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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, 2011
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
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THE SECURITIES EXCHANGE ACT OF 1934
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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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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $1.00
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New York Stock Exchange
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
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Smaller reporting company
o
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Items 1 and 2
Business and Properties
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Exploration and Production
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Item 1A
Risk Factors
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Item 1B
Unresolved Staff Comments
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Item 3
Legal Proceedings
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Item 4
Mine Safety Disclosures
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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 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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Item 15
Exhibits and Financial Statement Schedules
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AFUDC
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Allowance for funds used during construction
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Alusa
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Tecnica de Engenharia Electrica - Alusa
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Army Corps
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U.S. Army Corps of Engineers
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ASC
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FASB Accounting Standards Codification
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BART
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Best available retrofit technology
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Bbl
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Barrel
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Bcf
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Billion cubic feet
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Bcfe
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Billion cubic feet equivalent
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Bicent
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Bicent Power LLC
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Big Stone Station
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450-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
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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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Brazilian Transmission Lines
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Company's equity method investment in the company owning ECTE, ENTE and ERTE (ownership interests in ENTE and ERTE were sold in the fourth quarter of 2010 and a portion of the ownership interest in ECTE was sold in the fourth quarter of 2011 and 2010)
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Btu
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British thermal unit
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Cascade
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Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
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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 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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Colorado State District Court
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Colorado Thirteenth Judicial District Court, Yuma County
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Company
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MDU Resources Group, Inc.
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dk
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Decatherm
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Dodd-Frank Act
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Dodd-Frank Wall Street Reform and Consumer Protection Act
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ECTE
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Empresa Catarinense de Transmissão de Energia S.A. (7.51 percent ownership interest at December 31, 2011, 2.5 and 14.99 percent ownership interest was sold in 2011 and 2010, respectively)
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EIN
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Employer Identification Number
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ENTE
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Empresa Norte de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
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EPA
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U.S. Environmental Protection Agency
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ERISA
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Employee Retirement Income Security Act of 1974
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ERTE
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Empresa Regional de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
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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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FIP
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Funding improvement plan
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GAAP
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Accounting principles generally accepted in the United States of America
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GHG
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Greenhouse gas
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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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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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IFRS
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International Financial Reporting Standards
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Intermountain
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Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
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IPUC
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Idaho Public Utilities Commission
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Item 8
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Financial Statements and Supplementary Data
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JTL
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JTL Group, Inc., an indirect wholly owned subsidiary of Knife River
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Knife River
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Knife River Corporation, a direct wholly owned subsidiary of Centennial
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Knife River - Northwest
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Knife River Corporation - Northwest, an indirect wholly owned subsidiary of Knife River (previously Morse Bros., Inc., name changed effective January 1, 2010)
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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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LPP
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Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006)
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LTM
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LTM, Inc., an indirect wholly owned subsidiary of Knife River
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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
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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 Resources
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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 - natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil
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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 Department of Environmental Quality
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Montana First Judicial District Court
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Montana First Judicial District Court, Lewis and Clark County
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Montana Seventeenth Judicial District Court
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Montana Seventeenth Judicial District Court, Phillips County
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MPPAA
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Multiemployer Pension Plan Amendments Act of 1980
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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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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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Oil
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Includes crude oil, condensate and natural gas liquids
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Omimex
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Omimex Canada, Ltd.
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OPUC
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Oregon Public Utility Commission
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Oregon Circuit Court
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Circuit Court of the State of Oregon for the County of Klamath
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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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PDP
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Proved developed producing
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PRC
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Planning resource credit - a MW of demand equivalent assigned to generators by the Midwest ISO for meeting system reliability requirements
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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 2012 Proxy Statement
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PRP
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Potentially Responsible Party
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PUD
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Proved undeveloped
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RCRA
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Resource Conservation and Recovery Act
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ROD
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Record of Decision
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RP
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Rehabilitation plan
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Ryder Scott
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Ryder Scott Company, L.P.
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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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SEC Defined Prices
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The average price of natural gas and oil during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
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Securities Act
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Securities Act of 1933, as amended
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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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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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SourceGas
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SourceGas Distribution LLC
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Stock Purchase Plan
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Company's Dividend Reinvestment and Direct Stock Purchase Plan
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UA
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United Association of Journeyman and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada
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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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Wygen III
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100-MW coal-fired electric generating facility near Gillette, Wyoming (25 percent ownership)
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WYPSC
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Wyoming Public Service Commission
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Years ended December 31,
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2011
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2010
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2009
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Average cost of coal per MMBtu
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$
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1.62
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$
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1.55
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$
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1.52
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Average cost of coal per ton
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$
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23.38
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$
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22.60
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$
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22.05
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•
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Bakken areas - Fidelity significantly increased its acreage position in the Bakken oil play in 2011. The Company holds approximately 16,000 net acres in Mountrail County, North Dakota, approximately 50,000 net acres in Stark County, North Dakota, and approximately 30,000 net acres in Richland County, Montana.
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•
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Cedar Creek Anticline - Primarily in eastern Montana, the Company has a long-held net profits interest in this oil play.
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Other exploratory oil projects - Fidelity holds approximately 75,000 net acres in the Paradox Basin in Utah, approximately 65,000 net acres in the Niobrara play in Wyoming and approximately 90,000 net acres in the Heath Shale prospect in Montana.
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Big Horn Basin - These interests include approximately 36,000 net acres and are in Wyoming, targeting oil and natural gas liquids.
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Green River Basin - These properties are primarily natural gas targets in Wyoming in which the Company holds approximately 36,000 net acres.
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Baker Field - Long-held natural gas properties in which Fidelity holds approximately 98,000 net acres in southeastern Montana and southwestern North Dakota.
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•
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Bowdoin Field - Long-held natural gas properties in which Fidelity holds approximately 127,000 net acres in north-central Montana.
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•
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Other - Includes the Powder River Basin and Bonny Field which Fidelity anticipates divesting of in 2012, along with various non-operated positions.
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•
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South Texas - This area includes approximately 10,000 net acres in the Tabasco, Texan Gardens and Flores fields. This area has significant natural gas liquids content associated with the natural gas.
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•
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East/Central Texas - Fidelity holds approximately 28,000 net acres.
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•
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Other - Includes various non-operated onshore interests, as well as offshore interests in the shallow waters off the coasts of Texas and Louisiana.
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Net Exploratory
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Net Development
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Productive
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Dry Holes
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Total
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Productive
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Dry Holes
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Total
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Total
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2011
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4
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—
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4
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48
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—
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48
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52
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2010
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3
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4
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7
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133
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1
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134
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141
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2009
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1
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2
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3
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104
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—
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104
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107
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Number of Sites
(Crushed Stone)
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Number of Sites
(Sand & Gravel)
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Tons Sold (000's)
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Estimated Reserves
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Lease
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Reserve
Life
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Production Area
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owned
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leased
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owned
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leased
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2011
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2010
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2009
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(000's tons)
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Expiration
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(years)
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Anchorage, AK
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—
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—
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1
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|
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—
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137
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|
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854
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891
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16,563
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N/A
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26
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Hawaii
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—
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6
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—
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—
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1,527
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1,412
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1,940
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60,683
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2012-2064
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37
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Northern CA
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—
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—
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9
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1
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1,552
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1,043
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1,215
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48,298
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2014
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38
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Southern CA
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—
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2
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—
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—
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1,134
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619
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337
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93,135
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2035
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Over 100
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Portland, OR
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1
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3
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5
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3
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3,106
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2,521
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2,718
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242,614
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2012-2055
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87
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Eugene, OR
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3
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4
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4
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1
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884
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1,311
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|
1,097
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170,063
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2013-2046
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Over 100
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Central OR/WA/ID
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1
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|
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2
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4
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4
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851
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1,192
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1,436
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105,789
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2012-2077
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|
91
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Southwest OR
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5
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4
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11
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6
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|
1,604
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|
|
1,505
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|
1,871
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|
|
99,629
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2012-2048
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|
60
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Central MT
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—
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|
|
—
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|
|
1
|
|
|
2
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|
|
758
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971
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1,220
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29,667
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|
2013-2027
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|
30
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Northwest MT
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—
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|
|
—
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|
|
7
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|
|
1
|
|
|
1,370
|
|
|
1,362
|
|
|
1,289
|
|
|
45,545
|
|
|
2020
|
|
34
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|
Wyoming
|
—
|
|
|
—
|
|
|
1
|
|
|
2
|
|
|
461
|
|
|
447
|
|
|
655
|
|
|
13,133
|
|
|
2013-2019
|
|
25
|
|
Central MN
|
—
|
|
|
1
|
|
|
36
|
|
|
27
|
|
|
1,520
|
|
|
1,527
|
|
|
1,868
|
|
|
77,217
|
|
|
2012-2028
|
|
47
|
|
Northern MN
|
2
|
|
|
—
|
|
|
16
|
|
|
5
|
|
|
355
|
|
|
401
|
|
|
838
|
|
|
27,201
|
|
|
2013-2016
|
|
51
|
|
ND/SD
|
—
|
|
|
—
|
|
|
3
|
|
|
19
|
|
|
1,727
|
|
|
1,106
|
|
|
699
|
|
|
30,199
|
|
|
2012-2031
|
|
26
|
|
Iowa
|
—
|
|
|
1
|
|
|
1
|
|
|
8
|
|
|
249
|
|
|
642
|
|
|
545
|
|
|
7,703
|
|
|
2012-2020
|
|
16
|
|
Texas
|
1
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
1,182
|
|
|
1,648
|
|
|
1,080
|
|
|
21,394
|
|
|
2015-2025
|
|
16
|
|
Sales from other sources
|
|
|
|
|
|
|
|
|
6,319
|
|
|
4,788
|
|
|
4,296
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
|
|
|
|
24,736
|
|
|
23,349
|
|
|
23,995
|
|
|
1,088,833
|
|
|
|
|
|
•
|
A severe prolonged economic downturn
|
•
|
The bankruptcy of unrelated industry leaders in the same line of business
|
•
|
Deterioration in capital market conditions
|
•
|
Turmoil in the financial services industry
|
•
|
Volatility in commodity prices
|
•
|
Terrorist attacks
|
•
|
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 ability to obtain adequate and timely cost recovery for the Company's regulated operations through regulatory proceedings
|
•
|
The availability of economic expansion or development opportunities
|
•
|
Population growth rates and demographic patterns
|
•
|
Market demand for, available supplies of, and/or costs 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 technology
|
•
|
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 and funding requirements
|
Item 5.
|
Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
Common Stock Price (High)
|
|
|
Common Stock Price (Low)
|
|
|
Common Stock Dividends Declared
Per Share
|
|
|||
2011
|
|
|
|
|
|
||||||
First quarter
|
|
$23.00
|
|
|
|
$20.11
|
|
|
|
$.1625
|
|
Second quarter
|
24.05
|
|
|
21.47
|
|
|
.1625
|
|
|||
Third quarter
|
23.28
|
|
|
18.25
|
|
|
.1625
|
|
|||
Fourth quarter
|
22.19
|
|
|
18.00
|
|
|
.1675
|
|
|||
|
|
|
|
|
|
$.6550
|
|
||||
|
|
|
|
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|
||||||
2010
|
|
|
|
|
|
||||||
First quarter
|
|
$24.15
|
|
|
|
$19.54
|
|
|
|
$.1575
|
|
Second quarter
|
22.90
|
|
|
17.11
|
|
|
.1575
|
|
|||
Third quarter
|
20.48
|
|
|
17.61
|
|
|
.1575
|
|
|||
Fourth quarter
|
21.27
|
|
|
19.52
|
|
|
.1625
|
|
|||
|
|
|
|
|
|
$.6350
|
|
Period
|
(a)
Total Number
of Shares
(or Units)
Purchased (1)
|
|
|
(b)
Average Price Paid per Share
(or Unit)
|
|
|
(c)
Total Number of Shares
(or Units) Purchased
as Part of Publicly
Announced Plans
or Programs (2)
|
|
(d)
Maximum Number (or
Approximate Dollar
Value) of Shares (or
Units) that May Yet Be
Purchased Under the
Plans or Programs (2)
|
|
October 1 through October 31, 2011
|
—
|
|
|
|
|
|
|
|
||
November 1 through November 30, 2011
|
49,050
|
|
|
|
$20.18
|
|
|
|
|
|
December 1 through December 31, 2011
|
6,091
|
|
|
|
$20.52
|
|
|
|
|
|
Total
|
55,141
|
|
|
|
|
|
|
|
|
|
(1) Represents shares of common stock purchased on the open market in connection with annual stock grants made to the Company's non-employee directors and for those directors who elected to receive additional shares of common stock in lieu of a portion of their cash retainer.
(2) Not applicable. The Company does not currently have in place any publicly announced plans or programs to purchase equity securities.
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
*
|
2008
|
|
**
|
2007
|
|
|
2006
|
|
||||||
Selected Financial Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Operating revenues (000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Electric
|
$
|
225,468
|
|
|
$
|
211,544
|
|
|
$
|
196,171
|
|
|
$
|
208,326
|
|
|
$
|
193,367
|
|
|
$
|
187,301
|
|
Natural gas distribution
|
907,400
|
|
|
892,708
|
|
|
1,072,776
|
|
|
1,036,109
|
|
|
532,997
|
|
|
351,988
|
|
||||||
Pipeline and energy services
|
278,343
|
|
|
329,809
|
|
|
307,827
|
|
|
532,153
|
|
|
447,063
|
|
|
443,720
|
|
||||||
Exploration and production
|
453,586
|
|
|
434,354
|
|
|
439,655
|
|
|
712,279
|
|
|
514,854
|
|
|
483,952
|
|
||||||
Construction materials and contracting
|
1,510,010
|
|
|
1,445,148
|
|
|
1,515,122
|
|
|
1,640,683
|
|
|
1,761,473
|
|
|
1,877,021
|
|
||||||
Construction services
|
854,389
|
|
|
789,100
|
|
|
819,064
|
|
|
1,257,319
|
|
|
1,103,215
|
|
|
987,582
|
|
||||||
Other
|
11,446
|
|
|
7,727
|
|
|
9,487
|
|
|
10,501
|
|
|
10,061
|
|
|
8,117
|
|
||||||
Intersegment eliminations
|
(190,150
|
)
|
|
(200,695
|
)
|
|
(183,601
|
)
|
|
(394,092
|
)
|
|
(315,134
|
)
|
|
(335,142
|
)
|
||||||
|
$
|
4,050,492
|
|
|
$
|
3,909,695
|
|
|
$
|
4,176,501
|
|
|
$
|
5,003,278
|
|
|
$
|
4,247,896
|
|
|
$
|
4,004,539
|
|
Operating income (loss) (000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Electric
|
$
|
49,096
|
|
|
$
|
48,296
|
|
|
$
|
36,709
|
|
|
$
|
35,415
|
|
|
$
|
31,652
|
|
|
$
|
27,716
|
|
Natural gas distribution
|
82,856
|
|
|
75,697
|
|
|
76,899
|
|
|
76,887
|
|
|
32,903
|
|
|
8,744
|
|
||||||
Pipeline and energy services
|
45,365
|
|
|
46,310
|
|
|
69,388
|
|
|
49,560
|
|
|
58,026
|
|
|
57,133
|
|
||||||
Exploration and production
|
133,790
|
|
|
143,169
|
|
|
(473,399
|
)
|
|
202,954
|
|
|
227,728
|
|
|
231,802
|
|
||||||
Construction materials and contracting
|
51,092
|
|
|
63,045
|
|
|
93,270
|
|
|
62,849
|
|
|
138,635
|
|
|
156,104
|
|
||||||
Construction services
|
39,144
|
|
|
33,352
|
|
|
44,255
|
|
|
81,485
|
|
|
75,511
|
|
|
50,651
|
|
||||||
Other
|
5,024
|
|
|
858
|
|
|
(219
|
)
|
|
2,887
|
|
|
(7,335
|
)
|
|
(9,075
|
)
|
||||||
|
$
|
406,367
|
|
|
$
|
410,727
|
|
|
$
|
(153,097
|
)
|
|
$
|
512,037
|
|
|
$
|
557,120
|
|
|
$
|
523,075
|
|
Earnings (loss) on common stock (000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Electric
|
$
|
29,258
|
|
|
$
|
28,908
|
|
|
$
|
24,099
|
|
|
$
|
18,755
|
|
|
$
|
17,700
|
|
|
$
|
14,401
|
|
Natural gas distribution
|
38,398
|
|
|
36,944
|
|
|
30,796
|
|
|
34,774
|
|
|
14,044
|
|
|
5,680
|
|
||||||
Pipeline and energy services
|
23,082
|
|
|
23,208
|
|
|
37,845
|
|
|
26,367
|
|
|
31,408
|
|
|
32,126
|
|
||||||
Exploration and production
|
80,282
|
|
|
85,638
|
|
|
(296,730
|
)
|
|
122,326
|
|
|
142,485
|
|
|
145,657
|
|
||||||
Construction materials and contracting
|
26,430
|
|
|
29,609
|
|
|
47,085
|
|
|
30,172
|
|
|
77,001
|
|
|
85,702
|
|
||||||
Construction services
|
21,627
|
|
|
17,982
|
|
|
25,589
|
|
|
49,782
|
|
|
43,843
|
|
|
27,851
|
|
||||||
Other
|
6,190
|
|
|
21,046
|
|
|
7,357
|
|
|
10,812
|
|
|
(4,380
|
)
|
|
(4,324
|
)
|
||||||
Earnings (loss) on common stock before income (loss) from discontinued operations
|
225,267
|
|
|
243,335
|
|
|
(123,959
|
)
|
|
292,988
|
|
|
322,101
|
|
|
307,093
|
|
||||||
Income (loss) from discontinued operations, net of tax
|
(12,926
|
)
|
|
(3,361
|
)
|
|
—
|
|
|
—
|
|
|
109,334
|
|
|
7,979
|
|
||||||
|
$
|
212,341
|
|
|
$
|
239,974
|
|
|
$
|
(123,959
|
)
|
|
$
|
292,988
|
|
|
$
|
431,435
|
|
|
$
|
315,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
||||||
General
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Total assets (000's)
|
$
|
6,556,125
|
|
|
$
|
6,303,549
|
|
|
$
|
5,990,952
|
|
|
$
|
6,587,845
|
|
|
$
|
5,592,434
|
|
|
$
|
4,903,474
|
|
Total long-term debt (000's)
|
$
|
1,424,678
|
|
|
$
|
1,506,752
|
|
|
$
|
1,499,306
|
|
|
$
|
1,647,302
|
|
|
$
|
1,308,463
|
|
|
$
|
1,254,582
|
|
Capitalization ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Common equity
|
66
|
%
|
|
64
|
%
|
|
63
|
%
|
|
61
|
%
|
|
66
|
%
|
|
63
|
%
|
||||||
Total debt
|
34
|
|
|
36
|
|
|
37
|
|
|
39
|
|
|
34
|
|
|
37
|
|
||||||
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
||||||
Electric
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Retail sales (thousand kWh)
|
2,878,852
|
|
|
2,785,710
|
|
|
2,663,560
|
|
|
2,663,452
|
|
|
2,601,649
|
|
|
2,483,248
|
|
||||||
Sales for resale (thousand kWh)
|
63,899
|
|
|
58,321
|
|
|
90,789
|
|
|
223,778
|
|
|
165,639
|
|
|
483,944
|
|
||||||
Electric system summer generating and firm purchase capability - kW (Interconnected system)
|
658,900
|
|
|
594,180
|
|
|
594,700
|
|
|
597,250
|
|
|
571,160
|
|
|
547,485
|
|
||||||
Electric system summer and firm purchase contract PRCs (Interconnected system)
|
572.8
|
|
|
553.3
|
|
|
*
|
|
|
*
|
|
|
*
|
|
|
*
|
|
||||||
Electric system peak demand obligation, including firm purchase contracts, PRCs (Interconnected system)
|
524.2
|
|
|
529.5
|
|
|
*
|
|
|
*
|
|
|
*
|
|
|
*
|
|
||||||
Demand peak - kW (Interconnected system)
|
535,761
|
|
|
525,643
|
|
|
525,643
|
|
|
525,643
|
|
|
525,643
|
|
|
485,456
|
|
||||||
Electricity produced (thousand kWh)
|
2,488,337
|
|
|
2,472,288
|
|
|
2,203,665
|
|
|
2,538,439
|
|
|
2,253,851
|
|
|
2,218,059
|
|
||||||
Electricity purchased (thousand kWh)
|
645,567
|
|
|
521,156
|
|
|
682,152
|
|
|
516,654
|
|
|
576,613
|
|
|
833,647
|
|
||||||
Average cost of fuel and purchased power per kWh
|
$
|
.021
|
|
|
$
|
.021
|
|
|
$
|
.023
|
|
|
$
|
.025
|
|
|
$
|
.025
|
|
|
$
|
.022
|
|
Natural Gas Distribution**
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Sales (Mdk)
|
103,237
|
|
|
95,480
|
|
|
102,670
|
|
|
87,924
|
|
|
52,977
|
|
|
34,553
|
|
||||||
Transportation (Mdk)
|
124,227
|
|
|
135,823
|
|
|
132,689
|
|
|
103,504
|
|
|
54,698
|
|
|
14,058
|
|
||||||
Degree days (% of normal)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Montana-Dakota
|
101
|
%
|
|
98
|
%
|
|
104
|
%
|
|
103
|
%
|
|
93
|
%
|
|
87
|
%
|
||||||
Cascade
|
103
|
%
|
|
96
|
%
|
|
105
|
%
|
|
108
|
%
|
|
102
|
%
|
|
—
|
|
||||||
Intermountain
|
107
|
%
|
|
100
|
%
|
|
107
|
%
|
|
90
|
%
|
|
—
|
|
|
—
|
|
||||||
Pipeline and Energy Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Transportation (Mdk)
|
113,217
|
|
|
140,528
|
|
|
163,283
|
|
|
138,003
|
|
|
140,762
|
|
|
130,889
|
|
||||||
Gathering (Mdk)
|
66,500
|
|
|
77,154
|
|
|
92,598
|
|
|
102,064
|
|
|
92,414
|
|
|
87,135
|
|
||||||
Customer natural gas storage balance (Mdk)
|
36,021
|
|
|
58,784
|
|
|
61,506
|
|
|
30,598
|
|
|
50,219
|
|
|
51,477
|
|
||||||
Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Natural gas (MMcf)
|
45,598
|
|
|
50,391
|
|
|
56,632
|
|
|
65,457
|
|
|
62,798
|
|
|
62,062
|
|
||||||
Oil (MBbls)
|
3,500
|
|
|
3,262
|
|
|
3,111
|
|
|
2,808
|
|
|
2,365
|
|
|
2,041
|
|
||||||
Total production (MMcfe)
|
66,596
|
|
|
69,963
|
|
|
75,299
|
|
|
82,303
|
|
|
76,988
|
|
|
74,307
|
|
||||||
Average realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Natural gas (per Mcf)
|
$
|
3.85
|
|
|
$
|
4.36
|
|
|
$
|
5.16
|
|
|
$
|
7.38
|
|
|
$
|
5.96
|
|
|
$
|
6.03
|
|
Oil (per Bbl)
|
$
|
79.43
|
|
|
$
|
65.85
|
|
|
$
|
47.38
|
|
|
$
|
81.68
|
|
|
$
|
59.26
|
|
|
$
|
50.64
|
|
Average realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Natural gas (per Mcf)
|
$
|
3.30
|
|
|
$
|
3.57
|
|
|
$
|
2.99
|
|
|
$
|
7.29
|
|
|
$
|
5.37
|
|
|
$
|
5.62
|
|
Oil (per Bbl)
|
$
|
83.30
|
|
|
$
|
66.71
|
|
|
$
|
49.76
|
|
|
$
|
82.28
|
|
|
$
|
59.53
|
|
|
$
|
51.73
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Natural gas (MMcf)
|
379,827
|
|
|
448,397
|
|
|
448,425
|
|
|
604,282
|
|
|
523,737
|
|
|
538,100
|
|
||||||
Oil (MBbls)
|
34,347
|
|
|
32,867
|
|
|
34,216
|
|
|
34,348
|
|
|
30,612
|
|
|
27,100
|
|
||||||
Total reserves (MMcfe)
|
585,908
|
|
|
645,596
|
|
|
653,724
|
|
|
810,371
|
|
|
707,409
|
|
|
700,700
|
|
Item 7.
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
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
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(Dollars in millions, where applicable)
|
||||||||||
Electric
|
$
|
29.2
|
|
|
$
|
28.9
|
|
|
$
|
24.1
|
|
Natural gas distribution
|
38.4
|
|
|
37.0
|
|
|
30.8
|
|
|||
Pipeline and energy services
|
23.1
|
|
|
23.2
|
|
|
37.8
|
|
|||
Exploration and production
|
80.3
|
|
|
85.6
|
|
|
(296.7
|
)
|
|||
Construction materials and contracting
|
26.4
|
|
|
29.6
|
|
|
47.1
|
|
|||
Construction services
|
21.6
|
|
|
18.0
|
|
|
25.6
|
|
|||
Other
|
6.2
|
|
|
21.0
|
|
|
7.3
|
|
|||
Earnings (loss) before discontinued operations
|
225.2
|
|
|
243.3
|
|
|
(124.0
|
)
|
|||
Loss from discontinued operations, net of tax
|
(12.9
|
)
|
|
(3.3
|
)
|
|
—
|
|
|||
Earnings (loss) on common stock
|
$
|
212.3
|
|
|
$
|
240.0
|
|
|
$
|
(124.0
|
)
|
Earnings (loss) per common share - basic:
|
|
|
|
|
|
|
|
|
|||
Earnings (loss) before discontinued operations
|
$
|
1.19
|
|
|
$
|
1.29
|
|
|
$
|
(.67
|
)
|
Discontinued operations, net of tax
|
(.07
|
)
|
|
(.01
|
)
|
|
—
|
|
|||
Earnings (loss) per common share - basic
|
$
|
1.12
|
|
|
$
|
1.28
|
|
|
$
|
(.67
|
)
|
Earnings (loss) per common share - diluted:
|
|
|
|
|
|
|
|
|
|||
Earnings (loss) before discontinued operations
|
$
|
1.19
|
|
|
$
|
1.29
|
|
|
$
|
(.67
|
)
|
Discontinued operations, net of tax
|
(.07
|
)
|
|
(.02
|
)
|
|
—
|
|
|||
Earnings (loss) per common share - diluted
|
$
|
1.12
|
|
|
$
|
1.27
|
|
|
$
|
(.67
|
)
|
Return on average common equity
|
7.8
|
%
|
|
9.1
|
%
|
|
(4.9
|
)%
|
•
|
Absence of a $13.8 million (after tax) gain on the sale of the Brazilian Transmission Lines, as discussed in Item 8 - Note 4, as well as an increased loss of $9.6 million (after tax) from discontinued operations, as discussed in Item 8 - Note 3. Both of these items are included in the Other category.
|
•
|
Lower average realized natural gas prices, decreased natural gas production, higher depreciation, depletion and amortization expense, increased lease operating costs, higher production and property taxes and higher general and administrative expense, partially offset by higher average realized oil prices and increased oil production at the exploration and production business
|
•
|
Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), higher average realized oil prices, increased oil production and lower general and administrative expense, partially offset by lower average realized natural gas prices, decreased natural gas production and higher production taxes at the exploration and production business
|
•
|
A $13.8 million (after tax) gain on the sale of the Brazilian Transmission Lines, as previously discussed, as well as a $3.3 million (after tax) loss from discontinued operations, as discussed in Item 8 - Note 3. Both of these items are included in the Other category.
|
•
|
Lower liquid asphalt oil, ready-mixed concrete and asphalt margins and volumes, as well as decreased construction margins, partially offset by lower selling, general and administrative expense at the construction materials and contracting segment
|
•
|
Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $16.5 million (after tax) and lower gathering volumes, partially offset by higher storage services revenue at the pipeline and energy services business
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(Dollars in millions, where applicable)
|
||||||||||
Operating revenues
|
$
|
225.5
|
|
|
$
|
211.6
|
|
|
$
|
196.2
|
|
Operating expenses:
|
|
|
|
|
|
|
|
||||
Fuel and purchased power
|
64.5
|
|
|
63.1
|
|
|
65.7
|
|
|||
Operation and maintenance
|
70.3
|
|
|
63.8
|
|
|
60.7
|
|
|||
Depreciation, depletion and amortization
|
32.2
|
|
|
27.3
|
|
|
24.7
|
|
|||
Taxes, other than income
|
9.4
|
|
|
9.1
|
|
|
8.4
|
|
|||
|
176.4
|
|
|
163.3
|
|
|
159.5
|
|
|||
Operating income
|
49.1
|
|
|
48.3
|
|
|
36.7
|
|
|||
Earnings
|
$
|
29.2
|
|
|
$
|
28.9
|
|
|
$
|
24.1
|
|
Retail sales (million kWh)
|
2,878.9
|
|
|
2,785.7
|
|
|
2,663.5
|
|
|||
Sales for resale (million kWh)
|
63.9
|
|
|
58.3
|
|
|
90.8
|
|
|||
Average cost of fuel and purchased power per kWh
|
$
|
.021
|
|
|
$
|
.021
|
|
|
$
|
.023
|
|
•
|
Higher electric retail sales margins, primarily due to higher rates in North Dakota, Montana and Wyoming
|
•
|
Increased retail sales volumes of 3 percent, primarily to residential and small commercial and industrial customers, reflecting increased customers and demand
|
•
|
Lower income taxes of $3.4 million, including an income tax benefit of $1.2 million related to favorable resolution of certain income tax matters, higher production tax credits, as well as a reduction of income taxes associated with benefits
|
•
|
Higher operation and maintenance expense of $4.1 million (after tax), primarily increased benefit-related costs, as well as increased contract services
|
•
|
Increased depreciation, depletion and amortization expense of $3.0 million (after tax), including the effects of higher property, plant and equipment balances
|
•
|
Lower other income of $2.2 million (after tax), largely lower allowance for funds used during construction related to electric generation projects, which were placed in service in 2010
|
•
|
Higher net interest expense of $1.4 million (after tax), including lower capitalized interest
|
•
|
Higher electric retail sales margins, primarily due to implementation of higher rates in Wyoming, as well as interim rates in North Dakota
|
•
|
Higher retail sales volumes of 5 percent, primarily to residential and small commercial and industrial customers, reflecting increased customers and demand
|
•
|
Higher operation and maintenance expense of $1.8 million (after tax), primarily costs due to storm damage, as well as expenses at Wygen III, which commenced operation in the second quarter of 2010
|
•
|
Lower other income of $1.6 million (after tax), primarily lower allowance for funds used during construction related to electric generation projects, which were placed in service in 2010
|
•
|
Increased depreciation, depletion and amortization expense of $1.6 million (after tax), including the effects of higher property, plant and equipment balances
|
•
|
Higher net interest expense of $1.3 million (after tax), resulting from higher average borrowings and lower capitalized interest
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(Dollars in millions, where applicable)
|
||||||||||
Operating revenues
|
$
|
907.4
|
|
|
$
|
892.7
|
|
|
$
|
1,072.8
|
|
Operating expenses:
|
|
|
|
|
|
|
|
||||
Purchased natural gas sold
|
594.6
|
|
|
589.3
|
|
|
757.6
|
|
|||
Operation and maintenance
|
137.3
|
|
|
137.4
|
|
|
140.5
|
|
|||
Depreciation, depletion and amortization
|
44.6
|
|
|
43.0
|
|
|
42.7
|
|
|||
Taxes, other than income
|
48.0
|
|
|
47.3
|
|
|
55.1
|
|
|||
|
824.5
|
|
|
817.0
|
|
|
995.9
|
|
|||
Operating income
|
82.9
|
|
|
75.7
|
|
|
76.9
|
|
|||
Earnings
|
$
|
38.4
|
|
|
$
|
37.0
|
|
|
$
|
30.8
|
|
Volumes (MMdk):
|
|
|
|
|
|
|
|
||||
Sales
|
103.3
|
|
|
95.5
|
|
|
102.7
|
|
|||
Transportation
|
124.2
|
|
|
135.8
|
|
|
132.7
|
|
|||
Total throughput
|
227.5
|
|
|
231.3
|
|
|
235.4
|
|
|||
Degree days (% of normal)*
|
|
|
|
|
|
|
|
|
|||
Montana-Dakota
|
101
|
%
|
|
98
|
%
|
|
104
|
%
|
|||
Cascade
|
103
|
%
|
|
96
|
%
|
|
105
|
%
|
|||
Intermountain
|
107
|
%
|
|
100
|
%
|
|
107
|
%
|
|||
Average cost of natural gas, including transportation, per dk
|
$
|
5.76
|
|
|
$
|
6.17
|
|
|
$
|
7.38
|
|
* Degree days are a measure of the daily temperature-related demand for energy for heating.
|
•
|
Higher regulated operation and maintenance expense of $3.5 million (after tax), primarily higher benefit-related costs
|
•
|
Higher income taxes of $2.1 million, primarily related to the absence of a 2010 income tax benefit of $4.8 million related to a reduction in deferred income taxes associated with property, plant and equipment, partially offset by a reduction of income taxes associated with benefits
|
•
|
Lower nonregulated energy-related services of $1.3 million (after tax), largely related to lower pipeline project activity
|
•
|
Increased depreciation, depletion and amortization expense of $1.0 million (after tax), primarily resulting from higher property, plant and equipment balances
|
•
|
An income tax benefit of $4.8 million, as previously discussed
|
•
|
Lower operation and maintenance expense of $2.7 million (after tax), largely lower bad debt expense and benefit-related costs
|
•
|
Higher nonregulated energy-related services of $1.4 million (after tax), including pipeline project activity
|
•
|
Lower net interest expense of $1.3 million (after tax), primarily due to higher capitalized interest and lower average borrowings
|
•
|
Higher other income of $1.1 million (after tax), primarily allowance for funds used during construction due to higher rates
|
•
|
Increased demand-related transportation volumes of $900,000 (after tax), primarily industrial customers
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(Dollars in millions)
|
||||||||||
Operating revenues
|
$
|
278.3
|
|
|
$
|
329.8
|
|
|
$
|
307.8
|
|
Operating expenses:
|
|
|
|
|
|
|
|
||||
Purchased natural gas sold
|
125.3
|
|
|
153.9
|
|
|
138.8
|
|
|||
Operation and maintenance
|
68.9
|
|
|
90.6
|
|
|
63.1
|
|
|||
Depreciation, depletion and amortization
|
25.5
|
|
|
26.0
|
|
|
25.5
|
|
|||
Taxes, other than income
|
13.2
|
|
|
13.0
|
|
|
11.0
|
|
|||
|
232.9
|
|
|
283.5
|
|
|
238.4
|
|
|||
Operating income
|
45.4
|
|
|
46.3
|
|
|
69.4
|
|
|||
Earnings
|
$
|
23.1
|
|
|
$
|
23.2
|
|
|
$
|
37.8
|
|
Transportation volumes (MMdk)
|
113.2
|
|
|
140.5
|
|
|
163.3
|
|
|||
Gathering volumes (MMdk)
|
66.5
|
|
|
77.2
|
|
|
92.6
|
|
|||
Customer natural gas storage balance (MMdk):
|
|
|
|
|
|
|
|
||||
Beginning of period
|
58.8
|
|
|
61.5
|
|
|
30.6
|
|
|||
Net injection (withdrawal)
|
(22.8
|
)
|
|
(2.7
|
)
|
|
30.9
|
|
|||
End of period
|
36.0
|
|
|
58.8
|
|
|
61.5
|
|
•
|
Lower storage services revenue of $7.1 million (after tax), largely lower storage balances
|
•
|
Decreased transportation volumes of $4.6 million (after tax), largely lower volumes transported to storage resulting from decreased customer demand, as well as lower off-system transportation volumes
|
•
|
Lower gathering volumes of $3.9 million (after tax), largely resulting from customers experiencing normal production declines
|
•
|
Higher operation and maintenance expense, primarily due to a natural gas gathering arbitration charge of $26.6 million ($16.5 million after tax), partially offset by lower costs related to natural gas storage litigation, largely due to an insurance recovery; both as previously discussed
|
•
|
Lower gathering volumes of $4.2 million (after tax), largely resulting from customers experiencing normal production declines
|
•
|
Decreased transportation volumes of $2.0 million (after tax), largely lower volumes transported to storage resulting from decreased customer demand
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(Dollars in millions, where applicable)
|
||||||||||
Operating revenues:
|
|
|
|
|
|
||||||
Natural gas
|
$
|
175.6
|
|
|
$
|
219.6
|
|
|
$
|
292.3
|
|
Oil
|
278.0
|
|
|
214.8
|
|
|
147.4
|
|
|||
|
453.6
|
|
|
434.4
|
|
|
439.7
|
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
||||
Operation and maintenance:
|
|
|
|
|
|
|
|
||||
Lease operating costs
|
75.6
|
|
|
68.5
|
|
|
70.1
|
|
|||
Gathering and transportation
|
24.3
|
|
|
23.5
|
|
|
24.0
|
|
|||
Other
|
36.5
|
|
|
32.5
|
|
|
39.2
|
|
|||
Depreciation, depletion and amortization
|
142.6
|
|
|
130.5
|
|
|
129.9
|
|
|||
Taxes, other than income:
|
|
|
|
|
|
|
|
||||
Production and property taxes
|
40.8
|
|
|
35.5
|
|
|
29.1
|
|
|||
Other
|
—
|
|
|
.7
|
|
|
.8
|
|
|||
Write-down of natural gas and oil properties
|
—
|
|
|
—
|
|
|
620.0
|
|
|||
|
319.8
|
|
|
291.2
|
|
|
913.1
|
|
|||
Operating income (loss)
|
133.8
|
|
|
143.2
|
|
|
(473.4
|
)
|
|||
Earnings (loss)
|
$
|
80.3
|
|
|
$
|
85.6
|
|
|
$
|
(296.7
|
)
|
Production:
|
|
|
|
|
|
|
|
||||
Natural gas (MMcf)
|
45,598
|
|
|
50,391
|
|
|
56,632
|
|
|||
Oil (MBbls)
|
3,500
|
|
|
3,262
|
|
|
3,111
|
|
|||
Total production (MMcfe)
|
66,596
|
|
|
69,963
|
|
|
75,299
|
|
|||
Average realized prices (including hedges):
|
|
|
|
|
|
|
|
||||
Natural gas (per Mcf)
|
$
|
3.85
|
|
|
$
|
4.36
|
|
|
$
|
5.16
|
|
Oil (per Bbl)
|
$
|
79.43
|
|
|
$
|
65.85
|
|
|
$
|
47.38
|
|
Average realized prices (excluding hedges):
|
|
|
|
|
|
|
|
||||
Natural gas (per Mcf)
|
$
|
3.30
|
|
|
$
|
3.57
|
|
|
$
|
2.99
|
|
Oil (per Bbl)
|
$
|
83.30
|
|
|
$
|
66.71
|
|
|
$
|
49.76
|
|
Average depreciation, depletion and amortization rate, per equivalent Mcf
|
$
|
2.04
|
|
|
$
|
1.77
|
|
|
$
|
1.64
|
|
Production costs, including taxes, per equivalent Mcf:
|
|
|
|
|
|
|
|
||||
Lease operating costs
|
$
|
1.13
|
|
|
$
|
.98
|
|
|
$
|
.93
|
|
Gathering and transportation
|
.36
|
|
|
.34
|
|
|
.32
|
|
|||
Production and property taxes
|
.61
|
|
|
.51
|
|
|
.39
|
|
|||
|
$
|
2.10
|
|
|
$
|
1.83
|
|
|
$
|
1.64
|
|
•
|
Lower average realized natural gas prices of 12 percent
|
•
|
Decreased natural gas production of 10 percent, largely related to normal production declines at certain properties, partially offset by increased production from the South Texas properties resulting from drilling activity, as well as production from the Green River Basin properties, which were acquired in April 2010
|
•
|
Higher depreciation, depletion and amortization expense of $7.6 million (after tax), due to higher depletion rates, partially offset by lower volumes
|
•
|
Increased lease operating expenses of $4.4 million (after tax) largely related to higher well maintenance costs, including higher workover costs at the Cedar Creek Anticline properties, in which the Company holds a net profits interest; costs from the Green River Basin properties, which were acquired in April 2010; as well as higher costs resulting from increased production in the Bakken area and at the South Texas properties
|
•
|
Higher production and property taxes of $3.3 million (after tax), largely resulting from higher oil prices excluding hedges
|
•
|
Higher general and administrative expense of $2.0 million (after tax), largely higher payroll-related costs
|
•
|
Higher average realized oil prices of 21 percent
|
•
|
Increased oil production of 7 percent, largely related to drilling activity at the South Texas properties, as well as in the Bakken area, partially offset by normal production declines at certain properties
|
•
|
Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), as discussed in Item 8 - Note 1
|
•
|
Higher average realized oil prices of 39 percent
|
•
|
Increased oil production of 5 percent, largely related to drilling activity in the Bakken area, partially offset by normal production declines at certain existing properties
|
•
|
Lower general and administrative expense of $4.2 million (after tax), including the absence of rig contract termination costs in 2009
|
•
|
Lower net interest expense of $1.3 million (after tax), primarily due to lower average borrowings and higher capitalized interest, partially offset by higher effective interest rates
|
•
|
Lower average realized natural gas prices of 16 percent
|
•
|
Decreased natural gas production of 11 percent, largely related to normal production declines at existing properties, partially offset by production from the Green River Basin properties, which were acquired in April 2010, as discussed in Item 8 - Note 2
|
•
|
Higher production and property taxes of $4.0 million (after tax), largely resulting from higher natural gas and oil prices excluding hedges
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(Dollars in millions)
|
||||||||||
Operating revenues
|
$
|
1,510.0
|
|
|
$
|
1,445.1
|
|
|
$
|
1,515.1
|
|
Operating expenses:
|
|
|
|
|
|
|
|
||||
Operation and maintenance
|
1,337.4
|
|
|
1,260.4
|
|
|
1,292.0
|
|
|||
Depreciation, depletion and amortization
|
85.5
|
|
|
88.3
|
|
|
93.6
|
|
|||
Taxes, other than income
|
36.0
|
|
|
33.4
|
|
|
36.2
|
|
|||
|
1,458.9
|
|
|
1,382.1
|
|
|
1,421.8
|
|
|||
Operating income
|
51.1
|
|
|
63.0
|
|
|
93.3
|
|
|||
Earnings
|
$
|
26.4
|
|
|
$
|
29.6
|
|
|
$
|
47.1
|
|
Sales (000's):
|
|
|
|
|
|
|
|
||||
Aggregates (tons)
|
24,736
|
|
|
23,349
|
|
|
23,995
|
|
|||
Asphalt (tons)
|
6,709
|
|
|
6,279
|
|
|
6,360
|
|
|||
Ready-mixed concrete (cubic yards)
|
2,864
|
|
|
2,764
|
|
|
3,042
|
|
•
|
Lower earnings of $5.8 million (after tax) resulting from lower liquid asphalt oil margins, largely due to higher asphalt oil costs
|
•
|
Lower earnings of $3.3 million (after tax) resulting from lower other product line margins, largely due to lower revenues and higher costs
|
•
|
Lower earnings of $2.3 million (after tax) resulting from lower ready-mixed concrete margins, primarily due to higher costs
|
•
|
Increased construction margins of $5.4 million (after tax), largely due to increased margins and volumes in the Pacific, North Central and Mountain regions
|
•
|
Lower interest expense of $2.3 million (after tax), primarily due to lower average interest rates
|
•
|
Lower earnings of $11.1 million (after tax), as a result of lower liquid asphalt oil margins and volumes, largely due to increased competition
|
•
|
Lower earnings of $7.3 million (after tax) resulting from lower ready-mixed concrete margins and volumes, primarily due to less available work and increased competition
|
•
|
Decreased construction margins of $7.1 million (after tax), largely due to increased competition
|
•
|
Lower earnings of $5.7 million (after tax) resulting from lower asphalt margins and volumes, primarily due to increased competition, as well as higher asphalt oil costs
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In millions)
|
||||||||||
Operating revenues
|
$
|
854.4
|
|
|
$
|
789.1
|
|
|
$
|
819.0
|
|
Operating expenses:
|
|
|
|
|
|
||||||
Operation and maintenance
|
778.5
|
|
|
719.7
|
|
|
736.3
|
|
|||
Depreciation, depletion and amortization
|
11.4
|
|
|
12.1
|
|
|
12.8
|
|
|||
Taxes, other than income
|
25.4
|
|
|
23.9
|
|
|
25.7
|
|
|||
|
815.3
|
|
|
755.7
|
|
|
774.8
|
|
|||
Operating income
|
39.1
|
|
|
33.4
|
|
|
44.2
|
|
|||
Earnings
|
$
|
21.6
|
|
|
$
|
18.0
|
|
|
$
|
25.6
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In millions)
|
||||||||||
Other:
|
|
|
|
|
|
||||||
Operating revenues
|
$
|
11.4
|
|
|
$
|
7.7
|
|
|
$
|
9.5
|
|
Operation and maintenance
|
4.7
|
|
|
4.8
|
|
|
8.1
|
|
|||
Depreciation, depletion and amortization
|
1.6
|
|
|
1.6
|
|
|
1.3
|
|
|||
Taxes, other than income
|
.1
|
|
|
.5
|
|
|
.3
|
|
|||
Intersegment transactions:
|
|
|
|
|
|
|
|
||||
Operating revenues
|
$
|
190.1
|
|
|
$
|
200.7
|
|
|
$
|
183.6
|
|
Purchased natural gas sold
|
147.7
|
|
|
175.4
|
|
|
156.7
|
|
|||
Operation and maintenance
|
42.4
|
|
|
25.3
|
|
|
26.9
|
|
•
|
Earnings per common share for 2012, diluted, are projected in the range of $1.00 to $1.25. The Company expects the approximate percentage of 2012 earnings per common share by quarter to be:
|
◦
|
First quarter - 15 percent
|
◦
|
Second quarter - 15 percent
|
◦
|
Third quarter - 40 percent
|
◦
|
Fourth quarter - 30 percent
|
•
|
Although near term market conditions are uncertain, the Company's long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.
|
•
|
The Company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.
|
•
|
The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that upon approval by the EPA will require the Big Stone Station to install and operate a BART air quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides as early as practicable, but not later than five years after EPA's approval of the state program. The state program was submitted January 21, 2011. The Company's share of the cost of this air quality control system is estimated at $125 million. The Company believes continuing to operate Big Stone Station with the upgrade is the best option. The Company intends to seek recovery of costs related to the above matter in electric rates charged to customers. On May 20, 2011, the Company filed for an advance determination of prudence with the NDPSC requesting advance determination that the air quality control system is reasonable and prudent, as discussed in Item 8 - Note 18.
|
•
|
On July 7, 2011, the Company filed for an advance determination of prudence with the NDPSC on the construction of an 88-MW simple cycle natural gas turbine and associated facilities, as discussed in Item 8 - Note 18.
|
•
|
The Company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors with company and customer-owned pipeline facilities designed to serve existing facilities currently served by fuel oil or propane, and to serve new customers.
|
•
|
Currently the Company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest.
|
•
|
The Company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major market areas. The Company has a contract to develop a 30-mile high-voltage power line in southeast North Dakota to move power to the electric grid from a proposed 150-MW wind farm. The proposed project totals approximately $18 million and includes substation upgrades. Construction is underway and the project is expected to be completed by mid 2012.
|
•
|
The Company expects lower customer storage balances in 2012 compared to 2011. In addition, the anticipated divestment of certain natural gas properties and the deferral of certain gas development activity at our exploration and production business are expected to result in gathering volumes being lower in 2012 compared to 2011. These declines are expected to be partially offset by higher transportation volumes related to growth projects placed in service in the Bakken area.
|
•
|
The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its
|
•
|
Installation of additional compression at the Charbonneau station was completed and placed into service in September 2011, providing additional firm capacity for producers in the Bakken production area. With some additional modifications, this project has the potential of adding a total of 27 MMcf of firm capacity.
|
•
|
Construction was completed in December 2011 on approximately 12 miles of high pressure transmission pipeline providing takeaway capacity from the Garden Creek processing facility in northwestern North Dakota.
|
•
|
Preparations are underway for the construction of approximately 13 miles of high pressure transmission pipeline from the Stateline I and II processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline. The project is expected to be completed by mid 2012.
|
•
|
The Company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. It continues to seek interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125 MMcf per day. Commitment on approximately 30 percent of the total potential project was received and the additional firm deliverability became available in November 2011.
|
•
|
The Company expects to spend approximately $400 million in capital expenditures in 2012. The Company continues its focus on returns by allocating the majority of its capital investment into the production of oil in the current commodity price environment. Its capital program reflects further exploitation of existing properties, acquisition of additional leasehold acreage, and exploratory drilling. The 2012 planned capital expenditure total does not include potential acquisitions of producing properties.
|
•
|
For 2012, the Company expects a 20 percent to 30 percent increase in oil production and a 12 percent to 16 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of the anticipated divestment of certain natural gas properties and the deferral of certain natural gas development activity because of sustained low natural gas prices.
|
•
|
The Company has a total of 8 drilling rigs deployed on its acreage in the Bakken, Niobrara, Texas, Paradox, Heath Shale and Big Horn areas, up from 2 rigs in the first quarter of 2011. Dependent upon results during 2012, further growth in rig activity could occur.
|
•
|
Bakken Area
|
◦
|
The Company holds a total of approximately 95,000 net acres of leaseholds.
|
◦
|
Capital expenditures are expected to total approximately $160 million in 2012; approximately $60 million higher than the capital spent for 2011.
|
◦
|
Mountrail County, North Dakota
|
▪
|
The Company holds approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations.
|
▪
|
The drilling of 17 operated and participation in various non-operated wells is expected for 2012 with approximately $75 million of capital expenditures.
|
▪
|
Over 50 future gross well sites have been identified. Estimated gross ultimate recovery per well is 250,000 to 500,000 Bbls.
|
◦
|
Stark County, North Dakota
|
▪
|
The Company holds approximately 50,000 net exploratory leasehold acres, targeting the Three Forks formation.
|
▪
|
The drilling of 7 operated wells and participation in various non-operated wells is expected for 2012 with approximately $60 million of capital expenditures.
|
▪
|
Based on 640-acre spacing, approximately 140 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.
|
◦
|
Richland County, Montana
|
▪
|
The Company has increased its acreage to approximately 30,000 net exploratory leasehold acres, targeting the Three Forks formation.
|
▪
|
The first appraisal well is expected to be spud in the first quarter of 2012 and a total of 5 operated wells are planned for this year with approximately $25 million of capital expenditures.
|
▪
|
Approximately 100 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.
|
•
|
Niobrara - southeastern Wyoming
|
◦
|
The Company holds approximately 65,000 net exploratory leasehold acres.
|
◦
|
The drilling of 4 operated wells and participation in various non-operated wells is expected for 2012 with approximately $25 million of capital expenditures.
|
◦
|
Approximately 200 potential gross well sites have been identified based on 640-acre spacing. Estimated gross ultimate recovery rates per well are 200,000 to 300,000 Bbls.
|
•
|
Paradox Basin - Cane Creek Federal Unit, Utah
|
◦
|
The Company holds approximately 75,000 net exploratory leasehold acres.
|
◦
|
The drilling of 4 operated wells is expected in 2012 with capital expenditures of approximately $35 million.
|
◦
|
Approximately 70 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 Bbls.
|
•
|
Texas
|
◦
|
The Company is targeting areas that have the potential for higher liquids content with approximately $60 million of capital planned for 2012.
|
◦
|
Plans are to drill 20 operated wells in Texas in 2012.
|
◦
|
Approximately 50 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.
|
•
|
Heath Shale
|
◦
|
The Company holds approximately 90,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana and expects to drill between 2 and 4 wells in 2012 with capital of approximately $20 million.
|
•
|
Other Opportunities
|
◦
|
The Company continues to pursue acquisitions of additional leaseholds. Approximately $25 million of capital has been allocated to leasehold acquisitions, focusing on expansion of existing positions and new opportunities.
|
◦
|
The remaining forecasted 2012 capital has been allocated to other operated and non-operated opportunities.
|
•
|
Reserve information
|
◦
|
The Company's combined proved natural gas and oil reserves as of December 31, 2011, were 586 Bcfe.
|
◦
|
Reserve additions replaced annual production, however, there were approximately 60 Bcfe of negative revisions to last year's estimates. Approximately 85 percent of the negative revisions were associated with natural gas properties. Revisions of prior estimates, low natural gas prices and a change in strategy to focus on oil properties led to a significant reduction in the number of PUD reserves associated with natural gas properties.
|
◦
|
Oil reserves are 5 percent higher than a year ago primarily the result of approximately 60 percent growth in Bakken reserves. The Company's oil reserve replacement ratio was 175 percent for 2011, excluding revisions.
|
◦
|
Natural gas reserves are 15 percent lower primarily for the reasons mentioned previously. The biggest changes occurred in the dry gas fields of Baker and Bowdoin.
|
◦
|
With increasing oil reserves as well as higher oil prices, the combined PV-10 value of proved oil and natural gas reserves grew by more than 10 percent year-over-year.
|
•
|
Earnings guidance reflects estimated natural gas and oil prices for February through December as follows:
|
•
|
For 2012, the Company has hedged approximately 30 percent to 35 percent of its estimated natural gas production and 65 percent to 70 percent of its estimated oil production. For 2013, the Company has hedged 30 percent to 35 percent of its estimated oil production. The hedges that are in place as of February 17, 2012, are summarized in the following chart:
|
•
|
Work backlog as of December 31, 2011, was approximately $384 million, with 92 percent of construction backlog being public work and private representing 8 percent. Backlog a year ago was approximately $420 million. Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and harbor expansion projects.
|
•
|
The Company has green fielded an operation in Williston in the Bakken area of North Dakota and currently has $31 million of backlog in the area. The Company is pursuing substantial growth opportunities associated with the Bakken area.
|
•
|
The Company is part of a joint venture that was selected as the low bidder on the Port of Long Beach expansion. Its share of the project for this phase is expected to exceed $25 million. It also placed a new approximately 35,000 ton asphalt oil terminal into service in December 2011 in Wyoming. The Company is the primary cement provider in Hawaii and has the opportunity to supply a portion of the ready-mixed concrete and aggregate related to an approximate $5 billion multi-phased light rail project.
|
•
|
Projected revenues included in the Company's 2012 earnings guidance are in the range of $1.3 billion to $1.4 billion.
|
•
|
The Company anticipates margins in 2012 to be higher than 2011 levels.
|
•
|
The Company continues to pursue work related to energy projects, such as wind towers, transmission projects, geothermal and refineries. It is also pursuing opportunities for expansion of its existing business lines including initiatives aimed at capturing additional market share and expansion into new markets.
|
•
|
As the country's 5th largest sand and gravel producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.
|
•
|
Work backlog as of December 31, 2011, was approximately $308 million, compared to approximately $373 million a year ago. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.
|
•
|
Projected revenues included in the Company's 2012 earnings guidance are in the range of $700 million to $800 million.
|
•
|
The Company anticipates margins in 2012 to be higher than 2011 levels.
|
•
|
The Company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction, governmental facilities, refinery turnaround projects and utility service work.
|
•
|
Lower proceeds from the sale of the Company's equity method investments in the Brazilian Transmission Lines of $66.3 million
|
•
|
Increased ongoing capital expenditures of $47.7 million, largely at the construction materials and contracting business
|
•
|
Lower proceeds from the sale or disposition of properties and other of $36.3 million, largely at the exploration and
|
•
|
Proceeds from the sale of the Company's equity method investments in the Brazilian Transmission Lines of $69.1 million
|
•
|
Higher proceeds from the sale or disposition of properties and other of $49.7 million, largely at the exploration and production business and construction materials and contracting business
|
•
|
System upgrades
|
•
|
Routine replacements
|
•
|
Service extensions
|
•
|
Routine equipment maintenance and replacements
|
•
|
Buildings, land and building improvements
|
•
|
Pipeline and gathering projects
|
•
|
Further development of existing properties, acquisition of additional leasehold acreage and exploratory drilling at the exploration and production segment
|
•
|
Power generation opportunities, including certain costs for additional electric generating capacity
|
•
|
Environmental upgrades
|
•
|
Other growth opportunities
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2016
|
|
|
Thereafter
|
|
|
Total
|
|
|
Fair
Value
|
|
||||||||
|
(Dollars in millions)
|
||||||||||||||||||||||||||||||
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Fixed rate
|
$
|
139.3
|
|
|
$
|
259.2
|
|
|
$
|
9.3
|
|
|
$
|
266.4
|
|
|
$
|
288.4
|
|
|
$
|
454.0
|
|
|
$
|
1,416.6
|
|
|
$
|
1,584.7
|
|
Weighted average interest rate
|
5.8
|
%
|
|
6.0
|
%
|
|
6.9
|
%
|
|
5.7
|
%
|
|
6.4
|
%
|
|
6.1
|
%
|
|
6.1
|
%
|
|
—
|
|
||||||||
Variable rate
|
—
|
|
|
$
|
8.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
8.1
|
|
|
$
|
8.1
|
|
|||||
Weighted average interest rate
|
—
|
|
|
2.5
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.5
|
%
|
|
—
|
|
/s/ Terry D. Hildestad
|
/s/ Doran N. Schwartz
|
|
|
Terry D. Hildestad
|
Doran N. Schwartz
|
President and Chief Executive Officer
|
Vice President and Chief Financial Officer
|
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands, except per share amounts)
|
||||||||||
Operating revenues:
|
|
|
|
|
|
||||||
Electric, natural gas distribution and pipeline and energy services
|
$
|
1,343,714
|
|
|
$
|
1,359,028
|
|
|
$
|
1,504,269
|
|
Exploration and production, construction materials and contracting, construction services and other
|
2,706,778
|
|
|
2,550,667
|
|
|
2,672,232
|
|
|||
Total operating revenues
|
4,050,492
|
|
|
3,909,695
|
|
|
4,176,501
|
|
|||
Operating expenses:
|
|
|
|
|
|
|
|
|
|||
Fuel and purchased power
|
64,485
|
|
|
63,065
|
|
|
65,717
|
|
|||
Purchased natural gas sold
|
572,187
|
|
|
567,806
|
|
|
739,678
|
|
|||
Operation and maintenance:
|
|
|
|
|
|
|
|
|
|||
Electric, natural gas distribution and pipeline and energy services
|
275,866
|
|
|
291,524
|
|
|
263,869
|
|
|||
Exploration and production, construction materials and contracting, construction services and other
|
2,215,269
|
|
|
2,084,377
|
|
|
2,143,195
|
|
|||
Depreciation, depletion and amortization
|
343,395
|
|
|
328,843
|
|
|
330,542
|
|
|||
Taxes, other than income
|
172,923
|
|
|
163,353
|
|
|
166,597
|
|
|||
Write-down of natural gas and oil properties (Note 1)
|
—
|
|
|
—
|
|
|
620,000
|
|
|||
Total operating expenses
|
3,644,125
|
|
|
3,498,968
|
|
|
4,329,598
|
|
|||
Operating income (loss)
|
406,367
|
|
|
410,727
|
|
|
(153,097
|
)
|
|||
Earnings from equity method investments
|
4,693
|
|
|
30,816
|
|
|
8,499
|
|
|||
Other income
|
6,520
|
|
|
8,018
|
|
|
9,331
|
|
|||
Interest expense
|
81,354
|
|
|
83,011
|
|
|
84,099
|
|
|||
Income (loss) before income taxes
|
336,226
|
|
|
366,550
|
|
|
(219,366
|
)
|
|||
Income taxes
|
110,274
|
|
|
122,530
|
|
|
(96,092
|
)
|
|||
Income (loss) from continuing operations
|
225,952
|
|
|
244,020
|
|
|
(123,274
|
)
|
|||
Loss from discontinued operations, net of tax (Note 3)
|
(12,926
|
)
|
|
(3,361
|
)
|
|
—
|
|
|||
Net income (loss)
|
213,026
|
|
|
240,659
|
|
|
(123,274
|
)
|
|||
Dividends declared on preferred stocks
|
685
|
|
|
685
|
|
|
685
|
|
|||
Earnings (loss) on common stock
|
$
|
212,341
|
|
|
$
|
239,974
|
|
|
$
|
(123,959
|
)
|
Earnings (loss) per common share - basic:
|
|
|
|
|
|
|
|
|
|||
Earnings (loss) before discontinued operations
|
$
|
1.19
|
|
|
$
|
1.29
|
|
|
$
|
(.67
|
)
|
Discontinued operations, net of tax
|
(.07
|
)
|
|
(.01
|
)
|
|
—
|
|
|||
Earnings (loss) per common share - basic
|
$
|
1.12
|
|
|
$
|
1.28
|
|
|
$
|
(.67
|
)
|
Earnings (loss) per common share - diluted:
|
|
|
|
|
|
|
|
|
|||
Earnings (loss) before discontinued operations
|
$
|
1.19
|
|
|
$
|
1.29
|
|
|
$
|
(.67
|
)
|
Discontinued operations, net of tax
|
(.07
|
)
|
|
(.02
|
)
|
|
—
|
|
|||
Earnings (loss) per common share - diluted
|
$
|
1.12
|
|
|
$
|
1.27
|
|
|
$
|
(.67
|
)
|
Dividends declared per common share
|
$
|
.6550
|
|
|
$
|
.6350
|
|
|
$
|
.6225
|
|
Weighted average common shares outstanding - basic
|
188,763
|
|
|
188,137
|
|
|
185,175
|
|
|||
Weighted average common shares outstanding - diluted
|
188,905
|
|
|
188,229
|
|
|
185,175
|
|
December 31,
|
2011
|
|
|
2010
|
|
||
(In thousands, except shares and per share amounts)
|
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
162,772
|
|
|
$
|
222,074
|
|
Receivables, net
|
646,251
|
|
|
583,743
|
|
||
Inventories
|
274,205
|
|
|
252,897
|
|
||
Deferred income taxes
|
40,407
|
|
|
32,890
|
|
||
Commodity derivative instruments
|
27,687
|
|
|
15,123
|
|
||
Prepayments and other current assets
|
43,316
|
|
|
60,441
|
|
||
Total current assets
|
1,194,638
|
|
|
1,167,168
|
|
||
Investments
|
109,424
|
|
|
103,661
|
|
||
Property, plant and equipment (Note 1)
|
7,646,222
|
|
|
7,218,503
|
|
||
Less accumulated depreciation, depletion and amortization
|
3,361,208
|
|
|
3,103,323
|
|
||
Net property, plant and equipment
|
4,285,014
|
|
|
4,115,180
|
|
||
Deferred charges and other assets:
|
|
|
|
|
|
||
Goodwill (Note 5)
|
634,931
|
|
|
634,633
|
|
||
Other intangible assets, net (Note 5)
|
20,843
|
|
|
25,271
|
|
||
Other
|
311,275
|
|
|
257,636
|
|
||
Total deferred charges and other assets
|
967,049
|
|
|
917,540
|
|
||
Total assets
|
$
|
6,556,125
|
|
|
$
|
6,303,549
|
|
|
|
|
|
||||
Liabilities and Stockholders' Equity
|
|
|
|
|
|
||
Current liabilities:
|
|
|
|
|
|
||
Short-term borrowings (Note 9)
|
$
|
—
|
|
|
$
|
20,000
|
|
Long-term debt due within one year
|
139,267
|
|
|
72,797
|
|
||
Accounts payable
|
337,228
|
|
|
301,132
|
|
||
Taxes payable
|
70,176
|
|
|
56,186
|
|
||
Dividends payable
|
31,794
|
|
|
30,773
|
|
||
Accrued compensation
|
47,804
|
|
|
40,121
|
|
||
Commodity derivative instruments
|
13,164
|
|
|
24,428
|
|
||
Other accrued liabilities
|
259,320
|
|
|
222,639
|
|
||
Total current liabilities
|
898,753
|
|
|
768,076
|
|
||
Long-term debt (Note 9)
|
1,285,411
|
|
|
1,433,955
|
|
||
Deferred credits and other liabilities:
|
|
|
|
|
|
||
Deferred income taxes
|
769,166
|
|
|
672,269
|
|
||
Other liabilities
|
827,228
|
|
|
736,447
|
|
||
Total deferred credits and other liabilities
|
1,596,394
|
|
|
1,408,716
|
|
||
Commitments and contingencies (Notes 16, 18 and 19)
|
|
|
|
|
|
||
Stockholders' equity:
|
|
|
|
|
|
||
Preferred stocks (Note 11)
|
15,000
|
|
|
15,000
|
|
||
Common stockholders' equity:
|
|
|
|
|
|
||
Common stock (Note 12)
|
|
|
|
|
|
||
Authorized - 500,000,000 shares, $1.00 par value
|
|
|
|
|
|
||
Issued - 189,332,485 shares in 2011 and 188,901,379 shares in 2010
|
189,332
|
|
|
188,901
|
|
||
Other paid-in capital
|
1,035,739
|
|
|
1,026,349
|
|
||
Retained earnings
|
1,586,123
|
|
|
1,497,439
|
|
||
Accumulated other comprehensive loss
|
(47,001
|
)
|
|
(31,261
|
)
|
||
Treasury stock at cost - 538,921 shares
|
(3,626
|
)
|
|
(3,626
|
)
|
||
Total common stockholders' equity
|
2,760,567
|
|
|
2,677,802
|
|
||
Total stockholders' equity
|
2,775,567
|
|
|
2,692,802
|
|
||
Total liabilities and stockholders' equity
|
$
|
6,556,125
|
|
|
$
|
6,303,549
|
|
Years ended December 31, 2011, 2010 and 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
|
|
|
|
|
Other
Paid-in Capital
|
|
|
Retained Earnings
|
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|||||||||||
|
Common Stock
|
|
|
|
|
Treasury Stock
|
|
|
|||||||||||||||||||||
|
Shares
|
|
|
Amount
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Total
|
|
||||||||||||
|
(In thousands, except shares)
|
||||||||||||||||||||||||||||
Balance at December 31, 2008
|
184,208,283
|
|
|
$
|
184,208
|
|
|
$
|
938,299
|
|
|
$
|
1,616,830
|
|
|
$
|
10,365
|
|
|
(538,921
|
)
|
|
$
|
(3,626
|
)
|
|
$
|
2,746,076
|
|
Comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(123,274
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(123,274
|
)
|
||||||
Other comprehensive income (loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net unrealized loss on derivative instruments qualifying as hedges
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(51,684
|
)
|
|
—
|
|
|
—
|
|
|
(51,684
|
)
|
||||||
Postretirement liability adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,918
|
|
|
—
|
|
|
—
|
|
|
9,918
|
|
||||||
Foreign currency translation adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,568
|
|
|
—
|
|
|
—
|
|
|
10,568
|
|
||||||
Total comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(154,472
|
)
|
||||||
Dividends declared on preferred stocks
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
||||||
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(115,832
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(115,832
|
)
|
||||||
Net tax deficit on stock-based compensation
|
—
|
|
|
—
|
|
|
(117
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(117
|
)
|
||||||
Issuance of common stock
|
4,180,982
|
|
|
4,181
|
|
|
77,496
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
81,677
|
|
||||||
Balance at December 31, 2009
|
188,389,265
|
|
|
188,389
|
|
|
1,015,678
|
|
|
1,377,039
|
|
|
(20,833
|
)
|
|
(538,921
|
)
|
|
(3,626
|
)
|
|
2,556,647
|
|
||||||
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
240,659
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
240,659
|
|
||||||
Other comprehensive income (loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net unrealized gain on derivative instruments qualifying as hedges
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
673
|
|
|
—
|
|
|
—
|
|
|
673
|
|
||||||
Postretirement liability adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,730
|
)
|
|
—
|
|
|
—
|
|
|
(5,730
|
)
|
||||||
Foreign currency translation adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,371
|
)
|
|
—
|
|
|
—
|
|
|
(5,371
|
)
|
||||||
Total comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
230,231
|
|
||||||
Dividends declared on preferred stocks
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
||||||
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(119,574
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(119,574
|
)
|
||||||
Tax benefit on stock-based compensation
|
—
|
|
|
—
|
|
|
924
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
924
|
|
||||||
Issuance of common stock
|
512,114
|
|
|
512
|
|
|
9,747
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,259
|
|
||||||
Balance at December 31, 2010
|
188,901,379
|
|
|
188,901
|
|
|
1,026,349
|
|
|
1,497,439
|
|
|
(31,261
|
)
|
|
(538,921
|
)
|
|
(3,626
|
)
|
|
2,677,802
|
|
||||||
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
213,026
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213,026
|
|
||||||
Other comprehensive income (loss), net of tax -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net unrealized gain on derivative instruments qualifying as hedges
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,900
|
|
|
—
|
|
|
—
|
|
|
7,900
|
|
||||||
Postretirement liability adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,427
|
)
|
|
—
|
|
|
—
|
|
|
(22,427
|
)
|
||||||
Foreign currency translation adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,295
|
)
|
|
—
|
|
|
—
|
|
|
(1,295
|
)
|
||||||
Net unrealized gains on available-for-sale investments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
82
|
|
|
—
|
|
|
—
|
|
|
82
|
|
||||||
Total comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
197,286
|
|
||||||
Dividends declared on preferred stocks
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
||||||
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(123,657
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(123,657
|
)
|
||||||
Net tax deficit on stock-based compensation
|
—
|
|
|
—
|
|
|
(909
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(909
|
)
|
||||||
Issuance of common stock
|
431,106
|
|
|
431
|
|
|
10,299
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,730
|
|
||||||
Balance at December 31, 2011
|
189,332,485
|
|
|
$
|
189,332
|
|
|
$
|
1,035,739
|
|
|
$
|
1,586,123
|
|
|
$
|
(47,001
|
)
|
|
(538,921
|
)
|
|
$
|
(3,626
|
)
|
|
$
|
2,760,567
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Operating activities:
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
213,026
|
|
|
$
|
240,659
|
|
|
$
|
(123,274
|
)
|
Loss from discontinued operations, net of tax
|
(12,926
|
)
|
|
(3,361
|
)
|
|
—
|
|
|||
Income (loss) from continuing operations
|
225,952
|
|
|
244,020
|
|
|
(123,274
|
)
|
|||
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|||
Depreciation, depletion and amortization
|
343,395
|
|
|
328,843
|
|
|
330,542
|
|
|||
Earnings, net of distributions, from equity method investments
|
(2,111
|
)
|
|
(26,158
|
)
|
|
(3,018
|
)
|
|||
Deferred income taxes
|
118,925
|
|
|
66,585
|
|
|
(169,764
|
)
|
|||
Write-down of natural gas and oil properties (Note 1)
|
—
|
|
|
—
|
|
|
620,000
|
|
|||
Changes in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|||
Receivables
|
(30,452
|
)
|
|
(59,037
|
)
|
|
132,939
|
|
|||
Inventories
|
(24,226
|
)
|
|
(4,728
|
)
|
|
13,969
|
|
|||
Other current assets
|
7,729
|
|
|
(7,424
|
)
|
|
67,803
|
|
|||
Accounts payable
|
(12,263
|
)
|
|
17,833
|
|
|
(61,867
|
)
|
|||
Other current liabilities
|
33,738
|
|
|
12,289
|
|
|
44,039
|
|
|||
Other noncurrent changes
|
(33,365
|
)
|
|
(20,271
|
)
|
|
(4,683
|
)
|
|||
Net cash provided by continuing operations
|
627,322
|
|
|
551,952
|
|
|
846,686
|
|
|||
Net cash used in discontinued operations
|
(674
|
)
|
|
(319
|
)
|
|
—
|
|
|||
Net cash provided by operating activities
|
626,648
|
|
|
551,633
|
|
|
846,686
|
|
|||
Investing activities:
|
|
|
|
|
|
|
|
|
|||
Capital expenditures
|
(497,000
|
)
|
|
(449,282
|
)
|
|
(448,675
|
)
|
|||
Acquisitions, net of cash acquired
|
(157
|
)
|
|
(104,812
|
)
|
|
(6,410
|
)
|
|||
Net proceeds from sale or disposition of property and other
|
40,107
|
|
|
76,386
|
|
|
26,679
|
|
|||
Investments
|
(10,302
|
)
|
|
704
|
|
|
(3,740
|
)
|
|||
Proceeds from sale of equity method investments
|
2,807
|
|
|
69,060
|
|
|
—
|
|
|||
Net cash used in continuing operations
|
(464,545
|
)
|
|
(407,944
|
)
|
|
(432,146
|
)
|
|||
Net cash provided by discontinued operations
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net cash used in investing activities
|
(464,545
|
)
|
|
(407,944
|
)
|
|
(432,146
|
)
|
|||
Financing activities:
|
|
|
|
|
|
|
|
|
|||
Issuance of short-term borrowings
|
—
|
|
|
20,000
|
|
|
10,300
|
|
|||
Repayment of short-term borrowings
|
(20,000
|
)
|
|
(10,300
|
)
|
|
(105,100
|
)
|
|||
Issuance of long-term debt
|
300
|
|
|
20,200
|
|
|
145,000
|
|
|||
Repayment of long-term debt
|
(85,151
|
)
|
|
(13,668
|
)
|
|
(292,907
|
)
|
|||
Proceeds from issuance of common stock
|
5,744
|
|
|
4,972
|
|
|
65,207
|
|
|||
Dividends paid
|
(123,323
|
)
|
|
(119,157
|
)
|
|
(115,023
|
)
|
|||
Tax benefit on stock-based compensation
|
1,239
|
|
|
1,186
|
|
|
601
|
|
|||
Net cash used in continuing operations
|
(221,191
|
)
|
|
(96,767
|
)
|
|
(291,922
|
)
|
|||
Net cash provided by discontinued operations
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net cash used in financing activities
|
(221,191
|
)
|
|
(96,767
|
)
|
|
(291,922
|
)
|
|||
Effect of exchange rate changes on cash and cash equivalents
|
(214
|
)
|
|
38
|
|
|
782
|
|
|||
Increase (decrease) in cash and cash equivalents
|
(59,302
|
)
|
|
46,960
|
|
|
123,400
|
|
|||
Cash and cash equivalents - beginning of year
|
222,074
|
|
|
175,114
|
|
|
51,714
|
|
|||
Cash and cash equivalents - end of year
|
$
|
162,772
|
|
|
$
|
222,074
|
|
|
$
|
175,114
|
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Aggregates held for resale
|
$
|
78,518
|
|
|
$
|
79,894
|
|
Materials and supplies
|
61,611
|
|
|
57,324
|
|
||
Natural gas in storage (current)
|
36,578
|
|
|
34,557
|
|
||
Asphalt oil
|
32,335
|
|
|
25,234
|
|
||
Merchandise for resale
|
32,165
|
|
|
30,182
|
|
||
Other
|
32,998
|
|
|
25,706
|
|
||
Total
|
$
|
274,205
|
|
|
$
|
252,897
|
|
|
2011
|
|
|
2010
|
|
|
Weighted Average
Depreciable Life in
Years
|
|
||
|
(Dollars in thousands, where applicable)
|
|||||||||
Regulated:
|
|
|
|
|
|
|||||
Electric:
|
|
|
|
|
|
|||||
Generation
|
$
|
546,783
|
|
|
$
|
538,071
|
|
|
47
|
|
Distribution
|
255,232
|
|
|
243,205
|
|
|
36
|
|
||
Transmission
|
179,580
|
|
|
161,972
|
|
|
44
|
|
||
Other
|
86,929
|
|
|
83,786
|
|
|
13
|
|
||
Natural gas distribution:
|
|
|
|
|
|
|
|
|
||
Distribution
|
1,257,360
|
|
|
1,223,239
|
|
|
38
|
|
||
Other
|
311,506
|
|
|
285,606
|
|
|
23
|
|
||
Pipeline and energy services:
|
|
|
|
|
|
|
|
|
||
Transmission
|
386,227
|
|
|
357,395
|
|
|
52
|
|
||
Gathering
|
42,378
|
|
|
41,931
|
|
|
19
|
|
||
Storage
|
41,908
|
|
|
33,967
|
|
|
51
|
|
||
Other
|
36,179
|
|
|
33,938
|
|
|
29
|
|
||
Nonregulated:
|
|
|
|
|
|
|
|
|
||
Pipeline and energy services:
|
|
|
|
|
|
|
|
|
||
Gathering
|
198,864
|
|
|
203,064
|
|
|
17
|
|
||
Other
|
13,735
|
|
|
13,512
|
|
|
10
|
|
||
Exploration and production:
|
|
|
|
|
|
|
|
|
||
Natural gas and oil properties
|
2,577,576
|
|
|
2,320,967
|
|
|
*
|
|
||
Other
|
37,570
|
|
|
35,971
|
|
|
9
|
|
||
Construction materials and contracting:
|
|
|
|
|
|
|
|
|
||
Land
|
126,790
|
|
|
124,018
|
|
|
—
|
|
||
Buildings and improvements
|
67,627
|
|
|
65,003
|
|
|
20
|
|
||
Machinery, vehicles and equipment
|
902,136
|
|
|
899,365
|
|
|
12
|
|
||
Construction in progress
|
8,085
|
|
|
4,879
|
|
|
—
|
|
||
Aggregate reserves
|
395,214
|
|
|
393,110
|
|
|
**
|
|
||
Construction services:
|
|
|
|
|
|
|
|
|
||
Land
|
4,706
|
|
|
4,526
|
|
|
—
|
|
||
Buildings and improvements
|
15,001
|
|
|
14,101
|
|
|
22
|
|
||
Machinery, vehicles and equipment
|
95,891
|
|
|
94,252
|
|
|
7
|
|
||
Other
|
9,198
|
|
|
10,061
|
|
|
4
|
|
||
Other:
|
|
|
|
|
|
|
|
|
||
Land
|
2,837
|
|
|
2,837
|
|
|
—
|
|
||
Other
|
46,910
|
|
|
29,727
|
|
|
24
|
|
||
Less accumulated depreciation, depletion and amortization
|
3,361,208
|
|
|
3,103,323
|
|
|
|
|
||
Net property, plant and equipment
|
$
|
4,285,014
|
|
|
$
|
4,115,180
|
|
|
|
|
|
|
|
Year Costs Incurred
|
||||||||||||||||
|
Total
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008 and prior
|
|
|||||
|
(In thousands)
|
||||||||||||||||||
Acquisition
|
$
|
185,773
|
|
|
$
|
50,721
|
|
|
$
|
71,315
|
|
|
$
|
988
|
|
|
$
|
62,749
|
|
Development
|
9,938
|
|
|
9,689
|
|
|
156
|
|
|
2
|
|
|
91
|
|
|||||
Exploration
|
27,439
|
|
|
24,389
|
|
|
2,710
|
|
|
72
|
|
|
268
|
|
|||||
Capitalized interest
|
9,312
|
|
|
3,539
|
|
|
3,096
|
|
|
44
|
|
|
2,633
|
|
|||||
Total costs not subject to amortization
|
$
|
232,462
|
|
|
$
|
88,338
|
|
|
$
|
77,277
|
|
|
$
|
1,106
|
|
|
$
|
65,741
|
|
|
2011
|
|
2010
|
|
2009
|
|
*
|
|
(In thousands)
|
|
|||||
Weighted average common shares outstanding - basic
|
188,763
|
|
188,137
|
|
185,175
|
|
|
Effect of dilutive stock options and performance share awards
|
142
|
|
92
|
|
—
|
|
|
Weighted average common shares outstanding - diluted
|
188,905
|
|
188,229
|
|
185,175
|
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Interest, net of amount capitalized
|
$
|
78,133
|
|
|
$
|
80,962
|
|
|
$
|
81,267
|
|
Income taxes paid (refunded), net
|
$
|
(12,287
|
)
|
|
$
|
46,892
|
|
|
$
|
39,807
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Other comprehensive 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 $4,683, $(1,867) and $(2,509) in 2011, 2010 and 2009, respectively
|
$
|
7,900
|
|
|
$
|
(3,077
|
)
|
|
$
|
(4,094
|
)
|
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $0, $(2,305) and $29,170 in 2011, 2010 and 2009, respectively
|
—
|
|
|
(3,750
|
)
|
|
47,590
|
|
|||
Net unrealized gain (loss) on derivative instruments qualifying as hedges
|
7,900
|
|
|
673
|
|
|
(51,684
|
)
|
|||
Postretirement liability adjustment, net of tax of $(13,573), $(3,609) and $6,291 in 2011, 2010 and 2009, respectively
|
(22,427
|
)
|
|
(5,730
|
)
|
|
9,918
|
|
|||
Foreign currency translation adjustment, net of tax of $(832), $(3,486) and $6,814 in 2011, 2010 and 2009, respectively
|
(1,295
|
)
|
|
(5,371
|
)
|
|
10,568
|
|
|||
Net unrealized gains on available-for-sale investments, net of tax of $44 in 2011
|
82
|
|
|
—
|
|
|
—
|
|
|||
Total other comprehensive loss
|
$
|
(15,740
|
)
|
|
$
|
(10,428
|
)
|
|
$
|
(31,198
|
)
|
|
Net Unrealized Gain (Loss) on Derivative
Instruments
Qualifying as Hedges
|
|
|
Postretirement
Liability Adjustment
|
|
|
Foreign Currency
Translation
Adjustment
|
|
|
Net Unrealized Gains on Available-for-sale Investments
|
|
|
Total Accumulated
Other
Comprehensive
Loss
|
|
|||||
|
(In thousands)
|
||||||||||||||||||
Balance at December 31, 2009
|
$
|
(2,298
|
)
|
|
$
|
(25,163
|
)
|
|
$
|
6,628
|
|
|
$
|
—
|
|
|
$
|
(20,833
|
)
|
Balance at December 31, 2010
|
$
|
(1,625
|
)
|
|
$
|
(30,893
|
)
|
|
$
|
1,257
|
|
|
$
|
—
|
|
|
$
|
(31,261
|
)
|
Balance at December 31, 2011
|
$
|
6,275
|
|
|
$
|
(53,320
|
)
|
|
$
|
(38
|
)
|
|
$
|
82
|
|
|
$
|
(47,001
|
)
|
|
Balance as of
January 1, 2011
|
|
*
|
Goodwill Acquired During the Year
|
|
**
|
Balance as of December 31, 2011
|
|
*
|
|||
|
(In thousands)
|
|
||||||||||
Electric
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Natural gas distribution
|
345,736
|
|
|
—
|
|
|
345,736
|
|
|
|||
Pipeline and energy services
|
9,737
|
|
|
—
|
|
|
9,737
|
|
|
|||
Exploration and production
|
—
|
|
|
—
|
|
|
—
|
|
|
|||
Construction materials and contracting
|
176,290
|
|
|
—
|
|
|
176,290
|
|
|
|||
Construction services
|
102,870
|
|
|
298
|
|
|
103,168
|
|
|
|||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
|||
Total
|
$
|
634,633
|
|
|
$
|
298
|
|
|
$
|
634,931
|
|
|
|
Balance as of
January 1, 2010
|
|
*
|
Goodwill Acquired During the Year
|
|
**
|
Balance as of December 31, 2010
|
|
*
|
|||
|
(In thousands)
|
|
||||||||||
Electric
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Natural gas distribution
|
345,736
|
|
|
—
|
|
|
345,736
|
|
|
|||
Pipeline and energy services
|
7,857
|
|
|
1,880
|
|
|
9,737
|
|
|
|||
Exploration and production
|
—
|
|
|
—
|
|
|
—
|
|
|
|||
Construction materials and contracting
|
175,743
|
|
|
547
|
|
|
176,290
|
|
|
|||
Construction services
|
100,127
|
|
|
2,743
|
|
|
102,870
|
|
|
|||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
|||
Total
|
$
|
629,463
|
|
|
$
|
5,170
|
|
|
$
|
634,633
|
|
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Customer relationships
|
$
|
21,702
|
|
|
$
|
24,942
|
|
Accumulated amortization
|
(10,392
|
)
|
|
(11,625
|
)
|
||
|
11,310
|
|
|
13,317
|
|
||
Noncompete agreements
|
7,685
|
|
|
9,405
|
|
||
Accumulated amortization
|
(5,371
|
)
|
|
(6,425
|
)
|
||
|
2,314
|
|
|
2,980
|
|
||
Other
|
11,442
|
|
|
13,217
|
|
||
Accumulated amortization
|
(4,223
|
)
|
|
(4,243
|
)
|
||
|
7,219
|
|
|
8,974
|
|
||
Total
|
$
|
20,843
|
|
|
$
|
25,271
|
|
|
|
Estimated Recovery Period
|
|
*
|
2011
|
|
|
2010
|
|
|
|
|
|
(In thousands)
|
|||||
Regulatory assets:
|
|
|
|
|
|
|
|||
Pension and postretirement benefits (a)
|
|
(e)
|
|
|
171,492
|
|
|
103,818
|
|
Deferred income taxes
|
|
**
|
|
|
119,189
|
|
|
114,427
|
|
Taxes recoverable from customers (a)
|
|
—
|
|
|
12,433
|
|
|
11,961
|
|
Plant costs (a)
|
|
Over plant lives
|
|
|
10,256
|
|
|
9,964
|
|
Long-term debt refinancing costs (a)
|
|
Up to 27 years
|
|
|
10,112
|
|
|
11,101
|
|
Costs related to identifying generation development (a)
|
|
Up to 15 years
|
|
|
9,817
|
|
|
13,777
|
|
Natural gas supply derivatives (b)
|
|
Up to 1 year
|
|
|
437
|
|
|
9,359
|
|
Natural gas cost recoverable through rate adjustments (b)
|
|
Up to 28 months
|
|
|
2,622
|
|
|
6,609
|
|
Other (a) (b)
|
|
Largely within 1 year
|
|
|
22,651
|
|
|
35,225
|
|
Total regulatory assets
|
|
|
|
|
359,009
|
|
|
316,241
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
|
|
Plant removal and decommissioning costs (c)
|
|
|
|
|
289,972
|
|
|
276,652
|
|
Deferred income taxes**
|
|
|
|
|
84,963
|
|
|
64,017
|
|
Natural gas costs refundable through rate adjustments (d)
|
|
|
|
|
45,064
|
|
|
36,996
|
|
Taxes refundable to customers (c)
|
|
|
|
|
31,837
|
|
|
19,352
|
|
Other (c) (d)
|
|
|
|
|
8,393
|
|
|
16,080
|
|
Total regulatory liabilities
|
|
|
|
|
460,229
|
|
|
413,097
|
|
Net regulatory position
|
|
|
|
|
(101,220
|
)
|
|
(96,856
|
)
|
Asset Derivatives
|
|
Location on Consolidated Balance Sheets
|
|
Fair Value at December 31, 2011
|
|
|
Fair Value at December 31, 2010
|
|
||
|
|
|
|
(In thousands)
|
||||||
Designated as hedges:
|
|
|
|
|
|
|
||||
Commodity derivatives
|
|
Commodity derivative instruments
|
|
$
|
27,687
|
|
|
$
|
15,123
|
|
|
|
Other assets - noncurrent
|
|
2,768
|
|
|
4,104
|
|
||
|
|
|
|
30,455
|
|
|
19,227
|
|
||
Not designated as hedges:
|
|
|
|
|
|
|
||||
Commodity derivatives
|
|
Commodity derivative instruments
|
|
—
|
|
|
—
|
|
||
|
|
Other assets - noncurrent
|
|
—
|
|
|
—
|
|
||
|
|
|
|
—
|
|
|
—
|
|
||
Total asset derivatives
|
|
|
|
$
|
30,455
|
|
|
$
|
19,227
|
|
Liability Derivatives
|
|
Location on Consolidated Balance Sheets
|
|
Fair Value at December 31, 2011
|
|
|
Fair Value at December 31, 2010
|
|
||
|
|
|
|
(In thousands)
|
||||||
Designated as hedges:
|
|
|
|
|
|
|
||||
Commodity derivatives
|
|
Commodity derivative instruments
|
|
$
|
12,727
|
|
|
$
|
15,069
|
|
|
|
Other liabilities - noncurrent
|
|
937
|
|
|
6,483
|
|
||
Interest rate derivatives
|
|
Other accrued liabilities
|
|
827
|
|
|
—
|
|
||
|
|
Other liabilities - noncurrent
|
|
3,935
|
|
|
—
|
|
||
|
|
|
|
18,426
|
|
|
21,552
|
|
||
Not designated as hedges:
|
|
|
|
|
|
|
||||
Commodity derivatives
|
|
Commodity derivative instruments
|
|
437
|
|
|
9,359
|
|
||
|
|
Other liabilities - noncurrent
|
|
—
|
|
|
—
|
|
||
|
|
|
|
437
|
|
|
9,359
|
|
||
Total liability derivatives
|
|
|
|
$
|
18,863
|
|
|
$
|
30,911
|
|
December 31, 2011
|
Cost
|
|
Gross Unrealized Gains
|
|
Gross Unrealized Losses
|
|
Fair Value
|
|
||||
|
(In thousands)
|
|||||||||||
Insurance investment contract
|
$
|
31,884
|
|
$
|
6,468
|
|
$
|
—
|
|
$
|
38,352
|
|
Auction rate securities
|
11,400
|
|
—
|
|
—
|
|
11,400
|
|
||||
Mortgage-backed securities
|
8,206
|
|
95
|
|
(5
|
)
|
8,296
|
|
||||
U.S. Treasury securities
|
1,619
|
|
37
|
|
—
|
|
1,656
|
|
||||
Total
|
$
|
53,109
|
|
$
|
6,600
|
|
$
|
(5
|
)
|
$
|
59,704
|
|
|
Fair Value Measurements at
December 31, 2011, Using |
|
|
||||||||||||
|
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
|
|
Significant Other Observable Inputs (Level 2)
|
|
|
Significant Unobservable Inputs
(Level 3)
|
|
|
Balance at December 31, 2011
|
|
||||
|
(In thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Money market funds
|
$
|
—
|
|
|
$
|
97,500
|
|
|
$
|
—
|
|
|
$
|
97,500
|
|
Available-for-sale securities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Insurance investment contract*
|
—
|
|
|
38,352
|
|
|
—
|
|
|
38,352
|
|
||||
Auction rate securities
|
—
|
|
|
11,400
|
|
|
—
|
|
|
11,400
|
|
||||
Mortgage-backed securities
|
—
|
|
|
8,296
|
|
|
—
|
|
|
8,296
|
|
||||
U.S. Treasury securities
|
—
|
|
|
1,656
|
|
|
—
|
|
|
1,656
|
|
||||
Commodity derivative instruments - current
|
—
|
|
|
27,687
|
|
|
—
|
|
|
27,687
|
|
||||
Commodity derivative instruments - noncurrent
|
—
|
|
|
2,768
|
|
|
—
|
|
|
2,768
|
|
||||
Total assets measured at fair value
|
$
|
—
|
|
|
$
|
187,659
|
|
|
$
|
—
|
|
|
$
|
187,659
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commodity derivative instruments - current
|
$
|
—
|
|
|
$
|
13,164
|
|
|
$
|
—
|
|
|
$
|
13,164
|
|
Commodity derivative instruments - noncurrent
|
—
|
|
|
937
|
|
|
—
|
|
|
937
|
|
||||
Interest rate derivative instruments - current
|
—
|
|
|
827
|
|
|
—
|
|
|
827
|
|
||||
Interest rate derivative instruments - noncurrent
|
—
|
|
|
3,935
|
|
|
—
|
|
|
3,935
|
|
||||
Total liabilities measured at fair value
|
$
|
—
|
|
|
$
|
18,863
|
|
|
$
|
—
|
|
|
$
|
18,863
|
|
|
Fair Value Measurements at
December 31, 2010, Using |
|
|
||||||||||||
|
Quoted Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant Other Observable Inputs (Level 2)
|
|
|
Significant Unobservable Inputs
(Level 3)
|
|
|
Balance at December 31, 2010
|
|
||||
|
(In thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Money market funds
|
$
|
—
|
|
|
$
|
166,620
|
|
|
$
|
—
|
|
|
$
|
166,620
|
|
Available-for-sale securities:
|
|
|
|
|
|
|
|
||||||||
Insurance investment contract*
|
—
|
|
|
39,541
|
|
|
—
|
|
|
39,541
|
|
||||
Auction rate securities
|
—
|
|
|
11,400
|
|
|
—
|
|
|
11,400
|
|
||||
Commodity derivative instruments - current
|
—
|
|
|
15,123
|
|
|
—
|
|
|
15,123
|
|
||||
Commodity derivative instruments - noncurrent
|
—
|
|
|
4,104
|
|
|
—
|
|
|
4,104
|
|
||||
Total assets measured at fair value
|
$
|
—
|
|
|
$
|
236,788
|
|
|
$
|
—
|
|
|
$
|
236,788
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commodity derivative instruments - current
|
$
|
—
|
|
|
$
|
24,428
|
|
|
$
|
—
|
|
|
$
|
24,428
|
|
Commodity derivative instruments - noncurrent
|
—
|
|
|
6,483
|
|
|
—
|
|
|
6,483
|
|
||||
Total liabilities measured at fair value
|
$
|
—
|
|
|
$
|
30,911
|
|
|
$
|
—
|
|
|
$
|
30,911
|
|
|
2011
|
|
2010
|
||||||||||||
|
Carrying Amount
|
|
|
Fair Value
|
|
|
Carrying Amount
|
|
|
Fair Value
|
|
||||
|
(In thousands)
|
||||||||||||||
Long-term debt
|
$
|
1,424,678
|
|
|
$
|
1,592,807
|
|
|
$
|
1,506,752
|
|
|
$
|
1,621,184
|
|
Company
|
|
Facility
|
|
Facility
Limit
|
|
|
Amount Outstanding at December 31, 2011
|
|
|
Amount Outstanding at December 31, 2010
|
|
|
Letters of Credit at December 31, 2011
|
|
|
Expiration
Date
|
|
||||
|
|
|
|
(Dollars in millions)
|
|||||||||||||||||
MDU Resources Group, Inc.
|
|
Commercial paper/Revolving credit agreement
|
(a)
|
$
|
100.0
|
|
|
$
|
—
|
|
(h)
|
$
|
20.0
|
|
(b)
|
$
|
—
|
|
|
5/26/15
|
|
Cascade Natural Gas Corporation
|
|
Revolving credit agreement
|
|
$
|
50.0
|
|
(c)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.9
|
|
(d)
|
12/28/12
|
(e)
|
Intermountain Gas Company
|
|
Revolving credit agreement
|
|
$
|
65.0
|
|
(f)
|
$
|
8.1
|
|
|
$
|
20.2
|
|
|
$
|
—
|
|
|
8/11/13
|
|
Centennial Energy Holdings, Inc.
|
|
Commercial paper/Revolving credit agreement
|
(g)
|
$
|
400.0
|
|
|
$
|
—
|
|
(h)
|
$
|
—
|
|
(h)
|
$
|
21.6
|
|
(d)
|
12/13/12
|
|
(h)
|
Amount outstanding under commercial paper program.
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Senior Notes at a weighted average rate of 6.01%, due on dates ranging from May 15, 2012 to March 8, 2037
|
$
|
1,287,576
|
|
|
$
|
1,358,848
|
|
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
|
|
|
81,000
|
|
||
Other notes at a weighted average rate of 5.24%, due on dates ranging from September 1, 2020 to February 1, 2035
|
40,469
|
|
|
41,189
|
|
||
Credit agreements at a weighted average rate of 2.98%, due on dates ranging from September 30, 2012 to November 30, 2038
|
15,633
|
|
|
25,715
|
|
||
Total long-term debt
|
1,424,678
|
|
|
1,506,752
|
|
||
Less current maturities
|
139,267
|
|
|
72,797
|
|
||
Net long-term debt
|
$
|
1,285,411
|
|
|
$
|
1,433,955
|
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Balance at beginning of year
|
$
|
95,970
|
|
|
$
|
76,359
|
|
Liabilities incurred
|
3,870
|
|
|
8,608
|
|
||
Liabilities acquired
|
—
|
|
|
5,272
|
|
||
Liabilities settled
|
(10,418
|
)
|
|
(10,740
|
)
|
||
Accretion expense
|
4,466
|
|
|
3,588
|
|
||
Revisions in estimates
|
3,921
|
|
|
12,621
|
|
||
Other
|
342
|
|
|
262
|
|
||
Balance at end of year
|
$
|
98,151
|
|
|
$
|
95,970
|
|
|
2011
|
|
|
2010
|
|
||
|
(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
|
|
|
Number of Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Balance at beginning of year
|
440,984
|
|
|
|
$13.34
|
|
Forfeited
|
(3,893
|
)
|
|
13.22
|
|
|
Exercised
|
(430,341
|
)
|
|
13.34
|
|
|
Balance at end of year
|
6,750
|
|
13.03
|
|
||
Exercisable at end of year
|
6,750
|
|
|
|
$13.03
|
|
|
|
|
2011
|
|
|
|
2010
|
|
|
|
2009
|
|
||||||
Grant-date fair value
|
|
|
|
$19.99
|
|
|
|
|
$17.40
|
|
|
|
|
$20.39
|
|
|||
Blended volatility range
|
23.20
|
%
|
-
|
32.18
|
%
|
25.69
|
%
|
-
|
35.36
|
%
|
40.40
|
%
|
-
|
50.98
|
%
|
|||
Risk-free interest rate range
|
.09
|
%
|
-
|
1.34
|
%
|
.13
|
%
|
-
|
1.45
|
%
|
.30
|
%
|
-
|
1.36
|
%
|
|||
Discounted dividends per share
|
|
|
|
$1.23
|
|
|
|
|
$1.04
|
|
|
|
|
$1.79
|
|
|
Number of
Shares
|
|
|
Weighted Average Grant-Date Fair Value
|
|
|
Nonvested at beginning of period
|
669,685
|
|
|
$
|
22.19
|
|
Granted
|
278,252
|
|
|
19.99
|
|
|
Vested
|
—
|
|
|
—
|
|
|
Forfeited
|
(185,783
|
)
|
|
30.55
|
|
|
Nonvested at end of period
|
762,154
|
|
|
$
|
19.35
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
United States
|
$
|
333,486
|
|
|
$
|
336,450
|
|
|
$
|
(227,021
|
)
|
Foreign
|
2,740
|
|
|
30,100
|
|
|
7,655
|
|
|||
Income (loss) before income taxes from continuing operations
|
$
|
336,226
|
|
|
$
|
366,550
|
|
|
$
|
(219,366
|
)
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
(7,188
|
)
|
|
$
|
37,014
|
|
|
$
|
64,389
|
|
State
|
778
|
|
|
10,589
|
|
|
8,284
|
|
|||
Foreign
|
127
|
|
|
4,451
|
|
|
254
|
|
|||
|
(6,283
|
)
|
|
52,054
|
|
|
72,927
|
|
|||
Deferred:
|
|
|
|
|
|
|
|
|
|||
Income taxes -
|
|
|
|
|
|
|
|
||||
Federal
|
105,528
|
|
|
62,618
|
|
|
(147,607
|
)
|
|||
State
|
13,157
|
|
|
4,147
|
|
|
(22,370
|
)
|
|||
Investment tax credit - net
|
240
|
|
|
(180
|
)
|
|
213
|
|
|||
|
118,925
|
|
|
66,585
|
|
|
(169,764
|
)
|
|||
Change in uncertain tax benefits
|
(1,048
|
)
|
|
3,230
|
|
|
562
|
|
|||
Change in accrued interest
|
(1,320
|
)
|
|
661
|
|
|
183
|
|
|||
Total income tax expense (benefit)
|
$
|
110,274
|
|
|
$
|
122,530
|
|
|
$
|
(96,092
|
)
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Deferred tax assets:
|
|
|
|
||||
Regulatory matters
|
$
|
119,189
|
|
|
$
|
114,427
|
|
Accrued pension costs
|
95,260
|
|
|
82,085
|
|
||
Asset retirement obligations
|
26,380
|
|
|
24,391
|
|
||
Legal and environmental contingencies
|
21,788
|
|
|
13,622
|
|
||
Compensation-related
|
16,241
|
|
|
17,261
|
|
||
Other
|
41,055
|
|
|
40,307
|
|
||
Total deferred tax assets
|
319,913
|
|
|
292,093
|
|
||
Deferred tax liabilities:
|
|
|
|
|
|
||
Depreciation and basis differences on property, plant and equipment
|
715,482
|
|
|
679,809
|
|
||
Basis differences on natural gas and oil producing properties
|
210,146
|
|
|
152,455
|
|
||
Regulatory matters
|
84,963
|
|
|
64,017
|
|
||
Intangible asset amortization
|
14,307
|
|
|
14,843
|
|
||
Other
|
23,774
|
|
|
20,348
|
|
||
Total deferred tax liabilities
|
1,048,672
|
|
|
931,472
|
|
||
Net deferred income tax liability
|
$
|
(728,759
|
)
|
|
$
|
(639,379
|
)
|
|
2011
|
|
|
(In thousands)
|
|
||
Change in net deferred income tax liability from the preceding table
|
$
|
89,380
|
|
Deferred taxes associated with other comprehensive loss
|
9,678
|
|
|
Deferred taxes associated with discontinued operations
|
8,090
|
|
|
Other
|
11,777
|
|
|
Deferred income tax expense for the period
|
$
|
118,925
|
|
Years ended December 31,
|
2011
|
|
2010
|
|
2009
|
|||||||||||||||
|
Amount
|
|
|
%
|
|
|
Amount
|
|
|
%
|
|
|
Amount
|
|
|
%
|
|
|||
|
(Dollars in thousands)
|
|||||||||||||||||||
Computed tax at federal statutory rate
|
$
|
117,679
|
|
|
35.0
|
|
|
$
|
128,293
|
|
|
35.0
|
|
|
$
|
(76,778
|
)
|
|
35.0
|
|
Increases (reductions) resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
State income taxes, net of federal income tax benefit (expense)
|
10,653
|
|
|
3.2
|
|
|
10,210
|
|
|
2.8
|
|
|
(7,280
|
)
|
|
3.3
|
|
|||
Resolution of tax matters and uncertain tax positions
|
(3,906
|
)
|
|
(1.2
|
)
|
|
667
|
|
|
.2
|
|
|
881
|
|
|
(.4
|
)
|
|||
Federal renewable energy credit
|
(3,485
|
)
|
|
(1.0
|
)
|
|
(2,185
|
)
|
|
(.6
|
)
|
|
(1,452
|
)
|
|
.7
|
|
|||
Depletion allowance
|
(3,266
|
)
|
|
(1.0
|
)
|
|
(2,810
|
)
|
|
(.8
|
)
|
|
(2,320
|
)
|
|
1.0
|
|
|||
Deductible K-Plan dividends
|
(2,282
|
)
|
|
(.7
|
)
|
|
(2,309
|
)
|
|
(.6
|
)
|
|
(2,369
|
)
|
|
1.1
|
|
|||
Foreign operations
|
(391
|
)
|
|
(.1
|
)
|
|
(588
|
)
|
|
(.2
|
)
|
|
(1,148
|
)
|
|
.5
|
|
|||
Domestic production activities deduction
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(856
|
)
|
|
.4
|
|
|||
Other
|
(4,728
|
)
|
|
(1.4
|
)
|
|
(8,748
|
)
|
|
(2.4
|
)
|
|
(4,770
|
)
|
|
2.2
|
|
|||
Total income tax expense (benefit)
|
$
|
110,274
|
|
|
32.8
|
|
|
$
|
122,530
|
|
|
33.4
|
|
|
$
|
(96,092
|
)
|
|
43.8
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Balance at beginning of year
|
$
|
9,378
|
|
|
$
|
6,148
|
|
|
$
|
5,586
|
|
Additions for tax positions of prior years
|
4,172
|
|
|
3,230
|
|
|
562
|
|
|||
Settlements
|
(2,344
|
)
|
|
—
|
|
|
—
|
|
|||
Balance at end of year
|
$
|
11,206
|
|
|
$
|
9,378
|
|
|
$
|
6,148
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
External operating revenues:
|
|
|
|
|
|
||||||
Electric
|
$
|
225,468
|
|
|
$
|
211,544
|
|
|
$
|
196,171
|
|
Natural gas distribution
|
907,400
|
|
|
892,708
|
|
|
1,072,776
|
|
|||
Pipeline and energy services
|
210,846
|
|
|
254,776
|
|
|
235,322
|
|
|||
|
1,343,714
|
|
|
1,359,028
|
|
|
1,504,269
|
|
|||
Exploration and production
|
359,873
|
|
|
318,570
|
|
|
338,425
|
|
|||
Construction materials and contracting
|
1,509,538
|
|
|
1,445,148
|
|
|
1,515,122
|
|
|||
Construction services
|
834,918
|
|
|
786,802
|
|
|
818,685
|
|
|||
Other
|
2,449
|
|
|
147
|
|
|
—
|
|
|||
|
2,706,778
|
|
|
2,550,667
|
|
|
2,672,232
|
|
|||
Total external operating revenues
|
$
|
4,050,492
|
|
|
$
|
3,909,695
|
|
|
$
|
4,176,501
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Intersegment operating revenues:
|
|
|
|
|
|
|
|
|
|||
Electric
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Natural gas distribution
|
—
|
|
|
—
|
|
|
—
|
|
|||
Pipeline and energy services
|
67,497
|
|
|
75,033
|
|
|
72,505
|
|
|||
Exploration and production
|
93,713
|
|
|
115,784
|
|
|
101,230
|
|
|||
Construction materials and contracting
|
472
|
|
|
—
|
|
|
—
|
|
|||
Construction services
|
19,471
|
|
|
2,298
|
|
|
379
|
|
|||
Other
|
8,997
|
|
|
7,580
|
|
|
9,487
|
|
|||
Intersegment eliminations
|
(190,150
|
)
|
|
(200,695
|
)
|
|
(183,601
|
)
|
|||
Total intersegment operating revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization:
|
|
|
|
|
|
|
|
|
|||
Electric
|
$
|
32,177
|
|
|
$
|
27,274
|
|
|
$
|
24,637
|
|
Natural gas distribution
|
44,641
|
|
|
43,044
|
|
|
42,723
|
|
|||
Pipeline and energy services
|
25,502
|
|
|
26,001
|
|
|
25,581
|
|
|||
Exploration and production
|
142,645
|
|
|
130,455
|
|
|
129,922
|
|
|||
Construction materials and contracting
|
85,459
|
|
|
88,331
|
|
|
93,615
|
|
|||
Construction services
|
11,399
|
|
|
12,147
|
|
|
12,760
|
|
|||
Other
|
1,572
|
|
|
1,591
|
|
|
1,304
|
|
|||
Total depreciation, depletion and amortization
|
$
|
343,395
|
|
|
$
|
328,843
|
|
|
$
|
330,542
|
|
|
|
|
|
|
|
||||||
Interest expense:
|
|
|
|
|
|
|
|
|
|||
Electric
|
$
|
13,745
|
|
|
$
|
12,216
|
|
|
$
|
9,577
|
|
Natural gas distribution
|
29,444
|
|
|
28,996
|
|
|
30,656
|
|
|||
Pipeline and energy services
|
10,516
|
|
|
9,064
|
|
|
8,896
|
|
|||
Exploration and production
|
7,445
|
|
|
8,580
|
|
|
10,621
|
|
|||
Construction materials and contracting
|
16,241
|
|
|
19,859
|
|
|
20,495
|
|
|||
Construction services
|
4,473
|
|
|
4,411
|
|
|
4,490
|
|
|||
Other
|
—
|
|
|
47
|
|
|
43
|
|
|||
Intersegment eliminations
|
(510
|
)
|
|
(162
|
)
|
|
(679
|
)
|
|||
Total interest expense
|
$
|
81,354
|
|
|
$
|
83,011
|
|
|
$
|
84,099
|
|
|
|
|
|
|
|
||||||
Income taxes:
|
|
|
|
|
|
|
|
|
|||
Electric
|
$
|
7,242
|
|
|
$
|
11,187
|
|
|
$
|
8,205
|
|
Natural gas distribution
|
16,931
|
|
|
12,171
|
|
|
16,331
|
|
|||
Pipeline and energy services
|
12,912
|
|
|
13,933
|
|
|
22,982
|
|
|||
Exploration and production
|
46,298
|
|
|
49,034
|
|
|
(187,000
|
)
|
|||
Construction materials and contracting
|
11,227
|
|
|
13,822
|
|
|
25,940
|
|
|||
Construction services
|
13,426
|
|
|
11,456
|
|
|
15,189
|
|
|||
Other
|
2,238
|
|
|
10,927
|
|
|
2,261
|
|
|||
Total income taxes
|
$
|
110,274
|
|
|
$
|
122,530
|
|
|
$
|
(96,092
|
)
|
|
|
|
|
|
|
||||||
Earnings (loss) on common stock:
|
|
|
|
|
|
|
|
|
|||
Electric
|
$
|
29,258
|
|
|
$
|
28,908
|
|
|
$
|
24,099
|
|
Natural gas distribution
|
38,398
|
|
|
36,944
|
|
|
30,796
|
|
|||
Pipeline and energy services
|
23,082
|
|
|
23,208
|
|
|
37,845
|
|
|||
Exploration and production
|
80,282
|
|
|
85,638
|
|
|
(296,730
|
)
|
|||
Construction materials and contracting
|
26,430
|
|
|
29,609
|
|
|
47,085
|
|
|||
Construction services
|
21,627
|
|
|
17,982
|
|
|
25,589
|
|
|||
Other
|
6,190
|
|
|
21,046
|
|
|
7,357
|
|
|||
Earnings (loss) on common stock before loss from discontinued operations
|
225,267
|
|
|
243,335
|
|
|
(123,959
|
)
|
|||
Loss from discontinued operations, net of tax*
|
(12,926
|
)
|
|
(3,361
|
)
|
|
—
|
|
|||
Total earnings (loss) on common stock
|
$
|
212,341
|
|
|
$
|
239,974
|
|
|
$
|
(123,959
|
)
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Capital expenditures:
|
|
|
|
|
|
|
|
|
|||
Electric
|
$
|
52,072
|
|
|
$
|
85,787
|
|
|
$
|
115,240
|
|
Natural gas distribution
|
70,624
|
|
|
75,365
|
|
|
43,820
|
|
|||
Pipeline and energy services
|
45,556
|
|
|
14,255
|
|
|
70,168
|
|
|||
Exploration and production
|
272,855
|
|
|
355,845
|
|
|
183,140
|
|
|||
Construction materials and contracting
|
52,303
|
|
|
25,724
|
|
|
26,313
|
|
|||
Construction services
|
9,711
|
|
|
14,849
|
|
|
12,814
|
|
|||
Other
|
18,759
|
|
|
2,182
|
|
|
3,196
|
|
|||
Net proceeds from sale or disposition of property and other
|
(40,857
|
)
|
|
(78,761
|
)
|
|
(26,679
|
)
|
|||
Total net capital expenditures
|
$
|
481,023
|
|
|
$
|
495,246
|
|
|
$
|
428,012
|
|
|
|
|
|
|
|
||||||
Assets:
|
|
|
|
|
|
|
|
|
|||
Electric**
|
$
|
672,940
|
|
|
$
|
643,636
|
|
|
$
|
569,666
|
|
Natural gas distribution**
|
1,679,091
|
|
|
1,632,012
|
|
|
1,588,144
|
|
|||
Pipeline and energy services
|
526,797
|
|
|
523,075
|
|
|
538,230
|
|
|||
Exploration and production
|
1,481,556
|
|
|
1,342,808
|
|
|
1,137,628
|
|
|||
Construction materials and contracting
|
1,374,026
|
|
|
1,382,836
|
|
|
1,449,469
|
|
|||
Construction services
|
418,519
|
|
|
387,627
|
|
|
328,895
|
|
|||
Other***
|
403,196
|
|
|
391,555
|
|
|
378,920
|
|
|||
Total assets
|
$
|
6,556,125
|
|
|
$
|
6,303,549
|
|
|
$
|
5,990,952
|
|
|
|
|
|
|
|
||||||
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|||
Electric**
|
$
|
1,068,524
|
|
|
$
|
1,027,034
|
|
|
$
|
941,791
|
|
Natural gas distribution**
|
1,568,866
|
|
|
1,508,845
|
|
|
1,456,208
|
|
|||
Pipeline and energy services
|
719,291
|
|
|
683,807
|
|
|
675,199
|
|
|||
Exploration and production
|
2,615,146
|
|
|
2,356,938
|
|
|
2,028,794
|
|
|||
Construction materials and contracting
|
1,499,852
|
|
|
1,486,375
|
|
|
1,514,989
|
|
|||
Construction services
|
124,796
|
|
|
122,940
|
|
|
116,236
|
|
|||
Other
|
49,747
|
|
|
32,564
|
|
|
33,365
|
|
|||
Less accumulated depreciation, depletion and amortization
|
3,361,208
|
|
|
3,103,323
|
|
|
2,872,465
|
|
|||
Net property, plant and equipment
|
$
|
4,285,014
|
|
|
$
|
4,115,180
|
|
|
$
|
3,894,117
|
|
|
Pension Benefits
|
|
Other
Postretirement Benefits
|
||||||||||||
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
||||
|
(In thousands)
|
||||||||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
$
|
388,589
|
|
|
$
|
352,915
|
|
|
$
|
91,286
|
|
|
$
|
88,151
|
|
Service cost
|
2,252
|
|
|
2,889
|
|
|
1,443
|
|
|
1,357
|
|
||||
Interest cost
|
19,500
|
|
|
19,761
|
|
|
4,700
|
|
|
4,817
|
|
||||
Plan participants' contributions
|
—
|
|
|
—
|
|
|
2,644
|
|
|
2,500
|
|
||||
Amendments
|
—
|
|
|
353
|
|
|
—
|
|
|
121
|
|
||||
Actuarial loss
|
62,722
|
|
|
34,687
|
|
|
17,940
|
|
|
3,228
|
|
||||
Curtailment gain
|
(13,939
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Benefits paid
|
(23,506
|
)
|
|
(22,016
|
)
|
|
(7,324
|
)
|
|
(8,888
|
)
|
||||
Benefit obligation at end of year
|
435,618
|
|
|
388,589
|
|
|
110,689
|
|
|
91,286
|
|
||||
Change in net plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Fair value of plan assets at beginning of year
|
277,598
|
|
|
255,327
|
|
|
70,610
|
|
|
66,984
|
|
||||
Actual gain (loss) on plan assets
|
(4,718
|
)
|
|
37,853
|
|
|
(872
|
)
|
|
7,278
|
|
||||
Employer contribution
|
28,626
|
|
|
6,434
|
|
|
3,027
|
|
|
2,736
|
|
||||
Plan participants' contributions
|
—
|
|
|
—
|
|
|
2,644
|
|
|
2,500
|
|
||||
Benefits paid
|
(23,506
|
)
|
|
(22,016
|
)
|
|
(7,324
|
)
|
|
(8,888
|
)
|
||||
Fair value of net plan assets at end of year
|
278,000
|
|
|
277,598
|
|
|
68,085
|
|
|
70,610
|
|
||||
Funded status - under
|
$
|
(157,618
|
)
|
|
$
|
(110,991
|
)
|
|
$
|
(42,604
|
)
|
|
$
|
(20,676
|
)
|
Amounts recognized in the Consolidated Balance Sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other accrued liabilities (current)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(550
|
)
|
|
$
|
(525
|
)
|
Other liabilities (noncurrent)
|
(157,618
|
)
|
|
(110,991
|
)
|
|
(42,054
|
)
|
|
(20,151
|
)
|
||||
Net amount recognized
|
$
|
(157,618
|
)
|
|
$
|
(110,991
|
)
|
|
$
|
(42,604
|
)
|
|
$
|
(20,676
|
)
|
Amounts recognized in accumulated other comprehensive (income) loss consist of:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Actuarial loss
|
$
|
189,494
|
|
|
$
|
117,840
|
|
|
$
|
43,861
|
|
|
$
|
20,751
|
|
Prior service cost (credit)
|
(632
|
)
|
|
631
|
|
|
(8,615
|
)
|
|
(11,292
|
)
|
||||
Transition obligation
|
—
|
|
|
—
|
|
|
2,128
|
|
|
4,253
|
|
||||
Total
|
$
|
188,862
|
|
|
$
|
118,471
|
|
|
$
|
37,374
|
|
|
$
|
13,712
|
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Projected benefit obligation
|
$
|
435,618
|
|
|
$
|
388,589
|
|
Accumulated benefit obligation
|
$
|
435,618
|
|
|
$
|
374,538
|
|
Fair value of plan assets
|
$
|
278,000
|
|
|
$
|
277,598
|
|
|
Pension Benefits
|
|
Other
Postretirement Benefits
|
||||||||||||||||||||
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
||||||
|
(In thousands)
|
||||||||||||||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
2,252
|
|
|
$
|
2,889
|
|
|
$
|
8,127
|
|
|
$
|
1,443
|
|
|
$
|
1,357
|
|
|
$
|
2,206
|
|
Interest cost
|
19,500
|
|
|
19,761
|
|
|
21,919
|
|
|
4,700
|
|
|
4,817
|
|
|
5,465
|
|
||||||
Expected return on assets
|
(22,809
|
)
|
|
(23,643
|
)
|
|
(25,062
|
)
|
|
(5,051
|
)
|
|
(5,512
|
)
|
|
(5,471
|
)
|
||||||
Amortization of prior service cost (credit)
|
45
|
|
|
152
|
|
|
605
|
|
|
(2,677
|
)
|
|
(3,303
|
)
|
|
(2,756
|
)
|
||||||
Recognized net actuarial loss
|
4,656
|
|
|
2,622
|
|
|
2,096
|
|
|
753
|
|
|
845
|
|
|
970
|
|
||||||
Curtailment loss
|
1,218
|
|
|
—
|
|
|
1,650
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net transition obligation
|
—
|
|
|
—
|
|
|
—
|
|
|
2,125
|
|
|
2,125
|
|
|
2,125
|
|
||||||
Net periodic benefit cost, including amount capitalized
|
4,862
|
|
|
1,781
|
|
|
9,335
|
|
|
1,293
|
|
|
329
|
|
|
2,539
|
|
||||||
Less amount capitalized
|
1,196
|
|
|
791
|
|
|
1,127
|
|
|
(50
|
)
|
|
(92
|
)
|
|
330
|
|
||||||
Net periodic benefit cost
|
3,666
|
|
|
990
|
|
|
8,208
|
|
|
1,343
|
|
|
421
|
|
|
2,209
|
|
||||||
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive (income) loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net (gain) loss
|
76,310
|
|
|
20,477
|
|
|
(29,000
|
)
|
|
23,863
|
|
|
1,462
|
|
|
(2,314
|
)
|
||||||
Prior service cost (credit)
|
—
|
|
|
353
|
|
|
—
|
|
|
—
|
|
|
121
|
|
|
(9,321
|
)
|
||||||
Amortization of actuarial loss
|
(4,656
|
)
|
|
(2,622
|
)
|
|
(2,096
|
)
|
|
(753
|
)
|
|
(845
|
)
|
|
(970
|
)
|
||||||
Amortization of prior service (cost) credit
|
(1,263
|
)
|
|
(152
|
)
|
|
(2,255
|
)
|
|
2,677
|
|
|
3,303
|
|
|
2,756
|
|
||||||
Amortization of net transition obligation
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,125
|
)
|
|
(2,125
|
)
|
|
(2,125
|
)
|
||||||
Total recognized in accumulated other comprehensive (income) loss
|
70,391
|
|
|
18,056
|
|
|
(33,351
|
)
|
|
23,662
|
|
|
1,916
|
|
|
(11,974
|
)
|
||||||
Total recognized in net periodic benefit cost and accumulated other comprehensive (income) loss
|
$
|
74,057
|
|
|
$
|
19,046
|
|
|
$
|
(25,143
|
)
|
|
$
|
25,005
|
|
|
$
|
2,337
|
|
|
$
|
(9,765
|
)
|
|
Pension Benefits
|
|
Other
Postretirement Benefits
|
||||||||
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
Discount rate
|
4.16
|
%
|
|
5.26
|
%
|
|
4.13
|
%
|
|
5.21
|
%
|
Expected return on plan assets
|
7.75
|
%
|
|
7.75
|
%
|
|
6.75
|
%
|
|
6.75
|
%
|
Rate of compensation increase
|
N/A
|
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
1 Percentage
Point Increase
|
|
|
1 Percentage Point
Decrease
|
|
||
|
(In thousands)
|
||||||
Effect on total of service and interest cost components
|
$
|
171
|
|
|
$
|
(822
|
)
|
Effect on postretirement benefit obligation
|
$
|
3,175
|
|
|
$
|
(10,946
|
)
|
|
Fair Value Measurements at
December 31, 2011, Using
|
|
|
||||||||||||
|
Quoted Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant Other Observable Inputs
(Level 2)
|
|
|
Significant Unobservable
Inputs
(Level 3)
|
|
|
Balance at December 31, 2011
|
|
||||
|
(In thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
2,256
|
|
|
$
|
17,534
|
|
|
$
|
—
|
|
|
$
|
19,790
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|||||||
U.S. companies
|
99,315
|
|
|
—
|
|
|
—
|
|
|
99,315
|
|
||||
International companies
|
35,353
|
|
|
—
|
|
|
—
|
|
|
35,353
|
|
||||
Collective and mutual funds (a)
|
43,214
|
|
|
15,541
|
|
|
—
|
|
|
58,755
|
|
||||
Corporate bonds
|
—
|
|
|
23,579
|
|
|
289
|
|
|
23,868
|
|
||||
Mortgage-backed securities
|
—
|
|
|
22,987
|
|
|
—
|
|
|
22,987
|
|
||||
Municipal bonds
|
—
|
|
|
9,290
|
|
|
—
|
|
|
9,290
|
|
||||
U.S. Treasury securities
|
—
|
|
|
8,642
|
|
|
—
|
|
|
8,642
|
|
||||
Total assets measured at fair value
|
$
|
180,138
|
|
|
$
|
97,573
|
|
|
$
|
289
|
|
|
$
|
278,000
|
|
|
Fair Value Measurements at
December 31, 2010, Using
|
|
|
||||||||||||
|
Quoted Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant Other Observable Inputs
(Level 2)
|
|
|
Significant Unobservable
Inputs
(Level 3)
|
|
|
Balance at December 31, 2010
|
|
||||
|
(In thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
4,663
|
|
|
$
|
8,699
|
|
|
$
|
—
|
|
|
$
|
13,362
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
U.S. companies
|
102,944
|
|
|
—
|
|
|
—
|
|
|
102,944
|
|
||||
International companies
|
40,017
|
|
|
—
|
|
|
—
|
|
|
40,017
|
|
||||
Collective and mutual funds (a)
|
45,410
|
|
|
17,701
|
|
|
—
|
|
|
63,111
|
|
||||
Collateral held on loaned securities (b)
|
—
|
|
|
23,148
|
|
|
694
|
|
|
23,842
|
|
||||
Corporate bonds
|
—
|
|
|
23,014
|
|
|
—
|
|
|
23,014
|
|
||||
Mortgage-backed securities
|
—
|
|
|
19,478
|
|
|
—
|
|
|
19,478
|
|
||||
U.S. Treasury securities
|
—
|
|
|
9,239
|
|
|
—
|
|
|
9,239
|
|
||||
Municipal bonds
|
—
|
|
|
8,285
|
|
|
—
|
|
|
8,285
|
|
||||
Total assets measured at fair value
|
193,034
|
|
|
109,564
|
|
|
694
|
|
|
303,292
|
|
||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Obligation for collateral received
|
25,694
|
|
|
—
|
|
|
—
|
|
|
25,694
|
|
||||
Net assets measured at fair value
|
$
|
167,340
|
|
|
$
|
109,564
|
|
|
$
|
694
|
|
|
$
|
277,598
|
|
|
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
|
||||||||
|
Corporate Bonds
|
|
Collateral Held on Loaned Securities
|
|
Total
|
|
|||
|
(In thousands)
|
||||||||
Balance at beginning of year
|
$
|
—
|
|
$
|
694
|
|
$
|
694
|
|
Total realized/unrealized losses
|
(2
|
)
|
(259
|
)
|
(261
|
)
|
|||
Purchases, issuances and settlements (net)
|
291
|
|
(435
|
)
|
(144
|
)
|
|||
Balance at end of year
|
$
|
289
|
|
$
|
—
|
|
$
|
289
|
|
|
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
|
|||
|
|
Collateral Held on Loaned Securities
|
|
|
|
|
(In thousands)
|
|
|
Balance at beginning of year
|
|
$
|
937
|
|
Total realized/unrealized losses
|
|
189
|
|
|
Purchases, issuances and settlements (net)
|
|
(432
|
)
|
|
Balance at end of year
|
|
$
|
694
|
|
|
Fair Value Measurements
at December 31, 2011, Using
|
|
|
||||||||||||
|
Quoted Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant Other Observable Inputs
(Level 2)
|
|
|
Significant Unobservable
Inputs
(Level 3)
|
|
|
Balance at December 31, 2011
|
|
||||
|
(In thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
59
|
|
|
$
|
1,836
|
|
|
$
|
—
|
|
|
$
|
1,895
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|||||||
U.S. companies
|
2,098
|
|
|
—
|
|
|
—
|
|
|
2,098
|
|
||||
International companies
|
262
|
|
|
—
|
|
|
—
|
|
|
262
|
|
||||
Insurance investment contract*
|
—
|
|
|
63,830
|
|
|
—
|
|
|
63,830
|
|
||||
Total assets measured at fair value
|
$
|
2,419
|
|
|
$
|
65,666
|
|
|
$
|
—
|
|
|
$
|
68,085
|
|
|
Fair Value Measurements
at December 31, 2010, Using
|
|
|
||||||||||||
|
Quoted Prices in Active Markets for Identical Assets
(Level 1)
|
|
|
Significant Other Observable Inputs
(Level 2)
|
|
|
Significant Unobservable
Inputs
(Level 3)
|
|
|
Balance at December 31, 2010
|
|
||||
|
(In thousands)
|
||||||||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
53
|
|
|
$
|
1,274
|
|
|
$
|
—
|
|
|
$
|
1,327
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
U.S. companies
|
2,791
|
|
|
—
|
|
|
—
|
|
|
2,791
|
|
||||
International companies
|
353
|
|
|
—
|
|
|
—
|
|
|
353
|
|
||||
Insurance investment contract*
|
—
|
|
|
66,139
|
|
|
—
|
|
|
66,139
|
|
||||
Total assets measured at fair value
|
$
|
3,197
|
|
|
$
|
67,413
|
|
|
$
|
—
|
|
|
$
|
70,610
|
|
Years
|
Pension
Benefits
|
|
|
Other Postretirement Benefits
|
|
|
Expected
Medicare
Part D Subsidy
|
|
|||
|
(In thousands)
|
||||||||||
2012
|
$
|
22,426
|
|
|
$
|
6,892
|
|
|
$
|
618
|
|
2013
|
22,811
|
|
|
7,062
|
|
|
656
|
|
|||
2014
|
23,082
|
|
|
7,188
|
|
|
694
|
|
|||
2015
|
23,508
|
|
|
7,298
|
|
|
730
|
|
|||
2016
|
23,893
|
|
|
7,371
|
|
|
766
|
|
|||
2017 - 2021
|
127,895
|
|
|
37,682
|
|
|
4,322
|
|
•
|
Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers
|
•
|
If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers
|
•
|
If the Company chooses to stop participating in some of its multiemployer plans, the Company may be required to pay those plans an amount based on the underfunded status of the plan, referred to as a withdrawal liability
|
Pension Fund
|
Year Contributions to Plan Exceeded More Than 5 Percent of Total Contributions (as of December 31 of the Plan's Year-End)
|
Defined Benefit Pension Plan of AGC-IUOE Local 701 Pension Trust Fund
|
2010 and 2009
|
Edison Pension Plan
|
2010 and 2009
|
Eighth District Electrical Pension Fund
|
2010 and 2009
|
IBEW Local 38 Pension Plan
|
2010 and 2009
|
IBEW Local No. 82 Pension Plan
|
2010 and 2009
|
IBEW Local Union No. 357 Pension Plan A
|
2010 and 2009
|
IBEW Local 648 Pension Plan
|
2010 and 2009
|
Idaho Plumbers and Pipefitters Pension Plan
|
2010 and 2009
|
Laborers AGC Pension Trust of Montana
|
2009
|
Local Union No. 124 IBEW Pension Trust Fund
|
2010 and 2009
|
Local Union 212 IBEW Pension Trust Fund
|
2010 and 2009
|
Minnesota Teamsters Constr Division Pension Fund
|
2010 and 2009
|
Operating Engineers Local 800 and Wyoming Contractors Association, Inc. Pension Plan for Wyoming
|
2010 and 2009
|
Plumbers & Pipefitters Local 162 Pension Fund
|
2010 and 2009
|
Southwest Marine Pension Trust
|
2009
|
|
2011
|
|
|
2010
|
|
||
|
(In thousands)
|
||||||
Big Stone Station:
|
|
|
|
||||
Utility plant in service
|
$
|
63,715
|
|
|
$
|
60,404
|
|
Less accumulated depreciation
|
42,475
|
|
|
41,136
|
|
||
|
$
|
21,240
|
|
|
$
|
19,268
|
|
Coyote Station:
|
|
|
|
|
|
||
Utility plant in service
|
$
|
131,719
|
|
|
$
|
131,395
|
|
Less accumulated depreciation
|
86,788
|
|
|
84,710
|
|
||
|
$
|
44,931
|
|
|
$
|
46,685
|
|
Wygen III:*
|
|
|
|
|
|
||
Utility plant in service
|
$
|
63,300
|
|
|
$
|
63,215
|
|
Less accumulated depreciation
|
2,106
|
|
|
838
|
|
||
|
$
|
61,194
|
|
|
$
|
62,377
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
*
|
Fourth
Quarter
|
|
**
|
||||
|
(In thousands, except per share amounts)
|
|
||||||||||||||
2011
|
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
901,805
|
|
|
$
|
930,757
|
|
|
$
|
1,152,181
|
|
|
$
|
1,065,749
|
|
|
Operating expenses
|
823,739
|
|
|
848,454
|
|
|
1,032,760
|
|
|
939,172
|
|
|
||||
Operating income
|
78,066
|
|
|
82,303
|
|
|
119,421
|
|
|
126,577
|
|
|
||||
Income from continuing operations
|
42,529
|
|
|
45,235
|
|
|
64,100
|
|
|
74,088
|
|
|
||||
Income (loss) from discontinued operations, net of tax
|
448
|
|
|
(168
|
)
|
|
(126
|
)
|
|
(13,080
|
)
|
|
||||
Net income
|
42,977
|
|
|
45,067
|
|
|
63,974
|
|
|
61,008
|
|
|
||||
Earnings per common share - basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Earnings before discontinued operations
|
.22
|
|
|
.24
|
|
|
.34
|
|
|
.39
|
|
|
||||
Discontinued operations, net of tax
|
.01
|
|
|
—
|
|
|
—
|
|
|
(.07
|
)
|
|
||||
Earnings per common share - basic
|
.23
|
|
|
.24
|
|
|
.34
|
|
|
.32
|
|
|
||||
Earnings per common share - diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Earnings before discontinued operations
|
.22
|
|
|
.24
|
|
|
.34
|
|
|
.39
|
|
|
||||
Discontinued operations, net of tax
|
.01
|
|
|
—
|
|
|
—
|
|
|
(.07
|
)
|
|
||||
Earnings per common share - diluted
|
.23
|
|
|
.24
|
|
|
.34
|
|
|
.32
|
|
|
||||
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
188,671
|
|
|
188,794
|
|
|
188,794
|
|
|
188,794
|
|
|
||||
Diluted
|
188,815
|
|
|
188,968
|
|
|
188,797
|
|
|
188,932
|
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating revenues
|
$
|
834,777
|
|
|
$
|
906,444
|
|
|
$
|
1,125,923
|
|
|
$
|
1,042,551
|
|
|
Operating expenses
|
751,848
|
|
|
817,782
|
|
|
1,016,961
|
|
|
912,377
|
|
|
||||
Operating income
|
82,929
|
|
|
88,662
|
|
|
108,962
|
|
|
130,174
|
|
|
||||
Income from continuing operations
|
41,772
|
|
|
48,938
|
|
|
61,010
|
|
|
92,300
|
|
|
||||
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,361
|
)
|
|
||||
Net income
|
41,772
|
|
|
48,938
|
|
|
61,010
|
|
|
88,939
|
|
|
||||
Earnings per common share - basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Earnings before discontinued operations
|
.22
|
|
|
.26
|
|
|
.32
|
|
|
.49
|
|
|
||||
Discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
(.02
|
)
|
|
||||
Earnings per common share - basic
|
.22
|
|
|
.26
|
|
|
.32
|
|
|
.47
|
|
|
||||
Earnings per common share - diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Earnings before discontinued operations
|
.22
|
|
|
.26
|
|
|
.32
|
|
|
.49
|
|
|
||||
Discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
(.02
|
)
|
|
||||
Earnings per common share - diluted
|
.22
|
|
|
.26
|
|
|
.32
|
|
|
.47
|
|
|
||||
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
187,963
|
|
|
188,129
|
|
|
188,170
|
|
|
188,281
|
|
|
||||
Diluted
|
188,220
|
|
|
188,267
|
|
|
188,338
|
|
|
188,374
|
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Subject to amortization
|
$
|
2,345,114
|
|
|
$
|
2,138,565
|
|
|
$
|
1,815,380
|
|
Not subject to amortization
|
232,462
|
|
|
182,402
|
|
|
178,214
|
|
|||
Total capitalized costs
|
2,577,576
|
|
|
2,320,967
|
|
|
1,993,594
|
|
|||
Less accumulated depreciation, depletion and amortization
|
1,229,654
|
|
|
1,093,723
|
|
|
969,630
|
|
|||
Net capitalized costs
|
$
|
1,347,922
|
|
|
$
|
1,227,244
|
|
|
$
|
1,023,964
|
|
Years ended December 31,
|
2011
|
|
*
|
2010
|
|
*
|
2009
|
|
*
|
|||
|
(In thousands)
|
|
||||||||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|||
Proved properties
|
$
|
3,999
|
|
|
$
|
89,733
|
|
|
$
|
3,879
|
|
|
Unproved properties
|
63,354
|
|
|
92,100
|
|
|
8,771
|
|
|
|||
Exploration
|
41,775
|
|
|
33,226
|
|
|
33,123
|
|
|
|||
Development
|
161,647
|
|
|
139,733
|
|
|
135,202
|
|
|
|||
Total capital expenditures
|
$
|
270,775
|
|
|
$
|
354,792
|
|
|
$
|
180,975
|
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Revenues:
|
|
|
|
|
|
||||||
Sales to affiliates
|
$
|
93,713
|
|
|
$
|
115,784
|
|
|
$
|
101,230
|
|
Sales to external customers
|
359,873
|
|
|
318,565
|
|
|
338,425
|
|
|||
Production costs
|
140,606
|
|
|
127,403
|
|
|
123,148
|
|
|||
Depreciation, depletion and amortization*
|
139,539
|
|
|
127,266
|
|
|
126,278
|
|
|||
Write-down of natural gas and oil properties
|
—
|
|
|
—
|
|
|
620,000
|
|
|||
Pretax income
|
173,441
|
|
|
179,680
|
|
|
(429,771
|
)
|
|||
Income tax expense
|
63,655
|
|
|
66,293
|
|
|
(164,216
|
)
|
|||
Results of operations for producing activities
|
$
|
109,786
|
|
|
$
|
113,387
|
|
|
$
|
(265,555
|
)
|
|
Natural Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Total
(MMcfe)
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|||
Balance at beginning of year
|
448,397
|
|
|
32,867
|
|
|
645,596
|
|
Production
|
(45,598
|
)
|
|
(3,500
|
)
|
|
(66,596
|
)
|
Extensions and discoveries
|
28,221
|
|
|
6,138
|
|
|
65,049
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of proved reserves
|
54
|
|
|
239
|
|
|
1,486
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
(51,247
|
)
|
|
(1,397
|
)
|
|
(59,627
|
)
|
Balance at end of year
|
379,827
|
|
|
34,347
|
|
|
585,908
|
|
•
|
Extensions and discoveries of
65.0 Bcfe
primarily due to drilling activity at the Company's Bakken and Big Horn properties
|
•
|
Revisions of previous estimates of
(59.6) Bcfe
, largely the result of a reduction in PUD reserves of
53.6 Bcfe
resulting principally in the Company's Bowdoin, Baker, Coalbed, East Texas and Big Horn Basin properties. The remaining negative revisions were a reduction in PDP natural gas reserves.
|
|
Natural Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Total
(MMcfe)
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|||
Balance at beginning of year
|
448,425
|
|
|
34,216
|
|
|
653,724
|
|
Production
|
(50,391
|
)
|
|
(3,262
|
)
|
|
(69,963
|
)
|
Extensions and discoveries
|
36,191
|
|
|
3,389
|
|
|
56,523
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of proved reserves
|
55,119
|
|
|
979
|
|
|
60,991
|
|
Sales of proved reserves
|
(92
|
)
|
|
(18
|
)
|
|
(202
|
)
|
Revisions of previous estimates
|
(40,855
|
)
|
|
(2,437
|
)
|
|
(55,477
|
)
|
Balance at end of year
|
448,397
|
|
|
32,867
|
|
|
645,596
|
|
•
|
Extensions and discoveries of
56.5 Bcfe
primarily due to drilling activity at the Company's Bakken, Baker, Bowdoin and east Texas properties
|
•
|
Purchases of proved reserves of
61.0 Bcfe
as a result of the Company's acquisition of natural gas properties in the Green River Basin in Wyoming, as discussed in Note 2
|
•
|
Revisions of previous estimates of
(55.5) Bcfe
largely the result of negative performance revisions resulting primarily from new information gained from production history and developmental drilling activity in the Company's Bowdoin, south Texas, Baker and east Texas properties and removal of PUD reserves due to the five-year limitation rule, partially offset by positive revisions due to increased natural gas and oil prices
|
|
Natural Gas
(MMcf)
|
|
|
Oil
(MBbls)
|
|
|
Total
(MMcfe)
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|||
Balance at beginning of year
|
604,282
|
|
|
34,348
|
|
|
810,371
|
|
Production
|
(56,632
|
)
|
|
(3,111
|
)
|
|
(75,299
|
)
|
Extensions and discoveries
|
26,882
|
|
|
2,569
|
|
|
42,297
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
(22
|
)
|
|
(248
|
)
|
|
(1,510
|
)
|
Revisions of previous estimates
|
(126,085
|
)
|
|
658
|
|
|
(122,135
|
)
|
Balance at end of year
|
448,425
|
|
|
34,216
|
|
|
653,724
|
|
•
|
Extensions and discoveries of
42.3 Bcfe
primarily due to drilling activity at the Company's Bowdoin, Bakken, Baker and east Texas properties
|
•
|
Revisions of previous estimates of
(122.1) Bcfe
largely the result of negative revisions resulting from decreased natural gas and oil prices and negative performance revisions resulting primarily from new information gained from production history and developmental drilling activity in the Company's east Texas and south Texas properties
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
Proved developed reserves:
|
|
|
|
|
|
|||
Natural Gas (MMcf)
|
303,495
|
|
|
334,911
|
|
|
321,561
|
|
Oil (MBbls)
|
28,878
|
|
|
26,586
|
|
|
26,794
|
|
Total (MMcfe)
|
476,763
|
|
|
494,426
|
|
|
482,329
|
|
PUD reserves:
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf)
|
76,332
|
|
|
113,486
|
|
|
126,864
|
|
Oil (MBbls)
|
5,469
|
|
|
6,281
|
|
|
7,422
|
|
Total (MMcfe)
|
109,145
|
|
|
151,170
|
|
|
171,395
|
|
Total proved reserves:
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf)
|
379,827
|
|
|
448,397
|
|
|
448,425
|
|
Oil (MBbls)
|
34,347
|
|
|
32,867
|
|
|
34,216
|
|
Total (MMcfe)
|
585,908
|
|
|
645,596
|
|
|
653,724
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Future cash inflows
|
$
|
4,188,000
|
|
|
$
|
3,790,700
|
|
|
$
|
2,991,200
|
|
Future production costs
|
1,560,300
|
|
|
1,393,000
|
|
|
1,095,600
|
|
|||
Future development costs
|
285,300
|
|
|
312,500
|
|
|
315,000
|
|
|||
Future net cash flows before income taxes
|
2,342,400
|
|
|
2,085,200
|
|
|
1,580,600
|
|
|||
Future income tax expense
|
531,100
|
|
|
432,800
|
|
|
291,000
|
|
|||
Future net cash flows
|
1,811,300
|
|
|
1,652,400
|
|
|
1,289,600
|
|
|||
10% annual discount for estimated timing of cash flows
|
832,500
|
|
|
756,300
|
|
|
630,800
|
|
|||
Discounted future net cash flows relating to proved natural gas and oil reserves
|
$
|
978,800
|
|
|
$
|
896,100
|
|
|
$
|
658,800
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Beginning of year
|
$
|
896,100
|
|
|
$
|
658,800
|
|
|
$
|
969,800
|
|
Net revenues from production
|
(301,500
|
)
|
|
(270,000
|
)
|
|
(200,900
|
)
|
|||
Net change in sales prices and production costs related to future production
|
82,300
|
|
|
362,400
|
|
|
(364,800
|
)
|
|||
Extensions and discoveries, net of future production-related costs
|
226,300
|
|
|
130,500
|
|
|
70,500
|
|
|||
Improved recovery, net of future production-related costs
|
—
|
|
|
—
|
|
|
—
|
|
|||
Purchases of proved reserves, net of future production-related costs
|
9,500
|
|
|
99,800
|
|
|
—
|
|
|||
Sales of proved reserves
|
—
|
|
|
(500
|
)
|
|
(1,100
|
)
|
|||
Changes in estimated future development costs
|
51,100
|
|
|
34,100
|
|
|
43,600
|
|
|||
Development costs incurred during the current year
|
56,300
|
|
|
43,100
|
|
|
46,400
|
|
|||
Accretion of discount
|
105,000
|
|
|
76,500
|
|
|
115,900
|
|
|||
Net change in income taxes
|
(55,800
|
)
|
|
(103,300
|
)
|
|
142,800
|
|
|||
Revisions of previous estimates
|
(92,900
|
)
|
|
(132,000
|
)
|
|
(155,500
|
)
|
|||
Other
|
2,400
|
|
|
(3,300
|
)
|
|
(7,900
|
)
|
|||
Net change
|
82,700
|
|
|
237,300
|
|
|
(311,000
|
)
|
|||
End of year
|
$
|
978,800
|
|
|
$
|
896,100
|
|
|
$
|
658,800
|
|
Item 9.
|
Changes
in
and Disagreements With Accountants on Accounting and Financial Disclosure
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
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)
|
|
768,904
|
|
(2)
|
$
|
19.30
|
|
|
6,310,260
|
|
(3)(4)
|
Equity compensation plans not approved by stockholders
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
|
(1) Consists of the Non-Employee Director Long-Term Incentive Compensation Plan, the Long-Term Performance-Based Incentive Plan and the Non-Employee Director Stock Compensation Plan.
|
|||||||||||
(2) Includes 762,154 performance shares.
|
|||||||||||
(3) In addition to being available for issuance upon exercise of options, 357,757 shares remain available for future issuance under the Non-Employee Director Long-Term Incentive Compensation Plan in connection with grants of stock appreciation rights, restricted stock, performance units, performance shares or other equity-based awards. 5,686,144 shares under the Long-Term Performance-Based Incentive Plan remain available for future issuance in connection with grants of restricted stock, performance units, performance shares or other equity-based awards.
|
|||||||||||
(4) This amount also includes 266,359 shares available for issuance under the Non-Employee Director Stock Compensation Plan. Under this plan, in addition to a cash retainer, non-employee directors are awarded shares equal in value to $110,000 annually. A non-employee director may acquire additional shares under the plan in lieu of receiving the cash portion of the director's retainer or fees.
|
(a) Financial Statements, Financial Statement Schedules and Exhibits
|
1. Financial Statements
|
|
The following consolidated financial statements required under this item are included under Item 8 - Financial Statements and Supplementary Data.
|
Page
|
|
|
|
|
|
|
|
|
|
|
2. Financial Statement Schedules
The following financial statement schedules are included in Part IV of this report.
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Operating revenues
|
$
|
518,268
|
|
|
$
|
503,658
|
|
|
$
|
514,519
|
|
Operating expenses
|
450,579
|
|
|
431,293
|
|
|
458,130
|
|
|||
Operating income
|
67,689
|
|
|
72,365
|
|
|
56,389
|
|
|||
Other income
|
2,710
|
|
|
5,734
|
|
|
6,588
|
|
|||
Interest expense
|
18,660
|
|
|
16,664
|
|
|
13,996
|
|
|||
Income before income taxes
|
51,739
|
|
|
61,435
|
|
|
48,981
|
|
|||
Income taxes
|
10,476
|
|
|
17,983
|
|
|
13,279
|
|
|||
Equity in earnings of subsidiaries
|
171,763
|
|
|
197,207
|
|
|
(158,976
|
)
|
|||
Net income
|
213,026
|
|
|
240,659
|
|
|
(123,274
|
)
|
|||
Dividends declared on preferred stocks
|
685
|
|
|
685
|
|
|
685
|
|
|||
Earnings on common stock
|
$
|
212,341
|
|
|
$
|
239,974
|
|
|
$
|
(123,959
|
)
|
December 31,
|
2011
|
|
|
2010
|
|
||
(In thousands, except shares and per share amounts)
|
|
||||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
6,900
|
|
|
$
|
6,275
|
|
Receivables, net
|
67,761
|
|
|
76,757
|
|
||
Accounts receivable from subsidiaries
|
28,734
|
|
|
27,837
|
|
||
Inventories
|
42,596
|
|
|
34,583
|
|
||
Deferred income taxes
|
2
|
|
|
—
|
|
||
Prepayments and other current assets
|
12,154
|
|
|
15,473
|
|
||
Total current assets
|
158,147
|
|
|
160,925
|
|
||
Investments
|
47,835
|
|
|
48,038
|
|
||
Investment in subsidiaries
|
2,402,891
|
|
|
2,336,133
|
|
||
Property, plant and equipment
|
1,453,089
|
|
|
1,388,128
|
|
||
Less accumulated depreciation, depletion and amortization
|
605,510
|
|
|
583,447
|
|
||
Net property, plant and equipment
|
847,579
|
|
|
804,681
|
|
||
Deferred charges and other assets:
|
|
|
|
||||
Goodwill
|
4,812
|
|
|
4,812
|
|
||
Other
|
166,732
|
|
|
119,081
|
|
||
Total deferred charges and other assets
|
171,544
|
|
|
123,893
|
|
||
Total assets
|
$
|
3,627,996
|
|
|
$
|
3,473,670
|
|
|
|
|
|
||||
Liabilities and Stockholders' Equity
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Short-term borrowings
|
$
|
—
|
|
|
$
|
20,000
|
|
Long-term debt due within one year
|
107
|
|
|
107
|
|
||
Accounts payable
|
37,986
|
|
|
36,235
|
|
||
Accounts payable to subsidiaries
|
4,868
|
|
|
9,445
|
|
||
Taxes payable
|
18,304
|
|
|
8,104
|
|
||
Deferred income taxes
|
—
|
|
|
469
|
|
||
Dividends payable
|
31,794
|
|
|
30,773
|
|
||
Accrued compensation
|
10,173
|
|
|
11,540
|
|
||
Other accrued liabilities
|
27,064
|
|
|
26,002
|
|
||
Total current liabilities
|
130,296
|
|
|
142,675
|
|
||
Long-term debt
|
280,781
|
|
|
280,889
|
|
||
Deferred credits and other liabilities:
|
|
|
|
||||
Deferred income taxes
|
137,751
|
|
|
103,725
|
|
||
Other liabilities
|
303,601
|
|
|
253,579
|
|
||
Total deferred credits and other liabilities
|
441,352
|
|
|
357,304
|
|
||
Commitments and contingencies
|
|
|
|
|
|
||
Stockholders' equity:
|
|
|
|
|
|
||
Preferred stocks
|
15,000
|
|
|
15,000
|
|
||
Common stockholders' equity:
|
|
|
|
|
|
||
Common stock
|
|
|
|
|
|
||
Authorized - 500,000,000 shares, $1.00 par value
|
|
|
|
|
|||
Issued - 188,332,485 shares in 2011 and 188,901,379 shares in 2010
|
189,332
|
|
|
188,901
|
|
||
Other paid-in capital
|
1,035,739
|
|
|
1,026,349
|
|
||
Retained earnings
|
1,586,123
|
|
|
1,497,439
|
|
||
Accumulated other comprehensive loss
|
(47,001
|
)
|
|
(31,261
|
)
|
||
Treasury stock at cost - 538,921 shares
|
(3,626
|
)
|
|
(3,626
|
)
|
||
Total common stockholders' equity
|
2,760,567
|
|
|
2,677,802
|
|
||
Total stockholders' equity
|
2,775,567
|
|
|
2,692,802
|
|
||
Total liabilities and stockholders' equity
|
$
|
3,627,996
|
|
|
$
|
3,473,670
|
|
Years ended December 31,
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
(In thousands)
|
||||||||||
Net cash provided by operating activities
|
$
|
217,514
|
|
|
$
|
185,887
|
|
|
$
|
209,128
|
|
Investing activities:
|
|
|
|
|
|
|
|
||||
Capital expenditures
|
(74,580
|
)
|
|
(114,045
|
)
|
|
(120,352
|
)
|
|||
Net proceeds from sale or disposition of property and other
|
720
|
|
|
625
|
|
|
1,039
|
|
|||
Investments in and advances to subsidiaries
|
(5,701
|
)
|
|
(1,636
|
)
|
|
—
|
|
|||
Investments from and advances from subsidiaries
|
—
|
|
|
—
|
|
|
2,916
|
|
|||
Disposition of investments in subsidiaries
|
—
|
|
|
—
|
|
|
20,000
|
|
|||
Investments
|
—
|
|
|
(742
|
)
|
|
(637
|
)
|
|||
Net cash used in investing activities
|
(79,561
|
)
|
|
(115,798
|
)
|
|
(97,034
|
)
|
|||
Financing activities:
|
|
|
|
|
|
|
|
||||
Issuance of short-term borrowings
|
—
|
|
|
20,000
|
|
|
—
|
|
|||
Repayment of short-term borrowings
|
(20,000
|
)
|
|
—
|
|
|
—
|
|
|||
Issuance of long-term debt
|
—
|
|
|
—
|
|
|
50,000
|
|
|||
Repayment of long-term debt
|
(107
|
)
|
|
(107
|
)
|
|
(85,104
|
)
|
|||
Proceeds from issuance of common stock
|
5,744
|
|
|
4,972
|
|
|
65,207
|
|
|||
Dividends paid
|
(123,323
|
)
|
|
(119,157
|
)
|
|
(115,023
|
)
|
|||
Tax benefit on stock-based compensation
|
358
|
|
|
375
|
|
|
264
|
|
|||
Net cash used in financing activities
|
(137,328
|
)
|
|
(93,917
|
)
|
|
(84,656
|
)
|
|||
Increase (decrease) in cash and cash equivalents
|
625
|
|
|
(23,828
|
)
|
|
27,438
|
|
|||
Cash and cash equivalents - beginning of year
|
6,275
|
|
|
30,103
|
|
|
2,665
|
|
|||
Cash and cash equivalents - end of year
|
$
|
6,900
|
|
|
$
|
6,275
|
|
|
$
|
30,103
|
|
For the years ended December 31, 2011, 2010 and 2009
|
|||||||||||||||||||
|
|
|
Additions
|
|
|
|
|||||||||||||
Description
|
Balance at Beginning of Year
|
|
|
Charged to Costs and Expenses
|
|
|
Other
|
|
*
|
Deductions
|
|
**
|
Balance at End of Year
|
|
|||||
|
(In thousands)
|
||||||||||||||||||
Allowance for doubtful accounts:
|
|
|
|
|
|
|
|
|
|||||||||||
2011
|
$
|
15,284
|
|
|
$
|
3,977
|
|
|
$
|
2,112
|
|
|
$
|
8,966
|
|
|
$
|
12,407
|
|
2010
|
16,649
|
|
|
5,044
|
|
|
2,300
|
|
|
8,709
|
|
|
15,284
|
|
|||||
2009
|
13,691
|
|
|
12,152
|
|
|
1,412
|
|
|
10,606
|
|
|
16,649
|
|
3(a)
|
Restated Certificate of Incorporation of the Company, as amended, dated May 13, 2010, filed as Exhibit 3(a) to Form 10-Q for the quarter ended September 30, 2010, filed on November 3, 2010, in File No. 1-3480*
|
|
|
3(b)
|
Company Bylaws, as amended and restated, on November 17, 2011**
|
|
|
4(a)
|
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(b)
|
First Supplemental Indenture, dated as of November 17, 2009, between the Company and The Bank of New York Mellon, as trustee, filed as Exhibit 4(c) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
4(c)
|
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(d)
|
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(e)
|
MDU Resources Group, Inc. Credit Agreement, dated May 26, 2011, among MDU Resources Group, Inc., Various Lenders, and Wells Fargo Bank, National Association, as Administrative Agent**
|
|
|
4(f)
|
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, filed as Exhibit 4(j) to Form 10-K for the year ended December 31, 2007, filed on February 20, 2008, in File No. 1-3480*
|
|
|
4(g)
|
Consent dated November 9, 2009, under Centennial Energy Holdings, Inc. Credit Agreement, among Centennial Energy Holdings, Inc., U.S. Bank National Association, as Administrative Agent, and The Other Financial Institutions party thereto, filed as Exhibit 4(i) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
4(h)
|
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(i)
|
Amendment No. 1 to Master Shelf Agreement, dated October 1, 2008, among MDU Energy Capital, LLC, Prudential Investment Management, Inc., the Prudential Insurance Company of America, and the holders of the notes thereunder, filed as Exhibit 4(b) to Form 10-Q for the quarter ended September 30, 2008, filed on November 5, 2008, in File No. 1-3480*
|
|
|
4(j)
|
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(k)
|
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(l)
|
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(m)
|
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)
|
Supplemental Income Security Plan, as amended and restated November 12, 2009, filed as Exhibit 10(b) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
+10(b)
|
Directors' Compensation Policy, as amended May 12, 2011, filed as Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2011, filed on August 5, 2011, in File No. 1-3480*
|
|
|
+10(c)
|
Deferred Compensation Plan for Directors, as amended May 15, 2008, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2008, filed on August 7, 2008, in File No. 1-3480*
|
|
|
+10(d)
|
Non-Employee Director Stock Compensation Plan, as amended May 12, 2011, filed as Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2011, filed on August 5, 2011, in File No. 1-3480*
|
|
|
+10(e)
|
Non-Employee Director Long-Term Incentive Compensation Plan, as amended November 12, 2009, filed as Exhibit 10(f) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
+10(f)
|
WBI Holdings, Inc. Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended November 11, 2009, filed as Exhibit 10(i) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
+10(g)
|
Knife River Corporation Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended November 16, 2009, filed as Exhibit 10(j) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
+10(h)
|
Long-Term Performance-Based Incentive Plan, as amended November 17, 2011**
|
|
|
+10(i)
|
MDU Resources Group, Inc. Executive Incentive Compensation Plan, as amended November 15, 2007, and Rules and Regulations, as amended November 11, 2009, filed as Exhibit 10(l) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
+10(j)
|
Montana-Dakota Utilities Co. Executive Incentive Compensation Plan, as amended November 15, 2007, and Rules and Regulations, as amended November 11, 2009, filed as Exhibit 10(m) to Form 10-K for the year ended December 31, 2009, filed on February 17, 2010, in File No. 1-3480*
|
|
|
+10(k)
|
Form of Change of Control Employment Agreement, as amended May 15, 2008, filed as Exhibit 10.1 to Form 8-K dated May 15, 2008, filed on May 20, 2008, in File No. 1-3480*
|
|
|
+10(l)
|
MDU Resources Group, Inc. Executive Officers with Change of Control Employment Agreements Chart, as of December 31, 2010, filed as Exhibit 10(n) to Form 10-K for the year ended December 31, 2010, filed on February 23, 2011, in File No. 1-3480*
|
|
|
+10(m)
|
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(n)
|
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(o)
|
Form of Performance Share Award Agreement under the Long-Term Performance-Based Incentive Plan, as amended February 15, 2011, filed as Exhibit 10.4 to Form 8-K dated February 15, 2011, filed on February 22, 2011, in File No. 1-3480*
|
|
|
+10(p)
|
MDU Construction Services Group, Inc. Executive Incentive Compensation Plan, as amended January 31, 2008, and Rules and Regulations, as amended February 16, 2009, filed as Exhibit 10(c) to Form 10-Q for the quarter ended March 31, 2009, filed on May 6, 2009, in File No. 1-3480*
|
|
|
+10(q)
|
Form of Annual Incentive Award Agreement under the Long-Term Performance-Based Incentive Plan as amended February 22, 2011, filed as Exhibit 10.2 to Form 8-K dated February 15, 2011, filed on February 22, 2011, in File No. 1-3480*
|
|
|
+10(r)
|
Agreement for Termination of Change of Control Employment Agreement, dated June 15, 2010, by and between MDU Resources Group, Inc. and Terry D. Hildestad, filed as Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2010, filed on August 6, 2010, in File No. 1-3480*
|
|
|
+10(s)
|
Form of Notice of Expiration of Coverage Period - Change of Control Employment Agreement, dated June 15, 2010, sent by MDU Resources Group, Inc. to William E. Schneider, John G. Harp, Steven L. Bietz, David L. Goodin, William R. Connors, Mark A. Del Vecchio, Nicole A. Kivisto, Cynthia J. Norland, Paul K. Sandness, Doran N. Schwartz, and John P. Stumpf, filed as Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2010, filed on August 6, 2010, in File No. 1-3480*
|
|
|
+10(t)
|
Form of MDU Resources Group, Inc. Indemnification Agreement for Section 16 Officers and Directors, filed as Exhibit 10.1 to Form 8-K dated August 12, 2010, filed on August 17, 2010, in File No. 1-3480*
|
|
|
+10(u)
|
MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of December 31, 2011**
|
|
|
+10(v)
|
Employment Letter for J. Kent Wells, dated March 9, 2011**
|
|
|
+10(w)
|
MDU Resources Group, Inc. Long-Term Performance-Based Incentive Plan 2011 Fidelity President and CEO Award Agreement**
|
|
|
+10(x)
|
MDU Resources Group, Inc. Nonqualified Defined Contribution Plan, as adopted November 17, 2011**
|
|
|
+10(y)
|
MDU Resources Group, Inc. 401(k) Retirement Plan, as restated March 1, 2011, filed as Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2011, filed on November 4, 2011, in File No. 1-3480*
|
|
|
+10(z)
|
Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated March 29, 2011, filed as Exhibit 10(b) to Form 10-Q for the quarter ended March 31, 2011, filed on May 5, 2011, in File No. 1-3480*
|
|
|
+10(aa)
|
Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated June 30, 2011, filed as Exhibit 10(d) to Form 10-Q for the quarter ended June 30, 2011, filed on August 5, 2011, in File No. 1-3480*
|
|
|
+10(ab)
|
Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated September 9, 2011, filed as Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 2011, filed on November 4, 2011, in File No. 1-3480*
|
|
|
+10(ac)
|
Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated December 29, 2011**
|
|
|
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(a)
|
Consent of Independent Registered Public Accounting Firm**
|
|
|
23(b)
|
Consent of Ryder Scott Company, L.P.**
|
|
|
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**
|
|
|
95
|
Mine Safety Disclosures**
|
|
|
99
|
Ryder Scott Company, L.P. report dated January 10, 2012**
|
|
|
101
|
The following materials from MDU Resources Group, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Common Stockholders' Equity, (iv) the Consolidated Statements of Cash Flows, (v) the Notes to Consolidated Financial Statements, tagged in summary and detail, (vi) Schedule I - Condensed Financial Information of Registrant, tagged in summary and detail and (vii) Schedule II - Consolidated Valuation and Qualifying Accounts, tagged in summary and detail
|
* Incorporated herein by reference as indicated.
|
** Filed herewith.
|
+ Management contract, compensatory plan or arrangement.
|
|
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.
|
|
|
MDU Resources Group, Inc.
|
|
|
|
|
|
Date:
|
February 24, 2012
|
By:
|
/s/ Terry D. Hildestad
|
|
|
|
Terry D. Hildestad
(President and Chief Executive Officer)
|
Signature
|
Title
|
Date
|
|
|
|
/s/ Terry D. Hildestad
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Chief Executive Officer and Director
|
February 24, 2012
|
Terry D. Hildestad
(President and Chief Executive Officer)
|
|
|
|
|
|
/s/ Doran N. Schwartz
|
Chief Financial Officer
|
February 24, 2012
|
Doran N. Schwartz
(Vice President and Chief Financial Officer)
|
|
|
|
|
|
/s/ Nicole A. Kivisto
|
Chief Accounting Officer
|
February 24, 2012
|
Nicole A. Kivisto
(Vice President, Controller and Chief Accounting Officer)
|
|
|
|
|
|
/s/ Harry J. Pearce
|
Director
|
February 24, 2012
|
Harry J. Pearce
|
|
|
(Chairman of the Board)
|
|
|
|
|
|
/s/ Thomas Everist
|
Director
|
February 24, 2012
|
Thomas Everist
|
|
|
|
|
|
/s/ Karen B. Fagg
|
Director
|
February 24, 2012
|
Karen B. Fagg
|
|
|
|
|
|
/s/ A. Bart Holaday
|
Director
|
February 24, 2012
|
A. Bart Holaday
|
|
|
|
|
|
/s/ Dennis W. Johnson
|
Director
|
February 24, 2012
|
Dennis W. Johnson
|
|
|
|
|
|
/s/ Thomas C. Knudson
|
Director
|
February 24, 2012
|
Thomas C. Knudson
|
|
|
|
|
|
/s/ Richard H. Lewis
|
Director
|
February 24, 2012
|
Richard H. Lewis
|
|
|
|
|
|
/s/ Patricia L. Moss
|
Director
|
February 24, 2012
|
Patricia L. Moss
|
|
|
|
|
|
/s/ John K. Wilson
|
Director
|
February 24, 2012
|
John K. Wilson
|
|
|
|
Bylaws of
|
|
|
|
|
|
MDU RESOURCES
|
|
|
GROUP, INC.
|
|
|
Page No.
|
|
||
OFFICES
|
1
|
|
||
|
1.01 Registered Office
|
1
|
|
|
|
1.02 Other Offices
|
1
|
|
|
MEETINGS OF STOCKHOLDERS
|
1
|
|
||
|
2.01 Place of Meetings
|
1
|
|
|
|
2.02 Annual Meetings
|
1
|
|
|
|
2.03 Notice of Annual Meeting
|
2
|
|
|
|
2.04 Stockholders List
|
2
|
|
|
|
2.05 Notice of Special Meeting
|
2
|
|
|
|
2.06 Quorum
|
2
|
|
|
|
2.07 Voting Rights
|
3
|
|
|
|
2.08 Nominations for Director
|
3
|
|
|
|
2.09 Business at Meetings of Stockholders
|
6
|
|
|
DIRECTORS
|
8
|
|
||
|
3.01 Authority of Directors
|
8
|
|
|
|
3.02 Qualifications
|
8
|
|
|
|
3.03 Place of Meetings
|
9
|
|
|
|
3.04 Annual Meetings
|
9
|
|
|
|
3.05 Regular Meetings
|
9
|
|
|
|
3.06 Special Meetings
|
9
|
|
|
|
3.07 Quorum
|
9
|
|
|
|
3.08 Participation of Directors by Conference Telephone
|
9
|
|
|
|
3.09 Written Action of Directors
|
9
|
|
|
|
3.10 Committees
|
10
|
|
|
|
3.11 Reports of Committees
|
10
|
|
|
|
3.12 Compensation of Directors
|
10
|
|
|
|
3.13 Chairman of the Board
|
10
|
|
|
|
3.14 Lead Director
|
10
|
|
|
NOTICES
|
11
|
|
||
|
4.01 Notices
|
11
|
|
|
|
4.02 Waiver
|
11
|
|
|
OFFICERS
|
11
|
|
||
|
5.01 Election, Qualifications
|
11
|
|
|
|
5.02 Additional Officers
|
11
|
|
|
|
5.03 Salaries
|
12
|
|
|
|
5.04 Term
|
12
|
|
CREDIT AGREEMENT
among
MDU RESOURCES GROUP, INC.
as Borrower;
VARIOUS LENDERS;
and
WELLS FARGO BANK, NATIONAL ASSOCIATION,
as Administrative Agent
WELLS FARGO SECURITIES, LLC
AND UNION BANK, N.A.,
as Joint Lead Arrangers and Joint Lead Bookrunners
UNION BANK, N.A.,
as Syndication Agent
|
Closing Date: May 26, 2011
|
$100,000,000 Revolving Credit Facility
|
ARTICLE I Definitions
|
1
|
|
|
Section 1.1
|
Definitions.
|
1
|
|
Section 1.2
|
Rules of Construction
|
13
|
|
ARTICLE II Amount and Terms of the Credit Facilities
|
14
|
|
|
Section 2.1
|
Revolving Facility.
|
14
|
|
Section 2.2
|
Converting ABR Loans to LIBOR Loans; Procedures.
|
15
|
|
Section 2.3
|
Procedures at End of an Interest Period.
|
15
|
|
Section 2.4
|
Setting and Notice of Rates.
|
15
|
|
Section 2.5
|
Level Status, Margins and Fee Rates.
|
15
|
|
Section 2.6
|
Interest on Loans.
|
17
|
|
Section 2.7
|
Obligation to Repay Advances; Representations.
|
18
|
|
Section 2.8
|
Scheduled Payments; Mandatory Prepayments; Evidence of Obligations.
|
18
|
|
Section 2.9
|
Computation of Interest and Fees.
|
18
|
|
Section 2.10
|
Fees.
|
19
|
|
Section 2.11
|
Use of Proceeds.
|
19
|
|
Section 2.12
|
Voluntary Prepayments.
|
19
|
|
Section 2.13
|
Voluntary Reduction or Termination of Aggregate Revolving Commitment Amount.
|
20
|
|
Section 2.14
|
Optional Increases of Aggregate Revolving Commitment Amount.
|
20
|
|
Section 2.15
|
Payments Generally.
|
21
|
|
Section 2.16
|
Increased Costs.
|
22
|
|
Section 2.17
|
Taxes.
|
23
|
|
Section 2.18
|
Basis for Determining Interest Rate Inadequate or Unfair; Illegality.
|
25
|
|
Section 2.19
|
Loan Losses.
|
25
|
|
Section 2.20
|
Right of Lenders to Fund through Other Offices.
|
26
|
|
Section 2.21
|
Discretion of Lenders as to Manner of Loan.
|
26
|
|
Section 2.22
|
Conclusiveness of Statements; Survival of Provisions; Limited Time for Claims.
|
26
|
|
Section 2.23
|
Nature of Lender Parties' Obligations.
|
26
|
|
Section 2.24
|
Defaulting Lenders.
|
26
|
|
ARTICLE III Conditions Precedent
|
28
|
|
|
Section 3.1
|
Initial Conditions Precedent.
|
28
|
|
Section 3.2
|
Conditions Precedent to All Borrowings.
|
28
|
|
ARTICLE IV Representations and Warranties
|
29
|
|
|
Section 4.1
|
Existence and Power.
|
29
|
|
Section 4.2
|
Authorization of Credit Extensions; No Conflict as to Law or Agreements.
|
29
|
|
Section 4.3
|
Legal Agreements.
|
29
|
|
Section 4.4
|
Subsidiaries.
|
29
|
|
Section 4.5
|
Financial Condition.
|
30
|
|
Section 4.6
|
Adverse Change.
|
30
|
|
Section 4.7
|
Litigation.
|
30
|
|
Section 4.8
|
Environmental Matters.
|
30
|
|
Section 4.9
|
Margin Regulations.
|
30
|
|
Section 4.10
|
Taxes.
|
30
|
|
Section 4.11
|
Titles and Liens.
|
31
|
|
Section 4.12
|
Intellectual Property.
|
31
|
|
Section 4.13
|
ERISA.
|
31
|
|
ARTICLE V Affirmative Covenants
|
31
|
|
|
Section 5.1
|
Reporting.
|
31
|
|
Section 5.2
|
Books and Records; Inspection and Examination.
|
33
|
|
Section 5.3
|
Compliance with Laws.
|
33
|
|
Section 5.4
|
Payment of Taxes and Other Claims.
|
33
|
|
Section 5.5
|
Maintenance of Properties.
|
34
|
|
Section 5.6
|
Insurance.
|
34
|
|
Section 5.7
|
Preservation of Corporate Existence.
|
34
|
|
ARTICLE VI Negative Covenants
|
34
|
|
|
Section 6.1
|
Liens.
|
34
|
|
Section 6.2
|
Investments.
|
35
|
|
Section 6.3
|
Distributions.
|
36
|
|
Section 6.4
|
Sale of Assets.
|
36
|
|
Section 6.5
|
Transactions with Affiliates.
|
36
|
|
Section 6.6
|
Consolidation and Merger.
|
36
|
|
Section 6.7
|
Environmental Laws.
|
37
|
|
Section 6.8
|
Restrictions on Nature of Business.
|
37
|
|
Section 6.9
|
Consolidated Total Leverage Ratio.
|
37
|
|
Section 6.10
|
Borrower Leverage Ratio.
|
37
|
|
ARTICLE VII Events of Default, Rights and Remedies
|
37
|
|
|
Section 7.1
|
Events of Default.
|
37
|
|
Section 7.2
|
Rights and Remedies.
|
39
|
|
Section 7.3
|
Right of Setoff.
|
39
|
|
Section 7.4
|
Crediting of Payments and Proceeds.
|
39
|
|
ARTICLE VIII THE ADMINISTRATIVE AGENT
|
40
|
|
|
Section 8.1
|
Appointment and Authority.
|
40
|
|
Section 8.2
|
Rights as a Lender.
|
40
|
|
Section 8.3
|
Exculpatory Provisions.
|
41
|
|
Section 8.4
|
Reliance by Administrative Agent.
|
42
|
|
Section 8.5
|
Delegation of Duties.
|
42
|
|
Section 8.6
|
Resignation and Removal of Administrative Agent.
|
42
|
|
Section 8.7
|
Non-Reliance on Administrative Agent and Other Lenders.
|
43
|
|
Section 8.8
|
No Other Duties, Etc.
|
43
|
|
Section 8.9
|
Administrative Agent May File Proofs of Claim.
|
43
|
|
Section 8.10
|
Collateral and Guaranty Matters.
|
44
|
|
ARTICLE IX Miscellaneous
|
45
|
|
|
Section 9.1
|
No Waiver; Cumulative Remedies.
|
45
|
|
Section 9.2
|
Amendments, Etc.
|
45
|
|
Section 9.3
|
Notices; Distribution of Information Via Electronic Means.
|
45
|
|
Section 9.4
|
Expenses; Indemnity; Damage Waiver
|
46
|
|
Section 9.5
|
Execution in Counterparts.
|
47
|
|
Section 9.6
|
Successors and Assigns; Register.
|
48
|
|
Section 9.7
|
Sharing of Payments by Lenders.
|
51
|
|
Section 9.8
|
Disclosure of Information.
|
51
|
|
Section 9.9
|
Governing Law.
|
52
|
|
Section 9.10
|
Consent to Jurisdiction.
|
52
|
|
Section 9.11
|
Waiver of Jury Trial.
|
52
|
|
Section 9.12
|
Severability of Provisions.
|
52
|
|
Section 9.13
|
Prior Agreements.
|
52
|
|
Section 9.14
|
Other Financing.
|
52
|
|
Section 9.15
|
Termination of Existing Credit Facility.
|
53
|
|
Section 9.16
|
Headings.
|
53
|
|
Section 1.1
|
Definitions.
|
Section 1.2
|
Rules of Construction
|
Section 2.1
|
Revolving Facility.
|
Section 2.2
|
Converting ABR Loans to LIBOR Loans; Procedures.
|
Section 2.3
|
Procedures at End of an Interest Period.
|
Section 2.4
|
Setting and Notice of Rates.
|
Section 2.5
|
Level Status, Margins and Fee Rates.
|
|
Level I
|
Level II
|
Level III
|
Level IV
|
Level V
|
S&P
|
A or better
|
A- or better, but less than A
|
BBB+ or better, but less than A-
|
BBB or better, but less than BBB+
|
Less than BBB
|
Fitch
|
A or better
|
A- or better, but less than A
|
BBB+ or better, but less than A-
|
BBB or better, but less than BBB+
|
Less than BBB
|
(i)
|
If any of the Rating Agencies changes the meaning or designation for its Applicable Ratings referenced in paragraph (a), the criteria for Level Status in the table in paragraph (a) shall be adjusted in such manner as the Required Lenders may reasonably determine to correspond with the applicable rating designations used by the applicable Rating Agency in effect on the date hereof.
|
(ii)
|
If the Rating Agencies’ Applicable Ratings are not in the same column above, the Borrower’s Level Status shall be determined as follows:
|
(A)
|
If the Applicable Ratings provided by the Rating Agencies are in adjacent columns, the Borrower’s Level Status shall be based on the leftmost of the columns.
|
(B)
|
If the Applicable Ratings provided by the Rating Agencies are separated by one or more columns, the Borrower’s Level Status shall be based on the column to the immediate right of the leftmost applicable column.
|
(iii)
|
If one Rating Agency (but not both Rating Agencies) ceases to issue its Applicable Rating, the Borrower’s Level Status shall be determined on the basis of the Applicable Rating of the remaining Rating Agency. If both Rating Agencies cease to establish their Applicable Ratings, the Borrower shall be deemed to be at Level Status V.
|
|
Level I
|
Level II
|
Level III
|
Level IV
|
Level V
|
ABR Loan Margin
|
0%
|
0.125%
|
0.200%
|
0.275%
|
0.475%
|
LIBOR Loan Margin
|
0.900%
|
1.125%
|
1.200%
|
1.275%
|
1.475%
|
Facility Fee Rate
|
0.100%
|
0.125%
|
0.175%
|
0.225%
|
0.275%
|
Section 2.6
|
Interest on Loans.
|
Section 2.7
|
Obligation to Repay Advances; Representations.
|
Section 2.8
|
Scheduled Payments; Mandatory Prepayments; Evidence of Obligations.
|
Section 2.9
|
Computation of Interest and Fees.
|
Section 2.10
|
Fees.
|
Section 2.11
|
Use of Proceeds.
|
Section 2.12
|
Voluntary Prepayments.
|
Section 2.13
|
Voluntary Reduction or Termination of Aggregate Revolving Commitment Amount.
|
Section 2.14
|
Optional Increases of Aggregate Revolving Commitment Amount.
|
(i)
|
An amendment, modification or joinder to this Agreement, duly signed by the Borrower, the Administrative Agent and each Lender whose Revolving Commitment will be increased and each other Lender or Eligible Assignee who has subscribed to provide a portion of the Increased Commitment Amount, modifying the definition of “Aggregate Revolving Commitment Amount” and setting forth the agreement of each Eligible Assignee to become a party to this
|
(ii)
|
Amendments and modifications, duly executed by the Borrower and the Administrative Agent, to any other Loan Documents reasonably requested by the Administrative Agent in relation to the Increased Commitment Amount, which amendments and modifications the Administrative Agent is hereby authorized to execute and deliver on behalf of the Lenders.
|
(iii)
|
Notes, duly executed by the Borrower, as any Lender or Eligible Assignee may require.
|
(iv)
|
Evidence of appropriate corporate authorization on the part of the Borrower with respect to the Increased Commitment Amount and the execution and delivery of the documents described in this Section 2.14.
|
(v)
|
Such opinions of counsel for the Borrower and other assurances as the Administrative Agent may reasonably request.
|
(vi)
|
Reimbursement of the Administrative Agent’s out-of-pocket costs and expenses (including reasonable attorney’s fees) incurred in connection therewith.
|
Section 2.15
|
Payments Generally.
|
Section 2.16
|
Increased Costs.
|
(i)
|
impose, modify or deem applicable any reserve, special deposit, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or participated in by, any Lender (except any reserve requirement reflected in the Adjusted LIBO Rate);
|
(ii)
|
subject any Lender to any tax of any kind whatsoever with respect to this Agreement or any Loan made by it, or change the basis of taxation of payments to such Lender in respect thereof (except for Indemnified Taxes or Other Taxes covered by Section 2.17 and the imposition of, or any change in the rate of, any Excluded Tax payable by such Lender); or
|
(iii)
|
impose on any Lender or the London interbank market any other condition, cost or expense affecting this Agreement or LIBOR Loans made by such Lender;
|
Section 2.17
|
Taxes.
|
Section 2.18
|
Basis for Determining Interest Rate Inadequate or Unfair; Illegality.
|
Section 2.19
|
Loan Losses.
|
Section 2.20
|
Right of Lenders to Fund through Other Offices.
|
Section 2.21
|
Discretion of Lenders as to Manner of Loan.
|
Section 2.22
|
Conclusiveness of Statements; Survival of Provisions; Limited Time for Claims.
|
Section 2.23
|
Nature of Lender Parties’ Obligations.
|
Section 2.24
|
Defaulting Lenders.
|
(i)
|
Waivers and Amendments
. Such Defaulting Lender’s right to approve or disapprove any amendment, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of Required Lenders and Section 9.2.
|
(ii)
|
Defaulting Lender Waterfall
. Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of such Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Article VII or otherwise) or received by the Administrative Agent from a Defaulting Lender pursuant to Section 7.3 shall be applied at such time or times as may be determined by the Administrative Agent as follows:
first
, to the payment of any amounts owing by such Defaulting Lender to the Administrative Agent hereunder;
second
, as the Borrower may request (so long as no Default or Event
|
(iii)
|
Facility Fee
. Each Defaulting Lender shall be entitled to receive a Facility Fee for any period during which that Lender is a Defaulting Lender only to extent allocable to the sum of the outstanding principal amount of the Revolving Loans funded by it.
|
Section 3.1
|
Initial Conditions Precedent.
|
Section 3.2
|
Conditions Precedent to All Borrowings.
|
Section 4.1
|
Existence and Power.
|
Section 4.2
|
Authorization of Credit Extensions; No Conflict as to Law or Agreements.
|
Section 4.3
|
Legal Agreements.
|
Section 4.4
|
Subsidiaries.
|
Section 4.5
|
Financial Condition.
|
Section 4.6
|
Adverse Change.
|
Section 4.7
|
Litigation.
|
Section 4.8
|
Environmental Matters.
|
Section 4.9
|
Margin Regulations.
|
Section 4.10
|
Taxes.
|
Section 4.11
|
Titles and Liens.
|
Section 4.12
|
Intellectual Property.
|
Section 4.13
|
ERISA.
|
Section 5.1
|
Reporting.
|
(i)
|
A copy of the unaudited nonconsolidated balance sheets of the Borrower at the end of such fiscal year and the related unaudited nonconsolidated statements of income, retained earnings and cash flows of the Borrower for such fiscal year, in reasonable detail, all prepared in accordance with GAAP.
|
(ii)
|
A copy of the annual audit report-regulatory basis of the Borrower with an unqualified opinion of independent certified public accountants selected by the Borrower and acceptable to the Required Lenders, which annual report shall include a copy of the balance sheet-regulatory basis of the Borrower as the end of such fiscal year and the related statements of income-regulatory basis, retained earnings-regulatory basis and cash flows-regulatory basis of the Borrower for the fiscal year then ended, all prepared in accordance with FERC Accounting Principles.
|
Section 5.2
|
Books and Records; Inspection and Examination.
|
Section 5.3
|
Compliance with Laws.
|
Section 5.4
|
Payment of Taxes and Other Claims.
|
Section 5.5
|
Maintenance of Properties.
|
Section 5.6
|
Insurance.
|
Section 5.7
|
Preservation of Corporate Existence.
|
Section 6.1
|
Liens.
|
Section 6.2
|
Investments.
|
Section 6.3
|
Distributions.
|
Section 6.4
|
Sale of Assets.
|
Section 6.5
|
Transactions with Affiliates.
|
Section 6.6
|
Consolidation and Merger.
|
Section 6.7
|
Environmental Laws.
|
Section 6.8
|
Restrictions on Nature of Business.
|
Section 6.9
|
Consolidated Total Leverage Ratio.
|
Section 6.10
|
Borrower Leverage Ratio.
|
Section 7.1
|
Events of Default.
|
Section 7.2
|
Rights and Remedies.
|
Section 7.3
|
Right of Setoff.
|
Section 7.4
|
Crediting of Payments and Proceeds.
|
Section 8.1
|
Appointment and Authority.
|
Section 8.2
|
Rights as a Lender.
|
Section 8.3
|
Exculpatory Provisions.
|
(i)
|
shall not be subject to any fiduciary or other implied duties, regardless of whether a Default or Event of Default has occurred and is continuing;
|
(ii)
|
shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Administrative Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for herein or in the other Loan Documents),
provided
that the Administrative Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Administrative Agent to liability or that is contrary to any Loan Document or applicable law, including any action that may be in violation of the automatic stay under any Debtor Relief Law or that may effect a forfeiture, modification or termination of property of a Defaulting Lender in violation of any Debtor Relief Law; and
|
(iii)
|
shall not, except as expressly set forth herein and in the other Loan Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as the Administrative Agent or any of its Affiliates in any capacity.
|
Section 8.4
|
Reliance by Administrative Agent.
|
Section 8.5
|
Delegation of Duties.
|
Section 8.6
|
Resignation and Removal of Administrative Agent.
|
Section 8.7
|
Non-Reliance on Administrative Agent and Other Lenders.
|
Section 8.8
|
No Other Duties, Etc.
|
Section 8.9
|
Administrative Agent May File Proofs of Claim.
|
Section 8.10
|
Collateral and Guaranty Matters.
|
(i)
|
to release any Lien on any property granted to or held by the Administrative Agent under any Loan Document (A) upon termination of all Commitments and payment in full of all Obligations (other than contingent indemnification obligations), (B) that is sold or otherwise disposed of or to be sold or otherwise disposed of as part of or in connection with any sale or other disposition permitted under the Loan Documents, or (C) subject to Section 9.2, if approved, authorized or ratified in writing by the Required Lenders;
|
(ii)
|
to subordinate any Lien on any property granted to or held by the Administrative Agent under any Loan Document to the holder of any Lien on such property that is permitted by Section 6.1(e); and
|
(iii)
|
to release any guarantor from its obligations under any guaranty of the Obligations if such Person ceases to be a Subsidiary as a result of a transaction permitted under the Loan Documents.
|
Section 9.1
|
No Waiver; Cumulative Remedies.
|
Section 9.2
|
Amendments, Etc.
|
Section 9.3
|
Notices; Distribution of Information Via Electronic Means.
|
Section 9.4
|
Expenses; Indemnity; Damage Waiver
|
Section 9.5
|
Execution in Counterparts.
|
Section 9.6
|
Successors and Assigns; Register.
|
(i)
|
Minimum Amounts
.
|
(A)
|
In the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and the Loans at the time owing to it or in the case of an assignment to a Lender, no minimum amount need be assigned.
|
(B)
|
In any case not described in paragraph (b)(i)(A) of this Section, (i) through the Revolving Commitment Termination Date, the aggregate amount of the Commitment (which for this purpose includes Advances outstanding thereunder) of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if
“Trade Date”
is specified in the Assignment and Assumption, as of such Trade Date) shall not be less than 25% of the Aggregate Revolving Commitment Amount then in effect, and (ii) thereafter, the principal outstanding balance of the Advances of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if
“Trade Date”
is specified in the Assignment and Assumption, as of such Trade Date) shall not be less than $5,000,000.
|
(ii)
|
Required Consents
. No consent shall be required for any assignment except as follows:
|
(A)
|
the consent of the Borrower (such consent not to be unreasonably
|
(B)
|
The consent of the Administrative Agent shall be required for assignments in respect of a Facility if such assignment is to a Person that is not a Lender.
|
(iii)
|
Assignment and Assumption
. The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500; provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment
.
The assignee, if it is not a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.
|
(iv)
|
No Assignment to Certain Persons
. No such assignment shall be made to (A) the Borrower or any of the Borrower’s Affiliates or Subsidiaries, or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute any of the foregoing Persons described in this clause (B).
|
(v)
|
No Assignment to Natural Persons
. No such assignment shall be made to a natural person.
|
(vi)
|
Certain Additional Payments
. In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Loans previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent and each other Lender hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full pro rata share of all Loans in accordance with its Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable law without compliance with the provisions of this paragraph, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.
|
Section 9.7
|
Sharing of Payments by Lenders.
|
Section 9.8
|
Disclosure of Information.
|
Section 9.9
|
Governing Law.
|
Section 9.10
|
Consent to Jurisdiction.
|
Section 9.11
|
Waiver of Jury Trial.
|
Section 9.12
|
Severability of Provisions.
|
Section 9.13
|
Prior Agreements.
|
Section 9.14
|
Other Financing.
|
Section 9.15
|
Termination of Existing Credit Facility.
|
Section 9.16
|
Headings.
|
|
MDU RESOURCES GROUP, INC.
By
/s/ Doran N. Schwartz
Doran N. Schwartz
|
|
Its Vice President and Chief Financial Officer
|
|
|
|
WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent and a Lender
By
/s/ Keith Luettel
|
|
Its
Keith Luettel
|
|
Vice President
|
|
Wells Fargo Bank, National Association
|
|
UNION BANK, N.A.
/s/ Eric Otieno
By Eric Otieno
|
|
|
|
Its Assistant Vice President
|
|
PNC BANK, NATIONAL ASSOCIATION
By
/s/Susan J. Dimmick
|
|
Its
Senior Vice President
|
|
U.S. BANK NATIONAL ASSOCIATION
By
/s/ John Prigge
|
|
Its
John Prigge
|
|
Vice President
|
Exhibit A
|
Commitments and Addresses
|
Exhibit B
|
Form of Revolving Note
|
Exhibit C
|
Form of Compliance Certificate
|
Exhibit D
|
Assignment Certificate
|
Exhibit E-1
|
Form of General Counsel Opinion
|
Exhibit E-2
|
Form of Cohen Tauber Spievack & Wagner P.C. Opinion
|
Exhibit F
|
Form of Borrowing Opinion
|
Schedule 4.2
|
Authorizing Orders
|
Schedule 4.4
|
Subsidiaries
|
Schedule 6.1
|
Permitted Liens
|
Name
|
Revolving Commitment
|
Notice Address
|
MDU Resources Group, Inc.
|
N/A
|
1200 West Century Avenue
Bismarck, ND 58503
Attention: Doug Mahowald, Treasurer
Telecopier: 701-530-1734
E-Mail: Doug.Mahowald@MDUResources.com
|
Wells Fargo Bank, National Association, as Administrative Agent
|
N/A
|
1525 W WT Harris Boulevard
Mail Code: D1109-019
Attention: Syndication Agency Services
Charlotte, NC 28262
Telecopier: 704-590-2790
E-Mail: cathy.burke@wachovia.com
with a copy to:
MAC N9305-070
90 South Seventh Street
Minneapolis, MN 55402
Attention: Patrick McCue
Telecopier: 612-316-0506
E-Mail: patrick.mccue@wellsfargo.com
|
Wells Fargo Bank, National Association, as a Lender
|
$27,500,000
|
MAC N9305-070
90 South Seventh Street
Minneapolis, MN 55402
Attention: Patrick McCue
Telecopier: 612-316-0506
E-Mail: patrick.mccue@wellsfargo.com
|
Union Bank, N.A.
|
$27,500,000
|
445 S. Figueroa Street, 15th Floor
Los Angeles, CA 90071
Attention: Kevin Zitar
Telecopier: 213-236‐4096
E-Mail: kevin.zitar@unionbank.com
|
PNC Bank NA
|
$22,500,000
|
Three PNC Plaza
225 Fifth Avenue 4th Floor
Pittsburgh PA 15222
Attention: Susan Dimmick
Telecopier: 412-705-3232
E-Mail: Susan.dimmick@pnc.com
|
U.S. Bank National Association
|
$22,500,000
|
800 Nicollet Mall
Minneapolis, MN 55402
Attention: John Prigge
Telecopier: 612-303-2265
E-Mail: John.prigge@usbank.com
|
$_____________________________
|
|
________________, 20__
|
|
MDU RESOURCES GROUP, INC.
By _________________________________
|
|
Its _______________________________
|
|
__________________________, ______
|
1.
|
I am the chief financial officer of the Borrower, and I am familiar with the financial statements and financial affairs of the Borrower.
|
2.
|
The Statements have been prepared in accordance with GAAP, except for any portion thereof provided pursuant to Section 5.1(b)(ii), which have been prepared in accordance with FERC Accounting Principles.
|
3.
|
The computations attached hereto have been prepared in accordance with GAAP and set forth the Borrower’s compliance or non-compliance with the requirements set forth in the Financial Covenants as of the Effective Date. Such computations below have been prepared from, and on a basis consistent with, the Statements. Further attached hereto are all relevant facts in reasonable detail to evidence, and the computations of, the financial covenants referred to above.
|
4.
|
I have no knowledge of the occurrence of any Default or Event of Default under the Credit Agreement, except as set forth in the attachments, if any, hereto.
|
|
Very truly yours,
|
|
|
1.
|
Assignor[s]:
|
|
|
|
|
2.
|
Assignee[s]:
|
|
|
|
|
1
|
For bracketed language here and elsewhere in this form relating to the Assignor(s), if the assignment is from a single Assignor, choose the first bracketed language. If the assignment is from multiple Assignors, choose the second bracketed language.
|
2
|
For bracketed language here and elsewhere in this form relating to the Assignee(s), if the assignment is to a single Assignee, choose the first bracketed language. If the assignment is to multiple Assignees, choose the second bracketed language.
|
3
|
Select as appropriate.
|
4
|
Include bracketed language if there are either multiple Assignors or multiple Assignees.
|
3.
|
Borrower(s): ______________________________
|
4.
|
Administrative Agent: ______________________, as the administrative agent under the Credit Agreement
|
5.
|
Credit Agreement: Credit Agreement dated as of May 26, 2011 among MDU Resources Group, Inc., the Lenders parties thereto, Wells Fargo Bank, National Association, as Administrative Agent, and the other agents parties thereto
|
6.
|
Assigned Interest[s]:
|
Assignor[s]
5
|
Assignee[s]
6
|
Facility Assigned
7
|
Aggregate Amount of Commitment/ Loans for all Lenders
8
|
Amount of Commitment/ Loans Assigned
8
|
CUSIP Number
|
|
|
|
$
|
$
|
|
|
|
|
$
|
$
|
|
|
|
|
$
|
$
|
|
[7.
|
Trade Date: ______________]
9
|
5
|
List each Assignor, as appropriate.
|
6
|
List each Assignee, as appropriate.
|
7
|
Fill in the appropriate terminology for the types of facilities under the Credit Agreement that are being assigned under this Assignment (e.g. “Revolving Credit Commitment,” “Term Loan Commitment,” etc.)
|
8
|
Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.
|
9
|
To be completed if the Assignor(s) and the Assignee(s) intend that the minimum assignment amount is to be determined as of the Trade Date.
|
10
|
Add additional signature blocks as needed.
|
11
|
Add additional signature blocks as needed.
|
12
|
To be added only if the consent of the Administrative Agent is required by the terms of the Credit Agreement.
|
13
|
To be added only if the consent of the Borrower and/or other parties (e.g. Swingline Lender, Letter of Credit Issuer) is required by the terms of the Credit Agreement.
|
a.
|
By an order dated December 1, 2010, MDU received authorization from the Federal Energy Regulatory Commission (FERC) in Docket No. ES11-3-000.
This FERC authorization is effective from December 13, 2010 through December 13, 2012.
|
b.
|
By an order dated November 16, 2010
,
MDU received authorization from the Montana Public Service Commission in Docket No.D2010.11.103, Order No. 7119.
This Montana authorization is effective from January 1, 2011 to December 31, 2012.
|
1.
|
Alaska Basic Industries, Inc., an Alaska corporation, 100%
|
2.
|
Ames Sand & Gravel, Inc., a North Dakota corporation, 100%
|
3.
|
Anchorage Sand and Gravel Company, Inc., an Alaska corporation , 100%
|
4.
|
Baldwin Contracting Company, Inc., a California corporation, 100%
|
5.
|
BEH Electric Holdings, LLC, a Nevada limited liability company, 100%
|
6.
|
Bell Electrical Contractors, Inc., a Missouri corporation, 100%
|
7.
|
Bitter Creek Pipelines, LLC, a Colorado limited liability company, 100%
|
8.
|
BMH Mechanical Holdings, LLC, a Nevada limited liability company, 100%
|
9.
|
Bombard Electric, LLC, a Nevada limited liability company, 100%
|
10.
|
Bombard Mechanical, LLC, a Nevada limited liability company, 100%
|
11.
|
Capital Electric Construction Company, Inc., a Kansas corporation, 100%
|
12.
|
Capital Electric Line Builders, Inc., a Kansas corporation, 100%
|
13.
|
Cascade Natural Gas Corporation, a Washington corporation, 100%
|
14.
|
Centennial Energy Holdings, Inc., a Delaware corporation, 100%
|
15.
|
Centennial Energy Resources International, Inc., a Delaware corporation, 100%
|
16.
|
Centennial Energy Resources LLC, a Delaware limited liability company, 100%
|
17.
|
Centennial Holdings Capital LLC, a Delaware limited liability company, 100%
|
18.
|
Central Oregon Redi-Mix, L.L.C., an Oregon limited liability company, 78%
|
19.
|
CGC Resources, Inc., a Washington corporation, 100%
|
20.
|
Concrete, Inc., a California corporation, 100%
|
21.
|
Connolly-Pacific Co., a California corporation, 100%
|
22.
|
Continental Line Builders, Inc., a Delaware corporation, 100%
|
23.
|
Coordinating and Planning Services, Inc., a Delaware corporation, 100%
|
24.
|
Desert Fire Holdings, Inc., a Nevada corporation, 100%
|
25.
|
Desert Fire Protection, a Nevada Limited Partnership, 100%
|
26.
|
Desert Fire Protection, Inc., a Nevada corporation, 100%
|
27.
|
Desert Fire Protection, LLC, a Nevada limited liability company, 100%
|
28.
|
D S S Company, a California corporation, 100%
|
29.
|
E.S.I., Inc., an Ohio corporation, 100%
|
30.
|
Fairbanks Materials, Inc., an Alaska corporation, 100%
|
31.
|
Fidelity Exploration & Production Company, a Delaware corporation, 100%
|
32.
|
Fidelity Oil Co., a Delaware corporation, 100%
|
33.
|
Frebco, Inc., an Ohio corporation, 100%
|
34.
|
FutureSource Capital Corp., a Delaware corporation, 100%
|
35.
|
Granite City Ready Mix, Inc., a Minnesota corporation, 100%
|
36.
|
Hamlin Electric Company, a Colorado corporation, 100%
|
37.
|
Harp Engineering, Inc., a Montana corporation, 100%
|
38.
|
Hawaiian Cement, a Hawaii partnership, 100%
|
39.
|
ILB Hawaii, Inc., a Hawaii corporation, 100%
|
40.
|
Independent Fire Fabricators, LLC, a Nevada limited liability company, 100%
|
41.
|
Intermountain Gas Company, an Idaho corporation, 100%
|
42.
|
International Line Builders, Inc., a Delaware corporation, 100%
|
43.
|
InterSource Insurance Company, a Vermont corporation, 100%
|
44.
|
Jebro Incorporated, an Iowa corporation, 100%
|
45.
|
JTL Group, Inc., a Montana corporation, 100%
|
46.
|
JTL Group, Inc., a Wyoming corporation, 100%
|
47.
|
Kent’s Oil Service, a California corporation, 100%
|
48.
|
Knife River Corporation, a Delaware corporation, 100%
|
49.
|
Knife River Corporation – North Central, a Minnesota corporation, 100%
|
50.
|
Knife River Corporation – Northwest, an Oregon corporation, 100%
|
51.
|
Knife River Corporation – South, a Texas corporation, 100%
|
52.
|
Knife River Dakota, Inc., a Delaware corporation, 100%
|
53.
|
Knife River Equipment, Inc., a Delaware corporation, 100%
|
54.
|
Knife River Hawaii, Inc., a Delaware corporation, 100%
|
55.
|
Knife River Marine, Inc., a Delaware corporation, 100%
|
56.
|
Knife River Midwest, LLC, a Delaware limited liability company, 100%
|
57.
|
KRC Holdings, Inc., a Delaware corporation, 100%
|
58.
|
LME&U Holdings, LLC, a Nevada limited liability company, 100%
|
59.
|
Lone Mountain Excavation & Utilities, LLC, a Nevada limited liability company, 100%
|
60.
|
Loy Clark Pipeline Co., an Oregon corporation, 100%
|
61.
|
LTM, Incorporated, an Oregon corporation, 100%
|
62.
|
MDU Brasil Ltda., a Brazil limited liability company, 100%
|
63.
|
MDU Construction Services Group, Inc., a Delaware corporation, 100%
|
64.
|
MDU Energy Capital, LLC, a Delaware limited liability company, 100%
|
65.
|
MDU Industrial Services, Inc., a Delaware corporation, 100%
|
66.
|
MDU Resources International LLC, a Delaware limited liability company, 100%
|
67.
|
MDU Resources Luxembourg I LLC S.a.r.l., a Luxembourg limited liability company, 100%
|
68.
|
MDU Resources Luxembourg II LLC S.a.r.l., a Luxembourg limited liability company, 100%
|
69.
|
Midland Technical Crafts, Inc., a Delaware corporation, 100%
|
70.
|
Netricity LLC, an Alaska limited liability company, 75%
|
71.
|
Nevada Solar Solutions, LLC, a Delaware limited liability company, 100%
|
72.
|
Northstar Materials, Inc., a Minnesota corporation, 100%
|
73.
|
Oregon Electric Construction, Inc., an Oregon corporation, 100%
|
74.
|
Pouk & Steinle, Inc., a California corporation, 100%
|
75.
|
Prairie Cascade Energy Holdings, LLC, a Delaware limited liability company, 100%
|
76.
|
Prairie Intermountain Energy Holdings, LLC, a Delaware limited liability company, 100%
|
77.
|
Prairielands Energy Marketing, Inc., a Delaware corporation, 100%
|
78.
|
Prairielands Magnetics Limited, a Scotland private limited company, 100%
|
79.
|
Rocky Mountain Contractors, Inc., a Montana corporation, 100%
|
80.
|
USI Industrial Services, Inc., a Delaware corporation, 100%
|
81.
|
The Wagner Group, Inc., a Delaware corporation, 100%
|
82.
|
Wagner Industrial Electric, Inc., a Delaware corporation, 100%
|
83.
|
The Wagner-Smith Company, an Ohio corporation, 100%
|
84.
|
Wagner-Smith Equipment Co., a Delaware corporation, 100%
|
85.
|
Wagner-Smith Pumps & Systems, Inc., an Ohio corporation, 100%
|
86.
|
Warner Enterprises, Inc., a Nevada corporation, 100%
|
87.
|
WBI Canadian Pipeline, Ltd., a Canadian corporation, 100%
|
88.
|
WBI Energy Services, Inc., a Delaware corporation, 100%
|
89.
|
WBI Holdings, Inc., a Delaware corporation, 100%
|
90.
|
WBI Pipeline & Storage Group, Inc., a Delaware corporation, 100%
|
91.
|
WHC, Ltd., a Hawaii corporation, 100%
|
92.
|
Williston Basin Interstate Pipeline Company, a Delaware corporation, 100%
|
(a)
|
The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change in Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (iv) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of subsection (c) of this Section 2.4; or
|
(b)
|
Individuals who, as of April 22, 1997, which is the effective date of the Plan, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or
|
(c)
|
Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who
|
(d)
|
Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
|
(a)
|
Any restriction periods and restrictions imposed on Restricted Stock, Qualified Restricted Stock or Awards granted pursuant to Article 8 (if not performance-based) shall be deemed to have expired and such Restricted Stock, Qualified Restricted Stock or Awards shall become immediately vested in full; and
|
(b)
|
The target payout opportunity attainable under all outstanding Awards of Performance Units, Performance Shares and Awards granted pursuant to Article 8 (if performance-based) shall be deemed to have been fully earned for the entire Performance Period(s) as of the
effective
date of the Change in Control, and shall be paid out promptly in Shares or cash pursuant to the terms of the Award Agreement, or in the absence of such designation, as the Committee shall determine.
|
Name
|
Title
|
Date of Agreement
|
Terry D. Hildestad
|
President and Chief Executive Officer, MDU Resources Group, Inc.
|
August 12, 2010
|
William E. Schneider
|
President and Chief Executive Officer, Knife River Corporation. Effective January 1, 2012, Executive Vice President – Bakken Development, MDU Resources Group, Inc.
|
August 12, 2010
|
John G. Harp
|
President and Chief Executive Officer, MDU Construction Services Group, Inc. Effective January 1, 2012, Chief Executive Officer, MDU Construction Services Group, Inc. and Knife River Corporation
|
August 12, 2010
|
Steven L. Bietz
|
President and Chief Executive Officer, WBI Holdings, Inc.
|
August 12, 2010
|
David L. Goodin
|
President and Chief Executive Officer, Montana-Dakota Utilities Co., Great Plains Natural Gas Co., Cascade Natural Gas Corporation and Intermountain Gas Company
|
August 12, 2010
|
William R. Connors
|
Vice President – Renewable Resources, MDU Resources Group, Inc.
|
August 12, 2010
|
Mark A. Del Vecchio
|
Vice President - Human Resources, MDU Resources Group, Inc.
|
August 12, 2010
|
Nicole A. Kivisto
|
Vice President, Controller and Chief Accounting Officer, MDU Resources Group, Inc.
|
August 12, 2010
|
Cynthia J. Norland
|
Vice President - Administration, MDU Resources Group, Inc.
|
August 12, 2010
|
Paul K. Sandness
|
General Counsel and Secretary, MDU Resources Group, Inc.
|
August 12, 2010
|
Doran N. Schwartz
|
Vice President and Chief Financial Officer, MDU Resources Group, Inc.
|
August 12, 2010
|
John P. Stumpf
|
Vice President – Strategic Planning, MDU Resources Group, Inc.
|
August 12, 2010
|
Douglass A. Mahowald
|
Treasurer and Assistant Secretary, MDU Resources Group, Inc.
|
August 12, 2010
|
J. Kent Wells
|
President and Chief Executive Officer, Fidelity Exploration & Production Company
|
May 2, 2011
|
Name
|
Title
|
Date of Agreement
|
Harry J. Pearce
|
Chairman of the Board of Directors
|
August 12, 2010
|
Terry D. Hildestad
|
Director
|
August 12, 2010
|
A. Bart Holaday
|
Director
|
August 12, 2010
|
Thomas Everist
|
Director
|
August 12, 2010
|
Karen B. Fagg
|
Director
|
August 12, 2010
|
Dennis W. Johnson
|
Director
|
August 12, 2010
|
Thomas C. Knudson
|
Director
|
August 12, 2010
|
Richard H. Lewis
|
Director
|
August 12, 2010
|
Patricia L. Moss
|
Director
|
August 12, 2010
|
John K. Wilson
|
Director
|
August 12, 2010
|
MDU RESOURCES
|
|
|
GROUP, INC.
|
|
|
1200 West Century Avenue
|
|
Terry D. Hildestad
|
Bismarck, ND 58503
|
|
President and
Chief Executive Officer
|
Mailing Address:
|
January 22, 2011
|
|
P.O. Box 5650
|
|
|
Bismarck, ND 58506-5650
|
|
|
(701) 530-1000
|
|
|
MDU RESOURCES GROUP, INC.
|
MDU RESOURCES GROUP, INC.
|
MDU RESOURCES GROUP, INC.
|
1/20/2011
|
1
|
|
1/20/2011
|
2
|
|
1/20/2011
|
3
|
|
•
|
Fitness Facility Membership
|
•
|
Participation in a Weight-Loss or Personal Coaching Program
|
•
|
Fitness Equipment
|
•
|
Resource Materials
|
1/20/2011
|
4
|
|
a.
|
Reasonable attorney's fees;
|
b.
|
Federal, State, and local transfer taxes;
|
c.
|
Search fees and title insurance;
|
d.
|
Brokerage commission of a licensed real estate broker;
|
e.
|
Mortgage prepayment penalties;
|
f.
|
Recording fees;
|
g.
|
Any other fees or expense approved in advance in writing by the Company.
|
a.
|
Title search and title insurance;
|
b.
|
Mortgage service charges and mortgage taxes;
|
c.
|
Bank applications and processing and appraisal fees;
|
d.
|
Recording and notary fees;
|
e.
|
State and local transfer taxes;
|
f.
|
Termite inspection;
|
g.
|
Land survey;
|
h.
|
Attorney's fees up to a maximum of one percent (1%) of the new mortgage amount;
|
i.
|
Origination fees or points up to a maximum of two percent (2%) of the new mortgage amount;
|
j.
|
Any other fees or expenses approved in advance in writing by the Company.
|
Award:
|
$1,850,000, payable 50% in cash and 50% in shares of Company common stock, $1.00 par value ( “Shares”)
|
Performance Goal:
|
Described in Annex A
|
Performance Period:
|
January 1, 2011 through December 31, 2011 (the "Performance Period")
|
Date of Grant:
|
May 2, 2011
|
Dividend Equivalents:
|
No
|
# of Shares
|
=
|
$925,000
|
|
|
Closing price of Company Common Stock on January 2, 2012
|
|
|
|
Cash
|
=
|
$925,000 + Closing price of Company Common Stock on
January 2, 2012 for any fractional share
|
2.1
|
“Administrator”
means the Compensation Committee of the Board.
|
2.2
|
“Beneficiary”
means the person or entity determined to be a Participant’s beneficiary pursuant to Section 11.
|
2.3
|
“Board”
means the Board of Directors of the Company.
|
2.4
|
“Code”
means the Internal Revenue Code of 1986, as amended from time to time.
|
2.5
|
“Company”
means MDU Resources Group, Inc., and any current or future corporation that (a) is in a controlled group of corporations (within the meaning of Section 414(b) of the Code) of which MDU Resources Group, Inc. is a member and (b) has been approved by the Compensation Committee of the Board upon recommendation of the Chief Executive Officer to adopt the Plan for the benefit of its eligible employees. For purposes hereof, each such participating affiliate shall be deemed to have appointed MDU Resources Group, Inc. as its agent to act on its behalf in all matters relating to administration, amendment or termination of the Plan.
|
2.6
|
“Compensation”
means the annualized base salary paid to a Participant as of the first day of the Plan Year.
|
2.7
|
“ERISA”
means the Employee Retirement Income Security Act of 1974, as amended from time to time.
|
2.8
|
“Participant”
means an employee of the Company who has been selected to participate in the Plan pursuant to Section 3.
|
2.9
|
“Plan”
means the MDU Resources Group, Inc. Nonqualified Defined Contribution Plan, as set forth herein and as amended from time to time.
|
2.10
|
“Plan Year”
means the calendar year.
|
(a)
|
a single lump sum payment; or
|
(b)
|
annual installments over a period of up to five (5) years, the amount of each installment to equal the balance of the Participant’s vested account(s) immediately prior to the installment divided by the number of installments remaining to be paid. Each subsequent installment shall be made on the first day of the calendar month following the one (1) year anniversary of the prior payment.
|
(i)
|
if the Participant elected a single lump sum payment, such lump sum payment shall be made within ninety (90) days following the Participant’s “separation from service” with the Company (within the meaning of Code Section 409A); or
|
(ii)
|
if the Participant elected annual installments over a period of up to five (5) years, the annual installments shall commence within ninety (90) days following the Participant’s “separation from service” with the Company (within the meaning of Code Section 409A) or, if later, the date the Participant attains age sixty-five (65);
|
(a)
|
Pursuant to procedures established by the Administrator, claims for benefits under the Plan made by a Participant or Beneficiary (the "claimant") must be submitted in writing to the Administrator.
|
(i)
|
the specific reason or reasons for the denial of the claim;
|
(ii)
|
the specific references to the pertinent Plan provisions on which the denial is based;
|
(iii)
|
a description of any additional material or information necessary to perfect the claim, and an explanation of why such material or information is necessary; and
|
(iv)
|
a
statement
that any appeal of the denial must be made by giving to the Administrator, within sixty (60) days after receipt of the denial of the claim, written notice of such appeal, such notice to include a full description of the pertinent issues and basis of the claim.
|
(b)
|
Upon denial of a claim in whole or part, the claimant (or his duly authorized representative) shall have the right to submit a written request to the Administrator for a full and fair review of the denied claim, to be permitted to review documents pertinent to the denial, and to submit issues and comments in writing. Any appeal of the denial must be given to the Administrator within the period of time prescribed under (a)(iv) above. If the claimant (or his duly authorized representative) fails to appeal the denial to the Administrator within the prescribed time, the Administrator’s adverse determination shall be final, binding and conclusive.
|
1.
|
Establishment of Specified Employee List.
Between January 1
st
and April 1
st
of each calendar year, the Company shall establish a “Specified Employee List.” The Specified Employee List shall become effective on April 1
st
of the calendar year in which the Specified Employee List is established and shall cease to be effective on March 31
st
of the following calendar year. Any individual who, as of his or her “separation from service” (within the meaning of Code Section 409A(a)(2)(A)(i)), is on the Specified Employee List then in effect shall be considered a “specified employee” for purposes of Section 409A.
|
2.
|
Inclusion on the Specified Employee List.
The Specified Employee List shall include all individuals who, at any time during the Determination Year, met the requirements of Code Section 416(i)(l)(A)(i), (ii) or (iii) and the related regulations (but without regard to Code Section 415(i)(5)). For this purpose, “Determination Year” shall mean the calendar year ending on the December 31
st
prior to the April 1
st
when the Specified Employee List becomes effective. For purposes of determining which individuals meet the requirements of Code Section 416(i)(l)(A)(i), (ii) or (iii) and the related regulations (but without regard to Code Section 415(i)(5)), the term gross compensation shall have the meaning set forth in the MDU Resources Group, Inc. 401(k) Retirement Plan, as may be amended from time to time (the “Retirement Plan”).
|
3.
|
Delayed Payments.
If any employee is determined to be a specified employee under this Policy, any compensation to be provided to such specified employee that is required to be delayed to comply with Code Section 409A(a)(2)(B)(i) shall not be provided before the date that is six months after the date of such separation from service (or, if earlier than the end of such six-month period, the date of death of the specified employee). This Policy shall not apply to any payment that is not treated as deferred compensation under, or is otherwise excluded from, the requirements of Code Section 409A and the regulations promulgated thereunder.
|
4.
|
Changes to Policy.
The Company may amend or modify this Policy at any time; provided, however, that any changes made to the period during which the Specified Employee List is effective or the Determination Year shall not take effect for a period of at least 12 months and any changes made to the definition of compensation (either in the Policy or in the Retirement Plan) shall not be used to identify specified employees until the next Specified Employee List is established.
|
1.
|
By replacing the table in Section D‑1‑2
Eligibility to Share in the Profit Sharing Feature
of Supplement D-1,
Provisions Relating to the Profit Sharing Feature for Certain Participating Affiliates
, in its entirety, with the following:
|
Participating Affiliate
|
Current Effective Date
(Original Effective Date)
2
|
Anchorage Sand & Gravel Company, Inc. (excluding President)
|
January 1, 1999
|
Baldwin Contracting Company, Inc.
|
January 1, 1999
|
Bell Electrical Contractors, Inc.
|
January 1, 2002
|
Bitter Creek Pipelines, LLC
1/3
|
January 1, 2010
(January 1, 2001)
|
Cascade Natural Gas Corporation
|
January 1, 2011
July 2, 2007
|
Concrete, Inc.
|
January 1, 2001
|
Connolly-Pacific Co.
|
January 1, 2007
|
DSS Company
|
January 1, 2004
(July 8, 1999)
|
E.S.I., Inc.
|
January 1, 2008
(January 1, 2003)
|
Fairbanks Materials, Inc.
|
May 1, 2008
|
Granite City Ready Mix, Inc.
|
June 1, 2002
|
Great Plains Natural Gas Co.
|
January 1, 2008
|
Participating Affiliate
|
Current Effective Date
(Original Effective Date)
2
|
Hawaiian Cement (non-union employees hired after December 31, 2005)
|
January 1, 2009
|
Intermountain Gas Company
|
January 1, 2011
|
Jebro Incorporated
|
November 1, 2005
|
Kent’s Oil Service
|
January 1, 2007
|
Knife River Corporation – Northwest (the Central Oregon Division, f/k/a HTS)
|
January 1, 2010
(January 1, 1999)
|
Knife River Corporation – Northwest (the Southern Idaho Division)
|
January 1, 2010
(January 1, 2006)
|
Knife River Corporation – Northwest (the Spokane Division)
|
January 1, 2010
(January 1, 2006)
|
Knife River Corporation - South
(f/k/a Young Contractors, Inc.)
|
January 1, 2008
(January 1, 2007)
|
LTM, Incorporated
|
January 1, 2003
|
Montana-Dakota Utilities Co. (including union employees)
|
January 1, 2008
|
Oregon Electric Construction, Inc.
3
|
March 7, 2011
|
Wagner Industrial Electric, Inc.
|
January 1, 2008
|
Wagner Smith Equipment Co.
|
January 1, 2008
(July 1, 2000)
|
WBI Holdings, Inc.
1/3
|
January 1, 2009
|
WHC, Ltd.
|
September 1, 2001
|
Williston Basin Interstate Pipeline Company
1/3
|
January 1, 2009
|
2.
|
Effective January 1, 2012, by replacing the following entries in Schedule A:
|
|
MDU RESOURCES GROUP, INC.
|
|
EMPLOYEE BENEFITS COMMITTEE
|
|
|
|
|
|
By:
/s/ Doran N. Schwartz
|
|
Doran N. Schwartz, Chairman
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|||||
|
|
(In thousands of dollars)
|
||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Earnings Available for Fixed Charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (a)
|
|
$
|
223,842
|
|
|
$
|
218,205
|
|
|
$
|
(126,653
|
)
|
|
$
|
293,826
|
|
|
$
|
308,288
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income Taxes
|
|
110,273
|
|
|
122,530
|
|
|
(96,092
|
)
|
|
147,475
|
|
|
190,024
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
334,115
|
|
|
340,735
|
|
|
(222,745
|
)
|
|
441,301
|
|
|
498,312
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Rents (b)
|
|
13,568
|
|
|
12,897
|
|
|
14,475
|
|
|
11,781
|
|
|
11,947
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest (c)
|
|
86,505
|
|
|
88,930
|
|
|
89,943
|
|
|
86,320
|
|
|
76,248
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total Earnings Available for Fixed Charges
|
|
$
|
434,188
|
|
|
$
|
442,562
|
|
|
$
|
(118,327
|
)
|
|
$
|
539,402
|
|
|
$
|
586,507
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Preferred Dividend Requirements
|
|
$
|
685
|
|
|
$
|
685
|
|
|
$
|
685
|
|
|
$
|
685
|
|
|
$
|
685
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Income Before Income Taxes to Net Income
|
|
149
|
%
|
|
156
|
%
|
|
176
|
%
|
|
150
|
%
|
|
159
|
%
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Preferred Dividend Factor on Pretax Basis
|
|
1,021
|
|
|
1,069
|
|
|
1,206
|
|
|
1,028
|
|
|
1,089
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges (d)
|
|
106,348
|
|
|
107,552
|
|
|
109,117
|
|
|
101,452
|
|
|
90,545
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Combined Fixed Charges and Preferred Stock Dividends
|
|
$
|
107,369
|
|
|
$
|
108,621
|
|
|
$
|
110,323
|
|
|
$
|
102,480
|
|
|
$
|
91,634
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
4.1x
|
|
|
4.1x
|
|
|
—
|
|
(e)
|
5.3x
|
|
|
6.5x
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
|
|
4.0x
|
|
|
4.1x
|
|
|
—
|
|
(e)
|
5.3x
|
|
|
6.4x
|
|
(a)
|
Net
income
excludes undistributed income for equity investees.
|
(b)
|
Represents interest portion of rents estimated at 33 1/3%.
|
(c)
|
Represents interest, amortization of debt discount and expense on all indebtedness and amortization of interest capitalized, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income) and interest capitalized.
|
(d)
|
Represents rents (as defined above), interest, amortization of debt discount and expense on all indebtedness, and excludes amortization of gains or losses on reacquired debt (which, under the Federal Energy Regulatory Commission Uniform System of Accounts, is classified as a reduction of, or increase in, interest expense in the Consolidated Statements of Income).
|
(e)
|
Due to the $384.4 million after-tax noncash write-down of natural gas and oil properties in the first quarter of 2009, earnings were insufficient by $228.7 million to cover combined fixed charges and preferred stock dividends for the twelve months ended December 31, 2009. If the $384.4 million after-tax noncash write-down is excluded, the ratio of earnings to fixed charges and the ratio of earnings to combined fixed charges and preferred stock dividends would both have been 4.6 times for the twelve months ended December 31, 2009.
|
Subsidiaries
|
Jurisdiction of
Formation
|
Alaska Basic Industries, Inc.
|
Alaska
|
Ames Sand & Gravel, Inc.
|
North Dakota
|
Anchorage Sand and Gravel Company, Inc.
|
Alaska
|
Baldwin Contracting Company, Inc.
|
California
|
BEH Electric Holdings, LLC
|
Nevada
|
Bell Electrical Contractors, Inc.
|
Missouri
|
Bitter Creek Pipelines, LLC
|
Colorado
|
BMH Mechanical Holdings, LLC
|
Nevada
|
Bombard Electric, LLC
|
Nevada
|
Bombard Mechanical, LLC
|
Nevada
|
Capital Electric Construction Company, Inc.
|
Kansas
|
Capital Electric Line Builders, Inc.
|
Kansas
|
Cascade Natural Gas Corporation
|
Washington
|
Centennial Energy Holdings, Inc.
|
Delaware
|
Centennial Energy Resources International, Inc.
|
Delaware
|
Centennial Energy Resources LLC
|
Delaware
|
Centennial Holdings Capital LLC
|
Delaware
|
Central Oregon Redi-Mix, LLC
|
Oregon
|
CGC Resources, Inc.
|
Washington
|
Concrete, Inc.
|
California
|
Connolly-Pacific Co.
|
California
|
Continental Line Builders, Inc.
|
Delaware
|
Coordinating and Planning Services, Inc.
|
Delaware
|
D S S Company
|
California
|
Desert Fire Holdings, Inc.
|
Nevada
|
Desert Fire Protection, a Nevada Limited Partnership
|
Nevada
|
Desert Fire Protection, Inc.
|
Nevada
|
Desert Fire Protection, LLC
|
Nevada
|
E.S.I., Inc.
|
Ohio
|
Fairbanks Materials, Inc.
|
Alaska
|
Fidelity Exploration & Production Company
|
Delaware
|
Fidelity Oil Co.
|
Delaware
|
Frebco, Inc.
|
Ohio
|
FutureSource Capital Corp.
|
Delaware
|
Granite City Ready Mix, Inc.
|
Minnesota
|
Hamlin Electric Company
|
Colorado
|
Harp Engineering, Inc.
|
Montana
|
Hawaiian Cement, a partnership
|
Hawaii
|
ILB Hawaii, Inc.
|
Hawaii
|
Independent Fire Fabricators, LLC
|
Nevada
|
Intermountain Gas Company
|
Idaho
|
International Line Builders, Inc.
|
Delaware
|
InterSource Insurance Company
|
Vermont
|
Jebro Incorporated
|
Iowa
|
JTL Group, Inc., a Montana corporation
|
Montana
|
JTL Group, Inc., a Wyoming corporation
|
Wyoming
|
Kent’s Oil Service
|
California
|
Knife River Corporation
|
Delaware
|
Knife River Corporation – North Central
|
Minnesota
|
Knife River Corporation – Northwest
|
Oregon
|
Knife River Corporation – South
|
Texas
|
Knife River Dakota, Inc.
|
Delaware
|
Knife River Equipment, Inc.
|
Delaware
|
Knife River Hawaii, Inc.
|
Delaware
|
RYDER SCOTT COMPANY
|
|
|
PETROLEUM CONSULTANTS
|
|
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
|
FAX (713) 651-0849
|
1100 LOUISIANA SUITE 3800
|
HOUSTON, TEXAS 77002-5235
|
TELEPHONE (713) 651-9191
|
SUITE 600, 1015 4TH STREET, S.W.
|
CALGARY, ALBERTA T2R 1J4
|
TEL (403) 262-2799
|
FAX (403) 262-2790
|
621 17TH STREET, SUITE 1550
|
DENVER, COLORADO 80293-1501
|
TEL (303) 623-9147
|
FAX (303) 623-4258
|
1.
|
I have reviewed this annual report on Form 10-K of MDU Resources Group, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
1.
|
I have reviewed this annual report on Form 10-K of MDU Resources Group, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
1.
|
Citations issued under Section 104 of the Mine Safety Act for violations that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard.
|
2.
|
Orders issued under Section 104(b) of the Mine Safety Act. Orders are issued under this section when citations issued under Section 104 have not been totally abated within the time period allowed by the citation or subsequent extensions.
|
3.
|
Citations or orders issued under Section 104(d) of the Mine Safety Act. Citations or orders are issued under this section when it has been determined that the violation is caused by an unwarrantable failure of the mine operator to comply with the standards. An unwarrantable failure occurs when the mine operator is deemed to have engaged in aggravated conduct constituting more than ordinary negligence.
|
4.
|
Citations issued under Section 110(b)(2) of the Mine Safety Act for flagrant violations. Violations are considered flagrant for repeat or reckless failures to make reasonable efforts to eliminate a known violation of a mandatory health and safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.
|
5.
|
Imminent danger orders issued under Section 107(a) of the Mine Safety Act. An imminent danger is defined as the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated.
|
6.
|
Notice received under Section 104(e) of the Mine Safety Act of a pattern of violations or the potential to have such a pattern of violations that could significantly and substantially contribute to the cause and effect of mine health and safety standards.
|
Mine or Operating Name/MSHA Identification Number
|
Section 104 S&S Citations (#)
|
Section
104(b) Orders (#)
|
Section
107(a) Orders (#)
|
Total Dollar Value of MSHA Assessments Proposed ($)
|
Total Number of Mining Related Fatalities (#)
|
Legal Actions Pending as of Last Day of Period (#)
|
Legal Actions Initiated During Period (#)
|
Legal Actions Resolved During Period (#)
|
|||||||||
140 Pit
|
1
|
|
—
|
|
—
|
|
$
|
176
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Advance Aggregate
|
1
|
|
—
|
|
—
|
|
762
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Alva
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Amyx Pit
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Anderson Pit
|
1
|
|
—
|
|
—
|
|
392
|
|
—
|
|
1
|
|
1
|
|
—
|
|
|
Angell Quarry
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
—
|
|
—
|
|
|
Bang Pit
|
—
|
|
—
|
|
—
|
|
600
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Becker Portable
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
3
|
|
|
Becker Wash Plant #1
|
2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Bender Pit
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
|
Billings Pit
|
1
|
|
—
|
|
—
|
|
490
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Birchwood
|
1
|
|
—
|
|
—
|
|
262
|
|
—
|
|
1
|
|
1
|
|
—
|
|
|
Coffee Lake
|
—
|
|
—
|
|
—
|
|
400
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Mine or Operating Name/MSHA Identification Number
|
Section 104 S&S Citations (#)
|
Section
104(b) Orders (#)
|
Section
107(a) Orders (#)
|
Total Dollar Value of MSHA Assessments Proposed ($)
|
Total Number of Mining Related Fatalities (#)
|
Legal Actions Pending as of Last Day of Period (#)
|
Legal Actions Initiated During Period (#)
|
Legal Actions Resolved During Period (#)
|
|||||||||
Coffin Butte
|
—
|
|
—
|
|
—
|
|
300
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Concrete, Inc.
|
—
|
|
—
|
|
—
|
|
263
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Crusher #1
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Davis Slough
|
1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Dralle Pit
|
—
|
|
—
|
|
—
|
|
500
|
|
—
|
|
—
|
|
3
|
|
—
|
|
|
Drycreek Landfill
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Elk River Wash Plant
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
|
Eugene
|
5
|
|
—
|
|
—
|
|
924
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Fisher Island
|
—
|
|
—
|
|
—
|
|
1,848
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Fitzgerald Pit
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Gardner Pit
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
—
|
|
—
|
|
—
|
|
|
Gazley Pit
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Gresham S&G
|
1
|
|
—
|
|
—
|
|
725
|
|
—
|
|
2
|
|
—
|
|
—
|
|
|
Halawa Quarry
|
2
|
|
—
|
|
—
|
|
6,904
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Halawa Valley
|
—
|
|
—
|
|
—
|
|
815
|
|
—
|
|
3
|
|
—
|
|
—
|
|
|
Hallwood Plant
|
2
|
|
—
|
|
—
|
|
1,404
|
|
—
|
|
2
|
|
2
|
|
—
|
|
|
Kalispell Wash Plant
|
2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Kirkland
|
—
|
|
—
|
|
—
|
|
300
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Klatt Terminal
|
2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Kona Sand Plant
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Lampasas Quarry
|
—
|
|
1
|
|
—
|
|
112
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Little Falls
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
|
Lone Pine Portable Plant
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
—
|
|
—
|
|
|
Lone Pine Wash Plant
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
McKenzie Pit
|
1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Mobile Crusher #1
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
—
|
|
—
|
|
|
Moses Wash Plant
|
1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Orland Plant
|
3
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3
|
|
8
|
|
5
|
|
|
Paetsch Pit
|
—
|
|
1
|
|
—
|
|
200
|
|
—
|
|
5
|
|
2
|
|
—
|
|
|
Pebbly Beach Quarry
|
5
|
|
—
|
|
1
|
|
3,399
|
|
—
|
|
4
|
|
4
|
|
—
|
|
|
Pioneer
|
2
|
|
—
|
|
—
|
|
570
|
|
—
|
|
7
|
|
5
|
|
—
|
|
|
Portable 1
|
3
|
|
—
|
|
—
|
|
1,306
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Portable 2
|
—
|
|
—
|
|
—
|
|
600
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Portable Crusher #1
|
1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Puunene Quarry
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
1
|
|
—
|
|
—
|
|
|
Quality Quarry
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Quality Rock
|
4
|
|
—
|
|
—
|
|
21,840
|
|
—
|
|
3
|
|
—
|
|
—
|
|
|
Rittenour Pit
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3
|
|
|
Rockville 3 Quarry
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
—
|
|
—
|
|
|
Round Prairie
|
2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Salem-Reed Pit
|
2
|
|
—
|
|
—
|
|
894
|
|
—
|
|
—
|
|
4
|
|
4
|
|
|
Sauk Rapids
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Mine or Operating Name/MSHA Identification Number
|
Section 104 S&S Citations (#)
|
Section
104(b) Orders (#)
|
Section
107(a) Orders (#)
|
Total Dollar Value of MSHA Assessments Proposed ($)
|
Total Number of Mining Related Fatalities (#)
|
Legal Actions Pending as of Last Day of Period (#)
|
Legal Actions Initiated During Period (#)
|
Legal Actions Resolved During Period (#)
|
|||||||||
Sky High Pit
|
3
|
|
—
|
|
—
|
|
424
|
|
—
|
|
1
|
|
1
|
|
—
|
|
|
Slatt Quarry
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
—
|
|
—
|
|
|
Star Pit #1
|
1
|
|
—
|
|
—
|
|
700
|
|
—
|
|
5
|
|
5
|
|
—
|
|
|
Stark Pit
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Stayton
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Sullivan Quarry MC1
|
2
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
T Olson Pit
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3
|
|
|
Vernalis
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Voight Pit
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
VR Pit
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
—
|
|
—
|
|
|
Waikapu Quarry
|
3
|
|
—
|
|
1
|
|
1,589
|
|
—
|
|
—
|
|
2
|
|
2
|
|
|
Waikapu Sand Pit
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Waimea Quarry
|
—
|
|
—
|
|
—
|
|
93
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Wash Plant
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
—
|
|
—
|
|
|
Waterview
|
1
|
|
—
|
|
—
|
|
1,361
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Watters Quarry
|
—
|
|
—
|
|
—
|
|
100
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Weddle Pit
|
—
|
|
—
|
|
—
|
|
200
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Wienmann Pit
|
—
|
|
—
|
|
—
|
|
2,512
|
|
—
|
|
—
|
|
1
|
|
—
|
|
|
Wong Pit (Jig Plant)
|
2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
—
|
|
—
|
|
|
|
58
|
|
2
|
|
2
|
|
$
|
55,765
|
|
1
|
|
49
|
|
39
|
|
25
|
|
/s/ Joseph E. Blankenship
|
Joseph E. Blankenship, P.E.
|
TBPE License No. 62093
|
Senior Vice President
|
RYDER SCOTT COMPANY
|
|
|
PETROLEUM CONSULTANTS
|
|
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
|
FAX (713) 651-0849
|
1100 LOUISIANA SUITE 3800
|
HOUSTON, TEXAS 77002-5235
|
TELEPHONE (713) 651-9191
|
|
|
|
|
|
|
|
January 10, 2012
|
|
SUITE 600, 1015 4TH STREET, S.W.
|
CALGARY, ALBERTA T2R 1J4
|
TEL (403) 262-2799
|
FAX (403) 262-2790
|
621 17TH STREET, SUITE 1550
|
DENVER, COLORADO 80293-1501
|
TEL (303) 623-9147
|
FAX (303) 623-4258
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As of December 31, 2011
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Proved
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Developed
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Total
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Producing
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Non-Producing
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Undeveloped
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Proved
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Total Net Reserves
All Audited by Ryder Scott
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Oil/Condensate - Barrels
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22,792,968
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860,790
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3,351,683
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27,005,441
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Plant Products - Barrels
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3,815,421
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1,408,838
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2,117,263
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7,341,522
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Gas - MMCF
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274,534
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28,961
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76,332
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379,827
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Very truly yours,
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RYDER SCOTT COMPANY, L.P.
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TBPE Firm Registration No. F-1580
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/s/ Joseph E. Blankenship
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Joseph E. Blankenship, P.E.
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TBPE License No. 62093
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Senior Vice President
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(1)
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completion intervals which are open at the time of the estimate, but which have not started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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