Congenital heart defects are the leading cause of all infant deaths in the US
A new study, published last week in the scientific journal Environmental Health Perspectives, draws a correlation between birth defects and maternal exposures to natural gas.
After examining 124,842 births between 1996 and 2009 in rural Colorado, the study found a higher incidence of congenital heart defects (CHDs) and neural tube defects (NTDs) with infants whose mothers experienced higher exposures to natural gas.
The study (download pdf here) was led by researchers from the Colorado School of Public Health and Brown University, with support from The Colorado Department of Public Health and Environment (CDPHE). Born out of health concerns surrounding the growth of natural gas development throughout the US, it looked at health outcomes for children born of mothers who lived within a 10 mile radius of natural gas development in Colorado.
The researchers note that natural gas “emits several potential teratogens” – i.e. a substance which causes malformations. They suggest concerns around the health impacts of natural gas exposures are real and require more scientific study:
[quote]In this large cohort, we observed an association between density and proximity of natural gas wells within a 10-mile radius of maternal residence and prevalence of CHDs and possibly NTDs. Greater specificity in exposure estimates are needed to further explore these associations. [/quote]
According to the US-based Children’s Heart Foundation, “Congenital heart defects are the leading cause of all infant deaths in the United States,” with over 40,000 babies born every year, suffering from CHD.
NEW YORK – The frigid winter of 2014 is setting the price of natural gas on fire.
Friday, the price in the futures market soared past $5 per 1,000 cubic feet, up 9 per cent for the day to the highest level in three and a half years. The price of natural gas is up 29 per cent in two weeks, and is 50 per cent higher than last year at this time.
Record amounts of natural gas are being burned for heat and electricity. Meanwhile, it’s so cold that drillers are struggling to produce enough to keep up with the high demand. So much natural gas is coming out of storage that the Energy Department says supplies have fallen 20 per cent below a year ago — and that was before this latest cold spell. Says energy analyst Stephen Schork:
[quote]We’ve got record demand, record withdrawals from storage, and short-term production is threatened. It’s a dangerous market right now.[/quote]
Natural gas and electric customers are sure to see somewhat higher rates in the coming months. But they will be insulated from sharp increases because regulators often force natural gas and electric utilities to use financial instruments and fuel-buying strategies that protect residential customers from high volatility.
North America faces second major cold snap
To understand the price increase, just look at the thermometer. A second major cold snap this month is gripping much of the country, including the heavily-populated Northeast. And forecasters are now predicting colder weather in the weeks to come, extending south through Texas.
Natural gas is used by half the nation’s households for heating, making it the most important heating fuel. Electricity is the second most popular heating source, and electric power generators use natural gas to generate power more than any other fuel except for coal.
Commodity Weather Group, which predicts heating demand for energy companies and consumers, said in a report Friday that periodic breaks in the cold weather are expected to be “weaker and briefer, extending the duration of colder weather” in late January and early February.
Shale gas wells can freeze up
There are a couple of other factors at play. In the past, much of U.S. natural gas was produced in the Gulf of Mexico. If weather disrupted supplies there, it was typically in the early fall, during hurricane season, when heating and electricity demand are low and natural gas storage facilities are mostly full in preparation for winter.
Now, much of U.S. production comes from on-shore formations that are more susceptible to cold, ice and snow. Wells that are not designed for such extreme conditions can freeze, halting production.
“Now the threat to production is when demand is at its highest,” Schork says.
Also, electric utilities have for several years been switching to cheaper natural gas for power generation. And new pipelines aren’t being built fast enough to deliver all the gas required at times of high demand. That can lead to regional shortages that send prices skyrocketing.
Gas prices could remain high
When the Calvert Cliffs Nuclear Station in Maryland shut down earlier this week because of an electrical problem brought on by snow and ice, power generators across the East Coast scrambled to replace the lost power by cranking up natural gas-fired plants. That sent natural gas prices for immediate delivery, known as the spot price, to a record $120 per 1,000 cubic feet in some markets on the East Coast. To put that in perspective, that’s equivalent to oil at more than $700 per barrel.
Analysts say there is plenty of gas to replenish supplies, and drillers will scramble to boost production so they can fetch prices they haven’t seen since the summer of 2010.
If, that is, the weather heats up later in February and March. If it’s still cold when baseball season opens in early April, though, Schork says, “we’ll be looking at much higher natural gas prices.”
Fracking operations in BC’s Horn River Basin (Two Island Films)
A new report from geoscientist and shale gas expert David Hughes offers a big reality check for BC’s proposed liquefied natural gas (LNG) industry. As a former 32-year veteran of the Geological Survey of Canada, Hughes led a national review of the country’s unconventional gas potential. Now, after drilling down on the BC Liberal government’s LNG vision, he has some sobering things to say about its promise of a $100 Billion windfall “prosperity fund”, built on accessing new markets in Asia.
David Hughes
In a new report titled BC LNG: A Reality Check – released by the Watershed Sentinelon January 18, where you can read it in full – Hughes analyzes the implications of 7 large LNG export licences recently issued by the National Energy Board. Together, they constitute a staggering 14.6 billion cubic feet/day (bcf/d) of gas – more than the total amount of gas coming out of the entire country today, at 12.7 bcf/d.
Drawing on the best available production and geological data from Canada’s gas sector, Hughes assails both the NEB’s reckless approval of this much gas for export and the BC Liberal policy for economic development that is driving the LNG boom.
Regulator violates mandate
“The NEB appears to have violated its mandate to ensure Canadian energy security by approving seven LNG export applications, which add up to more than the current gas production of all of Canada, and far exceed even its most optimistic projections of BC gas production, says Hughes.”
[quote]To put this in perspective, the US, which produces five times as much gas as Canada, has approved only four export projects with a total capacity of less than half that of the NEB approvals.[/quote]
Hughes found that, on average, production from a given unconventional gas well in BC plummets by 69% in its first three years – a far sharper decline than the historical rate for conventional gas, meaning that a drilling treadmill is required just to keep production flat, let alone grow it.
To that latter point, Hughes paints a startling picture of what fulfilling these export demands would look like on the ground: i.e. a dramatic increase in controversial fracking and consequent water use.
LNG export licences = gas equivalent of Tar Sands x 2
The NEB has approved 7 LNG export licences so far
The most recent approval by the NEB of 4 export licences, just before Christmas, came in the same week the regulator received Kinder Morgan’s application for a major oil pipeline expansion to Vancouver and announced its conditional recommendation of the proposed Enbridge pipeline. The LNG story was thus lost in the shuffle – this despite the fact, as The Common Sense Canadian noted at the time, those four gas licenses alone were the equivalent of almost 2 million barrels of oil per day for 25 years. In other words, roughly four times bigger than the proposed Enbridge pipeline and the same size of the entire Alberta Tar Sands oil output today.
Add in the three licences it had already approved before that, plus the the 4 more it still has under review – totalling an additional 3.4 bcf/d – and you have double the energy equivalent of today’s Tar Sands.
Another 50,000 holes in the ground
Hughes’ report gives a shocking glimpse of the environmental and economic implications of powering BC’s LNG vision:
[quote]…meeting the NEB export approvals would require drilling nearly 50,000 new wells in the next 27 years (double the approximately 25,000 wells drilled in BC since the 1950s).[/quote]
A fracking drill in BC’s Horn River Basin (Two Island Films)
After extensively researching wellhead data across the US shale gas boom – which is a few years ahead of Canada since it was the birthplace of modern high-volume slick water hydraulic fracturing – Hughes came to the conclusion that shale gas wells don’t produce for nearly as long as conventional gas wells did. In fact, the average 3-year decline rate (the speed at which production falls toward zero) of the 5 major US shale gas plays – accounting for 80% of the nation’s production – was a staggering 84%. That means that most wells are pretty much tapped out in a few years. It also means continual high rates of drilling are required to offset declines – just to maintain, let alone grow, production.
Fracking would use more water than City of Calgary
Turning his attention to Canada over the past year, Hughes is seeing similar trends. “Given the steep production declines associated with shale and tight-gas, drilling rates of more than 3,000 new wells per year would be required to ramp up production to required export levels, followed by nearly 2000 wells per year to maintain production,” he warns. (emphasis added)
[quote]Notwithstanding the other well publicized environmental issues with hydraulic fracturing (fracking), which would be the principal completion technology used to produce this gas, water consumption alone during the ramp up phase would exceed that of the City of Calgary, which has more than a million people.[/quote]
Regulator, Government’s numbers don’t add up
To Hughes though, it’s much more than a matter of underestimating the environmental costs. The NEB and provincial government are misrepresenting the geology too. The regulator’s numbers simply don’t add up, says Hughes, when it comes to supplying the gas for the export licences they’ve issued. “The NEB’s forecasts of gas production in BC through 2035 do not come close to the levels needed for its LNG export approvals,” he notes. “Its reference case forecast for BC is the production of 57 trillion cubic feet (tcf) by 2035, yet 120 tcf are required to meet its approvals (more than three times BC gas reserves).”
Hughes has also tackled the erroneous boasts being made by BC’s Minister for Natural Gas Development, Rich “The Optimist” Coleman. Although more exploration will certainly find additional recoverable reserves, Coleman recently declared that there are over 950 trillion cubic feet (tcf) of recoverable resources in BC alone – this compares to the recent NEB estimate of 861 tcf in Manitoba, Saskatchewan, Alberta and BC combined. The most recent estimates of marketable gas reserves in BC by Coleman’s own Oil and Gas Commision is only 33.4 tcf.
To put this in perspective, just 25 tcf of marketable gas has been recovered in BC since the 1950s from more than 25,000 wells. Nearly five times this amount would need to be recovered in just 27 years to meet the NEB’s export approvals.
Could Canadians run out of gas due to export commitments?
At issue is Canadians’ own future energy security. A central piece of the NEB’s mandate is to ensure that exports run surplus to domestic needs. And they’ve given their stamp of approval to these LNG export licences:
[quote]We have determined that the quantity of gas proposed to be exported by Prince Rupert LNG is surplus to Canadian need. The Board is satisfied that the gas resource base in Canada, as well as North America, is large and can accommodate reasonably foreseeable Canadian demand, the LNG exports proposed in this Application, and a plausible potential increase in demand.[/quote]
But is this true? Hughes thinks not. “Canadian production peaked in 2002 and is now down 30 per cent from its peak. The only province with substantial growth is BC, which constitutes 28 per cent of Canadian production (although it is now on a plateau),” he writes. “Coupled with current BC production, which is mostly committed to existing customers, meeting the NEB export approvals to date would require increasing BC’s gas production to nearly 50 per cent more than all of Canada currently produces – within less than a decade.” (emphasis added)
And that’s easier said than done, says Hughes.
BC’s steep production declines
The decline rates for BC’s shale gas wells may not be quite as severe as Hughes has observed south of the border, but they are steeper than the conventional gas wells that made up BC production in the past.
In the Horn River Basin, near Fort Nelson – the second biggest shale gas play in the province – the 3-year drop-off averages 80%. The province’s biggest play, the Montney Shale near Fort St. John and Hudson’s Hope, the decline rate is 61% for the same period, compared with 69% for the whole province.
As the rate of decline is steepest in the first year, the overall field decline is less, averaging about 26% per year – meaning that on average 26% of BC gas production must be replaced each year by more drilling to keep production flat.
That’s how you get to 50,000 new wells by 2040 to supply BC’s much-vaunted LNG industry.
A warning worth heeding
Though both the NEB and BC Government are likely to pretend this report never came into existence – preferring instead to forge ahead with an industry built on exuberant talk – they are foolish to do so. Mr. Hughes is a man who knows of what he speaks. He headed unconventional gas research during his 32 years with the Geological Survey of Canada (GSC), and, since leaving there, has continued his research, publishing a seminal report earlier this year on shale gas and tight oil production in the US.
Mr. Hughes’ opinion is being sought by people around the world deciding the future of shale gas. In recent months, he has spoken to the European Parliament, academics, energy financiers, and global financial media. The work he’s done in the US is changing the game there and abroad.
But if Christy Clark and our regulator decide to ignore this warning, they do so at the public’s peril – not their own. For none of them will be in their current positions long enough to answer for the catastrophic choices they’re making today.
A visualization of industrial impacts across Canada as of 2010 (Global Forest Watch)
A national study suggests that Alberta has disturbed more natural landscape than any other province.
The analysis by Global Forest Watch adds that Wild Rose Country also has two of the three areas in Canada where the rate of disturbance is the highest.
“There were at least three major hotspots, two in Alberta,” said report author Peter Lee.
The report (download here) combines government data, satellite imagery and cropland maps to look at human intrusions in the last decade into all major Canadian ecozones. Those disruptions included everything from roads to seismic lines to clearcuts to croplands.
“We took all the available credible data sets that we could find and combined them all,” said Lee. “We ended up with what we believe is the best available map of human footprint across Canada.”
Alberta leads in the amount of land disturbed at about 410,000 square kilometres. Almost two-thirds of the province — 62 per cent — has seen industrial or agricultural intrusion.
Saskatchewan, at 46 per cent, is second among the larger provinces. Quebec comes nearest in area with 347,000 square kilometres.
The Maritime provinces actually have the highest rate of disturbance. The human footprint in Prince Edward Island, New Brunswick and Nova Scotia is 94, 85 and 72 per cent respectively of each province’s total area. But those provinces are so relatively small that the actual amount of disturbed land is dwarfed by totals elsewhere.
When Lee compared the current map to one developed about 10 years ago, he found two of three areas where the rate of development was highest were in Alberta as well — one was in the oilsands region; the other along the eastern slopes of the Rockies.
The third area is in a heavily logged part of northern Quebec. New intrusion in northeastern British Columbia, where there is extensive energy development, is almost as heavy.
Lee said development in the three top zones is pushing into previously untouched land at the rate of five to 10 kilometres a year.
The report’s calculations include a 500-metre buffer zone, which corresponds to the distance animals such as woodland caribou tend to keep between themselves and development.
Duncan MacDonnell of Alberta Environment said the government has plans to set aside about 20 per cent of the remaining boreal forest, which covers the northern third of the province.
That includes about 20,000 square kilometres in the oilsands region. MacDonnell said Alberta plans to eventually combine old and new protected areas to create the largest connected boreal conservation area in North America.
Those plans haven’t been implemented and all are the subject of controversy with area aboriginals.
MacDonnell said the province is developing land-use plans for the entire province which are intended to balance pressures on the landscape.
Representatives from the federal government were not available for comment.
Lee notes his findings come at a time when Canadian and provincial policies on development are being increasingly scrutinized, whether they involve forestry, energy or agriculture. He said this sort of basic, common-sense data-gathering should be done by Ottawa.
“It’s those sort of general questions that the person in the street asks,” said Lee. “Where are all the disturbances in Canada? Where are the pristine areas?
“This is a simple monitoring analysis that should be done and could very easily be done by the feds … (but) they’re not doing it.”
The wastewater is created when some of the chemical-laced water used to fracture thick underground rocks flows back out of the wellbore. The water is tainted with chemicals, toxins and in some parts of the country — such as Pennsylvania — naturally occurring radioactive materials, such as radium. Research has shown that even wastewater that had been treated with conventional means was changing the chemistry of rivers when discharged into waterways.
In 2011, Pennsylvania barred drillers from taking the wastewater to treatment facilities, forcing them to haul the fluid waste to be disposed in underground injection wells in Ohio. This, along with a lack of freshwater in other parts of the country needed to drill new wells, has scientists and the industry looking for creative solutions.
Mining waste and fracking radiation – an unlikely marriage
The discovery by Duke University researchers would allow oil and gas drillers to combine flowback waters from the fracking process with acid drainage from mining, or any other salty water. The solids that form, which include radioactive materials, are removed and dumped at a hazardous waste landfill, and then the now cleaner water is used to drill a new well, said Avner Vengosh, the Duke professor who oversaw the project, which included scientists from Dartmouth College and the Technion – Israel Institute of Technology in Haifa.
The metals and radium in the drilling wastewater automatically attract to sulfates — or salts, he explained.
“It’s a romance. It’s inevitable it will combine,” said Vengosh, a professor of geochemistry and water quality.
The research was primarily funded by Duke University, Vengosh said. One of the scientists had some funding from the National Science Foundation, he added.
Vengosh’s research was published in December in the journal Environmental Science and Technology, but still needs to be field tested, he said.
Finding solutions for safely dealing with contaminated water and having enough usable water to drill new wells is crucial for the oil and gas industry. It has booming in recent years due to new methods of hydraulic fracturing — or fracking — a method that uses millions of gallons of chemical-laced water to crack thick layers of underground rock so fossil fuels can flow out.
But as drilling spreads to more areas the industry has faced obstacles. In the gas-rich Marcellus shale region of Pennsylvania, wastewater disposal is problematic. In drought-prone areas, such as Texas and California, drillers face a shortage of freshwater. As a result, the industry is seeking to recycle wastewater.
Vengosh’s researchers blended fracking wastewater from the Marcellus shale with acid drainage from mines, materials collected in western Pennsylvania by the industry. The researchers had hypothesized that the salts, metals and radium would combine so they could be removed as solids, leaving behind water clean enough to be used in another fracking operation, though not quite pure enough to be potable.
After two days, they examined the chemical and radioactive levels of the 26 different mixtures they had created and found that within the first 10 hours the metals — including iron, barium and strontium — and most of the radium had combined to form a new solid. The salinity of the remaining fluid had reduced enough to be used in fracking, Vengosh said.
“I’m not sure it resolves all the problems, but it can have some improvement,” Vengosh said.
Texas facing its own water issues from fracking
Ben Shepperd, president of the Permian Basin Petroleum Association, which represents drillers in an oil-rich, desert-like area of West Texas, said maximizing water use is a top priority for the industry.
“Those of us who live, work and play near oil and gas activities place a premium on efficient water uses,” he said in an email.
But Tad Patzek, chairman and professor of the petroleum engineering department at the University of Texas in Austin, cautioned that the method could present problems in the field. The remaining water would still be jam-packed with chemicals and toxins, he noted.
“That water can get spilled,” Patzek said. “That water can get into a shallow aquifer. There are many other considerations.”
Still, freshwater and wastewater are such serious issues that Donald Van Nieuwenhuise, director of the University of Houston’s geosciences program, said researchers are seeking solutions on several fronts: by recycling flowback water, by creating ways to use less water to begin with or by using a liquid other than water to crack the rock.
Texas doesn’t have acid mine waste, an environmental threat to the Appalachian basin, to mix with the fracking fluids, but the method could be applied in the Lone Star state differently, Van Nieuwenhuise noted. The contaminated drilling water could be mixed with fluids from brine aquifers that are too salty to be used as drinking water, he said.
“This is novel. It’s a really neat idea,” he said, adding that solid waste is safer than liquid and the amount created in this process would be manageable.
CALGARY – A First Nation is appealing a court injunction against a blockade of an energy company’s drilling site in northern Alberta.
The Lubicon Lake Nation says the injunction granted to PennWest Petroleum Ltd. (TSX:PWT) last month gives the company unfettered access to an oil hydraulic fracturing site in the heart of its traditional territory.
The First Nation says PennWest wanted a week-long injunction but the judge gave a six-month injunction on Dec. 16.
The protesters had been blocking an access road to PennWest’s drilling site by Haig Lake since late November.
The group said the protest was peaceful and was intended to stop the company from fracking on traditional Lubicon territory.
The protesting band and the federal and provincial governments have been trying to work out a land claim deal since the 1980s. The province continued to issue energy leases in the area, including around Haig Lake.
The Lubicon Lake Nation claims more than $14 billion worth of oil and gas has been extracted from its territory without their consent.
“This is our land until the Government of Canada enters into an agreement with us,” Chief Bernard Ominayak said in a news release Monday.
[quote]PennWest, the province of Alberta, and the courts cannot simply choose to ignore our inherent rights and assist industry at the expense of our land and our people.[/quote]
Texan Steve Lipsky sparked a heated battle over fracking and water contamination (image: Gasland II)
Despite the shale gas industry’s aggressive efforts to keep a lid on water use and contamination issues relating to its activities, troubling new evidence continues bubbling to the surface, making it increasingly difficult to deny such concerns.
Two big strikes against shale gas industry
In December, a subsidiary of America’s second biggest fracking company, Chesapeake Energy, was hit with a penalties totalling close to $10 million by the US Environmental Protection Agency (EPA) for violations of the Clean Water Act – this in spite of regulatory loopholes that shield shale gas operators from such fines.
Both cases simultaneously demonstrate the lengths to which shale gas operators have gone to protect themselves from investigation and the the ways in which those efforts are beginning to fail.
Industry, governments play defence
Last year, the EPA was forced to abandon a landmark study into water contamination in Wyoming, under intense political and legal pressure, following the release of its damning preliminary findings in 2011. Despite convincing evidence of carcinogenic fracking fluids from Encana’s nearby shale gas operations in two test wells drilled by the EPA, the study was handed off to state authorities far less equipped to conclude the work. It is now being funded in part by the very company under investigation, Encana.
Fracking and water issues in Canada
Arrow shows Talisman’s leaking frackwater pit (Two Island Films)
In neighbouring British Columbia, Natural Gas Minister Rich Coleman and representatives of the Oil and Gas Commission continue to maintain:
[quote]BC’s water supply is protected and safe. It has never been contaminated as a result of hydraulic fracturing.[/quote]
This despite a report by The Common Sense Canadiandetailing clear-cut groundwater contamination from Talisman’s Farrell Creek operations in northeast BC.
EPA finds new tools to take on fracking
Despite the litigious nature of the industry and regulatory capture of governments, it’s getting harder and harder to deny the water contamination issues that surround fracking. According to the New York State Department of Environmental Conservation, as of 2009, fracking companies there were using a cocktail of at least 260 chemicals to help crack open shale formations – including known carcinogens like benzene.
Changes made in 2005 to the US Clean Water Act and Safe Drinking Water Act largely exempted fracking fluids and contaminants from regulation. This led to years of inaction on the part of the EPA – but that has begun to change. The agency employed section 404 of the Clean Water Act, which does not apply to the fracking fluids themselves, to go after Chesapeake recently.
The EPA explained its method as follows:
[quote]The federal government and the West Virginia Department of Environmental Protection (WVDEP) allege that the company impounded streams and discharged sand, dirt, rocks and other fill material into streams and wetlands without a federal permit in order to construct well pads, impoundments, road crossings and other facilities related to natural gas extraction.[/quote]
The result, was a settlement with Chesapeake for approximately “$6.5 million to restore 27 sites damaged by unauthorized discharges of fill material into streams and wetlands…and a civil penalty of $3.2 million, one of the largest ever levied by the federal government for violations of the Clean Water Act (CWA), under the Section 404 program, which requires a federal permit prior to the discharge of dredge or fill material materials into wetlands, rivers, streams, and other waters of the United States.”
Fracked up water in Texas
The announcement of the Chesapeake settlement came just 5 days before another deeply troubling regulatory decision for the industry, involving well water contamination in Texas. After investigating and siding with complaints of water contamination related to Range Resources’ Parker County fracking operations, the EPA’s Region 6 office intervened on behalf of local landowners like Steve Lipsky. The company later sued Lipsky for $3 million over alleged defamation when he publicly linked the ability to light his water on fire to the company’s nearby fracking activities, referencing the EPA’s findings.
Republican Senator and renowned energy industry defender James Inhoffe also interfered with the EPA’s efforts, calling for an internal investigation into the agency’s study and subsequent regulatory intervention. Inhoffe alleged the original investigation was politically motivated by the Obama administration.
Yet, on December 24, the agency’s Inspector General overruled Inhoffe’s complaint. According to Earthworks Gulf regional organizer Sharon Wilson:
[quote]The EPA’s internal watchdog has confirmed that [it] was justified in stepping in to protect residents who were and still are in imminent danger…Now we need an investigation as to whether political corruption caused EPA to withdraw that protection.[/quote]
For landowners like Lipsky, the Obama administration isn’t going far enough to regulate fracking.“President Obama promised that hydraulic fracturing would occur safely,” said Lipsky after learning of the Inspector General’s findings. “With this IG report, it now seems clear that he is determined to squash any evidence to the contrary.”
Even with the EPA’s strengthened position, the battle is far from over, as the state-run Texas Railroad Commission has decided to wade in with its own investigation, which, in another bizarre example of the Byzantine regulatory tangle that continues to protect the industry, could once again usurp the EPA’s ability to halt or control fracking activities in Parker County.
‘Radio-fractivity’
A recent study published in the journal Environmental Science and Technology sounded yet another alarm regarding the threat shale gas poses to groundwater. The study, published by professors at Duke University in October, found concentrations of radium in a tributary of Pennsylvania’s Allegheny river at 200 times normal levels. The radium, along with a number of other contaminants, came from a nearby plant for treating fracking wastewater.
In an interview with Bloomberg, the study’s co-author, Aver Vengosh stated, “The absolute levels that we found are much higher than what you allow in the U.S. for any place to dump radioactive material…The radium will be bio-accumulating. You eventually could get it in the fish.”
Alberta rancher Howard Hawkwood (photo: Green Planet Monitor)
It appears that fracking underground shale beds may release pre-existing radiation along with the gases trapped deep beneath the surface – a veritable Pandora’s box which shale gas companies are unwittingly opening.
These concerns are echoed anecdotally by Alberta cattle rancher Howard Hawkwood, who has lost 10 percent of his his cows over the past year, which he attributes to radiation from fracking operations.
Hawkwood described these dead cows and dead spots on his farm in a recent radio program:
[quote]These are the dead spots in the field, where my cows have urinated. This all showed up last spring…We’ve actually taken soil samples of the dead spot and a sample from a foot and a half away and we’ve got high levels of radon, barium, uranium, strontium, and magnesium is extremely high.[/quote]
Hawks also raises the issue of industry intervention in investigating these problems. He contends it imposes detailed non-disclosure agreements on landowners seeking compensation for damages to their land and health. “The other ranchers are experiencing the same thing but they don’t want to come forward, because they don’t want to create a problem,” says Hawkwood. “Or they have oil and gas on their property and they’ve had to sign non-disclosure agreements. One fellow told me that if he does a cow problem, he phones them and he’s got a cheque in the mail – as long as he doesn’t speak up.”
The issue of “radio-fractivity”, to coin a phrase (you heard it here first), is at an early stage of investigation, but these few indications are already deeply troubling and should raise the level of regulatory caution and research – unfettered by industry and government.
If the fracking industry is as clean as it purports to be, then there is no need for the aggressive tactics it continues to deploy – suing concerned landowners, imposing non-disclosure agreements, pressuring governments to scuttle investigations and create regulatory loopholes to protect them from compelling evidence that they are jeopardizing the health of people and the environment.
Newfoundland’s Gros Morne National Park (Newfoundland and Labrador Tourism)
ST. JOHN’S, N.L. – An oil exploration company that set off intense debate with plans to frack near Gros Morne National Park in western Newfoundland says it will lose its licence next month to drill wells near the UNESCO world heritage site.
CEO Mark Jarvis of Shoal Point Energy Ltd. (CNSX:SPE) said his company’s bid to extend one of three exploration licences it holds in the province was rejected Dec. 5 by the Canada-Newfoundland and Labrador Offshore Petroleum Board.
The company said the decision means his company will lose the licence as of Jan. 15 as well as a $1-million deposit made last January for a one-year extension on drilling exploration wells.
“We are disappointed by this decision,” Jarvis said in a statement Thursday.
Shoal Point Energy and Black Spruce Exploration, a subsidiary of Foothills Capital Corp., had proposed to hunt for oil in shale rock layers in enclaves surrounded by the park using hydraulic fracturing, also known as fracking.
The process involves pumping water, nitrogen, sand and chemical additives at high pressure to fracture shale rock formations and allow gas or oil to flow through well bores to the surface.
The prospect of drilling in the Green Point shale near the picturesque park raised alarms about groundwater pollution and other risks.
In a statement issued Friday the offshore board said it considered and rejected three separate proposals from the company for a one-year extension to its exploration licence.
The board said in making its decision it considered that the licence was issued based on conventional exploration work and that eight years had passed with minimal exploration undertaken.
It said the company’s proposal did not identify a plan to proceed with the drilling obligation on the licence and instead identified “a physical and legal impossibility to undertake a drilling program” in the only format now under consideration.
The board also said the company did not incorporate a forfeiture of its drilling deposit for not meeting the obligations of the licence to date.
Shoal Point Energy said it was willing to give up more than half of the approximately 202 hectares covered by the licence if the board approved the extension, including the portion neighbouring Gros Morne.
The company said it was also prepared to make an additional drilling deposit of $250,000, but the board denied both requests.
Jarvis said the Vancouver-based company felt its application respected the importance of the park.
“Our proposal balanced a desire to protect this unique and beautiful park with a desire to safely and responsibly develop a much-needed economic opportunity on the west coast of Newfoundland,” he said.
In total, the company’s three licences cover approximately 291 hectares in western Newfoundland.
“We still have a very large prospective resource to explore and develop in our remaining exploration licences,” said Jarvis. “We believe that the majority of people in this area want economic opportunity, as long as they are satisfied that operations are safe and respect the environment.”
Fracking operation in northeast BC’s Horn River (Two Island Films/Fractured Land)
A First Nation with un-surrendered traditional territory in both northern BC and the Yukon passed a motion late last week banning fracking. On December 5, the Carcross/Tagish First Nation (C/TFN) General Council ratified an earlier motion from the nation’s Executive Council, opposing the controversial natural gas extraction process on its territory.
“It’s our responsibility to protect our lands and water for future generations,” said the Executive Council’s George Shepherd, who moved the motion.
[quote]Not only is fracking a completely ineffective way to extract resources, it would cause a great deal of harm to the land we take such great pride in.[/quote]
The motion grew out of work by C/TFN’s Land Use team, which weighed potential economic benefits against anticipated environmental impacts from fracking. In the end, the team found “the use of fracking doesn’t make any sense,” says Lands Manager Frank James.
“It’s our responsibility to protect the environment and our Traditional Territory, which includes the headwaters of the Yukon river,” said C/TFN’s Khà Shâde Héni, Danny Cresswell.
[quote]The harm a fracking project would cause to the land and waterways would not be worth the revenues. Not to mention the damage it would cause to the natural landscape, which is something we would never be able to recover.[/quote]
The move comes amid widespread debate about the merits and trade-offs of fracking, which has prompted two Canadian provinces – Quebec and Newfoundland and Labrador – and a number of other countries to pass fracking bans and moratoria.
C/TFN’s members are mostly located in the Yukon but the nation holds 4,000 square miles of territory on the BC side of the border as well, where there is intense pressure to expand fracking operations in order to feed the province’s ambitious, proposed liquefied natural gas (LNG) industry.
That concern is now spreading north to potential future fracking plays in the Yukon. C/TFN joins fellow Yukon First Nations, the Vuntut-Gwitchin of Old Crow, whose members passed a motion at their annual general assembly in August opposing fracking in their northern Yukon territory.
In October, a protest near Rexton turned violent when police enforced a court-ordered injunction to halt the blockade of a compound used by SWN Resources to store equipment.
SWN Resources, a wholly owned subsidiary of U.S.-based Southwestern Energy Company, was recently granted another injunction that provides a buffer zone around its equipment in order to complete its work.
