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A V-Shaped Outlook for Natural Gas Production and Prices

March 2, 2016 | By Charles Nevle

Despite a significant drop in operating rig counts and hydrocarbon prices over the last 18 months, U.S. dry natural production averaged a record high of 74.6 billion cubic feet per day (Bcf/d) in February 2016.

A couple of weeks ago, PointLogic Energy analyst Jack Weixel laid out a compelling argument in the Get The Pointarticle The Winter that Never Was and the Summer that Could Be. The argument is essentially this – given extremely high storage inventories likely to exist at the end of this season, the market is limited as to how much can be injected over this summer.

One way to think about it is this: The lower 48 gas market began April 2015 with 1,485 Bcf of storage, and companies injected a net 2,524 Bcf by the end of October 2015 to arrive at an-end-of-summer inventory of 4,009 Bcf.

Now, let’s look at this year. PointLogic Energy is projecting that the domestic gas market will have an 885 Bcf head start compared to last April, assuming a March 2016 ending inventory of 2,370 Bcf. If we were to theoretically inject the same volume as summer 2015, we would have an ending inventory of 4,894 Bcf. This is well beyond the limits of storage capacity. Thus, we must inject less this summer. Assuming an operating inventory capacity of between 4.2 and 4.3 trillion cubic feet (Tcf), we would need to inject 694 less Bcf this summer than last summer, or 3.2 Bcf/d less every day between April 1 and Oct. 31.

As pointed out in the Feb. 17 Get the Point, our view is that the market will achieve this lower injection rate by a combination of higher demand than last summer and reduced production. On the production side, we're projecting a reduction from the current 74.6 Bcf/d level to an average of 73.3 Bcf/d over the summer of 2016, equivalent to production last summer. Because this decline will come gradually, end-of-summer production will have to be much lower than the overall summer average. For example, if production starts to decline in March, our forecast shows that production will need to average 72.6 Bcf/d for October 2016.

Of course, the longer the market waits to slow production the steeper the decline has to be -- and the lower the October production needs to be to keep the market within storage limitations.

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One could characterize this as a ‘supply push’ driven summer pricing market: Too much production exists, so prices will have to fall enough to incentivize the market to balance through a combination of increased demand and lower supply. Currently Henry Hub cash prices in the $1.70/Btu ballpark don’t seem to be accomplishing this feat, which implies that the price of natural gas may have to fall even lower over the summer.   

The Other Side of the V

The implications of this supply/demand picture go well beyond summer 2016, and there might be some better news as soon as next year. The story for 2017 is shaping up to be vastly different than 2016 for natural gas, what we are calling a "V-Shaped" recovery. In 2017 we should start to see some real new demand hit the market in the form of liquefied natural gas (LNG) exports as well as increased capacity to Mexico. And that will create incentives for production to rise again.

According to PointLogic’s Pipeline Projects database, projects totaling 2.8 Bcf/d come on line in Mexico in 2016, while a whopping 12.6 Bcf/d could come on line 2017. On the U.S. side of the border, we are tracking 12 projects aimed at taking gas into Mexico totaling over 10 Bcf/d (with over 7 Bcf/d slated to come online in 2017).

While we do not necessarily expect all of that capacity to pour into Mexico in 2017, we do expect 2016 exports to be higher than 2015, and 2017 to be higher than 2016 (see graph below). The Mexican Energy Ministry, SENER, expects natural gas demand in Mexico to increase by 0.3 Bcf/d in 2016 and 0.5 Bcf/d in 2017. While the government expects much of this increased demand to be met by increasing domestic production, this is a big assumption as it goes against the trend of Mexican gas production over the past several years.

In addition, nearly 1 Bcf/d of LNG is imported into Mexico. As pipelines are built to take gas from the U.S. to Mexico and infrastructure is built out in Mexico, it seems there would be a strong incentive to displace expensive LNG imports with much cheaper pipeline gas imports from the U.S.

In 2015, we saw gas exports to Mexico rising 0.9 Bcf/d, an impressive 46% over 2014 levels. We expect 2016 exports to rise another 0.8 Bcf/d, or 26% over 2015. Assuming a conservative 10% increase in exports in 2017 over 2016, that implies another increase of 0.5 Bcf/d in summer 2017 over summer 2016.

Exports to Mexico

In terms of LNG, total Lower 48 liquefaction capacity is on track to increase to an average of 1.3 Bcf/d in 2016 and 3.8 Bcf/d in 2017. We expect actual gas demand at the export facilities to grow to 0.9 Bcf/d in 2016 and 2.9 Bcf/d in 2017, with an incremental 2.5 Bcf/d for summer 2017 over summer 2016. This works out to an annual average utilization rate of 69% in 2016 and 76% in 2017 (see graph below). 

US Lower 48 LNG Liquifaction Capacity Through 2016

Impact on Storage

The developments described above also have an impact on gas storage in the U.S. The market is coming out of this winter with an extremely high storage balance, which will restrict the amount of gas that can be injected this summer. PointLogic forecasts the U.S. will inject 1,845 Bcf over the summer of 2016 compared to a 7-year average of 2,181 Bcf. That calculates out to a differential of 1.6 Bcf/d LESS injections during the 214-day summer season.

Even with this reduction, PointLogic’s forecast provides an end of summer inventory of over 4.2 Tcf, by far the largest balance on record.

If we restrict the storage balance to 4.1 Tcf, that increases the needed daily reduction in storage injections to 2.2 Bcf/d below the 7-year average (see table below).

Storage Balance

When we assume no change in summer 2017 vs. summer 2016 demand for power, industrial and residential/commercial and add the incremental demand for exports to Mexico, LNG exports and incremental storage injections, this yields an increase of 4.6 Bcf/d in total demand (see below). 

Summer 2017 vs. Summer 2016

This indicates a significant tightening of the market next year. That incremental 4.6 Bcf/d of demand needs to be met by supply, which by a large measure, must be met by lower 48 dry gas production. One could theorize that other sectors of demand could be lower, notably the power sector, but let’s leave that alone for now as some in the market believe that 2017 power demand will be significantly greater than 2016.

PointLogic is forecasting average summer 2016 production of 73.3 Bcf/d. Adding the incremental demand calculated above indicates that summer 2017 production must equal 77.9 Bcf/d in order for the market not to run short natural gas. That’s a big number, and it would possibly be partially covered by some drawdown in storage.

Turning those numbers into monthly average production (see below) gives a better picture of the true impact. This is the “V” shaped line that shows how market forces could breathe new life into gas production in summer 2017.

Dry Natural Gas Production

In order to achieve average summer 2017 production of 77.9 Bcf/d from the starting point of October 2016 at 72.6 Bcf/d, PointLogic projects that production will have to rise to 79.6 Bcf/d by October 2017. Ironically, the longer production takes to decline this summer, the more steeply production will have to drop to stay within storage limitations, but then the more quickly and higher it will need to grow in 2017.

So, what we have are two dramatically different stories for natural gas in 2016 vs. 2017.

  • For 2016, the story is the market needs to send a bearish enough price signal to push production lower to balance a market facing storage capacity limitations in October 2016.
  • For 2017, the story is the market needs to send a bullish enough signal to increase production (or push off enough demand) to satisfy new LNG export and Mexican export appetites.

In both cases, it is up to production to balance the market. And production responds to prices eventually.

How strong do prices in 2017 have to be in order to achieve this production growth? That’s a difficult question to answer – but think about it like this – the above story implies an increase of 4.6 Bcf/d of production for summer 2017 over summer 2016. That’s record production growth. By comparison, at its peak, lower 48 dry gas production increased by only 2.9 Bcf/d between the summer of 2014 and summer of 2015.

Keep in mind, too, that a lot will depend on the price of oil and drilling incentives in plays with significant amounts of associated gas. In other words, if oil prices and oil/NGL drilling activity remain depressed, then gas prices will have to increase enough to incentivize significant investments in dry gas production basins. However, if we see higher oil prices and significant growth in activity from associated gas plays, then the gas price increase will not need to be as high.

What is clear is that because of the necessity of decreasing production this year, a significant turnaround will be needed in 2017 to satisfy demand growth. Surviving 2016 will be a test for many production companies of different makes and sizes. Those with capital remaining and resources at the ready in 2017 should fare well because they can quickly respond to systemic demand and utilize the significant amount of new pipeline capacity to take new production to market.

Last week’s Get The Point discussed the increased production out of the Northeast being unleashed by several new pipeline projects. In upcoming issues of Get The Point we will discuss how the Lower 48 can meet the challenge presented by the 2017 demand story. Stay tuned!


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