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Wagons circling in Canada EnCana, Fort Hills, Compton on most-watched list; winter drilling down Gary Park For Petroleum News
At the three-quarter mark for 2008, government land sales in Western Canada were up 55 percent from a year earlier at a stunning C$4.12 billion, while new well permits were up 37 percent in Saskatchewan and almost 11 percent in British Columbia and off only 6 percent in Alberta.
So what’s all the natter about Armageddon in the Canadian oil patch?
In blunt terms, it’s the loss of more than C$120 billion in the market value of the 58 companies on the S&P-TSX capped energy index, dragged down by about half in just over a month amid panic selling and the nosedive in commodity prices.
And it’s not just the minnows who are getting hammered.
Oil sands giant Suncor Energy has seen its market cap spiral down from C$70 billion to the C$25 billion range; at the other end of the spectrum, Birchcliff Energy, despite being strongly-placed in the British Columbia gas properties, watched its market value slump from almost C$1.8 billion to barely C$650 million in the bloodletting.
None has escaped the carnage, much to the distress of John Wright, chief executive officer of Petrobank Energy and Resources, whose combined production in Canada and Latin America has grown in the past year to about 24,000 barrels of oil equivalent per day from 7,000 boe per day, generating enough cash to ensure that access to credit is not a worry.
But the market is taking no prisoners. Petrobank has seen its market cap plunge to C$1.7 billion from C$5.24 billion and shares, that more than doubled in 2007 to reach a 52-week high of C$63, have shed all that and more, tumbling to almost C$20.
Wright describes the dive as “surreal” for a company that is funding all of its growth internally, but can’t continue a share repurchase program because it is in a blackout until third-quarter results are disclosed.
He finds that especially troubling “because the best investment we can make right now is buying more shares of Petrobank.”
EnCana split in question There’s no shortage of tell-tale signs pointing to the health and near-term future of the industry.
Take three that are due for action this quarter:
• The future of EnCana’s plan to divide its operations into separate natural gas and oil sands companies.
• A decision by Petro-Canada and its junior partners, UTS Energy and Teck Cominco, on whether to proceed with the Fort Hills oil sands project, whose costs have climbed in the past year to about C$25 billion from C$14 billion.
• Whether Compton Petroleum will find a buyer.
Given the “unprecedented conditions in credit markets,” EnCana says it is faced with making a decision in the best interest of shareholders on the proposed breakup that is due for a final vote in December.
But the challenge right now is to negotiate loan packages to support the two units, with analysts concluding that the $9.9 billion of debt needed for the transaction may not be available, forcing a delay in the breakup.
Philip Skolnick, an analyst at Genuity Capital Markets, told the Globe and Mail that if the costs of raising capital are greater for parts of EnCana than the company as a whole that could make it easier for the oil sands unit to get taken out.
He said that would also put paid to any plans by Husky Energy and Petro-Canada to copy EnCana’s strategy.
Fort Hills ultimate test case The future of the Fort Hills project has become the ultimate test case for the mega-sector of the oil sands, now that capital cost estimates have topped C$180,000 per flowing barrel of production.
FirstEnergy Capital figures that oil prices of US$115 per barrel for the entire operating life are needed to yield an internal rate of return of 10 percent.
For the initial phase of the Fort Hills mine and upgrader, Petro-Canada must come up with C$15.6 billion, about C$3 billion more than its latest market value. The plight of its junior partners is even worse.
The simple solution appears to be dropping the C$10 billion upgrader from the plans and downsizing the mine. That could be accompanied by the inclusion of new partners.
Otherwise shelving or scrubbing the project might draw a swarm of better-financed companies eager to snatch up assets at a bargain price.
Those, including former Alberta premier Peter Lougheed, who have advocated slowing the pace of oil sands expansion may be about to get their wish, but not for the right reasons.
If Fort Hills topples off the table, talk of a C$170 billion capital outlay over the next decade will grow very quiet.
Compton in play In the realm of barometers, mid-sized Compton Petroleum is worth tracking. In fact, it’s the only company that is officially in play.
Since June, after finally caving into demands from its largest shareholder, New York-based Centennial Partners, Compton is offering a bundle of attractive assets — 30,700 boe per day of production from assets estimated at 271 million boe entering 2008, although the sale of assets this year for C$212 million has trimmed output by 3,700 boe per day.
But, having missed one of the best opportunities of 2008 to unload the bulk of its holdings, it is fast approaching bargain-basement levels as its shares slide towards C$2 from a 52-week high of C$13.45.
A data room was opened more than a month ago to prospective buyers and Compton indicates it still hopes to conclude a deal this fall. Given the natural gas-levered nature of the company, it is difficult for analysts to agree on a possible outcome.
Ed Giacomelli, managing director of investment banker Crosbie & Co., doubts there will be a sudden M&A feeding frenzy, regardless of the industry’s undervalued state, until there are signs of stability and he has no idea when that might occur.
The one exception might be companies whose lines of credit are about to dry up and have no choice but to chase capital by unloading assets.
Winter drilling hit expected What troubles all sectors is the prospect of the winter drilling season taking its worst hit on record because of the decline in gas prices and uncertainty over oil prices.
Those worries are deepening in the shale gas plays of northeastern British Columbia, where the costs of special completion, stimulation and production methods are compounded by remoteness and a lack of infrastructure.
It’s already a given that Alberta is heading for a bleak winter because of costs, slumping commodity prices and scheduled royalty increases in 2009 (barring a sudden change of heart by the government).
But Alberta is no longer alone. BMO Capital Market analyst Mark Leggett told an energy roundtable this month that rapid growth in the Barnett shale play has changed North American market dynamics, removing any fears of a winter gas shortage.
As a result, he expects many companies will follow Chesapeake Energy’s lead in slashing its budgets through 2010.
Leggett estimated a break-even shale price of $4 in the U.S. would likely be closer to $9 in Alberta and $6.50 in British Columbia.
Roger Soucy, president of the Petroleum Services Association of Canada, said that regardless of any winter price uptick he does not expect higher gas drilling activity.
Thus, although the land holdings and well permits are in hand for better days, the signs point to a continuing drop in gas output after last year’s 6 percent decline.
Now there is the looming threat of oil testing the $80 barrier, which Leggett rates as the marginal supply cost, and causing companies to back off exploration and development programs in hopes of triggering a price recovery.
The drop off in drilling has FirstEnergy forecasting a decline in Western Canada’s field receipt supplies of 416 million cubic feet per day this year and 800 million in 2009, with benchmark AECO spot gas prices for the current quarter — having dropped to $6 per gigajoule in September from $9.03 in July — averaging $7.37, which is scarcely breakeven for many conventional plays in Western Canada.
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