Natural Gas: Is The Injection Season Already In The Rear View Mirror?

by: Richard Zeits

As the injection season for natural gas is moving closer to its finish line, the next several weeks' storage statistics will be in the center of many analysts' attention. However, one could argue that, from the gas price perspective, the storage statistics this season will be of relatively minor importance.

Latest data

As of September 7, 2012, working gas in storage for the Lower 48 States stood at 3,429 Bcf, according to EIA estimates. Stocks were 342 Bcf higher than last year at this time and 284 Bcf above the 5-year average of 3,145 Bcf. By region, the surplus relative to 5-year average was 80 Bcf in the East Region, 147 Bcf in the Producing Region, and 57 Bcf in the West Region.

To estimate potential outcome for this year's injection season, it is helpful to review historical storage data.

When does the injection season end?

The date by which working gas in Lower 48 storage reaches its peak varies from year to year depending on the weather pattern during late October and November. Based on my review of EIA data, during the past ten years (2002-2011), the earliest date when the peak reading for aggregate working gas in storage was achieved was October 20 (2006) and the latest was November 27 (2009). The rate of injection slows in mid-October as heating demand starts to kick in.

As of this date, there are approximately eight weeks left of this year's injection season, of which the next six are likely to be the most impactful.

How much gas is typically put into storage between now and the end of the injection season?

The graph below shows the aggregate increase in the Lower 48 working gas in storage from the first week in September through the week when the storage reading peaked.

As shown in the graph, the highest amount injected, 740 Bcf, was last year, and the lowest, 317 Bcf, was in 2002. The ten-year average injection was approximately 510 Bcf. It would probably be appropriate to "normalize" the injected amounts by using "percentage full" metrics, as the size of the storage system has grown substantially during the past ten years. The "normalized" average would be greater than the 510 Bcf simple historical average.

By adding the ten-year low and ten-year high amounts to the current storage level, one would arrive at this year's end-of-season gas in storage possible range of 3,746-4,169 Bcf. The low end of this range would be approximately equal to the five-year average and would be "sufficient" given the industry's demonstrated ability to ramp up production in a short period of time once the price stimulus is there. On the other hand, the upper end of the range (improbable given the current injection rate, as discussed further) would come close to the physical limits of available storage capacity in some regions and put downward pressure of the spot gas price during October and November.

How does current rate of injection compare to last year's?

The dramatic decline in natural gas prices during the first half of this year has translated into reduced storage injection rates during this summer (as visible from the first graph: a flatter storage injection curve, shown in red, during the summer 2012 period relative to the same period last year). The 908 Bcf storage surplus relative to the five-year average as of April 27 this year has declined to 284 Bcf surplus as of September 7. While the decline can in part be attributed to the hotter-than-average summer, the largest factor is the estimated 3-4 Bcf/d average year-on-year reduction of the production surplus over weather-normalized demand. Assuming that the injection will continue through the end of this season at a rate which is 4 Bcf/d lower than last year, the storage would peak this year at approximately 3.9 Tcf, similar to last year's level.

How much spare storage capacity is left this year?

EIA estimates total working gas storage capacity ("design capacity") for the Lower 48 states at 4.5 Tcf as of April 2012. It is important to note that, according to EIA data, total Lower 48 design capacity increased by 110 Bcf from April 2011 to April 2012, and therefore natural gas storage likely has extra 100 Bcf of headroom this year relative to last.

At the peak, actual amount of gas stored in the system is below the aggregate design capacity (not all the facilities are full at the same time). EIA uses the concept of "demonstrated peak capacity" which is the sum of the highest storage inventory level of working gas observed in each facility over the prior 5-year period (as reported by the operator on the Form EIA- 191M "Monthly Underground Gas Storage Report").

EIA estimates that the demonstrated peak working gas capacity for U.S. underground working natural gas storage for the Lower 48 states was 4,239 Bcf as of April 2012, a 3%, or 136 Bcf, increase from April 2011. Most of the increase came in the form of more use of traditional storage in the West (56 Bcf) and salt cavern storage in the Producing region (58 Bcf). Salt cavern storage allows rapid injection and withdrawal to respond to market conditions and other short-term events. Demonstrated peak working natural gas in the East rose by only 14 Bcf (less than 1%), but this small increase coincided with the rapid growth of production from the Marcellus Shale.

What are the implications for natural gas prices?

This year's injection season is largely in the rear view mirror. Given the much reduced production surplus relative to apparent demand, the 100 Bcf expanded storage capacity and operators' demonstrated willingness to shut in production rather than sell gas at uneconomic prices, in my view, there is little risk that a storage crunch will occur this year. The next two-three weeks should resolve the remaining uncertainty. While the storage "overflow" is unlikely, so is the substantial price recovery until November. As significant production volumes remain curtailed, subdued natural gas prices will be needed to avoid the acceleration of shut-in amounts before the end of the injection season.

The market already seems to be looking beyond November and focusing on the supply/demand fundamentals for 2013. The critical question remains, what gas price will be required to motivate operators to put some additional rigs to work in dry gas shales. Looking at the NYMEX futures, the market seems to believe that $3.50-$4.00/MMBtu should be sufficient for a "soft rebalancing" of supply and demand in 2013.

This discussion of natural gas fundamentals bears relevance to natural gas producer stocks. My natural gas producer index includes:

  • Chesapeake Energy (CHK)
  • EnCana Corporation (ECA)
  • Devon Energy (DVN)
  • Southwestern Energy (SWN)
  • Ultra Petroleum (UPL)
  • EXCO Resources (XCO)
  • WPX Energy (WPX)
  • Cabot Oil & Gas (COG)
  • Range Resources (RRC)
  • QEP Resources (QEP)
  • Quicksilver Resources (KWK)
  • Forest Oil (FST)

Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.