Dominion Power 2005 Annual Report Download - page 37

Dominion 2005 35
Operating Expenses and Other Items
Electric fuel and energy purchases expense increased 30%
to $2.2 billion, primarily reflecting:
•A $408 million increase related to regulated utility operations
resulting from the combined effects of an increase in the fixed
fuel rate and the elimination of fuel deferral accounting for the
Virginia jurisdiction, which resulted in the recognition of fuel
expenses in excess of amounts recovered in fixed fuel rates. The
increase also reflects higher generation output;
•A $162 million increase related to nonregulated retail energy
marketing operations discussed in Operating Revenue;
•An $88 million increase related to merchant generation opera-
tions, largely due to the addition of Fairless, partially offset by
decreased fuel expense at certain other stations resulting from
lower generation output; partially offset by
•A $163 million decrease related to energy marketing and risk
management activities.
Purchased gas expense increased 35% to $2.9 billion, princi-
pally resulting from:
•A $357 million increase associated with gas aggregation activi-
ties and nonregulated retail energy marketing operations dis-
cussed in Operating Revenue;
•A $130 million increase associated with regulated gas distribu-
tion operations discussed in Operating Revenue;
•A $66 million increase from gas transmission operations due to
increased gathering and extraction activities and higher gas
usage; and
•A $58 million increase associated with exploration and
production operations discussed in Operating Revenue.
Other energy-related commodity purchases expense
increased 122% to $989 million, primarily reflecting a $348 million
increase in coal purchased for resale, a $108 million increase
related to purchases of oil by our exploration and production opera-
tions and a $105 million increase in the cost of emissions
allowances purchased for resale, each of which are discussed in
Operating Revenue.
Other operations and maintenance expense decreased 6%
to $2.8 billion, resulting from:
•A $113 million net benefit due to favorable changes in the fair
value of certain oil options related to exploration and production
operations. During 2004, we effectively settled certain oil
options not designated as hedges by entering into offsetting
option positions that had the effect of preserving approximately
$120 million in mark-to-market gains attributable to favorable
changes in time value; and
•The impact of the following charges recognized in 2003:
•A $197 million charge representing incremental electric util-
ity restoration expenses associated with Hurricane Isabel;
•A $108 million charge from asset and goodwill impairments
associated with DCI’s financial services operations;
•A $105 million charge associated with the termination of
certain long-term power purchase agreements;
•A $64 million charge for the restructuring of certain electric
sales contracts recorded as derivative assets;
•A $60 million goodwill impairment associated with the pur-
chase of the remaining interest in the telecommunications
joint venture, Dominion Fiber Ventures, LLC (DFV), held by
another party;
•A $28 million charge related to severance costs for work-
force reductions; and
•A $22 million impairment related to CNG International’s
(CNGI) generation assets that were sold in December 2003.
These benefits were partially offset by the following charges and
incremental expenses recognized in 2004:
•A $184 million charge related to the sale of our interest in a
long-term power tolling contract;
•A $96 million loss related to the discontinuance of hedge
accounting for certain oil hedges resulting from an interruption
of oil production in the Gulf of Mexico caused by Hurricane Ivan,
and subsequent changes in the fair value of those hedges dur-
ing the third quarter;
•A $72 million charge associated with the impairment of retained
interests from mortgage securitizations and venture capital and
other equity investments held by DCI;
•A $71 million net charge associated with the termination of cer-
tain long-term power purchase agreements;
•An approximate $60 million increase in costs related to gas and
oil production activities;
•An $18 million increase in reliability expenses associated with
utility operations primarily due to increased tree-trimming;
•A $13 million increase related to salaries, wages and benefits
resulting from a $60 million increase in pension and medical
benefits and a $46 million increase due to wage increases and
other factors, partially offset by an $89 million decrease in
incentive-based compensation expense due to failure to meet
targeted earnings goals; and
•A $10 million charge associated with the sale of our natural gas
and oil assets in British Columbia, Canada.
Depreciation, depletion and amortization expense
increased 7% to $1.3 billion, largely due to incremental deprecia-
tion expense resulting from property additions, including those
resulting from the consolidation of certain variable interest entities
as a result of adopting FIN 46R at December 31, 2003.
Other taxes increased 9% to $519 million, primarily due to
higher gross receipts taxes and higher severance and property taxes
associated with increased commodity prices.
Other income increased to $167 million from a net loss of $40
million in 2003, primarily reflecting:
•A $61 million increase resulting from net realized gains (includ-
ing investment income) associated with nuclear decommission-
ing trust fund investments as opposed to net realized losses
(net of investment income) in 2003;
•A $23 million benefit associated with the disposition of CNGI’s
investment in Australian pipeline assets that were sold during
2004; and
•The impact of the following charges recognized in 2003, which
did not recur in 2004:
•$57 million of costs associated with the acquisition of DFV
senior notes;
•$27 million for the reallocation of equity losses between us
and the minority interest owner of DFV; and
•A $62 million impairment of CNGI’s investment in Australian
pipeline assets held for sale.
Income tax expense
— Our effective tax rate decreased 3.0% to
35.6% for 2004, reflecting an increase in the valuation allowance
for 2003 with no comparable increase in 2004, partially offset by
increases in 2004 in utility plant differences and other factors.
Loss from discontinued operations decreased to $15 million
from $642 million, primarily reflecting the sale of our discontinued