Dominion Power 2007 Annual Report Download - page 88

Notes to Consolidated Financial Statements, Continued
N OTE 13. P ROPERTY ,P LANT AND
E QUIPMENT
Major classes of property, plant and equipment and their
respective balances are:
At December 31, 2007 2006
(millions)
Utility:
Generation $10,237 $10,088
Transmission 3,817 3,627
Distribution 8,332 7,944
Storage 1,146 1,109
Nuclear fuel 930 907
Gas gathering and processing 647 433
General and other 732 735
Other—including plant under construction 1,819 1,136
Total utility 27,660 25,979
Nonutility:
Exploration and production properties being
amortized:
Proved 1,789 11,747
Unproved —913
Unproved exploration and production properties
not being amortized 10 1,067
Merchant generation—nuclear 1,077 1,034
Merchant generation—other 1,393 1,311
Nuclear fuel 482 441
Other—including plant under construction 920 1,083
Total nonutility 5,671 17,596
Total property, plant and equipment $33,331 $43,575
Following the sale of our non-Appalachian E&P operations,
costs of unproved properties capitalized under the full cost
method of accounting that were excluded from amortization at
December 31, 2007 were not material. There were no significant
properties under development, as defined by the SEC, excluded
from amortization at December 31, 2007. As gas and oil reserves
are proved through drilling or as properties are deemed to be
impaired, excluded costs and any related reserves are transferred
on an ongoing, well-by-well basis into the amortization calcu-
lation.
Amortization rates for capitalized costs under the full cost
method of accounting for our U.S. and Canadian cost centers
were as follows:
Year Ended December 31, 2007 2006 2005
(Per mcf equivalent)
U.S. cost center $1.90 $1.65 $1.41
Canadian cost center —(1) 2.19 1.82
mcf = thousand cubic feet
(1) As a result of the sale of our Canadian E&P operations in June 2007,
we discontinued the amortization of capitalized unproved property costs
for the Canadian cost center as of June 30, 2007. The amortization rate
for capitalized costs for our Canadian cost center as of June 2007 was
$1.89 per mcf equivalent.
Volumetric Production Payment Transactions
In 2005, we received $424 million in cash for the sale of a fixed-
term overriding royalty interest in certain of our natural gas
reserves for the period March 2005 through February 2009. The
sale reduced our proved natural gas reserves by approximately 76
billion cubic feet (bcf) in 2005. While we were obligated under
the agreement to deliver to the purchaser its portion of future
natural gas production from the properties, we retained control of
the properties and rights to future development drilling. If pro-
duction from the properties subject to the sale was inadequate to
deliver the approximately 76 bcf of natural gas scheduled for
delivery to the purchaser, we had no obligation to make up the
shortfall. Cash proceeds received from this VPP transaction were
recorded as deferred revenue. We recognized revenue as natural
gas was produced and delivered to the purchaser. We previously
entered into VPP transactions in 2004 and 2003 for approx-
imately 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. During 2007, in conjunction with the sale of our
non-Appalachian E&P operations, we paid $250 million to
terminate the VPP agreements and have retained the repurchased
fixed-term overriding royalty interests formerly associated with
these agreements.
Sale of E&P Properties
In 2007, we sold our non-Appalachian natural gas and oil E&P
operations and assets for approximately $13.9 billion, which
included the sale of a portion of our U.S. full cost pool and our
entire Canadian full cost pool.
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.
Jointly-Owned Power Stations
Our proportionate share of jointly-owned power stations at
December 31, 2007 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 $1,013 $2,053 $ 557 $ 791
Accumulated depreciation (415) (998) (141) (141)
Nuclear fuel — 457 — 253
Accumulated amortization
of nuclear fuel — (356) — (162)
Plant under construction 10 110 1 55
(1) Represents our ownership interest in unit 3.
The co-owners are obligated to pay their share of all future con-
struction expenditures and operating costs of the jointly-owned
facilities in the same proportion as their respective ownership inter-
est. We report our share of operating costs in the appropriate operat-
ing expense (electric fuel and energy purchases, other operations and
maintenance, depreciation, depletion and amortization and other
taxes, etc.) in our Consolidated Statements of Income.
86 Dominion 2007 Annual Report