German Government Plans Total Nuclear Shutdown by 2022

Deutsche Welle, May 30, 2011
As public opposition to nuclear power remains high, the German government has announced new plans to phase it out completely in the next 11 years. And the proposal may have a chance at support from the center-left.

The German government on Monday announced plans to completely phase out nuclear energy by 2022, a 14-year acceleration of its previous plans.

Environment Minister Norbert Röttgen announced the proposal in the early hours of Monday, after a 12-hour marathon meeting between Chancellor Angela Merkel's Christian Democrats (CDU) and the junior coalition partners, the Free Democrats (FDP).

"It's definite: the latest end of the last three nuclear power plants is 2022," Röttgen told reporters. "There will be no clause for revision."

Last October, the German parliament voted in favor of a much slower nuclear shutdown, lasting until 2036. The government said that it was necessary to ensure the supply of Germany's energy needs.

After the nuclear disaster at the Fukushima nuclear power plant in Japan [please see my March blog posts under the category/label "Japan." -- D.R.], public opposition to nuclear energy sharply increased. In March, Merkel announced a temporary shutdown of seven older nuclear plants [Chancellor Angela Merkel decreed that the country's nuclear power reactors which began operation in 1980 or earlier, i.e., Biblis-A, Neckarwestheim 1, Brunsbüttel, Biblis-B, Isar 1, Unterweser, Phillipsburg 1, should be immediately shut down---please see my post/remarks, here. Those units then closed and were joined by another unit/Krümmel already in long-term shutdown, despite having started up in 1984, making a total of 8336 MWe offline under her direction, about 6.4% of the country's generating capacity. -- D.R.]

The new timeline would keep those [...] [eight] plants offline permanently. Six more would be shut down in 2021, and three would stay on until 2022 to ensure no disruption to power supply [Thus, all 17 of the country's nuclear plants will be shut by 2022 -- D.R.]. [Read more]

(Before March's moratorium on the older power plants, nuclear power supplied 23% of Germany's electricity. The United States is the world's biggest nuclear-electricity producer, followed by France, Japan, Russia, South Korea and Germany, according to the 2009 data---please see here. -- D.R.)

Study: North America Dominates Global Shale Gas Market

by Jonathan Katz, IndustryWeek, May 26, 2011
North America will hold a 78% share of the global shale gas production in 10 years because of the region's technical expertise and availability of resources, according to a report released May 25 by Markets and Markets [please see remarks below -- D.R.].

In 2010 North America was the only region active with commercial shale gas production. But current exploration and production activities by major oil and gas companies in Europe and Asia Pacific are expected to lead to shale gas commercialization in these regions by 2016, the report says.

The markets representing high growth rate in shale gas production from 2016 to 2021 are China (6.2%), Poland (6%), France (5.4%) [regarding shale exploration in France, please see my post "Shale Gas Development in Europe" below -- D.R.], South Africa (5.1%) and the United States (5%).

Global shale gas production is expected to grow to 6,991 billion cubic feet in 2021 at a compound annual growth rate of 5.4% [sic; from 2011] through 2021. [Please see remarks below -- D.R.]

Rising shale gas production will likely boost ethylene production by 6.6% by 2021. Ethylene is a feedstock [that can also be] derived from natural gas that is used in petrochemicals. [Also, please see my post, including remarks, here -- D.R.]

Challenges that could hinder shale gas development include the capital-intensive nature of shale gas projects and environmental issues associated with hydraulic fracturing. [Full story]

(Please see a press release from Markets and Markets "MarketsandMarkets: Global Shale Gas Market to reach 6.9 tcf by 2021 and With 78% Market Share North America Continues to dominate the Shale Gas Market." According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010. In 2010, U.S. shale gas production constituted 23 percent of total U.S. natural gas production---please see here. For exploration of shale gas in Poland, please see my post "Marathon, Nexen to Jointly Explore Shale in Poland," here. For shale gas in Europe, please see my post "World Watch [Shale Gas Development in Europe]," here. For China's quest for unconventional gas, please see my post "China Plans to Exploit its Shale Gas Resources," here. For Mexico's first shale gas production, please see, inter alia, here. Also, please see Table: Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries, Compared to Existing Reported Reserves, Production and Consumption during 2009 --- EIA, here. -- D.R.)

Cheniere Gets OK to Ship [LNG] Overseas

Upstream Online, May 20, 2011
Cheniere Energy received approval from the Department of Energy to export US natural gas overseas, the first such authorization in over forty years, the company said today.

Assuming Cheniere is granted a subsequent license from US power regulators to build its liquefaction plant in Louisiana, it may become the first company to begin shipping LNG abroad since the discovery of vast shale reserves in recent years upended the US market, flooding it with decades' worth of supply.

Cheniere has the authorization to export up to 803 billion cubic feet of natural gas per year to major LNG importers across the globe [...] in the form of liquefied natural gas [...] [Actually, Cheniere now has authorization to export domestically produced natural gas from the Sabine Pass LNG terminal as LNG to any country that has, or in the future develops, the capacity to import LNG and with which trade is permissible -- D.R.]

The Houston-based company already had approval [as of Sept 2010] to export natural gas [as LNG] to countries with which the United States had a free-trade agreement [such as Mexico, Canada, Chile and Singapore ...].

Friday's [May 20] move opens up the export to all major [and minor] LNG importers.

"With the unprecedented growth in unconventional reserves, supply of natural gas (in the United States) continues to outpace demand dramatically," said Cheniere chief executive Charif Souki.

 "The US has an opportunity to become a significant supplier in the global energy markets," he added.

The first and only US LNG export plant was built in Alaska 40 years ago [the Kenai LNG export plant began operating in 1969 -- D.R.], but is now in the process of shutting down because it is no longer competitive with newer suppliers in Asia.

Cheniere announced plans last year to build a natural gas liquefaction plant at Sabine Pass in Louisiana, which it expects will come online in 2015 on the site of its existing LNG import terminal.

The approval is subject to the Federal Energy Regulatory Commission giving approval to build the export plant. [Read full]

(Following the conditional authorization of LNG exports from the Sabine Pass terminal, Lithuania's Deputy Foreign Minister Egidijus Meilūnas discussed the implications of the export project with the U.S. State Department. Meilūnas observed that U.S. LNG exports could help lower Lithuanian natural gas prices---please see The Baltic Course, May 24, 2011. "Exporting LNG to Lithuania will allow one of our allies to diversify its natural gas supply, increase its energy security and strengthen its economy. Cheniere is happy to fill this important role in the global energy markets," said Charif Souki, Chairman, President and CEO of Cheniere Energy, Inc.---please see here. For Lithuania's natural gas consumption in 2010, please see my post "Eurogas: EU 27 Gas Consumption Rises 7.2% in 2010," including remarks, here. Separately, for the U.S. shale gas production and reserves, please see my post "[United States:] Natural Gas Production/Consumption Retrospective 2010," including remarks, here. -- D.R.)

EPP to Extend Eagle Ford Crude Oil Pipeline

by Christopher E. Smith, OGJ Pipeline Editor, OGJ, May 6, 2011
Enterprise Products Partners LP plans to build an 80-mile extension of its 350,000-b/d Eagle Ford shale crude oil pipeline, allowing it to serve growing production areas in the southwestern portion of the play. The 200,000 b/d Phase II project would originate in Wilson County, Tex., at the terminus of Enterprise's previously announced 140-mile Phase I segment (OGJ Online, Sept. 30, 2010), and extend to a site near Gardendale, Tex., in La Salle County, where a new 500,000 bbl central delivery point is planned.

Phase I is on schedule to begin service by second-quarter 2012, according to EPP, with Phase II set to commence operations in first-quarter 2013. The roughly 220-mile pipeline system will provide Eagle Ford producers with access to the Texas Gulf Coast refining complex through EPP’s Sealy, Tex., delivery point. The Sealy facility interconnects with its Rancho Pipeline and feeds into EPP’s new ECHO crude oil storage terminal being constructed along the Houston Ship Channel in southeast Harris County, Tex. (OGJ Online, Nov. 11, 2010).

The Phase II extension is anchored by a 10-year, 100,000 b/d shipping agreement with Chesapeake Energy Marketing Inc., a subsidiary of Chesapeake Energy Corp. EPP said, including the Chesapeake agreement, it now has producer commitments for 320,000 b/d under 10-year contracts.

About 165 rigs are working in the Eagle Ford shale, having drilled more than 1,200 wells, Enterprise said. Current production from the play is roughly 100,000 b/d [of crude oil and condensate -- D.R.]. With more than 2.5 million acres under lease and potentially 15,000 wells to be drilled over the production life of the Phase II service area (based on EPP’s research and information it obtained from producers), the company expects development activity in this region of the Eagle Ford shale to remain brisk.

Estimates provided by producers also suggest that up to 3 billion bbl of crude oil are recoverable in the southwestern region of the play, EPP said. [Full story]

(Also, Plains All American Pipeline LP/PAA plans to build a 300,000 b/d, 130-mile crude oil and condensate pipeline, a marine terminal facility, and 1.5 million bbl of storage to serve growing Eagle Ford production in South Texas. A long-term throughput agreement with Chesapeake Energy Marketing Inc., a subsidiary of Chesapeake Energy Corp., underpins the construction plans. PAA expects the pipeline to enter service in fourth-quarter 2012 at a cost of about $330 million---please see OGJ, May 18, 2011. Separately, please see my post "BENTEK: Eagle Ford Crude Oil Production Expected to Grow Fivefold in Five Years," here. For maps of the Eagle Ford shale, please see here. For the map of North American shale plays from the U.S. Energy Information Administration/EIA, including the United States, Canada and Mexico, as of May 9, 2011, please see here. -- D.R.)

BENTEK: Eagle Ford Crude Oil Production Expected to Grow Fivefold in Five Years [...]

Business Wire, Apr 18, 2011
Oil, gas and NGL production from the liquids-rich Eagle Ford Shale in South Texas set to boom, due to a highly attractive oil/condensate play, a solid base of midstream infrastructure, extensive planned infrastructure expansions and proximity to some of the largest energy markets in North America. [...]

“Horizontal drilling for oil has been highly successful in the northern part of the play, with production expected to increase [more than] fivefold from current levels of 71,000 barrels of oil per day (B/pd) to an average of 421,000 B/pd by 2015, [almost as much as Australia],” said BENTEK Managing Director E. Russell (Rusty) Braziel. “We are projecting that dry natural gas production, mostly located in the southern portion of the Eagle Ford, will increase [...] [Read more]

(For the current Eagle Ford production of crude oil and condensate, please also see, inter alia, here. Update: for the 2012 figures of crude oil -- here. The increase in U.S. crude oil production in 2010 was led by escalating horizontal drilling programs in U.S. shale plays---please see my post "United States: Oil Production From Shale Formations, 2005-2010 -- EIA," here. For the map of the Eagle Ford shale from the U.S. Energy Information Administration/EIA - map date Oct 6, 2010, please see here. For EIA's map of North American shale plays, including the United States, Canada and Mexico, as of May 9, 2011, please see here. Mexico has begun drilling its northern regions for shale gas which it regards as an extension of the US' frenzied Eagle Ford Shale in South Texas, a bonanza which contains both oil and gas---please see my post, here. Mexico's state-owned oil company Petróleos Mexicanos/Pemex, said in March it had produced its first shale gas from an exploratory well at the Eagle Ford Shale formation in the northeastern state of Coahuila in February. -- D.R.)

Chart: History of U.S. Crude Oil Production, 1970-2010

by David Rachovich, retrieved from Aaron and David Rachovich, "U.S. Crude Oil Production, 1970-2010 -- EIA"

To view the chart (PDF format), please click here.

Please view data source for my chart.

(United States crude oil output reached its all-time peak of 9.637 million barrels per day in 1970 and began to fall rapidly and steadily after 1985. Following declines in all but one year, 1991, from 1986 to 2008, U.S. crude oil output increased in 2009 and again in 2010. -- D.R.)

World Watch [Shale Gas Development in Europe]

by Jim Washer, London, EI, May 16, 2011
Shale gas is beginning to take off in Europe, as a subject of debate and as a plausible new energy supply option. France’s National Assembly last week voted to ban the controversial technique of hydraulic fracturing in shale oil and gas exploration, a move which threatens to strangle the country's shale gas sector at birth. But elsewhere in the region, interest in shale exploration is growing, with Total farming into two concessions in Poland operated by Exxon Mobil, which is also assessing unconventional gas prospects in neighboring Ukraine. Europe can’t match North America’s shale gas resource potential, nor its attractive framework for onshore gas development. But one factor which typically complicates energy development elsewhere -- politics -- may encourage shale development in Europe. Countries like Poland and Ukraine both depend heavily – and not always happily -- on Russia for gas. Developing more indigenous gas resources would improve these countries’ security of supply, as well as strengthening their hand in gas supply and transit negotiations with Moscow.

(Poland's technically recoverable resources of shale gas are estimated to be 187 trillion cubic feet/tcf or c. 5.3 trillion cubic meters/tcm, the highest in Europe, followed by France with 180 tcf or c. 5.1 tcm---please see my post/table "Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries -- EIA," here. Also, please see my post "World Shale Gas Resources Outside US Assessed," here. For exploration of shale gas in Poland, please also see my post "Marathon, Nexen to Jointly Explore Shale in Poland," here. In theory, unconventional gas resources "might be able to cover European gas demand for another 60 years," said a recent study on unconventional gas – EUCERS Strategy Paper No 1, p. 30. -- D.R.)   

US Horizontal Rigs Drift past 1,000 Mark on "Shale Sail"

By Starr Spencer, Platts oil blog - The Barrel, May 13, 2011
Apologies to Bob Seger, but it seems just about everyone in the oil and gas industry these days is following the sentiment in this song, or at least doing a reasonable facimile.

There are all sorts of statistical goodies buried in the Baker Hughes weekly rig count. Here is one of them:

Apart from the fact that the US oil rig count is soaring and has now surpassed the number of rigs drilling for natural gas, which happened last month , US rigs drilling horizontal wells also passed the 1,000 mark in April [data showed on April 1st -- D.R.] for the first time.

And it continues its upward march. This past week ended May 13, 1,041 rigs were drilling horizontal wells, out of a total 1,830 total rigs. [Horizontal rigs now make up about 57 percent of the total rig count, up from a low of less than 4 percent in Sept 1998. Also, for the total drilling rigs in historical perspective, please see remarks below -- D.R.] That is the highest number since Baker Hughes began keeping track of such data in 1991, and probably [sic] is an all-time record.

The surge in horizontal drilling can only be traced to the shale explosion, which is truly one of the energy industry's Biggest Things. Everyone seems to be exploring for or at least reading about shale oil and gas these days, and in the process the purses of oil operators and also national economies are reaping the benefit.

Once companies hit on the idea, sometime in the early 2000s, that they could get a lot more natural gas by not only drilling down vertically, but then taking the well sideways or horizontally once they reached total depth, it was one of those "Eureka!" moments.

They then coupled that with fracture-stimulating or forcing fluid into rock at high pressure, and drilling increasingly longer laterals to access more of a reservoir from a single wellbore. The greater cost of a horizontal well was offset by more output. Once oil prices began to climb, they applied these notions to oil wells, with similar results.

Rig numbers tell the story. Horizontal drilling before the early 2000s wasn't unknown, but at that point it was more in the experimental stage. When Baker Hughes began keeping track of horizontal versus vertical wells starting the first week of January 1991, 100 rigs were drilling horizontally out of a total 1,108 rigs that week. Another 81 rigs were drilling directionally while the vast majority--927 rigs--worked on vertical wells.

In the succeeding years, horizontal drilling largely stayed below--sometimes well below--100 rigs. That is, until 2004, when the Barnett Shale [in Texas] began to glitter things up and everyone wanted to ride the shale trail. Then kicked off an upward trend of horizontal drilling that, except for the economic pullback of late 2008 to late 2009, continues to this day. [Also, horizontal rigs comprised less than one-third of oil-directed rigs in September 2008, and with a tripling of horizontal oil rigs since then, that share has increased to about 46 percent---please see my post "Domestic Oil Production Reversed Decades-Long Decline in 2009 and 2010," here. -- D.R.] 

Now the excitement of shale drilling is becoming an international phenomenon. Canada is several years into several shale gas and oil plays there; places such as Poland [please see my post "Marathon, Nexen to Jointly Explore Shale in Poland," here -- D.R.] and Germany are exploring their potential, and even Mexico has begun drilling its northern regions for shale gas which it regards as an extension of the US' frenzied Eagle Ford Shale in South Texas, a bonanza which contains both oil and gas [please see remarks below -- D.R.].

Still, not all shales require horizontal drilling. Small oil-focused Venoco, which held a nearly two-hour conference call this week and spoke at length about its pioneering Monterey Shale operation onshore southern California, said it expects vertical wells are the most likely way to develop that oil pool. However, with only one rig drilling Venoco's slice of the Monterey for the rest of the year, it appears to be the exception that proves the rule. [Full story]

(Since 1944 the highest weekly U.S. rig count was 4,530 recorded on December 28, 1981, the height of the oil boom. The lowest rig count of 488 was recorded on April 23, 1999. In Canada the highest weekly rig count of 718 was recorded on February 17, 2006. The lowest weekly rotary rig count of 29 was recorded on April 24, 1992---please see my post > remarks, here. Separately, please see my post/table "Estimated Shale Gas Technically Recoverable Resources for Select Basins in 32 Countries -- EIA," including China, Argentina, Mexico, Australia, Canada, Poland, France, etc., here. Also, please see my post "China Plans to Exploit its Shale Gas Resources," here.  Mexico's state-owned oil company Petróleos Mexicanos/Pemex, said in March it had produced its first shale gas from an exploratory well at the Eagle Ford Shale formation in the northeastern state of Coahuila in February. -- D.R.)

Top 8 Oil Producers in Asia & Oceania, 2006-2010 -- EIA

by Aaron and David Rachovich

Production of Crude Oil including Lease Condensate (Thousand Barrels Per Day), 2006-2010

Rank	Country	Full Year 2010 Average	Full Year 2009 Average	Full Year 2008 Average	Full Year 2007 Average	Full Year 2006 Average
1.	China	4,076	3,799	3,790	3,729	3,673
2.	Indonesia	943	946	972	964	1,019
3.	India	752	680	694	698	689
4.	Malaysia	554	578	609	588	613
5.	Australia	436	475	477	465	429
6.	Vietnam	318	299	300	319	345
7.	Thailand	242	238	229	213	204
8.	Brunei	136	131	133	155	198
Top 8 countries		7,457	7,146	7,204	7,131	7,170
Asia & Oceania total		7,753	7,442	7,518	7,416	7,459
Africa total		9,997	9,757	9,989	9,949	9,641
All Countries (World)		74,043	72,259	73,655	72,986	73,428

Source: U.S. Energy Information Administration (EIA), International Energy Statistics, here.

(Figures above may be updated at any time by EIA. Also, please see Aaron and David Rachovich, "World's Top 22 Oil Producers, Full Year 2010 (including OPEC and plus 2009 production)," here. And our post "Top 25 World Oil Consumers, 2009-2010," here. -- D.R.)

North Dakota Oil Tax Revenue Breaks $100M Mark in March as Industry Booms

by Judson Berger, Fox News, May 9, 2011
North Dakota's booming oil industry has yielded record tax revenue for the state, breaking the $100 million mark in March at a time when other states are struggling to stay afloat.

The state in just the last few years has become an oil-producing powerhouse and is looking to overtake California in total production. [...]

Much of the recent increase is due to rising crude prices, which have shot up amid concerns over unrest in the Middle East. But North Dakota's oil production is also accelerating rapidly, and state officials expect the windfall to hold steady. [...]

The 350,000 barrels a day produced in March was actually about 2,000 barrels a day lower than in February. But [state Deputy Tax Commissioner Ryan] Rauschenberger attributed the dip to the weather, and said that even if crude prices return to prior levels the state expects to take in $2 billion in oil-related tax revenue over the next two years. [...]

Amid a debate on Capitol Hill over whether the U.S. needs to do more to encourage domestic oil production, North Dakota is charging ahead with expansion. The state industry was helped in no small part by efforts over the past several years to tap into a massive oil field known as the Bakken Shale deposit, where virtually all future expansion is happening [please see remarks below -- D.R.].

Production is expected to grow "substantially," Ron Ness, president of the North Dakota Petroleum Council, said. With 5,300 wells across the state and thousands more expected to come online, Ness projected that the state could reach up to 700,000 barrels a day by 2015.

North Dakota is the fourth-largest oil producing state in the U.S. behind California, Alaska and Texas [when output from the Federal Outer Continental Shelf/OCS is excluded from the total ranking -- D.R.], and Ness said California is in their "target zone." [Read more]

(Operators increased North Dakota's Bakken production from less than 3,000 bbl/d in 2005 to over 230,000 bbl/d in 2010. The Bakken's share of total North Dakota oil production rose from about 3 percent to about 75 percent over the same period---please see my post "United States: Oil Production From Shale Formations, 2005-2010," here. North Dakota produced an average of 307,000 barrels of crude oil per day in 2010 and comprised about 5.6 percent of the nation's total crude production---please see EIA data, here. For the U.S. crude oil production, please see also my post "U.S. Crude Oil Production, 1970-2010," here. North Dakota's crude oil production increased sharply in the late 1970s and peaked in 1984 at 144,000 barrels per day. Production declined through the late 1980s and early 1990s. After a small rise in 1995-97, production slowed again. Crude production dropped to 81,000 barrels per day in 2003. But since 2004, it has grown constantly to reach the above mentioned all-time peak of 307,000 barrels per day in 2010, surpassing the previous peak of 218,000 barrels per day in 2009. Also significantly, on a monthly basis, North Dakota's crude oil production rose from 138,000 barrels per day in January 2008, to 357,000 barrels per day in November 2010, before falling slightly to 344,000 barrels per day in December 2010. Update: North Dakota passed Alaska in March 2012 to become the second-leading state in crude oil production, trailing only Texas---please see my post "North Dakota Tops Alaska in Oil Production, Trailing Only Texas." -- D.R.)