August 31, 2009
Please Mrs. Nixon
The Royal Bank of Canada is the largest financier of tar sands projects. Michael Broom of Rainforest Action Network appeals to Mrs. Nixon, asking her to talk to her husband, Royal Bank CEO Gordon Nixon, to help end the tar sands.
Watch the video here.
Time for Natural-Gas Autos?
By MIKE HOGAN
Barron's Online
August 29, 2009
The investment outlook for natural gas gets brighter.
AS "CASH FOR CLUNKERS" DEMONSTRATED, AMERICANS love a deal. And Congress may have yet another for you when it returns from summer recess.
The plan is to offer tax credits worth up to $12,500 on the purchase of new cars and trucks. The catch is that your new vehicle must run on natural gas -- compressed natural gas, or CNG, to be precise. A Senate bill, the counterpart to the House's NAT GAS Act, also would offer up to $64,000 in tax credits on fleet vehicles, and up to $100,000 to anyone opening a CNG filling station.
Washington is beginning to wake up to the value of using this plentiful, homegrown fuel for transportation -- and that in turn could open up some intriguing investment opportunities.
Right now, only one CNG car -- Honda's Civic GX -- is available to U.S. buyers. But a dozen auto makers sell some two dozen CNG models overseas, and the Web can help you track their development. For an overview of the current cars, go to www.cngnow.com and click CNG Vehicles Around the World.
AOL Autos also is packed with good information (http://autos.aol.com/gallery/hybrid-cars-15k-25k). Likewise, CNG Chat (www.cngchat.com) lets natural-gas vehicle owners share operating tips and parts sources, and the Environmental Protection Agency offers a searchable database of hybrids (www.fueleconomy.gov/feg/byfueltype.htm).
[In Canada, the Canadian Natural Gas Vehicle Alliance represents those businesses involved in natural gas vehicles and who would like to see the use of gas expanded as a vehicle fuel. www.cngva.org. The CNGVA provides a list of only 22 natural gas fueling stations in British Columbia.]
NATURAL-GAS ENGINES -- found in some American buses and fleet vehicles -- have clear appeal. Boosters say a "gallon equivalent" of natural gas is about half the price of gasoline or diesel and produces about a third the harmful emissions. And America is swimming in the stuff.
Although a shortage of natural gas was forecast a couple years ago, supply has surged 50% since then -- primarily as a result of record gas discoveries in the strategically located Barnett, Haynesville, Marcellus and Bakken shale fields. These so-called unconventional sources are tapped using methods pioneered by outfits like Chesapeake Energy (ticker: CHK) and Denbury Resources (DNR) and can be quickly disseminated through the nearby pipelines of El Paso Corp. (EP) and Kinder Morgan Energy Partners (KMP).
Still, CNG vehicles in America face the same chicken-and-egg dilemma other hybrids do: building a refueling network. Refueling stations are scarce because only about 150,000 of America's 250 million automobiles are CNG-powered.
So near-term, it will be large commercial shippers like Wal-Mart (WMT) and PepsiCo (PEP) that drive increased use of natural gas on the road, predicts Andrew Littlefair, chief executive of natural-gas filling-station operator Clean Energy Fuels (CLNE).
Operators of America's long-haul trucks can afford natural-gas pumps in their shipping yards, and utilize Clean Energy's growing network of 184 North America truck stops. The economic incentives are fairly obvious for these big energy users, less so for consumers paying a premium for CNG vehicles.
ALL THIS ADDS UP TO AN INVESTING outlook that, while cloudy for the moment, seems likely to brighten.
Institutional investors see many good long-term values among the sector's 40 or so exploration-and-production and field-service companies, says Jon Najarian, co-founder of Chicago-based optionMONSTER (www.optionmonster.com). But depressed commodity prices and potentially punitive regulations directed at energy trades have kept many on the sidelines. Najarian is seeing lower-than-warranted volumes in the U.S. Natural Gas Fund (UNG), the main proxy for the volatile commodity, and other energy ETFs like the levered ProShares Ultra Oil & Gas (DIG) and its inverse, UltraShort Oil & Gas (DUG).
On the other hand, commodity volatility provides plenty of trading opportunities. Najarian recommends a covered-call strategy -- going long on a natural-gas stock or fund while selling a call on the same issue, to profit from both up and down price movements. OptionMONSTER's Covered Call Investor newsletter will walk you through this complicated swing-trading strategy for $149 monthly. At optionmonster.com, click Options Products, then Covered Call Investor.
Auto makers are another possible way to play the trend. But even a marked increase in CNG car sales won't provide much earnings catalyst for giants like Honda (HMC) and Toyota (TM), which plans to bring some of its CNG-powered vehicles here in the future.
Clean Energy is among potential winners. It just opened the world's largest natural-gas fueling facility at the Port of Los Angeles, and completed an $8.30-a-share offering that brought in $73 million. Shares recently closed at $12.78, bouncing off a 52-week low of $3.23 last November and a wider-than-expected second-quarter loss in August.
Likewise, Fuel Systems Solutions (FSYS), which supplies electronic gas-flow systems to car makers, picked up the technology for a home-refueling appliance when Honda liquidated its FuelMaker subsidiary in May. FSYS shares recently closed around $30 after the company handily beat second-quarter earnings estimates in a 52-week range of $10-to-$61. With a forward price/earnings ratio of 16, FSYS may appear fully priced, but not in view of a quarterly earnings-growth rate of 56% compared with the prior year.
THE QUESTION FOR ALL CNG-RELATED stock is: Will there be a legislative catalyst? Congress will have a lot on its plate when it returns to Washington -- bigger fish to fry, as it were. On the other hand, Senate Majority Leader Harry Reid of Nevada and White House Chief of Staff Rahm Emanuel head the bill's glittering list of supporters.
Among the politically influential fans cheering the Senate bill at the recent Clean Energy Summit were Bill Clinton, his former chief of staff John Podesta, Al Gore and BP Capital Management Chairman T. Boone Pickens. Populating American roads with CNG cars is Pickens' Plan B to cut our foreign-oil bill by a third. The renowned energy investor has pulled the plug (temporarily) on Pickens' Plan A: building the world's largest wind farm.
Sums up Najarian: "There are all kinds of reasons to be bearish on this sector in the short term -- and just as many reasons to be bullish in the long term."
E-mail: mike@mikhogan.com
August 30, 2009
Tesoro moves oil to Pacific on reversed Panama line
COMMENT: Interesting news item in the context of global oil distribution. Alaska's North Slope oil came onstream with the Trans-Alaska Pipeline in 1977. US law at the time prevented Alaska oil from being sold outside the United States. The consequence was that California and Washington State refineries had a captive supplier. The only alternative was an expensive protracted 40 day tanker route around Cape Horn to Gulf of Mexico refineries, as the very large crude carriers (VLCCs) were too large to pass through the Panama Canal.
The solution was the 81 mile Trans-Panama Pipeline (TPP) from the Pacific coast of Panama to the Atlantic coast, close to the border with Costa Rica. The TPP came onstream in 1982, capable of shipping 860,000 barrels per day. VLCCs would offload on the Pacific side, and other VLCCs would reload on the Atlantic side - a 10 day trip.
But declining production in both Alaska and California, and a lifting of the export ban in 1995 undermined the justification for TPP, and in 1996 the pipeline was shut down.
In more recent years, various proposals have emerged to start TPP up again, but this time reversed - shipping oil from Atlantic basin sources to Pacific destinations. Venezuela wants it to ship oil to China. BP has signed onto the project. And in this article, Tesoro just shipped the first boatload of Colombian oil to one of its refineries in California, and intends to use the TPP for oil from the North Atlantic and Africa, as well.
Bruce Nichols
Reuters News
August 27, 2009
HOUSTON, Aug 27 (Reuters) - Tesoro Corp (TSO.N) has shipped its first barrels of crude oil from the Atlantic to the Pacific Basin on a reversed Panama pipeline, the company said Thursday.
Reversal of the 81-mile (130 km) Petroterminal de Panama pipeline, which formerly flowed from the Pacific to the Atlantic, creates a new oil conduit from the Atlantic to the Pacific and gives Tesoro access to more crude for its refineries in California, Washington, Hawaii and Alaska, the company said.
"In addition to exposing Tesoro to an array of crude oils typically marketed in the Atlantic Basin, our abilities to utilize the tankage dedicated for Tesoro's exclusive use at PTP and the reversed pipeline are expected to afford our company strategic advantages related to freight, storage, blending, and delivery scheduling optimization," said Doug Koskie, vice president of arbitrage trading for Tesoro Refining and Marketing Company.
The first oil through was Castilla blend from Colombia, which will be refined in California, Koskie said.
Tesoro is a leading independent producer of petroleum products, such as gasoline and diesel, in the western United States, including Alaska, and its seven refineries have a total capacity of 660,000 barrels per day.
August 29, 2009
Carbon disaster vs Hell Yes CCS
Lawrence Solomon
National Post
August 15, 2009
 Photo: Carbon-capture plants may worry neighbouring communities. (Canwest News Service) |
Don’t worry about the risks of earthquakes or suffocation or water contamination. Carbon capture is good, really
If you live in or near a community that manufactures chemicals or cement, or that has a refinery or a coal or natural gas electricity generating station, or that has abandoned mines or other suitable geological formations, you may soon be asked to save the planet from global warming by hosting an underground carbon dioxide storage facility.
You and your neighbours will be told not to worry about carbon dioxide poisoning your water supplies. Yes, ruptures or large leaks of the gas could not only make the water undrinkable for you but also kill vegetation and aquatic life, the authorities will acknowledge, but inventors are working on new, improved technology that will prevent underground pipes and other infrastructure from leaking.
You and your neighbours will also be told not to worry about mass asphyxiation in your sleep in the event of an unexpected release of carbon dioxide, a gas that’s heavier than air — to their knowledge, that only happened to humans once before, in rural Africa when a release of naturally stored carbon dioxide from Lake Nyos in Cameroon enshrouded and suffocated 1,700 people. The authorities in Canada promise to take this risk seriously and double-promise to design state-of-the-art carbon dioxide storage plants that won’t fail fed by pipelines that won’t blow out. Plus, they’ll install monitors in case plants fail or pipelines blow out.
Finally, you and your neighbours will be told not to worry about the possibility that your community will become susceptible to earthquakes. Yes, the authorities will admit when pressed, these carbon-storage facilities are expected to become one of the top five triggers of earthquakes — induced seismicity, it’s called — but hey, somebody’s got to save the planet and the authorities have selected you.
In turn, you and your neighbours, having received all these assurances from the authorities — and having confirmed that the government plans to exempt the carbon-storage industry from liability in the event of an accident — will rise up in opposition and try to run the authorities out of town.
I am guessing, of course, at what you and your neighbours will ultimately decide to do — maybe your community can be bribed into acquiescence. But I am not guessing that our federal and provincial governments have a crash program underway to make Canada an early leader in the carbon-storage industry.
Last month, the Alberta government, which has already committed $2-billion to carbon-storage schemes, announced the province’s first host communities as if it had selected lottery winners. “Alberta announces three winning projects for carbon-capture funding,” reported the Calgary Herald. “[They] will each receive a portion of $2-billion in carbon capture and storage funding, if final negotiations between the province and companies are successful.”
The neighbours to the winners — Edmonton-area ventures involving Shell Canada, Chevron Canada and Epcor, among others — may feel more like guinea pigs after the public consultations begin, and concerns get aired. The government expects the storage facilities to be up and running by 2015, meaning that the pressure will soon be on to ram these projects through. Look for environmental groups to be enlisted as government persuaders — the Alberta-based Pembina Institute has already recommended that environmental groups take on this enabling role. And look for the environmental groups to be held in the same regard as the governments and companies they are working with.
Last September, a carbon-storage demonstration scheme in northern Germany — Vattenfall’s Schwarze Pumpe project in Spremberg — opened to wide acclaim. The $110-million facility was touted as the first to trap carbon dioxide at a coal plant before transporting it for burial. Last week it came out that the burial never happened. Because of local opposition, the town had refused to give Vattenfall a permit for burial. Rather than storing the gas underground, Vattenfall revealed during a conference, it has been quietly (and safely) venting the carbon dioxide straight into the atmosphere all along. Similarly, local opposition foiled Shell’s plans to store carbon dioxide in depleted gas fields under the Dutch town of Barendrecht, near Rotterdam, in March. After sitting through a public consultation, and receiving assurances from Shell that the technology is proven to be safe, 1,300 residents lodged their protests.
The Numby phenomenon — Not Under My Back Yard — is not limited to opposition by local residents: industries with a stake in safe water are also alarmed. The American Water Works Association, a trade group representing 4,700 water utilities that produce 80% of America’s drinking water, has added the carbon-storage industry to coal and the other resource industries that threaten its interests and those of its customers.
“Our biggest concern is the prevention of degradation of underground sources of drinking water” by interfering with the complex chemistry of water in underground settings, the association told Congress in detailed testimony last year, citing the numerous ways that carbon dioxide burial threatens aquifers with profound contamination, and noting that many communities don’t have alternative sources of affordable drinking water.
The association also noted that carbon-storage technology is unproven and may not even succeed in its primary goal, of removing carbon dioxide from the atmosphere. Why risk a nation’s water supplies without the evidence being in, it asked Congress. Why indeed.
Lawrence Solomon is executive director of Energy Probe and Urban Renaissance Institute and author of The Deniers: The world-renowned scientists who stood up against global warming hysteria, political persecution, and fraud.
Hell yes, back CCS
Eric Beynon & Marlo Raynolds
National Post
August 29, 2009
Re: Carbon disaster, Lawrence Solomon, Aug 15.
Lawrence Solomon's column illustrates a lack of understanding of the potential of carbon capture and storage (CCS) as one of the tools to reduce greenhouse-gas emissions globally.
Anyone serious about dealing with greenhouse gas emissions and who has done research and analysis on the solutions, knows we need a complete portfolio of actions, including the appropriate and safe application of carbon capture and sequestration. ICO2N has undertaken a significant amount of research on CCS technology, analysis of economic models for development and the best way for establishing an integrated carbon capture and storage network in Canada. This is not unproven technology, and a great deal of work is being done to ensure our understanding of this important tool is comprehensive on every front.
The Pembina Institute views CCS as one of a number of technologies that can contribute to reducing greenhouse gas emissions on the scale required to combat dangerous climate change. There is no single solution to addressing climate change and it is incumbent on all of us to ensure accurate information on all the tools available to us.
Here are some key points from ICO2N's research to consider in assessing the merits of Mr. Solomon's opinion:
-Throughout recorded history, no earthquake has ever been powerful enough to cause an instantaneous release of oil or gas from a sandstone sediment layer. And since the CO2 would be held in place by the very same impermeable cap rock that has held oil and gas under the earth through millions of years and countless earthquakes, sequestered CO2 would not be in danger of release due to seismic activity.
-Any system for carbon capture and storage would have stringent guidelines and monitoring systems to ensure the safety of people, integrity of systems and protection of the environment. Underground storage of CCS will be 800 metres to 2 kilometres underground, far below drinking water sources at less than 300 meters underground.
-Many things can be dangerous, but natural gases are already deep underground and not leaking to the surface now. The 1986 Lake Nyos tragedy was a natural occurrence not dissimilar to mud slides, floods and tsunamis that occur in other parts of the world.
-CO2 capture and storage is not a new or untested idea. CCS is a technically viable and environmentally safe means of reducing greenhouse gases. The subsurface is an effective trap for CO2 and other natural gases and large scale trials provide strong evidence that industrial volumes of CO2 can be stored successfully.
-There are many CCS projects of varying sizes already underway around the world and underground storage of CO2 has been underway for more than a third of a century in the United States. The safety records of existing CCS projects across North America and around the world are exemplary.
-In Canada, EnCana's Weyburn project, which has been monitored by the International Energy Agency, has successfully stored over 13 million tonnes of CO2 in southern Saskatchewan over the past 9 years.
-Norwegian energy company Statoil, an early leader in CCS, has pumped over ten million tonnes of carbon dioxide beneath the bed of the North Sea over the past decade without incident.
-Suitable sites for CO2 storage are chosen after rigourous analysis of their quality and capacity and are typically either depleted oil or gas reservoirs or deep saline formations.
Eric Beynon, director, Strategy and Policy, Integrated CO2 Network, Calgary;
Marlo Raynolds, executive director, Pembina Institute, Calgary.
Coal is still king
By Lawrence Solomon
Financial Post
August 29, 2009
Carbon capture and storage technologies pushed by Western governments may or may not work, but ...
 Lawrence Solomon |
And since burial solves the carbon dioxide problem, they then conclude, we can with a clear conscience crank up our use of coal.
This is the case in Canada, where the National Roundtable on the Environment and the Economy proposes a continuation of the boom that we’ve seen in coal mining this decade. This is the case in the U.S., where coal production has been steadily growing and where President Barack Obama touts coal above other energy options. And this is especially the case in the United Kingdom, perhaps the world’s most earnest warner of global warming catastrophe. The U.K. is today so bullish on burial that it has resuscitated the coal mining industry that Maggie Thatcher tried to kill off in the 1980s.
In the last four years, the U.K. has approved 54 coal mines, most of them open-pit, while simultaneously pointing to the aggressive reductions in CO2 emissions to which it’s committed — 34% by 2020. Scotland, which boasts the world’s very toughest CO2 reduction targets (42% by 2020), has approved 25 new open-pit mines, helping them along by relaxing planning regulations that apply to open-pit mines. Because all this isn’t enough, the U.K. is considering the approval of another 19 open-pit mines as well as upping its coal imports too.
“We don’t see this as counter to our climate change message,” cheerily states the government’s Department for Energy and Climate Change. “The U.K. is at the forefront of global efforts to decarbonise fossil fuels.”
The decarbonisation that the U.K. government refers to involves burial on land and — especially attractive for an island nation — at sea. A recently released Scottish government report determined that the Scottish area of the North Sea alone could store all the carbon dioxide that all the coal-fired plants in the U.K. would produce over the next two centuries, leading the Scottish First Minister to speculate that a high-tech carbon capture and storage industry could create 10,000 Scottish jobs.
But ocean storage raises a tide of objections from environmentalists, Greenpeace among them. Carbon dioxide in water could seriously acidify the oceans — already a concern — removing nutrients for plankton in areas like the U.K.’s North Sea as well as in shallow ocean waters, and affecting the food source for marine life. Some ocean storage technologies kill marine life directly. Plus, many scientists believe the oceans will fail to effectively contain carbon dioxide, which will be pumped into waters in either liquid or gaseous form. No one, not even the U.N.’s Intergovernmental Panel on Climate Change, considers ocean storage to be much more than a concept, let alone a proven technology.
The potential for havoc to humans is much greater with carbon storage facilities under land. Carbon dioxide could adversely acidify groundwater, leading to leaching of contaminants into the water supply and rendering aquifers unusable. For this reason and others — an unplanned release of the gas could suffocate humans or animals, and carbon storage can induce earthquakes — governments on both sides of the Atlantic have proposed carbon storage facilities and communities have opposed them.
How will this all end? We can be confident that coal use will keep on growing for decades to come, in line with official projections that show worldwide demand soon doubling —without coal for electricity production, most jurisdictions will be unable to keep the lights on. We can also be confident that communities will successfully fend off many if not most of the carbon storage schemes that threaten them and their environments. Finally, we can be confident that governments, after spending tens of billions on carbon storage schemes of dubious benefit, will conclude that the safest place to store today’s relatively high levels of carbon dioxide is in the atmosphere, where it now resides.
Lawrence Solomon is executive director of Energy Probe and Urban Renaissance Institute and author of The Deniers: The world-renowned scientists who stood up against global warming hysteria, political persecution, and fraud.
Awash in natural gas, prices hit new 7-year lows
By CHRIS KAHN
Washington Post
Thursday, August 27, 2009
NEW YORK -- Natural gas prices slumped to their lowest level in seven years Thursday after the government reported that salt caverns, aquifers and other underground areas where it is stored are filling up.
Levels of natural gas have been building because power-intense industries like manufacturing have cut back severely on production.
Natural gas tumbled 6.7 cents to settle at $2.843 per 1,000 cubic feet. The price dropped as low as $2.692 per 1,000 cubic feet earlier in the day, a price not seen since Aug. 7, 2002. The contract is scheduled to end Thursday, however, and most of the trading already has switched to the October contract that gave up 4.6 cents to trade at $3.248.
Meanwhile, crude and gasoline futures were tugged higher as equities markets rose and the dollar fell among other major currencies.
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Benchmark crude for October delivery added $1.06 to settle at $72.49 a barrel on the New York Mercantile Exchange.
Still, oil prices have been tumbling since they touched $75 a barrel on Tuesday, and analysts said they expect it will fall further as the summer driving season ends in a few weeks.
Retail gas prices peaked in late June at around $2.69 per gallon and have been falling slowly since, giving consumers a bit of a break in the tough economy.
Gas prices gave up two-tenths of a penny to $2.62 a gallon, according to auto club AAA, Wright Express and Oil Price Information Service. A gallon of regular gasoline is 11.5 cents more expensive than last month, but it's $1.047 cheaper than the same time last year.
Oil remains above $70, largely because it is bought in the U.S. dollar. That means when the dollar falls, like it did Thursday, investors can get more crude for less money. Crude supplies grow this week, however, and they remain well above seasonal norms.
"It's getting harder and harder to justify it at these prices," PFGBest analyst Phil Flynn said.
Natural gas prices plunged early in the day when the Energy Information Administration reported that natural gas placed into storage surged again.
There is so much natural gas in storage, it has begun to test the country's storage capacity. But EIA economist Jose Villar told The Associated Press that storage facilities have added about 100 billion cubic feet of extra space, giving suppliers more places to put it. The EIA will include details of the added capacity in a report to be published in the next few weeks, Villar said.
In other Nymex trading, gasoline for September delivery increased 4.88 cents to settle at $2.0314 a gallon and heating oil added less than a penny to settle at $1.8592 a gallon. In London, Brent crude rose 86 cents to settle at $72.51.
Associated Press Writers Carlo Piovano in London and Eileen Ng in Kuala Lumpur contributed to this report.
Weak dollar pushes energy prices higher
The Associated Press
Friday August 28, 2009
LONDON -- The effect of the weak dollar is again pushing oil prices higher in the face of little demand for energy and huge surpluses of crude.
On Friday, the dollar again fell against major currencies.
Since March, the dollar index, which weighs the U.S. currency against a basket of foreign currencies like the euro, the Japanese yen, the pound and the Swiss franc, has fallen nearly 12 percent. In that same period, crude has jumped 81 percent.
The widening gap between the value of a dollar and that of a barrel of oil shows just how much oil-based index funds have come to affect the prices that consumers pay for energy.
Benchmark crude for October delivery rose 81 cents to $73.30 on the New York Mercantile Exchange. Oil prices earlier this week hit $75, a high for the year.
Oil prices are threatening to hit new highs in a week when the government reported that more unused crude is being placed into storage. The U.S. is also nearing the end of the driving season, when demand generally falls.
Demand for gasoline is already weaker than it was last year, even though right now it costs a dollar less to buy every gallon.
Overnight, retail gasoline fell nearly a penny to $2.613. That's a dime more than gas cost a month ago, largely because of refineries have cut production to match falling demand.
It is difficult to predict how long oil prices can remain at current levels when so little of it is being used. Yet value of a barrel of oil will likely remain elevated as long as investors are skittish about the health of banks and other businesses.
Money under the control of the Federal Deposit Insurance Corp. has been severely depleted by the wave of collapsing financial institutions. Some analysts warn that the FDIC, which guarantees bank deposits, could be losing money by the end of the year.
To a lot of big investors, oil looks like a pretty safe place to park money right now.
"Oil became a safe haven as traders lost confidence in the U.S. banking system (and) ran to oil to protect themselves from the deteriorating economic world around us," said PFGBest analyst Phil Flynn. "Now some critics now call that excessive speculation but what I call it is reflection of the reality. You have to remember the value of any commodity when expressed in a currency will ultimately be determined by the confidence and faith in that underlying instrument."
It seems nothing can prop up prices for natural gas, which hit seven-year lows this week. There is so much gas being pumped into the ground that the U.S. is running out of places to store it. That is largely because big energy users, like manufacturers, have cut back severely on operations as they ride out the recession.
Natural gas prices fell 11 cents to $3.095 per 1,000 cubic feet.
In other Nymex trading, gasoline for September delivery rose 2.2 cents to $2.0535 a gallon and heating oil rose 2 cents to $1.8787 a gallon.
In London, Brent crude rose 54 cents to $73.05.
The Associated Press
Oil, Ecuador and its people (Part 1)
Editorial
Los Angeles Times
August 28, 2009
AGUINDA VS. TEXACO INC.
Today, a swath of the Ecuadorean Amazon remains contaminated beyond imagining. Neither side disputes the devastation, only who should pay for it. Chevron says it is the state oil company's responsibility.
In a small, spare courtroom in the Amazon region of Ecuador, Chevron Corp., California's largest company and one of the world's largest oil producers, will soon face a day of reckoning. After 16 years of litigation, a case the company inherited in a merger, Aguinda vs. Texaco Inc., is nearing an end. The legal battle that began in the United States in 1993 and resumed in Ecuador in 2003 has pitted the multinational against an unlikely adversary, a coalition of indigenous tribes and communities. A verdict is expected early next year. The plaintiffs are poised to prevail, and Chevron acknowledges that it is likely to lose.
The case is historic by several measures. Never before have indigenous peoples brought a multinational oil corporation to trial in their own country. Moreover, a victory would mark a turning point in the relations between native populations around the world and the foreign corporations that do business in their homelands. And the potential damages are staggering: A court-appointed expert has determined that they could run to $27 billion, almost 10 times that initially awarded to plaintiffs after the Exxon Valdez oil spill.
Today, a swath of the Ecuadorean Amazon the size of Rhode Island remains contaminated beyond imagining. At one site after another, oil hangs in the air, slides on the water's surface and saturates the land. Pipelines and waste pits left behind years ago still drip and ooze. Advocates for the plaintiffs have called the former Texaco concession area the "Amazon Chernobyl." Were it in the United States, it would easily qualify as a Superfund site. Neither side in the case disputes the devastation, only who should pay for it. Chevron says it is the state-owned oil company's responsibility; the plaintiffs say it is Chevron's.
The plaintiffs are seeking unspecified damages for environmental cleanup, reforestation and healthcare. (Under Ecuador's legal system, they cannot receive individual compensation.) In addition to reams of documents and hundreds of soil and water samples, the case has generated abundant ill will. Chevron maintains that it's the victim of a scheme to plunder its deep pockets and make it pay for pollution caused by Petroecuador, the state oil company, which took over after Texaco's operations ended. The plaintiffs contend that the pollution was caused by the faulty infrastructure Petroecuador inherited from Texaco; as with a faulty car, to use their analogy, it is the manufacturer, not the driver, who is to blame. Entire communities, they say, have been plagued with devastating illnesses as a result of oil waste in their drinking and bathing water, and their suffering has fallen on deaf corporate ears. Their resentment runs as deep as the oil Texaco once drilled.
Assessing the damage
Texaco Petroleum and Ecuadorean Gulf Oil Co. began exploring for oil in the Ecuadorean Amazon in 1964, found it three years later and, from 1972 to 1992, produced 1.7 billion barrels of crude. Texaco held a 37.5% interest in the consortium, but it designed and constructed the wells, pipelines and waste pits, and it was the sole operator of the 1,700-square-mile concession area.
In 1992, after the government did not renew its contract, Texaco turned over its infrastructure to Petroecuador and left the country. One year later, five indigenous tribes and 80 communities filed a class-action lawsuit in federal court in New York, then Texaco's headquarters. The suit alleged that Texaco discharged more than 18 billion gallons of waste water into rivers and streams, burned millions of cubic meters of natural gas without proper emissions controls and spilled millions of gallons of crude oil directly into the earth, polluting the region's only sources of water, sickening inhabitants and even contributing to the extinction of one small tribe, the Tetete.
In a report submitted last year, the court- appointed expert, geologist Richard Cabrera, estimated that 1,400 people in the region had died of cancer caused by toxic chemicals involved in oil extraction. That calculation accounts for $2.9 billion of the damages assessment. Chevron contends that Cabrera is not qualified to make such a determination and that neither science nor medicine supports his assertion; he has not presented the medical records of any victims. As for remediation, the company says Texaco already did that.
Chevron disputes the scientific methods used to determine its culpability, but the heart of its defense is its assertion that the case never should have been permitted to go forward. The company maintains that it is the victim of the retroactive application of environmental laws that did not apply when Texaco was operating the concession area, and that Texaco fulfilled its clean-up obligations.
After the suit was filed in New York, Texaco entered into a remediation agreement with the Ecuadorean government. As part of that agreement, the company spent about $40 million cleaning up oil field waste pits and funding socioeconomic projects in local communities. In 1998, after years of government oversight and periodic approvals, the Ministry of Energy and Mines and Petroecuador certified that Texaco's remediation met the country's standards, and the government issued a waiver releasing the company from further liability. Chevron, which merged with Texaco in 2001, maintains that the waiver not only immunized it against any action by the government but obviated all other claims. Yet the waiver says nothing about third parties. It releases Texaco "forever, from any liability and claims by the Government of the Republic of Ecuador, Petroecuador and its Affiliates."
More than legal interpretation is at issue. Cabrera concluded that soil samples even from areas Texaco said it remediated are contaminated, which prompted the government to take action against the company as well. Declaring the original remediation a fraud, it indicted two Chevron officials and seven former government officials. And just recently, the court agreed to turn over Cabrera's damages assessment to the office of the federal prosecutor. As a result, Chevron is battling not just the plaintiffs but Ecuador itself. It has tried to pressure the government to assume responsibility for remediations by urging the United States to revoke the country's preferential trade status. So far, that effort has failed.
In Lago Agrio
Such tactics represent a remarkable break in a long relationship between American oil companies and the Ecuadorean government. Indeed, so comfortable was Texaco with the country's government and judicial system that soon after the lawsuit was filed in New York, it argued to move the case to Ecuador. In support of that motion, it filed affidavits attesting to the transparency and fairness of the Ecuadorean court system, pleadings it would come to regret.
At the time, moving the trial was the last thing the plaintiffs wanted. Historical collusion between government officials and oil executives, coupled with the racism and discrimination faced by indigenous peoples in their homeland, made a fair trial inconceivable, they argued. Plaintiffs' advocates likened it to African Americans in the pre-civil rights South obtaining justice from a court in, say, Mississippi -- not impossible, but unlikely. The New York judge sided with Chevron and agreed to dismiss the case as long as the company promised to abide by the Ecuadorean judge's verdict. Chevron promised it would, and in 2003 the fight started over again in a jungle-adjacent courtroom in Lago Agrio.
There, in the grimy oil town named after Texaco's birthplace in Sour Lake, Texas, the two sides await a verdict in a case with echoes and implications around the world. From Nigeria to Peru, native peoples are challenging with new force the destructive legacies of multinationals. In that, Aguinda vs. Texaco is a legal landmark -- one we hope, whatever its outcome, will enable multinational corporations to better navigate the changing world in which they do business and thus encourage a new era of corporate responsibility.
For its part, Chevron has ample reason to be anxious. The company succeeded in having the trial moved to Ecuador, where American oil companies once held great sway. But the country's politics, environmental ethos and regard for its native peoples were about to evolve in dramatic, unforeseen ways. The new Ecuador has turned out to be a far less hospitable place for Chevron than the old Ecuador had been for Texaco.
Tomorrow: A changing Ecuador, and the "shadow case" against Chevron.
Copyright © 2009, The Los Angeles Times
August 28, 2009
First Nations take oilsands concerns to U. K.
By Hanneke Brooymans
Edmonton Journal
August 28, 2009
Three First Nations people from northern Alberta are in London, protesting the involvement of United Kingdom companies in oilsands development.
Residents of Fort Chipewyan are especially concerned about some types of cancer in their communities.
"Because of the people in my community dying and being sick, that's not motivation, that's an obligation on my behalf to go out and spread the word," said Lionel Lepine, a 31-year-old member of the Athabasca Chipewyan First Nation.
"At first, it started as a provincial-awareness type of thing. Then we got the awareness spread right across Canada. And now we're taking this awareness international."
Lepine is accompanied by George Poitras, of the Mikisew Cree First Nation, and Eriel Tchekwie Deranger, also of the Athabasca Chipewyan.
All five will be attending the climate action camp taking place on a patch of common land in London called Blackheath. This location has a history of protest and dissent that dates back to the 14th century, said Jess Worth, a United Kingdom communications organizer for activist groups.
About 1,500 people from around the U. K. will camp there from Aug. 27 to Sept. 2, holding workshops on topics such as climate science, carbon trading, and activist tactics.
"We decided to camp in London because we want to make the links between the economic crisis and the climate crisis, and we believe both are being driven by the banks and the corporations and the government, which have their headquarters in London," Worth said.
People in the U. K. don't know anything about the oilsands, even though they're one of the most destructive projects in the world, she said.
"So if we're going to try to end investment in the tarsands, we can't just work in Canada, we've got to work in the U. K as well."
Worth said that means putting pressure on oil companies such as BP and the Royal Bank of Scotland.
"The tarsands are happening in Canada but they're very much being driven in London."
The Canadian delegation is trying to raise awareness about the oilsands, the scale of the project and the climate implications, and it should start getting action taken against the companies involved, Worth said.
BP Canada declined to comment, directing a request to their London office, which could not be reached.
Poitras said there are a lot of foreign companies involved in oilsands development. "I think the fact we do come to these countries and raise awareness, informs people about the issues and concerns that are not readily made available by the governments of Alberta or Canada in their promotion of the tarsands internationally," he said.
The Canada West Foundation, which tracks the message going out about oilsands development in traditional and Internet media, noted that environmental coverage of the oilsands in July was overwhelmingly negative.
hbrooymans@thejournal.canwest.com.
© Copyright (c) The Edmonton Journal
August 27, 2009
Natural Gas Markets Headed for A Crash?
G. Allen Brooks, Managing Partner
Parks Paton Hoepfl & Brown
Rigzone
Tuesday, August 18, 2009
Natural gas prices after rallying on surprisingly strong labor market news have retreated in recent days as the prospect of full storage suggests the industry will be forced to curtail production unless demand picks up. At the end of July, natural gas in storage was almost 3.1 trillion cubic feet (Tcf), or about 25% above the 5-year average for volumes at this time of year. Estimates of full storage capacity range from 3.7 Tcf to 4.1 Tcf. At the date of this report from the Energy Information Administration (EIA), there were 10 weeks left to the storage injection season meaning that without a strong pick up in gas demand or a collapse in production, domestic gas producers are facing the eventuality of all having to curtail their production. When that happens, we should expect a meaningful drop in natural gas prices.
This industry-wide predicament was highlighted by Aubrey McClendon, CEO of Chesapeake Energy (CHK-NYSE) on his company's earnings conference call. Mr. McClendon, the poster child for aggressive gas production management during periods of weak gas prices, announced his company was not planning to curtail production since it expected storage to max out and thus they, along with all other producers, would be forced to shut in flowing gas volumes. For the first time, Chesapeake was not about to exhibit discipline in supporting gas prices for the benefit of producers who did not curtail their production. Does this suggest that leaders of the natural gas industry are prepared to ignore production economics to demonstrate a point to their fellow producers?
We have been watching and writing about the travails of the domestic gas business as the collapse in the drilling rig count does not seem to have dented gas production as everyone assumed. Since we last opined on the gas market, the Energy Information Administration (EIA) has released its monthly gas production estimates gleaned from their Form 914 survey of operators. These surveys, reportedly providing the industry with more accurate production data, started in 2005. The only problem is that the data is still dated as the latest monthly estimated production volume figure released was for May, some 60 days old.
The May 914 gas production was 62.84 billion cubic feet per day (Bcf/d), down from the revised April monthly data showing production of 63.35 Bcf/d. Many analysts, gas producing company executives and forecasters jumped on this decline as confirmation the long-anticipated gas production decline was underway. On closer examination, however, we can't be totally sure because there have been a number of other recent months when the initial monthly gas production estimate was revised lower. The initial May production estimate now is virtually identical to the revised December 2008 estimate.
The initial gas production estimate for April was revised down, but only from 63.37 Bcf/d to 63.35 Bcf/d. The revised April production estimate was down from the March revised figure by approximately 200 million cubic feet per day (MMcf/d), but it was essentially flat with the revised February production estimate of 63.58 Bcf/d. Can we take solace in the May production estimate decline? Is the recent monthly revision pattern being reduced a sign that when the May estimate is revised it too will show even lower production?
Since January 2005, there have been 52 revisions to the initial monthly production estimate. One revision showed no change. Of the remaining revisions, 33 were higher than the initial estimate and 18 were lower. Increased estimates were made nearly two-thirds of the time. Admittedly, there were stretches when the revisions were always up, just as there were stretches when they were all lower. At the moment, we appear to be in a period marked by mostly lower revisions, but we can't find any rhyme or reason why historical patterns of revisions shifted from mostly up to down or vice a versa.
Given the data history showing such a strong bias in favor of increased monthly production estimate revisions, we remain skeptical in calling for a further reduction for May's initial estimate.
The other concern we have had about the gas production scenario is the developments in the drilling rig market. We, along with everyone else, watched with horror last fall as the domestic drilling rig business entered a freefall. We and others have wrestled with determining exactly how far down the rig count would go in this market correction and when it might bottom. More recently we have begun focusing on the pace and shape of the rig count's recovery.
One aspect of the drilling industry decline that has been of particular significance for the gas business has been the difference in the type of drilling rigs that were being laid down. This interest has gained significance by the emergence of the gas-shale plays. Data has shown that wells drilled horizontally in these gas-shales have tended to be more prolific than wells drilled vertically. The guiding principal behind the significant initial production volumes coming from gasshale wells has been the successful marriage of horizontal drilling technology with improved formation fracturing capability. Drillers have been able to rapidly drill long lateral well sections in the heart of many of the gas-rich formations. Well stimulation technology has enabled the development of multiple stage fracturing applications within the same well bore. Together these technologies have produced gas wells with initial production volumes multiples of conventionally drilled and completed gas well volumes.
We showed in our last Musings drilling and production data for Fayetteville gas shale wells derived from Southwestern Energy's (SWN-NYSE) financial reports. The data, covering a two-year period since early 2007, showed significant progress in drilling time, drilling performance and well production. The length of time required to drill the wells fell from 20 days to 12 while the lateral distance drilled increased 84% to almost 3,900 feet. At the same time, the 30-day average production rate grew from 1,006 MMcf/d to 2,373 MMcf/d.
Given the growing importance to the nation's production of natural gas from wells drilled horizontally, we examined overall gas production figures versus measures of drilling rig activity. When gas production is paired with gas-oriented drilling rigs, one sees a dramatic fall-off in rigs since last fall with barely any movement in the Form 194 monthly gas production volumes so far this year, based on the initial monthly production estimate.
On the other hand, if we match the same Form 914 gas production volumes against the number of active horizontal rigs, we also are hard pressed to see any impact from the downturn in drilling.
On the other hand, if we plot the percentage of all rigs drilling horizontally, there is a pattern of a steady increase as gas production increased and as it is holding steady now.
While we were wrestling with this data, we came across an interesting article by Arthur Berman published in World Oil and republished by the Association for the Study of Peak Oil in its latest newsletter. In the article, Mr. Berman re-analyzed well production data from the Barnett Shale, the initial stimulus for the gas-shale drilling explosion. He updated the data from the roughly 2,000 horizontal wells that he initially studied two years ago. Based on this new study of well performance, he concluded the following points: there is little correlation between the initial production rate and the well's ultimate recoverable reserves; the life of average well production is shorter than predicted; the volume of commerciallyrecoverable gas has been over-stated; core areas of the play do not provide higher recoverable reserves; recoverable reserves from horizontal wells are no greater than reserves in vertical wells; and average well performance has decreased consistently since 2003 for horizontal wells.
The key finding of the study, and a point that will hearten those who are arguing that the fall-off in gas production is imminent due to the drilling collapse, is that the overall ultimate recoverable reserves from horizontal wells decreased by 30% from Mr. Berman's earlier projection. Additionally, he found that the average ultimate recoverable reserve estimate per well fell from 1.24 Bcf to 0.84 Bcf. These findings reflect the fact that "most wells do not maintain the hyperbolic decline projection indicated from their first months or years of production." What Mr. Berman found was that wells experienced an abrupt negative departure from the hyperbolic decline as early as 12-18 months, but more likely in the fourth of fifth year of the well's production. This conclusion may temper the expectation of a significant fall-off in gas production given the drilling rig cutback.
What Mr. Berman discovered in updating his study was that the decline curves are rapid and more severe than previously thought, so the ultimate amount of reserves recovered from producing wells is less than originally thought. For those who believe in the longterm positive outlook for the oil service industry, this finding is highly supportive. On the other hand, the fact that these gas wells don't fall off their hyperbolic decline curves as quickly as some people have thought (or hoped for) may signal that the domestic land rig count might experience another downturn when natural gas prices hit the wall as gas storage capacity fills to the brim. Or possibly the rig count will experience a much longer and more gradual recovery than currently expected.
Additional findings from Mr. Berman's study point to less favorable production economics from horizontal wells. Mr. Berman focused a part of his study on the wells in the "sweet" spot of the Barnett formation, or those wells located in Tarrant and Johnson counties in and around Ft. Worth, Texas. This area comprises about 9.5 million acres. What he found was that this sweet spot did not produce appreciably higher ultimate recoverable reserves per well than the overall play. Horizontal wells only resulted in about a 31% improvement in reserves recovered compared to their 2.5-times greater cost; not a positive for profitability. This conclusion suggests that many of the claims about low costs associated with the gasshale plays may prove inaccurate. According to Mr. Berman, "If every operator in the Barnett Shale was hedged at a netback gas price of $8/Mcf, only 31% of horizontal wells would break even or make money. At $6/Mcf, only 15% of wells would reach this commercial threshold." Does this analysis suggest that many of the gas producers are deluding themselves about how successful they are progressing in developing gas shales? Will the new gas-shale plays really have better economics? Are producers who suggest they have superior acreage positions and better technology really exceptional? Maybe they are all citizens of Garrison Keillor's Lake Wobegon where everyone is "above average."
http://www.rigzone.com/news/article.asp?a_id=79414
Is It Possible to Have Sub $4/Mcf Gas for Five Years?
by G. Allen Brooks, Managing Director
Parks Paton Hoepfl & Brown
Rigzone
Tuesday, August 04, 2009
Two weeks ago we attended a presentation at the Petroleum Club where Jim Simpson of BENTEK Energy, LLC, a natural gas oriented analytics firm, presented his case for sub $4 per thousand cubic feet (Mcf) natural gas prices through 2010. His audience at the Houston Producers Forum consisted of 160 energy and financial executives. Following his presentation and in response to the first question from the audience, he dismissed the likelihood this distressed price scenario would last for 10 years as low gas prices did throughout the 1990s, but he did say it was possible the low price could last five years.
If that answer wasn't depressing enough, he responded to the second question about the impact of Exxon's Horn River gas discoveries in Canada on the U.S. market by saying he could not rule out the possibility of sub $3/Mcf natural gas prices for a period of time. Following the second question no one in the audience ventured another - possibly out of fear that they would be bidding down the estimate of future gas prices. Stop while you're ahead seemed to be the mantra. As the moderator thanked the presenter, the shell-shocked audience began to drift out of the dining room. The only missing ingredient among the darkness of the room and the dark mood of the audience was a funeral dirge playing in the background.
Is it possible that natural gas prices might never recover to their lofty levels of earlier this year (five years is virtually a lifetime for most investors)? On the other hand, one can rightly ask: What does Mr. Simpson know? His is only a forecast and we know the spotty record of energy price forecasters. He did, however, bring some telling data and insights that must be considered, but in the end a forecast is a forecast and it depends on critical assumptions, one being that current market conditions and company actions continue as they have in the past, assumptions that become suspect when dealing with energy markets.
In light of the surge in unconventional natural gas production and weak demand fundamentals, natural gas prices have been depressed throughout 2009 despite crude oil prices rallying back to almost half of their historic high of last July. Mr. Simpson's analysis examined changes in natural gas supply and demand and how successful development of the new unconventional gas-shale resources has created a significant oversupply that is depressing current gas prices. Part of the problem plaguing natural gas as Mr. Simpson pointed out is geography - the location of new gas supplies and gas consuming markets given transportation capacity limitations for moving the growing supply volumes.
Mr. Simpson explained the problem with a chart showing the total capacity of all pipelines out of the Southeast/Gulf Coast region that has been fixed at 23 Bcf/d for a number of years. He then showed how net pipeline outflows have grown over time trimming the unutilized capacity each winter season. The production flows were defined as regional production plus inbound flows from other basins plus storage withdrawals and LNG imports minus intraregional gas demand and storage injections. From the winter of 2005-6 to last winter, the nominal surplus pipeline capacity has shrunk from 7.5 Bcf/d to 3.5 Bcf/d, or by more than half. As gas shale production in this region and/or LNG shipments continues to increase, we can expect a further shrinking of available pipeline capacity putting the brakes on supply growth. Will those brakes limit western gas inflows to the region, LNG shipments or gas-shale production growth?
In a nutshell, Mr. Simpson's analysis is that falling natural gas demand coupled with rising gas supplies have placed gas producers in a box. The box is caused by a lack of adequate long-haul pipeline capacity in the geographic region spanning from East Texas to the Texas Gulf Coast and across Louisiana to Mississippi (an area referred to as an "I"). This capacity constraint restricts more costly gas supplies located west of the pipelines' terminus points because the market is adequately served by cheaper gas volumes. Not only are more expensive western gas supplies fighting cheaper shale-gas production for access to the long-haul pipelines and the consumer markets in the Northeast, Midwest and Southeast regions of the country, but they also are competing with Gulf of Mexico gas and liquefied natural gas (LNG) supplies arriving from overseas markets.
Compounding the gas producers' problem is that current natural gas prices are below finding and development costs for many of the traditional western gas basins, making it difficult for them to compete for markets. Gas-shale basins have evolved into real estate and engineering plays in contrast to exploration plays. The ubiquitous nature of natural gas shales in this country has reduced the need for exploration; witness the collapse of the open-hole wireline logging market in the United States. The key for gas-shale profitability is to assemble as much prime acreage (that which possesses the thickest gas seams that can be easily exploited) and figure out how to drill, complete and produce the wells at the lowest cost.
Another advantage for many of the gas shales is that they are located either within the pipeline "I" or immediately adjacent. This gives them a location advantage and reduces the transportation cost. In addition, some of newly developing gas-shale plays are situated east of the pipeline terminus points allowing them access as the lines move north or east. At the root of the supply problem, however, is that the gas-shale wells are proving to be highly prolific resulting in low gas costs, even below currently weak gas prices, which further encourages their development. The growth of unconventional gas supplies is slowly displacing conventional natural gas production in this country.
Producers of unconventional gas supplies have been successful in reducing meaningfully their finding and development cost in recent months. Some of the cost savings have come from the oversupply of oilfield equipment and services that has contributed to lower service company prices, while continued technological improvements in accessing and extracting the gas from these challenging formations have also contributed.
We have used several of the slides from Mr. Simpson's presentation to further explain his argument. In addition, we have updated one critical slide he used to demonstrate the impact of development efficiencies for gas-shale producers. The key assumption in Mr. Simpson's analysis is the fall in natural gas demand, which he estimates has shrunk by 1.9 billion cubic feet per day (Bcf/d). The recession-induced consumption declines among industrial and commercial customers and reduced gas use by residential users was offset somewhat by higher natural gas use to generate electricity.
On the supply side, Canadian natural gas imports into the U.S. are off by approximately 1.4 Bcf/d, while LNG imports are higher by 0.3 Bcf/d. Mr. Simpson estimates that domestic natural gas production is higher by 2.0 Bcf/d, which is consistent with most other estimates. The net increase in gas supplies of 0.9 Bcf/d, when combined with the 1.9 Bcf/d demand fall, means the gap between gas supply and gas demand has grown to 2.8 Bcf/d. That gap represents approximately 4.5% of annual natural gas consumption based on 2008's total consumption of 23.2 trillion cubic feet, or roughly 63.6 Bcf/d. Can this gap be closed?
In Mr. Simpson's estimation closing this gap will prove difficult. The challenge is due to the rapidly growing output from gas-shale basins, which is driven by their low development costs. Mr. Simpson argues that based on data his firm has access to, which is essentially daily production flows into pipelines, despite the significant drop in gasdirected drilling, production has not fallen off commensurately. We have re-created the essence of a slide Mr. Simpson used that showed the total U.S. rig count versus production, which he defined as gross gas withdrawals. One difference is that we elected to use the Baker Hughes gas-directed rig count rather than the total rig count. If we simply used the Energy Information Administration's (EIA) data on monthly gross gas withdrawals, our daily numbers came out much higher than on Mr. Simpson's slide. We then removed the volume of gas the EIA says is used for repressuring fields. Since that data is published with a long lag time, we calculated the average daily re-injected volumes for 2006 and 2007 and applied this average to the gross withdrawal estimates. When we plotted the results, our gross gas withdrawal estimates for 2009 showed more volatility than Mr. Simpson's chart.
One might argue the recent monthly gross gas withdrawal declines reflect production responses to the dramatic decline in gas drilling we have experienced so far this year. Others might see the monthly fluctuations as too modest to assume a trend change and thus argue that gas production is essentially flat. This was Mr. Simpson's argument, and he said he based his conclusion on data his firm gets daily. Since we don't have access to his data, or know exactly where it comes from, we cannot explain the discrepancy between the two charts. What we can say about our chart is that if production has begun a downturn, it required a huge drop in the gas-directed drilling to move the needle. Of course, it is possible the monthly data variations are the result of producers shutting-in gas production due to low prices.
There were two other aspects to Mr. Simpson's analysis about the lack of production response to the falling rig count. First was the drilling efficiency improvement impact on production growth. Secondly, the improved economics for gas-shale wells due to lower total development expenditures versus increased total production. Fewer wells and greater initial production, even with higher well costs, has translated into improved economics.
To demonstrate his point, Mr. Simpson showed a slide with data on drilling and production in the Fayetteville gas shale formation taken from the 10-Q reports of Southwestern Energy Company (SWNNYSE) for the first quarter of 2007, the first quarter of 2008 and the fourth quarter of 2008. We have updated the data through the first quarter of 2009, which not only further supported Mr. Simpson's observations, but also added some additional insight. A crucial point in the Southwestern Energy data is the dramatic reduction in the time required to drill the wells even as their average lateral length increased. Additionally, the wells are showing progressively greater average production during their first 30 days of operation.
The improved drilling performance has slowed the pace of cost increases for these Fayetteville wells. With dramatic improvement in initial production additions per rig per year, the improving profitability of these gas shale wells is clear and helps explain why producers such as Southwestern Energy are inclined to continue drilling these highly profitable wells.
When one examines the data for the 30-day average production rate per well and the IP additions per rig per year, there was a noticeable decline between the fourth quarter of 2008 and the first quarter of 2009. Southwestern Energy explained this quarterly variance as due to the delay in the expansion of the Boardwalk Pipeline that caused the company to develop a backlog of finished wells that could not be hooked up upon completion. When the pipeline expansion was completed, Southwestern Energy commenced hooking up the backlogged-wells based on the wells' productive volumes. Therefore, the 2007 fourth quarter benefitted from more high-flow-rate wells beginning production as some lower-volume producing wells drilled in the quarter were shifted into 2009 for hookup.
To demonstrate this point, Southwestern Energy detailed its monthly well performance. The initial production for wells hooked up in January and February 2009 was around 2,800 MMcf/d in contrast to the March production rate that was in excess of 3,300 Mmcf/d and the estimated rate in April (based on data for the first half of the month) of nearly 3,800 Mmcf/d. When one annualizes the production gains it becomes clear that the historic trend in initial well productivity and the IP additions per rig per year would have continued had wells been hooked up as they completed during the fourth quarter of 2008 and the first quarter of 2009, rather than being shifted around.
The main message from Mr. Simpson's analysis is that the efficiency performance of gas-shale producers will keep them drilling and producing. The net impact is that their development costs are falling and, in many cases, are below current spot gas prices and certainly below the prices suggested by the forward strip for natural gas prices. These trends will continue to put pressure on the more costly western gas basins, especially when it comes to seeking pipeline access. Add into this mix the potential for additional LNG volumes at what can be very low prices and more Canadian gas imports as a result of that country's storage capacity rapidly filling, we could see more downward pressure on natural gas prices.
Countering the negative forecast for natural gas prices, the analysts at Bernstein Research recently issued a report arguing that the base production of U.S. natural gas is declining at an annual pace of 30% in 2009. They believe that if the U.S. gas rig count remains flat for the balance of this year, gas production from December 2008 to December 2009 will be down by 10.5%, implying in their view a switch from an oversupply of 1-2 Bcf/d to an undersupply of 4-5 Bcf/d. Since they believe gas supply will decline sharply in the summer months, they expect gas prices to rise during the second half of 2009.
The firm's analysis is based on measuring the increase in the annual decline rate for natural gas wells and the contribution to production from new well drilling. The challenge in any analysis of the natural gas market is to understand the contribution from the unconventional gas shales. The Bernstein analysis begins with the EIA's chart showing the relative contribution to total natural gas supply in the U.S. from conventional onshore, unconventional onshore and offshore gas production. The growing contribution from onshore unconventional supplies is clear.
When production is examined on an annual basis it becomes clear that the domestic gas industry is facing an accelerating decline rate. This means gas producers must either drill more wells per year, assuming they continue to find the same size producing wells, or they need to find wells with greater production. Therein lays the great attraction with the gas-shale reservoirs around the country.
Next they demonstrated that gas supply in the U.S. has become a real-time drilling issue. The chart showing the percentage of gas produced from wells drilled in the previous three years clearly demonstrates that conclusion. In fact, the last two years show a sharp increase in the trend reflecting the explosion in gas-shale drilling and production.
Equally important to understand about gas-shale production is not only its significant initial well production but also its rapid depletion. As the Bernstein analysis shows, non-horizontal gas wells tend to have about 45% decline rate in the first year while horizontal wells experience about a 62% rate, based on the data for 2007 and 2008. This means gas producers are on a sharply upward sloping treadmill of drilling if they wish to sustain let alone increase production.
In order to estimate how much additional gas supply can come from drilling this year, the Bernstein analysts examined the contribution to 2007 gas supply additions by the type of well drilled. What their analysis showed was that vertical wells drilled the bulk of all gas wells drilled that year and added the greatest share of volume. What is noticeable about the data, however, is the relative contribution per well by the various wells drilled. Offshore wells added the most gas supply per well by a wide margin, but both horizontal and directional onshore wells contributed more than twice that of vertical onshore wells.
Using the 2007 gas volume contributions by well type, the Bernstein analysts then moved on to see how much additional gas supply could come from drilling activity this year. They assumed there would be no change to the current rig count for the balance of the year. They did assume that because of the industry downturn, rigs drilling this year would be more efficient and better prospects would be drilled. This led them to assume an increase in the wells per rig that would be drilled and in the average December contribution per new well. Based on those assumptions and analysis below, the Bernstein analysts calculate that there will be a 10.5% reduction in production between December 2007 and December 2009.
We have one issue with the Bernstein analysis: why do horizontal land rigs and wells not experience the same improvements as the vertical and directional categories? If we grant horizontal the same improvement total December volumes are 58.05 Bcf/d, or only down 1.3% from the December 2007 volumes. That one change in assumptions makes a huge change in the conclusion.
The issue of the gas futures price trend recently has been highlighted by a growing debate over whether greater controls should be placed on the futures trading market in an effort to restrain "speculators" from driving prices higher. While the possibility of tighter regulations in the commodity futures market is mostly focused on crude oil, any changes in the regulation of traders will impact all U.S. commodity markets.
The U.S. Natural Gas Fund (UNG-NYSE), a mutual fund that enables individuals to invest in natural gas futures, has been
questioned about its role in accentuating gas futures price moves due to its size. In a recent 8-K filing, UNG produced a chart showing the funds' growth, i.e., increase in futures contracts held as natural gas futures prices have fallen. UNG is using this chart to help dispel government attempts to put more restrictive limits on the number of futures contracts that traders, i.e., the fund, can hold.
The larger issue raised by UNG's price and holdings chart is whether the fund has actually supported natural gas prices at higher levels than they would have traded absent the fund buying activity. One clearly sees that the dive in natural gas prices seemed to stop when the fund began to expand and gas prices have moved higher and stabilized as the fund grew even more. There is little doubt that natural gas has become identified as the best fuel to bridge the transition in energy eras for the United States from one dominated by "dirty" fuels to one marked by "cleaner" fuels so it is reasonable to expect increased investor interest.
So far this year, the disparity between the price-to-energy-value of crude oil to natural gas has been volatile, but for much of the year it has been above the average of the past 15 years. Today the disparity is at an all-time high. In expectation of increased demand for natural gas and the extreme price disparity, investors have embraced the "natural gas trade" - buy natural gas futures and sell crude oil futures. The heightened investor interest in this trade explains much of the UNG fund's growth this year. Intuitively the growth of the fund has supported natural gas futures prices at higher levels than supply/demand fundamentals would support.
Natural gas pricing this year may have sent the wrong signals to the E&P companies who were making decisions about drilling gas wells. There might have been a swifter and deeper gas-directed rig count fall-off this spring if gas prices had fallen faster and farther than they did. At current prices, producers drilling in most gas-shale basins are still making money. It would not have been the case if prices were lower. As a result, we may have entered an extended period of natural gas oversupply from sustained drilling despite low prices.
This realization may be behind comments by oilfield service company CEOs on their second quarter earnings conference calls about the pace of the industry recovery. Dave Lesar, Halliburton Companies' (HAL-NYSE) CEO characterized it this way, "Due to continued weakness in natural-gas demand ... we believe it is unlikely that there will be a meaningful recovery in natural gas prices and, consequently, drilling activity for the remainder of the year."
Our own view is that natural gas is in an extended period of low prices driven by a combination of weak gas demand due to the anemic economic recovery and continued gas supply growth from domestic production, Canadian imports and additional LNG deliveries. Like Mr. Simpson, we don't believe this will be a decadelong experience. Could it last five years? Possibly, but then again, no one knows. Absent a greater cutback in drilling and a more rapid falloff in production than we are currently seeing or a sharp upturn in gas-consumption, the domestic natural gas market may be in for an extended depressing period.
http://www.rigzone.com/news/article.asp?a_id=78944
August 26, 2009
Critics say work on power lines premature
COMMENT: As the Alberta government writes legislation to push transmission projects ahead, the BC government is similarly about to issue a special order to the BC Utilities Commission in response to its end-of-July rejection of BC Hydro's Long Term Acquisition Plan.
Alberta's Bill 50 says "The Lieutenant Governor in Council may designate as
critical transmission infrastructure a proposed transmission facility". Hearkens back to the Bill 30 change to BC's Utilities Commission Act which said local government no longer has zoning authority with respect to power projects on Crown land. It's even more ominous in the context of the Throne Speech references to advancing the "Northern Energy Corridor".
By Darcy Henton
Edmonton Journal
August 26, 2009
'A total disrespect for . . . legislative process'
A move by the Alberta government to authorize two companies to start work on controversial state-of-the-art north-south transmission lines in advance of approval by the Alberta Utilities Commission has sparked outrage from consumers.
Alberta Energy announced Tuesday that AltaLink and ATCO Electric may begin design work, environmental assessments, siting options and consultations for the proposed 500-KV direct current lines between Calgary and Edmonton.
But critics say the move is premature and they're unconvinced the two high-voltage lines are needed.
They say there must to be an independent assessment of the need for the lines before they are constructed because consumers will be stuck with the multibillion-dollar bill.
"It's outrageous," said Sheldon Fulton, executive director of the Independent Power Consumers Association of Alberta. "They're short-circuiting their own process. Nobody has demonstrated a need for these lines."
Fulton said the province "is not playing by anybody's rules."
Gary Holden, president of Calgary-based Enmax, says the Alberta Utilities Commission is much better qualified than the Conservative cabinet to make the decision on the size and scope of new transmission lines that will ultimately be paid for by consumers.
"We're in strong support of the Alberta Utilities Commission having direct and thorough control over the utility companies running amok with costs," he said. "To disenfranchise the Alberta Utilities Commission at a time when we probably need it the most goes against the quality of the regulatory framework we've been using the last five decades. We think consumers are in for a rough ride."
Holden says research by his company shows the amount of electricity being transmitted over the existing lines has actually dropped back to 2005 levels and the two "expensive" new lines are a massive overbuild.
He said Enmax is building three gas-fired electrical generating plants in the Calgary area that will further reduce the need for the lines.
"We keep bringing the north-south transfers down such that more transmission isn't needed at all," he said. "These are factual points that are yet to be considered and the place where they should be considered is at the Alberta Utilities Commission."
The Conservatives under Premier Ed Stelmach have introduced legislation to eliminate the legal requirement for a hearing to determine whether the lines are needed, but the bill won't be debated until the fall session of the legislature.
Critics have questioned whether the province even has the legal authority to launch the project before it uses its massive majority in the legislature to pass Bill 50.
"This is a total disrespect for the legislature and the legislative process," said Liberal MLA Hugh MacDonald.
But Alberta Energy spokesman Bob McManus says there's no connection between the companies being given the authority to start work and the bill before the House.
"This is separate and distinct from Bill 50," he said. "This is not an unusual practice. The preliminary work by the firms to go out and look at the potential routes and that sort of thing is routinely decided prior to needs hearings."
He said the projects have been identified by the Alberta Electric System Operator as critical in its 20-year plan and, the sooner the lines are built, the better for consumers.
"The benefit is people will continue to have reliable power past 2014," he said. "The cost if the projects don't go ahead could be problems providing safe, secure, reliable electricity for the entire province."
Joe Anglin, who heads a landowner group near Rimbey, accused the government of putting "the cart before the horse" by launching the project before passing the necessary legislation empowering it to do so.
"Everything they have done to this point is just farcical," he said.
He compared the scope of the project to building a congestion-free provincial road system with interchanges at every intersection instead of stop lights.
"It's uneconomical. You wouldn't do it with your road system and it doesn't make sense for the grid. We'll overbuild this thing and the public will pay through the nose for it."
Spokesmen for Epcor and Capital Power, which now operates Epcor's generating stations, applauded the move, saying construction of the lines is long overdue.
"New power transmission capacity is urgently needed in Alberta," said Epcor spokesman Tim le Riche. "No major transmission system additions have been made in Alberta for 20 years."
But Jim Wachowich, counsel for the Alberta Consumers Coalition, says the province needs to demonstrate to consumers why it needs two direct current lines when alternating current lines are cheaper. It also needs to explain why consumers are paying for lines that will likely be used to export power for the benefit of generators, he said.
"We're skeptical of them overbuilding the system and pre-building export capacity on the tab of the Alberta utility customer."
Fulton, whose association represents industrial power users, questioned why the projects were not put out to tender and the logic of how having two companies building separate lines would be cost efficient.
But officials with Altalink and ATCO said their costs will be scrutinized by the Alberta Utilities Commission and they will strive to build the lines on time and on budget.
"I know there will be a lot of angst with the dollar amount," said ATCO Electric president Sett Policicchio. "Our costs will get scrutinized by the interveners very closely."
© Copyright (c) The Calgary Herald
‘Peak Oil’ Is a Waste of Energy
By MICHAEL LYNCH
New York Times
August 24, 2009
REMEMBER “peak oil”? It’s the theory that geological scarcity will at some point make it impossible for global petroleum production to avoid falling, heralding the end of the oil age and, potentially, economic catastrophe. Well, just when we thought that the collapse in oil prices since last summer had put an end to such talk, along comes Fatih Birol, the top economist at the International Energy Agency, to insist that we’ll reach the peak moment in 10 years, a decade sooner than most previous predictions (although a few ardent pessimists believe the moment of no return has already come and gone).
Like many Malthusian beliefs, peak oil theory has been promoted by a motivated group of scientists and laymen who base their conclusions on poor analyses of data and misinterpretations of technical material. But because the news media and prominent figures like James Schlesinger, a former secretary of energy, and the oilman T. Boone Pickens have taken peak oil seriously, the public is understandably alarmed.
A careful examination of the facts shows that most arguments about peak oil are based on anecdotal information, vague references and ignorance of how the oil industry goes about finding fields and extracting petroleum. And this has been demonstrated over and over again: the founder of the Association for the Study of Peak Oil first claimed in 1989 that the peak had already been reached, and Mr. Schlesinger argued a decade earlier that production was unlikely to ever go much higher.
Mr. Birol isn’t the only one still worrying. One leading proponent of peak oil, the writer Paul Roberts, recently expressed shock to discover that the liquid coming out of the Ghawar Field in Saudi Arabia, the world’s largest known deposit, is around 35 percent water and rising. But this is hardly a concern — the buildup is caused by the Saudis pumping seawater into the field to keep pressure up and make extraction easier. The global average for water in oil field yields is estimated to be as high as 75 percent.
Another critic, a prominent consultant and investor named Matthew Simmons, has raised concerns over oil engineers using “fuzzy logic” to estimate reservoir holdings. But fuzzy logic is a programming method that has been used since I was in graduate school in situations where the factors are hazy and variable — everything from physical science to international relations — and its track record in oil geology has been quite good.
But those are just the latest arguments — for the most part the peak-oil crowd rests its case on three major claims: that the world is discovering only one barrel for every three or four produced; that political instability in oil-producing countries puts us at an unprecedented risk of having the spigots turned off; and that we have already used half of the two trillion barrels of oil that the earth contained.
Let’s take the rate-of-discovery argument first: it is a statement that reflects ignorance of industry terminology. When a new field is found, it is given a size estimate that indicates how much is thought to be recoverable at that point in time. But as years pass, the estimate is almost always revised upward, either because more pockets of oil are found in the field or because new technology makes it possible to extract oil that was previously unreachable. Yet because petroleum geologists don’t report that additional recoverable oil as “newly discovered,” the peak oil advocates tend to ignore it. In truth, the combination of new discoveries and revisions to size estimates of older fields has been keeping pace with production for many years.
A related argument — that the “easy oil” is gone and that extraction can only become more difficult and cost-ineffective — should be recognized as vague and irrelevant. Drillers in Persia a century ago certainly didn’t consider their work easy, and the mechanized, computerized industry of today is a far sight from 19th-century mule-drawn rigs. Hundreds of fields that produce “easy oil” today were once thought technologically unreachable.
The latest acorn in the discovery debate is a recent increase in the overall estimated rate at which production is declining in large oil fields. This is assumed to be the result of the “superstraw” technologies that have become dominant over the past decade, which can drain fields faster than ever. True, because quicker extraction causes the fluid pressure in the field to drop rapidly, the wells become less and less productive over time. But this declining return on individual wells doesn’t necessarily mean that whole fields are being cleaned out. As the Saudis have proved in recent years at Ghawar, additional investment — to find new deposits and drill new wells — can keep a field’s overall production from falling.
When their shaky claims on geology are exposed, the peak-oil advocates tend to argue that today’s geopolitical instability needs to be taken into consideration. But political risk is hardly new: a leading Communist labor organizer in the Baku oil industry in the early 1900s would later be known to the world as Josef Stalin.
When the large supply disruptions of 1973 and 1979 led to skyrocketing prices, nearly all oil experts said the underlying cause was resource scarcity and that prices would go ever higher in the future. The oil companies diversified their investments — Mobil even started buying up department stores! — and President Jimmy Carter pushed for the development of synthetic fuels like shale oil, arguing that markets were too myopic to realize the imminent need for substitutes. All sorts of policy wonks, energy consultants and Nobel-prize-winning economists jumped on the bandwagon to explain that prices would only go up — even though they had never done so historically. Prices instead proceeded to slide for two decades, rather as the tide ignored King Canute.
Just as, in the 1970s, it was the Arab oil embargo and the Iranian Revolution, today it is the invasion of Iraq and instability in Venezuela and Nigeria. But the solution, as ever, is for the industry to shift investment into new regions, and that’s what it is doing. Yet peak-oil advocates take advantage of the inevitable delay in bringing this new production on line to claim that global production is on an irreversible decline.
In the end, perhaps the most misleading claim of the peak-oil advocates is that the earth was endowed with only 2 trillion barrels of “recoverable” oil. Actually, the consensus among geologists is that there are some 10 trillion barrels out there. A century ago, only 10 percent of it was considered recoverable, but improvements in technology should allow us to recover some 35 percent — another 2.5 trillion barrels — in an economically viable way. And this doesn’t even include such potential sources as tar sands, which in time we may be able to efficiently tap.
Oil remains abundant, and the price will likely come down closer to the historical level of $30 a barrel as new supplies come forward in the deep waters off West Africa and Latin America, in East Africa, and perhaps in the Bakken oil shale fields of Montana and North Dakota. But that may not keep the Chicken Littles from convincing policymakers in Washington and elsewhere that oil, being finite, must increase in price. (That’s the logic that led the Carter administration to create the Synthetic Fuels Corporation, a $3 billion boondoggle that never produced a gallon of useable fuel.)
This is not to say that we shouldn’t keep looking for other cost-effective, low-pollution energy sources — why not broaden our options? But we can’t let the false threat of disappearing oil lead the government to throw money away on harebrained renewable energy schemes or impose unnecessary and expensive conservation measures on a public already struggling through tough economic times.
Michael Lynch, the former director for Asian energy and security at the Center for International Studies at the Massachusetts Institute of Technology, is an energy consultant.
August 25, 2009
Time to unleash seabed methane?
Anna Barnett
Climate Feedback
the climate change blog
August 21, 2009
 Methane actively dissociating from a hydrate mound / National Energy Technology Lab |
Following an enthusiastic Congressional testimony, Ray Boswell of the US Department of Energy's National Energy Technology Laboratory (NETL) has a commentary in Science on hydrates’ potential as an energy source. But methane hydrates are also making headlines this week as a worrying harbinger of climate change. Some scientists have warned that ocean warming could destabilize hydrates and send methane gas bubbling into the ocean. Now a team led by Graham Westbrook of the University of Birmingham has spotted over 250 such gas plumes near Svalbard, Norway - echoing a similar observation from a group in Siberia earlier this year.
Much of the released gas dissolves in the water column, but any portion that reaches the air could amplify warming.
By drilling for hydrates, could we wake a sleeping giant? Boswell doesn’t tackle this question head on, but he offers some relevant points.
First off, hydrates in the Arctic - where gas plumes have been seen - are hard to get at. Before they go messing with the permafrost lid that protects the vast northern stores of methane, prospectors will find more enticing targets, says Boswell. Specifically, it’s hydrates found in sandy deposits in the Gulf of Mexico that are raising hopes at NETL.
Hydrate-bearing sands were first spotted off Japan in 1999. By recent estimates the Gulf of Mexico holds 190 trillion cubic meters of natural gas in such sands - over 300 times the amount of gas the US burns annually. An April expedition to probe the Gulf's deposits found promising pockets of highly saturated hydrates. There are technical and economic hurdles to extracting this gas, says Boswell, but many could be overcome with existing technology. That's a big difference from the hydrates known a decade ago, which were dispersed across muddy fields or packed into solid mounds.
Methane from sandy hydrates may also be easier to control. Boswell writes:
These resevoirs are commonly buried many hundreds of meters below the sea floor and enclosed in a matrix of impermeable sediments that help to prevent the escape of released methane. The most prospective gas hydrate deposits are also those that are most effectively buffered from environmental change.
In other words, drillers are keen to avoid the escape of methane - they want to get it to customers who’ll burn it.
Speaking of which, does the world need another fossil fuel reservoir? Not if you’re hoping our supplies will run out in time to save the climate. But with the world facing dwindling oil reserves and a sluggish start on renewables, Boswell implies the gas could fill an important gap: “hydrates may offer an important ‘bridging’ fuel that will help ease the transition to the sustainable energy supplies of the future.”
August 23, 2009
Natural-gas producers hoping for cold winter
COMMENT: This is kind of funny. Here we've got gas drillers drilling like carpenter ants on speed, and producers producing like broken fire hydrants and now they're complaining that the price isn't good enough. Here in BC, our government is putting every giveaway incentive in place to encourage even more profligate production of natural gas into a market that doesn't want any more.
And what is their collective strategic response to a market awash in gas, and driving prices to lows not seen for years? Praying for hurricanes, for goodness sake.
Would any of them sit back and (as we've said before), hold off until production and demand fall back into some balance, and prices rise again? Not government, so dependent on revenues from the auctions of drilling rights and gas royalites. And certainly not industry.
Because these drillers and producers are programmed to do one thing only. Given changing circumstances, they still do the one thing they know how to do. In natural systems, the incapacity to adapt to changing circumstances leads to extinction. For corporations, bankruptcy. The number of producers and affiliated businesses in creditor protection is at an all time high. With more queued up.
And when they're not fending off creditors and laying off employees, what's left of their operation is out there drilling and producing. It's all they know how to do.
Actually, maybe it's kind of sad.
Dave Cooper
The Province
August 23, 2009
With vast underground natural-gas storage cells almost full across North America months earlier than normal, producers hope for an early, cold winter to eat up some of the surplus.
And perhaps even a hurricane or two to hit the Gulf of Mexico and take some gas production off-line.
"It's a heck of a way to run a business, hoping for storms and cold weather," said Gary Leach, executive director of the Small Explorers and Producers of Canada.
Sagging consumption because of the recession and less air-conditioner use during a cool summer in the U. S. has killed demand. But until recently, the supply has been strong from existing gas fields and new shale-gas plays.
U.S. producers are pumping more than 66 billion cubic feet of natural gas each week into storage reservoirs -- largely depleted oil and gas deposits
-- which now hold more than three trillion cubic feet of gas. The total U.
S. capacity is estimated at about four TCF.
The situation is even more dramatic in Alberta, where producers have put almost 360 BCF into the 380 BCF of storage available here.
"We hit the 360 BCF in Alberta last year, and it was the highest figure ever. But we hit that in November, and the start of winter, not August,"
said Greg Stringham, a vice-president of the Canadian Association of Petroleum Producers. "Essentially we are full right now, even though drilling has really slowed and many firms are shutting in their production. And whatever can't go into storage has to go onto the market."
And that means months of oversupply and very low gas prices.
The spot price for natural gas in New York fell below $3 US per million BTUs and kept dropping Thursday, winding up at $2.94. The average home uses 120 Gj per year. That means there is enough natural gas in storage today in Alberta to supply 3.3 million homes.
Paul Amirault, senior vice-president of Niska Gas Storage, said his facilities in the Suffield and Countess areas of southern Alberta are, like most in North America, almost full. Niska rents storage space to producers. "If customers fill their space to 100 per cent and have more gas that they want to store, that's their problem. I've seen years when the capacity approaches full at the end of the injection season [in late fall] and the gas commodity price sees downward pressure until cold weather comes."
Natural gas was trading at less than $2 per GJ throughout the 1990s, but there is hope it will rise by next summer. Gas futures are trading at $6 for August 2010 in the U. S. -- much less than the $10 price peak in 2008.
While larger oil and gas companies have shut some of their gas fields, Leach says smaller producers don't always have that option because they need the cash flow to cover their operating costs.
August 22, 2009
New meter to crank up power bills
COMMENT: Section 64.04 of the 2008 Utilities Commission Amendment Act (Bill 15) says that BC Hydro "... must install and put into operation smart meters ... by the end of the 2012 calendar year"
http://leg.bc.ca/38th4th/3rd_read/gov15-3.htm
BC Hydro has information about its Smart Metering & Infrastructure Program on its website.
Tentative costs for the smart meters component is $480-$530 million, and the entire program may cost $930 million. Ahem. In answer to the question, "Which technology will be used?", BC Hydro says, "No decisions have been made yet as to which technologies may be deployed." So much for the comfort level with the early estimates.
And in answer to the impact on electricity rates, BC Hydro says, "... impact on electricity bills ... is unknown at this time .... However, we expect the rate impact to be neutral because of the realization of benefits expected." Feeling even more comfortable now.
As to the pros and cons, BC Hydro lists the benefits, again on its website.
There is great value in knowing with a lot more granularity about when and where electricity is used. Assuming that the information isn't locked up by distributors "for competitive reasons" as propietary, it enables policies that can make for more efficient use of energy. It enables distributors to more efficiently target energy not just to an expected load, but to a load they can closely monitor.
But then, there's the cost of the meters and the installation and the meter readers who are now redundant.
And all that capital fleeing the province to the manufacturer of the meters. Oh, sure, we could insist that the meters be manufactured in BC. With BC Hydro buying 1.2 million of them, that's gotta come close to the economies of scale that make manufacturing them here cost-effective - without even considering the economic multipliers and jobs that come as a result. But with the Canadian government's latest desperate offer to President Obama ("The Canadian government has offered the U.S. guaranteed access to the provinces’ public purchases in exchange for a quick waiver of Buy American provisions") hopes of being able to do that are shrinking fast.
If the costs jack up electricity rates, and how can an expenditure of nearly a billion dollars not affect rates, that should reduce consumption. But offsetting that is the matter of inelasticity of demand for electricity and the inability of those on limited fixed incomes to take the hit.
And so on. It doesn't look to me like there will be a clear winner on this one.
Here's one story, from Australia.
Leon Gettler
The Age, Australia
http://www.theage.com.au
August 23, 2009
HOUSEHOLDS face an average $263-a-year leap in electricity bills with the installation of new smart meters that begins in 10 days' time.
A study by the St Vincent de Paul Society says that with smart meters changing billing from a flat rate to one based on the time of use, average bills will rise by 35 per cent, or about $263 a year. For pensioners, the increase will be even bigger - 42 per cent, or an extra $254 a year.
"Some customers will financially benefit while others will be penalised,'' says the report, to be released tomorrow. ''As electricity is most expensive during the day from Monday to Friday, households comprising people that are at work during the day are most likely to benefit.
On the other hand, households with young children at home, the unemployed and age pensioners [those at home during the day] are most likely to be financially worse off."
St Vincent de Paul is concerned that suppliers could misuse the meters' capacity to turn off power, and even turn off individual appliances.
Although consumers could be offered discounts in exchange for allowing the supplier to switch off appliances such as air conditioners, the report says retailers could use it to intimidate late-paying customers, effectively "putting a choker on a household's energy supply".
The report, backed by the Brotherhood of St Laurence, the Victorian Council of Social Service and other charities, will be presented to federal and state governments and energy regulators this week.
It also warns that the Federal Government's emissions trading scheme will add $200 to power bills for the average Victorian household because so much of the state's electricity comes from brown coal.
"Combined, the underlying increase in energy costs [smart meters and ETS] and the potential cost impacts associated with tariff reallocations … may increase domestic energy bills [by] as much as $490 per annum."
Electricity retailers have already warned that they will need to raise prices because of new information technology systems and the need for more employees to process the extra information. Instead of four sets of readings a year from a household, they will get more than 17,500, at half-hour intervals.
Domenic Capomolla, chief executive officer of second-tier retailer Simply Energy, said bills could rise by more than $100 a year, possibly a lot more. "One hundred dollars to $150 is a conservative number,'' he said.
The smart meter roll-out, which begins on September 1, will take an estimated four years to cover the state's 2.6 million households and 300,000 small businesses.
The first meters will be placed in homes in Broadmeadows and Melbourne's northern suburbs by distributor Jemena. Spokesman Scott Parker said the smart meters provided a much better service.
Powercor, which covers the area from Werribee to the South Australian border, and Citipower, which focuses on the inner city, will begin installing in October.
Where electricity retailers now send someone out to read meters four times a year, smart meter technology monitors the electricity consumption of households and businesses remotely, doing this every 30 minutes.
The St Vincent de Paul report warns that this will create "winners and losers" and that the meters themselves would cost $80 a year.
A spokeswoman for Energy and Resources Minister Peter Batchelor disputed the $80 fee. She said the Australian Energy Regulator's draft determination suggested the annual meter charge would average about $53 in 2010 and $25 in 2011.
She rejected suggestions that smart meters would increase costs for those least able to afford it, pointing out that the Government had brought in legislation last year requiring the independent Essential Services Commission to monitor and report on electricity prices and products. She said the Government had the power to step in if it saw that prices were "unreasonable".
"There are a range of protections available to protect vulnerable people, such as pensioners, and ensure that they can afford electricity,'' she said.
''Retailers cannot, for example, just switch the power off if someone cannot afford to pay their bill. They must work with them to develop suitable alternatives. Anyone who has problems with their energy retail company can also call the energy ombudsman who can help negotiate an appropriate solution."
Oil spill threatens ocean as driller faces multimillion bill
COMMENT: From the It Would Never Happen Here Department
Josh Gordon
The Age, Australia
theage.com.au
August 23, 2009
 The oil rig West Atlas leaks gas and oil 250 kilometres off the West Australian coast yesterday. |
THE operator of an oil rig responsible for a massive oil leak off the West Australian coast will be forced to pay millions of dollars to clean up the spill, which authorities warn poses a serious threat to the environment.
The Australian Maritime Safety Authority yesterday launched a major clean-up operation as oil and gas continued to seep from a 1200-metre-deep well drilled by the West Atlas - an oil rig located 690 kilometres west of Darwin, 250 kilometres off the far north Kimberley coast and 150 kilometres south-east of Ashmore Reef.
The spill, which is eight nautical miles long and 30 metres wide, began early on Friday, forcing the evacuation of 69 workers to Darwin.
The company responsible for the rig, PTTEP Australasia, said the leak had not yet been brought under control.
PTTEP director Jose Martins said the leak was mainly gas, with a much lower oil content than when the spill began, but the related fire risk meant it was impossible to get back on to the platform.
''So that option for bringing the leak under control is ruled out for now,'' he said.
He said early reports that poisonous hydrogen sulphide gas had been released were wrong.
The company has called in gas and oil spill experts to help with the clean-up.
The Australian Maritime Safety Authority was put in charge of the operation after the size of the spill became apparent. It warned that the remote location of the rig would make the clean-up difficult.
Authority chief executive Graham Peachey said it was too early to determine the environmental impact, cost, or when the leak would be stopped.
''It hasn't been contained but the slick hasn't grown overnight, and indications are it is either breaking down or evaporating as quickly as it is leaking out of the ocean floor, but all of that has to be confirmed by the science,'' Mr Peachey said.
While the slick remained a long way offshore and had not moved closer to the coastline, Mr Peachey said the environmental threat remained serious.
''Oil on the water is not good for the environment. What we are trying to do is mitigate the risks to the environment and to do so as quickly as we can.''
The authority has chartered a Hercules aircraft from Singapore to spray the slick with about 50 tonnes of chemicals to help disperse the oil. Two more aircraft are on standby for support.
Mr Peachey said the clean-up would be expensive but he would not speculate on the final bill.
He said only that the authority had insisted that PTTEP agree to meet the cost.
''I'd be speculating, but you can imagine, we've got two aircraft on the spot, we've got personnel all round the north, we've got a Hercules chartered from Singapore, and we've got a lot of stockpile of dispersant moved up there, so this is going to cost a lot,'' he said.
One of the evacuated rig workers told ABC Radio his colleagues had detected a gas leak and observed bubbling around one of the platform's 1200-metre-deep drilling holes.
He said the rig had been evacuated after concerns that hydrogen sulphide was leaking from the area.
Australian Marine Conservation Society director Darren Kindleysides said there was huge potential for damage to unique marine biodiversity.
''With the west continuing to grow as a frontier for oil and gas exploration, this could become more regular,'' Mr Kindleysides said.
WA Greens senator and the party's marine spokeswoman, Rachel Siewert, accused the company of withholding information and said the clean-up plan was taking too long.
''We should be putting out emergency response equipment much closer to those sites so that we don't have to wait 24 hours,'' Senator Siewert said.
August 21, 2009
(US) Permit for Alberta Clipper Pipeline Issued
Office of the Spokesman
U.S. Dept of State
Washington, DC
August 20, 2009
By Executive Order, the State Department has been delegated authority from the president to receive applications for the construction, connection, operation and maintenance of facilities at the borders of the United States, including petroleum pipelines, and to issue or deny Presidential Permits for such facilities upon a National Interest Determination. A Presidential Permit application triggers an environmental review of the proposed project, under applicable environmental laws and regulations.
After considerable review and evaluation, on August 20, 2009, the Department issued a Presidential Permit to Enbridge Energy, Limited Partnership for the Alberta Clipper pipeline. In evaluating the Enbridge application, the Department worked in consultation with all relevant agencies and parties and with extensive public and stakeholder participation and outreach.
The Department found that the addition of crude oil pipeline capacity between Canada and the United States will advance a number of strategic interests of the United States. These included increasing the diversity of available supplies among the United States’ worldwide crude oil sources in a time of considerable political tension in other major oil producing countries and regions; shortening the transportation pathway for crude oil supplies; and increasing crude oil supplies from a major non-Organization of Petroleum Exporting Countries producer. Canada is a stable and reliable ally and trading partner of the United States, with which we have free trade agreements which augment the security of this energy supply.
Approval of the permit sends a positive economic signal, in a difficult economic period, about the future reliability and availability of a portion of United States’ energy imports, and in the immediate term, this shovel-ready project will provide construction jobs for workers in the United States.
The National Interest Determination took many factors into account, including greenhouse gas emissions. The administration believes the reduction of greenhouse gas emissions are best addressed through each country’s robust domestic policies and a strong international agreement.
The United States is taking unprecedented steps at home to transform how we produce and consume energy. The president is committed to reducing overall emissions and leading the global transition to a low-carbon economy.
The United States will continue to reduce reliance on oil through conservation and energy efficiency measures, such as the recently increased Corporate Average Fuel Economy (CAFE) standards, as well as through the pursuit of comprehensive climate legislation and an ambitious global agreement on climate change to include substantial emission reductions for both the United States and Canada.
The State Department will continue to work to ensure that both the United States and Canada take ambitious action to address climate change, and will cooperate with the Canadian government through the U.S.-Canada Clean Energy Dialogue, the pursuit of comprehensive climate legislation, the United Nations Framework Convention on Climate Change and other processes to reduce greenhouse gas emissions.
Additional information can be obtained at http://albertaclipper.state.gov
Download this media release from the State Dept
U.S. approves Alberta Clipper pipeline project
ReutersGlobe and Mail
Thursday, Aug. 20, 2009
 Enbridge says pipeline construction to start soon |
Calgary — The United States approved Enbridge Inc. (ENB-T40.940.010.02%) 's $3.3-billion Alberta Clipper pipeline project Thursday, granting the project, which will deliver Canadian oil to U.S. refineries, a presidential permit, and raising the ire of some environmental groups.
The U.S. State Department said that allowing construction of the 450,000 barrel per day line serves U.S. interests by adding secure oil supplies from outside the OPEC nations at a time when political tensions in some producing regions threaten to interfere with oil shipments.
“The department found that the addition of crude oil pipeline capacity between Canada and the United States will advance a number of strategic interests of the United States,” it said in a statement.
The department also said construction of the line would create jobs for U.S. workers in what it called a difficult economic period.
Enbridge, which hopes to have the 1,600-kilometre line up and running by mid-2010, said it expects to begin construction soon, creating more than 3,000 U.S. jobs.
“We're pleased we've reached this latest milestone and are in the process of mobilizing well over 3,000 workers and will begin construction within hours or days,” said Denise Hamsher, a spokeswoman for Enbridge.
Most of the oil shipped on the line will come from Canadian oil sands producers, which have been under attack from some U.S. environmental groups and legislators for boosting greenhouse gas emissions because of expanding production in the oil sands – a Florida-sized region of northern Alberta that contains the largest oil reserves outside the Middle East.
The State Department said it took greenhouse gas emissions into account when deciding to issue the permit, saying that the issue is best addressed through the domestic policies of the United States and Canada and through international agreements.
However, some environmental groups said the State Department should have shown greater concern about rising greenhouse gas output, the impact of oil sands production on northern Alberta's boreal forest, and the impact of boosting imports of a fuel that they consider to be more polluting than conventionally produced oil.
“It means large amounts of more air pollution, large amounts of water pollution and extra (greenhouse gases) because more energy is required to convert this (heavy oil) into a refined, usable petroleum product,” said Sarah Burt, a lawyer at Earthjustice. “None of that was taken into account ... in determination of whether or not this would be in the national interest. That is problematic.”
Ms. Burt said Earthjustice, a non-profit law firm, planned to file suit next week in court in the Northern District of California asking that the State Department look at the cumulative environmental impact of building new pipelines from the oil sands. It will also seek a motion to keep Enbridge from starting construction while the case is heard.
Alberta Clipper pipeline approved for U.S. midwest
Lisa SchmidtCalgary Herald
August 21, 2009
CALGARY — Enbridge Inc. is plowing ahead with construction work on the U.S. portion of its Alberta Clipper pipeline after receiving U.S.
approvals Wednesday to carry oilsands crude to the U.S. Midwest.
The U.S. State Department said Wednesday it has granted a permit to the Calgary-based pipeline company to build the U.S. portion of the line.
When the $3.7-billion pipeline is completed in about a year, it will ship 450,000 barrels of bitumen a day to Superior, Wis., with the potential to reach 800,000 barrels a day.
Construction work will begin immediately on the U.S. leg, expected to cost about $1.2 billion.
The Canadian segment of the Enbridge pipeline starts at Hardisty, Alta. — about 200 kilometres southeast of Edmonton — and goes through Saskatchewan and Manitoba to the U. S. border. It has been under construction since last summer.
"We're just really pleased we've reached this milestone, and we're in the process of mobilizing 3,000 construction workers," said Denise Hampsher, a Houston-based spokeswoman with Enbridge.
The pipeline has raised concerns on both sides of the border. Alberta critics raised concerns the line will potentially drain investment and upgrading jobs to the U.S., while American environmental groups argue the pipeline will bring greenhouse-gas intensive oilsands crude from Canada.
In a statement, the State Department said the approval sends a positive signal for both the economy and security of energy supply.
"The department found that the addition of crude oil pipeline capacity between Canada and the United States will advance a number of strategic interests," the statement said.
It also added that the reduction of greenhouse-gas emissions are "best addressed through each country's robust domestic policies and a strong international agreement."
But a group of U.S. environmental and native groups said they will challenge the approval in court, arguing the pipeline is not in that country's national interest because it would ultimately increase greenhouse-gas emissions.
"At a time when concern is growing about the national security threat posed by global warming, it doesn't make sense to open our gates to one of the dirtiest fuels on earth," Sierra Club executive director Carl Pope said in a statement.
"This pipeline will lock America into a dirty-energy infrastructure for years to come."
Canadian oilsands production is expected to climb by one million barrels a day to 2.2 million by 2015, even after a spate of project deferrals and cancellations over the past year as the recession took hold.
Enbridge already moves about two million barrels a day of conventional and unconventional crude on its pipelines to the U.S. Midwest and southern Ontario.
Enbridge shares fell 39 cents to $40.93 on the Toronto Stock Exchange on Thursday.
lschmidt@theherald.canwest.com
August 19, 2009
Is the Mackenzie Pipeline dead?
COMMENT: It's an urban myth (or a lie conjured by those who would benefit) that the initiative to build the Mackenzie Pipeline was ever driven by the market. The market has never, and never will, justify building that pipeline.
What will underpin the Mackenzie Pipeline, is the federal subsidy. If the feds pony up enough cash, Imperial and the other partners in the pipeline will be in there like dogs after a bitch in heat.
This is true too, of the proposed Alaska Natural Gas Line. Federal and state subsidies will make or break that project; it will never happen by market forces alone.
This is true of all the big energy projects. The Columbia and Peace River dams. Northeast coal.
Even shale gas in northeast BC - without all the royalty and other giveaways concocted by the provincial Ministry of Energy, Mines and Petroleum Resources, shale gas in BC might be a non-starter. Oh, sure, $8 gas makes a lot of difference, but given the ROI for a dollar put into conventional gas in northeast BC, or shale gas in Texas, vs shale gas in northeast BC? Gimme those incentives, then I'll come.
Ditto coalbed methane in BC. With the exception of the three big prizes (northeast BC again, East Kootenays, and Klappan), government ultimately hasn't been able to pay anybody to develop the smaller coalfields. That's not to say that collapsing gas prices hasn't helped keep industry away. (Those guys sniffing around the smaller coalfields were never "industry" anyway. With the exception of Petrobank in Princeton, they have all been a band of scumbag profiteers without expertise, capital, or integrity. So, sue me.)
Offshore oil development in BC? The market won't drive that one either. It'll only happen with a whack of subsidy.
Peter Foster
National Post
August 18, 2009
New technology has revitalized old gas exploration areas and opened new ones, putting the economic logic of northern pipelines in doubt
Here’s a thorny question to pose as Prime Minister Stephen Harper moves about the Canadian North this week promoting Arctic sovereignty and use-it-or-lose it development: is the Mackenzie Valley natural gas pipeline dead?
A year ago, Imperial’s CEO Bruce March declared that he was as optimistic about Mackenzie development as he had been “in five or six years.” As recently as January, Minister of the Environment Jim Prentice was talking about getting “framework issues” resolved and moving forward. But whatever fiscal terms the government has offered, Imperial and its partners apparently don’t like them.
Sean Parnell, the successor to Sarah Palin as Governor of Alaska, has declared that pushing a pipeline for North Slope gas will be his top priority. That would kill the Mackenzie line dead. But the prospects for both Alaska and Mackenzie Delta gas are seriously threatened by major new gas finds — and even more major prospects — in the south.
Just as the whole economic logic of northern natural gas pipelines was undermined in the 1970s and 1980s by the removal of perverse legislation in the United States — which opened up exploration and production in the lower 48 — so the rug may be pulled from under northern gas again, only this time by technology.
Three years ago, natural gas production in the United States looked to be in permanent decline. But then, as a recent report from global intelligence company Stratfor notes, things changed big time. Production was boosted by high prices and cheap credit. Wellhead prices almost quadrupled between 2002 and 2008, but the really big development was in technology, specifically for cracking open “tight” natural gas formations.
“Hydraulic fracturing,” or “fracing,” involves injecting high pressure water into underground rock formations to shatter them. The resultant fissures are held open by granular matter pumped in with the water, allowing the gas to escape. Advances in this technology, which is in fact decades old, have, along with other techniques such as horizontal drilling, revitalized old exploration areas and opened up new ones. The Wall Street Journal recently noted that shale gas finds “have moved the U.S. natural-gas market from scarcity to abundance.”
The “Potential Gas Committee,” a group of academics and industry specialists linked to the Colorado School of Mines, earlier this year reported the biggest increase in natural-gas reserves in its 44-year history. Estimated U.S. reserves rose by a whopping one third, from 1,532 trillion cubic feet (TCF) in 2006 to 2,074 TCF in 2008.
The Stratfor study suggests that the United States might even become an exporter of natural gas, possibly even to Europe, which would for obvious reasons love sources of supply apart from Russia and Iran.
This is not such good news for Canada, however, which is the major supplier to the gas import market. Such developments help explain, however, why the Kitimat project in B.C., which was originally meant to facilitate imports of liquefied natural gas, is suddenly being reformulated as an export terminal.
Significantly, one of the most exciting new areas for shale gas is the Horn River Basin in northern British Columbia. EnCana executive vice-president Michael Graham has called the Horn River field possibly “the best shale play in North America.” Exxon Mobil is throwing itself into shale exploration not merely at areas such as Horn River but in Europe and elsewhere.
Development of this relatively high-priced non-conventional gas was brought to a grinding halt as prices slumped with the recession this past year. Nevertheless, the existence of these vast reserves places a natural price cap on the North American market. The question is whether that price makes Arctic gas too expensive. Since Exxon is Imperial Oil’s parent, and is also a direct partner in the Mackenzie pipeline, it understands better than anybody the impact of such developments on the viability of Arctic gas, but its lips are sealed tighter than one of those shale formations.
Currently, prices are hovering not far above US$3 a thousand cubic feet, a level which induces thoughts of suicide in gas producers, but the important price is the one that will prevail when northern pipelines come onstream. EnCana, North America’s leading gas producer, recently hauled down its long-term price expectations from the range of US$7 to US$8 per million British thermal units (BTUs) — which is approximately the same as a thousand cubic feet — to US$6 to US$7 per million BTUs, but others, such as Ron Brenneman, the retiring head of Petro-Canada, expect prices to stay below US$6. As he told the Financial Post’s Claudia Cattaneo recently “We know enough about these shale gas plays to understand the potential and the cost associated with development. Any time you see a little bump in natural-gas prices, which we will see periodically, you will see a corresponding increase in activity and, therefore, supply, and it will smooth itself out again. If you look at the forward curve right now for natural-gas prices… I think it’s going to stay under $6, and at that level you can’t justify conventional developments in Western Canada.”
Much less, presumably, in the Arctic. So it will be fascinating to hear if Mr. Harper even mentions pipelines this week.
Oil Industry Backs Protests of Emissions Bill
By CLIFFORD KRAUSS and JAD MOUAWAD
New York Times
August 18, 2009
 A rally against legislation to set a limit on greenhouse gas emissions in Houston on Tuesday. Oil companies bused in their employees. |
HOUSTON — Hard on the heels of the health care protests, another citizen movement seems to have sprung up, this one to oppose Washington’s attempts to tackle climate change. But behind the scenes, an industry with much at stake — Big Oil — is pulling the strings.
Hundreds of people packed a downtown theater here on Tuesday for a lunchtime rally that was as much a celebration of oil’s traditional role in the Texas way of life as it was a political protest against Washington’s energy policies, which many here fear will raise energy prices.
“Something we hold dear is in danger, and that’s our future,” said Bill Bailey, a rodeo announcer and local celebrity, who was the master of ceremonies at the hourlong rally.
 Gaylene Reier, center, at the rally. Workers at her company, Anadarko Petroleum, were provided with buses to get there. (Karen Warren/Houston Chronicle, via Associated Press) |
The event on Tuesday was organized by a group called Energy Citizens, which is backed by the American Petroleum Institute, the oil industry’s main trade group. Many of the people attending the demonstration were employees of oil companies who work in Houston and were bused from their workplaces.
This was the first of a series of about 20 rallies planned for Southern and oil-producing states to organize resistance to proposed legislation that would set a limit on emissions of heat-trapping gases, requiring many companies to buy emission permits. Participants described the system as an energy tax that would undermine the economy of Houston, the nation’s energy capital.
Mentions of the legislation, which narrowly passed the House in June, drew boos, but most of the rally was festive. A high school marching band played, hot dogs and hamburgers were served, a video featuring the country star Trace Adkins was shown, and hundreds of people wore yellow T-shirts with slogans like “Create American Jobs Don’t Export Them” and “I’ll Pass on $4 Gas.”
The buoyant atmosphere belied the billions of dollars at stake for the petroleum industry. Since the House passed the bill, oil executives have repeatedly complained that their industry would incur sharply higher costs, while federal subsidies would flow to coal-fired utilities and renewable energy programs.
“It’s just a sense of outrage and disappointment with the bill passed by the House,” said James T. Hackett, chief executive of Anadarko Petroleum, who attended the rally. He defended, as an environmental measure, the use of buses financed by oil companies and Energy Citizens to carry employees to the rally. “If we all drove in cars, it wouldn’t look good,” he said.
While polls show that a majority of Americans support efforts to tackle climate change, opposition to the climate bill from energy-intensive industries has become more vigorous in recent weeks. The Senate is expected to consider its own version of the bill at the end of September.
A public relations company hired by a pro-coal industry group, the American Coalition for Clean Coal Electricity, recently sent at least 58 fake letters opposing new climate laws to members of Congress. The letters, forged by the public relations company Bonner & Associates, purported to be from groups like the National Association for the Advancement of Colored People and Hispanic organizations.
Bonner & Associates has acknowledged the forgeries, blaming them on a temporary employee who was subsequently fired. The coal coalition has apologized for the fake letters and said it was cooperating with an investigation of the matter by a Congressional committee.
For its part, the oil industry plans to raise the pressure in coming weeks through its public rallies so that it can negotiate more favorable terms in the Senate than it got in the House. The strategy was outlined by the American Petroleum Institute in a memorandum sent to its members, which include Exxon Mobil, Chevron and ConocoPhillips. The memorandum, not meant for the public, was obtained by the environmental group Greenpeace last week.
“It’s a clear political hit campaign,” said Kert Davies, the research director at Greenpeace.
In the memorandum, the president and chief executive of the American Petroleum Institute, Jack N. Gerard, said that the aim of the rallies was to send a “loud message” to the Senate. He said the rallies should focus on higher energy costs and jobs. “It’s important that our views be heard,” Mr. Gerard wrote.
Cathy Landry, a spokeswoman for the American Petroleum Institute, confirmed the contents of the memorandum, but said that the rally was not strictly an institute event and that Energy Citizens included other organizations representing farm and other business interests.
The House bill seeks to reduce greenhouse gases in the United States by 83 percent by 2050 through a mechanism known as cap and trade, which would create carbon permits that could be bought and sold. President Obama initially wanted these permits to be entirely auctioned off, so that all industries would be on the same footing, but the sponsors of the bill agreed to hand out 85 percent of the permits free to ensure passage of the legislation.
The power sector, which accounts for about a third of the nation’s emissions, got 35.5 percent of the free allowances. Petroleum refiners, meanwhile, got 2.25 percent of these allowances, although the transportation sector accounts for about 40 percent of emissions. That means oil companies would have to buy many of their permits on the open market, and they contend that they would have to raise gasoline prices to do so.
But Daniel J. Weiss, a senior fellow at the Center for American Progress, a research and advocacy organization, said that refiners would be allowed to keep the value of the free allowances they received, while public utilities would be required to return the value of their permits to customers.
“There is a myth out there that this is a giveaway to utilities,” Mr. Weiss said. “It’s not true. The oil industry’s goal is to block or weaken efforts to tackle global warming.”
The rallies have opened a rift within the industry. Royal Dutch Shell, an initial supporter of climate legislation, said that it had told the institute that it would not participate in the rallies, although its employees would be free to attend if they wanted to. ConocoPhillips, meanwhile, has opposed the bill since its passage and, in a note on its Web site, encouraged employees to attend the rallies.
Since Mr. Obama’s election, the oil industry has lost some clout in Washington. The rally on Tuesday gave voice to the feeling among employees of oil companies that their industry was being battered.
“I experienced Carter’s war against the industry, and I’m tired of being pushed around,” said David H. Leland, a geological map maker for NFR Energy. “We provide a product for a reasonable price, and we’re going to be punished for doing a damn good job.”
Clifford Krauss reported from Houston, and Jad Mouawad from New York.
Earlier in sqwalk.com:
Oil lobby to fund campaign against Obama's climate change strategy
August 18, 2009
States weigh benefits, risks of drilling in parks
COMMENT: The pressure in the US to open up parks and other protected areas for oil and gas drilling is unrelenting, and mounting. The BC Liberals are already diving to the bottom of the barrel with low royalties and even more generous giveaway deals to get more drillers in the northeast.
You don't think they're also sizing up the political risks of moving into BC's parks and protected areas?
Given incredibly blatant burying of evidence with the disappeared emails in the BC Rail-Basi-Virk affair, the unannounced introduction of the HST, the sudden dismissal of Tourism BC, not to mention unilateral cancellations of entire sessions of the Legislature - this government is revealing itself as not just high-handed, unethical, and arrogant but undemocratic. They can, and may, do anything as Gordon Campbell runs out the clock to the Olympics and a probable exit from politics into the warm embrace of a hundred corporate directorships.
So what's the risk of drilling in a park or two? Environmentalists have already shown themselves split on climate change - some willing to overlook all the other sins of Liberal rule because of the carbon tax and green energy policies and initiatives that this government has taken. Others, not so much.
So Campbell and his energy minister, Blair Lekstrom, can probably count on enviros not to rage with a unified voice if they open up, let's suggest, the Muskwa-Kechika for a little more drilling than is taking place there already. Heck, it's a long long way from Vancouver and Victoria, there aren't many NIMBY's to provoke, and the hundreds of millions of dollars that would rush in with an auction of drilling rights in M-K are desperately needed for health care...
I'm just sayin.
By JULIE CARR SMYTH
Associated Press
Google Media
17-Aug-2009
COLUMBUS, Ohio — State parks aren't just for hiking, camping and other recreation anymore. Increasingly, these lands are being used for oil and gas drilling as budget-strapped states seek new sources of revenue.
As they allow more energy exploration in state parks — in some cases by reversing previous bans — lawmakers are being met with resistance from environmentalists and park officials.
Opponents of the drilling say it raises troubling questions about acceptable uses of publicly shared land — even when new technology allows rigs positioned outside park boundaries to reach petroleum pockets deep beneath the parks by drilling horizontally.
Sean Logan, director of the Ohio Department of Natural Resources, said parks get 40 percent of their money from fees related to camping, boating, beach access and other recreational activities. If drilling affects the panoramas or the noise level, these other revenue sources could start suffering, he said.
Drilling is still barred in national parks. But the reversal of some state bans coincides with efforts to expand exploration in other previously off-limits locations: offshore in coastal states, near Aztec ruins in New Mexico and in some urban parks.
Arkansas has signed a lease allowing drilling to begin under Woolly Hollow State Park. Pennsylvania saw its first drilling on state park property this spring.
In July, a circuit court judge in West Virginia ruled against the state environmental protection agency's attempt to block drilling under Chief Logan State Park. The first well in Living Desert Zoo and Gardens State Park in Carlsbad, N.M., was drilled in 2007.
The U.S. Geologic Survey monitors oil and gas activity nationally, though no organization tracks drilling that falls within the boundary of state parks, or how much oil and gas can be pulled from that land.
In western New York, retiree Jay Wopperer is fighting a proposal to drill in Allegany State Park, 65,000 acres of forested valleys south of Buffalo.
"I don't oppose drilling," said Wopperer, of Clarence, N.Y., who has led the Audubon Society's bird hikes in Allegany for 10 years. "But there are plenty of other places to drill in western New York. This is the people's park."
To drill, roughly two acres are cleared of trees and vegetation. Gravel roads are also required to access drilling masts about 120 feet high. Producers have in some cases put mufflers on machinery and reduced other noises, but there are still trucks and other related sounds.
Backers say that wellheads and nature trails can coexist, in part because of new technology reduces the environmental footprint of drilling operations.
In Ohio's Salt Fork State Park, much of the work would be by directional drilling, a technique that involves entering the surface at one location, making an underground turn and tunneling sometimes for miles underground to reach oil or natural gas pockets.
"You probably wouldn't even notice the drilling rigs. It's very, very environmentally sensitive and, at the same time, would produce a huge amount of revenue," said state Sen. Keith Faber, who is pushing a proposal to allow the first-ever drilling in Ohio state parks.
A state committee puts Ohio's estimated take from new drilling as high as $5 million a year. Ohio, with 11 percent unemployment and among the worst foreclosure rates in the country, needs the cash to offset declining tax revenues.
Ohio is not alone.
According to the latest figures from the nonpartisan Center on Budget and Policy Priorities, state budgets face a combined $163 billion shortfall in fiscal year 2010 even after making billions in cuts.
The money from drilling won't cure state shortfalls, but every office is being asked to find new revenue or face cuts, including parks.
Arkansas parks director Greg Butts said his state received about $200,000 in initial bonus payments by signing the deal allowing natural gas directional drilling under Woolly Hollow, cradled in the Ozark foothills. The lease doesn't allow drilling on park property.
On land sitting above massive natural gas reserves like the Marcellus shale, which spreads over four states including Ohio, new drilling techniques have created a lot more opportunities for companies like Oklahoma City-based Chesapeake Energy Corp.
"In our home state, in fact, one of our larger royalty owners is the Oklahoma Department of Wildlife Conservation," said spokesman Jim Gipson. "Many public entities are seeing that there is significant opportunity to create economic value from natural gas resource development while simultaneously protecting the environment."
Some states have balked, with lawmakers in Kentucky and Ohio allowing state-park drilling proposals to die this year. Looking solely at proceeds from drilling, some say, is missing the bigger picture and the greater harm.
In Pennsylvania, however, a state ban on surface drilling in state parks was unable to thwart private drilling in Goddard State Park because the company, Pittsburgh-based Vista Resources, owns the mineral rights.
Most state park directors still see drilling as contrary to their mission of leaving the land as pristine as possible, said Philip McKnelly, executive director of the National Association of State Park Directors.
Once that line is crossed, park officials say, there is no going back.
Right now, there is a huge glut of natural gas because of the recession and the new drilling techniques. Prices have plunged as a result. There is apprehension from some park directors that with any economic rebound, the pressure to drill on public lands will only grow stronger.
Associated Press writers Stephen Majors in Columbus and news researcher Monika Mathur in New York contributed to this report.
August 17, 2009
Oil lobby to fund campaign against Obama's climate change strategy
COMMENT: We're sometimes castigated as paranoid, and mistrustful, told that the corporations (and governments) we most often find ourselves pitted against, may have different objectives than we do but at heart, are not evil and will not stoop to unethical behaviour. Well, countless times we are given evidence that these organizations, and unfortunately, the people who work for them, are unscrupulous, and will stoop very far indeed. I cite just three examples: Enron (Powerex did not have clean hands either), Weapons of Mass Destruction (my vote for the biggest lie of this decade), BC Rail-Basi-Virk- and the disappeared emails.
Now this...
Suzanne Goldenberg
US environment correspondent
guardian.co.uk
Friday 14 August 2009
Email from American Petroleum Institute outlines plan to create appearance of public opposition to Obama's climate and energy reform
The US oil and gas lobby are planning to stage public events to give the appearance of a groundswell of public opinion against legislation that is key to Barack Obama's climate change strategy, according to campaigners.
A key lobbying group will bankroll and organise 20 ''energy citizen'' rallies in 20 states. In an email obtained by Greenpeace, Jack Gerard, the president of the American Petroleum Institute (API), outlined what he called a "sensitive" plan to stage events during the August congressional recess to put a "human face" on opposition to climate and energy reform.
After the clamour over healthcare, the memo raises the possibility of a new round of protests against a key Obama issue.
"Our goal is to energise people and show them that they are not alone," said Cathy Landry, for API, who confirmed that the memo was authentic.
The email from Gerard lays out ambitious plans to stage a series of lunchtime rallies to try to shape the climate bill that was passed by the house in June and will come before the Senate in September. "We must move aggressively," it reads.
The API strategy also extends to a PR drive. Gerard cites polls to test the effectiveness of its arguments against climate change legislation. It offers up the "energy citizen" rallies as ready-made events, noting that allies – which include manufacturing and farm alliances as well as 400 oil and gas member organisations – will have to do little more than turn up.
"API will provide the up-front resources," the email said. "This includes contracting with a highly experienced events management company that has produced successful rallies for presidential campaigns."
However, it said member organisations should encourage employees to attend to command the attention of senators. "In the 11 states with an industry core, our member company local leadership – including your facility manager's commitment to provide significant attendance – is essential," said the email.
Greenpeace described the meetings as "astroturfing" – events intended to exert pressure on legislators by giving the impression of a groundswell of public opinion. Kert Davies, its research director, said: "It is the behind the scenes plan to disrupt the debate and weaken political support for climate regulation."
The rally sites were chosen to exert maximum pressure on Democrats in conservative areas. The API also included talking points for the rallies – including figures on the costs of energy reform that were refuted weeks ago by the congressional budget office.
The API drive also points to a possible fracturing of the US Climate Action Partnership (Uscap), a broad coalition of corporations and energy organisations which was instrumental in drafting the Waxman-Markey climate change bill that passed in the House of Representatives in June.
Passage of the legislation is seen as crucial to the prospects of getting the world to sign on to a climate change treaty at Copenhagen next December.
Five members of Uscap are also in API, including BP which said its employees were aware of the rallies. Conoco Phillips, which was also a member of the climate action partnership, has also turned against climate change, warning on its website that the legislation will put jobs at risk, and compromise America's energy security. The company is also advertising the energy rallies on its website, urging readers: "Make your voice heard."
However, Shell, also a member of both groups, said it did not support the rallies. Bill Tenner, a spokesman, said: "We are not participating."
August 16, 2009
Support lawmakers for escort tug efforts
COMMENT: Sorry, friends, this turned out to be a rather longer "comment" than usual. You may just want to skip to the article. Maybe not even that!
Sen. Lisa Murkowski is a friend of Alaska's oil and gas industry. That hasn't stopped her championing the world's best tankering protocols in Prince William Sound, the site of the tragic Exxon Valdez disaster of twenty years ago.
Most of the oil brought into the refineries in Puget Sound comes by tanker from Alaska down the west coast of British Columbia and through the Strait of Juan De Fuca. Tanker activity in Puget Sound and the Strait of Juan de Fuca is governed by another laudable set of protocols. These limit the size and frequency of tankers as well as construction standards - double hulls, with redundant propulsion and steering.
On either side of British Columbia waters, our own waters are somewhat protected by US legislation. Within BC waters, it's another matter.
Instead of tanker standards, we have in place the Tanker Exclusion Zone (TEZ), a voluntary agreement (ie, non-enforcable) by the operators of tankers travelling south from Alaska. Its intent is to keep these vessels well offshore until they start heading into the Strait of Juan de Fuca. Generally, the TEZ is respected, but monitoring is a challenge (some vessels don't keep their remote locating devices operating, and Canada does not have in place any air or seaborne oversight of the TEZ).
The TEZ only covers tankers, and has no applicability to other vessels, carrying other cargo which itself may or may not be dangerous, and all of them configured with their own huge fuel tanks.
When a spill does occur, either side of the TEZ, BC will discover "how woefully unprepared," we are to deal with it. Those are Sen. Murkowski's words to the US Senate.
The only dedicated rescue tug capable of dealing with marine incidents off BC's coast is based at Neah Bay in Washington State. So we rely on "tugs of convenience" - tugs which may be in the vicinity, virtually all of which will be busy with their own cargo/tow operation.
The TEZ line is designed to keep tankers far enough offshore that a rescue tug from Anacortes or Neah Bay could get to it, before the ship grounds. In the case of Langara Point, on the northeast corner of the Queen Charlotte Islands, that's estimated to be 54.5 hours, and the TEZ is 100 miles to the west. The problem is, however, that the "model" is hugely imperfect - that given the extremes and vagaries of weather and of the behaviour and condition of the distressed tanker, that a tug could get to the tanker in time, or that it could provide any remedy.
So Alaska and Washington State are doing their bit, and showcasing the "best of" practices for shipping oil by sea.
Now, with Enbridge's proposal to start shipping bitumen from the tar sands by tanker, to import condensate, and Kitimat LNG's proposal to export natural gas in LNG vessels - all of this via Douglas Channel, Hecate Strait and Dixon Entrance, how is our readiness to take on the challenges?
First, of course, is the "no tankers" campaign - to push the federal government to declare BC's north coast as a zone in which tankers are not permitted, not in any direction.
Hold on, you say, we have a tanker moratorium in place. Well, that's become an arguable point, and most of the power, as usual, is with those who are arguing that we don't have a moratorium.
Government and corporate behaviour on the tanker moratorium is disgusting, given how self-serving it is. Until 2006, it was explicitly accepted by the federal government that a tanker moratorium did exist on BC's north coast and had done so for thirty years. But then Enbridge came along with its Gateway Pipeline proposal, and suddenly, the story changed. In a letter dated July 11, 2006, the lawyers representing Enbridge stated that "there is in fact no restriction on the movement of tankers into or out of Canadian ports."
And since then federal and provincial politicians, as well as any corporations with an interest in the subject, have echoed Enbridge's lawyer (whose name, as a matter of curious coincidence, happens to be Richard Neufeld, but not the former BC Energy Minister and now sucking up the big bucks in Ottawa as a Senator.)
They may win this argument, although they will have a hell of a fight. Northern Gateway may yet prove to be economically viable - though time and global politics and climate change may help impede the project, as it has once already, and project approval may be granted - though various legal, environmental, and science-based evidence and arguments will be thrown in its way. One day, the project may go ahead.
Then what?
Are ship construction and operation protocols similar to those in Prince William Sound and the Strait of Juan de Fuca, as good as we can get it? Can we even get that? Here are some of the main items:
- double hull tankers (actually, these all they build for oil these days)
- redundant propulsion and steering
- double escorts out of Douglas Channel into Hecate Strait
- double escorts up through Hecate Strait and out of Dixon Entrance
- rescue tug(s) stationed at one or two locations on on QCI
- fully equipped spill response station (such as Burrard Clean has in Burnaby) installed in the area
The first permanent rescue tug on the north coast will lead to tanker owners demanding removal of the TEZ - so that would immediately lead to an increased risk of disaster along the entire coast.
As good as all of that is, it would still leave a magnificent coast vulnerable to awful and irreparable devastation, so no to tankers is an absolute and non-negotiable position.
But if we lose ...
Support lawmakers for escort tug efforts
By Stephen K. LewisCOMPASS: Other points of view
Anchorage Daily News
August 14th, 2009
 Stephen K. Lewis is president of Prince William Sound Regional Citizens Advisory Council. He lives in Seldovia. |
We Alaskans have always fared best when our state leaders have put politics aside and pulled together for the common good. Examples range from the campaign for statehood, to the settlement of our Native peoples' land claims, to the effort to open up Prudhoe Bay and build the trans-Alaska pipeline.
The latest example of the spirit that has served Alaska so well is the effort by our state Legislature and congressional delegation to preserve the system of escort tugs that help protect Prince William Sound from oil spills.
Ever since the devastating Exxon Valdez spill two decades ago, each loaded oil tanker passing through the Sound has been accompanied by two escort tugs, ready and able to assist the tanker in a crisis or to begin the cleanup if the worst should happen.
But, because a key provision in federal law is about to sunset, this state-of-the-art safety system could be cut back or even eliminated altogether unless Congress acts to save it. Luckily for our state, its elected leaders have joined together in the effort to make sure that happens.
In March -- the month of the 20th anniversary of the Exxon spill -- both chambers of the Alaska Legislature unanimously passed a resolution calling on Congress to preserve the escort system. Alaska's governor followed up with a strong letter supporting the call.
In May, Sens. Lisa Murkowski and Mark Begich -- a Republican and a Democrat -- teamed up to introduce legislation that would require continuation of the double escorts. Rep. Don Young has been working through Democratic connections in the U.S. House to move similar legislation there.
This measure would not impose new financial burdens on industry; it would only make sure there is no relaxation of present standards and practices. It would only preserve what we have now in Prince William Sound: a world-class escort system to protect a world-class natural treasure from a repeat of the Exxon Valdez spill and the devastation it brought.
As an owner state, we have a duty to protect the extraordinary natural resources we hold in common. It is a duty that has been taken seriously by most of our state leaders over the years. All Alaskans should be proud of the latest example of our leaders once again pulling together when it counts the most.
I urge my fellow citizens of the 49th state to do as I will be doing: Supporting Sens. Murkowski and Begich, and Congressman Young, as they attempt to move this important legislation through Congress when it reconvenes at the end of this month.
excerpt from the Floor Statement for Dual Escort Vessels for Double Hulled Tankers in Prince William Sound, Alaska
Sen. Lisa MurkowskiU.S. Senate
May 14, 2009
Ms. MURKOWSKI: Mr. President, today I am introducing a bill, with my colleague from Alaska Senator Mark Begich, that will require all oil laden tankers in Prince William Sound to be ecorted by at least two towing vessels or other vessels considered appropriate by the Secretary of the Department of Homeland Security.
At 12:04 a.m. on March 24, 1989, the Exxon Valdez, carrying over 53 million gallons of crude oil, failed to turn back into the shipping lane after detouring to avoid ice, and ran aground on Bligh Reef. Alaskans will never forget that morning, waking up to hear about the worst oil spill and environmental disaster in U.S. history and living with the lasting impacts it has had on our State and residents.
The National Transportation Safety Board investigated the accident and determined probable causes for the accident. While it determined that it was primarily caused by human error of the captain and crew, it is my belief that we had also become complacent. It had been 12 years since we had begun to tanker oil out of Valdez and there had not been an incident. However, when the spill occurred, we became acutely aware of how woefully unprepared we were. The few prevention measures that were available were inadequate and the spill response and clean-up resources were seriously deficient. The oil eventually fouled some 1,300 miles of shoreline, stretching almost 500 miles, and covered an area of 11,000 square miles.
While the captain and crew were found at fault for the immediate cause of the spill, the incident also highlighted huge gaps in regulatory oversight of the oil industry. The response of Congress to the spill was passage of the Oil Spill Pollution Act of 1990 or OPA90. The law overhauled shipping regulations, imposed new liability on the industry, required detailed response plans and added extra safeguards for shipping in Prince William Sound. Since the law took effect, annual oil spills were greatly reduced and lawmakers, marine experts, the oil industry and environmentalists credit the law for major improvements in U.S. oil and shipping industries.
Oil spill prevention and response have been greatly improved in Prince William Sound since the passage of OPA90. The U.S. Coast Guard now monitors fully laden tankers all the way through Prince William Sound. Specially trained marine pilots ride the ships for 25 of the 70 mile journey through the Sound and there are weather criteria for safe navigation. Contingency plans, skimmers, dispersants, oil barges and containment booms are all now readily available. An advanced ice-detecting radar system is also in place to monitor the ice bergs that flow off of the mighty Columbia Glacier.
Two escort tugs accompany each tanker while passing through the Sound and are capable of assisting the tanker in the case of an emergency. This world class safety system recently saw the 11,000th fully loaded tanker safely escorted through Prince William Sound. It is estimated that if the Exxon Valdez would have been double-hulled, the amount of the spill would have been reduced by more than half. While double hulled tankers are a huge improvement over single hulls, they do not prevent oil spills.
The legislation that Senator Begich and I are introducing today will maintain the existing escort system in place for all tankers. Presently, the federal requirement that every loaded tanker be accompanied through the Sound by two tugs applies only to single-hulled tankers. Even though, right now, double-hulled tankers are escorted by two vessels, federal law does not require them to be. The last single hulled tanker in the Prince William Sound fleet is expected to be retired from service by August 2012 and our legislation ensures all double hulled tankers will aways be escorted by twotugs.
Although there have been a number of marine incidents and near misses since the Exxon Valdez Oil Spill in 1989, over the past 20 years, through the efforts of the U.S. Coast Guard, industry, the State of Alaska, and the Prince William Sound Citizens Advisory Council to implement the requirements of OPA 90, there have been no major oil spills. Today, as a result, the marine transportation safety system established for Prince William Sound is regarded as among the most effective in the world. A key reason for that accomplishment is, in part, because of the safety benefits resulting from having dual escort vessels transiting the Sound.
Full text of the Floor Statement for Dual Escort Vessels for Double Hulled Tankers in Prince William Sound, Alaska
Sen. Lisa Murkowski, U.S. Senate, May 14, 2009
Prince William Sound Citizen Advisory Council info and backgrounder on the Tanker Escort System
August 14, 2009
Alberta frets over U.S. climate change tariff bill
Renata D'Aliesio
Calgary Herald
August 13, 2009
CALGARY — The Alberta government is worried about a provision in a U.S.
climate change bill that would grant the president the power to slap tariffs on imports that have a carbon footprint larger than American-made goods.
In a recent interview with the Calgary Herald, Premier Ed Stelmach said the province is keeping close watch on the Clean Energy and Security Act, also known as the Waxman-Markey bill.
The proposed legislation was narrowly passed in June by the U.S. House of Representatives but it hasn't received full airing in the Senate.
"The thing that really bothers me . . . is that they're giving the president, presently the way it's written, executive powers of imposing administrative taxes, border adjustment taxes," Stelmach said.
"That is of great concern because we don't know under what conditions those taxes can be applied and on what goods or services."
Alberta's chief envoy in Washington, Gary Mar, said the Waxman-Markey bill is at the top of his priority list.
His office, along with prominent consultants hired by the province, has been lobbying U.S. politicians to moderate some of the "sharper edges" of the Waxman-Markey bill.
The United States is Canada's largest trading partner and Alberta's biggest customer.
"Alberta's standard of living depends much upon our ability to export, and the majority of those exports, by and large, are energy exports," Mar said. "So anything that has a potential to stop our oil or natural gas from crossing the border should be of great concern to Albertans."
Mar said it's difficult to predict what the Senate will do with the divisive legislation. It could pass the Waxman-Markey bill as is, make key changes, or the Senate could introduce an entirely different climate change package when it reconvenes in September.
The legislation could also be put off — and not dealt with until after an important UN climate change conference in December — due to heated debates over health care reform that have erupted in the United States, Mar noted.
If the bill passes unchanged and is signed into law, the U.S. would commit to trimming greenhouse gas emissions 17 per cent from the 2005 level by 2020 and 83 per cent by 2050. Ottawa's most recent targets are to reduce emissions 20 per cent below 2006's mark by 2020 and 60 to 70 per cent by 2050.
Federal Environment Minister Jim Prentice said Ottawa wants to harmonize its climate change polices with the United States, therefore reducing the threat of carbon tariffs on imports.
"At the end of the day, we're confident that Canada will have a commensurate environmental regime, and so those border adjustments won't penalize Canada," Prentice said in Calgary.
Rick Hyndman, the Canadian Association of Petroleum Producers' senior climate change policy adviser, agrees with Prentice's take on the proposed tariffs, which wouldn't come into effect until 2020.
"One is always concerned about protectionist sentiments," he said. "But the idea that Canada in 2020 would not be in the same treaty as the United States or that we wouldn't have policies . . . comparable to the United States strikes me as highly unlikely."
While Alberta's oilsands have been a lightning rod for environmentalists on both sides of the border, University of Alberta economist Andrew Leach suspects the development won't face the wrath of carbon tariffs.
Leach noted the Waxman-Markey bill doesn't target a country's carbon footprint, but instead focuses on a commercial sector's overall greenhouse gas impact, comparing its performance to the same industry in the United States.
"The U.S. doesn't have a competing oil sector," Leach said. "Canadian oil production isn't displacing domestic U.S. production."
Prentice has pledged to meet with all of the country's premiers before the UN climate conference. He has already met with Stelmach on the issue about five times and said they plan to meet again soon.
Meanwhile the Pembina Institute, an environmental think-tank, took aim Thursday at Ottawa's greenhouse gas offset program, saying the proposed system will "lead to a massive overstatement of emission cuts." (link)
The Alberta-based organization said there are at least six key loopholes in the scheme that grant credits for greenhouse gas reductions that would've occurred anyway. The system, Pembina argues, also allows for double counting of emission cuts.
"If these loopholes are not closed, Canada's actual emissions are likely to miss the targets in the government's upcoming regulations for Canadian industry by millions of tonnes," the think-tank said in a statement.
The Pembina Institute compared the currently proposed system to "lax financial accounting rules" that create fictional profits. The report also found the majority of offsets in Alberta's burgeoning system are coming from projects that would have likely occurred on their own.
rdaliesio@theherald.canwest.com
Accounting Loopholes in Government Proposal Risk a Massive Overstatement of Emission Cuts
Pembina Institute releases analysis of Environment Canada's draft offset system, 13-Aug-2009
August 13, 2009
NEB Reports Highest Pipeline Worker Injury Rate Since 2000
The NEB's annual Focus on Safety and Environment: A Comparative Analysis of Pipeline Performance 2000-2007 reports that nearly two out of every 100 pipeline workers suffered a serious workplace injury in 2007, almost double the seven-year average. It is the highest worker injury rate since the NEB began reporting on safety performance indicators in 2000.
News Release 09/16 - National Energy Board Taking Steps to Improve Worker Safety
Pipeline Safety Performance - Pipeline Incident Reporting
The report singled out factors such as employee experience levels, increasing pressure to meet deadlines, worker complacency and increased construction activity as possible causes for the rise in the injury frequency. In 2007, there were several pipeline projects under construction including the 145-kilometre long Emera Brunswick pipeline and the Trans-Mountain Anchor Loop pipeline that stretches for 151 km through mountainous terrain.
The report also noted that for the tenth consecutive year, there were no fatalities on NEB-regulated facilities. However, two fatalities were reported in 2008, and early reporting by NEB-regulated companies indicates that the injury rate for pipeline workers is rising.
"The National Energy Board has been committed to safety since the day this organization was founded nearly 50 years ago. Safety is, and always will be, our number one goal," said NEB Chair Gaétan Caron.
"Together with our industry stakeholders, we have been working hard to understand the factors underlying this important issue. We have also been taking steps to help improve pipeline worker safety by increasing the number of compliance activities and hosting events such as the recent NEB Forum 2009 where industry leaders can share best practices in the area of safety."
NEB-regulated pipeline companies reported 49 incidents to the NEB in 2007, including two ruptures, the first since 2002. The first rupture was caused by pipeline cracking due to fatigue which allowed approximately 990 cubic metres (6 227 barrels) of crude oil to spill into a farmer's field near Glenavon, Saskatchewan in April.
In July, NEB staff responded to an oil pipeline spill in Burnaby, British Columbia. A contractor doing construction in the community struck an underground 24-inch pipeline. Approximately 232 cubic metres (1 460 barrels) of heavy synthetic crude oil was released.
Between 1991 and 2002, there was an average of 2.5 ruptures per year on NEB-regulated pipelines. The Board introduced new regulations in 1999 making integrity management programs compulsory, which has helped to reduce the number of ruptures.
The National Energy Board uses this report to help improve the Board's compliance programs. For example, NEB staff increased compliance activities, such as inspections or audits, from 99 in 2007 to 216 in 2008. NEB inspection staff noted fewer incidents of non-compliance with NEB regultions in 2007 than in 2006 and most of these incidents were corrected while NEB staff were still onsite. The most common incidence of non-compliance was related to personal protective equipment such as not wearing hard hats or safety glasses correctly.
In May, 2009 the National Energy Board brought more than 300 representatives from pipeline companies, contractors, regulators, First Nations and landowners together at the NEB Forum 2009 to discuss issues related to pipeline safety, security and emergency management. The NEB plans to continue hosting events such as these as one step towards improving worker safety.
Celebrating 50 years of regulatory leadership, the NEB is an independent federal agency that regulates several parts of Canada's energy industry. Its purpose is to promote safety and security, environmental protection, and efficient energy infrastructure and markets in the Canadian public interest, within the mandate set by Parliament in the regulation of pipelines, energy development and trade. As part of its mandate, the NEB monitors the supply of all energy commodities in Canada and reports its findings. The NEB Internet site is regularly updated with new energy information for the Canadian public.
- 30 -
For further information:
Tara Sukut (tara.sukut@neb-one.gc.ca)
Communications Officer
Telephone: 403-299-3930
Telephone (toll free): 1-800-899-1265
August 12, 2009
Revival or dam-nation?
COMMENT: You gotta appreciate the irony of this: here's the Snohomish PUD trying to increase the amount of renewable energy both to meet GHG emission targets and dramatically increased demand - because of Boeing's new jet plant. And, um, jet planes are one of the most egregious burners of fossil fuels and emitters of carbon dioxide - at altitude where the intensity of CO2 is much greater than at ground level.
It's an absurd scenario. In BC, just imagine that BC Hydro were ramping up generation in BC to provide additional electricity to the TeckCominco/Elk Valley Coal mines - mines which expect to increase coal production by 50% in the next eight years so that China and Korea and Japan can add massive tonnages of CO2 to the atmosphere by burning BC coal. Oops. That's exactly what BC Hydro is doing. It's what Aberfeldie and Glacier/Howser are all about, come to think of it.
Joshua Zaffos
High Country News
July 27, 2009
 A small 6-foot-tall dam in Woods Creek that Snohomish PUD bought from a private energy company last year for $1.1 million. (by Dan Bates, the Daily Herald in Everett, Washington) |
The push for green power could spawn a rush for small hydropower projects in the Northwest
Thanks partly to Boeing's new jet factory, Snohomish County, Wash., is one of the fastest-growing counties in the country. The north Seattle county's energy demand is expected to increase 25 percent over the next decade, and its local utility is scrambling for new sources of power.
Currently, the Snohomish County Public Utility District gets 80 percent of its energy from massive dams on the Columbia River. But with big dams and fossil fuels losing favor, it's looking to alternative sources: solar, wind, geothermal and biomass and, perhaps the most controversial of all, small-scale dams, which utility managers consider environmentally and economically viable.
Boosters tout small-scale hydroelectric projects -- defined as generating less than 30 megawatts, or enough to power up to 30,000 homes -- as carbon-neutral and more fish-friendly. And the resource has staggering potential: Just a fraction of the possible sites on Washington's waterways could power millions of homes.
But although utilities, investors and speculators are getting into the game, small-hydro development won't be easy or cheap without policy incentives and tax credits. And not everyone thinks it's a good idea. "We look at our watersheds and waterways in the Northwest as pretty stressed already. The impacts are apparent everywhere,"
says Rich Bowers, Northwest coordinator for the Hydropower Reform Coalition, a network of 140-plus environmental and outdoor recreation groups.
Snohomish PUD will build its first small-hydro project on Youngs Creek near Sultan, Wash. The 7.5-megawatt, $30 million plant and its successors will be "run-of-the-river" works, which use dams less than
15 feet high, and rely on natural streamflows and grade to generate electricity (instead of engineering stronger flows and a higher grade, as conventional dams do). Youngs Creek lacks salmon and recreational activity, so the environmental and boating-advocacy group American Whitewater and other groups have dropped their initial objections.
The Youngs Creek project demonstrates the potential upside of small hydro. Migrating fish can usually bypass or swim up small dams, and water quality and temperature aren't greatly affected because there's no deep reservoir. Small hydro has virtually no carbon output, and it represents a local and distributed power base. And Snohomish PUD -- which expects to have a list of 10 preferred small hydroelectric projects out this summer -- plans to meet certification through the Low Impact Hydropower Institute (LIHI), the hydroelectric equivalent of the LEED program for "green" building.
Whether or not they're certified green, however, the potential proliferation of new dams worries most environmentalists. "These small projects in many cases have the biggest impacts relative to their size," says American Whitewater's Thomas O'Keefe.
New projects often use "weirs," low dams that allow water to spill over the top, but O'Keefe says such structures still de-water streams to turn turbines, thereby annihilating boating runs. And even small projects require habitat-disturbing transmission lines and maintenance roads. One plant on a salmon-free creek might be OK, but critics worry that the cumulative effects of numerous small dams will stifle river systems and fish populations. O'Keefe and other opponents believe new hydroelectricity should come instead from efficiency upgrades and the addition of turbines to existing dams.
Dam operators are increasing capacity at existing sites and looking into the 97 percent of dams in the country that don't have hydroelectric works. But efforts like those of the Snohomish utility district are still important, says National Hydropower Association president Andrew Munro. "We can double U.S. water-power resources (currently 95,000 megawatts) without large dams," he says, as early as 2025 with the right incentives.
In Washington, though, the "right" incentives haven't emerged. The state's renewable energy standard, which requires most energy providers to get 15 percent of their electricity from renewables by 2020, counts power from improvements at existing dams, not new ones.
Utility districts supported a bill last year to include new, "low-impact" hydro projects that produce 5 megawatts or less, but it didn't pass.
But the federal renewable energy standard is still up in the air, and other Pacific Coast states welcome new hydro. Oregon, for example, counts new projects up to 50 megawatts if they meet low-impact certification. In January 2008, a San Francisco developer proposed nine new "damless" hydro plants along a 34-mile stretch of the McKenzie River, east of Eugene. The scheme was rejected, but it aroused opposition from paddlers and river advocates, who feared it would harm fish and ruin a popular boating run.
California allows for new small-hydro projects that meet certain criteria, but the state is struggling to meet its goal to produce 20 percent of its electricity from renewable sources by 2010. The utility Pacific Gas and Electric wants to amend the standard to include energy from British Columbia run-of-the-river hydro projects that don't meet California's current renewable criteria. Bowers of the Hydropower Reform Coalition says Washington state legislators are keeping a close eye on California's decision, which could encourage similar projects in Washington, regardless of that state's stricter renewable controls, to serve California's energy needs. It could also inspire a new era of investment and development for small hydro in the Northwest.
"I think everybody's collectively holding their breath to see where the market goes," says LIHI executive director Fred Ayer.
- Joshua Zaffos is a freelance writer in Fort Collins, Colorado.
Oil sands test of Obama’s green credentials
By Sheila McNulty in Houston
Financial Times
August 10 2009
The Obama administration faces a test of its environmental credentials in deciding whether to approve a pipeline carrying greenhouse gas-intensive oil sands fuel from Canada into the US.
Hillary Clinton, secretary of state, is expected to decide as early as this month whether to approve the Alberta Clipper, a 1,000-mile pipeline designed to carry up to 800,000 barrels a day of fuel from Canada’s vast oil sands.
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Environmentalists say doing so would be at odds with the green economy pledged by the administration.
“Approving new mega-projects like the Alberta Clipper pipeline would lock North America into the old, high-carbon energy economy,” said Keith Stewart, director of climate change at WWF-Canada. “We need to invest in the green economy of the future, not pour billions into the Betamax of the energy world.”
But Enbridge Energy, the Canadian pipeline builder, said the project would improve US energy security. The pipeline and associated facilities “will serve the national interest . . . enhancing the ability to deliver a secure and growing supply of Canadian crude oil, thereby supplementing the diminishing supplies of domestically produced crude oil,” the company said in its May application.
It is hard for the US to resist the 175bn barrels of oil sand reserves, given rising concerns over energy security. But the extraction of a barrel of crude from oil sands is estimated to generate as much as five times more greenhouse gas emissions as from a barrel of conventional crude.
Environmentalists have seized on a delay in granting the permit, which could have come in early July, as a sign it might be rejected. But the state department told the Financial Times it had not finished the review process.
Enbridge is confident it will obtain the permit this month, enabling it to build.
“We’re going to start construction at the end of this month,” the company said. “We believe we will have a successful outcome and look forward to completion by mid-2010. We’re not worried at all.”
Canadian environmentalists sent the state department a letter last week urging it to delay a decision until after a climate treaty emerges from the Copenhagen summit. “This decision carries significant implications regarding greenhouse gas pollution and global warming that cannot be duly considered in the absence of clear US climate change policy and an understanding of an international climate treaty,” it read.
The Dirty Oil Sands Network said: “Climate security and energy security must go hand in hand. The best way to achieve this is for the Obama administration to keep building a clean energy economy.”
Amy Myers Jaffee, energy expert at the James A. Baker III Institute for public policy, said the place to take a stand on oil sands would not be in permit issuance but in bilateral talks with Canada ahead of the Copenhagen summit.
“The Obama people have to think about the overall Canadian relationship,” she said.
The countries are already embroiled in a lumber dispute, one of the longest-running trade disputes in history, which is centred on Canadian subsidies.
“You have to make a choice here,” said Steven Kallick, director of the boreal conservation project for the Pew Charitable Trust, a prominent US advocacy group. “[Extracting from] oil sands is clearly inconsistent with limiting climate change.”
TransCanada received permission from the Bush administration in 2008 to build a similar pipeline to carry oil sands fuel from Alberta to Illinois and Oklahoma.
Before the economic downturn, analysts estimated that pipeline companies and refiners planned to invest more than $31bn (€22bn, £19bn) by 2015 to export, process and distribute oil sands products. Some of that investment has been delayed or suspended.
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August 11, 2009
Canada's oil patch open for Chinese business: Flaherty
Jorge Barrera
Canwest News Service with files from the Financial Post
Financial Post
Monday, August 10, 2009
Finance Minister Jim Flaherty rolled out the welcome mat for Chinese investment in the Canadian energy sector Monday, saying this country's foreign-investment rules pose little hindrance to the growth of a Chinese presence.
Mr. Flaherty, in Beijing to give Canadian corporate interests a boost in the region, said China is flush with U.S. dollars reserves and is looking to spend it in the "emerging energy superpower" that is Canada.
In meetings with Chinese Vice-Premier Li Keqiang and Chinese Finance Minister Xie Xuren, Mr. Flaherty said neither indicated concerns Canada's foreign-investments regulatory framework would hinder Chinese business interests.
"They did not express any concerns," said Mr. Flaherty. "We are encouraging Chinese foreign direct investment in Canada . . . so long as there is compliance with the governance concern and other rules that we have with Investment Canada."
China has recently expressed concern over its difficulty in establishing a presence in Canada's energy sector.
"China has a great need for natural resources," said Mr. Flaherty, during a conference call with reporters. "Over time, we will see more investment by Chinese businesses in Canada and, over time, we will see growth by our financial institutions in this market (China)."
Mr. Flaherty was accompanied by a high-powered Canadian coterie of financial and corporate leaders, including Mark Carney, governor of the Bank of Canada, along with senior executives from Canadian banks, major insurance firms and the Toronto Stock Exchange.
The state of the global recession and efforts by governments to re-energize their respective economies dominated much of the discussions, said Mr. Flaherty.
"We agreed it is important that the other countries in the G20 keep their commitments that provide stimulus to their economies," said Mr. Flaherty.
Carney is scheduled to deliver a speech Wednesday to the Canadian Financial Forum in Beijing on how the Canadian model could be used to build a "resilient financial system."
Mr. Flaherty said his second trip to Beijing was aimed primarily at promoting Canadian corporate interests in China, and to also to entice more Chinese investment into Canada.
While China has been making deals with energy rich countries around the world like Iran and Venezuela, it has failed make any serious inroads into the Canadian energy sector.
In a speech delivered in Geneva on May 4, an official with state-owned China National Petroleum Corp. called for a strategic alliance between China and Canada to create an energy corridor hooking energy-rich Western Canada into energy-starved China.
"The opportunity is there. The question is action. China is prepared for the future and we see the potential Sino-Canadian relationship as a tangible, long-term, mutually beneficial strategy," the official said during a forum attended by Alberta Premier Ed Stelmach.
But Chinese interests have been stymied by regulatory, political and private-sector obstacles.
The high price of developing the oil sands has been a concern for China, which wants to bring in their own cheap labour to offset costs. Chinese firms have also encountered energy players reluctant to enter into major joint ventures. An undercurrent of political hostility also exists toward a large Chinese business presence in the Canadian energy sector.
August 07, 2009
NATURAL GAS: Market glut could push prices lower
COMMENT: In the context of the BC government slashing royalties to encourage even more investment in BC's lucrative gas plays (link), this shows that the government is chasing the market to the bottom, and giving away a valuable natural resource.
Greenwire
Friday, August 7, 2009
U.S. natural gas producers continue to increase production volumes past market demand, leading many to predict a price plunge that could put some small firms out of business.
The ability to extract gas from shale has increased reserves and lowered production costs, but as the recession continues to depress energy demand market prices are already down 70 percent from last year's peak of $13 per million British thermal units.
But producers who are reaping rich supplies from newfound fields aren't willing to switch off the spigot in the hopes of keeping prices stable. "Pretty soon, everybody is going to start involuntarily curtailing gas so we don't see any reason to take it on the chin for the team any more than we did," said Aubrey McClendon, chief executive of Chesapeake Energy. Chesapeake stopped curbing output in the second quarter. Its output is up 5 percent from a year ago.
Some analysts have questioned the strategy of expanded production in the face of increased inventories (Jason Womack, Dow Jones/Wall Street Journal [subscription required], Aug. 6). -- PR
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August 01, 2009
Is it time to press reset on nuclear?
Kathryn Blaze Carlson,
National Post
July 31, 2009
Cost overruns, delays in building reactors are sapping a nuclear revival
In a throwback to its tumultuous past, nuclear power is teetering on the brink of renaissance or relapse, waffling between a return to its golden age and a slow demise.
The world's relationship with nuclear has long been unstable, beginning in the 1960s when governments first embraced the energy source, then declining in the 1980s after projects grew grossly over budget and two major nuclear disasters rocked confidence. But the quest to quash climate change coupled with a hunger for energy security, have helped resuscitate nuclear power. The industry built better, more reliable reactors, and governments gave nuclear a starring role in their long-term energy plans.
Recent events, however, have put nuclear back on the defensive, bringing into question the future of the industry in Canada and beyond.
Today's debate pits proponents, who laud the technology for its ability to supply baseload demand, against those who tout renewable energies as both enviromentally friendly and economically responsible.
Onlookers from both camps are keeping a close eye on Ontario after it recently suspended plans for two nuclear reactors at its Darlington station, citing the reported $26-billion cost and the murky outlook of Atomic Energy of Canada Ltd., the arms-length federal body which produces CANDU reactors and whose bid was the only proposal to meet the province's terms.
The New York Times recently called the Darlington price tag and the subsequent delay a setback for AECL, a company that also faced criticism earlier this year after it was forced to shut down its Chalk River research reactor because of safety concerns.
Indeed, the Ontario situation is being watched by many -- from the Saskatchewan government, to London's Daily Telegraph, to a high-profile report by an American economist -- read by some as a cautionary tale that paints nuclear energy as more costly and less feasible than initially anticipated.
"The rest of the world has been looking at what we do on our own turf,"
said Neil Alexander, president of the Organization of CANDU industries, which represents more than 100 companies in the nuclear industry in Canada.
Globally, half of the 45 reactors currently under construction have encountered construction delays and many are over-budget, according to an analysis recently tabled to the German government. These delays and hefty cost overruns, together with the recession's decreased energy demand, have prompted a closer look at what was just years ago considered the world's favourite energy source.
The Point Lepreau station in New Brunswick -- Atlantic Canada's only nuclear facility and the first CANDU-6 reactor to undergo a complete rebuild -- has been under refurbishment since March 2008 and is now seven months behind schedule. The province is on the hook for roughly $150-million in additional replacement fuel costs, and will rack up another $20 million for every month the project is delayed.
In Finland, a massive power plant touted as the poster child of the nuclear renaissance has been under construction for four years. While the reactor was scheduled for completion this summer, Areva, the French company building it and one of three bidders on Ontario's Darlington project, is now unwilling to predict when it will go online. The reactor, slated to be the biggest in the world with an excavation site the size of
55 football fields, is today roughly 50% over budget.
Russia announced last week that it will rein in construction of new reactors because of the financial downturn and a decline in electricity consumption. Though the government planned to build two units each year over the next several years, it has "corrected" that plan by halving production to one unit per year.
Officials in the U.S. announced in April it would suspend construction of a $6-billion nuclear project in Missouri. Two months later, the country's largest nuclear power generator, Exelon, said it was "ramping back" plans to build a proposed nuclear plant in Texas.
"The industry has predicted that new cheap reactors, in a world searching for silver-bullet solutions to climate change, would revive an industry moribund since Chernobyl," said Shawn-Patrick Stensil, spokesman for Greenpeace Canada, referring to the 1986 nuclear disaster that left an entire Ukraine city uninhabitable. "Ontario's delay shows the industry is failing to deliver on cheap reactors."
Of course, rethinking nuclear would be no small thing.
Since the first station went online in Russia in 1954, another 440 nuclear reactors have popped up in 32 countries, the bulk of which are scattered across the United States, France, Japan and Russia.
Nuclear power generated 16% of the world's electricity in 2006, making it the fourth-largest source of electricity worldwide behind coal, hydro and gas.
According to the International Atomic Energy Agency (IAEA), world demand for uranium -- the atoms of which are split during the production of nuclear energy -- has at times outrun supply, so much so that decomissioned Russian warheads today satiate much of the world's appetite for uranium.
It is significant, then, that the global industry appears very much at a fork in the road, with two camps vying to steer its course.
In one corner is the nuclear lobby, which maintains that nuclear energy -- albeit expensive, with costs rising-- is the only reliable source of baseload supply and is far more environmentally friendly than its coal counterpart. They argue that green technologies, however noble in their eco-friendliness, are immature at best, weather-reliant, and pricey.
Though wind is on the cheaper end at roughly 8 to 15 cents per kilowatt hour, solar is pegged closer to 40 cents per kilowatt hour.
Among the pro-nuclear governments are Sweden and Italy, both of which recently overturned decades-old prohibitions on new power stations. Spain is likewise working to reverse a policy that phases out nuclear. China and India are going ahead with ambitious building programs, while the United Arab Emirates is fielding bids from South Korea, France and Japan to build a US$40-billion fleet due to be commissioned starting 2017.
Mr. Alexander, the CANDU president, argues that governments like these are wise to look beyond today's energy lull. "I would be very surprised if demand didn't pick up after the economy turns around," he said. "We need to make decisions today so that we have options 10 years from now."
Nuclear opponents, meanwhile, claim that wind, solar, and cogeneration are less expensive than nuclear in the long run, can be turned up or down depending on demand, and can help tackle climate change.
Indeed, for nuclear power to have a significant impact on reducing greenhouse gases, an average of a dozen reactors would have to be constructed worldwide each year until 2030, according to the Nuclear Energy Agency at the Organization for Economic Development. Currently, however, there are not even enough reactors under construction to replace those slated for retirement.
Mr. Stensil said governments once wooed by the idea that nuclear is cost-effective, are today forced to "face the bills" -- bills that, by some estimates, are 130% higher than they were in 2000. The delays and suspensions that inevitably ensue, are more proof that the nuclear renaissance is "dead on arrival," he said.
Not so, said Mr. Alexander, who argues that nuclear will work through its challenges and, when it does, Canada should be there to reap the benefits.
"Every day we delay, we are prejudicing our ability to be at the forefront of the nuclear renaissance," he said.
But whether a nuclear revival is, in fact, on the horizon is a prediction that is today hotly debated around the world.
Two weeks before the Darlington project was put on hold, economist Mark Cooper of the Institute for Energy and the Environment at Vermont Law School released a report stating that recent cost projections are "four times as high as the initial nuclear renaissance projections." Utilities, the report said, are embarking on "an ominous repeat of history."
Nuclear's difficulties began in the 1970s, a decade that saw costs balloon and was capped by 1979's Three Mile Island -- the most significant accident in the history of commercial nuclear-power generation in America.
After the devastation at Chernobyl, nuclear power was poised for
extinction: Two-thirds of all nuclear plants ordered after January 1970 were eventually cancelled.
Whether this decade will be marred by cancellations is yet to be seen. In the meantime, governments appear more cautious than ever.
Shortly after the announcement of the Darlington delay, Saskatchewan's Energy and Resources Minister Bill Boyd -- who is considering a proposal for a nuclear reactor in Northern Saskatchewan -- said Ontario's situation adds "additional questions about the whole area of nuclear power."
And just as governments, think-tanks, and the media are keeping an eye on the future of nuclear, so too are the markets.
On June 25, US credit-ratings firm Moody's Investors Service reported it may take a more negative view of power companies looking to build new nuclear powerplants, pointing to the risk incurred by developers.
Moreover, in 2008, Moody's noted that traditional technologies have fixed designs whose costs are rapidly increasing. Renewable technologies, it said, are still undergoing advancements in terms of energy-conversion efficiency and cost reductions.
Said Energy Probe's Lawrence Solomon: "Better late than never to bail out," he said. "This is a question of throwing more good money after bad."