A propos Peter's LNG post today- here's something from CWEI IV board poster Manfredthedog. His comment followed by Reuter's 3/25 text.
LNG- a lot coming from Nigeria-soon, see-Cheniere Energy
The below LNG US potential supply, unless UK, etc outbids it, and it doesn't arrive, is going to make these Bcf/day Supply Numbers a lot bigger on Robry's current supply chart if you note the capacity numbers in the two LNG plants cited below- So what will the impact of this marginal increase be? A lot coming into the Henry Hub, and prices there may be softer than Rockies historical softness- Am I reading these numbers correctly? apples to apples? Rockies gas is definetly needed thru the new REX pipeline despite the LNG potential supply, as it is indeed a potential supply-this is a TEST ship from NIGERIA coming into Sabine Pass facility (The LNG tanker "Celestine River" departed from Nigeria this week carrying cool-down cargo for Cheniere Energy Inc.):
_____ 2005__2006__2007__2008___ 2005__2006__2007__2008__ 2005_2006_2007_2008__ 2005_2006_2007_2008
FREEPORT, Texas, March 25 (Reuters) - Freeport LNG import terminal hopes to receive its first liquefied natural gas cargo by the end of April and be commercially open for business by June 1, officials told a kickoff briefing Tuesday.
The $1-billion project, which will have the capacity to send out 1.5 billion cubic feet of natural gas per day when operational, would be the first new onshore U.S. LNG import terminal opened in more than 25 years. "It's very satisfying," Charles Reimer, president of Freeport LNG Development LP, told a briefing to prepare the news media for the event.
Another terminal, 90 miles northeast near Port Arthur, also is very near completion and running a close race with Freeport for startup.The $1.5-billion, 2.6 Bcf per day Sabine Pass LNG terminal expects its first cargo in the next few weeks and plans commercial startup before June 30. Its kickoff briefing and tour is scheduled for April 21.
When finished, the two will lead a parade of terminal startups that will double U.S. LNG import capacity in about 18 months. Opening of Sabine, Freeport and three other terminals will raise U.S. import capacity from about 6 Bcfd to 13 Bcfd. (my NOTE=this is capacity and of course subject to competing demand from several other places-note that UK shortage problem mentioned in another post-and see the Michael Smith quote below)
From The Australian:
May 01, 2008
CONSUMERS of liquefied natural gas are today more willing to pay as much as they would for oil to use the cleaner energy source, according to Woodside Petroleum.
"Buyers are increasingly prepared to pay prices for LNG which are close to oil-price equivalent," despite huge jumps in oil prices, Woodside Petroleum (ASX: WPL: quote) chairman Michael Chaney said.
LNG - gas that has been cooled to liquid for transport in ships - has previously been supplied at a cheaper rate than oil, but demand is surging as energy use grows and countries seek cleaner forms of energy than oil and coal.
Woodside Petroleum chief executive Don Voelte said he had signalled a portfolio review in light of the growing global demand for LNG.
from UPL board- UBS nat gas report- PARK
What Has Changed in the US Gas Market?
Raising normalized natural gas price forecast to $9.00 from $7.25
We are raising our normalized natural gas price to $9/MMBtu from $7.25/MMBtu
as a confluence of factors throughout the global energy supply chain exert upward
pressure on longer term prices. We have increased our NAVs and price targets by
15% & 13% on average.
Why are we changing our forecast?
We expect prices to be more volatile going forward as the market has evolved from
a North American-centric commodity dominated by domestic supply and demand
trends to one being pulled by global forces. Specifically, we expect much higher
global LNG prices, underlying support from rising coal prices, improved industrial
demand, and higher electricity demand/prices to pull US gas prices higher, offset
partly by stronger US production growth from emerging unconventional resources.
Despite the big move, E&P sector is still attractively valued
While the group feels extended over the short term, we believe the sector is
discounting long term prices of $7.55/MMBtu and $73/Bbl. These are 32% and
35% discounts to the 12-month futures curves, steeper than the traditional 22%
discount the sector has reflected over the last five years. We see 10% additional
downside risk with a continued correction and 30% upside to fair value.
Valuation: E&Ps discounting $7.55/MMBtu & offer 30% upside to PTs
We favor resource-rich companies with above average production per debtadjusted
share growth. Our top picks are APA, COG, HK, SWN, UPL, and XTO.
Valuations Assuming a Range of Normalized NYMEX Natural Gas Price Scenarios
We continue to see solid global energy demand growth and a confluence of supply
constraints throughout the energy chain: anemic crude production, limited LNG
liquefaction capacity, struggling coal output, and declining electric generation
reserve margins. While historical analysis of E&P stocks and U.S. natural gas
prices in particular centered on domestic production, imports, and demand, the
global constraints in LNG, electric generation, and coal should have an increasing
impact on US natural gas going forward with an upward bias.
Given the increasing number of factors impacting US natural gas prices, we expect
increased volatility going forward. In fact, we believe the new range for natural gas
prices could be as wide as $7-14/MMBtu. For now, we are raising our single-point
normalized natural gas price to $9/MMBtu from $7.25/MMBtu given prices
necessary to generate adequate US production growth, expectations of robust gasfired
power demand, and the need to have higher prices to stimulate LNG imports
in the face of robust international demand. We believe we are in the middle of a
brief correction in E&P stocks (down 5% from the peak with 5-10% additional
downside risk) and would use the weakness as a buying opportunity as we see
upside potential of 30% to our price targets. We continue to have Buy ratings
across most of our coverage universe but highlight the following stocks as our top
picks: Cabot Oil & Gas, Petrohawk, Southwestern Energy, Ultra Petroleum, and
More about Khurais:
Production will be increased by bringing 2.4 M bpd of seawater from about 120 miles away (another article claims 4.5 M bpd). The Persian Gulf water is more salty than normal sea water and has a lot of very fine polished sand that must be filtered out to avoid clogging the oil formation. 125 water injection wells will be used and production will be from horizontal wells. The permeability of the giant field is very variable (100 mD to 5 mD)
All, The "New" Saudi field is the Khurais complex.
Some of its history: So far, the giant field that couldn´t.
Discovered in 1957. Low production started in 1959 and ended in 1961. Production started again in the early 1970s and produced between 20 K and 40 K b/d until the end of the 70s from about 80 wells. In 1980 production was 68 K b/d which increased to 144 K b/d in 1981. In 1983 gas inreinjection wells were drilled (72 in the complex). Results were mixed.
In 2001 a study team tested 57 wells and cored another 29 wells to help understand the production problems. Development plans for Kurais were shelved. In 2005 a predicted production of 800 K b/d was announced for, perhaps, 2008. Unnamed sources predicted 1.2 M b/d.
Ref: Twilight in the Desert, by Matthew R. Simmons
It will be interesting to learn if they build a water pipeline to the field for water injection or use some other method to increase production.
All, thanks. Front page WSJ, Saudi field coming on next year, cost now is $40k for each daily barrel of production vs $16k in 90s. Vinod Khosla on CNBC interview sees new technology, cellulosic ethanol, driving oil to $35 pb in a couple of decades. Know he talking his book. Also, Ken Heebner, who seems to have the Midas touch for being in the right sectors the past few years, sees US stock market as an opportunity, compares it to 1982. He sees global growth as the opportunity.
6:1 isn't really an argument but rather something close to the point where a rational user of either product who could use either would chose one over the other based on price if the ratio were not at that point. I think that given the increasing internationalization of natural gas markets we might see very different ability to fuel switch over time. As Hugh notes, the increases from natural gas liquids and refinery gains have probably been the answer. This isn't surprising in a way because at the beginning of this millenium world oil resources could probably been described as over-exploited while, on a comparative basis, world natural gas resources could have been described as under-exploited.
Yesterday, one of our bell weather's, LNG, reported the laying off of half of their employees and the stock is down a further 40% this AM:
That link speaks volumes, I think, about what we might expect to see for LNG imports this year.
Simmons gives the 2006 data as 43,530,000 b/d of black crude, 7,795,000 b/d of NG liquids, and 3,272,000 b/d as refinery gains and "other". He claims that global black crude production peaked almost 3 years ago.
Peter, the 6 to 1 argument has been around a long time and in the past and was never realized, my rule of thumb was 10 to 1, admittedly not very scientific, seemed like a reasonable relationship, consistent with your analysis. And you never know, maybe oil will correct to reduce the ratio. This brings up a question, the 5 mbod of gas liquids in the global supply numbers. Haven't researched it, but has that number been fairly stable over the past few years and could that have an impact on supply in the future. Today, I'm not uneasy about low pricing but the prospect of runaway pricing, in the intermediate term, if demand keeps growing and the national oil interests see urgency to expand supply. The other factors make it difficult on their own to increase supply.
HIstory tells us that an actual catalyst is required probably because so much of our annual requirements are provided by domestic sources which are not only the biggest part of the stream but are also growing although they also may have plateaued temporarily, as has the rig count. Gh asked about 2 months ago: "Why did we spend so much time talking about storage, anyway?" The answer is that storage matters. From the period of Kat-Rita to last summer natural gas pricing fluctuated wildly but it didn't advance any to speak of. Why, because storage was always ample after the immediate effects of Kat-Rita were felt.
What's different now? It is a trifle too early to be sure but we'll know in a few months. What is different is that we appear to be significantly on our own in terms of meeting our natural gas needs and, therefore, natural gas pricing may swing wildly the other way in the event of any difficulty with US supply. Let us say, for example, that we have difficulty storing natural gas to "full" this year--new full 3.45 Tcf and oil is still priced at $110. My guess would be that NG could trade as high as $18 in the winter. But, ah, you'd say, demand destruction would set in. Yes, it would and to a degree but it wouldn't to the degree that it once could because there is much less fall-back on cheap international natural gas because much international natural gas is actually more expensive elsewhere. Taking the above assumptions and throwing a colder than normal winter at it drawing storage down to, say, 1 Tcf and my bet would be that we'd see $25 natural gas pricing. For an earlier bigger price scenario think of a Cat 3 that took out 300 Bcf of GOM production. That would do it, too.
Downside? A cooler than normal summer, no shut in and a return of LNG imports (that's why you watch LNG and use it as a bell-weather or watch Robry's LNG import report (which is still showing next to bupkiss on imports). Other than some combination of the above, it is becoming harder and harder to see how natural gas pricing returns to the pattern of '07-'07.