Natural gas storage may reach full capacity this fall as production, propelled by shale gas development, increases supply faster than additional storage comes online. Yet, exactly how much natural gas can be stored is a debatable, murky number, and in constant flux.

In its September 2010 release, the Energy Information Administration (EIA) reported that, as of April 2010, the demonstrated peak working-gas capacity was 4.049 trillion cubic feet (Tcf) compared to 3.889 Tcf in April 2009 —and that working-gas design capacity was 4.364 Tcf, compared to 4.313 Tcf in April 2009.

In November 2010, natural gas in storage reached 3.84 trillion cubic feet, about 88% of working-gas design capacity, prompting many analysts to predict storage would reach ultimate capacity by November 2011.

The EIA’s demonstrated peak working-gas capacity is derived as the sum of the highest storage-inventory level of working gas observed in each facility. It is the optimal level, a figure rarely reached, at any given time. Working-gas capacity, on the other hand, is an imprecise figure. It is derived from subtracting total storage capacity from base gas, also known as cushion gas. Base gas is the permanent volume of gas needed to provide adequate pressure to operate the facility.

In September, the EIA noted an East-West imbalance, stating, “Demonstrated peak working capacity as a percent of working-gas design capacity is lower in the West region than the East and producing region for several reasons. The West has several still-active fields whose primary role is not seasonal storage. These include fields used for pipeline load balancing and fields that are being drawn down to be taken out of service. Additionally, some fields in the West have large design capacities, but have infrastructure constraints that limit actual storage capacity.”

Murky numbers

Meanwhile, Stephen Smith, founder of Stephen Smith Energy Associates, an energy investment research firm, based in Natchez, Mississippi, says, “The maximum amount of natural gas that can be stored as the traditional fall storage peak is a more complex issue than it sounds.”

“The logistical need is evolving into two camps. In the first, shale gas with a lot of liquids becomes ‘must-move’ gas to get the liquids into a $100-per barrel market,” explains Ken Beckman, president, of Houston-based International Gas Consulting.

The number lies somewhere between demonstrated working capacity and design capacity, he says, and the aggregate of all operator problems prevent them from reaching capacity. Further compounding the industry’s ability to reach a consensus on a definite number is that it must rely on statistics from the EIA, and even the most current of those numbers, are historical, often several months old, rather than real time. The capacity, at even given time, does not reflect operator difficulties, or any additions that operators may have added since the EIA’s best estimate of capacity, notes Smith, who was a Wall Street oil and natural gas analyst for 15 years and has been engaged in energy investment research and analysis of energy markets for more than 35 years.

Whatever the actual capacity number, the market will send strong signals, prompting various actions, as the market perceives that capacity is about to be reached, Smith asserts. If storage nears capacity, that will mean that supply and demand are out of balance, and the market will correct itself, prompting price-responsive demand gains. An oversupply would put downward pressure on natural gas prices, prompting producers to slow, or even curtail additional production, while the consumers that are able to do so would switch to natural gas, increasing demand, which is already underway.

An unknown variable that can skew any projections is weather, the historical driver of storage development and usage. Producers are hoping for an early and cold winter to eat up some of the gas surplus.

“A nearing of storage capacity would make whatever remaining capacity is available more valuable, driving up prices for access to market-based, non-contracted storage,” explains Smith. “That available storage would go to those who want it most and are willing to pay the most.”

In such a scenario, storage operators would do their best to correct any operational problems, and bring on any additional capacity, getting as close as operational constraints would allow, to reaching design capacity. Still, exactly what the market would do, and how it would react, is unknown, because storage has not reached capacity since natural gas has become a market-driven, competitive commodity.

Further compounding precise calculations is that some announced storage projects have been delayed, or even cancelled. But, unlike when developers launch a project, they rarely issue press releases announcing an indefinite delay in projects.

Ken Beckman, president, of Houston-based International Gas Consulting, says that storage capacity is not likely to be reached this fall. “No, the seasonal spread just will not support marketing companies ‘topping’ storage for spread capture unless the forward market changes quite a lot. The utilities will fill to ‘plan,’ which is a number closer to 2.8 or 2.9 Tcf. I believe the remainder is more nearly seasonal capture or speculative volumes. The greater issue is that we did not really pull storage very hard this winter, so we are starting with a high residual gas volume,” Beckman says.

“Most utilities have an annual plan—so much firm transportation, so much storage capacity, so much LNG in the tank, et cetera. It’s rare that they exceed the plan, as the plans are what have been approved by the Public Utility Commissions, and there is not any value in being brave for no good reason. A plan is designed for a 20-year weather event for most of the utilities, so the plan is very conservative.

“In years of very high storage fills, especially in the producing area, it’s driven by trading-and-marketing-company late-season fill activity capturing the October to January-February arbitrage spread. It’s unlikely that this year will fuel such activity, and that tends to reduce the national storage fill activities,” he says.

The EIA’s recent estimate of capacity is a “good number,” he admits, although there may be an incremental expansion. “There is a fairly large volume that just is impractical to fill, not enough pipeline capacity to deliver it in the desired high-priced months. The Baker reservoir on Williston Basin Interstate Pipeline Co.’s system is such a storage facility,” he says.

Logistical demand

Today, increasing shale gas production is creating a logistical demand for storage, even as price-driven demand for storage continues to slump, thus creating a clash between logistical need and price volatility indifference.

“The logistical need is evolving into two camps. In the first, shale gas with a lot of liquids becomes ‘must-move’ gas to get the liquids into a $100-per barrel market,” explains Beckman. “In the other camp are dry shale-gas producers that need to pay for their wells and just need a market of any kind so as to generate a cash flow. There are more of the former and fewer and fewer of the later. The Marcellus and Eagle Ford drillers are the operators looking for a home for their gas. The Barnett, Woodford, and Haynesville are all flowing what has been drilled. Most of those areas are slowing down and the wet-gas areas are picking up, as the rig counts indicate.”

Overall, Beckman says the short-term prospect for storage development is “dismal.” Also, the need for a reasonable amount of volatility to return to natural gas pricing, so as to support storage capacity value, is obvious, he says.

“There are a number of very good and commercially viable projects moving to in-service. Most will immediately seek to do some sort of incremental expansion. That is going to keep new entrants at bay in this market. Longer term, around 2012 to 2013, the story gets better, as I believe electric generation demands will create new storage capacity opportunity.”

On another front, the refusal of the developers to reduce capacity pricing to extremely low levels (at values supported in the market today) to garner customers will create a pent-up demand for capacity—particularly that which accept shale gas via new pipelines that are coming on line.

Beckman continues, “Commodity gas price cuts two ways for storage. Higher prices tend to allow greater volatility, without which the industry suffers greatly. The problem is that higher costs for base gas require ever higher capacity charges to cover the developers’ return requirements. The perfect world would be a return of volatility without absolute gas price increases.”

Yet, there are secondary issues involved, he says. The greater the gas price, the more balancing penalties becomes value-adders for storage, and the more physical gas customers need storage to ‘fix’ daily imbalances that are a part of the cost of doing business.

Conversely, lower commodity prices support greater use of natural gas as an energy source, which translates to greater demand, more customers, and most of all, greater overall use of the pipeline infrastructure, which demands more storage to provide the flexibility the system requires to operate.

From January 2000 through September 2010, storage capacity increased 973.1 billion cubic feet, according to the Federal Energy Regulatory Commission (FERC). Much of that increase occurred since 2005, as 861 Bcf of capacity was added. Salt-cavern storage growth has been particularly strong along the Gulf of Mexico in Texas, Louisiana and Mississippi. Many operators are focusing on incremental expansions rather than greenfield projects.

Today, most new storage capacity is sold at market-based rates instead of traditional cost-of-service rates. Market-based prices enable the market, as opposed to regulators, to decide which projects are economical, and thus get built.

Record production

International consulting firm, Wood Mackenzie, tracks gas storage infrastructure. “For the calendar year 2010, as opposed to the April-to-April statistics updated by the EIA, we tracked 76 Bcf of capacity adds, and expect 86 Bcf during 2011,” says Ed Kelly, vice president for North American natural gas and power for the firm. “A rough estimate is that, by 2015, working-gas capacity will increase by about 100 Bcf. By 2020, another 200 Bcf will be needed.”

Yet, the term “needed” is subjective, as some market participants believe that, given the current relatively weak demand for additional supplies of natural gas, storage is actually overbuilt. Considering that total U.S. natural gas production is about 24 Tcf per year, storage capacity of 4 Tcf, or about 16.6% of production, is a high ratio, compared to that of most commodities.

Spurred by shale gas, total U.S. natural gas production in 2010 was 21.57 Tcf, just short of the record 21.73 Tcf. Although producers are “chomping at the bit” to produce still more gas, low prices have slowed growth. Any further production uptick would raise the question: will production growth now be slowed by inadequate storage capacity?

Elsewhere, rapidly changing gas market dynamics has prompted the INGAA Foundation and other sponsors to conduct an update of the infrastructure study it undertook in 2009. The updated report, released in June 2011, reveals that an estimated (at press time) 589 Bcf of additional storage capacity will be needed by the year 2035. If reached, that’s an annual average increase of about 24 Bcf. The study also finds that, within the next 25 years, total needed expenditures to expand storage capacity will be $4.8 billion, with $4.2 billion of that to be invested by 2020.

Richard Hoffmann, executive director of the INGAA Foundation, says the 2011 study, when compared to 2009, shows a significant increase in the need for more gas storage. The 2009 study projected that storage additions would need to be only 450 Bcf by 2030. Interestingly, much of the new capacity will be need to “park” growing gas supplies until the market demands the supplies.

Notably, the foundation’s statistics and projections include all of the U.S. plus Canada. The EIA and FERC numbers do not include Canada, and often are focused just on the Lower 48 states in the U.S.

Hoffmann says the study projects the need for an annual expenditure for expanding storage infrastructure of about $200 million. That investment and the annual capacity increases are well within the industry’s capabilities, he says. The industry has always shown an ability to meet investment needs warranted by market conditions.

The foundation’s projections assume a significant increase of natural gas consumption during the project study period. By 2035 annual gas consumption, in the U.S. and Canada, will be 38.8 Tcf, compared to 27.6 Tcf in 2010, it reports. Much of that increase is expected to come from greater usage of natural gas for power generation. The INGAA Foundation also expects gas prices to rise from $4 per thousand cubic feet to $6 or $7 during its study period.

Storage additions

David Pursell, managing director at Tudor Pickering Holt & Co., in Houston, notes that, because much of the recent storage growth has occurred in the Gulf Coast producing region and is multi-turn-cavern storage, versus the depleted-reservoir type on the East Coast, the coastal region is blessed with a flexible storage system.

“I have been moderately surprised that the working-gas capacity has continued to grow, even though U.S. gas demand growth has been tepid,” he says. “U.S. natural gas is a closed system. What is produced or imported, but not consumed or exported, must be stored. Once storage is filled, the only option is to reduce production. How much storage will be needed will depend on overall demand growth and the seasonal nature of that demand.”

The flat gas curve is not providing an impetus to build new storage facilities, he observes. As of mid-April 2011, the return for buying natural gas this spring and selling it for use next winter has dropped to its lowest level in seven years. Buying gas for April delivery and selling November futures yielded just 35.7 cents per thousand cubic feet—the lowest premium since 2004. A year ago the yield was 72 cents.

“What drives storage additions is the ability to make money from the spread between summer gas and winter futures gas prices,” Pursell says. “For example, if I buy July spot gas at $4.5 per thousand cubic feet and sell it forward to the following January for $5.5, that is a $1 arbitrage. The cost to store, if I already own the storage, is maybe 10 cents per thousand cubic feet injection and 10 cents withdrawal, plus a financing cost of maybe 5 cents, so in this case, I can lock in a 75 cent profit.”

The magnitude of summer-to-winter arbitrage drives profitability. As it widens, more storage gets built. Storage development, however, cannot immediately respond to short-term, volatile price signals.

Storage facilities are long-term investments with significant initial development costs and decades of performance potential that have a long lag time from conception to service. Also, builders also must overcome regulatory, engineering and construction constraints. The buzz phrase for much of the planned new breed of storage facilities is “high deliverability, multi cycle”, (HDMC). Unlike traditional single-cycle storage connected to long-haul systems, salt caverns have the most desirable HDMC characteristics.

To date, there are about 400 gas storage sites in the lower 48 states, mostly in depleted reservoirs. An estimated 70 companies own at least one storage facility. For the short term, gas-storage capacity and the demand for it are nearing equilibrium. For the long term, perhaps new sources of gas demand and continually increasing shale-gas supply will drive another storage buildout.