Oil India Plans to Invest $4B in Five Years to Raise Output

- Oil India Plans to Invest $4B in Five Years to Raise Output

Tuesday, September 13, 2011
Dow Jones Newswires
NEW DELHI
by Rakesh Sharma

Oil India plans to raise its capital expenditure 73% to about INR190 billion ($4 billion) in the five years starting April 2012 as the state-run explorer seeks to sharply raise oil and gas production, its finance director said.

"We are stepping up exploration and development of our blocks in India and overseas," T.K. Ananth Kumar told Dow Jones Newswires late Monday. "We are also seeking producing assets, so we have raised our capital expenditure plans."

The company's capital expenditure in the five years ending March 2012 is likely to be about INR110 billion. It accounted for a 10th of India's total oil output of 754,000 barrels a day and 4.5% of total gas output of 52.22 billion cubic meters in the last financial year. Kumar didn't say how much the company is aiming to produce.

Oil India will mainly fund its investments through internal accruals, but may raise debt, he said.

The company, which was listed on local stock exchanges in September 2009, has cash reserves of INR130 billion, he added.

Oil India and its bigger state-run rival Oil & Natural Gas Corp. need to boost capital spending to bring new fields into production amid falling output at their aging fields. India, which imports about four-fifths of its crude oil requirements, is encouraging explorers to ramp up exploration and production to meet surging demand for energy in the world's second-fastest growing major economy.

"We have been witnessing an increase in capex by oil and gas explorers in India for the past several years as energy security is a focus. This sort of high capex is quite achievable by Oil India considering they have more than INR120 billion of cash and have been generating a cash flow of about INR40 billion per year," Alok Deshpande, analyst with Elara Securities Ltd., said.

Oil India is seeking to acquire producing oil and gas assets in Australia, Russia, Kazakhstan and Canada, Kumar said.

"We have shifted our focus to acquiring producing assets, rather than going for exploration blocks, as we already have our hands full with existing exploratory blocks. Also, we have enough cash in hand and that would be the best use of it," Kumar said.

Oil India is in talks with French explorer Etablissements Maurel et Prom to buy a stake in its Gabon assets and plans to close the deal by March, Mint newspaper reported Monday. Kumar declined to comment on the report.

Copyright (c) 2011 Dow Jones & Company, Inc.

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NPD Head: Norway's New Oil Finds May Help Stem Mid-Term Output Fall

- NPD Head: Norway's New Oil Finds May Help Stem Mid-Term Output Fall

Monday, September 12, 2011
Dow Jones Newswires
by Katarina Gustafsson

Two major oil finds this year by Norwegian oil and gas giant Statoil (STO) could stave off a steep decline in Norway's production in the mid-term, but won't reverse the longer downward trend, Bente Nyland, head of the Norwegian Petroleum Directorate has told Dow Jones Newswires.

This summer's find in the North Sea that is one of the 10th biggest discoveries ever on the Norwegian continental shelf and the earlier slightly smaller success in the Barents Sea complement measures to tackle the fall in the short- and mid-term that are being considered and implemented by the Scandinavian country.

However, ultimately Norway will have to open up new areas and that is more problematic.

"In the short- and mid-term it's important to keep and increase recovery, to have new finds in production and build out what you have found. While in the long run, it's necessary to discuss whether to open up new areas. And that is a political question," Nyland said.

Norway this year reached a treaty with Russia over a long disputed maritime border in the Barents Sea. But it could be a while before this new zone is opened up for exploration, Nyland said the quickest scenario would be around two or three years.

The petroleum directorate has started collecting seismic data from the region and Nyland, a geologist and head of the government body since 2008, said some indication of the region's resources could be given in 2012-13.

The state agency, tasked with overseeing Norway's oil and gas activities, predicts total production will be kept at about the current level until around 2020-25, Nyland said.

Norway's oil production peaked in 2001. Gas production is still rising but Nyland said she expects output to begin decreasing some time at the start of the 2020s given the lack of large gas finds.

"Gas production will to some extent fill in the gap in coming years," she said, adding that increasing the recovery rates in existing oil fields will be critical in the short term.

The petroleum sector is Norway's largest industry. Investments next year in oil and gas activities are seen at a record-high NOK172 billion ($32 billion), according to a recent forecast from Statistics Norway.

Last week, the Norwegian krone climbed to an eight-year high as traders sought a new safe haven after the Swiss National Bank capped the value of the Swiss franc against the euro.

"We have no indications that companies have become more restrictive. But it's too early to say," Nyland said.

In January, the Norwegian Petroleum directorate revised down estimates for undiscovered resources on the Norwegian continental shelf, to 2.6 billion standard cubic meters of oil equivalents from 3.3 billion standard cubic meters of oil equivalents.

"This year's finds give no base for changing our analysis," she said.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Lundin Reports Strong 2Q Results, Boosts Output Forecast

- Lundin Reports Strong 2Q Results, Boosts Output Forecast

Wednesday, August 03, 2011
Lundin Petroleum AB

Lundin reported for the six month period ended June 30, 2011

Six months ended June 30, 2011

• Production of 32,300 boepd up 13% from the first six months 2010
• Profit after tax of MUSD 130.3 up 526% from the first six months 2010
• EBITDA of MUSD 505.3 up 96% from the first six months 2010
• Operating cash flow of MUSD 390.3 up 52% from the first six months 2010
• Net debt down to below MUSD 120 from MUSD 410 at year end
• Five exploration discoveries, four in Norway and one in Malaysia
• Ten Norwegian licenses awarded in the 2010 Norwegian licensing round, six as operator
• Operated license awarded in Barents Sea in the 21st Norwegian licensing round
• Operated Gurita block awarded in the Natuna Sea, offshore Indonesia

Second Quarter ended June 30, 2011

• Production of 31,100 boepd
• Profit after tax of MUSD 76.9
• EBITDA of MUSD 266.9
• Operating cash flow of MUSD 196.7
• Three exploration discoveries – Skalle and Earb South discoveries in Norway and Tarap discovery in Malaysia
• Appraisal well confirmed extension of the Avaldsnes discovery
• New operated block PM307 awarded in Malaysia
• Brynhild field plan of development (formerly called Nemo) submitted

Comments from C. Ashley Heppenstall, President and CEO

Lundin Petroleum achieved excellent results in the second quarter of 2011 with increased profitability and cash flow. What is extremely pleasing however, is the continued exploration success. I have always highlighted that the major valuation creation for our company will be achieved through increasing our oil and gas resources, and the best way to do that is through exploration.

Lundin Petroleum produced a net result for the first six months of MUSD 130.3. The strong production coupled with oil prices achieved of well over USD 100 per barrel resulted in operating cash flow of MUSD 390.3 and EBITDA of MUSD 505.3. Despite our significant exploration and development investment program net debt during the first half of the year has reduced from MUSD 410 to below MUSD 120.

The positive exploration news has continued during the second quarter with further discoveries at Skalle in PL438 in the Barents Sea, Earb South in PL505 in the northern Norwegian north Sea and Tarap in Block SB303 offshore East Malaysia. In addition the results of the first Avaldsnes appraisal well were extremely encouraging confirming the extension of the Avaldsnes field to the south east. We have now achieved five discoveries from our first five exploration wells this year following the Tellus and Caterpillar discoveries during the first quarter.

Our business is continuing to grow and I am confident we will continue to increase shareholder value. We are generating strong cash flow and profitability from our existing production which is outperforming, our development projects are proceeding well and our exploration success continues.

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Record Output, Higher Prices Drive Devon's 2Q Profit to $2.7B

- Record Output, Higher Prices Drive Devon's 2Q Profit to $2.7B

Wednesday, August 03, 2011
Devon Energy Corp.

Devon reported net earnings of $2.7 billion for the quarter ended June 30, 2011, or $6.50 per common share ($6.48 per diluted share). This is a 288 percent increase compared with second-quarter 2010 net earnings of $706 million, or $1.59 per common share ($1.58 per diluted share).

For the six months ended June 30, 2011, Devon reported net earnings of $3.2 billion, or $7.44 per common share ($7.41 per diluted share). This compares with net earnings for the six months ended June 30, 2010, of $1.9 billion, or $4.26 per common share ($4.24 per diluted share).

Second-quarter 2011 financial results were impacted by certain items securities analysts typically exclude from their published estimates. The most significant of the adjusting items was a $2.5 billion gain on the sale of assets in Brazil. Excluding adjusting items, Devon earned $726 million or $1.71 per diluted common share in the second quarter. The adjusting items are discussed in more detail later in this news release.

Record Production and Higher Prices Drive Oil and Gas Sales

Sales of oil, natural gas, and natural gas liquids from continuing operations were $2.2 billion in the second quarter of 2011, a 23 percent increase over the second quarter of 2010. Both higher production and higher oil and natural gas liquids pricing contributed to the increase.

Devon's North American onshore production averaged the highest daily rate in the company's history at 660,000 oil-equivalent barrels (Boe) per day in the second quarter of 2011. This represents a production increase of more than six percent over the second-quarter 2010, driven by a 12 percent increase in oil and natural gas liquids production.

Devon's marketing and midstream operating profit totaled $148 million in the second-quarter 2011, a 19 percent increase over the second quarter of 2010. The improvement resulted from higher natural gas liquids production and prices as well as increased gas throughput.

Strategic Repositioning Completed; Share Repurchase Plan Remains on Schedule

In May, the company closed the $3.2 billion sale of its Brazilian operations. Devon has now substantially completed its International and Gulf of Mexico divestiture plan. In aggregate, sales proceeds from the combined divestitures exceeded $10 billion with after-tax proceeds expected to approximate $8 billion.

"The execution of Devon's strategic repositioning was excellent," said John Richels, president and chief executive officer. "Devon has emerged with a pristine balance sheet, a deep inventory of oil and liquids-rich growth opportunities and a highly competitive cost structure. As demonstrated by our second-quarter results, the repositioned Devon is delivering profitable growth per share."

In May 2010, Devon commenced a program to repurchase $3.5 billion of its common stock. As of June 30, 2011, the company had repurchased 33.5 million shares at a total cost of $2.5 billion. Devon expects to complete the stock repurchase program by the end of 2011.

Production Growth Leads Operating Highlights

• In the Permian Basin, Devon increased production 17 percent over the second quarter of 2010, to 49,000 oil-equivalent barrels per day. Oil and natural gas liquids accounted for 75 percent of the quarter's production.
• The company completed nine operated Bone Spring wells within the Permian Basin in the second quarter. Initial daily production from the nine wells averaged more than 700 Boe per day per well. Devon has an average working interest of 77 percent in these wells.
• In Canada, Devon commenced steam injection and achieved first production from its Jackfish 2 oil sands project in the second quarter. Production from the 100 percent-owned project is expected to ramp-up to 35,000 barrels per day before royalties over the next 18 months.
• Production from the company's Cana-Woodford Shale play averaged a record 189 million cubic feet of natural gas equivalent per day in the second quarter, including nearly 9,000 barrels per day of liquids. This represents an 80 percent increase in total production compared to the year-ago quarter.
• Devon's Barnett Shale production increased 13 percent over the second-quarter 2010 to a record 1.3 billion cubic feet of natural gas equivalent per day, including 46,000 barrels per day of liquids production.
• Devon brought eight operated Granite Wash wells online in the second quarter. Initial production from these wells averaged 2,010 barrels of oil-equivalent per day, including 200 barrels of oil and 730 barrels of natural gas liquids per day. The company has an average working interest of 71 percent in these wells.
• The company has assembled 1.1 million net acres targeting new oil and liquids-rich gas opportunities across multiple basins in the U.S. Devon plans to drill more than 30 wells this year targeting the Tuscaloosa Marine Shale, Niobrara Shale, Mississippian Lime, Ohio Utica Shale and the A1 Carbonate and Utica Shale in Michigan.

Cost Containment Efforts Offset Rising Industry Costs

Lease operating expenses (LOE) were $453 million in the second quarter of 2011, or $7.55 per Boe. This represents a one cent per Boe decrease from the second-quarter 2010. Effective cost management and higher production offset the effects of the strengthening Canadian dollar and rising service and supply costs.

Taxes other than income increased $28 million to $120 million in the second quarter of 2011. The year-over-year increase was driven by higher production taxes, resulting from the significant increase in oil and natural gas liquids revenues.

Second-quarter 2011 general and administrative expenses (G&A) totaled $135 million, or $2.26 per Boe. Compared to the second quarter of 2010, G&A per Boe increased approximately two percent. Efficiencies gained through the company's strategic repositioning helped mitigate the effects of the strengthening Canadian dollar and an increase in overall activity levels.

Depreciation, depletion and amortization expense (DD&A) of oil and gas properties increased to $485 million in the second quarter of 2011. Compared to the year-ago quarter, unit DD&A increased 11 percent to $8.08 per Boe.

Interest expense decreased 24 percent in the second quarter to $85 million. Second-quarter 2010 interest expense included a $19 million charge related to the early redemption of senior notes.

Second-quarter income tax expense from continuing operations totaled $1.2 billion, or 87 percent of pre-tax earnings. This unusually high tax rate resulted from a $744 million charge related to U.S. income taxes on foreign earnings assumed to be repatriated under current U.S. tax law. After adjusting for this and other items generally excluded by securities analysts, Devon's second quarter tax rate totaled 32 percent of pre-tax earnings from continuing operations.

Cash Flow and Divestiture Proceeds Total $4.8 Billion

Cash flow before balance sheet changes totaled $1.6 billion in the second quarter of 2011, a 115 percent increase over the year-ago quarter. In addition, Devon received $3.2 billion of pre-tax proceeds from the sale of its assets in Brazil.

As of June 30, 2011, the company's cash and short-term investments reached $6.7 billion and its net debt to adjusted capitalization ratio declined to five percent. Reconciliations of cash flow before balance sheet changes, net debt and adjusted capitalization, which are non-GAAP measures, are provided in this release.

Devon Adds To Natural Gas Hedges

Devon continued to bolster its natural gas hedge positions for 2011 and 2012. For the second half of 2011, the company now has approximately 980 million cubic feet per day protected utilizing swap and collar contracts with a weighted average floor price of $5.28 per Mcf. For 2012, Devon now has hedges covering 815 million cubic feet per day hedged at a weighted average floor price of $4.89 per Mcf. The company's natural gas hedges for both 2011 and 2012 are based on the Henry Hub benchmark index.

Divestitures Impact Reported Financial and Operational Results

In accordance with accounting standards, Devon has classified the assets, liabilities, and results of its international segment as discontinued operations for all accounting periods presented in this release. Included with this release is a table of revenues, expenses, production categories, and the amounts classified as discontinued operations for each period presented.

Items Excluded from Published Earnings Estimates

Devon's reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company's financial results. These items and their effects upon reported earnings for the second-quarter 2011 were as follows:

Items affecting continuing operations

• U.S. income taxes on foreign earnings assumed to be repatriated to the U.S. decreased second-quarter earnings by $744 million.
• A change in the fair value of oil, gas and NGL derivative instruments increased second-quarter earnings by $357 million pre-tax ($233 million after tax).
• A change in fair value of interest-rate and other financial instruments decreased second-quarter earnings by $30 million pre-tax ($20 million after tax).
• Restructuring costs decreased second-quarter earnings by $6 million pre-tax ($3 million after tax).

Items affecting discontinued operations

• Divestitures of assets in Brazil resulted in a second-quarter gain of $2.5 billion pre-tax ($2.5 billion after tax).
• Restructuring costs increased second-quarter earnings by $8 million pre-tax ($5 million after tax).

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Slumping Output Raises Tough Questions for European Oil Giants

- Slumping Output Raises Tough Questions for European Oil Giants

Monday, August 01, 2011
Dow Jones Newswires
LONDON
by Alexis Flynn

When Europe's major oil companies reported quarterly earnings last week, headlines across national capitals once again excoriated the petroleum giants for soaring profits in the face of consumers anger at high fuel prices.

Yet the profits couldn't mask a trend that continues to trouble Wall Street and corporate boardrooms: Nearly every major oil company reported year-on-year oil and gas output declines, often in the double-digits.

Big Oil is throwing huge resources at the problem with more open embrace of unconventional petroleum developments, high-risk exploration in frontier areas and corporate restructuring. But even if these strategies work in some cases, there is little doubt that anemic petroleum output signals a long-term challenge confronting the sector.

The particulars varied across the sector. BP's 11% output drop was fueled in part by the continued hit from its reduced activity in the U.S. Gulf of Mexico after last year's disastrous spill. Italian giant Eni's production fell 15% due to its disproportionate exposure to war-ravaged Libya. Spain's Repsol, whose output fell 17%, was affected by both Libya and the U.S. Gulf, as well as by labor unrest in Argentina. Norway's Statoil saw a16% output decline largely on production outages and maintenance in its home market in the North Sea.

Oil giants are more vulnerable to operational problems in part because of their declining dominance over key resources. Whereas in 1973, independent oil firms controlled three-quarters of the world's reserves, they hold as little as10% today, according to some estimates. That has forced oil majors to rely to a greater extent on costly unconventional plays such as shale gas, deepwater exploration, and Arctic exploration.

Investment in conventional assets accounted for 63% of the majors' total capital expenditure between 2001 and 2005, research by Wood Mackenzie showed, with this proportion set to fall to 40% between 2011 and 2015.

Last week's reports showed that the two biggest oil giants, Shell and ExxonMobil, were somewhat better positioned than their smaller peers, in light of their capacity to progress capital-intensive projects. Another standout, Wall Street darling BG Group, the only European oil major to report higher year-on-year output, has prospered from recent discoveries in the hot Brazil offshore region.

Yet there are problems even with these templates. Though demand for natural gas remains solid, natural gas prices could see further weakness in light of surging North American shale gas output and economic weakness in Europe and the U.S.

The push for more exploration has ignited interest in Africa following new seismic results and recent discoveries in Ghana and Uganda. But it's a risky and capital-intensive game and one requiring a fleetness of foot to grasp opportunities and adapt quickly to contrary political circumstances. Industry anecdotes abound of how some of the most lucrative recent discoveries on the continent were once passed up by reluctant majors.

Consolidation offers another way forward, yet few expect large corporate mergers between integrated oil giants in light of antitrust concerns and today's high oil prices. More likely is a deal akin to Exxon's purchase of U.S. unconventional gas specialist XTO, a major factor in Exxon's standout 10% rise in production in the quarter. Wood Mackenzie's Simon Flowers predicts more such "infill acquisitions," but says "large-scale acquisition is not likely in the near term."

Another possibility is the flowering of deals between private oil giants and emerging state-controlled firms like Brazil's Petrobras, Russia's Rosneft and China's CNPC. BP's failed share swap and Arctic exploration deal with Rosneft was an example and illustrates the lengths to which companies are prepared to go to gain access to their potentially lucrative reserves.

Wall Street will likely push harder for some sort of tangible action from Big Oil in the coming months. The sector trades at a significant discount to the oil price itself, a factor that could sharpen calls for share buybacks and more special dividends. The recent move by ConocoPhillips to hive off its downstream business lifted the Texas company's share price and spawned questions for the rest of the sector. But so far, most of Conoco's peers have dismissed the idea as impractical in light of the advantages of the conventional integrated model.

Copyright (c) 2011 Dow Jones & Company, Inc.

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BG 2Q Earnings Double on Commodity Prices, Output

- BG 2Q Earnings Double on Commodity Prices, Output

Tuesday, July 26, 2011
BG Group plc

BG Group reported its second quarter and half year results for 2011.

Second Quarter Key Points

• Earnings up 27%; cash generated by operations up 11%
• Interim dividend of 10.8 cents per share, up 10%
• Reserves and resources doubled in Brazil since 2010; upside potential now 8 billion boe net
• Brazil reservoir performance significantly reduces unit costs; unit resource value increased
• Lifted first one million barrels of equity oil from Lula field
• Assumed operatorship offshore Tanzania; agreements to operate offshore Kenya

BG Group's Chief Executive, Sir Frank Chapman said, "We made good progress in both our E&P and LNG businesses. In Brazil, we saw major increases in our reserves and resources; with the new resources delivering a higher unit value as their production is expected to require no additional surface facilities. We have invested $4.4B in organic growth in the first half and made good progress across our major growth projects in Australia, Brazil and the USA; progress that continues to de-risk the delivery of our growth program."

Second quarter

Revenue and other operating income increased by 26% to $5.115 billion, reflecting the benefit of higher commodity prices and a 3% increase in E&P production, with solid operational performance across the Group's assets.

As a result of the above and a lower exploration charge in the quarter, total operating profit increased by 43% to $2.152 billion.

Cash generated by operations increased by 11% to $2.581 billion as a result of higher profits and, as anticipated, the partial reversal of prior period margin calls on the Group's hedged LNG contracts.

As of 30 June 2011, the Group's net debt was $9.468 billion with an average maturity of around 8 years, and the gearing ratio was 24%. During the quarter, BG Group signed a cooperation agreement with Bank of China that allows for up to $1.5 billion of new funding alternatives to support the Group's major growth programme. The Group's undrawn committed facilities have been increased to $5.5 billion with maturities from 2012 to 2016.

Net finance costs amounted to $59 million for the quarter, against $25 million income in 2010, including foreign exchange gains of $7 million (2010 $71 million gain).

Capital investment (including acquisitions of $113 million) in the quarter was $2.537 billion and comprised investment in E&P ($1 918 million), LNG ($537 million) and T&D ($82 million). This investment focused primarily on the Group's major growth projects in Australia, Brazil and the USA and represents a 58% increase in underlying organic capital investment compared with second quarter 2010. More details on project developments are provided in the relevant segmental business highlights.

Half year

Revenue and other operating income of $9 918 million was 16% higher than in the same period in 2010, reflecting 48% and 14% increases in realised oil and gas prices, respectively. This revenue performance, combined with a lower exploration charge, was the main contributor to the 19% increase in total operating profit from $3.456 billion to $4.117 billion.

Cash generated by operations of $4.380 billion was 9% lower than last year, principally as a result of changes in working capital associated with margin calls on the Group's hedged LNG contracts. As already observed, the cash outflow associated with margin calls has reversed in the second quarter, a trend that is expected to continue in future periods when the underlying LNG contracts settle.

The $153 million increase in net finance costs was driven primarily by changes in foreign exchange (2011 foreign exchange losses of $15 million compared with a $122 million gain in 2010).

The Group's effective tax rate (including BG Group's share of joint venture and associates' tax but excluding prior period taxation) for the full year is expected to be 45% (2010 38.5%). The increase is primarily as a result of the change in UK North Sea taxation announced in March 2011. This led to an additional charge of $324 million consisting of a $121 million charge for the half year in addition to a one-off tax charge of $203 million in respect of the revision of opening deferred tax balances. The one-off charge was partially offset by an $8 million credit as a result of a reduction in the UK taxation rate applicable outside the UK North Sea (net $195 million). The Group's effective tax rate in future years is expected to be 43% to 44% in the near term and trend downwards thereafter as more of the Group's profits are generated from outside of the UK North Sea.

As previously announced, the Group is undertaking an extensive investment programme to deliver its growth. Capital investment in the half year (including acquisitions of $432 million) was $4 833 million and comprised investment in E&P ($3.744 billion), LNG ($936 million) and T&D ($153 million). This investment focused primarily on the Group's major growth projects in Australia, Brazil and the USA and represents a 28% increase in underlying organic capital investment compared with 2010. This expenditure is in line with the Group's previous guidance of $10 billion for the full year at reference conditions.

In line with the Group's financial performance, the Board has approved the payment of an interim dividend of 10.80 cents per share. This is half of the 2010 total dividend, in accordance with the Board's established policy. The interim dividend has been converted to Sterling at the average of the closing exchange rate for the three business days preceding this announcement and will be paid on 8 September 2011 as 6.63 pence per share to shareholders on the register as at August 5, 2011.

Disposals, re-measurements and impairments - continuing operations

A post-tax gain of $123 million for the quarter (2010 $443 million charge) was recorded in respect of disposals, re-measurements and impairments. This comprised a post-tax gain of $121 million (2010 $302 million charge) in relation to mark-to-market movements on long-term commodity contracts and economic hedges, a $24 million post-tax gain in respect of disposals of non-current assets and impairments (2010 $135 million charge) and a $22 million post-tax charge (2010 $6 million charge) in respect of re-measurements of treasury financial instruments.

A post-tax charge of $100 million for the half year (2010 $377 million charge) was recorded in respect of disposals, re-measurements and impairments.

Exploration and Production (E&P)

Second quarter

Revenue and other operating income increased by 35% to $2 787 million, reflecting the benefit of higher realized prices and a 3% increase in production volumes. Total operating profit of $1.420 billion was 90% higher as a result of the increase in revenue and other operating income and a lower exploration charge.

Higher production volumes in the quarter reflected continuing production build-up in the USA, Brazil and at Hasdrubal in Tunisia. In the UK North Sea, the Everest, Lomond and Erskine fields progressively returned to production following the shutdown in the first quarter. BG Group expects Buzzard to return to full capacity in the third quarter following a period of restricted production. Whilst there continued to be sporadic disruption from social unrest in Egypt and Tunisia, this had a relatively small impact on production in the second quarter.

BG Group continues to expect modest production growth in 2011, ahead of the strong ramp-up in production volumes which begins in 2012 and continues through the decade.

International gas price realizations were 17% higher at 39.02 cents per produced therm, reflecting changes in the production mix and the effects of higher oil prices. The average realized gas price in the UK increased by 48% to 44.43 pence per produced therm, as a result of higher contract and market prices.

The exploration charge of $120 million is $246 million lower than 2010 as a result of lower well write-off costs.

Unit operating expenditure increased to $8.93 per barrel of oil equivalent, reflecting the impact of higher commodity prices, adverse foreign exchange movements and changes in the production mix, including higher than portfolio average costs associated with the production start-up activities in Brazil. BG Group continues to expect unit operating costs to be between $8.50 and $9.00 per barrel of oil equivalent at an oil price of around $100 per barrel for the full year.

Capital investment of $1 918 million in the quarter comprised investment in the Americas ($673 million, including $113 million on acquisitions), Australia ($496 million), Europe and Central Asia ($443 million) and Africa, Middle East and Asia ($306 million).
Half year

Revenue and other operating income increased by 22% to $5.297 billion, principally as a result of higher realized prices. Total operating profit increased by 38% to $2.678 billion, reflecting the increase in revenue and other operating income and a lower exploration charge.

The Group's average realized gas price per produced therm increased by 14% to 41.12 cents, reflecting generally higher market prices and changes in the production mix.

Unit operating expenditure increased to $8.46 per barrel of oil equivalent, reflecting the impact of the UK North Sea shutdown during the first quarter, higher commodity prices and changes in the production mix.

Capital investment of $3 744 million in the half year comprised investment in the Americas ($1.450 billion, including $376 million on acquisitions), Australia ($899 million), Europe and Central Asia ($798 million, including $56 million on acquisitions) and Africa, Middle East and Asia ($597 million).

Second quarter business highlights

Bolivia

In July, BG Group sanctioned Phase II of the Margarita project. This follows on from the sanction of Phase I in 2010, where construction is underway and early production facilities are onstream. Production from the two phases and the early production facilities is expected to reach over 40 thousand barrels of oil equivalent per day net to BG Group by 2014. Net investment in Phase I is estimated at $164 million and Phase II at $250 million.

Brazil

In June 2011, BG Group issued a material reserves and resources upgrade for its interests in the pre-salt Santos Basin, offshore Brazil. Mean total reserves and resources are now estimated to amount to some 6 billion barrels of oil equivalent (boe) net to BG Group, with an upside potential of 8 billion boe net.

The mean total reserves and resources represents a doubling of BG Group's previous best estimate of 3 billion boe prevailing at the time of the Group's February 2010 Strategy Presentation. The aggregate range of total reserves and resources net to BG Group is from 4 billion boe (P90) to 8 billion boe (P10).

The Lula, Guará, Cernambi, Iara and Carioca fields account for 95% of BG Group's total reserves and resources in the Santos Basin.

The recent increase in BG Group's estimate of its reserves and resources in Brazil was based upon a wealth of drilling, appraisal and other new data. Importantly, this includes dynamic data showing much higher well deliverability and greater connectivity within the reservoirs allowing increased recovery per well.

In addition to improved reservoir characteristics and resource estimates, there has been significant progress on the cost front. Experience with tendering, construction progress and operations experience with FPSOs has given confidence in the cost and schedule for surface facilities. Meanwhile a substantial improvement in drilling performance in the first half of 2011 has provided greater confidence that anticipated drilling cost reductions will be achieved over future phases.

In summary, as a consequence of the above BG Group now expects:

• Higher flow rates and recovery per well;
• Earlier achievement of plateau production from fewer wells;
• Lower unit costs and higher unit value.

Significantly, BG Group expects that virtually all of the additional resources announced in June, contained within the Lula, Guará, Cernambi, Iara and Carioca fields, will be recovered from the same surface facilities envisaged in BG Group's field development plan prior to the resources upgrade. The incremental volumes are thus of a substantially higher value and result in significant unit cost reductions and higher unit value for the now increased total resources base.

Finally, during the quarter, BG Group took delivery of the oil tanker Windsor Knutsen which will be used to transport

BG Group's equity oil from Brazil. The Windsor Knutsen was converted from a conventional Suezmax tanker into the world's largest shuttle tanker, with the capacity to hold 1.1 million barrels of crude oil. First crude oil from the Lula FPSO has been lifted and is in transit to be delivered in August. BG Group has also committed to charter four further Suezmax shuttle tankers which are expected to be delivered in the period 2013 to 2014.

Egypt

In May, BG Group and its partner sanctioned Phase 8b, the next phase of investment in the West Delta Deep Marine Concession (WDDM) offshore the Nile Delta. This is one of a series of investments to maintain production from this concession that supplies gas for domestic and export needs. Phase 8b will bring seven additional wells onstream, allowing BG Group to meet its contracted gas commitments.

In 2011, BG Group, with its partners, also invested in WDDM development Phases 7 and 8a. The Phase 7 third pipeline came onstream in January with the compression project due onstream later this year. Phase 8a will bring onstream nine additional sub-sea wells. The first stage of drilling for Phase 8a has been completed with first gas expected in late 2011.

Kazakhstan

In June 2011, a fourth liquid stabilization train at the Karachaganak Processing Complex was successfully put into operation. The start-up of the new oil processing facility raises the stabilization and export capacity of the plant to 10.3 million tonnes of condensate per year.

Kenya

In May, BG Group announced it had signed Production Sharing Contracts with the Government of Kenya for two offshore exploration blocks - L10A and L10B. BG Group will be the operator of both blocks and will hold a 40% equity interest in block L10A and a 45% interest in block L10B. These blocks together cover an area of more than 10 400 square kilometres in the southern portion of the Lamu Basin. The initial work program consists of a commitment to acquire seismic data during an initial two-year exploration period.

Norway

In June, the plan for development and operation of the Knarr field (previously known as Jordbær) was approved by the Norwegian Parliament. Production is scheduled to start in 2014. Knarr is an oil field in a water depth of 410 meters, situated in the Tampen North area in the Norwegian North Sea. Also in June, the lease and operate contract for the FPSO for the Knarr field was signed.

Tanzania

BG Group received approval from the Government of Tanzania to assume the role of Operator of Blocks 1, 3 and 4, offshore Tanzania, effective from 1 July 2011. To date, three successful exploration wells have been drilled. As part of the operatorship transition arrangements, BG Group has led a number of project activities over recent months in preparation for the next stage of the exploration and appraisal program, scheduled to commence in late 2011.

USA

Progress in BG Group's shale gas operations continued to gather pace with production continuing to build-up and the 200th EXCO-operated Haynesville horizontal well being brought into production. During the quarter, 38 wells were spudded and 22 rigs were operating in the Haynesville, while 8 wells were drilled in the Marcellus shale.

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Pennsylvania Shale Gas Output to More Than Double This Year - Study

- Pennsylvania Shale Gas Output to More Than Double This Year - Study

Thursday, July 21, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Natural gas production from Pennsylvania's Marcellus Shale should reach the equivalent of 3.5 billion cubic feet per day this year, more than double 2010's output, according to new research by a trio of Pennsylvania State University professors.

The study, released Wednesday, further estimates that production in the state from the deeply-buried rock formation will rise to the equivalent of 6.7 billion cubic feet per day in 2012 and 17.5 bcfe in 2020.

That level of production would make the Pennsylvania basin the largest supplier of natural gas in the U.S., able to meet about 25% of the country's demand, said Kathryn Klaber, who heads the Marcellus Shale Coalition, an oil and gas industry advocacy group.

The Marcellus Shale underlies parts of several Mid-Atlantic and Midwestern states but production is centered in Pennsylvania.

In 2010 1,405 wells were drilled there, yielding the equivalent of 1.3 billion cubic feet of gas per day, according to the study. The professors, who obtained data from producers through the advocacy group, said that 2,300 wells are planned to be drilled this year and forecast that the number will steadily rise to about 2,500 a year by 2020.

While producers have focused on Pennsylvania with some forays into Ohio and West Virginia, several are eying an expansion into New York.

Many initially believed that southwest Pennsylvania held the most productive fields. But a string of recently drilled wells in northern Pennsylvania have made exploration in New York -- where a ban on hydraulic fracturing, the controversial technique needed to crack open the energy-bearing rock, was recently lifted -- more attractive.

Twenty-four of Pennsylvania's 25 highest producing wells are in counties that border New York, according to the Pennsylvania Department of Environmental Protection.

In May, Houston-based Cabot Oil & Gas said two of its wells in that border area are producing nearly 30 million cubic feet of natural gas per day -- significantly more than any previous Pennsylvania wells.

Copyright (c) 2011 Dow Jones & Company, Inc.

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PetroVietnam to Start Output at 5 New Fields in 2nd Half

- PetroVietnam to Start Output at 5 New Fields in 2nd Half

Wednesday, July 06, 2011
Dow Jones Newswires
HANOI
by Vu Trong Khanh

State-run Vietnam Oil & Gas Group said that it is starting production at new fields in the second half of the year and beginning construction on a second refinery, as it seeks to increase production to feed its fast-growing economy.

The company, known as PetroVietnam, said it will begin producing at five oil fields, including two that are overseas. The announcement comes amid uncertainty about Vietnam's offshore program due to an increasingly bitter territorial dispute with China, which has involved Chinese harassment of Vietnamese oil prospecting activities.

PetroVietnam said it expects to begin production at Russia's Nenetsky field this month and at Dana field in Malaysia's SK305 Block in August.

Production at Te Giac Trang and the second phase of Dai Hung field will start in August, while output at Chim Sao field will begin in September, it said. The fields are between 100 kilometers and 350 kilometers off Vietnam's southern coast, an area that is far away from the area of dispute with China.

The company reported two new commercial findings in the first half, raising its proven crude oil reserves by 10.2 million metric tons.

Late last month, Vietsovpetro, a joint venture between PetroVietnam and Russia's JSC Zarubezhneft, announced that it had discovered additional oil in the Bach Ho field off Vietnam's southern coast, with tests confirming strong oil flow of 4,560 barrels a day.

Meanwhile, Malaysia's Petroliam Nasional Bhd., or Petronas, said last month that it and PetroVietnam have discovered oil offshore Vietnam, with confirmed oil flow of 5,200 barrels a day.

PetroVietnam said Wednesday that it will continue oil exploration Vietnam's continental shelf in the second half of this year, aiming to raise its proven crude oil reserves by 20 million-25 million tons in the period. It didn't say how large its current reserves are.

Meanwhile, the company said it and its partners will start building the Nghi Son oil refinery in northern Vietnam in the third quarter.

PetroVietnam said previously that it would work with Kuwait Petroleum Corp., Idemitsu Kosan and Mitsui Chemicals on the 200,000-barrel-a-day refinery in Thanh Hoa province.

PetroVietnam is targeting output of 7.8 million tons of crude oil in the January-June period, which will take its full-year output to 15 million tons, flat from last year.

It will sell 7.3 million tons of crude oil in the period, including 1.66 million tons to the Dung Quat refinery, which will likely produce 2.48 million tons of oil products in the second half, taking its 2011 output to 5.6 million tons, the company said.

The 130,000-barrel-a-day refinery is scheduled for a maintenance shutdown for two months starting July 15.

PetroVietnam had pretax profit of VND49.9 trillion in the January-June period, up 44% from a year earlier and meeting 68% of its full-year target, the company said.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Statoil to Boost Output Levels to 2.5MM boepd in 2020

- Statoil to Boost Output Levels to 2.5MM boepd in 2020

Monday, June 20, 2011
Statoil

Statoil presents its long term growth outlook. The company expects to raise production from around 1,9 million barrels in 2010 to above 2.5 million barrels of oil equivalents per day in 2020.

With premium positions on a revitalized Norwegian Continental Shelf (NCS) and a world class project portfolio, Statoil is positioned to deliver strong shareholder returns.

Celebrating its ten years anniversary as a publicly listed company, Statoil expands on its outlook for the coming years at the Capital Markets Day at the New York Stock Exchange.

"We have made significant strategic progress and have proven ability to deliver competitive returns since our IPO in 2001. With a premium project portfolio and strong commitment to leverage the company's competitive strengths, we will continue our journey," said Helge Lund, president and CEO of Statoil.

"The industry has changed considerably since we listed the company. Today we announce a strategy that reflects those changes and how we address them to the benefit of our shareholders," Lund added.

Statoil grew production at a compound annual growth rate (CAGR) of 3% in the last decade, excluding the Hydro merger. Production is expected to continue growing at the same rate over the next ten years, reaching a level of above 2.5 million barrels of oil equivalents (boe) per day in 2020.

• A first wave of new projects will provide a step-up in production in 2012, delivering around 3% CAGR 2010-2012.
• A second wave of projects will give further growth from 2014 and onwards, providing a 2-3% CAGR for the years 2012 – 2016 with production in 2013 expected to be around 2012 level.
• A third wave of projects will provide a 3-4% CAGR from 2016 to 2020, taking production above 2.5 million boe per day in 2020.

This corresponds to an overall CAGR of around 3 % from 2010 till 2020, a growth rate backed by a strong resource base and a portfolio of world class projects. In 2020 the production from NCS is expected to be above 1.4 million boe per day, while the international portfolio is expected to produce above 1.1 million boe per day.

"The NCS has a significant potential and continues to yield long term, superior value creation opportunities in an investment friendly environment. The NCS remains a very attractive and globally competitive province for future oil and gas activities," said Helge Lund.

"To realize the project portfolio Statoil increased investments for 2011 to USD 16 billion, and expects the investments in 2012 to be at the same level."

"Towards 2020 our ambition is to establish material positions in 3 – 5 offshore business clusters outside the NCS and step up our shale gas and liquids production. These positions have significant resource potential and through exploration, business development and the application of our distinct technological capabilities we will lift value creation beyond today's levels," Lund said.

The offshore business clusters include Gulf of Mexico, Brazil, Angola, the Caspian region and Arctic outside the NCS.

Statoil today announces discoveries in both side tracks on the Peregrino South well, immediately adjacent to the newly opened Peregrino field offshore Brazil. The estimates of recoverable volumes in Peregrino South are between 150 – 300 million boe. This discovery brings a phase two development of the Statoil operated Peregrino field considerably closer.

Statoil also confirms an increase in expected volumes from the Skrugard oil discovery in the Barents Sea in Norway. The Skrugard volumes are now estimated at approximately 250 million boe recoverable resources, with a significant upside potential in the license. The Skrugard well has significantly improved Statoil's understanding of other prospects in the area.

"Our recent performance marks an early indication that our sharpened exploration strategy is working. This reaffirms that our competence and experience allow us to pursue an exploration strategy emphasizing early access at scale and priority to high impact opportunities," said Helge Lund.

Statoil expects to drill 20 – 25 high impact wells in the years 2011 – 2013.

Technology focused, upstream strategy

In recent years, Statoil has streamlined its business, reinforcing its position as a technology focused upstream company. While building a leading position on the NCS, Statoil has taken positions in a number of the world's most prolific provinces and established an attractive resource base. Since listing the company has increased its non-Norwegian production more than five fold. The core competencies and capabilities, including innovative development and application of technology coupled with the execution of complex offshore and onshore field development projects, positions Statoil as operator and partner globally.

Statoil's long term strategy focuses on six core building blocks. Firstly, Statoil will further revitalize and expand the NCS horizon with high value barrels. The company's position on the NCS remains a strong cash generator, with a set of premium projects that form the foundation for its growth outlook. Secondly, Statoil will utilize its superior gas position to deliver value in strong and growing markets. Thirdly, the company will leverage its leadership in complex offshore projects, and build material positions in 3-5 business clusters in addition to the NCS. Fourthly, it will continue to strengthen its resource base through leading exploration activities. Fifthly, Statoil will step up the company's shale gas and liquids activity, strengthening performance based on its early entry and core technology competencies. Finally, the company will further enhance shareholder return through active portfolio management.

In addition the focus on renewables concentrated around offshore wind continues. Statoil has taken important positions currently centered on the Sheringham Shoal and Dogger Bank projects in the UK.

A new industrial horizon in Norway

Statoil sees three long term business clusters on the NCS - the North Sea, the Norwegian Sea and the Barents Sea.

The Skrugard discovery provides renewed optimism for the whole Barents region. It also reaffirms the long term perspective of the NCS, where there is a set of opportunities based on current producing assets and access to new, promising areas. The delineation agreement between Norway and Russia, and statements from the Norwegian government on its intent to give access to new acreage, adds to a positive outlook for the Barents Sea.

The company will maximize the value of the North Sea through operational improvements, IOR measures and development of satellite fields. The development of new fields, such as Valemon, Gudrun and Dagny/Ermintrude represents a significant business opportunity. In the Norwegian Sea cluster, the company will fast track the projects in the pipeline, and is looking at further growth options, including opening of the resource rich areas of Nordland VI and VII.

Capturing value from gas

Natural gas is emerging as the most plentiful, cost efficient and cleanest of fossil fuels. There is a particularly strong case for an increased use of gas in power generation. Gas is cost competitive with coal, nuclear and renewables, which allows for even higher gas prices. Growing demand for gas in Asia will also impact prices in Europe through export of LNG. Statoil is well positioned to take part in this expected growth in the gas markets.

The positive outlook for gas, and the opportunities for enhanced value creation in the expanding markets worldwide, covers conventional as well as unconventional resources. Going forward our industrial roadmap for North American will focus on building the Marcellus and Eagle Ford positions, taking on operatorship and growing into new areas.

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Platts: OPEC Boosts Oil Output in May

- Platts: OPEC Boosts Oil Output in May

Tuesday, June 14, 2011
Platts

The Organization of the Exporting Countries (OPEC) pushed out an additional 200,000 barrels per day (b/d) of crude oil in May, boosting output to 29.04 million b/d from 28.84 million b/d in April, showed a just-released Platts survey of OPEC and oil industry officials and analysts.

OPEC kingpin Saudi Arabia, which vowed after OPEC's June 8 meeting in Vienna to ensure that world oil markets would not suffer any supply shortage, accounted for most of the additional barrels.

"You can see that the task ahead of Saudi Arabia, and any other nation determined to meet what is expected to be steadily increasing demand, is substantial," said John Kingston, Platts global director of news. A difference of opinion in what the market needs was the topic of unresolved debate at last week's OPEC meeting, which Saudi Oil Minister Naimi called the "worst ever," and which ended with the parley breaking up and taking no action.

"OPEC produced 29.8 million b/d before the Libyan uprising and it's only climbed back above 29 million b/d with the increases of the past month," Kingston added. "Most supply/demand estimates see an absolute minimum need for output of 30 million b/d in the second half of the year. It's a large jump, and all eyes will be on Saudi Arabia to see if it can get the job done."

Excluding Iraq, which does not participate in OPEC output agreements, the 11 members bound by quotas (OPEC-11) increased output by 160,000 b/d to 26.34 million b/d in May from 26.18 million b/d in April, the survey showed. This left OPEC-11 overproducing their notional 24.845-million-b/d target by 1.5 million b/d.

But that target, in place since January 2009, is now redundant following the failure of OPEC's June 8 ministerial meeting in Vienna to reach an agreement on output.

Saudi Arabia and its fellow Gulf Arab producers wanted OPEC to increase estimated April output of 28.8 million b/d by 1.5 million b/d to 30.3 million b/d, in line with the OPEC secretariat's projections of higher demand for OPEC crude in the second half of this year. Algeria, Angola, Ecuador, Iran, Libya and Venezuela opposed an increase.

As the Vienna talks broke up, Saudi oil minister Ali Naimi told reporters it and its Gulf neighbors intended to meet the expected higher demand.

"Saudi Arabia and the other three GCC countries are able and willing to supply whatever the market needs," he said, referring to Kuwait, the United Arab Emirates and Qatar which, with Saudi Arabia are members of the Gulf Cooperation Council, or GCC.

"The market is not going to see any shortage because we could not reach agreement at this meeting. We are willing and we are able and we will deliver what is needed," Naimi said.

Saudi Arabia, which had been producing well above its notional OPEC quota of just over 8 million b/d for some time, increased output by some 200,000 b/d in May, to 9.05 million b/d from 8.85 million b/d in April.

Other increases came from Nigeria, Qatar and Venezuela, while volumes dipped in Algeria, Angola, Iran, Libya and the UAE. Libyan crude production had been running close to 1.6 million b/d before the rebellion against the regime of Moammar Qadhafi, now in its fifth month, but dropped to an average of around 160,000 b/d in May from 200,000 b/d in April.

Saudi-owned newspaper al-Hayat reported, according to senior OPEC sources, June 10 that the country planned to raise oil production to 10 million b/d in July and to maintain that level for a month before reducing output in August in line with an expected dip in demand.

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Cenovus Boosts Output Target for Next Decade

- Cenovus Boosts Output Target for Next Decade

Monday, June 06, 2011
Cenovus Energy Inc.

Cenovus is advancing development of its vast oil assets and bringing forward the value of its resource for shareholders. The company has approved a 2011 strategic plan that builds upon its original strategy created in 2010 and establishes new timelines and significant oil production increases for the next decade.

The plan targets:

• total oil production of about 500,000 barrels per day (bbls/d) net by the end of 2021
• oil sands production of more than 400,000 bbls/d net by the end of 2021, about six times greater than current oil sands production
• conventional oil production of 120,000 bbls/d to 130,000 bbls/d by the end of 2016, nearly double current production of about 70,000 bbls/d
• a new oil sands project phase expected on stream every 12 to 18 months
• an increase in total production capacity at Foster Creek to between 270,000 and 290,000 bbls/d gross, through increased production capacity at phases F, G and H and future phases
• drilling about 450 stratigraphic (strat) wells per year for the next five years to prepare for the development of oil sands opportunities
• doubling of net asset value in the 2010 to 2015 time-frame

"Based on the strong performance delivered by our teams over the past year, we believe we can bring on substantially more oil production earlier than initially planned," said Brian Ferguson, President & Chief Executive Officer of Cenovus. "We plan to expand current conventional oil and oil sands opportunities and bring on new projects. Our industry-leading oil sands capital efficiencies and low operating costs will help us achieve even greater total shareholder return."

The company expects to be producing 500,000 bbls/d net oil production by the end of 2021; with more than 400,000 bbls/d from its oil sands operations. Foster Creek and Christina Lake are expected to contribute about two-thirds of that oil sands production. The company now expects to reach approximately 350,000 bbls/d of oil sands production by the end of 2019, compared with the 300,000 bbls/d milestone it had set in its 2010 strategic plan. To achieve its production growth, Cenovus is working to have 400,000 bbls/d to 500,000 bbls/d net of oil sands projects approved by regulators by 2015.

The strong resource base at Foster Creek has prompted the company to increase expected total gross production capacity to between 270,000 bbls/d and 290,000 bbls/d, from the previous expectation of 235,000 bbls/d gross. Foster Creek phases F, G and H are now each planned to have production capacity of 35,000 bbls/d, which is 5,000 bbls/d more than initially anticipated at each phase. Cenovus is also moving up the anticipated timelines for first production from phases G and H as well as future phases. Steaming at Christina Lake phase C is underway, about six weeks ahead of schedule. Construction of phase D is more than half complete and is three to six months ahead of schedule. Cenovus is assessing whether it will be able to increase the production capacity of future phases at Christina Lake and accelerate the timing of those projects. The Narrows Lake project is still expected to begin producing in 2016 and Grand Rapids in 2017. Foster Creek, Christina Lake and Narrows Lake are jointly owned with ConocoPhillips and project timing is subject to partner approval.

"We're able to proceed with our growth plans thanks to our strong balance sheet and our anticipated cash flow being well in excess of what's needed for approved projects," Ferguson said. "We're continuing down the path created by our strategic plan last year - just moving a little faster."

Cenovus remains committed to bringing forward value from oil sands holdings not currently included in near-term development plans by entering into a strategic transaction by the end of 2011. This could include a potential partnership, farm out, swap or divestiture. Companies from around the world have shown interest in this opportunity and Cenovus is assessing which potential transaction would provide the best value for the company.

Capital investment will be focused on growing the company's oil assets with a total average annual investment of about $3.0 billion to $3.5 billion planned over the next decade. Cenovus is committed to maintaining its cost-efficient manufacturing approach with all its oil sands expansions, allowing it to implement improvements with each new phase and deliver expansions on time and on budget. The company expects to continue achieving industry-leading low steam to oil ratios (SORs) and capital efficiencies of between $22,000 and $23,000 per flowing barrel at Christina Lake phases C, D and E and between $25,000 and $28,000 per flowing barrel at Foster Creek phases F, G and H. There is considerable flexibility built into Cenovus' capital plan since most of the investment is discretionary with only $1.1 billion of the 2012 plan considered to be committed capital needed to maintain current operations and construct currently approved oil sands expansions. Cenovus anticipates an average of $0.8 billion to $1.0 billion in committed capital for each of the remaining years of the next decade.

Cenovus plans to take a balanced approach to its use of cash flow in excess of committed capital. A priority is expected to be placed on using excess cash flow to grow the dividend after 2011. Organic growth opportunities will be funded with the balance of free cash flow and the prudent use of balance sheet capacity. If necessary, additional debt financing will be used to support capital investment for the first half of the 10-year plan. The company is committed to maintaining strong investment grade status and anticipates its debt to capitalization and debt to adjusted EBITDA ratios will track to the low end of its targeted ranges.

While the bulk of Cenovus' future growth will be in the oil sands, the company also expects significant near-term growth in conventional oil production. The strategic plan anticipates oil production from operations such as Pelican Lake, Weyburn, southern Alberta, Saskatchewan Bakken and Lower Shaunavon will increase to between 120,000 bbls/d and 130,000 bbls/d by the end of 2016 from about 70,000 bbls/d currently. Additionally, the company plans to assess the potential of new oil projects on its existing properties and new regions, especially tight oil opportunities.

Cenovus will continue to steward its natural gas operations as financial assets that contribute significantly to its oil growth projects. Over the next decade, the managed decline of natural gas production, combined with expected production increases from oil properties, should result in an even greater percentage of cash flow coming from oil operations. Natural gas is expected to provide only 5% of the company's operating cash flow in 2021 compared with about 20% in 2011. Cenovus plans to continue to protect its cash flow and capital program by hedging as much as 75% of its natural gas production although the company expects to reduce the amount of oil it hedges in the coming years.

A key enabler for the company's long-term plan is access to attractive markets for its heavy oil production. Heavy refining capacity will increase when the coker and refinery expansion (CORE) project at the company's Wood River Refinery is complete, expected later this year. However, Cenovus' oil sands growth plans will eventually result in more heavy production than the company has the capacity to refine at its two U.S. refineries, both jointly owned with ConocoPhillips. Over the coming years, Cenovus will look at opportunities to protect a greater percentage of its future heavy volumes from the light-heavy differential.

Cenovus expects to maintain industry-leading low operating costs at its oil sands projects and remains committed to the goal of doubling its net asset value between 2010 and 2015. It plans to accomplish this by growing production internally with no acquisitions required. The company also plans to continue developing innovative techniques to improve recovery and unlock development opportunities on its expansive oil sands resource.

"We are fostering a culture at Cenovus that encourages innovative thinking," Ferguson said. "The technology modifications and breakthroughs being developed by our staff are expected to result in improved project economics, more resources being placed in the contingent category and a reduced impact on the environment."

The company will maintain its goal of commercializing at least one new research and development (R&D) technology every year and plans to continue to have more than 60 projects in various stages at all times. Cenovus has 10 field pilots underway or planned to help understand recovery schemes and demonstrate commercial potential. Technology development at Cenovus will continue to focus on increasing recovery factors while enhancing environmental performance, with three-quarters of current R&D projects offering potential environmental benefits.

NOTE: Between 2012 and 2021, Cenovus' strategic plan assumes WTI oil prices that range from US $85.00/bbl to US $105.00/bbl, NYMEX natural gas prices that range from US $4.00/Mcf to US $6.00/Mcf and a Chicago 3-2-1 crack spread of US $9.00/bbl.

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Gazprom to Reach Pre-Crisis Output 2013, Sees Increase in 2014

- Gazprom to Reach Pre-Crisis Output 2013, Sees Increase in 2014

Thursday, June 02, 2011
Dow Jones Newswires
by Alexander Kolyandr

Gazprom expects to reach its "pre-crisis production level" in 2013, for which it needs to put the Yamal field on-line in 2012, said the company's Deputy Chief Executive Alexander Ananenkov.

Speaking at a televised press conference, he said the company is aiming to reach a production level of about 550 billion cubic meters (BCM) of gas, first reached in 2006, in 2013.

He said Gazprom is currently producing gas ahead of the planned level of 505.6 BCM and may reach production of 519 BCM in 2011.

By 2014 there will be a significant production growth and the company may increase production to 570 BCM.

Gazprom said late 2010 it expects gas production to be between 570 billion cubic meters and 580 billion cubic meters by 2015.

Ananenkov said to enable this production growth the company needs to start full production on Yamal gas field.

He said the company is not planning to start any production on Kovykta gas field before 2017.

Ananenkov said Russia's total gas production may reach 1 trillion cubic meters by 2030.

Copyright (c) 2011 Dow Jones & Company, Inc.

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CNOOC: Confident Will Achieve Full Year Output Target this Year

- CNOOC: Confident Will Achieve Full Year Output Target this Year

Friday, May 27, 2011
Dow Jones Newswires
by Yvonne Lee

CNOOC expects to meet its full-year output target despite the shutdown of four oil fields in the Bohai Bay last month due to a malfunction, Chief Executive Yang Hua said Friday.

Cnooc said in March it planned to raise crude-oil and natural gas output in 2011, targeting production of 355 million-365 million barrels of oil equivalent, up 8%-11% from 328.8 million barrels in 2010.

The company is also targeting oil and gas output growth at a compound annual rate of 6%-10% between 2011 and 2015.

In April, four of Cnooc's oil fields with a total production capacity of about 39,000 barrels a day were shut down following a malfunction at a vessel in the Bohai Bay caused by rough sea conditions.

Yang also said he expects the company to drill four to six deep-water wells in the South China Sea this year, and added that the company plans to accelerate oil exploration in deep-water wells over the next four years.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Toyota Motor Said It Will Increase Production Capacity At Its Indonesian Plant

- Toyota Motor Said It Will Increase Production Capacity At Its Indonesian Plant



May 25, 2011

Toyota Motor Corp. (NYSE:TM) said it will increase production capacity at a plant in Indonesia in its first manufacturing investment deal since the earthquake in Japan as the company continues efforts to bring output operations back to normal.

Toyota plans to lift annual output capacity at Karawang to 140,000 vehicles, up from the current 100,000.

Toyota Motor has a potential upside of 14.4% based on a current price of $80.76 and an average consensus analyst price target of $92.4.

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Reliance Debunks Claims on KG-D6 Output Decline

Reliance Debunks Claims on KG-D6 Output Decline

Monday, May 09, 2011
Asia Pulse Pte Ltd

India's Reliance Industries has debunked charges that KG-D6 gas field output fell due to non-drilling of an adequate number of wells, saying the phenomenon was a result of reservoir complexity and indiscriminate drilling would have lead to infructous capital expenditure.

The drop in production from over 61 million cubic meters per day achieved in March, 2010, to under 50 mmcmd was a result of the main reservoir channels not behaving in the manner predicted in 2006.

"Reliance has told us that pressure in wells has fallen rapidly and some wells haven shown early water ingress," an Oil Ministry official said. "They made a detailed presentation on the problems being faced at the field on May 2 and by the look of it, we feel there are some genuine reservoir issues."

More wells on the main channel area of the Dhirubhai-1 and 3 fields, the largest of the 18 gas finds in the block that were put into production in 2009, is unlikely to either raise production rate or recovery as they will drain the same resource, he said.

Reliance will identify disconnected gas volumes and drill wells on them, an exercise that will take 3-4 years.

It has drilled 20 out of the 22 wells committed in the field development plan (FDP) as it now feels that drilling of additional wells unmindful of the reservoir behavior would have resulted in huge capital expenditure which would have been difficult to justify later.

Oil regulator DGH is pushing for drilling of 11 committed wells by April 1, 2012, to raise output. Reliance wants UK's BP Plc to come on board first.

BP is buying 30 percent interest in KG-D6 and 22 other blocks for US$7.2 billion.

Once the government approves the stake buy, Reliance plans to sit with BP to come up with most optimal solution to the reservoir problem including drilling of additional wells.

Reliance is allowed to recover every penny spent on the field from sale of gas before profits are split with the government. Investment in injudicious additional wells would have led to a reduction in the government's petroleum profit.

Sitting in water depths of up to 1.2 kilometers, the KG-D6 is the first deepsea field in South Asia to go on production and there are no deepwater analogs available for reference on how the reservoir will behave.

As a result, Reliance had to depend on its own resources and some global industry consultants for the characterization, modelling and development of this complex deepwater reservoir system.

Current wells have no contribution from the areas outside the main channel area, contrary to what was predicted at the time of FDP in 2006.

(C) 2011 Asia Pulse Pte Ltd.

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India, RIL in Proxy Fight Over KG-D6 Output Decline - Bernstein

India, RIL in Proxy Fight Over KG-D6 Output Decline - Bernstein

Thursday, May 05, 2011
Asia Pulse Pte Ltd

India's Reliance Industries wants a hike in the price of natural gas to resume drilling in the KG-D6 fields, which have seen a sharp drop in output due to drilling of less wells than committed, investment research group Sanford C Bernstein & Co said.

"We believe that RIL doesn't believe it is worth its while to invest additional capital in drilling wells when the price at the beach remains at US$4.20" per million British thermal units, Neil Beveridge, a Hong Kong-based analyst for Bernstein, said in a report on Thursday.

Gas output from the Dhirubhai-1 and 3 fields in the KG-D6 block had steadily risen to 53 million standard cubic meters per day in March last year, but have dropped to below 42 mmscmd now instead of rising to the projected level of 61 mmscmd.

Another 8 mmscmd is produced from the MA field in the same block, taking the total output from KG-D6 to about 50 mmscmd.

The fall in output due to drilling of less wells had earned RIL the ire of the government and the regulator DGH.

While the DGH is pressing RIL to drill more wells outside the main channel that is currently producing, the government is pressuring RIL by directing it to supply gas to priority sectors like fertilizer and power and cut off sales to refineries and petrochemical plants, including its own.

"We believe that this is a proxy fight between the government and RIL," Bernstein Research said.

"Lower production output is primarily a function of the hiatus in development drilling," it said. "While it seems likely that the reservoir is more complex than originally anticipated, performance on a per well basis has not been too dissimilar to the original field development plan.

"Instead, the lower number of development wells drilled (18 versus 22 planned) is primarily the reason for the under-performance," it said.

Bernstein said completion of Phase - I drilling plus initiation of Phase-II drilling, when the total number of wells could reach up to 50, would restore output growth.

"We believe that the natural rate of the decline in production for the KG-D6 wells is around 20 percent annually, or around 5 percent per quarter, not substantially different from similar fields around the world," it said.

"In case RIL doesn't take any more action on the drilling of wells and connecting those to the reservoir and continues operating with 18 wells, we expect the production to reach a level of around 37-38 mmscmd by FY'2013," Bernstein said.

The government has asked the company to drill 11 wells by the fiscal-end to take the total number to 31 as had been planned when RIL won approval for investing $8.8 billion, S.K. Srivastava, the director general of the country's oil regulator, had said earlier this week.

RIL will submit a drilling plan in two weeks, he had said on May 2.

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Husky's 1Q Profit Leaps on Higher Output, Prices

Husky's 1Q Profit Leaps on Higher Output, Prices

Wednesday, April 27, 2011
Husky Energy Inc.

Husky achieved strong earnings and cash flow growth in the first quarter of 2011 compared to the same quarter of 2010. Performance was driven primarily by increased production volumes, higher realized crude oil prices for the Atlantic Region and South East Asia, and higher throughput rates and margins within the downstream segment.

"Our first quarter results are in accordance with our execution plan," said CEO Asim Ghosh. "Actions undertaken to grow near-term production have achieved the intended result during a period of strengthening prices. At the same time, our downstream refining segment posted strong performance, with higher throughput enabling us to capitalize on improving market conditions."

"In addition, we have made steady progress in advancing our mid and long-term growth initiatives. Steps taken in the quarter have enabled Husky to achieve important milestones towards progressing the Liwan Gas Project offshore China. This project will create shareholder value by tapping into the fast growing energy markets in Hong Kong and mainland China."


A summary of first quarter results, together with recent key highlights, follows:

• Net earnings of $626 million, or $0.70 per share (diluted), including an after-tax gain of $143 million on the sale of non-core assets, an increase of 70 percent from a year ago.
• Cash flow from operations of $1,164 million, or $1.30 per share (diluted), an increase of 36 percent from a year ago.
• Total production before royalties for the quarter averaged 310,400 boe/day, 5 percent above the same quarter of last year and 11 percent higher than the fourth quarter of 2010.
• Progressed the Liwan Gas Project as the Company expects to submit the Overall Development Plan for Liwan 3-1 to the Chinese authorities in the second quarter. The Liwan Gas Project includes several fields; Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 with first gas anticipated from Liwan 3-1 and Liuhua 34-2 in late 2013, ramping up through 2014. Liuhua 29-1 production is anticipated late 2014. Husky's production share is 49 percent.
• Liwan gas is expected to be sold under a long-term contract at competitive prices in the Guangdong and Hong Kong markets.
• Phase I of the Sunrise Energy Project progressed on schedule as development drilling commenced in early 2011 with 12 horizontal wells spud and seven drilled in the quarter.
• In the Atlantic Region, the Company continued to ramp up North Amethyst volumes.
• The Lloydminster Upgrader resumed normal operations in April at which time repairs were completed.
• Closed the previously announced Western Canada asset acquisition on February 4th.
• Closed a $300 million preferred share financing to enhance our liquidity and financial flexibility.

First quarter production averaged 310,400 boe/day in line with guidance. Volumes compare positively with 280,500 boe/day in the fourth quarter of 2010 and 295,900 boe/day in first quarter of 2010. Production volumes were driven higher by the February closing of the Western Canada asset acquisition and good performance from White Rose and North Amethyst.

First quarter cash flow and earnings growth were driven by higher upstream production volumes, higher realized light crude oil prices for the Atlantic Region and South East Asia, and stronger throughput rates and margins within the downstream segment. These were partially offset by the impact on Western Canada realized crude oil pricing of higher discounts to WTI, the impact of a strong Canadian dollar, lower throughput at the Lloydminster Upgrader and weak natural gas prices.

Light crude oil prices averaged U.S. $104.97 per barrel for the quarter, 38 percent higher compared to same period of 2010. Of the Company's total production, approximately 20 percent is priced and sold relative to light crude prices (North Sea Brent). U.S. refining market crack spreads were stronger during the quarter with the average Chicago 3:2:1 crack spread at U.S. $16.58 per barrel, compared to U.S. $6.23 in the same period of 2010.

"We continue to prudently manage our financial position and exercise discipline in all aspects of our capital and operating expenditures," said Alister Cowan, CFO.

KEY AREA SUMMARY AND GROWTH UPDATE:

Western Canada - Unconventional and Conventional

The Company continues to maintain production levels from Western Canada and has accelerated development drilling.

Oil Resource Plays

Within the oil resource portfolio, the Company is focused on developing its opportunities in the Lower Shaunavon and Bakken zones in Southern Saskatchewan along with the Viking zone in Southwest Saskatchewan and central Alberta. Husky has approximately 500,000 net acres in its oil resource portfolio. Seventeen wells were drilled during the period with six placed on production.

Gas Resource Plays

Husky advanced development drilling of its liquids-rich gas assets in the Alberta Deep Basin. In the Ansell area, four rigs were active and a total of 20 Cardium formation wells were drilled during the quarter and an additional six exploration and development wells were drilled in Kakwa, Bivouac, the Horn River Basin and on the Cypress acreage.

Through a combination of crown land sales and private purchases, Husky increased its land holdings in its gas resource portfolio during the first quarter by 29,000 acres.

Heavy Oil

Husky is amongst the industry leaders in heavy oil production and has a significant land and resource portfolio along with a solid integrated infrastructure position. Within its heavy oil operations, the Company's strategy is focused on maintaining production levels, being a low cost producer and continuing to drive new enhanced recovery techniques to sustain production volumes.

Construction of the 8,000 bbl/day South Pikes Peak project was approximately 58 percent complete at the end of the first quarter with production expected in mid 2012. The project continues to progress as expected.

The 3,000 bbl/day Paradise Hill project activity commenced in the first quarter, and will utilize the existing Bolney infrastructure. Production is anticipated in late 2012.

Oil Sands

The Company advanced the recently sanctioned Phase I Sunrise Energy Project. Twelve horizontal wells were spud and seven drilled during the quarter. The Company made several significant equipment orders that included the steam generators, vessels, water treating plant and a camp to support the project.

Tucker contributed positive earnings in the quarter with an average production volume of 6,200 bbls/day. Further wells will be brought on production in the second quarter.

Atlantic Region

Through the first quarter, North Amethyst performed well with average production of 21,400 bbls/day net to Husky. In 2011, Husky expects to tie-in an additional producer and one more injector well.

The West White Rose satellite pilot development is progressing on schedule. These wells will provide additional information on the reservoir to refine understanding of the best development scheme for the full West White Rose field. First production from the pilot is anticipated in the third quarter of 2011.

Husky holds exploration rights to nineteen parcels of land in the area. In 2011, the Company plans to participate in the drilling of an appraisal well at the Mizzen discovery and an exploration well to the south of Terra Nova.

South East Asia

Development of the Liwan Gas Project is progressing in accordance with the Heads of Agreement signed with China National Offshore Oil Corporation (CNOOC) in December 2010. Under the Heads of Agreement, Husky will operate the deepwater portion of the project involving development drilling and completions, subsea equipment and controls, and subsea tie-backs to a shallow water platform. CNOOC will operate the shallow water portion of the project including a shallow water platform, approximately 270 km of subsea pipeline to shore, and the onshore gas processing plant.

Development of the Liwan Gas Project comprises three discoveries on Block 29/26; Liwan 3-1, Liuhua 34-2 and Liuhua 29-1, with first gas production expected in late 2013, ramping up through 2014. Official project sanction is expected later in 2011. It is anticipated the natural gas will be sold under a long-term contract at competitive prices in the Guangdong and Hong Kong markets.

The partnership has made considerable progress in advancing the Liwan Gas Project as the Overall Development Plan (ODP) for Liwan 3-1 has been prepared and is undergoing final reviews with submission to authorities scheduled in the second quarter. Development of the Liwan 3-1 and Liuhua 34-2 fields are proceeding in parallel and will share infrastructure. The ODP for the Liuhua 34-2 field is in preparation and planned for submission to authorities mid-2011. Liuhua 29-1 is expected to be fully delineated later this year with an ODP submission targeted before year end.

All nine development wells for the Liwan 3-1 field have been successfully drilled confirming the quality and extent of the reservoir. Fabrication and construction has begun, and long lead time items ordered in accordance with the schedule. Deepwater installation and pipe lay work are planned to take place in 2012 and 2013.

CNOOC is progressing with the development of the shallow water portion of the project. The infrastructure is designed to allow for the tie-in of incremental wells and fields. Gas from the Liuhua 29-1 field will be processed through the same shallow water platform and onshore gas plant as the other two fields and is expected to come on stream in late 2014.

In Indonesia, Husky and its partners continue to progress and plan for the development of the BD and MDA gas fields with first gas production expected in 2014. The long lead time items for the BD field, including the FPSO, are set to go to tender by mid-year. An appraisal well for the MDA field will be drilled later this year as well as a nearby low risk exploratory well targeting the same type of reservoir.