Dominion Power 2006 Annual Report Download - page 50

purchases of nuclear fuel and expenditures to explore forand
develop natural gas and oil properties. We expect tofund our
capital expenditures with cash from operations and a combination
of securities issuances and short-term borrowings.
Based on available generation capacity and current estimates of
growth in customer demand, we will need additional generation
in the future. We currently have plans to restart our Hopewell
plant in 2007, a 63 Mw (at net summer capability) coal burning
plant located in Hopewell, Virginia, which has been out of service
since 2003, and we are evaluating a 290 Mw (at net summer
capability) expansion of our Ladysmith site in Ladysmith, Virgin-
ia. We are also leading a consortium of companies that are
considering building a500to 600 Mw coal-fired plant in south-
west Virginia. We will continue to evaluate the development of
new plants to meet customer demand foradditional generation
needs in the future.Through 2009, we will continue to meet any
additional capacity requirements through market purchases.
We maychoose to postpone or cancel certain planned capital
expenditures in order to mitigate the need forfuture debt
financings.
Use of Off-Balance Sheet Arrangements
GUARANTEES
We primarily enter into guarantee arrangements on behalf of our
consolidated subsidiaries. These arrangements are not subject to
the recognition and measurement provisions of FASB Inter-
pretationNo. 45, Guarantor’s Accounting andDisclosure Require-
ments for Guarantees, Including Indirect Guarantees of Indebtedness
of Others. See Note 23 to our Consolidated Financial Statements
forfurther discussion of these guarantees.
At December 31, 2006, we have issued$32million of guaran-
tees to support third parties, equity method investees and
employees affected by Hurricane Katrina. In addition, in 2005,
we, along with two other gasand oil E&P companies, entered
into afour-year drillingcontract related to anew, ultra-deepwater
drillingrig that is expected to be delivered in mid-2008. The
contract has a four-year primary term, plus fourone-year
extension options.Our minimum commitment under the agree-
ment is forapproximately $99 million over the four-year term;
however, we are jointly and severally liable forup to $394 million
to the contractor if the other parties fail to pay the contractor for
their obligations under the primary term of the agreement. We
believe this scenario is improbable and have not recognized any
significant liabilities related to any of these arrangements.
In 2006, we, along with three other gasand oil exploration
companies, executed agreements with athird party to design,
construct, install and own the ThunderHawk facility,asemi-
submersible productionfacility to be located in the deepwater
Gulf of Mexico. We anticipate that mechanical completion of the
Thunder Hawk facility will occur in 2009 and that the processing
of our productionwill start by 2010. Due to current offshore
insurance marketconditions, it is anticipated that the Thunder
Hawk facility will only be partially insured against a catastrophic
full or partial loss.We, along with the threeother participating
producers, will be required to continue to make demand pay-
ments in the event of acatastrophic lossif insurance payments are
not sufficient to pay the lessor’s outstanding debt incurred for the
Thunder Hawk facility. The agreements require that we pay a
demand charge of approximately $63 millionoverfiveyears start-
ing on the day after the mechanical completion of the Thunder
Hawk facility. Our obligation will terminate upon the earlier
event of full payment of the lessor’s debt incurred forthe Thun-
der Hawk facility or the full payment of our demand charge obli-
gation. We believe that it is unlikely that we would be required to
perform under this guarantee and have not recognized any sig-
nificant liabilities for this arrangement. The agreements also
require the payment of productionprocessingfees including a
minimum processing fee if yearly productionprocessingfees are
below specified amounts. Our maximum obligation for the
minimum processing fee would be approximately $3 million per
year. Our obligation for the payment of these processing fees will
terminate upon the cessation of our production.
LEASING ARRANGEMENT
We have an agreementtolease the Fairless power station in Penn-
sylvania, which began commercial operations in June 2004.
During construction, we actedas the construction agent for the
lessor, controlled the design andconstruction of the facility and
have since been reimbursed forall project costs($898 million)
advanced to the lessor. We make annual lease payments of $53
million. The lease expires in 2013 and at that time, we mayrenew
the lease at negotiated amounts based on original project costs
and current market conditions, subject to lessorapproval; pur-
chase Fairless at itsoriginal construction cost; or sell Fairless, on
behalf of the lessor, to an independent third party. If Fairless is
sold and the proceeds from the sale are less than its original con-
struction cost, we would be required to make apayment tothe
lessorinan amountupto 70.75% of original project costs
adjusted forcertain other costs as specified in the lease. The lease
agreement does not contain anyprovisions that involve credit
rating or stock price trigger events.
Benefits of this arrangement include:
Certain taxbenefits as we are considered the ownerof the
leased property fortax purposes. As aresult, we are entitled to
taxdeductions fordepreciation not recognized forfinancial
accounting purposes; and
As an operatinglease forfinancial accounting purposes, the
asset and related borrowings used to finance the construction
of the asset are not included in our Consolidated Balance
Sheets. Although this improves measures of leverage calculated
using amounts reported in ourConsolidated Financial State-
ments, credit rating agencies view lease obligationsasdebt
equivalents in evaluating our credit profile.
FUTUREISSUESANDOTHER MATTERS
Status of Electric Restructuring in Virginia
1999 VIRGINIA RESTRUCTURINGACT
The Virginia Electric Utility Restructuring Act (1999 Virginia
Restructuring Act) was enacted in 1999 and established aplan to
restructure the electric utility industry in Virginia. In general, this
legislation provided for a transition from bundled cost-based rates
forregulated electric service to unbundled cost-based rates for
transmission and distribution services, and to market pricing for
generation services, including retail choice forour customers. The
1999 VirginiaRestructuring Act addressed capped base rates,
RTO participation, retail choice, stranded costsrecovery, and
functional separation of an electric utility’s generation from its
transmission and distribution operations.
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