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Gut Check Part II: A Closer Look at Summer 2017 Power Demand

July 19, 2017 | By Jack Weixel

This week marks the halfway point for the summer injection season – 16 weeks down since the start of April, 15 weeks to go until the end of October. This edition of Get the Point looks at natural gas demand for power and how this important sector has affected total domestic demand through the first half of summer 2017. PointLogic’s definition of domestic demand includes the power, industrial and residential & commercial components of demand. In the summer, power demand is the largest component of the three, and it has the most influence over price, storage levels and the supply and demand balance as the market approaches winter.

Given where we stand today and what we can anticipate, PointLogic will forecast what to expect out of power and domestic demand over the second half of the summer. 

Domestic demand in summer 2017 has been squarely down over the past 16 weeks compared to summer 2016, averaging just above 57.2 billion cubic feet per day (Bcf/d) through July 17. This is predominantly due to higher Henry Hub prices resulting from faster year over year non-power demand growth relative to growth in supply. The first half of summer 2016 saw a much more vibrant domestic demand that set a record high average of 60.7 Bcf/d as growing production collided with record storage surpluses to put downward pressure on prices.

Source: PointLogic Energy Supply & Demand

Domestic demand in the first half of summer 2016 exceeded the 5-year average by 3.4 Bcf/d, primarily driven by high power demand, which in turn was influenced by lower relative prices of natural gas for electricity generation. Power demand accounted for 3.2 Bcf/d of the domestic demand increase vs. the 5-year average.   

Source: PointLogic Energy Supply & Demand

Preceding this summer, PointLogic and other analysts largely anticipated a drop off in power demand from last year because natural gas prices are higher this year. The pace of supply growth and the size of the resulting dropoff in demand were at question. 

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While pipeline expansions to relieve pipeline constraints in the Northeast and a slow ramp-up of associated gas production left supply relatively static to the prior summer, increased exports (Mexico and LNG) along with higher storage injections relative to last year meant that Henry Hub was short gas and exposed to summer weather. Higher prices to conserve South Central storage inventories led to power demand through the first seven weeks of summer 2017 that lagged summer 2016 by just 1.3 Bcf/d, but this was just the warmup.  Over the next nine weeks, summer 2017 power demand has fallen behind last year by nearly 3.3 Bcf/d, as last year's demand accelerated during this time. 

For the entire first half of summer 2017, power demand has averaged 26.9 Bcf/d and resides 2.4 Bcf/d lower than summer 2016 levels through the same date. While this 2017 level is about 0.8 Bcf/d above the 5-year average and is higher than the halfway mark of summers 2013-2015, it lags behind the famously hot summer of 2012 by about 1.4 Bcf/d, when gas first began to penetrate the coal stack due to a lower relative price. 

Weather and Price Impact

On a cooling degree day (CDDs) basis, the first half of summer 2017 has had nearly 393 CDDs. Despite power demand being lower than a year ago, the summer of 2017 has produced more than 44 additional CDDs than a year ago, an increase of 16%. Absolute population-weighted temperatures for summer 2017 to-date are 68.7 degrees Fahrenheit, compared to summer 2016 to-date temperatures of 68.3 degrees.  

Source: Statweather and PointLogic Energy

The point is worth emphasizing: Despite the fact that it has been marginally warmer on average through the first half of summer 2017 compared to summer 2016, there has not been enough severe heat to generate an increase in gas-fired power demand. 

What happened? Quite simply, the price of natural gas increased this year.

Last year, natural gas prices at Henry Hub averaged $2.19/MMBtu through the first half of summer, touching bottom at $1.71/MMBtu from April 16-18 and topping out at $2.93/MMBtu on June 16. This summer, Henry Hub has averaged over $0.84/MMBtu more at $3.03/MMBtu, hitting a low of $2.83/MMBtu from June 3-5 and a high of $3.27/MMBtu on May 16.  

Source: PointLogic Energy

With a 150 Bcf inventory surplus to the 5-year average in the South Central, storage has provided about 3.0 Bcf/d of a supply cushion for the hot periods of late July and August, while production has finally begun to increase relative to last year, allowing Henry Hub cash prices to fall below $3.00/MMBtu. This has resulted in prices from the two summers converging (see graph above), signaling that modest changes could be underfoot after summer heat reaches its full potential sometime in the next few weeks. On July 12, power demand hit 37.4 Bcf/d, which on a historical basis is the 30th highest power demand number of all time (although it should be noted that the top 30 list includes 24 days from either July or August 2016).

One of the most significant obstacles for natural gas this summer has been its price compared to the price of coal. While natural gas prices have risen by roughly 30% year on year, coal prices generally have not risen as quickly and U.S. coal supply is anticipated to grow faster than utility consumption rates in 2017.

Source: IHS Markit and PointLogic Energy

As the chart from our colleagues at IHS Markit illustrates, the price of natural gas this summer has only been competitive with CAPP (Central Appalachia) coal and NAPP (North Appalachia) coal and is still more expensive than NAPP coal delivered to the PJM electric power market, one of the largest in North America. What this chart doesn’t show is that PRB (Powder River Basin) coal makes up nearly 50% of utility coal consumption in the U.S., while NAPP and CAPP coal combined constitute less than 30%.  

By contrast, the average price of natural gas in the first half of summer 2016 was competitive with every ton of coal delivered to any electric power market, with the exception of PRB coal delivered to the West Coast. In sum, there is less incentive to burn natural gas over coal this summer compared to last summer.  

Expectations for the Balance of Summer 2017

As summer 2017 gas prices have come more in line with late-summer 2016 prices, will power demand levels continue to falter? To answer that question, we must look at both weather and price to account for any extreme scenarios that could push power demand levels in any one direction. 

From a weather perspective, the National Oceanic and Atmospheric Administration’s (NOAA) Climate Prediction Center expects that the months of July, August and September will be relatively warm in most regions of the country compared to the 30-year normal (observed temperatures from 1981 to 2010). 

Source: National Oceanic and Atmospheric Administration, Climate Prediction Center 

Comparisons vary, however. When compared to more recent 10-year normal weather averages, the differentials do not look as severe. In the chart below from our partners at Statweather, we feature their 90-day forecast compared to 10-year normal weather on a cumulative basis at over 125 temperature stations across the Lower 48.

Source: Statweather and PointLogic Energy

The deltas between the forecast and the 10-year normal are relatively minor until mid-September, when forecast temperatures begin to exceed the 10-year normal by more than 200 cumulative degree units. However, absolute temperatures are lower in mid-September than at the height of summer in July or August. By that time, most of the potential for large swings in power demand will have passed because a degree-day change at a lower absolute temperature level becomes less significant.    

So what about price? While prices are never set in stone, the forward market gives a fairly good diagnosis of what the market expects to occur over the near term.  

Source: NYMEX/CME and PointLogic Energy

PointLogic’s assessment of Henry Hub spot prices over the balance of summer 2016 (July 17 through Oct. 31) was an average price of $2.87/MMBtu. As of July 17, the forward curve is showing an average of $3.03/MMBtu for the months August through October, a 16-cents differential to the balance of last summer. 

More importantly, summer 2017 gas prices would have to swing much lower than the forward curve indicates right now in order to compete against coal in most locations. At an average forward price of $3.03/MMBtu, prices would have to move down by 30 cents (10%) in quick order to become competitive with PRB coal and take over a significant amount of generation share across the country. 

In Conclusion

The ultimate arbiter of natural gas price is storage. That said, are there any serious influences on storage besides power and domestic demand that could upset its relative status between now and Oct. 31.

Certainly, production could increase more rapidly than currently anticipated and force prices down as more supply enters the market. Alternatively, LNG or Mexico export demand could crater from their recent high levels, which would bring down prices as excess gas searches for a new home. 

At the moment, PointLogic does not foresee any significant risk of any of these events occurring. Storage inventories will erode versus the 5-year average due to a more subdued production recovery until further pipeline capacity is opened up in the Northeast U.S (see our Northeast Production Resurgence Get the Point here). While LNG exports are prone to short-term disturbances, feed gas deliveries to Sabine Pass should remain steady through October, as a surplus of storage gas in the EIA Southeast storage region provides plenty of room for gas to be moved offshore. In addition, Train 4 at Sabine Pass will begin taking feed gas in anticipation of its commercial operation start-up in just a few months.    

In our Two Season Natural Gas Supply and Demand Balanced Forecast, PointLogic has projected that power demand will average 27.8 Bcf/d for all of summer 2017. This is 2.4 Bcf/d below summer 2016 levels. Total domestic demand for summer 2017 will average 57.3 Bcf/d, or about 2.5 Bcf/d below summer 2016 levels. 

Source: PointLogic Energy Two Season Supply and Demand Forecast

Stay tuned to PointLogic as we continue to monitor power burn levels on a daily basis throughout the summer. We'll also be on top of changes to storage, production and exports on a regional level that will affect the fundamentals balance going forward.  

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