_

U.S. crude stocks fell sharply last week as Hurricane Isaac’s passage through the Gulf of Mexico shut in production and closed ports, data from the industry’s American Petroleum Institute showed on Tuesday.

Crude inventories fell by 7.2 million barrels in the week to Aug. 31, compared with analysts’ expectations for a drawdown of 5.3 million barrels. The API-reported inventory drop was the largest since the week to July 27, when stocks fell by almost 12 million barrels.

Hurricane Isaac temporarily disrupted the majority of oil production in the U.S. Gulf of Mexico for several days, shut import terminals and shuttered several refineries in the region. Drilling companies are busy restoring output this week.

U.S. crude imports fell by 1.7 million barrels per day (bpd) to 7.9 million bpd, the API said.

Refinery utilization fell 3.8 percentage points to 87.1 percent of capacity, API figures showed.

In PADD 3, the Gulf Coast region, crude stocks fell by nearly 7.6 million barrels and gasoline inventories were down by 1.8 million barrels, while distillates fell by 800,000 barrels.

Total U.S. distillate stocks fell by 132,000 barrels. Analysts polled by Reuters had expected a larger 1.9-million barrel draw.

Gasoline stocks fell 2.3 million barrels, compared to forecasts for a larger decline of 3.4 million barrels.

U.S. crude futures slightly extended their earlier gains following the release of the API stock data, rising in post-settlement trading to $95.95 per barrel. Crude had settled earlier up 6 cents per barrel at $95.36.

Crude stocks at the delivery hub of Cushing, Oklahoma, rose by 58,000 barrels last week, API said.

original article

_

The price of oil slipped Tuesday after a weak report on U.S. manufacturing suggested demand for oil would fall.

U.S. benchmark crude fell $1.17 to close at $95.30 in New York. Brent crude, which is used by many U.S. refineries to make gasoline, fell $1.60 to $114.18 in London.

The Institute for Supply Management said Tuesday its index of U.S. factory activity fell for the third straight month, suggesting more weakness in the U.S. economy. When economic growth slows, drivers, shippers and travelers use less gasoline, diesel and jet fuel.

Meanwhile, oil production in the Gulf of Mexico is ramping up after Hurricane Isaac, erasing fears that the storm would impact supplies for an extended period and send prices up. The Bureau of Safety and Environmental Enforcement said Tuesday only 3.5 percent of the Gulf of Mexico oil platforms remain evacuated. Production ramped up by about 100,000 barrels per day between Tuesday and Wednesday and is now 710,000 barrels per day below normal. At the height of the storm, 1.3 million barrels per day of production was halted.

Oil might have fallen further Tuesday, analysts said, but traders are expecting stimulus programs will soon be announced in Europe, the U.S. and China that could free up cash for oil purchases and boost economic growth worldwide.

“There are a lot of crosscurrents,” said Andrew Lebow, an analyst at Jefferies Bache.

The European Central Bank President Mario Draghi is expected to reveal a program Thursday aimed at easing borrowing costs. Last week Federal Reserve Chairman Ben Bernanke suggested the Fed could do the same. A weak manufacturing report in China raised speculation that the Chinese government would also announce stimulus measures.

These programs reduce interest rates and free up cash for investors. They are then likely to use some of that money to invest in oil and other commodities, pushing prices higher.

Phil Flynn of Price Futures Group suggested hopes for stimulus could already be priced into the oil market, however.

“Last week we were intoxicated by stimulus,” he said. “The market now may want to see more than talk. It may want to see some action.”

Gasoline prices also fell — slightly. The national average retail price of gasoline slipped less than a penny to $3.82 per gallon.

Bigger declines could be on the way, though. Analysts expect gasoline prices to fall in the coming weeks as the refineries return to full strength, the summer driving season ends, and refiners switch to cheaper winter gasoline blends.

Phillips 66 said Tuesday that power had been restored to its 247,000-barrel per day refinery in Belle Chasse, La. that had been shut down in anticipation of the storm and then flooded by Isaac’s heavy rains. The company said it will be “a couple of weeks” before the refinery is running at normal rates. But now all of the refineries that were shut or slowed are in the process of ramping back up, according to the Energy Department.

Gas could stay relatively high, though, if economic stimulus measures keep the price of crude elevated. Retail gasoline prices are higher than ever for this time of year.

In other futures trading in New York:

— Natural gas rose 5 cents, or 1.8 percent, to close at $2.85 per thousand cubic feet.

— Wholesale gasoline fell 2 cents to close at $2.95 per gallon.

— Heating oil fell 3 cents to close at $3.15 per gallon.

original article

_

Natural gas has been one of the most talked about commodities this year, as its prices tumbled at the start of 2012. Up until a few months ago, NG had been one of the worst performing commodities over the past few years, as the recession started the fossil fuel on a slippery slope that it would never fully recover from.

In fact, low prices and a supply surplus forced many major companies to switch to oil exploration as opposed to doing the same for gas. “Last April about half of the nation’s 1,800 or so drilling rigs were looking for oil while half were looking for gas, according to IA. By this May over twice as many were looking for oil, and EIA has reported recent natural gas production numbers slightly below levels seen at the end of last year” writes Steve Hargreaves.

But the past few months have watched this asset claw its way higher as temperatures around the country have risen. Searing heat has led to a much higher demand for gas-powered appliances and helped to alleviate some of the growing stockpiles. This caused natural gas prices to tack on nearly 70% over the trailing three month period (despite plenty of volatility along the way). As such, a number of natural-gas based investments have performed exceptionally well, leading many to make bets on the industry. The only question that remains is how long this rally will last and if you will be able to time it properly.

original article

_

Nuclear power has become hard to justify as the shale gas revolution creates an abundance of natural gas that makes it the fuel of choice to back up renewables, the chief executive of General Electric told the Financial Times on Monday.

A sharp rise in shale gas production in North America in the past five years has pulled U.S. natural gas prices down close to 10-year lows and could turn the country into a gas exporter soon.

Large conventional offshore gas findings in Europe and Africa in the past two years, vast existing reserves in Russia and Central Asia and increasing production in Australia also mean gas is abundant elsewhere as well.

At the same time, nuclear power has come under pressure following the meltdown at Japan’s Fukushima reactor during the March 2011 earthquake and tsunami, with countries such as Germany and Switzerland pulling out of nuclear power generation.

“They’re finding more gas all the time. It’s just hard to justify nuclear. Gas is so cheap and at some point, economics rule,” the newspaper quoted GE CEO Jeff Immelt as saying in an interview on Monday.

GE is one of the world’s leading power generation engineering companies and, together with Japan’s Hitachi, is also active in designing and building nuclear reactors.

“It’s really a gas and wind world today,” said Immelt, referring to two sources of electricity he said most countries were shifting towards as natural gas became “permanently cheap”.

Solar and wind power, aided by component price drops and government subsidies, have made renewable power more competitive during the higher priced peak demand hours (usually 0800 to 2000 local time).

Immelt said that because GE was active in all forms of power generation, such a shift in production trends would have a limited impact on the company.

“We’ve got them all, so in some ways when you have them all you don’t have to be so smart about anything,” he said.

original article

_

Natural gas prices have surged over 70% during the past three months, fueled by increased air conditioning use, a switch from coal in power plants, and declining production rates.

The price for natural gas at Henry Hub, a junction of pipelines and storage facilities in Louisiana, has gone from $1.85 per million British thermal units in April to $3.14 Tuesday — a seven-month high.

“Hot weather forecasts and elevated cooling demands continue to provide a boost to the market,” Addison Armstrong, director of market research at the brokerage Tradition Energy, wrote in research note Tuesday.

Natural gas-fired power plants can be turned on and off relatively quickly, and as such are generally used by utilities to generate electricity during times of peak demand, like during a heat wave.

This June was the 14th hottest June on record, with temperatures nationwide two degrees above the twentieth century average, according to the National Oceanic and Atmospheric Administration.

U.S. cuts greenhouse gases despite do-nothing Congress

But that’s not the only reason behind the price spike.

The low prices seen earlier this year — they reached a 10-year low — prompted many utilities to switch from coal to natural gas for power plants in continuous operation.

In fact, electricity generated using natural gas was roughly even with coal for the first time ever in April, according to the Energy Information Administration. Historically, coal accounted for just under half of the nation’s electricity needs, while natural gas typically supplied just over 20%.

The low prices have also prompted many natural gas companies such as Chesapeake (CHK, Fortune 500), Devon (DVN, Fortune 500), EOG (EOG, Fortune 500) and Exxon Mobil (XOM, Fortune 500) to switch from natural gas exploration to exploration for oil.

Last April about half of the nation’s 1,800 or so drilling rigs were looking for oil while half were looking for gas, according to IA. By this May over twice as many were looking for oil, and EIA has reported recent natural gas production numbers slightly below levels seen at the end of last year.

Increased demand and lower production mean less natural gas is being stored. That storage number is a key barometer for natural gas traders. Armstrong said this week should be the twelfth consecutive week of below average storage rates.

But analysts caution that prices wont rise too far above current levels.

At $3 per million BTUs, coal once again becomes competitive as a fuel source.

And despite fewer drill rigs seeking out natural gas, plenty of the stuff still comes up along with oil in many oil wells.

“The current price level [for gas] is overvalued and is likely to decline and settle back,” Michael Fitzpatrick, editor of the industry newsletter the Kilduff Report, wrote Tuesday.

original article

_

There is a glut of natural gas. Everybody knows that. There’s so much of the latest multi stage hydraulic fracturing going on from New York State to Texas and all places in between, prices will be low forever. But just as a full watering hole can deplete quickly the current gas storage glut can recede. If fact it already has been and at an alarmingly brisk pace and there may be a confluence of other events which could hasten the process. Consider this. The weekly EIA natural gas storage numbers reported each Thursday came in with a 28 billion cubic feet (bcf) injection. The inventory increase last year at this time was 67 bcf while the five year average accretion was 74 bcf. So true that one week does not a trend make. But this makes eleven straight weeks that have experienced below average storage injections. After Thursday’s numbers were released inventories stood at 3.163 Trillion Cubic Feet or 19.2% above last year but only 17.5% above the five year average. A seemingly decent cushion until you consider as recently as May 10 stockpiles were 48.4% and 49.9% ahead of the previous year and the five year averages respectively. So the question becomes, why are rates of gas injection dropping so precipitously unless the shale plays are actually unable to produce the necessary incremental volumes.

A Little History And Some Facts

Natural Gas production in the US was declining steadily until 2005 into what many perceived as an irreversible trend with an implication of persistent shortages. Enter the knight in shining armor; horizontal resource drilling. Daily gas production increased from 51 bcfd in 2005 to an average of 66.2 bcfd (billion cubic feet per day) in 2011. Some months have even spiked above 70 bcfd.  The natural gas rig count peaked at 1,600 in the summer of 2008. No coincidence gas prices topped out concurrently the first few days in July at $13.28 per mcf. So in six plus years while gas drillers were able to increase daily supply by 30% demand has increased only half that amount. The result has been a spot gas price that bottomed on April 17, 2012 at $1.89 per mcf (thousand cubic feet). But the pendulum is now trending in the other direction as power suppliers and the transportation industry begin to capitalize on the low price of natural gas.

The EIA (US Energy Information Association) has prognosticated a 2012 daily production average of 68.98 bcfd and consumption of 69.91 bcfd. Methinks those production numbers extravagantly optimistic and yet the agency continues to publicly adhere to them. Firstly, actual output over the last two months has already slipped to a bit under 64 bcfd.   Next, the natural gas rig count collapsed to 486, a thirteen year low, on June 22 and had made only minimal recovery to 518 rigs as of last week. Lastly, numerous major gas producers such as COP and CHK have shut in parts of their dry gas production and are switching their drilling programs away from dry gas to natural gas liquids and oil. Conversely, consumption may exceed EIA projections. Here’s why. Hotter than usual temperatures across much of the country especially in the population heavy northeast is causing excess energy demand. Another thought provoking data point from the EIA last week reported that for the first time in history natural gas fired power plants generated more electricity than coal fired plants. That’s quite a milestone. Each now comprise 32% of U.S. power generation. Gas is cleaner and at current prices is a cost effective coal alternative. Adding to short term supply pressures, four nuclear power plants are down, all effecting east coast residents. Though still in early stages numerous fortune 500 companies such as Fed Ex and UPS are transitioning to natural gas powered trucks. A national fueling system is near completion with locations along the major interstate arteries.

Drilling Economics

The earliest horizontal resource drilling was done by Mitchell Energy (now part of DVN) in 2005 in the Barnett Shale which is in and around Fort Worth, Texas.  Horizontal fracturing into shale has become much more sophisticated since those early days, with enhanced recovery of gas in place, although at much greater cost per well. An average 20 stage horizontal dry gas well in the South Texas Eagle Ford Shale or the East Texas/North Louisiana Haynesville play may cost $8.5 to $12 million. It will be drilled to vertical depths of 8,000 to 12,000 feet below surface. I have examined production data for over 50 wells that have been operating for 9 months to over a year and a half. Now let’s do some arithmetic. Let’s assume an average well cost of $10 million with an estimated ultimate recovery (EUR) of 6 bcf.  At $2.00 per mcf gross expected revenues are $12 million and at $3.00 mcf revenues are $18 million and so on. Don’t forget about the expense side of the ledger. There is the mineral owner royalty payment which is often ¼ or 25% which comes right off the top. There are state severance taxes which vary from state to state but in Texas are 7.5%. There are ad valorem taxes of about 2% as well. Operating expenses will average $120,000 to $160,000 per well per year. Then the gas must be “cleaned” to make it conform to pipeline specifications. The highly toxic H2S (hydrogen sulfide) and CO2 (carbon dioxide) are removed along with excess water to get the gas below 7 ppm (parts per million). Only then is it ready to go into a KMP or EPD main high pressure sales pipeline. Estimated price tag for this gas prep is at least $.25 per mcf. Then after some number of years the well pressure will fall below certain levels and a compressor will need to be installed. If gas prices are low (like now) and the well’s gas production has declined to a small fraction of its original flow rates, the calculation is made as to which is more economic; install the compressor or shut in the production all together. The latter is the decision reached by hundreds of producers across the country. You are welcome to check my calculations but you lose a whole lot of money at $2.00 gas, lose some money at $3.00 gas, and make less than a 5% return at $4.00 gas. And all this assumes you can make an average of 6 bcf per well. The debate on this issue is becoming quite spirited. Recent data now suggest that many of these deep multistage horizontal wells are declining at greater than anticipated rates of 80% to as much as 90% in the first year. This was the case for almost all the well data that I inspected. So this means if production began at 5mmcf (million cubic feet) per day that by the end of year one that number may be reduced to 500 mcf to 750 mcf per day. The equally consequential part of this dispute is how long does this production last. The certain answer is that nobody knows for sure. The technology is so new that there aren’t any deep (below 10,000 feet) multistage horizontals that have been on production for 10 years or even 5 years. But if, and it is if, the “tail” in these shale wells fizzles out and the well becomes uneconomic after 8 or even 12 years instead of the projected 25 year life then the entire economics of the shale boom must be revisited.

Energy Content And Economics

The British Thermal Unit (btu) equivalent of one barrel of oil equals six thousand cubic feet of natural gas. Therefore if gas at $3.00 per mcf were to be at energy parity with oil, then oil would sell for $18.00. But WTI sells at $90 bbl. So gas must get more expensive or oil will get cheaper. As the gas rig count dwindles and evidence mounts that at least some of the shale plays are depleting much faster than projected, the result has been the aforementioned much lower than normal stockpile injection rates. With the disparity between oil and gas prices at such extremes, all available capital will continue to flow into drilling for gas liquids and oil. Some of the remaining dry gas drilling is probably just to maintain lease rights.  Newton’s 3rd Law of Thermodynamics says for every action there is an equal and opposite reaction. Natural Gas at $13.28 is too high and the April price of $1.89 is too low. The rubber band is becoming stretched in the direction of tight supply. It’s too cheap to drill for, so supplies will further dwindle until inexorably the shortage occurs and prices spike irrationally higher. That time is sooner than later.

Catalysts

We had an abnormally warm 2011-12 winter season in the US which sank home heating gas demand to extremely low levels. Was it because of an El Nino effect or did global warming play the pivotal role? Or, most likely, it is a confluence of several factors. Whatever the cause, the jet streams carrying the traditional cold temperatures and accompanying snowstorms didn’t reach south as far and as often as usual. Conversely, Europe had an abnormally cold winter last season suggested causes being the abstruse North Atlantic Oscillation Index, low solar activity and attendant low sunspot numbers and associated solar magnetic flux. You understand, right.

Natural Gas prices have spent all of 2012 below $3.00. Just the past three trading days, perhaps starting to reflect the fundamentals discussed herein, have seen spot prices nudge above the $3.00 level.  So combine 13 year low gas rig counts, declining production levels with resultant ultralow storage injections, shut in gas production, faster than anticipated shale well declines, persistent switching from oil and coal to cheaper and cleaner gas alternatives…..Then consider unending hotter than normal summer temperatures, continued greater than normal nuclear plant outages, a hurricane or two that knocks out Gulf of Mexico natural gas production for a week or two, and a La Nina induced cold winter…….any one of these can light the fuse that pushes the tenuous supply/demand balance into cardiac arrest. That’s the chain and it’s going to lead us to $8.00 mcf natural gas by the approaching winter.

original article

_

Rather than being a political football, fuels of the future will be cleaner, cheaper, and more “made in America” if the United States adopts a national Low Carbon Fuel Standard. That’s what scientists from six of the nation’s leading research institutions found in a series of studies released today at a bipartisan briefing on Capitol Hill.

“A national Low Carbon Fuel Standard is a promising framework to help solve the transportation energy challenges that have eluded us for several decades,” said Dr. Daniel Sperling, director of the Institute of Transportation Studies at the University of California, Davis. “Technologically, an LCFS is very doable. And it can help us address the complex choices with conventional oil, shale gas, oil sands, biofuels, and electric vehicles.”

Joining the scientists at the briefing were representatives of the automobile, electric utility, and biofuels industries.

Rather than government picking winners, a Low Carbon Fuel Standard (LCFS) is designed to reduce the amount of carbon in transportation fuels. It would require all energy companies to meet a common target for carbon intensity, but leave it up to the companies themselves to decide how to reach that goal. So, for example, an oil company might choose to diversify into electric or hydrogen fuels. Or it might add more low-carbon biofuels to its mix of offerings. Or it might buy credits from companies that specialize in low-carbon fuels, or that can lower the carbon intensity of their fuels more efficiently.

“An LCFS encourages innovation and diversity by harnessing market forces,” said Dr. Jonathan Rubin, professor of economics at the University of Maine. “These reports provide practical policy recommendations, and are designed to inject scientific information into the national conversation on a Low Carbon Fuel Standard.” The peer-reviewed reports will be published in The Energy Policy Journal’s special issue on Low Carbon Fuel Policy over the next several months.

Today’s reports are from the National LCFS Project–collaboration among researchers from six top U.S. institutions–each looking at a different aspect of how a Low Carbon Fuel Standard would affect America’s energy posture, national security, environment, and economy. The participating researchers are from Oak Ridge National Laboratory, the University of California, the University of Illinois, the University of Maine, Carnegie Mellon University, and the International Food Policy Research Institute.

Building on LCFS policies already adopted in Europe, British Columbia, and California, the researchers looked at potential costs and benefits of reducing the carbon intensity of transportation fuels by 10 to 15 percent by 2030. Researchers found an LCFS would buffer the economy against global oil price spikes, trim demand for petroleum, and lessen upward pressure on gas prices. It would also create fresh opportunities for new fuels to compete in the marketplace, save consumers money, reduce greenhouse gas emissions, and boost energy security.

“Our current energy posture has left America’s economy exposed to global oil price shocks and high oil import costs,” said energy security expert Paul Leiby of Oak Ridge National Laboratory. “An LCFS would substitute domestic resources like ethanol, natural gas, and electricity for imported oil, providing energy security savings up to $22 a barrel.”

The researchers say deep reductions in emissions from transportation over the medium term and long term could come from wider adoption of plug-in electric vehicles and fuel cell vehicles that run on hydrogen. Fuels from waste materials–from agricultural and forestry leftovers to municipal waste–are another important source of low-carbon fuel.

“A national Low Carbon Fuel Standard creates a strong market signal that attracts investment and spurs innovation in clean fuel technologies, increases consumption of clean fuels and lowers average consumer fuel prices, for a total savings of $411 billion by 2035 on fuel expenditures,” said Dr. Madhu Khanna, professor of economics at the University of Illinois, Urbana-Champaign’s Department of Agriculture and Consumer Economics.

The researchers found a national Low Carbon Fuel Standard would encourage farmers to grow crops that are especially suitable for conversion to fuel, rather than selling food crops into the biofuels market. That would ease pressure on food prices while giving farmers profitable options for degraded cropland.

“We have a big challenge that didn’t happen overnight, but these recommendations provide a framework for moving America toward a more sustainable transportation system. We look forward to spurring a national dialogue,” said Dr. Sonia Yeh, co-chair of the National LCFS Project.

original article

_

Oil prices are unlikely to fall much further over the balance of this year but could come under pressure in 2013 as the global economy falters due to slower US and Chinese growth, the IEA said Thursday.

The International Energy Agency, which advises developed countries on energy policy, said supply risks appeared to have put a floor under prices for this year even as global economic growth slows.

But for 2013, oil prices could fall in real terms by more than 7.0 percent, based on current models and futures contracts, it said, adding that such a downturn should marginally support demand.

Global economic growth this year will likely come in at 3.3 percent, down from the previous estimate of 3.5 percent as an “exceptionally challenging macroeconomic backdrop” forced the IEA to change its forecasts.

For 2013, the global economy should grow 3.8 percent, down from the previous 4.1-percent estimate based on figures in April from the International Monetary Fund, it added.

“Concerns are mounting on the sustainability of the eurozone, there has been a definite easing in China’s economic impetus and the US outlook has weakened,” the IEA said in its latest monthly report.

“Ongoing debt concerns across the developed world will likely see associated austerity measures curtailing government, business and consumer expenditure levels alike,” it said.

The IMF is expected to issue new economic growth forecasts shortly.

Oil prices were slightly easier, with New York’s main contract, light sweet crude for delivery in August, down 34 cents to $85.47 a barrel.

Brent North Sea crude for August shed 22 cents to $100.01, having fallen as low as $89 in late June after hitting highs in March of around $125.

In terms of oil demand, the IEA left its 2012 growth forecast at around 800,000 barrels per day (bpd) to around 89.9 million bpd, with 2013 gaining a “relatively muted” 1.0 mbd to 90.9 mbd, led by Asia.

The increase next year, while marginally more than the expected 2012 gain, was much less than would have been expected based on trends before the 2008 global financial crisis brought the economy to its knees, it said.

The eurozone debt crisis has since undercut growth further.

The IEA said that total global oil supply in June was down 500,000 bpd to some 90.4 mpd, with OPEC production slipping 100,000 bpd to 31.8 mpd.

Among OPEC members, the IEA noted that Iranian output had slumped to near 22-year lows at 3.2 mbd in June, down 100,000 bpd from May as US and EU sanctions ramp up from July 1.

However, despite the fall in output, the IEA noted that Iran exports to China had increased substantially by 300,000 bpd to 800,000 bpd and said it was now harder to track Iranian production and shipments.

The US and EU imposed tougher sanctions on Tehran over its nuclear energy programme, claiming it is a cover for atomic weapons development, a charge Iran consistently rejects.

On Wednesday, OPEC left its world oil demand forecast for 2012 unchanged at 88.68 mbd, putting 2013 at 89.50 mbd, up 820,000 bpd and compared to the 890,000 bpd gain expected in 2012.

Like the IEA, the Organisation of Petroleum Exporting Countries also cited the uncertain economic outlook for its cautious assessment.

original article