The U.S. natural gas market is staring down a “summer of extremes” because of record storage inventory, which means production curtailments are coming, but they won’t prevent a repeat of sub-$2.00 spot pricing later this year, according to Bentek Energy LLC.
Other analysts also are concerned about what’s ahead with so much gas. Even back-to-back hurricanes in the Gulf of Mexico are unlikely to have much impact on U.S. gas storage, according to Standard & Poor’s Rating Services (S&P). And analysts with Barclays Capital on Friday said near-term prices “must” remain in the low $2/MMBtu range to produce enough coal displacement to avoid an early fill of storage.
However, Credit Suisse analysts played contrarians last week and said the market may have forgotten about the sharp decline in conventional gas drilling, which could reset the market faster than some think otherwise.
In “Gas Tank Full: Henry Hub Will Re-Test Price Floor,” issued on Thursday, Bentek’s analysts said the April-ending 0.9 Tcf storage surplus would force the domestic gas market to test operational storage constraints by the end of injection season, leading to extremes in injection rates, power demand and production curtailments.
To reduce storage inventories, up to 0.9 Bcf/d of production would need to be shut in from basins outside of the Northeast. “The market will elicit the needed behavior through low pricing, averaging in the $2.00-2.75 range during the peak of the cooling season, with a $1.00 handle monthly average at the end of summer,” the Bentek team wrote.
Steady output growth from the Marcellus, Haynesville, Eagle Ford and Granite Wash, which accelerated in 2010, “easily” offset declines in conventional and offshore producing areas. Meanwhile, gas storage has been “carving out a new five-year high every week,” and domestic stores “will very likely” hit a record inventory by the end of the injection season.
According to Bentek, storage operators have reported constraints in the past, which indicate that a “more realistic” gas storage capacity may be somewhere between the Energy Information Administration’s (EIA) most recent 4,103 Bcf noncoincidental peak working gas capacity and the 4,488 Bcf total design capacity. EIA’s figure is equal to the sum of each field’s maximum observed inventory; Bentek assumes a “generally high level of operational flexibility” from operators and has settled at 4,200 Bcf, taking into account this summer’s storage expansion projects.
“Such an event will be accompanied by mandatory limits to storage activity,” said the report, which noted that the maximum observed U.S. inventory was 3.9 Tcf in November 2011. The limits mean that only 65 Bcf can be injected weekly, or about 1.3 Bcf less than the 2005-2011 average weekly rate and 4.6 Bcf less than the 2008-2011 weekly rate.
Without anywhere to put the gas, demand could take the pressure off, but it will take a “strong weather-adjusted power burn” to avoid production curtailments later this summer, according to Bentek. “Even in a scenario where production remains flat for the entire injection season, total demand will have to average 6.3 Bcf/d stronger than the five-year summer average and 4.3 Bcf/d stronger than summer 2011 average demand to hit a 4.2 Tcf inventory by the end of the season.”
An unusually hot summer — even back-to-back hurricanes — would have little impact on the U.S. gas market at this point, according to S&P’s Ben Tsocanos.
Many U.S. exploration and production (E&P) companies have the financial resources and flexibility to wait out low gas prices, but operators whose reserves are dry gas-concentrated, lack price hedges and have limited liquidity may be in for a bumpy ride, Tsocanos said. He and his team analyzed what’s ahead for domestic E&Ps in “How U.S. Exploration & Production Companies are Coping with Low Gas Prices.”
Gas prices won’t rebound quickly, and supplies likely will remain plentiful over the next 12 months “in part because oil wells liberate it,” said Tsocanos. “This means that a relatively small proportion of liquids can make even a gas well profitable — while the well swells gas supplies.”
Mirroring Bentek’s report, Tsocanos said “gas prices could drop further if storage hits capacity (possibly by fall) while supplies continue to rise; there’s now nearly 40% more gas in storage than the five-year average for this time of year.”
Natural gas liquids (NGL) can’t “prop up profits of even liquid-rich gas wells indefinitely,” said Tsocanos. S&P already has begun to see prices drop for some types of NGLs, including ethane, as supplies grow. Low gas prices may stimulate gas consumption in several industries, encourage exports and even fuel transportation fleets, but none of this will happen overnight. Even Mother Nature wouldn’t diminish gas supplies much at this point, said Tsocanos.
“An unusually hot summer would likely have only a short-term impact,” said the S&P analyst. Even back-to-back Gulf of Mexico hurricanes like Katrina and Rita, which upended the gas market in 2005, would be offset by inland unconventional plays.
Barclays’ team, led by Michael Zenker, said Friday in a note that coal displacement has to run strongly “all summer long or risk a gas price collapse, in our view.” However, even though gas prices this year will remain under pressure, “we believe a bullish catalyst is around the corner” and when a market consensus adopts a view that supply is convincingly on the down slope, prices for calendar 2013 and beyond should be supported.”
Credit Suisse analysts are more optimistic about this year. One aspect of U.S. drilling activity that has been left out of the equation is conventional gas drilling. Sharp declines in onshore conventional drilling and a more “permanent” shift to liquids plays may bring about a faster reset in the gas market than the futures strip implies, analysts said. And a return to conventional activity is “unlikely given shifting operator behavior,” said the Credit Suisse team, led by Arun Jayaram.
“Given weak natural gas prices, conventional production began to soften in October 2011. Since that time the conventional natural gas rig count has tumbled by 194 rigs, or 56%, and a further 100-plus rig decline is anticipated,” analysts said. “We believe a snapback in conventional production is not likely given what looks to be more permanent shifts in producer economics favoring lower cost gas shales (i.e., the Marcellus) and oil/liquids-rich unconventional plays.”
Credit Suisse analysts anticipate the “potential for meaningful declines,” with 3.2 Bcf/d in 2013 and a 1.6 Bcf/d decline in 2014, partially offset by rising unconventional gas. “While we share the market’s near-term pessimism on gas given bloated inventories as well as limits on coal-to-gas switching this summer, we believe an underappreciated and under-analyzed part of the supply equation is the potential decline of conventional production, which is generally at the higher-end of the cost curve.”
The “missing link” has been onshore conventional production, which accounted for 34 Bcf/d or 46% of production, based on 2011 data. “Conventional production is still a larger piece to the supply equation than unconventionals (18.4 Bcf/d, or 27%),” noted the analysts. Associated gas from liquids plays accounted for 10.3 Bcf/d or 15%; offshore output took another 5.1 Bcf/d or 7%; and net imports totaled 5.3 Bcf/d or 7%.
Credit Suisse has used a database of more than 508,000 conventional wells since 1982 to model predictive production and to gauge productive capacity.
“Our model suggests conventional production peaked in 1Q2012 and is poised to move lower given weak gas prices and unfavorable drilling economics for conventional drilling,” said the Credit Suisse team. Based on the current production rates, the “unremediated decline curve” for conventional gas is about 11.1%, or 4.1 Bcf/d, a year.
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