AWE Reports Net Loss

- AWE Reports Net Loss

Monday, August 29, 2011
AWE Ltd.

AWE Limited has announced a statutory net loss of $117.6 million for the 12 months to June 2011. After adjustment for significant one-off, the underlying loss was $16.1 million.

The Company's production assets performed strongly with production of 6.1 million BOE. This delivered a 61% increase in after tax net cash flow from operating activities of $140 million, which included exploration expense of $21 million.

Investment in growth activities continued during the year, with $32 million invested in the completion of the Adelphi takeover, $69 million in exploration activities and a further $80 million in project developments (primarily BassGas MLE and Sugarloaf drilling).

The Adelphi Energy takeover, completed during the year, provides AWE with access to an exciting gas and liquids development project in the US, which is delivering strong initial production performance. Reserve reporting to date at Sugarloaf has highlighted the growth potential of the asset, with 2P reserves increasing to 8.5 million BOE at June, 2011.

The Company reported a cash position of $117 million, at June 30, 2011 with an undrawn $150 million loan facility.

Commenting on the result, AWE's Managing Director Bruce Clement said, "The Company's core business continues to perform well as evidenced by the increased operating cashflow of $140 million for the year, reflecting the strength and diversity of AWE's portfolio of production assets.

"The statutory loss of $118 million was impacted by a number of significant one-off factors, primarily asset impairments and the derecognition of previously booked tax losses.

"The second half of 2010/11 has been a period of consolidation for AWE following an extended period of major exploration activity.

"The Company's focus has been on delivering its core production operations, exploiting its existing asset base and establishing its tight gas and shale gas business through the Sugarloaf acquisition and the Perth Basin exploration initiatives. The Company has also completed a comprehensive review of its core assets.

"Looking forward, AWE has a strong balance sheet, robust future cash flow from its 66 million BOE 2P reserve base and significant potential in its Perth Basin gas exploration assets with access to premium domestic markets.

"The Company's near term plans will focus on continuing the strong performance of the base business, exploiting its tight gas and shale gas projects and pursuing selective growth opportunities.

"The Board and Management of AWE are confident about the Company's future. AWE is well positioned to build on its existing assets and to take advantage of opportunities in the current volatile business environment."

Finance

Operating cashflow was strong for the year, rising 61% to $140 million. The reported cashflow included exploration expense of $21 million and significant Tui and Cliff Head workover costs of $29 million.

The year-end financial position of the Company was strong, with cash of $117 million and no debt (and with a $150 million undrawn corporate debt facility available if required).

AWE's sales revenue fell 14% to $305 million for the year, with net field contributions also lower at $172 million. Total oil and gas sales volumes were in line with the prior year, although oil production was down by 36%, offset by increased gas and associated gas liquids sales over the period. Average received oil prices improved to approximately $91 per barrel, as a result in the stronger international prices partially offset by the stronger A$.

In accordance with AWE's successful efforts accounting policy, $63 million of exploration costs were expensed during the year. These costs were largely related to unsuccessful drilling activity in New Zealand, Yemen and Australia.

A net exploration impairment charge of $61 million (post tax) impacted the statutory results. This impairment included the write down of the Yemen and Bass Basin exploration assets acquired as part of the ARC Energy merger in 2008. In addition, a post-tax net oil and gas asset impairment of $15 million was also recorded (largely related to the Cliff Head project).

Subsequent to the end of the year, AWE sold its shareholding in Buru Energy Limited for a cash consideration of $17 million. These funds were received after year end and are not included in the reported results.

Exploration

Exploration expenditure for the year was primarily incurred on the conventional oil and gas exploration opportunities in Australia, New Zealand and Yemen.

In the latter part of year, AWE accelerated activities in tight gas and shale gas exploration in the onshore Perth Basin, where drilling of the Arrowsmith-2 well has been completed and hydraulic stimulations are being planned. Timing of the hydraulic stimulation activity is subject to the receipt of all regulatory approvals.

AWE continues to pursue further conventional and unconventional exploration opportunities, applying an added degree of financial and technical discipline.

Development

The Adelphi takeover was completed during the year, and development drilling activity in its USA operations has accelerated since the acquisition was finalised. An independent reserve statement was released in March 2011, which reported a 37% improvement (to 8.6 million BOE net to AWE) in existing 2P reserves in the Sugarloaf AMI. Further drilling activity is expected to see added conversion of possible reserves into the 2P reserves category during 2011/12.

The $346 million gross budget for first phase of the Yolla MLE project was approved during the year and significant progress has been made with the onshore fabrication of gas compression and accommodation modules and preparations for offshore installation at the end of 2011. An extended production shutdown is planned during the offshore installation activities (December to April).

The second phase of the development will incorporate the drilling of at least two additional development wells on the Yolla field and remains on schedule for late 2012/early 2013. Engineering planning, including the evaluation of additional upside potential in the field, is continuing with budget commitment expected by end 2011. Total expenditure to June 30, 2011 on the MLE project was $107 million.

Production well workovers were successfully completed on the Pateke and Cliff Head projects, with the Cliff Head-12 well workover increasing production from the Cliff Head field by over 1,500 bopd after coming on stream in August 2011.

2011-2012 guidance

Production guidance for the current financial year has been set at 5.0 to 5.5 million BOE, substantially impacted by the planned extended shutdown of the Yolla field for the offshore installation activities associated with the MLE project. Based on a A$100 per
barrel Brent oil price for the year, AWE expects oil and gas sales revenue to reach a range of $270 to $300 million. Planned exploration expenditure for the year is estimated at $50 million, with development expenditure planned to reach $150 million, the majority of which will be incurred on the BassGas MLE project.

With a net cash position of $117 million AWE is well positioned to further exploit those assets within the Company's existing portfolio and take advantage of opportunities to add to its asset base.

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Commodity Corner: Oil Ends Week Lower

- Commodity Corner: Oil Ends Week Lower

Friday, August 19, 2011
Rigzone Staff
by Saaniya Bangee

Light, sweet crude posted a slight loss Friday, pressured by yesterday's bearish stock sell-off, as well as a series of negative economic data.

Oil futures ended the week 12 cents lower, settling at $82.26 a barrel Friday and down 3.7 percent for the week. Oil prices traded as low as $79.17 after an earlier intraday peak of $83.55, which was caused by an early rise in the stock market.

Crude gained some support Friday from a weaker dollar. The Dollar Index, which measures the dollar against a basket of major foreign currencies, traded at 74.002 from 74.216. The greenback reached a new post-World War II low against the Japanese yen.

Meanwhile, the September Brent contract price settled $1.63 higher at $108.62 a barrel. The intraday range for Brent was $106.43 to $109.30 a barrel.

Natural gas for September delivery gained nearly 5 cents, or 1.2 percent, to settle at $3.94 per thousand cubic feet. Natural gas fluctuated between $3.90 and $3.97 for the last trading session of the week.

Front-month gasoline advanced 5.80 cents to finish at $2.84 a gallon Friday. RBOB rose for a second straight week.

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Risk Is A Four Letter Word

- Risk Is A Four Letter Word

Thursday, August 18, 2011
Rigzone Staff
by Trey Cowan

The average investor often overlooks the simple concept of how the market discounts risk. Risk and reward typically correlate strongly with one another. Currently, the risk premium that an investor demands in exchange for lending to broader markets is expanding. In broad terms, investors must be anticipating that future risk levels are increasing.

To better define the risk/reward relationship, we first point to the current situation surrounding the 10-Year Treasury Note. From July through the week ending August 12, 2011, the note's yield has declined 26 percent from 3.18 percent to a 2.34 percent. Today, the 10-Year dropped below 2 percent.

Previously, the lowest the yield on the 10-year was 2.12 percent, set in December 2008; when fears regarding the global credit freeze were near their highest levels. Yields for fixed income instruments respond inversely to price. Investors buy the 10-Year to reallocate their holdings away from risk and into this safe-haven, which has the effect of driving the price up. We note the key concept in finance: the yield on a 10-Year is often looked upon as the proxy for the risk-free rate of return.

Another component in the valuation of assets is the risk premium. As the risk-free rate of return shrinks the average risk premium an investor demands must rise. In other words, if the 10-year yield is falling, then market risk is actually on the rise. Let's assume for a moment that an investor wants a 10 percent return on their investment. If the risk free rate has dropped from 3 percent to 2 percent, then the risk premium that investor is willing to take on has grown by a corresponding amount. Otherwise, the investor's required return falls to 9 percent (signifying their aversion to taking on additional risk). Therefore, when we see dramatic drops in the 10-year, like what just took place, all else equal, investment risks must be perceived to be on the rise. Such a move is justified to mathematically keep the overall return at equilibrium.

Using the earnings estimates we can prove that these financial concepts are factoring into current market valuations. For our example we are using the earning's yield of the the S&P 500 Index. We took the recent annual earnings for the S&P 500, $112.8, and divided it by the index value for the week ending August 12, 2011 (1178.81). What we found was that the earnings-to-price (E/P) yield was 9.5 percent. If you subtract the corresponding 10-year treasury yield (i.e. the risk-free rate) of 2.3 percent from the E/P, the remainder is the risk premium for the S&P 500 Index (i.e. 7.2 percent).

The risk premium for the S&P 500 is relevant for two issues. First, the S&P 500 includes only well-capitalized U.S. operated firms of a significant size. If the market expects a total earnings yield of 9.5 percent for blue-chip U.S. firms, then obviously the required return (and associated risk) for lesser quality investments is going to be higher. Second, the current risk premium at 7.3 percent for the S&P 500 is well outside the norm (3.85 percent average since 2005 and 5 percent YTD).

This growing level of inherent risk in the broader markets and the market's appetite for risk does have an impact on oil prices that is worth considering. Although the Fed's posture towards interest rates (and their vow to hold them low into 2013) would suggest that the dollar will remain weak, this is no time to get bullish on oil. Look no further than price variability to understand our reasoning. Since 2005, one standard deviation in the price of a barrel of oil represents 25 percent of the total price. Conversely, one standard deviation in the S&P 500 Index approximates 15 percent of the total. Therefore, at a time when the market is risk averse, an investment in crude oil bears with it 66 percent more risk than the total market.

Suppose that inherent in recent market sentiment is a fear that the U.S. economic growth profile for next year will slip by about 10 percent or approximately three-tenths of one percent of GDP. Ultimately, such a scenario would be accompanied by less demand for oil. We used regression analysis to compute the value of one barrel of oil based on a 10 percent decline in S&P 500 earnings using observations starting in 2005. Our calculations peg the implied value of WTI crude oil at $84/barrel based on if NTM earnings estimates drop $11 for the S&P 500 Index. Our calculations would be well below what the EIA and leading economist recently had considered a reasonable assumption for next year (+$100/bbl).

Also, consider how much the current risk premium exceeds its average 52-week value. Recent history suggests that a growing risk premium (that is well outside this 52-wk norm) spells trouble for oil prices. Back in 2008, risk premium exceeded its own norm by 2 percentage points. Oil prices in the subsequent 10 weeks fell 53 percent. Again in 2010, the S&P 500 risk premium broke 2 percent above its norm and oil prices fell 5 percent in the following ten weeks. With the markets now showing a risk premium that is again 2 percent above the norm, a repeat of this pattern does not seem far-fetched.

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Oil, Freight Prices Lift Denmark's Moller-Maersk

- Oil, Freight Prices Lift Denmark's Moller-Maersk

Wednesday, August 17, 2011
Knight Ridder/Tribune Business News
by Lennart Simonsson, dpa, Berlin

Higher oil prices and more freight volumes lifted Danish shipping and oil group Moller-Maersk's six-month net profit to 2.7 billion dollars, the group said Wednesday.

The net profit was up 8 percent on the first half of 2010, the conglomerate said.

Turnover, measured in dollars, rose 9 percent year-on-year to 29.9 billion dollars.

The group that operates Maersk Line, the world's biggest container shipper, said it expected global demand for seaborne containers to grow by 6 to 8 percent in 2011.

In the short term, it said freight prices were not expected to rise due to addition of new tonnage, especially on routes between Asia and Europe. Higher oil prices could also weigh on profit.

The group repeated its earlier statement that it expected full-year results to be lower than in 2010.

The group's total fleet counted 621 container vessels at the end of the six-month period, of which 376 were chartered.

AP Moller-Maersk Group operations include sea transport, offshore oil and gas activities and retail and shipyard operations.

Year-on-year the oil price was 44 percent higher but production decreased 11 percent, mainly as a result of a lower production share in Qatar and lower output in the Danish and British section of the North Sea, the group said.

During the January-June period the group was also involved in exploration in Angola, Brazil, Denmark, Norway, Qatar, Britain and the United States. Exploration costs almost doubled to 355 million dollars.

Copyright (c) 2011, dpa, Berlin

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Gas Prices Fall $0.10

- Gas Prices Fall $0.10



Aug 12, 2011

Oil prices continued to fall during the week but gasoline prices are taking bit longer to catch up.

Some motorists saw some relief as the national average of self-serve regular gasoline fell today to $3.60 a gallon, down $0.10 from $3.70, according to AAA.

The prices of oil fell around $82 a barrel this week as anxiety increased over the European debt crisis and mounting evidence that the economy in the U.S. is slowing once again.

Many oil analysts claimed for months that oil prices were overpriced, based on market fundamentals.

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Baker Hughes Prices Senior Notes

- Baker Hughes Prices Senior Notes

Thursday, August 11, 2011
Baker Hughes Inc.

Baker Hughes announced the pricing of $750 million aggregate principal amount of its 3.20% senior notes due August 15, 2021. Interest is payable on February 15 and August 15 of each year. The first interest payment will be made on February 15, 2012, and will consist of interest from closing to that date. The offering is expected to close on August 17, 2011, subject to customary closing conditions.

The company intends to use the net proceeds of the offering to redeem all of its outstanding 6.50% senior notes due 2013, of which an aggregate principal amount of $500 million is currently outstanding. The company will use any remaining net proceeds for general corporate purposes, which could include funding ongoing operations, business acquisitions and repurchases of the company's common stock. The net proceeds of the offering may be invested temporarily in short-term marketable securities pending such usages.

The notes to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The notes will be offered and issued only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S.

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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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Oil Prices Fall As Gasoline Supplies And Pump Prices Rise

- Oil Prices Fall As Gasoline Supplies And Pump Prices Rise



Jul 27, 2011

The price of oil is falling after the government announced the nation's oil and gasoline supplies increased last week.

On Wednesday morning, Benchmark West Texas Intermediate crude for September lost $1.50 to $98.90 per barrel at the New York Mercantile Exchange.

The Energy Department stated that oil inventories increased 2.3 million barrels to 354 million barrels last week. Supplies of gasoline raised to 213.5 million barrels. The demand for gas over the past four weeks remains below year-ago levels.

Prices at gasoline stations rose about half a cent on Wednesday to a national average of $3.698 a gallon which is just about $1 more than a year ago.

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Delta Airlines Q2 Misses Earnings Estimates Due To Costly Fuel Prices

- Delta Airlines Q2 Misses Earnings Estimates Due To Costly Fuel Prices



Jul 27, 2011

Delta Airlines (NYSE:DAL) reported a Q2 loss of $0.43, narrower than analyst estimates for a loss of $0.46 per share. Revenues for the quarter rose 12.1% year-over-year to $9.15 billion, missing consensus estimates of $9.16 billion.

Richard Anderson, Delta's chief executive officer said, "High fuel prices are putting significant pressure on the industry, but the benefits of Delta's strategic actions and the dedication of Delta employees are evident in the solid profit we produced despite more than $1 billion in higher fuel expense. Our revenue momentum, coupled with the capacity reductions we are making in September and actions to get our non-fuel costs to 2010 levels, will generate the margins we need to hit our return targets."

Delta Air Lines (NYSE:DAL) has a potential upside of 80.1% based on a current price of $8.02 and an average consensus analyst price target of $14.44.

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Hess' Second-Quarter Net Surges 62% On High Oil Prices

- Hess' Second-Quarter Net Surges 62% On High Oil Prices

Wednesday, July 27, 2011
Dow Jones Newswires
by Tess Stynes & Ryan Dezember

Hess' second-quarter earnings soared 62% thanks to sharply higher oil prices and despite a wider loss for its marketing and refining operations.

Hess' performance in recent quarters has been boosted by high oil prices, as well as improved demand for gasoline and diesel products. However, its marketing and refining business has continued to lag.

Hess reported a profit of $607 million, or $1.78 a share, up from $375 million, or $1.15 a share, a year earlier. Revenue climbed 27% to $9.81 billion.

Analysts polled by Thomson Reuters most recently forecast earnings of $1.94 a share on revenue of $10.08 billion.

Pearce Hammond, an analyst with Houston investment bank Simmons & Co., said that Hess' trading losses as well as those from its refining joint venture with Venezuela's state oil company were "major disappointments." Overall, the results "will likely weigh on the stock today," Hammond wrote in a note to clients.

Shares recently traded 3.13% lower at $70.80.

Earnings at the exploration-and-production segment, which accounts for most of Hess' profit, surged 53% despite lower production. Average prices, excluding hedging impacts, jumped 46% for oil and 6.5% for natural gas.

In the marketing and refining business, losses widened in the refining-and-trading segments, while marketing income strengthened by 65%.

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

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Commodity Corner: Debt Talks Boost Crude

- Commodity Corner: Debt Talks Boost Crude

Tuesday, July 26, 2011
Rigzone Staff
by Saaniya Bangee

Crude prices briefly passed the $100-mark Tuesday as investors remained uncertain about the U.S. economy.

Tuesday's trading volumes were moderate as oil traders anticipated the upcoming deal. Oil prices fluctuated between $97.76 and $100.62 during the trading session. Republican and Democrat lawmakers are trying to compromise on a deal to raise the federal government's debt ceiling ahead of the Treasury Department's Aug. 2 deadline.

Likewise, the political maneuvering surrounding the debt ceiling prompted the dollar to drop against the euro. Against a basket of six other major currencies, the dollar index fell 0.6 percent to 73.595.

Light, sweet crude for September delivery settled at $99.59 a barrel Tuesday.

In other economic news, consumer confidence rose to 59.5 in July, according to a Conference Board report. In addition, the Commerce Department reported a 5-month high in new single family homes.

Its European counterpart, Brent crude added 34 cents, settling at $118.28 a barrel. Brent prices traded between a range of $116.59 and $118.98 Tuesday.

Meanwhile, natural for August delivery slid lower Tuesday, ending the session at $4.37 per thousand cubic feet. Natural gas prices fluctuated between $4.316 and $4.391 Tuesday.

The front-month contract expires at the close of Wednesday's trading session.

RBOB gasoline added 1.68 cents to settle at $3.15 a gallon. The intraday range was $3.095 to $3.17 Tuesday.

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Precision Drilling Prices Senior Notes

- Precision Drilling Prices Senior Notes

Tuesday, July 26, 2011
Precision Drilling Corp.

Precision Drilling announced that it priced US $400 million aggregate principal amount of 6.5% senior unsecured notes due 2021 (the "notes") in a private placement.

Precision intends to use the net proceeds from the notes offering to fund its capital expenditure program, including its 2011 new build program, and for general corporate purposes.

The notes are being offered to qualified institutional buyers under Rule 144A and may be offered outside the United States pursuant to Regulation S. The notes have not been registered under the U.S. Securities Act of 1933, as amended (the "Securities Act"), and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. This news release shall not constitute an offer to sell or the solicitation of an offer to buy any securities, including the notes, nor shall there be any offer or sale of the notes in any state, or jurisdiction in which such offer, solicitation, or sale would be unlawful.

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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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Chevron Sees Increase in 2Q Earnings on Higher Oil Prices

- Chevron Sees Increase in 2Q Earnings on Higher Oil Prices

Tuesday, July 12, 2011
Chevron Corp.

Chevron reported in its interim update that earnings for the second quarter 2011 are expected to be higher than in the first quarter 2011. Upstream results are projected to improve between sequential quarters, benefiting from higher crude oil prices.

Basis for Comparison in Interim Update

The interim update contains certain industry and company operating data for the second quarter 2011. The production volumes, realizations, margins and certain other items in the report are based on a portion of the quarter and are not necessarily indicative of Chevron's full quarterly results to be reported on July 29, 2011.

Unless noted otherwise, all commentary is based on two months of the second quarter 2011 versus full first quarter 2011 results.

UPSTREAM

U.S. net oil-equivalent production during the first two months of the second quarter was in line with the first quarter 2011. International net oil-equivalent production declined 76,000 barrels per day, largely reflecting maintenance activity in Kazakhstan.

U.S. crude-oil realizations for the first two months of the second quarter increased about $18 per barrel to $111.11, and International liquids realizations improved approximately $13 to $108.46 per barrel. U.S. natural gas realizations increased $0.28 to $4.32 per thousand cubic feet, and international natural gas realizations increased $0.41 to $5.44 per thousand cubic feet.

International Upstream earnings in the second quarter are expected to reflect higher exploration expenses.

The company's general guidance for the quarterly net after-tax charges related to corporate and other activities is between $250 million and $350 million. Due to foreign currency effects and the potential for irregularly occurring accruals related to income taxes and other matters, actual results may significantly differ from the guidance range.

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Commodity Corner: Oil Rises on Economic Data

- Commodity Corner: Oil Rises on Economic Data

Thursday, July 07, 2011
Rigzone Staff
by Saaniya Bangee

Propelled by forecasts that better days—and improved petroleum demand—are ahead for the global economy during the second half of this year, oil prices ended the day higher Thursday.

The front-month WTI contract price rose 2.09 percent Thursday, settling at $98.67 a barrel. Positive employment news contributed to the increase. According to the U.S. Labor Department, claims for unemployment benefits fell by 14,000—the lowest level in seven weeks. Meanwhile, payroll processor ADP said private-sector employment grew by 157,000 jobs last month. This is more than double of what economic experts had anticipated.

In addition, top U.S. retailers reported better-than-average sales for the month of June.

Light, sweet crude oil futures traded between $96.99 and $99.42—the highest intraday since June 15.

Its European counterpart gained nearly 5 dollars, settling at $118.59 per barrel on the ICE futures exchange. Brent prices fluctuated between $114.20 and $118.68 Thursday.

Natural gas for August delivery fell 8.8 cents Thursday on EIA reports. The U.S. Energy Information Agency reported a 634,000 barrel-decline in gasoline stocks, while distillate stocks fell by 191,000 barrels. Prices for natural gas peaked at $4.25 and bottomed out at $4.11, before settling at $4.138 per thousand cubic feet.

Gasoline futures added 9.23 cents a gallon, ending the trading session at $3.09 a gallon.

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UK Govt Raises Field Allowance for N. Sea Investment

- UK Govt Raises Field Allowance for N. Sea Investment

Tuesday, July 05, 2011
HM Treasury

The Government announced that the annual rate of the Ring Fence Expenditure Supplement (RFES) for the North Sea fiscal regime will be increased from 6% to 10%, following discussions with industry initiated at the 2011 Budget. This provides extra support for investment in the North Sea, including in marginal fields that qualify for the current field allowance, and will also support the ongoing considerations on new categories of field allowance.

In the Budget, as part of a package of measures to help motorists cope with high petrol prices, the Government announced a Fair Fuel Stabilizer that would be funded by higher taxation of the profits from oil and gas companies when oil prices are high. The Government said at that time that it would consider with the oil and gas industry the case for a new category of field that would qualify for field allowance to support investment in marginal fields.

In the course of those discussions with industry, the Government has identified that the ability of a company to benefit fully from the field allowance is dependent on whether a company has sufficient current taxable income against which to off-set expenditure. This is addressed to some extent by the Ring Fence Expenditure Supplement, which currently allows companies with insufficient taxable income to uprate losses by 6% for six accounting periods.

The increase to 10% announced today will help ensure existing field allowances work more effectively and equitably to support investment in marginal fields. It also brings RFES in line with the discount rate typically used by the sector.

The Government will continue to engage with oil and gas companies on the case for new categories of field qualifying for field allowance.

Justine Greening, Economic Secretary to the Treasury, said, "The Government was clear at the Budget that it would engage with oil and gas companies, including to consider the case for further support for marginal projects. Today's change demonstrates our commitment to ensure current allowances work effectively and equitably, and lays the groundwork for further constructive discussions on field allowances."

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Energy Sector Update: June 14, 2011

- Energy Sector Update: June 14, 2011



Jun 14, 2011

Energy shares are higher mid-day as the broader market is looking to regain lost ground. Light, sweet crude oil for July delivery traded up 1.5% to $98.78 a barrel. Cloud Peak Energy (NYSE:CLD), a U.S. coal producer, today, announced an agreement with Westshore Terminals LP to permit coal shipments through the Westshore Terminal in Vancouver, BC for ten years. Cloud Peak Energy exported 3.3 mln tons to Asian customers in 2010 through the terminal. The contract will commence in 2013 once the current contract ends, pending a definitive agreement between the parties.

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W&T Offshore Prices Senior Notes

- W&T Offshore Prices Senior Notes

Monday, June 06, 2011
W&T Offshore Inc.

W&T Offshore has priced at par its private offering of $600 million aggregate principal amount of 8.5% senior notes due 2019 (the "Senior Notes"). The offering is expected to close on June 10, 2011, subject to customary closing conditions.

W&T Offshore intends to use the net proceeds from the Senior Notes offering to fund the purchase price of its cash tender offer (the "Tender Offer") for any and all 8.25% senior notes due 2014 (the "2014 Notes"). To the extent less than all of the outstanding 2014 Notes are tendered or the Tender Offer is not consummated, W&T Offshore will use the net proceeds from the Senior Notes offering to redeem or repurchase any or all of the 2014 Notes remaining outstanding. The remaining net proceeds will be used to repay outstanding indebtedness incurred under its revolving bank credit facility that was used to fund a portion of its recent acquisition in the West Texas Permian Basin.

The Senior Notes have not been registered under the Securities Act of 1933, as amended (the "Securities Act") or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and state securities laws. The Senior Notes may be resold by the initial purchasers pursuant to Rule 144A and Regulation S under the Securities Act.

This press release is being issued pursuant to Rule 135c under the Securities Act, and is neither an offer to sell nor a solicitation of an offer to buy any of these securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale is unlawful.

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Energy Sector Update: June 1, 2011

- Energy Sector Update: June 1, 2011



Jun 1, 2011

Energy shares are down in mid-day trading as crude oil futures fall below $101 a barrel at the New York Mercantile Exchange. Light, sweet crude for July delivery is trading down 1.8% to $100.85 a barrel.

In mid-day news, shareholders for both Alpha Natural Resources (ANR) and Massey Energy Co. (MEE) today at their respective special stockholders' meetings said that they have approved various proposals related to Alpha's acquisition of all outstanding shares of Massey's common stock. The acquisition is anticipated to conclude later today.

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Exxon Mobil Gains 1.1%; Makes Progress Resolving Dispute with Nigeria

- Exxon Mobil Gains 1.1%; Makes Progress Resolving Dispute with Nigeria



May 25, 2011

Exxon Mobil (XOM) shares are higher on a Reuters report that the oil major and the Nigerian government are moving closer to resolving a dispute over oil licensing renewals.

The report said the renewals concern fields that produce over 500,000 barrels of oil per day.

Exxon shares are up 1.09%, or $0.87, to $82.15.

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