Posted on June 28, 2012 at 4:04 pm by Jennifer A. Dlouhy

The Obama administration on Thursday finalized a five-year plan for offshore drilling that focuses on allowing development in already-explored areas of the Gulf of Mexico and the Arctic to the chagrin of oil and gas companies who were hoping for more territory. The first sale of leases under the Interior Department’s 2012-2017 plan is set to take place this fall, with areas of the western Gulf of Mexico up for grabs. Eleven more Gulf of Mexico sales are planned, as well as three auctions of leases in the Cook Inlet near Anchorage and the Chukchi and Beaufort seas north of Alaska. The plan rules out lease sales in Atlantic waters, despite pressure from Virginia officials eager for oil and gas development off the commonwealth’s shores.

Interior Secretary Ken Salazar described the plan as “smart,” but “aggressive,” with planned auctions of waters around Alaska targeted to areas that have both big potential energy resources and small environmental and other conflicts.

But oil industry representatives and their allies in Congress said the administration’s plan would keep promising areas off the table. American Petroleum Institute Upstream Director Erik Milito said the program demonstrated “unnecessary restraint.”
The plan “makes more areas off limits than it makes available,” Milito said, adding that the program’s focus on the Gulf of Mexico overlooks promising new areas for development in the Atlantic and Pacific oceans. “While vitally important, the western and central Gulf of Mexico areas including in this proposed offshore program are not new areas,” Milito said.

Rep. Doc Hastings, R-Wash., the head of the House Natural Resources Committee, said the plan offers “a bleak future for American energy production” because it keeps the East and West Coast “under lock and key.”
And Randall Luthi, a former drilling regulator that heads the National Ocean Industries Association, called the administration’s plan “deeply disappointing.”

“Taking the entire East and West coasts off the table and further delaying Alaska sales clearly shows this administration is not following its own advice to lessen our dependence on foreign sources of energy by bolstering production here at home,” Luthi said.
The final 5-year plan, which replaces a Bush-era leasing program that ends June 30, is nearly identical to a proposal the Interior Department unveiled last November. The biggest change is a decision to delay a planned Beaufort Sea lease sale from 2015 to 2017.

Sales of drilling rights in the Chukchi Sea and Cook Inlet would take place in 2016. The oil industry recently has not had a big appetite to drill in federal Cook Inlet waters. But after the Bureau of Ocean Energy Management recently asked oil and gas companies about the region, there was enough support to move forward with a planned sale, said bureau Director Tommy Beaudreau. He described the industry interest as “significant.”

The Obama administration’s leasing plan continues a tradition in the Gulf of holding area-wide lease sales, with much of the non-leased acreage up for grabs.

But when it comes to the Arctic and Alaskan waters, the government is taking a different approach, borrowed from its handling of oil and gas drilling on federal lands. There, the acreage on the auction block will be selected to avoid harming wildlife and the native Alaskan communities that depend on whaling and fishing for food, Beaudreau said.
Many of the native Alaskan communities are “dependent on the ocean resources, literally, for survival,” Beaudreau said. “We need to be respectful of that, and we need to be protective of that.”

Salazar said that he fully expected the Arctic lease sales to go forth as planned, but stressed the importance of carefully selecting areas for auction. Already, the final five-year leasing plan walls off some areas north of Barrow, Alaska for development because of the subsistence whaling in the region. The administration also will preserve an existing 25-mile buffer zone along Alaska’s Chukchi Sea coastline and wall off the Hanna Shoal area that is home to a high concentration of marine life.

Shell Oil Co. is poised to begin exploratory drilling in the Chukchi and Beaufort seas this summer, under leases it purchased in 2005, 2007 and 2008. If that work is authorized as expected, it will add to the body of knowledge about the area’s potential oil and gas resources and guide future lease sales, Salazar said. Planned development in Canada’s Arctic waters as well as extensive scientific study also will be factored in, Salazar said. Salazar argued that there is too little information about potential oil and gas along the Atlantic coast _ including where it might be located _ “to make credible decisions” about drilling there. The Department of Defense has raised concerns about oil and gas drilling in some areas off the Virginia coast.

Environmentalists said the plan puts pristine Arctic areas up for grabs. “President Obama is doubling down on risky offshore oil development when he should be investing in clean energy,” said Miyoko Sakashita, oceans program director for the Arizona-based Center for Biological Diversity.

Special thanks to Richard Charter

http://www.reuters.com/article/2012/06/27/us-usa-lng-exports-idUSBRE85Q05820120627

By Ayesha Rascoe and Emily Stephenson
WASHINGTON | Wed Jun 27, 2012 1:45am EDT

(Reuters) – In a bitterly divided U.S. political environment, there’s at least one thing Republicans and Democrats can agree on: Avoid a public showdown on natural gas exports, arguably the most important energy policy decision in recent memory.

While fluctuating gasoline prices, the Keystone pipeline and the fight over fracking steal headlines, the question of how much of the newfound U.S. shale gas bounty should be shared with the rest of the world goes largely without comment or coverage — despite holding far wider and longer-lasting consequences.

The reason is clear: unlike the relatively simple, black-and-white issues that politicians often favor and voters connect to, liquefied natural gas (LNG) is deep, deep gray.

It affects a tangled web of constituents, from Big Oil to international allies such as Japan, pits free-trade orthodoxy against the domestic economy, and requires an awkward explanation of why allowing some exports — inevitably raising U.S. energy prices in the short term, even if at the margin — may ultimately be better for the country in the long run.
All the same, this U.S. president or the next will have to make a tricky decision, and its consequences may only become clear years from now: How much U.S. gas should be sold to other countries if it means boosting prices for consumers at home?

“Right now I don’t think this issue is getting anywhere near the attention it deserves,” said Democratic congressman Edward Markey, one of a small number of politicians actively seeking to rein in energy exports.

“Keystone and Solyndra are election-year political sideshows,” he said, referring to the bankruptcy of a government-funded solar panel maker. “This is the main event.”

But lobbyists on both sides of the issue say it suits them best to keep the subject out of the headlines. The gas producers that stand to benefit from higher selling prices see no upside from a public brawl, while many manufacturers who could benefit from continuing low prices shy away from anti-export statements.

With Congress unlikely to weigh in, the decision falls to a small, obscure unit of the Energy Department, the Office of Natural Gas Regulatory Activities.

The department’s statistical branch has been criticized for failing to predict how new drilling techniques would revolutionize the sector, and how quickly the vast stores of unearthed gas would send domestic prices to unsustainable lows.

So the natural gas office is now awaiting advice from a second and final report on the economic implications of exports — a report so sensitive that the government has kept it under wraps, including the identity of the consultants preparing it.

SHHHHHHHH, SOFTLY-SOFTLY
Not since the liberalization of power markets in the 1980s have politicians had more sway over future energy costs — or been less willing to grapple publicly with the issue.
Only one hearing on LNG exports has been held to date in the Senate, and in the House of Representatives, the Energy and Commerce Committee has no plan to hold hearings at the moment.

Markey has struggled to get traction behind legislation that would block gas exports, a measure almost certain to fail to pass through the divided Congress. Few lawmakers openly oppose exports, though even fewer vocally advocate a fully open market that would raise prices at home.

The Obama administration has said it will wait until the gas office releases the final economic analysis of LNG exports to make any decision on eight pending applications to sell liquefied natural gas to countries with which the United States has no free-trade agreement — the most political step of the multiple state and federal approvals needed to send LNG abroad.

The report was due out this spring, but in March the administration pushed back the release until later in the year. A White House official said on Monday the report could be released in the next few weeks.

Overall, the boom in the energy sector, coupled with a slow recovery in domestic manufacturing, could raise gross domestic product by 2 to 3.3 percent by 2020, according to a recent analysis by Citigroup. But exports could force politicians to play favorites, effectively choosing between energy companies and industry.

Democrats, often critical of the oil and gas sector, are wary of getting out in front of an issue that divides even the manufacturers benefitting from low gas prices. Republicans, who favor free trade and support fossil fuel development, are leery of being accused of raising costs for consumers and industry.

“No politician wants to be accused of raising end-user prices to add to oil companies’ bottom lines,” says Kevin Book, an energy analyst at Clearview Energy Partners.
So for most officials willing to take a stand, it is inevitably one of moderation. Few are ready to weigh in on the toughest question: How much is too much?

Senator Ron Wyden, a Democrat who has backed the pause in the permitting process, knows how quickly fortunes can change: just a few years ago he witnessed the battle over the prospect of a gas import terminal in his home state of Oregon at a time when the industry was convinced of a growing U.S. gas deficit.

Instead, the pioneering use of hydraulic fracturing and horizontal drilling has lifted economically recoverable U.S. reserves of natural gas to 500 trillion cubic feet, a previously unimaginable level.

“I’ve always supported market-expanding agreements, and I’m trying to balance that with the fact that, with natural gas, America now has a strategic advantage,” Wyden said.

“This is something where we now lead. I just want to make sure we don’t trade it away,” said Wyden, who is in line to be the top Democrat on the Senate energy committee next year. Unlike Markey, he has no plans to push legislation that would prevent exports, an acknowledgement of the issue’s complexity.

Republicans in the House Energy and Commerce Committee believe gas companies would likely export marginal amounts compared to the current supply, and any price effects will be minimal.

“If we don’t have some sort of exports, it’s not going to be economic to produce as much gas here,” a committee Republican aide said.

CONFLICT ON CONFLICT
Congressman Gene Green, a Democrat on the House energy committee who represents the greater part of eastern Houston, said he supports LNG export projects — on a case-by-case basis. His district includes a chemical complex, and such plants tend to be large consumers of natural gas. Several companies plan to build new U.S. facilities to take advantage of now-low prices.

“We can simultaneously have reasonable natural gas prices that foster chemical industry expansion while we export natural gas,” Green said.

Energy-intensive manufacturers are keen to use cheap gas to boost domestic production, but many companies also have plants overseas that could benefit from U.S. gas exports.

Others are wary of advocating any measures that would impinge on free trade. They too are taking a quiet, moderate stance.

Although Dow Chemical is a major consumer of natural gas, it supports a limited amount of exports, controlled perhaps by some kind of quota based on total gas production.

“As a proponent of fair and free trade, (Dow) opposes policies that arbitrarily limit reasonable exports of natural gas to free-trade agreement countries or that provide for unlimited global exports,” the company said in a statement.

BIG STAKES
The surge in gas output has made companies such as Chesapeake and Exxon Mobil’s XTO victims of their own success, unleashing a surplus of supply that could keep prices — and therefore profits — depressed for decades.

For them, selling gas to Japan or Europe — which buys imported LNG at five or six times the domestic price of $2.50 per million British thermal units — is essential to continue expanding their U.S. business, creating jobs in the process.

The shale gas boom is on track to support 1.5 million jobs across the United States by 2015, according to an industry-funded study by IHS Global Insight.

Export licenses will make big winners out of some firms such as Cheniere, which last year secured the first and, so far, only export permit from the Energy Department.

For those that get the green light, the multibillion-dollar terminals are likely to be buzzing for decades, freezing and compressing the gas at a temperature of -260 degrees Fahrenheit (-162 Celsius) for seaborne shipment on special tankers.

But others in the queue — which includes firms from utility Southern Co to gas giant BG Group and Australian bank Macquarie — could come out disappointed, as few analysts expect all the projects to be approved.

“I don’t think they are going to give blanket approval to all takers, but on a case-by-case basis, I think they would be favorably disposed if the supply is there,” said Frank Verrastro, director of the energy and national security program at the Center for Strategic and International Studies.

The eight projects pending review span from Maryland to Oregon. Including Cheniere’s Sabine Pass in Louisiana, these sites could export more than 12 billion cubic feet per day of gas — equivalent to about one-sixth of current U.S. demand.

TAPPING THE BOUNTY
If the gap between global and domestic prices remains wide, as many analysts expect, more export projects are certain to be brought forward and the government may draw a line in the sand.

A ban on energy exports is not without precedent. The Mineral Leasing Act of 1920 and the Outer Continental Shelf Lands Act require a presidential waiver for the sale of most unrefined crude oil abroad, essentially blocking exports.

Even with a boom in domestic oil output, the United States is in little danger of becoming an oil exporter. But gas is far less fraught with geopolitical significance.

“Oil has been a political issue. Natural gas has never been that,” said David Wochner, an attorney for the Sutherland law firm that represents natural gas producers.

Heather Zichal, a White House energy adviser, told a recent conference that the administration was not opposed to exports and that it wanted “analysis to drive the decisions”.

That puts the burden squarely on the Energy Department’s natural gas regulatory office and its coming report.

It remains to be seen whether the prognosis from the department’s commissioned study is more prescient than previous examinations of the shale gas surge, which has proven extraordinarily hard to predict.

A much-critiqued, department-commissioned analysis earlier from the Energy Information Administration found that approving all pending export applications could add as much as 9 percent a year to prices of the fuel in the next two decades.

A more recent report from the Brookings Institution moderated the EIA finding, predicting that sending U.S. gas abroad would have only a “modest” upward impact on prices and that U.S. manufacturers would stay competitive despite exports.

The department has declined to commit publicly to any timeline for evaluating the export applications. Facing no legislative deadline to act, it can essentially stretch out or speed up the process to its liking.

It is already honing its rationale, including the benefit of using exports as a “balancing” mechanism for the market, one that has been so volatile over past decades that drillers and users have struggled to make long-term plans.

“One of the potential impacts that you might have from LNG exports would be creating a stable block of demand, which helps the market get to a stable sustainable price,” Christopher Smith, deputy assistant secretary in the department’s office of fossil energy, told Reuters in February.

APPROVALS: WAIT AND SEE
The American Public Gas Association, a lobby group representing publicly owned gas distributors, has been one of the few groups to press lawmakers against exports and supports Markey’s legislation.

On the other side of the debate, the Center for Liquefied Natural Gas, a trade group that represents LNG companies, has been reaching out to lawmakers in Congress to “educate” on the process for approving exports.

It spent $40,000 on lobbying last year and about $10,000 in the first quarter of 2012, according to data from the Center for Responsive Politics. Cheniere spent $520,000 on lobbying last year, and $80,000 so far this year.

The LNG group does not want hearings or legislation. It wants Congress to step back and let the Department of Energy decide.

“There’s nothing we want done other than letting DOE do its job,” said Bill Cooper, the center’s president. “We want people to know about the process and that it does work when it’s allowed to.”

(Additional reporting by Roberta Rampton and Lily Kuo; Editing by Russell Blinch and Dale Hudson)

Special thanks to Richard Charter

http://www.pennenergy.com/index/petroleum/display/1225558377/articles/pennenergy/petroleum/offshore/2012/june/researchers-track.html?cmpid=EnlDailyPetroJune272012

June 26, 2012

A new report from researchers at the University of Florida illustrates that the 2010 Deepwater Horizon oil spill contributed significantly to the destruction of marshes in Louisiana, according to The Washington Post.

Led by professor Brian Silliman, the group investigated the rate of erosion at marshes in the state that were exposed to substantial amounts of oil compared to those that saw relatively minimal exposure.

They found that the oiled marshes eroded at twice the usual rate for the state’s marshes, as the marshes’ heavy grasses died and their roots ceased to hold together the banks of loose soil. However, the presence of the grasses did limit exposure in the area, as oil became trapped within the vegetation.

While the impact from the spill was significant, Silliman noted that the long-term effects of changes to the Mississippi river and rising sea levels were having a more dramatic impact on the marshes, but the research provides a better understanding of the impact oil spills can have on certain sensitive coastal regions.

The region has also moved past the incident to an extent, as Bloomberg reports BP recently won new oil leases near the destroyed rig.

An analysis of the impact of the Gulf oil spill can be found at PennEnergy’s Research area.

Special thanks to Richard Charter

http://www.propublica.org/article/injection-wells-the-poison-beneath-us

Injection Wells: The Poison Beneath Us

by Abrahm Lustgarten

ProPublica, June 21, 2012, 9:20 a.m.

Over the past several decades, U.S. industries have injected more than 30 trillion gallons of toxic liquid deep into the earth, using broad expanses of the nation’s geology as an invisible dumping ground.

No company would be allowed to pour such dangerous chemicals into the rivers or onto the soil. But until recently, scientists and environmental officials have assumed that deep layers of rock beneath the earth would safely entomb the waste for millennia.

There are growing signs they were mistaken.

Records from disparate corners of the United States show that wells drilled to bury this waste deep beneath the ground have repeatedly leaked, sending dangerous chemicals and waste gurgling to the surface or, on occasion, seeping into shallow aquifers that store a significant portion of the nation’s drinking water.

In 2010, contaminants from such a well bubbled up in a west Los Angeles dog park. Within the past three years, similar fountains of oil and gas drilling waste have appeared in Oklahoma and Louisiana. In South Florida, 20 of the nation’s most stringently regulated disposal wells failed in the early 1990s, releasing partly treated sewage into aquifers that may one day be needed to supply Miami’s drinking water.

There are more than 680,000 underground waste and injection wells nationwide, more than 150,000 of which shoot industrial fluids thousands of feet below the surface. Scientists and federal regulators acknowledge they do not know how many of the sites are leaking.

Federal officials and many geologists insist that the risks posed by all this dumping are minimal. Accidents are uncommon, they say, and groundwater reserves – from which most Americans get their drinking water – remain safe and far exceed any plausible threat posed by injecting toxic chemicals into the ground.

But in interviews, several key experts acknowledged that the idea that injection is safe rests on science that has not kept pace with reality, and on oversight that doesn’t always work.

“In 10 to 100 years we are going to find out that most of our groundwater is polluted,” said Mario Salazar, an engineer who worked for 25 years as a technical expert with the EPA’s underground injection program in Washington. “A lot of people are going to get sick, and a lot of people may die.”

The boom in oil and natural gas drilling is deepening the uncertainties, geologists acknowledge. Drilling produces copious amounts of waste, burdening regulators and demanding hundreds of additional disposal wells. Those wells – more holes punched in the ground – are changing the earth’s geology, adding man-made fractures that allow water and waste to flow more freely.

“There is no certainty at all in any of this, and whoever tells you the opposite is not telling you the truth,” said Stefan Finsterle, a leading hydrogeologist at Lawrence Berkeley National Laboratory who specializes in understanding the properties of rock layers and modeling how fluid flows through them. “You have changed the system with pressure and temperature and fracturing, so you don’t know how it will behave.”

A ProPublica review of well records, case histories and government summaries of more than 220,000 well inspections found that structural failures inside injection wells are routine. From late 2007 to late 2010, one well integrity violation was issued for every six deep injection wells examined – more than 17,000 violations nationally. More than 7,000 wells showed signs that their walls were leaking. Records also show wells are frequently operated in violation of safety regulations and under conditions that greatly increase the risk of fluid leakage and the threat of water contamination.

Structurally, a disposal well is the same as an oil or gas well. Tubes of concrete and steel extend anywhere from a few hundred feet to two miles into the earth. At the bottom, the well opens into a natural rock formation. There is no container. Waste simply seeps out, filling tiny spaces left between the grains in the rock like the gaps between stacked marbles.

Many scientists and regulators say the alternatives to the injection process – burning waste, treating wastewater, recycling, or disposing of waste on the surface – are far more expensive or bring additional environmental risks.

Subterranean waste disposal, they point out, is a cornerstone of the nation’s economy, relied on by the pharmaceutical, agricultural and chemical industries. It’s also critical to a future less dependent on foreign oil: Hydraulic fracturing, “clean coal” technologies, nuclear fuel production and carbon storage (the keystone of the strategy to address climate change) all count on pushing waste into rock formations below the earth’s surface.

The U.S. Environmental Protection Agency, which has primary regulatory authority over the nation’s injection wells, would not discuss specific well failures identified by ProPublica or make staffers available for interviews. The agency also declined to answer many questions in writing, though it sent responses to several. Its director for the Drinking Water Protection Division, Ann Codrington, sent a statement to ProPublica defending the injection program’s effectiveness.

“Underground injection has been and continues to be a viable technique for subsurface storage and disposal of fluids when properly done,” the statement said. “EPA recognizes that more can be done to enhance drinking water safeguards and, along with states and tribes, will work to improve the efficiency of the underground injection control program.”

Still, some experts see the well failures and leaks discovered so far as signs of broader problems, raising concerns about how much pollution may be leaking out undetected. By the time the damage is discovered, they say, it could be irreversible.

“Are we heading down a path we might regret in the future?” said Anthony Ingraffea, a Cornell University engineering professor who has been an outspoken critic of claims that wells don’t leak. “Yes.”

***

In September 2003, Ed Cowley got a call to check out a pool of briny water in a bucolic farm field outside Chico, Texas. Nearby, he said, a stand of trees had begun to wither, their leaves turning crispy brown and falling to the ground.

Chico, a town of about 1,000 people 50 miles northwest of Fort Worth, lies in the heart of Texas’ Barnett Shale. Gas wells dot the landscape like mailboxes in suburbia. A short distance away from the murky pond, an oil services company had begun pumping millions of gallons of drilling waste into an injection well.

Regulators refer to such waste as salt water or brine, but it often includes less benign contaminants, including fracking chemicals, benzene and other substances known to cause cancer.

The well had been authorized by the Railroad Commission of Texas, which once regulated railways but now oversees 260,000 oil and gas wells and 52,000 injection wells. (Another agency, the Texas Commission on Environmental Quality, regulates injection wells for waste from other industries.)

Before issuing the permit, commission officials studied mathematical models showing that waste could be safely injected into a sandstone layer about one-third of a mile beneath the farm. They specified how much waste could go into the well, under how much pressure, and calculated how far it would dissipate underground. As federal law requires, they also reviewed a quarter-mile radius around the site to make sure waste would not seep back toward the surface through abandoned wells or other holes in the area.
Yet the precautions failed. “Salt water” brine migrated from the injection site and shot back to the surface through three old well holes nearby.

“Have you ever seen an artesian well?” recalled Cowley, Chico’s director of public works. “It was just water flowing up out of the ground.”

Despite residents’ fears that the injected waste could be making its way toward their drinking water, commission officials did not sample soil or water near the leak.
If the injection well waste “had threatened harm to the ground water in the area, an in-depth RRC investigation would have been initiated,” Ramona Nye, a spokeswoman for Texas’ Railroad Commission, wrote in an email.

The agency disputes Cowley’s description of a pool of brine or of dead trees, saying that the waste barely spilled beyond the overflowing wells, though officials could not identify any documents or staffers who contradicted Cowley’s recollections. Accounts similar to Cowley’s appeared in an article about the leak in the Wise County Messenger, a local newspaper. The agency has destroyed its records about the incident, saying it is required to keep them for only two years.

After the breach, the commission ordered two of the old wells to be plugged with cement and restricted the rate at which waste could be injected into the well. It did not issue any violations against the disposal company, which had followed Texas’ rules, regulators said. The commission allowed the well operator to continue injecting thousands of barrels of brine into the well each day. A few months later, brine began spurting out of three more old wells nearby.

“It’s kind of like Whac-a-Mole, where one thing pops up and by the time you go to hit it, another thing comes up,” Cowley said. “It was frustrating. … If your water goes, what does that do to the value of your land?”

Deep well injection takes place in 32 states, from Pennsylvania to Michigan to California. Most wells are around the Great Lakes and in areas where oil and gas is produced: along the Appalachian crest and the Gulf Coast, in California and in Texas, which has more wells for hazardous industrial waste and oil and gas waste than any other state.

Federal rules divide wells into six classes based on the material they hold and the industry that produced it. Class 1 wells handle the most hazardous materials, including fertilizers, acids and deadly compounds such as asbestos, PCBs and cyanide. The energy industry has its own category, Class 2, which includes disposal wells and wells in which fluids are injected to force out trapped oil and gas. The most common wells, called Class 5, are a sort of catch-all for everything left over from the other categories, including storm-water runoff from gas stations.

The EPA requires that Class 1 and 2 injection wells be drilled the deepest to assure that the most toxic waste is pushed far below drinking water aquifers. Both types of wells are supposed to be walled with multiple layers of steel tubing and cement and regularly monitored for cracks.

Officials’ confidence in this manner of disposal stems not only from safety precautions, but from an understanding of how rock formations trap fluid.

Underground waste, officials say, is contained by layer after layer of impermeable rock. If one layer leaks, the next blocks the waste from spreading before it reaches groundwater. The laws of physics and fluid dynamics should ensure that the waste can’t spread far and is diluted as it goes.

The layering “is a very strong phenomenon and it’s on our side,” said Susan Hovorka, a senior research scientist at the University of Texas at Austin’s Bureau of Economic Geology.

According to risk analyses cited in EPA documents, a significant well leak that leads to water contamination is highly unlikely – on the order of one in a million.

Once waste is underground, though, there are few ways to track how far it goes, how quickly or where it winds up. There is plenty of theory, but little data to prove the system works.

“I do think the risks are low, but it has never been adequately demonstrated,” said John Apps, a leading geoscientist who advises the Department of Energy for Lawrence Berkeley National Labs. “Every statement is based on a collection of experts that offer you their opinions. Then you do a scientific analysis of their opinions and get some probability out of it. This is a wonderful way to go when you don’t have any evidence one way or another… But it really doesn’t mean anything scientifically.”

The hard data that does exist comes from well inspections conducted by federal and state regulators, who can issue citations to operators for injecting illegally, for not maintaining wells, or for operating wells at unsafe pressures. This information is the EPA’s primary means of tracking the system’s health on a national scale.

Yet, in response to questions from ProPublica, the EPA acknowledged it has done very little with the data it collects. The agency could not provide ProPublica with a tally of how frequently wells fail or of how often disposal regulations are violated. It has not counted the number of cases of waste migration or contamination in more than 20 years.
The agency often accepts reports from state injection regulators that are partly blank, contain conflicting figures or are missing key details, ProPublica found.

In 2007, the EPA launched a national data system to centralize reports on injection wells. As of September 2011 – the last time the EPA issued a public update – less than half of the state and local regulatory agencies overseeing injection were contributing to the database. It contained complete information from only a handful of states, accounting for a small fraction of the deep wells in the country.

The EPA did not respond to questions seeking more detail about how it handles its data, or about how the agency judges whether its oversight is working.

In a 2008 interview with ProPublica, one EPA scientist acknowledged shortcomings in the way the agency oversees the injection program.

“It’s assumed that the monitoring rules and requirements are in place and are protective – that’s assumed,” said Gregory Oberley, an EPA groundwater specialist who studies injection and water issues in the Rocky Mountain region. “You’re not going to know what’s going on until someone’s well is contaminated and they are complaining about it.”

***

ProPublica’s analysis of case histories and EPA data from October 2007 to October 2010 showed that when an injection well fails, it is most often because of holes or cracks in the well structure itself.

Operators are required to do so-called “mechanical integrity” tests at regular intervals, yearly for Class 1 wells and at least once every five years for Class 2 wells. In 2010, the tests led to more than 7,500 violations nationally, with more than 2,300 wells failing. In Texas, one violation was issued for every three Class 2 wells examined in 2010.

Such breakdowns can have serious consequences. Damage to the cement or steel casing can allow fluids to seep into the earth, where they could migrate into water supplies.

Regulators say redundant layers of protection usually prevent waste from getting that far, but EPA data shows that in the three years analyzed by ProPublica, more than 7,500 well test failures involved what federal water protection regulations describe as “fluid migration” and “significant leaks.”

In September 2009, workers for Unit Petroleum Company discovered oil and gas waste in a roadside ditch in southern Louisiana. After tracing the fluid to a crack in the casing of a nearby injection well, operators tested the rest of the well. Only then did they find another hole – 600 feet down, and just a few hundred feet away from an aquifer that is a source of drinking water for that part of the state.

Most well failures are patched within six months of being discovered, EPA data shows, but with as much as five years passing between integrity tests, it can take a while for leaks to be discovered. And not every well can be repaired. Kansas shut down at least 47 injection wells in 2010, filling them with cement and burying them, because their mechanical integrity could not be restored. Louisiana shut down 82. Wyoming shut down 144.

Another way wells can leak is if waste is injected with such force that it accidentally shatters the rock meant to contain it. A report published by scientists at the Department of Energy’s Pacific Northwest National Laboratory and the University of Texas said that high pressure is “the driving force” that can help connect deep geologic layers with shallower ones, allowing fluid to seep through the earth.

Most injection well permits strictly limit the maximum pressure allowed, but well operators – rushing to dispose of more waste in less time – sometimes break the rules, state regulatory inspections show. According to data provided by states to the EPA, deep well operators have been caught exceeding injection pressure limits more than 1,100 times since 2008.

Excessive pressure factored into a 1989 well failure that yielded new clues about the risks of injection.

While drilling a disposal well in southern Ohio, workers for the Aristech Chemical Corp. (since bought by Sunoco, and sold again, in 2011, to Haverhill Chemicals) were overwhelmed by the smell of phenol, a deadly chemical the company had injected into two Class 1 wells nearby. Somehow, perhaps over decades, the pollution had risen 1,400 feet through solid rock and was progressing toward surface aquifers.

Ohio environmental officials – aided by the EPA – investigated for some 15 years. They concluded that the wells were mechanically sound, but Aristech had injected waste into them faster and under higher pressure than the geologic formation could bear.

Though scientists maintain that the Aristech leak was a rarity, they acknowledge that such problems are more likely in places where industrial activity has changed the underground environment.

There are upwards of 2 million abandoned and plugged oil and gas wells in the U.S., more than 100,000 of which may not appear in regulators’ records. Sometimes they are just broken off tubes of steel, buried or sticking out of the ground. Many are supposed to be sealed shut with cement, but studies show that cement breaks down over time, allowing seepage up the well structure.

Also, if injected waste reaches the bottom of old wells, it can quickly be driven back toward aquifers, as it was in Chico.

“The United States looks like a pin cushion,” said Bruce Kobelski, a geologist who has been with the agency’s underground injection program since 1986. Kobelski spoke to ProPublica in May, 2011, before the EPA declined additional interview requests for this story. “Unfortunately there are cases where someone missed a well or a well wasn’t indicated. It could have been a well from the turn of the [20th] century.”

Clefts left after the earth is cracked open to frack for oil and gas also can connect abandoned wells and waste injection zones. How far these man-made fissures go is still the subject of research and debate, but in some cases they have reached as much as a half-mile, even intersecting fractures from neighboring wells.

When injection wells intersect with fracked wells and abandoned wells, the combined effect is that many of the natural protections assumed to be provided by deep underground geology no longer exist.

“It’s a natural system and if you go in and start punching holes through it and changing pressure systems around, it’s no longer natural,” said Nathan Wiser, an underground injection expert working for the EPA in its Rocky Mountain region, in a 2010 interview. “It’s difficult to know how it would behave in those circumstances.”

EPA data provides a window into some injection well problems, but not all. There is no way to know how many wells have undetected leaks or to measure the amount of waste escaping from them.

In at least some cases, records obtained by ProPublica show, well failures may have contaminated sources of drinking water. Between 2008 and 2011, state regulators reported 150 instances of what the EPA calls “cases of alleged contamination,” in which waste from injection wells purportedly reached aquifers. In 25 instances, the waste came from Class 2 wells. The EPA did not respond to requests for the results of investigations into those incidents or to clarify the standard for reporting a case.

The data probably understates the true extent of such incidents, however.

Leaking wells can simply go undetected. One Texas study looking for the cause of high salinity in soil found that at least 29 brine injection wells in its study area were likely sending a plume of salt water up into the ground unnoticed. Even when a problem is reported, as in Chico, regulators don’t always do the expensive and time-consuming work necessary to investigate its cause.

“The absence of episodes of pollution can mean that there are none, or that no one is looking,” said Salazar, the EPA’s former injection expert. “I would tend to believe it is the latter.”

***

The practice of injecting waste underground arose as a solution to an environmental crisis.

In the first half of the 20th century, toxic waste collected in cesspools, or was dumped in rivers or poured onto fields. As the consequences of unbridled pollution became unacceptable, the country turned to an out-of-sight alternative. Drawing on techniques developed by the oil and gas industry, companies started pumping waste back into wells drilled for resources. Toxic waste became all but invisible. Air and water began to get cleaner.

Then a host of unanticipated problems began to arise.

In April, 1967 pesticide waste injected by a chemical plant at Denver’s Rocky Mountain Arsenal destabilized a seismic fault, causing a magnitude 5.0 earthquake – strong enough to shatter windows and close schools – and jolting scientists with newfound risks of injection, according to the U.S. Geological Survey.

A year later, a corroded hazardous waste well for pulping liquor at the Hammermill Paper Co., in Erie, Pa., ruptured. Five miles away, according to an EPA report, “a noxious black liquid seeped from an abandoned gas well” in Presque Isle State Park.

In 1975 in Beaumont, Texas, dioxin and a highly acidic herbicide injected underground by the Velsicol Chemical Corp. burned a hole through its well casing, sending as much as five million gallons of the waste into a nearby drinking water aquifer.

Then in August 1984 in Oak Ridge, Tenn., radioactive waste was turned up by water monitoring near a deep injection well at a government nuclear facility.

Regulators raced to catch up. In 1974, the Safe Drinking Water Act was passed, establishing a framework for regulating injection. Then, in 1980, the EPA set up the tiered classes of wells and began to establish basic construction standards and inspection schedules. The EPA licensed some state agencies to monitor wells within their borders and handled oversight jointly with others, but all had to meet the baseline requirements of the federal Underground Injection Control program.

Even with stricter regulations in place, 17 states – including Alabama, North Carolina, South Carolina and Wisconsin – banned Class 1 hazardous deep well injection.

“We just felt like based on the knowledge that we had at that time that it was not something that was really in the best interest of the environment or the state,” said James Warr, who headed Alabama’s Department of Environmental Management at the time.

Injection accidents kept cropping up.

A 1987 General Accountability Office review put the total number of cases in which waste had migrated from Class 1 hazardous waste wells into underground aquifers at 10 – including the Texas and Pennsylvania sites. Two of those aquifers were considered potential drinking water sources.

In 1989, the GAO reported 23 more cases in seven states where oil and gas injection wells had failed and polluted aquifers. New regulations had done little to prevent the problems, the report said, largely because most of the wells involved had been grandfathered in and had not had to comply with key aspects of the rules.

Noting four more suspected cases, the report also suggested there could be more well failures, and more widespread pollution, beyond the cases identified. “The full extent to which injected brines have contaminated underground sources of drinking water is unknown,” it stated.

The GAO concluded that most of the contaminated aquifers could not be reclaimed because fixing the damage was “too costly” or “technically infeasible.”

Faced with such findings, the federal government drafted more rules aimed at strengthening the injection program. The government outlawed certain types of wells above or near drinking water aquifers, mandating that most industrial waste be injected deeper.

The agency also began to hold companies that disposed of hazardous industrial waste to far stiffer standards. To get permits to dispose of hazardous waster after 1988, companies had to prove – using complex models and geological studies – that the stuff they injected wouldn’t migrate anywhere near water supplies for 10,000 years. They were already required to test for fault zones and to conduct reviews to ensure there were no conduits for leakage, such as abandoned wells, within a quarter-mile radius. Later, that became a two-mile minimum radius for some wells.

The added regulations would have prevented the vast majority of the accidents that occurred before the late 1980s, EPA officials contend.

“The requirements weren’t as rigorous, the testing wasn’t as rigorous and in some cases the shallow aquifers were contaminated,” Kobelski said. “The program is not the same as it was when we first started.”

Today’s injection program, however, faces a new set of problems.

As federal regulators toughened rules for injecting hazardous waste, oil and gas companies argued that the new standards could drive them out of business. State oil and gas regulators pushed back against the regulations, too, saying that enforcing the rules for Class 2 wells – which handle the vast majority of injected waste by volume – would be expensive and difficult.

Ultimately, the energy industry won a critical change in the federal government’s legal definition of waste: Since 1988, all material resulting from the oil and gas drilling process is considered non-hazardous, regardless of its content or toxicity.

“It took a lot of talking to sell the EPA on that and there are still a lot of people that don’t like it,” said Bill Bryson, a geologist and former head of the Kansas Corporation Commission’s Conservation Division, who lobbied for and helped draft the federal rules. “But it seemed the best way to protect the environment and to stop everybody from just having to test everything all the time.”

The new approach removed many of the constraints on the oil and gas industry. They were no longer required to conduct seismic tests (a stricture that remained in place for Class 1 wells). Operators were allowed to test their wells less frequently for mechanical integrity and the area they had to check for abandoned wells was kept to a minimum – one reason drilling waste kept bubbling to the surface near Chico.

Soon after the first Chico incident, Texas expanded the area regulators were required to check for abandoned waste wells (a rule that applied only to certain parts of the state). Doubling the radius they reviewed in Chico to a half mile, they found 13 other injection or oil and gas wells. When they studied the land within a mile – the radius required for review of many Class 1 wells – officials discovered another 35 wells, many dating to the 1950s.

The Railroad Commission concluded that the Chico injection well had overflowed: The target rock zone could no longer handle the volume being pushed into it. Trying to cram in more waste at the same speed could cause further leaks, regulators feared. The commission set new limits on how fast the waste could be injected, but did not forbid further disposal. The well remains in use to this day.

In late 2008, samples of Chico’s municipal drinking water were found to contain radium, a radioactive derivative of uranium and a common attribute of drilling waste. The water well was a few miles away from the leaking injection well site, but environmental officials said the contaminants discovered in the water well were unrelated, mostly because they didn’t include the level of sodium typical of brine.

Since then, Ed Cowley, the public works director, said commission officials have continued to assure him that brine won’t reach Chico’s drinking water. But since the agency keeps allowing more injection and doesn’t track the cumulative volume of waste going into wells in the area, he’s skeptical that they can keep their promise.

“I was kind of like, ‘You all need to get together and look at the total amount you are trying to fit through the eye of the needle,'” he said.

***

When sewage flowed from 20 Class 1 wells near Miami into the Upper Floridan aquifer, it challenged some of scientists’ fundamental assumptions about the injection system.

The wells – which had helped fuel the growth of South Florida by eliminating the need for expensive water treatment plants – had passed rigorous EPA and state evaluation throughout the 1980s and 1990s. Inspections showed they were structurally sound. As Class 1 wells, they were subject to some of the most frequent tests and closest scrutiny.
Yet they failed.

The wells’ designers would have calculated what is typically called the “zone of influence” – the space that waste injected into the wells was expected to fill. This was based on estimates of how much fluid would be injected and under what pressure.

In drawings, the zone of influence typically looks like a Hershey’s kiss, an evenly dispersed plume spreading in a predictable circular fashion away from the bottom of the well. Above the zone, most drawings depict uniform formations of rock not unlike a layer cake.

Based on modeling and analysis by some of the most sophisticated engineering consultants in the country, Florida officials, with the EPA’s assent, concluded that waste injected into the Miami-area wells would be forever trapped far below the South Florida peninsula.

“All of the modeling indicated that the injectate would be confined in the injection zone,” an EPA spokesperson wrote to ProPublica in a statement.

But as Miami poured nearly half a billion gallons of partly treated sewage into the ground each day from the late 1980s through the mid 1990s, hydrogeologists learned that the earth – and the flow of fluids through it – wasn’t as uniform as the models depicted. Florida’s injection wells, for example, had been drilled into rock that was far more porous and fractured than scientists previously understood.

“Geology is never what you think it is,” said Ronald Reese, a geologist with the United States Geological Survey in Florida who has studied the well failures there. “There are always surprises.”

Other gaps have emerged between theories of how underground injection should work and how it actually does. Rock layers aren’t always neatly stacked as they appear in engineers’ sketches. They often fold and twist over on themselves. Waste injected into such formations is more likely to spread in lopsided, unpredictable ways than in a uniform cone. It is also likely to channel through spaces in the rock as pressure forces it along the weakest lines.

Petroleum engineers in Texas have found that when they pump fluid into one end of an oil reservoir to push oil out the other, the injected fluid sometimes flows around the reservoir, completely missing the targeted zone.

“People are still surprised at the route that the injectate is taking or the bypassing that can happen,” said Jean-Philippe Nicot, a research scientist at the University of Texas’ Bureau of Economic Geology.

Conventional wisdom says fluids injected underground should spread at a rate of several inches or less each year, and go only as far as they are pushed by the pressure inside the well. In some instances, however, fluids have traveled faster and farther than researchers thought possible.

In a 2000 case that wasn’t caused by injection but brought important lessons about how fluids could move underground, hydrogeologists concluded that bacteria-polluted water migrated horizontally underground for several thousand feet in just 26 hours, contaminating a drinking water well in Walkerton, Ontario, and sickening thousands of residents. The fluids traveled 80 times as fast as the standard software model predicted was possible.

According to the model, vertical movement of underground fluids shouldn’t be possible at all, or should happen over what scientists call “geologic time”: thousands of years or longer. Yet a 2011 study in Wisconsin found that human viruses had managed to infiltrate deep aquifers, probably moving downward through layers believed to be a permanent seal.

According to a study published in April in the journal Ground Water, it’s not a matter of if fluid will move through rock layers, but when.

Tom Myers, a hydrologist, drew on research showing that natural faults and fractures are more prevalent than commonly understood to create a model that predicts how chemicals might move in the Marcellus Shale, a dense layer of rock that has been called impermeable. The Marcellus Shale, which stretches from New York to Tennessee, is the focus of intense debate because of concerns that chemicals injected in drilling for natural gas will pollute water.

Myers’ new model said that chemicals could leak through natural cracks into aquifers tapped for drinking water in about 100 years, far more quickly than had been thought. In areas where there is hydraulic fracturing or drilling, Myers’ model shows, man-made faults and natural ones could intersect and chemicals could migrate to the surface in as little as “a few years, or less.”

“It’s out of sight, out of mind now. But 50 years from now?” Myers said, referring to injected waste and the rock layers trusted to entrap it. “Simply put, they are not impermeable.”

Myers’ work is among the few studies done over the past few decades to compare theories of hydrogeology to what actually happens. But even his research is based on models.

“A lot of the concepts and a lot of the regulations that govern this whole practice of subsurface injection is kind of dated at this point,” said one senior EPA hydrologist who was not authorized to speak to ProPublica, and declined to be quoted by name.
“It’s a problem,” he said. “There needs to be a hard look at this in a new way.”

Special thanks to Richard Charter

Date: June 26, 2012
Contact: Blake Androff (DOI) 202-208-6416
Will hold 12:00 PM EDT press teleconference today to discuss next steps in energy planning for U.S. Arctic

TRONDHEIM, NORWAY – As part of the Obama administration’s “all of the above” energy strategy, Secretary of the Interior Ken Salazar and Deputy Secretary David J. Hayes today delivered remarks at the Norway Arctic Roundtable in Trondheim, Norway. These discussions and meetings are part of the Obama administration’s commitment to expanding safe and responsible production of our domestic resources while ensuring the strongest possible safety and environmental oversight of offshore oil and gas activities on the U.S. Outer Continental Shelf.
Secretary Salazar and Deputy Secretary Hayes’s remarks from the Norway Arctic Roundtable, as prepared for delivery, are below:

Remarks by Secretary Salazar at the Norway Arctic Roundtable
June 26, 2012 – Trondheim, Norway
As Prepared for Delivery

Good morning to my counterparts, industry representatives and other dignitaries here today.

A special thank you to Ola Borten Moe, Norway’s minister of petroleum and energy and his staff, for welcoming us all to your great country and for organizing two days of focused discussions about safe and responsible oil and gas development in the oceans of the world.

All of us are here today because we have a shared interest in the Arctic. We share its waters. We confront shared challenges in its frontiers. And we have a shared stake in a sustainable future.

The challenges we see in the Arctic bring together a number of overlapping conversations. It’s impossible to talk about energy development and resource management without talking about the need to preserve fragile environments, the need to develop infrastructure, or the need to protect Native communities and their way of life.

For U.S. policy-makers, these issues coalesce in Alaska, which includes America’s Arctic.

The Department of the Interior has significant equities in Alaska. We manage more than half of all land in Alaska, including Denali National Park and the Alaska National Wildlife Refuge. We also oversee all of Alaska’s Outer Continental Shelf, including the Beaufort and Chukchi Seas in the Arctic.

As Secretary of the Interior – responsible for the stewardship of America’s natural resources and energy supplies – I can tell you that President Obama and his administration take very seriously the complexities and unique conditions in the Arctic. It is a frontier. It is a place where development can only safely expand if we also expand our understanding through science and experience.

That is why the Arctic, we believe, demands its own approach. We have to listen to each other as global partners and we must listen to local communities. We have to invest in science and share information. We have to cooperate in our planning. And we must always put caution and safety first.

Nowhere are caution and safety more important than in energy exploration and development.

In the U.S. Arctic, the Beaufort and Chukchi Seas hold large estimated undiscovered oil and gas resources.

These resources, if developed safely, can be important components in the ‘all of the above’ energy strategy that President Obama is implementing to expand U.S. energy production.

But if we are to access these resources, we have to take a careful, step-by-step approach that is grounded in science and that protects subsistence uses, wildlife, local communities, and the broader ecosystem.

And while we must do everything possible to proceed safely and responsibly, we must, of course, be ready to respond in the event of an incident.

Many of you know that we are currently in the final stages of a rigorous review of Shell’s proposal to drill exploratory wells in the Beaufort and Chukchi Seas this summer.

If Shell meets our standards and passes our inspections, its exploration activities will be conducted under the closest oversight and most rigorous safety standards ever implemented.

In particular, all operators must now meet new drilling safety standards requirements for the equipment, systems, and infrastructure necessary for spill response in the Arctic. We implemented these standards in the aftermath of the Deepwater Horizon disaster two years ago as part of the most aggressive and comprehensive reforms to offshore oil and gas regulation in U.S. history.

Operators must also comply with strong new oversight from the Bureau of Safety and Environmental Enforcement, an agency we established last year to focus solely on safety and environmental protection. If Shell activities in the Arctic proceed this summer, BSEE will have an inspector on-site 24 hours a day. They are also required to have a full suite of response capabilities in the area, including a capping stack and containment systems.

These near-term exploratory activities would be limited in scale—and for good reason: we want to be certain that any activity is well within planning, safety and response capabilities that are deployed.

We also believe that this type of careful exploration in the Arctic can help develop critical science and information to guide future leasing and development decisions. This is, in fact, an important principle of the Administration’s offshore energy strategy over the next five years.

Later this week, I will announce our final proposed Five Year Outer Continental Shelf Oil and Gas Leasing Program, which outlines our plan for safely and responsibly expanding energy development, including in the Arctic.

Like the Gulf of Mexico lease sale we held last week, which made nearly 39 million acres available and brought in over $1.7 billion U.S. dollars in bonus bids, this five-year program will show that we can move confidently – with comprehensive safety standards in place – to continue to grow our energy economy at home while protecting the environment and human health.

In this plan, we will make available vast areas in the most resource-rich parts of the U.S. outer continental shelf for oil and gas leasing. This includes frontier areas of the Alaskan Arctic.

Our plan schedules two potential lease sales in the Arctic – one in the Chukchi planning area in 2016, and one in the Beaufort planning area in 2017.

Our goal is to maximize the availability of oil and gas resources in those areas that we are making available for leasing, while minimizing potential conflicts with environmentally sensitive areas and the native Alaskan communities that rely on the ocean for subsistence use.

To achieve this, we are taking a different approach – a more strategic approach – than the past. Specifically, we intend to gather information from industry, Native Alaskan communities, the scientific community, and the public to identify specific high-resource, low-conflict areas that are best suited for exploration and development.

This strategy, which is similar to how we now conduct onshore oil and gas lease sales and offshore wind energy planning, will allow us to design potential lease sales in the Arctic in a way that best balances factors like resource potential, subsistence use, and environmental considerations. Specifically, this analysis will help us to design the specific features of Arctic sales – like the size and location of the sale area and the terms and conditions that ensure that any leases are developed responsibly. This will enhance certainty for industry and reduce conflict, litigation, and delays.

You can call this approach “targeted leasing.” It means that we are aggregating what we know and identifying areas best suited for exploration and development, based on the latest information.

For example, a 25 mile buffer along the coast of the Chukchi Sea has long been excluded from leasing because it is so important for Native subsistence use. We will continue to maintain that buffer in our next plan.

In this next five-year plan, we have determined that an additional area north of Barrow – one that has not historically attracted industry interest and that has very high subsistence value to Native Alaskan communities – will not be considered for future leasing for the same reason.

Leasing has tended to focus in areas elsewhere in the Chukchi with higher estimated resource potential, so this area fits our strategy of offering areas with the greatest resources.

Overall, this Arctic strategy represents a shift from the ‘one-size-fits-all’ approach of the past to a recognition of that science, planning, and the voices of local communities can guide us on a smarter, more strategic, and more effective path.

I look forward to the opportunity to share our experiences with you today, and to hear from all of you about your experiences in the Arctic frontier.

With that, I will turn it over to Deputy Secretary David J. Hayes for his remarks.

Remarks by Deputy Secretary Hayes at the Norway Arctic Roundtable
June 26, 2012 – Trondheim, Norway
As Prepared for Delivery

As the Secretary mentioned, our shared responsibility for the Arctic brings us together today. This is an exceptional forum to share our experiences.

A critical regional tool, of course, is the Arctic Council, under the auspices of which our nations are working to craft a formal agreement to strengthen cooperation on oil pollution response. With increased shipping and natural resource development activities projected for the Arctic in the coming decades, this is a priority effort. The United States is proud to be part of the Council’s newly created Oil Pollution Response Task Force – a task force that has strong support from around the region.

Another important event is tomorrow’s meeting convened by our Norwegian hosts: the second Ministerial Forum on Offshore Energy Safety. This is a Forum Secretary Salazar established last year in Washington, D.C., and we have been heartened by Norway’s commitment to continued minister-level dialogue about safety issues. While the Forum is of global scope, its themes are especially relevant to the Arctic.

Good science must underpin development. We need to continue expanding what we know about the Arctic and its unique ecosystems and cultural resources, marine environments, sea currents, ice migration and weather patterns.

In the United States, we are taking a number of steps toward that goal. We have a dedicated team of scientists who are working and coordinating across agencies and organizations to build our understanding of the environment, resources, geology and culture of the Arctic.

We are also looking ahead and thinking strategically about future science needs. The Congressionally-chartered Arctic Research Commission is working to coordinate the research that 15 different federal agencies are sponsoring on Arctic matters. And our National Science Foundation is putting together, as we speak, a new plan for addressing science needs in the Arctic, as a complement to its huge commitment to on-going Antarctic research.

These are in addition to a number of collaborative international initiatives to improve scientific information about the Arctic that the United States is involved in.

Continuing to build our body of scientific knowledge about the polar regions is paramount – but it is only the first step. Equally important is to ensure that there is a strong, meaningful link between polar science and the decisions facing policymakers in the Arctic and Antarctic.

This is one of the charges that President Obama gave to the Interagency Working Group on Energy and Permitting in Alaska, which he created last summer in order to facilitate coordinated, science-based domestic energy development and permitting in Alaska. As Chair of the group, I coordinate the efforts of decision makers across the federal government when it comes to developing both conventional and renewable energy resources in Alaska. In my capacity as chair, I also am partnering with Fran Ulmer to advance this mission by promoting the dialogue between federal policy makers and the scientific community on how to optimize the availability of relevant scientific information for decision-makers.

We held three Science and Decision-making workshops with members of the federal government, state, local, and tribal government representatives and members of industry, academia, and non-governmental organizations.

One of the key themes that emerged from our first Science and Decision-making workshop is the need to adopt an integrated, holistic approach to resource management in the Arctic. The Arctic’s ice shelf and coastal, terrestrial and marine ecosystems are changing too fast for sector-by-sector, project-by-project, or issue-by-issue management. Getting it right in the Arctic calls for a fully integrated approach if we expect to protect natural resources and subsistence values while continuing commercial activities.

This echoes a theme that Secretary Salazar and I heard in Nuuk last summer, where the Arctic Council agreed to take a serious look at how the many resources – including energy resources – of the Arctic can be managed sustainably, without compromising the resilience of important ecological and cultural systems.

The Arctic Council’s ecosystem-based management (or EBM) approach holds a great deal of promise as a means to operate in the region with less risk and greater foresight. The EBM Experts Group just had a very successful meeting in Sweden this spring and is continuing to foster greater cooperation and develop a body of best practices for adaptive management in a rapidly changing environment.

This effort has also helped to inform an important domestic initiative in the United States focused on “Integrated Arctic Management.” We have established a government-wide task force to use the best available scientific and traditional knowledge about the Arctic to identify key indicators of change and recommend actions that will help ensure the long-term health and resilience of the environment while still achieving sustainable commercial activities. Near-term deliverables will include an assessment of environmentally and culturally sensitive areas and the development of plausible future scenarios to guide planning in the Arctic region.

The rapid changes underway in the Arctic underscore the urgency of effective and far-sighted policies to ensure the health and welfare of the native communities.

It is important to consider and to support the collection and sharing of traditional knowledge, often the best available information. This information should help inform any decisions we make in this region, including decisions about energy development, in order to protect Alaska native communities.

Integrated Arctic Management, as mentioned, is a means to ensure that these critical needs are incorporated into management and planning.

That concludes our portion of the program this morning – thank you very much.

###
Special thanks to Richard Charter