Swimming in natural gas

By Jonathan Ratner
Financial Post
July 4, 2009

At a recent presentation to money managers in Canada's oil and gas heartland, the chief executive of a major Calgary-based energy trust used an interesting choice of words to describe natural gas. He referred to the commodity as a "wasted byproduct."

The suggestion that natural gas is worthless may be extreme, but it is an indication of the challenge the industry faces. Market experts continue to expect weak prices for natural gas as a surge in unconventional gas discoveries, such as shale plays, pour on to an already-flooded market. Add in unpredictable weather and a slower-than-forecast economic recovery, and the outlook doesn't get much brighter.

Canadian companies such as EnCana Corp., North America's largest natural gas producer, are trying to hedge production but investors might take a look at Australian players that are capitalizing on Chinese demand, or global majors such as Exxon Mobil Corp. and Royal Dutch Shell PLC, that are likely to come out ahead in the race to develop low-cost shale projects.

"We're going into one of those periods where this commodity has everything going against it," said Norman MacDonald, who manages the Trimark Canadian Resource Fund. "When you couple low-cost gas from the Middle East about to hit the shores of North America with some of these shale plays that have been emerging, it's kind of a worst-case scenario for the overall supply outlook and supply cost for natural gas."

While the stabilization of many global economies has sent oil prices higher, demand for natural gas has fallen off a cliff. The recession that closed factories and power plants has driven gas prices to roughly US$4 per MBTU, slightly above a six-year low of US$3.15 reached in April.

NYMEX natural gas futures spiked above US$15 at the end of 2005 after a busy storm season marked by Hurricane Katrina, but prices fell back sharply less than a year later. They rose again to nearly US$14 by the summer of 2008 as oil prices surged above US$140 per barrel, but have declined more than 70% since then.

Meanwhile, cargoes of excess liquefied natural gas (LNG) from offshore projects in Australia, Saudi Arabia and Qatar are heading for North America because it has storage capacity the other regions don't have. The Canaport LNG terminal in New Brunswick received its first cargo last week. It has the capacity to import one billion cubic feet per day of LNG.

"Storage is basically the buffer zone between demand and supply," said Martin King, vice-president of institutional research at First-Energy Capital Corp. in Calgary. "The storage levels in Western Canada and the U. S. are the highest ever for this time of year."

To top it off, Coloradobased Potential Gas Committee recently boosted its total potential U. S. gas supply estimate by 35% to 2,074 trillion cubic feet, the highest level in the gas supply authority's 44-year history, primarily due to the proliferation of unconventional shale gas plays. Shale gas, which is found locked in tightly layered rock formations, now accounts for 33% of recoverable U. S. natural gas.

The Haynesville, in the southern United States, and Marcellus, in the northeast United States, shales are considered the most economically viable resource plays in the United States, even at today's depressed prices. New horizontal drilling technology has also unlocked shale plays in Canada, in places like Horn River and the Montney in northeast British Columbia. While development and drilling of many of these deposits has slowed because of the price downturn, their cost structures, reserve sizes and amount of production continues to lure both companies and investors.

Some market observers say that natural gas has dropped so far it has nowhere to go but up. The reasoning is that the traditional pricing ratio between oil and gas appears to have completely broken down. The theoretical energy equivalent between the two commodities is a six to one ratio (six MMBTU of natural gas equates to one barrel of crude oil), but oil has appreciated so much that the ratio has surged to a 20-year high of almost 20 to one.

"As tempting as this straightforward conclusion would seem, we are unconvinced that natural gas will reconnect with oil anytime soon, given the relative lack of 'switchability' between the fuels and the insular nature of the U. S. gas market," said Shannon Nome, an analyst at Deutsche Bank.

While companies in Canada's natural gas sector move to diversify toward unconventional forms of production, many are opting to hedge their exposure to protect against weak prices. EnCana has entered into fixed price hedge contracts on about 35% of its anticipated production for the 2010 gas year, at an average price of US$6.21.

Most companies are hedging what they can with what appears to be a floor near US$5 or US$6, according to Subash Chandra, analyst at Jefferies & Co. But hedging is no panacea.

"All said, the industry can only hedge a small fraction of their ... enterprise value," he said in a note. "Also, the industry remains leveraged. So spending plans must be balanced against the need to reduce bank debt."

Birchcliff Energy Ltd., Vero Energy Inc. and Iteration Energy Ltd. are among the names that have recently tapped the market for equity financings. However, an industry watcher, who asked not to be identified, said the proceeds are not going into spending but rather paying down bank lines.

Meanwhile, U. S. shale assets will find their way into majors hands, predicted Mr. MacDonald of Invesco Trimark. "One thing they're good at is controlling the pace of development, which controls the supply of natural gas."

Recent acreage deals involving British Gas, Royal Dutch Shell and Exxon Mobil suggest the appetite for corporate acquisitions isn't far behind, Mr. MacDonald said. He also suggested they might not even have to pay very much given the debt situation faced by names such as Chesapeake Energy Corp., Petrohawk Energy Corp, and some companies in Western Canada.

"All you need is an unseasonably warm winter and these majors will be able to come in and name their prices," Mr. MacDonald said. "They're not going to be talking to the companies, they're going to be talking to the banks."

He also considers Australia an interesting opportunity, not so much because of the quality of deposits, but the pricing dynamic. "The northeast portion of the offshore Australian gas market is becoming as hot as Fort McMurray."

Australian gas had traded at a massive discount relative to global markets for a long time but has picked up dramatically because of the proximity to Asia for LNG export facilities. Mr. MacDonald considers Apache Corp. the best way to get some value out of the Australian gas market, while suggesting Calgary-based Enerflex Systems Income Fund as a way to take advantage of a secondary play on the market.

Not everyone is a pessimist on the outlook for the market.

Mr. King of FirstEnergy Capital expects supply to tighten in the United States because of the downturn in drilling that has been going on for almost a year now. Gas rigs now hover around the 690-level, marking a 57% peak-to-trough tumble in U. S. drilling activity since last fall.

He expects to see some stabilization of demand into 2010. So, if supply continues to come off, non-weather related demand improves and winter is cold, the big storage overhang may start to be unwound.

Those, however, are a lot of ducks to get in a row.

jratner@nationalpost.com

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