Frigid temperatures and blizzard conditions moved across Europe in early February, setting new records – and as temperatures fell, gas prices from the main pipeline in Russia rose to the highest levels since 2006.
Frigid temperatures and blizzard conditions moved across Europe in early February, setting new records – and as temperatures fell, gas prices from the main pipeline in Russia rose to the highest levels since 2006.
One week later in North America, colder weather pushed across the continent causing a slight uptick in natural gas consumption, but not enough to offset the excess supply and appreciably boost market price. About half the homes in the United States alone use gas for heating, but natural gas usage was lower than normal due to unseasonably warm temperatures in November, December and January.
In the classic economic theory of supply and demand, as demand for a commodity increases, prices rise. Increased supply drives the price down. In today’s world, however, many other factors can affect price, including government regulations, fluctuating costs, transport systems, etc.
And in the current case, reduced product demand together with plentiful supply from shale gas play development appears to be the cause of a downward natural gas price trend.
A U.S. Energy Information Administration report from early February illustrates the economics in hard numbers:
“Total working natural gas in underground storage in the lower 48 states was 3,098 Bcf for the week ending Jan. 20 – 21 percent above the storage levels from one year ago.”
Daily dry gas production averaged about 64.2 billion cubic feet per day (Bcfd) in January, up almost 10 percent from last January, according to the report. And natural gas prices hit a 10-year low on Jan. 19 at $2.32 per 1,000 cubic feet, according to industry reports.
As market prices for gas appeared to hit bottom, U.S.-based companies Chesapeake Energy and ConocoPhillips announced production cuts due to low prices and thin margins, while other companies have slowed drilling programs in purely natural gas fields.
Chesapeake Energy, the second largest natural gas producer in the United States, said last month it will sharply cut drilling spending, forecasting it will cut dry gas drilling capital expenditures to $900 million in 2012, compared with $3.1 billion last year.
Chesapeake also announced that it would trim production by about 500 million cubic feet per day, while ConocoPhillips reportedly is considering shutting down another 100 million cubic feet per day of production.
Around this same time, Royal Dutch Shell announced it will shift focus from shale gas to tight oil, due to declining U.S. gas prices. Chesapeake also announced a shift in its exploration efforts to liquids-rich plays like the Eagle Ford in Texas.
Even T. Boone Pickens, longtime proponent of natural gas-powered vehicles, recently offered a cure for declining gas prices. Reuters quoted Pickens as saying, “The only way to get natural gas prices up is to stop companies’ drilling.”
Over the past year, a chill in the economic climate also has settled over Canada. Previously, Canadian producers supplied approximately 20 to 25 per cent of North America’s demand for natural gas – yet Canadian producers have seen their U.S. exports drop by 31 percent since 2010.
For a time, reduced demand due to the excess supply from booming U.S. shale gas production pointed to a partly cloudy economic outlook for Canada’s shale gas industry.
Canadian Challenges
Meanwhile, with exports to the United States declining, many Canadian producers are facing similar issues, as Progress Energy Resources Corp. announced shutting-in up to 10 percent of its dry natural gas production (25-30 mmcf/d) and other companies are looking for opportunities to monetize plentiful natural gas supplies.
This period of low prices is seen by some as the optimum time to assess the potential of new business markets for natural gas, study the feasibility of bringing new technology to Canada and, ultimately, to invest in market diversification – all aimed at increasing the value of western Canada’s natural gas.
“Production growth in British Columbia is second only to Alberta, and is attributed largely to the development of unconventional shale gas,” according to a spokesperson for the British Columbia Ministry of Energy and Mines.
Recently, the National Energy Board (an independent federal regulator) and the British Columbia Ministry of Energy and Mines jointly assessed the huge volumes of shale gas potentially producible in the Horn River Basin. The 2011 energy market assessment, “Ultimate Potential for Unconventional Natural Gas in Northeastern British Columbia’s Horn River Basin,” is considered the first probabilistic resource assessment of a Canadian shale basin.
“The assessment suggests that B.C.’s Horn River Basin holds the potential for 78 trillion cubic feet of marketable shale gas (a medium estimate within the range of production calculated in the study),” says the Ministry spokesperson.
Clarifying the significance of the assessed gas volume, the Ministry spokesperson added, “This is a significant number because the entire province currently produces just over one trillion cubic feet of gas per year.”
Options and Exports
Canadian companies are looking for ways to monetize natural gas. The business case is straight forward – leverage the difference between low gas prices and high oil prices.
Among the possible monetizing options for natural gas are new markets or potential expanded markets under consideration in western Canada are: Liquefied Natural Gas (LNG) exports; gas-to-liquids technology (GTL); increased usage of natural gas used in oil sands production; and large-scale conversion of vehicles to natural gas-burning engines.
With the first three options producers are basically investing at natural gas price levels, then extracting liquids to sell at higher oil price levels.
According to a June 2011 Canadian Energy Research Institute report, “Faced with the prospect of a long-term glut of gas and low prices in North America, producers in western Canada have more incentive than ever to build liquefied natural gas terminals on the west coast to allow exports into the premium-priced Asian market.”
On Feb. 3, Premier Christy Clark announced British Columbia's natural gas strategy, which includes the report “Liquefied Natural Gas – A Strategy for B.C.’s Newest Industry.”
"We are creating new and exciting opportunities by diversifying our natural gas sector, strengthening job prospects for British Columbians and opening the door to new clean energy projects,” she said. “My government is positioning liquefied natural gas as a cornerstone of British Columbia's long-term economic success.”
The Canadian government recently approved a 20-year export license for the LNG facility being built in Kitimat – the first such license ever issued in Canada. By exporting LNG to markets in southeast Asia, like China and Japan, producers can access market prices for natural gas that are four times higher than North American prices.
China and Japan are both looking for new energy supply sources – China to fuel its massive infrastructure expansion, and Japan to diversify its fuel supply away from primarily nuclear energy.
The Kitimat LNG export terminal on B.C.’s West Coast is reportedly on target to be fully operational by 2015.
GTL Potential
Talisman Energy of Canada and South African energy and chemicals group, Sasol, are jointly conducting a feasibility study for a gas-to-liquids facility in western Canada. Sasol and Talisman previously joined forces to explore the Montney basin in Western Canada, where the two companies are equal partners in two shale gas assets near Dawson Creek, British Colombia.
The exact location under consideration for a GTL plant is not yet known to the public, but Alberta and British Colombia are taking steps to demonstrate their province’s suitability and commitment to the project.
The Talisman-Sasol study will assess the infrastructure, work force capacity and potential markets for diesel fuel in western Canada and the western United States, including offshore opportunities needed to develop a GTL plant.
According to Rob Gibb, Talisman’s manager of corporate and public affairs-Canada GTL Project, the study is expected to conclude by the end of June, and after that “business decisions will be made by the partner companies on whether and how to go forward with the project.”
The primary product of the GTL process is low sulfur diesel – a superior performance diesel fuel that is readily useable without changes in engine design. Naptha, used to blend with bitumen, is also produced.
“By converting natural gas into transportation fuels such as diesel and jet fuel, the value of natural gas would more closely track oil prices,” Gibb said.
Risk comes into the equation depending upon how predictable are the capital costs and operating cost estimates.
And, “depending on timing of the provincial regulatory process”, Gibb added, “cost estimates could change.”
Formed in South Africa to make oil from coal, Sasol began commercial use of its coal-to-liquids (CTL) technology in 1950. The first gas-to-liquids plant, developed for Oryx in Qatar, began production in 2007. Sasol now operates in over 30 countries in response to growing interest in its CTL and GTL projects.
“An Alberta location would be close to industry with lots of local demand for diesel and naptha,” said Deborah M. Pietrusik, corporate relations manager for Sasol Canada. The Alberta oil sands industry blends naptha with oil sands to produce bitumen.
“Alberta has seen a shortage of diesel due to significant industry growth,” she said, adding that the GTL plant “would alleviate local concerns about fuel shortages in the event of an unplanned outage at diesel-producing refineries.”
If B.C. is selected as the proposed GTL plant site, the Kitimat export facility would provide access to global markets.
Officials in Alberta and British Columbia are vying for the honor of being the first province to welcome GTL technology, but also recognize the significant value of new jobs generated by the project. The feasibility study is looking at building either at 48,000 bpd plant or a 96,000 bpd plant, which could be optimized to 98,000 bpd. With either of these scenarios, 73 percent of the production would be diesel.
As Peitrusik puts it, “approximately 7,000 jobs will be employed during the construction phase.” And when fully operational, she estimates, “the GTL plant will offer nearly 500 permanent employment positions.”