MDU RESOURCES GROUP, INC.
1998 FINANCIAL REPORT
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
Audit 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 Audit 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 generally
accepted auditing standards 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
President and Chief Vice President, Treasurer
Executive Officer and Chief 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, 1998 and 1997, 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, 1998. 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 generally accepted auditing
standards. 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, 1998 and
1997, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 21, 1999
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 1998 1997 1996
(In thousands, except per share amounts)
Operating revenues:
Electric $ 211,453 $ 164,351 $ 138,761
Natural gas 287,426 200,789 175,408
Construction materials and mining 346,451 174,147 132,222
Oil and natural gas production 51,297 68,387 68,310
896,627 607,674 514,701
Operating expenses:
Fuel and purchased power 49,829 45,604 43,983
Purchased natural gas sold 158,908 77,082 48,886
Operation and maintenance 448,290 283,894 225,682
Depreciation, depletion and
amortization 77,786 65,767 62,651
Taxes, other than income 24,871 23,766 21,974
Write-downs of oil and natural gas
properties (Note 1) 66,000 --- ---
825,684 496,113 403,176
Operating income:
Electric 38,099 33,089 29,476
Natural gas distribution 8,028 10,410 11,504
Natural gas transmission 38,114 29,169 30,231
Construction materials and mining 41,609 14,602 16,062
Oil and natural gas production (54,907) 24,291 24,252
70,943 111,561 111,525
Other income -- net 10,922 4,008 5,617
Interest expense 30,273 30,209 28,832
Costs on natural gas
repurchase commitment (Note 15) --- --- 26,753
Income before income taxes 51,592 85,360 61,557
Income taxes 17,485 30,743 16,087
Net income 34,107 54,617 45,470
Dividends on preferred stocks 777 782 787
Earnings on common stock $ 33,330 $ 53,835 $ 44,683
Earnings per common share -- basic $ .66 $ 1.24 $ 1.05
Earnings per common share -- diluted $ .66 $ 1.24 $ 1.04
Dividends per common share $ .7834 $ .7534 $ .7333
Weighted average common shares
outstanding -- basic 50,536 43,315 42,715
Weighted average common shares
outstanding -- diluted 50,837 43,478 42,824
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1998 1997
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 39,216 $ 28,174
Receivables 124,114 80,585
Inventories 44,865 41,322
Deferred income taxes 16,918 17,356
Prepayments and other current assets 15,536 12,479
240,649 179,916
Investments 43,029 18,935
Property, plant and equipment:
Electric 583,047 566,247
Natural gas distribution 178,522 172,086
Natural gas transmission 304,054 288,709
Construction materials and mining 484,419 243,110
Oil and natural gas production 260,758 240,193
1,810,800 1,510,345
Less accumulated depreciation,
depletion and amortization 726,123 670,809
1,084,677 839,536
Deferred charges and other assets 84,420 75,505
$1,452,775 $1,113,892
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 15,000 $ 3,347
Long-term debt and preferred
stock due within one year 3,292 7,902
Accounts payable 60,023 31,571
Taxes payable 9,226 9,057
Dividends payable 10,799 8,574
Other accrued liabilities,
including reserved revenues 71,129 88,563
169,469 149,014
Long-term debt (Note 6) 413,264 298,561
Deferred credits and other liabilities:
Deferred income taxes 173,094 119,747
Other liabilities (Note 15) 129,506 143,574
302,600 263,321
Preferred stock subject to mandatory
redemption (Note 7) 1,600 1,700
Commitments and contingencies
(Notes 11, 14, 15 and 16)
Stockholders' Equity:
Preferred stocks (Note 7) 15,000 15,000
Common stockholders' equity:
Common stock (Note 8)
Authorized -- 75,000,000 shares,
$3.33 par value
Issued -- 53,272,951 and 29,143,332
shares in 1998 and
1997, respectively 177,399 97,047
Other paid-in capital 171,486 76,526
Retained earnings 205,583 212,723
Treasury stock at cost - 239,521 shares (3,626) ---
Total common stockholders' equity 550,842 386,296
Total stockholders' equity 565,842 401,296
$1,452,775 $1,113,892
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, Other
1998, 1997 and 1996 Common Stock Paid-In Retained Treasury Stock
Shares Amount Capital Earnings Shares Amount Total
(In thousands, except shares)
Balance at
December 31, 1995 28,476,981 $ 94,828 $ 64,305 $178,184 --- $ --- $337,317
Net income --- --- --- 45,470 --- --- 45,470
Dividends on
preferred stocks --- --- --- (787) --- --- (787)
Dividends on common stock --- --- --- (31,326) --- --- (31,326)
Balance at
December 31, 1996 28,476,981 94,828 64,305 191,541 --- --- 350,674
Net income --- --- --- 54,617 --- --- 54,617
Dividends on
preferred stocks --- --- --- (782) --- --- (782)
Dividends on common stock --- --- --- (32,653) --- --- (32,653)
Issuance of common stock:
Acquisitions 225,629 751 3,622 --- --- --- 4,373
Other 440,722 1,468 8,599 --- --- --- 10,067
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:
Acquisitions (pre-split) 4,973,629 16,562 112,353 --- --- --- 128,915
Other (pre-split) 869,068 2,894 26,900 --- --- --- 29,794
Treasury stock
acquired --- --- --- --- (159,681) (3,626) (3,626)
Three-for-two
common stock
split (Note 8) 17,493,014 58,252 (58,252) --- (79,840) --- ---
Issuance of
common stock:
Acquisitions (post-split) 672,863 2,241 11,234 --- --- --- 13,475
Other (post-split) 121,045 403 2,725 --- --- --- 3,128
Balance at
December 31, 1998 53,272,951 $177,399 $171,486 $205,583 (239,521) $(3,626) $550,842
<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, 1998 1997 1996
(In thousands)
Operating activities:
Net income $ 34,107 $ 54,617 $ 45,470
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 77,786 65,767 62,651
Deferred income taxes and
investment tax credit (17,256) 12,894 138
Recovery of deferred natural gas
contract litigation settlement
costs --- 5,486 10,743
Write-down of natural gas
available under repurchase
commitment (Note 15) --- --- 18,553
Write-downs of oil and natural gas
properties (Note 1) 66,000 --- ---
Changes in current assets and
liabilities:
Receivables (10,464) 6,951 (9,346)
Inventories 1,718 (4,214) (1,218)
Other current assets (547) 2,026 (1,467)
Accounts payable 14,094 (5,605) 7,584
Other current liabilities (19,805) (6,087) (22,434)
Other noncurrent changes (7,187) 6,794 (4,436)
Net cash provided by operating
activities 138,446 138,629 106,238
Financing activities:
Net change in short-term borrowings 3,933 (5,919) 3,350
Issuance of long-term debt 209,890 54,064 81,300
Repayment of long-term debt (113,600) (47,899) (43,262)
Retirement of preferred stocks (100) (100) (100)
Issuance of common stock 32,922 10,067 ---
Retirement of natural gas
repurchase commitment (17,105) (52,090) (4,157)
Dividends paid (41,247) (33,435) (32,113)
Net cash provided by (used in)
financing activities 74,693 (75,312) 5,018
Investing activities:
Capital expenditures including
acquisitions of businesses:
Electric (10,897) (18,713) (18,674)
Natural gas distribution (8,256) (8,858) (6,255)
Natural gas transmission (17,522) (13,205) (10,127)
Construction materials and mining (60,014) (40,797) (25,063)
Oil and natural gas production (94,465) (30,651) (51,821)
(191,154) (112,224) (111,940)
Net proceeds from sale or
disposition of property 4,275 4,522 11,803
Net capital expenditures (186,879) (107,702) (100,137)
Sale of natural gas available
under repurchase commitment 7,727 27,008 10,595
Investments (22,945) (2,248) (7,313)
Net cash used in investing
activities (202,097) (82,942) (96,855)
Increase (decrease) in cash
and cash equivalents 11,042 (19,625) 14,401
Cash and cash equivalents --
beginning of year 28,174 47,799 33,398
Cash and cash equivalents --
end of year $ 39,216 $ 28,174 $ 47,799
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.
(company) include the accounts of two regulated businesses -- retail and
wholesale sales of electricity and retail sales and/or transportation of
natural gas and propane, and natural gas transmission and storage -- and
two nonregulated businesses -- construction materials and mining
operations, and oil and natural gas production. The statements also
include the ownership interests in the assets, liabilities and expenses of
two jointly owned electric generating 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 allows 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 3 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.
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 oil
and natural gas 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 amounts of AFUDC and
interest capitalized were not material in 1998, 1997 and 1996. Property,
plant and equipment are depreciated on a straight-line basis over the
average useful lives of the assets, except for oil and natural gas
production properties as described below.
Oil and natural gas
The company uses the full-cost method of accounting for its oil and
natural gas production activities. Under this method, all costs incurred
in the acquisition, exploration and development of oil and natural gas
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 oil and natural gas 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 oil and natural gas producing properties.
These noncash write-downs amounted to $33.1 million ($20.0 million after
tax) and $32.9 million ($19.9 million after tax) for the quarters ended
June 30, 1998 and December 31, 1998, respectively.
Natural gas in underground storage and available under repurchase
commitment
Natural gas in underground storage is carried at cost using the last-in,
first-out (LIFO) method. The portion of the cost of natural gas in
underground storage expected to be used within one year is included in
inventories.
Natural gas available under a repurchase commitment with Frontier Gas
Storage Company (Frontier) is carried at Frontier's cost of purchased
natural gas, less an allowance to reflect changed market conditions, and
is reflected on the company's Consolidated Balance Sheets in "Deferred
charges and other assets." See Note 15 for discussion on the write-down
which occurred in 1996 of the natural gas available under the repurchase
commitment with Frontier.
Inventories
Inventories, other than natural gas in underground storage, consist
primarily of materials and supplies and inventories held for resale.
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 generally recognizes all
other revenues when services are rendered or goods are delivered.
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 24 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 Montana-Dakota's and Williston Basin'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. Common stock outstanding
includes issued shares less shares held in treasury. Earnings per share
have been restated to reflect the three-for-two common stock split
effected in July 1998 as discussed in Note 8.
Comprehensive income
On January 1, 1998, the company adopted Statement of Financial Accounting
Standards No. 130, "Reporting Comprehensive Income" (SFAS No. 130). SFAS
No. 130 provides authoritative guidance on the reporting and display of
comprehensive income and its components. For the years ended December 31,
1998, 1997 and 1996, comprehensive income equaled net income as reported.
Use of estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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 plant
depreciable lives, tax provisions, uncollectible accounts, environmental
and other loss contingencies, accumulated provision for revenues subject
to refund, 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, 1998 1997 1996
(In thousands)
Interest, net of amount capitalized $26,394 $25,626 $25,449
Income taxes $34,498 $18,171 $28,163
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Reclassifications
Certain reclassifications have been made in the financial statements for
prior years to conform to the current presentation. Such
reclassifications had no effect on net income or common stockholders'
equity as previously reported.
New accounting standard
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (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 a derivative's 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 is effective for fiscal years beginning after June 15, 1999.
SFAS No. 133 must be applied to derivative instruments and certain
derivative instruments embedded in hybrid contracts that were issued,
acquired, or substantively modified after December 31, 1997. The company
will adopt SFAS No. 133 on January 1, 2000, and has not yet quantified the
impacts of adopting SFAS No. 133 on the company's financial position or
results of operations.
NOTE 2
NATURAL GAS IN UNDERGROUND STORAGE
Natural gas in underground storage included in natural gas transmission
and natural gas distribution property, plant and equipment amounted to
$43.7 million at December 31, 1998, and $43.1 million at December 31,
1997. In addition, $11.5 million and $11.4 million at December 31, 1998
and 1997, respectively, of natural gas in underground storage is included
in inventories.
NOTE 3
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:
1998 1997
(In thousands)
Regulatory assets:
Long-term debt refinancing costs $ 10,995 $ 11,466
Postretirement benefit costs 2,036 2,940
Plant costs 3,003 3,173
Other 11,647 10,899
Total regulatory assets 27,681 28,478
Regulatory liabilities:
Reserves for regulatory matters 39,981 39,193
Taxes refundable to customers 14,129 13,933
Plant decommissioning costs 6,413 5,843
Natural gas costs refundable
through rate adjustments 274 21,721
Other 1,351 1,393
Total regulatory liabilities 62,148 82,083
Net regulatory position $(34,467) $(53,605)
As of December 31, 1998, substantially all of the company's regulatory
assets are being reflected in rates charged to customers and are being
recovered over the next 1 to 18 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 4
FINANCIAL INSTRUMENTS
Derivatives
Williston Basin Interstate Pipeline Company and Fidelity Oil Group have
entered into certain price swap and collar agreements to manage a portion
of the market risk associated with fluctuations in the price of oil and
natural gas. These swap and collar agreements are not held for trading
purposes. The swap and collar agreements call for Williston Basin and
Fidelity 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 an oil
price quoted on the New York Mercantile Exchange (NYMEX) or a quoted
natural gas price on the NYMEX or Colorado Interstate Gas Index. 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. Amounts payable or receivable on the swap and collar
agreements are 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 amounts
payable or receivable are generally offset by corresponding increases and
decreases in the value of the underlying commodity transactions.
Innovative Gas Services, Incorporated participates in the natural gas
futures market to hedge a portion of the price risk associated with
natural gas purchase and sale commitments. These futures are not held for
trading purposes. Gains or losses on the futures contracts are deferred
until the transaction occurs, at which point they are reported in
"Purchased natural gas sold" on the Consolidated Statements of Income.
The gains or losses on the futures contracts are generally offset by
corresponding increases and decreases in the value of the underlying
commodity transactions.
Williston Basin and Knife River Corporation entered into interest rate
swap agreements to manage a portion of their interest rate exposure on the
natural gas repurchase commitment and long-term debt, respectively. These
interest rate swap agreements, which expired in August 1997 and August
1998, respectively, were not held for trading purposes. The interest rate
swap agreements called for Williston Basin and Knife River to receive
quarterly payments from or make payments to counterparties based upon the
difference between fixed and variable rates as specified by the interest
rate swap agreements. The variable prices were based on the three-month
floating London Interbank Offered Rate. Settlement amounts payable or
receivable under these interest rate swap agreements were recorded in
"Interest expense" for Knife River and "Costs on natural gas repurchase
commitment" for Williston Basin on the Consolidated Statements of Income
in the accounting period they were incurred. The amounts payable or
receivable were generally offset by interest on the related debt
instruments.
The company's policy prohibits the use of derivative instruments for
trading purposes 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 following table summarizes the company's hedging activity:
Years ended December 31, 1998 1997 1996
(Notional amounts in thousands)
Oil swap agreements:*
Range of fixed prices per barrel $20.92 $19.77-$21.36 $18.74-$19.07
Notional amount (in barrels) 219 730 635
Natural gas swap/collar agreements:*
Range of fixed prices per MMBtu $1.54-$2.67 $1.30-$2.395 $1.40-$2.05
Notional amount (in MMBtu's) 6,082 8,039 5,331
Natural gas futures contracts:*
Range of fixed prices per MMBtu $1.96-$2.50 --- ---
Notional amount (in MMBtu's) 650 --- ---
Natural gas collar agreement:**
Range of fixed prices per MMBtu --- --- $1.22-$1.52
Notional amount (in MMBtu's) --- --- 910
Interest rate swap agreements:**
Range of fixed interest rates 5.50%-6.50% 5.50%-6.50% 5.50%-6.50%
Notional amount (in dollars) $10,000 $30,000 $30,000
* Receive fixed -- pay variable
** Receive variable -- pay fixed
At December 31, 1998, the company has natural gas collar agreements
outstanding for 2.9 million MMBtu's of natural gas which call for the
company, in 1999, to receive monthly payments from counterparties when the
settlement price is below the floor price in the collar agreement or make
monthly payments to counterparties when the settlement price is above the
ceiling price in the collar agreement. The weighted average floor price
and ceiling price is $2.10 and $2.51, respectively.
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 currently not recorded on the company's financial
statements. 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. The company's net favorable position on all hedge
agreements outstanding at December 31, 1998, was $597,000.
In the event a hedge agreement does not qualify for hedge accounting or
when the underlying commodity transaction or related debt instrument
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
or related debt instrument is sold or matures and is expected to generally
offset the corresponding increases or decreases in the value of the
underlying commodity transaction or interest on the related debt
instrument.
Fair value of other financial instruments
The estimated fair value of the company's long-term debt and preferred
stock subject to mandatory redemption are based on quoted market prices of
the same or similar issues. The estimated fair values of the company's
long-term debt and preferred stock subject to mandatory redemption at
December 31 are as follows:
1998 1997
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $416,456 $435,078 $306,363 $319,367
Preferred stock
subject to mandatory
redemption $ 1,700 $ 1,592 $ 1,800 $ 1,584
The fair value of other financial instruments for which estimated fair
values have not been presented is not materially different than the
related carrying amount.
NOTE 5
SHORT-TERM BORROWINGS
The company and its subsidiaries had unsecured short-term lines of credit
from a number of banks totaling $60 million at December 31, 1998. 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. Commercial paper amounts outstanding
supported by the lines of credit were $15 million at December 31, 1998,
and $3.3 million at December 31, 1997. The weighted average interest rate
for borrowings outstanding at December 31, 1998 and 1997, was 5.45 percent
and 8.50 percent, respectively. The unused portions of the lines of
credit are subject to withdrawal based on the occurrence of certain
events.
NOTE 6
LONG-TERM DEBT AND INDENTURE PROVISIONS
Long-term debt outstanding at December 31 is as follows:
1998 1997
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, paid in 1998 $ --- $ 20,000
Pollution Control Refunding Revenue
Bonds, Series 1992 --
Mercer County, North Dakota,
6.65%, due June 1, 2022 15,000 15,000
Morton County, North Dakota,
6.65%, due June 1, 2022 2,600 2,600
Richland County, Montana,
6.65%, due June 1, 2022 3,250 3,250
Secured Medium-Term Notes,
Series A --
6.52%, due October 1, 2004 15,000 15,000
8.25%, due April 1, 2007 30,000 30,000
5.83%, due October 1, 2008 15,000 ---
6.71%, due October 1, 2009 15,000 15,000
8.60%, due April 1, 2012 35,000 35,000
Total first mortgage bonds and notes 130,850 135,850
Pollution control
note obligation, 6.20%, due
March 1, 2004 3,400 3,700
Senior notes:
8.70%, paid in 1998 --- 6,500
8.43%, due December 31, 2000 9,000 12,000
7.35%, due July 31, 2002 4,000 5,000
7.51%, due October 9, 2003 3,000 3,000
6.86%, due October 30, 2004 12,500 12,500
6.43%, due October 30, 2005 10,000 ---
7.45%, due May 31, 2006 20,000 20,000
6.68%, due October 30, 2006 15,000 ---
7.60%, due November 3, 2008 15,000 15,000
7.10%, due October 30, 2009 12,500 12,500
6.73%, due October 30, 2010 10,000 ---
7.28%, due October 30, 2012 10,000 10,000
6.87%, due October 30, 2013 5,000 ---
7.05%, due October 30, 2018 15,000 ---
Commercial paper at a weighted average
rate of 6.49%, supported by a revolving
credit agreement due on November 29, 2001 82,921 ---
Revolving lines of credit at a
weighted average rate of 6.96%,
due on dates ranging from
January 5, 2001 through December 31, 2002 45,200 64,000
Term credit agreements at a weighted
average rate of 7.84%, due on dates
ranging from January 28, 2000
through November 25, 2012 13,211 6,398
Other (126) (85)
Total long-term debt 416,456 306,363
Less current maturities 3,192 7,802
Net long-term debt $ 413,264 $ 298,561
During 1998, Centennial Energy Holdings, Inc., a direct subsidiary of the
company, entered into a revolving credit agreement with various banks on
behalf of its subsidiaries that allows for borrowings of up to $200
million. This facility supports the Centennial commercial paper program.
Under the Centennial commercial paper program, $82.9 million was
outstanding at December 31, 1998. The commercial paper borrowings are
classified as long term as the company intends to refinance these
borrowings on a long term basis through continued commercial paper
borrowings supported by the revolving credit agreement.
Under the revolving lines of credit, the company and a subsidiary have
$50 million available, $45.2 million of which was outstanding at December
31, 1998. The amounts of scheduled long-term debt maturities for the five
years following December 31, 1998 aggregate $3.2 million in 1999;
$12.4 million in 2000; $100.3 million in 2001; $49.4 million in 2002 and
$6.4 million in 2003. 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 such Indenture, the company could have issued approximately
$273 million of additional first mortgage bonds at December 31, 1998.
Certain of the company's other debt instruments contain restrictive
covenants all of which the company is in compliance with at December 31,
1998.
NOTE 7
PREFERRED STOCKS
Preferred stocks at December 31 are as follows:
1998 1997
(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 -- 17,000 and 18,000 shares
in 1998 and 1997, respectively $ 1,700 $ 1,800
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 16,700 16,800
Less current maturities and
sinking fund requirements 100 100
Net preferred stocks $16,600 $16,700
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.
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, 1998, is $100,000.
NOTE 8
COMMON STOCK
On May 14, 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 has been
restated to give retroactive effect to the stock split.
The company's Automatic Dividend Reinvestment and Stock Purchase Plan
(DRIP) provides participants in the DRIP the opportunity to invest all or
a portion of their cash dividends in shares of the company's common stock
and/or 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 DRIP. The
company's Tax Deferred Compensation Savings Plans (K-Plans) pursuant to
Section 401(k) of the Internal Revenue Code are funded with the company's
common stock. From January 1, 1989, through September 30, 1998, the DRIP
and K-Plans 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 DRIP and K-
Plans. Beginning October 1, 1998, shares of authorized but unissued
common stock were used to fund the DRIP, while the K-Plans continued to be
funded by the purchase of shares of common stock on the open market. At
December 31, 1998, there were 8.2 million shares of common stock reserved
for issuance under the DRIP and K-Plans.
On November 12, 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.
NOTE 9
INCOME TAXES
Income tax expense is summarized as follows:
Years ended December 31, 1998 1997 1996
(In thousands)
Current:
Federal $ 28,256 $15,427 $12,617
State 5,880 2,362 3,272
Foreign 605 60 60
34,741 17,849 15,949
Deferred:
Investment tax credit (975) (1,150) (1,099)
Income taxes --
Federal (14,214) 11,844 1,139
State (2,067) 2,200 120
Foreign --- --- (22)
(17,256) 12,894 138
Total income tax expense $ 17,485 $30,743 $16,087
Components of deferred tax assets and deferred tax liabilities recognized
in the company's Consolidated Balance Sheets at December 31 are as
follows:
1998 1997
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 35,703 $ 32,789
Natural gas available under
repurchase commitment 2,268 4,821
Accrued pension costs 9,274 8,445
Deferred investment tax credits 2,336 2,714
Accrued land reclamation 2,907 3,184
Other 13,266 12,851
Total deferred tax assets 65,754 64,804
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 192,166 123,629
Basis differences on oil and
natural gas producing properties 9,604 30,726
Long-term debt refinancing costs 4,491 4,672
Other 15,669 8,168
Total deferred tax liabilities 221,930 167,195
Net deferred income tax liability $(156,176) $(102,391)
The following table reconciles the change in the net deferred income tax
liability from December 31, 1997, to December 31, 1998, to the deferred
income tax expense included in the Consolidated Statements of Income:
1998
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 53,785
Change in tax effects of income tax-related
regulatory assets and liabilities 323
Deferred taxes associated with acquisitions (70,389)
Deferred income tax expense for the period $(16,281)
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, 1998 1997 1996
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $18,057 35.0 $29,876 35.0 $21,545 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,571) (3.0) (828) (1.0) (1,070) (1.7)
State income
taxes -- net of
federal income tax
benefit 2,312 4.5 3,473 4.1 2,770 4.5
Investment tax credit
amortization (975) (1.9) (1,150) (1.4) (1,099) (1.8)
Tax reserve adjustment --- --- --- --- (6,600) (10.7)
Other items (338) (.7) (628) (.7) 541 .8
Total income tax expense $17,485 33.9 $30,743 36.0 $16,087 26.1
In 1996, the company reached a settlement with the Internal Revenue
Service concerning notices of deficiency issued in connection with
disputed items for the 1983 through 1988 tax years and, in 1997, reached a
similar settlement for the tax years 1989 through 1991. In 1996, the
company reflected the effects of the 1996 settlement and the 1997
anticipated settlement in the consolidated financial statements and, in
addition, reversed reserves which had previously been provided and were
deemed to be no longer required.
NOTE 10
BUSINESS SEGMENT DATA
In 1998, the company adopted SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information" (SFAS No. 131). SFAS No. 131
requires the disclosure of certain information about operating segments in
financial statements. The company's operations are conducted through five
business segments. 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 electric, natural gas distribution, natural
gas transmission, construction materials and mining, and oil and natural
gas production businesses are substantially all located within the United
States. The electric business operates electric power generation,
transmission and distribution facilities in North Dakota, South Dakota,
Montana and Wyoming and installs and repairs electric transmission and
distribution power lines and provides related supplies, equipment and
engineering services throughout the western United States and Hawaii. The
natural gas distribution business provides natural gas distribution
services in North Dakota, South Dakota, Montana and Wyoming. The natural
gas transmission business serves the Midwestern, Southern and Central
regions of the United States providing natural gas transmission and
related services including storage and production along with energy
marketing and management, wholesale/retail propane and energy facility
construction. The construction materials and mining business produces and
markets aggregates and construction materials in Alaska, California,
Hawaii and Oregon, and operates lignite coal mines in Montana and North
Dakota. The oil and natural gas production business is engaged in oil and
natural gas acquisition, exploration and production activities throughout
the United States, the Gulf of Mexico and Canada.
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:
Oil and
Natural Natural Construction Natural
Gas Gas Materials Gas Eliminations
Electric Distribution Transmission and Mining Production and Adjustments Total
(In thousands)
1998
Operating revenues:
External $211,453 $154,147 $133,279 $338,702 (a) $ 51,297 $ --- $ 888,878
Intersegment --- --- 47,420 7,749 --- (47,420) (b) 7,749
Depreciation, depletion
and amortization 19,798 7,150 8,463 20,562 21,813 --- 77,786
Interest expense 10,304 3,728 6,426 7,402 2,413 --- 30,273
Income taxes 10,204 2,681 13,977 15,155 (24,532) --- 17,485
Earnings on common stock 17,180 3,501 20,823 24,499 (32,673) --- 33,330
Other significant
noncash items:
Write-downs of oil and
natural gas properties
(Note 1) --- --- --- --- 66,000 --- 66,000
Identifiable assets (d) 344,304 129,654 260,942 500,720 171,207 45,948 (c) 1,452,775
Capital expenditures 31,378 8,256 23,710 172,108 94,465 (4,275) (e) 325,642
1997
Operating revenues:
External $164,351 $157,005 $ 43,784 $168,067 (a) $ 68,387 $ --- $ 601,594
Intersegment --- --- 49,622 6,080 --- (49,622) (b) 6,080
Depreciation, depletion
and amortization 17,771 7,013 5,550 10,999 24,434 --- 65,767
Interest expense 10,949 3,698 8,605 4,503 2,454 --- 30,209
Income taxes 7,642 2,987 8,429 4,392 7,293 --- 30,743
Earnings on common stock 13,388 4,514 11,317 10,111 14,505 --- 53,835
Identifiable assets (d) 326,615 128,517 227,030 235,221 162,785 33,724 (c) 1,113,892
Capital expenditures 27,970 8,858 13,205 41,472 30,651 (4,522) (e) 117,634
1996
Operating revenues:
External $138,761 $155,012 $ 20,396 $126,275 (a) $ 68,310 $ --- $ 508,754
Intersegment --- --- 58,224 5,947 --- (58,224) (b) 5,947
Depreciation, depletion
and amortization 17,053 6,880 6,748 6,974 24,996 --- 62,651
Interest expense 11,269 4,422 7,799 3,277 3,111 (1,046) (b) 28,832
Income taxes 5,859 3,507 (5,962) 5,985 6,698 --- 16,087
Earnings on common stock 11,436 4,892 2,459 11,521 14,375 --- 44,683
Other significant
noncash items:
Write-down of natural
gas available under
repurchase commitment
(Note 15) --- --- 18,553 --- --- --- 18,553
Identifiable assets (d) 313,815 120,645 276,843 171,283 161,647 44,940 (c) 1,089,173
Capital expenditures 18,674 6,255 10,890 25,063 51,821 (11,803) (e) 100,900
<FN>
(a) Includes sales, for use at the Coyote Station, an electric generating
station jointly owned by the company and other utilities, of (in thousands)
$6,714, $5,061 and $6,358 for 1998, 1997 and 1996, respectively.
(b) Intersegment eliminations.
(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).
(d) Includes, in the case of electric and natural gas distribution property,
allocations of common utility property. Natural gas stored or available
under repurchase commitment, as applicable, is included in natural gas
distribution and transmission identifiable assets.
(e) Net proceeds from sale or disposition of property.
</FN>
Capital expenditures for 1998 and 1997, related to acquisitions, in the
preceeding table include the following noncash transactions: issuance of
the company's equity securities, less treasury stock acquired, in 1998 of
$138.8 million; and assumed debt and the issuance of the company's equity
securities in total for 1997 of $9.9 million. In addition, natural gas
transmission capital expenditures for 1996 include $763,000 for
Prairielands Energy Marketing, Inc. which were not reflected in investing
activities in the Consolidated Statements of Cash Flows as Prairielands
was not considered a major business segment.
On March 5, 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, asphaltic concrete,
prestress 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 businesses in 1998, none of which
were 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.
In 1997, the company acquired several businesses, none of which were
individually material, including the remaining 50 percent interest in
Hawaiian Cement (See Note 12) and utility services construction and
construction supplies and equipment businesses in Oregon. The total
purchase consideration, consisting of the company's common stock and cash,
for these businesses was $35.2 million.
The above acquisitions were accounted for under the purchase method of
accounting. 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
In 1998, the company adopted SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits" (SFAS No. 132). SFAS No. 132
revises employers' disclosures about pension and other postretirement
benefit plans but does not change the measurement or recognition of
amounts related to these benefit plans. For comparative purposes, prior
year amounts have been restated.
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, 1998 and 1997.
Changes in benefit obligation and plan assets for the years ended December
31 are as follows:
Other
Pension Postretirement
Benefits Benefits
1998 1997 1998 1997
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $178,199 $150,829 $ 73,838 $ 65,608
Service cost 4,509 3,889 1,502 1,272
Interest cost 12,248 11,651 4,848 4,691
Plan participants' contributions --- --- 475 379
Amendments 437 --- (4,810) ---
Actuarial (gain) loss 5,971 12,263 (1,695) (888)
Acquisition --- 9,463 --- 6,394
Benefits paid (13,699) (9,896) (3,820) (3,618)
Benefit obligation at
end of year $187,665 $178,199 $ 70,338 $ 73,838
Change in plan assets:
Fair value of plan assets at
beginning of year $225,201 $185,872 $ 30,595 $ 21,712
Actual return on plan assets 39,604 38,272 6,226 5,621
Employer contribution 88 265 6,067 6,501
Plan participants' contributions --- --- 475 379
Acquisition --- 10,688 --- ---
Benefits paid (13,699) (9,896) (3,820) (3,618)
Fair value of plan assets at end
of year 251,194 225,201 39,543 30,595
Funded status 63,529 47,002 (30,795) (43,243)
Unrecognized actuarial gain (73,963) (56,844) (8,036) (2,679)
Unrecognized prior service cost 7,645 8,056 (1,433) ---
Unrecognized net transition
obligation (5,340) (6,333) 31,029 36,864
Accrued benefit cost $ (8,129) $ (8,119) $ (9,235) $(9,058)
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
1998 1997 1998 1997
Discount rate 6.75% 7.00% 6.75% 7.00%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
Health care rate assumptions for the company's other postretirement
benefit plans as of December 31 are as follows:
1998 1997
Health care trend rate 6.50%-8.50% 7.00%-9.00%
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, 1998 1997 1996 1998 1997 1996
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 4,509 $ 3,889 $ 3,852 $ 1,502 $ 1,272 $ 1,333
Interest cost 12,248 11,651 10,823 4,848 4,691 4,701
Expected return on assets (15,892) (14,321) (13,145) (2,395) (1,748) (1,279)
Amortization of prior
service cost 848 811 755 --- --- ---
Recognized net actuarial
(gain) loss (621) (666) (98) (169) (105) 48
Amortization of net
transition obligation (994) (988) (990) 2,458 2,458 2,458
Net periodic benefit cost 98 376 1,197 6,244 6,568 7,261
Less amount capitalized 79 70 131 628 625 735
Net periodic benefit
expense $ 19 $ 306 $ 1,066 $ 5,616 $ 5,943 $ 6,526
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 1 percentage point change
in the assumed health care cost trend rates would have the following
effects at December 31, 1998:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 243 $ (294)
Effect on postretirement benefit
obligation $3,671 $(4,546)
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
$2.7 million in 1998 and $2.2 million in both 1997 and 1996.
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. Under the stock option plans, the company is
authorized to grant options for up to 4.3 million shares of common stock
and has granted options on 1.9 million shares through December 31, 1998.
Had the company recorded compensation expense for the fair value of
options granted consistent with SFAS No. 123, "Accounting for Stock-Based
Compensation" (SFAS No. 123), net income would have been reduced on a pro
forma basis by $820,000 in 1998, $51,400 in 1997 and $48,000 in 1996. On
a pro forma basis, basic and diluted earnings per share for 1998 would
have been reduced by $.02 and there would have been no effect for 1997 and
1996. Since SFAS No. 123 does not require this accounting to be applied
to options granted prior to January 1, 1995, the resulting pro forma
compensation costs may not be representative of those to be expected in
future years.
A summary of the status of the stock option plans at December 31, 1998,
1997 and 1996, and changes during the years then ended are as follows:
1998 1997 1996
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 594,180 $12.07 635,965 $11.77 703,105 $11.65
Granted 1,225,920 21.12 22,500 16.37 --- ---
Forfeited (37,875) 21.05 (13,600) 11.41 --- ---
Exercised (265,417) 11.98 (50,685) 10.50 (67,140) 10.50
Balance at end
of year 1,516,808 19.17 594,180 12.07 635,965 11.77
Exercisable at
end of year 333,261 $12.94 112,461 $11.67 140,646 $10.50
Exercise prices on options outstanding at December 31, 1998, range from
$10.50 to $23.84 with a weighted average remaining contractual life of
approximately 8 years.
The weighted average fair value of each option granted in 1998 and 1997 is
$2.40 and $2.09, respectively. The fair value of each option is estimated
on the date of grant using the Black-Scholes option pricing model. The
assumptions used to estimate the fair value of options granted in 1998 and
1997 were a weighted average risk-free interest rate of 4.78 percent and
6.60 percent, respectively, a weighted average expected dividend yield of
5.13 percent and 5.48 percent, respectively, an expected life of 7 years
and a weighted average expected volatility 16.27 percent and 14.51
percent, respectively.
The company sponsors various defined contribution plans for eligible
employees. Costs incurred by the company under these plans were
$3.1 million in 1998, $2.1 million in 1997 and $1.9 million in 1996. The
costs incurred in each year reflect additional participants as a result of
business acquisitions.
NOTE 12
PARTNERSHIP INVESTMENT
In September 1995, KRC Holdings, Inc., through its wholly owned
subsidiary, Knife River Hawaii, Inc., acquired a 50 percent interest in
Hawaiian Cement, which was previously owned by Lone Star Industries, Inc.
Knife River Dakota, Inc., a wholly owned subsidiary of KRC Holdings, Inc.
acquired the remaining 50 percent interest in Hawaiian Cement from the
previous owner, Adelaide Brighton Cement (Hawaii), Inc. of Adelaide,
Australia, in July 1997.
In August 1997, the company began consolidating Hawaiian Cement into its
financial statements. Prior to August 1997, the company's net investment
in Hawaiian Cement was not consolidated and was accounted for by the
equity method. The company's share of operating results for the seven
months ended July 31, 1997, and the year ended December 31, 1996, is
included in "Other income -- net" in the accompanying Consolidated
Statements of Income for the years ended December 31, 1997 and 1996,
respectively. Summarized operating results for Hawaiian Cement for the
seven months ended July 31, 1997, and for the year ended December 31,
1996, when accounted for by the equity method, are as follows: net sales
of $33.5 million and $70.1 million; operating margin of $4.7 million and
$9.9 million; and income before income taxes of $2.0 million and $5.4
million, respectively.
NOTE 13
JOINTLY OWNED FACILITIES
The consolidated financial statements include the company's 22.7 percent
and 25.0 percent ownership interests in the assets, liabilities and
expenses of the Big Stone Station and the Coyote Station, respectively.
Each owner of the Big Stone and Coyote stations is responsible for
financing its investment in the jointly owned facilities.
The company's share of the Big Stone Station and Coyote Station operating
expenses is reflected in the appropriate categories of operating expenses
in the Consolidated Statements of Income.
At December 31, the company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
1998 1997
(In thousands)
Big Stone Station:
Utility plant in service $ 49,762 $ 49,467
Less accumulated depreciation 28,781 27,971
$ 20,981 $ 21,496
Coyote Station:
Utility plant in service $121,726 $121,604
Less accumulated depreciation 56,770 53,107
$ 64,956 $ 68,497
NOTE 14
REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND
General rate proceedings
Williston Basin had pending with the FERC a general natural gas rate
change application implemented in 1992. In October 1997, Williston Basin
appealed to the United States Court of Appeals for the D.C. Circuit (D.C.
Circuit Court) certain issues decided by the FERC in prior orders
concerning the 1992 proceeding. Williston Basin is awaiting a decision
from the D.C. Circuit Court.
In June 1995, Williston Basin filed a general rate increase application
with the 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 resulting in an increase of $8.9 million or
19.1 percent over the then current effective rates. Williston Basin began
collecting such increase effective January 1, 1996, subject to refund. On
July 29, 1998, the FERC issued an order which addressed various issues
including storage cost allocations, return on equity and throughput. On
August 28, 1998, Williston Basin requested rehearing of such order.
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.
Williston Basin believes that such reserves are adequate based on its
assessment of the ultimate outcome of the various proceedings.
NOTE 15
NATURAL GAS REPURCHASE COMMITMENT
The company has offered for sale since 1984 the inventoried natural gas
owned by Frontier, a special purpose, nonaffiliated corporation. Through
an agreement, Williston Basin is obligated to repurchase all of the
natural gas at Frontier's original cost and reimburse Frontier for all of
its financing and general administrative costs. Frontier has financed the
purchase of the natural gas under a term loan agreement with several
banks. At December 31, 1998 and 1997, borrowings totaled $14.8 million
and $32.0 million, respectively, at a weighted average interest rate of
6.19 percent and 6.63 percent, respectively. At December 31, 1998 and
1997, the natural gas repurchase commitment of $14.3 million and
$30.4 million, respectively, is reflected on the company's Consolidated
Balance Sheets under "Other liabilities" and $551,000 and $1.6 million,
respectively, is reflected under "Other accrued liabilities." The
financing costs associated with this repurchase commitment, consisting
principally of interest and related financing fees, approximated $5.7
million in 1996. The costs incurred in 1998 and 1997 were not material
and are included in "Other income -- net" on the Consolidated Statements
of Income. The term loan agreement will terminate on October 2, 1999,
subject to an option to renew this agreement upon the lenders' consent for
up to five years, unless terminated earlier by the occurrence of certain
events.
The FERC has issued orders that have held that storage costs should be
allocated to this gas, prospectively beginning May 1992, as opposed to
being included in rates applicable to Williston Basin's customers. These
storage costs, as initially allocated to the Frontier gas, approximated
$2.1 million annually, for which Williston Basin has provided reserves.
Williston Basin appealed these orders to the D.C. Circuit Court which in
December 1996 issued its order ruling that the FERC's actions in
allocating storage capacity costs to the Frontier gas were appropriate.
On August 28, 1998, Williston Basin requested rehearing of the July 29,
1998 FERC order which addressed various issues, including a requirement
that storage deliverability costs be allocated to the Frontier gas.
Williston Basin sells and transports natural gas held under the repurchase
commitment. In the third quarter of 1996, Williston Basin, based on a
number of factors including differences in regional natural gas prices and
natural gas sales occurring at that time, wrote down 43.0 MMdk of this gas
to its then current value. The value of this gas was determined using the
sum of discounted cash flows of expected future sales occurring at then
current regional natural gas prices as adjusted for anticipated future
price increases. This resulted in a write-down aggregating $18.6 million
($11.4 million after tax). In addition, Williston Basin wrote off certain
other costs related to this natural gas of approximately $2.5 million
($1.5 million after tax). The amounts related to this write-down are
included in "Costs on natural gas repurchase commitment" in the
Consolidated Statements of Income. At December 31, 1998 and 1997, natural
gas held under the repurchase commitment of $6.9 million and
$14.6 million, respectively, is included in the company's Consolidated
Balance Sheets under "Deferred charges and other assets." The amount of
this natural gas in storage as of December 31, 1998 was 7.0 MMdk.
NOTE 16
COMMITMENTS AND CONTINGENCIES
Pending litigation
In November 1993, the estate of W.A. Moncrief (Moncrief), a producer from
whom Williston Basin purchased a portion of its natural gas supply, filed
suit in Federal District Court for the District of Wyoming (Federal
District Court) against Williston Basin and the company disputing certain
price and volume issues under the contract.
Through the course of this action Moncrief submitted damage calculations
which totaled approximately $19 million or, under its alternative pricing
theory, approximately $39 million.
In June 1997, the Federal District Court issued its order awarding
Moncrief damages of approximately $15.6 million. In July 1997, the
Federal District Court issued an order limiting Moncrief's reimbursable
costs to post-judgment interest, instead of both pre- and post-judgment
interest as Moncrief had sought. In August 1997, Moncrief filed a notice
of appeal with the United States Court of Appeals for the Tenth Circuit
(U.S. Court of Appeals) related to the Federal District Court's orders.
In September 1997, Williston Basin and the company filed a notice of
cross-appeal. Oral argument before the U.S. Court of Appeals was held
September 23, 1998. Williston Basin and the company are awaiting a
decision from the U.S. Court of Appeals.
Williston Basin believes that it is entitled to recover from customers
virtually all of the costs which might ultimately be incurred as a result
of this litigation as gas supply realignment transition costs pursuant to
the provisions of the FERC's Order 636. However, the amount of costs that
can ultimately be recovered is subject to approval by the FERC and market
conditions.
In December 1993, Apache Corporation (Apache) and Snyder Oil Corporation
(Snyder) filed suit in North Dakota Northwest Judicial District Court
(North Dakota District Court) against Williston Basin and the company.
Apache and Snyder are oil and natural gas producers which had processing
agreements with Koch Hydrocarbon Company (Koch). Williston Basin and the
company had a natural gas purchase contract with Koch. Apache and Snyder
have alleged they are entitled to damages for the breach of Williston
Basin's and the company's contract with Koch. Williston Basin and the
company believe that if Apache and Snyder have any legal claims, such
claims are with Koch, not with Williston Basin or the company as Williston
Basin, the company and Koch have settled their disputes. Apache and
Snyder have submitted damage estimates under differing theories
aggregating up to $4.8 million without interest. A motion to intervene in
the case by several other producers, all of which had contracts with Koch
but not with Williston Basin, was denied in December 1996. The trial
before the North Dakota District Court was completed in November 1997. On
November 25, 1998, the North Dakota District Court entered an order
directing the entry of judgment in favor of Williston Basin and the
company. On December 15, 1998, Apache and Snyder filed a motion for
relief asking the North Dakota District Court to reconsider its November
25, 1998 order.
In a related matter, in March 1997, a suit was filed by nine other
producers, several of which had unsuccessfully tried to intervene in the
Apache and Snyder litigation, against Koch, Williston Basin and the
company. The parties to this suit are making claims similar to those in
the Apache and Snyder litigation, although no specific damages have been
stated.
In Williston Basin's opinion, the claims of Apache and Synder are without
merit and overstated and the claims of the nine other producers are
without merit. If any amounts are ultimately found to be due, Williston
Basin plans to file with the FERC for recovery from customers. However,
the amount of costs that can ultimately be recovered is subject to
approval by the FERC and market conditions.
In November 1995, a suit was filed in District Court, County of Burleigh,
State of North Dakota (State District Court) by Minnkota Power
Cooperative, Inc., Otter Tail Power Company, Northwestern Public Service
Company and Northern Municipal Power Agency (Co-owners), the owners of an
aggregate 75 percent interest in the Coyote electric generating station
(Coyote Station), against the company (an owner of a 25 percent interest
in the Coyote Station) and Knife River. In its complaint, the Co-owners
have alleged a breach of contract against Knife River with respect to the
long-term coal supply agreement (Agreement) between the owners of the
Coyote Station and Knife River. The Co-owners have requested a
determination by the State District Court of the pricing mechanism to be
applied to the Agreement and have further requested damages during the
term of such alleged breach on the difference between the prices charged
by Knife River and the prices that may ultimately be determined by the
State District Court. The Co-owners also alleged a breach of fiduciary
duties by the company as operating agent of the Coyote Station, asserting
essentially that the company was unable to cause Knife River to reduce its
coal price sufficiently under the Agreement, and the Co-owners are seeking
damages in an unspecified amount. In May 1996, the State District Court
stayed the suit filed by the Co-owners pending arbitration, as provided
for in the Agreement.
In September 1996, the Co-owners notified the company and Knife River of
their demand for arbitration of the pricing dispute that had arisen under
the Agreement. The demand for arbitration, filed with the American
Arbitration Association (AAA), did not make any direct claim against the
company in its capacity as operator of the Coyote Station. The Co-owners
requested that the arbitrators make a determination that the pricing
dispute is not a proper subject for arbitration. By an April 1997 order,
the arbitration panel concluded that the claims raised by the Co-owners
are arbitrable. The Co-owners have requested the arbitrators to make a
determination that the prices charged by Knife River were excessive and
that the Co-owners should be awarded damages, based upon the difference
between the prices that Knife River charged and a "fair and equitable"
price. Upon application by the company and Knife River, the AAA
administratively determined that the company was not a proper party
defendant to the arbitration, and the arbitration is proceeding against
Knife River. On October 9, 1998, a hearing before the arbitration panel
was completed. At the hearing the Co-owners requested damages of
approximately $24 million, including interest, plus a reduction in the
future price of coal under the Agreement. The company is currently
awaiting a decision from the arbitration panel. Although unable to
predict the outcome of the arbitration, Knife River and the company
believe that the Co-owners' claims are without merit and intend to
vigorously defend the prices charged pursuant to the Agreement.
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
Montana-Dakota and Williston Basin discovered polychlorinated biphenyls
(PCBs) in portions of their natural gas systems and informed the United
States Environmental Protection Agency (EPA) in January 1991. Montana-
Dakota and Williston Basin believe the PCBs entered the system from a
valve sealant. In January 1994, Montana-Dakota, Williston Basin and
Rockwell International Corporation (Rockwell), manufacturer of the valve
sealant, reached an agreement under which Rockwell has reimbursed and will
continue to reimburse Montana-Dakota and Williston Basin for a portion of
certain remediation costs. On the basis of findings to date, Montana-
Dakota and Williston Basin estimate future environmental assessment and
remediation costs will aggregate $3 million to $15 million. Based on such
estimated cost, the expected recovery from Rockwell and the ability of
Montana-Dakota and Williston Basin to recover their portions of such costs
from ratepayers, Montana-Dakota and Williston Basin believe that the
ultimate costs related to these matters will not be material to each of
their respective financial positions or results of operations.
Electric purchased power commitments
Through October 31, 2006, Montana-Dakota has contracted to purchase 66,400
kW of participation power 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 from Black Hills Power
and Light Company.
NOTE 17
QUARTERLY DATA (UNAUDITED)
The following unaudited information shows selected items by quarter for
the years 1998 and 1997:
First Second Third Fourth
Quarter Quarter* Quarter Quarter*
(In thousands, except per share amounts)
1998
Operating revenues $170,122 $179,715 $269,978 $276,812
Operating expenses 137,913 186,310 227,283 274,178
Operating income (loss) 32,209 (6,595) 42,695 2,634
Net income (loss) 17,793 (5,785) 22,538 (439)
Earnings (loss) per common share:
Basic .39 (.12) .42 (.01)
Diluted .39 (.12) .42 (.01)
Weighted average common shares
outstanding:
Basic 45,375 50,936 52,703 53,021
Diluted 45,629 50,936 53,062 53,021
1997
Operating revenues $139,811 $125,380 $163,699 $178,784
Operating expenses 109,055 106,932 134,675 145,451
Operating income 30,756 18,448 29,024 33,333
Net income 14,597 8,741 14,195 17,084
Earnings per common share:
Basic .34 .20 .32 .39
Diluted .33 .20 .32 .39
Weighted average common shares
outstanding:
Basic 42,894 43,104 43,577 43,676
Diluted 43,019 43,247 43,733 43,901
* Reflects $20.0 million and $19.9 million in noncash after-tax write-
downs of oil and natural gas properties for the second quarter and
fourth quarter of 1998, respectively.
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 18
OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)
Fidelity Oil Group is involved in the acquisition, exploration,
development and production of oil and natural gas properties. Fidelity's
operations vary from the acquisition of producing properties with
potential development opportunities to exploration and are located
throughout the United States, the Gulf of Mexico and Canada. Fidelity
shares revenues and expenses from the development of specified properties
in proportion to its interests.
Williston Basin Interstate Pipeline Company owns in fee or holds natural
gas leases and operating rights primarily applicable to the shallow rights
(above 2,000 feet) in the Cedar Creek Anticline in southeastern Montana
and to all rights in the Bowdoin area located in north-central Montana.
The following information includes the company's proportionate share of
all its oil and natural gas interests held by both Fidelity and Williston
Basin.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to oil and natural gas
producing activities at December 31:
1998 1997 1996
(In thousands)
Subject to amortization $266,301 $252,291 $223,409
Not subject to amortization 22,153 9,408 6,792
Total capitalized costs 288,454 261,699 230,201
Accumulated depreciation, depletion
and amortization 111,472 95,611 71,554
Net capitalized costs $176,982 $166,088 $158,647
NOTE: Net capitalized costs as of December 31, 1998 reflect noncash
write-downs of the company's oil and natural gas properties as
discussed in Note 1.
Capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities are as follows:
Years ended December 31, 1998 1997 1996
(In thousands)
Acquisitions $ 63,419 $ 59 $23,284
Exploration 15,976 13,344 8,101
Development 21,545 18,874 19,979
Total capital expenditures $100,940 $32,277 $51,364
The following summary reflects income resulting from the company's
operations of oil and natural gas producing activities, excluding
corporate overhead and financing costs:
Years ended December 31, 1998 1997 1996
(In thousands)
Revenues* $ 61,831 $77,756 $75,335
Production costs 19,419 23,251 21,296
Depreciation, depletion and
amortization 23,050 24,864 25,629
Write-downs of oil and natural gas
properties (Note 1) 66,000 --- ---
Pretax income (46,638) 29,641 28,410
Income tax expense (benefit) (19,268) 10,968 10,875
Results of operations for
producing activities $(27,370) $18,673 $17,535
* Includes $10.5 million, $9.4 million and $7.0 million of revenues
for 1998, 1997 and 1996, respectively, related to Williston Basin's
natural gas production activities which are included in "Natural
gas" operating revenues in the Consolidated Statements of Income.
The following table summarizes the company's estimated quantities of
proved oil and natural gas reserves at December 31, 1998, 1997 and
1996, and reconciles the changes between these dates. Estimates of
economically recoverable oil and natural gas 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.
1998 1997 1996
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 14,900 184,900 16,100 200,200 14,200 179,000
Production (1,900) (20,700) (2,100) (20,400) (2,100) (20,400)
Extensions and
discoveries 200 21,300 600 12,100 600 27,000
Purchases of proved
reserves 2,000 56,600 --- 200 2,900 9,900
Sales of reserves
in place --- (100) (200) (2,300) (700) (3,700)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions (3,700) 1,600 500 (4,900) 1,200 8,400
Balance at end
of year 11,500 243,600 14,900 184,900 16,100 200,200
Proved developed reserves:
January 1, 1996 13,600 156,400
December 31, 1996 15,400 168,200
December 31, 1997 14,500 163,800
December 31, 1998 10,700 193,000
Virtually all of the company's interests in oil and natural gas
reserves are located in the continental United States. Reserve
interests at December 31, 1998, applicable to the company's $411,000
net investment in oil and natural gas properties located in Canada
comprise approximately 2 percent of the total reserves.
The standardized measure of the company's estimated discounted future
net cash flows of total proved reserves associated with its various oil
and natural gas interests at December 31 is as follows:
1998 1997 1996
(In thousands)
Future net cash flows before
income taxes $246,700 $306,600 $580,300
Future income tax expenses 40,500 86,600 194,200
Future net cash flows 206,200 220,000 386,100
10% annual discount for estimated
timing of cash flows 81,100 81,000 152,100
Discounted future net cash flows
relating to proved oil and natural
gas reserves $125,100 $139,000 $234,000
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1998 1997 1996
(In thousands)
Beginning of year $139,000 $ 234,000 $120,900
Net revenues from production (42,400) (54,500) (54,000)
Change in net realization (70,500) (158,400) 125,800
Extensions, discoveries and improved
recovery, net of future
production-related costs 18,200 19,400 43,500
Purchases of proved reserves 51,000 200 49,600
Sales of reserves in place (100) (2,800) (6,700)
Changes in estimated future
development costs, net of those
incurred during the year (16,600) 7,700 (2,400)
Accretion of discount 18,600 32,800 16,900
Net change in income taxes 30,100 62,100 (69,200)
Revisions of previous quantity
estimates (1,600) (1,300) 8,700
Other (600) (200) 900
Net change (13,900) (95,000) 113,100
End of year $125,100 $ 139,000 $234,000
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end oil and
natural gas 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.
1998* 1997 1996 1995 1994 1993 1988
Selected Financial Data
Operating revenues: (000's)
Electric $ 211,453 $ 164,351 $ 138,761 $ 134,609 $ 133,953 $ 131,109 $126,128
Natural gas 287,426 200,789 175,408 167,787 160,970 178,981 168,125
Construction materials and mining 346,451 174,147 132,222 113,066 116,646 90,397 42,388
Oil and natural gas production 51,297 68,387 68,310 48,784 37,959 39,125 20,918
$ 896,627 $ 607,674 $ 514,701 $ 464,246 $ 449,528 $ 439,612 $357,559
Operating income: (000's)
Electric $ 38,099 $ 33,089 $ 29,476 $ 29,898 $ 27,596 $ 30,520 $ 33,505
Natural gas distribution 8,028 10,410 11,504 6,917 3,948 4,730 5,368
Natural gas transmission 38,114 29,169 30,231 25,427 21,281 20,108 21,189
Construction materials and mining 41,609 14,602 16,062 14,463 16,593 16,984 9,841
Oil and natural gas production (54,907) 24,291 24,252 13,871 8,757 11,750 7,352
$ 70,943 $ 111,561 $ 111,525 $ 90,576 $ 78,175 $ 84,092 $ 77,255
Earnings on common stock: (000's)
Electric $ 17,180 $ 13,388 $ 11,436 $ 12,000 $ 11,719 $ 12,652** $ 13,444
Natural gas distribution 3,501 4,514 4,892 1,604 285 1,182** 1,474
Natural gas transmission 20,823 11,317 2,459 8,416 6,155 4,713 2,320
Construction materials and mining 24,499 10,111 11,521 10,819 11,622 12,359 11,493
Oil and natural gas production (32,673) 14,505 14,375 8,002 9,267 7,109 5,115
Earnings on common stock
before cumulative effect of
accounting change 33,330 53,835 44,683 40,841 39,048 38,015** 33,846
Cumulative effect of
accounting change --- --- --- --- --- 5,521 ---
$ 33,330 $ 53,835 $ 44,683 $ 40,841 $ 39,048 $ 43,536 $ 33,846
Earnings per common share before
cumulative effect of accounting
change -- diluted $ .66 $ 1.24 $ 1.04 $ .95 $ .91 $ .89** $ .80
Cumulative effect of accounting change --- --- --- --- --- .13 ---
$ .66 $ 1.24 $ 1.04 $ .95 $ .91 $ 1.02 $ .80
Pro forma amounts assuming retroactive
application of accounting change:
Net income (000's) $ 34,107 $ 54,617 $ 45,470 $ 41,633 $ 39,845 $ 38,817 $ 34,957
Earnings per common
share -- diluted $ .66 $ 1.24 $ 1.04 $ .95 $ .91 $ .89 $ .80
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 50,837 43,478 42,824 42,789 42,763 42,801 42,116
Dividends per common share $ .7834 $ .7534 $ .7333 $ .7188 $ .7022 $ .6755 $ .6311
Book value per common share $ 10.39 $ 8.84 $ 8.21 $ 7.90 $ 7.66 $ 7.45 $ 6.55
Market price per common
share (year-end) $ 26.31 $ 21.08 $ 15.33 $ 13.25 $ 12.06 $ 14.00 $ 8.45
Market price ratios:
Dividend payout 119% 61% 70% 76% 77% 76%** 78%
Yield 3.0% 3.6% 4.8% 5.5% 5.9% 5.0% 7.5%
Price/earnings ratio 39.9x 17.0x 14.6x 13.9x 13.2x 15.8x** 10.5x
Market value as a
percent of book value 253.2% 238.5% 186.8% 167.7% 157.4% 188.0% 128.8%
Profitability Indicators
Return on average common equity 6.5% 14.6% 13.0% 12.3% 12.1% 12.3%** 12.4%
Return on average invested capital 5.5% 10.3% 9.5% 9.2% 9.1% 9.4%** 9.0%
Interest coverage 6.1x 6.0x 5.4x 3.9x 3.3x 3.4x** 2.7x
Fixed charges coverage, including
preferred dividends 2.5x 3.4x 2.7x 3.0x 2.8x 2.9x** 2.2x
General
Total assets (000's) $ 1,452,775 $ 1,113,892 $ 1,089,173 $ 1,056,479 $ 1,004,718 $ 1,041,051 $949,509
Net long-term debt (000's) $ 413,264 $ 298,561 $ 280,666 $ 237,352 $ 217,693 $ 231,770 $242,593
Redeemable preferred stock (000's) $ 1,700 $ 1,800 $ 1,900 $ 2,000 $ 2,100 $ 2,200 $ 3,100
Capitalization ratios:
Common stockholders' equity 56% 55% 54% 57% 58% 56% 52%
Preferred stocks 2 2 3 3 3 3 3
Long-term debt 42 43 43 40 39 41 45
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 oil and natural gas properties.
**Before cumulative effect of an accounting change reflecting the accrual of estimated unbilled revenues.
NOTE: Common stock share amounts reflect the company's three-for-two common stock splits effected in October 1995 and July 1998.
</FN>
1998 1997 1996 1995 1994 1993 1988
Electric Operations
Sales to ultimate consumers (thousand kWh) 2,053,862 2,041,191 2,067,926 1,993,693 1,955,136 1,893,713 1,843,982
Sales for resale (thousand kWh) 586,540 361,954 374,535 408,011 444,492 510,987 246,425
Electric system generating and firm purchase
capability -- kW (Interconnected system) 489,100 487,500 481,800 472,400 470,900 465,200 451,600
Demand peak -- kW (Interconnected system) 402,500 404,600 393,300 412,700 369,800 350,300 386,700
Electricity produced (thousand kWh) 2,103,199 1,826,770 1,829,669 1,718,077 1,901,119 1,870,740 1,691,778
Electricity purchased (thousand kWh) 730,949 769,679 809,261 867,524 700,912 701,736 598,443
Average cost of fuel and purchased
power per kWh $.017 $.018 $.017 $.016 $.017 $.016 $.017
Natural Gas Distribution Operations
Sales (Mdk) 32,024 34,320 38,283 33,939 31,840 31,147 32,557
Transportation (Mdk) 10,324 10,067 9,423 11,091 9,278 12,704 3,314
Weighted average degree days -- % of
previous year's actual 94% 85% 114% 105% 92% 115% 113%
Natural Gas Transmission Operations
Natural gas transmission:
Sales for resale (Mdk) --- --- --- --- --- 13,201 33,515
Transportation (Mdk) 88,974 85,464 82,169 68,015 63,870 59,416 33,892
Produced (Mdk) 7,412 6,949 6,073 4,981 4,732 3,876 1,744
Net recoverable reserves (MMcf) 140,200 127,300 133,400 113,000 99,300 --- ---
Energy marketing:
Natural gas volumes (Mdk) 58,495 14,971 4,670 3,556 7,301 6,827 ---
Propane (thousand gallons) 7,037 10,005 9,689 7,471 6,462 2,210 ---
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 11,054 5,113 3,374 2,904 2,688 2,391 ---
Asphalt (tons sold) 1,790 758 694 373 391 141 ---
Ready-mixed concrete (cubic yards sold) 1,021 516 340 307 315 157 ---
Recoverable aggregate reserves (tons) 654,670 169,375 119,800 68,000 71,000 74,200 ---
Coal: (000's)
Sales (tons) 3,113 2,375 2,899 4,218 5,206 5,066 4,759
Recoverable reserves (tons) 190,152 226,560 228,900 231,900 236,100 230,600 270,800
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,912 2,088 2,149 1,973 1,565 1,497 1,358
Natural gas (MMcf) 13,025 13,192 14,067 12,319 9,228 8,817 1,464
Average sales prices:
Oil (per barrel) $ 12.71 $ 17.50 $ 17.91 $ 15.07 $ 13.14 $ 14.84 $ 13.43
Natural gas (per Mcf) $ 2.07 $ 2.41 $ 2.09 $ 1.51 $ 1.84 $ 1.86 $ 2.14
Net recoverable reserves:
Oil (000's of barrels) 11,500 14,900 16,100 14,200 12,500 11,200 11,500
Natural gas (MMcf) 103,400 57,600 66,800 66,000 54,900 50,300 9,400