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 of America 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 certain 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 Deloitte & Touche LLP,
independent auditors, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities. The internal
auditors and Deloitte & Touche LLP have full and free access to the
Audit Committee, without management present, to discuss auditing,
internal accounting control and financial reporting matters.
Deloitte & Touche 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 of America 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 Treasurer and
Chief Executive Officer Chief Financial Officer
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2002 2001 2000
(In thousands, except per share amounts)
Operating revenues $2,031,537 $2,223,632 $1,873,671
Operating expenses:
Fuel and purchased power 56,010 57,393 54,114
Purchased natural gas sold 92,528 529,356 634,277
Operation and maintenance 1,393,028 1,168,271 812,600
Depreciation, depletion and
amortization 157,961 139,917 110,888
Taxes, other than income 65,893 55,427 44,805
1,765,420 1,950,364 1,656,684
Operating income 266,117 273,268 216,987
Other income -- net 13,572 26,821 11,724
Interest expense 45,015 45,899 48,033
Income before income taxes 234,674 254,190 180,678
Income taxes 86,230 98,341 69,650
Net income 148,444 155,849 111,028
Dividends on preferred stocks 756 762 766
Earnings on common stock $ 147,688 $ 155,087 $ 110,262
Earnings per common share --
basic $ 2.09 $ 2.31 $ 1.80
Earnings per common share --
diluted $ 2.07 $ 2.29 $ 1.80
Dividends per common share $ .94 $ .90 $ .86
Weighted average common shares
outstanding -- basic 70,743 67,272 61,090
Weighted average common shares
outstanding -- diluted 71,242 67,869 61,390
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
December 31, 2002 2001
(In thousands, except shares and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 67,556 $ 41,811
Receivables, net 325,395 285,081
Inventories 93,123 95,341
Deferred income taxes 8,877 18,973
Prepayments and other current assets 42,597 40,286
537,548 481,492
Investments 42,864 38,198
Property, plant and equipment 3,003,996 2,647,121
Less accumulated depreciation,
depletion and amortization 1,079,110 942,723
1,924,886 1,704,398
Deferred charges and other assets:
Goodwill (Note 3) 190,999 173,997
Other intangible assets, net (Note 3) 176,164 163,978
Other 64,788 61,008
431,951 398,983
$2,937,249 $2,623,071
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings (Note 7) $ 20,000 $ ---
Long-term debt and preferred
stock due within one year 22,183 11,185
Accounts payable 132,120 110,649
Taxes payable 13,108 11,826
Dividends payable 17,959 16,108
Other accrued liabilities 94,275 95,559
299,645 245,327
Long-term debt (Note 8) 819,558 783,709
Deferred credits and other liabilities:
Deferred income taxes 374,097 342,412
Other liabilities 144,004 125,552
518,101 467,964
Preferred stock subject to mandatory
redemption (Note 9) 1,200 1,300
Commitments and contingencies (Notes 14, 16 and 17)
Stockholders' equity:
Preferred stocks (Note 9) 15,000 15,000
Common stockholders' equity:
Common stock (Note 10)
Authorized -- 250,000,000 shares,
$1.00 par value in 2002,
150,000,000 shares,
$1.00 par value in 2001
Issued -- 74,282,038 shares in 2002 and
70,016,851 shares in 2001 74,282 70,017
Other paid-in capital 748,095 646,521
Retained earnings 474,798 394,641
Accumulated other comprehensive
income (loss) (9,804) 2,218
Treasury stock at cost - 239,521 shares (3,626) (3,626)
Total common stockholders' equity 1,283,745 1,109,771
Total stockholders' equity 1,298,745 1,124,771
$2,937,249 $2,623,071
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Years ended December 31, 2002, 2001 and 2000
Accumu-
lated
Other
Compre-
Other hensive
Common Stock Paid-in Retained Income Treasury Stock
Shares Amount Capital Earnings (Loss) Shares Amount Total
(In thousands, except shares)
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 of tax -
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
Comprehensive income:
Net income --- --- --- 148,444 --- --- --- 148,444
Other comprehensive
loss, net of tax -
Net unrealized loss on
derivative instruments
qualifying as hedges --- --- --- --- (6,759) --- --- (6,759)
Minimum pension liability
adjustment --- --- --- --- (4,464) --- --- (4,464)
Foreign currency
translation adjustment --- --- --- --- (799) --- --- (799)
Total comprehensive
income --- --- --- --- --- --- --- 136,422
Dividends on
preferred stocks --- --- --- (756) --- --- --- (756)
Dividends on
common stock --- --- --- (67,531) --- --- --- (67,531)
Issuance of
common stock, net 4,265,187 4,265 101,574 --- --- --- --- 105,839
Balance at
December 31, 2002 74,282,038 $ 74,282 $748,095 $474,798 $(9,804) (239,521) $(3,626) $1,283,745
<FN>
The accompanying notes are an integral part of these consolidated statements.
</FN>
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2002 2001 2000
(In thousands)
Operating activities:
Net income $148,444 $155,849 $111,028
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 157,961 139,917 110,888
Deferred income taxes and
investment tax credit 30,759 21,014 36,530
Changes in current assets and
liabilities, net of acquisitions:
Receivables (19,739) 127,267 (117,449)
Inventories 6,537 (26,540) 9,578
Other current assets (5,562) (2,792) (3,514)
Accounts payable 11,600 (90,576) 61,021
Other current liabilities (9,499) 34,331 (3,821)
Other noncurrent changes 5,830 (9,916) 2,701
Net cash provided by operating
activities 326,331 348,554 206,962
Investing activities:
Capital expenditures (276,776) (269,542) (254,940)
Acquisitions, net of cash acquired (92,657) (112,743) (153,886)
Net proceeds from sale or
disposition of property 16,217 51,641 11,000
Investments (4,666) 2,760 2,102
Additions to notes receivable --- (23,813) (5,000)
Proceeds from notes receivable 4,000 4,000 4,000
Net cash used in investing
activities (353,882) (347,697) (396,724)
Financing activities:
Net change in short-term borrowings 20,000 (8,000) (7,242)
Issuance of long-term debt 129,072 122,283 192,162
Repayment of long-term debt (82,523) (115,062) (29,349)
Retirement of preferred stock (100) (100) (100)
Proceeds from issuance of
common stock, net 55,134 67,176 47,249
Dividends paid (68,287) (61,855) (53,950)
Net cash provided by
financing activities 53,296 4,442 148,770
Increase (decrease) in cash
and cash equivalents 25,745 5,299 (40,992)
Cash and cash equivalents --
beginning of year 41,811 36,512 77,504
Cash and cash equivalents --
end of year $ 67,556 $ 41,811 $ 36,512
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,
construction materials and mining and independent power production.
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, construction materials and mining, and independent
power production segments, and a portion of the pipeline and energy
services segment. For further descriptions of the Company's business
segments, see Note 12. The statements also include the ownership
interests in the assets, liabilities and expenses of two jointly owned
electric generation stations.
The Company uses the equity method of accounting for its 49 percent
interest in MPX Holdings, Ltda. (MPX), which was formed to develop
electric generation and transmission, steam generation, power equipment
and coal mining projects in Brazil. For more information on the
Company's equity investment, see Note 2.
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 generally is 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 4 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 12, intercompany coal sales, which were made at prices
approximately the same as those charged to others, and the related
utility fuel purchases were not eliminated in accordance with the
provisions of SFAS No. 71. All other significant intercompany balances
and transactions have been eliminated in consolidation.
Cash and cash equivalents
The Company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of December 31, 2002
and 2001, was $8.2 million and $5.8 million, respectively.
Natural gas in underground storage
Natural gas in underground storage for the Company's regulated
operations is carried at cost using the last-in, first-out method. The
portion of the cost of natural gas in underground storage expected to
be used within one year was included in inventories and amounted to
$18.2 million and $28.6 million at December 31, 2002 and 2001,
respectively. The remainder of natural gas in underground storage was
included in property, plant and equipment and was $42.2 million and
$43.1 million at December 31, 2002 and 2001, respectively.
Inventories
Inventories, other than natural gas in underground storage for the
Company's regulated operations, consisted primarily of materials and
supplies of $23.0 million and $22.5 million, aggregates held for resale
of $39.6 million and $31.1 million and other inventories of $12.3
million and $13.1 million as of December 31, 2002 and 2001,
respectively. These inventories were stated at the lower of average
cost or market.
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 $7.6 million, $6.6 million and $5.2 million in 2002,
2001 and 2000, respectively. Generally, property, plant and equipment
are depreciated on a straight-line basis over the average useful lives
of the assets, except for depletable reserves, which are depleted based
on the units of production method based on recoverable deposits, and
natural gas and oil production properties as described below.
Property, plant and equipment at December 31, 2002 and 2001, was as
follows:
Estimated
Depreciable
Life
2002 2001 in Years
(Dollars in thousands)
Regulated:
Electric:
Electric generation, distribution
and transmission plant $ 619,230 $ 597,080 4-50
Natural gas distribution:
Natural gas distribution plant(a) 246,844 238,566 4-40
Pipeline and energy services:
Natural gas transmission,
gathering and storage
facilities (b) 303,245 294,237 3-70
Nonregulated:
Utility services:
Land 2,601 2,330 ---
Buildings and improvements 8,768 4,586 10-40
Machinery, vehicles and equipment 54,833 46,090 2-10
Other 4,458 6,184 3-10
Pipeline and energy services:
Natural gas gathering
and other facilities 108,179 108,482 3-30
Energy services 1,270 7,330 3-15
Natural gas and oil production:
Natural gas and oil properties 748,844 628,509 (c)
Other 6,944 2,317 5-7
Construction materials and mining:
Land 85,376 80,526 ---
Buildings and improvements 43,144 43,069 3-39
Machinery, vehicles and equipment 493,349 412,856 3-20
Construction in progress 10,151 10,631 ---
Depletable reserves 172,235 164,328 (d)
Independent power production:
Electric generation 58,000 --- 20-30
Other 36,525 --- 3-20
Less accumulated depreciation,
depletion and amortization 1,079,110 942,723
Net property, plant and equipment $1,924,886 $1,704,398
(a) Includes natural gas in underground storage of $1.9 million and
$2.8 million at December 31, 2002 and 2001, respectively, which is
not subject to depreciation.
(b) Includes natural gas in underground storage of $40.3 million at
December 31, 2002 and 2001, which is not subject to depreciation.
(c) Amortized on the units of production method based on total proved
reserves.
(d) Depleted based on the units of production method based on
recoverable deposits.
Impairment of long-lived assets
The Company reviews the carrying values of its long-lived assets,
excluding goodwill, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable. 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 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 have been impaired and,
accordingly, no other impairment losses have been recorded in 2002,
2001 and 2000. Unforeseen events and changes in circumstances could
require the recognition of other impairment losses at some future date.
Goodwill
Goodwill represents the excess of the purchase price over the fair
value of identifiable net tangible and intangible assets acquired in a
business combination. On January 1, 2002, the Company adopted
Statement of Financial Accounting Standards No. 142, "Goodwill and
Other Intangibles" (SFAS No. 142) and ceased amortization of its
goodwill. Goodwill is required to be tested for impairment annually,
or more frequently if events or changes in circumstances indicate that
goodwill may be impaired. In accordance with SFAS No. 142, the Company
performed its transitional goodwill impairment testing as of January 1,
2002, and performed its annual goodwill impairment testing as of
October 31, 2002, and determined that no impairments existed at those
dates. For more information on goodwill and the adoption of SFAS
No. 142, see Note 3 and new accounting standards in Note 1 as discussed
below.
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.
At December 31, 2002 and 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, 2002, could
result in a future write-down of the Company's natural gas and oil
properties.
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 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
$19.4 million and $29.7 million for the years ended December 31, 2002
and 2001, respectively, represents revenues recognized in excess of
amounts billed and was included in receivables, net. Billings in
excess of costs on uncompleted contracts of $24.5 million and $17.3
million for the years ended December 31, 2002 and 2001, respectively,
represents billings in excess of revenues recognized and was included
in accounts payable. Also included in receivables, net were amounts
representing balances billed but not paid by customers under retainage
provisions in contracts that amounted to $25.6 million and
$20.5 million as of December 31, 2002 and 2001, respectively.
Derivative instruments
The Company's policy allows the use of derivative instruments as part
of an overall energy price, foreign currency and interest rate risk
management program to efficiently manage and minimize commodity price,
foreign currency and interest rate risk. The 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 derivative
instruments in the event of nonperformance by counterparties. The
Company's policy requires settlement of natural gas and oil price
derivative instruments monthly and all interest rate derivative
transactions must be settled over a period that will not exceed 90
days, and any foreign currency derivative transaction settlement
periods may not exceed a 12-month period. The Company has policies and
procedures that management believes minimize credit-risk exposure.
These policies and procedures include an evaluation of potential
counterparties' credit ratings and credit exposure limitations.
Accordingly, the Company does not anticipate any material effect to its
financial position or results of operations as a result of
nonperformance by counterparties.
Advertising
The Company expenses advertising costs as incurred, and the amount of
advertising expense for the years 2002, 2001 and 2000, was $3.4
million, $2.9 million and $2.0 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 that 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 $2.4 million and
$27.7 million at December 31, 2002 and 2001, respectively, and are
included in other accrued liabilities.
Insurance
Certain subsidiaries of the Company are insured for workers'
compensation losses, subject to deductibles ranging up to $500,000 per
occurrence. Automobile liability and general liability losses are
insured, subject to deductibles ranging up to $500,000 per accident or
occurrence. These subsidiaries have excess coverage on a per
occurrence basis beyond the deductible levels. The subsidiaries of the
Company are insuring for losses up to the deductible amounts, which are
accrued based on estimates of the liability for claims incurred and an
estimate of claims incurred but not reported.
Income taxes
The Company provides deferred federal and state income taxes on all
temporary differences between the book and tax basis of the Company's
assets and liabilities. Excess deferred income tax balances associated
with the Company's rate-regulated activities resulting from the
Company's adoption of Statement of Financial Accounting Standards
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 to 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 that conform to the ratemaking
treatment prescribed by the applicable state public service
commissions.
Foreign currency translation adjustment
The functional currency of the Company's investment in a 200-megawatt
natural gas-fired power plant in Brazil, as further discussed in
Note 2, is the Brazilian real. Translation from the Brazilian real to
the U.S. dollar for assets and liabilities is performed using the
exchange rate in effect at the balance sheet date. Revenues and
expenses have been translated using the weighted average exchange rate
for each month prevailing during the period reported. Adjustments
resulting from such translations are reported as a separate component
of other comprehensive income in common stockholders' equity.
Transaction gains and losses resulting from the effect of exchange rate
changes on transactions denominated in a currency other than the
functional currency of the reporting entity are recorded in income.
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 ended December 31, 2002 and 2001,
2,449,950 shares and 150,630 shares, respectively, with an average
exercise price of $30.13 and $36.86, 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 ended December 31, 2000, there were no shares excluded from
the calculation of diluted earnings per share. For the years ended
December 31, 2002, 2001 and 2000, 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.
Stock-based compensation
The Company has stock option plans for directors, key employees and
employees and accounts for these option plans in accordance with
Accounting Principles Board (APB) Opinion No. 25 under which no
compensation cost has been recognized. For more information on the
Company's stock-based compensation, see Note 10.
The following table illustrates the effect on earnings and earnings per
common share for the years ended December 31, 2002, 2001 and 2000, as
if the Company had applied Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123) to
its stock-based compensation:
2002 2001 2000
(In thousands, except per share amounts)
Earnings on common stock, as reported $147,688 $155,087 $110,262
Total stock-based compensation
expense determined under fair value
method for all awards, net of related
tax effects (2,862) (3,799) (529)
Pro forma earnings on common stock $144,826 $151,288 $109,733
Earnings per common share:
Basic -- as reported $ 2.09 $ 2.31 $ 1.80
Basic -- pro forma $ 2.05 $ 2.25 $ 1.80
Diluted -- as reported $ 2.07 $ 2.29 $ 1.80
Diluted -- pro forma $ 2.03 $ 2.23 $ 1.79
Use of estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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 items such as impairment testing of long-lived
assets, goodwill and natural gas and oil properties; fair values of
acquired assets and liabilities under the purchase method of
accounting; natural gas and oil reserves; 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; actuarially
determined benefit costs; the valuation of stock-based compensation;
and the fair value of an embedded derivative in a power purchase
agreement related to an equity method investment in Brazil, as
discussed in Note 2. 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, 2002 2001 2000
(In thousands)
Interest, net of amount capitalized $37,788 $42,267 $41,912
Income taxes $60,988 $75,284 $30,930
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 standards
In June 2001, the Financial Accounting Standards Board (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 lives
and reviewed for impairment in accordance with Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." For more information on the adoption
of SFAS No. 142, see Note 3.
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 has identified certain asset retirement obligations that
will be subject to the standard and adopted SFAS No. 143 on January 1,
2003. These obligations include the plugging and abandonment of
natural gas and oil wells; decommissioning of certain electric
generating facilities; reclamation of certain aggregate properties;
removal of certain natural gas distribution, transmission, storage and
gathering facilities, and certain other obligations associated with
leased properties. Certain natural gas distribution, transmission,
storage and gathering facilities have been determined to have
indeterminate useful lives. The adoption of SFAS No. 143 is expected
to result in a one-time cumulative effect after-tax charge to earnings
in the range of $7.0 million to $10.0 million and also is estimated to
reduce 2003 earnings before the cumulative effect charge by
approximately $1.6 million to $2.1 million. In addition, a regulatory
asset that is approximated to be less than $1.0 million will be
recognized for the transition amount that is expected to be recovered
in rates over time. The Company intends to record the cumulative
charge and regulatory asset in the first quarter of 2003.
In April 2002, the FASB approved Statement of Financial Accounting
Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS
No. 145). FASB No. 4 required all gains or losses from extinguishment
of debt to be classified as extraordinary items net of income taxes.
SFAS No. 145 requires that gains and losses from extinguishment of debt
be evaluated under the provisions of APB Opinion No. 30, and be
classified as ordinary items unless they are unusual or infrequent or
meet the specific criteria for treatment as an extraordinary item.
SFAS No. 145 is effective for fiscal years beginning after May 15,
2002. The Company believes the adoption of SFAS No. 145 will not have
a material effect on its financial position or results of operations.
In June 2002, the FASB approved Statement of Financial Accounting
Standards No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities" (SFAS No. 146). SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal
activities and nullifies EITF Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)" (EITF
No. 94-3). SFAS No. 146 requires recognition of a liability for a cost
associated with an exit or disposal activity when the liability is
incurred, as opposed to when the entity commits to an exit plan under
EITF No. 94-3. SFAS No. 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002, and is not
expected to have a material effect on the Company's financial position
or results of operations.
In September 2002, the Emerging Issues Task Force (EITF) reached a
consensus in EITF Issue No. 02-13, "Deferred Income Tax Considerations
in Applying the Goodwill Impairment Test in FASB Statement No. 142,
Goodwill and Other Intangible Assets" (EITF No. 02-13) that the
determination of whether to estimate the fair value of a reporting unit
by assuming that the unit could be bought or sold in a nontaxable
transaction versus a taxable transaction is a matter of judgment that
depends on the relevant facts and circumstances. The EITF also reached
the consensus that deferred income taxes should be included in the
carrying value of the reporting unit, regardless of whether the fair
value of the reporting unit will be determined assuming it would be
bought or sold in a taxable or nontaxable transaction. In addition,
EITF No. 02-13 states that for purposes of determining the implied fair
value of a reporting unit's goodwill, an entity should use the income
tax bases of a reporting unit's assets and liabilities implicit in the
tax structure assumed in its estimation of fair value of the reporting
unit. EITF No. 02-13 did not have a material effect on the Company's
goodwill impairment testing.
In October 2002, the EITF reached a consensus in EITF Issue No. 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities" (EITF No. 02-3) to rescind EITF Issue No. 98-10
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF No. 98-10). The impact of the rescission
of EITF No. 98-10 is to preclude mark-to-market accounting for all
energy trading contracts not within the scope of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities", as amended, (SFAS No. 133). In addition, the
EITF reached a consensus that gains and losses on derivative
instruments within the scope of SFAS No. 133 should be shown net in the
income statement if the derivative instruments are held for trading
purposes. The adoption of EITF No. 02-3 and rescission of EITF No. 98-
10 did not have a material effect on the Company's financial position
or results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
(Interpretation No. 45). Interpretation No. 45 clarifies the
disclosures to be made by a guarantor in its interim and annual
financial statements about its obligations under certain guarantees
that it has issued. Interpretation No. 45 also requires a guarantor to
recognize, at the inception of a guarantee, a liability for the fair
value of the obligation undertaken in issuing certain types of
guarantees. Certain types of guarantees are not subject to the initial
recognition and measurement provisions of Interpretation No. 45 but are
subject to its disclosure requirements. The initial recognition and
initial measurement provisions of Interpretation No. 45 are applicable
on a prospective basis to guarantees issued or modified after
December 31, 2002, regardless of the guarantor's fiscal year-end. The
guarantor's previous accounting for guarantees issued prior to the date
of the initial application of Interpretation No. 45 shall not be
revised or restated. The disclosure requirements in Interpretation No.
45 are effective for financial statements of interim or annual periods
ended after December 15, 2002. The Company will apply the initial
recognition and initial measurement provisions of Interpretation No. 45
to guarantees issued or modified after December 31, 2002. For more
information on the Company's guarantees and the disclosure requirements
of Interpretation No. 45, as applicable to the Company, see Note 17.
In December 2002, the FASB approved Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure - an amendment of FASB Statement No. 123"
(SFAS No. 148). SFAS No. 148 amends SFAS No. 123 to provide
alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation.
In addition, SFAS No. 148 amends the disclosure requirements of SFAS
No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported
results. SFAS No. 148 is effective for financial statements for fiscal
years ending after December 15, 2002. The Company had adopted the
disclosure provisions of SFAS No. 148 at December 31, 2002.
Comprehensive income
Comprehensive income is the sum of net income as reported and other
comprehensive income (loss). The Company's other comprehensive income
(loss) resulted from gains and losses on derivative instruments
qualifying as hedges, a minimum pension liability adjustment and a
foreign currency translation adjustment.
The components of other comprehensive income (loss) and their related
tax effects for the years ended December 31, 2002, 2001 and 2000, were
as follows:
2002 2001 2000
(In thousands)
Net unrealized gain (loss) 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 in 2001 $ --- $ (6,080) $ ---
Net unrealized gain (loss)
on derivative instruments
arising during the period,
net of tax of $2,903 and
$1,448 in 2002 and 2001,
respectively (4,541) 2,218 ---
Less: Reclassification adjustment
for gain (loss) on derivative
instruments included in
net income, net of tax of
$1,448 and $3,970 in 2002
and 2001, respectively 2,218 (6,080) ---
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges (6,759) 2,218 ---
Minimum pension liability
adjustment, net of tax of
$2,876 in 2002 (4,464) --- ---
Foreign currency translation
adjustment (799) --- ---
Total other comprehensive
income (loss) $(12,022) $ 2,218 $ ---
The after-tax components of accumulated other comprehensive income
(loss) as of December 31, 2002, 2001 and 2000, were as follows:
Net
Unrealized
Gain (Loss) on Total
Derivative Minimum Foreign Accumulated
Instruments Pension Currency Other
Qualifying Liability Translation Comprehensive
as Hedges Adjustment Adjustment Income (Loss)
(In thousands)
Balance at December 31, 2000 $ --- $ --- $ --- $ ---
Balance at December 31, 2001 $ 2,218 $ --- $ --- $ 2,218
Balance at December 31, 2002 $(4,541) $(4,464) $ (799) $(9,804)
NOTE 2
Equity Method Investment
In August 2001, a Brazilian subsidiary of the Company entered into a
joint venture agreement with a Brazilian firm under which the parties
have formed MPX. This subsidiary has a 49 percent interest in MPX.
MPX, through a wholly owned subsidiary, has constructed a 200-megawatt
natural gas-fired power plant (Project) in the Brazilian state of
Ceara. The first 100 megawatts entered commercial service in July
2002, and the second 100 megawatts entered commercial service in
January 2003. Petrobras, the partially Brazilian state-owned energy
company, has agreed to purchase all of the capacity and market all of
the Project's energy. Petrobras commenced making capacity payments in
the third quarter of 2002. The power purchase agreement with Petrobras
expires in May 2008. Petrobras also is under contract for five years
to supply natural gas to the Project. This contract is renewable for
an additional 13 years. The functional currency for the Project is the
Brazilian real. The power purchase agreement with Petrobras contains
an embedded derivative, which derives its value from an annual
adjustment factor, which largely indexes the contract capacity payments
to the U.S. dollar. At December 31, 2002, the Company's 49 percent
share of the gain from the embedded derivative in the power purchase
agreement was $13.6 million (after tax). In addition, the Company's 49
percent share of the foreign currency losses resulting from devaluation
of the Brazilian real totaled $9.4 million (after tax) for the year
ended December 31, 2002.
The Company's investment in the Project has been accounted for under
the equity method of accounting, and the Company's share of net income
for the year ended December 31, 2002, was included in other income -
net. At December 31, 2002 and 2001, the Company's investment in the
Project was approximately $27.8 million and $23.8 million,
respectively.
NOTE 3
Goodwill and Other Intangible Assets
The Company adopted SFAS No. 142, as discussed in Note 1, on January 1,
2002. The Company completed its transitional goodwill impairment
testing as of January 1, 2002, and performed its annual goodwill
impairment testing as of October 31, 2002, and determined that no
impairments existed at those dates. Therefore, no impairment loss has
been recorded for the year ended December 31, 2002.
On January 1, 2002, in accordance with SFAS No. 142, the Company ceased
amortization of its goodwill recorded in business combinations that
occurred on or before June 30, 2001. The following information is
presented as if SFAS No. 142 was adopted as of January 1, 2000. The
reconciliation of previously reported earnings and earnings per common
share to the amounts adjusted for the exclusion of goodwill
amortization, net of the related income tax effects, for the years
ended December 31, 2002, 2001 and 2000, were as follows:
2002 2001 2000
(In thousands, except per share amounts)
Reported earnings on common stock $147,688 $155,087 $110,262
Add: Goodwill amortization, net of tax --- 3,649 2,741
Adjusted earnings on common stock $147,688 $158,736 $113,003
Reported earnings per common
share -- basic $ 2.09 $ 2.31 $ 1.80
Add: Goodwill amortization, net of tax --- .05 .05
Adjusted earnings per common
share -- basic $ 2.09 $ 2.36 $ 1.85
Reported earnings per common
share -- diluted $ 2.07 $ 2.29 $ 1.80
Add: Goodwill amortization, net of tax --- .05 .04
Adjusted earnings per common
share -- diluted $ 2.07 $ 2.34 $ 1.84
The changes in the carrying amount of goodwill for the year ended
December 31, 2002, by business segment were as follows:
Balance Goodwill Balance
as of Acquired as of
January 1, During December 31,
2002 the Year 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 578 62,487
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 9,135 111,887
Independent power production --- 7,131 7,131
Total $173,997 $ 17,002 $190,999
Other intangible assets at December 31, 2002 and 2001, were as follows:
2002 2001
(In thousands)
Amortizable intangible assets:
Leasehold rights $172,496 $164,446
Accumulated amortization (7,494) (4,896)
165,002 159,550
Noncompete agreements 12,075 12,034
Accumulated amortization (9,366) (8,811)
2,709 3,223
Other 7,224 1,377
Accumulated amortization (374) (172)
6,850 1,205
Unamortizable intangible assets 1,603 ---
Total $176,164 $163,978
Amortization expense for amortizable intangible assets for the year
ended December 31, 2002, was $3.4 million. Estimated amortization
expense for amortizable intangible assets is $4.4 million in 2003,
$4.3 million in 2004, $4.4 million in 2005, $3.1 million in 2006,
$3.1 million in 2007 and $155.3 million thereafter.
NOTE 4
Regulatory Assets and Liabilities
The following table summarizes the individual components of unamortized
regulatory assets and liabilities as of December 31:
2002 2001
(In thousands)
Regulatory assets:
Long-term debt refinancing costs $ 5,627 $ 6,829
Deferred income taxes 4,230 13,417
Plant costs 2,330 2,499
Postretirement benefit costs 616 722
Other 4,788 5,929
Total regulatory assets 17,591 29,396
Regulatory liabilities:
Taxes refundable to customers 11,699 12,318
Reserves for regulatory matters 9,856 7,132
Plant decommissioning costs 8,879 8,243
Deferred income taxes 5,491 5,661
Natural gas costs refundable
through rate adjustments 2,396 27,706
Other 2,779 5,053
Total regulatory liabilities 41,100 66,113
Net regulatory position $(23,509) $ (36,717)
As of December 31, 2002, substantially all of the Company's regulatory
assets, other than certain deferred income taxes, were being reflected
in rates charged to customers and are being recovered over the next one
to 20 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 5
Derivative Instruments
The Company adopted 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 Opinion No. 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 reclassified into earnings during the year ended
December 31, 2001. The transition to SFAS No. 133 did not have an
effect on the Company's net income at adoption.
In the event a derivative instrument being accounted for as a cash flow
hedge 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
accumulated 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 had accumulated in other
comprehensive income (loss) would be recognized immediately in
earnings. In the event of a sale, termination or extinguishment of a
foreign currency derivative, the resulting gain or loss would be
recognized immediately in earnings. The Company's policy requires
approval to terminate a derivative instrument prior to its original
maturity.
As of December 31, 2002, certain subsidiaries of the Company held
derivative instruments designated as cash flow hedging instruments, and
a foreign currency derivative that was not designated as a hedge.
Hedging activities
A subsidiary of the Company utilizes natural gas and oil price swap and
collar agreements to manage a portion of the market risk associated
with fluctuations in the price of natural gas and oil on the
subsidiary's forecasted sales of natural gas and oil production.
Centennial Energy Holdings, Inc. (Centennial), a wholly owned
subsidiary of the Company, entered into an interest rate swap agreement
that expired in the fourth quarter of 2001. The objective for holding
the interest rate swap agreement was to manage a portion of
Centennial's interest rate risk on the forecasted issuance of fixed-
rate debt under Centennial's commercial paper program. Each of the
natural gas and oil price swap and collar agreements were designated as
a hedge of the forecasted sale of natural gas and oil production and
Centennial designated the interest rate swap agreement as a hedge of
the risk of changes in interest rates on Centennial's forecasted
issuances of fixed-rate debt under Centennial's commercial paper
program.
On an ongoing basis, the balance sheet is adjusted to reflect the
current fair market value of the swap and collar 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 years ended December 31, 2002 and 2001, these subsidiaries of
the Company recognized the ineffectiveness of cash flow hedges, which
is included in operating revenues and interest expense for the natural
gas and oil price swap and collar agreements and the interest rate swap
agreement, respectively. For the years ended December 31, 2002 and
2001, the amount of hedge ineffectiveness recognized was immaterial.
For the years ended December 31, 2002 and 2001, these subsidiaries 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, 2002, the maximum term of the
subsidiary's swap and collar agreements, in which the subsidiary of the
Company is hedging its exposure to the variability in future cash flows
for forecasted transactions, is 12 months. The subsidiary of the
Company estimates that over the next 12 months net losses of
approximately $4.5 million will be reclassified from accumulated other
comprehensive loss into earnings, subject to changes in natural gas and
oil market prices, as the hedged transactions affect earnings.
Foreign currency derivative
On August 12, 2002, an indirect wholly owned Brazilian subsidiary of
the Company entered into a foreign currency collar agreement for a
notional amount of $21.3 million with a fixed price floor of R$3.10 and
a fixed price ceiling of R$3.40 to manage a portion of its foreign
currency risk. A subsidiary of the Company has a 49 percent equity
investment in a 200-megawatt natural gas-fired electric generation
project in Brazil, which has a portion of its borrowings and payables
denominated in U.S. dollars. The Company's Brazilian subsidiary has
exposure to currency exchange risk as a result of fluctuations in
currency exchange rates between the U.S. dollar and the Brazilian real.
The term of the collar agreement is from August 12, 2002, through
February 3, 2003, and the collar agreement settles on February 3, 2003.
The foreign currency collar agreement has not been designated as a
hedge and is recorded at fair value on the Consolidated Balance Sheets.
Gains or losses on this derivative instrument are recorded in other
income - net. The Company recorded a gain of $566,000 (after tax) on
the foreign currency collar agreement for the year ended December 31,
2002.
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. Net unrealized gains and losses on these
derivative instruments were not material for the years ended
December 31, 2001 and 2000.
NOTE 6
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 values of the
Company's natural gas and oil price swap and collar agreements were
included in current liabilities and current assets at December 31, 2002
and 2001, respectively. The estimated fair value of the Company's
foreign currency collar agreement was included in current assets at
December 31, 2002. The estimated fair values of the Company's natural
gas and oil price swap and collar agreements and foreign currency
collar agreement reflect the estimated amounts the Company would
receive or pay to terminate the contracts at the reporting date based
upon quoted market prices of comparable contracts. The estimated fair
value of the Company's long-term debt, preferred stock subject to
mandatory redemption, natural gas and oil price swap and collar
agreements and foreign currency collar agreement at December 31 was as
follows:
2002 2001
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $841,641 $888,066 $794,794 $816,988
Preferred stock
subject to mandatory
redemption $ 1,300 $ 1,168 $ 1,400 $ 1,217
Natural gas and oil
price swap and
collar agreements $ (7,444) $ (7,444) $ 3,667 $ 3,667
Foreign currency
collar agreement $ 903 $ 903 $ --- $ ---
The carrying amounts of the Company's remaining financial instruments
included in current assets and current liabilities (excluding unsettled
derivative instruments) approximate their fair values because of their
short-term nature.
NOTE 7
Short-term Borrowings
MDU Resources Group, Inc.
MDU Resources Group, Inc. (MDU Resources) has unsecured short-term bank
lines of credit from several banks totaling $46 million and a revolving
credit agreement with various banks totaling $50 million at
December 31, 2002. The bank lines of credit provide for commitment
fees at varying rates and there were no amounts outstanding under the
bank lines of credit or the credit agreement at December 31, 2002 or
2001. The bank lines of credit and the credit agreement support MDU
Resources' $75 million commercial paper program. Under the MDU
Resources commercial paper program, $58.0 million was outstanding at
December 31, 2002, of which $8.0 million was classified as short-term
borrowings and $50.0 million was classified as long-term debt. There
were no amounts outstanding under MDU Resources' commercial paper
program at December 31, 2001. The commercial paper borrowings
classified as short term are supported by the short-term bank lines of
credit. The commercial paper borrowings classified as long-term debt
(see Note 8) are intended to be refinanced on a long-term basis through
continued MDU Resources commercial paper borrowings supported by the
credit agreement, which allows for subsequent borrowings up to a term
of one year. MDU Resources intends to renew or replace the existing
credit agreement, which expires December 30, 2003.
In order to borrow under MDU Resources' credit agreement, MDU Resources
must be in compliance with the applicable covenants and certain other
conditions. The significant covenants include maximum leverage ratios,
minimum interest coverage ratio, limitation on sale of assets and
limitation on investments. MDU Resources was in compliance with these
covenants and met the required conditions at December 31, 2002.
Currently, there are no credit facilities that contain cross-default
provisions between MDU Resources and any of its subsidiaries.
International operations
A subsidiary of the Company, which has an investment in electric
generating facilities in Brazil, has a short-term credit agreement that
allows for borrowings of up to $25 million. Under this agreement,
$12.0 million was outstanding at December 31, 2002, and there were no
amounts outstanding at December 31, 2001. This subsidiary intends to
renew this credit agreement, which expires June 30, 2003.
In order to borrow under the credit facility, the subsidiary must be in
compliance with the applicable covenants and certain other conditions.
The significant covenants include limitation on sale of assets and
limitation on loans and investments. This subsidiary was in compliance
with these covenants and met the required conditions at December 31,
2002.
NOTE 8
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 was as follows:
2002 2001
(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 6.90%, due on
dates ranging from May 4, 2003
to October 30, 2018 549,100 405,200
Commercial paper at a weighted average
rate of 1.47%, supported by revolving
credit agreements 151,900 219,700
Revolving line of credit, expired
December 31, 2002 --- 25,000
Term credit agreements at a weighted
average rate of 7.08%, due on dates
ranging from January 3, 2003
to December 1, 2013 7,873 11,769
Pollution control note obligation,
6.20%, due March 1, 2004 2,000 2,500
Discount (82) (225)
Total long-term debt 841,641 794,794
Less current maturities 22,083 11,085
Net long-term debt $ 819,558 $783,709
The amounts of scheduled long-term debt maturities for the five years
and thereafter following December 31, 2002, aggregate $22.1 million in
2003; $173.8 million in 2004; $70.3 million in 2005; $100.2 million in
2006; $105.4 million in 2007 and $369.8 million thereafter.
Certain debt instruments of the Company and its subsidiaries, including
those discussed below, contain restrictive covenants, all of which the
Company and its subsidiaries were in compliance with at December 31,
2002.
MDU Resources Group, Inc.
As discussed in Note 7, MDU Resources has a revolving credit agreement
with various banks that supports $50 million of its $75 million
commercial paper program.
At December 31, 2001, there was $25.0 million outstanding under a
previous revolving line of credit.
MDU Resources' issuance of first mortgage debt is subject to certain
restrictions imposed under the terms and conditions of its Indenture of
Mortgage. Generally, those restrictions require MDU Resources to
pledge $1.43 of unfunded property to the trustee for each dollar of
indebtedness incurred under the Indenture and that annual earnings
(pretax and before interest charges), as defined in the Indenture,
equal at least two times its annualized first mortgage bond interest
costs. Under the more restrictive of the two tests, as of December 31,
2002, MDU Resources could have issued approximately $327 million of
additional first mortgage bonds.
Centennial Energy Holdings, Inc.
Centennial has a revolving credit agreement with various banks that
supports $305 million of Centennial's $350 million commercial paper
program. There were no outstanding borrowings under the Centennial
credit agreement at December 31, 2002 and 2001. Under the Centennial
commercial paper program, $101.9 million and $219.7 million were
outstanding at December 31, 2002 and 2001, respectively. The
Centennial commercial paper borrowings are classified as long term as
Centennial intends to refinance these borrowings on a long-term basis
through continued Centennial commercial paper borrowings and as further
supported by the Centennial credit agreement, which allows for
subsequent borrowings up to a term of one year. Centennial intends to
renew the Centennial credit agreement, which expires September 26,
2003.
Centennial has an uncommitted long-term master shelf agreement that
allows for borrowings of up to $400 million. Under the terms of the
master shelf agreement, $360.6 million was outstanding at December 31,
2002, and $210.0 million was outstanding at December 31, 2001. The
amount outstanding under the uncommitted long-term master shelf
agreement is included in senior notes in the preceding long-term debt
table.
In order to borrow under Centennial's credit agreement and the
Centennial uncommitted long-term master shelf agreement, Centennial and
certain of its subsidiaries must be in compliance with the applicable
covenants and certain other conditions. The significant covenants
include maximum capitalization ratios, minimum interest coverage
ratios, minimum consolidated net worth, limitation on priority debt,
limitation on sale of assets and limitation on loans and investments.
Centennial and such subsidiaries were in compliance with these
covenants and met the required conditions at December 31, 2002.
The Centennial credit agreement and the Centennial uncommitted long-
term master shelf agreement contain cross-default provisions. These
provisions state that if Centennial or any subsidiary of Centennial
fails to make any payment with respect to any indebtedness or
contingent obligation, in excess of a specified amount, under any
agreement that causes such indebtedness to be due prior to its stated
maturity or the contingent obligation to become payable, the Centennial
credit agreement and the Centennial uncommitted long-term master shelf
agreement will be in default. The Centennial credit agreement, the
Centennial uncommitted long-term master shelf agreement and
Centennial's practice limit the amount of subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin Interstate Pipeline Company (Williston Basin), an
indirect wholly owned subsidiary of the Company, has an uncommitted
long-term master shelf agreement that allows for borrowings of up to
$100 million. Under the terms of the master shelf agreement, $30.0
million was outstanding at December 31, 2002.
In order to borrow under Williston Basin's uncommitted long-term master
shelf agreement, it must be in compliance with the applicable covenants
and certain other conditions. The significant covenants include
limitation on consolidated indebtedness, limitation on priority debt,
limitation on sale of assets and limitation on investments. Williston
Basin was in compliance with these covenants and met the required
conditions at December 31, 2002.
NOTE 9
Preferred Stocks
Preferred stocks at December 31 were as follows:
2002 2001
(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 - 13,000 shares in 2002
and 14,000 shares in 2001 $ 1,300 $ 1,400
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 16,300 16,400
Less sinking fund requirements 100 100
Net preferred stocks $16,200 $16,300
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, 2002, and $800,000 thereafter.
NOTE 10
Common Stock
At the Annual Meeting of Stockholders held on April 23, 2002, the
Company's common stockholders approved an amendment to the Certificate
of Incorporation increasing the authorized number of common shares from
150 million shares to 250 million shares with a par value of $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 partially funded with the
Company's common stock. Since January 1, 2000, the Stock Purchase Plan
and K-Plan, with respect to Company stock, have been funded by the
purchase of shares of common stock on the open market. At December 31,
2002, 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, that 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 and 348,021 shares in 2001 and
2000, 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 and $20.81 in 2001 and 2000,
respectively. The Company also has granted stock awards totaling
14,260 shares, 12,673 shares and 7,582 shares in 2002, 2001 and 2000,
respectively, under a nonemployee director stock compensation plan.
The weighted average grant date fair value of the stock grants was
$28.80, $30.14 and $22.98, in 2002, 2001 and 2000, respectively.
Nonemployee directors may receive shares of common stock instead of
cash in payment for director's fees under the nonemployee director
stock compensation plan. Compensation expense recognized for
restricted stock grants and stock grants was $5.2 million, $4.9 million
and $1.8 million in 2002, 2001 and 2000, respectively. The Company is
authorized to grant options, restricted stock and stock for up to 10.0
million shares of common stock and has granted options, restricted
stock and stock on 4.7 million shares through December 31, 2002.
For a discussion of the effect on earnings and earnings per common
share for the years ended December 31, 2002, 2001 and 2000, if the
Company had applied SFAS No. 123, see Note 1.
A summary of the status of the stock option plans at December 31, 2002,
2001 and 2000, and changes during the years then ended was as follows:
2002 2001 2000
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 3,472,207 $27.90 1,224,959 $20.61 1,427,262 $19.46
Granted 107,070 28.72 2,693,120 30.14 74,000 20.54
Forfeited (302,560) 29.66 (74,282) 27.24 (84,135) 21.18
Exercised (35,872) 18.30 (371,590) 20.23 (192,168) 11.84
Balance at end
of year 3,240,845 27.87 3,472,207 27.90 1,224,959 20.61
Exercisable at
end of year 756,700 $21.84 770,142 $21.41 129,763 $18.11
Summarized information about stock options outstanding and exercisable
as of December 31, 2002, was 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
$12.33 - 17.50 28,374 2.9 $13.62 28,374 $13.62
17.51 - 24.50 762,521 5.3 21.14 671,326 21.14
24.51 - 31.50 2,301,910 8.2 29.69 27,000 29.32
31.51 - 38.55 148,040 8.2 36.87 30,000 38.55
Balance at end of year 3,240,845 7.4 27.87 756,700 21.84
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 were as follows:
2002 2001 2000
Weighted average fair value of
options at grant date $ 8.07 $ 7.38 $ 5.07
Weighted average risk-free
interest rate 5.14% 5.19% 6.76%
Weighted average expected
price volatility 30.80% 26.05% 23.55%
Weighted average expected
dividend yield 3.43% 3.53% 3.84%
Expected life in years 7 7 7
NOTE 11
Income Taxes
Income tax expense for the years ended December 31 was as follows:
2002 2001 2000
(In thousands)
Current:
Federal $46,389 $ 66,211 $27,865
State 9,082 11,160 5,188
Foreign --- (44) 67
55,471 77,327 33,120
Deferred:
Income taxes --
Federal 26,373 16,972 29,323
State 4,632 4,773 8,060
Foreign 338 --- ---
Investment tax credit (584) (731) (853)
30,759 21,014 36,530
Total income tax expense $86,230 $ 98,341 $69,650
Components of deferred tax assets and deferred tax liabilities
recognized at December 31 were as follows:
2002 2001
(In thousands)
Deferred tax assets:
Accrued pension costs $ 12,112 $ 9,349
Regulatory matters 11,644 21,000
Deferred compensation 3,991 2,386
Bad debts 2,798 1,774
Deferred investment tax credit 1,185 1,413
Accrued land reclamation 263 1,648
Other 20,848 17,531
Total deferred tax assets 52,841 55,101
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 331,694 302,103
Basis differences on natural gas
and oil producing properties 70,464 61,684
Regulatory matters 5,491 5,661
Other 10,412 9,092
Total deferred tax liabilities 418,061 378,540
Net deferred income tax liability $(365,220) $(323,439)
As of December 31, 2002 and 2001, no valuation allowance has been
recorded associated with the above deferred tax assets.
The following table reconciles the change in the net deferred income
tax liability from December 31, 2001, to December 31, 2002, to deferred
income tax expense:
2002
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 41,781
Deferred taxes associated with acquisitions (17,217)
Deferred taxes associated with other comprehensive loss 7,227
Other (1,032)
Deferred income tax expense for the period $ 30,759
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 were as follows:
Years ended December 31, 2002 2001 2000
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $82,136 35.0 $88,966 35.0 $63,237 35.0
Increases (reductions)
resulting from:
State income taxes,
net of federal
income tax benefit 10,279 4.4 11,311 4.5 8,044 4.4
Investment tax credit
amortization (584) (.3) (731) (.3) (853) (.5)
Depletion allowance (2,200) (.9) (1,820) (.7) (1,631) (.9)
Other items (3,401) (1.5) 615 .2 853 .5
Total income tax expense $86,230 36.7 $98,341 38.7 $69,650 38.5
The Company considers earnings from its foreign equity method
investment in a natural gas-fired electric generation facility in
Brazil to be reinvested indefinitely outside of the United States and,
accordingly, no U.S. deferred income taxes are recorded with respect to
such earnings. Should the earnings be remitted as dividends, the
Company may be subject to additional U.S. taxes, net of allowable
foreign tax credits.
NOTE 12
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. Prior to the fourth quarter of 2002, the Company reported
six business segments consisting of electric, natural gas distribution,
utility services, pipeline and energy services, natural gas and oil
production and construction materials and mining. During the fourth
quarter of 2002, the Company added an additional segment, independent
power production, based on the significance of this segment's
operations. Substantially all of the operations of the independent
power production segment began in 2002, therefore financial information
for years prior to 2002 has not been presented.
The Company's operations are now conducted through seven business
segments. The vast majority of the Company's operations are located
within the United States. The Company also has investments in foreign
countries, which consists largely of an investment in a natural gas-
fired electric generation station in Brazil as discussed in Note 2.
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 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 also 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. The
pipeline and energy services segment also provides energy-related
management services, including cable and pipeline magnetization and
locating. The natural gas and oil production segment is engaged in
natural gas and oil acquisition, exploration 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 related
construction materials, including ready-mixed concrete, cement, asphalt
and other value-added products, as well as performing integrated
construction services, in the north central and western United States,
including Alaska and Hawaii. The independent power production segment
owns electric generating facilities in the United States and Brazil.
Electric capacity and energy produced at these facilities is sold under
long-term contracts to nonaffiliated entities. This segment also
invests in potential new growth and synergistic opportunities that are
not directly being pursued by other business segments.
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.
Segment information follows the same accounting policies as described
in the Summary of Significant Accounting Policies. Segment information
as of December 31 and for the years then ended was as follows:
2002 2001 2000
(In thousands)
External operating revenues:
Electric $ 162,616 $ 168,837 $ 161,621
Natural gas distribution 186,569 255,389 233,051
Utility services 458,660 364,746 169,382
Pipeline and energy services 110,224 479,108 579,207
Natural gas and oil production 148,158 148,653 99,014
Construction materials and mining 962,312 801,883 617,564
Independent power production 2,998 --- ---
Total external operating revenues $2,031,537 $2,218,616 $1,859,839
Intersegment operating revenues:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services --- 4 ---
Pipeline and energy services 55,034 52,006 57,641
Natural gas and oil production 55,437 61,178 39,302
Construction materials and mining --- 5,016(a) 13,832(a)
Independent power production 3,778 --- ---
Intersegment eliminations (114,249) (113,188) (96,943)
Total intersegment
operating revenues $ --- $ 5,016(a) $ 13,832(a)
Depreciation, depletion and
amortization:
Electric $ 19,537 $ 19,488 $ 19,115
Natural gas distribution 9,940 9,337 8,399
Utility services 9,871 8,395 4,912
Pipeline and energy services 14,846 14,341 15,301
Natural gas and oil production 48,714 41,690 27,008
Construction materials and mining 54,334 46,666 36,153
Independent power production 719 --- ---
Total depreciation, depletion
and amortization $ 157,961 $ 139,917 $ 110,888
Interest expense:
Electric $ 7,621 $ 8,531 $ 10,007
Natural gas distribution 4,364 3,727 4,142
Utility services 3,568 3,807 2,492
Pipeline and energy services 7,670 9,136 10,029
Natural gas and oil production 2,464 1,359 5,160
Construction materials and mining 18,422 19,339 16,415
Independent power production 1,122 --- ---
Intersegment eliminations (216) --- (212)
Total interest expense $ 45,015 $ 45,899 $ 48,033
Income taxes:
Electric $ 9,501 $ 10,511 $ 10,048
Natural gas distribution (1,325) 1,067 3,544
Utility services 4,781 9,131 6,027
Pipeline and energy services 12,462 11,633 9,214
Natural gas and oil production 30,604 40,486 23,906
Construction materials and mining 29,415 25,513 16,911
Independent power production 792 --- ---
Total income taxes $ 86,230 $ 98,341 $ 69,650
Earnings on common stock:
Electric $ 15,780 $ 18,717 $ 17,733
Natural gas distribution 3,587 677 4,741
Utility services 6,371 12,910 8,607
Pipeline and energy services 19,097 16,406 10,494
Natural gas and oil production 53,192 63,178 38,574
Construction materials and mining 48,702 43,199 30,113
Independent power production 959 --- ---
Total earnings on common stock $ 147,688 $ 155,087 $ 110,262
Capital expenditures:
Electric $ 27,795 $ 14,373 $ 15,788
Natural gas distribution 11,044 14,685 21,336
Utility services 17,242 70,232 42,633
Pipeline and energy services 21,449 51,054 69,006
Natural gas and oil production 136,424 118,719 173,441
Construction materials and mining 106,893 170,585 218,716
Independent power production 95,748 --- ---
Net proceeds from sale or
disposition of property (16,217) (51,641) (11,000)
Total net capital expenditures $ 400,378 $ 388,007 $ 529,920
Identifiable assets:
Electric(b) $ 310,519 $ 291,229 $ 305,099
Natural gas distribution(b) 170,672 182,705 192,854
Utility services 230,888 239,069 123,451
Pipeline and energy services 302,972 346,879 362,592
Natural gas and oil production 554,420 476,105 410,207
Construction materials and mining 1,137,697 1,035,929 874,299
Independent power production 148,770 --- ---
Corporate assets(c) 81,311 51,155 44,457
Total identifiable assets $2,937,249 $2,623,071 $2,312,959
Property, plant and equipment:
Electric (b) $ 619,230 $ 597,080 $ 589,700
Natural gas distribution (b) 246,844 238,566 227,742
Utility services 70,660 59,190 39,865
Pipeline and energy services 412,694 410,049 369,834
Natural gas and oil production 755,788 630,826 513,419
Construction materials and mining 804,255 711,410 653,189
Independent power production 94,525 --- ---
Less accumulated depreciation,
depletion and amortization 1,079,110 942,723 891,228
Net property, plant and equipment $1,924,886 $1,704,398 $1,502,521
(a) In accordance with the provision of SFAS No. 71, intercompany coal
sales were 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 2002, 2001 and 2000, related to acquisitions,
in the preceding table included the following noncash transactions:
issuance of the Company's equity securities of $47.2 million in 2002;
issuance of the Company's equity securities of $57.4 million in 2001;
and issuance of the Company's equity securities and the conversion of a
note receivable to purchase consideration of $132.1 million in 2000.
NOTE 13
Acquisitions
In 2002, the Company acquired a number of businesses, none of which was
individually material, including utility services companies in
California and Ohio, construction materials and mining businesses in
Minnesota and Montana, an energy development company in Montana and
natural gas-fired electric generating facilities in Colorado. The
total purchase consideration for these businesses, consisting of the
Company's common stock and cash, was $139.8 million.
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
could, but was 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.
Fidelity had the right, but not the obligation, to purchase Seller's
Option Interest from Preston for an amount as specified in the
agreement. On July 10, 2002, Fidelity purchased the Seller's Option
Interest.
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 2002. 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 14
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 and amounts recognized in the
Consolidated Balance Sheets at December 31 were as follows:
Other
Pension Postretirement
Benefits Benefits
2002 2001 2002 2001
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $204,046 $200,880 $67,019 $69,467
Service cost 5,135 4,716 1,460 1,376
Interest cost 14,877 14,498 4,915 4,691
Plan participants' contributions --- --- 834 866
Amendments 372 (1,342) --- ---
Actuarial (gain) loss 12,324 8,128 5,678 (2,109)
Divestiture* --- (10,017) --- (2,871)
Benefits paid (11,988) (12,817) (4,989) (4,401)
Benefit obligation at
end of year 224,766 204,046 74,917 67,019
Change in plan assets:
Fair value of plan assets at
beginning of year 224,667 261,864 45,175 47,046
Actual loss on plan assets (26,543) (13,828) (4,196) (2,235)
Employer contribution 3,007 337 4,065 3,899
Plan participants' contributions --- --- 834 866
Divestiture* --- (10,889) --- ---
Benefits paid (11,988) (12,817) (4,989) (4,401)
Fair value of plan assets at end
of year 189,143 224,667 40,889 45,175
Funded status - over (under) (35,623) 20,621 (34,028) (21,844)
Unrecognized actuarial (gain) loss 35,662 (26,170) 3,484 (10,799)
Unrecognized prior service cost 9,501 10,278 --- ---
Unrecognized net transition
obligation (asset) (1,247) (2,195) 21,513 23,665
Prepaid (accrued) benefit cost 8,293 2,534 (9,031) (8,978)
Amounts recognized in the
Consolidated Balance Sheets
at December 31:
Prepaid benefit cost 16,175 11,867 --- ---
Accrued benefit liability (7,882) (9,333) (9,031) (8,978)
Additional minimum liability (4,905) --- --- ---
Intangible asset 533 --- --- ---
Accumulated other
comprehensive loss 4,372 --- --- ---
Net amount recognized $ 8,293 $ 2,534 $(9,031) $(8,978)
* See Note 12 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 were as follows:
Other
Pension Postretirement
Benefits Benefits
2002 2001 2002 2001
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 4.50% 5.00% 4.50% 5.00%
Health care rate assumptions for the Company's other postretirement
benefit plans as of December 31 were as follows:
2002 2001
Health care trend rate 6.00%-11.00% 6.00%-11.00%
Health care cost trend rate - ultimate 5.00%-6.00% 5.00%-6.00%
Year in which ultimate trend rate achieved 1999-2011 1999-2010
Components of net periodic benefit expense (income) for the Company's
pension and other postretirement benefit plans were as follows:
Other
Pension Postretirement
Benefits Benefits
2002 2001 2000 2002 2001 2000
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 5,135 $ 4,716 $ 4,561 $ 1,460 $ 1,376 $ 1,307
Interest cost 14,877 14,498 14,174 4,915 4,691 4,946
Expected return on assets(21,110) (20,672) (19,927) (3,843) (3,619) (3,267)
Amortization of prior
service cost 1,148 1,247 1,047 --- --- ---
Recognized net actuarial
gain (1,855) (2,687) (2,907) (566) (930) (799)
Settlement (gain) loss --- (884) (700) --- 15 ---
Amortization of net
transition obligation
(asset) (947) (965) (997) 2,151 2,227 2,378
Net periodic benefit cost
(income) (2,752) (4,747) (4,749) 4,117 3,760 4,565
Less amount capitalized (352) (391) (397) 404 329 369
Net periodic benefit
expense (income) $(2,400) $(4,356) $(4,352) $ 3,713 $ 3,431 $ 4,196
The projected benefit obligation, accumulated benefit obligation and
fair value of plan assets, for the pension plans with accumulated
benefit obligations in excess of plan assets, were $22.1 million, $19.6
million and $17.3 million, respectively, as of December 31, 2002. As a
result of the accumulated benefit obligations exceeding the fair value
of plan assets for these plans, an additional minimum liability of $4.9
million was recognized in 2002. The additional minimum liability also
reflects the amount of prepaid benefit cost or accrued benefit
liability related to these plans.
The Company's other postretirement benefit plans include health care
and life insurance benefits for certain employees. 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, 2002:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 232 $ (841)
Effect on postretirement benefit
obligation $ 3,062 $(8,076)
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 $27.8 million,
$19.9 million and $10.6 million in 2002, 2001 and 2000, respectively.
In addition to the qualified plan defined pension benefits reflected in
the table at the beginning of this footnote, the Company also 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 or as an equivalent life annuity. 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
$5.1 million, $4.3 million and $3.5 million in 2002, 2001 and 2000,
respectively. The total projected obligation for this plan was $40.5
million and $41.0 million at December 31, 2002 and 2001, respectively.
The additional minimum liability relating to this plan was $4.0 million
at December 31, 2002. The Company has a related intangible asset
recognized as of December 31, 2002, of $1.1 million. The actuarial
valuations for this plan were determined based on a discount rate of
6.75 percent and 7.25 percent as of December 31, 2002 and 2001,
respectively, and a rate of compensation increase of 4.50 percent and
5.00 percent as of December 31, 2002 and 2001, respectively.
The Company sponsors various defined contribution plans for eligible
employees. Costs incurred by the Company under these plans were
$9.6 million in 2002, $7.2 million in 2001 and $6.1 million in 2000.
The costs incurred in each year reflect additional participants as a
result of business acquisitions.
NOTE 15
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 was 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:
2002 2001
(In thousands)
Big Stone Station:
Utility plant in service $ 53,018 $ 50,053
Less accumulated depreciation 34,456 32,956
$ 18,562 $ 17,097
Coyote Station:
Utility plant in service $122,476 $122,436
Less accumulated depreciation 70,778 67,414
$ 51,698 $ 55,022
NOTE 16
Regulatory Matters and Revenues Subject To Refund
On December 30, 2002, Montana-Dakota Utilities Co. (Montana-Dakota), a
public utility division of MDU Resources, filed an application with the
South Dakota Public Utilities Commission (SDPUC) for a natural gas rate
increase. Montana-Dakota requested a total of $2.2 million annually or
5.8 percent above current rates. A final order from the SDPUC is due
June 30, 2003.
On October 7, 2002, Great Plains Natural Gas Co. (Great Plains), a
public utility division of MDU Resources, filed an application with the
Minnesota Public Utilities Commission (MPUC) for a natural gas rate
increase. Great Plains requested a total of $1.6 million annually or
6.9 percent above current rates. On December 4, 2002, the MPUC issued
an Order setting interim rates that approved an interim increase of
$1.4 million annually effective December 6, 2002. Great Plains began
collecting such rates effective December 6, 2002, subject to refund
until the MPUC issues a final order. A final order from the MPUC is
due August 22, 2003.
On June 10, 2002, Montana-Dakota filed an application with the Wyoming
Public Service Commission (WYPSC) for a natural gas rate increase.
Montana-Dakota requested a total of $662,000 annually or 5.6 percent
above current rates. On December 9, 2002, the WYPSC approved an
increase of $466,000 annually effective January 1, 2003.
On May 20, 2002, Montana-Dakota filed an application with the Montana
Public Service Commission (MTPSC) for a natural gas rate increase.
Montana-Dakota requested a total of $3.6 million annually or 6.5
percent above current rates. On September 5, 2002, the MTPSC approved
an interim increase of $2.1 million annually, effective with service
rendered on and after September 5, 2002. Montana-Dakota began
collecting such rates effective September 5, 2002, which are subject to
refund until the MTPSC issues a final order. On November 7, 2002, the
MTPSC approved an additional interim increase of $300,000 annually
effective November 15, 2002. The additional interim increase is the
result of a Stipulation reached between Montana-Dakota and the Montana
Consumer Counsel, the only intervener in the proceeding. Under the
terms of the Stipulation, the total interim relief granted ($2.4
million) will be the final increase in the proceeding. A hearing
before the MTPSC was held on December 6, 2002, at which the MTPSC took
under advisement the Stipulation agreed upon by Montana-Dakota and the
Montana Consumer Counsel. A final order from the MTPSC is due
February 20, 2003.
On April 12, 2002, Montana-Dakota filed an application with the North
Dakota Public Service Commission (NDPSC) for a natural gas rate
increase. Montana-Dakota requested a total of $2.8 million annually or
4.1 percent above current rates. On December 10, 2002, the NDPSC
approved an increase of $2.0 million annually, effective with service
rendered on or after December 12, 2002.
Reserves have been provided for a portion of the revenues that have
been collected subject to refund for certain of the above proceedings.
The Company believes that such reserves are adequate based on its
assessment of the ultimate outcome of the proceedings.
The NDPSC authorized its Staff to initiate an investigation into the
earnings levels of Montana-Dakota's North Dakota electric operations
based on Montana-Dakota's 2000 Annual Report to the NDPSC. The
investigation was based on a complaint filed with the NDPSC in
September 2001, by the NDPSC Staff. On April 24, 2002, the NDPSC
issued an Order requiring Montana-Dakota to reduce its North Dakota
electric rates by $4.3 million annually, effective May 8, 2002. On
April 25, 2002, Montana-Dakota filed an appeal of the NDPSC Order in
the North Dakota South Central Judicial District Court (District
Court). The filing also requested a stay of the effectiveness of the
NDPSC Order while the appeal was pending. Montana-Dakota challenged
the NDPSC's determination of the level of wholesale electricity sales
margins expected to be received by Montana-Dakota. On May 2, 2002, the
District Court granted Montana-Dakota's request for a stay of a portion
of the $4.3 million annual rate reduction ordered by the NDPSC.
Accordingly, Montana-Dakota implemented an annual rate reduction of
$800,000 effective with service rendered on and after May 8, 2002,
rather than the $4.3 million annual reduction ordered by the NDPSC.
The remaining $3.5 million was subject to refund if Montana-Dakota did
not prevail in this proceeding. On November 22, 2002, the District
Court issued an Order reversing the decision of the NDPSC and remanded
the case back to the NDPSC. On January 15, 2003, the NDPSC issued an
Order accepting Montana-Dakota's level of wholesale electricity sales
margins thus reversing its initial decision and allowing Montana-Dakota
to continue to charge the electric rates which were in effect.
Montana-Dakota had established reserves for 2002 revenues that had been
collected subject to refund with respect to Montana-Dakota's pending
electric rate reduction. Based on the January 15, 2003, Order, as
previously discussed, the reserves were reversed and recognized in
income in 2002.
In December 1999, Williston Basin filed a general natural gas rate
change application with the FERC. Williston Basin began collecting
such rates effective June 1, 2000, subject to refund. In May 2001, the
Administrative Law Judge issued an Initial Decision on Williston
Basin's natural gas rate change application. This 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 Williston Basin's
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 believes that its remaining reserves are adequate based on its
assessment of the ultimate outcome of the application filed in December
1999.
NOTE 17
Commitments and Contingencies
Litigation
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 reflected 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.
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 and 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 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. In May 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. In September 2001, the defendants in this
suit filed a motion to dismiss with the State District Court. The
motion to dismiss was denied by the State District Court on August 19,
2002. 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.
Williston Basin and Montana-Dakota believe it is not probable that
Grynberg and Quinque will ultimately succeed given the current status
of the litigation.
The Company is also involved in other legal actions in the ordinary
course of its business. Although the outcomes of any such legal
actions cannot be predicted, management believes that the outcomes with
respect to these other legal proceedings will not have a material
adverse effect upon the Company's financial position or results of
operations.
Environmental matters
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.
The Company believes it is not probable that it will incur any material
environmental remediation costs or damages in relation to the above
administrative action.
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, 2002, were
$19.3 million in 2003, $14.3 million in 2004, $11.2 million in 2005,
$7.8 million in 2006, $4.3 million in 2007 and $21.3 million
thereafter. Rent expense related to operating leases was approximately
$26.9 million, $31.5 million and $23.7 million for the years ended
December 31, 2002, 2001 and 2000, respectively.
Purchase commitments
The Company has entered into various commitments, largely purchased
power, coal and natural gas supply, electric generation construction
and natural gas transportation contracts. These commitments range from
one to 18 years. The commitments under these contracts as of
December 31, 2002, were $171.3 million in 2003, $55.4 million in 2004,
$43.1 million in 2005, $37.0 million in 2006, $27.6 million in 2007 and
$130.4 million thereafter. These commitments are not reflected in the
Company's consolidated financial statements.
Guarantees
Centennial has guaranteed, with the right of subrogation, a portion of
certain obligations of MPX in connection with the Company's equity
method investment in the natural gas-fired electric generation station
in Brazil, as discussed in Note 2. The Company, through a subsidiary,
owns 49 percent of MPX. These guarantees expire in 2003, and at
December 31, 2002, the maximum amounts outstanding under these
guarantees totaled $24.9 million. In the event MPX defaults under its
obligations, Centennial would be required to make payments under these
guarantees. These guarantees are not reflected on the Consolidated
Balance Sheets.
In addition, Centennial has guaranteed, without recourse, the short-
term line of credit agreement of a subsidiary of the Company as
discussed in Note 7. The proceeds from the short-term line of credit
were used in connection with the Company's investment in international
projects. The fixed maximum amount of Centennial's guarantee of this
line of credit is $25 million and the amount outstanding under this
line of credit at December 31, 2002, was $12.0 million, which amount is
reflected on the Consolidated Balance Sheets. This subsidiary of the
Company intends to renew this credit agreement, which expires June 30,
2003. In the event this subsidiary of the Company defaults under its
obligation, Centennial would be required to make payments under its
guarantee.
Centennial has guaranteed, without recourse, a foreign currency collar
agreement obligation of an indirect wholly owned subsidiary of the
Company. There is no fixed maximum amount guaranteed under the foreign
currency collar agreement. The Company recorded an asset for the fair
value of the foreign currency collar agreement at December 31, 2002, of
$903,000, therefore there was no outstanding obligation guaranteed at
December 31, 2002. The foreign currency collar agreement expires on
February 3, 2003. In addition, WBI Holdings, Inc. (WBI Holdings), an
indirect wholly owned subsidiary of the Company, has guaranteed,
without recourse, certain of its subsidiary's natural gas and oil price
swap and collar agreement obligations. The amount of the subsidiary's
obligation at December 31, 2002, was $4.2 million. There is no fixed
maximum amount guaranteed in relation to the natural gas and oil price
swap and collar agreements; however, the amount of hedging activity
entered into by the subsidiary is limited by corporate policy. The
guarantees of the natural gas and oil price swap and collar agreements
expire in December 2003; however, WBI Holdings anticipates continued
hedging activities by its subsidiary, and, as a result, will likely
issue additional guarantees on potential hedging obligations. The
amounts outstanding under the natural gas and oil price swap and collar
agreements were reflected on the Consolidated Balance Sheets. In the
event the above subsidiaries default under their obligations,
Centennial and WBI Holdings would be required to make payments under
their respective guarantees.
Certain subsidiaries of the Company have outstanding guarantees to
third parties that guarantee the performance of other subsidiaries of
the Company that are related to natural gas transportation and sales
agreements, electric power supply agreements and certain other
guarantees. These guarantees are without recourse and at December 31,
2002, the fixed maximum amounts guaranteed under these agreements
aggregated $55.8 million. The amounts of scheduled expiration of the
maximum amounts guaranteed under these agreements aggregate $29.0
million in 2003; $1.4 million in 2004; $20.0 million in 2009; $2.0
million, which is subject to expiration 30 days after the receipt of
written notice; $425,000, which expires upon completion of a guaranteed
project and $3.0 million, which has no scheduled maturity date. In the
event of default under these guarantee obligations, the subsidiary
issuing the guarantee for that particular obligation would be required
to make payments under its guarantees. Any amounts outstanding by
subsidiaries of the Company under the above guarantees were reflected
on the Consolidated Balance Sheets at December 31, 2002.
In addition, Centennial has issued guarantees related to the Company's
purchase of maintenance items to third parties for which no fixed
maximum amounts have been specified. These guarantees are without
recourse and have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in relation to
the purchase of certain maintenance items, Centennial would be required
to make payments under these guarantees. Any amounts outstanding by
subsidiaries of the Company for maintenance were reflected on the
Consolidated Balance Sheets at December 31, 2002.
As of December 31, 2002, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately $200
million of surety bonds. These bonds are principally for construction
contracts and reclamation obligations of these subsidiaries, entered
into in the normal course of business. Centennial indemnifies the
respective surety bond companies against any exposure under the bonds.
A large portion of these contingent commitments expire in 2003, however
Centennial will likely continue to enter into surety bonds for its
subsidiaries in the future.
Centennial has also guaranteed a wholly owned subsidiary's payment to a
third party of the $102.5 million acquisition price in connection with
the acquisition of the 66.6-megawatt wind-powered electric generation
facility in California. The guarantee will terminate upon the
occurrence of the closing of the purchase of the above facility and is
without recourse. For more information on the purchase of this
facility, see Note 19.
NOTE 18
Inability to Obtain Consent of Prior Independent Public Accountants
There may be risks and stockholders' recovery may be limited as a
result of the Company's prior use of Arthur Andersen LLP as the
Company's independent public accounting firm. On June 15, 2002, Arthur
Andersen LLP was convicted for obstruction of justice charges. Arthur
Andersen LLP audited the Company's financial statements for the years
ended December 31, 2001 and 2000. On February 14, 2002, Arthur
Andersen LLP was dismissed as the Company's independent public
accountants and on March 25, 2002, Deloitte & Touche LLP was hired as
the Company's independent auditors for the 2002 fiscal year. Because
the former audit partner and manager have left Arthur Andersen LLP, the
Company was not able to obtain the written consent of Arthur Andersen
LLP as required by Section 7 of the Securities Act of 1933 (the
Securities Act). Accordingly, investors will not be able to sue Arthur
Andersen LLP pursuant to Section 11(a)(4) of the Securities Act and
therefore may have their recovery limited as a result of the lack of
consent.
NOTE 19
Subsequent Event
On January 31, 2003, Centennial Power, Inc., an indirect wholly owned
subsidiary of the Company, purchased a 66.6-megawatt wind-powered
electric generation facility from San Gorgonio Power Corporation, an
affiliate of PG&E National Energy Group, for $102.5 million cash,
subject to certain closing adjustments. This facility is located in
the San Gorgonio Pass, northwest of Palm Springs, California. The
facility consists of 111 wind turbines and began commercial operation
in September 2001. The facility sells all of its output under a long-
term contract with the California Department of Water Resources.
SeaWest Wind Power, Inc. will continue to operate the facility.
Independent Auditors' Report
To the Board of Directors and Stockholders of
MDU Resources Group, Inc.:
We have audited the accompanying consolidated balance sheet of MDU
Resources Group, Inc. (a Delaware corporation) and Subsidiaries as of
December 31, 2002, and the related consolidated statements of income,
common stockholders' equity, and cash flows for the year then ended.
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 audit. The consolidated financial
statements of the company as of December 31, 2001, and for the years
ended December 31, 2001 and 2000, were audited by other auditors who
have ceased operations and whose report, dated January 23, 2002,
expressed an unqualified opinion on those statements and included an
explanatory paragraph that described the company's change in its method
of accounting for derivative instruments due to the adoption of a new
accounting pronouncement as discussed in Note 5 to the financial
statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that
we plan and perform the audit to obtain reasonable assurance about
whether the 2002 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 audit
provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements present fairly, in all
material respects, the financial position of the company as of
December 31, 2002, and the results of its operations and its cash flows
for the year then ended in conformity with accounting principles
generally accepted in the United States of America.
As discussed above, the financial statements of the company as of
December 31, 2001, and for the years ended December 31, 2001 and 2000,
were audited by other auditors who have ceased operations. As
described in Note 3 these financial statements have been revised to
include the transitional disclosures required by Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets,"
(Statement) which, as described in Note 1, was adopted by the company
as of January 1, 2002. Our audit procedures with respect to the
disclosures in Note 3 with respect to 2001 and 2000 included (a)
agreeing the previously reported net income to the previously issued
financial statements and the adjustments to reported net income
representing amortization expense (including any related tax effects)
recognized in those periods related to goodwill that is no longer being
amortized as a result of initially applying the Statement to the
company's underlying records obtained from management, and (b) testing
the mathematical accuracy of the reconciliation of adjusted net income
to reported net income, and the related earnings per share amounts. In
our opinion, the disclosures for 2001 and 2000 in Note 3 are
appropriate. However, we were not engaged to audit, review, or apply
any procedures to the 2001 and 2000 financial statements of the company
other than with respect to such disclosures and, accordingly, we do not
express an opinion or any other form of assurance on the 2001 and 2000
financial statements taken as a whole.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
January 24, 2003
THIS IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP.
THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP NOR HAS ARTHUR
ANDERSEN LLP PROVIDED A CONSENT TO THE INCLUSION OF ITS REPORT IN THIS
ANNUAL REPORT. (SEE NOTE 18 OF NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS FOR FURTHER DISCUSSION.)
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
MDU RESOURCES GROUP, INC.
SUPPLEMENTARY FINANCIAL INFORMATION
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter for
the years 2002 and 2001:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
2002
Operating revenues $381,935 $480,218 $612,398 $556,986
Operating expenses 336,138 429,023 522,227 478,032
Operating income 45,797 51,195 90,171 78,954
Net income 23,722 24,853 53,931 45,938
Earnings per common share:
Basic .34 .35 .76 .63
Diluted .34 .35 .75 .63
Weighted average common shares
outstanding:
Basic 69,469 70,456 70,923 72,095
Diluted 70,013 71,027 71,344 72,576
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
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.
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 Montana and Wyoming.
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:
2002 2001 2000
(In thousands)
Subject to amortization $603,151 $506,155 $416,881
Not subject to amortization 145,692 122,354 94,856
Total capitalized costs 748,843 628,509 511,737
Less accumulated depreciation,
depletion and amortization 239,964 195,469 155,198
Net capitalized costs $508,879 $433,040 $356,539
Capital expenditures, including those not subject to amortization,
related to natural gas and oil producing activities were as follows:
Years ended December 31, 2002 2001 2000
(In thousands)
Acquisitions $ 31,439 $ 1,695 $ 68,858
Exploration 5,325 13,938 34,839
Development 94,943 102,670 69,051
Total capital expenditures $131,707 $118,303 $172,748
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, 2002* 2001 2000
(In thousands)
Revenues $203,550 $203,727 $128,217
Production costs 55,463 47,045 33,919
Depreciation, depletion and
amortization 48,064 41,223 26,739
Pretax income 100,023 115,459 67,559
Income tax expense 36,886 45,245 25,835
Results of operations for
producing activities $ 63,137 $ 70,214 $ 41,724
*Includes the compromise agreement as discussed in Note 17.
The following table summarizes the Company's estimated quantities of
proved natural gas and oil reserves at December 31, 2002, 2001 and
2000, 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.
2002 2001 2000
Natural Natural Natural
Gas Oil Gas Oil Gas Oil
(In thousands of Mcf/barrels)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 324,100 17,500 309,800 15,100 268,900 14,700
Production (48,200) (2,000)(40,600) (2,000)(29,200) (1,900)
Extensions and
discoveries 80,100 2,200 66,400 2,000 51,300 1,600
Purchases of proved
reserves 1,200 100 1,000 100 23,200 100
Sales of reserves
in place (4,400) (300) --- --- --- (100)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 19,700 --- (12,500) 2,300 (4,400) 700
Balance at end
of year 372,500 17,500 324,100 17,500 309,800 15,100
Proved developed reserves:
January 1, 2000 213,400 13,300
December 31, 2000 263,400 14,200
December 31, 2001 291,300 17,100
December 31, 2002 331,300 14,800
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 was as follows:
2002 2001 2000
(In thousands)
Future net cash flows before
income taxes $1,151,600 $ 548,000 $2,349,500
Future income tax expense 324,000 112,000 827,000
Future net cash flows 827,600 436,000 1,522,500
10% annual discount for estimated
timing of cash flows 321,300 174,000 601,200
Discounted future net cash flows
relating to proved natural gas
and oil reserves $ 506,300 $ 262,000 $ 921,300
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
2002 2001 2000
(In thousands)
Beginning of year $ 262,000 $ 921,300 $ 229,100
Net revenues from production (112,900) (153,500) (94,300)
Change in net realization 296,100 (1,119,700) 861,700
Extensions, discoveries and
improved recovery, net of
future production-related costs 130,600 64,200 288,700
Purchases of proved reserves 3,700 2,600 93,200
Sales of reserves in place (8,900) --- (1,500)
Changes in estimated future
development costs, net of those
incurred during the year (100) (3,300) 3,400
Accretion of discount 32,100 126,900 31,200
Net change in income taxes (124,700) 436,500 (412,300)
Revisions of previous quantity
estimates 30,000 (11,700) (79,200)
Other (1,600) (1,300) 1,300
Net change 244,300 (659,300) 692,200
End of year $ 506,300 $ 262,000 $ 921,300
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.
MDU RESOURCES GROUP, INC.
OPERATING STATISTICS
2002 2001 2000 1999 1998* 1997 1992
Selected Financial Data
Operating revenues (000's):
Electric $ 162,616 $ 168,837 $ 161,621 $ 154,869 $ 147,221 $ 141,590 $ 123,908
Natural gas distribution 186,569 255,389 233,051 157,692 154,147 157,005 128,194
Utility services 458,660 364,750 169,382 99,917 64,232 22,761 ---
Pipeline and energy services 165,258 531,114 636,848 383,532 180,732 87,018 92,686
Natural gas and oil production 203,595 209,831 138,316 78,394 61,842 77,916 40,088
Construction materials and mining 962,312 806,899 631,396 469,905 346,451 174,147 45,032
Independent power production 6,776 --- --- --- --- --- ---
Intersegment eliminations (114,249) (113,188) (96,943) (64,500) (57,998) (52,763) (67,733)
$2,031,537 $2,223,632 $1,873,671 $1,279,809 $ 896,627 $ 607,674 $ 362,175
Operating income (000's):
Electric $ 33,915 $ 38,731 $ 38,743 $ 35,727 $ 32,167 $ 31,307 $ 30,188
Natural gas distribution 2,414 3,576 9,530 6,688 8,028 10,410 4,509
Utility services 13,980 25,199 16,606 11,518 5,932 1,782 ---
Pipeline and energy services 39,091 30,368 28,782 40,627 33,651 25,822 18,825
Natural gas and oil production 85,555 103,943 66,510 26,845 (50,444) 27,638 12,005
Construction materials and mining 91,430 71,451 56,816 38,346 41,609 14,602 11,532
Independent power production (268) --- --- --- --- --- ---
$ 266,117 $ 273,268 $ 216,987 $ 159,751 $ 70,943 $ 111,561 $ 77,059
Earnings on common stock (000's):
Electric $ 15,780 $ 18,717 $ 17,733 $ 15,973 $ 13,908 $ 12,441 $ 13,302
Natural gas distribution 3,587 677 4,741 3,192 3,501 4,514 1,370
Utility services 6,371 12,910 8,607 6,505 3,272 947 ---
Pipeline and energy services 19,097 16,406 10,494 20,972 18,651 9,955 2,270
Natural gas and oil production 53,192 63,178 38,574 16,207 (30,501) 15,867 6,960
Construction materials and mining 48,702 43,199 30,113 20,459 24,499 10,111 10,662
Independent power production 959 --- --- --- --- --- ---
$ 147,688 $ 155,087 $ 110,262 $ 83,308 $ 33,330 $ 53,835 $ 34,564
Earnings per common share -- diluted $ 2.07 $ 2.29 $ 1.80 $ 1.52 $ .66 $ 1.24 $ .81
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 71,242 67,869 61,390 54,870 50,837 43,478 42,741
Dividends per common share $ .94 $ .90 $ .86 $ .82 $ .7834 $ .7534 $ .6489
Book value per common share $ 17.34 $ 15.90 $ 13.55 $ 11.74 $ 10.39 $ 8.84 $ 7.11
Market price per common share (year-end) $ 25.81 $ 28.15 $ 32.50 $ 20.00 $ 26.31 $ 21.08 $ 11.72
Market price ratios:
Dividend payout 45% 39% 48% 54% 119% 61% 80%
Yield 3.7% 3.3% 2.7% 4.2% 3.0% 3.6% 5.6%
Price/earnings ratio 12.5x 12.3x 18.1x 13.2x 39.9x 17.0x 14.5x
Market value as a percent of book value 148.8% 177.0% 239.9% 170.4% 253.2% 238.5% 165.0%
Profitability Indicators
Return on average common equity 12.5% 15.3% 14.3% 13.9% 6.5% 14.6% 11.6%
Return on average invested capital 8.6% 10.1% 9.5% 9.6% 5.5% 10.3% 8.7%
Interest coverage 7.7x 8.5x 8.3x 7.1x 6.1x 6.0x 3.3x
Fixed charges coverage, including
preferred dividends 4.8x 5.3x 4.1x 4.3x 2.5x 3.4x 2.4x
General
Total assets (000's) $2,937,249 $2,623,071 $2,312,959 $1,766,303 $1,452,775 $1,113,892 $1,024,510
Net long-term debt (000's) $ 819,558 $ 783,709 $ 728,166 $ 563,545 $ 413,264 $ 298,561 $ 249,845
Redeemable preferred stock (000's) $ 1,300 $ 1,400 $ 1,500 $ 1,600 $ 1,700 $ 1,800 $ 2,300
Capitalization ratios:
Common equity 60% 58% 54% 54% 56% 55% 53%
Preferred stocks 1 1 1 1 2 2 3
Long-term debt 39 41 45 45 42 43 44
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.
</FN>
NOTE: Common stock share amounts reflect the Company's three-for-two common stock splits effected in October 1995 and July 1998.
2002 2001 2000 1999 1998 1997 1992
Electric
Retail sales (thousand kWh) 2,275,024 2,177,886 2,161,280 2,075,446 2,053,862 2,041,191 1,829,933
Sales for resale (thousand kWh) 784,530 898,178 930,318 943,520 586,540 361,954 352,550
Electric system generating and firm
purchase
capability -- kW (Interconnected system) 500,570 500,820 500,420 492,800 489,100 487,500 460,200
Demand peak -- kW (Interconnected system) 458,800 453,000 432,300 420,550 402,500 404,600 339,100
Electricity produced (thousand kWh) 2,316,980 2,469,573 2,331,188 2,350,769 2,103,199 1,826,770 1,774,322
Electricity purchased (thousand kWh) 857,720 792,641 948,700 860,508 730,949 769,679 593,612
Average cost of fuel and purchased
power per kWh $.018 $.018 $.016 $.016 $.017 $.018 $.016
Natural Gas Distribution
Sales (Mdk) 39,558 36,479 36,595 30,931 32,024 34,320 26,681
Transportation (Mdk) 13,721 14,338 14,314 11,551 10,324 10,067 13,742
Weighted average degree days --
% of previous year's actual 109% 95% 113% 95% 94% 85% 98%
Pipeline and Energy Services
Sales for resale (Mdk) --- --- --- --- --- --- 16,841
Transportation (Mdk) 99,890 97,199 86,787 78,061 88,974 85,464 64,498
Gathering (Mdk) 72,692 61,136 41,717 19,799 9,093 9,550 6,735
Natural Gas and Oil Production
Production:
Natural gas (MMcf) 48,239 40,591 29,222 24,652 20,699 20,407 8,805
Oil (000's of barrels) 1,968 2,042 1,882 1,758 1,912 2,088 1,531
Average realized prices:
Natural gas (per Mcf) $ 2.72 $ 3.78 $ 2.90 $ 1.94 $ 1.81 $ 2.02 $ 1.58
Oil (per barrel) $22.80 $24.59 $23.06 $15.34 $12.71 $17.50 $16.74
Net recoverable reserves:
Natural gas (MMcf) 372,500 324,100 309,800 268,900 243,600 184,900 37,200
Oil (000's of barrels) 17,500 17,500 15,100 14,700 11,500 14,900 12,200
Construction Materials and Mining
Construction materials (000's):
Aggregates (tons sold) 35,078 27,565 18,315 13,981 11,054 5,113 263
Asphalt (tons sold) 7,272 6,228 3,310 2,993 1,790 758 ---
Ready-mixed concrete (cubic yards sold) 2,902 2,542 1,696 1,186 1,021 516 ---
Recoverable aggregate reserves (tons) 1,110,020 1,065,330 894,500 740,030 654,670 169,375 20,600
Coal (000's):
Sales (tons) ---* 1,171* 3,111 3,236 3,113 2,375 4,913
Recoverable reserves (tons) 37,761* 56,012* 145,643 182,761 190,152 226,560 235,700
Independent Power Production **
Net generation capacity -- kW 213,000 --- --- --- --- --- ---
Electricity produced and sold (thousand kWh) 15,804 --- --- --- --- --- ---
<FN>
* Coal operations were sold effective April 30, 2001.
** Reflects domestic independent power production operations acquired in November 2002.
</FN>
INDEPENDENT AUDITORS' REPORT
To MDU Resources Group, Inc.
We have audited the financial statements of MDU Resources Group,
Inc. (the Company) as of December 31, 2002 and for the year then
ended and have issued our report thereon dated January 24, 2003
(which expresses an unqualified opinion and includes an
explanatory paragraph relating to the adoption of Statement of
Financial Accounting Standards No. 142 as described in Notes 1
and 3). Such financial statements and report are included in your
2002 Annual Report to Stockholders and are incorporated herein by
reference. Our audit also included the financial statement
Schedule II of the Company, included in Item 15. This financial
statement Schedule II is the responsibility of the Company's
management. Our responsibility is to express an opinion based on
our audit. The financial statements and Schedule II of the
Company as of December 31, 2001 and for the years ended December
31, 2001 and 2000, were audited by other auditors who have ceased
operations and whose reports, dated January 23, 2002, expressed
an unqualified opinion on those financial statements and Schedule
II. In our opinion, such financial statement schedule for the
year ended December 31, 2002, when considered in relation to the
basic financial statements for 2002 taken as a whole, presents
fairly in all material respects the information set forth
therein.
/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
January 24, 2003
THIS IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARUTHUR ANDERSEN
LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP
NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT TO THE INCLUSION
OF ITS REPORT IN THIS ANNUAL REPORT. (SEE NOTE 18 OF NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS FOR FURTHER DISCUSSION.)
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, 2002, 2001 AND 2000
Additions
_______________________
Balance at Charged to
beginning costs and Balance at
Description of year expenses Other(a)(b) Deductions(c) end of year
(In thousands)
Allowance for
doubtful accounts:
2002 $5,773 $8,192 $1,164 $6,892 $8,237
2001 4,063 3,896 2,003 4,189 5,773
2000 2,111 4,252 1,085 3,385 4,063
(a) Allowance for doubtful accounts for companies acquired
(b) Recoveries
(c) Uncollectible accounts written off