Concerning gas supplies and production analysts

Sorry but I can't resist this quote.  There was an ASPO meeting in the UK yesterday.  The invited along Michael Lynch, who among other things had the following comment:
He says that the study of peak oil is not a science and that those who advocate it are guilty of naiveté, ignorance and plain manipulation of the data. "There are a lot of zealots out there and a lot of claims are made which are not tested," he says. "It is true that oil is finite but since 1989 people have repeatedly predicted the peak too soon and have had to keep on increasing their estimate of reserves. Just because a country's output has peaked and gone into decline, it doesn't mean that production can't rise again."
(Grin, and a nod to Powerswitch. (So Stuart and Prof take note, you are being watched ( :-) ). Incidentally Chris Skebowski is quoted as saying that he expects the peak to be in 2008, and I am presuming that he is including NGL and other non-conventional sourced liquids in this.

While the Iranian situation seems to be easing off a bit, the cold spell in Russia is now affecting supplies to a number of countries, the BBC reporting that a number of countries have seen supply drops, although Gazprom is perhaps claiming that it is still meeting its obligations. (A later BBC story says that they have cut back, despite their earlier denial).  That second story also comments that:

More seriously, some of the oil wells in Siberia have frozen, and Russia is producing 200,000 barrels of oil a day less than it was last month.
Over on the Eastern Siberian coast Sakhalin Island has shut down for the winter, since oil still moves from there by tanker, although there are plans to put in pipelines so that by 2008 the oil can flow, even at times like these. (Tip to Nick Rouse).
The weather is supposed to become even more severe through Friday over there, and so one might assume that this shortage of supply will remain in place through the weekend.  Unfortunately it is hard to see where other countries can get, in the short term, an alternative supply.  If, in fact Western Europe is seeing a shortage of about 20%, then we know from the Ukrainian situation at the New Year, that neither the Netherlands nor Norway is going to be able to help very much. There are a couple of new pipelines going in, but neither will be in place for at least a year, and this is probably too short a time frame, and too small an opportunity, for an alternate source to be developed. On the other hand, BP is telling you not to worry.

And on a couple of parenthetical notes Moldova has also now agreed to pay more for their gas. A little more, in fact, than the Ukraine. And Exxon Mobil is denying reports that they have suspended exports from Nigera, as I had noted that they had done, yesterday.

I also want to note that activity is continuing to recover gas from the Barnett Shale in Texas, as much because it will be interesting to revisit this over the next couple of years to find out how supply holds up, given

The Barnett Shale is the largest gas producing field in Texas and one of the three largest in the United States, with production expected to exceed 400 billion cubic feet this year.
To put that in perspective, see here and here.

Historically there has been a bit of a lull in demand in the second quarter of the year, between the fuel needs of winter and the driving and air conditioning demands of the summer.  This is the time for refinery maintenance, oil stock buildup and the like.  That drop in demand is unlikely to occur, given that borrowed fuel must be repaid, and the discussions about increasing the size of the SPR. If both the US and China choose to put oil into SPR tanks, then demand may even rise, and prices with them.  This was a constraint on Chinese action in this regard, last year.  However, given the benefits of such action, one wonders whether they will continue to hold off much longer?

Too bad the meeting wasn't held in Tomsk.
There have certainly been production increases after declines, but has any major producing area (with at least 50 Gb or so in recoverable reserves) shown a production increase after hitting about 55% of Qt, based on P/Q versus Q?  

Based on the data I have seen, the answer is no.  

The current key case history is Saudi Arabia--at 55% of Qt.

The "nonscientific" label is interesting.  One of Lynch's cohorts, Peter Huber, asserts that our energy consumption will increase--forever.   Huber, if pressed, will admit that some energy sources, like conventional oil, will eventually peak and decline, but he still asserts that aggregate energy consumption--from a group of finite energy sources--will increase forever.   Let's see, infinite energy from a group of finite energy sources--yep, that makes a lot of sense.  

but has any major producing area (with at least 50 Gb or so in recoverable reserves) shown a production increase after hitting about 55% of Qt, based on P/Q versus Q?
Only if you do the linearization too early. For example
You can't model UK production with a single logistic model.

Two cycles of discovery -> Two logistic models.

The US crossed 50% Qt in 1971 and crossed 55% of Qt in 1978 (using 220gb as Qt) yet our production increased each year from 1976 to 1985 (except 1981 small drop). Yes that was Alaska for the most part, so your 'geologic' point is sound.(if you include Alaska in north america as a whole I dont think this still holds). But on a country basis, here is one example. Perhaps there are others.
The Lower 48 peaked before serious production even began in Alaska.  In terms of timing of development, geology and distance, Alaska might as well be in the Middle East.  

The key to developing a useful model is to set reasonable geographic limits.  In time, the world--a geographically limited area--will show the same type of production behavior as our geographically limited models--Lower 48; Texas and the North Sea.  

Texas peaked at 54% of Qt (66 Gb), and production has steadily fallen.

The Lower 48 peaked at 48% of Qt (200 Gb), and production has steadily fallen.

The North Sea peaked at 52% of Qt (60 Gb), and production has steadily fallen. Furthermore, the North Sea P/Q intercept accurately predicted that the North Sea would have a steeper decline rate than Texas and the Lower 48.

The peaks significantly before 50% of Qt, e.g. Iran, have corresponded to political problems.

My proposed ground rules are:  (1)  reasonable geographic limits; (2)  decades of serious production and (3)  a Qt of at least 50 Gb.  

Within those limits, has any region shown production increases beyond 55% of Qt?

The multi-trillion dollar question is Saudi Arabia, currently at 55% of Qt.

It certainly sounds reasonable that once a field has gotten past a certain point, it has not been economical to try to force an actual increase in production. It would probably be possible to do so, if you spent enough money, but it makes more sense to spend that money on newer fields which will give you a much greater return on your investment.

This is why I have urged caution in extending these principles into the environment of a worldwide peak. Once we get to the point where there are no other fields to go to, where the only possibility is to spend more to improve production from existing fields, then incentives will be different and we may well see different results.

In the near-peak and post-peak periods, oil will rapidly increase in value and oil owners will try much, much harder than we have ever seen before to improve extraction from their fields. I don't know how much success they will have, but you can't extrapolate from past failures to resurrect declining fields and assume that this will remain true once we hit a worldwide peak.

Oil companies in Texas have had considerable incentives to increase production from existing fields.  We have tried everything known to the oil industry.  The same thing is true in the North Sea.  In both cases, it's been all downhill once production peaked at around 50% of Qt.  Note that these two peaks were 27 years apart (1972 and 1999).  

The best example of the true problem is the East Texas Field, which is now producing 1.2 million bpd of water, with a 1% oil cut (12,000 bpd).  What can technology do to increase production from a field that has watered out? This is precisely the same problem facing the Saudis in the Ghawar Field.

At Matt Simmons has documented, better technology has primarily given us faster production rates--and faster decline rates once production peaks.

As we approach peak you would expect to see all available rigs jump out of cold storage and drill for hydrocarbons. That has happened. More money will not provide the world with hardly any more rigs in the near term. Meanwhile, reduced production/ng well has resulted in high prices for ng, which in turn has distracted the US rigs such that 85%, up from 50%, are now drilling for ng. Higher oil prices will just compete with high ng prices for available rigs - total US production will continue declining regardless of price. The same situation exists all around the world - Saudi poached deep sea rigs from our gulf to drill in theirs.
I'm pretty sure that if you ask a geologist why the number of rigs drilling for NG is relatively higher, she/he'll say that it is not because they had a choice between drilling either an oil well OR drilling a gas well, but that they (geologists) see a 5.67 times higher successful completion percentage (or would it be 5.67 x the # completions x expected profit/completion?  Anyway...) in recommending that they try drilling for gas rather than try to drill for increasingly scarce oil with holes that have increasing probabilities of coming up dry.
Its simpler than this. ng companiew bid against oil companies for rigs, and can afford to bid more because ng has increased much more than oil over the bast couple of years.
Actually that used to be true but now isnt. Since Jan of 2003, Nat gas has gone from $5.10 to $9.20 or up about 80% -(in November it was at $15.70+) During the same period WTI crude has gone from $32 to $68 or about $115%. If price is the switching impetus, expect the # of rigs drilling for gas to decline -
I thought that somebody would bring that up, which is why I included the semi-formula for maximizing expected returns if gas price had increased overproportionally to oil in recent times, rather than just having left it with the formula based on  choosing X from the total available possibilities, so there was really no possibility of a wrong answer as I kinda' suggested both could be driving factors, but anyway... I know that there's a hellova' lot more gas fields than oil and its a long-held geologist's (shall we say) "superstition" that its always easier to hit a producer (oil or gas) near the ones you already know are winners.  Usually they'll try that unitl its even plainly obvious to the investors that there just aint any more to be found here and they can't trust the geologist's recommendations any longer, 'cause the geologists are still saying to drill the next 40 acres right there, even if the last 10 came up dry.  Nobody's more optimistic than a geologist.  (I don't mean that in a poor way.  I have much respect and know I don't have X-ray vision either.  Just that the continously optimistic production forecasts made it real hard for me to optimize the gathering system when the wells would make 30 MMCFD for 30 days than fall off to 50,000 CFD in the next couple of weeks and stay there for the next 2 years.  Granted, it wasn't the best producing formations they were drilling on either.)

I see there's another one that agrees.

I think we're talking about increasing production ABOVE the highest amount before 55% Qt was extracted. Sure you can increase production one year over another, but to actually reach a higher Bbl output after "peak" would seem to be impossible (in addition to never happening thus far). Its kind of like thermodynamics. No variations have ever been observed in nature, unless your research is funded by oil companies, you don't do science, or really really really want to believe in cornocopia.
The UK, if you were just looking at the linearization, you'd have thought you were well past Qt/2 and then been surprised by the second peak.  So you have to have some awareness of the discoveries in the pipeline.
Note that the UK by itself falls short of my 50 Gb limit, but the UK and Norway together have a Qt of 60 Gb.  FYI--I used crude + condensate for the Qt estimate.
And there is the second large mistake that Lynch is using. He looks at production curves of nations and concludes from that that nations do not have an neat gaussian production curve. Then Lynch states that oil production is influenced by politics more then by geolological restraints.

See this UK graph

But Lynch doesn't realise that by looking at nations he specificaly is looking at political units while large culsters of oilfields most often do not lie in a single political unit. If you look at production curves of the North Sea in total you come to the astonishing conclusion that even when the UK's production curve might not fit a gaussian curve, the Northsea's resembles it far more closely.

Iraq is another example of a "wierd" production curve which is influenced by politics. Yet the world production curve is driven by demand, so if one poltical unit fails to deliver another will come up with the difference.

By looking at the production curves of nations political influences on the world are wildly exaggerated.

That last sentence should have been:

By looking at the production curves of nations political influences on the world production is wildly exaggerated.


Good point.  

Perhaps ASPO should do analyses of geological regions, rather than analyzing individual countries a second time around.  

I've read through Lynch's papers and some online presentations that "debunk" peak oil. He's a believer in the magic of price, reserves additions, EOR technology--actually technology in general--and unconventional sources. What he consistently fails to notice is what is actually happening now on and under the ground. From this presentation Unconventional Oil: Filling in the Gap or Flooding the Market?. These are his "urban legends"
While I find myself in agreement with the last item, the others are all dubious for reasons that have been talked about time and time again here at TOD. Discoveries are inadequate and the easy oil is gone. This is admitted by IHS Energy and other mainstream analysts. This presumption is reflected in the behaviour of the IOCs. Just the other day, Dr. D. Nathan Meehan at said
Easy pickings are gone. Field studies that my colleagues and I have completed in the last few years are yielding somewhat different results as we reevaluate mature fields. We routinely integrate 3D seismic, integrated petrophysics, fracture and fault modeling, well testing, reservoir simulation, etc., to identify ways to increase recovery and production rates in mature fields. These studies are our bread and butter, and the forecasts we used to make generally had increased oil and gas rates in our look ahead, as we recommended additional drilling, pattern realignment, expanded flooding, etc.

More and more, our forecasts show only decreased decline rates and "dragging out the tail," as increasingly detailed analyses integrate real-time monitoring, intelligent wells and other advanced technology in place in the fields. The easy pickings are long past, and almost all of what once were marginal projects have been completed. We are helping not only independents, but majors and NOCs, pursue projects with ever-climbing costs per barrel and increased risks.
Shale oil in commercially producible amounts is decades away. Or, perhaps it is the oil of the future and will always be so. I suppose there could come a day--2040 or so--when shale oil with its very low EROEI could be cheaper than conventional oil if say it was only $754/barrel and conventionl oil was trading somewhat higher. He actually says (slide 23) that "SHALE OIL COULD BECOME IMPORTANT BY 2015". Shell, using their in-situ methods, would surprised to hear that. They are gearing up to build a prototype by 2012 as yet another step toward seeing if obtaining liquids in commercially viable amounts is a reality. Who knows how that will turn out.

And on and on. Has he been following the difficulties and rising costs in extracting liquids from Canadian tar sands? Is he aware that Canada's production (including these sands) is flat? Is he aware of what the deepwater reserves are in places like West Africa, what their anticipated production schedule is and reasonable assumptions about when this oil province will go into depeletion like the North Sea? I doubt it.

My feeling is that he's just out of touch with what's actually going on in the world.
In a way, the presentation you link to is very interesting from lynch.  It's completely focussed on unconventional possibilities, with "filling the gap" in the title.  It's almost like he is making a backhanded acknowledgement that the peak in conventional crude is close enough that it's time to start seriously ramping up the alternatives.
I heard Daniel Yergin on NPR a few months ago - I think it was here: - and even he is talking about the need for increased energy efficiency and conservation.  I felt it undercut his and CERA's main 2005 argument that we are about to see a glut of new, conventional oil coming on stream and that there is no near-term geologic peak.  My guess is that for his exit strategy he will soon be talking about how some of the various  "above-ground, geopolitical risks" mentioned in CERA's report are coming true.
Has to be awfully cold to freeze oil

According to above link, the 'pouring' point of oil is between -57C and 32C (-70F and 90F). Siberia probably not a good post-peak choice, unless you own the oil....;)

I think they're talking about refined oil, but I didn't bother to get a free trial and download it.  As they note farther below about the boiling points of crudes, the pour point for crudes varies considerably too, mostly depending on parafins content (thinking hard here).  In any case a lot can get very hard to handle around 0ºF and ususally pumps and pipelines will definately not run at max rates.  Crude can be anywhere from something cleaner than used motor oil all the way to a Venezuelan Heavy APIº9 that I worked with that I still to this day don't think was really oil at all (Conoco-Maraven VEHOP project to the Zapata Field) and had to be cut with around 40% naphtha for which  we had to build another ||pipeline to bring the naphtha to the oil field, mix it with the crude and then heat it all up to at least 170ºF before it could be pumped into the pipeline.  If I recall correctly, it had a cP of around 1300 at room temp but lowered to around 80-100 or so at 180ºF.
Got it wrong again.  Not that anybody other than me cares (actually not even me), but south Texas was the Zapata gas field; Venezuela was Zuata.  <Note: Must increase  Altzheimer dose.>
Count your blessings, at least it's not Waldheimer's.
I'm reminded of German accounts from the eastern front (Russia) during ww2.  They had to run vehicle engines every few hours to keep the oil in the engine from freezing solid, installed external electric heating blocks, and in some cases actually had to pour fuel on the engine and ignite it just to get the engine warm enough to turn over.  In short, extreme cold like that seen in Russia affects more than just the viscosity of crude oil, it can actually prevent pumps and motors from running.
Diesel is a lot like jello at -10C.  Put some olive oil in your freezer.  At about -8C you get olive drab ice cubes.  Just invented the Moscow Martini.
On the bright side, as long as there are people who listen to the likes of Lynch, there is money to be made off of them.
Russia is producing 200,000 barrels of oil a day less than it was last month.

Uh Oh......
Combine this with Nigeria's 200K loss and 1st quarter 2006 looks like lower prduction numbers than 4th 2005.
Freddy might have to change his prediction.

Add in  140,000 barrels of oil, 118,000 barrels of condensate and around 46 million cubic metres of natural gas per day, shut reported to be shut in  the Norwegian sector of the North Sea by gas leaks and storms. Also threatened is the Åsgard field, currently producing 74,000 barrels  of oil 130,000 barrels of condensate and natural gas liquids and 31 million cubic metres of natural gas per day.
...I am presuming that he is including NGL and other non-conventional sourced liquids in this.

Could someone tell me what exactly NGL (NatGasLiq) is? Is it a byproduct of the extraction of Oil and gas from the ground or something else? Is it considered a non-conventional liquid like oil derived from tar sands? It is obviously counted in the total of 85 million barrels and along with RPG's and "Other Liquids" make up by my calculations 13% of this total - but is it in fact GTL? Any advanced knowledge of this issue would be appreciated.

I lack advanced knowledge of this issue.........
but this might answer your question.

from wikipedia

Liquefied natural gas or LNG is natural gas that has been processed to remove impurities and heavy hydrocarbons and then condensed into a liquid at atmospheric pressure by cooling it to approximately -160 degrees Celsius. LNG is transported by specially designed vessels and stored in specially designed tanks. LNG is about 1/640th the volume of natural gas at standard temperature and pressure (STP), making it much more cost-efficient to transport over long distances where pipelines don't exist. Where moving natural gas by pipelines is not possible or economical, it can be transported by LNG vessels, where the most common tank types are membrane or moss.
oops.....   ;-0

dyslexia strikes again....

for what it's worth this is what Wikipedia has to say about NGL......


Natural gas liquids are the liquids that, combined with methane, form natural gas. The liquids consist of ethane, propane, butane, isobutane and natural gasoline These liquids are used as petrochemical feedstocks, home heating fuels and refinery blending.

Before most natural gas is marketed to a distributor or an end-user, it is processed to remove the natural gas liquids (NGLs), which usually have more value on their own than when left in the natural gas. The product that results after NGLs are removed, called plant residue gas, consist of methane, which is the natural gas used as heating and cooking fuel.

After NGLs are removed from natural gas, they are reprocessed in a unit called a fractionator to break them out for individual sale as propane, butane and other products.

Ok, well then if a chemical plant has a "flare up". Which can be seen for miles and miles at night! Especially with low cloud cover. And really looks cool in an odd sort of way at night out the window of an airplane at 35,000 ft. What gas or combination of gases is it? Is it really waste? Couldn't it be used for something?  
If its refinery you were looking at, they should only be flaring during an upset condition and the fuel could any combination of the number of burnable components (say 2 to 30 or even more) in their current feedstock.
Shouldn't an oil CEO already know all that?  ;-)

BP explains what NGLs is here.

Maybe I was just testing you :)

"Superficially, what he does seems simple enough: he ferrets out details from a variety of sources, fits them into patterns in his mind,and writes them up.  But that process requires unlimited patience, sound technical knowledge, an intense determination to avoid making mistakes, and a sense for the plausible in a world full of lies."

p.100 of this month's Atlantic Monthly. I won't tell you the author or the topic of this brilliant piece of journalism, completely relevant to the most popular discussion in this very forum for the last few days. I will say that these words are describing a man named Mark Hibbs. But what struck me was how much I felt they describe so many people here. And I want to thank you all for that.

And would the individual good enough to answer that question also explain what "condensate" is and how it differs from NGL?
Ya... I thought so too.

Condensate is the general term applied to the mixture of hydrocarbons coming from a gas well that are normally in the liquid phase at standard temperature and pressure.  They usually arrive with natural gas from deep underground at a high pressure and temperature at the well head and when they cool down (due to the Joule-Thompson effect) upon depressurization, the heavier hydrocarbons molecules generally condense out and form liquids that run along the bottom of the gathering pipeline until they are extracted at a ... gas liquid extraction plant.  There any carbon dioxide, nitrogen, hydrogen sulfide, etc can be removed and the heavier components can be seperated into propanes, butanes, pentanes, hexanes, heptanes, octanes, nonanes, decanes da.. da.. da, sometimes up to as many as 18-20 components or so, but normally a good number of places just put them all in the same bottle and sell it on to a speciality refiner or a consumer under the general title "gas liquids".  

Wanna' know what hydrates are?

Yes, please.
They're like "gas snow".  I learned of them because they also freeze and plug gathering  pipelines when the right temperature and pressures exist.  

Their MOST important aspect is that they might represent a significant previously UNKNOWN gas reserve, however not enough is yet known about their naturally occuring quantity and distribution to say for sure.

I lifted the following definition from,

"Gas Hydrate is an ice-like crystalline solid formed from a mixture of water and natural gas, usually methane. They occur in the pore spaces of sediments, and may form cements, nodes or layers."

sorry...  generally no difference (at least in my small mind) between condensate and NGL, except NGL is maybe the clean marketable version where all the heaviest components are removed.  LNG, not to be confussed with NGL, as LNG is CH4 methane, very cold and under pressure.   Oh, by the way, water can be a "condensate" too, but I think mostly just the HCs are typically included in the "definition".
Slightly off topic, but Sir John Browne seems very optimistic about the future of the North Sea:

Ladies and Gentlemen, if those conditions can be satisfied, then I believe the future of the North Sea - including the UKCS - can be very strong. As UKOOA has said, there is no reason, in terms of resources, why the United Kingdom shouldn't still be producing 2 million boe per day in 2020.
Continue reading The Future of the North Sea: a Perspective (via Policy Pete, another source on energy analysis worth visiting).
There is some evidence that optomists are very bad predicters but most folks can't stand listening to pessimists.
Personal experience:  The probability of getting paid X amount increases with the square of the number of optamistic words used in your reports, as does X.
Tom - that makes sense and is fascinating. Do you have a link?
BP Browne's optimistic about alot of things:

Ex #1- We can reduce 2Giga Tonnes of CO2 (the world produces over 8) by building 700 1GW  Nuke Plants and 700 coal fired plants.

Ex #2 The North Sea gas is falling by 8% per year now.  Gas drop off is sudden, no warning.

For some time I have been encouraging people to be very observant of energy events in the UK, and this past year has fit the pattern that I have been predicting. I believe the UK will be the first major industrialized country to face the permanent global oil crisis head on.

"Britain is reportedly to be importing liquified gas, for the first time in history as its North Sea oil reserve dwindles..." [2005 July 4 (Xinhua)]

"The North Sea is now at peak, with the UK being off 7% in 2000 and 16% off October to October, meaning that production is set to fall by one-half in ten years...." [2001 April (Peak Oil: a Turning for Mankind)]

 I believe we can say it's "Two minutes to Midnight" here in Europe...
Michael Lynch makes a classic mistake. He states something which might be true:

"There are a lot of zealots out there and a lot of claims are made which are not tested"

and concludes from that observation that all peakoil predictions can not be true. Obviously that is not a correct way of reasoning. For example, the existence of quacks doesn't say anything at all about the validity of medical science either..

Re:  Saudi Arabia (SA) & Other Exporters

With all the optimistic talk about SA's production possibilities, what I find interesting is that according to the EIA, SA has never produced more than 10 mbpd (using  the crude + condensate numbers).  Also, SA's production has basically been flat since June, 2004, while oil prices have exploded.  

Three of the four top exporters (SA; Russia; Norway & Iran) are past the 50% of Qt mark--all but Russia.  (I don't have a plot for Russia).  All four countries are showing virtually flat production year over year or declines.

A homerun baseball follows a ballistic trajectory.  It's vertical speed gradually slows as the ball approaches the top of its arc.  For a brief moment, the ball seems to defy gravity at the top of its arc.  But the ball inevitably starts a relentless downward trajectory.  

I believe that world oil production is at the top of the arc, right at the cusp of a permanent decline.  I think that we are going to see an incredible scramble for available net oil exports.

I see "50% of Qt" all the time on The Oil Drum.  For people like me that are not in the industry (or just ignorant), what is Qt?

I tried searching for it on this website...but only received references to it.  I found something about P5 plus P50 reserves.  But, that leads to the question...what is P5 and P50?

So, a nice simple definition would be great, if somebody would be so kind.

Maybe somebody could expand the FAQ to include definitions for the common abbreviations and math formulas that are used on The Oil Drum.

Thanks in advance,

Qt is a term used in Hubbert linearization.  It is where the line crosses the x-axis.  This represents the estimated ultimately recoverable amount of oil.  
"Chris Skrebowski believes that, from as early as 2007, the volumes of new oil production are likely to fall short of the combined need to replace lost capacity from depleting older fields"

from a long-winded PO story in the Guardian:

Sorry, meant to say "in the Independent"
I found that long article by Jeremy Leggett to be the best new article on PO I've seen in months.  It's actually a long excerpt from Jeremy Leggett's book.  One thing I like about this article is that it is careful NOT to rely on the "halfway" argument and its reliance on symmetry of the Hubbert curve - a detail that is quite inessential but has been latched on by likes of Michael Lynch to discredit the peakers.  And this despite the name of his book, "Half Gone".

I did find something in that article that I completely disagree with:
"The good news is that it will be possible to replace oil, gas and coal completely with a plentiful supply of renewable energy, and faster than most people think."

The text after that even explicitly states that by "replace" they mean for a world of 10 billion people, and at per capita power levels similar to current US level.  Not a chance!

His example of the town of Woking is probably based on natural gas (not renewable), plus PV panels (many years to return the energy investment), plus efficiency (insulation, CFLs, etc). Efficiency is great but can also be used with the Big Bad Grid.  I don't see why "private wires" are cheaper than grid ones.  The main advantage of the Woking mini-grid is the use of co-generation: the combined-heat-and-power units, since electricity-only generating stations waste 60% of the input energy as waste heat.  That can be done (and is widely done in Scandinavia) in several scales, from residential to town level, and can also be connected to the Grid.  Anyway, the claim that Woking "has cut carbon-dioxide emissions by fully 77 per cent" is not explained - what is counted?  Did they include transportation?  What about the energy for growing the food eaten in the town?  For manufacturing industrial products (including those PV panels) used in the town?  Seems to me like they only included direct energy for residential heating and electricity in the accounting.

I did find something in that article that I completely disagree with:
"The good news is that it will be possible to replace oil, gas and coal completely with a plentiful supply of renewable energy, and faster than most people think."

Precsely -- a pity that Jeremy Leggett loses so much credibility by taking a trip to fantasy land. He's Chief Executive of a UK-based alternative energy company called Solar Century, BTW.