Report Concludes PTTEP, Regulator at Fault for Montara Spill

Rigzone Staff

PTTEP Australasia (PTTEP AA), a subsidiary of Thailand-based operator PTT Exploration and Production (PTTEP), and the Northern Territory Designated Authority are both at fault for the Montara oil spill, the largest spill to occur offshore Australia in over 20 years, the Australian government concluded in its Report of the Montara Commission of Inquiry and a draft Government response released Nov. 24.
The Inquiry was set up to investigate the likely causes of the uncontrolled release of oil and gas from the Montara Wellhead Platform in the Timor Sea on Aug. 21, 2009 and make recommendations to the Government on how to prevent future incidents. The inquiry found that the blowout was likely caused by defective installation of a cemented shoe in the casing of the H1 well in March 2009, which was intended to serve as a primary barrier against a blowout.
The pumping of displacement fluid beneath the float collar, which resulted in over-displacement from the casing shoe track and the area outside the casing shoe, also contributed to the blowout by weakening the cemented shoe's integrity as a barrier. PTTEP workers and Atlas workers both onshore and offshore failed to recognize that a wet shoe had been created from cementing operations and to test the cemented casing shoe. Deficiencies in PTTEP's management system for communications and failure to assess risk also were noted as contributing factors.
A test would likely have confirmed the unreliability of the cemented casing shoe as a barrier, allowing for remedial action that would have prevented the blowout. Other factors that may have contributed to the blowout include using an incorrect volume of tail cement in cementing operations. PTTEP also failed to install a casing pressure containing anti-corrosion caps (PCCC) on the 13-3/8 casing string on the H1 well and removed a 9-5/8 inch PCCC and failure to reinstall another PCCC on the 9-5/8 casing string in August 2009. These actions left the well without a secondary barrier against a blowout.
According to the report, the designated authority, the Northern Territory Department of Resources, should not have approved the Phase 1B drilling program for the Montara field in July 2009, and also adopted a "minimalist approach" to its regulatory responsibilities. The way the regulatory conducted its responsibilities gave little chance of discovering PTTEP AA's poor practices. "In this case, the regulatory dog did not bark," the report said.
The Report contains 100 findings and 105 recommendations, which have implications for governments, regulators, and the offshore petroleum industry. The Government proposes accepting 92, noting 10, and not accepting three of the Report's recommendations.
Outlining the Government's draft response, Minister for Resources and Energy Martin Ferguson noted that it provides a comprehensive plan to tackle head on the tough policy challenges posed by the Montara incident.
"The fact is that we were lucky with Montara – no lives were lost, there were no serious injuries and the quick, coordinated response from governments, regulators and industry meant that the impact on the marine environment was minimal," Minister Ferguson said.
"We can't just turn our backs on this industry – it is too important to Australia's economic and energy security. What we can do – working together – is make Australia's offshore safety regime the best and safest in the world."
Ferguson said the report recognizes that while there is room for some improvements, the nation's regulatory regime is effective. "At the heart of this matter is the failure of the operator and the failure of the regulator to adhere to this regime. If either - or preferably both – PTTEP AA or the Northern Territory Designated Authority had done their jobs properly and complied with requirements, the Montara Blowout would never have happened.
The minister said the government would next consult with industry and other stakeholders to form the Government's final response. "A key aspect of this will be the Government's intention to move toward a single national offshore regulator – consistent with the Report's recommendations."
The Government will also move to legislate the polluter pays principle and the requirements for environmental monitoring, further strengthening environmental safeguards.
"I am confident that by working methodically and diligently through the implementation of the remaining recommendations we will achieve a result that benefits all and maintains the industry's social license to operate."
In a statement released today, PTTEP said its subsidiary PTTEP AA has been working on an Action Plan over the past 12 months to prove PPTEP AA's capability to be an operator in Australia. The key elements of the Action Plan covers the improvement of the SSHE management system; development of a drilling and a competency management system; and the interfaces between PTTEP Headquarter in Bangkok and PTTEP AA in Perth.
Some elements of this Action Plan have been accomplished or are in progress. PTTEP noted that the clarification of well integrity barriers of the Montara Wells has already been certified by the Australian authorities, and the review of PTTEP AA Drilling organization to improve efficiency and safety is almost complete.
Anon Sirisaengtaksin, President and CEO of PTTEP said, "PTTEP is confident that PTTEP AA will continue its development of Montara since we have developed the Action Plan and implemented it for 12 months. We regularly updated its progress to the Australian Government. We therefore reaffirm our confidence that this extensive implementation can regain the Australian Government trust in PTTEP AA capability as a prudent Operator with International best practice. We also commit to continue our investment in Australia in long term."

Australia rebukes Thailand's PTTEP to tighten oil regulation after massive oil spill

Thai state oil company announced Tuesday it will buy 40% of Statoil’s Canadian oilsands project for $2.3B US

 

 

 

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A handout photograph shows the West Atlas oil rig and Montara well head platform on fire before the relief operation to pump heavy mud into the well was completed, off the northwest coast of Australia, in the morning of Tuesday, Nov. 3, 2009.

CANBERRA - Australia plans to tighten regulation of offshore oil exploration and review projects run by Thailand's PTT Exploration and Production after the nation's worst offshore oil spill last year.
An oil rig operated by the Thai company's Australian subsidiary caught fire off northwest Australia in August 2009 and spewed oil and condensate from the Montara wellhead for 74 days before it was stopped.
"Widespread and systemic shortcomings in PTTEP Australasia's procedures were a direct cause of the loss of well control," Resources Minister Martin Ferguson said on Wednesday as he released a report into the spill.
Ferguson's comments sent PTTEP shares 3.6 lower to a more than three week low against a slightly lower broader market.
On Tuesday, the Thai state oil company announced it is buying a minority stake in Statoil's Kai Kos Dehseh oilsands project near Fort McMurray.
The environmental impact of the spill and a leak in the Gulf of Mexico of a well operated by BP Plc have thrown a spotlight on drilling off Australia's coast, with environmentalists calling for a suspension of new projects.
The report blamed PTTEP Australasia for failing to follow safe practices, including having effective fail-safe mechanisms that would have prevented a blowout and fire on the platform.
Only one of two planned secondary well-control barriers was installed, the inquiry found. But it also blamed a minimalist approach by the Northern Territory area regulator, which meant authorities had little chance of discovering poor practices.
The incident caused no deaths, but Ferguson said he had ordered a review of PTTEP's Australian operations which could lead to cancellation of its exploration and development licence.
The review would be completed this year.
"The outcome of this process will assist me in forming a view as to whether the deficiencies in PTTEP Australasia's procedures as identified by the commissioner relate only to the Montara oilfield, or PTTEP's general performance," Ferguson said.
COMPANY SAYS FOLLOWED PLAN
The company operates seven exploration permits, five production licences, seven retention leases and has interests in other permits which it does not operate.
"We're confident that we did everything according to plan," PTTEP chief executive Anon Sirisaengtaksin told Reuters, adding the company was now awaiting the government's assessment of its Australian projects.
Ferguson said he had also accepted an inquiry recommendation that Australia establish a single national offshore exploration regulator, with new legislation setting it up by January 2012.
"Montara was the first major loss of well control in 25 years of safe offshore petroleum operations," he said. "We can't just turn our backs on this industry. It is too important to Australia's economic and energy security."
Environmental group WWF said the oil slick had killed sea life and damaged the fishing industry in neighbouring Indonesia and East Timor.
PTTEP, which on Tuesday announced a $2.3 billion deal to buy into a Canadian oilsands project, is being pursued by Indonesia's government for $2.4 billion in compensation over the spill. The company recorded about $319 million in expenses for the Montara cleanup and rig-damage costs during the second half of last year.
Australia was working closely with the United States in the wake of Montara and the catastrophic blowout on the Deepwater Horizon project in the Gulf of Mexico, Ferguson said, and would hold a conference next year to talk about industry changes.

Read more: http://www.calgaryherald.com/business/Australia+rebukes+Thailand+PTTEP+tighten+regulation+after+massive+spill/3878907/story.html#ixzz16HBCZSXH

Report blames rig operator for Australian spill

By ROD McGUIRK

CANBERRA, Australia
A Thai-owned oil rig operator could be banned from Australian waters after a government report on Wednesday blamed it and a lax regulator for Australia's worst ever oil spill that stained the coasts of Indonesia and East Timor last year.
Australia also plans to tighten regulations on its rapidly growing offshore oil and gas industry in response to the 11-week Montara oil field spill that began on Aug. 21 last year and the more disastrous explosion and spill at BP's Deepwater Horizon rig in the Gulf of Mexico that killed 11 workers on April 20.
Resources Minister Martin Ferguson told Parliament he is investigating whether deficiencies in procedures at the Montara oil field that was operated by a unit of Thailand's PTT Exploration & Production Plc. reflected the company's "general performance as an operator."
The investigation, to be completed this year, will help determine what action should be taken against the company which could include cancellation of its oil and gas production rights, Ferguson said.
The Thai company's Australian unit, PTTEP Australasia, holds five production licenses in Australia's waters including Montara but is not currently producing oil or gas from any of them.
The company would require new regulatory approval before it could resume production at Montara and has not yet made such an application.
PTTEP Australasia issued a statement Wednesday acknowledging the "deficiencies" identified by the report and said all managers and supervisors involved in the Montara drilling have been "removed from their positions."
It said it was implementing reforms that address the technical and governance problems identified in the report to "ensure the incident which occurred at Montara is never repeated."
Ferguson said the company could yet be charged over failure to comply with regulations and for endangering the 69 workers at Montara.
Australia's burgeoning offshore oil and gas industry oil earned energy companies 35.6 billion Australian dollars ($35 billion) in oil and gas revenue last year.
More than 400 barrels of oil a day flowed from the Montara well in the Timor Sea and stained the coasts of Indonesia and East Timor before mud pumped through a relief well shut off the deepwater spigot 11 weeks later.
Ferguson said there were similarities with the Gulf of Mexico disaster in that "you ... find, to a large extent, the same human failures."
Australia had worked closely with the U.S. government in formulating its response to both disasters, he said.
Halliburton, a Texas-based global oil field services provider, was the contractor that provided cement seals for both the Gulf of Mexico and Montara wells.
The Montara spill occurred because the underwater cement barrier designed to prevent oil blowouts failed.
But the government report found it would not be appropriate to criticize Halliburton.
Halliburton reported to PTTEP Australasia "a major ongoing problem" with the cement barrier, yet the rig operator's senior supervisor signed off on that report with the annotation: "good job well done," the government investigation found.
A U.S. national commission will report on Jan. 12 next year on the causes of the Gulf of Mexico disaster.
PTTEP paid $319 million for the clean up. Ferguson said the government planned to change the law to remove any doubt that companies responsible for any future leaks would be made to pay.
Indonesians were still seeking compensation, Ferguson said.
Environmental group WWF Australia reported that thousands of dead fish and clumps of oil had been found drifting near Indonesia's coastline more than two months after the well began leaking.
"PTTEP Australasia did not observe sensible oil field practice at the Montara field," Ferguson said.
"Other findings include that the widespread and systematic shortcomings of PTTEP Australasia procedures were a direct cause of the loss of well control," he said.
Ferguson said the field's regulator, the Northern Territory Department of Resource, was "not a diligent regulator and its minimalist approach to its regulatory responsibility gave it little chance of discovering these poor practices."
"Well control practices approved by the regulator would have been sufficient to prevent the loss of well control," he said. "However PTTEP Australasia did not adhere to these practices or its own well construction standards."
Ferguson said the government planned to replace state regulators with a national regulator of the offshore energy industry by January, 2012.
Ferguson said the industry did not have a "cowboy culture," with Montara the first major leak in Australian waters in 25 years during which more than 3,000 wells had been drilled.

Australia blames Thai oil rig firm for Timor Sea spill

Engineers tried to stop the leak for 10 weeks before succeeding

An Australian government inquiry has blamed the country's worst offshore oil leak on the rig's Thai owner.

The report said PTTEP Australasia, a unit of Thailand's PTT Exploration and Production, had failed to observe "sensible" practice.
The Australian Resources Minister told parliament the Thai firm should have its operating licence reviewed.
More than 400 barrels of oil a day spewed into the pristine Timor Sea off Australia's north coast for 10 weeks.
The oil hit the coast of Indonesia and East Timor.
Oil began leaking from the West Atlas rig and Montara wellhead platform north of Australia last August.
It was plugged on a fifth attempt in November 2009, after a slick had spread an estimated 90,000 sq km (35,000 sq miles).
Loss of control "The widespread and systematic shortcomings of PTTEP Australasia's procedures were a direct cause of the loss of well-control," Mr Ferguson said.
"Well-control practices approved by the regulator would have been sufficient to prevent the loss of well-control, however PTTEP Australasia did not adhere to these practices or its own well-construction standards," he said.
The company paid $390m (£245m) for the clean-up but the minister said he thought relevant laws needed to be strengthened to make absolutely clear that companies would be held responsible for any future leaks.
He also criticised the Australian government regulator which had pursued a "minimalist" approach in handling the emergency, saying the entire incident had been avoidable.
There was no immediate response from PTTEP.
The government ordered the inquiry while environmentalists have expressed concerns about the waters off Australia's north-west coast, which are home to whales and dolphins.

Santos-Petronas JV Charge Ahead with Gladstone Construction

Gladstone LNG Project
(Click to Enlarge)

SYDNEY (Dow Jones Newswires), Feb. 18, 2010
Santos said Thursday its joint venture with Petronas will officially green light the construction of their Gladstone liquefied natural gas project even if they don't find a second customer before a midyear deadline.
That means the only remaining obstacle to sanctioning the massive project is lawmaker approval of its associated environmental impact statement, or EIS, which Santos Chief Executive David Knox said is expected to occur in line with the joint venture's tight timetable.
Approval of the project would put the JV on track to release 3.6 million metric tons of LNG a year into global gas export markets by 2014. This should boost Santos' revenues astronomically but risks remain, with the jury still out on whether enough LNG demand and skilled labor exists to underpin the construction, and ongoing operation, of around a dozen planned Australian LNG projects.
Knox said he doesn't believe "there are any real showstoppers" to getting environmental approval but said "there are lots of issues that have come back to us that need consideration and discussion".
Approval of the EIS will largely determine the precise timing of a final investment decision, or FID, Knox said.
Santos on Thursday met analysts' expectations with a steep fall in annual profit, dragged down by lower oil and gas prices, but the LNG developments are more crucial to its prospects.
The company wants to sanction a doubling of the size of the Gladstone LNG project by mid-2011 but will need to find more customers and more gas to support the expansion.
For its first production train, Santos has already agreed to sell up to 3 million metric tons a year of LNG to Petronas, virtually underpinning its full 3.6 mtpa capacity.
"We would very much like to introduce another third party customer into the first train but it's not a requirement for us to move forward to FID," Knox told analysts on a conference call.
He shrugged off analysts' concerns that Santos isn't proving up its reserves quickly enough to support a second train, or that such concerns are complicating ongoing negotiations with buyers.
Santos still wants to divest another 9% of the project and Knox said that while it's getting "strong engagement" from potential takers, the stake sale component is slowing offtake negotiations.
Andrew Williams, an energy analyst at Credit Suisse, said an agreement with a more traditional, external LNG buyer would give the project more credibility, while a second train would greatly enhance its economics, given that extra trains are cheaper to build.
Williams, however, said Santos could face challenges convincing potential customers that it has enough feed gas to underpin a second train.
"Until coal seam gas establishes a bit of a track record in lager-scale sustained production, the buyers are probably going to want to see more reserves cover than you'd need for a more traditional project," Williams said.
To date, Santos has proven up just over half the reserves it will need to support a two-train project.
The company's funding outlook is also watched closely by analysts.
Despite it raising A$3 billion from a share issue last year, Santos is also involved in the construction of a US$15 billion project in Papua New Guinea, and has a more long-dated floating LNG venture with GDF Suez to consider.
While it had A$5.06 billion in cash and committed debt facilities at Dec. 31, JPMorgan reckons Santos will need to raise another A$2.15 billion if oil prices remain at US$75 a barrel and it can't sell the 9% stake in Gladstone LNG.
Knox said Santos won't provide a cost estimate for the project until it is sanctioned. He reiterated that Santos has assets in the Timor Sea that it could sell, among a number of "big levers" in its funding plans.
Last year, Knox said that there's a "sporting chance" that the company won't have to do another equity raising before 2014.
Santos' net profit for 2009 fell to A$434.0 million from A$1.65 billion in 2008 when earnings were artificially boosted by the sale of gas assets to Petronas, which currently has 40% of Gladstone LNG to Santos' 60%.
Underlying profit fell 53% to A$257.0 million.
Santos reiterated its 2010 production guidance of 51 million to 54 million barrels of oil equivalent and declared a final dividend of 20 cents a share, unchanged from last year.

Today's Trends: Chinese Oil Demand Rises in October

China's apparent oil demand in October rose 11.8% from a year ago to 37.88 million metric tons (mt), or an average of 8.95 million b/d, according to Platts' analysis of official data from the People's Republic of China. October demand was 3.1% higher than the September figure of 35.53 million mt. China's apparent oil demand in the first ten months of this year total 355.58 million mt, or an average of 8.57 million b/d, up 10.4% from the same period of 2009, Platts data showed.
Crude throughput volumes at Chinese refiners spiked to a collective total of 37.04 million mt or 8.76 million b/d on average in October, a historic high, and up 11.3% from a year ago, data from the country's National Bureau of Statistics showed. The sharp rise in crude processing contrasted with a significant drop in Chinese crude imports in October, to 16.39 million mt or 3.88 million b/d. This was the lowest monthly import figure to date in 2010 and 15.2% lower than the corresponding month of 2009.
Platts noted last month that China's net crude import and throughput figures for September indicated the country had likely put a little more than 5 million mt of crude into storage. More than 3 million mt of that crude surplus should have been used up in October with crude purchases during that month from overseas being the lowest so far this year while refiners' processing volumes were the highest. "An acute shortage of gasoil in China, attributed to a reduction in power supply, has headlined the oil industry in Asia and beyond for the past few weeks. The situation explains the 36% jump in China's net refined product imports in October from a month ago as well as refiners cranking up output to an all-time high," said Vandana Hari, Asia editorial director for Platts.

PTTEP Finds Natural Gas at Oliver Field in Timor Sea

PTTEP has found a commercially viable amount of natural gas at its exploration well Oliver-2 in the Timor Sea. The well has good potential for production with the floating liquefied natural gas technique, popularly known as FLNG. The success added more confidence to the company which is planning to invest 15,600 million baht in Australia this year.
Mr. Anon Sirisaengtaksin, CEO and President of PTT Exploration and Production Public Company Limited or PTTEP said that the company drilled Oliver-2 exploration well to the last depth of 3,233 meters and found a reservoir with a net gas thickness of 81 meters. This is a promising progress and it is likely to lead to the development of the FLNG business in the future.
The company in October 2009 bought the rights for the Block AC/P33, also known as Oliver field. The Australian Government has approved the transaction.
Block AC/P33 or Oliver field is in the Timor Sea Northwest of Australia covering an area of 421 square kilometers. It is about 30 kilometers away from Jabiru and Challis fields and is close to Audacious and Tenacious fields as well as other fields.
In 2010, PTTEP will continue to develop the Montara field and drill 2 to 3 exploration and appraisal wells in other fields. It will also conduct preliminary engineering studies on FLNG.

Woodside Puts Finishing Touches on Sunrise LNG Plan

Sunrise Project and Troubadour Project

PERTH (Dow Jones), Jan. 13, 2010
Australia's Woodside Petroleum Ltd. said Wednesday it's finalizing a development plan for the Sunrise liquefied natural gas field that will deliver "significant" benefits to the fledgling nation of East Timor.
But hopes of a quick approval for the project receded when East Timor said it will block proposals by the Woodside-led consortium to develop billions of dollars in disputed oil and gas.
According to an Associated Press report from Jakarta, East Timor Secretary of State Agio Pereira said proposals from Woodside to exploit the Sunrise field "would not be approved by the government."
The apparent hard line by East Timor, which wants an LNG plant built on its coastline, as opposed to Woodside's preference to pipe the gas to Darwin or use a floating LNG plant, raises the prospects of further delays.
Containing more than 5 trillion cubic feet of gas and associated condensate, Sunrise was discovered more than three decades ago. But its location in the Australia and Timor-Leste joint petroleum development area has frustrated several previous development attempts.
Under a treaty between the two countries -- and the Sunrise Joint Venture participants -- operator Woodside is required to develop the gas "to the best commercial advantage, consistent with good oil field practice," the company said in response to the AP story.
"Woodside and its Joint Venture participants are finalizing a development theme selection that will accord with key treaty requirements," the company said.
Following concept selection, Woodside will work with the Timor Leste and Australian governments to secure the timely approval of a development plan, it said.
Sunrise will deliver "significant social and economic benefits including petroleum revenues, taxes and training and employment opportunities to both Australia and Timor Leste," it added.
The project, which Woodside hopes to approve by 2011, is one of several big LNG developments planned by the Australian energy company in the next few years as it pushes to become a world-scale LNG player.
The others are an expansion of Woodside's partly built Pluto venture, and the Browse project, both offshore Western Australia.
Few analysts have factored Sunrise into their Woodside profit models because of the project's long history of false dawns.
East Timor wants to create a new petrochemical sector on its shores to create jobs and spur the economy.
But Woodside has ruled out landing the gas in East Timor, citing greater costs and the technical risks in having to build a pipeline across a deep ocean trench.
Woodside's Sunrise partners are ConocoPhillips (COP), Royal Dutch Shell (RDSB.LN) and Osaka Gas.

Eni Selects FPSO Glas Dowr for Kitan Operations

FPSO Glas Dowr

Bluewater has received a Letter of Award from ENI for the Chartering, Operation and Maintenance of the upgraded FPSO Glas Dowr, complete with mooring system, including provision of logistics and ancillary services at the Kitan field.

This Letter of Award remains subject to ENI obtaining approval for the contract from its co-venturers and from the East Timor government.

The contract has a minimum term of 5 years after start of production and can be extended up to 10 years.

The Kitan field is situated in the Joint Petroleum Development Area (JPDA), approximately 170 km south of the Timor-Leste coast and 500 km north of the Australian coast, and is located in around 344m of water depth. Kitan is located in the permit 06-105 of the JPDA, an area jointly administered by Timor-Leste and Australia. ENI serves as the operator of the field and holds a 40% working interest; Inpex Timor Sea Ltd holds 35%; and Talisman Resources Pty Ltd holds the remaining 25%.

Eni Reports $2.38B in 3Q Earnings

Eni announced its group results for the third quarter and first nine months of 2010 1 (unaudited).

Financial Highlights

• Adjusted operating profit: €4.11 billion in the quarter (up 31.7%); €12.57 billion in the first nine months (up 33.4%).
• Adjusted net profit: €1.70 billion ($2.36B) in the quarter (up 47.5%); €5.15 billion in the first nine months (up 35%).
• Net profit: €1.72 billion in the quarter (up 39%); €5.77 billion in the first nine months (up 45.1%).
• Cash flow: €2.41 billion in the quarter; €11.55 billion in the first nine months.

Operational Highlights

• Oil and natural gas production: 1.705 million barrels per day in the quarter, unchanged from 2009 on a comparable basis2 (up 0.7% in the first nine months).
• Natural gas sales: down 17.4% to 18.60 billion cubic meters in the quarter (down 9.3% in the first nine months).
• Achieved project milestones at the giant Zubair field in Iraq with first production expected to be reported in the next quarter. Started production at 8 fields out of the 12 planned for the year.
• Important exploration successes achieved in Venezuela, Angola and the UK.
• Awarded licenses in new high potential areas (Democratic Republic of Congo and Togo).

Paolo Scaroni, Chief Executive Officer, commented, "In the third quarter, Eni has achieved excellent results against a backdrop of ongoing challenging conditions in the gas market. We have moved forward in developing the giant Zubair oilfield in Iraq, and have delivered significant discoveries in Angola, Venezuela and in the North Sea as well as access to the Democratic Republic of Congo and Togo, two new countries with high mineral potential. We continue to invest for future growth in particular in E&P. I am confident that the 2010 full year results will show a marked improvement on last year."

Adjusted operating profit

Adjusted operating profit for the third quarter of 2010 was €4.11 billion, an increase of 31.7% compared with the third quarter of 2009. For the first nine months of 2010, adjusted operating profit was €12.57 billion, an increase of 33.4% from a year ago. These results reflected an excellent operating performance reported by the Exploration & Production division (an increase of 34.9% compared with the third quarter of 2009) driven by higher oil prices and the appreciation of the dollar vs. the euro. The downstream refining and petrochemical businesses both turned a profit reversing prior-year losses thanks to a more favorable trading environment. In contrast, the Gas & Power division reported sharply lower results as margins and sales volumes were hit by strong competitive pressures.

Adjusted net profit

Adjusted net profit for the third quarter of 2010 was €1.70 billion, up 47.5% compared with a year ago. In the first nine months of 2010, net profit increased by 35% to €5.15 billion. Both reporting periods benefited from an improved operating performance. In addition, the nine-month result was supported by higher profits reported by equity-accounted entities, while the quarterly result was helped by a lowered adjusted tax rate (down by 5 percentage points in the third quarter; it was stable in the first nine months).

Capital expenditures

Capital expenditures amounted to €2.85 billion for the quarter and €9.96 billion for the first nine months, mainly relating to the continuing development of oil and gas reserves, the upgrading of rigs and offshore vessels in the Engineering & Construction segment and of the gas transport infrastructures.

Cash flow

The main cash inflows for the quarter were net cash generated by operating activities amounting to €2,409 million (€11,548 million in the first nine months of 2010) and proceeds from divestments of €107 million (€902 million in the first nine months of 2010). These inflows were used to fund part of the financing requirements associated with capital expenditures of €2,851 million (€9,958 million in the first nine months of 2010) and the dividend payments to Eni's shareholders amounting to €1,811 million in the quarter, relating to the interim dividend for fiscal year 2010 (they amounted to €3,622 million in the nine months of 2010 and also included payment of balance for the 2009 dividend). Other dividend payments to non-controlling interests amounted to €354 million in the nine months. As a result, net borrowings 3 as of September 30, 2010 amounted to €25,261 million, representing an increase of €1,919 million from June 30, 2010 and €2,206 million from December 31, 2009.

Financial Ratios

Ratio of net borrowings to shareholders' equity including non-controlling interest – leverage 4 – slightly declined to 0.47 at September 30, 2010 from 0.46 as of December 31, 2009. However, compared to the first-half results the ratio decline was more marked as it was down by 0.06 points due to the depreciation of the US dollar against the euro as recorded at September 30, 2010 vs. June 30, 2010 (down by 11%) which caused a reduction in total equity of €3.4 billion in the period, in addition to increased net borrowings.
Return on Average Capital Employed (ROACE) 4 calculated on an adjusted basis for the twelve-month period to September 30, 2010 was 10.6% (10% at September 30, 2009).

Exploration & Production

In the third quarter of 2010, Eni's reported liquids and gas production was 1,705 kboe/d (1,768 kboe/d in the first nine months of 2010). This was calculated assuming a conversion rate of gas to barrel equivalent which was updated to 5,550 cubic feet of gas equals 1 barrel of oil (it was 5,742 cubic feet of gas per barrel in previous reporting periods; for further disclosures on this matter see page 6). On a comparable basis, i.e. when excluding the effect of updating the gas conversion rate, production was nearly unchanged on a quarter-to-quarter basis, while reporting an increase of 0.7% for the first nine months of 2010. Production increases were driven by continued organic growth achieved in Nigeria, Congo and Italy, new field start-ups and production ramp-up at fields which were started-up in 2009. Those trends were offset by planned facility downtime in Kazakhstan and Libya, and mature field declines mainly in the North Sea. The positive impact of lower OPEC restrictions offset lower entitlements in the Company's PSAs due to higher oil prices as well as lower gas uplifts in Libya as a result of oversupply conditions in the European market.

Gas & Power

Against the backdrop of strong competitive pressures both in the domestic and European markets, Eni's gas sales in the third quarter of 2010 registered a decrease of 17.4% compared with the third quarter of 2009, to 18.60 bcm. In the first nine months of 2010, gas sales declined by 9.3% from the first nine months of 2009 to 68.30 bcm. Sales volumes on the Italian market experienced the greatest declines (down by 2.32 bcm and 6.29 bcm, or 26% and 20.9% in the third quarter and in the first nine months of 2010, respectively) as all market segments posted volume losses. In the third quarter of 2010, sales in European markets declined by 11.2%, mainly in Belgium, Turkey and Hungary. In the first nine months of 2010 they were unchanged.

Refining & Marketing

Refining margins remained on a downward trend as sales prices of refined products failed to fully recover the cost of oil-based feedstock due to weak underlying fundamentals (sluggish demand, excess capacity and high inventory levels). In the third quarter of 2010, the marker Brent margin was $2.09 (down $0.25 per barrel in the quarter, or 10.7%, and down $1.13 per barrel, or 30.1%, in the first nine months). Eni's margins in the same period profited from a slight re-opening of light-heavy crude differentials in the Mediterranean area and from the fact that inland refineries benefited from higher premium on final prices compared to exporting refineries (CIF vs. FOB spreads). Also the appreciation of the dollar over the euro helped Eni's realized margins.
Volumes of refined products marketed on the Italian network declined by 3.4% and 4.6% in the quarter and first nine months of 2010, respectively. The performance was affected by weak domestic consumption of fuels and increasing competitive pressures causing Eni's market share to drop by almost one percentage point to 30.7% in the quarter. On the positive side, volumes marketed on the European markets increased by 13.8% and 4.4% in the third quarter and first nine months respectively benefiting in the quarter from the purchase of a network of service stations in Austria and an improved performance in Eastern Europe.

Currency

Results of operations were helped by the depreciation of the euro vs. the US dollar, down 9.8% and 3.6% in the third quarter and first nine months of 2010, respectively.

Portfolio developments

Start-up of the Zubair project in Iraq

Development activity has progressed at the giant Zubair oilfield in Iraq throughout the year and all project milestones have been achieved in line with contract arrangements. The Company expects to book its share of production in the year. Eni with a 32.8% interest, leads the consortium in charge of developing the field over 20 years targeting a production plateau of 1.2 mmbbl/d over the next six years.

Main production start-ups

Main production start-ups for the quarter were Arcadia 1 and Tuna in Egypt and Morvin in Norway, reaching production at 8 out of the 12 fields planned for the year.

Acquisition of exploration assets in the Democratic Republic of Congo

On August 16, 2010, Eni signed an agreement with UK-based Surestream Petroleum to acquire a stake of 55% and operatorship in the Ndunda block located in the Democratic Republic of Congo. The agreement has already been sanctioned by the relevant authorities and marks the implementation of the strategic partnership signed with the Democratic Republic of Congo in August 2009 to cooperate in developing the Country's oil resources.

Exploration Activities

In the third quarter of 2010, significant exploratory success was achieved in Venezuela with the appraisal well Perla 3 (Eni 50%), Angola with the exploratory wells Cabaca South East-2 and Mpungi 2 located in the 15/06 offshore block (Eni 35%, operator) and United Kingdom with the appraisal well Culzean 2.

Developments in the Hewett area

In October 2010, as part of the development project intended to build an offshore storage facility in the Hewett area located in the North Sea basin, Eni was granted from the relevant British authorities all the necessary permits to use the Deborah field as a storage site, as well a gas storage license. A final investment decision of the project is expected to be made by the first quarter of 2011.

Divestment of assets in the Exploration & Production division

On October 19, 2010, with a view to rationalizing its upstream portfolio, Eni closed the divestment of the entire share capital of its subsidiary Padana Energia to Gas Plus. The divested subsidiary includes exploration leases and concessions for developing and producing oil and natural gas in Northern Italy. Cash consideration for the deal amounted to €179 million, subject to a possible adjustment of up to €25 million related to achieving certain production targets at assets under development. Further price adjustments are foreseen in connection with appraising the underlying exploration potential. The agreement also encompasses, on the part of Gas Plus a call option to purchase 100% of Eni's wholly-owned subsidiary Adriatica Idrocarburi, which owns oil and gas assets in Central Italy. The option expires on November 30, 2010.

European Commission's investigations on players active in the natural gas sector

On September 29, 2010, the European Commission resolved to accept certain commitments presented by Eni to settle an antitrust proceeding without the ascertainment of any illicit behavior and consequently without imposition of any fines or sanctions. The proceeding related to alleged anti-competitive behavior in the natural gas market ascribed to the Company, associated with an alleged unjustified refusal to grant access to the TAG (Austria) and TENP/Transitgas (Germany/Switzerland) pipelines, connected with the Italian gas transport system. The commitments presented by Eni which have become mandatory following the Commission's decision, include the divestment of Eni's interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines and associated carrier companies. Given the strategic importance of the Austrian Tag gas pipeline, which transports gas from Russia to Italy, Eni has negotiated a solution with the Commission which calls for the transfer of its stake to an entity controlled by the Italian State. The Company will take all the necessary steps to execute those commitments in accordance with such terms and time schedules as agreed upon with the Commission (a non-confidential version of the agreed commitments will be released subject to the Commission's consent).
As a result of the European Commission's approval of Eni's divestment plan, as of September 30, 2010, assets and liabilities of the interested Eni entities (which include both controlling and non-controlling shareholdings in 7 entities) have been reclassified to the balance-sheet line item "assets held for sale".

Outlook

In what remains an uncertain and volatile energy environment, Eni forecasts a modest improvement in global oil demand and a Brent price of 77 $/barrel for the full year 2010. Against this backdrop, key volumes trends for the year are expected to be the following:

• Production of liquids and natural gas is forecast to be in line with 2009 (production in 2009 was 1.769 million boe/d). This estimate is based on the Company's assumption for a Brent price of 77 $/barrel for the full year, the same level of OPEC restrictions as in the first nine months of 2010 and asset disposals underway. It excludes the effect of updating the gas conversion rate. Growth will be driven by continuing field start-ups, mainly in Italy, Congo and Norway and marginally by the Zubair project in Iraq, as well as production ramp-up at the Company's recently started fields, mainly in Nigeria and Angola. These additions will be offset by mature field declines, lower gas uplifts in Libya due to oversupply conditions on the European market and the rescheduling of certain projects expected in the Gulf of Mexico as a consequence of the accident at the BP-operated Macondo well;
• Worldwide gas sales are forecasted to decrease compared with 2009 (approximately 104 bcm were achieved in 2009). Increasing competitive pressures, mainly in Italy, are expected to be partly offset by an anticipated recovery in European gas demand as well as a benefit associated with integrating Distrigas operations;
• Regulated businesses in Italy will benefit from the pre-set regulatory return on new capital expenditures and cost savings from integrating the full chain of transport, storage and distribution activities;
• Refining throughputs on Eni's account are planned to be in line with 2009 (actual throughputs in 2009 were 34.55 mmtonnes), due to higher rates of capacity utilization at Eni's refineries and entry into operation of a new hydrocracking unit at the Taranto refinery, offset by lowered volumes on third party refineries reflecting the Company's decision to terminate certain processing agreements;
• Retail sales of refined products in Italy and the rest of Europe are expected to decline slightly from 2009 (12.02 mmtonnes in 2009) reflecting sluggish consumption. Marketing initiatives are planned in order to support sales volumes and margins in the Italian retail market and to develop the Company's market share in European markets;
• The Engineering & Construction business is expected to see solid results due to a robust order backlog.

In 2010, management plans to slightly increase capital expenditures compared with 2009 (€13.69 billion was invested in 2009) with the aim of optimizing production and taking into account the impact of the appreciation of the US dollar over the euro. Capital expenditures will mainly be directed to the development of oil and natural gas reserves, exploration projects, the upgrading of construction vessels and rigs, and the upgrading of the natural gas transport infrastructure. The Company expects that the divestment of Eni's interests in the German TENP, in the Swiss Transitgas and in the Austrian TAG gas pipelines may be finalized by mid-2011, as financing, legal and technical due diligence is ongoing. Management forecasts that ratio of net borrowings to total equity (leverage) at year-end will be at the same level as at 2009 year-end supported by the effect of certain defined measures, a part of which has been already implemented throughout the course of the year.

Eni Confirms Another Perla Discovery

Eni on Monday announced the successful results of the Perla 3 well, located in the Cardon IV Block, in the shallow water of the Gulf of Venezuela. This well confirms Perla as a world-class supergiant gas discovery, one of the most significant in recent years and the largest ever in Venezuela, upgrading current estimates of gas in place to over 14 Tcf (2.5 billion barrels of oil equivalent).
Perla 3, drilled in 70 m of water depth, encountered 675 ft (210 m) of net pay carbonate sequence with the same hydraulic regime as the discovery well and with excellent reservoir characteristics, confirmed by the 730 ft (225m) of bottom hole cores that have been recovered.
During the production test, the well flowed 68 million scf per day of gas and 1,350 barrels of condensate per day, highlighting the high productivity of this reservoir.
The Cardon IV Block is currently licensed and operated by a Joint Operating Company named Cardon IV S.A. which is 50% owned by Eni and 50% by Repsol. The Venezuelan state company Petroleos de Venezuela S.A. (PDVSA) owns a 35% back-in right to be exercised in the development phase, and at that time Eni and Repsol will each hold a 32.5% interest in the project, which will then be jointly operated by the three companies.
Cardon IV plans to continue the drilling campaign with another well, Perla 4, which will follow Perla 3 to target additional potential reserves in the untested northern sector of the structure.
Eni and Repsol have already begun, together with PDVSA, to evaluate options for fast track development Perla through an early production phase of 300 million scf per day, targeted to start-up in mid 2013. The early production phase could include utilization of the wells already successfully drilled and the installation of light offshore platforms linked, through a gas pipeline, to a Central Processing Facility located onshore.
Eni is also present in Venezuela through its participation in Petrosucre, the Operating Company which runs the Corocoro Field (PDVSA 74%, Eni 26%) with a daily equity production of approximately 10,000 barrels of oil per day, and in Petrolera Guiria (PDVSA 64.25%, Eni 19.5%, Ineparia 16.25%) which operates the discovery of Punta Sur. Furthermore, Eni signed an agreement with PDVSA to develop Junin-5 heavy oil block, located in the Faja of Orinoco, which holds 35 billion barrels of certified oil in place. PDVSA will hold 60% and Eni 40% in the Junin-5 venture, which will be jointly operated.

Far East Energy Reports 7 Tcf of CBM Gas in Shouyang Block

Shouyang Block

Far East Energy reported the results of an independent engineering report prepared by Netherland, Sewell & Associates estimating the total coalbed methane Original Gas-in-Place (OGIP) in Far East Energy's Shouyang Block situated in Shanxi Province, China.
The report covers three target coal seams (the Nos. 3, 9 and 15) and concludes with a best estimate of Original Gas-in-Place of 7.0 trillion cubic feet (Tcf) of coalbed methane (CBM) gas and a high estimate of 8.5 Tcf covering the 487,000 acres under the company's Shouyang Production Sharing Contract (PSC). This is the first time the entire Shouyang Block has been assessed by a third-party engineering firm.
"We are pleased to receive this report on Original Gas-in-Place for the Shouyang PSC," said Michael R. McElwrath, CEO and President of Far East Energy. "This report is a clear indicator of increased potential of the Shouyang Block, and we are excited about the results. As previously announced, this NSAI Original Gas-in-Place report will be followed, subsequent to year-end, by a report covering SEC reserves in the Shouyang Block calculated as of December 31, 2010, and gas sales are expected to begin at that time, as we continue to tick off milestones. All of this comes at a time when, based on current exchange rates, the pricing of our natural gas in China is approximately $6.00 to $6.45 per Mcf, which includes enacted and announced government subsidies and compares quite favorably to the November 3 Henry Hub US natural gas price of $3.35 per Mcf."
Far East Energy previously received data in 2003 from ConocoPhillips for the northern 204,000 acres of the Shouyang Block estimating Original Gas-in-Place at a low of 3.9 Tcf, a median of 4.8 Tcf, and a high of 6.1 Tcf. The current NSAI report estimates OGIP at a low of 5.4 Tcf, a best estimate of 7.0 Tcf and a high of 8.5 Tcf

Baker Hughes Opens New Facility in Australia Baker Hughes

Baker Hughes has opened a new facility in Welshpool, Australia, to meet growing demand and increased oilfield activity in Australia. Three of the company’s service lines–pumping services, tubular services, and process and pipeline services–are now housed in the new 340,000-square-foot facility.
Major growth in the region prompted the company to expand its presence and increase personnel nearly fourfold during the past three years. Earlier this year, Chevron Pty Ltd awarded Baker Hughes a contract to provide pipeline precommissioning services on the Gorgon Project off the Northwest Shelf of Australia. Work has begun and is scheduled for completion by the end of 2013.
“To support our dramatic increase in activity, we required a larger facility to accommodate more staff and equipment. By consolidating three service lines at one base, we can share resources and work together as a team more efficiently. Our customers ultimately benefit from these synergies,” says Jaipreet Singh, Baker Hughes Australia area manager for process and pipeline services.
The new purpose-built facility, which serves as the operations base for Australia and New Zealand, includes offices, laboratories, training space, workshop facilities, a warehouse and storage, and an equipment lay-down area. To support operations in the region, Baker Hughes maintains a full complement of equipment for pumping services, tubular services, and process and pipeline services at Welshpool. Baker Hughes also houses the largest fleet of nitrogen services equipment in Australia.