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Year-End 2009 U.S. Proved Crude Oil, Condensate and Natural Gas Liquid Reserves

Code: 
( millions of barrels )
                          Total 
U.S. Total Offshore       4,926 
U.S. Federal Offshore     4,659 
U.S. State Offshore         267 
U.S. Onshore             25,946 
U.S. Total Reserves      30,872 
Total Gulf Offshore       4,411 
Federal Gulf of Mexico    4,308 
Gulf States Offshore        103 
  
Total Offshore Percent of Total Reserves  16% 
Total Gulf Offshore Percent of Total Reserves  14%

http://www.eia.doe.gov/special/gulf_of_mexico/index.cfm
 
http://edition.cnn.com/2011/BUSINESS/04/03/gulf.spill.bonuses/

(CNN) -- Declaring 2010 "the best year in safety performance in our company's history," Transocean Ltd., owner of the Gulf of Mexico oil rig that exploded, killing 11 workers, has awarded its top executives hefty bonuses and raises, according to a recent filing with the U.S. Securities and Exchange Commission.
That includes a $200,000 salary increase for Transocean president and chief executive officer Steven L. Newman, whose base salary will increase from $900,000 to $1.1 million, according to the SEC report. Newman's bonus was $374,062, the report states.
Newman also has a $5.4 million long-term compensation package the company awarded him upon his appointment as CEO in March 2010, according to the SEC filing.
The latest cash awards are based in part on the company's "performance under safety," the Transocean filing states.
"Notwithstanding the tragic loss of life in the Gulf of Mexico, we achieved an exemplary statistical safety record as measured by our total recordable incident rate and total potential severity rate," the SEC statement reads. "As measured by these standards, we recorded the best year in safety performance in our Company's history."
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History of Offshore Oil and Gas in the United States


1896
First offshore oil production in the United States—from wooden piers off Summerland, California

1938
First Gulf of Mexico discovery well in state waters; first free-standing production platform in the ocean—Creole field offshore Louisiana

1947
First well drilled from fixed platform offshore out-of-sight-of-land in Federal waters —Kermac 16 offshore Louisiana

1953
Submerged Lands Act & Outer Continental Shelf Lands Act

1954
First federal Outer Continental Shelf lease sale & Maiden voyage of the Mr. Charlie submersible drilling vessel, industry’s first “day rate” contract

1962
First semi-submersible drilling vessel, Blue Water 1, and first subsea well completion

1969
Santa Barbara blowout/oil spill (California)

1978
Shell Oil Company’s Cognac production platform (first in 1,000 feet of water) & OCS Lands Act Amendments

1981
First Congressional Outer Continental Shelf leasing moratorium

1982
Creation of the Minerals Management Service (MMS)

1988
Piper Alpha disaster in the North Sea

1994
First production from Shell’s Auger tension-leg platform in 2,860 feet of water

1995
Deepwater Royalty Relief Act

1996
First spar production facility in the Gulf of Mexico at the Neptune field

1999
Discovery of BP’s Thunder Horse field in 6,000 feet of water; at 1 billion barrels of oil equivalent, the largest discovery in the Gulf of Mexico

2006
Successful test at the Jack 2 field, in 7,000 feet of water and more than 20,000 feet below the seafloor, establishing the viability of the deepwater Lower Tertiary play

2010
Arrival of Deepwater Horizon at Macondo well in January


Sources:
http://www.oilspillcommission.gov/sites/default/files/documents/FinalReportChapter2.pdf
http://www.oilspillcommission.gov/
 
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http://noir.bloomberg.com/apps/news?pid=20601109&sid=anfG5lKurAjs&pos=15


Russian Gas Beckons for Germany as Merkel Turns From Nuclear
By Tony Czuczka

April 8 (Bloomberg) -- Chancellor Angela Merkel’s shift away from nuclear power is set to make Germany more reliant on Russian gas and Merkel more dependent on her predecessor, Gerhard Schroeder.

Merkel’s pledge to speed the exit from atomic power after the crisis in Japan is helping push natural-gas prices higher as Germany scrambles to identify energy alternatives. Gas supplied by OAO Gazprom may be the easiest way for her to meet Germany’s climate goals and keep Europe’s largest economy running.

As workers battle a meltdown at the Fukushima Dai-Ichi plant, Merkel is leading a global push to revisit nuclear energy, which provides about a quarter of the power generated in Germany. Increasing imports of gas from Russia, which holds the world’s biggest reserves, would deepen ties to the east yet risk raising tension with the U.S.

Russia is “re-emerging as this stable energy supplier for Europe,” Will Pearson, a London-based energy analyst at Eurasia Group, said in an interview. “There’s so much energy capacity there and right now it looks like a safer alternative” to options such as North Africa.

Likely winners include the Nord Stream AG Baltic Sea gas pipeline chaired by Schroeder, a 7.4 billion-euro ($10.6 billion) project that underscores Europe’s dependence on Russia as an energy supplier and the growing global clout of emerging economies that also include China, India and Brazil. The so- called BRIC nations are due to discuss commodities when they meet on April 14 in Sanya, China.

Pipeline Rivals
Also set for a boost is the Nabucco project, a pipeline that’s still on the drawing board, to channel Caspian gas to Europe. It’s championed by former Foreign Minister Joschka Fischer, a one-time leader of Germany’s anti-nuclear Greens party and Schroeder’s partner in government from 1998 until Merkel defeated their coalition in 2005.

Merkel is scheduled to meet with Germany’s 16 state prime ministers on April 15 to discuss the future energy mix after last month calling a 90-day moratorium on a planned extension of the lifespan of Germany’s 17 atomic plants and ordering the seven oldest reactors idled pending industry wide safety checks.

Pressured by a regional election loss amid a surge in support for the Greens, Merkel, a trained physicist and former advocate of atomic power, said on March 28 that her “view on nuclear energy has changed.”

‘Nuclear Witch-Hunt’
The result is “a nuclear witch-hunt” that may result in more than seven reactor closures, said Lueder Schumacher, an analyst at UniCredit SpA in London. “So far the public debate in Germany has focused on the desire to exit nuclear energy with little thought being spared as to what is actually going to replace it.”

German power for next year has risen about 10 percent since Merkel’s announcement, reaching its highest price in more than 19 months on April 4, according to broker data compiled by Bloomberg. Gas for delivery in 2013 cost 7 percent more at the Dutch-based Endex TTF gas exchange yesterday.

Europe’s most populous nation, Germany imports 85 percent of its natural gas and is already more reliant on Russia to meet its needs than the European Union as a whole. Germany imports about a third of its gas from Russia, compared with about a quarter for the EU.

Germany wants Russia to be “a major supplier of natural resources,” Merkel said on Nov. 26 during a visit by Prime Minister Vladimir Putin. “Europe and Russia are strategic partners whose potential for cooperation is far from exhausted.”

Merkel, who speaks fluent Russian, is already elevating Russia as a commercial and diplomatic partner, promoting exports there by German companies such as train maker Siemens AG.

‘Full Steam Ahead’
“The German attitude seems to be full steam ahead” with Russia, Charles Kupchan, a senior fellow at the Council on Foreign Relations, said by phone from Washington. Merkel is “very pragmatic, very realist, and that’s where western Europe is headed right now in terms of relations with Russia.”

For their part, the Russians are keen to oblige. Gazprom said that “German partners can increase gas purchases” under the terms of current contracts, according to an e-mailed response to questions on March 31.

“I am glad that pragmatic voices in the European Union point to the high significance of gas as an energy source,” Energy Minister Sergei Shmatko told reporters in Moscow two days ago. “The latest events which we have been witnessing lately show that stable and safe supplies of gas from Russia on the long-term basis is key to Europe’s energy security.”

‘Frequent Power Outages’
German utilities have so far borne the brunt of Merkel’s nuclear reversal, caught between powering the world’s No. 2 exporter and EU emissions-reduction goals.

RWE AG filed a lawsuit on April 1 challenging the shutdown of its Biblis A nuclear plant by the state of Hesse as part of the government-imposed moratorium. Chief Executive Officer Juergen Grossmann warned two days later of “more frequent power outages, say two, three days a year.”

“I fear that some of the industrial foundation of our country will be lost,” Grossmann said in a Deutschlandfunk radio interview.

E.ON AG and RWE, the two biggest utilities, are among the worst performers this year on the 30-member benchmark DAX index, declining 2.7 percent and 5.9 percent as of yesterday.

The Bloomberg Global Leaders Solar Index of solar company shares is up about 11 percent since March 11, when the earthquake and tsunami in Japan knocked out cooling systems at the Fukushima plant. Munich-based Wacker Chemie AG, which makes polysilicon used in solar cells, has gained more than 23 percent in that time.

CO2 Emissions
While Merkel has said she wants to speed the transition to energy from the wind and sun, traditional power sources are still needed to counteract the variable nature of renewables, said Matthias Heck, a Macquarie Research analyst.

“Longer term there’ll likely be a move to natural gas because it has lower CO2 emissions than coal and the government will want to keep carbon emissions down,” Heck said by phone from Frankfurt.

Rising prices for the permits that companies buy for the right to emit carbon rose may spur the shift. EU carbon permits rose to their highest price in almost three weeks on the ICE Futures Europe exchange in London on April 4.

Growing gas demand also plays into the hands of Schroeder and Fischer, who crafted Germany’s original pullout from nuclear power by about 2022 when in coalition government in 2002.

Schroeder, who was hired to head Nord Stream by Russia’s gas monopoly Gazprom months after leaving office in 2005, lost little time in claiming that Merkel’s new-found skepticism about nuclear power vindicated him.

‘Social Progress’
“It’s welcome social progress when others are capable of recognizing that we need to exit nuclear energy as quickly as possible,” he told the Die Zeit weekly in an interview published March 23.

The Nord Stream undersea pipeline to Germany is due to start delivering Russian gas to European consumers in October. Chances that Nabucco will also be built are increasing as Germany edges away from nuclear power, said Claudia Kemfert, an energy analyst at the Berlin-based DIW economic institute.

“This pipeline will be swept up in the boom,” she said. “It will be built to meet increased demand for gas.”

Not all Germans are convinced that Nabucco, which would avoid Russian territory, is enough to stem Germany’s reliance.

“We have to make sure there’s a diversity of sources,” said Michael Kauch, parliamentary environment spokesman for Merkel’s Free Democratic Party coalition partner. “We can’t get too dependent on Russia.”

For Merkel, practical considerations may outweigh any concerns at becoming over-reliant on Russia, Alexander Rahr, a Russia expert at the German Council on Foreign Relations in Berlin, said by phone.

Merkel “understands very well what she can expect of Russia; where Russia can be of help, where Russia cannot be of help,” Rahr said. “Nobody expected what happened in Japan, but in the end it will benefit those who have built those extra pipelines from Russia.”
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http://www.eia.doe.gov/analysis/studies/worldshalegas/


World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States

...The development of shale gas plays has become a “game changer” for the U.S. natural gas market. The proliferation of activity into new shale plays has increased shale gas production in the United States from 0.39 trillion cubic feet in 2000 to 4.87 trillion cubic feet in 2010, or 23 percent of U.S. dry gas production. Shale gas reserves have increased to about 60.6 trillion cubic feet by year-end 2009, when they comprised about 21 percent of overall U.S. natural gas reserves, now at the highest level since 1971.3
The growing importance of U.S. shale gas resources is also reflected in EIA's Annual Energy Outlook 2011 (AEO2011) energy projections, with technically recoverable U.S. shale gas resources now estimated at 862 trillion cubic feet. Given a total natural gas resource base of 2,543 trillion cubic feet in the AEO2011 Reference case, shale gas resources constitute 34 percent of the domestic natural gas resource base represented in the AEO2011 projections and 50 percent of lower 48 onshore resources. As a result, shale gas is the largest contributor to the projected growth in production, and by 2035 shale gas production accounts for 46 percent of U.S. natural gas production.

The successful investment of capital and diffusion of shale gas technologies has continued into Canadian shales as well. In response, several other countries have expressed interest in developing their own nascent shale gas resource base, which has lead to questions regarding the broader implications of shale gas for international natural gas markets. The U.S. Energy Information Administration (EIA) has received and responded to numerous requests over the past three years for information and analysis regarding domestic and international shale gas. EIA's previous work on the topic has begun to identify the importance of shale gas on the outlook for natural gas.4 It appears evident from the significant investments in preliminary leasing activity in many parts of the world that there is significant international potential for shale gas that could play an increasingly important role in global natural gas markets...


...the report assessed 48 shale gas basins in 32 countries, containing almost 70 shale gas formations. These assessments cover the most prospective shale gas resources in a select group of countries that demonstrate some level of relatively near-term promise and for basins that have a sufficient amount of geologic data for resource analysis. Figure 1 shows the location of these basins and the regions analyzed. The map legend indicates four different colors on the world map that correspond to the geographic scope of this initial assessment:

•Red colored areas represent the location of assessed shale gas basins for which estimates of the ‘risked’ gas-in-place and technically recoverable resources were provided.
•Yellow colored area represents the location of shale gas basins that were reviewed, but for which estimates were not provided, mainly due to the lack of data necessary to conduct the assessment.
•White colored countries are those for which at least one shale gas basin was considered for this report.
•Gray colored countries are those for which no shale gas basins were considered for this report.


Although the shale gas resource estimates will likely change over time as additional information becomes available, the report shows that the international shale gas resource base is vast. The initial estimate of technically recoverable shale gas resources in the 32 countries examined is 5,760 trillion cubic feet, as shown in Table 1. Adding the U.S. estimate of the shale gas technically recoverable resources of 862 trillion cubic feet results in a total shale resource base estimate of 6,622 trillion cubic feet for the United States and the other 32 countries assessed. To put this shale gas resource estimate in some perspective, world proven reserves of natural gas as of January 1, 2010 are about 6,609 trillion cubic feet, and world technically recoverable gas resources are roughly 16,000 trillion cubic feet, largely excluding shale gas. Thus, adding the identified shale gas resources to other gas resources increases total world technically recoverable gas resources by over 40 percent to 22,600 trillion cubic feet...
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http://en.rian.ru/business/20110415/163541017.html


Mid-sized Russian oil company Bashneft, the winner of a tender to develop the giant Trebs and Titov oilfields in the Russian Arctic and the country's largest private oil firm LUKoil will sign an agreement of intent on Friday to jointly develop the fields, a LUKoil spokesman said.

The Trebs and Titov deposits are among the most promising in the Timan-Pechora province with C1 reserves estimated at 78.9 million tons (578 million barrels) and 63.4 million tons (465 million barrels) of oil respectively. Russia's subsoil use agency granted Bashneft the license for the deposits in February following a December auction.

Bashneft could sell a 25% share in the project to LUKoil as it had infrastructure in the region, a source close to the negotiations has said.

LUKoil had invested about $1 billion in the development of Timan-Pechora. Total investment in the Trebs and Titov oilfields is estimated at $7 billion.

MOSCOW, April 15 (RIA Novosti)
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http://noir.bloomberg.com/apps/news?pid=20601110&sid=aT.LHuCPHk2w


Falklands Oil Search With Petrobras, Cnooc May Boost YPF 8%
By Rodrigo Orihuela

April 15 (Bloomberg) -- YPF SA, Argentina’s largest oil company, may climb about 8 percent if it discovers crude in offshore drilling slated to begin later this year near the disputed Falkland Islands, an analyst said.

YPF, controlled by Spain’s Repsol YPF SA, may gain “$3.50 per share in a success scenario,” said Anish Kapadia, an analyst with Houston-based Tudor Pickering Holt & Co. LLC, who rates YPF a “buy.” “We assign a 10 percent success rate” the company will find oil in the Falklands, Kapadia said in an interview. The stock closed at $44.93 in New York yesterday.

Argentina and the U.K., which went to war over the islands in 1982, had a diplomatic dispute last year after four British companies announced plans to drill in U.K.-controlled waters. Argentina claims sovereignty over the islands, which have been occupied by Britain since the beginning of the 19th century.

A U.S. Geological Survey has said there’s a 50 percent chance the Falklands contain 4 billion barrels of crude.

YPF rose 22 cents, or 0.5 percent, to $45.15 at 11:01 a.m. in New York Stock Exchange composite trading.

Buenos Aires-based YPF heads a joint venture with Petrobras Energia SA, the Argentine unit of Brazil’s largest oil company, and Pan American Energy LLC, which is 50 percent owned by China’s Cnooc Ltd., China’s largest offshore energy producer. The companies haven’t specified a date to start drilling for oil in Argentine-controlled waters.

Commercial Discovery
The three companies will use a ship called Stena Drillmax, owned by Aberdeen, U.K.-based Stena Drilling Ltd. The drillship has a water depth capacity of 10,000 feet (3,048 meters), according to Stena’s website.

The ship is now drilling for Madrid-based Repsol in the Campos basin, offshore Brazil, according to the Brazilian oil regulatory agency’s website.

Rockhopper Exploration Plc, based in Salisbury, England, has been the only company so far to make a potential commercial discovery in U.K.-controlled waters. The company said April 4 that the Sea Lion prospect may contain at least 516 million barrels of oil.

Desire Petroleum Plc and Falkland Oil & Gas Ltd., both of the U.K., are also exploring for crude in the Falklands.

A group including The Hague’s Royal Dutch Shell Plc drilled six wells in 1998 without making a commercial discovery in British waters.
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http://noir.bloomberg.com/apps/news?pid=20601207&sid=aBzGCn9n_KxY


Total to Boost Russia Output 30-Fold by 2020 as Arctic Opens
By Anna Shiryaevskaya

April 22 (Bloomberg) -- Total SA is seeking to boost output in Russia more than 30-fold within a decade, as the French producer develops Arctic projects.

Total plans to produce between 300,000 to 400,000 barrels of oil equivalent a day by 2020, Pierre Nerguararian, head of Total E&P Russie, said in a presentation in Moscow today. In June, the producer marks its 20th anniversary in Russia.

Europe’s third-biggest oil producer is working on five exploration and production projects with Russian partners and holds about 12 percent in OAO Novatek, as international energy companies look to Russia to boost reserves. Total agreed to buy the stake for about $4 billion at a ceremony last month attended by Prime Minister Vladimir Putin.

The French company’s output in Russia, the world’s biggest energy producer, is now limited to its 40 percent share of the Kharyaga project which is being developed under a production sharing agreement. The field, located in harsh conditions above the Arctic Circle, produces about 30,000 barrels a day of crude with a high paraffin and sulfur content.

Total and its Kharyaga partners, Norway’s Statoil ASA, Russia’s OAO Zarubezhneft and the local Nenets Oil Co., plan to keep output at that plateau level “for as long as possible,” Nerguararian said.

Yamal LNG
The Russian government approved a budget of $591 million for Kharyaga this year, up from $416 million in 2010, according to Total’s presentation. The state has received over $1 billion in revenue from the project, he said. Production will be at about the same level this year as in 2010, he said.

Total also aims to produce natural gas at the OAO Gazprom- led Shtokman project in the Barents Sea and at Novatek’s Yamal LNG project, both in the Arctic, the executive said. The French company holds 25 percent of the Shtokman operating company, and agreed last month to buy a 20 percent stake of Yamal LNG.

Shtokman remains a priority for Total, Nerguararian said. Yamal LNG may start producing liquefied natural gas in 2016, a year earlier than Shtokman, according to the Russian government. The partners moved an investment decision on pipeline gas from March until December, when they will also decide on an LNG facility. The next Shtokman board meeting is scheduled for June, according to Total’s presentations.

Novatek and Total are also working together at the Termokarstovoye field, which may hold more than 47 billion cubic meters of gas and 10 million metric tons of condensate. An appraisal well drilled at the field last year confirmed the reserves, Nerguararian said. The partners aim to make a final investment decision at the end of the year, he said.

Total is also a partner in the Khvalynskoye field, operated by OAO Lukoil, on the Russia-Kazakh border in the Caspian Sea. The project, which the partners aim to develop under a production sharing agreement, may progress by the end of the year, Nerguararian said.

Russian President Dmitry Medvedev in September ordered Natural Resources Minister Yuri Trutnev to speed up work on a production sharing agreement for the Khvalynskoye field.
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http://noir.bloomberg.com/apps/news?pid=20601087&sid=agvge7ra8F8c&pos=5


BP’s Quest for Transocean Spill Payment May Be Helped by Report
By Edward Klump and Asjylyn Loder

April 23 (Bloomberg) -- A U.S. Coast Guard report that cited safety failures by drilling-rig owner Transocean Ltd. may help bolster BP Plc’s effort to recover some of the costs of last year’s oil spill in the Gulf of Mexico, an analyst said.

http://homeport.uscg.mil/cgi-bin/st...f?id=54d497aa64c00bc9467247350fc3f07239677129
http://marineinvestigations.us/

Transocean’s poor maintenance of electrical equipment, bypassing of gas alarms and automatic shutdown systems and a lack of training played a role in the April 20, 2010, catastrophe, the Coast Guard said in a 288-page report released yesterday. The disaster killed 11 rig workers, injured 16 and left crude pouring into the Gulf for 87 days.

BP, which leased the Deepwater Horizon rig from Vernier, Switzerland-based Transocean, sued the company on April 20 for billions of dollars in damages, saying that without its “misconduct,” there wouldn’t have been any explosion, fire, deaths or oil spill. Transocean lacked effective safety management and culture, which “contributed” to the disaster at the rig, according to the Coast Guard report.

“BP will probably look at it as helping support their argument that Transocean is partially to blame,” said Brian Youngberg, an analyst at Edward Jones in St. Louis. BP may be “more persistent” in trying to get Transocean to help pay for the disaster, he said.

BP, based in London, said in its complaint in federal court in New Orleans that it has incurred costs of $17.7 billion and that it took a pretax charge last year of $40.9 billion in relation to the spill.

Scott Dean, a spokesman for BP in the U.S., didn’t immediately respond to an after-hours e-mail and voicemail seeking comment on the Coast Guard report. An e-mail to BP’s U.S. media affairs also wasn’t returned.

‘Strongly Disagree’
“We strongly disagree with, and documentary evidence in the Coast Guard’s possession refutes, key findings in this report,” Lou Colasuonno, a Transocean spokesman in New York, said in an e-mail yesterday.

“The Coast Guard inspected the Deepwater Horizon just seven months before the Macondo incident and certified the rig as being fully compliant with all applicable U.S. and international marine safety compliance standards, including those associated with fire and gas detection systems,” Colasuonno said. “The company looks forward to setting the record straight.”

While BP likely will pay for the vast majority of the costs related to Macondo, Transocean may end up paying some of the costs if BP continues to push, said Youngberg, who has a “hold” rating on Transocean’s shares and BP’s American depositary receipts and doesn’t own either.

Joint Investigation
The explosion and subsequent sinking of the rig has led to hundreds of lawsuits against BP and its partners and contractors.

The report is volume 1 of a Coast Guard and Interior Department joint investigation. The Coast Guard has jurisdiction over what happened on the Deepwater Horizon rig, according to a statement yesterday. The report covers the explosions, the resulting fire, evacuations, the flooding and sinking of the rig, and safety systems.

The report didn’t analyze what led to a loss of well control or aspects that are overseen by the U.S. Bureau of Ocean Energy Management, Regulation and Enforcement. The final report by the joint investigation team is expected by July 27, according to the Coast Guard.
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http://online.wsj.com/article/SB10001424052748704013604576248881417246502.html?mod=ITP_opinion_0

The Wall Street Journal
APRIL 16, 2011.
Oil Without Apologies

John Watson, Chevron's CEO, says Americans must stop taking affordable energy for granted. That means more 'oil, gas and coal.'

By KIMBERLEY A. STRASSEL
San Ramon, Calif.

It's the day after President Obama delivered his most recent vision of America's energy future, and I'm sitting in the sunny corporate offices of Chevron, the country's second-largest oil company. Let's just say John Watson has a different view.

The Chevron CEO is a rare breed these days: an unapologetic oil man. For decades—going back to Jimmy Carter—politicians have been peddling an America free of fossil fuels. Mr. Obama has taken that to an unprecedented level, closing off more acreage to drilling, pouring money into green energy, pushing new oil company taxes, instituting anticarbon regulations. America is going backward on affordable energy, even as oil hits $110 a barrel.

Enter the tall, bespectacled Mr. Watson, who a little more than a year ago stepped into the shoes of longtime CEO David O'Reilly. An economist by training, soft-spoken by nature, the 53-year-old Mr. Watson is hardly some swaggering wildcatter. Yet in a year of speeches, he has emerged as one of the industry's foremost energy realists. No "Beyond Petroleum" (BP) for him. On energy, he says, America "has a lot to learn."

Starting with the argument—so popular among greens and Democrats—that we are running out of oil. "Peak oil"—the theory that global oil production will soon hit maximum levels and begin to decline—is a favorite among this crowd, and it is one basis for their call for more biofuels and solar power. Mr. Watson doesn't dismiss the idea but explains why it remains largely irrelevant.

In theory, he says, "we've been running out of oil and gas for a long time," yet technology creates new opportunities. Mr. Watson cites a Chevron field long in decline down the road in Bakersfield—to the point that for every 100 barrels of oil "in place," the company was extracting only 10 or 20. But thanks to a new technology called steam flooding, Chevron is now getting 70 to 80 barrels. "Price creates incentive, and energy will be developed if there's demand for it at the price you can develop it," Mr. Watson says. In that sense, "oil and gas are plentiful."

Don't believe it? Over the past 30 years, even as "peak oil" was a trendy theme, the world's proven reserves of oil and natural gas increased 130%, to 2.5 trillion barrels.

Or consider America's latest energy innovation: hydrofracking for abundant and cheap natural gas. This advance, says Mr. Watson, took even the industry "by surprise"—as evidenced by the many U.S. ports to import liquid natural gas that are now "sitting idle." Chevron last year paid $3.2 billion to buy natural-gas producer Atlas Energy as its foray into this new market.

Mr. Watson has little time for the Beltway fiction that America will soon be able to do without, or nearly without, fossil fuels. Yes, "we need all forms of energy." But the world consumes 250 million barrels of energy equivalent today, only a "tiny fraction of which" is wind and solar—and even those "are not affordable at scale," he says.

As for biofuels, "we would need to consume land the size of states" to hit the country's current ethanol targets. Chevron is investigating biofuels, but Mr. Watson says the "economics aren't there" yet. Unlike many CEOs, Mr. Watson insists on products that can prosper without federal subsidies, which he believes are costly and lacking in transparency when "consumer pockets are tight, government pockets are tight."

Bottom line: "We're going to need oil and gas and coal for a long time if America wants to keep the lights on."

He seems to mean it, too: Chevron recently announced the largest capital and exploratory budget in its history, $26 billion to drill in Australia, Western Africa and the Gulf of Thailand, among other places. Some of that cash will go to the Gulf of Mexico, though Mr. Watson wishes there were more U.S. opportunities.

"Most of the well-developed world—Australia, Western Europe—they develop their resources base, they inventory it, they develop it, and they view it as a good source of jobs and revenue," he says. The U.S.? "We are a country" that for too long has taken "affordable energy for granted."


The Chevron exec was "pleased" to see Mr. Obama acknowledge that "oil and gas were fuels of the future—because I hadn't heard that before. That's a significant step." Looking to reassure Americans about rising gas prices, the president nonetheless resorted to the old standby of calling for a one-third reduction in U.S. oil imports by 2025. Mr. Watson thinks that's a fine goal, but he points to the enormous disconnect between what the president is proposing and existing policies.

The only conceivable way to meet that goal is by dramatically increasing U.S. oil production—immediately. The White House recently bragged that last year American oil production hit its highest levels since 2003. What it failed to mention is that it takes years for leases to start producing, so credit for last year's surge goes to the Bush administration.

But what about the BP Gulf spill? Mr. Watson blames the "cultural aspects and behavioral aspects" of the particular drilling rig that exploded. He roundly disagrees with the finding of Mr. Obama's spill commission that the "root causes" of the spill were "systemic" to the industry.

"There is no evidence to support that. I don't know how that conclusion was reached. I know the industry has drilled 14,000 deep water wells without having this sort of problem." As for the moratorium, "I can understand taking a pause. I can't understand shutting down a whole industry for a better part of a year."

Chevron has three deep water rigs in the Gulf, so the ban cost it millions of dollars in idle rigs and lost jobs. For the country, says Mr. Watson, it means "less oil." Offshore drilling takes years of lead time. Mr. Watson cites Chevron's Gulf "Tahiti" project, which started producing about 18 months ago. It has taken "the better part of a decade to do the seismic work, drill the exploratory wells, evaluate those wells, drill other development wells, to delineate it, to build the facilities and to place the oil wells online," he explains.

The endless moratorium has already meant that "if you go out to the middle of the decade, there are already 200,000 to 300,000 barrels a day of oil that aren't going to be produced that year. . . . That won't be retrieved." And the lost production number is getting larger, since the new Bureau of Ocean and Energy Management is still dallying on permits—and those primarily for backlogged projects, not new leases.


Democrats are now arguing, as Mr. Obama did in his speech, that the oil industry already "holds tens of millions of acres of leases where it's not producing a drop." Some are advocating "use it or lose it," calling for the government to strip oil companies of their leases if they don't immediately start producing.

Mr. Watson explains why this is bogus. Only one-third of Chevron's offshore leases are classified as "producing" oil and gas today. The other two-thirds either are "unsuccessful" (they don't hold viable oil or gas) or "are in varying stages of development—seismic work, drilling wells, constructing facilities." Mr. Watson says companies would be crazy to sit on productive lands, since leases require costly bonus payments and annual rental payments to the government.

If Washington institutes Mr. Obama's "use it or lose it" policy, Mr. Watson says, it will mean less U.S. oil production. And how does this help Mr. Obama with his goal of reducing imported oil?

As for soaring oil prices, Mr. Watson blames growing demand, tighter supply, Mideast uncertainty and inflation. He doesn't predict future price trends, though during a recent analyst call he warned that the drilling moratorium would only make them higher. Lost production in the Gulf is "going to represent a sizable chunk of the spare capacity that the industry expects to see. And that will impact prices, and that will retard economic growth."

The economy is also why Mr. Watson won't pay the usual energy CEO lip service to new carbon regulations. The cap-and-trade bill the House passed in 2009 was "poorly conceived and it collapsed under its own weight for good reason," he notes.

The EPA move to regulate carbon is no better: "It's not why the Clean Air Act was put in place, and it doesn't seem to be the right way to attack concerns about greenhouse gas emissions," he says. The EPA is "placing huge new regulatory burdens on industries that are import sensitive." The regulations will place burdens on refineries, putting "their competitiveness at risk, and ultimately we'll produce less gasoline here and end up importing it from refineries that are less energy efficient overseas."

Mr. Watson says Americans can accomplish a great deal with "affordable conservation." And "a wealthy economy," he adds, "is better able to deal with the costs of greenhouse gas abatement than a poor economy." Since "large numbers" of countries are "unlikely to take aggressive action on greenhouse gas emissions," the "U.S. is going to have to decide, just as California is going to have to decide, if they want to go it alone. . . . Are they willing to place the burden on our economy and our consumers, at the expense of jobs?"

That pretty much sums up the broader choice America faces on energy policy. It can listen to the Washington siren song on alternative energy, pouring scarce dollars into green subsidies, driving up the cost of energy, and driving out U.S. manufacturing and jobs. Or it can embrace our own fossil fuel resources, which are cheap and plentiful.

"What I see are people who want affordable energy," says Mr. Watson. "They want strong environmental standards—they want a lot of things—but first and foremost they want affordable energy. And if you want affordable energy, you want oil, gas and coal."
Click to expand...
 
http://noir.bloomberg.com/apps/news?pid=conewsstory&tkr=RDSA:LN&sid=a3zl2PLCMhUQ


Shell Says Slow U.S. Drill Permits in Alaska ‘Irresponsible’
By Kim Chipman

April 26 (Bloomberg) -- Royal Dutch Shell Plc is being blocked from offshore oil and gas exploration in Alaska by the “irresponsible” delays of federal regulators, said the company’s U.S. president, Marvin Odum.

Shell, based in The Hague, has spent more than $2 billion for hundreds of drilling leases in Alaska since 2005, and has invested $1.5 billion on an exploration program that exceeds current regulatory requirements, Odum said.

“Despite our most intense efforts, we have yet to drill a single well,” Odum said today at a conference in Washington.

Shell’s biggest impediment has been obtaining an air permit from the Environmental Protection Agency for temporary exploration operations off the Alaska coast, Odum said.

“The delay is frustrating and disappointing and it undermines confidence in the American regulatory system,” he said. “Beyond that, you might call it irresponsible. Thousands of men and women were counting on those jobs, local businesses were counting on the revenue and communities were counting on the tax boost.”

Shell delayed its drilling campaign in Alaska and put off plans to spend as much as $150 million in the region until 2012, citing regulatory delays, according to a Feb. 3 statement. Alaska may hold the second-biggest U.S. oil and gas reserves after the Gulf of Mexico, according to government estimates.

Odum said Shell supports appropriate new offshore drilling regulations after the 2010 BP Plc oil spill in the Gulf. The U.S. must restore projects in the Gulf and open areas of the eastern Gulf and Alaska for exploration, he said.

Shell Deep-Water Permit
Last month, Shell won a U.S. permit to drill a deep-water well in the Gulf where exploration was banned after the BP blowout a year ago.

“That’s encouraging and I’m cautiously optimistic that marks a turning point in the Gulf,” Odum said today. Shell is the second-largest producer of crude from U.S. Gulf wells.

The regulatory status in Alaska is “much different,” he said. Odum said he’s hopeful the delay will be resolved and he appreciates EPA Administrator Lisa Jackson looking at the issue.

Several federal agencies have worked with Shell to help the company in Alaska, including the EPA, which issued a permit on March 31, 2010, according to a statement.

“That permit was subsequently appealed by outside groups, including local Alaskan stakeholders, and overturned by the independent Environmental Appeals Board,” according to the statement. “EPA immediately appealed for reconsideration and we have worked with Shell to address the concerns.”

‘Preferred Fuel’
Odum said Shell, which has invested more than $17 billion in North American natural gas production and development, next year will produce more gas than oil.

“It’s worth pursuing and it will be a preferred fuel,” he said.

The U.S. has enough untapped gas to last a century, though some states and environmentalists are concerned that hydraulic fracturing, or fracking, in which a chemical mix is injected into shale rock to free gas will taint drinking water.

Reports challenging the safety of fracking are “at best incomplete and at worst irresponsible,” Odum said. “Make no mistake, it can be done without harming the environment.”
Click to expand...
 
http://noir.bloomberg.com/apps/news?pid=20601207&sid=am6.7q3mEEls


Libya Hurts Med Refiners, Rewards Russian Links
By Rachel Graham

April 27 (Bloomberg) -- The best-quality oil is fetching the highest premium in more than two years, weighing on profits at Mediterranean refiners that depend on Libyan crude.

North Sea Dated Brent, Europe’s benchmark low-sulfur crude, sold for $7.11 a barrel more than Dubai crude, a Middle Eastern high-sulfur oil, on April 11, according to data compiled by Bloomberg. That’s the highest spread since October 2008. Brent’s premium to Iran Heavy crude has doubled from January’s average.

Nine weeks of civil conflict in Libya is crimping supply of lower-sulfur “sweet” crude, which is more easily refined into cleaner-burning fuels, pushing up prices for comparable grades from the North Sea and Nigeria. That helps Finland’s Neste Oil Oyj, Hungary’s Mol Nryt. and refiners set up to turn high-sulfur “sour” crude like Russian Urals, while hurting Mediterranean refiners such as Saras SpA and Hellenic Petroleum SA that can’t easily switch away from low-sulfur grades.

“The ability to process heavy-sour crudes will be a potentially significant source of competitive advantage for refiners this summer,” Daniel Ekstein, a London-based oil and gas analyst at Jefferies International Ltd., said in an April 13 note. “A lot of the Med refineries are configured to run a very particular crude slate, and it’s not straightforward to change that configuration.”

Workers Evacuated
Libya accounted for 8.8 percent of global light, low-sulfur crude supply in 2010, according to JBC Energy GmbH, a Vienna- based consultant. Oil output from the African OPEC member is down 75 percent as fighting between rebels and government troops forced producers such as Marathon Oil Corp. to evacuate workers.

Prices are rising for low-sulfur grades from Nigeria, Algeria and Azerbaijan, as well as those in the North Sea. Nigerian Qua Iboe’s premium to Brent rose to $4.13 a barrel on March 30, the most since July 2008. Meanwhile, Russian Urals’ discount to Brent crude in northwest Europe widened to $4.30 a barrel on April 12 from $1.90 discount at the start of the year.

The discount on Urals helps refiners including Neste Oil, which operates plants in Naantali and Porvoo in Finland and gets most of its crude from Russia, according to AlphaValue, a Paris- based research company.

Neste’s stock gained 13 percent this year, compared with a 5 percent advance in Europe’s Stoxx 600 Oil and Gas Index. The company, based in Espoo, Finland, gets 70 percent of its crude from Russia and none from Libya, according to Kaisa Lipponen, a company spokeswoman.

Soviet Links
“Plants that can handle Russian crude are doing well right now,” Credit Agricole’s Barret said from London. Many refineries in former Eastern bloc countries such as PKN Orlen SA’s Plock facility were designed to handle Russian heavy crude and are still linked by pipelines dating back to Soviet times.

BP Plc can process Urals at its Gelsenkirchen facility in Germany, while Total SA uses Russian imports at Leuna, south of Berlin, where a sulfur-removal unit was completed in 2009.

Mediterranean refiners, being closest to Libya, tend to be the most reliant on its crude. Saras, which operates the Sarroch refinery in Sardinia, imports as much as 40 percent of its crude from Libya, Rafaella Casula, a spokeswoman for the company in Milan, said in an e-mail yesterday.

Saras has ample flexibility in its operations, allowing it to use more than 20 types of crude, Casula said. The company will likely need to find alternatives to Libyan crude from the second quarter, the e-mail said. The Italian company was more reliant on Libya than Repsol YPF SA, Spain’s biggest oil company, which bought 16 percent of its crude from North Africa in 2009, according to its website.

Hellenic’s Oil Supply
Hellenic Petroleum relies on Libya for as much as 12 percent of its supply, John Kostopoulos, chief executive officer, said in February. Athens-based Hellenic may be “competitively disadvantaged” by the rising premium for sweet crude until it finishes a 1.2 billion euro ($1.8 billion) upgrade at its Elefsis plant, Jefferies’ Ekstein said.

“Refineries are designed to process a certain percentage of sweet and sour crudes,” said Christophe Barret, an oil analyst at Credit Agricole CIB. “They have to reassess production if they lose supply, and that can be quite costly.”

Hellenic had to switch to other sources of light-sweet crude because of lost Libyan supply, a spokesman said from Athens, declining to be identified in line with company policy.

OMV AG, one of the oil producers forced to curb output in Libya, is adapting its Burghausen refinery in southern Germany to use crudes from other countries. Vienna-based OMV ran about 20 percent of its capacity on Libyan oil before the crisis.

Suitable Alternatives
OMV told investors the crisis in Libya will cut earnings before interest and taxes by an estimated 20 percent, Philipp Chladek, an analyst at Raiffeisen Centrobank AG, said in an April 20 note. Sven Pusswald, a spokesman for OMV, declined to comment on profit.

European refiners may find it harder in coming weeks to get suitable crudes as they return from seasonal maintenance, the International Energy Agency in Paris said in an April 12 report.

“The impact of the lost supplies has so far been muted by the fact that European spring turnarounds hit a seasonal peak in March,” the agency said. Refinery maintenance is mostly timed to allow refiners to maximize production of gasoline in the European summer and heating oil in winter.

Supply from Saudi Arabia, the biggest producer in the Organization of Petroleum Exporting Countries, is helping to offset the loss in Libyan supply, an official from Kuwait National Petroleum Company said. “The impact is softened with Saudi Arabia’s production boost to compensate the deficit,” Bakhit al-Rashidi, deputy managing director, said in an e-mailed statement yesterday.

Poor Substitute
Most Saudi Arabia crude isn’t a direct substitute because it has more sulfur than Libyan crude. Arab Medium and Arab Extra Light contains more sulfur than Es Sider, the Libyan benchmark. Saudi’s Extra Light contains 1.16 percent sulfur, compared with a 0.44 percent threshold for Libya’s Es Sider, according to Energy Intelligence Group.

Saudi Arabia developed two new blends with reduced sulfur content in response to the Libyan shortfall. The blends have seen a “lukewarm response” from European refiners, Amrita Sen, an analyst at Barclays Plc, said in an April 14 report.

Putting a lesser quality crude through a refinery’s processing units can yield inferior fuels.

“Some refiners are set up to produce low-sulfur gasoline and diesel,” said Jonathan Leitch, a London-based senior analyst at Wood Mackenzie Consultants Ltd. “If you run heavy crudes you’ll have problems. It could mean the refiner can’t meet the market specification.”

Tupras Turkiye Petrol Rafinerileri AS, the operator of refineries in Turkey, is buying more Saudi and Iranian crude for its plants, making it one of the beneficiaries of the discount on Middle East grades, Tamas Pletser, an analyst at ING Groep NV, said by phone. “Tupras is a major buyer of sour crudes, so this expanding margin is likely to be replicated in the company’s own margins,” he said.

Tupras gained 24 percent this year on the Istanbul Stock Exchange, outperforming a 3 percent rise on the ISE National 100 Index, Turkey’s benchmark index. Tupras officials in Izmit weren’t available for comment when called yesterday.
Click to expand...
 

Amazing stuff.


Discovered in July 2004 by the Discoverer Deep Seas drillship, the Jack oil field is located on Walker Ridge Blocks 758 and 759 in the Gulf of Mexico. Situated in approximately 7,000 feet (2,134 meters) of water, the ultra-deepwater discovery is located 270 miles (435 kilometers) southwest of New Orleans.

Drilled to a total depth of 29,000 feet (8,839 meters) on July 29, 2004, the Jack-1 exploration well encountered more than 350 feet (107 meters) of net oil sands pay.

In 2005, a second well was drilled on the field by the Discoverer Deep Seas drillship, and in the fall of 2006, the Cajun Express semisubmersible recorded an exceptional well test on Jack-2. Drilled on Walker Ridge 758 in 7,000 feet of water (2,134 meters), the record-breaking well reached a total depth of 28,175 feet (8,588 meters) and was the deepest ever to be successfully production tested.

Additionally, the well set more than half a dozen world records for equipment pressure, depth and duration. Conducted to test a portion of the total pay interval, the Jack-2 well test maintained a daily flow rate of more than 6,000 bopd, which represents only 40% of the total net pay measured.

Completed in November 2008, the third well, drilled on Walker Ridge 758 by Devon, is an appraisal well, too. Information has not yet been released on the results of this well.

Appraisal drilling continues on Jack, but current size estimates foretell one of the largest fields in the Gulf of Mexico. Information available to date, rates the field's size as the fifth-largest in deepwater Gulf of Mexico with nearly 500 MMboe.


Innovative Exploration and Production

Hydrocarbons on the field are located in the emerging Lower Tertiary Trend, deposited about 65 million years ago more than 20,000 feet (609 meters) under the seabed. The MMS reports that the formation is "an exciting new trend," adding that the area could extend across as many as 300 miles (483 kilometers) and significantly increase reserves. Although field development plans have not been released, development solutions have been leaning toward FPSO/FSO production in conjunction with St. Malo nearby. Production is expected to commence in 2013.

At such depths, the field is in a league of its own in regard to using historical information to help with development ideas. In fact, to encourage ultra-deepwater drilling and production, the MMS has offered royalty relief to companies pushing the envelope in these areas.

The field is operated by Chevron, which has 50% interest. Partners include Maersk with 25% working interest and Statoil with the remaining 25% working interest.


St. Malo

Discovered in October 2003 by the Discoverer Spirit drillship, St. Malo is considered to be a major deepwater discovery in the Gulf of Mexico. The field is located on Walker Ridge Block 678 in a water depth of 2,100 feet (640 meters).

Chevron is the operator and holds a 51% working interest. Chevron co-ventures on the St. Malo prospect with Petrobras, 25%; Statoil, 21.50%; ExxonMobil, 1.25%; and ENI, 1.25%.

Located 250 miles (402 kilometers) south of New Orleans, St. Malo's discovery well was spud by the Cajun Express semisub on July 6, 2003. The discovery well is located in 6,900 feet (2,103 meters) of water and was drilled to a depth of 29,066 feet (8,859 meters). More than 450 feet (137 meters) of net oil pay over a gross interval of 1,400 feet (427 meters) was encountered on the field.

On May 4, 2004, an appraisal well was drilled -- one mile (2 kilometers) east of the St. Malo discovery. The well, previously named Dana Point, was a re-entry and deepening of a dry hole that was drilled in 2001. The re-entry well was deepened to a depth of 28,903 feet (8,810 meters) in roughly 7,032 feet (2,143 meters) of water by the Discoverer Deep Seas drillship. The well was re-entered to save costs, cutting $25 million by not drilling a new well.

Evaluation of the appraisal well found that St. Malo's hydrocarbon resources span across a larger area than previously suggested by the discovery well.


Field Development

A final investment decision for the joint development of the project was approved on Oct. 21, 2010. Initially, the project will require an investment of about US $7.5 billion and will compromise three subsea centers tied-back to a production hub. The facility will have a production capacity of 170,000 bopd and 42.5 MMcf/d of natural gas, as well as house provisions for future water injection of 200,000 bpd.

In May 2009, Chevron awarded Mustang the FEED contract for a joint Jack/St. Malo semisub production facility.

Enbridge announced in June 2009 that a letter of intent signed with Chevron could result in the expansion of its offshore pipeline system. The letter of intent proposes to construct, own and operate the Walker Ridge Gathering System to provide natural gas gathering services to the joint development.

The operator awarded a contract to Cameron for the supply of subsea production systems for the first stage of the Jack and St. Malo development. The project encompasses a dozen 15,000 psi subsea trees, production control systems, four manifolds and associated connection systems, engineering and project management services. Deliveries are scheduled to begin in the third quarter of 2011 and continue through the second quarter of 2013.

Chevron awarded Technip a contract in January 2011, for the engineering, fabrication and subsea installation of more than 53 miles of 1.75-inch outer diameter flowlines, steel catenary risers, pipeline end terminations, manifolds, pump stations and tie-in skids. Offshore installation is scheduled for completion in 2013.

InterMoor finalized an agreement with Cameron to design and fabricate 11 suction piles for the Jack/St. Malo development. The 11 suction piles are 18 feet (5 meters) in diameter, ranging from 55 to 75 feet (17 to 23 meters) in length and weighing up to 115 tons. The fabrication portion was awarded later in 2010; fabrication started in December; and the last pile will be delivered in January 2012.

In April 2011, Chervon awarded MyCelx a contract to design and deliver a produced water treatment system, to remove oil and water soluble organics to below 10 parts per million, for the Jack/St. Malo facility.
Click to expand...
 


Un-frickin'-believable—




http://www.youtube.com/watch?v=0WNTTlAwwhU&feature=relmfu

Shell has been a leader in deep-water exploration and production for 30 years. Parque das Conchas (BC-10) offshore Brazil is one of our most challenging deep-water projects. Shell has a 50% interest in the project and is the operator. Parque das Conchas (BC-10) lies in around 1,780 metres of water...

Technology
Parque das Conchas (BC-10) represents a key milestone in the development and commercialisation of Brazil’s offshore heavy oil. The three fields have been developed with subsea wells and manifolds, with each field tied back to a centrally located Floating Production Storage and Offloading (FPSO) vessel moored in around 1,780m of water. The development is the first of its kind based fully on subsea oil and gas separation and subsea pumping. The drilling programme uses floating-rig surface blow-out preventer well drilling and completions.

The development includes the first application of steel tube hydraulic and multi-circuit high power umbilicals, which deliver power to 1,500-horsepower pumps on the sea floor. It is also the first application of lazy wave steel riser technology on a turreted FPSO. Initial production is expected to reach ~60,000 kboe/d, with headroom in the FPSO design for additional growth from improved recovery or future discoveries...


http://www.shell.com/home/content/aboutshell/our_strategy/major_projects_2/bc_10/overview/
Click to expand...



http://www-static.shell.com/static/media/downloads/press/golf_mexico_perdido.pdf
 
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http://www.eia.doe.gov/oiaf/aeo/electricity_generation.html

According to the Institute of Energy Research, the cost of electricity from new plants designed to open in 2016 from different sources will be approximately as follows:
( $/Mwh )

Solar thermal ..............................................312
Offshore Wind ............................................243
Solar photovoltaic ........................................211
Coal with CCS ............................................136
Nuclear ......................................................114
Biomass ......................................................112
Wind ..........................................................97
Coal ..........................................................95
Gas with CCS ..............................................89
Hydro ........................................................86
Gas, combined cycle ..................................63


The levelized cost shown for each utility-scale generation technology in the table are calculated based on a 30-year cost recovery period, using a real after tax weighted average cost of capital (WACC) of 7.4 percent. However, in the AEO2011 reference case a 3-percentage point increase in the cost of capital is added when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). While the 3-percentage point adjustment is somewhat arbitrary, in levelized cost terms its impact is similar to that of a $15 per metric ton of carbon dioxide (CO2) emissions fee when investing in a new coal plant without CCS, similar to the costs used in simulations that utilities and regulators have used in their resource planning. The adjustment should not be seen as an increase in the actual cost of financing, but rather as representing the implicit hurdle being added to GHG-intensive projects to account for the possibility they may eventually have to purchase allowances or invest in other GHG emission-reducing projects that offset their emissions. As a result, the levelized capital costs of coal-fired plants without CCS are higher than would otherwise be expected.

In the table, the levelized cost for each technology is evaluated based on the capacity factor indicated, which generally corresponds to the maximum availability of each technology. Simple combustion turbines (conventional or advanced technology) are typically used for peak load duty cycles, and are thus evaluated at a 30 percent capacity factor. The duty cycle for intermittent renewable resources of wind and solar is not operator controlled, but dependent on the weather or solar cycle (that is, sunrise/sunset). The availability of wind or solar will not necessarily correspond to operator dispatched duty cycles and, as a result, their levelized costs are not directly comparable to those for other technologies (even where the average annual capacity factor may be similar).
 

The Shale Gas Shock
by Matt Ridley, Ph.D.
http://thegwpf.org/images/stories/gwpf-reports/Shale-Gas_4_May_11.pdf
p. 21


There are cases in Colorado, highlighted by a flaming tap in Fort Lupton in the film "Gasland," where gas in domestic drinking water from an aquifer can be ignited. However, testing has shown that in Fort Lupton the water well penetrates several coal seams and the gas is 'biogenic' gas (from coal) with a chemical signature different from the 'thermogenic' deep shale gas below:

In most cases, however, the [Colorado Oil and Gas Conservation Commission] has found that contamination is not present or that the methane comes from biogenic sources and is not attributable to oil and gas production.
-- Colorado Oil and Gas Conservation Commission, 2010.

http://cogcc.state.co.us/library/GASLAND DOC.pdf
Click to expand...
Click to expand...
 
http://bittooth.blogspot.com/


...It is going to combine a little bit of history (along the lines that Econbrowser posted on Saturday about the initial discovery by “Colonel” Drake, in Pennsylvania in 1859, with the evolution and current status of some of those fields. (And again Econbrower has beaten me to that particular punch by posting the plot, taken from Caplinger which shows the historic production from the more than 350,000 oil and gas wells that have been drilled in that state, since that time...
Click to expand...
 



Hookay, lessee heah.

Code: 
 $3.85 	 $2.09 	 $2.34 	Cost per gallon
			
$0.46	$0.25	$0.28	Distribution & Marketing
$0.41	$0.31	$0.35	Refining Costs & Profit Margin ( @ 5% of retail price)
$0.60	$0.46	$0.51	Federal & State Taxes
$2.38	$1.07	$1.19	Petroleum Cost/Gallon
× 42	× 42	× 42	Gallons/Barrel
$100.00 $44.77 $50.12	Petroleum Cost/Barrel

Source: http://www.eia.gov/energyexplained/index.cfm?page=gasoline_factors_affecting_prices

 

http://www.bloomberg.com/apps/chart?h=200&w=280&range=1y&type=gp_line&cfg=BQuoteComp_10.xml&ticks=S5ENRS%3AIND&img=png

Standard and Poor's 500 Energy Index is a capitalization-weighted index.
The index was developed with a base level of 10 for the 1941-43 base period.
The parent index is SPXL1. This is a GICS Level 1 Sector group.


​

http://noir.bloomberg.com/apps/quote?ticker=S5ENRS:IND

______________________________


http://www.bloomberg.com/apps/chart?h=200&w=280&range=1y&type=gp_line&cfg=BQuoteComp_10.xml&ticks=SPICENRG%3AIND&img=png

These indices track S&P Net income by sector on a quarterly basis. The
incomes reported for the current quarter are progressive over the length of
the quarter and are revised as more earnings are reported. The historical
data provided is not revised and exists as it was at the end of the quarter
indicated. These indices are taken off of news stories that report earnings
results from the S&P.


​
http://noir.bloomberg.com/apps/quote?ticker=SPICENRG:IND
 
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