(April 2012) MidAmerican Energy awarded a contract to Siemens Energy to supply wind turbines for its 407-MW project expansion. American Electric Power began operating the 580-...
Gas Turbinemania: The Merchant Power Plant
April 11, 2001, Entergy took at least an estimated $1.15 per share write-off on 225 million shares, with details to be announced later. A year earlier, Entergy had sold its rights to 22 turbines to a "special purpose entity ... formed through equity contributions from an unrelated third party." 5 Sound familiar? Entergy retained a guarantee "of up to $309 million" due to this turbine "transfer." Apparently this guarantee was triggered in April 2002.
But Entergy is unfazed, announcing: "... we expect to be more a buyer than a builder of generating assets. ... Entergy is in a strong financial position to seize opportunities in the 'distressed' asset market we see developing." 6
In addition, TECO is an ambitious merchant with a rich cash flow fueled by utility depreciation and earnings and Section 29 tax credits (of 56 million in 2001). But TECO hired an Enron subsidiary to build its plants. As a result, TECO is facing $63 million in cover payments and $200 million in accelerated payments due to Enron's collapse.
As the shakeout continues, the buyers include AEP, FPL Energy, CLECO, GE Capital, Aquila, and TXU. Leading sellers are AES, Cogentrix, Calpine, NRG, and Mirant. Meanwhile, as shown in Figure 1, collapsing equity P/Es have dried up financing for merchant plants. The bonds of many independent merchants have fallen to junk status.
New Turbine Capacity Factor & Efficiency Data:
Looking To The Crystal Ball
Had the turbine boom not encountered Enron's difficulties, it would have ended as new units failed to achieve the capacity factors needed to achieve the pro-forma financial results lenders had been promised. This metric applies to CTs and combined-cycle combustion turbines (CCGT), but the expected capacity factor is lower for the former peakers than for the combined-cycle units. About 40 percent of the turbines added to the U.S. generation base in 2001 were CTs and 60 percent CCGTs. The capacity factors for the 1999-2001 classes of CCGTs are shown ().
Certainly, capacity factor data can be influenced by start up problems, which have plagued the class of 1999 (six units) for three years.
The classes of 2000 and 2001 achieved respectively 45 percent and 42 percent capacity factors in 2001. These capacity factors are examined on a regional basis ().
The data suggest that merchant CCGTs located outside the markets of New England, Texas, and Arizona-Nevada may have difficulty achieving "bankable" capacity factors. The New England, Texas, and Arizona-Nevada (California) markets generally have steam gas or oil units operating as marginal (the highest cost) units most of the year.
Therefore, in these regions new CCGTs with superior efficiency will be economically competitive most of the time. In contrast, in 2001 some 30 plants located outside these regions achieved an 11 percent weighted average capacity factor.
If this level is sustained, new CCGTs in the following power pools could face difficulty achieving acceptable merchant revenues: PJM, SERC, VACAR, MAPP, MAIN, SPP, and ECAR.
Moreover, another test of CCGT viability is whether new units are achieving the expected high efficiency (low heat rate) levels expected of them ().