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 generally accepted accounting principles as applied to
the company's regulated and nonregulated businesses and necessarily
include some amounts that are based on informed judgments and estimates
of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost-effective basis, that
transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an organizational
structure which provides an appropriate segregation of
responsibilities, effective selection and training of personnel,
written policies and procedures and periodic reviews by the Internal
Auditing Department. In addition, the company has a policy which
requires all employees to acknowledge their responsibility for ethical
conduct. Management believes that these measures provide for a system
that is effective and reasonably assures that all transactions are
properly recorded for the preparation of financial statements.
Management modifies and improves its system of internal accounting
controls in response to changes in business conditions. The company's
Internal Auditing Department is charged with the responsibility for
determining compliance with company procedures.
The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting. The audit committee meets regularly with
management, the internal auditors and Arthur Andersen LLP, independent
public accountants, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities. The internal
auditors and Arthur Andersen LLP have full and free access to the audit
committee, without management present, to discuss auditing, internal
accounting control and financial reporting matters.
Arthur Andersen LLP is engaged to express an opinion on the financial
statements. Their audit is conducted in accordance with auditing
standards generally accepted in the United States and includes
examining, on a test basis, supporting evidence, assessing the
company's accounting principles used and significant estimates made by
management and evaluating the overall financial statement presentation
to the extent necessary to allow them to report on the fairness, in all
material respects, of the financial condition and operating results of
the company.
Martin A. White Warren L. Robinson
Chairman of the Board, Executive Vice President,
President and Chief Treasurer and Chief
Executive Officer Financial Officer
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, 2000 and 1999, 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, 2000. 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, 2000 and
1999, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2000, in conformity
with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 25, 2001
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 2000 1999 1998
(In thousands, except per share amounts)
Operating revenues $1,873,671 $1,279,809 $896,627
Operating expenses:
Fuel and purchased power 54,114 51,802 49,829
Purchased natural gas sold 634,277 349,215 158,908
Operation and maintenance 821,528 608,104 448,290
Depreciation, depletion and
amortization 110,888 81,818 77,786
Taxes, other than income 35,877 29,119 24,871
Write-downs of natural gas and
oil properties (Note 1) --- --- 66,000
1,656,684 1,120,058 825,684
Operating income 216,987 159,751 70,943
Other income -- net 11,724 9,645 10,922
Interest expense 48,033 36,006 30,273
Income before income taxes 180,678 133,390 51,592
Income taxes 69,650 49,310 17,485
Net income 111,028 84,080 34,107
Dividends on preferred stocks 766 772 777
Earnings on common stock $ 110,262 $ 83,308 $ 33,330
Earnings per common share --
basic $ 1.80 $ 1.53 $ .66
Earnings per common share --
diluted $ 1.80 $ 1.52 $ .66
Dividends per common share $ .86 $ .82 $ .7834
Weighted average common shares
outstanding -- basic 61,090 54,615 50,536
Weighted average common shares
outstanding -- diluted 61,390 54,870 50,837
The accompanying notes are an integral part of these consolidated
statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 2000 1999
(In thousands, except shares and per share amount)
ASSETS
Current assets:
Cash and cash equivalents $ 36,512 $ 77,504
Receivables 342,354 169,560
Inventories 64,017 64,608
Deferred income taxes 8,048 15,600
Prepayments and other current assets 29,355 24,424
480,286 351,696
Investments 41,380 43,128
Property, plant and equipment 2,496,123 2,042,281
Less accumulated depreciation,
depletion and amortization 895,109 794,105
1,601,014 1,248,176
Deferred charges and other assets 190,279 123,303
$2,312,959 $1,766,303
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings (Note 4) $ 8,000 $ 14,693
Long-term debt and preferred
stock due within one year 19,695 4,428
Accounts payable 171,929 81,262
Taxes payable 10,437 6,842
Dividends payable 14,423 12,171
Other accrued liabilities,
including reserved revenues 59,989 67,931
284,473 187,327
Long-term debt (Note 5) 728,166 563,545
Deferred credits and other liabilities:
Deferred income taxes 281,000 213,771
Other liabilities 121,860 115,627
402,860 329,398
Preferred stock subject to mandatory
redemption (Note 6) 1,400 1,500
Commitments and contingencies (Notes 11, 13 and 14)
Stockholders' equity:
Preferred stocks (Note 6) 15,000 15,000
Common stockholders' equity:
Common stock (Note 7)
Authorized -- 150,000,000 shares,
$1.00 par value
Issued -- 65,267,567 shares in 2000 and
57,277,915 shares in 1999 65,268 57,278
Other paid-in capital 518,771 372,312
Retained earnings 300,647 243,569
Treasury stock at cost - 239,521 shares (3,626) (3,626)
Total common stockholders' equity 881,060 669,533
Total stockholders' equity 896,060 684,533
$2,312,959 $1,766,303
The accompanying notes are an integral part of these consolidated
statements.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
MDU RESOURCES GROUP, INC.
Years ended December 31, 2000, 1999 and 1998
Other
Common Stock Paid-in Retained Treasury Stock
Shares Amount Capital Earnings Shares Amount Total
(In thousands, except shares)
Balance at
December 31, 1997 29,143,332 $ 97,047 $ 76,526 $ 212,723 --- $ --- $386,296
Net income --- --- --- 34,107 --- --- 34,107
Dividends on
preferred stocks --- --- --- (777) --- --- (777)
Dividends on
common stock --- --- --- (40,470) --- --- (40,470)
Issuance of
common stock
(pre-split) 5,842,697 19,456 139,253 --- --- --- 158,709
Treasury stock
acquired --- --- --- --- (159,681) (3,626) (3,626)
Three-for-two
common stock
split (Note 7) 17,493,014 58,252 (58,252) --- (79,840) --- ---
Issuance of
common stock
(post-split) 793,908 2,644 13,959 --- --- --- 16,603
Balance at
December 31, 1998 53,272,951 177,399 171,486 205,583 (239,521) (3,626) 550,842
Net income --- --- --- 84,080 --- --- 84,080
Dividends on
preferred stocks --- --- --- (772) --- --- (772)
Dividends on
common stock --- --- --- (45,322) --- --- (45,322)
Reduction in par
value of common
stock --- (124,126) 124,126 --- --- --- ---
Issuance of
common stock 4,004,964 4,005 76,700 --- --- --- 80,705
Balance at
December 31, 1999 57,277,915 57,278 372,312 243,569 (239,521) (3,626) 669,533
Net income --- --- --- 111,028 --- --- 111,028
Dividends on
preferred stocks --- --- --- (766) --- --- (766)
Dividends on
common stock --- --- --- (53,184) --- --- (53,184)
Issuance of
common stock 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
<FN>
The accompanying notes are an integral part of these consolidated statements.
</FN>
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 2000 1999 1998
(In thousands)
Operating activities:
Net income $111,028 $ 84,080 $ 34,107
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 110,888 81,818 77,786
Deferred income taxes and
investment tax credit 36,530 15,704 (17,256)
Write-downs of natural gas and oil
properties (Note 1) --- --- 66,000
Changes in current assets and
liabilities, net of acquisitions:
Receivables (117,449) (12,310) (10,464)
Inventories 9,578 (13,460) 1,718
Other current assets (3,514) (4,190) (547)
Accounts payable 61,021 12,492 14,094
Other current liabilities (3,821) (8,972) (19,805)
Other noncurrent changes 2,701 (289) (7,187)
Net cash provided by operating
activities 206,962 154,873 138,446
Investing activities:
Capital expenditures including
acquisitions of businesses (408,826) (170,510) (191,154)
Net proceeds from sale or
disposition of property 11,000 16,660 4,275
Net capital expenditures (397,826) (153,850) (186,879)
Sale of natural gas available
under repurchase commitment --- 1,330 7,727
Investments 2,102 (99) (22,945)
Additions to notes receivable (5,000) (35,907) ---
Proceeds from notes receivable 4,000 --- ---
Net cash used in investing
activities (396,724) (188,526) (202,097)
Financing activities:
Net change in short-term borrowings (7,242) (6,585) 3,933
Issuance of long-term debt 192,162 154,546 209,890
Repayment of long-term debt (29,349) (18,714) (113,600)
Retirement of preferred stock (100) (100) (100)
Issuance of common stock 47,249 3,184 32,922
Retirement of natural gas
repurchase commitment --- (14,296) (17,105)
Dividends paid (53,950) (46,094) (41,247)
Net cash provided by
financing activities 148,770 71,941 74,693
Increase (decrease) in cash
and cash equivalents (40,992) 38,288 11,042
Cash and cash equivalents --
beginning of year 77,504 39,216 28,174
Cash and cash equivalents --
end of year $ 36,512 $ 77,504 $ 39,216
The accompanying notes are an integral part of these consolidated
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, and
construction materials and mining. The electric and natural gas
distribution segments and a portion of the pipeline and energy services
segment are regulated. The company's nonregulated operations include
the utility services, natural gas and oil production, and construction
materials and mining segments, and a portion of the pipeline and energy
services segment. For further descriptions of the company's business
segments see Note 9. The statements also include the ownership
interests in the assets, liabilities and expenses of two jointly owned
electric generation stations.
The company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by the company's
nonregulated businesses.
The company's regulated businesses account for certain income and
expense items under the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Regulation" (SFAS No.
71). SFAS No. 71 requires these businesses to defer as regulatory
assets or liabilities certain items that would have otherwise been
reflected as expense or income, respectively, based on the expected
regulatory treatment in future rates. The expected recovery or
flowback of these deferred items are generally based on specific
ratemaking decisions or precedent for each item. Regulatory assets and
liabilities are being amortized consistently with the regulatory
treatment established by the FERC and the applicable state public
service commissions. See Note 2 for more information regarding the
nature and amounts of these regulatory deferrals.
In accordance with the provisions of SFAS No. 71, intercompany coal
sales, which are made at prices approximately the same as those charged
to others, and the related utility fuel purchases are not eliminated.
All other significant intercompany balances and transactions have been
eliminated in consolidation.
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 $5.2 million, $1.7 million and $1.4 million in 2000,
1999 and 1998, respectively. Property, plant and equipment are
depreciated on a straight-line basis over the average useful lives of
the assets, except for natural gas and oil production properties as
described below.
Goodwill and other intangible assets
The excess of the cost over the fair value of net assets of purchased
businesses is recorded as goodwill and is amortized on a straight-line
basis over estimated useful lives. Goodwill was $91.4 million, net of
accumulated amortization of $12.0 million as of December 31, 2000 and
was $46.7 million, net of accumulated amortization of $5.1 million as
of December 31, 1999. Goodwill amortization expense was $7.0 million,
$2.0 million and $1.4 million for 2000, 1999 and 1998, respectively.
The weighted average amortization period for goodwill as of
December 31, 2000 was 25 years.
Impairment of long-lived assets and intangibles
The company reviews the carrying values of its long-lived assets,
including goodwill and identifiable intangibles, whenever events or
changes in circumstances indicate that such carrying values may not be
recoverable. The determination of whether an impairment has occurred
is based on an estimate of undiscounted future cash flows attributable
to the assets, compared to the carrying value of the assets. If an
impairment has occurred, the amount of the impairment recognized is
determined by estimating the fair value of the assets and recording a
loss if the carrying value is greater than the fair value. In 2000,
the company experienced significant changes in market conditions at one
of its energy marketing operations, which negatively affected the fair
value of the assets at that operation. Due to the significance of the
decline, the company recorded an impairment charge against goodwill of
$3.9 million after tax in the fourth quarter of 2000. The amount
related to this impairment is included in "Depreciation, depletion and
amortization" in the company's Consolidated Statements of Income.
Excluding this impairment and the write-downs of natural gas and oil
properties as discussed herein, no other long-lived assets or
intangibles have been impaired and accordingly no other impairment
losses have been recorded in 2000, 1999 and 1998. Unforeseen events
and changes in circumstances could require the recognition of other
impairment losses at some future date.
Natural gas and oil
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 and the lower of cost or fair value of
unproved properties. Future net revenue is estimated based on end-of-
quarter 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.
Due to low natural gas and oil prices, the company's capitalized costs
under the full-cost method of accounting exceeded the full-cost ceiling
at June 30, 1998 and December 31, 1998. Accordingly, the company was
required to write down its natural gas and oil producing properties.
These noncash write-downs amounted to $66.0 million ($39.9 million
after tax).
Natural gas in underground storage
Natural gas in underground storage for the company's regulated
operations is carried at cost using the last-in, first-out method. The
portion of the cost of natural gas in underground storage expected to
be used within one year is included in inventories and amounted to
$11.0 million and $26.1 million at December 31, 2000 and 1999,
respectively. The remainder of natural gas in underground storage is
included in property, plant and equipment and was $43.6 million and
$46.8 million at December 31, 2000 and 1999, respectively.
Inventories
Inventories, other than natural gas in underground storage for the
company's regulated operations, consist primarily of materials and
supplies of $20.4 million and $15.9 million, aggregates held for resale
of $22.7 million and $15.6 million and other inventories of $9.9
million and $7.0 million as of December 31, 2000 and 1999,
respectively. These inventories are stated at the lower of average
cost or market.
Revenue recognition
The company recognizes utility revenue each month based on the services
provided to all utility customers during the month. For its
construction businesses, the company recognizes construction contract
revenue on the percentage of completion method. The company recognizes
revenue from natural gas and oil production activities only on that
portion of production sold and allocable to the company's ownership
interest in the related well. The company generally recognizes all
other revenues when services are rendered or goods are delivered.
Advertising
The company expenses advertising costs as incurred and the amount of
advertising expense for the years 2000, 1999 and 1998, was $2.0
million, $1.3 million and $1.0 million, respectively.
Natural gas costs recoverable through rate adjustments
Under the terms of certain orders of the applicable state public
service commissions, the company is deferring natural gas commodity,
transportation and storage costs which are greater or less than amounts
presently being recovered through its existing rate schedules. Such
orders generally provide that these amounts are recoverable or
refundable through rate adjustments within a period ranging from 24
months to 28 months from the time such costs are paid.
Income taxes
The company provides deferred federal and state income taxes on all
temporary differences. Excess deferred income tax balances associated
with the company's rate-regulated activities resulting from the
company's adoption of SFAS No. 109, "Accounting for Income Taxes," have
been recorded as a regulatory liability and are included in "Other
liabilities" in the company's Consolidated Balance Sheets. These
regulatory liabilities are expected to be reflected as a reduction in
future rates charged customers in accordance with applicable regulatory
procedures.
The company uses the deferral method of accounting for investment tax
credits and amortizes the credits on electric and natural gas
distribution plant over various periods which conform to the ratemaking
treatment prescribed by the applicable state public service
commissions.
Earnings per common share
Basic earnings per common share were computed by dividing earnings on
common stock by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share were
computed by dividing earnings on common stock by the total of the
weighted average number of shares of common stock outstanding during
the year, plus the effect of outstanding stock options and restricted
stock grants. Common stock outstanding includes issued shares less
shares held in treasury.
Comprehensive income
For the years ended December 31, 2000, 1999 and 1998, comprehensive
income equaled net income as reported.
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires the
company to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
Estimates are used for such items as property depreciable lives, tax
provisions, uncollectible accounts, environmental and other loss
contingencies, accumulated provision for revenues subject to refund,
costs on long-term construction contracts, unbilled revenues and
actuarially determined benefit costs. As better 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, 2000 1999 1998
(In thousands)
Interest, net of amount capitalized $41,912 $30,772 $26,394
Income taxes $30,930 $32,723 $34,498
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
New accounting pronouncements
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133), amended
by Statement of Financial Accounting Standards No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" and Statement of Financial
Accounting Standards No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" (all such statements
hereinafter referred to as SFAS No. 133). SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS No. 133 requires that
changes in the derivative'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.
The company plans to utilize certain derivative financial instruments
to manage a portion of the market risk associated with fluctuations in
the price of natural gas and oil. The company intends to designate
these contracts as hedges of the underlying purchases or sales and will
record derivative assets and liabilities on its balance sheet based on
the fair value of the contracts. Such amounts are expected to be
substantially offset by an amount that will be recorded in "Accumulated
other comprehensive income" on the company's Consolidated Balance
Sheets. The fair values of derivative instruments will fluctuate over
time due to changes in the underlying commodity prices.
The company adopted SFAS No. 133 on January 1, 2001. SFAS No. 133 will
likely impact the company's financial position and could increase
volatility in earnings and accumulated other comprehensive income.
Based on the contracts outstanding as of January 1, 2001, pretax
unrealized gains on derivatives of $2.2 million and pretax unrealized
losses on derivatives of $12.3 million would be recognized as assets
and liabilities, respectively, on the balance sheet with the offsetting
amounts being recorded as a component of accumulated other
comprehensive income.
In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), which
provides guidance on the recognition, presentation and disclosure of
revenue in financial statements. The company adopted SAB No. 101 in
the fourth quarter of 2000. The adoption of SAB No. 101 did not have a
material effect on the company's financial position or results of
operations.
NOTE 2
REGULATORY ASSETS AND LIABILITIES
The following table summarizes the individual components of unamortized
regulatory assets and liabilities included in the accompanying
Consolidated Balance Sheets as of December 31:
2000 1999
(In thousands)
Regulatory assets:
Long-term debt refinancing costs $ 8,125 $ 9,514
Plant costs 2,668 2,835
Natural gas contract settlement and
restructuring costs 1,562 3,000
Postretirement benefit costs 833 1,742
Deferred income taxes 263 7,274
Other 5,490 6,789
Total regulatory assets 18,941 31,154
Regulatory liabilities:
Taxes refundable to customers 11,656 11,504
Natural gas costs refundable
through rate adjustments 8,772 2,579
Plant decommissioning costs 7,601 6,989
Reserves for regulatory matters 6,087 24,231
Deferred income taxes 3,554 6,785
Other 1,193 710
Total regulatory liabilities 38,863 52,798
Net regulatory position $(19,922) $(21,644)
As of December 31, 2000, substantially all of the company's regulatory
assets, other than certain deferred income taxes, are being reflected
in rates charged to customers and are being recovered over the next 1
to 16 years.
If, for any reason, the company's regulated businesses cease to meet
the criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities relating to those
portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income as an
extraordinary item in the period in which the discontinuance of SFAS
No. 71 occurs.
NOTE 3
RISK MANAGEMENT ACTIVITIES AND FINANCIAL INSTRUMENTS
Derivatives
The company utilizes derivative financial instruments, including price
swap and collar agreements, to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil. 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 financial instruments in the event of nonperformance by
counterparties, but does not expect any counterparties to fail to meet
their obligations given their existing credit ratings.
The swap and collar agreements call for the company to receive monthly
payments from or make payments to counterparties based upon the
difference between a fixed and a variable price as specified by the
agreements. The variable price is either a quoted natural gas price on
the New York Mercantile Exchange (NYMEX), Colorado Interstate Gas Index
or other various indexes or an oil price quoted on the NYMEX. The
company believes that there is a high degree of correlation because the
timing of purchases and production and the swap and collar agreements
are closely matched, and hedge prices are established in the areas of
operations. For the years ending December 31, 2000, 1999 and 1998,
gains or losses on the swap and collar agreements were matched and
reported in operating revenues on the Consolidated Statements of Income
as a component of the related commodity transaction at the time of
settlement with the counterparty.
The following table summarizes hedge agreements entered into by certain
wholly owned subsidiaries of the company, as of December 31, 2000.
These agreements call for the subsidiaries to receive fixed prices and
pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount Fair
(Per MMBtu) (In MMBtu's) Value
Natural gas swap
agreements maturing $ 4.45 5,461 $(12,311)
in 2001
Weighted
Average Notional
Fixed Price Amount Fair
(Per barrel) (In barrels) Value
Oil swap agreements
maturing in 2001 $28.80 593 $ 2,261
The fair value of these derivative financial instruments reflects the
estimated amounts that the company would receive or pay to terminate
the contracts at the reporting date, thereby taking into account the
current favorable or unfavorable position on open contracts. The
favorable or unfavorable position is not recorded on the company's
Consolidated Balance Sheets as of December 31, 2000 and 1999.
Favorable and unfavorable positions related to commodity hedge
agreements are expected to be generally offset by corresponding
increases and decreases in the value of the underlying commodity
transactions.
In the event a derivative financial instrument does not qualify for
hedge accounting or when the underlying commodity transaction matures,
is sold, is extinguished, or is terminated, the current favorable or
unfavorable position on the open contract would be included in results
of operations. The company's policy requires approval to terminate a
hedge agreement prior to its original maturity. In the event a hedge
agreement is terminated, the realized gain or loss at the time of
termination would be deferred until the underlying commodity
transaction is sold or matures and is expected to generally offset the
corresponding increases or decreases in the value of the underlying
commodity transaction.
Energy marketing
The company has energy marketing operations that are exposed to risks,
including risks relating to changes in natural gas prices and
counterparty performance (credit risk), associated with natural gas
forward purchase and sale commitments. These commitments involve the
purchase and sale of natural gas and related delivery of such
commodity. The energy marketing operations seek to match natural gas
purchases and sales on specific contracts so that a margin is obtained
on the transportation of such commodity as distinguished from earning a
margin on changes in market prices. In addition, the energy marketing
contracts are generally entered into on a seasonal basis with contracts
of a duration generally not exceeding 12 months. Contracts related to
these activities are valued at fair value and changes in fair value are
recorded as assets or liabilities on the company's Consolidated Balance
Sheets. The net change in fair value representing unrealized gains and
losses resulting from changes in market prices on these contracts is
reflected in earnings on the company's Consolidated Statements of
Income. Net unrealized gains and losses on these contracts were not
material in 2000, 1999 or 1998. In general, market risk is the risk of
fluctuations in the market price of the commodity being marketed and is
influenced primarily by supply and demand. The company monitors and
manages its exposure to market risk through a variety of risk
management techniques. Such procedures include monitoring commitments
and positions, evaluating sensitivity to changes in market prices and
market volatility, and reporting to senior management. Credit risk is
the risk of loss from nonperformance by counterparties of their
contractual obligations. The company maintains credit procedures,
which management believes significantly minimize overall credit risk.
The company seeks to mitigate credit risk by applying specific
eligibility criteria to prospective counterparties and may require
letters of credit or similar security to secure payment on such sales
contracts. However, despite mitigation efforts, defaults by
counterparties may occur. To date, no such defaults have had a
material effect on the company's financial position or results of
operations.
Fair value of other financial instruments
The estimated fair value of the company's long-term debt and preferred
stock subject to mandatory redemption is based on quoted market prices
of the same or similar issues. The estimated fair value of the
company's long-term debt and preferred stock subject to mandatory
redemption at December 31 is as follows:
2000 1999
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $747,761 $772,127 $567,873 $555,730
Preferred stock
subject to mandatory
redemption $ 1,500 $ 927 $ 1,600 $ 1,418
The fair value of other financial instruments for which estimated fair
value has not been presented is not materially different than the
related carrying amount.
NOTE 4
SHORT-TERM BORROWINGS
The company and its subsidiaries had unsecured short-term lines of
credit from a number of banks totaling $75 million at December 31,
2000. These line of credit agreements provide for bank borrowings
against the lines and/or support for commercial paper issues. The
agreements provide for commitment fees at varying rates. Amounts
outstanding on the short-term lines of credit were $8 million at
December 31, 2000, and $14.7 million at December 31, 1999. The
weighted average interest rate for borrowings outstanding at
December 31, 2000 and 1999, was 6.60 percent and 6.97 percent,
respectively. The unused portions of the lines of credit are subject
to withdrawal based on the occurrence of certain events.
NOTE 5
LONG-TERM DEBT AND INDENTURE PROVISIONS
Long-term debt outstanding at December 31 is as follows:
2000 1999
(In thousands)
First mortgage bonds and notes:
Pollution Control Refunding Revenue
Bonds, Series 1992,
6.65%, due June 1, 2022 $ 20,850 $ 20,850
Secured Medium-Term Notes,
Series A at a weighted
average rate of 7.59%, due on
dates ranging from October 1, 2004
to April 1, 2012 110,000 110,000
Total first mortgage bonds and notes 130,850 130,850
Senior notes at a weighted
average rate of 7.65%, due on
dates ranging from January 2, 2001
to October 30, 2018 294,300 151,400
Commercial paper at a weighted average
rate of 6.93%, supported by a revolving
credit agreement due on September 29, 2003 261,350 223,169
Revolving lines of credit at a
weighted average rate of 9.36%,
due on dates ranging from
November 1, 2001 through December 31, 2002 46,302 45,900
Term credit agreements at a weighted
average rate of 7.65%, due on dates
ranging from March 15, 2001
through July 1, 2016 12,731 13,970
Pollution control note obligation,
6.20%, due March 1, 2004 2,800 3,100
Other (572) (516)
Total long-term debt 747,761 567,873
Less current maturities 19,595 4,328
Net long-term debt $ 728,166 $563,545
Centennial Energy Holdings, Inc., (Centennial) a direct wholly owned
subsidiary of the company, has a revolving credit agreement with
various banks on behalf of its subsidiaries that supports $315 million
of Centennial's $325 million commercial paper program. Under the
Centennial commercial paper program, $261.4 million and $223.2 million
were outstanding at December 31, 2000 and 1999, respectively. The
commercial paper borrowings are classified as long term as Centennial
intends to refinance these borrowings on a long-term basis through
continued commercial paper borrowings supported by the revolving credit
agreement due September 29, 2003. Centennial intends to renew this
existing credit agreement on an annual basis.
Centennial has an uncommitted long-term master shelf agreement on
behalf of its subsidiaries that allows for borrowings of up to $200
million. Under the master shelf agreement, $150 million was
outstanding at December 31, 2000 and none was outstanding at December
31, 1999. The amount outstanding is presented in senior notes in the
preceding table.
Under the revolving lines of credit, the company and certain
subsidiaries have $48.2 million available as of December 31, 2000.
Amounts outstanding under the revolving lines of credit were
$46.3 million and $45.9 million at December 31, 2000 and 1999,
respectively.
The amounts of scheduled long-term debt maturities for the five years
following December 31, 2000 aggregate $19.6 million in 2001;
$50.4 million in 2002; $282.7 million in 2003; $21.6 million in 2004
and $69.9 million in 2005.
Substantially all of the company's electric and natural gas
distribution properties, with certain exceptions, are subject to the
lien of its Indenture of Mortgage. Under the terms and conditions of
the Indenture, the company could have issued approximately $295 million
of additional first mortgage bonds at December 31, 2000. Certain other
debt instruments of the company and its subsidiaries contain
restrictive covenants, all of which the company and its subsidiaries
are in compliance with at December 31, 2000.
NOTE 6
PREFERRED STOCKS
Preferred stocks at December 31 are as follows:
2000 1999
(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 -- 15,000 shares in 2000
and 16,000 shares in 1999 $ 1,500 $ 1,600
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 16,500 16,600
Less sinking fund requirements 100 100
Net preferred stocks $16,400 $16,500
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 for each of the five years following
December 31, 2000, is $100,000.
NOTE 7
COMMON STOCK
At the Annual Meeting of Stockholders held in April 1999, the company's
common stockholders approved an amendment to the Certificate of
Incorporation increasing the authorized number of common shares from 75
million shares to 150 million shares and reducing the par value of the
common stock from $3.33 per share to $1.00 per share.
In May 1998, the company's Board of Directors approved a three-for-two
common stock split effected in the form of a 50 percent common stock
dividend. The additional shares of common stock were distributed on
July 13, 1998, to common stockholders of record on July 3, 1998.
Common stock information appearing in the accompanying Consolidated
Statements of Income and Notes to Consolidated Financial Statements
give retroactive effect to stock split.
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 of up to $5,000 per
month 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 Tax Deferred Compensation
Savings Plan(s) (K-Plan(s)), which were merged effective January 1,
1999, pursuant to Section 401(k) of the Internal Revenue Code are
funded with the company's common stock. Since January 1, 1989, the
Stock Purchase Plan and K-Plan(s) have been funded primarily by the
purchase of shares of common stock on the open market, except for a
portion of 1997 where shares of authorized but unissued common stock
were used to fund the Stock Purchase Plan and K-Plan(s) and from
October 1, 1998 through March 31, 1999, when shares of authorized but
unissued common stock were used to fund the Stock Purchase Plan. At
December 31, 2000, there were 8.1 million shares of common stock
reserved for original issuance under the Stock Purchase Plan and K-
Plan.
In November 1998, the company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) for each outstanding share of the company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for one one-thousandth of a share of Series B
Preference Stock of the company, without par value, at an exercise
price of $125 per one one-thousandth, subject to certain adjustments.
The rights are currently not exercisable and will be exercisable only
if a person or group (acquiring person) either acquires ownership of 15
percent or more of the company's common stock or commences a tender or
exchange offer that would result in ownership of 15 percent or more.
In the event the company is acquired in a merger or other business
combination transaction or 50 percent or more of its consolidated
assets or earnings power are sold, each right entitles the holder to
receive, upon the exercise thereof at the then current exercise price
of the right multiplied by the number of one one-thousandth of a Series
B Preference Stock for which a right is then exercisable, in accordance
with the terms of the rights agreement, such number of shares of common
stock of the acquiring person having a market value of twice the then
current exercise price of the right. The rights, which expire on
December 31, 2008, are redeemable in whole, but not in part, for a
price of $.01 per right, at the company's option at any time until any
acquiring person has acquired 15 percent or more of the company's
common stock.
The company has stock option plans for directors, key employees and
employees, which grant options to purchase shares of the company's
stock. The company accounts for these option plans in accordance with
APB Opinion No. 25 under which no compensation expense has been
recognized. The option exercise price is the market value of the stock
on the date of grant. Options granted to the key employees
automatically vest after nine years, but the plan provides for
accelerated vesting based on the attainment of certain performance
goals or upon a change in control of the company. Options granted to
directors and employees vest at date of grant and three years after
date of grant, respectively, and expire ten years after the date of
grant. In addition, the company has granted restricted stock awards
under a long-term incentive plan, deferred compensation agreement and a
restricted stock agreement totaling 348,021 shares, 105,250 shares and
21,135 shares in 2000, 1999 and 1998, respectively. The restricted
stock awards granted vest to the participants at various times ranging
from three 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 $20.81, $22.91 and
$23.24 in 2000, 1999 and 1998, respectively. Compensation expense
recognized for restricted stock grants was $1.6 million, $722,000 and
$123,000 in 2000, 1999 and 1998, respectively. Under the stock option
plans and long-term incentive plan, the company is authorized to grant
options and restricted stock for up to 4.3 million shares of common
stock and has granted options and restricted stock on 2.1 million
shares through December 31, 2000.
Had the company recorded compensation expense for the fair value of
options granted consistent with SFAS No. 123, "Accounting for Stock-
Based Compensation," net income would have been reduced on a pro forma
basis by $529,000 in 2000, $498,000 in 1999, and $820,000 in 1998. On
a pro forma basis, there would have been no effect on basic earnings
per share for 2000, and diluted earnings per share would have been
reduced by $.01. On a pro forma basis, basic and diluted earnings per
share for 1999 and 1998 would have been reduced by $.01 and $.02,
respectively.
A summary of the status of the stock option plans at December 31, 2000,
1999 and 1998, and changes during the years then ended are as follows:
2000 1999 1998
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 1,427,262 $19.46 1,516,808 $19.17 594,180 $12.07
Granted 74,000 20.54 22,500 23.31 1,225,920 21.12
Forfeited (84,135) 21.18 (57,966) 20.38 (37,875) 21.05
Exercised (192,168) 11.84 (54,080) 11.95 (265,417) 11.98
Balance at end
of year 1,224,959 20.61 1,427,262 19.46 1,516,808 19.17
Exercisable at
end of year 129,763 $18.11 301,681 $13.89 333,261 $12.94
Exercise prices on options outstanding at December 31, 2000, range from
$10.50 to $23.84 with a weighted average remaining contractual life of
approximately 7 years.
The fair value of each option is estimated on the date of grant using
the Black-Scholes option pricing model. The weighted average fair
value of the options granted and the assumptions used to estimate the
fair value of options are as follows:
2000 1999 1998
Fair value of options at grant date $ 5.07 $ 4.82 $ 2.40
Weighted average risk-free
interest rate 6.76% 5.98% 4.78%
Weighted average expected
price volatility 23.55% 22.03% 16.27%
Weighted average expected
dividend yield 3.84% 4.22% 5.13%
Expected life in years 7 7 7
NOTE 8
INCOME TAXES
Income tax expense is summarized as follows:
Years ended December 31, 2000 1999 1998
(In thousands)
Current:
Federal $27,865 $29,574 $28,256
State 5,188 3,874 5,880
Foreign 67 158 605
33,120 33,606 34,741
Deferred:
Income taxes --
Federal 29,323 12,902 (14,214)
State 8,060 3,690 (2,067)
Investment tax credit (853) (888) (975)
36,530 15,704 (17,256)
Total income tax expense $69,650 $49,310 $17,485
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
2000 1999
(In thousands)
Deferred tax assets:
Accrued pension costs $ 10,325 $ 10,898
Regulatory matters 7,650 14,562
Accrued land reclamation 1,941 2,803
Deferred investment tax credit 1,697 2,028
Other 18,213 16,892
Total deferred tax assets 39,826 47,183
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 264,635 218,355
Basis differences on natural gas
and oil producing properties 36,763 17,163
Regulatory matters 3,554 6,785
Other 7,826 3,051
Total deferred tax liabilities 312,778 245,354
Net deferred income tax liability $(272,952)$(198,171)
The following table reconciles the change in the net deferred income
tax liability from December 31, 1999, to December 31, 2000, to the
deferred income tax expense included in the Consolidated Statements of
Income:
2000
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 74,781
Change in tax effects of income tax-related
regulatory assets and liabilities (150)
Deferred taxes associated with acquisitions (38,101)
Deferred income tax expense for the period $ 36,530
Total income tax expense differs from the amount computed by applying
the statutory federal income tax rate to income before taxes. The
reasons for this difference are as follows:
Years ended December 31, 2000 1999 1998
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $63,237 35.0 $46,686 35.0 $18,057 35.0
Increases (reductions)
resulting from:
State income taxes,
net of federal
income tax benefit 8,044 4.4 5,921 4.4 2,312 4.5
Investment tax credit
amortization (853) (.5) (888) (.6) (975) (1.9)
Depletion allowance (1,631) (.9) (1,300) (1.0) (1,571) (3.0)
Other items 853 .5 (1,109) (.8) (338) (.7)
Total income tax expense $69,650 38.5 $49,310 37.0 $17,485 33.9
NOTE 9
BUSINESS SEGMENT DATA
The company's reportable segments are those that are based on the
company's method of internal reporting, which generally segregates the
strategic business units due to differences in products, services and
regulation.
The company's operations are conducted through six business segments.
Substantially all of the company's operations are located within the
United States. The electric business generates, transmits and
distributes electricity and the natural gas distribution business
distributes natural gas. These operations also supply related
value-added products and services in the Northern Great Plains. The
utility services business consists of a diversified infrastructure
construction company specializing in electric, natural gas and
telecommunication utility construction as well as interior industrial
electrical, exterior lighting and traffic signalization. Utility
services has engineering, design and build capability and provides
related specialty equipment sales and rental services throughout most
of the United States. The pipeline and energy services business
provides natural gas transportation, underground storage and gathering
services through regulated and nonregulated pipeline systems and
provides energy-related marketing and management services. The natural
gas and oil production business 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 business mines and markets
aggregates and related value-added construction materials products and
services in the western United States, including Alaska and Hawaii, and
it also operates lignite coal mines in Montana and North Dakota.
On September 28, 2000, the company announced an agreement to sell its
coal operations to Westmoreland Coal Company for $28.8 million cash,
excluding final settlement cost adjustments. The agreement is subject
to various closing conditions and therefore will not be finalized
unless and until the parties are satisfied that those conditions are
met.
Segment information follows the same accounting policies as described
in the Summary of Significant Accounting Policies. Segment information
included in the accompanying Consolidated Balance Sheets as of
December 31 and included in the Consolidated Statements of Income for
the years then ended is as follows:
2000 1999 1998
(In thousands)
External operating revenues:
Electric $ 161,621 $ 154,869 $ 147,221
Natural gas distribution 233,051 157,692 154,147
Utility services 169,382 99,917 64,232
Pipeline and energy services 579,207 334,188 132,826
Natural gas and oil production 99,014 63,238 51,750
Construction materials and mining 617,564 455,939 331,988
Total external operating revenues $1,859,839 $1,265,843 $ 882,164
Intersegment operating revenues:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services --- --- ---
Pipeline and energy services 57,641 49,344 47,906
Natural gas and oil production 39,302 15,156 10,092
Construction materials and mining(a) 13,832 13,966 14,463
Intersegment eliminations (96,943) (64,500) (57,998)
Total intersegment
operating revenues(a) $ 13,832 $ 13,966 $ 14,463
Depreciation, depletion and
amortization:
Electric $ 19,115 $ 18,375 $ 18,129
Natural gas distribution 8,399 7,348 7,150
Utility services 4,912 2,591 1,669
Pipeline and energy services 15,301 8,248 6,972
Natural gas and oil production 27,008 19,248 23,304
Construction materials and mining 36,153 26,008 20,562
Total depreciation, depletion
and amortization $ 110,888 $ 81,818 $ 77,786
Interest expense:
Electric $ 10,007 $ 9,692 $ 9,979
Natural gas distribution 4,142 3,614 3,728
Utility services 2,492 812 325
Pipeline and energy services 10,029 7,281 5,800
Natural gas and oil production 5,160 3,405 3,039
Construction materials and mining 16,415 11,202 7,402
Intersegment eliminations (212) --- ---
Total interest expense $ 48,033 $ 36,006 $ 30,273
Income taxes:
Electric $ 10,048 $ 8,678 $ 7,767
Natural gas distribution 3,544 1,443 2,681
Utility services 6,027 4,323 2,437
Pipeline and energy services 9,214 13,356 12,579
Natural gas and oil production 23,906 10,032 (23,134)
Construction materials and mining 16,911 11,478 15,155
Total income taxes $ 69,650 $ 49,310 $ 17,485
Earnings on common stock:
Electric $ 17,733 $ 15,973 $ 13,908
Natural gas distribution 4,741 3,192 3,501
Utility services 8,607 6,505 3,272
Pipeline and energy services 10,494 20,972 18,651
Natural gas and oil production 38,574 16,207 (30,501)(b)
Construction materials and mining 30,113 20,459 24,499
Total earnings on common stock $ 110,262 $ 83,308 $ 33,330
Capital expenditures:
Electric $ 15,788 $ 18,218 $ 13,035
Natural gas distribution 21,336 9,246 8,256
Utility services 42,633 16,052 18,343
Pipeline and energy services 69,006 35,123 17,603
Natural gas and oil production 173,441 64,294 100,572
Construction materials and mining 218,716 105,098 172,108
Net proceeds from sale or
disposition of property (11,000) (16,660) (4,275)
Total net capital expenditures $ 529,920 $ 231,371 $ 325,642
Identifiable assets:
Electric(c) $ 305,099 $ 307,417
Natural gas distribution(c) 192,854 131,294
Utility services 123,451 67,755
Pipeline and energy services 362,592 302,587
Natural gas and oil production 410,207 255,416
Construction materials and mining 874,299 655,499
Corporate assets(d) 44,457 46,335
Total identifiable assets $2,312,959 $1,766,303
Property, plant and equipment:
Electric $ 589,700 $ 581,090
Natural gas distribution 227,742 185,797
Utility services 39,865 21,876
Pipeline and energy services 369,834 308,409
Natural gas and oil production 513,419 343,157
Construction materials and mining 755,563 601,952
Less accumulated depreciation,
depletion and amortization 895,109 794,105
Net property, plant and equipment $1,601,014 $1,248,176
(a) In accordance with the provision of SFAS No. 71,
intercompany coal sales are not eliminated.
(b) Reflects $39.9 million in noncash after-tax write-
downs of natural gas and oil properties.
(c) Includes, in the case of electric and natural gas distribution
property, allocations of common utility property.
(d) 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 2000, 1999 and 1998, related to acquisitions,
in the preceding table include the following noncash transactions:
issuance of the company's equity securities and the conversion of a
note receivable to purchase consideration of $132.1 million in 2000;
the issuance of the company's equity securities of $77.5 million in
1999; and the issuance of the company's equity securities, less
treasury stock acquired, in 1998 of $138.8 million.
NOTE 10
ACQUISITIONS
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
coal bed 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, WBI Production, Inc., an indirect wholly owned
subsidiary of the company, purchased substantially all of the assets of
Preston Reynolds & Co., Inc. (Preston), a coal bed natural gas
development operation, as previously discussed. Pursuant to the asset
purchase and sale agreement, Preston may, but is not obligated to
purchase, acquire and own an undivided 25 percent working interest
(Seller's Option Interest) in oil and gas leases or properties acquired
and/or generated by Redstone Gas Partners, LLC, a limited liability
company controlled by the company. The Seller's Option Interest
commences April 1, 2002 and terminates six months thereafter and
requires Preston to pay WBI Production 25 percent of its capital
investment, during the two year period subsequent to April 1, 2000, in
the oil and gas leases or properties. WBI Production has the right,
but not the obligation, to purchase Seller's Option Interest from
Preston for an amount as specified in the agreement.
In 1999, the company acquired a number of businesses, none of which was
individually material, including construction materials and mining
companies with operations in California, Montana, Oregon and Wyoming;
and utility services companies based in Montana and Oregon. The total
purchase consideration for these businesses, consisting of the
company's common stock and cash, was $81.9 million.
In March 1998, the company acquired Morse Bros., Inc. and S2 - F Corp.,
privately held construction materials companies located in Oregon's
Willamette Valley. The purchase consideration for such companies
consisted of $98.2 million of the company's common stock and cash.
Morse Bros., Inc. sells aggregate, ready-mixed concrete, asphalt,
prestressed concrete and construction services in the Willamette Valley
from Portland to Eugene. S2 - F Corp. sells aggregate and construction
services.
The company also acquired a number of other businesses in 1998, none of
which was individually material, including construction materials and
mining businesses in Oregon, utility services construction and
engineering businesses in California and Montana and a natural gas
marketing business in Kentucky. The total purchase consideration,
consisting of the company's common stock and cash, for these businesses
was $62.7 million.
The above acquisitions were accounted for under the purchase method of
accounting and accordingly, the acquired assets and liabilities assumed
have been preliminarily recorded at their respective fair values as of
the date of acquisition. 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. 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 11
EMPLOYEE BENEFIT PLANS
The company has noncontributory defined benefit pension plans and other
postretirement benefit plans. There were no additional minimum pension
liabilities required to be recognized as of December 31, 2000 and 1999.
Changes in benefit obligation and plan assets for the years ended
December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
2000 1999 2000 1999
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $180,997 $187,665 $65,939 $ 70,338
Service cost 4,561 4,894 1,307 1,451
Interest cost 14,174 12,573 4,946 4,720
Plan participants' contributions --- --- 677 617
Amendments 7,111 3,612 --- 3,691
Actuarial (gain) loss 9,535 (17,134) 928 (11,047)
Benefits paid (15,498) (10,613) (4,330) (3,831)
Benefit obligation at
end of year 200,880 180,997 69,467 65,939
Change in plan assets:
Fair value of plan assets at
beginning of year 276,459 251,194 47,147 39,543
Actual return on plan assets 875 35,874 (1,078) 5,223
Employer contribution 28 4 4,630 5,595
Plan participants' contributions --- --- 677 617
Benefits paid (15,498) (10,613) (4,330) (3,831)
Fair value of plan assets at end
of year 261,864 276,459 47,046 47,147
Funded status 60,984 95,462 (22,421) (18,792)
Unrecognized actuarial gain (76,417) (108,593) (15,228) (21,299)
Unrecognized prior service cost 16,271 10,206 --- ---
Unrecognized net transition
obligation (asset) (3,387) (4,402) 28,532 30,910
Accrued benefit cost $ (2,549) $ (7,327) $(9,117) $ (9,181)
Weighted average assumptions for the company's pension and other
postretirement benefit plans as of December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
2000 1999 2000 1999
Discount rate 7.50% 7.75% 7.50% 7.75%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Health care rate assumptions for the company's other postretirement
benefit plans as of December 31 are as follows:
2000 1999
Health care trend rate 6.00%-7.50% 6.00%-8.00%
Health care cost trend rate - ultimate 5.00%-6.00% 5.00%-6.00%
Year in which ultimate trend rate achieved 1999-2004 1999-2004
Components of net periodic benefit cost for the company's pension and
other postretirement benefit plans are as follows:
Other
Pension Postretirement
Benefits Benefits
Years ended December 31, 2000 1999 1998 2000 1999 1998
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 4,561 $ 4,894 $ 4,509 $1,307 $1,451 $1,502
Interest cost 14,174 12,573 12,248 4,946 4,720 4,848
Expected return on assets (19,927) (17,489) (15,892) (3,267) (2,807) (2,395)
Amortization of prior
service cost 1,047 842 848 --- --- ---
Recognized net actuarial
gain (2,907) (995) (621) (799) (200) (169)
Settlement gain (700) --- --- --- --- ---
Amortization of net
transition obligation
(asset) (997) (997) (994) 2,378 2,377 2,458
Net periodic benefit cost
(income) (4,749) (1,172) 98 4,565 5,541 6,244
Less amount capitalized (397) (87) 79 369 463 628
Net periodic benefit
expense (income) $ (4,352) $(1,085) $ 19 $4,196 $5,078 $5,616
The company has other postretirement benefit plans including health
care and life insurance. 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 plan 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, 2000:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 216 $ (196)
Effect on postretirement benefit
obligation $ 2,716 $(2,627)
In addition to company-sponsored plans, certain union employees of
Hawaiian Cement, an indirect wholly owned subsidiary of the company,
are covered under a multi-employer defined benefit plan administered by
a union. Amounts contributed to the multi-employer plan were $947,000,
$818,000 and $755,000 in 2000, 1999 and 1998, respectively.
The company has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that provides for defined
benefit payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period. Investments consist of
life insurance carried on plan participants which is payable to the
company upon the employee's death. The cost of these benefits was
$3.5 million, $3.3 million and $2.7 million in 2000, 1999 and 1998,
respectively.
The company sponsors various defined contribution plans for eligible
employees. Costs incurred by the company under these plans were
$6.1 million in 2000, $4.4 million in 1999 and $3.1 million in 1998.
The costs incurred in each year reflect additional participants as a
result of business acquisitions.
NOTE 12
JOINTLY OWNED FACILITIES
The consolidated financial statements include the company's 22.7
percent and 25.0 percent ownership interests in the assets, liabilities
and expenses of the Big Stone Station and the Coyote Station,
respectively. Each owner of the Big Stone and Coyote stations is
responsible for financing its investment in the jointly owned
facilities.
The company's share of the Big Stone Station and Coyote Station
operating expenses is reflected in the appropriate categories of
operating expenses in the Consolidated Statements of Income.
At December 31, the company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
2000 1999
(In thousands)
Big Stone Station:
Utility plant in service $ 50,029 $ 49,889
Less accumulated depreciation 31,381 29,611
$ 18,648 $ 20,278
Coyote Station:
Utility plant in service $122,111 $121,919
Less accumulated depreciation 63,741 60,350
$ 58,370 $ 61,569
NOTE 13
REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND
In June 1995, Williston Basin Interstate Pipeline Company (Williston
Basin), an indirect wholly owned subsidiary of the company, filed a
general rate increase application with the Federal Energy Regulatory
Commission (FERC). As a result of FERC orders issued after Williston
Basin's application was filed, Williston Basin filed revised base rates
in December 1995 with the FERC. Williston Basin began collecting such
increase effective January 1, 1996, subject to refund. In July 1998,
the FERC issued an order which addressed various issues including
storage cost allocations, return on equity and throughput. In August
1998, Williston Basin requested rehearing of such order. In June 1999,
the FERC issued an order approving and denying various issues addressed
in Williston Basin's rehearing request, and also remanding the return
on equity issue to an Administrative Law Judge for further proceedings.
In July 1999, Williston Basin requested rehearing of certain issues
which were contained in the June 1999 FERC order. In September 1999,
the FERC granted Williston Basin's request for rehearing with respect
to the return on equity issue but also ordered Williston Basin to issue
interim refunds prior to the final determination in this proceeding.
As a result, in October 1999, Williston Basin issued refunds to its
customers totaling $11.3 million, all from amounts which had previously
been reserved. In December 1999, a hearing was held before the FERC
regarding the return on equity issue. On April 27, 2000, the
Administrative Law Judge issued an Initial Decision regarding the
remanded return on equity issue. On August 15, 2000, Williston Basin
filed a stipulation and agreement for the purpose of resolving the rate
and refund matters at issue with the FERC. On November 21, 2000, the
FERC issued its order accepting the August 15, 2000 stipulation and
agreement. As a result, on December 28, 2000, Williston Basin issued
refunds to its customers totaling $13.0 million, all from amounts which
had previously been reserved.
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.
Reserves have been provided for a portion of the revenues that have
been collected subject to refund with respect to pending regulatory
proceedings and to reflect future resolution of certain issues with the
FERC. Based on the November 21, 2000 FERC order referenced above,
Williston Basin, in the fourth quarter of 2000, determined that
reserves it had previously established exceeded its expected refund
obligation and, accordingly, reversed reserves and recognized in income
$6.7 million after tax. Williston Basin, in the second quarter of
1999, determined that reserves it had previously established in
relation to a 1992 general natural gas rate change application and the
1995 general rate increase application exceeded its expected refund
obligation and, accordingly, reversed reserves and recognized in income
$4.4 million after tax. Williston Basin believes that its remaining
reserves are adequate based on its assessment of the ultimate outcome
of the application filed in December 1999.
NOTE 14
COMMITMENTS AND CONTINGENCIES
Litigation
In March 1997, 11 natural gas producers filed suit in North Dakota
Northwest Judicial District Court (North Dakota District Court) against
Williston Basin and the company. The natural gas producers had
processing agreements with Koch Hydrocarbon Company (Koch). Williston
Basin and the company had natural gas purchase contracts with Koch.
The natural gas producers alleged they were entitled to damages for the
breach of Williston Basin's and the company's contracts with Koch
although no specific damages were stated. A similar suit was filed by
Apache Corporation (Apache) and Snyder Oil Corporation (Snyder) in
North Dakota District Court in December 1993. The North Dakota Supreme
Court in December 1999 affirmed the North Dakota District Court
decision dismissing Apache's and Snyder's claims against Williston
Basin and the company. Based in part upon the decision of the North
Dakota Supreme Court affirming the dismissal of the claims brought by
Apache and Snyder, Williston Basin and the company filed motions for
summary judgment to dismiss the claims of the 11 natural gas producers.
The motions for summary judgment were granted by the North Dakota
District Court on July 3, 2000. The company is awaiting entry of a
final judgment on the July 3, 2000 order granting the motions for
summary judgment.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in United States
District Court for the District of Columbia (U.S. District Court)
against Williston Basin and over 70 other natural gas pipeline
companies. Grynberg, acting on behalf of the United States under the
Federal False Claims Act, alleged improper measurement of the heating
content or volume of natural gas purchased by the defendants resulting
in the underpayment of royalties to the United States. In March 1997,
the U.S. District Court dismissed the suit without prejudice and the
dismissal was affirmed by the D.C. Circuit Court 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 on March 17, 2000. Williston Basin and Montana-Dakota are
awaiting a decision from the Federal District Court.
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, 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.
Williston Basin and Montana-Dakota believe the claims of Grynberg and
Quinque are without merit and intend to vigorously contest these suits.
The company is also involved in other legal actions in the ordinary
course of its business. Although the outcomes of any such legal
actions cannot be predicted, management believes that there is no
pending legal proceeding against or involving the company, except those
discussed above, for which the outcome is likely to have a material
adverse effect upon the company's financial position or results of
operations.
Environmental matters
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly owned
subsidiary of the company, was named by the United States Environmental
Protection Agency (EPA) as a Potentially Responsible Party in
connection with the cleanup of a commercial property site, now owned by
MBI, and part of the Portland, Oregon, Harbor Superfund Site. Sixty-
eight other parties were also named in this administrative action. The
EPA wants responsible parties to share in the cleanup of sediment
contamination in the Willamette River. Based upon a review of the
Portland Harbor sediment contamination evaluation by the Oregon State
Department of Environmental Quality and other information available,
MBI does not believe it is a Responsible Party. In addition, MBI
intends to seek indemnity for any and all liabilities incurred in
relation to the above matters from Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, pursuant to the terms of
their sale agreement.
Electric purchased power commitments
Through October 31, 2006, Montana-Dakota has contracted to purchase
66,400 kW of participation power annually from Basin Electric Power
Cooperative. In addition, Montana-Dakota, under a power supply
contract through December 31, 2006, is purchasing up to 55,000 kW of
capacity annually from Black Hills Power and Light Company.
NOTE 15
QUARTERLY DATA (UNAUDITED)
The following unaudited information shows selected items by quarter for
the years 2000 and 1999:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
2000
Operating revenues $371,989 $362,979 $530,834 $607,869
Operating expenses 342,559 321,900 454,811 537,414
Operating income 29,430 41,079 76,023 70,455
Net income 13,364 21,126 39,992 36,546
Earnings per common share:
Basic .23 .35 .63 .57
Diluted .23 .35 .63 .56
Weighted average common shares
outstanding:
Basic 57,051 59,987 62,975 64,289
Diluted 57,188 60,212 63,345 64,817
1999
Operating revenues $259,046 $290,267 $375,591 $354,905
Operating expenses 233,585 254,619 321,535 310,319
Operating income 25,461 35,648 54,056 44,586
Net income 12,721 17,796 29,098 24,465
Earnings per common share:
Basic .24 .33 .53 .43
Diluted .23 .33 .52 .42
Weighted average common shares
outstanding:
Basic 53,147 53,373 54,995 56,898
Diluted 53,420 53,603 55,278 57,127
Certain company operations are highly seasonal and revenues from and
certain expenses for such operations may fluctuate significantly among
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 16
NATURAL GAS AND OIL ACTIVITIES (UNAUDITED)
Fidelity Exploration & Production Company (Fidelity), an indirect
wholly owned subsidiary of the company, is involved in the acquisition,
exploration, development and production of natural gas and oil
resources. Fidelity's operations include the acquisition of producing
properties with potential development opportunities, exploratory
drilling and the operation 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 and North Dakota. These rights are in the
Bonny Field located in eastern Colorado, the Cedar Creek Anticline in
southeastern Montana and southwestern North Dakota, and in the Bowdoin
area located in north-central Montana. In 2000, coal bed natural gas
reserves in the Powder River Basin of Wyoming and Montana were
acquired. These acquisitions include over 210,000 net acres under
lease.
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:
2000 1999 1998
(In thousands)
Subject to amortization $416,881 $319,448 $266,301
Not subject to amortization 94,856 23,464 22,153
Total capitalized costs 511,737 342,912 288,454
Less accumulated depreciation,
depletion and amortization 155,198 129,211 111,472
Net capitalized costs $356,539 $213,701 $176,982
NOTE: Net capitalized costs as of December 31, 1998, reflect noncash
write-downs of the company's natural gas and oil properties as
discussed in Note 1.
Capital expenditures, including those not subject to amortization,
related to natural gas and oil producing activities are as follows:
Years ended December 31, 2000 1999 1998
(In thousands)
Acquisitions $ 68,858 $ 30,842 $ 63,419
Exploration 34,839 11,010 15,976
Development 69,051 21,822 21,148
Total capital expenditures $172,748 $ 63,674 $100,543
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, 2000 1999 1998
(In thousands)
Revenues $128,217 $ 75,327 $ 61,831
Production costs 33,919 25,402 19,419
Depreciation, depletion and
amortization 26,739 19,136 23,050
Write-downs of natural gas and oil
properties (Note 1) --- --- 66,000
Pretax income (loss) 67,559 30,789 (46,638)
Income tax expense (benefit) 25,835 11,815 (19,268)
Results of operations for
producing activities $ 41,724 $ 18,974 $(27,370)
The following table summarizes the company's estimated quantities of
proved natural gas and oil reserves at December 31, 2000, 1999 and
1998, 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.
2000 1999 1998
Natural Natural Natural
Gas Oil Gas Oil Gas Oil
(In thousands of Mcf/barrels)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 268,900 14,700 243,600 11,500 184,900 14,900
Production (29,200) (1,900) (24,700) (1,800) (20,700) (1,900)
Extensions and
discoveries 51,300 1,600 21,800 800 21,300 200
Purchases of proved
reserves 23,200 100 38,200 700 56,600 2,000
Sales of reserves
in place --- (100) (9,300) (400) (100) ---
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions (4,400) 700 (700) 3,900 1,600 (3,700)
Balance at end
of year 309,800 15,100 268,900 14,700 243,600 11,500
Proved developed reserves:
January 1, 1998 163,800 14,500
December 31, 1998 193,000 10,700
December 31, 1999 213,400 13,300
December 31, 2000 263,400 14,200
All of the company's interests in natural gas and oil reserves are
located in the United States and in the Gulf of Mexico.
The standardized measure of the company's estimated discounted future
net cash flows of total proved reserves associated with its various
natural gas and oil interests at December 31 is as follows:
2000 1999 1998
(In thousands)
Future net cash flows before
income taxes $2,349,500 $492,000 $246,700
Future income tax expense 827,000 131,500 40,500
Future net cash flows 1,522,500 360,500 206,200
10% annual discount for estimated
timing of cash flows 601,200 131,400 81,100
Discounted future net cash flows
relating to proved natural gas
and oil reserves $ 921,300 $229,100 $125,100
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
2000 1999 1998
(In thousands)
Beginning of year $229,100 $125,100 $139,000
Net revenues from production (94,300) (49,900) (42,400)
Change in net realization 861,700 123,100 (70,500)
Extensions, discoveries and improved
recovery, net of future
production-related costs 288,700 33,500 18,200
Purchases of proved reserves 93,200 57,700 51,000
Sales of reserves in place (1,500) (14,700) (100)
Changes in estimated future
development costs, net of those
incurred during the year 3,400 (9,800) (16,600)
Accretion of discount 31,200 16,700 18,600
Net change in income taxes (412,300) (59,800) 30,100
Revisions of previous quantity
estimates (79,200) 7,400 (1,600)
Other 1,300 (200) (600)
Net change 692,200 104,000 (13,900)
End of year $921,300 $229,100 $125,100
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end natural gas
prices and oil prices except in those instances where future natural
gas or oil sales are covered by physical or derivative contract terms
providing for higher or lower amounts. 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.
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
2000 1999 1998* 1997 1996 1995 1990
Selected Financial Data
Operating revenues (000's):
Electric $ 161,621 $ 154,869 $ 147,221 $ 141,590 $ 138,761 $ 134,609 $ 124,156
Natural gas distribution 233,051 157,692 154,147 157,005 155,012 150,532 127,844
Utility services 169,382 99,917 64,232 22,761 --- --- ---
Pipeline and energy services 636,848 383,532 180,732 87,018 71,580 67,186 103,711
Natural gas and oil production 138,316 78,394 61,842 77,916 75,350 53,505 35,038
Construction materials and mining 631,396 469,905 346,451 174,147 132,222 113,066 38,276
Intersegment eliminations (96,943) (64,500) (57,998) (52,763) (58,224) (54,652) (83,781)
$1,873,671 $1,279,809 $ 896,627 $ 607,674 $ 514,701 $ 464,246 $ 345,244
Operating income (000's):
Electric $ 38,743 $ 35,727 $ 32,167 $ 31,307 $ 29,476 $ 29,898 $ 32,221
Natural gas distribution 9,530 6,688 8,028 10,410 11,504 6,917 6,578
Utility services 16,606 11,518 5,932 1,782 --- --- ---
Pipeline and energy services 28,782 40,627 33,651 25,822 27,697 24,043 17,464
Natural gas and oil production 66,510 26,845 (50,444) 27,638 26,786 15,255 14,421
Construction materials and mining 56,816 38,346 41,609 14,602 16,062 14,463 7,749
$ 216,987 $ 159,751 $ 70,943 $ 111,561 $ 111,525 $ 90,576 $ 78,433
Earnings on common stock (000's):
Electric $ 17,733 $ 15,973 $ 13,908 $ 12,441 $ 11,436 $ 12,000 $ 14,280
Natural gas distribution 4,741 3,192 3,501 4,514 4,892 1,604 2,704
Utility services 8,607 6,505 3,272 947 --- --- ---
Pipeline and energy services 10,494 20,972 18,651 9,955 1,649 7,804 (8,737)**
Natural gas and oil production 38,574 16,207 (30,501) 15,867 15,185 8,614 9,230
Construction materials and mining 30,113 20,459 24,499 10,111 11,521 10,819 9,632
$ 110,262 $ 83,308 $ 33,330 $ 53,835 $ 44,683 $ 40,841 $ 27,109**
Earnings per common share -- diluted $ 1.80 $ 1.52 $ .66 $ 1.24 $ 1.04 $ .95 $ .63**
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 61,390 54,870 50,837 43,478 42,824 42,789 42,715
Dividends per common share $ .86 $ .82 $ .7834 $ .7534 $ .7333 $ .7188 $ .6311
Book value per common share $ 13.55 $ 11.74 $ 10.39 $ 8.84 $ 8.21 $ 7.90 $ 6.72
Market price per common share (year-end) $ 32.50 $ 20.00 $ 26.31 $ 21.08 $ 15.33 $ 13.25 $ 9.11
Market price ratios:
Dividend payout 48% 54% 119% 61% 70% 76% 99%**
Yield 2.7% 4.2% 3.0% 3.6% 4.8% 5.5% 6.9%
Price/earnings ratio 18.1x 13.2x 39.9x 17.0x 14.6x 13.9x 14.3x**
Market value as a percent of book value 239.9% 170.4% 253.2% 238.5% 186.8% 167.7% 135.6%
Profitability Indicators
Return on average common equity 14.3% 13.9% 6.5% 14.6% 13.0% 12.3% 9.4%**
Return on average invested capital 9.5% 9.6% 5.5% 10.3% 9.5% 9.2% 7.8%**
Interest coverage 8.3x 7.1x 6.1x 6.0x 5.4x 3.9x 2.7x**
Fixed charges coverage, including
preferred dividends 4.1x 4.3x 2.5x 3.4x 2.7x 3.0x 1.9x**
General
Total assets (000's) $2,312,959 $1,766,303 $1,452,775 $1,113,892 $1,089,173 $1,056,479 $ 959,946
Net long-term debt (000's) $ 728,166 $ 563,545 $ 413,264 $298,561 $ 280,666 $ 237,352 $ 229,786
Redeemable preferred stock (000's) $ 1,500 $ 1,600 $ 1,700 $ 1,800 $ 1,900 $ 2,000 $ 2,500
Capitalization ratios:
Common equity 54% 54% 56% 55% 54% 57% 54%
Preferred stocks 1 1 2 2 3 3 3
Long-term debt 45 45 42 43 43 40 43
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.
** Reflects a $6.8 million or 16 cent per common share after-tax effect of an absorption of certain natural gas contract litigation
settlement costs.
</FN>
NOTE: Common stock share amounts reflect the company's three-for-two common stock splits effected in October 1995 and July 1998.
2000 1999 1998 1997 1996 1995 1990
Electric
Sales to ultimate consumers (thousand kWh) 2,161,280 2,075,446 2,053,862 2,041,191 2,067,926 1,993,693 1,820,150
Sales for resale (thousand kWh) 930,318 943,520 586,540 361,954 374,535 408,011 285,564
Electric system generating and firm purchase
capability -- kW (Interconnected system) 500,420 492,800 489,100 487,500 481,800 472,400 451,600
Demand peak -- kW (Interconnected system) 432,300 420,550 402,500 404,600 393,300 412,700 381,600
Electricity produced (thousand kWh) 2,331,188 2,350,769 2,103,199 1,826,770 1,829,669 1,718,077 1,674,648
Electricity purchased (thousand kWh) 948,700 860,508 730,949 769,679 809,261 867,524 573,099
Average cost of fuel and purchased
power per kWh $.016 $.016 $.017 $.018 $.017 $.016 $.016
Natural Gas Distribution
Sales (Mdk) 36,595 30,931 32,024 34,320 38,283 33,939 28,278
Transportation (Mdk) 14,314 11,551 10,324 10,067 9,423 11,091 11,806
Weighted average degree days --
% of previous year's actual 113% 95% 94% 85% 114% 105% 88%
Pipeline and Energy Services
Pipeline:
Sales for resale (Mdk) --- --- --- --- --- --- 19,658
Transportation (Mdk) 86,787 78,061 88,974 85,464 82,169 68,015 50,809
Gathering (Mdk) 41,717 19,799 9,093 9,550 8,983 9,651 1,324
Energy services:
Natural gas volumes (Mdk) 149,823 131,687 58,495 14,971 4,670 3,556 1,853
Natural Gas and Oil Production
Production:
Natural gas (MMcf) 29,222 24,652 20,699 20,407 20,391 17,574 3,846
Oil (000's of barrels) 1,882 1,758 1,912 2,088 2,149 1,973 1,374
Average realized prices:
Natural gas (per Mcf) $ 2.90 $ 1.94 $ 1.81 $ 2.02 $ 1.79 $ 1.33 $ 1.76
Oil (per barrel) $23.06 $15.34 $12.71 $17.50 $17.91 $15.07 $20.11
Net recoverable reserves:
Natural gas (MMcf) 309,800 268,900 243,600 184,900 200,200 179,000 16,100
Oil (000's of barrels) 15,100 14,700 11,500 14,900 16,100 14,200 12,400
Construction Materials and Mining
Construction materials (000's):
Aggregates (tons sold) 18,315 13,981 11,054 5,113 3,374 2,904 ---
Asphalt (tons sold) 3,310 2,993 1,790 758 694 373 ---
Ready-mixed concrete (cubic yards sold) 1,696 1,186 1,021 516 340 307 ---
Recoverable aggregate reserves (tons) 894,500 740,030 654,670 169,375 119,800 68,000 ---
Coal (000's):
Sales (tons) 3,111 3,236 3,113 2,375 2,899 4,218 4,439
Recoverable reserves (tons) 145,643 182,761 190,152 226,560 228,900 231,900 261,500