EQT Corporation today announced the launch of a pilot program to begin converting drilling rigs to liquefied natural gas (LNG), displacing the diesel used to power equipment at the well site. This program marks the first LNG rig conversion in the Marcellus Shale and will provide a cleaner burning alternative fuel for the region’s drilling operations.
“We want to be a leader in reducing the environmental impacts related to drilling and we are proud to be the first operator in the Marcellus to launch such a program,” states Steve Schlotterbeck, President Exploration and Production for EQT. “Along with safety, protection of the environment is top-of-mind for our employees, contractors, and of course communities. We continually look for opportunities to improve our operations and displacing diesel, by introducing the use of alternatives such as LNG and field gas, is one way of doing so,” Schlotterbeck continued.
LNG is natural gas in its liquid form and from a physical property standpoint is as safe as, or safer than, using traditional fuels, such as propane or diesel. LNG, if exposed, evaporates quickly and leaves no residue on water or soil. Compared to diesel, natural gas emits between 20% and 30% less carbon dioxide and has a fraction of the emissions of nitrogen oxides, sulfur oxides, and particulates.
There are other LNG benefits, such as a reduction in fuel costs — with LNG being about 40% less expensive than diesel. The use of LNG also provides another means of reducing our dependence on foreign oil imports — with sourcing coming from various U.S. shale plays. The LNG being used for EQT’s pilot program is produced locally from Marcellus natural gas reserves.
EQT’s initial rig conversion is now operating in Northern West Virginia; and pending evaluation of the pilot program, the Company hopes to convert additional rigs in West Virginia and Pennsylvania.
- EQT Converts Shale Gas Drilling Rigs to LNG (environmentalleader.com)
- Natural-gas prices force down number of Marcellus drilling rigs (philly.com)
- Natural Gas: Where Endless Money Went to Die (mb50.wordpress.com)
Several US shale gas firms are cutting production because cheap prices have affected cost-effectiveness, reports say.
Chesapeake Energy, Statoil’s east-coast Marcellus Formation partner, is axing 900 million dollars-worth of investments in comparison to last year’s 3.1 billion. This equates to an eight percent production cut.
Statoil press spokesperson Bård Glad Pedersen says to Dagens Næringsliv the measure is, “consistent with an industry trend over the past year to move activity from areas with dry natural gas to those with wet gas and oil. This is partly due to lower gas prices.”
Chesapeake, the US’ next-largest gas producer, was the first company to decrease output. It has not ruled out further reductions if prices do not move in a positive direction.
Gas prices rose 15 percent over four days following investment and production cut reports by Occidental Petroleum, ConocoPhillips and Consol Energy. The increase follows a long period of falls of 28 percent.
Nevertheless, IHS consultant Mary Barcella tells The Financial times she believes prices will be around USD 3 per million British Thermal Units (BTUs) for the rest of 2012. This is the lowest for 10 years.
US gas industry expansion since 2008 has lead to prices falling 80 percent.
- Natural gas sector set up by Obama to be sabotaged? (mb50.wordpress.com)
- Shale gas the place to be (business.financialpost.com)
- Marcellus formation may hold less gas (goerie.com)
- Chesapeake: Report Finds No Major Influence from Gas Well Drilling on Drinking Water (USA) (mb50.wordpress.com)
- Is Anyone Still Drilling for Natural Gas? (dailyfinance.com)
Chevron Corporation announced a $32.7 billion capital and exploratory spending program for 2012.
Included in the 2012 program are $3 billion of planned expenditures by affiliates, which do not require cash outlays by Chevron.
Total investments for 2011 are estimated at $33 billion, reflecting approximately $28 billion in capital and exploratory expenditures and $4.5 billion for the acquisition of Atlas Energy, Inc., which closed earlier in the year.
“We continue to develop an unparalleled project queue,” said Chairman and CEO John Watson. “Our 2012 capital program covers a number of multi-year projects currently in the construction phase, including two world-class Australian LNG projects and multiple deepwater developments. We believe these investments will yield significant production growth and reward our shareholders for years to come. By 2017, we expect our net crude oil and natural gas production to grow about 20 percent to 3.3 million barrels per day. This growth profile, along with our current financial strength, supports our priority of continuously growing our dividends.”
Watson continued, “Our 2012 capital program includes spending of nearly $9 billion in the United States, with major new investments in the deepwater Gulf of Mexico, the Marcellus Shale in Pennsylvania and our refinery at Pascagoula, Mississippi. These projects are expected to result in new jobs and new sources of revenues for the communities where we operate. Our investments, both in the United States and elsewhere around the globe, help provide affordable new energy supplies to support a growing economy.”
- Chevron To Spend Record $32.7 Bln On Capital Projects in 2012 (gcaptain.com)
- Chevron’s $33 bln capital plan richer than view (marketwatch.com)
- USA: Chevron Strikes Oil in Deepwater Gulf of Mexico (mb50.wordpress.com)
- USA: ConocoPhillips Allocates USD 14 Billion for E&P in 2012 (mb50.wordpress.com)
- Chevron Throws the Brakes on Current and Future Drilling Offshore Brazil (mb50.wordpress.com)
- Chevron approves $29 billion Aussie LNG project (seattletimes.nwsource.com)
Shale gas enhancing energy supply, security
Whether you call it revolution or evolution, one thing is clear: Shale natural gas is producing jobs and economic benefits across the nation.
This week, shale gas was the focus of a major conference in Houston involving industry representatives, government officials and academics who gathered to discuss the technologies and future of this increasingly important source of energy.
For most of the nation, the contributions of shale gas may seem like a revolution. Shale gas has created thousands of new jobs, meant millions of dollars in new government revenues and enhanced energy security for America.
Of course, those of us who work in and around the energy industry understand that shale gas has been more of an evolution than a revolution.
The technologies used to develop these natural gas supplies aren’t new. Our industry began directional drilling in the 1920s, leading to substantial use of horizontal drilling in recent decades. And we have used the process of hydraulic fracturing since the 1940s. In that time, the industry has safely drilled more than a million wells.
The transformative impact of shale gas is challenging us all to think in new ways.
Not long ago many worried about a natural gas supply shortage in the U.S. But as President Obama recently stated, a “century’s worth … [lies] in the shale beneath our feet.” A decade ago gas from shale accounted for less than 2 percent of U.S. natural gas production. Today it is nearly 30 percent and growing.
As our nation considers this potential, we are reminded of the importance of reliable, affordable energy to our economy – especially during challenging economic times. Affordable supplies of natural gas – driven by the increase in shale production – have helped reinvigorate the domestic petrochemical industry, which relies on gas as a feedstock to make plastics and the other building blocks of modern manufacturing. These supplies are strengthening America’s steel industry, which is building new mills and hiring workers to support shale gas drilling. And areas where production of shale oil or natural gas is occurring are experiencing economic growth, job creation, and increased tax revenue.
For instance, in North Dakota, unconventional oil and gas production in the Bakken Shale has provided enormous economic benefits, with close to $5 billion in direct economic activity in 2009. In Texas, a study of the Barnett Shale formation near Fort Worth estimates it is now responsible for $11 billion in annual economic output and more than 100,000 jobs for the North Texas region. And in Pennsylvania, state labor statistics show 214,000 Marcellus Shale-related jobs at the beginning of 2011. Penn State researchers meanwhile calculate that Marcellus drilling could add nearly $10 billion in value to the Pennsylvania economy this year.
We also must not forget that hydraulic fracturing helps our nation reach our shared goals for responsible environmental stewardship. Natural gas produces about 50 percent fewer greenhouse gas emissions than coal when used to produce electricity for consumers and businesses, and significantly reduces other emissions such as mercury, sulfur and nitrogen oxide. It also uses a small fraction of the water used in coal, nuclear and solar power generation processes to produce a barrel of oil equivalent energy.
To ensure economic and environmental benefits continue, the people of the natural gas industry understand that we must remain firm in our commitment to properly manage the risks involved in drilling operations. That means meeting the highest standards of well design and well integrity. It means training our personnel and contractors to ensure adherence to established operating procedures. It means safely and efficiently handling the water and additives used to fracture wells. And it means working with state regulators to ensure protection of water and air quality.
The United States’ shale gas resources are an extraordinary energy endowment for our country, and our industry knows how to produce these resources safely and responsibly. We must keep these facts in mind as the public and policymakers discuss energy policies – and what increased access and technology mean for the energy industry.
With a commitment to operations integrity, wise development of our shale gas can provide new supplies of affordable, reliable energy in a safe, secure and environmentally responsible manner. And the rise of this resource comes at a time when our country – and the world – clearly needs the economic and environmental benefits that natural gas stands ready to deliver.
Mark W. Albers is a senior vice president at Exxon Mobil Corporation.
- Greece Investigates Shale Gas (mb50.wordpress.com)
- Natural gas shale play development now going global (mb50.wordpress.com)
- BHP to spend billions on US shale gas (news.theage.com.au)
The research was sponsored by a grant from the center, which is a legislative agency of the Pennsylvania General Assembly.
The Center for Rural Pennsylvania is a bipartisan, bicameral legislative agency that serves as a resource for rural policy within the Pennsylvania General Assembly, its website indicates.
According to the report, this research studied the water quality in private water wells in rural Pennsylvania before and after the drilling of nearby Marcellus Shale gas wells. It also documented “both the enforcement of existing regulations and the use of voluntary measures by homeowners to protect water supplies.”
In its introduction, the authors said they evaluated water sampled from 233 water wells near Marcellus gas wells in rural regions of Pennsylvania in 2010 and 2011.
“Among these were treatment sites (water wells sampled before and after gas well drilling nearby) and control sites (water wells sampled though no well drilling occurred nearby),” the study indicated. “Phase 1 of the research focused on 48 private water wells located within about 2,500 feet of a nearby Marcellus well pad, and Phase 2 focused on an additional 185 private water wells located within about 5,000 feet of a Marcellus well pad.”
During that phase, the researchers collected both pre- and post-drilling water well samples and analyzed them for water quality at various analytical labs. During Phase 2, the researchers or homeowners collected only post-drilling water well samples, which were then analyzed.
The post-drilling analyses were compared with existing records of pre-drilling water quality, which had been previously analyzed at state-accredited labs, from these wells.
“According to the study results, approximately 40 percent of the water wells failed at least one Safe Drinking Water Act water quality standard, most frequently for coliform bacteria, turbidity and manganese, before gas well drilling occurred,” the report indicated. “This existing pollution rate and the general characteristics of the water wells, such as depth and construction, in this study were similar to past studies of private water wells in Pennsylvania.”
The study’s pre-drilling results for dissolved methane showed its occurrence in about 20 percent of water wells—although levels were generally far below any advisory levels.
“Despite an abundance of water testing, many private water well owners had difficulty identifying pre-existing water quality problems in their water supply,” the report indicted. “The lack of awareness of pre-drilling water quality problems suggests that water well owners would benefit from unbiased and consistent educational programs that explain and answer questions related to complex water test reports.”
In this study, statistical analyses of post-drilling versus pre-drilling water “did not suggest major influences from gas well drilling or hydrofracturing (fracking) on nearby water wells, when considering changes in potential pollutants that are most prominent in drilling waste fluids.”
When comparing dissolved methane concentrations in the 48 water wells that were sampled both before and after drilling, the research found no statistically significant increases in methane levels after drilling—and no significant correlation to distance from drilling.
“However, the researchers suggest that more intensive research on the occurrence and sources of methane in water wells is needed,” the report indicated.
The report then cited the Pennsylvania Oil and Gas Act of 1984, which indicates that gas well operators are “presumed responsible” for pollution of water supplies within 1,000 feet of their gas well for six months after drilling is completed if no pre-drilling water samples were collected from the private water supply.
“This has resulted in extensive industry-sponsored pre-drilling testing of most water supplies within 1,000 feet of Marcellus drilling operations,” the report states. “However, the research found a rapid drop-off in testing beyond this distance, which is driven by both the lack of presumed responsibility of the industry and also the cost of testing for homeowners.”
The authors of the study said their research suggests that a standardized list of minimum required testing parameters should be required across all pre-drilling surveys to eliminate confusion among between water supply owners and water professionals.
The study indicates that this standardized list should include bromide. The research found that bromide levels in some water wells increased after drilling and/or fracking. These increases may suggest more subtle impacts to groundwater and the need for more research.
“Bromide increases appeared to be mostly related to the drilling process,” the study indicated.
Additionally, “a small number of water wells also appeared to be affected by disturbances due to drilling as evidenced by sediment and/or metals increases that were noticeable to the water supply owner and confirmed by water testing results.”
Increased bromide and sediment concentrations in water wells were observed within 3,000 feet of Marcellus gas well sites in this study, suggesting “that a 3,000 foot distance between the location of gas wells and nearby private water wells is a more reasonable distance for both presumed responsibility and certified mail notification related to Marcellus gas well drilling than the 1,000 feet that is currently required.”
On the regulatory side, “the research found that regulations requiring certified mail notification of water supply owners, chain-of-custody water sampling protocols, and the Pennsylvania Department of Environmental Protection’s investigation of water supply complaints were generally followed, with a few exceptions.”
The study also concluded that “since voluntary stipulations were not frequently implemented by private water well owners” that more educational and financial resources should be made available to facilitate testing.
The authors were clear: “This research was limited to the study of relatively short-term changes that might occur in water wells near Marcellus gas well sites. Additional monitoring at these sites or other longer-term studies will be needed to provide a more thorough examination of potential water quality problems related to Marcellus gas well drilling.”
- Environmental officials study instances of methane in wells near Marcellus Shale drilling operation (pennlive.com)
- Flowback from “fracking” Marcellus gas wells in PA has killed vegetation similar to West Virginia Study (pennlive.com)
- ‘Citizens Shale Commission’ weighs in on Marcellus policy (pennlive.com)
If 2008 was the Year of the Shales, 2011 is shaping up to be the Year of Liquids-Rich Plays–and there are still four months to go.
A major recurring theme in second-quarter conference calls was oil companies’ news of positions amassed or initial test wells drilled in new shale and unconventional fields containing oil and natural gas liquids.
Plays such as the Tuscaloosa Marine Shale, Mississippi Lime, Lower Smackover/Brown Dense and Utica shales–both in Ohio and to the west in Michigan–are lining up to be the emerging fields of 2012 and 2013, analysts said.
“We’ll see a movement in some of these plays and it’s not going to slow down–if anything, it will be a pretty tight market for services, fracturing crews and pipeline access,” Michael Bodino, head of energy research for Global Hunter Securities, said.
Arguably, the Utica Shale was the showpiece of the quarter, particularly because its cachet resembles that of Northwest Louisiana’s giant Haynesville Shale, which took Wall Street by storm when Chesapeake Energy trumpeted it in March 2008.
Chesapeake again took the lead in showcasing the Utica late last month, relating the news that the play economically “looks similar, but is likely superior to the Eagle Ford Shale in South Texas…because of the quality of the rock and location of the asset” near eastern US population centers, CEO Aubrey McClendon said.
Like the Eagle Ford, which stands out as one of the US’ most sizzling shale plays at present, the Utica has oil and “dry” natural gas and “wet gas” (gas liquids) windows, he said.
Jeff Ventura, chief operating officer at Range Resources, which pioneered the Marcellus Shale in Pennsylvania, said his company already has drilled two Utica wells. At least on its acreage, Utica is at the bottom of a pancake stack of three play zones, with the Upper Devonian Shale on top and the Marcellus in the middle. The Upper Devonian shales contain about as much gas in place as the Marcellus zone, Ventura said, adding that the Marcellus gas field has been called one of the US’ largest.
Both Range and Chesapeake also have scored success in Northern Oklahoma’s Mississippi Lime play. “In the past year it has become more clear that we have a major play on our hands,” said McClendon, with Chesapeake holding 1.1 million acres there, running six rigs, aiming for 10 rigs by year-end and 30 to 40 by end-2014 or 2015.
Range’s Ventura suggested the play, found at relatively shallow depths of 5,000-6,000 feet, is also highly profitable; it boasts a 100% rate of return at $100/b oil, and he added that even at $90/b it yields a roughly 80% return. Range, which has completed seven horizontal wells, sees its main near-term activity there as nailing the optimal lateral length and well spacing.
Ventura said liquids make up 70% of a well’s recoverable hydrocarbons. McClendon estimated 415,000 barrels of oil equivalent per well, at an average finding cost to date of roughly $11/b, which he called “very, very attractive results.”
Meanwhile, in its late July conference call, Southwestern Energy CEO Steven Mueller said his company has acquired 460,000 net acres in an unconventional horizontal play targeting the Lower Smackover Brown Dense formation.
“This happens to be almost the exact same number of acres we had when we announced the Fayetteville Shale play back in August 2004,” Mueller said. That news kicked off an industry rush to that gas play, Mueller said.
But having reviewed the results of more than 70 wells that penetrated the Brown Dense zone, “we currently have more data about [it] than we had on the Fayetteville Shale when it was announced,” he said.
Mueller said the Brown Dense is an oil reservoir in Northern Louisiana and Southern Arkansas, at 8,000-11,000 foot depths and below the Haynesville Shale which is also a gas play. Brown Dense is “extensive over a large area and ranges in thickness from 300 to 530 feet,” he said.
Southwestern plans its first Smackover/Brown Dense well in Columbia County Arkansas, before the end of September, with a second well later in the year in Claiborne Parish, Louisiana.
In addition, Goodrich Petroleum in early August said it had begun drilling the Buda Lime, beneath the Eagle Ford. The small company averaged a respectable 900 boe/d oil from those wells, against 800 boe/d from its 11 Eagle Ford wells so far.
Rob Turnham, Goodrich chief operating officer, also touted the Tuscaloosa Marine Shale, along the horizontal Mississippi-Louisiana border, where both Encana and Devon Energy have large positions and are drilling wells. Tuscaloosa “has a lot of similarities to the Eagle Ford–similar permeability and porosity” of the rocks, he said. Goodrich will begin drilling in early 2012.
He said nine older wells in the play have flowed oil but “none of them have been properly stimulated.” If the vertical wells were to be taken horizontally several thousand feet, fractured with current technology, and properly stimulated, “we’re very optimistic,” said Turnham.–Starr Spencer in Houston
Bernard L. Weinstein
Over the past three years, we have seen a dramatic rebound in America’s oil and natural gas production after a hiatus of almost 40 years. This has occurred despite falling output in Alaska, the moratorium on deep-water drilling imposed in the wake of the Gulf of Mexico oil rig blowout last year, and extremely low prices for natural gas.
New technologies for extracting oil and gas from deep under the ocean floor as well as shale formations have been largely responsible for the country’s fossil fuel renaissance.
All this is good news for America’s consumers. Though gasoline and diesel prices have jumped 30 percent over the past year, absent the 11 percent increase in oil production from U.S. fields consumers might be paying even more.
At the same time, falling imports chopped about $20 billion off America’s import bill last year. Abundant new supplies of natural gas at low cost have reduced the home heating and electric bills for millions of American households.
In a sluggish economy, energy producing states like Texas, Oklahoma, Arkansas and Louisiana are benefiting from the job and income growth associated with the resurgent energy sector.
Each of these states currently posts unemployment rates below the U.S. average of 9.1 percent and each has posted job gains over the past year, led by the energy sector.
According to a recently-released study by Quest Offshore Resources, drilling and production in the Gulf of Mexico currently support about 182,000 jobs in Texas, Louisiana, Mississippi and Alabama — a number that would have been even higher in the absence of the deep-water moratorium. Should drilling permits return to their pre-Macondo pace, by 2013 Gulf of Mexico operations could support 320,000 jobs in these states.
Non-energy states are also benefiting from the nation’s fossil fuel revival. According to the American Petroleum Institute, 9.2 million jobs across the county can be attributed directly and indirectly to spending by the oil and gas industry.
Developing oil and gas resources currently off-limits in the Outer Continental Shelf (OCS), Alaska and the Rockies could create another 160,000 jobs by 2030 while expanding production in the Marcellus Shale and Canadian oil sands could add a further 620,000 over the next 20 years.
President Obama can help create these jobs by dropping his perennial call for higher taxes on U.S. oil and gas producers. These companies already fight an uphill battle against foreign firms who receive sweetheart tax and regulatory deals from their home governments.
Second, the OCS and other areas currently off-limits but rich in fossil fuels should be opened for environmentally-responsible exploration, drilling and production. Finally, the proposed Keystone XL pipeline that will bring oil from Alberta to refineries on the Gulf Coast should be approved without further delay.
The Energy Information Agency believes more than 59 billion barrels of recoverable oil reside in U.S. offshore waters. The U.S. Geological Survey recently estimated total recoverable oil reserves in North Dakota, home to the Bakken Formation, at four billion barrels.
Alaska, California, Pennsylvania, New York and Texas also possess great potential for additional oil and gas recovery, if only we have the political will.
Investing in North America’s energy resources, especially oil and gas, can revive our economy, lessen our dependence on imports, and increase our national security. But the current energy boom will only become sustainable if public policy becomes accommodating rather than inhibiting.
Congresswoman Michele Bachmann recently promised $2/gallon gas at one of her campaign functions, and a researcher affiliated with NASA reported that aliens may destroy humanity to save the planet. Which statement is farther off the wall? Let’s set the stage with the facts.
Last week, the Obama administration found itself in a legal battle with Exxon over the largest find in the company’s history, a field of over 1 billion barrels off the coast of Louisiana. This represents 5% of total U.S. oil reserves and there’s supposed to be a lot more out there. The Marcellus Shale field in New York, Pennsylvania, Ohio, and Maryland contains between 160 and 500 trillion cubic feet of natural gas. Out in North Dakota, Montana, and Saskatchewan, the Bakken deposit is estimated to contain from 10-40 billion barrels of oil equivalent according to industry experts. This doesn’t include large deposits in Colorado, Wyoming, and elsewhere. Even if Bakken comes in at the low end it, represents another 40-50% increase in onshore American oil reserves.
In the meantime, the oil companies drilling in the Gulf of Mexico are still reporting incredible delays in re-opening even the inshore oil rigs. Offshore fields have become almost impossible to develop despite the incredible size of some of these discoveries. The government shut down even the inshore oil fields in the Gulf after the Deepwater Horizon disaster last year. The Department of the Interior just announced the first auction of oil leases since the Deepwater Horizon tragedy in April of last year, to be held in December. The Gulf provides 29% of America’s oil and 13% of our natural gas.
A report released in July by LA Senator David Vitter noted the departure of 10 deep-water rigs, the imminent departure of several more, and the diversion of 8 more since the moratorium was declared in May 2010. Each of these projects ranged from hundreds of millions to billions of dollars in investment. Many of those rigs are on their way to the vast 50- to 80-billion-bbl Lula oil field off the Brazilian coast. It is interesting to note that the Export-Import Bank is loaning $10 billion to Petrobras, the Brazilian oil company, to invest in their offshore oil industry. Funny timing.
The administration has also done its best to stall drilling both on the North Slope and in the Cook Inlet in Alaska. While talking about exploration, new pipelines, and improved practices, the reality is that every roadblock possible is being placed in the way of increased production. Last year, Fenton Associates, the public relations agency for many environmental groups, boasted that they had shut down drilling in Alaska.
“Drill, baby, Drill” has been replaced by “Chill, baby, Chill.”
While having approved several nuclear power projects, all of them additional reactors at existing sites, the government has adroitly avoided offering the necessary licensing guarantees necessary to obtain funding to build them. Another catch-22 engineered by the bureaucracy.
Ezra Klein in the Washington Post reports that the EPA is moving forward with its plans to shutter 20% of the nation’s coal-fired power plants. While many are grandfathered in, the power will still go offline starting in the next 18 months. The president has clearly stated on the record that he wants to put the coal industry out of business.
The real battle is being fought under the radar. The administration is using regulatory power and permitting to choke off conventional power. Last year, I sat in a packed conference center at China’s largest solar power conference as I listened to one of Europe’s leading solar power executives state that the industry needed to work to make conventional power so expensive that alternative energy sources can compete. This has been a part of the plan all along and the current administration seems to be working along those lines.
This is economic and engineering Luddism at its worst. After the farce of the carbon offset scam and many of the issues facing the industry, administrators, systems operators, and users would be well-advised to look upon many alternative energy technology providers with a gimlet eye. Objectivity is critical to the long-term health of the energy industry.
Let’s look at the alternatives. Test data on solar modules indicates a failure rate of between 3-7% within seven years of installation. Failures of inverters are exceeding 10%. None of this data is reflected in the current economic models for solar power. The assumption is 25 years, but there is very limited data. The business model for solar panels is becoming ever more challenging with rising materials costs globally and that of labor in China. In North America Solyndra has gone through over $535 million in government funding and is on the edge. Evergreen Solar, another poster child for solar power in this country, filed for bankruptcy last week.
Globally, the solar module industry will install 11-12 gigawatts of power this year, or the equivalent of 4-5 nuclear power plants. This certainly does not keep up with demand. As Germany and Japan have announced the phase-out of nuclear power, the great mystery is how it will be replaced.
As GM, Nissan, Toyota, and other car companies have ramped up production of electric vehicles, General Motors reported that the company had sold only 125 Chevy Volts in July. Costco announced that the company was removing electric vehicle charging stations from most of its locations because the stations are never used.
Wind power has received a lot of press, but even there, the largest project planned for the country was canceled because of obstruction and a poor financial outlook. Wind power is subsidized at up to 10 times the cost of conventional energy and is unpredictable. In studies of the over 6,000 turbines in Denmark, it has been found that without heavy subsidies, wind power would rapidly fail. Germany and Spain have withdrawn subsidies for wind power installations not because the industry has grown more viable, but rather because the difficulties and costs associated with this source of power outweigh the benefits.
And yet nowhere have I seen a coherent and objective study of the energy needs and policy of the United States, the world’s largest consumer. As American consumption of energy stands at 27,000 terawatts, with $85-bbl oil, an economy on the verge of recession, and significant capacity going offline, it would be nice to have a policy that is not based upon smoke and mirrors, or even some kind of sensible policy at all.
Maybe Congresswoman Bachmann isn’t so crazy after all. Judge for yourself. In the meantime I’ll be watching the skies for alien invaders.