Final Results for the Year Ended 31 December 2011

RNS Number : 6429Y

Petrofac Limited

05 March 2012

 



Press Release

5 March 2012

PETROFAC LIMITED

FINAL RESULTS FOR THE YEAR ENDED 31 DECEMBER 2011

FINANCIAL HIGHLIGHTS

·     Revenue up 33% to US$5.8 billion (2010: US$4.4 billion)

·     Net profit⁽¹⁾ up 25% to US$539.4 million (2010: US$433.0⁽²⁾ million)

·     Earnings per share (diluted) up 25% to 157.13 cents (2010: 126.09⁽²⁾ cents)

·     Final dividend up 24% to 37.20 cents (23.39 pence⁽³⁾) per share (2010: 30.00 cents)

·     Backlog⁽⁴⁾ US$10.8 billion at 31 December 2011 (2010: US$11.7 billion)

·     Net cash balances at 31 December 2011 of US$1.5 billion (31 December 2010: US$1.0 billion)

Ayman Asfari, Petrofac's Group Chief Executive commented on the final results:

"I am very pleased to present another excellent set of results. 2011 has been an important year for us, with good operational performance across our portfolio of projects, the rolling out of Integrated Energy Services (IES) and positive initial progress in delivering our IES strategy.

"During the year we also set out our medium-term target of more than doubling our recurring 2010 Group earnings by 2015. The extensive pipeline of new bidding opportunities, our strong financial position together with our differentiated and competitive offering and proven track record in project execution increase our confidence in achieving that goal. In 2012, we expect to make further progress towards this ambition, with net profit expected to grow by at least 15%."

OPERATIONAL HIGHLIGHTS

ENGINEERING, CONSTRUCTION, OPERATIONS & MAINTENANCE (ECOM)

Onshore Engineering & Construction

·     Good progress on portfolio of projects, including the South Yoloten development in Turkmenistan where we have reached the progress threshold for profit recognition

·     Completed the In Salah Gas compression facilities and power generation project in Algeria and the Jihar gas plant in Syria

·     Secured new awards in 2011 in Algeria and Iraq, and the Badra project in Iraq in 2012 to date

Offshore Projects & Operations

·     Secured a number of new contracts and extensions, including US$540 million of FPF1 upgrade and Duty Holder contracts for the Greater Stella Area development in the Central North Sea

·     Record activity levels and good progress towards taking our EPC capability offshore, with high levels of activity on the SEPAT development in Malaysia, where we delivered first oil ahead of schedule, and upgrade of the FPSO Berantai in Malaysia

Engineering & Consulting Services

·     Expanded our Asia Pacific engineering hub through a collaboration agreement with a Malaysian engineering company, taking total headcount in Asia Pacific to around 1,250

·     Opened a third Indian office, in Delhi, to support growth in activity levels across the Group

·     Entered a joint venture with CPECC to provide project management and engineering services on projects for Chinese oil & gas companies in China and internationally

INTEGRATED ENERGY SERVICES (IES)

·     Secured first Risk Service Contract in Malaysia, for development of the Berantai field

·     Awarded Magallanes and Santuario Production Enhancement Contracts by PEMEX: the first time in over 70 years that production has been managed by a foreign company

·     Good progress on Ticleni field in Romania: reversed the decline for the first time in 6 years

·     Field Development Programme approved by PETRONAS to develop the third phase of Block PM304, West Desaru, with first oil expected in late 2012

·     Agreement to earn 20% interest in Greater Stella Area: first oil expected 2H 2013

·     Invested a further US$50 million in Seven Energy in Nigeria taking our interest up to 22.0%⁽⁵⁾

OUTLOOK

Our backlog gives us excellent revenue visibility for the ECOM division for 2012. Furthermore, we see a strong bidding pipeline for the ECOM division for both the current year and beyond. There are a large number of opportunities in our core markets in the Middle East, North Africa, the Commonwealth of Independent States, particularly the Caspian region, Europe and Asia Pacific. We believe that we can grow our backlog over the medium-term, notwithstanding that we still face significant competition in many of our established markets, to enable us to deliver double-digit average annual growth in revenues, while maintaining our net margins in Onshore Engineering & Construction at around 11% and incrementally growing our margins in Offshore Projects & Operations as we undertake more offshore capital projects.

In Integrated Energy Services, we are focused on ensuring that we continue to build our execution track record, with important delivery milestones throughout 2012 on our existing projects. Nonetheless, we expect to bid on new opportunities through structured bidding processes in Mexico, Romania and Malaysia, as well as through direct negotiation with a number of resource holders (both National Oil Companies and International Oil Companies). Following the signing of a co-operation agreement with Schlumberger in early 2012, which will allow us to pursue larger projects and develop at a faster pace, we have shortlisted a number of Production Enhancement opportunities to pursue jointly. We expect to deliver strong earnings growth in IES in 2012, driven by existing projects: commencement of the Mexican Production Enhancement Contracts; profit recognition on the Berantai Risk Service Contract; improving production on the Ticleni Production Enhancement Contract in Romania; and initial profit from the Ithaca transaction.

Overall, our existing portfolio of projects, the strong pipeline of new bidding opportunities for ECOM and IES, our strong financial position, our differentiated and competitive offering and our proven track record in project execution give us increasing confidence in achieving our medium-term target of more than doubling our recurring 2010 Group earnings by 2015. 2012 should see us make further progress towards that goal, with net profit expected to grow by at least 15%.

Notes

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

⁽²⁾      Excluding the gain on the EnQuest demerger in April 2010.

⁽³⁾         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 2011 final dividend from US dollars into Sterling is based upon an exchange rate of US$1.5902:£1, being the Bank of England Sterling spot rate as at midday on 2 March 2012.

⁽⁴⁾         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, operations, maintenance and Integrated Energy Services contracts, the estimated revenue attributable to the lesser of the remaining term of the contract and five years. Backlog will not be booked on Integrated Energy Services contracts where the Group has entitlement to reserves. The Group uses this key performance indicator as a measure of the visibility of future revenue. Backlog is not an audited measure.

⁽⁵⁾         On a fully diluted basis assuming the full conversion of all convertible securities and exercise of all outstanding warrants and options.

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=167517.

For further information contact:

Petrofac Limited                                                                [phone]

Jonathan Low, Head of Investor Relations

Tess Palmer, Investor Relations Manager

Tulchan Communications Group Ltd                                       [phone]

Stephen Malthouse

Martin Robinson

[e-mail]

Notes to Editors

Petrofac

Petrofac is a leading international service provider 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 two divisions: Engineering, Construction, Operations & Maintenance (ECOM - comprising Onshore Engineering & Construction, Offshore Projects & Operations and Engineering & Consulting Services) and Integrated Energy Services (IES). Through these divisions 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 more than 15,000 employees, Petrofac operates out of seven strategically located operational centres, in Aberdeen, Sharjah, Woking, Chennai, Mumbai, Abu Dhabi and Kuala Lumpur and a further 24 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 2011. Page number references refer to the full Annual Report when available.)

Operating review

Segmental analysis

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

US$millions	Revenue		Operating profit(1,2,4)		Net profit(1,3)		EBITDA(1,4)
	2011	2010	2011	2010	2011	2010	2011	2010
Onshore Engineering & Construction	4,146.2	3,253.9	553.8	438.1	462.8	373.0	584.9	471.8
Offshore Projects & Operations	1,251.4	721.9	56.9	24.5	43.5	17.2	61.4	27.3
Engineering & Consulting Services	208.2	173.4	32.9	19.8	30.8	21.1	39.7	25.6
Integrated Energy Services	518.9	384.2	53.4	73.7	22.6	38.0	89.9	127.5
Corporate, consolidation & elimination	(324.0)	(179.2)	(17.7)	(17.6)	(20.3)	(16.3)	(16.5)	(17.8)
	────────	────────	──────	──────	──────	──────	──────	──────
Group	5,800.7	4,354.2	679.3	538.5	539.4	433.0	759.4	634.4
	════════	════════	══════	══════	══════	══════	══════	══════

Growth/margin analysis %	Revenue growth		Operating margin		Net margin		EBITDA margin
	2011	2010	2011	2010	2011	2010	2011	2010
Onshore Engineering & Construction	27.4	29.7	13.4	13.5	11.2	11.5	14.1	14.5
Offshore Projects & Operations	73.3	15.2	4.5	3.4	3.5	2.4	4.9	3.8
Engineering & Consulting Services	20.0	51.8	15.8	11.4	14.8	12.2	19.1	14.7
Integrated Energy Services	35.0	(20.6)	10.3	19.2	4.4	9.9	17.3	33.2
	────────	────────	──────	──────	──────	──────	──────	──────
Group	33.2	19.1	11.7	12.4	9.3	9.9	13.1	14.6
	════════	════════	══════	══════	══════	══════	══════	══════

(1) Excludes the gain on the EnQuest demerger in 2010

(2) Profit from operations before tax and finance costs.

(3) Profit for the year attributable to Petrofac Limited shareholders.

(4) Operating profit and EBITDA includes the Group's share of losses of associates.

Engineering, Construction, Operations & Maintenance (ECOM)

Engineering, Construction, Operations & Maintenance designs and builds oil & gas facilities and operates, manages and maintains them on behalf of our customers. The division has three service lines, which report as separate financial segments.

Onshore Engineering & Construction

 

Onshore Engineering & Construction undertakes engineering, procurement and construction (EPC) projects predominantly on a lump-sum basis, with a typical duration of two to four years. Onshore Engineering & Construction is predominantly focused on markets in the Middle East and Africa and the Commonwealth of Independent States, particularly the Caspian region.

 

We have continued our good operational performance across our portfolio of projects in 2011, including the completion of the Jihar gas plant in Syria and the In Salah Gas compression facilities and power generation project in Algeria earlier in the year.

 

We are making good progress on our largest project, the South Yoloten development in Turkmenistan, having placed the majority of orders for procurement items and undertaken early construction activities. We have reached the progress threshold such that we are now recognising profit.

We have made substantial progress on the Asab oil field development and the GASCO natural gas liquids train in Abu Dhabi, the El Merk central processing facility in Algeria, the gas sweetening facilities for Qatar Petroleum and the fuel gas and gas oil pipelines project in Kuwait.

 

New awards

We were successful in securing the following awards during the year:

 

In Salah Gas southern fields, Algeria

In January 2011, we were awarded a 50-month US$1.2 billion lump-sum EPC contract by In Salah Gas, an association between Sonatrach, BP and Statoil, to develop southern fields in the In Salah development. As noted above, we successfully completed the compression facilities and power generation project for the same customer in early 2011 and we believe this new award reflects our dedication to this strategically important market where we maintain excellent relationships with both our customers and local construction partners.

 

Majnoon early production facility, Iraq

In March 2011, we announced the award of our first contract in Iraq, a US$240 million EPC management project with Shell. The Majnoon field in southern Iraq is one of Iraq's largest developments and we are delighted to be working with Shell to assist them with unlocking the field's potential. We are providing engineering, procurement, fabrication and construction management services for the development of a new early production system comprising two trains each with capacity for 50,000 barrels of oil per day, along with the upgrade of existing brownfield facilities.

We were also successful in securing the following project in early 2012:

 

Badra oilfield development project, Iraq

In February 2012, we were awarded a US$330 million lump-sum EPC contract by Gazprom for the first phase of the Badra oilfield development project. We will provide detailed design, engineering, procurement, construction, pre-commissioning, commissioning and start-up work on the Badra development's central processing facility, which comprises three crude oil processing trains.  The first phase of the project is expected to come on stream in the second half of 2013, with final completion scheduled during the second half of 2015.

 

Results

Revenue for the year increased by 27.4% to US$4,146.2 million (2010: US$3,253.9 million), reflecting a substantial increase in activity levels, particularly on the Asab oil field development in Abu Dhabi and the second phase of the South Yoloten project in Turkmenistan.

 

Net profit for the year increased by 24.1% to US$462.8 million (2010: US$373.0 million), representing a net margin of 11.2% (2010: 11.5%). The net margin is consistent with our medium-term guidance of 'around 11%'. The higher net margin in 2010 was due to the completion of a number of projects during 2010 and the first-time recognition of profit on a number of contracts awarded in 2009.

Onshore Engineering & Construction headcount increased from 5,400 to 6,600 over the year, reflecting the increase in activity levels.

 

Onshore Engineering & Construction backlog stood at US$6.4 billion at 31 December 2011 (2010: US$9.0 billion).

Offshore Projects & Operations

Offshore Projects & 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. The majority of Offshore Projects & Operations' activities are in the UK Continental Shelf (UKCS), but a growing proportion of activities are outside of the UK, including in the United Arab Emirates, Iraq, Malaysia and Thailand. Services are predominantly provided on a reimbursable basis, but often with incentive income linked to the successful delivery of performance targets. Many of our production and maintenance contracts are long-term (typically three to five years) and in the case of the provision of Duty Holder services⁽⁵⁾ are generally open-ended. Increasingly, we are delivering our engineering and construction services on a lump-sum basis on offshore capital projects, as we progress our strategy of taking our onshore EPC capability offshore.

 

2011 saw record activity levels across the business from both long-term operations management contracts and offshore capital projects, such as the SEPAT development and the upgrade and life extension works on the FPSO Berantai, both in Malaysia (both projects are being undertaken jointly with Onshore Engineering & Construction). As at the end of 2011, we had substantially completed the SEPAT development for PETRONAS, delivering first oil ahead of schedule. We have also made good progress on the awards secured in the second half of 2010, including the Duty Holder contract for the Sajaa gas plant in the UAE and the Laggan-Tormore gas plant on Shetland Island in the UK.

New awards

We secured a number of contract extensions and new awards in 2011, including:

·     modification and upgrade works to the FPF1 floating production facility ahead of its deployment on the Greater Stella Area development in the Central North Sea and subsequently the provision of Duty Holder services to the FPF1 on a life of field contract(see the Integrated Energy Services section); in accordance with our standard accounting policy, we have booked the initial five years' of estimated contract revenues into backlog in relation to the upgrade and Duty Holder contracts, which equates to US$540 million

·     a US$63 million one-year contract to provide maintenance services on the Rumaila oilfield in Iraq for BP

·     two North Sea operations, maintenance, engineering and general support services contracts for GDF SUEZ worth £30 million over three years, with an additional two- year option

·     an operations contract for the FPF3 floating, production, storage and offloading (FPSO) vessel (formerly the Jasmine Venture) in Thailand (see the Integrated Energy Services section)

·     a four-year extension on our engineering, construction, operations and maintenance services contract with Marathon on its North Sea Brae assets; the base scope is valued at £36 million, although this does not include the value of any future projects which may be sanctioned

·     a two year extension to our Duty Holder contract with Centrica

 

 

⁽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 Department of Energy and Climate Change.

Results

Reported revenue for the year increased by 73.3% to US$1,251.4 million (2010: US$721.9 million), reflecting record activity levels across the business, particularly on the SEPAT development and the FPSO Berantai upgrade, the Sajaa gas plant Duty Holder contract, the Laggan-Tormore gas plant and the Apache UKCS engineering and construction contract. Around two-thirds of Offshore Projects & Operations' revenue was generated in the UKCS and those revenues are generally denominated in Sterling. The average US dollar to Sterling exchange rate for 2011 was around 4% higher than in 2010, which made a marginal contribution to the reported revenue growth.

 

Financial reporting exchange rates US$/Sterling	Year ended 31 December 2011	Year ended 31 December 2010
Average rate for year	1.60	1.54
Year-end rate	1.55	1.56

 

Net profit increased by 152.7% to US$43.5 million (2010: US$17.2 million), reflecting the significant increase in activity levels, particularly from the SEPAT development and the FPSO Berantai, and a provision release in the first half of the year following completion of a long-term maintenance services contract.

Net margin increased to 3.5% (2010: 2.4%), reflecting the provision release on the long-term maintenance services contract, and a significant contribution from capital projects, in particular the SEPAT development and the FPSO Berantai projects.

At 31 December 2011, headcount stood at 4,100 (December 2010: 4,400) as the increase in headcount due to new projects was more than offset by the completion of the long-term maintenance services contract.

 

Offshore Projects & Operations backlog increased to US$2.7 billion at 31 December 2011 (2010: US$2.4 billion).

Engineering & Consulting Services

Engineering & Consulting Services operates as our centre of technical engineering excellence providing high-calibre engineering resources and technical assurance services across onshore and offshore oil & gas projects. Engineering & Consulting Services provides early stage engineering studies, including conceptual studies and FEED studies, to external customers and in support of ECOM and IES projects, primarily on a reimbursable basis.

 

Building on the success of our offices in Mumbai and Chennai, we opened our third Indian engineering office, in Delhi, earlier in 2011, taking our total headcount for our Indian engineering offices to around 1,700. We have also continued to grow our presence in Asia Pacific, establishing a new engineering hub in Malaysia with the recent signing of a collaboration agreement with a Malaysian engineering company, which takes our total headcount in Malaysia to around 1,000. We have a further 250 employees in Asia Pacific, through our joint venture with IKPT, in Indonesia.

 

In September 2011, we entered into a strategic joint venture with China Petroleum Engineering & Construction Corporation (CPECC). Operationally based in Sharjah, the joint venture will provide project management and engineering services on projects for Chinese oil & gas companies in China and internationally.

 

Activity levels at our Indian offices were higher in 2011, reflecting an increase in work for Onshore Engineering & Construction, which the offices predominantly support. At our Woking office in the UK, activity levels were also higher, with support given to a number of ECOM and IES projects, as well as work for external customers.

 

Results

Reported revenue for the year increased 20.0% to US$208.2 million (2010: US$173.4 million), predominantly reflecting strong growth in revenues from our Indian offices as a result of higher activity levels to support Onshore Engineering & Construction. Net profit increased by 45.7% to US$30.8 million (2010: US$21.1 million), reflecting higher activity levels in our Indian offices and improved profitability from our Woking office.

Headcount increased to 2,300 at 31 December 2011 (2010: 2,000), partly due to the opening of our third Indian office in Delhi. From early 2012, we will also include around a further 500 personnel in our headcount reporting through our collaboration agreement with a Malaysian engineering company.

Integrated Energy Services

Integrated Energy Services comprises three discrete but integrated service lines, Developments, Production Solutions and Training Services. Where we can leverage our service capabilities to enhance value, mitigate risks and reduce costs, Integrated Energy Services provides a fully integrated service offering 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 financial capital in addition to our intellectual capital. Our service offering is underpinned by the ability to develop resource holders' local capability through the provision of technical skills training programmes and competency development and assurance frameworks

Integrated Energy Services was formally launched as a new division at a Capital Markets Day held in June 2011.We believe that the scale of the opportunity for Integrated Energy Services is significant and that our service offering responds directly to the needs of resource holders. Petrofac has been on a journey for more than ten years to add competence beyond our core engineering & construction capability, and it is the resulting scope and depth of our service capability that now positions us to offer a differentiated and integrated solution to the marketplace.

Integrated Energy Services deploys its services to meet the individual needs of customers using different commercial frameworks: Risk Service Contracts (RSC), Production Enhancement Contracts (PEC), and traditional upstream equity investment models including both Production Sharing Contracts (PSC) and royalty concessions. During 2011 we were awarded examples of each, on which initial progress is discussed below: the Berantai field in Malaysia (RSC), the Magallanes and Santuario blocks in Mexico (PECs), and the Greater Stella Area development in the United Kingdom (equity investment). In addition, we announced a Co-operation Agreement with Schlumberger Production Management in January 2012, under which the two divisions will work together to deliver integrated and high-value production projects in the emerging and growing production services and production enhancement market.

Within our Training Services business, delegate numbers were higher than in 2010, and we saw the strongest growth in our UK facilities, including the Altens and Marine Training Centres in Aberdeen, and in the Americas. In November 2011, we entered into a strategic partnership with Raytheon Company to deliver water survival training to the oil & gas industry at NASA's Johnson Space Center underwater facility in Houston.

Training Services is a key component of our integrated offer. Through a well constructed training and competence development programme, our customers can attain global standards with local capability. This was the driving force behind the memorandum of understanding (MOU) we signed with PETRONAS in July 2011, to collaborate in the areas of competency development, capability building and education activities. Already in 2012 we have signed a five year deal with Saudi Petroleum Services Polytechnic to deliver a construction and drilling training curriculum into Saudi Aramco and its supply chain.

In Nigeria, our personnel continue to assist Seven Energy with its asset development both at the operational level and through representation on Seven Energy's Board and management committees. As at 31 December 2011, 80% of our warrants had vested after reaching agreed milestones. Earlier in the year, we invested a further US$50 million in the company, taking our interest up to 22.0%⁽⁶⁾. Since entering into the strategic alliance with Seven Energy in November 2010 we have gained significant knowledge which will be crucial in addressing the growing opportunity set in Nigeria and establishing an independent local presence in-country.

⁽⁶⁾ On a fully diluted basis assuming the full conversion of all convertible securities and exercise of all outstanding warrants and options.

During the year, we made good progress on Integrated Energy Services' portfolio of assets, both operational and in development. An update on our key projects is provided below:

Ticleni fields, Romania

We are continuing to make good progress on the Ticleni oilfield and its eight satellite fields, in Romania. Ticleni represents our first PEC, and 2011 was the first full year of Petrofac operation after we secured the award in July 2010, and took over full operatorship in November of that year. The fields' production decline was halted and reversed during 2011, with year-on-year 2011 oil production exceeding 2010 oil production from the fields. Overall production averaged approximately 3,500 bpd of oil equivalent in 2011 (of which 93% was oil production and 7% gas production).

The pilot water flood programme is now underway and the initial results are expected during 2012. This programme involves the drilling of one new well and the injection of water into three existing wells. In addition to this pilot programme, key work items for the boosting of production have commenced and will be progressed in 2012. These include a multi-well drilling programme, the working over and/or maintenance of currently producing wells, the reactivation of shut-in wells, and a project to achieve automated measurement on high production wells.

Magallanes and Santuario blocks, Mexico

In October 2011, we were awarded two Production Enhancement Contracts by Petroleos Mexicanos ('PEMEX') to develop the Magallanes and Santuario blocks in central Mexico. Under the terms of the 25-year contracts, we will provide a fully integrated solution to increase production through the reactivation and development of both blocks as well as managing their ongoing operation and maintenance.

We have committed to an investment of approximately US$500 million for a 90% interest in the contract to develop the blocks, while a subsidiary of PEMEX will retain a 10% economic interest in the contract. Petrofac will be reimbursed for 75% of its operational and development expenditure through a cost recovery mechanism and will receive tariffs for each barrel of baseline and incremental production. Petrofac successfully completed the transition and assumed operational responsibility for these blocks on 1 February 2012.

Berantai field, Malaysia

In January 2011, we secured our first RSC in Malaysia, to lead the development of the Berantai field, offshore Peninsular Malaysia, for PETRONAS. We have a 50% interest in the RSC, alongside local partners Kencana and Sapura, both of whom hold a 25% interest (together known as the 'Berantai partners').

Under the terms of the RSC, the Berantai partners will 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.

The Berantai partners are in the process of developing the field and will subsequently operate the field for a period of seven years after first gas production. As part of the fast-track development, a wellhead platform has been installed to support the drilling of 18 wells, with the drilling programme progressing well. The conversion and upgrade of the FPSO Berantai is being undertaken by Onshore Engineering & Construction and Offshore Projects & Operations and is in its final stages of upgrade in Singapore. The FPSO Berantai is expected to mobilise to the Berantai field during the second quarter of 2012, and we expect to achieve first gas from the field shortly thereafter. A second wellhead platform is expected to be installed in a subsequent phase, with both platforms being connected to the FPSO Berantai by subsea flowlines. Gas will be exported by subsea pipeline via a nearby host platform, and critical tie-in works were completed in late 2011.

Ohanet project, Algeria

Overall production was lower than in 2010, averaging approximately 90,000 bpd of oil equivalent for the first ten months of the year (2010: 113,000 bpd of oil equivalent). On average, we earned our share of the monthly liquids production by the 11th day of the month (2010: 11th), with the lower production rates offsetting the higher average oil & gas prices.The RSC expired at the end of October 2011, as expected, eight years from first gas, over which time we earned our defined return.

Block PM304, Malaysia

As anticipated, and reported in the first half, oil production from the first phase of Cendor was lower in 2011 at 10,000 bpd (2010: 13,300 bpd), despite achieving production uptime of over 98%. Production is now in decline as a result of the natural decrease in field pressure. Gas lift facilities were installed in the fourth quarter of 2011, which are now operational, in order to stabilise production in 2012.

The Field Development Programme (FDP) for the third phase of development of Block PM304 (West Desaru) was approved by PETRONAS in February 2012. We intend to accelerate the development of this fault block by introducing an Early Production System which will deploy the upgraded FPF5 Mobile Offshore Production Unit (MOPU) (formerly the Ocean Legend which we purchased in September 2011), initially exporting stabilised crude oil through existing facilities, and ultimately through the phase two FPSO after its arrival in the Cendor field. First oil is currently planned for the fourth quarter of 2012.

Work is progressing on the second phase of development of Block PM304 which will involve a larger permanent facility to develop fully the Cendor fault block. The facilities comprise two fixed wellhead structures tied back to a Floating Production, Storage and Offloading (FPSO) vessel. We are on schedule to meet the 2012 installation work programme for the wellhead structures and pipelines. First oil is currently planned for the second quarter of 2013, and will bring the overall production capacity of Block PM304 to around 60,000 barrels per day.

Total proven and probable reserves on Block PM304 (Petrofac net entitlement) increased to 17.5 million barrels of oil equivalent as at 31 December 2011, following the inclusion of 5.9 million barrels relating to West Desaru (2010: 12.3 million barrels).

Chergui field, Tunisia

The Chergui gas plant performed strongly, with an average of 28.2 million standard cubic feet per day (mmscfd) of gas sold during the year (2010: 27.8mmscfd). This was despite the impact of several short shut-ins that occurred during the periods of political unrest early in 2011.The increase in production was underpinned by better reservoir performance and pressure support, and operating efficiency gains, as well as the performance of the third well which was tied back to the plant in mid 2010.

The development programme for 2012 includes drilling two to three wells to access additional reserves and to further appraise the concession area.

Total proven and probable reserves on the Chergui field (Petrofac net entitlement) was 4.6 million barrels of oil equivalent as at 31 December 2011 (2010: 5.4 million barrels of oil equivalent).

Greater Stella Area development, UK

In October 2011, we signed an agreement that will see the deployment of the floating production facility FPF1 ('the FPF1') on the Greater Stella Area development in the North Sea. Following the FDP submission in early 2012, we will finalise the sale of 80% of the share capital in the company holding the FPF1 to Ithaca Energy Inc ('Ithaca'), and Dyas BV, which will result in the recognition of a sale profit in 2012.

Offshore Projects & Operations will carry out modification and upgrade works to the FPF1 ahead of its deployment on the Greater Stella Area development, and will subsequently provide Duty Holder services to the FPF1 on a life of field contract.

We will acquire a 20% interest from the other co-venturers in the development, consisting of three UKCS licences. The capital budget for the full field development, including delivery of the FPF1, is approximately US$1 billion, of which our share is 20%.

FPF3 - Jasmine field, Thailand

In June 2011, we acquired the FPF3 (formerly the Jasmine Venture) from field operator Pearl Energy. This vessel is currently deployed on the Jasmine field in the Gulf of Thailand, and will be leased to Pearl Energy, a subsidiary of Mubadala Energy, for a minimum term of three years, with options to extend for a further three years. The transaction reflects our strong ongoing relationship with Mubadala, our partner in the Petrofac Emirates joint venture.

We are also providing operations and maintenance services for the FPF3 through Offshore Projects & Operations. As both owner of the FPSO and its service provider, we can support Pearl Energy's current requirements, while working with them to identify potential areas for further support on this and future projects in the Gulf of Thailand.

Results

Integrated Energy Services' revenue increased by 35.0% to US$518.9 million (2010: US$384.2 million), primarily reflecting the significant progress made on the Berantai RSC as well as the contribution from the Ticleni PEC.

Net profit for the year was lower at US$22.6 million in 2011 (2010: US$38.0 million), principally reflecting the loss of contribution from Dubai Petroleum as a result of the transition of our role in 2010 from service operator to a technical services agreement (now accounted for in Offshore Projects & Operations), lower production on Cendor and the demerger of the Don assets in April 2010. These factors were partially offset by the higher average oil price in 2011⁽⁷⁾ alongside profit contribution in relation to the vesting of Seven Energy warrants and the lease of the FPF3 FPSO in Thailand.

At 31 December 2011, headcount had grown to 2,300 (2010: 2,000), reflecting the increase in activity levels.

Integrated Energy Services' backlog stood at US$1.6 billion at 31 December 2011 (2010: US$0.3 billion).

⁽⁷⁾ For example, Brent, a benchmark crude oil, averaged US$111 per barrelfor 2011 (2010: US$80 per barrel).

Financial review⁽⁸⁾

Revenue

Group revenue increased by 33.2% to US$5,800.7 million (2010: US$4,354.2 million) due to strong growth in all four reporting segments. The strong growth in the Onshore Engineering & Construction reporting segment (up 27.4%), which accounted over two-thirds of the Group's revenue, was a result of high levels of activity on lump-sum EPC contracts, particularly on the Asab oil field development in Abu Dhabi and the South Yoloten project in Turkmenistan. The increase in revenues in Offshore Projects & Operations (up 73.3%) was a result of record activity levels across the business, particularly from offshore capital projects. The growth in Engineering & Consulting Services (up 20.0%) reflects strong growth in revenue from our Indian offices as a result of higher activity levels to support Onshore Engineering & Construction. Integrated Energy Services revenues grew by 35.0%, predominantly due to the commencement of the Berantai Risk Service Contract in Malaysia.

Operating profit⁽⁹⁾

Group operating profit for the year increased 26.2% to US$679.3 million (2010: US$538.5 million), representing an operating margin of 11.7% (2010: 12.4%). The decrease in operating margin was due to disproportionately strong growth in the lower margin Offshore Projects & Operations reporting segment.

Net profit

Reported profit for the year attributable to Petrofac Limited shareholders increased 24.6% to US$539.4 million (2010: US$433.0 million). The increase was driven predominantly by Onshore Engineering & Construction and Offshore Projects & Operations due to strong growth in revenue and profits in these reporting segments as a result of record levels of activity. The net margin for the Group was lower at 9.3% (2010: 9.9%), due to slightly lower net margins in Onshore Engineering & Construction and disproportionately strong growth in the lower margin Offshore Projects & Operations reporting segment (albeit that reporting segment achieved a significant improvement in net margin from 2.4% to 3.5%). Onshore Engineering & Construction net margins were unusually high in 2010 due to the completion of a number of projects in 2010 and first-time profit recognition on a number of projects awarded in 2009. The Offshore Projects & Operations reporting segment earns lower net margins as services are predominantly provided on a reimbursable basis.

Earnings Before Interest, Tax, Depreciation and Amortisation (EBITDA)⁽⁹⁾

EBITDA increased 19.7% to US$759.4 million (2010: US$634.4 million), representing an EBITDA margin of 13.1% (2010: 14.6%). EBITDA margins were lower in Onshore Engineering & Construction at 14.1% (2010: 14.5%) for the same reasons that net margins were lower (see above). The EBITDA margin for Offshore Projects& Operations increased from 3.8% to 4.9%, however, the strong growth in this relatively lower margin reporting segment resulted in lowering the average EBITDA margin for the Group. EBITDA margin was lower in the relatively higher margin Integrated Energy Services reporting segment at 17.3% (2010: 33.2%), primarily due to revenues from the Berantai RSC, where we have not yet recognised profit. Integrated Energy Services results also decreased as a proportion of the Group's EBITDA (from 20.1% in 2010 to 11.8% in 2011). The EBITDA contribution from Engineering & Consulting Services increased by more than 50% (from US$25.6 million to US$39.7 million), due to an increase in EBITDA margin from 14.7% to 19.1% and strong growth in activity levels.

⁽⁸⁾ For the purposes of the Financial Review, references to prior year comparative figures, and growth rates and margins calculated thereon, exclude the gain from the EnQuest demerger in April 2010.

⁽⁹⁾ Including our share of losses from associates.

Backlog

The Group's backlog stood at US$10.8 billion at 31 December 2011 (2010: US$11.7 billion). An increase in backlog from new Integrated Energy Services projects was more than offset by a net reduction in Onshore Engineering & Construction due to high levels of progress across its portfolio of projects.

Exchange rates

The Group's reporting currency is US dollars. A significant proportion of Offshore Projects & Operations' revenue is generated in the UKCS (approximately two-thirds) 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 2011 and 2010 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	2011	2010
Average rate for the year	1.60	1.54
Year-end rate	1.55	1.56

Interest

Net finance income for the year was lower at US$1.3 million (2010: US$5.1 million), due to lower finance income. While net cash balances were higher on average in 2011 compared with the prior year, finance income was lower as a larger proportion of deposits were held in US dollars, which attracted lower interest rates.

Taxation

Our policy in respect of tax is to:

·     operate in accordance with the terms of the Petrofac Code of Business Conduct

·     act with integrity in all tax matters

·     work together with the tax authorities in jurisdictions that we operate in to build positive long-term relationships

·     where disputes occur, to address them promptly

·     manage tax in a pro-active manner to maximise value for our customers and shareholders

Responsibility for the tax policy and management of tax risk rests with the Chief Financial Officer and Group Head of Tax who report the Group's tax position regularly to the Group Audit Committee. The Group's tax affairs and the management of tax risk are delegated to a global team of tax professionals.

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 marginally higher at 20.7% (2010: 20.3%). The effective tax rate for the Group's largest reporting segment, Onshore Engineering & Construction, was marginally higher at 17.4% (2010: 16.7%). The effective tax rate for Offshore Projects & Operations was lower at 22.1% (2010: 27.5%) due to a larger proportion of profits coming from outside the UK; however, the strong growth in Offshore Projects & Operations resulted in it contributing a greater proportion of the Group's income tax expense (8.7% compared to 5.9% in 2010). The Integrated Energy Services effective tax rate increased from 46.2% to 55.3%; however, the relative contribution from Integrated Energy Services fell (from 29.6% to 19.8%) due to lower profitability. The effective tax rate for Engineering & Consulting Services was 6.6% after reporting an effective a tax credit in 2010 (2010: 6.1% credit).

Earnings per share

Fully diluted earnings per share increased to 157.13 cents per share (2010: 126.09 cents), an increase of 24.6%, in line with the Group's increase in profit for the year attributable to Petrofac Limited shareholders.

Operating cash flow and liquidity

The net cash generated from operations was US$1,423.0 million (2010: US$207.3 million), representing 187.4% of EBITDA (2010: 32.7% of EBITDA excluding the gain on the EnQuest demerger).

The increase in net cash generated from operations was due to the cash generated from operating profits before working capital and other non-current changes of US$796 million (2010: US$667 million) and net working capital inflows of US$758 million (2010: US$451 million outflow), partially offset by a long-term receivable of US$130 million from the Berantai RSC which commenced in January 2011.

The main net working capital inflows included an increase in trade and other payables of US$735 million (2010: US$168 million) due to an increase in advances received from customers of US$358 million, an increase in billings in excess of cost of US$211 million (2010: US$283 million decrease), a reduction in work in progress of US$192 million (2010: US$470 million increase), partially offset by an increase in trade receivables and other receivables of US$301 million (2010: US$267 million).

The other key movements in cash included:

·     investing activities totalled US$522 million (2010: US$254 million), including:

o  capital expenditure on Integrated Energy Services projects of US$352 million, predominantly in relation to the acquisition and upgrade of supporting infrastructure

o  other capital expenditure of US$108 million, including temporary project camp facilities, office equipment and furniture and site-based vehicles

o  investment of a further US$50 million (of an agreed US$75 million) in Seven Energy (see note 14 to the financial statements for details)

o  US$16 million for deferred consideration in relation to acquisitions

·     financing activities of US$228 million (2010: US$201 million), including:

o  payment of the 2010 final dividend and 2011 interim dividend totalling US$159 million

o  repayment of interest-bearing loans and borrowings of US$19 million

o  financing the purchase of treasury shares for the purpose of making awards under the Group's share schemes of US$49 million

·     net income taxes paid of US$157 million (2010: US$99 million)

The net result of the above was the Group's net cash increased to US$1,495.2 million at 31 December 2011 (2010: US$975.3 million).

The Group reduced its levels of interest-bearing loans and borrowings to US$77.2 million (2010: US$87.7 million) following scheduled loan repayments in 2011, contributing to the decrease in the Group's gross gearing ratio to 6.9% (2010: 11.3%).

Gearing ratio	2011	2010
	US$ millions (unless otherwise stated)
Interest-bearing loans and borrowings (A)	77.2	87.7
Cash and short term deposits (B)	1,572.3	1,063.0
Net cash/(debt) (C = B - A)	1,495.2	975.3
Total equity (D)	1,113.8	779.1
Gross gearing ratio (A/D)	6.9%	11.3%
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 2011 were US$80.3 million (2010: US$91.8 million), of which 39.0% was denominated in US dollars (2010: 39.5%) and 60.7% was denominated in sterling (2010: 60.5%).

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 totalled US$435.4 million in the year ended 31 December 2011(2010: US$116.2 million). The principal elements of capital expenditure during the year were:

·     capital expenditure on Integrated Energy Services projects of US$312 million, predominantly in relation to the acquisition and upgrade of supporting infrastructure

·     other capital expenditure of US$123 million, including temporary project camp facilities, office equipment and furniture and site-based vehicles

 

Capital expenditure on intangible oil & gas assets during the year was US$39.7 million (2010: US$15.6 million) in respect of capitalised expenditure, including near field appraisal wells, in relation to Integrated Energy Services' interest in Block PM304, offshore Malaysia.

Total equity

Total equity at 31 December 2011 was US$1,113.8 million (2010: US$779.1 million). The main elements of the net movement were: net profit for the year of US$539.6 million, less dividends paid in the year of US$161.0 million and the purchase of treasury shares of US$49.1 million, which are held in the Petrofac Employees Benefit Trust for the purpose of making awards under the Group's share schemes (see note 25 to the financial statements).

Return on capital employed

The Group's return on capital employed for the year ended 31 December 2011 was 62.1% (2010: 53.0%).

Dividends

The Company proposes a final dividend of 37.20 cents per share for the year ended 31 December 2011 (2010: 30.00 cents), which, if approved, will be paid to shareholders on 18 May 2012 provided they were on the register on 20 April 2012. Shareholders who have not elected (before 2 March 2012) to receive dividends in US dollars will receive a sterling equivalent of 23.39 pence per share.

Together with the interim dividend of 17.40 cents per share (2010: 13.80 cents), equivalent to 10.54 pence, this gives a total dividend for the year of 54.60 cents per share (2010: 43.80 cents), an increase of 24.7%, in line with the increase in net profit.

Directors' statements

Directors' responsibilities

The Directors are responsible for preparing the annual report and the financial statements in accordance with applicable law and regulations. The Directors have chosen to prepare the financial statements in accordance with International Financial Reporting Standards (IFRS). The Directors are also responsible for the preparation of the Directors' remuneration report, which they have chosen to prepare, being under no obligation to do so under Jersey law. The Directors are also responsible for the preparation of the corporate governance report under the Listing Rules.

Jersey Company law (the 'Law') requires the Directors to prepare financial statements for each financial period in accordance with generally accepted accounting principles. The financial statements are required by law to give a true and fair view of the state of affairs of the Company at the period end and the profit or loss of the Company for the period then ended. In preparing these financial statements, the Directors should:

·     select suitable accounting policies and then apply them consistently

·     make judgements and estimates that are reasonable and prudent

·     specify which generally accepted accounting principles have been adopted in their preparation

·     prepare the financial statements on a going concern basis unless it is inappropriate to presume that the Company will continue in business

The Directors are responsible for keeping proper accounting records which are sufficient to show and explain the Company's transactions and as such as to disclose with reasonable accuracy at any time the financial position of the Company and enable them to ensure that the financial statements prepared by the Company comply with the Law. They are also responsible for safeguarding the assets of the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company's website. Legislation in Jersey governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

 

Directors' approach

The Board's objective is to present a balanced and understandable assessment of the Company's position and prospects, particularly in the annual report, half year report (formerly the interim report) and other published documents and reports to regulators. The Board has established an Audit Committee to assist with this obligation.

 

Going concern

The Company's business activities, together with the factors likely to affect its future development, performance and position are set out in the business review on pages 22 to 40. The financial position of the Company, its cash flows, liquidity position and borrowing facilities are described in the financial review on pages 44 to 46. In addition, note 34 to the financial statements include the Company's objectives, policies and processes for managing its capital; its financial risk management objectives; details of its financial instruments and hedging activities; and its exposures to credit risk and liquidity risk.

The Company has considerable financial resources together with long-term contracts with a number of customers and suppliers across different geographic areas and industries. As a consequence, the Directors believe that the Company is well placed to manage its business risks successfully despite the current uncertain economic outlook.

The Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

 

Responsibility statement under the Disclosure and Transparency Rules

Each of the Directors listed on pages 66 and 67 confirm that to the best of their knowledge: the financial statements, prepared in accordance with IFRS, give a true and fair view of the assets, liabilities, financial position and profit of the Company and the undertakings included in the consolidation taken as a whole; and the operating and financial review includes a fair view of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face.

By order of the Board

Tim Weller

Chief Financial Officer

Consolidated income statement

For the year ended 31 December 2011

	Notes	2011  US$'000	2010 US$'000
Revenue	4a	5,800,719	4,354,217
Cost of sales	4b	(4,840,943)	(3,595,142)
Gross profit		959,776	759,075
Selling, general and administration expenses	4c	(283,392)	(221,449)
Gain on EnQuest demerger	11	-	124,864
Other income	4f	11,600	5,013
Other expenses	4g	(5,104)	(4,053)
Profit from operations before tax and finance income/(costs)		682,880	663,450
Finance costs	5	(6,599)	(5,131)
Finance income	5	7,877	10,209
Share of losses of associates	14	(3,593)	(131)
Profit before tax		680,565	668,397
Income tax expense	6	(140,984)	(110,545)
Profit for the year		539,581	557,852
Attributable to:
Petrofac Limited shareholders		539,425	557,817
Non-controlling interests		156	35
		539,581	557,852
Earnings per share (US cents)	7
- Basic (excluding gain on EnQuest demerger)		159.01	127.76
- Diluted (excluding gain on EnQuest demerger)		157.13	126.09
- Basic (including gain on EnQuest demerger)		159.01	164.61
- Diluted (including gain on EnQuest demerger)		157.13	162.46

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

Consolidated statement of comprehensive income

For the year ended 31 December 2011

	Notes	2011 US$'000	2010 US$'000
Profit for the year		539,581	557,852
Foreign currency translation	26	(15,927)	(908)
Foreign currency translation recycled to income statement in the year on EnQuest demerger	26	-	45,818
Net loss on maturity of cash flow hedges recycled in the period	26	(3,675)	(16,612)
Net changes in fair value of derivatives and financial assets designated as cash flow hedges	26	(13,590)	(18,958)
Net changes in the fair value of available-for-sale financial assets	26	-	70
Disposal of available-for-sale financial assets	26	(70)	(74)
Other comprehensive income		(33,262)	9,336
Total comprehensive income for the period		506,319	567,188
Attributable to:
Petrofac Limited shareholders		506,163	567,153
Non-controlling interests		156	35
		506,319	567,188

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

Consolidated statement of financial position

At 31 December 2011

	Notes	2011 US$'000	2010 US$'000
Assets Non-current assets
Property, plant and equipment	9	593,737	287,158
Goodwill	12	106,681	105,832
Intangible assets	13	121,821	85,837
Investments in associates	14	164,405	16,349
Available-for-sale financial assets	16	-	101,494
Other financial assets	17	140,109	2,223
Deferred income tax assets	6c	29,142	26,301
		1,155,895	625,194
Current assets
Non-current asset held for sale	18	44,330	-
Inventories	19	10,529	7,202
Work in progress	20	612,009	803,986
Trade and other receivables	21	1,353,042	1,056,759
Due from related parties	33	99,075	327
Other financial assets	17	29,634	42,350
Income tax receivable		15,364	2,525
Cash and short-term deposits	22	1,572,338	1,063,005
		3,736,321	2,976,154
Total assets		4,892,216	3,601,348
Equity and liabilities Equity attributable to Petrofac Limited shareholders
Share capital	23	6,916	6,914
Share premium		2,211	992
Capital redemption reserve		10,881	10,881
Shares to be issued		-	994
Treasury shares	24	(75,686)	(65,317)
Other reserves	26	5,638	34,728
Retained earnings		1,160,776	787,270
		1,110,736	776,462
Non-controlling interests		3,092	2,592
Total equity		1,113,828	779,054
Non-current liabilities
Interest-bearing loans and borrowings	27	16,450	40,226
Provisions	28	59,561	45,441
Other financial liabilities	29	23,542	11,453
Deferred income tax liabilities	6c	59,605	48,086
		159,158	145,206
Current liabilities
Trade and other payables	30	1,744,182	1,021,436
Due to related parties	33	23,166	11,710
Interest-bearing loans and borrowings	27	60,711	47,435
Other financial liabilities	29	31,677	37,054
Liabilities directly associated with non-current asset held for sale	18	5,150	-
Income tax payable		96,122	105,559
Billings in excess of cost and estimated earnings	20	389,404	178,429
Accrued contract expenses	31	1,268,818	1,275,465
		3,619,230	2,677,088
Total liabilities		3,778,388	2,822,294
Total equity and liabilities		4,892,216	3,601,348

The financial statements on pages 109 to 152 were approved by the Board of Directors on 2 March 2012 and signed on its behalf by Tim Weller - Chief Financial Officer.

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

Consolidated statement of cash flows

For the year ended 31 December 2011

	Notes	2011 US$'000	2010 US$'000
Operating activities
Profit before tax		680,565	668,397
Gain on EnQuest demerger		-	(124,864)
		680,565	543,533
Non-cash adjustments to reconcile profit before tax to net cash flows:    Depreciation, amortisation, impairment and write off	4b, 4c	80,088	95,903
Share-based payments	4d	23,056	14,784
Difference between other long-term employment benefits paid and      amounts recognised in the income statement		9,450	6,074
Net finance income	5	(1,278)	(5,078)
(Gain)/loss on disposal of property, plant and equipment	4b, 4f, 4g	(34)	315
Gain on fair value changes in Seven Energy warrants	4f	(5,647)	-
Gain on disposal of intangible assets	4f	-	(2,338)
Share of losses of associates	14	3,593	131
Other non-cash items, net		5,865	13,188
		795,658	666,512
Working capital adjustments:    Trade and other receivables		(300,567)	(266,757)
Work in progress		191,977	(470,288)
Due from related parties		(98,748)	17,933
Inventories		(3,327)	(2,982)
Other current financial assets		17,142	(12,661)
Trade and other payables		735,124	167,707
Billings in excess of cost and estimated earnings		210,975	(282,715)
Accrued contract expenses		(6,647)	438,809
Due to related parties		11,456	(45,616)
Other current financial liabilities		324	6,045
		1,553,367	215,987
Long-term receivable from a customer	17	(130,206)	-
Other non-current items, net		(196)	(8,720)
Cash generated from operations		1,422,965	207,267
Interest paid		(3,156)	(1,948)
Income taxes paid, net		(156,848)	(99,030)
Net cash flows from operating activities		1,262,961	106,289
Investing activities
Purchase of property, plant and equipment		(420,360)	(115,345)
Acquisition of subsidiaries, net of cash acquired	10	-	(15,110)
Payment of deferred consideration on acquisition		(15,969)	-
Purchase of other intangible assets	13	(5,722)	(153)
Purchase of intangible oil & gas assets	13	(39,728)	(15,644)
Cash outflow on EnQuest demerger (including transaction costs)		-	(17,783)
Investment in associates	14	(50,282)	(8,459)
Purchase of available-for-sale financial assets	16	-	(101,494)
Proceeds from disposal of property, plant and equipment		886	3,219
Proceeds from disposal of available-for-sale financial assets		243	539
Proceeds from sale of intangible assets		-	6,018
Interest received		8,468	10,257
Net cash flows used in investing activities		(522,464)	(253,955)
Financing activities
Repayment of interest-bearing loans and borrowings		(19,489)	(32,458)
Treasury shares purchased	24	(49,062)	(36,486)
Equity dividends paid		(159,087)	(132,244)
Net cash flows used in financing activities		(227,638)	(201,188)
Net increase/(decrease) in cash and cash equivalents		512,859	(348,854)
Net foreign exchange difference		(11,550)	(7,793)
Cash and cash equivalents at 1 January		1,034,097	1,390,744
Cash and cash equivalents at 31 December	22	1,535,406	1,034,097

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

Consolidated statement of changes in equity

For the year ended 31 December 2011

	Attributable to shareholders of Petrofac Limited
	Issued share capital US$'000	Share premium US$'000	Capital redemption reserve US$'000	Shares to be issued US$'000	*Treasury shares US$'000 (note 24)	Other reserves US$'000 (note 26)	Retained earnings US$'000	Total US$'000	Non- controlling interests US$'000	Total equity US$'000
Balance at 1 January 2011	6,914	992	10,881	994	(65,317)	34,728	787,270	776,462	2,592	779,054
Net profit for the year	-	-	-	-	-	-	539,425	539,425	156	539,581
Other comprehensive income	-	-	-	-	-	(33,262)	-	(33,262)	-	(33,262)
Total comprehensive income    for the year	-	-	-	-	-	(33,262)	539,425	506,163	156	506,319
Shares issued as payment of    consideration on acquisition	2	1,219	-	(994)	-	-	-	227	-	227
Share-based payments    charge (note 25)	-	-	-	-	-	23,056	-	23,056	-	23,056
Shares vested during the year     (note 24)	-	-	-	-	38,693	(33,776)	(4,917)	-	-	-
Transfer to reserve for share-    based payments (note 25)	-	-	-	-	-	17,974	-	17,974	-	17,974
Treasury shares purchased     (note 24)	-	-	-	-	(49,062)	-	-	(49,062)	-	(49,062)
Income tax on share-based    payments reserve	-	-	-	-	-	(3,082)	-	(3,082)	-	(3,082)
Dividends (note 8)	-	-	-	-	-	-	(161,002)	(161,002)	-	(161,002)
Movement in    non-controlling interests	-	-	-	-	-	-	-	-	344	344
Balance at 31 December 2011	6,916	2,211	10,881	-	(75,686)	5,638	1,160,776	1,110,736	3,092	1,113,828

Consolidated statement of changes in equity

For the year ended 31 December 2011

	Attributable to shareholders of Petrofac Limited
	Issued share capital US$'000	Share premium US$'000	Capital redemption reserve US$'000	Shares to be issued US$'000	*Treasury shares US$'000 (note 24)	Other reserves US$'000 (note 26)	Retained earnings US$'000	Total US$'000	Non- controlling interests US$'000	Total equity US$'000
Balance at 1 January 2010	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 on acquisition	4	2,452	-	(994)	-	-	-	1,462	-	1,462
Share-based payments    charge (note 25)	-	-	-	-	-	14,784	-	14,784	-	14,784
Shares vested during the year     (note 24)	-	-	-	-	27,454	(26,170)	(1,284)	-	-	-
Transfer to reserve for share-    based payments (note 25)	-	-	-	-	-	12,750	-	12,750	-	12,750
Treasury shares purchased     (note 24)	-	-	-	-	(36,486)	-	-	(36,486)	-	(36,486)
Income tax on share-based    payments reserve	-	-	-	-	-	(1,366)	-	(1,366)	-	(1,366)
EnQuest demerger share split    and redemption	(1,728)	-	-	-	-	-	1,728	-	-	-
Distribution on EnQuest demerger	-	(71,172)	-	-	-	-	(473,325)	(544,497)	-	(544,497)
Dividends (note 8)	-	-	-	-	-	-	(132,048)	(132,048)	-	(132,048)
Movement in non-controlling    interests	-	-	-	-	-	-	-	-	(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 and Petrofac Joint Venture Companies Employee Benefit Trust.

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

Notes to the consolidated financial statements

For the year ended 31 December 2011

1 Corporate information

The consolidated financial statements of Petrofac Limited (the 'Company') for the year ended 31 December 2011 were authorised for issue in accordance with a resolution of the Directors on 2 March 2012.

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 2011 financial statements are shown on pages 155 to 168. The Group's principal activity is the provision of services to the oil & gas production and processing industry.

A full listing of all Group companies, and joint venture entities, 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.

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 and non-controlling interests are allocated their share of total comprehensive income for the year even if this results in a deficit balance.

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 2011. The principal effects of the adoption of these new and amended standards and improvements are discussed below:

·      IAS 24 Related Party Disclosures (amendment) effective 1 January 2011

·      Improvements to IFRS's (May 2010):

-      IFRS 3 Business Combinations - measurement options available for non-controlling interest (NCI) effective 1 July 2010

-      IFRS 7 Financial Instruments: Disclosures - collateral and qualitative disclosures

-      IAS 1 Presentation of Financial Statements - analysis of other comprehensive income

IAS 24 Related Party Disclosures (Amendment)

The IASB has issued an amendment to IAS 24 that clarifies the identification of related party relationships, particularly in relation to significant influence or control. The new definitions emphasise a symmetrical view on related party relationships as well as clarifying in which circumstances persons and key management personnel affect related party relationships of an entity. While the adoption of the amendment did not have any current impact on the financial position, performance, or disclosure of the Group, as all required information is currently being appropriately captured and disclosed, it is relevant to the application of the Group's accounting policy in identifying future potential related party relationships.

Improvements to IFRS's:

The improvements did not have any impact on the accounting policies, financial position or performance of the Group.

Standards issued but not yet effective

Standards issued but not yet effective up to the date of issuance of the Group's financial statements are listed below and include only those standards and interpretations that are likely to have an impact on the disclosures, financial position or performance of the Group at a future date. The Group intends to adopt these standards when they become effective.

IAS 1 Financial Statement Presentation - Presentation of Items of Other Comprehensive Income (OCI)

The amendments to IAS 1 change the grouping of items presented in OCI. Items that could be reclassified (or 'recycled') to profit or loss at a future point in time (for example, upon de-recognition or settlement) would be presented separately from items that will never be reclassified. The amendment affects presentation only and has therefore no impact on the Group's financial position or performance. The amendment becomes effective for annual periods beginning on or after 1 July 2012.

IAS 27 Separate Financial Statements (as revised in 2011)

As a consequence of the new IFRS 10 and IFRS 12, what remains of IAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in separate financial statements. The amendment becomes effective for annual periods beginning on or after 1 January 2013 but is not expected to have any financial impact on the separate financial statements of the Group but will require some changes in disclosure.

IAS 28 Investments in Associates and Joint Ventures (as revised in 2011)

As a consequence of the new IFRS 11 and IFRS 12, IAS 28 has been renamed IAS 28 Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. The Group is currently assessing the impact that this standard will have on its financial position and performance. The amendment becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 7 Financial Instruments: Disclosures - Enhanced Derecognition Disclosure Requirements

The amendment requires additional disclosure about financial assets that have been transferred but not de-recognised to enable the user of the Group's financial statements to understand the relationship with those assets that have not been de-recognised and their associated liabilities. In addition, the amendment requires disclosures about continuing involvement in de-recognised assets to enable the user to evaluate the nature of, and risks associated with, the entity's continuing involvement in those de-recognised assets. The amendment affects disclosure only and has no impact on the Group's financial position or performance. The amendment becomes effective for annual periods beginning on or after 1 July 2011.

IFRS 9 Financial Instruments: Classification and Measurement

IFRS 9 as issued reflects the first phase of the IASB's work on the replacement of IAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in IAS 39. The standard is effective for annual periods beginning on or after 1 January 2015. In subsequent phases, the IASB will address hedge accounting and impairment of financial assets. The completion of this project is expected over the course of the first half of 2012. The adoption of the first phase of IFRS 9 will have an effect on the classification and measurement of the Group's financial assets, but will potentially have no impact on classification and measurements of financial liabilities. The Group will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

IFRS 10 Consolidated Financial Statements

IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. It also includes the issues raised in SIC-12 Consolidation - Special Purpose Entities.

IFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by IFRS 10 will require management to exercise significant judgement to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that were in IAS 27. The Group is currently assessing the impact that this standard will have on its financial position and performance.

This standard becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 11 Joint Arrangements

IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly-controlled Entities - Non-monetary Contributions by Venturers.

IFRS 11 removes the option to account for jointly-controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method.

The application of this new standard will impact the financial position and performance of the Group but the quantification of this amount is still being determined. This standard becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 12 Disclosure of Involvement with Other Entities

IFRS 12 includes all of the disclosures that were previously in IAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 and IAS 28. These disclosures relate to an entity's interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. This standard becomes effective for annual periods beginning on or after 1 January 2013. The application of this standard affects disclosure only and will have no impact on the Group's financial position or performance.

IFRS 13 Fair Value Measurement

IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted. The Group is currently assessing the impact that this standard will have on the financial position and performance of the Group. This standard becomes effective for annual periods beginning on or after 1 January 2013.

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:

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. This estimate will impact revenues, cost of sales, work-in-progress, billings in excess of costs and estimated earnings and accrued contract expenses

·      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 US$ nil (2010: US$2,523,000)

·      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 2011 was US$106,681,000 (2010: US$105,832,000) (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 2011 was US$29,142,000 (2010: US$26,301,000)

·      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

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 the same accounting policies and reporting periods as that of the Group.

The carried value of the 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 carrying 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 US 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 the statement of changes in equity until the disposal of the net investment at which time they are recognised in the consolidated income statement.

The statements of financial position 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 the 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.

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 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 IFRS 8 '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.

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 a business combination

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 are 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 adjustments 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.

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.

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.

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

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 28.

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 and service  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 Trusts

The Petrofac Employee Benefit Trust and the Petrofac Joint Venture Companies Employee Benefit Trust warehouse ordinary shares purchased to satisfy various new share scheme awards made to the employees of the Company and its joint venture partner employees, 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 trusts have been consolidated in the Group financial statements in accordance with SIC 12 'Special Purpose Entities'. The cost of shares temporarily held by the trusts are 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.

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

Assets held under finance leases are recognised as non-current assets of the Group at the lower of their fair value at the date of commencement of the lease and the present value of the minimum lease payments. These assets are depreciated on a straight-line basis over the shorter of the useful life of the asset and the lease term. The corresponding liability to the lessor is included in the consolidated statement of financial position as a finance lease obligation. Lease payments are apportioned between finance costs in the income statement and reduction of the lease obligation so as to achieve a constant rate of interest on the remaining balance of the liability.

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.

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:

Onshore 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.

Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services

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.

Integrated Energy Services

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 over the life of the contract.

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

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 the 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 the 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

As described on pages 12 to 13 during the year, the Group reorganised to deliver its services through four reporting segments; Onshore Engineering & Construction, Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services. As a result the segment information has been realigned to fit the new Group organisational structure which now comprises the following four reporting segments:

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

·      Offshore Projects & Operations which provides offshore engineering, operations and maintenance on and offshore

·      Engineering & Consulting Services which provides technical engineering, consultancy, conceptual design, front end engineering and design (FEED) and project management consultancy (PMC) across all sectors including renewables and carbon capture

·      Integrated Energy Services which co-invests with partners in oil & gas production, processing and transportation assets, provides production improvement services under value aligned commercial structures and oil & gas related technical competency training and consultancy services

Management separately monitors the trading results of its four reporting segments for the purpose of making an assessment of their performance and making decisions about how resources are allocated to them. Each segment's 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 reporting segments.

The following tables represent revenue and profit information relating to the Group's reporting segments for the year ended 31 December 2011 and the comparative segmental information has been restated to reflect the revised Group organisational structure.

Year ended 31 December 2011

	Onshore Engineering & Construction US$'000	Offshore Projects & Operations US$'000	Engineering & Consulting Services US$'000	Integrated Energy Services US$'000	Corporate & others US$'000	Consolidation adjustments & eliminations US$'000	Total US$'000
Revenue
External sales	4,068,324	1,164,565	64,391	503,439	-	-	5,800,719
Inter-segment sales	77,894	86,787	143,775	15,417	-	(323,873)	-
Total revenue	4,146,218	1,251,352	208,166	518,856	-	(323,873)	5,800,719
Segment results	553,797	56,930	32,930	57,024	(420)	(7,517)	692,744
Unallocated corporate costs	-	-	-	-	(9,864)	-	(9,864)
Profit/(loss) before tax and finance income/(costs)	553,797	56,930	32,930	57,024	(10,284)	(7,517)	682,880
Share of loss of associate	-	-	-	(3,593)	-	-	(3,593)
Finance costs	(1,450)	(1,292)	-	(3,180)	(2,921)	2,244	(6,599)
Finance income	8,375	212	58	357	1,807	(2,932)	7,877
Profit/(loss) before income tax	560,722	55,850	32,988	50,608	(11,398)	(8,205)	680,565
Income tax (expense)/income	(97,734)	(12,323)	(2,170)	(27,983)	1,415	(2,189)	(140,984)
Non-controlling interests	(156)	-	-	-	-	-	(156)
Profit/(loss) for the year attributable to    Petrofac Limited shareholders	462,832	43,527	30,818	22,625	(9,983)	(10,394)	539,425
Other segment information Capital expenditures:
Property, plant and equipment	54,028	58,572	7,599	311,948	6,059	(2,766)	435,440
Intangible oil & gas assets	-	-	-	39,728	-	-	39,728
Charges:
Depreciation	31,097	3,449	5,678	35,322	1,378	(145)	76,779
Amortisation	-	1,047	1,078	1,184	-	-	3,309
Other long-term employment benefits	12,013	352	-	396	100	-	12,861
Share-based payments	11,863	2,521	774	3,674	4,224	-	23,056

3 Segment information

Year ended 31 December 2010 (as restated)

	Onshore Engineering & Construction US$'000	Offshore Projects & Operations US$'000	Engineering & Consulting Services US$'000	Integrated Energy Services US$'000	Corporate & others US$'000	Consolidation adjustments & eliminations US$'000	Total US$'000
Revenue
External sales	3,232,174	710,080	39,693	372,270	-	-	4,354,217
Inter-segment sales	21,732	11,821	133,739	11,964	-	(179,256)	-
Total revenue	3,253,906	721,901	173,432	384,234	-	(179,256)	4,354,217
Segment results	438,096	24,506	19,803	73,848	(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)	438,096	24,506	19,803	198,712	(14,305)	(3,362)	663,450
Share of loss of associate	-	-	-	(131)	-	-	(131)
Finance costs	-	(968)	(12)	(3,805)	(3,659)	3,313	(5,131)
Finance income	9,741	209	142	731	2,699	(3,313)	10,209
Profit/(loss) before income tax	447,837	23,747	19,933	195,507	(15,265)	(3,362)	668,397
Income tax (expense)/income	(74,848)	(6,519)	1,215	(32,668)	2,275	-	(110,545)
Non-controlling interests	(35)	-	-	-	-	-	(35)
Profit/(loss) for the year attributable to    Petrofac Limited shareholders	372,954	17,228	21,148	162,839	(12,990)	(3,362)	557,817
Other segment information Capital expenditures:
Property, plant and equipment	59,522	2,785	3,597	46,938	4,575	(1,178)	116,239
Intangible oil & gas assets	-	-	-	15,644	-	-	15,644
Charges:
Depreciation	33,710	2,238	4,719	52,933	367	(575)	93,392
Amortisation	-	597	1,044	870	-	-	2,511
Other long-term employment benefits	10,435	613	41	1,594	87	-	12,770
Share-based payments	7,693	1,167	718	2,299	2,907	-	14,784

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 2011 and 2010.

Year ended 31 December 2011

	United Arab Emirates US$'000	United Kingdom US$'000	Turkmenistan US$'000	Malaysia US$'000	Algeria US$'000	Kuwait US$'000	Qatar US$'000	Other countries US$'000	Consolidated US$'000
Revenues from    external customers	1,290,673	938,606	768,283	653,395	749,204	379,178	256,657	764,723	5,800,719

	United Kingdom US$'000	United Arab Emirates US$'000	Tunisia US$'000	Algeria US$'000	Malaysia US$'000	Thailand US$'000	Other countries US$'000	Consolidated US$'000
Non-current assets:
Property, plant and equipment	71,276	104,466	41,824	26,889	255,958	47,854	45,470	593,737
Intangible oil & gas assets	1,130	-	-	-	102,345	-	-	103,475
Other intangible assets	12,510	-	-	-	-	-	5,836	18,346
Goodwill	91,268	14,914	-	-	-	-	499	106,681

3 Segment information

Year ended 31 December 2010

	Algeria US$'000	United Arab Emirates US$'000	United Kingdom US$'000	Kuwait US$'000	Oman US$'000	Syria US$'000	Saudi Arabia US$'000	Other countries US$'000	Consolidated 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 Kingdom US$'000	United Arab Emirates US$'000	Tunisia US$'000	Algeria US$'000	Malaysia US$'000	Indonesia US$'000	Other countries US$'000	Consolidated US$'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	-	-	69,532
Other intangible assets	9,365	-	-	-	-	6,940	-	16,305
Goodwill	90,093	15,240	-	-	-	-	499	105,832

Revenues disclosed in the above tables are based on where the project is located. Revenue from two customers amounted to US$1,651,994,000 (2010: US$1,422,410,000) in the Onshore Engineering & Construction segment.

 

4 Revenues and expenses

a. Revenue

	2011 US$'000	2010 US$'000
Rendering of services	5,650,892	4,202,371
Sale of crude oil & gas	143,122	146,075
Sale of processed hydrocarbons	6,705	5,771
	5,800,719	4,354,217

Included in revenues from rendering of services are Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services revenues of a 'pass-through' nature with zero or low margins amounting to US$229,422,000 (2010: US$227,974,000). The revenues are included as external revenues of the Group since the risks and rewards associated with its recognition are assumed by the Group.

b. Cost of sales

Included in cost of sales for the year ended 31 December 2011 is US$62,000 loss (2010: US$154,000 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$62,180,000 during 2011 (2010: US$85,186,000) 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 losses on undesignated derivatives of US$5,881,000 (2010: US$3,409,000 loss). These amounts are an economic hedge of foreign exchange risk but do not meet the criteria within IAS 39 and are most appropriately recorded in cost of sales.

c. Selling, general and administration expenses

	2011  US$'000	2010 US$'000
Staff costs	186,462	126,475
Depreciation (note 9)	14,599	8,206
Amortisation (note 13)	3,309	2,511
Other operating expenses	79,022	84,257
	283,392	221,449

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

d. Staff costs

	2011 US$'000	2010 US$'000
Total staff costs:
Wages and salaries	1,044,361	828,439
Social security costs	37,936	31,809
Defined contribution pension costs	20,576	12,621
Other long-term employee benefit costs (note 28)	14,313	12,770
Expense of share-based payments (note 25)	23,056	14,784
	1,140,242	900,423

Of the US$1,140,242,000 (2010: US$900,423,000) of staff costs shown above, US$953,780,000 (2010: US$773,948,000) 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 13,212 (2010: 12,807).

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:

	2011 US$'000	2010 US$'000
Group audit fee	1,124	958
Audit of accounts of subsidiaries	1,007	798
Audit related assurance services	301	239
Taxation compliance services	200	75
Other taxation services	435	445
All other non-audit services	88	119
	3,155	2,634

f. Other income

	2011 US$'000	2010 US$'000
Foreign exchange gains	2,564	720
Gain on sale of property, plant and equipment	140	8
Gain on sale of available-for-sale financial assets	70	-
Gain on fair value changes in Seven Energy warrants (note 14)	5,647	-
Gain on sale of intangible assets	-	2,338
Other income	3,179	1,947
	11,600	5,013

g. Other expenses

	2011 US$'000	2010 US$'000
Foreign exchange losses	3,716	3,452
Loss on sale of property, plant and equipment	44	477
Other expenses	1,344	124
	5,104	4,053

5 Finance (costs)/income

	2011 US$'000	2010 US$'000
Interest payable:
Long-term borrowings	(2,561)	(2,908)
Other interest, including short-term loans and overdrafts	(1,734)	(581)
Unwinding of discount on provisions	(2,304)	(1,642)
Total finance cost	(6,599)	(5,131)
Interest receivable:
Bank interest receivable	7,594	9,945
Other interest receivable	283	264
Total finance income	7,877	10,209

6 Income tax

a. Tax on ordinary activities

The major components of income tax expense are as follows:

	2011 US$'000	2010 US$'000
Current income tax Current income tax charge	138,205	115,199
Adjustments in respect of current income tax of previous years	782	(2,843)
Deferred income tax Relating to origination and reversal of temporary differences	8,832	907
Adjustments in respect of deferred income tax of previous years	(6,835)	(2,718)
Income tax expense reported in the income statement	140,984	110,545

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:

	2011 US$'000	2010 US$'000
Accounting profit before tax	680,565	668,397
At Jersey's domestic income tax rate of 0% (2010: 0%)	-	-
Expected tax charge in higher rate jurisdictions	141,347	116,199
Expenditure not allowable for income tax purposes	2,741	1,073
Adjustments in respect of previous years	(6,053)	(5,561)
Tax effect of utilisation of tax losses not previously recognised	(607)	(568)
Unrecognised tax losses	1,388	1,634
Other permanent differences	1,338	(2,157)
Effect of change in tax rates	830	(75)
At the effective income tax rate of 20.7% (2010: 16.5%)	140,984	110,545

The Group's effective tax rate for the year ended 31 December 2011 is 20.7% (2010: 16.5% including EnQuest demerger; 20.3% excluding EnQuest demerger). No chargeable gain arose for UK corporate tax purposes on the 2010 demerger of Petrofac's UKCS business to EnQuest Plc. Excluding the gain on demerger, there has been no significant change to the Group's effective tax rate. Any variance results from changes in jurisdictions in which profits are expected to be earned. From 1 April 2012 the UK corporation tax rate will be 25% and the change in UK rate was substantially enacted as at the balance sheet date. This change will impact the reversal of the temporary difference from this date onwards, reducing the Group's UK deferred tax assets and liabilities for the period ended 31 December 2011.

c. Deferred income tax

Deferred income tax relates to the following:

	Consolidated statement of financial position		Consolidated income statement
	2011 US$'000	2010 US$'000	2011 US$'000	2010 US$'000
Deferred income tax liabilities Fair value adjustment on acquisitions	2,889	1,412	1,477	(597)
Accelerated depreciation	42,884	36,581	6,303	14,630
Profit recognition	13,655	7,896	5,760	(4,768)
Other temporary differences	177	2,197	(2,020)	432
Gross deferred income tax liabilities	59,605	48,086
Deferred income tax assets Losses available for offset	1,846	2,258	412	(14,135)
Decelerated depreciation for tax purposes	1,967	2,403	436	327
Share scheme	9,950	15,721	(911)	(230)
Profit recognition	11,310	4,160	(7,150)	-
Other temporary differences	4,069	1,759	(2,310)	2,530
Gross deferred income tax assets	29,142	26,301
Deferred income tax charge/(credit)			1,997	(1,811)

Certain items of other temporary differences in 2010 have been reclassified to be consistent with current year presentation.

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$26,626,000 (2010: US$18,366,000).

	2011 US$'000	2010 US$'000
Expiration dates for tax losses No earlier than 2022	8,917	9,466
No expiration date	4,032	6,384
	12,949	15,850
Tax credits (no expiration date)	13,677	2,516
	26,626	18,366

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:

	2011 US$'000	2010 US$'000
Net profit attributable to ordinary shareholders for basic and diluted earnings    per share excluding gain on EnQuest demerger	539,425	432,953
Net profit attributable to ordinary shareholders for basic and diluted earnings    per share including gain on EnQuest demerger	539,425	557,817

	2011 Number '000	2010 Number '000
Weighted average number of ordinary shares for basic earnings per share	339,239	338,867
Effect of diluted potential ordinary shares granted under share-based payment schemes	4,069	4,493
Adjusted weighted average number of ordinary shares for diluted earnings per share	343,308	343,360

8 Dividends paid and proposed

	2011 US$'000	2010 US$'000
Declared and paid during the year
Equity dividends on ordinary shares: Final dividend for 2009: 25.10 cents per share	-	85,291
Interim dividend 2010: 13.80 cents per share	-	46,757
Final dividend for 2010: 30.00 cents per share	101,788	-
Interim dividend 2011: 17.40 cents per share	59,214	-
	161,002	132,048

	2011 US$'000	2010 US$'000
Proposed for approval at AGM (not recognised as a liability as at 31 December)
Equity dividends on ordinary shares Final dividend for 2011: 37.20 cents per share (2010: 30.00 cents per share)	128,670	103,715

9 Property, plant and equipment

	Oil & gas assets US$'000	Oil & gas facilities US$'000	Land, buildings and leasehold improvements US$'000	Plant and equipment US$'000	Vehicles US$'000	Office furniture and equipment US$'000	Assets under construction US$'000	Total US$'000
Cost 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 1 January 2011	117,706	165,585	158,228	23,454	14,685	87,408	13,380	580,446
Additions	2,774	306,704	63,619	5,388	2,815	29,926	24,214	435,440
Disposals	-	-	(1,718)	(2,269)	(631)	(10,311)	-	(14,929)
Transfers	-	(44,330)	(20)	-	-	13,172	(13,152)	(44,330)
Exchange difference	(2,638)	(1,721)	(2,504)	(245)	-	(1,103)	(277)	(8,488)
At 31 December 2011	117,842	426,238	217,605	26,328	16,869	119,092	24,165	948,139
Depreciation 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 1 January 2011	(49,783)	(118,273)	(44,623)	(18,487)	(8,451)	(53,671)	-	(293,288)
Charge for the year	(13,390)	(18,697)	(19,978)	(1,321)	(3,502)	(19,891)	-	(76,779)
Disposals	-	-	1,567	2,234	412	9,864	-	14,077
Transfers	-	-	12	-	-	(12)	-	-
Exchange difference	913	28	316	14	5	312	-	1,588
At 31 December 2011	(62,260)	(136,942)	(62,706)	(17,560)	(11,536)	(63,398)	-	(354,402)
Net carrying amount: At 31 December 2011	55,582	289,296	154,899	8,768	5,333	55,694	24,165	593,737
At 31 December 2010	67,923	47,312	113,605	4,967	6,234	33,737	13,380	287,158

No interest has been capitalised within oil & gas facilities during the year (2010: nil) and the accumulated capitalised interest, net of depreciation at 31 December 2011, was nil (2010: US$432,000).

Additions to oil & gas facilities in 2011 mainly comprise of the purchase and upgrade of the FPF1, FPSO Berantai, FPF3, FPF4 and FPF5 for a combined cost of US$305,394,000. Transfers from oil & gas facilities include the transfer of the FPF1 to non-current asset held for sale as part of the pending Ithaca transaction (note 18).

Included in oil & gas assets are US$3,262,000 (2010: US$2,196,000) of capitalised decommissioning costs net of depreciation provided on the PM304 asset in Malaysia and the Chergui asset in Tunisia.

Of the total charge for depreciation in the income statement, US$62,180,000 (2010: US$85,186,000) is included in cost of sales and US$14,599,000 (2010: US$8,206,000) in selling, general and administration expenses.

Assets under construction comprise expenditures incurred in relation to a new office building in the United Arab Emirates and the Group ERP project.

Included in land, buildings and leasehold improvements is property, plant and equipment under finance lease agreements, for which book values are as follows:

Net book value	US$'000
Gross book value	35,809
Depreciation	(994)
At 31 December 2011	34,815
At 31 December 2010	-

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 UK based company, involved in the servicing and repair of oilfield pressure control equipment. 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 2010 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 was from zero to a maximum of sterling 2,000,000 (equivalent US$3,122,000) over a three year period.

The fair value of net assets acquired was US$4,967,000 which included fair value of intangible assets recognised on acquisition of US$1,107,000.

These 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 of US$2,437,000 (2010: US$2,449,000) comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the Group.

During the year a charge of US$54,000 (2010: US$59,000) for the unwinding of interest on deferred consideration payable has been reflected in the consolidated income 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 459,000, equivalent US$735,000 (2010: sterling 135,000, equivalent US$208,000) with a corresponding increase in other income within the consolidated income statement.

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 UK 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. 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 value of net assets acquired was US$3,382,000 which included fair value of intangible assets recognised on acquisition of US$2,065,000.

These 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 of US$3,562,000 (2010: US$3,578,000) comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the Group.

During the year a charge of US$ nil (2010: US$25,000) for the unwinding of interest has been reflected in the consolidated income 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 214,000, equivalent US$343,000 (2010: sterling 188,000, equivalent US$293,000) with a corresponding increase in other income within the consolidated income statement.

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).

The fair value of net assets acquired was US$340,000.

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 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 67,000, equivalent US$107,000 (2010: sterling 44,000, equivalent US$68,000).

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 fair value of net assets acquired was US$2,587,000.

The residual goodwill of US$7,695,000 (2010: US$7,728,000) comprises the fair value of expected future synergies and business opportunities arising from the integration of the business into the Group.

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 three years from the date of completion which will be recognised as an expense in the income statement on a straight-line basis over the three years. The charge for the current year is sterling 513,000, equivalent US$821,000 (2010: 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. A gain of US$124,864,000 was made on the demerger transaction.

 

12 Goodwill

A summary of the movements in goodwill is presented below:

	2011 US$'000	2010 US$'000
At 1 January	105,832	97,922
Acquisitions during the year (note 10)	-	13,223
Reassessment of deferred consideration payable	820	(1,313)
Write off on EnQuest demerger	-	(1,146)
Exchange difference	29	(2,854)
At 31 December	106,681	105,832

Reassessment of deferred consideration payable comprises of the increase in deferred consideration payable on SPD Group Limited of US$820,000 (2010: US$3,141,000) and Caltec Limited of US$ nil (2010: US$4,285,000 decrease).

Goodwill acquired through business combinations has been allocated to three groups of cash-generating units, for impairment testing as follows:

·      Offshore Projects & Operations

·      Engineering & Consulting Services

·      Integrated Energy Services

These represent the lowest level within the Group at which the goodwill is monitored for internal management purposes. The goodwill previously monitored separately for Production Solutions, Training Services and Energy Developments is now monitored on a combined basis following the Group reorganisation.

Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services
cash-generating units

The recoverable amounts for the Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services cash-generating 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 Projects & Operations and Engineering & Consulting Services cash-generating units. For the Integrated Energy Services business the cash flows are based on field models over a ten-year horizon for Production Enhancement Contracts and Risk Service Contracts and on financial budgets approved by senior management covering a five-year period, extrapolated for a further five years at a growth rate of 2.5% for other operations as these include acquired businesses where there is less track record of achieving financial projections.

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

	2011 US$'000	2010 US$'000
Offshore Projects & Operations unit	27,904	27,992
Engineering & Consulting Services unit	7,695	7,728
Integrated Energy Services unit	71,082	70,112
	106,681	105,832

Key assumptions used in value in use calculations for the Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services units:

Market share: the assumption relating to market share for the Offshore Projects & 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 business which is within Integrated Energy Services, 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.

Capital expenditure: the Production Enhancement Contracts in the Integrated Energy Services unit require a minimum level of capital spend on the projects in the initial years to meet contractual commitments. If the capital is not spent a cash payment of the balance is required which does not qualify for cost recovery. The level of capital spend assumed in the value in use calculation is that expected over the period of the budget based on the current field development plans which assumes the minimum spend is met on each project and the contracts remain in force for the entire duration of the project.

Reserve volumes and production profiles: management has used its internally developed economic models of reserves and production as inputs in to the value in use for the Production Enhancement, Risk Service and Production Sharing Contracts. Management has used an oil price of US$85 per barrel to determine reserve volumes on Production Sharing Contracts.

Tariffs and payment terms: the tariffs and payment terms used in the value in use calculations for the Production Enhancement and Risk Service Contracts are those specified in the respective contracts with assumptions consistent with the current field development plan where KPI's influence the payment terms.

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 the Offshore Projects & Operations and Engineering & Consulting Services cash-generating units for the remaining five years of the ten-year projection period and 2.5% per annum for the Integrated Energy Services cash-generating unit since it includes newly acquired businesses where there is less historic track record of achieving financial projections.

Discount rate: management has used a pre-tax discount rate of 13.8% per annum. In 2010 a discount rate of 14.6% was used for the Offshore Projects & Operations, Engineering & Consulting Services, Production Solutions and Training Services cash-generating units and a rate of 13.4% for the Energy Developments cash generating unit. The discount rate is derived from the estimated weighted average cost of capital of the Group and 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.

Sensitivity to changes in assumptions

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

	2011 US$'000	2010 US$'000
Intangible oil & gas assets
Cost: At 1 January	69,532	53,888
Additions	39,728	15,644
Transfer to costs	(5,785)	-
Net book value of intangible oil & gas assets at 31 December	103,475	69,532
Other intangible assets
Cost: At 1 January	24,538	25,476
Additions on acquisition (note 10)	-	3,172
Additions	5,722	153
Disposal	-	(4,220)
Exchange difference	(504)	(43)
At 31 December	29,756	24,538
Accumulated amortisation: At 1 January	(8,233)	(6,257)
Amortisation	(3,309)	(2,511)
Disposal	-	540
Exchange difference	132	(5)
At 31 December	(11,410)	(8,233)
Net book value of other intangible assets at 31 December	18,346	16,305
Total intangible assets	121,821	85,837

Intangible oil & gas assets

Oil & gas asset (part of the Integrated Energy Services segment) additions above comprise of US$38,688,000 (2010: US$15,644,000) of capitalised expenditure on the Group's assets in Malaysia.

There were investing cash outflows relating to capitalised intangible oil & gas assets of US$39,728,000 (2010: US$15,644,000) in the current period arising from pre-development activities.

US$5,785,000 relates to a long-term receivable from a customer on the Berantai RSC contract being their share of development expenditure, which was transferred to costs.

Other intangible assets

Other intangible asset additions above largely consist of US$4,003,000 of gas storage project development costs and US$1,634,000 of competency training software that formed part of the acquisition during the year of Skills XP.

Other intangible assets comprising project development expenditure customer contracts, proprietary software, LNG intellectual property and patent technology are being amortised over their estimated economic useful life on a straight-line basis and the related amortisation charges included in selling, general and administrative expenses (note 4c).

14 Investments in associates

	2011 US$'000	2010 US$'000
Investment in Gateway Storage Company Limited	14,835	15,601
Associates acquired through acquisition of Scotvalve (note 10)	745	748
Investment in Seven Energy International Limited transferred from available-for-sale financial assets (note 16)	148,825	-
	164,405	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:

	2011 US$'000	2010 US$'000
Non-current assets	154	123
Current assets	1,612	3,050
Current liabilities	(40)	(795)
Equity	1,726	2,378
Transaction costs incurred	720	664
Fair value of free services to be provided	780	780
Deferred consideration payable	6,556	6,556
Exchange	(364)	(194)
Residual goodwill	5,417	5,417
Carrying value of investment	14,835	15,601
Share of associates revenues and net loss: Revenue	-	-
Net loss	(885)	(131)

Seven Energy International Limited

On 25 November 2010, the Company invested US$100,000,000 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 incurring US$1,251,000 of transaction costs. This investment which was previously held under available-for-sale financial assets was transferred to investment in associates, pursuant to an investment on 10 June 2011 of US$50,000,000 for an additional 5% of the share capital of Seven Energy which resulted in the Group being in a position to exercise significant influence over Seven Energy. The Company 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 performance of certain service provision conditions and milestones in relation to project execution. These warrants have been fair valued at 31 December 2011 as derivative financial instruments under IAS 39, using Black Scholes Model, amounting to US$17,616,000 (2010:US$11,969,000). US$5,647,000 has been recognised as other income in the current period income statement as a result of the revaluation of these derivatives at 31 December 2011 (note 4f). At 31 December 2011, there was a corresponding entry for the fair value in trade and other payables representing the deferred revenue relating to the performance conditions. This deferred revenue is released as revenue in the income statement in line with the percentage of performance conditions satisfied at each reporting date. At 31 December 2011, 80% of the performance conditions have been completed (2010: nil) resulting in current year revenue recognised of US$9,576,000.

The share of the associate's statement of financial position is as follows:

	2011 US$'000
Non-current assets	92,563
Current assets	21,965
Non-current liabilities	(47,597)
Current liabilities	(10,970)
Equity	55,961
Transaction costs incurred	1,533
Residual goodwill	91,331
Carrying value of investment	148,825
Share of associates revenues and net loss: Revenue	24,289
Net loss	(2,708)

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:

	2011 US$'000	2010 US$'000
Revenue	452,672	194,848
Cost of sales	(375,538)	(171,233)
Gross profit	77,134	23,615
Selling, general and administration expenses	(49,786)	(14,286)
Other (expense)/income, net	-	(6,553)
Finance income, net	440	643
Profit before income tax	27,788	3,419
Income tax	(792)	(263)
Net profit	26,996	3,156
Current assets	172,117	94,935
Non-current assets	182,746	27,634
Total assets	354,863	122,569
Current liabilities	272,080	120,892
Non-current liabilities	57,256	1,658
Total liabilities	329,336	122,550
Net assets	25,527	19

16 Available-for-sale financial assets

	2011 US$'000	2010 US$'000
Seven Energy International Limited	-	101,251
Shares - listed	-	243
	-	101,494

The investment in Seven Energy International Limited was transferred to investment in associates (note 14), pursuant to an additional investment made during the year, which took the Group's holding in the share capital of Seven Energy to over 20% (2010: 15%).

17 Other financial assets

	2011 US$'000	2010 US$'000
Other financial assets - non-current Fair value of derivative instruments (note 34)	-	12
Long-term receivable from a customer	130,206	-
Restricted cash	307	266
Other	9,596	1,945
	140,109	2,223
Other financial assets - current Seven Energy warrants (note 14)	17,616	11,969
Fair value of derivative instruments (note 34)	8,553	9,183
Interest receivable	140	731
Restricted cash	2,506	19,196
Other	819	1,271
	29,634	42,350

Long-term receivable from a customer relates to an amount due on the Berantai RSC.

Restricted cash comprises deposits with financial institutions securing various guarantees and performance bonds associated with the Group's trading activities (note 32). This cash will be released on the maturity of these guarantees and performance bonds. Included in other non-current financial assets are transition costs relating to the Santuario, Magallanes and Ticleni Production Enhancement Contracts which are recoverable over the lives of these contracts.

18 Asset held for sale

	2011 US$'000	2010 US$'000
Non-current asset held for sale (note 9)	44,330	-
Liabilities directly associated with non-current asset held for sale	5,150	-

Non-current asset held for sale comprises FPF1 Ltd pending the completion of the Ithaca transaction. This entry is reported under the Integrated Energy Services segment.

19 Inventories

	2011 US$'000	2010 US$'000
Crude oil	3,942	2,119
Processed hydrocarbons	84	90
Stores and spares	5,650	4,083
Raw materials	853	910
	10,529	7,202

Included in the consolidated income statement are costs of inventories expensed of US$31,706,000 (2010: US$28,840,000).

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

	2011 US$'000	2010 US$'000
Cost and estimated earnings	12,066,357	7,812,897
Less: billings	(11,454,348)	(7,008,911)
Work in progress	612,009	803,986
Billings	2,856,375	2,144,252
Less: cost and estimated earnings	(2,466,971)	(1,965,823)
Billings in excess of cost and estimated earnings	389,404	178,429
Total cost and estimated earnings	14,533,328	9,778,720
Total billings	14,310,723	9,153,163

21 Trade and other receivables

	2011 US$'000	2010 US$'000
Trade receivables	869,124	785,383
Retentions receivable	71,375	26,297
Advances	215,470	179,101
Prepayments and deposits	30,802	34,059
Receivables from joint venture partners	121,477	-
Other receivables	44,794	31,919
	1,353,042	1,056,759

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$869,124,000 (2010: US$785,383,000) are as follows:

	2011			2010
	Specific impairment US$'000	General impairment US$'000	Total US$'000	Specific impairment US$'000	General impairment US$'000	Total US$'000
At 1 January	2,790	2,935	5,725	4,875	1,754	6,629
Charge for the year	524	(412)	112	2,189	1,796	3,985
Amounts written off	(294)	(1,854)	(2,148)	(2,197)	(67)	(2,264)
Unused amounts reversed	(235)	(120)	(355)	(1,738)	(893)	(2,631)
Transfers	-	-	-	(326)	326	-
Exchange difference	(9)	(39)	(48)	(13)	19	6
At 31 December	2,776	510	3,286	2,790	2,935	5,725

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

		Number of days past due
	Neither past due nor impaired US$'000	< 30 days US$'000	31-60 days US$'000	61-90  days  US$'000	91-120 days  US$'000	121-360 days  US$'000	> 360  days  US$'000	Total  US$'000
Unimpaired	570,445	156,310	108,780	13,857	3,615	13,233	616	866,856
Impaired	-	-	-	-	2,445	2,207	902	5,554
	570,445	156,310	108,780	13,857	6,060	15,440	1,518	872,410
Less: impairment provision	-	-	-	-	(441)	(1,932)	(913)	(3,286)
Net trade receivables 2011	570,445	156,310	108,780	13,857	5,619	13,508	605	869,124
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

21 Trade and other receivables

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 subcontractors 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 2011 relates to new contract awards in the Onshore Engineering & Construction business partly offset by the unwinding of advances on more mature contracts.

Receivables from joint venture partners are amounts recoverable from venture partners on the Berantai floating production platform and PM304.

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 euros.

22 Cash and short-term deposits

	2011 US$'000	2010 US$'000
Cash at bank and in hand	490,446	244,018
Short-term deposits	1,081,892	818,987
Total cash and bank balances	1,572,338	1,063,005

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$1,572,338,000 (2010: US$1,063,005,000).

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

	2011 US$'000	2010 US$'000
Cash at bank and in hand	490,446	244,018
Short-term deposits	1,081,892	818,987
Bank overdrafts (note 27)	(36,932)	(28,908)
	1,535,406	1,034,097

23 Share capital

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

	2011 US$'000	2010 US$'000
Authorised 750,000,000 ordinary shares of US$0.020 each (2010: 750,000,000 ordinary shares of US$0.020 each)	15,000	15,000
Issued and fully paid 345,821,729 ordinary shares of US$0.020 each (2010: 345,715,053 ordinary shares of US$0.020 each)	6,916	6,914

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 2010	345,532,388
Issued during the year as further deferred consideration payable for the acquisition of a subsidiary	182,665
Ordinary shares of US$0.020 each at 1 January 2011	345,715,053
Issued during the year as further deferred consideration payable for the acquisition of subsidiaries	106,676
Ordinary shares of US$0.020 each at 31 December 2011	345,821,729

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

Share premium: The balance on the share premium account represents the amount received in excess of the nominal value of the ordinary shares.

Capital redemption reserve: The balance on the capital redemption reserve represents the aggregated nominal value of the ordinary shares repurchased and cancelled.

**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.

24 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 and the Petrofac Joint Venture Companies 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:

	2011		2010
	Number	US$'000	Number	US$'000
At 1 January	6,757,339	65,317	7,210,965	56,285
Acquired during the year	2,074,138	49,062	2,122,960	36,486
Vested during the year	(3,095,460)	(38,693)	(2,576,586)	(27,454)
At 31 December	5,736,017	75,686	6,757,339	65,317

Shares vested during the year include dividend shares and 8% uplift adjustment made in respect of the EnQuest demerger of 393,344 (2010: 120,504).

 

25 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
2011 awards	1,426p	94.3%
2010 awards	1,103p	93.8%
2009 awards	545p	93.1%
2008 awards	522p	92.3%

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:

	2011 awards	2010 awards	2009 awards	2008 awards
Expected share price volatility (based on median of comparator    Group's three-year volatilities)	51.0%	50.0%	49.0%	32.0%
Share price correlation with comparator Group	43.0%	39.0%	36.0%	22.0%
Risk-free interest rate	1.7%	1.50%	2.10%	3.79%
Expected life of share award	3 years	3 years	3 years	3 years
Fair value of TSR portion	788p	743p	456p	287p

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

	2011 Number	2010 Number
Outstanding at 1 January	1,350,189	1,432,680
Granted during the year	482,379	390,278
Vested during the year	(421,309)	(407,316)
Forfeited during the year	(53,213)	(65,453)
Outstanding at 31 December	1,358,046	1,350,189

The number of outstanding shares excludes the 8% uplift adjustment made in respect of the EnQuest demerger of 47,335 shares (2010: 82,594 shares) and any rolled up declared dividends of 68,073 shares (2010: 64,264 shares). 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 2011 is made up of 454,969 in respect of 2011 awards (2010: nil), 368,005 in respect of 2010 awards (2010: 390,278), 535,072 in respect of 2009 awards (2010: 538,602), and nil in respect of 2008 awards (2010: 421,309).

The charge recognised in the current year amounted to US$5,999,000 (2010: US$3,208,000).

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 corresponding 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
2011 awards	1,426p	97.0%
2010 awards	1,185p	90.8%
2009 awards	545p	91.8%
2008 awards	522p	90.9%

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

	2011 Number*	2010 Number*
Outstanding at 1 January	4,082,311	4,694,191
Granted during the year	1,538,252	1,397,094
Vested during the year	(1,681,130)	(1,792,895)
Forfeited during the year	(129,687)	(216,079)
Outstanding at 31 December	3,809,746	4,082,311

*Includes Invested and Matching Shares.

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger of 188,177 shares (2010: 327,058 shares) and rolled up declared dividends of 158,691 shares (2010: 184,599 shares).

The number of awards still outstanding but not exercisable at 31 December 2011 is made up of 1,491,298 in respect of 2011 awards (2010: nil), 984,496 in respect of 2010 awards (2010: 1,313,894), 1,333,952 in respect of 2009 awards (2010: 1,948,340), and nil in respect of 2008 awards (2010: 820,077).

The charge recognised in the 2011 income statement in relation to matching share awards amounted to US$12,920,000 (2010: US$9,195,000).

Share Incentive Plan (SIP)

All UK employees, including UK Executive 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
2011 awards	1,463p	99.3%
2010 awards	990p	92.3%
2009 awards	430p	70.0%
2008 awards	478p	97.6%

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

	2011 Number	2010 Number
Outstanding at 1 January	1,003,712	1,082,461
Granted during the year	204,402	203,384
Vested during the year	(664,512)	(176,360)
Forfeited during the year	(8,822)	(105,773)
Outstanding at 31 December	534,780	1,003,712

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger of 27,982 shares (2010: 78,156 shares) and rolled up declared dividends of 27,090 shares (2010: 48,474 shares).

The number of awards still outstanding but not exercisable at 31 December 2011 is made up of 204,402 in respect of 2011 awards (2010: nil), 186,758 in respect of 2010 awards (2010: 195,580), 36,658 in respect of 2009 awards (2010: 36,658), 1,030 in respect of 2008 awards (2010: 665,542), and 105,932 in respect of 2007 awards (2010: 105,932).

The charge recognised in the 2011 income statement in relation to RSP awards amounted to US$4,137,000 (2010: US$2,381,000).

The Group has recognised a total charge of US$23,056,000 (2010: US$14,784,000) 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$17,974,000 of the bonus liability accrued for the year ended 31 December 2010 which has been settled in shares granted during the year (2010: US$12,750,000).

For further details on the above employee share-based payment schemes refer to pages 97 to 101 of the Directors' remuneration report.

26 Other reserves

	Net unrealised gains/(losses) on available-for-sale-financial assets US$'000	Net unrealised (losses)/ gains on derivatives US$'000	Foreign currency translation US$'000	Reserve for share-based payments US$'000	Total US$'000
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 25)	-	-	-	14,784	14,784
Transfer during the year (note 25)	-	-	-	12,750	12,750
Shares vested during the year (note 25)	-	-	-	(26,170)	(26,170)
Deferred tax on share based payments reserve	-	-	-	(1,366)	(1,366)
Balance at 1 January 2011	70	(2,797)	(19,418)	56,873	34,728
Foreign currency translation	-	-	(15,927)	-	(15,927)
Net gains on maturity of cash flow hedges recycled in the year	-	(3,675)	-	-	(3,675)
Net changes in fair value of derivatives and financial assets    designated as cash flow hedges	-	(13,590)	-	-	(13,590)
Disposal of available-for-sale financial assets	(70)	-	-	-	(70)
Share-based payments charge (note 25)	-	-	-	23,056	23,056
Transfer during the year (note 25)	-	-	-	17,974	17,974
Shares vested during the year (note 25)	-	-	-	(33,776)	(33,776)
Deferred tax on share-based payments reserve	-	-	-	(3,082)	(3,082)
Balance at 31 December 2011	-	(20,062)	(35,345)	61,045	5,638

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$3,979,000 (2010: US$16,764,000) relating to foreign currency forward contracts and financial assets designated as cash flow hedges have been recognised in cost of sales and a realised net loss of US$304,000 (2010: US$152,000) was deducted from revenues in respect of oil derivatives.

The forward currency points element and ineffective portion of derivative financial instruments relating to forward currency contracts and gains on un-designated derivatives amounting to a net loss of US$5,881,000 (2010: US$3,409,000 loss) 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 2011 of US$17,974,000 (2010 bonus of US$12,750,000) which has been voluntarily elected or mandatorily obliged to be settled in shares during the year (note 25).

27 Interest-bearing loans and borrowings

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

		31 December 2011 Actual interest rate %	31 December 2010 Actual interest rate %	Effective interest rate %	Maturity	2011 US$'000	2010 US$'000
Current
Bank overdrafts	(i)	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	36,932	28,908
Other loans:
Current portion of term loan	(ii)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	3.16% to 3.96% (2010: 3.26% to 4.14%)		17,119	14,241
Current portion of term loan	(iii)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	1.67% to 3.55% (2010: 2.01% to 3.91%)		6,660	4,286
						60,711	47,435
Non-current
Term loan	(ii)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	3.16% to 3.96% (2010: 3.26% to 4.14%)	2012-2013	12,433	30,576
Term loan	(iii)	US/UK LIBOR + 0.875%	US/UK LIBOR + 0.875%	1.67% to 3.55% (2010: 2.01% to 3.91%)	2012-2013	7,133	13,809
						19,566	44,385
Less:
Debt acquisition costs net of    accumulated amortisation and    effective rate adjustments						(3,116)	(4,159)
						16,450	40,226

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

(i) 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.

(ii) Term loan

This term loan at 31 December 2011 comprised drawings of US$14,857,000 (2010: US$23,057,000) denominated in US dollars and US$14,695,000 (2010: US$21,760,000) denominated in sterling. Both elements of the loan are repayable over a period of three years ending 30 September 2013.

(iii) Term loan

This term loan at 31 December 2011 comprised drawings of US$10,075,000 (2010: US$13,203,000) denominated in US dollars and US$3,718,000 (2010: US$4,892,000) denominated in sterling. Both elements of the loan are repayable over a period of three years ending 30 September 2013.

The Group's credit facilities and debt agreements contain covenants relating to interest and net borrowings cover. 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.

28 Provisions

	Other long-term employment benefits provision US$'000	Provision for decommissioning US$'000	Other provisions US$'000	Total US$'000
At 1 January 2011	40,204	3,676	1,561	45,441
Additions during the year	12,861	2,649	1,237	16,747
Unused amounts reversed	-	(835)	-	(835)
Paid in the year	(3,411)	-	-	(3,411)
Unwinding of discount	1,452	167	-	1,619
At 31 December 2011	51,106	5,657	2,798	59,561

Other long-term employment benefits provision

Labour laws in the United Arab Emirates 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 based on their final salary and number of years service. All amounts are unfunded. The long-term employment benefits provision is based on an internally produced end of service benefits valuation model with the key underlying assumptions being as follows:

	Senior employees	Other employees
Average number of years of future service	5	3
Average annual % salary increases	6%	4%
Discount factor	4%	4%

Senior employees are those earning a base of salary of over US$96,000 per annum.

Discount factor used is the local Dubai five-year Sukuk rate.

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 4.16% on PM304 (2010: 3.80%) and 5.25% on Chergui (2010: 5.25%). 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 2026 on PM304 and in 2018 on Chergui.

Other provisions

This represents amounts set aside to cover claims against the Group which will be settled via the captive insurance company Jermyn Insurance Company Limited.

29 Other financial liabilities

	2011 US$'000	2010 US$'000
Other financial liabilities - non-current Deferred consideration payable	12,889	11,279
Finance lease creditors (note 32)	10,644	-
Fair value of derivative instruments (note 34)	-	174
Other	9	-
	23,542	11,453
Other financial liabilities - current Deferred consideration payable	3,379	24,595
Interest payable	107	9
Fair value of derivative instruments (note 34)	22,466	12,197
Finance lease creditors (note 32)	5,392	-
Other	333	253
	31,677	37,054

Included in deferred consideration payable above is an amount payable of US$6,466,000 (2010: US$6,556,000) relating to the Group's investment in an associate (note 14).

30 Trade and other payables

	2011 US$'000	2010 US$'000
Trade payables	476,851	278,383
Advances received from customers	769,637	412,044
Accrued expenses	414,725	251,512
Other taxes payable	24,571	12,755
Other payables	58,398	66,742
	1,744,182	1,021,436

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$29,200,000 (2010: US$6,170,000). Also included in other payables above is US$2,393,000 (2010: 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 14).

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.

31 Accrued contract expenses

	2011 US$'000	2010 US$'000
Accrued contract expenses	1,268,818	1,272,942
Reserve for contract losses	-	2,523
	1,268,818	1,275,465

The reserve for contract losses in the prior year was to cover costs in excess of revenues on certain contracts.

 

32 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 2011, the Group had letters of credit of US$5,995,000 (2010: US$2,984,000) and outstanding letters of guarantee, including performance, advance payments and bid bonds, of US$2,185,385,000 (2010: US$2,951,553,000) against which the Group had pledged or restricted cash balances of, in aggregate, US$2,813,000 (2010: US$19,462,000).

At 31 December 2011, the Group had outstanding forward exchange contracts amounting to US$324,221,000 (2010: US$188,561,000).

These commitments consist of future obligations to either acquire or sell designated amounts of foreign currency at agreed rates and value dates (note 34).

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 17 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:

	2011 US$'000	2010 US$'000
Within one year	23,856	18,031
After one year but not more than five years	44,674	41,239
More than five years	48,987	76,914
	117,517	136,184

Included in the above are commitments relating to the lease of an office building extension in Aberdeen, United Kingdom of US$34,041,000 (2010: US$49,232,000).

Minimum lease payments recognised as an operating lease expense during the year amounted to US$37,272,000 (2010: US$35,625,000).

Long-term finance lease commitments are as follows:

	Future minimum lease payments US$'000	Finance cost US$'000	Present value US$'000
Land, buildings and leasehold improvements	17,371	1,335	16,036
The commitments are as follows:
Within one year	6,225	833	5,392
After one year but not more than five years	11,146	502	10,644
More than five years	-	-	-
	17,371	1,335	16,036

Capital commitments

At 31 December 2011, the Group had capital commitments of US$479,968,000 (2010: US$90,416,000) excluding the above lease commitments.

Included in the above are commitments in respect of Production Enhancement Contracts in Mexico on the Magallanes field of US$108,300,000 and Santuario field of US$116,900,000, costs to refurbish the Berantai FPSO of US$89,250,000 (2010: US$52,800,000), further appraisal and development of wells as part of Block PM304 in Malaysia amounting to US$110,600,000 (2010: US$7,269,000), commitments in respect of the Ticleni Production Enhancement Contract in Romania of US$25,000,000 (2010: US$21,046,000), commitments in respect of the construction of a new office building in United Arab Emirates of US$21,436,000 (2010: US$ nil) and commitments in respect of IT projects of US$6,171,000 (2010: US$9,281,000).

 

33 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 parties US$'000	Purchases from related parties US$'000	Amounts owed by related parties US$'000	Amounts owed to related parties US$'000
Joint ventures	2011	322,669	187,440	95,075	22,899
	2010	101,370	88,796	327	11,098
Associates	2011	14,118	-	4,000	-
	2010	-	-	-	-
Key management personnel interests	2011	-	1,591	-	267
	2010	-	1,688	-	612

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$1,411,000 (2010: US$1,601,000) 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$180,000 (2010: US$87,000) relating to client entertainment provided by a business owned by a member of the Group's key management.

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 91 to 105.

	2011 US$'000	2010 US$'000 As restated
Short-term employee benefits	19,807	17,381
Other long-term employment benefits	158	142
Share-based payments	8,114	4,159
Fees paid to Non-executive Directors	836	609
	28,915	22,291

Comparatives have been restated to include the invested portion of DBSP awards to be consistent with the current year presentation.

34 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 82 to 90.

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 point increase US$'000	100 basis point decrease US$'000	100 basis point increase US$'000	100 basis point decrease US$'000
31 December 2011	(516)	516	-	-
31 December 2010	(710)	710	-	-

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

Year ended 31 December 2011

	Within 1 year US$'000		1-2 years US$'000		2-3 years US$'000		3-4 years US$'000		4-5 years US$'000		More than 5 years US$'000		Total US$'000
Financial liabilities
Floating rates Bank overdrafts (note 27)	36,932	-		-		-		-		-		36,932
Term loans (note 27)	23,779	19,566		-		-		-		-		43,345
	60,711	19,566		-		-		-		-		80,277
Financial assets
Floating rates Cash and short-term deposits (note 22)	1,572,338	-		-		-		-		-		1,572,338
Restricted cash balances (note 17)	2,506	307		-		-		-		-		2,813
	1,574,844	307		-		-		-		-		1,575,151

Year ended 31 December 2010

	Within 1 year US$'000	1-2 years US$'000	2-3 years US$'000	3-4 years US$'000	4-5 years US$'000	More than 5 years US$'000	Total US$'000
Financial liabilities
Floating rates Bank overdrafts (note 27)	28,908	-	-	-	-	-	28,908
Term loans (note 27)	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 22)	1,063,005	-	-	-	-	-	1,063,005
Restricted cash balances (note 17)	19,196	266	-	-	-	-	19,462
	1,082,201	266	-	-	-	-	1,082,467

Financial liabilities in the above table are disclosed gross of debt acquisition costs and effective rate adjustments of US$3,116,000 (2010: US$4,159,000).

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 2011, the Group held no derivative instruments, designated as cash flow hedges in relation to floating rate interest-bearing loans and borrowings (2010: nil).

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.

	2011 % of foreign currency denominated items	2010 % of foreign currency denominated items
Revenues	36.4%	41.6%
Costs	57.7%	62.2%
Current financial assets	32.5%	34.8%
Non-current financial assets	0.0%	0.0%
Current financial liabilities	34.7%	51.2%
Non-current financial liabilities	54.2%	59.4%

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:

	2011		2010
	Average rate	Closing rate	Average rate	Closing rate
Sterling	1.60	1.55	1.54	1.56
Kuwaiti dinar	3.62	3.59	3.49	3.55
Euro	1.40	1.30	1.32	1.34

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 US$'000	-10% US  dollar rate decrease US$'000	+10% US dollar rate increase US$'000	-10% US dollar rate decrease US$'000
31 December 2011	(3,814)	3,814	49,659	(49,659)
31 December 2010	(3,750)	3,750	6,272	(6,272)

Derivative instruments designated as cash flow hedges

At 31 December 2011, the Group had foreign exchange forward contracts as follows:

	Contract value		Fair value (undesignated)		Fair value (designated)		Net unrealised gain/(loss)
	2011 US$'000	2010 US$'000	2011 US$'000	2010 US$'000	2011 US$'000	2010 US$'000	2011 US$'000	2010 US$'000
Euro purchases	222,617	171,072	-	(1,794)	(9,748)	(2,046)	(7,729)	(1,827)
Sterling purchases	40,156	14,405	-	(135)	(1,815)	1,583	(1,425)	1,695
Yen (sales) purchases	(4,030)	1,721	30	128	29	76	44	117
Singapore dollar purchases	45,683	-	(471)	-	(1,302)	-	(1,180)	-
Swiss francs purchases	-	1,363	-	-	-	175	-	14
							(10,290)	(1)

The above foreign exchange contracts mature and will affect income between January 2012 and July 2013 (2010: between January 2011 and July 2013).

At 31 December 2011, the Group had cash and short-term deposits designated as cash flow hedges with a fair value loss of US$9,440,000 (2010: US$1,633,000 loss) as follows:

	Fair value		Net unrealised gain/(loss)
	2011 US$'000	2010 US$'000	2011 US$'000	2010 US$'000
Euro cash and short-term deposits	180,520	15,730	(9,206)	(1,798)
Sterling cash and short-term deposits	15,098	2,086	(377)	(120)
Yen cash and short-term deposits	3,251	4,510	145	278
Swiss francs cash and short-term deposits	-	660	-	7
			(9,440)	(1,633)

During 2011, changes in fair value losses of US$14,117,000 (2010: losses US$19,456,000) relating to these derivative instruments and financial assets were taken to equity and US$3,979,000 of gains (2010: US$16,764,000 gains) were recycled from equity into cost of sales in the income statement. The forward points and ineffective portions of the above foreign exchange forward contracts and loss on
un-designated derivatives of US$5,881,000 (2010: US$3,409,000 loss) were 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 & 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 and zero cost collars hedging oil production of 163,766 barrels (bbl) (2010: 176,400 bbl) with maturities ranging from January 2012 to December 2012. In addition, fuel oil swaps were also entered into for hedging gas production of 21,100 metric tons (MT) (2010: 43,750MT) with maturities from January 2012 to September 2012.

The fair value of oil derivatives at 31 December 2011 was US$636,000 liability (2010: US$1,163,000 liability) with net unrealised losses deferred in equity of US$332,000. During the year, losses of US$304,000 (2010: US$152,000 loss) were recycled from equity into the consolidated income statement on the occurrence of the hedged transactions and a gain in the fair value recognised in equity of US$527,000 (2010: US$1,163,000 loss).

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$/bbl increase US$'000	-10 US$/bbl decrease US$'000	+10 US$/bbl increase US$'000	-10 US$/bbl decrease US$'000
31 December 2011	(1,050)	1,050	(1,716)	1,716
31 December 2010	(194)	194	(802)	802

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 2011, the Group's five largest customers accounted for 47.1% of outstanding trade receivables and work in progress (2010: 72.0%).

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 primary objective is to ensure sufficient liquidity to support future growth. Our Integrated Energy Services strategy includes the provision of financial capital and the potential impact on the Group's capital structure is reviewed regularly. The Group is not exposed to any external capital constraints. The maturity profiles of the Group's financial liabilities at 31 December 2011 are as follows:

Year ended 31 December 2011

	6 months or less US$'000	6-12 months US$'000	1-2 years US$'000	2-5 years  US$'000	More than 5 years US$'000	Contractual undiscounted cash flows US$'000	Carrying amount US$'000
Financial liabilities
Interest-bearing loans and borrowings	48,346	12,365	19,566	-	-	80,277	77,161
Finance lease creditors	-	6,225	11,146	-	-	17,371	16,036
Trade and other payables (excluding advances    from customers)	958,936	15,609	-	-	-	974,545	974,545
Due to related parties	23,166	-	-	-	-	23,166	23,166
Deferred consideration	1,554	1,975	13,094	-	-	16,623	16,268
Derivative instruments	19,423	3,043	-	-	-	22,466	22,466
Interest payable	107	-	-	-	-	107	107
Interest payments	356	263	158	-	-	777	-
	1,051,888	39,480	43,964	-	-	1,135,332	1,129,749

Year ended 31 December 2010

	6 months or less US$'000	6-12 months US$'000	1-2 years US$'000	2-5 years  US$'000	More than 5 years US$'000	Contractual undiscounted cash flows US$'000	Carrying amount 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

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:

	2011 US$'000	2010 US$'000
Cash and short-term deposits	1,572,338	1,063,005
Interest-bearing loans and borrowings (A)	(77,161)	(87,661)
Net cash (B)	1,495,177	975,344
Equity attributable to Petrofac Limited shareholders (C)	1,110,736	776,462
Profit for the year attributable to Petrofac Limited shareholders (D)	539,425	557,817
Gross gearing ratio (A/C)	6.9%	11.3%
Net gearing ratio (B/C)	Net cash position	Net cash position
Shareholders' return on investment (D/C)	48.6%	71.8%

 

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
	2011 US$'000	2010 US$'000	2011 US$'000	2010 US$'000
Financial assets
Cash and short-term deposits	1,572,338	1,063,005	1,572,338	1,063,005
Restricted cash	2,813	19,462	2,813	19,462
Available-for-sale financial assets	-	101,494	-	101,494
Seven Energy warrants	17,616	11,969	17,616	11,969
Forward currency contracts - designated as cash flow hedge	8,376	7,961	8,376	7,961
Forward currency contracts - undesignated	177	1,234	177	1,234
Financial liabilities
Interest-bearing loans and borrowings	77,161	87,661	80,277	91,820
Deferred consideration	16,268	35,874	16,268	35,874
Oil derivative	636	1,163	636	1,163
Forward currency contracts - designated as cash flow hedge	21,212	8,173	21,212	8,173
Forward currency contracts - undesignated	618	3,035	618	3,035

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 derivatives. The fair value of warrants over equity instruments in Seven Energy has been calculated using a Black Scholes option valuation model (note 14). 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 2011

	Tier 1 US$'000	Tier 2 US$'000	2011 US$'000
Financial assets
Seven Energy warrants	-	17,616	17,616
Forward currency contracts - designated as cash flow hedge	-	8,376	8,376
Forward currency contracts - undesignated	-	177	177
Financial liabilities
Forward currency contracts - designated as cash flow hedge	-	21,212	21,212
Forward currency contracts - undesignated	-	618	618
Oil derivative	-	636	636

Year ended 31 December 2010

	Tier 1 US$'000	Tier 2 US$'000	2010 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
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

 

35 Subsidiaries and joint ventures

At 31 December 2011, the Group had investments in the following subsidiaries and incorporated joint ventures:

		Proportion of nominal value of issued shares controlled by the Group
Name of company	Country of incorporation	2011	2010
Trading subsidiaries
Petrofac Inc.	USA	100	*100
Petrofac International Ltd	Jersey	*100	*100
Petrofac Energy Development UK Limited	England	*100	*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 Training International Limited	Jersey	*100	*100
Petroleum Facilities E & C Limited	Jersey	*100	*100
Jermyn Insurance Company Limited	Guernsey	*100	*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
PFMAP Sendirian Berhad	Malaysia	100	100
Petrofac (Malaysia-PM304) Limited	England	100	100
Petrofac South East Asia Pte Ltd	Singapore	100	-
Petrofac Netherlands Cooperatief U.A.	Netherlands	100	-
Petrofac Netherlands Holding B.V.	Netherlands	100	-
Petrofac Treasury B.V.	Netherlands	100	-
Petrofac Kazakhstan B.V.	Netherlands	100	-
PTS B.V	Netherlands	100	-
Petrofac Mexico SA de CV	Mexico	100	-
Petrofac Mexico Servicios SA de CV	Mexico	100	-
Petrofac Energy Developments Sdn Bhd	Malaysia	100	-
Petrofac FPF003 Pte Ltd	Singapore	100	-
Petrofac FPF004 Limited	Jersey	100	-
Petrofac FPF005 Limited	Malaysia	100	-
Petrofac GSA Limited	Jersey	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
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
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
		Proportion of nominal value of issued shares controlled by the Group
Name of company	Country of incorporation	2011	2010
Trading subsidiaries
Sakhalin Technical Training Centre	Russia	80	80
Petrofac Norge AS	Norway	100	100
SPD Group Limited	British Virgin Islands	100	51
SPD UK Limited	Scotland	100	51
SPD LLC	United Arab Emirates	**49	**25
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
Caltec Limited	England	100	100
i Perform Limited	Scotland	100	100
Petrofac FPF1 Limited	Jersey	100	100
Petrofac Platform Management Services Limited	Jersey	100	100
Petrokyrgyzstan Limited	Jersey	100	100
Scotvalve Services Limited	Scotland	100	100
Stephen Gillespie Consultants Limited	Scotland	100	100
CO2DeepStore Limited	Scotland	100	100
CO2DeepStore Holdings Limited	Jersey	100	100
CO2DeepStore (Aspen) Limited	England	100	100
TNEI Services Limited	England	100	100
Petrofac E&C Sdn Bhd	Malaysia	100	100
Petrofac FPSO Holding Limited	Jersey	100	100
The New Energy Industries Limited	England	100	100
Petrofac Information Services Private Limited	India	100	100
Petrofac Solutions & Facilities Support S.R.L	Romania	100	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
China Petroleum Petrofac Engineering Services Cooperatif U.A.	Netherlands	49	-
Berantai Floating Production Limited	Malaysia	51	-
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
Petrofac Services Inc	USA	*100	*100
Petrofac Training (Trinidad) Limited	Trinidad	100	100
Petrofac ESOP Trustees Limited	Jersey	*100	*100

* Directly held by Petrofac Limited

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

The Company's interest in joint venture operations are disclosed on page 133.

 

END

 

 

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