Producers lining up to launch unconventional natural gas developments propelled drilling rights sales in British Columbia to a record C$2.66 billion (US$2.23 billion) for 2008. The new annual high scored by monthly auctions of provincial mineral rights is more than double British Columbia’s previous peak of C$1.05 billion (US$874 million) set in 2007 and a six-fold jump from the previous 10-year average of C$434 million (US$364 million).

The 2008 purchases were 7,567 square kilometers (2,920 square miles) of gas development targets, well below the record 8,542 square kilometers (3,297 square miles) set in 2001. But 2008 prices for the hottest properties shot up as high as C$28,974 per hectare (US$9,394 per acre) at the mid-December sale, the last one of the year. The 2008 average of about C$3,700 per hectare (US$1,200 per acre) was more than double the previous record, set in 2007, of C$1,758 per hectare (US$570 per acre).

The 2008 mineral rights action focused on unconventional tight and shale gas target areas known as Montney in north-central BC and the remote Horn River Basin just south of the province’s boundary with the Northwest Territories. Industry was drawn by a combination of geological and technical discoveries that are making possible the use of horizontal drilling and rock-fracturing technology imported from the Barnett Shale region of Texas in the Dallas-Fort Worth area.

The scale of development in the works is highlighted by TransCanada Corp., which is signing up shipper support for two BC extensions, called Groundbirch and Horn River, of its Nova pipeline grid in Alberta. Each new line is intended to use jumbo pipe 42 inches in diameter that can have initial capacity of 1 Bcf/d and commence operations as early as 2010 (see Daily GPI, Dec 15).

BC Energy Minister Richard Neufeld drew no quarrels from producers when he gave the province’s Liberal government a share of the credit for the burst of interest in a region also known as the Canadian gas industry’s “near frontier.” Neufeld declared, “Through effective incentives, programs and royalty structures, BC has established itself as one of the most competitive oil and gas jurisdictions in North America.”

The magic ingredient in 2008 was introduction of a BC gas counterpart to the oilsands royalty regime that set off a 10-year industrial development boom in the bitumen belt of northern Alberta. The new BC regime mimics the “net profit” oilsands royalty system by scrapping the traditional Canadian provincial government royalty approach of taking large shares in cash or kind straight off the top of industry operations from the day they start, by levying charges determined by sliding scales of production volumes and market prices on gross production revenues.

The net profit method delays significant collections until development expenses are paid off. Then royalties are calculated as percentages of revenues after costs negotiated with industry, including an agreed minimum return that is usually the going interest rate on government bonds. As in Alberta’s oilsands, BC’s new gas regime sets the provincial royalty at a nominal 2% of revenues for the “pre-payout period.” In BC’s case that can last for up to 10 years. Then rates rise in “tiers” or stages to 15%, 20% and ultimately 35% of net after-production expenses gas production revenues.

The timing of steps up the BC gas royalty ladder is determined by how long it takes to achieve net revenues that first cover, then rise to double and triple initial development costs. As a floor for aging projects — and a limit to creative cost accounting — the provincial policy sets a minimum royalty of 5% of gross revenues from paid-for gas wells.

Consultations continue between the BC energy ministry and the industry on details of exactly what types and locations of gas supply developments will qualify for the net profit royalty regime. But producers expect unconventional northern gas development to have no trouble satisfying the declared provincial objectives of opening new production sources, introducing technical innovations and spreading industry into remote areas where job creation and associated services such as road and bridge building are desirable.

There is no counterpart to BC’s light royalties regime for unconventional gas in Alberta, where the provincial government turned down requests for special consideration during flurries of coalbed methane development. The Alberta regime sets gas royalties at nominal levels for all types of low-productivity wells, which effectively means rates are favorable for coalbed methane.

The special case of shale gas, which flows in much higher volumes per well, has not yet generated much public discussion in the main Canadian gas producing jurisdiction. But the government’s Alberta Research Council and Alberta Geological Survey are doing work in the new field while industry performs largely confidential field trials. A hint that unconventional gas has a chance to win special favor appears in a newly minted provincial energy strategy. Although the paper is long on principles and short on details, it promises “Alberta will consider royalty structures to allow the development of marginal resources and promote best use of current and new technologies.”

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