Good morning Mr. Chairman, Commissioners. 

My name is Steve Harvey and along with Jeff Wright we would like to present our last regular review of 

U.S. natural gas market conditions for the winter of 2005/2006. I’ll start by reviewing current prices and 

market conditions and then spend a minute or two on remaining issues. Jeff Wright will then explore 

related storage capacity and operations issues in greater detail. 

Federal Energy Regulatory Commission

Winter 2005 Winter 2005 - 2006

Energy Market Update Energy Market Update

Item No.: A Item No.: A-3

March 16, 2006 March 16, 2006
2

Prices in late February and early March have continued the downward trend we observed last month, 

dropping last week into a range around the mid- $6.00 per million British thermal units (or MMBtu) level. 

This week, prices rebounded some to around $7.00/MMBtu. In trading Wednesday for gas delivered 

today at Henry Hub, Louisiana, prices averaged $7.10 on the IntercontinentalExchange. To put these 

prices in a historical context, let me superimpose last year’s prices at Henry Hub for the same dates. 

Price Declines with Price Declines with 

Better Supply/Demand Better Supply/Demand 

Source:

Intercontinental

Exchange

Natural Gas Prices (MMBtu)

$5

$10

$15

$20

Katrina

Rita

M J J A S O N D J F M

2005 2006
3

The red line is from May 2005 through last week; the blue line is from May 2004 through early March 

2005. This chart shows that prices in early March have fallen back below where they were a year ago at 

the same time – the first time this has happened at Henry Hub since June 2005. Early this week, prices 

rose back above last year’s levels, but, as of yesterday prices were 5 1⁄2 cents below last year in trading 

on March 15. 

Like at Henry, prices across the country remain close to where they were last year at this time. As least 

for the next-day physical market, we’ve seen the end of the cycle of higher prices that started last 

summer with record natural gas demand for electric generation, and continued because of the damage 

done by hurricanes Katrina and Rita. 

Prices Have Declined Prices Have Declined 

to Early 2005 Levels to Early 2005 Levels 

Source:

Intercontinental

Exchange

Natural Gas Prices (MMBtu)

$5

$10

$15

$20

M J J A S O N D J F M

2005/2006

2004/2005
4

Why haven’t prices fallen further? I pointed out the relationship between oil and gas prices here a few 

months ago. Gas prices rarely fall much below competing fuel oil prices for any substantial period of time. 

Because of the availability of the relevant prices, New York shows these relationships best and New York 

prices are plotted on this graph. We can see by comparing the blue line that represents wholesale gas 

prices in New York and the red line that represents residual fuel prices in New York that gas prices have 

recently fallen below resid prices. Price increases earlier this week for gas were matched by oil products, 

so this relationship still holds today. While gas prices falling below competing fuels is not a typical 

condition, I’ll restate what I said in January about the possibility: 

I could conceive of a situation where this alternate fuel floor would not hold and gas prices could 

plunge – if so much inventory was still in storage at the end of the winter that physical operations 

required its owners to remove it no matter what the price. This condition seems unlikely unless 

current warm weather conditions remain through February. 

In fact, though February was not nearly as extreme a month as January, we’ve seen this scenario play 

out in this way. 

Gas Prices Now Below Gas Prices Now Below 

Past Oil Relationship Past Oil Relationship 

Source:

Bloomberg

Transco 

Zone 6 Gas

Heating Oil

Resid Oil

NY Fuel Prices (MMBtu)

$5

$10

$15

$20

A5/1 10/1 M J J A S O N D J F M

2005 2006
5

Consistent with that last observation, storage inventories are very full at this time. The Energy 

Information Administration last week reported that storage inventories for natural gas reached recorded 

highs for this point in the withdrawal cycle—664 billion cubic feet (or Bcf) above the 5-year average or 54 

percent higher than normal. 

With so much gas in storage and without abnormally cold weather, the requirements to withdraw have 

created competition between wellhead production and storage withdrawals. That competition has driven 

down price—at least to where oil prices limit more price decreases. LNG imports have remained 

extremely weak due to more attractive prices in Europe and Asia. As the United States carries this very 

strong storage position into the spring and summer, we could see further weakening of prices. Certainly, 

in the absence of strong weather-related demand, high storage inventories are likely to be a continuing 

factor in determining natural gas prices throughout 2006. 

Storage Storage Very Strong Very Strong 

Compared to History Compared to History

5-year 

range

2004-05

2005-06

Source:

Energy Information

Administration

Storage Inventory (Bcf) 1,000

2,000

3,000

0

A M J J A S O N D J F M

Months
6

In addition, recovery of Gulf production shut-in by the hurricanes last year continues to improve, although 

at a considerably slower pace. The most recent reports from the Minerals Management Service and the 

Louisiana Department of Natural Resources indicate that total production shut-in in Louisiana and in the 

Gulf of Mexico has fallen from highs of close to 10 Bcf per day immediately after Rita’s landfall to less 

than 1.8 Bcf/d as of March 8. At 1.8 Bcf/d, a total of less than 4 percent of U.S. production remains 

unavailable, and with current healthy storage inventories, still shut-in gas represents no immediate threat. 
7

We continue to see very active U.S. drilling for natural gas, despite reductions over the past few weeks. 

The Baker-Hughes rig count for natural gas was reported as down slightly in early March, but still quite 

close to two-decade highs. As you can see on the graph, natural gas drilling (in red) has clearly been 

responding to prices (in green) throughout the past eight years. Last fall, after a warm summer and the 

passage of two destructive hurricanes through a major U.S. production region, prospects did not look 

good for natural gas markets. Today, prospects look much better. The reason clearly was extraordinarily 

mild weather across the United States from late December through early February. As a result, 

wholesale natural gas inventories are high, drilling is active, production in the Gulf is recovering and 

prices have returned to levels lower than those seen last year at this time. Nevertheless, I’d like to close 

with two somewhat less sanguine observations. 

Gas Drilling Continues Gas Drilling Continues 

to Respond to Signals to Respond to Signals 

Source:

Baker Hughes

Operating Gas Rigs

Henry Price ($/MMBtu)

‘98 ‘99 ‘00 ‘01 ‘02 ‘03 ‘04 ‘05 0

500

1,000

1,500

$0

$5

$10

$15
8

First, futures markets are clearly assigning some possibility to price increases as 2006 continues. 

Currently, April natural gas futures are at the lowest price traded – lower than futures price all the way to 

December 2011. What is striking on this graph is that, despite recently similar spot prices, at last year at 

this time, the futures curve has risen from last year at this time. The curve in red is the path of futures 

prices as of the New York Mercantile Exchange’s close last Friday, and the blue curve is for one year 

earlier. We see that expectations for April 2006 are similar, but the rest of the curve has shifted up by 

about $3.00 next winter and a little more by the next. In other words, market participants’ assessments of 

the risk of higher prices have increased over the last year. Remember, from this graph, that spot prices 

are back around last year’s levels, but concerns about the future have been heightened. 

Challenges Remain Challenges Remain 

for Natural Gas for Natural Gas

Source:

NYMEX

Gas Futures Prices (MMBtu)

2005 2006 2007

3/10/06 Close

3/10/05 Close $5

$10

$15
9

The second observation regarding future gas prices starts with the reminder that all the prices I’ve shown 

are from wholesale markets. There is a difference in prices between wholesale and retail. Today, 

distribution companies and others are withdrawing gas from storage that was injected last summer at 

prices higher than today’s spot prices. These retailers have to make these withdrawals – the physical 

integrity of the storage fields requires it. Jeff will speak to the technical issues involved in a minute. But, 

as a consequence, retail rates will not drop as fast as these wholesale prices have. While this may be 

frustrating, these costs are real and necessary. Filling natural gas storage adequately every fall and 

empting that storage every spring is vital to protect the natural gas markets from additional volatility and 

the possibility of not delivering at times of stress. We enjoyed a mild winter this year, but that is no 

guarantee that next winter will be the same. The U.S. natural gas system has been under severe stress 

due to cold winter weather before – most recently in February 2003. Under those conditions prices can 

rise explosively, and even put the reliability of deliveries under threat. The higher cost supplies now 

entering the retail system – assuming they were prudently acquired in the first place – represent a real 

cost of the industry’s regular preparation for the possibility of occasional extreme cold weather. In 

general, prospects for more moderate prices than those experienced last fall are quite good in 2006. 

Now I’ll turn the presentation over to Jeff. 

Prices Have Declined Prices Have Declined 

to Early 2005 Levels to Early 2005 Levels 

Source:

Intercontinental

Exchange

Natural Gas Prices (MMBtu)

$5

$10

$15

$20

M J J A S O N D J F M

2005/2006

2004/2005
10

Let me briefly give you a background on underground natural gas storage in the United States. There are 

three major types of underground reservoirs that are used to store gas. The first type is depleted gas or 

oil fields which is the most common type of underground storage. These formations are suitable when: 

1) there is adequate space or porosity in the formation; 2) there is sufficient permeability such that can the 

gas be easily injected and withdrawn through the storage formation; and 3) the gas injected into the 

formation is retained, that is, it does not migrate to unrecoverable areas. The second type of 

underground storage is aquifers. Aquifer storage consists of injecting gas in formations that are filled with 

water and displacing that water. The third type is salt cavern storage which consists of removing layers of 

salt through solution-mining and removing the resulting brine, which creates a cavern to store gas. 

Deliveries from these three types of storage facilities can either be classified as seasonal supply 

reservoirs or high-deliverability sites. Usually, seasonal supply reservoirs are filled during the traditional 

non-heating season from April through October and the inventory is drawn down during the heating 

season from November through March. The depleted fields are typical of seasonal supply reservoirs. 

High deliverability storage sites, typified by salt caverns, have rapid injection and withdrawal cycles and 

can go through several complete cycles during a heating season. This makes them well suited to meet 

severe peaking needs or as an emergency source of gas. Aquifers can be categorized as high 

deliverability or as seasonal supply reservoirs depending upon the individual field. 

Gas Storage in the Gas Storage in the 

United States United States

 Three types of underground storage Three types of underground storage

• Depleted Gas and Oil Fields Depleted Gas and Oil Fields

• Aquifers Aquifers

• Salt Caverns Salt Caverns

 Delivery Classification Delivery Classification

• Seasonal Supply Reservoirs Seasonal Supply Reservoirs

• High Deliverability High Deliverability
11

At the end of 2004, the Energy Information Administration of the Department of Energy stated that there 

are 393 active storage fields in the United States. Storage in the eastern part of the U.S. is characterized 

by depleted reservoirs and aquifers with a few salt caverns. It is noteworthy that there is no underground 

storage in New England due to the geology of the region. Storage in the Gulf Coast is made up of a 

mixture of depleted gas, oil fields and salt caverns, while storage in the West primarily consists of 

depleted fields. 

Underground Gas Underground Gas 

Storage in the U.S. Storage in the U.S.

Source:

Energy 

Information

Administration

Depleted 

Fields

Salt 

Caverns

Aquifers
12

The storage capacity of any given storage field consists of two components – the base or cushion gas 

that must remain in the storage field to provide the pressure necessary to extract the other component, 

the working gas, which is the gas that is being stored and withdrawn. 

Total storage capacity, base gas and working gas, totaled a little over 8.2 trillion cubic feet for 2004 

according to EIA. Depleted gas field storage accounted for 6.8 Tcf of this total, or 82 percent of the 

capacity in 320 fields. Aquifers made up about 1.2 Tcf or 15 percent of the capacity in 43 fields. And, the 

capacity of salt caverns totaled a little more than 0.2 Tcf or around 3 percent of the capacity in 30 fields. 

Capacity of Storage Capacity of Storage 

Fields by Type Fields by Type

0

1000

2000

3000

4000

5000

6000

7000

8000

Depleted Field Aquifier Salt Cavern

Total Capacity in Bcf

320

43

30

Number of Storage Fields

Source:

Energy 

Information

Administration
13

This slide gives you the idea of the working gas volumes that cycle in and out of storage on a monthly 

basis from the beginning of 2000 through the end of February 2006. The peak amount of working gas in 

storage, usually reached in October of every year, has not significantly changed since 2001. What has 

changed is the amount of gas in storage in February of every year, as depicted by the lighter color, yellow 

bars. With the exception of February 2002, which was a warm winter, the amount of working gas in 

storage has increased since 2000 to the highest level of working gas that we have seen in storage in 

February. In short, there is slightly more than 400 Bcf working gas in storage than there was at this time 

last year. 

Isn’t this surplus a good thing? Well, not necessarily. Most of this gas is stored in depleted gas and oil 

fields. As I mentioned earlier, these storage fields are seasonal supply reservoirs, usually have just one 

withdrawal cycle during the course of the year. Based on the individual characteristics of the storage 

field, a certain amount of gas needs to be withdrawn by a specific time in the spring. Many gas tariffs of 

storage operators specify the maximum amount of gas that their customers can have in storage at the 

end of the heating season. This is to sustain the physical integrity of the storage field. If gas is not 

withdrawn by a specific time, the high pressures in the storage field could cause an unwanted expansion 

of the reservoir, causing gas to migrate and become unrecoverable. The proper recycling of the storage 

reservoir is the major tool in the prevention of the unwanted migration of gas. And, of course, the loss of 

gas is definitely an unwanted economic effect. 

Working Gas Volumes Working Gas Volumes

in Storage in Storage

1

2

3

2000 2001 2002 2003 2004 2005 2006

Trillion Cubic Feet

Source:

Energy 

Information

Administration
14

So, does this seeming oversupply of working gas in storage indicate that there is too much storage 

capacity? No, because again we come back to the weather. Over the injection season, gas was 

prudently put into storage in order to prepare for the cold weather of winter. However, as we know, there 

has not been a truly prolonged cold spell this winter, and the high level of storage inventory at this time of 

the year is indicative of this. It is important to not be shortsighted. There will be cold winters again and 

gas demand will increase. The ability to store natural gas will be crucial in meeting our peak demands in 

coming years. In fact, I would like to note that overall U.S. working gas storage capacity has actually 

declined from about 4.3 trillion cubic feet (Tcf) at the beginning of 1989 to about 4.0 Tcf as of December 

2005, a decrease of approximately 6.5 percent. As Steve and I have said over the last few month, 

declines in domestic production will be somewhat replaced by 1) higher cost non-traditional production; 

and 2) Canadian imports, which did step up last fall due to increased Canadian drilling activity; but that 

does not seem to be sustainable at historic levels over the long run. As demand increases, the 

increasing supply/demand gap will have to be filled by LNG and Alaskan supplies. However as we’ve 

seen this past winter, some LNG supplies can be bid away from U.S. markets. An excellent way to 

overcome the need for more gas availability to meet demand is to construct more gas storage. This 

allows not only domestically-produced gas to be put underground for cold weather consumption, but also 

LNG, which can be delivered, regasified and stored during those months when LNG is not in high 

worldwide demand. 

The Commission has been active in processing applications to build more storage in the U.S. Since 

2000, the Commission has approved numerous projects that total 257 Bcf of capacity and almost 12 Bcf 

per day of deliverability. Currently, the Commission is processing storage projects totaling 31 Bcf of 

capacity and about 1.7 Bcf per day of deliverability. The majority of this new capacity and deliverability is 

Commission Commission 

Storage Activity Storage Activity

 Approved Since 2000 Approved Since 2000

• 257 Bcf of Storage Capacity of Storage Capacity

• 12 Bcf per day of Deliverability per day of Deliverability

 Pending Pending

• 31 Bcf of Storage Capacity of Storage Capacity

• 1.7 Bcf per day of Deliverability per day of Deliverability

 Potential Potential

• 128 Bcf of Capacity of Capacity

• 4.1 Bcf per day of Deliverability per day of Deliverability
15

centered around three projects: Bobcat Gas Storage field in Louisiana, an expansion of the Stagecoach 

facility in New York and the Windy Hill Gas Storage Project in Colorado. Both Bobcat and Windy Hill are 

high-deliverability salt cavern projects. On the horizon, we see storage projects with the potential to store 

128 Bcf of gas and deliver 4.1 Bcf per day. While these appear to be large numbers, we can see that in 

recent years the peak amounts of working gas in storage have not changed. In fact, there was more 

working gas in storage at the beginning of the 2001-2002 and 2004-2005 heating seasons than the 

current heating season. 

Let’s again look at the question, “why is more storage needed?” As you have stated on several 

occasions, Mr. Chairman, and as echoed in the Notice of Proposed Rulemaking entitled Rate Regulation 

of Certain Underground Storage Facilities, or the Storage NOPR, customers will be better off if more 

storage infrastructure is built because it increases customer alternatives in a market and mitigates price 

volatility. And, based on the approach described in the storage NOPR, additional development of 

appropriate storage infrastructure is the expected outcome. 

I mentioned earlier how regasified LNG can dovetail nicely with storage, but there are additional, hidden 

synergies between LNG and underground gas storage. In the Gulf area, where most high-deliverability 

storage fields are located, the Commission has certificated seven LNG projects with a daily send-out 

capacity of 11.2 Bcf beginning with the Cameron project in 2003. Several more LNG projects at new sites 

and expansions of already-approved sites in the Gulf area are pending with a combined daily sendout 

capacity of 13.2 Bcf. If built, these LNG import terminals will have a significant amount of onsite storage 

in large cryogenic tanks; however, until the LNG has been vaporized and those tanks emptied, LNG 

tankers cannot deliver additional cargoes. ¶ 

Additional storage, proximate to the import terminals, can provide a solution. Vaporized LNG can be sent 

out, not for immediate consumption, but instead for redelivery into storage. This would allow for a more 

consistent turnover of LNG and a more efficient utilization of the LNG import facilities. 

At the other end of the transportation grid, the presence of LNG in the market area of the Northeast could 

help in the more effective utilization and development of market area storage. That is, as LNG is 

delivered into the Northeast, traditional gas supply from the South will not have to travel as far north, and 

importantly, the regasified LNG then can be stored in the storage areas of Pennsylvania and New York. 

In the winter, under this scenario, it will not be necessary for the traditional southern gas supplies to fill 

the pipelines in the Northeast market areas, especially in New England, which has stifled the efficient use 

of storage. 

Such an infusion of market area LNG could send the appropriate price signals and lead to new 

consideration being given to additional storage infrastructure development. This, coupled with the new 

approaches offered by section 312 of EPAct and the Commission’s proposed refinement to its storage 

pricing policy, should stimulate such development, thus increasing customer choices in the market and 

serving to mitigate pricing volatility. That concludes our presentation. Steve and I would be happy to 

answer any questions you may have.