A PowerPoint Presentation from July of 2003 by Chris Hall - Senate Chair, Utilities and Energy Committee Maine Legislature

This was converted to html by Burr Taylor
I. New England’s Energy Market

A. Senator Christopher Hall (D)

B. Senate Chair,

C. Utilities and Energy Committee

D. Maine Legislature

II. Assumptions:

  • There’s no going back to a $2/MBTU world for gas.
  • Wellhead gas prices likely to remain at the $5+ level for the next couple of years.
  • Long-term prices in the $4-$5 range likely.
  • We need natural gas to meet air quality standards, chiefly in electric power generation.

III. New England:

  • 14 million people
  • Gas is 18% of region’s primary energy consumption (versus 24% nationally)
  • Home heating: fuel oil has 49% share, natural gas 33%
  • Gas consumption by sector: homes, 24%; commercial/industrial, 37%; power generation, 39%
  • IV. How is New England untypical?

  • Few energy sources within region (limited hydro, biomass)
  • No refineries, and few refined products pipelines.
  • Refined products largely distributed by barge then truck.
  • Markets partly integrated with Canada (especially in Maine, Vermont).
  • V. History – New England electric power generation

  • 1960s - Oil
  • 1970s - Nuclear
  • 1980s - Coal and renewables – especially biomass
  • 1990s - Natural Gas
  • VI. Cycles driven by:

  • temporary price advantages of fuels
  • expectations of capacity shortfalls
  • fears about fuel supply
  • Economic result: stranded costs
  • Political result: regional electric restructuring
  • VII. Sources of New England’s natural gas

  • 43% from Canada (western and offshore Atlantic Canada
  • 15% imported Liquified Natural Gas (LNG) (mostly from Trinidad and Tobago)
  • 42% western U.S.
  • Canadian share likely to increase long term with capacity expansion of Nova Scotia production and pipeline.
  • VIII. Pipeline systems into New England:

  • From western US:
  • Algonquin (part of Duke Energy)
  • Tennessee (part of El Paso Natural Corp)
  • From western Canada:
  • Iroquois Natural Gas Pipeline
  • Portland Natural Gas Transmission
  • From Atlantic Canada:
  • Maritimes & Northeast Pipeline
  • IX. Recent developments:

  • Iroquois pipeline completed 1992
  • Portland pipeline completed 1998
  • Maritimes & Northeast completed 1999
  • For the first time, natural gas available across northern as well as southern New England.
  • X. Biggest recent development for Maine: gas from Nova Scotia since 2000.

    XI. Recent developments:

  • Electric restructuring in late 1990s in 5 states (not Vermont) separated generation from transmission.
  • Merchant power plant building boom in New England 1998-2005, fueled by availability of new natural gas sources (Canadian pipelines, LNG).
  • XII. Natural gas-fired power generation

  • 1980: Less than 1% of New England’s generation was from gas.
  • 2002: 31% from gas units, 10% from dual gas/oil units.
  • 6,000 megawatts of gas capacity added between 1998 and 2002
  • 3,000 megawatts coming on-line in 2003.
  • XIII. Natural gas-fired power generation - II

  • At least 10,700 MW gas capacity by 2005
  • Natural gas expected to account for 49% of region’s power generation in 2005.
  • The most dependent region in North America on natural gas for power generation – Texas excepted.
  • Future growth through 2012 forecast to depend on natural gas.
  • XIV. Supply constraints – natural gas

  • 100% of pipeline capacity used during winter peaks. No underground storage in region.
  • LNG used as balancing element in supply picture.
  • Any disruption of pipelines would knock out electricity generation and would threaten grid.
  • Price rise and volatility threatens electric power market stability.
  • XV. Supply constraints - electricity

  • Regional grid has transmission constraints:
  • Load pockets in Boston area & southern Connecticut depend on high-cost local peak generation.
  • Maine has significant surplus of generation but cannot wheel power south.
  • Political and transmission constraints to importing more cheap Hydro-Québec power
  • XVI. Spot prices – natural gas and fuel oil

    • Yellow = Natural gas: Henry hub, $ per MMBtu
    • Blue = Fuel oil, NY #2, converted to Btus

  • Since May, gas has been priced above oil – gas is the marginal fuel.
  • XVII. New York Natural Gas Price, Relative to Oil prices

    XVIII. June and Nov. Natural Gas futures

    XIX. The policymakers’ dilemma:

  • Will regional gas prices stay high?
  • Is dependence on one fuel source sufficiently worrying to merit market intervention?
  • Should we make consumers pay more to maintain capacity ‘comfort margin’ of redundancy and security?
  • Are gas lines inherently more vulnerable to disruption than other fuel sources?
  • What about the Homeland Security issues around LNG terminals in a metropolitan area like Boston?
  • XX. How is the market responding?

    • Investment in pipeline capacity and connectivity moving ahead.
    • No changes yet in investment plans for additional gas generation.
    • Harder for plants to get long term, uninterruptible gas contracts.
    • Wholesale electricity market moving to more spot pricing and less stability.

    XXI. How should regulators and legislators respond?

  • Promote new & diverse sources of power? Who pays?
  • Promote efficiency & conservation? Who pays?
  • Promote improved transmission capacity, for both gas and electricity? Who pays?
  • XXII. Maine’s responses

  • 2003 Legislative session:
  • Climate change bill: state DEP to develop plan to reduce greenhouse gases state-wide.
  • Direction to PUC: T&D utility regulation must encourage efficiency and grid security
  • Target: cut state government’s own energy consumption by 25% by 2010.
  • Tax incentives for biodiesel fuels.
  • XXIII. Maine’s possible next steps

  • 2004 Legislative session – carry-over bills with strong support:
  • Fund new renewables capacity?
  • Increase funding for direct investments in efficiency?
  • Adopt appliance efficiency standards? Building code energy standards?
  • XXIV. Maine’s long term dilemma: integrate with energy markets to the NORTH or SOUTH?

  • One third of Maine is linked to the Canadian grid and NOT to the New England grid.
  • Maine is in an intermediate position between the Canadian and New York/New England power markets. Transmission constraints prevent full integration.
  • Canada – especially Quebec – has cheaper electric power, southern New England is more expensive.
  • XXV. The Canadian connection

  • All Maine’s natural gas comes from Canada.
  • Much of Maine’s petroleum products comes from the Irving Saint John refinery in New Brunswick.
  • Atlantic Canada likely to expend offshore production of gas and oil.
  • XXVI. But limiting Maine’s options:

  • Part of New England electricity market (NEPOOL and ISO-New England). Federal pressure to expand RTOs leading to integration of New England and New York (& other?) power markets
  • Likely investment in expanded transmission capacity between Maine and southern New England would eliminate Maine’s generation capacity ‘surplus’
  • Restructuring has left the state few tools for controlling power generation.
  • XXVII. Most of all:

  • Maine has only 1.25 million people.
  • Maine will always have regional energy prices set elsewhere – whether Boston and New York or Montreal and Saint John.
  • Public support for "green" power does not seem to translate into a willingness to pay a premium!
  • XXVIII. Interesting times:

  • Maine has a political "window of opportunity" for ratepayer funding of renewables, supply diversity, efficiency, and grid security projects in 2004-2006 because electric bills will fall sharply as stranded costs are paid off.
  • Should we use this chance to fund new projects – or will we merely create new stranded costs?
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