MDU 2nd Quarter 10-Q
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
X
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
|
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
The Quarterly Period Ended June 30, 2007
OR
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
|
THE
SECURITIES EXCHANGE ACT OF 1934
For
the Transition Period from _____________ to ______________
Commission
file number 1-3480
MDU
Resources Group, Inc.
(Exact
name of registrant as specified in its charter)
Delaware
|
|
41-0423660
|
(State
or other jurisdiction of incorporation
or organization)
|
|
(I.R.S.
Employer Identification
No.)
|
1200
West Century Avenue
P.O.
Box 5650
Bismarck,
North Dakota 58506-5650
(Address
of principal executive offices)
(Zip
Code)
(701)
530-1000
(Registrant's
telephone number, including area code)
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. Yes x
No o.
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check
one):
Large
accelerated filer x
Accelerated filer o
Non-accelerated filer o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o
No x.
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock, as of August 1, 2007:
182,112,362 shares.
DEFINITIONS
The
following abbreviations and acronyms used in this Form 10-Q are defined
below:
Abbreviation
or Acronym
2006
Annual Report
|
Company's
Annual Report on Form 10-K for the year ended December 31,
2006
|
ALJ
|
Administrative
Law Judge
|
Anadarko
|
Anadarko
Petroleum Corporation
|
APB
|
Accounting
Principles Board
|
APB
Opinion No. 28
|
Interim
Financial Reporting
|
Badger
Hills Project
|
Tongue
River-Badger Hills Project
|
Bbl
|
Barrel
of oil or other liquid hydrocarbons
|
Bcf
|
Billion
cubic feet
|
BER
|
Montana
Board of Environmental Review
|
Big
Stone Station
|
450-MW
coal-fired electric generating facility located near Big Stone City,
South
Dakota (22.7 percent ownership)
|
Big
Stone II
|
Proposed
600-MW coal-fired electric generating facility located near Big Stone
City, South Dakota (19.33 percent ownership)
|
BLM
|
Bureau
of Land Management
|
Brazilian
Transmission Lines
|
Company’s
equity method investment in companies owning ECTE, ENTE and
ERTE
|
Btu
|
British
thermal unit
|
Carib
Power
|
Carib
Power Management LLC
|
Cascade
|
Cascade
Natural Gas Corporation
|
CBNG
|
Coalbed
natural gas
|
CEM
|
Colorado
Energy Management, LLC, a direct wholly owned subsidiary of Centennial
Resources
|
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
International
|
Centennial
Energy Resources International, Inc., a direct wholly owned subsidiary
of
Centennial Resources
|
Centennial
Power
|
Centennial
Power, Inc., a direct wholly owned subsidiary of Centennial
Resources
|
Centennial
Resources
|
Centennial
Energy Resources LLC, a direct wholly owned subsidiary of
Centennial
|
Clean
Air Act
|
Federal
Clean Air Act
|
Clean
Water Act
|
Federal
Clean Water Act
|
Colorado
Federal District Court
|
U.S.
District Court for the District of Colorado
|
Company
|
MDU
Resources Group, Inc.
|
D.C.
Appeals Court
|
U.S.
Court of Appeals for the District of Columbia Circuit
|
dk
|
Decatherm
|
DRC
|
Dakota
Resource Council
|
EBSR
|
Elk
Basin Storage Reservoir, one of Williston Basin's natural gas storage
reservoirs, which is located in Montana and Wyoming
|
ECTE
|
Empresa
Catarinense de Transmissão de Energia S.A.
|
EIS
|
Environmental
Impact Statement
|
ENTE
|
Empresa
Norte de Transmissão de Energia S.A.
|
EPA
|
U.S.
Environmental Protection Agency
|
ERTE
|
Empresa
Regional de Transmissão de Energia S.A.
|
Exchange
Act
|
Securities
Exchange Act of 1934, as amended
|
FASB
|
Financial
Accounting Standards Board
|
FERC
|
Federal
Energy Regulatory Commission
|
Fidelity
|
Fidelity
Exploration & Production Company, a direct wholly owned subsidiary of
WBI Holdings
|
FIN
|
FASB
Interpretation No.
|
FIN
48
|
Accounting
for Uncertainty in Income Taxes
|
Great
Plains
|
Great
Plains Natural Gas Co., a public utility division of the
Company
|
Grynberg
|
Jack
J. Grynberg
|
Hardin
Generating Facility
|
116-MW
coal-fired electric generating facility near Hardin,
Montana
|
Hartwell
|
Hartwell
Energy Limited Partnership
|
Howell
|
Howell
Petroleum Corporation, a wholly owned subsidiary of
Anadarko
|
Indenture
|
Indenture
dated as of December 15, 2003, as supplemented, from the Company
to The
Bank of New York, as Trustee
|
Innovatum
|
Innovatum
Inc., a former indirect wholly owned subsidiary of WBI Holdings (the
stock
and a portion of Innovatum’s assets were sold during the fourth quarter of
2006)
|
Knife
River
|
Knife
River Corporation, a direct wholly owned subsidiary of
Centennial
|
kW
|
Kilowatt
|
kWh
|
Kilowatt-hour
|
LWG
|
Lower
Willamette Group
|
MBbls
|
Thousand
barrels of oil or other liquid hydrocarbons
|
MBI
|
Morse
Bros., Inc., an indirect wholly owned subsidiary of Knife
River
|
Mcf
|
Thousand
cubic feet
|
MDU
Brasil
|
MDU
Brasil Ltda., an indirect wholly owned subsidiary of Centennial
International
|
MDU
Construction Services
|
MDU
Construction Services Group, Inc., a direct wholly owned subsidiary
of
Centennial
|
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
State Department of Environmental Quality
|
Montana
Federal District Court
|
U.S.
District Court for the District of Montana
|
Mortgage
|
Indenture
of Mortgage dated May 1, 1939, as supplemented, amended and restated,
from
the Company to The Bank of New York and Douglas J. MacInnes, successor
trustees
|
MPX
|
MPX
Termoceara Ltda. (49 percent ownership, sold in June
2005)
|
MTPSC
|
Montana
Public Service Commission
|
MW
|
Megawatt
|
ND
Health Department
|
North
Dakota Department of Health
|
NDPSC
|
North
Dakota Public Service Commission
|
NEPA
|
National
Environmental Policy Act
|
NHPA
|
National
Historic Preservation Act
|
Ninth
Circuit
|
U.S.
Ninth Circuit Court of Appeals
|
NPRC
|
Northern
Plains Resource Council
|
Order
on Rehearing
|
Order
on Rehearing and Compliance and Remanding Certain Issues for
Hearing
|
Oregon
DEQ
|
Oregon
State Department of Environmental Quality
|
Prairielands
|
Prairielands
Energy Marketing, Inc., an indirect wholly owned subsidiary of WBI
Holdings
|
SEC
|
U.S.
Securities and Exchange Commission
|
SEIS
|
Supplemental
Environmental Impact Statement
|
SFAS
|
Statement
of Financial Accounting Standards
|
SFAS
No. 87
|
Employers’
Accounting for Pensions
|
SFAS
No. 109
|
Accounting
for Income Taxes
|
SFAS
No. 142
|
Goodwill
and Other Intangible Assets
|
SFAS
No. 144
|
Accounting
for the Impairment or Disposal of Long-Lived Assets
|
SFAS
No. 157
|
Fair
Value Measurements
|
SFAS
No. 159
|
The
Fair Value Option for Financial Assets and Financial
Liabilities
|
SIP
|
State
Implementation Plan
|
TRWUA
|
Tongue
River Water Users’ Association
|
WBI
Holdings
|
WBI
Holdings, Inc., a direct wholly owned subsidiary of
Centennial
|
Williston
Basin
|
Williston
Basin Interstate Pipeline Company, an indirect wholly owned subsidiary
of
WBI Holdings
|
Wyoming
Federal District Court
|
U.S.
District Court for the District of
Wyoming
|
INTRODUCTION
The
Company is a diversified natural resource company, which was incorporated under
the laws of the state of Delaware in 1924. Its principal executive offices
are
at 1200 West Century Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650,
telephone (701) 530-1000.
Montana-Dakota,
through the electric and natural gas distribution segments,
generates, transmits and distributes electricity and distributes natural gas
in
Montana, North Dakota, South Dakota and Wyoming. Great Plains distributes
natural gas in western Minnesota and southeastern North Dakota. These operations
also supply related value-added products and services.
On
July
2, 2007, the Company acquired Cascade. For further information, see Note
20.
The
Company, through its wholly owned subsidiary, Centennial, owns WBI Holdings
(comprised of the pipeline and energy services and the natural gas and oil
production segments), Knife River (construction materials and mining segment),
MDU Construction Services (construction services segment), Centennial Resources
(independent power production segment) and Centennial Capital (reflected in
the
Other category). For more information on the Company’s business segments, see
Note 16.
INDEX
Part
I -- Financial Information
Consolidated
Statements of Income --
Three
and
Six Months Ended June 30, 2007 and 2006
Consolidated
Balance Sheets --
June
30,
2007 and 2006, and December 31, 2006
Consolidated
Statements of Cash Flows --
Six
Months Ended June 30, 2007 and 2006
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
Exhibits
Signatures
Exhibit
Index
Exhibits
PART
I -- FINANCIAL INFORMATION
ITEM
1. FINANCIAL STATEMENTS
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
STATEMENTS OF INCOME
(Unaudited)
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
thousands, except per share amounts)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
$
|
195,488
|
|
$
|
170,589
|
|
$
|
463,500
|
|
$
|
461,640
|
|
Construction
services, natural gas and oil production, construction materials
and
mining, and other
|
|
|
786,877
|
|
|
790,846
|
|
|
1,306,356
|
|
|
1,303,313
|
|
|
|
|
982,365
|
|
|
961,435
|
|
|
1,769,856
|
|
|
1,764,953
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
15,489
|
|
|
15,940
|
|
|
32,607
|
|
|
32,075
|
|
Purchased
natural gas sold
|
|
|
40,294
|
|
|
39,361
|
|
|
139,129
|
|
|
166,321
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
|
46,659
|
|
|
42,816
|
|
|
91,315
|
|
|
80,102
|
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
629,782
|
|
|
644,272
|
|
|
1,075,631
|
|
|
1,083,121
|
|
Depreciation,
depletion and amortization
|
|
|
70,044
|
|
|
64,840
|
|
|
139,846
|
|
|
125,821
|
|
Taxes,
other than income
|
|
|
37,312
|
|
|
31,976
|
|
|
69,574
|
|
|
64,216
|
|
|
|
|
839,580
|
|
|
839,205
|
|
|
1,548,102
|
|
|
1,551,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
142,785
|
|
|
122,230
|
|
|
221,754
|
|
|
213,297
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from equity method investments
|
|
|
4,030
|
|
|
2,900
|
|
|
6,084
|
|
|
6,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
income
|
|
|
883
|
|
|
2,881
|
|
|
2,215
|
|
|
5,263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
17,478
|
|
|
19,110
|
|
|
34,854
|
|
|
33,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
130,220
|
|
|
108,901
|
|
|
195,199
|
|
|
191,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
48,184
|
|
|
40,450
|
|
|
71,756
|
|
|
70,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
|
|
82,036
|
|
|
68,451
|
|
|
123,443
|
|
|
120,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from discontinued operations, net of
tax
(Note
3)
|
|
|
7,439
|
|
|
2,991
|
|
|
12,694
|
|
|
3,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
89,475
|
|
|
71,442
|
|
|
136,137
|
|
|
124,689
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
on preferred stocks
|
|
|
171
|
|
|
171
|
|
|
343
|
|
|
343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
on common stock
|
|
$
|
89,304
|
|
$
|
71,271
|
|
$
|
135,794
|
|
$
|
124,346
|
|
Earnings
per common share -- basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
.45
|
|
$
|
.38
|
|
$
|
.68
|
|
$
|
.67
|
|
Discontinued
operations, net of tax
|
|
|
.04
|
|
|
.02
|
|
|
.07
|
|
|
.02
|
|
Earnings
per common share -- basic
|
|
$
|
.49
|
|
$
|
.40
|
|
$
|
.75
|
|
$
|
.69
|
|
Earnings
per common share -- diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
.45
|
|
$
|
.38
|
|
$
|
.67
|
|
$
|
.67
|
|
Discontinued
operations, net of tax
|
|
|
.04
|
|
|
.01
|
|
|
.07
|
|
|
.02
|
|
Earnings
per common share -- diluted
|
|
$
|
.49
|
|
$
|
.39
|
|
$
|
.74
|
|
$
|
.69
|
|
Dividends
per common share
|
|
$
|
.1350
|
|
$
|
.1267
|
|
$
|
.2700
|
|
$
|
.2534
|
|
Weighted
average common shares outstanding -- basic
|
|
|
181,847
|
|
|
179,911
|
|
|
181,595
|
|
|
179,867
|
|
Weighted
average common shares outstanding -- diluted
|
|
|
182,746
|
|
|
181,107
|
|
|
182,469
|
|
|
181,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
BALANCE SHEETS
(Unaudited)
|
|
June
30,
2007
|
|
June
30,
2006
|
|
December
31,
2006
|
(In
thousands, except shares and per share amounts)
|
ASSETS
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
68,134
|
|
$
|
114,787
|
|
$
|
73,078
|
|
Receivables,
net
|
|
|
642,559
|
|
|
643,439
|
|
|
622,478
|
|
Inventories
|
|
|
221,179
|
|
|
206,682
|
|
|
204,440
|
|
Deferred
income taxes
|
|
|
---
|
|
|
11,637
|
|
|
---
|
|
Prepayments
and other current assets
|
|
|
95,235
|
|
|
90,898
|
|
|
81,083
|
|
Current
assets held for sale and related to discontinued operations
|
|
|
69,662
|
|
|
13,033
|
|
|
12,656
|
|
|
|
|
1,096,769
|
|
|
1,080,476
|
|
|
993,735
|
|
Investments
|
|
|
136,585
|
|
|
106,226
|
|
|
155,111
|
|
Property,
plant and equipment
|
|
|
4,953,171
|
|
|
4,502,534
|
|
|
4,727,725
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
1,851,825
|
|
|
1,627,887
|
|
|
1,735,302
|
|
|
|
|
3,101,346
|
|
|
2,874,647
|
|
|
2,992,423
|
|
Deferred
charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
227,029
|
|
|
227,483
|
|
|
224,298
|
|
Other
intangible assets, net
|
|
|
17,150
|
|
|
17,787
|
|
|
22,802
|
|
Other
|
|
|
113,193
|
|
|
100,785
|
|
|
103,840
|
|
Noncurrent
assets held for sale and related to discontinued operations
|
|
|
410,662
|
|
|
422,025
|
|
|
411,265
|
|
|
|
|
768,034
|
|
|
768,080
|
|
|
762,205
|
|
|
|
$
|
5,102,734
|
|
$
|
4,829,429
|
|
$
|
4,903,474
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt due within one year
|
|
$
|
131,661
|
|
$
|
159,168
|
|
$
|
84,034
|
|
Accounts
payable
|
|
|
284,208
|
|
|
290,166
|
|
|
289,836
|
|
Taxes
payable
|
|
|
38,769
|
|
|
31,248
|
|
|
54,290
|
|
Deferred
income taxes
|
|
|
1,396
|
|
|
---
|
|
|
5,969
|
|
Dividends
payable
|
|
|
24,725
|
|
|
22,967
|
|
|
24,606
|
|
Other
accrued liabilities
|
|
|
155,890
|
|
|
154,908
|
|
|
180,327
|
|
Current
liabilities held for sale and related to discontinued operations
|
|
|
14,156
|
|
|
7,986
|
|
|
14,900
|
|
|
|
|
650,805
|
|
|
666,443
|
|
|
653,962
|
|
Long-term
debt
|
|
|
1,224,286
|
|
|
1,299,175
|
|
|
1,170,548
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
570,590
|
|
|
543,278
|
|
|
546,602
|
|
Other
liabilities
|
|
|
349,895
|
|
|
279,617
|
|
|
336,916
|
|
Noncurrent
liabilities held for sale and related to discontinued operations
|
|
|
35,488
|
|
|
30,466
|
|
|
30,533
|
|
|
|
|
955,973
|
|
|
853,361
|
|
|
914,051
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
|
|
|
|
|
|
Preferred
stocks
|
|
|
15,000
|
|
|
15,000
|
|
|
15,000
|
|
Common
stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
|
|
|
|
|
|
|
Shares
issued -- $1.00 par value, 182,416,029 at June 30, 2007, 180,515,943
at
June 30, 2006 and 181,557,543 at December 31, 2006
|
|
|
182,416
|
|
|
180,516
|
|
|
181,558
|
|
Other
paid-in capital
|
|
|
895,838
|
|
|
856,366
|
|
|
874,253
|
|
Retained
earnings
|
|
|
1,190,935
|
|
|
963,194
|
|
|
1,104,210
|
|
Accumulated
other comprehensive loss
|
|
|
(8,893
|
)
|
|
(1,000
|
)
|
|
(6,482
|
)
|
Treasury
stock at cost - 538,921 shares
at
June 30, 2007, June 30, 2006 and December 31, 2006
|
|
|
(3,626
|
)
|
|
(3,626
|
)
|
|
(3,626
|
)
|
Total
common stockholders’ equity
|
|
|
2,256,670
|
|
|
1,995,450
|
|
|
2,149,913
|
|
Total
stockholders’ equity
|
|
|
2,271,670
|
|
|
2,010,450
|
|
|
2,164,913
|
|
|
|
$
|
5,102,734
|
|
$
|
4,829,429
|
|
$
|
4,903,474
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
136,137
|
|
$
|
124,689
|
|
Income
from discontinued operations, net of tax
|
|
|
12,694
|
|
|
3,792
|
|
Income
from continuing operations
|
|
|
123,443
|
|
|
120,897
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
139,846
|
|
|
125,821
|
|
Earnings,
net of distributions, from equity method investments
|
|
|
(722
|
)
|
|
(3,107
|
)
|
Deferred
income taxes
|
|
|
24,756
|
|
|
15,942
|
|
Changes
in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
Receivables
|
|
|
(14,083
|
)
|
|
(31,563
|
)
|
Inventories
|
|
|
(16,690
|
)
|
|
(33,173
|
)
|
Other
current assets
|
|
|
(25,259
|
)
|
|
(37,513
|
)
|
Accounts
payable
|
|
|
(11,644
|
)
|
|
29,003
|
|
Other
current liabilities
|
|
|
(38,040
|
)
|
|
(10,866
|
)
|
Other
noncurrent changes
|
|
|
(1,107
|
)
|
|
5,792
|
|
Net
cash provided by continuing operations
|
|
|
180,500
|
|
|
181,233
|
|
Net
cash provided by (used in) discontinued operations
|
|
|
(41,884
|
)
|
|
10,234
|
|
Net
cash provided by operating activities
|
|
|
138,616
|
|
|
191,467
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(242,729
|
)
|
|
(240,606
|
)
|
Acquisitions,
net of cash acquired
|
|
|
(329
|
)
|
|
(109,250
|
)
|
Net
proceeds from sale or disposition of property
|
|
|
10,848
|
|
|
14,878
|
|
Investments
|
|
|
17,309
|
|
|
(5,184
|
)
|
Net
cash used in continuing operations
|
|
|
(214,901
|
)
|
|
(340,162
|
)
|
Net
cash used in discontinued operations
|
|
|
(1,379
|
)
|
|
(38,119
|
)
|
Net
cash used in investing activities
|
|
|
(216,280
|
)
|
|
(378,281
|
)
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
Issuance
of long-term debt
|
|
|
186,578
|
|
|
335,653
|
|
Repayment
of long-term debt
|
|
|
(85,028
|
)
|
|
(97,158
|
)
|
Proceeds
from issuance of common stock
|
|
|
15,775
|
|
|
2,709
|
|
Dividends
paid
|
|
|
(49,300
|
)
|
|
(45,914
|
)
|
Tax
benefit on stock-based compensation
|
|
|
4,505
|
|
|
3,167
|
|
Net
cash provided by continuing operations
|
|
|
72,530
|
|
|
198,457
|
|
Net
cash provided by discontinued operations
|
|
|
---
|
|
|
---
|
|
Net
cash provided by financing activities
|
|
|
72,530
|
|
|
198,457
|
|
Effect
of exchange rate changes on cash and cash
equivalents
|
|
|
190
|
|
|
(2,354
|
)
|
Increase
(decrease) in cash and cash equivalents
|
|
|
(4,944
|
)
|
|
9,289
|
|
Cash
and cash equivalents -- beginning of year
|
|
|
73,078
|
|
|
105,498
|
|
Cash
and cash equivalents -- end of period
|
|
$
|
68,134
|
|
$
|
114,787
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS
June
30, 2007 and 2006
(Unaudited)
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 2006 Annual Report, and the
standards of accounting measurement set forth in APB Opinion No. 28 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 2006 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.
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. Discontinued
operations
During
the third quarter of 2006, the Company initiated a plan to sell Innovatum
because the Company determined that Innovatum is a non-strategic asset.
Innovatum, a component of the pipeline and energy services segment, specialized
in cable and pipeline magnetization and location. During the fourth quarter
of
2006, the stock and a portion of the assets of Innovatum were sold and the
Company expects to sell the remaining assets of Innovatum within one year of
the
initial plan to sell. The loss on disposal on the portion of Innovatum that
has
been sold was not material. The Company does not expect to have any involvement
in the operations of Innovatum after the sale.
During
the fourth quarter of 2006, the Company initiated a plan to sell certain of
the
domestic assets of Centennial Resources, which largely comprise the independent
power production segment. The plan to sell was based on the increased market
demand for independent power production assets, combined with the Company’s
desire to efficiently fund future capital needs. The results of operations
of
these assets were shown in continuing operations in the Company’s financial
statements in the 2006 Annual Report as the Company intended to have significant
continuing involvement with these assets in the form of continuing existing
operation and maintenance agreements between CEM and these assets after the
sale.
The
Company subsequently committed to a plan to sell CEM due to strong interest
in
the operations of CEM during the bidding process for the domestic independent
power production assets in the first quarter of 2007. As a result of the
Company’s commitment to a plan to sell CEM, the Company will no longer have
significant continuing involvement in the operations of the other domestic
independent power production assets after the sale. Therefore, in accordance
with SFAS No. 144, the results of operations of all of the domestic independent
power production assets, including CEM, are presented as discontinued
operations. For more information on the sale of the domestic independent power
production assets, see Note 20.
In
accordance with SFAS No. 144, the Company’s consolidated financial statements
and accompanying notes for prior periods have been restated to present the
results of operations of Innovatum and the domestic independent power production
assets as discontinued operations. In addition, the assets and liabilities
of
these operations are treated as held for sale, and as a result, no depreciation,
depletion and amortization expense was recorded from the time each of the assets
was classified as held for sale, respectively.
In
accordance with SFAS No. 142, at the time the Company committed to the plan
to
sell each of the assets, the Company was required to test the respective assets
for goodwill impairment. The fair value of Innovatum, a reporting unit for
goodwill impairment testing, was estimated using the expected proceeds from
the
sale, which was estimated to be the current book value of the assets of
Innovatum other than its goodwill. As a result, a goodwill impairment loss
of
$4.3 million (before tax) was recognized and recorded as part of discontinued
operations, net of tax, in the Consolidated Statements of Income in the third
quarter of 2006. There were no goodwill impairments associated with the other
assets held for sale.
Operating
results related to Innovatum were as follows:
|
|
Three
Months
Ended
June
30,
|
|
Six
Months
Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$
|
439
|
|
$
|
632
|
|
$
|
689
|
|
$
|
1,142
|
|
Income
(loss) from discontinued operations before income tax expense
(benefit)
|
|
|
104
|
|
|
(389
|
)
|
|
28
|
|
|
(862
|
)
|
Income
tax expense (benefit)
|
|
|
15
|
|
|
(116
|
)
|
|
(29
|
)
|
|
(265
|
)
|
Income
(loss) from discontinued operations, net of tax
|
|
$
|
89
|
|
$
|
(273
|
)
|
$
|
57
|
|
$
|
(597
|
)
|
Operating
results related to the domestic independent power production assets were as
follows:
|
|
Three
Months
Ended
June
30,
|
|
Six
Months
Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
Operating
revenues
|
|
$
|
64,291
|
|
$
|
11,716
|
|
$
|
98,887
|
|
$
|
22,982
|
|
Income
from discontinued operations before income tax expense
(benefit)
|
|
|
9,532
|
|
|
2,540
|
|
|
16,923
|
|
|
3,031
|
|
Income
tax expense (benefit)
|
|
|
2,182
|
|
|
(724
|
)
|
|
4,286
|
|
|
(1,358
|
)
|
Income
from discontinued operations, net of tax
|
|
$
|
7,350
|
|
$
|
3,264
|
|
$
|
12,637
|
|
$
|
4,389
|
|
The
carrying amounts of the major assets and liabilities related to the domestic
independent power production assets held for sale, as well as the major assets
and liabilities related to Innovatum, were as follows:
|
|
June
30,
2007
|
|
June
30,
2006
|
|
December
31, 2006
|
|
|
|
(In
thousands)
|
|
Cash
and cash equivalents
|
|
$
|
1,575
|
|
$
|
1,911
|
|
$
|
1,878
|
|
Receivables,
net
|
|
|
7,878
|
|
|
7,753
|
|
|
8,307
|
|
Inventories
|
|
|
555
|
|
|
1,064
|
|
|
490
|
|
Prepayments
and other current assets
|
|
|
59,654
|
|
|
2,305
|
|
|
1,981
|
|
Total
current assets held for sale and related
to
discontinued
operations
|
|
$
|
69,662
|
|
$
|
13,033
|
|
$
|
12,656
|
|
Net
property, plant and equipment
|
|
$
|
391,708
|
|
$
|
396,434
|
|
$
|
390,679
|
|
Goodwill
|
|
|
11,167
|
|
|
15,472
|
|
|
11,167
|
|
Other
intangible assets, net
|
|
|
7,241
|
|
|
7,763
|
|
|
7,162
|
|
Other
|
|
|
546
|
|
|
2,356
|
|
|
2,257
|
|
Total
noncurrent assets held for sale and related
to
discontinued
operations
|
|
$
|
410,662
|
|
$
|
422,025
|
|
$
|
411,265
|
|
Accounts
payable
|
|
$
|
7,264
|
|
$
|
4,785
|
|
$
|
11,557
|
|
Other
accrued liabilities
|
|
|
6,892
|
|
|
3,201
|
|
|
3,343
|
|
Total
current liabilities held for sale and related
to
discontinued
operations
|
|
$
|
14,156
|
|
$
|
7,986
|
|
$
|
14,900
|
|
Deferred
income taxes
|
|
$
|
32,888
|
|
$
|
28,149
|
|
$
|
27,956
|
|
Other
liabilities
|
|
|
2,600
|
|
|
2,317
|
|
|
2,577
|
|
Total
noncurrent liabilities held for sale and
related to
discontinued
operations
|
|
$
|
35,488
|
|
$
|
30,466
|
|
$
|
30,533
|
|
4. Common
stock
At
the
Annual Meeting of Stockholders held on April 24, 2007, the Company’s common
stockholders approved an amendment to the Restated Certificate of Incorporation
that increased the authorized number of common shares from 250 million shares
to
500 million shares with a par value of $1.00 per share.
5. Allowance
for doubtful accounts
The
Company's allowance for doubtful accounts as of June 30, 2007 and 2006, and
December 31, 2006, was $7.7 million, $7.2 million and $7.7 million,
respectively.
6. Natural
gas in underground storage
Natural
gas in underground storage for the Company's regulated operations is carried
at
cost using the last-in, first-out method. The portion of the cost of natural
gas
in underground storage expected to be used within one year was included in
inventories and was $9.7 million, $19.4 million and $32.6 million at June 30,
2007 and 2006, and December 31, 2006, respectively. The remainder of
natural gas in underground storage was included in other assets and was $44.2
million, $43.2 million, and $44.2 million at June 30, 2007 and 2006, and
December 31, 2006, respectively.
7. Inventories
Inventories,
other than natural gas in underground storage for the Company’s regulated
operations, consisted primarily of aggregates held for resale of $100.6 million,
$93.1 million and $88.1 million; materials and supplies of $75.0 million, $70.3
million and $54.1 million; and other inventories of $35.9 million, $23.9 million
and $29.6 million, as of June 30, 2007 and 2006, and December 31, 2006,
respectively. These inventories were stated at the lower of average cost or
market value.
8. 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, restricted stock grants and performance share awards.
For the three and six months ended June 30, 2007 and 2006, there were no shares
excluded from the calculation of diluted earnings per share. Common stock
outstanding includes issued shares less shares held in treasury.
9. Cash
flow information
Cash
expenditures for interest and income taxes were as follows:
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
$
|
35,028
|
|
$
|
27,988
|
|
Income
taxes
|
|
$
|
113,919
|
|
$ |
78,382
|
|
Income
taxes paid for the six months ended June 30, 2007, increased from the amount
paid for the six months ended June 30, 2006, primarily due to estimated
quarterly income tax payments on the estimated gain on the sale of the domestic
independent power production assets as discussed in Note 20.
10. New
accounting standards
FIN
48 In
July
2006, the FASB issued FIN 48. FIN 48 clarifies the application of SFAS No.
109
by defining a criterion that an individual tax position must meet for any part
of the benefit of that position to be recognized in an enterprise’s financial
statements. The criterion allows for recognition in the financial statements
of
a tax position when it is more likely than not that the position will be
sustained upon examination. FIN 48 was effective for the Company on January
1,
2007. The adoption of FIN 48 did not have a material effect on the Company’s
financial position or results of operations. For more information on the
implementation of FIN 48, see Note 15.
SFAS
No. 157 In
September 2006, the FASB issued SFAS No. 157. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures about
fair value measurements. The standard applies under other accounting
pronouncements that require or permit fair value measurements with certain
exceptions. SFAS No. 157 is effective for the Company on January 1, 2008. The
Company is evaluating the effects of the adoption of SFAS No. 157.
SFAS
No. 159
In
February 2007, the FASB issued SFAS No. 159. SFAS No. 159 permits entities
to
choose to measure many financial instruments and certain other items at fair
value that are not currently required to be measured at fair value. The standard
also establishes presentation and disclosure requirements designed to facilitate
comparisons between entities that choose different measurement attributes for
similar types of assets and liabilities. SFAS No. 159 is effective for the
Company on January 1, 2008. The Company is evaluating the effects of the
adoption of SFAS No. 159.
11. 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 and foreign currency
translation adjustments. For more information on derivative instruments, see
Note 14.
Comprehensive
income, and the components of other comprehensive income (loss) and related
tax
effects, were as follows:
|
Three
Months Ended
June
30,
|
|
|
2007
|
|
2006
|
|
|
(In
thousands)
|
|
Net
income
|
$ |
89,475
|
|
$
|
71,442
|
|
Other
comprehensive income:
|
|
|
|
|
|
|
Net
unrealized gain on derivative instruments qualifying as
hedges:
|
|
|
|
|
|
|
Net
unrealized gain on derivative instruments arising during the period,
net
of tax of $6,096 and $4,051 in 2007 and 2006, respectively
|
|
9,739
|
|
|
6,471
|
|
Less:
Reclassification adjustment for gain on derivative instruments included
in
net income, net of tax of $1,509 and $1,033 in 2007 and 2006,
respectively
|
|
2,411
|
|
|
1,650
|
|
Net
unrealized gain on derivative instruments qualifying as
hedges
|
|
7,328
|
|
|
4,821
|
|
Foreign
currency translation adjustment
|
|
3,576
|
|
|
(2,176
|
)
|
|
|
10,904
|
|
|
2,645
|
|
Comprehensive
income
|
$ |
100,379
|
|
$
|
74,087
|
|
|
Six
Months Ended
June
30,
|
|
|
2007
|
|
2006
|
|
|
(In
thousands)
|
|
Net
income
|
$ |
136,137
|
|
$
|
124,689
|
|
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 $1,204 and $17,652 in 2007 and 2006, respectively
|
|
1,923
|
|
|
28,197
|
|
Less:
Reclassification adjustment for gain (loss) on derivative instruments
included in net income, net of tax of $6,272 and $4,254 in 2007 and
2006,
respectively
|
|
10,018
|
|
|
(6,796
|
) |
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
(8,095
|
) |
|
34,993
|
|
Foreign
currency translation adjustment
|
|
5,684
|
|
|
(2,177
|
) |
|
|
(2,411
|
) |
|
32,816
|
|
Comprehensive
income
|
$ |
133,726
|
|
$
|
157,505
|
|
12. Equity
method investments
The
Company’s equity method investments at June 30, 2007, include Hartwell and the
Brazilian Transmission Lines.
In
February 2004, Centennial International acquired 49.99 percent of Carib Power.
Carib Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired
electric generating facility in Trinidad and Tobago. On February 26, 2007,
the
Company sold its interest in Carib Power. The sale did not have a significant
effect on the Company’s results of operations.
In
September 2004, Centennial Resources, through indirect wholly owned
subsidiaries, acquired a 50-percent ownership interest in Hartwell, which owns
a
310-MW natural gas-fired electric generating facility near Hartwell, Georgia.
On
July 10, 2007, the Company sold its ownership interest in Hartwell. For more
information, see Note 20.
In
August
2006, MDU Brasil acquired ownership interests in companies owning three electric
transmission lines. The interests involve the ENTE (13.3-percent ownership
interest), ERTE (13.3-percent ownership interest) and ECTE (25-percent ownership
interest) electric transmission lines, which are primarily in northeastern
and
southern Brazil.
At
June
30, 2007 and 2006, and December 31, 2006, the Company's equity method
investments had total assets of $469.2 million, $228.9 million and $583.6
million, respectively, and long-term debt of $277.2 million, $149.5 million
and
$321.5 million, respectively. The Company's investment in its equity method
investments was approximately $80.6 million, $50.1 million and $102.0 million,
including undistributed earnings of $7.6 million, $6.5 million and $8.5
million, at June 30, 2007 and 2006, and December 31, 2006, respectively.
13. 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, 2007
|
|
2007
|
|
the
Year*
|
|
2007
|
|
|
|
(In
thousands)
|
|
Electric
|
$ |
---
|
$ |
---
|
$ |
---
|
|
Natural
gas distribution
|
|
---
|
|
---
|
|
---
|
|
Construction
services
|
|
86,942
|
|
3,596
|
|
90,538
|
|
Pipeline
and energy services
|
|
1,159
|
|
---
|
|
1,159
|
|
Natural
gas and oil production
|
|
---
|
|
---
|
|
---
|
|
Construction
materials and mining
|
|
136,197
|
|
(865)
|
|
135,332
|
|
Independent
power production
|
|
---
|
|
---
|
|
---
|
|
Other
|
|
---
|
|
---
|
|
---
|
|
Total
|
$ |
224,298
|
$ |
2,731
|
$ |
227,029
|
|
* Includes
purchase price adjustments that were not material related to acquisitions
in a prior period. |
|
|
|
|
|
Balance
|
|
Goodwill
|
|
Balance
|
|
|
|
as
of
|
|
Acquired
|
|
as
of
|
|
Six
Months Ended
|
|
January
1,
|
|
During
|
|
June
30,
|
|
June
30, 2006
|
|
2006
|
|
the
Year*
|
|
2006
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
80,970
|
|
|
5,981
|
|
|
86,951
|
|
Pipeline
and energy services
|
|
|
1,159
|
|
|
---
|
|
|
1,159
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
6,109
|
|
|
139,373
|
|
Independent
power production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
215,393
|
|
$
|
12,090
|
|
$
|
227,483
|
|
* Includes
purchase price adjustments that were not material related to acquisitions
in a prior period.
|
Year
Ended
December
31, 2006
|
|
Balance
as
of
January 1,
2006
|
|
Goodwill
Acquired
During
the Year*
|
|
Balance
as
of
December
31, 2006
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
80,970
|
|
|
5,972
|
|
|
86,942
|
|
Pipeline
and energy services
|
|
|
1,159
|
|
|
---
|
|
|
1,159
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
2,933
|
|
|
136,197
|
|
Independent
power production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
215,393
|
|
$
|
8,905
|
|
$
|
224,298
|
|
|
*
|
Includes
purchase price adjustments that were not material related to acquisitions
in a prior period.
|
Other
intangible assets were as follows:
|
|
June
30,
2007
|
|
June
30,
2006
|
|
December
31,
2006
|
|
|
|
(In
thousands)
|
|
Amortizable
intangible assets:
|
|
|
|
|
|
|
|
|
Customer
relationships
|
|
|
|
|
$
|
13,959
|
|
$
|
6,900
|
|
$
|
13,030
|
|
Accumulated
amortization
|
|
|
|
|
|
(3,234
|
)
|
|
(855
|
)
|
|
(1,890
|
)
|
|
|
|
|
|
|
10,725
|
|
|
6,045
|
|
|
11,140
|
|
Noncompete
agreements
|
|
|
|
|
|
7,434
|
|
|
11,984
|
|
|
12,886
|
|
Accumulated
amortization
|
|
|
|
|
|
(2,926
|
)
|
|
(8,900
|
)
|
|
(8,540
|
)
|
|
|
|
|
|
|
4,508
|
|
|
3,084
|
|
|
4,346
|
|
Acquired
contracts
|
|
|
|
|
|
1,186
|
|
|
8,164
|
|
|
8,307
|
|
Accumulated
amortization
|
|
|
|
|
|
(1,156
|
)
|
|
(3,802
|
)
|
|
(4,646
|
)
|
|
|
|
|
|
|
30
|
|
|
4,362
|
|
|
3,661
|
|
Other
|
|
|
|
|
|
2,559
|
|
|
4,662
|
|
|
5,062
|
|
Accumulated
amortization
|
|
|
|
|
|
(672
|
)
|
|
(890
|
)
|
|
(1,407
|
)
|
|
|
|
|
|
|
1,887
|
|
|
3,772
|
|
|
3,655
|
|
Unamortizable
intangible assets
|
|
|
|
|
|
---
|
|
|
524
|
|
|
---
|
|
Total
|
|
|
|
|
$
|
17,150
|
|
$
|
17,787
|
|
$
|
22,802
|
|
The
unamortizable intangible assets at June 30, 2006, were recognized in accordance
with SFAS No. 87, which requires that if an additional minimum liability is
recognized, an equal amount shall be recognized as an intangible asset provided
that the asset recognized shall not exceed the amount of unrecognized prior
service cost.
Amortization
expense for amortizable intangible assets for the three and six months ended
June 30, 2007, was $900,000 and $1.9 million, respectively. Amortization expense
for the three and six months ended June 30, 2006, and for the year ended
December 31, 2006, was $1.3 million, $2.1 million and $4.3 million,
respectively. Estimated amortization expense for amortizable intangible assets
is $3.7 million in 2007, $2.8 million in 2008, $2.4 million in 2009, $1.9
million in 2010, $1.5 million in 2011 and $6.8 million thereafter.
14. Derivative
instruments
From
time
to time, the Company utilizes 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, 2007, 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 2006 Annual Report.
At
June
30, 2007, Fidelity held natural gas swap and collar derivative instruments
designated as cash flow hedging instruments and had no outstanding oil
derivative instruments.
Hedging
activities
Fidelity
utilizes natural gas and oil price swap and collar agreements to manage a
portion of the market risk associated with fluctuations in the price of natural
gas and oil on its forecasted sales of natural gas and oil production. Each
of
the price swap and collar agreements was designated as a hedge of the forecasted
sale of the related production.
The
fair
value of the hedging instruments must be estimated as of the end of each
reporting period and is recorded on the Consolidated Balance Sheets as an asset
or a liability. Changes in the fair value attributable to the effective portion
of hedging instruments, net of tax, are recorded in stockholders' equity as
a
component of accumulated other comprehensive income (loss). At the date the
natural gas or oil production 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 the Company receives for its natural gas and oil production are also
generally based on market prices.
For
the
three and six months ended June 30, 2007, the amount of hedge ineffectiveness
was immaterial. In the second quarter of 2006, Fidelity had oil collar
agreements that became ineffective and no longer qualified for hedge accounting.
The amount of ineffectiveness for the three and six months ended June 30, 2006,
related to these collar agreements was approximately $979,000 (before tax)
and
was recorded in operation and maintenance expense. The amount of hedge
ineffectiveness on Fidelity’s remaining hedges was immaterial for the three and
six months ended June 30, 2006. For the three and six months ended June 30,
2007
and 2006, Fidelity did not exclude any components of the derivative instruments’
gain or loss from the assessment of hedge effectiveness. Gains and losses must
be reclassified into earnings as a result of the discontinuance of cash flow
hedges if it is probable that the original forecasted transactions will not
occur. There were no such reclassifications into earnings as a result of the
discontinuance of hedges.
Gains
and
losses on derivative instruments that are reclassified from accumulated other
comprehensive income (loss) to current-period earnings are included in the
line
item in which the hedged item is recorded. As of June 30, 2007, the maximum
term
of Fidelity’s swap and collar agreements, in which Fidelity is hedging its
exposure to the variability in future cash flows for forecasted transactions,
is
18 months. The Company estimates that over the next 12 months net gains of
approximately $11.6 million (after tax) will be reclassified from accumulated
other comprehensive income into earnings, subject to changes in natural gas
market prices, as the hedged transactions affect earnings.
15.
|
Uncertainty
in income taxes
|
On
January 1, 2007, the Company adopted FIN 48 as discussed in Note
10.
The
Company and its subsidiaries file income tax returns in the U.S. federal
jurisdiction and various state, local and foreign jurisdictions. With few
exceptions, the Company is no longer subject to U.S. federal, state and local,
or non-U.S. income tax examinations by tax authorities for years ending prior
to
2003.
Upon
the
adoption of FIN 48, the Company recognized a decrease in the liability for
unrecognized tax benefits, which was not material and was accounted for as
an
increase to the January 1, 2007, balance of retained earnings. At the date
of
adoption, the amount of unrecognized tax benefits was $4.5 million.
Included
in the balance of unrecognized tax benefits at the date of adoption are $3.0
million of tax positions for which the ultimate deductibility is highly certain
but for which there is uncertainty about the timing of such deductibility.
Because of the impact of deferred tax accounting, other than interest and
penalties, the disallowance of the shorter deductibility period would not affect
the annual effective tax rate but would accelerate the payment of cash to the
taxing authority to an earlier period. The amount of unrecognized tax benefits
at the date of adoption that, if recognized, would affect the effective tax
rate
was $1.5 million, including $304,000 for the payment of interest and penalties.
The Company recognizes interest and penalties accrued related to unrecognized
tax benefits in income taxes.
16. Business
segment data
The
Company’s reportable segments are those that are based on the Company’s method
of internal reporting, which generally segregates the strategic business units
due to differences in products, services and regulation. The vast majority
of
the Company’s operations are located within the United States. The Company also
has investments in foreign countries, which largely consist of investments
in
companies owning electric transmission lines.
The
electric segment generates, transmits and distributes electricity in Montana,
North Dakota, South Dakota and Wyoming. The natural gas distribution segment
distributes natural gas in those states as well as in western Minnesota. These
operations also supply related value-added products and services.
The
construction services segment specializes in electric line construction,
pipeline construction, inside electrical wiring, cabling and mechanical work,
fire protection and the manufacture and distribution of specialty equipment.
The
pipeline and energy services segment provides natural gas transportation,
underground storage and gathering services through regulated and nonregulated
pipeline systems primarily in the Rocky Mountain and northern Great Plains
regions of the United States. The pipeline and energy services segment also
provides energy-related management services.
The
natural gas and oil production segment is engaged in natural gas and oil
acquisition, exploration, development and production activities primarily in
the
Rocky Mountain and Mid-Continent regions of the United States and in and around
the Gulf of Mexico.
The
construction materials and mining segment mines aggregates and markets crushed
stone, sand, gravel and related construction materials, including ready-mixed
concrete, cement, asphalt, liquid asphalt and other value-added products. It
also performs integrated construction services. The construction materials
and
mining segment operates in the central, southern and western United States
and
Alaska and Hawaii.
The
independent power production segment’s international operation has investments
in companies that own electric transmission lines. This segment’s domestic
operations owned, built and operated electric generating facilities in the
United States and had investments in natural resource-based projects. Electric
capacity and energy produced at its power plants primarily were sold under
mid-
and long-term contracts to nonaffiliated entities. For more information
regarding the discontinued operations of the domestic operations of this segment
and the sale of these assets, see Notes 3 and 20.
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
information below follows the same accounting policies as described in Note
1 of
the Company’s Notes to Consolidated Financial Statements in the 2006 Annual
Report. Information on the Company’s businesses was as follows:
|
|
|
|
Inter-
|
|
|
|
Three
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
on Common
|
|
Ended
June 30, 2007
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
44,591
|
|
$
|
---
|
|
$
|
3,568
|
|
Natural
gas distribution
|
|
|
53,403
|
|
|
---
|
|
|
(559
|
)
|
Pipeline
and energy services
|
|
|
97,494
|
|
|
14,660
|
|
|
6,228
|
|
|
|
|
195,488
|
|
|
14,660
|
|
|
9,237
|
|
Construction
services
|
|
|
263,483
|
|
|
349
|
|
|
13,026
|
|
Natural
gas and oil production
|
|
|
67,924
|
|
|
59,471
|
|
|
35,166
|
|
Construction
materials and mining
|
|
|
455,470
|
|
|
---
|
|
|
25,541
|
|
Independent
power production
|
|
|
---
|
|
|
---
|
|
|
5,971
|
|
Other
|
|
|
---
|
|
|
2,440
|
|
|
363
|
|
|
|
|
786,877
|
|
|
62,260
|
|
|
80,067
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(76,920
|
)
|
|
---
|
|
Total
|
|
$
|
982,365
|
|
$
|
---
|
|
$
|
89,304
|
|
|
|
|
|
Inter-
|
|
|
|
|
|
External
|
|
segment
|
|
Earnings
|
|
Three
Months
|
|
Operating
|
|
Operating
|
|
on
Common
|
|
Ended
June 30, 2006
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
40,875
|
|
$
|
---
|
|
$
|
509
|
|
Natural
gas distribution
|
|
|
45,845
|
|
|
---
|
|
|
(2,530
|
)
|
Pipeline
and energy services
|
|
|
83,869
|
|
|
18,568
|
|
|
5,580
|
|
|
|
|
170,589
|
|
|
18,568
|
|
|
3,559
|
|
Construction
services
|
|
|
243,062
|
|
|
136
|
|
|
9,679
|
|
Natural
gas and oil production
|
|
|
62,906
|
|
|
51,206
|
|
|
30,979
|
|
Construction
materials and mining
|
|
|
484,878
|
|
|
---
|
|
|
25,311
|
|
Independent
power production
|
|
|
---
|
|
|
---
|
|
|
1,504
|
|
Other
|
|
|
---
|
|
|
2,318
|
|
|
239
|
|
|
|
|
790,846
|
|
|
53,660
|
|
|
67,712
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(72,228
|
)
|
|
---
|
|
Total
|
|
$
|
961,435
|
|
$
|
---
|
|
$
|
71,271
|
|
|
|
|
|
Inter-
|
|
|
|
Six
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
on Common
|
|
Ended
June 30, 2007
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
91,695
|
|
$
|
---
|
|
$
|
7,353
|
|
Natural
gas distribution
|
|
|
189,465
|
|
|
---
|
|
|
5,584
|
|
Pipeline
and energy services
|
|
|
182,340
|
|
|
42,952
|
|
|
11,938
|
|
|
|
|
463,500
|
|
|
42,952
|
|
|
24,875
|
|
Construction
services
|
|
|
500,120
|
|
|
474
|
|
|
20,260
|
|
Natural
gas and oil production
|
|
|
123,193
|
|
|
122,781
|
|
|
65,787
|
|
Construction
materials and mining
|
|
|
683,043
|
|
|
---
|
|
|
15,745
|
|
Independent
power production
|
|
|
---
|
|
|
---
|
|
|
8,488
|
|
Other
|
|
|
---
|
|
|
4,880
|
|
|
639
|
|
|
|
|
1,306,356
|
|
|
128,135
|
|
|
110,919
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(171,087
|
)
|
|
---
|
|
Total
|
|
$
|
1,769,856
|
|
$
|
---
|
|
$
|
135,794
|
|
|
|
|
|
Inter-
|
|
|
|
|
|
External
|
|
segment
|
|
Earnings
|
|
Six
Months
|
|
Operating
|
|
Operating
|
|
on
Common
|
|
Ended
June 30, 2006
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
85,905
|
|
$
|
---
|
|
$
|
4,305
|
|
Natural
gas distribution
|
|
|
198,124
|
|
|
---
|
|
|
2,793
|
|
Pipeline
and energy services
|
|
|
177,611
|
|
|
51,374
|
|
|
10,149
|
|
|
|
|
461,640
|
|
|
51,374
|
|
|
17,247
|
|
Construction
services
|
|
|
466,747
|
|
|
246
|
|
|
15,077
|
|
Natural
gas and oil production
|
|
|
118,004
|
|
|
124,498
|
|
|
72,237
|
|
Construction
materials and mining
|
|
|
718,562
|
|
|
---
|
|
|
16,437
|
|
Independent
power production
|
|
|
---
|
|
|
---
|
|
|
2,846
|
|
Other
|
|
|
---
|
|
|
4,087
|
|
|
502
|
|
|
|
|
1,303,313
|
|
|
128,831
|
|
|
107,099
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(180,205
|
)
|
|
---
|
|
Total
|
|
$
|
1,764,953
|
|
$
|
---
|
|
$
|
124,346
|
|
The
pipeline and energy services segment recognized income from discontinued
operations, net of tax, of $89,000 and $57,000 for the three and six months
ended June 30, 2007, respectively, and a loss from discontinued operations,
net
of tax of $273,000 and $597,000 for the three and six months ended June 30,
2006, respectively. The independent power production segment recognized income
from discontinued operations, net of tax, of $7.4 million and $12.6 million
for
the three and six months ended June 30, 2007, respectively, and $3.3 million
and
$4.4 million for the three and six months ended June 30, 2006, respectively.
Excluding the income (loss) from discontinued operations at pipeline and energy
services, earnings (loss) 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 mining, independent power production, and other are all from
nonregulated operations.
17. Employee
benefit plans
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. Components of
net
periodic benefit cost for the Company's pension and other postretirement benefit
plans were as follows:
Three
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
Ended
June 30,
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
2,011
|
|
|
|
|
$
|
2,301
|
|
|
|
|
$
|
447
|
|
|
|
|
$
|
472
|
|
Interest
cost
|
|
|
4,222
|
|
|
|
|
|
4,074
|
|
|
|
|
|
1,180
|
|
|
|
|
|
928
|
|
Expected
return on assets
|
|
|
(5,094
|
)
|
|
|
|
|
(4,718
|
)
|
|
|
|
|
(1,279
|
)
|
|
|
|
|
(926
|
)
|
Amortization
of prior service cost
|
|
|
207
|
|
|
|
|
|
257
|
|
|
|
|
|
14
|
|
|
|
|
|
12
|
|
Recognized
net actuarial (gain) loss
|
|
|
426
|
|
|
|
|
|
509
|
|
|
|
|
|
164
|
|
|
|
|
|
(85
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
---
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
635
|
|
|
|
|
|
531
|
|
Net
periodic benefit cost, including amount capitalized
|
|
|
1,772
|
|
|
|
|
|
2,422
|
|
|
|
|
|
1,161
|
|
|
|
|
|
932
|
|
Less
amount capitalized
|
|
|
217
|
|
|
|
|
|
225
|
|
|
|
|
|
90
|
|
|
|
|
|
79
|
|
Net
periodic benefit cost
|
|
$
|
1,555
|
|
|
|
|
$
|
2,197
|
|
|
|
|
$
|
1,071
|
|
|
|
|
$
|
853
|
|
Six
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
Ended
June 30,
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
4,261
|
|
$
|
4,602
|
|
$
|
980
|
|
$
|
943
|
|
Interest
cost
|
|
|
8,363
|
|
|
8,148
|
|
|
2,118
|
|
|
1,857
|
|
Expected
return on assets
|
|
|
(10,164
|
)
|
|
(9,436
|
)
|
|
(2,372
|
)
|
|
(1,851
|
)
|
Amortization
of prior service cost
|
|
|
416
|
|
|
513
|
|
|
25
|
|
|
23
|
|
Recognized
net actuarial (gain) loss
|
|
|
500
|
|
|
1,018
|
|
|
(149
|
)
|
|
(169
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
---
|
|
|
(2
|
)
|
|
1,166
|
|
|
1,062
|
|
Net
periodic benefit cost, including amount capitalized
|
|
|
3,376
|
|
|
4,843
|
|
|
1,768
|
|
|
1,865
|
|
Less
amount capitalized
|
|
|
368
|
|
|
381
|
|
|
141
|
|
|
125
|
|
Net
periodic benefit cost
|
|
$
|
3,008
|
|
$
|
4,462
|
|
$
|
1,627
|
|
$
|
1,740
|
|
In
addition to the qualified plan defined pension benefits reflected in the table,
the Company also has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that generally provides for
defined benefit payments at age 65 following the employee’s retirement or to
their beneficiaries upon death for a 15-year period. The Company's net periodic
benefit cost for this plan for the three and six months ended June 30, 2007,
was
$2.1 million and $3.9 million, respectively. The Company’s net periodic benefit
cost for this plan for the three and six months ended June 30, 2006, was $1.9
million and $3.9 million, respectively.
18. Regulatory
matters and revenues subject to refund
On
July
12, 2007, Montana-Dakota filed an application with the MTPSC for an electric
rate increase. Montana-Dakota requested a total of $7.8 million annually or
approximately 22 percent above current rates. Montana-Dakota is requesting
a
fuel and purchased power tracking adjustment and an off-system sales margin
sharing adjustment. Montana-Dakota also requested an interim increase of $3.9
million annually, subject to refund. A final order is expected from the MTPSC
by
May 2008.
In
November 2006, Montana-Dakota filed an application with the NDPSC for approval
of advance determination of prudence of Montana-Dakota’s participation and
ownership interest in Big Stone II, which is expected to be completed in 2012.
Hearings on the application were held June 26-28, 2007. An order on the
application is expected by September 2007.
In
December 1999, Williston Basin filed a general natural gas rate change
application with the FERC. Williston Basin began collecting such rates effective
June 1, 2000, subject to refund. Currently, the only remaining issue outstanding
related to this rate change application is in regard to certain service
restrictions. In May 2004, the FERC remanded this issue to an ALJ for
resolution. In November 2005, the FERC issued an Order on Initial Decision
affirming the ALJ’s Initial Decision regarding certain service and annual demand
quantity restrictions. In April 2006, the FERC issued an Order on Rehearing
denying Williston Basin’s Request for Rehearing of the FERC’s Order on Initial
Decision. In April 2006, Williston Basin appealed to the D.C. Appeals Court
certain issues addressed by the FERC’s Order on Initial Decision and its Order
on Rehearing. The matter concerning the service restrictions is pending
resolution by the D.C. Appeals Court.
19. Contingencies
Litigation
Royalties
Case In
June
1997, Grynberg, acting on behalf of the United States, filed suit under the
Federal False Claims Act against Williston Basin and Montana-Dakota. He also
filed more than 70 similar suits against natural gas transmission companies
and
producers, gatherers and processors of natural gas. Grynberg alleged improper
measurement of the heating content and volume of natural gas purchased by the
defendants resulting in the underpayment of royalties to the United States.
All
cases were consolidated in Wyoming Federal District Court.
In
October 2006, the Wyoming Federal District Court ordered that the actions
against Williston Basin and Montana-Dakota be dismissed. Grynberg filed a Notice
of Appeal of the decision to the U.S. Tenth Circuit Court of Appeals in November
2006.
On
March
6, 2007, a settlement was reached between Grynberg, Williston Basin and
Montana-Dakota. The case was dismissed by the U.S. Tenth Circuit Court of
Appeals on April 20, 2007.
Coalbed
Natural Gas Operations Fidelity
has been named as a defendant in, and/or certain of its operations are or have
been the subject of, more than a dozen lawsuits filed in connection with its
CBNG development in the Powder River Basin in Montana and Wyoming. These
lawsuits were filed in federal and state courts in Montana between June 2000
and
January 2007 by a number of environmental organizations, including the NPRC
and
the Montana Environmental Information Center, as well as the TRWUA and the
Northern Cheyenne Tribe. Portions of three of the lawsuits have been transferred
to the Wyoming Federal District Court. The lawsuits involve allegations that
Fidelity and/or various government agencies are in violation of state and/or
federal law, including the Clean Water Act, the NEPA, the Federal Land
Management Policy Act, the NHPA, the Montana State Constitution, the Montana
Environmental Policy Act and the Montana Water Quality Act. The suits that
remain extant include a variety of claims that state and federal government
agencies violated various environmental laws that impose procedural and
substantive requirements. The lawsuits seek injunctive relief, invalidation
of
various permits and unspecified damages. Fidelity has intervened or moved to
intervene in three lawsuits filed by other gas producers which challenge the
adoption of rules by the BER related to management of water associated with
CBNG
production. The state of Wyoming has filed a similar suit and Fidelity has
also
moved to intervene in that action.
In
suits
filed in the Montana Federal District Court, the NPRC and the Northern Cheyenne
Tribe asserted that the BLM violated NEPA and other federal laws when approving
the 2003 EIS analyzing CBNG development in southeastern Montana. The Montana
Federal District Court, in February 2005, entered a ruling finding that the
2003
EIS was inadequate. The Montana Federal District Court later entered an order
that would have allowed limited CBNG development in the Powder River Basin
in
Montana pending the BLM's preparation of a SEIS. The plaintiffs appealed the
decision to the Ninth Circuit because the Montana Federal District Court
declined to enter an injunction enjoining all development pending completion
of
the SEIS. The Montana Federal District Court also declined to enter an
injunction pending the appeal. In May 2005, the Ninth Circuit granted the
request of the NPRC and the Northern Cheyenne Tribe and, pending appeal or
further order from the Ninth Circuit, enjoined the BLM from approving any new
CBNG development of federal minerals in the Montana Powder River Basin. The
Ninth Circuit also enjoined Fidelity from drilling any additional federally
permitted wells associated with its Montana Coal Creek Project and from
constructing infrastructure to produce and transport CBNG from the Coal Creek
Project's existing federal wells. The matter has been fully briefed and argued
before the Ninth Circuit and the parties are awaiting a decision of the court.
In December 2006, the BLM issued a draft SEIS that endorses a phased-development
approach to CBNG production in the Montana Powder River Basin, whereby future
development projects would be reviewed against four screens or filters (relating
to water quality, wildlife, Native American concerns and air quality). Fidelity
filed written comments on the draft SEIS asking the BLM to reconsider its
proposed phased-development approach and to make numerous other changes to
the
draft SEIS. The public comment period on the draft SEIS concluded on May 2,
2007. The final SEIS is scheduled for release in February 2008. Fidelity cannot
predict what the final terms of the SEIS will be.
In
related actions in the Montana Federal District Court, the NPRC and the Northern
Cheyenne Tribe asserted, among other things, that the actions of the BLM in
approving Fidelity's applications for permits and the plan of development for
the Badger Hills Project in Montana did not comply with applicable federal
laws,
including the NHPA and the NEPA. In June 2005, the Montana Federal District
Court issued orders in these cases enjoining operations on Fidelity's Badger
Hills Project pending the BLM's consultation with the Northern Cheyenne Tribe
as
to satisfaction of the applicable requirements of the NHPA and a further
environmental analysis under the NEPA. Fidelity sought and obtained stays of
the
injunctive relief from the Montana Federal District Court and production from
Fidelity’s Badger Hills Project continues. In September 2005, the Montana
Federal District Court entered an Order based on a stipulation between the
parties to the NPRC action that production from existing wells in Fidelity’s
Badger Hills Project may continue pending preparation of a revised environmental
analysis. In November 2005, the Montana Federal District Court entered an Order
dismissing the Northern Cheyenne Tribe lawsuit based on the parties’ stipulation
that production from existing wells in Fidelity’s Badger Hills Project could
continue pending consultation with the Northern Cheyenne Tribe under the NHPA.
In December 2005, Fidelity filed a Notice of Appeal of the NPRC lawsuit to
the
Ninth Circuit in
connection with the Montana Federal District Court’s decision insofar as it
found the BLM’s approval of Fidelity’s applications did not comply with
applicable law.
In
May
2005, the NPRC and other petitioners filed a petition with the BER to promulgate
rules related to the management of water produced in association with CBNG
operations. Thereafter, the BER initiated related rulemaking proceedings to
consider rules that would, if promulgated, require re-injection of water
produced in connection with CBNG operations, treatment of such water in the
event re-injection is not feasible and amend the non-degradation policy in
connection with CBNG development to include additional limitations on factors
deemed harmful, thereby restricting discharges even further than under the
previous standards. In March 2006, the BER issued its decision on the rulemaking
petition. The BER rejected the proposed requirement of re-injection of water
produced in connection with CBNG and deferred action on the proposed treatment
requirement. The BER adopted the proposed amendment to the non-degradation
policy. While it is possible the BER’s ruling could have an adverse impact on
Fidelity’s operations, Fidelity believes that two five-year water discharge
permits issued by the Montana DEQ in February 2006 should, assuming normal
operating conditions, allow Fidelity to continue its existing CBNG operations
at
least through the expiration of the permits in March 2011. However, these
permits are now under challenge in Montana state court by the Northern Cheyenne
Tribe. Specifically, in April 2006, the Northern Cheyenne Tribe filed a
complaint in the District Court of Big Horn County against the Montana DEQ
seeking to set aside the two permits. The Northern Cheyenne Tribe asserted
that
the Montana DEQ issued the permits in violation of various federal and state
environmental laws. In particular, the Northern Cheyenne Tribe claimed the
agency violated the Clean Water Act and the Montana Water Quality Act by failing
to include in the permits conditions requiring application of the best
practicable control technology currently available and by ignoring the BER’s
recently adopted amendment to the non-degradation policy. In addition, the
Northern Cheyenne Tribe claimed that the actions of the Montana DEQ violated
the
Montana State Constitution’s guarantee of a clean and healthful environment,
that the Montana DEQ’s related environmental assessment was invalid, that the
Montana DEQ was required, but failed, to prepare an EIS and that the Montana
DEQ
failed to consider other alternatives to the issuance of the permits. Fidelity,
the NPRC and the TRWUA have been granted leave to intervene in this proceeding.
The parties have submitted cross motions for summary judgment. The motions
were
argued to the District Court of Big Horn County on February 28, 2007. Fidelity’s
discharge of water pursuant to its two permits is its primary means for managing
CBNG produced water. If its permits are set aside, Fidelity’s CBNG operations in
Montana could be significantly and adversely affected.
In
a
related proceeding, in July 2006, Fidelity filed a motion to intervene in a
lawsuit filed in the District Court of Big Horn County by other producers.
The
lawsuit challenges the BER’s 2006 rulemaking, which amended the non-degradation
policy, as well as the BER’s 2003 rulemaking procedure which first set numeric
limits for certain parameters contained in water produced in connection with
CBNG operations. Fidelity’s motion for intervention was granted in August 2006.
The parties have briefed cross motions for summary judgment and the District
Court of Big Horn County heard oral argument on those motions on July 2,
2007.
Similarly,
industry members have filed two lawsuits, and the state of Wyoming has filed
one
lawsuit, in Wyoming Federal District Court. These lawsuits challenge the EPA’s
failure to timely disapprove the 2006 rules. All three Wyoming lawsuits were
consolidated in September 2006. Fidelity has moved to intervene in these
consolidated cases.
Fidelity
will continue to vigorously defend its interests in all CBNG-related lawsuits
and related actions in which it is involved, including the Ninth Circuit
injunction and the proceedings challenging its water permits. In those cases
where damage claims have been asserted, Fidelity is unable to quantify the
damages sought and will be unable to do so until after the completion of
discovery. If the plaintiffs are successful in these lawsuits, the ultimate
outcome of the actions could have a material adverse effect on Fidelity’s
existing CBNG operations and/or the future development of this resource in
the
affected regions.
Electric
Operations
Montana-Dakota joined with two electric generators in appealing a September
2003
finding by the ND Health Department that it may unilaterally revise operating
permits previously issued to electric generating plants. Although it is doubtful
that any revision of Montana-Dakota's operating permits by the ND Health
Department would reduce the amount of electricity its plants could generate,
the
finding, if allowed to stand, could increase costs for sulfur dioxide removal
and/or limit Montana-Dakota's ability to modify or expand operations at its
North Dakota generation sites. Montana-Dakota and the other electric generators
filed their appeal of the order in October 2003 in the Burleigh County District
Court in Bismarck, North Dakota. Proceedings were stayed pending conclusion
of
the periodic review of sulfur dioxide emissions in the state.
In
September 2005, the ND Health Department issued its final periodic review
decision based on its August 2005 final air quality modeling report. The ND
Health Department concluded there are no violations of the sulfur dioxide
increment in North Dakota. In March 2006, the DRC filed a complaint in Colorado
Federal District Court seeking to force the EPA to declare that the increment
had been violated based on earlier modeling conducted by the EPA. The EPA
defended against the DRC claim and filed a motion to dismiss the case. The
Colorado Federal District Court
has
dismissed the case.
Montana-Dakota
expects the EPA to initiate a rulemaking proceeding to formally approve the
conclusions contained in the September 2005 ND Health Department decision and
the August 2005 final report. Once concluded, this rulemaking should result
in a
revision to the North Dakota SIP that, in turn, should allow for the dismissal
of the case in Burleigh County District Court referenced above.
In
November 2006, the Sierra Club sent a notice of intent to file a citizen suit
in
federal court under the Clean Air Act to the co-owners, including
Montana-Dakota, of the Big Stone Station. The suit would seek injunctive relief
and monetary penalties based on the Sierra Club’s claim that three projects
conducted at the Big Stone Station between 1995 and 2005 were modifications
of a
major source and that the Big Stone Station failed to obtain a prevention of
significant deterioration permit, conduct best available control technology
analyses, and comply with other regulatory requirements for those projects.
The
South Dakota Department of Environment and Natural Resources reviewed and
approved the three projects and the co-owners of the Big Stone Station believe
that the Sierra Club’s claims are without merit. The Big Stone Station co-owners
intend to vigorously defend their interests if the suit is filed.
Natural
Gas Storage Based
on
reservoir and well pressure data and other information, Williston Basin believes
that reservoir pressure in the EBSR, one of its natural gas storage reservoirs,
has decreased as a result of Howell and Anadarko’s drilling and production
activities in areas within and near the boundaries of the EBSR. As of June
30,
2007, Williston Basin estimated approximately 9 Bcf of storage gas had been
diverted from the EBSR as a result of Howell and Anadarko’s drilling and
production.
Williston
Basin filed suit in Montana Federal District Court in January 2006, seeking
to
recover unspecified damages from Howell and Anadarko, and to enjoin Howell
and
Anadarko’s present and future production from specified wells in and near the
EBSR. The Montana Federal District Court entered an Order in July 2006,
dismissing the case for lack of subject matter jurisdiction. Williston Basin
filed
a
Notice
of
Appeal to the Ninth Circuit in July 2006. The parties are currently
briefing the issues.
In
related litigation, Howell filed suit in Wyoming State District Court against
Williston Basin in February 2006 asserting that it is entitled to produce any
gas that might escape from the EBSR. In August 2006, Williston Basin moved
for a
preliminary injunction to halt Howell and Anadarko’s production in and near the
EBSR. A district court-appointed special master conducted a hearing on the
motion in December 2006, and recommended denial of the motion on February 15,
2007. The Wyoming State District Court adopted the special master’s report on
July 25, 2007, and denied Williston Basin’s motion for a preliminary injunction.
On June 25, 2007, the Wyoming State District Court filed a motion with the
Wyoming Supreme Court requesting it to answer questions of law concerning the
production of Williston Basin’s storage gas by Howell and Anadarko. On July 10,
2007, the Wyoming Supreme Court issued an Order declining to answer those
questions.
As
noted
above, Williston Basin estimates that as of June 30, 2007, Howell and Anadarko
had diverted approximately 9 Bcf from the EBSR. Williston Basin believes Howell
and Anadarko continue to divert gas from the EBSR and Williston Basin continues
to monitor and analyze the situation. At trial, Williston Basin will seek
recovery based on the amount of gas that has been and continues to be diverted
as well as on the amount of gas that must be recovered as a result of the
equalization of the pressures of various interconnected geological formations.
In
light
of the actions of Howell and Anadarko, Williston Basin installed additional
compression at the site in order to maintain deliverability into the
transmission system. While installation of the additional compression has
provided temporary relief, Williston Basin believes that the adverse physical
and operational effects occasioned by the continued loss of storage gas, if
left
unchecked, could threaten the operation and viability of the EBSR, impair
Williston Basin’s ability to comply with the EBSR certificated operating
requirements mandated by the FERC and adversely affect Williston Basin’s ability
to meet its contractual storage and transportation service commitments to
customers. Williston Basin intends to vigorously defend its rights and interests
in these proceedings, to assess further avenues for recovery through the
regulatory process at the FERC, and to pursue the recovery of any and all
economic losses it may have
suffered. Williston Basin cannot predict the ultimate outcome of this
proceeding.
The
Company also is involved in other
legal
actions in the ordinary course of its business. Although the outcomes of any
such legal actions cannot be predicted, management believes that the outcomes
with respect to these other legal proceedings will not have a material adverse
effect upon the Company’s financial position or results of
operations.
Environmental
matters
Portland
Harbor Site In
December 2000, MBI was named by the EPA as a Potentially Responsible Party
in
connection with the cleanup of a riverbed site adjacent to a commercial property
site, acquired by MBI in 1999. The riverbed site is part of the Portland,
Oregon, Harbor Superfund Site. Sixty-eight other parties were also named in
this
administrative action. The EPA wants responsible parties to share in the cleanup
of sediment contamination in the Willamette River. To date, costs of the overall
remedial investigation of the harbor site for both the EPA and the Oregon DEQ
are being recorded, and initially paid, through an administrative consent order
by the LWG, a group of 10 entities, which does not include MBI or
Georgia-Pacific West, Inc., the seller of the commercial property to MBI.
Although the LWG originally estimated the overall remedial investigation and
feasibility study would cost approximately $10 million, it is now
anticipated, on the basis of costs incurred to date and delays attributable
to
an additional round of sampling and potential further investigative work, that
such cost could increase to a total in excess of $60 million. It is not possible
to estimate the cost of a corrective action plan until the remedial
investigation and feasibility study has been completed, the EPA has decided
on a
strategy and a record of decision has been published. While the remedial
investigation and feasibility study for the harbor site has commenced, it is
expected to take several more years to complete. The development of a proposed
plan and record of decision on the harbor site is not anticipated to occur
until
2010, after which a cleanup plan will be undertaken.
Based
upon a review of the Portland Harbor sediment contamination evaluation by the
Oregon DEQ and other information available, MBI does not believe it is a
Responsible Party. In addition, MBI has notified Georgia-Pacific West, Inc.,
that it intends to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their sale
agreement. MBI has entered into an agreement tolling the statute of
limitation in connection with the LWG’s potential claim for contribution to the
costs of the remedial investigation and feasibility study.
The
Company believes it is not probable that it will incur any material
environmental remediation costs or damages in relation to the above referenced
administrative action.
Hardin
Generating Facility
In
connection with the sale of the domestic independent power production business,
Centennial Resources also agreed to obtain an amended air permit for the Hardin
Generating Facility, the application process for which Centennial Resources
initiated during the sales process, and to pay certain fines and penalties,
if
any, assessed against the facility on or prior to the date that the facility
complies with the amended air permit, as well as certain costs related to
obtaining the amended air permit. The Hardin Generating Facility has received
three notices of violation from the Montana DEQ relating to emissions
exceedances associated with startup and maintenance periods for the Hardin
Generating Facility. The Company is working with the Montana DEQ to address
these issues and to secure the amended air permit and is unable to estimate
what, if any, fines may be imposed by the Montana DEQ.
Guarantees
In
connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly
owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent
of any losses which Petrobras may incur from certain contingent liabilities
specified in the purchase agreement. Centennial has agreed to unconditionally
guarantee payment of the indemnity obligations to Petrobras for periods ranging
up to five and a half years from the date of sale. The guarantee was required
by
Petrobras as a condition to closing the sale of MPX.
Centennial
continues to guarantee CEM’s obligations under a construction contract for a
550-MW combined-cycle electric generating facility near Hobbs, New Mexico.
As
described in Note 20, Centennial Resources sold CEM in July 2007 to Bicent
Power
LLC, which has provided a $10 million bank letter of credit to Centennial in
support of that guarantee obligation.
In
addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas price
swap and collar agreement obligations. There is no fixed maximum amount
guaranteed in relation to the natural gas price swap and collar agreements,
as
the amount of the obligation is dependent upon natural gas commodity prices.
The
amount of hedging activity entered into by the subsidiary is limited by
corporate policy. The guarantees of the natural gas price swap and collar
agreements at June 30, 2007, expire in 2008; however, Fidelity continues to
enter into additional hedging activities and, as a result, WBI Holdings from
time to time may issue additional guarantees on these hedging obligations.
The
amount outstanding by Fidelity was $900,000 and was reflected on the
Consolidated Balance Sheets at June 30, 2007. In the event Fidelity defaults
under its obligations, WBI Holdings would be required to make payments under
its
guarantees.
Certain
subsidiaries of the Company have outstanding guarantees to third parties that
guarantee the performance of other subsidiaries of the Company. These guarantees
are related to construction contracts, natural gas transportation and sales
agreements, electric power supply agreements, gathering contracts, a conditional
purchase agreement and certain other guarantees. At June 30, 2007, the fixed
maximum amounts guaranteed under these agreements aggregated $543.2 million.
The
amounts of scheduled expiration of the maximum amounts guaranteed under these
agreements aggregate $7.0 million in 2007; $87.0 million in 2008; $366.6 million
in 2009; $30.4 million in 2010; $23.0 million in 2011; $12.7 million in 2012;
$11.2 million in 2017; $300,000 in 2028; $1.0 million, which is subject to
expiration 30 days after the receipt of written notice; and $4.0 million, which
has no scheduled maturity date. A guarantee for an unfixed amount estimated
at
$250,000 at June 30, 2007, has no scheduled maturity date. The amount
outstanding by subsidiaries of the Company under the above guarantees was
$674,000 and was reflected on the Consolidated Balance Sheet at June 30, 2007.
In the event of default under these guarantee obligations, the subsidiary
issuing the guarantee for that particular obligation would be required to make
payments under its guarantee.
Centennial
has outstanding letters of credit to third parties related to insurance policies
and other agreements that guarantee the performance of other subsidiaries of
the
Company. At June 30, 2007, the fixed maximum amounts guaranteed under these
letters of credit aggregated $42.6 million. In 2007 and 2008, $9.6 million
and
$33.0 million, respectively, of letters of credit are scheduled to expire.
There
were no amounts outstanding under the above letters of credit at June 30,
2007.
Fidelity
and WBI Holdings have outstanding guarantees to Williston Basin. These
guarantees are related to natural gas transportation and storage agreements
that
guarantee the performance of Prairielands. At June 30, 2007, the fixed maximum
amounts guaranteed under these agreements aggregated $25.1 million. Scheduled
expiration of the maximum amounts guaranteed under these agreements aggregate
$2.2 million in 2007, $2.9 million in 2008 and $20.0 million in 2009. In the
event of Prairielands’ default in its payment obligations, the subsidiary
issuing the guarantee for that particular obligation would be required to make
payments under its guarantee. The amount outstanding by Prairielands under
the
above guarantees was $1.6 million, which was not reflected on the Consolidated
Balance Sheet at June 30, 2007, because these intercompany transactions are
eliminated in consolidation.
In
addition, Centennial and Knife River have issued guarantees to third parties
related to routine purchases by their subsidiaries of maintenance items,
materials and lease obligations for which no fixed maximum amounts have been
specified. These guarantees have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in relation to the
purchase of certain maintenance items, materials or lease obligations,
Centennial or Knife River would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the Company for these
maintenance items and materials were reflected on the Consolidated Balance
Sheet
at June 30, 2007.
In
the
normal course of business, Centennial has purchased surety bonds related to
construction contracts and reclamation obligations of its subsidiaries. In
the
event a subsidiary of Centennial does not fulfill a bonded obligation,
Centennial would be responsible to the surety bond company for completion of
the
bonded contract or obligation. A large portion of the surety bonds is expected
to expire within the next 12 months; however, Centennial will likely continue
to
enter into surety bonds for its subsidiaries in the future. As of June 30,
2007,
approximately $535 million of surety bonds were outstanding, which were not
reflected on the Consolidated Balance Sheet.
On
July
2, 2007, the acquisition of Cascade was finalized and Cascade became an indirect
wholly owned subsidiary of the Company. The total value of the transaction,
including the outstanding indebtedness of Cascade, is approximately $475
million. Cascade’s natural gas service areas are concentrated in western and
south central Washington and south central and eastern Oregon. Future results
of
Cascade will be part of the Company’s natural gas distribution
segment.
In
connection with the funding of the Cascade acquisition, on June 29, 2007, the
Company entered into a term loan agreement with Wells Fargo Bank, National
Association, providing for a commitment amount of $310 million. The Company
borrowed $310 million under this agreement on July 2, 2007. On July 11, 2007,
the Company paid down $220 million of the outstanding principal balance. This
term loan agreement matures on June 27, 2008.
On
July
10, 2007, Centennial Resources sold its domestic independent power production
business consisting of Centennial Power and CEM to Bicent Power LLC (formerly
known as Montana Acquisition Company LLC). The transaction is valued at $636
million, which includes the assumption of approximately $36 million of
project-related debt. The estimated gain on the sale of the assets is expected
to be approximately $90 million (after tax). A portion of the proceeds from
the
sale was used to pay a dividend to the Company. This dividend was then used
to
prepay, in part, the outstanding term loan indebtedness that was incurred by
the
Company to fund the Cascade acquisition. The remaining proceeds of the sale
are
anticipated to provide additional cash for growth opportunities that exist
in
the Company’s core lines of business.
ITEM
2. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
|
AND
RESULTS OF OPERATIONS
|
OVERVIEW
The
Company’s strategy is to apply its expertise in energy and transportation
infrastructure industries to increase market share, increase profitability
and
enhance shareholder value through:
· |
Organic
growth as well as a continued disciplined approach to the acquisition
of
well-managed companies and
properties
|
· |
The
elimination of system-wide cost redundancies through increased focus
on
integration of operations and standardization and consolidation of
various
support services and functions across companies within the
organization
|
· |
The
development of projects that are accretive to earnings per share
and
return on invested capital
|
The
Company has capabilities to fund its growth and operations through various
sources, including internally generated funds, credit facilities
and the
issuance from time to time of debt securities and the Company’s equity
securities. For
more
information on the Company’s net capital expenditures, see Liquidity and Capital
Commitments. Net capital expenditures are comprised of (A) capital expenditures
plus (B) acquisitions (including the issuance of the Company’s equity
securities, less cash acquired) less (C) net proceeds from the sale or
disposition of property.
The
key
strategies for each of the Company’s business segments, and certain related
business challenges, are summarized below.
Key
Strategies and Challenges
Electric
and Natural Gas Distribution
Strategy
Provide
competitively priced energy to customers while working with them to ensure
efficient usage. Both the electric and natural gas distribution segments
continually seek opportunities for growth and expansion of their customer base
through extensions of existing operations and through selected acquisitions
of
companies and properties at prices that will provide stable cash flows and
an
opportunity for the Company to earn a competitive return on investment. The
natural gas distribution segment also continues to pursue growth
by
expanding its level of energy-related services.
Challenges Both
segments are subject to extensive regulation in the state jurisdictions where
they conduct operations with respect to costs and permitted returns on
investment as well as subject to certain operational regulations at the federal
level. The ability of these segments to grow through acquisitions is subject
to
significant competition from other energy providers. In addition, as to the
electric business, the ability of this segment to grow its service territory
and
customer base is affected by significant competition from other energy
providers, including rural electric cooperatives.
Construction
Services
Strategy
Provide
a competitive return on investment while operating in a competitive industry
by:
building new and strengthening existing customer relationships;
effectively controlling costs; recruiting,
developing and retaining talented employees; focusing business development
efforts on project areas that will permit higher margins; and properly managing
risk. This segment continuously seeks opportunities to expand through strategic
acquisitions.
Challenges
This
segment operates in highly competitive markets with many jobs subject to
competitive bidding. Maintenance of effective operational and cost controls
and
retention of key personnel are ongoing challenges.
Pipeline
and Energy Services
Strategy
Leverage
the segment’s existing expertise in energy infrastructure and related services
to increase market share and profitability through optimization of existing
operations, internal growth, and acquisitions of energy-related assets and
companies. Incremental and new growth opportunities include: access to new
sources of natural gas for storage, gathering and transportation services;
expansion
of existing gathering and transmission facilities;
and
incremental
expansion of pipeline capacity to allow customers access to more liquid and
higher-priced markets.
Challenges
Energy
price volatility; natural gas basis differentials; regulatory requirements;
ongoing litigation; recruitment and retention of a skilled workforce; and
increased competition from other natural
gas pipeline
and
gathering companies.
Natural
Gas and Oil Production
Strategy
Apply
new technology and leverage existing exploration and production expertise,
with
a focus on operated properties, to increase production and reserves from
existing leaseholds, and to seek additional reserves and production
opportunities in new areas to further diversify the segment’s asset base. By
optimizing existing operations and taking advantage of new and incremental
growth opportunities, this segment’s goal is to increase both production and
reserves over the long term so as to generate competitive returns on
investment.
Challenges
Fluctuations in natural gas and oil prices; ongoing environmental litigation
and
administrative proceedings; timely receipt of necessary permits and approvals;
recruitment and retention of a skilled workforce; availability of drilling
rigs,
auxiliary equipment and industry-related field services; inflationary pressure
on development and operating costs; and increased competition from other
natural
gas and oil companies.
Construction
Materials and Mining
Strategy
Focus on
high growth strategic markets located near major transportation corridors and
desirable mid-sized metropolitan areas; strengthen long-term, strategic
aggregate reserve position through purchase and/or lease opportunities; enhance
profitability through cost containment, margin discipline and vertical
integration of the segment’s operations; and continue growth through organic and
acquisition opportunities. Ongoing efforts to increase margin are being pursued
through the implementation of a variety of continuous improvement programs,
including corporate purchasing of equipment, parts and commodities (liquid
asphalt, diesel fuel, cement and other materials), negotiation of contract
price
escalation provisions and the utilization of national purchasing accounts.
Vertical integration allows the segment to manage operations from aggregate
mining to final lay-down of concrete and asphalt, with control of and access
to
adequate quantities of permitted aggregate reserves being significant. A key
element of the Company’s long-term strategy for this business is to further
expand its presence, through acquisition, in the higher-margin materials
business (rock, sand, gravel, liquid asphalt, ready-mixed concrete and related
products), complementing and expanding on the Company’s expertise.
Challenges
Price
volatility with respect to, and availability of, raw materials such as liquid
asphalt, diesel fuel and cement; recruitment and retention of a skilled
workforce; and management of fixed price construction contracts, which are
particularly vulnerable to volatility of these energy and material
prices.
Some of
our markets are affected by the slowdown in housing, which should be partially
mitigated by increased commercial spending.
Independent
Power Production
Overall
business challenges for this segment include the risks and uncertainties
associated with foreign currency fluctuation and political risk in the countries
where this segment does business.
For
further information on the risks and challenges the Company faces as it pursues
its growth strategies and other factors that should be considered for a better
understanding of the Company’s financial condition, see Part II, Item 1A - Risk
Factors, as well as Part I, Item 1A - Risk Factors in the 2006 Annual Report.
For further information on each segment’s key growth strategies, projections and
certain assumptions, see Prospective Information. For information pertinent
to
various commitments and contingencies, see Notes to Consolidated Financial
Statements.
Earnings
Overview
The
following table summarizes the contribution to consolidated earnings by each
of
the Company's businesses.
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Electric
|
|
$
|
3.6
|
|
$
|
.5
|
|
$
|
7.4
|
$ |
4.3
|
Natural
gas distribution
|
|
|
(.6
|
)
|
|
(2.5
|
)
|
|
5.6
|
|
2.8
|
Construction
services
|
|
|
13.0
|
|
|
9.7
|
|
|
20.3
|
|
15.1
|
Pipeline
and energy services
|
|
|
6.1
|
|
|
5.9
|
|
|
11.8
|
|
10.8
|
Natural
gas and oil production
|
|
|
35.2
|
|
|
31.0
|
|
|
65.8
|
|
72.2
|
Construction
materials and mining
|
|
|
25.5
|
|
|
25.3
|
|
|
15.7
|
|
16.4
|
Independent
power production
|
|
|
(1.4
|
)
|
|
(1.8
|
)
|
|
(4.1
|
)
|
(1.6)
|
Other
|
|
|
.4
|
|
|
.2
|
|
|
.6
|
|
.5
|
Earnings
before discontinued operations
|
|
|
81.8
|
|
|
68.3
|
|
|
123.1
|
|
120.5
|
Income
from discontinued operations, net of tax
|
|
|
7.5
|
|
|
3.0
|
|
|
12.7
|
|
3.8
|
Earnings
on common stock
|
|
$
|
89.3
|
|
$
|
71.3
|
|
$
|
135.8
|
$ |
124.3
|
Earnings
per common share - basic:
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
.45
|
|
$
|
.38
|
|
$
|
.68
|
$ |
.67
|
Discontinued
operations, net of tax
|
|
|
.04
|
|
|
.02
|
|
|
.07
|
|
.02
|
Earnings
per common share - basic
|
|
$
|
.49
|
|
$
|
.40
|
|
$
|
.75
|
$ |
.69
|
Earnings
per common share - diluted:
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
before discontinued operations
|
|
$
|
.45
|
|
$
|
.38
|
|
$
|
.67
|
$ |
.67
|
Discontinued
operations, net of tax
|
|
|
.04
|
|
|
.01
|
|
|
.07
|
|
.02
|
Earnings
per common share - diluted
|
|
$
|
.49
|
|
$
|
.39
|
|
$
|
.74
|
$ |
.69
|
Return
on average common equity for the 12 months ended
|
|
|
|
|
|
|
|
|
15.2
|
%
|
15.1%
|
Three
Months Ended June 30, 2007 and 2006
Consolidated earnings for the quarter ended June 30, 2007, increased $18.0
million from the comparable prior period largely due to:
· |
Increased
combined natural gas and oil production of 4 percent, partially offset
by
higher depreciation, depletion and amortization expense at the natural
gas
and oil production business
|
· |
Increased
income from discontinued operations, net of tax, largely the absence
in
2007 of depreciation expense related to assets held for sale and
earnings
related to an electric generating facility construction project at
the
independent power production
business
|
· |
Higher
earnings from increased retail sales volumes and margins and decreased
operation and maintenance expense at the electric
business
|
· |
Higher
earnings from increased construction margins and equipment sales
and
rentals at the construction services
business
|
Six
Months Ended June 30, 2007 and 2006
Consolidated earnings for the six months ended June 30, 2007, increased $11.5
million from the comparable prior period largely due to:
· |
Increased
income from discontinued operations, net of tax, largely the absence
in
2007 of depreciation expense related to assets held for sale, earnings
related to an electric generating facility construction project and
higher
earnings from the Hardin Generating Station at the independent power
production business
|
· |
Higher
earnings from construction services business, as previously
discussed
|
· |
Higher
earnings from increased retail sales volumes and margins at the electric
business
|
Partially
offsetting this increase were lower earnings at the natural gas and oil
production business.
FINANCIAL
AND OPERATING DATA
The
following tables contain key financial and operating statistics for each of
the
Company's businesses.
Electric
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$
|
44.6
|
|
$
|
40.9
|
|
$
|
91.7
|
|
$
|
85.9
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
15.5
|
|
|
16.0
|
|
|
32.6
|
|
|
32.0
|
|
Operation
and maintenance
|
|
|
14.5
|
|
|
15.7
|
|
|
29.5
|
|
|
29.7
|
|
Depreciation,
depletion and amortization
|
|
|
5.6
|
|
|
5.3
|
|
|
11.2
|
|
|
10.6
|
|
Taxes,
other than income
|
|
|
2.1
|
|
|
2.0
|
|
|
4.3
|
|
|
4.3
|
|
|
|
|
37.7
|
|
|
39.0
|
|
|
77.6
|
|
|
76.6
|
|
Operating
income
|
|
|
6.9
|
|
|
1.9
|
|
|
14.1
|
|
|
9.3
|
|
Earnings
|
|
$
|
3.6
|
|
$
|
.5
|
|
$
|
7.4
|
|
$
|
4.3
|
|
Retail
sales (million kWh)
|
|
|
596.3
|
|
|
563.0
|
|
|
1,242.0
|
|
|
1,175.9
|
|
Sales
for resale (million kWh)
|
|
|
47.0
|
|
|
85.3
|
|
|
91.2
|
|
|
251.7
|
|
Average
cost of fuel and purchased power per kWh
|
|
$
|
.024
|
|
$
|
.024
|
|
$
|
.024
|
|
$
|
.022
|
|
Three
Months Ended June 30, 2007 and 2006 Electric
earnings increased $3.1 million due to:
· |
Higher
retail sales volumes and margins
|
· |
Decreased
operation and maintenance expense of $800,000 (after tax), largely
due to
lower maintenance expense at certain electric generating
stations
|
Partially
offsetting this increase were lower sales for resale volumes.
Six
Months Ended June 30, 2007 and 2006 Electric
earnings increased $3.1 million largely due to higher retail sales volumes
and
margins and higher sales for resale margins, partially offset by lower sales
for
resale volumes.
Natural
Gas Distribution
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$
|
53.4
|
|
$
|
45.8
|
|
$
|
189.5
|
|
$
|
198.1
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
34.3
|
|
|
33.4
|
|
|
140.5
|
|
|
161.8
|
|
Operation
and maintenance
|
|
|
15.6
|
|
|
13.0
|
|
|
31.2
|
|
|
24.8
|
|
Depreciation,
depletion and amortization
|
|
|
2.5
|
|
|
2.4
|
|
|
5.0
|
|
|
4.8
|
|
Taxes,
other than income
|
|
|
1.5
|
|
|
1.5
|
|
|
3.2
|
|
|
3.0
|
|
|
|
|
53.9
|
|
|
50.3
|
|
|
179.9
|
|
|
194.4
|
|
Operating
income (loss)
|
|
|
(.5
|
)
|
|
(4.5
|
)
|
|
9.6
|
|
|
3.7
|
|
Earnings
(loss)
|
|
$
|
(.6
|
)
|
$
|
(2.5
|
)
|
$
|
5.6
|
|
$
|
2.8
|
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
5.3
|
|
|
4.6
|
|
|
21.2
|
|
|
18.8
|
|
Transportation
|
|
|
2.9
|
|
|
2.8
|
|
|
6.3
|
|
|
7.2
|
|
Total
throughput
|
|
|
8.2
|
|
|
7.4
|
|
|
27.5
|
|
|
26.0
|
|
Degree
days (% of normal)*
|
|
|
94
|
%
|
|
68
|
%
|
|
94
|
%
|
|
82
|
%
|
Average
cost of natural gas, including transportation, per
dk
|
|
$
|
6.44
|
|
$
|
7.29
|
|
$
|
6.64
|
|
$
|
8.59
|
|
*
Degree days are a measure of the daily temperature-related demand for energy
for
heating.
Three
Months Ended June 30, 2007 and 2006 The
natural gas distribution business experienced a seasonal loss of $600,000 in
the
second quarter of 2007 compared to a loss of $2.5 million in the second quarter
of 2006. The increase in earnings of $1.9 million was largely due
to:
· |
Decreased
payroll and benefit-related costs of $1.0 million (after tax), including
the absence in 2007 of the 2006 early retirement program
costs
|
· |
Increased
retail sales volumes, resulting from 39 percent colder weather than
last
year
|
· |
Higher
nonregulated energy-related services contributed to the earnings
increase
as well as to the increase in revenues and operation and maintenance
expense
|
Six
Months Ended June 30, 2007 and 2006
Earnings
at the natural gas distribution business increased $2.8 million due
to:
· |
Decreased
payroll and benefit-related costs of $1.1 million (after tax), including
the absence in 2007 of the 2006 early retirement program
costs
|
· |
Increased
retail sales volumes, resulting from 14 percent colder weather than
last
year
|
· |
Higher
nonregulated energy-related services
|
The
pass-through of lower natural gas prices is reflected in the decrease in both
revenues and purchased natural gas sold. The decrease in revenues was partially
offset by revenues from nonregulated energy-related services. Nonregulated
energy-related services also contributed to the operation and maintenance
expense increase.
Construction
Services
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Operating
revenues
|
|
$
|
263.8
|
|
$
|
243.2
|
|
$
|
500.6
|
|
$
|
467.0
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
230.6
|
|
|
216.5
|
|
|
442.4
|
|
|
419.3
|
|
Depreciation,
depletion and amortization
|
|
|
3.4
|
|
|
3.9
|
|
|
6.9
|
|
|
7.4
|
|
Taxes,
other than income
|
|
|
7.5
|
|
|
5.5
|
|
|
16.2
|
|
|
12.9
|
|
|
|
|
241.5
|
|
|
225.9
|
|
|
465.5
|
|
|
439.6
|
|
Operating
income
|
|
|
22.3
|
|
|
17.3
|
|
|
35.1
|
|
|
27.4
|
|
Earnings
|
|
$
|
13.0
|
|
$
|
9.7
|
|
$
|
20.3
|
|
$
|
15.1
|
|
Three
Months Ended June 30, 2007 and 2006 Construction
services earnings increased $3.3 million due to:
· |
Higher
construction margins of $2.7 million (after tax), including
industrial-related work
|
· |
Increased
equipment sales and rentals
|
Six
Months Ended June 30, 2007 and 2006
Construction services earnings increased $5.2 million due to:
· |
Higher
construction margins of $4.4 million (after tax) in all regions,
including
industrial-related work
|
· |
Increased
equipment sales and rentals
|
Pipeline
and Energy Services
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
$
|
28.6
|
|
$
|
26.1
|
|
$
|
54.5
|
|
$
|
46.8
|
|
Energy
services
|
|
|
83.6
|
|
|
76.4
|
|
|
170.8
|
|
|
182.2
|
|
|
|
|
112.2
|
|
|
102.5
|
|
|
225.3
|
|
|
229.0
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
75.8
|
|
|
69.3
|
|
|
155.4
|
|
|
167.1
|
|
Operation
and maintenance
|
|
|
16.6
|
|
|
14.1
|
|
|
30.6
|
|
|
25.7
|
|
Depreciation,
depletion and amortization
|
|
|
5.2
|
|
|
5.1
|
|
|
10.6
|
|
|
10.0
|
|
Taxes,
other than income
|
|
|
2.7
|
|
|
2.6
|
|
|
5.5
|
|
|
5.1
|
|
|
|
|
100.3
|
|
|
91.1
|
|
|
202.1
|
|
|
207.9
|
|
Operating
income
|
|
|
11.9
|
|
|
11.4
|
|
|
23.2
|
|
|
21.1
|
|
Income
from continuing operations
|
|
|
6.1
|
|
|
5.9
|
|
|
11.8
|
|
|
10.8
|
|
Income
(loss) from discontinued operations, net of tax
|
|
|
.1
|
|
|
(.3
|
)
|
|
.1
|
|
|
(.6
|
)
|
Earnings
|
|
$
|
6.2
|
|
$
|
5.6
|
|
$
|
11.9
|
|
$
|
10.2
|
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
7.1
|
|
|
7.1
|
|
|
15.1
|
|
|
15.1
|
|
Other
|
|
|
29.7
|
|
|
28.0
|
|
|
50.2
|
|
|
46.2
|
|
|
|
|
36.8
|
|
|
35.1
|
|
|
65.3
|
|
|
61.3
|
|
Gathering
volumes (MMdk)
|
|
|
22.5
|
|
|
21.2
|
|
|
44.7
|
|
|
42.9
|
|
Three
Months Ended June 30, 2007 and 2006 Pipeline
and energy services experienced an increase in earnings of $600,000 due
to:
· |
Higher
transportation and gathering volumes of $900,000 (after
tax)
|
· |
Higher
gathering rates of $400,000 (after
tax)
|
· |
Higher
storage services revenue of $300,000 (after
tax)
|
Partially
offsetting these increases were higher operation and maintenance expenses,
including payroll and material costs.
Six
Months Ended June 30, 2007 and 2006
Pipeline
and energy services experienced an increase in earnings of $1.7 million due
to:
· |
Higher
storage services revenue of $2.2 million (after
tax)
|
· |
Higher
transportation and gathering volumes of $1.9 million (after
tax)
|
· |
Higher
gathering rates of $800,000 (after
tax)
|
Partially
offsetting these increases were higher operation and maintenance expenses,
primarily related to the natural gas storage litigation and higher payroll
and
material costs. For more information regarding natural gas storage litigation,
see Note 19.
The
decrease in energy services revenues and purchased natural gas sold reflects
the
effect of lower natural gas prices.
Natural
Gas and Oil Production
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
96.1
|
|
$
|
87.2
|
|
$
|
190.0
|
|
$
|
192.5
|
|
Oil
|
|
|
31.2
|
|
|
25.4
|
|
|
55.8
|
|
|
46.5
|
|
Other
|
|
|
.1
|
|
|
1.5
|
|
|
.2
|
|
|
3.5
|
|
|
|
|
127.4
|
|
|
114.1
|
|
|
246.0
|
|
|
242.5
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
---
|
|
|
1.7
|
|
|
.3
|
|
|
3.7
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
15.6
|
|
|
12.3
|
|
|
31.1
|
|
|
24.2
|
|
Gathering
and transportation
|
|
|
5.0
|
|
|
4.7
|
|
|
9.5
|
|
|
9.4
|
|
Other
|
|
|
9.1
|
|
|
9.4
|
|
|
17.5
|
|
|
16.8
|
|
Depreciation,
depletion and amortization
|
|
|
29.8
|
|
|
25.8
|
|
|
59.6
|
|
|
50.3
|
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
9.3
|
|
|
8.0
|
|
|
18.2
|
|
|
18.0
|
|
Other
|
|
|
.3
|
|
|
.4
|
|
|
.5
|
|
|
.5
|
|
|
|
|
69.1
|
|
|
62.3
|
|
|
136.7
|
|
|
122.9
|
|
Operating
income
|
|
|
58.3
|
|
|
51.8
|
|
|
109.3
|
|
|
119.6
|
|
Earnings
|
|
$
|
35.2
|
|
$
|
31.0
|
|
$
|
65.8
|
|
$
|
72.2
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
15,231
|
|
|
15,242
|
|
|
30,671
|
|
|
30,604
|
|
Oil
(MBbls)
|
|
|
589
|
|
|
471
|
|
|
1,145
|
|
|
921
|
|
Average
realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
6.31
|
|
$
|
5.72
|
|
$
|
6.20
|
|
$
|
6.29
|
|
Oil
(per barrel)
|
|
$
|
52.83
|
|
$
|
54.00
|
|
$
|
48.71
|
|
$
|
50.43
|
|
Average
realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
5.82
|
|
$
|
5.15
|
|
$
|
5.78
|
|
$
|
6.03
|
|
Oil
(per barrel)
|
|
$
|
52.83
|
|
$
|
55.71
|
|
$
|
48.71
|
|
$
|
51.77
|
|
Production
costs, including taxes, per net equivalent Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$
|
.83
|
|
$
|
.68
|
|
$
|
.83
|
|
$
|
.67
|
|
Gathering
and transportation
|
|
|
.27
|
|
|
.26
|
|
|
.25
|
|
|
.26
|
|
Production
and property taxes
|
|
|
.50
|
|
|
.45
|
|
|
.49
|
|
|
.50
|
|
|
|
$
|
1.60
|
|
$
|
1.39
|
|
$
|
1.57
|
|
$
|
1.43
|
|
Three
Months Ended June 30, 2007 and 2006 The
natural gas and oil production business experienced a $4.2 million increase
in
earnings due to:
· |
Higher
average realized gas prices of 10
percent
|
· |
Increased
combined natural gas and oil production of 4 percent, largely due
to
increased production at the South Texas properties, as well as from
the
May 2006 Big Horn acquisition
|
Partially
offsetting these increases were:
· |
Higher
depreciation, depletion and amortization expense of $2.5 million
(after
tax) due to higher depletion rates and increased
production
|
· |
Higher
lease operating expense of $2.2 million (after tax), largely CBNG
and
acquisition- related costs
|
· |
Lower
average realized oil prices of 2
percent
|
Six
Months Ended June 30, 2007 and 2006
The
natural gas and oil production business experienced a $6.4 million decrease
in
earnings due to:
· |
Higher
depreciation, depletion and amortization expense of $5.7 million
(after
tax), as previously discussed
|
· |
Higher
lease operating expense of $4.3 million (after tax), as previously
discussed
|
· |
Lower
average realized gas prices of 1 percent and lower average realized
oil
prices of 3 percent
|
· |
Increased
general and administrative expense of $1.0 million (after tax), primarily
due to higher payroll-related costs
|
Partially
offsetting these decreases were increased combined natural gas and oil
production of 4 percent, largely due to increased production resulting from
the
May 2006 Big Horn acquisition, as well as from the South Texas
properties.
Construction
Materials and Mining
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
455.5
|
|
$
|
484.9
|
|
$
|
683.0
|
|
$
|
718.6
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
372.8
|
|
|
404.5
|
|
|
581.6
|
|
|
620.2
|
|
Depreciation,
depletion and amortization
|
|
|
23.2
|
|
|
22.1
|
|
|
45.8
|
|
|
42.2
|
|
Taxes,
other than income
|
|
|
13.9
|
|
|
11.9
|
|
|
21.6
|
|
|
20.3
|
|
|
|
|
409.9
|
|
|
438.5
|
|
|
649.0
|
|
|
682.7
|
|
Operating
income
|
|
|
45.6
|
|
|
46.4
|
|
|
34.0
|
|
|
35.9
|
|
Earnings
|
|
$
|
25.5
|
|
$
|
25.3
|
|
$
|
15.7
|
|
$
|
16.4
|
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
10,339
|
|
|
13,341
|
|
|
15,896
|
|
|
19,425
|
|
Asphalt
(tons)
|
|
|
1,769
|
|
|
2,356
|
|
|
2,105
|
|
|
2,689
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
1,092
|
|
|
1,260
|
|
|
1,718
|
|
|
1,971
|
|
Three
Months Ended June 30, 2007 and 2006
Earnings
at the construction materials and mining business increased $200,000 due
to:
· |
Higher
earnings of $1.7 million (after tax) from asphalt operations, largely
due
to higher realized prices, partially offset by lower
volumes
|
· |
Increased
earnings realized from this segment’s liquid asphalt materials business of
$1.6 million (after tax), largely due to higher realized oil prices
|
· |
Earnings
from companies acquired since the comparable prior period which
contributed 4 percent to earnings
|
Partially
offsetting these increases were:
· |
Lower
earnings of $2.1 million (after tax) from aggregate and ready-mixed
concrete operations, largely due to lower volumes, partially offset
by
higher realized prices
|
· |
Higher
depreciation, depletion and amortization of $500,000 (after tax),
primarily due to higher plant and equipment
balances
|
Lower
product sales volumes reflect the slow down in the residential housing
market.
Six
Months Ended June 30, 2007 and 2006
Earnings
at the construction materials and mining business decreased $700,000 due
to:
· |
Lower
earnings of $2.6 million (after tax) from ready-mixed concrete operations,
due to lower margins and volumes
|
· |
Lower
earnings of $1.3 million (after tax) from aggregate operations, largely
due to lower volumes, partially offset by higher realized
prices
|
· |
Higher
depreciation, depletion and amortization of $1.8 million (after tax),
as
previously discussed
|
Partially
offsetting these decreases were:
· |
Higher
earnings from construction, largely due to strong demand in the Northwest
region
|
· |
Increased
earnings from asphalt operations of $1.9 million (after tax), largely
due
to higher prices, partially offset by lower
volumes
|
· |
Increased
earnings realized from this segment’s liquid asphalt materials business of
$1.6 million (after tax), largely due to higher realized oil
prices
|
Lower
product sales volumes reflect the slow down in the residential housing
market.
Independent
Power Production
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
1.9
|
|
|
2.3
|
|
|
3.6
|
|
|
4.0
|
|
Depreciation,
depletion and amortization
|
|
|
.1
|
|
|
.1
|
|
|
.2
|
|
|
.1
|
|
Taxes,
other than income
|
|
|
---
|
|
|
---
|
|
|
.1
|
|
|
.1
|
|
|
|
|
2.0
|
|
|
2.4
|
|
|
3.9
|
|
|
4.2
|
|
Operating
loss
|
|
|
(2.0
|
)
|
|
(2.4
|
)
|
|
(3.9
|
)
|
|
(4.2
|
)
|
Loss
from continuing operations
|
|
|
(1.4
|
)
|
|
(1.8
|
)
|
|
(4.1
|
)
|
|
(1.6
|
)
|
Income from discontinued operations, net of tax
|
|
|
7.4
|
|
|
3.3
|
|
|
12.6
|
|
|
4.4
|
|
Earnings
|
|
$
|
6.0
|
|
$
|
1.5
|
|
$
|
8.5
|
|
$
|
2.8
|
|
Net
generation capacity (kW)*
|
|
|
437,600
|
|
|
437,600
|
|
|
437,600
|
|
|
437,600
|
|
Electricity produced and sold (thousand kWh)*
|
|
|
277,347
|
|
|
202,778
|
|
|
515,358
|
|
|
291,275
|
|
* Excludes equity method investments.
Three
Months Ended June 30, 2007 and 2006 Earnings
at the independent power production business increased $4.5 million due to
increased income from discontinued operations, net of tax, of $4.1 million,
largely due to:
· |
The
absence in 2007 of depreciation expense related to assets held for
sale
|
· |
Earnings
related to an electric generating facility construction project in
Hobbs,
New Mexico
|
Six
Months Ended June 30, 2007 and 2006
Earnings
at the independent power production business increased $5.7 million due to
increased income from discontinued operations, net of tax, of $8.2 million,
largely due to:
· |
The
absence in 2007 of depreciation expense related to assets held for
sale
|
· |
Earnings
related to an electric generating facility construction project in
Hobbs,
New Mexico
|
· |
Higher
income at the Hardin Generating Station which was placed into service
in
March of 2006
|
Partially
offsetting these increases were decreased income from continuing operations,
largely due to higher interest expense and lower earnings from equity method
investments. For more information, see Note 20.
Other
and Intersegment Transactions
Amounts
presented in the preceding tables will not agree with the Consolidated
Statements of Income due to the Company’s other operations and the elimination
of intersegment transactions. The amounts relating to these items are as
follows:
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
2.4
|
|
$
|
2.3
|
|
$
|
4.9
|
|
$
|
4.1
|
|
Operation
and maintenance
|
|
|
1.8
|
|
|
1.8
|
|
|
3.9
|
|
|
3.0
|
|
Depreciation,
depletion and amortization
|
|
|
.3
|
|
|
.2
|
|
|
.6
|
|
|
.5
|
|
Taxes,
other than income
|
|
|
---
|
|
|
.1
|
|
|
---
|
|
|
.1
|
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
76.9
|
|
$
|
72.2
|
|
$
|
171.1
|
|
$
|
180.2
|
|
Purchased
natural gas sold
|
|
|
69.8
|
|
|
65.0
|
|
|
157.1
|
|
|
166.3
|
|
Operation
and maintenance
|
|
|
7.1
|
|
|
7.2
|
|
|
14.0
|
|
|
13.9
|
|
For
further information on intersegment eliminations, see Note 16.
PROSPECTIVE
INFORMATION
The
following information highlights the key growth strategies, projections and
certain assumptions for the Company and its subsidiaries and other matters
for
each of the Company’s businesses. Many of these highlighted points are
“forward-looking statements.” There is no assurance that the Company’s
projections, including estimates for growth and increases in revenues and
earnings, will in fact be achieved. Please refer to assumptions contained in
this section, as well as the various important factors listed in Part II, Item
1A - Risk Factors, as well as Part I, Item 1A - Risk Factors in the 2006 Annual
Report. Changes in such assumptions and factors could cause actual future
results to differ materially from targeted growth, revenue and earnings
projections.
MDU
Resources Group, Inc.
· |
Earnings
per common share for 2007, diluted, are projected in the range of
$2.15 to
$2.35. This
earnings per share guidance range includes the estimated third quarter
gain of approximately $90 million (after tax) on the sale of the
domestic independent power production assets and earnings from
discontinued operations. Excluding the estimated gain, earnings per
share guidance for 2007 has been increased to a range of $1.65 to
$1.85,
an increase from prior guidance of $1.55 to $1.75.
|
· |
The
Company expects the percentage of 2007 earnings per common share,
diluted,
by quarter, including the gain on the sale of the domestic independent
power production assets, to be in the following approximate
ranges:
|
o |
Third
quarter - 45 percent to 50 percent
|
o |
Fourth
quarter - 15 percent to 20 percent
|
· |
Long-term
compound annual growth goals on earnings per share from operations
are in
the range of 7 percent to 10
percent.
|
Electric
· |
The
Company is analyzing potential projects for accommodating load growth
and
replacing an expired purchased power contract with company-owned
generation which will add to base-load capacity and rate base. A
filing in
North Dakota for prudence approval of Big Stone II was made in November
2006, with an order expected by September 2007. The Company would
own
approximately 116 MW of Big Stone II. The plant is projected to be
on line
in 2012. A final decision on the project will be made once major
permits
are issued, which
is expected to occur in early 2008.
|
· |
The
Company is in the process of constructing approximately 20 MW of
wind-powered electric generation near Baker, Montana. The project
includes
13, 1.5-MW wind turbines at a project cost of approximately $37 million.
The project is expected to be rate based and on line in late
2007.
|
· |
On
July 12, 2007, Montana-Dakota filed an electric rate case with the
MTPSC,
as discussed in Note 18.
|
Natural
gas distribution
· |
This
business continues to pursue expansion of energy-related services
and
expects continuing strong customer growth in Washington and
Oregon.
|
· |
For
more information on the acquisition of Cascade, see Note
20.
|
Construction
services
· |
The
Company anticipates higher average margins in 2007 as compared to
2006,
and continues to focus on costs and efficiencies to improve
margins.
|
· |
Work
backlog as of June 30, 2007, was approximately $765 million compared
to
$523 million at June 30,
2006.
|
Pipeline
and energy services
· |
Based
on anticipated demand, additional incremental expansions to the Grasslands
Pipeline are forecasted over the next few years. The next expansion,
to
138,000 Mcf per day, is scheduled for completion in late 2007. Through
additional compression, the pipeline capacity could ultimately reach
200,000 Mcf per day.
|
· |
In
2007, total gathering and transportation throughput is expected to
increase approximately 5 percent over 2006 record
levels.
|
Natural
gas and oil production
· |
Long-term
compound annual growth goals for production are in the range of 7
percent
to 10 percent.
|
· |
In
2007, the Company expects a combined natural gas and oil production
increase in the range of 5 percent to 7 percent. The updated guidance
reflects delayed infrastructure installation in the Company’s Powder River
coalbed and South Texas operations, spring weather conditions which
delayed completion and work over activities, and longer dewatering
time
required on the coalbed wells drilled in
2006.
|
· |
The
Company expects to drill approximately 250 wells in 2007, dependent
on the
timely receipt of regulatory approvals. Previous guidance assumed
the
drilling of one coalbed well for each coal seam targeted. Revised
guidance is based on the commingling of multiple coal seams into
a single
well bore, reducing the number of wells required to be drilled while
accessing the same reserve potential. Currently, this segment’s net
combined natural gas and oil production is approximately 200,000
Mcf
equivalent to 210,000 Mcf equivalent per
day.
|
· |
Earnings
guidance reflects estimated natural gas prices for August through
December
2007 as follows:
|
Index*
|
Price
Per Mcf
|
Ventura
|
$6.25
to $6.75
|
NYMEX
|
$6.75
to $7.25
|
CIG
|
$4.00
to $4.50
|
*
Ventura is an index pricing point related to Northern Natural Gas
Co.’s
system; CIG is an index pricing point related to Colorado Interstate
Gas
Co.’s system.
|
|
During
2006, more than three-fourths of natural gas production was priced
at
non-NYMEX prices, the majority of which was at Ventura pricing.
|
· |
Earnings
guidance reflects estimated NYMEX crude oil prices for July through
December 2007 in the range of $63 to $68 per barrel.
|
· |
The
Company has hedged approximately 35 percent to 40 percent of its
estimated
natural gas production and less than five percent of its estimated
oil
production for the last six months of 2007. For 2008, the Company
has
hedged approximately 25 percent to 30 percent of its estimated natural
gas
production and less than five percent of its estimated oil production.
The
hedges that are in place as of August 3, 2007, are summarized in
the
following chart:
|
Commodity
|
Index*
|
Period
Outstanding
|
Forward
Notional Volume
(MMBtu)(Bbl)
|
Price
Swap or
Costless
Collar
Floor-Ceiling
(Per
MMBtu/Bbl)
|
Natural
Gas
|
Ventura
|
7/07
- 10/07
|
922,500
|
$7.16
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
920,000
|
$8.00-$11.91
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
460,000
|
$8.00-$11.80
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
460,000
|
$8.00-$11.75
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
920,000
|
$7.50-$10.55
|
Natural
Gas
|
CIG
|
7/07
- 12/07
|
920,000
|
$7.40
|
Natural
Gas
|
CIG
|
7/07
- 12/07
|
920,000
|
$7.405
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
736,000
|
$8.25-$10.80
|
Natural
Gas
|
CIG
|
7/07
- 12/07
|
460,000
|
$7.50-$9.12
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
920,000
|
$8.29
|
Natural
Gas
|
Ventura
|
7/07
- 12/07
|
920,000
|
$7.85-$9.70
|
Natural
Gas
|
Ventura
|
7/07
-
12/07
|
1,840,000
|
$7.67
|
Natural
Gas
|
NYMEX
|
7/07
- 12/07
|
920,000
|
$7.50-$8.50
|
Natural
Gas
|
Ventura
|
11/07
- 3/08
|
1,520,000
|
$8.00-$8.75
|
Natural
Gas
|
Ventura
|
11/07
- 3/08
|
608,000
|
$9.01
|
Natural
Gas
|
Ventura
|
1/08
- 3/08
|
910,000
|
$9.35
|
Natural
Gas
|
CIG
|
1/08
- 3/08
|
910,000
|
$7.00-$7.79
|
Natural
Gas
|
CIG
|
1/08
- 3/08
|
910,000
|
$8.06
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.00-$8.05
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.00-$8.06
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.45
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$7.50-$8.70
|
Natural
Gas
|
Ventura
|
4/08
- 10/08
|
1,070,000
|
$8.005
|
Natural
Gas
|
Ventura
|
1/08
- 12/08
|
1,830,000
|
$7.00-$8.45
|
Natural
Gas
|
Ventura
|
1/08
- 12/08
|
1,830,000
|
$7.50-$8.34
|
Natural
Gas
|
Ventura
|
1/08
- 12/08
|
3,294,000
|
$8.55
|
Natural
Gas
|
Ventura
|
11/08
- 12/08
|
610,000
|
$8.85
|
Crude
Oil
|
NYMEX
|
9/07
- 12/07
|
51,850
|
$75.25
|
Crude
Oil
|
NYMEX
|
1/08
- 12/08
|
73,200
|
$67.50-$78.70
|
*
Ventura is an index pricing point related to Northern Natural Gas
Co.’s
system; CIG is
an index pricing point related to Colorado Interstate Gas Co.’s
system.
|
Construction
materials and mining
· |
The
Company has 1.2 billion tons of strategically located aggregate reserves,
a key element of its vertical integration
strategy.
|
· |
The
Company anticipates margins in 2007 to be comparable to 2006.
|
· |
Work
backlog as of June 30, 2007, of approximately $662 million includes
a
higher expected average margin than the backlog of $763 million at
June 30, 2006.
|
Independent
power production
· |
For
information regarding the sale of the domestic independent power
production assets, see Note 20.
|
NEW
ACCOUNTING STANDARDS
For
information regarding new accounting standards, see Note 10, which is
incorporated by reference.
CRITICAL
ACCOUNTING POLICIES INVOLVING SIGNIFICANT ESTIMATES
The
Company’s critical accounting policies involving significant estimates include
impairment testing of long-lived assets and intangibles, impairment testing
of
natural gas and oil production properties, revenue recognition, purchase
accounting, asset retirement obligations, and pension and other postretirement
benefits. There were no material changes in the Company’s critical accounting
policies involving significant estimates from those reported in the 2006 Annual
Report. For more information on critical accounting policies involving
significant estimates, see Part II, Item 7 in the 2006 Annual
Report.
LIQUIDITY
AND CAPITAL COMMITMENTS
Cash
flows
Operating
activities Net
income before depreciation, depletion and amortization is a significant
contributor to cash flows from operating activities. The changes in cash flows
from operating activities generally follow the results of operations as
discussed in Financial and Operating Data and also are affected by changes
in
working capital. Cash flows provided by operating activities in the first six
months of 2007 decreased $52.9 million from the comparable 2006 period, the
result of increased cash used related to discontinued operations of $52.1
million, largely due to an increase in quarterly income tax payments due to
the
estimated gain on the sale of the domestic independent power production assets.
In addition, cash used for working capital requirements increased $21.6 million,
largely due to the effects of:
· |
Lower
accounts payable, largely at the construction services and construction
materials and mining businesses
|
· |
The
timing of natural gas costs recoverable through rate adjustments
at the
natural gas distribution business
|
Partially
offsetting the decrease in cash flows from operating activities
were:
· |
Decreased
receivables at the construction services and construction materials
and
mining businesses, partially offset by higher receivables at the
natural
gas distribution and natural gas and oil production businesses, due
to
fluctuations in natural gas prices
|
· |
Higher
depreciation, depletion and amortization expense of $14.0 million
and
higher deferred income taxes of $8.8
million
|
Investing
activities Cash
flows used in investing activities in the first six months of 2007 decreased
$162.0 million compared to the comparable 2006 period, the result of:
· |
A
decrease in cash flows used for acquisitions of $108.9 million, largely
at
the natural gas and oil production
business
|
· |
Decreased
cash used in investing activities from discontinued operations of
$36.7
million, largely the result of lower capital expenditures related
to the
Hardin Generating Facility and a decrease in cash flows used for
acquisitions, both of which are related to the independent power
production business
|
· |
Lower
investments of $22.5 million, primarily the result of the sale of
the
Trinity Generating Facility during the first quarter of
2007
|
Financing
activities Cash
flows provided by financing activities in the first six months of 2007 decreased
$125.9 million compared to the comparable 2006 period, primarily the result
of a
decrease in the issuance of long-term debt of $149.1 million, partially offset
by a decrease in the repayment of long-term debt of $12.1 million and an
increase in the issuance of common stock of $13.1 million.
Defined
benefit pension plans
There
were no material changes to the Company’s qualified noncontributory defined
benefit pension plans from those reported in the 2006 Annual Report. For further
information, see Note 17 and Part II, Item 7 in the 2006 Annual Report.
Capital
expenditures
Net
capital expenditures for the first six months of 2007 were $245.0 million.
Net
capital expenditures are estimated to be approximately $1.1 billion for 2007,
excluding proceeds from the sale of the domestic independent power production
assets. Estimated 2007 net capital expenditures also exclude potential future
acquisitions and proceeds related to the disposal of unidentified assets.
Estimated capital expenditures include those for:
· |
Routine
equipment maintenance and
replacements
|
· |
Buildings,
land and building improvements
|
· |
Pipeline
and gathering projects
|
· |
Further
enhancement of natural gas and oil production and reserve
growth
|
· |
Power
generation opportunities, including certain costs for additional
electric
generating capacity
|
· |
Other
growth opportunities
|
Approximately
46 percent of estimated 2007 net capital expenditures noted above are
associated with completed acquisitions, primarily related to the acquisition
of
Cascade. The Company continues to evaluate potential future acquisitions and
other growth opportunities; however, they are dependent upon the availability
of
economic opportunities and, as a result, capital expenditures may vary
significantly from the estimated 2007 capital expenditures referred to
previously. It is anticipated that all of the funds required for capital
expenditures will be met from various sources, including internally generated
funds; the Company’s credit facilities, as described below; and through the
issuance of long-term debt and the Company’s equity securities.
Capital
resources
Certain
debt instruments of the Company and its subsidiaries, including those discussed
below, contain restrictive covenants, all of which the Company and its
subsidiaries were in compliance with at June 30, 2007.
MDU
Resources Group, Inc. The
Company has a revolving credit agreement with various banks totaling $125
million (with provision for an increase, at the option of the Company on stated
conditions, up to a maximum of $150 million). There were no amounts outstanding
under the credit agreement at June 30, 2007. The credit agreement supports
the
Company’s $100 million commercial paper program. Under the Company’s
commercial paper program, $18.5 million was outstanding at June 30, 2007. The
commercial paper borrowings are classified as long-term debt as they are
intended to be refinanced on a long-term basis through continued commercial
paper borrowings (supported by the credit agreement, which expires in June
2011).
The
Company’s objective is to maintain acceptable credit ratings in order to access
the capital markets through the issuance of commercial paper. Minor fluctuations
in the Company’s credit ratings have not limited, nor would they be expected to
limit, the Company’s ability to access the capital markets. In the event of a
minor downgrade, the Company may experience a nominal basis point increase
in
overall interest rates with respect to its cost of borrowings. If the Company
was to experience a significant downgrade of its credit ratings, it may need
to
borrow under its credit agreement.
Prior
to
the maturity of the credit agreement, the Company expects that it will negotiate
the extension or replacement of this agreement. If the Company is unable to
successfully negotiate an extension of, or replacement for, the credit
agreement, or if the fees on this facility became too expensive, which the
Company does not currently anticipate, the Company would seek alternative
funding.
In
order
to borrow under the Company’s credit agreement discussed above, the Company must
be in compliance with the applicable covenants and certain other conditions.
For
information on the covenants and certain other conditions of the Company’s
credit agreement, see Part II, Item 7, in the 2006 Annual Report. The Company
was in compliance with these covenants and met the required conditions at June
30, 2007. In the event the Company does not comply with the applicable covenants
and other conditions, alternative sources of funding may need to be pursued,
as
previously described.
On
June
29, 2007, the Company entered into a term loan agreement to be used in
connection with the Cascade acquisition. For more information, see Note
20.
The
term
loan agreement contains customary covenants and default provisions, including
covenants of the Company not to permit, as of the end of any fiscal quarter,
(i)
the ratio of funded debt to total capitalization (on a consolidated basis)
to be
greater than 65 percent or (ii) the ratio of funded debt to capitalization
(determined with respect to the Company only, excluding subsidiaries) to be
greater than 65 percent. The agreement also includes a covenant requiring the
ratio of the Company’s earnings before interest, taxes, depreciation and
amortization to interest expense (determined with respect to the Company only,
excluding subsidiaries), for the twelve month period ended each fiscal quarter,
to be greater than 2.5 to 1.
There
are
no credit facilities that contain cross-default provisions between the Company
and any of its subsidiaries.
The
Company's issuance of first mortgage debt is subject to certain restrictions
imposed under the terms and conditions of its Mortgage. Generally, those
restrictions require the Company to fund $1.43 of unfunded property or use
$1.00
of refunded bonds for each dollar of indebtedness incurred under the Indenture
and, in some cases, to certify to the trustee that annual earnings (pretax
and
before interest charges), as defined in the Indenture, equal at least two times
its annualized first mortgage bond interest costs. Under the more restrictive
of
the tests, as of June 30, 2007, the Company could have issued approximately
$493
million of additional first mortgage bonds.
The
Company's coverage of fixed charges including preferred dividends was 6.2 times
and 6.4 times for the 12 months ended June 30, 2007 and December 31, 2006,
respectively. Additionally, the Company's first mortgage bond interest coverage
was 35.1 times and 26.0 times for the 12 months ended June 30, 2007 and December
31, 2006, respectively. Common stockholders' equity as a percent of total
capitalization (net of long-term debt due within one year) was 65 percent at
both June 30, 2007 and December 31, 2006.
The
Company has repurchased, and may from time to time seek to repurchase,
outstanding first mortgage bonds through open market purchases or privately
negotiated transactions. The Company will evaluate any such transactions in
light of then existing market conditions, taking into account its liquidity
and
prospects for future access to capital. As of June 30, 2007, the Company had
$50.5 million of first mortgage bonds outstanding, $30 million of which were
held by the Indenture trustee for the benefit of the senior note holders. At
such time as the aggregate principal amount of the Company’s outstanding first
mortgage bonds, other than those held by the Indenture trustee, is $20 million
or less, the Company would have the ability, subject to satisfying certain
specified conditions, to require that any debt issued under its Indenture become
unsecured and rank equally with all of the Company’s other unsecured and
unsubordinated debt (as of June 30, 2007, the only such debt outstanding under
the Indenture was $30 million in aggregate principal amount of the Company’s
5.98% Senior Notes due in 2033).
The
Company has entered into a Sales Agency Financing Agreement, as amended June
25,
2007, with Wells Fargo Securities, LLC with respect to the issuance and sale
of
up to 3,000,000 shares of the Company’s common stock, par value $1.00 per share,
together with preference share purchase rights appurtenant thereto. The common
stock may be offered for sale, from time to time, in accordance with the terms
and conditions of the agreement, which terminates on December 1, 2008. Proceeds
from the sale of shares of common stock under the agreement are expected to
be
used for corporate development purposes and other general corporate purposes.
The offering would be made pursuant to the Company’s shelf registration
statement on Form S-3, as amended, which became effective on September 26,
2003,
as supplemented by a prospectus supplement, dated June 28, 2007, filed with
the
SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended. The
Company has not issued any stock under the Sales Agency Financing Agreement
through June 30, 2007.
Centennial
Energy Holdings, Inc.
Centennial has two revolving credit agreements with various banks and
institutions totaling $425 million with certain provisions allowing for
increased borrowings. These credit agreements support Centennial’s
$400 million commercial paper program. There were no outstanding borrowings
under the Centennial credit agreements at June 30, 2007. Under the Centennial
commercial paper program, $283.8 million was outstanding at June 30, 2007.
The
Centennial commercial paper borrowings are classified as long-term debt as
Centennial intends to refinance these borrowings on a long-term basis through
continued Centennial commercial paper borrowings (supported by Centennial credit
agreements). One of these credit agreements is for $400 million, which includes
a provision for an increase, at the option of Centennial on stated conditions,
up to a maximum of $450 million and expires on August 26, 2010. The second
agreement is an uncommitted line for $25 million, and may be terminated by
the
bank at any time. As of June 30, 2007, $42.6 million of letters of credit were
outstanding, as discussed in Note 19, of which $28.5 million reduced amounts
available under these agreements.
Centennial
has an uncommitted long-term master shelf agreement that allows for borrowings
of up to $550 million. Under the terms of the master shelf agreement, $468.5
million was outstanding at June 30, 2007. The ability to request additional
borrowings under this master shelf agreement expires on May 8, 2009. To meet
potential future financing needs, Centennial may pursue other financing
arrangements, including private and/or public financing.
Centennial’s
objective is to maintain acceptable credit ratings in order to access the
capital markets through the issuance of commercial paper. Minor fluctuations
in
Centennial’s credit ratings have not limited, nor would they be expected to
limit, Centennial’s ability to access the capital markets. In the event of a
minor downgrade, Centennial may experience a nominal basis point increase in
overall interest rates with respect to its cost of borrowings. If Centennial
was
to experience a significant downgrade of its credit ratings, it may need to
borrow under its committed bank lines.
Prior
to
the maturity of the Centennial credit agreements, Centennial expects that it
will negotiate the extension or replacement of these agreements, which provide
credit support to access the capital markets. In the event Centennial was unable
to successfully negotiate these agreements, or in the event the fees on such
facilities became too expensive, which Centennial does not currently anticipate,
it would seek alternative funding.
In
order
to borrow under Centennial’s credit agreements and the Centennial uncommitted
long-term master shelf agreement, Centennial and certain of its subsidiaries
must be in compliance with the applicable covenants and certain other
conditions. For more information on the covenants and certain other conditions
for the $400 million credit agreement and the master shelf agreement, see Part
II, Item 7, in the 2006 Annual Report. Centennial and such subsidiaries were
in
compliance with these covenants and met the required conditions at June 30,
2007. In the event Centennial or such subsidiaries do not comply with the
applicable covenants and other conditions, alternative sources of funding may
need to be pursued as previously described.
Certain
of Centennial’s financing agreements contain cross-default provisions. These
provisions state that if Centennial or any subsidiary of Centennial fails to
make any payment with respect to any indebtedness or contingent obligation,
in
excess of a specified amount, under any agreement that causes such indebtedness
to be due prior to its stated maturity or the contingent obligation to become
payable, the applicable agreements will be in default. Certain of Centennial’s
financing agreements and Centennial’s practice limit the amount of subsidiary
indebtedness.
Williston
Basin Interstate Pipeline Company Williston
Basin has an uncommitted long-term master shelf agreement that allows for
borrowings of up to $100 million. Under the terms of the master shelf agreement,
$80.0 million was outstanding at June 30, 2007. The ability to request
additional borrowings under this master shelf agreement expires on December
20,
2008.
In
order
to borrow under its uncommitted long-term master shelf agreement, Williston
Basin must be in compliance with the applicable covenants and certain other
conditions. For more information on the covenants and certain other conditions
for the uncommitted long-term master shelf agreement, see Part II, Item 7,
in
the 2006 Annual Report. Williston Basin was in compliance with these covenants
and met the required conditions at June 30, 2007. In the event Williston Basin
does not comply with the applicable covenants and other conditions, alternative
sources of funding may need to be pursued.
Off
balance sheet arrangements
In
connection with the sale of MPX in June 2005 to Petrobras, an indirect wholly
owned subsidiary of the Company has agreed to indemnify Petrobras for 49 percent
of any losses that Petrobras may incur from certain contingent liabilities
specified in the purchase agreement. For more information, see Note
19.
Centennial
continues to guarantee CEM’s obligations under a construction contract for a
550-MW combined-cycle electric generating facility near Hobbs, New Mexico.
For
more information, see Note 19.
Contractual
obligations and commercial commitments
There
were no material changes in the Company’s contractual obligations relating to
long-term debt, operating leases and purchase commitments from those reported
in
the 2006 Annual Report.
For
more
information on contractual obligations and commercial commitments, see Part
II,
Item 7 in the 2006 Annual Report.
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The
Company is exposed to the impact of market fluctuations associated with
commodity prices, interest rates and foreign currency. The Company has policies
and procedures to assist in controlling these market risks and utilizes
derivatives to manage a portion of its risk.
Commodity
price risk
Fidelity
utilizes derivative instruments to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil on its
forecasted sales of natural gas and oil production. At June 30, 2007, Fidelity
held natural gas swap and collar derivative instruments designated as cash
flow
hedging instruments and had no outstanding oil derivative instruments. For
more
information on derivative instruments and commodity price risk, see Part II,
Item 7A in the 2006 Annual Report, and Notes 11 and 14.
The
following table summarizes derivative instruments entered into by Fidelity
as of
June 30, 2007. These agreements call for Fidelity to receive fixed prices and
pay variable prices.
(Notional amount and fair value in thousands)
|
|
Weighted
Average
Fixed
Price
(Per
MMBtu)
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
Fair
Value
|
|
Natural
gas swap agreements maturing in 2007
|
|
|
$7.66
|
|
5,767
|
|
|
$9,263
|
|
Natural
gas swap agreements maturing in 2008
|
|
|
$8.41
|
|
8,228
|
|
|
$3,265
|
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
MMBtu)
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2007
|
|
|
$7.83/$10.26
|
|
|
6,406
|
|
|
$
7,578
|
|
Natural
gas collar agreements maturing in 2008
|
|
|
$7.27/$8.32
|
|
|
8,690
|
|
|
$(1,194)
|
|
Interest
rate risk
There
were no material changes to interest rate risk faced by the Company from those
reported in the 2006 Annual Report. For more information on interest rate risk,
see Part II, Item 7A in the 2006 Annual Report.
At
June
30, 2007 and 2006, and December 31, 2006, the Company had no outstanding
interest rate hedges.
Foreign
currency risk
MDU
Brasil’s equity method investments in the Brazilian Transmission Lines are
exposed to market risks from changes in foreign currency exchange rates between
the U.S. dollar and the Brazilian Real. For further information on foreign
currency risk, see Note 4 in the 2006 Annual Report.
At
June
30, 2007 and 2006, and December 31, 2006, the Company had no outstanding foreign
currency hedges.
ITEM
4. CONTROLS AND PROCEDURES
The
following information includes the evaluation of disclosure controls and
procedures by the Company’s chief executive officer and the chief financial
officer, along with any significant changes in internal controls of the
Company.
Evaluation
of disclosure controls and procedures
The
term
"disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e)
of the Exchange Act. These rules refer to the controls and other procedures
of a
company that are designed to ensure that information required to be disclosed
by
a company in the reports it files under the Exchange Act is recorded, processed,
summarized and reported within required time periods. The Company’s chief
executive officer and chief financial officer have evaluated the effectiveness
of the Company’s disclosure controls and procedures and they have concluded
that, as of the end of the period covered by this report, such controls and
procedures were effective.
Changes
in internal controls
The
Company maintains a system of internal accounting controls that is designed
to
provide reasonable assurance that the Company’s transactions are properly
authorized, that the Company’s assets are safeguarded against unauthorized or
improper use and that the Company’s transactions are properly recorded and
reported to permit preparation of the Company’s financial statements in
conformity with generally accepted accounting principles in the United States
of
America. There were no changes in the Company’s internal control over financial
reporting that occurred during the period covered by this report that have
materially affected, or are reasonably likely to materially affect, the
Company’s internal control over financial reporting.
PART
II -- OTHER INFORMATION
ITEM
1. LEGAL PROCEEDINGS
For
information regarding legal proceedings, see Note 19, which is incorporated
by
reference.
ITEM
1A. RISK FACTORS
This
Form
10-Q contains forward-looking statements within the meaning of Section 21E
of
the Exchange Act. Forward-looking statements are all statements other than
statements of historical fact, including without limitation those statements
that are identified by the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts" and similar expressions.
The
Company is including the following factors and cautionary statements in this
Form 10-Q to make applicable and to take advantage of the safe harbor provisions
of the Private Securities Litigation Reform Act of 1995 for any forward-looking
statements made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies, future
events or performance, and underlying assumptions (many of which are based,
in
turn, upon further assumptions) and other statements that are other than
statements of historical facts. From time to time, the Company may publish
or
otherwise make available forward-looking statements of this nature, including
statements contained within Prospective Information. All these subsequent
forward-looking statements, whether written or oral and whether made by or
on
behalf of the Company, also are expressly qualified by these factors and
cautionary statements.
Forward-looking
statements involve risks and uncertainties, which could cause actual results
or
outcomes to differ materially from those expressed. The Company's expectations,
beliefs and projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation, management's
examination of historical operating trends, data contained in the Company's
records and other data available from third parties. Nonetheless, the Company's
expectations, beliefs or projections may not be achieved or accomplished.
Any
forward-looking statement contained in this document speaks only as of the
date
on which the statement is made, and the Company undertakes no obligation to
update any forward-looking statement or statements to reflect events or
circumstances that occur after the date on which the statement is made or to
reflect the occurrence of unanticipated events. New factors emerge from time
to
time, and it is not possible for management to predict all of the factors,
nor
can it assess the effect of each factor on the Company's business or the extent
to which any factor, or combination of factors, may cause actual results to
differ materially from those contained in any forward-looking
statement.
There
are
no material changes in the Company’s risk factors from those reported in Part I,
Item 1A - Risk Factors of the 2006 Annual Report other than the completion
of
the Company’s acquisition of Cascade. These factors are important factors that
could cause actual results or outcomes for the Company to differ materially
from
those discussed in the forward-looking statements included elsewhere in this
document.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
Between
April 1, 2007 and June 30, 2007, the Company issued 1,295 shares of common
stock, $1.00 par value, and the preference share purchase rights appurtenant
thereto, as part of the consideration paid by the Company in the acquisition
of
businesses acquired by the Company in a prior period. The common stock and
preference share purchase rights issued by the Company in these transactions
were issued in a private transaction exempt from registration under the
Securities Act of 1933, as amended, pursuant to Section 4 (2) thereof, Rule
506
promulgated thereunder, or both. The classes of persons to whom these securities
were sold were either accredited investors or other persons to whom such
securities were permitted to be offered under the applicable
exemption.
The
following table includes information with respect to the issuer’s purchase of
equity securities:
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
(a)
Total
Number of Shares
(or
Units) Purchased (1)
|
(b)
Average
Price Paid
per
Share
(or
Unit)
|
(c)
Total
Number of Shares (or Units) Purchased as Part of Publicly Announced
Plans
or Programs (2)
|
(d)
Maximum
Number (or Approximate Dollar Value) of Shares (or Units) that May
Yet Be
Purchased Under the Plans or Programs (2)
|
April
1 through April 30, 2007
|
36,668
|
$31.05
|
|
|
May
1 through May 31, 2007
|
|
|
|
|
June
1 through June 30, 2007
|
|
|
|
|
Total
|
36,668
|
|
|
|
(1)
Represents 218 shares of common stock withheld by the Company to pay taxes
in
connection with the vesting of shares granted pursuant to a compensation plan
and 36,450 shares of common stock purchased on the open market in connection
with annual stock grants made to the Company’s non-employee
directors.
(2)
Not
applicable. The Company does not currently have in place any publicly announced
plans or programs to repurchase equity securities.
ITEM
6. EXHIBITS
See
the
index to exhibits immediately preceding the exhibits filed with this
report.
SIGNATURES
Pursuant
to the requirements of the Exchange Act, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly
authorized.
|
|
MDU
RESOURCES GROUP, INC.
|
|
|
|
|
|
|
|
|
|
|
|
|
DATE:
August
8, 2007
|
|
BY:
|
/s/
Vernon A. Raile
|
|
|
|
Vernon
A. Raile
|
|
|
|
Executive
Vice President, Treasurer
|
|
|
|
and
Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
BY:
|
/s/
Doran N. Schwartz
|
|
|
|
Doran
N. Schwartz
|
|
|
|
Vice
President and Chief Accounting
Officer
|
EXHIBIT
INDEX
Exhibit
No.
4
|
MDU
Resources Group, Inc. Term Loan Agreement, dated June 29, 2007, among
MDU
Resources Group, Inc., Wells Fargo Bank, National Association, as
Administrative Agent, and The Other Financial Institutions party
thereto
|
|
|
+10
|
Consulting
Agreement, dated July 2, 2007, by and between Williston Basin Interstate
Pipeline Company and John K. Castleberry
|
|
|
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
|
+
Management contract, compensatory plan or arrangement.
MDU
Resources Group, Inc. agrees to furnish to the SEC upon request any instrument
with respect to long-term debt that MDU Resources Group, Inc. has not filed
as
an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of
Regulation S-K.