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Did Speculation Fuel Oil Price Swings?

(CBS) About the only economic break most Americans have gotten in the last six months has been the drastic drop in the price of oil, which has fallen even more precipitously than it rose. In a year's time, a commodity that was theoretically priced according to supply and demand doubled from $69 a barrel to nearly $150, and then, in a period of just three months, crashed along with the stock market.

So what happened? It's a complicated question, and there are lots of theories. But as correspondent Steve Kroft reports, many people believe it was a speculative bubble, not unlike the one that caused the housing crisis, and that it had more to do with traders and speculators on Wall Street than with oil company executives or sheiks in Saudi Arabia.

To understand what happened to the price of oil, you first have to understand the way it's traded. For years it has been bought and sold on something called the commodities futures market. At the New York Mercantile Exchange, it's traded alongside cotton and coffee, copper and steel by brokers who buy and sell contracts to deliver those goods at a certain price at some date in the future.

It was created so that farmers could gauge what their unharvested crops would be worth months in advance, so that factories could lock in the best price for raw materials, and airlines could manage their fuel costs. But more than a year ago those markets started to behave erratically. And when oil doubled to more than $147 a barrel, no one was more suspicious than Dan Gilligan.

As the president of the Petroleum Marketers Association, he represents more than 8,000 retail and wholesale suppliers, everyone from home heating oil companies to gas station owners.

When 60 Minutes talked to him last summer, his members were getting blamed for gouging the public, even though their costs had also gone through the roof. He told Kroft the problem was in the commodities markets, which had been invaded by a new breed of investor.

"Approximately 60 to 70 percent of the oil contracts in the futures markets are now held by speculative entities. Not by companies that need oil, not by the airlines, not by the oil companies. But by investors that are looking to make money from their speculative positions," Gilligan explained.

Gilligan said these investors don't actually take delivery of the oil. "All they do is buy the paper, and hope that they can sell it for more than they paid for it. Before they have to take delivery."

"They're trying to make money on the market for oil?" Kroft asked.

"Absolutely," Gilligan replied. "On the volatility that exists in the market. They make it going up and down."

He says his members in the home heating oil business, like Sean Cota of Bellows Falls, Vt., were the first to notice the effects a few years ago when prices seemed to disconnect from the basic fundamentals of supply and demand. Cota says there was plenty of product at the supply terminals, but the prices kept going up and up.

"We've had three price changes during the day where we pick up products, actually don't know what we paid for it and we'll go out and we'll sell that to the retail customer guessing at what the price was," Cota remembered. "The volatility is being driven by the huge amounts of money and the huge amounts of leverage that is going in to these markets."

About the same time, hedge fund manager Michael Masters reached the same conclusion. Masters' expertise is in tracking the flow of investments into and out of financial markets and he noticed huge amounts of money leaving stocks for commodities and oil futures, most of it going into index funds, betting the price of oil was going to go up.

Asked who was buying this "paper oil," Masters told Kroft, "The California pension fund. Harvard Endowment. Lots of large institutional investors. And, by the way, other investors, hedge funds, Wall Street trading desks were following right behind them, putting money - sovereign wealth funds were putting money in the futures markets as well. So you had all these investors putting money in the futures markets. And that was driving the price up."

In a five year period, Masters said the amount of money institutional investors, hedge funds, and the big Wall Street banks had placed in the commodities markets went from $13 billion to $300 billion. Last year, 27 barrels of crude were being traded every day on the New York Mercantile Exchange for every one barrel of oil that was actually being consumed in the United States.

"We talked to the largest physical trader of crude oil. And they told us that compared to the size of the investment inflows - and remember, this is the largest physical crude oil trader in the United States - they said that we are basically a flea on an elephant, that that's how big these flows were," Masters remembered.

Yet when Congress began holding hearings last summer and asked Wall Street banker Lawrence Eagles of J.P. Morgan what role excessive speculation played in rising oil prices, the answer was little to none. "We believe that high energy prices are fundamentally a result of supply and demand," he said in his testimony.

(CBS) As it turns out, not even J.P. Morgan's chief global investment officer agreed with him. The same that day Eagles testified, an e-mail went out to clients saying "an enormous amount of speculation" ran up the price" and "140 dollars in July was ridiculous."

If anyone had any doubts, they were dispelled a few days after that hearing when the price of oil jumped $25 in a single day. That day was Sept. 22.

Michael Greenberger, a former director of trading for the U.S. Commodity Futures Trading Commission, the federal agency that oversees oil futures, says there were no supply disruptions that could have justified such a big increase.

"Did China and India suddenly have gigantic needs for new oil products in a single day? No. Everybody agrees supply-demand could not drive the price up $25, which was a record increase in the price of oil. The price of oil went from somewhere in the 60s to $147 in less than a year. And we were being told, on that run-up, 'It's supply-demand, supply-demand, supply-demand,'" Greenberger said.

A recent report out of MIT, analyzing world oil production and consumption, also concluded that the basic fundamentals of supply and demand could not have been responsible for last year's run-up in oil prices. And Michael Masters says the U.S. Department of Energy's own statistics show that if the markets had been working properly, the price of oil should have been going down, not up.

"From quarter four of '07 until the second quarter of '08 the EIA, the Energy Information Administration, said that supply went up, worldwide supply went up. And worldwide demand went down. So you have supply going up and demand going down, which generally means the price is going down," Masters told Kroft.

"And this was the period of the spike," Kroft noted.

"This was the period of the spike," Masters agreed. "So you had the largest price increase in history during a time when actual demand was going down and actual supply was going up during the same period. However, the only thing that makes sense that lifted the price was investor demand."

Masters believes the investor demand for commodities, and oil futures in particular, was created on Wall Street by hedge funds and the big Wall Street investment banks like Morgan Stanley, Goldman Sachs, Barclays, and J.P. Morgan, who made billions investing hundreds of billions of dollars of their clients’ money.

"The investment banks facilitated it," Masters said. "You know, they found folks to write papers espousing the benefits of investing in commodities. And then they promoted commodities as a, quote/unquote, 'asset class.' Like, you could invest in commodities just like you could in stocks or bonds or anything else, like they were suitable for long-term investment."

(CBS) Dan Gilligan of the Petroleum Marketers Association agreed.

"Are you saying that companies like Goldman Sachs and Morgan Stanley and Barclays have as much to do with the price of oil going up as Exxon? Or…Shell?" Kroft asked.

"Yes," Gilligan said. "I tease people sometimes that, you know, people say, 'Well, who's the largest oil company in America?' And they'll always say, 'Well, Exxon Mobil or Chevron, or BP.' But I'll say, 'No. Morgan Stanley.'"

Morgan Stanley isn't an oil company in the traditional sense of the word - it doesn't own or control oil wells or refineries, or gas stations. But according to documents filed with the Securities and Exchange Commission, Morgan Stanley is a significant player in the wholesale market through various entities controlled by the corporation.

It not only buys and sells the physical product through subsidiaries and companies that it controls, Morgan Stanley has the capacity to store and hold 20 million barrels. For example, some storage tanks in New Haven, Conn. hold Morgan Stanley heating oil bound for homes in New England, where it controls nearly 15 percent of the market.

The Wall Street bank Goldman Sachs also has huge stakes in companies that own a refinery in Coffeyville, Kan., and control 43,000 miles of pipeline and more than 150 storage terminals.

And analysts at both investment banks contributed to the oil frenzy that drove prices to record highs: Goldman's top oil analyst predicted last March that the price of a barrel was going to $200; Morgan Stanley predicted $150 a barrel.

Both companies declined 60 Minutes' requests for an interview, but maintain that their oil businesses are completely separate from their trading activities, and that neither influence the independent opinions of their analysts. There is no evidence that either company has done anything illegal.

Asked if there is price manipulation going on, Dan Gilligan told Kroft, "I can't say. And the reason I can't say it, is because nobody knows. Our federal regulators don't have access to the data. They don't know who holds what positions."

"Why don't they know?" Kroft asked.

"Because federal law doesn't give them the jurisdiction to find out," Gilligan said.

It's impossible to tell exactly who was buying and selling all those oil contracts because most of the trading is now conducted in secret, with no public scrutiny or government oversight. Over time, the big Wall Street banks were allowed to buy and sell as many oil contracts as they wanted for their clients, circumventing regulations intended to limit speculation. And in 2000, Congress effectively deregulated the futures market, granting exemptions for complicated derivative investments called oil swaps, as well as electronic trading on private exchanges.

(CBS) "Who was responsible for deregulating the oil future market?" Kroft asked Michael Greenberger.

"You'd have to say Enron," he replied. "This was something they desperately wanted, and they got."

Greenberger, who wanted more regulation while he was at the Commodity Futures Trading Commission, not less, says it all happened when Enron was the seventh largest corporation in the United States. "This was when Enron was riding high. And what Enron wanted, Enron got."

Asked why they wanted a deregulated market in oil futures, Greenberger said, "Because they wanted to establish their own little energy futures exchange through computerized trading. They knew that if they could get this trading engine established without the controls that had been placed on speculators, they would have the ability to drive the price of energy products in any way they wanted to take it."

"When Enron failed, we learned that Enron, and its conspirators who used their trading engine, were able to drive the price of electricity up, some say, by as much as 300 percent on the West Coast," he added.

"Is the same thing going on right now in the oil business?" Kroft asked.

"Every Enron trader, who knew how to do these manipulations, became the most valuable employee on Wall Street," Greenberger said.

But some of them may now be looking for work. The oil bubble began to deflate early last fall when Congress threatened new regulations and federal agencies announced they were beginning major investigations. It finally popped with the bankruptcy of Lehman Brothers and the near collapse of AIG, who were both heavily invested in the oil markets. With hedge funds and investment houses facing margin calls, the speculators headed for the exits.

"From July 15th until the end of November, roughly $70 billion came out of commodities futures from these index funds," Masters explained. "In fact, gasoline demand went down by roughly five percent over that same period of time. Yet the price of crude oil dropped more than $100 a barrel. It dropped 75 percent."

Asked how he explains that, Masters said, "By looking at investors, that's the only way you can explain it."


The regulatory lapses in the commodities market that many believe fomented the rampant speculation in oil have still not been addressed, although the incoming Obama administration has promised to do so.

Source

Questerre Updates Quebec Activities

Questerre Updates Quebec Activities

00:41 EST Monday, January 12, 2009
CALGARY, ALBERTA--(Marketwire - Jan. 12, 2009) -

NOT FOR DISTRIBUTION ON U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES

Questerre Energy Corporation ("Questerre" or the "Company") (TSX:QEC)(OSLO:QEC) reported today that drilling operations have been successfully completed on the St. David well in the St. Lawrence Lowlands, Quebec.

Drilled to a target depth of 1995m on schedule and budget, St. David is the third well in the four-well farm-in program. The well has been cased as a potential gas producer. St. David was recently logged to evaluate the Utica and Lorraine shale/siltstone zones and the Trenton Black-River group. An analysis of these logs is ongoing to select prospective intervals for stimulation and testing.

Subject to equipment availability, completion and testing will commence after spring break-up. The Company expects the operator will spud the fourth and final well in the program, St. Edouard, in late February.

Questerre also reported on the status of the La Visitation and Gentilly wells in the Lowlands. Completion operations with multiple fracs on the recently drilled La Visitation well are currently underway. On the Gentilly well, the operational issues surrounding the packer have been resolved in order to allow testing of the Lorraine to resume shortly. Questerre anticipates preliminary results from these wells will be available during the second quarter.

Michael Binnion, President and Chief Executive Officer of Questerre, commented, "Drilling results on St. David were very positive as we saw promising gas shows in the Utica and Lorraine." Mr. Binnion also commented, "The pilot programs in the Lowlands are rapidly ramping up with several operations underway simultaneously. All these operations are designed to provide extensive technical data critical to assessing the commerciality of the play. We are very pleased that the operator does not compromise in this regard. We believe we remain on track to have an adequate sample of quality results to make a preliminary assessment of the commerciality of the Quebec shales in 2009."

Questerre is a Calgary-based independent resource company actively engaged in the exploration, development and acquisition of high-impact exploration and development oil and gas projects in Canada.

This news release contains forward-looking information. Implicit in this information are assumptions regarding commodity pricing, production, royalties and expenses, that, although considered reasonable by the Company at the time of preparation, may prove to be incorrect. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Actual results could differ materially as a result of changes in the Company's plans, commodity prices, equipment availability, general economic, market, regulatory and business conditions as well as production, development and operating performance and other risks associated with oil and gas operations. There is no guarantee made by the Company that the actual results achieved will be the same as those forecasted herein.

Barrel of oil equivalent ("boe") amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil and is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalent at the wellhead.

This news release does not constitute an offer of securities for sale in the United States. These securities may not be offered or sold in the United States absent registration or an available exemption from registration under the United States Securities Act of 1933, as amended.

FOR FURTHER INFORMATION PLEASE CONTACT:

Questerre Energy Corporation
Anela Dido
Investor Relations
(403) 777-1185
(403) 777-1578 (FAX)
Email: info@questerre.com
Website: www.questerre.com

© Copyright CCNMatthews

The Shale Gas Revolution

Oil Magazine.

Dec 2008

A float on fir rafts and light royalties, a production line forms across a northern B.C. muskeg seaMike Graham, EnCana Corp.’schief for the Canadian foothills of the Rocky Mountains, has noillusions.

The breakthrough he’s mandated to lead in northeasternBritish Columbia takes labor and cash – big time.“You walk offthose mats and you’ll be up to your waist in muck,” he says. Hiswarning describes a hazard of tapping natural gas beneath muskeg swampsin the Horn River Basin near B.C.’s boundary with the NorthwestTerritories.

The insects are beyond description.Portable firdecks are built by the tens of thousands at Prince George timber millsfor truck deliveries north, to lay down end-to-end and side-by-side ina growing network of floating roads and work platforms for B.C.drilling rigs.“It’s by no means cheap,” Graham adds. Each well into the new geological jackpot, where EnCana leads the industry pack with nearly 900 square kilometers of Horn River mineral rights, can cost $10 million.

The target only yields its riches to horizontal bores drilled up to 1.5kilometers across formations buried as deep as three kilometers belowthe swamps. Every well requires up to 10 “fracs” or rock-fracturinginjections of sandy fluid, with each shot using about 4.5 millionlitres of salt water obtained by drilling nearly a kilometer down intoanother geological layer. Multiple wells radiate outwards from eachfloating rig location.

This is the gritty and expensive Canadian version of the hottest drilling play in the United States: shale gas. EnCanaranks among the top participants in the new specialty’s cornerstoneBarnett Shale, a 13,000-square-kilometre Texas field in the Dallas-FortWorth region that produces about three billion cubic feet per day or asmuch as all of B.C. The Barnett total has the potential to triple,Graham says.EnCana also has 1,320 square kilometers of mineral rights in an emerging U.S. field – the Haynesville Shale on safe, dry land in northern Louisiana – that Graham describes as potentially twice as productive as the Barnett.

Therewere easier places to start transplanting the Texas technology toCanada. Earth scientists are poring over geological maps of shaleformations and starting to drill in Alberta, Nova Scotia, New Brunswickand Quebec.Talisman Energy and Questerre Energy are poised to launch a commercial pilot project in the St. Lawrence Lowlands west of Quebec City. Stealth Ventures Ltd. describes its pioneer Albertashale gas program as advancing from “a conceptual technology play to acommercial producing asset” with a 70-well drilling program atWildmere, southeast of Edmonton.

Triangle Petroleum Corp. and Corridor Resources Inc. are probing geological formations beneath New Brunswick, Nova Scotia and Prince Edward Island.B.C. lured large-scale development by industry who’s who – from Apache Canada to Nexen Inc. – with a gas counterpart to Alberta’s pro-development oil sands royalties. Mineral rights sales in the Horn River region and similar Montney area topped $2 billion in the first nine months of 2008 or more than double B.C.’s previous annual record.Thenew B.C. regime, enacted with Alberta industry guidance and no publicfanfare last spring as the “net profit royalty regulation,” chargesonly two per cent of gross production revenues.

The rate stays at thatnominal level until all gas-field drilling and development costs arepaid over up to 10 years.After “payout” or full cost recovery,three higher “tiers” set B.C. gas royalty rates at the greater ofseveral potential levels: five per cent of gross revenues or 15, 20 or35 per cent of net revenues after operating expenses.

The rules ensureincreases will be gradual. The rising tiers only kick in as revenuesreach levels double and then triple project costs. The policy continuesto evolve and potentially widen beyond shale gas, with B.C. authoritiesinviting further industry submissions on types of operations thatshould qualify for the incentive scheme.As in Alberta’s oilsands, the key to commercial success in B.C. shale gas is economies ofscale. Developments work when high initial costs are spread thin overthe greatest possible production. In industry language coined by EnCanathese are “resource plays,” where jumbo projects harvest large mineralrights spreads by doing multiple standardized, repetitive drilling andproduction installations over long periods of time. “We talk about amanufacturing approach,” Graham says. “We talk about a natural gasfactory.”EnCana alone expects to produce one billion cubic feet of Horn River gasper day eventually, single-handedly increasing B.C.’s current totaloutput by 33 per cent. The company plans to operate up to 10 drillingrigs around the clock, 365 days a year in the remote region.

“Everytime we drill a well, we get more proficient. We get better at it,”Graham says.At a technical level, the new specialty deserves tobe called revolutionary. The approach replaces eons of fossil fuelevolution. Shale is a geological “source rock,” where organic materialfrom ancient sea beds and swamps biodegrades into methane or oil, thenslowly leaks out and migrates to underground “trap” formations.

These much rarer natural storage sites have been the industry’s drillingtargets for its entire history to date, with their scarcity, size andstructure setting limits on reserves and production.Theresource potential of source rocks is measured in hundreds or eventhousands of trillions of cubic feet, in a gas version of theastronomical ratings for the oil sands. B.C. alone has enoughpotentially gas-charged shale to harbor up to 1,000 trillion cubicfeet, the province’s energy ministry calculates – a fossil fuel motherlode that is the energy equivalent to 166 billion barrels of oil. Theswampy Horn River Basin sprawls across 12,800 square kilometers ofnortheastern B.C.Shale gas also has the potential torevolutionize the energy outlook for all of North America, Graham says.Conventional forecasts, saying U.S. and Canadian gas supplies havepeaked and begun to turn down, are starting to look obsolete.“We’re still just scratching the surface.

The big supply is yet to come.”Instead of building a long lineup of import terminals currently proposed for tanker cargoes of liquefied natural gas from overseas, the industry may need LNG export ports, the EnCana executive suggests.

The first project catering to a possible about-face in gas suppliessurfaced as summer ended. Calgary-based Kitimat LNG Inc. converted its$750-million proposal for a north Pacific import terminal on the B.C.coast at Kitimat into an export scheme about four times bigger.Alberta Oil Magazine.Dec 2008