MDU RESOURCES GROUP, INC.
1997 FINANCIAL REPORT
REPORT OF MANAGEMENT
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report. The financial statements have been prepared in
conformity with generally accepted accounting principles as applied to
the company's regulated and non-regulated businesses and necessarily
include some amounts that are based on informed judgments and
estimates of management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost-effective basis,
that transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an
organizational structure which provides an appropriate segregation of
responsibilities, effective selection and training of personnel,
written policies and procedures and periodic reviews by the Internal
Audit Department. In addition, the company has a policy which
requires all employees to acknowledge their responsibility for ethical
conduct. Management believes that these measures provide for a system
that is effective and reasonably assures that all transactions are
properly recorded for the preparation of financial statements.
Management modifies and improves its system of internal accounting
controls in response to changes in business conditions. The company's
Internal Audit Department is charged with the responsibility for
determining compliance with company procedures.
The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting. The audit committee meets regularly with
management, the internal auditors and Arthur Andersen LLP, independent
public accountants, to discuss auditing and financial matters and to
assure that each is carrying out its responsibilities. The internal
auditors and Arthur Andersen LLP have full and free access to the
audit committee, without management present, to discuss auditing,
internal accounting control and financial reporting matters.
Arthur Andersen LLP is engaged to express an opinion on the financial
statements. Their audit is conducted in accordance with generally
accepted auditing standards and includes examining, on a test basis,
supporting evidence, assessing the company's accounting principles
used and significant estimates made by management and evaluating the
overall financial statement presentation to the extent necessary to
allow them to report on the fairness, in all material respects, of the
financial condition and operating results of the company.
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
Years ended December 31, 1997 1996 1995
(In thousands, except per share amounts)
Operating Revenues
Electric $164,351 $138,761 $134,609
Natural gas 200,789 175,408 167,787
Construction materials and mining 174,147 132,222 113,066
Oil and natural gas production 68,387 68,310 48,784
607,674 514,701 464,246
Operating Expenses
Fuel and purchased power 45,604 43,983 41,769
Purchased natural gas sold 77,082 48,886 53,351
Operation and maintenance 283,894 225,682 202,327
Depreciation, depletion and
amortization 65,767 62,651 54,825
Taxes, other than income 23,766 21,974 21,398
496,113 403,176 373,670
Operating Income
Electric 33,089 29,476 29,898
Natural gas distribution 10,410 11,504 6,917
Natural gas transmission 29,169 30,231 25,427
Construction materials and mining 14,602 16,062 14,463
Oil and natural gas production 24,291 24,252 13,871
111,561 111,525 90,576
Other income -- net 4,008 5,617 4,789
Interest expense 30,209 28,832 24,690
Costs on natural gas
repurchase commitment (Note 3) --- 26,753 5,985
Income before income taxes 85,360 61,557 64,690
Income taxes 30,743 16,087 23,057
Net income 54,617 45,470 41,633
Dividends on preferred stocks 782 787 792
Earnings on common stock $53,835 $44,683 $40,841
Earnings per common share--basic $1.86 $1.57 $1.43
Earnings per common share--diluted $1.86 $1.57 $1.43
Dividends per common share $1.13 $1.10 $1.0782
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1997 1996
(In thousands)
ASSETS
Current Assets
Cash and cash equivalents $ 28,174 $ 47,799
Receivables 80,585 73,187
Inventories 41,322 27,361
Deferred income taxes 17,356 26,011
Prepayments and other current assets 12,479 17,300
179,916 191,658
Investments (Note 15) 18,935 53,501
Property, Plant and Equipment
Electric 566,247 546,477
Natural gas distribution 172,086 164,843
Natural gas transmission 288,709 273,775
Construction materials and mining 243,110 173,663
Oil and natural gas production 240,193 211,555
1,510,345 1,370,313
Less accumulated depreciation,
depletion and amortization 670,809 617,724
839,536 752,589
Deferred charges and other assets 75,505 91,425
$1,113,892 $1,089,173
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Short-term borrowings $ 3,347 $ 3,950
Long-term debt and preferred
stock due within one year 7,902 11,854
Accounts payable 31,571 31,580
Taxes payable 9,057 8,683
Dividends payable 8,574 8,099
Other accrued liabilities,
including reserved revenues 88,563 100,938
149,014 165,104
Long-term debt (Note 11) 298,561 280,666
Deferred credits and other liabilities
Deferred income taxes 119,747 116,208
Other liabilities (Note 3) 143,574 159,721
263,321 275,929
Commitments and contingencies
(Notes 2, 3, 4 and 14)
Stockholders' Equity
Preferred stocks (Note 10) 16,700 16,800
Common stockholders' equity
Common stock (Note 9)
Authorized -- 75,000,000 shares,
$3.33 par value
Outstanding -- 29,143,332 and 28,476,981
shares in 1997 and
1996, respectively 97,047 94,828
Other paid-in capital 76,526 64,305
Retained earnings 212,723 191,541
Total common stockholders' equity 386,296 350,674
Total stockholders' equity 402,996 367,474
$1,113,892 $1,089,173
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
MDU RESOURCES GROUP, INC.
Years ended Other
December 31, Common Stock Paid-In Retained
1997, 1996 and 1995 Shares Amount Capital Earnings Total
(In thousands, except shares)
Balance at
December 31, 1994 18,984,654 $63,219 $95,914 $168,050 $327,183
Net income --- --- --- 41,633 41,633
Dividends on
preferred stocks --- --- --- (792) (792)
Dividends on
common stock --- --- --- (30,707) (30,707)
Three-for-two
common stock
split (Note 9) 9,492,327 31,609 (31,609) --- ---
Balance at
December 31, 1995 28,476,981 94,828 64,305 178,184 337,317
Net income --- --- --- 45,470 45,470
Dividends on
preferred stocks --- --- --- (787) (787)
Dividends on
common stock --- --- --- (31,326) (31,326)
Balance at
December 31, 1996 28,476,981 94,828 64,305 191,541 350,674
Net income --- --- --- 54,617 54,617
Dividends on
preferred stocks --- --- --- (782) (782)
Dividends on
common stock --- --- --- (32,653) (32,653)
Issuance of common
stock:
Acquisitions 225,629 751 3,622 --- 4,373
Other 440,722 1,468 8,599 --- 10,067
Balance at
December 31, 1997 29,143,332 $97,047 $76,526 $212,723 $386,296
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1997 1996 1995
(In thousands)
Operating Activities
Net income $ 54,617 $ 45,470 $ 41,633
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 65,767 62,651 54,825
Deferred income taxes and
investment tax credit -- net 7,152 4,551 7,631
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 3,360 6,580 7,177
Write-down of natural gas
available under repurchase
commitment, net of income
taxes (Note 3) --- 11,364 ---
Changes in current assets and
liabilities:
Receivables 6,951 (9,346) (6,552)
Inventories (4,214) (1,218) 3,141
Other current assets 10,681 4,185 (3,943)
Accounts payable (5,605) 7,584 2,039
Other current liabilities (6,087) (22,434) 17,177
Other noncurrent changes 6,007 (3,149) (1,023)
Net cash provided by operating
activities 138,629 106,238 122,105
Financing Activities
Net change in short-term borrowings (5,919) 3,350 (80)
Issuance of long-term debt 54,064 81,300 36,710
Repayment of long-term debt (47,899) (43,262) (20,433)
Retirement of preferred stocks (100) (100) (100)
Issuance of common stock 10,067 --- ---
Retirement of natural gas
repurchase commitment (52,090) (4,157) (204)
Dividends paid (33,435) (32,113) (31,499)
Net cash provided by (used in)
financing activities (75,312) 5,018 (15,606)
Investing Activities
Capital expenditures including
acquisitions of businesses:
Electric (18,713) (18,674) (19,689)
Natural gas distribution (8,858) (6,255) (8,878)
Natural gas transmission (13,205) (10,127) (9,688)
Construction materials and mining (40,797) (25,063) (36,810)
Oil and natural gas production (30,651) (51,821) (39,917)
(112,224) (111,940) (114,982)
Net proceeds from sale or
disposition of property 4,522 11,803 2,802
Net capital expenditures (107,702) (100,137) (112,180)
Sale of natural gas available
under repurchase commitment 27,008 10,595 163
Investments (2,248) (7,313) 1,726
Net cash used in investing
activities (82,942) (96,855) (110,291)
Increase (decrease) in cash
and cash equivalents (19,625) 14,401 (3,792)
Cash and cash equivalents --
beginning of year 47,799 33,398 37,190
Cash and cash equivalents --
end of year $ 28,174 $ 47,799 $ 33,398
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.
(the "company") include the accounts of two regulated businesses --
retail and wholesale sales of electricity and retail sales and/or
transportation of natural gas and propane, and natural gas
transmission and storage -- and two non-regulated businesses --
construction materials and mining operations, and oil and natural gas
production. The statements also include the ownership interests in the
assets, liabilities and expenses of two jointly owned electric
generating stations.
The company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by the company's
non-regulated 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 6 for more
information regarding the nature and amounts of these regulatory
deferrals.
In accordance with the provisions of SFAS No. 71, intercompany coal
sales, which are made at prices approximately the same as those
charged to others, and the related utility fuel purchases are not
eliminated. All other significant intercompany balances and
transactions have been eliminated.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost when
first placed in service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original
cost and cost of removal, less salvage, is charged to accumulated
depreciation. With respect to the retirement or disposal of all other
assets, except for oil and natural gas production properties as
described below, the resulting gains or losses are recognized as a
component of income. The company is permitted to capitalize an
allowance for funds used during construction (AFUDC) on regulated
construction projects and to include such amounts in rate base when
the related facilities are placed in service. In addition, the
company capitalizes interest, when applicable, on certain construction
projects associated with its other operations. The amounts of AFUDC
and interest capitalized were not material in 1997, 1996 and 1995.
Property, plant and equipment are depreciated on a straight-line basis
over the average useful lives of the assets, except for oil and
natural gas production properties as described below.
Oil and Natural Gas
The company uses the full-cost method of accounting for its oil and
natural gas production activities. Under this method, all costs
incurred in the acquisition, exploration and development of oil and
natural gas properties are capitalized and amortized on the units of
production method based on total proved reserves. Cost centers for
amortization purposes are determined on a country-by-country basis.
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. 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 realized.
Natural Gas in Underground Storage and Available Under Repurchase
Commitment
Natural gas in underground storage is carried at cost using the
last-in, first-out (LIFO) method. That portion of the cost of natural
gas in underground storage expected to be used within one year is
included in inventories.
Natural gas available under a repurchase commitment with Frontier Gas
Storage Company (Frontier) is carried at Frontier's cost of purchased
natural gas, less an allowance to reflect changed market conditions
and is reflected on the company's Consolidated Balance Sheets in
"Deferred charges and other assets". See Note 3 for discussion on the
write-down which occurred in 1996 of the natural gas available under
the repurchase commitment with Frontier.
Inventories
Inventories, other than natural gas in underground storage, consist
primarily of materials and supplies and inventories held for resale.
These inventories are stated at the lower of average cost or market.
Revenue Recognition
The company recognizes utility revenue each month based on the
services provided to all utility customers during the month. For its
construction business, the company recognizes revenue on the
percentage of completion method.
Natural Gas Costs Recoverable Through Rate Adjustments
Under the terms of certain orders of the applicable state public
service commissions, the company is deferring natural gas commodity,
transportation and storage costs which are greater or less than
amounts presently being recovered through its existing rate schedules.
Such orders generally provide that these amounts are recoverable or
refundable through rate adjustments within 24 months from the time
such costs are paid.
Income Taxes
The company provides deferred federal and state income taxes on all
temporary differences. Excess deferred income tax balances associated
with Montana-Dakota's and Williston Basin's rate-regulated activities
resulting from the company's adoption of SFAS No. 109, "Accounting for
Income Taxes", have been recorded as a regulatory liability and are
included in "Other liabilities" in the company's Consolidated Balance
Sheets. This regulatory liability is 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
In 1997, the company adopted SFAS No. 128, "Earnings Per Share". The
adoption of this pronouncement did not affect previously reported
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.
The weighted average common shares outstanding used for basic earnings
per common share (in thousands) were 28,877 in 1997 and 28,477 in both
1996 and 1995. The number of common shares used for diluted earnings
per common share (in thousands) were 28,985 in 1997, 28,549 in 1996
and 28,526 in 1995.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires the company to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Estimates are used for such
items as plant depreciable lives, tax provisions, uncollectible
accounts, environmental and other loss contingencies, 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, 1997 1996 1995
(In thousands)
Interest, net of amount capitalized $25,626 $25,449 $24,436
Income taxes $18,171 $28,163 $18,330
The company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents. The
company's Consolidated Statements of Cash Flows include the effects
from acquisitions.
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.
NOTE 2
Regulatory Matters and Revenues Subject to Refund
General Rate Proceedings
Williston Basin has pending with the FERC a general natural gas rate
change application implemented in 1992. On October 20, 1997,
Williston Basin appealed to the U.S. District Court of Appeals for the
D.C. Circuit (D.C. Circuit Court) certain issues decided by the FERC
in prior orders concerning the 1992 proceeding. On December 10, 1997,
the FERC issued an order accepting, subject to certain conditions,
Williston Basin's July 25, 1997 compliance filing. On December 22,
1997, Williston Basin submitted a compliance filing pursuant to the
FERC's December 10, 1997 order. On December 31, 1997, Williston Basin
refunded $33.8 million to its customers, including $30.8 million to
Montana-Dakota, in addition to the $6.1 million interim refund that it
had previously made in November 1996. All such amounts had been
previously reserved. Williston Basin is awaiting an order from the
FERC on its December 22, 1997 compliance filing.
Reserves have been provided for a portion of the revenues that have
been collected subject to refund with respect to pending regulatory
proceedings and to reflect future resolution of certain issues with
the FERC. Williston Basin believes that such reserves are adequate
based on its assessment of the ultimate outcome of the various
proceedings.
NOTE 3
Natural Gas Repurchase Commitment
The company has offered for sale since 1984 the inventoried natural
gas owned by Frontier, a special purpose, non-affiliated corporation.
Through an agreement, Williston Basin is obligated to repurchase all
of the natural gas at Frontier's original cost and reimburse Frontier
for all of its financing and general administrative costs. Frontier
has financed the purchase of the natural gas under a term loan
agreement with several banks. At December 31, 1997, borrowings
totaled $32.0 million at a weighted average interest rate of
6.63 percent. At December 31, 1997 and 1996, the natural gas
repurchase commitment of $30.4 million and $66.3 million,
respectively, is reflected on the company's Consolidated Balance
Sheets under "Other liabilities" and $1.6 million and $17.7 million,
respectively, is reflected under "Other accrued liabilities". The
term loan agreement will terminate on October 2, 1999, subject to an
option to renew this agreement upon the lenders' consent for up to
five years, unless terminated earlier by the occurrence of certain
events.
The FERC has issued orders that have held that storage costs should be
allocated to this gas, prospectively beginning May 1992, as opposed to
being included in rates applicable to Williston Basin's customers.
These storage costs, as initially allocated to the Frontier gas,
approximated $2.1 million annually, for which Williston Basin has
provided reserves. Williston Basin appealed these orders to the D.C.
Circuit Court which in December 1996 issued its order ruling that the
FERC's actions in allocating costs to the Frontier gas were
appropriate. Williston Basin is awaiting a final order from the FERC
as to the appropriate costs to be allocated.
Williston Basin sells and transports natural gas held under the
repurchase commitment. In the third quarter of 1996, Williston Basin,
based on a number of factors including differences in regional natural
gas prices and natural gas sales occurring at that time, wrote down
43.0 MMdk of this gas to its then current value. The value of this
gas was determined using the sum of discounted cash flows of expected
future sales occurring at then current regional natural gas prices as
adjusted for anticipated future price increases. This resulted in a
write-down aggregating $18.6 million ($11.4 million after tax). In
addition, Williston Basin wrote off certain other costs related to
this natural gas of approximately $2.5 million ($1.5 million after
tax). The amounts related to this write-down are included in "Costs
on natural gas repurchase commitment" in the Consolidated Statements
of Income. At December 31, 1997 and 1996, natural gas held under the
repurchase commitment of $14.6 million and $37.2 million,
respectively, is included in the company's Consolidated Balance Sheets
under "Deferred charges and other assets". The recognition of the
then current market value of this natural gas facilitated the sale by
Williston Basin of 28.1 MMdk from the date of this write-down through
December 31, 1997, and should allow Williston Basin to market the
remaining 14.9 MMdk on a sustained basis enabling Williston Basin to
liquidate this asset over approximately the next three to four years.
NOTE 4
Commitments and Contingencies
Pending Litigation
In November 1993, the estate of W.A. Moncrief (Moncrief), a producer
from whom Williston Basin purchased a portion of its natural gas
supply, filed suit in Federal District Court for the District of
Wyoming (Federal District Court) against Williston Basin and the
company disputing certain price and volume issues under the contract.
Through the course of this action Moncrief submitted damage
calculations which totaled approximately $19 million or, under its
alternative pricing theory, approximately $39 million.
On June 26, 1997, the Federal District Court issued its order awarding
Moncrief damages of approximately $15.6 million. On July 25, 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. On August 25, 1997,
Moncrief filed a notice of appeal with the United States Court of
Appeals for the Tenth Circuit related to the Federal District Court's
orders. On September 2, 1997, Williston Basin and the company filed a
notice of cross-appeal.
Williston Basin believes that it is entitled to recover from
ratepayers virtually all of the costs ultimately incurred as a result
of these orders as gas supply realignment transition costs pursuant to
the provisions of the FERC's Order 636. However, the amount of costs
that can ultimately be recovered is subject to approval by the FERC
and market conditions.
In December 1993, Apache Corporation (Apache) and Snyder Oil
Corporation (Snyder) filed suit in North Dakota Northwest Judicial
District Court (North Dakota District Court), against Williston Basin
and the company. Apache and Snyder are oil and natural gas producers
which had processing agreements with Koch Hydrocarbon Company (Koch).
Williston Basin and the company had a natural gas purchase contract
with Koch. Apache and Snyder have alleged they are entitled to
damages for the breach of Williston Basin's and the company's contract
with Koch. Williston Basin and the company believe that if Apache and
Snyder have any legal claims, such claims are with Koch, not with
Williston Basin or the company as Williston Basin, the company and
Koch have settled their disputes. Apache and Snyder have recently
provided alleged damages under differing theories ranging up to $4.8
million without interest. A motion to intervene in the case by
several other producers, all of which had contracts with Koch but not
with Williston Basin, was denied in December 1996. The trial before
the North Dakota District Court was completed on November 6, 1997.
Williston Basin and the company are awaiting a decision from the North
Dakota District Court.
In a related matter, on March 14, 1997, a suit was filed by nine other
producers, several of which had unsuccessfully tried to intervene in
the Apache and Snyder litigation, against Koch, Williston Basin and
the company. The parties to this suit are making claims similar to
those in the Apache and Snyder litigation, although no specific
damages have been specified.
In Williston Basin's opinion, the claims of Apache and Snyder are
without merit and overstated and the claims of the nine other
producers are without merit. If any amounts are ultimately found to
be due, Williston Basin plans to file with the FERC for recovery from
ratepayers.
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 electrical
generating station (Coyote Station), against the company (an owner of
a 25 percent interest in the Coyote Station) and Knife River. In its
complaint, the Co-owners have alleged a breach of contract against
Knife River of the long-term coal supply agreement (Agreement) between
the owners of the Coyote Station and Knife River. The Co-owners have
requested a determination by the State District Court of the pricing
mechanism to be applied to the Agreement and have further requested
damages during the term of such alleged breach on the difference
between the prices charged by Knife River and the prices that may
ultimately be determined by the State District Court. The Co-owners
also alleged a breach of fiduciary duties by the company as operating
agent of the Coyote Station, asserting essentially that the company
was unable to cause Knife River to reduce its coal price sufficiently
under the Agreement, and the Co-owners are seeking damages in an
unspecified amount. In January 1996, the company and Knife River
filed separate motions with the State District Court to dismiss or
stay, pending arbitration. In May 1996, the State District Court
granted the company's and Knife River's motions and stayed the suit
filed by the Co-owners pending arbitration, as provided for in the
Agreement.
In September 1996, the Co-owners notified the company and Knife River
of their demand for arbitration of the pricing dispute that had arisen
under the Agreement. The demand for arbitration, filed with the
American Arbitration Association (AAA), did not make any direct claim
against the company in its capacity as operator of the Coyote Station.
The Co-owners requested that the arbitrators make a determination that
the pricing dispute is not a proper subject for arbitration. By order
dated April 25, 1997, the arbitration panel concluded that the claims
raised by the Co-owners are arbitrable. The Co-owners have requested
the arbitrators to make a determination that the prices charged by
Knife River were excessive and that the Co-owners should be awarded
damages, based upon the difference between the prices that Knife River
charged and a "fair and equitable" price, of approximately $50 million
or more. Upon application by the company and Knife River, the AAA
administratively determined that the company was not a proper party
defendant to the arbitration, and the arbitration is proceeding
against Knife River. By letter dated May 14, 1997, Knife River
requested permission to move for summary judgment which permission was
granted by the arbitration panel over objections of the Co-owners.
Knife River filed its summary judgment motion on July 21, 1997, which
motion was denied on October 29, 1997. Although unable to predict the
outcome of the arbitration, Knife River and the company believe that
the Co-owners' claims are without merit and intend to vigorously
defend the prices charged pursuant to the Agreement.
For a description of litigation filed by Unitek Environmental
Services, Inc. and Unitek Solvent Services, Inc. against Hawaiian
Cement, see Environmental Matters.
The company is also involved in other legal actions in the ordinary
course of its business. Although the outcomes of any such legal
actions cannot be predicted, management believes that there is no
pending legal proceeding against or involving the company, except
those discussed above, for which the outcome is likely to have a
material adverse effect upon the company's financial position or
results of operations.
Environmental Matters
Montana-Dakota and Williston Basin discovered polychlorinated
biphenyls (PCBs) in portions of their natural gas systems and informed
the U.S. Environmental Protection Agency (EPA) in January 1991.
Montana-Dakota and Williston Basin believe the PCBs entered the system
from a valve sealant. In January 1994, Montana-Dakota, Williston
Basin and Rockwell International Corporation (Rockwell), manufacturer
of the valve sealant, reached an agreement under which Rockwell has
and will continue to reimburse Montana-Dakota and Williston Basin for
a portion of certain remediation costs. On the basis of findings to
date, Montana-Dakota and Williston Basin estimate future environmental
assessment and remediation costs will aggregate $3 million to $15
million. Based on such estimated cost, the expected recovery from
Rockwell and the ability of Montana-Dakota and Williston Basin to
recover their portions of such costs from ratepayers, Montana-Dakota
and Williston Basin believe that the ultimate costs related to these
matters will not be material to each of their respective financial
positions or results of operations.
In September 1995, Unitek Environmental Services, Inc. and Unitek
Solvent Services, Inc. (Unitek) filed a complaint against Hawaiian
Cement in the U.S. District Court for the District of Hawaii (District
Court) alleging that dust emissions from Hawaiian Cement's cement
manufacturing plant at Kapolei, Hawaii (Plant) violated the Hawaii
State Implementation Plan (SIP) of the U.S. Clean Air Act (Clean Air
Act), constituted a continual nuisance and trespass on the plaintiff's
property, and that Hawaiian Cement's conduct warranted the award of
punitive damages. Hawaiian Cement is a Hawaiian general partnership
whose general partners are now Knife River Hawaii, Inc. and Knife
River Dakota, Inc., indirect wholly owned subsidiaries of the company.
Knife River Dakota, Inc. purchased its partnership interest from
Adelaide Brighton Cement (Hawaii), Inc. on July 31, 1997. Unitek
sought civil penalties under the Clean Air Act (as described below),
and up to $20 million in damages for various claims (as described
above).
In August 1996, the District Court issued an order granting
Plaintiffs' motion for partial summary judgment relating to the Clean
Air Act, indicating that it would issue an injunction shortly. The
issue of civil penalties under the Clean Air Act was reserved for
further hearing at a later date, and Unitek's claims for damages were
not addressed by the District Court at such time.
In September 1996, Unitek and Hawaiian Cement reached a settlement
which resolved all claims except as to Clean Air Act penalties. Based
on a joint petition filed by Unitek and Hawaiian Cement, the District
Court stayed the proceeding and the issuance of an injunction while
the parties continued to negotiate the remaining Clean Air Act claims.
In May 1996, the EPA issued a Notice of Violation (NOV) to Hawaiian
Cement. The NOV stated that dust emissions from the Plant violated
the SIP. Under the Clean Air Act, the EPA has the authority to issue
an order requiring compliance with the SIP, issue an administrative
order requiring the payment of penalties of up to $25,000 per day per
violation (not to exceed $200,000), or bring a civil action for
penalties of not more than $25,000 per day per violation and/or bring
a civil action for injunctive relief.
On April 7, 1997, a settlement resolving the remaining Clean Air Act
claims and the EPA's NOV issued in May 1996, was reached by Hawaiian
Cement, the EPA and Unitek. This settlement is subject to public
comment and the approval of the District Court.
If the District Court approves the April 1997 settlement, the total
costs relating to both the September 1996 and April 1997 settlements
are not expected to have a material effect on the company's results of
operations.
Electric Purchased Power Commitments
Montana-Dakota has contracted to purchase through October 31, 2006,
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 5
Natural Gas in Underground Storage
Natural gas in underground storage included in natural gas
transmission and natural gas distribution property, plant and
equipment amounted to approximately $43.1 million at December 31,
1997, and $42.3 million at December 31, 1996. In addition,
$11.4 million and $7.2 million at December 31, 1997 and 1996,
respectively, of natural gas in underground storage is included in
inventories.
NOTE 6
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:
1997 1996
(In thousands)
Regulatory assets:
Natural gas contract settlement
and restructuring costs $ --- $ 4,960
Long-term debt refinancing costs 11,466 13,520
Postretirement benefit costs 2,940 3,849
Plant costs 3,173 3,341
Other 10,899 7,890
Total regulatory assets 28,478 33,560
Regulatory liabilities:
Reserves for regulatory matters 39,193 59,277
Natural gas costs refundable
through rate adjustments 21,721 1,499
Taxes refundable to customers 13,933 12,868
Plant decommissioning costs 5,843 5,301
Other 1,393 2,433
Total regulatory liabilities 82,083 81,378
Net regulatory position $(53,605) $(47,818)
As of December 31, 1997, 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 19 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 7
Financial Instruments
Derivatives
The company, in connection with the operations of Montana-Dakota,
Williston Basin and Fidelity Oil, has entered into certain price swap
and collar agreements (hedge agreements) to manage a portion of the
market risk associated with fluctuations in the price of oil and
natural gas. These hedge agreements are not held for trading
purposes. The hedge 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 hedge agreements. The variable price is either an oil price
quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural
gas price on the NYMEX or Colorado Interstate Gas Index. The company
believes that there is a high degree of correlation because the timing
of purchases and production and the hedge agreements are closely
matched, and hedge prices are established in the areas of the
company's operations. Amounts payable or receivable on hedge
agreements are matched and reported in operating revenues on the
Consolidated Statements of Income as a component of the related
commodity transaction at the time of settlement with the counterparty.
The amounts payable or receivable are offset by corresponding
increases and decreases in the value of the underlying commodity
transactions.
Williston Basin and Knife River have entered into interest rate
swap agreements to manage a portion of their interest rate exposure on
the natural gas repurchase commitment and long-term debt,
respectively. These interest rate swap agreements are not held for
trading purposes. The interest rate swap agreements call for the
company to receive quarterly payments from or make payments to
counterparties based upon the difference between fixed and variable
rates as specified by the interest rate swap agreements. The variable
prices are based on the three-month floating London Interbank Offered
Rate. Settlement amounts payable or receivable under these interest
rate swap agreements are recorded in "Interest expense" for Knife
River and "Costs on natural gas repurchase commitment" for Williston
Basin on the Consolidated Statements of Income in the accounting
period they are incurred. The amounts payable or receivable are
offset by interest on the related debt instruments.
The company's policy prohibits the use of derivative instruments for
trading purposes and the company has procedures in place to monitor
their use. The company is exposed to credit-related losses in the
event of nonperformance by counterparties to these financial
instruments, but does not expect any counterparties to fail to meet
their obligations given their existing credit ratings.
The following table summarizes the company's hedging activity:
Years ended December 31, 1997 1996 1995
(Notional amounts in thousands)
Oil swap/collar agreements:*
Range of fixed prices
per barrel $19.77-$21.36 $18.74-$19.07 $17.75-$20.75
Notional amount
(in barrels) 730 635 260
Natural gas swap/collar agreements:*
Range of fixed prices
per MMBtu $1.30-$2.395 $1.40-$2.05 $1.70-$1.85
Notional amount
(in MMBtu's) 8,039 5,331 644
Natural gas collar agreement:**
Fixed price per MMBtu --- $1.22-$1.52 $1.22-$1.52
Notional amount (in MMBtu's) --- 910 2,750
Interest rate swap agreements:**
Range of fixed
interest rates 5.50%-6.50% 5.50%-6.50% 5.97%
Notional amount (in dollars) $30,000 $30,000 $20,000
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The following table summarizes swap agreements outstanding at
December 31, 1997 (notional amounts in thousands):
Notional
Fixed Price Amount
Year (Per barrel) (In barrels)
Oil swap agreements* 1998 $20.92 219
Range of Notional
Fixed Prices Amount
Year (Per MMBtu) (In MMBtu's)
Natural gas swap agreements* 1998 $2.10-$2.67 4,370
Notional
Range of Fixed Amount
Year Interest Rates (In dollars)
Interest rate swap agreements** 1998 5.50%-6.50% $10,000
* Receive fixed -- pay variable
** Receive variable -- pay fixed
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 oil and natural gas hedge agreements will be offset by
corresponding increases and decreases in the value of the underlying
commodity transactions. Favorable and unfavorable positions on
interest rate swap agreements will be offset by interest on the
related debt instruments. The company's net favorable position on all
swap and collar agreements outstanding at December 31, 1997, was
$1.2 million. In the event a hedge agreement does not qualify for
hedge accounting or when the underlying commodity transaction or
related debt instrument matures, is sold, is extinguished, or is
terminated, the current favorable or unfavorable position on the open
contract would be included in results of operations. The company's
policy requires approval to terminate a hedge agreement prior to its
original maturity. In the event a hedge agreement is terminated, the
realized gain or loss at the time of termination would be deferred
until the underlying commodity transaction or related debt instrument
is sold or matures and would be offset by corresponding increases or
decreases in the value of the underlying commodity transaction or
interest on the related debt instrument.
Fair Value of Other Financial Instruments
The estimated fair value of the company's long-term debt and preferred
stocks are based on quoted market prices of the same or similar
issues. The estimated fair value of the company's long-term debt and
preferred stocks at December 31 are as follows:
1997 1996
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $306,363 $319,367 $292,420 $298,592
Preferred stocks $ 16,800 $ 12,103 $ 16,900 $ 10,762
The fair value of other financial instruments for which estimated fair
values have not been presented is not materially different than the
related book value.
NOTE 8
Short-term Borrowings
The company and its subsidiaries had unsecured short-term lines of
credit from a number of banks totaling $120.4 million at December 31,
1997. 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 under the lines of credit were $3.3 million at
December 31, 1997, and $4.0 million at December 31, 1996. The
weighted average interest rate for borrowings outstanding at
December 31, 1997 and 1996, was 8.50 percent and 7.25 percent,
respectively. The unused portions of the lines of credit are subject
to withdrawal based on the occurrence of certain events.
NOTE 9
Common Stock
In August 1995, the company's Board of Directors approved a three-for-
two common stock split to be effected in the form of a 50 percent
common stock dividend. The additional shares of common stock were
distributed on October 13, 1995, to common stockholders of record on
September 27, 1995.
The company's Automatic Dividend Reinvestment and Stock Purchase Plan
(DRIP) provides participants in the DRIP the opportunity to invest all
or a portion of their cash dividends in shares of the company's common
stock and/or to make optional cash payments of up to $5,000 per month
for the same purpose. Holders of all classes of the company's capital
stock and other investors who are domiciled in the states of North
Dakota, South Dakota, Montana or Wyoming, are eligible to participate
in the DRIP. The company's Tax Deferred Compensation Savings Plans
(K-Plans) pursuant to Section 401(k) of the Internal Revenue Code are
funded with the company's common stock. Since January 1, 1989, the
DRIP and K-Plans have been funded by the purchase of shares of common
stock on the open market except for a portion of 1997, where shares of
authorized but unissued common stock were used to fund the DRIP and
K-Plans. At December 31, 1997, there were 5,547,331 shares of common
stock reserved for issuance under the DRIP and K-Plans.
In November 1988, the company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) on each outstanding share of the company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for one one-hundred and fiftieth of a share of Series
A preference stock, without par value, at an exercise price of $33.33
per one one-hundred and fiftieth, 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 20
percent or more of the company's common stock or commences a tender or
exchange offer that would result in ownership of 30 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-hundredths of a
Series A preference share 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 in November 1998, are redeemable in whole, but not in
part, for a price of $.01333 per right, at the company's option at any
time until any acquiring person has acquired 20 percent or more of the
company's common stock. Preference share purchase rights have been
appropriately adjusted to reflect the effects of the common stock
split discussed above.
NOTE 10
Preferred Stocks
Preferred stocks at December 31 are as follows:
1997 1996
(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 requirements --
Preferred --
5.10% Series -- 18,000 shares in 1997
(19,000 shares in 1996) $ 1,800 $ 1,900
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 16,800 16,900
Less current maturities and
sinking fund requirements 100 100
Net preferred stocks $16,700 $16,800
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% $105.00 (b) --- ---
4.70% $102.00 (b) --- ---
5.10% $102.00 1,000 (c) $100.00
(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 requirements for each of the five
years following December 31, 1997, is $100,000.
NOTE 11
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
1997 1996
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, due May 15, 2006 $ 20,000 $ 25,000
9 1/8% Series, paid in 1997 --- 20,000
Pollution Control Refunding Revenue
Bonds, Series 1992 --
Mercer County, North Dakota,
6.65%, due June 1, 2022 15,000 15,000
Morton County, North Dakota,
6.65%, due June 1, 2022 2,600 2,600
Richland County, Montana,
6.65%, due June 1, 2022 3,250 3,250
Secured Medium-Term Notes,
Series A --
7.20%, paid in 1997 --- 5,000
6.52%, due October 1, 2004 15,000 ---
8.25%, due April 1, 2007 30,000 30,000
6.71%, due October 1, 2009 15,000 ---
8.60%, due April 1, 2012 35,000 35,000
Total first mortgage bonds
and notes 135,850 135,850
Pollution control lease and
note obligation, 6.20%, due
March 1, 2004 3,700 4,000
Senior notes:
8.43%, due December 31, 2000 12,000 15,000
8.70%, due March 31, 2002 6,500 ---
7.35%, due July 31, 2002 5,000 5,000
7.51%, due October 9, 2003 3,000 3,000
6.86%, due October 30, 2004 12,500 ---
7.45%, due May 31, 2006 20,000 20,000
7.60%, due November 3, 2008 15,000 15,000
7.10%, due October 30, 2009 12,500 ---
7.28%, due October 30, 2012 10,000 ---
Revolving lines of credit:
8.50%, expires December 31, 2002 18,000 30,000
Other revolving lines of credit at
rates ranging from 6.34% to
7.25%, expiring on dates
ranging from May 30, 2000, through
October 6, 2001 46,000 61,800
Term credit facilities:
7.70%, due December 1, 2003 1,331 1,556
7.90%, due September 24, 2002 1,764 ---
Other term credit facilities at
rates ranging from 7.24% to 11.25%,
due on dates ranging from February 21,
1999, through April 4, 2002 3,303 1,308
Other (85) (94)
Total long-term debt 306,363 292,420
Less current maturities and sinking
fund requirements 7,802 11,754
Net long-term debt $298,561 $280,666
Under the revolving lines of credit, the company and its subsidiaries
have $160 million available, $64 million of which was outstanding at
December 31, 1997. The amounts of scheduled long-term debt maturities
and sinking fund requirements for the five years following
December 31, 1997, aggregate $7.8 million in 1998; $15.2 million in
1999; $53.8 million in 2000; $14.2 million in 2001 and $33.3 million
in 2002. Substantially all of the company's electric and natural gas
distribution properties, with certain exceptions, are subject to the
lien of its Indenture of Mortgage. Under the terms and conditions of
such Indenture, the company could have issued approximately
$259 million of additional first mortgage bonds at December 31, 1997.
Certain of the company's other debt instruments contain restrictive
covenants all of which the company is in compliance with at December
31, 1997.
NOTE 12
Income Taxes
Income tax expense is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Current:
Federal $15,427 $12,617 $20,259
State 2,362 3,272 3,801
Foreign 60 60 369
17,849 15,949 24,429
Deferred:
Investment tax credit -- net (1,150) (1,099) (1,028)
Income taxes --
Federal 11,844 1,139 (564)
State 2,200 120 220
Foreign --- (22) ---
12,894 138 (1,372)
Total income tax expense $30,743 $16,087 $23,057
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at
December 31 are as follows:
1997 1996
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 32,789 $ 38,404
Natural gas available under
repurchase commitment 4,821 10,521
Accrued pension costs 8,445 7,814
Deferred investment tax credits 2,714 3,160
Accrued land reclamation 3,184 3,604
Other 12,851 13,499
Total deferred tax assets 64,804 77,002
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 123,629 121,763
Basis differences on oil and
natural gas producing properties 30,726 30,361
Natural gas contract settlement and
restructuring costs --- 1,926
Long-term debt refinancing costs 4,672 4,688
Other 8,168 8,461
Total deferred tax liabilities 167,195 167,199
Net deferred income tax liability $(102,391) $(90,197)
The following table reconciles the change in the net deferred income
tax liability from December 31, 1996, to December 31, 1997, to the
deferred income tax expense included in the Consolidated Statements of
Income:
1997
(In thousands)
Net change in deferred income tax
liability from the preceding table $12,194
Change in tax effects of income tax-related
regulatory assets and liabilities 1,741
Deferred taxes associated with acquisitions 109
Deferred income tax expense for the period $14,044
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:
1997 1996 1995
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $29,876 35.0 $21,545 35.0 $22,642 35.0
Increases (reductions)
resulting from:
Depletion allowance (828) (1.0) (1,070) (1.7) (1,346) (2.1)
State income
taxes -- net of
federal income tax
benefit 3,473 4.1 2,770 4.5 2,492 3.9
Investment tax credit
amortization (1,150) (1.4) (1,099) (1.8) (1,028) (1.6)
Tax reserve adjustment --- --- (6,600) (10.7) --- ---
Other items (628) (.7) 541 .8 297 .4
Actual taxes $30,743 36.0 $16,087 26.1 $23,057 35.6
In 1996, the company reached a settlement with the Internal Revenue
Service concerning notices of deficiency issued in connection with
disputed items for the 1983 through 1988 tax years and, in 1997,
reached a similar settlement for the tax years 1989 through 1991. In
1996, the company reflected the effects of the 1996 settlement and the
1997 anticipated settlement and, in addition, reversed reserves which
had previously been provided and were deemed to be no longer required.
NOTE 13
Business Segment Data
The company's operations are conducted through five business segments.
The electric, natural gas distribution, natural gas transmission,
construction materials and mining, and oil and natural gas production
businesses are substantially all located within the United States. A
description of these segments and their primary operations is
presented on the inside front cover of this Annual Report to
Stockholders and Item 1 of the Annual Report on Form 10-K.
Segment operating information at December 31, 1997, 1996 and 1995, is
presented in the Consolidated Statements of Income. Depreciation,
depletion and amortization by segment is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Electric $17,771 $ 17,053 $ 16,361
Natural gas distribution 7,013 6,880 6,719
Natural gas transmission 5,550 6,748 6,940
Construction materials
and mining 10,999 6,974 6,199
Oil and natural gas production 24,434 24,996 18,606
Total depreciation, depletion
and amortization $65,767 $ 62,651 $ 54,825
Segment investment information included in the accompanying
Consolidated Balance Sheets at December 31 is as follows:
1997 1996
(In thousands)
Identifiable assets:
Electric (a) $ 326,615 $ 313,815
Natural gas distribution (a) 128,517 120,645
Natural gas transmission (a) 227,030 276,843
Construction materials
and mining 235,221 171,283
Oil and natural gas
production 162,785 161,647
Total identifiable assets 1,080,168 1,044,233
Corporate assets (b) 33,724 44,940
Total consolidated assets $1,113,892 $1,089,173
(a) Includes, in the case of electric and natural gas distribution
property, allocations of common utility property. Natural gas stored
or available under repurchase commitment, as applicable, is included
in natural gas distribution and transmission identifiable assets.
(b) 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.
Approximately 3 percent of construction materials and mining revenues
in 1997 (4 percent in 1996 and 1995) represent Knife River's direct
sales of lignite coal to the company. The company's share of Knife
River's 1997 sales for use at the Coyote Station, a generating station
jointly owned by the company and other utilities, was approximately
3 percent and 5 percent of construction materials and mining revenues
in 1997 and 1996, respectively. In 1995, the company's share of Knife
River's sales for use at the Coyote Station and the Big Stone Station,
another generating station jointly owned by the company and other
utilities, was 7 percent of construction materials and mining
revenues.
In April 1996, KRC Holdings, Inc. (KRC Holdings), a wholly owned
subsidiary of Knife River, purchased Baldwin Contracting Company, Inc.
(Baldwin) of Chico, California. Baldwin is a major supplier of
aggregate, asphalt and construction services in the northern
Sacramento Valley and adjacent Sierra Nevada Mountains of northern
California. Baldwin also provides a variety of construction services,
primarily earth moving, grading and road and highway construction and
maintenance.
In June 1996, KRC Holdings purchased the assets of Medford Ready-Mix
Concrete, Inc. located in Medford, Oregon. The acquired company
serves the residential and small commercial construction market with
ready-mixed concrete and aggregates.
On February 14, 1997, Baldwin purchased the physical assets of Orland
Asphalt located in Orland, California, including a hot-mix plant and
aggregate reserves. Orland Asphalt was combined with and operates as
part of Baldwin.
On July 1, 1997, the company acquired two electric services companies,
International Line Builders, Inc. and High Line Equipment, Inc., both
located in Portland, Oregon. International Line Builders, Inc.
installs and repairs transmission and distribution power lines in the
western United States and Hawaii and High Line Equipment, Inc.
provides related construction supplies and equipment.
On July 31, 1997, Knife River purchased the 50 percent interest in
Hawaiian Cement, that it did not previously own, from Adelaide
Brighton Cement (Hawaii), Inc. of Adelaide, Australia. The company's
initial 50 percent partnership interest in Hawaiian Cement was
acquired in September 1995. See Note 15 for more discussion on this
partnership investment.
Pro forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not material
to the company's financial position or results of operations.
NOTE 14
Employee Benefit Plans
The company has noncontributory defined benefit pension plans covering
most full-time employees. Pension benefits are based primarily on
employee's years of service and earnings. The company makes annual
contributions to the plans consistent with the funding requirements of
federal law and regulations.
Pension expense is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Service cost/benefits earned during
the year $ 3,889 $ 3,852 $ 3,538
Interest cost on projected benefit
obligation 11,651 10,823 10,784
Return on plan assets (38,273) (24,972) (37,185)
Net amortization and deferral 23,109 11,494 24,407
Special termination benefit cost --- --- 853
Total pension costs 376 1,197 2,397
Less amounts capitalized 70 131 184
Total pension expense $ 306 $ 1,066 $ 2,213
The funded status of the company's plans at December 31 is summarized
as follows:
1997 1996
(In thousands)
Projected benefit obligation:
Vested $141,951 $122,119
Nonvested 6,204 3,923
Accumulated benefit obligation 148,155 126,042
Provision for future pay increases 30,044 24,787
Projected benefit obligation 178,199 150,829
Plan assets at market value 225,201 185,872
(47,002) (35,043)
Plus:
Unrecognized transition asset 6,333 7,336
Unrecognized net gains and prior service costs 48,788 35,848
Accrued pension costs $ 8,119 $ 8,141
The projected pension benefit obligation was determined using the
following assumptions:
1997 1996
Discount rate 7.00% 7.50%
Assumed compensation increase 4.50% 4.50%
Assumed long-term rate of
return on plan assets 8.00%-8.50% 8.50%
The change in these assumptions had the effect of increasing the
projected benefit obligation at December 31, 1997, by $12 million.
Plan assets consist primarily of debt and equity securities.
In addition to providing pension benefits, the company has a policy of
providing all eligible employees and dependents certain other
postretirement benefits which include health care and life insurance
upon their retirement. 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.
Postretirement benefits expense is summarized as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Service cost/benefits earned during
the year $ 1,272 $ 1,333 $ 1,226
Interest cost on accumulated
postretirement benefit obligation 4,691 4,701 4,777
Return on plan assets (5,380) (2,491) (183)
Amortization of transition obligation 2,458 2,458 2,458
Net amortization and deferral 3,527 1,260 (719)
Total postretirement benefits cost 6,568 7,261 7,559
Less amounts capitalized 625 735 442
Total postretirement benefits expense $ 5,943 $ 6,526 $ 7,117
The funded status of the company's plans at December 31 is summarized
as follows:
1997 1996
(In thousands)
Accumulated postretirement benefit
obligation:
Retirees eligible for benefits $ 44,876 $40,775
Active employees fully eligible for benefits 1,646 ---
Active employees not fully eligible 27,316 24,833
Total 73,838 65,608
Plan assets at market value 30,595 21,712
43,243 43,896
Less:
Unrecognized transition obligation 36,864 39,322
Unrecognized net loss (gain) (2,679) 3,693
Accrued postretirement benefits cost $ 9,058 $ 881
The accumulated postretirement benefit obligation was determined using
the following assumptions:
1997 1996
Discount rate 7.00% 7.50%
Compensation increase as it applies to
life insurance benefits 4.50% 4.50%
Long-term rate of return on plan assets 7.50% 7.50%
Health care cost trend rate 7.00%-9.00% 9.00%
Health care cost trend rate -- ultimate 5.00%-6.00% 6.00%
Year in which ultimate trend rate achieved 1999-2004 1999
The change in these assumptions had the effect of increasing the
accumulated postretirement benefit obligation at December 31, 1997, by
$5 million.
The health plan cost trend rate assumption has a significant effect on
the amounts reported. To illustrate, increasing the assumed health
plan cost trend rates by 1 percent each year would increase the
accumulated postretirement benefit obligation as of December 31, 1997,
by $3.8 million and the aggregate of the service and interest cost
components of postretirement benefits expense by $239,000. Plan
assets consist primarily of certain life insurance products of which
the return depends on the performance of underlying debt and equity
securities. The company's policy with respect to most plans is to
fund the annual expense amount. One subsidiary of KRC Holdings has a
policy to fund postretirement benefits on a cash basis.
The company has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that provides for
defined benefit payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period. Investments consist of
life insurance carried on plan participants which is payable to the
company upon the employee's death. The cost of these benefits was
$2.2 million in both 1997 and 1996 and $1.9 million in 1995.
The company has a Key Employee Stock Option Plan (KESOP). The company
accounts for the KESOP in accordance with APB Opinion No. 25 under
which no compensation expense has been recognized. Under the KESOP
the option price equals the market value of the stock on the date of
grant. Options automatically vest after nine years, but the KESOP
provides for accelerated vesting based upon the attainment of certain
performance goals or upon a change in control of the company. The
options expire 10 years after the date of grant. The company also
adopted a Non-Employee Director Option Plan (Director Plan) and an
Executive Long-Term Incentive Plan (Executive Plan) in 1997. Under
the KESOP, Director Plan and Executive Plan, the company is authorized
to grant options for up to 2.6 million shares of common stock and has
granted options on 490,473 shares through December 31, 1997.
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 $51,400 in 1997 and $48,000 in both 1996 and
1995. On a pro forma basis, there would have been no effect on
reported basic earnings per share for 1997, 1996 and 1995. There
would have been no effect on reported diluted earnings per share in
1997 and 1995, however diluted earnings per share would have been
reduced on a pro forma basis by $.01 in 1996. Since SFAS No. 123 does
not require this accounting to be applied to options granted prior to
January 1, 1995, the resulting pro forma compensation costs may not be
representative of that to be expected in future years.
A summary of the status of the KESOP and Director Plan at December 31,
1997, 1996 and 1995, and changes during the years then ended are as
follows:
1997 1996 1995
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at
beginning
of year 423,977 $17.66 468,737 $17.48 192,284 $15.82
Granted 15,000 24.56 --- --- 294,956 18.50
Forfeited (9,067) 17.11 --- --- (2,700) 20.83
Exercised (33,790) 15.75 (44,760) 15.75 (15,803) 15.75
Balance at end
of year 396,120 18.10 423,977 17.66 468,737 17.48
Exercisable at
end of year 74,974 $17.51 93,764 $15.75 138,524 $15.75
Exercise prices on options outstanding at December 31, 1997, range
from $15.75 to $24.56 with a weighted average remaining contractual
life of approximately 7 years.
The weighted average fair value of each option granted in 1997 and
1995 is $3.13 and $2.67, respectively. The fair value of each option
is estimated on the date of grant using the Black-Scholes option
pricing model. The assumptions used to estimate the fair value of
options granted in 1997 and 1995 were a risk-free interest rate of
6.60 percent and 7.80 percent, respectively, an expected dividend
yield of 5.48 percent and 5.80 percent, respectively, an expected life
of 7 years and 10 years, respectively, and expected volatility of
14.51 percent and 15.80 percent, respectively.
The company has Tax Deferred Compensation Savings Plans for eligible
employees. Generally each participant may contribute amounts up to 15
percent of eligible compensation, subject to certain limitations. The
company contributes an amount equal to 50 percent of the participant's
savings contribution up to a maximum of 6 percent of such
participant's contribution. Company contributions were $2.1 million
in 1997 and $1.9 million in both 1996 and 1995.
NOTE 15
Partnership Investment
In September 1995, KRC Holdings 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, on July 31, 1997. Hawaiian Cement is a
partnership headquartered in Honolulu, Hawaii, and is one of the
largest construction materials suppliers in Hawaii, serving four of
the islands. Hawaiian Cement's operations include construction
aggregate mining, ready-mixed concrete and cement manufacturing and
distribution.
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 original 50 percent
investment is included in "Investments" in the accompanying
Consolidated Balance Sheets at December 31, 1996, while its share of
operating results for the seven months ended July 31, 1997, the year
ended December 31, 1996, and the four months ended December 31, 1995,
is included in "Other income -- net" in the accompanying Consolidated
Statements of Income for the years ended December 31, 1997, 1996 and
1995, respectively. Summarized financial information for Hawaiian
Cement, when accounted for by the equity method, includes: current
assets; net property, plant and equipment; current liabilities; and,
other liabilities, as of December 31, 1996, (in millions) of $17.3,
$52.3, $10.1 and $15.0, respectively. Operating results for the seven
months ended July 31, 1997, for the year ended December 31, 1996, and
for the four months ended December 31, 1995, (in millions) were net
sales of $33.5, $70.1 and $24.4; operating margin of $4.7, $9.9 and
$5.1; and income before income taxes of $2.0, $5.4 and $2.8,
respectively.
NOTE 16
Jointly Owned Facilities
The consolidated financial statements include the company's 22.70
percent and 25 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:
1997 1996
(In thousands)
Big Stone Station:
Utility plant in service $ 49,467 $ 48,907
Accumulated depreciation 27,971 26,676
$ 21,496 $ 22,231
Coyote Station:
Utility plant in service $121,604 $122,320
Accumulated depreciation 53,107 52,721
$ 68,497 $ 69,599
NOTE 17
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1997 and 1996:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
1997
Operating revenues $139,811 $125,380 $163,699 $178,784
Operating expenses 109,055 106,932 134,675 145,451
Operating income 30,756 18,448 29,024 33,333
Net income 14,597 8,741 14,195 17,084
Earnings per common share:
Basic .50 .30 .48 .58
Diluted .50 .30 .48 .58
1996
Operating revenues $126,529 $110,213 $133,759 $144,200
Operating expenses 98,447 90,012 103,038 111,679
Operating income 28,082 20,201 30,721 32,521
Net income 13,135 8,600 8,495 15,240
Earnings per common share:
Basic .45 .30 .29 .53
Diluted .45 .30 .29 .53
Certain company operations are highly seasonal and revenues from and
certain expenses for such operations may fluctuate significantly among
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 18
Oil and Natural Gas Activities (Unaudited)
Fidelity Oil is involved in the acquisition, exploration, development
and production of oil and natural gas properties. Fidelity's
operations vary from the acquisition of producing properties with
potential development opportunities to exploration and are located
throughout the United States, the Gulf of Mexico and Canada. Fidelity
Oil shares revenues and expenses from the development of specified
properties in proportion to its interests.
Williston Basin owns in fee or holds natural gas leases and operating
rights primarily applicable to the shallow rights (above 2,000 feet)
in the Cedar Creek Anticline in southeastern Montana and to all rights
in the Bowdoin area located in north-central Montana.
The following information includes the company's proportionate share
of all its oil and natural gas interests held by both Fidelity Oil and
Williston Basin.
The following table sets forth capitalized costs and accumulated
depreciation, depletion and amortization related to oil and natural
gas producing activities at December 31:
1997 1996 1995
(In thousands)
Subject to amortization $252,291 $223,409 $173,501
Not subject to amortization 9,408 6,792 8,831
Total capitalized costs 261,699 230,201 182,332
Accumulated depreciation, depletion
and amortization 95,611 71,554 49,498
Net capitalized costs $166,088 $158,647 $132,834
Net capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities are as follows:
Years ended December 31, 1997 1996 1995
(In thousands)
Acquisitions $ 59 $23,284 $ 9,159
Exploration 13,344 8,101 7,678
Development 18,874 19,979 24,955
Net capital expenditures $32,277 $51,364 $41,792
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, 1997 1996 1995
(In thousands)
Revenues* $77,756 $75,335 $53,484
Production costs 23,251 21,296 16,888
Depreciation, depletion and
amortization 24,864 25,629 19,058
Pretax income 29,641 28,410 17,538
Income tax expense 10,968 10,875 6,397
Results of operations for
producing activities $18,673 $17,535 $11,141
* Includes $9.4 million, $7.0 million and $4.7 million of revenues
for 1997, 1996 and 1995, respectively, related to Williston Basin's
natural gas production activities which are included in "Natural gas"
operating revenues in the Consolidated Statements of Income.
The following table summarizes the company's estimated quantities of
proved oil and natural gas reserves at December 31, 1997, 1996 and
1995, 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.
1997 1996 1995
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 16,100 200,200 14,200 179,000 12,500 154,200
Production (2,100) (20,400) (2,100) (20,400) (2,000) (17,500)
Extensions and
discoveries 600 12,100 600 27,000 1,800 23,800
Purchases of proved
reserves --- 200 2,900 9,900 1,100 6,700
Sales of reserves
in place (200) (2,300) (700) (3,700) (300) (200)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 500 (4,900) 1,200 8,400 1,100 12,000
Balance at end
of year 14,900 184,900 16,100 200,200 14,200 179,000
Proved developed reserves:
January 1, 1995 12,200 147,200
December 31, 1995 13,600 156,400
December 31, 1996 15,400 168,200
December 31, 1997 14,500 163,800
Virtually all of the company's interests in oil and natural gas
reserves are located in the continental United States. Reserve
interests at December 31, 1997, applicable to the company's $852,000
net investment in oil and natural gas properties located in Canada
comprise approximately 2 percent of the total reserves.
The standardized measure of the company's estimated discounted future
net cash flows of total proved reserves associated with its various
oil and natural gas interests at December 31 is as follows:
1997 1996 1995
(In thousands)
Future net cash flows before
income taxes $306,600 $580,300 $267,300
Future income tax expenses 86,600 194,200 76,100
Future net cash flows 220,000 386,100 191,200
10% annual discount for estimated
timing of cash flows 81,000 152,100 70,300
Discounted future net cash flows
relating to proved oil and natural
gas reserves $139,000 $234,000 $120,900
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1997 1996 1995
(In thousands)
Beginning of year $234,000 $120,900 $ 94,900
Net revenues from production (54,500) (54,000) (36,400)
Change in net realization (158,400) 125,800 26,300
Extensions, discoveries and improved
recovery, net of future
production-related costs 19,400 43,500 31,200
Purchases of proved reserves 200 49,600 10,900
Sales of reserves in place (2,800) (6,700) (1,000)
Changes in estimated future
development costs -- net of those
incurred during the year 7,700 (2,400) (8,900)
Accretion of discount 32,800 16,900 12,300
Net change in income taxes 62,100 (69,200) (17,100)
Revisions of previous quantity
estimates (1,300) 8,700 8,900
Other (200) 900 (200)
Net change (95,000) 113,100 26,000
End of year $139,000 $234,000 $120,900
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.
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, 1997 and 1996, 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, 1997. 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, 1997 and
1996, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
January 22, 1998
1997 1996 1995
Selected Financial Data
Operating revenues: (000's)
Electric $ 164,351 $ 138,761 $ 134,609
Natural gas 200,789 175,408 167,787
Construction materials and mining 174,147 132,222 113,066
Oil and natural gas production 68,387 68,310 48,784
$ 607,674 $ 514,701 $ 464,246
Operating income: (000's)
Electric $ 33,089 $ 29,476 $ 29,898
Natural gas distribution 10,410 11,504 6,917
Natural gas transmission 29,169 30,231 25,427
Construction materials and mining 14,602 16,062 14,463
Oil and natural gas production 24,291 24,252 13,871
$ 111,561 $ 111,525 $ 90,576
Earnings on common stock: (000's)
Electric $ 13,388 $ 11,436 $ 12,000
Natural gas distribution 4,514 4,892 1,604
Natural gas transmission 11,317 2,459 8,416
Construction materials and mining 10,111 11,521 10,819
Oil and natural gas production 14,505 14,375 8,002
Earnings on common stock
before cumulative effect of
accounting change 53,835 44,683 40,841
Cumulative effect of
accounting change --- --- ---
$ 53,835 $ 44,683 $ 40,841
Earnings per common share before
cumulative effect of accounting
change -- diluted $ 1.86 $ 1.57 $ 1.43
Cumulative effect of
accounting change --- --- ---
$ 1.86 $ 1.57 $ 1.43
Pro forma amounts assuming
retroactive application
of accounting change:
Net income (000's) $ 54,617 $ 45,470 $ 41,633
Earnings per common
share -- diluted $ 1.86 $ 1.57 $ 1.43
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 28,985 28,549 28,526
Dividends per common share $ 1.13 $ 1.10 $ 1.0782
Book value per common share $ 13.26 $ 12.31 $ 11.85
Market price per common
share (year end) $ 31.63 $ 23.00 $ 19.88
Market price ratios:
Dividend payout 61% 70% 76%
Yield 3.6% 4.8% 5.5%
Price/earnings ratio 17.0x 14.6x 13.9x
Market value as a percent
of book value 238.5% 186.8% 167.7%
Profitability Indicators
Return on average common equity 14.6% 13.0% 12.3%
Return on average invested capital 10.3% 9.5% 9.2%
Interest coverage 6.0x 5.4x 3.9x
Fixed charges coverage, including
preferred dividends 3.4x 2.7x 3.0x
General
Total assets (000's) $1,113,892 $1,089,173 $1,056,479
Net long-term debt (000's) $ 298,561 $ 280,666 $ 237,352
Redeemable preferred
stock (000's) $ 1,800 $ 1,900 $ 2,000
Capitalization ratios:
Common stockholders' equity 55% 54% 57%
Preferred stocks 2 3 3
Long-term debt 43 43 40
100% 100% 100%
1994 1993 1992
Selected Financial Data
Operating revenues: (000's)
Electric $ 133,953 $ 131,109 $ 123,908
Natural gas 160,970 178,981 159,438
Construction materials and mining 116,646 90,397 45,032
Oil and natural gas production 37,959 39,125 33,797
$ 449,528 $ 439,612 $ 362,175
Operating income: (000's)
Electric $ 27,596 $ 30,520 $ 30,188
Natural gas distribution 3,948 4,730 4,509
Natural gas transmission 21,281 20,108 21,331
Construction materials and mining 16,593 16,984 11,532
Oil and natural gas production 8,757 11,750 9,499
$ 78,175 $ 84,092 $ 77,059
Earnings on common stock: (000's)
Electric $ 11,719 $ 12,652* $ 13,302
Natural gas distribution 285 1,182* 1,370
Natural gas transmission 6,155 4,713 3,479
Construction materials and mining 11,622 12,359 10,662
Oil and natural gas production 9,267 7,109 5,751
Earnings on common stock
before cumulative effect of
accounting change 39,048 38,015* 34,564
Cumulative effect of
accounting change --- 5,521 ---
$ 39,048 $ 43,536 $ 34,564
Earnings per common share before
cumulative effect of accounting
change -- diluted $ 1.37 $ 1.34* $ 1.21
Cumulative effect of
accounting change --- .19 ---
$ 1.37 $ 1.53 $ 1.21
Pro forma amounts assuming
retroactive application
of accounting change:
Net income (000's) $ 39,845 $ 38,817 $ 35,852
Earnings per common
share -- diluted $ 1.37 $ 1.34 $ 1.23
Common Stock Statistics
Weighted average common shares
outstanding -- diluted (000's) 28,509 28,534 28,494
Dividends per common share $ 1.0533 $ 1.0133 $ .9733
Book value per common share $ 11.49 $ 11.17 $ 10.66
Market price per common
share (year end) $ 18.08 $ 21.00 $ 17.58
Market price ratios:
Dividend payout 77% 76%* 80%
Yield 5.9% 5.0% 5.6%
Price/earnings ratio 13.2x 15.8x* 14.5x
Market value as a percent
of book value 157.4% 188.0% 165.0%
Profitability Indicators
Return on average common equity 12.1% 12.3%* 11.6%
Return on average invested capital 9.1% 9.4%* 8.7%
Interest coverage 3.3x 3.4x* 3.3x
Fixed charges coverage, including
preferred dividends 2.8x 2.9x* 2.4x
General
Total assets (000's) $1,004,718 $1,041,051 $1,024,510
Net long-term debt (000's) $ 217,693 $ 231,770 $ 249,845
Redeemable preferred
stock (000's) $ 2,100 $ 2,200 $ 2,300
Capitalization ratios:
Common stockholders' equity 58% 56% 53%
Preferred stocks 3 3 3
Long-term debt 39 41 44
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the
accrual of estimated unbilled revenues.
1997 1996 1995
Electric Operations
Sales to ultimate consumers
(thousand kWh) 2,041,191 2,067,926 1,993,693
Sales for resale (thousand kWh) 361,954 374,535 408,011
Electric system generating and
firm purchase capability --
kW (Interconnected system) 487,500 481,800 472,400
Demand peak --
kW (Interconnected system) 404,600 393,300 412,700
Electricity produced (thousand kWh) 1,826,770 1,829,669 1,718,077
Electricity purchased (thousand kWh) 769,679 809,261 867,524
Cost of fuel and purchased
power per kWh $.018 $.017 $.016
Natural Gas Distribution Operations
Sales (Mdk) 34,320 38,283 33,939
Transportation (Mdk) 10,067 9,423 11,091
Weighted average degree days -- % of
previous year's actual 85% 114% 105%
Natural Gas Transmission Operations
Natural gas transmission:
Sales for resale (Mdk) --- --- ---
Transportation (Mdk) 85,464 82,169 68,015
Produced (Mdk) 6,949 6,073 4,981
Net recoverable reserves (MMcf) 127,300 133,400 113,000
Energy marketing:
Natural gas volumes (Mdk) 14,971 4,670 3,556
Propane (thousand gallons) 10,005 9,689 7,471
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 5,113 3,374 2,904
Asphalt (tons sold) 758 694 373
Ready-mixed concrete
(cubic yards sold) 516 340 307
Recoverable aggregate
reserves (tons) 169,375 119,800 68,000
Coal: (000's)
Sales (tons) 2,375 2,899 4,218
Recoverable reserves (tons) 226,560 228,900 231,900
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 2,088 2,149 1,973
Natural gas (MMcf) 13,192 14,067 12,319
Average sales prices:
Oil (per barrel) $ 17.50 $ 17.91 $ 15.07
Natural gas (per Mcf) $ 2.41 $ 2.09 $ 1.51
Net recoverable reserves:
Oil (000's of barrels) 14,900 16,100 14,200
Natural gas (MMcf) 57,600 66,800 66,000
1994 1993 1992
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,955,136 1,893,713 1,829,933
Sales for resale (thousand kWh) 444,492 510,987 352,550
Electric system generating and
firm purchase capability --
kW (Interconnected system) 470,900 465,200 460,200
Demand peak --
kW (Interconnected system) 369,800 350,300 339,100
Electricity produced (thousand kWh) 1,901,119 1,870,740 1,774,322
Electricity purchased (thousand kWh) 700,912 701,736 593,612
Cost of fuel and purchased
power per kWh $.017 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 31,840 31,147 26,681
Transportation (Mdk) 9,278 12,704 13,742
Weighted average degree days -- % of
previous year's actual 92% 115% 98%
Natural Gas Transmission Operations
Natural gas transmission:
Sales for resale (Mdk) --- 13,201 16,841
Transportation (Mdk) 63,870 59,416 64,498
Produced (Mdk) 4,732 3,876 3,551
Net recoverable reserves (MMcf) 99,300 --- ---
Energy marketing:
Natural gas volumes (Mdk) 7,301 6,827 3,292
Propane (thousand gallons) 6,462 2,210 ---
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 2,688 2,391 263
Asphalt (tons sold) 391 141 ---
Ready-mixed concrete
(cubic yards sold) 315 157 ---
Recoverable aggregate
reserves (tons) 71,000 74,200 20,600
Coal: (000's)
Sales (tons) 5,206 5,066 4,913
Recoverable reserves (tons) 236,100 230,600 235,700
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,565 1,497 1,531
Natural gas (MMcf) 9,228 8,817 5,024
Average sales prices:
Oil (per barrel) $ 13.14 $ 14.84 $ 16.74
Natural gas (per Mcf) $ 1.84 $ 1.86 $ 1.53
Net recoverable reserves:
Oil (000's of barrels) 12,500 11,200 12,200
Natural gas (MMcf) 54,900 50,300 37,200