Despite the high level of natural gas storage overhang at the end of last winter, which resulted from record gas production last year and above-normal winter conditions, constructing new storage facilities in the United States is not supported by market conditions at this time, according to a report issued Thursday by FERC's Office of Enforcement (OE).
"Although very high storage levels so early in the refill season indicate a need for additional storage, market conditions do not generally support the building of new storage...Winter-summer gas price spreads are at historically low levels and barely cover the cost of storing gas," OE said in "2011 State of the Markets" report. It said gas in inventory at the end of March was more than 50% higher than the five-year average, which was a record.
"Overall for storage value has declined because of the prices, because of [falling] seasonal spreads, especially [those] that we've seen this winter," said OE's Valeria Annibali, who delivered the report on the gas market. Salt cavern storage facilities in the Gulf Coast have been the most affected. "Falling seasonal spreads reflect increased production and storage capacity, as well as greater year-round use of natural gas by power genrators," the report noted.
At the end of March, the official close of the winter heating season, working inventories totaled 2,479 Bcf, which was 887 Bcf more than last year's level and 934 Bcf above the five-year average, the Energy Information Administration recently reported (see NGI, April 16). Inventories hit 2,512 Bcf on April 13, or more than half of the peak storage capacity of 4.1 Tcf in the U.S.
Low gas prices, while good news for consumers, caused concern among some OE staff. The sub-$2 Henry Hub prices could set the stage for a production bust, which could lead to higher prices down the road, said OE's Chris Ellsworth. Low prices will continue to make gas more attractive to power generation, which could create capacity problems on interstate pipelines.
Gas production reached an all-time record in 2011, surpassing levels last seen in the 1970s, the OE report said (see NGI, Nov. 14, 2011). Supply outpaced demand, which led to record-high storage going into the 2011-2012 winter and gas prices fell to lows not seen since the early 2000s. Gas consumption rose a paltry 1% to a little more than 60 Bcf/d in 2011 over the prior year, with much of the growth coming from the power sector.
Dry gas production grew 7% to 65 Bcf/d, exceeding a record last set 25 years ago, according to the report. The growth was primarily driven by shale development, which accounted for one-third of total dry gas production by the end of 2011.
Annibali said the Federal Energy Regulatory Commission (FERC) hasn't seen "a lot of production decreases" in the market, rather producers appear to be shifting from developing dry gas wells to oil and natural gas liquids (NGL) wells. Although some dry gas-only wells might be shut in, production of gas associated with NGLs and oil is continuing to grow, so it has balanced...out. We haven't seen [an] overall...decline in production," she said.
Dry gas shales, such as the Haynesville in Louisiana, the Fayetteville in Arkansas and the Barnett in Texas, remained the largest producing shales in 2011. However, the fastest growing production was found in the liquids-rich shale basins, such as the Marcellus Shale, the report said (see NGI, April 16). Production in the Marcellus doubled to nearly 6 Bcf/d by the end of 2011, while production in the Eagle Ford Shale in South Texas grew 64% to 3 Bcf/d over the same period, the highest growth of any shale.
In 2011, the price of natural gas fell from the mid-$4/MMBtu level at the start of the year to less than $3/MMBtu by December. Prices are now under $2/MMBtu. "The most recent Nymex forward curve for natural gas shows that the market anticipates that prices at Henry Hub will remain under $4/MMBtu through 2014," OE staff said.
All pricing points declined last year. The report estimated that average gas spot prices across the nation fell by approximately 7%. This winter was the warmest in 60 years, and the Northeast, which usually sees the highest winter prices, saw no sustained price spikes, it said.
"New pipelines completed during 2011 linked growing supply sources to markets and contributed to shrinking regional price differences. In some cases the market price of natural gas between regions declined to less than variable transportation costs...We have also seen a decline in the seasonal difference between winter and summer natural gas prices," the report said.
In addition to impacting prices, shale development is affecting gas flows on traditional long-haul pipelines. "For example, we saw Rockies natural gas flows to the Northeast on Rockies Express Pipeline (REX) decline more than 40% since early November 2010, from 1.7 Bcf/d to 1 Bcf/d. The decline was so severe that S&P [Standard & Poor's] reduced REX's credit rating [see NGI, Feb. 6]."
Rockies gas has been displaced in the Northeast by increased flows of the cheaper Marcellus Shale gas from Pennsylvania. On the West Coast, REX is facing competition from Ruby Pipeline, which is providing producers with access to the northern California market.
FERC said jurisdictional gas pipelines in 2011 added roughly 2,100 miles of new pipeline, or about 9.3 Bcf/d of transportation capacity, while major intrastate lines added 400 miles of new pipeline and 4.7 Bcf/d of capacity. The projects proposed last year focused on relieving local bottlenecks in new producing basins rather than long-haul pipelines.
Most of the proposed pipe projects are in the Northeast and Southeast and include the Tennessee Gas Pipeline Line 300 expansion, Texas Eastern Transmission's TEMAX/TIME III project and the Acadian Haynesville Extension, an intrastate pipeline that feeds into the Henry Hub.
As for LNG, Annibali said the soonest the U.S. can expect to see significant exports of LNG is in the 2016-2018 time frame. She said companies seeking new foreign markets for LNG proposed 14 Bcf/d of export capacity last year in various location in the U.S, which she estimated is about 21% of daily domestic gas production.
Cheniere Energy's Sabine Pass LNG, which has been approved by the Department of Energy to export domestically produced gas as LNG, "is the furthest along with 90% of its proposed export capacity contracted by buyers in Korea, India and Spain. These buyers are likely willing to pay a price premium for the security and diversity that the U.S. natural gas market provides" (see related story). FERC's approval last week was its first authorization of a project that would export LNG from production resources within the United States.
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