# Presentation: 698352

## Energy Information Administration’s Outlook On Gas Pricing and Storage Deliverability

**Infocast Conference**
**Boston, Massachusetts**
**June 17, 2003**
**William Trapmann**
**Energy Information Administration**

**www.eia.doe.gov**

**Notes:**
The Energy Information Administration (EIA) collects data and performs analyses and forecasts of U.S. energy supply and demand.  

This presentation will discuss natural gas markets in the Northeast and the current short-term energy out look of the EIA.

## Presentation Coverage

**Natural Gas Supply **
**Natural Gas Markets in the Northeast**
**Natural Gas Storage**
**Status of Working Gas Storage**
**U.S. Natural Gas Markets**
**Natural Gas Market Outlook**

## NATURAL GAS SUPPLY

## Producing Basins AndRegional Natural Gas Flows

**Producing Basins And****Regional Natural Gas Flows**

**Notes:**
 Natural gas resources are distributed between a number of major geologic basins.  Most U.S. natural gas is produced in the onshore and offshore regions of the Gulf coast. According to 2001 data, 60 percent of gas produced in the United States flows from the onshore and offshore areas of the Gulf of Mexico.  Another 23 percent was produced in New Mexico, Oklahoma, and Wyoming.

Many major consuming markets (e.g., the Northeast, Midwest, California, and Florida) are located at significant distances away from the producing regions, so the system depends on the pipeline network.

The interstate pipeline network consists of almost 300,000 miles of pipe. 

(The map shows major geologic basins and transportation corridors.  The relative size of transportation flows is reflected in the size of the arrows.  The basins, on the other hand, are represented in terms of the area in which the basins lie.  The largest basins on the map are not necessarily the most prolific.) 

## Gas Rigs Tend To Follow Spot Prices With A Lag

- Source: Natural Gas Intelligence Weekly Gas Price Index, Baker-Hughes Weekly US Rig Report.

**Notes:**
 Natural gas rigs exhibit a loose correlation with the Henry Hub spot price, however, with a lag.  
 As an example of the response lag, the peak of 1,068 gas rigs was attained in mid July 2001, although spot prices had peaked in January and subsequently declined.  Similarly, rig activity began to recover in 2002 only after the spot price has started to rise.
  Henry Hub spot prices seem to have peaked in February 2003 at an average of $7.64 per MMBtu, with a one-day spike of $18.85.  The subsequent decline has not discouraged the expanding gas rig count to date.  As of June 13, gas rigs running were 910, which is about 30 percent above the rig count at the start of the year, and more than 50 percent above the bottom level hit in April 2002. 

## Most Production Flows from Wells Not More Than Three Years Old

**Source: Energy Information Administration.**

**Notes:**
 Natural gas (as well as oil) wells exhibit the highest rates of flow in their early years.  Consequently, total U.S. natural gas production flows mostly from wells that are not more than 3 years old.  This pattern has grown in recent years from less than 40 percent of total production to more than 50 percent. 
 Normal for an extractive industry:  this pattern of early peak production followed by a natural decline has been part of the industry since the earliest wells.  However, it is believed that the rate of decline from the initial peak may have accelerated in recent years.  
 A more rapid extraction of resources is beneficial because it enhances the economics by increasing the present value of expected revenues.  This allows the development and production from resources that otherwise might be sub-economic.  
 However, the associated rapid declines makes aggregate production increasingly dependent on the level of gas drilling.

## NATURAL GAS MARKETS IN THE NORTHEAST

## Interstate Natural Gas Pipeline Capabilities in the Northeast

**                 ****Capacity**

** ****(in Million Cubic Feet per Day)**

**3,600**

**4,800**

**6,000**

**       ****0**

**  ****1,200**

**Maine**

**New York**

**Pennsylvania**

**New Jersey**

**Rhode Island**

**Vermont**

**Connecticut**

**New Hampshire**

**Massachusetts**

**1,368 MMcf/d**

**5,157 MMcf/d**

**1,800 MMcf/d**

**2,556 MMcf/d**

**3,495 MMcf/d**

**3,077 MMcf/d**

**1,011 MMcf/d**

**445 MMcf/d**

**628 MMcf/d**

**178 MMcf/d**

**52 MMcf/d**

**2,400**

**1,059 MMcf/d**

**2,041 MMcf/d**

**4,495 MMcf/****d**

**Total Capacity Into the Region – 12,567 MMcf/d**

- Source: Energy Information Administration, GasTran Gas Transportation System, Gas Pipeline Capacity Database.

- Note: Capacity is as-of December 2002. MMcf/d = Million cubic feet per day

**New Brunswick**

**Quebec**

**Ontario**

**Interstate Natural Gas Pipeline Capabilities in the Northeast**

**Notes:**
 Fifteen major interstate pipeline companies transported natural gas supplies to fifty local gas distribution companies that then delivered the gas to the ultimate consumer. The largest amount of natural gas pipeline capacity enters the Northeast region from the Midwest (5.2 Bcf/d), most of it on the Texas Eastern and Tennessee Gas Pipeline systems. 
 Natural gas transportation from the Southwest to the Northeast region also comes via the Southeast region (4.3 Bcf/d). The Transcontinental Gas Pipeline and Columbia Gulf pipeline systems are the two key pipelines along this route. 
  Offshore Canadian gas is currently reaching northern Massachusetts in significant amounts (628 MMcf/d capacity), and, in 2003 is slated to reach the Boston area, with the completion of extensions to the Maritimes & Northeast Pipeline system (350 MMcf/d) and a complementary expansion of the Algonquin Pipeline system into Boston (295 MMcf/d). 
 The largest concentration of pipeline capacity in the region, 2,480 MMcf/d, is directed into the New York City metropolitan area (Long Island, Greater New York City and the southern New York counties of Westchester, Richmond, and Hudson). This represents an increase in capacity of 17 percent since 1998. 

## Underground Natural Gas Storage in the Northeast 2002

**Underground Natural Gas Storage in the Northeast 2002**

**Notes:**
 Underground storage facilities located within New York and Pennsylvania represent approximately 488 billion cubic feet of working gas capacity, which is the equivalent of roughly 50 days of service at peak withdrawal capability. 
 LNG facilities located in the Northeast are important also and are shown in the next slide.  
Many of the underground storage facilities located in New York and Pennsylvania (as well as many in West Virginia) are the primary providers of backup and natural gas peaking service to the interstate pipelines delivering supplies within the region. However, nineteen of the 82 storage sites in the region are owned and operated by local distribution companies and serve their systems exclusively. 
All but one of the underground storage facilities in the region uses depleted oil/gas production reservoirs as a storage medium. The other is a high-deliverability salt cavern site. Several depleted reservoir fields have been, or are in the process of being, retrofitted with horizontal drilling technology to increase daily deliverability rates. The Stagecoach storage field, placed in service in 2002 and located in southern New York State with a 500 MMcf daily withdrawal capability, is one such example. 

## Liquefied Natural Gas Storage Facilities in the Northeast 2002

**Liquefied Natural Gas Storage Facilities in the Northeast 2002**

**Notes:**
 The LNG facilities located in the Northeast represent about 31 billion cubic feet of capacity, or about 9 days of service at designed deliverability rates.    
During the 2001-2002 winter heating season, approximately 250 billion cubic feet (Bcf) of natural gas (net) was withdrawn from underground storage facilities located in Pennsylvania and New York and was delivered into the natural gas pipeline system serving the region. (Note: some portion of the storage gas withdrawn from fields in Pennsylvania is also directed onto pipelines serving customers in Ohio and West Virginia. However, the reverse is true as well: some storage gas withdrawn from fields in Ohio and West Virginia is also directed onto pipelines serving customers in the Northeast. The precise level of these movements is unknown). 
 Although LNG is only 5% of holding capacity, deliverability from these facilities is almost one-fourth of total deliverability from storage.  

## Northeast Natural Gas Consumption by Customer Sector - 2001

**Annual – 95 Bcf (2001) vs 5.7 Bcf (1998)**
**2001 Peak Month - .87 Bcf (January)**

**Annual – 1,171 Bcf (2001) vs 1,232 Bcf (1998)**
**2001 Peak Month - 134 Bcf (January)**

**Annual – 635 Bcf (2001) vs 644 Bcf (1998)**
**2001 Peak Month - 96 Bcf (January)**

**Annual - 564 Bcf (2001) vs 680 (1998)**
**2001 Peak Month - 82 Bcf (January)**

**Annual – 23 Bcf (2001) vs 19 Bcf (1998)**
**2001 Peak Month – 2.8 Bcf (January)**

**Annual - 8 Bcf (2001) vs 8 Bcf (1998)**
**2001 Peak Month – 1.2 Bcf (January)**

**Annual – 146 Bcf (2001) vs 132 Bcf (1998)**
**2001 Peak Month - 17 Bcf (January)**

**Annual – 364 Bcf (2001) vs 359 Bcf (1998)**
**2001 Peak Month - 44 Bcf (January)**

**Annual – 96 Bcf (2001) vs 131 Bcf (1998)**
**2001 Peak Month - 10 Bcf (March)**

- Sources: Energy Information Administration: **Annual **- Form EIA-176, “Annual Report of Natural and Supplemental Gas Supply and Disposition;” **Monthly **– Form EIA-857, “Monthly Report of Natural Gas Purchases and Deliveries to Consumers.” (2001 Preliminary).

_**Consumption by Customer Sector - 2001**_
**(Total Volume – Billion Cubic Feet (Bcf))**

**Total Deliveries to Consumers – 3,102 Bcf**
**2001 Peak Monthly Delivery – 388 Bcf (January)**

**Northeast Natural Gas Consumption by Customer Sector - 2001**

**Notes:**
 Total natural gas consumed in the nine States that make up the region reached 3.1 trillion cubic feet (Tcf) in 2001; the largest monthly consumption level, 388 Bcf, occurring in January 2001. 
  The EIA estimates that there are 11.3 million residential gas users in the region in addition to 1,090,000 commercial, industrial and electric power generator customers. 
In the Northeast region, the population increased 5.5 percent between 1990 and 2000, while total housing units grew to 22.2 million. Yet, five of the nine States in the northeast have more household using natural gas than fuel oil as a heating fuel. The mid-Atlantic States, New Jersey, New York and Pennsylvania, have the largest share of households using natural gas. The New England States, with the exception of Massachusetts,  have a relatively low share of gas (heating) users, which is to be expected. Historically, these States have been primarily fuel oil users. The low population density of the area was a disincentive to the development of an expensive natural gas distribution system in the area. 

## NATURAL GAS STORAGE

## Natural Gas Storage Attributes

-  Critical supply component during heating season
-  Helps satisfy sudden shifts in demand and supply
-  Accommodates stable production rates
-  Supports pipeline operations and hub services

**Notes:**
Storage is usually integrated into or available to the system at the production and/or market end of the pipeline system as a means of balancing flow levels throughout the year.   Typically, gas is injected into underground storage during the non-heating season, and withdrawn from underground storage during the heating season.
Underground storage has an important role to the market, in that it is used to accommodate variations in supply and demand. Storage is particularly critical in regions with significant heating load.  Cold weather can lead to a surge in demand, requiring storage withdrawals  to satisfy system requirements.  
Storage provides pipelines with the operational flexibility needed to satisfy changes in supply and demand.  In addition, storage is used to support hub services such as parking and loaning of gas.

## Storage Supplies Help Satisfy Demand Peaks

**Storage Supplies Help Satisfy ****Demand Peaks**

**Notes:**
Natural gas consumption varies widely between seasons.  This pattern is driven greatly by temperature-sensitive residential gas load.  The average daily residential load during the peak month is more than seven times the level of the summer lows.  
Production and net imports exhibit fairly stable flows throughout the year.  
 Gas use for electric generation during the summer results in a secondary seasonal peak.  Although limited nationally, summer peak volumes can be significant regionally—for example, Texas or California often have net storage withdrawals in the summer. 
 The difference between consumption and current supply (production plus net imports) is accommodated by storage injections or withdrawals. 

## Natural Gas Storage in the United States 

- Underground Storage
- Depleted reservoirs in oil and/or gas fields
- Aquifers
- Salt cavern formations (high deliverability)
- Additional Storage
- Liquefied natural gas (LNG) facilities
- Propane and CNG
- Pipeline line pack

**Notes:**
 Natural gas storage facilities differ by type—each of which has certain economic or technical characteristics. 
 Two of the most important characteristics of a storage reservoir are its capability to hold natural gas for future use and the rate at which gas inventory can be withdrawn–its deliverability rate.  One advantage of salt caverns is that their deliverability rates are very high, relative to their working gas capacity.
 Other storage approaches include propane injection, compressed natural gas (CNG), and “line pack”.   In line packing, by increasing  the pressure within the pipe, the pipeline itself is used to hold more gas.)

## Storage Capacity and Volumes January 1999-January 2003

**Natural Gas In Underground Storage**

**Notes:**
Underground storage comprises the bulk of all gas storage.  Before we go further with our discussion of storage, I would like to establish some basic concepts. 
This slide shows the various levels of base and working gas in underground storage, and storage capacity since 1999.
Key point:  Base gas comprises more than half the natural gas contained in underground storage facilities, although that varies by type.  
Operators can withdraw from base gas, as was reported this past winter (and previously).  
If you want more information on basic storage concepts, EIA released a report that is available on its web-site.

## Natural Gas Storage Facilities in the Lower 48 States

**Natural Gas Storage Facilities in the Lower 48 States**

**Notes:**
 There are about 415 facilities underground natural gas storage facilities operating in most of the Lower 48 states. Total underground working gas capacity is roughly 4 trillion cubic feet, although volumes entering the heating season rarely get above 3.2 Tcf.  
 Most of the underground storage capacity is located in former producing fields.  These depleted fields comprise 86 percent of capacity.  The other underground storage types are acquifer storage (10 percent) and salt caverns (4 percent). 
 There are about 96 LNG storage facilities (excluding marine terminals) with 86 Bcf capacity and deliverability of approximately 11 Bcf/day. 

## STATUS OF WORKING GAS STORAGE

## Natural Gas Stocks are Beginning to Recover from Winter Lows

**Natural Gas Stocks are Beginning to Recover from Winter Lows**

**Notes:**
This figure shows historical data for natural gas storage stocks for the U.S. and 3 regions: Producing, Consuming East, Consuming West. 
Storage stocks began this past winter in the upper end of the 5-year-average range, indicated on the figure—total stocks: 3,116 Bcf.
Natural gas in storage hit new all-time lows on April 13, 2003, working gas volumes were 623 Bcf—well below the previous record low of 697 reported for April 12, 1996. 
 Positive net injections occurred during the final 2 weeks of the heating season.  However, operators reported net withdrawals for the first 2 weeks of the refill season.
 As of June 6, stocks relative to the 5-year average in the East and Producing regions were at roughly 27 and 33 percent below average.
 Stocks in the West are within the 5-year operating range, although about 2 percent below average.  
 Overall, stocks are about 25 percent below the 5-year average.  This has caused some concern about market conditions during this summer and then into the winter.  The need for refill volumes is addressed in the following slides.

## Assuming Average Refill Rates, Natural Gas in Storage on Nov. 1 Will be Low Relative to Recent History

- Working Gas in Storage
- (billion cubic feet)

**Level as of**
**June 6, 2003**
**1,324 Bcf**

**Average **
**Refill Rate**
**1998-2002**

**Estimate:**
**2,617 Bcf**

- Storage Stocks as of November 1

**Source: EIA data and estimate assuming average refill rate from June 7 – Oct. 31.**

**Notes:**
 Natural gas volumes at the start of the heating season have varied between 2,732 and 3,191 Bcf in the past 10 years, with an average of roughly 3,000 Bcf.  
 Natural gas in storage hit record lows this past spring, so a large quantity of gas will be needed to achieve volumes generally deemed adequate. 
 The need to replenish stocks this year will introduce significant incremental demand during the summer months, which will compete with cooling loads and other uses for limited supplies. 
At the 5-year average refill rate the level of working gas in storage at the beginning of the heating season (November 1) would be 2,617 Bcf, which is 16 percent below the 2002 level and 14 percent below the 5-year average level.
 For 7 of the past 8 weeks, however, net additions to storage have exceeded the 5-year average.

The 2,617 Bcf estimate of Nov 1, 2003 working gas in storage was developed from the June 13 stock by adding an estimate of refill volumes for the remainder of the refill season.  As of June 13, storage stocks were 1,324 Billion cubic feet.  Refill volumes for this estimate are based on average daily rates for the months June-October in the years 1998-2002.   

## Working Gas Stock Projections

**Working Gas Stock Projections**

**1,324 Bcf in Underground Storage as of June 6, 2003**

**3,004 Bcf**

**2,617 Bcf**

**Notes:**
An unofficial target for storage has been 3,000 Bcf (roughly equal to the 1998-2001 average).

The volume needed to achieve 3,000 Bcf in storage would require net injections of 2,300 during the refill season, which is less than the 2,402 Bcf injected in 2001.

According to the EIA Short-Term Energy Outlook (June 2003), about 2,200 Bcf of gas is expected to be injected into storage, which would yield a total volume of almost 2,900 Bcf entering next heating season (November-March).  This level of working gas would be below the average of recent years, but still above levels recorded for 1996 (2,810 Bcf) and 2000 (2,732 Bcf), and comparable to storage in 1997 (2,886 Bcf). The projected net injections also are well below the recent high of roughly 2,400 Bcf in 2001.

## Natural Gas Storage

**Injections and withdrawals from storage occur throughout the year.**
**Inventories at the start of the past 5 winters have been 2.7-3.2 Tcf . **
**With an average refill rate for the remainder of the refill season, Nov 1 stocks will exceed 2.6 Tcf**
**EIA projects that the refill rate this summer will be slightly higher than the average, yielding almost 2.9 Tcf in storage on Nov 1, 2003.**

## U.S. NATURAL GAS MARKETS

## High Natural Gas Prices in Winter 2002-2003

-  High crude prices
-  Cold temperatures in major gas markets
-  Relatively low storage volumes
-  Weak production
-  Low net imports

**Notes:**
 To better appreciate the current market circumstances, let’s review natural gas markets in the past winter.  
  Natural gas prices were quite high by February: the Henry Hub spot price hit $18.85 per MMBtu on Feb 25.
 The spot price was not consistently above $4 until late October, and it was January before it consistently exceeded $5.  

## This Winter Was Colder Than Last Winter(Cumulative Heating Degree Days, Heating Season 2002-2003)

- Source: Energy Information Administration, derived from Heating Degree Day Monitoring, National Climatic Center.

**Notes:**
A major influence on gas markets is the weather. 
Because of the extremely warm weather in the West, overall U.S. HDD were only slightly below normal (-3.0%).  Overall, HDD in the U.S. were much higher than the prior winter– by more than 10 percent. 
Key regions of the country, including most major natural gas consuming markets, had temperatures close to or above normal. Heating-degree days (HDD) in the East North Central region were roughly normal (-1.4%), and the Middle Atlantic (5.6%) and New England (3.9%) were considerably above normal.  
  However, weather was much colder than the prior year.  In the New England, Middle Atlantic, and East North Central regions were between 18 and 30 percent more than the prior winter.  
 In all cases, the comparisons would indicate a greater degree of cold, except for the unusually warm end of March.  This obscures the degree of cold during the key winter period.
The colder weather increased consumption generally, increasing the need for large storage withdrawals and generally adding upward pressure on prices.  

## Natural Gas Net Imports in 2002 Declined for the First Time Since 1986

- U.S. Natural Gas Net Imports

**Natural Gas Net Imports in 2002 Declined for the First Time Since 1986**

**Notes:**
 Net imports of natural gas is an important portion of aggregate supply.  Net imports in the past 2 years equaled at least 17 percent of total U.S. gas consumption.
 Since 1986, net natural gas imports increased consistently each year through 2001.  This 15-year trend ended in 2002.  
 Natural gas imports from Canada increased by roughly 100 Bcf in 2002 v 2001.  However, this was more than offset by a slight reduction in LNG imports (-8 Bcf), and increased exports to Canada (53 Bcf) and Mexico (128 Bcf).  This resulted in an overall decline in net imports between 2001 and 2002.
 Although the overall volume is not very large relative to the total U.S. market, the change from continual increases to a decrease can only contribute to upward price pressure. 

## NATURAL GAS MARKET OUTLOOK

## Short-Term Outlook: Natural Gas

- Consumption expected to be essentially flat in 2003 and 2004
- Prices encourage supply activities, but supplies must fill depleted storage and meet current demand
- Supply picture is mixed
- Need increasing completion rates to offset decline from producing wells
- Expect net imports to remain fairly steady through 2004
- Storage refill is a question

**Notes:**
  Gas consumption is expected to be fairly stable through 2004.  This projection is includes an assumption of normal weather this summer, which is 8 percent cooler than last year.  
  With the continued, relatively high world oil prices expected, we do not expect much switching from natural gas to petroleum.   Overall, demand is expected to be fairly strong.      
  The supply picture is mixed. 
  Natural gas production is expected to increase 2.2% this year. 
  With imports expected to be flat in 2004, the U.S. will depend increasingly on domestic supplies.
  Refilling  the low inventory levels will put pressure on the gas prices throughout the summer. 
  I’d now like to provide some details concerning the natural gas demand and supply picture, including storage.

## Demand Growth Expected To Be Flat in 2003 and 2004

**Proj.**

**History**

**Notes:**
The industrial sector is the largest consuming sector, representing approximately a third of the gas consumed in the U.S.  The next largest consumer of natural gas is the electric generation sector, which accounts for approximately one-quarter of natural gas consumed. 
 Natural gas demand is expected to be very close to the 2002 level.  Expected consumption is projected at 23.23 Tcf in 2003.  This remains below the 2000 level by more than 200 Bcf. 
 Although industrial demand recovers from its 2002/2003 level, this is offset by lower consumption in the residential and commercial sectors.  
Electric power capacity fired by natural gas is expected to continue its growth trend. By the end of 2003, gas-fired combustion turbines and combined-cycle capacity is expected to be more than double the level in 2000. Most of the growth in the electric power industry’s capacity increase in 2003 is from more than 60% expansion of electric power combined cycle capacity in 2003 over 2002 (74.8 to 122.5 gigawatts). . 
Demand for natural gas this summer is expected to fall about 1 percent from last summer’s level, partially due to summer weather effects. In the event of a hotter than normal summer this year, natural gas prices could jump as cooling demand would compete with the need to build storage inventories.

## Natural Gas Spot Prices Will Decline FromThe Level of the First Quarter of 2003                                                                                     (Base Case and 95% Confidence Interval)

**Natural Gas Spot Prices Will Decline From****The Level of the First Quarter of 2003****                                                                                     (Base Case and 95% Confidence Interval)**

**Notes:**
 Given the factors already discussed, natural gas prices are expected to decline from their peak levels of this winter.  However, they are not projected to return to levels of early 2002.
 Natural gas prices are expected to average $5.34 per Mcf in 2003, followed by $4.99 in 2004.  The 2003 price would establish a new record high, beating the 20-year old record of $4.28 (constant 2002 dollars) set in 1983.  
 The 2003 and 2004 prices would mark the first time since then also that prices exceeded $4 in 2 consecutive years (prices measured in 2002 dollars).
 The price estimates along with the indicated confidence interval are for monthly average prices.  Short-term (daily or weekly) fluctuations might swing beyond the indicated bounds.

## Natural Gas Market Outlook Summary

-  Demand is projected to be flat through 2004
-  Domestic production is expected to expand with rising gas rigs drilling
-  Net imports are projected to remain generally stable
-  Storage refill will depend on weather and other market conditions this summer

**Notes:**
  Key attributes of the EIA short-term outlook are shown in the slide.

 A key feature of any forecast is the uncertainty surrounding major assumptions and the resulting projections.

## Near-Term Natural Gas Market Issues

**Supply:**		Will supply increase enough to satisfy 				potential growth in demand? Will boom and 			bust cycles discourage investment?
**Weather:****	**	The possibility of a hot summer or cold 				winter would put upward demand pressure 			on gas markets.
**Storage:**		Will refill be adequate for next winter’s 				demand?
**Consumption:**	Will forecasted growth in natural gas  				consumption be realized? How will 				consumption be affected by price volatility, 			fuel competition and service requirements                                                                                                			of electric generators?

**Notes:**
There are a number of short-term, as well as mid- and longer-term issues for the natural gas market.   These issues relate to supply, demand, infrastructure for natural gas.  Taken together, this leads to uncertainty about the future.   As a reminder, EIA’s projections are based on a set of assumptions, and future market conditions may differ from those assumptions.