The oilpatch has recorded its first global casualty of tough new rules for companies reporting their oil and gas reserves.
In contrast, a lot of firms in Alberta are chalking up surprisingly positive reserve numbers, even under the stricter reporting regimes.
Pressured by angry investors, Royal Dutch/Shell Group’s twin boards sought and got the head – figuratively speaking, of course – of embattled chairman Sir Philip Watts this month.
Watts tendered his resignation following an internal audit, after the oil giant stunned investors and industry observers in January by slashing its worldwide tally of oil and gas reserves by 20 per cent – equivalent to 3.9 billion barrels of oil.
The U.S. Securities and Exchange Commission, which brought in more stringent reserves reporting rules this year, is investigating how the world’s third-largest energy group could overstate by one-fifth the amount of recoverable oil and gas it has in the ground.
Accounting rules in both Canada and the U.S. require companies to book so-called proved reserves only when there’s a 90-per-cent probability (the Canadian rule) or reasonable certainty (the U.S. rule) that the oil and gas can be economically extracted.
Investors and analysts keep an eagle eye on reserve numbers, which indicate a company’s intrinsic financial value and ability to add future production.
In Canada, the Alberta Securities Commission’s policy, based on the new National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, establishes a more conservative reporting standard for proved and probable reserves.
Several analysts expected the new rule to put a dent in many Alberta companies’ reserves, especially the smaller players.
But a lot of companies – many backed by independent audits of their reserves – are reporting increases rather than declines in their reserve numbers compared with last year.
Some examples among Calgary-based juniors are: n Real Resources Inc., whose total proved reserves grew by 19 per cent, entirely on the basis of new exploration and drilling.
* Desmarais Energy Corp., with proved reserves up by three per cent.
* Vaquero Energy Ltd., with proved reserves increasing by 130 per cent or 4.5 million barrels of oil equivalent (boe).
* Devlan Exploration Inc., which expects to increase its production by the end of March by another 200 boe per day to 2,700 boe/d, reported proved reserves jumped by 15.5 per cent.
* Canex Energy Inc., whose proved reserves increased by 29 per cent.
* True Energy Inc., which had an increase in total proved reserves of 15 per cent.
* Burmis Energy Inc., whose proved reserves soared by 83 per cent or 1.17 million boe.
* Progress Energy Ltd., which plans to spend $85 million this year drilling more than 75 wells (including 50 in B.C. and the rest in central Alberta and Saskatchewan), says its proved reserves rose by 37 per cent.
So what do all these glowing reserve reports indicate?
They show that fast-growing junior companies – which have always provided the new lifeblood in the oilpatch – are aggressively reinvesting their revenues in oil and gas exploration in Alberta and B.C. And they’re expanding their reserves because of that investment.
Thumbs down for Sumas
The battle over the proposed $400-million Sumas Energy 2 (SE2) natural gas-fired power plant project isn’t over yet, despite a decision being cheered by residents in Abbotsford, B.C., and Premier Gordon Campbell.
The National Energy Board (NEB) denied an application by U.S.-based SE2 Inc., which has spent six years trying to get the 660-megawatt power plant built, to construct the Canadian portion of an 8.5-kilometre international power line for the project.
The line would have enabled SE2 to transport electricity from the power plant near Sumas in Washington State across the border into the Fraser Valley to a BC Hydro substation in Abbotsford, for distribution into the Pacific Northwest regional power grid. Without the line, the project looks uneconomical.
The NEB decided after holding a public hearing that, on balance, the negative effects of the SE2 project outweighed the benefits to Canada, especially for local and regional communities.
The power plant would emit 2.5 tonnes of pollutants a day into the Fraser Valley – already one of the most polluted airsheds in Canada.
SE2, which says it is “flabbergasted” by the NEB’s decision, already has approval from Washington state energy regulators for the power plant, which would generate enough electricity for a city of 400,000.
The U.S. firm now has the option of asking the NEB to reconsider its decision or launching an appeal in Canada’s Federal Court.
Federal Environment Minister David Anderson says he expects that a court appeal will be forthcoming.
But Oilpatch Opinion’s prediction is that if SE2 goes ahead, the company will instead try to plug the plant into the U.S. power grid about 30 kilometres away along the Interstate 5 freeway. It’s a much more costly route, but it won’t be nearly as expensive as an international court battle.
Air Products Canada Ltd. is making a pretty sound bet on Alberta’s oilsands and energy future.
The company, a subsidiary of Pennsylvania-based Air Products and Chemicals Inc., announced plans to build a plant next to Petro-Canada’s Edmonton refinery by April 2006, to extract hydrogen from natural gas. Air Products intends to build a second, larger hydrogen plant in the same area by 2008.
The company, which has more than 25 similar deals on hydrogen plants with refineries worldwide, builds the facilities with Paris-based Technip, which specializes in the plants’ design and construction.
The first plant will recover about 71 million cubic feet of hydrogen, for use in Petrocan’s refinery to comply with new federal rules for low-sulphur gasoline and diesel fuel.
But the hydrogen will also be needed to strip out unwanted sulphur impurities from oilsands crude, as increasing volumes arrive at the Edmonton-Fort Saskatchewan refinery centre via pipeline from the Fort McMurray region.
Hydrogen also will play a starring role in Alberta’s long-range energy picture.
The Alberta Energy and Research Institute, which is leading the province’s energy research strategy, aims to make Alberta a world leader in the large-scale production, transportation and handling of hydrogen.
Plentiful supplies of the fuel of the future will be required, for everything from fuel cell- powered vehicles to power plants that run on fuel cells.
Energy Trust Focused on B.C.
Focus Energy Trust is buying the remaining natural gas-producing properties at its Tommy Lakes site in northeast B.C. for $110 million from an undisclosed seller.
Focus says it will finance the purchase by selling $74.5 million of trust units at $14.90 each and through existing credit facilities.
The Calgary company says the properties being acquired had average production in January and February of about 11.7 million cubic feet a day of natural gas and 250 barrels a day of natural gas liquids.
The deal makes sense, since the Tommy Lakes site is Focus’s flagship operation. The company owned about half of the properties and operated the site.
Focus was formed in August, 2002, when Storm Energy Inc. split into a trust and a separate exploration company.
Fairwinds Blows Away
LNG could stand for “Losing Natural Gas” in the case of TransCanada Corp. and ConocoPhillips.
The companies are suspending further work in Harpswell, Me., on their joint Fairwinds liquefied natural gas (LNG) project, first announced last fall.
The move follows a vote by the residents of Harpswell against leasing the former U.S. Navy fuel depot site in the community so the companies could build an LNG regasification facility, to handle foreign tankers hauling LNG by sea.
But with some 40 new LNG projects on the drawing board for the U.S. coast, watch for TransCanada and ConocoPhillips to find another LNG venture – either separately or together.
Compton Seeks Breather
The Alberta Energy and Utilities Board (EUB) rarely says ‘no’ to oil and gas companies that offer sensible reasons for postponing public hearings on contentious projects.
So some 250,000 residents of southeast Calgary will probably breathe a huge sigh of relief this week, when (as Oilpatch Opinion expects), the EUB grants Compton Petroleum Ltd.’s request to postpone a hearing on its application to drill six sour gas wells just outside the city’s southeast boundary.
The hearing is scheduled to begin March 30. But Compton is asking for a six-month delay so it can address concerns raised by dozens of interveners at the hearing, including the Calgary Health Region and several community associations.
Some participants have asked for a review of the company’s existing sour gas well in the area and the safety of a pipeline that transports the gas to a processing plant near High River.
The EUB will say ‘yes’ to a delay, especially if it means both Compton and its opponents are better prepared to come to the hearing when it’s eventually held – likely in the fall.