at the end of August. Moody’s said that it expected to reconfirm its ‘B1’ rating on the subor-
dinated notes if the banks granted the waiver and Drax was able to replenish the Debt Service
Reserve Account, but otherwise it would have to downgrade the notes by at least one notch.
As of late February 2002 Drax’s parent AES owned all or part of 182 power plants in 31
countries, most of them acquired in the past five years and financed with US$22 billion debt
then outstanding, US$16.5 billion issued by subsidiaries such as Drax on non-recourse terms.
It employed 60,000 people, although only 100 worked in its Arlington headquarters. The
price of the company’s shares had climbed from less than US$5 in 1994 to a peak of
US$67.50 in 1999, but they were now trading below US$5. Analysts were concerned that the
company could run out of money at the end of the year as a result of two primary factors:
falling worldwide wholesale electricity prices and economic difficulty in Latin America,
where half the company’s assets were located.^4
The company responded with a restructuring plan to sell off US$1.0–1.5 billion in assets
to shore up its balance sheet and boost liquidity, and to reduce its capital spending on new
construction by US$500 million to US$700 million. Company officials said that over the long
term AES would sell a large part of its merchant generation business, which made it too sus-
ceptible to swings in the price of electricity. As part of the restructuring effort, AES hired a
consultant to help it to reevaluate Drax and other investments in the United Kingdom.
By March 2002 electricity for the summer months in the United Kingdom was selling at
£13.60 per MWh, which was below the operating costs of some plants. AES had recently said
that Drax’s marginal costs were just £9 per MWh, helped by low-cost coal contracts with UK
Coal plc and a relatively high level of efficiency, at 38 per cent. However, industry experts
believed that the fully absorbed cost for the entire plant had to be considerably higher. They
questioned whether even a plant with Drax’s high efficiency could operate profitably through
the summer. An article in the Dow Jones Energy Service estimated that coal-fired units small-
er than 200 MW could generate power for about £14 per MWh, while units around 500 MW
could achieve £12.87 per MWh, assuming 35 per cent efficiency and an international coal
price of £1.25 per gigajoule, including transport charges. Additional costs for imbalance
charges (when the plant produces more or less than its contracted amount), connection costs
and a conservative estimate of unplanned outage costs would add £1 per MWh, bringing the
total estimated generating cost of a coal-fired plant to £14–15 per MWh. As a result it
appeared likely that some operators of older coal-fired plants would turn them off for the
summer or mothball them for longer periods.^5
Also in March 2002 AES closed its 363 MW coal-fired Fifoots power plant in Wales and
put it into receivership because wholesale electricity prices were not covering its operating
costs. In addition, the company put its 230 MW gas-fired Barry plant, also in Wales, up for
sale. Fifoots, built in 1963, thus became the first IPP to fail after the implementation of
NETA. AES had bought the plant in 1996 after it had been mothballed for four years by its
previous owner, National Power. AES had spent about US$200 million refurbishing the plant.
As part of that process, it had installed flue-gas desulphurising equipment, which had
increased its operating cost by an undisclosed amount. During the spring several other power
companies in the United Kingdom, including TXU Europe and PowerGen, also decided to
mothball uneconomic power plants.
In May 2002 TXU Europe reportedly told its lawyers to scrutinise the terms of the hedg-
ing contract. This raised concerns because Drax had been required to renegotiate its insurance
after 11 September 2001 and was not as fully covered as before, creating a technical default
DRAX, UNITED KINGDOM