MDU RESOURCES GROUP, INC.
Report of Management
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report. The financial statements have been prepared in
conformity with accounting principles generally accepted in the United
States as applied to the company's regulated and nonregulated
businesses and necessarily include some amounts that are based on
informed judgments and estimates of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost-effective basis, that
transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an organizational
structure which provides an appropriate segregation of
responsibilities, effective selection and training of personnel,
written policies and procedures and periodic reviews by the Internal
Auditing Department. In addition, the company has a policy which
requires all employees to acknowledge their responsibility for ethical
conduct. Management believes that these measures provide for a system
that is effective and reasonably assures that all transactions are
properly recorded for the preparation of financial statements.
Management modifies and improves its system of internal accounting
controls in response to changes in business conditions. The company's
Internal Auditing Department is charged with the responsibility for
determining compliance with company procedures.
The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting. The audit committee meets regularly with
management, the internal auditors and Arthur Andersen LLP, independent
public accountants, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities. The internal
auditors and Arthur Andersen LLP have full and free access to the audit
committee, without management present, to discuss auditing, internal
accounting control and financial reporting matters.
Arthur Andersen LLP is engaged to express an opinion on the financial
statements. Their audit is conducted in accordance with auditing
standards generally accepted in the United States and includes
examining, on a test basis, supporting evidence, assessing the
company's accounting principles used and significant estimates made by
management and evaluating the overall financial statement presentation
to the extent necessary to allow them to report on the fairness, in all
material respects, of the financial condition and operating results of
the company.
/s/ Martin A. White /s/ Warren L. Robinson
Martin A. White Warren L. Robinson
Chairman of the Board Executive Vice President
President and Chief Treasurer and Chief
Executive Officer Financial Officer
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 2001 2000 1999
(In thousands, except per share amounts)
Operating revenues $2,223,632 $1,873,671 $1,279,809
Operating expenses:
Fuel and purchased power 57,393 54,114 51,802
Purchased natural gas sold 529,356 634,277 349,215
Operation and maintenance 1,168,271 812,600 604,014
Depreciation, depletion and
amortization 139,917 110,888 81,818
Taxes, other than income 55,427 44,805 33,209
1,950,364 1,656,684 1,120,058
Operating income 273,268 216,987 159,751
Other income -- net 26,821 11,724 9,645
Interest expense 45,899 48,033 36,006
Income before income taxes 254,190 180,678 133,390
Income taxes 98,341 69,650 49,310
Net income 155,849 111,028 84,080
Dividends on preferred stocks 762 766 772
Earnings on common stock $ 155,087 $ 110,262 $ 83,308
Earnings per common share --
basic $ 2.31 $ 1.80 $ 1.53
Earnings per common share --
diluted $ 2.29 $ 1.80 $ 1.52
Dividends per common share $ .90 $ .86 $ .82
Weighted average common shares
outstanding -- basic 67,272 61,090 54,615
Weighted average common shares
outstanding -- diluted 67,869 61,390 54,870
The accompanying notes are an integral part of these consolidated
statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 2001 2000
(In thousands, except shares and per share amount)
ASSETS
Current assets:
Cash and cash equivalents $ 41,811 $ 36,512
Receivables, net 285,081 342,354
Inventories 95,341 64,017
Deferred income taxes 18,973 8,048
Prepayments and other current assets 40,286 29,355
481,492 480,286
Investments 38,198 41,380
Property, plant and equipment 2,756,695 2,496,123
Less accumulated depreciation,
depletion and amortization 947,377 895,109
1,809,318 1,601,014
Deferred charges and other assets 294,063 190,279
$2,623,071 $2,312,959
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings (Note 5) $ --- $ 8,000
Long-term debt and preferred
stock due within one year 11,185 19,695
Accounts payable 110,649 171,929
Taxes payable 11,826 10,437
Dividends payable 16,108 14,423
Other accrued liabilities 95,559 59,989
245,327 284,473
Long-term debt (Note 6) 783,709 728,166
Deferred credits and other liabilities:
Deferred income taxes 342,412 281,000
Other liabilities 125,552 121,860
467,964 402,860
Preferred stock subject to mandatory
redemption (Note 7) 1,300 1,400
Commitments and contingencies (Notes 12, 14 and 15)
Stockholders' equity:
Preferred stocks (Note 7) 15,000 15,000
Common stockholders' equity:
Common stock (Note 8)
Authorized -- 150,000,000 shares,
$1.00 par value
Issued -- 70,016,851 shares in 2001 and
65,267,567 shares in 2000 70,017 65,268
Other paid-in capital 646,521 518,771
Retained earnings 394,641 300,647
Accumulated other comprehensive income 2,218 ---
Treasury stock at cost - 239,521 shares (3,626) (3,626)
Total common stockholders' equity 1,109,771 881,060
Total stockholders' equity 1,124,771 896,060
$2,623,071 $2,312,959
The accompanying notes are an integral part of these consolidated
statements.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
MDU RESOURCES GROUP, INC.
Years ended December 31, 2001, 2000 and 1999
Accumu-
lated
Other
Other Compre-
Common Stock Paid-in Retained hensive Treasury Stock
Shares Amount Capital Earnings Income Shares Amount Total
(In thousands, except shares)
Balance at
December 31, 1998 53,272,951 $177,399 $171,486 $205,583 $ --- (239,521) $(3,626) $ 550,842
Net income --- --- --- 84,080 --- --- --- 84,080
Dividends on
preferred stocks --- --- --- (772) --- --- --- (772)
Dividends on
common stock --- --- --- (45,322) --- --- --- (45,322)
Reduction in par
value of common
stock --- (124,126) 124,126 --- --- --- --- ---
Issuance of
common stock, net 4,004,964 4,005 76,700 --- --- --- --- 80,705
Balance at
December 31, 1999 57,277,915 57,278 372,312 243,569 --- (239,521) (3,626) 669,533
Net income --- --- --- 111,028 --- --- --- 111,028
Dividends on
preferred stocks --- --- --- (766) --- --- --- (766)
Dividends on
common stock --- --- --- (53,184) --- --- --- (53,184)
Issuance of
common stock, net 7,989,652 7,990 146,459 --- --- --- --- 154,449
Balance at
December 31, 2000 65,267,567 65,268 518,771 300,647 --- (239,521) (3,626) 881,060
Comprehensive income
Net income --- --- --- 155,849 --- --- --- 155,849
Other comprehensive
income
Net unrealized gain on
derivative instruments
qualifying as hedges:
Unrealized loss on
derivative instruments
at January 1, 2001,
due to cumulative
effect of a change in
accounting principle,
net of tax of $3,970 --- --- --- --- (6,080) --- --- (6,080)
Net unrealized gain on
derivative instruments
arising during the
period, net of tax
of $1,448 --- --- --- --- 2,218 --- --- 2,218
Reclassification
adjustment for losses
on derivative
instruments included
in net income, net of
tax of $3,970 --- --- --- --- 6,080 --- --- 6,080
Net unrealized gain on
derivative instruments
qualifying as hedges --- --- --- --- 2,218 --- --- 2,218
Total comprehensive
income --- --- --- --- --- --- --- 158,067
Dividends on
preferred stocks --- --- --- (762) --- --- --- (762)
Dividends on
common stock --- --- --- (61,093) --- --- --- (61,093)
Issuance of
common stock, net 4,749,284 4,749 127,750 --- --- --- --- 132,499
Balance at
December 31, 2001 70,016,851 $ 70,017 $646,521 $394,641 $2,218 (239,521) $(3,626) $1,109,771
<FN>
The accompanying notes are an integral part of these consolidated statements.
</FN>
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 2001 2000 1999
(In thousands)
Operating activities:
Net income $155,849 $ 111,028 $ 84,080
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 139,917 110,888 81,818
Deferred income taxes and
investment tax credit 21,014 36,530 15,704
Changes in current assets and
liabilities, net of acquisitions:
Receivables 127,267 (117,449) (12,310)
Inventories (26,540) 9,578 (13,460)
Other current assets (2,792) (3,514) (4,190)
Accounts payable (90,576) 61,021 12,492
Other current liabilities 34,331 (3,821) (8,972)
Other noncurrent changes (9,916) 2,701 (289)
Net cash provided by operating
activities 348,554 206,962 154,873
Investing activities:
Capital expenditures including
acquisitions of businesses (382,285) (408,826) (170,510)
Net proceeds from sale or
disposition of property 51,641 11,000 16,660
Net capital expenditures (330,644) (397,826) (153,850)
Sale of natural gas available
under repurchase commitment --- --- 1,330
Investments 2,760 2,102 (99)
Additions to notes receivable (23,813) (5,000) (35,907)
Proceeds from notes receivable 4,000 4,000 ---
Net cash used in investing
activities (347,697) (396,724) (188,526)
Financing activities:
Net change in short-term borrowings (8,000) (7,242) (6,585)
Issuance of long-term debt 122,283 192,162 154,546
Repayment of long-term debt (115,062) (29,349) (18,714)
Retirement of preferred stock (100) (100) (100)
Proceeds from issuance of
common stock, net 67,176 47,249 3,184
Retirement of natural gas
repurchase commitment --- --- (14,296)
Dividends paid (61,855) (53,950) (46,094)
Net cash provided by
financing activities 4,442 148,770 71,941
Increase (decrease) in cash
and cash equivalents 5,299 (40,992) 38,288
Cash and cash equivalents --
beginning of year 36,512 77,504 39,216
Cash and cash equivalents --
end of year $ 41,811 $ 36,512 $ 77,504
The accompanying notes are an integral part of these consolidated
statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
NOTE 1
Summary of Significant Accounting Policies
Basis of presentation
The consolidated financial statements of MDU Resources Group, Inc. and
its subsidiaries (company) include the accounts of the following
segments: electric, natural gas distribution, utility services,
pipeline and energy services, natural gas and oil production, and
construction materials and mining. The electric and natural gas
distribution segments and a portion of the pipeline and energy services
segment are regulated. The company's nonregulated operations include
the utility services, natural gas and oil production, and construction
materials and mining segments, and a portion of the pipeline and energy
services segment. For further descriptions of the company's business
segments see Note 10. The statements also include the ownership
interests in the assets, liabilities and expenses of two jointly owned
electric generation stations.
The company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by the company's
nonregulated businesses.
The company's regulated businesses account for certain income and
expense items under the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Regulation" (SFAS
No. 71). SFAS No. 71 requires these businesses to defer as regulatory
assets or liabilities certain items that would have otherwise been
reflected as expense or income, respectively, based on the expected
regulatory treatment in future rates. The expected recovery or
flowback of these deferred items is generally based on specific
ratemaking decisions or precedent for each item. Regulatory assets and
liabilities are being amortized consistently with the regulatory
treatment established by the FERC and the applicable state public
service commissions. See Note 2 for more information regarding the
nature and amounts of these regulatory deferrals.
Prior to the sale of the company's coal operations as discussed in
Note 10, intercompany coal sales, which were made at prices
approximately the same as those charged to others, and the related
utility fuel purchases are not eliminated in accordance with the
provisions of SFAS No. 71. All other significant intercompany balances
and transactions have been eliminated in consolidation.
Allowance for doubtful accounts
The company's allowance for doubtful accounts as of December 31, 2001
and 2000, was $5.8 million and $4.1 million, respectively.
Property, plant and equipment
Additions to property, plant and equipment are recorded at cost when
first placed in service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original
cost and cost of removal, less salvage, is charged to accumulated
depreciation. With respect to the retirement or disposal of all other
assets, except for natural gas and oil production properties as
described below, the resulting gains or losses are recognized as a
component of income. The company is permitted to capitalize an
allowance for funds used during construction (AFUDC) on regulated
construction projects and to include such amounts in rate base when the
related facilities are placed in service. In addition, the company
capitalizes interest, when applicable, on certain construction projects
associated with its other operations. The amount of AFUDC and interest
capitalized was $6.6 million, $5.2 million and $1.7 million in 2001,
2000 and 1999, respectively. Generally, property, plant and equipment
are depreciated on a straight-line basis over the average useful lives
of the assets, except for natural gas and oil production properties as
described below.
Goodwill and other intangible assets
The excess of the cost over the fair value of net assets of purchased
businesses is recorded as goodwill and was being amortized on a
straight-line basis over estimated useful lives for recorded goodwill
in place at June 30, 2001. However, Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS
No. 142), which the company adopted as of January 1, 2002, as discussed
later in Note 1, requires the discontinuance of goodwill amortization
for the company's recorded goodwill at June 30, 2001, on January 1,
2002. Goodwill acquired after June 30, 2001, was subject immediately
to the nonamortization provisions of SFAS No. 142.
Goodwill, net of accumulated amortization, was $174.2 million and
$91.4 million as of December 31, 2001 and 2000, respectively. Goodwill
is included in deferred charges and other assets. Goodwill
amortization expense was $4.8 million, $7.0 million and $2.0 million
for 2001, 2000 and 1999, respectively.
Impairment of long-lived assets and intangibles
The company reviews the carrying values of its long-lived assets,
including goodwill and identifiable intangibles, whenever events or
changes in circumstances indicate that such carrying values may not be
recoverable and annually for goodwill as required by SFAS No. 142. The
determination of whether an impairment has occurred is based on an
estimate of undiscounted future cash flows attributable to the assets,
compared to the carrying value of the assets. If an impairment has
occurred, the amount of the impairment recognized is determined by
estimating the fair value of the assets and recording a loss if the
carrying value is greater than the fair value. In 2000, the company
experienced significant changes in market conditions at one of its
energy marketing operations, which negatively affected the fair value
of the assets at that operation. Due to the significance of the
decline, the company recorded an impairment charge against goodwill of
$3.9 million after-tax in 2000. The amount related to this impairment
is included in depreciation, depletion and amortization. Excluding
this impairment, no other long-lived assets or intangibles have been
impaired and accordingly, no other impairment losses have been recorded
in 2001, 2000 and 1999. Unforeseen events and changes in circumstances
could require the recognition of other impairment losses at some future
date.
Impairment testing of natural gas and oil properties
The company uses the full-cost method of accounting for its natural gas
and oil production activities. Under this method, all costs incurred
in the acquisition, exploration and development of natural gas and oil
properties are capitalized and amortized on the units of production
method based on total proved reserves. Any conveyances of properties,
including gains or losses on abandonments of properties, are treated as
adjustments to the cost of the properties with no gain or loss
recognized. Capitalized costs are subject to a "ceiling test" that
limits such costs to the aggregate of the present value of future net
revenues of proved reserves based on single point in time spot market
prices, as mandated under the rules of the Securities and Exchange
Commission, and the lower of cost or fair value of unproved properties.
Future net revenue is estimated based on end-of-quarter spot market
prices adjusted for contracted price changes. If capitalized costs
exceed the full-cost ceiling at the end of any quarter, a permanent
noncash write-down is required to be charged to earnings in that
quarter unless subsequent price changes eliminate or reduce an
indicated write-down.
Due to abnormally low spot natural gas prices that existed on the last
trading day of the third quarter of 2001, the company's capitalized
costs under the full-cost method of accounting exceeded the full-cost
ceiling at September 30, 2001. The lower natural gas prices were
largely attributable to a sharp decline in nationwide spot market
prices, especially natural gas prices in the Rocky Mountain region,
over a relatively short period of time following the terrorist attacks
on New York and Washington, D.C. on September 11, 2001, and prior to
October 1, 2001. Oil prices likewise experienced a sharp drop during
this same period. The company believes the decline in natural gas
prices did not reflect the economics of its production assets in that
natural gas prices actually being received by the company at the end of
the third quarter of 2001 were significantly higher than the spot
market prices at that time. In addition, historic natural gas prices
have also generally been much higher and only a small portion of the
company's natural gas is sold using spot market pricing. As of
September 30, 2001, the capitalized costs exceeded the full-cost
ceiling and would have resulted in a write-down of the company's
natural gas and oil properties in the amount of approximately $32
million after-tax. However, subsequent to September 30, 2001, natural
gas prices both nationwide and in the Rocky Mountain region increased
significantly, thereby eliminating the need for a write-down of the
company's natural gas and oil producing properties.
At December 31, 2001, the company's full-cost ceiling exceeded the
company's capitalized cost. However, sustained downward movements in
natural gas and oil prices subsequent to December 31, 2001, could
result in a future write-down of the company's natural gas and oil
properties.
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 is included in inventories and amounted to
$28.6 million and $11.0 million at December 31, 2001 and 2000,
respectively. The remainder of natural gas in underground storage is
included in property, plant and equipment and was $43.1 million and
$43.6 million at December 31, 2001 and 2000, respectively.
Inventories
Inventories, other than natural gas in underground storage for the
company's regulated operations, consist primarily of materials and
supplies of $22.5 million and $20.4 million, aggregates held for resale
of $31.1 million and $22.7 million and other inventories of $13.1
million and $9.9 million as of December 31, 2001 and 2000,
respectively. These inventories are stated at the lower of average
cost or market.
Revenue recognition
Revenue is recognized when the earnings process is complete, as
evidenced by an agreement between the customer and the company, when
delivery has occurred or services have been rendered, when the fee is
fixed or determinable and when collection is probable. The company
recognizes utility revenue each month based on the services provided to
all utility customers during the month. The company recognizes
construction contract revenue at its construction businesses using the
percentage-of-completion method as discussed below. The company
recognizes revenue from natural gas and oil production activities only
on that portion of production sold and allocable to the company's
ownership interest in the related well. The company generally
recognizes all other revenues when services are rendered or goods are
delivered.
Percentage-of-completion method
The company recognizes construction contract revenue from fixed price
and modified fixed price construction contracts at its construction
businesses using the percentage-of-completion method, measured by the
percentage of costs incurred to date to estimated total costs for each
contract. Costs in excess of billings on uncompleted contracts of
$29.7 million and $13.9 million for the years ending December 31, 2001
and 2000, respectively, represents revenues recognized in excess of
amounts billed and is included in accounts receivable. Billings in
excess of costs on uncompleted contracts of $17.3 million and $8.0
million for the years ending December 31, 2001 and 2000, respectively,
represents billings in excess of revenues recognized and are included
in accounts payable. Also included in accounts receivable are amounts
representing balances billed but not paid by customers under retainage
provisions in contracts which amounted to $20.5 million and
$13.7 million as of December 31, 2001 and 2000, respectively.
Advertising
The company expenses advertising costs as incurred and the amount of
advertising expense for the years 2001, 2000 and 1999, was $2.9
million, $2.0 million and $1.3 million, respectively.
Natural gas costs recoverable or refundable through rate adjustments
Under the terms of certain orders of the applicable state public
service commissions, the company is deferring natural gas commodity,
transportation and storage costs which are greater or less than amounts
presently being recovered through its existing rate schedules. Such
orders generally provide that these amounts are recoverable or
refundable through rate adjustments within a period ranging from 24
months to 28 months from the time such costs are paid. Natural gas
costs refundable through rate adjustments amounted to $27.7 million and
$8.8 million for the years ended December 31, 2001 and 2000,
respectively, and are included in other accrued liabilities.
Income taxes
The company provides deferred federal and state income taxes on all
temporary differences. Excess deferred income tax balances associated
with the company's rate-regulated activities resulting from the
company's adoption of SFAS No. 109, "Accounting for Income Taxes," have
been recorded as a regulatory liability and are included in other
accrued liabilities. These regulatory liabilities are expected to be
reflected as a reduction in future rates charged customers in
accordance with applicable regulatory procedures.
The company uses the deferral method of accounting for investment tax
credits and amortizes the credits on electric and natural gas
distribution plant over various periods which conform to the ratemaking
treatment prescribed by the applicable state public service
commissions.
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 year. 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 year, plus the effect of outstanding stock options and restricted
stock grants. For the years ending December 31, 2001 and 1999, 150,630
shares and 76,500 shares, respectively, with an average exercise price
of $36.86 and $23.44, respectively, attributable to the exercise of
outstanding options were excluded from the calculation of diluted
earnings per share because their effect was antidilutive. For the year
ending December 31, 2000, there were no shares excluded from the
calculation of diluted earnings per share. For the years ending
December 31, 2001, 2000 and 1999, no adjustments were made to reported
earnings in the computation of earnings per share. Common stock
outstanding includes issued shares less shares held in treasury.
Use of estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires the company
to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period.
Estimates are used for such items as property depreciable lives, tax
provisions, uncollectible accounts, environmental and other loss
contingencies, accumulated provision for revenues subject to refund,
costs on construction contracts, unbilled revenues and actuarially
determined benefit costs. As additional information becomes available,
or actual amounts are determinable, the recorded estimates are revised.
Consequently, operating results can be affected by revisions to prior
accounting estimates.
Cash flow information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 2001 2000 1999
(In thousands)
Interest, net of amount capitalized $42,267 $41,912 $30,772
Income taxes $75,284 $30,930 $32,723
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Reclassifications
Certain reclassifications have been made in the financial statements
for prior years to conform to the current presentation. Such
reclassifications had no effect on net income or stockholders' equity
as previously reported.
New accounting pronouncements
In June 2001, the Financial Accounting Standards Board (FASB) approved
Statement of Financial Accounting Standards No. 141, "Business
Combinations" (SFAS No. 141). SFAS No. 141 requires that all business
combinations be accounted for using the purchase method of accounting.
The use of the pooling-of-interest method of accounting for business
combinations is prohibited. The provisions of SFAS No. 141 apply to
all business combinations initiated after June 30, 2001. The
company is accounting for business combinations after June 30, 2001, in
accordance with SFAS No. 141.
In June 2001, the FASB approved SFAS No. 142. SFAS No. 142 changes the
accounting for goodwill and intangible assets and requires that
goodwill no longer be amortized but be tested for impairment at least
annually at the reporting unit level in accordance with SFAS No. 142.
Recognized intangible assets with determinable useful lives should be
amortized over their useful life and reviewed for impairment in
accordance with Statement of Financial Accounting Standards No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS
No. 144). The provisions of SFAS No. 142 are effective for fiscal
years beginning after December 15, 2001, except for provisions related
to the nonamortization and amortization of goodwill and intangible
assets acquired after June 30, 2001, which were subject immediately to
the provisions of SFAS No. 142. The company adopted SFAS No. 142 on
January 1, 2002. The company ceased amortization of its recorded
goodwill at June 30, 2001, on January 1, 2002. Goodwill at each
reporting unit will be tested for impairment as of January 1, 2002.
The company will perform this transitional goodwill impairment test
within six months of the date of adoption of SFAS No. 142. However,
the amounts used in the transitional goodwill impairment test shall be
measured as of January 1, 2002. The company believes the adoption of
the goodwill impairment provisions of SFAS No. 142 will not have a
material effect on its financial position or results of operations.
In June 2001, the FASB approved Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS
No. 143). SFAS No. 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it
is incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for the recorded amount or incurs
a gain or loss upon settlement. SFAS No. 143 is effective for fiscal
years beginning after June 15, 2002. The company will adopt SFAS No.
143 on January 1, 2003, but has not yet quantified the effects of
adopting SFAS No. 143 on its financial position or results of
operations.
In August 2001, the FASB approved SFAS No. 144. SFAS No. 144
supersedes Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS No. 144 addresses accounting and
reporting for the impairment or disposal of long-lived assets,
including the disposal of a segment of a business. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001. The
company adopted SFAS No. 144 on January 1, 2002. The adoption of SFAS
No. 144 did not have an effect on the company's financial position or
results of operations.
The company adopted Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133), amended by Statement of Financial Accounting Standards
No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133" and Statement
of Financial Accounting Standards No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" (all such
statements hereinafter referred to as SFAS No. 133) on January 1, 2001.
SFAS No. 133 establishes accounting and reporting standards requiring
that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance
sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative instrument's fair value
be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows
derivative gains and losses to offset the related results on the hedged
item in the income statement, and requires that a company must formally
document, designate and assess the effectiveness of transactions that
receive hedge accounting treatment.
SFAS No. 133 requires that as of the date of initial adoption, the
difference between the fair market value of derivative instruments
recorded on the balance sheet and the previous carrying amount of those
derivative instruments be reported in net income or other comprehensive
income (loss), as appropriate, as the cumulative effect of a change in
accounting principle in accordance with APB 20, "Accounting Changes."
On January 1, 2001, the company reported a net-of-tax cumulative-effect
adjustment of $6.1 million in accumulated other comprehensive loss to
recognize at fair value all derivative instruments that are designated
as cash-flow hedging instruments, which the company reflected in
earnings over the 12 months ended December 31, 2001. The transition to
SFAS No. 133 did not have an effect on the company's net income at
adoption.
Comprehensive income
Upon the adoption of SFAS No. 133 on January 1, 2001, the company
recorded a cumulative-effect adjustment in accumulated other
comprehensive income to recognize all derivative instruments designated
as hedges at fair value. As of December 31, 2001, the company has
recorded unrealized gains and losses on swap agreements in accordance
with SFAS No. 133. These amounts are reflected in the Consolidated
Statements of Common Stockholders' Equity. For additional information
on the adoption of SFAS No. 133, see new accounting pronouncements in
Note 1, and Note 3. For the years ended December 31, 2000 and 1999,
comprehensive income equaled net income as reported.
NOTE 2
Regulatory Assets and Liabilities
The following table summarizes the individual components of unamortized
regulatory assets and liabilities included in the accompanying
Consolidated Balance Sheets as of December 31:
2001 2000
(In thousands)
Regulatory assets:
Deferred income taxes $ 13,417 $ 263
Long-term debt refinancing costs 6,829 8,125
Plant costs 2,499 2,668
Postretirement benefit costs 722 833
Other 5,929 7,052
Total regulatory assets 29,396 18,941
Regulatory liabilities:
Natural gas costs refundable
through rate adjustments 27,706 8,772
Taxes refundable to customers 12,318 11,656
Plant decommissioning costs 8,243 7,601
Reserves for regulatory matters 7,132 6,087
Deferred income taxes 5,661 3,554
Other 5,053 1,193
Total regulatory liabilities 66,113 38,863
Net regulatory position $(36,717) $(19,922)
As of December 31, 2001, substantially all of the company's regulatory
assets, other than certain deferred income taxes, are being reflected
in rates charged to customers and are being recovered over the next one
to 15 years.
If, for any reason, the company's regulated businesses cease to meet
the criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities relating to those
portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income as an
extraordinary item in the period in which the discontinuance of SFAS
No. 71 occurs.
NOTE 3
Derivative Instruments
As of December 31, 2001, the company held derivative instruments
designated as cash flow hedging instruments. All derivative
instruments are recognized on the Consolidated Balance Sheets at fair
value.
Hedging activities
The cash flow hedging instruments in place at December 31, 2001, are
comprised of natural gas and oil price swap agreements. The objective
for holding the natural gas and oil price swap agreements is to manage
a portion of the market risk associated with fluctuations in the price
of natural gas and oil on the company's forecasted sales of natural gas
and oil production. The company also entered into an interest rate
swap agreement which expired in the fourth quarter of 2001. The
objective for holding the interest rate swap agreement was to manage a
portion of the company's interest rate risk on the forecasted issuance
of fixed-rate debt under Centennial Energy Holdings, Inc.'s
(Centennial), a direct wholly owned subsidiary of the company,
commercial paper program. The company designated each of the natural
gas and oil price swap agreements as a hedge of the forecasted sale of
natural gas and oil production and designated the interest rate swap
agreement as a hedge of the risk of changes in interest rates on the
company's forecasted issuances of fixed-rate debt under Centennial's
commercial paper program.
The company's policy allows the use of derivative instruments as part
of an overall energy price and interest rate risk management program to
efficiently manage and minimize commodity price and interest rate risk.
The company's policy prohibits the use of derivative instruments for
speculating to take advantage of market trends and conditions and the
company has procedures in place to monitor compliance with its
policies. The company is exposed to credit-related losses in relation
to hedged derivative instruments in the event of nonperformance by
counterparties. The company has policies and procedures, which
management believes minimize credit-risk exposure. These policies and
procedures include an evaluation of potential counterparties' credit
ratings, credit exposure limitations, settlement of natural gas and oil
price swap agreements monthly and settlement of interest rate swap
agreements within 90 days. Accordingly, the company does not
anticipate any material effect to its financial position or results of
operations as a result of nonperformance by counterparties.
Upon the adoption of SFAS No. 133, the company recorded the fair market
value of the natural gas and oil price swap agreements on the company's
Consolidated Balance Sheets. On an ongoing basis, the company adjusts
its balance sheet to reflect the current fair market value of its swap
agreements. The related gains or losses on these agreements are
recorded in common stockholders' equity as a component of other
comprehensive income (loss). At the date the underlying transaction
occurs, 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.
For the year ended December 31, 2001, the company recognized the
ineffectiveness of all cash flow hedges, which is included in operating
revenues and interest expense for the natural gas and oil price swap
agreements and the interest rate swap agreement, respectively. For the
year ended December 31, 2001, the amount of ineffectiveness recognized
was immaterial. For the year ended December 31, 2001, the company 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 the discontinuance of
hedges.
Gains and losses on derivative instruments that are reclassified from
accumulated other comprehensive income (loss) to current-period
earnings are included in the line item in which the hedged item is
recorded. As of December 31, 2001, the maximum length of time over
which the company is hedging its exposure to the variability in future
cash flows for forecasted transactions is 12 months and the company
estimates that net gains of approximately $2.2 million will be
reclassified from accumulated other comprehensive income into earnings,
subject to changes in natural gas and oil market prices, within the 12
months between January 1, 2002 and December 31, 2002, as the hedged
transactions affect earnings.
In the event a derivative instrument does not qualify for hedge
accounting because it is no longer highly effective in offsetting
changes in cash flows of a hedged item; or if the derivative instrument
expires or is sold, terminated, or exercised; or if management
determines that designation of the derivative instrument as a hedge
instrument is no longer appropriate, hedge accounting will be
discontinued, and the derivative instrument would continue to be
carried at fair value with changes in its fair value recognized in
earnings. In these circumstances, the net gain or loss at the time of
discontinuance of hedge accounting would remain in other comprehensive
income (loss) until the period or periods during which the hedged
forecasted transaction affects earnings, at which time the net gain or
loss would be reclassified into earnings. In the event a cash flow
hedge is discontinued because it is unlikely that a forecasted
transaction will occur, the derivative instrument would continue to be
carried on the balance sheet at its fair value, and gains and losses
that were accumulated in other comprehensive income (loss) would be
recognized immediately in earnings. The company's policy requires
approval to terminate a hedge agreement prior to its original maturity.
Energy marketing
The company had entered into other derivative instruments that were not
designated as hedges in its energy marketing operations. In the third
quarter of 2001, the company sold the vast majority of its energy
marketing operations. The derivative instruments entered into by these
operations prior to the sale in the third quarter of 2001 were natural
gas forward purchase and sale commitments. These commitments involved
the purchase and sale of natural gas and related delivery of such
commodity. These operations sought to match natural gas purchases and
sales so that a margin was obtained on the transportation of such
commodity as distinguished from earning a margin on changes in market
prices. The net change in fair value representing unrealized gains and
losses resulting from changes in market prices on these derivative
instruments was reflected as operating revenues or purchased natural
gas sold. Net unrealized gains and losses on these derivative
instruments were not material for the years ended December 31, 2001,
2000 and 1999.
NOTE 4
Fair Value of Other Financial Instruments
The estimated fair value of the company's long-term debt and preferred
stock subject to mandatory redemption is based on quoted market prices
of the same or similar issues. The estimated fair value of the
company's long-term debt and preferred stock subject to mandatory
redemption at December 31 is as follows:
2001 2000
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $794,794 $894,652 $747,761 $772,127
Preferred stock
subject to mandatory
redemption $ 1,400 $ 940 $ 1,500 $ 927
The fair value of other financial instruments for which estimated fair
value has not been presented is not materially different than the
related carrying amount.
NOTE 5
Short-term Borrowings
The company has unsecured short-term lines of credit from a number of
banks totaling $110 million at December 31, 2001. These line of credit
agreements provide for bank borrowings against the lines and/or support
for commercial paper issues. The agreements provide for commitment
fees at varying rates. There were no amounts outstanding on the short-
term lines of credit at December 31, 2001. The amount outstanding on
the short-term lines of credit was $8 million at December 31, 2000.
The weighted average interest rate for borrowings outstanding at
December 31, 2000, was 6.6 percent.
NOTE 6
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
2001 2000
(In thousands)
First mortgage bonds and notes:
Pollution Control Refunding Revenue
Bonds, Series 1992,
6.65%, due June 1, 2022 $ 20,850 $ 20,850
Secured Medium-Term Notes,
Series A at a weighted
average rate of 7.59%, due on
dates ranging from October 1, 2004
to April 1, 2012 110,000 110,000
Total first mortgage bonds and notes 130,850 130,850
Senior notes at a weighted
average rate of 7.34%, due on
dates ranging from July 31, 2002
to October 30, 2018 405,200 294,300
Commercial paper at a weighted average
rate of 2.43%, supported by a revolving
credit agreement 219,700 261,350
Revolving line of credit, 4.75%, due
December 31, 2003 25,000 46,302
Term credit agreements at a weighted
average rate of 7.38%, due on dates
ranging from February 1, 2002
through December 1, 2013 11,769 12,731
Pollution control note obligation,
6.20%, due March 1, 2004 2,500 2,800
Discount (225) (572)
Total long-term debt 794,794 747,761
Less current maturities 11,085 19,595
Net long-term debt $783,709 $728,166
Centennial has a revolving credit agreement with various banks that
supports Centennial's $350 million commercial paper program. There
were no outstanding borrowings under the Centennial credit agreement at
December 31, 2001. Under the commercial paper program, $219.7 million
and $261.4 million were outstanding at December 31, 2001 and 2000,
respectively. The commercial paper borrowings are classified as long
term as Centennial intends to refinance these borrowings on a long-term
basis through continued commercial paper borrowings and as further
supported by the revolving credit agreement, which allows for
subsequent borrowings up to a term of one year. Centennial intends to
renew this existing credit agreement, which expires September 27, 2002,
on an annual basis.
Centennial has an uncommitted long-term master shelf agreement that
allows for borrowings of up to $300 million. Under the master shelf
agreement, $210 million was outstanding at December 31, 2001, and
$150 million was outstanding at December 31, 2000. The amount
outstanding is included in senior notes in the preceding long-term debt
table.
Under a revolving line of credit, the company has $40 million available
as of December 31, 2001. The amount outstanding under the revolving
line of credit was $25.0 million at December 31, 2001. At December 31,
2000, the company had $46.3 million outstanding under revolving lines
of credit.
The amounts of scheduled long-term debt maturities for the five years
and thereafter following December 31, 2001, aggregate $11.1 million in
2002; $266.8 million in 2003; $21.9 million in 2004; $70.2 million in
2005; $85.2 million in 2006 and $339.6 million thereafter.
Substantially all of the company's electric and natural gas
distribution properties, with certain exceptions, are subject to the
lien of its Indenture of Mortgage. Under the terms and conditions of
the Indenture, the company could have issued approximately $305 million
of additional first mortgage bonds at December 31, 2001. Certain other
debt instruments of the company contain restrictive covenants, all of
which the company is in compliance with at December 31, 2001.
NOTE 7
Preferred Stocks
Preferred stocks at December 31 are as follows:
2001 2000
(Dollars in thousands)
Authorized:
Preferred --
500,000 shares, cumulative,
par value $100, issuable in series
Preferred stock A --
1,000,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Preference --
500,000 shares, cumulative, without par
value, issuable in series (none outstanding)
Outstanding:
Subject to mandatory redemption --
Preferred --
5.10% Series -- 14,000 shares in 2001
and 15,000 shares in 2000 $ 1,400 $ 1,500
Other preferred stock --
4.50% Series -- 100,000 shares 10,000 10,000
4.70% Series -- 50,000 shares 5,000 5,000
15,000 15,000
Total preferred stocks 16,400 16,500
Less sinking fund requirements 100 100
Net preferred stocks $16,300 $16,400
The preferred stocks outstanding are subject to redemption, in whole or
in part, at the option of the company with certain limitations on 30
days notice on any quarterly dividend date on certain series of
preferred stock.
The company is obligated to make annual sinking fund contributions to
retire the 5.10% Series preferred stock. The redemption prices and
sinking fund requirements, where applicable, are summarized below:
Redemption Sinking Fund
Series Price (a) Shares Price (a)
Preferred stocks:
4.50% $105 (b) --- ---
4.70% $102 (b) --- ---
5.10% $102 1,000 (c) $100
(a) Plus accrued dividends.
(b) These series are redeemable at the sole discretion of the company.
(c) Annually on December 1, if tendered.
In the event of a voluntary or involuntary liquidation, all preferred
stock series holders are entitled to $100 per share, plus accrued
dividends.
The aggregate annual sinking fund amount applicable to preferred stock
subject to mandatory redemption is $100,000 for each of the five years
following December 31, 2001, and $900,000 thereafter.
NOTE 8
Common Stock
At the Annual Meeting of Stockholders held in April 1999, the company's
common stockholders approved an amendment to the Certificate of
Incorporation increasing the authorized number of common shares from 75
million shares to 150 million shares and reducing the par value of the
common stock from $3.33 per share to $1.00 per share.
The company's Automatic Dividend Reinvestment and Stock Purchase Plan
(Stock Purchase Plan) provides participants the opportunity to invest
all or a portion of their cash dividends in shares of the company's
common stock and to make optional cash payments for the same purpose.
Holders of all classes of the company's capital stock, legal residents
in any of the 50 states, and beneficial owners, whose shares are held
by brokers or other nominees through participation by their brokers or
nominees, are eligible to participate in the Stock Purchase Plan. The
company's 401(k) Retirement Plan (K-Plan), is funded with the company's
common stock. Since January 1, 1999, the Stock Purchase Plan and K-
Plan have been funded primarily by the purchase of shares of common
stock on the open market, except from January 1, 1999 through March 31,
1999, when shares of authorized but unissued common stock were used to
fund the Stock Purchase Plan. At December 31, 2001, there were 8.1
million shares of common stock reserved for original issuance under the
Stock Purchase Plan and K-Plan.
In November 1998, the company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) for each outstanding share of the company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for one one-thousandth of a share of Series B
Preference Stock of the company, without par value, at an exercise
price of $125 per one one-thousandth, subject to certain adjustments.
The rights are currently not exercisable and will be exercisable only
if a person or group (acquiring person) either acquires ownership of 15
percent or more of the company's common stock or commences a tender or
exchange offer that would result in ownership of 15 percent or more.
In the event the company is acquired in a merger or other business
combination transaction or 50 percent or more of its consolidated
assets or earnings power are sold, each right entitles the holder to
receive, upon the exercise thereof at the then current exercise price
of the right multiplied by the number of one one-thousandth of a Series
B Preference Stock for which a right is then exercisable, in accordance
with the terms of the rights agreement, such number of shares of common
stock of the acquiring person having a market value of twice the then
current exercise price of the right. The rights, which expire on
December 31, 2008, are redeemable in whole, but not in part, for a
price of $.01 per right, at the company's option at any time until any
acquiring person has acquired 15 percent or more of the company's
common stock.
The company has stock option plans for directors, key employees and
employees, which grant options to purchase shares of the company's
stock. The company accounts for these option plans in accordance with
APB Opinion No. 25 under which no compensation expense has been
recognized. The option exercise price is the market value of the stock
on the date of grant. Options granted to the 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. In
addition, the company has granted restricted stock awards under a long-
term incentive plan, deferred compensation agreements and a restricted
stock agreement totaling 350,392 shares, 348,021 shares and 105,250
shares in 2001, 2000 and 1999, respectively. The restricted stock
awards granted vest to the participants at various times ranging from
two years 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 weighted average grant
date fair value of the restricted stock grants was $31.55, $20.81 and
$22.91 in 2001, 2000 and 1999, respectively. Compensation expense
recognized for restricted stock grants was $4.5 million, $1.6 million
and $722,000 in 2001, 2000 and 1999, respectively. Under the stock
option plans and long-term incentive plan, the company is authorized to
grant options and restricted stock for up to 9.8 million shares of
common stock and has granted options and restricted stock on 4.8
million shares through December 31, 2001.
Had the company recorded compensation expense for the fair value of
options granted consistent with SFAS No. 123, "Accounting for Stock-
Based Compensation," net income would have been reduced on a pro forma
basis by $3.8 million in 2001, $529,000 in 2000, and $498,000 in 1999.
On a pro forma basis, basic and diluted earnings per share for 2001
would have been reduced by $.06. On a pro forma basis, there would
have been no effect on basic earnings per share for 2000, and diluted
earnings per share would have been reduced by $.01. On a pro forma
basis, basic and diluted earnings per share for 1999 would have been
reduced by $.01.
A summary of the status of the stock option plans at December 31, 2001,
2000 and 1999, and changes during the years then ended are as follows:
2001 2000 1999
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 1,224,959 $20.61 1,427,262 $19.46 1,516,808 $19.17
Granted 2,693,120 30.14 74,000 20.54 22,500 23.31
Forfeited (74,282) 27.24 (84,135) 21.18 (57,966) 20.38
Exercised (371,590) 20.23 (192,168) 11.84 (54,080) 11.95
Balance at end
of year 3,472,207 27.90 1,224,959 20.61 1,427,262 19.46
Exercisable at
end of year 770,142 $21.41 129,763 $18.11 301,681 $13.89
Summarized information about stock options outstanding and exercisable
as of December 31, 2001, is as follows:
Options Outstanding Options Exercisable
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercisable Prices Outstanding in Years Price Exercisable Price
$10.50 - 17.50 41,966 3.7 $13.36 41,966 $13.36
17.51 - 24.50 789,371 6.3 21.15 698,176 21.16
24.51 - 31.50 2,490,240 9.2 29.74 --- ---
31.51 - 38.55 150,630 9.2 36.86 30,000 38.55
3,472,207 770,142
The fair value of each option is estimated on the date of grant using
the Black-Scholes option pricing model. The weighted average fair
value of the options granted and the assumptions used to estimate the
fair value of options are as follows:
2001 2000 1999
Weighted average fair value of
options at grant date $ 7.38 $ 5.07 $ 4.82
Weighted average risk-free
interest rate 5.19% 6.76% 5.98%
Weighted average expected
price volatility 26.05% 23.55% 22.03%
Weighted average expected
dividend yield 3.53% 3.84% 4.22%
Expected life in years 7 7 7
NOTE 9
Income Taxes
Income tax expense is summarized as follows:
Years ended December 31, 2001 2000 1999
(In thousands)
Current:
Federal $66,211 $27,865 $29,574
State 11,160 5,188 3,874
Foreign (44) 67 158
77,327 33,120 33,606
Deferred:
Income taxes --
Federal 16,972 29,323 12,902
State 4,773 8,060 3,690
Investment tax credit (731) (853) (888)
21,014 36,530 15,704
Total income tax expense $98,341 $69,650 $49,310
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
2001 2000
(In thousands)
Deferred tax assets:
Regulatory matters $ 21,000 $ 7,650
Accrued pension costs 9,349 10,325
Accrued land reclamation 1,648 1,941
Deferred investment tax credit 1,413 1,697
Other 21,691 18,213
Total deferred tax assets 55,101 39,826
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 302,103 264,635
Basis differences on natural gas
and oil producing properties 61,684 36,763
Regulatory matters 5,661 3,554
Other 9,092 7,826
Total deferred tax liabilities 378,540 312,778
Net deferred income tax liability $(323,439)$(272,952)
The following table reconciles the change in the net deferred income
tax liability from December 31, 2000, to December 31, 2001, to the
deferred income tax expense included in the Consolidated Statements of
Income:
2001
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 50,487
Deferred taxes associated with acquisitions (29,807)
Other 334
Deferred income tax expense for the period $ 21,014
Total income tax expense differs from the amount computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for this difference are as follows:
Years ended December 31, 2001 2000 1999
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $88,966 35.0 $63,237 35.0 $46,686 35.0
Increases (reductions)
resulting from:
State income taxes,
net of federal
income tax benefit 11,311 4.5 8,044 4.4 5,921 4.4
Investment tax credit
amortization (731) (.3) (853) (.5) (888) (.6)
Depletion allowance (1,820) (.7) (1,631) (.9) (1,300) (1.0)
Other items 615 .2 853 .5 (1,109) (.8)
Total income tax expense $98,341 38.7 $69,650 38.5 $49,310 37.0
NOTE 10
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 company's operations are conducted through six business segments.
Substantially all of the company's operations are located within the
United States. The electric segment generates, transmits and
distributes electricity and the natural gas distribution segment
distributes natural gas. These operations also supply related
value-added products and services in the northern Great Plains. The
utility services segment consists of a diversified infrastructure
company specializing in engineering, design and build capability for
electric, gas and telecommunication utility construction, as well as
industrial and commercial electrical, exterior lighting and traffic
signalization throughout most of the United States. Utility services
provides related specialty equipment manufacturing sales and rental
services. 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.
Energy-related marketing and management services as well as cable and
pipeline locating services also are provided. The pipeline and energy
services segment includes investments in domestic and international
growth opportunities. The natural gas and oil production segment is
engaged in natural gas and oil acquisition, exploration and production
activities primarily in the Rocky Mountain region of the United States
and in the Gulf of Mexico. The construction materials and mining
segment mines aggregates and markets crushed stone, sand, gravel and
other related construction materials, including ready-mixed concrete,
cement and asphalt, as well as value-added products and services in the
north central and western United States, including Alaska and Hawaii.
In 2001, the company sold its coal operations to Westmoreland Coal
Company for $28.2 million in cash, including final settlement cost
adjustments. The sale of the coal operations was effective April 30,
2001. Included in the sale were active coal mines in North Dakota and
Montana, coal sales agreements, reserves and mining equipment, and
certain development rights at the former Gascoyne Mine site in North
Dakota. The company retains ownership of coal reserves and leases at
its former Gascoyne Mine site. Including final settlement cost
adjustments, the company recorded a gain of $10.3 million ($6.2 million
after-tax) included in other income - net from the sale in 2001.
On August 30, 2001, MDU Resources International, Inc. (MDU
International), a wholly owned subsidiary of the company, through an
indirect wholly owned Brazilian subsidiary, entered into a joint
venture agreement with a Brazilian firm under which the parties have
formed MPX Holdings, Ltda. (MPX) to develop electric generation and
transmission, steam generation, power equipment, coal mining and
construction materials projects in Brazil. MDU International has a 49
percent interest in MPX. MPX is currently developing, through a wholly
owned subsidiary, and has under construction a 200-megawatt natural gas-
fired power plant (Project) in the Brazilian state of Ceara. The
Project is expected to enter commercial operation in the second quarter
of 2002. MPX expects to enter into an agreement with Petrobras, the
state-controlled energy company, under which Petrobras would purchase
all of the capacity and market all of the Project's energy. Petrobras
would also supply natural gas to the Project when energy is dispatched.
The Project has a total estimated construction cost of approximately
$96 million. At December 31, 2001, MDU International's investment in
the Project was approximately $23.8 million. In addition, the
company's subsidiaries had guaranteed Project obligations and loans for
approximately $17.3 million as of December 31, 2001.
Segment information follows the same accounting policies as described
in the Summary of Significant Accounting Policies. Segment information
included in the accompanying Consolidated Balance Sheets as of
December 31 and included in the Consolidated Statements of Income for
the years then ended is as follows:
2001 2000 1999
(In thousands)
External operating revenues:
Electric $ 168,837 $ 161,621 $ 154,869
Natural gas distribution 255,389 233,051 157,692
Utility services 364,746 169,382 99,917
Pipeline and energy services 479,108 579,207 334,188
Natural gas and oil production 148,653 99,014 63,238
Construction materials and mining 801,883 617,564 455,939
Total external operating revenues $2,218,616 $1,859,839 $1,265,843
Intersegment operating revenues:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services 4 --- ---
Pipeline and energy services 52,006 57,641 49,344
Natural gas and oil production 61,178 39,302 15,156
Construction materials and mining(a) 5,016 13,832 13,966
Intersegment eliminations (113,188) (96,943) (64,500)
Total intersegment
operating revenues(a) $ 5,016 $ 13,832 $ 13,966
Depreciation, depletion and
amortization:
Electric $ 19,488 $ 19,115 $ 18,375
Natural gas distribution 9,337 8,399 7,348
Utility services 8,395 4,912 2,591
Pipeline and energy services 14,341 15,301 8,248
Natural gas and oil production 41,690 27,008 19,248
Construction materials and mining 46,666 36,153 26,008
Total depreciation, depletion
and amortization $ 139,917 $ 110,888 $ 81,818
Interest expense:
Electric $ 8,531 $ 10,007 $ 9,692
Natural gas distribution 3,727 4,142 3,614
Utility services 3,807 2,492 812
Pipeline and energy services 9,136 10,029 7,281
Natural gas and oil production 1,359 5,160 3,405
Construction materials and mining 19,339 16,415 11,202
Intersegment eliminations --- (212) ---
Total interest expense $ 45,899 $ 48,033 $ 36,006
Income taxes:
Electric $ 10,511 $ 10,048 $ 8,678
Natural gas distribution 1,067 3,544 1,443
Utility services 9,131 6,027 4,323
Pipeline and energy services 11,633 9,214 13,356
Natural gas and oil production 40,486 23,906 10,032
Construction materials and mining 25,513 16,911 11,478
Total income taxes $ 98,341 $ 69,650 $ 49,310
Earnings on common stock:
Electric $ 18,717 $ 17,733 $ 15,973
Natural gas distribution 677 4,741 3,192
Utility services 12,910 8,607 6,505
Pipeline and energy services 16,406 10,494 20,972
Natural gas and oil production 63,178 38,574 16,207
Construction materials and mining 43,199 30,113 20,459
Total earnings on common stock $ 155,087 $ 110,262 $ 83,308
Capital expenditures:
Electric $ 14,373 $ 15,788 $ 18,218
Natural gas distribution 14,685 21,336 9,246
Utility services 70,232 42,633 16,052
Pipeline and energy services 51,054 69,006 35,123
Natural gas and oil production 118,719 173,441 64,294
Construction materials and mining 170,585 218,716 105,098
Net proceeds from sale or
disposition of property (51,641) (11,000) (16,660)
Total net capital expenditures $ 388,007 $ 529,920 $ 231,371
Identifiable assets:
Electric(b) $ 291,229 $ 305,099 $ 307,417
Natural gas distribution(b) 182,705 192,854 131,294
Utility services 239,069 123,451 67,755
Pipeline and energy services 346,879 362,592 302,587
Natural gas and oil production 476,105 410,207 255,416
Construction materials and mining 1,035,929 874,299 655,499
Corporate assets(c) 51,155 44,457 46,335
Total identifiable assets $2,623,071 $2,312,959 $1,766,303
Property, plant and equipment:
Electric (b) $ 597,080 $ 589,700 $ 581,090
Natural gas distribution (b) 238,566 227,742 185,797
Utility services 59,190 39,865 21,876
Pipeline and energy services 410,049 369,834 308,409
Natural gas and oil production 630,826 513,419 343,157
Construction materials and mining 820,984 755,563 601,952
Less accumulated depreciation,
depletion and amortization 947,377 895,109 794,105
Net property, plant and equipment $1,809,318 $1,601,014 $1,248,176
(a) In accordance with the provision of SFAS No. 71, intercompany coal
sales are not eliminated.
(b) Includes, in the case of electric and natural gas distribution
property, allocations of common utility property.
(c) Corporate assets consist of assets not directly assignable to a
business segment (i.e., cash and cash equivalents, certain accounts
receivable and other miscellaneous current and deferred assets).
Capital expenditures for 2001, 2000 and 1999, related to acquisitions,
in the preceding table include the following noncash transactions:
issuance of the company's equity securities of $57.4 million in 2001;
issuance of the company's equity securities and the conversion of a
note receivable to purchase consideration of $132.1 million in 2000;
and issuance of the company's equity securities of $77.5 million in
1999.
NOTE 11
Acquisitions
In 2001, the company acquired a number of businesses, none of which was
individually material, including construction materials and mining
businesses in Hawaii, Minnesota and Oregon; utility services businesses
based in Missouri and Oregon; and an energy services company
specializing in cable and pipeline locating and tracking systems. The
total purchase consideration for these businesses, consisting of the
company's common stock and cash, was $170.1 million.
In 2000, the company acquired a number of businesses, none of which was
individually material, including construction materials and mining
businesses with operations in Alaska, California, Montana and Oregon; a
coalbed natural gas development operation based in Colorado with
related oil and gas leases and properties in Montana and Wyoming;
utility services businesses based in California, Colorado, Montana and
Ohio; a natural gas distribution business serving southeastern North
Dakota and western Minnesota; and an energy services company based in
Texas. The total purchase consideration for these businesses,
consisting of the company's common stock, cash and the conversion of a
note receivable to purchase consideration, was $286.0 million.
On April 1, 2000, Fidelity Exploration & Production Company (Fidelity),
an indirect wholly owned subsidiary of the company, purchased
substantially all of the assets of Preston Reynolds & Co., Inc.
(Preston), a coalbed natural gas development operation, as previously
discussed. Pursuant to the asset purchase and sale agreement, Preston
may, but is not obligated to purchase, acquire and own an undivided 25
percent working interest (Seller's Option Interest) in certain oil and
gas leases or properties acquired and/or generated by Fidelity. The
Seller's Option Interest commences April 1, 2002 and terminates six
months thereafter and requires Preston to pay Fidelity 25 percent of
its capital investment, during the two year period subsequent to
April 1, 2000, in the oil and gas leases or properties. Fidelity has
the right, but not the obligation, to purchase Seller's Option Interest
from Preston for an amount as specified in the agreement.
In 1999, the company acquired a number of businesses, none of which was
individually material, including construction materials and mining
companies with operations in California, Montana, Oregon and Wyoming;
and utility services companies based in Montana and Oregon. The total
purchase consideration for these businesses, consisting of the
company's common stock and cash, was $81.9 million.
The above acquisitions were accounted for under the purchase method of
accounting and accordingly, the acquired assets and liabilities assumed
have been preliminarily recorded at their respective fair values as of
the date of acquisition. Final fair market values are pending the
completion of the review of the relevant assets, liabilities and issues
identified as of the acquisition date on certain of the above
acquisitions made in 2001. The results of operations of the acquired
businesses are included in the financial statements since the date of
each acquisition. Pro forma financial amounts reflecting the effects
of the above acquisitions are not presented as such acquisitions were
not material to the company's financial position or results of
operations.
NOTE 12
Employee Benefit Plans
The company has noncontributory defined benefit pension plans and other
postretirement benefit plans. Changes in benefit obligation and plan
assets for the years ended December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
2001 2000 2001 2000
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $200,880 $180,997 $69,467 $65,939
Service cost 4,716 4,561 1,376 1,307
Interest cost 14,498 14,174 4,691 4,946
Plan participants' contributions --- --- 866 677
Amendments (1,342) 7,111 --- ---
Actuarial (gain) loss 8,128 9,535 (2,109) 928
Divestiture* (10,017) --- (2,871) ---
Benefits paid (12,817) (15,498) (4,401) (4,330)
Benefit obligation at
end of year 204,046 200,880 67,019 69,467
Change in plan assets:
Fair value of plan assets at
beginning of year 261,864 276,459 47,046 47,147
Actual return on plan assets (13,828) 875 (2,235) (1,078)
Employer contribution 337 28 3,899 4,630
Plan participants' contributions --- --- 866 677
Divestiture* (10,889) --- --- ---
Benefits paid (12,817) (15,498) (4,401) (4,330)
Fair value of plan assets at end
of year 224,667 261,864 45,175 47,046
Funded status 20,621 60,984 (21,844) (22,421)
Unrecognized actuarial gain (26,170) (76,417) (10,799) (15,228)
Unrecognized prior service cost 10,278 16,271 --- ---
Unrecognized net transition
obligation (asset) (2,195) (3,387) 23,665 28,532
Prepaid (accrued) benefit cost $ 2,534 $(2,549) $(8,978) $(9,117)
* See Note 10 for more information on the sale of the company's coal
operations.
Weighted average assumptions for the company's pension and other
postretirement benefit plans as of December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
2001 2000 2001 2000
Discount rate 7.25% 7.50% 7.25% 7.50%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Health care rate assumptions for the company's other postretirement
benefit plans as of December 31 are as follows:
2001 2000
Health care trend rate 6.00%-7.00% 6.00%-7.50%
Health care cost trend rate - ultimate 5.00%-6.00% 5.00%-6.00%
Year in which ultimate trend rate achieved 1999-2004 1999-2004
Components of net periodic benefit cost for the company's pension and
other postretirement benefit plans are as follows:
Other
Pension Postretirement
Benefits Benefits
Years ended December 31, 2001 2000 1999 2001 2000 1999
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 4,716 $ 4,561 $ 4,894 $ 1,376 $ 1,307 $1,451
Interest cost 14,498 14,174 12,573 4,691 4,946 4,720
Expected return on assets (20,672) (19,927) (17,489) (3,619) (3,267) (2,807)
Amortization of prior
service cost 1,247 1,047 842 --- --- ---
Recognized net actuarial
gain (2,687) (2,907) (995) (930) (799) (200)
Settlement (gain) loss (884) (700) --- 15 --- ---
Amortization of net
transition obligation
(asset) (965) (997) (997) 2,227 2,378 2,377
Net periodic benefit cost
(income) (4,747) (4,749) (1,172) 3,760 4,565 5,541
Less amount capitalized (391) (397) (87) 329 369 463
Net periodic benefit
expense (income) $(4,356) $(4,352) $(1,085) $ 3,431 $ 4,196 $5,078
The company's other postretirement benefit plans include health care
and life insurance benefits. The plans underlying these benefits may
require contributions by the employee depending on such employee's age
and years of service at retirement or the date of retirement. The
accounting for the health care plans anticipates future cost-sharing
changes that are consistent with the company's expressed intent to
generally increase retiree contributions each year by the excess of the
expected health care cost trend rate over 6 percent.
Assumed health care cost trend rates may have a significant effect on
the amounts reported for the health care plans. A one percentage point
change in the assumed health care cost trend rates would have the
following effects at December 31, 2001:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 260 $ (229)
Effect on postretirement benefit
obligation $ 3,326 $(2,906)
In addition to company-sponsored plans, certain employees are covered
under multi-employer defined benefit plans administered by a union.
Amounts contributed to the multi-employer plans were $19.9 million,
$10.6 million and $6.8 million in 2001, 2000 and 1999, respectively.
The company has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that provides for defined
benefit payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period. Investments consist of
life insurance carried on plan participants, which is payable to the
company upon the employee's death. The cost of these benefits was
$4.3 million, $3.5 million and $3.3 million in 2001, 2000 and 1999,
respectively.
The company sponsors various defined contribution plans for eligible
employees. Costs incurred by the company under these plans were
$7.2 million in 2001, $6.1 million in 2000 and $4.4 million in 1999.
The costs incurred in each year reflect additional participants as a
result of business acquisitions.
NOTE 13
Jointly Owned Facilities
The consolidated financial statements include the company's 22.7
percent and 25.0 percent ownership interests in the assets, liabilities
and expenses of the Big Stone Station and the Coyote Station,
respectively. Each owner of the Big Stone and Coyote stations is
responsible for financing its investment in the jointly owned
facilities.
The company's share of the Big Stone Station and Coyote Station
operating expenses is reflected in the appropriate categories of
operating expenses in the Consolidated Statements of Income.
At December 31, the company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
2001 2000
(In thousands)
Big Stone Station:
Utility plant in service $ 50,053 $ 50,029
Less accumulated depreciation 32,956 31,381
$ 17,097 $ 18,648
Coyote Station:
Utility plant in service $122,436 $122,111
Less accumulated depreciation 67,414 63,741
$ 55,022 $ 58,370
NOTE 14
Regulatory Matters and Revenues Subject To Refund
In December 1999, Williston Basin Interstate Pipeline Company
(Williston Basin), an indirect wholly owned subsidiary of the company,
filed a general natural gas rate change application with the FERC.
Williston Basin began collecting such rates effective June 1, 2000,
subject to refund. On May 9, 2001, the Administrative Law Judge issued
an Initial Decision on Williston Basin's natural gas rate change
application, which matter is currently pending before and subject to
revision by the FERC.
Reserves have been provided for a portion of the revenues that have
been collected subject to refund with respect to the pending regulatory
proceeding. Williston Basin, in the fourth quarter of 2000, determined
that reserves it had previously established for certain regulatory
proceedings, prior to the proceeding filed in 1999, exceeded its
expected refund obligation and, accordingly, reversed reserves and
recognized in income $6.7 million after-tax. Williston Basin, in the
second quarter of 1999, determined that reserves it had previously
established in relation to a 1992 general natural gas rate change
application and the 1995 general rate increase application exceeded its
expected refund obligation and, accordingly, reversed reserves and
recognized in income $4.4 million after-tax. Williston Basin believes
that its remaining reserves are adequate based on its assessment of the
ultimate outcome of the application filed in December 1999.
NOTE 15
Commitments and Contingencies
Litigation
In March 1997, 11 natural gas producers filed suit in North Dakota
Southwest Judicial District Court (North Dakota District Court) against
Williston Basin and the company. The natural gas producers had
processing agreements with Koch Hydrocarbon Company (Koch). Williston
Basin and the company had natural gas purchase contracts with Koch.
The natural gas producers alleged they were entitled to damages for the
breach of Williston Basin's and the company's contracts with Koch
although no specific damages were stated. A similar suit was filed by
Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) in
North Dakota Northwest Judicial District Court in December 1993. The
North Dakota Supreme Court in December 1999 affirmed the North Dakota
Northwest Judicial District Court decision dismissing Apache's and
Snyder's claims against Williston Basin and the company. Based in part
upon the decision of the North Dakota Supreme Court affirming the
dismissal of the claims brought by Apache and Snyder, Williston Basin
and the company filed motions for summary judgment to dismiss the
claims of the 11 natural gas producers. The motions for summary
judgment were granted by the North Dakota District Court in July 2000.
On March 5, 2001, the North Dakota District Court entered a final
judgment on the July 2000 order granting the motions for summary
judgment. On May 4, 2001, the 11 natural gas producers appealed the
North Dakota District Court's decision by filing a Notice of Appeal
with the North Dakota Supreme Court. Oral argument was held before the
North Dakota Supreme Court on December 12, 2001. Williston Basin and
the company are awaiting a decision from the North Dakota Supreme
Court.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in United States
District Court for the District of Columbia (U.S. District Court)
against Williston Basin and over 70 other natural gas pipeline
companies. Grynberg, acting on behalf of the United States under the
Federal False Claims Act, alleged improper measurement of the heating
content or volume of natural gas purchased by the defendants resulting
in the underpayment of royalties to the United States. In March 1997,
the U.S. District Court dismissed the suit without prejudice and the
dismissal was affirmed by the United States Court of Appeals for the
D.C. Circuit in October 1998. In June 1997, Grynberg filed a similar
Federal False Claims Act suit against Williston Basin and Montana-
Dakota Utilities Co. (Montana-Dakota) and filed over 70 other separate
similar suits against natural gas transmission companies and producers,
gatherers, and processors of natural gas. In April 1999, the United
States Department of Justice decided not to intervene in these cases.
In response to a motion filed by Grynberg, the Judicial Panel on
Multidistrict Litigation consolidated all of these cases in the Federal
District Court of Wyoming (Federal District Court). Oral argument on
motions to dismiss was held before the Federal District Court in
March 2000. On May 18, 2001, the Federal District Court denied
Williston Basin's and Montana-Dakota's motion to dismiss. The matter
is currently pending.
The Quinque Operating Company (Quinque), on behalf of itself and
subclasses of gas producers, royalty owners and state taxing
authorities, instituted a legal proceeding in State District Court for
Stevens County, Kansas, (State District Court) against over 200 natural
gas transmission companies and producers, gatherers, and processors of
natural gas, including Williston Basin and Montana-Dakota. The
complaint, which was served on Williston Basin and Montana-Dakota in
September 1999, contains allegations of improper measurement of the
heating content and volume of all natural gas measured by the
defendants other than natural gas produced from federal lands. In
response to a motion filed by the defendants in this suit, the Judicial
Panel on Multidistrict Litigation transferred the suit to the Federal
District Court for inclusion in the pretrial proceedings of the
Grynberg suit. Upon motion of plaintiffs, the case has been remanded
to State District Court. On September 12, 2001, the defendants in this
suit filed a motion to dismiss with the State District Court. The
matter is currently pending.
Williston Basin and Montana-Dakota believe the claims of Grynberg and
Quinque are without merit and intend to vigorously contest these suits.
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 there is no
pending legal proceeding against or involving the company, except those
discussed above, for which the outcome is likely to have a material
adverse effect upon the company's financial position or results of
operations.
Environmental matters
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned
subsidiary of the company, was named by the United States Environmental
Protection Agency (EPA) as a Potentially Responsible Party in
connection with the cleanup of a commercial property site, now owned by
MBI, 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. Based upon a review of the
Portland Harbor sediment contamination evaluation by the Oregon State
Department of Environmental Quality and other information available,
MBI does not believe it is a Responsible Party. In addition, MBI
intends to seek indemnity for any and all liabilities incurred in
relation to the above matters from Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, pursuant to the terms of
their sale agreement.
Operating leases
The company leases certain equipment, facilities and land under
operating lease agreements. The amounts of annual minimum lease
payments due under these leases as of December 31, 2001, are
$17.4 million in 2002, $14.3 million in 2003, $11.0 million in 2004,
$8.3 million in 2005, $6.3 million in 2006 and $25.1 million
thereafter. Rent expense related to operating leases was approximately
$31.5 million, $23.7 million and $15.4 million for the years ended
December 31, 2001, 2000 and 1999, respectively.
Purchase commitments
The company has entered into various commitments, largely purchased-
power, coal and natural gas supply, and natural gas transportation
contracts. These commitments range from one to 17 years. The
commitments under these contracts as of December 31, 2001, are
$108.8 million in 2002, $53.1 million in 2003, $46.9 million in 2004,
$39.2 million in 2005, $33.2 million in 2006 and $126.5 million
thereafter. These commitments are not reflected in the company's
consolidated financial statements.
Guarantees
The company has certain financial guarantees largely consisting of
guarantees on obligations and loans on the natural gas-fired power
plant project in the Brazilian state of Ceara. For more information on
the natural gas-fired power plant project see Note 10. These
guarantees, as of December 31, 2001, are approximately $20.6 million
for 2002. These guarantees are not reflected in the consolidated
financial statements.
NOTE 16
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter for
the years 2001 and 2000:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
2001
Operating revenues $641,248 $546,418 $551,680 $484,286
Operating expenses 577,727 476,071 458,441 438,125
Operating income 63,521 70,347 93,239 46,161
Net income 32,687 43,417 50,746 28,999
Earnings per common share:
Basic .50 .64 .75 .42
Diluted .49 .63 .74 .42
Weighted average common shares
outstanding:
Basic 65,405 67,264 67,650 68,729
Diluted 65,979 68,376 68,127 69,126
2000
Operating revenues $371,989 $362,979 $530,834 $607,869
Operating expenses 342,559 321,900 454,811 537,414
Operating income 29,430 41,079 76,023 70,455
Net income 13,364 21,126 39,992 36,546
Earnings per common share:
Basic .23 .35 .63 .57
Diluted .23 .35 .63 .56
Weighted average common shares
outstanding:
Basic 57,051 59,987 62,975 64,289
Diluted 57,188 60,212 63,345 64,817
Certain company operations are highly seasonal and revenues from and
certain expenses for such operations may fluctuate significantly among
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 17
Natural Gas and Oil Activities (Unaudited)
Fidelity is involved in the acquisition, exploration, development and
production of natural gas and oil resources. Fidelity's activities
include the acquisition of producing properties with potential
development opportunities, exploratory drilling and the operation and
development of natural gas production properties. Fidelity shares
revenues and expenses from the development of specified properties
located primarily in the Rocky Mountain region of the United States and
in the Gulf of Mexico in proportion to its interests.
Fidelity owns in fee or holds natural gas leases for the properties it
operates in Colorado, Montana, North Dakota and Wyoming. These rights
are in the Bonny Field located in eastern Colorado, the Cedar Creek
Anticline in southeastern Montana and southwestern North Dakota, the
Bowdoin area located in north-central Montana and in the Powder River
Basin of Wyoming and Montana.
The information that follows includes the company's proportionate share
of all its natural gas and oil interests held by Fidelity.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to natural gas and oil
producing activities at December 31:
2001 2000 1999
(In thousands)
Subject to amortization $506,155 $416,881 $319,448
Not subject to amortization 122,354 94,856 23,464
Total capitalized costs 628,509 511,737 342,912
Less accumulated depreciation,
depletion and amortization 195,469 155,198 129,211
Net capitalized costs $433,040 $356,539 $213,701
Capital expenditures, including those not subject to amortization,
related to natural gas and oil producing activities are as follows:
Years ended December 31, 2001 2000 1999
(In thousands)
Acquisitions $ 1,695 $ 68,858 $ 30,842
Exploration 13,938 34,839 11,010
Development 102,670 69,051 21,822
Total capital expenditures $118,303 $172,748 $ 63,674
The following summary reflects income resulting from the company's
operations of natural gas and oil producing activities, excluding
corporate overhead and financing costs:
Years ended December 31, 2001 2000 1999
(In thousands)
Revenues $203,727 $128,217 $ 75,327
Production costs 47,045 33,919 25,402
Depreciation, depletion and
amortization 41,223 26,739 19,136
Pretax income 115,459 67,559 30,789
Income tax expense 45,245 25,835 11,815
Results of operations for
producing activities $ 70,214 $ 41,724 $ 18,974
The following table summarizes the company's estimated quantities of
proved natural gas and oil reserves at December 31, 2001, 2000 and
1999, and reconciles the changes between these dates. Estimates of
economically recoverable natural gas and oil reserves and future net
revenues therefrom are based upon a number of variable factors and
assumptions. For these reasons, estimates of economically recoverable
reserves and future net revenues may vary from actual results.
2001 2000 1999
Natural Natural Natural
Gas Oil Gas Oil Gas Oil
(In thousands of Mcf/barrels)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 309,800 15,100 268,900 14,700 243,600 11,500
Production (40,600) (2,000)(29,200) (1,900)(24,700) (1,800)
Extensions and
discoveries 66,400 2,000 51,300 1,600 21,800 800
Purchases of proved
reserves 1,000 100 23,200 100 38,200 700
Sales of reserves
in place --- --- --- (100) (9,300) (400)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions (12,500) 2,300 (4,400) 700 (700) 3,900
Balance at end
of year 324,100 17,500 309,800 15,100 268,900 14,700
Proved developed reserves:
January 1, 1999 193,000 10,700
December 31, 1999 213,400 13,300
December 31, 2000 263,400 14,200
December 31, 2001 291,300 17,100
All of the company's interests in natural gas and oil reserves are
located in the United States and in the Gulf of Mexico.
The standardized measure of the company's estimated discounted future
net cash flows of total proved reserves associated with its various
natural gas and oil interests at December 31 is as follows:
2001 2000 1999
(In thousands)
Future net cash flows before
income taxes $548,000 $2,349,500 $492,000
Future income tax expense 112,000 827,000 131,500
Future net cash flows 436,000 1,522,500 360,500
10% annual discount for estimated
timing of cash flows 174,000 601,200 131,400
Discounted future net cash flows
relating to proved natural gas
and oil reserves $262,000 $ 921,300 $229,100
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
2001 2000 1999
(In thousands)
Beginning of year $ 921,300 $229,100 $125,100
Net revenues from production (153,500) (94,300) (49,900)
Change in net realization (1,119,700) 861,700 123,100
Extensions, discoveries and
improved recovery, net of
future production-related costs 64,200 288,700 33,500
Purchases of proved reserves 2,600 93,200 57,700
Sales of reserves in place --- (1,500) (14,700)
Changes in estimated future
development costs, net of those
incurred during the year (3,300) 3,400 (9,800)
Accretion of discount 126,900 31,200 16,700
Net change in income taxes 436,500 (412,300) (59,800)
Revisions of previous quantity
estimates (11,700) (79,200) 7,400
Other (1,300) 1,300 (200)
Net change (659,300) 692,200 104,000
End of year $ 262,000 $921,300 $229,100
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end natural gas
prices and oil prices. Future development and production costs
attributable to proved reserves were computed by applying year-end
costs to be incurred in producing and further developing the proved
reserves. Future income tax expenses were computed by applying
statutory tax rates (adjusted for permanent differences and tax
credits) to estimated net future pretax cash flows.
The standardized measure of discounted future net cash flows does not
purport to represent the fair market value of natural gas and oil
properties. There are significant uncertainties inherent in estimating
quantities of proved reserves and in projecting rates of production and
the timing and amount of future costs. In addition, future realization
of natural gas and oil prices over the remaining reserve lives may vary
significantly from current prices.
NOTE 18
Subsequent Event
In January 2002, Fidelity Oil Co. (FOC), one of the company's natural
gas and oil production subsidiaries, entered into a compromise
agreement with the former operator of certain of FOC's oil production
properties in southeastern Montana. The compromise agreement resolved
litigation involving the interpretation and application of contractual
provisions regarding net proceeds interests paid by the former operator
to FOC for a number of years prior to 1998. The terms of the
compromise agreement are confidential. As a result of the compromise
agreement, the natural gas and oil production segment will reflect a
nonrecurring gain in its financial results for the first quarter of
2002 of approximately $16.6 million after-tax. As part of the
settlement, FOC gave the former operator a full and complete release,
and FOC is not asserting any such claim against the former operator for
periods after 1997.
Report of Independent Public Accountants
To MDU Resources Group, Inc.:
We have audited the accompanying consolidated balance sheets of MDU
Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of
December 31, 2001 and 2000, and the related consolidated statements of
income, common stockholders' equity and cash flows for each of the
three years in the period ended December 31, 2001. These financial
statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of MDU
Resources Group, Inc. and Subsidiaries as of December 31, 2001 and
2000, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.
As explained in Note 1 to the consolidated financial statements,
effective January 1, 2001, the company changed its method of accounting
for derivative instruments due to the adoption of a new accounting
pronouncement.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 23, 2002
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
2001 2000 1999 1998* 1997 1996 1991
Selected Financial Data
Operating revenues (000's):
Electric $ 168,837 $ 161,621 $ 154,869 $ 147,221 $ 141,590 $ 138,761 $ 128,708
Natural gas distribution 255,389 233,051 157,692 154,147 157,005 155,012 138,634
Utility services 364,750 169,382 99,917 64,232 22,761 --- ---
Pipeline and energy services 531,114 636,848 383,532 180,732 87,018 71,580 108,397
Natural gas and oil production 209,831 138,316 78,394 61,842 77,916 75,350 41,583
Construction materials and mining 806,899 631,396 469,905 346,451 174,147 132,222 41,201
Intersegment eliminations (113,188) (96,943) (64,500) (57,998) (52,763) (58,224) (80,810)
$2,223,632 $1,873,671 $1,279,809 $ 896,627 $ 607,674 $ 514,701 $ 377,713
Operating income (000's):
Electric $ 38,731 $ 38,743 $ 35,727 $ 32,167 $ 31,307 $ 29,476 $ 34,647
Natural gas distribution 3,576 9,530 6,688 8,028 10,410 11,504 8,518
Utility services 25,199 16,606 11,518 5,932 1,782 --- ---
Pipeline and energy services 30,368 28,782 40,627 33,651 25,822 27,697 15,516
Natural gas and oil production 103,943 66,510 26,845 (50,444) 27,638 26,786 16,940
Construction materials and mining 71,451 56,816 38,346 41,609 14,602 16,062 9,682
$ 273,268 $ 216,987 $ 159,751 $ 70,943 $ 111,561 $ 111,525 $ 85,303
Earnings on common stock (000's):
Electric $ 18,717 $ 17,733 $ 15,973 $ 13,908 $ 12,441 $ 11,436 $ 15,292
Natural gas distribution 677 4,741 3,192 3,501 4,514 4,892 3,645
Utility services 12,910 8,607 6,505 3,272 947 --- ---
Pipeline and energy services 16,406 10,494 20,972 18,651 9,955 1,649 (1,950)
Natural gas and oil production 63,178 38,574 16,207 (30,501) 15,867 15,185 10,409
Construction materials and mining 43,199 30,113 20,459 24,499 10,111 11,521 9,809
$ 155,087 $ 110,262 $ 83,308 $ 33,330 $ 53,835 $ 44,683 $ 37,205
Earnings per common share -- diluted $ 2.29 $ 1.80 $ 1.52 $ .66 $ 1.24 $ 1.04 $ .87
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 67,869 61,390 54,870 50,837 43,478 42,824 42,715
Dividends per common share $ .90 $ .86 $ .82 $ .7834 $ .7534 $ .7333 $ .6378
Book value per common share $ 15.90 $ 13.55 $ 11.74 $ 10.39 $ 8.84 $ 8.21 $ 6.95
Market price per common share (year-end) $ 28.15 $ 32.50 $ 20.00 $ 26.31 $ 21.08 $ 15.33 $ 10.95
Market price ratios:
Dividend payout 39% 48% 54% 119% 61% 70% 73%
Yield 3.3% 2.7% 4.2% 3.0% 3.6% 4.8% 5.8%
Price/earnings ratio 12.3x 18.1x 13.2x 39.9x 17.0x 14.6x 12.6x
Market value as a percent of book value 177.0% 239.9% 170.4% 253.2% 238.5% 186.8% 157.7%
Profitability Indicators
Return on average common equity 15.3% 14.3% 13.9% 6.5% 14.6% 13.0% 12.7%
Return on average invested capital 10.1% 9.5% 9.6% 5.5% 10.3% 9.5% 9.6%
Interest coverage 8.5x 8.3x 7.1x 6.1x 6.0x 5.4x 3.8x**
Fixed charges coverage, including
preferred dividends 5.3x 4.1x 4.3x 2.5x 3.4x 2.7x 2.4x
General
Total assets (000's) $2,623,071 $2,312,959 $1,766,303 $1,452,775 $1,113,892 $1,089,173 $ 964,691
Net long-term debt (000's) $ 783,709 $ 728,166 $ 563,545 $ 413,264 $ 298,561 $ 280,666 $ 220,623
Redeemable preferred stock (000's) $ 1,400 $ 1,500 $ 1,600 $ 1,700 $ 1,800 $ 1,900 $ 2,400
Capitalization ratios:
Common equity 58% 54% 54% 56% 55% 54% 56%
Preferred stocks 1 1 1 2 2 3 3
Long-term debt 41 45 45 42 43 43 41
100% 100% 100% 100% 100% 100% 100%
<FN>
* Reflects $39.9 million or 78 cents per common share in noncash after-tax write-downs of natural gas and oil properties.
** Calculation reflects the provisions of the company's restatement of its indenture of mortgage effective April 1992.
</FN>
NOTE: Common stock share amounts reflect the company's three-for-two common stock splits effected in October 1995 and July 1998.
2001 2000 1999 1998 1997 1996 1991
Electric
Sales to ultimate consumers (thousand kWh) 2,177,886 2,161,280 2,075,446 2,053,862 2,041,191 2,067,926 1,877,634
Sales for resale (thousand kWh) 898,178 930,318 943,520 586,540 361,954 374,535 331,314
Electric system generating and firm purchase
capability -- kW (Interconnected system) 500,820 500,420 492,800 489,100 487,500 481,800 454,400
Demand peak -- kW (Interconnected system) 453,000 432,300 420,550 402,500 404,600 393,300 387,100
Electricity produced (thousand kWh) 2,469,573 2,331,188 2,350,769 2,103,199 1,826,770 1,829,669 1,736,187
Electricity purchased (thousand kWh) 792,641 948,700 860,508 730,949 769,679 809,261 611,884
Average cost of fuel and purchased
power per kWh $.018 $.016 $.016 $.017 $.018 $.017 $.016
Natural Gas Distribution
Sales (Mdk) 36,479 36,595 30,931 32,024 34,320 38,283 30,074
Transportation (Mdk) 14,338 14,314 11,551 10,324 10,067 9,423 12,261
Weighted average degree days --
% of previous year's actual 95% 113% 95% 94% 85% 114% 101%
Pipeline and Energy Services
Pipeline:
Sales for resale (Mdk) --- --- --- --- --- --- 19,572
Transportation (Mdk) 97,199 86,787 78,061 88,974 85,464 82,169 53,930
Gathering (Mdk) 61,136 41,717 19,799 9,093 9,550 8,983 6,116
Energy services:
Natural gas volumes (Mdk) 82,682 149,823 131,687 58,495 14,971 4,670 991
Natural Gas and Oil Production
Production:
Natural gas (MMcf) 40,591 29,222 24,652 20,699 20,407 20,391 6,557
Oil (000's of barrels) 2,042 1,882 1,758 1,912 2,088 2,149 1,491
Average realized prices:
Natural gas (per Mcf) $ 3.78 $ 2.90 $ 1.94 $ 1.81 $ 2.02 $ 1.79 $ 1.74
Oil (per barrel) $24.59 $23.06 $15.34 $12.71 $17.50 $17.91 $19.90
Net recoverable reserves:
Natural gas (MMcf) 324,100 309,800 268,900 243,600 184,900 200,200 27,500
Oil (000's of barrels) 17,500 15,100 14,700 11,500 14,900 16,100 11,600
Construction Materials and Mining
Construction materials (000's):
Aggregates (tons sold) 27,565 18,315 13,981 11,054 5,113 3,374 ---
Asphalt (tons sold) 6,228 3,310 2,993 1,790 758 694 ---
Ready-mixed concrete (cubic yards sold) 2,542 1,696 1,186 1,021 516 340 ---
Recoverable aggregate reserves (tons) 1,065,330 894,500 740,030 654,670 169,375 119,800 ---
Coal (000's):
Sales (tons) 1,171* 3,111 3,236 3,113 2,375 2,899 4,731
Recoverable reserves (tons) 56,012* 145,643 182,761 190,152 226,560 228,900 256,700
<FN>
* Coal operations were sold effective April 30, 2001.
</FN>
Change in Accountants
On February 14, 2002, upon the recommendation of the Audit
Committee of the Board of Directors, the Board of Directors of
the company approved the dismissal of Arthur Andersen LLP (Arthur
Andersen) as the company's independent auditors following the
2001 audit. The company has not selected independent auditors
for the 2002 fiscal year, but is currently in the process of
reviewing new auditor candidates and expects to make a selection
in the near future.
In connection with the audits for the two most recent fiscal
years and through February 20, 2002, there have been no
disagreements with Arthur Andersen on any matter of accounting
principles or practices, financial statement disclosure, or
auditing scope or procedure, which disagreements, if not resolved
to the satisfaction of Arthur Andersen, would have caused Arthur
Andersen to make reference thereto in its report on the financial
statements of the company for such time periods. Also, during
those time periods, there have been no "reportable events," as
such term is used in Item 304 (a)(1)(v) of Regulation S-K.
Arthur Andersen's reports on the financial statements of the
company for the last two years neither contained an adverse
opinion or disclaimer of opinion, nor were they qualified or
modified as to uncertainty, audit scope, or accounting
principles.
We have provided Arthur Andersen a copy of the company's Form 8-K
prior to its filing with the Securities and Exchange Commission
(Commission). Arthur Andersen has provided us with a letter,
addressed to the Commission, which is filed as an Exhibit to the
company's Form 8-K, as filed with the Commission on February 20,
2002.
To MDU Resources Group, Inc.:
We have audited in accordance with auditing standards
generally accepted in the United States, the financial
statements included in MDU Resources Group, Inc.'s annual
report to stockholders incorporated by reference in this Form
10-K, and have issued our report thereon dated January 23,
2002. Our audit was made for the purpose of forming an
opinion on those statements taken as a whole. Schedule II is
the responsibility of the company's management and is
presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the
auditing procedures applied in the audit of the basic
financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth
therein in relation to the basic financial statements taken as
a whole.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 23, 2002
MDU RESOURCES GROUP, INC.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Additions
Balance at Charged to Balance
beginning costs and at end
Description of year expenses Other(a)(b) Deductions(c) of year
- ----------- ---------- ---------- ----------- ------------- -------
(In thousands)
Allowance for
doubtful accounts:
2001 $4,063 $3,896 $2,003 $4,189 $5,773
2000 $2,111 $4,252 $1,085 $3,385 $4,063
1999 $1,685 $1,359 $ 395 $1,328 $2,111
(a) Allowance for doubtful accounts for companies acquired
(b) Recoveries
(c) Uncollectible accounts written off