# Presentation: 010654

## Natural Gas Infrastructure

## T&D Task Group Participants

**T&D Task Group Participants**

- El Paso

- Pat Johnson

- NiSource

- Mark Maassel

- Kinder Morgan

- Ron Brown
- EnCana
- Rick Daniel

***Members***

- ANR Pipeline
- BP Energy** **
- BP N. Am Gas & Power
- Burlington Resources
- Columbia
- ConocoPhillips
- Dominion Energy Inc.
- Duke Energy
- ElPaso Pipeline Group
- ExxonMobil
- Kinder Morgan Inc.
- TransCanada Pipeline

- Memphis Light and Gas
- NiSource Inc.
- Northwest Natural Gas
- Peoples Energy
- Wisconsin Public Service Corp.

- BP Energy
- Dominion Energy Inc.
- EIA
- ElPaso Pipeline Group
- EnCana Corp.
- Duke Energy
- Falcon Gas Storage
- FERC
- Kinder Morgan
- PB Energy Storage Services

**T&D Task Group: Working Group Team Composition**

- Byron Wright

## Transmission

## Scope of Work

**The modeling system consists of a complex nodal (physical flow) structure**
** ****Unit pricing concepts determine gas flow through existing facilities and/or decisions to build pipelines between nodes**
**The model will always attempt to utilize existing facilities to their maximum **

## North American Transmission Grid

**300,000+ miles of pipeline facilities**
**More than 88% installed prior to 1970**** **
**19+ million Hp of compression**
**More than 52% installed prior to 1970**

**Notes:**
Review of historical pipeline corridors, updating:
Capacity
Max rate
Fuel/Loss
Analysis of announced pipeline projects through 2005 for inclusion in model runs
Review of timing of expansions after 2005
Analysis of costs to maintain existing Transmission infrastructure
Pipeline Safety Improvements Act
Horsepower replacement

## Pipeline Market Outlook, 2003 to 2010

**Forecast created from integrated corridor analysis model**
**Changes in supply and demand rebalance flows across entire North American grid**
**Pipeline capacity is built in response to basis pricing**

**1070**

**(460)**

**2530**

**590**

**1060**

**500**

**600**

**(320)**

**770**

**200**

**1050**

**760**

**(350)**

**(580)**

**900**

**750**

**(400)**

**(480)**

**Changes in Pipeline Flow (MMCF/D)**

**Notes:**
Pipeline infrastructure is primarily supply drive
	Arctic
	LNG
	Rockies 
	Offshore Gulf of Mexico
12 month basis signal required
	2 1⁄2 years to build pipelines (12 months for Rockies)
	Arctic, Eastern Canada and Deep Offshore – Just In Time

## Sustaining Capital is Becoming More Significant

**Finding: Pipeline and distribution investments will average $8.0 billion/year, with an increasing share required to sustain the reliability of existing infrastructure.**
**Recommendation: “Federal and State regulators should provide regulatory certainty by maintaining a consistent cost recovery and contracting environment** **”**

**Sustaining Capital is Becoming More Significant**

-         _Lower 48_
- $35 Billion - New transportation & storage
- $70 billion - New distribution
- $70 billion –  Sustaining capital:     all segments

## Changes in Pipeline Contracting Practices

**Recommendation: “Regulatory policies should address the barriers to long-term, firm contracts for entities providing service to human needs customers** **”**

**0%**

**20%**

**40%**

**60%**

**80%**

**Shorter than**

**5 Years**

**Longer than 5**

**Years**

**Total Expirations of Firm Contracts**

**Firm Contract Expirations**

**	****	****	****1998****	****2002**
**1st Year****	****	****15%****	****22%**
**2nd Year****	****	****27****	****35**
**3rd Year****	****	****39****	****48**
**4th Year****	****	****44****	****55**
**5th Year ****	****	****51****	****64**
**6****th**** Plus****	****	****49****	****36**

**Cumulative Expirations**

**Changes in Pipeline Contracting Practices**

## Who Will Be the Future Customers?

**Recommendation: “FERC should allow operators to configure transportation and storage infrastructure and related tariff services to meet changing market demand profiles.”**

**	****	****	****1998****	****2002**
**1st Year****	****	****8%****	****17%**
**2nd Year****	****	****17****	****37**
**3rd Year****	****	****32****	****50**
**4th Year****	****	****37****	****59**
**5th Year ****	****	****43****	****71**
**6****th**** Plus****	****	****57****	****29**

**LDC Cumulative Expirations**

**Firm Contract Holders**

**0%**

**20%**

**40%**

**60%**

**80%**

**100%**

**1998**

**2002**

**Power**

**Marketer**

**Producer**

**LDC**

**Industrial**

**Pipeline**

**Other**

**Expirations**
**Retail unbundling**

**Expirations**
**Bankruptcy Credit**

## Changes in Pipeline and LNG Capacity, 2003 to 2010

**Incremental Pipeline and LNG Capacity in MMCF/D**

**North American pipeline expenditures will average $2.7 billion per year from 2003 to 2025 for a total of $59.4 billion**

**800**

**1370**

**1500**

**760**

**1000**

**360**

**450**

**750**

**380**

**2070**

**470**

**600**

**1000**

**750**

**28,900 incremental pipeline miles required by 2010**** **
**2.5 million Hp of incremental compression required by 2010**

## Changes in Pipeline and LNG Capacity, 2011 to 2025

**Recommendation: Local, state, and federal permit reviews of major infrastructure projects should occur within a one year period utilizing a “Joint Agency Review Process.”**

**57,500 miles of pipeline additions required by 2025**** **
**7 million Hp of incremental compression required by 2025**

**4000**

**500-2000**

**700**

**750**

**750**

**2500**

**600**

**1000**

**750**

**650**

**1600**

**Incremental Pipeline and LNG Capacity in MMCF/D**

## Sensitivity Analyses

**-1.5**

**-1.0**

**-0.5**

**0.0**

**0.5**

**1.0**

**1.5**

**2.0**

**Average Annual Henry Hub Price Impact, $/MMBtu**

- Cold Weather

- Warm Weather

**Weather induced volatility**

**Average Annual Price Impact, $/MMBtu **

**No New East Coast LNG Terminals**

**Extreme Weather**
**(hypothetical weather stress cases)**

**30-year average weather****(Balanced Future)**

**Hypothetical cases displaying results of coldest and hottest sequences on record**

## Distribution

## Expansion follows demographic trends
Usage per customer continues to decline
Conservation
Energy efficiency
Cost data assembled from all regions
Reviewed based on industry data
Reviewed based on benchmarking data
Operations & Maintenance costs based on industry data
Replacement of some existing facilities
No replacement of any facility built during the study
Assumed continued enhanced productivity
Requires development of new technologies

**Usage per customer continues to decline**
- Conservation
- Energy efficiency
**Cost data assembled from all regions**
- Reviewed based on industry data
- Reviewed based on benchmarking data
**Operations & Maintenance costs based on industry data**
- Replacement of some existing facilities
- No replacement of any facility built during the study
**Assumed continued enhanced productivity**
- Requires development of new technologies

**Modeling Assumptions**

## Total Costs - $135 billion
Slightly less than average annual expenditures in 1990s
Impact of Pipeline Safety Improvement Act
FERC definition of “distribution” differs from DOT
22,000 miles impacted
Costs $2.7 – $4.7 billion

- Slightly less than average annual expenditures in 1990s
- Impact of Pipeline Safety Improvement Act
- FERC definition of “distribution” differs from DOT
- 22,000 miles impacted
- Costs $2.7 – $4.7 billion

**Cost Projections**

## Siting and Permitting
Larger distribution projects may face review by multiple agencies
States should develop centralized, coordinated siting processes
One model is the NARUC/IOGCC Pipeline Siting Work Group Report (similar to Joint Agency Review Process) 
Access to Capital
Future expansion will require external funding
Requires a stable regulatory environment 
Reliable Gas Service in a Changing Market
Changing requirements on pipelines by their customers
Can impact “traditional” LDC purchases

Possible Tension: LDC Revenues and Capital Requirements
US needs continued market driven improvements in efficiency
Rate of customer growth continues upward
LDCs have historically financed a significant portion of their expansion needs through internal funding mechanisms. Future revenues may not increase at a sufficient rate for sustaining and new capital requirements
Innovative tariff structures may assist in proper balance

- Larger distribution projects may face review by multiple agencies
- States should develop centralized, coordinated siting processes
- One model is the NARUC/IOGCC Pipeline Siting Work Group Report (similar to Joint Agency Review Process)
**Access to Capital**
- Future expansion will require external funding
- Requires a stable regulatory environment
**Reliable Gas Service in a Changing Market**
- Changing requirements on pipelines by their customers
- Can impact “traditional” LDC purchases
**Possible Tension: LDC Revenues and Capital Requirements**
- US needs continued market driven improvements in efficiency
- Rate of customer growth continues upward
- LDCs have historically financed a significant portion of their expansion needs through internal funding mechanisms. Future revenues may not increase at a sufficient rate for sustaining and new capital requirements
- Innovative tariff structures may assist in proper balance

**Challenges**

## Challenges

**Challenges**

**Technology Contribution To Distribution Through Research **
- Base assumption: 1% per year productivity improvement can be achieved to enhance operations and lower costs
- Research has played a key role; technology advances are required
- Historical funding gone
- Estimated savings $300-$400 million per year
- Safety
- Improved replacement techniques with less disturbance
- Enhanced locational technologies
- Advanced environmental remediation

**Recommendation: “Regulators should encourage collaborative research into more efficient and less expensive infrastructure options”**

## Contract length appears to be shortening
Customers need service and stability
Long-term contracts must be an option

**Customers need service and stability**
**Long-term contracts must be an option**

**Challenges**

**0%**

**20%**

**40%**

**60%**

**80%**

**Shorter than**

**5 Years**

**Longer than 5**

**Years**

**Total Expirations of Firm Contracts**

**Firm Contract Expirations**

**Recommendation: “Regulatory policies should address the barriers to long-term, firm contracts for entities providing service to human needs customers.”**

## Storage

## Storage Methodology

**Forecast aggregate North American demand for seasonal storage**
- Assumed monthly gas supply will continue to be relatively flat as supply is stretched to meet demand
- Analyzed detailed monthly, daily demand outlooks developed by Demand Task Group
- Calculated seasonal demand differential (April-Oct versus Nov-March) to estimate seasonal storage requirement
**Forecast regional development of new storage capacity**
- Estimated regional storage development costs (by type of facility, new projects vs. expansions)
- Model uses regional summer / winter price differentials versus supply costs to determine most likely regions for capacity additions
- Model output may still overestimate market area storage development versus supply area
- geological, other constraints on development

## Increasing Peak Demands

**Increasing Peak Demands**

- Stable Industrial loads are declining
- Weather-sensitive residential, commercial, power loads growing
- Electric generation is not only amplifying winter peaks ,but is creating a secondary summer peak, competing with storage injections
- Storage facilities and services will have to be more flexible in the future
- high shoulder season injections
- higher peak day withdrawals

## Recommendation

**Recommendation: “FERC Should Allow Operators to Configure Transportation and Storage Infrastructure and Related Tariff Services to Meet Changing Market Demand Profiles.”**

## Demand for Seasonal Storage

**Total North American Demand for Seasonal Storage**

**'Normal Weather'**

**(1,000)**

**(500)**

**0**

**500**

**1,000**

**1,500**

**2,000**

**2,500**

**3,000**

**3,500**

**2000/01**

**2005/06**

**2010/11**

**2015/16**

**2020/21**

**2025/26**

**Withdrawal Year**

**BCF**

- Residential

- Commercial

- Industrial

- Power Generation

- Total

**Demand for Seasonal Storage**

**1999-2002 average: 2269**

- Total demand for seasonal storage grows by 1 Tcf by 2025 (versus ‘99-02 average)
- Residential, commercial demand requires most seasonal storage
- Power generation sector slightly reduces total *seasonal* storage demand due to summer peak, but more than offset by strong residential/commercial growth

## Current North American Seasonal Storage Capacity

- ‘Theoretical’ working gas capacity over 4.5 Tcf
- Maximum cycled (peak to trough) is approx 2.9 Tcf
- 2.5 U.S. (see chart), plus Canada
- Cycling 2.9 Tcf pushes limits of injection / withdrawal capability:
- extreme winter prices, demand destruction
- low summer prices, production shut-ins
- Current infrastructure appears capable of 2.6 Tcf without extreme prices

**U.S. Working Gas in Storage vs. Average Wellhead Price**

**(Monthly Jan/94 - Feb/03)**

- 500

- 1,000

- 1,500

- 2,000

- 2,500

- 3,000

- 3,500

- Jan-94

- May-94

- Sep-94

- Jan-95

- May-95

- Sep-95

- Jan-96

- May-96

- Sep-96

- Jan-97

- May-97

- Sep-97

- Jan-98

- May-98

- Sep-98

- Jan-99

- May-99

- Sep-99

- Jan-00

- May-00

- Sep-00

- Jan-01

- May-01

- Sep-01

- Jan-02

- May-02

- Sep-02

- Jan-03

**BCF**

- $1.00

- $2.00

- $3.00

- $4.00

- $5.00

- $6.00

- $7.00

- $8.00

**$/mcf**

**Working Gas in Storage (Left Axis)**

**Average Wellhead Price (Right Axis)**

***Source: EIA***

## Projected Demand for Seasonal Storage

- Average 2000-2002 seasonal storage demand approx. 2.3 Tcf
- 5 year average storage fill 2.2 Tcf
- Return to ‘normal weather’ requires 2.7 Tcf in near term
- Current capacity plus expected expansions of over 100 Bcf by 2005 may be sufficient to meet ‘normal weather’ demand
- Additional builds of 600 Bcf required beyond 2005 to meet market growth

## Weather Sensitivities

**Total North American Storage Demand - Reactive Path**

**(Normal Weather vs. Historical Weather variability)**

**1,500**

**2,000**

**2,500**

**3,000**

**3,500**

**4,000**

- 1999/00

- 2000/01

- 2001/02

- 2002/03

- 2003/04

- 2004/05

- 2005/06

- 2006/07

- 2007/08

- 2008/09

- 2009/10

- 2010/11

- 2011/12

- 2012/13

- 2013/14

- 2014/15

- 2015/16

- 2016/17

- 2017/18

- 2018/19

- 2019/20

- 2020/21

- 2021/22

- 2022/23

- 2023/24

- 2024/25

**Withdrawal Year**

**Bcf**

- Normal Weather

- Historical Variability

***Cold winter storage demand exceeds previous maximum in near term.***

- Weather sensitivities based on historical pattern of HDDs, CDDs
- Very high year-to-year variability in demand for seasonal storage
- Cold winters could stretch storage capacity beyond previous limits, even in near term
- Price volatility could exceed levels of recent years

## Seasonal Storage Demand:Reactive Path vs. Balanced Future

**Total North American Storage Demand**

**(Balanced Future vs. Reactive Path - Variable Weather)**

**1,500**

**2,000**

**2,500**

**3,000**

**3,500**

**4,000**

- 1999/00

- 2000/01

- 2001/02

- 2002/03

- 2003/04

- 2004/05

- 2005/06

- 2006/07

- 2007/08

- 2008/09

- 2009/10

- 2010/11

- 2011/12

- 2012/13

- 2013/14

- 2014/15

- 2015/16

- 2016/17

- 2017/18

- 2018/19

- 2019/20

- 2020/21

- 2021/22

- 2022/23

- 2023/24

- 2024/25

- 2025/26

- 2026/27

- 2027/28

- 2028/29

- 2029/30

**Withdrawal Year**

**BCF**

- Balanced Future

- Reactive Path

- Over time, ‘Balanced Future’ scenario reduces growth rate in demand for seasonal storage
- In near term, ‘Cold Winters’ could still stretch storage infrastructure beyond current capabilities

## Gas Storage Infrastructure: Challengesand Opportunities

- Higher _peaking capability_ needed to meet ***weather sensitive demand growth***
- Higher _inventory capability_ needed primarily for ***colder than average winters***
- alternative may be greater price volatility, demand destruction
- High ***cushion gas*** costs are _constraint on new projects_, opportunity for _enhancement of some existing projects_
- reduce cushion gas with added investment in wells, compression
***Daily volatility of power demand*** will require _more flexible physical capability and more flexible services_

**Gas Storage Infrastructure: Challenges****and Opportunities**

## Gas Storage Infrastructure: Challengesand Opportunities

***Geological limitations*** may require _additional supply area storage_, coupled with pipeline capacity to market
- Despite attractive fundamentals, storage developers face many ***market uncertainties***:
- decline of energy merchants as major storage customers
- lack of long term contracting by LDCs for pipeline, storage capacity
- uncertainties regarding future seasonal price differentials
- Most storage remains ***highly regulated*** re: project approval timelines, market rates, service flexibility

**Gas Storage Infrastructure: Challenges****and Opportunities**

## Gas Storage - Summary

**Gas Storage - Summary**

- Demand profiles are changing, requiring greater flexibility in physical capabilities of storage facilities and in the services they provide
- Demand for seasonal storage capacity will continue to grow.  The greatest risk to the adequacy of the system continues to be cold winter weather
- FERC should allow operators to configure transportation and storage infrastructure and related tariff services to meet changing market demand profiles

## Conclusion

## Findings

**Findings**

- “A balanced future that includes increased energy efficiency, immediate development of new resources, and flexibility in fuel choice, could save $1 trillion in U.S. natural gas costs over the next 20 years.  Public policy must support these objectives.**”**

**Notes:**
You have seen the report.  
Here are the findings.
We will go into detail on each finding.

## Recommendations

## Federal Energy Regulatory Commission

**Natural Gas Markets Conference**
**Balancing Natural Gas Policy:**
**Fueling the Demands of a Growing Economy**
- October 14, 2003

**National Petroleum Council**

**Natural Gas Study**