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)
|
PART
I. Financial Information
|
||
Item
1.
|
|
|
|
||
|
||
|
||
|
||
Item
2.
|
|
|
Item
3.
|
|
|
Item
4.
|
|
|
PART
II. Other Information
|
||
Item
1.
|
|
|
Item
1A.
|
|
|
Item
2.
|
|
|
Item
4.
|
|
|
Item
6.
|
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(millions,
except per share amounts)
|
|||||||||||||
Operating
Revenue
|
$
|
3,556
|
$
|
3,646
|
$
|
8,513
|
$
|
8,382
|
|||||
Operating
Expenses
|
|||||||||||||
Electric
fuel and energy purchases
|
760
|
943
|
1,526
|
1,784
|
|||||||||
Purchased
electric capacity
|
116
|
122
|
239
|
256
|
|||||||||
Purchased
gas
|
432
|
553
|
1,810
|
1,775
|
|||||||||
Other
energy-related commodity purchases
|
318
|
318
|
718
|
642
|
|||||||||
Other
operations and maintenance
|
906
|
522
|
1,674
|
1,353
|
|||||||||
Depreciation,
depletion and amortization
|
410
|
349
|
791
|
695
|
|||||||||
Other
taxes
|
131
|
134
|
312
|
299
|
|||||||||
Total
operating expenses
|
3,073
|
2,941
|
7,070
|
6,804
|
|||||||||
Income
from operations
|
483
|
705
|
1,443
|
1,578
|
|||||||||
Other
income
|
49
|
32
|
92
|
83
|
|||||||||
Interest
and related charges:
|
|||||||||||||
Interest
expense
|
224
|
199
|
458
|
416
|
|||||||||
Interest
expense - junior subordinated notes payable
|
33
|
26
|
60
|
52
|
|||||||||
Subsidiary
preferred dividends
|
4
|
4
|
8
|
8
|
|||||||||
Total
interest and related charges
|
261
|
229
|
526
|
476
|
|||||||||
Income
before income tax expense
|
271
|
508
|
1,009
|
1,185
|
|||||||||
Income
tax expense
|
110
|
176
|
314
|
424
|
|||||||||
Net
income
|
$
|
161
|
$
|
332
|
$
|
695
|
$
|
761
|
|||||
Earnings
Per Common Share - Basic
|
$
|
0.46
|
$
|
0.98
|
$
|
2.00
|
$
|
2.24
|
|||||
Earnings
Per Common Share - Diluted
|
$
|
0.46
|
$
|
0.97
|
$
|
1.99
|
$
|
2.23
|
|||||
Dividends
paid per common share
|
$
|
0.69
|
$
|
0.67
|
$
|
1.38
|
$
|
1.34
|
June
30,
2006
|
December
31,
2005(1)
|
||||||
(millions)
|
|||||||
ASSETS
|
|||||||
Current
Assets
|
|||||||
Cash
and cash equivalents
|
$
|
81
|
$
|
146
|
|||
Customer
accounts receivable (less allowance for doubtful accounts of
$24 and
$38)
|
2,220
|
3,335
|
|||||
Other
receivables (less allowance for doubtful accounts of $9 at both
dates)
|
241
|
226
|
|||||
Inventories
|
1,034
|
1,167
|
|||||
Derivative
assets
|
2,554
|
3,429
|
|||||
Deferred
income taxes
|
642
|
928
|
|||||
Assets
held for sale
|
1,059
|
4
|
|||||
Prepayments
|
103
|
161
|
|||||
Other
|
590
|
733
|
|||||
Total
current assets
|
8,524
|
10,129
|
|||||
Investments
|
|||||||
Nuclear
decommissioning trust funds
|
2,557
|
2,534
|
|||||
Available
for sale securities
|
39
|
287
|
|||||
Loans
receivable, net
|
397
|
31
|
|||||
Other
|
652
|
649
|
|||||
Total
investments
|
3,645
|
3,501
|
|||||
Property,
Plant and Equipment
|
|||||||
Property,
plant and equipment
|
42,937
|
42,063
|
|||||
Accumulated
depreciation, depletion and amortization
|
(13,418
|
)
|
(13,123
|
)
|
|||
Total
property, plant and equipment, net
|
29,519
|
28,940
|
|||||
Deferred
Charges and Other Assets
|
|||||||
Goodwill
|
4,298
|
4,298
|
|||||
Prepaid
pension cost
|
1,882
|
1,915
|
|||||
Derivative
assets
|
1,082
|
1,915
|
|||||
Regulatory
assets
|
435
|
758
|
|||||
Other
|
1,283
|
1,204
|
|||||
Total
deferred charges and other assets
|
8,980
|
10,090
|
|||||
Total
assets
|
$
|
50,668
|
$
|
52,660
|
(1)
|
The
Consolidated Balance Sheet at December 31, 2005 has been derived
from the
audited Consolidated Financial Statements at that
date.
|
June
30,
2006
|
December
31,
2005(1)
|
||||||
(millions)
|
|||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
Current
Liabilities
|
|||||||
Securities
due within one year
|
$
|
2,279
|
$
|
2,330
|
|||
Short-term
debt
|
1,065
|
1,618
|
|||||
Accounts
payable
|
1,773
|
2,756
|
|||||
Accrued
interest, payroll and taxes
|
681
|
694
|
|||||
Derivative
liabilities
|
4,212
|
6,087
|
|||||
Liabilities
held for sale
|
404
|
--
|
|||||
Other
|
662
|
995
|
|||||
Total
current liabilities
|
11,076
|
14,480
|
|||||
Long-Term
Debt
|
|||||||
Long-term
debt
|
13,964
|
13,237
|
|||||
Junior
subordinated notes payable:
|
|||||||
Affiliates
|
1,440
|
1,416
|
|||||
Other
|
299
|
--
|
|||||
Total
long-term debt
|
15,703
|
14,653
|
|||||
Deferred
Credits and Other Liabilities
|
|||||||
Deferred
income taxes and investment tax credits
|
5,384
|
4,984
|
|||||
Asset
retirement obligations
|
2,335
|
2,249
|
|||||
Derivative
liabilities
|
2,174
|
3,971
|
|||||
Regulatory
liabilities
|
590
|
607
|
|||||
Other
|
1,023
|
1,062
|
|||||
Total
deferred credits and other liabilities
|
11,506
|
12,873
|
|||||
Total
liabilities
|
38,285
|
42,006
|
|||||
Commitments
and Contingencies (see
Note 15)
|
|||||||
Minority
Interest
|
17
|
--
|
|||||
Subsidiary
Preferred Stock Not Subject to Mandatory
Redemption
|
257
|
257
|
|||||
Common
Shareholders' Equity
|
|||||||
Common
stock - no par(2)
|
11,672
|
11,286
|
|||||
Other
paid-in capital
|
127
|
125
|
|||||
Retained
earnings
|
1,762
|
1,550
|
|||||
Accumulated
other comprehensive loss
|
(1,452
|
)
|
(2,564
|
)
|
|||
Total
common shareholders’ equity
|
12,109
|
10,397
|
|||||
Total
liabilities and shareholders’ equity
|
$
|
50,668
|
$
|
52,660
|
(1)
|
The
Consolidated Balance Sheet at December 31, 2005 has been derived
from the
audited Consolidated Financial Statements at that
date.
|
(2)
|
500
million shares authorized; 353 million shares outstanding at June
30, 2006
and 347 million shares outstanding at December 31,
2005.
|
Six
Months Ended June 30,
|
2006
|
2005
|
|||||
(millions)
|
|||||||
Operating
Activities
|
|||||||
Net
income
|
$
|
695
|
$
|
761
|
|||
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|||||||
DCI
impairment losses
|
89
|
15
|
|||||
Charges
related to pending sale of gas distribution subsidiaries
|
178
|
--
|
|||||
Net
realized and unrealized derivative (gains) losses
|
(234
|
)
|
50
|
||||
Depreciation,
depletion and amortization
|
862
|
751
|
|||||
Deferred
income taxes and investment tax credits, net
|
242
|
115
|
|||||
Other
adjustments to income, net
|
(176
|
)
|
(135
|
)
|
|||
Changes
in:
|
|||||||
Accounts
receivable
|
964
|
171
|
|||||
Inventories
|
93
|
69
|
|||||
Deferred
fuel and purchased gas costs, net
|
202
|
114
|
|||||
Prepaid
pension cost
|
28
|
15
|
|||||
Accounts
payable
|
(884
|
)
|
(164
|
)
|
|||
Accrued
interest, payroll and taxes
|
33
|
33
|
|||||
Deferred
revenues
|
(143
|
)
|
(163
|
)
|
|||
Margin
deposit assets and liabilities
|
(142
|
)
|
(323
|
)
|
|||
Other
operating assets and liabilities
|
182
|
61
|
|||||
Net
cash provided by operating activities
|
1,989
|
1,370
|
|||||
Investing
Activities
|
|||||||
Plant
construction and other property additions
|
(913
|
)
|
(774
|
)
|
|||
Additions
to gas and oil properties, including acquisitions
|
(1,018
|
)
|
(812
|
)
|
|||
Proceeds
from sale of gas and oil properties
|
20
|
580
|
|||||
Acquisition
of businesses
|
(91
|
)
|
(642
|
)
|
|||
Proceeds
from sale of securities
|
493
|
422
|
|||||
Purchases
of securities
|
(530
|
)
|
(451
|
)
|
|||
Other
|
87
|
122
|
|||||
Net
cash used in investing activities
|
(1,952
|
)
|
(1,555
|
)
|
|||
Financing
Activities
|
|||||||
Issuance
(repayment) of short-term debt, net
|
(553
|
)
|
709
|
||||
Issuance
of long-term debt
|
1,300
|
600
|
|||||
Repayment
of long-term debt
|
(723
|
)
|
(915
|
)
|
|||
Issuance
of common stock
|
372
|
245
|
|||||
Repurchase
of common stock
|
--
|
(276
|
)
|
||||
Common
dividend payments
|
(483
|
)
|
(458
|
)
|
|||
Other
|
(13
|
)
|
(37
|
)
|
|||
Net
cash used in financing activities
|
(100
|
)
|
(132
|
)
|
|||
Decrease
in cash and cash equivalents
|
(63
|
)
|
(317
|
)
|
|||
Cash
and cash equivalents at beginning of period
|
146
|
361
|
|||||
Cash
and cash equivalents at end of period(1)
|
$
|
83
|
$
|
44
|
|||
Noncash
Financing Activities:
|
|||||||
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 $2 million of cash classified as held for sale on
the
Consolidated Balance Sheet.
|
Three
Months Ended
June
30, 2005
|
Six
Months Ended
June
30, 2005
|
||||||
(millions,
except EPS)
|
|||||||
Net
income, as reported
|
$
|
332
|
$
|
761
|
|||
Add:
actual stock-based compensation expense, net of tax
|
3
|
6
|
|||||
Deduct:
pro forma stock-based compensation expense, net of tax
|
(4
|
)
|
(7
|
)
|
|||
Net
income, pro forma
|
$
|
331
|
$
|
760
|
|||
Basic
EPS - as reported
|
$
|
0.98
|
$
|
2.24
|
|||
Basic
EPS - pro forma
|
$
|
0.98
|
$
|
2.24
|
|||
Diluted
EPS - as reported
|
$
|
0.97
|
$
|
2.23
|
|||
Diluted
EPS - pro forma
|
$
|
0.97
|
$
|
2.22
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
|||
2006
|
2005
|
2006
|
2005
|
|
(millions)
|
||||
Sale
activity included in operating revenue
|
$191
|
$83
|
$422
|
$176
|
Purchase
activity included in operating expenses(1)
|
185
|
79
|
409
|
168
|
June
30, 2006
|
||||
(millions)
|
||||
ASSETS
|
||||
Current
Assets
|
||||
Cash
|
$
|
2
|
||
Customer
accounts receivable
|
127
|
|||
Unrecovered
gas costs
|
30
|
|||
Other
|
66
|
|||
Total
current assets
|
225
|
|||
Investments
|
2
|
|||
Property,
Plant and Equipment
|
||||
Property,
plant and equipment
|
1,110
|
|||
Accumulated
depreciation, depletion and amortization
|
(382
|
)
|
||
Total
property, plant and equipment, net
|
728
|
|||
Deferred
Charges and Other Assets
|
||||
Regulatory
assets
|
101
|
|||
Other
|
2
|
|||
Total
deferred charges and other assets
|
103
|
|||
Assets
held for sale
|
$
|
1,058
|
||
LIABILITIES
|
||||
Current
Liabilities
|
||||
Accounts
payable, trade
|
$
|
46
|
||
Payables
to affiliates
|
20
|
|||
Deferred
income taxes
|
14
|
|||
Other
|
92
|
|||
Total
current liabilities
|
172
|
|||
Deferred
Credits and Other Liabilities
|
||||
Asset
retirement obligations
|
33
|
|||
Deferred
income taxes
|
164
|
|||
Regulatory
liabilities
|
26
|
|||
Other
|
9
|
|||
Total
deferred credits and other liabilities
|
232
|
|||
Liabilities
held for sale
|
$
|
404
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(millions)
|
|||||||||||||
Operating
Revenue
|
$
|
92
|
$
|
96
|
$
|
449
|
$
|
412
|
|||||
Income
(loss) before income taxes
|
--
|
1
|
(128
|
)
|
46
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(millions)
|
|||||||||||||
Operating
Revenue
|
|||||||||||||
Electric
sales:
|
|||||||||||||
Regulated
|
$
|
1,283
|
$
|
1,245
|
$
|
2,581
|
$
|
2,567
|
|||||
Nonregulated
|
551
|
541
|
1,151
|
1,255
|
|||||||||
Gas
sales:
|
|||||||||||||
Regulated
|
175
|
217
|
975
|
995
|
|||||||||
Nonregulated
|
377
|
475
|
1,259
|
1,220
|
|||||||||
Other
energy-related commodity sales
|
415
|
389
|
908
|
785
|
|||||||||
Gas
transportation and storage
|
202
|
181
|
487
|
456
|
|||||||||
Gas
and oil production
|
489
|
407
|
1,021
|
818
|
|||||||||
Other
|
64
|
191
|
131
|
286
|
|||||||||
Total
operating revenue
|
$
|
3,556
|
$
|
3,646
|
$
|
8,513
|
$
|
8,382
|
Six
Months Ended
June
30,
|
|||||||
2006
|
2005
|
||||||
U.S.
statutory rate
|
35.0
|
%
|
35.0
|
%
|
|||
Increases
(decreases) resulting from:
|
|||||||
Amortization
of investment tax credits
|
(0.5
|
)
|
(0.5
|
)
|
|||
Employee
pension and other benefits
|
(0.4
|
)
|
(0.4
|
)
|
|||
Employee
stock ownership plan and restricted stock dividends
|
(0.5
|
)
|
(0.4
|
)
|
|||
Other
benefits and taxes - foreign operations
|
(0.5
|
)
|
(0.9
|
)
|
|||
State
taxes, net of federal benefit
|
6.3
|
2.8
|
|||||
Changes
in valuation allowances
|
(20.1
|
)
|
0.1
|
||||
Recognition
of deferred taxes - stock of subsidiaries held for sale
|
13.4
|
--
|
|||||
Other,
net
|
(1.6
|
)
|
0.1
|
||||
Effective
tax rate
|
31.1
|
%
|
35.8
|
%
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(millions,
except EPS)
|
|||||||||||||
Net
income
|
$
|
161
|
$
|
332
|
$
|
695
|
$
|
761
|
|||||
Basic
EPS
|
|||||||||||||
Average
shares of common stock outstanding - basic
|
349.0
|
339.7
|
347.8
|
340.0
|
|||||||||
Net
income
|
$
|
0.46
|
$
|
0.98
|
$
|
2.00
|
$
|
2.24
|
|||||
Diluted
EPS
|
|||||||||||||
Average
shares of common stock outstanding
|
349.0
|
339.7
|
347.8
|
340.0
|
|||||||||
Net
effect of potentially dilutive securities(1)
|
1.5
|
2.3
|
1.5
|
2.1
|
|||||||||
Average
shares of common stock outstanding - diluted
|
350.5
|
342.0
|
349.3
|
342.1
|
|||||||||
Net
income
|
$
|
0.46
|
$
|
0.97
|
$
|
1.99
|
$
|
2.23
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
|||
2006
|
2005
|
2006
|
2005
|
|
(millions)
|
||||
Net
income
|
$161
|
$332
|
$ 695
|
$ 761
|
Other
comprehensive income (loss):
|
||||
Net
other comprehensive income (loss) associated with
effective portion of changes in fair value of
derivatives designated as cash flow hedges, net of taxes
and amounts reclassified to earnings
|
404(1)
|
(27)
|
1,123(1)
|
(915)(2)
|
Other(3)
|
(31)
|
18
|
(11)
|
(19)
|
Other
comprehensive income (loss)
|
373
|
(9)
|
1,112
|
(934)
|
Total
comprehensive income (loss)
|
$534
|
$323
|
$1,807
|
$(173)
|
(1)
|
Largely
due to the settlement of certain commodity derivative contracts
and
favorable changes in fair value, primarily resulting from a decrease
in
gas prices.
|
(2)
|
Principally
due to unfavorable changes in the fair value of certain commodity
derivatives resulting from an increase in commodity
prices.
|
(3)
|
Primarily
reflects the impact of both unrealized gains and losses on investments
held in decommissioning trusts and foreign currency translation
adjustments.
|
Three
Months Ended
June
30,
|
Six
Months Ended
June
30,
|
|||
2006
|
2005
|
2006
|
2005
|
|
(millions)
|
||||
Portion
of gains (losses) on hedging instruments determined to be ineffective
and
included in net income:
|
||||
Fair
value hedges
|
$(1)
|
$ 1
|
$ (8)
|
$ 5
|
Cash
flow hedges (1)
|
5
|
(15)
|
24
|
(21)
|
Net
ineffectiveness
|
$ 4
|
$(14)
|
$16
|
$(16)
|
(1)
|
Represents
hedge ineffectiveness, primarily due to changes in the fair value
differential between the delivery location and commodity specifications
of
derivatives held by our E&P operations and the delivery location and
commodity specifications of our forecasted gas and oil
sales.
|
AOCI
After-Tax
|
Portion
Expected to be Reclassified to Earnings during the next 12 Months
After-Tax
|
Maximum
Term
|
||||||||
(millions)
|
||||||||||
Commodities:
|
||||||||||
Gas
|
$
|
(743
|
)
|
$
|
(486
|
)
|
57
months
|
|||
Oil
|
(550
|
)
|
(343
|
)
|
30
months
|
|||||
Electricity
|
(367
|
)
|
(246
|
)
|
42
months
|
|||||
Other
|
(2
|
)
|
(2
|
)
|
4
months
|
|||||
Interest
rate
|
(14
|
)
|
8
|
240
months
|
||||||
Foreign
currency
|
22
|
12
|
17
months
|
|||||||
Total
|
$
|
(1,654
|
)
|
$
|
(1,057
|
)
|
Facility
Limit
|
Outstanding
Commercial
Paper
|
Outstanding
Letters
of
Credit
|
Facility
Capacity
Available
|
||||||||||
(millions)
|
|||||||||||||
Five-year
revolving credit facility(1)
|
$
|
3,000
|
$
|
998
|
$
|
653
|
$
|
1,349
|
|||||
Five-year
CNG credit facility(2)
|
1,700
|
--
|
1,039
|
661
|
|||||||||
364-day
CNG credit facility(3)
|
1,050
|
--
|
--
|
1,050
|
|||||||||
Totals
|
$
|
5,750
|
$
|
998
|
$
|
1,692
|
$
|
3,060
|
(1)
|
The
$3.0 billion five-year credit facility was entered into in February
2006
and terminates in February 2011. This credit facility can also be
used to
support up to $1.5 billion of letters of credit.
|
(2)
|
The
$1.7 billion five-year credit facility is used to support the issuance
of
letters of credit and commercial paper by CNG to fund collateral
requirements under its gas and oil hedging program. The facility
was
entered into in February 2006 and terminates in August
2010.
|
(3)
|
The
$1.05 billion 364-day credit facility is used to support the issuance
of
letters of credit and commercial paper by CNG to fund collateral
requirements under its gas and oil hedging program. The facility
was
entered into in February 2006 and terminates in February
2007.
|
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
|
5
|
95
|
August
2004
|
August
2009
|
|||||||||||
CNG(1)
|
200
|
--
|
200
|
December
2005
|
December
2010
|
|||||||||||
Totals
|
$
|
400
|
$
|
105
|
$
|
295
|
(1)
|
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
|
(89
|
)
|
57.50
|
$
|
1
|
||||||||
Forfeited/expired
|
(10
|
)
|
61.85
|
||||||||||
Outstanding
and exercisable at June 30, 2006
|
8,115
|
$
|
60.46
|
3.7
|
$
|
114
|
(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
|
313
|
70.20
|
Vested
|
(164)
|
60.42
|
Cancelled
and forfeited
|
(8)
|
67.69
|
Nonvested
at June 30, 2006
|
1,272
|
$65.32
|
Targeted
Number of Shares |
Weighted-Average
Grant Date Fair Value |
|
(thousands)
|
||
Nonvested
at January 1, 2006
|
--
|
$ --
|
Granted
|
100.0
|
69.53
|
Vested
|
--
|
--
|
Cancelled
and forfeited
|
(0.5)
|
69.53
|
Nonvested
at June 30, 2006
|
99.5
|
$69.53
|
|
Stated Limit
|
Value(1)
|
|||||
(millions)
|
|||||||
Subsidiary
debt(2)
|
$
|
1,318
|
$
|
1,318
|
|||
Commodity
transactions(3)
|
3,678
|
1,183
|
|||||
Lease
obligation for power generation facility(4)
|
898
|
898
|
|||||
Nuclear
obligations(5)
|
375
|
302
|
|||||
Offshore
drilling commitments(6)
|
--
|
493
|
|||||
Other
|
599
|
424
|
|||||
Total
|
$
|
6,868
|
$
|
4,618
|
(1)
|
Represents
the estimated portion of the guarantee’s stated limit that is utilized as
of June 30, 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, Inc. (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.
|
(4)
|
Guarantee
of a DEI subsidiary’s leasing obligation for the Fairless Energy power
station.
|
(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 guarantees for
Virginia
Power’s commitment to buy nuclear fuel. In addition to the guarantees
listed above, we have also agreed to provide up to $150 million and
$60
million to two DEI subsidiaries, if requested by such subsidiaries,
to pay
the operating expenses in the event of a prolonged outage of the
Millstone
and Kewaunee power stations, respectively, as part of satisfying
certain
NRC requirements concerned with ensuring adequate funding for the
operations of nuclear power
stations.
|
(6)
|
Performance
and payment guarantees related to an offshore day work drilling contract,
rig share agreements and related services for certain subsidiaries
of CNG.
There are no stated limits for these
guarantees.
|
Pension
Benefits
|
Other
Postretirement Benefits
|
||||||||||||
2006
|
2005
|
2006
|
2005
|
||||||||||
(millions)
|
|||||||||||||
Three
Months Ended June 30,
|
|||||||||||||
Service
cost
|
$
|
30
|
$
|
27
|
$
|
19
|
$
|
16
|
|||||
Interest
cost
|
50
|
51
|
21
|
21
|
|||||||||
Expected
return on plan assets
|
(86
|
)
|
(86
|
)
|
(15
|
)
|
(13
|
)
|
|||||
Amortization
of prior service cost (credit)
|
1
|
1
|
(1
|
)
|
(1
|
)
|
|||||||
Amortization
of transition obligation
|
--
|
--
|
1
|
1
|
|||||||||
Amortization
of net loss
|
22
|
19
|
7
|
5
|
|||||||||
Net
periodic benefit cost
|
$
|
17
|
$
|
12
|
$
|
32
|
$
|
29
|
|||||
Six
Months Ended June 30,
|
|||||||||||||
Service
cost
|
$
|
65
|
$
|
56
|
$
|
40
|
$
|
32
|
|||||
Interest
cost
|
108
|
105
|
44
|
41
|
|||||||||
Expected
return on plan assets
|
(185
|
)
|
(179
|
)
|
(32
|
)
|
(26
|
)
|
|||||
Curtailment loss(1)
|
6
|
--
|
--
|
--
|
|||||||||
Amortization
of prior service cost (credit)
|
2
|
2
|
(2
|
)
|
(1
|
)
|
|||||||
Amortization
of transition obligation
|
--
|
--
|
2
|
2
|
|||||||||
Amortization
of net loss
|
47
|
40
|
15
|
10
|
|||||||||
Net
periodic benefit cost
|
$
|
43
|
$
|
24
|
$
|
67
|
$
|
58
|
(1)
|
Relates
to the pending sale of Peoples and Hope, as discussed in Note
5.
|
Amount
|
||||
(millions)
|
||||
Other
current assets
|
$
|
155
|
||
Loans
receivable, net
|
365
|
|||
Other
investments
|
64
|
|||
Total
assets
|
$
|
584
|
·
|
A
$77 million ($47 million after-tax) charge resulting from the termination
of a long-term power purchase agreement, attributable to Dominion
Generation; and
|
·
|
A
$13 million ($8 million after-tax) charge related to our interest
in a
long-term power tolling contract that was divested in 2005, attributable
to Dominion Generation.
|
Dominion
Delivery
|
Dominion
Energy
|
Dominion
Generation
|
Dominion
E&P
|
Corporate
|
Adjustments/
Eliminations
|
Consolidated
Total
|
|
(millions)
|
|||||||
Three
Months Ended June 30,
|
|||||||
2006
|
|||||||
Operating
Revenue:
|
|||||||
External
customers
|
$737
|
$248
|
$1,575
|
$780
|
$ (19)
|
$ 235
|
$3,556
|
Intersegment
|
3
|
287
|
38
|
50
|
187
|
(565)
|
--
|
Total
operating revenue
|
740
|
535
|
1,613
|
830
|
168
|
(330)
|
3,556
|
Net
income (loss)
|
80
|
68
|
60
|
114
|
(161)
|
--
|
161
|
2005
|
|||||||
Operating
Revenue:
|
|||||||
External
customers
|
$707
|
$271
|
$1,670
|
$715
|
$ 10
|
$ 273
|
$3,646
|
Intersegment
|
10
|
277
|
35
|
46
|
142
|
(510)
|
--
|
Total
operating revenue
|
717
|
548
|
1,705
|
761
|
152
|
(237)
|
3,646
|
Net
income (loss)
|
73
|
64
|
54
|
189
|
(48)
|
--
|
332
|
Six
Months Ended June 30,
|
|||||||
2006
|
|||||||
Operating
Revenue:
|
|||||||
External
customers
|
$2,409
|
$ 845
|
$3,233
|
$1,653
|
$ (56)
|
$
429
|
$8,513
|
Intersegment
|
6
|
563
|
81
|
118
|
381
|
(1,149)
|
--
|
Total
operating revenue
|
2,415
|
1,408
|
3,314
|
1,771
|
325
|
(720)
|
8,513
|
Net
income (loss)
|
236
|
175
|
192
|
344
|
(252)
|
--
|
695
|
2005
|
|||||||
Operating
Revenue:
|
|||||||
External
customers
|
$2,238
|
$ 755
|
$3,536
|
$1,350
|
$ 8
|
$ 495
|
$8,382
|
Intersegment
|
28
|
504
|
91
|
89
|
291
|
(1,003)
|
--
|
Total
operating revenue
|
2,266
|
1,259
|
3,627
|
1,439
|
299
|
(508)
|
8,382
|
Net
income (loss)
|
257
|
163
|
199
|
301
|
(159)
|
--
|
761
|
·
|
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;
|
·
|
Political
and economic conditions, including the threat of domestic terrorism,
inflation and deflation;
|
·
|
Completing
the divestiture of investments held by our financial services subsidiary,
DCI; and
|
·
|
Additional
risk exposure associated with the termination of business interruption,
offshore property damage and other insurance related to our E&P
operations and our inability to replace such insurance on commercially
reasonable terms.
|
2006
|
2005
|
$
Change
|
|
(millions,
except EPS)
|
|||
Second
Quarter
|
|||
Net
income
|
$ 161
|
$ 332
|
$(171)
|
Diluted
EPS
|
0.46
|
0.97
|
(0.51)
|
Year-To-Date
|
|||
Net
income
|
$ 695
|
$ 761
|
$ (66)
|
Diluted
EPS
|
1.99
|
2.23
|
(0.24)
|
Second
Quarter
|
Year-To-Date
|
|||||
2006
|
2005
|
$
Change
|
2006
|
2005
|
$
Change
|
|
(millions)
|
||||||
Operating
Revenue
|
$3,556
|
$3,646
|
$ (90)
|
$8,513
|
$8,382
|
$ 131
|
Operating
Expenses
|
||||||
Electric
fuel and energy purchases
|
760
|
943
|
(183)
|
1,526
|
1,784
|
(258)
|
Purchased
electric capacity
|
116
|
122
|
(6)
|
239
|
256
|
(17)
|
Purchased
gas
|
432
|
553
|
(121)
|
1,810
|
1,775
|
35
|
Other
energy-related commodity purchases
|
318
|
318
|
--
|
718
|
642
|
76
|
Other
operations and maintenance
|
906
|
522
|
384
|
1,674
|
1,353
|
321
|
Depreciation,
depletion and amortization
|
410
|
349
|
61
|
791
|
695
|
96
|
Other
taxes
|
131
|
134
|
(3)
|
312
|
299
|
13
|
Other
income
|
49
|
32
|
17
|
92
|
83
|
9
|
Interest
and related charges
|
261
|
229
|
32
|
526
|
476
|
50
|
Income
tax expense
|
110
|
176
|
(66)
|
314
|
424
|
(110)
|
·
|
The
absence of $135 million of business interruption insurance proceeds
received in 2005 associated with Hurricane
Ivan;
|
·
|
A
$95 million decrease in non-utility coal sales revenue primarily
resulting
from decreased sales volumes ($74 million) and lower prices ($21
million);
|
·
|
An
$81 million decrease from gas trading and marketing activities primarily
reflecting decreased volumes and lower
prices;
|
·
|
A
$42 million decrease from regulated gas distribution operations, primarily
reflecting a $35 million decrease resulting from the loss of customers
to
Energy Choice programs and a $27 million decrease associated with
milder
weather, changes in customer usage and other factors, partially offset
by
a $20 million increase related to the recovery of higher gas prices.
The
effect of this net decrease was largely offset by a corresponding
decrease
in Purchased
gas expense;
|
·
|
A
$30 million decrease in sales of emissions allowances held for resale,
primarily as a result of decreased sales volume;
and
|
·
|
A
$20 million decrease in revenue from sales of gas purchased by E&P
operations to facilitate gas transportation and other contracts.
|
·
|
A
$108 million increase in sales of purchased oil under buy/sell
arrangements by E&P operations, resulting from higher prices ($47
million) and increased sales volume ($61
million);
|
·
|
An
$82 million increase in sales of gas and oil production, primarily
due to
higher volumes ($93 million), partially offset by decreased prices
($11
million);
|
·
|
A
$47 million increase from the Kewaunee power station (Kewaunee) acquired
in July 2005;
|
·
|
A
$44 million increase in gas sales by nonregulated retail energy marketing
activities primarily reflecting higher volumes;
|
·
|
A
$43 million increase in sales of extracted products, primarily due
to
increased prices and a contractual change for a portion of our gas
production processed by third parties. We now take title to and market
the
extracted products from this gas;
and
|
·
|
A
$41 million decrease in revenues associated with price risk management
activities for our merchant generation operations, including lower
sales
volume for requirements-based
sales
contracts.
|
·
|
A
$254 million decrease in purchases primarily due to lower volumes
associated with price risk management activities for our merchant
generation operations and purchases for requirements-based sales
contracts; partially offset by
|
·
|
A
$50 million increase related to our utility generation operations,
primarily due to higher commodity prices, including purchased power;
and
|
·
|
An
$18 million increase resulting from the addition of Kewaunee.
|
·
|
A
$57 million decrease related to gas aggregation
activities;
|
·
|
A
$24 million decrease related to E&P operations;
|
·
|
A
$22 million decrease from nonregulated retail energy marketing
activities;
and
|
·
|
A
$28 million decrease in costs attributable to regulated gas distribution
operations, reflecting lower prices ($12 million) and lower volumes
($16
million).
|
·
|
An
$89 million increase primarily resulting from price risk management
activities associated with our merchant generation
assets;
|
·
|
An
$85 million charge resulting from the impairment of a DCI
investment;
|
·
|
A
$60 million increase due to an adjustment eliminating the application
of
hedge accounting for certain interest rate swaps associated with
our
junior subordinated notes payable to affiliated trusts that sold
trust
preferred securities. Prior to June 30, 2006, we applied the shortcut
method of fair value hedge accounting under SFAS No. 133 to these
swaps,
allowing us to assume no hedge ineffectiveness for these derivatives.
We
have since determined that these swaps did not qualify for the shortcut
method because of an interest deferral mechanism within the junior
subordinated notes and they cannot qualify for hedge accounting
retrospectively because the hedge documentation required for the
long-haul
method was not in place at the inception of the hedge. These instruments
have been and, we believe, will continue to be highly effective economic
hedges. We have since re-designated the interest rate swaps associated
with these transactions as fair value hedges under the long-haul
accounting method in order to qualify them going forward for fair
value
hedge accounting under SFAS No.
133;
|
·
|
$42
million of additional incentive-based compensation, salaries, wages
and
benefits expenses;
|
·
|
A
$40 million decrease in gains from the sales of emission allowances
held
for consumption;
|
·
|
A
$34 million increase due to the addition of
Kewaunee;
|
·
|
A
$33 million increase due to higher production and transportation
costs for
E&P operations; and
|
·
|
An
$11 million increase in insurance costs for E&P operations, primarily
due to higher insurance premiums following the 2005 hurricanes; partially
offset by
|
·
|
A
$20 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
$246 million increase in sales of purchased oil under buy/sell
arrangements by E&P operations resulting from higher prices ($95
million) and increased sales volumes ($151
million);
|
·
|
A
$203 million increase in sales of gas and oil production, primarily
due to
increased production ($156 million) and higher average realized prices
($47 million);
|
·
|
A
$146 million
increase in gas sales by nonregulated retail energy marketing activities
primarily reflecting higher volumes ($66 million) and increased prices
($80 million);
|
·
|
A
$95 million increase from the addition of Kewaunee;
and
|
·
|
A
$79 million increase in sales of extracted products, primarily due
to
increased prices and a contractual change for a portion of our gas
production processed by third parties. We now take title to and market
the
extracted products from this gas.
|
·
|
A
$217 million decrease in revenues associated with price risk management
activities for our merchant generation operations, including lower
sales
volume for requirements-based sales
contracts;
|
·
|
A
$165 million decline in nonutility coal sales resulting primarily
from
lower sales volumes ($147 million) and decreased prices ($18
million);
|
·
|
A
$179 million decrease due to the absence of business interruption
insurance proceeds recognized in 2005 associated with Hurricane Ivan;
|
·
|
A
$30 million decrease in sales of emissions allowances held for resale,
resulting from lower overall sales volumes for the current year-to-date
period ($46 million), partially offset by higher prices realized
on sales
during the first quarter of 2006 ($16 million). The effect of this
decrease was largely offset by a corresponding decrease in Other
energy-related commodity purchases expense;
and
|
·
|
A
$22 million decrease in revenue from sales of gas purchased by E&P
operations to facilitate gas transportation and other
contracts.
|
·
|
A
$424 million decrease primarily due to lower volumes associated
with price
risk management activities for our merchant generation operations
and
purchases for requirements-based sales contracts; partially offset
by
|
·
|
A
$137 million increase related to our utility generation operations,
primarily due to higher commodity prices, including purchased power
and
congestion costs associated with PJM; and
|
·
|
A
$22 million increase resulting from the addition of
Kewaunee.
|
·
|
A
$162 million charge from the write-off of certain regulatory assets
related to the pending sale of Peoples and
Hope;
|
·
|
$89
million of impairment charges related to DCI
investments;
|
·
|
$76
million of additional salaries, wages, incentive-based compensation
and
benefits expenses;
|
·
|
A
$61 million increase due to the addition of
Kewaunee;
|
·
|
$61
million of additional production and transportation costs for E&P
operations;
|
·
|
A
$60 million increase due to an adjustment eliminating the application
of
hedge accounting for certain interest rate swaps associated with
our
junior subordinated notes payable to affiliated
trusts;
|
·
|
A
$33 million decrease in gains from the sale of emission allowances
held
for consumption;
|
·
|
A
$33 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
$26 million increase in insurance costs for E&P operations primarily
due to higher insurance premiums following the 2005
hurricanes.
|
·
|
A
$138 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
$33 million benefit primarily from price risk management activities
associated with our merchant generation assets as discussed in
Operating
Revenue;
|
·
|
A
$31 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
$47 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.
|
Net
Income
|
Diluted
EPS
|
|||||
Second
Quarter
|
2006
|
2005
|
$
Change
|
2006
|
2005
|
$
Change
|
(millions,
except EPS)
|
||||||
Dominion
Delivery
|
$ 80
|
$ 73
|
$ 7
|
$ 0.23
|
$ 0.21
|
$ 0.02
|
Dominion
Energy
|
68
|
64
|
4
|
0.20
|
0.19
|
0.01
|
Dominion
Generation
|
60
|
54
|
6
|
0.17
|
0.16
|
0.01
|
Dominion
E&P
|
114
|
189
|
(75)
|
0.32
|
0.55
|
(0.23)
|
Primary
operating segments
|
322
|
380
|
(58)
|
0.92
|
1.11
|
(0.19)
|
Corporate
|
(161)
|
(48)
|
(113)
|
(0.46)
|
(0.14)
|
(0.32)
|
Consolidated
|
$ 161
|
$332
|
$(171)
|
$ 0.46
|
$ 0.97
|
$(0.51)
|
Year-To-Date
|
||||||
(millions,
except EPS)
|
||||||
Dominion
Delivery
|
$ 236
|
$ 257
|
$ (21)
|
$ 0.68
|
$ 0.75
|
$(0.07)
|
Dominion
Energy
|
175
|
163
|
12
|
0.50
|
0.48
|
0.02
|
Dominion
Generation
|
192
|
199
|
(7)
|
0.55
|
0.58
|
(0.03)
|
Dominion
E&P
|
344
|
301
|
43
|
0.98
|
0.88
|
0.10
|
Primary
operating segments
|
947
|
920
|
27
|
2.71
|
2.69
|
0.02
|
Corporate
|
(252)
|
(159)
|
(93)
|
(0.72)
|
(0.46)
|
(0.26)
|
Consolidated
|
$ 695
|
$ 761
|
$ (66)
|
$ 1.99
|
$ 2.23
|
$(0.24)
|
Second
Quarter
|
Year-To-Date
|
|||||
2006
|
2005
|
%
Change
|
2006
|
2005
|
%
Change
|
|
Electricity
delivered (million mwhrs)
|
18.7
|
18.6
|
1%
|
38.2
|
38.5
|
(1)%
|
Degree
days (electric service area):
|
||||||
Cooling(1)
|
396
|
370
|
7
|
409
|
370
|
11
|
Heating(2)
|
245
|
355
|
(31)
|
2,041
|
2,466
|
(17)
|
Electric
delivery customer accounts(3)
|
2,325
|
2,283
|
2
|
2,325
|
2,283
|
2
|
Gas
throughput (bcf):
|
||||||
Gas
sales
|
12
|
20
|
(40)
|
62
|
83
|
(25)
|
Gas
transportation
|
43
|
44
|
(2)
|
130
|
136
|
(4)
|
Heating
degree days (gas service area)(2)
|
656
|
748
|
(12)
|
3,236
|
3,770
|
(14)
|
Gas
delivery customer accounts(3):
|
||||||
Gas
sales
|
789
|
1,002
|
(21)
|
789
|
1,002
|
(21)
|
Gas
transportation
|
892
|
677
|
32
|
892
|
677
|
32
|
Nonregulated
retail energy marketing customer accounts(3)
|
1,392
|
1,149
|
21
|
1,392
|
1,149
|
21
|
(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.
|
Second
Quarter
|
Year-To-Date
|
|||
2006
vs. 2005
|
2006
vs. 2005
|
|||
Increase
(Decrease)
|
Increase
(Decrease)
|
|||
Amount
|
EPS
|
Amount
|
EPS
|
|
(millions,
except EPS)
|
||||
Nonregulated
retail energy marketing operations(1)
|
$ 6
|
$ 0.02
|
$ 16
|
$ 0.04
|
Regulated
electric sales:
|
||||
Customer
growth
|
3
|
0.01
|
6
|
0.02
|
Weather
|
(2)
|
(0.01)
|
(11)
|
(0.03)
|
Interest
expense(2)
|
(4)
|
(0.01)
|
(11)
|
(0.03)
|
Regulated
gas sales - weather
|
(2)
|
(0.01)
|
(15)
|
(0.04)
|
2005
North Carolina rate case settlement(3)
|
--
|
--
|
(6)
|
(0.02)
|
Other
|
6
|
0.02
|
--
|
--
|
Share
dilution
|
--
|
--
|
--
|
(0.01)
|
Change
in net income contribution
|
$7
|
$ 0.02
|
$(21)
|
$(0.07)
|
(1)
|
Largely
reflects higher electric and gas
margins.
|
(2)
|
Primarily
reflects additional intercompany borrowings and higher interest rates
on
those borrowings.
|
(3)
|
A
benefit recognized in 2005 by electric utility operations resulting
from
the establishment of certain regulatory assets in connection with
settlement of a North Carolina rate
case.
|
Second
Quarter
|
Year-To-Date
|
|||||
2006
|
2005
|
%
Change
|
2006
|
2005
|
%
Change
|
|
Gas
transmission throughput (bcf)
|
122
|
133
|
(8)%
|
356
|
434
|
(18)%
|
Second
Quarter
|
Year-To-Date
|
|||
2006
vs. 2005
|
2006
vs. 2005
|
|||
Increase
(Decrease)
|
Increase
(Decrease)
|
|||
Amount
|
EPS
|
Amount
|
EPS
|
|
(millions,
except EPS)
|
||||
Gas
transmission:
|
||||
Rate
settlement(1)
|
$(5)
|
$(0.01)
|
$(13)
|
$(0.04)
|
Other
margins(2)
|
15
|
0.04
|
17
|
0.04
|
Producer
services(3)(4)
|
(5)
|
(0.01)
|
9
|
0.03
|
Salaries,
wages, and benefits expense
|
(2)
|
(0.01)
|
(4)
|
(0.01)
|
Other
|
1
|
--
|
3
|
0.01
|
Share
dilution
|
--
|
--
|
--
|
(0.01)
|
Change
in net income contribution
|
$ 4
|
$0.01
|
$ 12
|
$0.02
|
(1)
|
Represents
lower natural gas transportation and storage revenues as a result
of a
rate settlement effective July
2005.
|
(2)
|
Higher
margins primarily from extracted products, natural gas production and
short-term service opportunities.
|
(3)
|
Lower
gains in the quarter-to-date period, resulting from the impact of
unfavorable price changes on gas marketing activities associated
with
certain contractual assets.
|
(4)
|
Higher
gains in the year-to-date period, resulting from the impact of favorable
price changes on gas marketing activities and higher margins on the
aggregation of gas supply.
|
Second
Quarter
|
Year-To-Date
|
|||||
2006
|
2005
|
%
Change
|
2006
|
2005
|
%
Change
|
|
Electricity
supplied (million mwhrs)
|
||||||
Utility
|
18.7
|
18.6
|
1
|
38.2
|
38.5
|
(1)
|
Merchant
|
9.9
|
8.6
|
15
|
20.9
|
18.6
|
12
|
Second
Quarter
|
Year-To-Date
|
|||
2006
vs. 2005
|
2006
vs. 2005
|
|||
Increase
(Decrease)
|
Increase
(Decrease)
|
|||
Amount
|
EPS
|
Amount
|
EPS
|
|
(millions,
except EPS)
|
||||
Merchant
generation margin(1)
|
$65
|
$ 0.19
|
$141
|
$ 0.41
|
Outage
costs
|
2
|
0.01
|
(11)
|
(0.03)
|
Regulated
electric sales:
|
||||
Customer
growth
|
5
|
0.01
|
11
|
0.03
|
Weather
|
(5)
|
(0.01)
|
(24)
|
(0.07)
|
Sale
of emissions allowances
|
(25)
|
(0.07)
|
(21)
|
(0.06)
|
Fuel
expenses in excess of rate recovery
|
(18)
|
(0.05)
|
(50)
|
(0.14)
|
Salaries,
wages, and benefits expense
|
(9)
|
(0.03)
|
(13)
|
(0.04)
|
Interest
expense
|
(3)
|
(0.01)
|
(12)
|
(0.04)
|
Energy
supply margin(2)
|
(7)
|
(0.02)
|
(2)
|
(0.01)
|
2005
North Carolina rate case settlement
|
--
|
--
|
(10)
|
(0.03)
|
Other
|
1
|
--
|
(16)
|
(0.04)
|
Share
dilution
|
--
|
(0.01)
|
--
|
(0.01)
|
Change
in net income contribution
|
$ 6
|
$ 0.01
|
$ (7)
|
$ (0.03)
|
(1)
|
Primarily
due to an increased contribution from Millstone, reflecting a significant
decrease in planned outage days over the prior
year.
|
(2)
|
Primarily
reflects a reduced benefit from FTRs in excess of congestion
costs.
|
Second
Quarter
|
Year-To-Date
|
|||||
2006
|
2005
|
%
Change
|
2006
|
2005
|
%
Change
|
|
Gas
production (bcf)
|
79
|
70
|
13%
|
151
|
144
|
5%
|
Oil
production (million bbls)
|
6.3
|
4.2
|
50
|
12.4
|
8.0
|
55
|
Average
realized prices without hedging results:
|
||||||
Gas
(per mcf)
(1)
|
$ 6.35
|
$ 6.79
|
(6)
|
$ 7.13
|
$ 6.48
|
10
|
Oil
(per bbl)
|
58.92
|
46.28
|
27
|
56.19
|
45.55
|
23
|
Average
realized prices with hedging results:
|
||||||
Gas
(per mcf)
(1)
|
4.10
|
4.17
|
(2)
|
4.52
|
4.18
|
8
|
Oil
(per bbl)
|
35.43
|
26.66
|
33
|
37.09
|
27.71
|
34
|
DD&A
(unit of production rate per mcfe)
|
$1.67
|
$1.42
|
17
|
$1.66
|
$1.42
|
17
|
(1)
|
Excludes
$63 million and $86 million for the three months ended June 30, 2006
and
2005, respectively, and $143 million and $163 million for the six
months
ended June 30, 2006 and 2005, respectively, of revenue recognized
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.
|
Second
Quarter
|
Year-To-Date
|
|||
2006
vs. 2005
|
2006
vs. 2005
|
|||
Increase
(Decrease)
|
Increase
(Decrease)
|
|||
Amount
|
EPS
|
Amount
|
EPS
|
|
(millions,
except EPS)
|
||||
Business
interruption insurance
|
$(86)
|
$(0.25)
|
$(116)
|
$(0.34)
|
DD&A(1)
|
(41)
|
(0.12)
|
(71)
|
(0.21)
|
Operations
and maintenance(2)
|
(28)
|
(0.08)
|
50
|
0.15
|
Interest
expense
|
(7)
|
(0.02)
|
(11)
|
(0.03)
|
Gas
and oil ¾
prices
|
(6)
|
(0.02)
|
56
|
0.16
|
Gas
and oil ¾
production(3)
|
86
|
0.25
|
134
|
0.39
|
Other
|
7
|
0.02
|
1
|
--
|
Share
dilution
|
--
|
(0.01)
|
--
|
(0.02)
|
Change
in net income contribution
|
$(75)
|
$(0.23)
|
$ 43
|
$ 0.10
|
(1)
|
Higher
DD&A, primarily reflecting higher industry finding and development
costs. For the year-to-date period, the increase also reflects increased
acquisition costs.
|
(2)
|
Higher
operations and maintenance expenses for the quarter, primarily resulting
from increased production costs and salaries, wages and benefits
expenses,
partially offset by favorable changes in the fair value of certain
gas and
oil hedges that were de-designated following the 2005 hurricanes.
Lower
operations and maintenance expenses for the year-to-date period are
largely attributable to favorable changes in the fair value of the
de-designated hedges mentioned
above.
|
(3)
|
Represents
an increase in oil production primarily resulting from deepwater
oil
production at the Gulf of Mexico Devils Tower, Triton and Goldfinger
projects, as well as an increase in gas production primarily resulting
from deepwater and Rocky Mountain
production.
|
Natural
Gas
|
Oil
|
|||
Year
|
Hedged
Production
(bcf)
|
Average
Hedge Price
(per
mcf)
|
Hedged
Production
(million bbls)
|
Average
Hedge Price
(per
bbl)
|
2006
|
112.1
|
$4.63
|
7.1
|
$25.02
|
2007
|
218.1
|
5.89
|
10.0
|
33.41
|
2008
|
164.1
|
8.27
|
5.0
|
49.36
|
Second
Quarter
|
Year-To-Date
|
|||||
2006
|
2005
|
$
Change
|
2006
|
2005
|
$
Change
|
|
(millions,
except EPS)
|
||||||
Specific
items attributable to operating segments
|
$ (9)
|
$ (2)
|
$ (7)
|
$ (102)
|
$ (56)
|
$ (46)
|
DCI
operations
|
(83)
|
--
|
(83)
|
(84)
|
(3)
|
(81)
|
Other
corporate operations
|
(69)
|
(46)
|
(23)
|
(66)
|
(100)
|
34
|
Total
net expense
|
$ (161)
|
$ (48)
|
$ (113)
|
$ (252)
|
$ (159)
|
$ (93)
|
Earnings
per share impact
|
$(0.46)
|
$(0.14)
|
$(0.32)
|
$(0.72)
|
$(0.46)
|
$(0.26)
|
·
|
A
$77 million ($47 million after-tax) charge resulting from the termination
of a long-term power purchase agreement, attributable to Dominion
Generation; and
|
·
|
A
$13 million ($8 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
|
24
|
Net
unrealized gain at inception of contracts initiated during the
period
|
--
|
Changes
in valuation techniques
|
--
|
Other
changes in fair value
|
(25)
|
Net
unrealized loss at June 30, 2006
|
$ (8)
|
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)
|
$
|
17
|
$
|
(13
|
)
|
$
|
1
|
$
|
1
|
$
|
--
|
$
|
6
|
||||||
Other
external sources(2)
|
(6
|
)
|
(6
|
)
|
(1
|
)
|
--
|
(1
|
)
|
(14
|
)
|
||||||||
Total
|
$
|
11
|
$
|
(19
|
)
|
$
|
--
|
$
|
1
|
$
|
(1
|
)
|
$
|
(8
|
)
|
(2)
|
Values
based on prices from over-the-counter broker activity and industry
services and, where applicable, conventional option pricing
models.
|
Gross
Credit
Exposure
|
|
(millions)
|
|
Investment
grade(1)
|
$ 636
|
Non-investment
grade(2)
|
34
|
No
external ratings:
|
|
Internally
rated - investment grade(3)
|
346
|
Internally
rated - non-investment grade(4)
|
185
|
Total
|
$1,201
|
(1)
|
Designations
as investment grade are based on minimum credit ratings assigned
by
Moody’s Investor Services (Moody’s) and Standard & Poor’s Rating
Services (Standard & Poor’s). The five largest counterparty exposures,
combined, for this category represented approximately 18% of the
total
gross credit exposure.
|
(2)
|
The
five largest counterparty exposures, combined, for this category
represented approximately 2% of the total gross credit exposure.
|
(3)
|
The
five largest counterparty exposures, combined, for this category
represented approximately 20% of the total gross credit exposure.
|
(4)
|
The
five largest counterparty exposures, combined, for this category
represented approximately 3% of the total gross credit
exposure.
|
·
|
$1.0
billion of capital expenditures for the purchase and development
of gas
and oil producing properties, drilling and equipment costs and
undeveloped
lease acquisitions;
|
·
|
$913
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;
|
·
|
$530
million for the purchases of securities held as investments in
our nuclear
decommissioning trusts; and
|
·
|
$91
million related to the acquisition of Pablo Energy LLC, which holds
producing and other properties in the Texas Panhandle area, net
of cash
acquired; partially offset by
|
·
|
$493
million of proceeds from the sales of securities held as investments
in
our nuclear decommissioning trusts; and
|
·
|
$20
million of proceeds received from prior year sales of gas and oil
mineral
rights and properties.
|
·
|
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
an adjustment 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
prior law, such a deferral was not
possible).
|
·
|
State
Line, a 515-megawatt coal-fired station in Hammond,
Indiana;
|
·
|
Armstrong,
a 625-megawatt natural gas-fired station in Shelocta,
Pennsylvania;
|
·
|
Troy,
a 600-megawatt natural gas-fired station in Luckey, Ohio,
and
|
·
|
Pleasants,
a 313-megawatt natural gas-fired station in St. Mary’s, West
Virginia.
|
Period
|
(a) Total
Number
of Shares
(or
Units)
Purchased(1)
|
(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
|
4/1/06-4/30/06
|
101
|
$74.55
|
N/A
|
21,275,000
shares/
$1.72
billion
|
5/1/06-5/31/06
|
--
|
--
|
N/A
|
21,275,000
shares/
$1.72
billion
|
6/1/06-6/30/06
|
835
|
$72.20
|
N/A
|
21,275,000
shares/
$1.72
billion
|
Total
|
936
|
$72.45
|
N/A
|
21,275,000
shares/
$1.72
billion
|
(1)
|
Amount
represents registered shares
tendered by employees to satisfy tax withholding obligations on vested
restricted stock.
|
·
|
Directors
were elected to the Board of Directors for a one-year term or until
next
year’s annual meeting;
|
·
|
Deloitte
& Touche LLP was ratified as our independent auditor for
2006;
|
·
|
Shareholders
did not approve the following:
|
·
|
A
proposal requesting that our articles of incorporation be amended
to
require director nominees be elected by majority vote of
shareholders;
|
·
|
A
proposal requesting a report to shareholders on how we are responding
to
regulatory and public pressure to reduce carbon dioxide and other
emissions; and
|
·
|
A
proposal requesting that shareholders approve any future extraordinary
retirement benefits for senior executives.
|
(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.
|
||
4.1
|
Junior
Subordinated Indenture II, dated June 1, 2006, between Dominion Resources,
Inc. and JPMorgan Chase Bank, N.A., as Trustee (filed
herewith).
|
||
4.2
|
First
Supplemental Indenture to the Junior Subordinated Indenture II dated
as of
June 1, 2006 pursuant to which the 2006 Series A Enhanced Junior
Subordinated Notes Due 2066 will be issued (filed herewith). The
form of
the 2006 Series A Enhanced Junior Subordinated Notes Due 2066 is
included
as Exhibit A to the First Supplemental Indenture.
|
||
4.3
|
Replacement
Capital Covenant entered into by Dominion Resources, Inc. dated June
23,
2006 (filed herewith).
|
||
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
|
|
August
3, 2006
|
/s/
Steven A.
Rogers
|
Steven
A. Rogers
Senior
Vice President and Controller
(Principal
Accounting Officer)
|
|