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, 2011
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
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THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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41-0423660
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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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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2010 Annual Report
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Company's Annual Report on Form 10-K for the year ended December 31, 2010
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Alusa
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Tecnica de Engenharia Electrica - Alusa
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ASC
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FASB Accounting Standards Codification
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BART
|
Best available retrofit technology
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Bbl
|
Barrel
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Big Stone Station
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450-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
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Big Stone Station II
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Formerly proposed coal-fired electric generating facility near Big Stone City, South Dakota (the Company had anticipated ownership of at least 116 MW)
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Bitter Creek
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Bitter Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI Holdings
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Brazilian Transmission Lines
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Company's equity method investment in the company owning ECTE, ENTE and ERTE (ownership interests in ENTE and ERTE and a portion of the ownership interests in ECTE were sold in the fourth quarter of 2010)
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Btu
|
British thermal unit
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Cascade
|
Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
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CELESC
|
Centrais Elétricas de Santa Catarina S.A.
|
CEM
|
Colorado Energy Management, LLC, a former direct wholly owned subsidiary of Centennial Resources (sold in the third quarter of 2007)
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CEMIG
|
Companhia Energética de Minas Gerais
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Centennial
|
Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
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Centennial Capital
|
Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
|
Centennial Resources
|
Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
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Clean Air Act
|
Federal Clean Air Act
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Colorado State District Court
|
Colorado Thirteenth Judicial District Court, Yuma County
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Company
|
MDU Resources Group, Inc.
|
dk
|
Decatherm
|
Dodd-Frank Act
|
Dodd-Frank Wall Street Reform and Consumer Protection Act
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ECTE
|
Company's equity method investment in Empresa Catarinense de Transmissão de Energia S.A. (10.01 percent ownership interest at June 30, 2011, 14.99 percent ownership interest sold in the fourth quarter of 2010)
|
ENTE
|
Empresa Norte de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
|
EPA
|
U.S. Environmental Protection Agency
|
ERISA
|
Employee Retirement Income Security Act of 1974
|
ERTE
|
Empresa Regional de Transmissão de Energia S.A. (entire 13.3 percent ownership interest sold in the fourth quarter of 2010)
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Exchange Act
|
Securities Exchange Act of 1934, as amended
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FASB
|
Financial Accounting Standards Board
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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
|
GHG
|
Greenhouse gas
|
Great Plains
|
Great Plains Natural Gas Co., a public utility division of the Company
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IFRS
|
International Financial Reporting Standards
|
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
|
Knife River – Northwest
|
Knife River Corporation – Northwest, an indirect wholly owned subsidiary of Knife River (previously Morse Bros., Inc., name changed effective January 1, 2010)
|
kWh
|
Kilowatt-hour
|
LPP
|
Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006)
|
LTM
|
LTM, Inc., an indirect wholly owned subsidiary of Knife River
|
LWG
|
Lower Willamette Group
|
MBbls
|
Thousands of barrels
|
Mcf
|
Thousand cubic feet
|
MDU Brasil
|
MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial Resources
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MDU Construction Services
|
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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Mine Safety Act
|
Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006
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MMBtu
|
Million Btu
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MMcf
|
Million cubic feet
|
MMcfe
|
Million cubic feet equivalent – natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of oil
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MMdk
|
Million decatherms
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Montana-Dakota
|
Montana-Dakota Utilities Co., a public utility division of the Company
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Montana District Court
|
Montana Seventeenth Judicial District Court, Phillips County
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MPPAA
|
Multiemployer Pension Plan Amendments Act of 1980
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MTPSC
|
Montana Public Service Commission
|
MW
|
Megawatt
|
NDPSC
|
North Dakota Public Service Commission
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Oil
|
Includes crude oil, condensate and natural gas liquids
|
OPUC
|
Oregon Public Utility Commission
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Oregon Circuit Court
|
Circuit Court of the State of Oregon for the County of Klamath
|
Oregon DEQ
|
Oregon State Department of Environmental Quality
|
Prairielands
|
Prairielands Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI Holdings
|
PRP
|
Potentially Responsible Party
|
RCRA
|
Resource Conservation and Recovery Act
|
ROD
|
Record of Decision
|
SEC
|
U.S. Securities and Exchange Commission
|
Securities Act
|
Securities Act of 1933, as amended
|
SourceGas
|
SourceGas Distribution LLC
|
WBI Holdings
|
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
|
WUTC
|
Washington Utilities and Transportation Commission
|
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, 2011 and 2010
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7
|
Consolidated Balance Sheets --
|
|
June 30, 2011 and 2010, and December 31, 2010
|
9
|
Consolidated Statements of Cash Flows --
|
|
Six Months Ended June 30, 2011 and 2010
|
10
|
Notes to Consolidated Financial Statements
|
11
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
36
|
Quantitative and Qualitative Disclosures About Market Risk
|
58
|
Controls and Procedures
|
60
|
Part II -- Other Information
|
|
Legal Proceedings
|
60
|
Risk Factors
|
60
|
Unregistered Sales of Equity Securities and Use of Proceeds
|
63
|
Other Information
|
64
|
Exhibits
|
67
|
Signatures
|
68
|
|
|
Exhibit Index
|
69
|
Exhibits
|
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(In thousands, except per share amounts)
|
||||||||||||||||
Operating revenues:
|
||||||||||||||||
Electric, natural gas distribution and pipeline and energy services
|
$ | 274,538 | $ | 272,177 | $ | 752,018 | $ | 732,422 | ||||||||
Construction services, natural gas and oil production, construction materials and contracting, and other
|
656,219 | 634,267 | 1,080,544 | 1,008,799 | ||||||||||||
Total operating revenues
|
930,757 | 906,444 | 1,832,562 | 1,741,221 | ||||||||||||
Operating expenses:
|
||||||||||||||||
Fuel and purchased power
|
14,474 | 13,106 | 31,428 | 30,017 | ||||||||||||
Purchased natural gas sold
|
101,538 | 97,441 | 346,224 | 331,133 | ||||||||||||
Operation and maintenance:
|
||||||||||||||||
Electric, natural gas distribution and pipeline and energy services
|
70,028 | 68,437 | 137,989 | 131,421 | ||||||||||||
Construction services, natural gas and oil production, construction materials and contracting, and other
|
536,608 | 516,854 | 896,408 | 830,642 | ||||||||||||
Depreciation, depletion and amortization
|
83,290 | 81,547 | 167,964 | 160,225 | ||||||||||||
Taxes, other than income
|
42,516 | 40,397 | 92,181 | 86,192 | ||||||||||||
Total operating expenses
|
848,454 | 817,782 | 1,672,194 | 1,569,630 | ||||||||||||
Operating income
|
82,303 | 88,662 | 160,368 | 171,591 | ||||||||||||
Earnings from equity method investments
|
949 | 2,260 | 1,433 | 4,443 | ||||||||||||
Other income
|
1,908 | 2,686 | 3,809 | 5,188 | ||||||||||||
Interest expense
|
20,036 | 20,490 | 42,053 | 41,006 | ||||||||||||
Income before income taxes
|
65,124 | 73,118 | 123,557 | 140,216 | ||||||||||||
Income taxes
|
19,889 | 24,180 | 35,793 | 49,506 | ||||||||||||
Income from continuing operations
|
45,235 | 48,938 | 87,764 | 90,710 | ||||||||||||
Income (loss) from discontinued operations, net of tax (Note 9)
|
(168 | ) | — | 280 | — | |||||||||||
Net income
|
45,067 | 48,938 | 88,044 | 90,710 | ||||||||||||
Dividends on preferred stocks
|
171 | 171 | 342 | 343 | ||||||||||||
Earnings on common stock
|
$ | 44,896 | $ | 48,767 | $ | 87,702 | $ | 90,367 |
Three Months Ended
June 30,
|
Six Months Ended
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(In thousands, except per share amounts)
|
||||||||||||||||
Earnings per common share -- basic:
|
||||||||||||||||
Earnings before discontinued operations
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Discontinued operations, net of tax
|
— | — | — | — | ||||||||||||
Earnings per common share -- basic
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Earnings per common share -- diluted:
|
||||||||||||||||
Earnings before discontinued operations
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Discontinued operations, net of tax
|
— | — | — | — | ||||||||||||
Earnings per common share -- diluted
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Dividends per common share
|
$ | .1625 | $ | .1575 | $ | .3250 | $ | .3150 | ||||||||
Weighted average common shares outstanding -- basic
|
188,794 | 188,129 | 188,732 | 188,047 | ||||||||||||
Weighted average common shares outstanding -- diluted
|
188,968 | 188,267 | 188,903 | 188,198 |
June 30,
2011
|
June 30,
2010
|
December 31,
2010
|
||||||||||
(In thousands, except shares and per share amounts)
|
||||||||||||
ASSETS
|
||||||||||||
Current assets:
|
||||||||||||
Cash and cash equivalents
|
$ | 107,768 | $ | 65,792 | $ | 222,074 | ||||||
Receivables, net
|
566,366 | 502,454 | 583,743 | |||||||||
Inventories
|
277,327 | 260,163 | 252,897 | |||||||||
Deferred income taxes
|
33,732 | 17,755 | 32,890 | |||||||||
Commodity derivative instruments
|
14,234 | 24,932 | 15,123 | |||||||||
Prepayments and other current assets
|
71,604 | 98,203 | 60,441 | |||||||||
Total current assets
|
1,071,031 | 969,299 | 1,167,168 | |||||||||
Investments
|
116,368 | 142,212 | 103,661 | |||||||||
Property, plant and equipment
|
7,394,616 | 7,085,632 | 7,218,503 | |||||||||
Less accumulated depreciation, depletion and amortization
|
3,236,417 | 3,000,663 | 3,103,323 | |||||||||
Net property, plant and equipment
|
4,158,199 | 4,084,969 | 4,115,180 | |||||||||
Deferred charges and other assets:
|
||||||||||||
Goodwill
|
634,931 | 634,654 | 634,633 | |||||||||
Other intangible assets, net
|
23,337 | 26,199 | 25,271 | |||||||||
Other
|
253,515 | 255,473 | 257,636 | |||||||||
Total deferred charges and other assets
|
911,783 | 916,326 | 917,540 | |||||||||
Total assets
|
$ | 6,257,381 | $ | 6,112,806 | $ | 6,303,549 | ||||||
LIABILITIES AND STOCKHOLDERS' EQUITY
|
||||||||||||
Current liabilities:
|
||||||||||||
Short-term borrowings
|
$ | — | $ | 3,700 | $ | 20,000 | ||||||
Long-term debt due within one year
|
62,571 | 72,551 | 72,797 | |||||||||
Accounts payable
|
304,049 | 266,069 | 301,132 | |||||||||
Taxes payable
|
45,065 | 39,976 | 56,186 | |||||||||
Dividends payable
|
30,850 | 29,802 | 30,773 | |||||||||
Accrued compensation
|
37,978 | 35,989 | 40,121 | |||||||||
Commodity derivative instruments
|
18,686 | 20,160 | 24,428 | |||||||||
Other accrued liabilities
|
224,220 | 172,446 | 222,639 | |||||||||
Total current liabilities
|
723,419 | 640,693 | 768,076 | |||||||||
Long-term debt
|
1,369,534 | 1,508,714 | 1,433,955 | |||||||||
Deferred credits and other liabilities:
|
||||||||||||
Deferred income taxes
|
727,562 | 627,256 | 672,269 | |||||||||
Other liabilities
|
711,516 | 708,403 | 736,447 | |||||||||
Total deferred credits and other liabilities
|
1,439,078 | 1,335,659 | 1,408,716 | |||||||||
Commitments and contingencies
|
||||||||||||
Stockholders' equity:
|
||||||||||||
Preferred stocks
|
15,000 | 15,000 | 15,000 | |||||||||
Common stockholders' equity:
|
||||||||||||
Common stock
|
||||||||||||
Shares issued -- $1.00 par value, 189,332,485 at June 30, 2011, 188,672,532 at June 30, 2010 and 188,901,379 at December 31, 2010
|
189,332 | 188,673 | 188,901 | |||||||||
Other paid-in capital
|
1,033,366 | 1,020,206 | 1,026,349 | |||||||||
Retained earnings
|
1,523,546 | 1,407,950 | 1,497,439 | |||||||||
Accumulated other comprehensive loss
|
(32,268 | ) | (463 | ) | (31,261 | ) | ||||||
Treasury stock at cost – 538,921 shares
|
(3,626 | ) | (3,626 | ) | (3,626 | ) | ||||||
Total common stockholders' equity
|
2,710,350 | 2,612,740 | 2,677,802 | |||||||||
Total stockholders' equity
|
2,725,350 | 2,627,740 | 2,692,802 | |||||||||
Total liabilities and stockholders' equity
|
$ | 6,257,381 | $ | 6,112,806 | $ | 6,303,549 |
Six Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Operating activities:
|
||||||||
Net income
|
$ | 88,044 | $ | 90,710 | ||||
Income from discontinued operations, net of tax
|
280 | — | ||||||
Income from continuing operations
|
87,764 | 90,710 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||
Depreciation, depletion and amortization
|
167,964 | 160,225 | ||||||
Earnings, net of distributions, from equity method investments
|
512 | (1,899 | ) | |||||
Deferred income taxes
|
60,960 | 35,758 | ||||||
Changes in current assets and liabilities, net of acquisitions:
|
||||||||
Receivables
|
17,259 | 27,149 | ||||||
Inventories
|
(29,154 | ) | (12,442 | ) | ||||
Other current assets
|
(19,600 | ) | (32,471 | ) | ||||
Accounts payable
|
(3,197 | ) | (13,164 | ) | ||||
Other current liabilities
|
(9,753 | ) | (45,613 | ) | ||||
Other noncurrent changes
|
(17,969 | ) | (4,882 | ) | ||||
Net cash provided by continuing operations
|
254,786 | 203,371 | ||||||
Net cash used in discontinued operations
|
(491 | ) | — | |||||
Net cash provided by operating activities
|
254,295 | 203,371 | ||||||
Investing activities:
|
||||||||
Capital expenditures
|
(224,934 | ) | (237,535 | ) | ||||
Acquisitions, net of cash acquired
|
(157 | ) | (106,548 | ) | ||||
Net proceeds from sale or disposition of property
|
16,145 | 11,972 | ||||||
Investments
|
(9,955 | ) | 1,228 | |||||
Net cash used in continuing operations
|
(218,901 | ) | (330,883 | ) | ||||
Net cash provided by discontinued operations
|
— | — | ||||||
Net cash used in investing activities
|
(218,901 | ) | (330,883 | ) | ||||
Financing activities:
|
||||||||
Repayment of short-term borrowings
|
(20,000 | ) | (6,600 | ) | ||||
Issuance of long-term debt
|
6,000 | 82,992 | ||||||
Repayment of long-term debt
|
(81,202 | ) | (814 | ) | ||||
Proceeds from issuance of common stock
|
5,744 | 1,739 | ||||||
Dividends paid
|
(61,623 | ) | (59,545 | ) | ||||
Excess tax benefit on stock-based compensation
|
1,248 | 548 | ||||||
Net cash provided by (used in) continuing operations
|
(149,833 | ) | 18,320 | |||||
Net cash provided by discontinued operations
|
— | — | ||||||
Net cash provided by (used in) financing activities
|
(149,833 | ) | 18,320 | |||||
Effect of exchange rate changes on cash and cash equivalents
|
133 | (130 | ) | |||||
Decrease in cash and cash equivalents
|
(114,306 | ) | (109,322 | ) | ||||
Cash and cash equivalents -- beginning of year
|
222,074 | 175,114 | ||||||
Cash and cash equivalents -- end of period
|
$ | 107,768 | $ | 65,792 |
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 2010 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 2010 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, 2011, 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.
|
Accounts receivable and allowance for doubtful accounts
|
|
Accounts receivable consists primarily of trade receivables from the sale of goods and services which are recorded at the invoiced amount net of allowance for doubtful accounts, and costs and estimated earnings in excess of billings on uncompleted contracts. The total balance of receivables past due 90 days or more was $41.4 million and $21.6 million as of June 30, 2011 and December 31, 2010, respectively.
|
|
The allowance for doubtful accounts is determined through a review of past due balances and other specific account data. Account balances are written off when management determines the amounts to be uncollectible. The Company's allowance for doubtful accounts as of June 30, 2011 and 2010, and December 31, 2010, was $14.2 million, $14.9 million and $15.3 million, respectively.
|
4.
|
Inventories and natural gas in storage
|
|
Inventories, other than natural gas in storage for the Company's regulated operations, were stated at the lower of average cost or market value. 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. Inventories consisted of:
|
June 30,
2011
|
June 30,
2010
|
December 31,
2010
|
||||||||||
(In thousands)
|
||||||||||||
Aggregates held for resale
|
$ | 82,936 | $ | 83,535 | $ | 79,894 | ||||||
Materials and supplies
|
65,363 | 62,070 | 57,324 | |||||||||
Natural gas in storage (current)
|
11,993 | 14,269 | 34,557 | |||||||||
Merchandise for resale
|
33,435 | 28,438 | 30,182 | |||||||||
Asphalt oil
|
55,729 | 51,956 | 25,234 | |||||||||
Other
|
27,871 | 19,895 | 25,706 | |||||||||
Total
|
$ | 277,327 | $ | 260,163 | $ | 252,897 |
|
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 $47.2 million, $59.3 million, and $48.0 million at June 30, 2011 and 2010, and December 31, 2010, respectively.
|
5.
|
Earnings per common share
|
|
Basic earnings per common share were computed by dividing earnings on common stock by the weighted average number of shares of common stock outstanding during the applicable period. Diluted earnings per common share were computed by dividing earnings on common stock by the total of the weighted average number of shares of common stock outstanding during the applicable period, plus the effect of outstanding stock options and performance share awards. For the three and six months ended June 30, 2011 and 2010, there were no shares excluded from the calculation of diluted earnings per share. Common stock outstanding includes issued shares less shares held in treasury.
|
6.
|
Cash flow information
|
|
Cash expenditures for interest and income taxes were as follows:
|
Six Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Interest, net of amount capitalized
|
$ | 40,646 | $ | 39,652 | ||||
Income taxes
|
$ | 12,887 | $ | 36,011 |
7.
|
New accounting standards
|
|
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 were effective on January 1, 2011. The guidance requires additional disclosures, but it will not impact the Company's financial position, results of operations or cash flows.
|
|
Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements. The guidance generally clarifies the application of existing requirements on topics including the concepts of highest and best use and valuation premise and disclosing quantitative information about the unobservable inputs used in the measurement of instruments categorized within Level 3 of the fair value hierarchy. Additionally, the guidance includes changes on topics such as measuring fair value of financial instruments that are managed within a portfolio and additional disclosure for fair value measurements categorized within Level 3 of the fair value hierarchy. This guidance is effective for the Company on January 1, 2012. The Company is evaluating the effects that adoption of this guidance will have.
|
|
Presentation of Comprehensive Income In June 2011, the FASB issued guidance on the presentation of comprehensive income. This guidance eliminates the option of presenting components of other comprehensive income as part of the statement of stockholders' equity. The guidance will allow the Company the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance is effective for the Company on January 1, 2012, and must be applied retrospectively. The Company is evaluating the effects of this guidance on disclosure, but it will not impact the Company's financial position, results of operations or cash flows.
|
8.
|
Comprehensive income
|
|
Comprehensive income is the sum of net income as reported and other comprehensive income (loss). The Company's other comprehensive income (loss) resulted from gains (losses) on derivative instruments qualifying as hedges, foreign currency translation adjustments and gains on available-for-sale investments. For more information on derivative instruments, see Note 12.
|
|
Comprehensive income, and the components of other comprehensive income (loss) and related tax effects, were as follows:
|
Three Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Net income
|
$ | 45,067 | $ | 48,938 | ||||
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 $10,576 and $2,588 in 2011 and 2010, respectively
|
17,057 | 4,637 | ||||||
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $(2,191) and $3,191 in 2011 and 2010, respectively
|
(3,650 | ) | 5,259 | |||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges
|
20,707 | (622 | ) | |||||
Foreign currency translation adjustment, net of tax of $32 and $(307) in 2011 and 2010, respectively
|
50 | (476 | ) | |||||
Net unrealized gains on available-for-sale investments, net of tax of $47 in 2011
|
87 | — | ||||||
20,844 | (1,098 | ) | ||||||
Comprehensive income
|
$ | 65,911 | $ | 47,840 |
Six Months Ended
June 30,
|
||||||||
2011
|
2010
|
|||||||
(In thousands)
|
||||||||
Net income
|
$ | 88,044 | $ | 90,710 | ||||
Other comprehensive income (loss):
|
||||||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges:
|
||||||||
Net unrealized gain (loss) on derivative instruments arising during the period, net of tax of $(388) and $11,962 in 2011 and 2010, respectively
|
(1,217 | ) | 19,932 | |||||
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income, net of tax of $91 and $(1,166) in 2011 and 2010, respectively
|
155 | (1,850 | ) | |||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges
|
(1,372 | ) | 21,782 | |||||
Foreign currency translation adjustment, net of tax of $170 and $(929) in 2011 and 2010, respectively
|
262 | (1,412 | ) | |||||
Net unrealized gains on available-for-sale investments, net of tax of $55 in 2011
|
103 | — | ||||||
(1,007 | ) | 20,370 | ||||||
Comprehensive income
|
$ | 87,037 | $ | 111,080 |
9.
|
Discontinued operations
|
|
In 2007, Centennial Resources sold CEM to Bicent Power LLC. In connection with the sale, Centennial Resources agreed to indemnify Bicent Power LLC and its affiliates from certain third party claims arising out of or in connection with Centennial Resources' ownership or operation of CEM prior to the sale. In addition, Centennial had previously guaranteed CEM's obligations under a construction contract. The Company incurred legal expenses related to this matter and had an income tax benefit related to favorable resolution of certain tax matters in the first quarter of 2011, which are reflected as discontinued operations in the consolidated financial statements and accompanying notes. Discontinued operations are included in the Other category. For further information, see Note 18.
|
10.
|
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, 2011, include ECTE.
|
|
In August 2006, MDU Brasil acquired ownership interests in the Brazilian Transmission Lines. The electric transmission lines are primarily in northeastern and southern Brazil. The transmission contracts provide for revenues denominated in the Brazilian Real, annual inflation adjustments and change in tax law adjustments. The functional currency for the Brazilian Transmission Lines is the Brazilian Real.
|
|
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. In November 2010, the Company completed the sale of its entire ownership interest in
|
|
ENTE and ERTE and 59.96 percent of its ownership interest in ECTE. One of the parties will purchase the Company's remaining ownership interests in ECTE over a four-year period. Alusa, CEMIG and CELESC hold the remaining ownership interests in ECTE.
|
|
At June 30, 2011 and 2010, and December 31, 2010, the Company's equity method investments had total assets of $107.7 million, $369.9 million and $107.4 million, respectively, and long-term debt of $49.6 million, $157.1 million and $30.1 million, respectively. The Company's investment in its equity method investments was approximately $11.4 million, $57.9 million and $10.9 million, including undistributed earnings of $2.1 million, $11.1 million and $1.9 million, at June 30, 2011 and 2010, and December 31, 2010, respectively.
|
11.
|
Goodwill and other intangible assets
|
|
The changes in the carrying amount of goodwill were as follows:
|
Balance
|
Goodwill
|
Balance
|
||||||||||
as of
|
Acquired
|
as of
|
||||||||||
Six Months Ended
|
January 1,
|
During
|
June 30,
|
|||||||||
June 30, 2011
|
2011* |
the Year**
|
2011* | |||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | — | $ | — | $ | — | ||||||
Natural gas distribution
|
345,736 | — | 345,736 | |||||||||
Construction services
|
102,870 | 298 | 103,168 | |||||||||
Pipeline and energy services
|
9,737 | — | 9,737 | |||||||||
Natural gas and oil production
|
— | — | — | |||||||||
Construction materials and contracting
|
176,290 | — | 176,290 | |||||||||
Other
|
— | — | — | |||||||||
Total
|
$ | 634,633 | $ | 298 | $ | 634,931 | ||||||
*Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
** Includes a purchase price adjustment that was not material related to an acquisition in a prior period.
|
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 | ||||||
*Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
** Includes purchase price adjustments that were not material related to acquisitions in a prior period.
|
Balance
|
Goodwill
|
Balance
|
|||||||||||
as of
|
Acquired
|
as of
|
|||||||||||
Year Ended
|
January 1,
|
During the
|
December 31,
|
||||||||||
December 31, 2010
|
2010* |
Year**
|
2010* | ||||||||||
(In thousands)
|
|||||||||||||
Electric
|
$ | — | $ | — | $ | — | |||||||
Natural gas distribution
|
345,736 | — | 345,736 | ||||||||||
Construction services
|
100,127 | 2,743 | 102,870 | ||||||||||
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 | $ | 5,170 | $ | 634,633 | |||||||
*Balance is presented net of accumulated impairment of $12.3 million at the pipeline and energy services segment, which occurred in prior periods.
** Includes purchase price adjustments that were not material related to acquisitions in a prior period.
|
|
Other amortizable intangible assets were as follows:
|
June 30,
2011
|
June 30,
2010
|
December 31,
2010
|
||||||||||
(In thousands)
|
||||||||||||
Customer relationships
|
$ | 21,702 | $ | 24,942 | $ | 24,942 | ||||||
Accumulated amortization
|
(9,395 | ) | (10,688 | ) | (11,625 | ) | ||||||
12,307 | 14,254 | 13,317 | ||||||||||
Noncompete agreements
|
7,685 | 9,405 | 9,405 | |||||||||
Accumulated amortization
|
(5,062 | ) | (6,033 | ) | (6,425 | ) | ||||||
2,623 | 3,372 | 2,980 | ||||||||||
Other
|
12,899 | 12,063 | 13,217 | |||||||||
Accumulated amortization
|
(4,492 | ) | (3,490 | ) | (4,243 | ) | ||||||
8,407 | 8,573 | 8,974 | ||||||||||
Total
|
$ | 23,337 | $ | 26,199 | $ | 25,271 |
|
Amortization expense for amortizable intangible assets for the three and six months ended June 30, 2011, was $1.0 million and $1.9 million, respectively. 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. Estimated amortization expense for amortizable intangible assets is $4.0 million in 2011, $3.9 million in 2012, $3.7 million in 2013, $3.4 million in 2014, $2.7 million in 2015 and $7.5 million thereafter.
|
12.
|
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, 2011, 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 2010 Annual Report.
|
|
Cascade and Intermountain
|
|
At June 30, 2011, Cascade held natural gas swap agreements, with total forward notional volumes of 676,000 MMBtu, which were not designated as hedges. Cascade utilizes, and Intermountain periodically utilizes, 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. Periodic changes in the fair market value of the derivative instruments are recorded 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, 2011, Cascade recorded the change in the fair market value of the derivative instruments of $1.9 million and $8.5 million, respectively, as a decrease to regulatory assets. 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 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's derivative instruments with credit-risk-related contingent features that are in a liability position at June 30, 2011, was $900,000. 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, 2011, was $900,000.
|
|
Fidelity
|
|
At June 30, 2011, Fidelity held natural gas swap agreements with total forward notional volumes of 23.3 million MMBtu, natural gas basis swap agreements with total forward notional volumes of 12.9 million MMBtu, and oil swap, collar and put option agreements with total forward notional volumes of 3.7 million Bbl, all of which were designated as cash flow hedging instruments. At June 30, 2011, Fidelity held an oil call option agreement with total forward notional volumes of 184,000 Bbl, which did not qualify for hedge accounting. 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.
|
|
The amount of hedge ineffectiveness was immaterial for the three and six months ended June 30, 2011, and 2010, 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. The gain on the derivative instrument that did not qualify for hedge accounting was reported in operating revenues on the Consolidated Statements of Income and was $1.9 million (before tax) and $179,000 (before tax) for the three and six months ended June 30, 2011, respectively.
|
|
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 8.
|
|
As of June 30, 2011, the maximum term of the derivative instruments, in which the exposure to the variability in future cash flows for forecasted transactions is being hedged, is 30 months. Based on June 30, 2011, fair values, over the next 12 months net losses of approximately $2.3 million (after tax) are estimated to 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 or any of its affiliates 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, 2011, was $24.5 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, 2011, was $24.5 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,
2011
|
Fair Value at
June 30,
2010
|
Fair Value at
December 31,
2010
|
|||||||||
(In thousands)
|
|||||||||||||
Designated as hedges
|
Commodity derivative instruments
|
$ | 14,040 | $ | 24,932 | $ | 15,123 | ||||||
Other assets – noncurrent
|
6,265 | 8,524 | 4,104 | ||||||||||
20,305 | 33,456 | 19,227 | |||||||||||
Not designated as hedges
|
Commodity derivative instruments
|
194 | — | — | |||||||||
Other assets – noncurrent
|
— | — | — | ||||||||||
194 | — | — | |||||||||||
Total asset derivatives
|
$ | 20,499 | $ | 33,456 | $ | 19,227 |
Liability
Derivatives
|
Location on
Consolidated
Balance Sheets
|
Fair Value at
June 30,
2011
|
Fair Value at
June 30,
2010
|
Fair Value at
December 31,
2010
|
|||||||||
(In thousands)
|
|||||||||||||
Designated as hedges
|
Commodity derivative instruments
|
$ | 17,780 | $ | 1,961 | $ | 15,069 | ||||||
Other liabilities – noncurrent
|
6,735 | — | 6,483 | ||||||||||
24,515 | 1,961 | 21,552 | |||||||||||
Not designated as hedges
|
Commodity derivative instruments
|
906 | 18,199 | 9,359 | |||||||||
Other liabilities – noncurrent
|
— | 698 | — | ||||||||||
906 | 18,897 | 9,359 | |||||||||||
Total liability derivatives
|
$ | 25,421 | $ | 20,858 | $ | 30,911 |
13.
|
Fair value measurements
|
|
The Company measures 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 $40.3 million, $20.2 million and $39.5 million, as of June 30, 2011 and 2010, and December 31, 2010, respectively, are classified as Investments on the Consolidated Balance Sheets. The fair value of these investments decreased $1.3 million (before tax) for the three months ended June 30, 2011, and increased $790,000 (before tax) for the six months ended June 30, 2011. 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 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 include auction rate securities, mortgage-backed securities and U.S. Treasury securities. These available-for-sale securities are recorded at fair value and are classified as Investments on the Consolidated Balance Sheets. The Company's auction rate securities, which totaled $11.4 million at June 30, 2011 and 2010, and December 31, 2010, 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. Unrealized gains or losses on mortgage-backed securities and U.S. Treasury securities are recorded in accumulated other comprehensive income (loss) as discussed in Note 8.
|
|
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, 2011, Using
|
||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3)
|
Balance at
June 30, 2011
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Assets:
|
||||||||||||||||
Money market funds
|
$ | — | $ | 8,297 | $ | — | $ | 8,297 | ||||||||
Available-for-sale securities:
|
||||||||||||||||
Insurance investment contract*
|
— | 40,328 | — | 40,328 | ||||||||||||
Auction rate securities
|
— | 11,400 | — | 11,400 | ||||||||||||
Mortgage-backed securities
|
— | 8,162 | — | 8,162 | ||||||||||||
U.S. Treasury securities
|
— | 1,969 | — | 1,969 | ||||||||||||
Commodity derivative instruments - current
|
— | 14,234 | — | 14,234 | ||||||||||||
Commodity derivative instruments - noncurrent
|
— | 6,265 | — | 6,265 | ||||||||||||
Total assets measured at fair value
|
$ | — | $ | 90,655 | $ | — | $ | 90,655 | ||||||||
Liabilities:
|
||||||||||||||||
Commodity derivative instruments - current
|
$ | — | $ | 18,686 | $ | — | $ | 18,686 | ||||||||
Commodity derivative instruments - noncurrent
|
— | 6,735 | — | 6,735 | ||||||||||||
Total liabilities measured at fair value
|
$ | — | $ | 25,421 | $ | — | $ | 25,421 | ||||||||
* The insurance investment contract invests approximately 34 percent in common stock of mid-cap companies, 33 percent in common stock of small-cap companies, 32 percent in common stock of large-cap companies and 1 percent in cash and cash equivalents.
|
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)
|
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
December 31, 2010, Using
|
||||||||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3)
|
Balance at December 31, 2010
|
|||||||||||||
(In thousands)
|
||||||||||||||||
Assets:
|
||||||||||||||||
Money market funds
|
$ | — | $ | 166,620 | $ | — | $ | 166,620 | ||||||||
Available-for-sale securities:
|
||||||||||||||||
Fixed-income securities
|
— | 11,400 | — | 11,400 | ||||||||||||
Insurance investment contract*
|
— | 39,541 | — | 39,541 | ||||||||||||
Commodity derivative instruments – current
|
— | 15,123 | — | 15,123 | ||||||||||||
Commodity derivative instruments – noncurrent
|
— | 4,104 | — | 4,104 | ||||||||||||
Total assets measured at fair value
|
$ | — | $ | 236,788 | $ | — | $ | 236,788 | ||||||||
Liabilities:
|
||||||||||||||||
Commodity derivative instruments – current
|
$ | — | $ | 24,428 | $ | — | $ | 24,428 | ||||||||
Commodity derivative instruments – noncurrent
|
— | 6,483 | — | 6,483 | ||||||||||||
Total liabilities measured at fair value
|
$ | — | $ | 30,911 | $ | — | $ | 30,911 | ||||||||
* The insurance investment contract invests approximately 35 percent in common stock of mid-cap companies, 33 percent in common stock of small-cap companies, 31 percent in common stock of large-cap companies and 1 percent in cash and cash equivalents.
|
|
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 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, other observable inputs or other sources, including pricing from outside sources such as the fund itself.
|
|
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. For the three and six months ended June 30, 2011, there were no transfers between Levels 1 and 2.
|
|
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, and 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, 2011
|
$ | 1,432,105 | $ | 1,550,592 | ||||
Long-term debt at June 30, 2010
|
$ | 1,581,265 | $ | 1,718,477 | ||||
Long-term debt at December 31, 2010
|
$ | 1,506,752 | $ | 1,621,184 |
|
The carrying amounts of the Company's remaining financial instruments included in current assets and current liabilities approximate their fair values.
|
14.
|
Income taxes
|
|
In the first quarter of 2011, the Company received favorable resolution of certain tax matters relating to the 2004 through 2006 tax years. As a result, the Company recorded an income tax benefit from continuing operations of $4.2 million. This resolution includes the effects of $2.8 million related to the reversal of unrecognized tax benefits that were previously established for the 2004 through 2006 tax years and associated interest of $600,000.
|
|
In the second quarter of 2011, the Company's unrecognized tax positions increased $3.6 million, excluding interest, largely due to tax positions under examination relating to the 2007 through 2009 tax years. The ultimate deductibility of these tax positions is highly certain but there is uncertainty about the timing of such deductibility. The Company anticipates the uncertainty about the timing of the deductibility will be resolved within the next 12 months.
|
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 ECTE.
|
|
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 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 ECTE.
|
|
The information below follows the same accounting policies as described in Note 1 of the Company's Notes to Consolidated Financial Statements in the 2010 Annual Report. Information on the Company's businesses was as follows:
|
Three Months
Ended June 30, 2011
|
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings
on Common
Stock
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | 49,986 | $ | — | $ | 4,807 | ||||||
Natural gas distribution
|
164,626 | — | 1,902 | |||||||||
Pipeline and energy services
|
59,926 | 12,504 | 4,772 | |||||||||
274,538 | 12,504 | 11,481 | ||||||||||
Construction services
|
192,697 | 5,379 | 6,138 | |||||||||
Natural gas and oil production
|
87,390 | 25,392 | 21,326 | |||||||||
Construction materials and contracting
|
375,613 | — | 4,980 | |||||||||
Other
|
519 | 2,301 | 971 | |||||||||
656,219 | 33,072 | 33,415 | ||||||||||
Intersegment eliminations
|
— | (45,576 | ) | — | ||||||||
Total
|
$ | 930,757 | $ | — | $ | 44,896 |
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 |
Six Months
Ended June 30, 2011
|
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings
on Common
Stock
|
|||||||||
(In thousands)
|
||||||||||||
Electric
|
$ | 107,831 | $ | — | $ | 13,331 | ||||||
Natural gas distribution
|
535,010 | — | 29,418 | |||||||||
Pipeline and energy services
|
109,177 | 37,245 | 11,691 | |||||||||
752,018 | 37,245 | 54,440 | ||||||||||
Construction services
|
394,877 | 6,596 | 10,771 | |||||||||
Natural gas and oil production
|
165,801 | 50,933 | 37,596 | |||||||||
Construction materials and contracting
|
519,146 | — | (16,423 | ) | ||||||||
Other
|
720 | 4,589 | 1,318 | |||||||||
1,080,544 | 62,118 | 33,262 | ||||||||||
Intersegment eliminations
|
— | (99,363 | ) | — | ||||||||
Total
|
$ | 1,832,562 | $ | — | $ | 87,702 |
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 |
|
The Other category recognized a loss of $168,000 and income of $280,000, from discontinued operations, net of tax, for the three and six months ended June 30, 2011, respectively. 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.
|
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,
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
(In thousands)
|
||||||||||||||||
Components of net periodic benefit cost:
|
||||||||||||||||
Service cost
|
$ | 827 | $ | 501 | $ | 383 | $ | 374 | ||||||||
Interest cost
|
4,959 | 4,004 | 1,161 | 1,317 | ||||||||||||
Expected return on assets
|
(5,727 | ) | (4,992 | ) | (1,308 | ) | (1,577 | ) | ||||||||
Amortization of prior service cost (credit)
|
44 | 31 | (669 | ) | (915 | ) | ||||||||||
Amortization of net actuarial (gain) loss
|
1,049 | 256 | (53 | ) | 67 | |||||||||||
Amortization of net transition obligation
|
— | — | 531 | 613 | ||||||||||||
Curtailment loss
|
1,218 | — | — | — | ||||||||||||
Net periodic benefit cost, including amount capitalized
|
2,370 | (200 | ) | 45 | (121 | ) | ||||||||||
Less amount capitalized
|
287 | 107 | (28 | ) | 37 | |||||||||||
Net periodic benefit cost
|
$ | 2,083 | $ | (307 | ) | $ | 73 | $ | (158 | ) |
Six Months
|
Pension Benefits
|
Other
Postretirement
Benefits
|
||||||||||||||
Ended June 30,
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
(In thousands)
|
||||||||||||||||
Components of net periodic benefit cost:
|
||||||||||||||||
Service cost
|
$ | 1,654 | $ | 1,305 | $ | 722 | $ | 731 | ||||||||
Interest cost
|
9,919 | 8,930 | 2,350 | 2,594 | ||||||||||||
Expected return on assets
|
(11,427 | ) | (10,684 | ) | (2,526 | ) | (2,969 | ) | ||||||||
Amortization of prior service cost (credit)
|
87 | 69 | (1,338 | ) | (1,779 | ) | ||||||||||
Amortization of net actuarial loss
|
2,592 | 1,228 | 258 | 455 | ||||||||||||
Amortization of net transition obligation
|
— | — | 1,062 | 1,145 | ||||||||||||
Curtailment loss
|
1,218 | — | — | — | ||||||||||||
Net periodic benefit cost, including amount capitalized
|
4,043 | 848 | 528 | 177 | ||||||||||||
Less amount capitalized
|
535 | 383 | (95 | ) | 84 | |||||||||||
Net periodic benefit cost
|
$ | 3,508 | $ | 465 | $ | 623 | $ | 93 |
|
Defined pension plan benefits to all nonunion and certain union employees hired after December 31, 2005, were discontinued. Employees that would have been eligible for defined pension plan benefits are eligible to receive additional defined contribution plan benefits. Effective January 1, 2010, all benefit and service accruals for nonunion and certain union plans were frozen. Effective June 30, 2011, all benefit and service accruals for an additional union plan were frozen. These employees will be 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, 2011, was $1.9 million and $4.0 million, respectively. 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.
|
17.
|
Regulatory matters and revenues subject to refund
|
|
In April 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 included the investment in infrastructure upgrades, recovery of the investment in renewable generation,
|
|
the costs associated with Big Stone Station II and the significant loss of wholesale sales margins. In June 2010, the NDPSC approved an interim increase of $7.6 million effective with service rendered June 18, 2010. In June 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. In July 2010, Montana-Dakota filed an amendment to its application to exclude the 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. In November 2010, Montana-Dakota and the NDPSC Advocacy Staff filed a second settlement agreement resolving certain issues raised by the NDPSC Advocacy Staff in its investigation of the rate increase application. Montana-Dakota revised its requested rate increase to $8.8 million annually or 7.7 percent as a result of the settlements, the exclusion of the Big Stone Station II development costs and other adjustments. The NDPSC Advocacy Staff sought reductions of $8.3 million annually from Montana-Dakota's requested increase. A hearing on the application was held in November 2010. On March 14, 2011, Montana-Dakota, the NDPSC Advocacy Staff and the Missouri Valley Resource Council filed a settlement agreement that resolved all outstanding issues in the case, resulting in an increase of $7.6 million annually. On June 8, 2011, the NDPSC approved the settlement agreements. Final rates were implemented effective with service rendered July 22, 2011.
|
|
On May 20, 2011, Montana-Dakota filed an application with the NDPSC requesting advance determination of prudence that the addition of the air quality control system at the Big Stone Station, to comply with the Clean Air Act and the South Dakota Regional Haze Implementation Plan, is reasonable and prudent. An order is expected in early 2012.
|
|
On July 7, 2011, Montana-Dakota filed for an advance determination of prudence with the NDPSC on the construction of an 88-MW simple cycle natural gas turbine and associated facilities projected to be in service in 2015. The turbine will be located on company owned property that is adjacent to Montana-Dakota's Heskett Generating Station near Mandan, North Dakota, and is required to meet the capacity requirements of Montana-Dakota's integrated electric system service customers. The capacity will be a partial replacement for third party contract capacity expiring in 2015. Project cost is estimated to be $85.6 million. An order is expected in the first quarter of 2012.
|
|
In August 2010, Montana-Dakota filed an application with the MTPSC for an electric rate increase. Montana-Dakota requested a total increase of $5.5 million annually or approximately 13 percent above current rates. The requested increase included the investment in infrastructure upgrades, recovery of the investment in renewable generation, the costs associated with Big Stone Station II and the significant loss of wholesale sales margins. Montana-Dakota requested an interim increase of $3.1 million or approximately 7.4 percent. On February 8, 2011, the MTPSC approved an interim increase of $2.6 million or approximately 6.28 percent, effective with service rendered February 14, 2011. On May 9, 2011, Montana-Dakota and intervenors to the case filed a settlement agreement with the MTPSC at the interim increase level. The MTPSC held a hearing on the settlement on June 29, 2011, and approved the settlement agreement on July 26, 2011.
|
|
On March 21, 2011, the WUTC filed a complaint against Cascade, alleging safety violations in the operations of its natural gas distribution system. For more information, see Note 18.
|
18.
|
Contingencies
|
|
The Company has reserved $40.7 million and $45.3 million for potential liabilities related to litigation and environmental matters as of June 30, 2011 and December 31, 2010, respectively, which includes amounts that may be reserved for matters discussed in litigation and environmental matters within this note.
|
|
Litigation
|
|
Guarantee Obligation Under a Construction Contract 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, which letter of credit expired in November 2010. 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 $149.7 million. 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 Resources for indemnification under the 2007 purchase and sale agreement for indemnifiable losses, including defense fees and costs which CEM and Bicent Power LLC have stated are more than $10.0 million, arising from LPP's arbitration demand and related to Centennial Resources' ownership of CEM prior to its sale to Bicent Power LLC. The Company believes the claims against Centennial and Centennial Resources are without merit and intends to vigorously defend against such claims. Centennial and Centennial Resources filed a complaint with the Supreme Court of the State of New York in November 2010, against CEM and Bicent Power LLC seeking damages for breach of contract and other relief including specific performance of the 2007 purchase and sale agreement allowing for Centennial Resources' participation in the arbitration proceeding and replacement of the letter of credit. On January 28, 2011, CEM and Bicent Power LLC filed a motion to dismiss the complaint filed by Centennial and Centennial Resources. On July 6, 2011, the Supreme Court of the State of New York entered an order granting CEM's motion to dismiss the complaint against it for lack of jurisdiction. The Supreme Court of the State of New York also dismissed one of the claims against Bicent Power LLC but denied Bicent Power LLC's motion to dismiss the remaining claims against it including the claims for breach of contract damages and specific performance of the 2007 purchase and sale agreement. The arbitration hearing on LPP's claim is currently scheduled for late in the third quarter of 2011.
|
|
Construction Materials In 2009, LTM provided pavement work under a subcontract for reconstruction at the Klamath Falls Airport owned by the City of Klamath Falls, Oregon. In October 2010, the City of Klamath Falls filed a complaint in Oregon Circuit Court against the project's general contractor alleging the work performed by LTM is defective. The general contractor tendered the defense and indemnity of the claim to LTM and its insurance carrier. On January 18, 2011, the general contractor served a third party complaint against LTM seeking indemnity and contribution for damages imposed on the general contractor. LTM filed a fourth-party complaint seeking contribution and indemnity for damages imposed on LTM against the project engineer firm which prepared the specifications for the airport runway. LTM's insurance carrier accepted defense of the
|
|
complaint against the general contractor and the third party complaint against LTM subject to reservation of its rights under the applicable insurance policy. Damages, including removal and replacement of the paved runway, were estimated by the plaintiff in its complaint as $6.0 million to $11.0 million. The Oregon Circuit Court granted a motion by LTM to dismiss certain of the plaintiff's claims relating to approximately $5.0 million of damages but allowed the plaintiff to amend its complaint. In its amended complaint, the plaintiff asserts new claims with estimated damages of $21.9 million plus interest and attorney fees. LTM believes its work met the specifications of the subcontract and expects to vigorously defend against the claims.
|
|
Natural Gas Gathering Operations In January 2010, SourceGas filed an application with the Colorado State District Court to compel Bitter Creek to arbitrate a dispute regarding operating pressures under a natural gas gathering contract on one of Bitter Creek's pipeline gathering systems in Montana. Bitter Creek resisted the application and sought a declaratory order interpreting the gathering contract. In May 2010, the Colorado State District Court granted the application and ordered Bitter Creek into arbitration. An arbitration hearing was held in August 2010. In October 2010, Bitter Creek was notified that the arbitration panel issued an award in favor of SourceGas for approximately $26.6 million. As a result, Bitter Creek, which is included in the pipeline and energy services segment, recorded a $26.6 million charge ($16.5 million after tax) in the third quarter of 2010. On April 20, 2011, the Colorado State District Court entered an order denying a motion by Bitter Creek to vacate the arbitration award and granting a motion by SourceGas to confirm the arbitration award as a court judgment. The Colorado State District Court also awarded $293,000 to SourceGas for legal fees and expense. Bitter Creek filed an appeal from the Colorado State District Court's order and judgment to the Colorado Court of Appeals on April 28, 2011.
|
|
In related matters, Noble Energy, Inc. made a written demand in December 2010, to Bitter Creek and SourceGas for arbitration under the gathering contract between Bitter Creek and SourceGas. Noble Energy, Inc. contends it is a third party beneficiary of the contract and alleged it is damaged by the increased operating pressures demanded by SourceGas on the natural gas gathering system. Bitter Creek filed a complaint in Colorado State District Court to enjoin arbitration by Noble Energy, Inc. On July 8, 2011, Bitter Creek and Noble Energy, Inc. entered into a settlement agreement to dismiss all claims between them without prejudice including withdrawal of Noble Energy, Inc.'s demand for arbitration. In July 2010, Omimex Canada, Ltd. filed a complaint against Bitter Creek in Montana District Court alleging Bitter Creek breached a separate gathering contract with Omimex Canada, Ltd. as a result of the increased operating pressures on the same natural gas gathering system. Omimex Canada, Ltd. seeks unspecified damages and injunctive relief.
|
|
Natural Gas Distribution The WUTC on March 21, 2011, filed a complaint against Cascade, alleging pipeline safety violations in the operation of its natural gas distribution system. The complaint alleged more than 360 violations of pipeline safety regulations and sought relief including unspecified monetary penalties. Cascade filed its answer to the complaint admitting some and denying other of the alleged violations. Cascade and the WUTC staff entered into a settlement agreement filed with the WUTC on July 13, 2011, which was approved by the WUTC on August 3, 2011. The settlement provides for an immediate cash payment by Cascade of $425,000 and suspended penalties totaling up to $1.8 million which Cascade will be required to pay if it fails to comply with action items for remediation of violations
|
|
and implementation of safety program improvements within timelines specified in the agreement. The Company's leadership is committed to pipeline safety compliance and over the past year and a half substantial resources have been invested by Cascade to improve pipeline safety documentation and procedures. Cascade recognized certain compliance issues and has been working with the WUTC to become fully compliant. Cascade believes most of the violations have been or are in the process of being remedied and intends to make significant additional technological and other investments over the next year to comply with the requirements of the settlement agreement and improve its compliance procedures and results.
|
|
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, results of operations or cash flows.
|
|
Portland Harbor Site In December 2000, Knife River – Northwest 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 Knife River – Northwest 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 Knife River – Northwest 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. Knife River – Northwest 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 Portland Harbor Natural Resource 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, Knife River – Northwest does not believe it is a Responsible Party. In addition, Knife River – Northwest 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. Knife River – Northwest 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 Knife River – Northwest and others to recover LWG's investigation costs to the extent Knife River – Northwest 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, Knife River – Northwest 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; however, Cascade anticipates its proportional share could be approximately fifty percent.
|
|
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. In October 2010, Cascade received notice from the United States Coast Guard that a hazardous substance appearing to be manufactured gas plant waste was released into the waterway from an abandoned pipe located on the shoreline in the vicinity of the former manufactured gas plant. Cascade subsequently received an administrative order from the United States Coast Guard requiring Cascade to remove the abandoned pipe and conduct other associated time-critical actions. The work satisfying the administrative order was completed by Cascade in November 2010. It is expected that subsequent remedial action at the site will be conducted under the oversight of the EPA. On June 27, 2011, the EPA provided Cascade with a draft administrative settlement agreement and statement of work for performance of a remediation investigation and feasibility study of the site. Cascade intends to meet with the EPA and discuss the draft agreement and statement of work with the intent of reaching consensus on the scope and schedule for the remediation investigation and feasibility study. Cascade has reserved $6.4 million for remediation of this site. In April 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 WUTC approved the petition in September 2010, subject to conditions set forth in the order.
|
|
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 and work plan with the Washington Department of Ecology for completion of a remedial investigation and feasibility study for the site. The remediation investigation and feasibility study report are expected to be completed by late 2011. There is currently not enough information available to estimate the potential liability to Cascade associated with this claim although Cascade believes its proportional share of any liability will be relatively small in comparison to other PRPs. The plant manufactured gas from coal between approximately 1890 and 1946. In 1946, shortly after Cascade's predecessor acquired the plant, it converted the plant to a propane-air gas facility. There are no documented wastes or by-products resulting from the mixing or distribution of propane-air gas.
|
|
Cascade has received notices from certain of its insurance carriers that they will participate in defense of Cascade for these contamination claims subject to full and complete reservations of rights and defenses to insurance coverage. 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
|
|
Centennial guaranteed CEM's obligations under a construction contract. For further information, see litigation in this note.
|
|
In connection with the sale of the Brazilian Transmission Lines, as discussed in Note 10, Centennial has agreed to 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 sale of the Brazilian Transmission Lines.
|
|
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, 2011, expire in the years ranging from 2011 to 2012; however, Fidelity continues to enter into additional hedging activities and, as a result, WBI Holdings from time to time may issue additional guarantees on these hedging obligations. The amount outstanding by Fidelity was $13.5 million and was reflected on the Consolidated Balance Sheet, at June 30, 2011. 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, 2011, the fixed maximum amounts guaranteed under these agreements aggregated $127.6 million. The amounts of scheduled expiration of the maximum amounts guaranteed under these agreements aggregate $27.8 million in 2011; $73.4 million in 2012; $18.2 million in 2013; $300,000 in 2014; $100,000 in 2015; $100,000 in 2016; $800,000 in 2018; $300,000 in 2019; $2.6 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 $1.3 million and was reflected on the Consolidated Balance Sheet at June 30, 2011. 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, some of which are guaranteed by other subsidiaries of the Company. At June 30, 2011, the fixed maximum amounts guaranteed under these letters of credit, aggregated $27.4 million. In 2011 and 2012, $21.6 million and $5.8 million, respectively, of letters of credit are scheduled to expire. There were no amounts outstanding under the above letters of credit at June 30, 2011.
|
|
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, 2011, the fixed maximum amount guaranteed under this agreement was $5.0 million and is scheduled to expire in 2014. 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, 2011, because this intercompany transaction was eliminated in consolidation.
|
|
In addition, Centennial, Knife River and MDU Construction Services have issued guarantees to third parties related to the 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 these obligations, Centennial, Knife River and MDU Construction Services would be required to make payments under these guarantees. Any amounts outstanding by subsidiaries of the Company for these guarantees were reflected on the Consolidated Balance Sheet at June 30, 2011.
|
|
In the normal course of business, Centennial has surety bonds related to construction contracts and reclamation obligations of its subsidiaries, as well as an arbitration award. 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, 2011, approximately $688 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,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Electric
|
$ | 4.8 | $ | 5.0 | $ | 13.3 | $ | 10.8 | ||||||||
Natural gas distribution
|
1.9 | .1 | 29.4 | 23.4 | ||||||||||||
Construction services
|
6.1 | 2.9 | 10.8 | 3.1 | ||||||||||||
Pipeline and energy services
|
4.8 | 9.5 | 11.7 | 18.3 | ||||||||||||
Natural gas and oil production
|
21.3 | 24.0 | 37.6 | 46.3 | ||||||||||||
Construction materials and contracting
|
5.0 | 5.7 | (16.4 | ) | (14.5 | ) | ||||||||||
Other
|
1.1 | 1.6 | 1.1 | 3.0 | ||||||||||||
Earnings before discontinued operations
|
45.0 | 48.8 | 87.5 | 90.4 | ||||||||||||
Income (loss) from discontinued operations, net of tax
|
(.1 | ) | — | .2 | — | |||||||||||
Earnings on common stock
|
$ | 44.9 | $ | 48.8 | $ | 87.7 | $ | 90.4 | ||||||||
Earnings per common share – basic:
|
||||||||||||||||
Earnings before discontinued operations
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Discontinued operations, net of tax
|
— | — | — | — | ||||||||||||
Earnings per common share – basic
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Earnings per common share – diluted:
|
||||||||||||||||
Earnings before discontinued operations
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Discontinued operations, net of tax
|
— | — | — | — | ||||||||||||
Earnings per common share – diluted
|
$ | .24 | $ | .26 | $ | .46 | $ | .48 | ||||||||
Return on average common equity for the 12 months ended
|
8.9 | % | 10.0 | % |
|
·
|
Decreased transportation volumes and lower storage services revenue at the pipeline and energy services business
|
|
·
|
Decreased natural gas production, lower average realized natural gas prices, increased lease operating expenses and higher production and property taxes, partially offset by higher average realized oil prices at the natural gas and oil production business
|
|
·
|
Higher construction workloads and margins in the Western region at the construction services business
|
|
·
|
Increased retail sales volumes at the natural gas distribution business
|
|
·
|
Lower average realized natural gas prices, decreased natural gas production, higher depreciation, depletion and amortization expense and increased lease operating expenses, partially offset by higher average realized oil prices at the natural gas and oil production business
|
|
·
|
Decreased transportation volumes, lower storage services revenue and lower gathering volumes, partially offset by lower operation and maintenance expense at the pipeline and energy services business
|
|
·
|
Higher construction workloads and margins in the Western region at the construction services business
|
|
·
|
Increased retail sales volumes and lower income taxes, partially offset by higher regulated operation and maintenance expense at the natural gas distribution business
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Operating revenues
|
$ | 50.0 | $ | 45.7 | $ | 107.8 | $ | 95.4 | ||||||||
Operating expenses:
|
||||||||||||||||
Fuel and purchased power
|
14.5 | 13.1 | 31.4 | 30.0 | ||||||||||||
Operation and maintenance
|
18.3 | 16.2 | 34.3 | 31.4 | ||||||||||||
Depreciation, depletion and amortization
|
7.9 | 6.1 | 16.1 | 11.9 | ||||||||||||
Taxes, other than income
|
2.5 | 2.2 | 5.0 | 4.8 | ||||||||||||
43.2 | 37.6 | 86.8 | 78.1 | |||||||||||||
Operating income
|
6.8 | 8.1 | 21.0 | 17.3 | ||||||||||||
Earnings
|
$ | 4.8 | $ | 5.0 | $ | 13.3 | $ | 10.8 | ||||||||
Retail sales (million kWh)
|
614.6 | 615.2 | 1,409.3 | 1,365.0 | ||||||||||||
Sales for resale (million kWh)
|
21.8 | 7.6 | 28.5 | 37.4 | ||||||||||||
Average cost of fuel and purchased power per kWh
|
$ | .021 | $ | .020 | $ | .021 | $ | .020 |
|
·
|
Higher operation and maintenance expense of $1.3 million (after tax), primarily increased benefit and payroll-related costs, as well as increased contract services
|
|
·
|
Increased depreciation, depletion and amortization expense of $1.1 million (after tax), including the effects of higher property, plant and equipment balances
|
|
·
|
Lower other income of $800,000 (after tax), primarily lower allowance for funds used during construction related to electric generation projects, which were placed in service in 2010
|
|
·
|
Higher net interest expense of $700,000 (after tax), including lower capitalized interest
|
|
·
|
Lower income taxes of $2.2 million, primarily related to a reduction of deferred income taxes associated with benefits
|
|
·
|
Higher electric retail sales margins, primarily due to implementation of interim rates in North Dakota and Montana
|
|
·
|
Higher electric retail sales margins, primarily due to implementation of interim rates in North Dakota and Montana, as well as higher rates in Wyoming
|
|
·
|
Lower income taxes of $3.5 million, including a reduction of deferred income taxes as previously discussed, as well as an income tax benefit of $1.2 million related to favorable resolution of certain income tax matters
|
|
·
|
Increased depreciation, depletion and amortization expense of $2.6 million (after tax), including the effects of higher property, plant and equipment balances
|
|
·
|
Lower other income of $1.9 million (after tax), as previously discussed
|
|
·
|
Higher operation and maintenance expense of $1.8 million (after tax), as previously discussed
|
|
·
|
Higher net interest expense of $1.5 million (after tax), as previously discussed
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Operating revenues
|
$ | 164.6 | $ | 160.1 | $ | 535.0 | $ | 509.2 | ||||||||
Operating expenses:
|
||||||||||||||||
Purchased natural gas sold
|
102.0 | 98.9 | 359.4 | 344.1 | ||||||||||||
Operation and maintenance
|
33.3 | 34.4 | 67.6 | 67.1 | ||||||||||||
Depreciation, depletion and amortization
|
11.2 | 10.7 | 22.4 | 21.4 | ||||||||||||
Taxes, other than income
|
10.6 | 10.5 | 28.4 | 27.0 | ||||||||||||
157.1 | 154.5 | 477.8 | 459.6 | |||||||||||||
Operating income
|
7.5 | 5.6 | 57.2 | 49.6 | ||||||||||||
Earnings
|
$ | 1.9 | $ | .1 | $ | 29.4 | $ | 23.4 | ||||||||
Volumes (MMdk):
|
||||||||||||||||
Sales
|
17.3 | 15.6 | 61.3 | 53.7 | ||||||||||||
Transportation
|
25.6 | 28.9 | 59.7 | 63.4 | ||||||||||||
Total throughput
|
42.9 | 44.5 | 121.0 | 117.1 | ||||||||||||
Degree days (% of normal)*
|
||||||||||||||||
Montana-Dakota
|
120 | % | 96 | % | 112 | % | 98 | % | ||||||||
Cascade
|
118 | % | 118 | % | 107 | % | 95 | % | ||||||||
Intermountain
|
141 | % | 132 | % | 113 | % | 103 | % | ||||||||
Average cost of natural gas, including transportation, per dk
|
$ | 5.88 | $ | 6.33 | $ | 5.87 | $ | 6.41 | ||||||||
*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
|
|
·
|
Lower income taxes of $1.0 million, primarily related to a reduction of deferred income taxes associated with benefits
|
|
·
|
Higher regulated operation and maintenance expense of $500,000 (after tax), including higher benefit-related costs
|
|
·
|
Increased depreciation, depletion and amortization expense of $300,000 (after tax), primarily resulting from higher property, plant and equipment balances
|
|
·
|
Increased retail sales volumes, largely resulting from colder weather than last year
|
|
·
|
Lower income taxes of $2.0 million, as previously discussed
|
|
·
|
Higher regulated operation and maintenance expense of $1.9 million (after tax), primarily higher benefit-related costs
|
|
·
|
Increased depreciation, depletion and amortization expense of $600,000 (after tax), as previously discussed
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(In millions)
|
||||||||||||||||
Operating revenues
|
$ | 198.1 | $ | 188.2 | $ | 401.5 | $ | 341.3 | ||||||||
Operating expenses:
|
||||||||||||||||
Operation and maintenance
|
178.3 | 173.2 | 363.2 | 315.0 | ||||||||||||
Depreciation, depletion and amortization
|
2.8 | 3.1 | 5.8 | 6.3 | ||||||||||||
Taxes, other than income
|
5.5 | 6.1 | 13.2 | 12.6 | ||||||||||||
186.6 | 182.4 | 382.2 | 333.9 | |||||||||||||
Operating income
|
11.5 | 5.8 | 19.3 | 7.4 | ||||||||||||
Earnings
|
$ | 6.1 | $ | 2.9 | $ | 10.8 | $ | 3.1 |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(Dollars in millions)
|
||||||||||||||||
Operating revenues
|
$ | 72.4 | $ | 80.5 | $ | 146.4 | $ | 169.1 | ||||||||
Operating expenses:
|
||||||||||||||||
Purchased natural gas sold
|
33.9 | 35.3 | 68.0 | 82.8 | ||||||||||||
Operation and maintenance
|
18.6 | 17.8 | 36.2 | 33.0 | ||||||||||||
Depreciation, depletion and amortization
|
6.4 | 6.5 | 12.8 | 12.9 | ||||||||||||
Taxes, other than income
|
3.4 | 3.2 | 7.0 | 6.2 | ||||||||||||
62.3 | 62.8 | 124.0 | 134.9 | |||||||||||||
Operating income
|
10.1 | 17.7 | 22.4 | 34.2 | ||||||||||||
Earnings
|
$ | 4.8 | $ | 9.5 | $ | 11.7 | $ | 18.3 | ||||||||
Transportation volumes (MMdk)
|
25.8 | 44.3 | 53.1 | 74.8 | ||||||||||||
Gathering volumes (MMdk)
|
16.9 | 19.3 | 34.4 | 38.4 | ||||||||||||
Customer natural gas storage balance (MMdk):
|
||||||||||||||||
Beginning of period
|
32.9 | 43.5 | 58.8 | 61.5 | ||||||||||||
Net injection (withdrawal)
|
(1.2 | ) | 20.7 | (27.1 | ) | 2.7 | ||||||||||
End of period
|
31.7 | 64.2 | 31.7 | 64.2 |
|
·
|
Decreased transportation volumes of $3.1 million (after tax), largely lower volumes transported to storage
|
|
·
|
Lower storage services revenue of $1.7 million (after tax), largely lower storage balances
|
|
·
|
Lower gathering volumes of $900,000 (after tax)
|
|
·
|
Decreased transportation volumes of $3.8 million (after tax), largely lower volumes transported to storage
|
|
·
|
Lower storage services revenue of $2.1 million (after tax), largely lower storage balances
|
|
·
|
Lower gathering volumes of $1.6 million (after tax)
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(Dollars in millions, where applicable)
|
||||||||||||||||
Operating revenues:
|
||||||||||||||||
Natural gas
|
$ | 44.3 | $ | 55.2 | $ | 89.7 | $ | 112.8 | ||||||||
Oil
|
68.5 | 55.6 | 127.0 | 105.6 | ||||||||||||
112.8 | 110.8 | 216.7 | 218.4 | |||||||||||||
Operating expenses:
|
||||||||||||||||
Operation and maintenance:
|
||||||||||||||||
Lease operating costs
|
18.4 | 16.3 | 36.4 | 32.1 | ||||||||||||
Gathering and transportation
|
5.6 | 5.9 | 11.3 | 11.8 | ||||||||||||
Other
|
9.2 | 8.8 | 17.5 | 17.4 | ||||||||||||
Depreciation, depletion and amortization
|
33.4 | 32.5 | 67.6 | 62.1 | ||||||||||||
Taxes, other than income:
|
||||||||||||||||
Production and property taxes
|
10.5 | 9.0 | 20.5 | 18.5 | ||||||||||||
Other
|
.2 | .1 | .5 | .5 | ||||||||||||
77.3 | 72.6 | 153.8 | 142.4 | |||||||||||||
Operating income
|
35.5 | 38.2 | 62.9 | 76.0 | ||||||||||||
Earnings
|
$ | 21.3 | $ | 24.0 | $ | 37.6 | $ | 46.3 | ||||||||
Production:
|
||||||||||||||||
Natural gas (MMcf)
|
11,253 | 12,809 | 23,011 | 25,052 | ||||||||||||
Oil (MBbls)
|
821 | 831 | 1,623 | 1,592 | ||||||||||||
Total Production (MMcfe)
|
16,180 | 17,794 | 32,750 | 34,602 | ||||||||||||
Average realized prices (including hedges):
|
||||||||||||||||
Natural gas (per Mcf)
|
$ | 3.94 | $ | 4.31 | $ | 3.90 | $ | 4.50 | ||||||||
Oil (per Bbl)
|
$ | 83.42 | $ | 66.88 | $ | 78.26 | $ | 66.36 | ||||||||
Average realized prices (excluding hedges):
|
||||||||||||||||
Natural gas (per Mcf)
|
$ | 3.49 | $ | 3.30 | $ | 3.44 | $ | 3.92 | ||||||||
Oil (per Bbl)
|
$ | 89.25 | $ | 67.21 | $ | 84.31 | $ | 66.83 | ||||||||
Average depreciation, depletion and amortization rate, per equivalent Mcf
|
$ | 1.96 | $ | 1.74 | $ | 1.96 | $ | 1.71 | ||||||||
Production costs, including taxes, per equivalent Mcf:
|
||||||||||||||||
Lease operating costs
|
$ | 1.14 | $ | .91 | $ | 1.11 | $ | .93 | ||||||||
Gathering and transportation
|
.34 | .33 | .34 | .34 | ||||||||||||
Production and property taxes
|
.65 | .51 | .63 | .53 | ||||||||||||
$ | 2.13 | $ | 1.75 | $ | 2.08 | $ | 1.80 |
|
·
|
Decreased natural gas production of 12 percent, largely related to weather and normal production declines at existing properties, partially offset by production from the Green River Basin properties, which were acquired in late April 2010
|
|
·
|
Lower average realized natural gas prices of 9 percent
|
|
·
|
Increased lease operating expenses of $1.3 million (after tax), including higher well maintenance costs
|
|
·
|
Higher production and property taxes of $900,000 (after tax), largely resulting from higher oil prices excluding hedges
|
|
·
|
Higher depreciation, depletion and amortization expense of $600,000 (after tax), due to higher depletion rates
|
|
·
|
Decreased oil production of 1 percent, largely related to weather and normal production declines at existing properties, partially offset by drilling activity in the Bakken area, as well as from the South Texas properties
|
|
·
|
Lower average realized natural gas prices of 13 percent
|
|
·
|
Decreased natural gas production of 8 percent, as previously discussed
|
|
·
|
Higher depreciation, depletion and amortization expense of $3.4 million (after tax), as previously discussed
|
|
·
|
Increased lease operating expenses of $2.7 million (after tax), including higher well maintenance costs and costs associated with properties acquired in late April 2010
|
|
·
|
Higher production and property taxes of $1.3 million (after tax), largely resulting from higher oil prices excluding hedges
|
|
·
|
Higher average realized oil prices of 18 percent
|
|
·
|
Increased oil production of 2 percent, largely related to drilling activity in the Bakken area, as well as from the South Texas properties, partially offset by weather and normal production declines at certain properties
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(Dollars in millions)
|
||||||||||||||||
Operating revenues
|
$ | 375.6 | $ | 361.6 | $ | 519.2 | $ | 511.4 | ||||||||
Operating expenses:
|
||||||||||||||||
Operation and maintenance
|
334.2 | 316.9 | 481.1 | 462.9 | ||||||||||||
Depreciation, depletion and amortization
|
21.2 | 22.2 | 42.6 | 44.8 | ||||||||||||
Taxes, other than income
|
9.8 | 9.2 | 17.5 | 16.5 | ||||||||||||
365.2 | 348.3 | 541.2 | 524.2 | |||||||||||||
Operating income (loss)
|
10.4 | 13.3 | (22.0 | ) | (12.8 | ) | ||||||||||
Earnings (loss)
|
$ | 5.0 | $ | 5.7 | $ | (16.4 | ) | $ | (14.5 | ) | ||||||
Sales (000's):
|
||||||||||||||||
Aggregates (tons)
|
6,479 | 6,261 | 9,306 | 9,224 | ||||||||||||
Asphalt (tons)
|
1,842 | 1,579 | 2,007 | 1,733 | ||||||||||||
Ready-mixed concrete (cubic yards)
|
698 | 742 | 1,095 | 1,218 |
|
·
|
Lower earnings of $2.3 million (after tax), resulting from lower ready-mixed concrete and other product line margins and volumes, largely due to increased competition, less available work and weather-related delays, partially offset by higher asphalt volumes and margins
|
|
·
|
Lower gains of $1.6 million (after tax) from the sale of property, plant and equipment
|
|
·
|
Increased construction margins of $1.5 million (after tax), largely due to increased margins and volumes in the Pacific region
|
|
·
|
Lower selling, general and administrative costs of $800,000 (after tax), largely lower payroll-related costs and lower bad debt expense
|
|
·
|
Lower interest expense of $700,000 (after tax), primarily due to lower average interest rates
|
|
·
|
Lower earnings of $4.2 million (after tax), resulting from lower ready-mixed concrete margins and volumes and lower other product line margins, largely due to increased competition, less available work and weather-related delays, partially offset by higher asphalt volumes and margins
|
|
·
|
Lower gains of $1.4 million (after tax) from the sale of property, plant and equipment
|
|
·
|
Decreased construction margins of $1.3 million (after tax), primarily due to weather-related delays
|
|
·
|
Lower income taxes of $2.5 million, primarily related to an income tax benefit related to favorable resolution of certain income tax matters
|
|
·
|
Lower selling, general and administrative expense of $2.1 million (after tax), largely lower payroll-related costs
|
|
·
|
Lower interest expense of $800,000 (after tax), as previously discussed
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
June 30,
|
June 30,
|
|||||||||||||||
2011
|
2010
|
2011
|
2010
|
|||||||||||||
(In millions)
|
||||||||||||||||
Other:
|
||||||||||||||||
Operating revenues
|
$ | 2.8 | $ | 2.3 | $ | 5.3 | $ | 4.5 | ||||||||
Operation and maintenance
|
1.9 | 1.8 | 4.9 | 3.7 | ||||||||||||
Depreciation, depletion and amortization
|
.4 | .4 | .7 | .8 | ||||||||||||
Taxes, other than income
|
— | .1 | .1 | .1 | ||||||||||||
Intersegment transactions:
|
||||||||||||||||
Operating revenues
|
$ | 45.5 | $ | 42.8 | $ | 99.3 | $ | 108.1 | ||||||||
Purchased natural gas sold
|
34.3 | 36.8 | 81.2 | 95.8 | ||||||||||||
Operation and maintenance
|
11.2 | 6.0 | 18.1 | 12.3 |
·
|
Earnings per common share for 2011, diluted, are projected in the range of $1.05 to $1.30. The Company expects the approximate percentage of 2011 earnings per common share by quarter to be:
|
|
o
|
Third quarter – 30 percent
|
|
o
|
Fourth quarter – 30 percent
|
·
|
Although near term market conditions are uncertain, the Company’s long-term compound annual growth goals on earnings per share from operations are in the range of 7 percent to 10 percent.
|
·
|
The Company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.
|
·
|
In April 2010, the Company filed an application with the NDPSC for an electric rate increase, as discussed in Note 17.
|
·
|
In August 2010, the Company filed an application with the MTPSC for an electric rate increase, as discussed in Note 17.
|
·
|
On July 7, 2011, the Company filed for an advance determination of prudence with the NDPSC on the construction of an 88-MW simple cycle natural gas turbine and associated facilities, as discussed in Note 17.
|
·
|
The Company is analyzing potential projects for accommodating load growth in its industrial and agricultural sectors with company and customer owned pipeline facilities designed to serve existing facilities currently served by fuel oil or propane, and to serve new customers.
|
·
|
The Company is currently involved with a number of pipeline looping projects to enhance the reliability and deliverability of its system in the Pacific Northwest.
|
·
|
The Company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted towards delivery of renewable energy from the wind rich regions that lie within its traditional electric service territory to major market areas. The Company has 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. The proposed project will total approximately $20 million and will include substation upgrades with construction expected to begin in the third quarter 2011. Its customers would not bear any of the costs associated with the project as costs will be recovered through an approved interconnect tariff. The NDPSC has approved the route permits for this project. The project is expected to be completed in the first quarter of 2012. A major market party to the wind farm project has announced its intentions to withdraw from the project which may affect development and timing of the associated power line by the Company.
|
·
|
The South Dakota Board of Minerals and Environment has approved rules implementing the South Dakota Regional Haze Program that upon approval by the EPA will require the Big Stone Station to install and operate a BART air quality control system to reduce emissions of particulate matter, sulfur dioxide and nitrogen oxides as early as practicable, but not later than five years after EPA's approval of the state program. The state program was submitted January 21, 2011. The Company’s share of the cost of this air quality control system could exceed $100 million. At this time the Company believes continuing to operate Big Stone Station with the upgrade is the best option; however, it will continue to review alternatives. The Company intends to seek recovery of costs related to the above matter in electric rates charged to customers. On May 20, 2011, the Company filed for an advance determination of prudence with the NDPSC requesting advance determination that the air quality control system is reasonable and prudent, as discussed in Note 17.
|
·
|
Work backlog as of June 30, 2011, was approximately $364 million, compared to $389 million a year ago, and $347 million at March 31, 2011. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.
|
·
|
As a result of the continued slow economic recovery, the Company anticipates margins in 2011 to be comparable to 2010 levels.
|
·
|
The Company is pursuing expansion in high-voltage transmission and substation construction, renewable resource construction, governmental facilities, refinery turnaround projects and utility service work.
|
·
|
The Company continues to focus on costs and efficiencies to enhance margins. Selling, general and administrative expenses are down more than 30 percent for the trailing twelve months through June 30, 2011, compared to the annual expenses in 2008, the peak earnings year for this segment.
|
·
|
With its highly skilled technical workforce, this group is prepared to take advantage of government stimulus spending on transmission infrastructure.
|
·
|
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 of North Dakota and eastern Montana. It owns an extensive natural gas pipeline system in the Bakken area. Ongoing energy development is expected to have many direct and indirect benefits to this business.
|
·
|
The Company solicited customer interest in a 27 MMcf per day expansion of its existing natural gas pipeline in the Bakken production area in northwestern North Dakota in the first quarter of 2011. Sufficient customer interest was received to move forward on a project. Construction is underway and the capacity is projected to be in service in late third quarter of 2011.
|
·
|
Final preparations are underway for the construction of approximately 12 miles of high pressure transmission pipeline providing takeaway capacity from Bear Paw Energy's Garden Creek processing facility being constructed in northwestern North Dakota. The pipeline project is expected to be completed in the fourth quarter of 2011.
|
·
|
The Company has recently executed agreements to build approximately 13 miles of high pressure transmission pipeline from the Stateline I and II processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline. It has a projected completion date of mid 2012.
|
·
|
The Company has three natural gas storage fields including the largest storage field in North America located near Baker, Montana. It continues to seek interest in its storage services and is pursuing a project to increase its firm deliverability from the Baker Storage field by 125 MMcf per day. The Company has received commitment on approximately 30 percent of the total potential project and is moving forward on this phase with a projected in-service date of November 2011.
|
·
|
Capital expenditures in 2011 are expected to be approximately $300 million. The Company continues its focus on returns by allocating a growing portion of its capital investment into the production of oil in the current commodity price environment. Its capital program reflects further exploitation of existing properties, acquisition of additional leasehold acreage, and exploratory drilling. The 2011 planned capital expenditure total does not include potential acquisitions of producing properties.
|
·
|
For 2011, the Company expects a 1 percent to 5 percent increase in oil production offset by an 8 percent to 12 percent decrease in natural gas production, the result of extensive rain and flooding conditions that hampered operations in the Rocky Mountain region, as well as the deferral of some gas development activity because of sustained low natural gas prices. If natural gas prices recover, the Company believes it is positioned to spend additional capital on drilling its low cost natural gas properties.
|
·
|
The Company added a second drilling rig in the Bakken early in the second quarter of 2011.
|
·
|
Bakken – Mountrail County, North Dakota
|
|
o
|
The Company owns approximately 16,000 net acres of leaseholds targeting the middle Bakken and Three Forks formations. The drilling of 15 operated and participation in various non-operated wells is planned for 2011 with approximately $55 million of capital expenditures. Plans include drilling 17 wells or more annually in 2012 and 2013.
|
o
|
Over 50 future wells sites have been identified. Estimated gross ultimate recovery per well is 250,000 to 500,000 Bbls.
|
·
|
Bakken – Stark County, North Dakota
|
|
o
|
The Company holds approximately 50,000 net exploratory leasehold acres, targeting the Three Forks formation. It anticipates drilling 3 operated wells on this acreage and participating in various non-operated wells in 2011 with capital of approximately $30 million.
|
|
o
|
Based on well results, the Company plans to drill 6 or more wells annually beginning in 2012.
|
|
o
|
Based on 640-acre spacing, the acreage holds over 75 potential drill sites. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.
|
·
|
Bakken – Richland County, Montana
|
|
o
|
The Company recently acquired approximately 20,000 net exploratory leasehold acres, targeting the Three Forks formation.
|
·
|
Niobrara – southeastern Wyoming
|
|
o
|
The Company holds approximately 65,000 net exploratory leasehold acres in this emerging oil play. It is completing seismic evaluation work on this acreage and expects to begin drilling 4 exploratory wells in 2011.
|
|
o
|
If successful, the Company plans to initiate a drilling program of approximately 8 wells annually starting in 2012.
|
|
o
|
The Company also expects to participate in various non-operated wells in the Niobrara.
|
|
o
|
The Company has more than 100 future locations on this acreage based on 640-acre spacing. Although this is an emerging exploratory play, early results by certain other
|
|
producers appear promising.
|
·
|
Paradox Basin – Cane Creek Federal Unit, Utah
|
|
o
|
The Company holds approximately 75,000 net exploratory leasehold acres.
|
|
o
|
An Environmental Assessment for 9 wells was recently received by the Company.
|
|
o
|
The Company is evaluating its drilling options.
|
·
|
Texas
|
|
o
|
The Company is targeting areas that have the potential for higher liquids content. It has approximately $50 million of capital targeted in 2011.
|
·
|
Other Opportunities
|
|
o
|
The Company holds approximately 80,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana. Plans include drilling 1 or 2 appraisal wells in 2011.
|
|
o
|
The Company continues to pursue acquisitions of additional leaseholds. Approximately $50 million of capital has been allocated to leasehold acquisitions in 2011, focusing on expansion of existing positions and new opportunities.
|
·
|
Earnings guidance reflects estimated natural gas and oil prices for August through December as follows:
|
Index*
|
Price Per Mcf/Bbl
|
Natural gas:
|
|
NYMEX
|
$4.00 to $4.50
|
Ventura
|
$3.75 to $4.25
|
CIG
|
$3.75 to $4.25
|
Oil:
|
|
NYMEX
|
$90.00 to $95.00
|
* Ventura is an index pricing point related to Northern Natural Gas Co.'s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s system.
|
·
|
For the last six months of 2011, the Company has hedged approximately 55 percent to 60 percent of its estimated natural gas production and 60 percent to 65 percent of its estimated oil production. For 2012, it has hedged 20 percent to 25 percent of its estimated natural gas production and 45 percent to 50 percent of its estimated oil production. The hedges that are in place as of August 1, 2011, are summarized in the following chart:
|
Commodity
|
Type
|
Index
|
Period
Outstanding
|
Forward
Notional
Volume
(MMBtu/Bbl)
|
Price
(Per MMBtu/Bbl)
|
Natural Gas
|
Swap
|
HSC
|
7/11 - 12/11
|
680,800
|
$8.00
|
Natural Gas
|
Swap
|
NYMEX
|
7/11 - 12/11
|
2,024,000
|
$6.1027
|
Natural Gas
|
Swap
|
NYMEX
|
7/11 - 12/11
|
1,840,000
|
$5.4975
|
Natural Gas
|
Swap
|
NYMEX
|
7/11 - 12/11
|
1,840,000
|
$4.58
|
Natural Gas
|
Swap
|
NYMEX
|
7/11 - 12/11
|
1,840,000
|
$4.70
|
Natural Gas
|
Swap
|
NYMEX
|
7/11 - 12/11
|
1,840,000
|
$4.75
|
Natural Gas
|
Swap
|
NYMEX
|
7/11 - 10/11
|
1,230,000
|
$4.775
|
Natural Gas
|
Swap
|
Ventura
|
7/11 - 10/11
|
1,230,000
|
$4.365
|
Natural Gas
|
Swap
|
NYMEX
|
1/12 - 12/12
|
3,477,000
|
$6.27
|
Natural Gas
|
Swap
|
NYMEX
|
1/12 - 12/12
|
1,830,000
|
$5.005
|
Natural Gas
|
Swap
|
NYMEX
|
1/12 - 12/12
|
915,000
|
$5.005
|
Natural Gas
|
Swap
|
NYMEX
|
1/12 - 12/12
|
915,000
|
$5.0125
|
Natural Gas
|
Swap
|
Ventura
|
1/12 - 12/12
|
3,660,000
|
$4.87
|
Crude Oil
|
Collar
|
NYMEX
|
7/11 - 12/11
|
276,000
|
$80.00-$94.00
|
Crude Oil
|
Collar
|
NYMEX
|
7/11 - 12/11
|
184,000
|
$80.00-$89.00
|
Crude Oil
|
Collar
|
NYMEX
|
7/11 - 12/11
|
92,000
|
$77.00-$86.45
|
Crude Oil
|
Collar
|
NYMEX
|
7/11 - 12/11
|
92,000
|
$75.00-$88.00
|
Crude Oil
|
Swap
|
NYMEX
|
7/11 - 12/11
|
184,000
|
$81.35
|
Crude Oil
|
Swap
|
NYMEX
|
7/11 - 12/11
|
92,000
|
$85.85
|
Crude Oil
|
Put Option
|
NYMEX
|
7/11 - 12/11
|
184,000
|
$80.00*
|
Crude Oil
|
Call Option
|
NYMEX
|
7/11 - 12/11
|
184,000
|
$103.00*
|
Crude Oil
|
Collar
|
NYMEX
|
1/12 - 12/12
|
366,000
|
$80.00-$87.80
|
Crude Oil
|
Collar
|
NYMEX
|
1/12 - 12/12
|
366,000
|
$80.00-$94.50
|
Crude Oil
|
Collar
|
NYMEX
|
1/12 - 12/12
|
366,000
|
$80.00-$98.36
|
Crude Oil
|
Collar
|
NYMEX
|
1/12 - 12/12
|
183,000
|
$85.00-$102.75
|
Crude Oil
|
Collar
|
NYMEX
|
1/12 - 12/12
|
183,000
|
$85.00-$103.00
|
Crude Oil
|
Swap
|
NYMEX
|
1/12 - 12/12
|
183,000
|
$100.10
|
Crude Oil
|
Swap
|
NYMEX
|
1/12 - 12/12
|
183,000
|
$100.00
|
Crude Oil
|
Swap
|
NYMEX
|
1/12 - 12/12
|
366,000
|
$110.30
|
Crude Oil
|
Collar
|
NYMEX
|
1/13 - 12/13
|
182,500
|
$95.00-$117.00
|
Crude Oil
|
Collar
|
NYMEX
|
1/13 - 12/13
|
182,500
|
$95.00-$117.00
|
Natural Gas
|
Basis Swap
|
CIG
|
7/11 - 12/11
|
2,024,000
|
$0.395
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/11 - 12/11
|
1,840,000
|
$0.15
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/11 - 12/11
|
920,000
|
$0.15
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/11 - 12/11
|
460,000
|
$0.16
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/11 - 12/11
|
1,840,000
|
$0.16
|
Natural Gas
|
Basis Swap
|
Ventura
|
7/11 - 12/11
|
2,300,000
|
$0.155
|
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
|
* Deferred premium of $4.00. Put option was purchased. Call option was sold.
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, 2011, was approximately $649 million, with 93 percent of construction backlog being public work and private representing 7 percent. In the Company’s peak earnings year of 2006, private backlog represented 40 percent of construction backlog. Backlog a year ago was $677 million. Total backlog at March 31, 2011, was $569 million.
|
·
|
Examples of projects in work backlog include several highway paving projects, airports, bridge work, reclamation and harbor expansion projects.
|
·
|
The Company is part of a joint venture that was selected as the low bidder on the Port of Long Beach expansion. Its share of the project for this phase is expected to exceed $25 million. The Company has green fielded an operation in Williston, North Dakota and was recently awarded a $33 million highway project in the Bakken area of North Dakota. It also expects to place a new asphalt oil terminal into service in late 2011 in Wyoming.
|
·
|
As a result of the continued slow recovery in the residential and commercial markets and uncertainty in federal and state transportation funding, the Company expects overall 2011 volumes to be comparable to 2010.
|
·
|
Federal transportation stimulus of $7.9 billion was directed to states where the Company operates. Of that amount, 74 percent was spent as of June 30, 2011, with the majority of the remaining $2.0 billion to be spent during the remainder of 2011.
|
·
|
The Company is the primary cement provider and has the opportunity to supply a portion of the ready-mixed concrete and aggregate related to a multi-phased light rail project in Hawaii.
|
·
|
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 more than 40 percent for the trailing twelve months through June 30, 2011, compared to the annual expenses in 2006, the peak earnings year for this segment.
|
·
|
As the country’s 5th largest sand and gravel producer, the Company will continue to strategically manage its 1.1 billion tons of aggregate reserves in all its markets, as well as take further advantage of being vertically integrated.
|
·
|
Of the nine labor contracts that Knife River was negotiating, as reported in Items 1 and 2 – Business and Properties – General in the 2010 Annual Report, six have been ratified. The three remaining contracts are still in negotiations.
|
|
·
|
System upgrades
|
|
·
|
Routine replacements
|
|
·
|
Service extensions
|
|
·
|
Routine equipment maintenance and replacements
|
|
·
|
Buildings, land and building improvements
|
|
·
|
Pipeline and gathering projects
|
|
·
|
Further development of existing properties, acquisition of additional leasehold acreage and exploratory drilling at the natural gas and oil production segment
|
|
·
|
Power generation opportunities, including certain costs for additional electric generating capacity
|
|
·
|
Environmental upgrades
|
|
·
|
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)
|
$ | 100.0 | $ | — |
(b)
|
$ | — |
5/26/15
|
|||||||||
Cascade Natural Gas Corporation
|
Revolving credit agreement
|
$ | 50.0 |
(c)
|
$ | — | $ | 1.9 |
(d)
|
12/28/12
|
(e)
|
||||||||
Intermountain Gas Company
|
Revolving credit agreement
|
$ | 65.0 |
(f)
|
$ | — | $ | — |
8/11/13
|
||||||||||
Centennial Energy Holdings, Inc.
|
Commercial paper/Revolving credit agreement
|
(g)
|
$ | 400.0 | $ | 6.0 |
(b)
|
$ | 24.9 |
(d)
|
12/13/12
|
||||||||
Williston Basin Interstate Pipeline Company
|
Uncommitted long-term private shelf agreement
|
$ | 125.0 | $ | 87.5 | $ | — |
12/23/11
|
(h)
|
(a)
|
The $125 million commercial paper program is supported by a revolving credit agreement with various banks totaling $100 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)
|
Certain provisions allow for increased borrowings, up to a maximum of $75 million.
|
(d)
|
The outstanding letters of credit, as discussed in Note 18, reduce amounts available under the credit agreement.
|
(e)
|
Provisions allow for an extension of up to two years upon consent of the banks.
|
(f)
|
Certain provisions allow for increased borrowings, up to a maximum of $80 million.
|
(g)
|
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.
|
(h)
|
Represents expiration of the ability to borrow additional funds under the 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 2011
|
$ | 5.19 | 12,525 | $ | 9,191 | ||||||||
Natural gas swap agreements maturing in 2012
|
$ | 5.37 | 10,797 | $ | 6,005 | ||||||||
Natural gas basis swap agreements maturing in 2011
|
$ | .21 | 9,384 | $ | (1,328 | ) | |||||||
Natural gas basis swap agreements maturing in 2012
|
$ | .41 | 3,477 | $ | (224 | ) | |||||||
Oil swap agreements maturing in 2011
|
$ | 82.85 | 276 | $ | (3,874 | ) | |||||||
Oil swap agreements maturing in 2012
|
$ | 105.18 | 732 | $ | 3,740 | ||||||||
Cascade
|
|||||||||||||
Natural gas swap agreement maturing in 2011
|
$ | 6.67 | 371 | $ | (902 | ) | |||||||
Natural gas swap agreements maturing in 2012
|
$ | 4.47 | 305 | $ | 11 | ||||||||
Weighted
Average
Floor/Ceiling
Price (Per Bbl)
|
Forward
Notional
Volume
(Bbl)
|
Fair Value
|
|||||||||||
Fidelity
|
|||||||||||||
Oil collar agreements maturing in 2011
|
$78.86/$90.64 | 644 | $ | (5,370 | ) | ||||||||
Oil collar agreements maturing in 2012
|
$81.25/$95.88 | 1,464 | $ | (13,166 | ) | ||||||||
Oil collar agreements maturing in 2013
|
$95.00/$117.00 | 365 | $ | 1,363 | |||||||||
Deferred Premium
|
Weighted Average Floor (Per Bbl)
|
Forward Notional Volume (Bbl)
|
Fair Value
|
||||||||||
Fidelity
|
|||||||||||||
Oil put agreement maturing in 2011
|
$4.00
|
$ | 80.00 | 184 | $ | (547 | ) | ||||||
Oil call agreement maturing in 2011
|
$4.00
|
$ | 103.00 | 184 | $ | 179 |
|
1.
|
Citations issued under section 104(a) of the Mine Safety Act for violations that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard.
|
|
2.
|
Orders issued under section 104(b) of the Mine Safety Act. Orders are issued under this section when citations issued under section 104(a) have not been totally abated within the time period allowed by the citation or subsequent extensions.
|
|
3.
|
Citations or orders issued under section 104(d) of the Mine Safety Act. Citations or orders are issued under this section when it has been determined that the violation is caused by an unwarrantable failure of the mine operator to comply with the standards. An unwarrantable failure occurs when the mine operator is deemed to have engaged in aggravated conduct constituting more than ordinary negligence.
|
|
4.
|
Citations issued under Section 110(b)(2) of the Mine Safety Act for flagrant violations. Violations are considered flagrant for repeat or reckless failures to make reasonable efforts to eliminate a known violation of a mandatory health and safety standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.
|
|
5.
|
Imminent danger orders issued under Section 107(a) of the Mine Safety Act. An imminent danger is defined as the existence of any condition or practice in a coal or other mine which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated.
|
|
6.
|
Notice received under Section 104(e) of the Mine Safety Act of a pattern of violations or the potential to have such a pattern of violations that could significantly and substantially contribute to the cause and effect of mine health and safety standards.
|
Mine
|
State
|
Section
104(a)
Citations
Issued
|
Section
107(a)
Citations
Issued
|
Citations
Contested
|
Proposed Assessments Levied
|
Outstanding as of June 30, 2011
|
|||||||||||||||
Klatt Terminal
|
AK
|
2 | — | — | $ | — | $ | — | |||||||||||||
Concrete, Inc.
|
CA
|
— | — | — | 263 | — | |||||||||||||||
Hallwood Plant
|
CA
|
1 | — | 2 | — | — | |||||||||||||||
Orland Plant
|
CA
|
3 | — | 8 | — | — | |||||||||||||||
Pebbly Beach Quarry
|
CA
|
4 | 1 | 4 | 2,015 | 1,815 | |||||||||||||||
Vernalis
|
CA
|
— | — | — | 100 | — | |||||||||||||||
Halawa Valley
|
HI
|
— | — | — | 815 | 22,490 | |||||||||||||||
Kona Sand Plant
|
HI
|
— | — | — | 100 | — | |||||||||||||||
Portable 1
|
HI
|
3 | — | — | 1,306 | — | |||||||||||||||
Portable 2
|
HI
|
— | — | — | 300 | — | |||||||||||||||
Puunene Quarry
|
HI
|
— | — | — | — | 660 | |||||||||||||||
Waikapu Quarry
|
HI
|
2 | 1 | — | 200 | 100 | |||||||||||||||
Waimea Quarry
|
HI
|
— | — | — | — | 238 | |||||||||||||||
Becker Wash Plant #1
|
IA
|
2 | — | — | — | — | |||||||||||||||
Crusher #1
|
ID
|
— | — | — | 200 | 100 | |||||||||||||||
Anderson Pit
|
MN
|
1 | — | — | — | — | |||||||||||||||
Kalispell Wash Plant
|
MT
|
2 | — | — | — | — | |||||||||||||||
Portable Crusher #1
|
MT
|
1 | — | — | — | — | |||||||||||||||
Dralle Pit
|
ND
|
— | — | — | 200 | — | |||||||||||||||
McKenzie Pit
|
ND
|
1 | — | — | — | — | |||||||||||||||
Pioneer
|
ND
|
2 | — | — | — | 18,500 | |||||||||||||||
Wienmann Pit
|
ND
|
— | — | — | 2,104 | — | |||||||||||||||
Coffee Lake
|
OR
|
— | — | — | 100 | — | |||||||||||||||
Coffin Butte
|
OR
|
— | — | — | 300 | — | |||||||||||||||
Eugene
|
OR
|
— | — | — | 100 | — | |||||||||||||||
Fisher Island
|
OR
|
— | — | — | 723 | — | |||||||||||||||
Gresham S & G
|
OR
|
1 | — | — | 625 | — | |||||||||||||||
Kirkland
|
OR
|
— | — | — | 300 | — | |||||||||||||||
Lone Pine Portable
|
OR
|
— | — | — | — | 100 | |||||||||||||||
Paetsch Pit
|
OR
|
— | — | — | — | 112 | |||||||||||||||
Salem-Reed Pit
|
OR
|
— | — | 4 | 794 | 478 | |||||||||||||||
Sullivan Quarry MC1
|
OR
|
2 | — | — | 200 | 200 | |||||||||||||||
Watters Quarry
|
OR
|
— | — | — | 100 | — | |||||||||||||||
Sky High Pit
|
TX
|
2 | — | 1 | — | — | |||||||||||||||
Star Pit #1
|
WY
|
1 | — | 5 | 700 | 500 | |||||||||||||||
Total
|
30 | 2 | 24 | $ | 11,545 | $ | 45,293 |
Mine
|
State
|
Month Citation Issued
|
Contest Initiated By
|
Category of Violation
|
Proposed Assessments Levied (Dollars) | * | Month Citation Closed | ** | Result of Contest | ** | ||||||||||||
Hallwood Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | $ | 100 | — | — | ||||||||||||
Hallwood Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | 1,304 | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Orland Plant
|
CA
|
4/2011 | *** |
Operator
|
104 | (a) | — | — | — | |||||||||||||
Pebbly Beach
|
CA
|
5/2011 | *** |
Operator
|
104 | (a) | 555 | — | — | |||||||||||||
Pebbly Beach
|
CA
|
5/2011 | *** |
Operator
|
104 | (a) | 555 | — | — | |||||||||||||
Pebbly Beach
|
CA
|
5/2011 | *** |
Operator
|
104 | (a) | 555 | — | — | |||||||||||||
Pebbly Beach
|
CA
|
5/2011 | *** |
Operator
|
107 | (a) | — | — | — | |||||||||||||
Waikapu Quarry
|
HI
|
2/2011 |
Operator
|
104 | (a) | 100 | 5/2011 |
No Change
|
||||||||||||||
Waikapu Quarry
|
HI
|
2/2011 |
Operator
|
104 | (a) | 117 | 5/2011 |
No Change
|
||||||||||||||
Little Falls
|
MN
|
10/2010 |
Operator
|
104 | (a) | 100 | 1/2011 |
No Change
|
||||||||||||||
Little Falls
|
MN
|
11/2010 |
Operator
|
104 | (a) | 100 | 1/2011 |
No Change
|
||||||||||||||
Rittenour Pit
|
MN
|
10/2010 |
Operator
|
104 | (a) | 100 | 4/2011 |
No Change
|
||||||||||||||
Rittenour Pit
|
MN
|
10/2010 |
Operator
|
104 | (a) | 100 | 4/2011 |
No Change
|
||||||||||||||
Rittenour Pit
|
MN
|
10/2010 |
Operator
|
104 | (a) | 362 | 4/2011 |
No Change
|
||||||||||||||
Rockville 3
|
MN
|
11/2010 |
Operator
|
104 | (d) | 2,400 | — | — | ||||||||||||||
T Olson Pit
|
MN
|
10/2010 |
Operator
|
104 | (a) | 392 | 6/2011 |
Vacated
|
||||||||||||||
T Olson Pit
|
MN
|
10/2010 |
Operator
|
104 | (a) | 100 | 6/2011 |
Reduced
|
||||||||||||||
T Olson Pit
|
MN
|
10/2010 |
Operator
|
104 | (a) | 100 | 6/2011 |
Reduced
|
||||||||||||||
Bender Pit
|
ND
|
8/2010 |
Operator
|
104 | (a) | 162 | 4/2011 |
No Change
|
||||||||||||||
Bender Pit
|
ND
|
8/2010 |
Operator
|
104 | (a) | 100 | 4/2011 |
No Change
|
||||||||||||||
Lone Pine
|
OR
|
7/2010 |
Operator
|
104 | (a) | 100 | — | — | ||||||||||||||
Paetsch Pit
|
OR
|
12/2010 |
Operator
|
104 | (a) | 112 | — | — | ||||||||||||||
Paetsch Pit
|
OR
|
1/2011 |
Operator
|
104 | (b) | — | — | — | ||||||||||||||
Quality Rock
|
OR
|
11/2010 |
Operator
|
104 | (d) | — | — | — | ||||||||||||||
Quality Rock
|
OR
|
11/2010 |
Operator
|
104 | (d) | — | — | — | ||||||||||||||
Quality Rock
|
OR
|
11/2010 |
Operator
|
104 | (d) | — | — | — | ||||||||||||||
Salem-Reed Pit
|
OR
|
2/2011 | *** |
Operator
|
104 | (a) | 108 | — | — | |||||||||||||
Salem-Reed Pit
|
OR
|
2/2011 | *** |
Operator
|
104 | (a) | 162 | — | — | |||||||||||||
Salem-Reed Pit
|
OR
|
2/2011 | *** |
Operator
|
104 | (a) | 108 | — | — | |||||||||||||
Salem-Reed Pit
|
OR
|
2/2011 | *** |
Operator
|
104 | (a) | 100 | — | — | |||||||||||||
Sky High Pit
|
TX
|
1/2011 | **** |
Operator
|
104 | (a) | 424 | — | — | |||||||||||||
Star Pit #1
|
WY
|
3/2011 | *** |
Operator
|
104 | (a) | 100 | — | — | |||||||||||||
Star Pit #1
|
WY
|
3/2011 | *** |
Operator
|
104 | (a) | 100 | — | — |
Star Pit #1
|
WY
|
4/2011 | *** |
Operator
|
104 | (a) | 100 | — | — | |||||||||||||
Star Pit #1
|
WY
|
4/2011 | *** |
Operator
|
104 | (a) | 100 | — | — | |||||||||||||
Star Pit #1
|
WY
|
4/2011 | *** |
Operator
|
104 | (a) | 100 | — | — | |||||||||||||
VR Pit
|
WY
|
11/2010 |
Operator
|
104 | (a) | 100 | — | — |
*
|
Assessments may not have yet been proposed for citations issued during the period for which the data is reported.
|
**
|
Results of citations contested will be reported as one of the following: Vacated – the citation was dropped; Reduced – the severity of the violation and/or the proposed assessment amount was reduced; or No Change – the citation was enforced as issued.
|
***
|
Contest initiated during the three months ended June 30, 2011.
|
MDU RESOURCES GROUP, INC.
|
|||
DATE: August 5, 2011
|
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)
|
Non-Employee Director Stock Compensation Plan, as amended May 12, 2011
|
+10(b)
|
Directors' Compensation Policy, as amended May 12, 2011
|
+10(c)
|
MDU Resources Group, Inc. Section 16 Officers and Directors with Indemnification Agreements Chart, as of June 30, 2011
|
+10(d)
|
Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated June 30, 2011
|
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, 2011, 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 in summary and detail
|