Deep in the heart of Louisiana, outside of a small town called Port Barre (population 2,349) a group of contractors is working around the clock on a site that sits atop a salt dome formation located deep underground. When several drilling rigs sprouted up, it closely resembled a traditional oil and gas exploration—a common sight in these parts. But the rigs operated for months, drilling to a depth of about 14,000 feet with no chance or intention of finding oil or gas.
Later this year, the site, with its two underground salt caverns, will become the Bobcat Gas Storage Project—one of the newest independent natural gas storage developments in the United States.
With a total construction cost of approximately $200 million, Bobcat represents a major piece of energy infrastructure, but to some degree amounts to a simple bet. Bobcat’s investors are betting on high natural gas prices and continued strong volatility in prices.
Bobcat is not alone. With FERC openly encouraging underground gas storage development and worries about high natural gas prices being expressed at all levels of industry and government—including former Federal Reserve Chairman Alan Greenspan—developers and investors are rushing to build and expand underground natural gas storage facilities. Additionally, acquisition prices for gas storage projects have surged, with valuations in some cases more than doubling over the past five years.
This frenzy of activity has invited comparisons with the natural gas-fired merchant power plant boom of a few years ago, with warnings of an inevitable bust to follow. But given the outlook for gas supply and demand, investments like the one in Port Barre, La., are part of a broader evolution that promises to globalize America’s gas market.
Underground natural gas storage has been an essential part of the natural gas industry from its very start. The first U.S. underground storage project began operation in 1916 at the Zoar field near Buffalo, N.Y.
Underground gas storage capacity steadily increased as the natural gas industry grew rapidly through the 1950s and ’60s (see Figure 1). Following the energy crises in the early ’70s and ’80s, natural gas demand fell and little storage capacity was built. The gas industry recovered in the 1990s with increases in demand, and a new wave of natural gas storage construction began a transformation that is still underway.
Before 1985, interstate natural gas pipelines bundled natural gas storage service together with gas commodity and transportation as part of a cost-of-service regulated rate. As a result, natural gas storage was owned and controlled largely by a handful of large pipeline companies. Also, for most of this period the price of gas purchased by interstate pipelines was regulated as well. Starting in 1978, federal lawmakers began deregulating the price of natural gas that producers sold to interstate pipelines.
Starting in the 1980s, regulatory steps toward open access began breaking apart the bundled nature of the U.S. interstate gas business. With the implementation of Order 636 in 1993, the process of unbundling gas sales from interstate transportation effectively was completed. In the past, interstate pipelines had managed gas commodity purchase, transportation and storage for customers. The unbundling process moved responsibility for managing these components downstream, allowing customers to contract directly with independent storage providers if they desired. FERC’s more recent actions have continued strengthening the competitiveness of service on the interstate grid and encouraging independent natural gas storage development.
As a result of these regulatory changes, while pipelines own the largest percentage of storage fields, gas utilities (LDCs) control most of the capacity of these fields through contracts for working gas capacity and deliverability. During the past decade marketers also have become significant players in natural gas storage, although they tend to focus on shorter-term contracts.
While these changes have led to the construction of new underground storage, starting in the 1990s, most operating gas storage is quite old. In fact, the average age of U.S. natural gas storage facilities is approximately 35 years. So the transformation still has quite a way to go. Meanwhile, the role most underground storage plays is almost the same as it was in the 1950s or 1960s.
Most underground natural gas storage plays a critical seasonal balancing role by providing a source of physical natural gas to balance relatively flat natural gas production throughout the year with weather-driven, highly seasonal natural gas demand.
U.S. gas consumption falls to less than 50 billion cubic feet (Bcf) per day during spring or fall (known as shoulder months) and can peak above 70 Bcf/day during winter. The growing summer peak in U.S. natural gas demand is driven by the use of natural gas in power plants. As a result, the market for summer gas is becoming more competitive.
In weather-sensitive consuming regions, storage located close to markets provides essential supply for peak seasonal periods. Underground storage provides economic benefits as well. By leveling wellhead production rates and increasing pipeline throughput, storage allows seasonal demand to be served in an efficient manner and provides end users with the opportunity to procure gas in summer, when prices should be relatively low, for use in winter, when prices typically are higher.
There are large differences in the types of underground gas storage, and as a result they perform different functions in the market (see sidebar, “Gas Storage 101”). LDCs primarily are interested in supply reliability to serve peak winter season needs. Therefore, LDCs control or contract primarily for depleted reservoir and aquifer storage.
With the build out of natural gas-fired power generation capacity during the merchant boom of the late 1990s through 2001, power generators became a significant potential storage customer, mainly to support daily balancing requirements on pipelines. More recently, as numerous LNG import terminals have been proposed in the U.S., LNG terminal operators and their capacity holders have become potential storage customers.
The flexibility of salt-cavern gas storage allows users to rapidly inject and withdraw inventory—in some cases up to 1 Bcf per day or more at a single cavern. As a result, salt-cavern storage has become highly attractive for traders that want to capture value from daily and monthly price volatility. The slower speed of injecting or withdrawing gas from many depleted reservoir fields makes it more difficult to extract this value from short term volatility.
The storage needs of power generators and LNG players tend to be driven by day-to-day more than seasonal requirements, and therefore salt cavern storage would seem a better fit for their needs. However, recent advances in drilling technology have allowed some depleted reservoir fields to increase injection and withdraw speeds to the point where they can serve customers or traders with an interest in daily price volatility.
An unprecedented wave of underground natural gas storage development is underway. 110 Bcf of new “working gas” (i.e., usable inventory) storage capacity is now under construction with another 600 Bcf under development (see Figure 2). This development activity represents a potential 20 percent increase in storage working gas capacity.
Most of this development activity is focused on salt cavern storage. Depleted reservoirs and small contributions from other types (mainly aquifers) comprise approximately 39 percent of all proposed capacity.
Also, there is a geographical impact from this focus on salt cavern gas storage (see Figure 3). Due to the geological location of underground salt domes along the Gulf Coast and the focus on salt cavern storage development, the states of Alabama, Louisiana, Mississippi, and Texas comprise two-thirds of all working gas capacity development. Given the high deliverability, rapid cycling characteristics of salt cavern gas storage, the intense focus by storage developers on the Gulf Coast region is understandable. Plus the extensive pipeline infrastructure, numerous interconnections, and trading hubs along the Gulf Coast make a supportive web to encourage salt cavern storage projects. During the past several years, rising gas price levels and strong price volatility have enabled these types of storage projects to act as cash machines. Not only have the negotiated rates for firm capacity at these projects increased by 50 percent or more, but hub-services revenues from advancing (loaning) or borrowing (parking) gas to support trading have exploded.
However, it’s important to note that gas storage development involves bringing together the right combination of many factors—such as a suitable underground reservoir or salt dome with the exact geological properties to support gas-storage operations, access to necessary pipeline infrastructure, technical and environmental expertise, marketing skills, and numerous other aspects.
As a result, in recent years more proposed working gas capacity has been cancelled than reached construction stage. Some of these projects failed due to regulatory and permitting challenges and some had difficulty attracting sufficient market interest.
Few gas-storage development projects can proceed without market support in the form of firm contracts, typically three to five years in length, for at least a portion of the capacity. While some investors may be willing to take on more revenue risk, many storage-development projects require debt financing, and lenders have maintained a strong line on this requirement. This has increased the challenge for developers as costs of land, labor, and equipment have been increasing, while customers tend to be risk averse, and reluctant to sign multi-year firm service contracts in advance of construction and operation. This leads to pressure on projected returns.
With over 160 Bcf of recent project cancellations, gas storage clearly is a very competitive business. Out of the 600 Bcf of working gas that remains under development, only a portion is likely to reach commercial stage given this challenging history. However, the current high level of interest in the sector is resulting in new storage development projects or expansions being announced on a frequent basis. Therefore, while the competition is likely to result in only the best projects finding commercial support and moving forward, the construction of a massive and unprecedented amount of new storage appears very likely over the next five years.
Does this massive amount of Gulf Coast storage development resemble a speculative investment bubble that will burst? Several trends suggest not.
First, the role of imported LNG in the U.S. supply mix is changing the function of gas storage capacity. LNG will be a growing source of supply, but will arrive (or not) subject to the complex global market. Increasingly, Henry Hub prices will reflect a much larger set of price dynamics beyond North American supply and demand.
Last summer saw a dramatic increase in monthly LNG imports. Most of the increase from prior years was due to BG Group approximately doubling the amount of supply shipped through its capacity at the Lake Charles terminal in Louisiana.
BG Group is the leading player in the LNG spot market, and has strategic capacity positions in regasification terminals in Europe and the United States, allowing it to arbitrage Atlantic Basin LNG cargoes. Many other LNG players are working to obtain similar supply and terminal positions to execute similar strategies.
While a number of factors went into the increase in U.S. LNG imports in 2007, it appears to be a pattern that will continue due to two fundamental factors. First, most large European and Asian natural gas markets are even more seasonal than the U.S. market. Second, Europe and Asia have very little underground natural gas storage relative to demand. Therefore, European and Asian buyers make long-term commitments to LNG to ensure adequate supply during peak periods, but they have limited flexibility to take cargoes for future needs. As the global market for LNG expands, North America likely will take more off-season cargoes. Of course, this role as the world’s market of last resort is secondary in nature, and any tightness in global LNG supply rapidly will dry up U.S. imports, making projections for future imports highly uncertain.
The second driver is the role of natural gas in U.S. power generation. From 1999 through 2001, approximately 200 GW of new natural gas-fired generation was installed in the United States. While dispatch of these gas-fired power plants is highly variable and weather dependant, on average since 1999 summer-period natural gas demand has risen by about 6 Bcf/ day due to this new generating capacity.
With a sharp rise in natural gas prices and a growing recognition that many power markets were overbuilt, the merchant power boom ended in 2002.
During the next several years, natural gas was out of favor as a power generation fuel. But in many regions of the country this appears to be changing.
Increasingly, carbon regulation appears to be a matter of timing. R.W. Beck studies show a price of $30 to $50 per ton of CO2 would lead to up to 50,000 MW of additional natural gas-fired capacity being built. Under higher tax scenarios, traditional coal power capacity will lose out to natural gas capacity, and eventually advanced clean coal and nuclear technology (see Figure 4).
An increase of 50,000 MW of natural gas-fired capacity could boost demand by up to 2 trillion cubic feet per year, and increase average Henry Hub natural gas prices by 20 to 25 percent (see Figure 5). However, the exact timing and level of this demand push from carbon regulation remains subject to a large degree of uncertainty.
Meanwhile, throughout the United States a dramatic increase of renewable power sources—mainly wind and solar—is underway, in large part in response to state level mandatory renewable portfolio standards (RPS). Some form of RPS are in place in many states, and the amount of power consumption covered by these states is about half of total U.S. power demand. Even without federal mandates for RPS it is clear that wind and solar capacity will continue to increase around the country.
These renewable resources might create a further reliance on natural gas-fired capacity, to firm up variable generation and ensure grid reliability and stability. An important consideration is that little of the installed renewable power generation can be considered capacity.
For utilities to meet reserve margin goals and reliability standards, many will need added dispatchable generation resources—with the choice clearly in favor of natural gas-fired capacity. Given the growing contribution of imported LNG to fuel these plants, gas storage capacity will serve an increasingly important role in enabling gas markets to meet the challenges of a changing power industry.
The U.S. natural gas industry is becoming more complex, with more uncertainty and weather sensitivity affecting both natural gas supply and demand. These trends strongly suggest higher levels of price volatility in the future. A massive increase in high performance gas storage is both the response to this expectation and a necessary tool to adapt to it.
The current wave of gas storage development represents the next step in the transformation of the gas storage industry from its historically relatively isolated role into a highly flexible role—integral to the global LNG market, U.S. electricity markets, and overall U.S. energy security.
For traders and marketers, the ability to capitalize on natural gas price volatility has been the primary driver for the recent wave of interest in natural gas storage. In the longer term, gas storage likely will be valued for its traditional and increasingly critical purposes—supply assurance, reliability and price management.