MDU RESOURCES GROUP, INC.
1995 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, 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, 1995 1994 1993
(In thousands, except per share amounts)
Operating Revenues
Electric $134,609 $133,953 $131,109
Natural gas 167,787 160,970 178,981
Construction materials and mining 113,066 116,646 90,397
Oil and natural gas production 48,784 37,959 39,125
464,246 449,528 439,612
Operating Expenses
Fuel and purchased power 41,769 43,203 41,298
Purchased natural gas sold 53,351 52,893 78,121
Operation and maintenance 202,327 203,269 167,374
Depreciation, depletion and
amortization 54,825 48,113 45,162
Taxes, other than income 21,398 23,875 23,565
373,670 371,353 355,520
Operating Income
Electric 29,898 27,596 30,520
Natural gas distribution 6,917 3,948 4,730
Natural gas transmission 25,427 21,281 20,108
Construction materials and mining 14,463 16,593 16,984
Oil and natural gas production 13,871 8,757 11,750
90,576 78,175 84,092
Other income--net 4,789 10,480 3,877
Interest expense 24,690 25,350 25,273
Carrying costs on natural gas
repurchase commitment (Note 3) 5,985 4,627 3,897
Income before income taxes 64,690 58,678 58,799
Income taxes 23,057 18,833 19,982
Income before cumulative effect
of accounting change 41,633 39,845 38,817
Cumulative effect of accounting
change (Note 1) --- --- 5,521
Net income 41,633 39,845 44,338
Dividends on preferred stocks 792 797 802
Earnings on common stock $ 40,841 $ 39,048 $ 43,536
Earnings per common share:
Earnings before cumulative effect
of accounting change $ 1.43 $ 1.37 $ 1.34
Cumulative effect of accounting
change --- --- .19
Earnings $ 1.43 $ 1.37 $ 1.53
Dividends per common share $ 1.08 $ 1.05 $ 1.01
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, 1995 1994 1993
(In thousands)
ASSETS
Property, Plant and Equipment
Electric $ 535,016 $ 514,152 $ 503,690
Natural gas distribution 161,080 157,174 141,100
Natural gas transmission 271,773 263,971 258,766
Construction materials and mining 151,751 147,284 145,014
Oil and natural gas production 167,542 151,532 116,833
1,287,162 1,234,113 1,165,403
Less accumulated depreciation,
depletion and amortization 570,855 541,842 501,451
716,307 692,271 663,952
Current Assets
Cash and cash equivalents 33,398 37,190 71,699
Receivables 61,961 55,409 67,553
Inventories 23,949 27,090 19,415
Deferred income taxes 31,663 26,694 32,243
Prepayments and other
current assets 11,261 12,287 14,262
162,232 158,670 205,172
Natural gas available under
repurchase commitment (Note 3) 70,750 70,913 79,031
Investments (Note 16) 46,188 16,914 16,858
Deferred charges and other assets 61,002 65,950 76,038
$1,056,479 $1,004,718 $1,041,051
CAPITALIZATION AND LIABILITIES
Capitalization (See Separate
Statements)
Common stockholders' investment $ 337,317 $ 327,183 $ 318,131
Preferred stocks 16,900 17,000 17,100
Long-term debt 237,352 217,693 231,770
591,569 561,876 567,001
Commitments and contingencies
(Notes 2, 3, 4, 13 and 15) --- --- ---
Current Liabilities
Short-term borrowings 600 680 9,540
Accounts payable 22,261 20,222 24,967
Taxes payable 13,566 8,817 9,204
Other accrued liabilities,
including reserved revenues 100,779 88,516 107,566
Dividends payable 7,958 7,793 7,605
Long-term debt and preferred
stock due within one year 17,087 20,450 15,300
162,251 146,478 174,182
Natural gas repurchase commitment
(Note 3) 88,200 88,404 98,525
Deferred credits:
Deferred income taxes 118,459 114,341 113,477
Other 96,000 93,619 87,866
214,459 207,960 201,343
$1,056,479 $1,004,718 $1,041,051
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
December 31, 1995 1994 1993
(In thousands)
Common Stockholders' Investment
Common stock (Note 9):
Authorized-- 75,000,000 shares,
$3.33 par value in 1995
and 1994, 50,000,000
shares, $5 par value
in 1993
Outstanding--28,476,981 shares in 1995,
and 18,984,654 shares in
1994 and 1993 $ 94,828 $ 63,219 $ 94,923
Other paid in capital 64,305 95,914 64,210
Retained earnings (Note 10) 178,184 168,050 158,998
Total common stockholders'
investment 337,317 327,183 318,131
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--20,000 shares
in 1995 (21,000 in 1994 and
22,000 in 1993) 2,000 2,100 2,200
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 17,000 17,100 17,200
Less current maturities and
sinking fund requirements 100 100 100
Net preferred stocks 16,900 17,000 17,100
Long-term Debt (Note 12)
Total long-term debt 254,339 238,043 246,970
Less current maturities and sinking
fund requirements 16,987 20,350 15,200
Net long-term debt 237,352 217,693 231,770
Total capitalization $591,569 $561,876 $567,001
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1995 1994 1993
(In thousands)
Operating Activities
Net income $ 41,633 $ 39,845 $ 44,338
Cumulative effect of accounting
change --- --- (5,521)
Adjustments to reconcile net income
to net cash provided by operations:
Depreciation, depletion and
amortization 54,825 48,113 45,162
Deferred income taxes and
investment tax credit--net 7,631 3,409 16,197
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 7,177 7,866 8,716
Changes in current assets and
liabilities:
Receivables (6,552) 12,144 (775)
Inventories 3,141 (6,799) (1,201)
Other current assets (3,943) 7,524 12,954
Accounts payable 2,039 (4,745) (430)
Other current liabilities 17,177 (19,249) (8,160)
Other noncurrent changes 1,779 9,705 (14,093)
Net cash provided by operating
activities 124,907 97,813 97,187
Financing Activities
Net change in short-term borrowings (80) (8,860) 1,765
Issuance of long-term debt 36,710 26,750 ---
Repayment of long-term debt (20,433) (35,700) (3,100)
Retirement of preferred stocks (100) (100) (100)
Retirement of natural gas
repurchase commitment (204) (10,121) (16,412)
Dividends paid (31,499) (30,793) (29,659)
Net cash used in financing
activities (15,606) (58,824) (47,506)
Investing Activities
Additions to property, plant and
equipment and acquisitions of
businesses:
Electric (19,689) (14,188) (16,156)
Natural gas distribution (8,878) (19,033) (15,012)
Natural gas transmission (9,688) (6,147) (3,669)
Construction materials and mining (36,810) (3,597) (43,123)
Oil and natural gas production (39,917) (38,595) (24,943)
(114,982) (81,560) (102,903)
Sale of natural gas available
under repurchase commitment 163 8,118 13,007
Investments 1,726 (56) 45,076
Net cash used in investing
activities (113,093) (73,498) (44,820)
Increase (decrease) in cash
and cash equivalents (3,792) (34,509) 4,861
Cash and cash equivalents--
beginning of year 37,190 71,699 66,838
Cash and cash equivalents--
end of year $ 33,398 $ 37,190 $ 71,699
The accompanying notes are an integral part of these consolidated statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 1995, 1994 and 1993
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 its
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.
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 in accordance with the provisions of SFAS
No. 71. All other significant intercompany balances and transactions
have been eliminated where appropriate.
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 was insignificant in 1995, 1994 and 1993.
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, other than the company's partnership investment in
Hawaiian Cement, consist principally of securities held for corporate
development purposes, which are carried at market which approximates
cost.
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 repurchase commitment is carried at
Frontier Gas Storage Company's cost of purchased natural gas, less an
allowance to reflect changed market conditions.
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.
Utility Revenue and Energy Cost
Effective with a January 1, 1993 accounting change, the company began
recognizing revenue each month based on the services provided to all
customers during the month. Prior to 1993, the company recorded
revenue and the cost of purchased natural gas sold when customers were
billed. The cumulative effect of this change on net income for the 12
months ended December 31, 1993, is presented net of applicable income
taxes of $3,355,000.
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 adopted the provisions of SFAS No. 109, "Accounting for
Income Taxes" (SFAS No. 109) on January 1, 1993, and is now providing
deferred federal and state income taxes on all temporary differences.
Effective with the adoption of SFAS No. 109, the company elected
to record the cumulative effect of the accounting change on prior
years in 1993 as allowed by SFAS No. 109, with such amount being
immaterial to its financial position or results of operations. Excess
deferred income tax balances associated with Montana-Dakota's and
Williston Basin's rate-regulated activities have been recorded as a
regulatory liability and are included in "Other deferred credits" in
the company's Consolidated Balance Sheets at December 31, 1995, 1994
and 1993. 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 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, 1995 1994 1993
(In thousands)
Interest, net of amount capitalized $24,436 $22,775 $22,717
Income taxes $18,330 $13,539 $24,545
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 1994 and 1993 to conform to the 1995 presentation. Such
reclassifications had no effect on net income or common stockholders'
investment as previously reported.
New Accounting Standard
In March 1995, the Financial Accounting Standards Board issued SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS No. 121). SFAS No. 121
imposes stricter criteria for assets, including regulatory assets, by
requiring that such assets be probable of future recovery at each
balance sheet date. The company will adopt SFAS No. 121 on January 1,
1996, and the adoption will not have a material affect on the
company's financial position or results of operations. This
conclusion may change in the future depending on the extent to which
recovery of the company's long-lived assets is influenced by an
increasingly competitive environment in the electric and natural gas
industries.
NOTE 2
Regulatory Matters and Revenues Subject to Refund
General Rate Proceedings
Williston Basin had pending with the FERC two general natural gas rate
change applications implemented in 1989 and 1992. In May 1994, the
FERC issued an order relating to the 1989 rate change. Williston
Basin requested rehearing of certain issues addressed in the order and
a stay of compliance and refund pending issuance of a final order by
the FERC. The requested stay was denied by the FERC and in July 1994,
Williston Basin refunded $47.8 million to its customers, including
$33.4 million to Montana-Dakota, all of which had been reserved. On
April 5, 1995, the FERC issued an order granting in part and denying
in part Williston Basin's rehearing request. As a result of the
FERC's order, Williston Basin, on May 18, 1995, billed its customers
approximately $2.7 million, plus interest, to recover a portion of the
amount previously refunded in July 1994.
On July 25, 1995, the FERC issued an order relating to Williston
Basin's 1992 rate change application. On August 24, 1995, Williston
Basin filed, under protest, tariff sheets in compliance with the
FERC's order, with rates to be effective September 1, 1995. Williston
Basin requested rehearing of certain issues addressed in the order and
the rehearing is pending before the FERC.
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 Gas Storage Company (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, 1995, borrowings totalled $88.4 million at a weighted
average interest rate of 6.6 percent. The term loan agreement will
terminate on October 2, 1999, subject to an option to renew this
agreement 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 and represent costs
which Williston Basin may not recover. This matter is currently on
appeal. The issue regarding the applicability of assessing storage
charges to the gas creates additional uncertainty as to the costs
associated with holding the gas.
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
December 31, 1995, 17.6 MMdk of this natural gas had been sold by
Williston Basin for use by both on- and off-system markets. Williston
Basin will continue to aggressively market the remaining 43.2 MMdk of
this natural gas whenever market conditions are favorable. In
addition, it will continue to seek long-term sales contracts.
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 has submitted damage
calculations which total approximately $19 million or, under its
alternative pricing theory, approximately $39 million. On March 10,
1995, the Federal District Court issued a summary judgment dismissing
Moncrief's pricing theories and substantially reducing Moncrief's
claims. Trial was held in January 1996, and Williston Basin is
awaiting the Federal District Court's decision.
Moncrief's damage claims, in Williston Basin's opinion, are
grossly overstated. Williston Basin plans to file for recovery from
ratepayers of amounts which may be ultimately due to Moncrief, if any.
On November 27, 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 as may
ultimately be determined by the State District Court. The Co-owners
are also alleging 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 such contract, 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. Such matter is pending before the State
District Court with oral arguments scheduled for April 22, 1996. The
company and Knife River believe they have meritorious defenses and
intend to vigorously defend the suit.
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 June 1990, Montana-Dakota was notified by the EPA that it and
several others were named as Potentially Responsible Parties (PRPs) in
connection with the cleanup of pollution at a landfill site located in
Minot, North Dakota. In June 1993, the EPA issued its decision on the
selected remediation to be performed at the site. Based on the EPA's
proposed remediation plan, estimates of the total cleanup costs,
including oversight costs, at this site range from approximately $3.7
million to $4.8 million. In October 1995, the EPA and the City of
Minot entered into a consent decree which requires the city to
implement as well as assume liability for all cleanup costs associated
with the remediation plan. The remaining liability at this site for
past and future federal government oversight costs has been estimated
by the EPA to be approximately $1 million. Montana-Dakota believes
that it was not a material contributor to this contamination and,
therefore, further believes that its share of the approximately $1
million estimated remaining liability will not have a material effect
on its results of operations.
Electric Purchased Power Commitments
Montana-Dakota has contracted to purchase through October 31, 2006, up
to 66,000 kW of participation power from Basin Electric Power
Cooperative (61,000 kW in 1995). In addition, Montana-Dakota under a
total requirements contract through December 31, 1996, is purchasing
approximately 44,000 kW of power from Pacific Power & Light Company.
Beginning January 1, 1997, Montana-Dakota will purchase up to 55,000
kW of capacity from Black Hills Power and Light Company under a 10-
year power supply contract, subject to approval by the FERC.
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 million at December 31, 1995,
$45 million at December 31, 1994, and $49 million at December 31,
1993. In addition, $6.6 million, $6.9 million and $1.3 million at
December 31, 1995, 1994 and 1993, 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:
1995 1994 1993
(In thousands)
Regulatory assets:
Natural gas contract settlement
and restructuring costs $ 15,275 $ 24,069 $ 34,915
Long-term debt refinancing costs 11,082 12,228 13,462
Postretirement benefit costs 4,833 4,551 3,345
Plant costs 3,509 3,678 3,846
Other 7,091 4,664 723
Total regulatory assets 41,790 49,190 56,291
Regulatory liabilities:
Reserves for regulatory matters 58,277 49,427 83,782
Natural gas costs refundable
through rate adjustments 21,192 14,878 ---
Taxes refundable to customers 12,531 12,229 16,836
Plant decommissioning costs 4,777 4,290 3,845
Other 7,205 9,883 656
Total regulatory liabilities 103,982 90,707 105,119
Net regulatory position $(62,192) $(41,517) $(48,828)
As of December 31, 1995, 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 income statement as an extraordinary
item in the period in which the discontinuance of SFAS No. 71 occurs.
NOTE 7
Financial Instruments
Derivatives
The company's operations involve managing market risks related to
changes in commodity prices and interest rates. Derivative financial
instruments, specifically swap and collar agreements, are used to
reduce and manage those risks. The company does not currently hold or
issue financial instruments for trading purposes.
The company periodically enters into swap and collar agreements
to hedge its exposure to commodity price fluctuations in connection
with the operations of Montana-Dakota, Williston Basin and Fidelity
Oil. The company believes that there is a high degree of correlation
because the timing of purchases/production and the hedge agreement are
closely matched, and hedge prices are established in the areas of the
company's operations. Recognized gains and losses on hedge
transactions are matched and reported as a component of the related
transaction.
At December 31, 1995, Montana-Dakota was a party to a natural gas
price collar with a notional amount of 3.7 million MMBtus for the
12 months ended March 1996, at a floor price of $1.22 per MMBtu and at
a cap price of $1.52 per MMBtu. Fidelity Oil was a party to two
natural gas price swaps with a total notional amount of 2.8 million
MMBtus for 1996 at a fixed price of approximately $1.80 per MMBtu.
Fidelity Oil was also a party to a natural gas price collar with a
notional amount of 1.5 million MMBtus for 1996 at a floor price of
$1.80 per MMBtu and a cap price of $2.05 per MMBtu.
Williston Basin has entered into an interest rate swap agreement
related to the natural gas repurchase commitment. The purpose of this
swap is to fix the interest rate on a portion of the variable rate
natural gas repurchase commitment and reduce Williston Basin's
exposure to interest rate fluctuations. At December 31, 1995,
Williston Basin had an interest rate swap with a notional amount of
$20 million. Under this agreement, Williston Basin will pay the
counterparty interest at a fixed rate of 5.97 percent and the
counterparty will pay Williston Basin interest at a rate based on the
three month floating London Interbank Offered Rate (LIBOR). This
transaction was executed for a two-year period beginning August 1995.
The company's hedging transactions did not have a material effect
on its results of operations for the years ended December 31, 1995,
1994 and 1993. There were no derivative financial instruments
outstanding at December 31, 1994.
Fair Value
The estimated fair value of long-term debt and preferred stocks are
based on quoted market prices of the same or similar issues. The
estimated fair value of long-term debt and preferred stocks at
December 31 are as follows:
1995 1994 1993
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
(In thousands)
Long-term
debt $254,339 $274,320 $238,043 $ 233,196 $ 246,970 $ 268,937
Preferred
stocks $ 17,000 $ 10,500 $ 17,100 $ 10,486 $ 17,200 $ 11,090
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 $86.4 million at December 31, 1995. 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 $600,000 at December 31, 1995, $680,000
at December 31, 1994, and $9.5 million at December 31, 1993. The
weighted average interest rate for borrowings outstanding at
December 31, 1995, 1994 and 1993, was 8.5 percent, 8.5 percent and
4.2 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.
On August 17, 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 prior years as set forth in the table
below.
Changes in common stock and other paid in capital during the
years ended December 31, 1995, 1994 and 1993 are summarized below:
Shares Par Other Paid
Outstanding Value In Capital
(In thousands)
Balance at December 31, 1992
and 1993 18,984,654 $94,923 $ 64,210
Reduction in par value --- (31,704) 31,704
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 28,476,981 $94,828 $ 64,305
The company's Dividend Reinvestment Plan (DRIP) provides holders
of all classes of the company's capital stock the opportunity to
invest their cash dividends in shares of common stock and to make
optional cash payments of up to $5,000 per quarter for the same
purpose. The company's Tax Deferred Compensation Savings Plans
pursuant to Section 401(k) of the Internal Revenue Code are funded
with common stock and also participate in the DRIP. Since January 1,
1989, these plans have been funded by the purchase of shares of common
stock on the open market. However, shares of authorized but unissued
common stock may be used for this purpose. At December 31, 1995,
there were 1,530,344 shares of common stock reserved for issuance
under the 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, 1995,
1994 and 1993 are as follows:
1995 1994 1993
(In thousands)
Balance at beginning of year $168,050 $158,998 $144,319
Net income 41,633 39,845 44,338
209,683 198,843 188,657
Deduct:
Dividends declared--
Preferred stocks at required
annual rates 792 797 802
Common stock 30,707 29,996 28,857
31,499 30,793 29,659
Balance at end of year $178,184 $168,050 $158,998
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, 1995, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
Long-term debt outstanding at December 31 is as follows:
1995 1994 1993
(In thousands)
First mortgage bonds and notes:
9 1/8% Series, due May 15, 2006 $ 50,000 $ 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:
5.80%, due April 1, 1994 --- --- 15,000
6.30%, due April 1, 1995 --- 10,000 10,000
6.95%, due April 1, 1996 10,000 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 170,850 180,850 195,850
Pollution control lease and note
obligation, 6.2%, due
March 1, 2004 4,300 4,600 4,800
Senior notes:
7.35%, due July 31, 2002 5,000 --- ---
8.43%, due December 31, 2000 15,000 15,000 15,000
Revolving lines of credit:
8.50%, expires December 31, 1998 21,500 17,000 30,000
6.375%, expires August 25, 2001 25,000 --- ---
8.50%, expires January 13, 2002 2,000 3,000 1,500
Term credit facilities:
5.95%, due March 31, 1997 7,500 17,500 ---
7.70%, due December 1, 2003 1,800 --- ---
Other term credit facilities at
rates ranging from 8.0% to 9.0%,
due from 1998 through 2000 1,527 250 ---
Other (138) (157) (180)
Total long-term debt 254,339 238,043 246,970
Less current maturities and sinking
fund requirements 16,987 20,350 15,200
Net long-term debt $237,352 $217,693 $231,770
Under the revolving lines of credit, the company has $95 million
available, $48.5 million of which was outstanding at December 31,
1995. The amounts of long-term debt maturities and sinking fund
requirements for the five years following December 31, 1995, aggregate
$17.0 million in 1996; $16.5 million in 1997; $32.8 million in 1998;
$11.3 million in 1999 and $14.5 million in 2000. 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 $200 million of additional
first mortgage bonds at December 31, 1995.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1995 1994 1993
(In thousands)
Current:
Federal $20,259 $11,995 $25,665
State 3,801 2,644 3,997
Foreign 369 210 10
24,429 14,849 29,672
Deferred:
Investment tax credit--net (1,028) (1,137) (1,144)
Income taxes--
Federal (564) 4,589 (9,560)
State 220 532 1,014
(1,372) 3,984 (9,690)
Total income tax expense $23,057 $18,833 $19,982
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1995 1994 1993
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 36,894 $ 33,076 $ 48,412
Natural gas available under
repurchase commitment 6,762 6,778 7,554
Accrued pension costs 7,039 5,646 4,955
Deferred investment tax credits 3,623 4,022 4,462
Accrued land reclamation 4,033 4,256 4,017
Natural gas costs refundable
through rate adjustments 6,125 4,034 ---
Other 11,321 10,220 5,043
Total deferred tax assets 75,797 68,032 74,443
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment 119,078 115,966 115,517
Basis differences on oil and
natural gas producing properties 28,113 21,049 15,889
Natural gas contract settlement and
restructuring costs 5,413 9,327 13,530
Long-term debt refinancing costs 4,524 4,745 5,223
Other 5,465 4,592 5,518
Total deferred tax liabilities 162,593 155,679 155,677
Net deferred income tax liability $(86,796) $(87,647) $(81,234)
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:
1995 1994
(In thousands)
Net change in deferred income tax liability
from the preceding table $(851) $ 6,413
Change in tax effects of income tax-related
regulatory assets and liabilities 507 (1,292)
Deferred income tax expense for the period $(344) $ 5,121
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:
1995 1994 1993
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $22,642 35.0 $20,537 35.0 $20,580 35.0
Increases (reductions)
resulting from:
Depletion allowance (1,346) (2.1) (1,454) (2.5) (1,424) (2.4)
State income
taxes--net of
federal income tax
benefit 2,492 3.9 2,337 4.0 2,171 3.7
Investment tax credit
amortization (1,028) (1.6) (1,137) (1.9) (1,144) (2.0)
Other items 297 .4 (1,450) (2.5) (201) (.3)
Actual taxes $23,057 35.6 $18,833 32.1 $19,982 34.0
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 is claiming a lower level of taxes due, plus interest as well
as penalties. In 1992 and the first quarter of 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
is related to the tax treatment of deductions claimed in connection
with certain investments made by Knife River and Fidelity Oil.
The company intends to contest vigorously the deficiencies
proposed by the IRS and, in that regard, has timely filed protests for
the 1983 through 1991 tax years contesting the treatment proposed in
the notices of proposed deficiency. Although it is reasonably
possible that the ultimate resolution of such matters could result in
a loss of up to approximately $21 million in excess of consolidated
reserves, management believes the company has meritorious defenses to
mitigate or eliminate the proposed deficiencies. In that regard, the
company's tax counsel has issued opinions related to the principal
issue discussed above, stating that it is more likely than not that
the company would prevail in this matter.
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, 1995, 1994 and
1993, is presented in the Consolidated Statements of Income. Other
segment information is presented below:
1995 1994 1993
(In thousands)
Depreciation, depletion and
amortization:
Electric $ 16,361 $ 15,513 $ 15,307
Natural gas distribution 6,719 6,118 5,114
Natural gas transmission 6,940 6,590 7,113
Construction materials
and mining 6,199 6,394 5,594
Oil and natural gas production 18,606 13,498 12,034
Total depreciation, depletion
and amortization $ 54,825 $ 48,113 $ 45,162
Investment information:
Identifiable assets--
Electric (a) $ 312,559 $ 307,861 $ 306,179
Natural gas distribution (a) 126,452 124,275 104,013
Natural gas transmission (a) 303,219 311,992 383,355
Construction materials
and mining 141,505 116,347 120,105
Oil and natural gas
production 133,289 106,631 89,690
Total identifiable assets 1,017,024 967,106 1,003,342
Corporate assets (b) 39,455 37,612 37,709
Total consolidated assets $1,056,479 $1,004,718 $1,041,051
(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 1995 (6 percent in 1994 and 7 percent in 1993) represent
Knife River's direct sales of lignite coal to the company. The
company's share of Knife River's sales for use at two generating
stations jointly owned by the company and other utilities was
approximately 7 percent of construction materials and mining revenues
in 1995, 8 percent in 1994 and 10 percent in 1993.
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:
1995 1994 1993
(In thousands)
Service cost/benefits earned during
the year $ 3,538 $ 4,035 $ 3,277
Interest cost on projected benefit
obligation 10,784 9,912 9,488
Loss (return) on plan assets (37,185) 3,154 (14,540)
Net amortization and deferral 24,407 (15,410) 2,916
Special termination benefit cost 853 --- ---
Total pension costs 2,397 1,691 1,141
Less amounts capitalized 184 198 133
Total pension expense $ 2,213 $ 1,493 $ 1,008
The funded status of the company's plans at December 31 is
summarized as follows:
1995 1994 1993
(In thousands)
Projected benefit obligation:
Vested $121,879 $105,561 $108,718
Nonvested 4,731 4,124 4,696
Accumulated benefit obligation 126,610 109,685 113,414
Provision for future pay increases 28,114 25,084 26,379
Projected benefit obligation 154,724 134,769 139,793
Plan assets at market value 170,793 139,332 149,184
(16,069) (4,563) (9,391)
Plus:
Unrecognized transition asset 8,326 9,315 10,305
Unrecognized net gains and prior
service costs 14,686 2,466 4,953
Accrued pension costs $ 6,943 $ 7,218 $ 5,867
The projected benefit obligation was determined using an assumed
discount rate of 7 1/4 percent (8 percent in 1994 and 7 percent in
1993) and assumed long-term rates for estimated compensation increases
of 4 1/2 percent (5 percent in 1994 and 4 1/2 percent in 1993). The
change in these assumptions had the effect of increasing the projected
benefit obligation at December 31, 1995, by $12 million but decreasing
the projected benefit obligation at December 31, 1994, by $16 million.
The assumed long-term rate of return on plan assets is 8 1/2 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. On January 1, 1993, the company
adopted SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" (SFAS No. 106). The company elected to
amortize the transition obligation of approximately $49 million at
January 1, 1993, which represents the accumulated postretirement
benefit obligation at the time of adoption, over 20 years as provided
by SFAS No. 106. 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:
1995 1994 1993
(In thousands)
Service cost/benefits earned during
the year $1,226 $1,454 $ 1,098
Interest cost on accumulated
postretirement benefit obligation 4,777 4,584 3,932
Return on plan assets (183) (176) ---
Amortization of transition obligation 2,458 2,458 2,458
Net amortization and deferral (719) 76 ---
Total postretirement benefits cost 7,559 8,396 7,488
Less amounts capitalized 442 419 ---
Total postretirement benefits expense $7,117 $7,977 $ 7,488
The funded status of the company's plans at December 31 is
summarized as follows:
1995 1994 1993
(In thousands)
Accumulated postretirement benefit
obligation:
Retirees eligible for benefits $43,543 $36,985 $31,029
Active employees fully eligible for
benefits 66 22 ---
Active employees not fully eligible 26,229 22,898 28,592
Total 69,838 59,905 59,621
Plan assets at market value 15,095 9,938 4,450
54,743 49,967 55,171
Less:
Unrecognized transition obligation 41,779 44,237 46,694
Unrecognized net losses 12,066 4,896 7,992
Accrued postretirement benefits cost $ 898 $ 834 $ 485
The health plan cost trend rate assumed in determining the
accumulated postretirement benefit obligation was 12 percent in 1993,
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, 1995, by $3.5
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $253,000.
The accumulated postretirement benefit obligation was determined
using an assumed discount rate of 7 1/4 percent at December 31, 1995,
8 percent at December 31, 1994, and 7 percent at December 31, 1993,
and assumed long-term rates for estimated compensation increases, as
they apply to life insurance benefits, of 4 1/2 percent (5 percent at
December 31, 1994, and 4 1/2 percent at December 31, 1993). The
change in these assumptions had the effect of increasing the
accumulated postretirement benefit obligation at December 31, 1995, by
$7 million but decreasing the accumulated postretirement benefit
obligation at December 31, 1994, by $9 million. The assumed long-term
rate of return on assets is 7 1/2 percent. Plan assets consist
primarily of 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 $1.9 million in 1995, $1.7 million in 1994 and $1.4
million in 1993.
The company has a Key Employee Stock Option Plan under which the
company is authorized to grant options for up to 1.2 million shares of
common stock with an option price equal to market value on the date of
grant. The company has contributed $4.3 million to a trust
established to fund its commitment under the Plan.
Transactions involving option shares for the Key Employee Stock
Option Plan are as follows:
Options Price
Balance at December 31, 1992 292,199 $12.25-$15.75
Granted 4,830 17.58-20.83
Forfeited (8,595) 15.75
Exercised (22,470) 12.25
Balance at December 31, 1993 265,964 15.75-20.83
Granted ---
Forfeited (73,680) 15.75-17.58
Exercised ---
Balance at December 31, 1994 192,284 15.75-20.83
Granted 294,956 18.50
Forfeited (2,700) 20.83
Exercised (15,803) 15.75
Balance at December 31, 1995 468,737 15.75-18.50
Exercisable at December 31, 1995 138,524 15.75
Available for future grant at
December 31, 1995 715,460
The company has Tax Deferred Compensation Savings Plans for
eligible employees. Each participant may contribute amounts up to 10
percent of eligible compensation (15 percent effective January 1,
1996), 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 1995 and 1994, and $1.7
million in 1993.
NOTE 16
Partnership Investment
In September 1995, KRC Holdings, Inc. (a wholly owned subsidiary of
Knife River) 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, 1995, while its share of operating results is included in
"Other income--net" in the accompanying Consolidated Statements of
Income for the year ended December 31, 1995. Summarized financial
information for Hawaiian Cement, which is not consolidated and is
accounted for by the equity method, as of and for the four months
ended December 31, 1995, as applicable, is as follows:
(In thousands)
Current assets $19,531
Property, plant and equipment, net 70,544
Current liabilities 14,209
Other liabilities 15,736
Net sales 24,433
Operating margin 5,096
Income before income taxes 2,757
The company's original investment in Hawaiian Cement at the date
of acquisition exceeded the underlying net assets by $10.4 million.
The excess is being amortized over 30 years.
NOTE 17
Jointly Owned Facilities
The consolidated financial statements include the company's 22.7
percent and 25.0 percent ownership interests in the assets,
liabilities and expenses of the Big Stone Station and the Coyote
Station, respectively. Each owner of the Big Stone and Coyote
stations is responsible for 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:
1995 1994 1993
(In thousands)
Big Stone Station:
Utility plant in service $ 47,687 $ 46,923 $ 47,349
Accumulated depreciation 27,026 25,505 24,663
$ 20,661 $ 21,418 $ 22,686
Coyote Station:
Utility plant in service $122,126 $121,784 $121,380
Accumulated depreciation 49,296 45,546 42,482
$ 72,830 $ 76,238 $ 78,898
NOTE 18
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1995 and 1994:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
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
1994
Operating revenues $124,362 $105,036 $106,528 $113,602
Operating expenses 99,847 89,880 87,618 94,008
Operating income 24,515 15,156 18,910 19,594
Net income 11,699 5,677 12,351 10,118
Earnings per common share .40 .19 .43 .35
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 holds oil and natural gas interests primarily through a
series of working-interest agreements with several oil and natural gas
producers and through operating agreements with Shell Western E & P,
Inc. (Shell).
Fidelity Oil undertakes ventures, through working-interest
agreements with selected operators. These ventures vary from the
acquisition of producing properties with potential development
opportunities to exploration and are located in the western United
States, offshore in the Gulf of Mexico and in Canada. In these
ventures, Fidelity Oil shares revenues and expenses from the
development of specified properties in proportion to its investments.
Fidelity Oil has net proceeds interests in the production of oil
and natural gas and has an operating agreement (Agreement) with Shell
applicable to certain of its acreage interests. Pursuant to the
Agreement, Shell, as operator, controls all development, production,
operations and marketing applicable to such acreage. As a net
proceeds interest owner, Fidelity Oil is entitled to proceeds only
when a particular unit has reached payout status.
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:
1995 1994 1993
(In thousands)
Subject to amortization $173,501 $155,303 $114,572
Not subject to amortization 8,831 8,530 2,022
Total capitalized costs 182,332 163,833 116,594
Accumulated depreciation, depletion
and amortization 49,498 54,376 36,084
Net capitalized costs $132,834 $109,457 $ 80,510
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:
1995 1994 1993
(In thousands)
Acquisitions $ 9,402 $ 5,542 $ 9,296
Exploration 7,730 13,241 7,787
Development 25,403 21,189 7,836
Total capital expenditures $42,535 $39,972 $24,919
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:
1995 1994 1993
(In thousands)
Revenues* $53,484 $45,053 $39,125
Production costs 16,888 18,463 13,700
Depreciation, depletion and
amortization 19,058 13,926 11,998
Pretax income 17,538 12,664 13,427
Income tax expense 6,397 4,257 4,606
Results of operations for
producing activities $11,141 $ 8,407 $ 8,821
* Includes $4.7 million and $7.1 million of revenues for 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, 1995,
1994 and 1993 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.
1995 1994 1993
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 12,500 154,200 11,200 50,300 12,200 37,200
Production (2,000)(16,800) (1,600) (9,200) (1,500) (8,800)
Extensions and
discoveries 1,800 23,800 1,300 17,800 600 10,600
Purchases of proved
reserves 1,100 6,700 600 2,900 500 9,200
Sales of reserves
in place (300) (200) (400) (2,700) (300) (100)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 1,100 11,300 1,400 95,100* (300) 2,200
Balance at end of year 14,200 179,000 12,500 154,200 11,200 50,300
*Includes 99,300 MMcf of Williston Basin's natural gas reserves.
Proved developed reserves:
January 1, 1993 11,800 36,500
December 31, 1993 11,100 43,100
December 31, 1994 12,200 147,200**
December 31, 1995 13,600 156,400
**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, 1995, applicable to the company's $9.8
million gross investment in oil and natural gas properties located in
Canada comprise approximately 3 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:
1995 1994 1993
(In thousands)
Future net cash flows before
income taxes $267,300 $197,900 $119,800
Future income tax expenses 76,100 48,800 15,600
Future net cash flows 191,200 149,100 104,200
10% annual discount for estimated
timing of cash flows 70,300 54,200 32,600
Discounted future net cash flows
relating to proved oil and natural
gas reserves $120,900 $ 94,900 $ 71,600
The following are the sources of change in the standardized
measure of discounted future net cash flows by year:
1995 1994 1993
(In thousands)
Beginning of year $ 94,900 $ 71,600 $ 76,700
Net revenues from production (36,400) (23,800) (26,000)
Change in net realization 26,600 (4,100) (24,000)
Extensions, discoveries and improved
recovery, net of future
production-related costs 31,100 31,700 16,800
Purchases of proved reserves 10,900 5,800 14,100
Sales of reserves in place (1,000) (3,700) (1,600)
Changes in estimated future
development costs--net of those
incurred during the year (8,900) (2,900) (3,800)
Accretion of discount 12,300 8,300 8,900
Net change in income taxes (17,100) (4,000) 6,000
Revisions of previous quantity
estimates 8,700 16,500* 4,400
Other (200) (500) 100
Net change 26,000 23,300 (5,100)
End of year $120,900 $ 94,900 $ 71,600
*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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1995, 1994 and 1993,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1995. 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, 1995,
1994 and 1993, and the results of their operations and their cash
flows for each of the three years in the period ended December 31,
1995, in conformity with generally accepted accounting principles.
As discussed in Notes 1 and 15 to the consolidated financial
statements, effective January 1, 1993, the company changed its method
of accounting for recording electric and natural gas distribution
revenues, postretirement benefits other than pensions and income
taxes.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Minneapolis, Minnesota
January 24, 1996
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1995 1994 1993
Selected Financial Data
Operating revenues: (000's)
Electric $ 134,609 $ 133,953 $ 131,109
Natural gas 167,787 160,970 178,981
Construction materials and mining 113,066 116,646 90,397
Oil and natural gas production 48,784 37,959 39,125
$ 464,246 $ 449,528 $ 439,612
Operating income: (000's)
Electric $ 29,898 $ 27,596 $ 30,520
Natural gas distribution 6,917 3,948 4,730
Natural gas transmission 25,427 21,281 20,108
Construction materials and mining 14,463 16,593 16,984
Oil and natural gas production 13,871 8,757 11,750
$ 90,576 $ 78,175 $ 84,092
Earnings (loss) on common
stock: (000's)
Electric $ 12,000 $ 11,719 $ 12,652*
Natural gas distribution 1,604 285 1,182*
Natural gas transmission 8,416 6,155 4,713
Construction materials and mining 10,819 11,622 12,359
Oil and natural gas production 8,002 9,267 7,109
Earnings on common stock
before cumulative effect of
accounting change 40,841 39,048 38,015*
Cumulative effect of
accounting change --- --- 5,521
$ 40,841 $ 39,048 $ 43,536
Earnings per common share before
cumulative effect of
accounting change $ 1.43 $ 1.37 $ 1.34*
Cumulative effect of accounting
change --- --- .19
$ 1.43 $ 1.37 $ 1.53
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 41,633 $ 39,845 $ 38,817
Earnings per common share $ 1.43 $ 1.37 $ 1.34
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ 1.08 $ 1.05 $ 1.01
Book value per common share $ 11.85 $ 11.49 $ 11.17
Market price ratios:
Dividend payout 76% 77% 76%*
Yield 5.5% 5.9% 5.0%
Price/earnings ratio 13.9x 13.2x 15.8x*
Market value as a percent of
book value 167.7% 157.4% 188.0%
Profitability Indicators
Return on average common equity 12.3% 12.1% 12.3%*
Return on average invested capital 9.2% 9.1% 9.4%*
Interest coverage 3.9x 3.3x 3.4x*
Fixed charges coverage, including
preferred dividends 3.0x 2.9x 3.0x*
General
Total assets (000's) $1,056,479 $1,004,718 $1,041,051
Net long-term debt (000's) $ 237,352 $ 217,693 $ 231,770
Redeemable preferred stock (000's) $ 2,000 $ 2,100 $ 2,200
Capitalization ratios:
Common stockholders' investment 57% 58% 56%
Preferred stocks 3 3 3
Long-term debt 40 39 41
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the accrual
of estimated unbilled revenues.
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1992 1991 1990
Selected Financial Data
Operating revenues: (000's)
Electric $ 123,908 $128,708 $124,156
Natural gas 159,438 173,865 151,599
Construction materials and mining 45,032 41,201 38,276
Oil and natural gas production 33,797 33,939 31,213
$ 362,175 $377,713 $345,244
Operating income: (000's)
Electric $ 30,188 $ 34,647 $ 32,221
Natural gas distribution 4,509 8,518 6,578
Natural gas transmission 21,331 19,904 19,362
Construction materials and mining 11,532 9,682 7,749
Oil and natural gas production 9,499 12,552 12,523
$ 77,059 $ 85,303 $ 78,433
Earnings (loss) on common
stock: (000's)
Electric $ 13,302 $ 15,292 $ 14,280
Natural gas distribution 1,370 3,645 2,704
Natural gas transmission 3,479 449 (7,578)*
Construction materials and mining 10,662 9,809 9,632
Oil and natural gas production 5,751 8,010 8,071
Earnings on common stock
before cumulative effect of
accounting change 34,564 37,205 27,109*
Cumulative effect of
accounting change --- --- ---
$ 34,564 $ 37,205 $ 27,109*
Earnings per common share before
cumulative effect of
accounting change $ 1.21 $ 1.31 $ .95*
Cumulative effect of accounting
change --- --- ---
$ 1.21 $ 1.31 $ .95*
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 35,852 $ 37,619 $ 28,395*
Earnings per common share $ 1.23 $ 1.29 $ .97*
Common Stock Statistics
Weighted average common shares
outstanding (000's) 28,477 28,477 28,477
Dividends per common share $ .97 $ .96 $ .95
Book value per common share $ 10.66 $ 10.42 $ 10.08
Market price ratios:
Dividend payout 80% 73% 99%*
Yield 5.6% 5.8% 6.9%
Price/earnings ratio 14.5x 12.6x 14.3x*
Market value as a percent of
book value 165.0% 157.7% 135.6%
Profitability Indicators
Return on average common equity 11.6% 12.7% 9.4%*
Return on average invested capital 8.7% 9.6% 7.8%*
Interest coverage 3.3x 3.8x** 2.7x*
Fixed charges coverage, including
preferred dividends 2.4x 2.4x 1.9x*
General
Total assets (000's) $1,024,510 $964,691 $959,946
Net long-term debt (000's) $ 249,845 $220,623 $229,786
Redeemable preferred stock (000's) $ 2,300 $ 2,400 $ 2,500
Capitalization ratios:
Common stockholders' investment 53% 56% 54%
Preferred stocks 3 3 3
Long-term debt 44 41 43
100% 100% 100%
* Reflects a $6.8 million or 24 cent per share after-tax effect of an
absorption of certain natural gas contract litigation settlement costs.
** Calculation reflects the provisions of the company's restatement of its
Indenture of Mortgage effective April 1992.
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1995 1994 1993
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,993,693 1,955,136 1,893,713
Sales for resale (thousand kWh) 408,011 444,492 510,987
Electric system generating and
firm purchase capability--kW
(Interconnected system) 472,400 470,900 465,200
Demand peak--kW
(Interconnected system) 412,700 369,800 350,300
Electricity produced
(thousand kWh) 1,718,077 1,901,119 1,870,740
Electricity purchased
(thousand kWh) 867,524 700,912 701,736
Cost of fuel and purchased
power per kWh $.016 $.017 $.016
Natural Gas Distribution Operations
Sales (Mdk) 33,939 31,840 31,147
Transportation (Mdk) 11,091 9,278 12,704
Weighted average degree days--% of
previous year's actual 105% 92% 115%
Energy Marketing Operations
Natural gas volumes (Mdk) 3,556 7,301 6,827
Propane (thousand gallons) 7,471 6,462 2,210
Natural Gas Transmission Operations
Sales for resale (Mdk) --- --- 13,201
Transportation (Mdk) 68,015 63,870 59,416
Produced (Mdk) 4,981 4,732 3,876
Net recoverable reserves (MMcf) 113,000 99,300 ---
Construction Materials and
Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 2,904 2,688 2,391
Asphalt (tons sold) 373 391 141
Ready-mixed concrete (cubic
yards sold) 307 315 157
Recoverable aggregate reserves
in tons 68,000 71,000 74,200
Coal: (000's)
Sales in tons 4,218 5,206 5,066
Recoverable reserves in tons 231,900 236,100 230,600
Oil and Natural Gas Production
Operations
Production:
Oil (000's of barrels) 1,973 1,565 1,497
Natural gas (MMcf) 12,319 9,228 8,817
Average sales prices:
Oil (per barrel) $15.07 $ 13.14 $14.84
Natural gas (per Mcf) $ 1.51 $ 1.84 $ 1.86
Net recoverable reserves:
Oil (000's of barrels) 14,200 12,500 11,200
Natural gas (MMcf) 66,000 54,900 50,300
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1992 1991 1990
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,829,933 1,877,634 1,820,150
Sales for resale (thousand kWh) 352,550 331,314 285,564
Electric system generating and
firm purchase capability--kW
(Interconnected system) 460,200 454,400 451,600
Demand peak--kW
(Interconnected system) 339,100 387,100 381,600
Electricity produced
(thousand kWh) 1,774,322 1,736,187 1,674,648
Electricity purchased
(thousand kWh) 593,612 611,884 573,099
Cost of fuel and purchased
power per kWh $.016 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 26,681 30,074 28,278
Transportation (Mdk) 13,742 12,261 11,806
Weighted average degree days--% of
previous year's actual 98% 101% 88%
Energy Marketing Operations
Natural gas volumes (Mdk) 3,292 991 1,853
Propane (thousand gallons) --- --- ---
Natural Gas Transmission Operations
Sales for resale (Mdk) 16,841 19,572 19,658
Transportation (Mdk) 64,498 53,930 50,809
Produced (Mdk) 3,551 3,742 1,881
Net recoverable reserves (MMcf) --- --- ---
Construction Materials and
Mining Operations
Construction materials: (000's)
Aggregates (tons sold) 263 --- ---
Asphalt (tons sold) --- --- ---
Ready-mixed concrete (cubic
yards sold) --- --- ---
Recoverable aggregate reserves
in tons 20,600 --- ---
Coal: (000's)
Sales in tons 4,913 4,731 4,439
Recoverable reserves in tons 235,700 256,700 261,500
Oil and Natural Gas Production
Operations
Production:
Oil (000's of barrels) 1,531 1,491 1,374
Natural gas (MMcf) 5,024 2,565 1,846
Average sales prices:
Oil (per barrel) $16.74 $19.90 $20.11
Natural gas (per Mcf) $ 1.53 $ 1.48 $ 1.63
Net recoverable reserves:
Oil (000's of barrels) 12,200 11,600 12,400
Natural gas (MMcf) 37,200 27,500 16,100