The Natural Gas Report for the week

Yesterday I was not all that cheerful about the omens foretelling the future of gasoline and crude in the near term. So today it is time to see what the latest in Natural Gas news is telling us, courtesy initially of the EIA.

This is the time where, as the Weekly Update noted, temperatures soar with the arrival of summer. With that comes increased power demands and increases in gas usage. However even the EIA is noting that so far the temperatures are more moderate than normal (they use data from NOAA), and this is impacting demand. Equally to the point the oversupply that came from the developments in the gas shales have yet to work their way through the system. Rig counts have dropped to 692 (picking up 7 from last week for the first increase in 29 weeks) from their peak last year of 1,606. Of the rigs in service some 391 are horizontal (counting both oil and natural gas), those most suitable to develop the shales. The result is that more natural gas is still being injected for storage, at a higher rate than normal, and bringing it significantly above the levels of both last year (632 Bcf more) and the 5-year average (482 Bcf more).

The industry also faces the potential for an increase in LNG shipments to the US. this year. Energy Trader, over at Seeking Alpha is currently very pessimistic about the situation, given the potential for LNG to be dumped into the United States as a world surplus develops this year. Prior to the development of the gas shales the world was looking at a situation where US supply would not be able to meet demand, and thus additional LNG capacity looked to be a very promising bet. Given the production from the shales, that bet is looking a lot less valuable and since the investments must still be paid off, deliveries to the US that undercut existing prices (given that shale gas is not that cheap to produce) may make this coming winter more of a buyers market than usual.

At the same time Alberta, with conventional gas deposits, is increasing the incentives to boost drilling for this gas, in the face of the gas shale developments.

The province will charge producers a flat rate of 5 percent during the first year of output from new wells, a government statement said. Drillers will also receive a royalty credit of C$200 ($172.64) for each meter (3.28 feet) of new well depth drilled.

The programs had been set to expire in March 2010, Energy Minister Mel Knight said in the statement. They will be extended to March 2011.

Companies including EnCana Corp., the nation’s biggest gas producer, are shutting wells amid a 70 percent decline in New York gas futures in the last year.

The question now becomes how quickly domestic production from the gas shales will decline, in light of their transient (about 2-year) life and the reduced drilling activity, and how much additional supply from LNG sources abroad will combat that decline. Within that puzzle lies the price that consumers are going to be paying for natural gas in the next couple of years. Opinions differ on what will occur. From the Calgary Herald

There are certainly positive signs that are driving the extreme contango in natural gas prices, when you look at winter contracts that are 50% higher than summer contracts. Commodity investors are looking at the collapse in U.S. rig activity which fell to 700 last week from 1600 last summer. They are betting on recovery in U.S. industrial activity. And they are looking at the disconnect between crude oil and natural gas futures.

However there are also signs that the commodity investors may be too early in their enthusiasm. Spot prices for natural gas (that’s the physical market) are well below the near-month futures prices, indicating that excess supply could continue to keep prices low for the rest of the storage injection season at the end of October. In Canada, spot prices are below C$3.00 per thousand cubic feet or US$1.00 per thousand cubic feet lower than U.S. spot prices.

On the other hand the Wall Street Journal sees the recent activity by Exxon Mobil, in starting three new LNG trains in Qatar, at a time when the world market is not capable of absorbing this increase (some 3 Bcf/day). The result:

So why would anyone ship LNG to the U.S.? In part, it's simple economics. Many projects were sanctioned and financed when lower natural-gas prices prevailed.

In Exxon's case, valuable liquids also produced in its Qatari projects take the market breakeven price of the natural gas itself "towards zero," says Deutsche Bank analyst Paul Sankey. Factoring in processing and shipping costs, that gas can be landed in the U.S. for less than $2 per million British thermal units, reckons Noel Tomnay, head of global gas at Wood Mackenzie. The current Nymex price is about $4.

Competing markets also look oversupplied. Wood Mackenzie estimates annual demand in Asia east of India will rise by 1.3 trillion cubic feet by 2015. New projects targeting the region and close to final investment decision amount to more than two trillion cubic feet of capacity.

In Europe, the prevalence of long-term pipeline contracts limits the size of the market up for grabs. Wood Mackenzie estimates about 4.9 trillion cubic feet of discretionary piped and liquefied natural gas per year will compete for a market half that size over the next three years.

Now Chesapeake has said that they can live with $4 (per kcf) natural gas prices but have shut in some 400 million cubic feet of production a day since April, in an attempt to stabilize prices. So far it is not working, at least to the level hoped (though it may be helping). As the EIA report notes the Henry Hub price has now dropped to $3.80. (And the greatest price drop in the country was at the Questar pipeline in Utah, where the price dropped to $2.50 – down 10%).

We will have to wait to see how this all plays out.