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What’s The Scenario? Forecasting End Of Winter Withdrawal Season
Storage Inventory

October 14, 2015 | By Jack Weixel

Summer injection season is rapidly coming to a close. It’s clear that storage inventories will enter the winter heating season at record levels, but the severity of how winter plays out will be one of the biggest drivers influencing summer 2016. This week’s Get the Point will focus on winter withdrawal season and end of March 2016 inventory levels. 

PointLogic Energy estimates that for the remainder of summer, if supply and demand keep pace at current levels, the U.S. could inject 2,613 billion cubic feet (Bcf) of natural gas, making this summer the second most prolific injection season on record. This level of injection is a mere 120 Bcf below the record setting injection level of 2,733 Bcf seen in summer 2014. 

What does this mean for inventories at the end of October? The below chart plots out both supply and demand forecasted for summer 2015 versus actual data for summer 2014 (all data in billion cubic feet per day or Bcf/d).

Source: PointLogic Energy

Inventory levels at the end of October will most certainly break the record inventory levels of 3,929 Bcf seen at the end of 2012 injection season. In fact, if the 2,613 Bcf scenario plays out, the U.S. could be looking at 4,089 Bcf in storage once colder weather finally takes hold. It’s also highly likely that final injection weeks could last into the first two or three weeks of November, as the level of dry gas production available to the market has swelled above 73.0 Bcf/d over the past several weeks.    

Using this storage inventory level as a base, let’s take a look at three scenarios for Winter 2015/2016 to examine how demand, weather, price and production levels could impact end of March carryout inventory levels. For the natural gas markets winter is defined as November through March and summer is defined as April through October.

Scenario #1: Using EIA’s Short Term Energy Outlook Predictions

Each month, the Energy Information Administration (EIA) updates its Short Term Energy Outlook (STEO) , which provides updated “actual” natural gas fundamentals data from its Natural Gas Monthly report and an outlook of these fundamentals through the next calendar year. 

For winter months, the most significant fundamental demand factor to forecast is residential and commercial demand (res/comm).  Abnormally cold or warm weather can shift the amount of gas used to heat homes and businesses by as much as 20 percent in any given winter. 

For example, during the polar vortex winter of 2013/14, January res/comm demand averaged 59.9 Bcf/d compared to the more normal winter of 2012/13 where January res/comm demand averaged only 50.1 Bcf/d.  This is a difference of 9.8 Bcf/d over an entire month, which equates to 304 Bcf of natural gas that would need to come from storage withdrawals.

In its most recent STEO, the EIA is expecting a decline in res/comm demand this winter compared to last winter of 2.5 Bcf/d due to warmer anticipated weather.  This equates to 378 Bcf less gas withdrawn from storage on its own, so what is moving the weather dial so abruptly?  The most talked about weather event since the polar vortex winter of 2013/14 is the anticipation of a strong El Nino weather pattern this winter.  El Nino is a weather condition that is realized when sea surfaces temperatures in the Pacific Ocean exceed normal levels. 

In its latest update, the National Oceanic and Atmospheric Administration (NOAA) is anticipating a significant  El Nino event this winter which will have  sweeping impacts on temperature and precipitation levels across North America.  The consensus from weather forecasters and NOAA is that El Nino has not weakened going into the shoulder season and could remain as prolific as recent El Ninos experienced in 1997 and 1992 as the below chart illustrates.

Source: National Oceanic and Atmospheric Administration (NOAA)

NOAA’s Climate Prediction Center anticipates that the forthcoming El Nino event will bring warm weather to the Pacific Northwest, Midcontinent market area and the Northeast.  Colder weather will be prevalent in southern regions of the U.S. extending from western New Mexico eastwardly through Texas and the greater Southeast. 

Source: National Oceanic and Atmospheric Administration (NOAA)

Because the major consumers of natural gas as a home heating fuel reside in the red, orange and yellow portions of the above map, lower overall demand from this region will be greater than any incremental demand from the regions shown in blue.  The EIA also expects that overall weak demand will keep a lid on prices, which will encourage increased use of natural gas from the power and industrial sectors.  In the below graphic, we reflect the changes to the demand side of the equation from winter to winter.

Source: EIA and PointLogic Energy

The chart above displays the expected demand differential between the upcoming winter and last winter. Power, Industrial and Res/Comm demand are all derived from the EIA’s Short Term Energy Outlook which assumes a warmer than normal winter.

In addition to the three traditional sources of demand, exports to Mexico and liquefied natural gas s Sabine Pass, located in Cameron Parish, Louisiana. 

All told, under this scenario total demand will average 0.2 Bcf/d higher than Winter 2014/2015 despite weakened res/comm demand precipitated by  El Nino. 

Scenario #2: Winter 2014/2015 Demand Side Repeat

According to weather provider WSI, the lower 48 experienced 2,707 gas-weighted heating degree days (GWHDD) during the peak winter months of December, January and February 2014/15.  Regionally, last winter in the Northeast was very similar to the polar vortex winter of 2013/14 (as New Englanders can attest battling record snow and cold throughout the period). 

While WSI projects 2,540 December through February GWHDDs this winter, a panel of forecasters at Scudder Publishing’s recent Winter Tealeaves conference in Houston leave a 30-35 percent chance of positive Artic Oscillation (AO) numbers.  A positive AO is often conducive to polar vortex occurrences, particularly in the Midwest and Northeast regions of the country.  Though slim, a sudden change in the weather pattern over the densely populated Northeast could shift natural gas prices upwards, leaving power burn demand slightly neutered as the cost of marginal gas-fired power plant increases.  In this regard, a repeat of winter 2014/15 weather related demand would look like the chart below

Source: PointLogic Energy

In this scenario, Mexican exports would look the same as scenario one, because much of this gas is sourced out of Texas and the Southwest.  PointLogic is assuming a slower ramp up in LNG exports due to a weather influenced increase in price at Henry Hub and the fact that Cheniere recently announced that commercial deliveries of LNG would not commence until April 2016. 

While it is believed that commissioning cargoes could roll off of Train 1 by late December, the average amount delivered over the course of winter 2015/16 would be slightly lower than EIA’s projection of 0.5 Bcf/d.  All told, eliminating the decrease in res/comm demand in this scenario would leave total demand at a 1.2 Bcf/d premium to winter 2014/15. 

Scenario #3: PointLogic Expectations

PointLogic Energy’s view of 2015/16 winter demand comes in somewhere in the middle of scenarios one and two.  With a 65-70 percent chance of a warmer winter than 2014/15, res/comm demand is down 2.0 Bcf/d winter-on-winter, while power and industrial demand continue to climb higher due to depressed natural gas prices.  Mexican exports and LNG retain their gains resulting in a total demand increase of 0.7 Bcf/d winter-on-winter.  

Source: PointLogic Energy

Regarding power demand specifically, this September as temperatures waned into neutral territory, PointLogic’s nomination data and estimated total deliveries did not ratchet down as expected.  Total power demand remained at an average of nearly 28.0 Bcf/d, or 2.2 Bcf/d higher than September 2014 levels.  The first two weeks of October have also seen elevated power burn levels averaging 1.0 Bcf/d above October 2014. 

On the supply side of the equation, PointLogic’s production forecast predicts a 1.8 Bcf/d winter-on-winter gain due to expanded infrastructure options for producers in West Virginia and Ohio portions of the Marcellus and Utica, along with smaller but steady dry production increases in the Northern Rockies and Permian basins out west.  When all three demand scenarios are laid out against this production forecast, the results can be visualized in the below graphic.

Source: PointLogic Energy

To visualize the impact on storage withdrawals over the course of the winter, the below chart plots our base level storage assumption of over 4,000 Bcf of natural gas available at the end of injection season 2015 and plots the corresponding scenario inventory levels.

Source: PointLogic Energy

Using EIA’s demand projections from the STEO nets a storage inventory level of 2,100 Bcf, while the lower bound is set at 1, 970 Bcf with a repeat of the winter 2014/15 winter.  The PointLogic estimate comes in squarely in the middle at 2,040 Tcf.  All three of these scenarios fall within the upper third portion of the range of actuals seen over the past five years, and regrettably for producers, all signal a continuation of depressed natural gas prices going into the summer of 2016. 

Lower Production Impact on Storage

So what if production levels do not pan out the way PointLogic envisions? While we are confident in our forecast, activity in specific basins comes down to individual producer decisions, who have been battered by low prices, capital expenditure reductions and falling rig counts all summer long. 

While evidence that rigs left drilling in the field are the most efficient and best of the fleet in terms of productivity and costs, another few months of depressed prices could lead producers to reduce the pace of new drilling even further until higher prices materialize.  Publications like EIA’s Drilling Productivity Report have alluded to this scenario and our own analysis of incremental flows on pipeline expansion projects have seen lower fill rates than prior rushes to fill capacity. However, a large inventory of drilled but uncompleted wells may keep production levels healthy if and when producers decide to bring that production to market.  

Lowering the production forecast to a more pedestrian 0.8 Bcf/d increase in winter 2015/16 compared to winter 2014/15 takes an incremental 150 Bcf of storage gas out of caverns over the course of November through March and results in the below storage inventory levels detailed below.

Source: PointLogic Energy

Final Takeaways

The range of end of March 2016 storage inventory estimates remains fairly tight in all of the scenarios laid out above.  In an attempt to be predictive, but pragmatic at the same time, PointLogic estimates that unless prevailing weather patterns change significantly and production slows down considerably, storage inventories at the end of March 2016 will remain near 2,000 Bcf. 

This level of inventory should set prices up nicely for consumers in the summer of 2016 while continuing the woes experienced by producers during the summer of 2015.  Stay tuned as we update our forecast based on the facts on the ground and plot out the trajectory and final landing spot of storage inventories throughout the winter season.

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