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Providing coverage of Alaska and northern Canada's oil and gas industry
June 2006

Vol. 11, No. 25 Week of June 18, 2006

Gas overhang a threat, says NEB

Canada’s National Energy Board sees storage space running out by late summer, pushing prices down, triggering possible shut-ins

Gary Park

For Petroleum News

Canadian natural gas producers may be forced to scale back production by late summer if North American storage space reaches capacity for the first time, driving down commodity prices, said the National Energy Board.

In its inaugural summer outlook, the federal regulator said refilling storage facilities is one month ahead of schedule and, unless that pace changes, the “overhang” could drive prices to US$5 per million British thermal units — the lowest point since September 2004 and 16 percent below current futures prices.

Even worse is a growing sense of gloom among some Canadian analysts that junior producers carrying high levels of debt could be pushed over the brink if their capital spending outpaces their cash flow after a year of watching record levels of activity drive up the costs of drilling and other services by 50 percent.

Typical of those starting to feel the squeeze is Berens Energy, whose bankers have hiked an operating facility to C$57 million from C$45 million while the company has cut its 2006 budget to C$51 million from C$71 million.

Their best hope is the one held out by the NEB which said a cold snap by late November or December could see prices rebound to the $7-$9 range.

Barring a catastrophic hurricane season in the Gulf of Mexico or a scorching summer, the board believes storage will hit its limit by late summer, leading to a gas surplus of 620 billion cubic feet.

To right the market, exports from Canada will have to fall, North American production will have to be trimmed, or consumption will have to rise, it said.

Of those options, the NEB is betting the most likely initial response will be for coal-fired electricity plants in the eastern U.S. to switch to gas, which could displace about 40,000 metric tons of coal a day.

That could also be accompanied by high-cost producers, such as those in the U.S. Rockies, cutting back on production until prices recover.

Paul Mortensen, an NEB analyst, told reporters that the board expects drilling will continue in Canada in the hope of a price recovery by mid-winter, but some producers may delay start-ups or shut in wells while hoping for a more normal winter.

Companies already cutting E&P spending

The clouds over the Canadian gas sector have already prompted EnCana, Husky Energy, Apache, Murphy Oil and several junior E&Ps and income trusts to cut their E&P spending, lowering a forecast by Citigroup Global Markets for overall capital spending in 2006 to C$27.8 billion.

That’s still up 8.6 percent from 2005, but short of the 12 percent hike predicted by Citigroup six months ago.

Of the 72 companies with operations in Canada who responded to the survey, 35 percent expect to spend more in the second half of 2006 than the first half and 27 percent expect to trim their budgets.

“It appears there is limited upside potential to Canadian spending plans this year (unless there is a) strengthening of natural gas prices,” Citigroup said. “The price likely to yield 10 percent budget increases, on average, is now C$10.07 (per thousand cubic feet), up slightly from C$9.98 in December and above the current 12-month futures strip of C$8.28.”

The survey found that 52 percent of Canadian respondents expect to spend more on gas than oil, roughly unchanged from a year ago, but well short of the 65 percent among U.S. independents.

Coalbed methane permitting down

The first hint of a pullback from unconventional plays because of price uncertainties and rising upstream costs has surfaced in Canada where new well permits have fallen behind 2005.

The Alberta Energy and Utilities Board issued 1,034 coalbed methane permits over the first five months, down just 12 wells from the same period last year, but May’s count was 143 compared with 232 in May 2005, putting a dent in hopes of 4,000 coalbed methane wells this year and 6,000 in 2007.

A disturbing sign has been the drastic scaling back of coalbed methane programs by the largest operators: Devon Canada has licensed eight wells compared with 78 to the end of May 2005; Apache Canada, 70 vs. 103; MGV Energy, 118 vs. 156; and EnCana 196 vs. 259.

Offsetting those trends, rig counts remain ahead of last year’s pace, with 60 percent of the activity targeting gas, and well completions are 20 percent higher than 2005.

David Hyman, an analyst with Raymond James, said in a research note that “field activity levels continue to build toward what is expected to be a very busy summer.

“While natural gas concerns remain rampant, we continue to believe that field level activity will continue to be governed by a longer-term view on pricing, which is still above prior year levels.”

Aside from whatever jitters the prospects for the rest of this year are causing in the industry, the Alberta government is likely to be on edge, having based its 2006-07 budget on average gas prices of $6.78 per million Btu. Currently, gas accounts for 60 percent of the province’s energy royalties and is forecast to reach C$7.15 billion in the current fiscal year, but may need a major adjustment.





Ingredients in place for price slump

Rattled by last winter’s dive in commodity prices, the North American natural gas sector is worried by a series of sign posts that are pointing in the wrong direction. But not everyone is reaching for the panic buttons.

The summer is forecast to be cooler than last year, lowering the demand for gas-generated electricity to run air conditioning systems, while gas storage systems may hit capacity this fall, laying the groundwork for a price slump around mid-September.

Ken Yeasting, a director of Cambridge Energy Research Associates, told a Calgary conference earlier in June that because there is insufficient storage working capacity to absorb all of the gas available for injection there is likely to be a “sharp and swift drop in spot gas prices” unless summer temperatures soar or hurricanes cause significant supply disruptions.

CERA is predicting that by early fall prices could drop from recent levels of just under US$6 per million British thermal units to $5, forcing some high-cost producers to sell at a loss for a period.

But Yeasting said that if prices drop towards $5, gas-fired power generation could displace coal-fired generation, creating additional gas demand and thus support prices and “rebalance the market.”

He said coal-fired plants likely to pay the price are older, inefficient eastern U.S. facilities that burn high-cost Appalachian coal without emission control equipment.

CERA has calculated that North American withdrawal capacity covers a spread from 37 billion cubic feet per day when inventory is below 20 percent of working capacity to 48 bcf when it is above 60 percent. The research firm said North American injection capability ranges from above 33 bcf per day when inventory is below 50 percent of working capacity to 15 bcf when inventory is above 90 percent.

Thus, when storage inventories are at their peak in summer, the gas market has less ability to respond to daily drops in demand or increases in supply. As a result, it will need a greater decrease in gas prices to balance the market when inventories are high and injection capabilities are low.

Record U.S. storage expected

The latest forecasts project Lower 48 storage inventories at a record level of 3.643 trillion cubic feet by the end of October, closing in on the working storage capacity of 3.76 tcf.

Based on those levels, CERA believes daily storage injection capability in the Lower 48 will drop to 10.7 bcf or lower at the end of the injection season.

However, despite growing storage inventories, prices for the upcoming winter have held firm around $10 per million British thermal units.

Calgary-based FirstEnergy Capital is not surprised by this trend, forecasting winter prices will remain strong regardless of how full storage reservoirs become.

In a new analysis, the firm said factors underpinning winter prices include the continued strength of crude oil prices, concerns about the prospect of hurricanes in the Gulf of Mexico (which drove gas futures to US$15.78 last December), the chances of a “normal” winter and the diversion of LNG cargoes from the U.S. if high prices take hold in overseas gas markets.

FirstEnergy said the obsession with record volumes in storage is not likely to cause a “significant reduction” in strong pricing levels for the 2006-07 winter.

Don Warlick, president of Texas-based consultancy Warlick International, told a Calgary conference that a hot summer and normal winter will stall price declines and reduce the anxieties among “financial types.”

But if North America experiences a cool summer and warm winter there would likely be a sharp drop in activity such as coalbed methane drilling, he said.

Warlick said Henry Hub prices are expected to average between $6.83 and $7.04 per thousand cubic feet this year and $5.29-$5.36 in 2007, a sharp downturn from last year’s spike of $8.02, but more in line with earlier years — $3.36 in 2002, $5.24 in 2003 and $5.58 in 2004.

He doubts LNG imports will have any impact on North American prices until 2012 because of the problems obtaining regulatory approvals in the face of community and environmental opposition and the competition for LNG supplies in Asia.

—Gary Park


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