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Industry Leader's Discuss Future Gas Storage Trends

Posted on: Friday, 1 July 2005, 03:00 CDT

Paul M. Amirault

Joseph A. Blount, Jr.

John Hopper

Rick Gentges

Projections indicate that North American gas demand will exceed 30 Tcf within the next 20 years and that as much as 700-800 Bcf of new storage capacity will be needed to meet expected demand growth. While the investment in storage will depend on a number of factors, the rising cost of base gas over the past 24 months has proven particularly worrisome.

To shed some light on this and other uncertainties, Pipeline & Gas Journal called on four industry experts to participate in a roundtable to discuss how much new storage is needed in terms of investment and where new facilities were likely to be located.

Replies were relatively upbeat, including responses to these and other pressing questions such as:

* What are the risks/obstacles for independent developers?

* What's needed from regulators? and

* Can existing pipelines carry additional loads?

Here are brief biographies on the four participants in this enlightening roundtable.

Paul M. Amirault is Vice President, Canada, for EnCana Gas Storage, a business unit of EnCana Midstream & Marketing, in Calgary. He is responsible for leading the Canadian sub-business unit of EnCana Gas Storage, comprised of three facilities (together called the AECO HUB) with total working gas capacity of 135 Bcf, and peak withdrawal capability of 3.25 Bcf/d.

Amirault has been with EnCana and one of its predecessor companies for over 10 yeasr. He has 25 years experience in the pipelines, natural gas marketing and gas storage industries.

Joseph A. Blount, Jr. has served as President and COO of Unocal Midstream & Trade (UMT) since March 2000. In this capacity, he oversees the worldwide marketing of Unocal's natural gas, crude oil and condensate resources, the development and management of its pipeline, terminal and storage assets, and the company's commodity risk management activities. He also provides commercial support, problem solving and strategy consulting for Unocal's exploration and production business units worldwide.

Blount joined Unocal in 1996 as General Manager of North American Gas Marketing, and was soon promoted to Senior Vice President of Unocal Global Trade.

John Hopper is President and CEO of Houston-based Falcon Gas Storage Company, the largest independently owned gas storage company in the U.S., owning and operating 22 Bcf of working gas storage capacity at two facilities in the North Texas/Dallas-Fort Worth market area.

Over the past 25 years, Hopper has started three different companies from scratch. The second, Falcon Gas Storage, was formed in 2000 to develop, own and operate high deliverability, multi- cycle natural gas storage facilities in strategic market areas across the United States.

Rick Gentges is Director of Reservoir Services for the El Paso Pipeline Group, a subsidiary of El Paso Corporation. Gentges began his career as a Staff Reservoir Engineer with ANR Pipeline Company over 23 years ago. He subsequently served in various capacities within ANR, all related to the design, construction, operation and maintenance of gas storage facilities. Gentges was appointed to his current position when ANR merged with El Paso in 2001.

He has served on various gas storage industry committees and is past Chairman of the AGA Underground Gas Storage Committee, and past Chairman of the Pipeline Research Council International Underground Storage Research Committee.

P&GJ: What is your outlook for storage between now and 2025? How much more is needed in terms of investment and where are the best locations in North America?

Hopper: The answer depends on a number of factors: How many LNG import facilities will be built, when and where? Will an Alaska pipeline be built, and if so, when? What role will technology and gas prices play in opening up new gas production plays that aren't economical right now? How realistic is "clean coal" technology and what role will it play in the development of incremental power plants? These are just a few of the many unknowns that will have an impact on the need for gas storage going forward. Having said this, my best guess is that we're going to need anywhere from 400-800 Bcf of new gas storage capacity over the next 20 years, most of it seasonal to mid-cycle, high-deliverability (2-4 annual inventory turns) storage located near demand centers and supply hubs.

Amirault: A study published by the National Petroleum Council (NPC) in fall 2003, Balancing Natural Gas Policy, estimated that an additional 700 Bcf of gas storage working capacity would be required by 2025 (assuming a growth rate of 35 Bcf per year) just to meet North America's seasonal balancing needs under normal weather conditions. EnCana's own analysis has indicated a clear trend of an increasingly weather-sensitive market, evidenced by increasing storage withdrawals per heating degree-day. Since mid-2004 it seems the broad market has also recognized this fundamental by maintaining summer-winter spreads on the futures markets that are much wider than historical levels.

For an efficient gas grid, the best North American locations for new storage development would be in the market regions, at the downstream end of the major pipelines. However, there are not enough resources in terms of economically developable reservoirs or salt deposits in such locations to meet the projected North American seasonal balancing requirement. By default, the bulk of new storage development will have to occur in the supply basins, where the best developable reservoirs are available.

Gentges: There have been several studies published during the past few years which project North American gas demand to exceed 30 Tcf within the next 20 years. Because of a strong dependency on storage to meet seasonal load variations, it's reasonable to expect that demand for storage will keep pace with the overall growth in demand for gas. Working gas capacity in North America currently stands at about 4.5 Tcf, 3.9 Tcf of which resides in the lower 48 and the remainder in Canada.

The NPC study that Paul mentioned reported that storage utilization in North America averaged about 2.3 Tcf annually during the period from 1999-2002. By comparison, EIA records indicate the highest recorded annual storage utilization was 2.9 Tcf.

The NPC study projected that increased demand for storage capacity would grow by an additional 1 Tcf by 2025; however, about 300 Bcf of this increase could be met with existing capacity, considering that utilization of storage during the 1999-2002 period was influenced by light demand due to relatively warm winter periods. Thus, about 700 Bcf of new capacity will likely need to be developed to meet expected demand growth. This level of growth seems reasonable, given the role that storage currently plays in the market.

A significant portion of this growth will be related to gas- fired electric generation and residential space heating, with power generation making up the majority of the projected demand growth. Demand for gas-fired generation is highly variable on an hourly, daily and monthly basis, and storage is ideally suited to satisfying such highly variable loads efficiently. Also, the growth in gas- fired generation has resulted in the development of a secondary demand peak during summer months to satisfy residential cooling loads. This growth of a summer peak will impact traditional summer storage injections, effectively siphoning off a portion of the supply that has traditionally been injected. The end result will likely require more injections into storage during the shoulder months of April through June and September through October in order to replenish storage for winter consumption requirements. Thus, new storage developments will of necessity be capable of providing more flexible services than much of the existing storage infrastructure.

Investment in storage will depend on a number of factors, though one of the largest cost components associated with developing new storage - the cost of base gas - has increased significantly as the commodity price has risen sharply over the past 24 months. The NPC study concluded in 2003 that storage infrastructure additions of 550 Bcf would be required between 2005 and 2025 at an estimated cost of nearly $5 billion. Not surprisingly, the largest growth is expected in the market area of the mid-Atlantic states (Pennsylvania and New York), where 141 Bcf of additions are projected at an estimated cost of $1.3 billion. Growth in the East North Central (Michigan, Indiana, Illinois, and Ohio) is expected to follow closely at 111 Bcf at an estimated cost of about $905 million. Growth in the South Atlantic is projected at 99 Bcf and at an estimated cost of $804 million. Remaining additions to storage in the lower 48 are projected at 141 Bcf and an estimated cost of $ 1.5 billion.

Blount: I'm familiar with both the NPC and the Interstate Natural Gas Association of America (INGAA) report that have projected the need for approximately 35 Bcf of new storage capacity each year for the next 20 years to meet forecasted consumer gas demand requirements. In orde\r to meet the increasingly variable gas demand load profile driven by gas-fired generation, I believe that the incremental storage capacity needed must be developed in high performance reservoirs or in salt caverns. Reservoirs must have sufficient permeability to allow for high rates of injection or withdrawal over relatively short periods and inventory levels. An average cost of $10 million per Bcf of high performance storage capacity translates to a $350 million per year investment. Geographically, I believe the incremental capacity is most needed in the Southwest, the Rockies, California, the Northeast, and at certain locations along the Gulf Coast, to serve the unique storage requirements that proposed LNG regasification terminals will have.

P&GJ: Are current pipelines capable of handling new loads of natural gas in accommodating swing supply/demand, especially as more LNG comes on line?

Hopper: No. For LNG to make economic sense, it is going to have to be baseloaded, just like flowing wellhead supply. The pipes won't be able to handle much in the way of day-to-day swing from LNG imports - certainly not hourly swing. We've already seen that the pipes are having problems with the gas consumption profiles of gas- fired electric generation facilities. Pipelines just weren't designed to provide a lot of daily or hourly swing, which is why most gas pipeline tariffs require ratable receipts and deliveries hourly across a 24-hour gas day. Gas storage is going to have to serve as the "capacitor" to absorb day-to-day and hourly swing in the market. Storage also is going to have to absorb seasonal swings in supply and demand (just like it always has), which I believe is going to present more of a problem for LNG imports than daily or hourly swings, the latter of which the LNG import facilities, to some extent, can handle themselves with on-site tank storage and variable rates of vaporization.

Blount: I don't believe the existing natural gas pipeline infrastructure is capable of handling the proposed large quantities of LNG slated for distribution along the Gulf Coast. I believe that strategically located, high-performance underground natural gas storage facilities will be important to facilitate the movement of LNG into the interstate pipeline grid where it will be distributed to other markets. New storage facilities will play a key role in balancing the volatility in regasification terminal receipts with the load volatility associated with consumptive gas demand.

Amirault: The key to that will be how much LNG comes on line and where. The most efficient answer for the grid would be for LNG terminals to be built close to highdemand market regions, freeing up some excess capacity in existing pipelines to facilitate delivery of seasonal storage withdrawals from increased supply area storage. It remains to be seen whether LNG terminal siting in market regions will be achievable.

In some supply regions now, such as western Canada and the eastern Gulf Coast, there seems to be sufficient excess pipeline capacity to accommodate additional storage developments and the peaking supply they could make available. LNG deliveries, however, in the Gulf Coast region are expected to come on line in large chunks and interconnect to pipelines in already constrained areas, repainting the flow dynamics in this region. New, large-diameter pipeline infrastructure will be required in the Gulf Coast region to move incremental volumes from the LNG terminals to liquid market centers with multiple pipeline take-away. The key is locating this new LNG pipeline infrastructure with connections to large amounts of storage for load balancing and delivery.

Gentges: I believe the INGAA study also examined the issue of pipeline infrastructure additions necessary to meet overall demand growth. The study concluded that some 41,000-43,000 miles of new interstate pipeline construction would be required to meet demand growth between now and 2025. Annual expenditures associated with these additions are estimated at about $2 billion. Interestingly, the study concluded that LNG is expected to have a minimal impact on new pipeline additions, and then only if LNG import facilities are not approved for construction in the mid-Atlantic and Northeast regions, causing LNG to be landed at sites within the Gulf of Mexico.

P&GJ: What are the most important factors to consider when planning and developing a new storage facility? What are the risks/ obstacles, especially for independent developers, and what can be done at state and federal levels to help new gas storage?

Gentges: Location is certainly a critical consideration in planning any new storage facility. Ideally, the storage facility should be located in close proximity to a number of major interstate transmission lines to afford access to multiple markets. The ability to provide multiple cycles annually is also valued by the market. The type of facility - depleted reservoir, salt cavern, or aquifer - is also a consideration, though development of an aquifer storage facility would likely be considered only if a suitable depleted reservoir or a salt cavern facility were not an option. As with most things in life each has trade-offs associated with them.

Depleted reservoirs are generally the least costly to develop and can typically be developed within 24-36 months, including the permitting process. A well-defined, high-quality depleted reservoir with excellent geologic characteristics (high permeability and porosity) can be converted into a storage facility with the capability for multiple cycles annually under the right conditions. Risk associated with developing this type of facility is relatively low since the reservoir served as an effective "container" for gas and/or oil over geologic time. Risks can include sub-surface gas loss or migration if not properly designed and engineered. In general, the industry has a long and safe operating history with depleted reservoir storage facilities. Local opposition and acquisition of land and sub-surface rights can be an obstacle; however, state and federal permitting requirements typically present the biggest obstacles facing the industry insofar as new development is concerned.

Solution-mined salt cavern storage facilities in certain circumstances are better suited to meet market requirements, particularly when peaking type storage services are desired. Salt cavern storage facilities typically require the least amount of base gas to operate efficiently and can provide very high deliverability relative to their size. However, they are the most expensive type of storage facility to construct, typically requiring 36-48 months including the permitting process. Risks associated with salt cavern development include cavern stability during construction in instances involving caverns in bedded salt formations, and potential surface subsidence. Disposal of very large quantities of brine associated with the solution mining process also poses certain risks. Similar to depleted reservoirs, local siting issues, access to land and sub-surface rights and state and federal permitting requirements are the biggest obstacles facing the industry.

Blount: A fundamental understanding of gas supply, pipeline infrastructure, and the gas demand load profile is necessary to design storage capacity and injection/withdrawal requirements for the market one wishes to serve. Unocal employs computer modeling to determine areas where a strong fundamental need for additional storage capacity is required. Once a market is identified, the next step is to find a suitable reservoir that exhibits the necessary characteristics to serve the market requirements. Given the variability in daily gas demand, reservoirs must have the capacity to handle the injection and withdrawal of large quantities of natural gas in a short period and over a wide range of working gas inventory levels.

I believe that salt caverns are the reservoir of choice to meet today's storage requirements, but also realize that necessary salt accumulations are limited, particularly outside of the Gulf Coast region. In the absence of salt formations, high-performance, depleted oil and gas reservoirs are the next best choice, followed by water-drive (aquifer) reservoirs. Reservoir capacity needs to match the specific requirements of the market(s) being served, so bigger is not necessarily better. Smaller capacity reservoirs (~10 Bcf) with the right performance characteristics are preferred over large reservoirs with inferior rock characteristics.

For independent storage developers, the major risk is the potential for "stranded" investment. Storage is often needed most in markets where the geology is uncertain. Rigorous geotechnical evaluations, and ultimately a test well, are necessary to verify reservoir performance characteristics. With salt cavern developments, a source of fresh water to mine a cavern is also necessary. Creating a cavern by the solution mining of salt produces brine that must be re-injected into a nearby disposal well, and that disposal well must have rock formations that will accommodate the brine. Project development will fail if a suitable reservoir is not discovered, and in the case of salt caverns, if a fresh water source for mining and a reservoir for brine disposal cannot be found.

Another potential obstacle is public resistance to local gas infrastructure development. Perceived land use conflicts, local and special interest group resistance, or general misinformation, irrespective of the need for the storage or the safety record of the industry, can derail a project.

Attracting capital to support the investment is another challenge for the independent developer. Rates of returns allowed under existing regulatory guidelines for facilities built under a "cost of service" methodology do not compensate developers for the extraneous risks associated with underground storage developm\ent. For example, a developer may evaluate several sites for suitability before a good location is found. Current regulatory guidelines do not permit recovery of those costs which can be considerable in the event that drilling fails to confirm suitable reservoir characteristics.

The positive news for storage developers is that certain states and the Federal Energy Regulatory Commission (FERC) recognize the need for additional gas infrastructure, including gas storage. FERC, in particular, has been proactive in soliciting feedback from the industry on how to promote additional infrastructure development. FERC has heard a consistent message from independent developers that higher returns under cost-of-service methodology are needed. Further, wider application of a market-based rate policy would allow developers to offer competitive storage services at rates reflecting the true value of the service.

Tax incentives are under consideration at the federal level. For example, allowing full (vs. partial) depreciation of cushion gas and accelerated depreciation of facility costs would enable higher returns on investment and facilitate the development of needed infrastructure. We are encouraged by the interest of FERC and other state and federal agencies to attract the capital necessary to build new infrastructure that will support the future gas demand requirements in the U.S.

Hopper: Market factors such as gas supply availability, pipeline access, the number of participants in the market at the location in question, and market needs in the area; unit development costs (for all three components of storage - i.e., injection capacity, withdrawal capacity and storage capacity); total development costs; timing; and local, state and federal regulatory issues and support. It appears to me that the developers of non-"rate base" storage - storage capacity that isn't going to wind up in the rate base of a regulated pipeline company - are going to have to be willing to build new storage capacity and sell it on a "merchant" basis without initial customer support in the form of long-term demand charge based contracts. 1 don't know of any gas storage facility that has been built recently by an independent storage developer with long- term contract support. Pipelines that build incremental storage capacity can get this kind of support because, one way or another, they can find a way to either bundle incremental gas storage capacity with pipeline transportation capacity and/or receive rolled- in rate treatment for incremental gas storage capacity. Both give the pipes a decided advantage in pricing and in securing long-term contract support for their customers. There are those out there that think this may change for the independent developers, but Tm not one of them.

Amirault: There are many important factors to consider like reservoir quality, depth and containment, aerial extent and complexity of mineral and surface rights ownership, history of the reservoir (production data in support of reservoir containment, but also migration risks of abandoned wells), environmental and community issues, and cost to connect to pipelines. It's getting harder all the time to find the unique combination of factors that leads to an economic and constructible storage project.

However, the key risk or obstacle, especially for independents, is the high cost of new storage development, and the scarcity of longterm commitments from customers to mitigate that risk. The majority of gas storage development occurred at a time when cushion gas was well below $2 per Mcf . In 1975, cushion gas would have represented less than 10% of the total capital. At today's natural gas prices, cushion gas costs can easily exceed 50% of the total capital.

Certainly, state and federal regulators can help by:

* Allowing the efficiency of relaxed affiliate rules for independents with no market power charging market based rates;

* Allowing depreciation of the capital cost of cushion gas;

* Relaxing state taxing regulations to encourage new storage infrastructure;

* Encouraging utility companies to make long-term infrastructure commitments as customers.

P&GJ : What factors are driving the market toward development or expansion of storage facilities?

Blount: U.S. gas supply is not growing at the same rate as gas demand, partially due to the fact that many traditional resource basins have matured and are in steep production decline. Gas imported from Canada has historically filled that gap, but with Canadian supply projected to remain flat in the future, other sources of gas will be required. Fortunately, gas imported in special tankers in a liquefied form (in other words, LNG) should help close the gap by the end of the decade, given the projects in construction today. LNG imports are dependent upon ships, which adds to the supply uncertainty. Ships can be delayed by weather, particularly in the Gulf of Mexico during hurricane season. Additional storage capacity will be required to balance the volatility of LNG supply with the demand requirements of the market.

U.S. gas demand continues to grow, driven largely by the increasing use of gas-fired power generation. Gas-fired generation is ideally suited to meet peak power loads, and therefore their use introduces additional variability to the gas demand profile. Additional high-delivery gas storage capacity is needed to serve a highly variable gas demand and to support pipelines not originally designed for such large, short-term demand swings.

Gentges: Overall demand growth is probably the key driver for storage expansions and new storage development. The gas "bubble" that existed from the mid '80s well into the '90s has dissipated as demand has grown. Thus, supply elasticity has diminished to the point where it is significantly less than it once was, which has resulted in greater volatility in prices. One need only look back at the winter of 2002-2003 when sustained cold weather in the Northeast lead to significant draw downs of storage inventory and sizable spikes in the spot market - albeit rather short lived, but nonetheless significant for end users who did not have storage service as a backup to their supply portfolios. An overall trend of increasing prices has since ensued with winter prices generally running $0.4 - 0.7/ Dth higher than summer prices, thereby providing a strong incentive for the market to purchase supplies during the summer months and inject it into storage when prices have generally been much lower.

Amirault: A few parties who have been monitoring the market fundamentals have been steadily seeking new storage prospects to develop. Many new prospects have been announced; however, few have been developed and made available to the market. Sometimes the failure is due to a development flaw, but most commonly it is due to the lack of sufficient customer commitments at a price sufficient to make the project economic and the risks acceptable.

Futures price spreads are now driving more interest in storage, but "long term" still tends to be more like three years than 15. Perhaps the LNO industry, with the 15- or 20-year term contracts that underpin its development, will spur a trend toward other longer term infrastructure commitments or new projects will be developed by independents with funds on hand vs. relying on project financing. However, EnCana suspects a long overdue "colder than normal" winter, with resulting supply scarcity, will be the real catalyst.

Hopper: Growing winter season heating demand from LDCs as a result of increased residential and commercial demand; growing LNG imports; the fuel supply needs of gas-fired electric generation facilities and growing summer season cooling demand as a result of the preponderance of new gas-fired generation capacity; decreases in flowing wellhead gas supply; changes in where new flowing wellhead gas supply is coming on line in the lower 48 states; and accelerating gas price volatility, primarily seasonally and intra- seasonally.

P&GJ: Wow does storage development improve reliability while minimizing price swings tor customers?

Amirault: Short-term peaks in demand, or dips in supply, are both typically accompanied by spot and futures price increases in response to the relative scarcity. When additional supply is available in storage to be withdrawn into the marketplace at such times, it helps to rebalance supply and demand. Price increases are the market signal which stimulates the storage withdrawal, but the withdrawn volumes can quickly dampen that price spike. Similarly, storage injections help smooth out the price impacts of temporary supply surpluses.

It doesn't really matter who is utilizing the storage - if injections and withdrawals are responding to short-term market signals, the increased use of storage will increasingly act to smooth prices. This is important to ensure that both consumers and producers respond to the average supply/demand balance and associated price level, rather than over-react to short-term blips generally caused by weather events.

Blount: Market-area gas storage provides supply security for local gas distribution companies (LDCs) and utilities, and increases the system flexibility to meet peak daily and seasonal gas demand. Typically, LDCs and utilities purchase gas to go into storage from April to November, when prices are normally lower, to help them manage peak winter heating loads. By storing gas purchased in low- demand periods when prices are moderate, LDCs and utilities are able to lower their net annual gas costs, which directly benefits consumers.

Gentges: Price swings are driven by fluctuations in demand and it's still true that demand is lower during the summer months. That said, storage development improves reliability in the market because it provides a source of incremental supply to meet market needs during the heating season when pipelines are traditionally running at or near capac\ity and demand is highest. During the highest demand days of the heating season, storage withdrawals satisfy about 50% of the daily North American load, and thus are critical to maintaining supply reliability. Absent adequate storage to bridge this gap, the alternative would be significant swing production from the supply basins during the winter season. A significantly greater amount of pipeline capacity and compression would also be necessary to transport the increased volume to the market areas, much of which would be vastly underutilized the rest of the year.

Hopper: Gas storage has always played a role in improving gas supply reliability. Gas processing plants go down, wells go down, hurricanes require shut-ins, pipelines curtail service. All of these affect gas supply reliability. Storage provides a source of back-up supply when "force majeure" events occur as well as a source of secure supply to meet seasonal and peak-day demand that can't be met with flowing wellhead gas supply.

P&GJ: How long does it lake to develop a typical storage facility and at what cost?

Gentges: Under ideal conditions, new storage capacity can be developed in as little as 18-24 months, including the permitting process, depending on whether the facility is developed as an intrastate or interstate facility. Depleted reservoirs normally require the least amount of time to develop because they originally contained oil and/or gas and are naturally suited to storage development. Aquifers take slightly longer typically because gas must be injected under very controlled conditions to displace the water that exists in them. New salt cavern storage facilities generally take 36 months or more to develop, including the permitting process, because the caverns must be created.

Development costs vary significantly from region to region and by facility type. Generally speaking, development costs for depleted reservoir storage range from about $7-12 million/Bcf; salt cavern development costs range from about $15-20 million/Bcf, and aquifer developments range from about $12-17 million/Bcf.

Hopper: Once permits are in place (which can take several years in some states), reservoir storage can be developed in 12-18 months, depending on surface use requirements and the number and configuration of storage wells (the latter is a function of the size of the reservoir and reservoir characteristics such as porosity and permeability). In contrast, it can take two to three years to leach one to two salt caverns for gas storage and place them in service, depending on the size of the caverns. It can also take a year or more to construct a leaching plant and brine disposal system for salt cavern storage. Typically, multi-cycle reservoir storage can be developed for anywhere from $5 to $7.50 per Mcf of working gas capacity, depending on pad gas requirements. A greenfield salt cavern storage facility can cost from $15-25 per Mcf of working gas capacity, depending on the number and size of storage caverns leached in the initial development phase.

Amirault: Realistically, it takes about five years to develop a typical storage facility, including identification and evaluation, obtaining the land, storage and mineral rights, building local community support, regulatory approvals, design and construction. And that assumes the market commitments are obtainable when needed by the developer to stay on pace. Even after the new project goes into service, it may be some years before the development is completed, or the confidence to use the maximum design capacity is reached.

Costs to develop storage capacity are on an upward trend for a number of reasons and differ for the three main types of storage; salt, depleted reservoir and aquifer. Most of the good storage reservoirs, in other words those with high quality rock located close to pipeline infrastructure, are already developed, leaving only marginal quality reservoirs at increasing distant locations. The poorer the rock quality the greater the number of wells, volume of cushion gas and compression horsepower required. Hence, costs for a grass roots reservoir project are in the range of $4 to $10 per Mcf of developed two to threecycle capacity. The market is trending toward higher and higher cycle capability which further increases costs.

Natural gas storage in salt can take the form of either small caverns in bedded salt structures or large caverns in salt domes. Bedded salt is more expensive to develop because more wells and caverns are required. Typically, brine disposal is difficult and expensive in the regions where bedded salt storage can be developed. Natural gas storage in salt domes is more economic due to economies of scale and more plentiful brine disposal options. Salt cavern capacity costs are in the range of $10-12 per Mcf of developed six- cycle capacity for brownfield developments (conversion of existing caverns) but are much higher when the caverns have to first be created through solution mining.

Aquifer storage is the most expensive type of underground gas storage. It requires large amounts of risk capital for reservoir delineation and testing. Plus, a large percentage (30-40%) of the injected cushion gas can never be recovered from the rock. Aquifer storage is only for utilities protected by cost of service regulations due to the high risk and cost.

Blount: A "greenfield" gas storage development project typically takes three to four years from initial assessment of feasibility to commencement of commercial operation. Historically, salt cavern storage facilities cost from $10-15 million per Bcf of capacity, and depleted reservoir facilities cost from $4-8 million per Bcf. Development costs, however, are highly site and reservoir-specific. 1 expect to see development costs increase significantly in the future. Higher costs will be driven by the cost of steel, wells and related services, as seen in the oil and gas industry today. Costs will also be driven by higher natural gas prices, which will increase the cost of cushion gas, particularly for depleted oil/gas reservoir storage which needs more cushion gas to support delivery of working gas.

P&GJ: What are your company's current and planned investments regarding storage?

Blount: Unocal's midstream business unit has focused on growing its gas storage asset base since 2000. We acquired our current 43% interest in the Alberta Hub between 2000 and 2003 and commenced construction of our Keystone Gas Storage facility in West Texas in 2000. Keystone, a greenfield bedded salt cavern storage facility serving the Texas intrastate, Midwest and Southwest markets, commenced commercial operations in 2002, and currently has 4 Bcf of storage capacity, 165 million cubic feet per day (MMcf/d) of injection capability, and 350 MMcf/d of withdrawal capability. An additional 1 Bcf in capacity is scheduled to be in service in 2006. Unocal recently received approval from the Texas Railroad Commission to expand Keystone by an additional 3 Bcf. We expect to begin cavern development for that later this year.

Unocal currently has three gas storage projects in various stages of development. Our Windy Hill project is located 75 miles northeast of Denver and is expected to provide 6 Bcf of salt cavern gas storage capacity to serve the Denver-Fort Collins energy corridor, as well as Midwest markets via its initial connection to the Cheyenne Plains pipeline. Unocal has confirmed the project's technical feasibility and will conduct an open season later this month to secure expressions of interest in firm gas storage services. We plan to file an application with FERC during this quarter and, assuming we get all of the necessary regulatory approvals, expect to begin facility construction in 2006 with first service in early 2008.

Unocal is also planning to file a FERC application for our Sabine Pass project, which is on the Texas Gulf Coast. The project is expected to be a 6-12 Bcf salt cavern facility on Unocal's Big Hill salt dome acreage near the Strategic Petroleum Reserve. This project is near the Cheniere Sabine Pass LNG regasification terminal, currently under construction, and ExxonMobil's proposed Golden Pass LNG regasification terminal, also at Sabine Pass. The storage facility has been designed to balance the unique storage and deliverability requirements associated with regasification terminals and will offer access to consumers in the Texas intrastate, Midwest, Southeast and Northeast markets. Unocal conducted a successful open season in late 2004 to gauge customer interest in the facility and anticipates first service will commence in late 2008.

The third development project is Picacho, a project in Arizona designed for the Phoenix-Tucson market. Unocal recently completed a test well to evaluate the geology in the area and preliminary results are favorable. The planned salt cavern facility is 6-9 Bcf in capacity with 200 Mmcf/d in injection capability and 400 Mmcf/d of deliverability. This project will provide needed peak day deliverability and supply security services for utilities and LDCs serving southeast Arizona.

Unocal regularly considers new development project opportunities in underserved markets in an effort to expand the company's gas storage presence in the United States.

Gentges: El Paso is continually looking at storage development prospects as opportunities arise within each of its five pipeline business units. Currently, ANR Pipeline Company, which owns and operates the largest group of storage assets within the El Paso Pipeline group, is in the midst of expanding a number of its storage reservoirs in Michigan. The expansion program involves drilling a total of eight new horizontal wells and modifying and adding certain other surface facilities at the LincolnFreeman storage field. The program also includes certain surface facility enhancements at ANR 's South Chester and Central Charlton storage fields as well. Combi\ned, the modifications at these three storage facilities will generate 4.1 Bcf of incremental storage capacity by converting base gas to working gas.

Amirault: EnCana Gas Storage, and affiliates, currently own and operate (all volumes are working gas capacity):

* The 135 Bcf AECO Hub, comprised of three separate facilities in Alberta, Canada.

* The 24 Bcf Wild Goose Storage facility in California.

* And the 15 Bcf Salt Plains Storage facility in Oklahoma.

Currently under development is the Starks Gas Storage facility in southwest Louisiana:

* Conversion of existing salt caverns to gas storage service

* First 9 Bcf cavern potentially in service by late 2006, subject to market response in Q1/05 open season.

* FERC regulatory approvals anticipated in first half 2005.

In addition, EnCana is continually seeking out and evaluating additional prospects. EnCana's focus is on prospects that have both a high chance of success, and a potential size of significance. Although our track record is better than most, such new developable storage prospects are few and far between.

Hopper: We've just started the Phase II expansion of our 10 Bcf Hill-Lake gas storage facility in North Texas, which will more than double its annual cycle-throughput capability. A Phase III expansion is in the wings, depending on market demand for HDMC storage services in the North Texas/Dallas-Fort Worth market. Our Worsham- Steed gas storage facility just west of Fort Worth is slated for an initial HDMC retrofit this fall, similar to the initial HDMC retrofit we did for Hill-Lake three years ago. This will add another 10-12 Bcf to our portfolio of operating HDMC storage capacity in North Texas. We also plan to file with the FERC for a 7(c) certificate and with the state of Alabama for all requisite state permits to develop our MoBay Storage Hub before year-end. Phase I is for 11 Bcf of working gas capacity. Phase Il would bring total working gas capacity at MoBay to 45 Bcf. We also have a couple of development prospects in the initial feasibility stage: one in the desert Southwest and the other in the Gulf Coast region that would serve new LNG vaporization capacity in the area.

Copyright Oildom Publishing Company of Texas, Inc. Jun 2005

Source: Pipeline & Gas Journal

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