VIRGINIA
(State
or other jurisdiction of incorporation or organization)
|
54-1229715
(I.R.S.
Employer Identification No.)
|
120
TREDEGAR STREET
RICHMOND,
VIRGINIA
(Address
of principal executive offices)
|
23219
(Zip
Code)
|
(804)
819-2000
(Registrant's
telephone number)
|
Page
Number
|
||
PART
I. Financial Information
|
||
Item
1.
|
|
|
|
3
|
|
|
4
|
|
|
6
|
|
|
7
|
|
Item
2.
|
|
23
|
Item
3.
|
|
36
|
Item
4.
|
|
38
|
PART
II. Other Information
|
||
Item
1.
|
|
39
|
Item
1A.
|
|
40
|
Item
2.
|
|
42
|
Item
4.
|
|
43
|
Item
6.
|
|
45
|
Three
Months Ended March 31,
|
||
2006
|
2005
|
|
(millions,
except per share amounts)
|
||
Operating
Revenue
|
$4,957
|
$4,736
|
Operating
Expenses
|
||
Electric
fuel and energy purchases
|
766
|
841
|
Purchased
electric capacity
|
123
|
134
|
Purchased
gas
|
1,378
|
1,222
|
Other
energy-related commodity purchases
|
400
|
324
|
Other
operations and maintenance
|
768
|
831
|
Depreciation,
depletion and amortization
|
381
|
346
|
Other
taxes
|
181
|
165
|
Total
operating expenses
|
3,997
|
3,863
|
Income
from operations
|
960
|
873
|
Other
income
|
43
|
51
|
Interest
and related charges:
|
||
Interest
expense
|
234
|
217
|
Interest
expense - junior subordinated notes payable to affiliated
trusts
|
27
|
26
|
Subsidiary
preferred dividends
|
4
|
4
|
Total
interest and related charges
|
265
|
247
|
Income
before income tax expense
|
738
|
677
|
Income
tax expense
|
204
|
248
|
Net
Income
|
$ 534
|
$ 429
|
Earnings
Per Common Share - Basic
|
$1.54
|
$1.26
|
Earnings
Per Common Share - Diluted
|
$1.53
|
$1.25
|
Dividends
paid per common share
|
$0.69
|
$0.67
|
ASSETS
|
March
31,
2006
|
December
31,
2005(1)
|
(millions)
|
||
Current
Assets
|
||
Cash
and cash equivalents
|
$ 69
|
$ 146
|
Accounts
receivable:
|
||
Customer
(less allowance for doubtful accounts of $24 and $38)
|
2,646
|
3,335
|
Other
(less allowance for doubtful accounts of $9 at both dates)
|
263
|
226
|
Inventories
|
888
|
1,167
|
Derivative
assets
|
2,483
|
3,429
|
Deferred
income taxes
|
639
|
928
|
Assets
held for sale
|
1,172
|
4
|
Other
|
847
|
894
|
Total
current assets
|
9,007
|
10,129
|
Investments
|
||
Nuclear
decommissioning trust funds
|
2,597
|
2,534
|
Available
for sale securities
|
287
|
287
|
Other
|
677
|
680
|
Total
investments
|
3,561
|
3,501
|
Property,
Plant and Equipment
|
||
Property,
plant and equipment
|
41,890
|
42,063
|
Accumulated
depreciation, depletion and amortization
|
(13,065)
|
(13,123)
|
Total
property, plant and equipment, net
|
28,825
|
28,940
|
Deferred
Charges and Other Assets
|
||
Goodwill
|
4,298
|
4,298
|
Prepaid
pension cost
|
1,894
|
1,915
|
Derivative
assets
|
1,296
|
1,915
|
Regulatory
assets
|
459
|
758
|
Other
|
1,204
|
1,204
|
Total
deferred charges and other assets
|
9,151
|
10,090
|
Total
assets
|
$50,544
|
$52,660
|
(1)
|
The
Consolidated Balance Sheet at December 31, 2005 has been derived
from the
audited Consolidated Financial Statements at that
date.
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
March
31,
2006
|
December
31,
2005(1)
|
(millions)
|
||
Current
Liabilities
|
||
Securities
due within one year
|
$ 2,378
|
$ 2,330
|
Short-term
debt
|
1,403
|
1,618
|
Accounts
payable
|
1,953
|
2,756
|
Accrued
interest, payroll and taxes
|
639
|
694
|
Derivative
liabilities
|
4,369
|
6,087
|
Liabilities
held for sale
|
459
|
--
|
Other
|
842
|
995
|
Total
current liabilities
|
12,043
|
14,480
|
Long-Term
Debt
|
||
Long-term
debt
|
13,617
|
13,237
|
Junior
subordinated notes payable to affiliated trusts
|
1,398
|
1,416
|
Total
long-term debt
|
15,015
|
14,653
|
Deferred
Credits and Other Liabilities
|
||
Deferred
income taxes and investment tax credits
|
5,129
|
4,984
|
Asset
retirement obligations
|
2,246
|
2,249
|
Derivative
liabilities
|
2,751
|
3,971
|
Regulatory
liabilities
|
589
|
607
|
Other
|
1,073
|
1,062
|
Total
deferred credits and other liabilities
|
11,788
|
12,873
|
Total
liabilities
|
38,846
|
42,006
|
Commitments
and Contingencies (see
Note 16)
|
||
Subsidiary
Preferred Stock Not Subject to Mandatory
Redemption
|
257
|
257
|
Common
Shareholders' Equity
|
||
Common
stock - no par(2)
|
11,295
|
11,286
|
Other
paid-in capital
|
127
|
125
|
Retained
earnings
|
1,844
|
1,550
|
Accumulated
other comprehensive loss
|
(1,825)
|
(2,564)
|
Total
common shareholders’ equity
|
11,441
|
10,397
|
Total
liabilities and shareholders’ equity
|
$50,544
|
$52,660
|
Three
Months Ended
March
31,
|
||
2006
|
2005
|
|
(millions)
|
||
Operating
Activities
|
||
Net
income
|
$ 534
|
$ 429
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||
Net
realized and unrealized derivative (gains)/losses
|
(241)
|
54
|
Depreciation,
depletion and amortization
|
414
|
380
|
Deferred
income taxes and investment tax credits, net
|
187
|
70
|
Charges
related to pending sale of gas distribution subsidiaries
|
172
|
--
|
Other
adjustments to net income
|
(49)
|
19
|
Changes
in:
|
||
Accounts
receivable
|
412
|
(126)
|
Inventories
|
262
|
287
|
Deferred
fuel and purchased gas costs, net
|
125
|
100
|
Accounts
payable, trade
|
(659)
|
(142)
|
Accrued
interest, payroll and taxes
|
(22)
|
145
|
Deferred
revenues
|
(79)
|
(76)
|
Margin
deposit assets and liabilities
|
(206)
|
(172)
|
Other
operating assets and liabilities
|
134
|
271
|
Net
cash provided by operating activities
|
984
|
1,239
|
Investing
Activities
|
||
Plant
construction and other property additions
|
(439)
|
(363)
|
Additions
to gas and oil properties, including acquisitions
|
(484)
|
(377)
|
Proceeds
from sale of gas and oil properties
|
--
|
580
|
Acquisition
of businesses, net of cash acquired
|
(91)
|
(642)
|
Proceeds
from sale of securities
|
273
|
126
|
Purchases
of securities
|
(281)
|
(350)
|
Other
|
36
|
68
|
Net
cash used in investing activities
|
(986)
|
(958)
|
Financing
Activities
|
||
Issuance
(repayment) of short-term debt, net
|
(215)
|
376
|
Issuance
of long-term debt
|
1,000
|
--
|
Repayment
of long-term debt
|
(609)
|
(462)
|
Issuance
of common stock
|
3
|
216
|
Repurchase
of common stock
|
--
|
(247)
|
Common
dividend payments
|
(240)
|
(230)
|
Other
|
(10)
|
(24)
|
Net
cash used in financing activities
|
(71)
|
(371)
|
Decrease
in cash and cash equivalents
|
(73)
|
(90)
|
Cash
and cash equivalents at beginning of period
|
146
|
361
|
Cash
and cash equivalents at end of period(1)
|
$ 73
|
$ 271
|
Noncash
Financing Activities
|
||
Exchange
of debt securities
|
$330
|
--
|
Issuance
of long-term debt and establishment of trust
|
47
|
--
|
Assumption
of debt related to acquisition of non-utility generating
facility
|
--
|
$62
|
(1) |
2006
amount includes $4 million of cash classified as held for sale on
the
Consolidated Balance Sheet
|
Three
Months Ended
March
31, 2005
|
|
(millions)
|
|
Net
income, as reported
|
$429
|
Add:
actual stock-based compensation expense, net of tax
|
3
|
Deduct:
pro forma stock-based compensation expense, net of tax
|
(3)
|
Net
income, pro forma
|
$429
|
Basic
EPS - as reported
|
$1.26
|
Basic
EPS - pro forma
|
$1.26
|
Diluted
EPS - as reported
|
$1.25
|
Diluted
EPS - pro forma
|
$1.25
|
March
31, 2006
|
|
(millions)
|
|
ASSETS
|
|
Current
Assets
|
|
Cash
|
$ 4
|
Customer
accounts receivable
|
243
|
Unrecovered
gas costs
|
59
|
Other
|
32
|
Total
current assets
|
338
|
Property,
Plant and Equipment
|
|
Property,
plant and equipment
|
1,100
|
Accumulated
depreciation, depletion and amortization
|
(385)
|
Total
property, plant and equipment, net
|
715
|
Deferred
Charges and Other Assets
|
|
Regulatory
assets
|
107
|
Other
|
8
|
Total
deferred charges and other assets
|
115
|
Assets
held for sale
|
$1,168
|
LIABILITIES
|
|
Current
Liabilities
|
|
Accounts
payable, trade
|
$ 61
|
Provision
for gas inventory replacement
|
52
|
Payables
to affiliates
|
30
|
Accrued
taxes
|
26
|
Deferred
income taxes
|
24
|
Other
|
37
|
Total
current liabilities
|
230
|
Deferred
Credits and Other Liabilities
|
|
Asset
retirement obligations
|
32
|
Deferred
income taxes
|
160
|
Regulatory
liabilities
|
26
|
Other
|
11
|
Total
deferred credits and other liabilities
|
229
|
Liabilities
held for sale
|
$ 459
|
Three
Months Ended
March
31,
|
||
2006
|
2005
|
|
(millions)
|
||
Operating
Revenue
|
$357
|
$316
|
Income
(loss) before income taxes
|
(128)
|
45
|
Three
Months Ended March 31,
|
||
2006
|
2005
|
|
Operating
Revenue
|
(millions)
|
|
Electric
sales:
|
||
Regulated
|
$1,298
|
$1,322
|
Nonregulated
|
600
|
714
|
Gas
sales:
|
||
Regulated
|
800
|
778
|
Nonregulated
|
882
|
745
|
Other
energy-related commodity sales
|
493
|
396
|
Gas
transportation and storage
|
285
|
275
|
Gas
and oil production
|
532
|
411
|
Other
|
67
|
95
|
Total
operating revenue
|
$4,957
|
$4,736
|
Three
Months Ended March
31,
|
||
2006
|
2005
|
|
U.S.
statutory rate
|
35.0%
|
35.0%
|
Increases
(decreases) resulting from:
|
||
Amortization
of investment tax credits
|
(0.4)
|
(0.5)
|
Employee
pension and other benefits
|
(0.4)
|
(0.3)
|
Employee
stock ownership plan and restricted stock dividends
|
(0.4)
|
(0.3)
|
Other
benefits and taxes - foreign operations
|
--
|
(1.4)
|
State
taxes, net of federal benefit
|
5.0
|
3.8
|
Other,
net
|
(1.2)
|
0.3
|
Subtotal
|
37.6
|
36.6
|
Changes
in valuation allowances
|
(29.1)
|
--
|
Recognition
of deferred taxes - stock of subsidiaries held for sale
|
19.1
|
--
|
Effective
tax rate
|
27.6%
|
36.6%
|
Three
Months Ended March 31,
|
||
2006
|
2005
|
|
(millions,
except EPS)
|
||
Net
income
|
$534
|
$429
|
Basic
EPS
|
||
Average
shares of common stock outstanding - basic
|
346.5
|
340.3
|
Net
income
|
$1.54
|
$1.26
|
Diluted
EPS
|
||
Average
shares of common stock outstanding
|
346.5
|
340.3
|
Net
effect of potentially dilutive securities (1)
|
1.6
|
2.0
|
Average
shares of common stock outstanding - diluted
|
348.1
|
342.3
|
Net
income
|
$1.53
|
$1.25
|
Three
Months Ended March 31,
|
||
2006
|
2005
|
|
(millions)
|
||
Net
income
|
$ 534
|
$ 429
|
Other
comprehensive income (loss):
|
||
Net
other comprehensive income (loss) associated with effective portion
of the changes in fair value of derivatives designated as cash
flows hedges, net of taxes and amounts reclassified to
earnings(1)
|
719
|
(888)
|
Other(2)
|
20
|
(37)
|
Other
comprehensive income (loss)
|
739
|
(925)
|
Total
comprehensive income (loss)
|
$1,273
|
$(496)
|
Three
Months Ended March 31,
|
||
2006
|
2005
|
|
Portion
of gains (losses) on hedging instruments determined to be ineffective
and
included in net income:
|
(millions)
|
|
Fair
value hedges
|
$ (7)
|
$ 4
|
Cash
flow hedges
|
19
|
(6)
|
Net
ineffectiveness
|
$ 12
|
$(2)
|
AOCI
After-Tax
|
Portion
Expected to be
Reclassified
to
Earnings
during the
Next
12 Months
After-Tax
|
Maximum
Term
|
|
(millions)
|
|||
Commodities:
|
|||
Gas
|
$ (987)
|
$ (568)
|
57
months
|
Oil
|
(570)
|
(339)
|
33
months
|
Electricity
|
(509)
|
(318)
|
45
months
|
Interest
rate
|
(15)
|
6
|
243
months
|
Foreign
currency
|
23
|
10
|
20
months
|
Total
|
$(2,058)
|
$(1,209)
|
Facility
Limit
|
Outstanding
Commercial
Paper
|
Outstanding
Letters
of
Credit
|
Facility
Capacity
Available
|
|
(millions)
|
|
|
|
|
Five-year
revolving credit facility(1)
|
$3,000
|
$1,356
|
$
631
|
$1,013
|
Five-year
CNG credit facility(2)
|
1,700
|
---
|
1,068
|
632
|
364-day
CNG credit facility(3)
|
1,050
|
---
|
---
|
1,050
|
Totals
|
$5,750
|
$1,356
|
$1,699
|
$2,695
|
Company
|
Facility
Limit
|
Outstanding
Letters
of
Credit
|
Facility
Capacity
Remaining
|
Facility
Inception
Date
|
Facility
Maturity
Date
|
|||||||||||
(millions)
|
|
|
|
|
|
|||||||||||
CNG
|
$
|
100
|
$
|
100
|
$
|
--
|
June
2004
|
June
2007
|
||||||||
CNG
|
100
|
100
|
--
|
August
2004
|
August
2009
|
|||||||||||
CNG(1)
|
150
|
--
|
150
|
October
2004
|
April
2006
|
|||||||||||
CNG(2)
|
200
|
--
|
200
|
December
2005
|
December
2010
|
|||||||||||
Dominion
Resources, Inc.(1)
|
215
|
40
|
175
|
October
2005
|
April
2006
|
|||||||||||
Totals
|
$
|
765
|
$
|
240
|
$
|
525
|
(1) |
We
did not renew these facilities prior to their maturity.
|
(2) |
This
facility can also be used to support commercial paper
borrowings.
|
Shares
|
Weighted-Average
Exercise
Price
|
Weighted-Average
Remaining Contractual
Life
|
Aggregate
intrinsic value(1)
|
|
(thousands)
|
(years)
|
(millions)
|
||
Outstanding
and exercisable at January 1, 2006
|
8,214
|
$60.43
|
||
Granted
|
--
|
--
|
||
Exercised
|
(60)
|
55.76
|
$ 1
|
|
Forfeited/expired
|
--
|
--
|
||
Outstanding
and exercisable at March 31, 2006
|
8,154
|
60.46
|
4.0
|
79
|
(1) |
Intrinsic
value represents the difference between the exercise price of the
option
and the market value of our stock.
|
Shares
|
Weighted-Average
Grant
Date Fair Value
|
|
(thousands)
|
||
Nonvested
at January 1, 2006
|
1,131
|
$63.28
|
Granted
|
3
|
76.07
|
Vested
|
(142)
|
58.84
|
Cancelled
and forfeited
|
(3)
|
63.35
|
Nonvested
at March 31, 2006
|
989
|
63.96
|
|
Stated Limit
|
Value(1)
|
(millions)
|
|
|
Subsidiary
debt(2)
|
$1,320
|
$1,320
|
Commodity
transactions(3)
|
3,766
|
1,762
|
Lease
obligation for power generation facility(4)
|
898
|
898
|
Nuclear
obligations(5)
|
375
|
303
|
Offshore
drilling commitments(6)
|
--
|
493
|
Other
|
594
|
422
|
Total
|
$6,953
|
$5,198
|
(1)
|
Represents
the estimated portion of the guarantee’s stated limit that is utilized as
of March 31, 2006 based upon prevailing economic conditions and fact
patterns specific to each guarantee arrangement. For those guarantees
related to obligations that are recorded as liabilities by our
subsidiaries, the value includes the recorded amount.
|
(2)
|
Guarantees
of debt of Dominion Resources Services (DRS), and certain DEI and
CNG
subsidiaries. In the event of default by the subsidiaries, we would
be
obligated to repay such amounts.
|
(3)
|
Guarantees
related to energy trading and marketing activities and other commodity
commitments of certain subsidiaries, including subsidiaries of CNG
and
DEI. These guarantees were provided to counterparties in order to
facilitate physical and financial transactions in gas, oil, electricity,
pipeline capacity, transportation and related commodities and services.
If
any of these subsidiaries fail to perform or pay under the contracts
and
the counterparties seek performance or payment, we would be obligated
to
satisfy such obligation. We and our subsidiaries receive similar
guarantees as collateral for credit extended to others. The value
provided
includes certain guarantees that do not have stated limits.
|
(5) |
Guarantees
related to Virginia Power’s and certain DEI subsidiaries’ potential
retrospective premiums that could be assessed if there is a nuclear
incident under our nuclear insurance programs and includes guarantees
for
Virginia Power’s commitment to buy nuclear fuel. Also, as part of
satisfying certain NRC requirements concerned with ensuring adequate
funding for the operations of the Millstone Power Station, we have
also
agreed to provide up to $150 million to a DEI subsidiary, if requested
by
such subsidiary, to pay Millstone’s operating
expenses.
|
(6) |
There
is no stated limit for this guarantee.
|
Pension
Benefits
|
Other
Postretirement Benefits
|
|||
Three
Months Ended March 31,
|
2006
|
2005
|
2006
|
2005
|
(millions)
|
||||
Service
cost
|
$35
|
$29
|
$21
|
$16
|
Interest
cost
|
58
|
54
|
23
|
20
|
Expected
return on plan assets
|
(99)
|
(93)
|
(17)
|
(13)
|
Curtailment
loss(1)
|
6
|
--
|
--
|
--
|
Amortization
of prior service cost (credit)
|
1
|
1
|
(1)
|
--
|
Amortization
of transition obligation
|
--
|
--
|
1
|
1
|
Amortization
of net loss
|
25
|
21
|
8
|
5
|
Net
periodic benefit cost
|
$26
|
$12
|
$35
|
$29
|
(1) |
Relates
to the pending sale of Peoples and Hope discussed in Note
6.
|
· |
A
$77 million ($47 million after-tax) charge related to our interest
in a
long-term power tolling contract that was divested in 2005 and the
termination of a long-term power purchase agreement;
and
|
· |
An
$11 million ($6 million after-tax) charge primarily related to our
interest in a long-term power tolling contract that was divested
in
2005.
|
Dominion
Delivery
|
Dominion
Energy
|
Dominion
Generation
|
Dominion
E&P
|
Corporate
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|
Three
Months Ended March 31,
|
(millions)
|
||||||
2006
|
|||||||
Operating
Revenue:
|
|||||||
External
customers
|
$1,672
|
$598
|
$1,659
|
$872
|
$ (37)
|
$ 193
|
$4,957
|
Intersegment
|
3
|
276
|
42
|
68
|
195
|
(584)
|
--
|
Total
operating revenue
|
1,675
|
874
|
1,701
|
940
|
158
|
(391)
|
4,957
|
Net
income (loss)
|
156
|
107
|
132
|
230
|
(91)
|
--
|
534
|
2005
|
|||||||
Operating
Revenue:
|
|||||||
External
customers
|
$1,531
|
$484
|
$1,867
|
$635
|
$ (2)
|
$ 221
|
$4,736
|
Intersegment
|
18
|
227
|
55
|
43
|
149
|
(492)
|
--
|
Total
operating revenue
|
1,549
|
711
|
1,922
|
678
|
147
|
(271)
|
4,736
|
Net
income (loss)
|
184
|
99
|
145
|
112
|
(111)
|
--
|
429
|
· |
Forward-Looking
Statements
|
· |
Accounting
Matters
|
· |
Results
of Operations
|
· |
Segment
Results of Operations
|
· |
Selected
Information — Energy Trading
Activities
|
· |
Sources
and Uses of Cash
|
· |
Future
Issues and Other Matters
|
· |
Unusual
weather conditions and their effect on energy sales to customers
and
energy commodity prices;
|
· |
Extreme
weather events, including hurricanes and winter storms, that can
cause
outages, production delays and property damage to our facilities;
|
· |
State
and federal legislative and regulatory developments, including
deregulation and changes in environmental and other laws and regulations
to which we are subject;
|
· |
Cost
of environmental compliance;
|
· |
Risks
associated with the operation of nuclear facilities;
|
· |
Fluctuations
in energy-related commodity prices and the effect these could have
on our
earnings, liquidity position and the underlying value of our
assets;
|
· |
Counterparty
credit risk;
|
· |
Capital
market conditions, including price risk due to marketable securities
held
as investments in nuclear decommissioning and benefit plan trusts;
|
· |
Fluctuations
in interest rates;
|
· |
Changes
in rating agency requirements or credit ratings and the effect on
availability and cost of capital;
|
· |
Changes
in financial or regulatory accounting principles or policies imposed
by
governing bodies;
|
· |
Employee
workforce factors including collective bargaining agreements and
labor
negotiations with union employees;
|
· |
The
risks of operating businesses in regulated industries that are subject
to
changing regulatory structures;
|
· |
Changes
in our ability to recover investments made under traditional regulation
through rates;
|
· |
Receipt
of approvals for and timing of closing dates for acquisitions and
divestitures;
|
· |
Realization
of expected business interruption insurance proceeds and decreased
availability of business interruption insurance on commercially reasonable
terms;
|
· |
Transitional
issues related to the transfer of control over our electric transmission
facilities to a regional transmission
organization;
|
· |
Political
and economic conditions, including the threat of domestic terrorism,
inflation and deflation; and
|
· |
Completing
the divestiture of investments held by our financial services subsidiary,
DCI.
|
First
Quarter
|
2006
|
2005
|
$
Change
|
Net
income (millions)
|
$ 534
|
$ 429
|
$ 105
|
Diluted
EPS
|
1.53
|
1.25
|
0.28
|
First
Quarter
|
2006
|
2005
|
$
Change
|
(millions)
|
|||
Operating
Revenue
|
$4,957
|
$4,736
|
$221
|
Operating
Expenses
|
|||
Electric
fuel and energy purchases
|
766
|
841
|
(75)
|
Purchased
electric capacity
|
123
|
134
|
(11)
|
Purchased
gas
|
1,378
|
1,222
|
156
|
Other
energy-related commodity purchases
|
400
|
324
|
76
|
Other
operations and maintenance
|
768
|
831
|
(63)
|
Depreciation,
depletion and amortization
|
381
|
346
|
35
|
Other
taxes
|
181
|
165
|
16
|
Other
income
|
43
|
51
|
(8)
|
Interest
and related charges
|
265
|
247
|
18
|
Income
tax expense
|
204
|
248
|
(44)
|
· |
A
$137 million increase in nonregulated gas sales revenue predominantly
due
to a $104 million increase from gas aggregation activities and a
$102
million increase from nonregulated retail energy marketing activities
both
primarily reflecting higher prices. These increases were partially
offset
by a $48 million decrease due to the impact of losses on derivatives
associated with certain transportation contracts. The increase in
nonregulated gas sales was largely offset by a corresponding increase
in
Purchased
gas expense;
|
· |
A
$121 million increase in gas and oil production revenue, reflecting
a $98
million increase in sales of oil production, primarily due to higher
volumes ($77 million) and increased prices ($21 million) and a $23
million
increase from gas production sales, primarily due to higher average
realized prices;
|
· |
A
$97 million increase in other energy-related commodity sales, primarily
reflecting the following:
|
· |
A
$138 million increase in sales of purchased oil under buy/sell
arrangements by exploration and production operations resulting from
higher prices ($48 million) and increased sales volumes ($90
million);
|
· |
A
$28 million increase in sales of extracted products, primarily due
to a
contractual change for a portion of our gas production processed
by third
parties. We now take title to and market the natural gas liquids
extracted
from this gas; partially offset by
|
· |
A
$62 million decline in nonutility coal sales resulting primarily
from
lower realized coal prices ($44 million) and sales volumes ($18
million).
|
· |
A
$114 million decrease in nonregulated electric sales revenue, primarily
reflecting:
|
· |
The
effects on revenue of price risk management activities associated
with our
merchant generation assets, including lower volumes for requirements-based
sales contracts ($178 million). We realized higher overall average
margins
for our merchant generation assets through financial and physical
hedges
and spot pool activity, the effects of which are also included in
the
decreases in Electric
fuel and energy purchases expense and
Other operations and maintenance expense;
partially offset by
|
· |
A
$47 million increase related to the acquisition in July 2005 of the
556-megawatt Kewaunee nuclear power station (Kewaunee);
and
|
· |
A
$21 million increase in revenue from nonregulated retail energy marketing
operations due to higher customer contract sales
rates.
|
· |
A
$28 million decrease in other revenue, largely reflecting a $44 million
decrease due to the absence of business interruption insurance revenue
recognized in 2005 associated with Hurricane Ivan, partially offset
by an
increase in miscellaneous service revenue and fees of approximately
$16
million.
|
· |
A
$160 million decrease related to merchant generation operations and
price
risk management activities associated with these assets as discussed
above
in Operating
Revenue;
and
|
· |
An
$87 million increase related to our utility generation operations,
primarily due to higher commodity prices, including purchased power
and
congestion costs associated with PJM, and the purchase of replacement
power in connection with a nuclear refueling outage. This increase
was
partially offset by lower customer usage associated with milder
weather.
|
· |
A
$135 million benefit primarily from price risk management activities,
associated with our merchant generation assets as discussed in
Operating
Revenue;
|
· |
A
$118 million benefit resulting from favorable changes in the fair
value of
certain gas and oil derivatives that were de-designated as hedges
following the 2005 hurricanes;
|
· |
A
$28 million benefit related to financial transmission rights (FTRs)
granted by PJM to our utility generation operations to offset congestion
costs associated with PJM spot market activity; and
|
· |
A
benefit resulting from the net impact of the following items recognized
in
2005:
|
· |
A
$77 million charge resulting from the termination of a long-term
power
purchase agreement; and
|
· |
A
$49 million loss related to the discontinuance of hedge accounting
for
certain oil derivatives primarily resulting from a delay in reaching
anticipated production levels in the Gulf of Mexico, and subsequent
changes in the fair value of those derivatives; partially offset
by
|
· |
A
$24 million net benefit recognized by regulated utility operations
resulting from the establishment of certain regulatory assets and
liabilities in connection with settlement of a North Carolina rate
case.
|
· |
A
$159 million charge from the write off of certain regulatory assets
related to the pending sale of Peoples and
Hope;
|
· |
A
$36 million increase due to higher salaries, wages and benefits
expenses;
|
· |
A
$32 million increase attributable to maintenance costs primarily
related
to scheduled outages at our generation
facilities;
|
· |
A
$27 million increase due to the addition of Kewaunee in July
2005;
|
· |
A
$27 million increase due to higher production and transportation
costs for
gas and oil production operations;
|
· |
A
$25 million increase in expenses for regulated gas operations related
to
low income home energy assistance programs. These expenditures for
regulated gas operations are recovered through rates and do not impact
our
net income; and
|
· |
A
$15 million increase in insurance costs for exploration and production
operations primarily due to higher insurance premiums following the
2005
hurricanes.
|
Net
Income
|
Diluted
EPS
|
|||||
First
Quarter
|
2006
|
2005
|
$
Change
|
2006
|
2005
|
$
Change
|
(millions,
except EPS)
|
||||||
Dominion
Delivery
|
$156
|
$184
|
$ (28)
|
$0.45
|
$0.54
|
$(0.09)
|
Dominion
Energy
|
107
|
99
|
8
|
0.31
|
0.29
|
0.02
|
Dominion
Generation
|
132
|
145
|
(13)
|
0.38
|
0.42
|
(0.04)
|
Dominion
Exploration & Production
|
230
|
112
|
118
|
0.66
|
0.33
|
0.33
|
Primary
operating segments
|
625
|
540
|
85
|
1.80
|
1.58
|
0.22
|
Corporate
|
(91)
|
(111)
|
20
|
(0.27)
|
(0.33)
|
0.06
|
Consolidated
|
$534
|
$429
|
$ 105
|
$1.53
|
$1.25
|
$ 0.28
|
First
Quarter
|
2006
|
2005
|
%
Change
|
Electricity
delivered (million mwhrs)
|
19.5
|
19.9
|
(2)%
|
Degree
days (electric service area):
|
|||
Cooling(1)
|
13
|
--
|
100
|
Heating(2)
|
1,796
|
2,111
|
(15)
|
Electric
delivery customer accounts(3)
|
2,318
|
2,277
|
2
|
Gas
throughput (bcf):
|
|||
Gas
sales
|
50
|
63
|
(21)
|
Gas
transportation
|
87
|
92
|
(5)
|
Heating
degree days (gas service area)
(2)
|
2,580
|
3,022
|
(15)
|
Gas
delivery customer accounts(3):
|
|||
Gas
sales
|
996
|
1,071
|
(7)
|
Gas
transportation
|
704
|
635
|
11
|
Nonregulated
retail energy marketing customer accounts(3)
|
1,199
|
1,131
|
6
|
(1) |
Cooling
degree days are the differences between the average temperature for
each
day and 65 degrees, assuming the average temperature is greater than
65
degrees.
|
(2) |
Heating
degree days are the differences between the average temperature for
each
day and 65 degrees, assuming the average temperature is less than
65
degrees.
|
(3) |
In
thousands, at period end.
|
First
Quarter
|
||
2006
vs. 2005
|
||
Increase
|
||
(Decrease)
|
||
Amount
|
EPS
|
|
(millions,
except EPS)
|
||
Regulated
gas sales - weather
|
$(12)
|
$(0.04)
|
Regulated
electric sales:
|
||
Weather
|
(9)
|
(0.03)
|
Customer
growth
|
3
|
0.01
|
Economy
and other margins(1)
|
(8)
|
(0.02)
|
Interest
expense(2)
|
(7)
|
(0.02)
|
North
Carolina rate case settlement
|
(6)
|
(0.02)
|
Nonregulated
retail energy marketing operations(3)
|
10
|
0.03
|
Other
|
1
|
--
|
Share
dilution
|
--
|
--
|
Change
in net income contribution
|
$(28)
|
$(0.09)
|
(1) |
Reflects
reduced customer usage, due in part to sensitivity to rising gas
prices.
|
(2) |
An
increase resulting from additional borrowings, as well as increased
rates
on intercompany borrowings.
|
(3) |
Largely
reflects higher electric and gas
margins.
|
First
Quarter
|
2006
|
2005
|
%
Change
|
Gas
transmission throughput (bcf)
|
234
|
301
|
(22)%
|
First
Quarter
|
||
2006
vs. 2005
|
||
Increase
|
||
(Decrease)
|
||
Amount
|
EPS
|
|
(millions,
except EPS)
|
||
Producer
services(1)
|
$15
|
$0.04
|
RTO
start-up and integration costs(2)
|
4
|
0.01
|
Gas
transmission rate settlement(3)
|
(9)
|
(0.03)
|
Other
|
(2)
|
--
|
Share
dilution
|
--
|
--
|
Change
in net income contribution
|
$ 8
|
$0.02
|
(1) |
Higher
gains resulting from the impact of favorable price changes on gas
marketing activities associated with certain contractual
assets.
|
(2) |
A
benefit from the absence of a 2005 charge incurred by our electric
utility
operations for the write-off of certain previously deferred start-up
and
integration costs associated with joining an RTO that were primarily
allocable to Virginia non-jurisdictional and wholesale
customers.
|
(3) |
Represents
lower natural gas transportation and storage revenues as a result
of a
rate settlement effective July
2005.
|
First
Quarter
|
2006
|
2005
|
%
Change
|
Electricity
supplied (million mwhrs)
|
|||
Utility
|
19.5
|
19.9
|
(2)%
|
Merchant
|
11
|
10
|
10
|
First
Quarter
|
||
2006
vs. 2005
|
||
Increase
|
||
(Decrease)
|
||
Amount
|
EPS
|
|
(millions,
except EPS)
|
||
Fuel
expenses in excess of rate recovery
|
$(32)
|
$(0.09)
|
Outage
costs
|
(19)
|
(0.05)
|
Regulated
electric sales:
|
||
Weather
|
(19)
|
(0.05)
|
Customer
growth
|
6
|
0.02
|
North
Carolina rate case settlement
|
(10)
|
(0.03)
|
Interest
expense(1)
|
(9)
|
(0.03)
|
Merchant
generation margins
|
76
|
0.22
|
RTO
start-up and integration costs
|
3
|
0.01
|
Other
|
(9)
|
(0.03)
|
Share
dilution
|
--
|
(0.01)
|
Change
in net income contribution
|
$(13)
|
$(0.04)
|
(1) |
Increase
related to higher interest rates on variable rate
debt.
|
First
Quarter
|
2006
|
2005
|
%
Change
|
Gas
production (bcf)
|
72
|
74
|
(3)%
|
Oil
production (million bbls)
|
6.1
|
3.8
|
61
|
Average
realized prices with hedging results
|
|||
Gas
(per mcf)
(1)
|
$ 4.99
|
$ 4.18
|
19
|
Oil
(per bbl)
|
38.82
|
28.91
|
34
|
Average
realized prices without hedging results
|
|||
Gas
(per mcf)
(1)
|
7.99
|
6.19
|
29
|
Oil
(per bbl)
|
53.35
|
44.72
|
19
|
DD&A
(unit of production rate per mcfe)
|
$1.66
|
$1.42
|
17
|
(1) |
Excludes
$79 million and $76 million of revenue recognized in first quarter
of 2006
and 2005, respectively under the volumetric production payment (VPP)
agreements described in Note 12 to our Consolidated Financial Statements
in our Annual Report on Form 10-K for the year ended December 31,
2005.
|
First
Quarter
|
||
2006
vs. 2005
|
||
Increase
|
||
(Decrease)
|
||
Amount
|
EPS
|
|
(millions,
except EPS)
|
||
Operations
and maintenance(1)
|
$80
|
$0.23
|
Gas
and oil ¾
prices
|
61
|
0.18
|
Gas
and oil ¾
production(2)
|
49
|
0.14
|
DD&A
|
(30)
|
(0.09)
|
Business
interruption insurance
|
(28)
|
(0.08)
|
Change
in state income tax estimate(3)
|
(10)
|
(0.03)
|
Other
|
(4)
|
(0.01)
|
Share
dilution
|
--
|
(0.01)
|
Change
in net income contribution
|
$118
|
$0.33
|
(1) |
Lower
operations and maintenance expenses, primarily resulting from favorable
changes in the fair value of certain gas and oil hedges that were
de-designated following the 2005 hurricanes, partially offset by
increased
production costs.
|
(2) |
Represents
an increase in oil production primarily resulting from deepwater
oil
production at the Gulf of Mexico Devils Tower, Triton and Goldfinger
projects, partially offset by lower gas production as compared to
2005,
largely due to a reduction associated with VPP required deliveries
and
continued interruptions caused by the 2005
hurricanes.
|
(3) |
Reflects
increased income tax expense largely due to the effect of a revision
to
estimated state income tax apportionment percentages on accumulated
deferred income taxes during the first quarter of
2006.
|
Natural
Gas
|
Oil
|
|||
Year
|
Hedged
production
(bcf)
|
Average
hedge price
(per
mcf)
|
Hedged
production
(million bbls)
|
Average
hedge price
(per
bbl)
|
2006
|
170.4
|
$4.63
|
10.4
|
$25.05
|
2007
|
212.3
|
5.76
|
10.0
|
33.41
|
2008
|
113.5
|
7.73
|
5.0
|
49.36
|
First
Quarter
|
||||
2006
|
2005
|
$
Change
|
||
(millions,
except EPS)
|
||||
Specific
items attributable to operating segments
|
$ (94)
|
$ (54)
|
$ (40)
|
|
DCI
operations
|
(1)
|
(3)
|
2
|
|
Other
corporate operations
|
4
|
(54)
|
58
|
|
Total
net expense
|
$ (91)
|
$
(111)
|
$ 20
|
|
Earnings
per share impact
|
$(0.27)
|
$(0.33)
|
$0.06
|
· |
A
$77 million ($47 million after-tax) charge resulting from the termination
of a long-term power purchase agreement, attributable to Dominion
Generation; and
|
· |
An
$11 million ($6 million after-tax) charge related to our interest
in a
long-term power tolling contract that was divested in 2005, attributable
to Dominion Generation.
|
Amount
|
|
(millions)
|
|
Net
unrealized loss at December 31, 2005
|
$ (7)
|
Contracts
realized or otherwise settled during the period
|
33
|
Net
unrealized gain at inception of contracts initiated during the
period
|
--
|
Changes
in valuation techniques
|
--
|
Other
changes in fair value
|
(31)
|
Net
unrealized loss at March 31, 2006
|
$ (5)
|
Maturity
Based on Contract Settlement or Delivery Date(s)
|
|||||||
Source
of Fair Value
|
Less than
1
year
|
1-2
years
|
2-3
years
|
3-5
years
|
In
Excess
of
5
years
|
Total
|
|
(millions)
|
|||||||
Actively
quoted (1)
|
$23
|
$(19)
|
$ (2)
|
$ 3
|
--
|
$ 5
|
|
Other
external sources (2)
|
--
|
(9)
|
2
|
(2)
|
$(1)
|
(10)
|
|
Total
|
$23
|
$(28)
|
$ --
|
$ 1
|
$(1)
|
$ (5)
|
Gross
Credit
Exposure
|
||
(millions)
|
||
Investment
grade(1)
|
$
736
|
|
Non-investment
grade(2)
|
20
|
|
No
external ratings:
|
||
Internally
rated - investment grade(3)
|
113
|
|
Internally
rated - non-investment grade(4)
|
224
|
|
Total
|
$
1,093
|
· |
$484
million of capital expenditures for the purchase and development
of gas
and oil producing properties, drilling and equipment costs and undeveloped
lease acquisitions;
|
· |
$439
million of capital expenditures for the construction and expansion
of
generation facilities, environmental upgrades, purchase of nuclear
fuel,
and construction and improvements of gas and electric transmission
and
distribution assets;
|
· |
$281
million for the purchase of securities;
and
|
· |
$91
million related to the acquisition of Pablo Energy LLC, net of cash
acquired; partially offset by
|
· |
$273
million from the sale of
securities.
|
Fitch
|
Moody’s
|
Standard
&
Poor’s
|
|
Dominion
Resources, Inc.
|
|
|
|
Senior
unsecured debt securities
|
BBB+
|
Baa2
|
BBB
|
Preferred
securities of affiliated trusts
|
BBB
|
Baa3
|
BB+
|
Commercial
paper
|
F2
|
P-2
|
A-2
|
Virginia
Power
|
|
|
|
Mortgage
bonds
|
A
|
A3
|
A-
|
Senior
unsecured (including tax-exempt) debt securities
|
BBB+
|
Baa1
|
BBB
|
Preferred
securities of affiliated trust
|
BBB
|
Baa2
|
BB+
|
Preferred
stock
|
BBB
|
Baa3
|
BB+
|
Commercial
paper
|
F2
|
P-2
|
A-2
|
CNG
|
|
|
|
Senior
unsecured debt securities
|
BBB+
|
Baa1
|
BBB
|
Preferred
securities of affiliated trust
|
BBB
|
Baa2
|
BB+
|
Commercial
paper
|
F2
|
P-2
|
A-2
|
· |
Allows
annual fuel rate adjustments for three twelve-month periods beginning
July
1, 2007 and one six-month period beginning July 1, 2010 (unless capped
rates are terminated earlier under the Virginia Restructuring
Act);
|
· |
Allows
a “true-up” at the end of each of the twelve-month periods to account for
differences between projections and actual recovery of fuel costs
during
the prior twelve months; and
|
· |
Authorizes
the Virginia Commission to defer up to 40% of any fuel factor increase
approved for the first twelve-month period, with recovery of the
deferred
amount over the two and one-half year period beginning July 1, 2008
(under
current law, such a deferral is not
possible).
|
Period
|
(a)
Total
Number
of Shares
(or
Units)
Purchased
|
(b)
Average
Price
Paid
per
Share
(or
Unit)
|
(c)
Total Number
of
Shares (or Units) Purchased as Part
of
Publicly Announced Plans or Programs
|
(d)
Maximum Number (or Approximate Dollar Value) of Shares (or Units)
that May
Yet Be Purchased under the Plans or Program
|
1/1/06-1/31/06
|
1,970(1)
|
$78.42
|
N/A
|
21,275,000
shares/
$1.72
billion
|
2/1/06-2/28/06
|
1,647(1)
|
$75.03
|
N/A
|
21,275,000
shares/
$1.72
billion
|
3/1/06-3/31/06
|
199(1)
|
$72.10
|
N/A
|
21,275,000
shares/
$1.72
billion
|
Total
|
3,816
|
$76.63
|
N/A
|
21,275,000
shares/
$1.72
billion
|
Nominee
|
Votes
For
|
Votes
Withheld
|
||
Peter
W. Brown
|
293,731,199
|
6,028,498
|
||
Ronald
J. Calise
|
295,524,168
|
4,235,529
|
||
Thos.
E. Capps
|
292,825,745
|
6,933,952
|
||
George
A. Davidson, Jr.
|
294,452,466
|
5,307,231
|
||
Thomas
F. Farrell, II
|
293,833,299
|
5,926,398
|
||
John
W. Harris
|
295,492,426
|
4,267,271
|
||
Robert
S. Jepson, Jr.
|
295,208,868
|
4,550,829
|
||
Mark
J. Kington
|
295,459,674
|
4,300,023
|
||
Benjamin
J. Lambert, III
|
293,922,380
|
5,837,317
|
||
Richard
L. Leatherwood
|
294,100,159
|
5,659,538
|
||
Margaret
A. McKenna
|
295,281,793
|
4,477,904
|
||
Frank
S. Royal
|
290,434,617
|
9,325,080
|
||
S.
Dallas Simmons
|
293,585,144
|
6,174,553
|
||
David
A. Wollard
|
295,064,541
|
4,695,156
|
Votes
For
|
Votes
Against
|
Votes
Abstained
|
||
294,932,317
|
2,544,876
|
2,282,504
|
||
Votes
For
|
Votes
Against
|
Votes
Abstained
|
Broker
Non-Votes
|
|||
116,145,914
|
133,655,710
|
4,997,247
|
44,960,826
|
|||
Votes
For
|
Votes
Against
|
Votes
Abstained
|
Broker
Non-Votes
|
|||
52,266,689
|
179,459,569
|
23,074,000
|
44,959,439
|
|||
Votes
For
|
Votes
Against
|
Votes
Abstained
|
Broker
Non-Votes
|
|||
72,023,771
|
177,932,789
|
4,843,665
|
44,959,472
|
|||
(a)
Exhibits:
|
||
3.1
|
Articles
of Incorporation as in effect August 9, 1999, as amended March
12, 2001
(Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File
No.
1-8489, incorporated by reference).
|
|
3.2
|
Bylaws
as in effect on October 20, 2000 (Exhibit 3, Form 10-Q for the
quarter
ended September 30, 2000, File No. 1-8489, incorporated by
reference).
|
|
4
|
Dominion
Resources, Inc. agrees to furnish to the Securities and Exchange
Commission upon request any other instrument with respect to long-term
debt as to which the total amount of securities authorized does
not exceed
10% of its total consolidated assets.
|
|
10.1
|
$3.0
billion Five-Year Credit Agreement dated February 28, 2006 among
Dominion
Resources, Inc., Virginia Electric and Power Company, Consolidated
Natural
Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent,
Citibank,
N.A., as Syndication Agent and Barclays Bank PLC, The Bank of Nova
Scotia
and Wachovia Bank, National Association, as Co-Documentation Agents
and
other lenders named therein. (Exhibit 10.1, Form 8-K filed March
3, 2006,
File No. 1-8489, incorporated by reference).
|
|
10.2
|
$1.70
billion Amended and Restated Five-Year Credit Agreement dated February
28,
2006 among Consolidated Natural Gas Company, Barclays Bank PLC,
as
Administrative Agent, Barclays Bank PLC and KeyBank National Association,
as Syndication Agents, and SunTrust Bank, The Bank of Nova Scotia
and ABN
AMRO Bank N.V., as Co-Documentation Agents and other lenders as
named
therein. (Exhibit 10.2, Form 8-K filed March 3, 2006, File No.
1-8489,
incorporated by reference).
|
|
10.3
|
$1.05
billion 364-Day Credit Agreement dated February 28, 2006 among
Consolidated Natural Gas Company, Barclays Bank PLC, as Administrative
Agent, Barclays Bank PLC and KeyBank National Association, as Syndication
Agents, The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ,
Ltd.,
New York Branch and Mizuho Corporate Bank, Ltd., as Co-Documentation
Agents and other lenders as named therein. (Exhibit 10.3, Form
8-K filed
March 3, 2006, File No. 1-8489, incorporated by
reference).
|
|
10.4
|
2006
Long-Term Compensation Program - Form of Restricted Stock Grant
(Exhibit
10.1, Form 8-K filed April 4, 2006, File No. 1-8489, incorporated
by
reference).
|
|
10.5
|
2006
Long-Term Compensation Program - Form of Performance Grant (Exhibit
10.2,
Form 8-K filed April 4, 2006, File No. 1-8489, incorporated by
reference).
|
|
12
|
Ratio
of earnings to fixed charges (filed herewith).
|
|
31.1
|
Certification
by Registrant’s Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 (filed herewith).
|
|
31.2
|
Certification
by Registrant’s Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 (filed herewith).
|
|
32
|
Certification
to the Securities and Exchange Commission by Registrant’s Chief Executive
Officer and Chief Financial Officer, as required by Section 906
of the
Sarbanes-Oxley Act of 2002 (filed herewith).
|
|
99
|
Condensed
consolidated earnings statements (unaudited) (filed
herewith).
|
DOMINION
RESOURCES, INC.
Registrant
|
|
May
3, 2006
|
/s/
Steven A.
Rogers
|
Steven
A. Rogers
Senior
Vice President and Controller
(Principal
Accounting Officer)
|
|