form10q.htm
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, 2007
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 November 2, 2007: 182,387,920 shares.
DEFINITIONS
The
following abbreviations and acronyms used in this Form 10-Q are defined
below:
Abbreviation
or Acronym
2006
Annual Report
|
Company's
Annual Report on Form 10-K for the year ended December 31,
2006
|
ALJ
|
Administrative
Law Judge
|
Anadarko
|
Anadarko
Petroleum Corporation
|
APB
|
Accounting
Principles Board
|
APB
Opinion No. 28
|
Interim
Financial Reporting
|
Badger
Hills Project
|
Tongue
River-Badger Hills Project
|
Bbl
|
Barrel
of oil or other liquid hydrocarbons
|
Bcf
|
Billion
cubic feet
|
BER
|
Montana
Board of Environmental Review
|
Big
Stone Station
|
450-MW
coal-fired electric generating facility located near Big Stone City,
South
Dakota (22.7 percent ownership)
|
Big
Stone II
|
Proposed
600-MW coal-fired electric generating facility located near Big Stone
City, South Dakota (19.33 percent ownership)
|
BLM
|
Bureau
of Land Management
|
Brazilian
Transmission Lines
|
Company’s
equity method investment in companies owning ECTE, ENTE and
ERTE
|
Btu
|
British
thermal unit
|
Carib
Power
|
Carib
Power Management LLC
|
Cascade
|
Cascade
Natural Gas Corporation, an indirect wholly owned subsidiary of MDU
Energy
Capital
|
CBNG
|
Coalbed
natural gas
|
CEM
|
Colorado
Energy Management, LLC, a former direct wholly owned subsidiary of
Centennial Resources (sold in the third quarter of
2007)
|
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 former direct wholly owned subsidiary of Centennial
Resources (sold in the third quarter of 2007)
|
Centennial
Resources
|
Centennial
Energy Resources LLC, a direct wholly owned subsidiary of
Centennial
|
Clean
Air Act
|
Federal
Clean Air Act
|
Clean
Water Act
|
Federal
Clean Water Act
|
CMS
|
Cost
Management Services, Inc.
|
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
|
EBSR
|
Elk
Basin Storage Reservoir, one of Williston Basin's natural gas storage
reservoirs, which is located in Montana and Wyoming
|
ECTE
|
Empresa
Catarinense de Transmissão de Energia S.A.
|
EIS
|
Environmental
Impact Statement
|
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, as amended
|
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
|
Hardin
Generating Facility
|
116-MW
coal-fired electric generating facility near Hardin, Montana (sold
in the
third quarter of 2007)
|
Hartwell
|
Hartwell
Energy Limited Partnership, a former equity method investment of
the
Company (sold in the third quarter of 2007)
|
Howell
|
Howell
Petroleum Corporation, a wholly owned subsidiary of
Anadarko
|
Indenture
|
Indenture
dated as of December 15, 2003, as supplemented, from the Company
to The
Bank of New York, as Trustee
|
Innovatum
|
Innovatum,
Inc., a former indirect wholly owned subsidiary of WBI Holdings (the
stock
and a portion of Innovatum’s assets were sold during the fourth quarter of
2006)
|
Knife
River
|
Knife
River Corporation, a direct wholly owned subsidiary of
Centennial
|
kWh
|
Kilowatt-hour
|
LWG
|
Lower
Willamette Group
|
MBbls
|
Thousand
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., a direct wholly owned subsidiary
of
Centennial
|
MDU
Energy Capital
|
MDU
Energy Capital, LLC, a direct wholly owned subsidiary of the
Company
|
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
|
Mortgage
|
Indenture
of Mortgage dated May 1, 1939, as supplemented, amended and restated,
from
the Company to The Bank of New York and Douglas J. MacInnes, successor
trustees
|
MPX
|
MPX
Termoceara Ltda. (49 percent ownership, sold in June
2005)
|
MTPSC
|
Montana
Public Service Commission
|
MW
|
Megawatt
|
ND
Health Department
|
North
Dakota Department of Health
|
NDPSC
|
North
Dakota Public Service Commission
|
NEPA
|
National
Environmental Policy Act
|
NHPA
|
National
Historic Preservation Act
|
Ninth
Circuit
|
U.S.
Ninth Circuit Court of Appeals
|
NPRC
|
Northern
Plains Resource Council
|
OPUC
|
Oregon
Public Utility Commission
|
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
|
PSD
|
Prevention
of Significant Deterioration
|
SEC
|
U.S.
Securities and Exchange Commission
|
SEIS
|
Supplemental
Environmental Impact Statement
|
SFAS
|
Statement
of Financial Accounting Standards
|
SFAS
No. 71
|
Accounting
for the Effects of Certain Types of Regulation
|
SFAS
No. 87
|
Employers’
Accounting for Pensions
|
SFAS
No. 109
|
Accounting
for Income Taxes
|
SFAS
No. 142
|
Goodwill
and Other Intangible Assets
|
SFAS
No. 144
|
Accounting
for the Impairment or Disposal of Long-Lived Assets
|
SFAS
No. 157
|
Fair
Value Measurements
|
SFAS
No. 159
|
The
Fair Value Option for Financial Assets and Financial
Liabilities
|
Trinity
Generating Facility
|
225-MW
natural gas-fired electric generating facility in Trinidad and Tobago
(49.99 percent ownership, sold in the first quarter of
2007)
|
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
|
WUTC
|
Washington
Utilities and Transportation Commission
|
Wyoming
Federal District Court
|
U.S.
District Court for the District of Wyoming
|
Wyoming
DEQ
|
Wyoming
State Department of Environmental Quality
|
|
|
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. Cascade distributes natural
gas
in Washington and Oregon. 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 17.
INDEX
Part
I -- Financial Information
Consolidated
Statements of Income
--
Three
and Nine Months Ended September
30, 2007 and 2006
Consolidated
Balance Sheets
--
September
30, 2007 and 2006, and
December 31, 2006
Consolidated
Statements of Cash Flows
--
Nine
Months Ended September 30, 2007
and 2006
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands, except per share amounts)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric, natural gas distribution and pipeline and energy
services
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Construction services, natural gas and oil production, construction
materials and mining, and other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric, natural gas distribution and pipeline and energy
services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction services, natural gas and oil production, construction
materials and mining, independent power production and
other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
|
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|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Income
from continuing operations
|
|
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|
|
|
|
|
|
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|
|
|
|
|
|
|
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|
|
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Income
from discontinued operations, net of tax (Note
4)
|
|
|
|
|
|
|
|
|
|
|
|
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Dividends
on preferred stocks
|
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|
|
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$ |
|
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|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Earnings
per common share -- basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued
operations
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Discontinued
operations, net of
tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share --
basic
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Earnings
per common share -- diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued
operations
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Discontinued
operations, net of
tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per common share --
diluted
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Dividends
per common share
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Weighted average common shares outstanding --
basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding --
diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
BALANCE SHEETS
(Unaudited)
|
|
September
30,
2007
|
|
|
September
30,
2006
|
|
|
December
31,
2006
|
|
(In
thousands, except shares and per share amounts)
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
94,528
|
|
|
$ |
68,786
|
|
|
$ |
73,078
|
|
Receivables,
net
|
|
|
748,858
|
|
|
|
714,754
|
|
|
|
622,478
|
|
Inventories
|
|
|
254,710
|
|
|
|
225,234
|
|
|
|
204,440
|
|
Deferred
income taxes
|
|
|
---
|
|
|
|
8,698
|
|
|
|
---
|
|
Prepayments
and other current assets
|
|
|
129,421
|
|
|
|
77,615
|
|
|
|
81,083
|
|
Current
assets held for sale and related to discontinued
operations
|
|
|
594
|
|
|
|
12,529
|
|
|
|
12,656
|
|
|
|
|
1,228,111
|
|
|
|
1,107,616
|
|
|
|
993,735
|
|
Investments
|
|
|
112,283
|
|
|
|
155,989
|
|
|
|
155,111
|
|
Property,
plant and equipment
|
|
|
5,740,966
|
|
|
|
4,620,912
|
|
|
|
4,727,725
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
2,203,218
|
|
|
|
1,683,286
|
|
|
|
1,735,302
|
|
|
|
|
3,537,748
|
|
|
|
2,937,626
|
|
|
|
2,992,423
|
|
Deferred
charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
430,644
|
|
|
|
226,672
|
|
|
|
224,298
|
|
Other
intangible assets, net
|
|
|
29,115
|
|
|
|
22,418
|
|
|
|
22,802
|
|
Other
|
|
|
152,607
|
|
|
|
100,542
|
|
|
|
103,840
|
|
Noncurrent
assets held for sale and related to discontinued
operations
|
|
|
140
|
|
|
|
415,693
|
|
|
|
411,265
|
|
|
|
|
612,506
|
|
|
|
765,325
|
|
|
|
762,205
|
|
|
|
$ |
5,490,648
|
|
|
$ |
4,966,556
|
|
|
$ |
4,903,474
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt due within one year
|
|
$ |
131,971
|
|
|
$ |
98,980
|
|
|
$ |
84,034
|
|
Accounts
payable
|
|
|
310,509
|
|
|
|
318,272
|
|
|
|
289,836
|
|
Taxes
payable
|
|
|
114,427
|
|
|
|
44,683
|
|
|
|
54,290
|
|
Deferred
income taxes
|
|
|
3,069
|
|
|
|
---
|
|
|
|
5,969
|
|
Dividends
payable
|
|
|
26,616
|
|
|
|
24,569
|
|
|
|
24,606
|
|
Other
accrued liabilities
|
|
|
266,149
|
|
|
|
163,565
|
|
|
|
180,327
|
|
Current
liabilities held for sale and related to discontinued
operations
|
|
|
---
|
|
|
|
6,110
|
|
|
|
14,900
|
|
|
|
|
852,741
|
|
|
|
656,179
|
|
|
|
653,962
|
|
Long-term
debt
|
|
|
1,146,708
|
|
|
|
1,307,050
|
|
|
|
1,170,548
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
629,582
|
|
|
|
558,044
|
|
|
|
546,602
|
|
Other
liabilities
|
|
|
398,353
|
|
|
|
293,024
|
|
|
|
336,916
|
|
Noncurrent
liabilities held for sale and related to discontinued
operations
|
|
|
---
|
|
|
|
31,429
|
|
|
|
30,533
|
|
|
|
|
1,027,935
|
|
|
|
882,497
|
|
|
|
914,051
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stocks
|
|
|
15,000
|
|
|
|
15,000
|
|
|
|
15,000
|
|
Common
stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
issued -- $1.00 par value 182,914,769 at September 30, 2007,
181,279,379
at September 30, 2006 and 181,557,543 at December 31, 2006
|
|
|
182,915
|
|
|
|
181,279
|
|
|
|
181,558
|
|
Other
paid-in capital
|
|
|
909,805
|
|
|
|
872,973
|
|
|
|
874,253
|
|
Retained
earnings
|
|
|
1,365,497
|
|
|
|
1,046,933
|
|
|
|
1,104,210
|
|
Accumulated
other comprehensive income (loss)
|
|
|
(6,327 |
) |
|
|
8,271
|
|
|
|
(6,482 |
) |
Treasury
stock at cost – 538,921 shares
|
|
|
(3,626 |
) |
|
|
(3,626 |
) |
|
|
(3,626 |
) |
Total
common stockholders’ equity
|
|
|
2,448,264
|
|
|
|
2,105,830
|
|
|
|
2,149,913
|
|
Total
stockholders’ equity
|
|
|
2,463,264
|
|
|
|
2,120,830
|
|
|
|
2,164,913
|
|
|
|
$ |
5,490,648
|
|
|
$ |
4,966,556
|
|
|
$ |
4,903,474
|
|
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
|
Net
income
|
|
$ |
337,398
|
|
|
$ |
233,176
|
|
Income
from discontinued operations, net of tax
|
|
|
109,459
|
|
|
|
5,169
|
|
Income
from continuing operations
|
|
|
227,939
|
|
|
|
228,007
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
218,246
|
|
|
|
192,855
|
|
Earnings,
net of distributions, from equity method investments
|
|
|
(12,448 |
) |
|
|
(3,164 |
) |
Deferred
income taxes
|
|
|
41,387
|
|
|
|
26,567
|
|
Changes
in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(67,602 |
) |
|
|
(100,494 |
) |
Inventories
|
|
|
(35,181 |
) |
|
|
(51,059 |
) |
Other
current assets
|
|
|
(39,563 |
) |
|
|
(12,299 |
) |
Accounts
payable
|
|
|
(19,962 |
) |
|
|
66,089
|
|
Other
current liabilities
|
|
|
40,182
|
|
|
|
10,153
|
|
Other
noncurrent changes
|
|
|
7,230
|
|
|
|
14,302
|
|
Net
cash provided by continuing operations
|
|
|
360,228
|
|
|
|
370,957
|
|
Net
cash provided by (used in) discontinued operations
|
|
|
(46,750 |
) |
|
|
18,203
|
|
Net
cash provided by operating activities
|
|
|
313,478
|
|
|
|
389,160
|
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(380,087 |
) |
|
|
(370,535 |
) |
Acquisitions,
net of cash acquired
|
|
|
(341,790 |
) |
|
|
(111,710 |
) |
Net
proceeds from sale or disposition of property
|
|
|
16,264
|
|
|
|
19,335
|
|
Investments
|
|
|
3,275
|
|
|
|
(55,956 |
) |
Proceeds
from sale of equity method investments
|
|
|
56,150
|
|
|
|
---
|
|
Net
cash used in continuing operations
|
|
|
(646,188 |
) |
|
|
(518,866 |
) |
Net
cash provided by (used in) discontinued operations
|
|
|
548,216
|
|
|
|
(40,091 |
) |
Net
cash used in investing activities
|
|
|
(97,972 |
) |
|
|
(558,957 |
) |
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
|
Issuance
of short-term borrowings
|
|
|
310,000
|
|
|
|
---
|
|
Repayment
of short-term borrowings
|
|
|
(310,000 |
) |
|
|
---
|
|
Issuance
of long-term debt
|
|
|
85,000
|
|
|
|
394,504
|
|
Repayment
of long-term debt
|
|
|
(226,791 |
) |
|
|
(206,437 |
) |
Proceeds
from issuance of common stock
|
|
|
16,580
|
|
|
|
13,255
|
|
Dividends
paid
|
|
|
(74,025 |
) |
|
|
(68,881 |
) |
Tax
benefit on stock-based compensation
|
|
|
4,883
|
|
|
|
2,050
|
|
Net
cash provided by (used in) continuing operations
|
|
|
(194,353 |
) |
|
|
134,491
|
|
Net
cash provided by discontinued operations
|
|
|
---
|
|
|
|
248
|
|
Net
cash provided by (used in) financing activities
|
|
|
(194,353 |
) |
|
|
134,739
|
|
Effect
of exchange rate changes on cash and cash
equivalents
|
|
|
297
|
|
|
|
(1,654 |
) |
Increase
(decrease) in cash and cash equivalents
|
|
|
21,450
|
|
|
|
(36,712 |
) |
Cash
and cash equivalents – beginning of year
|
|
|
73,078
|
|
|
|
105,498
|
|
Cash
and cash equivalents – end of period
|
|
$ |
94,528
|
|
|
$ |
68,786
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS
September
30, 2007 and 2006
(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 2006 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 2006 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. Acquisitions
During
the first nine months of 2007, the Company acquired construction materials
and
mining businesses in North Dakota, Texas and Wyoming, a construction services
business in Nevada, and Cascade, a natural gas distribution business, as
discussed below. The total purchase consideration for these businesses and
properties and purchase price adjustments with respect to certain other
acquisitions made prior to 2007, consisting of the Company's common stock and
cash and the outstanding indebtedness of Cascade, was $519.6
million.
On
July
2, 2007, the acquisition of Cascade was finalized and Cascade became an indirect
wholly owned subsidiary of the Company. The acquisition of Cascade was funded
with cash (largely proceeds from the sale of the domestic independent power
production assets) and debt. Cascade’s natural gas service areas are in
Washington and Oregon. Cascade is a part of the Company’s natural gas
distribution segment.
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. Final
fair market values, for certain of the above acquisitions, 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.
4. Discontinued
operations
Innovatum,
a component of the pipeline and energy services segment, specialized in cable
and pipeline magnetization and location. During the third quarter of 2006,
the
Company initiated a plan to sell Innovatum because the Company determined that
Innovatum is a non-strategic asset. During the fourth quarter of 2006, the
stock
and a portion of the assets of Innovatum were sold and the Company expects
to
sell the remaining assets of Innovatum in the fourth quarter of 2007. The loss
on disposal on the portion of Innovatum that has been sold was not material.
The
Company does not expect to have any involvement in the operations of Innovatum
after the sale.
During
the fourth quarter of 2006, the Company initiated a plan to sell certain of
the
domestic assets of Centennial Resources, which largely comprise the independent
power production segment. The plan to sell was based on the increased market
demand for independent power production assets, combined with the Company’s
desire to efficiently fund future capital needs. The results of operations
of
these assets were shown in continuing operations in the Company’s financial
statements in the 2006 Annual Report as the Company intended to have significant
continuing involvement with these assets in the form of continuing existing
operation and maintenance agreements between CEM and these assets after the
sale.
The
Company subsequently committed to a plan to sell CEM due to strong interest
in
the operations of CEM during the bidding process for the domestic independent
power production assets in the first quarter of 2007. As a result of the
Company’s commitment to a plan to sell CEM, the Company would no longer have
significant continuing involvement in the operations of the other domestic
independent power production assets after the sale. Therefore, in accordance
with SFAS No. 144, the results of operations of the domestic independent power
production assets, including CEM, are presented as discontinued
operations.
On
July
10, 2007, Centennial Resources sold its domestic independent power production
business consisting of Centennial Power and CEM to Bicent Power LLC (formerly
known as Montana Acquisition Company LLC). The transaction was valued at $636
million, which included the assumption of approximately $36 million of
project-related debt. The gain on the sale of the assets, excluding the gain
on
the sale of Hartwell as discussed in Note 13, was approximately $85.4 million
(after tax). A portion of the proceeds from the sale was used to pay a dividend
to the Company. This dividend was then used to prepay, in part, the outstanding
term loan indebtedness that was incurred by the Company to fund the Cascade
acquisition. The remaining proceeds of the sale are anticipated to provide
additional cash for growth opportunities that exist in the Company’s core lines
of business.
In
accordance with SFAS No. 144, the Company’s consolidated financial statements
and accompanying notes for prior periods have been restated to present the
results of operations of Innovatum and the domestic independent power production
assets as discontinued operations. In addition, the assets and liabilities
of
these operations are treated as held for sale, and as a result, no depreciation,
depletion and amortization expense was recorded from the time each of the assets
was classified as held for sale, respectively.
In
accordance with SFAS No. 142, at the time the Company committed to the plan
to
sell each of the assets, the Company was required to test the respective assets
for goodwill impairment. The fair value of Innovatum, a reporting unit for
goodwill impairment testing, was estimated using the expected proceeds from
the
sale, which was estimated to be the current book value of the assets of
Innovatum other than its goodwill. As a result, a goodwill impairment of $4.3
million (before tax) was recognized and recorded as part of discontinued
operations, net of tax, in the Consolidated Statements of Income in the third
quarter of 2006. There were no goodwill impairments associated with the other
assets held for sale.
Operating
results related to Innovatum were as follows:
|
|
Three
Months
Ended
September
30,
|
|
|
Nine
Months
Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$ |
593
|
|
|
$ |
654
|
|
|
$ |
1,283
|
|
|
$ |
1,796
|
|
Income (loss) from discontinued operations before income tax expense
(benefit)
|
|
|
218
|
|
|
|
(4,743 |
) |
|
|
246
|
|
|
|
(5,606 |
) |
Income
tax expense (benefit)
|
|
|
29
|
|
|
|
(3,132 |
) |
|
|
---
|
|
|
|
(3,398 |
) |
Income (loss) from discontinued operations,
net of tax
|
|
$ |
189
|
|
|
$ |
(1,611 |
) |
|
$ |
246
|
|
|
$ |
(2,208 |
) |
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 a capital loss tax benefit (which reflects the effect
of
the $4.0 million and $4.3 million goodwill impairments in 2004 and 2006,
respectively) resulting from the sale of the Innovatum stock.
Operating
results related to the domestic independent power production assets were as
follows:
|
|
Three
Months
Ended
September
30,
|
|
|
Nine
Months
Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$ |
26,980
|
|
|
$ |
16,958
|
|
|
$ |
125,867
|
|
|
$ |
39,941
|
|
Income from discontinued operations (including gain on disposal of
$142.4
million) before income tax expense (benefit)
|
|
|
160,612
|
|
|
|
3,166
|
|
|
|
177,535
|
|
|
|
6,197
|
|
Income
tax expense (benefit)
|
|
|
64,036
|
|
|
|
178
|
|
|
|
68,322
|
|
|
|
(1,180 |
) |
Income from discontinued operations, net of tax
|
|
$ |
96,576
|
|
|
$ |
2,988
|
|
|
$ |
109,213
|
|
|
$ |
7,377
|
|
The
carrying amounts of the major assets and liabilities related to the domestic
independent power production assets held for sale, as well as the major assets
and liabilities related to Innovatum, were as follows:
|
|
September
30,
2007
|
|
|
September
30,
2006
|
|
|
December
31, 2006
|
|
|
|
(In
thousands)
|
|
Cash
and cash equivalents
|
|
$ |
---
|
|
|
$ |
1,419
|
|
|
$ |
1,878
|
|
Receivables,
net
|
|
|
|
|
|
|
7,016
|
|
|
|
8,307
|
|
Inventories
|
|
|
594
|
|
|
|
1,164
|
|
|
|
490
|
|
Prepayments
and other current assets
|
|
|
---
|
|
|
|
2,930
|
|
|
|
1,981
|
|
Total current assets held for sale and related to discontinued
operations
|
|
$ |
594
|
|
|
$ |
12,529
|
|
|
$ |
12,656
|
|
Net
property, plant and equipment
|
|
$ |
140
|
|
|
$ |
393,234
|
|
|
$ |
390,679
|
|
Goodwill
|
|
|
---
|
|
|
|
11,167
|
|
|
|
11,167
|
|
Other
intangible assets, net
|
|
|
---
|
|
|
|
7,432
|
|
|
|
7,162
|
|
Other
|
|
|
---
|
|
|
|
3,860
|
|
|
|
2,257
|
|
Total noncurrent assets held for sale and related to discontinued
operations
|
|
$ |
140
|
|
|
$ |
415,693
|
|
|
$ |
411,265
|
|
Accounts
payable
|
|
$ |
---
|
|
|
$ |
1,143
|
|
|
$ |
11,557
|
|
Other
accrued liabilities
|
|
|
---
|
|
|
|
4,967
|
|
|
|
3,343
|
|
Total current liabilities held for sale and related to discontinued
operations
|
|
$ |
---
|
|
|
$ |
6,110
|
|
|
$ |
14,900
|
|
Deferred
income taxes
|
|
$ |
---
|
|
|
$ |
28,957
|
|
|
$ |
27,956
|
|
Other
liabilities
|
|
|
---
|
|
|
|
2,472
|
|
|
|
2,577
|
|
Total noncurrent liabilities held for sale and related to discontinued
operations
|
|
$ |
---
|
|
|
$ |
31,429
|
|
|
$ |
30,533
|
|
5. Common
stock
At
the
Annual Meeting of Stockholders held on April 24, 2007, the Company’s common
stockholders approved an amendment to the Restated Certificate of Incorporation
that increased the authorized number of common shares from 250 million shares
to
500 million shares with a par value of $1.00 per share.
6. Allowance
for doubtful accounts
The
Company's allowance for doubtful accounts as of September 30, 2007 and 2006,
and
December 31, 2006, was $12.2 million, $5.9 million and $7.7 million,
respectively.
7. Natural
gas in underground storage
Natural
gas in underground storage for the Company's regulated operations is generally
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 $49.1 million, $43.8 million and $32.6 million
at September 30, 2007 and 2006, and December 31, 2006, respectively. The
remainder of natural gas in underground storage was included in other assets
and
was $44.2 million, $43.2 million, and $44.2 million at September 30, 2007 and
2006, and December 31, 2006, respectively.
8. Inventories
Inventories,
other than natural gas in underground storage for the Company’s regulated
operations, consisted primarily of aggregates held for resale of $102.4 million,
$92.1 million and $88.1 million; materials and supplies of $68.2 million, $61.4
million and $54.1 million; and other inventories of $35.0 million, $27.9 million
and $29.6 million, as of September 30, 2007 and 2006, and December 31, 2006,
respectively. These inventories were stated at the lower of average cost or
market value.
9. 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, 2007 and 2006, there were
no
shares excluded from the calculation of diluted earnings per share. Common
stock
outstanding includes issued shares less shares held in treasury.
10. Cash
flow information
Cash
expenditures for interest and income taxes were as follows:
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
$ |
55,139
|
|
|
|
$ |
48,957
|
|
Income
taxes
|
|
$ |
153,030
|
|
|
|
$ |
105,264
|
|
Income
taxes paid for the nine months ended September 30, 2007, increased from the
amount paid for the nine months ended September 30, 2006, primarily due to
higher estimated quarterly income tax payments due in large part to the gain
on
the sale of the domestic independent power production assets as discussed in
Note 4.
11. New
accounting standards
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 was effective for the
Company on January 1, 2007. The adoption of FIN 48 did not have a material
effect on the Company’s financial position or results of operations. For more
information on the implementation of FIN 48, see Note 16.
SFAS
No. 157 In September 2006, the FASB issued SFAS No. 157. SFAS No.
157 defines fair value, establishes a framework for measuring fair value and
expands disclosures about fair value measurements. The standard applies under
other accounting pronouncements that require or permit fair value measurements
with certain exceptions. SFAS No. 157 is effective for the Company on January
1,
2008. The Company is evaluating the effects of the adoption of SFAS No.
157.
SFAS
No. 159 In February 2007, the FASB issued SFAS No. 159. SFAS No.
159 permits entities to choose to measure many financial instruments and certain
other items at fair value that are not currently required to be measured at
fair
value. The standard also establishes presentation and disclosure requirements
designed to facilitate comparisons between entities that choose different
measurement attributes for similar types of assets and liabilities. SFAS No.
159
is effective for the Company on January 1, 2008. The Company is evaluating
the
effects of the adoption of SFAS No. 159.
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
$ |
201,262
|
|
|
$ |
108,487
|
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges:
|
|
|
|
|
|
|
|
|
Net
unrealized gain on derivative instruments arising during the period,
net
of tax of $3,075 and $8,709 in 2007 and 2006, respectively
|
|
|
4,958
|
|
|
|
13,912
|
|
Less:
Reclassification adjustment for gain on derivative instruments
included in
net income, net of tax of $3,247 and $2,654 in 2007 and 2006,
respectively
|
|
|
5,187
|
|
|
|
4,240
|
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
|
(229 |
) |
|
|
9,672
|
|
Foreign
currency translation adjustment
|
|
|
2,795
|
|
|
|
(401 |
) |
|
|
|
2,566
|
|
|
|
9,271
|
|
Comprehensive
income
|
|
$ |
203,828
|
|
|
$ |
117,758
|
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
$ |
337,398
|
|
|
$ |
233,176
|
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges:
|
|
|
|
|
|
|
|
|
Net
unrealized gain on derivative instruments arising during the period,
net
of tax of $4,066 and $15,840 in 2007 and 2006,
respectively
|
|
|
6,541
|
|
|
|
25,304
|
|
Less:
Reclassification adjustment for gain (loss) on derivative instruments
included in net income, net of tax of $9,305 and $(12,121) in 2007
and
2006, respectively
|
|
|
14,864
|
|
|
|
(19,361 |
) |
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
|
(8,323 |
) |
|
|
44,665
|
|
Foreign
currency translation adjustment
|
|
|
8,478
|
|
|
|
(2,578 |
) |
|
|
|
155
|
|
|
|
42,087
|
|
Comprehensive
income
|
|
$ |
337,553
|
|
|
$ |
275,263
|
|
13. Equity
method investments
The
Company’s equity method investments at September 30, 2007, include the Brazilian
Transmission Lines.
In
August
2006, MDU Brasil acquired ownership interests in companies owning the Brazilian
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 transmission lines, which are primarily in northeastern
and
southern Brazil.
In
February 2004, Centennial International acquired 49.99 percent of Carib Power.
Carib Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired
electric generating facility in Trinidad and Tobago. On February 26, 2007,
the
Company sold its interest in Carib Power. The sale did not have a significant
effect on the Company’s results of operations.
In
September 2004, Centennial Resources, through indirect wholly owned
subsidiaries, acquired a 50-percent ownership interest in Hartwell, which owns
a
310-MW natural gas-fired electric generating facility near Hartwell, Georgia.
On
July 10, 2007, the Company sold its ownership interest in Hartwell, and realized
a gain of $10.1 million ($6.1 million after tax) from the sale which is recorded
in earnings from equity method investments on the Consolidated Statements of
Income.
At
September 30, 2007 and 2006, and December 31, 2006, the Company's equity method
investments had total assets of $380.5 million, $576.6 million and $583.6
million, respectively, and long-term debt of $210.3 million, $324.3 million
and
$321.5 million, respectively. The Company's investment in its equity method
investments was approximately $55.2 million, $99.2 million and $102.0 million,
including undistributed earnings of $5.2 million, $6.6 million and $8.5
million, at September 30, 2007 and 2006, and December 31, 2006,
respectively.
14. Goodwill
and other intangible assets
The
changes in the carrying amount of goodwill were as follows:
|
|
Balance
|
|
|
Goodwill
|
|
|
Balance
|
|
|
|
as
of
|
|
|
Acquired
|
|
|
as
of
|
|
Nine Months Ended
|
|
January 1,
|
|
|
During
|
|
|
September 30,
|
|
September 30, 2007
|
|
2007
|
|
|
the
Year*
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Natural gas distribution
|
|
|
---
|
|
|
|
177,167
|
|
|
|
177,167
|
|
Construction services
|
|
|
86,942
|
|
|
|
4,443
|
|
|
|
91,385
|
|
Pipeline and energy services
|
|
|
1,159
|
|
|
|
---
|
|
|
|
1,159
|
|
Natural gas and oil production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction materials and mining
|
|
|
136,197
|
|
|
|
24,736
|
|
|
|
160,933
|
|
Independent power production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Other
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Total
|
|
$ |
224,298
|
|
|
$ |
206,346
|
|
|
$ |
430,644
|
|
*Includes
purchase price adjustments that were not material related to acquisitions
in a prior period.
|
|
|
|
Balance
|
|
|
Goodwill
|
|
|
Balance
|
|
|
|
as
of
|
|
|
Acquired
|
|
|
as
of
|
|
Nine
Months Ended
|
|
January 1,
|
|
|
During
|
|
|
September 30,
|
|
September
30, 2006
|
|
2006
|
|
|
the Year*
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction
services
|
|
|
80,970
|
|
|
|
5,956
|
|
|
|
86,926
|
|
Pipeline
and energy services
|
|
|
1,159
|
|
|
|
---
|
|
|
|
1,159
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
|
5,323
|
|
|
|
138,587
|
|
Independent
power production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Other
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Total
|
|
$ |
215,393
|
|
|
$ |
11,279
|
|
|
$ |
226,672
|
|
*Includes
purchase price adjustments that were not material related to
acquisitions
in a prior period.
|
|
Year
Ended
December
31, 2006
|
|
Balance
as
of
January 1,
2006
|
|
|
Goodwill
Acquired
During
the Year*
|
|
|
Balance
as
of
December 31,
2006
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction
services
|
|
|
80,970
|
|
|
|
5,972
|
|
|
|
86,942
|
|
Pipeline
and energy services
|
|
|
1,159
|
|
|
|
---
|
|
|
|
1,159
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
|
2,933
|
|
|
|
136,197
|
|
Independent
power production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Other
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Total
|
|
$ |
215,393
|
|
|
$ |
8,905
|
|
|
$ |
224,298
|
|
*Includes
purchase price adjustments that were not material related to acquisitions in
a
prior period.
Other
intangible assets were as follows:
|
|
September 30,
2007
|
|
|
September 30,
2006
|
|
|
December 31,
2006
|
|
|
|
(In
thousands)
|
|
Amortizable
intangible assets:
|
|
|
|
|
|
|
|
|
|
Customer
relationships
|
|
$ |
21,518
|
|
|
$ |
6,900
|
|
|
$ |
13,030
|
|
Accumulated
amortization
|
|
|
(3,609 |
) |
|
|
(1,127 |
) |
|
|
(1,890 |
) |
|
|
|
17,909
|
|
|
|
5,773
|
|
|
|
11,140
|
|
Noncompete
agreements
|
|
|
10,596
|
|
|
|
12,886
|
|
|
|
12,886
|
|
Accumulated
amortization
|
|
|
(3,170 |
) |
|
|
(9,104 |
) |
|
|
(8,540 |
) |
|
|
|
7,426
|
|
|
|
3,782
|
|
|
|
4,346
|
|
Acquired
contracts
|
|
|
2,539
|
|
|
|
8,165
|
|
|
|
8,307
|
|
Accumulated
amortization
|
|
|
(1,281 |
) |
|
|
(4,242 |
) |
|
|
(4,646 |
) |
|
|
|
1,258
|
|
|
|
3,923
|
|
|
|
3,661
|
|
Other
|
|
|
3,401
|
|
|
|
9,512
|
|
|
|
5,062
|
|
Accumulated
amortization
|
|
|
(879 |
) |
|
|
(1,096 |
) |
|
|
(1,407 |
) |
|
|
|
2,522
|
|
|
|
8,416
|
|
|
|
3,655
|
|
Unamortizable
intangible assets
|
|
|
---
|
|
|
|
524
|
|
|
|
---
|
|
Total
|
|
$ |
29,115
|
|
|
$ |
22,418
|
|
|
$ |
22,802
|
|
The
unamortizable intangible assets at September 30, 2006, 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.
Amortization
expense for amortizable intangible assets for the three and nine months ended
September 30, 2007, was $1.0 million and $2.9 million, respectively.
Amortization expense for the three and nine months ended September 30, 2006,
and
for the year ended December 31, 2006, was $1.2 million, $3.3 million and $4.3
million, respectively. Estimated amortization expense for amortizable intangible
assets is $4.8 million in 2007, $5.5 million in 2008, $4.3 million in 2009,
$3.4 million in 2010, $2.8 million in 2011 and $11.2 million
thereafter.
15.
|
Derivative
instruments
|
The
Company’s policy allows the use of 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. The Company’s policy prohibits the use of derivative instruments for
speculating to take advantage of market trends and conditions, and the Company
has procedures in place to monitor compliance with its policies. The Company
is
exposed to credit-related losses in relation to derivative instruments in the
event of nonperformance by counterparties. The Company’s policy requires that
natural gas and oil price derivative instruments at Fidelity and interest rate
derivative instruments not exceed a period of 24 months and foreign currency
derivative instruments not exceed a 12-month period. Cascade is authorized
to
maintain a portfolio of natural gas derivative instruments not to exceed a
period of three years. The Company’s policy requires settlement of natural gas
and oil price derivative instruments monthly and all interest rate derivative
transactions must be settled over a period that will not exceed 90 days, and
any
foreign currency derivative transaction settlement periods may not exceed a
12-month period. The Company has policies and procedures that management
believes minimize credit-risk exposure. These policies and procedures include
an
evaluation of potential counterparties’ credit ratings and credit exposure
limitations. Accordingly, the Company does not anticipate any material effect
on
its financial position or results of operations as a result of nonperformance
by
counterparties.
As
of
September 30, 2007, the Company had no outstanding foreign currency or interest
rate hedges. The following information should be read in conjunction with Note
7
in the Company’s Notes to Consolidated Financial Statements in the 2006 Annual
Report.
At
September 30, 2007, Cascade held natural gas swap agreements which were
not
designated
as hedges.
Cascade
utilizes natural gas swap agreements to manage a portion of the market risk
associated with fluctuations in the price of natural gas on its forecasted
purchases of natural gas for core customers in accordance with authority
granted
by the WUTC and OPUC. Core customers consist of residential, commercial and
smaller industrial customers. The fair value of the derivative instrument
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. Cascade applies SFAS
No.
71 and records periodic changes in the fair market value of the derivative
instruments on the Consolidated Balance Sheets as a regulatory asset or a
regulatory liability, and settlements of these arrangements are expected
to be
recovered through the purchased gas cost adjustment mechanism. Under the
terms
of these arrangements, Cascade will either pay or receive settlement payments
based on the difference between the fixed strike price and the monthly index
price applicable to each contract.
Fidelity
and Cascade non-core
At
September 30, 2007, Fidelity held natural gas and oil swap and collar derivative
instruments designated as cash flow hedging instruments. Cascade held natural
gas swap derivative instruments designated as cash flow hedging
instruments.
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. Cascade
utilizes natural gas swap agreements to manage a portion of the market risk
associated with fluctuations in the price of natural gas on its forecasted
purchases of natural gas for non-core customers. Cascade’s non-core customers,
who are not covered by the purchased gas cost adjustment mechanism, are
generally large industrial, electric generation and institutional customers.
Each of the price swap and collar agreements was designated as a hedge of the
forecasted sale of the related production or as a hedge of the forecasted
purchase of the related commodity.
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 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 received for natural gas and oil production and the amount paid for
natural gas purchases are also generally based on market prices.
For
the
three and nine months ended September 30, 2007, the amount of hedge
ineffectiveness was immaterial. In the second quarter of 2006, Fidelity had
oil
collar agreements that became ineffective and no longer qualified for hedge
accounting. 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 the remaining hedges was immaterial for the three and nine
months ended September 30, 2006. For the three and nine months ended September
30, 2007 and 2006, there were no components of the derivative instruments’ gain
or loss excluded 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, 2007, the maximum
term of the swap and collar agreements, in which the exposure to the variability
in future cash flows for forecasted transactions is being hedged, is 15 months.
The Company estimates that over the next 12 months, net gains of approximately
$10.7 million (after tax) will be reclassified from accumulated other
comprehensive income into earnings, subject to changes in natural gas market
prices, as the hedged transactions affect earnings.
On
January 1, 2007, the Company adopted FIN 48 as discussed in Note
11.
The
Company and its subsidiaries file income tax returns in the U.S. federal
jurisdiction and various state, local and foreign jurisdictions. With few
exceptions, the Company is no longer subject to U.S. federal, state and local,
or non-U.S. income tax examinations by tax authorities for years ending prior
to
2003.
Upon
the
adoption of FIN 48, the Company recognized a decrease in the liability for
unrecognized tax benefits, which was not material and was accounted for as
an
increase to the January 1, 2007, balance of retained earnings. At the date
of
adoption, the amount of unrecognized tax benefits was $4.5 million.
Included
in the balance of unrecognized tax benefits at the date of adoption are $3.0
million of tax positions for which the ultimate deductibility is highly certain
but for which there is uncertainty about the timing of such deductibility.
Because of the impact of deferred tax accounting, other than interest and
penalties, the disallowance of the shorter deductibility period would not affect
the annual effective tax rate but would accelerate the payment of cash to the
taxing authority to an earlier period. The amount of unrecognized tax benefits
at the date of adoption that, if recognized, would affect the effective tax
rate
was $1.5 million, including $304,000 for the payment of interest and penalties.
The Company recognizes interest and penalties accrued related to unrecognized
tax benefits in income taxes.
Prior
to the sale of
the domestic independent power production assets on July 10, 2007, as discussed
in Note 4, the Company considered earnings (including the gain from the
sale of its foreign equity method investment in a natural gas-fired electric
generating facility in Brazil in 2005) to be reinvested indefinitely outside
of
the United States and, accordingly, no U.S. deferred income taxes were recorded
with respect to such earnings. Following the sale of these assets, the Company
reconsidered
its long-term plans for future development and expansion of its foreign
investment, and has determined that it has no immediate plans to explore or
invest in additional foreign investments at this time. Therefore, in accordance
with SFAS No. 109, deferred income taxes must now be accrued with respect to
the
temporary differences which had not been previously recorded. The
cumulative undistributed earnings at September 30, 2007, were approximately
$36
million. The amount of deferred tax liability, net of allowable foreign tax
credits, associated with the undistributed earnings and recognized in the third
quarter of 2007 was approximately $10 million. Future
earnings will also be subject to additional U.S. taxes, net of allowable
foreign tax credits.
17. 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
companies owning electric transmission lines.
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 Minnesota, Oregon and
Washington. These operations also supply related value-added products and
services.
The
construction services segment specializes in electric line construction,
pipeline construction, utility excavation, inside electrical wiring, cabling
and
mechanical work, fire protection 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, liquid asphalt and other value-added products. It
also performs integrated construction services. The construction materials
and
mining segment operates in the north central, southern and western United States
and Alaska and Hawaii.
The
independent power production segment’s international operation has investments
in companies that own electric transmission lines. Prior to the July 10, 2007
sale, this segment’s domestic operation owned, built and operated electric
generating facilities in the United States and had investments in natural
resource-based projects. For more information regarding the discontinued
operations of the domestic operations of this segment and the sale of these
assets, see Note 4.
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 2006 Annual
Report. Information on the Company’s businesses was as follows:
|
|
|
|
|
Inter-
|
|
|
|
|
Three
Months
|
|
External
Operating
|
|
|
segment
Operating
|
|
|
Earnings
on Common
|
|
Ended
September 30, 2007
|
|
Revenues
|
|
|
Revenues
|
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
53,986
|
|
|
$ |
---
|
|
|
$ |
5,668
|
|
Natural
gas distribution
|
|
|
90,706
|
|
|
|
---
|
|
|
|
(4,544 |
) |
Pipeline
and energy services
|
|
|
90,870
|
|
|
|
11,627
|
|
|
|
9,408
|
|
|
|
|
235,562
|
|
|
|
11,627
|
|
|
|
10,532
|
|
Construction
services
|
|
|
293,286
|
|
|
|
46
|
|
|
|
13,678
|
|
Natural
gas and oil production
|
|
|
76,839
|
|
|
|
46,242
|
|
|
|
33,182
|
|
Construction
materials and mining
|
|
|
639,623
|
|
|
|
---
|
|
|
|
50,389
|
|
Independent
power production
|
|
|
---
|
|
|
|
---
|
|
|
|
93,139
|
|
Other
|
|
|
---
|
|
|
|
2,446
|
|
|
|
170
|
|
|
|
|
1,009,748
|
|
|
|
48,734
|
|
|
|
190,558
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
|
(60,361 |
) |
|
|
---
|
|
Total
|
|
$ |
1,245,310
|
|
|
$ |
---
|
|
|
$ |
201,090
|
|
|
|
|
|
|
|
|
|
Earnings
|
|
Three
Months
|
|
|
|
|
|
|
|
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
|
|
|
---
|
|
|
|
---
|
|
|
|
1,714
|
|
Other
|
|
|
---
|
|
|
|
1,773
|
|
|
|
278
|
|
|
|
|
1,001,724
|
|
|
|
52,519
|
|
|
|
97,824
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
|
(68,953 |
) |
|
|
---
|
|
Total
|
|
$ |
1,173,678
|
|
|
$ |
---
|
|
|
$ |
108,316
|
|
Nine
Months
|
|
External
Operating
|
|
|
Operating
|
|
|
Earnings
on
Common
|
|
Ended
September 30, 2007
|
|
Revenues
|
|
|
Revenues
|
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
145,681
|
|
|
$ |
---
|
|
|
$ |
13,020
|
|
Natural
gas distribution
|
|
|
280,172
|
|
|
|
---
|
|
|
|
1,041
|
|
Pipeline
and energy services
|
|
|
273,210
|
|
|
|
54,579
|
|
|
|
21,346
|
|
|
|
|
699,063
|
|
|
|
54,579
|
|
|
|
35,407
|
|
Construction
services
|
|
|
793,406
|
|
|
|
520
|
|
|
|
33,938
|
|
Natural
gas and oil production
|
|
|
200,032
|
|
|
|
169,023
|
|
|
|
98,969
|
|
Construction
materials and mining
|
|
|
1,322,665
|
|
|
|
---
|
|
|
|
66,135
|
|
Independent
power production
|
|
|
---
|
|
|
|
---
|
|
|
|
101,627
|
|
Other
|
|
|
---
|
|
|
|
7,326
|
|
|
|
809
|
|
|
|
|
2,316,103
|
|
|
|
176,869
|
|
|
|
301,478
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
|
(231,448 |
) |
|
|
---
|
|
Total
|
|
$ |
3,015,166
|
|
|
$ |
---
|
|
|
$ |
336,885
|
|
Nine
Months
|
|
External
Operating
|
|
|
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
|
|
|
---
|
|
|
|
---
|
|
|
|
4,560
|
|
Other
|
|
|
---
|
|
|
|
5,861
|
|
|
|
780
|
|
|
|
|
2,305,040
|
|
|
|
181,350
|
|
|
|
204,923
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
|
(249,158 |
) |
|
|
---
|
|
Total
|
|
$ |
2,938,630
|
|
|
$ |
---
|
|
|
$ |
232,662
|
|
The
pipeline and energy services segment recognized income from discontinued
operations, net of tax, of $189,000 and $246,000 for the three and nine months
ended September 30, 2007, respectively and 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. The independent power production segment
recognized income from discontinued operations, net of tax, of $96.6 million,
$109.2 million, $3.0 million and $7.4 million for the three and nine months
ended September 30, 2007 and 2006, respectively. Excluding the income (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.
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,
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
(In
thousands)
|
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$ |
2,568
|
|
|
$ |
3,197
|
|
|
$ |
446
|
|
|
$ |
782
|
|
Interest
cost
|
|
|
5,389
|
|
|
|
5,861
|
|
|
|
1,071
|
|
|
|
1,107
|
|
Expected
return on assets
|
|
|
(6,497 |
) |
|
|
(7,983 |
) |
|
|
(1,235 |
) |
|
|
(1,643 |
) |
Amortization
of prior service cost
|
|
|
183
|
|
|
|
233
|
|
|
|
(662 |
) |
|
|
14
|
|
Recognized
net actuarial (gain) loss
|
|
|
582
|
|
|
|
569
|
|
|
|
121
|
|
|
|
(18 |
) |
Amortization
of net transition obligation (asset)
|
|
|
---
|
|
|
|
---
|
|
|
|
496
|
|
|
|
704
|
|
Net periodic benefit cost, including amount capitalized
|
|
|
2,225
|
|
|
|
1,877
|
|
|
|
237
|
|
|
|
946
|
|
Less
amount capitalized
|
|
|
220
|
|
|
|
179
|
|
|
|
104
|
|
|
|
80
|
|
Net
periodic benefit cost
|
|
$ |
2,005
|
|
|
$ |
1,698
|
|
|
$ |
133
|
|
|
$ |
866
|
|
Nine
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
Ended
September 30,
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
(In
thousands)
|
Components of net periodic benefit cost:
|
|
|
|
|
|
|
Service
cost
|
|
$ |
6,829
|
|
|
$ |
7,799
|
|
|
$ |
1,426
|
|
|
$ |
1,725
|
|
Interest
cost
|
|
|
13,752
|
|
|
|
14,009
|
|
|
|
3,189
|
|
|
|
2,964
|
|
Expected
return on assets
|
|
|
(16,661 |
) |
|
|
(17,419 |
) |
|
|
(3,607 |
) |
|
|
(3,494 |
) |
Amortization
of prior service cost
|
|
|
599
|
|
|
|
746
|
|
|
|
(637 |
) |
|
|
37
|
|
Recognized
net actuarial (gain) loss
|
|
|
1,082
|
|
|
|
1,587
|
|
|
|
(28 |
) |
|
|
(187 |
) |
Amortization
of net transition obligation (asset)
|
|
|
---
|
|
|
|
(2 |
) |
|
|
1,662
|
|
|
|
1,766
|
|
Net periodic benefit cost, including amount capitalized
|
|
|
5,601
|
|
|
|
6,720
|
|
|
|
2,005
|
|
|
|
2,811
|
|
Less
amount capitalized
|
|
|
588
|
|
|
|
560
|
|
|
|
245
|
|
|
|
205
|
|
Net
periodic benefit cost
|
|
$ |
5,013
|
|
|
$ |
6,160
|
|
|
$ |
1,760
|
|
|
$ |
2,606
|
|
In
addition to the qualified plan defined pension benefits reflected in the table,
the Company also has unfunded, nonqualified benefit plans for executive officers
and certain key management employees. The Company's net periodic benefit cost
for these plans for the three and nine months ended September 30, 2007, was
$2.1
million and $6.0 million, respectively. The Company’s net periodic benefit cost
for these plans for the three and nine months ended September 30, 2006, was
$1.8
million and $5.7 million, respectively.
19. Regulatory
matters and revenues subject to refund
In
August
2006, CMS, a competing gas marketer, filed a complaint against Cascade before
the WUTC alleging Cascade had entered into gas supply sales contracts with
its
non-core, transportation-only customers in violation of state law by not filing
tariffs and copies of the gas supply contracts with the WUTC. CMS’s complaint
additionally raised claims of undue preference and discrimination. On January
12, 2007, the WUTC entered an order allowing Cascade to continue to make
gas supply sales to non-core customers but requiring Cascade to file its
tariffs and sales contracts with the WUTC. On February 12, 2007, Cascade
filed revisions to its tariffs reflecting gas supply service options available
to non-core customers and on March 30, 2007, filed notice with the WUTC that
it
was reactivating a nonregulated affiliate to make retail gas sales to non-core
customers. The WUTC suspended the tariff filings and consolidated the tariff
proceeding with Cascade’s filing to re-establish an affiliate to make non-core
customer gas supply sales. On May 17, 2007, following a series of motions for
clarification of the order, the presiding ALJ closed the CMS complaint
docket and directed the WUTC Staff to conduct an investigation of the gas supply
sales contracts on an informal basis. CMS filed a petition for interlocutory
review which was granted by the WUTC on October 12, 2007. The WUTC order allows
CMS to pursue its complaint for undue preference and discrimination and to
add a
claim for price cross-subsidization. The WUTC is expected to issue a procedural
order in the proceeding after a pre-hearing conference.
On
July
12, 2007, Montana-Dakota filed an application with the MTPSC for an electric
rate increase. Montana-Dakota requested a total of $7.8 million annually or
approximately 22 percent above current rates. Montana-Dakota is requesting
a
fuel and purchased power tracking adjustment and an off-system sales margin
sharing adjustment. Montana-Dakota also requested an interim increase of $3.9
million annually, subject to refund. A final order is expected from the MTPSC
by
May 2008.
In
November 2006, Montana-Dakota filed an application with the NDPSC requesting
an
advance determination of prudence of Montana-Dakota’s ownership interest in Big
Stone II, which is expected to be completed in 2013. Hearings on the application
were held in June 2007. In September 2007, Montana-Dakota informed the NDPSC
that certain of the other participants in the project had withdrawn, that it
was
considering the impact of these withdrawals on the project and its options,
and
proposed that the NDPSC suspend the procedural schedule. In October 2007,
Montana-Dakota proposed to supplement the record and requested that the
procedural schedule be determined at a later date after consideration of optimal
plant configuration by the remaining participants. A new schedule will also
be
set for certain regulatory proceedings applicable to the Certificate of Need
filing in Minnesota applicable to the related transmission
facilities.
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. Currently, the only remaining issue outstanding
related to this rate change application is in regard to certain service
restrictions. In May 2004, the FERC remanded this issue to an ALJ for
resolution. In November 2005, the FERC issued an Order on Initial Decision
affirming the ALJ’s Initial Decision regarding certain service and annual demand
quantity restrictions. In April 2006, the FERC issued an Order on Rehearing
denying Williston Basin’s Request for Rehearing of the FERC’s Order on Initial
Decision. In April 2006, Williston Basin appealed to the D.C. Appeals Court
certain issues addressed by the FERC’s Order on Initial Decision and its Order
on Rehearing. The matter concerning the service restrictions is pending
resolution by the D.C. Appeals Court.
20. Contingencies
Litigation
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 January 2007 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 and substantive requirements. The lawsuits seek injunctive
relief, invalidation of various permits and unspecified damages. Fidelity has
intervened or moved to intervene in three lawsuits filed by other gas producers
which challenge the adoption of rules by the BER related to management of water
associated with CBNG production. The state of Wyoming has filed a similar suit
and Fidelity has also moved to intervene in that action.
In
suits
filed in the Montana Federal District Court, the NPRC and the Northern Cheyenne
Tribe asserted that the BLM violated NEPA and other federal laws when approving
the 2003 EIS analyzing CBNG development in southeastern Montana. 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 Montana Powder River
Basin 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 appeal or
further order from the Ninth Circuit, enjoined the BLM from approving any new
CBNG development of federal minerals in the Montana Powder River Basin. The
Ninth Circuit 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 was briefed and argued to the
Ninth
Circuit in September 2005. On September 11, 2007, the Ninth Circuit affirmed
the
Montana Federal District Court and ruled it had correctly issued an injunction
allowing up to 500 CBNG wells to be drilled each year on private, state and
federal land in the Montana Powder River Basin. On October 29, 2007, in response
to a motion filed by Fidelity, the Ninth Circuit lifted the 2005 injunction
it
had earlier issued pending the appeal. On the same date, the Ninth Circuit
ordered Fidelity to respond within 21 days to the Northern Cheyenne Tribe and
the NPRC’s October 16, 2007, petition to the Ninth Circuit to rehear the
case.
In
December 2006, the BLM issued a draft SEIS that endorses a phased-development
approach to CBNG production in the Montana Powder River Basin, whereby future
projects would be reviewed against four screens or filters (relating to water
quality, wildlife, Native American concerns and air quality). Fidelity filed
written comments on the draft SEIS asking the BLM to reconsider its proposed
phased-development approach and to make numerous other changes to the draft
SEIS. The public comment period on the draft SEIS concluded on May 2, 2007.
The
final SEIS is scheduled for release in April 2008. Fidelity cannot predict
what
the final terms of the SEIS will be.
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. 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 the NHPA and a further
environmental analysis under the 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
dismissing the Northern Cheyenne Tribe lawsuit based on the parties’ stipulation
that production from existing wells in Fidelity’s Badger Hills Project could
continue pending consultation with the Northern Cheyenne Tribe under the NHPA.
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 to promulgate
rules related to the management of water produced in association with CBNG
operations. Thereafter, the BER initiated related rulemaking proceedings to
consider 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. In March 2006, the BER issued its decision on the 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 under challenge in Montana state court by the Northern Cheyenne
Tribe. Specifically, in April 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
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 failing to impose
a
non-degradation policy like the one the BER adopted soon after the permit was
issued. 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 EIS
and that the Montana DEQ failed to consider other alternatives to the issuance
of the permits. Fidelity, the NPRC and the TRWUA have been granted leave to
intervene in this proceeding. The parties have submitted cross motions for
summary judgment. The motions were argued to the District Court of Big Horn
County on February 28, 2007. Fidelity’s discharge of water pursuant to its
two permits is its primary means for managing CBNG produced water. If its
permits are set aside, Fidelity’s CBNG operations in Montana could be
significantly and adversely affected.
In
a
related proceeding, in July 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 non-degradation
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 in August 2006.
The parties have briefed cross motions for summary judgment and the District
Court of Big Horn County heard oral argument on those motions on July 2, 2007.
On October 17, 2007, the District Court of Big Horn County entered an order
granting the motions filed by the BER and others and denying the motions filed
by Fidelity and other producers.
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 in September 2006. Fidelity has moved to intervene in these
consolidated cases. Fidelity has also intervened in a Wyoming State District
Court case in support of the Governor of Wyoming’s decision not to promulgate
rules which were proposed by the Powder River Basin Resource Council that would
have granted Wyoming’s DEQ authority to regulate water quantity issues that are
currently regulated by the Wyoming State Engineer.
Fidelity
will continue to vigorously defend its interests in all CBNG-related lawsuits
and related actions in which it is involved, including 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 adverse 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
defended against the DRC claim and filed a motion to dismiss the case. The
Colorado Federal District Court has dismissed the case.
On
June
6, 2007, the EPA noticed for public comment a proposed rule that would, among
other things, adopt PSD increment modeling refinements that, if adopted, would
operate to formally ratify the modeling techniques and conclusions contained
in
the September 2005 ND Health Department decision and the August 2005 final
report. The public comment period on the proposed rule closed September 28,
2007. The dismissal of the case in Burleigh County District Court referenced
above is dependant upon the outcome of the proposed rule.
In
November 2006, the Sierra Club sent a notice of intent to file a citizen suit
in
federal court under the Clean Air Act to the co-owners, including
Montana-Dakota, of the Big Stone Station. The suit would seek injunctive relief
and monetary penalties based on the Sierra Club’s claim that three projects
conducted at the Big Stone Station between 1995 and 2005 were modifications
of a
major source and that the Big Stone Station failed to obtain a PSD permit,
conduct best available control technology analyses, and comply with other
regulatory requirements for those projects. The South Dakota Department of
Environment and Natural Resources reviewed and approved the three projects
and
the co-owners of the Big Stone Station believe that the Sierra Club’s claims are
without merit. The Big Stone Station co-owners intend to vigorously defend
their
interests if the suit is filed.
Natural
Gas Storage Based on reservoir and well pressure data and other
information, Williston Basin believes that reservoir pressure (and therefore
the
amount of gas) in the EBSR, one of its natural gas storage reservoirs, has
decreased as a result of Howell and Anadarko’s drilling and production
activities in areas within and near the boundaries of the EBSR. As of September
30, 2007, Williston Basin estimated approximately 9.5 Bcf of storage gas had
been diverted from the EBSR as a result of Howell and Anadarko’s drilling and
production.
Williston
Basin filed suit in Montana Federal District Court in January 2006, seeking
to
recover unspecified damages from Howell and Anadarko, and to enjoin Howell
and
Anadarko’s present and future production from specified wells in and near the
EBSR. The Montana Federal District Court entered an Order in July 2006,
dismissing the case for lack of subject matter jurisdiction. Williston Basin
filed a Notice of Appeal to the Ninth Circuit in July 2006. The parties
have briefed the issues. Oral argument has not yet been scheduled.
In
related litigation, Howell filed suit in Wyoming State District Court against
Williston Basin in February 2006 asserting that it is entitled to produce any
gas that might escape from the EBSR. In August 2006, Williston Basin moved
for a
preliminary injunction to halt Howell and Anadarko’s production in and near the
EBSR. A district court-appointed special master conducted a hearing on the
motion in December 2006, and recommended denial of the motion on February 15,
2007. The Wyoming State District Court adopted the special master’s report on
July 25, 2007, and denied Williston Basin’s motion for a preliminary injunction.
On June 25, 2007, the Wyoming State District Court filed a motion with the
Wyoming Supreme Court requesting it to answer questions of law concerning the
production of Williston Basin’s storage gas by Howell and Anadarko. On July 10,
2007, the Wyoming Supreme Court issued an Order declining to answer those
questions. The Wyoming State District Court has set the case for trial beginning
September 29, 2008.
As
noted
above, Williston Basin estimates that as of September 30, 2007, Howell and
Anadarko had diverted approximately 9.5 Bcf from the EBSR. Williston Basin
believes Howell and Anadarko continue to divert gas from the EBSR and Williston
Basin continues to monitor and analyze the situation. At trial, Williston Basin
will seek recovery based on the amount of gas that has been and continues to
be
diverted as well as on the amount of gas that must be recovered as a result
of
the equalization of the pressures of various interconnected geological
formations.
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
these proceedings.
In
light
of the actions of Howell and Anadarko, Williston Basin installed temporary
compression at the site in 2006 in order to maintain deliverability into the
transmission system. Williston Basin has leased working gas for the 2007 -
2008
heating season to supplement its cushion gas. While installation of the
additional compression has provided temporary relief and the addition of leased
working gas is expected to provide additional temporary relief, Williston Basin
believes that the adverse physical and operational effects occasioned by the
continued loss of storage gas, if left unchecked, could threaten the operation
and viability of the EBSR, impair Williston Basin’s ability to comply with the
EBSR certificated operating requirements mandated by the FERC and adversely
affect Williston Basin’s ability to meet its contractual storage and
transportation service commitments to customers.
The
Company also is 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 in excess 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.
MBI has entered into an agreement tolling the statute of limitation in
connection with the LWG’s potential claim for contribution to the costs of the
remedial investigation and feasibility study.
The
Company believes it is not probable that it will incur any material
environmental remediation costs or damages in relation to the above referenced
administrative action.
Hardin
Generating Facility In connection with the sale of the domestic
independent power production business, Centennial Resources agreed to obtain
an
amended air permit for the Hardin Generating Facility, and to pay certain fines
and penalties assessed against the facility on or prior to compliance with
the
amended air permit, as well as costs related to obtaining the amended air
permit. The Hardin Generating Facility received four notices of violation from
the Montana DEQ relating to emissions exceedances associated with startup and
maintenance periods for the Hardin Generating Facility. On October 23, 2007,
the
Montana DEQ finalized the amended air permit. A penalty of $450,800 was paid
by
Centennial Resources in settlement of all four notices of
violation.
Manufactured
Gas Plant Sites There are two claims against Cascade for cleanup
of environmental contamination at manufactured gas plant sites operated by
Cascade’s predecessors.
The
first
claim is for soil and groundwater contamination at a site in Oregon and was
received in 1995. There are potentially responsible parties in addition to
Cascade that are potentially liable for cleanup of the contamination. Some
of these other parties have shared in the investigation costs. It is expected
that these and other potentially responsible parties will share in the cleanup
costs. Several alternatives for cleanup have been identified, with
preliminary cost estimates ranging from approximately $500,000 to $11.0 million.
It is not known at this time what share of the cleanup costs will actually
be
borne by Cascade.
The
second claim is for contamination at a site in Washington and was received
in
1997. Although a preliminary investigation has concluded the site is
contaminated, it appears that other property owners may have contributed to
the
contamination. There is currently not enough information available to
estimate the potential liability associated with this claim and no formal
investigation plan has been communicated to Cascade.
The
Company believes that both these claims are covered by insurance. To the
extent not covered by insurance, Cascade will seek recovery of contamination
remediation costs through its rates.
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
up 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.
Centennial
continues to guarantee CEM’s obligations under a construction contract for a
550-MW combined-cycle electric generating facility near Hobbs, New Mexico.
As
described in Note 4, Centennial Resources sold CEM in July 2007 to Bicent Power
LLC, which has provided a $10 million bank letter of credit to Centennial in
support of that guarantee obligation. The guarantee, which has no fixed maximum,
expires when CEM has completed its obligations under the construction
contract. Construction is expected to be completed in 2008, and the
warranty period associated with this project will expire one year after the
date
of substantial completion of the construction.
In
addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil
price swap and collar agreement obligations. 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, 2007, expire in 2007
and
2008; 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 $498,000
and was reflected on the Consolidated Balance Sheets at September 30, 2007.
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 construction contracts, natural gas transportation and sales
agreements, gathering contracts, a conditional purchase agreement and certain
other guarantees. At September 30, 2007, the fixed maximum amounts guaranteed
under these agreements aggregated $465.8 million. The amounts of scheduled
expiration of the maximum amounts guaranteed under these agreements aggregate
$15.8 million in 2007; $78.5 million in 2008; $341.9 million in 2009; $400,000
in 2010; $23.0 million in 2011; $1.2 million in 2012; $1.0 million, which is
subject to expiration 30 days after the receipt of written notice; and $4.0
million, which has no scheduled maturity date. The amount outstanding by
subsidiaries of the Company under the above guarantees was $667,000 and was
reflected on the Consolidated Balance Sheet at September 30, 2007. 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.
Certain
subsidiaries have outstanding letters of credit to third parties related to
insurance policies, natural gas transportation agreements and other agreements
that guarantee the performance of other subsidiaries of the Company. At
September 30, 2007, the fixed maximum amounts guaranteed under these letters
of
credit aggregated $39.5 million. In 2007 and 2008, $2.8 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,
2007.
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, 2007, the fixed
maximum amounts guaranteed under these agreements aggregated $25.1 million.
Scheduled expiration of the maximum amounts guaranteed under these agreements
aggregate $2.2 million in 2007, $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 $1.7 million, which was not reflected on the Consolidated
Balance Sheet at September 30, 2007, because these intercompany transactions
are
eliminated in consolidation.
In
addition, Centennial and Knife River have issued guarantees to third parties
related to the Company’s routine purchase of maintenance items, materials 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 with respect to the purchase of certain
maintenance items, materials or lease obligations, Centennial or Knife River
would be required to make payments under these guarantees. Any amounts
outstanding by subsidiaries of the Company for these maintenance items and
materials were reflected on the Consolidated Balance Sheet at September 30,
2007.
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,
2007, approximately $423 million of surety bonds were outstanding, which were
not reflected on the Consolidated Balance Sheet.
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
return 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 more 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 stable cash flows and
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 level of 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; retaining, developing and recruiting 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 and related
services 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
higher-priced markets.
Challenges
Energy price volatility; natural gas basis differentials; regulatory
requirements; ongoing litigation; 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; inflationary pressure
on development and operating costs; and increased competition from
other 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; strengthen long-term,
strategic aggregate reserve position through purchase and/or lease
opportunities; enhance profitability through cost containment, margin discipline
and vertical integration of the segment’s operations; and continue growth
through organic and acquisition opportunities. 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 (liquid asphalt, diesel fuel, cement and other materials),
negotiation of contract price escalation provisions and the utilization of
national purchasing accounts. 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, through acquisition, in the
higher-margin materials business (rock, sand, gravel, liquid asphalt,
ready-mixed concrete and related products), complementing and expanding on
the
Company’s expertise.
Challenges
Price volatility with respect to, and availability of, raw materials such as
liquid asphalt, diesel fuel and cement; recruitment and retention of a skilled
workforce; and management of fixed price construction contracts, which are
particularly vulnerable to volatility of these energy and material prices.
In
some of our markets, we are challenged to mitigate severe effects caused by
the
continued decline in the residential construction sector, as well as the level
and timing of federal and state transportation funding. A greater emphasis
on
commercial construction and cost containment should partially mitigate the
effects.
Independent
Power Production
Overall
business challenges for this segment include the risks and uncertainties
associated with 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 2006 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Electric
|
|
$ |
5.7
|
|
|
$ |
5.7
|
|
|
$ |
13.0
|
|
|
$ |
10.0
|
|
Natural
gas distribution
|
|
|
(4.5 |
) |
|
|
(2.3 |
) |
|
|
1.1
|
|
|
|
.4
|
|
Construction
services
|
|
|
13.7
|
|
|
|
8.3
|
|
|
|
33.9
|
|
|
|
23.4
|
|
Pipeline
and energy services
|
|
|
9.2
|
|
|
|
8.7
|
|
|
|
21.1
|
|
|
|
19.5
|
|
Natural
gas and oil production
|
|
|
33.2
|
|
|
|
35.0
|
|
|
|
99.0
|
|
|
|
107.2
|
|
Construction
materials and mining
|
|
|
50.4
|
|
|
|
52.5
|
|
|
|
66.1
|
|
|
|
69.0
|
|
Independent
power production
|
|
|
(3.5 |
) |
|
|
(1.3 |
) |
|
|
(7.6 |
) |
|
|
(2.8 |
) |
Other
|
|
|
.1
|
|
|
|
.3
|
|
|
|
.8
|
|
|
|
.8
|
|
Earnings
before discontinued operations
|
|
|
104.3
|
|
|
|
106.9
|
|
|
|
227.4
|
|
|
|
227.5
|
|
Income from discontinued operations, net of tax
|
|
|
96.8
|
|
|
|
1.4
|
|
|
|
109.5
|
|
|
|
5.2
|
|
Earnings
on common stock
|
|
$ |
201.1
|
|
|
$ |
108.3
|
|
|
$ |
336.9
|
|
|
$ |
232.7
|
|
Earnings
per common share – basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before
discontinued operations
|
|
$ |
.57
|
|
|
$ |
.59
|
|
|
$ |
1.25
|
|
|
$ |
1.26
|
|
Discontinued
operations, net of
tax
|
|
|
.53
|
|
|
|
.01
|
|
|
|
.60
|
|
|
|
.03
|
|
Earnings
per common share
– basic
|
|
$ |
1.10
|
|
|
$ |
.60
|
|
|
$ |
1.85
|
|
|
$ |
1.29
|
|
Earnings
per common share – diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before
discontinued operations
|
|
$ |
.57
|
|
|
$ |
.59
|
|
|
$ |
1.24
|
|
|
$ |
1.26
|
|
Discontinued
operations, net of
tax
|
|
|
.53
|
|
|
|
.01
|
|
|
|
.60
|
|
|
|
.03
|
|
Earnings
per common share
– diluted
|
|
$ |
1.10
|
|
|
$ |
.60
|
|
|
$ |
1.84
|
|
|
$ |
1.29
|
|
Return on average common equity for the 12 months
ended
|
|
|
|
|
|
|
|
|
|
|
18.7 |
% |
|
|
15.7 |
% |
Three
Months Ended September 30, 2007 and 2006 Consolidated earnings for
the quarter ended September 30, 2007, increased $92.8 million from the
comparable period largely due to:
·
|
Increased
income from discontinued operations, net of tax, largely due to the
gain
on the sale of the Company’s domestic independent power production assets
and earnings related to an electric generating facility construction
project
|
·
|
Partially
offset by lower earnings of $2.6 million from continuing
operations
|
Nine
Months Ended September 30, 2007 and 2006 Consolidated earnings for
the nine months ended September 30, 2007, increased $104.2 million, primarily
due to increased income from discontinued operations, net of tax, largely due
to
the gain on the sale of the Company’s domestic independent power production
assets, earnings related to an electric generating facility construction project
and the absence in 2007 of depreciation expense related to assets held for
sale.
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$ |
54.0
|
|
|
$ |
53.2
|
|
|
$ |
145.7
|
|
|
$ |
139.1
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
20.3
|
|
|
|
19.1
|
|
|
|
52.9
|
|
|
|
51.2
|
|
Operation
and maintenance
|
|
|
16.0
|
|
|
|
16.3
|
|
|
|
45.6
|
|
|
|
46.0
|
|
Depreciation,
depletion and amortization
|
|
|
5.7
|
|
|
|
5.4
|
|
|
|
16.9
|
|
|
|
15.9
|
|
Taxes,
other than income
|
|
|
2.1
|
|
|
|
2.1
|
|
|
|
6.4
|
|
|
|
6.4
|
|
|
|
|
44.1
|
|
|
|
42.9
|
|
|
|
121.8
|
|
|
|
119.5
|
|
Operating
income
|
|
|
9.9
|
|
|
|
10.3
|
|
|
|
23.9
|
|
|
|
19.6
|
|
Earnings
|
|
$ |
5.7
|
|
|
$ |
5.7
|
|
|
$ |
13.0
|
|
|
$ |
10.0
|
|
Retail
sales (million kWh)
|
|
|
703.5
|
|
|
|
652.1
|
|
|
|
1,945.5
|
|
|
|
1,828.1
|
|
Sales
for resale (million kWh)
|
|
|
39.2
|
|
|
|
172.3
|
|
|
|
130.4
|
|
|
|
423.9
|
|
Average cost of fuel and purchased power per kWh
|
|
$ |
.027
|
|
|
$ |
.022
|
|
|
$ |
.025
|
|
|
$ |
.022
|
|
Three
Months Ended September 30, 2007 and 2006 Electric earnings were
unchanged from the comparable prior period. Lower sales for resale margins
and
volumes were largely offset by higher retail sales volumes and
margins.
Nine
Months Ended September 30, 2007 and 2006 Electric earnings
increased $3.0 million largely due to higher retail sales margins and volumes
and higher sales for resale margins, partially offset by lower sales for resale
volumes.
Natural
Gas Distribution
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$ |
90.7
|
|
|
$ |
31.4
|
|
|
$ |
280.2
|
|
|
$ |
229.5
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
53.3
|
|
|
|
20.7
|
|
|
|
193.9
|
|
|
|
182.5
|
|
Operation
and maintenance
|
|
|
26.6
|
|
|
|
11.0
|
|
|
|
57.8
|
|
|
|
35.7
|
|
Depreciation,
depletion and amortization
|
|
|
7.1
|
|
|
|
2.5
|
|
|
|
12.0
|
|
|
|
7.3
|
|
Taxes,
other than income
|
|
|
5.9
|
|
|
|
1.4
|
|
|
|
9.1
|
|
|
|
4.5
|
|
|
|
|
92.9
|
|
|
|
35.6
|
|
|
|
272.8
|
|
|
|
230.0
|
|
Operating
income (loss)
|
|
|
(2.2 |
) |
|
|
(4.2 |
) |
|
|
7.4
|
|
|
|
(.5 |
) |
Earnings
(loss)
|
|
$ |
(4.5 |
) |
|
$ |
(2.3 |
) |
|
$ |
1.1
|
|
|
$ |
.4
|
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
7.2
|
|
|
|
3.1
|
|
|
|
28.4
|
|
|
|
21.9
|
|
Transportation
|
|
|
22.7
|
|
|
|
2.6
|
|
|
|
29.0
|
|
|
|
9.8
|
|
Total
throughput
|
|
|
29.9
|
|
|
|
5.7
|
|
|
|
57.4
|
|
|
|
31.7
|
|
Degree
days (% of normal)*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
71 |
% |
|
|
94 |
% |
|
|
93 |
% |
|
|
83 |
% |
Cascade
|
|
|
102 |
% |
|
|
---
|
|
|
|
102 |
% |
|
|
---
|
|
Average cost of natural gas, including transportation, per
dk**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
$ |
5.15
|
|
|
$ |
6.67
|
|
|
$ |
6.45
|
|
|
$ |
8.32
|
|
Cascade
|
|
$ |
7.60
|
|
|
|
---
|
|
|
$ |
7.60
|
|
|
|
---
|
|
|
* Degree
days are a measure of the daily temperature-related demand for
energy for
heating.
|
|
**
Regulated natural gas sales
only.
|
Note:
Cascade was acquired on July 2, 2007. For further information, see Note
3.
Three
Months Ended September 30, 2007 and 2006 The natural gas
distribution business experienced a seasonal loss of $4.5 million in the third
quarter of 2007 compared to a loss of $2.3 million in the third quarter of
2006.
The increase in loss was due to a seasonal loss of $2.4 million (after tax)
at
Cascade which was acquired since the comparable prior period.
Nine
Months Ended September 30, 2007 and 2006 Earnings at the natural
gas distribution business increased $700,000 due to:
·
|
Higher
retail sales margins, including increased retail sales volumes resulting
from 13 percent colder weather than last
year
|
·
|
Decreased
operation and maintenance expense (excluding Cascade) of $1.1 million
(after tax), including the absence in 2007 of the 2006 early retirement
program costs
|
·
|
Higher
nonregulated energy-related services of $700,000 (after
tax)
|
Largely
offsetting these increases was the third quarter seasonal loss of $2.4 million
(after tax) at Cascade which was acquired since the comparable prior
period.
Construction
Services
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
Operating
revenues
|
|
$ |
293.3
|
|
|
$ |
262.3
|
|
|
$ |
793.9
|
|
|
$ |
729.3
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
258.1
|
|
|
|
236.8
|
|
|
|
700.4
|
|
|
|
656.2
|
|
Depreciation,
depletion and amortization
|
|
|
3.5
|
|
|
|
3.6
|
|
|
|
10.5
|
|
|
|
11.0
|
|
Taxes,
other than income
|
|
|
8.5
|
|
|
|
6.6
|
|
|
|
24.8
|
|
|
|
19.5
|
|
|
|
|
270.1
|
|
|
|
247.0
|
|
|
|
735.7
|
|
|
|
686.7
|
|
Operating
income
|
|
|
23.2
|
|
|
|
15.3
|
|
|
|
58.2
|
|
|
|
42.6
|
|
Earnings
|
|
$ |
13.7
|
|
|
$ |
8.3
|
|
|
$ |
33.9
|
|
|
$ |
23.4
|
|
Three
Months Ended September 30, 2007 and 2006 Construction services
earnings increased $5.4 million due to:
·
|
Higher
construction margins and workloads of $4.6 million (after tax), largely
in
the Central and Southwest regions, including industrial-related
work
|
·
|
Increased
equipment sales and rentals
|
Nine
Months Ended September 30, 2007 and 2006 Construction services
earnings increased $10.5 million due to:
·
|
Higher
construction margins and workloads of $9.1 million (after tax), largely
in
the Central and Southwest regions, including industrial-related
work
|
·
|
Increased
equipment sales and rentals
|
Pipeline
and Energy Services
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
$ |
34.1
|
|
|
$ |
27.7
|
|
|
$ |
88.6
|
|
|
$ |
74.5
|
|
Energy
services
|
|
|
68.4
|
|
|
|
76.1
|
|
|
|
239.2
|
|
|
|
258.3
|
|
|
|
|
102.5
|
|
|
|
103.8
|
|
|
|
327.8
|
|
|
|
332.8
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
60.9
|
|
|
|
69.0
|
|
|
|
216.3
|
|
|
|
236.1
|
|
Operation
and maintenance
|
|
|
17.1
|
|
|
|
12.8
|
|
|
|
47.7
|
|
|
|
38.4
|
|
Depreciation,
depletion and amortization
|
|
|
5.4
|
|
|
|
4.9
|
|
|
|
16.1
|
|
|
|
14.9
|
|
Taxes,
other than income
|
|
|
2.7
|
|
|
|
2.5
|
|
|
|
8.1
|
|
|
|
7.6
|
|
|
|
|
86.1
|
|
|
|
89.2
|
|
|
|
288.2
|
|
|
|
297.0
|
|
Operating
income
|
|
|
16.4
|
|
|
|
14.6
|
|
|
|
39.6
|
|
|
|
35.8
|
|
Income
from continuing operations
|
|
|
9.2
|
|
|
|
8.7
|
|
|
|
21.1
|
|
|
|
19.5
|
|
Income (loss) from discontinued operations, net of
tax
|
|
|
.2
|
|
|
|
(1.6 |
) |
|
|
.3
|
|
|
|
(2.2 |
) |
Earnings
|
|
$ |
9.4
|
|
|
$ |
7.1
|
|
|
$ |
21.4
|
|
|
$ |
17.3
|
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
6.6
|
|
|
|
7.5
|
|
|
|
21.7
|
|
|
|
22.6
|
|
Other
|
|
|
33.5
|
|
|
|
29.3
|
|
|
|
83.7
|
|
|
|
75.4
|
|
|
|
|
40.1
|
|
|
|
36.8
|
|
|
|
105.4
|
|
|
|
98.0
|
|
Gathering
volumes (MMdk)
|
|
|
23.5
|
|
|
|
21.9
|
|
|
|
68.2
|
|
|
|
64.8
|
|
Three
Months Ended September 30, 2007 and 2006 Pipeline and energy
services experienced an increase in earnings of $2.3 million due
to:
·
|
Increased
income from discontinued operations of $1.8 million (after tax),
related
to Innovatum. For further information, see Note
4.
|
·
|
Higher
transportation and gathering
volumes
|
Nine
Months Ended September 30, 2007 and 2006 Pipeline and energy
services experienced an increase in earnings of $4.1 million due
to:
·
|
Higher
transportation and gathering volumes of $3.7 million (after
tax)
|
·
|
Increased
income from discontinued operations of $2.5 million (after tax),
related
to Innovatum, as previously
discussed
|
·
|
Higher
storage services revenue of $2.2 million (after
tax)
|
·
|
Higher
gathering rates of $1.1 million (after
tax)
|
Partially
offsetting these increases were higher operation and maintenance expenses,
primarily related to the natural gas storage litigation and higher material
and
payroll costs. For more information regarding natural gas storage
litigation, see Note 20.
The
decrease in energy services revenue and purchased natural gas sold reflects
the
effect of lower natural gas prices.
Natural
Gas and Oil Production
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
86.4
|
|
|
$ |
89.1
|
|
|
$ |
276.4
|
|
|
$ |
281.7
|
|
Oil
|
|
|
36.5
|
|
|
|
31.6
|
|
|
|
92.3
|
|
|
|
78.0
|
|
Other
|
|
|
.2
|
|
|
|
1.8
|
|
|
|
.4
|
|
|
|
5.3
|
|
|
|
|
123.1
|
|
|
|
122.5
|
|
|
|
369.1
|
|
|
|
365.0
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
---
|
|
|
|
1.5
|
|
|
|
.3
|
|
|
|
5.2
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
17.6
|
|
|
|
14.0
|
|
|
|
48.7
|
|
|
|
38.3
|
|
Gathering
and transportation
|
|
|
5.3
|
|
|
|
4.5
|
|
|
|
14.9
|
|
|
|
13.9
|
|
Other
|
|
|
8.9
|
|
|
|
7.2
|
|
|
|
26.3
|
|
|
|
23.9
|
|
Depreciation,
depletion and amortization
|
|
|
33.2
|
|
|
|
27.7
|
|
|
|
92.7
|
|
|
|
78.1
|
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
8.5
|
|
|
|
8.5
|
|
|
|
26.7
|
|
|
|
26.4
|
|
Other
|
|
|
.1
|
|
|
|
.2
|
|
|
|
.6
|
|
|
|
.7
|
|
|
|
|
73.6
|
|
|
|
63.6
|
|
|
|
210.2
|
|
|
|
186.5
|
|
Operating
income
|
|
|
49.5
|
|
|
|
58.9
|
|
|
|
158.9
|
|
|
|
178.5
|
|
Earnings
|
|
$ |
33.2
|
|
|
$ |
35.0
|
|
|
$ |
99.0
|
|
|
$ |
107.2
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
15,865
|
|
|
|
15,603
|
|
|
|
46,536
|
|
|
|
46,207
|
|
Oil
(MBbls)
|
|
|
565
|
|
|
|
554
|
|
|
|
1,710
|
|
|
|
1,475
|
|
Average realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
5.45
|
|
|
$ |
5.71
|
|
|
$ |
5.94
|
|
|
$ |
6.10
|
|
Oil
(per barrel)
|
|
$ |
64.54
|
|
|
$ |
57.01
|
|
|
$ |
53.94
|
|
|
$ |
52.90
|
|
Average realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
4.51
|
|
|
$ |
5.13
|
|
|
$ |
5.35
|
|
|
$ |
5.72
|
|
Oil
(per barrel)
|
|
$ |
64.64
|
|
|
$ |
57.69
|
|
|
$ |
53.98
|
|
|
$ |
53.99
|
|
Production costs, including taxes, per net equivalent
Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$ |
.91
|
|
|
$ |
.74
|
|
|
$ |
.86
|
|
|
$ |
.70
|
|
Gathering
and transportation
|
|
|
.28
|
|
|
|
.23
|
|
|
|
.26
|
|
|
|
.25
|
|
Production
and property taxes
|
|
|
.44
|
|
|
|
.45
|
|
|
|
.47
|
|
|
|
.48
|
|
|
|
$ |
1.63
|
|
|
$ |
1.42
|
|
|
$ |
1.59
|
|
|
$ |
1.43
|
|
Three
Months Ended September 30, 2007 and 2006 The natural gas and oil
production business experienced a decrease in earnings of $1.8 million due
to:
·
|
Increased
depreciation, depletion and amortization expense of $3.3 million
(after
tax) due to higher depletion rates and increased
production
|
·
|
Higher
lease operating expense of $2.2 million (after
tax)
|
·
|
Lower
average realized natural gas prices of 5
percent
|
Partially
offsetting these decreases were:
·
|
Income
tax benefit of $3.1 million due to lower effective state income tax
rates
|
·
|
Higher
average realized oil prices of 13
percent
|
·
|
Increased
natural gas production of 2 percent and increased oil production
of 2
percent, largely due to increased drilling activity at existing
properties
|
Nine
Months Ended September 30, 2007 and 2006 The natural gas and oil
production business experienced an $8.2 million decrease in earnings due
to:
·
|
Increased
depreciation, depletion and amortization expense of $9.1 million
(after
tax) due to higher depletion rates and increased
production
|
·
|
Higher
lease operating expense of $6.5 million (after tax), largely acquisition
and CBNG-related costs, as well as increased costs at nonoperated
properties
|
·
|
Lower
average realized natural gas prices of 3
percent
|
·
|
Increased
general and administrative expense of $1.5 million (after tax), partially
due to higher payroll-related costs
|
Partially
offsetting these decreases were:
·
|
Increased
oil production of 16 percent resulting from the May 2006 Big Horn
acquisition, as well as from the South Texas
properties
|
·
|
Income
tax benefit of $3.1 million, as previously
described
|
·
|
Higher
average realized oil prices of 2
percent
|
·
|
Increased
natural gas production of 1 percent
|
Construction
Materials and Mining
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$ |
639.6
|
|
|
$ |
667.6
|
|
|
$ |
1,322.7
|
|
|
$ |
1,386.2
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
519.7
|
|
|
|
546.9
|
|
|
|
1,101.4
|
|
|
|
1,167.1
|
|
Depreciation,
depletion and amortization
|
|
|
23.2
|
|
|
|
22.6
|
|
|
|
69.1
|
|
|
|
64.8
|
|
Taxes,
other than income
|
|
|
11.8
|
|
|
|
10.0
|
|
|
|
33.4
|
|
|
|
30.3
|
|
|
|
|
554.7
|
|
|
|
579.5
|
|
|
|
1,203.9
|
|
|
|
1,262.2
|
|
Operating
income
|
|
|
84.9
|
|
|
|
88.1
|
|
|
|
118.8
|
|
|
|
124.0
|
|
Earnings
|
|
$ |
50.4
|
|
|
$ |
52.5
|
|
|
$ |
66.1
|
|
|
$ |
69.0
|
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
11,769
|
|
|
|
14,961
|
|
|
|
27,665
|
|
|
|
34,386
|
|
Asphalt
(tons)
|
|
|
3,330
|
|
|
|
3,669
|
|
|
|
5,435
|
|
|
|
6,358
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
1,328
|
|
|
|
1,420
|
|
|
|
3,046
|
|
|
|
3,391
|
|
Three
Months Ended September 30, 2007 and 2006 Earnings at the
construction materials and mining business decreased $2.1 million from the
comparable prior period due to:
·
|
Lower
margins from existing operations of $6.2 million (after tax), primarily
related to lower sale volumes resulting from the slow down in certain
residential housing markets, partially offset by higher realized
prices as
well as higher margins from asphalt and related
products
|
Partially
offsetting the decrease were:
·
|
Decreased
general and administrative expense of $2.2 million (after tax), partially
due to lower payroll-related costs
|
·
|
Earnings
from companies acquired since the comparable prior period which
contributed 4 percent to earnings for the current
quarter
|
Nine
Months Ended September 30, 2007 and 2006 Earnings at the
construction materials and mining business decreased $2.9 million due
to:
·
|
Lower
margins from existing operations of $5.6 million, as previously
discussed
|
·
|
Higher
depreciation, depletion and amortization expense of $1.8 million
(after
tax), primarily due to higher property, plant and equipment
balances
|
Partially
offsetting these decreases were:
·
|
Earnings
from companies acquired since the comparable prior period which
contributed 3 percent to earnings for the nine months ended September
30,
2007
|
·
|
Decreased
general and administrative expense of $2.0 million (after tax), primarily
due to lower payroll-related costs
|
Independent
Power Production
|
|
Three
Months Ended
September
30,
|
|
|
Nine
Months Ended
September
30,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
(Dollars
in millions)
|
|
|
Operating
revenues
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
2.1
|
|
|
|
1.7
|
|
|
|
5.7
|
|
|
|
5.8
|
|
Depreciation,
depletion and amortization
|
|
|
---
|
|
|
|
---
|
|
|
|
.2
|
|
|
|
.1
|
|
Taxes,
other than income
|
|
|
.1
|
|
|
|
.1
|
|
|
|
.2
|
|
|
|
.1
|
|
|
|
|
2.2
|
|
|
|
1.8
|
|
|
|
6.1
|
|
|
|
6.0
|
|
Operating
loss
|
|
|
(2.2 |
) |
|
|
(1.8 |
) |
|
|
(6.1 |
) |
|
|
(6.0 |
) |
Loss from continuing operations
|
|
|
(3.5 |
) |
|
|
(1.3 |
) |
|
|
(7.6 |
) |
|
|
(2.8 |
) |
Income from discontinued operations, net of tax
|
|
|
96.6
|
|
|
|
3.0
|
|
|
|
109.2
|
|
|
|
7.4
|
|
Earnings
|
|
$ |
93.1
|
|
|
$ |
1.7
|
|
|
$ |
101.6
|
|
|
$ |
4.6
|
|
Three
Months Ended September 30, 2007 and 2006 Earnings at the
independent power production business increased $91.4 million due to the
following:
·
|
Increased
income from discontinued operations, net of tax, of $93.6 million
largely
due to:
|
o
|
An
$85.4 million (after tax) gain on the sale of the Company’s domestic
independent power production assets, excluding
Hartwell
|
o
|
Earnings
of $10.5 million (after tax) related to an electric generating station
construction project in Hobbs, New
Mexico
|
Partially
offsetting these increases was:
·
|
Higher
loss from continuing operations, net of tax, of $2.2 million, largely
due
to:
|
o
|
An
income tax adjustment of $10.0 million associated with the anticipated
repatriation of profits from Brazilian operations as discussed in
Note 16,
partially offset by the gain of $6.1 million (after tax) related
to the
sale of Hartwell
|
Nine
Months Ended September 30, 2007 and 2006 Earnings at the
independent power production business increased $97.0 million due
to:
·
|
Increases
previously discussed in the three months ended September 30, 2007
and
2006
|
·
|
The
absence in 2007 of depreciation expense related to assets held for
sale
|
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
2.4
|
|
|
$ |
1.8
|
|
|
$ |
7.3
|
|
|
$ |
5.9
|
|
Operation
and maintenance
|
|
|
2.4
|
|
|
|
1.2
|
|
|
|
6.3
|
|
|
|
4.3
|
|
Depreciation,
depletion and amortization
|
|
|
.3
|
|
|
|
.3
|
|
|
|
.8
|
|
|
|
.8
|
|
Taxes,
other than income
|
|
|
---
|
|
|
|
.1
|
|
|
|
---
|
|
|
|
.1
|
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
60.3
|
|
|
$ |
69.0
|
|
|
$ |
231.5
|
|
|
$ |
249.1
|
|
Purchased
natural gas sold
|
|
|
53.3
|
|
|
|
62.6
|
|
|
|
210.5
|
|
|
|
228.8
|
|
Operation
and maintenance
|
|
|
7.0
|
|
|
|
6.4
|
|
|
|
21.0
|
|
|
|
20.3
|
|
For
further information on intersegment eliminations, see Note 17.
PROSPECTIVE
INFORMATION
The
following information highlights 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 changes 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 2006 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 2007, diluted, are projected in the range of
$2.20 to
$2.35. The earnings per share guidance range includes the third quarter
gain of $91.5 million (after tax) on the sale of the domestic
independent power production assets, and earnings from discontinued
operations.
|
·
|
Long-term
compound annual growth goals on earnings per share from operations
are in
the range of 7 percent to 10
percent
|
Electric
·
|
The
Company is analyzing potential projects for accommodating load growth
and
replacing an expired purchased power contract with company-owned
generation, which will add to base-load capacity and rate base. For
further information, see Note 19.
|
·
|
The
Company is in the process of constructing approximately 20 MW of
wind-powered electric generation near Baker, Montana. The project
includes
13, 1.5-MW wind turbines at a project cost of approximately $37 million.
The project is expected to be rate based and on line in late
2007.
|
·
|
On
July 12, 2007, Montana-Dakota filed an electric rate case with the
MTPSC,
as discussed in Note 19
|
Natural
gas distribution
·
|
This
business continues to pursue expansion of energy-related services
and
expects continued strong customer growth in Washington and
Oregon
|
Construction
services
·
|
The
Company anticipates higher average margins in 2007 as compared to
2006,
and continues to focus on costs and efficiencies to improve
margins
|
·
|
Work
backlog as of September 30, 2007, is approximately $826 million compared
to backlog of $505 million at September 30,
2006
|
Pipeline
and energy services
·
|
Based
on anticipated demand, additional incremental expansions to the Grasslands
Pipeline are forecasted over the next few years. An expansion to
138,000
Mcf per day was completed on November 1, 2007. Through additional
compression, the pipeline capacity could ultimately reach 200,000
Mcf per
day.
|
·
|
In
2007, total gathering and transportation throughput is expected to
increase approximately 6 percent over 2006 record
levels
|
Natural
gas and oil production
·
|
Long-term
compound annual growth goals for production are in the range of 7
percent
to 10 percent
|
·
|
In
2007, the Company expects a combined natural gas and oil production
increase of approximately 4 percent
|
·
|
The
Company expects to drill approximately 250 wells in 2007, which reflects
the commingling of multiple coal seams into a single well bore.
Commingling reduces the number of wells required to be drilled while
accessing the same reserve potential. Currently this segment’s net
combined natural gas and oil production is approximately 210,000
Mcf
equivalent to 220,000 Mcf equivalent per
day.
|
·
|
Earnings
guidance reflects estimated natural gas prices for November through
December 2007 as follows:
|
Index*
|
Price
Per Mcf
|
Ventura
|
$6.25
to $6.75
|
NYMEX
|
$6.75
to $7.25
|
CIG
|
$4.00
to $4.50
|
*
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
|
During
2006 and through September 30, 2007, more than three-fourths of the Company’s
natural gas production was priced at non-NYMEX prices, the majority of which
was
at Ventura pricing.
·
|
Earnings
guidance reflects estimated NYMEX crude oil prices for October through
December 2007 in the range of $73 to $78 per
barrel
|
·
|
The
Company has hedged approximately 35 percent to 40 percent of its
estimated
natural gas production and approximately 5 percent to 10 percent
of its
estimated oil production for the last three months of 2007. For 2008,
the
Company has hedged approximately 30 percent to 35 percent of its
estimated
natural gas production and less than 5 percent of its estimated oil
production. The hedges that are in place as of November 2, 2007,
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
|
10/07
|
232,500
|
$7.16
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
460,000
|
$8.00-$11.91
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
230,000
|
$8.00-$11.80
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
230,000
|
$8.00-$11.75
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
460,000
|
$7.50-$10.55
|
Natural
Gas
|
CIG
|
10/07
- 12/07
|
460,000
|
$7.40
|
Natural
Gas
|
CIG
|
10/07
- 12/07
|
460,000
|
$7.405
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
368,000
|
$8.25-$10.80
|
Natural
Gas
|
CIG
|
10/07
- 12/07
|
230,000
|
$7.50-$9.12
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
460,000
|
$8.29
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
460,000
|
$7.85-$9.70
|
Natural
Gas
|
Ventura
|
10/07
- 12/07
|
920,000
|
$7.67
|
Natural
Gas
|
NYMEX
|
10/07
- 12/07
|
460,000
|
$7.50-$8.50
|
Natural
Gas
|
Ventura
|
11/07
- 3/08
|
1,520,000
|
$8.00-$8.75
|
Natural
Gas
|
Ventura
|
11/07
- 3/08
|
608,000
|
$9.01
|
Natural
Gas
|
Ventura
|
1/08
- 3/08
|
910,000
|
$9.35
|
Natural
Gas
|
CIG
|
1/08
- 3/08
|
910,000
|
$7.00-$7.79
|
Natural
Gas
|
CIG
|
1/08
- 3/08
|
910,000
|
$8.06
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.00-$8.05
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.00-$8.06
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.45
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.50-$8.70
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$8.005
|
Natural
Gas
|
Ventura
|
1/08
- 12/08
|
1,830,000
|
$7.00-$8.45
|
Natural
Gas
|
Ventura
|
1/08
- 12/08
|
1,830,000
|
$7.50-$8.34
|
Natural
Gas
|
Ventura
|
1/08
- 12/08
|
3,294,000
|
$8.55
|
Natural
Gas
|
NYMEX
|
1/08
- 12/08
|
1,830,000
|
$7.50-$10.15
|
Natural
Gas
|
CIG
|
4/08
- 12/08
|
1,375,000
|
$6.75-$7.04
|
Natural
Gas
|
CIG
|
4/08
- 12/08
|
1,375,000
|
$6.35
|
Natural
Gas
|
CIG
|
4/08
- 12/08
|
1,375,000
|
$6.41
|
Natural
Gas
|
Ventura
|
11/08
- 12/08
|
610,000
|
$8.85
|
Crude
Oil
|
NYMEX
|
10/07
- 12/07
|
39,100
|
$75.25
|
Crude
Oil
|
NYMEX
|
1/08
- 12/08
|
73,200
|
$67.50-$78.70
|
|
*
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
·
|
The
Company anticipates margins in 2007 to be comparable to
2006
|
·
|
Work
backlog as of September 30, 2007, was approximately $520 million
compared
to $594 million at September 30,
2006
|
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 2006 Annual
Report. For more information on critical accounting policies involving
significant estimates, see Part II, Item 7 in the 2006 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 2007
decreased $75.7 million from the comparable 2006 period, the result of increased
cash used related to discontinued operations of $65.0 million, largely due
to an
increase in quarterly income tax payments due to the gain on the sale of the
domestic independent power production assets. In addition, cash used
for working capital requirements increased $34.5 million. Partially offsetting
the decrease in cash flows from operating activities were higher depreciation,
depletion and amortization expense of $25.4 million and higher deferred income
taxes of $14.8 million.
Investing
activities Cash flows used by investing activities in the first
nine months of 2007 decreased $461.0 million compared to the comparable 2006
period, the result of:
·
|
An
increase in cash flows provided by discontinued operations of $588.3
million, primarily the result of the sale of the domestic independent
power production assets in the third quarter of
2007
|
·
|
An
increase in cash flows from investments of $59.2 million, largely
due to
the absence in 2007 of the 2006 acquisition of the Brazilian Transmission
Lines
|
·
|
Increased
proceeds from the sale of equity method investments of $56.2 million,
primarily the result of the sale of the Trinity Generating Facility
in the
first quarter of 2007 and Hartwell in the third quarter of
2007
|
Partially
offsetting the increase in cash flows from investing activities
were:
·
|
An
increase in cash flows used for acquisitions, net of cash acquired,
of
$230.1 million, largely the result of the Cascade acquisition, partially
offset by the absence in 2007 of the 2006 Big Horn acquisition at
the
natural gas and oil production
business
|
Financing
activities Cash flows used in financing activities in the first
nine months of 2007 increased $329.1 million compared to the comparable 2006
period, primarily the result of a decrease in the issuance of long-term debt
of
$309.5 million, and higher repayments of long-term debt of $20.4 million. Also
reflected in the cash flows from financing activities was the issuance and
subsequent repayment of short-term borrowings of $310.0 million from the term
loan agreement entered into in connection with the funding of the Cascade
acquisition.
Defined
benefit pension plans
Cascade
has a qualified noncontributory defined benefit pension plan covering
substantially all union employees and salaried employees hired before September
30, 2003. Plan assets consist of investments in equity and fixed income
securities. Various actuarial assumptions are used in calculating the benefit
expense (income) and liability (asset) related to the Cascade pension plan.
Actuarial assumptions include assumptions about the discount rate and expected
return on plan assets as determined by the Company within certain guidelines.
At
September 30, 2006, the Cascade pension plan’s accumulated benefit obligation
exceeded the plan’s assets by approximately $6.7 million. Cascade’s pension
expense is currently projected to be approximately $500,000 to $600,000 for
the
last six months of 2007. Funding for the Cascade pension plan is actuarially
determined.
Except
for changes related to the acquisition of Cascade as previously discussed,
there
were no other significant changes to the Company’s qualified noncontributory
defined benefit pension plans from those reported in the 2006 Annual Report.
For
further information, see Note 18 and Part II, Item 7 in the 2006 Annual
Report.
Net
capital expenditures for the first nine months of 2007 were approximately $906
million and are estimated to be approximately $1.16 billion for 2007. Both
of
these amounts include the outstanding indebtedness of Cascade at the time of
acquisition and exclude proceeds from the sale of the domestic independent
power
production assets. 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
48 percent of estimated 2007 net capital expenditures referred to
previously are associated with completed acquisitions, primarily related to
the
acquisition of Cascade. 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 2007 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; the Company’s credit facilities, as described below; and
through the issuance of long-term 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, 2007.
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,
up
to a maximum of $150 million). There were no amounts outstanding under the
credit agreement at September 30, 2007. The credit agreement supports the
Company’s $100 million commercial paper program. Under the Company’s
commercial paper program, $25.2 million was outstanding at September 30, 2007.
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).
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.
In
order
to borrow under the Company’s credit agreement, the Company must be in
compliance with the applicable covenants and certain other conditions. For
information on the covenants and certain other conditions of the Company’s
credit agreement, see Part II, Item 7, in the 2006 Annual Report. The Company
was in compliance with these covenants and met the required conditions at
September 30, 2007.
In
connection with the funding of the Cascade acquisition, on June 29, 2007, the
Company entered into a term loan agreement with Wells Fargo Bank, National
Association, providing for a commitment amount of $310 million. The Company
borrowed $310 million under this agreement on July 2, 2007. On July 11, 2007,
and August 14, 2007, the Company paid down $220 million and $5 million,
respectively, of the outstanding principal balance. In addition, on August
14,
2007 and August 28, 2007, the Company received $50 million and $35 million,
respectively, from the repayment of an intercompany loan with MDU Energy
Capital. The Company, in turn, repaid the outstanding principal balance of
the
term loan indebtedness that it incurred to fund the acquisition of Cascade.
The
term loan agreement terminated on August 28, 2007.
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 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, 2007, the Company could have issued approximately
$510 million of additional first mortgage bonds.
The
Company's coverage of fixed charges including preferred dividends was 6.2 times
and 6.4 times for the 12 months ended September 30, 2007 and December 31,
2006, respectively. Additionally, the Company's first mortgage bond interest
coverage was 39.9 times and 26.0 times for the 12 months ended
September 30, 2007 and December 31, 2006, respectively. Common
stockholders' equity as a percent of total capitalization (including long-term
debt due within one year) was 66 percent and 63 percent at September 30,
2007 and December 31, 2006, 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. As of September 30, 2007, the Company
had $50.5 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 $20.0 million or less, the Company would have the ability,
subject to satisfying certain specified conditions, to require that any debt
issued under its Indenture become unsecured and rank equally with all of the
Company’s other unsecured and unsubordinated debt (as of September 30, 2007, 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).
The
Company has entered into a Sales Agency Financing Agreement, as amended June
25,
2007, 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 December 1, 2008. 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 would be 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 June 28, 2007, filed with
the
SEC 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, 2007.
MDU
Energy Capital, LLC On August 14, 2007, MDU Energy Capital entered
into a $125 million master shelf agreement (dated as of August 9, 2007), and
borrowed $50 million under the agreement. On August 28, 2007, MDU Energy
Capital borrowed an additional $35 million under the master shelf agreement.
MDU
Energy Capital used the proceeds from the borrowings to repay a short-term
intercompany loan from the Company applicable to the acquisition of Cascade,
as
previously discussed.
The
master shelf agreement contains customary covenants and provisions, including
covenants of MDU Energy Capital not to permit (i) the ratio of its total debt
(on a consolidated basis) to adjusted total capitalization to be greater than
70
percent, or (ii) the ratio of subsidiary debt to subsidiary capitalization
to be
greater than 65 percent. The agreement also includes a covenant requiring the
ratio of MDU Energy Capital earnings before interest and taxes to interest
expense (on a consolidated basis), for the twelve month period ended each fiscal
quarter (commencing with the fiscal quarter ended September 30, 2007), to be
greater than 1.5 to 1. MDU Energy Capital was in compliance with these
covenants and met the required conditions at September 30, 2007. In addition,
payment obligations under the master shelf agreement may be accelerated upon
the
occurrence of an event of default (as described in the agreement). MDU
Energy Capital may incur additional indebtedness under the master shelf
agreement, up to a total of $125 million, until the earlier of August 14, 2010,
or such time as the agreement is terminated by either of the parties
thereto.
Cascade
Natural Gas Corporation Cascade has a $60 million
bank revolving credit agreement which expires on January 1, 2008. The Company
is
currently in negotiations regarding a renewal of this agreement. Cascade also
has a $20 million uncommitted line of credit which may be terminated by the
bank
or Cascade at any time. There were no outstanding borrowings under the Cascade
credit agreements at September 30, 2007. As of September
30, 2007, there were outstanding letters of credit, as discussed in Note 20,
of
which $1.9 million reduced amounts available under the $60 million credit
agreement.
In
order
to borrow under Cascade’s $60 million bank revolving credit agreement, Cascade
must be in compliance with the applicable covenants and certain other
conditions. This includes a covenant not to permit, at any time, the ratio
of
total debt to total capitalization to be greater than 65 percent. Also included
is a covenant that requires Cascade’s fixed charges coverage ratio to be greater
than 1.2 to 1 on any given date, as measured for the prior four fiscal quarters.
Cascade was in compliance with these covenants and met the required conditions
at September 30, 2007.
Centennial
Energy Holdings, Inc. Centennial has two revolving credit
agreements with various banks and institutions totaling $425 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 or the Centennial
commercial paper program at September 30, 2007. 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. The second agreement is an
uncommitted line for $25 million, and may be terminated by the bank at any
time.
As of September 30, 2007, there were outstanding letters of credit, as discussed
in Note 20, of which $27.2 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. Under the terms of the master shelf agreement, $420.0
million was outstanding at September 30, 2007. 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.
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. For more information on the covenants and certain other conditions
for the $400 million credit agreement and the master shelf agreement, see Part
II, Item 7, in the 2006 Annual Report. Centennial and such subsidiaries were
in
compliance with these covenants and met the required conditions at September
30,
2007.
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, 2007. 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. For more information on the covenants and certain other conditions
for the uncommitted long-term master shelf agreement, see Part II, Item 7,
in
the 2006 Annual Report. Williston Basin was in compliance with these covenants
and met the required conditions at September 30, 2007.
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. For more information, see
Note 20.
Centennial
continues to guarantee CEM’s obligations under a construction contract for a
550-MW combined-cycle electric generating facility near Hobbs, New Mexico.
For
more information, see Note 20.
Contractual
obligations and commercial commitments
At
September 30, 2007, 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:
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(In
millions)
|
|
Long-term
debt
|
|
$ |
132.0
|
|
|
$ |
87.7
|
|
|
$ |
22.8
|
|
|
$ |
92.6
|
|
|
$ |
80.4
|
|
|
$ |
863.2
|
|
|
$ |
1,278.7
|
|
Estimated interest payments*
|
|
|
70.4
|
|
|
|
63.2
|
|
|
|
60.5
|
|
|
|
57.2
|
|
|
|
53.1
|
|
|
|
351.2
|
|
|
|
655.6
|
|
Operating
leases
|
|
|
16.4
|
|
|
|
13.9
|
|
|
|
12.6
|
|
|
|
10.5
|
|
|
|
7.2
|
|
|
|
49.5
|
|
|
|
110.1
|
|
Purchase
commitments
|
|
|
508.9
|
|
|
|
332.0
|
|
|
|
253.7
|
|
|
|
172.1
|
|
|
|
121.8
|
|
|
|
342.3
|
|
|
|
1,730.8
|
|
|
|
$ |
727.7
|
|
|
$ |
496.8
|
|
|
$ |
349.6
|
|
|
$ |
332.4
|
|
|
$ |
262.5
|
|
|
$ |
1,606.2
|
|
|
$ |
3,775.2
|
|
*
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, interest rates and foreign currency. 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. Cascade utilizes derivative
instruments to manage a portion of the market risk associated with fluctuations
in the price of natural gas on its forecasted purchases of natural gas. At
September 30, 2007, Fidelity held natural gas and oil swap and collar derivative
instruments and Cascade held natural gas swap derivative instruments. For more
information on derivative instruments and commodity price risk, see Part II,
Item 7A in the 2006 Annual Report, and Notes 12 and 15.
The
following table summarizes derivative instruments entered into by Fidelity
and
Cascade as of September 30, 2007. These agreements call for Fidelity to receive
fixed prices and pay variable prices, and for Cascade to receive variable prices
and pay fixed prices.
(Notional
amount and fair value in thousands)
Fidelity
|
|
Weighted
Average
Fixed
Price
(Per
MMBtu)
|
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
|
Fair
Value
|
|
Natural
gas swap agreements maturing in 2007
|
|
$ |
7.76
|
|
|
|
2,777
|
|
|
$ |
6,393
|
|
Natural
gas swap agreements maturing in 2008
|
|
$ |
8.12
|
|
|
|
9,603
|
|
|
$ |
7,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cascade
Core
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2007
|
|
$ |
7.69
|
|
|
|
7,792
|
|
|
$ |
(13,421 |
) |
Natural
gas swap agreements maturing in 2008
|
|
$ |
7.72
|
|
|
|
20,104
|
|
|
$ |
(11,538 |
) |
Natural
gas swap agreements maturing in 2009
|
|
$ |
7.94
|
|
|
|
10,755
|
|
|
$ |
(4,479 |
) |
Natural
gas swap agreements maturing in 2010
|
|
$ |
7.73
|
|
|
|
4,576
|
|
|
$ |
(2,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cascade
Non-Core
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2007
|
|
$ |
6.58
|
|
|
|
601
|
|
|
$ |
(1,653 |
) |
Natural
gas swap agreements maturing in 2008
|
|
$ |
7.31
|
|
|
|
1,307
|
|
|
$ |
(686 |
) |
Fidelity
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
MMBtu)
|
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2007
|
|
$ |
7.84/$10.13
|
|
|
|
3,508
|
|
|
$ |
4,958
|
|
Natural
gas collar agreements maturing in 2008
|
|
$ |
7.27/$8.32
|
|
|
|
8,690
|
|
|
$ |
2,428
|
|
Fidelity
|
|
Weighted
Average
Fixed
Price
(Per
barrel)
|
|
|
Forward
Notional
Volume
(In
barrels)
|
|
|
Fair
Value
|
|
Oil
swap agreement maturing in 2007
|
|
$ |
75.25
|
|
|
|
39
|
|
|
$ |
(249 |
) |
Fidelity
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
barrel)
|
|
|
Forward
Notional
Volume
(In
barrels)
|
|
|
Fair
Value
|
|
Oil collar
agreement maturing in 2008
|
|
$ |
67.50/$78.70
|
|
|
|
73
|
|
|
$ |
(184 |
) |
Interest
rate risk
There
were no material changes to interest rate risk faced by the Company from those
reported in the 2006 Annual Report. For more information on interest rate risk,
see Part II, Item 7A in the 2006 Annual Report.
At
September 30, 2007 and 2006, and December 31, 2006, the Company had no
outstanding interest rate hedges.
Foreign
currency risk
MDU
Brasil’s equity method investments in the Brazilian Transmission Lines are
exposed to market risks from changes in foreign currency exchange rates between
the U.S. dollar and the Brazilian Real. For further information on foreign
currency risk, see Note 4 in the 2006 Annual Report.
At
September 30, 2007 and 2006, and December 31, 2006, the Company had no
outstanding foreign currency hedges.
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 2006 Annual Report other than the completion of
the Company’s acquisition of Cascade and risks related to a reduction in
construction activity at the construction materials and mining segment, as
discussed below. These factors 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.
Economic
volatility affects the Company’s operations, as well as the demand for its
products and services and, as a result, may have a negative impact on the
Company’s future revenues.
The
global demand for natural resources, interest rates, governmental budget
constraints and the ongoing threat of terrorism can create volatility in the
financial markets. A soft economy could negatively affect the level of public
and private expenditures on projects and the timing of these projects which,
in
turn, would negatively affect the demand for the Company’s products and
services.
The
construction materials and mining segment is experiencing a reduction in
construction activity and product sales volumes in some markets due to lower
demand, which could negatively affect the Company’s results of
operations.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
Between
July 1, 2007 and September 30, 2007, the Company issued 450,139 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
businesses acquired by the Company in this period. The common stock and
preference share purchase rights issued by the Company in these transactions
were issued in a private transaction exempt from registration under the
Securities Act of 1933, as amended, 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
See
the
index to exhibits immediately preceding the exhibits filed with this
report.
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 8, 2007
|
|
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.