The Alberta government’s latest stab at sweetening a relationship gone sour has attracted the most comforting noises from industry in recent years.
In taking the second of three steps to mend fences, the province unveiled a bundle of incentives and scaled-back royalties May 27 that it figures could shrink its royalty haul by C$1.5 billion over the next three years, but the Canadian Association of Petroleum Producers believes could pump as much as an extra C$3 billion into upstream spending in 2011.
The initial wave of reaction included research reports that hailed the incentives as “material and significant.”
Investment bank FirstEnergy Capital said the “economic picture” for the companies it covers “is better coming off this announcement,” and peer firm Peters & Co. said the modifications “are a substantial improvement” from what the government indicated in March “when there was minimal benefit for any play unless commodity prices increased significantly.”
Macquarie Securities said the royalty framework is “directionally positive for producers in Alberta and hopefully provides a new stable and clear regime for producers to carry out their oil and gas development.”
First Energy analyst Robert Fitzmartyn said companies will have to more closely examine the numbers over the next few weeks to decide whether to adjust their capital budgets, but he is confident that activity will increase.
Saskatchewan lowers royalty
As fast as Alberta brought in its regime, the neighboring province of Saskatchewan lowered its maximum royalty rate to 2.5 percent for the first 882 million cubic feet of gas produced from every horizontal well drilled between June 1, 2010, and March 31, 2013, in an effort to arrest a decline in gas drilling over the past seven years.
CAPP President David Collyer credited the government with delivering on its commitments to restore Alberta’s competitive standing in North America by making permanent a current incentive program royalty of 5 percent on new natural gas and conventional oil wells, which includes lowering the maximum royalty on conventional oil to 40 percent from 50 percent and on both conventional and unconventional natural gas to 36 percent from 50 percent.
It has also offered incentives to start unlocking shale gas in Alberta, give a fresh prod to the stalled coalbed methane sector and to promote horizontal oil and gas drilling.
The government estimated that although the breaks might lower its royalty take by C$1.5 billion that loss would be partly offset by more than C$800 million from increased land sales, tax revenues and oil patch activity.
Liepert: ‘nothing given away’
Energy Minister Ron Liepert said “there is nothing given away. We will be recovering a fair royalty return.”
“Industry and the investment community have asked for stability and predictability and that is what is being provided,” he said.
Liepert said the enhancements to the fiscal framework will allow new technologies to be deployed, developing new resources and extending the life of existing conventional basins.
He said the objective is to promote exploration and development of Alberta’s estimated 850 trillion cubic feet of potential shale gas resources and 500 tcf of potential coalbed methane resources.
To recognize the higher costs and risks associated with those emerging resources and technologies, the government is extending an up-front 5 percent royalty rate on a temporary basis, allowing operators to recover their costs.
Royalty regime changes
Among changes in the royalty regime, Alberta will:
• Set a maximum 5 percent royalty for all new shale gas products for 36 producing months. Charge a maximum royalty of 5 percent over 18 months for production from horizontal gas wells, setting a volume limit of 500 million cubic feet equivalent.
• Impose a maximum 5 percent royalty on horizontal oil wells or horizontal non-project oil sands wells, with volume and production limits tied to well depths.
• Set a maximum royalty of 5 percent for all products from coalbed methane wells for 36 producing months, with volumes limited to 750 million cubic feet equivalent.
The new royalties will apply to wells that came on-stream on May 1 or later.
Program review in 2014
The government promised it will review the program in 2014 and will not terminate any elements without three years’ notice.
“Overall, it is very positive,” Collyer said, adding the new regime has dealt with the competitiveness issue, which has been blamed for an exodus of billions of dollars in upstream spending from Alberta to British Columbia, Saskatchewan and the United States.
On the shale gas front alone, Alberta has “lagged behind British Columbia and other jurisdictions,” he said.
Chris Seasons, president of Devon Canada and vice chairman of CAPP, forecast a 10 percent hike in capital spending as a result of the incentives, placing his company’s Alberta portfolio in the same competitive league “as anything we’ve got across North America.”
Gary Leach, executive director of the Small Explorers and Producers Association of Canada, said his member companies were “excited by the emerging technology and emerging resources packages.”
“Hopefully, this will be a springboard to reducing the decline in conventional oil production and conventional natural gas and help us go after some of the really exciting potential resources, such as shale gas,” he said.
Peters & Co. said the approach is favorable to mid-depth horizontal wells which are rapidly accounting for a large chunk of the total well count, noting that horizontal wells have climbed from 12 percent in 2009 to 26 percent so far this year.
However, it said that lowering the upper royalty rates will affect only 12 of the 27 identified plays in Alberta and estimated that commodity prices will need to more than double from current levels for the new royalties to have even a 10 percent positive impact.
Regulatory streamlining report
Liepert said the government plans to release a progress report by mid-June on its regulatory streamlining work — the third step in the overhaul process that is being tackled by the departments of energy, environment and sustainable resource development.
Collyer said that is an important step in improving Alberta’s regulatory framework by blending environmental standards with greater efficiencies.
Liepert also announced that new studies are under way to support both industry and government in the development of provincial resources.
The first will expand mapping, geological and resource knowledge of Alberta’s shale gas reserves and the second will examine the enhanced recovery potential of Alberta’s existing conventional oil resource pools that could “immensely extend our total recoverable reserves” if they can benefit from the same technological advances that have unlocked shale gas and coalbed methane.
As well, Liepert said, the government is already working with the industry on a mature oilfield review for existing reserves, “trying to understand what technological and economic incentives are required to get people to go back to those fields.”
