x
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QUARTERLY 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 Quarterly Period Ended June 30, 2010
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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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Large accelerated filer x
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o
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2009 Annual Report
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Company's Annual Report on Form 10-K for the year ended December 31, 2009
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ASC
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FASB Accounting Standards Codification
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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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BER
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Montana Board of Environmental Review
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Big Stone Station
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450-MW coal-fired electric generating facility located near Big Stone City, South Dakota (22.7 percent ownership)
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Big Stone Station II
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Formerly proposed coal-fired electric generating facility located near Big Stone City, South Dakota (the Company had anticipated ownership of at least 116 MW)
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Brazilian Transmission Lines
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Company’s equity method investment in companies owning ECTE, ENTE and ERTE
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Btu
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British thermal unit
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Cascade
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Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
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CBNG
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Coalbed natural gas
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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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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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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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Company
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MDU Resources Group, Inc.
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dk
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Decatherm
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ECTE
|
Empresa Catarinense de Transmissão de Energia S.A.
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EIS
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Environmental Impact Statement
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ENTE
|
Empresa Norte de Transmissão de Energia S.A.
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EPA
|
U.S. Environmental Protection Agency
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ERTE
|
Empresa Regional de Transmissão de Energia S.A.
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Exchange Act
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Securities Exchange Act of 1934, as amended
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FASB
|
Financial Accounting Standards Board
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FERC
|
Federal Energy Regulatory Commission
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Fidelity
|
Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
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GAAP
|
Accounting principles generally accepted in the United States of America
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GHG
|
Greenhouse gas
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Great Plains
|
Great Plains Natural Gas Co., a public utility division of the Company
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Intermountain
|
Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
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IPUC
|
Idaho Public Utilities Commission
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Knife River
|
Knife River Corporation, a direct wholly owned subsidiary of Centennial
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kWh
|
Kilowatt-hour
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LTM
|
LTM, Inc., an indirect wholly owned subsidiary of Knife River
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LPP
|
Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006)
|
LWG
|
Lower Willamette Group
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MBbls
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Thousands of barrels
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MBI
|
Morse Bros., Inc., an indirect wholly owned subsidiary of Knife River
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MBOGC
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Montana Board of Oil and Gas Conservation
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Mcf
|
Thousand cubic feet
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MDU Brasil
|
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
|
MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
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MEIC
|
Montana Environmental Information Center, 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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MMdk
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Million decatherms
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Montana-Dakota
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Montana-Dakota Utilities Co., a public utility division of the Company
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Montana DEQ
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Montana State Department of Environmental Quality
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Montana First Judicial District Court
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Montana First Judicial District Court, Lewis and Clark County
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Montana Twenty-Second Judicial District Court
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Montana Twenty-Second Judicial District Court, Big Horn County
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MPX
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MPX Termoceara Ltda. (49 percent ownership, sold in June 2005)
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MTPSC
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Montana Public Service Commission
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MW
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Megawatt
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NDPSC
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North Dakota Public Service Commission
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North Dakota District Court
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North Dakota South Central Judicial District Court for Burleigh County
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NPRC
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Northern Plains Resource Council
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NSPS
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New Source Performance Standards
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Oil
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Includes crude oil, condensate and natural gas liquids
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OPUC
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Oregon Public Utility Commission
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Oregon DEQ
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Oregon State Department of Environmental Quality
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Prairielands
|
Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
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PRP
|
Potentially Responsible Party
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PSD
|
Prevention of Significant Deterioration
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ROD
|
Record of Decision
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SDPUC
|
South Dakota Public Utilities Commission
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SEC
|
U.S. Securities and Exchange Commission
|
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
|
Securities Act of 1933, as amended
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South Dakota Federal District Court
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U.S. District Court for the District of South Dakota
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South Dakota SIP
|
South Dakota State Implementation Plan
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TRWUA
|
Tongue River Water Users’ Association
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WBI Holdings
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WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
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Williston Basin
|
Williston Basin Interstate Pipeline Company, an indirect wholly owned subsidiary of WBI Holdings
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WUTC
|
Washington Utilities and Transportation Commission
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Wygen III
|
100-MW coal-fired electric generating facility located near Gillette, Wyoming (25 percent ownership)
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WYPSC
|
Wyoming Public Service Commission
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Part I -- Financial Information
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Page
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Consolidated Statements of Income --
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Three and Six Months Ended June 30, 2010 and 2009
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7
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Consolidated Balance Sheets --
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June 30, 2010 and 2009, and December 31, 2009
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8
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Consolidated Statements of Cash Flows --
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Six Months Ended June 30, 2010 and 2009
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9
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Notes to Consolidated Financial Statements
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10
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
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35
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Quantitative and Qualitative Disclosures About Market Risk
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55
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Controls and Procedures
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57
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Part II -- Other Information
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Legal Proceedings
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57
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Risk Factors
|
58
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Unregistered Sales of Equity Securities and Use of Proceeds
|
60
|
Exhibits
|
60
|
Signatures
|
61
|
|
|
Exhibit Index
|
62
|
Exhibits
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
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|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In thousands, except per share amounts)
|
||||||||||||||||
Operating revenues:
|
||||||||||||||||
Electric, natural gas distribution and pipeline and energy services
|
$ | 272,177 | $ | 263,617 | $ | 732,422 | $ | 858,191 | ||||||||
Construction services, natural gas and oil production, construction materials and contracting, and other
|
634,267 | 694,423 | 1,008,799 | 1,193,854 | ||||||||||||
Total operating revenues
|
906,444 | 958,040 | 1,741,221 | 2,052,045 | ||||||||||||
Operating expenses:
|
||||||||||||||||
Fuel and purchased power
|
13,106 | 15,166 | 30,017 | 33,896 | ||||||||||||
Purchased natural gas sold
|
97,441 | 106,401 | 331,133 | 462,897 | ||||||||||||
Operation and maintenance:
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Electric, natural gas distribution and pipeline and energy services
|
68,437 | 62,581 | 131,421 | 133,932 | ||||||||||||
Construction services, natural gas and oil production, construction materials and contracting, and other
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516,854 | 554,556 | 830,642 | 976,706 | ||||||||||||
Depreciation, depletion and amortization
|
81,547 | 80,449 | 160,225 | 173,694 | ||||||||||||
Taxes, other than income
|
40,397 | 38,822 | 86,192 | 91,774 | ||||||||||||
Write-down of natural gas and oil properties
|
— | — | — | 620,000 | ||||||||||||
Total operating expenses
|
817,782 | 857,975 | 1,569,630 | 2,492,899 | ||||||||||||
Operating income (loss)
|
88,662 | 100,065 | 171,591 | (440,854 | ) | |||||||||||
Earnings from equity method investments
|
2,260 | 2,078 | 4,443 | 3,864 | ||||||||||||
Other income
|
2,686 | 2,435 | 5,188 | 4,154 | ||||||||||||
Interest expense
|
20,490 | 20,759 | 41,006 | 41,755 | ||||||||||||
Income (loss) before income taxes
|
73,118 | 83,819 | 140,216 | (474,591 | ) | |||||||||||
Income taxes
|
24,180 | 28,508 | 49,506 | (186,100 | ) | |||||||||||
Net income (loss)
|
48,938 | 55,311 | 90,710 | (288,491 | ) | |||||||||||
Dividends on preferred stocks
|
171 | 171 | 343 | 343 | ||||||||||||
Earnings (loss) on common stock
|
$ | 48,767 | $ | 55,140 | $ | 90,367 | $ | (288,834 | ) | |||||||
Earnings (loss) per common share -- basic
|
$ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | |||||||
Earnings (loss) per common share -- diluted
|
$ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | |||||||
Dividends per common share
|
$ | .1575 | $ | .1550 | $ | .3150 | $ | .3100 | ||||||||
Weighted average common shares outstanding -- basic
|
188,129 | 183,964 | 188,047 | 183,876 | ||||||||||||
Weighted average common shares outstanding -- diluted
|
188,267 | 184,398 | 188,198 | 183,876 |
June 30,
2010
|
June 30,
2009
|
December 31,
2009
|
||||||||||
(In thousands, except shares and per share amounts)
|
||||||||||||
ASSETS
|
||||||||||||
Current assets:
|
||||||||||||
Cash and cash equivalents
|
$ | 65,792 | $ | 34,310 | $ | 175,114 | ||||||
Receivables, net
|
502,454 | 559,842 | 531,980 | |||||||||
Inventories
|
260,163 | 285,814 | 249,804 | |||||||||
Deferred income taxes
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17,755 | 2,490 | 28,145 | |||||||||
Short-term investments
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250 | 1,967 | 2,833 | |||||||||
Commodity derivative instruments
|
24,932 | 62,048 | 7,761 | |||||||||
Prepayments and other current assets
|
97,953 | 117,381 | 66,021 | |||||||||
Total current assets
|
969,299 | 1,063,852 | 1,061,658 | |||||||||
Investments
|
142,212 | 125,361 | 145,416 | |||||||||
Property, plant and equipment
|
7,085,632 | 6,651,088 | 6,766,582 | |||||||||
Less accumulated depreciation, depletion and amortization
|
3,000,663 | 2,906,824 | 2,872,465 | |||||||||
Net property, plant and equipment
|
4,084,969 | 3,744,264 | 3,894,117 | |||||||||
Deferred charges and other assets:
|
||||||||||||
Goodwill
|
634,654 | 622,131 | 629,463 | |||||||||
Other intangible assets, net
|
26,199 | 25,320 | 28,977 | |||||||||
Other
|
255,473 | 242,436 | 231,321 | |||||||||
Total deferred charges and other assets
|
916,326 | 889,887 | 889,761 | |||||||||
Total assets
|
$ | 6,112,806 | $ | 5,823,364 | $ | 5,990,952 | ||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||||||||
Current liabilities:
|
||||||||||||
Short-term borrowings
|
$ | 3,700 | $ | — | $ | 10,300 | ||||||
Long-term debt due within one year
|
72,551 | 27,879 | 12,629 | |||||||||
Accounts payable
|
266,069 | 332,957 | 281,906 | |||||||||
Taxes payable
|
39,976 | 42,151 | 55,540 | |||||||||
Dividends payable
|
29,802 | 28,686 | 29,749 | |||||||||
Accrued compensation
|
35,989 | 44,141 | 47,425 | |||||||||
Commodity derivative instruments
|
20,160 | 57,139 | 36,907 | |||||||||
Other accrued liabilities
|
172,446 | 158,661 | 192,729 | |||||||||
Total current liabilities
|
640,693 | 691,614 | 667,185 | |||||||||
Long-term debt
|
1,508,714 | 1,636,592 | 1,486,677 | |||||||||
Deferred credits and other liabilities:
|
||||||||||||
Deferred income taxes
|
627,256 | 540,952 | 590,968 | |||||||||
Other liabilities
|
708,403 | 544,104 | 674,475 | |||||||||
Total deferred credits and other liabilities
|
1,335,659 | 1,085,056 | 1,265,443 | |||||||||
Commitments and contingencies
|
||||||||||||
Stockholders’ equity:
|
||||||||||||
Preferred stocks
|
15,000 | 15,000 | 15,000 | |||||||||
Common stockholders’ equity:
|
||||||||||||
Common stock
|
||||||||||||
Shares issued -- $1.00 par value, 188,672,532 at June 30, 2010, 184,508,109 at June 30, 2009 and 188,389,265 at December 31, 2009
|
188,673 | 184,508 | 188,389 | |||||||||
Other paid-in capital
|
1,020,206 | 941,773 | 1,015,678 | |||||||||
Retained earnings
|
1,407,950 | 1,270,778 | 1,377,039 | |||||||||
Accumulated other comprehensive income (loss)
|
(463 | ) | 1,669 | (20,833 | ) | |||||||
Treasury stock at cost – 538,921 shares
|
(3,626 | ) | (3,626 | ) | (3,626 | ) | ||||||
Total common stockholders’ equity
|
2,612,740 | 2,395,102 | 2,556,647 | |||||||||
Total stockholders’ equity
|
2,627,740 | 2,410,102 | 2,571,647 | |||||||||
Total liabilities and stockholders’ equity
|
$ | 6,112,806 | $ | 5,823,364 | $ | 5,990,952 |
Six Months Ended
June 30,
|
||||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Operating activities:
|
||||||||
Net income (loss)
|
$ | 90,710 | $ | (288,491 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
||||||||
Depreciation, depletion and amortization
|
160,225 | 173,694 | ||||||
Earnings, net of distributions, from equity method investments
|
(1,899 | ) | (1,685 | ) | ||||
Deferred income taxes
|
35,758 | (206,955 | ) | |||||
Write-down of natural gas and oil properties
|
— | 620,000 | ||||||
Changes in current assets and liabilities, net of acquisitions:
|
||||||||
Receivables
|
27,149 | 149,782 | ||||||
Inventories
|
(12,442 | ) | (26,574 | ) | ||||
Other current assets
|
(32,471 | ) | 47,837 | |||||
Accounts payable
|
(13,164 | ) | (66,260 | ) | ||||
Other current liabilities
|
(45,613 | ) | 2,218 | |||||
Other noncurrent changes
|
(4,882 | ) | (5,141 | ) | ||||
Net cash provided by operating activities
|
203,371 | 398,425 | ||||||
Investing activities:
|
||||||||
Capital expenditures
|
(237,535 | ) | (272,867 | ) | ||||
Acquisitions, net of cash acquired
|
(106,548 | ) | (3,764 | ) | ||||
Net proceeds from sale or disposition of property
|
11,972 | 7,494 | ||||||
Investments
|
1,228 | (2,368 | ) | |||||
Net cash used in investing activities
|
(330,883 | ) | (271,505 | ) | ||||
Financing activities:
|
||||||||
Repayment of short-term borrowings
|
(6,600 | ) | (105,100 | ) | ||||
Issuance of long-term debt
|
82,992 | 109,400 | ||||||
Repayment of long-term debt
|
(814 | ) | (92,024 | ) | ||||
Proceeds from issuance of common stock
|
1,739 | 284 | ||||||
Dividends paid
|
(59,545 | ) | (57,325 | ) | ||||
Tax benefit on stock-based compensation
|
548 | 144 | ||||||
Net cash provided by (used in) financing activities
|
18,320 | (144,621 | ) | |||||
Effect of exchange rate changes on cash and cash equivalents
|
(130 | ) | 297 | |||||
Decrease in cash and cash equivalents
|
(109,322 | ) | (17,404 | ) | ||||
Cash and cash equivalents -- beginning of year
|
175,114 | 51,714 | ||||||
Cash and cash equivalents -- end of period
|
$ | 65,792 | $ | 34,310 |
1.
|
Basis of presentation
|
|
The accompanying consolidated interim financial statements were prepared in conformity with the basis of presentation reflected in the consolidated financial statements included in the Company's 2009 Annual Report, and the standards of accounting measurement set forth in the interim reporting guidance in the ASC and any amendments thereto adopted by the FASB. Interim financial statements do not include all disclosures provided in annual financial statements and, accordingly, these financial statements should be read in conjunction with those appearing in the 2009 Annual Report. The information is unaudited but includes all adjustments that are, in the opinion of management, necessary for a fair presentation of the accompanying consolidated interim financial statements and are of a normal recurring nature. Depreciation, depletion and amortization expense is reported separately on the Consolidated Statements of Income and therefore is excluded from the other line items within operating expenses. Management has also evaluated the impact of events occurring after June 30, 2010, up to the date of issuance of these consolidated interim financial statements.
|
2.
|
Seasonality of operations
|
|
Some of the Company's operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Accordingly, the interim results for particular businesses, and for the Company as a whole, may not be indicative of results for the full fiscal year.
|
3.
|
Allowance for doubtful accounts
|
|
The Company's allowance for doubtful accounts as of June 30, 2010 and 2009, and December 31, 2009, was $14.9 million, $16.5 million and $16.6 million, respectively.
|
4.
|
Natural gas in storage
|
|
Natural gas in storage for the Company's regulated operations is generally carried at average cost, or cost using the last-in, first-out method. The portion of the cost of natural gas in storage expected to be used within one year was included in inventories and was $14.3 million, $19.1 million and $35.6 million at June 30, 2010 and 2009, and December 31, 2009, respectively. The remainder of natural gas in storage, which largely represents the cost of gas required to maintain pressure levels for normal operating purposes, was included in other assets and was $59.3 million, $40.3 million, and $59.6 million at June 30, 2010 and 2009, and December 31, 2009, respectively.
|
5.
|
Inventories
|
|
Inventories, other than natural gas in storage for the Company’s regulated operations, consisted primarily of aggregates held for resale of $83.5 million, $96.3 million and $80.1 million; materials and supplies of $62.1 million, $69.4 million and $58.1 million; asphalt oil of $52.0 million, $49.8 million and $23.0 million; and other inventories of $48.3 million, $51.2 million and $53.0 million, as of June 30, 2010 and 2009, and December 31, 2009, respectively. These inventories were stated at the lower of average cost or market value.
|
6.
|
Natural gas and oil properties
|
|
The Company uses the full-cost method of accounting for its natural gas and oil production activities. Under this method, all costs incurred in the acquisition, exploration and development of natural gas and oil properties are capitalized and amortized on the units-of-production method based on total proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized.
|
|
Capitalized costs are subject to a “ceiling test” that limits such costs to the aggregate of the present value of future net cash flows from proved reserves discounted at 10 percent, as mandated under the rules of the SEC, plus the cost of unproved properties less applicable income taxes. Future net revenue was estimated based on end-of-quarter spot market prices adjusted for contracted price changes prior to the fourth quarter of 2009. Effective December 31, 2009, the Modernization of Oil and Gas Reporting rules issued by the SEC changed the pricing used to estimate reserves and associated future cash flows to SEC Defined Prices. Prior to that date, if capitalized costs exceeded the full-cost ceiling at the end of any quarter, a permanent noncash write-down was required to be charged to earnings in that quarter unless subsequent price changes eliminated or reduced an indicated write-down. Effective December 31, 2009, if capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent noncash write-down is required to be charged to earnings in that quarter regardless of subsequent price changes.
|
|
Due to low natural gas and oil prices that existed on March 31, 2009, the Company's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 2009. Accordingly, the Company was required to write down its natural gas and oil producing properties. The noncash write-down amounted to $620.0 million ($384.4 million after tax) for the three months ended March 31, 2009.
|
|
The Company hedges a portion of its natural gas and oil production and the effects of the cash flow hedges were used in determining the full-cost ceiling. The Company would have recognized an additional write-down of its natural gas and oil properties of $107.9 million ($66.9 million after tax) at March 31, 2009, if the effects of cash flow hedges had not been considered in calculating the full-cost ceiling. For more information on the Company's cash flow hedges, see Note 13.
|
|
At June 30, 2010, the Company’s full-cost ceiling exceeded the Company’s capitalized cost. However, sustained downward movements in natural gas and oil prices subsequent to June 30, 2010, could result in a future write-down of the Company’s natural gas and oil properties.
|
7.
|
Earnings (loss) per common share
|
|
Basic earnings (loss) per common share were computed by dividing earnings (loss) on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the applicable period, plus the effect of outstanding stock options, restricted stock grants and performance share awards. For the three months ended June 30, 2010 and 2009, and the six months ended June 30, 2010, there were no shares excluded from the calculation of diluted earnings per share. Diluted loss per common share for the six months ended June 30, 2009, was computed by dividing the loss on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Due to the loss on common stock for the six months ended June 30, 2009, the effect of outstanding stock options, restricted stock grants and performance share awards was excluded from the computation of diluted loss per common share as their effect was antidilutive. Common stock outstanding includes issued shares less shares held in treasury.
|
8.
|
Cash flow information
|
|
Cash expenditures for interest and income taxes were as follows:
|
Six Months Ended
June 30,
|
||||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Interest, net of amount capitalized
|
$ | 39,652 | $ | 40,588 | ||||
Income taxes
|
$ | 36,011 | $ | 13,343 |
9.
|
New accounting standards
|
|
Variable Interest Entities In June 2009, the FASB issued guidance related to variable interest entities which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting rights should be consolidated and modifies the approach for determining the primary beneficiary of a variable interest entity. This guidance requires a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. The guidance related to variable interest entities was effective for the Company on January 1, 2010. The adoption of this guidance did not have a material effect on the Company’s financial position or results of operations.
|
|
Improving Disclosure About Fair Value Measurements In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance requires additional disclosures but does not impact the Company’s financial position or results of operations.
|
|
Subsequent Events In February 2010, the FASB issued guidance amending certain recognition and disclosure requirements related to subsequent events. The guidance requires an entity that is an SEC filer to evaluate subsequent events through the date that the financial statements are issued. The guidance also removes the requirement to disclose the date through which subsequent events were evaluated. The guidance related to subsequent events was effective for the Company in the first quarter of 2010. The adoption of this guidance did not impact the Company’s financial position or results of operations.
|
10.
|
Comprehensive income (loss)
|
|
Comprehensive income (loss) is the sum of net income (loss) as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges and foreign currency translation adjustments. For more information on derivative instruments, see Note 13.
|
|
Comprehensive income (loss), and the components of other comprehensive income (loss) and related tax effects, were as follows:
|
Three Months Ended
June 30,
|
||||||||
2010
|
2009
|
|||||||
(In thousands)
|
||||||||
Net income
|
$ | 48,938 | $ | 55,311 | ||||
Other comprehensive loss:
|
||||||||
Net unrealized loss on derivative instruments qualifying as hedges:
|
||||||||
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $2,588 and $(4,028) in 2010 and 2009, respectively
|
4,637 | (6,571 | ) | |||||
Less: Reclassification adjustment for gain on derivative instruments included in net income, net of tax of $3,191 and $11,415 in 2010 and 2009, respectively
|
5,259 | 18,625 | ||||||
Net unrealized loss on derivative instruments qualifying as hedges
|
(622 | ) | (25,196 | ) | ||||
Foreign currency translation adjustment, net of tax of $307 and $3,711 in 2010 and 2009, respectively
|
(476 | ) | 5,756 | |||||
(1,098 | ) | (19,440 | ) | |||||
Comprehensive income
|
$ | 47,840 | $ | 35,871 | ||||
Six Months Ended
June 30,
|
||||||||
2010 | 2009 | |||||||
(In thousands)
|
||||||||
Net income (loss)
|
$ | 90,710 | $ | (288,491 | ) | |||
Other comprehensive income (loss):
|
||||||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
|
||||||||
Net unrealized gain on derivative instruments arising during the period, net of tax of $11,962 and $5,634 in 2010 and 2009, respectively
|
19,932 | 9,193 | ||||||
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $(1,166) and $14,646 in 2010 and 2009, respectively
|
(1,850 | ) | 23,896 | |||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges
|
21,782 | (14,703 | ) | |||||
Foreign currency translation adjustment, net of tax of $(929) and $3,875 in 2010 and 2009, respectively
|
(1,412 | ) | 6,007 | |||||
20,370 | (8,696 | ) | ||||||
Comprehensive income (loss)
|
$ | 111,080 | $ | (297,187 | ) |
11.
|
Equity method investments
|
|
Investments in companies in which the Company has the ability to exercise significant influence over operating and financial policies are accounted for using the equity method. The Company's equity method investments at June 30, 2010, include the Brazilian Transmission Lines.
|
|
In August 2006, MDU Brasil acquired ownership interests in companies owning the Brazilian Transmission Lines. The interests involve the ENTE (13.3-percent ownership interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership interest) electric transmission lines, which are primarily in northeastern and southern Brazil.
|
|
In the fourth quarter of 2009, multiple sales agreements were signed with three separate parties for the Company to sell its ownership interests in the Brazilian Transmission Lines. Regulatory approval for the sale has been received. The financial closing of the sale is anticipated to occur later this year. One of the parties will purchase 15.6 percent of the Company’s ownership interests over a four-year period. The other parties will purchase 84.4 percent of the Company’s ownership interests at the financial close of the transaction.
|
|
At June 30, 2010 and 2009, and December 31, 2009, the Company's equity method investments had total assets of $369.9 million, $348.3 million and $387.0 million, respectively, and long-term debt of $157.1 million, $171.7 million and $176.7 million, respectively. The Company's investment in its equity method investments was approximately $57.9 million, $52.6 million and $62.4 million, including undistributed earnings of $11.1 million, $8.4 million and $9.3 million, at June 30, 2010 and 2009, and December 31, 2009, respectively.
|
12.
|
Goodwill and other intangible assets
|
|
The changes in the carrying amount of goodwill were as follows:
|
Six Months Ended
June 30, 2010
|
Balance
as of
January 1,
2010
|
Goodwill
Acquired
During
the Year*
|
Balance
as of
June 30,
2010
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | — | $ | — | $ | — | ||||||
Natural gas distribution
|
345,736 | — | 345,736 | |||||||||
Construction services
|
100,127 | 2,764 | 102,891 | |||||||||
Pipeline and energy services
|
7,857 | 1,880 | 9,737 | |||||||||
Natural gas and oil production
|
— | — | — | |||||||||
Construction materials and contracting
|
175,743 | 547 | 176,290 | |||||||||
Other
|
— | — | — | |||||||||
Total
|
$ | 629,463 | $ | 5,191 | $ | 634,654 | ||||||
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.
|
Six Months Ended
June 30, 2009
|
Balance
as of
January 1,
2009
|
Goodwill
Acquired
During
the Year*
|
Balance
as of
June 30,
2009
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | — | $ | — | $ | — | ||||||
Natural gas distribution
|
344,952 | 296 | 345,248 | |||||||||
Construction services
|
95,619 | 4,398 | 100,017 | |||||||||
Pipeline and energy services
|
1,159 | — | 1,159 | |||||||||
Natural gas and oil production
|
— | — | — | |||||||||
Construction materials and contracting
|
174,005 | 1,702 | 175,707 | |||||||||
Other
|
— | — | — | |||||||||
Total
|
$ | 615,735 | $ | 6,396 | $ | 622,131 | ||||||
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.
|
Year Ended
December 31, 2009
|
Balance
as of
January 1,
2009
|
Goodwill
Acquired
During the
Year*
|
Balance
as of
December 31,
2009
|
||||||||||
(In thousands)
|
|||||||||||||
Electric
|
$ | — | $ | — | $ | — | |||||||
Natural gas distribution
|
344,952 | 784 | 345,736 | ||||||||||
Construction services
|
95,619 | 4,508 | 100,127 | ||||||||||
Pipeline and energy services
|
1,159 | 6,698 | 7,857 | ||||||||||
Natural gas and oil production
|
— | — | — | ||||||||||
Construction materials and contracting
|
174,005 | 1,738 | 175,743 | ||||||||||
Other
|
— | — | — | ||||||||||
Total
|
$ | 615,735 | $ | 13,728 | $ | 629,463 | |||||||
* Includes purchase price adjustments that were not material related to acquisitions in a prior period.
|
|
Other intangible assets were as follows:
|
June 30,
2010
|
June 30,
2009
|
December 31,
2009
|
||||||||||
(In thousands)
|
||||||||||||
Customer relationships
|
$ | 24,942 | $ | 21,688 | $ | 24,942 | ||||||
Accumulated amortization
|
(10,688 | ) | (8,142 | ) | (9,500 | ) | ||||||
14,254 | 13,546 | 15,442 | ||||||||||
Noncompete agreements
|
9,405 | 9,792 | 12,377 | |||||||||
Accumulated amortization
|
(6,033 | ) | (5,942 | ) | (6,675 | ) | ||||||
3,372 | 3,850 | 5,702 | ||||||||||
Other
|
12,063 | 10,679 | 10,859 | |||||||||
Accumulated amortization
|
(3,490 | ) | (2,755 | ) | (3,026 | ) | ||||||
8,573 | 7,924 | 7,833 | ||||||||||
Total
|
$ | 26,199 | $ | 25,320 | $ | 28,977 |
|
Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2010, was $1.1 million and $2.1 million, respectively. Amortization expense for the three and six months ended June 30, 2009, was $1.2 million and $2.6 million, respectively. Estimated amortization expense for amortizable intangible assets is $4.2 million in 2010, $3.9 million in 2011, $3.8 million in 2012, $3.3 million in 2013, $2.9 million in 2014 and $10.2 million thereafter.
|
13.
|
Derivative instruments
|
|
The Company's policy allows the use of derivative instruments as part of an overall energy price, foreign currency and interest rate risk management program to efficiently manage and minimize commodity price, foreign currency and interest rate risk. As of June 30, 2010, the Company had no outstanding foreign currency or interest rate hedges. The following information should be read in conjunction with Notes 1 and 7 in the Company's Notes to Consolidated Financial Statements in the 2009 Annual Report.
|
|
Cascade and Intermountain
|
|
At June 30, 2010, Cascade and Intermountain held natural gas swap agreements, with total forward notional volumes of 9.2 million MMBtu, which were not designated as hedges. Cascade and Intermountain utilize natural gas swap agreements to manage a portion of their regulated natural gas supply portfolios in order to manage fluctuations in the price of natural gas related to core customers in accordance with authority granted by the IPUC, WUTC and OPUC. Core customers consist of residential, commercial and smaller industrial customers. The fair value of the derivative instrument must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or a liability. Cascade and Intermountain record periodic changes in the fair market value of the derivative instruments on the Consolidated Balance Sheets as a regulatory asset or a regulatory liability, and settlements of these arrangements are expected to be recovered through the purchased gas cost adjustment mechanism. Gains and losses on the settlements of these derivative instruments are recorded as a component of purchased natural gas sold on the Consolidated Statements of Income as they are recovered through the purchased gas cost adjustment mechanism. Under the terms of these arrangements, Cascade and Intermountain will either pay or receive settlement payments based on the difference between the fixed strike price and the monthly index price applicable to each contract. For the three and six months ended June 30, 2010, Cascade and Intermountain recorded the change in the fair market value of the derivative instruments of $3.9 million and $9.0 million, respectively, as a decrease to regulatory assets.
|
|
Certain of Cascade's derivative instruments contain credit-risk-related contingent features that permit the counterparties to require collateralization if Cascade's derivative liability positions exceed certain dollar thresholds. The dollar thresholds in certain of Cascade's agreements are determined and may fluctuate based on Cascade's credit rating on its debt. In addition, Cascade's and Intermountain's derivative instruments contain cross-default provisions that state if the entity fails to make payment with respect to certain of its indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of such entity's derivative instruments in liability positions. The aggregate fair value of Cascade and Intermountain's derivative instruments with credit-risk-related contingent features that are in a liability position at June 30, 2010, was $18.9 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on June 30, 2010, was $18.9 million.
|
|
Fidelity
|
|
At June 30, 2010, Fidelity held natural gas swaps and collar agreements with total forward notional volumes of 27.1 million MMBtu, natural gas basis swaps with total forward notional volumes of 17.3 million MMBtu, and oil swap and collar agreements with total forward notional volumes of 2.0 million Bbl, which were designated as cash flow hedging instruments. Fidelity utilizes these derivative instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and oil and basis differentials on its forecasted sales of natural gas and oil production.
|
|
The fair value of the derivative instruments must be estimated as of the end of each reporting period and is recorded on the Consolidated Balance Sheets as an asset or liability. Changes in the fair value attributable to the effective portion of hedging instruments, net of tax, are recorded in stockholders' equity as a component of accumulated other comprehensive income (loss). At the date the natural gas and oil quantities are settled, the amounts accumulated in other comprehensive income (loss) are reported in the Consolidated Statements of Income. To the extent that the hedges are not effective, the ineffective portion of the changes in fair market value is recorded directly in earnings. The proceeds received for natural gas and oil production are generally based on market prices.
|
|
For the three and six months ended June 30, 2010, and 2009, the amount of hedge ineffectiveness was immaterial, and there were no components of the derivative instruments’ gain or loss excluded from the assessment of hedge effectiveness. Gains and losses must be reclassified into earnings as a result of the discontinuance of cash flow hedges if it is probable that the original forecasted transactions will not occur. There were no such reclassifications into earnings as a result of the discontinuance of hedges.
|
|
Gains and losses on derivative instruments that are reclassified from accumulated other comprehensive income (loss) to current-period earnings are included in operating revenues on the Consolidated Statements of Income. For further information regarding the gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in other comprehensive income (loss) and the gains and losses reclassified from accumulated other comprehensive income (loss) into earnings, see Note 10.
|
|
As of June 30, 2010, the maximum term of the swap and collar agreements, in which the exposure to the variability in future cash flows for forecasted transactions is being hedged, is 30 months. The Company estimates that over the next 12 months net gains of approximately $14.3 million (after tax) will be reclassified from accumulated other comprehensive income (loss) into earnings, subject to changes in natural gas and oil market prices, as the hedged transactions affect earnings.
|
|
Certain of Fidelity's derivative instruments contain cross-default provisions that state if Fidelity fails to make payment with respect to certain indebtedness, in excess of specified amounts, the counterparties could require early settlement or termination of derivative instruments in liability positions. The aggregate fair value of Fidelity's derivative instruments with credit-risk-related contingent features that are in a liability position at June 30, 2010, was $2.0 million. The aggregate fair value of assets that would have been needed to settle the instruments immediately if the credit-risk-related contingent features were triggered on June 30, 2010, was $2.0 million.
|
|
The location and fair value of all of the Company’s derivative instruments in the Consolidated Balance Sheets were as follows:
|
Asset
Derivatives
|
Location on
Consolidated
Balance Sheets
|
Fair Value at
June 30,
2010
|
Fair Value at
June 30,
2009
|
Fair Value at
December 31,
2009
|
|||||||||
(In thousands)
|
|||||||||||||
Designated as hedges
|
Commodity derivative instruments
|
$ | 24,932 | $ | 62,047 | $ | 7,761 | ||||||
Other assets – noncurrent
|
8,524 | 4,217 | 2,734 | ||||||||||
33,456 | 66,264 | 10,495 | |||||||||||
Not designated as hedges
|
Commodity derivative instruments
|
— | 1 | — | |||||||||
Other assets – noncurrent
|
— | 1 | — | ||||||||||
— | 2 | — | |||||||||||
Total asset derivatives
|
$ | 33,456 | $ | 66,266 | $ | 10,495 |
Liability
Derivatives
|
Location on
Consolidated
Balance Sheets
|
Fair Value at
June 30,
2010
|
Fair Value at
June 30,
2009
|
Fair Value at
December 31,
2009
|
|||||||||
(In thousands)
|
|||||||||||||
Designated as hedges
|
Commodity derivative instruments
|
$ | 1,961 | $ | 8,440 | $ | 13,763 | ||||||
Other liabilities – noncurrent
|
— | 1,538 | 114 | ||||||||||
1,961 | 9,978 | 13,877 | |||||||||||
Not designated as hedges
|
Commodity derivative instruments
|
18,199 | 48,699 | 23,144 | |||||||||
Other liabilities – noncurrent
|
698 | 10,786 | 4,756 | ||||||||||
18,897 | 59,485 | 27,900 | |||||||||||
Total liability derivatives
|
$ | 20,858 | $ | 69,463 | $ | 41,777 | |||||||
Note: The fair value of the commodity derivative instruments not designated as hedges is presented net of collateral provided to the counterparties by Cascade of $8.5 million at June 30, 2009.
|
14.
|
Fair value measurements
|
|
The Company elected to measure its investments in certain fixed-income and equity securities at fair value with changes in fair value recognized in income. The Company anticipates using these investments to satisfy its obligations under its unfunded, nonqualified benefit plans for executive officers and certain key management employees, and invests in these fixed-income and equity securities for the purpose of earning investment returns and capital appreciation. These investments, which totaled $20.2 million, $29.5 million and $34.8 million, as of June 30, 2010 and 2009, and December 31, 2009, respectively, are classified as Investments on the Consolidated Balance Sheets. The decrease in the fair value of these investments for the three and six months ended June 30, 2010, was $1.8 million (before tax) and $970,000 (before tax), respectively. The increase in the fair value of these investments for the three and six months ended June 30, 2009, was $3.7 million (before tax) and $1.8 million (before tax), respectively. The change in fair value, which is considered part of the cost of the plan, is classified in operation and maintenance expense on the Consolidated Statements of Income. The Company did not elect the fair value option for its remaining available-for-sale securities, which are auction rate securities. The Company’s auction rate securities, which totaled $11.4 million at June 30, 2010 and 2009, and December 31, 2009, are accounted for as available-for-sale and are recorded at fair value. The fair value of the auction rate securities approximate cost and, as a result, there are no accumulated unrealized gains or losses recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets related to these investments.
|
|
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The ASC establishes a hierarchy for grouping assets and liabilities, based on the significance of inputs. The Company’s assets and liabilities measured at fair value on a recurring basis are as follows:
|
Fair Value Measurements at
June 30, 2010, Using
|
||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3)
|
Collateral Provided to Counterparties
|
Balance at June 30, 2010
|
||||||||||||||||
(In thousands)
|
||||||||||||||||||||
Assets:
|
||||||||||||||||||||
Money market funds
|
$ | 8,251 | $ | — | $ | — | $ | — | $ | 8,251 | ||||||||||
Available-for-sale securities:
|
||||||||||||||||||||
Fixed-income securities
|
— | 11,400 | — | — | 11,400 | |||||||||||||||
Insurance contract*
|
— | 20,236 | — | — | 20,236 | |||||||||||||||
Commodity derivative instruments - current
|
— | 24,932 | — | — | 24,932 | |||||||||||||||
Commodity derivative instruments - noncurrent
|
— | 8,524 | — | — | 8,524 | |||||||||||||||
Total assets measured at fair value
|
$ | 8,251 | $ | 65,092 | $ | — | $ | — | $ | 73,343 | ||||||||||
Liabilities:
|
||||||||||||||||||||
Commodity derivative instruments - current
|
$ | — | $ | 20,160 | $ | — | $ | — | $ | 20,160 | ||||||||||
Commodity derivative instruments - noncurrent
|
— | 698 | — | — | 698 | |||||||||||||||
Total liabilities measured at fair value
|
$ | — | $ | 20,858 | $ | — | $ | — | $ | 20,858 | ||||||||||
* Invested in mutual funds.
|
Fair Value Measurements at
June 30, 2009, Using
|
||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3)
|
Collateral Provided to Counterparties
|
Balance at June 30, 2009
|
||||||||||||||||
(In thousands)
|
||||||||||||||||||||
Assets:
|
||||||||||||||||||||
Available-for-sale securities
|
$ | 29,532 | $ | 11,400 | $ | — | $ | — | $ | 40,932 | ||||||||||
Commodity derivative instruments - current
|
— | 62,048 | — | — | 62,048 | |||||||||||||||
Commodity derivative instruments - noncurrent
|
— | 4,218 | — | — | 4,218 | |||||||||||||||
Total assets measured at fair value
|
$ | 29,532 | $ | 77,666 | $ | — | $ | — | $ | 107,198 | ||||||||||
Liabilities:
|
||||||||||||||||||||
Commodity derivative instruments - current
|
$ | — | $ | 65,604 | $ | — | $ | 8,465 | $ | 57,139 | ||||||||||
Commodity derivative instruments - noncurrent
|
— | 12,324 | — | — | 12,324 | |||||||||||||||
Total liabilities measured at fair value
|
$ | — | $ | 77,928 | $ | — | $ | 8,465 | $ | 69,463 |
Fair Value Measurements at
December 31, 2009, Using
|
||||||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3)
|
Collateral Provided to Counterparties
|
Balance at December 31, 2009
|
||||||||||||||||
(In thousands)
|
||||||||||||||||||||
Assets:
|
||||||||||||||||||||
Money market funds
|
$ | 9,124 | $ | 151,000 | $ | — | $ | — | $ | 160,124 | ||||||||||
Available-for-sale securities
|
9,078 | 37,141 | — | — | 46,219 | |||||||||||||||
Commodity derivative instruments - current
|
— | 7,761 | — | — | 7,761 | |||||||||||||||
Commodity derivative instruments - noncurrent
|
— | 2,734 | — | — | 2,734 | |||||||||||||||
Total assets measured at fair value
|
$ | 18,202 | $ | 198,636 | $ | — | $ | — | $ | 216,838 | ||||||||||
Liabilities:
|
||||||||||||||||||||
Commodity derivative instruments - current
|
$ | — | $ | 36,907 | $ | — | $ | — | $ | 36,907 | ||||||||||
Commodity derivative instruments - noncurrent
|
— | 4,870 | — | — | 4,870 | |||||||||||||||
Total liabilities measured at fair value
|
$ | — | $ | 41,777 | $ | — | $ | — | $ | 41,777 |
|
The estimated fair value of the Company’s Level 1 money market funds is determined using the market approach and is valued at the net asset value of shares held by the Company, based on published market quotations in active markets.
|
|
The estimated fair value of the Company’s Level 1 available-for-sale securities is determined using the market approach and is based on quoted market prices in active markets for identical equity and fixed-income securities.
|
|
The estimated fair value of the Company’s Level 2 money market funds and available-for-sale securities is determined using the market approach. The Level 2 money market funds consist of investments in short-term unsecured promissory notes and the value is based on comparable market transactions taking into consideration the credit quality of the issuer. The estimated fair value of the Company’s Level 2 available for-sale securities is based on comparable market transactions.
|
|
The estimated fair value of the Company’s Level 2 commodity derivative instruments is based upon futures prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The nonperformance risk of the counterparties in addition to the Company’s nonperformance risk is also evaluated.
|
|
Though the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value.
|
|
The Company’s long-term debt is not measured at fair value on the Consolidated Balance Sheets and the fair value is being provided for disclosure purposes only. The estimated fair value of the Company’s long-term debt was based on quoted market prices of the same or similar issues. The estimated fair value of the Company's long-term debt was as follows:
|
Carrying
Amount
|
Fair
Value
|
|||||||
(In thousands)
|
||||||||
Long-term debt at June 30, 2010
|
$ | 1,581,265 | $ | 1,718,477 | ||||
Long-term debt at June 30, 2009
|
$ | 1,664,471 | $ | 1,538,693 | ||||
Long-term debt at December 31, 2009
|
$ | 1,499,306 | $ | 1,566,331 |
|
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.
|
15.
|
Business segment data
|
|
The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business units due to differences in products, services and regulation. The vast majority of the Company’s operations are located within the United States. The Company also has investments in foreign countries, which largely consist of Centennial Resources’ equity method investment in the Brazilian Transmission Lines.
|
|
The electric segment generates, transmits and distributes electricity in Montana, North Dakota, South Dakota and Wyoming. The natural gas distribution segment distributes natural gas in those states as well as in Idaho, Minnesota, Oregon and Washington. These operations also supply related value-added products and services.
|
|
The construction services segment specializes in constructing and maintaining electric and communication lines, gas pipelines, fire suppression systems, and external lighting and traffic signalization equipment. This segment also provides utility excavation services and inside electrical wiring, cabling and mechanical services, sells and distributes electrical materials, and manufactures and distributes specialty equipment.
|
|
The pipeline and energy services segment provides natural gas transportation, underground storage and gathering services through regulated and nonregulated pipeline systems primarily in the Rocky Mountain and northern Great Plains regions of the United States. This segment also provides cathodic protection and other energy-related services.
|
|
The natural gas and oil production segment is engaged in natural gas and oil acquisition, exploration, development and production activities in the Rocky Mountain and Mid-Continent regions of the United States and in and around the Gulf of Mexico.
|
|
The construction materials and contracting segment mines aggregates and markets crushed stone, sand, gravel and related construction materials, including ready-mixed concrete, cement, asphalt, liquid asphalt and other value-added products. It also performs integrated contracting services. This segment operates in the central, southern and western United States and Alaska and Hawaii.
|
|
The Other category includes the activities of Centennial Capital, which insures various types of risks as a captive insurer for certain of the Company’s subsidiaries. The function of the captive insurer is to fund the deductible layers of the insured companies’ general liability and automobile liability coverages. Centennial Capital also owns certain real and personal property. The Other category also includes Centennial Resources' equity method investment in the Brazilian Transmission Lines.
|
|
The information below follows the same accounting policies as described in Note 1 of the Company’s Notes to Consolidated Financial Statements in the 2009 Annual Report. Information on the Company's businesses was as follows:
|
Three Months
Ended June 30, 2010
|
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings
on Common
Stock
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | 45,683 | $ | — | $ | 4,947 | ||||||
Natural gas distribution
|
160,138 | — | 74 | |||||||||
Pipeline and energy services
|
66,356 | 14,143 | 9,541 | |||||||||
272,177 | 14,143 | 14,562 | ||||||||||
Construction services
|
188,182 | 8 | 2,923 | |||||||||
Natural gas and oil production
|
84,406 | 26,400 | 24,035 | |||||||||
Construction materials and contracting
|
361,625 | — | 5,659 | |||||||||
Other
|
54 | 2,213 | 1,588 | |||||||||
634,267 | 28,621 | 34,205 | ||||||||||
Intersegment eliminations
|
— | (42,764 | ) | — | ||||||||
Total
|
$ | 906,444 | $ | — | $ | 48,767 |
Three Months
Ended June 30, 2009
|
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings
on Common
Stock
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | 44,508 | $ | — | $ | 3,263 | ||||||
Natural gas distribution
|
164,158 | — | (4,765 | ) | ||||||||
Pipeline and energy services
|
54,951 | 13,046 | 10,876 | |||||||||
263,617 | 13,046 | 9,374 | ||||||||||
Construction services
|
220,697 | 10 | 6,931 | |||||||||
Natural gas and oil production
|
84,291 | 20,488 | 20,779 | |||||||||
Construction materials and contracting
|
389,435 | — | 15,983 | |||||||||
Other
|
— | 2,699 | 2,073 | |||||||||
694,423 | 23,197 | 45,766 | ||||||||||
Intersegment eliminations
|
— | (36,243 | ) | — | ||||||||
Total
|
$ | 958,040 | $ | — | $ | 55,140 |
Six Months
Ended June 30, 2010
|
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings
on Common
Stock
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | 95,379 | $ | — | $ | 10,832 | ||||||
Natural gas distribution
|
509,162 | — | 23,416 | |||||||||
Pipeline and energy services
|
127,881 | 41,228 | 18,332 | |||||||||
732,422 | 41,228 | 52,580 | ||||||||||
Construction services
|
341,247 | 32 | 3,051 | |||||||||
Natural gas and oil production
|
156,066 | 62,327 | 46,246 | |||||||||
Construction materials and contracting
|
511,432 | — | (14,478 | ) | ||||||||
Other
|
54 | 4,451 | 2,968 | |||||||||
1,008,799 | 66,810 | 37,787 | ||||||||||
Intersegment eliminations
|
— | (108,038 | ) | — | ||||||||
Total
|
$ | 1,741,221 | $ | — | $ | 90,367 |
Six Months
Ended June 30, 2009
|
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings
(Loss)
on Common
Stock
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | 95,755 | $ | — | $ | 8,329 | ||||||
Natural gas distribution
|
647,313 | — | 19,114 | |||||||||
Pipeline and energy services
|
115,123 | 37,973 | 17,261 | |||||||||
858,191 | 37,973 | 44,704 | ||||||||||
Construction services
|
465,495 | 41 | 15,565 | |||||||||
Natural gas and oil production
|
155,450 | 55,451 | (352,537 | ) | ||||||||
Construction materials and contracting
|
572,909 | — | 330 | |||||||||
Other
|
— | 5,398 | 3,104 | |||||||||
1,193,854 | 60,890 | (333,538 | ) | |||||||||
Intersegment eliminations
|
— | (98,863 | ) | — | ||||||||
Total
|
$ | 2,052,045 | $ | — | $ | (288,834 | ) |
|
Earnings from electric, natural gas distribution and pipeline and energy services are substantially all from regulated operations. Earnings from construction services, natural gas and oil production, construction materials and contracting, and other are all from nonregulated operations.
|
16.
|
Acquisitions
|
|
During the first six months of 2010, the Company acquired natural gas properties located in the Green River Basin in southwest Wyoming, with an October 1, 2009, effective date. The acquisition includes the purchase of over 60 Bcfe of proven reserves. The total purchase consideration for these properties and purchase price adjustments with respect to acquisitions made prior to 2010, consisting of the Company’s common stock and cash, was approximately $108.1 million.
|
|
The above acquisition was accounted for under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed have been preliminarily recorded at their respective fair values as of the date of acquisition. The final fair market values are pending the completion of the review of the relevant assets and liabilities identified as of the acquisition date. The results of operations of the acquired properties are included in the financial statements as of the date of acquisition. Pro forma financial amounts reflecting the effects of the above acquisition have not been presented, as the acquisition was not material to the Company’s financial position or results of operations.
|
17.
|
Employee benefit plans
|
|
The Company has noncontributory defined benefit pension plans and other postretirement benefit plans for certain eligible employees. Components of net periodic benefit cost for the Company's pension and other postretirement benefit plans were as follows:
|
Three Months
|
Pension Benefits
|
Other
Postretirement
Benefits
|
||||||||||||||
Ended June 30,
|
2010
|
2009
|
2010
|
2009
|
||||||||||||
(In thousands)
|
||||||||||||||||
Components of net periodic benefit cost:
|
||||||||||||||||
Service cost
|
$ | 501 | $ | 1,966 | $ | 374 | $ | 651 | ||||||||
Interest cost
|
4,004 | 5,430 | 1,317 | 1,530 | ||||||||||||
Expected return on assets
|
(4,992 | ) | (5,673 | ) | (1,577 | ) | (1,544 | ) | ||||||||
Amortization of prior service cost (credit)
|
31 | 151 | (915 | ) | (810 | ) | ||||||||||
Amortization of net actuarial loss
|
256 | 643 | 67 | 170 | ||||||||||||
Amortization of net transition obligation
|
— | — | 613 | 625 | ||||||||||||
Net periodic benefit cost, including amount capitalized
|
(200 | ) | 2,517 | (121 | ) | 622 | ||||||||||
Less amount capitalized
|
107 | 484 | 37 | (23 | ) | |||||||||||
Net periodic benefit cost
|
$ | (307 | ) | $ | 2,033 | $ | (158 | ) | $ | 645 | ||||||
Six Months
|
Pension Benefits
|
Other
Postretirement
Benefits
|
||||||||||||||
Ended June 30,
|
2010 | 2009 | 2010 | 2009 | ||||||||||||
(In thousands)
|
||||||||||||||||
Components of net periodic benefit cost:
|
||||||||||||||||
Service cost
|
$ | 1,305 | $ | 4,063 | $ | 731 | $ | 1,091 | ||||||||
Interest cost
|
8,930 | 10,959 | 2,594 | 2,725 | ||||||||||||
Expected return on assets
|
(10,684 | ) | (12,530 | ) | (2,969 | ) | (2,817 | ) | ||||||||
Amortization of prior service cost (credit)
|
69 | 302 | (1,779 | ) | (1,378 | ) | ||||||||||
Amortization of net actuarial loss
|
1,228 | 817 | 455 | 355 | ||||||||||||
Amortization of net transition obligation
|
— | — | 1,145 | 1,063 | ||||||||||||
Net periodic benefit cost, including amount capitalized
|
848 | 3,611 | 177 | 1,039 | ||||||||||||
Less amount capitalized
|
383 | 765 | 84 | 23 | ||||||||||||
Net periodic benefit cost
|
$ | 465 | $ | 2,846 | $ | 93 | $ | 1,016 |
|
In 2009, the Company evaluated several provisions of its employee defined benefit plans for nonunion and certain union employees. As a result of this evaluation, the Company determined that, effective January 1, 2010, all benefit and service accruals of these plans were frozen. These employees are eligible to receive additional defined contribution plan benefits.
|
|
Effective January 1, 2010, eligibility to receive retiree medical benefits was modified at certain of the Company’s businesses. Current employees who attain age 55 with 10 years of continuous service by December 31, 2010, will be provided the current retiree medical insurance benefits or can elect the new benefit, if desired, regardless of when they retire. All other current employees must meet the new eligibility criteria of age 60 and 10 years of continuous service at the time they retire. These employees will be eligible for a specified company funded Retiree Reimbursement Account. Employees hired after December 31, 2009, are not eligible for retiree medical benefits.
|
|
In addition to the qualified plan defined pension benefits reflected in the table, the Company has an unfunded, nonqualified benefit plan for executive officers and certain key management employees that generally provides for defined benefit payments at age 65 following the employee’s retirement or to their beneficiaries upon death for a 15-year period. The Company's net periodic benefit cost for this plan for the three and six months ended June 30, 2010, was $1.7 million and $3.8 million, respectively. The Company's net periodic benefit cost for this plan for the three and six months ended June 30, 2009, was $2.2 million and $4.3 million, respectively.
|
18.
|
Regulatory matters and revenues subject to refund
|
|
In November 2006, Montana-Dakota filed an application with the NDPSC requesting an advance determination of prudence of Montana-Dakota's ownership interest in Big Stone Station II. In August 2008, the NDPSC approved Montana-Dakota’s request for advance determination of prudence for ownership in the proposed Big Stone Station II for a minimum of 121.8 MW up to a maximum of 133 MW and a proportionate ownership share of the associated transmission electric resources. The intervenors in the proceeding appealed the NDPSC order to the North Dakota District Court which affirmed the order of the NDPSC. The intervenors then appealed the North Dakota District Court order to the North Dakota Supreme Court. The Big Stone Station II participants subsequently decided not to proceed with the project and in December 2009, Montana-Dakota filed an application with the NDPSC for a determination that Montana-Dakota’s continued participation in the Big Stone Station II is no longer prudent. In December 2009, Montana-Dakota filed applications with the NDPSC, SDPUC, and MTPSC for authority to defer the costs incurred for securing new electric generation, primarily Big Stone Station II, until the next general rate case. The SDPUC and the MTPSC approved Montana-Dakota’s applications on February 11, 2010, and April 6, 2010, respectively. On April 14, 2010, Montana-Dakota and the NDPSC Advocacy Staff filed a settlement agreement with the NDPSC. The settlement agreement provides for the recovery of the North Dakota allocated costs associated with the Big Stone Station II over a three-year period beginning June 1, 2010, with carrying charges applicable to the balance at the authorized rate of return until recovery commences. On June 25, 2010, the NDPSC approved the settlement agreement, with a modification to the carrying charge rate, to be effective with service rendered August 1, 2010. On July 7, 2010, Montana-Dakota filed a compliance filing on the June 25, 2010, order. On June 28, 2010, the North Dakota Supreme Court dismissed the appeal of the intervenors pursuant to a stipulation of voluntary dismissal by the parties.
|
|
|
In August 2009, Montana-Dakota filed an application with the WYPSC for an electric rate increase. Montana-Dakota requested a total increase of $6.2 million annually or approximately 31 percent above current rates. The rate increase request was necessitated by Montana-Dakota’s purchase of an ownership interest in Wygen III. On January 14, 2010, Montana-Dakota filed a supplement to the application to reflect the inclusion of bonus tax depreciation on Wygen III, reducing its request to a $5.1 million annual increase or approximately 25 percent above current rates. A hearing was held February 23 through February 25, 2010. A stipulation and agreement between Montana-Dakota and the Wyoming Office of Consumer Advocate was filed with the WYPSC on March 5, 2010, that provides a $3.3 million annual increase to be phased-in over a three-year period beginning May 1, 2010. The WYPSC held a hearing on the stipulation on March 22, 2010, and held additional deliberations on April 14, 2010, wherein the WYPSC decided on each issue in the case and Montana-Dakota was directed to file a compliance filing. Montana-Dakota submitted the compliance filing on April 23, 2010, reflecting an increase of $2.7 million annually or approximately 13.1 percent. On April 27, 2010, the WYPSC approved the compliance filing with rates effective May 1, 2010. On June 25, 2010, Montana-Dakota filed a Petition for Rehearing on the return on equity specified in the WYPSC’s order. On July 14, 2010, the WYPSC held oral arguments and denied Montana-Dakota’s request.
|
|
On April 19, 2010, Montana-Dakota filed an application with the NDPSC for an electric rate increase. Montana-Dakota requested a total increase of $15.4 million annually or approximately 14 percent above current rates. The requested increase includes the investment in infrastructure upgrades, recovery of the investment in renewable generation and the costs associated with Big Stone Station II. On June 16, 2010, the NDPSC approved an interim increase of $7.6 million effective with service rendered June 18, 2010. On June 16, 2010, Montana-Dakota and the NDPSC Advocacy Staff filed a partial settlement agreement agreeing to an overall rate of return and a sharing of earnings over a specified return on equity. On July 6, 2010, Montana-Dakota filed an amendment to its application to exclude the deferred generation development costs associated with Big Stone Station II because of a settlement agreement approved by the NDPSC that provided for recovery of such development costs. Montana-Dakota’s amended request is an increase of $13.3 million annually or 12 percent. A hearing has been set for November 8, 2010.
|
19.
|
Contingencies
|
|
Litigation
|
|
Coalbed Natural Gas Operations Fidelity’s CBNG operations are and have been the subject of numerous lawsuits in Montana and Wyoming. The current cases involve the permitting and use of water produced in connection with Fidelity’s CBNG development in the Powder River Basin. Some of these cases challenge the issuance of discharge permits by the Montana DEQ and approval of other water management tools by the MBOGC.
|
|
In April 2006, the Northern Cheyenne Tribe filed a complaint in Montana Twenty-Second Judicial District Court against the Montana DEQ seeking to set aside Fidelity’s direct discharge and treatment permits. The Northern Cheyenne Tribe claimed the Montana DEQ violated the Clean Water Act and the Montana Water Quality Act by failing to include in the permits conditions requiring application of the best practicable control technology currently available and by failing to impose a nondegradation policy like the one the BER adopted soon after the permit was issued. In addition, the Northern Cheyenne Tribe claimed that the actions of the Montana DEQ violated the Montana State Constitution’s guarantee of a clean and healthful environment, that the Montana DEQ’s related environmental assessment was invalid, that the Montana DEQ was required, but failed, to prepare an EIS and that the Montana DEQ failed to consider other alternatives to the issuance of the permits. Fidelity, the NPRC, and the TRWUA were granted leave to intervene in this proceeding. In January 2009, the Montana Twenty-Second Judicial District Court decided the case in favor of Fidelity and the Montana DEQ in all respects, denying the motions of the Northern Cheyenne Tribe, TRWUA, and NPRC, and granting the cross-motions of the Montana DEQ and Fidelity in their entirety. As a result, Fidelity continued to utilize its direct discharge and treatment permits. The NPRC, the TRWUA and the Northern Cheyenne Tribe appealed the decision to the Montana Supreme Court in March 2009. On May 18, 2010, the Montana Supreme Court reversed the Montana Twenty-Second Judicial District Court’s decision and held that the Montana DEQ violated the Clean Water Act and the Montana Water Quality Act by issuing discharge permits to Fidelity without imposing predischarge treatment standards. The Montana Supreme Court declared Fidelity’s permits void and directed the Montana DEQ to reevaluate Fidelity’s permit applications under the appropriate predischarge treatment standards within 90 days of the Court’s decision, during which time Fidelity may continue to operate under its current permits. On June 2, 2010, Fidelity filed a motion with the Montana Supreme Court requesting the court to allow the Montana DEQ an additional 90 days to complete its reevaluation of Fidelity’s discharge permits. On June 29, 2010, the Montana Supreme Court granted a one-time extension allowing the Montana DEQ until November 14, 2010, to complete the permitting process.
|
|
Fidelity’s discharge of water pursuant to its two permits is its primary means for managing CBNG-produced water. Fidelity will not be able to assess the impact to its operations until the Montana DEQ issues final permits.
|
|
In October 2003, Tongue & Yellowstone Irrigation District, NPRC and MEIC filed a lawsuit in Montana First Judicial District Court challenging the MBOGC’s ROD adopting the 2003 Final EIS which analyzed CBNG development in Montana. The primary legal issue before the court was whether the ROD authorized the “wasting” of ground water in violation of the Montana State Constitution and the public trust doctrine. Specifically, the plaintiffs contended that various water management tools, including Fidelity’s direct discharge permits, allowed for the waste of water. On March 5, 2010, the Montana First Judicial District Court issued an order holding that Fidelity’s direct discharge permits did not violate the Montana State Constitution. Once judgment is entered, the parties will have 60 days to appeal to the Montana Supreme Court. Should the Montana Supreme Court determine the permits violate the Montana State Constitution, Fidelity’s Montana CBNG operations could be significantly and adversely affected.
|
|
Fidelity will continue to vigorously defend its interests in all CBNG-related litigation in which it is involved. If the plaintiffs are successful in these lawsuits, the ultimate outcome of the actions could adversely impact Fidelity’s existing CBNG operations and/or the future development of this resource in the affected regions.
|
|
Electric Operations In June 2008, the Sierra Club filed a complaint in the South Dakota Federal District Court against Montana-Dakota and the two other co-owners of the Big Stone Station. The complaint alleged certain violations of the PSD and NSPS provisions of the Clean Air Act and certain violation of the South Dakota SIP. The action further alleged that the Big Stone Station was modified and operated without obtaining the appropriate permits, without meeting certain emissions limits and NSPS requirements and without installing appropriate emission control technology, all allegedly in violation of the Clean Air Act and the South Dakota SIP. The Sierra Club alleged that these actions contributed to air pollution and visibility impairment and have increased the risk of adverse health effects and environmental damage. The Sierra Club sought declaratory and injunctive relief to bring the co-owners of the Big Stone Station into compliance with the Clean Air Act and the South Dakota SIP and to require them to remedy the alleged violations. The Sierra Club also sought unspecified civil penalties, including a beneficial mitigation project. The Company believes the claims are without merit and that Big Stone Station has been and is being operated in compliance with the Clean Air Act and the South Dakota SIP. In March 2009, the District Court granted the motion of the co-owners to dismiss the complaint. The Sierra Club filed a motion requesting the District Court to reconsider its ruling on a portion of the order dismissing the complaint which was denied on July 22, 2009. On July 30, 2009, the Sierra Club appealed from the orders dismissing the case and denying the motion for reconsideration to the United States Court of Appeals for the Eighth Circuit. The United States has filed a brief as amicus curiae supporting the Sierra Club’s position in the appeal and the State of South Dakota filed a brief as amicus curiae supporting the Big Stone Station owners’ position in the appeal. Oral argument on the appeal was held on May 11, 2010.
|
|
Construction Materials LTM is a defendant in litigation pending in Oregon Circuit Court regarding the concrete floors in an industrial food processing facility located in Jackson County, Oregon. The plaintiffs assert claims against LTM, which supplied the concrete for the floors, and others that the concrete floors of the facility are defective and must be removed and replaced for suitable repair. Damages, including disruption of the food processing operations, have been estimated by the plaintiffs to be approximately $26.5 million. Discovery is currently being conducted by the parties. A trial date has been scheduled for April 5, 2011.
|
|
The Company also is involved in other legal actions in the ordinary course of its business. Although the outcomes of any such legal actions cannot be predicted, management believes that the outcomes with respect to these other legal proceedings will not have a material adverse effect upon the Company’s financial position or results of operations.
|
|
Environmental matters
|
|
Portland Harbor Site In December 2000, MBI was named by the EPA as a PRP in connection with the cleanup of a riverbed site adjacent to a commercial property site acquired by MBI from Georgia-Pacific West, Inc. in 1999. The riverbed site is part of the Portland, Oregon, Harbor Superfund Site. The EPA wants responsible parties to share in the cleanup of sediment contamination in the Willamette River. To date, costs of the overall remedial investigation and feasibility study of the harbor site are being recorded, and initially paid, through an administrative consent order by the LWG, a group of several entities, which does not include MBI or Georgia-Pacific West, Inc. Investigative costs are indicated to be in excess of $70 million. It is not possible to estimate the cost of a corrective action plan until the remedial investigation and feasibility study have been completed, the EPA has decided on a strategy and a ROD has been published. Corrective action will be taken after the development of a proposed plan and ROD on the harbor site is issued. MBI also received notice in January 2008 that the Portland Harbor Natural Resource Trustee Council intends to perform an injury assessment to natural resources resulting from the release of hazardous substances at the Harbor Superfund Site. The Trustee Council indicates the injury determination is appropriate to facilitate early settlement of damages and restoration for natural resource injuries. It is not possible to estimate the costs of natural resource damages until an assessment is completed and allocations are undertaken.
|
|
Based upon a review of the Portland Harbor sediment contamination evaluation by the Oregon DEQ and other information available, MBI does not believe it is a Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc., that it intends to seek indemnity for liabilities incurred in relation to the above matters pursuant to the terms of their sale agreement. MBI has entered into an agreement tolling the statute of limitations in connection with the LWG’s potential claim for contribution to the costs of the remedial investigation and feasibility study. By letter in March 2009, LWG stated its intent to file suit against MBI and others to recover LWG’s investigation costs to the extent MBI cannot demonstrate its non-liability for the contamination or is unwilling to participate in an alternative dispute resolution process that has been established to address the matter. At this time, MBI has agreed to participate in the alternative dispute resolution process.
|
|
The Company believes it is not probable that it will incur any material environmental remediation costs or damages in relation to the above referenced administrative action.
|
|
Manufactured Gas Plant Sites There are three claims against Cascade for cleanup of environmental contamination at manufactured gas plant sites operated by Cascade’s predecessors.
|
|
The first claim is for soil and groundwater contamination at a site in Oregon and was received in 1995. There are PRPs in addition to Cascade that may be liable for cleanup of the contamination. Some of these PRPs have shared in the investigation costs. It is expected that these and other PRPs will share in the cleanup costs. Several alternatives for cleanup have been identified, with preliminary cost estimates ranging from approximately $500,000 to $11.0 million. An ecological risk assessment draft report was submitted to the Oregon DEQ in June 2009. The assessment showed no unacceptable risk to the aquatic ecological receptors present in the shoreline along the site and concluded that no further ecological investigation is necessary. The report is being reviewed by the Oregon DEQ. It is anticipated the Oregon DEQ will recommend a cleanup alternative for the site after it completes its review of the report. It is not known at this time what share of the cleanup costs will actually be borne by Cascade.
|
|
The second claim is for contamination at a site in Washington and was received in 1997. A preliminary investigation has found soil and groundwater at the site contain contaminants requiring further investigation and cleanup. EPA conducted a Targeted Brownfields Assessment of the site and released a report summarizing the results of that assessment in August 2009. The assessment confirms that contaminants have affected soil and groundwater at the site, as well as sediments in the adjacent Port Washington Narrows. Alternative remediation options have been identified with preliminary cost estimates ranging from $340,000 to $6.4 million. Data developed through the assessment and previous investigations indicates the contamination likely derived from multiple, different sources and multiple current and former owners of properties and businesses in the vicinity of the site may be responsible for the contamination. Cascade received notice in April 2010, that the Washington Department of Ecology has determined that Cascade is a PRP for release of hazardous substances at the site. Cascade has reserved $6.4 million for remediation of this site. On April 9, 2010, Cascade filed a petition with the WUTC for authority to defer the costs, which are included in other noncurrent assets, incurred in relation to the environmental remediation of this site until the next general rate case.
|
|
The third claim is also for contamination at a site in Washington. Cascade received notice from a party in May 2008 that Cascade may be a PRP, along with other parties, for contamination from a manufactured gas plant owned by Cascade and its predecessor from about 1946 to 1962. The notice indicates that current estimates to complete investigation and cleanup of the site exceed $8.0 million. Other PRPs have reached an agreed order with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim.
|
|
To the extent these claims are not covered by insurance, Cascade will seek recovery through the OPUC and WUTC of remediation costs in its natural gas rates charged to customers.
|
|
Guarantees
|
|
In connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent of any losses that Petrobras may incur from certain contingent liabilities specified in the purchase agreement. Centennial has agreed to unconditionally guarantee payment of the indemnity obligations to Petrobras for periods ranging up to five and a half years from the date of sale. The guarantee was required by Petrobras as a condition to closing the sale of MPX.
|
|
Centennial guaranteed CEM's obligations under a construction contract with LPP for a 550-MW combined-cycle electric generating facility near Hobbs, New Mexico. Centennial Resources sold CEM in July 2007 to Bicent Power LLC, which provided a $10 million bank letter of credit to Centennial in support of the guarantee obligation. In February 2009, Centennial received a Notice and Demand from LPP under the guaranty agreement alleging that CEM did not meet certain of its obligations under the construction contract and demanding that Centennial indemnify LPP against all losses, damages, claims, costs, charges and expenses arising from CEM’s alleged failures. In December 2009, LPP submitted a demand for arbitration of its dispute with CEM to the American Arbitration Association. The demand seeks compensatory damages of $146 million plus damages for increased operating, capital and construction costs related to a water treatment facility for the generating facility. LPP’s notice of demand for arbitration also demanded performance of the guarantee by Centennial. In June 2010, CEM and Bicent Power, LLC made a demand on Centennial for indemnification under the 2007 purchase and sale agreement for indemnifiable losses, including defense fees and costs of more than $1.5 million, arising from LPP’s arbitration demand and related to Centennial’s ownership of CEM prior to its sale from Centennial to Bicent Power, LLC. The Company believes the indemnification claims against Centennial are without merit and intends to vigorously defend against such claims.
|
|
In connection with the pending sale of the Brazilian Transmission Lines, as discussed in Note 11, Centennial has agreed to unconditionally guarantee payment of any indemnity obligations of certain of the Company’s indirect wholly owned subsidiaries who are the sellers in three purchase and sale agreements for periods ranging up to 10 years from the date of sale. The guarantees were required by the buyers as a condition to the pending sale of the Brazilian Transmission Lines.
|
|
In addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil swap and collar agreement obligations. There is no fixed maximum amount guaranteed in relation to the natural gas and oil swap and collar agreements as the amount of the obligation is dependent upon natural gas and oil commodity prices. The amount of hedging activity entered into by the subsidiary is limited by corporate policy. The guarantees of the natural gas and oil swap and collar agreements at June 30, 2010, expire in the years ranging from 2010 to 2011; however, Fidelity continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. There were no amounts outstanding by Fidelity at June 30, 2010. In the event Fidelity defaults under its obligations, WBI Holdings would be required to make payments under its guarantees.
|
|
Certain subsidiaries of the Company have outstanding guarantees to third parties that guarantee the performance of other subsidiaries of the Company. These guarantees are related to construction contracts, natural gas transportation and sales agreements, gathering contracts, a conditional purchase agreement and certain other guarantees. At June 30, 2010, the fixed maximum amounts guaranteed under these agreements aggregated $224.5 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $4.3 million in 2010; $191.8 million in 2011; $18.7 million in 2012; $1.2 million in 2013; $200,000 in 2014; $900,000 in 2018; $300,000 in 2019; $3.1 million, which is subject to expiration on a specified number of days after the receipt of written notice; and $4.0 million, which has no scheduled maturity date. The amount outstanding by subsidiaries of the Company under the above guarantees was $500,000 and was reflected on the Consolidated Balance Sheet at June 30, 2010. In the event of default under these guarantee obligations, the subsidiary issuing the guarantee for that particular obligation would be required to make payments under its guarantee.
|
|
Certain subsidiaries have outstanding letters of credit to third parties related to insurance policies, natural gas transportation agreements and other agreements that guarantee the performance of other subsidiaries of the Company. At June 30, 2010, the fixed maximum amounts guaranteed under these letters of credit, aggregated $29.1 million. In 2010 and 2011, $22.2 million and $6.9 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at June 30, 2010.
|
|
WBI Holdings has an outstanding guarantee to Williston Basin. This guarantee is related to a natural gas transportation and storage agreement that guarantees the performance of Prairielands. At June 30, 2010, the fixed maximum amount guaranteed under this agreement aggregated $5.0 million and is scheduled to expire in 2011. In the event of Prairielands’ default in its payment obligations, WBI Holdings would be required to make payment under its guarantee. The amount outstanding by Prairielands under the above guarantee was $1.4 million. The amount outstanding under this guarantee was not reflected on the Consolidated Balance Sheet at June 30, 2010, because this intercompany transaction was eliminated in consolidation.
|
|
In addition, Centennial and Knife River have issued guarantees to third parties related to the Company’s routine purchase of maintenance items, materials and lease obligations for which no fixed maximum amounts have been specified. These guarantees have no scheduled maturity date. In the event a subsidiary of the Company defaults under its obligation in relation to the purchase of certain maintenance items, materials or lease obligations, Centennial or Knife River would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these maintenance items and materials were reflected on the Consolidated Balance Sheet at June 30, 2010.
|
|
In the normal course of business, Centennial has purchased surety bonds related to construction contracts and reclamation obligations of its subsidiaries. In the event a subsidiary of Centennial does not fulfill a bonded obligation, Centennial would be responsible to the surety bond company for completion of the bonded contract or obligation. A large portion of the surety bonds is expected to expire within the next 12 months; however, Centennial will likely continue to enter into surety bonds for its subsidiaries in the future. As of June 30, 2010, approximately $646 million of surety bonds were outstanding, which were not reflected on the Consolidated Balance Sheet.
|
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
·
|
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
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Electric
|
$ | 5.0 | $ | 3.2 | $ | 10.8 | $ | 8.3 | ||||||||
Natural gas distribution
|
.1 | (4.8 | ) | 23.4 | 19.1 | |||||||||||
Construction services
|
2.9 | 6.9 | 3.1 | 15.6 | ||||||||||||
Pipeline and energy services
|
9.5 | 10.9 | 18.3 | 17.3 | ||||||||||||
Natural gas and oil production
|
24.0 | 20.8 | 46.3 | (352.5 | ) | |||||||||||
Construction materials and contracting
|
5.7 | 16.0 | (14.5 | ) | .3 | |||||||||||
Other
|
1.6 | 2.1 | 3.0 | 3.1 | ||||||||||||
Earnings (loss) on common stock
|
$ | 48.8 | $ | 55.1 | $ | 90.4 | $ | (288.8 | ) | |||||||
Earnings (loss) per common share – basic
|
$ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | |||||||
Earnings (loss) per common share – diluted
|
$ | .26 | $ | .30 | $ | .48 | $ | (1.57 | ) | |||||||
Return on average common equity for the 12 months ended
|
10.0 | % | (6.9 | )% |
·
|
Lower aggregate, ready-mixed concrete and liquid asphalt oil volumes and margins, as well as decreased construction and asphalt margins, partially offset by lower depreciation, depletion and amortization expense at the construction materials and contracting business
|
·
|
Lower construction workloads and margins, partially offset by lower general and administrative expense at the construction services business
|
·
|
Increased retail sales and transportation volumes, lower operation and maintenance expense, as well as higher nonregulated energy-related services at the natural gas distribution business
|
·
|
Higher average realized oil prices, increased oil production, lower general and administrative and lease operating expenses, partially offset by lower average realized gas prices, decreased natural gas production, higher production taxes, as well as higher depreciation, depletion and amortization expense at the natural gas and oil 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, lower depreciation, depletion and amortization expense, lower lease operating expenses, increased oil production, as well as lower general and administrative expense, partially offset by decreased natural gas production, lower average realized natural gas prices and higher production taxes at the natural gas and oil production business
|
·
|
Lower operation and maintenance expense, lower interest expense and higher other income at the natural gas distribution business
|
·
|
Lower aggregate, ready-mixed concrete and liquid asphalt oil volumes and margins, as well as decreased construction and asphalt margins, partially offset by lower depreciation, depletion and amortization expense and lower selling, general and administrative expense at the construction materials and contracting business
|
·
|
Lower construction workloads and margins, partially offset by lower general and administrative expense at the construction services business
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Operating revenues
|
$ | 45.7 | $ | 44.5 | $ | 95.4 | $ | 95.8 | ||||||||
Operating expenses:
|
||||||||||||||||
Fuel and purchased power
|
13.1 | 15.2 | 30.0 | 33.9 | ||||||||||||
Operation and maintenance
|
16.2 | 15.9 | 31.4 | 31.5 | ||||||||||||
Depreciation, depletion and amortization
|
6.1 | 6.0 | 11.9 | 12.2 | ||||||||||||
Taxes, other than income
|
2.2 | 2.3 | 4.8 | 4.7 | ||||||||||||
37.6 | 39.4 | 78.1 | 82.3 | |||||||||||||
Operating income
|
8.1 | 5.1 | 17.3 | 13.5 | ||||||||||||
Earnings
|
$ | 5.0 | $ | 3.2 | $ | 10.8 | $ | 8.3 | ||||||||
Retail sales (million kWh)
|
615.2 | 595.3 | 1,365.0 | 1,320.1 | ||||||||||||
Sales for resale (million kWh)
|
7.6 | 22.8 | 37.4 | 32.5 | ||||||||||||
Average cost of fuel and purchased power per kWh
|
$ | .020 | $ | .023 | $ | .020 | $ | .024 |
·
|
Higher electric retail sales margins, primarily due to the implementation of higher rates in Wyoming
|
·
|
Higher retail sales volumes of 3 percent, primarily to commercial and residential customers
|
·
|
Increased retail sales margins and volumes of $2.1 million (after tax), as previously discussed
|
·
|
Higher other income of $900,000 (after tax), primarily allowance for funds used during construction related to electric generation projects
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Operating revenues
|
$ | 160.1 | $ | 164.1 | $ | 509.2 | $ | 647.3 | ||||||||
Operating expenses:
|
||||||||||||||||
Purchased natural gas sold
|
98.9 | 107.5 | 344.1 | 473.5 | ||||||||||||
Operation and maintenance
|
34.4 | 35.5 | 67.1 | 73.6 | ||||||||||||
Depreciation, depletion and amortization
|
10.7 | 10.6 | 21.4 | 21.3 | ||||||||||||
Taxes, other than income
|
10.5 | 11.3 | 27.0 | 34.2 | ||||||||||||
154.5 | 164.9 | 459.6 | 602.6 | |||||||||||||
Operating income (loss)
|
5.6 | (.8 | ) | 49.6 | 44.7 | |||||||||||
Earnings (loss)
|
$ | .1 | $ | (4.8 | ) | $ | 23.4 | $ | 19.1 | |||||||
Volumes (MMdk):
|
||||||||||||||||
Sales
|
15.6 | 14.1 | 53.7 | 57.7 | ||||||||||||
Transportation
|
28.9 | 23.4 | 63.4 | 57.4 | ||||||||||||
Total throughput
|
44.5 | 37.5 | 117.1 | 115.1 | ||||||||||||
Degree days (% of normal)*
|
||||||||||||||||
Montana-Dakota
|
96 | % | 119 | % | 98 | % | 106 | % | ||||||||
Cascade
|
118 | % | 100 | % | 95 | % | 105 | % | ||||||||
Intermountain
|
132 | % | 103 | % | 103 | % | 105 | % | ||||||||
Average cost of natural gas, including transportation, per dk
|
$ | 6.33 | $ | 7.61 | $ | 6.41 | $ | 8.20 | ||||||||
*Degree days are a measure of the daily temperature-related demand for energy for heating.
|
·
|
Increased retail sales volumes, largely resulting from colder weather than last year in the Northwest
|
·
|
Lower operation and maintenance expense, largely lower bad debt expense and benefit-related costs
|
·
|
Increased transportation volumes of $500,000 (after tax), primarily industrial customers
|
·
|
Higher nonregulated energy-related services of $400,000 (after tax)
|
·
|
Lower operation and maintenance expense of $3.2 million (after tax), largely lower payroll and benefit-related costs and bad debt expense
|
·
|
Lower interest expense, primarily due to lower average borrowings and higher capitalized interest
|
·
|
Higher other income of $600,000 (after tax), primarily allowance for funds used during construction
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions)
|
||||||||||||||||
Operating revenues
|
$ | 188.2 | $ | 220.7 | $ | 341.3 | $ | 465.5 | ||||||||
Operating expenses:
|
||||||||||||||||
Operation and maintenance
|
173.2 | 199.2 | 315.0 | 416.4 | ||||||||||||
Depreciation, depletion and amortization
|
3.1 | 3.3 | 6.3 | 6.7 | ||||||||||||
Taxes, other than income
|
6.1 | 6.4 | 12.6 | 16.0 | ||||||||||||
182.4 | 208.9 | 333.9 | 439.1 | |||||||||||||
Operating income
|
5.8 | 11.8 | 7.4 | 26.4 | ||||||||||||
Earnings
|
$ | 2.9 | $ | 6.9 | $ | 3.1 | $ | 15.6 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Dollars in millions)
|
||||||||||||||||
Operating revenues
|
$ | 80.5 | $ | 68.0 | $ | 169.1 | $ | 153.1 | ||||||||
Operating expenses:
|
||||||||||||||||
Purchased natural gas sold
|
35.3 | 28.1 | 82.8 | 74.2 | ||||||||||||
Operation and maintenance
|
17.8 | 11.1 | 33.0 | 28.8 | ||||||||||||
Depreciation, depletion and amortization
|
6.5 | 6.2 | 12.9 | 12.3 | ||||||||||||
Taxes, other than income
|
3.2 | 3.0 | 6.2 | 5.9 | ||||||||||||
62.8 | 48.4 | 134.9 | 121.2 | |||||||||||||
Operating income
|
17.7 | 19.6 | 34.2 | 31.9 | ||||||||||||
Earnings
|
$ | 9.5 | $ | 10.9 | $ | 18.3 | $ | 17.3 | ||||||||
Transportation volumes (MMdk):
|
||||||||||||||||
Montana-Dakota
|
7.3 | 10.2 | 14.9 | 18.5 | ||||||||||||
Other
|
37.0 | 33.6 | 59.9 | 62.4 | ||||||||||||
44.3 | 43.8 | 74.8 | 80.9 | |||||||||||||
Gathering volumes (MMdk)
|
19.3 | 24.3 | 38.4 | 48.6 |
·
|
Higher operation and maintenance expense of $3.1 million (after tax), primarily due to the absence of the settlement of the natural gas storage litigation, which lowered expense in the second quarter last year
|
·
|
Lower gathering volumes of $1.2 million (after tax)
|
·
|
Lower gathering volumes of $2.7 million (after tax)
|
·
|
Higher operation and maintenance expense of $1.0 million (after tax), including higher payroll-related costs
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Operating revenues:
|
||||||||||||||||
Natural gas
|
$ | 55.2 | $ | 69.2 | $ | 112.8 | $ | 150.9 | ||||||||
Oil
|
55.6 | 35.6 | 105.6 | 60.0 | ||||||||||||
110.8 | 104.8 | 218.4 | 210.9 | |||||||||||||
Operating expenses:
|
||||||||||||||||
Operation and maintenance:
|
||||||||||||||||
Lease operating costs
|
16.3 | 18.0 | 32.1 | 38.0 | ||||||||||||
Gathering and transportation
|
5.9 | 6.1 | 11.8 | 12.2 | ||||||||||||
Other
|
8.8 | 10.7 | 17.4 | 21.0 | ||||||||||||
Depreciation, depletion and amortization
|
32.5 | 30.2 | 62.1 | 72.8 | ||||||||||||
Taxes, other than income:
|
||||||||||||||||
Production and property taxes
|
9.0 | 5.7 | 18.5 | 13.2 | ||||||||||||
Other
|
.1 | .2 | .5 | .4 | ||||||||||||
Write-down of natural gas and oil properties
|
— | — | — | 620.0 | ||||||||||||
72.6 | 70.9 | 142.4 | 777.6 | |||||||||||||
Operating income (loss)
|
38.2 | 33.9 | 76.0 | (566.7 | ) | |||||||||||
Earnings (loss)
|
$ | 24.0 | $ | 20.8 | $ | 46.3 | $ | (352.5 | ) | |||||||
Production:
|
||||||||||||||||
Natural gas (MMcf)
|
12,809 | 14,297 | 25,052 | 29,698 | ||||||||||||
Oil (MBbls)
|
831 | 771 | 1,592 | 1,513 | ||||||||||||
Total Production (MMcf equivalent)
|
17,794 | 18,923 | 34,602 | 38,775 | ||||||||||||
Average realized prices (including hedges):
|
||||||||||||||||
Natural gas (per Mcf)
|
$ | 4.31 | $ | 4.84 | $ | 4.50 | $ | 5.08 | ||||||||
Oil (per barrel)
|
$ | 66.88 | $ | 46.21 | $ | 66.36 | $ | 39.67 | ||||||||
Average realized prices (excluding hedges):
|
||||||||||||||||
Natural gas (per Mcf)
|
$ | 3.30 | $ | 2.40 | $ | 3.92 | $ | 3.04 | ||||||||
Oil (per barrel)
|
$ | 67.21 | $ | 47.46 | $ | 66.83 | $ | 40.30 | ||||||||
Average depreciation, depletion and amortization rate, per equivalent Mcf
|
$ | 1.74 | $ | 1.52 | $ | 1.71 | $ | 1.80 | ||||||||
Production costs, including taxes, per net equivalent Mcf:
|
||||||||||||||||
Lease operating costs
|
$ | .91 | $ | .95 | $ | .93 | $ | .98 | ||||||||
Gathering and transportation
|
.33 | .32 | .34 | .31 | ||||||||||||
Production and property taxes
|
.51 | .30 | .53 | .34 | ||||||||||||
$ | 1.75 | $ | 1.57 | $ | 1.80 | $ | 1.63 |
·
|
Higher average realized oil prices of 45 percent
|
·
|
Increased oil production of 8 percent, largely related to drilling activity in the Bakken area
|
·
|
Lower general and administrative expense of $1.3 million (after tax)
|
·
|
Decreased lease operating expenses of $1.1 million (after tax)
|
·
|
Lower average realized natural gas prices of 11 percent
|
·
|
Decreased natural gas production of 10 percent, largely related to normal production declines at existing properties, partially offset by production from the recently acquired Green River Basin properties
|
·
|
Higher production taxes of $1.9 million (after tax)
|
·
|
Higher depreciation, depletion and amortization expense of $1.4 million (after tax), due to higher depletion rates
|
·
|
Absence of the 2009 noncash write-down of natural gas and oil properties of $384.4 million (after tax), as discussed in Note 6
|
·
|
Higher average realized oil prices of 67 percent
|
·
|
Lower depreciation, depletion and amortization expense of $6.6 million (after tax), due to lower depletion rates and decreased combined production. The lower depletion rates are largely the result of the write-down of natural gas and oil properties in March 2009.
|
·
|
Decreased lease operating expenses of $3.7 million (after tax)
|
·
|
Increased oil production of 5 percent, largely related to drilling activity in the Bakken area
|
·
|
Lower general and administrative expense of $2.2 million (after tax)
|
·
|
Decreased natural gas production of 16 percent, largely related to normal production declines, as previously discussed
|
·
|
Lower average realized natural gas prices of 11 percent
|
·
|
Higher production taxes of $3.4 million (after tax)
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(Dollars in millions)
|
||||||||||||||||
Operating revenues
|
$ | 361.6 | $ | 389.4 | $ | 511.4 | $ | 572.9 | ||||||||
Operating expenses:
|
||||||||||||||||
Operation and maintenance
|
316.9 | 325.7 | 462.9 | 498.0 | ||||||||||||
Depreciation, depletion and amortization
|
22.2 | 23.8 | 44.8 | 47.8 | ||||||||||||
Taxes, other than income
|
9.2 | 9.8 | 16.5 | 17.3 | ||||||||||||
348.3 | 359.3 | 524.2 | 563.1 | |||||||||||||
Operating income (loss)
|
13.3 | 30.1 | (12.8 | ) | 9.8 | |||||||||||
Earnings (loss)
|
$ | 5.7 | $ | 16.0 | $ | (14.5 | ) | $ | .3 | |||||||
Sales (000's):
|
||||||||||||||||
Aggregates (tons)
|
6,261 | 6,486 | 9,224 | 9,671 | ||||||||||||
Asphalt (tons)
|
1,579 | 1,530 | 1,733 | 1,718 | ||||||||||||
Ready-mixed concrete (cubic yards)
|
742 | 792 | 1,218 | 1,301 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||||||
(In millions)
|
||||||||||||||||
Other:
|
||||||||||||||||
Operating revenues
|
$ | 2.3 | $ | 2.7 | $ | 4.5 | $ | 5.4 | ||||||||
Operation and maintenance
|
1.8 | 1.9 | 3.7 | 5.2 | ||||||||||||
Depreciation, depletion and amortization
|
.4 | .3 | .8 | .6 | ||||||||||||
Taxes, other than income
|
.1 | .1 | .1 | .1 | ||||||||||||
Intersegment transactions:
|
||||||||||||||||
Operating revenues
|
$ | 42.8 | $ | 36.2 | $ | 108.1 | $ | 98.9 | ||||||||
Purchased natural gas sold
|
36.8 | 29.2 | 95.8 | 84.8 | ||||||||||||
Operation and maintenance
|
6.0 | 7.0 | 12.3 | 14.1 |
·
|
Earnings per common share for 2010, diluted, are projected in the range of $1.10 to $1.35. The Company expects the percentage of 2010 earnings per common share by quarter to be in the following approximate ranges:
|
o
|
Third quarter – 30 percent to 35 percent
|
o
|
Fourth quarter – 20 percent to 25 percent
|
·
|
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 Company continues to realize efficiencies and enhanced service levels through its efforts to standardize operations, share services and consolidate back-office functions among its four utility companies.
|
·
|
The Company has a 25 MW ownership interest in Wygen III, which commenced commercial operation on April 1, 2010. The WYPSC approved an increase, primarily related to the costs of Wygen III, in the amount of $2.7 million annually, or 13.1 percent, effective May 1, 2010.
|
·
|
In April 2010, the Company filed an application with the NDPSC for an electric rate increase, as discussed in Note 18.
|
·
|
The Company plans to file an application with the MTPSC for an electric rate increase in the third quarter of 2010. The request will include an increase related to the investment in infrastructure upgrades, recovery of the investment in renewable generation and the costs associated with the Big Stone Station II.
|
·
|
The Company is developing a landfill methane gas recovery project in Billings, Montana to supplement the Company’s gas supply portfolio. The project is expected to begin production in the fourth quarter of 2010, and upon total phase-in to recover up to 2,500 dk per day.
|
·
|
The Company is analyzing potential projects for accommodating load growth and replacing purchased power contracts with company-owned generation. The Company is reviewing the construction of natural gas-fired combustion and wind generation.
|
·
|
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 metropolitan areas. The Company has signed 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 being built by enXco for Xcel Energy. The $25 million project also will include substation upgrades. Pending regulatory approval, construction is expected to begin in 2011. Customers will not bear any of the costs associated with the project as costs will be recovered through an approved interconnect tariff.
|
·
|
In June 2010, the Company placed into service a 10.5 MW expansion of its Diamond Willow wind farm in Montana, and the new 19.5 MW Cedar Hills wind farm in southwest North Dakota.
|
·
|
Work backlog as of June 30, 2010, was approximately $389 million, compared to $507 million at June 30, 2009, which included backlog related to the Fontainebleau project of $182 million. The Fontainebleau project was removed from backlog in the third quarter of 2009 after Fontainebleau’s bankruptcy filing. Absent the Fontainebleau-related backlog, levels are $64 million higher than one year ago. Backlog at March 31, 2010, was $400 million.
|
·
|
Examples of new projects included in work backlog are solar projects in the Las Vegas area and substation related work.
|
·
|
The Company anticipates margins in 2010 to be lower than 2009 levels.
|
·
|
The Company is aggressively pursuing expansion in high voltage transmission and substation construction, renewable resource construction and military installation services. In late 2009, the Company was awarded the engineering, procurement and construction contract to build the 214-mile Montana Alberta Tie Line between Lethbridge, Alberta and Great Falls, Montana. In late June 2010, the Company received a notice to proceed with construction on the project.
|
·
|
The Company continues to focus on costs and efficiencies to enhance margins. Selling, general and administrative expenses are down 32 percent for the second quarter compared to one year ago.
|
·
|
With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure.
|
·
|
An incremental expansion to the Grasslands Pipeline of 75,000 Mcf per day went into service August 31, 2009. The firm capacity of the Grasslands Pipeline is at its ultimate full capacity of 213,000 Mcf per day.
|
·
|
The Company continues to pursue expansion of facilities and services offered to customers. Energy development within its geographic region, which includes portions of Colorado, Wyoming, Montana and North Dakota, is expanding, most notably the Bakken Shale of North Dakota and eastern Montana. Ongoing energy development is expected to have many direct and indirect benefits to its business.
|
·
|
The Company continues to pursue the expansion of its existing natural gas pipeline capacity by 30,000 Mcf per day in the Bakken production area in northwestern North Dakota. This expansion project is targeted for late 2011.
|
·
|
The Company continues to see strong interest in its storage services. It has three natural gas storage fields, including the largest storage field in North America located near Baker, Montana. The Company is pursuing a project to increase its firm deliverability from the Baker Storage field by 125,000 Mcf per day and related transportation capacity. The Company has received commitment on approximately 30 percent of the total potential project and is moving forward on that phase, subject to regulatory approval, with a projected in-service date of November 2011.
|
·
|
The Company expects to spend approximately $380 million in capital expenditures for 2010, approximately double the level of capital invested in 2009. This reflects further exploitation of existing properties, leasehold acquisitions in the Bakken and Niobrara oil shale plays and the acquisition of producing natural gas properties located in the Green River Basin. The capital expenditures forecasted reflect a shift from certain natural gas development activities to oil shale leasehold acquisitions, which will affect short-term production growth.
|
·
|
Earlier this year, the Company acquired exploratory acreage of approximately 40,000 net acres in the North Dakota Bakken area, bringing its total acreage position in this oil play to more than 56,000 net acres. For the 40,000 net acres held in Stark County, the Heart River project, plans include drilling three exploratory wells this year to evaluate the acreage targeting the Three Forks formation. Lease terms extend up to five years including renewal options available to the Company. A total of 60 potential drilling sites have been identified in this area based on 640-acre spacing.
|
·
|
The Company also acquired approximately 80,000 net exploratory acres in the emerging Niobrara oil play in Laramie and Goshen Counties in southeastern Wyoming. The Company plans to begin drilling exploratory wells in the area in 2011. Assuming 640-acre spacing, the Company has 120 potential drilling sites available on this acreage. Lease terms are generally five years with most having five-year renewal options available to the Company. Although this emerging play is still
|
·
|
The Company continues to pursue additional leasehold and reserve acquisitions which are not included in the current forecast.
|
·
|
Because of reduced capital spending in 2009 and the redirecting of forecasted 2010 capital expenditures, along with delays in obtaining well completion/frac services, primarily in Texas, the Company expects its 2010 combined natural gas and oil production to be approximately 3 percent to 6 percent below 2009 levels.
|
·
|
Earnings guidance reflects estimated natural gas prices for August through December as follows:
|
Index*
|
Price Per Mcf
|
Ventura
|
$4.25 to $4.75
|
NYMEX
|
$4.50 to $5.00
|
CIG
|
$4.00 to $4.50
|
* Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system.
|
·
|
Earnings guidance reflects estimated NYMEX crude oil prices for August through December in the range of $70 to $75 per barrel.
|
·
|
For the last six months of 2010, the Company has hedged approximately 50 percent to 55 percent of its estimated natural gas production and 40 percent to 45 percent of its estimated oil production. For 2011, the Company has hedged 15 percent to 20 percent of its estimated natural gas production and 30 percent to 35 percent of its estimated oil production. For 2012, the Company has hedged 5 percent to 10 percent of its estimated natural gas production. The hedges that are in place as of August 2, 2010, are summarized in the following chart:
|
Commodity
|
Type
|
Index
|
Period
Outstanding
|
Forward Notional Volume
(MMBtu/Bbl)
|
Price
(Per MMBtu/Bbl)
|
Natural Gas
|
Swap
|
HSC
|
7/10 - 12/10
|
809,600
|
$8.08
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 12/10
|
1,840,000
|
$6.18
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 12/10
|
920,000
|
$6.40
|
Natural Gas
|
Collar
|
NYMEX
|
7/10 - 12/10
|
920,000
|
$5.63-$6.00
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 12/10
|
920,000
|
$5.855
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 12/10
|
920,000
|
$6.045
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 12/10
|
920,000
|
$6.045
|
Natural Gas
|
Swap
|
CIG
|
7/10 - 12/10
|
1,840,000
|
$5.03
|
Natural Gas
|
Swap
|
HSC
|
7/10 - 10/10
|
246,000
|
$5.57
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 10/10
|
984,000
|
$5.645
|
Natural Gas
|
Swap
|
Ventura
|
7/10 - 12/10
|
920,000
|
$5.95
|
Natural Gas
|
Swap
|
NYMEX
|
7/10 - 12/10
|
2,024,000
|
$5.54
|
Natural Gas
|
Collar
|
NYMEX
|
7/10 - 3/11
|
1,370,000
|
$5.62-$6.50
|
Natural Gas
|
Swap
|
HSC
|
1/11 - 12/11
|
1,350,500
|
$8.00
|
Natural Gas
|
Swap
|
NYMEX
|
1/11 - 12/11
|
4,015,000
|
$6.1027
|
Natural Gas
|
Swap
|
NYMEX
|
1/11 - 12/11
|
3,650,000
|
$5.4975
|
Natural Gas
|
Swap
|
NYMEX
|
1/12 - 12/12
|
3,477,000
|
$6.27
|
Crude Oil
|
Collar
|
NYMEX
|
7/10 - 12/10
|
184,000
|
$60.00-$75.00
|
Crude Oil
|
Swap
|
NYMEX
|
7/10 - 12/10
|
184,000
|
$73.20
|
Crude Oil
|
Collar
|
NYMEX
|
7/10 - 12/10
|
184,000
|
$70.00-$86.00
|
Crude Oil
|
Swap
|
NYMEX
|
7/10 - 12/10
|
184,000
|
$83.05
|
Crude Oil
|
Collar
|
NYMEX
|
1/11 - 12/11
|
547,500
|
$80.00-$94.00
|
Crude Oil
|
Collar
|
NYMEX
|
1/11 - 12/11
|
365,000
|
$80.00-$89.00
|
Crude Oil
|
Collar
|
NYMEX
|
1/11 - 12/11
|
182,500
|
$77.00-$86.45
|
Crude Oil
|
Collar
|
NYMEX
|
1/11 - 12/11
|
182,500
|
$75.00-$88.00
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/10 - 12/10
|
1,840,000
|
$0.25
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/10 - 12/10
|
460,000
|
$0.245
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/10 - 12/10
|
2,300,000
|
$0.25
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/10 - 12/10
|
920,000
|
$0.225
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/10 - 12/10
|
460,000
|
$0.23
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/10 - 12/10
|
1,380,000
|
$0.23
|
Natural Gas
|
Basis Swap
|
CIG
|
7/10 - 12/10
|
2,024,000
|
$0.385
|
Natural Gas
|
Basis Swap
|
Ventura
|
1/11 - 3/11
|
450,000
|
$0.135
|
Natural Gas
|
Basis Swap
|
CIG
|
1/11 - 12/11
|
4,015,000
|
$0.395
|
Natural Gas
|
Basis Swap
|
CIG
|
1/12 - 12/12
|
2,745,000
|
$0.405
|
Natural Gas
|
Basis Swap
|
CIG
|
1/12 - 12/12
|
732,000
|
$0.41
|
Notes:
· Ventura is an index pricing point related to Northern Natural Gas Co.’s system; CIG is an index pricing point related to Colorado Interstate Gas Co.’s system; HSC is the Houston Ship Channel hub in southeast Texas which connects to several pipelines.
· For all basis swaps, Index prices are below NYMEX prices and are reported as a positive amount in the Price column.
|
·
|
Work backlog as of June 30, 2010, was approximately $677 million, $109 million higher than the March 31, 2010, backlog of $568 million. Backlog a year ago was $707 million. Private project backlog has decreased, however public work has increased over prior year levels.
|
·
|
Examples of new large projects included in work backlog are several highway paving projects, a reclamation project, and an L.A. harbor deepening project.
|
·
|
All of the markets served by the construction materials segment are seeing positive impacts related to the federal stimulus spending and the Company is well positioned to take advantage of this funding in the asphalt paving and liquid asphalt oil product lines. Federal transportation stimulus of $7.9 billion was directed to states where the Company operates. Of that amount, 41 percent was spent as of late July 2010, with the remaining $4.7 billion to be spent during the remainder of 2010 and 2011.
|
·
|
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.
|
·
|
The Company has a strong emphasis on operational efficiencies and cost reduction. Selling, general and administrative expenses are down 35 percent for the trailing 12 months through June 30, 2010, compared to the annual expenses in 2006, the peak earnings year for this segment.
|
·
|
The Company expects volumes and margins to be lower in 2010 compared to 2009 as a result of the economic downturn. Liquid asphalt volumes were at record levels in 2009.
|
·
|
The Company has planned green field expansions for the liquid asphalt oil business this year.
|
·
|
As the country’s 6th 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.
|
·
|
Of the five labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2009 Annual Report, four have been ratified. The one remaining contract is still in negotiations.
|
·
|
The acquisition of producing natural gas properties located in the Green River Basin in southwest Wyoming
|
·
|
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 and leasehold acquisitions at the natural gas and oil production segment
|
·
|
Power generation opportunities, including certain costs for additional electric generating capacity
|
·
|
Other growth opportunities
|
Company
|
Facility
|
Facility
Limit
|
Amount
Outstanding
|
Letters
of Credit
|
Expiration
Date
|
||||||||||||||
(Dollars in millions)
|
|||||||||||||||||||
MDU Resources Group, Inc.
|
Commercial paper/Revolving credit agreement
|
(a)
|
$ | 125.0 | $ | — |
(b)
|
$ | — |
6/21/11
|
|||||||||
MDU Energy Capital, LLC
|
Master shelf agreement
|
$ | 175.0 | $ | 165.0 | $ | — |
8/14/10
|
(c)(d)
|
||||||||||
Cascade Natural Gas Corporation
|
Revolving credit agreement
|
$ | 50.0 |
(e)
|
$ | — | $ | 1.9 |
(f)
|
12/28/12
|
(g)
|
||||||||
Intermountain Gas Company
|
Revolving credit agreement
|
$ | 65.0 |
(h)
|
$ | 3.7 | $ | — |
8/31/10
|
(i)
|
|||||||||
Centennial Energy Holdings, Inc.
|
Commercial paper/Revolving credit agreement
|
(j)
|
$ | 400.0 | $ | 83.0 |
(b)
|
$ | 25.8 |
(f)
|
12/13/12
|
||||||||
Williston Basin Interstate Pipeline Company
|
Uncommitted long-term private shelf agreement
|
$ | 125.0 | $ | 87.5 | $ | — |
12/23/11
|
(c)
|
(a)
|
The $125 million commercial paper program is supported by a revolving credit agreement with various banks totaling $125 million (provisions allow for increased borrowings, at the option of the Company on stated conditions, up to a maximum of $150 million). There were no amounts outstanding under the credit agreement.
|
(b)
|
Amount outstanding under commercial paper program.
|
(c)
|
Represents expiration of the ability to borrow additional funds under the agreement.
|
(d)
|
Or such time as the agreement is terminated by either of the parties thereto.
|
(e)
|
Certain provisions allow for increased borrowings, up to a maximum of $75 million.
|
(f)
|
The outstanding letters of credit, as discussed in Note 19, reduce amounts available under the credit agreement.
|
(g)
|
Provisions allow for an extension of up to two years upon consent of the banks.
|
(h)
|
Certain provisions allow for increased borrowings, up to a maximum of $70 million.
|
(i)
|
Intermountain plans to negotiate the extension or replacement of this agreement prior to its expiration.
|
(j)
|
The $400 million commercial paper program is supported by a revolving credit agreement with various banks totaling $400 million (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $450 million). There were no amounts outstanding under the credit agreement.
|
(Forward notional volume and fair value in thousands)
|
||||||||||||
Weighted
Average
Fixed
Price (Per MMBtu/Bbl)
|
Forward
Notional
Volume
(MMBtu/Bbl)
|
Fair Value
|
||||||||||
Fidelity
|
||||||||||||
Natural gas swap agreements maturing in 2010
|
$ | 5.93 | 12,344 | $ | 15,252 | |||||||
Natural gas swap agreements maturing in 2011
|
$ | 6.14 | 9,016 | $ | 7,372 | |||||||
Natural gas swap agreement maturing in 2012
|
$ | 6.27 | 3,477 | $ | 2,008 | |||||||
Natural gas basis swap agreements maturing in 2010
|
$ | .27 | 9,384 | $ | 162 | |||||||
Natural gas basis swap agreements maturing in 2011
|
$ | .37 | 4,465 | $ | 328 | |||||||
Natural gas basis swap agreements maturing in 2012
|
$ | .41 | 3,477 | $ | 285 | |||||||
Oil swap agreements maturing in 2010
|
$ | 78.13 | 368 | $ | 437 | |||||||
Cascade
|
||||||||||||
Natural gas swap agreements maturing in 2010
|
$ | 8.02 | 2,425 | $ | (9,382 | ) | ||||||
Natural gas swap agreements maturing in 2011
|
$ | 8.10 | 2,270 | $ | (7,601 | ) | ||||||
Intermountain
|
||||||||||||
Natural gas swap agreement maturing in 2010
|
$ | 4.96 | 1,661 | $ | (1,485 | ) | ||||||
Natural gas swap agreement maturing in 2011
|
$ | 4.96 | 2,889 | $ | (429 | ) | ||||||
Weighted
Average
Floor/Ceiling
Price (Per
MMBtu/Bbl)
|
Forward
Notional
Volume
(MMBtu/Bbl)
|
Fair Value
|
||||||||||
Fidelity
|
||||||||||||
Natural gas collar agreements maturing in 2010
|
$5.63/$6.25 | 1,840 | $ | 1,474 | ||||||||
Natural gas collar agreement maturing in 2011
|
$5.62/$6.50 | 450 | $ | 345 | ||||||||
Oil collar agreements maturing in 2010
|
$65.00/$80.50 | 368 | $ | (874 | ) | |||||||
Oil collar agreements maturing in 2011
|
$78.86/$90.64 | 1,278 | $ | 4,706 |
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)
|
April 1 through April 30, 2010
|
—
|
|||
May 1 through May 31, 2010
|
36,450
|
$19.52
|
||
June 1 through June 30, 2010
|
—
|
|||
Total
|
36,450
|
MDU RESOURCES GROUP, INC.
|
|||
DATE: August 6, 2010
|
BY:
|
/s/ Doran N. Schwartz
|
|
Doran N. Schwartz
|
|||
Vice President and Chief Financial Officer
|
|||
BY:
|
/s/ Nicole A. Kivisto
|
||
Nicole A. Kivisto
|
|||
Vice President, Controller and
|
|||
Chief Accounting Officer
|
+10(a)
|
Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated May 28, 2010
|
+10(b)
|
Agreement for Termination of Change of Control Employment Agreement, dated June 15, 2010, by and between MDU Resources Group, Inc. and Terry D. Hildestad
|
+10(c)
|
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
|
12
|
Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends
|
31(a)
|
Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
31(b)
|
Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
32
|
Certification of Chief Executive Officer and Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
101
|
The following materials from MDU Resources Group, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows and (iv) the Notes to Consolidated Financial Statements, tagged as blocks of text
|