Three analysts last week raised their projections for U.S. natural gas prices through this year based on wintry weather consumption and based on evidence that U.S. natural gas production has flattened, with the shift back to coal-fired generation is “stickier” than expected.

On Friday Goldman Sachs analysts raised their price forecast for natural gas and predicted that the gas rig count would top 500 this year.

“The cold weather in March combined with the ongoing tightening shift in the underlying balance due to structural demand growth against stable production means less than 1.7 Tcf of natural gas remained in storage by the end of March this year,” said the Goldman Sachs team. “As a result, we now estimate only 2.0 Bcf/d of coal-to-gas switching will be required on average this year to reach an end-of-summer storage level of around 3.65 Tcf, which will allow prices to continue to move higher.

“In addition, a return to production growth is required to balance the market after this summer, and we now expect prices to average $4.50/MMBtu in 2H2013 in order to make this happen.”

Production growth from “relatively price-insensitive sources” like the Marcellus Shale and associated gas are continuing, but “the momentum has likely peaked as rigs have dropped even in the Marcellus, and liquids-rich gas and oil drilling has stabilized, and natural gas liquids prices have been under pressure over the past year.”

The Marcellus natural gas production and U.S. oil production “in general face infrastructure constraints that will likely continue to limit the pace of growth in coming years. Further, given the underlying declines in conventional production, dry shale gas plays like the Haynesville are key for future natural gas production growth.”

Specifically, said the analysts, Haynesville Shale output is in meaningful decline, which has to be reversed. Encana Corp.’s decision in February to increase its Haynesville rig count to five from three this year (see NGI, Feb. 18) had “seemed early to us given where prices were at the time, [but] similar measures by other producers are needed.

“So far most producers have been very reluctant to increase gas- directed drilling, but with the March rally this could start to change. Specifically, we assume the U.S gas rig count rises back above 500 by the end of 2013 and above 600 by the end of 2014, from below 400 currently.”

That forecast is at odds with Barclays Capital, which late last month predicted that the gas rig count would remain below the 450 mark this year (see Daily GPI, April 1). Barclays last week also revised its average gas price forecast for this year upward to $3.90/MMBtu from a December forecast of $3.70.

“With the forward curve currently near $4.10/MMBtu for the remainder of this year, prices may have ran ahead of fundamentals, but only slightly so. Indeed, the late season cold weather effectively rebalanced 2013,” wrote Barclays’ Biliana Pehlivanova and Shiyang Wang. “In other words, the iteration between the trajectories of production, prices, coal-to-gas displacement, and end-of-season storage projections remains the four-wheeled base of natural gas markets in the U.S.,” they wrote in a note.

“Given market fundamentals and assuming normal weather for the rest of the year, we expect the market to balance,” with average prices of $4.00/MMBtu in 2Q2013 and 3Q2013, rising to $4.10 in the final three months of the year. Storage levels are predicted to be about 3.9 Tcf at the end of October.

Winter temperatures averaged close to 10-year norms in aggregate for the season, and the number of heating degree days recovered by 17% from 2012 levels, according to Barclays. However, “these statistics are deceiving” because November was colder than usual, while there were unseasonably warm temperatures in December and January. February weather was in line with historical norms. “Then came an exceptionally cold March…”

The market fundamentals suggest a higher price environment through the rest of the year, but the analysts are concerned that the current price rally may have run ahead of itself because the forecast for the supply trajectory remains unchanged from a previous review. Barclays analysts took a fresh look at the regional analysis of U.S. production conducted in early January and found that it confirmed their previous projections: domestic output was down except in “headline” onshore shale plays (see NGI, Jan. 14).

“Output in the Fayetteville has essentially stabilized at 2.9 Bcf/d as of December 2012, and we maintain our expectation for a modest pullback in 2013,” said the analysts. “The Marcellus continues to grow, adding an average of 107 MMcf/d in each of the past three months. Drilling activity in the play has leveled off, and a large backlog of wells remains…Along with a significant amount of pipeline and processing capacity additions, this will support the play’s pace of output growth in 2013, in our view.”

Data on Texas oil production and Barclays’ estimate of associated gas, as well as gas output in North Dakota also is tracking earlier projections. The declines in “all other” areas of the country appear to be “steeper than we had projected,” but the numbers are distorted by well freeze-offs. “The aggregate amount of production curtailments in each month is difficult to estimate, but pipeline flow data point to peak supply losses of as much as 1.8 Bcf/d” from well freeze-offs.

As always, coal-to-gas displacement remains the balancing item for gas markets, said the analysts. “Gas demand for power during this injection season should pull back by about 1 Bcf/d with a return to normal weather and changes in nuclear and renewables, excluding coal-to-gas displacement.

“Our analysis of all other supply and demand variables, excluding gas use in power generation, suggests that balances will tighten 1.9 Bcf/d during the injection season. In contrast, inventories will need to grow on average 4.0 Bcf/d faster than last year to rebuild to 3.9 Tcf by the end of October,” said the Barclays team. “This means that a 5.0 Bcf/d drop in coal-to-gas displacement compared with last year will be needed to rebalance the market.”

Stephen Smith Energy Associates also raised its price forecast for gas prices this year. Henry Hub (HH) prices now are expected to average $3.90/MMBtu in 2013, up from a previous estimate of $3.50. For the rest of the year, Smith sees an average HH price of $4.00/MMBtu in 2Q2013, climbing to $4.10 in 3Q2013 and $4.15 in the final three months of the year. The analyst previously had pegged prices to average $3.55/MMBtu in 2Q2013, $3.70 in 3Q2013 and $3.80 in 4Q2013. In 2014 prices were lifted by 40 cents from a previous forecast to $4.40/MMBtu.

“With considerable help from a very cold March, more evidence that gas production growth has flattened out, sub-normal nuclear generation, and some evidence of a ‘stickier’ shift back to coal-fired generation than the recent gas-versus-coal price spreads would suggest, the current gas storage surplus (versus 2006-2010 norms) is now down to only 100 Bcf as compared with 500 Bcf in mid-December,” said Smith.

This past winter consisted of two distinct seasons, he said. The nine weeks of December through January had 11% fewer heating degree days (HDD) than normal, while the eight weeks of February through March had 8% more HDDs than normal. The 17 weeks ending March 29 recorded 104 HDDs, which was 3.3% fewer than Smith’s regionally weighted HDD norms. Still, the gas storage surplus declined by almost 165 Bcf over the period. In the last five weeks of the period, HH cash prices averaged $3.76/MMBtu, compared with a $3.33 average for December through February.

“However, despite these stronger prices, the storage surplus declined by a massive 300 Bcf in the last five weeks of the 17-week span,” Smith said. “Most remarkably, this decline occurred with a five-week heating load, which was only 89 HDDs more than normal.

“This outcome suggests that either gas demand was less vulnerable than expected due to higher prices…or that production was in fact lower than most sources believed. Either of these explanations would suggest a tighter supply/demand balance going forward.”

The impact of higher gas prices has not been “nearly as strong as expected,” he wrote, which “suggests that either production is weaker than first thought or that gas is retaining higher generation shares at any given price (i.e., stronger than expected trend gains from some combination of coal shut-downs or gas startups).”

Onshore production growth “remains a key uncertainty,” Smith said, “but recent evidence suggests lower and perhaps even no sequential growth over the course of 2013.” May and June are both expected to be hotter than normal as well, and as a result, “we are likely to begin July with a storage deficit versus 2006-2010 norms.”

Until Energy Information Administration-914 production data was issued on Feb. 29 and March 31, “Marcellus-driven growth appeared to be gaining momentum, but the combined sequential decline for December/January showed a combined two-month decline of 1.37 Bcf/d for Lower 48 onshore production.” Because of the data, Smith cut projected production growth rates for the second consecutive month.

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