|To: Ed Ajootian who started this subject||2/27/2004 6:00:53 AM|
|From: Ed Ajootian|
Prices are based on delivery to National Balancing Point,
within Transco's transmission system.
Quotes for specific dates are settlement prices.
Week's High/Low reflects intra-day trading.
Above are UK gas futures, wrt ATPG.
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|To: Ed Ajootian who wrote (94)||3/4/2004 12:12:53 AM|
|Hi Ed: Thanks for the feedback. FXEN has dropped back but I view it as a healthy correction. I'm in this one for 3-5 years and believe that under Hartman's competent guidance, this company will do phenomenally well. Time will tell.|
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|From: Ed Ajootian||3/21/2007 4:58:09 AM|
|Alcan May Buy Gas From Rift Oil for Australian Plant |
By Angela Macdonald-Smith
March 21 (Bloomberg) -- Alcan Inc. signed an initial accord with Rift Oil Plc that may result in the world's second-biggest aluminum producer buying natural gas from a field in Papua New Guinea for an alumina refinery in the far north of Australia.
The company needs 40 billion cubic feet a year of gas for 20 years for the Gove plant and London-based Rift still needs to prove the Douglas field is big enough, Stefano Bertolli, an Alcan spokesman in Brisbane, said today. Rift's Douglas field is one of several potential supply options being considered, he said.
An agreement Alcan had earlier to buy gas for Gove from Exxon Mobil Corp.'s proposed $5.5 billion project to pipe gas from Papua New Guinea to eastern Australia lapsed late last year after the group that was to build the line decided the project was uneconomic. That prompted Alcan to study alternative options, including coal-seam methane and liquefied natural gas.
``We signed a non-binding MOU with Rift and they're going to explore to see if there are enough reserves there, and if there are then we're going to have to see how it moves forward,'' Bertolli said in a telephone interview. ``There are many options on the table and this is one of them.''
Last October Alcan agreed to start studying a gas-to-liquids project with Arrow Energy NL that would use coal seam gas from Brisbane-based Arrow's fields in Queensland. The study was to study gas-to-liquids against other options available for energy supply to Alcan's Australian operations.
Arrow said earlier this month the initial studies showed a plant costing about A$1 billion ($802 million) and producing about 20,000 barrels a day of diesel, naphtha and liquefied petroleum gas may be economic.
Should a final agreement be reached with Rift, it would require the construction of a $1 billion pipeline to take gas from the Douglas field in Papua New Guinea's Western Province to Gove in the Northern Territory, the Australian said today, citing Ian Gowrie-Smith, chairman of Rift Oil. The pipeline would be shorter and cheaper than Exxon's proposed line as it may only supply Gove, the newspaper said.
Alcan, based in Montreal, isn't considering investing in the pipeline at this stage, Bertolli said. The company is spending $2.3 billion on expanding the Gove refinery and wants to switch fuel supply at the site to gas from fuel oil because it's more economic.
Rift will explore at Douglas over the next 12 months to see if there are enough reserves and the companies will then decide whether to seek a final gas sales agreement, with the possibility of gas deliveries starting in 2010 or 2011, Bertolli said.
Rift's Foreland Oil Ltd. unit owns 65 percent of the PPL 235 exploration permit in Papua New Guinea, which holds the Douglas-1 and Langia-1 gas discoveries, which may also contain condensates, Rift said in a March 20 statement on the initial accord with Alcan. New Zealand's Austral Pacific Energy Ltd. owns the rest of the permit.
Planned work in the permit ``is expected to be completed by mid-2008 and aims to provide sufficient information for the parties to proceed to a binding agreement to supply natural gas to Gove,'' Rift said in the Regulatory News Service statement.
Wellington-based Austral said in July the Douglas field may hold ``several hundred billion cubic feet'' of gas across an area of 40 square kilometers.
Rift and Austral are also equal partners in an adjacent permit, PPL 261, which lies within about 100 kilometers (62 miles) of the Juha and Hides gas fields and the Moran, Mananda and Kutubu oil fields.
To contact the reporter on this story: Angela Macdonald-Smith in Sydney at firstname.lastname@example.org .
Last Updated: March 21, 2007 01:48 EDT
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|From: Ed Ajootian||1/4/2008 12:07:11 PM|
|UK energy prices rise in 2007, drive retail tariff rise |
Wholesale gas and power prices in the UK have risen steadily during the
12 months since the round of retail price cuts in early 2007, an analysis of
Platts' data shows. UK utilities have pointed to rising wholesale prices as
the basis for a new round of retail price tariff hikes.
UK utility RWE Npower said Friday it would announce retail price rises
later in the day, and its fellow utility Centrica said in its trading update
in December that rising wholesale prices had squeezed margins. If high
wholesale prices continued, they would "create a more difficult environment"
in 2008, Centrica said, adding: "We will continue to monitor this with regard
to future pricing policy."
The last round of domestic price changes from UK utilities began at the
end of 2006, when Centrica announced the first price cut after several years
of price rises. Scottish and Southern followed in January, with other
utilities promising price matching or special cheaper tariffs.
Last winter UK gas and power prices had been falling steadily for several
months, partly because of two new major pipelines bringing gas from Norway and
the Netherlands. In addition to the extra supply, the UK experienced an
extremely mild winter season, lowering demand and hence price.
At the start of 2006 prompt gas prices had spiked in response to supply
problems, with day-ahead reaching as high as 187.5 pence/therm in March 2006,
and the front month contract above 100 p/th at points during the winter.
But with the new supplies online at the end of 2006, and low demand, gas
prices plummeted. Day-ahead traded below 30 p/th for almost the whole of
the first quarter of 2007. Similarly, the month-ahead contract fell steadily
from above 50 p/th at the start of winter 2006 to under 30 p/th in January
2007, usually a peak period.
UK power prices tend to track UK gas prices because the marginal power
generation supply in the country is largely gas-fired. So with gas prices
fairly low, power prices followed. And that improved utilities' margins
significantly, creating a strong rationale for price cuts.
During the course of 2007, however, the bearish wholesale trend reversed.
To some extent this was due to a rising oil price. At the start of 2007 the
dated Brent crude oil contract was at just above $50/barrel. But by July it
was up to $77/b, and on the first trading day of 2008 it hit $100/b for the
first time ever.
Gas contracts on the Continent tend to be indexed to oil products, with a
six-month delay. So the steady rise in the oil price caused a steady rise in
European gas prices over the course of the year from July onwards. With
European gas prices rising, producers could choose to send gas to the
continent in preference to the UK, so UK gas prices also rose.
Compounding matters, there were several incidents of North Sea
infrastructure problems, including the extended outage at BP's CATS pipeline.
The weather was also an important factor with the UK experiencing a fairly
mild summer and then a rash of colder-than-normal weeks towards the end of the
year, raising demand.
In July, the UK gas day-ahead price stuck close to the 30 p/th mark, up
from the sub-20 p/th level seen in April despite the summer's traditionally
lower demand. As the year wore on and the market entered the higher demand
winter period, prompt prices rose further and day-ahead traded above 50 p/th
for much of November and December, almost double the level seen in early 2007.
By the start of 2008, infrastructure problems, higher demand than
expected and the rising oil price had combined to raise market expectations of
future prices. The winter 07 contract had closed in September at 43.75 p/th.
But January 3, the winter 08 gas contract was 50% higher than this, at 61.6
On the power side, as well as the rising gas price pushing up power
prices, nuclear plant problems added extra bullish spice. Four of British
Energy's nuclear power units, two at Hartlepool and two at its Heysham-1
plant, have been out of action since October 22 after the generator found a
wiring problem at Hartlepool-1. All the units have a similar design, and
therefore the three other units have been kept offline for further checks.
The four units together generate 2,360 MW of power and they are usually
run on a constant baseload shape, since marginal costs are relatively low
compared to gas and coal plants.
Traders said the nuclear outages brought up prompt power prices as well
as forward prices for November and December 2007, a period when demand
increases due to the colder winter weather. The average daily baseload power
price in November 2007 was GBP44/MWh, 57% higher than November 2006. In
December 2007, day-ahead power was 39% more expensive year-on-year, at an
average of GBP51/MWh.
Finally, in addition to other factors, the start of 2008 saw the onset of
the second phase of the EU's Emissions Trading Scheme. Phase 1 was
oversupplied with carbon certificates, leading to an EUA price of under 10
euro cent equivalent to 1 mt of CO2. But Phase 2 is widely expected to be
short and the current December 2008 EUA price is Eur23.50/mt CO2e. That makes
generating power using fossil fuels such as coal and gas more expensive, hence
raising power prices further.
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|To: Celtictrader who wrote (102)||4/11/2009 11:42:48 AM|
|Maybe Not,just found this article!|
Natural gas prices tumble almost 75%
COLUMBUS - The 60 million American homes that rely on natural gas for heat can expect substantially lower bills next winter, thanks to a glut in supply and the weak economy.
Just as distributors start to lock in contracts for the coming winter, natural gas prices have fallen almost 75 percent. Not all of that will show up as savings on heating bills, but it should mean noticeable savings.
New technology this decade has unlocked massive reserves of natural gas in North America, and the sudden jump in supply has collided with a recession, the worst since World War II, that has sapped demand.
The result has been a collapse even more dramatic than the drop in oil prices.
Natural gas futures ended this week at $3.61 per 1,000 cubic feet, down from a July peak of $13.69. That's a decline of 74 percent, compared with a decline of 64 percent in oil prices over the same period.
Households have yet to see those huge drops reflected in their heating bills because the companies that buy and distribute natural gas in bulk are still passing on the premium prices they paid last summer.
But lower rates are almost certainly coming. Distributors already are signing contracts for next winter that lock in today's low rates.
A 75 percent decline in the price of natural gas does not mean the heating bill will decline by that much. On average, the price of gas makes up about two-thirds of the bill with transportation, taxes, and other expenses covering the remaining costs. Americans spent about $60 billion on natural gas for heat this past winter.
Distributors don't profit from the price of gas. They typically make money from getting the gas to your home. If they want to charge more, they need approval of state regulators.
In some places, natural gas bills are already way down. The average bill this month for customers of Columbia Gas of Ohio will be $101.54, the lowest in five years and down 26 percent from a year ago.
The government's Energy Information Association says the volume of gas in storage around the country, a staggering 1.67 trillion cubic feet, is 35 percent more than it was last year.
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