MDU 3rd Quarter 2006 10-Q
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
X
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
|
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
The Quarterly Period Ended September 30, 2006
OR
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
For
the Transition Period from _____________ to ______________
Commission
file number 1-3480
MDU
Resources Group, Inc.
(Exact
name of registrant as specified in its charter)
Delaware
|
|
41-0423660
|
(State
or other jurisdiction of incorporation
or organization)
|
|
(I.R.S.
Employer Identification
No.)
|
1200
West Century Avenue
P.O.
Box 5650
Bismarck,
North Dakota 58506-5650
(Address
of principal executive offices)
(Zip
Code)
(701)
530-1000
(Registrant's
telephone number, including area code)
Indicate
by check mark whether the 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 x
No o.
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check
one):
Large
accelerated filer x
Accelerated filer o
Non-accelerated filer o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o
No x.
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock, as of October 27, 2006:
180,881,227 shares.
DEFINITIONS
The
following abbreviations and acronyms used in this Form 10-Q are defined
below:
Abbreviation
or Acronym
2005
Annual Report
|
Company's
Annual Report on Form 10-K for the year ended December 31,
2005
|
ALJ
|
Administrative
Law Judge
|
Alusa
|
Tecnica
de Engenharia Eletrica - Alusa
|
Anadarko
|
Anadarko
Petroleum Corporation
|
APB
|
Accounting
Principles Board
|
APB
Opinion No. 25
|
Accounting
for Stock-Based Compensation
|
APB
Opinion No. 28
|
Interim
Financial Reporting
|
Badger
Hills Project
|
Tongue
River-Badger Hills Project
|
Bbl
|
Barrel
|
BER
|
Montana
Board of Environmental Review
|
Bitter
Creek
|
Bitter
Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI
Holdings
|
BLM
|
Bureau
of Land Management
|
Brascan
|
Brascan
Brasil Ltda.
|
Brazilian
Transmission Lines
|
Company’s
equity method investment in companies owning ECTE, ENTE and
ERTE
|
Brush
Generating Facility
|
213
MW of natural gas-fired electric generating facilities located
near Brush,
Colorado
|
Carib
Power
|
Carib
Power Management LLC
|
Cascade
|
Cascade
Natural Gas Corporation
|
CBNG
|
Coalbed
natural gas
|
CELESC
|
Centrais
Elétricas de Santa Catarina S.A.
|
CEM
|
Colorado
Energy Management, LLC, a direct wholly owned subsidiary of Centennial
Resources
|
CEMIG
|
Companhia
Energética de Minas Gerais - CEMIG
|
Centennial
|
Centennial
Energy Holdings, Inc., a direct wholly owned subsidiary of the
Company
|
Centennial
Capital
|
Centennial
Holdings Capital LLC, a direct wholly owned subsidiary of
Centennial
|
Centennial
International
|
Centennial
Energy Resources International, Inc., a direct wholly owned subsidiary
of
Centennial Resources
|
Centennial
Power
|
Centennial
Power, Inc., a direct wholly owned subsidiary of Centennial
Resources
|
Centennial
Resources
|
Centennial
Energy Resources LLC, a direct wholly owned subsidiary of
Centennial
|
Clean
Water Act
|
Federal
Clean Water Act
|
Colorado
Federal District Court
|
U.S.
District Court for the District of Colorado
|
Company
|
MDU
Resources Group, Inc.
|
D.C.
Appeals Court
|
U.S.
Court of Appeals for the District of Columbia Circuit
|
dk
|
Decatherm
|
DRC
|
Dakota
Resource Council
|
ECTE
|
Empresa
Catarinense de Transmissão de Energia S.A.
|
EITF
|
Emerging
Issues Task Force
|
EITF
No. 04-6
|
Accounting
for Stripping Costs in the Mining Industry
|
EIS
|
Environmental
Impact Statement
|
Elk
Basin Storage Reservoir
|
Natural
gas storage reservoir located in Montana and Wyoming owned by Williston
Basin
|
ENTE
|
Empresa
Norte de Transmissão de Energia S.A.
|
EPA
|
U.S.
Environmental Protection Agency
|
ERTE
|
Empresa
Regional de Transmissão de Energia S.A.
|
Exchange
Act
|
Securities
Exchange Act of 1934
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy Regulatory Commission
|
Fidelity
|
Fidelity
Exploration & Production Company, a direct wholly owned subsidiary of
WBI Holdings
|
FIN
|
FASB
Interpretation No.
|
FIN
48
|
Accounting
for Uncertainty in Income Taxes
|
Great
Plains
|
Great
Plains Natural Gas Co., a public utility division of the
Company
|
Grynberg
|
Jack
J. Grynberg
|
Hardin
Generating Facility
|
116-MW
coal-fired electric generating facility near Hardin,
Montana
|
Hart-Scott-Rodino
Act
|
Hart-Scott-Rodino
Antitrust Improvements Act
|
Hartwell
|
Hartwell
Energy Limited Partnership
|
Hobbs
Power
|
Hobbs
Power Funding, LLC, an indirect subsidiary of ArcLight Energy Partners
Fund III, L.P.
|
Howell
|
Howell
Petroleum Corporation
|
Innovatum
|
Innovatum
Inc., an indirect wholly owned subsidiary of WBI
Holdings
|
Knife
River
|
Knife
River Corporation, a direct wholly owned subsidiary of
Centennial
|
kW
|
Kilowatts
|
kWh
|
Kilowatt-hour
|
LPP
|
Lea
Power Partners, LLC, a direct wholly owned subsidiary of Centennial
Power
|
LWG
|
Lower
Willamette Group
|
MBbls
|
Thousands
of barrels of oil or other liquid hydrocarbons
|
MBI
|
Morse
Bros., Inc., an indirect wholly owned subsidiary of Knife
River
|
Mcf
|
Thousand
cubic feet
|
MDU
Brasil
|
MDU
Brasil Ltda., an indirect wholly owned subsidiary of Centennial
International
|
MDU
Construction Services
|
MDU
Construction Services Group, Inc., formerly Utility Services, Inc.
(name
change was effective December 23, 2005), a direct wholly owned
subsidiary
of Centennial
|
MMBtu
|
Million
Btu
|
MMcf
|
Million
cubic feet
|
MMdk
|
Million
decatherms
|
Montana-Dakota
|
Montana-Dakota
Utilities Co., a public utility division of the Company
|
Montana
DEQ
|
Montana
State Department of Environmental Quality
|
Montana
Federal District Court
|
U.S.
District Court for the District of Montana
|
MNPUC
|
Minnesota
Public Utilities Commission
|
MPX
|
MPX
Termoceara Ltda.
|
MW
|
Megawatt
|
Nance
Petroleum
|
Nance
Petroleum Corporation, a wholly owned subsidiary of
St. Mary
|
ND
Health Department
|
North
Dakota Department of Health
|
NEPA
|
National
Environmental Policy Act
|
NHPA
|
National
Historic Preservation Act
|
Ninth
Circuit
|
U.S.
Ninth Circuit Court of Appeals
|
NPRC
|
Northern
Plains Resource Council
|
Order
on Rehearing
|
Order
on Rehearing and Compliance and Remanding Certain Issues for
Hearing
|
Oregon
DEQ
|
Oregon
State Department of Environmental Quality
|
Prairielands
|
Prairielands
Energy Marketing, Inc., an indirect wholly owned subsidiary of
WBI
Holdings
|
SEIS
|
Supplemental
Environmental Impact Statement
|
SFAS
|
Statement
of Financial Accounting Standards
|
SFAS
No. 87
|
Employers’
Accounting for Pensions
|
SFAS
No. 109
|
Accounting
for Income Taxes
|
SFAS
No. 123
|
Accounting
for Stock-Based Compensation
|
SFAS
No. 123 (revised)
|
Share-Based
Payment (revised 2004)
|
SFAS
No. 142
|
Goodwill
and Other Intangible Assets
|
SFAS
No. 144
|
Accounting
for the Impairment of Disposal of Long-Lived Assets
|
SFAS
No. 148
|
Accounting
for Stock-Based Compensation - Transition and Disclosure - an amendment
of
SFAS No. 123
|
SFAS
No. 158
|
Employers’
Accounting for Defined Benefit Pension and Other
Postretirement
Plans
|
SIP
|
State
Implementation Plan
|
St.
Mary
|
St.
Mary Land & Exploration Company
|
Termoceara
Generating Facility
|
220-MW
natural gas-fired electric generating facility in the Brazilian
state of
Ceara (49 percent ownership)
|
Trinity
Generating Facility
|
225-MW
natural gas-fired electric generating facility in Trinidad and
Tobago
(49.99 percent ownership)
|
TRWUA
|
Tongue
River Water Users’ Association
|
WBI
Holdings
|
WBI
Holdings, Inc., a direct wholly owned subsidiary of
Centennial
|
Williston
Basin
|
Williston
Basin Interstate Pipeline Company, an indirect wholly owned subsidiary
of
WBI Holdings
|
Wyoming
Federal District Court
|
U.S.
District Court for the District of
Wyoming
|
INTRODUCTION
The
Company is a diversified natural resource company, which was incorporated
under
the laws of the state of Delaware in 1924. Its principal executive offices
are
at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650,
telephone (701) 530-1000.
Montana-Dakota,
through the electric and natural gas distribution segments,
generates, transmits and distributes electricity and distributes natural
gas in
Montana, North Dakota, South Dakota and Wyoming. Great Plains distributes
natural gas in western Minnesota and southeastern North Dakota. These operations
also supply related value-added products and services.
The
Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings
(comprised of the pipeline and energy services and the natural gas and oil
production segments), Knife River (construction materials and mining segment),
MDU Construction Services (construction services segment), Centennial Resources
(independent power production segment) and Centennial Capital (reflected
in the
Other category). For more information on the Company’s business segments, see
Note 16.
On
May
11, 2006, the Company’s Board of Directors approved a three-for-two common stock
split. For more information on the common stock split, see Note 4.
INDEX
Part
I -- Financial Information
Consolidated
Statements of Income --
Three
and
Nine Months Ended September 30, 2006 and 2005
Consolidated
Balance Sheets --
September
30, 2006 and 2005, and December 31, 2005
Consolidated
Statements of Cash Flows --
Nine
Months Ended September 30, 2006 and 2005
Notes
to
Consolidated Financial Statements
Management's
Discussion and Analysis of Financial
Condition
and Results of Operations
Quantitative
and Qualitative Disclosures About Market Risk
Controls
and Procedures
Part
II -- Other Information
Legal
Proceedings
Risk
Factors
Unregistered
Sales of Equity Securities and Use of Proceeds
Exhibits
Signatures
Exhibit
Index
Exhibits
PART
I -- FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
STATEMENTS OF INCOME
(Unaudited)
|
|
Three
Months
Ended
September
30,
|
|
Nine
Months
Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands, except per share amounts)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
$
|
171,954
|
|
$
|
185,419
|
|
$
|
633,590
|
|
$
|
621,357
|
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
1,018,682
|
|
|
880,758
|
|
|
2,344,981
|
|
|
1,817,744
|
|
|
|
|
1,190,636
|
|
|
1,066,177
|
|
|
2,978,571
|
|
|
2,439,101
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
20,727
|
|
|
16,286
|
|
|
53,973
|
|
|
47,019
|
|
Purchased
natural gas sold
|
|
|
28,648
|
|
|
33,235
|
|
|
194,969
|
|
|
193,407
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
|
40,012
|
|
|
38,310
|
|
|
120,112
|
|
|
114,799
|
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
812,899
|
|
|
735,045
|
|
|
1,906,366
|
|
|
1,501,835
|
|
Depreciation,
depletion and amortization
|
|
|
71,312
|
|
|
60,504
|
|
|
203,675
|
|
|
164,798
|
|
Taxes,
other than income
|
|
|
32,476
|
|
|
32,894
|
|
|
98,629
|
|
|
88,099
|
|
|
|
|
1,006,074
|
|
|
916,274
|
|
|
2,577,724
|
|
|
2,109,957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
184,562
|
|
|
149,903
|
|
|
400,847
|
|
|
329,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from equity method investments
|
|
|
2,829
|
|
|
1,800
|
|
|
8,931
|
|
|
18,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
income
|
|
|
4,502
|
|
|
1,762
|
|
|
9,809
|
|
|
4,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
20,240
|
|
|
14,091
|
|
|
53,402
|
|
|
40,282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
171,653
|
|
|
139,374
|
|
|
366,185
|
|
|
311,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
61,555
|
|
|
51,851
|
|
|
130,801
|
|
|
109,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
|
|
110,098
|
|
|
87,523
|
|
|
235,384
|
|
|
202,646
|
|
Loss
from discontinued operations, net of tax (Note
3)
|
|
|
(1,611
|
)
|
|
(300
|
)
|
|
(2,208
|
)
|
|
(830
|
)
|
Net
income
|
|
|
108,487
|
|
|
87,223
|
|
|
233,176
|
|
|
201,816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
on preferred stocks
|
|
|
171
|
|
|
171
|
|
|
514
|
|
|
513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
on common stock
|
|
$
|
108,316
|
|
$
|
87,052
|
|
$
|
232,662
|
|
$
|
201,303
|
|
Earnings
per common share - basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
.61
|
|
$
|
.49
|
|
$
|
1.30
|
|
$
|
1.14
|
|
Discontinued
operations, net of tax
|
|
|
(.01
|
)
|
|
---
|
|
|
(.01
|
)
|
|
(.01
|
)
|
Earnings
per common share - basic
|
|
$
|
.60
|
|
$
|
.49
|
|
$
|
1.29
|
|
$
|
1.13
|
|
Earnings
per common share - diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
.61
|
|
$
|
.48
|
|
$
|
1.30
|
|
$
|
1.13
|
|
Discontinued
operations, net of tax
|
|
|
(.01
|
)
|
|
---
|
|
|
(.01
|
)
|
|
(.01
|
)
|
Earnings
per common share - diluted
|
|
$
|
.60
|
|
$
|
.48
|
|
$
|
1.29
|
|
$
|
1.12
|
|
Dividends
per common share
|
|
$
|
.1350
|
|
$
|
.1267
|
|
$
|
.3884
|
|
$
|
.3667
|
|
Weighted
average common shares outstanding -- basic
|
|
|
180,291
|
|
|
179,429
|
|
|
181,010
|
|
|
177,907
|
|
Weighted
average common shares outstanding -- diluted
|
|
|
181,307
|
|
|
180,584
|
|
|
181,010
|
|
|
178,953
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
BALANCE SHEETS
(Unaudited)
|
|
September
30,
2006
|
|
September
30,
2005
|
|
December
31,
2005
|
|
(In
thousands, except shares and per share amounts)
|
|
ASSETS
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
70,205
|
|
$
|
98,392
|
|
$
|
107,435
|
|
Receivables,
net
|
|
|
721,770
|
|
|
632,207
|
|
|
603,959
|
|
Inventories
|
|
|
226,398
|
|
|
193,934
|
|
|
172,201
|
|
Deferred
income taxes
|
|
|
8,698
|
|
|
3,416
|
|
|
9,062
|
|
Prepayments
and other current assets
|
|
|
80,545
|
|
|
42,100
|
|
|
40,539
|
|
|
|
|
1,107,616
|
|
|
970,049
|
|
|
933,196
|
|
Investments
|
|
|
155,989
|
|
|
100,954
|
|
|
98,217
|
|
Property,
plant and equipment
|
|
|
5,044,720
|
|
|
4,397,510
|
|
|
4,594,355
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
1,713,860
|
|
|
1,490,465
|
|
|
1,544,462
|
|
|
|
|
3,330,860
|
|
|
2,907,045
|
|
|
3,049,893
|
|
Deferred
charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
237,839
|
|
|
214,939
|
|
|
230,865
|
|
Other
intangible assets, net
|
|
|
29,850
|
|
|
28,487
|
|
|
19,059
|
|
Other
|
|
|
104,402
|
|
|
90,256
|
|
|
92,332
|
|
|
|
|
372,091
|
|
|
333,682
|
|
|
342,256
|
|
|
|
$
|
4,966,556
|
|
$
|
4,311,730
|
|
$
|
4,423,562
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt due within one year
|
|
$
|
98,980
|
|
$
|
86,802
|
|
$
|
101,758
|
|
Accounts
payable
|
|
|
319,415
|
|
|
300,509
|
|
|
269,021
|
|
Taxes
payable
|
|
|
46,633
|
|
|
75,263
|
|
|
50,533
|
|
Dividends
payable
|
|
|
24,569
|
|
|
22,935
|
|
|
22,951
|
|
Other
accrued liabilities
|
|
|
166,582
|
|
|
255,355
|
|
|
184,665
|
|
|
|
|
656,179
|
|
|
740,864
|
|
|
628,928
|
|
Long-term
debt
|
|
|
1,307,050
|
|
|
1,047,245
|
|
|
1,104,752
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
587,001
|
|
|
473,419
|
|
|
526,176
|
|
Other
liabilities
|
|
|
295,496
|
|
|
264,188
|
|
|
272,084
|
|
|
|
|
882,497
|
|
|
737,607
|
|
|
798,260
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
|
|
|
|
|
|
Preferred
stocks
|
|
|
15,000
|
|
|
15,000
|
|
|
15,000
|
|
Common
stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
|
|
|
|
|
|
|
Shares
issued -- $1.00 par value 181,279,379 at September 30, 2006, 120,191,877
at September 30, 2005 and 120,262,786 at December 31, 2005
|
|
|
181,279
|
|
|
120,192
|
|
|
120,263
|
|
Other
paid-in capital
|
|
|
872,973
|
|
|
901,302
|
|
|
909,006
|
|
Retained
earnings
|
|
|
1,046,933
|
|
|
834,567
|
|
|
884,795
|
|
Accumulated
other comprehensive income (loss)
|
|
|
8,271
|
|
|
(81,421
|
)
|
|
(33,816
|
)
|
Treasury
stock at cost - 538,921 shares
at
September 30, 2006, 359,281 shares at September 30, 2005 and December
31,
2005
|
|
|
(3,626
|
)
|
|
(3,626
|
)
|
|
(3,626
|
)
|
Total
common stockholders’ equity
|
|
|
2,105,830
|
|
|
1,771,014
|
|
|
1,876,622
|
|
Total
stockholders’ equity
|
|
|
2,120,830
|
|
|
1,786,014
|
|
|
1,891,622
|
|
|
|
$
|
4,966,556
|
|
$
|
4,311,730
|
|
$
|
4,423,562
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
Net
income
|
|
$
|
233,176
|
|
$
|
201,816
|
|
Loss
from discontinued operations, net of tax
|
|
|
2,208
|
|
|
830
|
|
Income
from continuing operations
|
|
|
235,384
|
|
|
202,646
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
203,675
|
|
|
164,798
|
|
Earnings,
net of distributions, from equity method investments
|
|
|
(3,164
|
)
|
|
(14,235
|
)
|
Deferred
income taxes
|
|
|
28,945
|
|
|
11,747
|
|
Changes
in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
Receivables
|
|
|
(102,271
|
)
|
|
(163,007
|
)
|
Inventories
|
|
|
(51,059
|
)
|
|
(47,781
|
)
|
Other
current assets
|
|
|
(13,814
|
)
|
|
(1,544
|
)
|
Accounts
payable
|
|
|
65,283
|
|
|
88,358
|
|
Other
current liabilities
|
|
|
12,220
|
|
|
49,585
|
|
Other
noncurrent changes
|
|
|
13,740
|
|
|
13,421
|
|
Net
cash provided by continuing operations
|
|
|
388,939
|
|
|
303,988
|
|
Net
cash used in discontinued operations
|
|
|
(297
|
)
|
|
(232
|
)
|
Net
cash provided by operating activities
|
|
|
388,642
|
|
|
303,756
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(398,079
|
)
|
|
(341,532
|
)
|
Acquisitions,
net of cash acquired
|
|
|
(124,240
|
)
|
|
(162,774
|
)
|
Net
proceeds from sale or disposition of property
|
|
|
19,342
|
|
|
31,643
|
|
Investments
|
|
|
(55,956
|
)
|
|
(1,863
|
)
|
Proceeds
from sale of equity method investment
|
|
|
---
|
|
|
38,166
|
|
Net
cash used in continuing operations
|
|
|
(558,933
|
)
|
|
(436,360
|
)
|
Net
cash used in discontinued operations
|
|
|
(24
|
)
|
|
(77
|
)
|
Net
cash used in investing activities
|
|
|
(558,957
|
)
|
|
(436,437
|
)
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
Issuance
of long-term debt
|
|
|
394,504
|
|
|
292,228
|
|
Repayment
of long-term debt
|
|
|
(206,437
|
)
|
|
(104,038
|
)
|
Proceeds
from issuance of common stock
|
|
|
13,255
|
|
|
7,858
|
|
Dividends
paid
|
|
|
(68,881
|
)
|
|
(64,616
|
)
|
Tax
benefit on stock-based compensation
|
|
|
2,050
|
|
|
---
|
|
Net
cash provided by continuing operations
|
|
|
134,491
|
|
|
131,432
|
|
Net
cash provided by discontinued operations
|
|
|
248
|
|
|
264
|
|
Net
cash provided by financing activities
|
|
|
134,739
|
|
|
131,696
|
|
Effect
of exchange rate changes on cash and cash
equivalents
|
|
|
(1,654
|
)
|
|
---
|
|
Decrease
in cash and cash equivalents
|
|
|
(37,230
|
)
|
|
(985
|
)
|
Cash
and cash equivalents -- beginning of year
|
|
|
107,435
|
|
|
99,377
|
|
Cash
and cash equivalents -- end of period
|
|
$
|
70,205
|
|
$
|
98,392
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS
September
30, 2006 and 2005
(Unaudited)
1.
Basis
of presentation
The
accompanying consolidated interim financial statements were prepared in
conformity with the basis of presentation reflected in the consolidated
financial statements included in the Company's 2005 Annual Report, and the
standards of accounting measurement set forth in APB Opinion No. 28 and any
amendments thereto adopted by the FASB. Interim financial statements do not
include all disclosures provided in annual financial statements and,
accordingly, these financial statements should be read in conjunction with
those
appearing in the 2005 Annual Report. The information is unaudited but includes
all adjustments that are, in the opinion of management, necessary for a fair
presentation of the accompanying consolidated interim financial statements.
2.
Seasonality
of operations
Some
of
the Company's operations are highly seasonal and revenues from, and certain
expenses for, such operations may fluctuate significantly among quarterly
periods. Accordingly, the interim results for particular businesses, and
for the
Company as a whole, may not be indicative of results for the full fiscal
year.
3.
Discontinued
operations
Innovatum,
a component of the pipeline and energy services segment, specializes in cable
and pipeline magnetization and location. During the third quarter of 2006,
the
Company initiated a plan to sell Innovatum within the next year because the
Company has determined that Innovatum is a non-strategic asset. The Company
does
not expect to have any involvement in the operations of Innovatum after the
sale.
In
accordance with SFAS No. 144, the Consolidated Statements of Income,
Consolidated Statements of Cash Flows, and related Notes to Consolidated
Financial Statements for current and prior periods have been restated to
present
the results of operations of Innovatum as a discontinued operation. In addition,
the assets and liabilities of Innovatum have been treated as held for sale
and,
as a result, no depreciation, depletion and amortization expense will be
recorded. The Company recorded a loss of $4.3 million (before tax) during
the
third quarter of 2006 to write down goodwill (see Note 14), with the remaining
assets of Innovatum recorded at net realizable value less estimated selling
costs. The loss on the write-down has been excluded from continuing operations
and recorded in discontinued operations, net of tax, in the Consolidated
Statements of Income.
Operating
results related to Innovatum were as follows:
|
|
Three
Months
Ended
September
30,
|
|
Nine
Months
Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$
|
654
|
|
$
|
685
|
|
$
|
1,796
|
|
$
|
2,228
|
|
Loss
from discontinued operations
|
|
|
(4,743
|
)
|
|
(435
|
)
|
|
(5,606
|
)
|
|
(1,207
|
)
|
Income
tax benefit
|
|
|
3,132
|
|
|
135
|
|
|
3,398
|
|
|
377
|
|
Net
loss from discontinued operations
|
|
$
|
(1,611
|
)
|
$
|
(300
|
)
|
$
|
(2,208
|
)
|
$
|
(830
|
)
|
The
income tax benefit for the three and nine months ended September 30, 2006,
is
larger than the customary relationship between the income tax benefit and
the
loss before tax due to an estimated capital loss tax benefit (which reflects
the
effect of the $4.0 million and $4.3 million goodwill impairments in 2004
and
2006, respectively) the Company will realize from the sale of the Innovatum
stock.
The
carrying amounts of the major assets and liabilities related to Innovatum
are as
follows:
|
|
September
30, 2006
|
|
September
30, 2005
|
|
December
31, 2005
|
|
|
|
(In
thousands)
|
|
Inventories
|
|
$
|
1,164
|
|
$
|
1,144
|
|
$
|
988
|
|
Other
current assets
|
|
|
126
|
|
|
147
|
|
|
863
|
|
Net
property, plant and equipment
|
|
|
234
|
|
|
416
|
|
|
361
|
|
Goodwill
|
|
|
---
|
|
|
4,305
|
|
|
4,305
|
|
Deferred
charges and other assets
|
|
|
3,491
|
|
|
487
|
|
|
478
|
|
Total
assets
|
|
$
|
5,015
|
|
$
|
6,499
|
|
$
|
6,995
|
|
Current
liabilities
|
|
$
|
28
|
|
$
|
203
|
|
$
|
36
|
|
Long-term
debt
|
|
|
4,013
|
|
|
10,118
|
|
|
3,765
|
|
Deferred
credits
|
|
|
188
|
|
|
265
|
|
|
209
|
|
Total
liabilities
|
|
$
|
4,229
|
|
$
|
10,586
|
|
$
|
4,010
|
|
4.
Common
stock split
On
May
11, 2006, the Company's Board of Directors approved a three-for-two common
stock
split to be effected in the form of a 50 percent common stock dividend. The
additional shares of common stock were distributed on July 26, 2006, to common
stockholders of record on July 12, 2006. Certain common stock information
appearing in the accompanying consolidated financial statements has been
restated in accordance with accounting principles generally accepted in the
United States of America to give retroactive effect to the stock split.
Additionally, preference share purchase rights have been appropriately adjusted
to reflect the effects of the split.
5.
Allowance
for doubtful accounts
The
Company's allowance for doubtful accounts as of September 30, 2006 and 2005,
and
December 31, 2005, was $6.0 million, $8.6 million and $8.0 million,
respectively.
6.
Natural
gas in underground storage
Natural
gas in underground storage for the Company's regulated operations is carried
at
cost using the last-in, first-out method. The portion of the cost of natural
gas
in underground storage expected to be used within one year was included in
inventories and was $43.8 million, $45.0 million and $24.7 million at
September 30, 2006 and 2005, and December 31, 2005, respectively. The
remainder of natural gas in underground storage was included in other assets
and
was $43.2 million, $43.3 million, and $43.2 million at September 30, 2006
and
2005, and December 31, 2005, respectively.
7.
Inventories
Inventories,
other than natural gas in underground storage for the Company’s regulated
operations, consisted primarily of aggregates held for resale of $92.1 million,
$79.5 million and $78.1 million; materials and supplies of $62.6 million,
$47.3
million and $48.7 million; and other inventories of $27.9 million, $22.1
million
and $20.7 million, as of September 30, 2006 and 2005, and December 31, 2005,
respectively. These inventories were stated at the lower of average cost
or
market value.
8.
Earnings
per common share
Basic
earnings per common share were computed by dividing earnings on common stock
by
the weighted average number of shares of common stock outstanding during
the
applicable period. Diluted earnings per common share were computed by dividing
earnings on common stock by the total of the weighted average number of shares
of common stock outstanding during the applicable period, plus the effect
of
outstanding stock options, restricted stock grants and performance share
awards.
For the three and nine months ended September 30, 2006 and 2005, there were
no
shares excluded from the calculation of diluted earnings per share. Common
stock
outstanding includes issued shares less shares held in treasury.
9.
|
Stock-based
compensation
|
On
January 1, 2006, the Company adopted SFAS No. 123 (revised). This
accounting standard revises SFAS No. 123 and requires entities to recognize
compensation expense in an amount equal to the grant-date fair value of
share-based payments granted to employees. SFAS No. 123 (revised) was adopted
using the modified prospective method, recognizing compensation expense for
all
awards granted after the date of adoption of the standard and for the unvested
portion of previously granted awards that remain outstanding at the date
of
adoption. In accordance with the modified prospective method, the Company’s
consolidated financial statements for prior periods have not been restated
to
reflect, and do not include, the impact of SFAS No. 123 (revised).
In
2003,
the Company adopted the fair value recognition provisions of SFAS No. 123
and
began expensing the fair market value of stock options for all awards granted
on
or after January 1, 2003. As permitted by SFAS No. 148, the Company accounted
for stock options granted prior to January 1, 2003, under APB Opinion No.
25. No compensation expense had been recognized for stock options granted
prior
to January 1, 2003, as the options granted had an exercise price equal to
the
market value of the underlying common stock on the date of the grant.
Compensation expense recognized for stock option awards granted on or after
January 1, 2003, for the nine months ended September 30, 2005, was $4,000,
net
of income taxes of $3,000.
The
Company adopted SFAS No. 123, effective January 1, 2003, for newly granted
stock
options only. The following table illustrates the effect on earnings and
earnings per common share for the three and nine months ended September 30,
2005, as if the Company had applied SFAS No. 123 and recognized compensation
expense for all outstanding and unvested stock options based on the fair
value
at the date of grant:
|
|
Three
Months
Ended
September
30, 2005
|
|
Nine
Months
Ended
September
30, 2005
|
|
|
|
(In
thousands, except per share amounts)
|
|
Earnings
on common stock, as reported
|
|
$
|
87,052
|
|
$
|
201,303
|
|
Stock-based
compensation expense included in reported earnings, net of related
tax
effects
|
|
|
---
|
|
|
4
|
|
Total
stock-based compensation expense determined under fair value method
for
all awards, net of related tax effects
|
|
|
50
|
|
|
(75
|
)
|
Pro
forma earnings on common stock
|
|
$
|
87,102
|
|
$
|
201,232
|
|
Earnings
per common share - basic - as reported
|
|
$
|
.49
|
|
$
|
1.13
|
|
Earnings
per common share - basic - pro forma
|
|
$
|
.49
|
|
$
|
1.13
|
|
Earnings
per common share - diluted - as reported
|
|
$
|
.48
|
|
$
|
1.12
|
|
Earnings
per common share - diluted - pro forma
|
|
$
|
.48
|
|
$
|
1.12
|
|
Total
stock-based compensation expense for the three and nine months ended September
30, 2006, was $848,000 and $3.0 million, net of income taxes of $542,000
and
$1.9 million, respectively, including $140,000 and $282,000, net of income
taxes
of $90,000 and $180,000, respectively, related to stock option
awards.
As
of
September 30, 2006, total remaining unrecognized compensation expense related
to
stock-based compensation was approximately $5.8 million (before income taxes)
which will be amortized over a weighted-average period of 1.8
years.
The
Company is authorized to grant options, restricted stock and stock for up
to
17.1 million shares of common stock and has granted options, restricted stock
and stock on 6.7 million shares through September 30, 2006.
The
Company generally issues new shares of common stock to satisfy stock option
exercises, restricted stock, stock and performance share awards.
Stock
Options
The
Company has stock option plans for directors, key employees and employees.
The
Company has not granted stock options since 2003. Options granted to key
employees automatically vest after nine years, but the plan provides for
accelerated vesting based on the attainment of certain performance goals
or upon
a change in control of the Company, and expire 10 years after the date of
grant.
Options granted to directors and employees vest at the date of grant and
three
years after the date of grant, respectively, and expire 10 years after the
date of grant.
The
fair
value of each option outstanding was estimated on the date of grant using
the
Black-Scholes option-pricing model.
A
summary
of the status of the stock option plans for the nine months ended September
30,
2006, was as follows:
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Weighted
|
|
Remaining
|
|
|
|
|
|
Average
|
|
Contractual
|
|
|
|
|
|
Exercise
|
|
Life
|
|
|
|
Shares
|
|
Price
|
|
In
Years
|
|
Outstanding
at beginning of period
|
|
|
2,786,973
|
|
$
|
12.99
|
|
|
|
|
Granted
|
|
|
---
|
|
|
---
|
|
|
|
|
Forfeited
|
|
|
(89,873
|
)
|
|
13.05
|
|
|
|
|
Exercised
|
|
|
(263,746
|
)
|
|
12.35
|
|
|
|
|
Outstanding
at end of period
|
|
|
2,433,354
|
|
|
13.06
|
|
|
4.1
|
|
Exercisable
at end of period
|
|
|
1,352,328
|
|
$
|
12.61
|
|
|
3.9
|
|
Summarized
information about stock options outstanding and exercisable as of
September 30, 2006, was as follows:
|
|
Options
Outstanding
|
|
Options
Exercisable
|
|
|
|
|
|
Remaining
|
|
Weighted
|
|
Aggregate
|
|
|
|
Weighted
|
|
Aggregate
|
|
Range
of
|
|
Number
|
|
Contractual
|
|
Average
|
|
Intrinsic
|
|
Number
|
|
Average
|
|
Intrinsic
|
|
Exercisable
|
|
Out-
|
|
Life
|
|
Exercise
|
|
Value
|
|
Exer-
|
|
Exercise
|
|
Value
|
|
Prices
|
|
standing
|
|
in
Years
|
|
Price
|
|
(000’s)
|
|
cisable
|
|
Price
|
|
(000’s)
|
|
$
7.28
- 8.00
|
|
|
10,124
|
|
|
0.8
|
|
$
|
7.28
|
|
$
|
152
|
|
|
10,124
|
|
$
|
7.28
|
|
$
|
152
|
|
8.01 - 11.00
|
|
|
290,565
|
|
|
1.7
|
|
|
9.60
|
|
|
3,702
|
|
|
287,673
|
|
|
9.60
|
|
|
3,666
|
|
11.01
- 14.00
|
|
|
1,877,924
|
|
|
4.4
|
|
|
13.18
|
|
|
17,202
|
|
|
962,831
|
|
|
13.19
|
|
|
8,809
|
|
14.01
- 17.13
|
|
|
254,741
|
|
|
4.5
|
|
|
16.32
|
|
|
1,534
|
|
|
91,700
|
|
|
16.54
|
|
|
532
|
|
Balance
at end of period
|
|
|
2,433,354
|
|
|
4.1
|
|
$
|
13.06
|
|
$
|
22,590
|
|
|
1,352,328
|
|
$
|
12.61
|
|
$
|
13,159
|
|
The
aggregate intrinsic value in the preceding table represents the total intrinsic
value (before income taxes), based on the Company’s stock price on September 30,
2006, which would have been received by the option holders had all option
holders exercised their options as of that date.
The
Company received cash of $584,000 and $3.3 million from the exercise of stock
options for the three and nine months ended September 30, 2006, respectively.
The aggregate intrinsic value of options exercised during the three and nine
months ended September 30, 2006, was $629,000 and $3.0 million,
respectively.
Restricted
Stock Awards
Prior
to
2002, the Company granted restricted stock awards under a long-term incentive
plan. The restricted stock awards granted vest at various times ranging from
one year to nine years from the date of issuance, but certain grants may
vest early based upon the attainment of certain performance goals or upon
a
change in control of the Company. The grant-date fair value is the market
price
of the Company’s stock on the grant date.
A
summary
of the status of the restricted stock awards for the nine months ended
September 30, 2006, was as follows:
|
|
|
|
Weighted
|
|
|
|
Number
|
|
Average
|
|
|
|
of
|
|
Grant-Date
|
|
|
|
Shares
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
130,764
|
|
$
|
10.63
|
|
Granted
|
|
|
---
|
|
|
---
|
|
Vested
|
|
|
(77,106
|
)
|
|
8.82
|
|
Forfeited
|
|
|
(21,541
|
)
|
|
13.22
|
|
Nonvested
at end of period
|
|
|
32,117
|
|
$
|
13.22
|
|
The
fair
value of restricted stock awards that vested during the nine months ended
September 30, 2006, was $1.8 million.
Stock
Awards
Nonemployee
directors may receive shares of common stock instead of cash in payment for
directors' fees under the nonemployee director stock compensation plan. There
were 40,500 shares with a fair value of $1.0 million issued under this plan
during the nine months ended September 30, 2006.
Performance
Share Awards
Since
2003, key employees of the Company have been awarded performance share awards
each year. Entitlement to performance shares is based on the Company's total
shareholder return over designated performance periods as measured against
a
selected peer group. The compensation expense is based on the grant-date
fair
value.
Target
grants of performance shares outstanding at September 30, 2006, were as
follows:
|
|
|
|
|
|
Grant
Date
|
|
Performance
Period
|
|
|
|
February
2004
|
|
|
2004-2006
|
|
|
278,600
|
|
February
2005
|
|
|
2005-2007
|
|
|
258,256
|
|
February
2006
|
|
|
2006-2008
|
|
|
203,343
|
|
Participants
may earn additional performance shares if the Company's total shareholder
return
exceeds that of the selected peer group. Compensation expense assumes that
the
target payout will be achieved. The fair value of performance share awards
that
vested during the nine months ended September 30, 2006, was $2.2
million.
A
summary
of the status of the performance share awards for the nine months ended
September 30, 2006, was as follows:
|
|
|
|
Weighted
|
|
|
|
Number
|
|
Average
|
|
|
|
of
|
|
Grant-Date
|
|
|
|
Shares
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
634,275
|
|
$
|
16.31
|
|
Granted
|
|
|
216,970
|
|
|
22.91
|
|
Additional
performance shares earned
|
|
|
14,522
|
|
|
11.14
|
|
Vested
|
|
|
(95,792
|
)
|
|
11.14
|
|
Forfeited
|
|
|
(29,776
|
)
|
|
18.76
|
|
Nonvested
at end of period
|
|
|
740,199
|
|
$
|
18.72
|
|
10.
Cash
flow information
Cash
expenditures for interest and income taxes were as follows:
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
$
|
48,957
|
|
$
|
33,059
|
|
Income
taxes
|
|
$
|
105,264
|
|
$
|
60,578
|
|
11.
New
accounting standards
SFAS
No. 123 (revised) In
December 2004, the FASB issued SFAS No. 123 (revised). This accounting standard
revises SFAS No. 123 and requires entities to recognize compensation expense
in
an amount equal to the grant-date fair value of share-based payments granted
to
employees. SFAS No. 123 (revised) was effective for the Company on January
1,
2006. As of the required effective date, the Company applied SFAS No. 123
(revised) using the modified prospective method, recognizing compensation
expense for all awards granted after the date of adoption of SFAS No. 123
(revised) and for the unvested portion of previously granted awards that
remain
outstanding at the date of adoption. The Company used the Black-Scholes
option-pricing model to calculate the fair value of stock options. For more
information on the adoption of SFAS No. 123 (revised), see Note 9.
EITF
No. 04-6
In March
2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires that stripping
costs during the production phase of a mine be treated as a variable inventory
production cost when incurred. EITF No. 04-6 was effective for the Company
on
January 1, 2006. The adoption of EITF No. 04-6 did not have a material effect
on
the Company’s financial position or results of operations.
FIN
48 In
July
2006, the FASB issued FIN 48. FIN 48 clarifies the application of SFAS No.
109
by defining a criterion that an individual tax position must meet for any
part
of the benefit of that position to be recognized in an enterprise’s financial
statements. The criterion allows for recognition in the financial statements
of
a tax position when it is more likely than not that the position will be
sustained upon examination. FIN 48 is effective for the Company on January
1,
2007. The Company is evaluating the effects of the adoption of
FIN 48.
SFAS
No. 158
In
September 2006, the FASB issued SFAS No. 158. SFAS No. 158 requires an employer
to recognize the overfunded or underfunded status of a defined benefit
postretirement plan (other than a multiemployer plan) as an asset or liability
in its balance sheet and recognize changes in that funded status in the year
in
which the changes occur through comprehensive income. The standard also requires
an employer to measure the funded status of the plan as of the date of its
year-end balance sheet. SFAS No. 158 is effective for the Company as of December
31, 2006. The Company is evaluating the effects of the adoption of SFAS No.
158.
12.
Comprehensive
income
Comprehensive
income is the sum of net income as reported and other comprehensive income
(loss). The Company's other comprehensive income (loss) resulted from gains
(losses) on derivative instruments qualifying as hedges and foreign currency
translation adjustments. For more information on derivative instruments,
see
Note 15.
Comprehensive
income, and the components of other comprehensive income (loss) and related
tax
effects, were as follows:
|
|
Three
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
$
|
108,487
|
|
$
|
87,223
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges:
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments arising during
the
period, net of tax of $8,709 and $39,038 in 2006 and 2005, respectively
|
|
|
13,912
|
|
|
(62,360
|
)
|
Less:
Reclassification adjustment for gain (loss) on derivative instruments
included in net income, net of tax of $2,654 and $3,353 in 2006
and 2005,
respectively
|
|
|
4,240
|
|
|
(5,356
|
)
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
|
9,672
|
|
|
(57,004
|
)
|
Foreign
currency translation adjustment
|
|
|
(401
|
)
|
|
(70
|
)
|
|
|
|
9,271
|
|
|
(57,074
|
)
|
Comprehensive
income
|
|
$
|
117,758
|
|
$
|
30,149
|
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
$
|
233,176
|
|
$
|
201,816
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges:
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments arising during
the
period, net of tax of $15,840 and $44,991 in 2006 and 2005, respectively
|
|
|
25,304
|
|
|
(71,869
|
)
|
Less:
Reclassification adjustment for loss on derivative instruments
included in
net income, net of tax of $12,121 and $1,895 in 2006 and 2005,
respectively
|
|
|
(19,361
|
)
|
|
(3,028
|
)
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
|
44,665
|
|
|
(68,841
|
)
|
Foreign
currency translation adjustment
|
|
|
(2,578
|
)
|
|
(1,089
|
)
|
|
|
|
42,087
|
|
|
(69,930
|
)
|
Comprehensive
income
|
|
$
|
275,263
|
|
$
|
131,886
|
|
13.
Equity
method investments
The
Company has equity method investments including a 49.99-percent ownership
interest in Carib Power and a 50-percent ownership interest in Hartwell.
Carib
Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired
electric generating facility in Trinidad and Tobago. Hartwell owns a 310-MW
natural gas-fired electric generating facility near Hartwell, Georgia.
On
August
16, 2006, MDU Brasil acquired ownership interests in companies owning three
electric energy transmission lines. The interests involve the ENTE (13.3-percent
ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent
ownership interest) electric energy transmission lines, which are located
primarily in northeastern and southern Brazil. The contracts provide for
revenues denominated in the Brazilian Real, annual inflation adjustments
and
change in tax law adjustments and have between 24 and 26 years remaining
under
the contracts. Alusa, Brascan, and CEMIG hold the remaining ownership
interests, with CELESC also having an ownership interest in ECTE. Alusa is
the
operating partner for the transmission lines.
The
Company assesses its equity method investments for impairment whenever events
or
changes in circumstances indicate that the related carrying values may not
be
recoverable. None of the Company’s equity method investments have been impaired
and, accordingly, no impairment losses have been recorded in the accompanying
consolidated financial statements or related equity method investment balances.
In
June
2005, the Company completed the sale of its 49 percent interest in MPX to
Petrobras, the Brazilian state-controlled energy company. The Company realized
a
gain of $15.6 million from the sale in the second quarter of 2005. In 2005,
the
Termoceara Generating Facility was accounted for as an asset held for sale
and,
as a result, no depreciation, depletion and amortization expense was recorded
in
2005.
At
September 30, 2006 and 2005, and December 31, 2005, the Company’s equity method
investments had total assets of $576.6 million, $244.3 million and $231.9
million, respectively, and long-term debt of $324.3 million, $159.6 million
and
$154.8 million, respectively. The Company’s investment in its equity method
investments was approximately $99.2 million, $44.0 million and $41.8 million,
including undistributed earnings of $6.6 million, $2.5 million and $3.5
million, at September 30, 2006 and 2005, and December 31, 2005, respectively.
14.
Goodwill
and other intangible assets
The
changes in the carrying amount of goodwill were as follows:
|
|
Balance
|
|
Goodwill
|
|
Goodwill
|
|
Balance
|
|
|
|
as
of
|
|
Acquired
|
|
Impaired
|
|
as
of
|
|
Nine
Months Ended
|
|
January
1,
|
|
During
|
|
During
|
|
September
30,
|
|
September
30, 2006
|
|
2006
|
|
the
Year*
|
|
the
Year
|
|
2006
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
80,970
|
|
|
5,956
|
|
|
---
|
|
|
86,926
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
(4,305
|
)
|
|
1,159
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
5,323
|
|
|
---
|
|
|
138,587
|
|
Independent
power production
|
|
|
11,167
|
|
|
---
|
|
|
---
|
|
|
11,167
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
230,865
|
|
$
|
11,279
|
|
$
|
(4,305
|
)
|
$
|
237,839
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
September
30, 2005
|
|
2005
|
|
the
Year*
|
|
2005
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
62,632
|
|
|
12,102
|
|
|
74,734
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
120,452
|
|
|
3,122
|
|
|
123,574
|
|
Independent
power production
|
|
|
11,195
|
|
|
(28
|
)
|
|
11,167
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
199,743
|
|
$
|
15,196
|
|
$
|
214,939
|
|
|
|
Balance
|
|
Goodwill
|
|
Balance
|
|
|
|
as
of
|
|
Acquired
|
|
as
of
|
|
Year
Ended
|
|
January
1,
|
|
During
|
|
December
31,
|
|
December
31, 2005
|
|
2005
|
|
the
Year*
|
|
2005
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
62,632
|
|
|
18,338
|
|
|
80,970
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
120,452
|
|
|
12,812
|
|
|
133,264
|
|
Independent
power production
|
|
|
11,195
|
|
|
(28
|
)
|
|
11,167
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
199,743
|
|
$
|
31,122
|
|
$
|
230,865
|
|
|
*
|
Includes
purchase price adjustments that were not material related to acquisitions
in a prior period.
|
During
the third quarter of 2006, the Company initiated a plan to sell Innovatum
which
is a reporting unit for goodwill impairment testing and part of the pipeline
and
energy services segment. In accordance with SFAS No. 142, the Company was
required to test Innovatum for impairment at the time that the Company
committed
to the plan to sell. The fair value of Innovatum was estimated using the
expected proceeds from the sale which is estimated to be the current book
value
of the assets of Innovatum other than its goodwill. As a result, a goodwill
impairment loss of $4.3 million (before tax) was recognized in the third
quarter
of 2006. For more information on Innovatum, see Note 3.
Other
intangible assets were as follows:
|
|
September
30,
2006
|
|
September
30,
2005
|
|
December
31,
2005
|
|
|
|
(In
thousands)
|
|
Amortizable
intangible assets:
|
|
|
|
|
|
|
|
|
|
|
Acquired
contracts
|
|
$
|
20,651
|
|
$
|
18,707
|
|
$
|
18,065
|
|
Accumulated
amortization
|
|
|
(9,958
|
)
|
|
(7,640
|
)
|
|
(9,458
|
)
|
|
|
|
10,693
|
|
|
11,067
|
|
|
8,607
|
|
Noncompete
agreements
|
|
|
12,886
|
|
|
11,784
|
|
|
11,784
|
|
Accumulated
amortization
|
|
|
(9,104
|
)
|
|
(8,434
|
)
|
|
(8,557
|
)
|
|
|
|
3,782
|
|
|
3,350
|
|
|
3,227
|
|
Other
|
|
|
17,208
|
|
|
14,699
|
|
|
7,914
|
|
Accumulated
amortization
|
|
|
(2,357
|
)
|
|
(1,480
|
)
|
|
(1,213
|
)
|
|
|
|
14,851
|
|
|
13,219
|
|
|
6,701
|
|
Unamortizable
intangible assets
|
|
|
524
|
|
|
851
|
|
|
524
|
|
Total
|
|
$
|
29,850
|
|
$
|
28,487
|
|
$
|
19,059
|
|
The
unamortizable intangible assets were recognized in accordance with SFAS No.
87,
which requires that if an additional minimum liability is recognized an equal
amount shall be recognized as an intangible asset provided that the asset
recognized shall not exceed the amount of unrecognized prior service cost.
The
unamortizable intangible asset will be eliminated or adjusted as necessary
upon
a new determination of the amount of additional liability.
Amortization
expense for amortizable intangible assets for the three and nine months ended
September 30, 2006, was $1.5 million and $4.3 million, respectively.
Amortization expense for the three and nine months ended September 30, 2005,
and
for the year ended December 31, 2005, was $1.8 million, $3.9 million and
$5.5 million, respectively. Estimated amortization expense for amortizable
intangible assets is $5.6 million in 2006, $6.2 million in 2007, $5.2
million in 2008, $4.2 million in 2009, $3.6 million in 2010 and $8.8 million
thereafter.
15.
Derivative
instruments
From
time
to time, the Company utilizes derivative instruments as part of an overall
energy price, foreign currency and interest rate risk management program
to
efficiently manage and minimize commodity price, foreign currency and interest
rate risk. As of September 30, 2006, the Company had no outstanding foreign
currency or interest rate hedges. The following information should be read
in
conjunction with Notes 1 and 5 in the Company's Notes to Consolidated Financial
Statements in the 2005 Annual Report.
Historically,
Fidelity has held derivative instruments designated as cash flow hedging
instruments. However, in the second quarter of 2006, the oil collar agreements
became ineffective and no longer qualified for hedge accounting, as discussed
below. At September 30, 2006, Fidelity held derivative instruments
designated as cash flow hedging instruments as well as derivative instruments
that did not qualify for hedge accounting.
Hedging
activities
Fidelity
utilizes natural gas and oil price swap and collar agreements to manage a
portion of the market risk associated with fluctuations in the price of natural
gas and oil on its forecasted sales of natural gas and oil production. Each
of
the natural gas and oil price swap and collar agreements was designated as
a
hedge of the forecasted sale of natural gas and oil production.
The
fair
value of the hedging instruments must be estimated as of the end of each
reporting period and is recorded on the Consolidated Balance Sheets as an
asset
or a liability. Changes in the fair value attributable to the effective portion
of hedging instruments, net of tax, are recorded in stockholders' equity
as a
component of accumulated other comprehensive income (loss). At the date the
natural gas or oil production quantities are settled, the amounts accumulated
in
other comprehensive income (loss) are reported in the Consolidated Statements
of
Income. To the extent that the hedges are not effective, the ineffective
portion
of the changes in fair market value is recorded directly in earnings. The
proceeds the Company receives for its natural gas and oil production are
also
generally based on market prices.
For
the
three and nine months ended September 30, 2005, the amount of hedge
ineffectiveness was immaterial. However, in the second quarter of 2006, the
oil
collar agreements became ineffective and no longer qualified for hedge
accounting. The oil hedges became ineffective as the physical price received
no
longer correlated to the hedge price due to the widening of regional basis
differentials on the price of the physical production received. The
ineffectiveness related to these collar agreements resulted in a gain of
approximately $841,000 (before tax) for the three months ended September
30,
2006, and a loss of approximately $138,000 (before tax) for the nine months
ended September 30, 2006. The ineffectiveness related to these collar agreements
was recorded in operation and maintenance expense. The amount of hedge
ineffectiveness on Fidelity’s remaining hedges was immaterial for the three and
nine months ended September 30, 2006.
For
the
three and nine months ended September 30, 2006 and 2005, Fidelity did not
exclude any components of the derivative instruments’ gain or loss from the
assessment of hedge effectiveness. Gains and losses must be reclassified
into
earnings as a result of the discontinuance of cash flow hedges if it is probable
that the original forecasted transactions will not occur. There were no such
reclassifications into earnings as a result of the discontinuance of hedges.
Gains
and
losses on derivative instruments that are reclassified from accumulated other
comprehensive income (loss) to current-period earnings are included in the
line
item in which the hedged item is recorded. As of September 30, 2006, the
maximum
term of Fidelity’s swap and collar agreements, in which Fidelity is hedging its
exposure to the variability in future cash flows for forecasted transactions,
is
15 months. The Company estimates that over the next 12 months net gains of
approximately $15.9 million (after tax) will be reclassified from accumulated
other comprehensive income into earnings, subject to changes in natural gas
and
oil market prices, as the hedged transactions affect earnings.
16.
Business
segment data
The
Company’s reportable segments are those that are based on the Company’s method
of internal reporting, which generally segregates the strategic business
units
due to differences in products, services and regulation. The vast majority
of
the Company’s operations are located within the United States. The Company also
has investments in foreign countries, which largely consist of investments
in
natural resource-based projects.
The
electric segment generates, transmits and distributes electricity in Montana,
North Dakota, South Dakota, and Wyoming. The natural gas distribution segment
distributes natural gas in those states as well as in western Minnesota.
These
operations also supply related value-added products and services.
The
construction services segment specializes in electrical line construction;
pipeline construction; inside electrical wiring, cabling and mechanical
services; and the manufacture and distribution of specialty
equipment.
The
pipeline and energy services segment provides natural gas transportation,
underground storage and gathering services through regulated and nonregulated
pipeline systems primarily in the Rocky Mountain and northern Great Plains
regions of the United States. The pipeline and energy services segment also
provides energy-related management services.
The
natural gas and oil production segment is engaged in natural gas and oil
acquisition, exploration, development and production activities primarily
in the
Rocky Mountain and Mid-Continent regions of the United States and in and
around
the Gulf of Mexico.
The
construction materials and mining segment mines aggregates and markets crushed
stone, sand, gravel and related construction materials, including ready-mixed
concrete, cement, asphalt and other value-added products, as well as performs
integrated construction services in the central and western United States
and in
Alaska and Hawaii.
The
independent power production segment owns, builds and operates electric
generating facilities in the United States and has domestic and international
investments including transmission and natural resource-based projects. Electric
capacity and energy produced at its power plants primarily are sold under
mid-
and long-term contracts to nonaffiliated entities.
The
Other
category includes the activities of Centennial Capital which insures various
types of risks as a captive insurer for certain of the Company’s subsidiaries.
The function of the captive insurer is to fund the deductible layers of the
insured companies’ general liability and automobile liability coverages.
Centennial Capital also owns certain real and personal property.
The
information below follows the same accounting policies as described in Note
1 of
the Company’s Notes to Consolidated Financial Statements in the 2005 Annual
Report. Information on the Company’s businesses was as follows:
|
|
|
|
Inter-
|
|
|
|
Three
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
on Common
|
|
Ended
September 30, 2006
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
53,204
|
|
$
|
---
|
|
$
|
5,698
|
|
Natural
gas distribution
|
|
|
31,378
|
|
|
---
|
|
|
(2,347
|
)
|
Pipeline
and energy services
|
|
|
87,372
|
|
|
16,434
|
|
|
7,141
|
|
|
|
|
171,954
|
|
|
16,434
|
|
|
10,492
|
|
Construction
services
|
|
|
262,188
|
|
|
139
|
|
|
8,300
|
|
Natural
gas and oil production
|
|
|
71,885
|
|
|
50,607
|
|
|
35,012
|
|
Construction
materials and mining
|
|
|
667,651
|
|
|
---
|
|
|
52,520
|
|
Independent
power production
|
|
|
16,958
|
|
|
---
|
|
|
1,714
|
|
Other
|
|
|
---
|
|
|
1,773
|
|
|
278
|
|
|
|
|
1,018,682
|
|
|
52,519
|
|
|
97,824
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(68,953
|
)
|
|
---
|
|
Total
|
|
$
|
1,190,636
|
|
$
|
---
|
|
$
|
108,316
|
|
|
|
|
|
Inter-
|
|
|
|
Three
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
on Common
|
|
Ended
September 30, 2005
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
50,195
|
|
$
|
---
|
|
$
|
6,169
|
|
Natural
gas distribution
|
|
|
34,014
|
|
|
---
|
|
|
(3,016
|
)
|
Pipeline
and energy services
|
|
|
101,210
|
|
|
17,086
|
|
|
5,282
|
|
|
|
|
185,419
|
|
|
17,086
|
|
|
8,435
|
|
Construction
services
|
|
|
207,259
|
|
|
162
|
|
|
5,131
|
|
Natural
gas and oil production
|
|
|
48,867
|
|
|
67,517
|
|
|
35,450
|
|
Construction
materials and mining
|
|
|
610,499
|
|
|
---
|
|
|
34,120
|
|
Independent
power production
|
|
|
14,133
|
|
|
---
|
|
|
3,730
|
|
Other
|
|
|
---
|
|
|
1,580
|
|
|
186
|
|
|
|
|
880,758
|
|
|
69,259
|
|
|
78,617
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(86,345
|
)
|
|
---
|
|
Total
|
|
$
|
1,066,177
|
|
$
|
---
|
|
$
|
87,052
|
|
|
|
|
|
Inter-
|
|
|
|
Nine
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
on Common
|
|
Ended
September 30, 2006
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
139,109
|
|
$
|
---
|
|
$
|
10,003
|
|
Natural
gas distribution
|
|
|
229,497
|
|
|
---
|
|
|
446
|
|
Pipeline
and energy services
|
|
|
264,984
|
|
|
67,808
|
|
|
17,290
|
|
|
|
|
633,590
|
|
|
67,808
|
|
|
27,739
|
|
Construction
services
|
|
|
728,936
|
|
|
385
|
|
|
23,377
|
|
Natural
gas and oil production
|
|
|
189,890
|
|
|
175,104
|
|
|
107,249
|
|
Construction
materials and mining
|
|
|
1,386,214
|
|
|
---
|
|
|
68,957
|
|
Independent
power production
|
|
|
39,941
|
|
|
---
|
|
|
4,560
|
|
Other
|
|
|
---
|
|
|
5,861
|
|
|
780
|
|
|
|
|
2,344,981
|
|
|
181,350
|
|
|
204,923
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(249,158
|
)
|
|
---
|
|
Total
|
|
$
|
2,978,571
|
|
$
|
---
|
|
$
|
232,662
|
|
|
|
|
|
Inter-
|
|
|
|
Nine
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
on Common
|
|
Ended
September 30, 2005
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
135,566
|
|
$
|
---
|
|
$
|
11,057
|
|
Natural
gas distribution
|
|
|
233,679
|
|
|
---
|
|
|
523
|
|
Pipeline
and energy services
|
|
|
252,112
|
|
|
58,889
|
|
|
17,245
|
|
|
|
|
621,357
|
|
|
58,889
|
|
|
28,825
|
|
Construction
services
|
|
|
457,879
|
|
|
294
|
|
|
10,748
|
|
Natural
gas and oil production
|
|
|
130,664
|
|
|
170,542
|
|
|
94,204
|
|
Construction
materials and mining
|
|
|
1,191,601
|
|
|
7
|
|
|
44,005
|
|
Independent
power production
|
|
|
37,600
|
|
|
---
|
|
|
23,069
|
|
Other
|
|
|
---
|
|
|
4,315
|
|
|
452
|
|
|
|
|
1,817,744
|
|
|
175,158
|
|
|
172,478
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(234,047
|
)
|
|
---
|
|
Total
|
|
$
|
2,439,101
|
|
$
|
---
|
|
$
|
201,303
|
|
The
pipeline and energy services segment recognized a loss from discontinued
operations, net of tax, of $1.6 million and $2.2 million for the three and
nine
months ended September 30, 2006, respectively, and $300,000 and $830,000
for the
three and nine months ended September 30, 2005, respectively. Excluding the
loss
from discontinued operations at pipeline and energy services, earnings (loss)
from electric, natural gas distribution and pipeline and energy services
are
substantially all from regulated operations. Earnings from construction
services, natural gas and oil production, construction materials and mining,
independent power production, and other are all from nonregulated
operations.
17.
Acquisitions
During
the first nine months of 2006, the Company acquired a construction services
business in Nevada, natural gas and oil properties in Wyoming, construction
materials and mining businesses in California and Washington, and a natural
gas-fired electric generating facility in California at the independent power
production segment, none of which was material. The total purchase consideration
for these businesses and properties and purchase price adjustments with respect
to certain other acquisitions made prior to 2006, consisting of the Company's
common stock and cash, was $131.0 million.
The
above
acquisitions were accounted for under the purchase method of accounting and,
accordingly, the acquired assets and liabilities assumed have been preliminarily
recorded at their respective fair values as of the date of acquisition. On
certain of the above acquisitions, final fair market values are pending the
completion of the review of the relevant assets, liabilities and issues
identified as of the acquisition date. The results of operations of the acquired
businesses and properties are included in the financial statements since
the
date of each acquisition. Pro forma financial amounts reflecting the effects
of
the above acquisitions are not presented, as such acquisitions were not material
to the Company's financial position or results of operations.
18.
Employee
benefit plans
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. Components of
net
periodic benefit cost for the Company's pension and other postretirement
benefit
plans were as follows:
Three
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
Ended
September 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost (income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
3,197
|
|
$
|
2,084
|
|
$
|
782
|
|
$
|
211
|
|
Interest
cost
|
|
|
5,861
|
|
|
4,155
|
|
|
1,107
|
|
|
666
|
|
Expected
return on assets
|
|
|
(7,983
|
)
|
|
(4,987
|
)
|
|
(1,643
|
)
|
|
(979
|
)
|
Amortization
of prior service cost
|
|
|
233
|
|
|
256
|
|
|
14
|
|
|
34
|
|
Recognized
net actuarial (gain) loss
|
|
|
569
|
|
|
346
|
|
|
(18
|
)
|
|
(364
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
---
|
|
|
(11
|
)
|
|
704
|
|
|
531
|
|
Net
periodic benefit cost
|
|
|
1,877
|
|
|
1,843
|
|
|
946
|
|
|
99
|
|
Less
amount capitalized
|
|
|
179
|
|
|
190
|
|
|
80
|
|
|
123
|
|
Net
periodic benefit cost (income)
|
|
$
|
1,698
|
|
$
|
1,653
|
|
$
|
866
|
|
$
|
(24
|
)
|
Nine
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
Ended
September 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
7,799
|
|
$
|
6,252
|
|
$
|
1,725
|
|
$
|
1,242
|
|
Interest
cost
|
|
|
14,009
|
|
|
12,463
|
|
|
2,964
|
|
|
2,802
|
|
Expected
return on assets
|
|
|
(17,419
|
)
|
|
(14,960
|
)
|
|
(3,494
|
)
|
|
(3,004
|
)
|
Amortization
of prior service cost
|
|
|
746
|
|
|
768
|
|
|
37
|
|
|
34
|
|
Recognized
net actuarial (gain) loss
|
|
|
1,587
|
|
|
1,038
|
|
|
(187
|
)
|
|
(441
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
(2
|
)
|
|
(33
|
)
|
|
1,766
|
|
|
1,594
|
|
Net
periodic benefit cost
|
|
|
6,720
|
|
|
5,528
|
|
|
2,811
|
|
|
2,227
|
|
Less
amount capitalized
|
|
|
560
|
|
|
547
|
|
|
205
|
|
|
329
|
|
Net
periodic benefit cost
|
|
$
|
6,160
|
|
$
|
4,981
|
|
$
|
2,606
|
|
$
|
1,898
|
|
In
addition to the qualified plan defined pension benefits reflected in the
table,
the Company has an unfunded, nonqualified benefit plan for executive officers
and certain key management employees that generally provides for defined
benefit
payments at age 65 following an employee’s retirement or to their beneficiaries
upon death for a 15-year period. The Company's net periodic benefit cost
for
this plan for the three and nine months ended September 30, 2006, was $1.8
million and $5.7 million, respectively. The Company’s net periodic benefit cost
for this plan for the three and nine months ended September 30, 2005, was
$1.6
million and $4.9 million, respectively.
19.
Regulatory
matters and revenues subject to refund
In
September 2004, Great Plains filed a natural gas rate application with the
MNPUC
requesting a revenue increase of $1.4 million annually, or approximately
4
percent. An interim increase of $1.4 million annually was effective January
10,
2005, subject to refund. The final order in the amount of $481,000 annually,
or
1.3 percent, was issued on May 1, 2006. A compliance filing was submitted
on
August 11, 2006, for MNPUC approval and is still pending action. Great Plains
has adequately provided a liability for the revenue subject to
refund.
In
December 1999, Williston Basin filed a general natural gas rate change
application with the FERC. Williston Basin began collecting such rates effective
June 1, 2000, subject to refund. In April 2005, the FERC issued its Order
on
Compliance Filing and Motion for Refunds. In this Order, the FERC approved
Williston Basin’s refund rates and established rates to be effective April 19,
2005. Williston Basin made its compliance filing complying with the requirements
of this Order regarding rates and issued refunds totaling approximately $18.5
million to its customers in May 2005. As a result of the Order, Williston
Basin
recorded a $5.0 million (after tax) benefit in the second quarter of 2005
from
the resolution of the rate proceeding which included the reversal of a portion
of the liability it had previously established for this regulatory proceeding.
In June 2005, Williston Basin appealed to the D.C. Appeals Court certain
issues
addressed by the FERC’s Order on Initial Decision dated July 2003 and its Order
on Rehearing dated May 2004 concerning determinations associated with cost
of
service and volumes used in allocating costs and designing rates. Oral argument
was held on October 20, 2006 regarding those matters. Those matters are pending
resolution by the D.C. Appeals Court. A provision has been established for
certain issues pending before the D.C. Appeals Court. The Company believes
that
the provision is adequate based on its assessment of the ultimate outcome
of the
proceeding.
In
May
2004, the FERC remanded issues regarding certain service and annual demand
quantity restrictions to an ALJ for resolution. In November 2005, the FERC
issued an Order on Initial Decision affirming the ALJ’s Initial Decision
regarding the service and annual demand quantity restrictions. On April 20,
2006, the FERC issued an Order on Rehearing denying Williston Basin’s Request
for Rehearing of the FERC’s November 2005 Order. On April 25, 2006, Williston
Basin appealed to the D.C. Appeals Court certain issues addressed by the
FERC’s
Order on Initial Decision dated November 2005 and its Order on Rehearing
issued
April 20, 2006, concerning the service and annual demand quantity restrictions.
Those matters are pending resolution by the D.C. Appeals Court.
20.
Contingencies
Litigation
Royalties
Case In
June
1997, Grynberg, acting on behalf of the United States, filed suit under the
Federal False Claims Act against Williston Basin and Montana-Dakota. He also
filed more than 70 similar suits against natural gas transmission companies
and
producers, gatherers and processors of natural gas. Grynberg alleged improper
measurement of the heating content and volume of natural gas purchased by
the
defendants resulting in the underpayment of royalties to the United States.
All
cases were consolidated in Wyoming Federal District Court.
In
June
2004, following preliminary discovery, Williston Basin and Montana-Dakota
joined
with other defendants and filed a Motion to Dismiss on the ground that the
information upon which Grynberg based his complaint was publicly disclosed
prior
to the filing of his complaint and further, that he is not the original source
of such information. The Motion to Dismiss was heard in March 2005 by the
Special Master appointed by the Wyoming Federal District Court. The Special
Master, in his Written Report dated May 2005, recommended that the lawsuit
be
dismissed against certain defendants, including Williston Basin and
Montana-Dakota. A hearing on the adoption of the Written Report was held
in
December 2005, before the Wyoming Federal District Court.
On
October 20, 2006, the Wyoming Federal District Court adopted and modified
the
Special Master’s Written Report and ordered that the actions against Williston
Basin and Montana-Dakota be dismissed. It is expected that Grynberg will
appeal
the decision to the U.S. Tenth Circuit Court of Appeals.
In
the
event the Wyoming Federal District Court’s decision is overturned and Grynberg’s
actions are reinstated, it is expected that further discovery will follow.
Williston Basin and Montana-Dakota believe Grynberg will not prevail in the
suit
or recover damages from Williston Basin and/or Montana-Dakota because
insufficient facts exist to support the allegations. Williston Basin and
Montana-Dakota believe Grynberg’s claims are without merit and intend to
vigorously contest this suit.
Grynberg
has not specified the amount he seeks to recover. Williston Basin and
Montana-Dakota are unable to estimate their potential exposure and will be
unable to do so until discovery is completed.
Coalbed
Natural Gas Operations Fidelity
has been named as a defendant in, and/or certain of its operations are or
have
been the subject of, more than a dozen lawsuits filed in connection with
its
CBNG development in the Powder River Basin in Montana and Wyoming. These
lawsuits were filed in federal and state courts in Montana between June 2000
and
April 2006 by a number of environmental organizations, including the NPRC
and
the Montana Environmental Information Center, as well as the TRWUA and the
Northern Cheyenne Tribe. Portions of three of the lawsuits have been transferred
to the Wyoming Federal District Court. The lawsuits involve allegations that
Fidelity and/or various government agencies are in violation of state and/or
federal law, including the Clean Water Act, the NEPA, the Federal Land
Management Policy Act, the NHPA, the Montana State Constitution, the Montana
Environmental Policy Act and the Montana Water Quality Act. The suits that
remain extant include a variety of claims that state and federal government
agencies violated various environmental laws that impose procedural
requirements. The lawsuits seek injunctive relief, invalidation of various
permits and unspecified damages.
In
suits
filed in the Montana Federal District Court, the NPRC and the Northern Cheyenne
Tribe asserted that further development by Fidelity and others of CBNG in
Montana should be enjoined until the BLM completes a SEIS. The Montana Federal
District Court, in February 2005, entered a ruling finding that the 2003
EIS was
inadequate. The Montana Federal District Court later entered an order that
would
have allowed limited CBNG development in the Powder River Basin in Montana
pending the BLM's preparation of a SEIS. The plaintiffs appealed the decision
to
the Ninth Circuit because the Montana Federal District Court declined to
enter
an injunction enjoining all development pending completion of the SEIS. The
Montana Federal District Court also declined to enter an injunction pending
the
appeal. In May 2005, the Ninth Circuit granted the request of the NPRC and
the
Northern Cheyenne Tribe and, pending further order from the Ninth Circuit,
enjoined the BLM from approving any new CBNG development projects in the
Powder
River Basin in Montana. That court also enjoined Fidelity from drilling any
additional federally permitted wells associated with its Montana Coal Creek
Project and from constructing infrastructure to produce and transport CBNG
from
the Coal Creek Project's existing federal wells. The matter has been fully
briefed and argued before the Ninth Circuit and the parties are awaiting
a
decision of the court.
In
related actions in the Montana Federal District Court, the NPRC and the Northern
Cheyenne Tribe asserted, among other things, that the actions of the BLM
in
approving Fidelity's applications for permits and the plan of development
for
the Badger Hills Project in Montana did not comply with applicable federal
laws,
including the NHPA and the NEPA. The NPRC also asserted that the environmental
assessment that supported the BLM's prior approval of the Badger Hills Project
was invalid. In June 2005, the Montana Federal District Court issued orders
in
these cases enjoining operations on Fidelity's Badger Hills Project pending
the
BLM's consultation with the Northern Cheyenne Tribe as to satisfaction of
the
applicable requirements of NHPA and a further environmental analysis under
NEPA.
Fidelity sought and obtained stays of the injunctive relief from the Montana
Federal District Court and production from Fidelity’s Badger Hills Project
continues. In September 2005, the Montana Federal District Court entered
an
Order based on a stipulation between the parties to the NPRC action that
production from existing wells in Fidelity’s Badger Hills Project may continue
pending preparation of a revised environmental analysis. In November 2005,
the
Montana Federal District Court entered an Order based on a stipulation between
the parties to the Northern Cheyenne Tribe action that production from existing
wells in Fidelity’s Badger Hills Project may continue pending preparation of a
revised environmental analysis. In December 2005, Fidelity filed a Notice
of
Appeal of the NPRC lawsuit to the Ninth Circuit in
connection with the Montana Federal District Court’s decision insofar as it
found the BLM’s approval of Fidelity’s applications did not comply with
applicable law.
In
May
2005, the NPRC and other petitioners filed a petition with the BER and the
BER
initiated related rulemaking proceedings to create rules that would, if
promulgated, require re-injection of water produced in connection with CBNG
operations, treatment of such water in the event re-injection is not feasible
and amend the non-degradation policy in connection with CBNG development
to
include additional limitations on factors deemed harmful, thereby restricting
discharges even further than under the previous standards. On March 23, 2006,
the BER issued its decision on the NPRC’s rulemaking petition. The BER rejected
the proposed requirement of re-injection of water produced in connection
with
CBNG and deferred action on the proposed treatment requirement. The BER adopted
the proposed amendment to the non-degradation policy. While it is possible
the
BER’s ruling could have an adverse impact on Fidelity’s operations, Fidelity
believes that two five-year water discharge permits issued by the Montana
DEQ in
February 2006 should, assuming normal operating conditions, allow Fidelity
to
continue its existing CBNG operations at least through the expiration of
the
permits in March 2011. However, these permits are now being challenged in
Montana state court by the Northern Cheyenne Tribe. Specifically, on April
3,
2006, the Northern Cheyenne Tribe filed a complaint in the District Court
of Big
Horn County against the Montana DEQ seeking to set aside the two permits.
The
Northern Cheyenne Tribe asserted that the Montana DEQ issued the permits
in
violation of various federal and state environmental laws. In particular,
the
Northern Cheyenne Tribe claimed the agency violated the Clean Water Act and
the
Montana Water Quality Act by failing to include in the permits conditions
requiring application of the best practicable control technology currently
available and by ignoring the BER’s recently adopted amendment to the
non-degradation policy. In addition, the Northern Cheyenne Tribe claimed
that
the actions of the Montana DEQ violated the Montana State Constitution’s
guarantee of a clean and healthful environment, that the Montana DEQ’s related
environmental assessment was invalid, that the Montana DEQ was required but
failed to prepare an environmental impact statement and that it failed to
consider other alternatives to the issuance of the permits. Fidelity, the
NPRC
and the TRWUA have been allowed to intervene in this proceeding. Fidelity
has
asserted that the Northern Cheyenne Tribe’s complaint should be dismissed with
prejudice, that Fidelity’s discharge of water pursuant to its two permits is its
primary means for managing CBNG produced water and that, if its permits are
set
aside, Fidelity’s CBNG operations in Montana could be significantly and
adversely affected.
In
a
related proceeding, on July 25, 2006, Fidelity filed a motion to intervene
in a
lawsuit filed in the District Court of Big Horn County by other producers.
The
lawsuit challenges the BER’s 2006 rulemaking, which amended the nondegradation
policy, as well as the BER’s 2003 rulemaking procedure which first set numeric
limits for certain parameters contained in water produced in connection with
CBNG operations. Fidelity’s motion for intervention was granted on August 1,
2006.
Similarly,
industry members have filed two lawsuits, and the State of Wyoming has filed
one
lawsuit, in Wyoming Federal District Court. These lawsuits challenge the
EPA’s
failure to timely disapprove the 2006 rules. All three Wyoming lawsuits were
consolidated on September 22, 2006.
Fidelity
will continue to vigorously defend its interests in all coalbed-related lawsuits
and related actions in which it is involved, including the Ninth Circuit
injunction and the proceedings challenging its water permits. In those cases
where damage claims have been asserted, Fidelity is unable to quantify the
damages sought and will be unable to do so until after the completion of
discovery. If the plaintiffs are successful in these lawsuits, the ultimate
outcome of the actions could have a material effect on Fidelity’s existing CBNG
operations and/or the future development of this resource in the affected
regions.
Electric
Operations Montana-Dakota
joined with two electric generators in appealing a September 2003 finding
by the
ND Health Department that it may unilaterally revise operating permits
previously issued to electric generating plants. Although it is doubtful
that
any revision of Montana-Dakota's operating permits by the ND Health Department
would reduce the amount of electricity its plants could generate, the finding,
if allowed to stand, could increase costs for sulfur dioxide removal and/or
limit Montana-Dakota's ability to modify or expand operations at its North
Dakota generation sites. Montana-Dakota and the other electric generators
filed
their appeal of the order in October 2003 in the Burleigh County District
Court
in Bismarck, North Dakota. Proceedings were stayed pending conclusion of
the
periodic review
of
sulfur dioxide emissions in the state.
In
September 2005, the ND Health Department issued its final periodic review
decision based on its August 2005 final air quality modeling report. The
ND
Health Department concluded there are no violations of the sulfur dioxide
increment in North Dakota. In March 2006, the DRC filed a complaint in Colorado
Federal District Court seeking to force the EPA to declare that the increment
had been violated based on earlier modeling conducted by the EPA. The EPA
is
defending against the DRC claim and it has filed a motion to dismiss the
case.
The Colorado Federal District Court has not yet ruled on
the
motion.
Montana-Dakota
expects the EPA to initiate a rulemaking proceeding to formally approve the
conclusions contained in the September 2005 ND Health Department decision
and
the August 2005 final report. Once concluded, this rulemaking should result
in a
revision to the North Dakota SIP that, in turn, should allow for the dismissal
of the case in Burleigh County District Court referenced above.
Natural
Gas Storage Williston
Basin filed suit in Montana Federal District Court on January 27, 2006, seeking
to recover unspecified damages from Anadarko and its wholly owned subsidiary,
Howell, and to enjoin Anadarko’s and Howell’s present and future operations in
and near the Elk Basin Storage Reservoir. Based on relevant information,
including reservoir and well pressure data, Williston Basin believes that
the
Elk Basin Storage Reservoir pressures have decreased and that quantities
of
natural gas have been diverted as a result of Anadarko’s and Howell’s drilling
and production activities in areas within and near the boundaries of the
Elk
Basin Storage Reservoir. Williston Basin is seeking not only to recover damages
for the gas that has been diverted, but to prevent further loss of gas from
the
Elk Basin Storage Reservoir. The Montana Federal District Court entered an
Order on July 14, 2006, dismissing the case for lack of subject matter
jurisdiction. Williston Basin filed a Notice of Appeal to the Ninth Circuit
on
July 31, 2006. In related litigation, Anadarko filed suit in Wyoming state
district court against Williston Basin asserting that it is entitled to produce
any gas that might escape from the Elk Basin Storage Reservoir. Williston
Basin
intends to vigorously defend its rights and interests in these proceedings,
to
assess further avenues for recovery through the regulatory process at the
FERC
and to pursue the recovery of any and all economic losses it may have suffered.
Williston Basin cannot predict the ultimate outcome of this
proceeding.
The
Company is also involved in other legal actions in the ordinary course of
its
business. Although the outcomes of any such legal actions cannot be predicted,
management believes that the outcomes with respect to these other legal
proceedings will not have a material adverse effect upon the Company's financial
position or results of operations.
Environmental
matters
Portland
Harbor Site In
December 2000, MBI was named by the EPA as a Potentially Responsible Party
in
connection with the cleanup of a riverbed site adjacent to a commercial property
site, acquired by MBI in 1999. The riverbed site is part of the Portland,
Oregon, Harbor Superfund Site. Sixty-eight other parties were also named
in this
administrative action. The EPA wants responsible parties to share in the
cleanup
of sediment contamination in the Willamette River. To date, costs of the
overall
remedial investigation of the harbor site for both the EPA and the Oregon
DEQ
are being recorded, and initially paid, through an administrative consent
order
by the LWG, a group of 10 entities, which does not include MBI or
Georgia-Pacific West, Inc., the seller of the commercial property to MBI.
Although the LWG originally estimated the overall remedial investigation
and
feasibility study would cost approximately $10 million, it is now
anticipated, on the basis of costs incurred to date and delays attributable
to
an additional round of sampling and potential further investigative work,
that
such cost could increase to a total of $60 million. It is not possible to
estimate the cost of a corrective action plan until the remedial investigation
and feasibility study has been completed, the EPA has decided on a strategy,
and
a record of decision has been published. While the remedial investigation
and
feasibility study for the harbor site has commenced, it is expected to take
several more years to complete. The development of a proposed plan and record
of
decision on the harbor site is not anticipated to occur until 2010, after
which
a cleanup plan will be undertaken.
Based
upon a review of the Portland Harbor sediment contamination evaluation by
the
Oregon DEQ and other information available, MBI does not believe it is a
Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc.,
that it intends to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their sale
agreement.
The
Company believes it is not probable that it will incur any material
environmental remediation costs or damages in relation to the above
administrative action.
Guarantees
In
connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly
owned subsidiary of the Company has agreed to indemnify Petrobras for 49
percent
of any losses which Petrobras may incur from certain contingent liabilities
specified in the purchase agreement. Centennial has agreed to unconditionally
guarantee payment of the indemnity obligations to Petrobras for periods ranging
from approximately two to five and a half years from the date of sale. The
guarantee was required by Petrobras as a condition to closing the sale of
MPX.
In
addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil
price swap and collar agreement obligations. Fidelity’s obligations at September
30, 2006, were immaterial. There is no fixed maximum amount guaranteed in
relation to the natural gas and oil price swap and collar agreements, as
the
amount of the obligation is dependent upon natural gas and oil commodity
prices.
The amount of hedging activity entered into by the subsidiary is limited
by
corporate policy. The guarantees of the natural gas and oil price swap and
collar agreements at September 30, 2006, expire in 2006 and 2007; however,
Fidelity continues to enter into additional hedging activities and, as a
result,
WBI Holdings from time to time may issue additional guarantees on these hedging
obligations. The amount outstanding by Fidelity was reflected on the
Consolidated Balance Sheet at September 30, 2006. In the event Fidelity defaults
under its obligations, WBI Holdings would be required to make payments under
its
guarantees.
Certain
subsidiaries of the Company have outstanding guarantees to third parties
that
guarantee the performance of other subsidiaries of the Company. These guarantees
are related to natural gas transportation and sales agreements, electric
power
supply agreements, construction contracts, a conditional purchase agreement
and
certain other guarantees. At September 30, 2006, the fixed maximum amounts
guaranteed under these agreements aggregated $180.1 million. The amounts
of
scheduled expiration of the maximum amounts guaranteed under these agreements
aggregate $1.0 million in 2006; $102.1 million in 2007; $4.7 million in 2008;
$2.7 million in 2009; $30.1 million in 2010; $23.0 million in 2011; $12.0
million in 2012; $500,000, which is subject to expiration 30 days after the
receipt of written notice and $4.0 million, which has no scheduled maturity
date. A guarantee for an unfixed amount estimated at $250,000 at September
30,
2006, has no scheduled maturity date. The amount outstanding by subsidiaries
of
the Company under the above guarantees was $700,000 and was reflected on
the
Consolidated Balance Sheet at September 30, 2006. In the event of default
under
these guarantee obligations, the subsidiary issuing the guarantee for that
particular obligation would be required to make payments under its guarantee.
Centennial
has outstanding letters of credit to third parties related to insurance policies
and other agreements that guarantee the performance of other subsidiaries
of the
Company. At September 30, 2006, the fixed maximum amounts guaranteed under
these
letters of credit aggregated $42.5 million. In 2006 and 2007, $5.8 million
and
$36.7 million, respectively, of letters of credit are scheduled to expire.
There
were no amounts outstanding under the above letters of credit at September
30,
2006.
Fidelity
and WBI Holdings have outstanding guarantees to Williston Basin. These
guarantees are related to natural gas transportation and storage agreements
that
guarantee the performance of Prairielands. At September 30, 2006, the fixed
maximum amounts guaranteed under these agreements aggregated $22.9 million.
Scheduled expiration of the maximum amounts guaranteed under these agreements
aggregate $2.9 million in 2008 and $20.0 million in 2009. In the event of
Prairielands’ default in its payment obligations, the subsidiary issuing the
guarantee for that particular obligation would be required to make payments
under its guarantee. The amount outstanding by Prairielands under the above
guarantees was $1.6 million, which was not reflected on the Consolidated
Balance
Sheet at September 30, 2006, because these intercompany transactions are
eliminated in consolidation.
In
addition, Centennial has issued guarantees to third parties related to the
Company’s routine purchase of maintenance items and lease obligations for which
no fixed maximum amounts have been specified. These guarantees have no scheduled
maturity date. In the event a subsidiary of the Company defaults under its
obligation in relation to the purchase of certain maintenance items or lease
obligations, Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the Company for these
maintenance items were reflected on the Consolidated Balance Sheet at
September 30, 2006.
In
the
normal course of business, Centennial has purchased surety bonds related
to
construction contracts and reclamation obligations of its subsidiaries. In
the
event a subsidiary of Centennial does not fulfill a bonded obligation,
Centennial would be responsible to the surety bond company for completion
of the
bonded contract or obligation. A large portion of the surety bonds is expected
to expire within the next 12 months; however, Centennial will likely continue
to
enter into surety bonds for its subsidiaries in the future. As of September
30,
2006, approximately $544 million of surety bonds were outstanding which were
not
reflected on the Consolidated Balance Sheet.
21.
Related
party transactions
In
2004,
Bitter Creek entered into two natural gas gathering agreements with Nance
Petroleum. Robert L. Nance, an executive officer and shareholder of St. Mary,
was also a member of the Board of Directors of the Company until his retirement
on August 17, 2006. The natural gas gathering agreements with Nance Petroleum
were effective upon completion of certain high and low pressure gathering
facilities, which occurred in mid-December 2004. Bitter Creek's capital
expenditures related to the completion of the gathering lines and the expansion
of its gathering facilities to accommodate the natural gas gathering agreements
were $11,000 and $39,000 for the three and nine months ended September 30,
2006,
and were $245,000 and $2.3 million for the three and nine months ended September
30, 2005, respectively, and are estimated for the next three years to be
$41,000
in 2006, $3.3 million in 2007 and $2.2 million in 2008. The natural gas
gathering agreements are each for a term of 15 years and month-to-month
thereafter. Bitter Creek's revenues from these contracts were $420,000 and
$1.2
million for the three and nine months ended September 30, 2006, respectively,
and were $316,000 and $855,000 for the three and nine months ended September
30,
2005, respectively. Estimated revenues from these contracts for the next
three
years are $1.8 million in 2006, $2.1 million in 2007 and $3.2 million in
2008.
The amount due from Nance Petroleum at September 30, 2006, was
$139,000.
In
2005,
Montana-Dakota entered into agreements to purchase natural gas from Nance
Petroleum through March 31, 2006. Montana-Dakota’s expenses under these
agreements through March 31, 2006, were $1.9 million. There were no amounts
due
to Nance Petroleum at September 30, 2006.
In
2005,
Fidelity entered into an agreement for the purchase of an ownership interest
in
a natural gas and oil property with a third party whereunder it became a
party
to a joint operating agreement in which St. Mary is the operator of the
property. St. Mary receives an overhead fee as operator of this property.
The
Company recorded its proportionate share of capital costs allocable to its
ownership interest in the related property, which were not material to
Fidelity.
On
July
8, 2006, the Company entered into a definitive merger agreement to acquire
Cascade, subject to approval of Cascade’s shareholders and various regulatory
authorities, as well as antitrust clearance under the Hart-Scott-Rodino Act,
and
the satisfaction of other customary closing conditions. On October 27, 2006,
shareholders of Cascade approved the merger agreement. Regulatory approvals
are
anticipated to be obtained by mid-year 2007. The total value of the transaction,
including the assumption of certain indebtedness, is approximately $475 million.
Cascade’s natural gas service areas are concentrated in western and south
central Washington and south central and eastern Oregon.
23.
Subsequent
event
On
October 20, 2006, Centennial Power sold 100 percent of its membership interest
in the recently formed LPP to Hobbs Power. LPP was formed to develop a
550-MW
combined-cycle generating facility to be built near Hobbs, New Mexico.
The
facility will consist of two combustion turbine generators, two heat-recovery
boilers and one steam turbine generator. Southwestern Public Service Company,
a
subsidiary of Xcel Energy, has signed a 25-year power purchase agreement
for the
entire capacity and output of the Hobbs facility. CEM is currently in
negotiations to construct and operate the new facility. Onsite construction
is
expected to begin by the spring of 2007 with power coming online by the
summer
of 2008. Because of expected continuing involvement by certain subsidiaries
of
Centennial Resources, revenues associated with the sale of LPP to Hobbs
Power
are currently expected to be recognized over the period of construction
of the
new facility.
ITEM
2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
|
AND
RESULTS OF OPERATIONS
|
OVERVIEW
The
Company’s strategy is to apply its expertise in energy and transportation
infrastructure industries to increase market share, increase profitability
and
enhance shareholder value through:
· |
Organic
growth as well as a continued disciplined approach to the acquisition
of
well-managed companies and properties
|
· |
The
elimination of system-wide cost redundancies through increased focus
on
integration of operations and standardization and consolidation of
various
support services and functions across companies within the
organization
|
· |
The
development of projects that are accretive to earnings per share
and
returns on invested capital
|
The
Company has capabilities to fund its growth and operations through various
sources, including internally generated funds, commercial paper facilities
and the
issuance from time to time of debt securities and the Company’s equity
securities. For
information on the Company’s net capital expenditures, see Liquidity and Capital
Commitments. Net capital expenditures are comprised of (A) capital expenditures
plus (B) acquisitions (including the issuance of the Company’s equity
securities, less cash acquired) less (C) net proceeds from the sale or
disposition of property.
The
key
strategies for each of the Company’s business segments, and certain related
business challenges, are summarized below.
Key
Strategies and Challenges
Electric
and Natural Gas Distribution
Strategy
Provide
competitively priced energy to customers while working with them to ensure
efficient usage. Both the electric and natural gas distribution segments
continually seek opportunities for growth and expansion of their customer
base
through extensions of existing operations and through selected acquisitions
of
companies and properties at prices that will provide an opportunity for the
Company to earn a competitive return on investment. The natural gas distribution
segment also continues to pursue growth
by
expanding its energy-related services.
Challenges Both
segments are subject to extensive regulation in the state jurisdictions where
they conduct operations with respect to costs and permitted returns on
investment as well as subject to certain operational regulations at the federal
level. The ability of these segments to grow through acquisitions is subject
to
significant competition from other energy providers. In addition, as to the
electric business, the ability of this segment to grow its service territory
and
customer base is affected by significant competition from other energy
providers, including rural electric cooperatives.
Construction
Services
Strategy
Provide
a competitive return on investment while operating in a competitive industry
by:
building new and strengthening existing customer relationships;
effectively controlling costs; recruiting,
developing and retaining talented employees; focusing business development
efforts on project areas that will permit higher margins; and properly managing
risk. This segment continuously seeks opportunities to expand through strategic
acquisitions.
Challenges
This
segment operates in highly competitive markets, with many jobs subject to
competitive bidding. Maintenance of effective operational and cost controls
and
retention of key personnel are ongoing challenges.
Pipeline
and Energy Services
Strategy
Leverage
the segment’s existing expertise in energy infrastructure, services and
technologies to increase market share and profitability through optimization
of
existing operations, internal growth, and acquisitions of energy-related
assets
and companies. Incremental and new growth opportunities include: access to
new
sources of natural gas for storage, gathering and transportation services;
expansion
of existing gathering and transmission facilities;
and
incremental
expansion of pipeline capacity to allow customers access to more liquid and
potentially higher-priced markets.
Challenges
Energy
price volatility; natural gas basis differentials; regulatory requirements;
recruitment and retention of a skilled workforce; and increased competition
from
other natural
gas pipeline
and
gathering companies.
Natural
Gas and Oil Production
Strategy
Apply
new technology and leverage existing exploration and production expertise,
with
a focus on operated properties, to increase production and reserves from
existing leaseholds, and to seek additional reserves and production
opportunities in new areas to further diversify the segment’s asset base. By
optimizing existing operations and taking advantage of new and incremental
growth opportunities, this segment’s goal is to increase both production and
reserves over the long term so as to generate competitive returns on
investment.
Challenges
Fluctuations in natural gas and oil prices; ongoing environmental litigation
and
administrative proceedings; timely receipt of necessary permits and approvals;
recruitment and retention of a skilled workforce; availability of drilling
rigs,
auxiliary equipment and industry-related field services; and increased
competition from many of the larger natural
gas and oil companies.
Construction
Materials and Mining
Strategy
Focus on
high growth strategic markets located near major transportation corridors
and
desirable mid-sized metropolitan areas; enhance profitability through cost
containment, margin discipline and vertical integration of the segment’s
operations; and continue growth through acquisitions. Vertical integration
allows the segment to manage operations from aggregate mining to final lay-down
of concrete and asphalt, with control of and access to adequate quantities
of
permitted aggregate reserves being significant. A
key
element of the Company’s long-term strategy for this business is to further
expand its presence in the higher-margin materials business (rock, sand,
gravel,
asphalt cement, ready-mix concrete and related products), complementing and
expanding on the Company’s expertise. Ongoing efforts to increase margin are
being pursued through the implementation of a variety of continuous improvement
programs, including corporate purchasing of equipment, parts and commodities
(asphalt cement, diesel fuel, cement, etc.), negotiation of contract price
escalation provisions and the utilization of national purchasing accounts.
A
critical element of the Company’s long term strategy for this business is the
acquisition and development of reserves deemed strategic to Company operations.
Ownership of, and access to aggregate reserves, is key to the vertical
integration strategy.
Challenges
Price
volatility with respect to, and availability of, raw materials such as asphalt
cement, diesel fuel and cement; recruitment and retention of a skilled
workforce; fixed price construction contracts are particularly vulnerable
to
volatility of these energy and material prices. Some of our markets are likely
to be affected by the slowdown in housing, which should be partially mitigated
by increased commercial spending.
Independent
Power Production
Strategy
Achieve
growth through the acquisition, construction and operation of domestic
nonregulated electric generation facilities and through international
investments in the energy and natural resources sectors. The segment continues
to seek projects with mid- to long-term agreements with financially stable
customers, while maintaining diversity in customers, geographic markets and
fuel
source.
Challenges
Overall
business challenges for this segment include: the risks and uncertainties
associated with the construction, startup and operation of power plant
facilities; changes in energy market pricing; increased competition from
other
independent power producers;
and
foreign currency fluctuation and political risk in the countries where this
segment does business.
For
further information on the risks and challenges the Company faces as it pursues
its growth strategies and other factors that should be considered for a better
understanding of the Company’s financial condition, see Part II, Item 1A - Risk
Factors, as well as Part I, Item 1A - Risk Factors in the 2005 Annual Report.
For further information on each segment’s key growth strategies, projections and
certain assumptions, see Prospective Information. For information pertinent
to
various commitments and contingencies, see Notes to Consolidated Financial
Statements.
Earnings
Overview
The
following table summarizes the contribution to consolidated earnings by each
of
the Company's businesses.
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Electric
|
|
$
|
5.7
|
|
$
|
6.2
|
|
$
|
10.0
|
|
$
|
11.1
|
|
Natural
gas distribution
|
|
|
(2.3
|
)
|
|
(3.0
|
)
|
|
.4
|
|
|
.5
|
|
Construction
services
|
|
|
8.3
|
|
|
5.1
|
|
|
23.4
|
|
|
10.7
|
|
Pipeline
and energy services
|
|
|
7.1
|
|
|
5.3
|
|
|
17.3
|
|
|
17.2
|
|
Natural
gas and oil production
|
|
|
35.0
|
|
|
35.5
|
|
|
107.2
|
|
|
94.2
|
|
Construction
materials and mining
|
|
|
52.5
|
|
|
34.1
|
|
|
69.0
|
|
|
44.0
|
|
Independent
power production
|
|
|
1.7
|
|
|
3.7
|
|
|
4.6
|
|
|
23.1
|
|
Other
|
|
|
.3
|
|
|
.2
|
|
|
.8
|
|
|
.5
|
|
Earnings
on common stock
|
|
$
|
108.3
|
|
$
|
87.1
|
|
$
|
232.7
|
|
$
|
201.3
|
|
Earnings
per common share - basic
|
|
$
|
.60
|
|
$
|
.49
|
|
$
|
1.29
|
|
$
|
1.13
|
|
Earnings
per common share - diluted
|
|
$
|
.60
|
|
$
|
.48
|
|
$
|
1.29
|
|
$
|
1.12
|
|
Return
on average common equity for the 12 months ended
|
|
|
|
|
|
|
|
|
15.7
|
%
|
|
15.0
|
%
|
Three
Months Ended September 30, 2006 and 2005
Consolidated earnings for the quarter ended September 30, 2006, increased
$21.2
million from the comparable period largely due to:
· |
Higher
earnings from construction due to increased volumes and margins,
earnings
from companies acquired since the comparable prior period and higher
earnings from aggregate and asphalt due to higher margins at the
construction materials and mining
business
|
· |
Higher
earnings from increased outside and inside construction workloads
and
margins at the construction services
business
|
Nine
Months Ended September 30, 2006 and 2005
Consolidated earnings for the nine months ended September 30, 2006, increased
$31.4 million from the comparable period largely due to:
· |
Higher
earnings from construction materials and mining business, as previously
discussed
|
· |
Higher
average realized natural gas and oil prices of 9 percent and 26 percent,
respectively, and increased natural gas and oil production of 5 percent
and 18 percent, respectively at the natural gas and oil production
business
|
· |
Higher
earnings from increased outside and inside construction workloads
and
margins, and earnings from companies acquired since the comparable
prior
period at the construction services
business
|
· |
Higher
transportation, storage and gathering volumes, largely offset by
the
absence in 2006 of the benefit from the resolution of a rate proceeding
of
$5.0 million (after tax) recorded in 2005 at the pipeline and energy
services business. For more information, see Note
19.
|
Partially
offsetting the increase were decreased earnings from equity method investments,
which largely reflect the absence in 2006 of the 2005 $15.6 million benefit
from
the sale of the Termoceara Generating Facility at the independent power
production business.
FINANCIAL
AND OPERATING DATA
The
following tables contain key financial and operating statistics for each
of the
Company's businesses.
Electric
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$
|
53.2
|
|
$
|
50.2
|
|
$
|
139.1
|
|
$
|
135.5
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
19.1
|
|
|
16.3
|
|
|
51.2
|
|
|
47.0
|
|
Operation
and maintenance
|
|
|
16.3
|
|
|
15.0
|
|
|
46.0
|
|
|
43.7
|
|
Depreciation,
depletion and amortization
|
|
|
5.4
|
|
|
5.2
|
|
|
15.9
|
|
|
15.5
|
|
Taxes,
other than income
|
|
|
2.1
|
|
|
2.1
|
|
|
6.4
|
|
|
6.5
|
|
|
|
|
42.9
|
|
|
38.6
|
|
|
119.5
|
|
|
112.7
|
|
Operating
income
|
|
|
10.3
|
|
|
11.6
|
|
|
19.6
|
|
|
22.8
|
|
Earnings
|
|
$
|
5.7
|
|
$
|
6.2
|
|
$
|
10.0
|
|
$
|
11.1
|
|
Retail
sales (million kWh)
|
|
|
652.1
|
|
|
626.3
|
|
|
1,828.1
|
|
|
1,785.5
|
|
Sales
for resale (million kWh)
|
|
|
172.3
|
|
|
169.1
|
|
|
423.9
|
|
|
482.4
|
|
Average
cost of fuel and purchased power per kWh
|
|
$
|
.022
|
|
$
|
.019
|
|
$
|
.022
|
|
$
|
.019
|
|
Three
Months Ended September 30, 2006 and 2005 Electric
earnings decreased $500,000 due to higher operation and maintenance expense
of
$800,000 (after tax), including costs related to a scheduled maintenance
outage
at an electric generating station. This decrease was partially offset by
higher
retail sales margins, largely due to increased volumes of 4
percent.
Nine
Months Ended September 30, 2006 and 2005 Electric
earnings decreased $1.1 million due to:
· |
Higher
operation and maintenance expense of $1.4 million (after tax), primarily
the result of scheduled maintenance outages at electric generating
stations
|
· |
Decreased
sales for resale margins due to lower average rates of 13 percent
and
decreased volumes of 12 percent largely due to plant
availability
|
Partially
offsetting the decrease were:
· |
Lower
interest expense of $600,000 (after tax), resulting from lower average
interest rates due to the repurchase and redemption of certain higher
cost
long-term debt
|
· |
Higher
retail sales margins, largely due to increased volumes of 2
percent
|
Natural
Gas Distribution
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
30.5
|
|
$
|
33.0
|
|
$
|
226.6
|
|
$
|
230.2
|
|
Transportation
and other
|
|
|
0.9
|
|
|
1.0
|
|
|
2.9
|
|
|
3.5
|
|
|
|
|
31.4
|
|
|
34.0
|
|
|
229.5
|
|
|
233.7
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
20.7
|
|
|
23.2
|
|
|
182.5
|
|
|
185.3
|
|
Operation
and maintenance
|
|
|
11.0
|
|
|
11.3
|
|
|
35.7
|
|
|
34.5
|
|
Depreciation,
depletion and amortization
|
|
|
2.5
|
|
|
2.4
|
|
|
7.3
|
|
|
7.2
|
|
Taxes,
other than income
|
|
|
1.4
|
|
|
1.3
|
|
|
4.5
|
|
|
4.3
|
|
|
|
|
35.6
|
|
|
38.2
|
|
|
230.0
|
|
|
231.3
|
|
Operating
income (loss)
|
|
|
(4.2
|
)
|
|
(4.2
|
)
|
|
(.5
|
)
|
|
2.4
|
|
Earnings
(loss)
|
|
$
|
(2.3
|
)
|
$
|
(3.0
|
)
|
$
|
.4
|
|
$
|
.5
|
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
3.1
|
|
|
3.0
|
|
|
21.9
|
|
|
24.1
|
|
Transportation
|
|
|
2.6
|
|
|
2.9
|
|
|
9.8
|
|
|
9.9
|
|
Total
throughput
|
|
|
5.7
|
|
|
5.9
|
|
|
31.7
|
|
|
34.0
|
|
Degree
days (% of normal)*
|
|
|
94
|
%
|
|
50
|
%
|
|
83
|
%
|
|
92
|
%
|
Average
cost of natural gas, including transportation, per
dk
|
|
$
|
6.67
|
|
$
|
7.78
|
|
$
|
8.32
|
|
$
|
7.68
|
|
*
Degree days are a measure of the daily temperature-related demand for energy
for
heating.
Three
Months Ended September 30, 2006 and 2005 The
natural gas distribution business experienced a seasonal loss of $2.3 million
in
the third quarter compared to a loss of $3.0 million in the third quarter
of
2005. The increase in earnings of $700,000 was largely due to higher
nonregulated earnings from energy-related services.
Nine
Months Ended September 30, 2006 and 2005
Earnings
at the natural gas distribution business decreased $100,000 due to:
· |
Lower
retail sales margin due to lower sales volumes of 9 percent, resulting
from 10 percent warmer weather than last year, partially offset by
higher
weather-normalized revenues in certain
jurisdictions
|
· |
Higher
operation and maintenance expense of $800,000 (after tax), largely
due to
higher payroll-related costs from an early retirement
program
|
Largely
offsetting the decrease in earnings were higher nonregulated earnings from
energy-related services.
Construction
Services
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Operating
revenues
|
|
$
|
262.3
|
|
$
|
207.4
|
|
$
|
729.3
|
|
$
|
458.2
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
236.8
|
|
|
188.8
|
|
|
656.2
|
|
|
412.4
|
|
Depreciation,
depletion and amortization
|
|
|
3.6
|
|
|
3.9
|
|
|
11.0
|
|
|
9.7
|
|
Taxes,
other than income
|
|
|
6.6
|
|
|
5.0
|
|
|
19.5
|
|
|
15.2
|
|
|
|
|
247.0
|
|
|
197.7
|
|
|
686.7
|
|
|
437.3
|
|
Operating
income
|
|
|
15.3
|
|
|
9.7
|
|
|
42.6
|
|
|
20.9
|
|
Earnings
|
|
$
|
8.3
|
|
$
|
5.1
|
|
$
|
23.4
|
|
$
|
10.7
|
|
Three
Months Ended September 30, 2006 and 2005 Construction
services earnings increased $3.2 million compared to the third quarter of
the comparable period due to:
· |
Higher
outside construction workloads and margins of $2.2 million (after
tax),
largely in the Southwest region
|
· |
Higher
inside construction workloads and margins of $900,000 (after tax),
largely
in the Southwest region
|
· |
Increased
equipment sales and rentals
|
Partially
offsetting this increase were higher general and administrative expenses
of
$600,000 (after tax), primarily payroll related.
Nine
Months Ended September 30, 2006 and 2005
Construction services earnings increased $12.7 million compared to the nine
months of the comparable period due to:
· |
Earnings
from acquisitions made since the comparable prior period, which
contributed approximately 40 percent of the earnings
increase
|
· |
Higher
inside construction workloads and margins of $4.6 million (after
tax) in
the Central, Southwest and Northwest
regions
|
· |
Higher
outside construction workloads and margins of $2.8 million (after
tax),
largely in the Southwest region, partially offset by decreased workloads
and margins in the Northwest region
|
· |
Increased
equipment sales and rentals
|
Partially
offsetting this increase were higher general and administrative expenses
of $1.7
million (after tax), primarily payroll related.
Pipeline
and Energy Services
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
$
|
27.7
|
|
$
|
21.5
|
|
$
|
74.5
|
|
$
|
63.7
|
|
Energy
services
|
|
|
76.1
|
|
|
96.8
|
|
|
258.3
|
|
|
247.3
|
|
|
|
|
103.8
|
|
|
118.3
|
|
|
332.8
|
|
|
311.0
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
69.0
|
|
|
89.3
|
|
|
236.1
|
|
|
226.1
|
|
Operation
and maintenance
|
|
|
12.8
|
|
|
11.9
|
|
|
38.4
|
|
|
36.7
|
|
Depreciation,
depletion and amortization
|
|
|
4.9
|
|
|
4.6
|
|
|
14.9
|
|
|
7.7
|
|
Taxes,
other than income
|
|
|
2.5
|
|
|
2.1
|
|
|
7.6
|
|
|
6.1
|
|
|
|
|
89.2
|
|
|
107.9
|
|
|
297.0
|
|
|
276.6
|
|
Operating
income
|
|
|
14.6
|
|
|
10.4
|
|
|
35.8
|
|
|
34.4
|
|
Earnings
|
|
$
|
7.1
|
|
$
|
5.3
|
|
$
|
17.3
|
|
$
|
17.2
|
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
7.5
|
|
|
7.7
|
|
|
22.6
|
|
|
23.1
|
|
Other
|
|
|
29.3
|
|
|
19.7
|
|
|
75.4
|
|
|
53.1
|
|
|
|
|
36.8
|
|
|
27.4
|
|
|
98.0
|
|
|
76.2
|
|
Gathering
volumes (MMdk)
|
|
|
21.9
|
|
|
20.6
|
|
|
64.8
|
|
|
60.2
|
|
Three
Months Ended September 30, 2006 and 2005 Pipeline
and energy services experienced an increase in earnings of $1.8 million due
to:
· |
Higher
transportation, storage and gathering volumes ($3.1 million after
tax)
|
· |
Higher
gathering and storage rates ($1.1 million after
tax)
|
Partially
offsetting this increase were:
· |
Higher
operation and maintenance expense, primarily related to the natural
gas
storage litigation. For more information, see Note
20.
|
· |
An
increased loss from discontinued operations of $1.3 million (after
tax)
related to Innovatum. For more information, see Notes 3 and
14.
|
Nine
Months Ended September 30, 2006 and 2005
Pipeline
and energy services experienced an increase in earnings of $100,000 due
to:
· |
Higher
transportation, storage and gathering volumes ($6.4 million after
tax)
|
· |
Higher
gathering rates ($2.7 million after tax)
|
Partially
offsetting this increase were:
· |
Absence
in 2006 of the benefit from the resolution of a rate proceeding of
$5.0
million (after tax) recorded in 2005, which included a reduction
to
depreciation, depletion and amortization expense. For more information,
see Note 19.
|
· |
Higher
operation and maintenance expense, primarily due to the natural gas
storage litigation, as previously
discussed
|
· |
An
increased loss from discontinued operations of $1.4 million (after
tax)
related to Innovatum, as previously
discussed
|
· |
Higher
taxes, other than income of $900,000 (after tax), primarily due to
property taxes
|
Natural
Gas and Oil Production
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
89.1
|
|
$
|
94.3
|
|
$
|
281.7
|
|
$
|
247.2
|
|
Oil
|
|
|
31.6
|
|
|
20.5
|
|
|
78.0
|
|
|
52.3
|
|
Other
|
|
|
1.8
|
|
|
1.6
|
|
|
5.3
|
|
|
1.7
|
|
|
|
|
122.5
|
|
|
116.4
|
|
|
365.0
|
|
|
301.2
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
1.5
|
|
|
1.5
|
|
|
5.2
|
|
|
1.7
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
14.0
|
|
|
10.9
|
|
|
38.3
|
|
|
28.6
|
|
Gathering
and transportation
|
|
|
4.5
|
|
|
3.8
|
|
|
13.9
|
|
|
9.5
|
|
Other
|
|
|
7.2
|
|
|
9.5
|
|
|
23.9
|
|
|
21.4
|
|
Depreciation,
depletion and amortization
|
|
|
27.7
|
|
|
22.3
|
|
|
78.1
|
|
|
60.6
|
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
8.5
|
|
|
9.3
|
|
|
26.4
|
|
|
22.7
|
|
Other
|
|
|
.2
|
|
|
.1
|
|
|
.7
|
|
|
.4
|
|
|
|
|
63.6
|
|
|
57.4
|
|
|
186.5
|
|
|
144.9
|
|
Operating
income
|
|
|
58.9
|
|
|
59.0
|
|
|
178.5
|
|
|
156.3
|
|
Earnings
|
|
$
|
35.0
|
|
$
|
35.5
|
|
$
|
107.2
|
|
$
|
94.2
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
15,603
|
|
|
15,015
|
|
|
46,207
|
|
|
44,069
|
|
Oil
(MBbls)
|
|
|
554
|
|
|
477
|
|
|
1,475
|
|
|
1,250
|
|
Average
realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
5.71
|
|
$
|
6.28
|
|
$
|
6.10
|
|
$
|
5.61
|
|
Oil
(per barrel)
|
|
$
|
57.01
|
|
$
|
42.95
|
|
$
|
52.90
|
|
$
|
41.88
|
|
Average
realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
5.13
|
|
$
|
6.87
|
|
$
|
5.72
|
|
$
|
5.88
|
|
Oil
(per barrel)
|
|
$
|
57.69
|
|
$
|
50.72
|
|
$
|
53.99
|
|
$
|
47.83
|
|
Production
costs, including taxes, per net equivalent Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$
|
.74
|
|
$
|
.61
|
|
$
|
.70
|
|
$
|
.55
|
|
Gathering
and transportation
|
|
|
.23
|
|
|
.21
|
|
|
.25
|
|
|
.19
|
|
Production
and property taxes
|
|
|
.45
|
|
|
.52
|
|
|
.48
|
|
|
.44
|
|
|
|
$
|
1.42
|
|
$
|
1.34
|
|
$
|
1.43
|
|
$
|
1.18
|
|
Three
Months Ended September 30, 2006 and 2005 The
natural gas and oil production business experienced a $500,000 decrease in
earnings due to:
· |
Lower
average realized natural gas prices of 9
percent
|
· |
Higher
depreciation, depletion and amortization of $3.4 million (after tax)
due
to higher depletion rates and increased
production
|
· |
Higher
lease operating expense of $1.9 million (after tax), largely CBNG
and
acquisition-related
|
Partially
offsetting the decrease were:
· |
Increased
oil production of 16 percent and natural gas production of 4 percent,
largely due to increased production in the Rocky Mountain region
as well
as from the May 2005 South Texas and May 2006 Big Horn
acquisitions
|
· |
Higher
average realized oil prices of 33 percent
|
· |
Decreased
general and administrative expense of $900,000 (after tax), primarily
lower outside service costs
|
Nine
Months Ended September 30, 2006 and 2005
The
natural gas and oil production business experienced a $13.0 million increase
in
earnings due to:
· |
Higher
average realized natural gas prices of 9 percent and higher average
realized oil prices of 26 percent
|
· |
Increased
natural gas production of 5 percent and oil production of 18 percent,
as
previously discussed
|
Partially
offsetting the increase were:
· |
Higher
depreciation, depletion and amortization of $10.8 million (after
tax) due
to higher depletion rates and increased
production
|
· |
Higher
lease operating expenses of $6.0 million (after tax), as previously
discussed
|
· |
Increased
gathering and transportation expense of $2.7 million (after tax),
largely
higher gathering rates
|
· |
Increased
general and administrative expense of $1.7 million (after tax), including
higher payroll-related and office
expenses
|
· |
Higher
interest expense of $1.1 million (after tax), primarily due to higher
average debt balances
|
Construction
Materials and Mining
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
667.6
|
|
$
|
610.5
|
|
$
|
1,386.2
|
|
$
|
1,191.6
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
546.9
|
|
|
518.3
|
|
|
1,167.1
|
|
|
1,018.8
|
|
Depreciation,
depletion and amortization
|
|
|
22.6
|
|
|
19.8
|
|
|
64.8
|
|
|
57.0
|
|
Taxes,
other than income
|
|
|
10.0
|
|
|
12.3
|
|
|
30.3
|
|
|
30.7
|
|
|
|
|
579.5
|
|
|
550.4
|
|
|
1,262.2
|
|
|
1,106.5
|
|
Operating
income
|
|
|
88.1
|
|
|
60.1
|
|
|
124.0
|
|
|
85.1
|
|
Earnings
|
|
$
|
52.5
|
|
$
|
34.1
|
|
$
|
69.0
|
|
$
|
44.0
|
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
14,961
|
|
|
17,518
|
|
|
34,386
|
|
|
34,447
|
|
Asphalt
(tons)
|
|
|
3,669
|
|
|
4,331
|
|
|
6,358
|
|
|
6,831
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
1,420
|
|
|
1,463
|
|
|
3,391
|
|
|
3,347
|
|
Three
Months Ended September 30, 2006 and 2005
Earnings
at the construction materials and mining business increased $18.4 million
due
to:
· |
Higher
earnings of $9.3 million (after tax) from construction, largely due
to
increased volumes and margins, the result of strong markets and favorable
weather
|
· |
Earnings
from companies acquired since the comparable prior period, which
contributed approximately 29 percent of the earnings
increase
|
· |
Increased
earnings from aggregate and asphalt operations of $5.0 million (after
tax), largely due to higher margins, partially offset by lower
volumes
|
Partially
offsetting the increase in earnings were:
· |
Higher
depreciation, depletion and amortization of $900,000 (after tax),
primarily due to higher plant and equipment
balances
|
· |
Lower
earnings of $900,000 (after tax) from ready-mixed concrete operations,
largely due to lower volumes
|
Nine
Months Ended September 30, 2006 and 2005
Earnings
at the construction materials and mining business increased $25.0 million
due
to:
· |
Higher
earnings of $15.0 million (after tax) from construction, as previously
discussed
|
· |
Increased
earnings from aggregate operations of $5.6 million (after tax), largely
due to higher margins
|
· |
Increased
earnings from asphalt and ready-mixed concrete operations of $3.8
million
(after tax) due to higher margins, partially offset by lower volumes
from
existing operations
|
· |
Earnings
from companies acquired since the comparable period, which contributed
approximately 19 percent of the earnings
increase
|
Partially
offsetting the increase in earnings were:
· |
Higher
depreciation, depletion and amortization of $2.9 million (after tax),
as
previously discussed
|
· |
Increased
general and administrative expense of $2.0 million (after tax), primarily
payroll-related
|
Independent
Power Production
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
17.0
|
|
$
|
14.1
|
|
$
|
39.9
|
|
$
|
37.6
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
1.7
|
|
|
---
|
|
|
3.0
|
|
|
---
|
|
Operation
and maintenance
|
|
|
8.5
|
|
|
8.0
|
|
|
22.8
|
|
|
21.7
|
|
Depreciation,
depletion and amortization
|
|
|
4.3
|
|
|
2.2
|
|
|
10.9
|
|
|
6.9
|
|
Taxes,
other than income
|
|
|
1.1
|
|
|
.7
|
|
|
3.1
|
|
|
2.1
|
|
|
|
|
15.6
|
|
|
10.9
|
|
|
39.8
|
|
|
30.7
|
|
Operating
income
|
|
|
1.4
|
|
|
3.2
|
|
|
.1
|
|
|
6.9
|
|
Earnings
|
|
$
|
1.7
|
|
$
|
3.7
|
|
$
|
4.6
|
|
$
|
23.1
|
|
Net
generation capacity (kW)*
|
|
|
437,600
|
|
|
279,600
|
|
|
437,600
|
|
|
279,600
|
|
Electricity
produced and sold (thousand kWh)*
|
|
|
300,951
|
|
|
89,646
|
|
|
592,226
|
|
|
217,658
|
|
*
Excludes equity method investments.
Three
Months Ended September 30, 2006 and 2005 Earnings
at the independent power production business decreased $2.0 million largely
due
to:
· |
Lower
margins of $2.0 million (after tax) related to domestic electric
generating facilities primarily due to lower capacity
revenues
|
· |
Higher
interest expense of $1.9 million (after tax) largely due to debt
related
to the Hardin Generating Facility which was placed in commercial
operation
in March 2006
|
Partially
offsetting the decrease in earnings were:
· |
Higher
earnings from equity method investments of $700,000 (after tax),
due to
the acquisition of the Brazilian Transmission Lines in August
2006
|
· |
Earnings
from an acquisition of a domestic electric generating facility made
since
the comparable prior period
|
Nine
Months Ended September 30, 2006 and 2005
Earnings
at the independent power production business decreased $18.5 million largely
due
to:
· |
Decreased
earnings from equity method investments of $11.8 million, which largely
reflect the absence in 2006 of the 2005 $15.6 million benefit from
the
sale of the Termoceara Generating Facility, partially offset by increased
earnings from the acquisition of the Brazilian Transmission Lines
in
August 2006 and increased earnings at the Trinity Generating Facility
partially resulting from a one-time benefit due to a tax rate
deduction
|
· |
Lower
margins of $4.0 million (after tax) related to domestic electric
generating facilities, as previously
discussed
|
· |
Higher
interest expense of $3.7 million (after tax), as previously
discussed
|
Partially
offsetting the decrease in earnings were earnings from an acquisition of
a
domestic electric generating facility made since the comparable prior
period.
Other
and Intersegment Transactions
Amounts
presented in the preceding tables will not agree with the Consolidated
Statements of Income due to the Company’s other operations and the elimination
of intersegment transactions. The amounts relating to these items are as
follows:
|
|
Three
Months Ended
September
30,
|
|
Nine
Months Ended
September
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
1.8
|
|
$
|
1.6
|
|
$
|
5.9
|
|
$
|
4.3
|
|
Operation
and maintenance
|
|
|
1.2
|
|
|
1.4
|
|
|
4.3
|
|
|
3.7
|
|
Depreciation,
depletion and amortization
|
|
|
.3
|
|
|
.1
|
|
|
.8
|
|
|
.2
|
|
Taxes,
other than income
|
|
|
.1
|
|
|
---
|
|
|
.1
|
|
|
.1
|
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
69.0
|
|
$
|
86.3
|
|
$
|
249.1
|
|
$
|
234.0
|
|
Fuel
and purchased power
|
|
|
.1
|
|
|
---
|
|
|
.2
|
|
|
---
|
|
Purchased
natural gas sold
|
|
|
62.6
|
|
|
80.8
|
|
|
228.8
|
|
|
219.7
|
|
Operation
and maintenance
|
|
|
6.3
|
|
|
5.5
|
|
|
20.1
|
|
|
14.3
|
|
For
further information on intersegment eliminations, see Note 16.
PROSPECTIVE
INFORMATION
The
following information includes highlights of the key growth strategies,
projections and certain assumptions for the Company and its subsidiaries
and
other matters for each of the Company’s businesses. Many of these highlighted
points are forward-looking statements. There is no assurance that the Company’s
projections, including estimates for growth and increases in revenues and
earnings, will in fact be achieved. Please refer to assumptions contained
in
this section, as well as the various important factors listed in Part II,
Item
1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2005
Annual
Report. Changes in such assumptions and factors could cause actual future
results to differ materially from targeted growth, revenue and earnings
projections.
MDU
Resources Group, Inc.
· |
Earnings
per common share for 2006, diluted, are projected in the range of
$1.50 to
$1.65, an increase from prior guidance of $1.47 to
$1.60.
|
· |
The
Company’s long-term compound annual growth goal on earnings per share is
in the range of 7 to 10 percent.
|
Electric
· |
The
Company is analyzing potential projects for accommodating load growth
and
replacing an expiring purchased power contract with Company-owned
generation. This will add to the Company’s base-load capacity and rate
base. New generation is projected to be on line in late 2011 or early
2012. A major commitment decision on the project will be made in
mid-year
2007.
|
· |
This
business continues to pursue growth opportunities by expanding
energy-related services.
|
· |
Montana-Dakota
has obtained and holds, or is in the process of renewing, valid and
existing franchises authorizing it to conduct its electric operations
in
all of the municipalities it serves where such franchises are required.
Montana-Dakota intends to protect its service area and seek renewal
of all
expiring franchises.
|
Natural
gas distribution
· |
As
discussed in Note 22, the Company has entered into a definitive merger
agreement to acquire Cascade. When the acquisition is completed,
it is
expected to significantly enhance regulated earnings and cash flows.
Regulatory approvals are anticipated by mid-year
2007.
|
· |
The
Company is awaiting approval by the MNPUC of its compliance filing
reflecting a natural gas rate increase of $481,000 annually, or
1.3 percent, stemming from a general rate case filing made in
September 2004. For further information, see Note
19.
|
· |
This
business continues to pursue growth by expanding energy-related
services.
|
· |
Montana-Dakota
and Great Plains have obtained and hold, or are in the process of
renewing, valid and existing franchises authorizing them to conduct
their
natural gas operations in all of the municipalities they serve where
such
franchises are required. Montana-Dakota and Great Plains intend to
protect
their service areas and seek renewal of all expiring
franchises.
|
Construction
services
· |
Revenues
in 2006 will be significantly higher than 2005 record
levels.
|
· |
The
Company expects higher margins in 2006 as compared to 2005
levels.
|
· |
Work
backlog as of September 30, 2006, was approximately $505 million
compared
to $406 million at September 30, 2005.
|
Pipeline
and energy services
· |
Firm
capacity for the Grasslands Pipeline increased from 90,000 Mcf per
day to
97,000 Mcf per day effective November 1, 2006, with possible expansion
to
200,000 Mcf per day. Based on anticipated demand, additional incremental
expansions are forecasted over the next few years beginning in
2008.
|
· |
In
2006, total gathering and transportation throughput is expected to
increase approximately 15 percent over 2005
levels.
|
Natural
gas and oil production
· |
The
Company’s long-term compound annual growth goal for production is in the
range of 7 percent to 10 percent. In 2006, the Company expects to
be
within this range.
|
· |
The
Company expects to drill more than 350 wells in 2006. Currently,
this
segment’s net combined natural gas and oil production is approximately
200,000 Mcf equivalent to 210,000 Mcf equivalent per
day.
|
· |
The
Company’s 2006 earnings guidance reflects estimated November-December
NYMEX prices for natural gas in the range of $6.25 to $6.75 per Mcf,
Ventura prices in the range of $5.75 to $6.25 and CIG prices in the
range
of $4.75 to $5.25. Also reflected are the actual natural gas index
prices
for October, which were lower than the November-December estimates.
For
the first nine months of 2006, more than three-fourths of this segment’s
natural gas production was priced at non-NYMEX prices, the majority
of
which was at Ventura pricing.
|
· |
Estimates
of NYMEX crude oil prices for October-December, reflected in the
Company’s
2006 earnings guidance, are projected in the range of $60 to $65
per
barrel.
|
· |
The
Company has hedged approximately 30 percent to 35 percent of its
estimated
natural gas production and 20 percent to 25 percent of its estimated
oil
production for the last three months of 2006. For 2007, the Company
has
hedged approximately 25 percent to 30 percent of its estimated
natural gas production. The hedges that are in place as of October
27,
2006, are summarized in the following
chart:
|
Commodity
|
Index*
|
Period
Outstanding
|
Forward
Notional Volume
(MMBtu)/(Bbl)
|
Price
Swap or
Costless
Collar
Floor-Ceiling
(Per
MMBtu/Bbl)
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
460,000
|
$6.00-$7.60
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
920,000
|
$6.655
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
460,000
|
$6.75-$7.71
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
460,000
|
$6.75-$7.77
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
460,000
|
$7.00-$8.85
|
Natural
Gas
|
NYMEX
|
10/06
- 12/06
|
460,000
|
$7.75-$8.50
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
460,000
|
$7.76
|
Natural
Gas
|
CIG
|
10/06
- 12/06
|
460,000
|
$6.50-$6.98
|
Natural
Gas
|
CIG
|
10/06
- 12/06
|
460,000
|
$7.00-$8.87
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
230,000
|
$8.50-$10.00
|
Natural
Gas
|
Ventura
|
10/06
- 12/06
|
230,000
|
$8.50-$10.15
|
Natural
Gas
|
Ventura
|
10/06
- 10/06
|
155,000
|
$9.25-$12.88
|
Natural
Gas
|
Ventura
|
10/06
- 10/06
|
155,000
|
$9.25-$12.80
|
Natural
Gas
|
CIG
|
11/06
- 12/06
|
305,000
|
$7.00-$8.65
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$8.00-$11.91
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
912,500
|
$8.00-$11.80
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
912,500
|
$8.00-$11.75
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$7.50-$10.55
|
Natural
Gas
|
CIG
|
1/07
- 12/07
|
1,825,000
|
$7.40
|
Natural
Gas
|
CIG
|
1/07
- 12/07
|
1,825,000
|
$7.405
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,460,000
|
$8.25-$10.80
|
Natural
Gas
|
CIG
|
1/07
- 12/07
|
912,500
|
$7.50-$9.12
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$8.29
|
Natural
Gas
|
Ventura
|
11/06
- 3/07
|
755,000
|
$8.00-$9.80
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$7.85-$9.70
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
3,650,000
|
$7.67
|
Crude
Oil
|
NYMEX
|
10/06
- 12/06
|
46,000
|
$43.00-$54.15
|
Crude
Oil
|
NYMEX
|
10/06
- 12/06
|
36,800
|
$60.00-$69.20
|
Crude
Oil
|
NYMEX
|
10/06
- 12/06
|
23,000
|
$60.00-$76.80
|
*Ventura
is an index pricing point related to Northern Natural Gas Co.’s system; CIG
is
an
index pricing point related to Colorado Interstate Gas Co.’s system.
Construction
materials and mining
· |
A
key element of the Company’s long-term strategy for this business is to
further expand its presence in the higher-margin materials business
(rock,
sand, gravel, asphalt cement, ready-mixed concrete and related products),
complementing and expanding on the Company’s expertise. Ongoing efforts to
increase margin are being pursued through the implementation of a
variety
of continuous improvement programs, including corporate purchasing
of
equipment, parts and commodities (asphalt cement, diesel fuel, cement,
etc.), negotiation of contract price escalation provisions and the
utilization of national purchasing accounts. Ownership of, and access
to
aggregate reserves, is key to the vertical integration strategy.
|
· |
The
Company’s overall margin is expected to improve in 2006 as compared to
2005 because of strong markets and demand for construction materials
and
services, favorable weather, and continued operational improvements
in
Texas.
|
· |
Work
backlog as of September 30, 2006, of approximately $594 million,
includes
a higher expected average margin than the backlog of $597 million
at
September 30, 2005.
|
Independent
power production
· |
Earnings
at this segment are expected to be minimal in 2006, reflecting primarily
the sale of the Company’s Brazilian electric generating facility in June
2005, significantly higher interest expense related to the construction
of
the Hardin Generating Facility and lower revenues because of the
bridge
contract renewal at the Brush Generating Facility. The bridge contract
will be replaced by a more favorably priced 10-year contract beginning
in
May 2007.
|
· |
This
segment continues to evaluate opportunities for domestic and international
investments, utilizing the Company’s disciplined approach for
acquisitions.
|
NEW
ACCOUNTING STANDARDS
For
information regarding new accounting standards, see Note 11, which is
incorporated by reference.
CRITICAL
ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The
Company’s critical accounting policies involving significant estimates include
impairment testing of long-lived assets and intangibles, impairment testing
of
natural gas and oil production properties, revenue recognition, purchase
accounting, asset retirement obligations, and pension and other postretirement
benefits. There were no material changes in the Company’s critical accounting
policies involving significant estimates from those reported in the 2005
Annual
Report. For more information on critical accounting policies involving
significant estimates, see Part II, Item 7 in the 2005 Annual
Report.
LIQUIDITY
AND CAPITAL COMMITMENTS
Cash
flows
Operating
activities Net
income before depreciation, depletion and amortization is a significant
contributor to cash flows from operating activities. The changes in cash
flows
from operating activities generally follow the results of operations as
discussed in Financial and Operating Data and also are affected by changes
in
working capital. Cash flows provided by operating activities in the first
nine
months of 2006 increased $84.9 million from the comparable 2005 period, the
result of:
· |
Higher
depreciation, depletion, and amortization expense of $38.9 million,
largely at the natural gas and oil production business, as previously
discussed
|
· |
Increased
net income of $31.4 million, largely increased earnings at the
construction materials and mining, natural gas and oil production
and
construction services businesses
|
· |
Higher
deferred income taxes of $17.2 million due to increased property,
plant,
and equipment balances at the natural gas and oil production business;
natural gas costs recoverable through rate adjustments at the natural
gas
distribution business; and costs associated with the repurchase of
certain
first mortgage bonds at the electric and natural gas distribution
businesses
|
· |
Decreased
earnings, net of distributions, from equity method investments of
$11.1
million, primarily the result of the sale of the Termoceara Generating
Facility
|
Partially
offsetting the increase in cash flows from operating activities were higher
working capital requirements of $15.3 million.
Investing
activities Cash
flows used in investing activities in the first nine months of 2006 increased
$122.5 million compared to the comparable 2005 period, the result
of:
· |
Increased
capital expenditures at the natural gas and oil production business,
largely due to additional exploration and development, and higher
ongoing
capital expenditures at the construction materials and mining business;
partially offset by lower capital expenditures related to the Hardin
Generating Facility
|
· |
Lower
proceeds from sale of equity method investment due to the absence
in 2006
of the 2005 sale of the Termoceara Generating
Facility
|
· |
Increased
investments largely due to the acquisition of the Brazilian Transmission
Lines in 2006
|
Partially
offsetting this increase was a decrease in cash flows used for acquisitions
of
$38.5 million, largely at the natural gas and oil production
business.
Financing
activities Cash
flows provided by financing activities in the first nine months of 2006
increased $3.0 million compared to the comparable 2005 period, the result
of an
increase in the issuance of long-term debt and common stock, partially offset
by
an increase in the repayment of long-term debt and dividends paid.
Defined
benefit pension plans
There
are
no material changes to the Company’s qualified noncontributory defined benefit
pension plans from those reported in the 2005 Annual Report. For further
information, see Note 18.
Capital
expenditures
Net
capital expenditures for the first nine months of 2006 were $487.1 million
and
are estimated to be approximately $620 million for the year 2006. Estimated
capital expenditures include those for:
· |
Routine
equipment maintenance and replacements
|
· |
Buildings,
land and building improvements
|
· |
Pipeline
and gathering projects
|
· |
Further
enhancement of natural gas and oil production and reserve
growth
|
· |
Power
generation opportunities, including certain costs for additional
electric
generating capacity
|
· |
Other
growth opportunities
|
Approximately
24 percent of estimated 2006 net capital expenditures are associated with
completed acquisitions. The Company continues to evaluate potential future
acquisitions and other growth opportunities; however, they are dependent
upon
the availability of economic opportunities and, as a result, capital
expenditures may vary significantly from the estimated 2006 capital expenditures
referred to previously. It is anticipated that all of the funds required
for
capital expenditures will be met from various sources, including internally
generated funds; commercial paper credit facilities at Centennial Energy
Holdings, Inc. and MDU Resources Group, Inc., as described below; and through
the issuance of debt and the Company’s equity securities.
Capital
resources
Certain
debt instruments of the Company and its subsidiaries, including those discussed
below, contain restrictive covenants, all of which the Company and its
subsidiaries were in compliance with at September 30, 2006.
MDU
Resources Group, Inc. The
Company has a revolving credit agreement with various banks totaling $125
million (with provision for an increase, at the option of the Company on
stated
conditions and upon regulatory approval, up to a maximum of $150 million).
There
were no amounts outstanding under the credit agreement at September 30, 2006.
The credit agreement supports the Company’s $100 million commercial paper
program. Under the Company’s commercial paper program, $12.0 million was
outstanding at September 30, 2006. The commercial paper borrowings are
classified as long-term debt as they are intended to be refinanced on a
long-term basis through continued commercial paper borrowings (supported
by the
credit agreement, which expires in June 2011). In August 2006, the Company
borrowed $100 million through the issuance of unsecured notes. The funds
were
used primarily to pay down commercial paper borrowings and for general corporate
purposes in connection with the Company’s electric and natural gas distribution
businesses.
The
Company’s objective is to maintain acceptable credit ratings in order to access
the capital markets through the issuance of commercial paper. Minor fluctuations
in the Company’s credit ratings have not limited, nor would they be expected to
limit, the Company’s ability to access the capital markets. In the event of a
minor downgrade, the Company may experience a nominal basis point increase
in
overall interest rates with respect to its cost of borrowings. If the Company
were to experience a significant downgrade of its credit ratings, it may
need to
borrow under its credit agreement.
Prior
to
the maturity of the credit agreement, the Company expects that it will negotiate
the extension or replacement of this agreement. If the Company is unable
to
successfully negotiate an extension of, or replacement for, the credit
agreement, or if the fees on this facility became too expensive, which the
Company does not currently anticipate, the Company would seek alternative
funding. One source of alternative funding might involve the securitization
of
certain Company assets.
In
order
to borrow under the Company’s credit agreement, the Company must be in
compliance with the applicable covenants and certain other conditions, including
covenants not to permit, as of the end of any fiscal quarter, (A) the ratio
of
funded debt to total capitalization (determined on a consolidated basis)
to be
greater than 65 percent or (B) the ratio of funded debt to capitalization
(determined with respect to the Company alone, excluding its subsidiaries)
to be
greater than 65 percent. Also included is a covenant that does not permit
the ratio of the Company's earnings before interest, taxes, depreciation
and
amortization to interest expense (determined with respect to the Company
alone,
excluding its subsidiaries), for the 12-month period ended each fiscal quarter,
to be less than 2.5 to 1. Other covenants include restrictions on the sale
of
certain assets and on the making of certain investments. The Company was
in
compliance with these covenants and met the required conditions at September
30,
2006. In the event the Company does not comply with the applicable covenants
and
other conditions, alternative sources of funding may need to be pursued,
as
previously described.
There
are
no credit facilities that contain cross-default provisions between the Company
and any of its subsidiaries.
The
Company's issuance of first mortgage debt is subject to certain restrictions
imposed under the terms and conditions of its Indenture of Mortgage. Generally,
those restrictions require the Company to fund $1.43 of unfunded property
or use
$1.00 of refunded bonds for each dollar of indebtedness incurred under the
Indenture and, in some cases, to certify to the trustee that annual earnings
(pretax and before interest charges), as defined in the Indenture, equal
at
least two times its annualized first mortgage bond interest costs. Under
the
more restrictive of the tests, as of September 30, 2006, the Company could
have
issued approximately $452 million of additional first mortgage
bonds.
The
Company's coverage of fixed charges including preferred dividends was 6.2
times
and 6.1 times for the 12 months ended September 30, 2006 and December
31, 2005, respectively. Additionally, the Company's first mortgage bond interest
coverage was 25.0 times and 10.2 times for the 12 months ended
September 30, 2006 and December 31, 2005, respectively. Common
stockholders' equity as a percent of total capitalization (net of long-term
debt
due within one year) was 61 percent and 63 percent at September 30, 2006
and December 31, 2005, respectively.
The
Company has repurchased, and may from time to time seek to repurchase,
outstanding first mortgage bonds through open market purchases or privately
negotiated transactions. The Company will evaluate any such transactions
in
light of then existing market conditions, taking into account its liquidity
and
prospects for future access to capital. Between January 1 and September 30,
2006, the Company repurchased $68.0 million of first mortgage bonds. As of
September 30, 2006, the Company had $57.0 million of first mortgage bonds
outstanding, $30.0 million of which were held by the Indenture trustee for
the
benefit of the Senior Note holders. At such time as the aggregate principal
amount of the Company’s outstanding first mortgage bonds, other than those held
by the Indenture trustee, is $20 million or less, the Company would have
the
ability, subject to satisfying certain specified conditions, to require that
any
debt issued under its Indenture, dated as of December 15, 2003, as supplemented,
from the Company to The Bank of New York, as trustee, become unsecured and
rank
equally with all of the Company’s other unsecured and unsubordinated debt (as of
September 30, 2006, the only such debt outstanding under the Indenture was
$30.0 million in aggregate principal amount of the Company’s 5.98% Senior Notes
due in 2033).
On
July
27, 2006, the Company entered into a Sales Agency Financing Agreement with
Wells
Fargo Securities, LLC with respect to the issuance and sale of up to 3,000,000
shares of the Company’s common stock, par value $1.00 per share, together with
preference share purchase rights appurtenant thereto. The common stock may
be
offered for sale, from time to time, in accordance with the terms and conditions
of the agreement, which terminates on June 30, 2007. Proceeds from the sale
of shares of common stock under the agreement are expected to be used for
corporate development purposes and other general corporate purposes. The
offering is made pursuant to the Company’s shelf registration statement on Form
S-3, as amended, which became effective on September 26, 2003, as supplemented
by a prospectus supplement, dated July 27, 2006, filed with the Securities
and
Exchange Commission pursuant to Rule 424(b) under the Securities Act of 1933,
as
amended. The Company has not issued any stock under the Sales Agency Financing
Agreement through September 30, 2006.
Centennial
Energy Holdings, Inc.
Centennial has three revolving credit agreements with various banks and
institutions totaling $437.9 million with certain provisions allowing for
increased borrowings. These credit agreements support Centennial’s
$400 million commercial paper program. There were no outstanding borrowings
under the Centennial credit agreements at September 30, 2006. Under the
Centennial commercial paper program, $292.5 million was outstanding at September
30, 2006. The Centennial commercial paper borrowings are classified as long-term
debt as Centennial intends to refinance these borrowings on a long-term basis
through continued Centennial commercial paper borrowings (supported by
Centennial credit agreements). One of these credit agreements is for $400
million, which includes a provision for an increase, at the option of Centennial
on stated conditions, up to a maximum of $450 million and expires on
August 26, 2010. Another agreement is for $17.9 million and expires on
April 30, 2007. Centennial intends to negotiate the extension or replacement
of
these agreements prior to their maturities. The third agreement is an
uncommitted line for $20 million and may be terminated by the bank at any
time.
As of September 30, 2006, $42.5 million of letters of credit were
outstanding, as discussed in Note 20, of which $25.9 million reduced amounts
available under these agreements.
Centennial
has an uncommitted long-term master shelf agreement that allows for borrowings
of up to $550 million (previously $450 million). Under the terms of the master
shelf agreement, $489.5 million was outstanding at September 30, 2006. On
October 16, 2006, Centennial borrowed an additional $50.0 million under this
agreement. The ability to request additional borrowings under this master
shelf
agreement expires on May 8, 2009. To meet potential future financing needs,
Centennial may pursue other financing arrangements, including private and/or
public financing.
Centennial’s
objective is to maintain acceptable credit ratings in order to access the
capital markets through the issuance of commercial paper. Minor fluctuations
in
Centennial’s credit ratings have not limited, nor would they be expected to
limit, Centennial’s ability to access the capital markets. In the event of a
minor downgrade, Centennial may experience a nominal basis point increase
in
overall interest rates with respect to its cost of borrowings. If Centennial
were to experience a significant downgrade of its credit ratings, it may
need to
borrow under its committed bank lines.
Prior
to
the maturity of the Centennial credit agreements, Centennial expects that
it
will negotiate the extension or replacement of these agreements, which provide
credit support to access the capital markets. In the event Centennial was
unable
to successfully negotiate these agreements, or in the event the fees on such
facilities became too expensive, which Centennial does not currently anticipate,
it would seek alternative funding. One source of alternative funding might
involve the securitization of certain Centennial assets.
In
order
to borrow under Centennial’s credit agreements and the Centennial uncommitted
long-term master shelf agreement, Centennial and certain of its subsidiaries
must be in compliance with the applicable covenants and certain other
conditions, including covenants not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater than
65
percent (for the $400 million credit agreement) and 60 percent (for the $17.9
million credit agreement and the master shelf agreement). Also included is
a
covenant that does not permit the ratio of Centennial’s earnings before
interest, taxes, depreciation and amortization to interest expense, for the
12-month period ended each fiscal quarter, to be less than 2.5 to 1 (for
the
$400 million credit agreement), 2.25 to 1 (for the $17.9 million credit
agreement) and 1.75 to 1 (for the master shelf agreement). Other covenants
include minimum consolidated net worth, limitation on priority debt and
restrictions on the sale of certain assets and on the making of certain loans
and investments. Centennial and such subsidiaries were in compliance with
these
covenants and met the required conditions at September 30, 2006. In the event
Centennial or such subsidiaries do not comply with the applicable covenants
and
other conditions, alternative sources of funding may need to be pursued as
previously described.
Certain
of Centennial’s financing agreements contain cross-default provisions. These
provisions state that if Centennial or any subsidiary of Centennial fails
to
make any payment with respect to any indebtedness or contingent obligation,
in
excess of a specified amount, under any agreement that causes such indebtedness
to be due prior to its stated maturity or the contingent obligation to become
payable, the applicable agreements will be in default. Certain of Centennial’s
financing agreements and Centennial’s practice limit the amount of subsidiary
indebtedness.
Williston
Basin Interstate Pipeline Company Williston
Basin has an uncommitted long-term master shelf agreement that allows for
borrowings of up to $100 million. Under the terms of the master shelf agreement,
$80.0 million was outstanding at September 30, 2006. The ability to request
additional borrowings under this master shelf agreement expires on December
20,
2008.
In
order
to borrow under its uncommitted long-term master shelf agreement, Williston
Basin must be in compliance with the applicable covenants and certain other
conditions, including covenants not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater than
55
percent. Other covenants include limitation on priority debt and some
restrictions on the sale of certain assets and the making of certain
investments. Williston Basin was in compliance with these covenants and met the
required conditions at September 30, 2006. In the event Williston Basin does
not
comply with the applicable covenants and other conditions, alternative sources
of funding may need to be pursued.
Off
balance sheet arrangements
In
connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly
owned subsidiary of the Company has agreed to indemnify Petrobras for 49
percent
of any losses that Petrobras may incur from certain contingent liabilities
specified in the purchase agreement. Centennial has agreed to unconditionally
guarantee payment of the indemnity obligations to Petrobras for periods ranging
from approximately two to five and a half years from the date of sale. The
guarantee was required by Petrobras as a condition to closing the sale of
MPX.
Contractual
obligations and commercial commitments
At
September 30, 2006, the Company’s contractual obligations related to long-term
debt, estimated interest payments, operating leases and purchase commitments
(for the twelve months ended September 30, of each year listed in the table
below) were as follows:
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Long-term
debt
|
|
$
|
99.0
|
|
$
|
131.9
|
|
$
|
87.3
|
|
$
|
314.7
|
|
$
|
79.3
|
|
$
|
693.8
|
|
$
|
1,406.0
|
|
Estimated
interest payments*
|
|
|
75.6
|
|
|
69.9
|
|
|
62.5
|
|
|
58.2
|
|
|
40.7
|
|
|
218.2
|
|
|
525.1
|
|
Operating
leases
|
|
|
15.9
|
|
|
12.5
|
|
|
10.5
|
|
|
9.6
|
|
|
8.4
|
|
|
35.6
|
|
|
92.5
|
|
Purchase
commitments
|
|
|
205.2
|
|
|
101.4
|
|
|
66.5
|
|
|
63.0
|
|
|
58.5
|
|
|
245.4
|
|
|
740.0
|
|
|
|
$
|
395.7
|
|
$
|
315.7
|
|
$
|
226.8
|
|
$
|
445.5
|
|
$
|
186.9
|
|
$
|
1,193.0
|
|
$
|
2,763.6
|
|
*
Estimated
interest payments are calculated based on the applicable rates
and payment
dates.
|
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The
Company is exposed to the impact of market fluctuations associated with
commodity prices and interest rates. The Company has policies and procedures
to
assist in controlling these market risks and utilizes derivatives to manage
a
portion of its risk.
Commodity
price risk
Fidelity
utilizes derivative instruments to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil on its
forecasted sales of natural gas and oil production. For more information
on
derivative instruments and commodity price risk, see Part II, Item 7A in
the
2005 Annual Report, and Notes 12 and 15.
The
following table summarizes derivative instruments entered into by Fidelity
as of
September 30, 2006. These agreements call for Fidelity to receive fixed prices
and pay variable prices.
(Notional
amount and fair value in thousands)
|
|
Weighted
Average
Fixed
Price
(Per
MMBtu)
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
Fair
Value
|
|
Natural
gas swap agreements maturing in 2006
|
|
|
$7.02
|
|
1,380
|
|
|
$2,218
|
|
Natural
gas swap agreements maturing in 2007
|
|
|
$7.70
|
|
5,475
|
|
|
$6,362
|
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
MMBtu)
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2006
|
|
$
|
7.24/$8.72
|
|
|
4,600
|
|
|
$10,027
|
|
Natural
gas collar agreements maturing in 2007
|
|
$
|
7.87/$10.74
|
|
|
10,123
|
|
|
$12,787
|
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
barrel)
|
|
Forward
Notional
Volume
(In
barrels)
|
|
Fair
Value
|
|
Oil
collar agreements maturing in 2006
|
|
$
|
52.61/$64.31
|
|
|
106
|
|
|
$(464)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate risk
There
were no material changes to interest rate risk faced by the Company from
those
reported in the 2005 Annual Report. For more information on interest rate
risk,
see Part II, Item 7A in the 2005 Annual Report.
ITEM
4. CONTROLS AND PROCEDURES
The
following information includes the evaluation of disclosure controls and
procedures by the Company’s chief executive officer and the chief financial
officer, along with any significant changes in internal controls of the
Company.
Evaluation
of disclosure controls and procedures
The
term
"disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e)
of the Exchange Act. These rules refer to the controls and other procedures
of a
company that are designed to ensure that information required to be disclosed
by
a company in the reports it files under the Exchange Act is recorded, processed,
summarized and reported within required time periods. The Company’s chief
executive officer and chief financial officer have evaluated the effectiveness
of the Company’s disclosure controls and procedures and they have concluded
that, as of the end of the period covered by this report, such controls and
procedures were effective.
Changes
in internal controls
The
Company maintains a system of internal accounting controls that is designed
to
provide reasonable assurance that the Company’s transactions are properly
authorized, the Company’s assets are safeguarded against unauthorized or
improper use, and the Company’s transactions are properly recorded and reported
to permit preparation of the Company’s financial statements in conformity with
generally accepted accounting principles in the United States of America.
There
were no changes in the Company’s internal control over financial reporting that
occurred during the period covered by this report that have materially affected,
or are reasonably likely to materially affect, the Company’s internal control
over financial reporting.
PART
II -- OTHER INFORMATION
ITEM
1. LEGAL PROCEEDINGS
For
information regarding legal proceedings, see Note 20, which is incorporated
by
reference.
ITEM
1A. RISK FACTORS
This
Form
10-Q contains forward-looking statements within the meaning of Section 21E
of
the Exchange Act. Forward-looking statements are all statements other than
statements of historical fact, including without limitation those statements
that are identified by the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts" and similar expressions.
The
Company is including the following factors and cautionary statements in this
Form 10-Q to make applicable and to take advantage of the safe harbor provisions
of the Private Securities Litigation Reform Act of 1995 for any forward-looking
statements made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies, future
events or performance, and underlying assumptions (many of which are based,
in
turn, upon further assumptions) and other statements that are other than
statements of historical facts. From time to time, the Company may publish
or
otherwise make available forward-looking statements of this nature, including
statements contained within Prospective Information. All these subsequent
forward-looking statements, whether written or oral and whether made by or
on
behalf of the Company, also are expressly qualified by these factors and
cautionary statements.
Forward-looking
statements involve risks and uncertainties, which could cause actual results
or
outcomes to differ materially from those expressed. The Company's expectations,
beliefs and projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation, management's
examination of historical operating trends, data contained in the Company's
records and other data available from third parties. Nonetheless, the Company's
expectations, beliefs or projections may not be achieved or accomplished.
Any
forward-looking statement contained in this document speaks only as of the
date
on which the statement is made, and the Company undertakes no obligation
to
update any forward-looking statement or statements to reflect events or
circumstances that occur after the date on which the statement is made or
to
reflect the occurrence of unanticipated events. New factors emerge from time
to
time, and it is not possible for management to predict all of the factors,
nor
can it assess the effect of each factor on the Company's business or the
extent
to which any factor, or combination of factors, may cause actual results
to
differ materially from those contained in any forward-looking
statement.
There
are
no material changes in the Company’s risk factors from those reported in Part I,
Item 1A - Risk Factors of the 2005 Annual Report other than the risks associated
with the ongoing litigation and administrative proceedings in connection
with
the Company’s CBNG development activities, and risks related to foreign
operations, a pending utility company acquisition, litigation in connection
with
one of the Company’s storage reservoirs and increases in employee and retiree
benefit costs, as discussed below. These factors and the other matters discussed
herein are important factors that could cause actual results or outcomes
for the
Company to differ materially from those discussed in the forward-looking
statements included elsewhere in this document.
Environmental
and Regulatory Risks
One
of the Company’s subsidiaries is subject to ongoing litigation and
administrative proceedings in connection with its CBNG development activities.
These proceedings have caused delays in CBNG drilling activity, and the ultimate
outcome of the actions could have a material negative effect on existing
CBNG
operations and/or the future development of its CBNG
properties.
Fidelity
has been named as a defendant in, and/or certain of its operations are or
have
been the subject of, more than a dozen lawsuits filed in connection with
its
CBNG development in the Powder River Basin in Montana and Wyoming. If the
plaintiffs are successful in these lawsuits, the ultimate outcome of the
actions
could have a material negative effect on Fidelity's existing CBNG operations
and/or the future development of its CBNG properties.
The
BER
in March 2006 issued a decision in a rulemaking proceeding, initiated by
the
NPRC, that amends the non-degradation policy applicable to water discharged
in
connection with CBNG operations. The amended policy includes additional
limitations on factors deemed harmful, thereby restricting water discharges
even
further than previous standards. Due in part to this amended policy, in May
2006, the Northern Cheyenne Tribe commenced litigation in Montana state court
challenging two five-year water discharge permits that the Montana DEQ granted
to Fidelity in February 2006 and which are critical to Fidelity’s ability to
manage water produced under present and future CBNG operations. If these
permits
are set aside, Fidelity’s CBNG operations in Montana could be significantly and
adversely affected.
Risks
Relating to Foreign Operations
The
value of the Company’s investments in foreign operations may diminish due to
political, regulatory and economic conditions and changes in currency exchange
rates in countries where the Company does business.
The
Company is subject to political, regulatory and economic conditions and changes
in currency exchange rates in foreign countries where the Company does business.
Significant changes in the political, regulatory or economic environment
in
these countries could negatively affect the value of the Company’s investments
located in these countries. Also, since the Company is unable to predict
the
fluctuations in the foreign currency exchange rates, these fluctuations may
have
an adverse impact on the Company’s results of operations.
Other
Risks
The
Company’s pending acquisition of Cascade may be delayed or may not occur if
certain conditions are not satisfied. Upon completion of the acquisition,
if the
Company is unable to integrate the Cascade operations effectively, its future
financial position or results of operations may be adversely
affected.
The
Company has entered into a definitive merger agreement to acquire Cascade.
The
total value of the transaction, including the assumption of certain
indebtedness, is approximately $475 million. The completion of the acquisition
is subject to the approval of various regulatory authorities, as well as
antitrust clearance under the Hart-Scott-Rodino Act, and the satisfaction
of
other customary closing conditions. The Company’s pending acquisition of Cascade
may be delayed or may not occur if the Company is unable to timely obtain
necessary regulatory approvals, satisfy closing conditions or obtain financing.
If the Company is unable to integrate the Cascade operations effectively,
its
future financial position or results of operations may be adversely
affected.
One
of the Company’s subsidiaries is engaged in litigation with a nonaffiliated
natural gas producer that has been conducting drilling and production operations
that the subsidiary believes is causing diversion and loss of storage gas
from
one of its storage reservoirs. If the subsidiary is not able to obtain relief
through the courts or regulatory process, its storage operations could be
materially and adversely affected.
Williston
Basin has filed suit in Federal court in Montana seeking to recover unspecified
damages from Anadarko and its wholly owned subsidiary, Howell, and to enjoin
Anadarko’s and Howell’s present and future operations in and near the Elk Basin
Storage Reservoir. Based on relevant information, including reservoir and
well
pressure data, Williston Basin believes that Elk Basin Storage Reservoir
pressures have decreased and that the storage reservoir has lost gas as a
result
of Anadarko’s and Howell’s drilling and production activities. In related
litigation, Howell filed suit in Wyoming state district court against Williston
Basin asserting that it is entitled to produce any gas that might escape
from
Williston Basin’s storage reservoir. Williston Basin has answered Howell’s
complaint and has asserted counterclaims. If Williston Basin is unable to
obtain
timely relief through the courts or regulatory process, its present and future
gas storage operations could be materially and adversely affected.
Other
factors that could impact the Company’s businesses.
In
addition to those reported in Part I, Item 1A - Risk Factors of the 2005
Annual
Report, the following factor may also impact the Company’s financial results in
future periods:
· |
Increases
in employee and retiree benefit costs
|
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
Between
July 1, 2006 and September 30, 2006, the Company issued 320,697 shares of
Common
Stock, $1.00 par value, and the preference share purchase rights appurtenant
thereto, as part of the consideration paid by the Company in the acquisition
of
a business acquired by the Company in this period. The Common Stock and
preference share purchase rights issued by the Company in this transaction
were
issued in a private transaction exempt from registration under the Securities
Act of 1933 pursuant to Section 4 (2) thereof, Rule 506 promulgated thereunder,
or both. The classes of persons to whom these securities were sold were either
accredited investors or other persons to whom such securities were permitted
to
be offered under the applicable exemption.
ITEM
6. EXHIBITS
|
|
12
|
Computation
of Ratio of Earnings to Fixed Charges and Combined Fixed Charges
and
Preferred Stock Dividends
|
|
|
31(a)
|
Certification
of Chief Executive Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
|
|
31(b)
|
Certification
of Chief Financial Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
|
|
32
|
Certification
of Chief Executive Officer and Chief Financial Officer furnished
pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
|
|
|
MDU
Resources Group, Inc. agrees to furnish to the SEC upon request any instrument
with respect to long-term debt that MDU Resources Group, Inc. has not filed
as
an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of
Regulation S-K.
SIGNATURES
Pursuant
to the requirements of the Exchange Act, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly
authorized.
|
|
MDU
RESOURCES GROUP, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
DATE:
November
3, 2006
|
|
BY:
|
/s/
Vernon A. Raile
|
|
|
|
Vernon
A. Raile
|
|
|
|
Executive
Vice President, Treasurer
|
|
|
|
and
Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
BY:
|
/s/
Doran N. Schwartz
|
|
|
|
Doran
N. Schwartz
|
|
|
|
Vice
President and Chief Accounting
Officer
|
EXHIBIT
INDEX
Exhibit
No.
|
|
12
|
Computation
of Ratio of Earnings to Fixed Charges and Combined Fixed Charges
and
Preferred Stock Dividends
|
|
|
31(a)
|
Certification
of Chief Executive Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
|
|
31(b)
|
Certification
of Chief Financial Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
|
|
32
|
Certification
of Chief Executive Officer and Chief Financial Officer furnished
pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
|
MDU
Resources Group, Inc. agrees to furnish to the SEC upon request any instrument
with respect to long-term debt that MDU Resources Group, Inc. has not filed
as
an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of
Regulation S-K.