?
What i´m missing here? 36 bcf is nothing imo
?

About a year ago I insulated my 80 year old house and installed good replacement windows. My natural gas consumption has fallen from an average of 8.3 therms per day (Nov. 1 through Feb. 28/29) to 5.4 therms per day, a decrease of 35%.

Clearly we have more ethanol production year over year as well. Does anyone have any statistics on the increase in natural gas usage due to ethanol plants ? (I guess it would also be possible to calculate NG use for fertilizer and pesticides but much of that is sourced overseas now)

I just wanted to point out that while it may seem cold for january (from the same Hadley data), we've seen (globally) recent colder Januaries in 2000 and 1996 (how soon we forget).

Here is the plot of the January data from 1900 to 2008. I'm working on one for seasonal winter and I'll post it shortly. Compared to previous years it is a drop but it is still the 30th warmest january on record from 1900 to 2008.

Watch and hear Schlesinger's comments on natural gas and more speaking at the
The National Academies Summit on America's Energy Future - The Geopolitical Context of America's Energy Future; Day 1, Part 3, March 13, 2008

He opens his speech with the following:

"We face a challenge, an immense challenge, both foreign and domestic.

The question is our ability to respond effectively to that challenge and that remains a bit problematic. In his study of history, a 12-volume study of history, Arnold Toynbee examined I think it was 27 civilizations and why some of them had failed, why they had collapsed and it was in response to a challenge that they could not handle, some specific challenge. And a question about which we might brood is whether the combination of energy and environmental challenges will be ones that we can handle, handle with severe damage or fail to handle."

This chart is from the Canadian National Energy Board short term 2007 - 2009 NG deliverability report.

The Canadian government is predicting a fall in natural gas production because current prices are too low to support high drilling activity in Canada. This is going to make it difficult to refill those stocks. We can expect that stocks will fall until a price spike drives prices high enough to do more drilling.

NG in North America is not like world oil. Prices are only a thin margin above drilling costs. That is because industrial feed stock users are being destroyed (a 22% drop in NG demand from 1997 - 2005). Don't delay those insulation and home heating investments. The industries are buying home owners a brief price respite. It is coming to an end.

I have spoken with David Hughes who sits on the Canadian Gas Potential Committee. He confirms Leherrere's prediction for Canadian Gas. The pink line is total production (U=1900 in the key).

You can hear him discuss the situation here: http://globalpublicmedia.com/transcripts/827

Precision Drilling Trust is one of the largest natural gas drilling service "companies" in Canada. This was taken from the 2007 3rd quarter report:

In Precision’s market in the Western Canada Sedimentary Basin (“WCSB”), lower oilfield activity, on a
seasonally adjusted basis, became further entrenched in the quarter. Activity for Precision’s drilling and
service rigs was 32% below the third quarter of 2006 and near their lowest levels for a third quarter in
the last decade.

Overall, the business environment for oilfield services in western Canada remained challenging as market
conditions and fundamentals weakened for the fifth consecutive quarter. Average customer pricing for
Precision’s services in Canada declined moderately in the third quarter, down 12% for drilling rigs and
essentially unchanged for service rigs, compared to the third quarter of 2006. Sequentially, drilling rig
pricing fell 8% from the second quarter of 2007 while average pricing for service rigs remained constant.
Precision is beginning to experience pricing pressure for new work in the United States. However, relative
to Canada, U.S. pricing remains strong.

There is a whole lot more to the story. The last year we had a severe drawdown from storage was the winter of 2002/3 which ended with about 730 Bcf in storage, and the NE on the edge of non delivery due to low pipeline pressure. Since then we have had a string of mild years, with low HDDs or CDDs or both. We have also increased storage caoacity from about 3200 Bcf to 3600 Bcf, and because of the mild weather have been able to reach essentially maximum storage every year. In 2006 we very nearly had more supply than we could store, and a small amount of supply was shut in. In 2007, with s little more capacity available we fell just short of the overfill point, mainly due to a decrease in both LNG and imports from Canada late in the year. USA production in 2007 was about back at the previous peak of 2002, due to growth in non conventional supply as shown in Laherreres chart. The growth in unconventional supply resulted from a huge increase in drilling during 2005/6/7, which cannot be continued due to lack of spare rig capacity. In fact drilling flattened, albeit at a high level in H2 2007.
For the 2008 injection season we can expect little to no increase in USA supply, some decline in Canadian supply (as shown above) and a decrease in LNG imports due to high demand/prices in ROW. To offset this problem we will likely have an increase in Hydro due to the huge western snow pack and precipitation, and maybe a mild summer if we are in the beginning of global cooling. For several years now we have not exceeded injection of 2100 Bcf. We are likely to end the withdrawal season with 1200 Bcf left in storage and maybe will start the next withdrawal season with no more than 3400 Bcf in storage vs a capacity of 3600 Bcf. Another withdrawal season like this one will bring storage below 1000 Bcf, and set the stage for a major crisis by March 2010.
If we have a few weeks of hot summer, one or two temporary nuke outages and a cold winter next year, the crisis will be by March 2009. Peak NG for North America is almost certainly coming before peak oil. If you heat with NG I strongly advise purchase of long johns and sweaters. Murray

Meanwhile pickens is advocating running cars on ng, low emissions/cost... great idea, but cars typically run for a decade, ng might not be so cheap in 2018. OTOH, he would do well if demand soars...

No one seems to be discussing the implications for electricity if natural gas prices increase too much.

Here in rural Iowa I have been using LP for a back up to my corn stove. With LP prices rising to the area of $2.00/gal or more retail, I am finding that electric heat is about the same price now. Plus I do not have to buy a full tank which can run $800.00 for 400 gals.. I know many heat with LP since natural gas is largely unavailable in the country.

I'm now using electric space heaters as back up on days that are too warm to start the corn stove which is difficult to regulate in warm weather. If others figure this out, there may be a shift to electricity in the country.

I would expect a shift to electricity at some point if natural gas prices rise sufficiently. Electricity prices seem to be more stable at least around here. I understand some places have a whole regulatory process to adjusting electricity rates. This is a definite advantage over LP gas since its price seems to vary a lot and change much more often.

Chevron discovered an estimated 6 trillion cubic feet natural gas field in Vietnam:

http://www.iht.com/articles/ap/2008/03/26/business/AS-FIN-Vietnam-Chevro...

Six trillion cubic feet of natural gas is the BOE/barrel of oil equivalent of a billion barrels of oil in BTU's.

EIA has also published the Natural Gas Year-In-Review 2007 this month, dunno if that's fresh off the PDF or not. Lotza inneresting factz - exports to Mexico down, LNG up, more pipeline capacity, rig count stabilizing, stocks high.

Nothing about that compressor station exploding in Kentucky - or was it Tennessee? They patch that up yet?

With respect to US natural gas production, the trend is not all that clear to me.

If we look at recent US production, it has actually increased a bit in the last two years:

Natural gas reserves have been growing fairly steadily:

The Year in Review tells about significant activity in building new pipeline. It is my understanding that some of the new tight gas and perhaps shale gas was shut in, because no pipelines were available. Now that pipelines have been built, this should help new production.

We know that there is a decline in conventional natural gas production, but exactly how that balances out with the increase in unconventional natural gas is not that clear to me.

Natural gas prices in the recent past have been low in relationship to oil prices. If the historical differential should hold, or even shift to a higher relativity for natural gas, than it seems like the higher price would encourage unconventional natural gas production. If there is a choice between higher natural gas prices and no electricity or no heat, it seems like we may choose higher natural gas prices.

There is a huge difference among oil, natural gas, and coal in price per BTU. If the natural gas price ever increases to near the oil price, it seems like a lot of otherwise uneconomic natural gas would become economic.

Could anybody tell me how to find the price of North Sea natural gas on the Internet? thx

and also price in Japan, and anywhere in the world

Saudi Desert's Gas Mirage?
Boast of Vast Reserves Faces
Growing Skepticism as Firms
Go Dry in the Empty Quarter

By GUY CHAZAN and NEIL KING JR.
March 25, 2008; Page B1

Saudi Arabia's boast that its southern desert region contains vast reserves of natural gas is facing growing skepticism, amid a string of exploration setbacks by international oil companies operating there.

The kingdom had hoped that gas in the Rub al Khali, a vast desert that translates into English as the Empty Quarter, would be a key source of fuel for its booming economy. If the region turns out to be as empty as its name implies, Saudi Arabia runs the risk of a gas-supply crunch within the next decade at today's rate of demand.

South Rub al Khali Co. so far has failed to hit large pockets of natural gas.

If that happens, and the kingdom has less gas than expected, it will be forced to divert more of the oil it produces for its own use, leaving less to fuel the rest of the world's cars, airliners and factories.

Pessimism about the Empty Quarter was fueled by French oil company Total SA's decision in January to quit a consortium exploring for gas in the region after it drilled its third dry well. "We don't see any way forward after [these] results," said Christophe de Margerie, Total's chief executive, in a recent interview.

Saudi Arabia has proven gas reserves of around 250 trillion cubic feet, according to British oil giant BP PLC, the world's fourth largest after Russia, Iran and Qatar. But most of that is caught up in producing oil fields, and not available for use. New discoveries have fallen far short of expectations. Meanwhile, the kingdom is seeing a huge increase in domestic demand for the fuel as a feedstock for everything from desalination plants to heavy industry and power generation.

Saudi Arabian Oil Co., the state-controlled oil giant known as Saudi Aramco, forecasts domestic gas demand will nearly triple by 2030 and is on a drive to boost the kingdom's reserves of nonassociated gas -- that is, gas from wells that don't contain any crude oil -- by 100 trillion cubic feet over the next ten years.

One of the world's largest deserts, the Rub al Khali is one of the most-inhospitable environments on earth: temperatures can reach 131 Fahrenheit. Former U.S. Secretary of Defense Caspar Weinberger once wrote that Rub al Khali "makes Death Valley look like a summer resort." But it has long been seen as the key to Saudi Arabia's gas-supply problems. The hope is that the region will add a significant fresh stream of natural gas by 2011.

Saudi Arabia has been off limits to foreigners for exploration, but five years ago it invited foreign investors to help it develop gas deposits in the Empty Quarter. That marked an evolutionary leap for Aramco, which has barred the big international operators from exploration work in the kingdom since the company was fully nationalized in 1980. The unraveling of these partnerships, should they fail to hit large pockets of gas, would be an embarrassment for a country that prides itself on being awash in hydrocarbons.

Saudi officials are confident there will be big finds. "There is still reason for optimism," said one. "We don't know what the success will be but the geologists are still hopeful."

One former senior Aramco official, however, remains skeptical. "If there was a lot of gas there, we would have been exploring it ourselves," said Sadad al-Husseini, former head of exploration and production, who retired in 2004. He spent several years overseeing gas exploration in the Empty Quarter in the early 1970s. "It is just unfortunate that so much money has been spent to confirm what we knew already," he said. The companies declined to divulge costs.

Mr. Husseini is among a growing contingent within Saudi Arabia that believes that the kingdom's whole gas strategy is misguided. With signs mounting that the kingdom overestimated its available gas supplies, Mr. Husseini said, "the consequence is that we need to go back to the strategy we had before, which is to make better use of oil, to be more efficient, and to be more gradual in our industrialization."

Total was a partner in one of four international consortia created to drill in the Empty Quarter. The company it formed along with Aramco and Royal Dutch Shell PLC -- the South Rub al Khali Co., or SRAK -- was awarded the largest concession, an area the size of Kansas. But the results have been disappointing. "We see the ingredients of a hydrocarbon system," says Malcolm Brinded, Shell's head of exploration and production. "We just haven't found them all together in the same place."

With Total gone, Shell will now have to shoulder more of SRAK's exploration costs. But it says it will stay the course. Shell Chief Executive Jeroen van der Veer recalls an incident in the 1930s when the company was asked to take part in an international consortium exploring for oil in Saudi Arabia. A famous telex, still in Shell's archives, declined the offer, saying there was no oil in the kingdom. "I don't like to make the same mistake based on three wells in an area fives times as big as the Netherlands," Mr. van der Veer says. None of the other foreign companies working in the Empty Quarter have found gas in commercial quantities either.

There has been some good news. Luksar, a joint venture of Aramco and Russian producer OAO Lukoil, last year reported discovering some hydrocarbons at one of its wells. Sino Saudi Gas, which brings together Aramco and Sinopec International Petroleum Exploration & Production Corp., also announced initial gas flow from one of its wells, though it's too early to say how much gas is there. EniRepsa, a consortium of Italy's Eni SpA, Spain's Repsol-YPF and Aramco, has found nothing substantial.

"They've only scratched the surface in terms of the search for gas," says Iain Brown, a Middle East expert at oil-and-gas consultancy Wood Mackenzie. "There's a long way to go before the potential for gas has been fully evaluated."

But as the failures build up, so are the costs of drilling each well, which has shot up to around $70 million, up from the $30-$50 million projected in initial budgets, according to industry observers. Rigs also are scarce, and wells on some blocks are taking longer than expected to drill.

From the start, the ventures had relatively low rates of return; the companies have to sell any gas they find to Aramco at 75 cents a million British thermal units, minus a fee for transportation of around 15 cents a MMBtu.

Conditions on the ground are tough, too. South Rub al Khali had to build its own airstrip so workers could be evacuated in an emergency. Drinking water must be brought in from the nearest town 190 miles away. Sandstorms mean workers have to wear respirators.

Analysts say the Rub al Khali might not even be the best place to be looking for gas in Saudi Arabia, and that the Saudi Aramco Reserve Area in the east of the kingdom -- a province off limits to foreign companies -- has by far the most-promising acreage that covers an area that is a little larger than North Dakota.

Yet companies still leapt at the chance of working in the Empty Quarter, hoping for a rare foot in the door in Saudi Arabia's oil-and-gas exploration sector and an in with Aramco. But Total's Mr. de Margerie says there was no point in staying in SRAK just to keep on the right side of Aramco. "You have to be pragmatic," he says. "If you start to do things to please, your company will be dead."