Five Reasons NatGas Prices Have Stabilized
While the infamous 'Gundlach' trade has done remarkably well since inception, our view on NatGas has become less vociferously bullish recently as the more constructive factors such as an under-appreciation of declining production and rising utility demand. While their remains upside potential to gas prices over the next 18 to 24 months, we tend to agree with Credit Suisse as they note five reasons why a near-term pause in pricing is likely. With unconventional supply more resilient than many had expected - covering the fall in conventional supply and absent an extremely cold winter (which NOAA is not expecting), a range-bound NatGas pricing market seems the new normal (for now).
Via Credit Suisse: Five Reasons Why A Near-Term Pause In Pricing Is Likely
(1) Haynesville (HV) production is higher than expected.
We estimate the break-even cost of gas is $3.77/Mcf in the Haynesville core and $4.93/Mcf outside of the core. As a result, HV drilling activity in the core has declined, averaging 19 rigs in Q312 versus the peak of 138 rigs in Q210. Given the decline in drilling activity, our proprietary production model estimated that July HV production was 5.9 Bcf/d, but State data indicates that actual production is 7.1 Bcf/d, or 20% above our estimate.
o HV volumes could be flat or higher in Q3. On October 2, Plains (PXP) preannounced 6.4% higher production relative to guidance. The biggest surprise was the implied sequential increase in natural gas given reduced activity in the Haynesville. It appears the company’s US gas volumes surged 7.5% sequentially to roughly 250 MMcf/d. PXP owns a 20% non-operated interest in Chesapeake’s HV acreage, who is the largest producer in the play.
o Why was HV production so resilient? HV activity has been more resilient given (1) higher than expected completion activity in the 1H12 as operators have worked through completion backlogs, (2) impacts from restricted rate programs, and (3) significant production shut-ins from CHK. In February, CHK began to shut-in volumes in response to low gas prices, peaking at more than 650 MMcf/d of shut-in HV volumes in Q212. We believe CHK resumed production from the wells in late Q2, which is boosting the nearterm HV production outlook.
(2) Drilling efficiencies mitigating lower gas activity.
On a year-over-year basis, the natural gas rig count has declined by 54%, yet production is yet to crack. One of the key factors why production has been so stubborn is the impact of drilling efficiencies. In the Barnett Shale, the industry has averaged 2.70 completions per month, which represents a 17% improvement in efficiencies relative to 2011. This is an astonishing 29% improvement relative to 2010, when the industry completed 2.1 monthly Barnett wells per rig. The same trends are evident in other key dry gas basins.
(3) Marcellus debottlenecking in 4Q should bring untapped supply to market:
The Tennessee Gas Pipeline (TGP) Northeast Supply Diversification and National Fuels Northern Access pipelines are expected to add 500 MMcf/d of takeaway capacity to the northeast market by November 1. TGP Northeast Supply Diversification will supply the New England market with 100 MMcf/d and an additional 150 MMcf/d into Canada via Niagara. National Fuel’s Northern Access project will extend from their TGP interconnect in Ellisburg, PA to the TransCanada Pipeline at Niagara, bringing 320 MMcf/d of supply with it. The key to these projects include the fact that they bypass the fully subscribed TGP 300 leg and are in close proximity to the estimated 1,000 drilled, but uncompleted wells in Pennsylvania.
(4) Widespread ethane rejecting is boosting gas supply by approximately 300 MMcf/d.
As a result of weak processing spreads (Mt. Belvieu frac spreads are only 10¢/gal), processors are rejecting ethane in several markets such as the Rockies, Mid-Continent, and San Juan Basin. Envantage estimates the industry is rejecting between 100 and 125 MBopd of ethane across the U.S. It appears that ethane rejection is boosting natural gas supply by approximately 275 to 350 MMcf/d.
(5) Switching Economics no Longer Universally Favor Gas:
Electric utility demand in 2012 has been off the charts, averaging 5.7 Bcf/d, or 29% above 2011 levels. Using historical correlations between coal generation market share and gas prices, we estimate the potential impacts to switching at different price points in the 1H13. We estimate natural gas could lose 2.4 to 5.1 Bcf/d of market share to coal at gas prices between $3.50 and $4.50 per Mcf. At the current futures strip of $3.95 per Mcf, we estimate gas could lose 3.75 Bcf/d of market share to coal in 2013.Focus shifts to key fundamental of gas market—winter weather. The largest risk to our outlook for the remainder of 2012 and into 2013 remains weather. As the 2011-2012 winter season proved, a warm winter in a market flush with supply of natural gas can significantly move prices lower. The same goes for a cold winter as well. We estimate that a one standard deviation event in winter weather can drive a 235 bcf swing to either side in season ending inventories compared to an only 100 bcf impact in the summer. As such, we approach the winter season with a heightened level of caution and fully appreciate the
and meanwhile, NOAA favors a warmer-than-normal West and gives equal chances to either side for the East. Shown below, warmer-than-normal temperatures are currently expected from TX toward the Pacific Norwest with the warmest temperatures coming at the Northern Rockies.
A drier-than-average winter is expected for the Pacific Northwest and Northern California, possibly leaving hydro output lower and gas burn higher in the West. Given uncertainty with El Niño and NOA, the NOAA gives equal chances for temperatures for much of the Midwest and Northeast.
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