It's In The Wind

Hurricane Katrina may have broken hearts in the US south, but this terrible event adds even more value to Woodside’s acquisition in the Gulf of Mexico. Gryphon Exploration is a gas producer with 15 wells in production and six under development; it is small by Woodside's standards, but its wells are worth far more than they were just one week ago.

Gas prices were already soaring before Katrina swept across America’s largest energy hub. In the eight months to mid-August, the gas price had climbed by 80% to $9 per 1000 cubic feet. Since Katrina hit, the price has risen further, to $11.50.

This was not the way it was supposed to be. The chart below from the Federal Reserve Board of Texas is typical of price projections in recent years. Fully aware of rapid depletion of Gulf gas fields many experts, if not most, forecast steady prices, admittedly above the $2–3 levels of the 1990s, but nevertheless bobbing along steadily at $5–5.50.

The two $10 spikes shown above were regarded as aberrations. The first, in the northern winter of 2000, was due to unusual weather conditions: a drought in the south-west, which sharply reduced water available to generate hydro electricity; and cold weather in the northern states, lifting demand for heating energy. This combined with a rising oil price due to tensions in the Middle East and so a swing away from oil. The second spike was caused by almost the same set of factors: rising oil prices, a cold snap and rising gas demand; but this time supply entered the scene. New fields disappointed. Initial volumes had been high, but rapid depletion followed, inventories fell and gas spiked once again to $10.

Strangely, US energy consultants remained upbeat, predicting prices of $5–5.50. They said the market would keep an even balance as new recovery techniques, “frontier” gas and imports would make up for the gradual depletion of domestic gas fields and meet rising demand.

In retrospect, the optimism of these forecasts is difficult to fathom. By 2003, there was already a widening gap of 3-4 trillion cubic feet between rising US demand and homeland output. Gas from Canada and the Caribbean made up the difference, but the “just-in-time” attitude of the oil industry did not seem to make enough allowance for the age of both US and Canadian gas fields. The Alberta fields, which produce 80% of Canadian gas, have been hard at work since the 1920s. They require about 10,000 wells a year just to maintain production '” not even steady '” in graceful decline.

The US Department of Energy says Canada’s reserves of conventional gas are also exceptionally low, with just 8–9 years remaining. This may be far too conservative a figure and not make sufficient allowance for remote discoveries, plus “probable” and “possible” gas outside the great Western Sedimentary Basin, but given the realities of depletion and extremities of the climate, anyone relying on Canadian gas might be wise to err on the side of caution.

There are also strong expectations about "unconventional" coal bed gas of which Canada, like Australia, has a vast endowment, but sheer geological volumes are quite different from economic extraction. Specialised drilling is required; there are often water problems, it is more intensive; the coal measures might not lie evenly, etc. Gathering the gas is the next issue, treating it and pipinng it over frozen landscapes another. Timing is a big issue: there are big gas deposits to the north, on the Arctic Circle, but they will not be linked to the United States for four or five years. On the east coast, two big pools will come into production soon but a more remote and challenging an area than Labrador would be hard to find.

Compounding these supply questions is output from traditional basins in Louisiana, Texas and Oklahoma: they have all been highly productive for years, but are in depletion. Oklahoma peaked in 1993 and is now down about 25%. All three will fall a further 18–20% over the next five years. This places a big burden on “frontier” discoveries, work-overs and imports. Even assuming a massive burst of drilling in both countries it is a big ask. One consultancy, Energy & Environment, believes “frontier” gas will provide 30% of the markets by 2010; it now supplies just 13%.

This approach to energy policy is based on the belief that “demand automatically produces supply”. It is valid up to a point '” there is certainly a drilling rush on '” but just as oils ain’t oils, not all gas is sweet, free-flowing or well located. This supplementary “frontier gas” is to come from deep offshore drilling; “fraccing” of tight rock formations; high altitude recoveries in the Rockies; distant, still unconnected Alaskan gas; or even more distant gas in Eastern Siberia, Qatar or Australia. That’s also fine, but shipped gas requires expensive receiving terminals. As BHP has just discovered, the citizens of California are not keen on having LNG terminals in their back yard. Then there’s politics. Venezuela has gas, but President Chavez is just a mite irked that the Reverend Pat Robertson is publicly advocating his removal from this sinful world.

Assuming “frontier” gas does arrive without a hitch, what will it cost? Australia has just congratulated itself on securing a 70% increase in the iron ore price. Steel for rigs and pipelines are more expensive than a year ago. The oil price has also gone up, making exploration and pipe-laying more expensive. Drilling rigs and geologists are in short supply, etc. It turns out that everything is connected to everything else. A month ago Shell announced that the budgeted cost of its big Sakhalin Island gas project had doubled, from $10 to $20 billion.

Oil itself is perhaps the biggest problem for gas. Six or seven years ago, before US gas prices started to show troubling tendencies, industry could always switch to oil. Many companies had dual-fuel boilers. Energy companies did quite a business sharing the cost savings of the switch. But these dual-fuel boilers have been phased out. Oil grew too expensive. It was dirty and less convenient than always-on-tap gas. Power companies, and, to a degree, householders did the same. Fuel oil was polluting and increasingly expensive: gas was the way to go. With nuclear energy politically off-limits, gas had no enemies. Coal still does the heavy lifting in US power generation, but gas-fired peak power stations have the great advantage of being acceptable politically, and from a profit perspective are highly flexible in meeting short periods of peak demand.

As a result, consumption growth came from power and household use, rather than just industrial expansion. US houses are much larger than they once were, requiring more energy to heat and cool; about 60% of households relied on gas to survive the the cold northern winter. On top of that are the gadgets, all of which require energy: wide-screen TVs, battery chargers, more internet users and more servers to host all the on-line shoppers and poker players.

So we return to the current situation. Gas rose steadily during 2004 to $6.50–6.90 and settled at $8 by March this year. Then came summer. Even before the hurricane season started in earnest, the signs looked ominous. Sweltering conditions settled on the southern states in August; air conditioners were turned up full and power companies called on more gas, some of which would have been injected in underground reservoirs in preparation for the northern winter. Prices spiked to $9 and southern mayors tried to sooth testy residents. They didn’t have good news: at a meeting only last week, a representative from the power authority Tennergy told municipal officials that the gas price would climb for “at least the next three or four years”.

That was three days before Katrina. An already tight situation has become ugly. The $10 spike level now looks cheap.

For Woodside, this was impeccable timing. Not only does Gryphon Exploration, bring 30mcf of production '” which may soon double '” the hand-shakes on the deal would have been done well before the announcement, when Gryphon’s reserves were at least $2–3 cheaper than they are right now. Even when the price subsides, Woodside’s Gulf gas will still be at least four times the price back home. The deal also brings local expertise. The Gulf of Mexico is highly gas-prone, but success there is not just the result of clever geology, it also relies on local knowledge about pending releases of blocks and keeping an ear to the general industry gossip.

This sort of know-how is invaluable and partly explains the success of Petsec, the only other Aussie gas producer in the Gulf. Petsec’s chief executive, Terry Fern, has more than a decade of experience drilling for either oil or gas, and once he changed tack to a strategy of avoiding high-risk plays and took to drilling for smaller gas pools in shallow waters, reserves and income took off. The new price level also helps. Gas sands found at $5.50–7 can now be sold at perhaps 30–40% minus royalties and taxes. Costs will be up, but as Petsec reported operating costs of just over $1 per unit of gas last year, the new margin offers a lot of room for mistakes.

Petsec’s near-perfect record is unlikely to remain unblemished, however. Katrina went nowhere near its producing platforms, but there will be more Katrinas and, by the look of it, chaos for months. The risks of the Gulf generally will need to be calibrated. Storm frequency may not rise, but the intensity almost certainly is greater. This gives even the onshore plays like Petsec’s up-coming Moonshine a heightened level of risk. Given Fern's geological acumen, it may be another winner, but as Moonshine is just 65 kilometres from flooded New Orleans, it’s clear why geologists know for sure that Murphy worked in the oil industry.

Disclaimer: The writer holds interests in Woodside and Petsec