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 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 Executive Vice President,
Executive Officer Treasurer and Chief
Financial Officer
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 1999 1998 1997
(In thousands, except per share amounts)
Operating revenues $1,279,809 $896,627 $607,674
Operating expenses:
Fuel and purchased power 51,802 49,829 45,604
Purchased natural gas sold 349,215 158,908 77,082
Operation and maintenance 608,104 448,290 283,894
Depreciation, depletion and
amortization 81,818 77,786 65,767
Taxes, other than income 29,119 24,871 23,766
Write-downs of oil and natural gas
properties (Note 1) --- 66,000 ---
1,120,058 825,684 496,113
Operating income 159,751 70,943 111,561
Other income -- net 9,645 10,922 4,008
Interest expense 36,006 30,273 30,209
Income before income taxes 133,390 51,592 85,360
Income taxes 49,310 17,485 30,743
Net income 84,080 34,107 54,617
Dividends on preferred stocks 772 777 782
Earnings on common stock $ 83,308 $ 33,330 $ 53,835
Earnings per common share--basic $ 1.53 $ .66 $ 1.24
Earnings per common share--diluted $ 1.52 $ .66 $ 1.24
Dividends per common share $ .82 $ .7834 $ .7534
Weighted average common shares
outstanding -- basic 54,615 50,536 43,315
Weighted average common shares
outstanding -- diluted 54,870 50,837 43,478
The accompanying notes are an integral part of these consolidated
statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1999 1998
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 77,504 $ 39,216
Receivables 169,560 124,114
Inventories 64,608 44,865
Deferred income taxes 15,600 16,918
Prepayments and other current assets 24,424 15,536
351,696 240,649
Investments 43,128 43,029
Property, plant and equipment 2,042,281 1,810,800
Less accumulated depreciation,
depletion and amortization 794,105 726,123
1,248,176 1,084,677
Deferred charges and other assets 123,303 84,420
$1,766,303 $1,452,775
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 14,693 $ 15,000
Long-term debt and preferred
stock due within one year 4,428 3,292
Accounts payable 81,262 60,023
Taxes payable 6,842 9,226
Dividends payable 12,171 10,799
Other accrued liabilities,
including reserved revenues 67,931 71,129
187,327 169,469
Long-term debt (Note 5) 563,545 413,264
Deferred credits and other liabilities:
Deferred income taxes 213,771 173,094
Other liabilities 115,627 129,506
329,398 302,600
Preferred stock subject to mandatory
redemption (Note 6) 1,500 1,600
Commitments and contingencies (Notes 11, 14 and 15)
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 in 1999,
75,000,000 shares,
$3.33 par value in 1998
Issued -- 57,277,915 shares in 1999 and
53,272,951 shares in 1998 57,278 177,399
Other paid-in capital 372,312 171,486
Retained earnings 243,569 205,583
Treasury stock at cost - 239,521 shares (3,626) (3,626)
Total common stockholders' equity 669,533 550,842
Total stockholders' equity 684,533 565,842
$1,766,303 $1,452,775
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, 1999, 1998 and 1997
Other
Common Stock Paid-in Retained Treasury Stock
Shares Amount Capital Earnings Shares Amount Total
(In thousands, except shares)
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 7) 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
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:
Acquisitions 3,882,390 3,882 73,639 --- --- --- 77,521
Other 122,574 123 3,061 --- --- --- 3,184
Balance at
December 31, 1999 57,277,915 $ 57,278 $ 372,312 $243,569 (239,521) $(3,626) $669,533
<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, 1999 1998 1997
(In thousands)
Operating activities:
Net income $ 84,080 $ 34,107 $ 54,617
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 81,818 77,786 65,767
Deferred income taxes and
investment tax credit 15,704 (17,256) 12,894
Recovery of deferred natural gas
contract litigation settlement
costs --- --- 5,486
Write-downs of oil and natural gas
properties (Note 1) --- 66,000 ---
Changes in current assets and
liabilities:
Receivables (12,310) (10,464) 6,951
Inventories (13,460) 1,718 (4,214)
Other current assets (4,190) (547) 2,026
Accounts payable 12,492 14,094 (5,605)
Other current liabilities (8,972) (19,805) (6,087)
Other noncurrent changes (289) (7,187) 6,794
Net cash provided by operating
activities 154,873 138,446 138,629
Financing activities:
Net change in short-term borrowings (6,585) 3,933 (5,919)
Issuance of long-term debt 154,546 209,890 54,064
Repayment of long-term debt (18,714) (113,600) (47,899)
Retirement of preferred stocks (100) (100) (100)
Issuance of common stock 3,184 32,922 10,067
Retirement of natural gas
repurchase commitment (14,296) (17,105) (52,090)
Dividends paid (46,094) (41,247) (33,435)
Net cash provided by (used in)
financing activities 71,941 74,693 (75,312)
Investing activities:
Capital expenditures including
acquisitions of businesses (170,510) (191,154) (112,224)
Net proceeds from sale or
disposition of property 16,660 4,275 4,522
Net capital expenditures (153,850) (186,879) (107,702)
Sale of natural gas available
under repurchase commitment 1,330 7,727 27,008
Investments (99) (22,945) (2,248)
Additions to notes receivable (35,907) --- ---
Net cash used in investing
activities (188,526) (202,097) (82,942)
Increase (decrease) in cash
and cash equivalents 38,288 11,042 (19,625)
Cash and cash equivalents --
beginning of year 39,216 28,174 47,799
Cash and cash equivalents --
end of year $ 77,504 $ 39,216 $ 28,174
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, oil and natural gas 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, oil and natural gas 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 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 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.
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 amount of AFUDC and interest
capitalized was $1.7 million, $1.4 million and $970,000 in 1999, 1998
and 1997, respectively. 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.
In accordance with the provisions of Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of," the company reviews the
carrying values of its long-lived assets whenever events or changes in
circumstances indicate that such carrying values may not be
recoverable. As yet, no asset or group of assets has been identified
for which the sum of expected future cash flows (undiscounted and
without interest charges) is less than the carrying amount of the
asset(s) and, accordingly, no impairment losses have been recorded.
However, currently unforeseen events and changes in circumstances could
require the recognition of impairment losses at some future date.
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
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
$26.1 million and $11.5 million at December 31, 1999 and 1998,
respectively. The remainder of natural gas in underground storage is
included in property, plant and equipment and was $46.8 million and
$43.7 million at December 31, 1999 and 1998, respectively.
Inventories
Inventories, other than natural gas in underground storage for the
company's regulated operations, 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 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. Common stock
outstanding includes issued shares less shares held in treasury.
Earnings per common share reflect the three-for-two common stock split
effected in July 1998 as discussed in Note 7.
Comprehensive income
For the years ended December 31, 1999, 1998 and 1997, 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 property 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, 1999 1998 1997
(In thousands)
Interest, net of amount capitalized $30,772 $26,394 $25,626
Income taxes $32,723 $34,498 $18,171
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 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). 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.
In June 1999, the FASB issued Statement of Financial Accounting
Standards No. 137, "Accounting for Derivative Instruments and Hedging
Activities -- Deferral of the Effective Date of FASB Statement No.
133," which delayed the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. The company will adopt SFAS No. 133 on
January 1, 2001. The company continues to evaluate the effect of
adopting SFAS No. 133 but has not yet determined what impact this
adoption will have on the company's financial position or results of
operations.
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. SAB No. 101 is effective for the first
fiscal quarter of the fiscal year beginning after December 15, 1999.
SAB No. 101 is not expected to 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:
1999 1998
(In thousands)
Regulatory assets:
Long-term debt refinancing costs $ 9,514 $ 10,995
Deferred income taxes 7,274 13,364
Natural gas contract settlement and
restructuring costs 3,000 ---
Postretirement benefit costs 1,742 2,036
Plant costs 2,835 3,004
Other 6,789 6,063
Total regulatory assets 31,154 35,462
Regulatory liabilities:
Reserves for regulatory matters 24,231 39,981
Taxes refundable to customers 11,504 14,130
Plant decommissioning costs 6,989 6,413
Deferred income taxes 6,785 7,047
Natural gas costs refundable
through rate adjustments 2,579 274
Other 710 157
Total regulatory liabilities 52,798 68,002
Net regulatory position $(21,644) $ (32,540)
As of December 31, 1999, 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 17 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
FINANCIAL INSTRUMENTS
Derivatives
From time to time, the company utilizes derivative financial
instruments, including price swap and collar agreements and natural gas
futures, to manage a portion of the market risk associated with
fluctuations in the price of oil and natural gas. 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 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 an oil price quoted on the
New York Mercantile Exchange (NYMEX) or a quoted natural gas price on
the NYMEX, Colorado Interstate Gas Index or Williams 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.
Gains or losses on futures contracts are deferred until the underlying
commodity transaction occurs, at which point they are reported in
"Purchased natural gas sold" on the Consolidated Statements of Income.
The following table summarizes hedge agreements entered into by
Fidelity Oil Co. and WBI Production, Inc., indirect wholly owned
subsidiaries of the company, as of December 31, 1999. These agreements
call for Fidelity Oil Co. and WBI Production, Inc. to receive fixed
prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount Fair
(Per barrel) (In barrels) Value
Oil swap agreements
maturing in 2000 $19.55 769 $(1,870)
Weighted
Average Notional
Fixed Price Amount Fair
(Per MMBtu) (In MMBtu's) Value
Natural gas swap
agreements maturing
in 2000 $2.33 5,307 $ 597
Weighted
Average
Floor/Ceiling Notional
Price Amount Fair
(Per barrel) (In barrels) Value
Oil collar agreement
maturing in 2000 $20.00/$22.33 183 $ (134)
Weighted
Average
Floor/Ceiling Notional
Price Amount Fair
(Per MMBtu) (In MMBtu's) Value
Natural gas collar
agreements maturing
in 2000 $2.34/$2.68 3,196 $ 112
At December 31, 1998, Fidelity Oil Co. had natural gas collar
agreements outstanding for 2.9 million MMBtu's of natural gas with a
weighted average floor price and ceiling price of $2.10 and $2.51,
respectively. The company's net favorable position on the natural gas
collar agreements outstanding at December 31, 1998, was $597,000.
These agreements call for Fidelity Oil Co. to receive fixed prices and
pay variable prices.
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.
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.
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:
1999 1998
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $567,873 $555,730 $416,456 $435,078
Preferred stock
subject to mandatory
redemption $ 1,600 $ 1,418 $ 1,700 $ 1,592
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 $81.9 million at December 31,
1999. 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 $14.7 million at
December 31, 1999, and $15 million at December 31, 1998. The weighted
average interest rate for borrowings outstanding at December 31, 1999
and 1998, was 6.97 percent and 5.45 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:
1999 1998
(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
Pollution control note obligation,
6.20%, due March 1, 2004 3,100 3,400
Senior notes at a weighted
average rate of 7.19%, due on
dates ranging from December 31, 2000
to October 30, 2018 151,400 141,000
Commercial paper at a weighted average
rate of 6.80%, supported by a revolving
credit agreement due on September 1, 2002 223,169 82,921
Revolving lines of credit at a
weighted average rate of 8.37%,
due on dates ranging from
November 1, 2001 through December 31, 2002 45,900 45,200
Term credit agreements at a weighted
average rate of 7.52%, due on dates
ranging from January 1, 2000
through November 25, 2012 13,970 13,211
Other (516) (126)
Total long-term debt 567,873 416,456
Less current maturities 4,328 3,192
Net long-term debt $ 563,545 $413,264
Centennial Energy Holdings, Inc., a direct wholly owned subsidiary of
the company, has a revolving credit agreement with various banks on
behalf of its subsidiaries that allows for borrowings of up to $240
million. This facility supports the Centennial commercial paper
program. Under the Centennial commercial paper program, $223.2 million
and $82.9 million were outstanding at December 31, 1999 and 1998,
respectively. 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 due September 1, 2002. The company
intends to renew this existing credit agreement on an annual basis.
Effective December 27, 1999, Centennial entered into an uncommitted
long-term master shelf agreement with The Prudential Insurance Company
of America on behalf of its subsidiaries that allows for borrowings of
up to $200 million, none of which was outstanding at December 31, 1999.
Under the revolving lines of credit, the company and certain
subsidiaries have $58.2 million available as of December 31, 1999.
Amounts outstanding under the revolving lines of credit were
$45.9 million and $45.2 million at December 31, 1999 and 1998,
respectively.
The amounts of scheduled long-term debt maturities for the five years
following December 31, 1999 aggregate $4.3 million in 2000;
$24.6 million in 2001; $272.3 million in 2002; $6.6 million in 2003 and
$21.6 million in 2004.
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 $287 million
of additional first mortgage bonds at December 31, 1999. 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, 1999.
NOTE 6
PREFERRED STOCKS
Preferred stocks at December 31 are as follows:
1999 1998
(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 -- 16,000 shares in 1999
and 17,000 shares in 1998 $ 1,600 $ 1,700
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 16,600 16,700
Less sinking fund requirements 100 100
Net preferred stocks $16,500 $16,600
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, 1999, is $100,000.
NOTE 7
COMMON STOCK
At the Annual Meeting of Stockholders held on April 27, 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 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 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 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 DRIP 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 DRIP 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 DRIP. At
December 31, 1999, there were 8.1 million shares of common stock
reserved for original issuance under the DRIP 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. 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, 1999.
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 $498,000 in 1999, $820,000 in 1998 and $51,400
in 1997. On a pro forma basis, basic and diluted earnings per share
for 1999 and 1998 would have been reduced by $.01 and $.02,
respectively, and there would have been no effect for 1997. 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, 1999,
1998 and 1997, and changes during the years then ended are as follows:
1999 1998 1997
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning of year 1,516,808 $19.17 594,180 $12.07 635,965 $11.77
Granted 22,500 23.31 1,225,920 21.12 22,500 16.37
Forfeited (57,966) 20.38 (37,875) 21.05 (13,600) 11.41
Exercised (54,080) 11.95 (265,417) 11.98 (50,685) 10.50
Balance at end
of year 1,427,262 19.46 1,516,808 19.17 594,180 12.07
Exercisable at
end of year 301,681 $13.89 333,261 $12.94 112,461 $11.67
Exercise prices on options outstanding at December 31, 1999, range from
$10.50 to $23.84 with a weighted average remaining contractual life of
approximately 8 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:
1999 1998 1997
Fair value of options at grant date $ 4.82 $ 2.40 $ 2.09
Weighted average risk-free
interest rate 5.98% 4.78% 6.60%
Weighted average expected
price volatility 22.03% 16.27% 14.51%
Weighted average expected
dividend yield 4.22% 5.13% 5.48%
Expected life in years 7 7 7
NOTE 8
INCOME TAXES
Income tax expense is summarized as follows:
Years ended December 31, 1999 1998 1997
(In thousands)
Current:
Federal $29,574 $ 28,256 $15,427
State 3,874 5,880 2,362
Foreign 158 605 60
33,606 34,741 17,849
Deferred:
Investment tax credit (888) (975) (1,150)
Income taxes --
Federal 12,902 (14,214) 11,844
State 3,690 (2,067) 2,200
15,704 (17,256) 12,894
Total income tax expense $49,310 $ 17,485 $30,743
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1999 1998
(In thousands)
Deferred tax assets:
Regulatory matters $ 14,562 $ 22,319
Accrued pension costs 10,898 9,274
Deferred investment tax credits 2,028 2,336
Accrued land reclamation 2,803 2,907
Other 16,892 17,572
Total deferred tax assets 47,183 54,408
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 218,355 188,375
Basis differences on oil and
natural gas producing properties 17,163 9,604
Regulatory matters 6,785 7,047
Other 3,051 5,558
Total deferred tax liabilities 245,354 210,584
Net deferred income tax liability $(198,171)$(156,176)
The following table reconciles the change in the net deferred income
tax liability from December 31, 1998, to December 31, 1999, to the
deferred income tax expense included in the Consolidated Statements of
Income:
1999
(In thousands)
Net change in deferred income tax
liability from the preceding table $ 41,995
Change in tax effects of income tax-related
regulatory assets and liabilities (4,293)
Deferred taxes associated with acquisitions (21,110)
Deferred income tax expense for the period $ 16,592
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, 1999 1998 1997
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $46,686 35.0 $18,057 35.0 $29,876 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,300) (1.0) (1,571) (3.0) (828) (1.0)
State income taxes --
net of federal
income tax benefit 5,921 4.4 2,312 4.5 3,473 4.1
Investment tax credit
amortization (888) (.6) (975) (1.9) (1,150) (1.4)
Other items (1,109) (.8) (338) (.7) (628) (.7)
Total income tax expense $49,310 37.0 $17,485 33.9 $30,743 36.0
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. Prior to the fourth quarter of 1999, the company reported
five operating segments consisting of electric, natural gas
distribution, natural gas transmission, construction materials and
mining, and oil and natural gas production. During the fourth quarter
of 1999, the company revised the components of the segments reported
based on organizational changes and the significance of current
segments. As a result, a utility services segment was separated from
the electric segment; gas production activities previously included in
the natural gas transmission segment are now reflected in the oil and
natural gas production segment; and the remaining operations of the
natural gas transmission business were renamed pipeline and energy
services.
The company's operations are now conducted through six business
segments and all prior period information has been restated to reflect
this change. As of December 31, 1999, 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, and these operations also supply
related value-added products and services in the Northern Great Plains.
The utility services business is a full-service engineering, design and
build company operating in the western United States specializing in
construction and maintenance of power and natural gas distribution and
transmission systems as well as communication and fiber optic
facilities. The pipeline and energy services business provides natural
gas transportation, underground storage and gathering services through
regulated and nonregulated pipeline systems and provides energy
marketing and management services throughout the United States. The
oil and natural gas production business is engaged in oil and natural
gas acquisition, exploration and production throughout 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. It also operates lignite coal
mines in Montana and North Dakota.
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:
1999 1998 1997
(In thousands)
Operating revenues - external:
Electric $ 154,869 $ 147,221 $ 141,590
Natural gas distribution 157,692 154,147 157,005
Utility services 99,917 64,232 22,761
Pipeline and energy services 334,188 132,826 36,999
Oil and natural gas production 63,238 51,750 75,172
Construction materials and mining 455,939 331,988 163,006
Total operating revenues - external $1,265,843 $ 882,164 $ 596,533
Operating revenues - intersegment:
Electric $ --- $ --- $ ---
Natural gas distribution --- --- ---
Utility services --- --- ---
Pipeline and energy services 49,344 47,906 50,019
Oil and natural gas production 15,156 10,092 2,744
Construction materials and mining(a) 13,966 14,463 11,141
Intersegment eliminations (64,500) (57,998) (52,763)
Total operating revenues -
intersegment(a) $ 13,966 $ 14,463 $ 11,141
Depreciation, depletion and
amortization:
Electric $ 18,375 $ 18,129 $ 17,491
Natural gas distribution 7,348 7,150 7,013
Utility services 2,591 1,669 280
Pipeline and energy services 8,248 6,972 4,888
Oil and natural gas production 19,248 23,304 25,096
Construction materials and mining 26,008 20,562 10,999
Total depreciation, depletion
and amortization $ 81,818 $ 77,786 $ 65,767
Interest expense:
Electric $ 9,692 $ 9,979 $ 10,735
Natural gas distribution 3,614 3,728 3,698
Utility services 812 325 214
Pipeline and energy services 7,281 5,800 8,117
Oil and natural gas production 3,405 3,039 2,942
Construction materials and mining 11,202 7,402 4,503
Total interest expense $ 36,006 $ 30,273 $ 30,209
Income taxes:
Electric $ 8,678 $ 7,767 $ 7,011
Natural gas distribution 1,443 2,681 2,987
Utility services 4,323 2,437 631
Pipeline and energy services 13,356 12,579 7,566
Oil and natural gas production 10,032 (23,134) 8,156
Construction materials and mining 11,478 15,155 4,392
Total income taxes $ 49,310 $ 17,485 $ 30,743
Earnings on common stock:
Electric $ 15,973 $ 13,908 $ 12,441
Natural gas distribution 3,192 3,501 4,514
Utility services 6,505 3,272 947
Pipeline and energy services 20,972 18,651 9,955
Oil and natural gas production 16,207 (30,501)(b) 15,867
Construction materials and mining 20,459 24,499 10,111
Total earnings on common stock $ 83,308 $ 33,330 $ 53,835
Capital expenditures:
Electric $ 18,218 $ 13,035 $ 18,363
Natural gas distribution 9,246 8,256 8,858
Utility services 16,052 18,343 9,607
Pipeline and energy services 35,123 17,603 9,684
Oil and natural gas production 64,294 100,572 34,172
Construction materials and mining 105,098 172,108 41,472
Net proceeds from sale or
disposition of property (16,660) (4,275) (4,522)
Total net capital expenditures $ 231,371 $ 325,642 $ 117,634
Identifiable assets:
Electric(c) $ 307,417 $ 305,627
Natural gas distribution(c) 131,294 129,654
Utility services 67,755 38,677
Pipeline and energy services 302,587 239,507
Oil and natural gas production 255,416 192,642
Construction materials and mining 655,499 500,720
Corporate assets(d) 46,335 45,948
Total identifiable assets $1,766,303 $1,452,775
Property, plant and equipment:
Electric $ 581,090 $ 567,282
Natural gas distribution 185,797 178,522
Utility services 21,876 15,765
Pipeline and energy services 308,409 276,325
Oil and natural gas production 343,157 288,487
Construction materials and mining 601,952 484,419
Less accumulated depreciation,
depletion and amortization 794,105 726,123
Net property, plant and equipment $1,248,176 $1,084,677
(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 oil and natural gas 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 1999, 1998 and 1997, related to acquisitions,
in the preceding table include the following noncash transactions:
issuance of the company's equity securities in 1999 of $77.5 million;
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.
NOTE 10
ACQUISITIONS
In 1999, the company acquired a number of businesses, none of which
were 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 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 and accordingly, the acquired assets and liabilities assumed
have been recorded at their respective fair values as of the date of
acquisition. 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, 1999 and 1998.
Changes in benefit obligation and plan assets for the years ended
December 31 are as follows:
Other
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
(In thousands)
Change in benefit obligation:
Benefit obligation at
beginning of year $187,665 $178,199 $70,338 $ 73,838
Service cost 4,894 4,509 1,451 1,502
Interest cost 12,573 12,248 4,720 4,848
Plan participants' contributions --- --- 617 475
Amendments 3,612 437 3,691 (4,810)
Actuarial (gain) loss (17,134) 5,971 (11,047) (1,695)
Benefits paid (10,613) (13,699) (3,831) (3,820)
Benefit obligation at
end of year 180,997 187,665 65,939 70,338
Change in plan assets:
Fair value of plan assets at
beginning of year 251,194 225,201 39,543 30,595
Actual return on plan assets 35,874 39,604 5,223 6,226
Employer contribution 4 88 5,595 6,067
Plan participants' contributions --- --- 617 475
Benefits paid (10,613) (13,699) (3,831) (3,820)
Fair value of plan assets at end
of year 276,459 251,194 47,147 39,543
Funded status 95,462 63,529 (18,792) (30,795)
Unrecognized actuarial gain (108,593) (73,963) (21,299) (8,036)
Unrecognized prior service cost 10,206 7,645 --- (1,433)
Unrecognized net transition
obligation (asset) (4,402) (5,340) 30,910 31,029
Accrued benefit cost $ (7,327) $ (8,129) $(9,181) $ (9,235)
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
1999 1998 1999 1998
Discount rate 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets 8.50% 8.50% 7.50% 7.50%
Rate of compensation increase 5.00% 4.50% 5.00% 4.50%
Health care rate assumptions for the company's other postretirement
benefit plans as of December 31 are as follows:
1999 1998
Health care trend rate 6.00%-8.00% 6.50%-8.50%
Health care cost trend rate - ultimate 5.00%-6.00% 5.00%-6.00%
Year in which ultimate trend rate achieved 1999-2004 1999-2004
Components of net periodic benefit cost for the company's pension and
other postretirement benefit plans are as follows:
Other
Pension Postretirement
Benefits Benefits
Years ended December 31, 1999 1998 1997 1999 1998 1997
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 4,894 $ 4,509 $ 3,889 $1,451 $1,502 $1,272
Interest cost 12,573 12,248 11,651 4,720 4,848 4,691
Expected return on assets (17,489) (15,892) (14,321) (2,807) (2,395) (1,748)
Amortization of prior
service cost 842 848 811 --- --- ---
Recognized net actuarial
gain (995) (621) (666) (200) (169) (105)
Amortization of net
transition obligation
(asset) (997) (994) (988) 2,377 2,458 2,458
Net periodic benefit cost
(income) (1,172) 98 376 5,541 6,244 6,568
Less amount capitalized (87) 79 70 463 628 625
Net periodic benefit
expense (income) $ (1,085) $ 19 $ 306 $5,078 $5,616 $5,943
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, 1999:
1 Percentage 1 Percentage
Point Increase Point Decrease
(In thousands)
Effect on total of service
and interest cost components $ 240 $ (217)
Effect on postretirement benefit
obligation $3,004 $(2,683)
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
$3.3 million, $2.7 million and $2.2 million in 1999, 1998 and 1997,
respectively.
The company sponsors various defined contribution plans for eligible
employees. Costs incurred by the company under these plans were
$4.4 million in 1999, $3.1 million in 1998 and $2.1 million in 1997.
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, is included in "Other income --
net" in the accompanying Consolidated Statements of Income for the year
ended December 31, 1997. Summarized operating results for Hawaiian
Cement for the seven months ended July 31, 1997, when accounted for by
the equity method, are as follows: net sales of $33.5 million,
operating margin of $4.7 million and income before income taxes of $2.0
million.
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:
1999 1998
(In thousands)
Big Stone Station:
Utility plant in service $ 49,889 $ 49,762
Less accumulated depreciation 29,611 28,781
$ 20,278 $ 20,981
Coyote Station:
Utility plant in service $121,919 $121,726
Less accumulated depreciation 60,350 56,770
$ 61,569 $ 64,956
NOTE 14
REGULATORY MATTERS AND REVENUES SUBJECT TO REFUND
Williston Basin Interstate Pipeline Company, an indirect wholly owned
subsidiary of the company, 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
orders concerning the 1992 proceeding. On January 22, 1999, the D.C.
Circuit Court issued its opinion remanding the issues of return on
equity, ad valorem taxes and throughput to the FERC for further
explanation and justification. The mandate was issued by the D.C.
Circuit Court to the FERC on March 11, 1999. By order dated June 1,
1999, the FERC remanded the return on equity issue to an Administrative
Law Judge for further proceedings. On October 13, 1999, the FERC
approved a settlement proposed by the parties to the proceeding which
resolves the remanded return on equity issue and concludes the
proceeding. Based on the FERC's approval of this settlement, Williston
Basin sought reimbursement from its customers in the fourth quarter of
1999 of a portion of the refunds made in 1997 relating to the return on
equity issue.
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. 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. On June 1,
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. On July 1, 1999, Williston Basin requested rehearing of
certain issues which were contained in the June 1, 1999 FERC order. On
September 29, 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, on October 29, 1999,
Williston Basin issued refunds to its customers totaling $11.3 million,
all from amounts which had previously been reserved. In mid-December
1999, a hearing was held before the FERC regarding the return on equity
issue. In addition, on July 29, 1999, Williston Basin appealed to the
D.C. Circuit Court certain issues concerning storage cost allocations
as decided by the FERC in its June 1, 1999 order. On October 12, 1999,
the D.C. Circuit Court issued an order which dismissed Williston
Basin's appeal but permitted Williston Basin to again appeal such
previously contested issues upon final determination of all issues by
the FERC in this proceeding.
On December 1, 1999, Williston Basin filed a general natural gas rate
change application with the FERC. Williston Basin will begin
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 June 1, 1999 FERC orders referenced above,
Williston Basin in the second quarter of 1999 determined that reserves
it had previously established exceeded its expected refund obligation
and, accordingly, reversed reserves in the amount of $4.4 million after
tax. Williston Basin believes that its remaining reserves are adequate
based on its assessment of the ultimate outcome of the various
proceedings.
NOTE 15
COMMITMENTS AND CONTINGENCIES
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.
On April 20, 1999, the U.S. Court of Appeals issued its order which
affirmed in part and reversed in part the Federal District Court's June
1997 decision. Additionally, the U.S. Court of Appeals remanded the
case to the Federal District Court for further determination of the
prices and volumes to be used for determination of damages. The U.S.
Court of Appeals also remanded to the lower court for further
consideration the issue of whether pre-judgment interest on damages is
recoverable by Moncrief. As a result of the decision by the U.S. Court
of Appeals, the prior judgment of $15.6 million by the Federal District
Court was vacated. On December 8, 1999, a settlement was entered into
between Williston Basin and Moncrief whereby Williston Basin paid
Moncrief $3.0 million in settlement of all claims. On December 28,
1999, the United States District Court, District of Wyoming dismissed
the case.
Williston Basin believes that it is entitled to recover from customers
virtually all of the costs which were incurred as a result of the
settlement 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 alleged they were entitled to damages for
the breach of Williston Basin's and the company's contract with Koch.
Apache and Snyder submitted damage estimates under differing theories
aggregating up to $4.8 million without interest. In November 1998, the
North Dakota District Court entered an order directing the entry of
judgment in favor of Williston Basin and the company. On March 31,
1999, judgment was entered, thereby dismissing Apache and Snyder's
claims against Williston Basin and the company. Apache and Snyder
filed a notice of appeal with the North Dakota Supreme Court on May 17,
1999. On December 28, 1999, the North Dakota Supreme Court
affirmed the decision of the North Dakota District Court, thereby
dismissing Apache and Snyder's claims against Williston Basin and the
company.
In a related matter, in March 1997, a suit was filed by 11 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 the 11 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 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 requested a determination by the State District Court of the
pricing mechanism to be applied to the Agreement and 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 sought 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 prices charged by Knife River were excessive and that the Co-owners
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 proceeded against Knife River. In October 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. During 1999, the arbitration panel issued three Memorandum
Opinions (Opinions) and held an additional hearing. Based on its
assessment of the proceedings, Knife River's earnings in the second
quarter of 1999 reflected a $3.7 million after-tax charge regarding
this matter. As a result of the Memorandum Opinion rendered by the
arbitrators in August 1999, Knife River's 1999 third quarter earnings
included a $1.9 million after-tax charge reflecting the resolution of
this matter. The arbitration panel also revised the pricing terms of
the Agreement beginning April 1, 1999. The revised pricing terms
retained the minimum return on sales provision but at a lower
guaranteed level than the Agreement previously provided.
On January 5, 2000, the State District Court entered a judgment agreed
to by all parties that dismissed the company from the action, confirmed
the Opinions of the arbitration panel, filed the Opinions under seal
pursuant to a confidentiality agreement among the parties, held that
each party shall bear its own costs subject to any contractual
agreements to the contrary, dismissed the November 1995 action, and
confirmed that all sums due pursuant to the arbitration have been paid
and satisfied.
On June 3, 1999, several oil and gas royalty interest owners filed suit
in Colorado State District Court, in the City and County of Denver,
against WBI Production, Inc. (WBI Production), an indirect wholly owned
subsidiary of the company, and several former producers of natural gas
with respect to certain gas production properties in the state of
Colorado. The complaint arose as a result of the purchase by WBI
Production effective January 1, 1999, of certain natural gas producing
leaseholds from the former producers. Prior to February 1, 1999, the
natural gas produced from the leaseholds was sold at above market
prices pursuant to a natural gas contract. Pursuant to the contract,
the royalty interest owners were paid royalties based upon the above
market prices. The royalty interest owners have alleged that WBI
Production took assignment of the rights to the natural gas contract
from the former owner of the contract and, with respect to natural gas
produced from such leases and sold at market prices thereafter, wrongly
ceased paying the higher royalties on such gas.
In their complaint, the royalty interest owners have alleged, in part,
breach of oil and gas lease obligations and unjust enrichment on the
part of WBI Production and the other former producers with respect to
the amount of royalties being paid to the royalty interest owners. The
royalty interest owners have requested damages for additional royalties
and other costs, including pre-judgment interest. No specific amount
of damages has been stated. Trial before the Colorado State District
Court has been scheduled for April 24, 2000. WBI Production intends to
vigorously contest the suit.
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 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.
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. The suit has been removed to the U.S.
District Court, District of Kansas. The defendants in this suit have
filed a motion to have the suit transferred to Wyoming and consolidated
with the Grynberg proceedings.
Williston Basin and Montana-Dakota believe the claims of Grynberg and
Quinque are without merit and intend to vigorously contest these suits.
Other
During the third quarter of 1999, the company and Williston Basin
reached resolution with respect to certain production tax and other
state tax matters that had been outstanding, some dating back to 1989.
Deficiency claims of approximately $5.6 million, plus interest, had
been received with respect to these issues. As a result in September
1999, Williston Basin reversed reserves which were no longer needed in
an amount of $3.9 million after tax.
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.
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 16
QUARTERLY DATA (UNAUDITED)
The following unaudited information shows selected items by quarter for
the years 1999 and 1998:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
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
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
* 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 17
OIL AND NATURAL GAS ACTIVITIES (UNAUDITED)
Fidelity Exploration & Production Company, an indirect wholly owned
subsidiary of the company, is involved in the acquisition, exploration,
development and production of oil and natural gas 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 throughout the United States and in the Gulf of Mexico in
proportion to its interests.
Fidelity also owns in fee or holds natural gas leases for the
properties it operates in Montana, North Dakota and Colorado. These
rights are in the Cedar Creek Anticline in southeastern Montana, in the
Bowdoin area located in north-central Montana and the Bonny Field
located in eastern Colorado.
The information that follows includes the company's proportionate share
of all its oil and natural gas interests held by Fidelity.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to oil and natural gas
producing activities at December 31:
1999 1998 1997
(In thousands)
Subject to amortization $319,448 $266,301 $252,291
Not subject to amortization 23,464 22,153 9,408
Total capitalized costs 342,912 288,454 261,699
Less accumulated depreciation,
depletion and amortization 129,211 111,472 95,611
Net capitalized costs $213,701 $176,982 $166,088
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, 1999 1998 1997
(In thousands)
Acquisitions $ 30,842 $ 63,419 $ 59
Exploration 11,010 15,976 13,344
Development 21,822 21,148 18,874
Total capital expenditures $ 63,674 $100,543 $ 32,277
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, 1999 1998 1997
(In thousands)
Revenues $ 75,327 $ 61,831 $ 77,756
Production costs 25,402 19,419 23,251
Depreciation, depletion and
amortization 19,136 23,050 24,864
Write-downs of oil and natural gas
properties (Note 1) --- 66,000 ---
Pretax income 30,789 (46,638) 29,641
Income tax expense (benefit) 11,815 (19,268) 10,968
Results of operations for
producing activities $ 18,974 $(27,370) $ 18,673
The following table summarizes the company's estimated quantities of
proved oil and natural gas reserves at December 31, 1999, 1998 and
1997, 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.
1999 1998 1997
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 11,500 243,600 14,900 184,900 16,100 200,200
Production (1,800) (24,700) (1,900) (20,700) (2,100) (20,400)
Extensions and
discoveries 800 21,800 200 21,300 600 12,100
Purchases of proved
reserves 700 38,200 2,000 56,600 --- 200
Sales of reserves
in place (400) (9,300) --- (100) (200) (2,300)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 3,900 (700) (3,700) 1,600 500 (4,900)
Balance at end
of year 14,700 268,900 11,500 243,600 14,900 184,900
Proved developed reserves:
January 1, 1997 15,400 168,200
December 31, 1997 14,500 163,800
December 31, 1998 10,700 193,000
December 31, 1999 13,300 213,400
All of the company's interests in oil and natural gas 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 oil
and natural gas interests at December 31 is as follows:
1999 1998 1997
(In thousands)
Future net cash flows before
income taxes $ 492,000 $246,700 $306,600
Future income tax expenses 131,500 40,500 86,600
Future net cash flows 360,500 206,200 220,000
10% annual discount for estimated
timing of cash flows 131,400 81,100 81,000
Discounted future net cash flows
relating to proved oil and natural
gas reserves $ 229,100 $125,100 $139,000
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1999 1998 1997
(In thousands)
Beginning of year $ 125,100 $139,000 $234,000
Net revenues from production (49,900) (42,400) (54,500)
Change in net realization 123,100 (70,500) (158,400)
Extensions, discoveries and improved
recovery, net of future
production-related costs 33,500 18,200 19,400
Purchases of proved reserves 57,700 51,000 200
Sales of reserves in place (14,700) (100) (2,800)
Changes in estimated future
development costs, net of those
incurred during the year (9,800) (16,600) 7,700
Accretion of discount 16,700 18,600 32,800
Net change in income taxes (59,800) 30,100 62,100
Revisions of previous quantity
estimates 7,400 (1,600) (1,300)
Other (200) (600) (200)
Net change 104,000 (13,900) (95,000)
End of year $ 229,100 $125,100 $139,000
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.
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, 1999 and 1998, 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, 1999. 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, 1999 and
1998, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1999, in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 24, 2000
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1999 1998* 1997 1996 1995 1994 1989
Selected Financial Data
Operating revenues: (000's)
Electric $ 154,869 $ 147,221 $ 141,590 $ 138,761 $ 134,609 $ 133,953 $ 126,228
Natural gas distribution 157,692 154,147 157,005 155,012 150,532 155,319 142,310
Utility services 99,917 64,232 22,761 --- --- --- ---
Pipeline and energy services 383,532 180,732 87,018 71,580 67,186 63,874 107,014
Oil and natural gas production 78,394 61,842 77,916 75,350 53,505 44,936 27,351
Construction materials and mining 469,905 346,451 174,147 132,222 113,066 116,646 41,643
Intersegment eliminations (64,500) (57,998) (52,763) (58,224) (54,652) (65,200) (91,773)
$1,279,809 $ 896,627 $ 607,674 $ 514,701 $ 464,246 $ 449,528 $ 352,773
Operating income: (000's)
Electric $ 35,727 $ 32,167 $ 31,307 $ 29,476 $ 29,898 $ 27,596 $ 32,592
Natural gas distribution 6,688 8,028 10,410 11,504 6,917 3,948 7,781
Utility services 11,518 5,932 1,782 --- --- --- ---
Pipeline and energy services 40,627 33,651 25,822 27,697 24,043 19,024 23,683
Oil and natural gas production 26,845 (50,444) 27,638 26,786 15,255 11,014 11,572
Construction materials and mining 38,346 41,609 14,602 16,062 14,463 16,593 9,087
$ 159,751 $ 70,943 $ 111,561 $ 111,525 $ 90,576 $ 78,175 $ 84,715
Earnings on common stock: (000's)
Electric $ 15,973 $ 13,908 $ 12,441 $ 11,436 $ 12,000 $ 11,719 $ 13,385
Natural gas distribution 3,192 3,501 4,514 4,892 1,604 285 3,123
Utility services 6,505 3,272 947 --- --- --- ---
Pipeline and energy services 20,972 18,651 9,955 1,649 7,804 5,106 3,125
Oil and natural gas production 16,207 (30,501) 15,867 15,185 8,614 10,316 7,362
Construction materials and mining 20,459 24,499 10,111 11,521 10,819 11,622 8,890
$ 83,308 $ 33,330 $ 53,835 $ 44,683 $ 40,841 $ 39,048 $ 35,885
Earnings per common share -- diluted $ 1.52 $ .66 $ 1.24 $ 1.04 $ .95 $ .91 $ .84
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 54,870 50,837 43,478 42,824 42,789 42,763 42,715
Dividends per common share $ .82 $ .7834 $ .7534 $ .7333 $ .7188 $ .7022 $ .6533
Book value per common share $ 11.74 $ 10.39 $ 8.84 $ 8.21 $ 7.90 $ 7.66 $ 6.71
Market price per common share (year-end) $ 20.00 $ 26.31 $ 21.08 $ 15.33 $ 13.25 $ 12.06 $ 10.05
Market price ratios:
Dividend payout 55% 119% 61% 70% 76% 77% 78%
Yield 4.2% 3.0% 3.6% 4.8% 5.5% 5.9% 6.5%
Price/earnings ratio 13.2x 39.9x 17.0x 14.6x 13.9x 13.2x 12.0x
Market value as a percent of book value 170.4% 253.2% 238.5% 186.8% 167.7% 157.4% 149.7%
Profitability Indicators
Return on average common equity 13.9% 6.5% 14.6% 13.0% 12.3% 12.1% 12.5%
Return on average invested capital 9.6% 5.5% 10.3% 9.5% 9.2% 9.1% 9.2%
Interest coverage 7.1x 6.1x 6.0x 5.4x 3.9x 3.3x 2.8x
Fixed charges coverage, including
preferred dividends 4.3x 2.5x 3.4x 2.7x 3.0x 2.8x 2.3x
General
Total assets (000's) $1,766,303 $1,452,775 $1,113,892 $1,089,173 $1,056,479 $1,004,718 $ 971,401
Net long-term debt (000's) $ 563,545 $ 413,264 $ 298,561 $ 280,666 $ 237,352 $ 217,693 $ 234,333
Redeemable preferred stock (000's) $ 1,600 $ 1,700 $ 1,800 $ 1,900 $ 2,000 $ 2,100 $ 2,600
Capitalization ratios:
Common stockholders' equity 54% 56% 55% 54% 57% 58% 53%
Preferred stocks 1 2 2 3 3 3 3
Long-term debt 45 42 43 43 40 39 44
100% 100% 100% 100% 100% 100% 100%
<FN>
* Reflects $39.9 million or 78 cents per common share in noncash after-tax write-downs of oil and natural gas properties.
</FN>
NOTE: Common stock share amounts reflect the company's three-for-two common stock splits effected in October 1995 and July 1998.
1999 1998 1997 1996 1995 1994 1989
Electric
Sales to ultimate consumers (thousand kWh) 2,075,446 2,053,862 2,041,191 2,067,926 1,993,693 1,955,136 1,836,099
Sales for resale (thousand kWh) 943,520 586,540 361,954 374,535 408,011 444,492 311,327
Electric system generating and firm purchase
capability -- kW (Interconnected system) 492,800 489,100 487,500 481,800 472,400 470,900 451,600
Demand peak -- kW (Interconnected system) 420,550 402,500 404,600 393,300 412,700 369,800 383,600
Electricity produced (thousand kWh) 2,350,769 2,103,199 1,826,770 1,829,669 1,718,077 1,901,119 1,773,849
Electricity purchased (thousand kWh) 860,508 730,949 769,679 809,261 867,524 700,912 557,650
Average cost of fuel and purchased
power per kWh $ .016 $ .017 $ .018 $ .017 $ .016 $ .017 $ .017
Natural Gas Distribution
Sales (Mdk) 30,931 32,024 34,320 38,283 33,939 31,840 31,643
Transportation (Mdk) 11,551 10,324 10,067 9,423 11,091 9,278 9,321
Weighted average degree days --
% of previous year's actual 89% 94% 85% 114% 105% 92% 112%
Pipeline and Energy Services
Pipeline:
Sales for resale (Mdk) --- --- --- --- --- --- 27,274
Transportation (Mdk) 78,061 88,974 85,464 82,169 68,015 63,870 51,159
Energy services:
Natural gas volumes (Mdk) 131,687 58,495 14,971 4,670 3,556 7,301 843
Propane (thousand gallons) 6,440 7,037 10,005 9,689 7,471 6,462 ---
Oil and Natural Gas Production
Production:
Oil (000's of barrels) 1,758 1,912 2,088 2,149 1,973 1,565 1,348
Natural gas (MMcf) 24,652 20,699 20,407 20,391 17,574 14,162 3,632
Average prices:
Oil (per barrel) $ 15.34 $ 12.71 $ 17.50 $ 17.91 $ 15.07 $ 13.14 $ 16.26
Natural gas (per Mcf) $ 1.94 $ 1.81 $ 2.02 $ 1.79 $ 1.33 $ 1.69 $ 1.33
Net recoverable reserves:
Oil (000's of barrels) 14,700 11,500 14,900 16,100 14,200 12,500 12,000
Natural gas (MMcf) 268,900 243,600 184,900 200,200 179,000 154,200 10,800
Construction Materials and Mining
Construction materials: (000's)
Aggregates (tons sold) 13,981 11,054 5,113 3,374 2,904 2,688 ---
Asphalt (tons sold) 2,993 1,790 758 694 373 391 ---
Ready-mixed concrete (cubic yards sold) 1,186 1,021 516 340 307 315 ---
Recoverable aggregate reserves (tons) 740,030 654,670 169,375 119,800 68,000 71,000 ---
Coal: (000's)
Sales (tons) 3,236 3,113 2,375 2,899 4,218 5,206 4,747
Recoverable reserves (tons) 182,761 190,152 226,560 228,900 231,900 236,100 266,000