‘Essentially, what’s happening is that as the gas comes out of the ground, the producer or whoever is marketing gas is paying the buyer’
Natural gas prices in Western Canada stumbled into negative territory last month, creating a sticky situation for petroleum producers facing a dilemma.
Either pay someone to take their gas – or curtail their output.
Inventory levels in the region have been running close to maximum and industry experts wonder how much more capacity is available for putting additional gas into storage before the winter heating season arrives.
After months of pain for producers tied to dismal AECO gas prices in the province, industry players and the provincial government are contemplating what steps, if any, can be taken to help the sector before an expected change in fortunes sometime next year.
“We recognize that they’re struggling,” Alberta Energy Minister Brian Jean said in an interview this week.
“We’re consulting with stakeholders on what can be done to support the industry, and dry gas producers in southern and central Alberta are obviously hurting. We’ve asked industry producers — large, medium and small producers — to give us advice.”
Alberta gas prices have been mired in a miserable slump this year, coming off warmer-than-normal winter weather last year. That led to higher levels of gas in storage and weak prices.
“We have just come through probably the worst summer on record for the last 10 years in terms of pricing,” said Doug Dafoe, CEO of Calgary-based gas producer Ember Resources.
“As we went through the summer, that storage level just got fuller and fuller and fuller — and there’s a limit as to physically how much gas you can stick in the ground.”
Gas production in the region has been increasing in preparation for the arrival of a new liquefied natural gas (LNG) industry in the country, capable of exporting super-chilled gas off the coast of British Columbia to customers in Asia.
The LNG Canada project, which will export about 1.8 billion cubic feet (bcf) per day, is gearing up for full commercial operations sometime next year.
Two smaller projects are also being built, yet prices were feeble this summer due to a glut of gas, although AECO prices have rallied this week.
Alberta spot gas prices traded at just five cents on Sept. 27 and were stuck below $1 per gigajoule between late July and last week, before closing Tuesday at $1.66.
Last month, the Station 2 natural gas price benchmark in British Columbia closed in negative territory three times, including at minus 19 cents on Sept. 23, according to data from Bloomberg.
“Essentially, what’s happening is that as the gas comes out of the ground, the producer or whoever is marketing gas is paying the buyer,” said Martin King, RBN Energy’s managing director of North American energy market analysis.
“We just have more supply than the rest of the market can take . . . and we still haven’t seen quite enough curtailment at the wellhead from the producers.”
ARC Resources, one of the country’s largest gas producers, said last month it had curtailed output by about 250 million cubic feet per day (mmcf/d) at its Sunrise dry gas play in northeast B.C.
On Tuesday, Advantage Energy announced it has started “strategic production curtailment” of up to 130 mmcf/d of dry gas due to unusually low prices in Alberta. It primarily affects dry gas produced at the company’s Glacier properties.
“The Glacier gas asset is generally acknowledged to be one of the best, lowest-cost assets in North America,” company CEO Mike Belenkie said Tuesday.
“If we are finding that it’s cash flow negative to keep producing, so is pretty much everybody else for any gas exposed to AECO or western Canadian prices.”
Shutting in gas will be determined continuously to eliminate the company’s variable cash costs and defer development capital, he said.
Despite recent shut-ins, King believes Western Canada is still producing 17.5 bcf of gas per day, and he estimates storage levels in the region are up to 98 per cent full.
Meanwhile, many operators have hedged some production — essentially locking it in a future price — or diversified to other markets, but it’s still a tough time for many in the sector.
Jean said the province will not put any taxpayer money on the table, although it is “exploring ways to aggregate gas from the small producers so that they can combine to sign hedging contracts and get into the NGTL (pipeline) system.”
The department is also looking at ways to encourage more gas use in the province.
“We do believe that the market will rebalance itself,” he added.
Operators producing a lot of natural gas liquids or those who’ve diversified their markets or hedged have been able to withstand the weak conditions, but those relying on spot prices in Western Canada are suffering, said Ian Archer, an associate director with S&P Global Commodity Insights in Calgary.
“We could still see negative prices this month or within the next couple of months. That wouldn’t surprise me at all,” he said.
The short-term solution for companies may be to hunker down and wait for colder winter weather to drive more consumption — and higher prices — while waiting for the beginning of LNG exports.
LNG Canada said it remains on track to deliver its first LNG cargoes by the middle of next year.
“We’re pretty bullish about the future, but we’re also cautious at the same time with respect to what volatility may be in store as they work through starting up that LNG facility,” said Birchcliff Energy CEO Chris Carlsen, a mid-sized gas producer.
“There’s a period of weak commodity prices today, but the future certainly looks quite good.”
A report released Tuesday by the U.S. Energy Information Administration projected benchmark gas prices south of the border will increase next year and average US$3.10 per million British thermal units.
“There’s some positives out there,” added Phil Hodge, CEO of Pine Cliff Energy.
“If some of these natural gas producers can just get through the next 12 months, I think they’re going to be OK. But I don’t know how close people are to the edge.”
Chris Varcoe is a Calgary Herald columnist.