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ý
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
|
|
THE SECURITIES EXCHANGE ACT OF 1934
|
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
|
|
THE SECURITIES EXCHANGE ACT OF 1934
|
|
Delaware
|
|
41-0423660
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
|
Large accelerated filer
ý
|
Accelerated filer
o
|
|
Non-accelerated filer
o
|
Smaller reporting company
o
|
Abbreviation or Acronym
|
|
2011 Annual Report
|
Company's Annual Report on Form 10-K for the year ended December 31, 2011
|
Alusa
|
Tecnica de Engenharia Electrica - Alusa
|
ASC
|
FASB Accounting Standards Codification
|
BART
|
Best available retrofit technology
|
Bbl
|
Barrel
|
Bicent
|
Bicent Power LLC
|
Big Stone Station
|
450-MW coal-fired electric generating facility near Big Stone City, South Dakota (22.7 percent ownership)
|
BLM
|
Bureau of Land Management
|
BOE
|
One barrel of oil equivalent - determined using the ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf of natural gas
|
BOPD
|
Barrels of oil per day
|
Brazilian Transmission Lines
|
Company's equity method investment in the company owning ECTE, ENTE and ERTE (ownership interests in ENTE and ERTE were sold in the fourth quarter of 2010 and portions of the ownership interest in ECTE were sold in the third quarter of 2012 and the fourth quarters of 2011 and 2010)
|
Btu
|
British thermal unit
|
Cascade
|
Cascade Natural Gas Corporation, an indirect wholly owned subsidiary of MDU Energy Capital
|
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)
|
CEMIG
|
Companhia Energética de Minas Gerais
|
Centennial
|
Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of the Company
|
Centennial Capital
|
Centennial Holdings Capital LLC, a direct wholly owned subsidiary of Centennial
|
Centennial Resources
|
Centennial Energy Resources LLC, a direct wholly owned subsidiary of Centennial
|
Colorado State District Court
|
Colorado Thirteenth Judicial District Court, Yuma County
|
Company
|
MDU Resources Group, Inc.
|
dk
|
Decatherm
|
Dodd-Frank Act
|
Dodd-Frank Wall Street Reform and Consumer Protection Act
|
ECTE
|
Empresa Catarinense de Transmissão de Energia S.A. (5.01 percent ownership interest at September 30, 2012, 2.5, 2.5 and 14.99 percent ownership interests were sold in the third quarter of 2012 and the fourth quarters of 2011 and 2010, respectively)
|
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)
|
Exchange Act
|
Securities Exchange Act of 1934, as amended
|
FASB
|
Financial Accounting Standards Board
|
Fidelity
|
Fidelity Exploration & Production Company, a direct wholly owned subsidiary of WBI Holdings
|
FIP
|
Funding improvement plan
|
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
|
Hawaiian Cement
|
Hawaiian Cement, an indirect wholly owned subsidiary of Knife River
|
IFRS
|
International Financial Reporting Standards
|
Intermountain
|
Intermountain Gas Company, an indirect wholly owned subsidiary of MDU Energy Capital
|
IP rates
|
Initial production rates
|
JTL
|
JTL Group, Inc., an indirect wholly owned subsidiary of Knife River
|
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
|
kWh
|
Kilowatt-hour
|
LPP
|
Lea Power Partners, LLC, a former indirect wholly owned subsidiary of Centennial Resources (member interests were sold in October 2006)
|
LWG
|
Lower Willamette Group
|
MBbls
|
Thousands of barrels
|
MBOE
|
Thousands of BOE
|
Mcf
|
Thousand cubic feet
|
MDU Brasil
|
MDU Brasil Ltda., an indirect wholly owned subsidiary of Centennial Resources
|
MDU Construction Services
|
MDU Construction Services Group, Inc., a direct wholly owned subsidiary of Centennial
|
MDU Energy Capital
|
MDU Energy Capital, LLC, a direct wholly owned subsidiary of the Company
|
MMBtu
|
Million Btu
|
MMcf
|
Million cubic feet
|
MMdk
|
Million decatherms
|
Montana-Dakota
|
Montana-Dakota Utilities Co., a public utility division of the Company
|
Montana DEQ
|
Montana Department of Environmental Quality
|
Montana First Judicial District Court
|
Montana First Judicial District Court, Lewis and Clark County
|
Montana Seventeenth Judicial District Court
|
Montana Seventeenth Judicial District Court, Phillips County
|
MPPAA
|
Multiemployer Pension Plan Amendments Act of 1980
|
MTPSC
|
Montana Public Service Commission
|
MW
|
Megawatt
|
NDPSC
|
North Dakota Public Service Commission
|
New York Supreme Court
|
Supreme Court of the State of New York, County of New York
|
NSPS
|
New Source Performance Standards
|
Oil
|
Includes crude oil, condensate and natural gas liquids
|
Omimex
|
Omimex Canada, Ltd.
|
OPUC
|
Oregon Public Utility Commission
|
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
|
RP
|
Rehabilitation plan
|
SEC
|
U.S. Securities and Exchange Commission
|
SEC Defined Prices
|
The average price of oil and natural gas during the applicable 12-month period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions
|
Securities Act
|
Securities Act of 1933, as amended
|
SourceGas
|
SourceGas Distribution LLC
|
WBI Energy Midstream
|
WBI Energy Midstream, LLC an indirect wholly owned subsidiary of WBI Holdings (previously Bitter Creek Pipelines, LLC, name changed effective July 1, 2012)
|
WBI Energy Transmission
|
WBI Energy Transmission, Inc., an indirect wholly owned subsidiary of WBI Holdings (previously Williston Basin Interstate Pipeline Company, name changed effective July 1, 2012)
|
WBI Holdings
|
WBI Holdings, Inc., a direct wholly owned subsidiary of Centennial
|
WI
|
Working interest
|
WUTC
|
Washington Utilities and Transportation Commission
|
Part I -- Financial Information
|
Page
|
|
|
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2012 and 2011
|
|
|
|
Consolidated Statements of Comprehensive Income --
Three and Nine Months Ended September 30, 2012 and 2011
|
|
|
|
Consolidated Balance Sheets --
September 30, 2012 and 2011, and December 31, 2011
|
|
|
|
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 2012 and 2011
|
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
|
|
|
Quantitative and Qualitative Disclosures About Market Risk
|
|
|
|
Controls and Procedures
|
|
|
|
Part II -- Other Information
|
|
|
|
Legal Proceedings
|
|
|
|
Risk Factors
|
|
|
|
Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
Mine Safety Disclosures
|
|
|
|
Exhibits
|
|
|
|
Signatures
|
|
|
|
Exhibit Index
|
|
|
|
Exhibits
|
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
2011
|
2012
|
2011
|
||||||||
|
(In thousands, except per share amounts)
|
|||||||||||
Operating revenues:
|
|
|
|
|
||||||||
Electric, natural gas distribution and pipeline and energy services
|
$
|
184,863
|
|
$
|
212,848
|
|
$
|
784,399
|
|
$
|
964,866
|
|
Exploration and production, construction materials and contracting, construction services and other
|
988,655
|
|
939,333
|
|
2,209,889
|
|
2,019,877
|
|
||||
Total operating revenues
|
1,173,518
|
|
1,152,181
|
|
2,994,288
|
|
2,984,743
|
|
||||
Operating expenses:
|
|
|
|
|
|
|
|
|
||||
Fuel and purchased power
|
17,634
|
|
17,357
|
|
51,247
|
|
48,784
|
|
||||
Purchased natural gas sold
|
35,199
|
|
50,102
|
|
279,038
|
|
396,326
|
|
||||
Operation and maintenance:
|
|
|
|
|
|
|
|
|
||||
Electric, natural gas distribution and pipeline and energy services
|
67,830
|
|
69,475
|
|
188,945
|
|
207,465
|
|
||||
Exploration and production, construction materials and contracting, construction services and other
|
793,850
|
|
767,519
|
|
1,793,347
|
|
1,663,927
|
|
||||
Depreciation, depletion and amortization
|
91,850
|
|
88,897
|
|
260,858
|
|
256,861
|
|
||||
Taxes, other than income
|
41,090
|
|
39,410
|
|
132,017
|
|
131,591
|
|
||||
Write-down of oil and natural gas properties (Note 5)
|
160,100
|
|
—
|
|
160,100
|
|
—
|
|
||||
Total operating expenses
|
1,207,553
|
|
1,032,760
|
|
2,865,552
|
|
2,704,954
|
|
||||
Operating income (loss)
|
(34,035
|
)
|
119,421
|
|
128,736
|
|
279,789
|
|
||||
Earnings from equity method investments
|
2,388
|
|
826
|
|
4,025
|
|
2,260
|
|
||||
Other income
|
1,702
|
|
1,282
|
|
4,050
|
|
5,090
|
|
||||
Interest expense
|
19,840
|
|
19,589
|
|
56,929
|
|
61,642
|
|
||||
Income (loss) before income taxes
|
(49,785
|
)
|
101,940
|
|
79,882
|
|
225,497
|
|
||||
Income taxes
|
(20,253
|
)
|
37,840
|
|
24,516
|
|
73,632
|
|
||||
Income (loss) from continuing operations
|
(29,532
|
)
|
64,100
|
|
55,366
|
|
151,865
|
|
||||
Income (loss) from discontinued operations, net of tax (Note 9)
|
(139
|
)
|
(126
|
)
|
4,867
|
|
154
|
|
||||
Net income (loss)
|
(29,671
|
)
|
63,974
|
|
60,233
|
|
152,019
|
|
||||
Dividends declared on preferred stocks
|
171
|
|
171
|
|
514
|
|
514
|
|
||||
Earnings (loss) on common stock
|
$
|
(29,842
|
)
|
$
|
63,803
|
|
$
|
59,719
|
|
$
|
151,505
|
|
|
|
|
|
|
||||||||
Earnings (loss) per common share - basic:
|
|
|
|
|
|
|
|
|
||||
Earnings (loss) before discontinued operations
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.29
|
|
$
|
.80
|
|
Discontinued operations, net of tax
|
—
|
|
—
|
|
.03
|
|
—
|
|
||||
Earnings (loss) per common share - basic
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.32
|
|
$
|
.80
|
|
|
|
|
|
|
||||||||
Earnings (loss) per common share - diluted:
|
|
|
|
|
|
|
|
|
||||
Earnings (loss) before discontinued operations
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.29
|
|
$
|
.80
|
|
Discontinued operations, net of tax
|
—
|
|
—
|
|
.03
|
|
—
|
|
||||
Earnings (loss) per common share - diluted
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.32
|
|
$
|
.80
|
|
|
|
|
|
|
||||||||
Dividends declared per common share
|
$
|
.1675
|
|
$
|
.1625
|
|
$
|
.5025
|
|
$
|
.4875
|
|
|
|
|
|
|
||||||||
Weighted average common shares outstanding - basic
|
188,831
|
|
188,794
|
|
188,824
|
|
188,753
|
|
||||
|
|
|
|
|
||||||||
Weighted average common shares outstanding - diluted
|
188,831
|
|
188,797
|
|
189,029
|
|
188,760
|
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
2011
|
2012
|
2011
|
||||||||
|
(In thousands)
|
|||||||||||
Net income (loss)
|
$
|
(29,671
|
)
|
$
|
63,974
|
|
$
|
60,233
|
|
$
|
152,019
|
|
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 $(5,377) and $19,481 for the three months ended and $4,570 and $19,367 for the nine months ended in 2012 and 2011, respectively
|
(9,125
|
)
|
32,547
|
|
7,962
|
|
31,787
|
|
||||
Less: Reclassification adjustment for gain (loss) on derivative instruments included in net income (loss), net of tax of $4,570 and $(320) for the three months ended and $4,126 and $45 for the nine months ended in 2012 and 2011, respectively
|
7,782
|
|
(534
|
)
|
7,029
|
|
77
|
|
||||
Net unrealized gain (loss) on derivative instruments qualifying as hedges
|
(16,907
|
)
|
33,081
|
|
933
|
|
31,710
|
|
||||
Foreign currency translation adjustment, net of tax of $(8) and $(905) for the three months ended and $(273) and $(736) for the nine months ended in 2012 and 2011, respectively
|
(5
|
)
|
(1,401
|
)
|
(440
|
)
|
(1,140
|
)
|
||||
Net unrealized gain on available-for-sale investments, net of tax of $21 and $0 for the three months ended and $32 and $56 for the nine months ended in 2012 and 2011, respectively
|
39
|
|
—
|
|
60
|
|
103
|
|
||||
Other comprehensive income (loss)
|
(16,873
|
)
|
31,680
|
|
553
|
|
30,673
|
|
||||
Comprehensive income (loss)
|
$
|
(46,544
|
)
|
$
|
95,654
|
|
$
|
60,786
|
|
$
|
182,692
|
|
|
September 30, 2012
|
September 30, 2011
|
December 31, 2011
|
||||||
(In thousands, except shares and per share amounts)
|
|
||||||||
ASSETS
|
|
|
|
||||||
Current assets:
|
|
|
|
||||||
Cash and cash equivalents
|
$
|
74,242
|
|
$
|
118,702
|
|
$
|
162,772
|
|
Receivables, net
|
743,274
|
|
641,389
|
|
646,251
|
|
|||
Inventories
|
315,767
|
|
269,569
|
|
274,205
|
|
|||
Deferred income taxes
|
25,345
|
|
14,713
|
|
40,407
|
|
|||
Commodity derivative instruments
|
19,193
|
|
38,794
|
|
27,687
|
|
|||
Prepayments and other current assets
|
71,579
|
|
48,851
|
|
43,316
|
|
|||
Total current assets
|
1,249,400
|
|
1,132,018
|
|
1,194,638
|
|
|||
Investments
|
102,139
|
|
109,249
|
|
109,424
|
|
|||
Property, plant and equipment
|
8,129,872
|
|
7,506,833
|
|
7,646,222
|
|
|||
Less accumulated depreciation, depletion and amortization
|
3,546,927
|
|
3,307,433
|
|
3,361,208
|
|
|||
Net property, plant and equipment
|
4,582,945
|
|
4,199,400
|
|
4,285,014
|
|
|||
Deferred charges and other assets:
|
|
|
|
|
|
|
|||
Goodwill
|
636,039
|
|
634,931
|
|
634,931
|
|
|||
Other intangible assets, net
|
18,015
|
|
22,248
|
|
20,843
|
|
|||
Other
|
314,133
|
|
262,107
|
|
311,275
|
|
|||
Total deferred charges and other assets
|
968,187
|
|
919,286
|
|
967,049
|
|
|||
Total assets
|
$
|
6,902,671
|
|
$
|
6,359,953
|
|
$
|
6,556,125
|
|
|
|
|
|
||||||
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|||
Current liabilities:
|
|
|
|
|
|
|
|||
Short-term borrowings
|
$
|
11,000
|
|
$
|
—
|
|
$
|
—
|
|
Long-term debt due within one year
|
240,564
|
|
76,600
|
|
139,267
|
|
|||
Accounts payable
|
402,241
|
|
305,695
|
|
337,228
|
|
|||
Taxes payable
|
54,903
|
|
77,190
|
|
70,176
|
|
|||
Dividends payable
|
31,800
|
|
30,850
|
|
31,794
|
|
|||
Accrued compensation
|
48,792
|
|
44,100
|
|
47,804
|
|
|||
Commodity derivative instruments
|
2,072
|
|
3,028
|
|
13,164
|
|
|||
Other accrued liabilities
|
233,773
|
|
226,986
|
|
259,320
|
|
|||
Total current liabilities
|
1,025,145
|
|
764,449
|
|
898,753
|
|
|||
Long-term debt
|
1,502,413
|
|
1,347,014
|
|
1,285,411
|
|
|||
Deferred credits and other liabilities:
|
|
|
|
|
|
|
|||
Deferred income taxes
|
797,249
|
|
746,946
|
|
769,166
|
|
|||
Other liabilities
|
834,934
|
|
710,465
|
|
827,228
|
|
|||
Total deferred credits and other liabilities
|
1,632,183
|
|
1,457,411
|
|
1,596,394
|
|
|||
Commitments and contingencies
|
|
|
|
|
|
|
|||
Stockholders' equity
:
|
|
|
|
|
|
|
|||
Preferred stocks
|
15,000
|
|
15,000
|
|
15,000
|
|
|||
Common stockholders' equity:
|
|
|
|
|
|
|
|||
Common stock
|
|
|
|
|
|
|
|||
Authorized - 500,000,000 shares, $1.00 par value
|
|
|
|
||||||
Shares issued - 189,369,450 at September 30, 2012, 189,332,485 at
September 30, 2011 and 189,332,485 at December 31, 2011
|
189,369
|
|
189,332
|
|
189,332
|
|
|||
Other paid-in capital
|
1,038,066
|
|
1,034,411
|
|
1,035,739
|
|
|||
Retained earnings
|
1,550,569
|
|
1,556,550
|
|
1,586,123
|
|
|||
Accumulated other comprehensive loss
|
(46,448
|
)
|
(588
|
)
|
(47,001
|
)
|
|||
Treasury stock at cost - 538,921 shares
|
(3,626
|
)
|
(3,626
|
)
|
(3,626
|
)
|
|||
Total common stockholders' equity
|
2,727,930
|
|
2,776,079
|
|
2,760,567
|
|
|||
Total stockholders' equity
|
2,742,930
|
|
2,791,079
|
|
2,775,567
|
|
|||
Total liabilities and stockholders' equity
|
$
|
6,902,671
|
|
$
|
6,359,953
|
|
$
|
6,556,125
|
|
|
Nine Months Ended
|
|||||
|
September 30,
|
|||||
|
2012
|
2011
|
||||
|
(In thousands)
|
|||||
Operating activities:
|
|
|
||||
Net income
|
$
|
60,233
|
|
$
|
152,019
|
|
Income from discontinued operations, net of tax
|
4,867
|
|
154
|
|
||
Income from continuing operations
|
55,366
|
|
151,865
|
|
||
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
||
Depreciation, depletion and amortization
|
260,858
|
|
256,861
|
|
||
Earnings, net of distributions, from equity method investments
|
(1,086
|
)
|
(314
|
)
|
||
Deferred income taxes
|
40,310
|
|
79,985
|
|
||
Write-down of oil and natural gas properties
|
160,100
|
|
—
|
|
||
Changes in current assets and liabilities, net of acquisitions:
|
|
|
|
|
||
Receivables
|
(89,596
|
)
|
(57,829
|
)
|
||
Inventories
|
(40,386
|
)
|
(21,004
|
)
|
||
Other current assets
|
(18,512
|
)
|
2,976
|
|
||
Accounts payable
|
21,811
|
|
(8,037
|
)
|
||
Other current liabilities
|
(32,994
|
)
|
31,592
|
|
||
Other noncurrent changes
|
(19,683
|
)
|
(23,908
|
)
|
||
Net cash provided by continuing operations
|
336,188
|
|
412,187
|
|
||
Net cash used in discontinued operations
|
(6,826
|
)
|
(572
|
)
|
||
Net cash provided by operating activities
|
329,362
|
|
411,615
|
|
||
|
|
|
||||
Investing activities:
|
|
|
|
|
||
Capital expenditures
|
(629,776
|
)
|
(339,461
|
)
|
||
Acquisitions, net of cash acquired
|
(67,253
|
)
|
(157
|
)
|
||
Net proceeds from sale or disposition of property and other
|
31,090
|
|
23,584
|
|
||
Investments
|
11,188
|
|
(9,768
|
)
|
||
Proceeds from sale of equity method investment
|
2,394
|
|
—
|
|
||
Net cash used in continuing operations
|
(652,357
|
)
|
(325,802
|
)
|
||
Net cash provided by discontinued operations
|
—
|
|
—
|
|
||
Net cash used in investing activities
|
(652,357
|
)
|
(325,802
|
)
|
||
|
|
|
||||
Financing activities:
|
|
|
|
|
||
Issuance of short-term borrowings
|
2,900
|
|
—
|
|
||
Repayment of short-term borrowings
|
—
|
|
(20,000
|
)
|
||
Issuance of long-term debt
|
400,443
|
|
300
|
|
||
Repayment of long-term debt
|
(73,459
|
)
|
(83,805
|
)
|
||
Proceeds from issuance of common stock
|
88
|
|
5,744
|
|
||
Dividends paid
|
(95,394
|
)
|
(92,473
|
)
|
||
Excess tax benefit on stock-based compensation
|
26
|
|
1,248
|
|
||
Net cash provided by (used in) continuing operations
|
234,604
|
|
(188,986
|
)
|
||
Net cash provided by discontinued operations
|
—
|
|
—
|
|
||
Net cash provided by (used in) financing activities
|
234,604
|
|
(188,986
|
)
|
||
Effect of exchange rate changes on cash and cash equivalents
|
(139
|
)
|
(199
|
)
|
||
Decrease in cash and cash equivalents
|
(88,530
|
)
|
(103,372
|
)
|
||
Cash and cash equivalents -- beginning of year
|
162,772
|
|
222,074
|
|
||
Cash and cash equivalents -- end of period
|
$
|
74,242
|
|
$
|
118,702
|
|
|
September 30,
2012 |
September 30,
2011 |
December 31,
2011 |
||||||
|
(In thousands)
|
||||||||
Aggregates held for resale
|
$
|
88,632
|
|
$
|
80,868
|
|
$
|
78,518
|
|
Materials and supplies
|
75,551
|
|
64,988
|
|
61,611
|
|
|||
Asphalt oil
|
47,084
|
|
26,851
|
|
32,335
|
|
|||
Natural gas in storage (current)
|
41,091
|
|
39,629
|
|
36,578
|
|
|||
Merchandise for resale
|
30,827
|
|
30,974
|
|
32,165
|
|
|||
Other
|
32,582
|
|
26,259
|
|
32,998
|
|
|||
Total
|
$
|
315,767
|
|
$
|
269,569
|
|
$
|
274,205
|
|
|
Three Months Ended
|
Nine Months Ended
|
||||||
|
September 30,
|
September 30,
|
||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
|
(In thousands)
|
|||||||
Weighted average common shares outstanding - basic
|
188,831
|
|
188,794
|
|
188,824
|
|
188,753
|
|
Effect of dilutive stock options and performance share awards
|
—
|
|
3
|
|
205
|
|
7
|
|
Weighted average common shares outstanding - diluted
|
188,831
|
|
188,797
|
|
189,029
|
|
188,760
|
|
Shares excluded from the calculation of diluted earnings per share
|
434
|
|
—
|
|
—
|
|
—
|
|
|
Nine Months Ended
|
|||||
|
September 30,
|
|||||
|
2012
|
|
2011
|
|
||
|
(In thousands)
|
|||||
Interest, net of amount capitalized
|
$
|
57,956
|
|
$
|
63,669
|
|
Income taxes paid (refunded), net
|
$
|
3,210
|
|
$
|
(11,331
|
)
|
|
September 30,
|
|||||
|
2012
|
|
2011
|
|
||
|
(In thousands)
|
|||||
Property, plant and equipment additions in accounts payable
|
$
|
68,636
|
|
$
|
31,100
|
|
Nine Months Ended
September 30, 2012 |
Balance
as of
January 1,
2012*
|
Goodwill
Acquired During
the Year**
|
Balance
as of September 30, 2012* |
||||||
|
(In thousands)
|
||||||||
Natural gas distribution
|
$
|
345,736
|
|
$
|
—
|
|
$
|
345,736
|
|
Pipeline and energy services
|
9,737
|
|
—
|
|
9,737
|
|
|||
Construction materials and contracting
|
176,290
|
|
—
|
|
176,290
|
|
|||
Construction services
|
103,168
|
|
1,108
|
|
104,276
|
|
|||
Total
|
$
|
634,931
|
|
$
|
1,108
|
|
$
|
636,039
|
|
Nine Months Ended
September 30, 2011 |
Balance
as of
January 1,
2011*
|
Goodwill
Acquired
During the
Year**
|
Balance
as of September 30, 2011* |
||||||
|
(In thousands)
|
||||||||
Natural gas distribution
|
$
|
345,736
|
|
$
|
—
|
|
$
|
345,736
|
|
Pipeline and energy services
|
9,737
|
|
—
|
|
9,737
|
|
|||
Construction materials and contracting
|
176,290
|
|
—
|
|
176,290
|
|
|||
Construction services
|
102,870
|
|
298
|
|
103,168
|
|
|||
Total
|
$
|
634,633
|
|
$
|
298
|
|
$
|
634,931
|
|
Year Ended
December 31, 2011
|
Balance
as of
January 1,
2011*
|
Goodwill
Acquired
During the
Year**
|
Balance
as of
December 31,
2011*
|
||||||
|
(In thousands)
|
||||||||
Natural gas distribution
|
$
|
345,736
|
|
$
|
—
|
|
$
|
345,736
|
|
Pipeline and energy services
|
9,737
|
|
—
|
|
9,737
|
|
|||
Construction materials and contracting
|
176,290
|
|
—
|
|
176,290
|
|
|||
Construction services
|
102,870
|
|
298
|
|
103,168
|
|
|||
Total
|
$
|
634,633
|
|
$
|
298
|
|
$
|
634,931
|
|
|
September 30,
2012 |
September 30,
2011 |
December 31,
2011 |
||||||
|
(In thousands)
|
||||||||
Customer relationships
|
$
|
21,310
|
|
$
|
21,702
|
|
$
|
21,702
|
|
Accumulated amortization
|
(11,192
|
)
|
(9,896
|
)
|
(10,392
|
)
|
|||
|
10,118
|
|
11,806
|
|
11,310
|
|
|||
Noncompete agreements
|
7,236
|
|
7,685
|
|
7,685
|
|
|||
Accumulated amortization
|
(5,198
|
)
|
(5,222
|
)
|
(5,371
|
)
|
|||
|
2,038
|
|
2,463
|
|
2,314
|
|
|||
Other
|
10,979
|
|
12,901
|
|
11,442
|
|
|||
Accumulated amortization
|
(5,120
|
)
|
(4,922
|
)
|
(4,223
|
)
|
|||
|
5,859
|
|
7,979
|
|
7,219
|
|
|||
Total
|
$
|
18,015
|
|
$
|
22,248
|
|
$
|
20,843
|
|
Asset
Derivatives
|
Location on
Consolidated
Balance Sheets
|
Fair Value at
September 30, 2012 |
Fair Value at
September 30, 2011 |
Fair Value at
December 31, 2011 |
||||||
|
|
(In thousands)
|
||||||||
Designated as hedges:
|
|
|
|
|||||||
Commodity derivatives
|
Commodity derivative instruments
|
$
|
18,619
|
|
$
|
38,458
|
|
$
|
27,687
|
|
|
Other assets - noncurrent
|
3,463
|
|
15,575
|
|
2,768
|
|
|||
|
|
22,082
|
|
54,033
|
|
30,455
|
|
|||
Not designated as hedges:
|
|
|
|
|
||||||
Commodity derivatives
|
Commodity derivative instruments
|
574
|
|
336
|
|
—
|
|
|||
|
Other assets - noncurrent
|
63
|
|
—
|
|
—
|
|
|||
|
|
637
|
|
336
|
|
—
|
|
|||
Total asset derivatives
|
|
$
|
22,719
|
|
$
|
54,369
|
|
$
|
30,455
|
|
Liability
Derivatives
|
Location on
Consolidated
Balance Sheets
|
Fair Value at
September 30, 2012 |
Fair Value at
September 30, 2011 |
Fair Value at
December 31, 2011 |
||||||
|
|
(In thousands)
|
||||||||
Designated as hedges:
|
|
|
|
|||||||
Commodity derivatives
|
Commodity derivative instruments
|
$
|
1,958
|
|
$
|
1,723
|
|
$
|
12,727
|
|
|
Other liabilities - noncurrent
|
83
|
|
157
|
|
937
|
|
|||
Interest rate derivatives
|
Other accrued liabilities
|
7,779
|
|
—
|
|
827
|
|
|||
|
Other liabilities - noncurrent
|
—
|
|
3,491
|
|
3,935
|
|
|||
|
|
9,820
|
|
5,371
|
|
18,426
|
|
|||
Not designated as hedges:
|
|
|
|
|
|
|
||||
Commodity derivatives
|
Commodity derivative instruments
|
114
|
|
1,305
|
|
437
|
|
|||
|
|
114
|
|
1,305
|
|
437
|
|
|||
Total liability derivatives
|
|
$
|
9,934
|
|
$
|
6,676
|
|
$
|
18,863
|
|
September 30, 2012
|
Cost
|
Gross Unrealized Gains
|
Gross Unrealized Losses
|
Fair Value
|
||||||||
|
(In thousands)
|
|||||||||||
Insurance investment contract
|
$
|
37,250
|
|
$
|
11,134
|
|
$
|
—
|
|
$
|
48,384
|
|
Mortgage-backed securities
|
8,391
|
|
175
|
|
(2
|
)
|
8,564
|
|
||||
U.S. Treasury securities
|
1,758
|
|
47
|
|
—
|
|
1,805
|
|
||||
Total
|
$
|
47,399
|
|
$
|
11,356
|
|
$
|
(2
|
)
|
$
|
58,753
|
|
December 31, 2011
|
Cost
|
Gross Unrealized Gains
|
Gross Unrealized Losses
|
Fair Value
|
||||||||
|
(In thousands)
|
|||||||||||
Insurance investment contract
|
$
|
31,884
|
|
$
|
6,468
|
|
$
|
—
|
|
$
|
38,352
|
|
Auction rate securities
|
11,400
|
|
—
|
|
—
|
|
11,400
|
|
||||
Mortgage-backed securities
|
8,206
|
|
95
|
|
(5
|
)
|
8,296
|
|
||||
U.S. Treasury securities
|
1,619
|
|
37
|
|
—
|
|
1,656
|
|
||||
Total
|
$
|
53,109
|
|
$
|
6,600
|
|
$
|
(5
|
)
|
$
|
59,704
|
|
|
Fair Value Measurements at
September 30, 2012, Using |
|
||||||||||
|
Quoted Prices in
Active Markets
for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs (Level 3)
|
Balance at
September 30, 2012 |
||||||||
|
(In thousands)
|
|||||||||||
Assets:
|
|
|
|
|
||||||||
Money market funds
|
$
|
—
|
|
$
|
21,816
|
|
$
|
—
|
|
$
|
21,816
|
|
Available-for-sale securities:
|
|
|
|
|
||||||||
Insurance investment contract*
|
—
|
|
48,384
|
|
—
|
|
48,384
|
|
||||
Mortgage-backed securities
|
—
|
|
8,564
|
|
—
|
|
8,564
|
|
||||
U.S. Treasury securities
|
—
|
|
1,805
|
|
—
|
|
1,805
|
|
||||
Commodity derivative instruments
|
—
|
|
22,719
|
|
—
|
|
22,719
|
|
||||
Total assets measured at fair value
|
$
|
—
|
|
$
|
103,288
|
|
$
|
—
|
|
$
|
103,288
|
|
Liabilities:
|
|
|
|
|
||||||||
Commodity derivative instruments
|
$
|
—
|
|
$
|
2,155
|
|
$
|
—
|
|
$
|
2,155
|
|
Interest rate derivative instruments
|
—
|
|
7,779
|
|
—
|
|
7,779
|
|
||||
Total liabilities measured at fair value
|
$
|
—
|
|
$
|
9,934
|
|
$
|
—
|
|
$
|
9,934
|
|
|
Fair Value Measurements at
September 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
September 30, 2011 |
||||||||
|
(In thousands)
|
|||||||||||
Assets:
|
|
|
|
|
||||||||
Money market funds
|
$
|
—
|
|
$
|
56,194
|
|
$
|
—
|
|
$
|
56,194
|
|
Available-for-sale securities:
|
|
|
|
|
||||||||
Insurance investment contract*
|
—
|
|
33,591
|
|
—
|
|
33,591
|
|
||||
Auction rate securities
|
—
|
|
11,400
|
|
—
|
|
11,400
|
|
||||
Mortgage-backed securities
|
—
|
|
8,570
|
|
—
|
|
8,570
|
|
||||
U.S. Treasury securities
|
—
|
|
1,444
|
|
—
|
|
1,444
|
|
||||
Commodity derivative instruments
|
—
|
|
54,369
|
|
—
|
|
54,369
|
|
||||
Total assets measured at fair value
|
$
|
—
|
|
$
|
165,568
|
|
$
|
—
|
|
$
|
165,568
|
|
Liabilities:
|
|
|
|
|
||||||||
Commodity derivative instruments
|
$
|
—
|
|
$
|
3,185
|
|
$
|
—
|
|
$
|
3,185
|
|
Interest rate derivative instruments
|
—
|
|
3,491
|
|
—
|
|
3,491
|
|
||||
Total liabilities measured at fair value
|
$
|
—
|
|
$
|
6,676
|
|
$
|
—
|
|
$
|
6,676
|
|
|
Fair Value Measurements at
December 31, 2011, Using |
|
||||||||||
|
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
Significant Other Observable Inputs (Level 2)
|
Significant Unobservable Inputs
(Level 3)
|
Balance at
December 31, 2011 |
||||||||
|
(In thousands)
|
|||||||||||
Assets:
|
|
|
|
|
||||||||
Money market funds
|
$
|
—
|
|
$
|
97,500
|
|
$
|
—
|
|
$
|
97,500
|
|
Available-for-sale securities:
|
|
|
|
|
||||||||
Insurance investment contract*
|
—
|
|
38,352
|
|
—
|
|
38,352
|
|
||||
Auction rate securities
|
—
|
|
11,400
|
|
—
|
|
11,400
|
|
||||
Mortgage-backed securities
|
—
|
|
8,296
|
|
—
|
|
8,296
|
|
||||
U.S. Treasury securities
|
—
|
|
1,656
|
|
—
|
|
1,656
|
|
||||
Commodity derivative instruments
|
—
|
|
30,455
|
|
—
|
|
30,455
|
|
||||
Total assets measured at fair value
|
$
|
—
|
|
$
|
187,659
|
|
$
|
—
|
|
$
|
187,659
|
|
Liabilities:
|
|
|
|
|
||||||||
Commodity derivative instruments
|
$
|
—
|
|
$
|
14,101
|
|
$
|
—
|
|
$
|
14,101
|
|
Interest rate derivative instruments
|
—
|
|
4,762
|
|
—
|
|
4,762
|
|
||||
Total liabilities measured at fair value
|
$
|
—
|
|
$
|
18,863
|
|
$
|
—
|
|
$
|
18,863
|
|
|
Carrying
Amount
|
Fair
Value
|
||||
|
(In thousands)
|
|||||
Long-term debt at September 30, 2012
|
$
|
1,742,977
|
|
$
|
1,906,673
|
|
Long-term debt at September 30, 2011
|
$
|
1,423,614
|
|
$
|
1,568,942
|
|
Long-term debt at December 31, 2011
|
$
|
1,424,678
|
|
$
|
1,592,807
|
|
Three Months Ended
September 30, 2012 |
External
Operating
Revenues
|
Inter-
segment
Operating
Revenues
|
Earnings (Loss)
on Common
Stock
|
||||||
|
(In thousands)
|
||||||||
Electric
|
$
|
63,492
|
|
$
|
—
|
|
$
|
11,000
|
|
Natural gas distribution
|
80,069
|
|
—
|
|
(8,782
|
)
|
|||
Pipeline and energy services
|
41,302
|
|
7,046
|
|
3,273
|
|
|||
|
184,863
|
|
7,046
|
|
5,491
|
|
|||
Exploration and production
|
100,380
|
|
8,076
|
|
(87,748
|
)
|
|||
Construction materials and contracting
|
641,500
|
|
8,508
|
|
41,889
|
|
|||
Construction services
|
246,358
|
|
834
|
|
9,863
|
|
|||
Other
|
417
|
|
1,948
|
|
663
|
|
|||
|
988,655
|
|
19,366
|
|
(35,333
|
)
|
|||
Intersegment eliminations
|
—
|
|
(26,412
|
)
|
—
|
|
|||
Total
|
$
|
1,173,518
|
|
$
|
—
|
|
$
|
(29,842
|
)
|
Three Months Ended
September 30, 2011 |
External
Operating
Revenues
|
|
Inter-
segment
Operating
Revenues
|
|
Earnings
on Common
Stock
|
|
|||
|
(In thousands)
|
||||||||
Electric
|
$
|
61,949
|
|
$
|
—
|
|
$
|
8,312
|
|
Natural gas distribution
|
92,440
|
|
—
|
|
(11,183
|
)
|
|||
Pipeline and energy services
|
58,459
|
|
10,591
|
|
5,221
|
|
|||
|
212,848
|
|
10,591
|
|
2,350
|
|
|||
Exploration and production
|
96,803
|
|
23,956
|
|
22,497
|
|
|||
Construction materials and contracting
|
619,134
|
|
—
|
|
33,103
|
|
|||
Construction services
|
222,822
|
|
3,344
|
|
5,044
|
|
|||
Other
|
574
|
|
2,025
|
|
809
|
|
|||
|
939,333
|
|
29,325
|
|
61,453
|
|
|||
Intersegment eliminations
|
—
|
|
(39,916
|
)
|
—
|
|
|||
Total
|
$
|
1,152,181
|
|
$
|
—
|
|
$
|
63,803
|
|
Nine Months Ended
September 30, 2012 |
External
Operating
Revenues
|
|
Inter-
segment
Operating
Revenues
|
|
Earnings
on Common
Stock
|
|
|||
|
(In thousands)
|
||||||||
Electric
|
$
|
174,410
|
|
$
|
—
|
|
$
|
22,977
|
|
Natural gas distribution
|
504,805
|
|
—
|
|
10,314
|
|
|||
Pipeline and energy services
|
105,184
|
|
36,393
|
|
21,884
|
|
|||
|
784,399
|
|
36,393
|
|
55,175
|
|
|||
Exploration and production
|
289,106
|
|
25,114
|
|
(56,860
|
)
|
|||
Construction materials and contracting
|
1,229,731
|
|
11,756
|
|
24,748
|
|
|||
Construction services
|
688,368
|
|
1,078
|
|
29,951
|
|
|||
Other
|
2,684
|
|
4,303
|
|
6,705
|
|
|||
|
2,209,889
|
|
42,251
|
|
4,544
|
|
|||
Intersegment eliminations
|
—
|
|
(78,644
|
)
|
—
|
|
|||
Total
|
$
|
2,994,288
|
|
$
|
—
|
|
$
|
59,719
|
|
Nine Months Ended
September 30, 2011 |
External
Operating
Revenues
|
|
Inter-
segment
Operating
Revenues
|
|
Earnings
on Common
Stock
|
|
|||
|
(In thousands)
|
||||||||
Electric
|
$
|
169,780
|
|
$
|
—
|
|
$
|
21,642
|
|
Natural gas distribution
|
627,450
|
|
—
|
|
18,235
|
|
|||
Pipeline and energy services
|
167,636
|
|
47,836
|
|
16,913
|
|
|||
|
964,866
|
|
47,836
|
|
56,790
|
|
|||
Exploration and production
|
262,604
|
|
74,889
|
|
60,093
|
|
|||
Construction materials and contracting
|
1,138,280
|
|
—
|
|
16,680
|
|
|||
Construction services
|
617,699
|
|
9,940
|
|
15,815
|
|
|||
Other
|
1,294
|
|
6,614
|
|
2,127
|
|
|||
|
2,019,877
|
|
91,443
|
|
94,715
|
|
|||
Intersegment eliminations
|
—
|
|
(139,279
|
)
|
—
|
|
|||
Total
|
$
|
2,984,743
|
|
$
|
—
|
|
$
|
151,505
|
|
|
|
|
Other
|
|||||||||
|
|
|
Postretirement
|
|||||||||
|
Pension Benefits
|
Benefits
|
||||||||||
Three Months Ended September 30,
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(In thousands)
|
|||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
||||||||
Service cost
|
$
|
349
|
|
$
|
35
|
|
$
|
437
|
|
$
|
361
|
|
Interest cost
|
4,407
|
|
4,706
|
|
943
|
|
1,175
|
|
||||
Expected return on assets
|
(5,865
|
)
|
(5,679
|
)
|
(1,222
|
)
|
(1,263
|
)
|
||||
Amortization of prior service credit
|
(22
|
)
|
(54
|
)
|
(534
|
)
|
(669
|
)
|
||||
Amortization of net actuarial loss
|
1,887
|
|
917
|
|
356
|
|
430
|
|
||||
Amortization of net transition obligation
|
—
|
|
—
|
|
531
|
|
532
|
|
||||
Curtailment gain
|
(1,023
|
)
|
—
|
|
—
|
|
—
|
|
||||
Net periodic benefit cost, including amount capitalized
|
(267
|
)
|
(75
|
)
|
511
|
|
566
|
|
||||
Less amount capitalized
|
185
|
|
323
|
|
314
|
|
(41
|
)
|
||||
Net periodic benefit cost
|
$
|
(452
|
)
|
$
|
(398
|
)
|
$
|
197
|
|
$
|
607
|
|
|
|
|
|
|
||||||||
|
|
|
Other
|
|||||||||
|
|
|
Postretirement
|
|||||||||
|
Pension Benefits
|
Benefits
|
||||||||||
Nine Months Ended September 30,
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(In thousands)
|
|||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
||||||||
Service cost
|
$
|
1,044
|
|
$
|
1,689
|
|
$
|
1,310
|
|
$
|
1,083
|
|
Interest cost
|
13,223
|
|
14,625
|
|
3,124
|
|
3,525
|
|
||||
Expected return on assets
|
(17,596
|
)
|
(17,106
|
)
|
(3,667
|
)
|
(3,789
|
)
|
||||
Amortization of prior service cost (credit)
|
(64
|
)
|
33
|
|
(1,078
|
)
|
(2,007
|
)
|
||||
Amortization of net actuarial loss
|
5,670
|
|
3,509
|
|
1,769
|
|
688
|
|
||||
Amortization of net transition obligation
|
—
|
|
—
|
|
1,594
|
|
1,594
|
|
||||
Curtailment (gain) loss
|
(1,023
|
)
|
1,218
|
|
—
|
|
—
|
|
||||
Net periodic benefit cost, including amount capitalized
|
1,254
|
|
3,968
|
|
3,052
|
|
1,094
|
|
||||
Less amount capitalized
|
615
|
|
858
|
|
635
|
|
(136
|
)
|
||||
Net periodic benefit cost
|
$
|
639
|
|
$
|
3,110
|
|
$
|
2,417
|
|
$
|
1,230
|
|
•
|
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
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(Dollars in millions, where applicable)
|
|||||||||||
Electric
|
$
|
11.0
|
|
$
|
8.3
|
|
$
|
23.0
|
|
$
|
21.7
|
|
Natural gas distribution
|
(8.8
|
)
|
(11.2
|
)
|
10.3
|
|
18.2
|
|
||||
Pipeline and energy services
|
3.3
|
|
5.2
|
|
21.9
|
|
16.9
|
|
||||
Exploration and production
|
(87.8
|
)
|
22.5
|
|
(56.9
|
)
|
60.1
|
|
||||
Construction materials and contracting
|
41.9
|
|
33.1
|
|
24.7
|
|
16.7
|
|
||||
Construction services
|
9.9
|
|
5.1
|
|
30.0
|
|
15.8
|
|
||||
Other
|
.8
|
|
.9
|
|
1.9
|
|
2.0
|
|
||||
Earnings (loss) before discontinued operations
|
(29.7
|
)
|
63.9
|
|
54.9
|
|
151.4
|
|
||||
Income (loss) from discontinued operations, net of tax
|
(.1
|
)
|
(.1
|
)
|
4.8
|
|
.1
|
|
||||
Earnings (loss) on common stock
|
$
|
(29.8
|
)
|
$
|
63.8
|
|
$
|
59.7
|
|
$
|
151.5
|
|
Earnings (loss) per common share - basic:
|
|
|
|
|
|
|
|
|
||||
Earnings (loss) before discontinued operations
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.29
|
|
$
|
.80
|
|
Discontinued operations, net of tax
|
—
|
|
—
|
|
.03
|
|
—
|
|
||||
Earnings (loss) per common share - basic
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.32
|
|
$
|
.80
|
|
Earnings (loss) per common share - diluted:
|
|
|
|
|
|
|
|
|
||||
Earnings (loss) before discontinued operations
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.29
|
|
$
|
.80
|
|
Discontinued operations, net of tax
|
—
|
|
—
|
|
.03
|
|
—
|
|
||||
Earnings (loss) per common share - diluted
|
$
|
(.16
|
)
|
$
|
.34
|
|
$
|
.32
|
|
$
|
.80
|
|
Return on average common equity for the 12 months ended
|
|
|
|
|
4.3
|
%
|
8.9
|
%
|
•
|
Increased construction margins, higher liquid asphalt oil margins and volumes, as well as lower selling, general and administrative expense at the construction materials and contracting business
|
•
|
Higher workloads and margins in the Central and Western regions, higher equipment sales and rental margins, as well as higher margins in the Mountain region, partially offset by higher general and administrative expense at the construction services business
|
•
|
A $100.9 million after-tax noncash write-down of oil and natural gas properties, lower average realized natural gas prices, as well as decreased natural gas production, partially offset by increased oil production at the exploration and production business
|
•
|
Decreased retail sales volumes at the natural gas distribution business
|
•
|
Higher workloads and margins in the Central and Western regions, higher equipment sales and rental margins, as well as higher margins in the Mountain region, partially offset by higher general and administrative expense at the construction services business
|
•
|
Increased construction margins and lower selling, general and administrative expense, partially offset by higher income taxes at the construction materials and contracting business
|
•
|
Lower operation and maintenance expense from existing operations largely related to a $15.0 million net benefit related to the natural gas gathering operations litigation, as discussed in Note 19, partially offset by lower natural gas gathering volumes from existing operations at the pipeline and energy services business
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(Dollars in millions, where applicable)
|
|||||||||||
Operating revenues
|
$
|
63.5
|
|
$
|
61.9
|
|
$
|
174.4
|
|
$
|
169.8
|
|
Operating expenses:
|
|
|
|
|
|
|
||||||
Fuel and purchased power
|
17.6
|
|
17.4
|
|
51.2
|
|
48.8
|
|
||||
Operation and maintenance
|
17.9
|
|
18.1
|
|
53.1
|
|
52.4
|
|
||||
Depreciation, depletion and amortization
|
8.1
|
|
8.1
|
|
24.2
|
|
24.2
|
|
||||
Taxes, other than income
|
2.6
|
|
2.4
|
|
7.9
|
|
7.5
|
|
||||
|
46.2
|
|
46.0
|
|
136.4
|
|
132.9
|
|
||||
Operating income
|
17.3
|
|
15.9
|
|
38.0
|
|
36.9
|
|
||||
Earnings
|
$
|
11.0
|
|
$
|
8.3
|
|
$
|
23.0
|
|
$
|
21.7
|
|
Retail sales (million kWh)
|
753.8
|
|
718.8
|
|
2,189.8
|
|
2,128.1
|
|
||||
Sales for resale (million kWh)
|
8.9
|
|
35.3
|
|
11.8
|
|
63.9
|
|
||||
Average cost of fuel and purchased power per kWh
|
$
|
.022
|
|
$
|
.022
|
|
$
|
.022
|
|
$
|
.021
|
|
•
|
Higher retail sales volumes of 5 percent, primarily to residential and small commercial and industrial customers, reflecting increased demand due to warmer weather than last year, as well as increased customer growth
|
•
|
Lower operation and maintenance expense of $600,000 (after tax), primarily decreased benefit-related costs, partially offset by increased contract services at certain of the Company's electric generation stations
|
•
|
Higher other income of $500,000 (after tax), largely higher allowance for funds used during construction
|
•
|
Higher retail sales volumes of 3 percent, primarily to small commercial and industrial and residential customers, as previously discussed, offset in part by decreased volumes to large commercial and industrial customers
|
•
|
Lower net interest expense of $800,000 (after tax), including higher capitalized interest
|
•
|
Higher other income of $600,000 (after tax), as previously discussed
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(Dollars in millions, where applicable)
|
|||||||||||
Operating revenues
|
$
|
80.1
|
|
$
|
92.4
|
|
$
|
504.8
|
|
$
|
627.5
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
||||
Purchased natural gas sold
|
38.0
|
|
49.3
|
|
300.2
|
|
408.8
|
|
||||
Operation and maintenance
|
31.8
|
|
34.8
|
|
102.9
|
|
102.5
|
|
||||
Depreciation, depletion and amortization
|
11.4
|
|
11.1
|
|
34.0
|
|
33.4
|
|
||||
Taxes, other than income
|
7.0
|
|
7.3
|
|
33.2
|
|
35.7
|
|
||||
|
88.2
|
|
102.5
|
|
470.3
|
|
580.4
|
|
||||
Operating income (loss)
|
(8.1
|
)
|
(10.1
|
)
|
34.5
|
|
47.1
|
|
||||
Earnings (loss)
|
$
|
(8.8
|
)
|
$
|
(11.2
|
)
|
$
|
10.3
|
|
$
|
18.2
|
|
Volumes (MMdk):
|
|
|
|
|
|
|
||||||
Sales
|
8.0
|
|
8.4
|
|
60.1
|
|
69.7
|
|
||||
Transportation
|
30.0
|
|
28.0
|
|
94.7
|
|
87.7
|
|
||||
Total throughput
|
38.0
|
|
36.4
|
|
154.8
|
|
157.4
|
|
||||
Degree days (% of normal)*
|
|
|
|
|
|
|
|
|
||||
Montana-Dakota/Great Plains
|
38
|
%
|
54
|
%
|
75
|
%
|
110
|
%
|
||||
Cascade
|
91
|
%
|
78
|
%
|
98
|
%
|
104
|
%
|
||||
Intermountain
|
51
|
%
|
39
|
%
|
92
|
%
|
110
|
%
|
||||
Average cost of natural gas, including transportation, per dk
|
$
|
4.73
|
|
$
|
5.85
|
|
$
|
4.99
|
|
$
|
5.87
|
|
* Degree days are a measure of the daily temperature-related demand for energy for heating.
|
•
|
Lower earnings of $7.3 million (after tax) related to decreased retail sales volumes, largely resulting from significantly warmer weather than last year, partially offset by weather normalization adjustments in certain jurisdictions
|
•
|
Higher income taxes of $1.0 million, primarily related to the absence of a reduction of deferred income taxes associated with benefits in 2011
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||||
|
September 30,
|
September 30,
|
||||||||||||
|
2012
|
|
|
2011
|
|
2012
|
|
|
2011
|
|
||||
|
(Dollars in millions)
|
|||||||||||||
Operating revenues
|
$
|
48.3
|
|
|
$
|
69.1
|
|
$
|
141.6
|
|
|
$
|
215.5
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
||||
Purchased natural gas sold
|
10.8
|
|
|
31.8
|
|
35.4
|
|
|
99.8
|
|
||||
Operation and maintenance
|
19.2
|
|
|
16.6
|
|
34.8
|
|
*
|
52.8
|
|
||||
Depreciation, depletion and amortization
|
7.3
|
|
|
6.4
|
|
20.4
|
|
|
19.3
|
|
||||
Taxes, other than income
|
3.5
|
|
|
3.4
|
|
10.5
|
|
|
10.3
|
|
||||
|
40.8
|
|
|
58.2
|
|
101.1
|
|
|
182.2
|
|
||||
Operating income
|
7.5
|
|
|
10.9
|
|
40.5
|
|
|
33.3
|
|
||||
Earnings
|
$
|
3.3
|
|
|
$
|
5.2
|
|
$
|
21.9
|
|
*
|
$
|
16.9
|
|
Transportation volumes (MMdk)
|
34.1
|
|
|
29.4
|
|
103.0
|
|
|
82.5
|
|
||||
Natural gas gathering volumes (MMdk)
|
10.7
|
|
|
16.4
|
|
36.5
|
|
|
50.8
|
|
||||
Customer natural gas storage balance (MMdk):
|
|
|
|
|
|
|
|
|
|
|
||||
Beginning of period
|
40.4
|
|
|
31.7
|
|
36.0
|
|
|
58.8
|
|
||||
Net injection (withdrawal)
|
8.8
|
|
|
6.8
|
|
13.2
|
|
|
(20.3
|
)
|
||||
End of period
|
49.2
|
|
|
38.5
|
|
49.2
|
|
|
38.5
|
|
||||
* Results reflect a net benefit of $24.1 million ($15.0 million after tax) related to the natural gas gathering operations litigation, largely reflected in operation and maintenance expense, as discussed in Note 19.
|
•
|
Lower natural gas gathering volumes from existing operations, largely resulting from customers experiencing curtailments, normal production declines, deferral of certain natural gas development activity and the Company's divestments
|
•
|
Higher operation and maintenance expense from existing operations of $700,000 (after tax), largely due to higher payroll-related and legal costs
|
•
|
Lower operation and maintenance expense from existing operations largely related to a $15.0 million (after tax) net benefit related to the natural gas gathering operations litigation, as discussed in Note 19, which was partially offset by an impairment of certain natural gas gathering assets of $1.7 million (after tax) due largely to low natural gas prices
|
•
|
Higher transportation volumes of $800,000 (after tax), largely higher volumes transported to storage
|
•
|
Lower earnings of $7.3 million (after tax) due to lower natural gas gathering volumes from existing operations, as previously discussed
|
•
|
Lower storage services revenue of $1.0 million (after tax), largely lower average storage balances
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(Dollars in millions, where applicable)
|
|||||||||||
Operating revenues:
|
|
|
|
|
||||||||
Oil
|
$
|
85.0
|
|
$
|
74.9
|
|
$
|
243.6
|
|
$
|
201.9
|
|
Natural gas
|
23.5
|
|
45.9
|
|
70.6
|
|
135.6
|
|
||||
|
108.5
|
|
120.8
|
|
314.2
|
|
337.5
|
|
||||
Operating expenses:
|
|
|
|
|
|
|
|
|
||||
Operation and maintenance:
|
|
|
|
|
|
|
|
|
||||
Lease operating costs
|
20.7
|
|
19.4
|
|
58.2
|
|
55.8
|
|
||||
Gathering and transportation
|
4.3
|
|
6.9
|
|
12.8
|
|
18.1
|
|
||||
Other
|
9.6
|
|
9.8
|
|
28.4
|
|
27.3
|
|
||||
Depreciation, depletion and amortization
|
41.4
|
|
38.5
|
|
112.6
|
|
106.0
|
|
||||
Taxes, other than income:
|
|
|
|
|
||||||||
Production and property taxes
|
9.6
|
|
10.0
|
|
27.8
|
|
30.5
|
|
||||
Other
|
.2
|
|
(.7
|
)
|
.8
|
|
(.1
|
)
|
||||
Write-down of oil and natural gas properties
|
160.1
|
|
—
|
|
160.1
|
|
—
|
|
||||
|
245.9
|
|
83.9
|
|
400.7
|
|
237.6
|
|
||||
Operating income (loss)
|
(137.4
|
)
|
36.9
|
|
(86.5
|
)
|
99.9
|
|
||||
Earnings (loss)
|
$
|
(87.8
|
)
|
$
|
22.5
|
|
$
|
(56.9
|
)
|
$
|
60.1
|
|
Production:
|
|
|
|
|
||||||||
Oil (MBbls)
|
1,123
|
|
944
|
|
3,165
|
|
2,567
|
|
||||
Natural gas (MMcf)
|
7,390
|
|
11,656
|
|
25,676
|
|
34,667
|
|
||||
Total production (MBOE)
|
2,354
|
|
2,887
|
|
7,444
|
|
8,345
|
|
||||
Average realized prices (including hedges):
|
|
|
|
|
||||||||
Oil (per Bbl)
|
$
|
75.69
|
|
$
|
79.28
|
|
$
|
76.96
|
|
$
|
78.64
|
|
Natural gas (per Mcf)
|
$
|
3.17
|
|
$
|
3.94
|
|
$
|
2.75
|
|
$
|
3.91
|
|
Average realized prices (excluding hedges):
|
|
|
|
|
||||||||
Oil (per Bbl)
|
$
|
73.89
|
|
$
|
80.90
|
|
$
|
76.45
|
|
$
|
83.05
|
|
Natural gas (per Mcf)
|
$
|
2.25
|
|
$
|
3.44
|
|
$
|
1.88
|
|
$
|
3.44
|
|
Average depreciation, depletion and amortization rate, per BOE
|
$
|
16.85
|
|
$
|
12.72
|
|
$
|
14.44
|
|
$
|
12.09
|
|
Production costs, including taxes, per BOE:
|
|
|
|
|||||||||
Lease operating costs
|
$
|
8.77
|
|
$
|
6.71
|
|
$
|
7.81
|
|
$
|
6.68
|
|
Gathering and transportation
|
1.84
|
|
2.37
|
|
1.72
|
|
2.17
|
|
||||
Production and property taxes
|
4.07
|
|
3.46
|
|
3.74
|
|
3.66
|
|
||||
|
$
|
14.68
|
|
$
|
12.54
|
|
$
|
13.27
|
|
$
|
12.51
|
|
•
|
A noncash write-down of oil and natural gas properties of $100.9 million (after tax), as discussed in Note 5
|
•
|
Decreased natural gas production of 37 percent, largely related to a decision to curtail production, normal production declines, deferral of certain natural gas development activity and divestment at existing properties
|
•
|
Lower average realized natural gas prices of 20 percent
|
•
|
Lower average realized oil prices of 5 percent
|
•
|
Higher depreciation, depletion and amortization expense of $1.9 million (after tax), due to higher depletion rates, partially offset by lower volumes
|
•
|
Increased oil production of 19 percent, largely related to drilling activity in the Bakken area, as well as the Paradox Basin
|
•
|
Lower gathering and transportation expense of $1.6 million (after tax), largely due to lower gathering costs resulting from lower volumes and lower gathering rates in the coalbed area
|
•
|
A noncash write-down of oil and natural gas properties of $100.9 million (after tax), as discussed in Note 5
|
•
|
Lower average realized natural gas prices of 30 percent
|
•
|
Decreased natural gas production of 26 percent, as previously discussed
|
•
|
Higher depreciation, depletion and amortization expense of $4.2 million (after tax), as previously discussed
|
•
|
Lower average realized oil prices of 2 percent
|
•
|
Increased lease operating expenses of $1.5 million (after tax), largely due to higher costs in the Bakken area resulting largely from increased production volumes and higher workover costs, partially offset by lower costs at certain natural gas properties where curtailments of production have occured
|
•
|
Higher general and administrative expense of $1.3 million (after tax), largely due to higher payroll-related costs
|
•
|
Increased oil production of 23 percent, largely related to drilling activity in the Bakken area, the Paradox Basin, as well as at the South Texas properties
|
•
|
Lower gathering and transportation expense of $3.3 million (after tax), as previously discussed
|
•
|
Lower production taxes of $1.6 million (after tax), largely resulting from lower revenues excluding hedges
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(Dollars in millions)
|
|||||||||||
Operating revenues
|
$
|
650.0
|
|
$
|
619.1
|
|
$
|
1,241.5
|
|
$
|
1,138.2
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|||||
Operation and maintenance
|
549.6
|
|
530.7
|
|
1,103.3
|
|
1,011.8
|
|
||||
Depreciation, depletion and amortization
|
20.3
|
|
21.6
|
|
59.9
|
|
64.2
|
|
||||
Taxes, other than income
|
11.0
|
|
11.1
|
|
29.6
|
|
28.6
|
|
||||
|
580.9
|
|
563.4
|
|
1,192.8
|
|
1,104.6
|
|
||||
Operating income
|
69.1
|
|
55.7
|
|
48.7
|
|
33.6
|
|
||||
Earnings
|
$
|
41.9
|
|
$
|
33.1
|
|
$
|
24.7
|
|
$
|
16.7
|
|
Sales (000's):
|
|
|
|
|
|
|
|
|
||||
Aggregates (tons)
|
9,009
|
|
9,196
|
|
17,983
|
|
18,502
|
|
||||
Asphalt (tons)
|
3,013
|
|
3,462
|
|
4,874
|
|
5,469
|
|
||||
Ready-mixed concrete (cubic yards)
|
1,105
|
|
986
|
|
2,410
|
|
2,081
|
|
•
|
Increased construction margins of $4.1 million (after tax) reflecting increased construction activity and margins in the South and North Central regions
|
•
|
Higher earnings of $2.3 million (after tax) resulting from higher liquid asphalt oil margins and volumes
|
•
|
Lower selling, general and administrative expense of $2.3 million (after tax), largely lower payroll and benefit-related costs
|
•
|
Higher earnings of $1.5 million (after tax) resulting from higher ready-mixed concrete volumes and margins
|
•
|
Lower earnings of $800,000 (after tax) resulting from lower aggregate margins primarily due to higher costs, as well as lower volumes
|
•
|
Lower gains of $700,000 (after tax) from the sale of property, plant and equipment
|
•
|
Increased construction margins of $8.3 million (after tax), largely due to favorable weather in the North Central and Intermountain regions and increased construction activity in the North Central region
|
•
|
Lower selling, general and administrative expense of $3.6 million (after tax), as previously discussed
|
•
|
Higher earnings of $3.0 million (after tax) resulting from higher ready-mixed concrete volumes and margins, largely in the North Central region
|
•
|
Higher earnings of $2.9 million (after tax) resulting from higher liquid asphalt oil margins and volumes
|
•
|
Higher income taxes, including the absence of an income tax benefit of $2.0 million related to favorable resolution of certain income tax matters in 2011
|
•
|
Lower earnings of $3.5 million (after tax) resulting from lower asphalt margins primarily due to higher costs, as well as lower volumes
|
•
|
Lower earnings of $3.3 million (after tax) resulting from lower aggregate margins and volumes, as previously discussed
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(In millions)
|
|||||||||||
Operating revenues
|
$
|
247.2
|
|
$
|
226.2
|
|
$
|
689.4
|
|
$
|
627.6
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
||||
Operation and maintenance
|
219.9
|
|
208.0
|
|
606.5
|
|
571.2
|
|
||||
Depreciation, depletion and amortization
|
2.8
|
|
2.8
|
|
8.3
|
|
8.5
|
|
||||
Taxes, other than income
|
7.2
|
|
5.8
|
|
22.1
|
|
19.0
|
|
||||
|
229.9
|
|
216.6
|
|
636.9
|
|
598.7
|
|
||||
Operating income
|
17.3
|
|
9.6
|
|
52.5
|
|
28.9
|
|
||||
Earnings
|
$
|
9.9
|
|
$
|
5.1
|
|
$
|
30.0
|
|
$
|
15.8
|
|
|
Three Months Ended
|
Nine Months Ended
|
||||||||||
|
September 30,
|
September 30,
|
||||||||||
|
2012
|
|
2011
|
|
2012
|
|
2011
|
|
||||
|
(In millions)
|
|||||||||||
Other:
|
|
|
|
|
||||||||
Operating revenues
|
$
|
2.3
|
|
$
|
2.6
|
|
$
|
7.0
|
|
$
|
7.9
|
|
Operation and maintenance
|
1.5
|
|
1.6
|
|
4.4
|
|
6.5
|
|
||||
Depreciation, depletion and amortization
|
.5
|
|
.4
|
|
1.5
|
|
1.2
|
|
||||
Taxes, other than income
|
—
|
|
.1
|
|
.1
|
|
.1
|
|
||||
Intersegment transactions:
|
|
|
|
|
|
|
||||||
Operating revenues
|
$
|
26.4
|
|
$
|
39.9
|
|
$
|
78.6
|
|
$
|
139.3
|
|
Purchased natural gas sold
|
13.6
|
|
31.0
|
|
56.5
|
|
112.3
|
|
||||
Operation and maintenance
|
12.8
|
|
8.9
|
|
22.1
|
|
27.0
|
|
•
|
Earnings per common share for 2012 are projected in the range of $1.05 to $1.20, excluding a third quarter noncash write-down of $100.9 million after tax and a second quarter $15.0 million after-tax benefit from a reversal of an arbitration charge. Including these items, earnings guidance for 2012 is 60 cents to 75 cents per common share.
|
•
|
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 to 10 percent.
|
•
|
The Company continually seeks opportunities to expand through strategic acquisitions and organic growth opportunities.
|
•
|
The Company filed an application with the MTPSC on September 26, 2012, for a natural gas rate increase, as discussed in Note 18.
|
•
|
The EPA approved the South Dakota Regional Haze Program, which requires 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. The Company's share of the cost for the installation is estimated at $125 million and is expected to be completed in 2015. Advance determination of prudence for recovery of costs related to this system in electric rates charged to customers has been approved by the NDPSC.
|
•
|
The Company plans to construct and operate an 88-MW simple-cycle natural gas turbine and associated facilities, with an estimated project cost of $85 million and a projected in-service date late 2014. It will be located on owned property that is adjacent to the Company's Heskett Generating Station near Mandan, North Dakota. The capacity is necessary to meet the requirements of the Company's integrated electric system customers and will be a partial replacement for third-party contract capacity expiring in 2015. Advance determination of prudence and a Certificate of Public Convenience and Necessity have been received from the NDPSC.
|
•
|
The Company plans to invest approximately $75 million in 2012 to serve the growing electric and gas customer base associated with the Bakken oil development in western North Dakota and eastern Montana.
|
•
|
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 engaged in a 30-mile natural gas line project into the Hanford Nuclear Site in Washington.
|
•
|
Currently the Company is involved with a number of pipeline projects to enhance the reliability and deliverability of its system in the Pacific Northwest and Idaho.
|
•
|
The Company is pursuing opportunities associated with the potential development of high-voltage transmission lines and system enhancements targeted toward delivery of energy to major market areas.
|
•
|
On October 10, 2012, the Company entered into a new coal supply agreement that will replace the Coyote coal supply agreement that expires in May 2016, as reported in Items 1 and 2 - Business and Properties - General in the
2011
Annual Report. The new agreement provides for the purchase of coal necessary to supply the coal requirements of the Coyote Station for the period May 2016 through December 2040.
|
•
|
On August 16, 2012, Cascade filed an application for a decoupling mechanism with the OPUC. The OPUC approved an extension until March 31, 2013, of Cascade's existing decoupling mechanism, which was scheduled to expire in the third quarter of 2012, as reported in Items 1 and 2 - Business and Properties - General in the 2011 Annual Report.
|
•
|
The Company along with Calumet Refining, LLC, continues to explore the feasibility of building and operating a 20,000 Bbl per day diesel topping plant in southwestern North Dakota. The facility would process Bakken crude and market the diesel within the Bakken region. Options to purchase land for the plant site were recently exercised. Total project costs are estimated to be approximately $280 million to $300 million with a projected in-service date in 2014.
|
•
|
In May 2012, the Company purchased a 50 percent undivided interest in Whiting Oil and Gas Corporation's Pronghorn natural gas and oil midstream assets near Belfield, North Dakota in the Bakken area. The Company expects to invest approximately $100 million in 2012 including the purchase price. The Belfield natural gas processing plant has an inlet processing capacity of 35 MMcf per day.
|
•
|
The Company expects average natural gas storage balances for the remainder of the year to be slightly higher than last year. The curtailment and/or divestment of certain natural gas properties and the deferral of certain gas development activity are expected to result in gathering volumes being lower in 2012 compared to last year. The decline is expected to be partially offset by higher transportation volumes related to growth projects placed in service in the Bakken area.
|
•
|
In August 2012, the Company placed in service approximately 13 miles of high-pressure transmission pipeline from the Stateline processing facilities in northwestern North Dakota to deliver gas into the Northern Border Pipeline.
|
•
|
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. The Company 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 has increased its expected capital expenditures to approximately $525 million in 2012. The Company has improved efficiencies across its portfolio to reduce individual well costs. However, an increase in the number of total planned wells for the year as well as the drilling of higher WI wells has resulted in higher total projected capital expenditures for the year. The Company continues its focus on returns by allocating the majority of its capital investment into the production of oil given the current commodity price environment.
|
•
|
For 2012, the Company expects a 25 to 30 percent increase in oil production and a 25 to 30 percent decrease in natural gas production. The projected decline in natural gas production is primarily the result of a decision to curtail certain natural gas properties as well as divestments and the deferral of certain natural gas development activity because of sustained low natural gas prices.
|
•
|
The Company has a total of seven drilling rigs deployed on its acreage in the Bakken, Texas and Paradox areas.
|
•
|
Bakken Area
|
◦
|
The Company owns a total of approximately 127,000 net acres of leaseholds in Mountrail, Stark and Richland counties.
|
◦
|
Capital expenditures are now expected to total approximately $265 million this year; an expansion of $165 million compared to 2011. The increase in the Bakken projected capital expenditures from earlier this year relates to more operated wells being drilled in 2012 along with the drilling of higher WI wells.
|
◦
|
Mountrail County, North Dakota
|
▪
|
The Company has had strong recent well results in the area. The Amundson 23-14H (15 percent WI) came on production October 16, 2012, with a 24-hour IP rate of 1,353 Bbls of oil and 582 Mcf of natural gas and the Luke 19-20-29H (58 percent WI) began producing October 18, 2012, at a 24-hour IP rate of 968 Bbls and 678 Mcf.
|
▪
|
Approximately 40 remaining middle Bakken locations have been identified. This does not include any additional Three Forks potential, which is currently being evaluated. Estimated gross ultimate recovery rates per well are 250,000 to 600,000 Bbls.
|
◦
|
Stark County, North Dakota
|
▪
|
The Company has had strong recent well results in the Pavlish 19-20H (71 percent WI) and Kudrna 5-8H (81 percent WI) with 24-hour IP rates of 1,097 Bbls of oil and 657 Mcf of natural gas, and 1,151 Bbls of oil and 571 Mcf, respectively. The Pavlish came on production on September 19, 2012, and the Kudrna September 20, 2012.
|
▪
|
Based on current information and assuming 1,280-acre spacing, the Company has identified approximately 40 future drill sites. Estimated gross ultimate recovery rates per well are 200,000 to 400,000 Bbls.
|
◦
|
Richland County, Montana
|
▪
|
On September 30, 2012, the Company brought the Klose (66 percent WI) well on line with a 24-hour IP rate of 371 Bbls of oil and 82 Mcf of natural gas.
|
▪
|
Approximately 100 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 500,000 Bbls.
|
◦
|
Paradox Basin - Cane Creek Federal Unit, Utah
|
▪
|
The Company holds approximately 75,000 net exploratory leasehold acres.
|
▪
|
The drilling of six operated wells is planned for this year with approximately $45 million of capital expenditures.
|
▪
|
The Company has experienced strong well results with the Cane Creek 12-1 (100 percent WI) consistently producing approximately 1,500 BOPD excluding natural gas over the past three weeks with consistently high flowing pressures.
|
▪
|
Approximately 50 to 75 future net locations have been identified. Estimated gross ultimate recovery rates per well range from 250,000 to 1 million Bbls.
|
◦
|
Texas
|
▪
|
The Company is targeting areas that have the potential for higher liquids content with approximately $65 million of capital planned for this year.
|
▪
|
Approximately 50 potential gross well sites have been identified. Estimated gross ultimate recovery rates per well are 250,000 to 400,000 Bbls.
|
◦
|
Heath Shale
|
▪
|
The Company holds approximately 90,000 net exploratory leasehold acres in the Heath Shale oil prospect in Montana and expects to spend approximately $40 million this year.
|
▪
|
Two recently completed wells have had IP rates in excess of 200 Bbls per day. Production optimization efforts continue in the Heath with ongoing cleanouts of the horizontal laterals and paraffin treatment to assure sustainable production from the field.
|
◦
|
Sioux County, Nebraska
|
▪
|
The Company has entered into an exploration agreement where it will drill two vertical wells and one horizontal well. The vertical wells in the project have been drilled and are undergoing selective well testing. The horizontal well is planned for the first half of next year. After evaluating these initial wells, the Company may exercise an option to purchase a 65 percent WI in approximately 79,000 gross acres.
|
◦
|
Other Opportunities
|
▪
|
The Company has spent approximately $25 million in the Niobrara area where the economic viability and other horizons are currently being evaluated.
|
▪
|
The remaining forecasted 2012 capital has been allocated to other operated and non-operated opportunities, including $25 million for acquisitions of leaseholds acquired earlier this year primarily in the Bakken, Richland County area.
|
•
|
Earnings guidance reflects estimated average NYMEX index prices for November and December in the ranges of $90.00 to $95.00 per Bbl of crude oil and $3.00 to $3.50 per Mcf of natural gas. Estimated prices do not reflect potential basis differentials.
|
•
|
For the last three months of 2012, the Company has hedged 8,000 BOPD utilizing swaps and costless collars at a weighted average price of $101.34 and $81.25/$95.88 (floor/ceiling) respectively, and 49,500 MMBtu of natural gas per day utilizing swaps at a weighted average price of $4.38.
|
•
|
For 2013, the Company has hedged 7,000 BOPD utilizing swaps and costless collars with a weighted average price of $99.83 and $92.50/$107.03 (floor/ceiling) respectively, and 30,000 MMBtu of natural gas per day utilizing swaps at a weighted average price of $3.89.
|
•
|
The hedges that are in place as of October 31, 2012, are summarized in the following chart:
|
Commodity
|
Type
|
Index
|
Period
Outstanding
|
Forward Notional Volume
(Bbl/MMBtu)
|
Price
(Per Bbl/MMBtu)
|
|||
Crude Oil
|
Collar
|
NYMEX
|
10/12 - 12/12
|
92,000
|
|
$80.00-$87.80
|
|
|
Crude Oil
|
Collar
|
NYMEX
|
10/12 - 12/12
|
92,000
|
|
$80.00-$94.50
|
|
|
Crude Oil
|
Collar
|
NYMEX
|
10/12 - 12/12
|
92,000
|
|
$80.00-$98.36
|
|
|
Crude Oil
|
Collar
|
NYMEX
|
10/12 - 12/12
|
46,000
|
|
$85.00-$102.75
|
|
|
Crude Oil
|
Collar
|
NYMEX
|
10/12 - 12/12
|
46,000
|
|
$85.00-$103.00
|
|
|
Crude Oil
|
Swap
|
NYMEX
|
10/12 - 12/12
|
46,000
|
|
|
$100.10
|
|
Crude Oil
|
Swap
|
NYMEX
|
10/12 - 12/12
|
46,000
|
|
|
$100.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
10/12 - 12/12
|
92,000
|
|
|
$110.30
|
|
Crude Oil
|
Swap
|
NYMEX
|
10/12 - 12/12
|
92,000
|
|
|
$96.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
10/12 - 12/12
|
92,000
|
|
|
$99.00
|
|
Natural Gas
|
Swap
|
NYMEX
|
10/12 - 12/12
|
874,000
|
|
|
$6.27
|
|
Natural Gas
|
Swap
|
NYMEX
|
10/12 - 12/12
|
460,000
|
|
|
$5.005
|
|
Natural Gas
|
Swap
|
NYMEX
|
10/12 - 12/12
|
230,000
|
|
|
$5.005
|
|
Natural Gas
|
Swap
|
NYMEX
|
10/12 - 12/12
|
230,000
|
|
|
$5.0125
|
|
Natural Gas
|
Swap
|
NYMEX
|
10/12 - 12/12
|
920,000
|
|
|
$3.05
|
|
Natural Gas
|
Swap
|
NYMEX
|
10/12 - 12/12
|
920,000
|
|
|
$2.805
|
|
Natural Gas
|
Swap
|
Ventura
|
10/12 - 12/12
|
920,000
|
|
|
$4.87
|
|
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
|
|
|
Crude Oil
|
Collar
|
NYMEX
|
1/13 - 12/13
|
365,000
|
|
$90.00-$97.05
|
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$95.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$95.30
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$100.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$100.02
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$102.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$102.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$104.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$104.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$98.00
|
|
Crude Oil
|
Swap
|
NYMEX
|
1/13 - 12/13
|
182,500
|
|
|
$98.00
|
|
Natural Gas
|
Swap
|
NYMEX
|
1/13 - 12/13
|
3,650,000
|
|
|
$3.76
|
|
Natural Gas
|
Swap
|
NYMEX
|
1/13 - 12/13
|
3,650,000
|
|
|
$3.90
|
|
Natural Gas
|
Swap
|
NYMEX
|
1/13 - 12/13
|
3,650,000
|
|
|
$4.00
|
|
Natural Gas
|
Basis Swap
|
CIG
|
10/12 - 12/12
|
690,000
|
|
|
$0.405
|
|
Natural Gas
|
Basis Swap
|
CIG
|
10/12 - 12/12
|
184,000
|
|
|
$0.41
|
|
Notes:
•
Ventura is an index pricing point related to Northern Natural Gas Co.'s system; CIG is an index pricing point related to Colorado Interstate Gas Co.'s system.
•
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 September 30, 2012, was approximately $464 million, compared to approximately $448 million a year ago. Private work represents 17 percent of the backlog, up from 8 percent in the second quarter. Public work represents 83 percent of the backlog. The backlog includes a variety of projects such as highway paving projects, airports, bridge work, reclamation and harbor expansions.
|
•
|
The Company's backlog in the Bakken area of North Dakota is approximately $49 million.
|
•
|
Projected revenues included in the Company's 2012 earnings guidance are approximately $1.5 billion.
|
•
|
The Company anticipates margins in 2012 to be slightly lower compared to 2011.
|
•
|
The Company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, wind towers and geothermal. Initiatives are aimed at capturing additional market share and expansion into new markets.
|
•
|
As the country's fifth 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 ten labor contracts that Knife River was negotiating, as reported in Items 1 and 2 - Business and Properties - General in the
2011
Annual Report, five have been ratified. The five remaining contracts are still in negotiations.
|
•
|
Work backlog as of September 30, 2012, was approximately $370 million, compared to approximately $331 million a year ago. The backlog includes a variety of projects such as substation and line construction, solar and other commercial, institutional and industrial projects including refinery work.
|
•
|
The Company's backlog in the Bakken area of North Dakota is approximately $1 million.
|
•
|
Projected revenues included in the Company's 2012 earnings guidance are approximately $900 million.
|
•
|
The Company anticipates margins in 2012 to be higher compared to 2011.
|
•
|
The Company continues to pursue opportunities for expansion in energy projects such as refineries, transmission, substations, utility services, as well as solar. Initiatives are aimed at capturing additional market share and expansion into new markets.
|
•
|
System upgrades
|
•
|
Routine replacements
|
•
|
Service extensions
|
•
|
Routine equipment maintenance and replacements
|
•
|
Buildings, land and building improvements
|
•
|
Pipeline and gathering projects, including an acquisition as discussed in Note 16
|
•
|
Further development of existing properties, acquisition of additional leasehold acreage and exploratory drilling at the exploration and production segment
|
•
|
Power generation opportunities, including certain costs for additional electric generating capacity
|
•
|
Environmental upgrades
|
•
|
Other growth opportunities
|
Company
|
|
Facility
|
|
Facility Limit
|
|
Amount Outstanding
|
|
Letters of Credit
|
|
Expiration Date
|
|
||||||
|
|
|
|
(In millions)
|
|||||||||||||
MDU Resources Group, Inc.
|
|
Commercial paper/Revolving credit agreement
|
(a)
|
$
|
100.0
|
|
|
$
|
50.0
|
|
(b)
|
$
|
—
|
|
|
5/26/15
|
|
Cascade Natural Gas Corporation
|
|
Revolving credit agreement
|
|
$
|
50.0
|
|
(c)
|
$
|
—
|
|
|
$
|
1.9
|
|
(d)
|
12/27/13
|
(e)
|
Intermountain Gas Company
|
|
Revolving credit agreement
|
|
$
|
65.0
|
|
(f)
|
$
|
11.0
|
|
|
$
|
—
|
|
|
8/11/13
|
|
Centennial Energy Holdings, Inc.
|
|
Commercial paper/Revolving credit agreement
|
(g)
|
$
|
500.0
|
|
|
$
|
350.5
|
|
(b)
|
$
|
20.2
|
|
(d)
|
6/8/17
|
|
(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. On October 4, 2012, the credit agreement was increased to $125 million and the expiration date was extended to October 4, 2017.
(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 19, reduce amounts available under the credit agreement.
(e) Effective June 27, 2012, Cascade extended the credit agreement.
(f) Certain provisions allow for increased borrowings, up to a maximum of $80 million.
(g) The $500 million commercial paper program is supported by a revolving credit agreement with various banks totaling $500 million (provisions allow for increased borrowings, at the option of Centennial on stated conditions, up to a maximum of $650 million). There were no amounts outstanding under the credit agreement.
|
|
(Forward notional volume and fair value in thousands)
|
|
|||||||
|
|
|
|
|
|||||
|
|
Weighted Average
Fixed Price
(Per Bbl/MMBtu)
|
Forward
Notional
Volume
(Bbl/MMBtu)
|
Fair Value
|
|||||
Fidelity
|
|
|
|
|
|||||
Oil swap agreements maturing in 2012
|
|
$
|
101.34
|
|
368
|
|
$
|
3,164
|
|
Oil swap agreements maturing in 2013
|
|
$
|
99.83
|
|
1,825
|
|
$
|
11,157
|
|
Natural gas swap agreements maturing in 2012
|
|
$
|
4.38
|
|
4,554
|
|
$
|
4,806
|
|
Natural gas swap agreement maturing in 2013
|
|
$
|
3.76
|
|
3,650
|
|
$
|
(307
|
)
|
Natural gas basis swap agreements maturing in 2012
|
|
$
|
.41
|
|
874
|
|
$
|
(174
|
)
|
|
|
|
|
|
|||||
Cascade
|
|
|
|
|
|
|
|
||
Natural gas swap agreement maturing in 2012
|
|
$
|
4.47
|
|
31
|
|
$
|
(53
|
)
|
|
|
|
|
|
|||||
|
|
Weighted
Average
Floor/Ceiling
Price (Per Bbl)
|
Forward
Notional
Volume
(Bbl)
|
Fair Value
|
|||||
Fidelity
|
|
|
|
|
|
|
|
||
Oil collar agreements maturing in 2012
|
|
$81.25/$95.88
|
|
368
|
|
$
|
(843
|
)
|
|
Oil collar agreements maturing in 2013
|
|
$92.50/$107.03
|
|
730
|
|
$
|
2,814
|
|
(Notional amount and fair value in thousands)
|
|
|||||||
|
|
|
|
|||||
|
Weighted
Average
Fixed
Interest Rate
|
Notional
Amount
|
Fair
Value
|
|||||
Centennial
|
|
|
|
|||||
Interest rate swap agreement with mandatory termination date in 2012
|
3.15
|
%
|
$
|
10,000
|
|
$
|
(1,343
|
)
|
Interest rate swap agreements with mandatory termination dates in 2013
|
3.22
|
%
|
$
|
50,000
|
|
$
|
(6,436
|
)
|
|
|
MDU RESOURCES GROUP, INC.
|
|
|
|
|
|
DATE:
|
November 7, 2012
|
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
|
Exhibit No.
|
|
|
|
|
|
3
|
|
Company Bylaws, as amended and restated, on August 16, 2012
|
|
|
|
4
|
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First Amendment to Credit Agreement, dated October 4, 2012, among MDU Resources Group, Inc., Various Lenders, and Wells Fargo Bank, National Association, as Administrative Agent
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+10(a)
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Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated August 29, 2012
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+10(b)
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Instrument of Amendment to the MDU Resources Group, Inc. 401(k) Retirement Plan, dated August 29, 2012
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+10(c)
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Form of Agreement for Termination of Change of Control Employment Agreement, effective November 1, 2012, by and between MDU Resources Group, Inc. and William E. Schneider, John G. Harp, Steven L. Bietz, David L. Goodin, William R. Connors, Mark A. Del Vecchio, Nicole A. Kivisto, Cynthia J. Norland, Paul K. Sandness, Doran N. Schwartz and John P. Stumpf
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12
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Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends
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31(a)
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Certification of Chief Executive Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
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31(b)
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Certification of Chief Financial Officer filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
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32
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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
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95
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Mine Safety Disclosures
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101
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The following materials from MDU Resources Group, Inc.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail
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No information found
* THE VALUE IS THE MARKET VALUE AS OF THE LAST DAY OF THE QUARTER FOR WHICH THE 13F WAS FILED.
FUND | NUMBER OF SHARES | VALUE ($) | PUT OR CALL |
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DIRECTORS | AGE | BIO | OTHER DIRECTOR MEMBERSHIPS |
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No information found
No Customers Found
Suppliers
Price
Yield
Owner | Position | Direct Shares | Indirect Shares |
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