Technological advances in electric generation and telecommunications make utility competition both possible and inevitable. These economic forces will eventually break down the regulatory...
Gas Crisis Forum: Is It Real, or Is It Hype?
a small percentage of the total wells drilled, with production lagging discovery by many years in remote areas.
Timely Industry Response
In both Canada and the United States, cheap and quick drilling prospects are declining after 20 years of steady exploitation. There is still money to be made on such plays, but the overall prospect mix is shifting to larger, deeper, more remote locations requiring greater per-well expenditures, potential delays in infrastructure access and, therefore, greater financial risk. This escalation in cost and requisite remuneration is a secular trend, not a cyclical phenomenon, requiring higher price expectations to justify investment.
Supply response does not consist solely of drilling activity, however. Demand growth also has highlighted constraints in the existing gas transmission infrastructure, attracting capital to capture the large price differentials that develop when too much gas deliverability is chasing too little pipeline capacity, such as in the Rocky Mountains, the San Juan Basin and, until recently, the Western Canadian Sedimentary Basin. A persistent transmission bottleneck out of Alberta was eliminated in the late 1990s with the opening of Alliance Pipeline and the numerous expansions of existing pipelines.
Other transmission projects are coming to fruition, and more are on the way. The Kern River Gas Transmission expansion project, in service May 1 of this year, is a case in point. The Kern River expansion, designed to bring incremental supplies of Rockies gas reserves to new power generation markets in Nevada and California, can now deliver enough fuel to generate about 5,500 MW of wholesale power supply. This new pipeline capacity (900 MMcf/d) immediately caused the Rockies basis differential (versus the Henry Hub) to fall from over $2.00 in April to about $1.00 as of mid-June, with producers pocketing the difference.
Meanwhile, the rig count continues to climb, with the overall U.S. oil and gas rig count at 1,071 as of mid-June (85 percent gas-oriented and up from 842 a year earlier) while the Canadian rig count has climbed to 344 from 222 over the same period. Higher gas price expectations have pushed many marginal high risk/high reward projects to the front burner as E&P companies review and pursue their prospect inventories. The North American resource base, variously estimated at 1,500 to 2,000 Tcf, indicates a domestic industry entering the decline mode some 20-30 years in the future, not today.
One final source of supply augmentation receiving much press these days is LNG imports. The immediate opportunity resides in the four existing import terminals (Lake Charles, La.; Elba Island, Ga.; Everett, Mass.; and Cove Point, Md.). In the short term, expanded LNG manufacturing capacity in Trinidad and Nigeria will find homes in the newly reopened Cove Point and Elba Island terminals. Cove Point alone will add 1 Bcf/d of incremental deliverability directly into the Mid-Atlantic region (enough to heat 3.5 million homes or fuel 6+ GW of CCGT capacity) later this year, bypassing upstream pipeline bottlenecks. Elba Island is ramping up production toward a sustainable 450 MMcf/d, to be expanded to 800 MMcf/d in late 2005. Other plant expansions are in the works elsewhere