MDU Resources' 1st Quarter 10-Q
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
X
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
|
|
|
THE
SECURITIES EXCHANGE ACT OF 1934
|
|
For
The Quarterly Period Ended March 31, 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 May 1, 2006:
119,968,568 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
|
Bcfe
|
Billion
cubic feet equivalent
|
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
|
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
|
Great
Plains
|
Great
Plains Natural Gas Co., a public utility division of the
Company
|
Grynberg
|
Jack
J. Grynberg
|
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
|
MPUC
|
Minnesota
Public Utilities Commission
|
MPX
|
MPX
Termoceara Ltda.
|
MTPSC
|
Montana
Public Service Commission
|
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. 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 14.
INDEX
Part
I - Financial Information
|
|
|
|
Consolidated
Statements of Income -
Three
Months Ended March 31, 2006 and 2005
|
|
|
|
Consolidated
Balance Sheets -
March
31, 2006 and 2005, and December 31, 2005
|
|
|
|
Consolidated
Statements of Cash Flows -
Three
Months Ended March 31, 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
|
|
|
|
Submission of Matters to a Vote of Security Holders
|
|
|
|
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
March
31,
|
|
|
2006
|
|
2005
|
|
(In
thousands, except
per
share amounts)
|
Operating
revenues:
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
$
|
291,561
|
|
$
|
255,373
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
523,733
|
|
|
348,922
|
|
|
|
815,294
|
|
|
604,295
|
Operating
expenses:
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
16,373
|
|
|
16,186
|
Purchased
natural gas sold
|
|
|
126,960
|
|
|
113,499
|
Operation
and maintenance:
|
|
|
|
|
|
|
Electric,
natural gas distribution and pipeline and energy services
|
|
|
38,166
|
|
|
38,985
|
Construction
services, natural gas and oil production, construction materials
and
mining, independent power production and other
|
|
|
446,275
|
|
|
291,004
|
Depreciation,
depletion and amortization
|
|
|
63,377
|
|
|
52,839
|
Taxes,
other than income
|
|
|
33,042
|
|
|
26,669
|
|
|
|
724,193
|
|
|
539,182
|
Operating
income
|
|
|
91,101
|
|
|
65,113
|
|
|
|
|
|
|
|
Earnings
from equity method investments
|
|
|
3,202
|
|
|
1,314
|
|
|
|
|
|
|
|
Other
income
|
|
|
2,398
|
|
|
1,151
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
14,084
|
|
|
13,017
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
82,617
|
|
|
54,561
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
29,371
|
|
|
20,141
|
|
|
|
|
|
|
|
Net
income
|
|
|
53,246
|
|
|
34,420
|
|
|
|
|
|
|
|
Dividends
on preferred stocks
|
|
|
171
|
|
|
171
|
|
|
|
|
|
|
|
Earnings
on common stock
|
|
$
|
53,075
|
|
$
|
34,249
|
Earnings
per common share -- basic
|
|
$
|
.44
|
|
$
|
.29
|
Earnings
per common share -- diluted
|
|
$
|
.44
|
|
$
|
.29
|
Dividends
per common share
|
|
$
|
.19
|
|
$
|
.18
|
Weighted
average common shares outstanding -- basic
|
|
|
119,882
|
|
|
117,827
|
Weighted
average common shares outstanding -- diluted
|
|
|
120,610
|
|
|
118,773
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
CONSOLIDATED
BALANCE SHEETS
(Unaudited)
|
|
March
31,
2006
|
|
March
31,
2005
|
|
December
31,
2005
|
(In
thousands, except shares and per share amounts)
|
ASSETS
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
109,749
|
|
$
|
146,667
|
|
$
|
107,435
|
|
Receivables,
net
|
|
|
547,997
|
|
|
392,694
|
|
|
603,959
|
|
Inventories
|
|
|
172,481
|
|
|
133,916
|
|
|
172,201
|
|
Deferred
income taxes
|
|
|
10,286
|
|
|
10,151
|
|
|
9,062
|
|
Prepayments
and other current assets
|
|
|
72,961
|
|
|
58,190
|
|
|
40,539
|
|
|
|
|
913,474
|
|
|
741,618
|
|
|
933,196
|
|
Investments
|
|
|
103,404
|
|
|
119,508
|
|
|
98,217
|
|
Property,
plant and equipment
|
|
|
4,702,848
|
|
|
4,026,501
|
|
|
4,594,355
|
|
Less
accumulated depreciation, depletion and amortization
|
|
|
1,597,760
|
|
|
1,404,500
|
|
|
1,544,462
|
|
|
|
|
3,105,088
|
|
|
2,622,001
|
|
|
3,049,893
|
|
Deferred
charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
230,439
|
|
|
199,840
|
|
|
230,865
|
|
Other
intangible assets, net
|
|
|
17,869
|
|
|
16,003
|
|
|
19,059
|
|
Other
|
|
|
112,110
|
|
|
88,370
|
|
|
92,332
|
|
|
|
|
360,418
|
|
|
304,213
|
|
|
342,256
|
|
|
|
$
|
4,482,384
|
|
$
|
3,787,340
|
|
$
|
4,423,562
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt due within one year
|
|
$
|
101,707
|
|
$
|
46,827
|
|
$
|
101,758
|
|
Accounts
payable
|
|
|
231,374
|
|
|
169,501
|
|
|
269,021
|
|
Taxes
payable
|
|
|
61,592
|
|
|
51,265
|
|
|
50,533
|
|
Dividends
payable
|
|
|
22,964
|
|
|
21,482
|
|
|
22,951
|
|
Other
accrued liabilities
|
|
|
139,900
|
|
|
182,367
|
|
|
184,665
|
|
|
|
|
557,537
|
|
|
471,442
|
|
|
628,928
|
|
Long-term
debt
|
|
|
1,134,889
|
|
|
907,061
|
|
|
1,104,752
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
553,272
|
|
|
484,928
|
|
|
526,176
|
|
Other
liabilities
|
|
|
280,742
|
|
|
248,562
|
|
|
272,084
|
|
|
|
|
834,014
|
|
|
733,490
|
|
|
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 120,290,305 at March 31, 2006, 118,774,075
at
March 31, 2005 and 120,262,786 at December 31, 2005
|
|
|
120,290
|
|
|
118,774
|
|
|
120,263
|
|
Other
paid-in capital
|
|
|
913,026
|
|
|
866,306
|
|
|
909,006
|
|
Retained
earnings
|
|
|
914,899
|
|
|
711,954
|
|
|
884,795
|
|
Accumulated
other comprehensive loss
|
|
|
(3,645
|
)
|
|
(32,602
|
)
|
|
(33,816
|
)
|
Treasury
stock at cost - 359,281 shares
at
March 31, 2006 and December 31, 2005 and 375,855 shares at
March
31, 2005
|
|
|
(3,626)
|
|
|
(4,085
|
)
|
|
(3,626
|
)
|
Total
common stockholders’ equity
|
|
|
1,940,944
|
|
|
1,660,347
|
|
|
1,876,622
|
|
Total
stockholders’ equity
|
|
|
1,955,944
|
|
|
1,675,347
|
|
|
1,891,622
|
|
|
|
$
|
4,482,384
|
|
$
|
3,787,340
|
|
$
|
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)
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Operating
activities:
|
|
|
|
|
|
Net
income
|
|
$
|
53,246
|
|
$
|
34,420
|
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
63,377
|
|
|
52,839
|
|
Earnings,
net of distributions, from equity method investments
|
|
|
(1,017
|
)
|
|
288
|
|
Deferred
income taxes
|
|
|
6,595
|
|
|
(4,224
|
)
|
Changes
in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
Receivables
|
|
|
55,778
|
|
|
47,876
|
|
Inventories
|
|
|
(280
|
)
|
|
9,964
|
|
Other
current assets
|
|
|
(26,125
|
)
|
|
(17,046
|
)
|
Accounts
payable
|
|
|
(24,980
|
)
|
|
(15,492
|
)
|
Other
current liabilities
|
|
|
8,312
|
|
|
32,475
|
|
Other
noncurrent changes
|
|
|
(3,273
|
)
|
|
10,461
|
|
Net
cash provided by operating activities
|
|
|
131,633
|
|
|
151,561
|
|
|
|
|
|
|
|
|
|
Investing
activities:
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(136,895
|
)
|
|
(98,439
|
)
|
Acquisitions,
net of cash acquired
|
|
|
---
|
|
|
(52
|
)
|
Net
proceeds from sale or disposition of property
|
|
|
8,820
|
|
|
4,649
|
|
Investments
|
|
|
(4,408
|
)
|
|
1,092
|
|
Net
cash used in investing activities
|
|
|
(132,483
|
)
|
|
(92,750
|
)
|
|
|
|
|
|
|
|
|
Financing
activities:
|
|
|
|
|
|
|
|
Issuance
of long-term debt
|
|
|
113,006
|
|
|
70,996
|
|
Repayment
of long-term debt
|
|
|
(91,441
|
)
|
|
(62,596
|
)
|
Proceeds
from issuance of common stock
|
|
|
1,698
|
|
|
1,528
|
|
Dividends
paid
|
|
|
(22,950
|
)
|
|
(21,449
|
)
|
Tax
benefit on stock-based compensation
|
|
|
2,851
|
|
|
---
|
|
Net
cash provided by (used in) financing activities
|
|
|
3,164
|
|
|
(11,521
|
)
|
|
|
|
|
|
|
|
|
Increase
in cash and cash equivalents
|
|
|
2,314
|
|
|
47,290
|
|
Cash
and cash equivalents -- beginning of year
|
|
|
107,435
|
|
|
99,377
|
|
Cash
and cash equivalents -- end of period
|
|
$
|
109,749
|
|
$
|
146,667
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
MDU
RESOURCES GROUP, INC.
NOTES
TO CONSOLIDATED
FINANCIAL
STATEMENTS
March
31, 2006 and 2005
(Unaudited)
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.
|
Allowance
for doubtful accounts
|
The
Company's allowance for doubtful accounts as of March 31, 2006 and 2005,
and
December 31, 2005, was $8.0 million, $7.0 million and $8.0 million,
respectively.
4.
|
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 $4.7 million, $4.8 million and $24.7 million at March
31,
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 March 31, 2006 and 2005, and
December 31, 2005, respectively.
Inventories,
other than natural gas in underground storage for the Company’s regulated
operations, consisted primarily of aggregates held for resale of $89.3 million,
$78.2 million and $78.1 million; materials and supplies of $56.1 million,
$37.5
million and $48.7 million; and other inventories of $22.4 million, $13.4
million
and $20.7 million, as of March 31, 2006 and 2005, and December 31, 2005,
respectively. These inventories were stated at the lower of average cost
or
market.
6.
|
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 months ended March 31, 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.
7.
|
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 three months ended March 31, 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 months ended March 31, 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
|
|
|
|
March
31, 2005
|
|
(In
thousands, except per share amounts)
|
|
Earnings
on common stock, as reported
|
|
$
|
34,249
|
|
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
|
|
|
(37
|
)
|
Pro
forma earnings on common stock
|
|
$
|
34,216
|
|
Earnings
per common share - basic - as reported
|
|
$
|
.29
|
|
Earnings
per common share - basic - pro forma
|
|
$
|
.29
|
|
Earnings
per common share - diluted - as reported
|
|
$
|
.29
|
|
Earnings
per common share - diluted - pro forma
|
|
$
|
.29
|
|
Total
stock-based compensation expense for the three months ended March 31, 2006,
was
$781,000, net of income taxes of $500,000, including $71,000, net of income
taxes of $45,000, related to stock option awards.
As
of
March 31, 2006, total remaining unrecognized compensation expense related
to
stock-based compensation was approximately $8.5 million (before income taxes)
which will be amortized over a weighted-average period of 2.1
years.
The
Company is authorized to grant options, restricted stock and stock for up
to
12.7 million shares of common stock and has granted options, restricted stock
and stock on 5.8 million shares through March 31, 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 date of grant and three
years
after 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. There were no options granted during
the
three months ended March 31, 2006 and 2005.
A
summary
of the status of the stock option plans for the three months ended
March 31, 2006, was as follows:
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Weighted
|
|
Remaining
|
|
|
|
|
|
Average
|
|
Contractual
|
|
|
|
|
|
Exercise
|
|
Life
|
|
|
|
Shares
|
|
Price
|
|
In
Years
|
|
Outstanding
at beginning of period
|
|
|
1,857,982
|
|
$
|
19.48
|
|
|
|
|
Granted
|
|
|
---
|
|
|
---
|
|
|
|
|
Forfeited
|
|
|
(23,477
|
)
|
|
19.48
|
|
|
|
|
Exercised
|
|
|
(93,659
|
)
|
|
18.82
|
|
|
|
|
Outstanding
at end of period
|
|
|
1,740,846
|
|
|
19.52
|
|
|
4.6
|
|
Exercisable
at end of period
|
|
|
992,439
|
|
$
|
18.86
|
|
|
4.3
|
|
Summarized
information about stock options outstanding and exercisable as of March 31,
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)
|
|
$
8.22 - 13.00
|
|
|
6,750
|
|
|
1.3
|
|
$
|
10.92
|
|
$
|
152
|
|
|
6,750
|
|
$
|
10.92
|
|
$
|
152
|
|
13.01
- 17.00
|
|
|
216,010
|
|
|
2.2
|
|
|
14.36
|
|
|
4,124
|
|
|
213,364
|
|
|
14.36
|
|
|
4,074
|
|
17.01
- 21.00
|
|
|
1,348,256
|
|
|
4.9
|
|
|
19.76
|
|
|
18,454
|
|
|
711,190
|
|
|
19.77
|
|
|
9,727
|
|
21.01
- 25.70
|
|
|
169,830
|
|
|
4.9
|
|
|
24.48
|
|
|
1,523
|
|
|
61,135
|
|
|
24.81
|
|
|
528
|
|
Balance
at end of period
|
|
|
1,740,846
|
|
|
4.6
|
|
$
|
19.52
|
|
$
|
24,253
|
|
|
992,439
|
|
$
|
18.86
|
|
$
|
14,481
|
|
The
aggregate intrinsic value in the preceding table represents the total intrinsic
value (before income taxes), based on the Company’s stock price on March 31,
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 $1.7 million from the exercise of stock options
for the
three months ended March 31, 2006. The aggregate intrinsic value of options
exercised during the three months ended March 31, 2006, was $1.5
million.
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 three months ended
March 31, 2006, was as follows:
|
|
|
|
Weighted
|
|
|
|
Number
|
|
Average
|
|
|
|
of
|
|
Grant-Date
|
|
|
|
Shares
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
87,176
|
|
$
|
15.94
|
|
Granted
|
|
|
---
|
|
|
---
|
|
Vested
|
|
|
(51,404
|
)
|
|
13.24
|
|
Forfeited
|
|
|
(2,475
|
)
|
|
19.83
|
|
Nonvested
at end of period
|
|
|
33,297
|
|
$
|
19.83
|
|
The
fair
value of restricted stock awards that vested during the three months ended
March
31, 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 no shares issued under this plan for the three months ended March 31,
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 March 31, 2006, were as
follows:
Grant
Date
|
|
Performance
Period
|
|
|
|
February
2004
|
|
|
2004-2006
|
|
|
185,739
|
|
February
2005
|
|
|
2005-2007
|
|
|
189,016
|
|
February
2006
|
|
|
2006-2008
|
|
|
137,211
|
|
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 of the performance units 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 three months ended March 31, 2006, was $2.2 million.
A
summary
of the status of the performance share awards for the three months ended
March 31, 2006, was as follows:
|
|
|
|
Weighted
|
|
|
|
Number
|
|
Average
|
|
|
|
of
|
|
Grant-Date
|
|
|
|
Shares
|
|
Fair
Value
|
|
Nonvested
at beginning of period
|
|
|
422,850
|
|
$
|
24.47
|
|
Granted
|
|
|
144,647
|
|
|
34.37
|
|
Additional
performance shares earned
|
|
|
9,681
|
|
|
16.71
|
|
Vested
|
|
|
(63,861
|
)
|
|
16.71
|
|
Forfeited
|
|
|
(1,351
|
)
|
|
27.53
|
|
Nonvested
at end of period
|
|
|
511,966
|
|
$
|
28.08
|
|
Cash
expenditures for interest and income taxes were as follows:
|
|
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
(In
thousands)
|
|
Interest,
net of amount capitalized
|
|
|
|
|
$
|
12,332
|
|
|
|
|
$
|
4,839
|
|
|
|
|
Income
taxes
|
|
|
|
|
$
|
5,888
|
|
|
|
|
$
|
2,972
|
|
|
|
|
9.
|
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 7.
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.
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 13.
Comprehensive
income, and the components of other comprehensive income (loss) and related
tax
effects, were as follows:
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
|
|
|
$
|
53,246
|
|
|
|
|
$
|
34,420
|
|
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 $14,639 and $15,891 in 2006 and 2005, respectively
|
|
|
|
|
|
23,385
|
|
|
|
|
|
(25,384
|
)
|
Less:
Reclassification adjustment for loss on derivative instruments
included in
net income, net of tax of $4,249 and $2,734 in 2006 and 2005,
respectively
|
|
|
|
|
|
(6,787
|
)
|
|
|
|
|
(4,367
|
)
|
Net
unrealized gain (loss) on derivative instruments qualifying as
hedges
|
|
|
|
|
|
30,172
|
|
|
|
|
|
(21,017
|
)
|
Foreign
currency translation adjustment
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
(94
|
)
|
|
|
|
|
|
|
30,171
|
|
|
|
|
|
(21,111
|
)
|
Comprehensive
income
|
|
|
|
|
$
|
83,417
|
|
|
|
|
$
|
13,309
|
|
11.
|
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
March
31, 2006 and December 31, 2005, the Company’s equity method investments,
including Carib Power and Hartwell, had total assets of $233.1 million and
$231.9 million, respectively, and long-term debt of $154.8 million at each
date.
At March 31, 2005, MPX, Carib Power and Hartwell had total assets of $344.0
million and long-term debt of $217.2 million. The Company’s investment in its
equity method investments, including the Trinity and Hartwell Generating
Facilities, was approximately $43.0 million and $41.8 million, including
undistributed earnings of $4.5 million and $3.5 million, at March 31, 2006
and
December 31, 2005, respectively. The Company’s investment in the Termoceara,
Trinity and Hartwell Generating Facilities was approximately $65.4 million,
including undistributed earnings of $26.4 million, at March 31,
2005.
12.
|
Goodwill
and other intangible assets
|
The
changes in the carrying amount of goodwill were as follows:
|
|
Balance
|
|
Goodwill
|
|
Balance
|
|
|
|
|
|
as
of
|
|
Acquired
|
|
as
of
|
|
|
|
Three
Months Ended
|
|
January
1,
|
|
During
|
|
March
31,
|
|
|
|
March
31, 2006
|
|
2006
|
|
the
Year*
|
|
2006
|
|
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
|
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
|
|
Construction
services
|
|
|
80,970
|
|
|
137
|
|
|
81,107
|
|
|
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
|
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
|
|
Construction
materials and mining
|
|
|
133,264
|
|
|
(563
|
)
|
|
132,701
|
|
|
|
|
Independent
power production
|
|
|
11,167
|
|
|
---
|
|
|
11,167
|
|
|
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
|
|
Total
|
|
$
|
230,865
|
|
$
|
(426
|
)
|
$
|
230,439
|
|
|
|
|
|
|
Balance
|
|
Goodwill
|
|
Balance
|
|
|
|
|
|
as
of
|
|
Acquired
|
|
as
of
|
|
|
|
Three
Months Ended
|
|
January
1,
|
|
During
|
|
March
31,
|
|
|
|
March
31, 2005
|
|
2005
|
|
the
Year*
|
|
2005
|
|
|
|
|
|
(In
thousands)
|
|
Electric
|
|
$
|
---
|
|
$
|
---
|
|
$
|
---
|
|
|
|
|
Natural
gas distribution
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
|
|
Construction
services
|
|
|
62,632
|
|
|
6
|
|
|
62,638
|
|
|
|
|
Pipeline
and energy services
|
|
|
5,464
|
|
|
---
|
|
|
5,464
|
|
|
|
|
Natural
gas and oil production
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
|
|
Construction
materials and mining
|
|
|
120,452
|
|
|
---
|
|
|
120,452
|
|
|
|
|
Independent
power production
|
|
|
11,195
|
|
|
91
|
|
|
11,286
|
|
|
|
|
Other
|
|
|
---
|
|
|
---
|
|
|
---
|
|
|
|
|
Total
|
|
$
|
199,743
|
|
$
|
97
|
|
$
|
199,840
|
|
|
|
|
|
|
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:
|
|
March
31,
2006
|
|
March
31,
2005
|
|
December
31,
2005
|
|
|
|
(In
thousands)
|
|
Amortizable
intangible assets:
|
|
|
|
|
|
|
|
Acquired
contracts
|
|
$
|
15,990
|
|
$
|
14,936
|
|
$
|
18,065
|
|
Accumulated
amortization
|
|
|
(8,221
|
)
|
|
(5,690
|
)
|
|
(9,458
|
)
|
|
|
|
7,769
|
|
|
9,246
|
|
|
8,607
|
|
Noncompete
agreements
|
|
|
11,784
|
|
|
10,575
|
|
|
11,784
|
|
Accumulated
amortization
|
|
|
(8,680
|
)
|
|
(8,266
|
)
|
|
(8,557
|
)
|
|
|
|
3,104
|
|
|
2,309
|
|
|
3,227
|
|
Other
|
|
|
7,914
|
|
|
4,224
|
|
|
7,914
|
|
Accumulated
amortization
|
|
|
(1,442
|
)
|
|
(627
|
)
|
|
(1,213
|
)
|
|
|
|
6,472
|
|
|
3,597
|
|
|
6,701
|
|
Unamortizable
intangible assets
|
|
|
524
|
|
|
851
|
|
|
524
|
|
Total
|
|
$
|
17,869
|
|
$
|
16,003
|
|
$
|
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 months ended March
31,
2006 and 2005, and for the year ended December 31, 2005, was $1.2 million,
$864,000 and $5.5 million, respectively. Estimated amortization expense for
amortizable intangible assets is $3.5 million in 2006, $2.7 million in
2007, $2.6 million in 2008, $2.6 million in 2009, $2.2 million in 2010 and
$4.9 million thereafter.
13.
|
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.
As
of
March 31, 2006, Fidelity held derivative instruments designated as cash flow
hedging instruments.
Hedging
activities
Fidelity
utilizes natural gas and oil price swap and collar agreements to manage a
portion of the market risk associated with fluctuations in the price of natural
gas and oil on its forecasted sales of natural gas and oil production. Each
of
the 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 months ended March 31, 2006 and 2005, the amount of hedge ineffectiveness,
which was included in operating revenues, was immaterial. For the three months
ended March 31, 2006 and 2005, Fidelity did not exclude any components of
the derivative instruments’ gain or loss from the assessment of hedge
effectiveness and there were no reclassifications into earnings as a result
of
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 March 31, 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
21 months. The Company estimates that over the next 12 months, net gains
of
approximately $4.1 million (after tax) will be reclassified from accumulated
other comprehensive income into earnings, subject to changes in natural gas
and
oil market prices, as the hedged transactions affect earnings.
14.
|
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:
Three
Months
|
|
External
Operating
|
|
Operating
|
|
|
|
Ended
March 31, 2006
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Stock
|
|
Electric
|
|
$
|
45,030
|
|
$
|
---
|
|
$
|
3,797
|
|
Natural
gas distribution
|
|
|
152,279
|
|
|
---
|
|
|
5,321
|
|
Pipeline
and energy services
|
|
|
94,252
|
|
|
32,806
|
|
|
4,569
|
|
|
|
|
291,561
|
|
|
32,806
|
|
|
13,687
|
|
Construction
services
|
|
|
223,685
|
|
|
110
|
|
|
5,398
|
|
Natural
gas and oil production
|
|
|
55,098
|
|
|
73,292
|
|
|
41,258
|
|
Construction
materials and mining
|
|
|
233,684
|
|
|
---
|
|
|
(8,874
|
)
|
Independent
power production
|
|
|
11,266
|
|
|
---
|
|
|
1,342
|
|
Other
|
|
|
---
|
|
|
1,769
|
|
|
264
|
|
|
|
|
523,733
|
|
|
75,171
|
|
|
39,388
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(107,977
|
)
|
|
---
|
|
Total
|
|
$
|
815,294
|
|
$
|
---
|
|
$
|
53,075
|
|
|
|
|
|
Inter-
|
|
|
|
|
|
External
|
|
segment
|
|
Earnings
|
|
Three
Months
|
|
Operating
|
|
Operating
|
|
on
Common
|
|
Ended
March 31, 2005
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Stock
|
|
Electric
|
|
$
|
44,319
|
|
$
|
---
|
|
$
|
3,134
|
|
Natural
gas distribution
|
|
|
144,976
|
|
|
---
|
|
|
4,821
|
|
Pipeline
and energy services
|
|
|
66,078
|
|
|
26,748
|
|
|
3,227
|
|
|
|
|
255,373
|
|
|
26,748
|
|
|
11,182
|
|
Construction
services
|
|
|
113,708
|
|
|
152
|
|
|
1,958
|
|
Natural
gas and oil production
|
|
|
38,310
|
|
|
48,770
|
|
|
28,805
|
|
Construction
materials and mining
|
|
|
187,087
|
|
|
7
|
|
|
(8,536
|
)
|
Independent
power production
|
|
|
9,817
|
|
|
---
|
|
|
756
|
|
Other
|
|
|
---
|
|
|
1,367
|
|
|
84
|
|
|
|
|
348,922
|
|
|
50,296
|
|
|
23,067
|
|
Intersegment
eliminations
|
|
|
---
|
|
|
(77,044
|
)
|
|
---
|
|
Total
|
|
$
|
604,295
|
|
$
|
---
|
|
$
|
34,249
|
|
Earnings
from electric, natural gas distribution and pipeline and energy services
are
substantially all from regulated operations. Earnings (loss) from construction
services, natural gas and oil production, construction materials and mining,
independent power production, and other are all from nonregulated
operations.
15.
|
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
March 31,
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
Components
of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
2,301
|
|
$
|
2,047
|
|
$
|
471
|
|
$
|
485
|
|
Interest
cost
|
|
|
4,074
|
|
|
4,156
|
|
|
929
|
|
|
1,097
|
|
Expected
return on assets
|
|
|
(4,718
|
)
|
|
(4,910
|
)
|
|
(925
|
)
|
|
(983
|
)
|
Amortization
of prior service cost
|
|
|
256
|
|
|
256
|
|
|
11
|
|
|
---
|
|
Recognized
net actuarial (gain) loss
|
|
|
509
|
|
|
209
|
|
|
(84
|
)
|
|
(39
|
)
|
Amortization
of net transition obligation (asset)
|
|
|
(1
|
)
|
|
(11
|
)
|
|
531
|
|
|
538
|
|
Net
periodic benefit cost
|
|
|
2,421
|
|
|
1,747
|
|
|
933
|
|
|
1,098
|
|
Less
amount capitalized
|
|
|
156
|
|
|
172
|
|
|
46
|
|
|
91
|
|
Net
periodic benefit cost
|
|
$
|
2,265
|
|
$
|
1,575
|
|
$
|
887
|
|
$
|
1,007
|
|
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 months ended March 31, 2006 and 2005,
was $2.0 million and $1.9 million, respectively.
16.
|
Regulatory
matters and revenues subject to refund
|
|
In
September 2004, Great Plains filed an application with the MPUC for
a
natural gas rate increase. Great Plains had requested a total increase
of
$1.4 million annually or approximately 4.0 percent above current
rates.
Great Plains also requested an interim increase of $1.4 million annually.
In November 2004, the MPUC issued an Order authorizing an interim
increase
of $1.4 million annually effective with service rendered on or after
January 10, 2005, subject to refund. On May 1, 2006, the MPUC issued
an
Order, which is currently being evaluated by the Company.
|
A
liability has been provided for a portion of the revenues that have been
collected subject to refund with respect to Great Plains’ pending regulatory
proceeding. Great Plains believes that the liability is adequate based on its
assessment of the outcome of the proceeding.
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 filed 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. Williston Basin participated
in
a hearing before the ALJ in early January 2005, regarding those service and
annual demand quantity restrictions. In April 2005, the ALJ issued an Initial
Decision on the matters remanded by the FERC. In the Initial Decision, the
ALJ
decided that Williston Basin had not supported its position regarding the
service and annual demand quantity restrictions. In May 2005, Williston Basin
filed its Brief on Exceptions regarding these issues with the FERC, and its
Brief Opposing Exceptions to issues raised by a certain party to the proceeding.
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. In December 2005, Williston Basin filed its Request for Rehearing
of the FERC’s Order on Initial Decision. 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. Williston Basin is planning on appealing to the D.C.
Appeals Court certain issues addressed by these two FERC Orders.
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 grounds 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.
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 existing 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 as well as 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 allow Fidelity to continue its existing
coalbed natural gas operations without undue operational constraints 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 Montana
Twenty-Second Judicial District Court against the Montana DEQ seeking to set
aside the two permits. The tribe asserted that the Montana DEQ issued the
permits in violation of various federal and state environmental laws. In
particular, the tribe claimed that 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 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.
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, it appears that reservoir pressure has decreased and that quantities
of
gas may have been diverted by 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. Williston Basin is also assessing further avenues for
recovery through the regulatory process at the FERC. Because
of
the preliminary stage of the legal proceedings, Williston Basin cannot estimate
the size of any potential loss or recovery, or the likelihood of obtaining
injunctive relief or recovery through the regulatory process.
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 commercial property site, acquired by MBI
in
1999, and 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. The LWG estimates the overall remedial investigation
and feasibility study will cost approximately $10 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 years to complete. The development of a proposed plan
and record of decision on the harbor site is not anticipated to occur until
later in 2006, 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.,
the
seller of the commercial property site to MBI, that it intends to seek indemnity
for any and all liabilities incurred in relation to the above matters, pursuant
to the terms of the sale agreement under which MBI acquired the
property.
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 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.
In
addition, WBI Holdings has guaranteed certain of Fidelity's natural gas and
oil
price swap and collar agreement obligations. Fidelity's obligations at March
31,
2006, were $1.8 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 March 31, 2006, expire in 2006; 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 Sheets
at March 31, 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 and certain other guarantees. At
March
31, 2006, the fixed maximum amounts guaranteed under these agreements aggregated
$97.7 million. The amounts of scheduled expiration of the maximum amounts
guaranteed under these agreements aggregate $8.1 million in 2006; $39.0 million
in 2007; $300,000 in 2008; $1.8 million in 2009; $30.0 million in 2010; $12.0
million in 2012; $2.0 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 March 31, 2006,
has no
scheduled maturity date. The amount outstanding by subsidiaries of the Company
under the
above
guarantees was $530,000 and was reflected on the Consolidated Balance Sheets
at
March 31, 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 March 31, 2006, the fixed maximum amounts guaranteed under these
letters of credit aggregated $39.7 million. In 2006 and 2007, $11.1 million
and
$28.6 million, respectively, of letters of credit are scheduled to expire.
There
were no amounts outstanding under the above letters of credit at March 31,
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 March 31, 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
$1.7 million, which was not reflected on the Consolidated Balance Sheets at
March 31, 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 and lease obligations were reflected on the Consolidated
Balance Sheets at March 31, 2006.
As
of
March 31, 2006, Centennial was contingently liable for the performance of
certain of its subsidiaries under approximately $479 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 Sheets.
18.
|
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 were $55,000 and $1.0 million
for the three months ended March 31, 2006 and 2005, respectively, and are
estimated for the next three years to be $2.2 million in 2006, $3.3 million
in 2007 and $500,000 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 $386,000 and $252,000 for the three months ended
March 31, 2006 and 2005, respectively, and estimated revenues from these
contracts for the next three years are $2.7 million in 2006, $3.5 million in
2007 and $5.4 million in 2008. The amount due from Nance Petroleum at March
31,
2006, was $133,000.
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 for the three months ended March 31, 2006, were $1.9 million. The
amount due to Nance Petroleum at March 31, 2006, was $564,000.
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.
On
May 1,
2006, Fidelity acquired oil and natural gas properties located in the Big Horn
Basin of Wyoming. In total, Fidelity acquired 51 Bcfe of proven reserves of
which 45 percent is oil, 44 percent natural gas, and 11 percent natural gas
liquids. In addition, over 75 Bcfe of estimated probable and possible reserves
are associated with the acquired properties. The reserve life for these
properties is estimated at 15 to 20 years. The purchase price for these
properties is approximately $88.5 million, or $1.74 per Mcf equivalent of
proven reserves, subject to accounting and purchase price adjustments customary
for oil and natural gas acquisitions of this type. A portion of the
purchase price is attributable to the substantial value associated with the
estimated 75 Bcfe of probable and possible reserves identified with these
properties. Additional future consideration may be paid to the seller if certain
production targets are met. The effective date of this purchase is March 1,
2006.
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 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 level of energy-related services.
Challenges Both
segments are subject to extensive regulation in the state jurisdictions where
they conduct operations with respect to costs and permitted returns on
investment as well as subject to certain operational regulations at the federal
level. The ability of these segments to grow through acquisitions is subject
to
significant competition from other energy providers. In addition, as to the
electric business, the ability of this segment to grow its service territory
and
customer base is affected by significant competition from other energy
providers, including rural electric cooperatives.
Construction
Services
Strategy
Provide
a competitive return on investment while operating in a competitive industry
by:
building new and strengthening existing customer relationships;
effectively controlling costs; recruiting,
developing and retaining talented employees; focusing business development
efforts on project areas that will permit higher margins; and properly managing
risk. This segment continuously seeks opportunities to expand through strategic
acquisitions.
Challenges
This
segment operates in highly competitive markets, with many jobs subject to
competitive bidding. Maintenance of effective 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 price 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; 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. The segment’s key
focus is on increasing margins and profitability 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
March
31,
|
|
|
|
2006
|
|
2005
|
|
(Dollars
in millions, where applicable)
|
|
Electric
|
|
$
|
3.8
|
|
$
|
3.1
|
|
Natural
gas distribution
|
|
|
5.3
|
|
|
4.8
|
|
Construction
services
|
|
|
5.4
|
|
|
2.0
|
|
Pipeline
and energy services
|
|
|
4.6
|
|
|
3.2
|
|
Natural
gas and oil production
|
|
|
41.3
|
|
|
28.8
|
|
Construction
materials and mining
|
|
|
(8.9
|
)
|
|
(8.5
|
)
|
Independent
power production
|
|
|
1.3
|
|
|
.7
|
|
Other
|
|
|
.3
|
|
|
.1
|
|
Earnings
on common stock
|
|
$
|
53.1
|
|
$
|
34.2
|
|
Earnings
per common share - basic
|
|
$
|
.44
|
|
$
|
.29
|
|
Earnings
per common share - diluted
|
|
$
|
.44
|
|
$
|
.29
|
|
Return
on average common equity for the 12 months ended
|
|
|
16.2
|
%
|
|
13.5
|
%
|
Three
Months Ended March 31, 2006 and 2005 Consolidated
earnings for the quarter ended March 31, 2006, increased $18.9 million from
the
comparable prior period largely due to:
· |
Higher
average realized natural gas prices of 37 percent, increased natural
gas
production of 6 percent and oil production of 23 percent, as well
as
higher average realized oil prices of 18 percent, partially offset
by
higher lease operating expenses and higher depreciation, depletion
and
amortization at the natural gas and oil production
business
|
· |
Higher
inside construction workloads and margins in all regions, as well
as
earnings from acquisitions made since the first quarter of 2005 at
the
construction 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
March
31,
|
|
|
|
2006
|
|
2005
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues
|
|
$
|
45.0
|
|
$
|
44.3
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
16.1
|
|
|
16.2
|
|
Operation
and maintenance
|
|
|
14.0
|
|
|
13.8
|
|
Depreciation,
depletion and amortization
|
|
|
5.3
|
|
|
5.1
|
|
Taxes,
other than income
|
|
|
2.2
|
|
|
2.3
|
|
|
|
|
37.6
|
|
|
37.4
|
|
Operating
income
|
|
|
7.4
|
|
|
6.9
|
|
Earnings
|
|
$
|
3.8
|
|
$
|
3.1
|
|
Retail
sales (million kWh)
|
|
|
612.9
|
|
|
604.5
|
|
Sales
for resale (million kWh)
|
|
|
166.4
|
|
|
198.0
|
|
Average
cost of fuel and purchased power per kWh
|
|
$
|
.020
|
|
$
|
.019
|
|
Three
Months Ended March 31, 2006 and 2005 Electric
earnings increased $700,000 due to:
· |
Higher
retail sales margins, largely the result of the timing of fuel and
purchased power costs and slightly higher sales
volumes
|
· |
Decreased
net interest expense of $200,000 (after tax) resulting from lower
average
interest rates
|
The
increase was partially offset by a decrease in sales for resale margins,
primarily the result of lower average rates of 17 percent and decreased volumes
of 16 percent.
Natural
Gas Distribution
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
Sales
|
|
$
|
151.2
|
|
$
|
143.6
|
|
Transportation
and other
|
|
|
1.1
|
|
|
1.3
|
|
|
|
|
152.3
|
|
|
144.9
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
128.4
|
|
|
120.5
|
|
Operation
and maintenance
|
|
|
11.8
|
|
|
11.9
|
|
Depreciation,
depletion and amortization
|
|
|
2.4
|
|
|
2.4
|
|
Taxes,
other than income
|
|
|
1.5
|
|
|
1.6
|
|
|
|
|
144.1
|
|
|
136.4
|
|
Operating
income
|
|
|
8.2
|
|
|
8.5
|
|
Earnings
|
|
$
|
5.3
|
|
$
|
4.8
|
|
Volumes
(MMdk):
|
|
|
|
|
|
|
|
Sales
|
|
|
14.2
|
|
|
15.8
|
|
Transportation
|
|
|
4.4
|
|
|
4.0
|
|
Total
throughput
|
|
|
18.6
|
|
|
19.8
|
|
Degree
days (% of normal)*
|
|
|
85
|
%
|
|
93
|
%
|
Average
cost of natural gas, including transportation, per
dk
|
|
$
|
9.01
|
|
$
|
7.61
|
|
*
Degree
days are a measure of the daily temperature-related demand for energy
for
heating.
|
Three
Months Ended March 31, 2006 and 2005 Earnings
at the natural gas distribution business increased $500,000, largely the result
of higher nonregulated earnings from energy-related services. The increase
was
partially offset by a decrease in retail sales margins largely due to lower
sales volumes of 10 percent, resulting from 9 percent warmer weather than
last year.
Construction
Services
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Operating
revenues
|
|
$
|
223.8
|
|
$
|
113.9
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
202.8
|
|
|
101.2
|
|
Depreciation,
depletion and amortization
|
|
|
3.5
|
|
|
2.7
|
|
Taxes,
other than income
|
|
|
7.4
|
|
|
5.8
|
|
|
|
|
213.7
|
|
|
109.7
|
|
Operating
income
|
|
|
10.1
|
|
|
4.2
|
|
Earnings
|
|
$
|
5.4
|
|
$
|
2.0
|
|
Three
Months Ended March 31, 2006 and 2005 Construction
services earnings increased $3.4 million compared to the first quarter of
the comparable prior period due to:
· |
Higher
inside construction workloads and margins in all regions of $2.4
million
(after tax), reflecting higher construction
activity
|
· |
Earnings
from acquisitions made since the first quarter of 2005, which contributed
approximately 62 percent of the earnings
increase
|
· |
Increased
equipment sales and rentals
|
Partially
offsetting the increase were:
· |
Decreased
outside construction margins of $800,000 (after tax), largely in
the
Northwest and Central regions, offset in part by increases in the
Southwest region
|
· |
Higher
general and administrative expenses of $800,000 (after
tax)
|
Pipeline
and Energy Services
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues:
|
|
|
|
|
|
Pipeline
|
|
$
|
20.7
|
|
$
|
19.7
|
|
Energy
services
|
|
|
106.3
|
|
|
73.1
|
|
|
|
|
127.0
|
|
|
92.8
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
97.8
|
|
|
65.5
|
|
Operation
and maintenance
|
|
|
12.4
|
|
|
13.3
|
|
Depreciation,
depletion and amortization
|
|
|
5.0
|
|
|
4.7
|
|
Taxes,
other than income
|
|
|
2.5
|
|
|
2.0
|
|
|
|
|
117.7
|
|
|
85.5
|
|
Operating
income
|
|
|
9.3
|
|
|
7.3
|
|
Earnings
|
|
$
|
4.6
|
|
$
|
3.2
|
|
Transportation
volumes (MMdk):
|
|
|
|
|
|
|
|
Montana-Dakota
|
|
|
8.0
|
|
|
7.7
|
|
Other
|
|
|
18.1
|
|
|
13.9
|
|
|
|
|
26.1
|
|
|
21.6
|
|
Gathering
volumes (MMdk)
|
|
|
21.7
|
|
|
20.0
|
|
Three
Months Ended March 31, 2006 and 2005
Pipeline
and energy services experienced an increase in earnings of $1.4 million due
to:
· |
Higher
transportation and gathering volumes of $1.1 million (after
tax)
|
· |
Higher
gathering rates of $1.0 million (after
tax)
|
Partially
offsetting the increase in earnings were higher operating expenses, primarily
higher property taxes and increased depreciation expense.
Natural
Gas and Oil Production
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
(Dollars
in millions, where applicable)
|
|
Operating
revenues:
|
|
|
|
|
|
Natural
gas
|
|
$
|
105.4
|
|
$
|
72.4
|
|
Oil
|
|
|
21.0
|
|
|
14.6
|
|
Other
|
|
|
2.0
|
|
|
.1
|
|
|
|
|
128.4
|
|
|
87.1
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Purchased
natural gas sold
|
|
|
2.0
|
|
|
.1
|
|
Operation
and maintenance:
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
|
11.9
|
|
|
7.9
|
|
Gathering
and transportation
|
|
|
4.7
|
|
|
2.8
|
|
Other
|
|
|
7.4
|
|
|
5.5
|
|
Depreciation,
depletion and amortization
|
|
|
24.5
|
|
|
17.2
|
|
Taxes,
other than income:
|
|
|
|
|
|
|
|
Production
and property taxes
|
|
|
9.9
|
|
|
5.9
|
|
Other
|
|
|
.2
|
|
|
.2
|
|
|
|
|
60.6
|
|
|
39.6
|
|
Operating
income
|
|
|
67.8
|
|
|
47.5
|
|
Earnings
|
|
$
|
41.3
|
|
$
|
28.8
|
|
Production:
|
|
|
|
|
|
|
|
Natural
gas (MMcf)
|
|
|
15,362
|
|
|
14,427
|
|
Oil
(MBbls)
|
|
|
450
|
|
|
367
|
|
Average
realized prices (including hedges):
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
6.86
|
|
$
|
5.02
|
|
Oil
(per barrel)
|
|
$
|
46.71
|
|
$
|
39.68
|
|
Average
realized prices (excluding hedges):
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
6.90
|
|
$
|
5.02
|
|
Oil
(per barrel)
|
|
$
|
47.65
|
|
$
|
44.11
|
|
Production
costs, including taxes, per net equivalent Mcf:
|
|
|
|
|
|
|
|
Lease
operating costs
|
|
$
|
.66
|
|
$
|
.47
|
|
Gathering
and transportation
|
|
|
.26
|
|
|
.17
|
|
Production
and property taxes
|
|
|
.55
|
|
|
.36
|
|
|
|
$
|
1.47
|
|
$
|
1.00
|
|
Three
Months Ended March 31, 2006 and 2005
The
natural gas and oil production business experienced a $12.5 million increase
in
earnings due to:
· |
Higher
average realized natural gas prices of 37
percent
|
· |
Increased
natural gas production of 6 percent and oil production of 23 percent,
due
largely to increased production in the Rocky Mountain region as well
as
the May 2005 South Texas acquisition
|
· |
Higher
average realized oil prices of 18
percent
|
Partially
offsetting the increase were:
· |
Higher
depreciation, depletion and amortization of $4.5 million (after tax)
due
to higher rates and increased
production
|
· |
Higher
lease operating expenses of $3.6 million (after tax), due in part
to the
May 2005 South Texas acquisition
|
· |
Increased
general and administrative expense of $1.2 million (after tax), including
higher outside service fees and payroll-related
expenses
|
Construction
Materials and Mining
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
233.7
|
|
$
|
187.1
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
215.7
|
|
|
170.4
|
|
Depreciation,
depletion and amortization
|
|
|
20.1
|
|
|
18.1
|
|
Taxes,
other than income
|
|
|
8.4
|
|
|
8.1
|
|
|
|
|
244.2
|
|
|
196.6
|
|
Operating
loss
|
|
|
(10.5
|
)
|
|
(9.5
|
)
|
Loss
|
|
$
|
(8.9
|
)
|
$
|
(8.5
|
)
|
Sales
(000's):
|
|
|
|
|
|
|
|
Aggregates
(tons)
|
|
|
6,084
|
|
|
5,906
|
|
Asphalt
(tons)
|
|
|
333
|
|
|
361
|
|
Ready-mixed
concrete (cubic yards)
|
|
|
711
|
|
|
660
|
|
Three
Months Ended March 31, 2006 and 2005
Construction materials and mining experienced a normal seasonal first quarter
loss of $8.9 million. The seasonal loss increased by $400,000 from
$8.5 million in 2005. The increased seasonal loss was due to operating
losses from companies acquired since the comparable prior period largely offset
by improvements from existing operations of $1.5 million. The improvements
at
existing operations were due to higher realized ready-mixed concrete prices;
increased construction margins due to increased construction activity; and
increased aggregate margins, the result of higher volumes.
Independent
Power Production
|
|
Three
Months Ended
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(Dollars
in millions)
|
|
Operating
revenues
|
|
$
|
11.3
|
|
$
|
9.8
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
Fuel
and purchased power
|
|
|
.3
|
|
|
---
|
|
Operation
and maintenance
|
|
|
9.2
|
|
|
6.4
|
|
Depreciation,
depletion and amortization
|
|
|
2.4
|
|
|
2.5
|
|
Taxes,
other than income
|
|
|
.9
|
|
|
.7
|
|
|
|
|
12.8
|
|
|
9.6
|
|
Operating
income (loss)
|
|
|
(1.5
|
)
|
|
.2
|
|
Earnings
|
|
$
|
1.3
|
|
$
|
.7
|
|
Net
generation capacity (kW)*
|
|
|
389,600
|
|
|
279,600
|
|
Electricity
produced and sold (thousand kWh)*
|
|
|
88,497
|
|
|
37,250
|
|
*
Excludes equity method investments.
|
|
|
|
|
|
|
|
Three
Months Ended March 31, 2006 and 2005
Earnings
at the independent power production business increased $600,000 largely due
to:
· |
Higher
earnings from equity method investments which
reflect:
|
- |
A
one-time benefit due to a tax rate reduction, which affected the
segment’s
generating facility located in
Trinidad
|
- |
Absence
in 2006 of expenses incurred at the Termoceara Generating Facility
of
$600,000 (after tax), which was sold in June of
2005
|
The
increase was offset in part by lower margins of $800,000 (after tax) related
to
a domestic electric generating facility due primarily 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
March
31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
millions)
|
|
Other:
|
|
|
|
|
|
Operating
revenues
|
|
$
|
1.8
|
|
$
|
1.4
|
|
Operation
and maintenance
|
|
|
1.3
|
|
|
1.2
|
|
Depreciation,
depletion and amortization
|
|
|
.2
|
|
|
.1
|
|
Taxes,
other than income
|
|
|
---
|
|
|
.1
|
|
Intersegment
transactions:
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
108.0
|
|
$
|
77.0
|
|
Purchased
natural gas sold
|
|
|
101.2
|
|
|
72.6
|
|
Operation
and maintenance
|
|
|
6.8
|
|
|
4.4
|
|
For
further information on intersegment eliminations, see Note 14.
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
$2.15 to
$2.35, an increase from prior guidance of $2.00 to
$2.20.
|
· |
The
Company expects the percentage of 2006 earnings per common share,
diluted,
by quarter to be in the following approximate
ranges:
|
o |
Second
quarter - 20 percent to 25 percent
|
o |
Third
quarter - 30 percent to 35 percent
|
o |
Fourth
quarter - 25 percent to 30 percent
|
· |
The
Company’s long-term compound annual growth goals on earnings per share are
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.
|
· |
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 MPUC requesting
an increase of $1.4 million annually, or approximately 4.0 percent.
For
further information, see Note 16.
|
· |
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 March 31, 2006, the MTPSC has not
issued
a final order relative to the last three years of monthly gas cost
changes
that were implemented on an interim basis. A proceeding is under
way and a
final ruling 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 higher than 2005 record
levels.
|
· |
The
Company anticipates margins to strengthen in 2006 as compared to
2005
levels.
|
· |
Work
backlog as of March 31, 2006, was approximately $439 million including
acquisitions, compared to $226 million at March 31,
2005.
|
Pipeline
and energy services
· |
Firm
capacity for the Grasslands Pipeline is 90,000 Mcf per day with expansion
possible to 200,000 Mcf per day. Based on anticipated demand, incremental
expansions are forecasted over the next few years beginning as early
as
2007.
|
· |
In
2006, total gathering and transportation throughput is expected to
increase approximately 5 percent over 2005
levels.
|
Natural
gas and oil production
· |
The
Company’s long-term compound annual growth goals for production are in the
range of 7 percent to 10 percent. In 2006, the Company expects to
exceed
the upper end of this range. These estimates exclude production from
the
recent acquisition of oil and natural gas properties located in the
Big
Horn Basin of Wyoming.
|
· |
The
Company is expecting to drill more than 300 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. These items
exclude production from the recent acquisition of oil and natural
gas
properties located in the Big Horn Basin of
Wyoming.
|
· |
Estimates
of natural gas prices in the Rocky Mountain region for May through
December 2006 reflected in the Company’s 2006 earnings guidance are in the
range of $5.50 to $6.00 per Mcf. The Company’s estimates for natural gas
prices on the NYMEX for May through December 2006, 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 May through December 2006, reflected
in the
Company’s 2006 earnings guidance, are projected in the range of $55 to $60
per barrel.
|
· |
The
Company has hedged approximately 30 percent to 35 percent of its
estimated
natural gas production and 20 percent to 25 percent of its estimated
oil
production for the last nine months of 2006. For 2007, the Company
has
hedged approximately 10 percent to 15 percent of its estimated natural
gas
production. These items exclude production from the recent acquisition
of
oil and natural gas properties located in the Big Horn Basin of Wyoming.
The hedges that are in place as of May 1, 2006, for 2006 and 2007
are
summarized in the following chart:
|
Commodity
|
Index*
|
Period
Outstanding
|
Forward
Notional Volume
(MMBtu)/(Bbl)
|
Price
Swap or
Costless
Collar
Floor-Ceiling
(Per
MMBtu/Bbl)
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
1,375,000
|
$6.00-$7.60
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
2,750,000
|
$6.655
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
1,375,000
|
$6.75-$7.71
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
1,375,000
|
$6.75-$7.77
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
1,375,000
|
$7.00-$8.85
|
Natural
Gas
|
NYMEX
|
4/06
- 12/06
|
1,375,000
|
$7.75-$8.50
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
1,375,000
|
$7.76
|
Natural
Gas
|
CIG
|
4/06
- 12/06
|
1,375,000
|
$6.50-$6.98
|
Natural
Gas
|
CIG
|
4/06
- 12/06
|
1,375,000
|
$7.00-$8.87
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
687,500
|
$8.50-$10.00
|
Natural
Gas
|
Ventura
|
4/06
- 12/06
|
687,500
|
$8.50-$10.15
|
Natural
Gas
|
Ventura
|
4/06
- 10/06
|
1,070,000
|
$9.25-$12.88
|
Natural
Gas
|
Ventura
|
4/06
- 10/06
|
1,070,000
|
$9.25-$12.80
|
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
|
Crude
Oil
|
NYMEX
|
4/06
- 12/06
|
137,500
|
$43.00-$54.15
|
Crude
Oil
|
NYMEX
|
4/06
- 12/06
|
110,000
|
$60.00-$69.20
|
Crude
Oil
|
NYMEX
|
4/06
- 12/06
|
68,750
|
$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, aggregate and asphalt volumes for 2006 are expected to
be higher
than the record levels achieved in 2005.
|
· |
Work
backlog as of March 31, 2006, was approximately $610 million including
acquisitions, compared to $527 million at March 31,
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, etc.), 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.
|
· |
Five
of the labor contracts that Knife River was negotiating, as reported
in
Items 1 and 2 - Business and Properties - General in the Company’s 2005
Annual Report remain in negotiations. Two have been
ratified.
|
Independent
power production
· |
Earnings
at this segment are expected to be minimal in 2006, primarily reflecting
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
Hardin Generating Facility was placed into commercial operation in
March
2006 at a competitive construction cost and has demonstrated an output
above 120 MW gross through the successful design, construction and
operation of the plant. All electricity generated by the plant is
sold to
Powerex Corp. (a wholly owned subsidiary of BC Hydro) under a power
purchase agreement expiring October 31, 2008, with the purchaser
having an
option for a two-year extension.
|
· |
This
segment continues to explore opportunities for investments both
domestically and internationally, using the corporation’s disciplined
approach for acquisitions. The Company is focused on redeploying
the funds
from the June 2005 sale of the Brazilian facility into strategic
assets.
|
NEW
ACCOUNTING STANDARDS
For
information regarding new accounting standards, see Note 9, 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
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 three months
of
2006 decreased
$19.9 million from the comparable 2005 period, reflecting the result of
increased working capital requirements of $45.1 million, largely at the
following businesses:
· |
Natural
gas distribution, due largely to timing of natural gas costs recoverable
through rate adjustments and higher natural gas
costs
|
· |
Construction
services, primarily due to higher receivables reflecting increased
construction activity
|
· |
Construction
materials and mining, due in part to higher asphalt oil and fuel
inventories in preparation for the upcoming construction
season
|
Partially
offsetting the decrease in cash flows from operating activities
were:
· |
Increased
net income of $18.9 million, largely increased earnings at the natural
gas
and oil production, construction services and pipeline and energy
services
businesses
|
· |
Higher
deferred income taxes of $10.8 million, primarily related to natural
gas
costs recoverable through rate adjustments and costs associated with
the
redemption 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
|
· |
Higher
depreciation, depletion and amortization expense of $10.6 million,
largely
at the natural gas and oil production business, as previously
discussed
|
Investing
activities Cash
flows used in investing activities in the first three months of 2006 increased
$39.7 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 in South Texas, and higher ongoing capital
expenditures at the construction materials and mining business.
Financing
activities Cash
flows provided by financing activities in the first three months of 2006
increased $14.7 million compared to the comparable 2005 period, primarily the
result of an increase in the issuance of long-term debt of $42.0 million,
partially offset by an increase in the repayment of long-term debt of $28.8
million.
Defined
benefit pension plans
There
are
no material changes to the Company’s qualified noncontributory defined benefit
pension plans (Pension Plans) from those reported in the 2005 Annual Report.
For
further information on the Company’s Pension Plans, see Note 15.
Capital
expenditures
Net
capital expenditures for the first three months of 2006 were $115.5 million
and
are estimated to be approximately $620 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
22 percent of estimated 2006 net capital expenditures are associated with
completed acquisitions, including the acquisition discussed in Note 19. 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 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 March 31, 2006.
MDU
Resources Group, Inc. The
Company has a revolving credit agreement with various banks totaling $100
million (with provision for an increase, at the option of the Company on stated
conditions, up to a maximum of $125 million). There were no amounts outstanding
under the credit agreement at March 31, 2006. The credit agreement supports
the
Company’s $100 million commercial paper program. Under the Company’s
commercial paper program, $98.0 million was outstanding at March 31, 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
2010). 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.
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 $147,000 (after tax) based
on
March 31, 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 March 31,
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 March 31, 2006, the Company could have
issued approximately $433 million of additional first mortgage
bonds.
The
Company's coverage of fixed charges including preferred dividends was 6.2 times
and 6.1 times for the 12 months ended March 31, 2006 and December 31, 2005,
respectively. Additionally, the Company's first mortgage bond interest coverage
was 26.3 times and 10.2 times for the 12 months ended March 31, 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 63 percent
at both March 31, 2006 and December 31, 2005.
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 March 31, 2006,
the Company repurchased $68.0 million of first mortgage bonds. As of March
31,
2006, the Company had $57.0 million of first mortgage bonds outstanding, $30
million of which were held by the Indenture trustee for the benefit of the
Senior Note holders. At such time as the aggregate principal amount of the
Company’s outstanding first mortgage bonds, other than those held by the
Indenture trustee, is $20 million or less, the Company would have the ability,
subject to satisfying certain specified conditions, to require that any debt
issued under its Indenture, 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
March 31, 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).
Centennial
Energy Holdings, Inc.
Centennial has three revolving credit agreements with various banks and
institutions totaling $441.4 million with certain provisions allowing for
increased borrowings. These credit agreements support Centennial’s
$400 million (previously $350 million) commercial paper program. There were
no outstanding borrowings under the Centennial credit agreements at March 31,
2006. Under the Centennial commercial paper program, $185.5 million was
outstanding at March 31, 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 $21.4 million and expires on
April 30, 2007. Pursuant to this credit agreement, on the last business day
of
April 2006, the line of credit will be reduced by $3.6 million. 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,
which was effective on January 27, 2006, and may be terminated by the bank
at
any time. As of March 31, 2006, $39.7 million of letters of credit were
outstanding, as discussed in Note 17, of which $24.4 million were outstanding
under the above credit agreements that reduced amounts available under these
agreements.
Centennial
has an uncommitted long-term master shelf agreement that allows for borrowings
of up to $450 million. Under the terms of the master shelf agreement, $447.5
million was outstanding at March 31, 2006. The ability to request additional
borrowings under this master shelf agreement expires in April 2008. 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 $278,000 (after tax) based on March 31, 2006, variable
rate borrowings. Based on Centennial’s overall interest rate exposure at March
31, 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 $21.4
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 $21.4 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 March 31, 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,
$55.0 million was outstanding at March 31, 2006. The ability to request
additional borrowings under this master shelf agreement expires on December
20,
2007.
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 March 31, 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
There
are
no material changes in the Company’s contractual obligations relating to
long-term debt from those reported in the 2005 Annual Report.
The
Company’s contractual obligations relating to operating leases at March 31,
2006, increased $13.9 million or 23 percent from December 31, 2005. Contractual
obligations relating to purchase commitments at March 31, 2006, were $808.1
million compared to purchase commitments of $935.0 million at December 31,
2005,
a decrease of 14 percent. At March 31, 2006, the Company’s contractual
obligations related to operating leases and purchase commitments (for the twelve
months ended March 31, of each year listed in the table below) were as
follows:
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
|
Total
|
|
|
|
(In
millions)
|
|
Operating
leases
|
|
$
|
14.5
|
|
$
|
10.2
|
|
$
|
8.3
|
|
$
|
7.0
|
|
$
|
5.7
|
|
$
|
27.6
|
|
$
|
73.3
|
|
Purchase
commitments
|
|
|
257.3
|
|
|
108.4
|
|
|
61.8
|
|
|
56.8
|
|
|
55.8
|
|
|
268.0
|
|
|
808.1
|
|
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 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. For
more
information on commodity price risk, see Part II, Item 7A in the 2005 Annual
Report, and Notes 10 and 13.
The
following table summarizes hedge agreements entered into by Fidelity as of
March
31, 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
|
|
|
4,125
|
|
$
|
(406
|
)
|
Natural
gas swap agreements maturing in 2007
|
|
$
|
7.40
|
|
|
3,650
|
|
$
|
(680
|
)
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
MMBtu)
|
|
Forward
Notional
Volume
(In
MMBtu's)
|
|
Fair
Value
|
|
Natural
gas collar agreements maturing in 2006
|
|
$
|
7.39/$9.04
|
|
|
13,140
|
|
$
|
9,394
|
|
Natural
gas collar agreements maturing in 2007
|
|
$
|
7.83/$11.41
|
|
|
5,475
|
|
$
|
1,168
|
|
|
|
Weighted
Average
Floor/Ceiling
Price
(Per
barrel)
|
|
Forward
Notional
Volume
(In
barrels)
|
|
Fair
Value
|
|
Oil
collar agreements maturing in 2006
|
|
$
|
52.61/$64.31
|
|
|
316
|
|
$
|
(2,435
|
)
|
|
|
|
|
|
|
|
|
|
|
|
For
further information on Fidelity’s natural gas and oil price swap and collar
agreements, see Note 13.
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.
Foreign
currency risk
The
Company’s investment in the Termoceara Generating Facility was sold in June 2005
as discussed in Note 11 and, as a result, the Company no longer has any material
exposure to foreign currency exchange risk.
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 17, 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 risk associated
with the ongoing litigation and administrative proceedings in connection with
the Company’s coalbed natural gas development activities, 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
conducted rulemaking proceedings, in response to a petition filed by the NPRC,
on whether to promulgate rules that would (1) 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 (2) 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 existing standards. While the BER, in March
2006, rejected the NPRC’s proposed requirements on re-injection and treatment,
it did adopt a non-degradation policy that could adversely impact Fidelity’s
operations, depending on applicability of the new policy to water discharge
permits issued to Fidelity by the Montana DEQ prior to the latest action of
the
BER. Fidelity believes that the previously issued permits, if they remain in
effect though their specified five-year terms, should allow Fidelity to continue
to conduct its existing coalbed natural gas operations without undue operational
constraints. However, the Northern Cheyenne Tribe filed suit in Montana state
court, in April 2006, seeking to have the permits set aside. If the permits
are
determined to be invalid, Fidelity’s existing coalbed natural gas operations
would likely be materially and adversely affected.
ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
The
following table includes information with respect to the issuer's
purchase of equity securities:
ISSUER
PURCHASES OF EQUITY SECURITIES
Period
|
(a)
Total
Number of Shares
(or
Units) Purchased (1)
|
(b)
Average
Price Paid
per
Share
(or
Unit)
|
(c)
Total
Number of Shares (or Units) Purchased as Part of Publicly Announced
Plans
or Programs (2)
|
(d)
Maximum
Number (or Approximate Dollar Value) of Shares (or Units) that May
Yet Be
Purchased Under the Plans or Programs (2)
|
January
1 through January 31, 2006
|
|
|
|
|
February
1 through February 28, 2006
|
37,533
|
$34.65
|
|
|
March
1 through March 31, 2006
|
|
|
|
|
Total
|
37,533
|
|
|
|
(1)
Represents shares of common stock withheld by the Company to pay taxes in
connection with the vesting of shares granted pursuant to a compensation
plan.
(2)
Not
applicable. The Company does not currently have in place any publicly announced
plans or programs to purchase equity securities.
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The
Company’s Annual Meeting of Stockholders was held on April 25, 2006. Three
proposals were submitted to stockholders as described in the Company’s Proxy
Statement dated March 9, 2006, and were voted upon and approved by stockholders
at the meeting. The table below briefly describes the proposals and the results
of the stockholder votes.
|
|
|
|
Shares
|
|
|
|
|
|
|
|
Shares
|
|
Against
or
|
|
|
|
Broker
|
|
|
|
For
|
|
Withheld
|
|
Abstentions
|
|
Non-Votes
|
|
Proposal
to elect three directors:
|
|
|
|
|
|
|
|
|
|
For
terms expiring in 2009 --
|
|
|
|
|
|
|
|
|
|
Richard
H. Lewis
|
|
|
106,484,336
|
|
|
1,154,261
|
|
|
---
|
|
|
---
|
|
Harry
J. Pearce
|
|
|
106,107,037
|
|
|
1,531,560
|
|
|
---
|
|
|
---
|
|
Sister
Thomas Welder, O.S.B.
|
|
|
105,948,733
|
|
|
1,689,864
|
|
|
---
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proposal
to ratify the appointment of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deloitte
& Touche LLP as the
Company’s
independent auditors for 2006
|
|
|
106,526,040
|
|
|
749,359
|
|
|
363,198
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proposal
to approve the Long-Term
Performance-Based
Incentive Plan
|
|
|
61,306,898
|
|
|
19,532,043
|
|
|
1,556,394
|
|
|
25,243,262
|
|
ITEM
6. EXHIBITS
10(a)
|
Employment
Agreement between the Company and John K. Castleberry
|
|
|
10(b)
|
Long-Term
Performance-Based Incentive Plan, as amended February 16,
2006
|
|
|
10(c)
|
Form
of Performance Share Award Agreement under the Long-Term Performance-Based
Incentive Plan
|
|
|
10(d)
|
1997 Non-Employee
Director Long-Term Incentive Plan, as amended February 16,
2006
|
|
|
10(e)
|
WBI
Holdings, Inc. Executive Incentive Compensation Plan, as amended
effective
January 1, 2006
|
|
|
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
|
|
|
SIGNATURES
Pursuant
to the requirements of the Exchange Act, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly
authorized.
|
|
MDU
RESOURCES GROUP, INC.
|
|
|
|
|
DATE:
May
5, 2006
|
|
BY:
|
/s/
Vernon A. Raile
|
|
|
|
Vernon
A. Raile
|
|
|
|
Executive
Vice President, Treasurer
|
|
|
|
and
Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
BY:
|
/s/
Doran N. Schwartz
|
|
|
|
Doran
N. Schwartz
|
|
|
|
Vice
President and Chief Accounting
Officer
|
EXHIBIT
INDEX
Exhibit
No.
10(a)
|
Employment
Agreement between the Company and John K. Castleberry
|
|
|
10(b)
|
Long-Term
Performance-Based Incentive Plan, as amended February 16,
2006
|
|
|
10(c)
|
Form
of Performance Share Award Agreement under the Long-Term Performance-Based
Incentive Plan
|
|
|
10(d)
|
1997 Non-Employee
Director Long-Term Incentive Plan, as amended February 16,
2006
|
|
|
10(e)
|
WBI
Holdings, Inc. Executive Incentive Compensation Plan, as amended
effective
January 1, 2006
|
|
|
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
|
|
|