mdu10k.htm
UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON,
D.C. 20549
FORM 10-K
X
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ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
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THE SECURITIES EXCHANGE ACT OF
1934
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For the
fiscal year ended December 31, 2007
OR
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
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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
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41-0423660
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(State
or other jurisdiction of incorporation
or organization)
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(I.R.S.
Employer Identification No.)
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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)
Securities
registered pursuant to Section 12(b) of the Act:
Title of each
class
Name of each exchange on
which registered
Common
Stock, par value $1.00
and
Preference Share Purchase Rights
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New
York Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act:
Preferred Stock, par value
$100
(Title of
Class)
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes x No o.
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange Act. Yes o No x.
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 if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of the registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act (Check one):
Large accelerated filer x Accelerated
filer o
Non-accelerated filer o Smaller
Reporting Company o
(Do not check if a smaller reporting
company)
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes o No x.
State the
aggregate market value of the voting common stock held by nonaffiliates of the
registrant as of June 30, 2007: $5,099,834,108.
Indicate
the number of shares outstanding of each of the registrant's classes of common
stock, as of February 11, 2008: 182,462,076 shares.
DOCUMENTS INCORPORATED BY
REFERENCE
Portions
of the registrant's 2008 Proxy Statement are incorporated by reference in Part
III, Items 10, 11, 12, 13 and 14 of this Report.
CONTENTS
PART
I
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Forward-Looking
Statements
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Items 1 and 2 Business
and Properties
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General
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Electric
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Natural
Gas Distribution
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Construction
Services
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Pipeline
and Energy Services
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Natural
Gas and Oil Production
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Construction
Materials and Contracting
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Item 1A
Risk Factors
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Item 1B
Unresolved Comments
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Item 3
Legal Proceedings
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Item 4
Submission of Matters to a Vote of Security Holders
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PART
II
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Item 5
Market for the Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
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Item 6
Selected Financial Data
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Item 7
Management's Discussion and Analysis of Financial Condition and
Results of Operations
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Item 7A
Quantitative and Qualitative Disclosures About Market
Risk
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Item 8
Financial Statements and Supplementary Data
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Item 9
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
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Item 9A
Controls and Procedures
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Item 9B
Other Information
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PART
III
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Item 10
Directors, Executive Officers and Corporate
Governance
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Item 11
Executive Compensation
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Item 12
Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
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Item 13
Certain Relationships and Related Transactions, and Director
Independence
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Item 14
Principal Accountant Fees and Services
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PART
IV
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Item 15
Exhibits and Financial Statement Schedules
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Signatures
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Exhibits
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DEFINITIONS
The
following abbreviations and acronyms used in this Form 10-K are defined
below:
Abbreviation or
Acronym
AFUDC
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Allowance
for funds used during construction
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ALJ
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Administrative
Law Judge
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Alusa
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Tecnica
de Engenharia Electrica - Alusa
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Anadarko
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Anadarko
Petroleum Corporation
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APB
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Accounting
Principles Board
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APB
Opinion No. 25
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Accounting
for Stock-Based Compensation
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Army
Corps
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U.S.
Army Corps of Engineers
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Badger
Hills Project
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Tongue
River-Badger Hills Project
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Bbl
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Barrel
of oil or other liquid hydrocarbons
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Bcf
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Billion
cubic feet
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BER
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Montana
Board of Environmental Review
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Big
Stone Station
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450-MW
coal-fired electric generating facility located near Big Stone City, South
Dakota (22.7 percent ownership)
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Big
Stone Station II
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Proposed
coal-fired electric generating facility located near Big Stone City, South
Dakota (the Company anticipates ownership of at least 116
MW)
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Bitter
Creek
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Bitter
Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI
Holdings
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Black
Hills Power
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Black
Hills Power and Light Company
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BLM
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Bureau
of Land Management
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Brascan
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Brascan
Brasil Ltda.
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Brazilian
Transmission Lines
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Company's
equity method investment in companies owning
ECTE,
ENTE and ERTE
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Btu
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British
thermal unit
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Carib
Power
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Carib
Power Management LLC
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Cascade
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Cascade
Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy
Capital (acquired July 2, 2007)
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CBNG
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Coalbed
natural gas
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CELESC
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Centrais
Elétricas de Santa Catarina S.A.
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CEM
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Colorado
Energy Management, LLC, a former direct wholly owned subsidiary of
Centennial Resources (sold in the third quarter of
2007)
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CEMIG
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Companhia
Energética de Minas Gerais
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Centennial
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Centennial
Energy Holdings, Inc., a direct wholly owned subsidiary of the
Company
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Centennial
Capital
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Centennial
Holdings Capital LLC, a direct wholly owned subsidiary of
Centennial
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Centennial
International
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Centennial
Energy Resources International, Inc., a direct wholly owned subsidiary of
Centennial Resources
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Centennial
Power
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Centennial
Power, Inc., a former direct wholly owned subsidiary of Centennial
Resources (sold in the third quarter of 2007)
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Centennial
Resources
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Centennial
Energy Resources LLC, a direct wholly owned subsidiary of
Centennial
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CERCLA
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Comprehensive
Environmental Response, Compensation and Liability Act
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Clean
Air Act
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Federal
Clean Air Act
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Clean
Water Act
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Federal
Clean Water Act
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CMS
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Cost
Management Services, Inc.
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Colorado
Federal District Court
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U.S.
District Court for the District of Colorado
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Company
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MDU
Resources Group, Inc.
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D.C.
Appeals Court
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U.S.
Court of Appeals for the District of Columbia Circuit
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dk
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Decatherm
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DRC
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Dakota
Resource Council
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EBSR
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Elk
Basin Storage Reservoir, one of Williston Basin's natural gas storage
reservoirs, which is located in Montana and Wyoming
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ECTE
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Empresa
Catarinense de Transmissão de Energia S.A.
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EIS
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Environmental
Impact Statement
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EITF
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Emerging
Issues Task Force
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EITF
No. 00-21
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Revenue
Arrangements with Multiple Deliverables
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EITF
No. 91-6
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Revenue
Recognition of Long-Term Power Sales Contracts
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ENTE
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Empresa
Norte de Transmissão de Energia S.A.
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EPA
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U.S.
Environmental Protection Agency
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ERTE
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Empresa
Regional de Transmissão de Energia S.A.
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ESA
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Endangered
Species Act
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Exchange
Act
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Securities
Exchange Act of 1934, as amended
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FASB
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Financial
Accounting Standards Board
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FERC
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Federal
Energy Regulatory Commission
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Fidelity
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Fidelity
Exploration & Production Company, a direct wholly owned subsidiary of
WBI Holdings
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FIN
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FASB
Interpretation No.
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FIN
47
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Accounting
for Conditional Asset Retirement Obligations - An Interpretation of FASB
Statement No. 143
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FIN
48
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Accounting
for Uncertainty in Income Taxes
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Great
Plains
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Great
Plains Natural Gas Co., a public utility division of the
Company
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Hartwell
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Hartwell
Energy Limited Partnership, a former equity method investment of the
Company (sold in the third quarter of 2007)
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Howell
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Howell
Petroleum Corporation, a wholly owned subsidiary of
Anadarko
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IBEW
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International
Brotherhood of Electrical Workers
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ICWU
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International
Chemical Workers Union
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Indenture
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Indenture
dated as of December 15, 2003, as supplemented, from the Company to The
Bank of New York as Trustee
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Innovatum
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Innovatum,
Inc., a former indirect wholly owned subsidiary of WBI Holdings (the stock
and Innovatum's assets have been sold)
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Item
8
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Financial
Statements and Supplementary Data
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Kennecott
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Kennecott
Coal Sales Company
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Knife
River
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Knife
River Corporation, a direct wholly owned subsidiary of
Centennial
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K-Plan
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Company's
401(k) Retirement Plan
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kW
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Kilowatts
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kWh
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Kilowatt-hour
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LWG
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Lower
Willamette Group
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MAPP
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Mid-Continent
Area Power Pool
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MBbls
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Thousands
of barrels of oil or other liquid hydrocarbons
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MBI
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Morse
Bros., Inc., an indirect wholly owned subsidiary of Knife
River
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Mcf
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Thousand
cubic feet
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MD&A
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Management's
Discussion and Analysis of Financial Condition and Results of
Operations
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Mdk
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Thousand
decatherms
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MDU
Brasil
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MDU
Brasil Ltda., an indirect wholly owned subsidiary of Centennial
International
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MDU
Construction Services
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MDU
Construction Services Group, Inc., a direct wholly owned subsidiary of
Centennial
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MDU
Energy Capital
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MDU
Energy Capital, LLC, a direct wholly owned subsidiary of the
Company
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Midwest
ISO
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Midwest
Independent Transmission System Operator, Inc.
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MMBtu
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Million
Btu
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MMcf
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Million
cubic feet
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MMcfe
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Million
cubic feet equivalent
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MMdk
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Million
decatherms
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MNPUC
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Minnesota
Public Utilities Commission
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Montana-Dakota
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Montana-Dakota
Utilities Co., a public utility division of the Company
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Montana
DEQ
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Montana
State Department of Environmental Quality
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Montana
Federal District Court
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U.S.
District Court for the District of Montana
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Mortgage
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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
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MPX
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MPX
Termoceara Ltda. (49 percent ownership, sold in June
2005)
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MTPSC
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Montana
Public Service Commission
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MW
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Megawatt
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ND
Health Department
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North
Dakota Department of Health
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NDPSC
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North
Dakota Public Service Commission
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NEPA
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National
Environmental Policy Act
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NHPA
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National
Historic Preservation Act
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Ninth
Circuit
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U.S.
Ninth Circuit Court of Appeals
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NPRC
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Northern
Plains Resource Council
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OPUC
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Oregon
Public Utilities Commission
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Order
on Rehearing
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Order
on Rehearing and Compliance and Remanding Certain Issues for
Hearing
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Oregon
DEQ
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Oregon
State Department of Environmental Quality
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PCBs
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Polychlorinated
biphenyls
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PPA
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Power
purchase and sale agreement
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Prairielands
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Prairielands
Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI
Holdings
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Proxy
Statement
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Company's
2008 Proxy Statement
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PSD
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Prevention
of Significant Deterioration
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RCRA
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Resource
Conservation and Recovery Act
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SDPUC
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South
Dakota Public Utilities Commission
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SEC
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U.S.
Securities and Exchange Commission
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Securities
Act Industry Guide 7
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Description
of Property by Issuers Engaged or to be Engaged in Significant Mining
Operations
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SEIS
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Supplemental
Environmental Impact Statement
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SFAS
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Statement
of Financial Accounting Standards
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SFAS
No. 71
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Accounting
for the Effects of Certain Types of Regulation
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SFAS
No. 109
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Accounting
for Income Taxes
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SFAS
No. 115
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Accounting
for Certain Investments in Debt and Equity Securities
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SFAS
No. 123
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Accounting
for Stock-Based Compensation
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SFAS
No. 123 (revised)
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Share-Based
Payment (revised 2004)
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SFAS
No. 141 (revised)
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Business
Combinations (revised 2007)
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SFAS
No. 142
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Goodwill
and Other Intangible Assets
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SFAS
No. 143
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Accounting
for Asset Retirement Obligations
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SFAS
No. 144
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Accounting
for the Impairment or Disposal of Long-Lived Assets
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SFAS
No. 148
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Accounting
for Stock-Based Compensation - Transition and Disclosure - an amendment of
SFAS No. 123
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SFAS
No. 157
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Fair
Value Measurements
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SFAS
No. 158
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Employers'
Accounting for Defined Benefit Pension and Other Postretirement
Plans
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SFAS
No. 159
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The
Fair Value Option for Financial Assets and Financial
Liabilities
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SFAS
No. 160
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Noncontrolling
Interests in Consolidated Financial Statements - an amendment of ARB No.
51 (Consolidated Financial Statements)
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Sheridan
System
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A
separate electric system owned by Montana-Dakota
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SMCRA
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Surface
Mining Control and Reclamation Act
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Stock
Purchase Plan
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Company's
Dividend Reinvestment and Direct Stock Purchase Plan
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Termoceara
Generating Facility
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220-MW
natural gas-fired electric generating facility in the Brazilian state of
Ceara, owned and operated by MPX (the Company's 49-percent ownership
interest was sold in June 2005)
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TRWUA
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Tongue
River Water Users' Association
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WBI
Holdings
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WBI
Holdings, Inc., a direct wholly owned subsidiary of
Centennial
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Westmoreland
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Westmoreland
Coal Company
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Williston
Basin
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Williston
Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of
WBI Holdings
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WUTC
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Washington
Utilities and Transportation Commission
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Wyoming
DEQ
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Wyoming
State Department of Environmental Quality
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Wyoming
Federal District Court
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U.S.
District Court for the District of Wyoming
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WYPSC
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Wyoming
Public Service Commission
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PART
I
FORWARD-LOOKING
STATEMENTS
This Form
10-K 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, and 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
Item 7 – MD&A – Prospective Information.
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. All
forward-looking statements, whether written or oral and whether made by or on
behalf of the Company, are expressly qualified by the risk factors and
cautionary statements in this Form 10-K, including statements contained within
Item 1A – Risk Factors.
ITEMS 1 AND 2. BUSINESS AND
PROPERTIES
GENERAL
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 contracting
segment – formerly construction materials and mining), MDU Construction Services
(construction services segment), Centennial Resources and Centennial Capital
(both reflected in the Other category).
The
Company's equity method investment in the Brazilian Transmission Lines, as
discussed in Item 8 – Note 4, is reflected in the
Other category.
As
discussed in Item 8 – Note 3, the Company sold its domestic independent power
production assets in the third quarter of 2007.
As of
December 31, 2007, the Company had 12,293 employees with 161 employed at
MDU Resources Group, Inc., 900 at Montana-Dakota, 35 at Great Plains, 376 at
Cascade, 570 at WBI Holdings, 4,905 at Knife River, 5,343 at MDU Construction
Services and three at Centennial Resources. The number of employees at certain
Company operations fluctuates during the year depending upon the number and size
of construction projects. The Company considers its relations with employees to
be satisfactory.
At
Montana-Dakota and Williston Basin, 437 and 79 employees, respectively, are
represented by the IBEW. Labor contracts with such employees are in effect
through May 30, 2011, and March 31, 2008, for Montana-Dakota and Williston
Basin, respectively. Williston Basin is in negotiations on its labor
contract.
At
Cascade, 210 employees are represented by the ICWU. Labor contracts with such
employees extend to April 1, 2009, and remain in force thereafter from year to
year unless terminated by either party.
Knife
River has 43 labor contracts that represent approximately 900 of its
construction materials employees. Knife River is in negotiations on six of its
labor contracts.
MDU
Construction Services has 81 labor contracts representing the majority of its
employees. The majority of the labor contracts contain provisions that prohibit
work stoppages or strikes and provide for binding arbitration dispute resolution
in the event of an extended disagreement.
The
Company's principal properties, which are of varying ages and are of different
construction types, are generally in good condition, are well maintained and are
generally suitable and adequate for the purposes for which they are
used.
The
financial results and data applicable to each of the Company's business
segments, as well as their financing requirements, are set forth in Item 7 –
MD&A and Item 8 – Note 16 and Supplementary Financial
Information.
The
operations of the Company and certain of its subsidiaries are subject to
federal, state and local laws and regulations providing for air, water and solid
waste pollution control; state facility-siting regulations; zoning and planning
regulations of certain state and local authorities; federal health and safety
regulations and state hazard communication standards. The Company believes that
it is in substantial compliance with these regulations, except as to what may be
ultimately determined with regard to items discussed in Environmental matters in
Item 8 – Note 20. There are no pending CERCLA actions for any of the Company's
properties, other than the Portland, Oregon, Harbor Superfund Site.
Governmental
regulations establishing environmental protection standards are continuously
evolving and, therefore, the character, scope, cost and availability of the
measures that will permit compliance with these laws or regulations cannot be
accurately predicted. Disclosure regarding specific environmental matters
applicable to each of the Company's businesses is set forth under each business
description below.
This
annual report on Form 10-K, the Company's quarterly reports on Form 10-Q, the
Company's current reports on Form 8-K and any amendments to those reports filed
or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are
available free of charge through the Company's Web site as soon as reasonably
practicable after the Company has electronically filed such reports with, or
furnished such reports to, the SEC. The Company's Web site address is
www.mdu.com. The information available on the Company's Web site is not part of
this annual report on Form 10-K.
ELECTRIC
General Montana-Dakota
provides electric service at retail, serving over 120,000 residential,
commercial, industrial and municipal customers located in 177 communities and
adjacent rural areas as of December 31, 2007. The principal properties owned by
Montana-Dakota for use in its electric operations include interests in eight
electric generating facilities, as further described under System Supply, System
Demand and Competition, and approximately 3,000 and 4,500 miles of transmission
and distribution lines, respectively. Montana-Dakota has obtained and holds, or
is in the process of renewing, valid and existing franchises authorizing it to
conduct its electric operations in all of the municipalities it serves where
such franchises are required. Montana-Dakota intends to protect its service area
and seek renewal of all expiring franchises. As of December 31, 2007,
Montana-Dakota's net electric plant investment approximated
$390 million.
Substantially
all of Montana-Dakota's electric properties are subject to the lien of the
Mortgage and to the junior lien of the Indenture.
The
percentage of Montana-Dakota's 2007 retail electric utility operating revenues
by jurisdiction is as follows: North Dakota – 62 percent; Montana –
21 percent; South Dakota – 7 percent; and Wyoming – 10 percent. Retail
electric rates, service, accounting and certain security issuances are subject
to regulation by the NDPSC, MTPSC, SDPUC and WYPSC. The interstate transmission
and wholesale electric power operations of Montana-Dakota also are subject to
regulation by the FERC under provisions of the Federal Power Act, as are
interconnections with other utilities and power generators, the issuance of
securities, accounting and other matters. Montana-Dakota participates in the
Midwest ISO wholesale energy market.
The
Midwest ISO is a regional transmission organization responsible for operational
control of the transmission systems of its members. The Midwest ISO provides
security center operations, tariff administration and operates a day-ahead and
real-time energy market. As a member of Midwest ISO, Montana-Dakota's generation
is sold into the Midwest ISO energy market and its energy needs are purchased
from that market.
System Supply, System Demand and
Competition Through an interconnected electric system,
Montana-Dakota serves markets in portions of western North Dakota, including
Bismarck, Dickinson and Williston; eastern Montana, including Glendive and Miles
City; and northern South Dakota, including Mobridge. The interconnected system
consists of eight electric generating facilities, which have an aggregate
nameplate rating attributable to Montana-Dakota's interest of 455,555 kW and a
total summer net capability of 483,360 kW. Montana-Dakota's four principal
generating stations are steam-turbine generating units using coal for fuel. The
nameplate rating for Montana-Dakota's ownership interest in these four stations
(including interests in the Big Stone Station and the Coyote Station,
aggregating 22.7 percent and 25.0 percent, respectively) is 327,758 kW.
During 2007, Montana-Dakota began construction on 19,500 kW of wind-powered
electric generation near Baker, Montana. Approximately 1,500 kW of this project
came online in December 2007, and the remainder came online in early 2008, and
is reflected in the following table. Three combustion turbine peaking stations
and the wind-powered electric generating facility supply the balance of
Montana-Dakota's interconnected system electric generating
capability.
In
September 2005, Montana-Dakota entered into a contract for seasonal capacity
from a neighboring utility, starting at 85 MW in 2007, increasing to 105 MW in
2011, with an option for capacity in 2012. In April 2007, Montana-Dakota entered
into an additional contract for seasonal capacity of 10 MW in May through
October of each year continuing through 2010. Energy also will be
purchased as needed from the Midwest ISO market. In 2007, Montana-Dakota
purchased approximately 13 percent of its kWh needs for its interconnected
system through the Midwest ISO market.
The
following table sets forth details applicable to the Company's electric
generating stations:
|
|
|
|
|
2007
Net
|
|
|
|
Nameplate
|
Summer
|
|
Generation
|
|
|
|
Rating
|
Capability
|
|
(kWh
in
|
|
Generating
Station
|
Type
|
(kW)
|
(kW)
|
|
thousands)
|
|
|
|
|
|
|
|
|
North
Dakota:
|
|
|
|
|
|
|
Coyote*
|
Steam
|
103,647
|
106,750
|
|
750,670
|
|
Heskett
|
Steam
|
86,000
|
103,260
|
|
618,431
|
|
Williston
|
Combustion
Turbine
|
7,800
|
9,600
|
|
(5)
|
**
|
South
Dakota:
|
|
|
|
|
|
|
Big
Stone*
|
Steam
|
94,111
|
105,950
|
|
554,967
|
|
Montana:
|
|
|
|
|
|
|
Lewis
& Clark
|
Steam
|
44,000
|
52,300
|
|
314,672
|
|
Glendive
|
Combustion
Turbine
|
77,347
|
78,900
|
|
12,477
|
|
Miles
City
|
Combustion
Turbine
|
23,150
|
22,300
|
|
2,623
|
|
Diamond
Willow
|
Wind
|
19,500
|
4,300
|
***
|
16
|
|
|
|
455,555
|
483,360
|
|
2,253,851
|
|
|
* Reflects
Montana-Dakota's ownership
interest.
|
|
** Station
use, to meet MAPP's accreditation requirements, exceeded
generation.
|
|
***Pending
accreditation.
|
Virtually
all of the current fuel requirements of the Coyote, Heskett and Lewis &
Clark stations are met with coal supplied by subsidiaries of Westmoreland.
Contracts with Westmoreland for the Coyote, Heskett and Lewis & Clark
stations expire in May 2016, April 2011 and December 2012, respectively. The
Coyote coal supply agreement provides for the purchase of coal necessary to
supply the coal requirements of the Coyote Station or 30,000 tons per week,
whichever may be the greater quantity at contracted pricing. The maximum
quantity of coal during the term of the agreement, and any extension, is 75
million tons. The Heskett and Lewis & Clark coal supply agreements provide
for the purchase of coal necessary to supply the coal requirements of these
stations at contracted pricing. Montana-Dakota estimates the Heskett and Lewis
& Clark coal requirement to be in the range of 500,000 to 600,000 tons, and
250,000 to 350,000 tons per contract year, respectively.
A coal
supply agreement, entered into in August 2007 with Kennecott, meets the majority
of the Big Stone Station’s fuel requirements for the years 2008 to 2010 at
contracted pricing. The Kennecott agreement provides for the purchase of
2.1 million, 1.8 million and 1.0 million tons of coal in 2008, 2009 and 2010,
respectively.
During
the years ended December 31, 2005, through December 31, 2007, the average
cost of coal purchased, including freight at Montana-Dakota's electric
generating stations (including the Big Stone and Coyote stations) was as
follows:
Years
Ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Average
cost of coal per MMBtu
|
|
$ |
1.29
|
|
|
$ |
1.26
|
|
|
$ |
1.14
|
|
Average
cost of coal per ton
|
|
$ |
18.71
|
|
|
$ |
18.48
|
|
|
$ |
17.01
|
|
The
maximum electric peak demand experienced to date attributable to sales to retail
customers on the interconnected system was 525,643 kW in July 2007.
Montana-Dakota's latest forecast for its interconnected system indicates that
its annual peak will continue to occur during the summer and the peak demand
growth rate through 2013 will approximate less than 1 percent
annually.
Montana-Dakota
has major interconnections with its neighboring utilities and considers these
interconnections adequate for coordinated planning, emergency assistance,
exchange of capacity and energy and power supply reliability.
Through
the Sheridan System, Montana-Dakota serves Sheridan, Wyoming, and neighboring
communities. The maximum peak demand experienced to date and attributable to
Montana-Dakota sales to retail customers on that system was approximately 60,600
kW and occurred in July 2007.
In
December 2004, Montana-Dakota entered into a power supply contract with Black
Hills Power to purchase up to 74,000 kW of capacity annually during the period
from January 1, 2007, to December 31, 2016. This contract also provides an
option for Montana-Dakota to purchase 25 MW of
an existing or future baseload coal-fired electric generating facility from
Black Hills Power to serve the Sheridan load.
Montana-Dakota
is subject to competition in varying degrees, in certain areas, from rural
electric cooperatives, on-site generators, co-generators and municipally owned
systems. In addition, competition in varying degrees exists between electricity
and alternative forms of energy such as natural gas.
Regulatory Matters and Revenues
Subject to Refund Fuel adjustment
clauses contained in North Dakota and South Dakota jurisdictional electric rate
schedules allow Montana-Dakota to reflect monthly increases or decreases in fuel
and purchased power costs (excluding demand charges). In North Dakota, the
Company is deferring electric fuel and purchased power costs (excluding demand
charges) that are greater or less than amounts presently being recovered through
its existing rate schedules. In Wyoming, an annual Electric Power Supply Cost
Adjustment mechanism allows Montana-Dakota to reflect increases or decreases in
fuel and purchased power costs (including demand charges) related to power
supply and Montana-Dakota is deferring costs that are greater or less than
amounts presently being recovered through its existing rate schedules. Such
orders generally provide that these amounts are recoverable or refundable
through rate adjustments within a period ranging from 14 to 25 months from the
time such costs are paid. In Montana, such cost changes are includable in
general rate filings. For additional information, see Item 8 – Note
19.
In July
2007, Montana-Dakota filed an electric rate case with the MTPSC. For additional
information, see Item 8 – Note 19.
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 Station II. For additional information, see Item 8 – Note 19.
Environmental Matters
Montana-Dakota's electric operations are subject to federal, state
and local laws and regulations providing for air, water and solid waste
pollution control; state facility-siting regulations; zoning and planning
regulations of certain state and local authorities; federal health and safety
regulations; and state hazard communication standards. Montana-Dakota believes
it is in substantial compliance with these regulations.
Montana-Dakota's
electric generating facilities have Title V Operating Permits, under the Clean
Air Act, issued by the states in which it operates. Each of these permits has a
five-year life. Near the expiration of these permits, renewal applications are
submitted. Permits continue in force beyond the expiration date, provided the
application for renewal is submitted by the required date, usually six months
prior to expiration. Renewal is pending for the Big Stone Station Title V
Operating Permit which expired in 2002. An application for renewal will be
submitted for the Coyote Station Title V Operating Permit that expires in
September 2008. State water discharge permits issued under the requirements of
the Clean Water Act are maintained for power production facilities on the
Yellowstone and Missouri rivers. These permits also have five-year lives.
Montana-Dakota renews these permits as necessary prior to expiration. Other
permits held by these facilities may include an initial siting permit, which is
typically a one-time, preconstruction permit issued by the state; state permits
to dispose of combustion by-products; state authorizations to withdraw water for
operations; and Army Corps permits to construct water intake structures.
Montana-Dakota's Army Corps permits grant one-time permission to construct and
do not require renewal. Other permit terms vary and the permits are renewed as
necessary.
Montana-Dakota's
electric operations are conditionally exempt small-quantity hazardous waste
generators and subject only to minimum regulation under the RCRA. Montana-Dakota
routinely handles PCBs from its electric operations in accordance with federal
requirements. PCB storage areas are registered with the EPA as
required.
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. For more information regarding this
notice, see Item 8 – Note 20.
Montana-Dakota
incurred $7.8 million of environmental expenditures in 2007. Expenditures are
estimated to be $29.1 million, $19.5 million and $6.3 million in 2008, 2009 and
2010, respectively, to maintain environmental compliance as new emission
controls are required. Projects will include sulfur-dioxide and mercury control
equipment installation at electric generating facilities. For matters involving
Montana-Dakota and the ND Health Department, see Item 8 – Note 20.
NATURAL GAS
DISTRIBUTION
General The Company's
natural gas distribution operations consist of Montana-Dakota, Great Plains and
Cascade. Montana-Dakota sells natural gas at retail, serving over 234,000
residential, commercial and industrial customers in 145 communities and adjacent
rural areas as of December 31, 2007, and provides natural gas
transportation services to certain customers on its system. Great Plains sells
natural gas at retail, serving over 22,000 residential, commercial and
industrial customers in 19 communities and adjacent rural areas as of
December 31, 2007, and provides natural gas transportation services to
certain customers on its system. Cascade sells natural gas at retail, serving
over 250,000 residential, commercial and industrial customers in 98 communities
and adjacent rural areas as of December 31, 2007, and provides natural gas
transportation services to certain customers on its system. These services for
the three public utility operations are provided through distribution systems
aggregating approximately 11,400 miles. The natural gas distribution operations
have obtained and hold, or are in the process of renewing, valid and existing
franchises authorizing them to conduct their natural gas operations in all of
the municipalities they serve where such franchises are required. These
operations intend to protect their service areas and seek renewal of all
expiring franchises. As of December 31, 2007, Montana-Dakota's, Great
Plains' and Cascade's net natural gas distribution plant investment approximated
$527.5 million.
Substantially
all of Montana-Dakota's natural gas distribution properties are subject to the
lien of the Mortgage and to the junior lien of the Indenture.
The
percentage of the natural gas distribution operations’ 2007 natural gas utility
operating sales revenues by jurisdiction is as follows: North Dakota – 23
percent; Minnesota – 8 percent; Montana – 15 percent; Oregon – 10 percent;
South Dakota – 12 percent; Washington – 29 percent and Wyoming – 3 percent. The
above percentages reflect operating sales revenues of Cascade since the date of
acquisition. The natural gas distribution operations are subject to regulation
by the NDPSC, MNPUC, MTPSC, OPUC, SDPUC, WUTC and WYPSC regarding retail rates,
service, accounting and certain security issuances.
System Supply, System Demand and
Competition The natural gas
distribution operations serve retail natural gas markets, consisting principally
of residential and firm commercial space and water heating users, in portions of
North Dakota, including Bismarck, Dickinson, Wahpeton, Williston, Minot and
Jamestown; western Minnesota, including Fergus Falls, Marshall and Crookston;
eastern Montana, including Billings, Glendive and Miles City; central and
eastern Oregon, including Bend and Pendleton; western and north-central South
Dakota, including Rapid City, Pierre and Mobridge; western and south-central
Washington, including Bellingham, Bremerton, Longview, Moses Lake, Mount Vernon,
Tri-Cities, Walla Walla and Yakima; and northern Wyoming, including Sheridan.
These markets are highly seasonal and sales volumes depend largely on the
weather, the effects of which are mitigated in certain jurisdictions by a
weather normalization mechanism discussed in Regulatory Matters.
Competition
in varying degrees exists between natural gas and other fuels and forms of
energy. The natural gas distribution operations have established various natural
gas transportation service rates for their distribution businesses to retain
interruptible commercial and industrial loads. Certain of these services include
transportation under flexible rate schedules whereby interruptible customers can
avail themselves of the advantages of open access transportation on regional
transmission pipelines, including the system of Williston Basin, Northern
Natural Gas Company, Viking Gas Transmission Company and Northwest Pipeline GP.
These services have enhanced Montana-Dakota's, Great Plains' and Cascade's
competitive posture with alternative fuels, although certain of Montana-Dakota's
and Cascade's customers have bypassed the respective distribution systems by
directly accessing transmission pipelines located within close proximity. These
bypasses did not have a material effect on results of operations.
The
natural gas distribution operations obtain their system requirements directly
from producers, processors and marketers. Such natural gas is supplied by a
portfolio of contracts specifying market-based pricing and is transported under
transportation agreements by Williston Basin, South Dakota Intrastate Pipeline
Company, Northern Border Pipeline Company, Viking Gas Transmission Company,
Northern Natural Gas Company, Source Gas, TransCanada Alberta System,
TransCanada Foothills System, Northwestern Energy, Northwest Pipeline GP, Gas
Transmission Northwest Corporation and Spectra Energy Gas Transmission to
provide firm service to their customers. Montana-Dakota also has contracted with
Williston Basin, Great Plains with Northern Natural Gas Company, and Cascade
with Northwest Pipeline GP, to provide firm storage services that enable all
three operations to meet winter peak requirements as well as allow them to
better manage their natural gas costs by purchasing natural gas at more uniform
daily volumes throughout the year. Demand for natural gas, which is a widely
traded commodity, has historically been sensitive to seasonal heating and
industrial load requirements as well as changes in market price. Montana-Dakota,
Great Plains and Cascade believe that, based on regional supplies of natural gas
and the pipeline transmission network currently available through their
suppliers and pipeline service providers, supplies are adequate to meet their
system natural gas requirements for the next five years.
Regulatory
Matters Montana-Dakota's, Great
Plains' and Cascade's retail natural gas rate schedules contain clauses
permitting adjustments in rates based upon changes in natural gas commodity,
transportation and storage costs. Current tariffs allow for recovery or refunds
of under or over recovered gas costs within a period ranging from 14 to 28
months.
Montana-Dakota's
North Dakota, South Dakota-Black Hills and South Dakota-East River area natural
gas tariffs contain a weather normalization mechanism applicable to firm
customers that adjusts the distribution delivery charge revenues to reflect
weather fluctuations during the billing period from November 1 through May
1.
Cascade
has received approval for decoupling its margins from weather and conservation
in Oregon, and has also received approval of a decoupling mechanism in
Washington which allows it to recover margin differences resulting from customer
conservation. Cascade also has an earnings sharing mechanism with respect to its
Oregon jurisdictional operations as required by the OPUC.
Environmental
Matters The natural gas
distribution operations are subject to federal, state and local environmental,
facility-siting, zoning and planning laws and regulations. Montana-Dakota, Great
Plains and Cascade believe they are in substantial compliance with those
regulations.
Natural
gas distribution operations are conditionally exempt small-quantity hazardous
waste generators and subject only to minimum regulation under the RCRA.
Montana-Dakota, Great Plains and Cascade routinely handle PCBs from their
natural gas operations in accordance with federal requirements. PCB storage
areas are registered with the EPA as required.
Montana-Dakota,
Great Plains, and Cascade did not incur any material environmental expenditures
in 2007 and, except as to what may be ultimately determined with regard to the
issues described below, do not expect to incur any material capital expenditures
related to environmental compliance with current laws and regulations in
relation to the natural gas distribution operations through 2010.
Montana-Dakota
completed remediation of a manufactured gas plant located in Bismarck, North
Dakota, in 2007. Expenses related to this work were approximately $1.0 million
and are expected to be recovered in rates through the regulatory process. In
addition, Montana-Dakota has had an economic interest in five other historic
manufactured gas plants within its service territory, none of which are
currently being actively investigated, and for which any remediation expenses
are not expected to be material. Cascade has had an economic interest in nine
former manufactured gas plants within its service territory. Cascade has been
involved with other potentially responsible parties in the investigation of a
manufactured gas plant site in Oregon, with remediation of this site pending
additional investigation. See Item 8 – Note 20 for a further discussion of this
site and an additional site for which Cascade has received claim notice. Cascade
believes the cost of claims for investigation and remediation of contamination
at these sites is covered by insurance. To the extent not covered by insurance,
Cascade will seek recovery of costs through its rates.
CONSTRUCTION
SERVICES
General MDU Construction
Services consists of diversified infrastructure construction companies
specializing in the construction and maintenance of electric and natural gas
distribution and transmission lines, and communication lines as well as inside
electrical wiring, cabling and mechanical work, fire protection, utility
excavation and the manufacture and distribution of specialty equipment. These
services are provided to utilities and large manufacturing, commercial,
industrial, institutional and government customers.
In 2007,
the Company acquired a construction service business in Nevada. This acquisition
was not material to the Company.
Construction
and maintenance crews are active year round. However, activity in certain
locations may be seasonal in nature due to the effects of weather.
MDU
Construction Services operates a fleet of owned and leased trucks and trailers,
support vehicles and specialty construction equipment, such as backhoes,
excavators, trenchers, generators, boring machines and cranes. In addition, as
of December 31, 2007, MDU Construction Services owned or leased facilities in 16
states. This space is used for offices, equipment yards, warehousing, storage
and vehicle shops. At December 31, 2007, MDU Construction Services' net plant
investment was approximately $48.2 million.
MDU
Construction Services' backlog is comprised of the uncompleted portion of
services to be performed under job-specific contracts. The backlog at December
31, 2007, was approximately $827 million compared to $527 million at December
31, 2006. MDU Construction Services expects to complete a significant amount of
this backlog during the year ending December 31, 2008. Due to the nature of its
contractual arrangements, in many instances MDU Construction Services' customers
are not committed to the specific volumes of services to be purchased under a
contract, but rather MDU Construction Services is committed to perform these
services if and to the extent requested by the customer. Therefore, there can be
no assurance as to the customer's requirements during a particular period or
that such estimates at any point in time are predictive of future
revenues.
This
industry is experiencing a shortage of skilled laborers in certain areas. MDU
Construction Services works with the National Electrical Contractors
Association, the IBEW and other trade associations on hiring and recruiting a
qualified workforce.
Competition MDU Construction
Services operates in a highly competitive business environment. Most of MDU
Construction Services' work is obtained on the basis of competitive bids or by
negotiation of either cost-plus or fixed-price contracts. The workforce and
equipment are highly mobile, providing greater flexibility in the size and
location of MDU Construction Services' market area. Competition is based
primarily on price and reputation for quality, safety and reliability. The size
and location of the services provided, as well as the state of the economy, will
be factors in the number of competitors that MDU Construction Services will
encounter on any particular project. MDU Construction Services believes that the
diversification of the services it provides, the markets it serves throughout
the United States and the management of its workforce will enable it to
effectively operate in this competitive environment.
Utilities
and independent contractors represent the largest customer base for this
segment. Accordingly, utility and subcontract work accounts for a significant
portion of the work performed by MDU Construction Services and the amount of
construction contracts is dependent to a certain extent on the level and timing
of maintenance and construction programs undertaken by customers. MDU
Construction Services relies on repeat customers and strives to maintain
successful long-term relationships with these customers.
Environmental
Matters MDU Construction
Services' operations are subject to regulation customary for the industry,
including federal, state and local environmental compliance. MDU Construction
Services believes it is in substantial compliance with these
regulations.
The
nature of MDU Construction Services' operations is such that few, if any,
environmental permits are required. Operational convenience supports the use of
petroleum storage tanks in several locations, which are permitted under state
programs authorized by the EPA. MDU Construction Services has no ongoing
remediation related to releases from petroleum storage tanks. MDU Construction
Services' operations are conditionally exempt small-quantity waste generators,
subject to minimal regulation under the RCRA. Federal permits for specific
construction and maintenance jobs that may require these permits are typically
obtained by the hiring entity, and not by MDU Construction
Services.
MDU
Construction Services did not incur any material environmental expenditures in
2007 and does not expect to incur any material capital expenditures related to
environmental compliance with current laws and regulations through
2010.
PIPELINE AND ENERGY
SERVICES
General Williston Basin, the
regulated business of WBI Holdings, owns and operates over 3,700 miles of
transmission, gathering and storage lines and owns or leases and operates
30 compressor stations in the states of Montana, North Dakota, South Dakota
and Wyoming. Three underground storage fields in Montana and Wyoming provide
storage services to local distribution companies, producers, natural gas
marketers and others, and serve to enhance system deliverability. Williston
Basin's system is strategically located near five natural gas producing basins,
making natural gas supplies available to Williston Basin's transportation and
storage customers. The system has 11 interconnecting points with other pipeline
facilities allowing for the receipt and/or delivery of natural gas to and from
other regions of the country and from Canada. At December 31, 2007,
Williston Basin's net plant investment was approximately $245.6 million.
Under the Natural Gas Act, as amended, Williston Basin is subject to the
jurisdiction of the FERC regarding certificate, rate, service and accounting
matters.
Bitter
Creek, the nonregulated pipeline business, owns and operates gathering
facilities in Colorado, Kansas, Montana and Wyoming. Bitter Creek also owns a
one-sixth interest in the assets of various offshore gathering pipelines, an
associated onshore pipeline and related processing facilities. In total, these
facilities include over 1,900 miles of field gathering lines and 85 owned or
leased compression facilities, some of which interconnect with Williston Basin's
system. In addition, Bitter Creek provides installation sales and/or leasing of
alternate energy delivery systems, primarily propane air facilities, energy
efficiency product sales and installation services to large end
users.
WBI
Holdings, through its energy services business, provides natural gas purchase
and sales services to local distribution companies, producers, other marketers
and a limited number of large end users, primarily using natural gas produced by
the Company's natural gas and oil production segment. Certain of the services
are provided based on contracts that call for a determinable quantity of natural
gas. WBI Holdings currently estimates that it can adequately meet the
requirements of these contracts. WBI Holdings transacts a substantial majority
of its pipeline and energy services business in the northern Great Plains and
Rocky Mountain regions of the United States.
System Demand and
Competition Williston Basin competes with several pipelines for
its customers' transportation, storage and gathering business and at times may
discount rates in an effort to retain market share. However, the strategic
location of Williston Basin's system near five natural gas producing basins and
the availability of underground storage and gathering services provided by
Williston Basin and affiliates along with interconnections with other pipelines
serve to enhance Williston Basin's competitive position.
Although
certain of Williston Basin's firm customers, including its largest firm customer
Montana-Dakota, serve relatively secure residential and commercial end users,
they generally all have some price-sensitive end users that could switch to
alternate fuels.
Williston
Basin transports substantially all of Montana-Dakota's natural gas, primarily
utilizing firm transportation agreements, which for the year ended December 31,
2007, represented 57 percent of Williston Basin's currently subscribed firm
transportation contract demand. Montana-Dakota has a firm transportation
agreement with Williston Basin for a term of five years expiring in June 2012.
In addition, Montana-Dakota has a contract with Williston Basin to provide firm
storage services to facilitate meeting Montana-Dakota's winter peak requirements
for a term of 20 years expiring in July 2015.
Bitter
Creek competes with several pipelines for existing customers and the expansion
of its systems to gather natural gas in new areas. Bitter Creek's strong
position in the fields in which it operates, its focus on customer service and
the variety of services it offers, along with its interconnection with various
other pipelines, serve to enhance its competitive position.
System Supply Williston Basin's
underground natural gas storage facilities have a certificated storage capacity
of approximately 353 Bcf, including 193 Bcf of working gas capacity, 85 Bcf of
cushion gas and 75 Bcf of native gas. The native gas includes an estimated
29 Bcf of recoverable gas. Williston Basin's storage facilities enable its
customers to purchase natural gas at more uniform daily volumes throughout the
year and, thus, facilitate meeting winter peak requirements. For information
regarding natural gas storage legal proceedings, see Item 1A – Risk Factors –
Other Risks and Item 8 – Note 20.
Natural
gas supplies emanate from traditional and nontraditional natural gas production
activities in the region and from off-system supply sources. While certain
traditional regional supply sources are in various stages of decline,
incremental supply from nontraditional sources have been developed which have
helped support Williston Basin's supply needs. This includes new natural gas
supply associated with the continued development of the Bakken play in Montana
and North Dakota. The Powder River Basin, including the Company's CBNG assets,
also provides a nontraditional natural gas supply to the Williston Basin system.
For additional information regarding CBNG legal proceedings, see Item 1A – Risk
Factors – Environmental and Regulatory Risks and Item 8 – Note 20. In addition,
off-system supply sources are available through the Company's interconnections
with other pipeline systems. Williston Basin expects to facilitate the movement
of these supplies by making available its transportation and storage services.
Williston Basin will continue to look for opportunities to increase
transportation, gathering and storage services through system expansion and/or
other pipeline interconnections or enhancements that could provide substantial
future benefits.
Regulatory Matters and Revenues
Subject to Refund In December 1999, Williston Basin filed a
general natural gas rate change application with the FERC. For additional
information, see Item 8 – Note 19.
Environmental Matters
WBI Holdings' pipeline and energy services operations are
generally subject to federal, state and local environmental, facility-siting,
zoning and planning laws and regulations. WBI Holdings believes it is in
substantial compliance with those regulations.
Ongoing
operations are subject to the Clean Air Act and the Clean Water Act.
Administration of many provisions of these laws has been delegated to the states
where Williston Basin and Bitter Creek operate, and permit terms vary. Some
permits require annual renewal, some have terms ranging from one to five years
and others have no expiration date. Permits are renewed as
necessary.
Detailed
environmental assessments are included in the FERC's permitting processes for
both the construction and abandonment of Williston Basin's natural gas
transmission pipelines and storage facilities.
WBI
Holdings' pipeline and energy services operations did not incur any material
environmental expenditures in 2007 and do not expect to incur any material
capital expenditures related to environmental compliance with current laws and
regulations through 2010.
NATURAL GAS AND OIL
PRODUCTION
General Fidelity is involved in
the acquisition, exploration, development and production of natural gas and oil
resources. Fidelity's activities include the acquisition of producing properties
and leaseholds with potential development opportunities, exploratory drilling
and the operation and development of natural gas and oil production properties.
Fidelity continues to seek additional reserve and production growth
opportunities through these activities. Future growth is dependent upon its
success in these endeavors. Fidelity shares revenues and expenses from the
development of specified properties in proportion to its ownership
interests.
Fidelity's
business is focused primarily in three core regions: Rocky Mountain,
Mid-Continent/Gulf States and Offshore Gulf of Mexico.
Rocky Mountain
Fidelity's
properties in this region are primarily located in the states of Colorado,
Montana, North Dakota, Utah and Wyoming. Fidelity owns in fee or holds natural
gas and oil leases for the properties it operates that are in the Bonny Field
located in eastern Colorado, the Baker Field in southeastern Montana and
southwestern North Dakota, the Bowdoin area located in north-central Montana,
the Powder River Basin of Montana and Wyoming, the Bakken formation in North
Dakota, the Paradox Basin of Utah, and the Big Horn Basin of Wyoming. Fidelity
also owns nonoperated natural gas and oil interests and undeveloped acreage
positions in this region.
Mid-Continent/Gulf
States
This
region includes properties in Alabama, Louisiana, New Mexico, Oklahoma and
Texas. Fidelity owns in fee or holds natural gas and oil leases for the
properties it operates that are in the Tabasco and Texan Gardens fields of
Texas. In addition, Fidelity owns several nonoperated interests and undeveloped
acreage positions in this region. On January 31, 2008, Fidelity completed the
acquisition of natural gas properties located in Rusk County in eastern Texas.
For additional information, see Item 8 – Note 21.
Offshore Gulf of
Mexico
Fidelity
has nonoperated interests throughout the Offshore Gulf of Mexico. These
interests are primarily located in the shallow waters off the coasts of Texas
and Louisiana.
Operating Information
Annual net production by region for 2007 was as
follows:
|
|
Natural
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Total
|
|
|
Percent
of
|
|
Region
|
|
(MMcf)
|
|
|
(MBbls)
|
|
|
(MMcfe)
|
|
|
Total
|
|
Rocky
Mountain
|
|
|
48,832
|
|
|
|
1,287
|
|
|
|
56,553
|
|
|
|
74 |
% |
Mid-Continent/Gulf
States
|
|
|
9,602
|
|
|
|
727
|
|
|
|
13,962
|
|
|
|
18
|
|
Offshore
Gulf of Mexico
|
|
|
4,364
|
|
|
|
351
|
|
|
|
6,473
|
|
|
|
8
|
|
Total
|
|
|
62,798
|
|
|
|
2,365
|
|
|
|
76,988
|
|
|
|
100 |
% |
Well and Acreage
Information Gross and net
productive well counts and gross and net developed and undeveloped acreage
related to Fidelity's interests at December 31, 2007, were as
follows:
|
|
Gross*
|
|
|
Net**
|
|
Productive
wells:
|
|
|
|
|
|
|
Natural
gas
|
|
|
3,978
|
|
|
|
3,180
|
|
Oil
|
|
|
3,797
|
|
|
|
233
|
|
Total
|
|
|
7,775
|
|
|
|
3,413
|
|
Developed
acreage (000's)
|
|
|
751
|
|
|
|
379
|
|
Undeveloped
acreage (000's)
|
|
|
1,039
|
|
|
|
481
|
|
* Reflects
well or acreage in which an interest is owned.
**
Reflects Fidelity's percentage of ownership.
Exploratory and Development Wells
The following table reflects activities relating to Fidelity's
natural gas and oil wells drilled and/or tested during 2007, 2006 and
2005:
|
|
Net
Exploratory
|
|
|
Net
Development
|
|
|
|
|
|
|
Productive
|
|
|
Dry
Holes
|
|
|
Total
|
|
|
Productive
|
|
|
Dry
Holes
|
|
|
Total
|
|
|
Total
|
|
2007
|
|
|
4
|
|
|
|
5
|
|
|
|
9
|
|
|
|
317
|
|
|
|
16
|
|
|
|
333
|
|
|
|
342
|
|
2006
|
|
|
4
|
|
|
|
1
|
|
|
|
5
|
|
|
|
331
|
|
|
|
1
|
|
|
|
332
|
|
|
|
337
|
|
2005
|
|
|
2
|
|
|
|
3
|
|
|
|
5
|
|
|
|
312
|
|
|
|
25
|
|
|
|
337
|
|
|
|
342
|
|
At
December 31, 2007, there were 170 gross (139 net) wells in the process of
drilling or under evaluation, 160 of which were development wells and 10 of
which were exploratory wells. These wells are not included in the previous
table. Fidelity expects to complete the drilling and testing of the majority of
these wells within the next 12 months.
The
information in the table above should not be considered indicative of future
performance nor should it be assumed that there is necessarily any correlation
between the number of productive wells drilled and quantities of reserves found
or economic value. Productive wells are those that produce commercial quantities
of hydrocarbons whether or not they produce a reasonable rate of
return.
Competition The
natural gas and oil industry is highly competitive. Fidelity competes with a
substantial number of major and independent natural gas and oil companies in
acquiring producing properties and new leases for future exploration and
development, and in securing the equipment, services and expertise necessary to
explore, develop and operate its properties.
Environmental
Matters Fidelity's natural gas
and oil production operations are generally subject to federal, state and local
environmental, facility-siting, zoning and planning laws and regulations.
Fidelity believes it is in substantial compliance with these
regulations.
The
ongoing operations of Fidelity are subject to the Clean Water Act, the Clean Air
Act, and other federal and state environmental regulations. Administration of
many provisions of the federal laws has been delegated to the states where
Fidelity operates, and permit terms vary. Some permits have terms ranging from
one to five years and others have no expiration date.
Detailed
environmental assessments and/or environmental impact statements under federal
and state laws are required as part of the permitting process incidental to the
commencement of drilling and production operations as well as in the closure,
abandonment and reclamation of facilities.
In
connection with production operations, Fidelity has incurred certain capital
expenditures related to water handling. For 2007, capital expenditures for water
handling in compliance with current laws and regulations were approximately $4.7
million and are estimated to be approximately $3.7 million, $5.7 million
and $4.5 million in 2008, 2009 and 2010, respectively. These water handling
costs are primarily related to the CBNG properties. For more information
regarding CBNG legal proceedings, see Item 1A – Risk Factors and Item 8 – Note
20.
Reserve
Information Estimates of reserves
are arrived at using actual historical wellhead production trends and/or
standard reservoir engineering methods utilizing available geological,
geophysical, engineering and economic data. Other factors used in the reserve
estimates are current natural gas and oil prices, current estimates of well
operating and future development costs, taxes, timing of operations, and the
interest owned by the Company in the well. The reserve estimates are prepared by
internal engineers and are reviewed by management. These estimates are refined
as new information becomes available.
Fidelity's
recoverable proved reserves by region at December 31, 2007, are as
follows:
Region
|
|
Natural
Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Total
(MMcfe)
|
|
|
Percent
of
Total
|
|
|
PV-10
Value
*
(in
millions)
|
|
Rocky
Mountain
|
|
|
392,174
|
|
|
|
22,118
|
|
|
|
524,883
|
|
|
|
74 |
% |
|
$ |
1,398.4
|
|
Mid-Continent/Gulf
States
|
|
|
119,500
|
|
|
|
7,616
|
|
|
|
165,197
|
|
|
|
23
|
|
|
|
527.0
|
|
Offshore
Gulf of Mexico
|
|
|
12,063
|
|
|
|
878
|
|
|
|
17,329
|
|
|
|
3
|
|
|
|
82.1
|
|
Total
reserves
|
|
|
523,737
|
|
|
|
30,612
|
|
|
|
707,409
|
|
|
|
100 |
% |
|
$ |
2,007.5
|
|
|
*
PV-10 value represents the discounted future net cash flows attributable
to proved reserves before income taxes, discounted at 10 percent. The
standardized measure of discounted future net cash flows in Item 8 –
Supplementary Financial Information represents the present value of future
cash flows attributable to proved reserves after income taxes, discounted
at 10 percent.
|
For
additional information related to natural gas and oil interests, see Item 8 –
Note 1 and Supplementary Financial Information.
CONSTRUCTION MATERIALS AND
CONTRACTING
General Knife River
operates construction materials and contracting businesses headquartered in
Alaska, California, Hawaii, Idaho, Iowa, Minnesota, Montana, North Dakota,
Oregon, Texas, Washington and Wyoming. These operations mine, process and sell
construction aggregates (crushed stone, sand and gravel); produce and sell
asphalt mix and supply liquid asphalt for various commercial and roadway
applications; and supply ready-mixed concrete for use in most types of
construction, including roads, freeways and bridges, as well as homes, schools,
shopping centers, office buildings and industrial parks. Although not common to
all locations, other products include the sale of cement, various finished
concrete products and other building materials and related construction
services.
During
2007, the Company acquired construction materials and contracting businesses
with operations in North Dakota, Texas and Wyoming. None of these acquisitions
was material to the Company.
Knife
River continues to investigate the acquisition of other construction materials
properties, particularly those relating to construction aggregates and related
products such as ready-mixed concrete, asphalt and related construction
services.
The
construction materials business had approximately $462 million in backlog at
December 31, 2007, compared to $483 million at December 31, 2006. The Company
anticipates that a significant amount of the current backlog will be completed
during the year ending December 31, 2008.
Competition Knife River's
construction materials products are marketed under highly competitive
conditions. Price is the principal competitive force to which these products are
subject, with service, quality, delivery time and proximity to the customer also
being significant factors. The number and size of competitors varies in each of
Knife River's principal market areas and product lines.
The
demand for construction materials products is significantly influenced by the
cyclical nature of the construction industry in general. In addition,
construction materials activity in certain locations may be seasonal in nature
due to the effects of weather. The key economic factors affecting product demand
are changes in the level of local, state and federal governmental spending,
general economic conditions within the market area that influence both the
commercial and private sectors, and prevailing interest rates.
Knife
River is not dependent on any single customer or group of customers for sales of
its products and services, the loss of which would have a materially adverse
effect on its construction materials businesses.
Reserve Information
Reserve estimates are calculated based on the best available data.
These data are collected from drill holes and other subsurface investigations,
as well as investigations of surface features such as mine highwalls and other
exposures of the aggregate reserves. Mine plans, production history and geologic
data also are utilized to estimate reserve quantities. Most acquisitions are
made of mature businesses with established reserves, as distinguished from
exploratory-type properties.
Estimates
are based on analyses of the data described above by experienced internal mining
engineers, operating personnel and geologists. Property setbacks and other
regulatory restrictions and limitations are identified to determine the total
area available for mining. Data described above are used to calculate the
thickness of aggregate materials to be recovered. Topography associated with
alluvial sand and gravel deposits is typically flat and volumes of these
materials are calculated by simply applying the thickness of the resource over
the areas available for mining. Volumes are then converted to tons by using an
appropriate conversion factor. Typically, 1.5 tons per cubic yard in the ground
is used for sand and gravel deposits.
Topography
associated with the hard rock reserves is typically much more diverse.
Therefore, using available data, a final topography map is created and computer
software is utilized to compute the volumes between the existing and final
topographies. Volumes are then converted to tons by using an appropriate
conversion factor. Typically, 2 tons per cubic yard in the ground is used for
hard rock quarries.
Estimated
reserves are probable reserves as defined in Securities Act Industry Guide 7.
Remaining reserves are based on estimates of volumes that can be economically
extracted and sold to meet current market and product applications. The reserve
estimates include only salable tonnage and thus exclude waste materials that are
generated in the crushing and processing phases of the operation. Approximately
1.1 billion tons of the 1.2 billion tons of aggregate reserves are permitted
reserves. The remaining reserves are on properties that are expected to be
permitted for mining under current regulatory requirements. The data used to
calculate the remaining reserves may require revisions in the future to account
for changes in customer requirements and unknown geological occurrences. The
years remaining were calculated by dividing remaining reserves by current-year
sales. Actual useful lives of these reserves will be subject to, among other
things, fluctuations in customer demand, customer specifications, geological
conditions and changes in mining plans.
The
following table sets forth details applicable to the Company's aggregate
reserves under ownership or lease as of December 31, 2007, and sales for the
years ended December 31, 2007, 2006 and 2005:
|
Number
of Sites
|
|
Number
of Sites
|
|
|
|
Estimated
|
|
|
Reserve
|
|
(Crushed
Stone)
|
|
(Sand
& Gravel)
|
|
Tons Sold
(000's)
|
|
Reserves
|
|
Lease
|
Life
|
Production
Area
|
owned
|
leased
|
|
owned
|
leased
|
|
2007
|
2006
|
2005
|
|
(000's
tons)
|
|
Expiration
|
(years)
|
Central
MN
|
---
|
1
|
|
49
|
52
|
|
2,639
|
4,834
|
4,608
|
|
90,833
|
|
2008-2028
|
34
|
Portland,
OR
|
1
|
4
|
|
5
|
3
|
|
5,372
|
5,862
|
5,559
|
|
255,034
|
|
2008-2055
|
47
|
Northern
CA
|
1
|
---
|
|
7
|
2
|
|
2,534
|
3,031
|
4,180
|
|
53,106
|
|
2046
|
21
|
Southwest
OR
|
4
|
7
|
|
12
|
5
|
|
3,686
|
4,425
|
3,892
|
|
110,332
|
|
2008-2031
|
30
|
Eugene,
OR
|
3
|
3
|
|
4
|
2
|
|
2,007
|
3,026
|
2,009
|
|
174,989
|
|
2008-2046
|
87
|
Hawaii
|
---
|
6
|
|
---
|
---
|
|
3,081
|
3,167
|
2,891
|
|
68,031
|
|
2011-2037
|
22
|
Central
MT
|
---
|
---
|
|
5
|
1
|
|
2,424
|
2,619
|
2,408
|
|
40,068
|
|
2023
|
17
|
Anchorage,
AK
|
---
|
---
|
|
1
|
---
|
|
1,118
|
1,142
|
1,307
|
|
19,712
|
|
N/A
|
18
|
Northwest
MT
|
---
|
---
|
|
8
|
5
|
|
1,318
|
1,434
|
1,679
|
|
24,161
|
|
2008-2020
|
18
|
Southern
CA
|
---
|
2
|
|
---
|
---
|
|
69
|
244
|
166
|
|
95,330
|
|
2035
|
Over
100
|
Bend, OR/WA/ Boise, ID
|
2
|
2
|
|
5
|
3
|
|
2,652
|
1,788
|
1,731
|
|
103,354
|
|
2010-2012
|
39
|
Northern
MN
|
2
|
---
|
|
19
|
17
|
|
753
|
520
|
968
|
|
30,802
|
|
2008-2016
|
41
|
Northern IA/ Southern MN
|
18
|
10
|
|
8
|
27
|
|
1,592
|
2,024
|
2,063
|
|
65,423
|
|
2008-2017
|
41
|
ND/SD
|
---
|
---
|
|
2
|
35
|
|
943
|
1,157
|
1,205
|
|
43,247
|
|
2008-2031
|
46
|
Eastern
TX
|
1
|
2
|
|
1
|
4
|
|
1,290
|
917
|
1,255
|
|
26,969
|
|
2008-2012
|
21
|
Casper, WY
|
---
|
---
|
|
---
|
2
|
|
116
|
5
|
2
|
|
13,862
|
|
2008
|
Over
100
|
Sales
from other sources
|
|
|
|
|
|
|
5,318
|
9,405
|
11,281
|
|
---
|
|
|
|
|
|
|
|
|
|
|
36,912
|
45,600
|
47,204
|
|
1,215,253
|
|
|
|
The 1.2
billion tons of estimated aggregate reserves at December 31, 2007, is
comprised of 509 million tons that are owned and 706 million tons that are
leased. Approximately 49 percent of the tons under lease have lease expiration
dates of 20 years or more. The weighted average years remaining on all
leases containing estimated probable aggregate reserves is approximately 19
years, including options for renewal that are at Knife River's discretion. Based
on 2007 sales from leased reserves, the average time necessary to produce
remaining aggregate reserves from such leases is approximately 47 years. Some sites have leases
that expire prior to the exhaustion of the estimated reserves. The estimated
reserve life assumes, based on Knife River's experience, that leases will be
renewed to allow sufficient time to fully recover these reserves.
The
following table summarizes Knife River's aggregate reserves at December 31,
2007, 2006 and 2005, and reconciles the changes between these
dates:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(000's
of tons)
|
|
Aggregate
reserves:
|
|
|
|
|
|
|
|
|
|
Beginning
of year
|
|
|
1,248,099
|
|
|
|
1,273,696
|
|
|
|
1,257,498
|
|
Acquisitions
|
|
|
29,740
|
|
|
|
7,300
|
|
|
|
53,495
|
|
Sales
volumes*
|
|
|
(31,594 |
) |
|
|
(36,195 |
) |
|
|
(35,923 |
) |
Other**
|
|
|
(30,992 |
) |
|
|
3,298
|
|
|
|
(1,374 |
) |
End
of year
|
|
|
1,215,253
|
|
|
|
1,248,099
|
|
|
|
1,273,696
|
|
* Excludes
sales from other sources.
**Includes
revisions of previous estimates.
|
|
|
|
|
|
|
|
|
|
|
|
|
Lignite Deposits The
Company has lignite deposits and leases at its former Gascoyne Mine site in
North Dakota. These lignite deposits are currently not being mined and are not
associated with an operating mine. The lignite deposits are of a high moisture
content and it is not economical to mine and ship the lignite to other distant
markets. However, should a power plant be constructed near the area, the Company
may have the opportunity to participate in supplying lignite to fuel a plant. As
of December 31, 2007, Knife River had under ownership or lease, deposits of
approximately 10.1 million tons of recoverable lignite coal.
Environmental
Matters Knife River's
construction materials and contracting operations are subject to regulation
customary for such operations, including federal, state and local environmental
compliance and reclamation regulations. Except as to what may be ultimately
determined with regard to the Portland, Oregon, Harbor Superfund Site issue
described later, Knife River believes it is in substantial compliance with these
regulations.
Knife
River's asphalt and ready-mixed concrete manufacturing plants and aggregate
processing plants are subject to Clean Air Act and Clean Water Act requirements
for controlling air emissions and water discharges. Some mining and construction
activities also are subject to these laws. In most of the states where Knife
River operates, these regulatory programs have been delegated to state and local
regulatory authorities. Knife River's facilities also are subject to RCRA as it
applies to the management of hazardous wastes and underground storage tank
systems. These programs also have generally been delegated to the state and
local authorities in the states where Knife River operates. No specific permits
are required but Knife River's facilities must comply with requirements for
managing wastes and underground storage tank systems.
Some
Knife River activities are directly regulated by federal agencies. For example,
gravel bar skimming and deep water dredging operations are subject to provisions
of the Clean Water Act that are administered by the Army Corps. Knife River
operates gravel bar skimming operations and deep water dredging operations in
Oregon, all of which are subject to joint permits with the Army Corps and Oregon
Department of State Lands. The expiration dates of these permits vary, with five
years generally being the longest term. None of these in-water mining operations
are included in Knife River's aggregate reserve numbers.
Knife
River's operations also are occasionally subject to the ESA. For example, land
use regulations often require environmental studies, including wildlife studies,
before a permit may be granted for a new or expanded mining facility or an
asphalt or concrete plant. If endangered species or their habitats are
identified, ESA requirements for protection, mitigation or avoidance apply.
Endangered species protection requirements are usually included as part of land
use permit conditions. Typical conditions include avoidance, setbacks,
restrictions on operations during certain times of the breeding or rearing
season, and construction or purchase of mitigation habitat. Knife River's
operations also are subject to state and federal cultural resources protection
laws when new areas are disturbed for mining operations or processing plants.
Land use permit applications generally require that areas proposed for mining or
other surface disturbances be surveyed for cultural resources. If any are
identified, they must be protected or managed in accordance with regulatory
agency requirements.
The most
comprehensive environmental permit requirements are usually associated with new
mining operations, although requirements vary widely from state to state and
even within states. In some areas, land use regulations and associated
permitting requirements are minimal. However, some states and local
jurisdictions have very demanding requirements for permitting new mines.
Environmental impact reports are sometimes required before a mining permit
application can even be considered for approval. These reports can take up to
several years to complete. The report can include projected impacts of the
proposed project on air and water quality, wildlife, noise levels, traffic,
scenic vistas and other environmental factors. The reports generally include
suggested actions to mitigate the projected adverse impacts.
Provisions
for public hearings and public comments are usually included in land use permit
application review procedures in the counties where Knife River operates. After
taking into account environmental, mine plan and reclamation information
provided by the permittee as well as comments from the public and other
regulatory agencies, the local authority approves or denies the permit
application. Denial is rare but land use permits often include conditions that
must be addressed by the permittee. Conditions may include property line
setbacks, reclamation requirements, environmental monitoring and reporting,
operating hour restrictions, financial guarantees for reclamation, and other
requirements intended to protect the environment or address concerns submitted
by the public or other regulatory agencies.
Knife
River has been successful in obtaining mining and other land use permit
approvals so that sufficient permitted reserves are available to support its
operations. For mining operations, this often requires considerable advanced
planning to ensure sufficient time is available to complete the permitting
process before the newly permitted aggregate reserve is needed to support Knife
River's operations.
Knife
River's Gascoyne surface coal mine last produced coal in 1995 but continues to
be subject to reclamation requirements of the SMCRA, as well as the North Dakota
Surface Mining Act. Portions of the Gascoyne Mine remain under reclamation bond
until the 10-year revegetation liability period has expired. A portion of the
original permit has been released from bond and additional areas are currently
in the process of having the bond released. Knife River's intention is to
request bond release as soon as it is deemed possible with all final bond
release applications being filed by 2013.
Knife
River did not incur any material environmental expenditures in 2007 and, except
as to what may be ultimately determined with regard to the issue described
below, Knife River does not expect to incur any material expenditures related to
environmental compliance with current laws and regulations through
2010.
In
December 2000, MBI was named by the EPA as a Potentially Responsible Party in
connection with the cleanup of a commercial property site, acquired by MBI in
1999, and part of the Portland, Oregon, Harbor Superfund Site. For additional
information, see Item 8 – Note 20.
ITEM 1A. RISK
FACTORS
The
Company's business and financial results are subject to a number of risks and
uncertainties, including those set forth below and in other documents that it
files with the SEC. The factors and the other matters discussed herein are
important factors that could cause actual results or outcomes for the Company to
differ materially from those discussed in the forward-looking statements
included elsewhere in this document.
Economic Risks
The Company's natural gas and oil
production and pipeline and energy services businesses are dependent on factors,
including commodity prices and commodity price basis differentials, which are
subject to various external influences that cannot be
controlled.
These
factors include: fluctuations in natural gas and crude oil prices; fluctuations
in commodity price basis differentials; availability of economic supplies of
natural gas; drilling successes in natural gas and oil operations; the timely
receipt of necessary permits and approvals; the ability to contract for or to
secure necessary drilling rig and service contracts and to retain employees to
drill for and develop reserves; the ability to acquire natural gas and oil
properties; and other risks incidental to the operations of natural gas and oil
wells. Significant changes in these factors could negatively affect the results
of operations, financial condition and cash flows of the Company's natural gas
and oil production and pipeline and energy services businesses.
The construction, startup and
operation of power generation facilities may involve unanticipated changes or
delays that could negatively impact the Company's business, its results of
operations and cash flows.
The
construction, startup and operation of power generation facilities involves many
risks, including: delays; breakdown or failure of equipment; competition;
inability to obtain required governmental permits and approvals; inability to
negotiate acceptable acquisition, construction, fuel supply, off-take,
transmission or other material agreements; changes in market price for power;
cost increases; as well as the risk of performance below expected levels of
output or efficiency. Such unanticipated events could negatively impact the
Company's business, its results of operations and cash flows.
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 and
cash flows.
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 contracting 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 and
cash flows.
The Company relies on financing
sources and capital markets. If the Company is unable to obtain economic
financing in the future, the Company's ability to execute its business plans,
make capital expenditures or pursue acquisitions that the Company may otherwise
rely on for future growth could be impaired.
The
Company relies on access to both short-term borrowings, including the issuance
of commercial paper, and long-term capital markets as sources of liquidity for
capital requirements not satisfied by its cash flow from operations. If the
Company is not able to access capital at competitive rates, the ability to
implement its business plans may be adversely affected. Market disruptions or a
downgrade of the Company's credit ratings may increase the cost of borrowing or
adversely affect its ability to access one or more financial markets. Such
disruptions could include:
·
|
A
severe prolonged economic downturn
|
·
|
The
bankruptcy of unrelated industry leaders in the same line of
business
|
·
|
A
deterioration in capital market
conditions
|
·
|
Volatility
in commodity prices
|
Actual quantities of recoverable
natural gas and oil reserves and discounted future net cash flows from those
reserves may vary significantly from estimated
amounts.
The
process of estimating natural gas and oil reserves is complex. Reserve estimates
are based on assumptions relating to natural gas and oil pricing, drilling and
operating expenses, capital expenditures, taxes, timing of operations, and the
percentage of interest owned by the Company in the well. The reserve estimates
are prepared for each of our properties by internal engineers assigned to an
asset team by geographic area. The internal engineers analyze available
geological, geophysical, engineering and economic data for each geographic area.
The internal engineers make various assumptions regarding this data. The extent,
quality and reliability of this data can vary. Although we have prepared our
reserve estimates in accordance with guidelines established by the industry and
the SEC, significant changes to the reserve estimates may occur based on actual
results of production, drilling, costs and pricing.
In
accordance with SEC requirements, we base the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
Actual future prices and costs may be significantly different.
Environmental and Regulatory
Risks
Some of the Company's operations are
subject to extensive environmental laws and regulations that may increase costs
of operations, impact or limit business plans, or expose the Company to
environmental liabilities.
The
Company is subject to extensive environmental laws and regulations affecting
many aspects of its present and future operations including air quality, water
quality, waste management and other environmental considerations. These laws and
regulations can result in increased capital, operating and other costs, and
delays as a result of ongoing litigation and administrative proceedings and
compliance, remediation, containment and monitoring obligations, particularly
with regard to laws relating to power plant emissions and CBNG development.
These laws and regulations generally require the Company to obtain and comply
with a wide variety of environmental licenses, permits, inspections and other
approvals. Public officials and entities, as well as private individuals and
organizations, may seek injunctive relief or other remedies to enforce
applicable environmental laws and regulations. The Company cannot predict the
outcome (financial or operational) of any related litigation or administrative
proceedings that may arise. Existing environmental regulations may be revised
and new regulations seeking to protect the environment may be adopted or become
applicable to the Company. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from customers, could have a material
adverse effect on the Company's results of operations and cash
flows.
One of the Company's subsidiaries is
subject to ongoing litigation and administrative proceedings in connection with
its CBNG development activities. These proceedings have caused delays in CBNG
drilling activity, and the ultimate outcome of the actions could have a material
negative effect on existing CBNG operations and/or the future development of its
CBNG properties.
Fidelity
has been named as a defendant in, and/or certain of its operations are or have
been the subject of, more than a dozen lawsuits filed in connection with its
CBNG development in the Powder River Basin in Montana and Wyoming. If the
plaintiffs are successful in these lawsuits, the ultimate outcome of the actions
could have a material negative effect on Fidelity's existing CBNG operations
and/or the future development of its CBNG properties.
The BER
in March 2006 issued a decision in a rulemaking proceeding, initiated by the
NPRC, that amends the non-degradation policy applicable to water discharged in
connection with CBNG operations. The amended policy includes additional
limitations on factors deemed harmful, thereby restricting water discharges even
further than under previous standards. Due in part to this amended policy, in
May 2006, the Northern Cheyenne Tribe commenced litigation in Montana state
court challenging two five-year water discharge permits that the Montana DEQ
granted to Fidelity in February 2006 and which are critical to Fidelity's
ability to manage water produced under present and future CBNG operations. If
these permits are set aside, Fidelity's CBNG operations in Montana could be
significantly and adversely affected.
The Company is subject to extensive
government regulations that may delay and/or have a negative impact on its
business and its results of operations and cash
flows.
The
Company is subject to regulation by federal, state and local regulatory agencies
with respect to, among other things, allowed rates of return, financings,
industry rate structures, and recovery of purchased power and purchased gas
costs. These governmental regulations significantly influence the Company's
operating environment and may affect its ability to recover costs from its
customers. The Company is unable to predict the impact on operating results from
the future regulatory activities of any of these agencies.
Changes
in regulations or the imposition of additional regulations could have an adverse
impact on the Company's results of operations and cash flows.
Risks Relating to Foreign
Operations
The value of the Company's
investments in foreign operations may diminish due to political, regulatory and
economic conditions and changes in currency exchange rates in countries where
the Company does business.
The
Company is subject to political, regulatory and economic conditions and changes
in currency exchange rates in foreign countries where the Company does business.
Significant changes in the political, regulatory or economic environment in
these countries could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to predict the
fluctuations in the foreign currency exchange rates, these fluctuations may have
an adverse impact on the Company's results of operations and cash
flows.
Other Risks
One of the Company's subsidiaries is
engaged in litigation with a nonaffiliated natural gas producer that has been
conducting drilling and production operations that the subsidiary believes is
causing diversion and loss of quantities of storage gas from one of its storage
reservoirs. If the subsidiary is not able to obtain relief through the courts or
the regulatory process, its storage operations could be materially and adversely
affected.
Williston
Basin has filed suit in Montana Federal District Court seeking to recover
unspecified damages from Anadarko and its wholly owned subsidiary, Howell, and
to enjoin Anadarko and Howell's present and future production operations in and
near the EBSR. Based on relevant information, including reservoir and well
pressure data, Williston Basin believes that EBSR pressures have decreased and
that the storage reservoir has lost gas and continues to lose gas as a result of
Anadarko and Howell's drilling and production activities. In related litigation,
Howell filed suit in Wyoming State District Court against Williston Basin
asserting that it is entitled to produce any gas that might escape from
Williston Basin's storage reservoir. Williston Basin has answered Howell's
complaint and has asserted counterclaims. If Williston Basin is unable to obtain
timely relief through the courts or regulatory process, its present and future
gas storage operations, including its ability to meet its contractual storage
and transportation obligations to customers, could be materially and adversely
affected.
Weather conditions can adversely
affect the Company's operations and revenues and cash
flows.
The
Company's results of operations can be affected by changes in the weather.
Weather conditions directly influence the demand for electricity and natural
gas, affect the price of energy commodities, affect the ability to perform
services at the construction services and construction materials and contracting
businesses and affect ongoing operation and maintenance and construction and
drilling activities for the pipeline and energy services and natural gas and oil
production businesses. In addition, severe weather can be destructive, causing
outages, reduced natural gas and oil production, and/or property damage, which
could require additional costs to be incurred. As a result, adverse weather
conditions could negatively affect the Company's results of operations,
financial condition and cash flows.
Competition is increasing in all of
the Company's businesses.
All of
the Company's businesses are subject to increased competition. Construction
services' competition is based primarily on price and reputation for quality,
safety and reliability. The construction materials products are marketed under
highly competitive conditions and are subject to such competitive forces as
price, service, delivery time and proximity to the customer. The electric
utility and natural gas industries also are experiencing increased competitive
pressures as a result of consumer demands, technological advances, increased
natural gas prices and other factors. Pipeline and energy services competes with
several pipelines for access to natural gas supplies and gathering,
transportation and storage business. The natural gas and oil production business
is subject to competition in the acquisition and development of natural gas and
oil properties. The increase in competition could negatively affect the
Company's results of operations, financial condition and cash
flows.
Other factors that could impact the
Company's businesses.
The
following are other factors that should be considered for a better understanding
of the financial condition of the Company. These other factors may impact the
Company's financial results in future periods.
|
·
|
Acquisition,
disposal and impairments of assets or
facilities
|
|
·
|
Changes
in operation, performance and construction of plant facilities or other
assets
|
|
·
|
Changes
in present or prospective
generation
|
|
·
|
The
availability of economic expansion or development
opportunities
|
|
·
|
Population
growth rates and demographic
patterns
|
|
·
|
Market
demand for, and/or available supplies of, energy- and construction-related
products and services
|
|
·
|
The
cyclical nature of large construction projects at certain
operations
|
|
·
|
Changes
in tax rates or policies
|
|
·
|
Unanticipated
project delays or changes in project costs, including related energy
costs
|
|
·
|
Unanticipated
changes in operating expenses or capital
expenditures
|
|
·
|
Labor
negotiations or disputes
|
|
·
|
Inability
of the various contract counterparties to meet their contractual
obligations
|
|
·
|
Changes
in accounting principles and/or the application of such principles to the
Company
|
|
·
|
Changes
in legal or regulatory proceedings
|
|
·
|
The
ability to effectively integrate the operations and the internal controls
of acquired companies
|
|
·
|
The
ability to attract and retain skilled labor and key
personnel
|
|
·
|
Increases
in employee and retiree benefit
costs
|
ITEM 1B. UNRESOLVED
COMMENTS
The
Company has no unresolved comments with the SEC.
ITEM
3.
|
LEGAL
PROCEEDINGS
|
|
For
information regarding legal proceedings of the Company, see Item 8 – Note
20.
|
ITEM
4.
|
SUBMISSION OF MATTERS
TO A VOTE OF SECURITY
HOLDERS
|
No
matters were submitted to a vote of security holders during the fourth quarter
of 2007.
PART
II
ITEM
5.
|
MARKET FOR THE
REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY
SECURITIES
|
The
Company's common stock is listed on the New York Stock Exchange under the symbol
"MDU." The price range of the Company's common stock as reported by The Wall
Street Journal composite tape during 2007 and 2006 and dividends declared
thereon were as follows:
|
|
|
Common
|
|
Common
|
Common
|
Stock
|
|
Stock
Price
|
Stock
Price
|
Dividends
|
|
(High)
|
(Low)
|
Per
Share
|
2007
|
|
|
|
First
quarter
|
$29.00
|
$24.39
|
$.1350
|
Second
quarter
|
31.79
|
27.40
|
.1350
|
Third
quarter
|
30.40
|
24.64
|
.1450
|
Fourth
quarter
|
28.69
|
25.89
|
.1450
|
|
|
|
$.5600
|
|
|
|
|
2006
|
|
|
|
First
quarter
|
$24.53
|
$21.85
|
$.1267
|
Second
quarter
|
24.99
|
22.53
|
.1267
|
Third
quarter
|
25.40
|
22.25
|
.1350
|
Fourth
quarter
|
27.04
|
22.29
|
.1350
|
|
|
|
$.5234
|
Note:
Common stock share amounts reflect the Company's three-for-two common stock
split effected in July 2006.
As of
December 31, 2007, the Company's common stock was held by approximately 15,400
stockholders of record.
ITEM 6. SELECTED FINANCIAL
DATA
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
Selected Financial
Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
193,367
|
|
|
$ |
187,301
|
|
|
$ |
181,238
|
|
|
$ |
178,803
|
|
|
$ |
178,562
|
|
|
$ |
162,616
|
|
Natural
gas
distribution
|
|
|
532,997
|
|
|
|
351,988
|
|
|
|
384,199
|
|
|
|
316,120
|
|
|
|
274,608
|
|
|
|
186,569
|
|
Construction
services
|
|
|
1,103,215
|
|
|
|
987,582
|
|
|
|
687,125
|
|
|
|
426,821
|
|
|
|
434,177
|
|
|
|
458,660
|
|
Pipeline
and energy
services
|
|
|
447,063
|
|
|
|
443,720
|
|
|
|
477,311
|
|
|
|
354,164
|
|
|
|
250,897
|
|
|
|
163,466
|
|
Natural
gas and oil
production
|
|
|
514,854
|
|
|
|
483,952
|
|
|
|
439,367
|
|
|
|
342,840
|
|
|
|
264,358
|
|
|
|
203,595
|
|
Construction
materials
and contracting
|
|
|
1,761,473
|
|
|
|
1,877,021
|
|
|
|
1,604,610
|
|
|
|
1,322,161
|
|
|
|
1,104,408
|
|
|
|
962,312
|
|
Other
|
|
|
10,061
|
|
|
|
8,117
|
|
|
|
6,038
|
|
|
|
4,423
|
|
|
|
2,728
|
|
|
|
3,778
|
|
Intersegment
eliminations
|
|
|
(315,134 |
) |
|
|
(335,142 |
) |
|
|
(375,965 |
) |
|
|
(272,199 |
) |
|
|
(191,105 |
) |
|
|
(114,249 |
) |
|
|
$ |
4,247,896
|
|
|
$ |
4,004,539
|
|
|
$ |
3,403,923
|
|
|
$ |
2,673,133
|
|
|
$ |
2,318,633
|
|
|
$ |
2,026,747
|
|
Operating
income (000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
31,652
|
|
|
$ |
27,716
|
|
|
$ |
29,038
|
|
|
$ |
26,776
|
|
|
$ |
35,761
|
|
|
$ |
33,915
|
|
Natural
gas
distribution
|
|
|
32,903
|
|
|
|
8,744
|
|
|
|
7,404
|
|
|
|
1,820
|
|
|
|
6,502
|
|
|
|
2,414
|
|
Construction
services
|
|
|
75,511
|
|
|
|
50,651
|
|
|
|
28,171
|
|
|
|
(5,757 |
) |
|
|
12,885
|
|
|
|
13,980
|
|
Pipeline
and energy
services
|
|
|
58,026
|
|
|
|
57,133
|
|
|
|
43,507
|
|
|
|
29,570
|
|
|
|
37,064
|
|
|
|
40,118
|
|
Natural
gas and oil
production
|
|
|
227,728
|
|
|
|
231,802
|
|
|
|
230,383
|
|
|
|
178,897
|
|
|
|
118,347
|
|
|
|
85,555
|
|
Construction
materials
and contracting
|
|
|
138,635
|
|
|
|
156,104
|
|
|
|
105,318
|
|
|
|
86,030
|
|
|
|
91,579
|
|
|
|
91,430
|
|
Other
|
|
|
(7,335 |
) |
|
|
(9,075 |
) |
|
|
(5,298 |
) |
|
|
(3,954 |
) |
|
|
(1,228 |
) |
|
|
(1,111 |
) |
|
|
$ |
557,120
|
|
|
$ |
523,075
|
|
|
$ |
438,523
|
|
|
$ |
313,382
|
|
|
$ |
300,910
|
|
|
$ |
266,301
|
|
Earnings
on common
stock (000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
17,700
|
|
|
$ |
14,401
|
|
|
$ |
13,940
|
|
|
$ |
12,790
|
|
|
$ |
16,950
|
|
|
$ |
15,780
|
|
Natural
gas
distribution
|
|
|
14,044
|
|
|
|
5,680
|
|
|
|
3,515
|
|
|
|
2,182
|
|
|
|
3,869
|
|
|
|
3,587
|
|
Construction
services
|
|
|
43,843
|
|
|
|
27,851
|
|
|
|
14,558
|
|
|
|
(5,650 |
) |
|
|
6,170
|
|
|
|
6,371
|
|
Pipeline
and energy
services
|
|
|
31,408
|
|
|
|
32,126
|
|
|
|
22,867
|
|
|
|
13,806
|
|
|
|
19,852
|
|
|
|
20,099
|
|
Natural
gas and oil
production
|
|
|
142,485
|
|
|
|
145,657
|
|
|
|
141,625
|
|
|
|
110,779
|
|
|
|
70,767
|
|
|
|
53,192
|
|
Construction
materials
and contracting
|
|
|
77,001
|
|
|
|
85,702
|
|
|
|
55,040
|
|
|
|
50,707
|
|
|
|
54,261
|
|
|
|
48,702
|
|
Other
|
|
|
(4,380 |
) |
|
|
(4,324 |
) |
|
|
13,061
|
|
|
|
15,967
|
|
|
|
597
|
|
|
|
497
|
|
Earnings
on common
stock before
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss) from
discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
and
cumulative
effect of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
accounting
change
|
|
|
322,101
|
|
|
|
307,093
|
|
|
|
264,606
|
|
|
|
200,581
|
|
|
|
172,466
|
|
|
|
148,228
|
|
Income
(loss) from
discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations,
net of tax
|
|
|
109,334
|
|
|
|
7,979
|
|
|
|
9,792
|
|
|
|
5,801
|
|
|
|
9,730
|
|
|
|
(540 |
) |
Cumulative
effect of
accounting change
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(7,589 |
) |
|
|
---
|
|
|
|
$ |
431,435
|
|
|
$ |
315,072
|
|
|
$ |
274,398
|
|
|
$ |
206,382
|
|
|
$ |
174,607
|
|
|
$ |
147,688
|
|
Earnings
per common
share before
discontinued operations
and cumulative effect of
accounting change -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
diluted
|
|
$ |
1.76
|
|
|
$ |
1.69
|
|
|
$ |
1.47
|
|
|
$ |
1.14
|
|
|
$ |
1.02
|
|
|
$ |
.92
|
|
Discontinued
operations,
net of tax
|
|
|
.60
|
|
|
|
.05
|
|
|
|
.06
|
|
|
|
.03
|
|
|
|
.06
|
|
|
|
---
|
|
Cumulative
effect of
accounting change
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(.04 |
) |
|
|
---
|
|
|
|
$ |
2.36
|
|
|
$ |
1.74
|
|
|
$ |
1.53
|
|
|
$ |
1.17
|
|
|
$ |
1.04
|
|
|
$ |
.92
|
|
Common
Stock
Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average
common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
outstanding
- diluted
(000's)
|
|
|
182,902
|
|
|
|
181,392
|
|
|
|
179,490
|
|
|
|
176,117
|
|
|
|
168,690
|
|
|
|
160,295
|
|
Dividends
per common
share
|
|
$ |
.5600
|
|
|
$ |
.5234
|
|
|
$ |
.4934
|
|
|
$ |
.4667
|
|
|
$ |
.4400
|
|
|
$ |
.4177
|
|
Book
value per common
share
|
|
$ |
13.80
|
|
|
$ |
11.88
|
|
|
$ |
10.43
|
|
|
$ |
9.39
|
|
|
$ |
8.44
|
|
|
$ |
7.71
|
|
Market
price per
common share
(year end)
|
|
$ |
27.61
|
|
|
$ |
25.64
|
|
|
$ |
21.83
|
|
|
$ |
17.79
|
|
|
$ |
15.87
|
|
|
$ |
11.47
|
|
Market
price ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend
payout
|
|
|
24 |
% |
|
|
30 |
% |
|
|
32 |
% |
|
|
40 |
% |
|
|
43 |
% |
|
|
45 |
% |
Yield
|
|
|
2.1 |
% |
|
|
2.1 |
% |
|
|
2.3 |
% |
|
|
2.7 |
% |
|
|
2.9 |
% |
|
|
3.7 |
% |
Price/earnings
ratio
|
|
|
11.7x
|
|
|
|
14.7x
|
|
|
|
14.3x
|
|
|
|
15.2x
|
|
|
|
15.4x
|
|
|
|
12.5x
|
|
Market
value as a
percent of book value
|
|
|
200.1 |
% |
|
|
215.8 |
% |
|
|
209.2 |
% |
|
|
189.4 |
% |
|
|
188.1 |
% |
|
|
148.8 |
% |
Profitability
Indicators
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
on average
common equity
|
|
|
18.5 |
% |
|
|
15.6 |
% |
|
|
15.7 |
% |
|
|
13.2 |
% |
|
|
13.0 |
% |
|
|
12.5 |
% |
Return
on average
invested capital
|
|
|
13.1 |
% |
|
|
10.6 |
% |
|
|
10.8 |
% |
|
|
9.4 |
% |
|
|
8.9 |
% |
|
|
8.6 |
% |
Fixed
charges coverage,
including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
preferred
dividends
|
|
|
6.4x
|
|
|
|
6.4x
|
|
|
|
6.6x
|
|
|
|
4.8x
|
|
|
|
4.6x
|
|
|
|
4.9x
|
|
General
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets (000's)
|
|
$ |
5,592,434
|
|
|
$ |
4,903,474
|
|
|
$ |
4,423,562
|
|
|
$ |
3,733,521
|
|
|
$ |
3,380,592
|
|
|
$ |
2,996,921
|
|
Total debt (000's)
|
|
$ |
1,310,163
|
|
|
$ |
1,254,582
|
|
|
$ |
1,206,510
|
|
|
$ |
945,487
|
|
|
$ |
967,096
|
|
|
$ |
861,741
|
|
Redeemable
preferred
stock (000's)
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
1,300
|
|
Capitalization
ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
equity
|
|
|
66 |
% |
|
|
63 |
% |
|
|
61 |
% |
|
|
63 |
% |
|
|
59 |
% |
|
|
59 |
% |
Preferred
stocks
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
Total
debt
|
|
|
34
|
|
|
|
37
|
|
|
|
39
|
|
|
|
36
|
|
|
|
40
|
|
|
|
40
|
|
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
NOTES:
·
|
Common stock share amounts
reflect the Company's three-for-two common stock splits effected in July
2006 and October 2003.
|
·
|
Cascade, a natural gas
distribution business, was acquired on July 2, 2007. For further
information, see Item 8 – Note
2.
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
Electric
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
sales (thousand
kWh)
|
|
|
2,601,649
|
|
|
|
2,483,248
|
|
|
|
2,413,704
|
|
|
|
2,303,460
|
|
|
|
2,359,888
|
|
|
|
2,275,024
|
|
Sales
for resale (thousand
kWh)
|
|
|
165,639
|
|
|
|
483,944
|
|
|
|
615,220
|
|
|
|
821,516
|
|
|
|
841,637
|
|
|
|
784,530
|
|
Electric system summer generating and firm purchase capability - kW
(Interconnected system)
|
|
|
571,160
|
|
|
|
547,485
|
|
|
|
546,085
|
|
|
|
544,220
|
|
|
|
542,680
|
|
|
|
500,570
|
|
Demand
peak – kW
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Interconnected
system)
|
|
|
525,643
|
|
|
|
485,456
|
|
|
|
470,470
|
|
|
|
470,470
|
|
|
|
470,470
|
|
|
|
458,800
|
|
Electricity
produced
(thousand kWh)
|
|
|
2,253,851
|
|
|
|
2,218,059
|
|
|
|
2,327,228
|
|
|
|
2,552,873
|
|
|
|
2,384,884
|
|
|
|
2,316,980
|
|
Electricity
purchased
(thousand kWh)
|
|
|
576,613
|
|
|
|
833,647
|
|
|
|
892,113
|
|
|
|
794,829
|
|
|
|
929,439
|
|
|
|
857,720
|
|
Average
cost of fuel and
purchased
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
power
per kWh
|
|
$ |
.025
|
|
|
$ |
.022
|
|
|
$ |
.020
|
|
|
$ |
.019
|
|
|
$ |
.019
|
|
|
$ |
.018
|
|
Natural Gas
Distribution*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
(Mdk)
|
|
|
52,977
|
|
|
|
34,553
|
|
|
|
36,231
|
|
|
|
36,607
|
|
|
|
38,572
|
|
|
|
39,558
|
|
Transportation
(Mdk)
|
|
|
54,698
|
|
|
|
14,058
|
|
|
|
14,565
|
|
|
|
13,856
|
|
|
|
13,903
|
|
|
|
13,721
|
|
Weighted
average degree
days – % of previous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
year's
actual
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
107 |
% |
|
|
95 |
% |
|
|
100 |
% |
|
|
94 |
% |
|
|
96 |
% |
|
|
109 |
% |
Cascade
|
|
|
101 |
% |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Pipeline and Energy
Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation
(Mdk)
|
|
|
140,762
|
|
|
|
130,889
|
|
|
|
104,909
|
|
|
|
114,206
|
|
|
|
90,239
|
|
|
|
99,890
|
|
Gathering
(Mdk)
|
|
|
92,414
|
|
|
|
87,135
|
|
|
|
82,111
|
|
|
|
80,527
|
|
|
|
75,861
|
|
|
|
72,692
|
|
Natural Gas and Oil
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
62,798
|
|
|
|
62,062
|
|
|
|
59,378
|
|
|
|
59,750
|
|
|
|
54,727
|
|
|
|
48,239
|
|
Oil
(MBbls)
|
|
|
2,365
|
|
|
|
2,041
|
|
|
|
1,707
|
|
|
|
1,747
|
|
|
|
1,856
|
|
|
|
1,968
|
|
Average
realized prices
(including
hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
5.96
|
|
|
$ |
6.03
|
|
|
$ |
6.11
|
|
|
$ |
4.69
|
|
|
$ |
3.90
|
|
|
$ |
2.72
|
|
Oil
(per barrel)
|
|
$ |
59.26
|
|
|
$ |
50.64
|
|
|
$ |
42.59
|
|
|
$ |
34.16
|
|
|
$ |
27.25
|
|
|
$ |
22.80
|
|
Proved
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
523,737
|
|
|
|
538,100
|
|
|
|
489,100
|
|
|
|
453,200
|
|
|
|
411,700
|
|
|
|
372,500
|
|
Oil
(MBbls)
|
|
|
30,612
|
|
|
|
27,100
|
|
|
|
21,200
|
|
|
|
17,100
|
|
|
|
18,900
|
|
|
|
17,500
|
|
Construction
Materials
and
Contracting
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
36,912
|
|
|
|
45,600
|
|
|
|
47,204
|
|
|
|
43,444
|
|
|
|
38,438
|
|
|
|
35,078
|
|
Asphalt
(tons)
|
|
|
7,062
|
|
|
|
8,273
|
|
|
|
9,142
|
|
|
|
8,643
|
|
|
|
7,275
|
|
|
|
7,272
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
4,085
|
|
|
|
4,588
|
|
|
|
4,448
|
|
|
|
4,292
|
|
|
|
3,484
|
|
|
|
2,902
|
|
Recoverable
aggregate
reserves (tons)
|
|
|
1,215,253
|
|
|
|
1,248,099
|
|
|
|
1,273,696
|
|
|
|
1,257,498
|
|
|
|
1,181,413
|
|
|
|
1,110,020
|
|
* Cascade was acquired on July
2, 2007. For further information, see Item 8 – Note
2.
|
|
ITEM 7. 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.
The key
strategies for each of the Company's business segments and certain related
business challenges are summarized below. For a discussion of the Company's
business segments, see Item 8 –
Note 16.
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, retention of
key personnel and managing through down turns in the economy 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 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
Contracting
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), and negotiation of contract price escalation
provisions. 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. The slowdown in
the residential housing sector has adversely impacted operations. A greater
emphasis on commercial, industrial, energy and public works projects and cost
containment should partially mitigate the effects.
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 Item 1A – Risk Factors.
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 Item 8 –
Notes to Consolidated Financial Statements.
Earnings Overview
The
following table summarizes the contribution to consolidated earnings by each of
the Company's businesses.
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in millions, where
applicable)
|
|
Electric
|
|
$ |
17.7
|
|
|
$ |
14.4
|
|
|
$ |
13.9
|
|
Natural
gas distribution
|
|
|
14.0
|
|
|
|
5.7
|
|
|
|
3.5
|
|
Construction
services
|
|
|
43.8
|
|
|
|
27.8
|
|
|
|
14.6
|
|
Pipeline
and energy services
|
|
|
31.4
|
|
|
|
32.1
|
|
|
|
22.9
|
|
Natural
gas and oil production
|
|
|
142.5
|
|
|
|
145.7
|
|
|
|
141.6
|
|
Construction
materials and contracting
|
|
|
77.0
|
|
|
|
85.7
|
|
|
|
55.1
|
|
Other
|
|
|
(4.3 |
) |
|
|
(4.3 |
) |
|
|
13.0
|
|
Earnings
before discontinued operations
|
|
|
322.1
|
|
|
|
307.1
|
|
|
|
264.6
|
|
Income from discontinued operations, net of tax
|
|
|
109.3
|
|
|
|
8.0
|
|
|
|
9.8
|
|
Earnings
on common stock
|
|
$ |
431.4
|
|
|
$ |
315.1
|
|
|
$ |
274.4
|
|
Earnings
per common share – basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$ |
1.77
|
|
|
$ |
1.70
|
|
|
$ |
1.48
|
|
Discontinued
operations, net of tax
|
|
|
.60
|
|
|
|
.05
|
|
|
|
.06
|
|
Earnings per
common share – basic
|
|
$ |
2.37
|
|
|
$ |
1.75
|
|
|
$ |
1.54
|
|
Earnings
per common share – diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$ |
1.76
|
|
|
$ |
1.69
|
|
|
$ |
1.47
|
|
Discontinued
operations, net of tax
|
|
|
.60
|
|
|
|
.05
|
|
|
|
.06
|
|
Earnings
per common share – diluted
|
|
$ |
2.36
|
|
|
$ |
1.74
|
|
|
$ |
1.53
|
|
Return
on average common equity
|
|
|
18.5 |
% |
|
|
15.6 |
% |
|
|
15.7 |
% |
2007 compared to 2006
Consolidated earnings for 2007 increased $116.3 million from the comparable
period largely due to:
·
|
Increased
income from discontinued operations, net of tax, largely related 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
|
·
|
Higher
margins, workloads and equipment sales and rentals at the construction
services business
|
·
|
Increased
earnings at the natural gas distribution business largely due to the
acquisition of Cascade
|
Partially
offsetting the increase were decreased earnings at the construction materials
and contracting business, primarily related to decreased volumes and margins
resulting from the slowdown in the residential housing sector.
Reflected
in the Other category is the negative effect from an income tax adjustment of
$9.4 million associated with the anticipated repatriation of profits from
Brazilian operations as discussed in Item 8 – Note 15, partially offset by the
gain of $6.1 million (after tax) related to the sale of Hartwell.
2006 compared to 2005
Consolidated earnings for 2006 increased $40.7 million from the comparable
period largely due to:
·
|
Higher
earnings from construction, aggregate and asphalt operations, and earnings
from companies acquired since the comparable prior period at the
construction materials and contracting
business
|
·
|
Higher
construction workloads and margins, as well as earnings from acquisitions
made since the comparable prior period at the construction services
business
|
·
|
Higher
transportation and gathering volumes, higher storage services revenue and
higher gathering rates at the pipeline and energy services
segment
|
·
|
Increased
oil and natural gas production of 20 percent and 5 percent, respectively,
and higher average realized oil prices of 19 percent, partially offset by
higher depreciation, depletion and amortization expense and higher lease
operating expense at the natural gas and oil production
business
|
Partially
offsetting the increase were decreased earnings from equity method investments,
which largely reflect the absence in 2006 of the 2005 $15.6 million benefit from
the sale of the Termoceara Generating Facility reflected in the Other
category.
FINANCIAL AND OPERATING
DATA
Below are
key financial and operating data for each of the Company's
businesses.
Electric
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in millions, where
applicable)
|
|
Operating
revenues
|
|
$ |
193.4
|
|
|
$ |
187.3
|
|
|
$ |
181.2
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
69.6
|
|
|
|
67.4
|
|
|
|
63.6
|
|
Operation
and maintenance
|
|
|
61.7
|
|
|
|
62.8
|
|
|
|
59.5
|
|
Depreciation,
depletion and amortization
|
|
|
22.5
|
|
|
|
21.4
|
|
|
|
20.8
|
|
Taxes,
other than income
|
|
|
7.9
|
|
|
|
8.0
|
|
|
|
8.3
|
|
|
|
|
161.7
|
|
|
|
159.6
|
|
|
|
152.2
|
|
Operating
income
|
|
|
31.7
|
|
|
|
27.7
|
|
|
|
29.0
|
|
Earnings
|
|
$ |
17.7
|
|
|
$ |
14.4
|
|
|
$ |
13.9
|
|
Retail
sales (million kWh)
|
|
|
2,601.7
|
|
|
|
2,483.2
|
|
|
|
2,413.7
|
|
Sales
for resale (million kWh)
|
|
|
165.6
|
|
|
|
484.0
|
|
|
|
615.2
|
|
Average
cost of fuel and purchased
|
|
|
|
|
|
|
|
|
|
|
|
|
power
per kWh
|
|
$ |
.025
|
|
|
$ |
.022
|
|
|
$ |
.020
|
|
2007 compared to
2006 Electric earnings
increased $3.3 million (23 percent) compared to the prior year due
to:
·
|
Higher
retail sales margins, primarily due to lower demand charges related to a
PPA that expired in the fourth quarter of 2006 and increased retail sales
volumes of 5 percent
|
·
|
Decreased
operation and maintenance expense of $700,000 (after tax), primarily lower
scheduled maintenance outage costs at electric generating
stations
|
Partially
offsetting the increase in earnings was lower sales for resale margins due to
decreased volumes of 66 percent, largely due to a PPA that expired in the fourth
quarter of 2006 and plant availability.
2006 compared to
2005 Electric earnings
increased $500,000 (3 percent) compared to the prior year due to:
·
|
Higher
retail sales margins, primarily due to increased volumes of 3 percent and
lower demand charges related to a PPA that expired in the fourth quarter
of 2006
|
·
|
Lower
income taxes of $700,000
|
·
|
Lower
interest expense of $600,000 (after tax), resulting from lower average
interest rates due to the purchase and redemption of certain higher cost
long-term debt
|
Partially
offsetting the increase in earnings were:
·
|
Decreased
sales for resale margins due to lower average rates of 15 percent and
decreased volumes of 21 percent, largely due to plant
availability
|
·
|
Higher
operation and maintenance expense of $1.7 million (after tax), primarily
the result of scheduled maintenance outages at electric generating
stations
|
Natural Gas
Distribution
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in millions, where
applicable)
|
|
Operating
revenues
|
|
$ |
533.0
|
|
|
$ |
352.0
|
|
|
$ |
384.2
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
372.2
|
|
|
|
259.5
|
|
|
|
315.4
|
|
Operation
and maintenance
|
|
|
88.5
|
|
|
|
68.4
|
|
|
|
46.0
|
|
Depreciation,
depletion and amortization
|
|
|
19.0
|
|
|
|
9.8
|
|
|
|
9.6
|
|
Taxes,
other than income
|
|
|
20.4
|
|
|
|
5.6
|
|
|
|
5.8
|
|
|
|
|
500.1
|
|
|
|
343.3
|
|
|
|
376.8
|
|
Operating
income
|
|
|
32.9
|
|
|
|
8.7
|
|
|
|
7.4
|
|
Earnings
|
|
$ |
14.0
|
|
|
$ |
5.7
|
|
|
$ |
3.5
|
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
53.0
|
|
|
|
34.5
|
|
|
|
36.2
|
|
Transportation
|
|
|
54.7
|
|
|
|
14.1
|
|
|
|
14.6
|
|
Total
throughput
|
|
|
107.7
|
|
|
|
48.6
|
|
|
|
50.8
|
|
Degree
days (% of normal)*
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
92.9 |
% |
|
|
86.7 |
% |
|
|
90.9 |
% |
Cascade
|
|
|
101.7 |
% |
|
|
---
|
|
|
|
---
|
|
Average
cost of natural gas,
|
|
|
|
|
|
|
|
|
|
|
|
|
including
transportation, per dk**
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
$ |
6.00
|
|
|
$ |
7.51
|
|
|
$ |
8.71
|
|
Cascade
|
|
$ |
7.75
|
|
|
$ |
---
|
|
|
$ |
---
|
|
*
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 Item 8
– Note 2.
|
|
2007 compared to 2006
The natural gas distribution business experienced an increase in earnings of
$8.3 million (147 percent) compared to the prior year due to:
·
|
Earnings
of $5.8 million, including a third quarter seasonal loss, at Cascade which
was acquired on July 2, 2007
|
·
|
Increased
nonregulated energy-related services of $1.3 million (after
tax)
|
·
|
Decreased
operation and maintenance expense, excluding Cascade, of $800,000 (after
tax), including the absence in 2007 of the 2006 early retirement program
costs
|
·
|
Increased
retail sales volumes resulting from 7 percent colder weather than last
year
|
2006 compared to 2005
The natural gas distribution business experienced an increase in earnings of
$2.2 million (62 percent) compared to the prior year due to:
·
|
Increased
nonregulated earnings of $1.7 million (after tax) from energy-related
services
|
·
|
Lower
income taxes of $900,000
|
Partially
offsetting this increase were higher payroll-related expenses of $900,000 (after
tax), largely due to an early retirement program.
The
pass-through of lower natural gas prices is reflected in the decrease in both
sales revenues and purchased natural gas sold. The decrease in sales revenues
was partially offset by revenues from nonregulated energy-related services.
Nonregulated energy-related services also contributed to the operation and
maintenance expense increase.
Construction
Services
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
millions)
|
|
Operating
revenues
|
|
$ |
1,103.2
|
|
|
$ |
987.6
|
|
|
$ |
687.1
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
979.7
|
|
|
|
892.7
|
|
|
|
625.1
|
|
Depreciation,
depletion and amortization
|
|
|
14.3
|
|
|
|
15.4
|
|
|
|
13.4
|
|
Taxes,
other than income
|
|
|
33.7
|
|
|
|
28.8
|
|
|
|
20.4
|
|
|
|
|
1,027.7
|
|
|
|
936.9
|
|
|
|
658.9
|
|
Operating
income
|
|
|
75.5
|
|
|
|
50.7
|
|
|
|
28.2
|
|
Earnings
|
|
$ |
43.8
|
|
|
$ |
27.8
|
|
|
$ |
14.6
|
|
2007 compared to 2006
Construction services earnings increased $16.0 million (57 percent) due
to:
·
|
Higher
construction margins and workloads of $13.1 million (after tax), largely
in the Southwest and Central regions, including industrial-related
work
|
·
|
Increased
equipment sales and rentals
|
2006 compared to 2005
Construction services earnings increased $13.2 million (91 percent) due
to:
·
|
Higher
construction workloads and margins of $7.3 million (after tax), largely in
the Southwest region
|
·
|
Earnings
from acquisitions made since the comparable prior period, which
contributed approximately 43 percent of the earnings
increase
|
·
|
Higher
equipment sales and rentals
|
Partially
offsetting this increase were higher general and administrative expenses of $1.7
million (after tax), primarily payroll related.
Pipeline and Energy
Services
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in
millions)
|
|
Operating
revenues
|
|
$ |
447.1
|
|
|
$ |
443.7
|
|
|
$ |
477.3
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
291.7
|
|
|
|
311.0
|
|
|
|
363.7
|
|
Operation
and maintenance
|
|
|
65.6
|
|
|
|
52.8
|
|
|
|
49.8
|
|
Depreciation,
depletion and amortization
|
|
|
21.7
|
|
|
|
13.3
|
|
|
|
12.5
|
|
Taxes,
other than income
|
|
|
10.1
|
|
|
|
9.5
|
|
|
|
7.8
|
|
|
|
|
389.1
|
|
|
|
386.6
|
|
|
|
433.8
|
|
Operating
income
|
|
|
58.0
|
|
|
|
57.1
|
|
|
|
43.5
|
|
Income
from continuing operations
|
|
|
31.4
|
|
|
|
32.1
|
|
|
|
22.9
|
|
Income (loss) from discontinued operations, net of tax
|
|
|
.1
|
|
|
|
(2.1 |
) |
|
|
(.8 |
) |
Earnings
|
|
$ |
31.5
|
|
|
$ |
30.0
|
|
|
$ |
22.1
|
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
29.3
|
|
|
|
31.0
|
|
|
|
31.4
|
|
Other
|
|
|
111.5
|
|
|
|
99.9
|
|
|
|
73.5
|
|
|
|
|
140.8
|
|
|
|
130.9
|
|
|
|
104.9
|
|
Gathering
volumes (MMdk)
|
|
|
92.4
|
|
|
|
87.1
|
|
|
|
82.1
|
|
2007 compared to 2006
Pipeline and energy services earnings increased $1.5 million (5 percent)
due largely to:
·
|
Higher
transportation and gathering volumes ($5.4 million after
tax)
|
·
|
Increased
income from discontinued operations of $2.2 million (after tax), related
to Innovatum. For further information, see Item 8 – Note
3.
|
·
|
Increased
storage services revenue ($2.2 million after
tax)
|
·
|
Higher
gathering rates ($1.4 million after
tax)
|
Partially
offsetting this increase in earnings were:
·
|
Absence
in 2007 of the benefit from the resolution of a rate proceeding of $4.1
million (after tax) recorded in 2006, which is reflected as a reduction to
depreciation, depletion and amortization
expense
|
·
|
Higher
operation and maintenance expense, largely due to the natural gas storage
litigation and higher material costs. For further information regarding
natural gas storage litigation, see Item 8 – Note
20.
|
The
decrease in energy services revenues and purchased natural gas sold reflects the
effect of lower natural gas prices.
2006 compared to 2005
Pipeline and energy services earnings increased $7.9 million (36 percent)
due largely to:
·
|
Higher
transportation and gathering volumes ($5.3 million after
tax)
|
·
|
Higher
storage services revenue ($5.8 million after
tax)
|
·
|
Higher
gathering rates ($3.2 million after
tax)
|
Partially
offsetting this increase in earnings were:
·
|
Absence
in 2006 of the benefit from the resolution of a rate proceeding of $5.0
million (after tax) recorded in 2005, which was largely offset by the
benefit from the resolution of a rate proceeding of $4.1 million (after
tax) recorded in 2006, both of which included a reduction to depreciation,
depletion and amortization expense.
|
·
|
Higher
operation and maintenance expense, primarily due to the natural gas
storage litigation. For further information, see Item 8 - Note
20.
|
·
|
An
increased loss from discontinued operations of $1.3 million (after tax),
related to Innovatum. For further information, see Item 8 – Note
3.
|
The
decrease in energy services revenues and purchased natural gas sold reflects the
effect of lower natural gas prices.
Natural Gas and Oil
Production
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in millions, where
applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$ |
374.1
|
|
|
$ |
373.9
|
|
|
$ |
362.5
|
|
Oil
|
|
|
140.1
|
|
|
|
103.4
|
|
|
|
72.7
|
|
Other
|
|
|
.6
|
|
|
|
6.7
|
|
|
|
4.2
|
|
|
|
|
514.8
|
|
|
|
484.0
|
|
|
|
439.4
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
.3
|
|
|
|
6.6
|
|
|
|
4.3
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
66.9
|
|
|
|
52.8
|
|
|
|
39.2
|
|
Gathering
and transportation
|
|
|
20.4
|
|
|
|
18.3
|
|
|
|
14.1
|
|
Other
|
|
|
34.6
|
|
|
|
31.9
|
|
|
|
31.2
|
|
Depreciation,
depletion and amortization
|
|
|
127.4
|
|
|
|
106.8
|
|
|
|
84.8
|
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
36.7
|
|
|
|
35.2
|
|
|
|
34.8
|
|
Other
|
|
|
.8
|
|
|
|
.6
|
|
|
|
.6
|
|
|
|
|
287.1
|
|
|
|
252.2
|
|
|
|
209.0
|
|
Operating
income
|
|
|
227.7
|
|
|
|
231.8
|
|
|
|
230.4
|
|
Earnings
|
|
$ |
142.5
|
|
|
$ |
145.7
|
|
|
$ |
141.6
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
62,798
|
|
|
|
62,062
|
|
|
|
59,378
|
|
Oil
(MBbls)
|
|
|
2,365
|
|
|
|
2,041
|
|
|
|
1,707
|
|
Average
realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
5.96
|
|
|
$ |
6.03
|
|
|
$ |
6.11
|
|
Oil
(per Bbl)
|
|
$ |
59.26
|
|
|
$ |
50.64
|
|
|
$ |
42.59
|
|
Average
realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$ |
5.37
|
|
|
$ |
5.62
|
|
|
$ |
6.87
|
|
Oil
(per Bbl)
|
|
$ |
59.53
|
|
|
$ |
51.73
|
|
|
$ |
48.73
|
|
Depreciation, depletion and amortization rate, per equivalent
Mcf
|
|
$ |
1.59
|
|
|
$ |
1.38
|
|
|
$ |
1.19
|
|
Production
costs, including taxes, per equivalent Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$ |
.87
|
|
|
$ |
.71
|
|
|
$ |
.56
|
|
Gathering
and transportation
|
|
|
.26
|
|
|
|
.25
|
|
|
|
.20
|
|
Production
and property taxes
|
|
|
.48
|
|
|
|
.47
|
|
|
|
.50
|
|
|
|
$ |
1.61
|
|
|
$ |
1.43
|
|
|
$ |
1.26
|
|
2007 compared to 2006
The natural gas and oil production business experienced a decrease in earnings
of $3.2 million (2 percent) due to:
·
|
Increased
depreciation, depletion and amortization expense of $12.8 million (after
tax) due to higher depletion rates and increased
production
|
·
|
Higher
lease operating costs of $8.8 million (after tax), largely CBNG-related
and costs related to acquired properties, as well as increased
service-related costs
|
·
|
Lower
average realized natural gas prices of 1
percent
|
·
|
Increased
general and administrative expense of $1.9 million (after
tax)
|
Partially
offsetting the decrease were:
·
|
Increased
oil production of 16 percent resulting from the May 2006 Big Horn
acquisition, as well as from the South Texas
properties
|
·
|
Higher
average realized oil prices of 17
percent
|
·
|
Increased
natural gas production of 1 percent
|
2006 compared to 2005
The natural gas and oil production business experienced an increase in earnings
of $4.1 million (3 percent) due to:
·
|
Increased
oil production of 20 percent and natural gas production of 5 percent,
largely due to the May 2005 South Texas and May 2006 Big Horn acquisitions
and increased production in the Rocky Mountain
region
|
·
|
Higher
average realized oil prices of 19
percent
|
Partially
offsetting the increase were:
·
|
Higher
depreciation, depletion and amortization expense of $13.5 million (after
tax) due to higher depletion rates and increased
production
|
·
|
Higher
lease operating expense of $8.4 million (after tax), largely acquisition
and CBNG-related costs
|
Construction Materials and
Contracting
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in
millions)
|
|
Operating
revenues
|
|
$ |
1,761.5
|
|
|
$ |
1,877.0
|
|
|
$ |
1,604.6
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
1,483.5
|
|
|
|
1,593.7
|
|
|
|
1,381.9
|
|
Depreciation,
depletion and amortization
|
|
|
95.8
|
|
|
|
88.7
|
|
|
|
78.0
|
|
Taxes,
other than income
|
|
|
43.6
|
|
|
|
38.5
|
|
|
|
39.4
|
|
|
|
|
1,622.9
|
|
|
|
1,720.9
|
|
|
|
1,499.3
|
|
Operating
income
|
|
|
138.6
|
|
|
|
156.1
|
|
|
|
105.3
|
|
Earnings
|
|
$ |
77.0
|
|
|
$ |
85.7
|
|
|
$ |
55.1
|
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
36,912
|
|
|
|
45,600
|
|
|
|
47,204
|
|
Asphalt
(tons)
|
|
|
7,062
|
|
|
|
8,273
|
|
|
|
9,142
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
4,085
|
|
|
|
4,588
|
|
|
|
4,448
|
|
|
2007 compared to
2006 Earnings at the construction materials and contracting
business decreased
|
|
$8.7
million (10 percent) due to:
|
·
|
Decreased
earnings of $14.2 million (after tax) from construction, primarily related
to the slowdown in the residential housing
sector
|
·
|
Lower
earnings from ready-mixed concrete and aggregate operations of $13.8
million (after tax), due to lower volumes and margins related to the
slowdown in the residential housing
sector
|
Partially
offsetting the decrease were:
·
|
Increased
earnings from asphalt and related products of $9.1 million (after tax),
due to higher margins
|
·
|
Decreased
general and administrative expense of $5.6 million (after tax), including
lower payroll-related costs
|
·
|
Earnings
from companies acquired since the comparable prior period, which
contributed approximately 3 percent of earnings for
2007
|
|
2006 compared to
2005 Earnings at the construction materials and contracting
business increased
|
|
$30.6
million (56 percent) due to:
|
·
|
Higher
earnings of $18.8 million (after tax) from construction, largely due to
increased volumes and margins, the result of strong markets and
improvements in Texas
|
·
|
Increased
earnings from aggregate and asphalt operations of $10.4 million (after
tax), largely due to higher realized margins, partially offset by lower
volumes
|
·
|
Earnings
from companies acquired since the comparable prior period, which
contributed approximately 18 percent of the earnings
increase
|
·
|
Higher
earnings of $4.2 million (after tax) from ready-mixed concrete operations,
largely due to higher margins
|
Partially
offsetting the increase were:
·
|
Higher
depreciation, depletion and amortization expense from existing operations
of $4.6 million (after tax), primarily due to higher property, plant and
equipment balances
|
·
|
Increased
general and administrative expense of $4.2 million (after tax), primarily
payroll-related
|
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:
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
10.0
|
|
|
$ |
8.1
|
|
|
$ |
6.0
|
|
Operation
and maintenance
|
|
|
15.9
|
|
|
|
15.4
|
|
|
|
10.7
|
|
Depreciation,
depletion and amortization
|
|
|
1.2
|
|
|
|
1.2
|
|
|
|
.3
|
|
Taxes,
other than income
|
|
|
.2
|
|
|
|
.6
|
|
|
|
.3
|
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
315.1
|
|
|
$ |
335.1
|
|
|
$ |
375.9
|
|
Purchased
natural gas sold
|
|
|
286.8
|
|
|
|
308.1
|
|
|
|
354.2
|
|
Operation
and maintenance
|
|
|
28.3
|
|
|
|
27.0
|
|
|
|
21.7
|
|
For
further information on intersegment eliminations, see Item 8 –
Note 16.
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 earnings, will in
fact be achieved. Please refer to assumptions contained in this section as well
as the various important factors listed in Item 1A – Risk Factors. Changes in
such assumptions and factors could cause actual future results to differ
materially from the Company's targeted growth and earnings
projections.
MDU Resources Group,
Inc.
·
|
Earnings
per common share for 2008, diluted, are projected in the range of $1.65 to
$1.90.
|
·
|
The
Company expects the percentage of 2008 earnings per common share, diluted,
by quarter to be in the following approximate
ranges:
|
o
|
First
quarter – 15 percent to 20 percent
|
o
|
Second
quarter – 20 percent to 25 percent
|
o
|
Third
quarter – 30 percent to 35 percent
|
o
|
Fourth
quarter – 25 percent to 30 percent
|
·
|
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. A final
decision on the Big Stone Station II project will be made when major
permits are issued and certain regulatory approvals are obtained, which is
expected by mid-to-late 2008. The plant is projected to be completed in
2013. The Company anticipates it would own at least 116 MW of this plant
or other generation sources. For further information, see Item 8 – Note
19.
|
·
|
On
July 12, 2007, Montana-Dakota filed an electric rate case with the MTPSC,
as discussed in Item 8 – Note 19.
|
·
|
This
business continues to pursue expansion of energy-related
services.
|
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 margins in 2008 to be slightly lower than
2007.
|
·
|
The
Company continues to focus on costs and efficiencies to enhance
margins.
|
Pipeline and energy
services
·
|
Based
on anticipated demand, incremental expansions to the Grasslands Pipeline
are forecasted over the next few years. Through additional compression,
the pipeline firm capacity could ultimately reach 200,000 Mcf per day, an
increase from the current firm capacity of 138,000 Mcf per
day.
|
·
|
In
2008, total gathering and transportation throughput is expected to be
slightly higher than 2007 record
levels.
|
Natural gas and oil
production
·
|
The
Company expects a combined natural gas and oil production increase in 2008
in the range of 12 percent to 16 percent over 2007 levels,
including the effects of the acquisition of natural gas production assets
in East Texas. Meeting these targets will depend on the timely receipt of
regulatory approvals and the success of exploration
activities.
|
·
|
The
Company expects to participate in more than 375 wells in 2008.
Specifically, in the Rocky Mountain Region, the Company expects to drill
approximately 240 operated wells (approximately 195 net wells) in the
Baker, Bowdoin, Powder River Basin and Big Horn Basin areas, and to
participate in 30 or more wells in the Bakken and Paradox Basin areas,
dependent upon success. Also included in the 375 wells are 25 wells to
further develop the properties associated with the acquisition of natural
gas production assets in East
Texas.
|
·
|
Currently,
this segment's net combined natural gas and oil production is
approximately 225,000 Mcf equivalents to 240,000 Mcf equivalents per day,
which includes the recently acquired East Texas
properties.
|
·
|
The
Company is pursuing exploratory drilling in the Bakken play in North
Dakota and the Paradox Basin in Utah. Its acreage position in the Bakken
play includes approximately 75,000 net acres in Mountrail and Burke
counties. The first of its operated wells in the Bakken play is scheduled
for completion in February. The Company’s first well in the Paradox Basin
began producing in mid-November. The Company owns approximately 57,000 net
acres in the Paradox Basin.
|
·
|
The
Company is pursuing continued reserve growth through the further
exploitation of its existing properties, exploratory drilling and
acquisitions of properties.
|
·
|
Earnings
guidance reflects estimated natural gas prices for February through
December 2008 as follows:
|
Index*
|
Price Per
Mcf
|
Ventura
|
$6.75
to $7.25
|
NYMEX
|
$7.25
to $7.75
|
CIG
|
$5.50
to $6.00
|
*
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
2007, more than three-fourths of 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 February through
December in the range of $75 to $80 per
barrel.
|
·
|
For
2008, the Company has hedged approximately 35 percent to 40 percent of its
estimated natural gas production and less than 5 percent of its estimated
oil production. Of its estimated natural gas production, the Company has
hedged approximately 15 percent to 20 percent for 2009, and less than 5
percent for 2010 and 2011. The hedges that are in place as of February 14,
2008, 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
|
1/08
- 3/08
|
910,000
|
$8.00-$8.75
|
Natural
Gas
|
Ventura
|
1/08
- 3/08
|
364,000
|
$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
|
4/08
- 10/08
|
749,000
|
$7.25-$8.02
|
Natural
Gas
|
CIG
|
4/08
- 10/08
|
749,000
|
$5.75-$7.40
|
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
|
HSC
|
3/08
- 12/08
|
2,080,800
|
$7.91
|
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
|
427,000
|
$9.25
|
Natural
Gas
|
Ventura
|
11/08
- 12/08
|
610,000
|
$8.85
|
Natural
Gas
|
CIG |
1/09 - 3/09
|
225,000
|
$8.45
|
Natural
Gas
|
HSC
|
1/09
- 12/09
|
2,482,000
|
$8.16
|
Natural
Gas
|
Ventura
|
1/09
- 12/09
|
1,460,000
|
$7.90-$8.54
|
Natural
Gas |
Ventura |
1/09
- 12/09
|
4,380,000 |
$8.25-$8.92
|
Natural
Gas
|
CIG
|
1/09
- 12/09
|
3,650,000
|
$6.50-$7.20
|
Natural
Gas |
CIG |
1/09
- 12/09
|
912,500 |
$7.27
|
Natural
Gas
|
HSC
|
1/10
- 12/10
|
1,606,000
|
$8.08
|
Natural
Gas
|
HSC
|
1/11
- 12/11
|
1,350,500
|
$8.00
|
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; HSC is the Houston
Ship Channel hub in southeast Texas which connects
to
several pipelines.
|
Construction materials and
contracting
·
|
The
slow down in the residential housing sector has adversely impacted
operations. A greater emphasis on commercial, industrial, energy and
public works projects and cost containment should partially mitigate the
effects.
|
NEW ACCOUNTING
STANDARDS
For
information regarding new accounting standards, see Item 8 – Note 1, which is
incorporated by reference.
CRITICAL ACCOUNTING POLICIES
INVOLVING SIGNIFICANT ESTIMATES
The
Company has prepared its financial statements in conformity with accounting
principles generally accepted in the United States of America. The preparation
of these financial statements requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities, at the date of the financial
statements as well as the reported amounts of revenues and expenses during the
reporting period. The Company's significant accounting policies are discussed in
Item 8 – Note 1.
Estimates
are used for items such as impairment testing of long-lived assets, goodwill and
natural gas and oil properties; fair values of acquired assets and liabilities
under the purchase method of accounting; natural gas and oil reserves; aggregate
reserves; property depreciable lives; tax provisions; uncollectible accounts;
environmental and other loss contingencies; accumulated provision for revenues
subject to refund; costs on construction contracts; unbilled revenues;
actuarially determined benefit costs; asset retirement obligations; the
valuation of stock-based compensation; and the fair value of derivative
instruments. The Company's critical accounting policies are subject to judgments
and uncertainties that affect the application of such policies. As discussed
below, the Company's financial position or results of operations may be
materially different when reported under different conditions or when using
different assumptions in the application of such policies.
As
additional information becomes available, or actual amounts are determinable,
the recorded estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates. The following critical
accounting policies involve significant judgments and estimates.
Impairment of long-lived assets and
intangibles
The
Company reviews the carrying values of its long-lived assets and intangibles,
excluding natural gas and oil properties, whenever events or changes in
circumstances indicate that such carrying values may not be recoverable and
annually for goodwill. Unforeseen events and changes in circumstances and market
conditions and material differences in the value of long-lived assets and
intangibles due to changes in estimates of future cash flows could negatively
affect the fair value of the Company's assets and result in an impairment
charge. If an impairment indicator exists for tangible and intangible assets,
excluding goodwill, the asset group held and used is tested for recoverability
by comparing an estimate of undiscounted future cash flows attributable to the
assets compared to the carrying value of the assets. If impairment has occurred,
the amount of the impairment recognized is determined by estimating the fair
value of the assets and recording a loss if the carrying value is greater than
the fair value. In the case of goodwill, the first step, used to identify a
potential impairment, compares the fair value of the reporting unit using
discounted cash flows, with its carrying amount, including goodwill. The second
step, used to measure the amount of the impairment loss if step one indicates a
potential impairment, compares the implied fair value of the reporting unit
goodwill with the carrying amount of goodwill.
Fair
value is the amount at which the asset could be bought or sold in a current
transaction between willing parties. The Company uses critical estimates and
assumptions when testing assets for impairment, including present value
techniques based on estimates of cash flows, quoted market prices or valuations
by third parties, or multiples of earnings or revenue performance measures. The
fair value of the asset could be different using different estimates and
assumptions in these valuation techniques.
There is
risk involved when determining the fair value of assets, tangible and
intangible, as there may be unforeseen events and changes in circumstances and
market conditions and changes in estimates of future cash flows.
The
Company believes its estimates used in calculating the fair value of long-lived
assets, including goodwill and identifiable intangibles, are reasonable based on
the information that is known when the estimates are made.
Natural gas and oil
properties
The
Company uses the full-cost method of accounting for its natural gas and oil
production activities. Capitalized costs are subject to a "ceiling test" that
limits such costs to the aggregate of the present value of future net revenues
of proved reserves based on single point-in-time spot market prices, as mandated
under the rules of the SEC, plus the cost of unproved properties. Judgments and
assumptions are made when estimating and valuing reserves. There is risk that
sustained downward movements in natural gas and oil prices, changes in estimates
of reserve quantities and changes in operating and development costs could
result in a future noncash write-down of the Company's natural gas and oil
properties.
Estimates
of reserves are arrived at using actual historical wellhead production trends
and/or standard reservoir engineering methods utilizing available engineering
and geologic data derived from well tests. Other factors used in the reserve
estimates are current natural gas and oil prices, current estimates of well
operating and future development costs, and the interest owned by the Company in
the well. These estimates are refined as new information becomes
available.
Historically,
the Company has not had any material revisions to its reserve estimates. As a
result, the Company has not changed its practice in estimating reserves and does
not anticipate changing its methodologies in the future.
Revenue
recognition
Revenue
is recognized when the earnings process is complete, as evidenced by an
agreement between the customer and the Company, when delivery has occurred or
services have been rendered, when the fee is fixed or determinable and when
collection is reasonably assured. The recognition of revenue in conformity with
accounting principles generally accepted in the United States of America
requires the Company to make estimates and assumptions that affect the reported
amounts of revenue. Critical estimates related to the recognition of revenue
include the accumulated provision for revenues subject to refund and costs on
construction contracts under the percentage-of-completion method.
Estimates
for revenues subject to refund are established initially for each regulatory
rate proceeding and are subject to change depending on the applicable regulatory
agency's (Agency) approval of final rates. These estimates are based on the
Company's analysis of its as-filed application compared to previous Agency
decisions in prior rate filings by the Company and other regulated companies.
The Company periodically reviews the status of its outstanding regulatory
proceedings and liability assumptions and may from time to time change its
liability estimates subject to known developments as the regulatory proceedings
move through the regulatory review process. The accuracy of the estimates is
ultimately determined when the Agency issues its final ruling on each regulatory
proceeding for which revenues were subject to refund. Estimates have changed
from time to time as additional information has become available as to what the
ultimate outcome may be and will likely continue to change in the future as new
information becomes available on each outstanding regulatory proceeding that is
subject to refund.
The
Company recognizes construction contract revenue from fixed-price and modified
fixed-price construction contracts at its construction businesses using the
percentage-of-completion method, measured by the percentage of costs incurred to
date to estimated total costs for each contract. This method depends largely on
the ability to make reasonably dependable estimates related to the extent of
progress toward completion of the contract, contract revenues and contract
costs. Inasmuch as contract prices are generally set before the work is
performed, the estimates pertaining to every project could contain significant
unknown risks such as volatile labor, material and fuel costs, weather delays,
adverse project site conditions, unforeseen actions by regulatory agencies,
performance by subcontractors, job management and relations with project
owners.
Several
factors are evaluated in determining the bid price for contract work. These
include, but are not limited to, the complexities of the job, past history
performing similar types of work, seasonal weather patterns, competition and
market conditions, job site conditions, work force safety, reputation of the
project owner, availability of labor, materials and fuel, project location and
project completion dates. As a project commences, estimates are continually
monitored and revised as information becomes available and actual costs and
conditions surrounding the job become known.
The
Company believes its estimates surrounding percentage-of-completion accounting
are reasonable based on the information that is known when the estimates are
made. The Company has contract administration, accounting and management control
systems in place that allow its estimates to be updated and monitored on a
regular basis. Because of the many factors that are evaluated in determining bid
prices, it is inherent that the Company's estimates have changed in the past and
will continually change in the future as new information becomes available for
each job.
Purchase
accounting
The
Company accounts for its acquisitions under the purchase method of accounting
and, accordingly, the acquired assets and liabilities assumed are recorded at
their respective fair values. The excess of the purchase price over the fair
value of the assets acquired and liabilities assumed is recorded as goodwill.
The recorded values of assets and liabilities are based on third-party estimates
and valuations when available. The remaining values are based on management's
judgments and estimates, and, accordingly, the Company's financial position or
results of operations may be affected by changes in estimates and
judgments.
Acquired
assets and liabilities assumed by the Company that are subject to critical
estimates include property, plant and equipment and intangibles.
The fair
value of owned recoverable aggregate reserve deposits is determined using
qualified internal personnel as well as geologists. Reserve estimates are
calculated based on the best available data. This data is collected from drill
holes and other subsurface investigations as well as investigations of surface
features such as mine highwalls and other exposures of the aggregate reserves.
Mine plans, production history and geologic data are also used to estimate
reserve quantities. Value is assigned to the aggregate reserves based on a
review of market royalty rates, expected cash flows and the number of years of
recoverable aggregate reserves at owned aggregate sites.
The fair
value of property, plant and equipment is based on a valuation performed either
by qualified internal personnel and/or outside appraisers. Fair values assigned
to plant and equipment are based on several factors including the age and
condition of the equipment, maintenance records of the equipment and auction
values for equipment with similar characteristics at the time of
purchase.
The fair
value of leasehold rights is based on estimates including royalty rates, lease
terms and other discernible factors for acquired leasehold rights, and estimated
cash flows.
While the
allocation of the purchase price of an acquisition is subject to a considerable
degree of judgment and uncertainty, the Company does not expect the estimates to
vary significantly once an acquisition has been completed. The Company believes
its estimates have been reasonable in the past as there have been no significant
valuation adjustments subsequent to the final allocation of the purchase price
to the acquired assets and liabilities. In addition, goodwill impairment testing
is performed annually in accordance with SFAS No. 142.
Asset retirement
obligations
Entities
are required to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. The Company has recorded
obligations related to the plugging and abandonment of natural gas and oil
wells, decommissioning of certain electric generating facilities, reclamation of
certain aggregate properties, special handling and disposal of hazardous
materials at certain electric generating facilities, natural gas distribution
and transmission facilities and buildings and certain other obligations
associated with leased properties.
The
liability for future asset retirement obligations bears the risk of change as
many factors go into the development of the estimate of these obligations and
the likelihood that over time these factors can and will change. Factors used in
the estimation of future asset retirement obligations include estimates of
current retirement costs, future inflation factors, life of the asset and
discount rates. These factors determine both a present value of the retirement
liability and the accretion to the retirement liability in subsequent
years.
Long-lived
assets are reviewed to determine if a legal retirement obligation exists. If a
legal retirement obligation exists, a determination of the liability is made if
a reasonable estimate of the present value of the obligation can be made. The
present value of the retirement obligation is calculated by inflating current
estimated retirement costs of the long-lived asset over its expected life to
determine the expected future cost and then discounting the expected future cost
back to the present value using a discount rate equal to the credit-adjusted
risk-free interest rate in effect when the liability was initially
recognized.
These
estimates and assumptions are subject to a number of variables and are expected
to change in the future. Estimates and assumptions will change as the estimated
useful lives of the assets change, the current estimated retirement costs
change, new legal retirement obligations occur and/or as existing legal asset
retirement obligations, for which a reasonable estimate of fair value could not
initially be made because of the range of time over which the Company may settle
the obligation is unknown or cannot be estimated, become less uncertain and a
reasonable estimate of the future liability can be made.
Pension and other postretirement
benefits
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. Various actuarial
assumptions are used in calculating the benefit expense (income) and liability
(asset) related to these plans. Costs of providing pension and other
postretirement benefits bear the risk of change, as they are dependent upon
numerous factors based on assumptions of future conditions.
The
Company makes various assumptions when determining plan costs, including the
current discount rates and the expected long-term return on plan assets, the
rate of compensation increases and healthcare cost trend rates. In selecting the
expected long-term return on plan assets, which is considered to be one of the
key variables in determining benefit expense or income, the Company considers
both current market conditions and expected future market trends, including
changes in interest rates and equity and bond market performance. Another key
variable in determining benefit expense or income is the discount rate. In
selecting the discount rate, the Company uses the yield of a fixed-income debt
security, which has a rating of "Aa" or higher published by a recognized rating
agency, as well as other factors, as a basis. The Company's pension and other
postretirement benefit plan assets are primarily made up of equity and
fixed-income investments. Fluctuations in actual equity and bond market returns
as well as changes in general interest rates may result in increased or
decreased pension and other postretirement benefit costs in the future.
Management estimates the rate of compensation increase based on long-term
assumed wage increases and the healthcare cost trend rates are determined by
historical and future trends.
The
Company believes the estimates made for its pension and other postretirement
benefits are reasonable based on the information that is known when the
estimates are made. These estimates and assumptions are subject to a number of
variables and are expected to change in the future. Estimates and assumptions
will be affected by changes in the discount rate, the expected long-term return
on plan assets, the rate of compensation increase and healthcare cost trend
rates. The Company plans to continue to use its current methodologies to
determine plan costs.
Income taxes
Income
taxes require significant judgments and estimates including the determination of
income tax expense, deferred tax assets and liabilities and, if necessary, any
valuation allowances that may be required for deferred tax assets and accruals
for uncertain tax positions. The effective income tax rate is subject to
variability from period to period as a result of changes in federal and state
income tax rates and/or changes in tax laws. In addition, the effective tax rate
may be affected by other changes including the allocation of property, payroll
and revenues between states.
The
Company provides deferred federal and state income taxes on all temporary
differences between the book and tax basis of the Company's assets and
liabilities. Excess deferred income tax balances associated with the Company's
rate-regulated activities resulting from the Company's adoption of SFAS
No. 109 have been recorded as a regulatory liability and are included in
other liabilities. These regulatory liabilities are expected to be reflected as
a reduction in future rates charged to customers in accordance with applicable
regulatory procedures.
The
Company uses the deferral method of accounting for investment tax credits and
amortizes the credits on electric and natural gas distribution plant over
various periods that conform to the ratemaking treatment prescribed by the
applicable state public service commissions.
On
January 1, 2007, the Company adopted FIN 48 as discussed in Item 8 – Notes 1 and
15. 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.
The
Company believes its estimates surrounding income taxes are reasonable based on
the information that is known when the estimates are made.
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 2007 decreased $96.4 million from the
comparable prior period, the result of:
·
|
Increased
cash flows used related to discontinued operations of $104.9 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
|
·
|
Increased
working capital requirements of $59.2 million, largely due to higher cash
needs for receivables at the natural gas distribution business, including
the effects of the acquisition of Cascade and fluctuations in natural gas
prices
|
Partially
offsetting the decrease in cash flows from operating activities
were:
·
|
Higher
depreciation, depletion and amortization expense of $45.4 million, largely
at the natural gas and oil production
business
|
·
|
Higher
deferred income taxes of $28.6 million, largely related to expenditures at
the natural gas and oil production business and the effect from an income
tax adjustment associated with the anticipated repatriation of profits
from Brazilian operations as discussed in Item 8 – Note
15.
|
Cash
flows provided by operating activities in 2006 increased $176.0 million
from the comparable 2005 period, the result of:
·
|
Lower
working capital requirements of $66.4 million, largely due to lower cash
needs for receivables at the natural gas distribution, natural gas and oil
production and construction services
businesses
|
·
|
Higher
depreciation, depletion and amortization expense of $37.1 million largely
at the natural gas and oil production and construction materials and
contracting businesses
|
·
|
Increased
income from continuing operations of $42.5 million, largely increased
earnings at the construction materials and contracting, construction
services and pipeline and energy services
businesses
|
·
|
Decreased
earnings, net of distributions, from equity method investments of $10.3
million,
|
primarily
the result of the sale of the Termoceara Generating Facility in
2005
Investing
activities Cash flows used in
investing activities in 2007 decreased $318.0 million compared to the comparable
prior period, the result of:
·
|
An
increase in cash flows provided by discontinued operations of $586.1
million, primarily the result of the sale of the domestic independent
power production assets in the third quarter of
2007
|
·
|
Increased
proceeds from the sale of equity method investments of $58.5 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 decrease in cash flows used in investing activities
were:
·
|
An
increase in cash flows used for acquisitions, net of cash acquired, of
$234.7 million, largely the result of the Cascade
acquisition
|
·
|
Higher
ongoing capital expenditures, including expenditures related to a wind
electric generation project at the electric
business
|
Cash
flows used in investing activities in 2006 increased $16.3 million compared to
the comparable 2005 period, the result of:
·
|
Increased
investments largely due to the acquisition of the Brazilian Transmission
Lines
|
·
|
The
absence in 2006 of the 2005 proceeds from the sale of the Termoceara
Generating Facility
|
·
|
Higher
ongoing capital expenditures, primarily at the natural gas and oil
production and construction materials and contracting
businesses
|
Partially
offsetting the increase was a decrease in cash flows used for:
·
|
Acquisitions
of $99.8 million, largely at the natural gas and oil production and
construction materials and contracting
businesses
|
·
|
Discontinued
operations, due to lower capital expenditures related to the Hardin
Generating Facility
|
Financing
activities Cash flows used in
financing activities in 2007 increased $158.4 million compared to the comparable
prior period, primarily the result of a decrease in the issuance of long-term
debt of $236.1 million, partially offset by lower repayments of long-term debt
of $83.0 million. Also reflected in 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.
Cash
flows provided by financing activities in 2006 decreased $198.8 million compared
to the comparable 2005 period, primarily the result of an increase in repayment
of long-term debt of $208.7 million, partially offset by an increase in proceeds
from the issuance of common stock of $10.8 million.
Defined benefit pension
plans
The
Company has qualified noncontributory defined benefit pension plans (Pension
Plans) for certain employees. 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 Pension Plans.
Actuarial assumptions include assumptions about the discount rate, expected
return on plan assets and rate of future compensation increases as determined by
the Company within certain guidelines. At December 31, 2007, certain Pension
Plans' accumulated benefit obligations exceeded these plans' assets by
approximately $600,000. Pretax pension expense reflected in the years ended
December 31, 2007, 2006 and 2005, was $6.5 million, $7.0 million and $6.6
million, respectively. The Company's pension expense is currently projected to
be approximately $8.0 million to $9.0 million in 2008. Funding for the Pension
Plans is actuarially determined. The minimum required contributions for 2007,
2006 and 2005 were approximately $1.8 million, $2.6 million and $1.6
million, respectively. For further information on the Company's Pension Plans,
see Item 8 – Note 17.
Capital
expenditures
The
Company's capital expenditures for 2005 through 2007 and as anticipated for 2008
through 2010 are summarized in the following table, which also includes the
Company's capital needs for the retirement of maturing long-term
debt.
|
Actual
|
|
Estimated*
|
|
2005
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
(In
millions) |
Capital
expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
$27
|
|
$39
|
|
$91
|
|
$95
|
|
$186
|
|
$146
|
Natural gas
distribution
|
17
|
|
15
|
|
500
|
|
65
|
|
52
|
|
44
|
Construction
services
|
51
|
|
32
|
|
18
|
|
19
|
|
12
|
|
13
|
Pipeline and
energy
services
|
36
|
|
43
|
|
39
|
|
53
|
|
38
|
|
18
|
Natural gas and
oil
production
|
330
|
|
329
|
|
284
|
|
605
|
|
392
|
|
385
|
Construction
materials
and contracting
|
162
|
|
141
|
|
190
|
|
110
|
|
105
|
|
105
|
Other
|
15
|
|
2
|
|
2
|
|
1
|
|
1
|
|
1
|
Net proceeds from sale
or
disposition of
property**
|
(41)
|
|
(31)
|
|
(25)
|
|
(7)
|
|
(2)
|
|
(2)
|
Net capital expenditures before discontinued operations
|
597
|
|
570
|
|
1,099
|
|
941
|
|
784
|
|
710
|
Discontinued
operations
|
133
|
|
33
|
|
(548)
|
|
---
|
|
---
|
|
---
|
Net
capital expenditures
|
730
|
|
603
|
|
551
|
|
941
|
|
784
|
|
710
|
Retirement
of
long-term debt
|
107
|
|
316
|
|
232
|
|
162
|
|
73
|
|
7
|
|
$837
|
|
$919
|
|
$783
|
|
$1,103
|
|
$857
|
|
$717
|
*
With the exception of
the acquisition of approximately $235 million of natural gas and oil
properties in the first quarter of 2008, the estimated 2008 through 2010
capital expenditures reflected in the above table exclude potential future
acquisitions and other growth opportunities which are dependent upon the
availability of economic opportunities and, as a result, capital
expenditures may vary significantly from the above
estimates.
** The
estimated 2008 through 2010 net proceeds exclude proceeds related to the
disposal of unidentified
assets.
|
Capital
expenditures for 2007, 2006 and 2005, in the preceding table include noncash
transactions, including the issuance of the Company's equity securities in
connection with acquisitions and the outstanding indebtedness related to the
2007 Cascade acquisition. The noncash transactions were $217.3 million in 2007,
immaterial in 2006 and $46.5 million in 2005.
In 2007,
the Company acquired construction materials and contracting businesses in North
Dakota, Texas and Wyoming, a construction services business in Nevada, and
Cascade, a natural gas distribution business. 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, was $526.3 million.
The 2007
capital expenditures, including those for the previously mentioned acquisitions
and retirements of long-term debt, were met from internal sources, the issuance
of long-term debt and the Company's equity securities. Estimated capital
expenditures for the years 2008 through 2010 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
|
·
|
Acquisition
of natural gas production assets in East Texas completed in late January
2008
|
·
|
Other
growth opportunities
|
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 estimates in the preceding table. It is anticipated that all of the funds
required for capital expenditures and retirement of long-term debt for the years
2008 through 2010 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 December 31, 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 December 31, 2007. The credit agreement supports the
Company's $100 million commercial paper program. Under the Company's
commercial paper program, $61.0 million was outstanding at December 31, 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 Item 8 – Note 10.
In
connection with the funding of the Cascade acquisition, on June 29, 2007, the
Company entered into a term loan agreement 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 remaining 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 Mortgage
and, in some cases, to certify to the trustee that annual earnings (pretax and
before interest charges), as defined in the Mortgage, equal at least two times
its annualized first mortgage bond interest costs. Under the more restrictive of
the tests, as of December 31, 2007, the Company could have issued approximately
$544 million of additional first mortgage bonds.
The
Company's coverage of fixed charges including preferred dividends was
6.4 times for the 12 months ended December 31, 2007 and 2006. Common
stockholders' equity as a percent of total capitalization was 66 percent and
63 percent at December 31, 2007 and 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 December 31, 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. The
aggregate principal amount of the Company's outstanding first mortgage bonds,
other than those held by the Indenture trustee, is $20.5 million and satisfies
the lien release requirements under the Indenture. As a result, the Company may
at any time, subject to satisfying certain specified conditions, 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 December 31,
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 December 31, 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. For
information on the covenants and certain other conditions of the MDU Energy
Capital master shelf agreement, see Item 8 – Note 10.
Cascade Natural Gas
Corporation Cascade has a revolving
credit agreement with various banks totaling $50 million with certain provisions
allowing for increased borrowings, up to a maximum of $75 million. The $50
million credit agreement expires on December 28, 2012, with provisions allowing
for an extension of up to two years upon consent of the banks. Cascade also has
a $20 million uncommitted line of credit which may be terminated by the bank or
Cascade at any time. There was $1.7 million outstanding under the Cascade credit
agreements at December 31, 2007. The borrowings are classified as short-term
borrowings as Cascade intends to repay the borrowings within one year. As of
December 31, 2007, there were outstanding letters of credit, as discussed in
Item 8 – Note 20, of which $1.9 million reduced amounts available under the $50
million credit agreement.
In order
to borrow under Cascade's $50 million credit agreement, Cascade must be in
compliance with the applicable covenants and certain other conditions. For
information on the covenants and certain other conditions of Cascade's $50
million credit agreement, see Item 8 – Note 9.
Cascade's
$50 million credit agreement contains cross-default provisions. These provisions
state that if Cascade 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 agreement will be in default.
Certain of Cascade's financing agreements and Cascade's practices limit the
amount of subsidiary indebtedness.
Centennial Energy Holdings,
Inc. Centennial has a revolving credit agreement and an
uncommitted line of credit 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 at
December 31, 2007. Under the Centennial commercial paper program there was no
amount outstanding at December 31, 2007. When Centennial has commercial paper
borrowings outstanding, the borrowings are classified as long-term debt as they
are intended to be refinanced on a long-term basis through continued Centennial
commercial paper borrowings (supported by Centennial credit agreements). The
revolving credit agreement 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 December 13, 2012. The uncommitted line of
credit for $25 million may be terminated by the bank at any time. As of
December 31, 2007, $56.6 million of letters of credit were outstanding, as
discussed in Item 8 – Note 20, of which $44.0 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, $418.5
million was outstanding at December 31, 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 information on the covenants and certain other conditions of
Centennial's credit agreement, see Item 8 – Note 10.
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 practices 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 up to
$100 million. Under the terms of the master shelf agreement, $80.0 million was
outstanding at December 31, 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 information on the covenants and certain other conditions of the
uncommitted long-term master shelf agreement, see Item 8 – Note 10.
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 Item 8 –
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 Item 8 – Note 20.
Contractual obligations and
commercial commitments
For more
information on the Company's contractual obligations on long-term debt,
operating leases, purchase commitments and uncertain tax positions, see Item 8 –
Notes 10, 15 and 20. At December 31, 2007, the Company's commitments under these
obligations were as follows:
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(In
millions)
|
|
Long-term
debt
|
|
$ |
161.7
|
|
|
$ |
73.4
|
|
|
$ |
7.3
|
|
|
$ |
128.0
|
|
|
$ |
135.5
|
|
|
$ |
802.6
|
|
|
$ |
1,308.5
|
|
Estimated
interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
payments*
|
|
|
70.8
|
|
|
|
63.5
|
|
|
|
61.7
|
|
|
|
56.4
|
|
|
|
51.3
|
|
|
|
335.5
|
|
|
|
639.2
|
|
Operating
leases
|
|
|
20.3
|
|
|
|
16.0
|
|
|
|
13.7
|
|
|
|
10.3
|
|
|
|
8.4
|
|
|
|
48.8
|
|
|
|
117.5
|
|
Purchase
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
commitments
|
|
|
479.2
|
|
|
|
340.0
|
|
|
|
233.4
|
|
|
|
163.7
|
|
|
|
105.6
|
|
|
|
323.1
|
|
|
|
1,645.0
|
|
|
|
$ |
732.0
|
|
|
$ |
492.9
|
|
|
$ |
316.1
|
|
|
$ |
358.4
|
|
|
$ |
300.8
|
|
|
$ |
1,510.0
|
|
|
$ |
3,710.2
|
|
* Estimated interest
payments are calculated based on the applicable rates and payment
dates.
|
|
Not
reflected in the table above are $3.7 million in uncertain tax
positions for which the year of settlement is not reasonably possible to
determine.
EFFECTS OF
INFLATION
Inflation
did not have a significant effect on the Company's operations in 2007, 2006 or
2005.
ITEM 7A. 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.
For more
information on derivatives and the Company's derivative policies and procedures,
see Item 8 – Notes 1 and 7.
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.
The
following table summarizes hedge agreements entered into by Fidelity and Cascade
as of December 31, 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.
(Forward
notional volume and fair value in thousands)
Fidelity
|
|
Weighted
Average
Fixed
Price
(Per
MMBtu)
|
|
|
Forward
Notional
Volume
(MMBtu)
|
|
|
Fair
Value
|
|
Natural
gas swap agreements maturing in 2008
|
|
$ |
7.90
|
|
|
|
10,978
|
|
|
$ |
8,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cascade
core
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2008
|
|
$ |
7.71
|
|
|
|
20,443
|
|
|
$ |
(11,542 |
) |
Natural
gas swap agreements maturing in 2009
|
|
$ |
7.79
|
|
|
|
13,410
|
|
|
$ |
(195 |
) |
Natural
gas swap agreements maturing in 2010
|
|
$ |
7.72
|
|
|
|
5,902
|
|
|
$ |
1,044
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cascade
non-core
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas swap agreements maturing in 2008
|
|
$ |
7.35
|
|
|
|
1,391
|
|
|
$ |
(1,014 |
) |
Fidelity
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
MMBtu/Bbl)
|
|
|
Forward
Notional
Volume
(MMBtu/Bbl)
|
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2008
|
|
$ |
7.25/$8.46
|
|
|
|
11,895
|
|
|
$ |
3,574
|
|
Oil collar
agreement maturing in 2008
|
|
$ |
67.50/$78.70
|
|
|
|
73
|
|
|
$ |
(1,112 |
) |
The
following table summarizes hedge agreements entered into by Fidelity as of
December 31, 2006. These agreements call for Fidelity to receive fixed
prices and pay variable prices.
(Forward
notional volume and fair value in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Forward
|
|
|
|
|
|
|
Average
|
|
|
Notional
|
|
|
|
|
|
|
Fixed
Price
|
|
|
Volume
|
|
|
|
|
Fidelity
|
|
(Per
MMBtu)
|
|
|
(MMBtu)
|
|
|
Fair
Value
|
|
Natural
gas swap agreements maturing in 2007
|
|
$ |
7.69
|
|
|
|
9,125
|
|
|
$ |
14,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Forward
|
|
|
|
|
|
|
|
Floor/Ceiling
|
|
|
Notional
|
|
|
|
|
|
|
|
Price
|
|
|
Volume
|
|
|
|
|
|
Fidelity
|
|
(Per
MMBtu)
|
|
|
(MMBtu)
|
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2007
|
|
$ |
7.87/$10.74
|
|
|
|
10,123
|
|
|
$ |
17,256
|
|
Interest rate
risk
The
Company uses fixed and variable rate long-term debt to partially finance capital
expenditures and mandatory debt retirements. These debt agreements expose the
Company to market risk related to changes in interest rates. The Company manages
this risk by taking advantage of market conditions when timing the placement of
long-term or permanent financing. The Company also has historically used
interest rate swap agreements to manage a portion of the Company's interest rate
risk and may take advantage of such agreements in the future to minimize such
risk. At December 31, 2007 and 2006, the Company had no outstanding interest
rate hedges.
The
following table shows the amount of debt, including current portion, and related
weighted average interest rates, both by expected maturity dates, as of December
31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
Value
|
|
|
|
(Dollars in
millions)
|
|
Long-term
debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
rate
|
|
$ |
161.7
|
|
|
$ |
73.4
|
|
|
$ |
7.3
|
|
|
$ |
67.0
|
|
|
$ |
135.5
|
|
|
$ |
802.6
|
|
|
$ |
1,247.5
|
|
|
$ |
1,233.3
|
|
Weighted
average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
interest
rate
|
|
|
4.5 |
% |
|
|
6.1 |
% |
|
|
6.8 |
% |
|
|
7.1 |
% |
|
|
5.9 |
% |
|
|
5.9 |
% |
|
|
5.8 |
% |
|
|
---
|
|
Variable
rate
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
$ |
61.0
|
|
|
|
---
|
|
|
|
---
|
|
|
$ |
61.0
|
|
|
$ |
60.6
|
|
Weighted
average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
interest
rate
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
4.9 |
% |
|
|
---
|
|
|
|
---
|
|
|
|
4.9 |
% |
|
|
---
|
|
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, see Item 8 –
Note 4. At December 31, 2007 and 2006, the Company had no outstanding foreign
currency hedges.
ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA
MANAGEMENT'S REPORT ON INTERNAL
CONTROL OVER FINANCIAL REPORTING
The
management of MDU Resources Group, Inc. is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) under the Securities Exchange Act of 1934. The Company's
internal control system is designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles.
All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
Management
assessed the effectiveness of the Company's internal control over financial
reporting as of December 31, 2007. In making this assessment, management used
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control–Integrated
Framework.
Based on
our evaluation under the framework in Internal Control–Integrated
Framework, management concluded that the Company's internal control over
financial reporting was effective as of December 31, 2007.
The
effectiveness of the Company's internal control over financial reporting as of
December 31, 2007, has been audited by Deloitte & Touche LLP, an independent
registered public accounting firm, as stated in their report.
/s/
Terry D. Hildestad
|
/s/
Vernon A. Raile
|
Terry
D. Hildestad
|
Vernon
A. Raile
|
President
and Chief Executive Officer
|
Executive
Vice President, Treasurer and
|
|
Chief
Financial Officer
|
|
|
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND
STOCKHOLDERS OF MDU RESOURCES GROUP, INC.:
We have
audited the accompanying consolidated balance sheets of MDU Resources Group,
Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the
related consolidated statements of income, common stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 2007. Our
audits also included the financial statement schedule for each of the three
years in the period ended December 31, 2007, listed in the Index at Item 15.
These consolidated financial statements and the financial statement schedule are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these consolidated financial statements and financial statement
schedule based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
consolidated financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the consolidated financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall consolidated financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of MDU Resources Group, Inc. and subsidiaries
as of December 31, 2007 and 2006, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2007, in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, the financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth
therein.
As
discussed in Note 17 to the consolidated financial statements, the Company
adopted SFAS No. 158 Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans effective as of December
31, 2006.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company's internal control over financial
reporting as of December 31, 2007, based on the criteria established in Internal Control–Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 12, 2008, expressed an
unqualified opinion on the Company's internal control over financial
reporting.
/s/ Deloitte & Touche
LLP
Minneapolis,
Minnesota
February
12, 2008
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND
STOCKHOLDERS OF MDU RESOURCES GROUP, INC.:
We have
audited the internal control over financial reporting of MDU Resources Group,
Inc. and subsidiaries (the "Company") as of December 31, 2007, based on criteria
established in Internal
Control–Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management's Report on Internal Control
Over Financial Reporting. Our responsibility is to express an opinion on the
Company's internal control over financial reporting based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2007, based on the criteria
established in Internal
Control–Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31, 2007 of
the Company and our report dated February 12, 2008 expressed an unqualified
opinion on those consolidated financial statements and financial statement
schedule and included an explanatory paragraph regarding the Company's adoption
of SFAS No. 158 Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans
effective as of December 31, 2006.
/s/ Deloitte & Touche
LLP
Minneapolis,
Minnesota
February
12, 2008
MDU RESOURCES GROUP,
INC.
CONSOLIDATED STATEMENTS OF
INCOME
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per
share amounts)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline
|
|
|
|
|
|
|
|
|
|
and
energy services
|
|
$ |
1,095,709
|
|
|
$ |
889,286
|
|
|
$ |
950,324
|
|
Construction
services, natural gas and oil production,
|
|
|
|
|
|
|
|
|
|
|
|
|
construction
materials and contracting, and other
|
|
|
3,152,187
|
|
|
|
3,115,253
|
|
|
|
2,453,599
|
|
|
|
|
4,247,896
|
|
|
|
4,004,539
|
|
|
|
3,403,923
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
69,616
|
|
|
|
67,414
|
|
|
|
63,591
|
|
Purchased
natural gas sold
|
|
|
377,404
|
|
|
|
268,981
|
|
|
|
329,190
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and
|
|
|
|
|
|
|
|
|
|
|
|
|
energy
services
|
|
|
215,587
|
|
|
|
183,992
|
|
|
|
155,323
|
|
Construction
services, natural gas and oil production,
|
|
|
|
|
|
|
|
|
|
|
|
|
construction
materials and contracting, and other
|
|
|
2,572,864
|
|
|
|
2,577,755
|
|
|
|
2,080,451
|
|
Depreciation,
depletion and amortization
|
|
|
301,932
|
|
|
|
256,531
|
|
|
|
219,440
|
|
Taxes,
other than income
|
|
|
153,373
|
|
|
|
126,791
|
|
|
|
117,405
|
|
|
|
|
3,690,776
|
|
|
|
3,481,464
|
|
|
|
2,965,400
|
|
Operating
income
|
|
|
557,120
|
|
|
|
523,075
|
|
|
|
438,523
|
|
Earnings from equity method
investments
|
|
|
19,609
|
|
|
|
10,838
|
|
|
|
20,192
|
|
Other
income
|
|
|
8,318
|
|
|
|
12,071
|
|
|
|
7,209
|
|
Interest
expense
|
|
|
72,237
|
|
|
|
72,095
|
|
|
|
54,384
|
|
Income before income
taxes
|
|
|
512,810
|
|
|
|
473,889
|
|
|
|
411,540
|
|
Income
taxes
|
|
|
190,024
|
|
|
|
166,111
|
|
|
|
146,249
|
|
Income from continuing
operations
|
|
|
322,786
|
|
|
|
307,778
|
|
|
|
265,291
|
|
Income from discontinued
operations, net of tax (Note 3)
|
|
|
109,334
|
|
|
|
7,979
|
|
|
|
9,792
|
|
Net
income
|
|
|
432,120
|
|
|
|
315,757
|
|
|
|
275,083
|
|
Dividends on preferred
stocks
|
|
|
685
|
|
|
|
685
|
|
|
|
685
|
|
Earnings on common
stock
|
|
$ |
431,435
|
|
|
$ |
315,072
|
|
|
$ |
274,398
|
|
Earnings per common share –
basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$ |
1.77
|
|
|
$ |
1.70
|
|
|
$ |
1.48
|
|
Discontinued
operations, net of tax
|
|
|
.60
|
|
|
|
.05
|
|
|
|
.06
|
|
Earnings
per common share –
basic
|
|
$ |
2.37
|
|
|
$ |
1.75
|
|
|
$ |
1.54
|
|
Earnings per common share –
diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$ |
1.76
|
|
|
$ |
1.69
|
|
|
$ |
1.47
|
|
Discontinued
operations, net of tax
|
|
|
.60
|
|
|
|
.05
|
|
|
|
.06
|
|
Earnings
per common share –
diluted
|
|
$ |
2.36
|
|
|
$ |
1.74
|
|
|
$ |
1.53
|
|
Dividends per common
share
|
|
$ |
.5600
|
|
|
$ |
.5234
|
|
|
$ |
.4934
|
|
Weighted average common shares
outstanding – basic
|
|
|
181,946
|
|
|
|
180,234
|
|
|
|
178,365
|
|
Weighted average common shares
outstanding – diluted
|
|
|
182,902
|
|
|
|
181,392
|
|
|
|
179,490
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP,
INC.
CONSOLIDATED BALANCE
SHEETS
December
31,
|
|
2007
|
|
|
2006
|
|
(In thousands, except shares
and per share amounts)
|
|
ASSETS
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
105,820
|
|
|
$ |
73,078
|
|
Receivables,
net
|
|
|
715,484
|
|
|
|
622,478
|
|
Inventories
|
|
|
229,255
|
|
|
|
204,440
|
|
Deferred
income taxes
|
|
|
7,046
|
|
|
|
---
|
|
Short-term
investments
|
|
|
91,550
|
|
|
|
23,250
|
|
Prepayments
and other current assets
|
|
|
64,998
|
|
|
|
57,833
|
|
Current
assets held for sale (Note 3)
|
|
|
179
|
|
|
|
12,656
|
|
|
|
|
1,214,332
|
|
|
|
993,735
|
|
Investments
|
|
|
118,602
|
|
|
|
155,111
|
|
Property, plant and equipment
(Note 1)
|
|
|
5,930,246
|
|
|
|
4,727,725
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
2,270,691
|
|
|
|
1,735,302
|
|
|
|
|
3,659,555
|
|
|
|
2,992,423
|
|
Deferred charges and other
assets:
|
|
|
|
|
|
|
|
|
Goodwill
(Note 5)
|
|
|
425,698
|
|
|
|
224,298
|
|
Other
intangible assets, net (Note 5)
|
|
|
27,792
|
|
|
|
22,802
|
|
Other
|
|
|
146,455
|
|
|
|
103,840
|
|
Noncurrent assets held for sale (Note 3)
|
|
|
---
|
|
|
|
411,265
|
|
|
|
|
599,945
|
|
|
|
762,205
|
|
|
|
$ |
5,592,434
|
|
|
$ |
4,903,474
|
|
LIABILITIES AND STOCKHOLDERS'
EQUITY
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Short-term
borrowings (Note 9)
|
|
$ |
1,700
|
|
|
$ |
---
|
|
Long-term
debt due within one year
|
|
|
161,682
|
|
|
|
84,034
|
|
Accounts
payable
|
|
|
369,235
|
|
|
|
289,836
|
|
Taxes
payable
|
|
|
60,407
|
|
|
|
54,290
|
|
Deferred
income taxes
|
|
|
---
|
|
|
|
5,969
|
|
Dividends
payable
|
|
|
26,619
|
|
|
|
24,606
|
|
Accrued
compensation
|
|
|
66,255
|
|
|
|
62,121
|
|
Other
accrued liabilities
|
|
|
163,990
|
|
|
|
118,206
|
|
Current
liabilities held for sale (Note 3)
|
|
|
---
|
|
|
|
14,900
|
|
|
|
|
849,888
|
|
|
|
653,962
|
|
Long-term debt (Note
10)
|
|
|
1,146,781
|
|
|
|
1,170,548
|
|
Deferred credits and other
liabilities:
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
668,016
|
|
|
|
546,602
|
|
Other
liabilities
|
|
|
396,430
|
|
|
|
336,916
|
|
Noncurrent liabilities held for sale (Note 3)
|
|
|
---
|
|
|
|
30,533
|
|
|
|
|
1,064,446
|
|
|
|
914,051
|
|
Commitments and contingencies
(Notes 17, 19 and 20)
|
|
|
|
|
|
|
|
|
Stockholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
stocks (Note 12)
|
|
|
15,000
|
|
|
|
15,000
|
|
Common
stockholders' equity:
|
|
|
|
|
|
|
|
|
Common
stock (Note 13)
|
|
|
|
|
|
|
|
|
Authorized – 500,000,000 shares, $1.00 par value in 2007, 250,000,000
shares, $1.00 par value in 2006
|
|
|
|
|
|
|
|
|
Issued – 182,946,528 shares in 2007 and 181,557,543 shares in
2006
|
|
|
182,947
|
|
|
|
181,558
|
|
Other
paid-in capital
|
|
|
912,806
|
|
|
|
874,253
|
|
Retained
earnings
|
|
|
1,433,585
|
|
|
|
1,104,210
|
|
Accumulated
other comprehensive loss
|
|
|
(9,393 |
) |
|
|
(6,482 |
) |
Treasury
stock at cost – 538,921 shares
|
|
|
(3,626 |
) |
|
|
(3,626 |
) |
Total
common stockholders' equity
|
|
|
2,516,319
|
|
|
|
2,149,913
|
|
Total
stockholders' equity
|
|
|
2,531,319
|
|
|
|
2,164,913
|
|
|
|
$ |
5,592,434
|
|
|
$ |
4,903,474
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP,
INC.
CONSOLIDATED STATEMENTS OF COMMON
STOCKHOLDERS' EQUITY
Years
ended December 31, 2007, 2006 and 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury
Stock
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Earnings
|
|
|
Loss
|
|
|
Shares
|
|
|
Amount
|
|
|
Total
|
|
|
|
(In thousands, except
shares)
|
|
Balance at December 31,
2004
|
|
|
118,586,065
|
|
|
$ |
118,586
|
|
|
$ |
863,449
|
|
|
$ |
699,095
|
|
|
$ |
(11,491 |
) |
|
|
(359,281 |
) |
|
$ |
(3,626 |
) |
|
$ |
1,666,013
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
275,083
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
275,083
|
|
Other
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized loss on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(21,800 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(21,800 |
) |
Pension
liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
574
|
|
|
|
---
|
|
|
|
---
|
|
|
|
574
|
|
Foreign
currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
translation
adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(1,099 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(1,099 |
) |
Total
comprehensive income
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
252,758
|
|
Dividends
on preferred
stocks
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(685 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(685 |
) |
Dividends
on common stock
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(88,698 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(88,698 |
) |
Tax benefit on stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
|
---
|
|
|
|
---
|
|
|
|
5,487
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
5,487
|
|
Issuance
of common stock
|
|
|
1,676,721
|
|
|
|
1,677
|
|
|
|
40,070
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
41,747
|
|
Balance at December 31,
2005
|
|
|
120,262,786
|
|
|
|
120,263
|
|
|
|
909,006
|
|
|
|
884,795
|
|
|
|
(33,816 |
) |
|
|
(359,281 |
) |
|
|
(3,626 |
) |
|
|
1,876,622
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
315,757
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
315,757
|
|
Other
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
45,610
|
|
|
|
---
|
|
|
|
---
|
|
|
|
45,610
|
|
Pension
liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
1,761
|
|
|
|
---
|
|
|
|
---
|
|
|
|
1,761
|
|
Foreign
currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
translation
adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(1,585 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(1,585 |
) |
Total
comprehensive income
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
361,543
|
|
SFAS No. 158 transition adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(18,452 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(18,452 |
) |
Dividends
on preferred
stocks
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(685 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(685 |
) |
Dividends
on common stock
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(95,657 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(95,657 |
) |
Tax benefit on stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
|
---
|
|
|
|
---
|
|
|
|
2,524
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
2,524
|
|
Issuance of common stock (pre-split)
|
|
|
120,702
|
|
|
|
121
|
|
|
|
3,242
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
3,363
|
|
Three-for-two common stock split (Note 13)
|
|
|
60,191,744
|
|
|
|
60,192
|
|
|
|
(60,192 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(179,640 |
) |
|
|
---
|
|
|
|
---
|
|
Issuance of common stock (post-split)
|
|
|
982,311
|
|
|
|
982
|
|
|
|
19,673
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
20,655
|
|
Balance at December 31,
2006
|
|
|
181,557,543
|
|
|
|
181,558
|
|
|
|
874,253
|
|
|
|
1,104,210
|
|
|
|
(6,482 |
) |
|
|
(538,921 |
) |
|
|
(3,626 |
) |
|
|
2,149,913
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
432,120
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
432,120
|
|
Other
comprehensive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
income
(loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized loss on
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(13,505 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(13,505 |
) |
Pension
liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
3,012
|
|
|
|
---
|
|
|
|
---
|
|
|
|
3,012
|
|
Foreign
currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
translation
adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
7,177
|
|
|
|
---
|
|
|
|
---
|
|
|
|
7,177
|
|
Net
unrealized gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
on
available-for-sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
investments
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
405
|
|
|
|
---
|
|
|
|
---
|
|
|
|
405
|
|
Total
comprehensive income
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
429,209
|
|
FIN
48 transition adjustment
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
31
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
31
|
|
Dividends
on preferred
stocks
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(685 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(685 |
) |
Dividends
on common stock
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(102,091 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
(102,091 |
) |
Tax benefit on stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
|
---
|
|
|
|
---
|
|
|
|
5,398
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
5,398
|
|
Issuance of common stock
|
|
|
1,388,985
|
|
|
|
1,389
|
|
|
|
33,155
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
34,544
|
|
Balance at December 31,
2007
|
|
|
182,946,528
|
|
|
$ |
182,947
|
|
|
$ |
912,806
|
|
|
$ |
1,433,585
|
|
|
$ |
(9,393 |
) |
|
|
(538,921 |
) |
|
$ |
(3,626 |
) |
|
$ |
2,516,319
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP,
INC.
CONSOLIDATED STATEMENTS OF CASH
FLOWS
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
432,120
|
|
|
$ |
315,757
|
|
|
$ |
275,083
|
|
Income
from discontinued operations, net of tax
|
|
|
109,334
|
|
|
|
7,979
|
|
|
|
9,792
|
|
Income
from continuing operations
|
|
|
322,786
|
|
|
|
307,778
|
|
|
|
265,291
|
|
Adjustments
to reconcile net income
|
|
|
|
|
|
|
|
|
|
|
|
|
to
net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
301,932
|
|
|
|
256,531
|
|
|
|
219,440
|
|
Earnings,
net of distributions, from equity
|
|
|
|
|
|
|
|
|
|
|
|
|
method
investments
|
|
|
(14,031 |
) |
|
|
(4,093 |
) |
|
|
(14,385 |
) |
Deferred
income taxes
|
|
|
67,272
|
|
|
|
38,645
|
|
|
|
23,157
|
|
Changes
in current assets and liabilities, net of
|
|
|
|
|
|
|
|
|
|
|
|
|
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables
|
|
|
(40,256 |
) |
|
|
(7,639 |
) |
|
|
(119,168 |
) |
Inventories
|
|
|
(7,130 |
) |
|
|
(29,736 |
) |
|
|
(20,217 |
) |
Other
current assets
|
|
|
(7,356 |
) |
|
|
(9,597 |
) |
|
|
435
|
|
Accounts
payable
|
|
|
24,702
|
|
|
|
19,834
|
|
|
|
52,121
|
|
Other
current liabilities
|
|
|
(22,932 |
) |
|
|
33,394
|
|
|
|
26,676
|
|
Other
noncurrent changes
|
|
|
9,594
|
|
|
|
20,913
|
|
|
|
21,379
|
|
Net
cash provided by continuing operations
|
|
|
634,581
|
|
|
|
626,030
|
|
|
|
454,729
|
|
Net
cash provided by (used in) discontinued operations
|
|
|
(71,389 |
) |
|
|
33,539
|
|
|
|
28,821
|
|
Net cash provided by operating
activities
|
|
|
563,192
|
|
|
|
659,569
|
|
|
|
483,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(558,283 |
) |
|
|
(479,872 |
) |
|
|
(377,856 |
) |
Acquisitions,
net of cash acquired
|
|
|
(348,490 |
) |
|
|
(113,781 |
) |
|
|
(213,557 |
) |
Net
proceeds from sale or disposition of property
|
|
|
24,983
|
|
|
|
30,501
|
|
|
|
40,460
|
|
Investments
|
|
|
(67,140 |
) |
|
|
(59,202 |
) |
|
|
1,833
|
|
Proceeds
from sale of equity method investments
|
|
|
58,450
|
|
|
|
---
|
|
|
|
38,166
|
|
Net
cash used in continuing operations
|
|
|
(890,480 |
) |
|
|
(622,354 |
) |
|
|
(510,954 |
) |
Net
cash provided by (used in) discontinued operations
|
|
|
548,216
|
|
|
|
(37,872 |
) |
|
|
(132,956 |
) |
Net cash used in investing
activities
|
|
|
(342,264 |
) |
|
|
(660,226 |
) |
|
|
(643,910 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance
of short-term borrowings
|
|
|
311,700
|
|
|
|
---
|
|
|
|
---
|
|
Repayment
of short-term borrowings
|
|
|
(310,000 |
) |
|
|
---
|
|
|
|
---
|
|
Issuance
of long-term debt
|
|
|
120,250
|
|
|
|
356,352
|
|
|
|
353,937
|
|
Repayment
of long-term debt
|
|
|
(232,464 |
) |
|
|
(315,486 |
) |
|
|
(106,822 |
) |
Proceeds
from issuance of common stock
|
|
|
17,263
|
|
|
|
19,963
|
|
|
|
9,165
|
|
Dividends
paid
|
|
|
(100,641 |
) |
|
|
(93,450 |
) |
|
|
(87,551 |
) |
Tax
benefit on stock-based compensation
|
|
|
5,398
|
|
|
|
2,524
|
|
|
|
---
|
|
Net
cash provided by (used in) continuing operations
|
|
|
(188,494 |
) |
|
|
(30,097 |
) |
|
|
168,729
|
|
Net
cash provided by discontinued operations
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Net cash provided by (used in)
financing activities
|
|
|
(188,494 |
) |
|
|
(30,097 |
) |
|
|
168,729
|
|
Effect of exchange rate
changes on cash and cash equivalents
|
|
|
308
|
|
|
|
(1,666 |
) |
|
|
---
|
|
Increase (decrease) in cash and
cash equivalents
|
|
|
32,742
|
|
|
|
(32,420 |
) |
|
|
8,369
|
|
Cash
and cash equivalents – beginning of year
|
|
|
73,078
|
|
|
|
105,498
|
|
|
|
97,129
|
|
Cash
and cash equivalents – end of year
|
|
$ |
105,820
|
|
|
$ |
73,078
|
|
|
$ |
105,498
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
NOTE 1 – SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
Basis of
presentation
The
consolidated financial statements of the Company include the accounts of the
following businesses: electric, natural gas distribution, construction services,
pipeline and energy services, natural gas and oil production, construction
materials and contracting, and other. The electric, natural gas distribution,
and pipeline and energy services businesses are substantially all regulated.
Construction services, natural gas and oil production, construction materials
and contracting, and other are nonregulated. For further descriptions of the
Company's businesses, see Note 16. The statements also include the ownership
interests in the assets, liabilities and expenses of two jointly owned electric
generating facilities.
The
Company's regulated businesses are subject to various state and federal agency
regulations. The accounting policies followed by these businesses are generally
subject to the Uniform System of Accounts of the FERC. These accounting policies
differ in some respects from those used by the Company's nonregulated
businesses.
The
Company's regulated businesses account for certain income and expense items
under the provisions of SFAS No. 71. SFAS No. 71 requires these businesses to
defer as regulatory assets or liabilities certain items that would have
otherwise been reflected as expense or income, respectively, based on the
expected regulatory treatment in future rates. The expected recovery or flowback
of these deferred items generally is based on specific ratemaking decisions or
precedent for each item. Regulatory assets and liabilities are being amortized
consistently with the regulatory treatment established by the FERC and the
applicable state public service commissions. See Note 6 for more
information regarding the nature and amounts of these regulatory
deferrals.
Cash and cash
equivalents
The
Company considers all highly liquid investments purchased with an original
maturity of three months or less to be cash equivalents.
Allowance for doubtful
accounts
The
Company's allowance for doubtful accounts as of December 31, 2007 and 2006, was
$14.6 million and $7.7 million, respectively.
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 $28.8 million and $32.6 million at
December 31, 2007 and 2006, respectively. The remainder of natural gas in
underground storage, which represents the cost of the gas required to maintain
pressure levels for normal operating purposes, was included in other assets and
was $43.0 million and $44.2 million at December 31, 2007 and 2006,
respectively.
Inventories
Inventories,
other than natural gas in underground storage for the Company's regulated
operations, consisted primarily of aggregates held for resale of $102.2 million
and $88.1 million, materials and supplies of $56.0 million and $54.1 million,
and other inventories of $42.3 million and $29.6 million, as of December
31, 2007 and 2006, respectively. These inventories were stated at the lower of
average cost or market value.
Short-term
investments
The
Company had auction rate securities of $91.6 million and $23.3 million at
December 31, 2007 and 2006, respectively, which are long-term variable rate
bonds tied to short-term interest rates that are reset through an auction
process which typically occurs every 90 days or less. The Company accounts for
these investments as available-for-sale in accordance with SFAS No. 115. Due to
the short interest rate reset period, the fair value of the auction rate
securities approximates cost and, as a result, there are no accumulated
unrealized gains or losses recorded in accumulated other comprehensive income on
the Consolidated Balance Sheets related to these investments.
Investments
The
Company's investments include its equity method investments as discussed in Note
4, the cash surrender value of life insurance policies, and investments in
fixed-income and equity securities which are accounted for as available-for-sale
investments in accordance with SFAS No. 115. Under the equity method,
investments are initially recorded at cost and adjusted for dividends and
undistributed earnings and losses. The Company's fixed-income and equity
securities are recorded at fair value with any unrealized gains and losses, net
of income taxes, recorded in accumulated other comprehensive income (loss) on
the Consolidated Balance Sheets until realized. For more information, see
comprehensive income in this note.
Property, plant and
equipment
Additions
to property, plant and equipment are recorded at cost. When regulated assets are
retired, or otherwise disposed of in the ordinary course of business, the
original cost of the asset is charged to accumulated depreciation. With respect
to the retirement or disposal of all other assets, except for natural gas and
oil production properties as described in natural gas and oil properties in this
note, the resulting gains or losses are recognized as a component of income. The
Company is permitted to capitalize AFUDC on regulated construction projects and
to include such amounts in rate base when the related facilities are placed in
service. In addition, the Company capitalizes interest, when applicable, on
certain construction projects associated with its other operations. The amount
of AFUDC and interest capitalized was $7.1 million, $5.8 million and
$4.3 million in 2007, 2006 and 2005, respectively. Generally, property, plant
and equipment are depreciated on a straight-line basis over the average useful
lives of the assets, except for depletable aggregate reserves, which are
depleted based on the units-of-production method based on recoverable aggregate
reserves, and natural gas and oil production properties, which are amortized on
the units-of-production method based on total reserves.
Property,
plant and equipment at December 31 was as follows:
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
Depreciable
|
|
|
|
2007
|
|
|
2006
|
|
|
Life
in Years
|
|
|
|
(Dollars in thousands, as
applicable)
|
|
Regulated:
|
|
|
|
|
|
|
|
|
|
Electric:
|
|
|
|
|
|
|
|
|
|
Electric
generation, distribution and transmission plant
|
|
$ |
784,705
|
|
|
$ |
703,838
|
|
|
|
4-50
|
|
Natural
gas distribution:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas distribution plant
|
|
|
948,446
|
|
|
|
289,106
|
|
|
|
4-45
|
|
Pipeline
and energy services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas transmission, gathering
|
|
|
|
|
|
|
|
|
|
|
|
|
and
storage facilities
|
|
|
403,459
|
|
|
|
384,354
|
|
|
|
8-104
|
|
Nonregulated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction
services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
4,513
|
|
|
|
3,974
|
|
|
|
-
|
|
Buildings
and improvements
|
|
|
11,987
|
|
|
|
11,288
|
|
|
|
3-40
|
|
Machinery,
vehicles and equipment
|
|
|
76,937
|
|
|
|
70,687
|
|
|
|
2-10
|
|
Other
|
|
|
8,498
|
|
|
|
8,805
|
|
|
|
3-10
|
|
Pipeline
and energy services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas gathering and other facilities
|
|
|
197,253
|
|
|
|
178,242
|
|
|
|
3-20
|
|
Natural
gas and oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas and oil properties
|
|
|
1,892,757
|
|
|
|
1,606,508
|
|
|
|
*
|
|
Other
|
|
|
31,142
|
|
|
|
29,737
|
|
|
|
3-15
|
|
Construction
materials and contracting:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
115,935
|
|
|
|
95,294
|
|
|
|
-
|
|
Buildings
and improvements
|
|
|
94,598
|
|
|
|
96,533
|
|
|
|
1-40
|
|
Machinery,
vehicles and equipment
|
|
|
921,199
|
|
|
|
817,209
|
|
|
|
1-20
|
|
Construction
in progress
|
|
|
22,253
|
|
|
|
23,968
|
|
|
|
-
|
|
Aggregate
reserves
|
|
|
384,731
|
|
|
|
377,653
|
|
|
|
**
|
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
3,022
|
|
|
|
3,079
|
|
|
|
-
|
|
Other
|
|
|
28,811
|
|
|
|
27,450
|
|
|
|
3-40
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
2,270,691
|
|
|
|
1,735,302
|
|
|
|
|
|
Net property, plant and equipment
|
|
$ |
3,659,555
|
|
|
$ |
2,992,423
|
|
|
|
|
|
*
|
Amortized on the
units-of-production method based on total proved reserves at an Mcf
equivalent average rate of $1.59, $1.38 and $1.19 for the years ended
December 31, 2007, 2006 and 2005, respectively. Includes natural gas and
oil production properties accounted for under the full-cost method, of
which $142.5 million and $164.0 million were excluded from amortization at
December 31, 2007 and 2006,
respectively.
|
**
|
Depleted on the
units-of-production method based on recoverable aggregate
reserves.
|
Impairment of long-lived
assets
The
Company reviews the carrying values of its long-lived assets, excluding goodwill
and natural gas and oil properties, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable. The determination of
whether an impairment has occurred is based on an estimate of undiscounted
future cash flows attributable to the assets, compared to the carrying value of
the assets. If impairment has occurred, the amount of the impairment recognized
is determined by estimating the fair value of the assets and recording a loss if
the carrying value is greater than the fair value. No significant impairment
losses were recorded in 2007, 2006 and 2005. Unforeseen events and changes in
circumstances could require the recognition of other impairment losses at some
future date.
Goodwill
Goodwill
represents the excess of the purchase price over the fair value of identifiable
net tangible and intangible assets acquired in a business combination. Goodwill
is required to be tested for impairment annually, which is completed in the
fourth quarter, or more frequently if events or changes in circumstances
indicate that goodwill may be impaired. For more information on goodwill
impairments and goodwill, see Notes 3 and 5.
Natural gas and oil
properties
The
Company uses the full-cost method of accounting for its natural gas and oil
production activities. Under this method, all costs incurred in the acquisition,
exploration and development of natural gas and oil properties are capitalized
and amortized on the units-of-production method based on total proved reserves.
Any conveyances of properties, including gains or losses on abandonments of
properties, are treated as adjustments to the cost of the properties with no
gain or loss recognized. Capitalized costs are subject to a "ceiling test" that
limits such costs to the aggregate of the present value of future net revenues
of proved reserves based on single point-in-time spot market prices, as mandated
under the rules of the SEC, plus the cost of unproved properties. Future net
revenue is estimated based on end-of-quarter spot market prices adjusted for
contracted price changes. If capitalized costs exceed the full-cost ceiling at
the end of any quarter, a permanent noncash write-down is required to be charged
to earnings in that quarter unless subsequent price changes eliminate or reduce
an indicated write-down.
At
December 31, 2007 and 2006, the Company's full-cost ceiling exceeded the
Company's capitalized cost. However, sustained downward movements in natural gas
and oil prices subsequent to December 31, 2007, could result in a future
write-down of the Company's natural gas and oil properties.
The
following table summarizes the Company's natural gas and oil properties not
subject to amortization at December 31, 2007, in total and by the year in which
such costs were incurred:
|
|
|
|
|
Year
Costs Incurred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
Total
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
and
prior
|
|
|
|
(In
thousands)
|
|
Acquisition
|
|
$ |
62,619
|
|
|
$ |
15,632
|
|
|
$ |
19,135
|
|
|
$ |
8,812
|
|
|
$ |
19,040
|
|
Development
|
|
|
60,352
|
|
|
|
33,380
|
|
|
|
16,853
|
|
|
|
5,225
|
|
|
|
4,894
|
|
Exploration
|
|
|
15,643
|
|
|
|
13,771
|
|
|
|
812
|
|
|
|
1,060
|
|
|
|
---
|
|
Capitalized
interest
|
|
|
3,910
|
|
|
|
1,771
|
|
|
|
1,038
|
|
|
|
426
|
|
|
|
675
|
|
Total
costs not subject
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
to
amortization
|
|
$ |
142,524
|
|
|
$ |
64,554
|
|
|
$ |
37,838
|
|
|
$ |
15,523
|
|
|
$ |
24,609
|
|
Costs not
subject to amortization as of December 31, 2007, consisted primarily of
unevaluated leaseholds, drilling costs, seismic costs and capitalized interest
associated primarily with CBNG in the Powder River Basin of Montana and Wyoming;
oil and gas development in the Big Horn Basin of Wyoming; an enhanced recovery
development project in the Cedar Creek Anticline in southeastern Montana; oil
and gas development in the Paradox Basin of Utah; a waterflood facility and
injection project in southern Texas; and development of the Bakken play in
western North Dakota. The Company expects that the majority of these costs will
be evaluated within the next five years and included in the amortization base as
the properties are evaluated and/or developed.
Revenue
recognition
Revenue
is recognized when the earnings process is complete, as evidenced by an
agreement between the customer and the Company, when delivery has occurred or
services have been rendered, when the fee is fixed or determinable and when
collection is reasonably assured. The Company recognizes utility revenue each
month based on the services provided to all utility customers during the month.
Accrued unbilled revenue which is included in receivables, net, represents
revenues recognized in excess of amounts billed. Accrued unbilled revenue at
Montana-Dakota and Cascade was $66.6 million at December 31, 2007. Accrued
unbilled revenue at Montana-Dakota was $35.6 million at December 31, 2006. The
Company recognizes construction contract revenue at its construction businesses
using the percentage-of-completion method as discussed later. The Company
recognizes revenue from natural gas and oil production properties only on that
portion of production sold and allocable to the Company's ownership interest in
the related well. The Company recognizes all other revenues when services are
rendered or goods are delivered.
Percentage-of-completion
method
The
Company recognizes construction contract revenue from fixed-price and modified
fixed-price construction contracts at its construction businesses using the
percentage-of-completion method, measured by the percentage of costs incurred to
date to estimated total costs for each contract. If a loss is anticipated on a
contract, the loss is immediately recognized. Costs in excess of billings on
uncompleted contracts of $45.2 million and $41.3 million at December 31, 2007
and 2006, respectively, represent revenues recognized in excess of amounts
billed and were included in receivables, net. Billings in excess of costs on
uncompleted contracts of $81.4 million and $84.2 million at
December 31, 2007 and 2006, respectively, represent billings in excess of
revenues recognized and were included in accounts payable. Amounts representing
balances billed but not paid by customers under retainage provisions in
contracts amounted to $80.3 million and $81.8 million at December 31, 2007 and
2006, respectively. The amounts expected to be paid within one year or less are
included in receivables, net, and amounted to $68.9 million and $81.8 million at
December 31, 2007 and 2006, respectively. The long-term retainage which was
included in deferred charges and other assets – other was $11.4 million at
December 31, 2007.
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 generally
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. The
Company's policy allows Cascade 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.
Accordingly, the Company does not anticipate any material effect on its
financial position or results of operations as a result of nonperformance by
counterparties. For more information on derivative instruments, see Note
7.
Asset retirement
obligations
The
Company records the fair value of a liability for an asset retirement obligation
in the period in which it is incurred. When the liability is initially recorded,
the Company capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, the Company either settles the
obligation for the recorded amount or incurs a gain or loss at its nonregulated
operations or incurs a regulatory asset or liability at its regulated
operations. For more information on asset retirement obligations, see Note
11.
Natural gas costs recoverable or
refundable through rate adjustments
Under the
terms of certain orders of the applicable state public service commissions, the
Company is deferring natural gas commodity, transportation and storage costs
that are greater or less than amounts presently being recovered through its
existing rate schedules. Such orders generally provide that these amounts are
recoverable or refundable through rate adjustments within a period ranging from
14 to 28 months from the time such costs are paid. Natural gas costs refundable
through rate adjustments were $11.6 million and $7.5 million at December 31,
2007 and 2006, respectively, which is included in other accrued liabilities.
Natural gas costs recoverable through rate adjustments were $3.9 million at
December 31, 2007, which is included in prepayments and other current
assets.
Insurance
Certain
subsidiaries of the Company are insured for workers' compensation losses,
subject to deductibles ranging up to $750,000 per occurrence. Automobile
liability and general liability losses are insured, subject to deductibles
ranging up to $500,000 per accident or occurrence. These subsidiaries have
excess coverage above the primary automobile and general liability policies on a
claims first-made basis beyond the deductible levels. The subsidiaries of the
Company are retaining losses up to the deductible amounts accrued on the basis
of estimates of liability for claims incurred and for claims incurred but not
reported.
Income taxes
The
Company provides deferred federal and state income taxes on all temporary
differences between the book and tax basis of the Company's assets and
liabilities. Excess deferred income tax balances associated with the Company's
rate-regulated activities resulting from the Company's adoption of SFAS
No. 109 have been recorded as a regulatory liability and are included in
other liabilities. These regulatory liabilities are expected to be reflected as
a reduction in future rates charged to customers in accordance with applicable
regulatory procedures.
The
Company uses the deferral method of accounting for investment tax credits and
amortizes the credits on electric and natural gas distribution plant over
various periods that conform to the ratemaking treatment prescribed by the
applicable state public service commissions.
Foreign currency translation
adjustment
The
functional currency of the Company's investment in the Brazilian Transmission
Lines and its former investment in the Termoceara Generating Facility, as
further discussed in Note 4, is the Brazilian Real. Translation from the
Brazilian Real to the U.S. dollar for assets and liabilities is performed using
the exchange rate in effect at the balance sheet date. Revenues and expenses are
translated on a year-to-date basis using weighted average daily exchange rates.
Adjustments resulting from such translations are reported as a separate
component of other comprehensive income (loss) in common stockholders'
equity.
Transaction
gains and losses resulting from the effect of exchange rate changes on
transactions denominated in a currency other than the functional currency of the
reporting entity would be recorded in income.
Common stock
split
On May
11, 2006, the Company's Board of Directors approved a three-for-two common stock
split. For more information on the common stock split, see Note 13.
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
year. 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 year, plus the effect of outstanding stock options,
restricted stock grants and performance share awards. In 2007, 2006 and 2005,
there were no shares excluded from the calculation of diluted earnings per
share. Common stock outstanding includes issued shares less shares held in
treasury.
Stock-based
compensation
On
January 1, 2006, the Company adopted SFAS No. 123 (revised). This
accounting standard revises SFAS No. 123 and requires entities to recognize
compensation expense in an amount equal to the grant-date fair value of
share-based payments granted to employees. SFAS No. 123 (revised) was adopted
using the modified prospective method, recognizing compensation expense for all
awards granted after the date of adoption of the standard and for the unvested
portion of previously granted awards that remain outstanding at the date of
adoption. In accordance with the modified prospective method, the Company's
consolidated financial statements for prior periods have not been restated to
reflect, and do not include, the impact of SFAS No. 123 (revised).
On
January 1, 2003, the Company adopted the fair value recognition provisions of
SFAS No. 123 and began expensing the fair market value of stock options for all
awards granted on or after January 1, 2003. As permitted by SFAS No. 148, the
Company accounted for stock options granted prior to January 1, 2003, under
APB Opinion No. 25 and no compensation expense was recognized as the options
granted had an exercise price equal to the market value of the underlying common
stock on the date of the grant.
The
following table illustrates the effect on earnings and earnings per common share
for the year ended December 31, 2005, as if the Company had applied SFAS
No. 123 and recognized compensation expense for all outstanding and unvested
stock options based on the fair value at the date of grant:
|
|
2005
|
|
(In thousands,
except
per share
amounts)
|
|
Earnings
on common stock, as reported
|
|
$ |
274,398
|
|
Stock-based
compensation expense included in reported
|
|
|
|
|
earnings,
net of related tax effects of $1
|
|
|
2
|
|
Total
stock-based compensation expense
|
|
|
|
|
determined
under fair value method for
|
|
|
|
|
all
awards, net of related tax effects
|
|
|
(471 |
) |
Pro
forma earnings on common stock
|
|
$ |
273,929
|
|
Earnings
per common share – basic – as reported
|
|
$ |
1.54
|
|
Earnings
per common share – basic – pro forma
|
|
$ |
1.54
|
|
Earnings
per common share – diluted – as reported
|
|
$ |
1.53
|
|
Earnings
per common share – diluted – pro forma
|
|
$ |
1.53
|
|
For more
information on the Company's stock-based compensation, see
Note 14.
Use of estimates
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires the Company to make
estimates and assumptions that affect the reported amounts of assets and
liabilities, and disclosure of contingent assets and liabilities at the date of
the financial statements, as well as the reported amounts of revenues and
expenses during the reporting period. Estimates are used for items such as
impairment testing of long-lived assets, goodwill and natural gas and oil
properties; fair values of acquired assets and liabilities under the purchase
method of accounting; natural gas and oil reserves; aggregate reserves; property
depreciable lives; tax provisions; uncollectible accounts; environmental and
other loss contingencies; accumulated provision for revenues subject to refund;
costs on construction contracts; unbilled revenues; actuarially determined
benefit costs; asset retirement obligations; the valuation of stock-based
compensation; and the fair value of derivative instruments. As additional
information becomes available, or actual amounts are determinable, the recorded
estimates are revised. Consequently, operating results can be affected by
revisions to prior accounting estimates.
Cash flow
information
Cash
expenditures for interest and income taxes were as follows:
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
$ |
74,404
|
|
|
$ |
65,850
|
|
|
$ |
47,902
|
|
Income
taxes
|
|
$ |
214,573
|
|
|
$ |
105,317
|
|
|
$ |
106,771
|
|
Income
taxes paid for the year ended December 31, 2007, increased from the amount paid
for the years ended December 31, 2006 and 2005, primarily due to higher
estimated quarterly tax payments due in large part to the gain on the sale of
the domestic independent power production assets as discussed in Note
3.
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 15.
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 was effective for the Company on January 1, 2008. The
adoption of SFAS No. 157 did not have a material effect on the Company's
financial position or results of operations.
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 was effective for the
Company on January 1, 2008, and at adoption, the Company elected to measure its
investments in certain fixed-income and equity securities at fair value in
accordance with SFAS No. 159. These investments prior to January 1, 2008, were
accounted for as available-for-sale investments and recorded at fair value with
any unrealized gains or losses, net of income taxes, recorded in accumulated
other comprehensive income (loss) on the Consolidated Balance Sheets until
realized. Upon the adoption of SFAS No. 159, the unrealized gain on the
available-for-sale investments of $405,000 (after tax) was recorded as an
increase to the January 1, 2008, balance of retained earnings. The adoption of
SFAS No. 159 did not have a material effect on the Company's financial position
or results of operations.
SFAS No. 141 (revised)
In December 2007, the FASB issued SFAS No. 141 (revised). SFAS No. 141 (revised)
requires an acquirer to recognize and measure the assets acquired, liabilities
assumed and any noncontrolling interests in the acquiree at the acquisition
date, measured at their fair values as of that date, with limited exception. In
addition, SFAS No. 141 (revised) requires that acquisition-related costs will be
generally expensed as incurred. SFAS No. 141 (revised) also expands the
disclosure requirements for business combinations. SFAS No. 141 (revised) will
be effective for the Company on January 1, 2009. The Company is evaluating the
effects of the adoption of SFAS No. 141 (revised).
SFAS No. 160 In December 2007, the
FASB issued SFAS No. 160. SFAS No. 160 establishes accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. SFAS No. 160 will be effective for the Company
on January 1, 2009. The Company is evaluating the effects of the adoption of
SFAS No. 160.
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, pension liability
adjustments, foreign currency translation adjustments and gains on
available-for-sale investments. For more information on derivative instruments,
see Note 7.
The
components of other comprehensive income (loss), and their related tax effects
for the years ended December 31, 2007, 2006 and 2005, were as
follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments
|
|
|
|
|
|
|
|
|
|
qualifying
as hedges:
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments
|
|
|
|
|
|
|
|
|
|
arising
during the period, net of tax of
|
|
|
|
|
|
|
|
|
|
$3,989,
$12,359 and $(16,391) in 2007,
|
|
|
|
|
|
|
|
|
|
2006
and 2005, respectively
|
|
$ |
6,508
|
|
|
$ |
19,743
|
|
|
$ |
(26,167 |
) |
Less:
Reclassification adjustment for gain (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
on
derivative instruments included in net
|
|
|
|
|
|
|
|
|
|
|
|
|
income,
net of tax of $12,504, $(16,194) and
|
|
|
|
|
|
|
|
|
|
|
|
|
$(2,734)
in 2007, 2006 and 2005, respectively
|
|
|
20,013
|
|
|
|
(25,867 |
) |
|
|
(4,367 |
) |
Net
unrealized gain (loss) on derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
instruments
qualifying as hedges
|
|
|
(13,505 |
) |
|
|
45,610
|
|
|
|
(21,800 |
) |
Pension
liability adjustment, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
of
$1,835, $1,122 and $353 in 2007,
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
and 2005, respectively
|
|
|
3,012
|
|
|
|
1,761
|
|
|
|
574
|
|
Foreign
currency translation adjustment, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
of
$3,606 in 2007
|
|
|
7,177
|
|
|
|
(1,585 |
) |
|
|
(1,099 |
) |
Net
unrealized gain on available-for-sale
|
|
|
|
|
|
|
|
|
|
|
|
|
investments,
net of tax of $270 in 2007
|
|
|
405
|
|
|
|
---
|
|
|
|
---
|
|
Total
other comprehensive income (loss)
|
|
$ |
(2,911 |
) |
|
$ |
45,786
|
|
|
$ |
(22,325 |
) |
The
after-tax components of accumulated other comprehensive loss as of December 31,
2007, 2006 and 2005, were as follows:
|
|
Net
Unrealized
Gain
(Loss)
on
Derivative
Instruments
Qualifying
as
Hedges
|
|
|
Pension
Liability
Adjustment
|
|
|
Foreign
Currency
Translation
Adjustment
|
|
|
Net
Unrealized
Gain
on
Available-
for-sale
Investments
|
|
|
Total
Accumulated
Other
Comprehensive
Loss
|
|
|
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
Balance
at December 31, 2005
|
|
$ |
(26,167 |
) |
|
$ |
(7,651 |
) |
|
$ |
2
|
|
|
$ |
---
|
|
|
$ |
(33,816 |
) |
Balance
at December 31, 2006
|
|
$ |
19,443
|
|
|
$ |
(24,342 |
) |
|
$ |
(1,583 |
) |
|
$ |
---
|
|
|
$ |
(6,482 |
) |
Balance at December 31,
2007
|
|
$ |
5,938
|
|
|
$ |
(21,330 |
) |
|
$ |
5,594
|
|
|
$ |
405
|
|
|
$ |
(9,393 |
) |
NOTE 2 –
ACQUISITIONS
In 2007,
the Company acquired construction materials and contracting 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 $526.3 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.
In 2006,
the Company acquired a construction services business in Nevada, natural gas and
oil production properties in Wyoming, and construction materials and contracting
businesses in California and Washington, none of which was material. The total
purchase consideration for these businesses and properties and purchase price
adjustments with respect to certain other acquisitions made prior to 2006,
consisting of the Company's common stock and cash, was $120.6
million.
In 2005,
the Company acquired construction services businesses in Nevada, natural gas and
oil production properties in southern Texas and construction materials and
contracting businesses in Idaho, Iowa and Oregon, none of which was material.
The total purchase consideration for these businesses and properties and
purchase price adjustments with respect to certain other acquisitions acquired
prior to 2005, consisting of the Company's common stock and cash, was $245.2
million.
The above
acquisitions were accounted for under the purchase method of accounting and,
accordingly, the acquired assets and liabilities assumed have been preliminarily
recorded at their respective fair values as of the date of acquisition. On
certain of the above acquisitions made in 2007, final fair market values are
pending the completion of the review of the relevant assets and liabilities 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.
NOTE 3 – 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 sold the
remaining assets of Innovatum on January 23, 2008. The loss on disposal of
Innovatum was not material.
During
the fourth quarter of 2006, the Company initiated a plan to sell certain of the
domestic assets of Centennial Resources. 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 Company’s 2006 Annual Report on Form 10-K 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 4, 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 provided
additional cash for growth opportunities.
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 were 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.
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 for the years ended December 31, 2007, 2006 and
2005, were as follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$ |
1,748
|
|
|
$ |
1,827
|
|
|
$ |
2,983
|
|
Loss from discontinued operations before income tax
benefit
|
|
|
(210 |
) |
|
|
(5,994 |
) |
|
|
(1,506 |
) |
Income
tax benefit
|
|
|
(316 |
) |
|
|
(3,834 |
) |
|
|
(731 |
) |
Income (loss) from discontinued operations, net of tax
|
|
$ |
106
|
|
|
$ |
(2,160 |
) |
|
$ |
(775 |
) |
The
income tax benefit for the year ended December 31, 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 $4.3 million
and $4.0 million goodwill impairments in 2006 and 2004, respectively) resulting
from the sale of the Innovatum stock.
Operating
results related to the domestic independent power production assets for the
years ended December 31, 2007, 2006 and 2005, were as follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$ |
125,867
|
|
|
$ |
66,145
|
|
|
$ |
48,508
|
|
Income from discontinued operations (including gain on disposal in 2007 of
$142.4 million) before income tax expense
(benefit)
|
|
|
177,666
|
|
|
|
9,276
|
|
|
|
10,828
|
|
Income
tax expense (benefit)
|
|
|
68,438
|
|
|
|
(863 |
) |
|
|
261
|
|
Income from discontinued operations, net of tax
|
|
$ |
109,228
|
|
|
$ |
10,139
|
|
|
$ |
10,567
|
|
The
income tax benefit for the year ended December 31, 2006, and the lower income
tax expense for the year ended December 31, 2005, reflect a renewable
electricity production tax credit of $4.4 million and $4.1 million,
respectively.
Revenues
at the former independent power production operations were recognized based on
electricity delivered and capacity provided, pursuant to contractual commitments
and, where applicable, revenues were recognized under EITF No. 91-6 ratably over
the terms of the related contract. Arrangements with multiple revenue-generating
activities were recognized under EITF No. 00-21 with the multiple
deliverables divided into separate units of accounting based on specific
criteria and revenues of the arrangements allocated to the separate units based
on their relative fair values.
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, at December 31, 2007 and 2006, were as
follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
Cash
and cash equivalents
|
|
$ |
---
|
|
|
$ |
1,878
|
|
Receivables,
net
|
|
|
---
|
|
|
|
8,307
|
|
Inventories
|
|
|
179
|
|
|
|
490
|
|
Prepayments
and other current assets
|
|
|
---
|
|
|
|
1,981
|
|
Total
current assets held for sale
|
|
$ |
179
|
|
|
$ |
12,656
|
|
Net
property, plant and equipment
|
|
$ |
---
|
|
|
$ |
390,679
|
|
Goodwill
|
|
|
---
|
|
|
|
11,167
|
|
Other
intangible assets, net
|
|
|
---
|
|
|
|
7,162
|
|
Other
|
|
|
---
|
|
|
|
2,257
|
|
Total
noncurrent assets held for sale
|
|
$ |
---
|
|
|
$ |
411,265
|
|
Accounts
payable
|
|
$ |
---
|
|
|
$ |
11,557
|
|
Other
accrued liabilities
|
|
|
---
|
|
|
|
3,343
|
|
Total
current liabilities held for sale
|
|
$ |
---
|
|
|
$ |
14,900
|
|
Deferred
income taxes
|
|
$ |
---
|
|
|
$ |
27,956
|
|
Other
liabilities
|
|
|
---
|
|
|
|
2,577
|
|
Total
noncurrent liabilities held for sale
|
|
$ |
---
|
|
|
$ |
30,533
|
|
NOTE 4 – EQUITY METHOD
INVESTMENTS
Investments
in companies in which the Company has the ability to exercise significant
influence over operating and financial policies are accounted for using the
equity method. The Company's equity method investments at December 31, 2007,
include the Brazilian Transmission Lines.
In August
2006, MDU Brasil acquired ownership interests in companies owning three electric
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. The contracts provide for revenues denominated in the Brazilian
Real, annual inflation adjustments and change in tax law adjustments and have
between 23 and 25 years remaining under the contracts. Alusa, Brascan and CEMIG
hold the remaining ownership interests, with CELESC also having an ownership
interest in ECTE. The functional currency for the Brazilian Transmission Lines
is the Brazilian Real.
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.
In June
2005, the Company completed the sale of its 49 percent interest in MPX to
Petrobras, the Brazilian state-controlled energy company. The Company realized a
gain of $15.6 million from the sale in 2005.
At
December 31, 2007 and 2006, the Company's equity method investments had total
assets of $398.4 million and $583.6 million, respectively, and long-term debt of
$211.2 million and $321.5 million, respectively. The Company's investment
in its equity method investments was approximately $59.0 million and $102.0
million, including undistributed earnings of $6.9 million and $8.5 million,
at December 31, 2007 and 2006, respectively.
NOTE 5 – GOODWILL AND OTHER
INTANGIBLE ASSETS
The
changes in the carrying amount of goodwill for the year ended December 31, 2007,
were as follows:
|
|
Balance
|
|
|
Goodwill
|
|
|
Balance
|
|
|
|
as
of
|
|
|
Acquired
|
|
|
as
of
|
|
|
|
January
1,
|
|
|
During
|
|
|
December
31,
|
|
|
|
2007
|
|
|
the
Year*
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
|
171,129
|
|
|
|
171,129
|
|
Construction
services
|
|
|
86,942
|
|
|
|
4,443
|
|
|
|
91,385
|
|
Pipeline
and energy services
|
|
|
1,159
|
|
|
|
---
|
|
|
|
1,159
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction materials and contracting
|
|
|
136,197
|
|
|
|
25,828
|
|
|
|
162,025
|
|
Other
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Total
|
|
$ |
224,298
|
|
|
$ |
201,400
|
|
|
$ |
425,698
|
|
|
*
|
Includes purchase price
adjustments that were not material related to acquisitions in a prior
period.
|
The
changes in the carrying amount of goodwill for the year ended December 31, 2006,
were as follows:
|
|
Balance
|
|
|
Goodwill
|
|
|
Balance
|
|
|
|
as
of
|
|
|
Acquired
|
|
|
as
of
|
|
|
|
January
1,
|
|
|
During
|
|
|
December
31,
|
|
|
|
2006
|
|
|
the
Year*
|
|
|
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 contracting
|
|
|
133,264
|
|
|
|
2,933
|
|
|
|
136,197
|
|
Other
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Total
|
|
$ |
215,393
|
|
|
$ |
8,905
|
|
|
$ |
224,298
|
|
|
*
|
Includes purchase price
adjustments that were not material related to acquisitions in a prior
period.
|
For more
information on the goodwill impairment related to the discontinued operations at
Innovatum in 2006, see Note 3.
Other
amortizable intangible assets at December 31, 2007 and 2006, were as
follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Customer
relationships
|
|
$ |
21,834
|
|
|
$ |
13,030
|
|
Accumulated
amortization
|
|
|
(4,444 |
) |
|
|
(1,890 |
) |
|
|
|
17,390
|
|
|
|
11,140
|
|
Noncompete
agreements
|
|
|
10,655
|
|
|
|
12,886
|
|
Accumulated
amortization
|
|
|
(3,654 |
) |
|
|
(8,540 |
) |
|
|
|
7,001
|
|
|
|
4,346
|
|
Acquired
contracts
|
|
|
2,539
|
|
|
|
8,307
|
|
Accumulated
amortization
|
|
|
(1,615 |
) |
|
|
(4,646 |
) |
|
|
|
924
|
|
|
|
3,661
|
|
Other
|
|
|
3,404
|
|
|
|
5,062
|
|
Accumulated
amortization
|
|
|
(927 |
) |
|
|
(1,407 |
) |
|
|
|
2,477
|
|
|
|
3,655
|
|
Total
|
|
$ |
27,792
|
|
|
$ |
22,802
|
|
Amortization
expense for intangible assets for the years ended December 31, 2007, 2006
and 2005, was $4.4 million, $4.3 million and $3.5 million, respectively.
Estimated amortization expense for intangible assets is $5.7 million in 2008,
$4.4 million in 2009, $3.4 million in 2010, $2.9 million in 2011,
$2.7 million in 2012 and $8.7 million thereafter.
NOTE 6 – REGULATORY ASSETS AND
LIABILITIES
The
following table summarizes the individual components of unamortized regulatory
assets and liabilities as of December 31:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Regulatory
assets:
|
|
|
|
|
|
|
Deferred
income taxes
|
|
$ |
43,866
|
|
|
$ |
35,978
|
|
Pension
and postretirement benefits
|
|
|
21,613
|
|
|
|
19,075
|
|
Natural
gas supply derivatives
|
|
|
16,324
|
|
|
|
---
|
|
Long-term
debt refinancing costs
|
|
|
10,605
|
|
|
|
11,232
|
|
Plant
costs
|
|
|
4,930
|
|
|
|
13,254
|
|
Other
|
|
|
15,812
|
|
|
|
7,230
|
|
Total
regulatory assets
|
|
|
113,150
|
|
|
|
86,769
|
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
Plant
removal and decommissioning costs
|
|
|
89,991
|
|
|
|
85,087
|
|
Taxes
refundable to customers
|
|
|
22,580
|
|
|
|
14,229
|
|
Deferred
income taxes
|
|
|
17,630
|
|
|
|
18,019
|
|
Natural
gas costs refundable through rate adjustments
|
|
|
11,568
|
|
|
|
7,516
|
|
Natural
gas supply derivatives
|
|
|
5,631
|
|
|
|
---
|
|
Other
|
|
|
8,250
|
|
|
|
4,179
|
|
Total
regulatory liabilities
|
|
|
155,650
|
|
|
|
129,030
|
|
Net
regulatory position
|
|
$ |
(42,500 |
) |
|
$ |
(42,261 |
) |
As of
December 31, 2007, a large portion of the Company's regulatory assets,
other than certain deferred income taxes, was being reflected in rates charged
to customers and is being recovered over the next 1 to 15 years. A portion of
the Company's regulatory assets are not earning a return; however, these
regulatory assets are expected to be recovered from customers in future
rates.
If, for
any reason, the Company's regulated businesses cease to meet the criteria for
application of SFAS No. 71 for all or part of their operations, the regulatory
assets and liabilities relating to those portions ceasing to meet such criteria
would be removed from the balance sheet and included in the statement of income
as an extraordinary item in the period in which the discontinuance of SFAS No.
71 occurs.
NOTE 7 – DERIVATIVE
INSTRUMENTS
Derivative
instruments, including certain derivative instruments embedded in other
contracts, are required to be recorded on the balance sheet as either an asset
or liability measured at fair value. Changes in the derivative instrument's fair
value are recognized currently in earnings unless specific hedge accounting
criteria are met. Accounting for qualifying hedges allows derivative gains and
losses to offset the related results on the hedged item in the income statement
and requires that a company must formally document, designate and assess the
effectiveness of transactions that receive hedge accounting
treatment.
In the
event a derivative instrument being accounted for as a cash flow hedge does not
qualify for hedge accounting because it is no longer highly effective in
offsetting changes in cash flows of a hedged item; if the derivative instrument
expires or is sold, terminated or exercised; or if management determines that
designation of the derivative instrument as a hedge instrument is no longer
appropriate, hedge accounting would be discontinued and the derivative
instrument would continue to be carried at fair value with changes in its fair
value recognized in earnings. In these circumstances, the net gain or loss at
the time of discontinuance of hedge accounting would remain in accumulated other
comprehensive income (loss) until the period or periods during which the hedged
forecasted transaction affects earnings, at which time the net gain or loss
would be reclassified into earnings. In the event a cash flow hedge is
discontinued because it is unlikely that a forecasted transaction will occur,
the derivative instrument would continue to be carried on the balance sheet at
its fair value, and gains and losses that had accumulated in other comprehensive
income (loss) would be recognized immediately in earnings. In the event of a
sale, termination or extinguishment of a foreign currency derivative, the
resulting gain or loss would be recognized immediately in earnings. The
Company's policy requires approval to terminate a derivative instrument prior to
its original maturity. As of December 31, 2007, the Company had no outstanding
foreign currency or interest rate hedges.
Cascade
core
At
December 31, 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
December 31, 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 cash flow hedge
of the forecasted sale of the related production or as a cash flow 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
years ended December 31, 2007 and 2005, the amount of hedge ineffectiveness was
immaterial. In the second quarter of 2006, Fidelity's oil collar agreements
became ineffective and no longer qualified for hedge accounting. The oil hedges
became ineffective as the physical price received no longer correlated to the
hedge price due to the widening of regional basis differentials on the price of
the physical production received. The ineffectiveness related to these collar
agreements resulted in a loss of approximately $138,000 (before tax) for the
year ended December 31, 2006, that was recorded in operation and
maintenance expense. The ineffective collar agreements expired by December 31,
2006. The amount of hedge ineffectiveness on Fidelity's remaining hedges was
immaterial for the year ended December 31, 2006.
For the
years ended December 31, 2007, 2006 and 2005, 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 December 31, 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
12 months. The Company estimates that over the next 12 months, net gains of
approximately $6.2 million (after tax) will be reclassified from accumulated
other comprehensive loss into earnings, subject to changes in natural gas and
oil market prices, as the hedged transactions affect earnings.
NOTE 8 – FAIR VALUE OF OTHER
FINANCIAL INSTRUMENTS
The
estimated fair value of the Company's long-term debt is based on quoted market
prices of the same or similar issues. The estimated fair values of the Company's
natural gas and oil price swap and collar agreements reflect the estimated
amounts the Company would receive or pay to terminate the contracts at the
reporting date based upon quoted market prices of comparable
contracts.
The
estimated fair value of the Company's long-term debt at December 31 was as
follows:
|
|
2007
|
|
|
2006
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In
thousands)
|
|
Long-term
debt
|
|
$ |
1,308,463
|
|
|
$ |
1,293,863
|
|
|
$ |
1,254,582
|
|
|
$ |
1,247,439
|
|
Commodity derivative agreements – current asset
|
|
$ |
12,740
|
|
|
$ |
12,740
|
|
|
$ |
32,101
|
|
|
$ |
32,101
|
|
Commodity derivative agreements – current liability
|
|
$ |
(14,799 |
) |
|
$ |
(14,799 |
) |
|
$ |
---
|
|
|
$ |
---
|
|
Commodity derivative agreements – noncurrent asset
|
|
$ |
3,419
|
|
|
$ |
3,419
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Commodity derivative agreements – noncurrent liability
|
|
$ |
(2,570 |
) |
|
$ |
(2,570 |
) |
|
$ |
---
|
|
|
$ |
---
|
|
The
carrying amounts of the Company's remaining financial instruments included in
current assets and current liabilities approximate their fair
values.
NOTE 9 – SHORT-TERM
BORROWINGS
Cascade
has a revolving credit agreement with various banks totaling $50 million with
certain provisions allowing for increased borrowings, up to a maximum of $75
million. The $50 million credit agreement expires on December 28, 2012, with
provisions allowing for an extension of up to two years upon consent of the
banks. Cascade also has a $20 million uncommitted line of credit which may
be terminated by the bank or Cascade at any time. There was $1.7 million
outstanding under the Cascade credit agreements at December 31, 2007. The
borrowings are classified as short-term borrowings as Cascade intends to repay
the borrowings within one year. The weighted average interest rate for
borrowings outstanding at December 31, 2007, was 4.75 percent. As of December
31, 2007, there were outstanding letters of credit, as discussed in Note 20, of
which $1.9 million reduced amounts available under the $50 million credit
agreement.
In order
to borrow under Cascade's $50 million 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. Cascade was in compliance with
these covenants and met the required conditions at December 31,
2007.
Cascade's
$50 million credit agreement contains cross-default provisions. These provisions
state that if Cascade 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 agreement will be in default.
Certain of Cascade's financing agreements and Cascade's practices limit the
amount of subsidiary indebtedness.
NOTE 10 – LONG-TERM DEBT AND
INDENTURE PROVISIONS
Long-term
debt outstanding at December 31 was as follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
First
mortgage bonds and notes:
|
|
|
|
|
|
|
Secured
Medium-Term Notes, Series A, at a weighted
|
|
|
|
|
|
|
average
rate of 6.48%, due on dates ranging from
|
|
|
|
|
|
|
October
1, 2008 to April 1, 2012
|
|
$ |
20,500
|
|
|
$ |
27,000
|
|
Senior
Notes, 5.98%, due December 15, 2033
|
|
|
30,000
|
|
|
|
30,000
|
|
Total
first mortgage bonds and notes
|
|
|
50,500
|
|
|
|
57,000
|
|
Senior
Notes at a weighted average rate of 5.64%,
|
|
|
|
|
|
|
|
|
due
on dates ranging from June 27, 2008
|
|
|
|
|
|
|
|
|
to
March 8, 2037
|
|
|
1,064,000
|
|
|
|
1,064,500
|
|
Medium-Term
Notes, at a weighted average rate of 7.72%
|
|
|
|
|
|
|
|
|
due
on dates ranging from September 4, 2012
|
|
|
|
|
|
|
|
|
to
March 16, 2029
|
|
|
81,000
|
|
|
|
---
|
|
Commercial
paper at a weighted average rate of 4.95%,
|
|
|
|
|
|
|
|
|
supported
by revolving credit agreements
|
|
|
61,000
|
|
|
|
122,850
|
|
Other
notes, at a weighted average rate of 5.24%
|
|
|
|
|
|
|
|
|
due
on dates ranging from September 1, 2020
|
|
|
|
|
|
|
|
|
to
February 1, 2035
|
|
|
43,679
|
|
|
|
---
|
|
Term
credit agreements at a weighted average rate of 5.88%,
|
|
|
|
|
|
|
|
|
due
on dates ranging from July 1, 2008
|
|
|
|
|
|
|
|
|
to
August 31, 2015
|
|
|
8,286
|
|
|
|
10,290
|
|
Discount
|
|
|
(2 |
) |
|
|
(58 |
) |
Total
long-term debt
|
|
|
1,308,463
|
|
|
|
1,254,582
|
|
Less
current maturities
|
|
|
161,682
|
|
|
|
84,034
|
|
Net
long-term debt
|
|
$ |
1,146,781
|
|
|
$ |
1,170,548
|
|
The
amounts of scheduled long-term debt maturities for the five years and thereafter
following December 31, 2007, aggregate $161.7 million in 2008;
$73.4 million in 2009; $7.3 million in 2010; $128.0 million in
2011; $135.5 million in 2012 and $802.6 million
thereafter.
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 December 31, 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 December 31, 2007 and 2006. The credit agreement supports
the Company's $100 million commercial paper program. Under the Company's
commercial paper program, $61.0 million and $25.8 million were
outstanding at December 31, 2007 and 2006, respectively. The commercial paper
borrowings are classified as long-term debt as they are intended to be
refinanced on a long-term basis through continued commercial paper borrowings
(supported by the credit agreement, which expires in June 2011).
In order
to borrow under the Company's credit agreement, the Company must be in
compliance with the applicable covenants and certain other conditions, including
covenants not to permit, as of the end of any fiscal quarter, (A) the ratio of
funded debt to total capitalization (determined on a consolidated basis) to be
greater than 65 percent or (B) the ratio of funded debt to capitalization
(determined with respect to the Company alone, excluding its subsidiaries) to be
greater than 65 percent. Also included is a covenant that does not permit
the ratio of the Company's earnings before interest, taxes, depreciation and
amortization to interest expense (determined with respect to the Company alone,
excluding its subsidiaries), for the 12-month period ended each fiscal quarter,
to be less than 2.5 to 1. Other covenants include restrictions on the sale of
certain assets and on the making of certain investments. The Company was in
compliance with these covenants and met the required conditions at December 31,
2007. In the event the Company does not comply with the applicable covenants and
other conditions, alternative sources of funding may need to be
pursued.
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 Mortgage
and, in some cases, to certify to the trustee that annual earnings (pretax and
before interest charges), as defined in the Mortgage, equal at least two times
its annualized first mortgage bond interest costs. Under the more restrictive of
the tests, as of December 31, 2007, the Company could have issued approximately
$544 million of additional first mortgage bonds.
Approximately
$549.8 million in net book value of the Company’s electric and natural gas
distribution properties at December 31, 2007, with certain exceptions, are
subject to the lien of the Mortgage and to the junior lien of the
Indenture.
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). Under the terms of the
master shelf agreement, $85.0 million was outstanding at December 31,
2007.
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 12-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 December 31, 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.
Centennial Energy Holdings,
Inc. Centennial has a revolving credit agreement and an
uncommitted line of credit 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 at
December 31, 2007 and 2006. Under the Centennial commercial paper program, there
was no amount outstanding at December 31, 2007, and $97.1 million outstanding at
December 31, 2006. Centennial commercial paper borrowings are classified as
long-term debt as they are intended to be refinanced on a long-term basis
through continued Centennial commercial paper borrowings (supported by
Centennial credit agreements). The revolving credit agreement 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 December
13, 2012. The uncommitted line of credit for $25 million may be terminated by
the bank at any time. As of December 31, 2007, $56.6 million of letters of
credit were outstanding, as discussed in Note 20, of which $44.0 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, $418.5
million and $539.5 million were outstanding at December 31, 2007 and 2006,
respectively. The ability to request additional borrowings under this master
shelf agreement expires on May 8, 2009.
In order
to borrow under Centennial's credit agreements and the Centennial uncommitted
long-term master shelf agreement, Centennial and certain of its subsidiaries
must be in compliance with the applicable covenants and certain other
conditions, including covenants not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater than 65
percent (for the $400 million credit agreement) and 60 percent (for the master
shelf agreement). The master shelf agreement also includes a covenant that does
not permit the ratio of Centennial's earnings before interest, taxes,
depreciation and amortization to interest expense, for the 12-month period ended
each fiscal quarter, to be less than 1.75 to 1. Other covenants include minimum
consolidated net worth, limitation on priority debt and restrictions on the sale
of certain assets and on the making of certain loans and investments. Centennial
and such subsidiaries were in compliance with these covenants and met the
required conditions at December 31, 2007. In the event Centennial or such
subsidiaries do not comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued.
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 practices 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 up to
$100 million. Under the terms of the master shelf agreement, $80.0 million was
outstanding at December 31, 2007 and 2006. The ability to request additional
borrowings under this master shelf agreement expires on December 20,
2008.
In order
to borrow under its uncommitted long-term master shelf agreement, Williston
Basin must be in compliance with the applicable covenants and certain other
conditions, including covenants not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater than 55
percent. Other covenants include limitation on priority debt and some
restrictions on the sale of certain assets and the making of certain
investments. Williston Basin was in compliance with these covenants and met the
required conditions at December 31, 2007. In the event Williston Basin does not
comply with the applicable covenants and other conditions, alternative sources
of funding may need to be pursued.
NOTE 11 – ASSET RETIREMENT
OBLIGATIONS
The
Company records obligations related to the plugging and abandonment of natural
gas and oil wells, decommissioning of certain electric generating facilities,
reclamation of certain aggregate properties and certain other obligations
associated with leased properties.
A
reconciliation of the Company's liability, which is included in other
liabilities, for the years ended December 31 was as follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Balance
at beginning of year
|
|
$ |
56,179
|
|
|
$ |
42,857
|
|
Liabilities
incurred
|
|
|
4,149
|
|
|
|
4,878
|
|
Liabilities
acquired
|
|
|
652
|
|
|
|
1,118
|
|
Liabilities
settled
|
|
|
(5,896 |
) |
|
|
(2,963 |
) |
Accretion
expense
|
|
|
3,081
|
|
|
|
3,093
|
|
Revisions
in estimates
|
|
|
6,100
|
|
|
|
6,321
|
|
Other
|
|
|
188
|
|
|
|
875
|
|
Balance
at end of year
|
|
$ |
64,453
|
|
|
$ |
56,179
|
|
The
Company believes that any expenses under SFAS No. 143 and FIN 47 as they relate
to regulated operations will be recovered in rates over time and, accordingly,
defers such expenses as regulatory assets.
The fair
value of assets that are legally restricted for purposes of settling asset
retirement obligations at December 31, 2007 and 2006, was $5.8 million and
$5.5 million, respectively.
NOTE 12 – PREFERRED
STOCKS
Preferred
stocks at December 31 were as follows:
|
2007
|
2006
|
|
(Dollars in
thousands)
|
Authorized:
|
|
|
Preferred
–
|
|
|
500,000
shares, cumulative, par value $100, issuable in series
|
|
|
Preferred
stock A –
|
|
|
1,000,000
shares, cumulative, without par value, issuable in series
|
|
|
(none
outstanding)
|
|
|
Preference
–
|
|
|
500,000
shares, cumulative, without par value, issuable in series
|
|
|
(none
outstanding)
|
|
|
Outstanding:
|
|
|
4.50%
Series – 100,000 shares
|
$10,000
|
$10,000
|
4.70%
Series – 50,000 shares
|
5,000
|
5,000
|
Total
preferred stocks
|
$15,000
|
$15,000
|
The 4.50%
Series and 4.70% Series preferred stocks outstanding are subject to redemption,
in whole or in part, at the option of the Company with certain limitations on 30
days notice on any quarterly dividend date at a redemption price, plus accrued
dividends, of $105 per share and $102 per share, respectively.
In the
event of a voluntary or involuntary liquidation, all preferred stock series
holders are entitled to $100 per share, plus accrued dividends.
The
affirmative vote of two-thirds of a series of the Company's outstanding
preferred stock is necessary for amendments to the Company's charter or bylaws
that adversely affect that series; creation of or increase in the amount of
authorized stock ranking senior to that series (or an affirmative majority vote
where the authorization relates to a new class of stock that ranks on parity
with such series); a voluntary liquidation or sale of substantially all of the
Company's assets; a merger or consolidation, with certain exceptions; or the
partial retirement of that series of preferred stock when all dividends on that
series of preferred stock have not been paid. The consent of the holders of a
particular series is not required for such corporate actions if the equivalent
vote of all outstanding series of preferred stock voting together has consented
to the given action and no particular series is affected differently than any
other series.
Subject
to the foregoing, the holders of common stock exclusively possess all voting
power. However, if cumulative dividends on preferred stock are in arrears, in
whole or in part, for one year, the holders of preferred stock would obtain the
right to one vote per share until all dividends in arrears have been paid and
current dividends have been declared and set aside.
NOTE 13 – COMMON
STOCK
On May
11, 2006, the Company's Board of Directors approved a three-for-two common stock
split to be effected in the form of a 50 percent common stock dividend. The
additional shares of common stock were distributed on July 26, 2006, to common
stockholders of record on July 12, 2006. Certain common stock information
appearing in the accompanying consolidated financial statements has been
restated in accordance with accounting principles generally accepted in the
United States of America to give retroactive effect to the stock split.
Additionally, preference share purchase rights have been appropriately adjusted
to reflect the effects of the split.
In 1998,
the Company's Board of Directors declared, pursuant to a stockholders' rights
plan, a dividend of one preference share purchase right (right) for each
outstanding share of the Company's common stock. Each right becomes exercisable,
upon the occurrence of certain events, for four-ninths of one one-thousandth of
a share of Series B Preference Stock of the Company, without par value, at an
exercise price of $125, subject to certain adjustments. The rights are currently
not exercisable and will be exercisable only if a person or group (acquiring
person) either acquires ownership of 15 percent or more of the Company's
common stock or commences a tender or exchange offer that would result in
ownership of 15 percent or more. In the event the Company is acquired in a
merger or other business combination transaction or 50 percent or more of its
consolidated assets or earnings power are sold, each right entitles the holder
to receive, upon the exercise thereof at the then current exercise price of the
right multiplied by the number of four-ninths of one one-thousandth of a share
of Series B Preference Stock for which a right is then exercisable, in
accordance with the terms of the rights agreement, such number of shares of
common stock of the acquiring person having a market value of twice the then
current exercise price of the right. The rights, which expire on
December 31, 2008, are redeemable in whole, but not in part, for a
price of $.00444 per right, at the Company's option at any time until any
acquiring person has acquired 15 percent or more of the Company's common
stock.
The Stock
Purchase Plan provides interested investors the opportunity to make optional
cash investments and to reinvest all or a percentage of their cash dividends in
shares of the Company's common stock. The K-Plan is partially funded with the
Company's common stock. From July 2006 through March 2007, the Stock Purchase
Plan and K-Plan, with respect to Company stock, were funded with shares of
authorized but unissued common stock. From January 2005 through June 2006,
and April 2007 through December 2007, purchases of shares of common stock on the
open market were used to fund the Stock Purchase Plan and K-Plan. At
December 31, 2007, there were 20.6 million shares of common stock reserved
for original issuance under the Stock Purchase Plan and K-Plan.
NOTE 14 – STOCK-BASED
COMPENSATION
On
January 1, 2006, the Company adopted SFAS No. 123 (revised) and on January
1, 2003, adopted SFAS No. 123. For a discussion of the adoption of SFAS No. 123
(revised) and SFAS No. 123, see Note 1.
The
Company has several stock-based compensation plans and is authorized to grant
options, restricted stock and stock for up to 17.1 million shares of common
stock and has granted options, restricted stock and stock of 6.9 million shares
through December 31, 2007. The Company generally issues new shares of common
stock to satisfy stock option exercises, restricted stock, stock and performance
share awards.
Total
stock-based compensation expense for the year ended December 31, 2007, was $4.7
million, net of income taxes of $3.1 million. Total stock-based compensation for
the year ended December 31, 2006, was $3.5 million, net of income taxes of $2.2
million.
As of
December 31, 2007, total remaining unrecognized compensation expense related to
stock-based compensation was approximately $4.7 million (before income taxes)
which will be amortized over a weighted average period of 1.5
years.
Stock options
The
Company has stock option plans for directors, key employees and employees. The
Company has not granted stock options since 2003. Options granted to key
employees automatically vest after nine years, but the plan provides for
accelerated vesting based on the attainment of certain performance goals or upon
a change in control of the Company, and expire 10 years after the date of grant.
Options granted to directors and employees vest at the date of grant and three
years after the date of grant, respectively, and expire 10 years after the
date of grant.
The fair
value of each option outstanding was estimated on the date of grant using the
Black-Scholes option-pricing model.
A summary
of the status of the stock option plans at December 31, 2007, and changes
during the year then ended was as follows:
|
|
Number
of
Shares
|
|
|
Weighted
Average
Exercise
Price
|
|
Balance at beginning of year
|
|
|
2,311,546
|
|
|
$ |
13.11
|
|
Forfeited
|
|
|
(39,352 |
) |
|
|
12.97
|
|
Exercised
|
|
|
(776,286 |
) |
|
|
13.15
|
|
Balance
at end of year
|
|
|
1,495,908
|
|
|
|
13.09
|
|
Exercisable
at end of year
|
|
|
1,468,940
|
|
|
$ |
13.08
|
|
Summarized
information about stock options outstanding and exercisable as of December 31,
2007, was as follows:
|
Options
Outstanding
|
Options
Exercisable
|
|
|
Remaining
|
Weighted
|
Aggregate
|
|
Weighted
|
Aggregate
|
|
|
Contractual
|
Average
|
Intrinsic
|
|
Average
|
Intrinsic
|
Range
of
|
Number
|
Life
|
Exercise
|
Value
|
Number
|
Exercise
|
Value
|
Exercisable
Prices
|
Outstanding
|
in
Years
|
Price
|
(000's)
|
Exercisable
|
Price
|
(000's)
|
|
|
|
|
|
|
|
|
$
8.88 – 11.00
|
135,776
|
.5
|
$9.71
|
$2,431
|
135,776
|
$9.71
|
$2,431
|
11.01
– 14.00
|
1,262,944
|
3.2
|
13.20
|
18,199
|
1,241,409
|
13.20
|
17,891
|
14.01
– 17.13
|
97,188
|
3.2
|
16.39
|
1,090
|
91,755
|
16.40
|
1,028
|
Balance
at end of year
|
1,495,908
|
2.9
|
$13.09
|
$21,720
|
1,468,940
|
$13.08
|
$21,350
|
The
aggregate intrinsic value in the preceding table represents the total intrinsic
value (before income taxes), based on the Company's stock price on December 31,
2007, which would have been received by the option holders had all option
holders exercised their options as of that date.
The
weighted average remaining contractual life of options exercisable was 2.9 years
at December 31, 2007.
The
Company received cash of $10.2 million and $4.5 million from the exercise of
stock options for the years ended December 31, 2007 and 2006, respectively. The
aggregate intrinsic value of options exercised during the years ended December
31, 2007 and 2006, was $11.2 million and $4.4 million,
respectively.
Restricted stock
awards
Prior to
2002, the Company granted restricted stock awards under a long-term incentive
plan. The restricted stock awards granted vest at various times ranging from
one year to nine years from the date of issuance, but certain grants may
vest early based upon the attainment of certain performance goals or upon a
change in control of the Company. The grant-date fair value is the market price
of the Company's stock on the grant date.
A summary
of the status of the restricted stock awards for the year ended December 31,
2007, was as follows:
|
|
Weighted
|
|
Number
|
Average
|
|
of
|
Grant-Date
|
|
Shares
|
Fair
Value
|
Nonvested
at beginning of period
|
32,117
|
$13.22
|
Vested
|
---
|
---
|
Forfeited
|
(5,384)
|
13.22
|
Nonvested
at end of period
|
26,733
|
$13.22
|
The fair
value of restricted stock awards that vested during the year ended December 31,
2006, was $1.8 million.
Stock awards
Nonemployee
directors may receive shares of common stock instead of cash in payment for
directors' fees under the nonemployee director stock compensation plan. There
were 48,228 shares with a fair value of $1.5 million and 50,627 shares with a
fair value of $1.3 million issued under this plan during the years ended
December 31, 2007 and 2006, respectively.
Performance share
awards
Since
2003, key employees of the Company have been awarded performance share awards
each year. Entitlement to performance shares is based on the Company's total
shareholder return over designated performance periods as measured against a
selected peer group.
Target
grants of performance shares outstanding at December 31, 2007, were as
follows:
|
|
Target
Grant
|
Grant
Date
|
Performance
Period
|
of
Shares
|
February
2005
|
2005-2007
|
256,081
|
February
2006
|
2006-2008
|
184,000
|
February
2007
|
2007-2009
|
184,418
|
Participants
may earn from zero to 200 percent of the target grant of shares based on the
Company's total shareholder return relative to that of the selected peer group.
Compensation expense is based on the grant-date fair value. The grant-date fair
value of performance share awards granted during the years ended December 31,
2007, 2006 and 2005, was $23.55, $25.22 and $18.36, per share, respectively. The
grant-date fair value for the performance shares granted in 2007 and 2006 was
determined by Monte Carlo simulation using a blended volatility term structure
comprised of 50 percent historical volatility and 50 percent implied volatility
and a risk-free interest rate term structure based on U.S. Treasury security
rates in effect as of the grant date. In addition, the mean over all simulation
paths of the discounted dividends expected to be earned in the performance
period used in the valuation was $1.25 and $1.37 per target share for the 2007
and 2006 awards, respectively. The grant-date fair value for the performance
shares issued in 2005 was equal to the market value of the common stock on the
grant date. The fair value of performance share awards that vested during the
years ended December 31, 2007 and 2006, was $6.0 million and $2.2 million,
respectively.
A summary
of the status of the performance share awards for the year ended December 31,
2007, was as follows:
|
|
Weighted
|
|
Number
|
Average
|
|
of
|
Grant-Date
|
|
Shares
|
Fair
Value
|
Nonvested
at beginning of period
|
738,684
|
$19.27
|
Granted
|
200,395
|
23.55
|
Vested
|
(228,452)
|
15.81
|
Forfeited
|
(86,128)
|
19.26
|
Nonvested
at end of period
|
624,499
|
$21.91
|
NOTE 15 – INCOME
TAXES
The
components of income before income taxes for each of the years ended December 31
were as follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
(In
thousands)
|
|
United
States
|
|
$ |
508,210
|
|
|
$ |
469,741
|
|
|
$ |
397,703
|
|
Foreign
|
|
|
4,600
|
|
|
|
4,148
|
|
|
|
13,837
|
|
Income
before income taxes
|
|
$ |
512,810
|
|
|
$ |
473,889
|
|
|
$ |
411,540
|
|
Income
tax expense for the years ended December 31 was as follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
106,399
|
|
|
$ |
108,843
|
|
|
$ |
102,736
|
|
State
|
|
|
15,135
|
|
|
|
18,487
|
|
|
|
20,449
|
|
Foreign
|
|
|
235
|
|
|
|
136
|
|
|
|
(93 |
) |
|
|
|
121,769
|
|
|
|
127,466
|
|
|
|
123,092
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes –
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
58,030
|
|
|
|
34,693
|
|
|
|
19,278
|
|
State
|
|
|
9,656
|
|
|
|
4,357
|
|
|
|
4,379
|
|
Investment
tax credit
|
|
|
(414 |
) |
|
|
(405 |
) |
|
|
(500 |
) |
|
|
|
67,272
|
|
|
|
38,645
|
|
|
|
23,157
|
|
Change
in uncertain tax benefits
|
|
|
869
|
|
|
|
---
|
|
|
|
---
|
|
Change
in accrued interest
|
|
|
114
|
|
|
|
---
|
|
|
|
---
|
|
Total
income tax expense
|
|
$ |
190,024
|
|
|
$ |
166,111
|
|
|
$ |
146,249
|
|
Components
of deferred tax assets and deferred tax liabilities recognized at
December 31 were as follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
Accrued
pension costs
|
|
$ |
44,002
|
|
|
$ |
43,433
|
|
Regulatory
matters
|
|
|
43,866
|
|
|
|
35,978
|
|
Asset
retirement obligations
|
|
|
15,163
|
|
|
|
14,789
|
|
Deferred
compensation
|
|
|
13,677
|
|
|
|
13,286
|
|
Other
|
|
|
45,335
|
|
|
|
43,818
|
|
Total
deferred tax assets
|
|
|
162,043
|
|
|
|
151,304
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
Depreciation
and basis differences on property,
|
|
|
|
|
|
|
|
|
plant
and equipment
|
|
|
498,933
|
|
|
|
445,315
|
|
Basis
differences on natural gas and oil
|
|
|
|
|
|
|
|
|
producing
properties
|
|
|
260,417
|
|
|
|
204,288
|
|
Regulatory
matters
|
|
|
17,630
|
|
|
|
18,019
|
|
Natural
gas and oil price swap and collar agreements
|
|
|
3,989
|
|
|
|
12,359
|
|
Other
|
|
|
42,044
|
|
|
|
23,894
|
|
Total
deferred tax liabilities
|
|
|
823,013
|
|
|
|
703,875
|
|
Net
deferred income tax liability
|
|
$ |
(660,970 |
) |
|
$ |
(552,571 |
) |
As of
December 31, 2007 and 2006, no valuation allowance has been recorded associated
with the above deferred tax assets.
The
following table reconciles the change in the net deferred income tax liability
from December 31, 2006, to December 31, 2007, to deferred income tax
expense:
|
|
2007
|
|
|
|
(In
thousands)
|
|
Change
in net deferred income tax
|
|
|
|
liability
from the preceding table
|
|
$ |
108,399
|
|
Deferred
taxes associated with other comprehensive loss
|
|
|
2,804
|
|
Deferred
taxes associated with acquisitions
|
|
|
(46,229 |
) |
Other
|
|
|
2,298
|
|
Deferred
income tax expense for the period
|
|
$ |
67,272
|
|
Total
income tax expense differs from the amount computed by applying the statutory
federal income tax rate to income before taxes. The reasons for this difference
were as follows:
Years
ended December 31,
|
2007
|
2006
|
2005
|
|
Amount
|
%
|
Amount
|
%
|
Amount
|
%
|
|
(Dollars in
thousands)
|
Computed
tax at federal
|
|
|
|
|
|
|
statutory
rate
|
$179,484
|
35.0
|
$165,861
|
35.0
|
$144,039
|
35.0
|
Increases
(reductions)
|
|
|
|
|
|
|
resulting
from:
|
|
|
|
|
|
|
State
income taxes,
|
|
|
|
|
|
|
net
of federal
|
|
|
|
|
|
|
income
tax benefit
|
17,121
|
3.3
|
17,786
|
3.8
|
15,064
|
3.7
|
Deferred
taxes associated
|
|
|
|
|
|
|
with
unrepatriated
|
|
|
|
|
|
|
foreign
earnings
|
9,368
|
1.8
|
---
|
---
|
---
|
---
|
Domestic
production
|
|
|
|
|
|
|
activities
deduction
|
(4,787)
|
(.9)
|
(2,324)
|
(.5)
|
(2,219)
|
(.5)
|
Depletion
allowance
|
(4,073)
|
(.8)
|
(4,784)
|
(1.0)
|
(4,381)
|
(1.1)
|
Resolution
of tax matters
|
208
|
---
|
(3,660)
|
(.8)
|
---
|
---
|
Foreign
operations
|
235
|
---
|
136
|
---
|
(4,225)
|
(1.0)
|
Other
items
|
(7,532)
|
(1.3)
|
(6,904)
|
(1.4)
|
(2,029)
|
(.6)
|
Total
income tax expense
|
$190,024
|
37.1
|
$166,111
|
35.1
|
$146,249
|
35.5
|
Prior to the sale of
the domestic independent power production assets on July 10, 2007, as discussed
in Note 3, 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, in the third quarter of 2007, deferred income taxes were
accrued with respect to the temporary differences which had not been previously
recorded. The cumulative undistributed earnings at December 31, 2007,
were approximately $36 million. The amount of deferred tax liability, net of
allowable foreign tax credits, associated with the undistributed earnings and
recognized during 2007 was approximately $9.4 million. Future
earnings will also be subject to additional U.S. taxes, net of allowable
foreign tax credits.
On
January 1, 2007, the Company adopted FIN 48 as discussed in Note 1. 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
2004.
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.
A
reconciliation of the unrecognized tax benefits (excluding interest) for the
year ended December 31, 2007, was as follows:
|
|
2007
|
|
|
|
(In
thousands)
|
|
Balance
at beginning of year
|
|
$ |
4,241
|
|
Additions
based on tax positions related to the current year
|
|
|
373
|
|
Additions
for tax positions of prior years
|
|
|
588
|
|
Lapse
of statute of limitations
|
|
|
(1,467 |
) |
Balance
at end of year
|
|
$ |
3,735
|
|
Included
in the balance of unrecognized tax benefits at December 31, 2007, were $1.6
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
that, if recognized, would affect the effective tax rate at December 31, 2007,
was $2.6 million, including approximately $441,000 for the payment of interest
and penalties.
The
Company does not anticipate the amount of unrecognized tax benefits to
significantly increase or decrease within the next 12 months.
The
Company recognizes interest and penalties accrued related to unrecognized tax
benefits in income taxes. For the years ended December 31, 2007, 2006 and 2005,
the Company recognized approximately $680,000, $7,100 and $7,300, respectively,
in interest expense. Penalties were not material in 2007, 2006 and 2005. The
Company recognized interest income of approximately $480,000, $1.5 million and
$62,000 for the years ended December 31, 2007, 2006 and 2005, respectively. The
Company had accrued liabilities of approximately $718,000 and $436,000 at
December 31, 2007 and 2006, respectively, for the payment of
interest.
NOTE 16 – BUSINESS SEGMENT
DATA
The
Company's reportable segments are those that are based on the Company's method
of internal reporting, which generally segregates the strategic business units
due to differences in products, services and regulation. The vast majority of
the Company's operations are located within the United States. The Company also
has investments in foreign countries, which largely consist of the Company’s
equity method investment in the Brazilian Transmission Lines.
Prior to
the fourth quarter of 2007, the Company reported seven business segments
consisting of electric, natural gas distribution, construction services,
pipeline and energy services, natural gas and oil production, construction
materials and contracting, and independent power production. As discussed in
Note 3, the domestic independent power production assets were sold in the third
quarter of 2007, and as a result, the remaining independent power production
operations are no longer significant and do not meet the criteria to be
considered a reportable segment. Therefore, the remaining operations of the
independent power production segment, including the Company's equity method
investment in the Brazilian Transmission Lines, are reported in the Other
category. The other operations do not meet the criteria to be considered a
reportable segment. The Company's operations are now conducted through six
reportable segments and prior period information has been restated to reflect
this change.
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 in the Rocky
Mountain and Mid-Continent regions of the United States and in and around the
Gulf of Mexico.
The
construction materials and contracting 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 contracting segment operates in the central, southern and western
United States and Alaska and Hawaii.
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 Other
category also includes the Company's equity investment in the Brazilian
Transmission Lines.
The
information below follows the same accounting policies as described in the
Summary of Significant Accounting Policies. Information on the Company's
businesses as of December 31 and for the years then ended was as
follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
External
operating revenues:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
193,367
|
|
|
$ |
187,301
|
|
|
$ |
181,238
|
|
Natural
gas distribution
|
|
|
532,997
|
|
|
|
351,988
|
|
|
|
384,199
|
|
Pipeline
and energy services
|
|
|
369,345
|
|
|
|
349,997
|
|
|
|
384,887
|
|
|
|
|
1,095,709
|
|
|
|
889,286
|
|
|
|
950,324
|
|
Construction
services
|
|
|
1,102,566
|
|
|
|
987,079
|
|
|
|
686,734
|
|
Natural
gas and oil production
|
|
|
288,148
|
|
|
|
251,153
|
|
|
|
163,539
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
1,761,473
|
|
|
|
1,877,021
|
|
|
|
1,603,326
|
|
Other
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
|
3,152,187
|
|
|
|
3,115,253
|
|
|
|
2,453,599
|
|
Total
external operating revenues
|
|
$ |
4,247,896
|
|
|
$ |
4,004,539
|
|
|
$ |
3,403,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment
operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
Construction
services
|
|
|
649
|
|
|
|
503
|
|
|
|
391
|
|
Pipeline
and energy services
|
|
|
77,718
|
|
|
|
93,723
|
|
|
|
92,424
|
|
Natural
gas and oil production
|
|
|
226,706
|
|
|
|
232,799
|
|
|
|
275,828
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
---
|
|
|
|
---
|
|
|
|
1,284
|
|
Other
|
|
|
10,061
|
|
|
|
8,117
|
|
|
|
6,038
|
|
Intersegment
eliminations
|
|
|
(315,134 |
) |
|
|
(335,142 |
) |
|
|
(375,965 |
) |
Total
intersegment
|
|
|
|
|
|
|
|
|
|
|
|
|
operating
revenues
|
|
$ |
---
|
|
|
$ |
---
|
|
|
$ |
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
22,549
|
|
|
$ |
21,396
|
|
|
$ |
20,818
|
|
Natural
gas distribution
|
|
|
19,054
|
|
|
|
9,776
|
|
|
|
9,534
|
|
Construction
services
|
|
|
14,314
|
|
|
|
15,449
|
|
|
|
13,459
|
|
Pipeline
and energy services
|
|
|
21,631
|
|
|
|
13,288
|
|
|
|
12,513
|
|
Natural
gas and oil production
|
|
|
127,408
|
|
|
|
106,768
|
|
|
|
84,754
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
95,732
|
|
|
|
88,723
|
|
|
|
77,988
|
|
Other
|
|
|
1,244
|
|
|
|
1,131
|
|
|
|
374
|
|
Total
depreciation, depletion
|
|
|
|
|
|
|
|
|
|
|
|
|
and
amortization
|
|
$ |
301,932
|
|
|
$ |
256,531
|
|
|
$ |
219,440
|
|
Interest
expense:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
6,737
|
|
|
$ |
6,493
|
|
|
$ |
7,553
|
|
Natural
gas distribution
|
|
|
13,566
|
|
|
|
3,885
|
|
|
|
3,973
|
|
Construction
services
|
|
|
4,878
|
|
|
|
6,295
|
|
|
|
4,177
|
|
Pipeline
and energy services
|
|
|
8,769
|
|
|
|
8,094
|
|
|
|
8,132
|
|
Natural
gas and oil production
|
|
|
8,394
|
|
|
|
9,864
|
|
|
|
7,550
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
23,997
|
|
|
|
25,943
|
|
|
|
21,365
|
|
Other
|
|
|
10,717
|
|
|
|
11,775
|
|
|
|
1,861
|
|
Intersegment
eliminations
|
|
|
(4,821 |
) |
|
|
(254 |
) |
|
|
(227 |
) |
Total
interest expense
|
|
$ |
72,237
|
|
|
$ |
72,095
|
|
|
$ |
54,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
8,528
|
|
|
$ |
7,403
|
|
|
$ |
8,308
|
|
Natural
gas distribution
|
|
|
6,477
|
|
|
|
2,108
|
|
|
|
2,240
|
|
Construction
services
|
|
|
26,829
|
|
|
|
16,497
|
|
|
|
9,693
|
|
Pipeline
and energy services
|
|
|
18,524
|
|
|
|
18,938
|
|
|
|
13,735
|
|
Natural
gas and oil production
|
|
|
78,348
|
|
|
|
78,960
|
|
|
|
82,428
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
39,045
|
|
|
|
46,245
|
|
|
|
29,244
|
|
Other
|
|
|
12,273
|
|
|
|
(4,040 |
) |
|
|
601
|
|
Total
income taxes
|
|
$ |
190,024
|
|
|
$ |
166,111
|
|
|
$ |
146,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
on common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
17,700
|
|
|
$ |
14,401
|
|
|
$ |
13,940
|
|
Natural
gas distribution
|
|
|
14,044
|
|
|
|
5,680
|
|
|
|
3,515
|
|
Construction
services
|
|
|
43,843
|
|
|
|
27,851
|
|
|
|
14,558
|
|
Pipeline
and energy services
|
|
|
31,408
|
|
|
|
32,126
|
|
|
|
22,867
|
|
Natural
gas and oil production
|
|
|
142,485
|
|
|
|
145,657
|
|
|
|
141,625
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
77,001
|
|
|
|
85,702
|
|
|
|
55,040
|
|
Other
|
|
|
(4,380 |
) |
|
|
(4,324 |
) |
|
|
13,061
|
|
Earnings
on common stock before
|
|
|
|
|
|
|
|
|
|
|
|
|
income
from discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
|
|
|
322,101
|
|
|
|
307,093
|
|
|
|
264,606
|
|
Income
from discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
operations,
net of tax
|
|
|
109,334
|
|
|
|
7,979
|
|
|
|
9,792
|
|
Total
earnings on common stock
|
|
$ |
431,435
|
|
|
$ |
315,072
|
|
|
$ |
274,398
|
|
Capital
expenditures:
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
91,548
|
|
|
$ |
39,055
|
|
|
$ |
27,036
|
|
Natural
gas distribution
|
|
|
500,178
|
|
|
|
15,398
|
|
|
|
17,224
|
|
Construction
services
|
|
|
18,241
|
|
|
|
31,354
|
|
|
|
50,900
|
|
Pipeline
and energy services
|
|
|
39,162
|
|
|
|
42,749
|
|
|
|
36,318
|
|
Natural
gas and oil production
|
|
|
283,589
|
|
|
|
328,979
|
|
|
|
329,773
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
189,727
|
|
|
|
141,088
|
|
|
|
161,977
|
|
Other
|
|
|
1,621
|
|
|
|
2,052
|
|
|
|
14,722
|
|
Net
proceeds from sale or
|
|
|
|
|
|
|
|
|
|
|
|
|
disposition
of property
|
|
|
(24,983 |
) |
|
|
(30,501 |
) |
|
|
(40,460 |
) |
Net capital expenditures before
|
|
|
|
|
|
|
|
|
|
|
|
|
discontinued
operations
|
|
|
1,099,083
|
|
|
|
570,174
|
|
|
|
597,490
|
|
Discontinued operations
|
|
|
(548,216 |
) |
|
|
33,090
|
|
|
|
132,956
|
|
Total
net capital expenditures
|
|
$ |
550,867
|
|
|
$ |
603,264
|
|
|
$ |
730,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric*
|
|
$ |
428,200
|
|
|
$ |
353,593
|
|
|
$ |
330,327
|
|
Natural
gas distribution*
|
|
|
942,454
|
|
|
|
264,102
|
|
|
|
271,653
|
|
Construction
services
|
|
|
456,564
|
|
|
|
401,832
|
|
|
|
351,654
|
|
Pipeline
and energy services
|
|
|
500,755
|
|
|
|
474,424
|
|
|
|
466,961
|
|
Natural
gas and oil production
|
|
|
1,299,406
|
|
|
|
1,173,797
|
|
|
|
898,883
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
1,642,729
|
|
|
|
1,562,868
|
|
|
|
1,498,338
|
|
Other**
|
|
|
322,326
|
|
|
|
672,858
|
|
|
|
605,746
|
|
Total
assets
|
|
$ |
5,592,434
|
|
|
$ |
4,903,474
|
|
|
$ |
4,423,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property,
plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric*
|
|
$ |
784,705
|
|
|
$ |
703,838
|
|
|
$ |
670,771
|
|
Natural
gas distribution*
|
|
|
948,446
|
|
|
|
289,106
|
|
|
|
277,288
|
|
Construction
services
|
|
|
101,935
|
|
|
|
94,754
|
|
|
|
90,110
|
|
Pipeline
and energy services
|
|
|
600,712
|
|
|
|
562,596
|
|
|
|
521,495
|
|
Natural
gas and oil production
|
|
|
1,923,899
|
|
|
|
1,636,245
|
|
|
|
1,303,447
|
|
Construction
materials and
|
|
|
|
|
|
|
|
|
|
|
|
|
contracting
|
|
|
1,538,716
|
|
|
|
1,410,657
|
|
|
|
1,310,426
|
|
Other
|
|
|
31,833
|
|
|
|
30,529
|
|
|
|
28,467
|
|
Less
accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
|
depletion
and amortization
|
|
|
2,270,691
|
|
|
|
1,735,302
|
|
|
|
1,523,887
|
|
Net
property, plant and equipment
|
|
$ |
3,659,555
|
|
|
$ |
2,992,423
|
|
|
$ |
2,678,117
|
|
* Includes
allocations of common utility property.
**
|
Includes the domestic
independent power production assets in 2006 and 2005 that were sold in
2007, and assets not directly assignable to a business (i.e. cash and cash
equivalents, certain accounts receivable, certain investments and
other miscellaneous current and deferred
assets).
|
The
pipeline and energy services segment recognized income from discontinued
operations, net of tax, of $106,000 for the year ended December 31, 2007, and a
loss from discontinued operations, net of tax, of $2.1 million and $775,000 for
the years ended December 31, 2006 and 2005, respectively. The Other category
reflects income from discontinued operations, net of tax, of $109.2 million,
$10.1 million and $10.6 million for the years ended December 31, 2007, 2006 and
2005, respectively.
Excluding
income (loss) from discontinued operations at pipeline and energy services,
earnings 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 contracting, and other are all from nonregulated operations.
Capital
expenditures for 2007, 2006 and 2005 include noncash transactions, including the
issuance of the Company's equity securities in connection with acquisitions and
the outstanding indebtedness related to the 2007 Cascade acquisition. The
noncash transactions were $217.3 million in 2007, immaterial in 2006 and $46.5
million in 2005.
NOTE 17 – EMPLOYEE BENEFIT
PLANS
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. Effective January
1, 2006, the Company discontinued defined pension plan benefits to all nonunion
and certain union employees hired after December 31, 2005. These employees that
would have been eligible for defined pension plan benefits are eligible to
receive additional defined contribution plan benefits. The Company uses a
measurement date of December 31 for all of its pension and postretirement
benefit plans.
Changes
in benefit obligation and plan assets for the year ended December 31, 2007, and
amounts recognized in the Consolidated Balance Sheets at December 31, 2007,
were as follows:
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of year
|
|
$ |
298,398
|
|
|
$ |
303,393
|
|
|
$ |
67,724
|
|
|
$ |
69,811
|
|
Service
cost
|
|
|
9,098
|
|
|
|
8,901
|
|
|
|
1,865
|
|
|
|
2,015
|
|
Interest
cost
|
|
|
18,591
|
|
|
|
16,056
|
|
|
|
4,212
|
|
|
|
3,633
|
|
Plan
participants' contributions
|
|
|
---
|
|
|
|
---
|
|
|
|
1,790
|
|
|
|
1,533
|
|
Actuarial
(gain) loss
|
|
|
(8,079 |
) |
|
|
(14,363 |
) |
|
|
482
|
|
|
|
(4,019 |
) |
Acquisition
|
|
|
63,556
|
|
|
|
---
|
|
|
|
11,734
|
|
|
|
---
|
|
Benefits
paid
|
|
|
(21,641 |
) |
|
|
(15,589 |
) |
|
|
(6,226 |
) |
|
|
(5,249 |
) |
Benefit
obligation at end of year
|
|
|
359,923
|
|
|
|
298,398
|
|
|
|
81,581
|
|
|
|
67,724
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of year
|
|
|
259,275
|
|
|
|
245,328
|
|
|
|
58,747
|
|
|
|
52,448
|
|
Actual
gain on plan assets
|
|
|
28,393
|
|
|
|
27,047
|
|
|
|
2,357
|
|
|
|
6,440
|
|
Employer
contribution
|
|
|
4,236
|
|
|
|
2,489
|
|
|
|
3,888
|
|
|
|
3,575
|
|
Plan
participants' contributions
|
|
|
---
|
|
|
|
---
|
|
|
|
1,790
|
|
|
|
1,533
|
|
Acquisition
|
|
|
60,703
|
|
|
|
---
|
|
|
|
13,128
|
|
|
|
---
|
|
Benefits
paid
|
|
|
(21,641 |
) |
|
|
(15,589 |
) |
|
|
(6,226 |
) |
|
|
(5,249 |
) |
Fair
value of plan assets at end of year
|
|
|
330,966
|
|
|
|
259,275
|
|
|
|
73,684
|
|
|
|
58,747
|
|
Funded
status – under
|
|
$ |
(28,957 |
) |
|
$ |
(39,123 |
) |
|
$ |
(7,897 |
) |
|
$ |
(8,977 |
) |
Amounts
recognized in the Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
Sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid
benefit cost (noncurrent)
|
|
$ |
10,253
|
|
|
$ |
4,368
|
|
|
$ |
664
|
|
|
$ |
---
|
|
Accrued
benefit liability (current)
|
|
|
---
|
|
|
|
---
|
|
|
|
(408 |
) |
|
|
(364 |
) |
Accrued
benefit liability (noncurrent)
|
|
|
(39,210 |
) |
|
|
(43,491 |
) |
|
|
(8,153 |
) |
|
|
(8,613 |
) |
Net
amount recognized
|
|
$ |
(28,957 |
) |
|
$ |
(39,123 |
) |
|
$ |
(7,897 |
) |
|
$ |
(8,977 |
) |
Amounts
recognized in accumulated other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive
loss consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial
(gain) loss
|
|
$ |
30,006
|
|
|
$ |
30,415
|
|
|
$ |
(2,466 |
) |
|
$ |
(13,718 |
) |
Prior
service cost (credit)
|
|
|
3,350
|
|
|
|
5,948
|
|
|
|
(10,524 |
) |
|
|
648
|
|
Transition
obligation
|
|
|
---
|
|
|
|
---
|
|
|
|
10,628
|
|
|
|
12,753
|
|
Total
|
|
$ |
33,356
|
|
|
$ |
36,363
|
|
|
$ |
(2,362 |
) |
|
$ |
(317 |
) |
Employer
contributions and benefits paid in the above table include only those amounts
contributed directly to, or paid directly from, plan assets.
Unrecognized
pension actuarial losses in excess of 10 percent of the greater of the projected
benefit obligation or the market-related value of assets is amortized on a
straight-line basis over the expected average remaining service lives of active
participants. The market-related value of assets is determined using a five-year
average of assets. Unrecognized postretirement net transition obligation is
amortized over a 20-year period ending 2012.
The
accumulated benefit obligation for the defined benefit pension plans reflected
above was $307.7 million and $245.6 million at December 31, 2007 and 2006,
respectively.
The
projected benefit obligation, accumulated benefit obligation and fair value of
plan assets for the pension plans with accumulated benefit obligations in excess
of plan assets at December 31, 2007 and 2006, were as follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Projected
benefit obligation
|
|
$ |
106,236
|
|
|
$ |
187,638
|
|
Accumulated
benefit obligation
|
|
$ |
95,435
|
|
|
$ |
151,850
|
|
Fair
value of plan assets
|
|
$ |
94,845
|
|
|
$ |
148,261
|
|
Components
of net periodic benefit cost for the Company's pension and other postretirement
benefit plans for the years ended December 31, 2007 and 2006, were as
follows:
|
|
Pension Benefits
|
|
|
Other Postretirement
Benefits
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In
thousands)
|
|
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$ |
9,098
|
|
|
$ |
8,901
|
|
|
$ |
1,865
|
|
|
$ |
2,015
|
|
Interest cost
|
|
|
18,591
|
|
|
|
16,056
|
|
|
|
4,212
|
|
|
|
3,633
|
|
Expected return on assets
|
|
|
(22,524 |
) |
|
|
(19,913 |
) |
|
|
(4,776 |
) |
|
|
(4,119 |
) |
Amortization of prior service cost (credit)
|
|
|
756
|
|
|
|
913
|
|
|
|
(1,300 |
) |
|
|
46
|
|
Recognized net actuarial (gain) loss
|
|
|
1,605
|
|
|
|
1,699
|
|
|
|
73
|
|
|
|
(243 |
) |
Amortization of net transition obligation (asset)
|
|
|
---
|
|
|
|
(3 |
) |
|
|
2,125
|
|
|
|
2,125
|
|
Net periodic benefit cost, including amount
capitalized
|
|
|
7,526
|
|
|
|
7,653
|
|
|
|
2,199
|
|
|
|
3,457
|
|
Less amount capitalized
|
|
|
991
|
|
|
|
689
|
|
|
|
373
|
|
|
|
261
|
|
Net periodic benefit cost
|
|
|
6,535
|
|
|
|
6,964
|
|
|
|
1,826
|
|
|
|
3,196
|
|
Other changes in plan assets and benefit obligations recognized
in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (gain) loss
|
|
|
(11,095 |
) |
|
|
(22,983 |
) |
|
|
1,507
|
|
|
|
(6,340 |
) |
Acquisition-related actuarial loss
|
|
|
12,291
|
|
|
|
---
|
|
|
|
9,818
|
|
|
|
---
|
|
Acquisition-related prior service credit
|
|
|
(1,842 |
) |
|
|
---
|
|
|
|
(12,472 |
) |
|
|
---
|
|
Amortization of actuarial gain (loss)
|
|
|
(1,605 |
) |
|
|
(1,699 |
) |
|
|
(73 |
) |
|
|
243
|
|
Amortization of prior service cost (credit)
|
|
|
(756 |
) |
|
|
(913 |
) |
|
|
1,300
|
|
|
|
(46 |
) |
Amortization of net transition (obligation) asset
|
|
|
---
|
|
|
|
3
|
|
|
|
(2,125 |
) |
|
|
(2,125 |
) |
Total recognized in accumulated other comprehensive
loss
|
|
|
(3,007 |
) |
|
|
(25,592 |
) |
|
|
(2,045 |
) |
|
|
(8,268 |
) |
Total recognized in net periodic benefit cost and accumulated
other comprehensive loss
|
|
$ |
3,528
|
|
|
$ |
(18,628 |
) |
|
$ |
(219 |
) |
|
$ |
(5,072 |
) |
Components
of net periodic benefit cost for the Company's pension and other postretirement
benefit plans for the year ended December 31, 2005, was as follows:
|
|
Pension
Benefits
|
|
|
Other
Postretirement
Benefits
|
|
|
|
2005
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
Service
cost
|
|
$ |
8,336
|
|
|
$ |
1,719
|
|
Interest
cost
|
|
|
16,617
|
|
|
|
3,784
|
|
Expected
return on assets
|
|
|
(19,947 |
) |
|
|
(4,005 |
) |
Amortization
of prior service cost
|
|
|
1,025
|
|
|
|
45
|
|
Recognized
net actuarial (gain) loss
|
|
|
1,385
|
|
|
|
(549 |
) |
Amortization
of net transition obligation (asset)
|
|
|
(45 |
) |
|
|
2,126
|
|
Net
periodic benefit cost, including amount capitalized
|
|
|
7,371
|
|
|
|
3,120
|
|
Less
amount capitalized
|
|
|
730
|
|
|
|
313
|
|
Net
periodic benefit cost
|
|
$ |
6,641
|
|
|
$ |
2,807
|
|
The
estimated net loss and prior service cost for the defined benefit pension plans
that will be amortized from accumulated other comprehensive loss into net
periodic benefit cost in 2008 are $967,000 and $665,000, respectively. The
estimated net loss, prior service credit and transition obligation for the other
postretirement benefit plans that will be amortized from accumulated other
comprehensive loss into net periodic benefit cost in 2008 are $461,000, $2.8
million and $2.1 million, respectively.
Weighted
average assumptions used to determine benefit obligations at December 31 were as
follows:
|
|
Other
|
|
Pension
|
Postretirement
|
|
Benefits
|
Benefits
|
|
2007
|
2006
|
2007
|
2006
|
|
|
|
|
|
Discount
rate
|
6.00%
|
5.75%
|
6.00%
|
5.75%
|
Rate
of compensation increase
|
4.20%
|
4.30%
|
4.50%
|
4.50%
|
Weighted
average assumptions used to determine net periodic benefit cost for the years
ended December 31 were as follows:
|
|
Other
|
|
Pension
|
Postretirement
|
|
Benefits
|
Benefits
|
|
2007
|
2006
|
2007
|
2006
|
|
|
|
|
|
Discount
rate
|
5.75%
|
5.50%
|
5.75%
|
5.50%
|
Expected
return on plan assets
|
8.40%
|
8.50%
|
7.50%
|
7.50%
|
Rate
of compensation increase
|
4.20%
|
4.30%
|
4.50%
|
4.50%
|
The
expected rate of return on plan assets is based on the targeted asset allocation
of 70 percent equity securities and 30 percent fixed-income securities and the
expected rate of return from these asset categories. The expected return on plan
assets for other postretirement benefits reflects insurance-related investment
costs.
Health
care rate assumptions for the Company's other postretirement benefit plans as of
December 31 were as follows:
|
2007
|
2006
|
Health
care trend rate assumed for next year
|
6.0%-10.0%
|
6.0%-9.0%
|
Health
care cost trend rate – ultimate
|
5.0%-6.0%
|
5.0%-6.0%
|
Year
in which ultimate trend rate achieved
|
1999-2017
|
1999-2014
|
The
Company's other postretirement benefit plans include health care and life
insurance benefits for certain employees. The plans underlying these benefits
may require contributions by the employee depending on such employee's age and
years of service at retirement or the date of retirement. The accounting for the
health care plans anticipates future cost-sharing changes that are consistent
with the Company's expressed intent to generally increase retiree contributions
each year by the excess of the expected health care cost trend rate over 6
percent.
Assumed
health care cost trend rates may have a significant effect on the amounts
reported for the health care plans. A one percentage point change in the assumed
health care cost trend rates would have had the following effects at December
31, 2007:
|
1
Percentage
|
1
Percentage
|
|
Point
Increase
|
Point
Decrease
|
|
(In
thousands)
|
Effect
on total of service
|
|
|
and
interest cost components
|
$(21)
|
$(930)
|
Effect
on postretirement
|
|
|
benefit
obligation
|
$1,335
|
$(9,796)
|
The
Company's defined benefit pension plans' asset allocation at December 31,
2007 and 2006, and weighted average targeted asset allocations at December 31,
2007, were as follows:
|
|
|
|
|
Weighted
Average
|
|
|
|
Percentage
|
|
|
Targeted
Asset
|
|
|
|
of
Plan
|
|
|
Allocation
|
|
|
|
Assets
|
|
|
Percentage
|
|
Asset
Category
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
Equity
securities
|
|
|
66 |
% |
|
|
69 |
% |
|
|
70 |
% |
Fixed-income
securities
|
|
|
29
|
|
|
|
27
|
|
|
|
30 |
* |
Other
|
|
|
5
|
|
|
|
4
|
|
|
|
---
|
|
Total
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
* Includes target for both
fixed-income securities and other.
The
Company's pension assets are managed by 12 outside investment managers. The
Company's other postretirement assets are managed by three outside investment
managers. The Company's investment policy with respect to pension and other
postretirement assets is to make investments solely in the interest of the
participants and beneficiaries of the plans and for the exclusive purpose of
providing benefits accrued and defraying the reasonable expenses of
administration. The Company strives to maintain investment diversification to
assist in minimizing the risk of large losses. The Company's policy guidelines
allow for investment of funds in cash equivalents, fixed-income securities and
equity securities. The guidelines prohibit investment in commodities and future
contracts, equity private placement, employer securities, leveraged or
derivative securities, options, direct real estate investments, precious metals,
venture capital and limited partnerships. The guidelines also prohibit short
selling and margin transactions. The Company's practice is to periodically
review and rebalance asset categories based on its targeted asset allocation
percentage policy.
The
Company's other postretirement benefit plans' asset allocation at December 31,
2007 and 2006, and weighted average targeted asset allocation at December 31,
2007, were as follows:
|
|
|
|
|
|
|
|
Weighted
Average
|
|
|
|
Percentage
|
|
|
Targeted
Asset
|
|
|
|
of
Plan
|
|
|
Allocation
|
|
|
|
Assets
|
|
|
Percentage
|
|
Asset
Category
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
Equity
securities
|
|
|
70 |
% |
|
|
70 |
% |
|
|
70 |
% |
Fixed-income
securities
|
|
|
27
|
|
|
|
27
|
|
|
|
30 |
* |
Other
|
|
|
3
|
|
|
|
3
|
|
|
|
---
|
|
Total
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
* Includes target for both
fixed-income securities and other.
The
Company expects to contribute approximately $5.6 million to its defined benefit
pension plans and approximately $3.5 million to its postretirement benefit plans
in 2008.
The
following benefit payments, which reflect future service, as appropriate, are
expected to be paid:
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
Years
|
|
Benefits
|
|
|
Benefits
|
|
|
|
(In
thousands)
|
|
2008
|
|
$ |
18,199
|
|
|
$ |
5,229
|
|
2009
|
|
|
18,993
|
|
|
|
5,429
|
|
2010
|
|
|
20,144
|
|
|
|
5,630
|
|
2011
|
|
|
21,046
|
|
|
|
5,852
|
|
2012
|
|
|
22,388
|
|
|
|
6,067
|
|
2013-2017
|
|
|
130,377
|
|
|
|
33,643
|
|
The
following Medicare Part D subsidies are expected: $736,000 in 2008; $786,000 in
2009; $841,000 in 2010; $889,000 in 2011; $948,000 in 2012; and $5.6 million
during the years 2013 through 2017.
In
addition to company-sponsored plans, certain employees are covered under
multi-employer pension plans administered by a union. Amounts contributed to the
multi-employer plans were $51.5 million, $57.6 million and $39.6 million in
2007, 2006 and 2005, respectively.
In
addition to the qualified plan defined pension benefits reflected in the table
at the beginning of this note, the Company also has an
unfunded, nonqualified benefit plan for executive officers and certain key
management employees that generally provides for defined benefit payments at age
65 following the employee's retirement or to their beneficiaries upon death for
a 15-year period. The Company had investments of $55.0 million at December 31,
2007, consisting of equity securities of $26.4 million, life insurance carried
on plan participants (payable upon the employee's death) of $20.8 million,
fixed-income securities of $4.0 million, and other investments of $3.8 million,
which the Company anticipates using to satisfy obligations under this plan. The
Company's net periodic benefit cost for this plan was $7.6 million,
$7.5 million and $7.4 million in 2007, 2006 and 2005, respectively.
The total projected benefit obligation for this plan was $80.6 million and
$69.5 million at December 31, 2007 and 2006, respectively. The accumulated
benefit obligation for this plan was $69.3 million and $57.4 million at
December 31, 2007 and 2006, respectively. A discount rate of 6.00 percent
and 5.75 percent at December 31, 2007 and 2006, respectively, and a rate of
compensation increase of 4.25 percent at December 31, 2007 and 2006, were
used to determine benefit obligations. A discount rate of 5.75 percent and 5.50
percent at December 31, 2007 and 2006, respectively, and a rate of compensation
increase of 4.25 percent at December 31, 2007 and 2006, were used to determine
net periodic benefit cost.
The
amount of benefit payments for the unfunded, nonqualified benefit plan, as
appropriate, are expected to aggregate $3.5 million in 2008; $3.6 million in
2009; $4.1 million in 2010; $4.4 million in 2011; $4.8 million in 2012; and
$31.1 million for the years 2013 through 2017.
The
Company sponsors various defined contribution plans for eligible employees.
Costs incurred by the Company under these plans were $21.1 million in 2007,
$17.3 million in 2006 and $17.0 million in 2005. The costs incurred in
each year reflect additional participants as a result of business
acquisitions.
SFAS No.
158 became effective for the Company as of December 31, 2006. The adoption
resulted in a negative transition effect on accumulated other comprehensive loss
of $18.5 million.
NOTE 18 – JOINTLY OWNED
FACILITIES
The
consolidated financial statements include the Company's 22.7 percent and
25.0 percent ownership interests in the assets, liabilities and expenses of the
Big Stone Station and the Coyote Station, respectively. Each owner of the Big
Stone and Coyote stations is responsible for financing its investment in the
jointly owned facilities.
The
Company's share of the Big Stone Station and Coyote Station operating expenses
was reflected in the appropriate categories of operating expenses in the
Consolidated Statements of Income.
At
December 31, the Company's share of the cost of utility plant in service and
related accumulated depreciation for the stations was as follows:
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Big
Stone Station:
|
|
|
|
|
|
|
Utility
plant in service
|
|
$ |
61,568
|
|
|
$ |
55,659
|
|
Less
accumulated depreciation
|
|
|
39,168
|
|
|
|
38,881
|
|
|
|
$ |
22,400
|
|
|
$ |
16,778
|
|
Coyote
Station:
|
|
|
|
|
|
|
|
|
Utility
plant in service
|
|
$ |
125,826
|
|
|
$ |
125,950
|
|
Less
accumulated depreciation
|
|
|
79,783
|
|
|
|
78,056
|
|
|
|
$ |
46,043
|
|
|
$ |
47,894
|
|
NOTE 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, transportation-only 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, transportation-only customers; however, on March
14, 2007, the WUTC suspended the tariff filing. On March 30, 2007, due to the
lack of approved tariffs, Cascade filed notice with the WUTC that it was
reactivating a nonregulated affiliate to make retail gas sales to non-core,
transportation-only customers. The WUTC consolidated the tariff proceeding with
Cascade's filing to re-establish an affiliate to make non-core,
transportation-only customer gas supply sales. On December 7, 2007, the WUTC
filed a complaint against Cascade alleging it is in violation of its most recent
general rate case settlement by not sharing gas supply sales margins with core
customers. Cascade filed an answer to the complaint on December 27, 2007. On
February 6, 2008, Cascade and the other participant parties entered into an
agreement settling the issues in all of the above proceedings. Under the
settlement, Cascade and its subsidiaries will discontinue the unbundled retail
sale of gas supply to non-core, transportation-only customers by November 1,
2008. Fifty percent of the net gas supply sales margins realized from non-core,
transportation-only customers by Cascade and its subsidiaries from April 1,
2007, through October 31, 2008, and fifty percent of the net gain, if any, from
the sale of such business, will be credited to Cascade’s core
customers. Cascade will also revise its gas procurement strategy for
core customers to enhance its ability to acquire gas supply from the Rocky
Mountain region. The settlement is subject to approval by the WUTC. Cascade has
reserved an amount for the crediting of the net gas supply sales margins
generated from April 1, 2007, through December 31, 2007. Cascade does not
consider the discontinuance of gas supply sales to non-core, transportation-only
customers to have a material impact on its financial position or results of
operations.
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 requested 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. On December 5, 2007, the MTPSC granted an interim
increase of $3.4 million annually. On February 8, 2008, Montana-Dakota and the
interveners reached a settlement stipulation (subject to MTPSC approval)
applicable to this filing whereby the $3.4 million of interim rate relief will
become final upon approval of the stipulation and an additional annual rate
increase of $730,000 will become effective January 1, 2009. As part of the
settlement, Montana-Dakota will be allowed to implement a fuel and purchased
power tracking mechanism on a shared basis, a margin sharing mechanism for
off-system sales, and modify certain decommissioning and net negative salvage
cost accruals. Also, Montana-Dakota will agree to not implement new rates from
any subsequent general rate filings before January 1, 2010.
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 Station 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 with additional resource
planning analysis reflecting changes in plant configuration as a result of the
participant withdrawals. On February 1, 2008, the NDPSC issued an order setting
supplemental hearings to commence April 28, 2008. The MNPUC is expected to rule
on the issuance of the related transmission Certificate of Need in April 2008
and the NDPSC is expected to rule on the advance determination of prudence in
June 2008.
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.
NOTE 20 – COMMITMENTS AND
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. In addition, Fidelity
has intervened or moved to intervene in three lawsuits filed by other gas
producers between June and September 2006 that challenge rules adopted by the
BER related to management of water associated with CBNG production. The state of
Wyoming has filed a similar suit in September 2006 and Fidelity moved to
intervene in that action. Fidelity is partly funding the Petroleum Association
of Wyoming’s intervention in two suits. The first was brought by two landowners
against the Wyoming State Engineer and the Wyoming Board of Control challenging
the state’s CBNG groundwater permitting practices. The second suit was brought
by the Wyoming Outdoor Council and Powder River Basin Resource Council appealing
the Wyoming Environmental Quality Council’s rules establishing water quality
standards relating to discharges of water associated with CBNG
production.
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 on federal lands 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. On January 15, 2008,
the Ninth Circuit denied the petition for rehearing.
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. In
response to comments, the BLM published an Air Quality Supplement to the draft
SEIS with the public comment period ending March 13, 2008. The final SEIS is
scheduled for release in July 2008 with a Record of Decision expected in
December 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. The other producers appealed the order on
December 26, 2007. Fidelity is not participating in the appeal.
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. In November 2007, the Wyoming State District Court
dismissed the suit. The Powder River Basin Resource Council did not
appeal.
Fidelity
is partly funding the Petroleum Association of Wyoming’s intervention in two
suits. In the first case, in which the Petroleum Association of Wyoming’s motion
to intervene has been conditionally granted, the Powder River Basin Resource
Council is funding litigation on behalf of two surface owners against the
Wyoming State Engineer and the Wyoming Board of Control. The plaintiffs in the
action, filed in Wyoming State District Court on June 14, 2007, seek a
declaratory judgment that current ground water permitting practices are
unlawful; that would mandate that the state adopt rules and procedures to ensure
that coalbed groundwater is managed in accordance with the Wyoming Constitution
and other laws; and that would prohibit the Wyoming State Engineer from issuing
permits to produce coalbed groundwater and permits to store coalbed groundwater
in reservoirs until the Wyoming State Engineer adopts such rules. In the second
case, the Wyoming Outdoor Council and Powder River Basin Resource Council filed
a petition on May 25, 2007, in the Wyoming State District Court seeking to
invalidate the Environmental Quality Council’s approval of amendments to Chapter
1 of the Wyoming Water Quality Rules and Regulations that subject certain
discharges of water produced in connection with CBNG development to stricter
water quality standards. The plaintiffs contend that the Wyoming DEQ’s actions
were arbitrary and capricious and that the rules are not in accordance with the
Clean Water Act.
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 were 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 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 December 31, 2007, Williston
Basin estimated that between 9.5 and 10 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 was held on February 5,
2008.
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. On December 12, 2007, motions were argued to the special
master concerning the application of certain legal principles to the production
of Williston Basin’s storage gas by Howell and Anadarko. The parties await a
decision.
As noted
above, Williston Basin estimates that as of December 31, 2007, Howell and
Anadarko had diverted between 9.5 and 10 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.
In expert
reports filed with the Wyoming State District Court in January 2008, Williston
Basin’s experts are of the opinion that all of the gas produced by Howell and
Anadarko is Williston Basin's gas and will have to be replaced. Williston
Basin’s experts estimate that the replacement cost of the gas produced by Howell
and Anadarko through October 2007 is approximately $106 million if injection is
completed by the end of the 2010 injection season. Williston Basin's experts
also estimate that Williston Basin will expend $8.7 million to mitigate the
damages that Williston Basin suffered during the period of Howell and Anadarko’s
production if the replacement gas is injected by the end of the 2010 injection
season. Williston Basin believes that its experts’ opinions are based on sound
law, economics, reservoir engineering, geology and geochemistry. The expert
reports filed by Howell and Anadarko claim that storage gas owned by Williston
Basin has migrated outside the EBSR into areas in which Howell and Anadarko have
oil and gas rights. They theorize that Williston Basin is accountable to Howell
and Anadarko for the migration of such gas. Although Howell and Anadarko have
not specified the amount of damages they seek to recover, Williston Basin
believes Howell and Anadarko’s proposed methodology for valuing their alleged
injury, if any, is flawed, inconsistent and lacking in factual and legal
support. Williston Basin continues to evaluate the Howell and Anadarko reports.
The parties have until May 14, 2008, to file rebuttal reports with the Wyoming
State District Court.
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. MBI also received notice in
January 2008 that the Portland Harbor Natural Resource Trustee Council intends
to perform an injury assessment to natural resources resulting from the release
of hazardous substances at the Harbor Superfund Site. The Trustee Council
indicates the injury determination is appropriate to facilitate early settlement
of damages and restoration for natural resource injuries.
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.
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. In November 2007, the Oregon Department of Environmental
Quality provided notice that additional ecological risk assessment of the site
was necessary. Completion of the assessment is anticipated by the end of
2008.
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.
Operating leases
The
Company leases certain equipment, facilities and land under operating lease
agreements. The amounts of annual minimum lease payments due under these leases
as of December 31, 2007, were $20.3 million in 2008, $16.0 million in
2009, $13.7 million in 2010, $10.3 million in 2011, $8.4 million
in 2012 and $48.8 million thereafter. Rent expense was $35.6 million,
$23.1 million and $33.3 million for the years ended December 31,
2007, 2006 and 2005, respectively.
Purchase
commitments
The
Company has entered into various commitments, largely natural gas and coal
supply, purchased power, natural gas transportation and construction materials
supply contracts. These commitments range from one to 53 years. The commitments
under these contracts as of December 31, 2007, were $479.2 million in
2008, $340.0 million in 2009, $233.4 million in 2010,
$163.7 million in 2011, $105.6 million in 2012 and $323.1 million
thereafter. Amounts purchased under various commitments for the years ended
December 31, 2007, 2006 and 2005, were approximately $857.0 million
(including the acquisition of Cascade as discussed in Note 2),
$265.8 million and $318.1 million, respectively. These commitments are
not reflected in the Company's consolidated financial statements.
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 3, 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 December 31, 2007, expire in 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
$1.4 million and was reflected on the Consolidated Balance Sheet at
December 31, 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 December 31, 2007, the fixed maximum amounts guaranteed
under these agreements aggregated $472.9 million. The amounts of scheduled
expiration of the maximum amounts guaranteed under these agreements aggregate
$86.3 million in 2008; $355.8 million in 2009; $400,000 in 2010; $23.0 million
in 2011; $1.2 million in 2012; $1.2 million in 2017; $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 $1.9 million and
was reflected on the Consolidated Balance Sheet at December 31, 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
December 31, 2007, the fixed maximum amounts guaranteed under these letters
of credit, which expire in 2008, aggregated $58.4 million. There were no
amounts outstanding under the above letters of credit at December 31,
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 December 31, 2007, the fixed
maximum amounts guaranteed under these agreements aggregated $22.9 million.
Scheduled expiration of the maximum amounts guaranteed under these agreements
aggregate $2.9 million in 2008 and $20.0 million in 2009. In the event
of Prairielands' default in its payment obligations, the subsidiary issuing the
guarantee for that particular obligation would be required to make payments
under its guarantee. The amount outstanding by Prairielands under the above
guarantees was $1.9 million, which was not reflected on the Consolidated
Balance Sheet at December 31, 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 in relation to the purchase of certain
maintenance items 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 December 31,
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 December 31,
2007, approximately $455 million of surety bonds were outstanding, which
were not reflected on the Consolidated Balance Sheet.
NOTE 21 - SUBSEQUENT
EVENT
On
January 31, 2008, Fidelity completed the acquisition of natural gas properties
located in Rusk County in eastern Texas, with a January 1, 2008, effective date.
The acquisition includes the purchase of 97 Bcfe of proven reserves. The
purchase price for these properties was approximately $235 million, subject to
accounting and purchase price adjustments customary with acquisitions of this
type.
SUPPLEMENTARY FINANCIAL
INFORMATION
Quarterly Data
(Unaudited)
The
following unaudited information shows selected items by quarter for the years
2007 and 2006:
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
(In thousands, except per
share amounts)
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
787,491
|
|
|
$ |
982,365
|
|
|
$ |
1,245,310
|
|
|
$ |
1,232,730
|
|
Operating
expenses
|
|
|
708,522
|
|
|
|
839,580
|
|
|
|
1,066,154
|
|
|
|
1,076,520
|
|
Operating
income
|
|
|
78,969
|
|
|
|
142,785
|
|
|
|
179,156
|
|
|
|
156,210
|
|
Income
from continuing operations
|
|
|
41,407
|
|
|
|
82,036
|
|
|
|
104,497
|
|
|
|
94,846
|
|
Income
(loss) from discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations,
net of tax
|
|
|
5,255
|
|
|
|
7,439
|
|
|
|
96,765
|
|
|
|
(125 |
) |
Net
income
|
|
|
46,662
|
|
|
|
89,475
|
|
|
|
201,262
|
|
|
|
94,721
|
|
Earnings
per common share – basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
|
|
|
.23
|
|
|
|
.45
|
|
|
|
.57
|
|
|
|
.52
|
|
Discontinued
operations, net of tax
|
|
|
.03
|
|
|
|
.04
|
|
|
|
.53
|
|
|
|
---
|
|
Earnings
per common share – basic
|
|
|
.26
|
|
|
|
.49
|
|
|
|
1.10
|
|
|
|
.52
|
|
Earnings
per common share – diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
|
|
|
.23
|
|
|
|
.45
|
|
|
|
.57
|
|
|
|
.52
|
|
Discontinued
operations, net of tax
|
|
|
.02
|
|
|
|
.04
|
|
|
|
.53
|
|
|
|
---
|
|
Earnings
per common share – diluted
|
|
|
.25
|
|
|
|
.49
|
|
|
|
1.10
|
|
|
|
.52
|
|
Weighted
average common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
181,341
|
|
|
|
181,847
|
|
|
|
182,192
|
|
|
|
182,391
|
|
Diluted
|
|
|
182,337
|
|
|
|
182,746
|
|
|
|
183,171
|
|
|
|
183,342
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
803,519
|
|
|
$ |
961,435
|
|
|
$ |
1,173,678
|
|
|
$ |
1,065,907
|
|
Operating
expenses
|
|
|
712,451
|
|
|
|
839,205
|
|
|
|
992,249
|
|
|
|
937,559
|
|
Operating
income
|
|
|
91,068
|
|
|
|
122,230
|
|
|
|
181,429
|
|
|
|
128,348
|
|
Income
from continuing operations
|
|
|
52,445
|
|
|
|
68,451
|
|
|
|
107,110
|
|
|
|
79,772
|
|
Income
from discontinued operations,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
of tax
|
|
|
801
|
|
|
|
2,991
|
|
|
|
1,377
|
|
|
|
2,810
|
|
Net
income
|
|
|
53,246
|
|
|
|
71,442
|
|
|
|
108,487
|
|
|
|
82,582
|
|
Earnings
per common share – basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
|
|
|
.29
|
|
|
|
.38
|
|
|
|
.59
|
|
|
|
.44
|
|
Discontinued
operations, net of tax
|
|
|
.01
|
|
|
|
.02
|
|
|
|
.01
|
|
|
|
.02
|
|
Earnings
per common share – basic
|
|
|
.30
|
|
|
|
.40
|
|
|
|
.60
|
|
|
|
.46
|
|
Earnings
per common share – diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
operations
|
|
|
.29
|
|
|
|
.38
|
|
|
|
.59
|
|
|
|
.44
|
|
Discontinued
operations, net of tax
|
|
|
---
|
|
|
|
.01
|
|
|
|
.01
|
|
|
|
.01
|
|
Earnings
per common share – diluted
|
|
|
.29
|
|
|
|
.39
|
|
|
|
.60
|
|
|
|
.45
|
|
Weighted
average common shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
179,823
|
|
|
|
179,911
|
|
|
|
180,291
|
|
|
|
180,900
|
|
Diluted
|
|
|
180,915
|
|
|
|
181,107
|
|
|
|
181,307
|
|
|
|
182,094
|
|
Certain
Company operations are highly seasonal and revenues from and certain expenses
for such operations may fluctuate significantly among quarterly periods.
Accordingly, quarterly financial information may not be indicative of results
for a full year.
Natural Gas and Oil Activities
(Unaudited)
Fidelity
is involved in the acquisition, exploration, development and production of
natural gas and oil resources. Fidelity's activities include the acquisition of
producing properties with potential development opportunities, exploratory
drilling and the operation and development of production properties. Fidelity
shares revenues and expenses from the development of specified properties
located in the Rocky Mountain and Mid-Continent regions of the United States and
in and around the Gulf of Mexico in proportion to its ownership
interests.
Fidelity
owns in fee or holds natural gas leases for the properties it operates in
Colorado, Montana, North Dakota, Texas, Utah and Wyoming. These rights are in
the Bonny Field located in eastern Colorado, the Baker Field in southeastern
Montana and southwestern North Dakota, the Bowdoin area located in north-central
Montana, the Powder River Basin of Montana and Wyoming, the Bakken formation in
North Dakota, the Paradox Basin of Utah, the Tabasco and Texan Gardens fields in
Texas, and the Big Horn Basin in Wyoming.
The
information that follows includes Fidelity's proportionate share of all its
natural gas and oil interests.
The
following table sets forth capitalized costs and accumulated depreciation,
depletion and amortization related to natural gas and oil producing activities
at December 31:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Subject
to amortization
|
|
$ |
1,750,233
|
|
|
$ |
1,442,533
|
|
|
$ |
1,198,669
|
|
Not
subject to amortization
|
|
|
142,524
|
|
|
|
163,975
|
|
|
|
82,291
|
|
Total
capitalized costs
|
|
|
1,892,757
|
|
|
|
1,606,508
|
|
|
|
1,280,960
|
|
Less
accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
|
depletion
and amortization
|
|
|
681,101
|
|
|
|
558,980
|
|
|
|
456,554
|
|
Net
capitalized costs
|
|
$ |
1,211,656
|
|
|
$ |
1,047,528
|
|
|
$ |
824,406
|
|
Capital
expenditures, including those not subject to amortization, related to natural
gas and oil producing activities were as follows:
Years
ended December 31,
|
|
|
2007 |
* |
|
|
2006 |
* |
|
|
2005 |
* |
|
|
(In
thousands)
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
$ |
426
|
|
|
$ |
75,520
|
|
|
$ |
149,253
|
|
Unproved
properties
|
|
|
17,731
|
|
|
|
27,383
|
|
|
|
16,920
|
|
Exploration
|
|
|
48,744
|
|
|
|
24,970
|
|
|
|
24,385
|
|
Development**
|
|
|
214,433
|
|
|
|
196,423
|
|
|
|
125,633
|
|
Total
capital expenditures
|
|
$ |
281,334
|
|
|
$ |
324,296
|
|
|
$ |
316,191
|
|
|
*
|
Excludes net additions to
property, plant and equipment related to the recognition of future
liabilities associated with the plugging and abandonment of natural gas
and oil wells in accordance with SFAS No. 143, as discussed in Note 11, of
$5.4 million, $8.7 million and $2.5 million for the years ended
December 31, 2007, 2006 and 2005,
respectively.
|
**
|
Includes expenditures for
proved undeveloped reserves of $74.6 million, $44.7 million and $37.0
million for the years ended December 31, 2007, 2006 and 2005,
respectively.
|
The
following summary reflects income resulting from the Company's operations of
natural gas and oil producing activities, excluding corporate overhead and
financing costs:
Years
ended December 31,
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Sales
to affiliates
|
|
$ |
226,706
|
|
|
$ |
232,799
|
|
|
$ |
275,828
|
|
Sales
to external customers
|
|
|
287,557
|
|
|
|
244,499
|
|
|
|
159,390
|
|
Production
costs
|
|
|
123,924
|
|
|
|
106,387
|
|
|
|
88,068
|
|
Depreciation,
depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
amortization*
|
|
|
124,599
|
|
|
|
104,741
|
|
|
|
84,099
|
|
Pretax
income
|
|
|
265,740
|
|
|
|
266,170
|
|
|
|
263,051
|
|
Income
tax expense
|
|
|
98,729
|
|
|
|
100,584
|
|
|
|
99,071
|
|
Results
of operations for
|
|
|
|
|
|
|
|
|
|
|
|
|
producing
activities
|
|
$ |
167,011
|
|
|
$ |
165,586
|
|
|
$ |
163,980
|
|
*
|
Includes accretion of discount
for asset retirement obligations of $2.5 million, $2.3 million and $1.5
million for the years ended December 31, 2007, 2006 and 2005,
respectively, in accordance with SFAS No. 143, as discussed in Note
11.
|
The
following table summarizes the Company's estimated quantities of proved natural
gas and oil reserves at December 31, 2007, 2006 and 2005, and reconciles
the changes between these dates. Estimates of economically recoverable natural
gas and oil reserves and future net revenues therefrom are based upon a number
of variable factors and assumptions. For these reasons, estimates of
economically recoverable reserves and future net revenues may vary from actual
results.
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(MMcf/MBbls)
|
|
Proved
developed and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
undeveloped
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at beginning of year
|
|
|
538,100
|
|
|
|
27,100
|
|
|
|
489,100
|
|
|
|
21,200
|
|
|
|
453,200
|
|
|
|
17,100
|
|
Production
|
|
|
(62,798 |
) |
|
|
(2,365 |
) |
|
|
(62,100 |
) |
|
|
(2,100 |
) |
|
|
(59,400 |
) |
|
|
(1,700 |
) |
Extensions
and discoveries
|
|
|
77,701
|
|
|
|
3,772
|
|
|
|
123,600
|
|
|
|
2,800
|
|
|
|
74,400
|
|
|
|
500
|
|
Improved
recovery
|
|
|
444
|
|
|
|
1,614
|
|
|
|
---
|
|
|
|
---
|
|
|
|
---
|
|
|
|
2,600
|
|
Purchases
of proved reserves
|
|
|
2
|
|
|
|
6
|
|
|
|
21,700
|
|
|
|
4,800
|
|
|
|
57,400
|
|
|
|
3,700
|
|
Sales
of reserves in place
|
|
|
(6 |
) |
|
|
(42 |
) |
|
|
---
|
|
|
|
---
|
|
|
|
(1,300 |
) |
|
|
(100 |
) |
Revisions
of previous
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
estimates
|
|
|
(29,706 |
) |
|
|
527
|
|
|
|
(34,200 |
) |
|
|
400
|
|
|
|
(35,200 |
) |
|
|
(900 |
) |
Balance
at end of year
|
|
|
523,737
|
|
|
|
30,612
|
|
|
|
538,100
|
|
|
|
27,100
|
|
|
|
489,100
|
|
|
|
21,200
|
|
Proved
developed reserves:
January
1, 2005
|
|
|
376,400
|
|
|
|
16,400
|
|
December
31, 2005
|
|
|
416,700
|
|
|
|
20,400
|
|
December
31, 2006
|
|
|
412,900
|
|
|
|
22,400
|
|
December 31,
2007
|
|
|
420,137
|
|
|
|
25,658
|
|
The
Company's interests in natural gas and oil reserves are located in the United
States and in and around the Gulf of Mexico.
The
standardized measure of the Company's estimated discounted future net cash flows
of total proved reserves associated with its various natural gas and oil
interests at December 31 was as follows:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Future
cash inflows
|
|
$ |
5,302,300
|
|
|
$ |
3,831,000
|
|
|
$ |
4,778,700
|
|
Future
production costs
|
|
|
1,415,700
|
|
|
|
1,084,000
|
|
|
|
1,095,400
|
|
Future
development costs
|
|
|
237,600
|
|
|
|
240,600
|
|
|
|
106,400
|
|
Future
net cash flows before income taxes
|
|
|
3,649,000
|
|
|
|
2,506,400
|
|
|
|
3,576,900
|
|
Future
income tax expense
|
|
|
1,179,900
|
|
|
|
759,300
|
|
|
|
1,205,700
|
|
Future
net cash flows
|
|
|
2,469,100
|
|
|
|
1,747,100
|
|
|
|
2,371,200
|
|
10%
annual discount for estimated timing of
|
|
|
|
|
|
|
|
|
|
|
|
|
cash
flows
|
|
|
1,107,200
|
|
|
|
743,600
|
|
|
|
950,400
|
|
Discounted
future net cash flows relating to
|
|
|
|
|
|
|
|
|
|
|
|
|
proved
natural gas and oil reserves
|
|
$ |
1,361,900
|
|
|
$ |
1,003,500
|
|
|
$ |
1,420,800
|
|
The
following are the sources of change in the standardized measure of discounted
future net cash flows by year:
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
thousands)
|
|
Beginning
of year
|
|
$ |
1,003,500
|
|
|
$ |
1,420,800
|
|
|
$ |
821,500
|
|
Net
revenues from production
|
|
|
(354,100 |
) |
|
|
(348,400 |
) |
|
|
(402,900 |
) |
Change
in net realization
|
|
|
527,900
|
|
|
|
(860,700 |
) |
|
|
777,700
|
|
Extensions
and discoveries, net of future
|
|
|
|
|
|
|
|
|
|
|
|
|
production-related
costs
|
|
|
310,300
|
|
|
|
293,300
|
|
|
|
294,800
|
|
Improved
recovery, net of future production-related costs
|
|
|
38,100
|
|
|
|
---
|
|
|
|
91,600
|
|
Purchases
of proved reserves, net of future production-related costs
|
|
|
200
|
|
|
|
99,800
|
|
|
|
258,300
|
|
Sales
of reserves in place
|
|
|
(1,300 |
) |
|
|
---
|
|
|
|
(12,500 |
) |
Changes
in estimated future development costs
|
|
|
(22,600 |
) |
|
|
(25,600 |
) |
|
|
(13,400 |
) |
Development costs incurred during the current year
|
|
|
103,000
|
|
|
|
60,900
|
|
|
|
40,900
|
|
Accretion
of discount
|
|
|
133,700
|
|
|
|
193,800
|
|
|
|
106,900
|
|
Net
change in income taxes
|
|
|
(212,500 |
) |
|
|
295,700
|
|
|
|
(339,700 |
) |
Revisions
of previous estimates
|
|
|
(163,700 |
) |
|
|
(123,200 |
) |
|
|
(200,500 |
) |
Other
|
|
|
(600 |
) |
|
|
(2,900 |
) |
|
|
(1,900 |
) |
Net
change
|
|
|
358,400
|
|
|
|
(417,300 |
) |
|
|
599,300
|
|
End
of year
|
|
$ |
1,361,900
|
|
|
$ |
1,003,500
|
|
|
$ |
1,420,800
|
|
The
estimated discounted future cash inflows from estimated future production of
proved reserves were computed using year-end natural gas and oil prices. Future
development and production costs attributable to proved reserves were computed
by applying year-end costs to be incurred in producing and further developing
the proved reserves. Future development costs estimated to be spent in each of
the next three years to develop proved undeveloped reserves as of December 31,
2007, are $94.5 million in 2008, $48.0 million in 2009 and $19.2 million in
2010. Future income tax expenses were computed by applying statutory tax rates,
adjusted for permanent differences and tax credits, to estimated net future
pretax cash flows.
The
standardized measure of discounted future net cash flows does not purport to
represent the fair market value of natural gas and oil properties. There are
significant uncertainties inherent in estimating quantities of proved reserves
and in projecting rates of production and the timing and amount of future costs.
In addition, future realization of natural gas and oil prices over the remaining
reserve lives may vary significantly from current prices.
ITEM 9. CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. 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 that 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 quarter ended December 31, 2007, that have materially
affected, or are reasonably likely to materially affect, the Company's internal
control over financial reporting.
MANAGEMENT'S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The
information required by this item is included in this Form 10-K at Item 8 –
Management's Report on Internal Control Over Financial Reporting.
ATTESTATION REPORT OF THE REGISTERED
PUBLIC ACCOUNTING FIRM
The
information required by this item is included in this Form 10-K at Item 8 –
Report of Independent Registered Public Accounting Firm.
ITEM 9B. OTHER
INFORMATION
PART
III
ITEM 10. DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The
information required by this item is included under the captions "Item 1.
Election of Directors – Director Nominees for One Year Term," "Continuing
Incumbent Directors," "Information Concerning Executive Officers," the first
paragraph, the second sentence of the second paragraph and third paragraph under
"Corporate Governance – Audit Committee," "Corporate Governance – Code of
Conduct," the last paragraph under "Corporate Governance – Board Meetings and
Committees" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the
Proxy Statement, which information is incorporated herein by
reference.
ITEM 11. EXECUTIVE
COMPENSATION
The
information required by this item is included under the caption "Executive
Compensation" in the Proxy Statement, which information is incorporated herein
by reference.
ITEM 12. SECURITY OWNERSHIP
OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
EQUITY COMPENSATION PLAN
INFORMATION
The
following table includes information as of December 31, 2007, with respect to
the Company's equity compensation plans:
Plan
Category
|
(a)
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
|
(b)
Weighted
average exercise price of outstanding options, warrants and
rights
|
(c)
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in
column (a))
|
Equity
compensation plans approved by
stockholders
(1)
|
1,568,549
(2)
|
$16.88
|
7,816,197
(3)(4)
|
Equity
compensation plans not approved
by
stockholders
(5)
|
613,319
|
12.90
|
2,323,915
(6)
|
Total
|
2,181,868
|
$15.76
|
10,140,112
|
(1)
|
Consists
of the 1992 Key Employee Stock Option Plan, the 1997 Non-Employee Director
Long-Term Incentive Plan, the Long-Term Performance-Based Incentive Plan
(formerly known as the 1997 Executive Long-Term Incentive Plan) and the
Non-Employee Director Stock Compensation
Plan.
|
(2)
|
Includes
685,960 performance shares.
|
(3)
|
In
addition to being available for future issuance upon exercise of options,
357,757 shares under the 1997 Non-Employee Director Long-Term Incentive
Plan may instead be issued in connection with stock appreciation rights,
restricted stock, performance units, performance shares or other
equity-based awards, and 6,320,232 shares under the Long-Term
Performance-Based Incentive Plan may instead be issued in connection with
stock appreciation rights, restricted stock, performance units,
performance shares or other equity-based
awards.
|
(4)
|
This
amount also includes 459,952 shares available for issuance under the
Non-Employee Director Stock Compensation Plan. Under this plan, in
addition to a cash retainer, nonemployee Directors are awarded 4,050
(adjusted for the three-for-two stock split in July 2006) shares following
the Company's annual meeting of stockholders. Additionally, a nonemployee
Director may acquire additional shares under the plan in lieu of receiving
the cash portion of the Director's retainer or
fees.
|
(5)
Consists of the 1998 Option Award Program and the Group Genius Innovation
Plan.
(6)
|
In
addition to being available for future issuance upon exercise of options,
220,050 shares under the Group Genius Innovation Plan may instead be
issued in connection with stock appreciation rights, restricted stock,
restricted stock units, performance units, performance stock or other
equity-based awards.
|
The
following equity compensation plans have not been approved by the Company's
stockholders.
The 1998 Option Award
Program
The 1998
Option Award Program is a broad-based plan adopted by the Board of Directors,
effective February 12, 1998. The plan permits the grant of nonqualified stock
options to employees of the Company and its subsidiaries. The maximum number of
shares that may be issued under the plan is 3,795,330. Shares granted may be
authorized but unissued shares, treasury shares, or shares purchased on the open
market. Option exercise prices are equal to the market value of the Company's
shares on the date of the option grant. Optionees receive dividend equivalents
on their options, with any credited dividends paid in cash to the optionee if
the option vests, or forfeited if the option is forfeited. Vested options remain
exercisable for one year following termination of employment due to death or
disability and for three months following termination of employment for any
other reason.
Unvested
options are forfeited upon termination of employment. Subject to the terms and
conditions of the plan, the plan's administrative committee determines the
number of shares subject to options granted to each participant and the other
terms and conditions pertaining to such options, including vesting provisions.
All options become immediately exercisable in the event of a change in control
of the Company.
In 1998,
337 options (adjusted for the three-for-two stock splits in July 1998, October
2003 and July 2006) were granted to each of approximately 2,200 employees. No
officers received grants. These options vested on March 2, 2001. In 2001, 450
options (adjusted for the three-for-two stock splits in October 2003 and July
2006) were granted to each of approximately 5,900 employees. No officers
received grants. These options vested on February 13, 2004. As of December 31,
2007, options covering 613,319 shares of common stock were outstanding under the
plan and 2,103,865 shares remained available for future grant. Options covering
1,078,146 shares had been exercised.
The Group Genius Innovation
Plan
The Group
Genius Innovation Plan was adopted by the Board of Directors, effective May 17,
2001, to encourage employees to share ideas for new business directions for the
Company and to reward them when the idea becomes profitable. Employees of the
Company and its subsidiaries who are selected by the plan's administrative
committee are eligible to participate in the plan. Officers and Directors are
not eligible to participate. The plan permits the granting of nonqualified stock
options, stock appreciation rights, restricted stock, restricted stock units,
performance units, performance stock and other awards. The maximum number of
shares that may be issued under the plan is 223,150. Shares granted under the
plan may be authorized but unissued shares, treasury shares or shares purchased
on the open market. Restricted stockholders have voting rights and, unless
determined otherwise by the plan's administrative committee, receive dividends
paid on the restricted stock. Dividend equivalents payable in cash may be
granted with respect to options and performance shares. The plan's
administrative committee determines the number of shares or units subject to
awards, and the other terms and conditions of the awards, including vesting
provisions and the effect of employment termination. Upon a change in control of
the Company, all options and stock appreciation rights become immediately vested
and exercisable, all restricted stock becomes immediately vested, all restricted
stock units become immediately vested and are paid out in cash, and target
payout opportunities under all performance units, performance stock, and other
awards are deemed to be fully earned, with awards denominated in stock paid out
in shares and awards denominated in units paid out in cash. As of December 31,
2007, 3,100 shares of stock had been granted to 56
employees.
The
remaining information required by this item is included under the caption
"Security Ownership” of the Proxy Statement, which is incorporated herein by
reference.
ITEM 13. CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The
information required by this item is included under the captions “Related Person
Disclosure” and “Corporate Governance – Director Independence” in the Proxy
Statement, which information is incorporated herein by reference.
ITEM 14. PRINCIPAL
ACCOUNTANT FEES AND SERVICES
The
information required by this item is included under the caption "Accounting and
Auditing Matters" of the Proxy Statement, which information is incorporated
herein by reference.
PART
IV
ITEM 15. EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
(a)
|
FINANCIAL STATEMENTS, FINANCIAL
STATEMENT SCHEDULES AND
EXHIBITS
|
Index to Financial Statements and
Financial Statement Schedules
1. Financial
Statements
The
following consolidated financial statements required under this item are
included under Item 8 – Financial Statements and Supplementary
Data.
Consolidated
Statements of Income for each of the three years in the period ended
December 31, 2007
Consolidated
Balance Sheets at December 31, 2007 and 2006
Consolidated
Statements of Common Stockholders' Equity for each of the three years in the
period ended December 31, 2007
Consolidated
Statements of Cash Flows for each of the three years in the period ended
December 31, 2007
Notes to
Consolidated Financial Statements
2. Financial Statement
Schedules
MDU
Resources Group, Inc.
|
Schedule
II - Consolidated Valuation and Qualifying Accounts
|
Years
Ended December 31, 2007, 2006 and 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
Balance
at
|
|
Charged
to
|
|
|
|
|
|
Balance
|
|
|
Beginning
|
|
Costs
and
|
|
|
|
|
|
at
End
|
Description
|
|
of
Year
|
|
Expenses
|
|
Other*
|
|
Deductions**
|
|
of
Year
|
|
|
(In
thousands)
|
Allowance
for doubtful accounts:
|
|
|
|
|
|
|
|
|
2007
|
|
$7,725
|
|
$8,799
|
|
$5,533
|
|
$7,422
|
|
$14,635
|
2006
|
|
8,031
|
|
5,470
|
|
1,576
|
|
7,352
|
|
7,725
|
2005
|
|
6,801
|
|
4,870
|
|
1,675
|
|
5,315
|
|
8,031
|
* Allowance
for doubtful accounts for companies acquired and
recoveries.
|
** Uncollectible accounts
written off.
|
All other
schedules are omitted because of the absence of the conditions under which they
are required, or because the information required is included in the Company's
Consolidated Financial Statements and Notes thereto.
3.
Exhibits
2
|
Agreement
and Plan of Merger by and among MDU Resources Group, Inc., Firemoon
Acquisition, Inc. and Cascade Natural Gas Corporation dated as of July 8,
2006, filed by Cascade Natural Gas Corporation as Exhibit 2.1 to Form 8-K
dated July 10, 2006, in File No. 1-7196* (1)
|
|
|
3(a)
|
Restated
Certificate of Incorporation of the Company, as amended, filed as Exhibit
3.1 to Form 8-A/A, as amended, filed on June 27, 2007, in File No.
1-3480*
|
|
|
3(b)
|
Company
Bylaws, as amended, filed as Exhibit 3.1 to Form 8-K dated November 16,
2006, filed on November 22, 2006, in File No. 1-3480*
|
|
|
3(c)
|
Certificate
of Designations of Series B Preference Stock of the Company, as amended,
filed as Exhibit 3(a) to Form 10-Q for the quarter ended September 30,
2002, filed on November 14, 2002, in File No. 1-3480*
|
|
|
4(a)
|
Indenture
of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth
Supplemental Indenture, dated as of April 21, 1992, and the
Forty-Sixth through Forty-Ninth Supplements thereto between the Company
and the New York Trust Company (The Bank of New York, successor Corporate
Trustee) and A. C. Downing (Douglas J. MacInnes, successor
Co-Trustee), filed as Exhibit 4(a) to Form S-3, in Registration No.
33-66682; and Exhibits 4(e), 4(f) and 4(g) to Form S-8, in Registration
No. 33-53896; and Exhibit 4(c)(i) to Form S-3, in Registration No.
333-49472*
|
|
|
4(b)
|
Fiftieth
Supplemental Indenture, dated as of December 15, 2003, filed as Exhibit
4(e) to Form S-8 on January 21, 2004, in Registration No.
333-112035*
|
|
|
4(c)
|
Rights
Agreement, dated as of November 12, 1998, between the Company and Wells
Fargo Bank Minnesota, N.A. (formerly known as Norwest Bank Minnesota,
N.A.), Rights Agent, filed as Exhibit 4.1 to Form 8-A on November 12,
1998, in File No. 1-3480*
|
|
|
4(d)
|
Indenture,
dated as of December 15, 2003, between the Company and The Bank of New
York, as trustee, filed as Exhibit 4(f) to Form S-8 on January 21, 2004,
in Registration No. 333-112035*
|
|
|
4(e)
|
Certificate
of Adjustment to Purchase Price and Redemption Price, as amended and
restated, pursuant to the Rights Agreement, dated as of November 12, 1998,
filed as Exhibit 4(c) to Form 10-Q for the quarter ended June 30, 2006,
filed on August 4, 2006, in File No. 1-3480*
|
|
|
4(f)
|
Centennial
Energy Holdings, Inc. Master Shelf Agreement, dated April 29, 2005, among
Centennial Energy Holdings, Inc. and the Prudential Insurance Company of
America, filed as Exhibit 4(a) to Form 10-Q for the quarter ended June 30,
2005, filed on August 3, 2005, in File No. 1-3480*
|
|
|
4(g)
|
Letter
Amendment No. 1 to Amended and Restated Master Shelf Agreement, dated May
17, 2006, among Centennial Energy Holdings, Inc., The Prudential Insurance
Company of America, and certain investors described in the Letter
Amendment filed as Exhibit 4(a) to Form 10-Q for the quarter ended June
30, 2006, filed on August 4, 2006, in File No. 1-3480*
|
|
|
4(h)
|
MDU
Resources Group, Inc. Credit Agreement, dated June 21, 2005, among MDU
Resources Group, Inc., Wells Fargo Bank, National Association, as
Administrative Agent, and The Other Financial Institutions Party thereto,
filed as Exhibit 4(b) to Form 10-Q for the quarter ended June 30, 2005,
filed on August 3, 2005, in File No. 1-3480*
|
|
|
4(i)
|
First
Amendment, dated June 30, 2006, to Credit Agreement, dated June 21, 2005,
among MDU Resources Group, Inc., Wells Fargo Bank, National Association,
as administrative agent, and certain lenders described in the credit
agreement, filed as Exhibit 4(b) to Form 10-Q for the quarter ended June
30, 2006, filed on August 4, 2006, in File No. 1-3480*
|
|
|
4(j)
|
Centennial
Energy Holdings, Inc. Credit Agreement, dated December 13, 2007, among
Centennial Energy Holdings, Inc., U.S. Bank National Association, as
Administrative Agent, and The Other Financial Institutions party
thereto**
|
|
|
4(k)
|
MDU
Resources Group, Inc. Term Loan Agreement, dated June 29, 2007, among MDU
Resources
Group,
Inc., Wells Fargo Bank, National Association, as Administrative Agent, and
The Other Financial
Institutions
party thereto, filed as Exhibit 4 to Form 10-Q for the quarter ended June
30, 2007, filed on
August
8, 2007, in File No. 1-3480*
|
|
|
4(l)
|
MDU
Energy Capital, LLC Master Shelf Agreement, dated as of August 9, 2007,
among MDU Energy Capital, LLC and the Prudential Insurance Company of
America, filed as Exhibit 4 to Form 8-K dated August 16, 2007, filed on
August 16, 2007, in File No. 1-3480*
|
|
|
4(m)
|
Indenture
dated as of August 1, 1992, between Cascade Natural Gas Corporation and
The Bank of New York relating to Medium-Term Notes, filed by Cascade
Natural Gas Corporation as Exhibit 4 to Form 8-K dated August 12, 1992, in
File No. 1-7196*
|
|
|
4(n)
|
First
Supplemental Indenture dated as of October 25, 1993, between Cascade
Natural Gas Corporation
and
The Bank of New York relating to Medium-Term Notes and the 7.5% Notes due
November 15,
2031,
filed by Cascade Natural Gas Corporation as Exhibit 4 to Form 10-Q for the
quarter ended June 30,
1993,
in File No. 1-7196*
|
|
|
4(o)
|
Second
Supplemental Indenture, dated January 25, 2005, between Cascade Natural
Gas Corporation and The Bank of New York, as trustee, filed by Cascade
Natural Gas Corporation as Exhibit 4.1 to Form 8-K dated January 25, 2005,
filed on January 26, 2005, in File No. 1-7196*
|
|
|
4(p)
|
Third
Supplemental Indenture dated as of March 8, 2007, between Cascade Natural
Gas Corporation and The Bank of New York Trust Company, N.A., as Successor
Trustee, filed by Cascade Natural Gas Corporation as Exhibit 4.1 to Form
8-K dated March 8, 2007, filed on March 8, 2007, in File No.
1-7196*
|
|
|
+10(a)
|
1992
Key Employee Stock Option Plan, as revised, filed as Exhibit 10(a) to Form
10-K for the year ended December 31, 2006, filed on February 21, 2007, in
File No. 1-3480*
|
|
|
+10(b)
|
Supplemental
Income Security Plan, as amended and restated, effective November 16,
2006, filed as Exhibit 10(b) to Form 10-K for the year ended December 31,
2006, filed on February 21, 2007, in File No. 1-3480*
|
|
|
+10(c)
|
Directors'
Compensation Policy, as amended February 15, 2007, filed as Exhibit 10(c)
to Form 10-K for the year ended December 31, 2006, filed on February 21,
2007, in File No. 1-3480*
|
|
|
+10(d)
|
Deferred
Compensation Plan for Directors, as amended, filed as Exhibit 10(e) to
Form 10-K for the year ended December 31, 2002, filed on February 28,
2003, in File No. 1-3480*
|
|
|
+10(e)
|
Non-Employee
Director Stock Compensation Plan, as revised, filed as Exhibit 10(e) to
Form 10-K for the year ended December 31, 2006, filed on February 21,
2007, in File No. 1-3480*
|
|
|
+10(f)
|
1997
Non-Employee Director Long-Term Incentive Plan, as revised, filed as
Exhibit 10(f) to Form 10-K for the year ended December 31, 2006, filed on
February 21, 2007, in File No. 1-3480*
|
|
|
+10(g)
|
Change
of Control Employment Agreement between the Company and Terry D.
Hildestad, filed as Exhibit 10(d) to Form 10-Q for the quarter ended
September 30, 2002, filed on November 14, 2002, in File No.
1-3480*
|
|
|
+10(h)
|
Change
of Control Employment Agreement between the Company and Bruce T. Imsdahl,
filed as Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2004,
filed on August 6, 2004, in File No. 1-3480*
|
|
|
+10(i)
|
Change
of Control Employment Agreement between the Company and Vernon A. Raile,
filed as Exhibit 10(f) to Form 10-Q for the quarter ended September 30,
2002, filed on November 14, 2002, in File No. 1-3480*
|
|
|
+10(j)
|
Change
of Control Employment Agreement between the Company and Paul K. Sandness,
filed as Exhibit 10(e) to Form 10-Q for the quarter ended June 30, 2004,
filed on August 6, 2004, in File No. 1-3480*
|
|
|
+10(k)
|
Change
of Control Employment Agreement between the Company and William E.
Schneider, filed as Exhibit 10(h) to Form 10-Q for the quarter ended
September 30, 2002, filed on November 14, 2002, in File No.
1-3480*
|
|
|
+10(l)
|
Change
of Control Employment Agreement between the Company and John G. Harp,
filed as Exhibit 10(p) to Form 10-K for the year ended December 31, 2006,
filed on February 21, 2007, in File No. 1-3480*
|
|
|
+10(m)
|
1998
Option Award Program, as revised, filed as Exhibit 10(q) to Form 10-K for
the year ended December 31, 2006, filed on February 21, 2007, in File No.
1-3480*
|
|
|
+10(n)
|
Group
Genius Innovation Plan, as revised, filed as Exhibit 10(r) to Form 10-K
for the year ended December 31, 2006, filed on February 21, 2007, in File
No. 1-3480*
|
|
|
10(o)
|
Purchase
and Sale Agreement, dated January 4, 2008, between Fidelity and EnerVest
Energy Institutional Fund IX, L.P., EnerVest Energy Institutional Fund
IX-WI, L.P., and Everstar Energy, LLC**
|
|
|
+10(p)
|
WBI
Holdings, Inc. Executive Incentive Compensation Plan and Rules and
Regulations, as amended February 26, 2007, filed as Exhibit 10(d) to Form
10-Q for the quarter ended March 31, 2007, filed on May 8, 2007, in File
No. 1-3480*
|
|
|
+10(q)
|
Knife
River Corporation Executive Incentive Compensation Plan and Rules and
Regulations, as amended February 26, 2007, filed as Exhibit 10(e) to Form
10-Q for the quarter ended March 31, 2007, filed on May 8, 2007, in File
No. 1-3480*
|
|
|
+10(r)
|
Long-Term
Performance-Based Incentive Plan, as revised, filed as Exhibit 10(y) to
Form 10-K for the year ended December 31, 2006, filed on February 21,
2007, in File No. 1-3480*
|
|
|
+10(s)
|
MDU
Resources Group, Inc. Executive Incentive Compensation Plan and Rules and
Regulations, as amended November 15, 2007**
|
|
|
+10(t)
|
Montana-Dakota
Utilities Co. Executive Incentive Compensation Plan and Rules and
Regulations, as amended November 15, 2007**
|
|
|
+10(u)
|
Change
of Control Employment Agreement between the Company and Steven L. Bietz,
filed as Exhibit 10(ai) to Form 10-K for the year ended December 31, 2005,
filed on February 22, 2006, in File No. 1-3480*
|
|
|
+10(v)
|
Change
of Control Employment Agreement between the Company and Nicole A. Kivisto,
filed as Exhibit 10(aj) to Form 10-K for the year ended December 31, 2005,
filed on February 22, 2006, in File No. 1-3480*
|
|
|
+10(w)
|
Change
of Control Employment Agreement between the Company and Doran N. Schwartz,
filed as Exhibit 10(ak) to Form 10-K for the year ended December 31, 2005,
filed on February 22, 2006, in File No. 1-3480*
|
|
|
+10(x)
|
Supplemental
Executive Retirement Plan for John G. Harp, dated December 4, 2006, filed
as Exhibit 10(ag) to Form 10-K for the year ended December 31, 2006, filed
on February 21, 2007, in File No. 1-3480*
|
|
|
+10(y)
|
Employment
Letter for John G. Harp, dated July 20, 2005, filed as Exhibit 10(ah) to
Form 10-K for the year ended December 31, 2006, filed on February 21,
2007, in File No. 1-3480*
|
|
|
+10(z)
|
Form
of Performance Share Award Agreement under the Long-Term Performance-Based
Incentive Plan, as amended November 15, 2007**
|
|
|
10(aa)
|
Centennial
Power, Inc. and Colorado Energy Management, LLC Purchase and Sale
Agreement by and between Centennial Energy Resources LLC, as Seller, and
Montana Acquisition Company LLC, as Buyer, dated April 25, 2007, filed as
Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 2007, filed on
May 8, 2007, in File No. 1-3480*
|
|
|
+10(ab)
|
MDU
Construction Services Group, Inc. Executive Incentive Compensation Plan
and Rules and Regulations, as adopted May 2, 2006, filed as Exhibit 10(f)
to Form 10-Q for the quarter ended March 31, 2007, filed on May 8, 2007,
in File No. 1-3480*
|
|
|
+10(ac)
|
Consulting
Agreement, dated July 2, 2007, by and between Williston Basin Interstate
Pipeline Company and John K. Castleberry, filed as Exhibit 10 to Form 10-Q
for the quarter ended June 30, 2007, filed on August 8, 2007, in File No.
1-3480*
|
|
|
12
|
Computation
of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and
Preferred Stock Dividends**
|
|
|
21
|
Subsidiaries
of MDU Resources Group, Inc.**
|
|
|
23
|
Consent
of Independent Registered Public Accounting Firm**
|
|
|
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**
|
|
|
99(a)
|
Sales
Agency Financing Agreement, dated as of July 27, 2006, between the Company
and Wells Fargo
Securities,
LLC, filed as Exhibit 1 to Form 8-K dated July 27, 2006, filed on July 27,
2006, in File No. 1-
3480*
|
|
|
99(b)
|
Amendment
to Sales Agency Financing Agreement, dated as of June 25, 2007, between
the Company and
Wells
Fargo Securities, LLC, filed as Exhibit 1 to Form 8-K dated June 25, 2007,
filed on June 28, 2007,
in File No. 1-3480*
|
|
|
————————————————————————
* Incorporated
herein by reference as indicated.
** Filed
herewith.
+ Management
contract, compensatory plan or arrangement.
(1)
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. MDU
Resources Group, Inc. hereby undertakes to furnish supplementally copies of any
of the omitted schedules upon request by the SEC.
MDU
Resources Group, Inc. agrees to furnish to the SEC upon request any instrument
with respect to long-term debt that MDU Resources Group, Inc. has not filed as
an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of
Regulation S-K.
SIGNATURES
Pursuant to the requirements of
Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
MDU RESOURCES GROUP, INC.
Date:
|
February 20,
2008
|
By:
|
/s/ Terry D.
Hildestad
|
|
|
|
Terry D.
Hildestad
(President and Chief Executive
Officer)
|
Pursuant to the requirements of the
Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrant in the capacities and on the date
indicated.
Signature
|
Title
|
Date
|
|
|
|
/s/ Terry D.
Hildestad
|
Chief Executive Officer and
Director
|
February 20,
2008
|
Terry D.
Hildestad
(President and Chief Executive
Officer)
|
|
|
|
|
|
/s/ Vernon A.
Raile
|
Chief Financial
Officer
|
February 20,
2008
|
Vernon A.
Raile
(Executive Vice President,
Treasurer and Chief Financial Officer)
|
|
|
|
|
|
/s/ Doran N.
Schwartz
|
Chief Accounting
Officer
|
February 20,
2008
|
Doran N.
Schwartz
(Vice President and Chief
Accounting Officer)
|
|
|
|
|
|
/s/ Harry J.
Pearce
|
Director
|
February 20,
2008
|
Harry J.
Pearce
|
|
|
(Chairman of the
Board)
|
|
|
|
|
|
/s/ Thomas
Everist
|
Director
|
February 20,
2008
|
Thomas
Everist
|
|
|
|
|
|
/s/ Karen B.
Fagg
|
Director
|
February 20,
2008
|
Karen B.
Fagg
|
|
|
|
|
|
/s/ Dennis W.
Johnson
|
Director
|
February 20,
2008
|
Dennis W.
Johnson
|
|
|
|
|
|
/s/ Richard H.
Lewis
|
Director
|
February 20,
2008
|
Richard H.
Lewis
|
|
|
|
|
|
/s/
Patricia L. Moss
|
Director
|
February 20,
2008
|
Patricia L.
Moss
|
|
|
|
|
|
/s/
John L. Olson
|
Director
|
February 20,
2008
|
John L.
Olson
|
|
|
|
|
|
/s/ Sister Thomas
Welder
|
Director
|
February 20,
2008
|
Sister Thomas
Welder
|
|
|
|
|
|
/s/
John K. Wilson
|
Director
|
February 20,
2008
|
John K.
Wilson
|
|
|