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First Solar, Inc and PT. Pembangkitan Jawa Bali Services Â of Indonesia today signed a memorandum of understanding (MOU) to collaborate on the delivery of 100 megawatts (MW) of utility-scale solar power plants in Indonesia in order to address the growing energy demand in the country.
“Indonesia has an increasingly urgent need for reliable, cost-effective energy resources. The agreement with PJB Services facilitates an ideal collaboration to provide Indonesia with the needed solution,” said Won Park, First Solar’s Senior Manager of Business Development and Sales in Southeast Asia.
This MOU underscores First Solar’s belief that the Indonesian market has great potential as a sustainable market where solar power can be a meaningful part of the energy mix.
The MOU is the first for First Solar in Indonesia and one of several related to the company’s strategy of forging strategic alliances in fast-growing, sustainable energy markets worldwide. The MOU also represents the first foray into the development of utility-scale solar photovoltaic power plants for PJB Services, a leading provider of services for the operation and maintenance of conventional power plants in Indonesia, whose parent company is PJB, a subsidiary of Perusahaan Listrik Negara (PLN).
The MOU represents an initial step in the collaboration between the two companies toward the development, engineering, procurement, construction, operation and maintenance of an approximately 100 MW pipeline for solar PV power plants, including PV hybrid solutions, using First Solar’s advanced thin-film PV modules and related system services and components.
“We are excited by the opportunity to collaborate with a world leader in solar energy for the development of utility-scale PV power plants in Indonesia,” said Bernadus Sudarmanta, President of PJB Services. “Solar PV electricity can help Indonesia meet its fast-growing power needs while reducing its dependence on fossil fuels.”
About First Solar, Inc.
First Solar is a leading global provider of comprehensive photovoltaic (PV) solar systems which use its advanced thin-film modules. The company’s integrated power plant solutions deliver an economically attractive alternative to fossil-fuel electricity generation today. From raw material sourcing through end-of-life module collection and recycling, First Solar’s renewable energy systems protect and enhance the environment. For more information about First Solar, please visit www.firstsolar.com.
For First Solar Investors
This release contains forward-looking statements which are made pursuant to the safe harbor provisions of Section 21E of the Securities Exchange Act of 1934. The forward-looking statements in this release do not constitute guarantees of future performance. Those statements involve a number of factors that could cause actual results to differ materially, including risks associated with the company’s business involving the company’s products, their development and distribution, economic and competitive factors and the company’s key strategic relationships and other risks detailed in the company’s filings with the Securities and Exchange Commission. First Solar assumes no obligation to update any forward-looking information contained in this press release or with respect to the announcements described herein.
About PJB Services
PT PJB Services is a subsidiary of PT. Pembangkitan Jawa Bali, a subsidiary of PLN, which was established to answer the need for additional line-up businesses in the areas of power plant operations and maintenance. PT PJB Services was established on March 31, 2001 with 95% shareholding owned by PT PJB and 5% owned by the Foundation for Education and Welfare of PT PJB. PT PJB Services initially focused only on the field of plant maintenance only. PT PJB Services has developed the ability to be a company engaged in the operation and maintenance of power plants. The company is currently represented in Indonesia, Singapore, Malaysia, Kuwait, China and Saudi Arabia. http://www.pjbservices.com/
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This story was co-published with The Financial Times and Propublica
When Gunvor, one of the world’s largest energy traders, invested $400 million in a troubled Montana coal mine, it looked like a promising deal. The plan was to sell much of the coal to the booming Asian market, where it was fetching far more than the prevailing price in the U.S.
The deal in October 2011 delivered impressive profits to the mine’s previous owners, a rare financial success in America’s depressed coal industry. It also set the mine on course to more than double production this year compared with last, at a time when total U.S. coal production is falling.
But shipping coal to the Asia Pacific region was not as straightforward as it seemed. Gunvor expanded from its core of trading oil into other energy sectors just as the price of coal in the U.S., Asia and elsewhere tumbled in part because U.S. power plants are burning cheaper natural gas. Now, the Geneva-based company is battling unexpected economic, political and legal headwinds in the U.S.
Gunvor and the two other owners of the Montana mine, called Signal Peak, are embroiled in a legal dispute over royalty payments. The mine has also bid on federal and state coal tracts, thrusting Gunvor into a debate raging in America over whether governments are getting a fair price for U.S. coal reserves.
Industry experts say Gunvor bought the mine at the height of the market. “The timing of the deal was terrible,” said a senior coal trader with a rival trading house. “They overpaid.”
In a statement last month, Gunvor defended “Signal Peak’s longterm value,” noting both the quality of the coal and the quantity â€” enough for the mine to keep producing for roughly 30 years.
One of the trading house’s two principal owners is Gennady Timchenko, a billionaire who has known Russian President Vladimir Putin since both men were based in St. Petersburg in the 1980s. Gunvor grew rapidly from a niche player in the Russian oil markets in the early 2000s to one of the largest global trading firms, reporting sales of more than $80 billion last year. Privately held Gunvor does not disclose profits, but trading houses generally have low margins.
A big beneficiary of the Gunvor investment has been FirstEnergy, the utility based in Ohio, which had owned half the Signal Peak mine with privately held Boich Companies, also based in Ohio. Each company sold a percentage of its stake to Gunvor so that the three now are equal owners. FirstEnergy’s public filings show its gains from the sale to Gunvor: It acquired the mine for $133.5 million in 2008. With its sale to Gunvor, it booked a pre-tax profit of $569 million and $260 million in cash.
The price for U.S. thermal coal â€” the kind produced at Signal Peak and other mines in the Powder River Basin in the western U.S. â€” has slumped in key Asian countries. Federal energy agency data show China’s price per ton of U.S. thermal coal in the first quarter of 2012 plunged to $56 from $121 in the first quarter of 2011.
Gunvor became an equal partner with FirstEnergy and Boich by paying $400 million for its third of the mine. Each must approve the hiring of key mining executives, can veto major financial transactions and is a co-guarantor on a credit extension, public filings show.
Such details can determine whether the Committee on Foreign Investment in the United States, or CFIUS, reviews a deal. The federal panel, which examines the security implications of foreign investment in the U.S., considers factors including whether a foreigner has control over financial or managerial decisions. The government has broad powers to initiate a review and in the past has interpreted “control” to mean less than 50 percent ownership. In this case, the deal has not been reviewed, said FirstEnergy spokeswoman Tricia Ingraham. “The parties did not believe the deal rose to the level of requiring it,” she said.
The U.S. government has considerable flexibility in determining the kinds of deal meriting CFIUS review, according to lawyers who handle such cases. Some previous acquisitions of coal assets by foreigners, including one involving a Russian entity, have gone through the CFIUS process.
Gunvor inked “a substantial coal purchase agreement” in the deal, according to a statement by the firm’s lawyers, and the mine has increased production. Signal Peak produced 3.82 million tons in the first quarter of 2012, compared to just 4.66 million tons in all of 2011, according to the U.S. federal mine data.
Gunvorâ€™s purchase agreement with Signal Peak has riled former owners of the mine, who sold it to FirstEnergy and Boich and have been reaping royalties from coal sold from the mine since then. Those owners have filed suit in federal court to argue the fairness of the set price used to calculate their royalties.
The royalty holders claim the Signal Peak price should be based on an arm’s length transaction. They contend the current owners have used insider transactions, which artificially lower the sale price and reduce the royalties. The current owners have filed for dismissal of the suit.
Gunvor’s lawyers argue the claims are baseless in part because the company has “an extremely remote connection at best” to the litigation. Gunvor, they say, “has never and does not presently conduct business in the State of Montana.” Gunvor purchased Signal Peak through an American subsidiary.
Signal Peak is pushing ahead with expansion plans, which has also made it part of an industry-wide debate over the price at which the government sells coal. Signal Peak recently paid $10.5 million to the federal Bureau of Land Management for the right to lease a nearby tract containing 31.75 million tons of coal. Critics have argued against the lease, complaining the price was too low given the likely export of the coal.
by Lena Groeger ProPublica
Last week several  media  outlets  obtained the federal Bureau of Land Management’s draft of proposed rules  requiring fracking companies to disclose the chemicals they pump into the ground. Such disclosure requirements have been championed by environmentalists for years and were endorsed by President Obama in the State of the Union, but critics say the rules may not go far enough.
In the process of fracking, or hydraulic fracturing, millions of gallons of highly pressurized water, mixed with sand and other chemicals, are injected into the ground to extract natural gas from rock. As we’ve noted before, some of these chemicals are toxic to humans  and have contaminated nearby groundwater . Some energy companies have voluntarily made their chemical information public , but others have fought to keep them secret.
InsideClimate notes  that the proposed national rules would specifically require companies to give both the names and concentrations  of individual chemicals used. So far, Colorado is the only state that requires such detailed information for all chemicals; eight other states with fracking disclosure rules either do not require companies to report concentrations or only require them to report concentrations of hazardous materials. The BLM’s rules also would compel companies to report the total volume of fracking fluid used, as well as how they intend to recover and dispose of it .
Though the BLM’s proposed rules are more stringent than most state laws, environmental and health advocates say drillers could circumvent some of the requirements. For instance, the rules would only apply to drilling on federal lands. Also, companies could request that certain chemicals be exempted from disclosure if they are deemed a “trade secret.” The trade secret exemptions “could potentially make the rules meaningless if applied broadly,” Dusty Horwitt , senior counsel at a public health advocacy group told InsideClimate .
While the BLM’s proposal states that all the non-exempted information would “become a matter of public record,” it makes no mention of how or where the disclosure information would appear — or how it would be made available to the public.
To compare the BLM’s draft rules with state disclosure provisions, take a look at the table here  (which we’ve recreated from a chart by InsideClimate ). You can also read the full draft legislation here .
by Joaquin Sapien
New York’s emerging plan to regulate natural gas drilling in the gas-rich Marcellus Shale needs to go further to safeguard drinking water, environmentally sensitive areas and gas industry workers, the U.S. Environmental Protection Agency has informed state officials.
The EPA’s comments, in a series of letters this week to the state’s Department of Environmental Conservation, are significant because they suggest the agency will be watching closely as states in the Northeast and Midwest embrace new drilling technologies to tap vast reserves of shale gas.
New York is in the forefront of the shale gas boom and has been working on regulations for more than three years. Judith Enck, the EPA regional administrator who issued the agency comments, noted that New York “will help set the pace for improved safeguards across the country.”
The EPA’s comments are among 20,000 the state has received on its proposed plan to regulate the environmental effects of drilling. Many of the EPA’s comments focus on how the state DEC will handle the chemically tainted wastewater from the drilling process known as hydraulic fracturing, or fracking.
To free the gas trapped in the Marcellus and other shale formations, drillers pump millions of gallons of water mixed with sand and chemicals deep underground under pressure. The wastewater can get into drinking water by being disposed of at sewage treatment plants, the EPA wrote.
As ProPublica first reported in 2009, these plants don’t typically have the equipment necessary to detect and treat the chemicals in drilling wastewater. Plant operators who accept drilling wastewater simply dilute it with regular sewage and then discharge it into water bodies. DEC wastewater samples had levels of radioactive elements thousands of times higher than drinking water limits, ProPublica reported.
In its comments, the EPA pointed out that New York’s current permitting system for water treatment plants doesn’t include limits on pollutants frequently contained in drilling wastewater, such as radionuclides, which can cause cancer at high levels.
The EPA said it needs to be more closely involved in analyzing and approving any treatment plant’s application to accept drilling wastewater. And while the DEC’s proposed rules suggest limits on radioactive elements such as radium, the EPA said it’s not clear who would be “responsible for addressing the potential health and safety issues” related to radiation exposure.
The EPA also flagged health risks to workers close to wastewater and other potentially radioactive materials, like the large amounts of soil and mud unearthed by drilling. “At a minimum, the human health risks to the site workers from radon and its decay products should be assessed along with the associated treatment technologies such as aeration systems or holding for decay,” the agency wrote.
The EPA raised concerns about the sheer amount of wastewater. To deal with the excess water, the DEC listed a number of out-of-state treatment plants as potential recipients, but the EPA warned that several of the plants probably don’t have the capacity to handle more wastewater.
ProPublica reported that neighboring Pennsylvania became overwhelmed by drilling wastewater after the state embraced the industry. The Monongahela River, which provides drinking water to 350,000 people, became contaminated with drilling salts and minerals.
The EPA letters are the latest in a series of federal moves to tighten oversight of gas drilling. In December, the agency scientifically linked underground water pollution to hydraulic fracturing for the first time. Last August, the EPA announced that it would develop its own rules on wastewater disposal instead of leaving it up to states.
Industry and green groups have split over the DEC’s proposed regulations, with drillers saying they are too restrictive and environmentalists contending they don’t go far enough. Meantime, the EPA has launched a comprehensive review of the environmental impacts of hydrofracking.
In August, DEC Commissioner Joe Martens told ProPublica that he didn’t think there would be much to learn from the EPA study and that the state was far ahead of the federal agency in its response to drilling.
by Nicholas Kusnetz
ProPublica. Reprinted with Permission
Early last year, deep in the forests of northern British Columbia, workers for Apache Corp. performed what the company proclaimed was the biggest hydraulic fracturing operation ever.
The project used 259 million gallons of water and 50,000 tons of sand to frack 16 gas wells side by side. It was “nearly four times larger than any project of its nature in North America,” Apache boasted.
As furious debate over fracking continues in the United States, it is instructive to look at how a similar gas boom is unfolding for our neighbor to the north.
To a large extent, the same themes have emerged as Canada struggles to balance the economic benefits drilling has brought with the reports of water contamination and air pollution that have accompanied them.
The Canadian boom has differed in one regard: The western provinces’ exuberant embrace of large-scale fracking offers a vision of what could happen elsewhere if governments clear away at least some of the regulatory hurdles to growth.
Even as some officials have questioned the wisdom of doing so, Alberta and British Columbia have dueled to draw investment by offering financial incentives and loosening rules. The result has been some of the most intensive drilling anywhere.
“There definitely is concern on the part of people living in northeast B.C. on the scale of developments, which are quite significant already and are only in their infancy,”said Ben Parfitt, an analyst with the Canadian Centre for Policy Alternatives, a research institute that promotes environmental sustainability. “We are seeing some of the largest fracking operations anywhere on earth.”
Canada’s eastern regions have proceeded more cautiously. In March, Quebec placed a moratorium on shale development  pending further study. Protesters have taken to the streets in New Brunswick  demanding the same.
Public opposition, coupled with low gas prices, has slowed drilling over the past year. Still, the Canadian Association of Petroleum Producers expects production from shale and other unconventional sources to more than triple in the next decade.
The industry’s aggressive plan for growth has drawn an ambivalent response from the nation’s top environmental officials.
In March, Canada’s deputy minister of the environment sent an internal memo warning that more work was needed to assess the risks from shale gas drilling . The memo, obtained by an Ottawa-based newspaper and addressed to Environment Minister Peter Kent, said water use and contamination top a list of environmental concerns including air pollution, greenhouse gas emissions and the use of unknown toxic chemicals. Kent subsequently ordered two studies looking at the safety and environmental impacts of shale drilling.
Yet, in a written response to questions from ProPublica, the environment ministry affirmed its commitment to continued development.
“Our Government believes shale gas is an important strategic resource that could provide numerous economic benefits to Canada,” the ministry’s statement said. Gas is an important part of a clean energy future, the ministry added, saying that “a healthy environment and a strong economy go hand in hand.”
B.C., Alberta Lure Drillers
Canada’s current drilling boom dates to the late 1990s, when Encana began using fracking to extract gas from dense rock in northern British Columbia.
The second-largest gas driller in North America, Encana also started fracking shallow coal seams, or coalbed methane, in Alberta in the early 2000s, using nitrogen rather than water to free the gas. Coalbed methane drilling generally requires less fluid than fracking shale but occurs much closer to drinking water. In some cases, Encana and other companies have drilled wells directly into aquifers, injecting fracking fluids into groundwater suitable for drinking.
In the middle of the last decade, Encana and other operators started exploring northern British Columbia’s shale gas reserves. The formations were promising, holding at least 200 trillion cubic feet of gas, according to industry estimates.
But drillers faced formidable hurdles to get to it. Unlike the Barnett and Marcellus shales in the U.S., Canada’s best shale basins are far from most markets and existing infrastructure. Soggy ground slows drilling in the spring and summer, and the average high temperature hovers around zero degrees Fahrenheit in January.
To encourage development, British Columbia enacted a series of incentives, including reduced royalties for deep drilling and credits for building roads and pipelines in the remote regions.
These changes, combined with the area’s severe conditions, spurred companies to concentrate and scale up their operations in British Columbia in an effort to cut costs, industry experts say. The result: a string of record-breaking fracks.
In a written response to questions from ProPublica, Apache said this approach reduces surface disturbance. It also can heighten the risk of air and water pollution, said Bruce Kramer, an expert in oil and gas law with McGinnis, Lochridge and Kilgore, a Texas-based law firm.
In both western provinces, the regional authorities responsible for regulating drilling have passed rules to allow more intensive drilling.
In Alberta, drillers can now pack wells closer together and pump more water out of shallow coal seams to free gas more efficiently. British Columbia issued detailed regulations last year that limit where and when companies can drill and set rigorous environmental standards but also gave its Oil and Gas Commission the authority to exempt drillers from virtually all of these provisions.
The commission referred an inquiry from ProPublica to its parent organization, the Ministry of Energy and Mines. In written responses to questions, the Ministry said the new regulations adequately address environmental concerns over drilling activity in the province. Pointing to an upcoming health study and new rules that compel companies to disclose chemicals used in fracking, officials said they would continue to review and revise standards as necessary.
Still, the regulatory shifts have prompted environmental advocates in Alberta and British Columbia to question whether officials are prepared to cope with rising concerns about water use, contamination and unchecked development.
“We just don’t have a clue how big this issue is from a public policy perspective,”said Bob Simpson, a member of British Columbia’s legislative assembly and an outspoken critic. “We really don’t know what we’re doing.”
Jessica Ernst’s Water Problems
Over the last five years, there have been several prominent cases in which Alberta residents have said gas drilling contaminated their water.
There are no hard numbers. The government does not track such complaints. But in some instances, residents’ frustration has been exacerbated by their sense that regulators have not properly investigated their claims.
In 2005, Jessica Ernst noticed strange things happening to her water. The toilet fizzed. The faucets whistled. Black particles clogged her filter. Then she began getting rashes.
Ernst, a longtime environmental consultant for oil and gas companies, wondered whether the changes could be connected to drilling nearby. Encana had been drilling shallow coalbed methane wells near her home outside of Rosebud, about 50 miles northeast of Calgary.
She asked Alberta Environment and Water, the agency that oversees groundwater, to test her well. When the well was drilled in 1986, tests showed it had no methane . The new tests, however, showed high levels of the gas, as well as a hydrocarbon called F2 and two other chemicals.
But in 2007, a government research agency concluded it was unlikely that drilling had affected her water . The final report said the chemicals found were not typically used in coalbed methane drilling, and that one had probably come from a plastic tube used to test the water.
Ernst wasn’t satisfied with the province’s response, however. The government’s report concluded that the methane in her well might be occurring naturally because tests showed similar levels of gas in nearby wells. But the tests were conducted after Ernst noticed the changes in her water — she saw the results as an indication that the contamination might be more widespread.
The government’s report also ignored evidence provided by one of its own analysts, a professor of geochemistry at the University of Alberta. When Karlis Muehlenbachs analyzed the gas in Ernst’s well for Alberta Environment and Water, he found ethane, a gas often found with methane, with a chemical signature indicating that it had come from deep underground, below the depth of the well.Â Muehlenbachs told ProPublica that the ethane’s signature meant that it could not have been there naturally. He said he is convinced that it resulted from drilling.
As Ernst searched for answers to what happened to her water, she unearthed evidence of other problems related to drilling. She found an Alberta Environment and Water report that listed cases in which the fracking of shallow wells resulted in gas or fluid leaking  into nearby gas wells or spraying into the air. She also found government gas well records that said Encana had fracked into the aquifer that supplies her water well.
“The community was used as a test tube,”she said. “I was used as a test tube.”
Earlier this year, Ernst sued Encana, Alberta Environment and Water and the Alberta Energy Resources Conservation Board , which regulates drilling, alleging that Encana’s drilling was negligent and that the government agencies had covered up the company’s contamination and failed to enforce regulations.
Ernst, who is asking for about $33 million Canadian in damages and return of wrongful profits, has vowed she will not accept a settlement that includes a confidentiality agreement, as others have done.
“Somebody has to do this,”she said.
Alan Boras, a spokesman for Encana, said the company would not comment on the case.
The Energy Resources Conservation Board denied a request for an interview. In written responses to questions, spokesman Bob Curran said he could not comment on the specifics of Ernst’s case, but the agency is confident it has conducted itself appropriately.
Carrie Sancartier, a spokeswoman for Alberta Environment and Water, would not comment on Ernst’s allegations because of the lawsuit but said there have been no confirmed cases of gas drilling contaminating water wells in the province.
Muehlenbachs, whose work has been used in several government investigations, said that is “simply false.” He said he’s analyzed thousands of cases of gas leaking up well bores and knows of at least a dozen cases of water contamination.
Alberta has introduced several measures to safeguard water from shallow drilling. In 2006, it established a buffer zone between shallow gas wells and water wells  and required drillers to test nearby water wells before drilling into an aquifer .
Nevertheless, last January, as part of a review of drilling regulations, the Energy Resources Conservation Board  said shallow fracking poses a risk to groundwater.
Is ‘Communication’ a Risk?
There have been no reports of groundwater contamination related to new drilling in British Columbia.
Increasingly, however, there are reports of something called “communication” –Â events in which a fracture travels through the ground and connects two gas wells.
Ken Paulson, chief engineer at the province’s Oil and Gas Commission, said these events do not pose a contamination risk. Other experts say their principal impact is to undermine production.
But opponents of expanded shale drilling say instances of communication show that drillers lack a full understanding of what happens when wells are fracked closer together, increasing the risk of contamination. Anthony Ingraffea, an engineering professor at Cornell University, said that if a fracture hit a natural fault, it could allow contaminants to enter aquifers.
Communication has occurred in the U.S. as well: Regulators in Texas, Oklahoma, Michigan and Pennsylvania reported such events to Canadian officials as part of the Energy Resources Conservation Board’s regulatory review .
Documents provided to ProPublica show that energy companies have reported 25 cases of communication in British Columbia  since 2009. Companies are not required to report such events, so the list isn’t comprehensive, Paulson said.
In May 2010, the province’s Oil and Gas Commission issued a warning when a drilling company inadvertently shot sand from one fracking job into another well  being drilled more than 2,000 feet away.
The advisory said the operator contained the resulting jump in pressure within the well but warned of a “potential safety hazard.” When communication occurs, Paulson said, the biggest concern is that an operator could lose control of a well and cause a blowout.
Concerns Over Water Consumption
As the debate over communication continues, Parfitt and other Canadian environmentalists have raised more immediate concerns about water use. Fracking requires lots of water — on their biggest reported fracking job, Apache and Encana used an average of 28 million gallons of water per well.
While the oil and gas industry says it is responsible for 1 percent or less of British Columbia’s overall water use, environmental advocates say that may not reflect the full extent of the industry’s consumption or long-term needs.
Drillers use both surface and groundwater. Access to surface water is regulated by two agencies that issue long-term licenses or year-long permits. Overwhelmingly, energy companies have chosen to obtain permits, which require less regulatory review.
Most groundwater withdrawals aren’t regulated at all. Drillers need permits to sink water wells, but there are no limits on the amount of water that can be taken from them. They can also purchase water from other well owners, so there’s no way to track overall use.
“How much water is actually being used and, more importantly, how much water is projected to be used over next the 10 to 15 years? Because of the scattershot approach of regulation, this isn’t something we can actually answer right now,”said Matt Horne, acting director of the climate change program at the Pembina Institute, an environmental think tank that published a report on the gas industry’s water use.
Last year, in a report focusing on province-wide groundwater oversight, British Columbia’s auditor general  said the province was not adequately protecting aquifers from overuse and potential contamination. Agencies lacked the basic data necessary to assess the risks, such as the number and extent of the province’s aquifers, the report said.
The Ministry of Energy and Mines, in a written response to questions, said the province is taking several steps to improve oversight of water use, including a research project studying aquifers. The agency said it can review large groundwater withdrawal projects and that pending changes to the province’s water law would regulate withdrawals.
Drillers themselves are also moving to address water concerns.Â Encana and Apache have started using saline water not suitable for drinking or irrigation in some of their projects. Alan Boras, the Encana spokesman, said the company uses non-potable water almost exclusively in its main operating area in the Horn River Basin, where the largest frack jobs were reported.
Environmentalists say they welcome the effort, but caution that these projects are tiny compared to the industry’s overall water use.
Governments, Industry Get Cozy
Public backlash to fracking has become such a concern for drillers and provincial governments in western Canada that last year they launched a joint effort to counter it.
In December 2010, the governments of British Columbia, Alberta and Saskatchewan signed a memorandum of understanding laying out a plan  to share information and develop standards for hydraulic fracturing and water use. The provinces invited only one non-governmental entity to participate in the project: the Canadian Association of Petroleum Producers.
The memo, which was leaked in August and published by the Alberta Federation of Labour, a union group, said the provinces and petroleum producers would work together to develop “key messages” on shale drilling to persuade the public not to fear fracking.
“The project will help to demonstrate that shale gas extraction is viable, safe and environmentally sustainable,” the memo said.
The memo blamed environmental groups for spreading misleading information and stirring opposition to drilling.
“Environmental Non-Government organizations (ENGOs) are supporting a ill-informed [sic] campaign on hydraulic fracturing and water related issues in British Columbia and in other jurisdictions,” it said. “This is expected to grow as shale gas development expands into Alberta and Saskatchewan.”
In a separate memo , Alberta Environment and Water reported that the Canadian Association of Petroleum Producers had approached the province to work on a joint public relations campaign.
Ultimately, no campaign materialized.
Janet Annesley, a spokeswoman for the Canadian Association of Petroleum Producers, said the group hadn’t wanted to join forces on PR but was just informing the province of plans to publish voluntary standards for shale gas drilling.
Still, critics saw the memo as proof of an overly cozy relationship between the government and the industry.
Bart Johnson, a spokesman for Alberta’s Energy Minister, said the petroleum producers had suggested a joint PR initiative but dropped the request. Such a collaboration, however, would not have been inappropriate, he said. The government works with industry groups all the time, he said, citing a campaign with education groups against bullying in schools.
“Oil and gas is huge in Alberta. It fuels our economy. Indeed it fuels the economy of Canada,” Johnson said. “Any suggestion that we shouldn’t meet with that industry is ridiculous.”
by Lena Groeger ProPublica,
A bill to strengthen pipeline safety regulations passed the House and Senate last week and now awaits President Obamaâ€™s signature. But while many applaud Congressâ€™s move toward more oversight, others question whether the impending law goes far enough to prevent oil and natural gas pipeline accidents.
The pipeline industry reports more than 100 significant hazardous liquid spills each year. (See a map of those spills). Every year, an average of 275 accidents kill 10 to 15 people and injure five to six times as many.
The â€œPipeline Safety, Regulatory Certainty, and Job Creation Act of 2011â€ would double potential fines for violations (up to a max of $2 million), require automated shutoff valves for new and replaced pipelines, and hire 10 new safety inspectors to join the current 124.
â€œThis is a huge step forward for the safety of Americaâ€™s pipelines,â€ Senator Frank R. Lautenberg (D-NJ) said in a statement.
But as the Associated Press noted, the bill doesnâ€™t implement several recommendations from a National Transportation Safety Board investigation of the natural gas pipeline explosion in San Bruno, California that killed eight people last September (the San Francisco Chronicle has a recent series on the disaster). One of those recommendations is that automated shutoff valves be installed on already existing pipelines (particularly old ones in highly populated areas, which are prone to accidents).
Safety experts also say that the Pipeline and Hazardous Materials Safety Administration, the federal agency responsible for regulating the vast network of 2.5 million miles of pipelines, needs many more inspectors to do the job right. The pipeline agency simply doesnâ€™t have enough inspectors, or money to hire them, a New York Times investigation recently found.
A recent Congressional Research Service report on pipeline safety found a long-term pattern of understaffing. Which means that itâ€™s often pipeline workers who notice and report problems â€“ if they catch them in time.
In recent years, a series of major accidents have further raised the profile of dangerous pipelines. In addition to the San Bruno blast, 800,000 gallons of oil spurted into Michiganâ€™s Kalamazoo River last July after a 30-inch pipeline sprung a leak. Another 42,000 gallons spilled in July into the Yellowstone River in Montana from a ruptured pipe.
Thousands of other pipelines could potentially share the same fate. More than 60 percent of the countryâ€™s gas pipelines are at least 40 years old, and they often arenâ€™t compatible with the latest in safety technology (the Philadelphia Inquirer has a recent series on aging pipelines).
Weâ€™ve covered the recurring troubles with Alaskaâ€™s pipelines, which federal agencies have repeatedly flagged, urging repairs or entire replacements of dangerously corroded pipes. Even portions of the pipelines that BP inspectors didnâ€™t give an â€œFâ€ ranking (BP is the largest single owner of the Alaska pipelines) have burst, spewing thousands of gallons of oily water and methanol.
Another problem, as weâ€™ve noted previously, is who writes the regulation standards. As it happens, the gas and oil industry has written at least 29 Âof the standards later adopted by the pipeline agency.
The bill comes alongside a Republican attempt to speed up the approval of the controversial Keystone XL Pipeline, a 1,700 mile long pipeline that would run from Canada to the Gulf of Mexico, carrying a particularly viscous form of crude called oil sands. As mentioned in the Times, the bill makes no reference to Keystone, but calls for more studies on whether oil sands needs extra regulation.
by Abrahm Lustgarten
Texas-based Legacy Resources backed out of a $45 million deal to buy the field near Pavillion, Wyom., from EnCana last week, soon after the Environmental Protection Agency said it had detected cancer-causing benzene at 50 times the level safe for humans and other carcinogenic pollutants during its latest round of sampling.
The cancelled sale could signal difficulty for companies trying to turn over aging gas fields if there are environmental or health concerns related to their operations.
â€œAlthough Encana retained responsibility for any outcome resulting from the ongoing groundwater investigation undertaken by EPA, due to the continued attention surrounding the investigation, and uncertainty regarding further development, Legacy is not prepared to go forward with the transaction,â€ said EnCana spokesman Doug Hock, in an email to ProPublica.
Legacy Resources did not respond to a call requesting comment.
Legacy Resources announced it had agreed to buy EnCanaâ€™s Pavillion-area wells, which produce an estimated 13 million cubic feet of gas a day, on Nov. 1. At the time, the company also said it planned to drill new wells in Pavillion to tap the 45 billion cubic feet of gas it believes lies underground.
But the prospects for future development have dimmed.
Residents had long complained of widespread water contamination and alleged that fracking was to blame. EnCana had trucked in replacement drinking water to some residents. The company faced increasing controversy when the EPA announced in late 2009 that it had found hydrocarbon contaminants in residentsâ€™ drinking water wells. The agency advised residents not to drink their water and to ventilate their homes when they showered or washed dishes. ProPublica began reporting on concerns about water contamination in Pavillion in 2008.
On Nov. 9 the EPA announced more test results from samples taken in Pavillion, this time from two water monitoring wells drilled to 1,000 feet â€“ far below most drinking water wells in the area. It found benzene, along with acetone, toluene, naphthalene and traces of diesel fuel. It also detected a solvent called 2-Butoxyethanol (2-BE) that is commonly used by the drilling industry to fracture wells. It also can be used for cleanup at well sites.
EnCana has maintained that the pollutants found in Pavillion-area wells occur naturally, and that drilling is not to blame. â€œNothing EPA presented suggests anything has changed since August of last year â€“ the science remains inconclusive in terms of data, impact, and source,â€ Hock wrote to ProPublica.
Hock said that the EPAâ€™s monitoring wells were drilled into a zone known to contain methane gas, and suggested the pollutants would have been expected to be there. He said that the 2-BE was only detected in one sample and could have leached from the plastics used to drill many drinking water and monitoring wells. In previous statements to ProPublica, he has said that the 2-BE might have come from household cleaning agents, which can contain the chemical. Hock did not reply to questions about whether EnCana had used 2-BE in fracking or any other processes in Pavillion.
The EPAâ€™s latest findings are consistent with previous samples taken from water wells at 42 homes in the area since 2008.
The agency has so far been careful not to draw conclusions about the cause of the pollution. EPA officials had said they planned to release a detailed report analyzing possible causes of the pollution by the end of November, but now say it will be at least a few more weeks.
by Abrahm Lustgarten
As the country awaits results from a nationwide safety study on the natural gas drilling process of fracking, a separate government investigation into contamination in a place where residents have long complained that drilling fouled their water has turned up alarming levels of underground pollution.
A pair of environmental monitoring wells drilled deep into an aquifer in Pavillion, Wyo., contain high levels of cancer-causing compounds and at least one chemical commonly used in hydraulic fracturing, according to new water test results released yesterday by the Environmental Protection Agency.
The findings are consistent with water samples the EPA has collected from at least 42 homes in the area since 2008, when ProPublica began reporting on foul water and health concerns in Pavillion and the agency started investigating reports of contamination there.
Last year — after warning residents not to drink or cook with the water and to ventilate their homes when they showered — the EPA drilled the monitoring wells to get a more precise picture of the extent of the contamination.
The Pavillion area has been drilled extensively for natural gas over the last two decades and is home to hundreds of gas wells. Residents have alleged for nearly a decade that the drilling — and hydraulic fracturing in particular — has caused their water to turn black and smell like gasoline. Some residents say they suffer neurological impairment, loss of smell, and nerve pain they associate with exposure to pollutants.
The gas industry — led by the Canadian company EnCana, which owns the wells in Pavillion — has denied that its activities are responsible for the contamination. EnCana has, however, supplied drinking water to residents.
The information released yesterday by the EPA was limited to raw sampling data: The agency did not interpret the findings or make any attempt to identify the source of the pollution. From the start of its investigation, the EPA has been careful to consider all possible causes of the contamination and to distance its inquiry from the controversy around hydraulic fracturing.
Still, the chemical compounds the EPA detected are consistent with those produced from drilling processes, including one — a solvent called 2-Butoxyethanol (2-BE) — widely used in the process of hydraulic fracturing. The agency said it had not found contaminants such as nitrates and fertilizers that would have signaled that agricultural activities were to blame.
The wells also contained benzene at 50 times the level that is considered safe for people, as well as phenols — another dangerous human carcinogen — acetone, toluene, naphthalene and traces of diesel fuel.
The EPA said the water samples were saturated with methane gas that matched the deep layers of natural gas being drilled for energy. The gas did not match the shallower methane that the gas industry says is naturally occurring in water, a signal that the contamination was related to drilling and was less likely to have come from drilling waste spilled above ground.
EnCana has recently agreed to sell its wells in the Pavillion area to Texas-based oil and gas company Legacy Reserves for a reported $45 million, but has pledged to continue to cooperate with the EPA’s investigation. EnCana bought many of the wells in 2004, after the first problems with groundwater contamination had been reported.
The EPA’s research in Wyoming is separate from the agency’s ongoing national study of hydraulic fracturing’s effect on water supplies, and is being funded through the Superfund cleanup program.
The EPA says it will release a lengthy draft of the Pavillion findings, including a detailed interpretation of them, later this month.
Reprinted with permission from ProPublica
The Forest County Potawatomi Tribe has completed a solar photovoltaic installation project in Milwaukee, funded in part with $2.6 million from the U.S. Department of Energy (DOE). The project is one of five Community Renewable Energy Deployment (CommRE) projects that received DOE funding through the American Recovery and Reinvestment Act, and is the first to be completed. DOE’s CommRE projects help communities implement long-term renewable energy technologies, create jobs, and provide examples for replication by other local governments, campuses, and small utilities.
Located on the rooftop of the Tribe’s administration building in Milwaukee, the solar energy system was installed by Milwaukee-based Pieper Electric and features locally manufactured panels from Milwaukee-based Helios USA, LLC. The Tribe estimates the system will produce approximately 35,000 kilowatt hours of electricity per year and reduce carbon dioxide emissions by approximately 41 tons annually.
Additionally, the Potawatomi Tribe will install a 1.25-megawatt combined heat and power biomass facility, which will provide electricity and heating and cooling to its Stone Lake campus. The project will also supply additional electricity and heat for the Tribe’s various buildings on the reservation, utilizing organic waste from its facilities, member’s homes, restaurants and Tribal lands.
Other CommRE projects include:
â€¢A combined heat and power district energy system for the City of Montpelier, Vermont
â€¢The 30-megawatt, community-owned, Haxtun Wind project in Phillips County, Colorado
â€¢A 1.5-megawatt concentrating solar photovoltaic system along California Highway 50 and biogas digestion systems in Sacramento, California
â€¢High-efficiency buildings and renewable energy systems at the University of California at Davis’ West Village community that will serve as a model for net-zero communities.
CommRE projects receive technical assistance from DOE’s National Renewable Energy Laboratory on concepts, best practices, planning, financial approaches, and policy guidance.
DOE’s Office of Energy Efficiency and Renewable Energy invests in clean energy technologies that strengthen the economy, protect the environment, and reduce dependence on foreign oil. Read more about the Potawatomi Tribe’s solar installation on the Energy.gov blog, and learn about the other CommRE projects.
Join the clean energy conversation on Facebook at DOE’s Energy Efficiency and Renewable Energy and Energy Savers pages.
By the end of this year, the State Department will decide whether to give a Canadian company permission to construct a 1,700-mile, $7 billion pipeline that would transport crude oil from Canada to refineries in Texas.
The project has sparked major environmental concerns, particularly in Nebraska, where the pipeline would pass over an aquifer that provides drinking water and irrigation to much of the Midwest. It has also drawn scrutiny because of the company’s political connections and conflicts of interest. A key lobbyist for TransCanada, which would build the pipeline, also worked for Secretary of State Hillary Clinton  on her presidential campaign. And the company that conducted the project’s environmental impact report had financial ties to TransCanada.
The debate over the pipeline is both complicated and fierce , and it crosses party lines, with much sparring over the potential environmental and economic impacts of the project. More than 1,000 arrests were made during protests of the pipeline  last summer in Washington, D.C.
Here’s our breakdown of the controversy, including the benefits and risks of the project, and the concerns about the State Department’s role.
Potential benefits â€” energy security and jobs for Americans â€” and how they’re disputed
Proponents of the project point to two main benefits for Americans. First, it would improve America’s energy security , because it would bring in more oil from friendly Canada and reduce our dependence on volatile countries in South America and the Middle East. Secondly, the pipeline would create well-paying construction jobs and provide a broader economic boost to the American economy. Labor unions have supported the project .
TransCanada estimates that the project would directly create 20,000 construction and manufacturing jobs for Americans . A study paid for by TransCanada  also estimated the economic impact over the life of the pipeline at about $20 billion in total spending.
But a report by Cornell University’s Global Labor Institute  questioned those numbers, noting that the project would “create no more than 2,500-4,650 temporary direct construction jobs for two years, according to TransCanada’s own data supplied to the State Department.”
Critics of the project have also questioned whether the pipeline’s oil, once processed in American refineries on the Gulf Coast, would actually be sold to Americans rather than being exported for sale elsewhere . As a New York Times editorial opposing the pipeline noted, five of the six companies  that have already contracted for much of the pipeline’s oil are foreign companies â€” and the sixth focuses on exporting oil.
The Washington Post, which editorialized in favor of the pipeline , said this should not be a major objection. “The bottom line remains: The more American refineries source their low-grade crude via pipeline from Canada and not from tankers out of the Middle East or Venezuela, the better, even if not every refined barrel stays in the country,” the Post editorial stated.
Cozy relationships with the State Department â€” and a compromised environmental report
Because the project crosses the U.S. border, it requires a permit from the State Department. As part of that process, the State Department did an environmental impact report . The study concluded that, if operated correctly, the pipeline would have “limited adverse environmental impacts.” But a New York Times investigation found that the company that the government hired to conduct the study had significant financial ties to TransCanada  â€” and that this conflict of interest “flouted the intent of a federal law” requiring federal agencies to select contractors that have no potential interest in the outcome of the project being evaluated.
Environmental groups have also scrutinized the relationship between State Department officials and TransCanada’s representative in Washington. Paul Elliott, who worked on Hillary Clinton’s presidential campaign, was actively lobbying the State Department and Congress  about the project for a year and a half before he officially registered as a lobbyist, according to State Department email messages made public by the environmental group Friends of the Earth . Elliott did not comment on the emails, but a TransCanada spokesperson said he was simply doing his job as a lobbyist.
The emails showed a friendly relationship between Elliott and his State Department contact, who wrote “Go Paul!”  when Elliott secured the support of a key congressman for the Keystone project.
The State Department has said that it will consider the merits of the pipeline proposal impartially .
As the news organization Mother Jones pointed out , the emails also revealed “an apparent understanding between the State Department and TransCanada that the company would later seek to raise the pressure used to pump oil through the pipeline â€” even though the company said publicly it would do the opposite .”
TransCanada had originally sought permission to use a higher-than-usual pressure in its pipeline  but publicly backed away from the request in response to the concerns of citizens and politicians that higher pressure might increase the risk of leaks and environmental damage.
A WikiLeaks cable also revealed that a different U.S. diplomat had given PR tips to Canadian officials about the project. As the Los Angeles Times noted, the diplomat “had instructed them in improving ‘oil sands messaging,’  including ‘increasing visibility and accessibility of more positive news stories.’”
Concerns about water contamination across the Great Plains
The proposed route of the pipeline passes over the Sandhills wetland of Nebraska â€” and over the most important aquifer in the nation, the Ogallala Aquifer, which provides drinking water and irrigation to a large swathe of Midwestern states .
This has prompted opposition from Nebraska politicians. The state’s Republican governor wrote a letter  to President Obama asking him not to approve the project, and state legislators are considering legislation  limiting where the pipeline can be located.
“Clearly, the contamination of groundwater is the top concern,” State Sen. Mike Flood told reporters .
Opposition to the pipeline is so broad in Nebraska  that a TransCanada-sponsored video that was perceived as supporting the pipeline was booed at a University of Nebraska football game , which resulted in the Cornhuskers athletic department ending a TransCanada sponsorship deal .
But at least one scientist with significant experience with the Ogallala Aquifer said fears about contamination from the pipeline are overblown .
James Goeke, a hydrogeologist and professor emeritus  at the University of Nebraska, wrote on The New York Times’ website that the geography of the aquifer â€” there’d be clay between the pipeline and the water, and much of the aquifer is uphill from the pipeline’s proposed location â€” means that a leak in the pipeline “would pose a minimal risk to the aquifer as a whole.” He suggested the government “require TransCanada to post a bond for any cleanup in the event of a spill,” and noted that in particularly vulnerable areas, TransCanada has promised to encase the pipeline in cement.
Leaks and spills
The Keystone XL pipeline would carry a diluted form of tar sands, a type of natural petroleum deposit. Environmentalists argue that the tar sands, or “dilbit,” mixture that the pipeline would transport  is more corrosive than typical crude oil, and thus might cause more leaks in the pipeline.
These fears were heightened by an oil spill in Michigan  that leaked roughly 800,000 gallons of tar sands into Michigan’s Kalamazoo River in July 2010. The spill came within 80 miles of Lake Michigan, and a year later, the Environmental Protection Agency has ordered Enbridge, the energy company responsible for the spill, to conduct further cleanup, citing pockets of submerged oil covering about 200 acres  of the river’s path.
The Christian Science Monitor has a good, brief summary of spills  on TransCanada’s existing U.S. pipeline, and notes that according to the State Department estimate, “the maximum the Keystone XL could potentially spill would be 2.8 million gallons along an area of 1.7 miles .”
Concerns about eminent domain
Some property owners whose land the pipeline would cross have spoken out against the company’s approach , particularly the fact that a Canadian company is able to use eminent domain to acquire the use of private land.
The issue has struck a nerve across the political spectrum and has helped bring together Tea Party and environmental activists in Texas  to oppose the project.
TransCanada says it is compensating landowners fairly, and notes that, “Our permit does allow us to use eminent domain  to acquire an easement and provide compensation for the landowner. Keystone XL always prefers to avoid the use of eminent domain, and if we cannot reach an agreement, then we turn to the independent processes/hearings that are established in Texas and other U.S. states.”
Broader environmental concerns
Environmentalists also object not just to the pipeline itself but to the start-to-finish process of refining tar sands, which has a heavy impact on the environment, including global warming. As a Stanford University professor wrote  on The New York Times’ website:
Available evidence suggests that oil sands, on a “well-to-wheels” basis, have 15 to 20 percent higher greenhouse emissions than conventional oil. This is because of increased energy demand during extraction and the use of high-carbon fuels like petroleum coke. Also, water pollution concerns plague mining-based projects that produce large volumes of tailings (a contaminated, watery waste product).
Critics of the project  argue that approving Keystone XL could have a “chilling effect” on efforts to create green jobs, and that it would demonstrate that the U.S. is not serious about its climate change leadership â€” and that Canada is not serious about trying to reach its Kyoto targets.
But as many have noted, denying approval to Keystone XL wouldn’t stop tar sands production. As the Heritage Foundation’s David Kreutzer argued : “Block the XL pipeline if you think the environment will be better served by shipping Canadian oil an extra 6,000 miles across the Pacific in oil-consuming super tankers and then refining it in less-regulated Chinese refineries.”
byÂ Nicholas Kusnetz ProPublica
Medical professionals and environmentalists sent a letter to Gov. Andrew Cuomo saying the state should study the health effects of gas drilling before allowing more of it
In aÂ letter sent Wednesday to Gov. Andrew Cuomo, the group said New Yorkâ€™s plan for regulating fracking ignores growing evidence that gas drilling harms public health. The group asked the state to assess disease rates in potential drilling areas to establish a baseline, identify specific risks from drilling and propose steps to mitigate those risks.
Emily DeSantis, a spokeswoman for the state Department of Environmental Conservation, said state officials had taken health effects into consideration in drafting theÂ new regulations for high-volume fracking that were released last week.
â€œBecause New York has developed the most rigorous requirements in the nation to protect the public health and the environment,â€ she wrote in an email, â€œa comparison of health impacts in other states is inappropriate.â€
New York put a hold on fracking three years ago, just as drilling into the Marcellus Shale formation was taking off in neighboring Pennsylvania.Â As ProPublica has reported, intense gas drilling in Pennsylvania and elsewhere has been accompanied by mounting complaints about health problems around drilling sites. Neither states nor the federal government currently track or study such reports systematically, however.
On Monday,Â Pennsylvaniaâ€™s Gov. Tom Corbett proposed a fee on drilling that would provide the state health department $1 million to $2 million a year to compile and investigate health complaints. The move followed a proposal from the stateâ€™s secretary of public health to create the nationâ€™s first drilling-related health registry.
The New York letter, which was signed by more than 250 health professionals and environmental groups, called for the state to conduct a health impact assessment similar to one started last year in a western Colorado community.
In the initial draft of the Colorado study, researchers concluded that new drilling in the area would likely affect residentsâ€™ health, but it came under criticism from drillers, andÂ county officials ended the work before a final draft was released.
Bernard Goldstein, professor emeritus at the University of Pittsburghâ€™s School of Public Health, has criticized officials in Pennsylvania for approving new drilling without adequately studying public health in drilling areas. While he didnâ€™t sign the New York letter, Goldstein said he supports the groupâ€™s demands, adding that New York should learn from Pennsylvaniaâ€™s experience and properly assess health risks before drilling begins.
â€œTo me, the idea of rushing ahead basically refutes all weâ€™ve learned in environmental health science over the last 40 years,â€ he said
by Nicholas Kusnetz
Pennsylvania Gov. Tom Corbett announced a plan Monday to impose the first-ever fees on companies drilling for natural gas in Pennsylvania. Gov. Tom Corbett announced a plan today to impose the first-ever fees on companies drilling for natural gas in Pennsylvania and to use the revenue raised to cover costs related to gas production.
Under Corbett’s proposal, drillers would pay up to $160,000 per well, spread out over the first 10 years of the well’s production, though they could earn credits of up to 30 percent by investing in natural gas fueling stations or gas-powered buses. The governor’s office estimated that the state and local governments would split $120 million to $200 million a year in fee revenue.
Pennsylvania has been the only major oil-and-gas-producing state without a drilling tax or fee, drawing heat from environmental groups as well as from some members of the legislature and public. Corbett’s plan would change that, but advocates criticized the approach of charging flat fees, rather than taxing drillers based on production or revenue, as several other states do.
“This impact fee structure is a gift to the drillers,” said Jan Jarrett, president and CEO of PennFuture, an environmental group that has pushed for stronger drilling rules. Tomorrow morning, Jarrett said she would join several advocacy groups and state legislators in calling for a tax on gas extraction.
Corbett’s fee proposal is part of a larger overhaul of Pennsylvania’s drilling rules. His plan also would expand the buffer between drilling operations and water wells and increase fines for some safety or environmental violations.
The Marcellus Shale Coalition, an industry group, issued a statement saying it supports Corbett’s plan in general and that it was still reviewing the specifics.
Corbett has proposed sending three-quarters of the fee money to local governments to spend on the effects of drilling, from road maintenance to emergency response preparedness to shortages of affordable housing.
The rest of the revenue would be divided among several state agencies, including the transportation, environment and health departments. Some environmental and budget groups have argued for fewer restrictions on where and what the money is spent on, saying drilling has statewide effects and costs.
As ProPublica has reported, health complaints are emerging  in Pennsylvania and other states where drilling has intensified. In June, Pennsylvania’s health secretary proposed creating a health registry  to track drilling-related complaints.
The health department could receive $1 million to $2 million a year from the fee, based on estimates from the governor’s office, but it’s unclear whether the money would be used on the registry. The governor’s announcement says that fee revenue could be used to investigate health complaints and for “collecting and disseminating information.” Health Department spokeswoman Christine Cronkright said the agency would submit plans to the governor within 30 days for how it would like to spend the money.
To become final, some of Corbett’s proposals would require legislative action, while others could be implemented with administrative changes.
Jarrett said she’s concerned that the entire package will be submitted to the legislature as a block, tying toughened regulations and penalty hikes to the fee proposal.
“I would not want to see the Marcellus fee tied to all these improvements,” she said. “They are separate issues and they should go on separate tracks.”
ByÂ Ariel WittenbergÂ ProPublica
“This is just evidence that we need a smarter, better, more secure system,” said Massoud Amin, director of the Technological Leadership Institute at the University of Minnesota, who has analyzed federal data on the reliability of the nation’s electric grid.
Blackouts disrupt power to at least a third of U.S. homes each year, and studies show the number of outages is rising .
The grid’s shortcomings have been well-documented, but efforts to modernize it haven’t kept up with demand. Many electrical transmission lines are outdated, and parts of the grid date back to the time of Thomas Edison.
The chairman of the Federal Energy Regulatory Commission, which oversees the nation’s grid, acknowledged increasing problems with the system.
In a July interview with ProPublica, FERC Chairman Jon Wellinghoff said that while the electric grid is reliable, it is degrading. “It’s not getting better,” he said. “It’s getting worse.”
Many experts say smart-grid technology would help. Such a system would be able to intelligently respond to sudden peaks or drops in demand and energy supply.
Last week, for example, a mishap involving a single worker  doing repairs on a power station near Yuma, Ariz., led to rolling blackouts over parts of Arizona, Southern California and Northern Mexico. The short circuit caused San Diego County’s power-supply system to completely shut down after it was required to take on the demand of those affected in Arizona and buckled under the extra load .
Had a smart grid been in place, it might have helped isolate the outage and prevent it from spreading. By monitoring activity on transmission lines in real time, a smart grid also can help pinpoint a problem and redirect power accordingly.
The Obama administration has allocated $11 billion in stimulus funding toward the electric grid. Of that, $4.4 billion was dedicated directly to building a smart grid. But the money will take years working its way through the bureaucratic pipeline; so far, only $1.4 billion has been spent.
Experts also say smart grids are only part of the solution and that transmission lines also have to be built.
“These are essential facilities. They are like highways, they are like airportsâ€”everyone relies on them,” former FERC Chairman Jim Hoecker said.
But transmission lines cost money, and utilities say investing too much more in infrastructure will cost consumers. According to David Owens, executive vice president for business operations at Edison Electric Institute, transmission costs make up 35 percent to 40 percent of a typical homeowner’s energy bill. Shareholder-owned utilities will invest $11.2 billion in transmission in 2011â€”almost twice as much as in 2004. The increase pushes the envelope on what customers are willing to pay, Owens said.
Wellinghoff, FERC’s current chairman, said the commission also needs broader authority to oversee transmission lines. That would require congressional approval.
One project that might benefit from broader FERC power is the Susquehanna-Roseland power line. The line, which would run from Pennsylvania to Northern New Jersey, has been delayed for two years because a four-mile stretch passes through a national park. Although the line would follow the same path as a pre-existing line, the National Park Service has blocked construction to analyze the effect of the line on the environment. Wellinghoff said FERC’s engineers had already done an environmental review.
Absent new transmission lines and a smart grid, large blackouts could become more common.
Last week’s massive outage echoed a blackout eight years ago. In 2003, a power surge on a transmission line that circles Lake Erie left dozens of cities in the East and Canada without power, shutting down 21 power plants in just three minutes.
After the power came back on, politicians, regulators and industry officials all pledged to push for a more reliable, modern grid.
But the promises did not translate into action.
“We have overharvested the infrastructure,” Amin said. “We aren’t milking the cow dry; we already have milked the cow dry. It has gotten to the point where there are many choke points. We cannot just sit and watch the load increase.”