Another heating season looms just ahead. Already in some northern states, furnaces kick on as the first chilly mornings of fall 2014 arrive.

Heading into this summer, many industry observers anticipated that gas storage reloading would be an issue since storage capacity was drawn to its lowest level in years by the bitter 2013 to 2014 winter. However, summer 2014 has been mild and record production levels have resulted in the storage deficit quickly closing the gap between the winter drawdown and summer injection.

That’s good news for natural gas customers. Gas-in-storage levels are returning to near-normal levels after falling off a cliff early this year due to record customer drawdowns. The U.S. Energy Information Administration (EIA) estimated that gas storage volumes were more than 50% below normal at the end of the last heating season.

The fact that storage levels are approaching normal surprises midstream observers, many of whom feared low gas in storage would linger over into the winter just ahead.

Observers credit several trends for the favorable direction but most cite the cool summer as the primary reason. The same phenomenon that caused the problem—cooler-than-average weather—has helped solve the problem. Summer 2014 has been cool, bringing a lower power demand as millions of air conditioners sat idle or ran infrequently. As a result, a considerable volume of produced gas went underground rather than to power plant burner tips.

Cool summer

Richard Hastings’ job as macro strategist for Global Hunter Securities requires him to monitor weather trends closely. He shared a personal anecdote with Midstream Business that Charlotte, N.C., where he is based, has had summer days that topped out in the high 60s. “That’s unbelievably cooler than normal,” he added. Meanwhile, normally steamy Houston recorded one August day with a high in the low 80s—not much warmer than some typical, midsummer overnight lows in the Bayou City.

It looks increasingly like this storage deficit will not be very sizable by the time the injection season ends. The EIA is projecting a record level of injection with close to 2.6 trillion cubic feet (Tcf) of gas being put into storage this summer.

“We’re projecting a normal winter with an anticipated 3.431 Tcf heading into the 2014 to 2015 winter heating season and a projected 1.5 Tcf by the end of the season in March 2015,” Katherine Teller, EIA natural gas analyst, told Midstream Business. “We’re not expecting anything out of the ordinary, but weather is always the big unknown.”

This was obviously the case this past winter when a sustained period of frigid temperatures resulted in a sharp price spike for natural gas and propane prices, along with large storage withdrawals.

Unexpected withdrawals

“There really wasn’t an expectation for that sort of weather because it’s so hard to project such extreme weather events. We definitely weren’t expecting the level of withdrawals that occurred,” Teller said.

Similarly, should there be an increase in late-summer hot weather, the storage outlook could change. However, it is becoming less likely that could occur given the length of time left in the injection season, as EIA anticipates about 80 billion cubic feet (Bcf) per week in injection levels the rest of the season. So far, the average injections have trended much higher of late, which has given a margin for storage projections even if there are hotter-than-normal days in late August or early September.

Hastings credits another thing besides that cool summer for high injection rates: surging gas production from the unconventional shale plays. EIA numbers show U.S. dry gas production now hovers around 70 billion cubic feet per day (Bcf/d)—an all-time record.

Those trends have been a big help for storage operators, some of whom were down to their cushion gas at the end of the heating season.

EIA figures say working gas in underground storage dropped to 822 Bcf the week of March 28, substantially below the nation’s five-year moving average for storage volumes and the lowest point in 18 years. By comparison, the low point at the close of the milder 2012 to 2013 heating season was 1.67 Tcf—more than twice as much gas at the ready.

Weather repeats itself

Weather, like history, repeats itself, and Hastings said the current trend reminds him of the colder-than-average winter of 2002 to 2003.

“The weather pattern then continued into the spring and summer of 2003, which facilitated a massive rebuilding of storage after a stunning winter of consumption,” he said. Now, as during that summer 11 years ago, “we see some rebuilding rather aggressively,” Hastings added.

Still, those positive injection trends could be a mite stronger, thank you, in the opinion of Tudor, Pickering, Holt & Co. In a recent report, the firm observed that the end of July was the “second week in a row [the] storage number surprised to the low side,” implying that the gas market was a bit tighter than analysts had expected. The report added, “absolute numbers are still terrible and [the] market remains well over-supplied.” The week ending July saw injection of some 88 Bcf of gas—below an expected 93 Bcf but still a very brisk injection rate, according to EIA, “and of course miles ahead of the 50 Bcf weekly norm,” the Tudor Pickering report pointed out. A few weeks this summer saw 100 Bcf of gas injected to storage.

Overall, weekly injection volumes generally ran above forecasts for much of the late spring and early summer.

Fuel switching

Why the injection slowdown? Tudor Pickering projected in early August that lower gas prices, relative to coal, may have driven incremental gas-fired power generation as utilities that could switched boiler fuels.

Tudor Pickering projected that gas storage is on track to reach 3.6 Tcf as the injection season ends, a little higher than EIA numbers but slightly below the industry’s five-year moving average. The report predicted gas in storage will be “a bit more than we think the market needs to be comfortable going into winter heating,” given projections for a milder 2014 to 2015 heating season.

Hastings projected that gas production will remain strong the rest of the year and that will continue to support strong injection rates.

“As we go into the winter, we should be able to go through November at 70 Bcf/d to 70.75 Bcf/d—with a chance of 71 Bcf/d by the end of the year. That being the case, do you need storage if you’re doing 70 Bcf/d?” he asked rhetorically.

“Maybe” seems to be the answer.

There are a lot of variables, Hastings pointed out. Those current forecasts for a milder winter do have some exceptions.

“It looks like there’s an opportunity for colder weather in the Middle Atlantic and Northeast, a little like what was seen in 2009. But I don’t know if we’ll get the blizzards there that we did in 2009. Another pocket of cold could be in Texas. Aside from that, it is not looking like an intense winter,” Hastings said.

Do we need storage?

The swelling gas production from the Marcellus and Utica plays—so close to major gas markets in the Northeast and Midwest—also alters the traditional gas storage need. Pipeline infrastructure to move that Marcellus-Utica gas to market has been tight but things are improving, he added.

One welcome addition to the transmission network will be Williams Cos. Inc.’s new 26-inch Rockaway Pipeline serving Long Island, Hastings said. The new line will connect to the existing Lower New York Bay lateral of Williams’ Transco system and is scheduled to enter service in November.

The line will complement Spectra Energy’s $1.2 billion New Jersey-New York expansion that began service late last year—the first new gas transmission capacity built into metropolitan New York City in 40 years. That line’s 800 million cubic feet per day of capacity moderated price swings for New Yorkers during the worst of last winter.

The Northeast remains underserved by the gas transmission network but “price differentials regionally will start to moderate so we don’t get a recurrence of the severe differentials what we saw in the winter of 2013 and 2104” as new lines enter service, Hastings added. “That starts not only this winter but it will continue to diminish in the next two to three years as more infrastructure is completed.”

Unfortunately for operators, in the region most in need of storage—New England—it is nearly impossible to build underground storage because of its geology.

The Granite State

“They don’t call [New Hampshire] the Granite State for nothing. Storage would be tremendously valuable and useful in New England as it would solve its peaking problem caused by pipeline constraints, but it’s not commercially viable, which is why it relies so heavily on LNG storage,” Harvey Harmon, senior director, North American natural gas and global LNG at PIRA Energy Group, told Midstream Business.

Consequently, midstream operators will need to build more pipelines from Pennsylvania and New York into New England, despite the large costs that will entail. Thus far, the costs associated have made it difficult to get subscribers for the projects, which will continue to be a headwind for the region for the foreseeable future.

“New England power generators are not allowed to recover long-term firm transportation charges in their rates. In other words, if they sign a 10- or 20-year contract for a pipeline project, they aren’t guaranteed to recover those funds. Until that changes, it’s going to be hard to build large-scale new pipelines to New England,” Harmon said.

But to answer that broader storage question for the nation, with growing production near major consuming areas—the Marcellus now produces somewhere close to 16 Bcf/d—and improving infrastructure, does storage still matter?

Yes, said Hastings.

Storage matters

“Storage still matters during severe winters but will not matter as much as it did historically” thanks to the current trends, he added. And those projections of a milder winter next time around just may prove wrong, say in forecasts for a mild 2013 to 2014 winter just a year ago.

Another help in the coming winter could be an increase in storage capacity.

Overall U.S. gas storage capacity increased in the past year by 2% to 4.681 Tcf with the bulk of these additions coming in what the EIA calls the producing region—comprised of Texas, Oklahoma, Louisiana, New Mexico, Kansas, Arkansas, Mississippi and Alabama. This region increased by 7% to 1.123 Tcf.

The East maintained the largest total capacity of any region at 2.305 Tcf with the West trailing at 804 Bcf.

Overbuilt capacity

“We had a very severe winter, and the only areas that look to be short are the producing regions,” PIRA’s Harmon added. “The outlook for 2014 to 2015 is more complicated because of this past winter. The West is on pace to fill where it was last year, the East is a little less than that, but we still expect the East to get close, if not equal to last year. The region I’m most bearish on is the producing region. It looks like the one region where there will be significantly less volumes at the end of October this year compared to last year. The producing region is still overbuilt and the value of storage will probably go down.”

The New York-based consulting firm stated that it is still bearish on the need for additional gas storage capacity despite the importance this capacity played in keeping utilities supplied during a frigid winter. PIRA has said for the past few years that storage was overbuilding as production remains large enough despite a downturn in drilling rigs that it can quickly reload even after sudden and extended demand depletes storage levels.

Harmon said that this outlook could be altered if enough gas-fired power generation used storage capacity to balance supplies. “If you have storage, particularly in a producing region, gas-fired generation, in our opinion, is your best bet to use your capacity. Without that, I just don’t see the value of producing-region storage improving in the near-term.”

Over the last three years, the firm has cautioned clients that Lower 48 storage was being overbuilt. While the pace of these additions has slowed, PIRA’s overbuild capacity worries remain.

“We’re still concerned about the producing region being overbuilt and experiencing decreased values. If companies can sell their storage as backup to power generators, they’re doing well. There’s also exceptions to the rule with salt storage being more valuable than non-salt. We also still have some questions about the consuming eastern region. The only area where I see storage investments still making sense is the West,” he said.

Frank Nieto can be reached at fnieto@hartenergy.com or 703-891-4807.

Paul Hart can be reached at pdhart@hartenergy.com or 713-260-6427.