U.S. offshore production of natural gas fell slightly; thenumber of new pipeline projects in the Gulf of Mexico droppeddramatically; Texas — the nation’s leading gas producer — tookhits to its production and consumption levels; California andWyoming experienced a robust boost in production; California sawthe sharpest rise in gas demand; residential users enjoyed theirsecond year of lower delivered gas prices; and pipeline importcapacity expanded considerably.
These were just a few of the snapshots of the gas industry in1999 that the Department of Energy’s Energy InformationAdministration (EIA) provided in its latest report, “Natural GasAnnual, 1999,” which was released this week.
The EIA reported that marketed production of gas from state andfederal waters declined slightly by 1% in 1999 from the previousyear, falling to 5.7 Tcf. However, it noted that offshoreproduction still accounted for 29% of the total U.S. marketed gasproduction in both 1999 and 1998. Louisiana maintained its positionas the nation’s leading offshore producer at 3.9 Tcf, while Texassaw its offshore marketed production fall 4% to 1.2 Tcf in 1999.
Reflecting the downturn in offshore production, the EIA reportnoted the pipeline construction in the Gulf of Mexico has fallenoff dramatically since 1998. In 1999, only four significantprojects (mostly upgrades to gathering operations) were completed,adding 1 Bcf/d to the region’s pipeline capacity. This compared tothe 14 Gulf pipeline projects totaling 6.4 Bcf/d of new gascapacity that were completed in 1998 and 1997. Most of the latterprojects “were large capacity pipelines connecting onshorefacilities with developing offshore ties, particularly in thedeep-water areas of the Gulf.”
Onshore, Texas and Oklahoma — the third largest U.S. producer— saw large declines in their marketed production in 1999 of 282Bcf and 74 Bcf respectively, the EIA said. The figures represent a4% drop for each state. Marketed gas production in Louisiana —the No. 2 producer — remained relatively flat last year, whileproduction in New Mexico increased by a mere 1%, according to thereport.
In contrast, California and Wyoming posted the sharpest rises inmarketed production in 1999 of 67 Bcf (21%) and 62 Bcf (6%)respectively, the EIA said. In California, the agency noted thatless gas was being used for the recovery of oil from the Elk Hillsoil field, which made more natural gas available to be sold intothe market.
Significantly, the number of gas and gas condensate wellstotaled 307,449 last year, a decline of 9,480 (3%) from theprevious year. This marked the first time that the number of wellshas fallen since 1992, the report said.
Nationwide, natural gas demand rose 2% to 21.7 Tcf last year,with end-users consuming 19.9 Tcf of the gas, or 413 Bcf more thanin 1998. The largest increase occurred in California, where end-useconsumption reached nearly 2.1 Tcf, up 137 Bcf over 1998, accordingto the EIA. The largest decrease was witnessed in Texas last year,with end-use demand declining by 128 Bcf to 3.5 Tcf, the agencynoted.
By customer classes, residential demand rose by 5% to 4.7 Tcf in1999; commercial gas consumption increased 2% to 3 Tcf; andindustrial consumption increased 4% to 9 Tcf. But surprisingly,consumption of gas by electric utilities fell by 4% to 3.1 Tcf lastyear, the EIA report said. This was due to the fact that someelectric utility consumption was reclassified as industrial demand.When utilities sell generation facilities, the facilities arereclassified as non-utility generators, and the natural gas thatthey consume is reported as industrial consumption rather thanelectric utility consumption, the agency noted.
In the residential market, the largest run-up in consumptionlast year was seen in Illinois, where demand rose by 35 Bcf or 9%.The biggest change in commercial gas demand came in the Californiamarket, with consumption dropping 13% to 37 Bcf.
As residential customers prepare for high gas bills this winter,the EIA report reminded them they have enjoyed two consecutiveyears of declining delivered gas prices. Last year, averagedelivered prices for residential users fell 2% to $6.69/Mcf from$6.82/Mcf. Residential customers got the benefit of the lowerdelivered prices, even though the average wellhead price rose 11%to $2.17/Mcf last year.
Still, the agency noted residential customers continue to paymuch higher prices for natural gas than do commercial andindustrial consumers. The average price for commercial customersfell 3% to $5.33/Mcf in 1999, while average prices for industrialswho continue to buy from LDCs were about 1% lower, $3.10/Mcf. Theexception was electric utilities, which on average paid 9% more($2.62/Mcf) for natural gas in 1999 than in the prior year,according to the EIA.
Gas imports from Canada and Mexico are playing a bigger role inthe U.S. gas market. Last year, net imports rose to a record levelof 3.4 Tcf, capturing 16% of domestic gas demand, the agency reportsaid. From Canada alone, gas imports grew by 10% last year comparedto 5% in 1998 due to “significant increases in crossbordercapacity” brought about by two pipeline projects: a Great Lakes GasTransmission expansion that added 126 MMcf/d of capacity; andNorthern Border Pipeline’s 700 MMcf/d expansion. The EIA also citeda third pipeline project, the Portland Natural Gas TransmissionSystem, which began transporting about 147 Bcf/d of Canadian gasinto U.S. Northeast markets last March.
The U.S./Canadian crossborder capacity expansion has continuedthroughout 2000, with the Maritimes and Northeast Pipeline —which began operating last January — delivering about 400 MMcf/dof Canadian gas to New England markets, and the Alliance Pipeline,which is scheduled to go into operation in late October, totransport 1.3 Bcf/d of Canadian gas to the U.S. Midwest markets. Asfor Mexico, the U.S. imported 55 Bcf of natural gas from thecountry by pipeline last year, more than triple the 1998 level of15 Bcf. On the flip side, natural gas exports to Mexico last yearreached their highest level since 1995 — 61 Bcf — whereasexports to Canada dropped 3% to 39 Bcf.
The U.S. pipeline grid is rapidly expanding. Last year, pipelinecompanies completed and placed into service at least 35 pipelineconstruction projects representing more than 6.6 Bcf/d ofadditional capacity, the EIA said. “…..[O]nly three were whollynew pipeline systems, while the rest were extensions or expansionsto existing systems, construction of large laterals off of mainlinetransmission systems (mainly to serve new gas-fired electric powergeneration facilities) or large gathering system header lines.”
For 2000, the EIA estimated that 28 expansions have been plannedthat would contribute up to 7.2 Bcf/d of additional capacity to thenational pipeline network. “As in 1999, expansion of importcapacity into the Northeast and Midwest United States will accountfor a large portion of the new capacity,” it said.
In addition to gas imports, imports of liquefied natural gas(LNG) into the U.S. nearly doubled in 1999, reaching 163 Bcf, thehighest level since 1979. Algeria continued to be the majorsupplier of LNG to the U.S., shipping 76 Bcf or 46% of total U.S.LNG imports. A new source, the new liquefaction facility andterminal in the Republic of Trinidad and Tobago, began shipping 51Bcf to the LNG receiving terminal in Everett, MA, in May 1999.
While the price for gas from Canada and Mexico rose last year,the price of LNG imports fell 6% to $2.47/Mcf in 1999. “Thisdecline occurred as global demand for LNG diminished,” according tothe EIA.
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