Dominion Power 2006 Annual Report Download - page 80

Presented below is selected information regarding the salesof
investment securities. In determiningrealized gainsand losses, the
cost of these securities was determined on aspecific identification
basis.
Year Ended December 31, 2006 2005 2004
(millions)
Available-for-sale securities:
Proceeds from sales $1,025 $754 $463
Realized gains 90 46 57
Realized losses 77 49 90
Trading securities:
Net unrealized gain 964
NOTE 12. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their
respective balances are:
At December 31, 2006 2005
(millions)
Utility:
Generation $10,088 $10,243
Transmission 3,627 3,570
Distribution 7,944 8,408
Storage 1,109 947
Nuclear fuel 907 870
Gas gathering andprocessing 433 433
General andother 735 736
Plant under construction 1,136 954
Total utility 25,979 26,161
Nonutility:
Exploration andproduction properties being
amortized:
Proved 11,747 9,929
Unproved 913 753
Unproved exploration andproduction properties
not being amortized 1,067 1,022
Merchant generation—nuclear 1,034 1,109
Merchant generation—other 1,311 1,612
Nuclear fuel 441 361
Other—including plant under construction 1,083 1,116
Total nonutility 17,596 15,902
Total property, plant and equipment $43,575 $42,063
Costs of unproved properties capitalized under the full cost
methodof accounting that were excluded from amortization at
December 31, 2006 and the years in which such excluded costs
were incurred, are as follows:
Total 2006 2005 2004
Years
Prior
(millions)
Property acquisition costs $573$135 $61 $17 $360
Exploration costs 335 184 73 3246
Capitalized interest 159 36 29 24 70
Total $1,067 $355 $163 $73 $476
There were no significant properties under development, as
defined by the SEC, excluded from amortization at December 31,
2006. As gas and oil reservesare provedthrough drillingor as
properties are deemed to be impaired, excluded costs and any
related reservesare transferred on an ongoing, well-by-well basis
into the amortization calculation.
Amortization rates forcapitalized costs under the full cost
methodof accounting for our U.S. and Canadian cost centers
were as follows:
Year Ended December 31, 2006 2005 2004
(Per Mcf Equivalent)
U.S. cost center $1.65 $1.41 $1.28
Canadian cost center 2.19 1.82 1.18
Volumetric Production PaymentTransactions
In 2005, we received $424 million in cash for the sale of a fixed-
term overriding royalty interest in certain of our natural gas
reservesforthe period March 2005 through February 2009. The
sale reduced our proved natural gas reserves by approximately 76
billion cubic feet (bcf). While we are obligatedunder theagree-
ment todeliver to the purchaseritsportion of future natural gas
productionfrom the properties, we retain control of the proper-
ties and rights to future development drilling.If production from
the properties subject tothesale is inadequate to deliver the
approximately 76 bcf of natural gas scheduled fordeliveryto the
purchaser,wehave no obligation to make up the shortfall. Cash
proceeds received from this VPP transaction were recorded as
deferred revenue.Werecognize revenue as natural gas is produced
and delivered to the purchaser. We previouslyentered into VPP
transactions in 2004 and 2003 forapproximately 83 bcf for the
period May 2004 through April 2008 and 66 bcf for the period
August 2003 through July 2007, respectively. The remaining
deferred revenue amounts were $248 million and $510 million at
December 31, 2006 and 2005, respectively.
Sale of E&P Properties
In 2006, we received approximately $393 million of proceeds
from the sale of gas and oil properties,primarily resulting from
the fourth quarter sale of certain properties located in Texas and
New Mexico. The proceeds were credited to our U.S. full cost
pool.
In December 2004, we sold the majority of our natural gas
and oil assetsin British Columbia, Canada, for$476 million,
which was credited to our Canadianfull cost pool. We received
cash proceeds of $320 millioninDecember 2004 and $156 mil-
lion in January 2005. The properties sold producedabout 30 bcf
equivalent net of natural gas annually. We recorded expenses of
$10 million in other operations and maintenance expense related
to the sale.
Jointly-Owned Power Stations
Our proportionate share of jointly-owned power stations at
December 31, 2006 is as follows:
Bath County
Pumped
Storage
Station
North Anna
Power
Station
Clover
Power
Station
Millstone
Power
Station(1)
(millions, except percentages)
Ownership interest 60.0% 88.4% 50.0% 93.5%
Plant in service $1,017 $1,998 $553 $534
Accumulated depreciation (406) (964) (132) (92)
Nuclear fuel —399—244
Accumulated amortization of
nuclear fuel —(331) — (159)
Plant under construction 10 63 435
(1) Represents our ownership interest in Millstoneunit 3.
DOMINION2006 Annual Report 79