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Pressure piles on North American gas producers

North American natural gas producers may face a summer of mergers, takeovers and asset sales as futures prices continue to plumb decade lows, potentially forcing a major realignment of the continent’s gas sector

On 11 April, the New York Mercantile Exchange (NYMEX) front month contract shattered a key psychological threshold, closing below $2/million British thermal units for the first time since January 2002.

Spring is traditionally a seasonal low period, and it all but guarantees prices will fall further until summer cooling demand kicks in. But even an extraordinarily hot summer would barely put a dent in bulging US storage inventories, which are on pace to hit all-time highs by fall.

According to the most recent Energy Information Administration numbers, Lower 48 inventories rose 8 billion cubic feet (cf) for the week ended 6 April, and are 56% higher than the same time last year and 58% higher than the five-year average. At that rate, supplies are on track to surpass the maximum theoretical storage limit (nobody knows exactly what the actual limit is) of 4 trillion cf by September.

It’s a body blow for gas producers who find their credit lines threatened and balance sheets under attack, especially those with exposure to large dry-gas plays, such as Horn River in Canada and Haynesville in Louisiana. Bank lines are backed by the value of reserves, which have plummeted as gas prices have dropped more than 30% since the start of the year.

Now it’s a race to the bottom, and all but the supermajors are at risk of takeover as a fundamental restructuring of the North American gas market appears inevitable. Those companies which survive will play a central role in how the market adapts.

We already know some of the big names: ExxonMobil, Shell and Chevron are starting to make moves to consolidate their existing holdings. But the real struggle is among the US and Canadian independents, which are frantically taking steps to raise funding for capital programmes.

Up to now, that money has come from offshore sources, from China and Japan, for example. But now US equity funds are starting to move in, snapping up prime properties at rock bottom prices.

Creative financing from private funds

This month, Oklahoma-based Chesapeake Energy completed three separate deals worth $2.6bn in cash. The first, with an investment group led by an affiliate of the Blackstone Group, involved preferred shares and a 3.5% production royalty worth $1.25bn covering 245,000 net acres of unconventional liquids-rich tight sand plays in Oklahoma. The second was a “volumetric production purchase”, in which an affiliate of Morgan Stanley agreed to buy future production and reserves from Chesapeake for $745m, or approximately $4.68 per thousand cubic feet equivalent (cfe). The deal included 160 billion cfe of proved reserves and current production of 125m cubic feet a day (cf/d).

Since December 2007, Chesapeake has sold 1.37 trillion cfe of proved reserves for combined proceeds of $6.4bn under similar volumetric agreements.

Likewise, on 9 April, a coalition of equity funds announced the formation of Houston-based Exaro Energy, a funding vehicle dressed up as an exploration and production company to acquire an earning interest in Calgary-based Encana’s Jonah field in Wyoming.

The total value of the deal, after an initial investment of $182m and subsequent capital commitments, amounts to $380m. Exaro is hoping to assume about 33% of Encana’s Jonah interest, which is presently producing about 500m cf/d.

The investors behind Exaro include New York-based Jefferies Capital Partners, which has about $850m under management. Private equity funds tend to take a longer-term view than stock market investors, and will stay on the sidelines if they don’t think the timing is right. For companies like Encana and Chesapeake, it is an incremental step to closing budget gaps made worse by low gas prices.

On 2 April, Encana said it was looking for partners to accelerate development of 1m acres in the Tuscaloosa Marine Shales in Mississippi and Louisiana; Michigan’s Utica/Collingwood; the Eaglebine play in east Texas; and the Mississippian Lime in Oklahoma and Kansas.

That will take more money than it is making in dry gas plays such as the Haynesville in Louisiana and the Horn River in northern Canada.

Although it is not a supermajor, Encana is North America’s third-largest gas producer after ExxonMobil and Chesapeake, and, like Chesapeake, it has assets it can liquidate to raise cash and keep its drill bits spinning.

However, both companies have seen their shares fall in tandem with natural gas prices and are trading near-record lows. On 11 April, Chesapeake lost 3% on the New York Stock Exchange (NYSE) to hit a new 52-week low of $20.03, down from $35.75 last August. Likewise, Encana’s New York-listed shares finished at $17.96, slightly above its all-time low of $17.02.

In contrast, ExxonMobil is thriving – its shares are near its 2008 peak, hovering at $82.70. But ExxonMobil is an integrated company and can afford to sit on its North American gas. It also has the luxury of considering liquefied natural gas, chemicals or any number of other options for processing its gas production.

It is also in a position to take aim at its competitors. And if the gas price continues to fall, that day may come sooner than later.

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