UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
(Mark
One)
þ
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|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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FOR
THE QUARTERLY PERIOD ENDED June 30,
2008
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OR
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o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
FOR
THE TRANSITION PERIOD FROM
TO
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Registrant,
Address of
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I.R.S.
Employer
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Principal
Executive Offices
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Identification
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State
of
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Commission
File Number
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and
Telephone Number
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Number
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Incorporation
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1-08788
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SIERRA
PACIFIC RESOURCES
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88-0198358
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Nevada
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P.O.
Box 10100
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(6100
Neil Road)
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Reno,
Nevada 89520-0400 (89511)
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(775)
834-4011
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2-28348
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NEVADA
POWER COMPANY
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88-0420104
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Nevada
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6226
West Sahara Avenue
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Las
Vegas, Nevada 89146
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(702)
367-5000
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0-00508
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SIERRA
PACIFIC POWER COMPANY
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88-0044418
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Nevada
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P.O.
Box 10100
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(6100
Neil Road)
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Reno,
Nevada 89520-0400 (89511)
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(775)
834-4011
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Indicate
by check mark whether registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes
þ
No
o
(Response
applicable to all registrants)
Indicate
by check mark whether any registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definition of “large accelerated
filer", "accelerated filer”, "non-accelerated filer" and "smaller reporting
company" in Rule 12b-2 of the Exchange Act.
Sierra
Pacific Resources:
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Large
accelerated filer
þ
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Accelerated
filer
o
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Non-accelerated
filer
o
|
Smaller reporting company
o
|
|
Nevada
Power Company:
|
|
Large
accelerated filer
o
|
|
Accelerated
filer
o
|
|
Non-accelerated
filer
þ
|
Smaller reporting company
o
|
|
Sierra
Pacific Power Company:
|
|
Large
accelerated filer
o
|
|
Accelerated
filer
o
|
|
Non-accelerated
filer
þ
|
Smaller reporting company
o
|
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes
o
No
þ
(Response applicable to all registrants)
Indicate
the number of shares outstanding of each of the issuer’s classes of Common
Stock, as of the latest practicable date.
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Class
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|
Outstanding
at August 1, 2008
|
Common
Stock, $1.00 par value
of
Sierra Pacific Resources
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234,088,844
Shares
|
Sierra
Pacific Resources is the sole holder of the 1,000 shares of outstanding Common
Stock, $1.00 stated value, of Nevada Power Company.
Sierra
Pacific Resources is the sole holder of the 1,000 shares of outstanding Common
Stock, $3.75 stated value, of Sierra Pacific Power Company.
This
combined Quarterly Report on Form 10-Q is separately filed by Sierra Pacific
Resources, Nevada Power Company and Sierra Pacific Power Company. Information
contained in this document relating to Nevada Power Company is filed by Sierra
Pacific Resources and separately by Nevada Power Company on its own behalf.
Nevada Power Company makes no representation as to information relating to
Sierra Pacific Resources or its subsidiaries, except as it may relate to Nevada
Power Company. Information contained in this document relating to Sierra Pacific
Power Company is filed by Sierra Pacific Resources and separately by Sierra
Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no
representation as to information relating to Sierra Pacific Resources or its
subsidiaries, except as it may relate to Sierra Pacific Power
Company.
SIERRA
PACIFIC RESOURCES
NEVADA
POWER COMPANY
SIERRA
PACIFIC POWER COMPANY
QUARTERLY
REPORTS ON FORM 10-Q
FOR
THE QUARTER ENDED JUNE 30, 2008
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|
CONSOLIDATED
BALANCE SHEETS
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|
(Dollars
in Thousands)
|
|
|
|
|
June
30,
|
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December
31,
|
|
|
|
|
2008
|
|
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2007
|
|
|
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(Unaudited)
|
|
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ASSETS
|
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|
Utility
Plant at Original Cost:
|
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|
|
|
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Plant in service
|
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$
|
8,640,135
|
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|
$
|
8,468,711
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Less accumulated provision for depreciation
|
|
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|
2,563,250
|
|
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|
2,526,379
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|
|
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|
6,076,885
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5,942,332
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|
Construction work-in-progress
|
|
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|
1,248,726
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|
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|
1,068,666
|
|
|
|
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|
7,325,611
|
|
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|
7,010,998
|
|
|
|
|
|
|
|
|
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|
Investments
and other property, net
|
|
|
|
30,952
|
|
|
|
31,061
|
|
|
|
|
|
|
|
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|
Current
Assets:
|
|
|
|
|
|
|
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Cash and cash equivalents
|
|
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|
70,825
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129,140
|
|
Accounts receivable less allowance for uncollectible
accounts:
|
|
|
|
|
|
|
|
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|
2008
- $28,556; 2007-$36,061
|
|
|
|
464,207
|
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|
434,359
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|
Deferred energy costs - electric (Note 1)
|
|
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|
67,944
|
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75,948
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|
Materials, supplies and fuel, at average cost
|
|
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120,199
|
|
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|
117,483
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|
Risk management assets (Note 5)
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|
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|
327,784
|
|
|
|
22,286
|
|
Deferred income taxes
|
|
|
|
67,177
|
|
|
|
43,295
|
|
Other
|
|
|
|
36,980
|
|
|
|
45,909
|
|
|
|
|
|
|
1,155,116
|
|
|
|
868,420
|
|
Deferred
Charges and Other Assets:
|
|
|
|
|
|
|
|
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|
Deferred energy costs - electric (Note 1)
|
|
|
|
179,718
|
|
|
|
205,030
|
|
Regulatory tax asset
|
|
|
|
264,250
|
|
|
|
267,848
|
|
Regulatory asset for pension plans
|
|
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|
189,279
|
|
|
|
133,984
|
|
Other regulatory assets
|
|
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|
784,029
|
|
|
|
758,287
|
|
Risk management assets (Note 5)
|
|
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|
58,022
|
|
|
|
12,429
|
|
Risk management regulatory assets - net (Note 5)
|
|
|
|
-
|
|
|
|
26,067
|
|
Unamortized debt issuance costs
|
|
|
|
61,075
|
|
|
|
65,218
|
|
Other
|
|
|
|
129,119
|
|
|
|
85,408
|
|
|
|
|
|
|
1,665,492
|
|
|
|
1,554,271
|
|
TOTAL
ASSETS
|
|
|
$
|
10,177,171
|
|
|
$
|
9,464,750
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
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|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholders' equity
|
|
|
$
|
3,024,027
|
|
|
$
|
2,996,575
|
|
Long-term debt
|
|
|
|
4,451,781
|
|
|
|
4,137,864
|
|
|
|
|
|
|
7,475,808
|
|
|
|
7,134,439
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
10,298
|
|
|
|
110,285
|
|
Accounts payable
|
|
|
|
388,460
|
|
|
|
357,867
|
|
Accrued interest
|
|
|
|
68,703
|
|
|
|
69,485
|
|
Accrued salaries and benefits
|
|
|
|
27,140
|
|
|
|
35,020
|
|
Current income taxes payable
|
|
|
|
1,344
|
|
|
|
3,544
|
|
Risk management liabilities (Note 5)
|
|
|
|
4,108
|
|
|
|
39,509
|
|
Accrued taxes
|
|
|
|
9,013
|
|
|
|
8,336
|
|
Deferred energy costs-electric (Note 1)
|
|
|
|
17,614
|
|
|
|
17,573
|
|
Deferred energy costs - gas (Note 1)
|
|
|
|
11,400
|
|
|
|
11,369
|
|
Other current liabilities
|
|
|
|
85,317
|
|
|
|
65,991
|
|
|
|
|
|
|
623,397
|
|
|
|
718,979
|
|
Commitments
and Contingencies (Note 6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
|
889,305
|
|
|
|
852,630
|
|
Deferred investment tax credit
|
|
|
|
27,408
|
|
|
|
28,895
|
|
Regulatory tax liability
|
|
|
|
26,901
|
|
|
|
28,445
|
|
Customer advances for construction
|
|
|
|
97,829
|
|
|
|
100,125
|
|
Accrued retirement benefits
|
|
|
|
148,353
|
|
|
|
77,525
|
|
Risk management liabilities
|
|
|
|
4,684
|
|
|
|
7,369
|
|
Risk management regulatory liability - net (Note 5)
|
|
|
|
353,272
|
|
|
|
-
|
|
Regulatory liabilities
|
|
|
|
318,958
|
|
|
|
304,026
|
|
Other
|
|
|
|
211,256
|
|
|
|
212,317
|
|
|
|
|
|
|
2,077,966
|
|
|
|
1,611,332
|
|
TOTAL
CAPITALIZATION AND LIABILITIES
|
|
|
$
|
10,177,171
|
|
|
$
|
9,464,750
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements.
|
|
|
|
CONSOLIDATED
INCOME STATEMENTS
|
|
(Dollars
in Thousands, Except Per Share Amounts)
|
|
(Unaudited)
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
806,638
|
|
|
$
|
820,464
|
|
|
$
|
1,526,088
|
|
|
$
|
1,491,508
|
|
Gas
|
|
|
32,152
|
|
|
|
31,378
|
|
|
|
117,746
|
|
|
|
116,498
|
|
Other
|
|
|
4
|
|
|
|
52
|
|
|
|
11
|
|
|
|
319
|
|
|
|
|
838,794
|
|
|
|
851,894
|
|
|
|
1,643,845
|
|
|
|
1,608,325
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
261,450
|
|
|
|
262,025
|
|
|
|
445,306
|
|
|
|
440,929
|
|
Fuel
for power generation
|
|
|
270,625
|
|
|
|
192,058
|
|
|
|
492,233
|
|
|
|
420,212
|
|
Gas
purchased for resale
|
|
|
27,632
|
|
|
|
19,862
|
|
|
|
94,528
|
|
|
|
91,508
|
|
Deferral
of energy costs - electric - net
|
|
|
(21,386
|
)
|
|
|
86,501
|
|
|
|
32,896
|
|
|
|
127,294
|
|
Deferral
of energy costs - gas - net
|
|
|
(3,774
|
)
|
|
|
3,554
|
|
|
|
(1,571
|
)
|
|
|
1,609
|
|
Other
|
|
|
98,647
|
|
|
|
92,268
|
|
|
|
190,322
|
|
|
|
177,015
|
|
Maintenance
|
|
|
21,472
|
|
|
|
30,633
|
|
|
|
44,594
|
|
|
|
54,378
|
|
Depreciation
and amortization
|
|
|
64,341
|
|
|
|
59,678
|
|
|
|
126,411
|
|
|
|
115,911
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
12,928
|
|
|
|
7,244
|
|
|
|
21,547
|
|
|
|
6,489
|
|
Other
than income
|
|
|
12,658
|
|
|
|
11,640
|
|
|
|
26,565
|
|
|
|
24,619
|
|
|
|
|
744,593
|
|
|
|
765,463
|
|
|
|
1,472,831
|
|
|
|
1,459,964
|
|
OPERATING
INCOME
|
|
|
94,201
|
|
|
|
86,431
|
|
|
|
171,014
|
|
|
|
148,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for other funds used during construction
|
|
|
13,113
|
|
|
|
6,612
|
|
|
|
25,070
|
|
|
|
13,179
|
|
Interest
accrued on deferred energy
|
|
|
457
|
|
|
|
3,773
|
|
|
|
1,693
|
|
|
|
8,387
|
|
Carrying
charge for Lenzie
|
|
|
-
|
|
|
|
5,998
|
|
|
|
-
|
|
|
|
16,080
|
|
Reinstated
interest on deferred energy
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,076
|
|
Other
income
|
|
|
4,532
|
|
|
|
6,382
|
|
|
|
18,204
|
|
|
|
13,688
|
|
Other
expense
|
|
|
(4,770
|
)
|
|
|
(8,150
|
)
|
|
|
(7,797
|
)
|
|
|
(13,066
|
)
|
Income
taxes
|
|
|
(4,099
|
)
|
|
|
(4,675
|
)
|
|
|
(12,188
|
)
|
|
|
(16,058
|
)
|
|
|
|
9,233
|
|
|
|
9,940
|
|
|
|
24,982
|
|
|
|
33,286
|
|
Total
Income Before Interest Charges
|
|
|
103,434
|
|
|
|
96,371
|
|
|
|
195,996
|
|
|
|
181,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
70,388
|
|
|
|
68,546
|
|
|
|
140,343
|
|
|
|
134,995
|
|
Other
|
|
|
7,000
|
|
|
|
7,445
|
|
|
|
14,701
|
|
|
|
15,999
|
|
Allowance
for borrowed funds used during construction
|
|
|
(10,088
|
)
|
|
|
(5,374
|
)
|
|
|
(19,240
|
)
|
|
|
(10,708
|
)
|
|
|
|
67,300
|
|
|
|
70,617
|
|
|
|
135,804
|
|
|
|
140,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME APPLICABLE TO COMMON STOCK
|
|
$
|
36,134
|
|
|
$
|
25,754
|
|
|
$
|
60,192
|
|
|
$
|
41,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
per share basic and diluted - (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income applicable to common stock
|
|
$
|
0.15
|
|
|
$
|
0.12
|
|
|
$
|
0.26
|
|
|
$
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares of Common Stock Outstanding - basic
|
|
|
233,992,721
|
|
|
|
221,412,345
|
|
|
|
233,914,046
|
|
|
|
221,329,347
|
|
Weighted
Average Shares of Common Stock Outstanding - diluted
|
|
|
234,519,562
|
|
|
|
221,821,195
|
|
|
|
234,420,336
|
|
|
|
221,738,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements.
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Dollars
in Thousands)
|
|
(Unaudited)
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
Income applicable to common stock
|
|
$
|
60,192
|
|
|
$
|
41,361
|
|
Adjustments
to reconcile net income to net cash from operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
126,411
|
|
|
|
115,911
|
|
Deferred
taxes and deferred investment tax credit
|
|
|
88,346
|
|
|
|
31,661
|
|
AFUDC
|
|
|
(25,070
|
)
|
|
|
(13,179
|
)
|
Amortization
of deferred energy costs - electric
|
|
|
106,821
|
|
|
|
88,482
|
|
Amortization
of deferred energy costs - gas
|
|
|
(865
|
)
|
|
|
638
|
|
Deferral
of energy costs - electric
|
|
|
(73,464
|
)
|
|
|
30,941
|
|
Deferral
of energy costs - gas
|
|
|
896
|
|
|
|
(638
|
)
|
Carrying
charge on Lenzie plant
|
|
|
-
|
|
|
|
(16,080
|
)
|
Reinstated
interest on deferred energy
|
|
|
-
|
|
|
|
(11,076
|
)
|
Other,
net
|
|
|
(10,992
|
)
|
|
|
15,782
|
|
Changes
in certain assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(63,653
|
)
|
|
|
(75,685
|
)
|
Materials,
supplies and fuel
|
|
|
(2,717
|
)
|
|
|
(4,460
|
)
|
Other
current assets
|
|
|
8,929
|
|
|
|
4,825
|
|
Accounts
payable
|
|
|
9,690
|
|
|
|
53,326
|
|
Accrued
retirement benefits
|
|
|
12,642
|
|
|
|
5,488
|
|
Other
current liabilities
|
|
|
11,414
|
|
|
|
(8,155
|
)
|
Risk
Management assets and liabilities
|
|
|
(9,837
|
)
|
|
|
(4,946
|
)
|
Other
deferred assets
|
|
|
(18,019
|
)
|
|
|
(14,506
|
)
|
Other
regulatory assets
|
|
|
(32,812
|
)
|
|
|
(7,976
|
)
|
Other
liabilities
|
|
|
178
|
|
|
|
(17,884
|
)
|
Net
Cash from Operating Activities
|
|
|
188,090
|
|
|
|
213,830
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS USED BY INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Additions
to utility plant (excluding equity related to AFUDC)
|
|
|
(471,675
|
)
|
|
|
(585,050
|
)
|
Customer
advances for construction
|
|
|
(2,297
|
)
|
|
|
5,254
|
|
Contributions
in aid of construction
|
|
|
41,994
|
|
|
|
30,312
|
|
Investments
and other property - net
|
|
|
4,379
|
|
|
|
1,381
|
|
Net
Cash used by Investing Activities
|
|
|
(427,599
|
)
|
|
|
(548,103
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of long-term debt
|
|
|
428,000
|
|
|
|
1,029,014
|
|
Retirement
of long-term debt
|
|
|
(214,070
|
)
|
|
|
(672,630
|
)
|
Sale
of common stock
|
|
|
4,795
|
|
|
|
-
|
|
Proceeds
from exercise of stock option
|
|
|
-
|
|
|
|
9,096
|
|
Dividends
paid
|
|
|
(37,531
|
)
|
|
|
-
|
|
Net
Cash from Financing Activities
|
|
|
181,194
|
|
|
|
365,480
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(58,315
|
)
|
|
|
31,207
|
|
Beginning
Balance in Cash and Cash Equivalents
|
|
|
129,140
|
|
|
|
115,709
|
|
Ending
Balance in Cash and Cash Equivalents
|
|
$
|
70,825
|
|
|
$
|
146,916
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures of Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash
paid during period for:
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
143,472
|
|
|
$
|
146,941
|
|
Income
taxes
|
|
$
|
15,553
|
|
|
$
|
6,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Dollars
in Thousands)
|
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
Utility
Plant at Original Cost:
|
|
|
|
|
|
|
|
Plant in service
|
|
|
$
|
5,699,780
|
|
|
$
|
5,571,492
|
|
Less accumulated provision for depreciation
|
|
|
|
1,426,298
|
|
|
|
1,407,334
|
|
|
|
|
|
4,273,482
|
|
|
|
4,164,158
|
|
Construction work-in-progress
|
|
|
|
716,331
|
|
|
|
576,127
|
|
|
|
|
|
4,989,813
|
|
|
|
4,740,285
|
|
|
|
|
|
|
|
|
|
|
|
Investments
and other property, net
|
|
|
|
19,568
|
|
|
|
19,544
|
|
|
|
|
|
|
|
|
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
36,488
|
|
|
|
37,001
|
|
Accounts receivable less allowance for uncollectible
accounts:
|
|
|
|
|
|
|
|
|
|
|
2008
- $25,996; 2007-$30,392
|
|
|
|
339,089
|
|
|
|
274,242
|
|
Deferred energy costs - electric (Note 1)
|
|
|
|
67,944
|
|
|
|
75,948
|
|
Materials, supplies and fuel, at average cost
|
|
|
|
67,945
|
|
|
|
68,671
|
|
Risk management assets (Note 5)
|
|
|
|
221,738
|
|
|
|
16,078
|
|
Intercompany income taxes receivable
|
|
|
|
43,572
|
|
|
|
-
|
|
Deferred income taxes
|
|
|
|
-
|
|
|
|
2,383
|
|
Other
|
|
|
|
25,968
|
|
|
|
28,352
|
|
|
|
|
|
|
802,744
|
|
|
|
502,675
|
|
Deferred
Charges and Other Assets:
|
|
|
|
|
|
|
|
|
|
Deferred energy costs - electric (Note 1)
|
|
|
|
179,718
|
|
|
|
205,030
|
|
Regulatory tax asset
|
|
|
|
167,899
|
|
|
|
165,257
|
|
Regulatory asset for pension plans
|
|
|
|
104,214
|
|
|
|
86,909
|
|
Other regulatory assets
|
|
|
|
540,774
|
|
|
|
524,460
|
|
Risk management assets (Note 5)
|
|
|
|
43,108
|
|
|
|
9,069
|
|
Risk management regulatory assets - net (Note 5)
|
|
|
|
-
|
|
|
|
17,186
|
|
Unamortized debt issuance costs
|
|
|
|
34,416
|
|
|
|
36,551
|
|
Other
|
|
|
|
108,626
|
|
|
|
70,403
|
|
|
|
|
|
|
1,178,755
|
|
|
|
1,114,865
|
|
TOTAL
ASSETS
|
|
|
$
|
6,990,880
|
|
|
$
|
6,377,369
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholder's equity
|
|
|
$
|
2,534,866
|
|
|
$
|
2,376,740
|
|
Long-term debt
|
|
|
|
2,664,929
|
|
|
|
2,528,141
|
|
|
|
|
|
|
5,199,795
|
|
|
|
4,904,881
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
8,636
|
|
|
|
8,642
|
|
Accounts payable
|
|
|
|
282,060
|
|
|
|
231,205
|
|
Accounts payable, affiliated companies
|
|
|
|
31,430
|
|
|
|
32,706
|
|
Accrued interest
|
|
|
|
41,765
|
|
|
|
41,920
|
|
Dividends declared
|
|
|
|
-
|
|
|
|
10,907
|
|
Accrued salaries and benefits
|
|
|
|
13,037
|
|
|
|
16,881
|
|
Current income taxes payable
|
|
|
|
-
|
|
|
|
3,544
|
|
Intercompany income taxes payable
|
|
|
|
-
|
|
|
|
15,403
|
|
Deferred income taxes
|
|
|
|
11,478
|
|
|
|
-
|
|
Risk management liabilities (Note 5)
|
|
|
|
2,085
|
|
|
|
26,982
|
|
Accrued taxes
|
|
|
|
4,872
|
|
|
|
4,529
|
|
Other current liabilities
|
|
|
|
71,963
|
|
|
|
50,902
|
|
|
|
|
|
|
467,326
|
|
|
|
443,621
|
|
Commitments
and Contingencies (Note 6)
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
|
612,223
|
|
|
|
585,168
|
|
Deferred investment tax credit
|
|
|
|
10,585
|
|
|
|
11,169
|
|
Regulatory tax liability
|
|
|
|
9,413
|
|
|
|
10,038
|
|
Customer advances for construction
|
|
|
|
54,921
|
|
|
|
58,890
|
|
Accrued retirement benefits
|
|
|
|
55,690
|
|
|
|
25,693
|
|
Risk management liabilities (Note 5)
|
|
|
|
3,323
|
|
|
|
5,116
|
|
Risk management regulatory liability - net (Note 5)
|
|
|
|
239,796
|
|
|
|
-
|
|
Regulatory liabilities
|
|
|
|
172,120
|
|
|
|
168,381
|
|
Other
|
|
|
|
165,688
|
|
|
|
164,412
|
|
|
|
|
|
|
1,323,759
|
|
|
|
1,028,867
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
CAPITALIZATION AND LIABILITIES
|
|
|
$
|
6,990,880
|
|
|
$
|
6,377,369
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements.
|
|
|
|
CONSOLIDATED
INCOME STATEMENTS
|
|
(Dollars
in Thousands)
|
|
(Unaudited)
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
OPERATING
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
570,223
|
|
|
$
|
575,108
|
|
|
$
|
1,039,395
|
|
|
$
|
993,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
164,087
|
|
|
|
175,716
|
|
|
|
257,837
|
|
|
|
271,310
|
|
Fuel
for power generation
|
|
|
209,920
|
|
|
|
140,773
|
|
|
|
373,941
|
|
|
|
304,858
|
|
Deferral
of energy costs-net
|
|
|
(9,691
|
)
|
|
|
67,731
|
|
|
|
36,084
|
|
|
|
94,663
|
|
Other
|
|
|
62,617
|
|
|
|
55,162
|
|
|
|
119,712
|
|
|
|
106,001
|
|
Maintenance
|
|
|
13,608
|
|
|
|
20,319
|
|
|
|
30,258
|
|
|
|
37,783
|
|
Depreciation
and amortization
|
|
|
42,323
|
|
|
|
38,833
|
|
|
|
82,953
|
|
|
|
74,594
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
12,865
|
|
|
|
8,654
|
|
|
|
14,997
|
|
|
|
442
|
|
Other
than income
|
|
|
7,427
|
|
|
|
6,692
|
|
|
|
15,749
|
|
|
|
14,426
|
|
|
|
|
503,156
|
|
|
|
513,880
|
|
|
|
931,531
|
|
|
|
904,077
|
|
OPERATING
INCOME
|
|
|
67,067
|
|
|
|
61,228
|
|
|
|
107,864
|
|
|
|
89,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for other funds used during construction
|
|
|
7,692
|
|
|
|
3,247
|
|
|
|
14,550
|
|
|
|
6,345
|
|
Interest
accrued on deferred energy
|
|
|
1,084
|
|
|
|
3,427
|
|
|
|
2,878
|
|
|
|
7,276
|
|
Carrying
charge for Lenzie
|
|
|
-
|
|
|
|
5,998
|
|
|
|
-
|
|
|
|
16,080
|
|
Reinstated
interest on deferred energy (Note 3)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,076
|
|
Other
income
|
|
|
3,107
|
|
|
|
2,909
|
|
|
|
8,854
|
|
|
|
8,030
|
|
Other
expense
|
|
|
(1,656
|
)
|
|
|
(5,384
|
)
|
|
|
(3,017
|
)
|
|
|
(7,426
|
)
|
Income
taxes
|
|
|
(3,131
|
)
|
|
|
(3,553
|
)
|
|
|
(7,522
|
)
|
|
|
(14,131
|
)
|
|
|
|
7,096
|
|
|
|
6,644
|
|
|
|
15,743
|
|
|
|
27,250
|
|
Total
Income Before Interest Charges
|
|
|
74,163
|
|
|
|
67,872
|
|
|
|
123,607
|
|
|
|
116,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
41,624
|
|
|
|
41,368
|
|
|
|
82,621
|
|
|
|
81,074
|
|
Other
|
|
|
5,384
|
|
|
|
5,603
|
|
|
|
11,215
|
|
|
|
12,439
|
|
Allowance
for borrowed funds used during construction
|
|
|
(6,020
|
)
|
|
|
(2,703
|
)
|
|
|
(11,375
|
)
|
|
|
(5,253
|
)
|
|
|
|
40,988
|
|
|
|
44,268
|
|
|
|
82,461
|
|
|
|
88,260
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
33,175
|
|
|
$
|
23,604
|
|
|
$
|
41,146
|
|
|
$
|
28,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements.
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Dollars
in Thousands)
|
|
(Unaudited)
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
Income
|
|
$
|
41,146
|
|
|
$
|
28,186
|
|
Adjustments
to reconcile net income to net cash from or
|
|
|
|
|
|
|
|
|
operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
82,953
|
|
|
|
74,594
|
|
Deferred
taxes and deferred investment tax credit
|
|
|
18,119
|
|
|
|
9,826
|
|
AFUDC
|
|
|
(14,550
|
)
|
|
|
(6,345
|
)
|
Amortization
of deferred energy costs
|
|
|
88,210
|
|
|
|
64,747
|
|
Deferral
of energy costs
|
|
|
(54,895
|
)
|
|
|
23,023
|
|
Carrying
charge on Lenzie plant
|
|
|
-
|
|
|
|
(16,080
|
)
|
Reinstated
interest on deferred energy
|
|
|
-
|
|
|
|
(11,076
|
)
|
Other,
net
|
|
|
(8,562
|
)
|
|
|
2,587
|
|
Changes
in certain assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(76,989
|
)
|
|
|
(113,064
|
)
|
Materials,
supplies and fuel
|
|
|
726
|
|
|
|
(2,576
|
)
|
Other
current assets
|
|
|
2,385
|
|
|
|
(5,292
|
)
|
Accounts
payable
|
|
|
19,379
|
|
|
|
65,001
|
|
Accrued
retirement benefits
|
|
|
7,789
|
|
|
|
6,983
|
|
Other
current liabilities
|
|
|
17,405
|
|
|
|
(6,077
|
)
|
Risk
management assets and liabilities
|
|
|
(9,406
|
)
|
|
|
(7,135
|
)
|
Other
deferred assets
|
|
|
(18,731
|
)
|
|
|
(10,829
|
)
|
Other
regulatory assets
|
|
|
(21,859
|
)
|
|
|
(5,981
|
)
|
Other
liabilities
|
|
|
1,357
|
|
|
|
(1,695
|
)
|
Net
Cash from Operating Activities
|
|
|
74,477
|
|
|
|
88,797
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS USED BY INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Additions
to utility plant (excluding equity related to AFUDC)
|
|
|
(352,560
|
)
|
|
|
(363,241
|
)
|
Customer
advances for construction
|
|
|
(3,969
|
)
|
|
|
3,313
|
|
Contributions
in aid of construction
|
|
|
33,869
|
|
|
|
20,289
|
|
Investments
and other property - net
|
|
|
2,795
|
|
|
|
1,366
|
|
Net
Cash used by Investing Activities
|
|
|
(319,865
|
)
|
|
|
(338,273
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of long-term debt
|
|
|
225,000
|
|
|
|
569,586
|
|
Retirement
of long-term debt
|
|
|
(88,218
|
)
|
|
|
(314,462
|
)
|
Additional
investment by parent company
|
|
|
133,000
|
|
|
|
-
|
|
Dividends
paid
|
|
|
(24,907
|
)
|
|
|
(13,472
|
)
|
Net
Cash from Financing Activities
|
|
|
244,875
|
|
|
|
241,652
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(513
|
)
|
|
|
(7,824
|
)
|
Beginning
Balance in Cash and Cash Equivalents
|
|
|
37,001
|
|
|
|
36,633
|
|
Ending
Balance in Cash and Cash Equivalents
|
|
$
|
36,488
|
|
|
$
|
28,809
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures of Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash
paid during period for:
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
84,783
|
|
|
$
|
90,847
|
|
Income
taxes
|
|
$
|
15,534
|
|
|
$
|
6,760
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(Dollars
in Thousands)
|
|
|
|
|
June
30,
|
|
|
December
31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
Utility
Plant at Original Cost:
|
|
|
|
|
|
|
|
Plant in service
|
|
|
$
|
2,940,355
|
|
|
$
|
2,897,219
|
|
Less accumulated provision for depreciation
|
|
|
|
1,136,952
|
|
|
|
1,119,045
|
|
|
|
|
|
1,803,403
|
|
|
|
1,778,174
|
|
Construction work-in-progress
|
|
|
|
532,395
|
|
|
|
492,539
|
|
|
|
|
|
2,335,798
|
|
|
|
2,270,713
|
|
|
|
|
|
|
|
|
|
|
|
Investments
and other property, net
|
|
|
|
438
|
|
|
|
570
|
|
|
|
|
|
|
|
|
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
21,829
|
|
|
|
23,807
|
|
Accounts receivable less allowance for uncollectible
accounts:
|
|
|
|
|
|
|
|
|
|
|
2008
- $2,560; 2007 - $5,669
|
|
|
|
125,021
|
|
|
|
160,014
|
|
Materials, supplies and fuel, at average cost
|
|
|
|
52,235
|
|
|
|
48,799
|
|
Risk management assets (Note 5)
|
|
|
|
106,046
|
|
|
|
6,208
|
|
Intercompany income taxes receivable
|
|
|
|
33,276
|
|
|
|
-
|
|
Deferred income taxes
|
|
|
|
17,686
|
|
|
|
17,728
|
|
Other
|
|
|
|
10,214
|
|
|
|
17,255
|
|
|
|
|
|
|
366,307
|
|
|
|
273,811
|
|
Deferred Charges and Other Assets:
|
|
|
|
|
|
|
|
|
|
Regulatory tax asset
|
|
|
|
96,351
|
|
|
|
102,591
|
|
Regulatory asset for pension plans
|
|
|
|
78,449
|
|
|
|
43,778
|
|
Other regulatory assets
|
|
|
|
243,255
|
|
|
|
233,827
|
|
Risk management assets (Note 5)
|
|
|
|
14,914
|
|
|
|
3,360
|
|
Risk management regulatory assets - net (Note 5)
|
|
|
|
-
|
|
|
|
8,881
|
|
Unamortized debt issuance costs
|
|
|
|
18,571
|
|
|
|
19,976
|
|
Other
|
|
|
|
20,194
|
|
|
|
19,017
|
|
|
|
|
|
|
471,734
|
|
|
|
431,430
|
|
TOTAL
ASSETS
|
|
|
$
|
3,174,277
|
|
|
$
|
2,976,524
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common shareholder’s equity
|
|
|
$
|
998,221
|
|
|
$
|
1,001,840
|
|
Long-term debt
|
|
|
|
1,261,788
|
|
|
|
1,084,550
|
|
|
|
|
|
|
2,260,009
|
|
|
|
2,086,390
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
|
1,662
|
|
|
|
101,643
|
|
Accounts payable
|
|
|
|
81,476
|
|
|
|
94,722
|
|
Accounts payable, affiliated companies
|
|
|
|
11,613
|
|
|
|
19,288
|
|
Accrued interest
|
|
|
|
15,112
|
|
|
|
15,750
|
|
Dividends declared
|
|
|
|
-
|
|
|
|
5,333
|
|
Accrued salaries and benefits
|
|
|
|
11,865
|
|
|
|
14,830
|
|
Intercompany income taxes payable
|
|
|
|
-
|
|
|
|
2,479
|
|
Risk management liabilities (Note 5)
|
|
|
|
2,023
|
|
|
|
12,527
|
|
Accrued taxes
|
|
|
|
4,043
|
|
|
|
3,542
|
|
Deferred energy costs-electric (Note 1)
|
|
|
|
17,614
|
|
|
|
17,573
|
|
Deferred energy costs - gas (Note 1)
|
|
|
|
11,400
|
|
|
|
11,369
|
|
Other current liabilities
|
|
|
|
13,354
|
|
|
|
15,015
|
|
|
|
|
|
|
170,162
|
|
|
|
314,071
|
|
Commitments
and Contingencies (Note 6)
|
|
|
|
|
|
|
|
|
|
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
|
276,357
|
|
|
|
267,801
|
|
Deferred investment tax credit
|
|
|
|
16,823
|
|
|
|
17,726
|
|
Regulatory tax liability
|
|
|
|
17,488
|
|
|
|
18,407
|
|
Customer advances for construction
|
|
|
|
42,908
|
|
|
|
41,235
|
|
Accrued retirement benefits
|
|
|
|
84,829
|
|
|
|
48,025
|
|
Risk management liabilities (Note 5)
|
|
|
|
1,361
|
|
|
|
2,253
|
|
Risk management regulatory liability - net (Note 5)
|
|
|
|
113,476
|
|
|
|
-
|
|
Regulatory liabilities
|
|
|
|
146,838
|
|
|
|
135,645
|
|
Other
|
|
|
|
44,026
|
|
|
|
44,971
|
|
|
|
|
|
|
744,106
|
|
|
|
576,063
|
|
TOTAL
CAPITALIZATION AND LIABILITIES
|
|
|
$
|
3,174,277
|
|
|
$
|
2,976,524
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
INCOME STATEMENTS
|
|
(Dollars
in Thousands)
|
|
(Unaudited)
|
|
|
|
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
OPERATING
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
236,415
|
|
|
$
|
245,356
|
|
|
$
|
486,693
|
|
|
$
|
498,235
|
|
Gas
|
|
|
32,152
|
|
|
|
31,378
|
|
|
|
117,746
|
|
|
|
116,498
|
|
|
|
|
268,567
|
|
|
|
276,734
|
|
|
|
604,439
|
|
|
|
614,733
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
97,363
|
|
|
|
86,309
|
|
|
|
187,469
|
|
|
|
169,619
|
|
Fuel
for power generation
|
|
|
60,705
|
|
|
|
51,285
|
|
|
|
118,292
|
|
|
|
115,354
|
|
Gas
purchased for resale
|
|
|
27,632
|
|
|
|
19,862
|
|
|
|
94,528
|
|
|
|
91,508
|
|
Deferral
of energy costs - electric - net
|
|
|
(11,695
|
)
|
|
|
18,770
|
|
|
|
(3,188
|
)
|
|
|
32,631
|
|
Deferral
of energy costs - gas - net
|
|
|
(3,774
|
)
|
|
|
3,554
|
|
|
|
(1,571
|
)
|
|
|
1,609
|
|
Other
|
|
|
34,765
|
|
|
|
35,994
|
|
|
|
68,270
|
|
|
|
68,842
|
|
Maintenance
|
|
|
7,864
|
|
|
|
10,314
|
|
|
|
14,336
|
|
|
|
16,595
|
|
Depreciation
and amortization
|
|
|
22,018
|
|
|
|
20,845
|
|
|
|
43,458
|
|
|
|
41,317
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
3,952
|
|
|
|
2,686
|
|
|
|
13,611
|
|
|
|
11,046
|
|
Other
than income
|
|
|
5,198
|
|
|
|
4,902
|
|
|
|
10,726
|
|
|
|
10,088
|
|
|
|
|
244,028
|
|
|
|
254,521
|
|
|
|
545,931
|
|
|
|
558,609
|
|
OPERATING
INCOME
|
|
|
24,539
|
|
|
|
22,213
|
|
|
|
58,508
|
|
|
|
56,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME (EXPENSE):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for other funds used during construction
|
|
|
5,421
|
|
|
|
3,365
|
|
|
|
10,520
|
|
|
|
6,834
|
|
Interest
accrued on deferred energy
|
|
|
(627
|
)
|
|
|
346
|
|
|
|
(1,185
|
)
|
|
|
1,111
|
|
Other
income
|
|
|
1,229
|
|
|
|
3,011
|
|
|
|
8,964
|
|
|
|
4,842
|
|
Other
expense
|
|
|
(2,881
|
)
|
|
|
(2,191
|
)
|
|
|
(4,681
|
)
|
|
|
(4,205
|
)
|
Income
taxes
|
|
|
(953
|
)
|
|
|
(1,282
|
)
|
|
|
(4,527
|
)
|
|
|
(2,493
|
)
|
|
|
|
2,189
|
|
|
|
3,249
|
|
|
|
9,091
|
|
|
|
6,089
|
|
Total
Income Before Interest Charges
|
|
|
26,728
|
|
|
|
25,462
|
|
|
|
67,599
|
|
|
|
62,213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST
CHARGES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
18,578
|
|
|
|
16,542
|
|
|
|
37,340
|
|
|
|
32,650
|
|
Other
|
|
|
1,369
|
|
|
|
1,583
|
|
|
|
2,991
|
|
|
|
3,042
|
|
Allowance
for borrowed funds used during construction
|
|
|
(4,068
|
)
|
|
|
(2,671
|
)
|
|
|
(7,865
|
)
|
|
|
(5,455
|
)
|
|
|
|
15,879
|
|
|
|
15,454
|
|
|
|
32,466
|
|
|
|
30,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET
INCOME
|
|
$
|
10,849
|
|
|
$
|
10,008
|
|
|
$
|
35,133
|
|
|
$
|
31,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
(Dollars
in Thousands)
|
|
(Unaudited)
|
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
|
2008
|
|
|
2007
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
Net
Income
|
|
$
|
35,133
|
|
|
$
|
31,976
|
|
Adjustments
to reconcile net income to net cash from operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
43,458
|
|
|
|
41,317
|
|
Deferred
taxes and deferred investment tax credit
|
|
|
10,537
|
|
|
|
(7,652
|
)
|
AFUDC
|
|
|
(10,520
|
)
|
|
|
(6,834
|
)
|
Amortization
of deferred energy costs - electric
|
|
|
18,611
|
|
|
|
23,735
|
|
Amortization
of deferred energy costs - gas
|
|
|
(865
|
)
|
|
|
638
|
|
Deferral
of energy costs - electric
|
|
|
(18,569
|
)
|
|
|
7,918
|
|
Deferral
of energy costs - gas
|
|
|
896
|
|
|
|
(638
|
)
|
Other,
net
|
|
|
2,235
|
|
|
|
13,216
|
|
Changes
in certain assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
13,330
|
|
|
|
37,212
|
|
Materials,
supplies and fuel
|
|
|
(3,437
|
)
|
|
|
(1,884
|
)
|
Other
current assets
|
|
|
7,041
|
|
|
|
10,161
|
|
Accounts
payable
|
|
|
(11,624
|
)
|
|
|
15,814
|
|
Accrued
retirement benefits
|
|
|
826
|
|
|
|
(2,354
|
)
|
Other
current liabilities
|
|
|
(4,762
|
)
|
|
|
(1,119
|
)
|
Risk
management assets and liabilities
|
|
|
(431
|
)
|
|
|
2,189
|
|
Other
deferred assets
|
|
|
712
|
|
|
|
(3,677
|
)
|
Other
regulatory assets
|
|
|
(10,953
|
)
|
|
|
(1,995
|
)
|
Other
liabilities
|
|
|
215
|
|
|
|
(2,139
|
)
|
Net
Cash from Operating Activities
|
|
|
71,833
|
|
|
|
155,884
|
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS USED BY INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Additions
to utility plant (excluding equity related to AFUDC)
|
|
|
(119,115
|
)
|
|
|
(221,809
|
)
|
Customer
advances for construction
|
|
|
1,672
|
|
|
|
1,941
|
|
Contributions
in aid of construction
|
|
|
8,125
|
|
|
|
10,023
|
|
Investments
and other property - net
|
|
|
1,584
|
|
|
|
12
|
|
Net
Cash used by Investing Activities
|
|
|
(107,734
|
)
|
|
|
(209,833
|
)
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of long-term debt
|
|
|
203,000
|
|
|
|
459,428
|
|
Retirement
of long-term debt
|
|
|
(125,744
|
)
|
|
|
(358,062
|
)
|
Investment
by parent company
|
|
|
20,000
|
|
|
|
-
|
|
Dividends
paid
|
|
|
(63,333
|
)
|
|
|
(6,736
|
)
|
Net
Cash from Financing Activities
|
|
|
33,923
|
|
|
|
94,630
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(1,978
|
)
|
|
|
40,681
|
|
Beginning
Balance in Cash and Cash Equivalents
|
|
|
23,807
|
|
|
|
53,260
|
|
Ending
Balance in Cash and Cash Equivalents
|
|
$
|
21,829
|
|
|
$
|
93,941
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures of Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash
paid during period for:
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
38,318
|
|
|
$
|
34,823
|
|
Income
taxes
|
|
$
|
19
|
|
|
$
|
64
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of the financial
statements
|
|
NOTE
1. SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
The
significant accounting policies for both utility and non-utility operations are
as follows:
Basis
of Presentation
The consolidated financial statements
of Sierra Pacific Resources (SPR) include the accounts of SPR and its
wholly-owned subsidiaries, Nevada Power Company (NPC) and Sierra Pacific Power
Company (SPPC) (collectively, the "Utilities"), Sierra Gas Holding Company
(SGHC), Sierra Pacific Energy Company (SPE), Lands of Sierra (LOS), Sierra
Pacific Communications (SPC) and Sierra Water Development Company
(SWDC). The consolidated financial statements of NPC include the
accounts of NPC and its wholly-owned subsidiary, Nevada Electric Investment
Company (NEICO). The consolidated financial statements of SPPC
include the accounts of SPPC and its wholly-owned subsidiaries, GPSF-B, Piñon
Pine Corporation (PPC), Piñon Pine Investment Company, Piñon Pine Company,
L.L.C. and Sierra Pacific Funding L.L.C. All significant intercompany
transactions and balances have been eliminated in consolidation.
The preparation of consolidated
financial statements in conformity with accounting principles generally accepted
in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of certain assets and
liabilities. These estimates and assumptions also affect the
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of certain revenues and expenses during the
reporting period. Actual results could differ from these
estimates.
In the opinion of the management of
SPR, NPC and SPPC, the accompanying unaudited interim consolidated financial
statements contain all adjustments necessary to present fairly the consolidated
financial position, results of operations and cash flows for the periods
shown. These consolidated financial statements do not contain the
complete detail concerning accounting policies and other matters, which are
included in full year financial statements; therefore, they should be read in
conjunction with the audited financial statements included in SPR’s, NPC’s and
SPPC’s Annual Reports on Form 10-K and/or Form 10-K/A for the year ended
December 31, 2007 (collectively, the “2007 Form 10-K”).
The results of operations and cash
flows of SPR, NPC and SPPC for the six months ended June 30, 2008, are not
necessarily indicative of the results to be expected for the full
year.
Deferral
of Energy Costs
NPC and SPPC follow deferred energy
accounting. See Note 1, Summary of Significant Accounting Policies,
of Notes to Financial Statements in NPC's and SPPC's 2007 Form 10-K, for
additional information regarding deferred energy accounting by the
Utilities.
The following deferred energy costs
were included in the consolidated balance sheets as of June 30, 2008 (dollars in
thousands):
|
|
June
30, 2008
|
|
Description
|
|
NPC
Electric
|
|
|
SPPC
Electric
|
|
|
SPPC
Gas
|
|
|
SPR
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unamortized
balances approved for collection in current rates as of January 1,
2008
|
|
$
|
79,924
|
|
|
$
|
13,257
|
|
|
$
|
(1,208
|
)
|
|
$
|
91,973
|
|
Balances pending PUCN approval
(1)
|
|
|
(43,699
|
)
|
|
|
(34,198
|
)
|
|
|
(10,161
|
)
|
|
|
(88,058
|
)
|
Cumulative
balance request in 2008 DEAA
|
|
|
36,225
|
|
|
|
(20,941
|
)
|
|
|
(11,369
|
)
|
|
|
3,915
|
|
2008
amortization of approved balances
|
|
|
(69,206
|
)
|
|
|
(15,765
|
)
|
|
|
865
|
|
|
|
(84,106
|
)
|
2008 deferred
energy
costs not yet
requested
|
|
|
52,321
|
|
|
|
18,285
|
|
|
|
(896
|
)
|
|
|
69,710
|
|
Western
Energy Crisis Rate Case - NPC
(effective 6/07, 3 years)
|
|
|
55,710
|
|
|
|
-
|
|
|
|
-
|
|
|
|
55,710
|
|
Reinstatement
of deferred
energy
(effective 6/07, 10 years)
|
|
|
172,612
|
|
|
|
-
|
|
|
|
-
|
|
|
|
172,612
|
|
Cumulative
CPUC balance
|
|
|
-
|
|
|
|
807
|
|
|
|
-
|
|
|
|
807
|
|
Total
|
|
$
|
247,662
|
|
|
$
|
(17,614
|
)
|
|
$
|
(11,400
|
)
|
|
$
|
218,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs –
electric
|
|
$
|
67,944
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
67,944
|
|
Deferred
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs -
electric
|
|
|
179,718
|
|
|
|
-
|
|
|
|
-
|
|
|
|
179,718
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred energy costs –
electric
|
|
|
-
|
|
|
|
(17,614
|
)
|
|
|
-
|
|
|
|
(17,614
|
)
|
Deferred energy costs –
gas
|
|
|
-
|
|
|
|
-
|
|
|
|
(11,400
|
)
|
|
|
(11,400
|
)
|
Total
|
|
$
|
247,662
|
|
|
$
|
(17,614
|
)
|
|
$
|
(11,400
|
)
|
|
$
|
218,648
|
|
(1)
|
Credit
balances represent potential refunds to the Utilities’
customers.
|
Recent
Pronouncements
SFAS 161
In March 2008, the FASB issued
Statement of Financial Accounting Standards No. 161 Disclosures about Derivative
Instruments and Hedging Activities an amendment of FASB Statement No. 133 (“SFAS
161”) which is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008. The purpose of
SFAS 161 is to provide more adequate disclosure about how derivative and hedging
activities affect an entity’s financial position, financial performance and cash
flows. The Utilities are currently evaluating the additional
disclosure requirements but do not expect their disclosure to change
significantly.
NOTE
2. SEGMENT
INFORMATION
The
Utilities operate three regulated business segments (as defined by SFAS 131,
“Disclosure about Segments of an Enterprise and Related Information”); which are
NPC electric, SPPC electric and SPPC natural gas service. Electric
service is provided to Las Vegas and surrounding Clark County by NPC, and
northern Nevada and the Lake Tahoe area of California by
SPPC. Natural gas services are provided by SPPC in the Reno-Sparks
area of Nevada. Other segment information includes segments below the
quantitative thresholds for separate disclosure.
Operational
information of the different business segments is set forth below based on the
nature of products and services offered. SPR evaluates performance
based on several factors, of which the primary financial measure is business
segment gross margin. Gross margin, which the Utilities calculate as
operating revenues less fuel, purchased power, and deferred energy costs,
provides a measure of income available to support the other operating expenses
of the Utilities. Operating expenses are provided by segment in order
to reconcile to operating income as reported in the consolidated financial
statements (dollars in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
NPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
SPR
|
|
June
30, 2008
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
Total
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
570,223
|
|
|
$
|
236,415
|
|
|
$
|
32,152
|
|
|
$
|
268,567
|
|
|
$
|
4
|
|
|
$
|
838,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
164,087
|
|
|
|
97,363
|
|
|
|
-
|
|
|
|
97,363
|
|
|
|
-
|
|
|
|
261,450
|
|
Fuel
for power generation
|
|
|
209,920
|
|
|
|
60,705
|
|
|
|
-
|
|
|
|
60,705
|
|
|
|
-
|
|
|
|
270,625
|
|
Gas
purchased for resale
|
|
|
-
|
|
|
|
-
|
|
|
|
27,632
|
|
|
|
27,632
|
|
|
|
-
|
|
|
|
27,632
|
|
Deferred
energy costs - net
|
|
|
(9,691
|
)
|
|
|
(11,695
|
)
|
|
|
(3,774
|
)
|
|
|
(15,469
|
)
|
|
|
-
|
|
|
|
(25,160
|
)
|
|
|
|
364,316
|
|
|
|
146,373
|
|
|
|
23,858
|
|
|
|
170,231
|
|
|
|
-
|
|
|
|
534,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
|
|
$
|
205,907
|
|
|
$
|
90,042
|
|
|
$
|
8,294
|
|
|
$
|
98,336
|
|
|
$
|
4
|
|
|
$
|
304,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
62,617
|
|
|
|
|
|
|
|
|
|
|
|
34,765
|
|
|
|
1,265
|
|
|
|
98,647
|
|
Maintenance
|
|
|
13,608
|
|
|
|
|
|
|
|
|
|
|
|
7,864
|
|
|
|
-
|
|
|
|
21,472
|
|
Depreciation
and amortization
|
|
|
42,323
|
|
|
|
|
|
|
|
|
|
|
|
22,018
|
|
|
|
-
|
|
|
|
64,341
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
12,865
|
|
|
|
|
|
|
|
|
|
|
|
3,952
|
|
|
|
(3,889
|
)
|
|
|
12,928
|
|
Other
than income
|
|
|
7,427
|
|
|
|
|
|
|
|
|
|
|
|
5,198
|
|
|
|
33
|
|
|
|
12,658
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
$
|
67,067
|
|
|
|
|
|
|
|
|
|
|
$
|
24,539
|
|
|
$
|
2,595
|
|
|
$
|
94,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
NPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
SPR
|
|
June
30, 2008
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
Total
|
|
|
Other
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
1,039,395
|
|
|
$
|
486,693
|
|
|
$
|
117,746
|
|
|
$
|
604,439
|
|
|
$
|
11
|
|
|
$
|
1,643,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
257,837
|
|
|
|
187,469
|
|
|
|
-
|
|
|
|
187,469
|
|
|
|
-
|
|
|
|
445,306
|
|
Fuel
for power generation
|
|
|
373,941
|
|
|
|
118,292
|
|
|
|
-
|
|
|
|
118,292
|
|
|
|
-
|
|
|
|
492,233
|
|
Gas
purchased for resale
|
|
|
-
|
|
|
|
-
|
|
|
|
94,528
|
|
|
|
94,528
|
|
|
|
-
|
|
|
|
94,528
|
|
Deferred
energy costs - net
|
|
|
36,084
|
|
|
|
(3,188
|
)
|
|
|
(1,571
|
)
|
|
|
(4,759
|
)
|
|
|
-
|
|
|
|
31,325
|
|
|
|
|
667,862
|
|
|
|
302,573
|
|
|
|
92,957
|
|
|
|
395,530
|
|
|
|
-
|
|
|
|
1,063,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
|
|
$
|
371,533
|
|
|
$
|
184,120
|
|
|
$
|
24,789
|
|
|
$
|
208,909
|
|
|
$
|
11
|
|
|
$
|
580,453
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
119,712
|
|
|
|
|
|
|
|
|
|
|
|
68,270
|
|
|
|
2,340
|
|
|
|
190,322
|
|
Maintenance
|
|
|
30,258
|
|
|
|
|
|
|
|
|
|
|
|
14,336
|
|
|
|
-
|
|
|
|
44,594
|
|
Depreciation
and amortization
|
|
|
82,953
|
|
|
|
|
|
|
|
|
|
|
|
43,458
|
|
|
|
-
|
|
|
|
126,411
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
14,997
|
|
|
|
|
|
|
|
|
|
|
|
13,611
|
|
|
|
(7,061
|
)
|
|
|
21,547
|
|
Other
than income
|
|
|
15,749
|
|
|
|
|
|
|
|
|
|
|
|
10,726
|
|
|
|
90
|
|
|
|
26,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
$
|
107,864
|
|
|
|
|
|
|
|
|
|
|
$
|
58,508
|
|
|
$
|
4,642
|
|
|
$
|
171,014
|
|
Three
Months Ended
|
|
NPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
SPR
|
|
June
30, 2007
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
Total
|
|
|
Other
|
|
|
Consolidated
|
|
Operating
Revenues
|
|
$
|
575,108
|
|
|
$
|
245,356
|
|
|
$
|
31,378
|
|
|
$
|
276,734
|
|
|
$
|
52
|
|
|
$
|
851,894
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
175,716
|
|
|
|
86,309
|
|
|
|
-
|
|
|
|
86,309
|
|
|
|
-
|
|
|
|
262,025
|
|
Fuel
for power generation
|
|
|
140,773
|
|
|
|
51,285
|
|
|
|
-
|
|
|
|
51,285
|
|
|
|
-
|
|
|
|
192,058
|
|
Gas
purchased for resale
|
|
|
-
|
|
|
|
-
|
|
|
|
19,862
|
|
|
|
19,862
|
|
|
|
-
|
|
|
|
19,862
|
|
Deferred
energy costs - net
|
|
|
67,731
|
|
|
|
18,770
|
|
|
|
3,554
|
|
|
|
22,324
|
|
|
|
-
|
|
|
|
90,055
|
|
|
|
|
384,220
|
|
|
|
156,364
|
|
|
|
23,416
|
|
|
|
179,780
|
|
|
|
-
|
|
|
|
564,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
|
|
$
|
190,888
|
|
|
$
|
88,992
|
|
|
$
|
7,962
|
|
|
$
|
96,954
|
|
|
$
|
52
|
|
|
$
|
287,894
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
55,162
|
|
|
|
|
|
|
|
|
|
|
|
35,994
|
|
|
|
1,112
|
|
|
|
92,268
|
|
Maintenance
|
|
|
20,319
|
|
|
|
|
|
|
|
|
|
|
|
10,314
|
|
|
|
-
|
|
|
|
30,633
|
|
Depreciation
and amortization
|
|
|
38,833
|
|
|
|
|
|
|
|
|
|
|
|
20,845
|
|
|
|
-
|
|
|
|
59,678
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
8,654
|
|
|
|
|
|
|
|
|
|
|
|
2,686
|
|
|
|
(4,096
|
)
|
|
|
7,244
|
|
Other
than income
|
|
|
6,692
|
|
|
|
|
|
|
|
|
|
|
|
4,902
|
|
|
|
46
|
|
|
|
11,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
$
|
61,228
|
|
|
|
|
|
|
|
|
|
|
$
|
22,213
|
|
|
$
|
2,990
|
|
|
$
|
86,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
NPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
SPR
|
|
June
30, 2007
|
|
Electric
|
|
|
Electric
|
|
|
Gas
|
|
|
Total
|
|
|
Other
|
|
|
Consolidated
|
|
Operating
Revenues
|
|
$
|
993,273
|
|
|
$
|
498,235
|
|
|
$
|
116,498
|
|
|
$
|
614,733
|
|
|
$
|
319
|
|
|
$
|
1,608,325
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
271,310
|
|
|
|
169,619
|
|
|
|
-
|
|
|
|
169,619
|
|
|
|
-
|
|
|
|
440,929
|
|
Fuel
for power generation
|
|
|
304,858
|
|
|
|
115,354
|
|
|
|
-
|
|
|
|
115,354
|
|
|
|
-
|
|
|
|
420,212
|
|
Gas
purchased for resale
|
|
|
-
|
|
|
|
-
|
|
|
|
91,508
|
|
|
|
91,508
|
|
|
|
-
|
|
|
|
91,508
|
|
Deferred
energy costs - net
|
|
|
94,663
|
|
|
|
32,631
|
|
|
|
1,609
|
|
|
|
34,240
|
|
|
|
-
|
|
|
|
128,903
|
|
|
|
|
670,831
|
|
|
|
317,604
|
|
|
|
93,117
|
|
|
|
410,721
|
|
|
|
-
|
|
|
|
1,081,552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
|
|
$
|
322,442
|
|
|
$
|
180,631
|
|
|
$
|
23,381
|
|
|
$
|
204,012
|
|
|
$
|
319
|
|
|
$
|
526,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
106,001
|
|
|
|
|
|
|
|
|
|
|
|
68,842
|
|
|
|
2,172
|
|
|
|
177,015
|
|
Maintenance
|
|
|
37,783
|
|
|
|
|
|
|
|
|
|
|
|
16,595
|
|
|
|
-
|
|
|
|
54,378
|
|
Depreciation
and amortization
|
|
|
74,594
|
|
|
|
|
|
|
|
|
|
|
|
41,317
|
|
|
|
-
|
|
|
|
115,911
|
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
442
|
|
|
|
|
|
|
|
|
|
|
|
11,046
|
|
|
|
(4,999
|
)
|
|
|
6,489
|
|
Other
than income
|
|
|
14,426
|
|
|
|
|
|
|
|
|
|
|
|
10,088
|
|
|
|
105
|
|
|
|
24,619
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
$
|
89,196
|
|
|
|
|
|
|
|
|
|
|
$
|
56,124
|
|
|
$
|
3,041
|
|
|
$
|
148,361
|
|
NOTE
3. REGULATORY
ACTIONS
Pending
Rate Cases
Nevada
Power Company
NPC 2008 Deferred Energy Rate Case and Base Tariff Energy Rate (BTER)
Update
In February 2008, NPC filed
applications to create a new Deferred Energy Accounting Adjustment (DEAA) rate
and to update the going forward BTER. In these applications, NPC
requests to decrease rates by $116.3 million, a decrease of 5.04% while
recovering $36 million of deferred fuel and purchased power
costs. The new DEAA rate will be effective October 1, 2008 and the
going forward BTER became effective April 1, 2008. Hearings on the
DEAA portion are scheduled for August 2008.
In May 2008 NPC filed an update to its
going forward BTER which decreased rates an additional $11.1 million, resulting
in less than a 1% additional decrease. The updated going forward BTER
became effective July 1, 2008.
NPC
Eighth Amendment to 2006 Integrated Resource Plan (IRP)
In
May 2008, NPC filed its eighth amendment to its IRP. Significant
requests in the eighth amendment include:
·
|
Several
approvals related to the Ely Energy Center (“EEC”): first, to delay the
required 2008 EEC Amendment filing to no later than April 2010; second, to
update the budget for the development and permitting of EEC ($155 million
through February 2010); and third, to revise the proposed EEC construction
schedule to accommodate a June 1, 2015 in-service date for Unit 1 and June
1, 2016 in-service date for Unit 2 (implicit in this request is the
continued operation of the Reid Gardner Units 1-3 through
2016).
|
·
|
Approval
to purchase the 598 MW (nominally rated) combined cycle Bighorn Power
Plant from Reliant Energy LLC and Reliant Energy Asset Management LLC for
approximately $510 million including costs for inventory and other closing
costs and adjustments.
|
·
|
Approval
to construct a 500 MW (nominally rated) combined cycle unit at the
existing Harry Allen site with a scheduled commercial operation date of
June 1, 2011. The estimated cost of this project is
approximately $682 million (excluding allowance for funds used during
construction). Additionally, the amendment requests approval to
establish a regulatory asset for the plant and related operations and
maintenance costs, depreciation and return on the plant until such time it
is included in rates.
|
·
|
Approval
of various electric transmission projects at a total estimated cost of
$220 million, the majority of which is the Sunrise 500 kV Tap project with
a scheduled commercial operation date of 2011 and a total estimated cost
of $182 million (not including previously purchased land and land
rights).
|
Hearings
for the eighth amendment will be held in September with a decision expected by
mid-October.
NPC Ninth Amendment to its IRP
In
August 2008, NPC filed its ninth amendment to its’ IRP. In the
amendment NPC seeks approval to establish a regulatory asset for the Carson Lake
Project and related operating and maintenance costs, depreciation and return on
the plant, until such time it is included in general rates.
Sierra
Pacific Power Company
SPPC Nevada Gas DEAA and BTER Update
In December 2007, SPPC filed for
the authority to implement quarterly BTER adjustments for its natural gas and
liquefied propane gas services. The authority was approved in January
2008, and as a result, in
February
2008, SPPC filed applications to create a new DEAA rate and to update the going
forward BTER. In these applications SPPC requests to decrease rates
by $9.9 million, a decrease of 5.53%, while refunding an over collection of
$11.4 million in deferred natural gas and liquid propane costs. The
new DEAA rate will be effective October 1, 2008 and the going forward BTER
became effective April 1, 2008. Hearings for the DEAA portion are
scheduled for August 2008.
In May 2008, SPPC filed an
update to its going forward BTER which decreased rates an additional $5.2
million, resulting in an additional 3% decrease. The updated going
forward BTER became effective July 1, 2008.
SPPC Nevada Electric DEAA and BTER Update
In
February 2008, SPPC filed applications to create a new DEAA rate and to update
the going forward BTER. In these applications SPPC requests to
decrease rates by $42.1 million, a decrease of 4.57%, while refunding an over
collection of $20.9 million in deferred fuel and purchased power
costs. The new DEAA rate will be effective October 1, 2008 and the
going forward BTER became effective April 1, 2008.
In
May 2008 SPPC filed an update to its going forward BTER which decreased rates
less than $500 thousand resulting in a less than 1% additional
decrease. The updated going forward BTER became effective July 1,
2008.
SPPC Nevada Electric Third Amendment to 2007 Integrated Resource Plan
(IRP)
In
May 2008, SPPC filed a third amendment to its IRP. Similar to NPC,
SPPC updated several items related to the EEC, as discussed
above. Hearings on the third amendment will be held in September with
a decision expected by mid-October.
SPPC California General Rate Case
In July 2008, SPPC filed a
general rate case. SPPC requested the following:
·
|
Increase
in general rates of $6.6 million, approximately an 8.1%
increase;
|
·
|
Return
on equity (ROE) and rate of return (ROR) of 11.4% and 8.81%,
respectively;
|
·
|
Authorization
to recover the costs of major plant additions which include the new Tracy
541 MW combined cycle generating plant, distribution plant additions and
an increase to the California Energy Efficiency
Program;
|
·
|
A
two-part mechanism to recover changes in non-energy cost adjustment clause
costs incurred during the two years between rate
cases.
|
If
approved, the new rates would be effective April 1, 2009.
Settled
Rate Cases
SPPC
California Energy Cost Adjustment Clause
In
April 2008, SPPC filed to decrease rates by $12.2 million, a decrease of
15.2%. The California Public Utilities Commission approved the filing
in August 2008. The rates requested in this filing will be effective
September 1, 2008.
NPC Seventh
Amendment to its IRP
In
March 2008, NPC filed its seventh amendment to its IRP. Included in
the amendment are several initiatives, all of which comport with the goal of
providing clean, safe, and reliable electricity to NPC’s customers at reasonable
and predictable prices. However, as a result of the potential
acquisition of the Bighorn Power Plant, announced in April 2008, NPC resubmitted
its seventh amendment to its IRP and filed an eighth amendment in May
2008. Significant requests that remained in the resubmitted seventh
amendment include:
·
|
Approval
to acquire a 50% interest in the Carson Lake Project, providing a minimum
of 30 megawatts (MW) of renewable energy (from a nominal net 24 MW to 40
MW) under the terms of a Joint Operating Agreement with an affiliate of
Ormat Technologies Inc.
|
·
|
Approval
to construct the 6 MW Goodsprings Waste Heat Recovery Project at the
compressor station on the Kern River Gas
Pipeline.
|
·
|
Approval
of an updated load forecast.
|
On
July 30, 2008, the PUCN approved the seventh amendment filing.
SPPC
Second Amendment to its IRP
In
March 2008, SPPC filed its second amendment to its 2007 IRP requesting approval
to modify the schedule and development budget for the EEC in a manner consistent
with the amendment to the NPC IRP described above, approval of a purchase power
agreement, authority to fund CO2 research and approval of a revised load
forecast. However, similar to NPC’s resubmission of its seventh
amendment as discussed above, SPPC also resubmitted a second amendment to its
2007 IRP and filed a third amendment in May 2008. The requests that
remained in the resubmitted second amendment were the approval of a purchase
power agreement, authority to fund CO2 research and approval of a revised load
forecast. The update of the EEC that was originally in the second
amendment was included in the third amendment. On July 30, 2008, the
PUCN approved the second amendment filing.
SPPC Nevada 2007 General Rate Case
In
December 2007, SPPC filed its statutorily required electric general rate case
(GRC). The filing requested a return on equity (ROE) and rate of
return (ROR) of 11.5% and 8.73%, respectively, and an increase to general
revenues of $110.8 million.
The PUCN
issued its order in June 2008, with rates effective July 1, 2008. The
PUCN order resulted in the following significant items:
·
|
Increase
in general rates of $87.1 million, a 10.45%
increase;
|
·
|
Return
on equity (ROE) and rate of return (ROR) of 10.6% and 8.41%,
respectively;
|
·
|
Authorization
to recover the costs of the new Tracy 541 MW combined cycle generating
plant; and
|
·
|
Authorization
to recover the projected operating and maintenance costs associated with
the new Tracy combined cycle generating
plant.
|
NPC Fifth Amendment to 2006 Integrated Resource Plan (IRP)
In December 2007, NPC filed its fifth
amendment to its 2006 IRP requesting approval of three items: 1) a revised
Demand Side Management Plan; 2) a settlement agreement and new long-term power
purchase agreement for approximately 50 MW of summer season capacity; and 3) a
new long-term tolling agreement that will provide 570 MW of unit contingent
summer season capacity. In March 2008, a stipulation between NPC and
the intervening parties was accepted by the PUCN which recommended approval of
the three items, as requested.
SPPC Nevada 2003 General Rate Case
In its 2003 GRC, SPPC sought recovery
of its unreimbursed costs associated with the Piñon Pine Coal Gasification
Demonstration Project (the “Project”). The Project represented
experimental technology tested pursuant to a Department of Energy (DOE) Clean
Coal Technology initiative. Under the terms of the Project agreement, SPPC
and DOE agreed to each fund 50% of construction costs of the Project.
SPPC's participation in the Project had received PUCN approval as part of SPPC’s
1993 integrated electric resource plan. While the conventional portion of
the plant, a gas-fired combined cycle unit, was installed and performed as
planned, the coal gasification unit never became fully operational. After
numerous attempts to re-engineer the coal gasifier, the technology was
determined to be unworkable.
In its order of May 25, 2004, the PUCN
disallowed $43 million of unreimbursed costs associated with the Project.
As a result, these amounts were expensed in 2004. SPPC filed a
Petition for Judicial Review with the Second Judicial District Court of Nevada
(District Court) in June 2004 (CV04-01434). On January 25, 2006, the
District Court vacated the PUCN’s disallowance in SPPC’s 2003 GRC and remanded
the case back to the PUCN for further review as to whether the costs were justly
and reasonably incurred (Order). On March 27, 2006, the PUCN appealed
the Order to the Nevada Supreme Court (the “Supreme Court”) and filed a motion
to stay the Order pending the appeal to the Supreme Court. On June
12, 2006, the District Court granted the PUCN’s motion to stay the
Order. The Supreme Court dismissed the appeal in September
2006. Requests for rehearing were denied in late December 2006, and
on January 18, 2007 the matter was remitted back to the District Court, which,
consistent with its January 25, 2006 order, remanded the matter back to the PUCN
for further review.
On March
18, 2008, the PUCN issued an order to place $5.8 million (Nevada jurisdiction)
of the previously disallowed $43 million unreimbursed costs in a regulatory
asset account without a carrying charge. As a result of this order
and in accordance with SFAS 90, Accounting for Abandonments and Disallowances of
Plant Costs, SPPC recognized approximately $4.3 million in income for the six
months ended June 30, 2008. The remaining difference of $1.5 million
will be recognized over an approximate six year period. The time for
any party to appeal the PUCN’s decision ended in June 2008 and no appeals were
filed.
NOTE
4. LONG-TERM
DEBT
As
of June 30, 2008, NPC’s, SPPC’s and SPR’s aggregate annual amount of maturities
for long-term debt (including obligations related to capital leases) for the
next five years and thereafter are shown below (dollars in
thousands):
|
|
NPC
|
|
|
SPPC
|
|
|
SPR
Holding Co. and Other Subs.
|
|
|
SPR
Consolidated
|
|
2008
|
|
$
|
3,614
|
|
|
$
|
1,062
|
|
|
$
|
-
|
|
|
$
|
4,676
|
|
2009
|
|
|
22,218
|
|
|
|
600
|
|
|
|
-
|
|
|
|
22,818
|
|
2010
|
|
|
148,004
|
|
|
|
178,000
|
|
|
|
-
|
|
|
|
326,004
|
|
2011
|
|
|
369,924
|
|
|
|
-
|
|
|
|
-
|
|
|
|
369,924
|
|
2012
|
|
|
136,448
|
|
|
|
100,000
|
|
|
|
63,670
|
|
|
|
300,118
|
|
|
|
|
680,208
|
|
|
|
279,662
|
|
|
|
63,670
|
|
|
|
1,023,540
|
|
Thereafter
|
|
|
2,005,750
|
|
|
|
973,250
|
|
|
|
460,539
|
|
|
|
3,439,539
|
|
|
|
|
2,685,958
|
|
|
|
1,252,912
|
|
|
|
524,209
|
|
|
|
4,463,079
|
|
Unamortized
Premium(Discount) Amount
|
|
|
(12,393
|
)
|
|
|
10,538
|
|
|
|
855
|
|
|
|
(1,000
|
)
|
Total
|
|
$
|
2,673,565
|
|
|
$
|
1,263,450
|
|
|
$
|
525,064
|
|
|
$
|
4,462,079
|
|
The preceding table includes
obligations related to capital lease obligations discussed under lease
commitments within this note. Substantially all utility plant is
subject to the liens of NPC’s and SPPC’s indentures under which their respective
General and Refunding Mortgage bonds are issued.
Financing
Transactions
Nevada
Power Company
General
and Refunding Mortgage Notes, Series S
On July
31, 2008, NPC issued and sold $500 million of its 6.5% General and Refunding
Mortgage Notes, Series S, due 2018
.
The net proceeds
of the issuance were used to repay $270 million of amounts outstanding under
NPC’s revolving credit facility and for general corporate purposes.
Redemption
Notice
On July 15, 2008, NPC provided a notice
of redemption to the holders of its 9.00% General and Refunding Mortgage Notes,
Series G, for approximately $17.2 million. The notes are scheduled to
be redeemed on August 15, 2008, at 104.50% of the stated principal amount, plus
accrued interest to the date of redemption. NPC intends to use
available cash on hand to redeem these notes.
Conversion
of Coconino County Pollution Control Refunding Revenue Bonds and Clark County
Pollution Control Revenue Bonds
In July 2008, NPC converted the $13
million principal amount Coconino County, Arizona Pollution Control Refunding
Revenue Bonds Series 2006B bonds, due 2039 and the $15 million principal amount
Clark County Nevada Pollution Control Revenue Bonds, Series 2000B due 2009,
collectively (the “Bonds”) from auction rate securities to variable rate demand
notes. The purpose of these conversions was to reduce interest costs
and volatility associated with these bonds. NPC purchased 100% of the
Bonds on that date with proceeds from its revolving credit facility and
available cash, and will remain the sole holder of the Bonds. The
Bonds remain outstanding and have not been retired or
cancelled. However, because NPC is the sole holder of the Bonds, for
financial reporting purposes the investment in the Bonds and the indebtedness
will be offset for presentation purposes.
Sierra
Pacific Power Company
Maturity
of General and Refunding Mortgage Bonds, Series A
On June 2, 2008, the 8.00% General and
Refunding Mortgage Bonds, Series A, in the aggregate principal amount of
approximately $99.2 million, matured. SPPC paid for the maturing debt
plus interest with the use of $90 million from its revolving credit facility
plus cash on hand.
Conversion
of Washoe County Water Facilities Refunding Revenue Bonds
In July
2008, SPPC converted the $40 million principal amount, Washoe County, Nevada
Water Facilities Refunding Revenue Bonds Series 2007B bonds, due 2036 (the
“Water Bonds”) from auction rate securities to variable rate demand
notes. The purpose of the conversion was to reduce the interest rate
on these bonds. SPPC purchased 100% of the Water Bonds on that date,
with proceeds from its revolving credit facility and available cash, and will
remain the sole holder of the Water Bonds. These Water Bonds remain
outstanding and have not been retired or cancelled. However, because
SPPC is the sole holder of the Water Bonds, for financial reporting purposes the
investment in the Water Bonds and the indebtedness will be offset for
presentation purposes.
NOTE
5. DERIVATIVES
AND HEDGING ACTIVITIES
SPR, SPPC
and NPC apply SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (“SFAS 133”), as amended by SFAS 138, SFAS No. 149, SFAS No.
155, and SFAS No. 157. As amended, SFAS 133 establishes accounting
and reporting standards for derivatives instruments, including certain
derivative instruments embedded in other contracts and for hedging
activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position, measure
those instruments at fair value, and recognize changes in the fair value of the
derivative instruments in earnings in the period of change, unless the
derivative meets certain defined conditions and qualifies as an effective
hedge. SFAS 133 also provides a scope exception for contracts that
meet the normal purchase and sales criteria specified in the
standard. The normal purchase and normal sales exception requires,
among other things, physical delivery in quantities expected to be used or sold
over a reasonable period in the normal course of business. Contracts
that are designated as normal purchase and normal sales are accounted for under
deferred energy accounting and not recorded on the Consolidated Balance Sheets
at fair value.
Commodity
Risk
The
energy supply function encompasses the reliable and efficient operation of the
Utilities’ generation, the procurement of all fuels and power and resource
optimization (i.e., physical and economic dispatch) and is exposed to risks
relating to, but not limited to, changes in commodity prices. SPR’s
and the Utilities’ objective in using derivative instruments is to reduce
exposure to energy price risk. Energy price risks result from
activities that include the generation, procurement and sale of power and the
procurement and sale of natural gas. Derivative instruments used to
manage energy price risk from time to time may include: forward contracts, which
involve physical delivery of an energy commodity; over-the-counter options with
financial institutions and other energy companies, which mitigate price risk by
providing the right, but not the requirement, to buy or sell energy related
commodities at a fixed price; and swaps, which require the Utilities to receive
or make payments based on the difference between a specified price and the
actual price of the underlying commodity. These contracts assist the Utilities
to reduce the risks associated with volatile electricity and natural gas
markets.
Adoption
of SFAS 157
Effective
January 1, 2008, SPR and the Utilities adopted SFAS 157, which defines fair
value, establishes a framework for measuring fair value and enhances disclosures
about assets and liabilities recorded at fair value.
SFAS 157
also establishes a three-level hierarchy which requires an entity to maximize
the use of observable inputs and minimize the use of unobservable inputs when
measuring fair value. Derivative instruments used by SPR and the
Utilities to manage energy price risk are valued using quoted exchange prices,
external dealer prices and option pricing models that utilize readily observable
market parameters and are therefore classified within level 2 of the fair value
hierarchy. The three levels are defined as follows:
Level 1 –
Quoted prices in active markets for identical assets or
liabilities. Active markets are those in which transactions for the
asset or liability occur in sufficient frequency and volume to provide pricing
information on an ongoing basis. Level 1 primarily consists of
financial instruments such as exchange-traded derivatives and listed
equities.
Level 2 –
Observable inputs other than Level 1 prices, such as quoted prices for similar
assets or liabilities; quoted prices in markets that are not active; or other
inputs that are observable or can be corroborated by observable market data for
substantially the full term of the assets or liabilities.
Level 3 –
Unobservable inputs that are supported by little or no market activity and that
are significant.
Determination
of Fair Value
As
required by SFAS 157, financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. Risk management assets and liabilities in the
recurring fair value measures table below include over-the-counter forwards,
swaps and options. Forwards and swaps are valued using a market
approach that uses quoted forward commodity prices for similar assets and
liabilities, which incorporates a mid-market pricing convention (the mid-point
price between bid and ask prices) as a practical expedient for valuing its
assets and liabilities measured and reported at fair value. Options
are valued based on an income approach that uses an option pricing model that
includes various inputs; such as forward commodity prices, interest rate yield
curves and option volatility rates. The determination of the fair
value for its derivative instruments not only include counterparty risk, but
also incorporate the impact of SPR and the Utilities nonperformance risk on its
liabilities. Nonperformance risk is based on the credit quality of
SPR and the Utilities and has minimal impact to the fair value of its derivative
instruments.
The
following table shows the fair value of the open derivative positions recorded
on the Consolidated Balance Sheets of SPR, NPC and SPPC and the related
regulatory assets/liabilities that did not meet the normal purchase and normal
sales exception criteria in SFAS 133. Due to deferred energy
accounting treatment under which the Utilities operate, regulatory assets and
liabilities are established to the extent that electricity and natural gas
derivative gains and losses are recoverable or payable through future rates,
once realized. This accounting treatment is intended to defer the
recognition of mark-to-market gains and losses on energy commodity transactions
until the period of settlement and to not recognize gains and losses on the
Consolidated Statements of Income (dollars in millions):
|
|
June
30, 2008
Fair
Value
Level
2
|
|
|
December
31, 2007
Fair
Value
|
|
|
|
SPR
|
|
|
NPC
|
|
|
SPPC
|
|
|
SPR
|
|
|
NPC
|
|
|
SPPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
management assets- current
|
|
$
|
327.8
|
|
|
$
|
221.7
|
|
|
$
|
106.1
|
|
|
$
|
22.3
|
|
|
$
|
16.1
|
|
|
$
|
6.2
|
|
Risk
management assets- noncurrent
|
|
|
58.0
|
|
|
|
43.1
|
|
|
|
14.9
|
|
|
|
12.5
|
|
|
|
9.1
|
|
|
|
3.4
|
|
Total
risk management assets
|
|
|
385.8
|
|
|
|
264.8
|
|
|
|
121.0
|
|
|
|
34.8
|
|
|
|
25.2
|
|
|
|
9.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
management liabilities- current
|
|
|
4.1
|
|
|
|
2.1
|
|
|
|
2.0
|
|
|
|
39.5
|
|
|
|
27.0
|
|
|
|
12.5
|
|
Risk
management liabilities- noncurrent
|
|
|
4.7
|
|
|
|
3.3
|
|
|
|
1.4
|
|
|
|
7.4
|
|
|
|
5.1
|
|
|
|
2.3
|
|
Total
risk management liabilities
|
|
|
8.8
|
|
|
|
5.4
|
|
|
|
3.4
|
|
|
|
46.9
|
|
|
|
32.1
|
|
|
|
14.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
prepaid electric and gas options
|
|
|
23.7
|
|
|
|
19.6
|
|
|
|
4.1
|
|
|
|
13.9
|
|
|
|
10.2
|
|
|
|
3.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
management regulatory assets/liabilities – net
(1)
|
|
$
|
353.3
|
|
|
$
|
239.8
|
|
|
$
|
113.5
|
|
|
$
|
(26.0
|
)
|
|
$
|
(17.1
|
)
|
|
$
|
(8.9
|
)
|
1
When amount is negative it represents a Risk Management Regulatory Asset (loss),
when positive it represents a Risk Management Regulatory Liability
(gain).
As a
result of the nature of operations and the use of mark-to-market accounting for
certain derivatives that do not meet the normal purchase and normal sales
exception criteria in SFAS 133, mark-to-market fair values will
fluctuate. The Utilities cannot predict these fluctuations, but the
primary factors that cause changes in the fair values are the number and size of
the Utilities open derivative positions with its counterparties and the changes
in forward commodity prices. The increase of risk management assets
as of June 30, 2008, as compared to December 31, 2007, is mainly due to
favorable derivative positions on natural gas options held by the Utilities to
hedge energy price risk for their customers resulting from higher commodity
prices for natural gas at June 30, 2008 relative to contract
prices.
NOTE
6. COMMITMENTS
AND CONTINGENCIES
Environmental
Nevada
Power Company
Reid
Gardner Station
Surface
and Groundwater Matters
Reid
Gardner Station is a coal generating station consisting of four
units. NPC is the owner and operator of Unit Nos. 1, 2 and
3. Unit No. 4 is co-owned by the California Department of Water
Resources (CDWR) 67.8% and 32.2% by NPC. NPC is the operating agent
for Unit No. 4.
Reid
Gardner has a number of raw water and scrubber make-up storage ponds as well as
ponds used for process water evaporation and fly ash
settling. Process water, which has been used beyond the treatable
limits, is routed to onsite ponds for evaporation. Waste management
units are present throughout the site and surrounding
area. Environmental contaminants identified at Reid Gardner include
but are not limited to, elevated concentrations of total dissolved solids,
sulfate, chloride, dissolved metals, volatile organic compounds and petroleum
hydrocarbons.
In August
1999, the Nevada Department of Environmental Protection (NDEP) issued a
discharge permit to Reid Gardner Station and an Order that requires all
evaporation and fly ash settling ponds to be closed or lined with impermeable
liners over the next ten years. This order also required NPC to
submit a Site Characterization Plan to NDEP to ascertain
impacts. This plan has been reviewed and approved by
NDEP. In collaboration with NDEP, NPC has evaluated remediation
requirements. In May 2004, NPC submitted a schedule of remediation
actions to NDEP which included proposed dates for corrective action plans and/or
suggested additional assessment plans for each specified area. Any
future ponds will be double-lined with inter-liner leak detection in accordance
with the most recent NDEP Authorization to Discharge Permit issued October
2005.
Pond
construction and lining costs to satisfy the NDEP order expended through June
30, 2008 is approximately $45 million. Additional expenditures
through 2010 are projected to be approximately $2.8 million, for a total
expenditure of approximately $47.8 million.
Over the
last two years, the water division of NDEP has been in discussions with NPC
regarding what additional surface and groundwater remediation may be required at
the site, beyond the scope of the current pond relining project. The
proposed solution was to enter into an Administrative Order on Consent (AOC) and
the final form of the proposed AOC was delivered to NPC in December
2007. Until such time, NPC did not know the extent of the obligation
or scope of work that would be required to effect site restoration due to the
complexities associated with environmental remediation of the target media and
the evolving standards of acceptable remediation standards. As a
result, management was unable to reasonably estimate the cost of this
comprehensive remediation project prior to concluding the negotiations and
receiving the final AOC from the NDEP.
In
February 2008, NPC signed the AOC as owner and operator of Unit Nos. 1, 2 and 3
and as co-owner and operating agent of Unit No. 4. The AOC has been
designed to supersede previous Orders and takes a comprehensive approach to
address historical environmental impacts associated with facility
operations. Upon receiving the final document in December 2007,
management was able to estimate a range of costs to satisfy the requirements of
the AOC. As a result, NPC has recorded an asset retirement obligation
of approximately $20 million, which it expects to receive regulatory recovery
of, similar to the PUCN’s treatment of other asset retirement
obligations. Other costs associated with the AOC are expected to
include capital expenditures and remediation costs of approximately $32.3
million in addition to operating and maintenance expense of approximately $1.3
million. However, these estimates may vary significantly once the
scope of work is initiated and additional characterization has been
completed.
NEICO
NEICO, a
wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the
site of a coal washing and load-out facility. The site has a
reclamation estimate supported by a bond of approximately $5 million with the
Utah Division of Oil and Gas Mining, which management believes is sufficient to
cover reclamation costs. Management is continuing to evaluate various
options including reclamation or sale of the property.
Litigation Contingencies
Nevada
Power Company
Peabody
Western Coal Company
NPC owns an 11% interest in the Navajo
Generating Station (Navajo Station) which is located in Northern Arizona and is
operated by the Salt River Project (Salt River). Other participants
in the Navajo Station are Arizona Public Service Company, Los Angeles Department
of Water and Power and Tucson Electric Power Company (together with Salt River
and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in
the Mohave Generating Station (Mohave Station) which is located in Laughlin,
Nevada and was operated by Southern California Edison (SCE) prior to the time it
became non-operational on December 31, 2005.
Royalty Claim
On
October 15, 2004, Navajo Station’s coal supplier, Peabody Western Coal Co.
(Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri
State Court in St. Louis, alleging, among other things, a declaration that the
Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax
or other obligations arising out of a lawsuit that the Navajo Nation filed
against Salt River, several Peabody Coal Company entities (including Peabody WC
and collectively referred to as “Peabody”) and SCE in June 1999 in the U.S.
District Court for the District of Columbia (DC Lawsuit).
As
discussed in more detail in the 2007 Form 10-K, the Navajo Joint owners were
first served in the Missouri lawsuit in January 2005. In July 2008, the
Court dismissed the three counts against NPC, two without prejudice to their
possible refilling at a later date. NPC is unable to predict whether any
liability may arise from any of these matters, including from the ultimate
outcome of the DC Lawsuit.
NPC is
not a party to the DC Lawsuit although, as noted above, it is a participant in
both the Navajo Station and the Mohave Station. The DC Lawsuit
consists of various claims relating to the renegotiations of coal royalty and
lease agreements and alleges, among other things, that the defendants obtained a
favorable coal royalty rate for the lease agreements under which Peabody mines
coal for both Navajo Station and the Mohave Station by improperly influencing
the outcome of a federal administrative process pursuant to which the royalty
rate was to be adjusted. The DC Lawsuit seeks $600 million in
damages, treble damages, and punitive damages of not less than $1 billion, and
the ejection of defendants from all possessory interests and Navajo Tribal lands
arising out of the primary coal lease. In July 2001, the U.S.
District Court dismissed all claims against Salt River. The action
had been stayed since October 5, 2004. In March, 2008, the US
District Court lifted the stay and referred pending discovery related motions to
a Magistrate judge.
Retiree
Health Care and Reclamation Claims
In
addition to the above action before the Missouri State Court, Peabody further
asserted in 1994 that the Navajo Joint Owners are liable under the Coal Supply
Agreement (CSA) for Retiree Health Care Costs (RHCC) and Final Reclamation Costs
(FRC), which Peabody WC is obligated to pay after the CSA expires and the
Kayenta Mine closes. In 1996, Salt River and the Navajo Joint Owners
filed a complaint in the Maricopa County (Arizona) Supreme Court seeking
determinations that they are not liable for RHCC or FRC or, alternatively, that
Peabody WC cannot recover RHCC and FRC until after the CSA ends. The
case was dormant for several years, while Peabody WC pursued other RHCC and FRC
claims arising out of similar coal contracts. Settlement discussions,
led by Salt River on both the RHCC matter and the FRC claim reached final
approvals with Peabody WC and the Navajo Joint Owners in July 2008
(Settlement
Agreement and Mutual Release with Peabody). As of June 30, 2008, NPC
has a $17.4 million liability recorded which management has assessed as the
approximate amount to be paid, and recorded a corresponding other regulatory
asset for such claims, as management believes that these costs are recoverable
through deferred energy.
Nevada
Power Company and Sierra Pacific Power Company
Calpine
Settlement
On September 19, 2007, NPC, SPPC and
Calpine Corporation (“Calpine”) entered into a settlement agreement (the
“Settlement Agreement”) that resolved the issues and claims pertaining to three
proofs of claim (Claim Nos. 5177, 5178 and 5179) filed by the Utilities against
Calpine in Calpine’s bankruptcy proceeding. The Settlement Agreement
was approved by the United States Bankruptcy Court for the Southern District of
New York on October 10, 2007, and by the Federal Energy Regulatory Commission
(“FERC”) on December 28, 2007, in orders that are final and
non-appealable.
Claim Nos. 5177 and 5179 filed by SPPC
and NPC relate to complaints filed with FERC in December 2001 under
Section 206 of the Federal Power Act seeking price reduction of forward
wholesale power purchase contracts entered into prior to the FERC mandated price
caps imposed in reaction to the Western United States energy
crisis. The Settlement Agreement provided that, for Claim Nos. 5177
and 5179, SPPC and NPC would receive general unsecured claims in the Calpine
bankruptcy proceeding of approximately $1.7 million and $1.3 million
respectively, totaling $3 million. In February 2008, Calpine
distributed shares of Calpine common stock to SPPC and NPC with respect to Claim
Nos. 5177 and 5179, at the approximate value at the time of the distribution of
approximately $1.3 million, and $1.1 million, respectively. The
Utilities recognized these amounts as income for the six months ended June 30,
2008.
Claim No. 5178 filed by NPC regarding
Calpine’s alleged breach of a 400 MW transmission service agreement (“TSA”) and
a 2002 settlement agreement approved by the FERC. The Settlement
Agreement provided that the claim shall be amended to reflect a general
unsecured claim of $18 million against Calpine. NPC agreed to treat
the distribution in respect to Claim No. 5178 as a prepayment for a new 400 MW
TSA (“New TSA”) with a term commencing January 1, 2008 and ending approximately
March 31, 2010, assuming no change in NPC’s open access transmission tariff
(“OATT”) service schedules and, in the event of any such changes, ending on the
date the $18 million is depleted based on the applicable OATT service rate
schedule. In February 2008, Calpine distributed shares of Calpine
common stock to NPC having an approximate value at that time of $14.4 million,
which will be recognized as transmission revenue over the term of the new
TSA.
The
distributions discussed above represent approximately 80% of the balance owed to
NPC and SPPC under the three proofs of claims filed. Management
cannot predict if the remaining 20% will be recovered due to the status of
Calpine’s bankruptcy proceedings, and as such has not recorded any further
amounts as income. Subsequent to the distribution, NPC and SPPC sold
all of their shares of Calpine common stock and recorded a gain of $1.8 million
for the six months ended June 30, 2008.
Sierra
Pacific Power Company
Farad
Dam
SPPC owns four hydro generating plants
(10.3 MW capacity) located in California that were to be included in the sale of
SPPC’s water business for $8 million to the Truckee Meadows Water Authority
(TMWA) in June 2001. The contract with TMWA requires that SPPC
transfer the hydro assets in working condition. However, one of the
four hydro generating plants, Farad 2.8 MW, has been out of service since the
summer of 1996 due to a collapsed flume. While planning the
reconstruction, a flood on the Truckee River in January 1997 destroyed the
diversion dam. The current estimate to rebuild the diversion dam, if
management decides to proceed, is approximately $20 million.
SPPC
filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance
Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the
flume and dam. In December 2003, SPPC sued the Insurers in the U.S.
District Court for the District of Nevada on a coverage dispute relating to
potential rebuild costs. In May 2005, Insurers filed a motion for
summary judgment on the coverage issue, which has been denied. In
October 2005, Insurers filed another partial summary judgment motion with
respect to coverage, which the court also denied. On June 16, 2006,
Insurers filed new summary judgment motions, which SPPC opposed. The
Court denied the motions and asked parties to brief the Court on certain
insurance coverage issues involving timing and cost recovery associated with
rebuilding the dam. The case went to trial in April
2008. NPC filed post-trial briefs in May 2008 and a decision is
expected in the summer of 2008. Management has not recorded a loss
contingency for this matter, because the loss, if any, cannot be estimated at
this time
.
Regulatory
Contingencies
The
Utilities have begun various construction projects and entered into related
construction contracts for which PUCN approval has not been previously
obtained. While management believes the costs to be prudent and
necessary to meet future electricity demand, in the event all or a portion of
these project costs were disallowed by the PUCN, the Utilities may be required
to evaluate these assets for impairment which could have a material effect on
the future financial position, results of operations and cash flows of SPR, NPC
and SPPC.
Other
Legal Matters
SPR and its subsidiaries, through the
course of their normal business operations, are currently involved in a number
of other legal actions, none of which, in the opinion of management, is expected
to have a significant impact on their financial positions, results of operations
or cash flows.
NOTE
7. EARNINGS
PER SHARE (EPS) (SPR)
The difference, if any, between
basic EPS and diluted EPS is due to potentially dilutive common shares resulting
from stock options, the employee stock purchase plan, performance and restricted
stock plans, and the non-employee director stock plan.
The
following table outlines the calculation for earnings per share
(EPS):
|
|
Three
months ended June 30,
|
|
|
Six
months ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Basic
EPS
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator
($000)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income applicable to common stock
|
|
$
|
36,134
|
|
|
$
|
25,754
|
|
|
$
|
60,192
|
|
|
$
|
41,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of common shares outstanding
|
|
|
233,992,721
|
|
|
|
221,412,345
|
|
|
|
233,914,046
|
|
|
|
221,329,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income applicable to common stock
|
|
$
|
0.15
|
|
|
$
|
0.12
|
|
|
$
|
0.26
|
|
|
$
|
0.19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
EPS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator
($000)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income applicable to common stock
|
|
$
|
36,134
|
|
|
$
|
25,754
|
|
|
$
|
60,192
|
|
|
$
|
41,361
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares outstanding before dilution
|
|
|
233,992,721
|
|
|
|
221,412,345
|
|
|
|
233,914,046
|
|
|
|
221,329,347
|
|
Stock
options
|
|
|
57,533
|
|
|
|
146,350
|
|
|
|
59,142
|
|
|
|
149,103
|
|
Non-Employee
Director stock plan
|
|
|
56,987
|
|
|
|
44,613
|
|
|
|
56,650
|
|
|
|
42,639
|
|
Employee
stock purchase plan
|
|
|
871
|
|
|
|
4,471
|
|
|
|
436
|
|
|
|
3,807
|
|
Restricted
Shares
|
|
|
5,247
|
|
|
|
-
|
|
|
|
3,279
|
|
|
|
-
|
|
Performance
Shares
|
|
|
406,203
|
|
|
|
213,416
|
|
|
|
386,783
|
|
|
|
213,416
|
|
|
|
|
234,519,562
|
|
|
|
221,821,195
|
|
|
|
234,420,336
|
|
|
|
221,738,312
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income applicable to common stock
|
|
$
|
0.15
|
|
|
$
|
0.12
|
|
|
$
|
0.26
|
|
|
$
|
0.19
|
|
(1)
|
The
denominator does not include stock equivalents resulting from the options
issued under the nonqualified stock option plan for the three and six
months ended June 30, 2008 and 2007, due to conversion prices being higher
than market prices for all periods. Under the nonqualified
stock option plan for the three and six months ended June 30, 2008,
972,761 and 941,278 shares, respectively, would be included and 581,074
and 727,949 shares, respectively, would be included for the three and six
months ended June 30, 2007.
|
NOTE
8.
PENSION AND OTHER POSTRETIREMENT
BENEFITS
A summary of the components of net
periodic pension and other postretirement costs for the three and six months
ended June 30 follows. This summary is based on a September 30
measurement date (dollars in thousands):
Sierra
Pacific Resources, consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
5,247
|
|
|
$
|
5,725
|
|
|
$
|
716
|
|
|
$
|
768
|
|
Interest
cost
|
|
|
10,675
|
|
|
|
9,855
|
|
|
|
3,148
|
|
|
|
2,570
|
|
Expected
return on plan assets
|
|
|
(11,463
|
)
|
|
|
(10,474
|
)
|
|
|
(2,144
|
)
|
|
|
(1,309
|
)
|
Amortization
of prior service cost
|
|
|
(118
|
)
|
|
|
407
|
|
|
|
234
|
|
|
|
30
|
|
Amortization
of net (gain)/loss
|
|
|
1,981
|
|
|
|
1,803
|
|
|
|
855
|
|
|
|
242
|
|
Amortization
of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
periodic benefit cost
|
|
$
|
6,322
|
|
|
$
|
7,316
|
|
|
$
|
2,809
|
|
|
$
|
3,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
11,270
|
|
|
$
|
11,450
|
|
|
$
|
1,281
|
|
|
$
|
1,536
|
|
Interest
cost
|
|
|
21,465
|
|
|
|
19,710
|
|
|
|
5,366
|
|
|
|
5,140
|
|
Expected
return on plan assets
|
|
|
(24,124
|
)
|
|
|
(20,948
|
)
|
|
|
(4,175
|
)
|
|
|
(2,618
|
)
|
Amortization
of prior service cost
|
|
|
290
|
|
|
|
814
|
|
|
|
(514
|
)
|
|
|
61
|
|
Amortization
of net (gain)/loss
|
|
|
2,752
|
|
|
|
3,606
|
|
|
|
1,744
|
|
|
|
484
|
|
Amortization
of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
periodic benefit cost
|
|
$
|
11,653
|
|
|
$
|
14,632
|
|
|
$
|
3,702
|
|
|
$
|
6,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nevada
Power Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
3,062
|
|
|
$
|
3,273
|
|
|
$
|
313
|
|
|
$
|
244
|
|
Interest
cost
|
|
|
5,257
|
|
|
|
4,744
|
|
|
|
707
|
|
|
|
510
|
|
Expected
return on plan assets
|
|
|
(5,496
|
)
|
|
|
(4,750
|
)
|
|
|
(671
|
)
|
|
|
(291
|
)
|
Amortization
of prior service cost
|
|
|
1
|
|
|
|
358
|
|
|
|
399
|
|
|
|
29
|
|
Amortization
of net (gain)/loss
|
|
|
981
|
|
|
|
857
|
|
|
|
186
|
|
|
|
160
|
|
Amortization
of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
periodic benefit cost
|
|
$
|
3,805
|
|
|
$
|
4,482
|
|
|
$
|
934
|
|
|
$
|
879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
6,612
|
|
|
$
|
6,546
|
|
|
$
|
608
|
|
|
$
|
519
|
|
Interest
cost
|
|
|
10,610
|
|
|
|
9,488
|
|
|
|
1,262
|
|
|
|
1,085
|
|
Expected
return on plan assets
|
|
|
(11,562
|
)
|
|
|
(9,500
|
)
|
|
|
(1,351
|
)
|
|
|
(619
|
)
|
Amortization
of prior service cost
|
|
|
363
|
|
|
|
715
|
|
|
|
579
|
|
|
|
61
|
|
Amortization
of net (gain)/loss
|
|
|
1,357
|
|
|
|
1,715
|
|
|
|
404
|
|
|
|
341
|
|
Amortization
of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
periodic benefit cost
|
|
$
|
7,380
|
|
|
$
|
8,964
|
|
|
$
|
1,502
|
|
|
$
|
1,871
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sierra
Pacific Power Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Three Months Ended June 30,
|
|
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
1,939
|
|
|
$
|
2,138
|
|
|
$
|
384
|
|
|
$
|
452
|
|
Interest
cost
|
|
|
5,063
|
|
|
|
4,775
|
|
|
|
2,401
|
|
|
|
1,839
|
|
Expected
return on plan assets
|
|
|
(5,668
|
)
|
|
|
(5,492
|
)
|
|
|
(1,438
|
)
|
|
|
(886
|
)
|
Amortization
of prior service cost
|
|
|
(64
|
)
|
|
|
53
|
|
|
|
(169
|
)
|
|
|
-
|
|
Amortization
of net (gain)/loss
|
|
|
920
|
|
|
|
867
|
|
|
|
659
|
|
|
|
585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
periodic benefit cost
|
|
$
|
2,190
|
|
|
$
|
2,341
|
|
|
$
|
1,837
|
|
|
$
|
1,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For
the Six Months Ended June 30,
|
|
|
|
Pension
Benefits
|
|
|
Other
Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
4,117
|
|
|
$
|
4,276
|
|
|
$
|
638
|
|
|
$
|
987
|
|
Interest
cost
|
|
|
10,149
|
|
|
|
9,550
|
|
|
|
4,027
|
|
|
|
4,021
|
|
Expected
return on plan assets
|
|
|
(11,933
|
)
|
|
|
(10,984
|
)
|
|
|
(2,756
|
)
|
|
|
(1,937
|
)
|
Amortization
of prior service cost
|
|
|
(12
|
)
|
|
|
106
|
|
|
|
(1,101
|
)
|
|
|
-
|
|
Amortization
of net (gain)/loss
|
|
|
1,256
|
|
|
|
1,734
|
|
|
|
1,317
|
|
|
|
1,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
periodic benefit cost
|
|
$
|
3,577
|
|
|
$
|
4,682
|
|
|
$
|
2,125
|
|
|
$
|
4,349
|
|
SFAS 158
“Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans,” (SFAS 158) requires companies to eliminate the early measurement date
and to measure their Defined Benefit Pension and Other Postretirement Plans
consistent with their fiscal year end. SFAS 158 provided a transition
alternative to the elimination of the early measurement date by allowing earlier
measurements determined for year end reporting of the fiscal year immediately
preceding the year that the measurement date provisions are applied to be used
to calculate the additional expense. As such and in accordance with
SFAS 158, SPR, NPC and SPPC recorded additional pension and other postretirement
benefits costs relating to the elimination of the early measurement date to
beginning retained earnings of $5.3 million and $1.0 million, $3.6 million and
$0.6 million; and $1.4 million and $0.4 million, respectively, before taxes
attributable to the three-month period from September 30, 2007 to December 31,
2007.
In
November 2007, the Board of Directors approved a change in the defined benefit
pension plan for SPR’s management, professional, administrative, and technical
employees, from a final average pay formula to a cash balance
formula. Employees with combined age and service totaling 75 years or
more, have the choice of staying with the current plan or electing to switch to
the new plan, which went into effect on April 1, 2008. Although these
changes resulted in cost savings, the recent downturn in the equity and debt
markets have caused a reduction in the asset values of the pension trust
resulting in higher costs and liability values when the plan was re-measured in
April 2008.
As a
result of the changes noted above, accrued retirement
benefit obligations increased from December 31, 2007 for changes
in the asset values of the pension trust and revisions to Other Post-Employment
Benefits ("OPEB") estimates, offset by a decrease in the obligation for changes
in plan design associated with the cash balance formula. The net increase
to accrued retirement obligations at June 30, 2008, was $57.8 million, $19.5
million and $34.8 million for SPR, NPC, and SPPC, respectively, with an offset
to the Regulatory Asset for Pension Plans. Additionally, included in
the net periodic benefit costs above for Pension Benefits are $990 thousand,
$231 thousand and $803 thousand for SPR, NPC and SPPC, respectively, and for
Other Postretirement Benefits $1.9 million, $367 thousand and $1.6 million for
SPR, NPC and SPPC, respectively, as a result of the changes noted
above.
As
previously disclosed in Note 11, Retirement Plan and Post-retirement Benefits,
in the 2007 Form 10-K, expected contributions for 2008 are $1.9 million for the
pension plan and $0.4 million for other postretirement
benefits. Management will continue to re-assess the amounts to be
funded for each of the plans in 2008, after final funding rules are adopted by
the Internal Revenue Service.
NOTE
9. DIVIDENDS
On February 7, 2008, SPR’s Board of
Directors declared a quarterly cash dividend of $0.08 per share which was paid
on March 12, 2008, to common shareholders of record on February 22,
2008. On April 28, 2008, SPR’s Board of Directors declared a
quarterly cash dividend of $0.08 per share, to common shareholders of record on
May 23, 2008 which was paid on June 11, 2008. On August 4
,
2008 SPR’s Board of
Directors declared a quarterly cash dividend of $0.08 per share to common
shareholders of record on August 22, 2008, payable on September 10,
2008.
Forward-Looking
Statements and Risk Factors
The
information in this Form 10-Q includes forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of
1995. These forward-looking statements relate to anticipated
financial performance, management’s plans and objectives for future operations,
business prospects, outcome of regulatory proceedings, market conditions and
other matters.
Words
such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and
“objective” and other similar expressions identify those statements that are
forward-looking. These statements are based on management’s beliefs
and assumptions and on information currently available to
management. Actual results could differ materially from those
contemplated by the forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
statements, factors that could cause the actual results of Sierra Pacific
Resources (SPR), Nevada Power Company (NPC), or Sierra Pacific Power Company
(SPPC) to differ materially from those contemplated in any forward-looking
statement include, among others, the following:
(1)
|
economic
conditions both nationwide and regionally, particularly in Southern
Nevada, including inflation rates, monetary policy, customer bankruptcies,
weaker housing markets and a decrease in tourism could affect customer
collections, customer demand and usage
patterns;
|
(2)
|
changes
in the rate of industrial, commercial and residential growth in the
service territories of the Utilities, including the effect of weaker
housing markets, could affect the Utilities' ability to accurately
forecast electric and gas demand;
|
(3)
|
the
ability and terms upon which SPR, NPC and SPPC will be able to access the
capital markets to support their requirements for working capital,
including amounts necessary for construction and acquisition costs and
other capital expenditures, as well as to finance deferred energy costs,
particularly in the event of unfavorable rulings by the Public Utilities
Commission of Nevada (PUCN), untimely regulatory approval for such
financings, and/or a downgrade of the current debt ratings of SPR, NPC, or
SPPC;
|
(4)
|
financial
market conditions, including the effect of recent volatility in financial
and credit markets, changes in availability of capital, or interest rate
fluctuations resulting from, among other things, the credit quality of
bond insurers that guarantee certain series of the Utilities’ auction rate
tax-exempt securities;
|
(5)
|
unseasonable
weather, drought and other natural phenomena, which could affect the
Utilities’ customers’ demand for power, could seriously impact the
Utilities’ ability to procure adequate supplies of fuel or purchased power
and the cost of procuring such supplies, and could affect the amount of
water available for electric generating plants in the Southwestern United
States;
|
(6)
|
whether
the Utilities will be able to continue to obtain fuel and power from their
suppliers on favorable payment terms and favorable prices, particularly in
the event of unanticipated power demands (for example, due to unseasonably
hot weather), sharp increases in the prices for fuel (including increases
in the price of coal and in the long term transportation costs for natural
gas) and/or power, or a ratings
downgrade;
|
(7)
|
changes
in environmental laws or regulations, including the imposition of limits
on emissions of carbon dioxide from electric generating facilities, which
could significantly affect our existing operations as well as our
construction program, especially the proposed Ely Energy
Center;
|
(8)
|
construction
risks, such as delays in permitting, changes in environmental laws,
difficulty in securing adequate skilled labor, cost and availability of
materials and equipment (including escalating costs for materials, labor
and environmental compliance due to timing delays and other economic
factors), equipment failure, work accidents, fire or explosions, business
interruptions, possible cost overruns, delay of in-service dates, and
pollution and environmental damage;
|
(9)
|
whether
the Utilities can procure sufficient renewable energy sources in each
compliance year to satisfy the Nevada Portfolio
Standard;
|
(10)
|
unfavorable
or untimely rulings in rate cases filed or to be filed by the Utilities
with the PUCN, including the periodic applications to recover costs for
fuel and purchased power that have been recorded by the Utilities in their
deferred energy accounts, and deferred natural gas costs recorded by SPPC
for its gas distribution business;
|
(11)
|
wholesale
market conditions, including availability of power on the spot market,
which affect the prices the Utilities have to pay for power as well as the
prices at which the Utilities can sell any excess
power;
|
(12)
|
employee
workforce factors, including changes in and renewals of collective
bargaining unit agreements, strikes or work
stoppages;
|
(13)
|
the
effect that any future terrorist attacks, wars, threats of war or
epidemics may have on the tourism and gaming industries in Nevada,
particularly in Las Vegas, as well as on the economy in
general;
|
(14)
|
changes
in tax or accounting matters or other laws and regulations to which SPR or
the Utilities are subject;
|
(15)
|
the
effect of existing or future Nevada, California or federal legislation or
regulations affecting electric industry restructuring, including laws or
regulations which could allow additional customers to choose new
electricity suppliers or change the conditions under which they may do
so;
|
(16)
|
changes
in the business or power demands of the Utilities’ major customers,
including those engaged in gold mining or gaming, which may result in
changes in the demand for services of the Utilities, including the effect
on the Nevada gaming industry of the opening of additional Indian gaming
establishments in California and other states;
and
|
(17)
|
unusual
or unanticipated changes in normal business operations, including unusual
maintenance or repairs.
|
Other
factors and assumptions not identified above may also have been involved in
deriving these forward-looking statements, and the failure of those other
assumptions to be realized, as well as other factors, may also cause actual
results to differ materially from those projected. SPR, NPC and SPPC
assume no obligation to update forward-looking statements to reflect actual
results, changes in assumptions or changes in other factors affecting
forward-looking statements.
EXECUTIVE
OVERVIEW
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
explains the general financial condition and the results of operations of Sierra
Pacific Resources (SPR) and its two primary subsidiaries, Nevada Power Company
(NPC) and Sierra Pacific Power Company (SPPC), collectively referred to as the
“Utilities” (references to “we,” “us” and “our” refer to SPR (holding company)
and the Utilities collectively), and includes the following:
|
•
|
Liquidity
and Capital Resources
|
|
• Energy
Supply (Utilities)
|
|
•
Regulatory Proceedings (Utilities)
|
SPR’s
Utilities operate three regulated business segments which are NPC electric, SPPC
electric and SPPC natural gas. The Utilities are public utilities
engaged in the generation, transmission, distribution and sale of electricity
and, in the case of SPPC, sale of natural gas. Other segment
operations consist mainly of unregulated operations and the holding company
operations. The Utilities are the principal operating subsidiaries of
SPR and account for substantially all of SPR’s assets and
revenues. SPR, NPC and SPPC are separate filers for SEC reporting
purposes and as such this discussion has been divided to reflect the individual
filers (SPR, NPC and SPPC), except for discussions that relate to all three
entities or the Utilities.
For the
three months ended June 30, 2008, SPR recognized net income applicable to common
stock of $36.1 million compared to $25.8 million for the same period in
2007. For the six months ended June 30, 2008, SPR recognized net
income applicable to common stock of $60.2 million compared to $41.4 million for
the same period in 2007. See SPR’s, NPC’s and SPPC’s respective
Results of Operations
for
more details on the increase in earnings.
The
Utilities’ revenues and operating income are subject to fluctuations during the
year due to impacts that seasonal weather, rate changes, and customer usage
patterns have on demand for electric energy and resources. NPC is a
summer peaking utility experiencing its highest retail energy sales in response
to the demand for air conditioning. SPPC’s electric system peak
typically occurs in the summer, while its gas business typically peaks in the
winter. The variations in energy usage by the Utilities’ customers
due to varying weather and other energy usage patterns necessitate a continual
balancing of loads and resources and purchases and sales of energy under short
and long term contracts. As a result, the prudent management and
optimization of available resources has a direct effect on the operating and
financial performance of the Utilities. Additionally, the recovery of
purchased power and fuel costs, and other costs, on a timely basis, and the
ability to earn a fair return on investments are essential to the operating and
financial performance of the Utilities.
2008
and Beyond Outlook
In
Southern Nevada, population growth continues, however at a much slower pace than
in prior years. As a result, Southern Nevada has experienced
decreased activity in the real estate and tourism
markets. Additionally on August 1, 2008, Boyd Gaming announced the
delay of the partially built Echelon Project, a $4.8 billion, 5,000 room, hotel
and casino in Las Vegas, which was scheduled to open in
2010. According to its press release, Boyd Gaming plans to resume
construction in three or four quarters, assuming credit market conditions and
the economic outlook improves. However, due to the current economic
conditions in Las Vegas, management is focusing on our assessments, strategies
and projections for factors such as growth, load forecasts, capital
expenditures, rising fuel costs, access to capital markets, collections on
accounts receivable and counterparty risk among other factors.
In the
Western and Southwestern portions of the United States, energy needs continue to
increase; however, the development of generating facilities by utility companies
has decreased. As a result, the cost of energy and natural gas
continues to rise with increased demand and the decline in the ability to meet
those demands. The economics of this situation coupled with
variations in weather, the capabilities and limits on the Utilities, owned
generating facilities, transmission constraints, regulations, and changes and
potential changes in environmental laws are significant business issues for the
Utilities. As a result, the Utilities’ strategies, as evidenced by
their most recent amendments to their Integrated Resource Plans (IRP), are aimed
at reducing dependence on purchased power by the use of energy efficiency and
conservation programs and diversifying fuel mix, including renewable energy and
owning more generating facilities.
2008
Key Objectives
·
|
Management
of Energy Resources
|
o
|
Energy
Efficiency and Conservation
Programs
|
o
|
Purchase
and Development of Renewable Energy
Projects
|
o
|
Construction
of Generating Facilities
|
o
|
Management
of Energy Risk, including fuel and purchased power
costs
|
·
|
Management
of Environmental Matters
|
·
|
Management
of Regulatory Filings
|
·
|
Further
Broaden Access to Capital
|
Management
of Energy Resources
Energy Management encompasses energy
efficiency and conservation programs, diversification of fuel mix, optimization
of generation assets, management of energy risk which includes the purchase of
short term and long term supply contracts, transmission, storage, reliability
and efficiency, and regulatory and legal considerations. The ability
to balance and optimize these functions is a significant business challenge that
we face.
Energy
Efficiency and Conservation Programs
A part of our strategy to reduce
dependence on purchased power is to manage our resources against our load
requirements with energy efficiency and conservation programs. As
such, the Utilities’ have committed to spending approximately $135 million over
the next three years towards increasing efficiency and qualified conservation
programs. NPC and SPPC have received PUCN approval of approximately
$110.5 million and $29.8 million, respectively for the years 2008-2010, which
will be deferred as a regulatory asset subject to prudency review by the
PUCN. The PUCN approval of the demand-side management (“DSM”) budget
increase was a key step in expanding the energy savings yield from the DSM
programs.
NPC and SPPC have designed a portfolio
of cost effective DSM programs that allow every customer to take advantage of
savings from energy efficiency measures. DSM programs are marketed
across all segments of customer classes (residential, commercial, public, and
low income). After the DSM percentage allowance, as described below,
is fully utilized, NPC’s and SPPC’s strategy is to continue to implement
cost-effective DSM programs.
Furthermore,
the Portfolio Standard, discussed below, allows energy efficiency measures from
qualified conservation programs to meet up to 25% of the Portfolio
Standard. A portfolio energy credit is created for each kWh of energy
conserved by qualified energy efficiency programs. Energy saved
during peak demand hours earns double the portfolio energy
credits. In April 2008, the Utilities filed their Portfolio Standard
Annual Report for Compliance Year 2007 (the “Portfolio Report”). In
the Portfolio Report, the Utilities reported that through energy efficiency
measures they achieved 60% of the allowable 25% that may be used to meet the
Portfolio Standard. In addition, NPC reported that it is in a
position to achieve the maximum 25% in 2008.
Purchase and Development of
Renewable Energy Projects
The
Utilities have embarked on a strategy to invest in renewable energy that, along
with purchased power contracts and an increase in DSM programs, will enhance the
opportunity for the Utilities to fully meet the renewable energy portfolio
standard (Portfolio Standard) as required by Nevada law. The
Utilities' compliance with the Portfolio Standard is dependent on the
availability of renewable energy resources. NPC’s current capital
budget includes investing approximately $457 million for renewable energy
projects through 2012.
Nevada
law sets forth the Portfolio Standard, requiring providers of electric service
to acquire, generate, or save a specific percentage of its total retail energy
sales from renewable energy resources (Renewables). Renewables
include biomass, geothermal, solar, waterpower and wind projects. In
2008, the Utilities are required to obtain 9% of their total energy from
Renewables. The Portfolio Standard increases by 3% every other year
until it reaches 20% in 2015. Moreover, not less than 5% of the total
Portfolio Standard must be met from solar resources.
Nevada
law requires providers of electric services to file an annual report that
describes the level of compliance with the Portfolio Standard. In the
Utilities’ April 2008 Portfolio Standard Annual Report for Compliance Year 2007
(submitted to the PUCN jointly), NPC reported that with PUCN approval of a sale
and purchase of SPPC’s excess non-solar portfolio credits (PCs), NPC met the
non-solar Portfolio Standard. SPPC reported compliance with the
non-solar component of the Portfolio Standard. However, due to the
late commercial operation of planned solar facilities, the Utilities did not
meet the solar portion of the Portfolio Standard. Additionally, the
report described the Utilities ongoing activities to reach full compliance with
the Portfolio Standard in the near future.
In May
2008, NPC re-filed its 7th amendment to its 2007-2026 Integrated Resource Plan
with the PUCN (“2006 Resource Plan”). Included in the amendment are
renewable energy requests which seek approvals to acquire a 50% interest in a
minimum 30 MW geothermal project (“Carson Lake Project”) and to construct a 6 MW
Goodsprings Waste Heat Recovery Project at the compressor station on the Kern
River Pipeline. In July 2008, the PUCN approved the 7th
amendment. Both projects are scheduled for commercial operation in late
2010, if approval is obtained from the PUCN. In August 2008, NPC
filed its ninth amendment to its IRP. In the amendment NPC seeks
approval to establish a regulatory asset for the Carson Lake Project and related
operating and maintenance costs, depreciation and return on the plant, until
such time it is included in general rates.
Construction
of Generating Facilities
Ely
Energy Center
As
discussed in more detail in the 2007 Form 10-K, included in the Utilities’ IRP
and various amendments is the construction of the Ely Energy Center that
consists of two 750 MW coal generation units to be located near Ely, Nevada and
a 250-mile 500 kilovolt (kV) transmission line that would deliver electricity
from the Ely Energy Center and from any possible future renewable resource
projects in the area, as well as link NPC’s and SPPC’s transmission systems in
the southern and northern portions of the state. In May 2008, the
Utilities filed amendments to their IRP’s. Among other items, the
Utilities requested permission to file the required IRP amendment regarding
final approval of the Ely Energy Center in April 2010, after the issuance of
required permits and bids for equipment and engineering, procurement and
construction costs are obtained. This request would give the
Utilities a better opportunity to evaluate the feasibility of the Ely Energy
Center for factors such as, but not limited to, the effects of construction
costs, carbon dioxide and climate change legislation, commodity prices and
electricity demand in Nevada.
Natural
Gas Generating Units
In 2006,
SPPC began construction of a 541 MW gas fired high efficiency combined cycle
generator at the Tracy Plant, which was completed in July
2008. In 2007, NPC began the construction of 619 MWs of natural
gas-fired combustion turbine peaking units at Clark Station. The
first block of approximately 206 MWs became commercially operable in July 2008
and the remaining two blocks are expected to be completed by August
2008. Additionally, in 2007, NPC began construction of a 500 MW
natural gas generating
station
at the existing Harry
Allen Station which is expected to be operational by summer 2011.
On April
22, 2008, NPC announced its intention to purchase the 598 MW (nominally rated),
natural gas fired combined cycle power plant, the Bighorn Power Plant, from
Reliant Resources, Inc., for approximately $510 million, including costs for
inventory and other closing costs and adjustments. NPC expects the
final acquisition to occur later in 2008 following required reviews and
approvals from various regulatory authorities, including the PUCN. As
a result of the potential acquisition of the Bighorn Power Plant, NPC
resubmitted its 7th amendment to its IRP as discussed in Note 3, Regulatory
Actions of the Condensed Notes to Financial Statements and filed an 8th
amendment to its IRP in May 2008. The requested approval of the Harry
Allen and Sunrise 500 kV TAP projects and the update of the Ely Energy Center,
which were originally in the 7th amendment, are now included in the 8th
amendment along with a request to approve the acquisition of the Bighorn Power
Plant. Additionally, SPPC resubmitted its 2nd amendment to its IRP,
as discussed in Note 3, Regulatory Actions of the Condensed Notes to Financial
Statements and filed a 3rd amendment to its IRP in May 2008, which addresses the
update of the Ely Energy Center that was originally in the 2nd
amendment.
Management
of Energy Risk
Entering 2008, the Utilities expect to
have open positions resulting from the management of their portfolio of
generation resources, load obligations, and purchased power and fuel contracts,
due to unfolding developments in regional energy markets. The risks
associated with the open positions are addressed in various ways. The
Utilities implement a prudent strategy of piecemeal procurements transacted in
regular intervals and completed before the start of the peak summer
season. This provides the Utilities with ample opportunities for
optimizing their portfolio on a rolling basis in anticipation of changes in
system conditions, load forecasts, and regional energy market
fundamentals. The Utilities also coordinate the planned maintenance
schedules of their owned generating plants and transmission facilities with
expectations of start dates of new generating plants or purchased power
contracts.
Management
of Environmental Matters
The impact environmental laws can have
on existing generating facilities and current and prospective capital
construction projects include but are not limited to increased costs, closure of
existing facilities, mandated equipment upgrades, and termination of the
construction of facilities. Environmental laws already affect the
energy we buy as discussed above under
Purchase and Development of
Renewable Energy Projects
. In the next five years, NPC is
projected to spend $214.3 million
on certain major
environmental projects/upgrades. Additionally, as discussed above,
under
Construction of
Generating Facilities, Ely Energy Center
, environmental laws will play a
significant role in the construction of Ely Energy Center.
A key objective for the Utilities in
2008 will be to enhance and maintain our energy infrastructure investments in
ways that meet customer demand for reliable energy in an efficient and
environmentally responsible manner. The Utilities believe that a
diverse and balanced portfolio of energy resources represents opportunity for
reliability and cost control, yet are also mindful of our overriding
environmental responsibility. The Utilities are committed to making
technology choices with a primary focus on limiting emissions and optimizing our
investments so that prices remain competitive. To meet the growing
demand for power, the Utilities are investing in a new generation of highly
efficient and environmentally advanced power plants, both coal and natural gas
fired as well as adding new environmental controls to their existing
plants. To help manage load demand, the Utilities are also increasing
their participation and development of new energy efficiency and demand side
conservation programs.
Management
of Regulatory Filings
As is the
case with most regulated entities, the Utilities are frequently involved in
various regulatory proceedings. The Utilities are required to file
for quarterly rate adjustments to provide recovery of their fuel and purchased
power costs. They are also required to file rate cases every three
years to adjust general rates that include their cost of service and return on
investment in order to more closely align earned returns with those allowed by
regulators. Furthermore, the Utilities are required to file a
triennial IRP which is a comprehensive plan that considers customer energy
requirements and proposes the resources to meet that
requirement. Resource additions approved by the PUCN in the resource
planning process are deemed prudent for ratemaking purposes. Between
IRP filings, the Utilities may seek PUCN approval for modifications to their
resource plans and for power purchases. Major projects included in
the Utilities’ IRPs include the Ely Energy Center, Tracy Generating Station, the
Bighorn Power Plant, and Clark Station. The Utilities incur costs for
such items as deferred fuel and purchased power costs, operations and
maintenance and capital projects; however, costs are not recovered through rates
until approved by regulators. The timing between costs incurred and
recovery is considered regulatory lag. As such, timely and accurate
filings of these various rate cases is essential to the Utilities’ operating and
financial performance as it reduces regulatory lag, which has a direct effect on
the cash flows of the Utilities. Furthermore, the timing of the
filings/decisions can affect the timing of construction and thus the economic
benefits. As a result, the Utilities file quarterly BTER updates to
minimize exposure to changes in fuel and purchased power expense, file
amendments to IRP’s as changes in resource needs occur, and under their general
rate case, pursuant to recent Nevada law, may elect to include in their filing
future projected costs particularly in the case of major construction projects
and related operating and maintenance expense, where significant amounts of
capital are required to reduce regulatory lag.
Significant decisions or
filings expected in 2008 include, but are not limited to, SPPC’s 2007 GRC,
amendments to the Utilities’ IRPs, and the filing of NPC’s GRC in late
2008. See Note 3, Regulatory Actions of the Condensed Notes to
Financial Statements in this Form 10-Q.
Further
Broaden Access to Capital
A significant focus in 2008 will again
be to generate sufficient cash from operations to meet their operating needs and
contribute to capital projects by managing recovery of deferred fuel and
purchased power costs, reducing regulatory lag in recovery of costs and
controlling costs. However, significant amounts of capital may be
necessary to fund existing and prospective construction projects, as well as
volatile energy costs. As a result of slower growth, the potential
acquisition of Bighorn and the timing of certain projects, management has
reduced the Utilities’ 2008 estimated cash construction requirement of $1.2
billion, which includes funds invested through June 30, 2008, by approximately
$100 - $150 million for the remainder of 2008. Additionally, the
Utilities intend to reduce 2009 estimated cash construction requirements by $100
- $150 million. As a result, the Utilities’ estimated cash
requirement for the years 2008-2012 is approximately $7.4 billion for capital
projects, some of which include: the Ely Energy Center for $2.4 billion (does
not include costs beyond 2012), Tracy for $30.1 million, Clark Station for
$120.3 million, Harry Allen for $681.9 million, renewable development of $457
million and environmental upgrades of $214.3 million. Of these major
projects, approximately $930 million has been approved by the
PUCN. In addition, pending regulatory approval of the acquisition of
the Bighorn Power Plant, cash requirements for 2008 will increase by
approximately $510 million, including costs for inventory and other closing
costs and adjustments. Management is likely to meet such financial
obligations with a combination of internally generated funds, the use of the
Utilities’ revolving credit facilities, the issuance of long-term debt, and the
issuance of equity by SPR. If energy costs rise at a rapid rate and
the Utilities do not recover the cost of fuel and purchased power in a timely
manner, the Utilities may need to rely more on their revolving credit
facilities, and if necessary, issue additional debt to support their operating
costs or delay capital expenditures.
RESULTS
OF OPERATIONS
Sierra
Pacific Resources (Consolidated)
The operating results of SPR primarily
reflect those of NPC and SPPC, discussed later. The holding company’s
(stand alone) operating results included approximately $20.9 million and $21.8
million of interest costs for the six months ended June 30, 2008 and 2007
respectively.
During
the three months ended June 30, 2008, SPR recognized net income applicable to
common stock of approximately $36.1 million compared to $25.8 million to the
same period in 2007. The increase was primarily due to an increase in
operating income and an increase in AFUDC, as a result of the construction of
the Clark Peaking Units and the expansion of the Tracy Generating
Station. Operating income increased primarily due to an increase in
NPC’s Base Tariff General Rates (BTGR), as a result of NPC’s 2006 GRC, effective
June 1, 2007.
During
the six months ended June 30, 2008, SPR recognized net income applicable to
common stock of approximately $60.2 million compared to $41.4 million to the
same period in 2007. The increase was primarily due to the items
noted above and the reinstatement of disallowed plant costs related to Piñon
Pine, as discussed further in Note 3, Regulatory Actions of the Condensed Notes
to Financial Statements. Partially offsetting this increase was
income recognized in 2007 for approximately $7.2 million (net of taxes) as a
result of the settlement with the PUCN regarding accrued interest on NPC’s 2001
deferred energy case, see Note 3, Regulatory Actions in the Notes to Financial
Statements in the 2007 Form 10-K.
As of
June 30, 2008 NPC had paid $24.9 million in dividends to SPR and SPPC had paid
$63.3 million in dividends to SPR. On August 4, 2008, NPC declared an
additional $30.0 million dividend to SPR. On August 4, 2008, SPPC
declared an additional $15.0
million dividend to
SPR.
ANALYSIS
OF CASH FLOWS
Cash
flows decreased during the six months ended June 30, 2008 compared to the same
period in 2007 due to decreases in cash from operating and financing activities,
partially offset by a decrease in cash used by investing
activities.
Cash From Operating
Activities
. The decrease in cash from operating activities was
primarily due to increases in energy costs in excess of the energy revenue
collected in rates, expenditures for conservation programs, site studies and
other regulatory activities in 2008. The decrease was partially
offset by the June 2007 rate increase resulting from NPC’s GRC, the settlement
with Calpine, and prepaid transmission revenues.
Cash Used By Investing
Activities
. Cash used for investing activities decreased
primarily due to the closing stages of major construction activity for the
peaking units at Clark Station and the combined cycle natural gas power plant at
the Tracy Generating Station which began in 2007 and 2006,
respectively.
Cash From Financing
Activities
. Cash from financing activities decreased due to
reduced debt financings and dividend payments to SPR shareholders in
2008.
LIQUIDITY
AND CAPITAL RESOURCES (SPR CONSOLIDATED)
Overall
Liquidity
SPR’s
consolidated operating cash flows are primarily derived from the operations of
NPC and SPPC. The primary source of operating cash flows for the
Utilities is revenues (including the recovery of previously deferred energy
costs and natural gas costs) from sales of electricity and natural
gas. Significant uses of cash flows from operations include the
purchase of electricity and natural gas, other operating expenses, capital
expenditures and interest. Operating cash flows can be significantly
influenced by factors such as weather, regulatory outcomes, and economic
conditions.
Available
Liquidity as of June 30, 2008 (in millions)
|
|
|
|
SPR
|
|
|
NPC
|
|
|
SPPC
|
|
Cash
and Cash Equivalents
|
|
$
|
12.2
|
|
|
$
|
36.5
|
|
|
$
|
21.8
|
|
Balance
available on Revolving Credit Facility
|
|
|
N/A
|
|
|
|
456.3
|
|
|
|
153.2
|
|
|
|
$
|
12.2
|
|
|
$
|
492.8
|
|
|
$
|
175.0
|
|
In
addition to cash on hand and the Utilities’ revolving credit facilities, the
Utilities may issue debt up to $1.3 billion on a consolidated basis, subject to
certain limitations discussed below and in the Utilities’ respective sections,
to meet their respective financial obligations.
SPR and
the Utilities anticipate that they will be able to meet short-term operating
costs, such as fuel and purchased power costs, with internally generated funds,
including the recovery of deferred energy, and the use of their revolving credit
facilities. To manage liquidity needs as a result of seasonal peaks
in fuel requirement, SPR and the Utilities may use hedging
activities. However, to fund long-term capital requirements, SPR and
the Utilities will likely meet such financial obligations with a combination of
internally generated funds, the use of the Utilities’ revolving credit
facilities, the issuance of long-term debt, and capital contributions from SPR
from the issuance of equity by SPR.
SPR has
approximately $40.7 million payable of debt service obligations for 2008, of
which $20.4 million was paid in the six months ended June 30,
2008. SPR intends to pay the remaining interest payments through
dividends from subsidiaries. (See “Factors Affecting
Liquidity-Dividends from Subsidiaries” below).
During the
six months ended June 30, 2008, there were no material changes to contractual
obligations as set forth in SPR’s 2007 Form 10-K for SPR. See NPC’s
and SPPC’s respective sections for changes in contractual
obligations.
Factors
Affecting Liquidity
Effect
of Holding Company Structure
As of June 30, 2008, SPR (on a
stand-alone basis) has outstanding debt and other obligations including, but not
limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $210.5
million of its unsecured 6.75% Senior Notes due 2017; and $250 million of its
unsecured 8.625% Senior Notes due 2014.
Due to the holding company structure,
SPR’s right as a common shareholder to receive assets of any of its direct or
indirect subsidiaries upon a subsidiary’s liquidation or reorganization is
junior to the claims against the assets of such subsidiary by its
creditors. Therefore, SPR’s debt obligations are effectively
subordinated to all existing and future claims of the creditors of NPC and SPPC
and its other subsidiaries, including trade creditors, debt holders, secured
creditors, taxing authorities and guarantee holders.
As of June 30, 2008, SPR, NPC, SPPC and
their subsidiaries had approximately $4.5 billion of debt and other obligations
outstanding, consisting of approximately $2.7 billion of debt at NPC,
approximately $1.3 billion of debt at SPPC and approximately $524 million of
debt at the holding company and other subsidiaries. Although SPR and
the Utilities are parties to agreements that limit the amount of additional
indebtedness they may incur, SPR and the Utilities retain the ability to incur
substantial additional indebtedness and other liabilities.
Dividends
from Subsidiaries
Since SPR
is a holding company, substantially all of its cash flow is provided by
dividends paid to SPR by NPC and SPPC on their common stock, all of which is
owned by SPR. Since NPC and SPPC are public utilities, they are
subject to regulation by state utility commissions, which impose limits on
investment returns or otherwise impact the amount of dividends that the
Utilities may declare and pay.
In
addition, certain agreements entered into by the Utilities set restrictions on
the amount of dividends they may declare and pay and restrict the circumstances
under which such dividends may be declared and paid. However, as a
result of the recent credit rating upgrade of the Utilities secured debt to
investment grade by Standard and Poor’s (S&P) these restrictions are
suspended and will no longer be in effect so long as the debt remains
investment grade by both Moody’s and S&P. See Credit Ratings
below.
In
addition to the restrictions imposed by specific agreements, the Federal Power
Act prohibits the payment of dividends from “capital
accounts.” Although the meaning of this provision is unclear, the
Utilities currently pay dividends to SPR out of earnings and are therefore not
affected by this provision. Moreover, the Utilities believe that the
Federal Power Act restriction, as applied to their particular circumstances,
would not be construed or applied by the FERC to prohibit the payment of
dividends for lawful and legitimate business purposes from earnings, or in the
absence of earnings, from other/additional paid-in capital
accounts. If, however, the Utilities experienced a material loss
and/or the FERC were to interpret this provision differently, the ability of the
Utilities to pay dividends to SPR could be jeopardized.
Credit
Ratings
SPR, NPC and SPPC are rated by four
Nationally Recognized Statistical Rating Organizations
(NRSRO’s): Dominion Bond Rating Service (DBRS), Fitch Ratings Ltd.
(Fitch), Moody’s Investors Service, Inc. (Moody’s) and S&P. The
secured debt of NPC and SPPC is rated investment grade by all four rating
organizations. As of August 1, 2008
,
the ratings are as
follows:
|
|
Rating
Agency
|
|
|
DBRS
|
Fitch
|
Moody’s
|
S&P
|
SPR
|
Sr.
Unsecured Debt
|
BB
(low)
|
BB-
|
Ba3
|
BB
|
NPC
|
Sr.
Secured Debt
|
BBB
(low)
|
BBB-
|
Baa3
|
BBB
|
NPC
|
Sr.
Unsecured Debt
|
Not
rated
|
BB
|
Not
rated
|
BB+
|
SPPC
|
Sr.
Secured Debt
|
BBB
(low)
|
BBB-
|
Baa3
|
BBB
|
On May
15, 2008, S&P increased SPR’s corporate credit rating to BB from BB-, and
unsecured notes at SPR were raised to BB from BB-. At the same time,
the secured ratings at NPC and SPPC were raised to BBB from BB+, and unsecured
notes at NPC were raised to BB+ from BB. As a result of these
upgrades, all four rating agencies currently rate the Utilities’ senior secured
debt investment grade. S&P’s, Moody’s and DBRS’s rating outlook
for SPR, NPC and SPPC is Stable. Fitch’s rating outlook for SPR, NPC
and SPPC is Positive.
A security
rating is not a recommendation to buy, sell or hold
securities. Security ratings are subject to revision and withdrawal
at any time by the assigning rating organization, and each rating should be
evaluated independently of any other rating.
Credit
Ratings of Bond Insurers
Recent
sub-prime mortgage issues have adversely affected the overall financial markets,
generally resulting in increased interest rates, reduced access to the capital
markets, and actual or potential downgrades of bond insurers, among other
negative matters. The interest rates on certain issues of the
Utilities' auction rate securities of approximately $556 million as of June 30,
2008, are periodically reset through auction processes. These
securities are supported by bond insurance policies provided by either Ambac
Financial Group (AMBAC), Financial Guaranty Insurance Company (FGIC), or MBIA,
Inc. (MBIA) (collectively, the “Insurers”), and the interest rates on those
securities are directly affected by the rating of the bond insurer due to, among
other things, the impact that such ratings have on the success or failure of the
auction process. S&P’s and Moody’s ratings on these bonds are the
higher
of a bond issues
underlying rating and the Insurer's rating. As of June 30, 2008,
AMBAC’s and MBIA’s credit ratings were investment grade or
above. However, FGIC’s credit ratings were below investment
grade. As a result, the bonds insured by FGIC are currently rated at
the investment grade ratings of the Utilities’ secured debt. See
Credit Ratings
above
.
The uncertainty
with the Insurers' credit quality has had an impact on the Utilities’ interest
costs for the first six months of 2008. With the ongoing review of
the credit ratings of the Insurers, the Utilities are experiencing higher
interest costs for these securities.
In July
2008 NPC and SPPC converted portions of their auction rate securities to
variable rate demand notes. This conversion will likely result in
higher interest charges compared to prior year, but lower than the failed
auction rates for this tax exempt debt. See
Financing Transactions
in
NPC’s and SPPC’s Liquidity sections. If higher interest rates
continue on the remaining auction rate securities outstanding, the Utilities may
seek to convert the debt to other short-term variable rate structures, term-put
structures and/or fixed-rate structures.
Financial
Covenants
Nevada
Power Company and Sierra Pacific Power Company
Each of NPC's $600 million Second
Amended and Restated Revolving Credit Agreement and SPPC's $350 million Amended
and Restated Revolving Credit Agreement, dated November 2005, and amended in
April 2006, contains two financial maintenance covenants. The first
requires the Utility to maintain a ratio of consolidated indebtedness to
consolidated capital, determined as of the last day of each fiscal quarter, not
to exceed 0.68 to 1. The second requires the Utility to maintain a
ratio of consolidated cash flow to consolidated interest expense, determined as
of the last day of each fiscal quarter for the period of four consecutive fiscal
quarters, not to be less than 2.0 to 1. As of June 30, 2008 both
Utilities were in compliance with these covenants.
Ability
to Issue Debt
Certain
debt of SPR places restrictions on debt incurrence, liens and dividends, unless,
at the time the debt is incurred, the ratio of consolidated cash flow to fixed
charges for SPR’s most recently ended four quarter period on a pro forma basis
is at least 2 to 1. Under this covenant restriction, as of June 30,
2008, SPR would be allowed to incur up to $1.3
billion of additional
indebtedness on a consolidated basis.
Notwithstanding
this restriction, under the terms of the debt, SPR would still be permitted to
incur debt including, but not limited to, obligations incurred to finance
property construction or improvement, certain intercompany indebtedness, or
indebtedness incurred to finance capital expenditures, pursuant to the two
Utilities’ integrated resource plans. NPC and SPPC would also be
permitted to incur a combined total of up to $500 million in indebtedness and
letters of credit under their respective revolving credit
facilities.
If the
applicable series of SPR’s debt is upgraded to investment grade by both Moody’s
and S&P, these restrictions will be suspended and will no longer be in
effect so long as the applicable series of Notes remain investment grade by both
Moody’s and S&P (see Credit Ratings above).
Nevada
Power Company
Ability
to Issue Debt
NPC’s
ability to issue debt is impacted by certain factors such as financing authority
from the PUCN, financial covenants in its financing agreements, and the terms of
certain SPR debt. As of June 30, 2008, NPC had approximately $1.6
billion of PUCN financing authority.
The
financial covenants under NPC’s debt allow for greater borrowings than SPR’s cap
on additional indebtedness; therefore, NPC is limited by SPR’s cap on additional
indebtedness of $1.3 billion.
Since SPR’s debt covenant
limitations are calculated on a consolidated basis, SPR’s debt covenant
limitations may allow for higher or lower borrowings than $1.3 billion,
depending on the Utilities combined usage of their revolving credit facilities
at the time of the covenant calculations.
Ability
to Issue General and Refunding Mortgage Securities
To the
extent that NPC has the ability to issue debt under the most restrictive
covenants in its financing agreements and has financing authority to do so from
the PUCN, NPC’s ability to issue secured debt is still limited by the amount of
bondable property or retired bonds that can be used to issue debt under NPC’s
General and Refunding Mortgage Indenture (“Indenture”).
As
of June 30, 2008, $2.8 billion of NPC’s General and Refunding Mortgage
Securities were outstanding. NPC had the capacity to issue an
additional $882 million of General and Refunding Mortgage Securities as of June
30, 2008.
NPC also has the ability to release
property from the lien of the mortgage indenture on the basis of net property
additions, cash and/or retired bonds. To the extent NPC releases
property from the lien of its General and Refunding Mortgage Indenture, it will
reduce the amount of securities issuable under that indenture. See
the 2007 Form 10-K for additional information.
Sierra
Pacific Power Company
Ability
to Issue Debt
SPPC’s
ability to issue debt is impacted by certain factors such as financing authority
from the PUCN, financial covenants in its financing agreements, and the terms of
certain SPR debt. As of June 30, 2008, SPPC had approximately $745
million of PUCN financing authority.
The
financial covenants under SPPC’s debt limit SPPC’s borrowing to approximately
$839.0 million as of June 30, 2008, therefore, SPPC is not limited by SPR’s cap
on additional indebtedness of $1.3 billion.
Since SPR’s debt covenant
limitations are calculated on a consolidated basis, SPR’s debt covenant
limitations may allow for higher or lower borrowings than $1.3 billion,
depending on the Utilities combined usage of their revolving credit facilities
at the time of the covenant calculations.
Ability
to Issue General and Refunding Mortgage Securities
To the
extent that SPPC has the ability to issue debt under the most restrictive
covenants in its financing agreements and has financing authority to do so from
the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of
bondable property or retired bonds that can be used to issue debt under SPPC’s
General and Refunding Mortgage Indenture (“Indenture”).
As
of June 30, 2008, $1.4 billion of SPPC’s General and Refunding Mortgage
Securities were outstanding. SPPC had the capacity to issue an
additional $480 million of General and Refunding Mortgage Securities as of June
30, 2008.
SPPC also has the ability to release
property from the lien of the mortgage indenture on the basis of net property
additions, cash and/or retired bonds. To the extent SPPC releases
property from the lien of its General and Refunding Mortgage Indenture, it will
reduce the amount of securities issuable under that indenture. See
the 2007 Form 10-K for additional information.
Cross
Default Provisions
None of
the Utilities’ financing agreements contains a cross-default provision that
would result in an event of default by that Utility upon an event of default by
SPR or the other Utility under any of their respective financing
agreements. Certain of SPR’s financing agreements, however, do
contain cross-default provisions that would result in event of default by SPR
upon an event of default by the Utilities under their respective financing
agreements. In addition, certain financing agreements of each of SPR
and the Utilities provide for an event of default if there is a failure under
other financing agreements of that entity to meet payment terms or to observe
other covenants that would result in an acceleration of payments
due. Most of these default provisions (other than ones relating to a
failure to pay other indebtedness) provide for a cure period of 30-60 days from
the occurrence of a specified event, during which time SPR or the Utilities may
rectify or correct the situation before it becomes an event of
default.
RESULTS
OF OPERATIONS
NPC
recognized net income of $33.2 million during the three months ended June 30,
2008 compared to net income of $23.6 million for the same period in
2007. During the six months ended June 30, 2008, NPC recognized net
income of approximately $41.1 million compared to net income of approximately
$28.2 million for the same period in 2007.
During
the six months ended June 30, 2008, NPC paid $24.9 million in dividends to
SPR. On August 4, 2008, NPC declared an additional $30.0 million
dividend to SPR.
Gross
margin is presented by NPC in order to provide information that management
believes aids the reader in determining how profitable the electric business is
at the most fundamental level. Gross margin, which is a “non-GAAP
financial measure” as defined in accordance with SEC rules, provides a measure
of income available to support the other operating expenses of the business and
is a key factor utilized by management in its analysis of its
business.
NPC
believes presenting gross margin allows the reader to assess the impact of NPC’s
regulatory treatment and its overall regulatory environment on a consistent
basis. Gross margin, as a percentage of revenue, is primarily
impacted by the fluctuations in electric and natural gas supply costs versus the
fixed rates collected from customers. While these fluctuating costs
impact gross margin as a percentage of revenue, they only impact gross margin
amounts if the costs cannot be passed through to customers. Gross
margin, which NPC calculates as operating revenues less fuel and purchased power
costs, provides a measure of income available to support the other operating
expenses of NPC. For reconciliation to operating income, see Note 2,
Segment information in the Condensed Notes to Financial
Statements. Gross margin changes based on such factors as general
base rate adjustments (which are required to be filed by statute every three
years) and reflect NPC’s strategy to increase internal power generation versus
purchased power, which generates no gross margin.
The
components of gross margin were (dollars in thousands):
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
Operating
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
570,223
|
|
|
$
|
575,108
|
|
|
|
-0.8
|
%
|
|
$
|
1,039,395
|
|
|
$
|
993,273
|
|
|
|
4.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
164,087
|
|
|
|
175,716
|
|
|
|
-6.6
|
%
|
|
|
257,837
|
|
|
|
271,310
|
|
|
|
-5.0
|
%
|
Fuel
for power generation
|
|
|
209,920
|
|
|
|
140,773
|
|
|
|
49.1
|
%
|
|
|
373,941
|
|
|
|
304,858
|
|
|
|
22.7
|
%
|
Deferral
of energy costs-net
|
|
|
(9,691
|
)
|
|
|
67,731
|
|
|
|
-114.3
|
%
|
|
|
36,084
|
|
|
|
94,663
|
|
|
|
-61.9
|
%
|
|
|
$
|
364,316
|
|
|
$
|
384,220
|
|
|
|
-5.2
|
%
|
|
$
|
667,862
|
|
|
$
|
670,831
|
|
|
|
-0.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin
|
|
$
|
205,907
|
|
|
$
|
190,888
|
|
|
|
7.9
|
%
|
|
$
|
371,533
|
|
|
$
|
322,442
|
|
|
|
15.2
|
%
|
Gross margin increased for the three
and six months ended June 30, 2008 compared to the same period in 2007 primarily
due to an increase in Base Tariff General Rates (BTGR) as a result of NPC’s 2006
GRC, effective June 1, 2007. Partially offsetting the increase was a
decrease in use per customer primarily due to cooler weather and a change in
customer usage patterns.
The
causes for significant changes in specific lines comprising the results of
operations for NPC for the respective years ended are provided below (dollars in
thousands except for amounts per unit).
Electric
Operating Revenue
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
Electric
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
245,810
|
|
|
$
|
267,060
|
|
|
|
-8.0
|
%
|
|
$
|
451,188
|
|
|
$
|
446,309
|
|
|
|
1.1
|
%
|
Commercial
|
|
|
123,947
|
|
|
|
122,130
|
|
|
|
1.5
|
%
|
|
|
228,459
|
|
|
|
218,033
|
|
|
|
4.8
|
%
|
Industrial
|
|
|
176,778
|
|
|
|
167,520
|
|
|
|
5.5
|
%
|
|
|
309,789
|
|
|
|
292,346
|
|
|
|
6.0
|
%
|
Retail revenues
|
|
|
546,535
|
|
|
|
556,710
|
|
|
|
-1.8
|
%
|
|
|
989,436
|
|
|
|
956,688
|
|
|
|
3.4
|
%
|
Other
|
|
|
23,688
|
|
|
|
18,398
|
|
|
|
28.8
|
%
|
|
|
49,959
|
|
|
|
36,585
|
|
|
|
36.6
|
%
|
Total
Revenues
|
|
$
|
570,223
|
|
|
$
|
575,108
|
|
|
|
-0.8
|
%
|
|
$
|
1,039,395
|
|
|
$
|
993,273
|
|
|
|
4.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
sales in thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Of
megawatt-hours (MWh)
|
|
|
5,245
|
|
|
|
5,588
|
|
|
|
-6.1
|
%
|
|
|
9,539
|
|
|
|
9,782
|
|
|
|
-2.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
retail revenue per MWh
|
|
$
|
104.20
|
|
|
$
|
99.63
|
|
|
|
4.6
|
%
|
|
$
|
103.72
|
|
|
$
|
97.80
|
|
|
|
6.1
|
%
|
NPC’s retail revenues decreased
for the three months ended June 30, 2008 as compared to the same period in 2007
due to a decrease in customer usage due to cooler weather and a change in
customer usage patterns. Partially offsetting the decrease in
revenues was an increase in retail rates and customer count. Retail
rates increased as a result of NPC’s various Base Tariff Energy Rate
(BTER), Deferred Energy Cases and NPC’s 2006 GRC, effective June 1,
2007 (see Note 3, Regulatory Actions of the Notes to the Financial Statements in
the 2007 Form 10-K). Average residential, commercial and industrial
customers increased by 0.7%, 2.6% and 3.6%, respectively, for the three months
ended June 30, 2008.
NPC’s
retail revenues increased for the six months ended June 30, 2008 as compared to
the same period in 2007 due to increases in retail rates and customer
count. Retail rates increased as a result of NPC’s various BTER,
Deferred Energy Cases and NPC’s 2006 GRC, effective June 1, 2007 (see Note 3,
Regulatory Actions of the Notes to the Financial Statements in the 2007 Form
10-K). Average residential, commercial and industrial customers
increased by 1.1%, 3.1% and 3.4%, respectively. These increases were
partially offset by a decrease in customer usage due to cooler weather and a
change in customer usage patterns.
Electric
Operating Revenues – Other increased for the three and six months ended June 30,
2008, compared to the same periods in 2007. The increase is primarily
due to the elimination of the reclassification of revenues associated with
Mohave, as a result of NPC’s 2006 GRC, which in 2007 were reclassified to Other
Regulatory Assets as a result of the shut down of the Mohave Generating
Station. For further discussion on Mohave refer to Note 1, Summary of
Significant Accounting Policies in the Notes to Financial Statements in the 2007
Form 10-K. Also contributing to the increase was transmission related
revenue as a result of the Calpine settlement, as discussed further in Note 5,
Commitments and Contingencies, and an increase in transmission revenue as a
result of the completion of the Harry Allen to Mead transmission
line.
Energy
Costs
Energy Costs include Purchased Power
and Fuel for Generation. Energy costs are dependent upon several
factors which may vary by season or period. As a result, NPC’s usage
and average cost per MWh of purchased power versus fuel for generation to meet
demand can vary significantly. Factors that may affect energy costs
include, but are not limited to:
·
|
Transmission
constraints
|
·
|
Natural
gas constraints
|
·
|
Long
term contracts; and
|
·
|
Mandated
power purchases
|
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs
|
|
$
|
374,007
|
|
|
$
|
316,489
|
|
|
|
18.2
|
%
|
|
$
|
631,778
|
|
|
$
|
576,168
|
|
|
|
9.7
|
%
|
Total
System Demand
|
|
|
5,617
|
|
|
|
5,925
|
|
|
|
-5.2
|
%
|
|
|
10,149
|
|
|
|
10,486
|
|
|
|
-3.2
|
%
|
Average
cost per MWH
|
|
$
|
66.58
|
|
|
$
|
53.42
|
|
|
|
24.6
|
%
|
|
$
|
62.25
|
|
|
$
|
54.95
|
|
|
|
13.3
|
%
|
For the three and six months ended June
30, 2008, energy costs and the average cost per MWh increased primarily due to
higher natural gas prices. Total system demand decreased primarily
due a decrease in customer usage as a result of cooler weather and a change in
customer usage patterns.
Purchased
Power
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power
|
|
$
|
164,087
|
|
|
$
|
175,716
|
|
|
|
-6.6
|
%
|
|
$
|
257,837
|
|
|
$
|
271,310
|
|
|
|
-5.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
Power in thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
MWhs
|
|
|
1,833
|
|
|
|
2,369
|
|
|
|
-22.6
|
%
|
|
|
3,029
|
|
|
|
3,552
|
|
|
|
-14.7
|
%
|
Average
cost per MWh of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
purchased
power
|
|
$
|
89.52
|
|
|
$
|
74.17
|
|
|
|
20.7
|
%
|
|
$
|
85.12
|
|
|
$
|
76.38
|
|
|
|
11.4
|
%
|
Purchased power costs and MWhs
decreased for the three and six months ended June 30, 2008 compared to the same
period in 2007 primarily due to an increase in the reliance on internal
generation and a decrease in total system demand. The average cost
per MWh of purchased power for the three and six months ended June 30,
2008, increased primarily due to higher natural gas
prices slightly offset by a decrease in fixed capacity charges and
cost of hedging instruments.
Fuel
For Power Generation
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
for power generation
|
|
$
|
209,920
|
|
|
$
|
140,773
|
|
|
|
49.1
|
%
|
|
$
|
373,941
|
|
|
$
|
304,858
|
|
|
|
22.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thousands
of MWhs generated
|
|
|
3,784
|
|
|
|
3,556
|
|
|
|
6.4
|
%
|
|
|
7,120
|
|
|
|
6,934
|
|
|
|
2.7
|
%
|
Average
cost per MWh of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
generated
power
|
|
$
|
55.48
|
|
|
$
|
39.59
|
|
|
|
40.1
|
%
|
|
$
|
52.52
|
|
|
$
|
43.97
|
|
|
|
19.4
|
%
|
Fuel for
power generation costs and the average cost per MWh increased for the three and
six months ended June 30, 2008 primarily due to higher natural gas prices
partially offset by a decrease in the cost of hedging instruments.
Deferral
of Energy Costs - Net
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
energy costs - net
|
|
$
|
(9,691
|
)
|
|
$
|
67,731
|
|
|
|
-114.3
|
%
|
|
$
|
36,084
|
|
|
$
|
94,663
|
|
|
|
-61.9
|
%
|
Deferral of energy costs – net
represents the difference between actual fuel and purchased power costs incurred
during the period and amounts recoverable through current rates. To
the extent actual costs exceed amounts recoverable through current rates, the
excess is recognized as a reduction in costs. Conversely to the
extent actual costs are less than amounts recoverable through current rates, the
difference is recognized as an increase in costs. Deferral of energy
costs – net also include the current amortization of fuel and purchased power
costs previously deferred. Reference Note 1, Summary of Significant
Accounting Policies, of the Condensed Notes to Financial Statements for further
detail of deferred energy balances.
Amounts for
the three months ended June 30, 2008 and 2007 include amortization of deferred
energy costs of $48.4 million and $40.6 million, respectively; and an
under-collection of amounts recoverable in rates of $58.1 million in 2008 and an
over-collection of $27.1 million in 2007. Amounts for the six months
ended June 30, 2008 and 2007 include amortization of deferred energy costs of
$88.2 million and $64.7 million, respectively; and an under-collection of
amounts recoverable in rates of $52.1 million in 2008 and an over-collection of
$29.9 million in 2007. Amortization for both the three and six month
periods include amounts for the Western Energy Crisis Rate Case and the
Reinstatement of deferred energy as discussed in Note 3, Regulatory Actions, of
Notes to Financial Statements in NPC’s 2007 Form 10-K.
Allowance
for Funds Used During Construction (AFUDC)
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for other funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
used
during construction
|
|
$
|
7,692
|
|
|
$
|
3,247
|
|
|
|
136.9
|
%
|
|
$
|
14,550
|
|
|
$
|
6,345
|
|
|
|
129.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for borrowed funds used during construction
|
|
$
|
6,020
|
|
|
$
|
2,703
|
|
|
|
122.7
|
%
|
|
$
|
11,375
|
|
|
$
|
5,253
|
|
|
|
116.5
|
%
|
|
|
$
|
13,712
|
|
|
$
|
5,950
|
|
|
|
130.5
|
%
|
|
$
|
25,925
|
|
|
$
|
11,598
|
|
|
|
123.5
|
%
|
AFUDC
increased for the three and six months ended June 30, 2008 compared to the same
period in 2007 primarily due to an increase in Construction Work-In-Progress
(CWIP) associated with the construction of the Clark Peaking Units.
Other
(Income) and Expenses
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
operating expense
|
|
$
|
62,617
|
|
|
$
|
55,162
|
|
|
|
14
|
%
|
|
$
|
119,712
|
|
|
$
|
106,001
|
|
|
|
13
|
%
|
Maintenance
expense
|
|
$
|
13,608
|
|
|
$
|
20,319
|
|
|
|
-33
|
%
|
|
$
|
30,258
|
|
|
$
|
37,783
|
|
|
|
-19.9
|
%
|
Depreciation
and amortization
|
|
$
|
42,323
|
|
|
$
|
38,833
|
|
|
|
9.0
|
%
|
|
$
|
82,953
|
|
|
$
|
74,594
|
|
|
|
11.2
|
%
|
Interest
charges on long-term debt
|
|
$
|
41,624
|
|
|
$
|
41,368
|
|
|
|
0.6
|
%
|
|
$
|
82,621
|
|
|
$
|
81,074
|
|
|
|
1.9
|
%
|
Interest
charges-other
|
|
$
|
5,384
|
|
|
$
|
5,603
|
|
|
|
-3.9
|
%
|
|
$
|
11,215
|
|
|
$
|
12,439
|
|
|
|
-9.8
|
%
|
Interest
accrued on deferred energy
|
|
$
|
(1,084
|
)
|
|
$
|
(3,427
|
)
|
|
|
-68.4
|
%
|
|
$
|
(2,878
|
)
|
|
$
|
(7,276
|
)
|
|
|
-60.4
|
%
|
Carrying
charge for Lenzie
|
|
|
-
|
|
|
$
|
(5,998
|
)
|
|
|
N/A
|
|
|
|
-
|
|
|
$
|
(16,080
|
)
|
|
|
N/A
|
|
Reinstated
interest on deferred energy
|
|
|
-
|
|
|
|
-
|
|
|
|
N/A
|
|
|
|
-
|
|
|
$
|
11,076
|
|
|
|
N/A
|
|
Other
income
|
|
$
|
(3,107
|
)
|
|
$
|
(2,909
|
)
|
|
|
6.8
|
%
|
|
$
|
(8,854
|
)
|
|
$
|
(8,030
|
)
|
|
|
10.3
|
%
|
Other
expense
|
|
$
|
1,656
|
|
|
$
|
5,384
|
|
|
|
-69.2
|
%
|
|
$
|
3,017
|
|
|
$
|
7,426
|
|
|
|
-59.4
|
%
|
Other operating expense increased for
the three and six months ended June 30, 2008, compared to the same period in
2007, primarily due to the reversal of a reserve established for Enron legal
fees in 2007. In March 2007, the PUCN granted recovery of these
expenses, see Note 3, Regulatory Actions, of the Notes to Financial Statements
in the 2007 Form 10-K for further discussion. Additionally, in 2007
certain consulting fees were reclassified to regulatory asset reducing expense
in 2007. Also contributing to the increase in other operating
expenses were increased costs for regulatory amortizations as compared to the
same period in 2007.
Maintenance expense decreased for the
three and six months ended June 30, 2008, compared to the same period in 2007,
due to planned maintenance costs for Lenzie and a forced outage at Harry Allen
in 2007.
Depreciation
and amortization expenses increased during the three months and six months ended
June 30, 2008, compared to the same periods in 2007, primarily as a result of
depreciation expense related to Lenzie, beginning June 2007 as a result of NPC’s
2006 GRC.
Interest
charges on Long-Term Debt increased for the three months and six months ended
June 30, 2008, as compared to the same period in 2007, due primarily to higher
interest rates on variable rate debt. See Note 6, Long-Term Debt of
the Notes to Financial Statements in the 2007 Form 10-K for additional
information regarding long-term debt and Note 4, Long-Term Debt, of the
Condensed Notes to Financial Statements in this Form 10-Q.
Interest
charges-other decreased for the three months and six months ended June 30, 2008,
as compared to the same period in 2007, due to lower interest associated with
customer transmission deposits, partially offset by higher amortization costs
related to new debt issues, and interest expense related to new
leases.
Interest
accrued on deferred energy costs decreased for the three months and six months
ended June 30, 2008, as compared to the same period in 2007, due to lower
deferred energy balances, partially offset by carrying charges associated with
NPC’s Western Energy Crisis Rate Case, which began June 1, 2007. See
Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to
Financial Statements for further details of deferred energy
balances.
Carrying
charges for Lenzie represent carrying charges earned on the incurred debt
component of the acquisition and construction costs of the completed Lenzie
Generating Station. The PUCN authorized NPC to accrue a carrying
charge for the cost of acquisition and construction until the plant is included
in rates. See Note 1, Summary of Significant Accounting Policies, of
the Notes to Financial Statements in the 2007 Form 10-K for discussion of the
accounting for the carrying charge for Lenzie.
Reinstated interest on deferred energy
represents the carrying charges which were previously expensed as a result of
the PUCN’s decision on NPC’s 2001 Deferred Energy Case. In March
2007, PUCN approved a settlement agreement allowing NPC to recover past carrying
charges. See Note 3, Regulatory Actions, of the Notes to Financial
Statements in the 2007 Form 10-K.
Other
income increased during the three months and six months ended June 30, 2008, as
compared to the same period in 2007, due to a gain from the settlement with
Calpine, and the subsequent gain on sale of the stock received, as discussed
further in Note 6, Commitments and Contingencies in the Condensed Notes to
Financial Statements. This income was partially offset by lower
interest income in 2008.
Other
expense decreased during the three months and six months ended June 30, 2008, as
compared to the same period in 2007, due to costs in 2007 associated with the
Energy Savings Project for the Clark County School District, as agreed upon in
the Reid Gardner Consent Decree discussed in Note 13, Commitments and
Contingencies of the Notes to Financial Statements in the 2007
10-K.
ANALYSIS
OF CASH FLOWS
Cash
flows increased during the six months ended June 30, 2008 compared to the same
period in 2007 due to a decrease in cash used for investing activities and an
increase in cash from financing activities, offset partially by a decrease in
cash from operating activities.
Cash From Operating
Activities
. The decrease in cash from operating activities was
due primarily to increases in energy costs in excess of the energy revenue
collected in rates, an increase in expenditures for conservation programs, site
studies and other regulatory activities in 2008 and a prepayment of tax
obligations. The decrease was partially offset by an increase in
general rates in 2007 resulting from NPC’s GRC, the settlement with Calpine and
prepaid transmission revenues.
Cash Used By Investing
Activities
. Cash used by investing activities decreased
primarily due to the closing stages of major construction activity for the
peaking units at Clark Station, which began in 2007, and a reduction in
construction for infrastructure.
Cash From Financing
Activities
. Cash from financing activities increased slightly
primarily due to $133 million of additional investment by SPR, offset by reduced
debt issuances and increased dividend payments.
LIQUIDITY
AND CAPITAL RESOURCES
Overall
Liquidity
NPC’s
primary source of operating cash flows is electric revenues, including the
recovery of previously deferred energy costs. Significant uses of
cash flows from operations include the purchase of electricity and natural gas,
other operating expenses, capital expenditures and the payment of interest on
NPC’s outstanding indebtedness. Operating cash flows can be
significantly influenced by factors such as weather, regulatory outcome, and
economic conditions.
Available
Liquidity as of June 30, 2008 (in millions)
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
$
|
36.5
|
|
Balance
available on Revolving Credit Facility
(1)
|
|
$
|
456.3
|
|
|
|
|
|
|
|
|
$
|
492.8
|
|
1
As of
August 4, 2008, NPC had approximately $596.3
million available under
its revolving credit facility.
In
addition to cash on hand and the revolving credit facility, NPC may issue debt
up to $1.3
billion
on a consolidated basis, subject to certain limitations discussed
below.
For the six
months ended June 30, 2008, SPR contributed capital to NPC of approximately $133
million for general corporate purposes. For the six months ended June
30, 2008, NPC paid dividends to SPR of $24.9 million. On August 4,
2008, NPC declared an additional $30.0 million dividend to
SPR.
NPC
anticipates that it will be able to meet short-term operating costs, such as
fuel and purchased power costs, with internally generated funds, including the
recovery of deferred energy and the use of its revolving credit
facility. To manage liquidity needs as a result of seasonal peaks in
fuel requirement, NPC may use hedging activities. However, to fund
long-term capital requirements, NPC will likely meet such financial obligations
with a combination of internally generated funds, the use of the revolving
credit facility, the issuance of long-term debt, and capital contributions from
SPR. Additionally, a portion of the revolving credit facility may be
used to fund the acquisition of the Bighorn Power Plant from Reliant Resources,
Inc, if approved.
During the
six months ended June 30, 2008, there were no material changes to contractual
obligations as set forth in NPC’s 2007 Form 10-K. However,
in April 2008, NPC entered into a Purchase Agreement with Reliant Resources, for
a 598 MW (nominally rated), natural gas fired combined cycle facility, for
approximately $510 million. The agreement is expected to be
consummated by the end of 2008 pending various regulatory
approvals. In June 2008, NPC entered into an equipment contract for
approximately $43.5 million related to Harry Allen.
Financing
Transactions
General
and Refunding Mortgage Notes, Series S
On July 31,
2008, NPC issued and sold $500 million of its 6.5% General and Refunding
Mortgage Notes, Series S, due 2018
.
The net proceeds
of the issuance were used to repay $270
million of amounts
outstanding under NPC’s revolving credit facility and for general corporate
purposes.
Redemption
Notice
On July 15,
2008, NPC provided a notice of redemption to the holders of its 9.00% General
and Refunding Mortgage Notes, Series G, for approximately $17.2
million. The notes are scheduled to be redeemed on August 15, 2008,
at 104.50% of the stated principal amount, plus accrued interest to the date of
redemption. NPC intends to use available cash on hand to redeem these
notes.
Conversion
of Coconino County Pollution Control Refunding Revenue Bonds and Clark County
Pollution Control Revenue Bonds
In July 2008,
NPC converted the $13 million principal amount Coconino County, Arizona
Pollution Control Refunding Revenue Bonds Series 2006B bonds, due 2039 and the
$15 million principal amount Clark County Nevada Pollution Control Revenue
Bonds, Series 2000B due 2009, collectively (the “Bonds”) from auction rate
securities to variable rate demand notes. The purpose of these
conversions was to reduce interest costs and volatility associated with these
Bonds. NPC purchased 100% of the Bonds with the use of its revolving
credit facility and available cash, and will remain the sole holder of the
Bonds. The Bonds remain outstanding and have not been retired or
cancelled. However, as NPC is the sole holder of the Bonds, for
financial reporting purposes the investment in the Bonds and the indebtedness
will be offset for presentation purposes.
Factors
Affecting Liquidity
Financial
Covenants
NPC's $600
million Second Amended and Restated Revolving Credit Agreement dated November
2005, and amended in April 2006, contains two financial maintenance
covenants. The first requires NPC to maintain a ratio of consolidated
indebtedness to consolidated capital, determined as of the last day of each
fiscal quarter, not to exceed 0.68 to 1. The second requires NPC to
maintain a ratio of consolidated cash flow to consolidated interest expense,
determined as of the last day of each fiscal quarter for the period of four
consecutive fiscal quarters, not to be less than 2.0 to 1. As of June
30, 2008, NPC was in compliance with these covenants.
Ability
to Issue Debt
NPC’s ability
to issue debt is impacted by certain factors such as financing authority from
the PUCN, financial covenants in its financing agreements, and the terms of
certain SPR debt. As of June 30, 2008, NPC had approximately $1.6
billion of PUCN financing authority.
The financial
covenants under NPC’s debt allow for greater borrowings than SPR’s cap on
additional indebtedness; therefore, NPC is limited by SPR’s cap on additional
indebtedness of $1.3 billion.
Since SPR’s
debt covenant limitations are calculated on a consolidated basis, SPR’s debt
covenant limitations may allow for higher or lower borrowings than $1.3 billion,
depending on the Utilities combined usage of their revolving credit facilities
at the time of the covenant calculations.
Ability
to Issue General and Refunding Mortgage Securities
To the extent
that NPC has the ability to issue debt under the most restrictive covenants in
its financing agreements and has financing authority to do so from the PUCN,
NPC’s ability to issue secured debt is still limited by the amount of bondable
property or retired bonds that can be used to issue debt under NPC’s General and
Refunding Mortgage Indenture (“Indenture”).
As of June 30, 2008, $2.8 billion of
NPC’s General and Refunding Mortgage Securities were outstanding. NPC
had the capacity to issue an additional $882 million of General and Refunding
Mortgage Securities as of June 30, 2008.
NPC also has the ability to release
property from the lien of the mortgage indenture on the basis of net property
additions, cash and/or retired bonds. To the extent NPC releases
property from the lien of its General and Refunding Mortgage Indenture, it will
reduce the amount of securities issuable under that indenture. See
the 2007 Form 10-K for additional information.
Credit
Ratings
NPC’s debt is rated investment grade by
four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch,
Moody’s and S&P. As of August 1, 2008, the ratings are as
follows:
|
|
Rating
Agency
|
|
|
DBRS
|
Fitch
|
Moody’s
|
S&P
|
NPC
|
Sr.
Secured Debt
|
BBB
(low)
|
BBB-
|
Baa3
|
BBB
|
NPC
|
Sr.
Unsecured Debt
|
Not
rated
|
BB
|
Not
rated
|
BB+
|
On May 15, 2008, S&P increased
NPC’s secured ratings to BBB from BB+, and the unsecured notes to BB+ from
BB. S&P’s, Moody’s and DBRS’s rating outlook for NPC is
Stable. Fitch’s rating outlook is Positive.
A security rating is not a
recommendation to buy, sell or hold securities. Security ratings are
subject to revision and withdrawal at any time by the assigning rating
organization, and each rating should be evaluated independently of any other
rating.
Credit
Ratings of Bond Insurers
Recent
sub-prime mortgage issues have adversely affected the overall financial markets,
generally resulting in increased interest rates, reduced access to the capital
markets, and actual or potential downgrades of bond insurers, among other
negative matters. The interest rates on certain issues of NPC’s
auction rate securities of approximately $207.5 million, as of June 30, 2008,
are periodically reset through auction processes. These securities
are supported by bond insurance policies provided by either AMBAC or FGIC and
the interest rates on those securities are directly affected by the rating of
the bond insurer due to, among other things, the impact that such ratings have
on the success or failure of the auction process. S&P’s and
Moody’s ratings on these bonds are the higher of a bond issues underlying rating
and the Insurer's rating. As of June 30, 2008, AMBAC’s credit rating
was investment grade. However, FGIC’s credit ratings were below
investment grade. As a result, the bonds insured by FGIC are
currently rated at the investment grade rating of NPC’s secured
debt.
See Credit
Ratings above.
The
uncertainty with the Insurers' credit quality has had an impact on NPC’s
interest costs for the first six months of 2008. With the ongoing
review of the credit ratings of the Insurers, NPC is experiencing higher
interest costs for these securities, with interest rates on these bonds set
during the second quarter 2008, ranging from a low of 4.16% to a high of 8.66%,
and a low of 3.25 % to a high of 8.66% for the six months ended June 30, 2008,
with a weighted average interest rate of 5.93% for the six months ended June 30,
2008.
In July
2008 NPC converted the Coconino County Arizona Pollution Control Revenue Bonds,
Series 2006B, and the Clark County Pollution Control Revenue Bonds, Series 2000B
from auction rate securities to variable rate demand notes. This
conversion will likely result in higher interest charges compared to prior year,
but lower than the failed auction rates for this tax exempt debt. See
Financing Transactions
above. If higher interest rates continue on the remaining auction
rate securities outstanding, NPC may seek to convert the debt to other
short-term variable rate structures, term-put structures and/or fixed-rate
structures.
Cross
Default Provisions
None of the financing agreements of NPC
contains a cross-default provision that would result in an event of default by
NPC upon an event of default by SPR or SPPC under any of its financing
agreements. In addition, certain financing agreements of NPC provide
for an event of default if there is a failure under other financing agreements
of NPC to meet payment terms or to observe other covenants that would result in
an acceleration of payments due. Most of these default provisions
(other than ones relating to a failure to pay such other indebtedness when due)
provide for a cure period of 30-60 days from the occurrence of a specified event
during which time NPC may rectify or correct the situation before it becomes an
event of default.
SPPC
recognized net income of $10.8 million for the three months ended June 30, 2008
compared to net income of $10.0 million for the same period in
2007. During the six months ended June 30, 2008, SPPC recognized net
income of approximately $35.1 million compared to $32.0 million for the same
period in 2007.
During
the six months ended June 30, 2008, SPPC paid $63.3 million in dividends to
SPR. On August 4, 2008, SPPC declared a dividend to SPR of $15.0
million.
Gross
margin is presented by SPPC in order to provide information by segment that
management believes aids the reader in determining how profitable the electric
and gas businesses are at the most fundamental level. Gross margin,
which is a “non-GAAP financial measure” as defined in accordance with SEC rules,
provides a measure of income available to support the other operating expenses
of the business and is utilized by management in its analysis of its
business.
SPPC
believes presenting gross margin allows the reader to assess the impact of
SPPC’s regulatory treatment and its overall regulatory environment on a
consistent basis. Gross margin, as a percentage of revenue, is
primarily impacted by the fluctuations in regulated electric and natural gas
supply costs versus the fixed rates collected from customers. While
these fluctuating costs impact gross margin as a percentage of revenue, they
only impact gross margin amounts if the costs cannot be passed through to
customers. Gross margin, which SPPC calculates as operating revenues
less fuel and purchased power costs, provides a measure of income available to
support the other operating expenses of SPPC. For reconciliation to
operating income, see Note 2, Segment Information in the Condensed Notes to
Financial Statements. Gross margin changes based on such factors as
general base rate adjustments (which are required to be filed by statute every
three years) and reflect SPPC’s strategy to increase internal power generation
versus purchased power, which generates no gross margin.
The
components of gross margin were (dollars in thousands):
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
Operating
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
236,415
|
|
|
$
|
245,356
|
|
|
|
-3.6
|
%
|
|
$
|
486,693
|
|
|
$
|
498,235
|
|
|
|
-2.3
|
%
|
Gas
|
|
|
32,152
|
|
|
|
31,378
|
|
|
|
2.5
|
%
|
|
|
117,746
|
|
|
|
116,498
|
|
|
|
1.1
|
%
|
|
|
$
|
268,567
|
|
|
$
|
276,734
|
|
|
|
-3.0
|
%
|
|
$
|
604,439
|
|
|
$
|
614,733
|
|
|
|
-1.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
|
97,363
|
|
|
|
86,309
|
|
|
|
12.8
|
%
|
|
|
187,469
|
|
|
|
169,619
|
|
|
|
10.5
|
%
|
Fuel
for power generation
|
|
|
60,705
|
|
|
|
51,285
|
|
|
|
18.4
|
%
|
|
|
118,292
|
|
|
|
115,354
|
|
|
|
2.5
|
%
|
Deferral
of energy costs-electric-net
|
|
|
(11,695
|
)
|
|
|
18,770
|
|
|
|
-162.3
|
%
|
|
|
(3,188
|
)
|
|
|
32,631
|
|
|
|
-109.8
|
%
|
Gas
purchased for resale
|
|
|
27,632
|
|
|
|
19,862
|
|
|
|
39.1
|
%
|
|
|
94,528
|
|
|
|
91,508
|
|
|
|
3.3
|
%
|
Deferral
of energy costs-gas-net
|
|
|
(3,774
|
)
|
|
|
3,554
|
|
|
|
-206.2
|
%
|
|
|
(1,571
|
)
|
|
|
1,609
|
|
|
|
-197.6
|
%
|
|
|
$
|
170,231
|
|
|
$
|
179,780
|
|
|
|
-5.3
|
%
|
|
$
|
395,530
|
|
|
$
|
410,721
|
|
|
|
-3.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs by Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
146,373
|
|
|
$
|
156,364
|
|
|
|
-6.4
|
%
|
|
$
|
302,573
|
|
|
$
|
317,604
|
|
|
|
-4.7
|
%
|
Gas
|
|
|
23,858
|
|
|
|
23,416
|
|
|
|
1.9
|
%
|
|
|
92,957
|
|
|
|
93,117
|
|
|
|
-0.2
|
%
|
|
|
$
|
170,231
|
|
|
$
|
179,780
|
|
|
|
-5.3
|
%
|
|
$
|
395,530
|
|
|
$
|
410,721
|
|
|
|
-3.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
Margin by Segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
90,042
|
|
|
$
|
88,992
|
|
|
|
1.2
|
%
|
|
$
|
184,120
|
|
|
$
|
180,631
|
|
|
|
1.9
|
%
|
Gas
|
|
|
8,294
|
|
|
|
7,962
|
|
|
|
4.2
|
%
|
|
|
24,789
|
|
|
|
23,381
|
|
|
|
6.0
|
%
|
|
|
$
|
98,336
|
|
|
$
|
96,954
|
|
|
|
1.4
|
%
|
|
$
|
208,909
|
|
|
$
|
204,012
|
|
|
|
2.4
|
%
|
Electric gross margin increased for the
three and six months ended June 30, 2008 compared to the same period in 2007
primarily due to an increase in customer growth partially offset by a decrease
in customer usage. Gas gross margin increased for the three and six
months ended June 30, 2008 compared to the same period in 2007 primarily due to
an increase in customer usage as a result of colder temperatures.
The
causes of significant changes in specific lines comprising the results of
operations are provided below (dollars in thousands except for amounts per
unit):
Electric
Operating Revenue
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
Electric
operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
70,289
|
|
|
$
|
70,347
|
|
|
|
-0.1
|
%
|
|
$
|
160,168
|
|
|
$
|
158,356
|
|
|
|
1.1
|
%
|
Commercial
|
|
|
93,060
|
|
|
|
95,872
|
|
|
|
-2.9
|
%
|
|
|
180,731
|
|
|
|
182,872
|
|
|
|
-1.2
|
%
|
Industrial
|
|
|
62,996
|
|
|
|
71,433
|
|
|
|
-11.8
|
%
|
|
|
128,779
|
|
|
|
141,874
|
|
|
|
-9.2
|
%
|
Retail revenues
|
|
|
226,345
|
|
|
|
237,652
|
|
|
|
-4.8
|
%
|
|
|
469,678
|
|
|
|
483,102
|
|
|
|
-2.8
|
%
|
Other
1
|
|
|
10,070
|
|
|
|
7,704
|
|
|
|
30.7
|
%
|
|
|
17,015
|
|
|
|
15,133
|
|
|
|
12.4
|
%
|
Total
revenues
|
|
$
|
236,415
|
|
|
$
|
245,356
|
|
|
|
-3.6
|
%
|
|
$
|
486,693
|
|
|
$
|
498,235
|
|
|
|
-2.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
sales in thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
megawatt-hours (MWh)
|
|
|
2,047
|
|
|
|
2,088
|
|
|
|
-2.0
|
%
|
|
|
4,197
|
|
|
|
4,238
|
|
|
|
-1.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
retail revenue per MWh
|
|
$
|
110.57
|
|
|
$
|
113.82
|
|
|
|
-2.9
|
%
|
|
$
|
111.91
|
|
|
$
|
113.99
|
|
|
|
-1.8
|
%
|
Retail
revenues decreased for the three and six months ended June 30, 2008 as compared
to the same period in 2007 primarily due to decreases in retail rates, lower
industrial revenue and to a lesser extent a decrease in customer
usage. Retail rates decreased as a result of SPPC’s quarterly BTER
updates. For details see Note 3, Regulatory Actions of the Notes to
Financial Statements in the 2007 Form 10-K. Industrial revenues
decreased primarily due to a new retail service agreement with Newmont Mining
Corporation (Newmont) and the transition of two large industrial customers to
distribution only service and standby service during the second quarter of
2007. These decreases were partially offset by increased customer
count. The average number of residential, commercial and industrial
customers increased by 0.5%, 2.2% and 2.4%, respectively, for the three months
ended June 30, 2008. The average number of residential, commercial
and industrial customers increased by 0.9%, 2.4% and 2.0% respectively for the
six months ended June 30, 2008.
In 2007,
SPPC and Newmont entered into a wholesale power sale agreement and a new form of
retail service, whereby Newmont will sell the electrical output from its
generating plant to SPPC for at least 15 years under a long-term wholesale
purchase power agreement and remain a retail customer of SPPC during at least
that period under the terms of the retail service agreement and pursuant to a
new rate schedule. The terms of these contracts became effective on
June 1, 2008 at which point Newmont moved to a new retail service agreement at a
reduced energy rate, which resulted in decreased electric revenues.
Electric
Operating Revenues – Other increased for the three and six months ended June 30,
2008 as compared to the same period in 2007 primarily due to the increased
transmission revenue.
Gas
Operating Revenues
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
Gas
operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
18,057
|
|
|
$
|
17,496
|
|
|
|
3.2
|
%
|
|
$
|
68,805
|
|
|
$
|
65,208
|
|
|
|
5.5
|
%
|
Commercial
|
|
|
8,475
|
|
|
|
8,492
|
|
|
|
-0.2
|
%
|
|
|
32,884
|
|
|
|
31,839
|
|
|
|
3.3
|
%
|
Industrial
|
|
|
3,866
|
|
|
|
3,706
|
|
|
|
4.3
|
%
|
|
|
11,853
|
|
|
|
11,005
|
|
|
|
7.7
|
%
|
Retail revenues
|
|
|
30,398
|
|
|
|
29,694
|
|
|
|
2.4
|
%
|
|
|
113,542
|
|
|
|
108,052
|
|
|
|
5.1
|
%
|
Wholesale
revenue
|
|
|
1,126
|
|
|
|
1,063
|
|
|
|
5.9
|
%
|
|
|
2,804
|
|
|
|
6,979
|
|
|
|
-59.8
|
%
|
Miscellaneous
|
|
|
628
|
|
|
|
621
|
|
|
|
1.1
|
%
|
|
|
1,400
|
|
|
|
1,467
|
|
|
|
-4.6
|
%
|
Total
revenues
|
|
$
|
32,152
|
|
|
$
|
31,378
|
|
|
|
2.5
|
%
|
|
$
|
117,746
|
|
|
$
|
116,498
|
|
|
|
1.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
sales in thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
decatherms
|
|
|
2,407
|
|
|
|
2,191
|
|
|
|
9.9
|
%
|
|
|
9,189
|
|
|
|
8,479
|
|
|
|
8.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
retail revenue per decatherm
|
|
$
|
12.63
|
|
|
$
|
13.55
|
|
|
|
-6.8
|
%
|
|
$
|
12.36
|
|
|
$
|
12.74
|
|
|
|
-3.0
|
%
|
SPPC’s retail gas revenues
increased for the three and six months ended June 30, 2008 as compared to the
same period in the prior year primarily due to
colder temperatures and
retail customer growth in 2008.
The average
number of retail customers increased by 1.7% and 1.5% for the three and six
months ended June 2008, respectively.
These
increases were partially offset by decreased retail rates as a result of SPPC’s
2007 and 2008 Natural Gas and Propane Deferred Rate Case and BTER
updates. See Note 3, Regulatory Actions of the Notes to Financial
Statements in the 2007 Form 10-K and Note 3, Regulatory Actions of the Condensed
Notes to Financial Statements.
Wholesale revenue for the three month
period ended June 30, 2008 was comparable to the same period in
2007. However, wholesale revenues for the six months ended June 30,
2008, decreased compared to the same period in 2007 primarily due to decreased
availability of gas for wholesale sales during the first quarter of
2008.
Energy
Costs
Energy Costs include Purchased Power
and Fuel for Generation. These costs are dependent upon many factors
which may vary by season or period. As a result, SPPC’s usage and
average cost per MWh of Purchased Power versus Fuel for Generation can vary
significantly as the company meets the demands of the season. These
factors include, but are not limited to:
·
|
Transmission
constraints
|
·
|
Gas
transportation constraints
|
·
|
Natural
gas constraints
|
·
|
Mandated
power purchases; and
|
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
Costs
|
|
$
|
158,069
|
|
|
$
|
137,594
|
|
|
|
14.9
|
%
|
|
$
|
305,761
|
|
|
$
|
284,973
|
|
|
|
7.3
|
%
|
Total
System Demand
|
|
|
2,247
|
|
|
|
2,258
|
|
|
|
-0.5
|
%
|
|
|
4,532
|
|
|
|
4,541
|
|
|
|
-0.2
|
%
|
Average
cost per MWH
|
|
$
|
70.35
|
|
|
$
|
60.94
|
|
|
|
15.4
|
%
|
|
$
|
67.47
|
|
|
$
|
62.76
|
|
|
|
7.5
|
%
|
Energy
costs and the average cost per MWh for the three and six months ended June 30,
2008 increased compared to the same period in 2007 due to higher natural gas
prices.
Purchased
Power
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power
|
|
$
|
97,363
|
|
|
$
|
86,309
|
|
|
|
12.8
|
%
|
|
$
|
187,469
|
|
|
$
|
169,619
|
|
|
|
10.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
power in thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
MWhs
|
|
|
1,391
|
|
|
|
1,450
|
|
|
|
-4.1
|
%
|
|
|
2,684
|
|
|
|
2,780
|
|
|
|
-3.5
|
%
|
Average
cost per MW of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
purchased
power
|
|
$
|
69.99
|
|
|
$
|
59.52
|
|
|
|
17.6
|
%
|
|
$
|
69.85
|
|
|
$
|
61.01
|
|
|
|
14.5
|
%
|
Purchased Power costs and the average
cost per MWh increased for the three and six months ended June 30, 2008 as
compared to the same period in 2007 primarily due to higher natural gas
prices. The volume of MWhs decreased for the three and six months
ended June 30, 2008 as compared to the same period in 2007 primarily due to
increased reliance on internal generation.
Fuel
for Power Generation
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
for power generation
|
|
$
|
60,705
|
|
|
$
|
51,285
|
|
|
|
18.4
|
%
|
|
$
|
118,292
|
|
|
$
|
115,354
|
|
|
|
2.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thousands
of MWh generated
|
|
|
856
|
|
|
|
808
|
|
|
|
5.9
|
%
|
|
|
1,848
|
|
|
|
1,761
|
|
|
|
4.9
|
%
|
Average
fuel cost per MWh
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
generated power
|
|
$
|
70.92
|
|
|
$
|
63.47
|
|
|
|
11.7
|
%
|
|
$
|
64.01
|
|
|
$
|
65.50
|
|
|
|
-2.3
|
%
|
Fuel for power generation and average
cost per MWh increased for the three months ended June 30, 2008, as compared to
the same period in 2007, due to higher natural gas prices, which were partially
offset by a decrease in the cost of hedging instruments.
Fuel
for power generation increased for the six months ended June 30, 2008 as
compared to the same period in 2007 due to higher natural gas prices and the use
of internal generation partially offset by a decrease in the cost of hedging
instruments. The volume of MWhs increased for the six months due to
increased reliance on internal generation, as it was more economical to generate
than purchase power. The average cost per MWh for fuel for power
generation for the six months ended June 30, 2008, as compared to the same
period in 2007, decreased due to a decrease in the cost of hedging instruments
which were offset by an increase in natural gas prices. In addition,
fuel for generation costs decreased as a result of increased reliance on Valmy
in 2008, which is a coal generating facility. The availability of
Valmy in 2007 was limited due to outages. The cost of natural gas is
significantly higher than the cost of coal.
Gas
Purchased for Resale
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
|
|
|
|
|
Change
from
|
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
2008
|
|
|
2007
|
|
|
Prior
Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
purchased for resale
|
|
$
|
27,632
|
|
|
$
|
19,862
|
|
|
|
39.1
|
%
|
|
$
|
94,528
|
|
|
$
|
91,508
|
|
|
|
3.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
purchased for resale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in
thousands of decatherms)
|
|
|
2,565
|
|
|
|
2,322
|
|
|
|
10.5
|
%
|
|
|
9,711
|
|
|
|
9,795
|
|
|
|
-0.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
cost per decatherm
|
|
$
|
10.77
|
|
|
$
|
8.55
|
|
|
|
26.0
|
%
|
|
$
|
9.73
|
|
|
$
|
9.34
|
|
|
|
4.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas purchased for resale and average
cost per decatherm increased for the three and six months ended June 30, 2008 as
compared to the same period in 2007. The increase is primarily due to
an increase in natural gas prices which were offset by lower costs associated
with the settlement of hedging instruments. Volume increased for the
three months ended June 30, 2008 compared to the same period in 2007 primarily
due to cooler weather. For the six months ended June 30, 2008 volume
remained relatively unchanged compared to the same period in the prior
year.
Deferral
of Energy Costs
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
energy costs - electric - net
|
|
$
|
(11,695
|
)
|
|
$
|
18,770
|
|
|
|
-162.3
|
%
|
|
$
|
(3,188
|
)
|
|
$
|
32,631
|
|
|
|
-109.8
|
%
|
Deferred
energy costs - gas - net
|
|
|
(3,774
|
)
|
|
|
3,554
|
|
|
|
-206.2
|
%
|
|
|
(1,571
|
)
|
|
|
1,609
|
|
|
|
-197.6
|
%
|
|
|
$
|
(15,469
|
)
|
|
$
|
22,324
|
|
|
|
|
|
|
$
|
(4,759
|
)
|
|
$
|
34,240
|
|
|
|
|
|
Deferral of energy costs – net
represents the difference between actual fuel and purchased power costs incurred
during the period and amounts recoverable through current rates. To
the extent actual costs exceed amounts recoverable through current rates the
excess is recognized as a reduction in costs. Conversely to the
extent actual costs are less than amounts recoverable through current rates the
difference is recognized as an increase in costs. Deferral of energy
costs – net also include the current amortization of fuel and purchased power
costs previously deferred Reference Note 1, Summary of Significant Accounting
Policies, of the Condensed Notes to Financial Statements for further detail of
deferred energy balances.
Deferral
of energy costs - electric – net for the three months ended June 30, 2008 and
2007 reflect amortization of deferred energy costs of $8.6 and $11.7 million
respectively; and an under-collection of amounts recoverable in rates of $20.3
million in 2008, and an over-collection of $7.1 million in 2007. For
the six months ended June 30, 2008 and 2007, amortization of deferred energy
costs were $18.6 million and $23.7 million, respectively; with an
under-collection of amounts recoverable in rates of $21.8 million in 2008, and
over-collection of $8.9 million in 2007.
Deferred
energy costs - gas - net for the three months ended June 30, 2008 and 2007
reflect amortization of deferred energy costs of ($0.2) million, and $0.2
million, respectively; and an under-collection of amounts recoverable in rates
in 2008 of $3.5 million and an over-collection of $3.4 million in
2007. For the six months ended June 30, 2008 and 2007, amortization
of deferred energy costs were ($0.9) million and $0.6 million, respectively;
with an under-collection of amounts recoverable in rates of $0.7 million and an
over-collection of $1 million, respectively.
Allowance
for Funds Used During Construction (AFUDC)
|
|
Three
Months Ended June 30,
|
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for other funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
used
during construction
|
|
$
|
5,421
|
|
|
$
|
3,365
|
|
|
|
61.1
|
%
|
|
$
|
10,520
|
|
|
$
|
6,834
|
|
|
|
53.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for borrowed funds used during construction
|
|
$
|
4,068
|
|
|
$
|
2,671
|
|
|
|
52.3
|
%
|
|
$
|
7,865
|
|
|
$
|
5,455
|
|
|
|
44.2
|
%
|
|
|
$
|
9,489
|
|
|
$
|
6,036
|
|
|
|
57.2
|
%
|
|
$
|
18,385
|
|
|
$
|
12,289
|
|
|
|
49.6
|
%
|
AFUDC increased for the three and six
months ended June 30, 2008 compared to the same period in 2007 due to an
increase in Construction Work-In-Progress (CWIP) associated with the expansion
of the Tracy Generating Station.
Other
(Income) and Expense
|
|
Three
Months Ended June 30,
|
|
Six
Months Ended June 30,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
2008
|
|
|
2007
|
|
|
Change
from Prior Year %
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
operating expense
|
|
$
|
34,765
|
|
|
$
|
35,994
|
|
|
|
-3.4
|
%
|
|
$
|
68,270
|
|
|
$
|
68,842
|
|
|
|
-0.8
|
%
|
Maintenance
expense
|
|
$
|
7,864
|
|
|
$
|
10,314
|
|
|
|
-24
|
%
|
|
$
|
14,336
|
|
|
$
|
16,595
|
|
|
|
-13.6
|
%
|
Depreciation
and amortization
|
|
$
|
22,018
|
|
|
$
|
20,845
|
|
|
|
5.6
|
%
|
|
$
|
43,458
|
|
|
$
|
41,317
|
|
|
|
5.2
|
%
|
Interest
charges on long-term debt
|
|
$
|
18,578
|
|
|
$
|
16,542
|
|
|
|
12.3
|
%
|
|
$
|
37,340
|
|
|
$
|
32,650
|
|
|
|
14.4
|
%
|
Interest
charges-other
|
|
$
|
1,369
|
|
|
$
|
1,583
|
|
|
|
-13.5
|
%
|
|
$
|
2,991
|
|
|
$
|
3,042
|
|
|
|
-1.7
|
%
|
Interest
accrued on deferred energy
|
|
$
|
627
|
|
|
$
|
(346
|
)
|
|
|
-281.2
|
%
|
|
$
|
1,185
|
|
|
$
|
(1,111
|
)
|
|
|
-206.7
|
%
|
Other
income
|
|
$
|
(1,229
|
)
|
|
$
|
(3,011
|
)
|
|
|
-59.2
|
%
|
|
$
|
(8,964
|
)
|
|
$
|
(4,842
|
)
|
|
|
85.1
|
%
|
Other
expense
|
|
$
|
2,
881
|
|
|
$
|
2,
191
|
|
|
|
31.5
|
%
|
|
$
|
4,681
|
|
|
$
|
4,205
|
|
|
|
11.3
|
%
|
Other operating expense decreased for
the three months ended June 30, 2008 compared to the same period in 2007
primarily due to lower costs for claims.
Other
operating expense decreased slightly for the six months ended June 30, 2008
compared to the same period in 2007 primarily due to a reduction in bad debt
expense and lower costs for claims, partially offset by lower allocations of
administrative and general costs to capital projects.
Maintenance
expense decreased for the three and six months ended June 30, 2008 compared to
the same period in 2007 mainly due to outages in 2007 at Valmy Unit 2 for
turbine and boiler tube repairs.
Depreciation
and amortization expenses increased for the three and six months ended June 30,
2008 compared to the same period in 2007 primarily as a result of increases to
plant-in-service.
Interest
charges on long-term debt for the three months and six months ended June 30,
2008 increased from 2007 due primarily to the issuance of $325 million Series P
General and Refunding Mortgage Notes in June 2007 and higher interest rates for
variable rate debt in 2008, offset partially by the redemptions of the $320
million Series A General and Refunding Mortgage Bonds of $221 million and $99
million in June 2007 and June 2008, respectively. See Note 4,
Long-Term Debt, of the Notes to Financial Statements in the 2007 10-K for
additional information regarding long-term debt and Note 4, Long-Term Debt, of
the Condensed Notes to Financial Statements in this Form 10-Q.
Interest
charges-other for the three months and six months ended June 30, 2008 did not
change significantly.
Interest accrued on deferred energy
costs decreased for the three months and six months ended June 30, 2008 due to
over collected deferred energy in 2008. See Note 1, Summary of
Significant Accounting Policies of the Condensed Notes to Financial Statements
for further details of deferred energy balances.
Other income decreased during the three
months ended June 30, 2008, when compared to the same period in 2007, due
primarily to a refund of expenses in 2007, lower interest income in 2008, and
lower gains associated with disposition of property in 2008.
Other
income increased during the six months ended June 30, 2008, when compared to the
same period in 2007 primarily due to the reinstatement of previously disallowed
costs associated with Pinon Pine, as discussed in Note 3, Regulatory Actions of
the Condensed Notes to Financial Statements and the settlement with Calpine, as
discussed further in Note 6, Commitments and Contingencies of the Condensed
Notes to Financial Statements.
Other
expense increased during the three months and six months ended June 30, 2008,
when compared to the same period in 2007, due to adjustments resulting from the
decision in SPPC’s GRC. See Note 3, Regulatory Actions of the
Condensed Notes to Financial Statements for further information.
ANALYSIS
OF CASH FLOWS
Cash
flows decreased during the six months ended June 30, 2008 compared to the same
period in 2007 due to a decrease in cash from operating and financing
activities, partially offset by a decrease in cash used for investing
activities.
Cash From Operating
Activities.
The decrease in cash from operating activities was
primarily due to increases in energy costs in excess of the energy revenue
collected in rates, prepayment of tax obligations and regulatory expenditures in
2008.
Cash Used By
Investing Activities
. Cash used by investing activities
decreased primarily due to the closing stages of major construction activity at
the Tracy Generating Station, which began in 2006.
Cash From Financing
Activities
. Cash from financing activities decreased primarily
due to a reduction in debt financing in 2008 and an increase in dividend
payments to SPR, partially offset by a $20 million investment by
SPR.
LIQUIDITY
AND CAPITAL RESOURCES
Overall
Liquidity
SPPC’s
primary source of operating cash flows is electric revenues, including the
recovery of previously deferred energy costs. Significant uses of
cash flows from operations include the purchase of electricity and natural gas,
other operating expenses, capital expenditures and the payment of interest on
SPPC’s outstanding indebtedness. Operating cash flows can be
significantly influenced by factors such as weather, regulatory outcomes, and
economic conditions.
Available
Liquidity as of June 30, 2008 (in millions)
|
|
Cash
and Cash Equivalents
|
|
$
|
21.8
|
|
Balance
available on Revolving Credit Facility
(1)
|
|
$
|
153.2
|
|
|
|
|
|
|
|
|
$
|
175.0
|
|
1
As of
August 4, 2008, SPPC had approximately $93.2
million available under
its revolving credit facility.
In
addition to cash on hand and the revolving credit facility, SPPC may issue debt
up to $1.3 billion on a consolidated basis, subject to certain limitations
discussed below.
For the
six months ended June 30, 2008, SPR contributed capital to SPPC of approximately
$20 million for general corporate purposes. For the six months ended
June 30, 2008, SPPC paid dividends to SPR of approximately $63.3
million. On August 4, 2008 SPPC declared an additional dividend to
SPR for $15.0 million.
SPPC
anticipates that it will be able to meet short-term operating costs, such as
fuel and purchased power costs, with internally generated funds, including the
recovery of deferred energy and the use of its revolving credit
facility. To manage liquidity needs as a result of seasonal peaks in
fuel requirement, SPPC may use hedging activities. However, to fund
long-term capital requirements SPPC will likely meet such financial obligations
with a combination of internally generated funds, the use of the revolving
credit facility, issuance of long-term debt, and capital contributions from
SPR.
During
the six months ended June 30, 2008, there were no material changes to
contractual obligations as set forth in SPPC’s 2007 Form 10-K.
Financing
Transactions
Maturity
of General and Refunding Mortgage Bonds, Series A
On June 2, 2008, the 8.00% General and
Refunding Mortgage Bonds, Series A, in the aggregate principal amount of
approximately $99.2 million, matured. SPPC paid for the maturing debt
plus interest with the use of $90 million from its revolving credit facility
plus cash on hand.
Conversion
of Washoe County Water Facilities Refunding Revenue Bonds
In July 2008, SPPC converted the $40
million principal amount, Washoe County, Nevada Water Facilities Refunding
Revenue Bonds Series 2007B bonds, due 2036 (the “Water Bonds”) from auction rate
securities to variable rate demand notes. The purpose of the
conversion was to reduce interest costs and volatility associated with these
bonds. SPPC purchased 100% of the Water Bonds on that date, with the
use of its revolving credit facility and available cash, and will remain the
sole holder of the Water Bonds. These Water Bonds remain outstanding
and have not been retired or cancelled. However, as SPPC is the sole
holder of the Water Bonds, for financial reporting purposes the investment in
the Water Bonds and the indebtedness will be offset for presentation
purposes.
Factors
Affecting Liquidity
Financial
Covenants
SPPC's $350 million Second Amended and
Restated Revolving Credit Agreement dated November 2005, as amended in April
2006, contains two financial maintenance covenants. The first
requires SPPC to maintain a ratio of consolidated indebtedness to consolidated
capital, determined as of the last day of each fiscal quarter, not to exceed
0.68 to 1. The second requires SPPC to maintain a ratio of
consolidated cash flow to consolidated interest expense, determined as of the
last day of each fiscal quarter for the period of four consecutive fiscal
quarters, not to be less than 2.0 to 1. As of June 30, 2008, SPPC was
in compliance with these covenants.
Ability
to Issue Debt
SPPC’s ability to issue debt is
impacted by certain factors such as financing authority from the PUCN, financial
covenants in its financing agreements, and the terms of certain SPR
debt. As of June 30, 2008, SPPC had approximately $745 million of
PUCN financing authority.
The financial covenants under SPPC’s
debt limit SPPC’s borrowing to approximately $839.0 million as of June 30, 2008,
therefore, SPPC is not limited by SPR’s cap on additional indebtedness of $1.3
billion.
Since SPR’s debt covenant limitations
are calculated on a consolidated basis, SPR’s debt covenant limitations may
allow for higher or lower borrowings than $1.3 billion, depending on the
Utilities combined usage of their revolving credit facilities at the time of the
covenant calculations.
Ability
to Issue General and Refunding Mortgage Securities
To the extent that SPPC has the ability
to issue debt under the most restrictive covenants in its financing agreements
and has financing authority to do so from the PUCN, SPPC’s ability to issue
secured debt is still limited by the amount of bondable property or retired
bonds that can be used to issue debt under SPPC’s General and Refunding Mortgage
Indenture (“Indenture”).
As of June 30, 2008, $1.4 billion of
SPPC’s General and Refunding Mortgage Securities were
outstanding. SPPC had the capacity to issue an additional $480
million of General and Refunding Mortgage Securities as of June 30,
2008.
SPPC also has the ability to release
property from the lien of the mortgage indenture on the basis of net property
additions, cash and/or retired bonds. To the extent SPPC releases
property from the lien of its General and Refunding Mortgage Indenture, it will
reduce the amount of securities issuable under that indenture. See
the 2007 Form 10-K for additional information.
Credit
Ratings
SPPC’s debt is rated investment grade
by four Nationally Recognized Statistical Rating Organizations: DBRS, Fitch,
Moody’s and S&P. As of August 1, 2008, the ratings are as
follows:
|
|
Rating
Agency
|
|
|
DBRS
|
Fitch
|
Moody’s
|
S&P
|
SPPC
|
Sr.
Secured Debt
|
BBB
(low)
|
BBB-
|
Baa3
|
BBB
|
On May 15, 2008, S&P increased
SPPC’s secured ratings to BBB from BB+. S&P’s, Moody’s and DBRS’s
rating outlook for SPPC is Stable. Fitch’s rating outlook is
Positive.
A security rating is not a
recommendation to buy, sell or hold securities. Security ratings are
subject to revision and withdrawal at any time by the assigning rating
organization, and each rating should be evaluated independently of any other
rating.
Credit
Ratings of Bond Insurers
Recent
sub-prime mortgage issues have adversely affected the overall financial markets,
generally resulting in increased interest rates, reduced access to the capital
markets, and actual or potential downgrades of bond insurers, among other
negative matters. The interest rates on certain issues of SPPC’s
auction rate securities of approximately
$
348.3 million as of June 30,
2008 are periodically reset through auction
processes. These securities are supported by bond insurance policies
provided by the Insurers and the interest rates on those securities are directly
affected by the rating of the bond insurer due to, among other things, the
impact that such ratings have on the success or failure of the auction
process. S&P’s and Moody’s ratings on these bonds are the
higher
of a bond issues
underlying rating and the Insurer's rating. As of June 30, 2008,
Ambac’s and MBIA’s credit ratings were investment grade or
above. However, FGIC’s credit ratings were below investment
grade. As a result, the bonds insured by FGIC are currently rated at
the investment grade rating of SPPC’s secured debt.
See Credit Ratings
above.
The
uncertainty with the Insurers' credit quality has had an impact on SPPC’s
interest costs for the first six months of 2008. With the ongoing
review of the credit ratings of the Insurers, SPPC is experiencing higher
interest costs for these securities, with interest rates on these bonds set
during the second quarter 2008, ranging from a low of 4.32% to a high of 8.66%,
and a low of 3.64 % to a high of 10.00% for the six months ended June 30, 2008,
with a weighted average interest rate of 5.64% for the six months ended June 30,
2008.
In July
2008, SPPC converted the $40 million of Water Bonds from auction rate securities
to variable rate demand notes. This conversion will likely result in
higher interest charges compared to prior year, but lower than the failed
auction rates for this tax exempt debt. See
Financing Transactions
above. If higher interest rates continue on the remaining
auction rate securities outstanding, SPPC may seek to convert the debt to other
short-term variable rate structures, term-put structures and/or fixed-rate
structures.
Cross
Default Provisions
SPPC’s financing agreements do not
contain any cross-default provisions that would result in an event of default by
SPPC upon an event of default by SPR or NPC under any of their respective
financing agreements. Certain financing agreements of SPPC provide
for an event of default if there is a failure under other financing agreements
of SPPC to meet payment terms or to observe other covenants that would result in
an acceleration of payments due. Most of these default provisions
(other than ones relating to a failure to pay such other indebtedness when due)
provide for a cure period of 30-60 days from the occurrence of a specified event
during which time SPPC may rectify or correct the situation before it becomes an
event of default.
REGULATORY
PROCEEDINGS (UTILITIES)
SPR is a “holding company” under the
Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result,
SPR and all of its subsidiaries (whether or not engaged in any energy related
business) are required to maintain books, accounts and other records in
accordance with FERC regulations and to make them available to the FERC, the
PUCN and CPUC. In addition, the PUCN, California Public Utilities
Commission (CPUC), or the FERC have the authority to review allocations of costs
of non-power goods and administrative services among SPR and its
subsidiaries. The FERC has the authority generally to require that
rates subject to its jurisdiction be just and reasonable and in this context
would continue to be able to, among other things, review transactions between
SPR, NPC and/or SPPC and/or any other affiliated company.
The
Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC,
the CPUC with respect to rates, standards of service, siting of and necessity
for generation and certain transmission facilities, accounting, issuance of
securities and other matters with respect to electric distribution and
transmission operations. NPC and SPPC submit Integrated Resource
Plans (IRPs) to the PUCN for approval.
Under
federal law, the Utilities are subject to certain jurisdictional regulation,
primarily by the FERC. The FERC has jurisdiction under the Federal
Power Act with respect to rates, service, interconnection, accounting and other
matters in connection with the Utilities’ sale of electricity for resale and
interstate transmission. The FERC also has jurisdiction over the
natural gas pipeline companies from which the Utilities take
service.
As a
result of regulation, many of the fundamental business decisions of the
Utilities, as well as the rate of return they are permitted to earn on their
utility assets, are subject to the approval of governmental
agencies.
The
Utilities are required to file annual electric and gas Deferred Energy
Accounting Adjustment (DEAA) cases on March 1 as mandated by the 2007 Nevada
Legislature, quarterly Base Tariff Energy Rate (BTER) updates for the Utilities’
electric and gas departments, and triennial GRCs in Nevada. A DEAA
case is filed to recover/refund any under/over collection of prior energy costs
and the BTER updates recover current energy costs. As of June 30,
2008, NPC’s and SPPC’s balance sheets included approximately $247.7 million and
credit of $29.0 million, respectively, of deferred energy costs of which $239.0
million and a credit of $2.1 million had been previously approved for collection
over various periods. The remaining amounts will be requested in
future DEAA filings. Refer to Note 1, Summary of Significant
Accounting Policies, of the Condensed Notes to Financial
Statements. A GRC filing is to set rates to recover operation and
maintenance expenses, depreciation, taxes and provide a return on invested
capital.
Rate case
applications filed in 2007 and 2008, as well as other regulatory matters such
as, the Utilities’ IRPs and subsequent amendments, other Nevada matters,
California matters and FERC matters, are discussed in more detail in Note 3,
Regulatory Actions, of the Condensed Notes to Financial Statements, and Note 3,
Regulatory Actions of the Notes to Financial Statements in the 2007 Form
10-K.
RECENT
PRONOUNCEMENTS
See Note
1, Summary of Significant Accounting Policies of the Condensed Notes to
Financial Statements, for discussion of accounting policies and recent
pronouncements.
ITEM
3.
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest
Rate Risk
As of
June 30, 2008, SPR, NPC and SPPC have evaluated their risk related to financial
instruments whose values are subject to market sensitivity. Such
instruments are fixed and variable rate debt. Fair market value is
determined using quoted market price for the same or similar issues or on the
current rates offered for debt of the same remaining maturities (dollars in
thousands).
|
|
Expected
Maturity Date
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
Value
|
|
Long-term
Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPR
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
Rate
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
63,670
|
|
|
$
|
460,539
|
|
|
$
|
524,209
|
|
|
$
|
530,352
|
|
Average Interest Rate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7.80
|
%
|
|
|
7.77
|
%
|
|
|
7.77
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
Rate
|
|
$
|
3
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
364,000
|
|
|
$
|
130,000
|
|
|
$
|
1,786,579
|
|
|
$
|
2,280,582
|
|
|
$
|
2,273,162
|
|
Average Interest Rate
|
|
|
8.17
|
%
|
|
|
-
|
|
|
|
-
|
|
|
|
8.14
|
%
|
|
|
6.50
|
%
|
|
|
6.34
|
%
|
|
|
6.64
|
%
|
|
|
|
|
Variable Rate
|
|
$
|
-
|
|
|
$
|
15,000
|
|
|
$
|
140,000
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
192,500
|
|
|
$
|
347,500
|
|
|
$
|
347,500
|
|
Average Interest Rate
|
|
|
-
|
|
|
|
5.26
|
%
|
|
|
3.24
|
%
|
|
|
-
|
|
|
|
-
|
|
|
|
5.98
|
%
|
|
|
4.85
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SPPC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
Rate
|
|
$
|
1,062
|
|
|
$
|
600
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
100,000
|
|
|
$
|
625,000
|
|
|
$
|
726,662
|
|
|
$
|
716,647
|
|
Average Interest Rate
|
|
|
6.40
|
%
|
|
|
6.40
|
%
|
|
|
-
|
|
|
|
-
|
|
|
|
6.25
|
%
|
|
|
6.39
|
%
|
|
|
6.37
|
%
|
|
|
|
|
Variable Rate
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
178,000
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
348,250
|
|
|
$
|
526,250
|
|
|
$
|
526,250
|
|
Average Interest Rate
|
|
|
-
|
|
|
|
-
|
|
|
|
3.34
|
%
|
|
|
-
|
|
|
|
-
|
|
|
|
5.64
|
%
|
|
|
4.86
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt
|
|
$
|
1,065
|
|
|
$
|
15,600
|
|
|
$
|
318,000
|
|
|
$
|
364,000
|
|
|
$
|
293,670
|
|
|
$
|
3,412,868
|
|
|
$
|
4,405,203
|
|
|
$
|
4,393,911
|
|
Commodity
Price Risk
See the 2007 Form 10-K, Item 7A,
Quantitative and Qualitative Disclosures About Market Risk, Commodity Price
Risk, for a discussion of Commodity Price Risk. No material changes
in commodity risk have occurred since December 31, 2007.
Credit
Risk
The
Utilities monitor and manage credit risk with their trading
counterparties. Credit risk is defined as the possibility that a
counterparty to one or more contracts will be unable or unwilling to fulfill its
financial or physical obligations to the Utilities because of the counterparty’s
financial condition. The Utilities’ credit risk associated with trading
counterparties was approximately $865.4 million as of June 30, 2008, which
increased from the $4.9 million balance at December 31, 2007 and the $58.9
million balance at June 30, 2007. Approximately $412.2 million of the
increase from December 31, 2007 is primarily the result of increased prices of
oil and natural gas during the first two quarters of 2008. The remainder
of the increase from December 31, 2007, or $453.2 million, is due to the
addition of a 10-year tolling agreement with Dynegy Power Marketing for the
entire output of the 570 MW Griffith Energy facility executed during the second
quarter of 2008.