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, 2006
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 July 31, 2006:
180,136,624 shares.
DEFINITIONS
The
following abbreviations and acronyms used in this Form 10-Q are defined
below:
Abbreviation
or Acronym
2005
Annual Report
|
Company's
Annual Report on Form 10-K for the year ended December 31,
2005
|
ALJ
|
Administrative
Law Judge
|
Anadarko
|
Anadarko
Petroleum Corporation
|
APB
|
Accounting
Principles Board
|
APB
Opinion No. 25
|
Accounting
for Stock-Based Compensation
|
APB
Opinion No. 28
|
Interim
Financial Reporting
|
Badger
Hills Project
|
Tongue
River-Badger Hills Project
|
Bbl
|
Barrel
|
BER
|
Montana
Board of Environmental Review
|
Bitter
Creek
|
Bitter
Creek Pipelines, LLC, an indirect wholly owned subsidiary of WBI
Holdings
|
BLM
|
Bureau
of Land Management
|
Carib
Power
|
Carib
Power Management LLC
|
Cascade
|
Cascade
Natural Gas Corporation
|
Centennial
|
Centennial
Energy Holdings, Inc., a direct wholly owned subsidiary of the
Company
|
Centennial
Capital
|
Centennial
Holdings Capital LLC, a direct wholly owned subsidiary of
Centennial
|
Centennial
Resources
|
Centennial
Energy Resources LLC, a direct wholly owned subsidiary of
Centennial
|
Clean
Water Act
|
Federal
Clean Water Act
|
Company
|
MDU
Resources Group, Inc.
|
D.C.
Appeals Court
|
U.S.
Court of Appeals for the District of Columbia Circuit
|
dk
|
Decatherm
|
EITF
|
Emerging
Issues Task Force
|
EITF
No. 04-6
|
Accounting
for Stripping Costs in the Mining Industry
|
EPA
|
U.S.
Environmental Protection Agency
|
Exchange
Act
|
Securities
Exchange Act of 1934
|
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
|
Hart-Scott-Rodino
Act
|
Hart-Scott-Rodino
Antitrust Improvements Act
|
Hartwell
|
Hartwell
Energy Limited Partnership
|
Hartwell
Generating Facility
|
310-MW
natural gas-fired electric generating facility near Hartwell, Georgia
(50
percent ownership)
|
Howell
|
Howell
Petroleum Corporation
|
Knife
River
|
Knife
River Corporation, a direct wholly owned subsidiary of
Centennial
|
kW
|
Kilowatts
|
kWh
|
Kilowatt-hour
|
LWG
|
Lower
Willamette Group
|
MBbls
|
Thousands
of barrels of oil or other liquid hydrocarbons
|
MBI
|
Morse
Bros., Inc., an indirect wholly owned subsidiary of Knife
River
|
Mcf
|
Thousand
cubic feet
|
MDU
Construction Services
|
MDU
Construction Services Group, Inc., formerly Utility Services, Inc.
(name
change was effective December 23, 2005), 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
|
MNPUC
|
Minnesota
Public Utilities Commission
|
MPX
|
MPX
Termoceara Ltda.
|
MW
|
Megawatt
|
Nance
Petroleum
|
Nance
Petroleum Corporation, a wholly owned subsidiary of
St. Mary
|
ND
Health Department
|
North
Dakota Department of Health
|
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
|
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. 123
|
Accounting
for Stock-Based Compensation
|
SFAS
No. 123 (revised)
|
Share-Based
Payment (revised 2004)
|
SFAS
No. 148
|
Accounting
for Stock-Based Compensation - Transition and Disclosure - an amendment
of
SFAS No. 123
|
St.
Mary
|
St.
Mary Land & Exploration Company
|
Termoceara
Generating Facility
|
220-MW
natural gas-fired electric generating facility in the Brazilian
state of
Ceara (49 percent ownership)
|
Trinity
Generating Facility
|
225-MW
natural gas-fired electric generating facility in Trinidad and
Tobago
(49.99 percent ownership)
|
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.
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 15.
On
May
11, 2006, the Company’s Board of Directors approved a three-for-two common stock
split. For more information on the common stock split, see Note 3.
INDEX
Part
I -- Financial Information
Consolidated
Statements of Income --
Three
and
Six Months Ended June 30, 2006 and 2005
Consolidated
Balance Sheets --
June
30,
2006 and 2005, and December 31, 2005
Consolidated
Statements of Cash Flows --
Six
Months Ended June 30, 2006 and 2005
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,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands, except per share amounts)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
$
|
171,221
|
|
$
|
182,109
|
|
$
|
462,782
|
|
$
|
437,481
|
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
802,562
|
|
|
588,063
|
|
|
1,326,295
|
|
|
936,986
|
|
|
|
|
973,783
|
|
|
770,172
|
|
|
1,789,077
|
|
|
1,374,467
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
16,872
|
|
|
14,547
|
|
|
33,246
|
|
|
30,733
|
|
Purchased
natural gas sold
|
|
|
39,361
|
|
|
46,673
|
|
|
166,321
|
|
|
160,172
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
|
43,719
|
|
|
39,482
|
|
|
81,883
|
|
|
78,467
|
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
647,190
|
|
|
475,784
|
|
|
1,093,466
|
|
|
766,788
|
|
Depreciation,
depletion and amortization
|
|
|
69,105
|
|
|
51,588
|
|
|
132,482
|
|
|
104,427
|
|
Taxes,
other than income
|
|
|
33,137
|
|
|
28,574
|
|
|
66,179
|
|
|
55,243
|
|
|
|
|
849,384
|
|
|
656,648
|
|
|
1,573,577
|
|
|
1,195,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
124,399
|
|
|
113,524
|
|
|
215,500
|
|
|
178,637
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
from equity method investments
|
|
|
2,900
|
|
|
15,404
|
|
|
6,102
|
|
|
16,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
income
|
|
|
2,912
|
|
|
1,505
|
|
|
5,310
|
|
|
2,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
19,159
|
|
|
13,342
|
|
|
33,243
|
|
|
26,359
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
111,052
|
|
|
117,091
|
|
|
193,669
|
|
|
171,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
39,610
|
|
|
36,918
|
|
|
68,980
|
|
|
57,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
71,442
|
|
|
80,173
|
|
|
124,689
|
|
|
114,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
on preferred stocks
|
|
|
171
|
|
|
171
|
|
|
343
|
|
|
342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
on common stock
|
|
$
|
71,271
|
|
$
|
80,002
|
|
$
|
124,346
|
|
$
|
114,251
|
|
Earnings
per common share -- basic
|
|
$
|
.40
|
|
$
|
.45
|
|
$
|
.69
|
|
$
|
.65
|
|
Earnings
per common share -- diluted
|
|
$
|
.39
|
|
$
|
.45
|
|
$
|
.69
|
|
$
|
.64
|
|
Dividends
per common share
|
|
$
|
.1267
|
|
$
|
.1200
|
|
$
|
.2534
|
|
$
|
.2400
|
|
Weighted
average common shares outstanding -- basic
|
|
|
179,911
|
|
|
177,522
|
|
|
179,867
|
|
|
177,133
|
|
Weighted
average common shares outstanding -- diluted
|
|
|
181,107
|
|
|
178,556
|
|
|
181,050
|
|
|
178,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
BALANCE SHEETS
(Unaudited)
|
|
June
30,
2006
|
|
June
30,
2005
|
|
December
31,
2005
|
(In
thousands, except shares and per share amounts)
|
ASSETS
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
116,698
|
|
$
|
57,711
|
|
$
|
107,435
|
|
Receivables,
net
|
|
|
651,192
|
|
|
546,722
|
|
|
603,959
|
|
Inventories
|
|
|
207,746
|
|
|
158,886
|
|
|
172,201
|
|
Deferred
income taxes
|
|
|
11,637
|
|
|
6,840
|
|
|
9,062
|
|
Prepayments
and other current assets
|
|
|
93,203
|
|
|
56,859
|
|
|
40,539
|
|
|
|
|
1,080,476
|
|
|
827,018
|
|
|
933,196
|
|
Investments
|
|
|
106,226
|
|
|
98,563
|
|
|
98,217
|
|
Property,
plant and equipment
|
|
|
4,925,546
|
|
|
4,273,670
|
|
|
4,594,355
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
1,654,465
|
|
|
1,440,732
|
|
|
1,544,462
|
|
|
|
|
3,271,081
|
|
|
2,832,938
|
|
|
3,049,893
|
|
Deferred
charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
242,955
|
|
|
214,972
|
|
|
230,865
|
|
Other
intangible assets, net
|
|
|
25,550
|
|
|
30,297
|
|
|
19,059
|
|
Other
|
|
|
103,141
|
|
|
91,953
|
|
|
92,332
|
|
|
|
|
371,646
|
|
|
337,222
|
|
|
342,256
|
|
|
|
$
|
4,829,429
|
|
$
|
4,095,741
|
|
$
|
4,423,562
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt due within one year
|
|
$
|
159,168
|
|
$
|
26,866
|
|
$
|
101,758
|
|
Accounts
payable
|
|
|
294,951
|
|
|
212,888
|
|
|
269,021
|
|
Taxes
payable
|
|
|
31,919
|
|
|
26,300
|
|
|
50,533
|
|
Dividends
payable
|
|
|
22,967
|
|
|
21,685
|
|
|
22,951
|
|
Other
accrued liabilities
|
|
|
157,438
|
|
|
164,225
|
|
|
184,665
|
|
|
|
|
666,443
|
|
|
451,964
|
|
|
628,928
|
|
Long-term
debt
|
|
|
1,299,175
|
|
|
1,119,719
|
|
|
1,104,752
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
571,427
|
|
|
505,651
|
|
|
526,176
|
|
Other
liabilities
|
|
|
281,934
|
|
|
244,018
|
|
|
272,084
|
|
|
|
|
853,361
|
|
|
749,669
|
|
|
798,260
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
|
|
|
|
|
|
Preferred
stocks
|
|
|
15,000
|
|
|
15,000
|
|
|
15,000
|
|
Common
stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
|
|
|
|
|
|
|
|
|
Shares
issued -- $1.00 par value 180,515,943 at June 30, 2006, 120,093,303
at
June 30, 2005 and 120,262,786 at December 31, 2005
|
|
|
180,516
|
|
|
120,093
|
|
|
120,263
|
|
Other
paid-in capital
|
|
|
856,366
|
|
|
898,373
|
|
|
909,006
|
|
Retained
earnings
|
|
|
963,194
|
|
|
770,361
|
|
|
884,795
|
|
Accumulated
other comprehensive loss
|
|
|
(1,000
|
)
|
|
(24,347
|
)
|
|
(33,816
|
)
|
Treasury
stock at cost - 538,921 shares
at
June 30, 2006, 359,281 shares at December 31, 2005 and 412,906
shares at
June 30, 2005
|
|
|
(3,626
|
)
|
|
(5,091
|
)
|
|
(3,626
|
)
|
Total
common stockholders’ equity
|
|
|
1,995,450
|
|
|
1,759,389
|
|
|
1,876,622
|
|
Total
stockholders’ equity
|
|
|
2,010,450
|
|
|
1,774,389
|
|
|
1,891,622
|
|
|
|
$
|
4,829,429
|
|
$
|
4,095,741
|
|
$
|
4,423,562
|
|
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,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
Net
income
|
|
$
|
124,689
|
|
$
|
114,593
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
132,482
|
|
|
104,427
|
|
Earnings,
net of distributions, from equity method investments
|
|
|
(3,107
|
)
|
|
(14,619
|
)
|
Deferred
income taxes
|
|
|
17,492
|
|
|
5,120
|
|
Changes
in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
Receivables
|
|
|
(32,863
|
)
|
|
(34,399
|
)
|
Inventories
|
|
|
(33,249
|
)
|
|
(12,963
|
)
|
Other
current assets
|
|
|
(39,617
|
)
|
|
(16,463
|
)
|
Accounts
payable
|
|
|
30,461
|
|
|
20,545
|
|
Other
current liabilities
|
|
|
(11,356
|
)
|
|
(12,193
|
)
|
Other
noncurrent changes
|
|
|
6,537
|
|
|
9,282
|
|
Net
cash provided by operating activities
|
|
|
191,469
|
|
|
163,330
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(266,251
|
)
|
|
(216,912
|
)
|
Acquisitions,
net of cash acquired
|
|
|
(121,735
|
)
|
|
(162,274
|
)
|
Net
proceeds from sale or disposition of property
|
|
|
14,885
|
|
|
11,355
|
|
Investments
|
|
|
(5,208
|
)
|
|
657
|
|
Net cash used in investing activities
|
|
|
(378,309
|
)
|
|
(367,174
|
)
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
Issuance
of long-term debt
|
|
|
335,653
|
|
|
324,727
|
|
Repayment
of long-term debt
|
|
|
(97,158
|
)
|
|
(123,734
|
)
|
Proceeds
from issuance of common stock
|
|
|
2,709
|
|
|
4,116
|
|
Dividends
paid
|
|
|
(45,914
|
)
|
|
(42,931
|
)
|
Tax
benefit on stock-based compensation
|
|
|
3,167
|
|
|
---
|
|
Net
cash provided by financing activities
|
|
|
198,457
|
|
|
162,178
|
|
Effect
of exchange rate changes on cash and cash
equivalents
|
|
|
(2,354
|
)
|
|
---
|
|
Increase
(decrease) in cash and cash equivalents
|
|
|
9,263
|
|
|
(41,666
|
)
|
Cash
and cash equivalents -- beginning of year
|
|
|
107,435
|
|
|
99,377
|
|
Cash
and cash equivalents -- end of period
|
|
$
|
116,698
|
|
$
|
57,711
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS
June
30, 2006 and 2005
(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 2005 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 2005 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.
Common
stock split
On
May
11, 2006, the Company's Board of Directors approved a three-for-two common
stock
split to be effected in the form of a 50 percent common stock dividend. The
additional shares of common stock were distributed on July 26, 2006, to common
stockholders of record on July 12, 2006. Certain common stock information
appearing in the accompanying consolidated financial statements has been
restated in accordance with accounting principles generally accepted in the
United States of America to give retroactive effect to the stock split.
Additionally, preference share purchase rights have been appropriately adjusted
to reflect the effects of the split.
4.
Allowance
for doubtful accounts
The
Company's allowance for doubtful accounts as of June 30, 2006 and 2005, and
December 31, 2005, was $7.3 million, $7.4 million and $8.0 million,
respectively.
5.
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 $19.4 million, $7.2 million and $24.7 million at June
30,
2006 and 2005, and December 31, 2005, respectively. The remainder of
natural gas in underground storage was included in other assets and was $43.2
million, $43.3 million, and $43.2 million at June 30, 2006 and 2005, and
December 31, 2005, respectively.
6.
Inventories
Inventories,
other than natural gas in underground storage for the Company’s regulated
operations, consisted primarily of aggregates held for resale of $93.1 million,
$84.2 million and $78.1 million; materials and supplies of $71.3 million,
$45.8
million and $48.7 million; and other inventories of $23.9 million, $21.7
million
and $20.7 million, as of June 30, 2006 and 2005, and December 31, 2005,
respectively. These inventories were stated at the lower of average cost
or
market value.
7.
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, 2006 and 2005, there were no
shares
excluded from the calculation of diluted earnings per share. Common stock
outstanding includes issued shares less shares held in treasury.
8.
|
Stock-based
compensation
|
On
January 1, 2006, the Company adopted SFAS No. 123 (revised). This
accounting standard revises SFAS No. 123 and requires entities to recognize
compensation expense in an amount equal to the grant-date fair value of
share-based payments granted to employees. SFAS No. 123 (revised) was adopted
using the modified prospective method, recognizing compensation expense for
all
awards granted after the date of adoption of the standard and for the unvested
portion of previously granted awards that remain outstanding at the date
of
adoption. In accordance with the modified prospective method, the Company’s
consolidated financial statements for prior periods have not been restated
to
reflect, and do not include, the impact of SFAS No. 123 (revised).
In
2003,
the Company adopted the fair value recognition provisions of SFAS No. 123
and
began expensing the fair market value of stock options for all awards granted
on
or after January 1, 2003. As permitted by SFAS No. 148, the Company accounted
for stock options granted prior to January 1, 2003, under APB Opinion No.
25. No compensation expense had been recognized for stock options granted
prior
to January 1, 2003, as the options granted had an exercise price equal to
the
market value of the underlying common stock on the date of the grant.
Compensation expense recognized for stock option awards granted on or after
January 1, 2003, for the six months ended June 30, 2005, was $4,000, net
of
income taxes of $3,000.
The
Company adopted SFAS No. 123 effective January 1, 2003, for newly granted
stock
options only. The following table illustrates the effect on earnings and
earnings per common share for the three and six months ended June 30, 2005,
as
if the Company had applied SFAS No. 123 and recognized compensation expense
for
all outstanding and unvested stock options based on the fair value at the
date
of grant:
|
|
Three
Months
Ended
June
30, 2005
|
|
Six
Months
Ended
June
30, 2005
|
|
|
|
(In
thousands, except per share amounts)
|
|
Earnings
on common stock, as reported
|
|
$
|
80,002
|
|
$
|
114,251
|
|
Stock-based
compensation expense included in reported earnings, net of related
tax
effects
|
|
|
---
|
|
|
4
|
|
Total
stock-based compensation expense determined under fair value method
for
all awards, net of related tax effects
|
|
|
(88
|
)
|
|
(125
|
)
|
Pro
forma earnings on common stock
|
|
$
|
79,914
|
|
$
|
114,130
|
|
Earnings
per common share - basic - as reported
|
|
$
|
.45
|
|
$
|
.65
|
|
Earnings
per common share - basic - pro forma
|
|
$
|
.45
|
|
$
|
.64
|
|
Earnings
per common share - diluted - as reported
|
|
$
|
.45
|
|
$
|
.64
|
|
Earnings
per common share - diluted - pro forma
|
|
$
|
.45
|
|
$
|
.64
|
|
Total
stock-based compensation expense for the three and six months ended June
30,
2006, was $1.4 million and $2.2 million, net of income taxes of $900,000
and
$1.4 million, respectively, including $71,000 and $142,000, net of income
taxes
of $45,000 and $90,000, respectively, related to stock option
awards.
As
of
June 30, 2006, total remaining unrecognized compensation expense related
to
stock-based compensation was approximately $7.2 million (before income taxes)
which will be amortized over a weighted-average period of 1.9
years.
The
Company is authorized to grant options, restricted stock and stock for up
to
17.1 million shares of common stock and has granted options, restricted stock
and stock on 6.7 million shares through June 30, 2006.
The
Company generally issues new shares of common stock to satisfy stock option
exercises, restricted stock, stock and performance share awards.
Stock
Options
The
Company has stock option plans for directors, key employees and employees.
The
Company has not granted stock options since 2003. Options granted to key
employees automatically vest after nine years, but the plan provides for
accelerated vesting based on the attainment of certain performance goals
or upon
a change in control of the Company, and expire 10 years after the date of
grant.
Options granted to directors and employees vest at the date of grant and
three
years after the date of grant, respectively, and expire 10 years after the
date of grant.
The
fair
value of each option outstanding was estimated on the date of grant using
the
Black-Scholes option pricing model.
A
summary
of the status of the stock option plans for the six months ended June 30,
2006,
was as follows:
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Weighted
|
|
Remaining
|
|
|
|
|
|
Average
|
|
Contractual
|
|
|
|
|
|
Exercise
|
|
Life
|
|
|
|
Shares
|
|
Price
|
|
In
Years
|
|
Outstanding
at beginning of period
|
|
|
2,786,973
|
|
$
|
12.99
|
|
|
|
|
Granted
|
|
|
---
|
|
|
---
|
|
|
|
|
Forfeited
|
|
|
(68,553
|
)
|
|
13.00
|
|
|
|
|
Exercised
|
|
|
(213,233
|
)
|
|
12.58
|
|
|
|
|
Outstanding
at end of period
|
|
|
2,505,187
|
|
|
13.02
|
|
|
4.3
|
|
Exercisable
at end of period
|
|
|
1,408,377
|
|
$
|
12.57
|
|
|
4.1
|
|
Summarized
information about stock options outstanding and exercisable as of June 30,
2006,
was as follows:
|
|
Options
Outstanding
|
|
Options
Exercisable
|
|
|
|
|
|
Remaining
|
|
Weighted
|
|
Aggregate
|
|
|
|
Weighted
|
|
Aggregate
|
|
Range
of
|
|
Number
|
|
Contractual
|
|
Average
|
|
Intrinsic
|
|
Number
|
|
Average
|
|
Intrinsic
|
|
Exercisable
|
|
Out-
|
|
Life
|
|
Exercise
|
|
Value
|
|
Exer-
|
|
Exercise
|
|
Value
|
|
Prices
|
|
standing
|
|
in
Years
|
|
Price
|
|
(000’s)
|
|
cisable
|
|
Price
|
|
(000’s)
|
|
$
7.28
- 8.00
|
|
|
10,125
|
|
|
1.0
|
|
$
|
7.28
|
|
$
|
173
|
|
|
10,125
|
|
$
|
7.28
|
|
$
|
173
|
|
8.01 - 11.00
|
|
|
315,024
|
|
|
1.9
|
|
|
9.58
|
|
|
4,672
|
|
|
312,132
|
|
|
9.58
|
|
|
4,629
|
|
11.01
- 14.00
|
|
|
1,925,293
|
|
|
4.7
|
|
|
13.18
|
|
|
21,621
|
|
|
994,417
|
|
|
13.19
|
|
|
11,156
|
|
14.01
- 17.13
|
|
|
254,745
|
|
|
4.7
|
|
|
16.32
|
|
|
2,061
|
|
|
91,703
|
|
|
16.54
|
|
|
722
|
|
Balance
at end of period
|
|
|
2,505,187
|
|
|
4.3
|
|
$
|
13.02
|
|
$
|
28,527
|
|
|
1,408,377
|
|
$
|
12.57
|
|
$
|
16,680
|
|
The
aggregate intrinsic value in the preceding table represents the total intrinsic
value (before income taxes), based on the Company’s stock price on June 30,
2006, which would have been received by the option holders had all option
holders exercised their options as of that date.
The
Company received cash of $1.0 million and $2.7 million from the exercise
of
stock options for the three and six months ended June 30, 2006, respectively.
The aggregate intrinsic value of options exercised during the three and six
months ended June 30, 2006, was $800,000 and $2.3 million,
respectively.
Restricted
Stock Awards
Prior
to
2002, the Company granted restricted stock awards under a long-term incentive
plan. The restricted stock awards granted vest at various times ranging from
one year to nine years from date of issuance, but certain grants may vest
early based upon the attainment of certain performance goals or upon a change
in
control of the Company. The grant-date fair value is the market price of
the
Company’s stock on the grant date.
A
summary
of the status of the restricted stock awards for the six months ended June
30,
2006, was as follows:
|
|
|
|
Weighted
|
|
|
|
Number
|
|
Average
|
|
|
|
of
|
|
Grant-Date
|
|
|
|
Shares
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
130,764
|
|
$
|
10.63
|
|
Granted
|
|
|
---
|
|
|
---
|
|
Vested
|
|
|
(77,106
|
)
|
|
8.82
|
|
Forfeited
|
|
|
(5,942
|
)
|
|
13.22
|
|
Nonvested
at end of period
|
|
|
47,716
|
|
$
|
13.22
|
|
The
fair
value of restricted stock awards that vested during the six months ended
June
30, 2006, was $1.8 million.
Stock
Awards
Nonemployee
directors may receive shares of common stock instead of cash in payment for
directors' fees under the nonemployee director stock compensation plan. There
were 40,500 shares with a fair value of $1.0 million issued under this plan
during the six months ended June 30, 2006.
Performance
Share Awards
Since
2003, key employees of the Company have been awarded performance share awards
each year. Entitlement to performance shares is based on the Company's total
shareholder return over designated performance periods as measured against
a
selected peer group. The grant-date fair value is the market price of the
Company’s stock on the grant date.
Target
grants of performance shares outstanding at June 30, 2006, were as
follows:
|
|
|
|
|
|
Grant
Date
|
|
Performance
Period
|
|
Target
Grant
of
Shares
|
|
February
2004
|
|
|
2004-2006
|
|
|
278,596
|
|
February
2005
|
|
|
2005-2007
|
|
|
283,512
|
|
February
2006
|
|
|
2006-2008
|
|
|
205,801
|
|
Participants
may earn additional performance shares if the Company's total shareholder
return
exceeds that of the selected peer group. Compensation expense assumes that
the
target payout will be achieved and is adjusted for subsequent changes in
the
expected outcome of performance-related conditions until the vesting date.
As a
result, the final value may vary according to the number of shares of Company
stock that are ultimately granted based on the performance criteria. The
fair
value of performance share awards that vested during the six months ended
June
30, 2006, was $2.2 million.
A
summary
of the status of the performance share awards for the six months ended June
30,
2006, was as follows:
|
|
|
|
Weighted
|
|
|
|
Number
|
|
Average
|
|
|
|
of
|
|
Grant-Date
|
|
|
|
Shares
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
634,275
|
|
$
|
16.31
|
|
Granted
|
|
|
216,970
|
|
|
22.91
|
|
Additional
performance shares earned
|
|
|
14,522
|
|
|
11.14
|
|
Vested
|
|
|
(95,792
|
)
|
|
11.14
|
|
Forfeited
|
|
|
(2,066
|
)
|
|
18.37
|
|
Nonvested
at end of period
|
|
|
767,909
|
|
$
|
18.72
|
|
9.
Cash
flow information
Cash
expenditures for interest and income taxes were as follows:
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
|
$27,988
|
|
|
$23,184
|
|
Income
taxes
|
|
|
$78,382
|
|
|
$54,650
|
|
10.
New
accounting standards
SFAS
No. 123 (revised) In
December 2004, the FASB issued SFAS No. 123 (revised). This accounting standard
revises SFAS No. 123 and requires entities to recognize compensation expense
in
an amount equal to the grant-date fair value of share-based payments granted
to
employees. SFAS No. 123 (revised) was effective for the Company on January
1,
2006. As of the required effective date, the Company applied SFAS No. 123
(revised) using the modified prospective method, recognizing compensation
expense for all awards granted after the date of adoption of SFAS No. 123
(revised) and for the unvested portion of previously granted awards that
remain
outstanding at the date of adoption. The Company used the Black-Scholes
option-pricing model to calculate the fair value of stock options. For more
information on the adoption of SFAS No. 123 (revised), see Note 8.
EITF
No. 04-6
In March
2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires that stripping
costs during the production phase of a mine be treated as a variable inventory
production cost when incurred. EITF No. 04-6 was effective for the Company
on
January 1, 2006. The adoption of EITF No. 04-6 did not have a material effect
on
the Company’s financial position or results of operations.
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 is effective for the Company on January
1,
2007. The Company is evaluating the effects of the adoption of FIN
48.
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,
|
|
|
2006
|
|
2005
|
|
|
(In
thousands)
|
|
Net
income
|
|
$71,442
|
|
|
$80,173
|
|
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 $4,051 and $1,225 in 2006 and 2005, respectively
|
|
6,471
|
|
|
1,957
|
|
Less:
Reclassification adjustment for gain (loss) on derivative instruments
included in net income, net of tax of $1,033 and $4,522 in 2006
and 2005,
respectively
|
|
1,650
|
|
|
(7,223
|
)
|
Net
unrealized gain on derivative instruments qualifying as
hedges
|
|
4,821
|
|
|
9,180
|
|
Foreign
currency translation adjustment
|
|
(2,176
|
)
|
|
(925
|
)
|
|
|
2,645
|
|
|
8,255
|
|
Comprehensive
income
|
|
$74,087
|
|
|
$88,428
|
|
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
|
|
|
$
|
124,689
|
|
$
|
114,593
|
|
Other
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges:
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gain (loss) on derivative instruments arising during
the
period, net of tax of $17,652 and $8,467 in 2006 and 2005, respectively
|
|
|
|
|
|
28,197
|
|
|
(13,525
|
)
|
Less: Reclassification adjustment for loss on derivative instruments
included in net income, net of tax of $4,254 and $1,057 in 2006
and 2005,
respectively
|
|
|
|
|
|
(6,796
|
)
|
|
(1,688
|
)
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
|
|
|
|
34,993
|
|
|
(11,837
|
)
|
Foreign
currency translation adjustment
|
|
|
|
|
|
(2,177
|
)
|
|
(1,019
|
)
|
|
|
|
|
|
|
32,816
|
|
|
(12,856
|
)
|
Comprehensive
income
|
|
|
|
|
$
|
157,505
|
|
$
|
101,737
|
|
12.
Equity
method investments
The
Company has equity method investments including a 49.99-percent ownership
interest in Carib Power and a 50-percent ownership interest in Hartwell.
Carib
Power, through a wholly owned subsidiary, owns a 225-MW natural gas-fired
electric generating facility in Trinidad and Tobago. Hartwell owns a 310-MW
natural gas-fired electric generating facility near Hartwell, Georgia. The
Company assesses its equity method investments for impairment whenever events
or
changes in circumstances indicate that the related carrying values may not
be
recoverable. None of the Company’s equity method investments have been impaired
and, accordingly, no impairment losses have been recorded in the accompanying
consolidated financial statements or related equity method investment balances.
In
June
2005, the Company completed the sale of its 49 percent interest in MPX to
Petrobras, the Brazilian state-controlled energy company. The Company realized
a
gain of $15.6 million from the sale in the second quarter of 2005. In 2005,
the
Termoceara Generating Facility was accounted for as an asset held for sale
and,
as a result, no depreciation, depletion and amortization expense was recorded
in
2005.
At
June
30, 2006 and 2005, and December 31, 2005, the Company’s equity method
investments, including Carib Power and Hartwell, had total assets of $228.9
million, $243.6 million and $231.9 million, respectively, and long-term debt
of
$149.5 million, $159.6 million and $154.8 million, respectively. The Company’s
investment in its equity method investments, including the Trinity and Hartwell
Generating Facilities, was approximately $50.1 million, $43.4 million and
$41.8
million, including undistributed earnings of $6.5 million, $2.6 million and
$3.5
million, at June 30, 2006 and 2005, and December 31, 2005, 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, 2006
|
|
2006
|
|
the
Year*
|
|
2006
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
80,970
|
|
|
5,981
|
|
|
86,951
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
6,109
|
|
|
139,373
|
|
Independent
power production
|
|
|
11,167
|
|
|
---
|
|
|
11,167
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
230,865
|
|
$
|
12,090
|
|
$
|
242,955
|
|
|
|
Balance
|
|
Goodwill
|
|
Balance
|
|
|
|
as
of
|
|
Acquired
|
|
as
of
|
|
Six
Months Ended
|
|
January
1,
|
|
During
|
|
June
30,
|
|
June
30, 2005
|
|
2005
|
|
the
Year*
|
|
2005
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
62,632
|
|
|
12,102
|
|
|
74,734
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
120,452
|
|
|
3,155
|
|
|
123,607
|
|
Independent
power production
|
|
|
11,195
|
|
|
(28
|
)
|
|
11,167
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
199,743
|
|
$
|
15,229
|
|
$
|
214,972
|
|
|
|
Balance
|
|
Goodwill
|
|
Balance
|
|
|
|
as
of
|
|
Acquired
|
|
as
of
|
|
Year
Ended
|
|
January
1,
|
|
During
|
|
December 31,
|
|
December
31, 2005
|
|
2005
|
|
the
Year*
|
|
2005
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
services
|
|
|
62,632
|
|
|
18,338
|
|
|
80,970
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Construction
materials and mining
|
|
|
120,452
|
|
|
12,812
|
|
|
133,264
|
|
Independent
power production
|
|
|
11,195
|
|
|
(28
|
)
|
|
11,167
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
Total
|
|
$
|
199,743
|
|
$
|
31,122
|
|
$
|
230,865
|
|
* Includes
purchase price adjustments that were not material related to acquisitions
in a
prior period.
Other
intangible assets were as follows:
|
|
June
30,
2006
|
|
June
30,
2005
|
|
December
31,
2005
|
|
|
|
(In
thousands)
|
|
Amortizable
intangible assets:
|
|
|
|
|
|
|
|
Acquired
contracts
|
|
$
|
20,650
|
|
$
|
18,707
|
|
|
|
|
$
|
18,065
|
|
Accumulated
amortization
|
|
|
(9,196
|
)
|
|
(6,519
|
)
|
|
|
|
|
(9,458
|
)
|
|
|
|
11,454
|
|
|
12,188
|
|
|
|
|
|
8,607
|
|
Noncompete
agreements
|
|
|
11,984
|
|
|
11,784
|
|
|
|
|
|
11,784
|
|
Accumulated
amortization
|
|
|
(8,900
|
)
|
|
(8,310
|
)
|
|
|
|
|
(8,557
|
)
|
|
|
|
3,084
|
|
|
3,474
|
|
|
|
|
|
3,227
|
|
Other
|
|
|
12,358
|
|
|
14,698
|
|
|
|
|
|
7,914
|
|
Accumulated
amortization
|
|
|
(1,870
|
)
|
|
(914
|
)
|
|
|
|
|
(1,213
|
)
|
|
|
|
10,488
|
|
|
13,784
|
|
|
|
|
|
6,701
|
|
Unamortizable
intangible assets
|
|
|
524
|
|
|
851
|
|
|
|
|
|
524
|
|
Total
|
|
$
|
25,550
|
|
$
|
30,297
|
|
|
|
|
$
|
19,059
|
|
The
unamortizable intangible assets 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.
The
unamortizable intangible asset will be eliminated or adjusted as necessary
upon
a new determination of the amount of additional liability.
Amortization
expense for amortizable intangible assets for the three and six months ended
June 30, 2006, was $1.6 million and $2.8 million, respectively. Amortization
expense for the three and six months ended June 30, 2005, and for the year
ended
December 31, 2005, was $1.2 million, $2.1 million and $5.5 million,
respectively. Estimated amortization expense for amortizable intangible assets
is $5.4 million in 2006, $5.7 million in 2007, $4.7 million in 2008, $3.7
million in 2009, $3.1 million in 2010 and $5.2 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. The following information should be read in conjunction with Notes
1
and 5 in the Company's Notes to Consolidated Financial Statements in the
2005
Annual Report.
Historically,
Fidelity has held derivative instruments designated as cash flow hedging
instruments. However, in the second quarter of 2006, the oil collar agreements
became ineffective and no longer qualify for hedge accounting, as discussed
below. At June 30, 2006, Fidelity held derivative instruments designated
as cash
flow hedging instruments as well as derivative instruments that did not qualify
for hedge accounting.
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 natural gas and oil price swap and collar agreements was designated as
a
hedge of the forecasted sale of natural gas and oil 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 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, 2005, the amount of hedge ineffectiveness
was immaterial. However, in the second quarter of 2006, the oil collar
agreements became ineffective and no longer qualify 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, 2006 and 2005, 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, 2006, 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 $7.5 million (after tax) will be reclassified from accumulated
other comprehensive income (loss) into earnings, subject to changes in natural
gas and oil market prices, as the hedged transactions affect
earnings.
15.
Business
segment data
The
Company’s reportable segments are those that are based on the Company’s method
of internal reporting, which generally segregates the strategic business
units
due to differences in products, services and regulation. The vast majority
of
the Company’s operations are located within the United States. The Company also
has investments in foreign countries, which largely consist of investments
in
natural resource-based projects.
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 electrical line construction;
pipeline construction; inside electrical wiring, cabling and mechanical
services; 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, including cable and pipeline
magnetization and locating.
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 and other value-added products, as well as performs
integrated construction services, in the central and western United States
and
in Alaska and Hawaii.
The
independent power production segment owns, builds and operates electric
generating facilities in the United States and has investments in domestic
and
international natural resource-based projects. Electric capacity and energy
produced at its power plants primarily are sold under mid- and long-term
contracts to nonaffiliated entities.
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 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 in
the Company’s Notes to Consolidated Financial Statements in the 2005 Annual
Report. Information on the Company’s businesses was as follows:
|
|
|
|
Inter-
|
|
|
|
Three
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
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
|
|
|
84,501
|
|
|
18,568
|
|
|
5,580
|
|
|
|
|
171,221
|
|
|
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
|
|
|
11,716
|
|
|
---
|
|
|
1,504
|
|
Other
|
|
|
---
|
|
|
2,318
|
|
|
239
|
|
|
|
|
802,562
|
|
|
53,660
|
|
|
67,712
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(72,228
|
)
|
|
---
|
|
Total
|
|
$
|
973,783
|
|
$
|
---
|
|
$
|
71,271
|
|
|
|
|
|
Inter-
|
|
|
|
|
|
External
|
|
segment
|
|
Earnings
|
|
Three
Months
|
|
Operating
|
|
Operating
|
|
on
Common
|
|
Ended
June 30, 2005
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
41,052
|
|
$
|
---
|
|
$
|
1,755
|
|
Natural
gas distribution
|
|
|
54,691
|
|
|
---
|
|
|
(1,283
|
)
|
Pipeline
and energy services
|
|
|
86,366
|
|
|
15,055
|
|
|
8,737
|
|
|
|
|
182,109
|
|
|
15,055
|
|
|
9,209
|
|
Construction
services
|
|
|
136,911
|
|
|
(19
|
)
|
|
3,659
|
|
Natural
gas and oil production
|
|
|
43,487
|
|
|
54,255
|
|
|
29,949
|
|
Construction
materials and mining
|
|
|
394,015
|
|
|
---
|
|
|
18,421
|
|
Independent
power production
|
|
|
13,650
|
|
|
---
|
|
|
18,582
|
|
Other
|
|
|
---
|
|
|
1,367
|
|
|
182
|
|
|
|
|
588,063
|
|
|
55,603
|
|
|
70,793
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(70,658
|
)
|
|
---
|
|
Total
|
|
$
|
770,172
|
|
$
|
---
|
|
$
|
80,002
|
|
|
|
|
|
Inter-
|
|
|
|
Six
Months
|
|
External
Operating
|
|
segment
Operating
|
|
Earnings
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
|
|
|
178,753
|
|
|
51,374
|
|
|
10,149
|
|
|
|
|
462,782
|
|
|
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
|
|
|
22,982
|
|
|
---
|
|
|
2,846
|
|
Other
|
|
|
---
|
|
|
4,087
|
|
|
502
|
|
|
|
|
1,326,295
|
|
|
128,831
|
|
|
107,099
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(180,205
|
)
|
|
---
|
|
Total
|
|
$
|
1,789,077
|
|
$
|
---
|
|
$
|
124,346
|
|
|
|
|
|
Inter-
|
|
|
|
|
|
External
|
|
segment
|
|
Earnings
|
|
Six
Months
|
|
Operating
|
|
Operating
|
|
on
Common
|
|
Ended
June 30, 2005
|
|
Revenues
|
|
Revenues
|
|
Stock
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
85,371
|
|
$
|
---
|
|
$
|
4,888
|
|
Natural
gas distribution
|
|
|
199,665
|
|
|
---
|
|
|
3,539
|
|
Pipeline
and energy services
|
|
|
152,445
|
|
|
41,803
|
|
|
11,963
|
|
|
|
|
437,481
|
|
|
41,803
|
|
|
20,390
|
|
Construction
services
|
|
|
250,621
|
|
|
132
|
|
|
5,617
|
|
Natural
gas and oil production
|
|
|
81,797
|
|
|
103,025
|
|
|
58,754
|
|
Construction
materials and mining
|
|
|
581,102
|
|
|
7
|
|
|
9,885
|
|
Independent
power production
|
|
|
23,466
|
|
|
---
|
|
|
19,339
|
|
Other
|
|
|
---
|
|
|
2,735
|
|
|
266
|
|
|
|
|
936,986
|
|
|
105,899
|
|
|
93,861
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(147,702
|
)
|
|
---
|
|
Total
|
|
$
|
1,374,467
|
|
$
|
---
|
|
$
|
114,251
|
|
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.
16.
Acquisitions
During
the first six months of 2006, the Company acquired a construction services
business in Nevada, natural gas and oil properties in Wyoming, construction
materials and mining businesses in Washington, and a natural gas-fired electric
generating facility in California at the independent power production segment,
none of which was material. The total purchase consideration for these
businesses and properties and purchase price adjustments with respect to
certain
other acquisitions made prior to 2006, consisting of the Company's common
stock
and cash, was $122.7 million.
The
above
acquisitions were accounted for under the purchase method of accounting and,
accordingly, the acquired assets and liabilities assumed have been preliminarily
recorded at their respective fair values as of the date of acquisition. On
certain of the above acquisitions, final fair market values are pending the
completion of the review of the relevant assets, liabilities and issues
identified as of the acquisition date. The results of operations of the acquired
businesses and properties are included in the financial statements since
the
date of each acquisition. Pro forma financial amounts reflecting the effects
of
the above acquisitions are not presented, as such acquisitions were not material
to the Company's financial position or results of operations.
17.
Employee
benefit plans
The
Company has noncontributory defined benefit pension plans and other
postretirement benefit plans for certain eligible employees. Components of
net
periodic benefit cost for the Company's pension and other postretirement
benefit
plans were as follows:
Three
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
Ended
June 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
2,301
|
|
|
|
|
$
|
2,121
|
|
|
|
|
$
|
472
|
|
|
|
|
$
|
546
|
|
Interest
cost
|
|
|
4,074
|
|
|
|
|
|
4,152
|
|
|
|
|
|
928
|
|
|
|
|
|
1,039
|
|
Expected
return on assets
|
|
|
(4,718
|
)
|
|
|
|
|
(5,063
|
)
|
|
|
|
|
(926
|
)
|
|
|
|
|
(1,042
|
)
|
Amortization
of prior service cost
|
|
|
257
|
|
|
|
|
|
256
|
|
|
|
|
|
12
|
|
|
|
|
|
---
|
|
Recognized
net actuarial (gain) loss
|
|
|
509
|
|
|
|
|
|
483
|
|
|
|
|
|
(85
|
)
|
|
|
|
|
(38
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
(1
|
)
|
|
|
|
|
(11
|
)
|
|
|
|
|
531
|
|
|
|
|
|
525
|
|
Net
periodic benefit cost
|
|
|
2,422
|
|
|
|
|
|
1,938
|
|
|
|
|
|
932
|
|
|
|
|
|
1,030
|
|
Less
amount capitalized
|
|
|
225
|
|
|
|
|
|
185
|
|
|
|
|
|
79
|
|
|
|
|
|
115
|
|
Net
periodic benefit cost
|
|
$
|
2,197
|
|
|
|
|
$
|
1,753
|
|
|
|
|
$
|
853
|
|
|
|
|
$
|
915
|
|
Six
Months
|
|
Pension
Benefits
|
|
Other
Postretirement
Benefits
|
|
Ended
June 30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
4,602
|
|
|
|
|
$
|
4,168
|
|
|
|
|
$
|
943
|
|
$
|
1,031
|
|
Interest
cost
|
|
|
8,148
|
|
|
|
|
|
8,308
|
|
|
|
|
|
1,857
|
|
|
2,136
|
|
Expected
return on assets
|
|
|
(9,436
|
)
|
|
|
|
|
(9,973
|
)
|
|
|
|
|
(1,851
|
)
|
|
(2,025
|
)
|
Amortization
of prior service cost
|
|
|
513
|
|
|
|
|
|
512
|
|
|
|
|
|
23
|
|
|
---
|
|
Recognized
net actuarial (gain) loss
|
|
|
1,018
|
|
|
|
|
|
692
|
|
|
|
|
|
(169
|
)
|
|
(77
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
(2
|
)
|
|
|
|
|
(22
|
)
|
|
|
|
|
1,062
|
|
|
1,063
|
|
Net
periodic benefit cost
|
|
|
4,843
|
|
|
|
|
|
3,685
|
|
|
|
|
|
1,865
|
|
|
2,128
|
|
Less
amount capitalized
|
|
|
381
|
|
|
|
|
|
357
|
|
|
|
|
|
125
|
|
|
206
|
|
Net
periodic benefit cost
|
|
$
|
4,462
|
|
|
|
|
$
|
3,328
|
|
|
|
|
$
|
1,740
|
|
$
|
1,922
|
|
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, 2006,
was
$1.9 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, 2005, was
$1.4
million and $3.3 million, respectively.
18.
Regulatory
matters and revenues subject to refund
In
September 2004, Great Plains filed a natural gas rate application with the
MNPUC
requesting a revenue increase of $1.4 million annually, or approximately
4
percent. An interim increase of $1.4 million annually was effective January
10,
2005, subject to refund. The final order in the amount of $481,000 annually,
or
1.3 percent, was issued on May 1, 2006. A compliance filing will be submitted
in
August 2006 for MNPUC approval. Great Plains has adequately provided a liability
for the revenue subject to refund.
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. In April 2005, the FERC issued its Order
on
Compliance Filing and Motion for Refunds. In this Order, the FERC approved
Williston Basin’s refund rates and established rates to be effective April 19,
2005. Williston Basin made its compliance filing complying with the requirements
of this Order regarding rates and issued refunds totaling approximately $18.5
million to its customers in May 2005. As a result of the Order, Williston
Basin
recorded a $5.0 million (after tax) benefit in the second quarter of 2005
from
the resolution of the rate proceeding which included the reversal of a portion
of the liability it had previously established for this regulatory proceeding.
In June 2005, Williston Basin appealed to the D.C. Appeals Court certain
issues
addressed by the FERC’s Order on Initial Decision dated July 2003 and its Order
on Rehearing dated May 2004 concerning determinations associated with cost
of
service and volumes used in allocating costs and designing rates. Those matters
are pending resolution by the D.C. Appeals Court. A provision has been
established for certain issues pending before the D.C. Appeals Court. The
Company believes that the provision is adequate based on its assessment of
the
ultimate outcome of the proceeding.
In
May
2004, the FERC remanded issues regarding certain service and annual demand
quantity restrictions to an ALJ for resolution. In November 2005, the FERC
issued an Order on Initial Decision affirming the ALJ’s Initial Decision
regarding the service and annual demand quantity restrictions. On April 20,
2006, the FERC issued an Order on Rehearing denying Williston Basin’s Request
for Rehearing of the FERC’s November 2005 Order. On April 25, 2006, Williston
Basin appealed to the D.C. Appeals Court certain issues addressed by the
FERC’s
Order on Initial Decision dated November 2005 and its Order on Rehearing
issued
April 20, 2006, concerning the service and annual demand quantity restrictions.
Those matters are pending resolution by the D.C. Appeals Court.
19.
Contingencies
Litigation
Royalties
Case In
June
1997, Grynberg filed suit under the Federal False Claims Act against Williston
Basin and Montana-Dakota. Grynberg also filed more than 70 similar suits
against
natural gas transmission companies and producers, gatherers and processors
of
natural gas. Grynberg, acting on behalf of the United States under the Federal
False Claims Act, 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
June
2004, following preliminary discovery, Williston Basin and Montana-Dakota
joined
with other defendants and filed a Motion to Dismiss on the ground that the
information upon which Grynberg based his complaint was publicly disclosed
prior
to the filing of his complaint and further, that he is not the original source
of such information. The Motion to Dismiss was heard in March 2005 by the
Special Master appointed by the Wyoming Federal District Court. The Special
Master, in his Written Report dated May 2005, recommended that the lawsuit
be
dismissed against certain defendants, including Williston Basin and
Montana-Dakota. A hearing on the adoption of the Written Report was held
in
December 2005, before the Wyoming Federal District Court.
In
the
event the Motion to Dismiss is not granted, it is expected that further
discovery will follow. Williston Basin and Montana-Dakota believe Grynberg
will
not prevail in the suit or recover damages from Williston Basin and/or
Montana-Dakota because insufficient facts exist to support the allegations.
Williston Basin and Montana-Dakota believe Grynberg’s claims are without merit
and intend to vigorously contest this suit.
Grynberg
has not specified the amount he seeks to recover. Williston Basin and
Montana-Dakota are unable to estimate their potential exposure and will be
unable to do so until discovery is completed.
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
coalbed natural gas 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 April 2006 by a number of environmental organizations,
including the NPRC and the Montana Environmental Information Center, as well
as
the Tongue River Water Users' Association and the Northern Cheyenne Tribe.
Portions of two 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 requirements and the lawsuits seek injunctive relief,
invalidation of various permits and unspecified damages.
In
suits
filed in the Montana Federal District Court, the NPRC and the Northern Cheyenne
Tribe asserted that further development by Fidelity and others of coalbed
natural gas in Montana should be enjoined until the BLM completes a SEIS.
The
Montana Federal District Court, in February 2005, entered a ruling requiring
the
BLM to complete a SEIS. The Montana Federal District Court later entered
an
order that would have allowed limited coalbed natural gas development in
the
Powder River Basin in Montana pending the BLM's preparation of the SEIS.
The
plaintiffs appealed the decision to the Ninth Circuit. The Montana Federal
District Court declined to enter an injunction requested by the NPRC and
the
Northern Cheyenne Tribe that would have enjoined development pending the
appeal.
In late May 2005, the Ninth Circuit granted the request of the NPRC and the
Northern Cheyenne Tribe and, pending further order from the Ninth Circuit,
enjoined the BLM from approving any new coalbed natural gas development projects
in the Powder River Basin in Montana. That court also enjoined Fidelity from
drilling any additional federally permitted wells in its Montana Coal Creek
Project and from constructing infrastructure to produce and transport coalbed
natural gas 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
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. The NPRC also asserted that the Environmental
Assessment that supported the BLM's prior approval of the Badger Hills Project
was invalid. 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 NHPA and a further environmental analysis under
NEPA.
Fidelity has 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 based on a stipulation between
the parties to the Northern Cheyenne Tribe action that production from existing
wells in Fidelity’s Badger Hills Project may continue pending preparation of a
revised environmental analysis. In December 2005, Fidelity filed a Notice
of
Appeal 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.
The
NPRC
filed a petition with the BER and the BER initiated related rulemaking
proceedings to create rules that would, if promulgated, require re-injection
of
water produced in connection with coalbed natural gas operations and treatment
of such water in the event re-injection is not feasible and amend the
non-degradation policy in connection with coalbed natural gas development
to
include additional limitations on factors deemed harmful, thereby restricting
discharges even further than under the previous standards. On March 23, 2006,
the BER issued its decision on the NPRC’s rulemaking petition. The BER rejected
the proposed requirement of re-injection of water produced in connection
with
coalbed natural gas 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 coalbed natural gas
operations at least through the expiration of the permits in March 2011.
However, these permits are now being challenged in Montana state court by
the
Northern Cheyenne Tribe. Specifically,
on April 3, 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 environmental impact statement and that it failed to
consider other alternatives to the issuance of the permits. Both Fidelity
and
the NPRC have filed motions to intervene in this proceeding. Fidelity has
asserted that the Northern Cheyenne Tribe’s complaint should be dismissed with
prejudice, that Fidelity’s discharge of water pursuant to its two permits is its
primary means for managing coalbed natural gas produced water and that, if
its
permits are set aside, Fidelity’s coalbed natural gas operations in Montana
could be significantly and adversely affected.
In
a
related proceeding, on July 25, 2006, Fidelity filed a motion to intervene
in a
lawsuit filed in Montana state court in Big Horn County by other producers.
The
lawsuit challenges the BER’s 2006 rulemaking, which amended the nondegradation
policy, as well as the BER’s 2003 rulemaking procedure which first set numeric
limits for water produced in connection with coalbed natural gas
operations.
Fidelity
will continue vigorously defending its interests in all coalbed-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 effect on Fidelity’s existing
coalbed natural gas operations and/or the future development of this resource
in
the affected regions.
Electric
Operations Montana-Dakota
has joined with two electric generators in appealing a finding by the ND
Health
Department in September 2003 that the ND Health Department 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 have
been
stayed pending discussions with the EPA, the ND Health Department and the
other
electric generators. The Company cannot predict the outcome of the ND Health
Department matter or its ultimate impact on its operations.
Natural
Gas Storage Williston
Basin filed suit in Montana Federal District Court on January 27, 2006, seeking
to recover unspecified damages from Anadarko and its wholly owned subsidiary,
Howell, and to enjoin Anadarko’s and Howell’s present and future operations in
and near Williston Basin’s Elk Basin Storage Reservoir located in Wyoming and
Montana. Based on relevant information, including reservoir and well pressure
data, Williston Basin believes that Elk Basin Storage Reservoir pressures
have
decreased and that quantities of natural gas have been diverted as a result
of
Anadarko’s and Howell’s drilling and production activities in areas within and
near the boundaries of Williston Basin’s Elk Basin Storage Reservoir. Williston
Basin is seeking not only to recover damages for the gas that has been diverted,
but to prevent further drainage of its storage reservoir. The Montana
Federal District Court entered an Order on July 14, 2006, dismissing the
case
for lack of subject matter jurisdiction. Williston Basin filed a Notice of
Appeal to the Ninth Circuit on July 31, 2006. In related litigation, Anadarko
filed suit in Wyoming state district court against Williston Basin asserting
that it is entitled to produce any gas that might escape from Williston Basin’s
storage reservoir. 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 or estimate the size of any potential
recovery.
The
Company is also 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 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.
The
Company believes it is not probable that it will incur any material
environmental remediation costs or damages in relation to the above
administrative action.
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 from approximately two 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.
In
addition, WBI Holdings has guaranteed certain of Fidelity’s natural gas and oil
price swap and collar agreement obligations. Fidelity's obligations at June
30,
2006, were approximately $1.1 million. There is no fixed maximum amount
guaranteed in relation to the natural gas and oil price swap and collar
agreements, as the amount of the obligation is dependent upon natural gas
and
oil commodity prices. The amount of hedging activity entered into by the
subsidiary is limited by corporate policy. The guarantees of the natural
gas and
oil price swap and collar agreements at June 30, 2006, expire in 2006 and
2007;
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 reflected
on
the Consolidated Balance Sheet at June 30, 2006. 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 natural gas transportation and sales agreements, electric
power
supply agreements, construction contracts, a conditional purchase agreement
and
certain other guarantees. At June 30, 2006, the fixed maximum amounts guaranteed
under these agreements aggregated $181.9 million. The amounts of scheduled
expiration of the maximum amounts guaranteed under these agreements aggregate
$1.4 million in 2006; $102.3 million in 2007; $4.0 million in 2008; $2.7
million
in 2009; $30.1 million in 2010; $23.0 million in 2011; $12.0 million in 2012;
$1.9 million in 2028; $500,000, 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,
2006,
has no scheduled maturity date. The amount outstanding by subsidiaries of
the
Company under the above guarantees was $700,000 and was reflected on the
Consolidated Balance Sheet at June 30, 2006. 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, 2006, the fixed maximum amounts guaranteed under these
letters of credit aggregated $43.4 million. In 2006 and 2007, $12.3 million
and
$31.1 million, respectively, of letters of credit are scheduled to expire.
There
were no amounts outstanding under the above letters of credit at June 30,
2006.
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, 2006, the fixed maximum
amounts guaranteed under these agreements aggregated $22.9 million. Scheduled
expiration of the maximum amounts guaranteed under these agreements aggregate
$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
$1.5 million, which was not reflected on the Consolidated Balance Sheet at
June
30, 2006, because these intercompany transactions are eliminated in
consolidation.
In
addition, Centennial has issued guarantees to third parties related to the
Company’s routine purchase of maintenance items 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 or lease
obligations, Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the Company for these
maintenance items were reflected on the Consolidated Balance Sheet at June
30,
2006.
As
of
June 30, 2006, Centennial was contingently liable for the performance of
certain
of its subsidiaries under approximately $558 million of surety bonds. These
bonds are principally for construction contracts and reclamation obligations
of
these subsidiaries entered into in the normal course of business. Centennial
indemnifies the respective surety bond companies against any exposure under
the
bonds. The purpose of Centennial’s indemnification is to allow the subsidiaries
to obtain bonding at competitive rates. In the event a subsidiary of the
Company
does not fulfill its obligations in relation to its bonded contract or
obligation, Centennial may be required to make payments under its
indemnification. A large portion of these contingent commitments 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. The surety bonds
were not reflected on the Consolidated Balance Sheet.
20.
Related
party transactions
In
2004,
Bitter Creek entered into two natural gas gathering agreements with Nance
Petroleum. Robert L. Nance, an executive officer and shareholder of St. Mary,
is
also a member of the Board of Directors of the Company. The natural gas
gathering agreements with Nance Petroleum were effective upon completion
of
certain high and low pressure gathering facilities, which occurred in
mid-December 2004. Bitter Creek's capital expenditures related to the completion
of the gathering lines and the expansion of its gathering facilities to
accommodate the natural gas gathering agreements was $28,000 for the six
months
ended June 30, 2006, and were $1.1 million and $2.1 million for the three
and
six months ended June 30, 2005, respectively, and are estimated for the next
three years to be $500,000 in 2006, $3.3 million in 2007 and $2.2 million
in
2008. The natural gas gathering agreements are each for a term of 15 years
and
month-to-month thereafter. Bitter Creek's revenues from these contracts were
$403,000 and $789,000 for the three and six months ended June 30, 2006,
respectively, and were $287,000 and $539,000 for the three and six months
ended
June 30, 2005, respectively. Estimated revenues from these contracts for
the
next three years are $1.8 million in 2006, $2.1 million in 2007 and $3.2
million
in 2008. The amount due from Nance Petroleum at June 30, 2006, was
$136,000.
In
2005,
Montana-Dakota entered into agreements to purchase natural gas from Nance
Petroleum through March 31, 2006. Montana-Dakota’s expenses under these
agreements through March 31, 2006, were $1.9 million. There were no amounts
due
to Nance Petroleum at June 30, 2006.
In
2005,
Fidelity entered into an agreement for the purchase of an ownership interest
in
a natural gas and oil property with a third party whereunder it became a
party
to a joint operating agreement in which St. Mary is the operator of the
property. St. Mary receives an overhead fee as operator of this property.
The
Company recorded its proportionate share of capital costs allocable to its
ownership interest in the related property, which were not material to
Fidelity.
21.
Subsequent
event
On
July
8, 2006, the Company entered into a definitive merger agreement to acquire
Cascade, subject to approval of Cascade’s shareholders and various regulatory
authorities, as well as antitrust clearance under the Hart-Scott-Rodino Act,
and
the satisfaction of other customary closing conditions. Regulatory approvals
are
anticipated to be obtained by mid-year 2007. The total value of the transaction,
including the assumption of certain indebtedness, is approximately $475 million.
Cascade’s natural gas service areas are concentrated in western and south
central Washington and south central and eastern Oregon.
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
returns on invested capital
|
The
Company has capabilities to fund its growth and operations through various
sources, including internally generated funds, commercial paper facilities
and the
issuance from time to time of debt securities and the Company’s equity
securities. For
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 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 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 cost controls and retention
of key
personnel are ongoing challenges.
Pipeline
and Energy Services
Strategy
Leverage
the segment’s existing expertise in energy infrastructure, services and
technologies 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;
incremental
expansion of the capacity of the Grasslands Pipeline to allow customers
access
to more liquid and potentially higher-priced markets; and pursuit of new
markets
for the segment’s locating and tracking technology business.
Challenges
Energy
price volatility; natural gas basis differentials; regulatory requirements;
recruitment and retention of a skilled workforce; increased competition
from
other natural
gas pipeline
and
gathering companies;
and
establishing and enhancing customer relationships at the location and tracking
technology business.
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
and industry specialty services; and increased competition from many of
the
larger natural
gas and oil companies.
Construction
Materials and Mining
Strategy
Focus on
high growth regional markets located near major transportation corridors
and
metropolitan areas; enhance profitability through vertical integration
of the
segment’s operations; and continue growth through acquisitions. 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 in the higher-margin materials business (rock, sand,
gravel
and related products), complementing the Company’s ongoing efforts to increase
margin by building a more profitable backlog of business and carefully
managing
costs
through
implementation of a variety of continuous improvement programs, including
centralized purchasing and negotiation of contract price escalation
provisions
and
the
utilization of national purchasing accounts.
Challenges
Price
volatility with respect to, and availability of, raw materials such as
steel and
cement; petroleum price volatility; recruitment and retention of a skilled
workforce; and increased competition from national and international
construction materials companies. In particular, increases in energy prices
can
affect the profitability of construction jobs.
Independent
Power Production
Strategy
Achieve
growth through the acquisition, construction and operation of domestic
nonregulated electric generation facilities and through international
investments in the energy and natural resources sectors. The segment continues
to seek projects with mid- to long-term agreements with financially stable
customers, while maintaining diversity in customers, geographic markets
and fuel
source.
Challenges
Overall
business challenges for this segment include: the risks and uncertainties
associated with the construction, startup and operation of power plant
facilities; changes in energy market pricing; increased competition from
other
independent power producers;
and
fluctuations in the value of foreign currency 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 2005 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,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Electric
|
|
$
|
.5
|
|
$
|
1.8
|
|
$
|
4.3
|
|
$4.9
|
Natural
gas distribution
|
|
|
(2.5
|
)
|
|
(1.3
|
)
|
|
2.8
|
|
3.5
|
Construction
services
|
|
|
9.7
|
|
|
3.7
|
|
|
15.1
|
|
5.6
|
Pipeline
and energy services
|
|
|
5.6
|
|
|
8.7
|
|
|
10.2
|
|
12.0
|
Natural
gas and oil production
|
|
|
31.0
|
|
|
29.9
|
|
|
72.2
|
|
58.8
|
Construction
materials and mining
|
|
|
25.3
|
|
|
18.4
|
|
|
16.4
|
|
9.9
|
Independent
power production
|
|
|
1.5
|
|
|
18.6
|
|
|
2.8
|
|
19.3
|
Other
|
|
|
.2
|
|
|
.2
|
|
|
.5
|
|
.3
|
Earnings
on common stock
|
|
$
|
71.3
|
|
$
|
80.0
|
|
$
|
124.3
|
|
$114.3
|
Earnings
per common share - basic
|
|
$
|
.40
|
|
$
|
.45
|
|
$
|
.69
|
|
$.65
|
Earnings
per common share - diluted
|
|
$
|
.39
|
|
$
|
.45
|
|
$
|
.69
|
|
$.64
|
Return
on average common equity for the 12 months ended
|
|
|
|
|
|
|
|
|
15.1
|
%
|
14.4%
|
Three
Months Ended June 30, 2006 and 2005
Consolidated earnings for the quarter ended June 30, 2006, decreased $8.7
million from the comparable prior period largely due to:
· |
Decreased
earnings from equity method investments, largely the absence in
2006 of
the 2005 $15.6 million benefit from the sale of the Termoceara
Generating
Facility at the independent power production
business
|
· |
Absence
in 2006 of the benefit from the resolution of a rate proceeding
of $5.0
million (after tax) recorded in 2005 at the pipeline and energy
services
business. For more information, see Note
18.
|
Partially
offsetting the decrease were:
· |
Higher
earnings from construction due to increased volumes and margins
and
earnings from companies acquired since the comparable prior period
at the
construction materials and mining
business
|
· |
Earnings
from acquisitions made since the comparable prior period and increased
outside construction workloads and inside construction workloads
and
margins at the construction services
business
|
Six
Months Ended June 30, 2006 and 2005
Consolidated earnings for the six months ended June 30, 2006, increased
$10.0
million from the comparable prior period largely due to:
· |
Higher
average realized natural gas prices of 20 percent, increased natural
gas
and oil production of 5 percent and 19 percent, respectively, and
higher
average realized oil prices of 22 percent at the natural gas and
oil
production business
|
· |
Earnings
from acquisitions made since the comparable prior period and higher
inside
construction workloads and margins at the construction services
business
|
· |
Higher
earnings from construction, as previously discussed, and increased
realized ready-mixed concrete volumes and margins at the construction
materials and mining business
|
Partially
offsetting the increase were:
· |
Decreased
earnings from equity method investments which reflect the absence
in 2006
of the 2005 $15.6 million benefit from the sale of the Termoceara
Generating Facility, higher net interest expense largely due to
debt
related to the Hardin Generating Facility which was placed in commercial
operation in March 2006, and lower margins related to domestic
electric generating facilities primarily due to lower capacity
revenues at
the independent power production business
|
· |
Absence
in 2006 of the benefit from the resolution of a rate proceeding
of $5.0
million (after tax) recorded in 2005, as previously discussed,
at the
pipeline and energy services 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,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$
|
40.9
|
|
$
|
41.1
|
|
$
|
85.9
|
|
$
|
85.4
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
16.0
|
|
|
14.5
|
|
|
32.0
|
|
|
30.7
|
|
Operation
and maintenance
|
|
|
15.7
|
|
|
14.9
|
|
|
29.7
|
|
|
28.7
|
|
Depreciation,
depletion and amortization
|
|
|
5.3
|
|
|
5.2
|
|
|
10.6
|
|
|
10.4
|
|
Taxes,
other than income
|
|
|
2.0
|
|
|
2.1
|
|
|
4.3
|
|
|
4.3
|
|
|
|
|
39.0
|
|
|
36.7
|
|
|
76.6
|
|
|
74.1
|
|
Operating
income
|
|
|
1.9
|
|
|
4.4
|
|
|
9.3
|
|
|
11.3
|
|
Earnings
|
|
$
|
.5
|
|
$
|
1.8
|
|
$
|
4.3
|
|
$
|
4.9
|
|
Retail
sales (million kWh)
|
|
|
563.0
|
|
|
554.7
|
|
|
1,175.9
|
|
|
1,159.2
|
|
Sales
for resale (million kWh)
|
|
|
85.3
|
|
|
115.3
|
|
|
251.7
|
|
|
313.3
|
|
Average
cost of fuel and purchased power per kWh
|
|
$
|
.024
|
|
$
|
.021
|
|
$
|
.022
|
|
$
|
.020
|
|
Three
Months Ended June 30, 2006 and 2005 Electric
earnings decreased $1.3 million due to:
· |
Higher
operation and maintenance expense of $500,000 (after tax), primarily
the
result of a scheduled maintenance outage at an electric generating
station
|
· |
Decreased
retail sales margins, largely the result of the timing of increased
fuel
and purchased power costs
|
· |
Decreased
sales for resale margins due to lower average rates of 15 percent
resulting from lower demand caused by mild weather and decreased
volumes
of 26 percent due to plant availability
|
This
decrease was partially offset by decreased interest expense of $200,000
(after
tax) resulting from lower average interest rates due to the repurchase
and
redemption of certain long-term debt.
Six
Months Ended June 30, 2006 and 2005 Electric
earnings decreased $600,000 due to:
· |
Decreased
sales for resale margins due to lower average rates of 16 percent
and
decreased volumes of 20 percent, both as previously
discussed
|
· |
Higher
operation and maintenance expense of $600,000 (after tax), largely
the
result of a scheduled maintenance outage at an electric generating
station
|
Partially
offsetting the decrease was decreased interest expense of $400,000 (after
tax)
resulting from lower average interest rates, as previously
discussed.
Natural
Gas Distribution
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
44.9
|
|
$
|
53.6
|
|
$
|
196.1
|
|
$
|
197.3
|
|
Transportation
and other
|
|
|
.9
|
|
|
1.1
|
|
|
2.0
|
|
|
2.4
|
|
|
|
|
45.8
|
|
|
54.7
|
|
|
198.1
|
|
|
199.7
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
33.4
|
|
|
41.6
|
|
|
161.8
|
|
|
162.1
|
|
Operation
and maintenance
|
|
|
13.0
|
|
|
11.3
|
|
|
24.8
|
|
|
23.2
|
|
Depreciation,
depletion and amortization
|
|
|
2.4
|
|
|
2.3
|
|
|
4.8
|
|
|
4.8
|
|
Taxes,
other than income
|
|
|
1.5
|
|
|
1.4
|
|
|
3.0
|
|
|
3.0
|
|
|
|
|
50.3
|
|
|
56.6
|
|
|
194.4
|
|
|
193.1
|
|
Operating
income (loss)
|
|
|
(4.5
|
)
|
|
(1.9
|
)
|
|
3.7
|
|
|
6.6
|
|
Earnings
(loss)
|
|
$
|
(2.5
|
)
|
$
|
(1.3
|
)
|
$
|
2.8
|
|
$
|
3.5
|
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
4.6
|
|
|
5.3
|
|
|
18.8
|
|
|
21.2
|
|
Transportation
|
|
|
2.8
|
|
|
3.0
|
|
|
7.2
|
|
|
6.9
|
|
Total
throughput
|
|
|
7.4
|
|
|
8.3
|
|
|
26.0
|
|
|
28.1
|
|
Degree
days (% of normal)*
|
|
|
68
|
%
|
|
92
|
%
|
|
82
|
%
|
|
93
|
%
|
Average
cost of natural gas, including transportation, per
dk
|
|
$
|
7.29
|
|
$
|
7.82
|
|
$
|
8.59
|
|
$
|
7.66
|
|
*
Degree days are a measure of the daily temperature-related demand for energy
for
heating.
Three
Months Ended June 30, 2006 and 2005 The
natural gas distribution business experienced a seasonal loss of $2.5 million
in
the second quarter compared to a loss of $1.3 million in the second quarter
of
2005. The decrease in earnings of $1.2 million was largely due to:
· |
Higher
operation and maintenance expense of $1.1 million (after tax),
largely due
to higher payroll-related costs from an early retirement program
|
· |
Lower
retail sales margins due to lower sales volumes of 14 percent,
resulting
from 27 percent warmer weather than last
year
|
Six
Months Ended June 30, 2006 and 2005
Earnings
at the natural gas distribution business decreased $700,000 due to:
· |
Higher
operation and maintenance expense of $1.0 million (after tax) largely
due
to higher payroll-related costs from an early retirement program
|
· |
Lower
retail sales margins due to lower sales volumes of 11 percent,
resulting
from 12 percent warmer weather than last year, partially offset
by higher
weather-normalized revenues in certain
jurisdictions
|
Partially
offsetting the decrease in earnings were higher nonregulated earnings from
energy-related services.
Construction
Services
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
(In
millions)
|
Operating
revenues
|
|
$
|
243.2
|
|
$
|
136.9
|
|
$
|
467.0
|
|
$
|
250.8
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
216.5
|
|
|
122.6
|
|
|
419.3
|
|
|
223.7
|
|
Depreciation,
depletion and amortization
|
|
|
3.9
|
|
|
3.1
|
|
|
7.4
|
|
|
5.9
|
|
Taxes,
other than income
|
|
|
5.5
|
|
|
4.3
|
|
|
12.9
|
|
|
10.1
|
|
|
|
|
225.9
|
|
|
130.0
|
|
|
439.6
|
|
|
239.7
|
|
Operating
income
|
|
|
17.3
|
|
|
6.9
|
|
|
27.4
|
|
|
11.1
|
|
Earnings
|
|
$
|
9.7
|
|
$
|
3.7
|
|
$
|
15.1
|
|
$
|
5.6
|
|
Three
Months Ended June 30, 2006 and 2005 Construction
services earnings increased $6.0 million compared to the second quarter
of the
comparable prior period due to:
· |
Earnings
from acquisitions made since the comparable prior period, which
contributed approximately 59 percent of the earnings
increase
|
· |
Higher
outside construction workloads and margins of $1.4 million (after
tax),
largely in the Southwest region partially offset by decreased workloads
and margins in the Northwest region
|
· |
Higher
inside construction workloads and margins of $1.1 million (after
tax)
|
· |
Increased
equipment sales and rentals
|
Six
Months Ended June 30, 2006 and 2005
Construction services earnings increased $9.5 million compared to the six
months
of the comparable prior period due to:
· |
Earnings
from acquisitions made since the comparable prior period, which
contributed approximately 60 percent of the earnings
increase
|
· |
Higher
inside construction workloads and margins of $3.4 million (after
tax)
|
· |
Increased
equipment sales and rentals
|
· |
Higher
outside construction workloads of $600,000 (after tax), largely in
the Southwest region partially offset by decreased workloads and
margins
in the Northwest region
|
Partially
offsetting the increase were higher general and administrative expenses
of $1.1
million (after tax), including higher payroll-related expenses and outside
services.
Pipeline
and Energy Services
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
$
|
26.1
|
|
$
|
22.5
|
|
$
|
46.8
|
|
$
|
42.3
|
|
Energy
services
|
|
|
77.0
|
|
|
78.9
|
|
|
183.3
|
|
|
151.9
|
|
|
|
|
103.1
|
|
|
101.4
|
|
|
230.1
|
|
|
194.2
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
69.3
|
|
|
71.4
|
|
|
167.1
|
|
|
136.9
|
|
Operation
and maintenance
|
|
|
15.0
|
|
|
13.3
|
|
|
27.5
|
|
|
26.6
|
|
Depreciation,
depletion and amortization
|
|
|
5.1
|
|
|
(1.5
|
)
|
|
10.1
|
|
|
3.1
|
|
Taxes,
other than income
|
|
|
2.6
|
|
|
2.0
|
|
|
5.1
|
|
|
4.1
|
|
|
|
|
92.0
|
|
|
85.2
|
|
|
209.8
|
|
|
170.7
|
|
Operating
income
|
|
|
11.1
|
|
|
16.2
|
|
|
20.3
|
|
|
23.5
|
|
Earnings
|
|
$
|
5.6
|
|
$
|
8.7
|
|
$
|
10.2
|
|
$
|
12.0
|
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
7.1
|
|
|
7.7
|
|
|
15.1
|
|
|
15.4
|
|
Other
|
|
|
28.0
|
|
|
19.6
|
|
|
46.2
|
|
|
33.5
|
|
|
|
|
35.1
|
|
|
27.3
|
|
|
61.3
|
|
|
48.9
|
|
Gathering
volumes (MMdk)
|
|
|
21.2
|
|
|
19.7
|
|
|
42.9
|
|
|
39.7
|
|
Three
Months Ended June 30, 2006 and 2005 Pipeline
and energy services experienced a decrease in earnings of $3.1 million
due
to:
· |
Absence
in 2006 of the benefit from the resolution of a rate proceeding
of $5.0
million (after tax) recorded in 2005, which included a reduction
to
depreciation, depletion and amortization expense. For more information,
see Note 18.
|
· |
Higher
operation and maintenance expense, primarily related to the natural
gas
storage litigation. For more information, see Note
19.
|
Partially
offsetting this decrease were higher transportation, storage and gathering
volumes of $2.6 million (after tax), and higher gathering rates of $1.0
million
(after tax).
Six
Months Ended June 30, 2006 and 2005
Pipeline
and energy services experienced a decrease in earnings of $1.8 million
due
to:
· |
Absence
in 2006 of the benefit from the resolution of a rate proceeding
of $5.0
million (after tax) recorded in 2005, as previously
discussed
|
· |
Higher
operation and maintenance expense, primarily related to the natural
gas
storage litigation, as previously
discussed
|
Partially
offsetting this decrease were higher transportation, storage and gathering
volumes of $3.3 million (after tax), and higher gathering rates of $2.1
million
(after tax).
Natural
Gas and Oil Production
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
87.2
|
|
$
|
80.3
|
|
$
|
192.5
|
|
$
|
152.8
|
|
Oil
|
|
|
25.4
|
|
|
17.3
|
|
|
46.5
|
|
|
31.8
|
|
Other
|
|
|
1.5
|
|
|
.1
|
|
|
3.5
|
|
|
.2
|
|
|
|
|
114.1
|
|
|
97.7
|
|
|
242.5
|
|
|
184.8
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
1.7
|
|
|
.1
|
|
|
3.7
|
|
|
.2
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
12.3
|
|
|
9.8
|
|
|
24.2
|
|
|
17.7
|
|
Gathering
and transportation
|
|
|
4.7
|
|
|
2.8
|
|
|
9.4
|
|
|
5.6
|
|
Other
|
|
|
9.4
|
|
|
6.4
|
|
|
16.8
|
|
|
11.9
|
|
Depreciation,
depletion and amortization
|
|
|
25.8
|
|
|
21.2
|
|
|
50.3
|
|
|
38.3
|
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
8.0
|
|
|
7.5
|
|
|
18.0
|
|
|
13.5
|
|
Other
|
|
|
.4
|
|
|
.1
|
|
|
.5
|
|
|
.3
|
|
|
|
|
62.3
|
|
|
47.9
|
|
|
122.9
|
|
|
87.5
|
|
Operating
income
|
|
|
51.8
|
|
|
49.8
|
|
|
119.6
|
|
|
97.3
|
|
Earnings
|
|
$
|
31.0
|
|
$
|
29.9
|
|
$
|
72.2
|
|
$
|
58.8
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
15,242
|
|
|
14,627
|
|
|
30,604
|
|
|
29,054
|
|
Oil
(MBbls)
|
|
|
471
|
|
|
406
|
|
|
921
|
|
|
773
|
|
Average
realized prices (including hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
5.72
|
|
$
|
5.49
|
|
$
|
6.29
|
|
$
|
5.26
|
|
Oil
(per barrel)
|
|
$
|
54.00
|
|
$
|
42.60
|
|
$
|
50.43
|
|
$
|
41.21
|
|
Average
realized prices (excluding hedges):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
5.15
|
|
$
|
5.71
|
|
$
|
6.03
|
|
$
|
5.37
|
|
Oil
(per barrel)
|
|
$
|
55.71
|
|
$
|
47.81
|
|
$
|
51.77
|
|
$
|
46.06
|
|
Production
costs, including taxes, per net equivalent Mcf:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$
|
.68
|
|
$
|
.57
|
|
$
|
.67
|
|
$
|
.52
|
|
Gathering
and transportation
|
|
|
.26
|
|
|
.17
|
|
|
.26
|
|
|
.17
|
|
Production
and property taxes
|
|
|
.45
|
|
|
.44
|
|
|
.50
|
|
|
.40
|
|
|
|
$
|
1.39
|
|
$
|
1.18
|
|
$
|
1.43
|
|
$
|
1.09
|
|
Three
Months Ended June 30, 2006 and 2005 The
natural gas and oil production business experienced a $1.1 million increase
in
earnings due to:
· |
Higher
average realized oil prices of 27 percent
|
· |
Higher
average realized natural gas prices of 4
percent
|
· |
Increased
oil production of 16 percent and natural gas production of 4 percent,
largely due to increased production in the Rocky Mountain region
as well
as from the May 2005 South Texas and May 2006 Big Horn
acquisitions
|
Partially
offsetting the increase were:
· |
Higher
depreciation, depletion and amortization of $2.9 million (after
tax) due
to higher depletion rates and increased
production
|
· |
Higher
lease operating expenses of $1.6 million (after tax), including
acquisitions since the comparable prior
period
|
· |
Increased
general and administrative expense of $1.3 million (after tax),
including
higher payroll-related expenses and office
expenses
|
Six
Months Ended June 30, 2006 and 2005
The
natural gas and oil production business experienced a $13.4 million increase
in
earnings due to:
· |
Higher
average realized natural gas prices of 20
percent
|
· |
Increased
natural gas production of 5 percent and oil production of 19 percent,
as
previously discussed
|
· |
Higher
average realized oil prices of 22 percent
|
Partially
offsetting the increase were:
· |
Higher
depreciation, depletion and amortization of $7.4 million (after
tax) due
to higher depletion rates and increased
production
|
· |
Higher
lease operating expenses of $4.0 million (after tax), as previously
discussed
|
· |
Increased
general and administrative expense of $2.5 million (after tax),
including
higher payroll-related expenses, outside service fees and office
expenses
|
Construction
Materials and Mining
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
484.9
|
|
$
|
394.0
|
|
$
|
718.6
|
|
$
|
581.1
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
404.5
|
|
|
330.0
|
|
|
620.2
|
|
|
500.5
|
|
Depreciation,
depletion and amortization
|
|
|
22.1
|
|
|
19.0
|
|
|
42.2
|
|
|
37.2
|
|
Taxes,
other than income
|
|
|
11.9
|
|
|
10.5
|
|
|
20.3
|
|
|
18.4
|
|
|
|
|
438.5
|
|
|
359.5
|
|
|
682.7
|
|
|
556.1
|
|
Operating
income
|
|
|
46.4
|
|
|
34.5
|
|
|
35.9
|
|
|
25.0
|
|
Earnings
|
|
$
|
25.3
|
|
$
|
18.4
|
|
$
|
16.4
|
|
$
|
9.9
|
|
Sales
(000's):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
13,341
|
|
|
11,023
|
|
|
19,425
|
|
|
16,929
|
|
Asphalt
(tons)
|
|
|
2,356
|
|
|
2,139
|
|
|
2,689
|
|
|
2,500
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
1,260
|
|
|
1,224
|
|
|
1,971
|
|
|
1,884
|
|
Three
Months Ended June 30, 2006 and 2005
Earnings
at the construction materials and mining business increased $6.9 million
due
to:
· |
Higher
earnings of $5.2 million (after tax) from construction, largely
due to
increased volumes and margins
|
· |
Earnings
from companies acquired since the comparable prior period, which
contributed approximately 21 percent of the earnings
increase
|
· |
Increased
earnings from aggregate and ready-mixed concrete operations of
$2.4
million (after tax), largely due to higher
volumes
|
Partially
offsetting the increase in earnings were:
· |
Increased
general and administrative expense of $1.6 million (after tax),
largely
payroll-related
|
· |
Higher
depreciation, depletion and amortization of $1.2 million (after
tax),
primarily due to higher plant and equipment balances and increased
aggregate production
|
Six
Months Ended June 30, 2006 and 2005
Earnings
at the construction materials and mining business increased $6.5 million
due
to:
· |
Higher
earnings of $5.7 million (after tax) from construction, as previously
discussed
|
· |
Higher
realized ready-mixed concrete margins and volumes added $3.4 million
(after tax) to earnings
|
· |
Higher
earnings from aggregate operations of $1.8 million (after tax),
largely
higher volumes
|
Partially
offsetting the increase in earnings were:
· |
Increased
general and administrative expense of $2.7 million (after tax),
primarily
payroll-related
|
· |
Higher
depreciation, depletion and amortization of $1.9 million (after
tax), as
previously discussed
|
· |
Higher
interest expense of $1.4 million (after tax), largely due to
acquisition-related debt and higher interest
rates
|
Independent
Power Production
|
|
Three
Months Ended
June
30,
|
|
Six
Months Ended
June
30,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
OOperating
revenues
|
|
$
|
11.7
|
|
$
|
13.7
|
|
$
|
23.0
|
|
$
|
23.5
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
1.0
|
|
|
---
|
|
|
1.3
|
|
|
---
|
|
Operation and maintenance
|
|
|
5.1
|
|
|
7.3
|
|
|
14.3
|
|
|
13.7
|
|
Depreciation, depletion and amortization
|
|
|
4.3
|
|
|
2.2
|
|
|
6.6
|
|
|
4.7
|
|
Taxes,
other than income
|
|
|
1.1
|
|
|
.7
|
|
|
2.0
|
|
|
1.4
|
|
|
|
|
11.5
|
|
|
10.2
|
|
|
24.2
|
|
|
19.8
|
|
Operating
income (loss)
|
|
|
.2
|
|
|
3.5
|
|
|
(1.2
|
)
|
|
3.7
|
|
Earnings
|
|
$
|
1.5
|
|
$
|
18.6
|
|
$
|
2.8
|
|
$
|
19.3
|
|
Net
generation capacity (kW)*
|
|
|
437,600
|
|
|
279,600
|
|
|
437,600
|
|
|
279,600
|
|
Electricity
produced and sold (thousand kWh)*
|
|
|
202,778
|
|
|
90,762
|
|
|
291,275
|
|
|
128,012
|
|
* Excludes equity method investments.
Three
Months Ended June 30, 2006 and 2005 Earnings
at the independent power production business decreased $17.1 million largely
due
to:
· |
Decreased
earnings from equity method investments which reflect the absence
in 2006
of the 2005 $15.6 million benefit from the sale of the Termoceara
Generating Facility, partially offset by increased earnings from
the
Trinity Generating Facility
|
· |
Higher
interest expense of $1.8 million (after tax) largely due to debt
related
to the Hardin Generating Facility which was placed in commercial
operation
in March 2006
|
· |
Lower
margins of $1.4 million (after tax) related to domestic electric
generating facilities primarily due to lower capacity
revenues
|
Six
Months Ended June 30, 2006 and 2005
Earnings
at the independent power production business decreased $16.5 million largely
due
to:
· |
Decreased
earnings from equity method investments which reflect the absence
in 2006
of the 2005 $15.6 million benefit from the sale of the Termoceara
Generating Facility, partially offset by increased earnings from
the
Trinity Generating Facility partially due to a one-time benefit
due to a
tax rate reduction
|
· |
Higher
interest expense of $1.8 million (after tax), as previously
discussed
|
· |
Lower
margins of $2.0 million (after tax) related to domestic electric
generating facilities primarily due to lower capacity
revenues
|
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,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
2.3
|
|
$
|
1.4
|
|
$
|
4.1
|
|
$
|
2.7
|
|
Operation
and maintenance
|
|
|
1.8
|
|
|
1.2
|
|
|
3.0
|
|
|
2.4
|
|
Depreciation,
depletion and amortization
|
|
|
.2
|
|
|
.1
|
|
|
.5
|
|
|
.1
|
|
Taxes,
other than income
|
|
|
.1
|
|
|
---
|
|
|
.1
|
|
|
.1
|
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
72.2
|
|
$
|
70.7
|
|
$
|
180.2
|
|
$
|
147.7
|
|
Fuel
and purchased power
|
|
|
.1
|
|
|
---
|
|
|
.1
|
|
|
---
|
|
Purchased
natural gas sold
|
|
|
65.0
|
|
|
66.4
|
|
|
166.3
|
|
|
139.0
|
|
Operation
and maintenance
|
|
|
7.1
|
|
|
4.3
|
|
|
13.8
|
|
|
8.7
|
|
For
further information on intersegment eliminations, see Note 15.
PROSPECTIVE
INFORMATION
The
following information includes highlights of 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 2005
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 2006, diluted, are projected in the range
of $1.47 to
$1.60, an increase from prior guidance of $1.43 to
$1.57.
|
· |
The
Company expects the percentage of 2006 earnings per common share,
diluted,
by quarter to be in the following approximate
ranges:
|
o |
Third
quarter - 30 percent to 35 percent
|
o |
Fourth
quarter - 20 percent to 25 percent
|
· |
The
Company’s long-term compound annual growth goal on earnings per share is
in the range of 7 percent to 10 percent, although the Company has
exceeded
this level in recent years.
|
Electric
· |
The
Company is analyzing potential projects for accommodating load
growth and
replacing an expiring purchased power contract with Company-owned
generation. This will add to the Company’s base-load capacity and rate
base. New generation is projected to be on line by 2011. A decision
on the
project to be built is anticipated by early
2007.
|
· |
As
discussed in Note 21, the Company has entered into a definitive
merger
agreement to acquire Cascade. When the acquisition is completed,
it is
expected to significantly enhance regulated earnings and cash flows.
Regulatory approvals are anticipated to be obtained by mid-year
2007.
|
· |
This
business continues to pursue growth by expanding energy-related
services.
|
· |
Montana-Dakota
has obtained and holds, or is in the process of renewing, valid
and
existing franchises authorizing it to conduct its electric operations
in
all of the municipalities it serves where such franchises are required.
Montana-Dakota intends to protect its service area and seek renewal
of all
expiring franchises.
|
Natural
gas distribution
· |
In
September 2004, a natural gas rate case was filed with the MNPUC
requesting a revenue increase of $1.4 million annually, or approximately
4
percent. For further information, see Note
18.
|
· |
Montana-Dakota's
and Great Plains' retail natural gas rate schedules contain clauses
permitting monthly adjustments in rates based upon changes in natural
gas
commodity, transportation and storage costs. Current regulatory
practices
allow Montana-Dakota and Great Plains to recover increases or refund
decreases in such costs within a period ranging from 24 to 28 months
from
the time such costs are paid. At June 30, 2006, the Montana Public
Service
Commission has not issued a final order relative to the three years
of
monthly gas cost changes that were implemented on an interim basis
from
May 2003 through May 2005. A final order is expected by late
2006.
|
· |
This
business continues to pursue growth by expanding energy-related
services.
|
· |
Montana-Dakota
and Great Plains have obtained and hold, or are in the process
of
renewing, valid and existing franchises authorizing them to conduct
their
natural gas operations in all of the municipalities they serve
where such
franchises are required. Montana-Dakota and Great Plains intend
to protect
their service areas and seek renewal of all expiring
franchises.
|
Construction
services
· |
Revenues
in 2006 are expected to be significantly higher than 2005 record
levels.
|
· |
The
Company anticipates margins to strengthen in 2006 as compared to
2005
levels.
|
· |
Work
backlog as of June 30, 2006, was approximately $523 million, including
acquisitions, compared to $358 million at June 30,
2005.
|
Pipeline
and energy services
· |
Firm
capacity for the Grasslands Pipeline is 90,000 Mcf per day with
possible
expansion to 200,000 Mcf per day. Based on anticipated demand,
incremental
expansions are forecasted over the next few years beginning as
early as
2008.
|
· |
In
2006, total gathering and transportation throughput is expected
to
increase approximately 5 percent to 10 percent over 2005
levels.
|
Natural
gas and oil production
· |
The
Company’s long-term compound annual growth goal for production is in the
range of 7 percent to 10 percent. In 2006, the Company expects
to exceed
the upper end of this range.
|
· |
The
Company is expecting to drill more than 325 wells in 2006. Currently,
this
segment’s net combined natural gas and oil production is approximately
200,000 Mcf equivalent to 210,000 Mcf equivalent per day.
|
· |
Estimates
of natural gas prices in the Rocky Mountain region for August through
December 2006, reflected in the Company’s 2006 earnings guidance, are in
the range of $5.50 to $6.00 per thousand cubic feet. The Company’s
estimates for natural gas prices on the NYMEX for August through
December,
reflected in the Company’s 2006 earnings guidance, are in the range of
$6.75 to $7.25 per Mcf. During 2005, more than three-fourths of
this
segment’s natural gas production was priced using Rocky Mountain or other
non-NYMEX prices.
|
· |
Estimates
of NYMEX crude oil prices for August through December, reflected
in the
Company’s 2006 earnings guidance, are projected in the range of $60 to
$65
per barrel.
|
· |
The
Company has hedged approximately 30 percent to 35 percent of its
estimated
natural gas production and 15 percent to 20 percent of its estimated
oil
production for the last six months of 2006. For 2007, the Company
has
hedged approximately 20 percent to 25 percent of its estimated
natural gas
production. The hedges that are in place as of July 27, 2006, 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
|
7/06
- 12/06
|
920,000
|
$6.00-$7.60
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
1,840,000
|
$6.655
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
920,000
|
$6.75-$7.71
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
920,000
|
$6.75-$7.77
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
920,000
|
$7.00-$8.85
|
Natural
Gas
|
NYMEX
|
7/06
- 12/06
|
920,000
|
$7.75-$8.50
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
920,000
|
$7.76
|
Natural
Gas
|
CIG
|
7/06
- 12/06
|
920,000
|
$6.50-$6.98
|
Natural
Gas
|
CIG
|
7/06
- 12/06
|
920,000
|
$7.00-$8.87
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
460,000
|
$8.50-$10.00
|
Natural
Gas
|
Ventura
|
7/06
- 12/06
|
460,000
|
$8.50-$10.15
|
Natural
Gas
|
Ventura
|
7/06
- 10/06
|
615,000
|
$9.25-$12.88
|
Natural
Gas
|
Ventura
|
7/06
- 10/06
|
615,000
|
$9.25-$12.80
|
Natural
Gas
|
CIG
|
11/06
- 12/06
|
305,000
|
$7.00-$8.65
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$8.00-$11.91
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
912,500
|
$8.00-$11.80
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
912,500
|
$8.00-$11.75
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$7.50-$10.55
|
Natural
Gas
|
CIG
|
1/07
- 12/07
|
1,825,000
|
$7.40
|
Natural
Gas
|
CIG
|
1/07
- 12/07
|
1,825,000
|
$7.405
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,460,000
|
$8.25-$10.80
|
Natural
Gas
|
CIG
|
1/07
- 12/07
|
912,500
|
$7.50-$9.12
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$8.29
|
Natural
Gas
|
Ventura
|
11/06
- 3/07
|
755,000
|
$8.00-$9.80
|
Natural
Gas
|
Ventura
|
1/07
- 12/07
|
1,825,000
|
$7.85-$9.70
|
Crude
Oil
|
NYMEX
|
7/06
- 12/06
|
92,000
|
$43.00-$54.15
|
Crude
Oil
|
NYMEX
|
7/06
- 12/06
|
73,600
|
$60.00-$69.20
|
Crude
Oil
|
NYMEX
|
7/06
- 12/06
|
46,000
|
$60.00-$76.80
|
*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
· |
Ready-mixed
concrete and aggregate volumes for 2006 are expected to be higher
than the
record levels achieved in 2005. Asphalt volumes are expected to
be
slightly lower than 2005 record volumes.
|
· |
Work
backlog as of June 30, 2006, was approximately $763 million, including
acquisitions, compared to $740 million at June 30,
2005.
|
· |
A
key element of the Company’s long-term strategy for this business is to
further expand its presence in the higher-margin materials business
(rock,
sand, gravel and related products), complementing the Company’s ongoing
efforts to increase margin by building a more profitable backlog
of
business and carefully managing costs.
|
· |
Strong
market and product demand, cost containment initiatives and continued
operational improvement in Texas are expected to result in improved
margins over 2005.
|
Independent
power production
· |
Earnings
at this segment are expected to be minimal in 2006, reflecting
primarily
the sale of the Company’s Brazilian electric generating facility in June
2005, significantly higher interest expense related to the construction
of
the Hardin Generating Facility and lower revenues because of the
bridge
contract renewal at the Brush Generating Facility. The bridge contract
will be replaced by a more favorably priced 10-year contract in
April
2007.
|
· |
This
segment is focused on redeploying the funds from the June 2005
sale of the
Brazilian facility and continues to explore for investment opportunities
both domestically and internationally, using the Company’s disciplined
approach for acquisitions.
|
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 2005
Annual
Report. For more information on critical accounting policies involving
significant estimates, see Part II, Item 7 in the 2005 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 2006 increased $28.1 million from the comparable 2005 period,
the
result of:
· |
Higher
depreciation, depletion and amortization expense of $28.1 million,
largely
at the natural gas and oil production business, as previously
discussed
|
· |
Higher
deferred income taxes of $12.4 million, primarily related to natural
gas
costs recoverable through rate adjustments and costs associated
with the
repurchase of certain first mortgage bonds at the electric and
natural gas
distribution businesses, as well as higher property, plant and
equipment
at the natural gas and oil production
business
|
· |
Decreased
earnings, net of distributions, from equity method investments
of $11.5
million, primarily the result of the sale of the Termoceara Generating
Facility
|
· |
Increased
net income of $10.0 million, largely increased earnings at the
natural gas
and oil production, construction services and construction materials
and
mining businesses
|
Partially
offsetting the increase in cash flows from operating activities
were:
· |
Increased
working capital requirements of $31.2 million, largely at the following
businesses:
|
- |
Natural
gas distribution, largely due to timing of natural gas costs
recoverable/refundable through rate adjustments, lower storage
withdrawals
and higher natural gas costs
|
- |
Construction
materials and mining, due to higher asphalt oil and fuel
inventories
|
- |
Higher
income tax payments
|
Investing
activities Cash
flows used in investing activities in the first six months of 2006 increased
$11.1 million compared to the comparable 2005 period, the result of increased
capital expenditures primarily at the natural gas and oil production business,
largely due to additional exploration and development, and higher ongoing
capital expenditures at the construction materials and mining business.
Partially offsetting this increase was a decrease in cash flows used for
acquisitions largely at the natural gas and oil production segment.
Financing
activities Cash
flows provided by financing activities in the first six months of 2006
increased
$36.3 million compared to the comparable 2005 period, the result of a decrease
in the repayment of long-term debt of $26.6 million and an increase in
the
issuance of long-term debt of $10.9 million.
Defined
benefit pension plans
There
are
no material changes to the Company’s qualified noncontributory defined benefit
pension plans from those reported in the 2005 Annual Report. For further
information, see Note 17.
Capital
expenditures
Net
capital expenditures for the first six months of 2006 were $362.3 million
and
are estimated to be approximately $590 million for the year 2006. 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
23 percent of estimated 2006 net capital expenditures are associated with
completed acquisitions. 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 2006 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; commercial paper credit facilities at Centennial Energy
Holdings, Inc. and MDU Resources Group, Inc., 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, 2006.
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 and upon regulatory approval, up to a maximum of $150 million).
There
were no amounts outstanding under the credit agreement at June 30, 2006.
The
credit agreement supports the Company’s $100 million commercial paper
program. Under the Company’s commercial paper program, $85.0 million was
outstanding at June 30, 2006. 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 plans to borrow up
to $100
million through the issuance of unsecured notes later this year. These
funds are
expected to be used primarily to pay down commercial paper borrowings and
for
general corporate purposes in connection with the Company’s electric and natural
gas distribution businesses.
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
were to experience a significant downgrade of its credit ratings, it may
need to
borrow under its credit agreement.
To
the
extent the Company needs to borrow under its credit agreement, it would
be
expected to incur increased annualized interest expense on its variable
rate
debt of approximately $128,000 (after tax) based on June 30, 2006, variable
rate
borrowings.
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. One source of alternative funding might involve the securitization
of
certain Company assets.
In
order
to borrow under the Company’s credit agreement, the Company must be in
compliance with the applicable covenants and certain other conditions,
including
covenants not to permit, as of the end of any fiscal quarter, (A) the ratio
of
funded debt to total capitalization (determined on a consolidated basis)
to be
greater than 65 percent or (B) the ratio of funded debt to capitalization
(determined with respect to the Company alone, excluding its subsidiaries)
to be
greater than 65 percent. Also included is a covenant that does not permit
the ratio of the Company's earnings before interest, taxes, depreciation
and
amortization to interest expense (determined with respect to the Company
alone,
excluding its subsidiaries), for the 12-month period ended each fiscal
quarter,
to be less than 2.5 to 1. Other covenants include restrictions on the sale
of
certain assets and on the making of certain investments. The Company was
in
compliance with these covenants and met the required conditions at June
30,
2006. 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.
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 Indenture of 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, 2006, the Company could have
issued approximately $441 million of additional first mortgage
bonds.
The
Company's coverage of fixed charges including preferred dividends was
6.1 times for both the 12 months ended June 30, 2006 and December 31, 2005.
Additionally, the Company's first mortgage bond interest coverage was 24.4
times
and 10.2 times for the 12 months ended June 30, 2006 and December 31, 2005,
respectively. Common stockholders' equity as a percent of total capitalization
(net of long-term debt due within one year) was 60 percent and 63 percent
at
June 30, 2006 and December 31, 2005, respectively.
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. Between January 1 and June 30,
2006, the
Company repurchased $68.0 million of first mortgage bonds. As of June 30,
2006,
the Company had $57.0 million of first mortgage bonds outstanding, $30.0
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, dated as of December 15, 2003, as supplemented, from the
Company
to The Bank of New York, as trustee, become unsecured and rank equally
with all
of the Company’s other unsecured and unsubordinated debt (as of June 30, 2006,
the only such debt outstanding under the Indenture was $30.0 million in
aggregate principal amount of the Company’s 5.98% Senior Notes due in
2033).
On
July
27, 2006, the Company entered into a Sales Agency Financing Agreement 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 June 30, 2007. 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 is 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 July 27, 2006, filed with the Securities
and
Exchange Commission pursuant to Rule 424(b) under the Securities Act of
1933, as
amended.
Centennial
Energy Holdings, Inc.
Centennial has three revolving credit agreements with various banks and
institutions totaling $437.9 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, 2006. Under the Centennial
commercial paper program, $310.5 million was outstanding at June 30, 2006.
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. Another
agreement is for $17.9 million and expires on April 30, 2007. Centennial
intends
to negotiate the extension or replacement of these agreements prior to
their
maturities. The third agreement is an uncommitted line for $20 million
and may
be terminated by the bank at any time. As of June 30, 2006, $43.4 million
of
letters of credit were outstanding, as discussed in Note 19, of which $25.9
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 (previously $450 million). Under the terms of the
master
shelf agreement, $547.5 million was outstanding at June 30, 2006. 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
were to experience a significant downgrade of its credit ratings, it may
need to
borrow under its committed bank lines.
To
the
extent Centennial needs to borrow under its committed bank lines, it would
be
expected to incur increased annualized interest expense on its variable
rate
debt of approximately $466,000 (after tax) based on June 30, 2006, variable
rate
borrowings. Based on Centennial’s overall interest rate exposure at June 30,
2006, this change would not have a material effect on the Company’s results of
operations or cash flows.
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. One source of alternative funding might
involve the securitization of certain Centennial assets.
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, including covenants not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater
than 65
percent (for the $400 million credit agreement) and 60 percent (for the
$17.9
million credit agreement and the master shelf agreement). Also included
is a
covenant that does not permit the ratio of Centennial’s earnings before
interest, taxes, depreciation and amortization to interest expense, for
the
12-month period ended each fiscal quarter, to be less than 2.5 to 1 (for
the
$400 million credit agreement), 2.25 to 1 (for the $17.9 million credit
agreement) and 1.75 to 1 (for the master shelf agreement). Other covenants
include minimum consolidated net worth, limitation on priority debt and
restrictions on the sale of certain assets and on the making of certain
loans
and investments. Centennial and such subsidiaries were in compliance with
these
covenants and met the required conditions at June 30, 2006. 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, 2006. 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, including covenants not to permit, as of the end of any fiscal
quarter, the ratio of total debt to total capitalization to be greater
than 55
percent. Other covenants include limitation on priority debt and some
restrictions on the sale of certain assets and the making of certain
investments. Williston Basin was in compliance with these covenants and
met the
required conditions at June 30, 2006. 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. Centennial has agreed to unconditionally
guarantee payment of the indemnity obligations to Petrobras for periods
ranging
from approximately two 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.
Contractual
obligations and commercial commitments
At
June
30, 2006, the Company’s contractual obligations related to long-term debt,
estimated interest payments, operating leases and purchase commitments
(for the
twelve months ended June 30, of each year listed in the table below) were
as
follows:
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Long-term
debt
|
|
$
|
159.2
|
|
$
|
132.0
|
|
$
|
87.4
|
|
$
|
22.5
|
|
$
|
492.4
|
|
$
|
564.8
|
|
$
|
1,458.3
|
|
Estimated
interest payments*
|
|
|
75.9
|
|
|
68.9
|
|
|
61.4
|
|
|
57.3
|
|
|
42.0
|
|
|
129.5
|
|
|
435.0
|
|
Operating
leases
|
|
|
14.2
|
|
|
10.5
|
|
|
8.9
|
|
|
8.1
|
|
|
6.9
|
|
|
35.7
|
|
|
84.3
|
|
Purchase
commitments
|
|
|
195.1
|
|
|
113.0
|
|
|
67.8
|
|
|
63.4
|
|
|
60.8
|
|
|
253.4
|
|
|
753.5
|
|
|
|
$
|
444.4
|
|
$
|
324.4
|
|
$
|
225.5
|
|
$
|
151.3
|
|
$
|
602.1
|
|
$
|
983.4
|
|
$
|
2,731.1
|
|
*
Estimated
interest payments are calculated based on the applicable rates
and payment
dates.
|
ITEM
3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The
Company is exposed to the impact of market fluctuations associated with
commodity prices and interest rates. 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. For more information
on
derivative instruments and commodity price risk, see Part II, Item 7A in
the
2005 Annual Report, and Notes 11 and 14.
The
following table summarizes derivative instruments entered into by Fidelity
as of
June 30, 2006. 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 2006
|
|
$
|
7.02
|
|
|
2,760
|
|
$
|
1,604
|
|
Natural
gas swap agreements maturing in 2007
|
|
$
|
7.70
|
|
|
5,475
|
|
$
|
(412
|
)
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
MMBtu)
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2006
|
|
$
|
7.34/8.94
|
|
$
|
8,895
|
|
$
|
11,693
|
|
Natural
gas collar agreements maturing in 2007
|
|
$
|
7.87/11.03
|
|
$
|
7,848
|
|
$
|
3,610
|
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
barrel)
|
|
Forward
Notional
Volume
(In
barrels)
|
|
Fair
Value
|
|
Oil
collar agreements maturing in 2006
|
|
$
|
52.61/64.31
|
|
|
212
|
|
$
|
(2,608
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Interest
rate risk
There
were no material changes to interest rate risk faced by the Company from
those
reported in the 2005 Annual Report. For more information on interest rate
risk,
see Part II, Item 7A in the 2005 Annual Report.
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, the Company’s assets are safeguarded against unauthorized or
improper use, and 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 2005 Annual Report other than the risks associated
with the ongoing litigation and administrative proceedings in connection
with
the Company’s coalbed natural gas development activities, and risks related to
foreign operations, a pending utility company acquisition, litigation in
connection with one of the Company’s storage reservoirs and increases in
employee and retiree benefit costs, as discussed below. These factors and
the
other matters discussed herein 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.
Environmental
and Regulatory Risks
One
of the Company’s subsidiaries is subject to ongoing litigation and
administrative proceedings in connection with its coalbed natural gas
development activities. These proceedings have caused delays in coalbed
natural
gas drilling activity, and the ultimate outcome of the actions could have
a
material effect on existing coalbed natural gas operations and/or the future
development of its coalbed natural gas properties.
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
coalbed natural gas development in the Powder River Basin in Montana and
Wyoming. If the plaintiffs are successful in these lawsuits, the ultimate
outcome of the actions could have a material effect on Fidelity's existing
coalbed natural gas operations and/or the future development of its coalbed
natural gas properties.
The
BER
in March 2006 issued a decision in a rulemaking proceeding, initiated by
the
NPRC, that amends the non-degradation policy applicable to water discharged
in
connection with coalbed natural gas operations. The amended policy includes
additional limitations on factors deemed harmful, thereby restricting water
discharges even further than under previous standards. In light of the
amended
policy, several parties commenced litigation in Montana state court challenging
two five-year water discharge permits that the Montana DEQ granted to Fidelity
in February 2006 and which are critical to Fidelity’s ability to manage water
produced under present and future coalbed natural gas operations. If these
permits are set aside, Fidelity’s coalbed natural gas operations in Montana
could be significantly and adversely affected.
Risks
Relating to Foreign Operations
The
value of the Company’s investments in foreign operations may diminish due to
political, regulatory and economic conditions and changes in currency exchange
rates in countries where the Company does business.
The
Company is subject to political, regulatory and economic conditions and
changes
in currency exchange rates in foreign countries where the Company does
business.
Significant changes in the political, regulatory or economic environment
in
these countries could negatively affect the value of the Company’s investments
located in these countries. Also, since the Company is unable to predict
the
fluctuations in the foreign currency exchange rates, these fluctuations
may have
an adverse impact on the Company’s results of operations.
Other
Risks
The
Company’s pending acquisition of Cascade may be delayed or may not occur if
certain conditions are not satisfied. Upon completion of the acquisition,
the
Company may not be able to integrate Cascade’s operations
effectively.
The
Company has entered into a definitive merger agreement to acquire Cascade.
The
total value of the transaction, including the assumption of certain
indebtedness, is approximately $475 million. The completion of the acquisition
is subject to the approval of Cascade’s shareholders and various regulatory
authorities, as well as antitrust clearance under the Hart-Scott-Rodino
Act, and
the satisfaction of other customary closing conditions. The Company’s pending
acquisition of Cascade may be delayed or may not occur if the Company is
unable
to timely obtain necessary regulatory approvals, satisfy closing conditions
or
obtain financing. If the Company is unable to integrate the Cascade operations
effectively, its future financial position or results of operations may
be
adversely affected.
One
of the Company’s subsidiaries is engaged in litigation with a non-affiliated
natural gas producer which has been conducting drilling and production
operations which the subsidiary believes is causing diversion and loss
of
storage gas from one of its storage reservoirs. If the subsidiary is not
able to
obtain relief through the courts or regulatory process, its storage operations
could be adversely affected.
Williston
Basin has filed suit in Federal court in Montana seeking to recover unspecified
damages from Anadarko and its wholly owned subsidiary, Howell, and to enjoin
Anadarko’s and Howell’s present and future operations in and near Williston
Basin’s Elk Basin Storage Reservoir located in Wyoming and Montana. Based on
relevant information, including reservoir and well pressure data, Williston
Basin believes that Elk Basin Storage Reservoir pressures have decreased
and
that quantities of natural gas have been diverted as a result of Anadarko’s and
Howell’s drilling and production activities. In related litigation, Anadarko
filed suit in Wyoming state district court against Williston Basin asserting
that it is entitled to produce any gas that might escape from Williston
Basin’s
storage reservoir. If Williston Basin is unable to obtain timely relief
through
the courts or regulatory process, its present and future gas storage operations
could be adversely affected.
Other
factors that could impact the Company’s businesses.
In
addition to those reported in Part I, Item 1A - Risk Factors of the 2005
Annual
Report, the following factor may also impact the Company’s financial results in
future periods:
· |
Increases
in employee and retiree benefit costs
|
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
Between
April 1, 2006 and June 30, 2006, the Company issued 1,785 shares (adjusted
for
the effect of the common stock split, as discussed in Note 3) 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
a
business acquired by the Company in a prior period. The Common Stock and
preference share purchase rights issued by the Company in this transaction
were
issued in a private transaction exempt from registration under the Securities
Act of 1933 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 (adjusted for the effect of the common stock split, as
discussed in Note 3):
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
(a)
Total
Number of Shares
(or
Units) Purchased
|
(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, 2006
|
40,831(1)
|
$24.72
|
|
|
May
1 through May 31, 2006
|
|
|
|
|
June
1 through June 30, 2006
|
|
|
|
|
Total
|
40,831
|
|
|
|
(1)
Represents 331 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 40,500 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
2
|
Agreement
and Plan of Merger by and among MDU Resources Group, Inc., Firemoon
Acquisition, Inc. and Cascade Natural Gas Corporation dated as
of July 8,
2006, filed by Cascade Natural Gas Corporation as Exhibit 2.1
to Form 8-K
dated July 10, 2006, in File No. 1-7196. (1)
|
|
|
3
|
Company
Bylaws, as amended
|
|
|
4(a)
|
Letter
Amendment No. 1 to Amended and Restated Master Shelf Agreement,
dated May
17, 2006, among Centennial Energy Holdings, Inc., The Prudential
Insurance
Company of America, and certain investors described in the Letter
Amendment
|
|
|
4(b)
|
First
Amendment, dated June 30, 2006, to Credit Agreement, dated June
21, 2005,
among MDU Resources Group, Inc., Wells Fargo Bank, National Association,
as administrative agent, and certain lenders described in the
credit
agreement amendment
|
|
|
4(c)
|
Certificate
of Adjustment to Purchase Price and Redemption Price, as amended
and
restated, pursuant to the Rights Agreement, dated as of November
12, 1998,
between MDU Resources Group, Inc. and Wells Fargo Bank, N.A.,
Rights
Agent
|
|
|
10(a)
|
Directors’
Compensation Policy, as amended
|
|
|
10(b)
|
Supplemental
Income Security Plan, as amended and restated effective as of
January 1,
2005
|
|
|
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
|
|
|
(1)
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K.
MDU
Resources Group, Inc. hereby undertakes to furnish supplementally copies
of any
of the omitted schedules upon request by the SEC.
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.
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.
|
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MDU
RESOURCES GROUP, INC.
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DATE:
August
4, 2006
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BY:
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/s/
Vernon A. Raile
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Vernon
A. Raile
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Executive
Vice President, Treasurer
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and
Chief Financial Officer
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BY:
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/s/
Doran N. Schwartz
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Doran
N. Schwartz
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Vice
President and Chief Accounting
Officer
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EXHIBIT
INDEX
Exhibit
No.
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2
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Agreement
and Plan of Merger by and among MDU Resources Group, Inc., Firemoon
Acquisition, Inc. and Cascade Natural Gas Corporation dated as
of July 8,
2006, filed by Cascade Natural Gas Corporation as Exhibit 2.1
to Form 8-K
dated July 10, 2006, in File No. 1-7196. (1)
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3
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Company
Bylaws, as amended
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4(a)
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Letter
Amendment No. 1 to Amended and Restated Master Shelf Agreement,
dated May
17, 2006, among Centennial Energy Holdings, Inc., The Prudential
Insurance
Company of America, and certain investors described in the Letter
Amendment
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4(b)
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First
Amendment, dated June 30, 2006, to Credit Agreement, dated June
21, 2005,
among MDU Resources Group, Inc., Wells Fargo Bank, National Association,
as administrative agent, and certain lenders described in the
credit
agreement amendment
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4(c)
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Certificate
of Adjustment to Purchase Price and Redemption Price, as amended
and
restated, pursuant to the Rights Agreement, dated as of November
12, 1998,
between MDU Resources Group, Inc. and Wells Fargo Bank, N.A.,
Rights
Agent
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10(a)
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Directors’
Compensation Policy, as amended
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10(b)
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Supplemental
Income Security Plan, as amended and restated effective as of
January 1,
2005
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12
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Computation
of Ratio of Earnings to Fixed Charges and Combined Fixed Charges
and
Preferred Stock Dividends
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31(a)
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Certification
of Chief Executive Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
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31(b)
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Certification
of Chief Financial Officer filed pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
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32
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Certification
of Chief Executive Officer and Chief Financial Officer furnished
pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
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(1)
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K.
MDU
Resources Group, Inc. hereby undertakes to furnish supplementally copies
of any
of the omitted schedules upon request by the SEC.
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.