Oil and Gas News: 08/18/11

Thursday, August 18, 2011

Oil & Gas Post - All News Report for Thursday, August 18, 2011

Thursday, August 18, 2011

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Commodity Corner: Oil Plummets 5.9 Percent

- Commodity Corner: Oil Plummets 5.9 Percent

Thursday, August 18, 2011
Rigzone Staff
by Saaniya Bangee

A broad sell-off in stocks triggered recession fears Thursday, reversing crude's upward move yesterday.

Light, sweet crude futures dove nearly 6 percent Thursday to end the day at $82.38 a barrel. Futures settled as low as $81.15 a barrel. Lingering concerns over the global economy have pressured oil prices to decline 14 percent this month.

A Philadelphia Federal Reserve survey showed that factory activity in the Mid-Atlantic region weakened to its lowest level in more than two years. In addition, the U.S. Labor Department said initial unemployment benefits rose by 9,000 to 408,000 for the week ending Aug. 13.

Existing homes sales declined by 3.5 percent in July, marking an 8-month low, the National Association of Realtors reported.

Brent crude also settled lower at $107.05 a barrel on the ICE futures exchange, down $3.55 a barrel.

Natural gas for September delivery settled lower 4.1 cents at $3.89 per thousand cubic feet on an increase in U.S. stockpiles. The Energy Information Administration said inventories for natural gas grew by 50 billion cubic feet for the week ended Aug. 12. According to the reports, stockpiles were 2.5 percent below the 5-year average and 5.8 percent below 2010 levels.

A tropical wave identified approximately 200 miles east-northeast of Nicaragua has an 80 percent chance of becoming a cyclone over the next 48 hours, the U.S. National Hurricane Center reported.

The intraday range for natural gas was $3.843 to $3.92 Thursday.

September gasoline lost 3 percent Thursday settling at $2.78 a gallon. Gasoline prices fluctuated between $2.76 and $2.879 a gallon.

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Gas Boom Or Not, More Oil Rigs Now

- Gas Boom Or Not, More Oil Rigs Now

Thursday, August 18, 2011
Houston Chronicle
by Tom Fowler

Natural gas drilling has been the dominant energy story in the U.S. for the past few years, but oil is back with a vengeance.

For the first time in 18 years, the number of oil rigs working in the U.S. has exceeded the number of natural gas rigs, according to July rig data compiled by IHS-CERA, covering both land and offshore rigs.

By 2020 this surge in oil drilling could increase U.S. oil production by as much as 3 million barrels per day, Peter Stark, head of IHS-CERA's industry relations said Wednesday during a session launching the start of Summer NAPE, the semi-annual oil and gas prospects expo being held in Houston.

Two factors are spurring the surge in oil production.

The combination of horizontal drilling and hydraulic fracturing, which has unlocked previously inaccessible gas, also has opened up new possibilities for oil production.

Relatively low natural gas prices have prompted companies to focus exploration efforts on more valuable oil and natural gas liquids.

Oil actually may have returned to the top of the heap among U.S. drilling rigs earlier this year, according to another data set. Baker Hughes' rig count for onshore and offshore rigs has oil surpassing natural gas on April 21, (913 oil rigs vs. 878 gas rigs) for the first time since April 28, 1995 (343 oil rigs vs. 321 gas rigs).

And on June 24 the number of rigs drilling for oil surpassed the 1,000 mark for the first time since 1987.

IHS-CERA predicts oil production could directly and indirectly generate another 1.3 million U.S. jobs over the next decade and raise an additional $97 billion in federal taxes and royalty payments.

The oil boom is showing up in well-known U.S. oil fields, like Texas' Permian Basin, and in newer fields like North Dakota's Bakken shale and the Utica shale in Ohio.

The surge could slow if natural gas prices continue to rise and make gas projects more attractive -- which many analysts expect in the next year.

Benchmark crude rose 93 cents Wednesday to $87.58 per barrel in trading on the New York Mercantile Exchange. Natural gas rose a penny to $3.93 per million British thermal units.

But at least for now, producers have reasons beyond crude and gas prices for renewed interest in oil.

In some cases drilling for oil can cost less than for gas. Tom Ward, CEO of SandRidge Energy, said his company is spending as little as $760,000 per well in the Central Basin field in the Permian, compared to several million per well in most shale gas fields.

John Christmann, head of Apache Corp.'s Permian Basin operations, said his company has acquired acreage in the Empire ABO field in the Permian, a field where no new wells have been drilled since 1984.

"In some cases you have million-barrel wells that have never had an offset drilled near them," Christmann said, seeing strong potential for large quantities of oil.

Oil shales will be a big topic on the floor of NAPE this year, as attendees assess potential oil and gas drilling and production projects.

Started in 1993 as the North American Prospect Expo with 80 booths and about 800 attendees, NAPE is now held twice a year, and the winter 2011 gathering in Houston had 1,600 booths and drew 16,000 attendees.

This week's Summer NAPE is expected to draw about 5,600 attendees and 600 booths.

Scott Wilmoth, a vice president at Houston investment bank Simmons & Co., said NAPE gives big firms and small a chance to see a lot of different deals in one place.

"Deals get done across the board," Wilmoth said.

NAPE is also a networking opportunity, said Charles Cusack, Petrohawk's Vice President of Exploration.

"The main benefit has been the multitude of contacts made at NAPE that have indirectly led to deals," Cusack said. "The most significant NAPE transaction was my first meeting Dick Stoneburner (Petrohawk's chief operating officer) at NAPE in 2000 that led to my working with him for over a decade."

Wilmoth expects a lot of discussion at NAPE about tight oil plays, including the Utica, the Lower Smackover Brown Dense in Arkansas and Louisiana, the Tuscaloosa Marine Shale and horizontal Wolfcamp in the Permian basin, among others.

The shale gas plays will still get attention, however -- including the areas in the Eagle Ford that yield oil and natural gas liquids, and the Marcellus shale in the northeast U.S., Wilmoth said. Internationally, unconventional oil and gas opportunities in Argentina may be a big draw at NAPE as well.

While the business is famously cyclical, the recent oil boom surprised some in the industry.

During a recent meeting of the National Petroleum Council in The Woodlands, the group discussed an upcoming report on U.S. natural gas reserves. Not surprising, the group said, the study would report that North American natural gas resource potential was enormous.

"Secondly, and perhaps surprisingly to some of us and certainly to many Americans, our Canadian and American oil resource base is also very big news," said NPC member Susan Tierney.

Copyright (c) 2011, Houston Chronicle

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Eagle Energy Trust Hands Tx. Field Reins to Subsidiary

- Eagle Energy Trust Hands Tx. Field Reins to Subsidiary

Thursday, August 18, 2011
Eagle Energy Trust

Eagle Energy Trust reported that effective immediately, Eagle Energy Acquisitions, the US operating subsidiary of the Trust, has been appointed the operator of the Salt Flat Field.

"On behalf of Eagle, we express thanks to North South Oil LLC for its hard work and dedication as the operator of the Salt Flat Field. This transition has been anticipated by the parties since the Trust's initial public offering last November and North South has been a key contributor to setting the stage for the full cycle development of the Salt Flat Field. Eagle US is excited to continue with this project," said Richard Clark, President and CEO.

In preparing to assume operatorship, Eagle US has accomplished a number of key items over the past few months. The necessary permits to operate petroleum properties in the State of Texas have been obtained. Key engineering and field staff have been added, providing Eagle US with the ability to manage the full cycle development of the Salt Flat Field, as well as accelerate its evaluation of potential new acquisitions. Eagle US has also opened a field office in Luling, Texas.

"Eagle US is now well positioned to commence its role as the operator of the Salt Flat Field and to execute on its overall growth plans," said Mr. Clark. "We expect no material change in our current level of general and administrative expenses or operating costs due to assuming operatorship of the Salt Flat Field. This is an important step for Eagle and will ready us for future growth as we add new core area acquisitions."

The Trust also announced that it intends to issue its next operations update on or about September 30, 2011.

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Northern Offshore Reports 2Q Earnings

- Northern Offshore Reports 2Q Earnings

Thursday, August 18, 2011
Northern Offshore Ltd.

Northern Offshore reported net income for the three months ended June 30, 2011 of US $4.6 million, or US $0.03 per diluted share. This compares to a net loss of US $0.5 million, or US $0.0 per diluted share for the second quarter of 2010. Revenues for the second quarter of 2011 were US $49.9 million compared to US $48.9 million for the second quarter of 2010.

For the six months ended June 30, 2011, net income was US $7.0 million or US $0.05 per diluted share. For the same period in the prior year, net income was US $22.7 million or US $0.15 per diluted share. Revenues for the first six months of 2011 were US $90.4 million compared to US $116.9 million for the same period in 2010.

The company's directors have declared a dividend of US $0.03 per share, or approximately US $5.0 million. Shareholders of record with the VPS on August 31, 2011 will be entitled to receive the dividend, which will be paid on or around September 15, 2011. The shares of the company will be trading ex-dividend from August 29, 2011.

Second Quarter Analysis

Revenues for the three months ended June 30, 2011 were slightly higher when compared to the same period of 2010, primarily due to higher utilization of the jackup fleet, partially offset by lower utilization of the drillship Energy Searcher.

Drilling and production expenses for the three months ended June 30, 2011 were US $2.8 million lower than the same period last year primarily due to lower operating expenses for the drillship Energy Searcher and reduced idle costs for the jackup Energy Exerter. This decrease was partially offset by higher operating expenses related to the contract start-up of the jackups Energy Enhancer and Energy Endeavour. Depreciation expense for the three months ended June 30, 2011 was US $6.5 million lower than the same period in 2010 due to the decrease in depreciable basis of the jackup fleet attributable to the asset impairment charge taken in December 2010. General and administrative expenses were lower than the same period in 2010 due to lower compensation costs.

Interest expense was US $1.3 million lower than in the second quarter of 2010 primarily due to lower outstanding loan balance. Amortization of deferred financing fees was higher than the same period last year primarily due to the acceleration of the amortization of the deferred financing fees relating to the early repayment and cancellation of the US $120 million Revolving Credit Facility on May 31, 2011. Income tax expense was US $6.4 million higher than the same period last year primarily due to a higher annualized effective tax rate, partially offset by a reduction in the accrued withholding tax rate for operations in India.

At June 30, 2011, the Revolving Credit Facility balance was US $32.0 million and the cash balance was US $35.6 million, of which approximately US $28.2 million is unrestricted, leaving the company a net cash position at the end of the period of US $3.6 million.

Updates

The company is pleased to report that the semisubmersible Energy Driller was recently both technically and commercially qualified in a tender process requesting three one-thousand foot depth rated floating drilling rigs for a program offshore India. Although an award has yet to be made, the company is optimistic that the rig should receive a three-year contract due to the qualifying bid and anticipates receiving a letter of award in the next four to six weeks.

The floating production facility Northern Producer remains under contract with EnQuest. The unit continues producing in the North Sea with further field development and tie-back ongoing. The tariff from the facility for the second quarter 2011 averaged US $134 thousand per day on average per-day production of 22.4 thousand barrels.

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NOV Notes Quarterly Dividend

- NOV Notes Quarterly Dividend

Thursday, August 18, 2011
National Oilwell Varco Inc.

National Oilwell Varco has declared the regular quarterly cash dividend of $0.11 per share of common stock, payable on September 23, 2011 to each stockholder of record on September 9, 2011.

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ABB Lands Marine Orders in Asia

- ABB Lands Marine Orders in Asia

Thursday, August 18, 2011
ABB

ABB won several orders for a total of $200 million from Samsung Heavy Industries, Hyundai Heavy Industries, Keppel FELS and Jurong Shipyard Pte Ltd., to supply equipment 23 new Jackup and DP drilling vessels and one FPSO to be executed in South-Korea and Singapore. The orders were booked during the second quarter.

The vessels operate in oil and gas extraction, production and transportation, and include semi-submersible drilling rigs, drill ships, mobile oil and gas platforms as well as floating production, storage and offloading vessels.

"This group of important orders underscores ABB's excellent reputation for delivering comprehensive, reliable solutions that help our marine customers operate at the highest levels of efficiency, as well as our vast oil and gas industry expertise," said Veli-Matti Reinikkala, head of ABB's Process Automation division.

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SMS Appoints Group Business Development Manager

- SMS Appoints Group Business Development Manager

Thursday, August 18, 2011
Sand Monitoring Services Ltd.

SMS (Sand Monitoring Services Ltd.) announced the appointment of Frazer Barclay as Group Business Development Manager at its Aberdeen headquarters. This key appointment will be instrumental in continuing to grow the SMS brand by increasing its core business, global presence and services portfolio.

Frazer, an honors graduate in Geology and Applied Geology from the University of Glasgow, brings with him more than 12 years industry experience related to sub-surface geoscience consultancy and business development. Frazer started his career with Western Geophysical as a geophysicist followed by a move into quantative interpretation with the leading reservoir characterization company Odegaard. Odegaard was acquired by Schlumberger in 2006 and subsequent to this Frazer built a new local consulting group offering production engineering, reservoir engineering, geoscience and geomechanical engineering services. Frazer has worked in several key oil and gas locations including London, Aberdeen, Kuala Lumpur and Perth with his most recent role as Global Geomechanics Sales and Marketing Manager being located in the United Kingdom.

Andrew Kinsler, Field Services Manager for SMS, commented, "We are very pleased to welcome Frazer to SMS during a time of much expansion. His proven track record in sub-surface geoscience consultancy, business development and years of industry experience will prove vital to the SMS growth strategy for 2011/12."

Andrew concluded, "SMS has grown to offer best in class sand monitoring and management services to the oil and gas industry, and our staff are instrumental to this. By employing some of the best talent in Scotland, we are confident that we can continue to strive for improvement and we look forward to implementing Frazer’s specialist skills to do just that."

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Wireless Seismic Strengthens Seismic Team

- Wireless Seismic Strengthens Seismic Team

Thursday, August 18, 2011
Wireless Seismic

Wireless Seismic announced the hiring of Travis Bird and Scott Williams to the newly-created positions of Chief Financial Officer and Sales Director/Americas respectively and the relocation of its corporate headquarters to Sugar Land, Texas, located just outside of Houston - the Energy Capital of the World. Wireless Seismic is the developer of an innovative wireless seismic data acquisition system with real-time data return.

"We are delighted to add Travis and Scott to our team," said Roy Kligfield, Wireless Seismic's President and Chief Executive Officer. "They bring the perfect combination of financial acumen, business strategy and industry knowledge that will be an invaluable addition to our company as we ramp-up the commercial launch of RT 1000 - our revolutionary seismic data acquisition system."

Prior to joining Wireless Seismic, Travis Bird served as Director, Corporate Development, at Novatek, Inc., a company that develops technologies for the oil and gas, construction and mining industries. In this role, Bird drove business strategy through the successful realization of multiple mergers and acquisition transactions. Bird has held executive financial roles with several emerging growth organizations. Before Novatek, he served as CFO of NovaDrill, Inc., a technology company that develops drilling tools for the oil and gas exploration and procurement industry. Bird drove financial strategies for NovaDrill through to its successful acquisition. He also worked at the global business services firm Ernst & Young, LLC in Los Angeles where he led engagement teams in providing corporate audit services to public and private businesses across multiple industries. Bird is a licensed CPA.

Scott Williams served as Vice President Sales for Guralp, a United Kingdom-based equipment manufacturer, prior to joining Wireless Seismic. Williams previously held positions as Regional Manager, United States and Latin America Sales, for INOVA Geophysical as well as Global Business Development Manager and Technical Sales Manager, Land Imaging Division, for ION Geophysical. Williams began his career as a surveyor and seismic observer before working his way up through the ranks to a regional field service manager. Scott also gained experience in managing electronic manufacturing operations.

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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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ExxonMobil Seeks to Retain Julia Leases in GOM

- ExxonMobil Seeks to Retain Julia Leases in GOM

Thursday, August 18, 2011
Rigzone Staff
by Karen Boman

ExxonMobil has filed a lawsuit against the U.S. Department of the Interior (DOI) to retain three federal offshore leases that are part of the Julia unit in the deepwater Gulf of Mexico.

The company filed the suit in the U.S. District Court in Lake Charles, La., stating that DOI has retroactively applied new legal standards in canceling the leases, departed from established agency practices, and singled out ExxonMobil for unprecedented adverse treatment. ExxonMobil also said the cancellation would prevent it from producing a reservoir believed to hold billions of barrels of oil.

ExxonMobil is operator of the Julia unit on Walker Ridge Block 627, which is comprised of Walker Ridge Blocks 584, 627, 628, 540 and 583; the first three are the original leases issued to ExxonMobil’s predecessor, Mobil Exploration and Production in 1998. The two additional leases were acquired by ExxonMobil and partner Statoil at the request of the U.S. Minerals Management Services (MMS) when it applied to develop the Julia discovery. ExxonMobil holds a 50 percent title interest in each of the leases within the Julia unit. Statoil holds the remaining 50 percent interest. ExxonMobil and Statoil announced the Julia discovery in the deepwater Gulf in January 2008.

The company contends that it is allowed under the law to suspend production in their fields in recognition of the time and planning needed to tie back subsea wells to deepwater host facilities. ExxonMobil had originally filed for a suspension of production (SOP) order for the three original Julia leases in 2008, saying it needed time to determine its drilling and development program for the Julia discovery, one of several pre-Tertiary deepwater discoveries made over the past decade.

MMS told ExxonMobil it needed to include Walker Ridge Blocks 540 and 583 to promote an expedite exploration and development. The company withdrew its original SOP request with the intent of submitted a new SOP for the entire Julia unit with the additional leases. ExxonMobil and Statoil acquired the two additional leases at a cost of over $60 million days before the end of the primary term of the original Julia leases. In the meantime, it continued drilling and development plans, investing $300 million dollars on the Julia discovery and drilling two producible wells. However, MMS denied the SOP request in 2009, saying it failed to show commitment to development the discovery.

ExxonMobil said MMS did not clearly specify what ExxonMobil needed to do to receive approval of the requested SOP and supplemented its original SOP request with numerous emails and letters demonstrating its commitment to produce the Julia discovery. ExxonMobil said it also made clear that if a plan to tie-back Julia to the Jack-St. Malo host facility was deemed insufficient that it would develop the Julia discovery as a standalone alternative.

The company said that MMS had granted more than 2,200 requests for SOPs for individual leases in the Gulf from 1994 through 2008 and denied only 33 such requests, and had often granted a series of sequential SOPs for a single lease or unit, resulting in delays in production commencement for periods of longer than five years after the initial SOP was granted. ExxonMobil noted that cancellation of the leases would give DOIG the opportunity to collect millions of dollars in bonuses and royalties that it would be entitled to collect if the original Julia leases are not canceled.

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Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

- Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

Thursday, August 18, 2011
Halliburton Co.

Halliburton has successfully executed the first horizontal, multistage hydraulic fracture shale gas completion in Argentina's Neuquén Basin for Apache. Halliburton provided all major well construction and completion services for the project, resulting in the successful delivery of South America's first horizontal and deepest shale gas well.

As global development of unconventional resources materialize, Halliburton is in the process of pre-positioning Unconventional Reservoir Solutions Teams around the world. These teams draw upon the extensive knowledge and experience garnered from Halliburton's unrivalled position in North America's unconventional reservoir development. Halliburton, chosen by Apache because of its Buenos Aires-based Unconventional Reservoir Solutions Team's expertise and understanding of the specific complexities of the Los Molles shale formation, placed 10 hydraulic fracture stages in the horizontal section at a depth of over 4,400 meters.

"Halliburton's ability to apply its expertise globally will assist operators to efficiently develop frontier unconventional reservoirs," said Roberto Munoz, vice president, Latin America Region, Halliburton. "With the third largest estimated unconventional reserves after China and the United States, Argentina's shale gas potential will benefit greatly from the application of these technologies."

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Royal Dutch Shell Trying to Stop Oil Leak in North Sea

- Royal Dutch Shell Trying to Stop Oil Leak in North Sea

Aug 18, 2011

Royal Dutch Shell (NYSE:RDS.A) is trying to stop an oil spill leak in the North Sea.

In the first phase of the operation to shut down the leak, engineers have lowered five giant concrete "blankets" on to a stretch of pipeline to place it back on the seabed after it lifted 4 feet off the sea floor.

Work is ongoing to lay concrete blankets to secure the pipeline, Shell spokesman Steve Harris said.

"First, we have to make a risk assessment ... to make sure that we can find a safe way to shut it off. We expect the result of the risk assessment very quickly and then divers will go down 300 feet (90 meters) and turn off the remaining amount of oil that is leaking into the sea."

Nearly 1,300 barrels of oil has leaked from its Gannet Alpha platform since August 12.

Royal Dutch Shell (NYSE:RDS.A) has a potential upside of 32.6% based on a current price of $63.21 and an average consensus analyst price target of $83.83.

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Noble Energy Pays $3.4 Billion For 50% Stake in Consol's Marcellus Assets

- Noble Energy Pays $3.4 Billion For 50% Stake in Consol's Marcellus Assets

Aug 18, 2011

Noble Energy (NYSE:NBL) agreed to pay $3.4 billion to Consol Energy (NYSE:CNX) for a 50% interest in Consol's Marcellus Shale assets.

The two companies will create a joint venture to develop Consol's 663,350 acres in the region.

In early trading, Consol rose $1.80, or 4.24%, to $42.22. In spite of the deal between Consol and Noble, most companies with property in the Marcellus region are declining along with the broader market.

Noble Energy (NYSE:NBL) has a potential upside of 33.4% based on a current price of $83.39 and an average consensus analyst price target of $111.25.

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Senex to Divest Stakes in AU Cooper Basin

- Senex to Divest Stakes in AU Cooper Basin

Thursday, August 18, 2011
Senex Energy Ltd.

Senex announced the farm-out of southern Cooper Basin conventional oil exploration licenses to Ambassador Exploration Pty Limited (Ambassador).

Senex is farming out a 60% interest in PEL 516 Mudlalee Block, a 60 %interest in PEL 516 Rowley Block and a 50% interest in PEL 113 Zulu Block to Ambassador. Notwithstanding the farm-outs, Senex retains 100% of the rights to "unconventional hydrocarbon production" within the Zulu Block and to any petroleum recovered from the Mudlalee and Rowley Blocks from beneath the Poolowanna horizon. Senex will retain Operatorship of each of these licenses.

The Farm-out Agreements have been executed and are subject to specific Conditions Precedent which are in the process of being completed. Details of the farm-out terms follow:

South Australian Cooper Basin License PEL 113 Zulu Block

Ambassador to pay 100% of the drilling cost of one well within the license area and 100% of the cost of acquiring, processing and interpreting 100 square kilometers of 3D seismic over the license area subject to agreed cost limits. On completion of the program, Senex will retain a 50% interest and Ambassador will have earned a 50% interest in Zulu Block production other than unconventional hydrocarbon production from the shale and coal deposits in the Permian sequence. Senex retains the rights to 100% of any unconventional hydrocarbon production from the Permian sequence.

South Australian Cooper Basin License PEL 516 Mudlalee Block

Ambassador to pay 100% of the drilling cost of one well within the license area subject to an agreed cost limit. On completion of the program, Senex will retain a 40% interest and Ambassador will have earned a 60% interest in the Mudlalee Block other than production from deposits that extend beneath the Poolowanna horizon. Senex retains the rights to 100% of any petroleum recovered from deposits beneath the Poolowanna horizon, being the unconventional hydrocarbon zones.

South Australian Cooper Basin License PEL 516 Rowley Block

Ambassador to pay 100% of the drilling cost of one well within the license area subject to an agreed cost limit. On completion of the program, Senex will retain a 40% interest and Ambassador will have earned a 60% interest in the Rowley Block other than production from deposits that extend beneath the Poolowanna horizon. Senex retains the rights to 100% of any petroleum recovered from beneath the Poolowanna horizon, being the unconventional hydrocarbon zones.

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Buccaneer to Commence Drilling 2nd Well at Kenai Loop

- Buccaneer to Commence Drilling 2nd Well at Kenai Loop

Thursday, August 18, 2011
Buccaneer Energy Ltd.

Buccaneer advised that it is on track to commence drilling of its second well at its 100% owned Kenai Loop project within the next 7 days.

The Company has contracted with Marathon Oil Company for the Glacier Drilling Rig # 1 to be on site for the second well at Kenai Loop, this being the same rig that successfully drilled KL # 1. The rig will mobilize to the location on August 22, 2011 (US time) with the well expecting to spud during that same week.

This second well will be a development well directionally drilled from the same drilling pad as KL # 1. The bottom hole location is expected to be approximately 1,800 feet from that of the KL # 1 well.

In May 2011 Buccaneer drilled the KL # 1 and intersected 26 separate gas pay zones. 2 of these zones were tested being the 9700' and 10000' sands. Due to restrictions on rig availability the Company was unable to test the remaining 24 identified pay zones.

The second Kenai Loop well will have the following primary objectives:

a step out well to test and possibly extend the known aerial extent of the 9,700' and 10,000' sands;
flow test additional pay zones (especially those at ~10,600') which were previously untested due to the then rig availability constraints;
further define reservoir characteristics and reserve potential; and
complete the well as a second producer in the Kenai Loop field.

The current independent assessment of 2P reserves at Kenai Loop of 38.3 BCF (4.8 MMBOE1) was based solely on the two tested pay zones in the 9,700' and 10,000' sands. The assessed 2P reserves covered an average of 340 acres of drainage area around the KL # 1 well. If the above objectives are successful, the 2P reserves are expected to increase.

The well is expected to take 30 days to reach its target depth of 11,000'. An additional 14 days of testing is anticipated.

Director of Buccaneer Energy, Dean Gallegos said, "The Company is very keen to take full advantage of the recently executed gas sales contract with ENSTAR, which allows for deliveries of up to 15.0 MMCFD.

"The sand in KL # 1 around the 10,600 feet depth look good on the logs and the second well will penetrate these sands in a slightly higher structural position than in KL # 1. These sands and the shallower 9700' and 10,000 foot sands are the most immediate way for us to increase booked reserves and future production capacity.

"In the last 12 months the Company has leased, technically assessed, permitted, execute a gas sales contract and drilled 2 wells. While there will always be delays due to unforeseen circumstances, I think this demonstrates management's capacity to deliver complex projects successfully."

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Entek to Test Ops at Niobrara Shale Program

- Entek to Test Ops at Niobrara Shale Program

Thursday, August 18, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L – The Frontier (secondary objective) test program will be initiated within the next 10 days. The Niobrara (primary objective) completion program, which includes testing and fracture stimulation of the potential Niobrara pay zones, is scheduled to start in September 2011.

Slater Dome (SD) Federal 24-9DL – The well is currently drilling ahead at 3,200 ft after successfully setting casing at 2,520 ft. The planned total depth of the well is 8,627 ft.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald O&G holding 45%. Entek is the operator. The GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

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Schilling Robotics, Gregg Marine Complete Subsea Drilling Test Offshore BC

- Schilling Robotics, Gregg Marine Complete Subsea Drilling Test Offshore BC

Thursday, August 18, 2011
Schilling Robotics LLC

Schilling Robotics and Gregg Marine announced the successful completion of the field testing of their subsea drill in the waters offshore of Vancouver, British Columbia.

The Seafloor Drill was conceived by John Gregg, owner of Gregg Marine, and completed its Factory Acceptance Testing at Schilling Robotics in June 2011. The four week sea trials took place last month in St. Vincent's Bay outside of Vancouver, Canada, in water depths up to 250 meters. The sea trials allowed Gregg to work closely with Schilling technicians to fine tune the control systems and train the drill's operators. The drill testing has exceeded Gregg's expectations, as well as the clients that attended the demonstrations.

When speaking of the sea trials, John Gregg commented, "The seafloor drill system is a complex and expanded technology over the current systems in the market today. By leveraging the proven technologies by Schilling Robotics, the Seafloor Drill offers robust telemetry and controls that will maximize the efficiency and effectiveness of the system. To demonstrate our confidence, we invited our industry colleagues to the sea trials in order to see the demonstrations first hand." The drill was able to successfully retrieve core samples of both unconsolidated soft sediment as well as granitic rock. Many in attendance were impressed with the flexibility of the drill compared to other equipment on the market. One of the clients for a major US energy company remarked that "Not many companies are willing to open themselves to outsiders during such an important phase of their development program. It appears to me that the team has put a lot of thought into the design of these tools and I am certain it will pay off with many successful projects."

The system is currently being mobilized to drill near Australia where it will begin work in the coming months. "I am very thankful to Apache Oil for the Seafloor Drill's first job. Their commitment to innovation is shown in their excitement about the system," said Gregg. "We are pleased that the sea trials for the Seafloor Drill were successful," said Tyler Schilling, CEO of Schilling Robotics. "With this technology, and the Cone Penetration Testing unit, Gregg Marine is uniquely equipped for seabed sampling worldwide."

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Baker Hughes Names Integrated Operations President

- Baker Hughes Names Integrated Operations President

Thursday, August 18, 2011
Baker Hughes Inc.

Baker Hughes announced that Darrell C. Howard has joined the company as President of the Integrated Operations organization. Howard joins Baker Hughes from VICO Indonesia, where he served as Vice President, Technical Support for the BP-Eni joint venture.

"Darrell's combination of technical expertise, project management capabilities, international business experience, and leadership qualities make him the ideal candidate to lead our integrated operations business," said Derek Mathieson, president of product lines and technology for Baker Hughes. "In this role, Darrell will apply his in-depth knowledge of the entire oil and gas asset lifecycle to expand Baker Hughes' position in the fast-growing integrated project management market. This is a critical business for our company and I look forward to working closely with Darrell to enhance Baker Hughes' top-tier integrated project management capabilities."

Howard joined Amoco Corp. following his graduation from the University of Colorado in 1978. During his career with Amoco he held a variety of drilling, completion, and production engineering and management roles. Howard has extensive international experience, including assignments where he worked closely with governments, national oil companies and third-party organizations in the United Kingdom, Norway, the Republic of Congo and Egypt. Immediately prior to his appointment with VICO Indonesia, he spent seven years in various roles with BP in Baku, Azerbaijan and with TNK-BP in Moscow, including Exploration Drilling Manager for the Shah Deniz Caspian gas project.

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SBM Offshore CEO to Step Down after Cost Over-runs Hit Profits

- SBM Offshore CEO to Step Down after Cost Over-runs Hit Profits

Thursday, August 18, 2011
Dow Jones Newswires
AMSTERDAM
by Robin van Daalen & Patrick Buis

SBM Offshore Thursday reported semi-annual results that bested analyst expectations, but announced plans to replace its chief executive after a large cost-overrun pushed its results into the red.

SBM, which owns and operates offshore units for the oil and gas industry, reported a net loss of $265.3 million, a big drop from the $77.6 million net profit a year ago, but somewhat higher than analyst expectations. SBM pointed to record orders and cited heavy interest for additional work from Brazil, Angola and other petroleum centers.

But company results have been tarnished by a $450 million impairment charge related to two problem projects that has weighed on shares since it was announced in July. SBM announced that "in light of recent events," Chief Executive Tony Mace would step down and it would recommend Chief Operating Officer Bruno Chabas for the top spot.

"Stepping down is a matter of taking responsibility," Mace said at a meeting without giving further detail.

SBM shares opened higher Thursday following the disclosure, but later gave up their gains following a broader market retreat. At 11:52 GMT, SBM shares were down 3.2% to EUR13.50, while the Amsterdam index was down about 2.6%.

SBM Offshore booked a $450 million impairment charge after it was unable to reach a settlement for additional compensation for cost overruns on SBM Offshore's Yme and Deep Panuke platforms which have been installed on their respective offshore locations in Norway and Canada. Legal action in the case of the Deep Panuke platform has been initiated in April against EnCana and arbitration proceedings were initiated in January for the Yme platform against Talisman But SBM said the outcome is uncertain.

Neither EnCana nor Talisman were available for comment Thursday. Talisman Chief Executive John Manzoni has publicly complained that a "poorly executed fabrication contract" has hindered the project.

ING said SBM's underlying results were "reasonable" and praised the decision to replace Mace as "a valuable step" that could spur a "fresh look" at the firm. But ING said it wanted more details on the "huge" $450 charge.

Turnover for the first six months of 2011 rose 6% to $1.46 billion, driven by fleet operations, where SBM operates Floating Production Storage Offloading (FPSO) units for its clients on a leasing basis.

Earnings before interest and taxes, or Ebit, excluding the impairment charge was $236 million, compared to $146 million a year ago. The increase was mainly driven by the solid performance of the Turnkey Systems segment, the company said.

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

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Anadarko Executive: Drilling First Deep-Water Well Off Liberia

- Anadarko Executive: Drilling First Deep-Water Well Off Liberia

Thursday, August 18, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Anadarko plans an aggressive deep-water exploration campaign worldwide over the next year and a half, the head of the company's exploration unit said Wednesday.

"The inventory of opportunities we have is better than it's ever been," Bob Daniels, Anadarko's senior vice president of Worldwide Exploration, said during a speech webcast from an investor conference in Denver. "We will continue with a very aggressive exploration program around the world."

The Houston company's success in Ghana, where it last year brought the vast Jubilee discovery into production, has spread into neighboring West African nations, he said. In addition to offshore exploration in Sierra Leone and the Ivory Coast, Anadarko is drilling Liberia's first deep-water well at the company's Montserrado prospect.

Judging from seismic data and other geologic factors, the Montserrado prospect "is a look-alike" to the Jubilee discovery, Daniels said.

Jubilee is estimated to hold the equivalent of between 600 million and 1.5 billion barrels of oil.

In all, Anadarko plans 15 deep-water exploration and appraisal wells in West African waters, Daniels said.

In East Africa, where Anadarko has already made a huge natural gas discovery off Mozambique, the company holds some 14 million acres. Daniels said Anadarko will bring a second rig to Mozambique in the fourth quarter and anticipates drilling prospects off Kenya, where Anadarko has leased "most of the deep water," next year.

Deep-water exploration is also slated to begin off New Zealand next year, he said.

"In the deep-water Gulf of Mexico, we have an inventory of discoveries and we have a very, very deep portfolio of exploration wells to drill," Daniels said.

The second-largest acreage holder in the U.S. Gulf of Mexico, Anadarko plans five deep-water exploration wells there this year and between six and eight exploration and appraisal wells next year.

In the last three weeks Anadarko has obtained three drilling permits from U.S. regulators, he said.

"That's very good progress in that we now have some confidence that when we apply for a permit we know about how long its going to take," he said. "That allows us to then put rig contracts in place."

Permits have been difficult to come by since last year's deadly Deepwater Horizon disaster. Anadarko was a minority owner of BP's doomed well, which blew out and caused the worst offshore oil spill in U.S. history.

Anadarko said last month that it has agreed to jointly develop its Lucius field in the Gulf with ExxonMobil, which has its own big discoveries a few miles away. Lucius is believed to hold 300 million barrels of high-quality crude and Daniels said he expects the project to be sanctioned by the end of this year with first production planned for 2014.

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

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Winstar to Farmout Interest in Tunisia Concession

- Winstar to Farmout Interest in Tunisia Concession

Thursday, August 18, 2011
Winstar Resources Ltd.

Winstar has executed a Memorandum of Understanding (MOU) with a privately held European exploration and production company ("Privateco") to farmout for cash and a work program, up to 50% of Winstar's current 45% working interest in the Sabria Concession in west-central Tunisia, including existing production, inventory and reserves. All amounts are in US dollars unless otherwise stated.

Winstar and Privateco have agreed to expeditiously work towards drafting and executing a comprehensive Farmout Agreement plus ancillary agreements in accordance with the commercial terms and conditions contained within the executed MOU.

This transaction is attractive to Winstar as it:

Provides an opportunity to accelerate the development of the extensive probable reserves associated with the Sabria Concession;
Provides incremental working capital to fund the current and near term capital programs; and
Provides meaningful near term incremental drilling operations at Sabria during a period in which Winstar's capital is focused on developing the Triassic and Silurian potential within the southern Tunisian concessions of Chouech Essaida and Ech Chouech.

The basic terms and conditions of the executed MOU are as follows:

Privateco will earn an undivided 22.5% working interest within the Sabria Concession upon Closing in exchange for a cash payment of US $6.55 million, subject to final closing adjustments, and a work commitment to pay 45% of the capital costs to:
Work-over an existing Sabria well;
Drill and complete 3 new Sabria horizontal development wells to a depth to exploit the reserves within the Ordovician Sandstones of the Hamra and El Atchane Formations.
The work commitment is to be completed within 2.5 years from the date on which the Tunisian government issues a decree granting approval of the title transfer to Privateco.
The work commitment is subject to budgetary approval by ETAP (Tunisian State Oil and Gas Company) which owns the remaining 55% working interest in the Sabria Concession.

The Effective Date of the transaction is July 1, 2011 with a closing date expected during the fourth quarter of 2011. At closing, Winstar will receive $6.55MM USD of which 5.7MM USD represents the estimated value for the proved developed producing ("PDP") reserves at July 1, 2011 plus seismic and inventory. This is based on a value of $7.0 MM USD for the PDP reserves at January 1, 2011 and will be adjusted based on actual net after tax cash flows attributable to the 22.5% interest from January 1, 2011 to coincide with the December 31, 2010 RPS Energy report mentioned below.

Winstar will remain as the Operator.

This transaction is subject to execution of the formal transaction documents and final approval by the parties' respective boards and the government of Tunisia.

The work commitment is estimated to have a value to Winstar, after earned carried working interest (22.5%), of approximately US $12.3 million. Privateco also agrees to transfer the deductible tax pools associated with Winstar's carried interest of the work commitment, which is estimated to be an additional US $6.1 million of tax benefits for Winstar. Thus, the total value of the transaction is estimated to be US $25.5 million, subject to final closing adjustments, net to Winstar in cash, work and tax benefits.

Based on RPS Energy Independent reserve report as December 31, 2010, and using a value of $7.0MM USD at January 1, 2011 for PDP reserves, the 22.5% working interest in the reserves and value of Sabria, which will be earned by the Privateco is as follows:

Total PDP Reserves; 326,000 boe (before royalty),
Total PDP Reserves; $6.4 million (Present Value, discounted at 10%, after tax)

Winstar's 45% working interest in current production at Sabria is 190 boepd and would be 95 boepd net to Winstar's 22.5% working interest after giving effect to this transaction.

Based on reserve values estimated as of December 31, 2010, and using a value of $7.0MM USD at January 1, 2011, the Privateco is paying $21.77 per boe for PDP reserves.

Winstar is currently producing 1,500 to 1,700 boepd (1,050 to 1,150 bopd of crude plus 450 to 550 boepd of solution gas). Sales of the solution gas produced in association with the crude oil are still partially restricted due to mechanical issues within the Tunisian national gas transmission system owned and operated by STEG (Tunisian National Electric and Natural Gas Company). As a result of the mechanical restriction, Winstar is currently selling 1,500 to 1,650 boepd. The mechanical challenges are anticipated to be resolved within the near future.

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WesternGeco Kicks Off 3D Seismic Survey in Barents Sea

- WesternGeco Kicks Off 3D Seismic Survey in Barents Sea

Thursday, August 18, 2011
Schlumberger Ltd.

WesternGeco has begun acquisition of the Bjørnøya Phase I "Ice Bear" 3D multiclient survey in the highly prospective West Loppa area of the Barents Sea.

Following previous surveys in the area, the Ice Bear survey will extend the existing WesternGeco West Loppa datasets to the North and West.

"The study area is located on the rim of the Bjørnøya Basin, on the west flank of the Loppa High and includes a large downthrown terrace in the North together with other Jurassic faulted structures, all of which have potential," said Phil Davey, WesternGeco Europe & Africa GeoSolutions manager, "Other, separate, but still promising features are seen in the southwestern part of the survey area."

Building on previous 2D datasets, the Ice Bear survey will consist of approximately 2500 sq km of 3D seismic data, acquired using 10 X 7 km streamers. Advanced acquisition techniques coupled with demultiple processing using the WesternGeco 3D GSMP General Surface Multiple Prediction technology will provide high-quality 3D data.

Acquisition commenced on July 10, 2011, and the fast-track data will be available in November 2011 in time for nominations for the 22nd Norwegian Licensing Round. The final processed data will be available for licensing in March 2012 in advance of the applications for the 22nd Norwegian Offshore Licensing Round. Companies are invited to contact WesternGeco to discuss their interest in this program.

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ConocoPhillips China Resumes Some Production at Bohai Bay Oil Field

- ConocoPhillips China Resumes Some Production at Bohai Bay Oil Field

Thursday, August 18, 2011
Dow Jones Newswires
BEIJING
by Wayne Ma

ConocoPhillips China said Thursday that it has restarted production at 14 production and water-injection wells at its Penglai 19-3 oil field in Bohai Bay.

The company has received approval from China's State Oceanic Administration to resume production after the wells were shut on July 13 because of an oil spill, it said in a statement on its website.

"Flowing these wells reduces the overall pressure in the subsurface formation, which will assure that the seeps stop and the fault, which was previously activated, naturally seals," the company said.

ConocoPhillips expects to have the oil spill cleaned up by the end of August, it added.

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

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Bering Begins Oil Production at Chicas Locas Well

- Bering Begins Oil Production at Chicas Locas Well

Thursday, August 18, 2011
Bering Exploration Inc.

Bering announced that the Chicas Locas #1 well located in the Roxanne field has begun producing oil from the lower Yegua formation.

The Company is evaluating the well to determine whether artificial lift will enhance the initial production. The Roxanne field consists of approximately 600 acres located in Victoria County, Texas and has multiple drilling locations that will target the Yegua and Frio formations at various depths. This field is estimated to have over $8 million in potential gross reserves based upon the current price of oil and gas and assuming all wells are drilled and successful. Bering will retain a 50% working interest in this prospect.

"We are pleased to have established our first producing oil well and expect to continue to develop this prospect." stated Steven Plumb, VP of Finance of Bering, "We continue to seek out prospects that we can develop and increase shareholder value."

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BHP Billiton-Petrohawk Deal Gets Final Nod

- BHP Billiton-Petrohawk Deal Gets Final Nod

Thursday, August 18, 2011
BHP Billiton plc

BHP Billiton and Petrohawk announced that on August 17, 2011, BHP Billiton and Petrohawk received notice from the Committee on Foreign Investment in the U.S. (CFIUS) that CFIUS has concluded that there are no national security issues of concern in relation to the transactions contemplated by the merger agreement between BHP Billiton and Petrohawk, including BHP Billiton's tender offer for all of the issued and outstanding shares of common stock of Petrohawk for US $38.75 per share in cash. As previously announced, on July 22, 2011, BHP Billiton and Petrohawk received notice from the U.S. Federal Trade Commission of early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act in relation to the tender offer. Accordingly, all regulatory approvals conditions to the tender offer have been satisfied.

The documents related to the tender offer have been filed with the U.S. Securities and Exchange Commission (the SEC). As previously announced, the tender offer has been unanimously recommended by the Petrohawk board of directors and is being made pursuant to the merger agreement between BHP Billiton and Petrohawk. The tender offer is scheduled to expire at midnight, New York City time, at the end of Friday, August 19, 2011, unless the tender offer is extended or earlier terminated in accordance with the rules and regulations of the SEC and the merger agreement.

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Noble, CONSOL Team Up in $3.4B Marcellus JV

- Noble, CONSOL Team Up in $3.4B Marcellus JV

Thursday, August 18, 2011
Noble Energy Inc.

Noble Energy has signed definitive agreements which create a joint venture partnership with CONSOL for the development of their Marcellus Shale properties in southwest Pennsylvania and northwest West Virginia.

Under the arrangement, Noble Energy will purchase a 50 percent interest in 663,350 net undeveloped acres for $1.07 billion, payable in three equal annual installments beginning at closing. In addition, the Company will fund $2.13 billion of CONSOL's future drilling and completion costs. This funding obligation is expected to extend over an eight-year period and is limited to one third of CONSOL's drilling and completion costs with an annual cap of $400 million and a suspension of disproportionate funding at natural gas prices below $4 per million British thermal unit (MMBtu). The acreage value of $3.2 billion equates to a discounted present value of $7,100 per net acre. Noble Energy will also acquire a 50 percent interest in 70 million cubic feet equivalent per day (MMcfe/d) of existing Marcellus production and infrastructure for $219 million. The payments are anticipated to be funded from cash on hand and the Company's currently undrawn revolving credit facility. The effective date of the transaction is July 1, 2011. Closing is expected to occur by the end of September 2011, subject to customary adjustments and conditions.

Key operational aspects of the joint venture include:

Acreage estimated to contain 7.4 trillion cubic feet equivalent (Tcfe) risked resources net to Noble Energy's interest, of which 400 billion cubic feet equivalent (Bcfe) were proven reserves at year-end 2010
More than a decade of development activity anticipated, which includes the drilling of approximately 4,400 gross well locations
Net production to Noble Energy's interest has the potential to reach 600 MMcfe/d in 2015 and is expected to continue growing into the next decade
Leasehold position is over 85 percent held by production, almost entirely operated with close to 100 percent working and 88 percent net revenue interests
A pre-defined long-term development plan forecasts drilling activity to increase from 4 rigs to 16 rigs in 2015
Operations to be shared between the partners with Noble Energy's initial focus on the wet gas portion of the acreage
Sharing of midstream infrastructure and access to water handling capabilities

Charles D. Davidson, Noble Energy's Chairman and CEO, commented, "Noble Energy is excited about the opportunity to establish a position in the Marcellus Shale, which is considered to be one of the most economically attractive developments in North America due to its enormous resource potential, its proximity and access to premium markets, and its competitive cost structure. This transaction will complement and further strengthen our U.S. portfolio by adding a high-quality asset with a substantial growth profile. The Marcellus, combined with our ongoing developments in the DJ basin and deepwater Gulf of Mexico, will provide important balance to our rapidly expanding international programs. Spreading the transaction costs over an extended time horizon creates better partner alignment on investment decisions and maintains our strong balance sheet."

David L. Stover, President and COO, added, "Noble Energy is fortunate to be partnering with CONSOL, a well-known and respected Appalachian operator. The joint oversight and operations are designed to create value through the sharing of best practices and expertise. Both companies are committed to operating in a safe, environmentally responsible manner while maintaining a good working relationship with the local communities."

J. Brett Harvey, CONSOL's Chairman and CEO, commented, "We are extremely pleased to have Noble Energy as our partner in the Marcellus. Noble Energy is a world-class operator that shares CONSOL's dedication to safety and compliance and they bring a strong technical and operational expertise to this partnership. This agreement will benefit the regional economy, the communities in which we operate, our employees, and our respective companies. Together we will be able to accelerate the development of this significant resource safely, efficiently and economically."

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