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The Winter that Never Was and the Summer that Could Be

February 17, 2016 | By Jack Weixel

This week's edition of Get the Point looks at what’s ahead in the U.S. natural gas market as winter 2015-2016 comes to a close and summer 2016 approaches. With low natural gas prices a fixture the past 18 months, either supply or demand will have to budge as the market has been long gas for the duration of winter. PointLogic Energy’s expectations for each component of supply and demand and the cumulative impact on storage inventories are detailed in the following paragraphs.  

How Did We Get Here?

At this date last year, if you had thought winter was finished, you would have been sorely mistaken. Storage withdrawals for the last two full weeks of February 2015 came in at 220 billion cubic feet (Bcf) and 229 Bcf, respectively. In two weeks, the natural gas market was suddenly relieved of nearly 450 Bcf of gas, even while production was averaging a relatively robust 72.2 Bcf per day (Bcf/d). Not coincidentally, the week of Feb. 23-27, 2015 was the last time that Henry Hub cash prices traded above $3.20 per million British thermal units ($/MMBtu).  

This February, forward weather forecasts are indicating relatively normal temperatures through the end the month, and with production hovering above 74.0 Bcf/d at the moment, PointLogic is anticipating withdrawals from storage will be at or below the five-year average for the duration of February. This will further extend the surplus in storage compared to last year.  

So where is the U.S. natural gas market situated now? A strong El Nino winter decimated natural gas demand, as mild weather saw average U.S. population-weighted temperatures increase about 4.3 degrees Fahrenheit this winter to-date compared to last winter. This warmth has resulted in dismal residential and commercial (res/comm) demand and declines in industrial demand (most recently discussed three weeks ago in Get the Point).  

Winter Supply and Demand

As shown in the graph above, power demand and Mexican exports are responsible for all of the season’s demand gains (LNG exports will soon start to make their mark, too). We’ve seen a total seasonal increase of 4.4 Bcf/d in those categories, which is not enough to counter the weather-driven declines in res/comm and industrial.

Impact on End of Season Storage

If this 3.5 Bcf/d gas surplus holds through the end of March, the net impact on storage withdrawals vs. last winter will be an extra 524 Bcf of gas left in the ground. Last year’s winter storage withdrawals equaled 2,086 Bcf, and this year’s projected winter withdrawals would total 1,562 Bcf, leaving end-of-season storage just shy of 2,370 Bcf.

Storage Inventory

Source: PointLogic Energy and Energy Information Administration (EIA)

This projected 2,370 Bcf of storage is about 100 Bcf below the highest recorded winter carryout ever, which came in 2012 at 2,474 Bcf.

In the near term, there’s not much chance that supply or demand will change significantly to affect the balance in February and March either up or down. Weather is always a variable, as the colder second half of February changed last year’s storage balance. Forward weather forecasts from the National Oceanic and Atmospheric Administration (NOAA) indicate that March temperatures will be above normal across most of the northern half of the lower 48. This does not bode well for a significant weather impact on March demand. 

Three-Month Outlook Temperature Probability

Source: National Oceanic and Atmospheric Administration (NOAA) Climate Prediction Center

The Summer that Could Be

Given the likelihood of a near-record winter carryout, summer 2016 will be pivotal for the U.S. natural gas market. Will we see a surge in power demand, Mexican exports and LNG? Will increased systemic demand be enough to support current production levels?

Assuming that storage inventories at the end of March are near 2,370 Bcf, something will have to give. That something is very likely a slowdown in lower 48 dry gas production, the main component of the lightning-fast increase to lower 48 supply witnessed over the past 7 years. The chart below illustrates the slowdown in season-on-season production gains already upon us. Last summer, production ran higher by 3.1 Bcf/d compared to the summer of 2014, but this winter-to-date that excess has narrowed to only a 0.8 Bcf/d increase.   

Lower 48 Dry Production

Source: PointLogic Energy

Admittedly, some of the pullback in production was due to unforeseen freeze-offs that occurred in parts of Texas at the end of December 2015. However, we’ve seen that production rebound, and so we’re still left with an unsustainable current level of production.

If production were to average current February levels above 74.0 Bcf/d through the summer, storage inventories would balloon past the physical limits of storage facility operating capacity. The Energy Information Administration (EIA) dubs this capacity limit as "demonstrated maximum working gas capacity," and it is estimated to be about 4,336 Bcf as of November 2014. If 2016 production averages 74.0 Bcf/d through the end of October, storage inventories could surpass 4,500 Bcf, based on PointLogic’s demand assumptions detailed below. There is simply not enough room for that amount of natural gas.

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PointLogic expects total lower 48 demand to average 70.2 Bcf/d in the summer of 2016, or about 3.0 Bcf/d higher than summer of 2015. Our demand expectations anticipate summer-on-summer increases in power burn, Mexican exports and LNG exports. Power burn should eclipse summer 2015 levels by 1.3 Bcf/d, though this amount of power burn from natural gas will be challenged by excessive coal stockpiles at many power stations across the country, which the EIA reports ended 2015 at a six-year high. The price of natural gas still makes the fuel very competitive to burn, so fuel switching could be a significant driver of demand as it has been in years past. Contribution from the industrial and res/comm sectors this summer are negligible, particularly as industrial demand regains some of its footing after a dismal 2015 performance.

Mexican and LNG exports will play a crucial role, and there are some promising developments. For example, OneOK’s Roadrunner Border Crossing Segment will come online next month. While it only travels less than a mile, its impact will be significant as it has the capacity to transport up to 870 MMcf/d of gas from Texas to San Isidro, Chihuahua, Mexico, under the Rio Grande.

Also, two expansions in Mexico will enable more gas to flow from the U.S. The Los Ramones Phase 2 South project is projected to come online in June of 2016, with capacity of 1.4 Bcf/d, which will extend the existing Los Ramones pipeline system farther into southern Mexico. Following that project, the Topolobampo pipeline will carry up to 670 MMcf/d of gas from Chihuahua into the state of Sinaloa.

As for LNG exports, the commencement of service on the Sabine Pass Train 1 has taken an average of 47 MMcf/d off the grid since Nov. 10, 2015 and peaking on Feb. 16, 2016 at 486 MMcf/d. With the commencement of service on Train 2 scheduled for June 2016, PointLogic is anticipating average demand from the facility to increase to 0.9 Bcf/d over the course of the summer. 

Lower 48 Demand

Source: PointLogic Energy

Nonetheless, with the high storage inventories exiting winter, these small gains in demand will not offset the established highs of production. Instead, the question shifts to how much of supply will have to be taken offline in order to balance the market?

Production Pain Imminent

During the month of February 2016 to date, dry production has averaged nearly 74.4 Bcf/d, with several producing areas establishing new high-water marks every day. As recently as Feb. 12, production in the Northeast broke through the 22.0 Bcf/d mark, driven by record volumes out of the Utica (above 3.7 Bcf/d). To provide some perspective, Utica production averaged only 2.0 Bcf/d for the month of February 2015 and 0.8 Bcf/d in February 2014. Texas production has also rebounded from late December freeze-offs to average 19.7 Bcf/d this month.

Provided below is our forecast of 2016 production – with the key point that total lower 48 dry production slips to average 73.3 Bcf/d for the summer of 2016, an amount equal to its average in summer of 2015. The good news is that the production train does not have to come crashing to a halt in order balance the market. The warning is that year-on-year and season-on-season production gains have to decrease significantly in order for storage levels not to exceed their physical capacity. 


Dry Production Forecast

Source: PointLogic Energy

In future editions of Get the Point, we will look more closely at which producing areas of the country will be most likely to retreat in order to make this forecast come to light. In general, we can expect that the production pain will be felt deepest in areas of the country with the most expensive drilling operations and least efficient recovery times.

To round out the production picture, our 2016 summer supply forecast estimates that Canadian imports to the U.S. will increase by about 0.2 Bcf/d and that LNG imports will continue to waffle just below 0.2 Bcf/d, falling slightly below summer 2015 levels.

Canada's situation shows that the oversupply situation in gas is not just a local problem. In Canada, Enerdata storage estimates put inventories at about 72.0% full as of the first full week of February, compared to 48.0% full one year ago. Using these estimates, the warm winter has caused decreased storage withdrawals of about 185 Bcf compared to last winter, or about 1.9 Bcf/d less withdrawn through the first 97 days of the season. If that trend continues, Canadian inventories will equal about 434 Bcf by the end of March, or about 57% full. With the need to export natural gas to the U.S. never greater, Canadian gas will price itself into lower 48 markets, particularly in the West and Midwest regions, where it will compete head to head with Rockies, Panhandle and Northeast production gas.

Storage Balancing Act

With flat production, increased Canadian imports and declining LNG imports, PointLogic estimates that total supply in the lower 48 will increase by 0.1 Bcf/d in summer 2016 vs. summer 2015. We anticipate that demand will increase about 3.0 Bcf/d, putting the summer net short natural gas by a little less than 2.9 Bcf/d, compared to the same period in 2015. Over the course of 214 days of summer, this equates to 612 Bcf less gas available to inject into storage.

In summer 2015, injections into storage eclipsed 2,524 Bcf, carrying storage inventories to a record carryout of 4,009 Bcf as the injection season extended three weeks into November. In contrast, PointLogic estimates that storage injections for summer 2016 will only total 1,912 Bcf. This would still put end of injection season inventory at a robust 4,281 Bcf, as detailed in the chart below.

Storage Inventory

Source: PointLogic Energy and EIA

The amount of gas we're projecting to be on hand at the end of injection season is unheard of, but still within demonstrated maximum working gas volumes observed by the EIA. Few analysts saw last year’s storage logjam materializing this early, nine months out from its initial inception. But the forces of supply and demand netted out a record inventory at the end of summer last year, and it appears this year the same situation could play out, but at an even higher total storage.

If the market is uncomfortable with this amount of storage at the end of summer 2016, there are some solutions that can be implemented: increase demand, or find areas to make further cuts to production. In our balanced forecast, PointLogic has tried to estimate reasonable approximations for both supply and demand. Actual numbers may vary, but the truth of the matter is that this summer must be net short gas compared to last summer. With increases in natural gas demand limited, gains from production must slow down.

Stay tuned to PointLogic’s Get the Point as we monitor the supply and demand situation and our early projection for storage over the course of summer.


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