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New England's Pipeline Delivery Capability Analysis

This presentation evaluates New England’s interstate pipeline delivery capacity, gas supply sources, infrastructure, and market dynamics, highlighting challenges and solutions for steady-state operations. It includes electric assumptions, merchant entry scenarios, projected shortfalls in gas requirements, modeling results, and ISO contingencies. The detailed analysis offers key recommendations for enhancing interstate transportation arrangements and fuel-switching capabilities.

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New England's Pipeline Delivery Capability Analysis

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  1. Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability Presentation to the MA Electric Restructuring Roundtable February 16, 2001 Richard Levitan Levitan & Associates, Inc. rll@levitan.com

  2. New England Natural Gas Supply Sources

  3. New England Natural Gas Infrastructure • New England’s Major Interstate Pipelines • Iroquois • Portland • Algonquin • Maritimes & Northeast • Tennessee • Existing pipeline delivery capacity = 3.8 Bcf/d. • Daily LNG sendout capability at Everett = 0.450 Bcf/d. • Expansion of 0.60 Bcf/d for 1,550 MW Sithe New Mystic Station, possibly Island End • About 1.4 Bcf/d peak day deliverability behind the citygates • Liquids via truck  0.1 Bcf/d

  4. Western Canadian Gas thru TCPL, Iroquois and PNGTS M&N Eastern Canadian Gas thru M&N PNGTS Tennessee Western Canadian Gas thru Tennessee Iroquois LNG from Algeria and Trinidad Algonquin Gulf Coast Gas thru Algonquin And Tennessee New England’s Interstate Pipelines

  5. Primary Interstate Pipelines

  6. Interstate Transportation Market Dynamics • 14 pipeline projects placed in-service during 1999-’00 + 2.0 Bcf/d in the Greater Northeast • New Pipelines in New England, M&N and PNGTS, result in + 615 MMcf/d (0.615 Bcf/d), or about 3800 MW • Counterflow capability through Dracut  Tennessee • Pressure and flow benefits improve network reliability • New LNG supplies from Trinidad • Commoditization of the “Supply Chain” • Repackaged Btu services • Synthetics • Increased liquidity • Risk management

  7. Electric Assumptions - Reference Case • Reference case load growth forecast thru 2005 • 7,500 MW (winter) of new capacity by 2005 • 200 MW of capacity attrition - 2000 CELT Report • Net Interchange: • firm contracts per 2000 CELT Report - (NY, NB, HQ) • modeling of post-HQ FEC deliveries - (HQ Phase II) • modeling of NEPOOL sales via proposed new interconnections (cross-sound cable)

  8. Electric Assumptions - High Case • High case load growth forecast thru 2005 • 11,500 MW (winter) of new capacity by 2005 • 4,000 MW (winter) of capacity attrition • Net Interchange - Higher than Reference case: • firm contracts per 2000 CELT Report - (NY, NB, HQ) • modeling of post-HQ FEC deliveries - (HQ Phase II) • modeling of NEPOOL sales via proposed new interconnections (cross-sound cable & Bridgeport cable)

  9. Merchant Entry in New England (High Case)

  10. Steady-State Highlights • No pipeline delivery constraints on a peak day in Winter 2000-01 • No summer peak day pipeline deliverability constraints through 2005 • Delivery constraints are apparent in Winter 2003 • Shortfall in gas requirements  1,755 MW out of 8,946 MW assumed • There are 71 gas-fired units, 51 of which are dual fueled • Delivery constraints intensify by Winter 2005 • Shortfall in gas requirements  3,226 MW out of 11,579 MW assumed • There are 75 gas-fired units, 54 of which are dual fueled • Theoretical mitigation potential thru back-up fuel

  11. * 6970 Btu/kWh 2001 2003 2005 Projected Shortfalls in Gas Requirements (MW)*

  12. Summary of Peak Day Scenarios – Total Regional Demand vs. System Capacity

  13. Steady-State Modeling Results Unserved merchant capacity does not take into account back-up fuel capabilities.

  14. ISO Contingencies • Loss of Major Gas-Fired Generating Unit • No significant loss of pressure or flows • Interstate pipelines have the ability to divert and/or re-route gas along the 1100-mile transportation path • Loss of 2000 MW HydroQuebec Line • Winter Peak Day - System cannot transport any additional gas • Summer Peak Day - More than sufficient pipeline capacity to support replacement gas fueled generation

  15. Available compression capacity at Burrillville on Algonquin derated from 11,400 hp to 5,700 hp Gas Contingency Scenario 1 • Increased horsepower requirements at other compressor stations • Fall in delivery pressures to levels that could disrupt plant operations • No observed impact on other pipelines

  16. Available compression capacity at Agawam on Tennessee derated from 9,760 hp to 3,253 hp Gas Contingency Scenario 2 • Downstream compressor stations able to make-up for loss • No unacceptably low delivery pressures for merchant plants observed • No impact on other pipelines

  17. 7 miles of Tennessee’s 36-inch line at NY-MA border removed Gas Contingency Scenario 3 • Downstream compressors able to compensate for pressure loss

  18. Mitigation Potential

  19. Recommendations • Establish quality of interstate transportation arrangements • Advocate the streamlining of FERC’s pipeline certification process • Promote coordination of power and natural gas scheduling protocols • Increase understanding of merchant generators’ fuel-switching capabilities

  20. Levitan & Associates, Inc.www.levitan.comTel: 617-531-2818Email: rll@levitan.com

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