Numerous risks could propel gas prices to new seasonal highs this summer
By Leticia Vasquez, Patrick Badgley in Houston
April 3, 2013 - With both cash and summer forward natural gas prices averaging well above year-ago levels so far this year, some markets could surpass last year's seasonal highs when the mercury rises this summer as pipeline maintenance, low hydro supplies, strong demand and a host of other issues underpin markets, a Platts analysis shows.
These hefty year-over-year premiums appear to be setting the stage for some sharp price swings in either direction as market players have baked in expected volatility earlier than usual.
New England's Algonquin Gas Transmission city-gates market — no stranger to volatility — is one market that stands to see price fluctuations as the summer season gets into full swing. (See related graph: Algonquin City-Gates Basis Differential: 2011-13).
With the system running at full capacity for more than a year now from west to east and major maintenance planned for the pipeline mid-year, the market hub could see a return to the $8/MMBtu levels of last summer, sources said.
Analysis continues below...
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Algonquin cash hit a summer high of $8.825/MMBtu on June 20 last year, Platts historical data shows.
The last time prices at the New England market hub reached such levels was in 2008, when they generally remained near or above the $10/MMBtu mark for much of the summer.
Meanwhile, year-to-date cash at Algonquin remains elevated as winter refuses to back out of the region without a fight, averaging at an almost $8/MMBtu premium over the same period last year, according to Platts historical data.
And although the market should soften as the below-average temperatures give way to warmer weather, Platts forward assessments show prices are stronger than this time last year.
The forward prompt-summer strip for Algonquin has averaged around $4.29/MMBtu so far this year, a more than $1 premium over what the summer 2012 package was trading at during the same period last year, Platts prices show.
One wildcard that could lead to a spike in prices early in the summer is maintenance that is scheduled in June at several locations along the Algonquin system, including at one of its major chokepoints, the Cromwell compressor station, in central Connecticut.
Algonquin will begin an approximately two-week outage at the station June 1, reducing flows to about 400,000 Mcf/d. The Cromwell station has a peak-day capacity of nearly 1 Bcf/d.
The Cromwell compressor station outage — and ongoing bottlenecks at other points on the Algonquin system — could force flows from Canada and LNG inflows to fill the gap on peak demand days, leading to higher prices.
In a possible indication of the volatility to come, when the Cromwell maintenance was announced, Algonquin June basis jumped post-market close and continued to climb 37 cents the next day.
"It's a balancing act up there right now," a regional trader said. "It seems all the incremental power demand is coming from gas-fired generation. As long as maintenance isn't coincidentally timed with hot weather, then capacity should be available."
Gas-fired generation in the New England Independent System Operator footprint has grown significantly in the past few years. Gas made up 49,577 MW of the total power generated in the region in 2012, up from 38,338 MW in 2008.
With the region's increased reliance on gas, any hot weather concerns could also drive up the market, the trader said, unless producers flood the market with supplies in anticipation of higher prices.
Northeast production now stands at 10.5 Bcf/d, compared with last year’s same-time level of 7.6 Bcf/d, according to Platts unit Bentek Energy.
Year-over-year production growth has been 2.9 Bcf/d, with the company expecting that positive growth trend to continue.
And while early forecasts show a warmer-than-normal start to the spring season in the Northeast, the prolonged winter has drained storage inventories in the region, with stocks running below last year's unusually high levels.
The longer the winter season lasts, the more gas will be needed to refill storage this summer, which could also provide support to other nearby Northeast markets, Bentek said.
At the Dominion Transmission storage facility, current inventories stand at 89 Bcf, down 60 Bcf from the same time last year and down 21 Bcf from the three-year average, Bentek said.
Columbia Gas Transmission's storage facility currently has 58 Bcf of inventory, a decline of 49 Bcf from the same time a year ago and a decline of 23.4 Bcf from the three-year average.
The higher gas prices will likely mean higher prices for electricity as well, and Platts data is already showing signs of that strength.
New England Mass Hub spot electricity prices for on-peak hours are averaging around $98/MWh year-to-date, up about $35 from the same period last year.
The July-August on-peak electricity forward assessment for Mass Hub has averaged around $54/MWh year-to-date, a roughly $11 premium for the comparable quarter in 2012.
The higher cash prices have not been isolated to the Northeast.
Points as diverse as AECO-Alberta and Florida Gas Transmission zone 3 have seen significant year-over-year increases. (See related graph: Florida Gas Zone 3 Basis Differential: 2011-13).
AECO, the western Canadian benchmark, has had spot prices averaging in the low C$3.00s/Gj year-to-date, compared with an average of about C$2.05/Gj in the same period last year.
The summer strip at AECO, meanwhile, is holding a roughly 80-cent premium over the comparable package during the same time in 2012.
Florida zone 3's average cash price has jumped above $3.50/MMBtu so far this year, about $1 higher than last year, while the summer forward price is averaging more than 90 cents above the comparable package a year ago.
Price swings could be in store for other regions this summer.
Westcoast Energy station 2 gas prices could see a jump in June as the pipeline conducts maintenance at the Fort Nelson gas plant June 1 to June 28.
The plant turnaround will include a total outage June 7 to June 19, as well as capacity limitations of 300,000 Mcf/d to 600,000 Mcf/d for most other days that month.
Bentek data shows receipts at the Fort Nelson plant averaging around 658,150 Mcf/d year-to-date, up from 524,899 Mcf/d in the same period last year.
"That can get it back up closer to AECO," a western Canadian trader said.
Next page: More gas needed to support hydro-electric supplies