To What Extent Might Coal Impact Natural Gas Prices This Winter -- RBN Energy -- November 14, 2018

Hang on to your hats:

The "shale price band." From The Financial Times. This is a pretty good article. Some data points:

• OPEC seriously under-estimated what US shale producers would add to global supply
• one year ago: OPEC forecast an additional 540,0000 bopd from the US, 2018 yoy
• in fact, the US added 1.5 million bopd, 2018, yoy
• shale oil and its light-end yield characteristics does not easily replace the heavier qualities of crude oil from the Middle East
• US shale oil is not necessarily the crude most desired by refiners, but that is irrelevant for US producers. They are driven by economics and will produce as long as the price is right
• in early October, data started to indicate that the US weekly statistical reports had been under-estimating production. That is when oil prices started to retreat and also when large speculators started to reduce their long exposure to crude oil futures
• by trying to control supply and support prices, Opec and its new partners have created better economics for the US producers and are back to facing a wave of supply increase that they did not expect and are struggling to control
• Comment: the US is nowhere near what it can produce -- the Permian is barely getting started; there are some interesting production profiles in the Bakken that have not been seen before 
• archived.

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Back to the Bakken

One well coming off confidential list today -- Wednesday, , November 14, 2018:

• 34453, SI/NC, XTO, Cherry Creek State 14X-36EXH-S, Pembroke, no production data, 

Active rigs:

$55.74😒	11/14/2018	11/14/2017	11/14/2016	11/14/2015	11/14/2014
Active Rigs	65	54	38	64	186

RBN Energy: how much could coal generation stem gas price upside in a cold winter?

The U.S. natural gas market enters winter this year in a delicate balance: production is at an all-time high and growing fast, but gas storage inventories are well below year-ago levels and the five-year average — and at an all-time low relative to consumption. If winter weather is normal or mild, the U.S. gas market will likely begin to settle into a period of sub-$3/MMBtu prices. But this year’s low inventory level means that colder-than-typical weather this winter could spell more gas price upside than the market has seen in many years. Today, we continue our review of the current gas market with a look at the relationship between gas- and coal-fired generation, and at how the combination of low gas storage inventories and low coal stockpiles might play out this winter.

Entering the winter (before forecasts turned cold), our NATGAS Billboard called for an end-of-March underground gas storage inventory level of about 1,250 Bcf (or 1.25 Tcf).

Even a moderately colder winter can add 400 Bcf of residential and commercial heating demand, and the upside to industrial demand could add another 100 Bcf.

But a colder-than-normal winter also adds demand in the power sector, more so now that increasing numbers of people are heating their houses with electricity, particularly in the South. We estimate that a moderately cold winter would add about 200 Bcf to gas demand for power generation, all other things being equal.

However, an atypically cold winter would quickly push coal inventories into uncharted territory, too. The coal demand upside in a moderately colder winter — before accounting for any additional market share gained from gas — would be in the neighborhood of 15 million tons. Current coal consumption rates average just under 2 million tons per day, so 15 million tons of extra demand divided by 2 million tons per day would reduce days of inventories by 7.5 days, taking coal inventories from just over 70 days of consumption to the low 60s — outside of the historical range. Layering in an additional 20 million tons of coal demand due to gas price upside (the coal equivalent of the 350 Bcf we discussed earlier) would bring coal inventories to only 53 days of consumption — likely an unsettlingly low level for utilities, even in an environment of declining coal demand.

Of course, the higher that gas prices climb, the more expensive it gets to source gas or coal from somewhere other than storage or stockpiles, and therefore the more comfortable utilities get with drawing down gas storage inventories and coal stockpiles to meet winter demand. We saw how gas and coal prices could spiral upward in the Polar Vortex winter of 2013-14. Gas prices rose and coal became more economic, but declining coal stockpiles — along with logistical constraints around delivering coal from mines in the West to power plants in the East — meant that coal generation didn’t prevent gas prices from climbing to $6/MMBtu in February 2014.

So this winter, the precise elasticity — just how high gas prices would need to rise to pull gas and coal out of inventory — will not be so predictable as it would be, for example, in response to a short-lived gas production outage. Rather, this elasticity will depend on the trajectory of winter weather (early versus late cold, extreme versus moderate cold, etc.), of gas supply growth (whether the market is comfortable that gas supply will be robust a few months down the line), and likely other factors. 

A somewhat unpredictable power-sector response means that we need to look elsewhere for factors that might stem gas price upside in a colder-than-normal winter. That brings us to a relatively new potential source of gas demand elasticity in the U.S.  — LNG exports — which we’ll cover in the final episode of this series.

Much more at the linked article.