Pipeline import capacity in the Northeast sub-region could fallshy of natural gas demand by more than 5 Bcf/d by 2010 if nosignificant capacity additions are constructed during the period,according to a new study by the Edison Electric Institute (EEI)that was released last week. The shortfall is predicatedon existingimport capacity in the sub-region remaining fairly constant at 12.4Bcf/d over the next decade, while the daily winter gas demand forthe area expands to about 17.5 Bcf/d.

Interestingly, the major pipeline projects planned for theNortheast sub-region, including Maritimes and Northeast andPortland Gas Transmission, would bring a total of about 3.5 Bcf/dof additional capacity into the market, which would mean that – ifthe study’s winter gas-demand projections for 2010 are on target -there still could be a lingering capacity shortfall even after allthe projects are built.

The EEI submitted the study, along with comments, last week toFERC as part of its review of the short- and long-term demand fornatural gas and capacity additions in the U.S. Northeast quadrant,which the Commission defined as all states east of the MississippiRiver and north of Tennessee and North Carolina [PL99-2]. For thepurposes of the study, Resource Data International Inc. (RDI) -which was commissioned by the EEI to do the review – divided thelarger Northeast quadrant into three sub-regions: the Northeast,Midwest and New England.

According to the study, gas consumption by electric generatorswill experience significant growth in the Northeast quadrant,increasing 11% annually between 1998-2010. This compares toexpected yearly growth rates of 0.6% and 0.3% in gas demand byindustrial and residential/commercial customers, respectively.

On a volume basis, the EEI study anticipates gas demand forelectric generation in the entire Northeast quadrant will triple to2 Tcf/year by 2010 over the current level of 625 Bcf/year, and willmore than quadruple to 2.9 Tcf/year by 2020. Three-fourths of thegrowth is expected to occur in the Northeast sub-region – reaching1.6 Tcf/year by 2010 and 2.1 Tcf/year by 2020 – due to itsincreased reliance on combined-cycle technology to serve electricbaseloads, it said. The Northeast sub-region encompasses Virginiaand Washington D.C. and most of the states north of them along theEast Coast.

In contrast, growth in generation-related gas demand in theMidwest sub-region will be “significantly lower” – reaching 501Bcf/year in 2010 and 795 Bcf/year in 2020. “Through the forecastperiod, coal should remain the primary fuel source for baseloadpower production in the Midwest,” the study noted. The Midwestsub-region includes Illinois, Indiana, Kentucky, Michigan, Ohio andWisconsin.

The volumetric gas requirements of electric generators in theNortheast quadrant still will lag behind industrial customers (2.7Tcf/year) in 2010, but EEI anticipates electric generators willovertake industrials by 2020. Residential/commercial customers areexpected to continue to account for the largest chunk of gas demandin the Northeast quadrant market – half of the expected total 9.7Tcf/year demand in 2010 and half of the anticipated 10.6 Tcf/yeardemand in 2020.

Underlying the anticipated gas growth are the gas-firedgenerating capacity additions that are planned for the Northeastquadrant over the next two decades, according to EEI. It estimates18,000 MWs of gas combined-cycle (CC) units and 39,000 MWs ofcombustion turbine (CT) capacity will be built by 2010, followed byan additional 27,454 MWs of CC units and 54,146 MWs of CT capacityby 2020. It estimates about 5,000 MWs for the New England subregionare either under construction or have been approved and financed.

EEI said it is concerned that the trend towards gas-fired CCunits in the New England sub-region, which would be used to servebaseload generation needs, could put a squeeze on the existingpipeline capacity in the area since the demand will “coincide”with the traditional seasonal heating demand.

The study estimates the average winter gas demand for the entireNortheast quadrant currently is about 34 Bcf/d while currentcapacity is about 30 Bcf/d, augmented by 38 Bcf/d of storagewithdrawal capacity and 6 Bcf/d of LNG peaking supplies.

The EEI report singled out the New England sub-region, sayingthat it is undergoing a “dramatic transformation” as a largeportion of its electric generation base shifts to natural gas. Thiscould put “significant stress” on pipelines, resulting in capacityshortages as early as 2002 if no new “greenfield” projects orexpansions are seen, the study said. It estimated that currentpipeline capacity in New England was about 2.7 Bcf/d – which isnearly equal to the existing daily gas demand for commercial andindustrial customers in the sub-region (between 2.2 and 2.6 Bcf).

New England generators have accounted for only a “small portion”of monthly gas demand in the sub-region over the past years – notexceeding 400 MMcf/d in the summer peak period, and averaging closeto 100 MMcf/d during the winter. But the EEI study predicts this isabout to change, with gas expected to fuel more than 40% of NewEngland generation by 2010 and about 60% by 2020.

The winter peaks for gas demand by New England generators areforecasted to reach 1 Bcf/d by 2002. When combined with thehistoric non-generation demand peaks of 2.4 Bcf/d for that market,total peak month gas demand could exceed 3.4 Bcf/d, the study said.

A tight market for pipeline capacity in the New Englandsub-region will drive the transportation component of gas pricesupwards, which will result in higher overall gas prices and higherelectricity prices, the EEI study pointed out.

The study authors say they expect gas prices in all regions toclimb as the result of the increased role for gas in powergeneration. In New England specifically, prices are projected torise to $3/Mcf from $2.50/Mcf by 2010. This scenario assumes thatmajor pipeline projects – such as Alliance Pipeline, PortlandNatural Gas Transmission and Maritimes and Northeast -will bebuilt. But if just limited expansions occur in the New Englandsub-region, gas prices would climb even higher – hitting about$3.25/Mcf in 2010 and about $4.25/Mcf in 2018.

And that won’t be good news for electricity, EEI said. “Gasprice increases that result from a lack of competition in thepipeline market will be directly transferred to the market clearingprice in wholesale electricity markets. This will increase theprice of every MW sold throughout the region when gas-firedgeneration is at the margin.”

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