Limited	England	100	100
Petrofac Training Group Limited	Scotland	100	100
Petrofac Training Holdings Limited	Scotland	100	100
Petrofac Training Limited	Scotland	100	100
Petrofac Training Inc.	USA	100	100
Petrofac Training (Trinidad) Limited	Trinidad	100	100
Monsoon Shipmanagement Limited	Jersey	100	100
Petrofac E&C International Limited	United Arab Emirates	100	100
Petrofac Saudi Arabia Limited	Saudi Arabia	100	100
Petrofac Energy Developments (Ohanet) Jersey Limited	Jersey	100	100
Petrofac Energy Developments (Ohanet) LLC	USA	100	100
PEDL Limited	England	100	100
Petrofac (Cyprus) Limited	Cyprus	100	100
PKT Technical Services Ltd	Russia	**50	**50
PKT Training Services Ltd	Russia	100	100
Pt PCI Indonesia	Indonesia	80	80
Petrofac Training Institute Pte Limited	Singapore	100	100
Petrofac Training Sdn Bhd	Malaysia	100	100

* Directly held by Petrofac Limited

**Companies consolidated as subsidiaries on the basis of control.

35 SUBSIDIARIES AND JOINT VENTURES (continued)

		Proportion of nominal
		value of issued shares
Name of company	Country of incorporation	controlled by the group

Trading subsidiaries (continued)		2010	2009

Sakhalin Technical Training Centre	Russia	80	80
Petrofac Norge AS	Norway	100	100
SPD Group Limited	British Virgin Islands	51	51
SPD UK Limited	Scotland	51	51
SPD LLC	United Arab Emirates	**25	**25
Petrofac Energy Developments Oceania Limited	Cayman Islands	-	100
PT. Petrofac IKPT International	Indonesia	51	51
Petrofac Kazakhstan Limited	England	100	100
Petrofac International (UAE) LLC	United Arab Emirates	100	100
Petrofac E&C Oman LLC	Oman	100	100
Petrofac International South Africa (Pty) Limited	South Africa	100	100
Eclipse Petroleum Technology Limited	England	100	100
Eclipse Petroleum Technology Inc	United States	100	100
Caltec Limited	England	100	100
i Perform Limited	Scotland	100	100
Petrofac FPF1Limited	Jersey	100	100
Petrofac Platform Management Services Limited	Jersey	100	100
Petrokyrgyzstan Limited	Jersey	100	100
Scotvalve Services Limited	Scotland	100	-
Stephen Gillespie Consultants Limited	Scotland	100	-
CO2DeepStore Limited	Scotland	100	-
CO2DeepStore Holdings Limited	Jersey	100	-
CO2DeepStore (Aspen) Limited	England	100	-
TNEI Services Limited	England	100	-
Petrofac E&C Sdn Bhd	Malaysia	100	-
Petrofac FPSO Holding Limited	Jersey	100	-
The New Energy Industries Limited	England	100	-
Petrofac Information Services Private Limited	India	100	-
Petrofac Solutions & Facilities Support S.R.L	Romania	100	-

Joint Ventures

Costain Petrofac Limited	England	50	50
Kyrgyz Petroleum Company	Kyrgyz Republic	50	50
MJVI Sendirian Berhad	Brunei	50	50
Spie Capag - Petrofac International Limited	Jersey	50	50
TTE Petrofac Limited	Jersey	50	50
Petrofac Emirates LLC	United Arab Emirates	**49	**49

Dormant subsidiaries

Joint Venture International Limited	Scotland	100	100
Montrose Park Hotels Limited	Scotland	100	100
RGIT Ethos Health & Safety Limited	Scotland	100	100
Scota Limited	Scotland	100	100
Monsoon Shipmanagement Limited	Cyprus	100	100
Rubicon Response Limited	Scotland	100	100

**Companies consolidated as subsidiaries on the basis of control.

Petrofac Limited

OTHER FINANCIAL INFORMATION

At 31 December 2010

OIL AND GAS RESERVES (UNAUDITED)

	Europe	Africa		South East Asia		Total
	Oil & NGLs	Oil & NGLs	Gas	Oil & NGLs	Oil & NGLs	Gas	Oil equivalent
	mmbbl	mmbbl	bcf	mmbbl	mmbbl	bcf	mmboe

Proven reserves
At 1 January 2010
Developed	3.4	1.4	19.3	3.6	8.4	19.3	11.8
Undeveloped	9.7	-	0.5	-	9.7	0.5	9.7
Proven	13.1	1.4	19.8	3.6	18.1	19.8	21.5

Changes during the year:
Revisions	-	(0.1)	8.2	(0.4)	(0.5)	8.2	0.9
Additions	-	-	1.6	8.9	8.9	1.6	9.1
Divestments	(12.6)	-	-	-	(12.6)	-	(12.6)
Production	(0.5)	(0.5)	(4.6)	(1.1)	(2.1)	(4.6)	(2.8)
At 31 December 2010
Developed	-	0.8	23.4	2.1	2.9	23.4	7.0
Undeveloped	-	-	1.6	8.9	8.9	1.6	9.1
Proven	-	0.8	25.0	11.0	11.8	25.0	16.1

Probable reserves
At 1 January 2010	6.4	-	6.2	0.5	6.9	6.2	8.1

Changes during the year:
Revisions	-	-	(3.3)	0.4	0.4	(3.3)	(0.1)
Additions	-	-	1.4	0.4	0.4	1.4	0.5
Divestments	(6.4)	-	-	-	(6.4)	-	(6.4)
Production	-	-	-	-	-	-	-
At 31 December 2010	-	-	4.3	1.3	1.3	4.3	2.1

Total proven & probable reserves
At 1 January 2010	19.5	1.4	26.0	4.1	25.0	26.0	29.6

Changes during the year:
Revisions	-	(0.1)	4.9	-	(0.1)	4.9	0.8
Additions	-	-	3.0	9.3	9.3	3.0	9.6
Divestments	(19.0)	-	-	-	(19.0)	-	(19.0)
Production	(0.5)	(0.5)	(4.6)	(1.1)	(2.1)	(4.6)	(2.8)

At 31 December 2010	-	0.8	29.3	12.3	13.1	29.3	18.2

Notes

· These estimates of reserves were prepared by the group's engineers and audited by a competent, independent third party based on the guidelines of the Petroleum Resources Management System (sponsored by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers).

· The reserves presented are the net entitlement volumes attributable to the company, under the terms of relevant production sharing contracts and assuming future oil prices equivalent to US$75 per barrel (Brent).

· For the purpose of calculating oil equivalent total reserves, volumes of natural gas have been converted to oil equivalent volumes at the rate of 5,800 standard cubic feet of gas per barrel of oil.

· The Europe geographical segment contains reserves attributable to the Don Fields, which were divested from the company in April 2010.

Petrofac Limited

SHAREHOLDER INFORMATION

At 31 December 2010

Petrofac shares are traded on the London Stock Exchange using code 'PFC.L'.

Registrar
Capita Registrars (Jersey) Limited
12 Castle Street
St Helier
Jersey JE2 3RT

UK Transfer Agent	Company Secretary and registered office
Capita Registrars	Ogier Corporate Services (Jersey) Limited
The Registry	Ogier House
34 Beckenham Road	The Esplanade
Beckenham	St Helier
Kent BR3 4TU	Jersey JE4 9WG

Legal Advisers to the Company
Freshfields Bruckhaus Deringer LLP
65 Fleet Street
London EC4Y 1HS


Joint Brokers
Goldman Sachs	JP Morgan Cazenove
Peterborough Court	10 Aldermanbury
133 Fleet Street London EC4A 2BB	London EC2V 7RF

Auditors	Corporate and Financial PR
Ernst & Young LLP	Tulchan Communications Group
1 More London Place	85 Fleet Street
London SE1 2AF	London EC4Y 1AE

Financial Calendar


13 May 2011	Annual General Meeting
20 May 2011	Final dividend payment
22 August 2011	Interim results announcement
October 2011	Interim dividend payment

Dates correct at time of print, but subject to change

The group's investor relations website can be found through www.petrofac.com

This information is provided by RNS

The company news service from the London Stock Exchange

END

FR QDLBBFXFFBBB

Companies

Petrofac Ltd. (PFC)

Monday, 6th January 2025

COMPANIES COVERED:

FXPO AXL S247

Smarttech 247 jumps on full year results update and Ukrainian based Ferrexpo tops the FTSE-250, whilst Arrow Exploration puts in a shaky start despite upbeat drilling results from Colombia.

Full Archive

UK 100

Latest directors dealings

7 hours ago Tirupati Graphite
9 hours ago CMC Markets
9 hours ago Invesco Perpetual UK Smaller Companies Inv Trust
9 hours ago Pearson
9 hours ago Gran Tierra Energy Inc. (CDI)

All directors dealings today

Final Results for the Year Ended 31 December 2010

Press Release

Ends

We present below an update on each of the group's reporting segments:

Order intake in 2010 exceeded US$6.0 billion. This includes our largest ever award, of US$3.4 billion, for the second phase of our contract with Turkmengas on the South Yoloten project in Turkmenistan, as well as contracts in Qatar, Kuwait and Malaysia.

We have delivered good progress on our current portfolio of contracts including the handover or substantial completion of the following:

We were awarded the following principal contracts during the year, on which initial progress has been in line with our expectations:

Gas sweetening facilities, Qatar

Pipelines from Mina Al-Ahmadi to power stations, Kuwait

Water injection project, Kuwait

South Yoloten development, Turkmenistan

SEPAT offshore early production system, Malaysia

At 31 December, the Engineering & Construction backlog stood at a record US$9.0 billion (2009: US$6.2 billion), reflecting the high level of order intake during the year.

Sharjah Government Duty Holder contract, UAE

Laggan Tormore EPC contract, UK

Maersk Oil engineering services contract, UK

Acquisitions

Net profit increased by 34.5% to US$17.2 million (2009: US$12.8 million), again reflecting increased activity levels. Net margin on revenue excluding pass-through revenue increased to 3.3%, compared to 2.9% in 2009, driven by new higher margin contracts.

Over the year, Offshore Engineering & Operations grew its headcount from 4,100 to 4,400, mostly attributable to the staff added on new contracts, including Laggan Tormore and the Sharjah Government Duty Holder contract.

The Engineering Services, Training Services and Production Solutions business units are reported together within this segment.

Net profit was 14.8% lower at US$27.6 million (2009: US$32.4 million), principally reflecting the change in scope on the Dubai Petroleum contract. This was also the primary driver for net margin on revenue excluding pass-through revenue falling to 8.5% (2009: 10.4%).

At 31 December 2010, headcount had grown to 600 (2009: 500).

Financial reporting exchange rates

2010

2009

Average rate for the year

1.54

1.56

Year-end rate

1.56

1.62

At 31 December 2010, the group's net cash was lower at US$975.3 million (2009: US$1,300.1 million) as the net result of cash generated from operating profits before working capital and other non-current changes of US$667 million, less:

· investing activities of US$254 million, including:

o the investment of US$100 million to acquire a 15% stake in Seven Energy (12.6% on a fully diluted basis; see page 30 for details)

o capital expenditure of US$59 million in relation to Energy Developments' portfolio of assets, including US$26 million on the Don fields prior to the EnQuest demerger and US$16 million on Cendor PM304 near field development

o capital expenditure on other property, plant and equipment of US$72 million, including temporary project camp facilities, office equipment and furniture and site-based vehicles, predominantly in Engineering & Construction

· financing activities of US$201 million, including:

o payment of the 2009 final dividend and 2010 interim dividend totalling US$132 million

o repayment of interest-bearing loans and borrowings of US$32 million

o financing the purchase of treasury shares for the purpose of making awards under the group's share schemes of US$36 million

· taxes paid of US$99 million

Basis of consolidation

Interests in joint ventures

Investment in associates

Foreign currency translation

Company Secretary and registered office

Jersey JE4 9WG

Corporate and Financial PR

Companies

UK 100

Latest directors dealings