1996 FINANCIAL REPORT
REPORT OF MANAGEMENT
The management of MDU Resource 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, careful 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, 1996 1995 1994
(In thousands, except per share amounts)
Operating Revenues
Electric $138,761 $134,609 $133,953
Natural gas 175,408 167,787 160,970
Construction materials and mining 132,222 113,066 116,646
Oil and natural gas production 68,310 48,784 37,959
514,701 464,246 449,528
Operating Expenses
Fuel and purchased power 43,983 41,769 43,203
Purchased natural gas sold 48,886 53,351 52,893
Operation and maintenance 225,682 202,327 203,269
Depreciation, depletion and
amortization 62,651 54,825 48,113
Taxes, other than income 21,974 21,398 23,875
403,176 373,670 371,353
Operating Income
Electric 29,476 29,898 27,596
Natural gas distribution 11,504 6,917 3,948
Natural gas transmission 30,231 25,427 21,281
Construction materials and mining 16,062 14,463 16,593
Oil and natural gas production 24,252 13,871 8,757
111,525 90,576 78,175
Other income -- net 5,617 4,789 10,480
Interest expense 28,832 24,690 25,350
Costs on natural gas repurchase
commitment (Note 3) 26,753 5,985 4,627
Income before income taxes 61,557 64,690 58,678
Income taxes 16,087 23,057 18,833
Net income 45,470 41,633 39,845
Dividends on preferred stocks 787 792 797
Earnings on common stock $ 44,683 $ 40,841 $ 39,048
Earnings per common share $ 1.57 $ 1.43 $ 1.37
Dividends per common share $ 1.1000 $ 1.0782 $ 1.0533
Average common shares outstanding 28,477 28,477 28,477
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1996 1995 1994
(In thousands)
ASSETS
Property, Plant and Equipment
Electric $ 546,477 $ 535,016 $ 514,152
Natural gas distribution 164,843 161,080 157,174
Natural gas transmission 273,775 271,773 263,971
Construction materials and mining 173,663 151,751 147,284
Oil and natural gas production 211,555 167,542 151,532
1,370,313 1,287,162 1,234,113
Less accumulated depreciation,
depletion and amortization 617,724 570,855 541,842
752,589 716,307 692,271
Current Assets
Cash and cash equivalents 47,799 33,398 37,190
Receivables 73,187 61,961 55,409
Inventories 27,361 23,949 27,090
Deferred income taxes 26,011 31,663 26,694
Prepayments and other
current assets 17,300 11,261 12,287
191,658 162,232 158,670
Natural gas available under
repurchase commitment (Note 3) 37,233 70,750 70,913
Investments (Note 16) 53,501 46,188 16,914
Deferred charges and other assets 54,192 61,002 65,950
$1,089,173 $1,056,479 $1,004,718
CAPITALIZATION AND LIABILITIES
Capitalization (See Separate
Statements)
Common stockholders' investment $ 350,674 $ 337,317 $ 327,183
Preferred stocks 16,800 16,900 17,000
Long-term debt 280,666 237,352 217,693
648,140 591,569 561,876
Commitments and contingencies
(Notes 2,3,4,13 and 15) --- --- ---
Current Liabilities
Short-term borrowings 3,950 600 680
Accounts payable 31,580 22,261 20,222
Taxes payable 8,683 13,566 8,817
Other accrued liabilities,
including reserved revenues 100,938 100,779 88,516
Dividends payable 8,099 7,958 7,793
Long-term debt and preferred
stock due within one year 11,854 17,087 20,450
165,104 162,251 146,478
Natural gas repurchase commitment
(Note 3) 66,294 88,200 88,404
Deferred credits:
Deferred income taxes 116,208 118,459 114,341
Other 93,427 96,000 93,619
209,635 214,459 207,960
$1,089,173 $1,056,479 $1,004,718
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
December 31, 1996 1995 1994
(In thousands)
Common Stockholders' Investment
Common stock (Note 9):
Authorized -- 75,000,000 shares,
$3.33 par value
Outstanding -- 28,476,981 shares
in 1996 and 1995,
and 18,984,654
shares in 1994 $ 94,828 $ 94,828 $ 63,219
Other paid in capital 64,305 64,305 95,914
Retained earnings (Note 10) 191,541 178,184 168,050
Total common stockholders'
investment 350,674 337,317 327,183
Preferred Stocks (Note 11)
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 -- 19,000 shares
in 1996 (20,000 in 1995 and
21,000 in 1994) 1,900 2,000 2,100
Other preferred stock --
4.50% Series -- 100,000 shares 10,000 10,000 10,000
4.70% Series -- 50,000 shares 5,000 5,000 5,000
15,000 15,000 15,000
Total preferred stocks 16,900 17,000 17,100
Less current maturities and
sinking fund requirements 100 100 100
Net preferred stocks 16,800 16,900 17,000
Long-term Debt (Note 12)
Total long-term debt 292,420 254,339 238,043
Less current maturities and sinking
fund requirements 11,754 16,987 20,350
Net long-term debt 280,666 237,352 217,693
Total capitalization $648,140 $591,569 $561,876
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1996 1995 1994
(In thousands)
Operating Activities
Net income $ 45,470 $ 41,633 $ 39,845
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion and
amortization 62,651 54,825 48,113
Deferred income taxes and
investment tax credit -- net 4,551 7,631 3,409
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 6,580 7,177 7,866
Write-down of natural gas available
under repurchase commitment, net
of income taxes (Note 3) 11,364 --- ---
Changes in current assets and
liabilities:
Receivables (9,346) (6,552) 12,144
Inventories (1,218) 3,141 (6,799)
Other current assets 4,185 (3,943) 7,524
Accounts payable 7,584 2,039 (4,745)
Other current liabilities (22,434) 17,177 (19,249)
Other noncurrent changes (3,149) (1,023) 6,133
Net cash provided by operating
activities 106,238 122,105 94,241
Financing Activities
Net change in short-term borrowings 3,350 (80) (8,860)
Issuance of long-term debt 81,300 36,710 26,750
Repayment of long-term debt (43,262) (20,433) (35,700)
Retirement of preferred stocks (100) (100) (100)
Retirement of natural gas
repurchase commitment (4,157) (204) (10,121)
Dividends paid (32,113) (31,499) (30,793)
Net cash provided by (used in)
financing activities 5,018 (15,606) (58,824)
Investing Activities
Capital expenditures including
acquisitions of businesses:
Electric (18,674) (19,689) (14,188)
Natural gas distribution (6,255) (8,878) (19,033)
Natural gas transmission (10,127) (9,688) (6,147)
Construction materials and mining (25,063) (36,810) (3,597)
Oil and natural gas production (51,821) (39,917) (38,595)
(111,940) (114,982) (81,560)
Net proceeds from sale or disposition
of property 11,803 2,802 3,572
Net capital expenditures (100,137) (112,180) (77,988)
Sale of natural gas available
under repurchase commitment 10,595 163 8,118
Investments (7,313) 1,726 (56)
Net cash used in investing
activities (96,855) (110,291) (69,926)
Increase (decrease) in cash
and cash equivalents 14,401 (3,792) (34,509)
Cash and cash equivalents --
beginning of year 33,398 37,190 71,699
Cash and cash equivalents --
end of year $ 47,799 $ 33,398 $ 37,190
The accompanying notes are an integral part of these consolidated statements.
NOTE 1
Statement of Principal 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 1996, 1995 and 1994.
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.
Investments
Investments consist principally of the company's partnership
investment in Hawaiian Cement. The company accounts for its
partnership investment in Hawaiian Cement by the equity method. See
Note 16 for more information on this partnership investment.
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.
See Note 3 for more information on a write-down of the natural gas
available under the repurchase commitment with Frontier which occurred
in 1996.
Inventories
Inventories, other than natural gas in underground storage, consist
primarily of materials and supplies and inventory 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. In
addition, the company recognizes revenue for its construction business
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 deferred credits" 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.
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, 1996 1995 1994
(In thousands)
Interest, net of amount capitalized $25,449 $24,436 $22,775
Income taxes $28,163 $18,330 $13,539
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 1995 and 1994 to conform to the 1996 presentation. Such
reclassifications had no effect on net income or common stockholders'
investment as previously reported.
New Accounting Standard
In October 1996, the American Institute of Certified Public
Accountants issued Statement of Position 96-1, "Environmental
Remediation Liabilities" (SOP 96-1). SOP 96-1 provides authoritative
guidance for the recognition, measurement, display and disclosure of
environmental remediation liabilities in financial statements. The
company will adopt SOP 96-1 on January 1, 1997, and the adoption is
not expected to have a material effect on the company's financial
position or results of operations.
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. In July 1995, the FERC issued
an order relating to Williston Basin's rate change application. In
August 1995, Williston Basin filed, under protest, tariff sheets in
compliance with the FERC's order, with rates which went into effect on
September 1, 1995. Williston Basin requested rehearing of certain
issues addressed in the order. On July 19, 1996, the FERC issued an
order granting in part and denying in part Williston Basin's rehearing
request. A hearing was held on August 29, 1996, and this matter is
currently pending before the FERC. In addition, Williston Basin has
appealed certain issues contained in the FERC's orders to the U.S.
Court of Appeals for the D.C. Circuit (D.C. Circuit Court).
Williston Basin anticipates filing briefs with the D.C. Circuit Court
on February 3, 1997, related to its appeal of orders which had been
received from the FERC beginning in May 1993, regarding the
appropriate selling price of certain natural gas in underground
storage which was determined to be excess upon Williston Basin's
implementation of Order 636. The FERC ordered that the gas be offered
for sale to Williston Basin's customers at its original cost.
Williston Basin requested rehearing of this matter on the grounds that
the FERC's order constituted a confiscation of its assets, which
request was subsequently denied by the FERC. Williston Basin believes
that it should be allowed to sell this natural gas at its fair value
and retain any profits resulting from such sales since its ratepayers
had never paid for the natural gas. Oral arguments on this matter
before the D.C. Circuit Court are scheduled for May 9, 1997.
Reserves have been provided for a portion of the revenues that have
been collected subject to refund with respect to pending regulatory
proceedings and for the recovery of certain producer settlement buy-
out/buy-down costs 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, 1996, borrowings
totalled $84.0 million at a weighted average interest rate of
6.13 percent of which $66.3 million is reflected on the company's
Consolidated Balance Sheets under "Natural gas repurchase commitment"
and $17.7 million is included in "Other accrued liabilities" and
relates to current amounts owed as a result of recent sales of a
portion of this natural gas. 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. On December 26, 1996, the D.C. Circuit Court 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.
Beginning in October 1992, as a result of prevailing natural gas
prices, Williston Basin began to sell and transport a portion of the
natural gas held under the repurchase commitment. Through the second
quarter of 1996, 17.8 MMdk of this natural gas had been sold.
However, 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 the remaining
43.0 MMdk of this gas to its then current market 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. The recognition of the then
current market value of this natural gas facilitated the sale by
Williston Basin of 10.5 MMdk from the date of this write-down through
December 31, 1996, and should allow Williston Basin to market the
remaining 32.5 MMdk on a sustained basis enabling Williston Basin to
liquidate this asset over approximately the next five 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 totalled approximately $19 million or, under its
alternative pricing theory, approximately $39 million.
On August 16, 1996, the Federal District Court issued its decision
finding that Moncrief is entitled to damages for the difference
between the price Moncrief would have received under the geographic
favored-nations price clause of the contract for the period from
August 13, 1993, through July 7, 1996, and the actual price received
for the gas. The favored-nations price is the highest price paid from
time to time under contracts in the same geographic region for natural
gas of similar quantity and quality. The Federal District Court
reopened the record until October 15, 1996, to receive additional
briefs and exhibits on this issue.
On October 15, 1996, Moncrief submitted its brief claiming damages
ranging as high as $22 million under the geographic favored-nations
price theory. Williston Basin, in its brief, contended that Moncrief
waived its claim for a favored-nations price under an agreement with
Williston Basin, and Moncrief's damage claims were calculated
utilizing non-comparable contracts. Williston Basin's exhibits show
Moncrief's damages should be limited to approximately $800,000 under
the geographic favored-nations price theory.
A hearing on all pending matters is currently scheduled for April 3,
1997. Williston Basin plans to file for recovery from ratepayers of
amounts which may be ultimately due to Moncrief, if any.
In December 1993, Apache Corporation (Apache) and Snyder Oil
Corporation (Snyder) filed suit in North Dakota District Court,
Northwest Judicial District, against Williston Basin and the company.
Apache and Snyder are oil and natural gas producers who 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. Williston Basin, the company and Koch have settled their
disputes. Apache and Snyder have recently provided alleged damages
under differing theories ranging up to $8.2 million without interest.
A motion to intervene in the case by several other producers, all of
whom had contracts with Koch but not with Williston Basin, was denied
on December 13, 1996. Trial on this matter is scheduled for
September 8, 1997.
The claims of Apache and Snyder, in Williston Basin's opinion, are
without merit and overstated. If any amounts are ultimately found to
be due Apache and Snyder, Williston Basin plans to file for recovery
from ratepayers.
On July 18, 1996, Jack J. Grynberg (Grynberg) filed suit in United
States District Court for the District of Columbia against Williston
Basin and over 70 other natural gas pipeline companies. Grynberg,
acting on behalf of the United States under the False Claims Act, is
alleging 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. The United States government,
particularly officials from the Departments of Justice and Interior,
reviewed the complaint and the evidence presented by Grynberg and
declined to intervene in the action, permitting Grynberg to proceed on
his own. Williston Basin believes Grynberg's claims are without merit
and intends to vigorously contest this suit.
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 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 as 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 are seeking damages in an unspecified amount.
On January 8, 1996, the company and Knife River filed separate motions
with the State District Court to dismiss or stay pending arbitration.
On May 6, 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.
On September 12, 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. In the alternative, the Co-owners 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, 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. 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. 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 United States Environmental Protection Agency (EPA) in
January 1991. Montana-Dakota and Williston Basin believe the PCBs
entered the system from a valve sealant. In January 1994, Montana-
Dakota, Williston Basin and Rockwell International Corporation
(Rockwell), manufacturer of the valve sealant, reached an agreement
under which Rockwell has 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 United States 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
payment of punitive damages. Hawaiian Cement is a Hawaiian general
partnership whose general partners (with joint and several liability)
are Knife River Hawaii, Inc., an indirect wholly owned subsidiary of
the company, and Adelaide Brighton Cement (Hawaii), Inc. Unitek is
seeking civil penalties under the Clean Air Act (as described below),
and had sought damages for various claims (as described above) of up
to $20 million in the aggregate.
On August 7, 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.
On September 16, 1996, Unitek and Hawaiian Cement reached a settlement
which resolved all claims relating to the $20 million in damages that
Unitek had previously sought. However, the settlement did not resolve
the matter regarding the civil penalties sought by Unitek relating to
the alleged violations by Hawaiian Cement of the Clean Air Act nor did
it affect the EPA's Notice of Violation (NOV) as discussed below.
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 continue to negotiate the remaining Clean Air Act
claims.
On May 7, 1996, the EPA issued a NOV to Hawaiian Cement. The NOV
states 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. It is also possible that the EPA could elect to
join the suit filed by Unitek. Depending upon the specific actions
that may ultimately be taken by either the EPA or the District Court,
Hawaiian Cement is likely to have to modify its operations at its
cement manufacturing facility. Hawaiian Cement has met with the EPA
and settlement discussions are currently ongoing.
Although no assurance can be provided, the company does not believe
that the total cost of any modifications to the facility, the level of
civil penalties which may ultimately be assessed or settlement costs,
will 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, up
to 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 $42.3 million at December 31,
1996, $42.1 million at December 31, 1995, and $45.2 million at
December 31, 1994. In addition, $7.2 million, $6.6 million and $6.9
million at December 31, 1996, 1995 and 1994, 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:
1996 1995 1994
(In thousands)
Regulatory assets:
Natural gas contract settlement
and restructuring costs $ 4,960 $ 15,275 $ 24,069
Long-term debt refinancing costs 13,520 11,082 12,228
Postretirement benefit costs 3,849 4,833 4,551
Plant costs 3,341 3,509 3,678
Other 7,890 7,091 4,664
Total regulatory assets 33,560 41,790 49,190
Regulatory liabilities:
Reserves for regulatory matters 59,277 58,277 49,427
Natural gas costs refundable
through rate adjustments 1,499 21,192 14,878
Taxes refundable to customers 12,868 12,531 12,229
Plant decommissioning costs 5,301 4,777 4,290
Other 2,433 7,205 9,883
Total regulatory liabilities 81,378 103,982 90,707
Net regulatory position $(47,818) $(62,192) $(41,517)
As of December 31, 1996, 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 20 years.
If for any reason, the company's regulated businesses cease to meet
the criteria for application of SFAS No. 71 for all or part of their
operations, the regulatory assets and liabilities relating to those
portions ceasing to meet such criteria would be removed from the
balance sheet and included in the statement of income as an
extraordinary item in the period in which the discontinuance of SFAS
No. 71 occurs.
NOTE 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
a 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 for
1996, 1995 and 1994:
1996 1995 1994
(Notional amounts in thousands)
Oil swap/collar agreements:*
Range of fixed prices per barrel $18.74-$19.07 $17.75-$20.75 $17.00-$21.05
Notional amount (in barrels) 635 260 242
Natural gas swap/collar agreements:*
Range of fixed prices per MMBtu $1.40-$2.05 $1.70-$1.85 $1.85-$2.32
Notional amount (in MMBtu's) 5,331 644 3,130
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% 5.97% ---
Notional amount (in dollars) $30,000 $20,000 ---
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The following table summarizes swap agreements outstanding at
December 31, 1996 (notional amounts in thousands):
Range of Notional
Fixed Prices Amount
Year (Per barrel) (In barrels)
Oil swap agreements* 1997 $19.77-$21.36 730
Range of Notional
Fixed Prices Amount
Year (Per MMBtu) (In MMBtu's)
Natural gas swap agreements* 1997 $1.30-$2.25 7,737
Notional
Range of Fixed Amount
Year Interest Rates (In dollars)
Interest rate swap agreements:** 1997 5.50%-6.50% $30,000
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 unfavorable position on
all swap and collar agreements outstanding at December 31, 1996, was
$4.2 million.
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:
1996 1995 1994
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
(In thousands)
Long-term
debt $292,420 $298,592 $254,339 $ 274,320 $ 238,043 $ 233,196
Preferred
stocks $ 16,900 $ 10,762 $ 17,000 $ 10,500 $ 17,100 $ 10,486
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 lines of credit from
several banks totalling $91.4 million at December 31, 1996. 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 $4.0 million at December 31, 1996,
$600,000 at December 31, 1995, and $680,000 at December 31, 1994. The
weighted average interest rate for borrowings outstanding at
December 31, 1996, 1995 and 1994, was 7.25 percent, 8.50 percent and
8.50 percent, respectively. The unused portions of the lines of
credit are subject to withdrawal based on the occurrence of certain
events.
NOTE 9
Common Stock
At the Annual Meeting of Stockholders held in April 1994, the
company's common stockholders approved an amendment to the Certificate
of Incorporation increasing the authorized number of common shares
from 50 million shares to 75 million shares and reducing the par value
of the common stock from $5.00 per share to $3.33 per share.
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. Common stock information appearing in the
accompanying consolidated financial statements and notes thereto has
been restated to give retroactive effect to the stock split, except
for shares outstanding in 1994 as set forth in the table below.
Changes in common stock and other paid in capital during the years
ended December 31, 1996, 1995 and 1994 are summarized below:
Shares Par Other Paid
Outstanding Value In Capital
(In thousands)
Balance at December 31, 1994 18,984,654 $63,219 $ 95,914
Three-for-two common stock split 9,492,327 31,609 (31,609)
Balance at December 31, 1995 and
1996 28,476,981 $94,828 $ 64,305
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. Shares held in the K-Plans
also participate in the DRIP. Since January 1, 1989, the DRIP and K-
Plans have been funded by the purchase of shares of common stock on
the open market. However, beginning January 1, 1997, shares of
authorized but unissued common stock are being used to fund the DRIP.
At December 31, 1996, there were 5,830,345 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
Retained Earnings
Changes in retained earnings for the years ended December 31, 1996,
1995 and 1994 are as follows:
1996 1995 1994
(In thousands)
Balance at beginning of year $178,184 $168,050 $158,998
Net income 45,470 41,633 39,845
223,654 209,683 198,843
Deduct:
Dividends declared --
Preferred stocks at required
annual rates 787 792 797
Common stock 31,326 30,707 29,996
32,113 31,499 30,793
Balance at end of year $191,541 $178,184 $168,050
NOTE 11
Preferred Stocks
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 stock:
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, 1996, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
1996 1995 1994
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, due May 15, 2006 $ 25,000 $ 50,000 $ 50,000
9 1/8% Series, due October 1, 2016 20,000 20,000 20,000
Pollution Control Refunding Revenue
Bonds, Series 1992:
Mercer County, North Dakota,
6.65%, due June 1, 2022 15,000 15,000 15,000
Morton County, North Dakota,
6.65%, due June 1, 2022 2,600 2,600 2,600
Richland County, Montana,
6.65%, due June 1, 2022 3,250 3,250 3,250
Secured Medium-Term Notes,
Series A:
6.30%, due April 1, 1995 --- --- 10,000
6.95%, due April 1, 1996 --- 10,000 10,000
7.20%, due April 1, 1997 5,000 5,000 5,000
8.25%, due April 1, 2007 30,000 30,000 30,000
8.60%, due April 1, 2012 35,000 35,000 35,000
Total first mortgage bonds
and notes 135,850 170,850 180,850
Pollution control lease and
note obligation, 6.20%, due
March 1, 2004 4,000 4,300 4,600
Senior notes:
7.35%, due July 31, 2002 5,000 5,000 ---
8.43%, due December 31, 2000 15,000 15,000 15,000
7.51%, expires October 9, 2003 3,000 --- ---
7.45%, due May 31, 2006 20,000 --- ---
7.60%, due November 3, 2008 15,000 --- ---
Revolving lines of credit:
8.25%, expires December 31, 1998 30,000 21,500 17,000
Other revolving lines of credit at
rates ranging from 6.03% to 8.50%,
expiring at various dates ranging
from October 6, 2001, through
April 30, 2002 61,800 27,000 3,000
Term credit facilities:
5.95%, due March 31, 1997 --- 7,500 17,500
7.70%, due December 1, 2003 1,556 1,800 ---
Other term credit facilities at
rates ranging from 8.00% to 9.00%,
due from June 30, 1999, through
December 1, 2000 1,308 1,527 250
Other (94) (138) (157)
Total long-term debt 292,420 254,339 238,043
Less current maturities and sinking
fund requirements 11,754 16,987 20,350
Net long-term debt $280,666 $237,352 $217,693
Under the revolving lines of credit, the company has $120 million
available, $91.8 million of which was outstanding at December 31,
1996. The amounts of scheduled long-term debt maturities and sinking
fund requirements for the five years following December 31, 1996,
aggregate $11.8 million in 1997; $44.5 million in 1998; $15.1 million
in 1999; $18.4 million in 2000 and $10.9 million in 2001.
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
$247 million of additional first mortgage bonds at December 31, 1996.
Certain of the company's other debt instruments contain restrictive
covenants all of which the company is in compliance with at December
31, 1996.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1996 1995 1994
(In thousands)
Current:
Federal $12,617 $20,259 $11,995
State 3,272 3,801 2,644
Foreign 60 369 210
15,949 24,429 14,849
Deferred:
Investment tax credit -- net (1,099) (1,028) (1,137)
Income taxes --
Federal 1,139 (564) 4,589
State 120 220 532
Foreign (22) --- ---
138 (1,372) 3,984
Total income tax expense $16,087 $23,057 $18,833
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1996 1995 1994
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 38,404 $ 36,894 $ 33,076
Natural gas available under
repurchase commitment 10,521 6,762 6,778
Accrued pension costs 7,814 7,039 5,646
Deferred investment tax credits 3,160 3,623 4,022
Accrued land reclamation 3,604 4,033 4,256
Natural gas costs refundable
through rate adjustments --- 6,125 4,034
Other 13,499 11,321 10,220
Total deferred tax assets 77,002 75,797 68,032
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 121,763 119,078 115,966
Basis differences on oil and
natural gas producing properties 30,361 28,113 21,049
Natural gas contract settlement and
restructuring costs 1,926 5,413 9,327
Long-term debt refinancing costs 4,688 4,524 4,745
Other 8,461 5,465 4,592
Total deferred tax liabilities 167,199 162,593 155,679
Net deferred income tax liability $(90,197) $(86,796) $(87,647)
The following table reconciles the change in the net deferred income
tax liability to the deferred income tax expense included in the
Consolidated Statements of Income:
1996 1995
(In thousands)
Net change in deferred income tax liability
from the preceding table $ 3,401 $(851)
Change in tax effects of income tax-related
regulatory assets and liabilities 1,155 507
Deferred taxes associated with acquisitions (3,319) ---
Deferred income tax expense for the period $ 1,237 $(344)
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:
1996 1995 1994
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $21,545 35.0 $22,642 35.0 $20,537 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,070) (1.7) (1,346) (2.1) (1,454)(2.5)
State income
taxes -- net of
federal income tax
benefit 2,770 4.5 2,492 3.9 2,337 4.0
Investment tax credit
amortization (1,099) (1.8) (1,028) (1.6) (1,137)(1.9)
Tax reserve adjustment (6,600)(10.7) --- --- --- ---
Other items 541 .8 297 .4 (1,450)(2.5)
Actual taxes $16,087 26.1 $23,057 35.6 $18,833 32.1
The company's consolidated federal income tax returns were under
examination by the Internal Revenue Service (IRS) for the tax years
1983 through 1991. In 1991, the company received a notice of proposed
deficiency from the IRS for the tax years 1983 through 1985 which
proposed substantial additional income taxes, plus interest. In an
alternative position contained in the notice of proposed deficiency,
the IRS had claimed a lower level of taxes due, plus interest as well
as penalties. In 1992 and 1995, similar notices of proposed
deficiency were received for the years 1986 through 1988 and 1989
through 1991, respectively. Although the notices of proposed
deficiency encompass a number of separate issues, the principal issue
was related to the tax treatment of deductions claimed in connection
with certain investments made by Knife River and Fidelity Oil.
The company timely filed protests for the 1983 through 1991 tax years
contesting the treatment proposed in the notices of proposed
deficiency. In April 1996, the company and the IRS reached a
settlement for the tax years 1983 through 1988, which should also
result in settlement of related issues for the years 1989 through
1991. The company reflected the effect of the settlement in the third
quarter of 1996 and, in addition, reversed reserves previously
provided which were deemed to be no longer required.
NOTE 14
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.
Segment operating information at December 31, 1996, 1995 and 1994, is
presented in the Consolidated Statements of Income. Other segment
information is presented below:
1996 1995 1994
(In thousands)
Depreciation, depletion and
amortization:
Electric $ 17,053 $ 16,361 $ 15,513
Natural gas distribution 6,880 6,719 6,118
Natural gas transmission 6,748 6,940 6,590
Construction materials
and mining 6,974 6,199 6,394
Oil and natural gas production 24,996 18,606 13,498
Total depreciation, depletion
and amortization $ 62,651 $ 54,825 $ 48,113
Investment information:
Identifiable assets--
Electric (a) $ 313,815 $ 312,559 $ 307,861
Natural gas distribution (a) 120,645 126,452 124,275
Natural gas transmission (a) 276,843 303,219 311,992
Construction materials
and mining 171,283 141,505 116,347
Oil and natural gas
production 161,647 133,289 106,631
Total identifiable assets 1,044,233 1,017,024 967,106
Corporate assets (b) 44,940 39,455 37,612
Total consolidated assets $1,089,173 $1,056,479 $1,004,718
(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 4 percent of construction materials and mining revenues
in 1996 (4 percent in 1995 and 6 percent in 1994) represent Knife
River's direct sales of lignite coal to the company. The company's
share of Knife River's 1996 sales for use at the Coyote Station, a
generating station jointly owned by the company and other utilities,
was approximately 5 percent of construction materials and mining
revenues in 1996. In 1995 and 1994, 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 and 8 percent, respectively, 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, 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.
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 15
Employee Benefit Plans
The company has noncontributory defined benefit pension plans covering
substantially all full-time employees. Pension benefits are based 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:
1996 1995 1994
(In thousands)
Service cost/benefits earned during
the year $ 3,852 $ 3,538 $ 4,035
Interest cost on projected benefit
obligation 10,823 10,784 9,912
Loss (return) on plan assets (24,972) (37,185) 3,154
Net amortization and deferral 11,494 24,407 (15,410)
Special termination benefit cost --- 853 ---
Total pension costs 1,197 2,397 1,691
Less amounts capitalized 131 184 198
Total pension expense $ 1,066 $ 2,213 $ 1,493
The funded status of the company's plans at December 31 is summarized
as follows:
1996 1995 1994
(In thousands)
Projected benefit obligation:
Vested $122,119 $121,879 $105,561
Nonvested 3,923 4,731 4,124
Accumulated benefit obligation 126,042 126,610 109,685
Provision for future pay increases 24,787 28,114 25,084
Projected benefit obligation 150,829 154,724 134,769
Plan assets at market value 185,872 170,793 139,332
(35,043) (16,069) (4,563)
Plus:
Unrecognized transition asset 7,336 8,326 9,315
Unrecognized net gains and prior
service costs 35,848 14,686 2,466
Accrued pension costs $ 8,141 $ 6,943 $ 7,218
The projected benefit obligation was determined using an assumed
discount rate of 7.50 percent (7.25 percent in 1995 and 8 percent in
1994) and assumed long-term rates for estimated compensation increases
of 4.50 percent (4.50 percent in 1995 and 5 percent in 1994). The
change in these assumptions had the effect of decreasing the projected
benefit obligation at December 31, 1996, by $5 million but increasing
the projected benefit obligation at December 31, 1995, by $12 million.
The assumed long-term rate of return on plan assets is 8.50 percent.
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
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:
1996 1995 1994
(In thousands)
Service cost/benefits earned during
the year $ 1,333 $1,226 $1,454
Interest cost on accumulated
postretirement benefit obligation 4,701 4,777 4,584
Return on plan assets (2,491) (183) (176)
Amortization of transition obligation 2,458 2,458 2,458
Net amortization and deferral 1,260 (719) 76
Total postretirement benefits cost 7,261 7,559 8,396
Less amounts capitalized 735 442 419
Total postretirement benefits expense $ 6,526 $7,117 $7,977
The funded status of the company's plans at December 31 is summarized
as follows:
1996 1995 1994
(In thousands)
Accumulated postretirement benefit
obligation:
Retirees eligible for benefits $40,775 $43,543 $36,985
Active employees fully eligible for
benefits --- 66 22
Active employees not fully eligible 24,833 26,229 22,898
Total 65,608 69,838 59,905
Plan assets at market value 21,712 15,095 9,938
43,896 54,743 49,967
Less:
Unrecognized transition obligation 39,322 41,779 44,237
Unrecognized net losses 3,693 12,066 4,896
Accrued postretirement benefits cost $ 881 $ 898 $ 834
The health plan cost trend rate assumed in determining the accumulated
postretirement benefit obligation at December 31, 1996, was 9 percent
decreasing by 1 percent per year until an ultimate rate of 6 percent
is reached in 1999 and remaining level thereafter. 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, 1996, by $3.1
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $233,000.
The accumulated postretirement benefit obligation was determined using
an assumed discount rate of 7.50 percent at December 31, 1996, 7.25
percent at December 31, 1995, and 8 percent at December 31, 1994, and
assumed long-term rates for estimated compensation increases, as they
apply to life insurance benefits, of 4.50 percent at December 31, 1996
and 1995, and 5 percent at December 31, 1994. The change in these
assumptions had the effect of decreasing the accumulated
postretirement benefit obligation at December 31, 1996, by $2 million
but increasing the accumulated postretirement benefit obligation at
December 31, 1995, by $7 million. The assumed long-term rate of
return on assets is 7.50 percent. 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 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 1996, $1.9 million in 1995 and $1.7 million in 1994.
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. The company is
authorized to grant options for up to 1.2 million shares of common
stock and has granted options on 484,540 shares through December 31,
1996. Under the KESOP the option price equals the stock's market
value 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 change in control and
expire 10 years after the date of grant. The company has contributed
$5.7 million to a trust established to fund its commitment under the
KESOP.
Pro forma net income and earnings per common share calculated using
the provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation" have not been presented because such amounts are not
materially different than actual amounts reported.
A summary of the status of the KESOP at December 31, 1996, 1995 and
1994, and changes during the years then ended are as follows:
1996 1995 1994
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Balance at 468,737 $17.48 192,284 $15.82 265,964 $15.82
beginning
of year
Granted --- --- 294,956 18.50 --- ---
Forfeited --- --- (2,700) 20.83 (73,680) 15.80
Exercised (44,760) 15.75 (15,803) 15.75 --- ---
Balance at end
of year 423,977 17.66 468,737 17.48 192,284 15.82
Exercisable at
end of year 93,764 $15.75 138,524 $15.75 --- ---
Exercise prices on options outstanding at December 31, 1996, range
from $15.75 to $18.50 with a weighted average remaining contractual
life of approximately 7 years.
The weighted average fair value of each option granted in 1995 is
$2.67. 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 1995 were a
risk-free interest rate of 7.80 percent, an expected dividend yield of
5.80 percent, an expected life of 10 years and expected volatility of
15.80 percent.
The company has Tax Deferred Compensation Savings Plans for eligible
employees. 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 $1.9 million in 1996, 1995
and 1994.
NOTE 16
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.
Hawaiian Cement 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. Hawaiian Cement, headquartered in
Honolulu, Hawaii, is a partnership which is also 50 percent owned by
Adelaide Brighton Ltd. of Adelaide, Australia.
The company's net investment in Hawaiian Cement is included in
"Investments" in the accompanying Consolidated Balance Sheets at
December 31, 1996 and 1995, while its share of operating results is
included in "Other income -- net" in the accompanying Consolidated
Statements of Income for the years ended December 31, 1996 and 1995.
Summarized financial information for Hawaiian Cement, which is not
consolidated and is accounted for by the equity method, as of and for
the year ended December 31, 1996, and as of and for the four months
ended December 31, 1995, as applicable, is as follows:
1996 1995
(In thousands)
Current assets $17,316 $19,531
Property, plant and equipment, net 52,316 70,544
Current liabilities 10,128 14,209
Other liabilities 14,954 15,736
Net sales 70,059 24,433
Operating margin 9,900 5,096
Income before income taxes 5,373 2,757
The company's investment in Hawaiian Cement exceeds the underlying net
assets by $13.2 million. The excess is being amortized over 30 years.
NOTE 17
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 providing its own financing of 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:
1996 1995 1994
(In thousands)
Big Stone Station:
Utility plant in service $ 48,907 $ 47,687 $ 46,923
Accumulated depreciation 26,676 27,026 25,505
$ 22,231 $ 20,661 $ 21,418
Coyote Station:
Utility plant in service $122,320 $122,126 $ 121,784
Accumulated depreciation 52,721 49,296 45,546
$ 69,599 $ 72,830 $ 76,238
NOTE 18
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1996 and 1995:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
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 .45 .30 .29 .53
Average common shares
outstanding 28,477 28,477 28,477 28,477
1995
Operating revenues $116,518 $111,267 $113,945 $122,516
Operating expenses 94,047 91,690 91,606 96,327
Operating income 22,471 19,577 22,339 26,189
Net income 10,272 8,662 10,472 12,227
Earnings per common share .35 .30 .36 .42
Average common shares
outstanding 28,477 28,477 28,477 28,477
Some of the company's 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 19
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.
In 1994, Williston Basin undertook a drilling program designed to
increase production and to gain updated data from which to assess the
future production capabilities of natural gas reserves held primarily
in Montana. In late 1994, upon analysis of the results of this
program, it was determined that the future production related to these
properties can be accelerated and, as a result, the economic value of
these reserves has become material to the company's consolidated oil
and natural gas production operations. Therefore, beginning in 1994,
the tables set forth below include information related to Williston
Basin's natural gas production activities.
The following information includes the company's proportionate share
of all its oil and natural gas interests.
The following table sets forth capitalized costs and related
accumulated depreciation, depletion and amortization related to oil
and natural gas producing activities at December 31:
1996 1995 1994
(In thousands)
Subject to amortization $223,409 $173,501 $155,303
Not subject to amortization 6,792 8,831 8,530
Total capitalized costs 230,201 182,332 163,833
Accumulated depreciation, depletion
and amortization 71,554 49,498 54,376
Net capitalized costs $158,647 $132,834 $109,457
Net capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities for the 12 months
ended December 31 are as follows:
1996 1995 1994
(In thousands)
Acquisitions $23,284 $ 9,159 $ 3,182
Exploration 8,101 7,678 12,656
Development 19,979 24,955 20,247
Net capital expenditures $51,364 $41,792 $36,085
The following summary reflects income resulting from the company's
operations of oil and natural gas producing activities, excluding
corporate overhead and financing costs, for the 12 months ended
December 31:
1996 1995 1994
(In thousands)
Revenues* $75,335 $53,484 $45,053
Production costs 21,296 16,888 18,463
Depreciation, depletion and
amortization 25,629 19,058 13,926
Pretax income 28,410 17,538 12,664
Income tax expense 10,875 6,397 4,257
Results of operations for
producing activities $17,535 $11,141 $ 8,407
* Includes $7.0 million, $4.7 million and $7.1 million of revenues for
1996, 1995 and 1994, respectively, related to Williston Basin's
natural gas production activities which are included in "Natural
gas" operating revenues on the Consolidated Statements of Income.
The following table summarizes the company's estimated quantities of
proved developed oil and natural gas reserves at December 31, 1996,
1995 and 1994, 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.
1996 1995 1994
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 14,200 179,000 12,500 154,200 11,200 50,300
Production (2,100) (20,400) (2,000) (17,500) (1,600) (9,200)
Extensions and
discoveries 600 27,000 1,800 23,800 1,300 17,800
Purchases of proved
reserves 2,900 9,900 1,100 6,700 600 2,900
Sales of reserves
in place (700) (3,700) (300) (200) (400) (2,700)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 1,200 8,400 1,100 12,000 1,400 95,100*
Balance at end of year 16,100 200,200 14,200 179,000 12,500 154,200
*Includes 99,300 MMcf of Williston Basin's natural gas reserves.
Proved developed reserves:
January 1, 1994 11,100 43,100
December 31, 1994 12,200 147,200**
December 31, 1995 13,600 156,400
December 31, 1996 15,400 168,200
**Includes 98,700 MMcf of Williston Basin's natural gas reserves.
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, 1996, applicable to the company's
$2.0 million 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:
1996 1995 1994
(In thousands)
Future net cash flows before
income taxes $580,300 $267,300 $197,900
Future income tax expenses 194,200 76,100 48,800
Future net cash flows 386,100 191,200 149,100
10% annual discount for estimated
timing of cash flows 152,100 70,300 54,200
Discounted future net cash flows
relating to proved oil and natural
gas reserves $234,000 $120,900 $ 94,900
The following are the sources of change in the standardized measure of
discounted future net cash flows by year:
1996 1995 1994
(In thousands)
Beginning of year $120,900 $ 94,900 $ 71,600
Net revenues from production (54,000) (36,400) (23,800)
Change in net realization 125,800 26,300 (4,100)
Extensions, discoveries and improved
recovery, net of future
production-related costs 43,500 31,200 31,700
Purchases of proved reserves 49,600 10,900 5,800
Sales of reserves in place (6,700) (1,000) (3,700)
Changes in estimated future
development costs -- net of those
incurred during the year (2,400) (8,900) (2,900)
Accretion of discount 16,900 12,300 8,300
Net change in income taxes (69,200) (17,100) (4,000)
Revisions of previous quantity
estimates 8,700 8,900 16,500*
Other 900 (200) (500)
Net change 113,100 26,000 23,300
End of year $234,000 $120,900 $ 94,900
*Includes $19.1 million related to Williston Basin's natural gas
reserves.
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 and
statements of capitalization of MDU Resources Group, Inc. (a Delaware
corporation) and Subsidiaries as of December 31, 1996, 1995 and 1994,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1996. 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, 1996, 1995
and 1994, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Minneapolis, Minnesota
January 23, 1997
1996 1995 1994
Selected Financial Data
Operating revenues: (000's)
Electric $ 138,761 $ 134,609 $ 133,953
Natural gas 175,408 167,787 160,970
Construction materials and mining 132,222 113,066 116,646
Oil and natural gas production 68,310 48,784 37,959
$ 514,701 $ 464,246 $ 449,528
Operating income: (000's)
Electric $ 29,476 $ 29,898 $ 27,596
Natural gas distribution 11,504 6,917 3,948
Natural gas transmission 30,231 25,427 21,281
Construction materials and mining 16,062 14,463 16,593
Oil and natural gas production 24,252 13,871 8,757
$ 111,525 $ 90,576 $ 78,175
Earnings on common stock: (000's)
Electric $ 11,436 $ 12,000 $ 11,719
Natural gas distribution 4,892 1,604 285
Natural gas transmission 2,459 8,416 6,155
Construction materials and mining 11,521 10,819 11,622
Oil and natural gas production 14,375 8,002 9,267
Earnings on common stock
before cumulative effect of
accounting change 44,683 40,841 39,048
Cumulative effect of
accounting change --- --- ---
$ 44,683 $ 40,841 $ 39,048
Earnings per common share before
cumulative effect of
accounting change $ 1.57 $ 1.43 $ 1.37
Cumulative effect of accounting
change --- --- ---
$ 1.57 $ 1.43 $ 1.37
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 45,470 $ 41,633 $ 39,845
Earnings per common share $ 1.57 $ 1.43 $ 1.37
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ 1.1000 $ 1.0782 $ 1.0533
Book value per common share $ 12.31 $ 11.85 $ 11.49
Market price per common share
(year-end) $ 23.00 $ 19.88 $ 18.08
Market price ratios:
Dividend payout 70% 76% 77%
Yield 4.8% 5.5% 5.9%
Price/earnings ratio 14.6x 13.9x 13.2x
Market value as a percent of
book value 186.8% 167.7% 157.4%
Profitability Indicators
Return on average common equity 13.0% 12.3% 12.1%
Return on average invested capital 9.5% 9.2% 9.1%
Interest coverage 5.4x 3.9x 3.3x
Fixed charges coverage, including
preferred dividends 2.7x 3.0x 2.9x
General
Total assets (000's) $1,089,173 $1,056,479 $1,004,718
Net long-term debt (000's) $ 280,666 $ 237,352 $ 217,693
Redeemable preferred stock (000's) $ 1,900 $ 2,000 $ 2,100
Capitalization ratios:
Common stockholders' investment 54% 57% 58%
Preferred stocks 3 3 3
Long-term debt 43 40 39
100% 100% 100%
1993 1992 1991
Selected Financial Data
Operating revenues: (000's)
Electric $ 131,109 $ 123,908 $128,708
Natural gas 178,981 159,438 173,865
Construction materials and mining 90,397 45,032 41,201
Oil and natural gas production 39,125 33,797 33,939
$ 439,612 $ 362,175 $377,713
Operating income: (000's)
Electric $ 30,520 $ 30,188 $ 34,647
Natural gas distribution 4,730 4,509 8,518
Natural gas transmission 20,108 21,331 19,904
Construction materials and mining 16,984 11,532 9,682
Oil and natural gas production 11,750 9,499 12,552
$ 84,092 $ 77,059 $ 85,303
Earnings on common stock: (000's)
Electric $ 12,652* $ 13,302 $ 15,292
Natural gas distribution 1,182* 1,370 3,645
Natural gas transmission 4,713 3,479 449
Construction materials and mining 12,359 10,662 9,809
Oil and natural gas production 7,109 5,751 8,010
Earnings on common stock
before cumulative effect of
accounting change 38,015* 34,564 37,205
Cumulative effect of
accounting change 5,521 --- ---
$ 43,536 $ 34,564 $ 37,205
Earnings per common share before
cumulative effect of
accounting change $ 1.34* $ 1.21 $ 1.31
Cumulative effect of accounting
change .19 --- ---
$ 1.53 $ 1.21 $ 1.31
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 38,817 $ 35,852 $ 37,619
Earnings per common share $ 1.34 $ 1.23 $ 1.29
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ 1.0133 $ .9733 $ .9567
Book value per common share $ 11.17 $ 10.66 $ 10.42
Market price per common share
(year-end) $ 21.00 $ 17.58 $ 16.42
Market price ratios:
Dividend payout 76%* 80% 73%
Yield 5.0% 5.6% 5.8%
Price/earnings ratio 15.8x* 14.5x 12.6x
Market value as a percent of
book value 188.0% 165.0% 157.7%
Profitability Indicators
Return on average common equity 12.3%* 11.6% 12.7%
Return on average invested capital 9.4%* 8.7% 9.6%
Interest coverage 3.4x* 3.3x 3.8x**
Fixed charges coverage, including
preferred dividends 3.0x* 2.4x 2.4x
General
Total assets (000's) $1,041,051 $1,024,510 $964,691
Net long-term debt (000's) $ 231,770 $ 249,845 $220,623
Redeemable preferred stock (000's) $ 2,200 $ 2,300 $ 2,400
Capitalization ratios:
Common stockholders' investment 56% 53% 56%
Preferred stocks 3 3 3
Long-term debt 41 44 41
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the
accrual of estimated unbilled revenues.
** Calculation reflects the provisions of the company's restatement of
its Indenture of Mortgage effective April 1992.
1996 1995 1994
Electric Operations
Sales to ultimate consumers
(thousand kWh) 2,067,926 1,993,693 1,955,136
Sales for resale (thousand kWh) 374,535 408,011 444,492
Electric system generating and
firm purchase capability--kW
(Interconnected system) 481,800 472,400 470,900
Demand peak--kW
(Interconnected system) 393,300 412,700 369,800
Electricity produced
(thousand kWh) 1,829,669 1,718,077 1,901,119
Electricity purchased
(thousand kWh) 809,261 867,524 700,912
Cost of fuel and purchased
power per kWh $.017 $.016 $.017
Natural Gas Distribution Operations
Sales (Mdk) 38,283 33,939 31,840
Transportation (Mdk) 9,423 11,091 9,278
Weighted average degree days--% of
previous year's actual 114% 105% 92%
Natural Gas Transmission Operations
Sales for resale (Mdk) --- --- ---
Transportation (Mdk) 82,169 68,015 63,870
Produced (Mdk) 6,073 4,981 4,732
Net recoverable reserves (MMcf) 133,400 113,000 99,300
Energy Marketing Operations
Natural gas volumes (Mdk) 4,670 3,556 7,301
Propane (thousand gallons) 9,689 7,471 6,462
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 3,374 2,904 2,688
Asphalt (tons sold) 694 373 391
Ready-mixed concrete (cubic
yards sold) 340 307 315
Recoverable aggregate reserves
(tons) 119,800 68,000 71,000
Coal: (000's)
Sales (tons) 2,899 4,218 5,206
Recoverable reserves (tons) 228,900 231,900 236,100
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 2,149 1,973 1,565
Natural gas (MMcf) 14,067 12,319 9,228
Average sales prices:
Oil (per barrel) $17.91 $15.07 $13.14
Natural gas (per Mcf) $ 2.09 $ 1.51 $ 1.84
Net recoverable reserves:
Oil (000's of barrels) 16,100 14,200 12,500
Natural gas (MMcf) 66,800 66,000 54,900
1993 1992 1991
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,893,713 1,829,933 1,877,634
Sales for resale (thousand kWh) 510,987 352,550 331,314
Electric system generating and
firm purchase capability--kW
(Interconnected system) 465,200 460,200 454,400
Demand peak--kW
(Interconnected system) 350,300 339,100 387,100
Electricity produced
(thousand kWh) 1,870,740 1,774,322 1,736,187
Electricity purchased
(thousand kWh) 701,736 593,612 611,884
Cost of fuel and purchased
power per kWh $.016 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 31,147 26,681 30,074
Transportation (Mdk) 12,704 13,742 12,261
Weighted average degree days--% of
previous year's actual 115% 98% 101%
Natural Gas Transmission Operations
Sales for resale (Mdk) 13,201 16,841 19,572
Transportation (Mdk) 59,416 64,498 53,930
Produced (Mdk) 3,876 3,551 3,742
Net recoverable reserves (MMcf) --- --- ---
Energy Marketing Operations
Natural gas volumes (Mdk) 6,827 3,292 991
Propane (thousand gallons) 2,210 --- ---
Construction Materials and Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 2,391 263 ---
Asphalt (tons sold) 141 --- ---
Ready-mixed concrete (cubic
yards sold) 157 --- ---
Recoverable aggregate reserves
(tons) 74,200 20,600 ---
Coal: (000's)
Sales (tons) 5,066 4,913 4,731
Recoverable reserves (tons) 230,600 235,700 256,700
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,497 1,531 1,491
Natural gas (MMcf) 8,817 5,024 2,565
Average sales prices:
Oil (per barrel) $14.84 $16.74 $19.90
Natural gas (per Mcf) $ 1.86 $ 1.53 $ 1.48
Net recoverable reserves:
Oil (000's of barrels) 11,200 12,200 11,600
Natural gas (MMcf) 50,300 37,200 27,500