GAS PIPELINES. Noting a move toward shorter-term contracts since Order 636, the FERC on July 29 issued an "integrated package" of reform proposals for the natural gas pipeline...
not change much unless price declines significantly. But if price does decline significantly, the results could be striking and not without precedent.
Between 1964 and 1969, saturation in New England increased from 34 percent to 46 percent, or an annual percentage change of 6.2 percent.[Fn.17] If such a change were to occur today, residential demand would increase by 167 MMcf per day within two years. However, such progress depends on elimination of restructuring fees and other conditions that make it difficult for outside companies to compete with the incumbent utility and provide customers with a lower price for natural gas.[Fn.18]
Interestingly, the commercial sectors and high-income households in the Northeast appear quite promising as a market for distributed natural gas power generation.[Fn.19] In fact, increased natural gas pipe capacity in conjunction with natural gas distributed power generation may turn out to be a possible means of circumventing the enormous institutional, economic and political problems associated with creating an integrated, economic and reliable power market in the Northeast. If commercial, large-residential and small-industrial customers use increasing amounts of natural gas for DG, then there will be less need to trade wholesale power across power markets. Gas will be traded instead.
As DG increasingly is used, there also may be fewer instances of wholesale power price surges and limited transmission capacity. Since natural gas markets, especially in the East, are becoming increasingly well-connected, there may well be an overall improvement in the efficiency of energy markets and less volatility in wholesale power markets, but some increase in the price of wholesale natural gas. However, there also will be less value associated with new investments in conventional, operationally flexible natural gas power generation, and less will be installed.[Fn.20]
John H. Herbert is adjunct professor of statistics at the Northern Virginia Graduate Center of the Virginia Polytechnic Institute & State University. He also provides expert testimony and consulting service on such topics as fundamental industry analysis, applied econometrics and forecasting, quantitative methods for asset valuation, price risk management and the interrelationship between commodity markets and price volatility. Before opening his private consulting practice, he served as a senior economist at the U.S. Energy Information Administration. He may be reached at firstname.lastname@example.org.
1 See "Gambling on Gas Demand: Timing is Everything," by Richard Stavros, Public Utilities Fortnightly, July 15, 1999, p. 54.
2 See "News Digest," Public Utilities Fortnightly, June 1, 1999, p. 11.
3 See "News Digest," Public Utilities Fortnightly, Jan. 15, 1999, p. 14.
4 Energy Information Administration in its Form 860B indicates that there are 6,072 MW of capacity planned for non-utility generators for 1999-2003. Because of confidentiality concerns, EIA does not report planned utility capacity additions for Northeast Power Coordinating Council (NPCC), which is very similar to the definition of Northeast used here. Our estimate based on reported information for other locations and aggregate information is 300 MW, which provides an estimate of about 6,400 MW of planned capacity between 1999 and 2003. Steven H. Watts, McGuire Woods Battle & Boothe LLP, www.mwbb.com/services/energy-mp.html, in early November indicated 2,178 MW is under