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Making the Case for a Summer Demand Frenzy

May 27, 2015 | By Jack Weixel

Shift in Supply of Natural GasThe natural gas market appears complacent enough at the moment to sit at $3.00 per million Btu (MMBtu) with some certainty that this summer will be weak from a weather perspective. But what about other sources of demand and systemic increases seen in the power sector, the industrial sector, and Mexican exports?  In this week’s Get the Point, PointLogic Energy will paint a picture of a scenario where demand overruns supply this summer, in part motivated by lower prices, but ultimately the result of a slow storm that has been brewing for some time, fed by abundant production and methodical, incremental additions to base levels of demand in every sector. 

The PointLogic Energy Supply & Demand chart below can reveal a few subtle clues as to the behavior of demand through the first 55 days of summer injection season.


Supply vs. Demand

Three sectors of demand stand out from a seasonal perspective, with power burn leading the way, up nearly 2.0 billion cubic feet per day (Bcf/d) versus last summer. Industrial demand is also significantly stronger at a 1.6 Bcf/d premium.  Mexican exports continue to show historic resilience, as we pointed out a few weeks ago, averaging near 2.5 Bcf/d in April and May, a 0.6 Bcf/d increase over the same time period last year. What do these season-on-season balances mean for the rest of the summer? Could this be a sign that a notable sustained shift in the demand equation is underway?

In the power sector, lower gas prices and natural gas fired power plants consistently burning as base load power providers has led to this increase. At a sub $3.00 price in the summer of 2012, the U.S. gas market witnessed coal to gas switching amounts up and over 5 Bcf/d compared to a 2010 base year. These amounts were even higher compared to a 2007 base year. This summer, while coal to gas switching may still occur, the instances happen on a much less frequent basis, simply because there is less coal around to displace. Regardless of the cause, power demand is up in every region of the country through April and May compared to the same time period last year.  

Average Delta Power Burn

The Southeast and Gulf Coast Onshore region (which includes Louisiana and much of the Texas Gulf coast) are up over 0.6 Bcf/d. These regions typically have some of the highest costs to ship coal to coal burning plants, but also happen to have some of the newest installed combined cycle gas plants in the country. Midcontinent power burn is up over 0.5 Bcf/d and is a typical haven for inexpensive Powder River Basin (PRB) coal, but clearly more gas-fired power plants are being dispatched in this region than ever before. In the Pacific Northwest (PNW), PointLogic observes that power burn is up near 0.3 Bcf/d season-on season, not necessarily due to the fact that gas is the cheapest alternative, but instead due to a poor hydro generation year in the region. The increase in gas demand in the PNW is directly stimulating an increase in Canadian exports on GTN Pipeline as well.

Week-on-Week Industrial Demand Delta Summer 15 vs. Summer 14In the industrial sector, demand is up season-on-season by a healthy 1.6 Bcf/d. This increase can also be attributed to a lower feedstock price for natural gas. A graph of week on week deltas this summer versus last summer shows a steady increase as the U.S. enters the last week of May. In last week’s Natural Gas Weekly, the EIA reported that it expects industrial demand to average 21.8 Bcf/d in 2015, over 0.8 Bcf/d higher than the average in 2014. There is reason to be cautious, however, with both the Dallas and Richmond Fed announcing this week that their manufacturing indexes are “soft” and “declining” for the month of May. The Dallas Fed adds that its manufacturing productivity index is now at its lowest level in six years.

But What about Production?

As was detailed in last week's Get the Point, there is evidence that lower 48 production has slowed over the course of 2015, failing to eclipse levels of December 2014 for five consecutive months. The chart below illustrates this development.

Lower 48 Dry Production

Gas wells first delivered by region are also down significantly in May, with PointLogic estimates pointing to a decline of 448 wells (40%) since January 2014. Future Get the Point articles will focus on production exclusively, with more detail by region coming over the course of the next few weeks.

But What about Price?

The spot price of natural gas has been has risen above $3/MMBtu on only two occasion since March 1, 2015 with both instances occurring early last week. This spot prices correlates very well with the level of natural gas in storage, with the EIA’s past two reporting week injections coming in well below market expectations. Could this be the sign of a pick-up in demand throwing off the markets collective sense of the supply and demand balance?

Henry Hub Spot Price

Prices are at their lowest level since the spring of 2012, but if production continues to slip in the face of increasing demand, how much longer can low prices last? To put everything together, PointLogic has revisited its supply and demand balance chart to project an end of season balance scenario with new season-on-season expectations.

Summer 15 Season Base Forecast

In the above scenario, PointLogic assumes that on the supply side, the fundamentals stay virtually the same. Production remains unfettered, but not growing, at 72.5 Bcf/d (which would be an increase of 2.2 Bcf/d compared to last summer). Canadian imports remain slightly higher than last summer, but slip slightly from current levels as prime hydro generation season wanes in the PNW. LNG sendout is only slightly impacted and remains close to its insignificant 2014 levels.

On the demand side, power demand increases to average 26.0 Bcf/d, a conservative estimate compared to summer 2012 levels, but still 2.1 Bcf/d higher than 2014 levels and the second highest burn average of all time. Industrial demand registers 21.5 Bcf/d, a 1.7 Bcf/d premium over summer 2014 and slightly shy of EIA estimates for the year average due to several facilities coming online in Q4 2015, as opposed to this summer. Res/com remains a non-factor barring an exceptionally cold October, while Mexican exports continue to pace above 2.6 Bcf/d, beating summer 2014 exports by 0.5 Bcf/d.

But What about Storage?

The net impact of all this prognostication and projection is a scenario where the current 3.1 Bcf/d long position at 55 days into summer shifts to a net short position of 2.0 Bcf/d for the entirety of the summer through October 31. This means that over the course of 214 days, the lower 48 will be unable to inject approximately 428 Bcf of natural gas in to storage due to a summer demand frenzy coupled with flat production.

Total net injections in the summer of 2014 smashed records, equaling 2,774 Bcf through October 31 (2,789 through November 7).  The next closest summer injection season with that sort of injection level was way back in summer 2003, with a pre-shale era net injection of 2,533 Bcf.

Assuming that 428 Bcf less gas is available for injection in summer 2015 compared to summer 2014, injections this summer would total 2,346 – comparable to 2004 injection levels, but lower than 2003 injection levels.

Summer Demand Impacts on Storage

With basic demand assumptions set, the lower 48 would end the 2015 injection season on October 31 with 3,899 Bcf in storage. This is over 150 Bcf higher than where the lower 48 would end up if this summer’s injections mimicked 5 year average injections, which would leave the lower 48 with 3,747 Bcf/d in the ground.

But What Does This All Mean?

The supply, demand and storage scenario laid out above means that there is significant tolerance for elevated levels of demand this summer, even with a production slow down. In fact, demand could exceed expectations laid out in this report and the market would still take comfort in knowing that storage will end near the 5 year average inventory mark of 3.8 Tcf. Demand could increase by 0.5 Bcf/d (107 Bcf incremental over 214 days of summer) over the assumptions laid out, moving the anticipated summer net short position to 2.5 Bcf/d. Such an increase would most likely occur in the power sector if prices persist below $3.00/MMBtu approaching summer 2012 levels of 27.9 Bcf/d. With the forward curve not showing a price above $3 until December 2015, the table is set for aggressive summer demand season and more than enough wiggle room to create a demand frenzy.

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