Alberta will remain a blank spot on the shale gas production map of North America until the provincial government overhauls unfavorable royalties, according to a study circulating in the industry capital of Calgary.
Factoring in all royalties and taxes in a comparison of a prototype drilling project in different shale locations, Alberta placed last as an investment destination with a return on investment of less than 10%, given a $6/Mcf gas price (U.S. dollars throughout, except where noted). The same project would bring in closer to 30% in several U.S. shale plays. The specialized computer software program created by Energy Navigator Inc. showed Texas the most profitable, followed by Pennsylvania and Louisiana, but the differences in the U.S. sites were only marginal.
In British Columbia, the hot spot of fledgling Canadian shale gas drilling, financial rewards trail well behind the U.S. But thanks to incentives worked out by consultations with Calgary companies return rates are in a respectable range of 20-50% depending on gas prices. The prototype development breaks even at gas prices of $4.31/MMBtu in Texas, $4.45 in Pennsylvania, $4.51 in Louisiana, $4.97 in BC and $5.90 in Alberta.
Energy Navigator President Boyd Russell presented the research results generated by his firm's specialized computer software at a technical meeting of the Calgary section of the Society of Petroleum Engineers. A call for urgent attention to the new fossil fuel source topped the industry agenda for the government's "competitiveness review" of energy policies, according to minutes of initial meetings that launched the mostly confidential inquiry. "There is a need to be very attentive to what is happening with shale gas and the technology surrounding it," says the sketchy public record on talks held at the Calgary Petroleum Club.
Newly appointed Alberta Energy Minister Ron Liepert, echoing Premier Ed Stelmach, has pledged to respond to the review after its report is completed this winter by a specialist group that includes recently-retired gas producers and financial executives. No firm date has been set for action. No commitment has been made to release the report publicly.
Russell's contribution is a paint-by-numbers portrait of a wide gap that the industry maintains the province's hotly contested New Royalty Framework (NRF), enacted in 2009, opened up between Canada's chief gas-producing province and other jurisdictions. His firm performed an analysis of how a 76-well shale gas development -- a real one, done in 2006-2008 -- would fare financially if it was repeated under the regimes prevailing as of year-end 2009 in the main Canadian producing provinces and the three U.S. locations.
To obtain details of the prototype drilling campaign, Russell pledged to keep its location and sponsors' identities secret. The analysis is a typical example of economic evaluations that senior energy production firms and financial institutions carry out in making decisions on the location and timing for significant supply projects, he says.
Where would an operation that has $500 million to put into a two-year shale gas project go? The prototype project's 76 horizontal wells all include high-tech flow-channel fracturing jobs and are drilled across a shale formation 2,370 meters (7,750 feet) underground. Maximum initial production rates average 6.7 MMcf/d.
Each well pumps out a total of 3.7 Bcf before running dry. Over the development's lifespan, daily production dwindles by an annual average of 12%, starting with a swift natural drop in the first year after the flows' youthful rush and followed by gradual tapering off with advancing age.
Excluding unpredictable bills for buying mineral rights and building new infrastructure such as access roads that cannot be easily or fairly compared among jurisdictions, the wells cost an average of $5 million each. Operating expenses are $3,000 per month or $1/Mcf of production.
The U.S. annual rates of return on investment came in near 30% at a gas price of $6/Mcf, 50% at $8, 70% at $10, and nearly 100% at $12. The Alberta return of less than 10% at $6 would barely top 20% even if the price bounces up to $12/Mcf, Russell said. Measured by after-tax cash flow into company coffers, the 76-well prototype development pays $300-730 million less in Alberta than in Texas.
For every $1 a production firm keeps when gas fetches $12, the provincial treasury in Edmonton scoops away $1.80 or all but about one-third of the cash flow gains from the high price, says Russell's evaluation. BC and the U.S. states attract the industry by letting it keep half or more of the gains when fat times return to the gas markets.
The fatal flaw in Alberta's NRF is that it looks backward and caters to the previous generation of gas supply additions, Russell says.
The Alberta royalty regime's sliding scales grant low royalties to shallow drilling with rapid, inexpensive wells into small deposits of conventional freely flowing supplies. Rates climb steeply as production volumes and prices rise, on the theory that the best wells are leftovers from big discoveries that were made early in the industry's history and already recovered their costs many times over. As a result, the system penalizes the shale gas pattern of tapping large, deep reserves with costly wells that have high initial production rates.
Alberta drilling rights auctions hint that some producers are betting the competitiveness review will end well for industry. At a single winter sale land brokers, working for undisclosed clients, paid C$365 million (US$343 million) for 1,470 square kilometers (588 square miles) of a dense geological layer north of Edmonton known as the Duvernay formation.
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