[TEXT]
MDU RESOURCES GROUP, INC.
1993 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
its 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 to maintain a high
standard of 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 & Co.,
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 & Co. have full and free
access to the audit committee, without management present, to discuss
auditing, internal accounting control and financial reporting matters.
Arthur Andersen & Co. 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, 1993 1992 1991
(In thousands, except per share amounts)
Operating revenues:
Electric . . . . . . . . . . . . . . $131,109 $123,908 $128,708
Natural gas. . . . . . . . . . . . . 178,981 159,438 173,865
Mining and construction materials. . 90,397 45,032 41,201
Oil and natural gas production . . . 39,125 33,797 33,939
439,612 362,175 377,713
Operating expenses:
Fuel and purchased power . . . . . . 41,298 37,892 38,379
Purchased natural gas sold . . . . . 78,121 58,420 66,559
Operation and maintenance. . . . . . 167,374 126,311 128,253
Depreciation, depletion and
amortization . . . . . . . . . . . 45,162 39,694 36,577
Taxes, other than income . . . . . . 23,565 22,799 22,642
355,520 285,116 292,410
Operating income:
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
Mining and construction materials. . 16,984 11,532 9,682
Oil and natural gas production . . . 11,750 9,499 12,552
84,092 77,059 85,303
Other income -- net . . . . . . . . . 3,877 273 5,957
Interest expense -- net . . . . . . . 25,273 25,227 27,952
Carrying costs on natural gas
repurchase commitment (Note 5) . . . 3,897 5,834 8,483
Income before taxes. . . . . . . . . . 58,799 46,271 54,825
Income taxes . . . . . . . . . . . . . 19,982 10,900 16,808
Income before cumulative effect
of accounting change . . . . . . . . 38,817 35,371 38,017
Cumulative effect of accounting
change (Note 2). . . . . . . . . . . 5,521 --- ---
Net income . . . . . . . . . . . . . . 44,338 35,371 38,017
Dividends on preferred stocks. . . . . 802 807 812
Earnings on common stock . . . . . . . $ 43,536 $ 34,564 $ 37,205
Earnings per common share:
Earnings before cumulative effect
of accounting change. . . . . . . . $ 2.00 $ 1.82 $ 1.96
Cumulative effect of accounting
change. . . . . . . . . . . . . . . .29 --- ---
Earnings . . . . . . . . . . . . . . $ 2.29 $ 1.82 $ 1.96
Dividends per common share . . . . . . $ 1.52 $ 1.46 $ 1.435
Average common shares outstanding . . 18,985 18,985 18,985
Pro forma amounts assuming
retroactive application of
accounting change:
Net income . . . . . . . . . . . . . $ 38,817 $ 35,852 $ 37,619
Earnings per common share. . . . . . $ 2.00 $ 1.85 $ 1.94
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1993 1992 1991
(In thousands)
ASSETS
Property, plant and equipment:
Electric . . . . . . . . . . . . . $ 503,690 $ 491,943 $ 482,312
Natural gas distribution . . . . . 141,100 125,314 120,155
Natural gas transmission . . . . . 258,766 278,978 271,569
Mining and construction materials. 145,014 104,370 88,535
Oil and natural gas production . . 116,833 93,667 68,253
1,165,403 1,094,272 1,030,824
Less accumulated depreciation,
depletion and amortization . . . 501,451 469,232 436,277
663,952 625,040 594,547
Current assets:
Cash and cash equivalents. . . . . 71,699 66,838 54,593
Receivables. . . . . . . . . . . . 67,553 57,902 43,334
Inventories. . . . . . . . . . . . 19,415 18,214 16,228
Exchange natural gas receivable. . 727 25,195 25,992
Deferred income taxes. . . . . . . 32,243 18,962 11,335
Other prepayments and
current assets . . . . . . . . . 13,535 15,302 10,913
205,172 202,413 162,395
Natural gas available under
repurchase commitment (Note 5) . . 79,031 92,038 99,449
Investments. . . . . . . . . . . . . 16,858 61,934 67,188
Deferred charges and other assets. . 76,038 43,085 41,112
$1,041,051 $1,024,510 $ 964,691
CAPITALIZATION AND LIABILITIES
Capitalization (see separate
statements):
Common stockholders' investment. . $ 318,131 $ 303,452 $ 296,605
Preferred stocks . . . . . . . . . 17,100 17,200 17,300
Long-term debt . . . . . . . . . . 231,770 249,845 220,623
567,001 570,497 534,528
Commitments and contingencies
(Notes 3, 4, 5, 6, 15 and 18). . . --- --- ---
Current liabilities:
Short-term borrowings. . . . . . . 9,540 7,775 ---
Accounts payable . . . . . . . . . 24,967 25,397 18,495
Taxes payable. . . . . . . . . . . 9,204 8,958 10,120
Other accrued liabilities,
including reserved revenues. . . 105,195 87,950 69,340
Exchange natural gas deliverable . 2,371 25,046 26,641
Dividends payable. . . . . . . . . 7,605 7,226 7,037
Long-term debt and preferred
stock due within one year. . . . 15,300 300 2,400
174,182 162,652 134,033
Natural gas repurchase commitment
(Note 5) . . . . . . . . . . . . . 98,525 114,937 123,981
Deferred credits:
Deferred income taxes and
unamortized investment tax
credit . . . . . . . . . . . . . 124,978 135,571 138,758
Other. . . . . . . . . . . . . . . 76,365 40,853 33,391
201,343 176,424 172,149
$1,041,051 $1,024,510 $ 964,691
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
December 31, 1993 1992 1991
(In thousands)
Common stockholders' investment:
Common stock (Note 9):
Authorized -- 50,000,000 shares,
$5 par value in 1993,
1992 and 1991
Outstanding -- 18,984,654 shares . $ 94,923 $ 94,923 $ 94,923
Other paid in capital . . . . . . . . 64,210 64,210 64,210
Retained earnings (Note 10) . . . . . 158,998 144,319 137,472
Total common stockholders'
investment. . . . . . . . . . . . . 318,131 303,452 296,605
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 -- 22,000 shares
in 1993 (23,000 in 1992 and
24,000 in 1991). . . . . . . . 2,200 2,300 2,400
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 17,200 17,300 17,400
Less current maturities and
sinking fund requirements. . . . . . 100 100 100
Net preferred stocks . . . . . . . . . 17,100 17,200 17,300
Long-term debt (Note 12):
First mortgage bonds and notes . . . . 195,850 195,850 180,400
Pollution control lease and note
obligation, 6.2%, due in
annual installments to 2004 . . . . . 4,800 5,000 26,050
Senior secured note, 8.43%,
due December 31, 2000 . . . . . . . . 15,000 --- ---
Secured line of credit at various
interest rates, terminating
October 6, 2002 . . . . . . . . . . . 1,500 19,400 ---
Term loan at various interest rates,
terminating December 31, 1996. . . . 30,000 30,000 16,900
Other. . . . . . . . . . . . . . . . . (180) (205) (427)
Total long-term debt . . . . . . . . . 246,970 250,045 222,923
Less current maturities and sinking
fund requirements. . . . . . . . . . 15,200 200 2,300
Net long-term debt . . . . . . . . . . 231,770 249,845 220,623
Total capitalization . . . . . . . . . .$567,001 $570,497 $534,528
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
Years ended December 31, 1993 1992 1991
(In thousands)
Operating activities:
Net income . . . . . . . . . . . . . $ 44,338 $ 35,371 $ 38,017
Cumulative effect of accounting
change . . . . . . . . . . . . . . (5,521) --- ---
Adjustments to reconcile net income
to net cash provided by operations:
Depreciation, depletion and
amortization . . . . . . . . . . 45,162 39,694 36,577
Deferred income taxes and
investment tax credit -- net . . 16,040 (789) 747
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes . . . 8,467 3,996 4,633
Changes in current assets and
liabilities --
Receivables. . . . . . . . . . . (775) (14,568) 983
Inventories. . . . . . . . . . . (1,201) (1,834) 5,457
Other current assets . . . . . . 12,954 (11,219) 4,402
Accounts payable . . . . . . . . (430) 6,902 (1,420)
Other current liabilities. . . . (8,160) 16,042 4,530
Other noncurrent changes . . . . . (13,687) 190 1,298
Net cash provided by operations. . . 97,187 73,785 95,224
Financing activities:
Net change in short-term borrowings. 1,765 7,775 ---
Issuance of long-term debt . . . . . 15,200 167,100 84,920
Repayment of long-term debt. . . . . (18,300) (140,200) (93,611)
Retirement of preferred stocks . . . (100) (100) (504)
Retirement of natural gas
repurchase commitment. . . . . . . (16,412) (9,044) ---
Dividends paid . . . . . . . . . . . (29,659) (28,524) (28,055)
Net cash used in financing
activities . . . . . . . . . . . . (47,506) (2,993) (37,250)
Investing activities:
Additions to property, plant and
equipment and acquisitions of
businesses --
Electric . . . . . . . . . . . . . (16,156) (13,226) (11,728)
Natural gas distribution . . . . . (15,012) (6,461) (5,758)
Natural gas transmission . . . . . (3,669) (9,452) (4,093)
Mining and construction materials. (43,123) (16,295) (909)
Oil and natural gas production . . (24,943) (25,778) (22,284)
(102,903) (71,212) (44,772)
Sale of natural gas available
under repurchase commitment. . . . 13,007 7,411 ---
Investments. . . . . . . . . . . . . 45,076 5,254 (2,851)
Net cash used in investment
activities . . . . . . . . . . . . (44,820) (58,547) (47,623)
Increase in cash and cash
equivalents. . . . . . . . . . . . 4,861 12,245 10,351
Cash and cash equivalents --
beginning of year. . . . . . . . . 66,838 54,593 44,242
Cash and cash equivalents --
end of year. . . . . . . . . . . . $ 71,699 $ 66,838 $ 54,593
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
[TEXT] NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
Years Ended December 31, 1993, 1992 and 1991
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 sales of electricity, natural gas and propane, and natural gas
transmission, storage and sales at wholesale -- and two non-regulated
businesses -- mining and construction materials 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.
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.
Property, plant and equipment and investments
Additions to property, plant and equipment are recorded at cost when
first placed in service. When utility 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. The company is permitted to capitalize an allowance for
funds used during construction (AFUDC) on utility construction
projects and to include such amounts in rate base when the related
facilities are placed in service. AFUDC capitalized was insignificant
in 1993, 1992 and 1991. 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, consisting principally of securities held for corporate
development purposes, are carried at cost which approximates market.
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
The company recognizes revenue each month based on the services
provided to all customers during the month. Because meters for retail
utility customers are read and billed on a monthly cycle billing
basis, revenues (and related energy costs) are estimated and recorded
for those services provided from the date which meters were last read
to month end. Prior to 1993, the company recorded revenue and the
cost of purchased natural gas sold when customers were billed. See
Note 2 for a discussion of an accounting change in the company's
revenue recognition method made effective January 1, 1993.
Natural gas costs recoverable through rate adjustments
Under the terms of certain orders of the public service commissions of
Montana, North Dakota, South Dakota and Wyoming, 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
Effective with the adoption of Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109) on
January 1, 1993, as further described in Note 2, the company is
providing deferred federal and state income taxes on all temporary
differences. Prior to 1993, the company provided deferred federal and
state income taxes on all non-utility timing differences and on all
FERC jurisdictional utility timing differences. With respect to state
jurisdictions, deferred federal and state income taxes were provided
on utility timing differences only as permitted for ratemaking
purposes.
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 public service commissions of
Montana, North Dakota, South Dakota and Wyoming.
Cash flow information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 1993 1992 1991
(In thousands)
Interest, net of amount capitalized. . .$22,717 $25,578 $29,749
Income taxes . . . . . . . . . . . . . .$24,545 $21,577 $17,645
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 1992 and 1991 to conform to the 1993 presentation. Such
reclassifications had no effect on net income or common stockholders'
investment as previously reported.
NOTE 2
Accounting Changes
Revenue recognition
On January 1, 1993, Montana-Dakota Utilities Co. (Montana-Dakota)
changed its revenue recognition method to include the accrual of
estimated unbilled revenues for electric and natural gas service.
This change results in a better matching of revenues and expenses and
is consistent with predominant industry practice. Prior to this
change, Montana-Dakota, for both its electric and natural gas
businesses, recognized revenues on a monthly cycle billing basis which
recorded revenues when customers were billed. Unbilled utility
revenues at December 31, 1993, aggregated $18.3 million and are
included in "Receivables" in the company's consolidated balance
sheets. The cumulative effect of this change on net income for the
twelve months ended December 31, 1993, is presented net of applicable
income taxes of $3,355,000.
Postretirement benefits other than pensions
On January 1, 1993, the company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS No. 106). The
company has 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 company's annual cost
for 1993 based on the provisions of SFAS No. 106 is approximately $7.5
million, including amortization of the transition obligation discussed
above. However, substantially all of the amounts related to Montana-
Dakota's and Williston Basin Interstate Pipeline Company's (Williston
Basin) regulated operations reflecting the difference between the 1993
SFAS No. 106 required accruals of approximately $6.0 million and the
costs associated with the currently recoverable pay-as-you-go method,
estimated to be approximately $2.0 million, are being deferred
pursuant to regulatory orders received and are expected to be
recovered in future rates charged to customers. See Note 15 for more
information on the regulatory treatment of SFAS No. 106 costs.
Accounting for income taxes
On January 1, 1993, the company adopted SFAS No. 109. The company
elected to record the cumulative effect 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, 1993. This regulatory
liability is expected to be reflected as a reduction in future rates
charged customers in accordance with applicable regulatory procedures.
NOTE 3
Pending Litigation
Koch Hydrocarbon Company (Koch)
On August 11, 1993, Koch and Williston Basin reached a settlement that
terminated the litigation, as previously described in the 1992 Annual
Report to Stockholders, with respect to all parties. The settlement,
as to both the company and Williston Basin, satisfies all of Koch's
claims for the past obligation, releases any claim with respect to
obligations up to the present time and terminates any contractual
arrangements with respect to the purchase of natural gas between the
parties for the future. The settlement thus resolves both the past
and the future obligation. In return, Williston Basin agreed to make
an immediate cash payment to Koch of $40 million (inclusive of the $32
million awarded by the District Court in October 1991) and to transfer
to Koch certain natural gas gathering facilities owned by Williston
Basin having a cost, net of accumulated depreciation, of approximately
$10.4 million.
The company believes that it is entitled to recover from ratepayers
most of the costs that were incurred as a result of this settlement.
Since the amount of costs which can ultimately be recovered is subject
to regulatory and market uncertainties, the company has provided
reserves which it believes are adequate for any amounts that may not
be recovered. Williston Basin expects to recover $8.3 million in
settlement costs through its purchased gas cost adjustment recovery
mechanism. See "Producer settlement cost recovery" and "Order 636"
contained in Note 4 for a discussion of Williston Basin's filings
under the FERC's Orders 500 and 636, respectively, requesting recovery
of the balance of the costs associated with the Koch settlement.
KN Energy, Inc. (KN)
In May 1991, KN, a pipeline for whom Williston Basin transports
natural gas, filed suit against Williston Basin in Federal District
Court for the District of Montana. KN alleges, in part, that
Williston Basin breached its contract with KN by failing to provide
priority transportation for KN, and by charging KN transportation
rates which were excessive. KN also alleges that Williston Basin is
responsible for any take-or-pay costs it may incur as a result of the
breach. Although no amount of damages was specified, KN asked the
Court to order Williston Basin to reimburse KN for damages and certain
other costs it has incurred along with requiring specific performance
pursuant to the contract. Williston Basin filed a motion for summary
judgment with the Court in August 1992, requesting that the Court
dismiss KN's suit on the basis that these matters are more appropriate
for FERC resolution. In September 1992, the Court denied Williston
Basin's motion for summary judgment, but suspended the proceedings
before it and referred these matters to the FERC. If the FERC is not
able to ultimately resolve this dispute, both KN and Williston Basin
can request reconsideration by the Court at that time. As of the
present time, KN has not requested further action by the FERC.
Although no assurances can be provided, based on previous FERC
decisions, Williston Basin believes that the ultimate outcome of this
matter will not be material to its financial position or results of
operations.
NOTE 4
Regulatory Matters and Revenues Subject to Refund
General rate proceedings
Williston Basin has pending two general natural gas rate change
applications filed in 1989 and 1992 and has implemented these changed
rates subject to refund. Williston Basin is awaiting final orders
from the FERC.
Reserves have been provided for a portion of the revenues collected
subject to refund with respect to pending regulatory proceedings and
for the recovery of certain producer settlement buy-out/buy-down costs
as discussed below 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.
Producer settlement cost recovery
In June 1990, Williston Basin filed to recover 75 percent of $43.4
million ($32.6 million) in buy-out/buy-down costs under the alternate
take-or-pay cost recovery mechanism embodied in Order 500. As
permitted under Order 500, Williston Basin elected to recover 25
percent or $10.8 million of such costs through a direct surcharge to
its sales customers, substantially all of which has been received,
with an equal amount being charged to second quarter 1990 earnings.
Williston Basin elected to recover the remaining 50 percent ($21.7
million) through a commodity sales rate surcharge. In July 1990, the
FERC issued an order requiring Williston Basin to recalculate its
surcharge and apply it to total throughput. Through December 31,
1993, Williston Basin has collected $23.6 million, including interest,
of these costs through its commodity sales and transportation rate
surcharges. In November 1990, Williston Basin appealed this order to
the U.S. Court of Appeals for the D.C. Circuit. Oral argument before
the Court was held in November 1991. In July 1992, the Court issued
its order denying Williston Basin's appeal and remanding certain
aspects of the case to the FERC. On May 6, 1993, the FERC issued an
order on those issues remanded by the Court. The principal issue
addressed by this order involved the exemption of one of Williston
Basin's major transportation customers from the assessment of take-or-
pay surcharges. Williston Basin made a filing seeking authority to
reallocate these costs to its other customers, which the FERC
approved.
On August 26, 1993, Williston Basin filed to recover 75 percent of
$28.7 million ($21.5 million) in buy-out/buy-down costs paid to Koch
as part of a lawsuit settlement under the alternate take-or-pay cost
recovery mechanism embodied in Order 500. As permitted under Order
500, Williston Basin elected to recover 25 percent or $7.2 million of
such costs through a direct surcharge to sales customers,
substantially all of which has been received. In addition, through
reserves previously provided, Williston Basin has absorbed an equal
amount. Williston Basin elected to recover the remaining 50 percent
($14.3 million) through a throughput surcharge applicable to both
sales and transportation. Williston Basin began collecting these
costs, subject to refund, on October 1, 1993, pending the outcome of
future hearings in mid-1994.
Order 636
In April 1992, the FERC issued Order 636, which requires fundamental
changes in the way natural gas pipelines do business. Under Order
636, pipelines are required to offer unbundled transportation service,
with the transportation customer having the option of purchasing gas
from other suppliers. Pipelines are also required to provide
"equivalent" transportation services for all customers regardless of
whether they are purchasing gas from such pipeline or other suppliers.
As a part of Order 636, the FERC acknowledged that incremental costs
may be required in the transition to the FERC-mandated service
structures. Such costs include facility costs, gas supply contract
restructuring and similar costs. Specific references concerning the
allowed recovery of such costs are included in the final rule.
In addition, Order 636 changes the rate design methodology used for
pipeline transportation to the straight fixed variable (SFV) method.
Under the SFV approach, all fixed storage and transmission costs,
including return on equity and associated taxes, are included in the
demand charge (a fixed monthly charge) and all variable costs are
recovered through a commodity charge based on volumes transported.
Under SFV, pipelines should be able to recover all fixed costs
properly allocable to firm transportation regardless of how much gas
is actually transported. Also included in Order 636 were guidelines
addressing abandonment of services, capacity release and/or assignment
of firm capacity rights.
In October 1992, Williston Basin filed a revised tariff with the
FERC designed to comply with Order 636. The revised tariff reflected
the cost allocation and rate design necessary to the unbundling of
Williston Basin's current services. The FERC issued an order on
February 12, 1993, in which it accepted Williston Basin's filing
subject to certain conditions.
On March 15, 1993, Williston Basin filed further tariff revisions
with the FERC in compliance with the FERC's February 12, 1993, order,
and on March 12, 1993, filed for rehearing and/or clarification of
other matters raised in the February 12, 1993, order. On May 13,
1993, the FERC issued an order addressing both Williston Basin's
rehearing request and its March 15 tariff filing. A significant issue
addressed by the FERC's order was a determination that certain natural
gas in underground storage which was determined to be excess upon the
future implementation of Order 636 must be sold at market prices. The
order further required that the profit from such sale be used to
offset any transition costs. Williston Basin requested rehearing of
this and other issues by the FERC.
An appeal was filed by Williston Basin on June 30, 1993, with the
U.S. Court of Appeals for the D.C. Circuit related to, among other
things, the FERC allowing firm transportation customers flexible
receipt and delivery points anywhere on Williston Basin's pipeline
system upon implementation of Order 636.
On September 17, 1993, the FERC issued its order authorizing
Williston Basin's implementation of Order 636 tariffs effective
November 1, 1993. As a part of this order, the FERC reversed its
May 13, 1993, determination related to the sale of certain natural gas
in underground storage and ordered that this storage gas be offered
for sale to Williston Basin's customers at its original cost. As a
result, any profits which would have been realized on the sale at
market prices of this storage gas will not reduce Williston Basin's
Order 636 transition costs. Williston Basin requested rehearing of
this issue by the FERC on the grounds that requiring the sale of this
storage gas at cost results in a confiscation of its assets, which the
FERC denied on December 16, 1993. Williston Basin has appealed the
FERC's decisions to the U.S. Court of Appeals for the D.C. Circuit.
On November 5, 1993, Williston Basin filed with the FERC, pursuant
to the provisions of Order 636, revised tariff sheets requesting the
recovery of $13.4 million of gas supply realignment transition costs
(GSR costs) effective December 1, 1993. The GSR cost recovery being
requested reflects costs paid to Koch as part of a lawsuit settlement,
as previously described in Note 3, and does not include other GSR
costs, if any, which may be incurred, and future recovery sought, by
Williston Basin. This matter is currently pending before the FERC.
Montana-Dakota has also filed revised gas cost tariffs with each of
its four state regulatory commissions reflecting the effects of
Williston Basin's November 1, 1993, implementation of Order 636. In
October 1993, all four state regulatory commissions approved the
revised tariffs.
Although no assurances can be provided, the company believes that
Order 636 will not have a significant effect on its financial position
or results of operations.
NOTE 5
Natural Gas Repurchase Commitment
The company has offered for sale since 1984 the 61 million decatherms
(MMdk) of inventoried natural gas owned by Frontier Gas Storage
Company (Frontier), a special purpose, non-affiliated corporation.
Through an agreement, an obligation exists 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 through the issuance of
commercial paper that has the credit support of an irrevocable $105
million letter of credit. At December 31, 1993, borrowings totalled
$101.1 million at a weighted average interest rate of 3.5 percent.
These transactions will terminate on November 30, 1995, unless
terminated earlier by the occurrence of certain events.
The FERC issued an order in July 1989, ruling on several cost-of-
service issues reserved as a part of the 1985 corporate realignment.
Addressed as a part of this order were certain rate design issues
related to the permissible rates for the transportation of the natural
gas held under the repurchase commitment. The issue relating to the
cost of storing this gas was not decided by that order. As a part of
orders issued in August 1990 and May 1991 related to a general rate
increase application, the FERC held that storage costs should be
allocated to this gas. Williston Basin's July 1991 refund related to
a general rate increase application, reflected implementation of the
above finding on a prospective basis only. The public service
commissions of Montana and South Dakota and the Montana Consumer
Counsel protested whether such storage costs should be allocated to
the gas prospectively rather than retroactively to May 2, 1986. In
October 1991, the FERC issued an order rejecting Williston Basin's
compliance filing on the basis that, among other things, Williston
Basin is required to allocate storage costs to this gas retroactive to
May 2, 1986. Williston Basin requested rehearing of the FERC's order
on this issue in November 1991. In February 1992, the FERC issued an
order which reversed its October 1991 order and held that such storage
costs be allocated to this gas on a prospective basis only, commencing
March 6, 1992. A compliance filing was made with the FERC in
March 1992, which the FERC approved on and with an effective date
beginning May 20, 1992. These storage costs, as initially allocated
to the Frontier gas, approximated $2.1 million annually and represent
costs which Williston Basin may not recover. The issue regarding the
applicability of assessing storage charges to the gas, which was
appealed by Williston Basin to the U.S. Court of Appeals for the D.C.
Circuit in July 1991, creates additional uncertainty as to the costs
associated with holding this gas. In July 1992, the Court, at the
FERC's request, returned the proceeding to the FERC for its further
consideration.
Beginning in October 1992, as a result of increases in natural gas
prices, Williston Basin began to sell and transport a portion of the
natural gas held under the repurchase commitment. Through
December 31, 1993, 12.5 MMdk of this natural gas had been sold and
transported by Williston Basin to off-system markets. Williston Basin
will continue to aggressively market the remaining 48.3 MMdk of this
natural gas as long as market conditions remain favorable. In
addition, it will continue to seek long-term sales contracts.
NOTE 6
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. Both Montana-Dakota and
Williston Basin have initiated testing, monitoring and remediation
procedures, in accordance with applicable regulations and the work
plan submitted to the EPA and the appropriate state agencies. Costs
incurred by Montana-Dakota and Williston Basin through December 31,
1993, to address this situation aggregated approximately $720,000.
These costs are related to the testing being performed, and the costs
to remove, dispose of and replace certain property found to be
contaminated. On the basis of findings to date, Montana-Dakota and
Williston Basin estimate that future environmental assessment and
remediation costs that will be incurred range from $3 million to $15
million. This estimate depends upon a number of assumptions
concerning the scope of remediation that will be required at certain
locations, the cost of remedial measures to be undertaken and the time
period over which the remedial measures are implemented. In a
separate action, Montana-Dakota and Williston Basin filed suit in
Montana State Court, Yellowstone County, in January 1991, against
Rockwell International Corporation, manufacturer of the valve sealant,
to recover any costs which may be associated with the presence of PCBs
in the system, including a remediation program. On January 31, 1994,
Montana-Dakota, Williston Basin and Rockwell reached a settlement
which terminated this litigation. Pursuant to the terms of the
settlement, Rockwell will reimburse Montana-Dakota and Williston Basin
for a portion of certain remediation costs incurred or expected to be
incurred. In addition, both Montana-Dakota and Williston Basin
consider unreimbursed environmental remediation costs and costs
associated with compliance with environmental standards to be
recoverable through rates, since they are prudent costs incurred in
the ordinary course of business and, accordingly, have sought and will
continue to seek recovery of such costs through rate filings.
Although no assurances can be given, based on the estimated cost of
the remediation program and the expected recovery of most of these
costs from third parties or ratepayers, Montana-Dakota and Williston
Basin believe that the ultimate costs related to these matters will
not be material to Montana-Dakota's or Williston Basin's financial
position or results of operations.
In mid-1992, Williston Basin discovered that several of its natural
gas compressor stations had been operating without air quality
permits. As a result, in late 1992, applications for permits were
filed with the Montana Air Quality Bureau (Bureau), the agency for the
state of Montana which regulates air quality. In March 1993, the
Bureau cited Williston Basin for operating the compressors without the
requisite air quality permits and further alleged excessive emissions
by the compressor engines of certain air pollutants, primarily oxides
of nitrogen and carbon monoxide. Williston Basin is currently engaged
in further testing these air emissions but is currently unable to
determine the costs that will be incurred to remedy the situation
although such costs are not expected to be material to its financial
position 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. An informational meeting was held on January 20,
1993, between the EPA and the PRPs outlining the EPA's proposed remedy
and the settlement process. On June 21, 1993, the EPA issued its
decision on the selected remediation to be performed at the site.
Based on the EPA's proposed remediation plan, current estimates of the
total cleanup costs for all parties, including oversight costs, at
this site range from approximately $3.7 million to $4.8 million.
Montana-Dakota believes that it was not a material contributor to this
contamination and, therefore, further believes that its share of the
liability for such cleanup will not have a material effect on its
results of operations.
NOTE 7
Natural Gas in Underground Storage
Natural gas in underground storage included in natural gas
transmission property, plant and equipment amounted to approximately
$49 million at December 31, 1993, $51 million at December 31, 1992 and
$53 million at December 31, 1991. In addition, $1.3 million, $3.7
million and $3.6 million at December 31, 1993, 1992 and 1991,
respectively, of natural gas in underground storage is included in
inventories.
NOTE 8
Short-term Borrowings
The company and its subsidiaries had unsecured lines of credit from
several banks totalling $86 million at December 31, 1993, $80 million
at December 31, 1992 and $73 million at December 31, 1991. 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 $9.5 million at December 31, 1993 and $7.8
million at December 31, 1992, with no amounts outstanding at
December 31, 1991. The unused portions of the lines of credit are
subject to withdrawal based on the occurrence of certain events.
NOTE 9
Common Stock
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-hundredth of a share of Series A
preference stock, without par value, at a purchase price of $50,
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
common stock of the acquiring person having a market value of twice
the exercise price of the right. The rights, which expire in November
1998, are redeemable in whole, but not in part, at the company's
option at any time for a price of $.02 per right.
There have been no changes in the amounts outstanding for common
stock and other paid in capital during the years ended December 31,
1993, 1992 and 1991.
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, 1993, there were 1,020,229
shares of common stock reserved for issuance under the plans.
NOTE 10
Retained Earnings
Changes in retained earnings for the years ended December 31, 1993,
1992 and 1991 are as follows:
1993 1992 1991
(In thousands)
Balance at beginning of year . . . . . .$144,319 $137,472 $127,914
Net income . . . . . . . . . . . . . . . 44,338 35,371 38,017
188,657 172,843 165,931
Deduct:
Dividends declared --
Preferred stocks at required
annual rates . . . . . . . . . . . 802 807 812
Common stock . . . . . . . . . . . . 28,857 27,717 27,243
29,659 28,524 28,055
Settlement costs associated with
repurchase of preferred stocks . . . --- --- 404
Balance at end of year . . . . . . . . .$158,998 $144,319 $137,472
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, 1993, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
First mortgage bonds and notes outstanding at December 31 are as
follows:
1993 1992 1991
(In thousands)
7 1/8% Series, due Nov. 1, 1993. . . .$ --- $ --- $ 9,400
8 5/8% Series, due Oct. 1, 2001. . . . --- --- 9,400
9 1/4% Series, due Sept. 15, 2003. . . --- --- 9,400
9 3/8% Series, due Nov. 15, 2011 . . . --- --- 75,200
9 1/8% Series, due May 15, 2006. . . . 50,000 50,000 50,000
9 1/8% Series, due Oct. 1, 2016. . . . 20,000 20,000 20,000
7 5/8% Sinking Fund, due Oct. 15, 1992 --- --- 1,000
8 1/2% Sinking Fund, due Oct. 1, 1996. --- --- 2,500
9% Sinking Fund, due Sept. 15, 1998. . --- --- 3,500
Pollution Control Refunding Revenue
Bonds, Series 1992 --
Mercer County, North Dakota, 6.65%,
due June 1, 2022 . . . . . . . . . 15,000 15,000 ---
Morton County, North Dakota, 6.65%,
due June 1, 2022 . . . . . . . . . 2,600 2,600 ---
Richland County, Montana, 6.65%,
due June 1, 2022 . . . . . . . . . 3,250 3,250 ---
Secured Medium-Term Notes, Series A --
5.80%, due Apr. 1, 1994. . . . . . . 15,000 15,000 ---
6.30%, due Apr. 1, 1995. . . . . . . 10,000 10,000 ---
6.95%, due Apr. 1, 1996. . . . . . . 10,000 10,000 ---
7.20%, due Apr. 1, 1997. . . . . . . 5,000 5,000 ---
8.25%, due Apr. 1, 2007. . . . . . . 30,000 30,000 ---
8.60%, due Apr. 1, 2012. . . . . . . 35,000 35,000 ---
Total first mortgage bonds
and notes. . . . . . . . . . . . . $195,850 $195,850 $180,400
The company has a revolving credit and term loan agreement which
totalled $30 million at December 31, 1993, 1992 and 1991. Amounts
outstanding under this agreement were $30 million at December 31, 1993
and 1992, respectively, and $10.5 million at December 31, 1991.
Fidelity Oil Co. has $15 million outstanding under a senior secured
note at December 31, 1993. In addition, Fidelity Oil Co. has
available $20 million under a secured line of credit, $1.5 million of
which was outstanding at December 31, 1993. At December 31, 1992,
Fidelity Oil Co. had a secured line of credit which totalled $35
million, of which $19.4 million was outstanding. However, on
January 13, 1993, $15 million of the line was converted to a senior
secured note. Fidelity Oil Co. had available $15 million under a
revolving credit and term loan agreement at December 31, 1991, $6.4
million of which was outstanding.
The amounts of long-term debt maturities and sinking fund
requirements for the five years following December 31, 1993, (net of
prepayments) aggregate $15.2 million in 1994; $10.7 million in 1995;
$40.7 million in 1996; $14.7 million in 1997 and $9.6 million in 1998.
Substantially all of the company's retail utility property is subject
to the lien of its Indenture of Mortgage. Under the terms and
conditions of such Indenture, the company could have issued
approximately $153 million of additional first mortgage bonds at
December 31, 1993. Certain natural gas transmission property is
subject to purchase money mortgages payable by Williston Basin to the
company.
In December 1991, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 107,
"Disclosures about Fair Value of Financial Instruments" (SFAS No.
107). SFAS No. 107 establishes fair value disclosure practices for
certain financial instruments. The fair value of the company's first
mortgage bonds and notes at December 31, 1993, is approximately $216
million. However, the difference between the recorded value of the
company's other debt instruments as well as investments in certain
securities and their fair values were not material.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1993 1992 1991
(In thousands)
Current --
Federal. . . . . . . . . . . . . . . $25,665 $ 18,272 $14,287
State. . . . . . . . . . . . . . . . 3,997 3,359 2,972
Foreign. . . . . . . . . . . . . . . 10 --- ---
29,672 21,631 17,259
Deferred --
Investment tax credit -- net . . . . (1,144) (1,183) (1,236)
Income taxes:
Federal. . . . . . . . . . . . . . (9,560) (8,505) 722
State. . . . . . . . . . . . . . . 1,014 (1,043) 63
(9,690) (10,731) (451)
Total income tax expense . . . . . . . $19,982 $ 10,900 $16,808
Components of deferred tax assets and deferred tax liabilities
recognized in the company's consolidated balance sheets are as
follows:
1993
(In thousands)
Deferred tax assets:
Reserves for regulatory matters . . . . . . . . . . . . . $ 40,195
Natural gas available under repurchase commitment . . . . 7,554
Deferred investment tax credits . . . . . . . . . . . . . 4,462
Accrued land reclamation. . . . . . . . . . . . . . . . . 4,017
Accrued pension costs . . . . . . . . . . . . . . . . . . 3,676
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,428
Total deferred tax assets. . . . . . . . . . . . . . . . . $ 66,332
Deferred tax liabilities:
Depreciation and basis differences on property,
plant and equipment . . . . . . . . . . . . . . . . . . $108,846
Basis differences on oil and natural gas
producing properties. . . . . . . . . . . . . . . . . . 15,889
Natural gas contract settlement and
restructuring costs . . . . . . . . . . . . . . . . . . 13,530
Long-term debt refinancing costs. . . . . . . . . . . . . 5,223
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 4,078
Total deferred tax liabilities . . . . . . . . . . . . . . $147,566
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:
1993 1992 1991
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate . . . . $20,580 35.0 $15,732 34.0 $18,640 34.0
Increases (reductions)
in provision for
taxes resulting from:
Depletion allowance. . (1,424) (2.4) (1,393) (3.0) (1,433) (2.6)
State income
taxes -- net of
federal income tax
benefit. . . . . . . 2,171 3.7 1,664 3.6 1,949 3.6
Tax-exempt interest. . (725) (1.2) (958) (2.1) (1,174) (2.1)
Investment tax credit
amortization . . . . (1,144) (2.0) (1,183) (2.5) (1,236) (2.3)
Other items. . . . . . 524 .9 (2,962) (6.4) 62 .1
Actual taxes . . . . . . $19,982 34.0 $10,900 23.6 $16,808 30.7
During 1992 and 1991, deferred income tax expense resulted from
differences in the timing of recognizing certain revenues and expenses
for tax and financial statement purposes. The sources of these
differences and the tax effect of each are as follows:
1992 1991
(In thousands)
Tax over book depreciation . . . . . . . . . . . $ 1,426 $ 1,834
Natural gas costs recoverable through
rate adjustments . . . . . . . . . . . . . . . 1,478 (1,562)
Natural gas contract settlement and
restructuring. . . . . . . . . . . . . . . . . (2,533) (3,028)
Reserves for regulatory matters. . . . . . . . . (7,270) (2,261)
Unbilled utility revenue . . . . . . . . . . . . (1,778) 1,093
Well drilling and development costs. . . . . . . 2,343 3,797
Land reclamation and other . . . . . . . . . . . (3,214) 912
Total deferred income tax expense. . . . . . . . $(9,548) $ 785
The company's consolidated federal income tax returns were under
examination by the Internal Revenue Service (IRS) for the tax years
1983 through 1988. In September 1991, the company received a
deficiency notice 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 May 1992, a similar notice of
proposed deficiency was received for the years 1986 through 1988.
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'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. Thus, the company
intends to contest vigorously the deficiencies proposed by the IRS
and, in that regard, has timely filed protests for the 1983 through
1988 tax years contesting the treatment proposed in the notices of
proposed deficiency. If the IRS position were upheld, the resulting
deficiencies would have a material effect on results of operations.
NOTE 14
Business Segment Data
The company's operations are conducted through five business segments.
The electric, natural gas distribution, natural gas transmission,
mining and construction materials, 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 page one.
Segment operating information at December 31, 1993, 1992 and 1991,
is presented in the Consolidated Statements of Income. Other segment
information is presented below:
1993 1992 1991
(In thousands)
Depreciation, depletion and
amortization --
Electric . . . . . . . . . . . . .$ 15,307 $ 15,132 $ 15,698
Natural gas distribution . . . . . 5,114 4,809 4,673
Natural gas transmission . . . . . 7,113 6,409 6,110
Mining and construction
materials . . . . . . . . . . . . 5,594 4,527 4,035
Oil and natural gas production . . 12,034 8,817 6,061
Total depreciation, depletion
and amortization . . . . . . .$ 45,162 $ 39,694 $ 36,577
Investment information --
Identifiable assets:
Electric (a) . . . . . . . . . .$ 306,179 $ 301,959 $302,296
Natural gas distribution (a) . . 104,013 90,979 84,250
Natural gas transmission (a) . . 383,355 404,250 391,735
Mining and construction
materials. . . . . . . . . . . 120,105 105,761 102,760
Oil and natural gas
production . . . . . . . . . . 89,690 80,128 61,935
Total identifiable assets. . . 1,003,342 983,077 942,976
Corporate assets (b) . . . . . . . 37,709 41,433 21,715
Total consolidated assets. . .$1,041,051 $1,024,510 $964,691
(a) Includes, in the case of natural gas distribution and electric
property, allocations of common utility property. Natural gas
stored or available under repurchase commitment is included in
natural gas 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 7 percent of mining and construction materials
revenues in 1993 (13 percent in 1992 and 16 percent in 1991) 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 10 percent of mining and construction materials revenues
in 1993, 20 percent in 1992 and 19 percent in 1991.
In May 1992, KRC Aggregate, Inc. (KRC Aggregate), an indirect,
wholly-owned subsidiary of Knife River, entered into the sand and
gravel business in central California through the purchase of certain
properties, including mining and processing equipment. These
operations, located near Lodi, California, surface mine, process and
market aggregate products to various customers, including road and
housing contractors, tile manufacturers and ready-mix plants, with a
market area extending approximately 60 miles from the mine.
On April 2, 1993, the assets of Alaska Basic Industries, Inc. (ABI)
and its subsidiaries were purchased by KRC Aggregate. ABI is a
vertically integrated construction materials business headquartered in
Anchorage, Alaska. ABI's nine divisions handle the sale of its sand
and gravel aggregates and related products such as ready-mixed
concrete, asphalt and finished aggregate products.
Effective September 1, 1993, KRC Aggregate, purchased the stock of
LTM, Incorporated (LTM), Rogue Aggregates, Inc. (Rogue) and Concrete,
Inc., construction materials subsidiaries of Terra Industries.
Headquartered in Medford, Oregon, LTM and Rogue are vertically
integrated construction materials businesses serving southern Oregon
markets. Their products include sand and gravel aggregates, ready-
mixed concrete, asphalt and finished aggregate products. Concrete,
Inc., headquartered in Stockton, California, operates four ready-mix
plants in San Joaquin County. These ready-mix plants became part of
KRC Aggregate's Lodi, California operations.
Pro forma amounts reflecting the effects of the above acquisitions
are not disclosed 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:
1993 1992 1991
(In thousands)
Service cost/benefits earned during
the year . . . . . . . . . . . . . .$ 3,277 $ 2,957 $ 2,803
Interest cost on projected benefit
obligation . . . . . . . . . . . . . 9,488 8,464 8,008
Loss (return) on plan assets . . . . . (14,540) (11,384) (25,822)
Net amortization and deferral. . . . . 2,916 491 15,637
Total pension costs. . . . . . . . . . 1,141 528 626
Less amounts capitalized . . . . . . . 133 75 58
Total pension expense. . . . . . . . .$ 1,008 $ 453 $ 568
The funded status of the company's plans is summarized as follows:
1993 1992 1991
(In thousands)
Projected benefit obligation:
Vested . . . . . . . . . . . . . . $108,718 $ 92,623 $ 81,766
Nonvested. . . . . . . . . . . . . 4,696 3,251 2,820
Accumulated benefit obligation . . . 113,414 95,874 84,586
Provision for future pay increases . 26,379 22,614 20,794
Projected benefit obligation . . . . . 139,793 118,488 105,380
Plan assets at market value. . . . . . 149,184 140,623 135,172
(9,391) (22,135) (29,792)
Plus:
Unrecognized transition asset. . . . 10,305 11,295 12,284
Unrecognized net gains and prior
service costs. . . . . . . . . . . 4,953 16,018 22,157
Accrued pension costs. . . . . . . . . $ 5,867 $ 5,178 $ 4,649
The projected benefit obligation was determined using an assumed
discount rate of 7 percent (8 percent in 1992 and 1991) and assumed
long-term rates for estimated compensation increases of 4 1/2 percent
(5 percent in 1992 and 5 1/2 percent in 1991). The change in these
assumptions had the effect of increasing the projected benefit
obligation at December 31, 1993, by $15 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. 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:
1993
(In thousands)
Service cost/benefits earned during the year . . . . . . . . $1,098
Interest cost on accumulated postretirement
benefit obligation . . . . . . . . . . . . . . . . . . . . 3,932
Amortization of transition obligation. . . . . . . . . . . . 2,458
Total postretirement benefits expense. . . . . . . . . . . . $7,488
The funded status of the company's plans is summarized as follows:
1993
(In thousands)
Accumulated postretirement benefit obligation:
Retirees eligible for benefits . . . . . . . . . . . . . . $31,029
Active employees not fully eligible. . . . . . . . . . . . 28,592
Total. . . . . . . . . . . . . . . . . . . . . . . . . . 59,621
Plan assets at market value. . . . . . . . . . . . . . . . . 4,450
55,171
Less:
Unrecognized transition obligation . . . . . . . . . . . . 46,694
Unrecognized net losses. . . . . . . . . . . . . . . . . . 7,992
Accrued postretirement benefits cost . . . . . . . . . . . . $ 485
The health care 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 care
cost trend rate assumption has a significant effect on the amounts
reported. To illustrate, increasing the assumed health care cost
trend rates by 1 percent each year would increase the accumulated
postretirement benefit obligation as of December 31, 1993, by $3.6
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $288,000.
The accumulated postretirement benefit obligation was determined
using an assumed discount rate of 7 percent (8 percent at January 1,
1993, the date of adoption) and assumed long-term rates for estimated
compensation increases, as they apply to life insurance benefits, of
4 1/2 percent (5 1/2 percent at January 1, 1993). The change in these
assumptions had the effect of increasing the accumulated
postretirement benefit obligation at December 31, 1993, by $8 million.
The assumed long-term rate of return on assets is 7 1/2 percent. Plan
assets at December 31, 1993,consist primarily of short-term
investments.
The company's accounting recognition and funding policy as it
applies to postretirement benefits, will depend, in part, on the
position of applicable regulatory bodies with respect to recovery of
such costs for its regulated businesses. Montana-Dakota filed
applications with the public service commissions of Montana, North
Dakota, South Dakota and Wyoming requesting that the commissions adopt
the principles of accrual accounting for these costs and that the
company be permitted to defer, on a limited basis, the difference
between the SFAS No. 106 required accruals and the costs associated
with the presently used pay-as-you-go method until such time that the
full SFAS No. 106 expense is allowed in the company's rates charged to
its customers. The company has received an order from the Montana
Public Service Commission authorizing such deferrals. The public
service commissions of North Dakota and Wyoming, as a part of orders
issued in 1993 related to general rate applications filed by Montana-
Dakota, adopted accrual accounting for ratemaking purposes and
generally require that these benefits be funded through an external
trust using the most tax-effective funding options available.
However, as a part of a 1993 general rate proceeding, the South Dakota
commission deferred this issue until commission hearings are held in
March 1994, and has continued the use of pay-as-you-go accounting for
ratemaking purposes until that date. The FERC, in a policy statement
issued in December 1992, has adopted accrual accounting for these
costs for ratemaking purposes and has authorized limited deferral of
the higher accrual costs. Williston Basin expects to seek recovery of
these costs in its next general rate proceeding.
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 in 1993
was $1.4 million.
The company has a Key Employee Stock Option Plan under which the
company is authorized to grant options for up to 800,000 shares of
common stock with an option price equal to market value on the date of
grant. At December 31, 1993, 183,040 options, with an average option
price of $23.72 per share, were outstanding, none of which were
exercisable. The company has contributed $3.2 million to a trust
established to fund its commitment under the Plan.
The company has Tax Deferred Compensation Savings Plans for eligible
employees. Each participant may contribute amounts up to 10 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 $1.7 million in 1993, $1.5
million in 1992 and $1.3 million in 1991.
NOTE 16
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:
1993 1992 1991
(In thousands)
Big Stone Station --
Utility plant in service . . . . . $ 47,349 $ 46,398 $ 46,783
Accumulated depreciation . . . . . 24,663 23,326 22,105
$ 22,686 $ 23,072 $ 24,678
Coyote Station --
Utility plant in service . . . . . $121,380 $121,294 $120,085
Accumulated depreciation . . . . . 42,482 39,129 35,474
$ 78,898 $ 82,165 $ 84,611
NOTE 17
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1993 and 1992:
First Second Third Fourth
Quarter Quarter Quarter Quarter
1993 (In thousands, except per share
amounts)
Operating revenues . . . . . $124,169 $88,995 $98,832 $127,616
Operating expenses . . . . . 92,631 76,378 84,266 102,245
Operating income . . . . . . 31,538 12,617 14,566 25,371
Income before cumulative
effect of accounting change 15,761 3,797 6,309 12,950
Cumulative effect of
accounting change. . . . . 5,521 --- --- ---
Net income . . . . . . . . . 21,282 3,797 6,309 12,950
Earnings per common share
before cumulative effect
of accounting change . . . .82 .19 .32 .67
Cumulative effect of
accounting change per
common share . . . . . . . .29 --- --- ---
Earnings per common share. . 1.11 .19 .32 .67
Average common shares
outstanding. . . . . . . . 18,985 18,985 18,985 18,985
1992
Operating revenues . . . . . $105,576 $78,839 $70,963 $106,797
Operating expenses . . . . . 81,793 66,181 57,756 79,386
Operating income . . . . . . 23,783 12,658 13,207 27,411
Net income . . . . . . . . . 11,440 4,018 5,174 14,739
Earnings per common share. . .59 .20 .26 .77
Average common shares
outstanding. . . . . . . . 18,985 18,985 18,985 18,985
Pro forma amounts assuming
retroactive application
of accounting change:
Net income . . . . . . . . $ 10,332 $ 3,507 $ 5,098 $ 16,915
Earnings per common share. .53 .17 .26 .88
Most of the company's operations are highly seasonal and revenues
from, and certain expenses for, such operations may fluctuate between
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 18
Oil and Natural Gas Activities (Unaudited)
Fidelity Oil holds various 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).
Since 1986, Fidelity Oil has undertaken ventures, through a series
of working-interest agreements with several different partners, that
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.
The following information includes Fidelity Oil's proportionate
share of all its oil and natural gas net proceeds and working
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:
1993 1992 1991
(In thousands)
Subject to amortization. . . . . . . . $114,572 $91,058 $66,501
Not subject to amortization. . . . . . 2,022 2,383 1,533
Total capitalized costs. . . . . . . . 116,594 93,441 68,034
Accumulated depreciation, depletion
and amortization . . . . . . . . . . 36,084 24,083 15,374
Net capitalized costs. . . . . . . . . $ 80,510 $69,358 $52,660
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:
1993 1992 1991
(In thousands)
Acquisitions . . . . . . . . . . . . . $ 9,296 $ 9,976 $ 4,667
Exploration. . . . . . . . . . . . . . 7,787 11,074 7,781
Development . . . . . . . . . . . . . 7,836 4,715 9,824
Total capital expenditures . . . . . . $24,919 $25,765 $22,272
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:
1993 1992 1991
(In thousands)
Revenues . . . . . . . . . . . . . . . $39,125 $33,797 $33,939
Production costs . . . . . . . . . . . 13,700 13,965 14,040
Depreciation, depletion and
amortization . . . . . . . . . . . . 11,998 8,782 6,027
Pretax income. . . . . . . . . . . . . 13,427 11,050 13,872
Income tax expense . . . . . . . . . . 4,606 3,658 4,745
Results of operations for
producing activities . . . . . . . . $ 8,821 $ 7,392 $ 9,127
The following table summarizes the company's estimated quantities of
proved developed oil and natural gas reserves at December 31, 1993,
1992 and 1991 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.
1993 1992 1991
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year. . . . . . . 12,200 37,200 11,600 27,500 12,400 16,100
Production . . . . . . (1,500)(8,800)(1,500)(5,000) (1,500)(2,600)
Extensions and
discoveries. . . . . 600 10,600 100 5,300 400 8,900
Purchases of proved
reserves . . . . . . 500 9,200 900 8,200 200 5,700
Sales of reserves
in place . . . . . . (300) (100) --- (100) --- (100)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions. (300) 2,200 1,100 1,300 100 (500)
Balance at end of year 11,200 50,300 12,200 37,200 11,600 27,500
Proved developed reserves:
January 1, 1991. . . . 12,300 13,900
December 31, 1991. . . 11,200 22,600
December 31, 1992. . . 11,800 36,500
December 31, 1993. . . 11,100 43,100
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, 1993, applicable to the company's $7.1
million gross investment in oil and natural gas properties located in
Canada comprise approximately 7 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:
1993 1992 1991
(In thousands)
Future net cash flows before
income taxes . . . . . . . . . . . . $119,800 $138,500 $94,300
Future income tax expenses . . . . . . 15,600 26,600 15,300
Future net cash flows. . . . . . . . . 104,200 111,900 79,000
10% annual discount for estimated
timing of cash flows . . . . . . . . 32,600 35,200 24,900
Discounted future net cash flows
relating to proved oil and natural
gas reserves . . . . . . . . . . . . $ 71,600 $ 76,700 $54,100
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1993 1992 1991
(In thousands)
Beginning of year. . . . . . . . . . . $ 76,700 $ 54,100 $ 68,000
Net revenues from production . . . . . (26,000) (19,700) (16,900)
Change in net realization. . . . . . . (24,000) 13,100 (53,100)
Extensions, discoveries and improved
recovery, net of future production
and development costs. . . . . . . . 16,800 8,200 12,900
Purchases of proved reserves . . . . . 14,100 16,000 7,100
Sales of reserves in place . . . . . . (1,600) (200) (300)
Changes in estimated future
development costs. . . . . . . . . . (11,600) (3,000) (5,000)
Development costs incurred
during the year. . . . . . . . . . . 7,800 4,700 9,800
Accretion of discount. . . . . . . . . 8,900 6,400 9,600
Net change in income taxes . . . . . . 6,000 (8,000) 18,200
Revisions of previous quantity
estimates. . . . . . . . . . . . . . 4,400 5,000 3,600
Other. . . . . . . . . . . . . . . . . 100 100 200
Net change . . . . . . . . . . . . . . (5,100) 22,600 (13,900)
End of year. . . . . . . . . . . . . . $ 71,600 $ 76,700 $ 54,100
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.
Supplementary information with respect to the company's natural gas
producing activities through Williston Basin is not included herein
since the related production is anticipated to recover its equivalent
cost of service. However, as a part of the settlement applicable to
the corporate realignment in January 1985, the company agreed to
adjust retail rates so as to limit flow-through of prices higher than
cost of service to 50 percent of the excess. Based on the terms of
the settlement, refunds for the 1991 and 1992 production years
aggregating $1.0 million and $176,000, respectively, were made in the
ensuing year. Estimated reserves associated with this gas are
approximately 116,476 MMcf. The unamortized capitalized costs related
to these reserves are approximately $7.9 million at December 31, 1993,
$7.2 million at December 31, 1992, and $7.5 million at December 31,
1991. Non-depreciable capitalized costs are amortized on a composite
unit-of-production method based on total estimated recoverable
reserves and depreciable capitalized costs are amortized on a
straight-line basis over the average useful life of the asset.
In March and May 1993, Williston Basin was directed by the United
States Minerals Management Service (MMS) to pay approximately $3.5
million, plus interest, in claimed royalty underpayments. These
royalties are attributable to natural gas production by Williston
Basin from federal leases in Montana and North Dakota for the period
December 1, 1978, through February 29, 1988. Williston Basin has
filed an administrative appeal with the MMS on this issue stating the
gas was properly valued for royalty purposes. Williston Basin also
believes that the statute of limitations limits this claim. Williston
Basin is pursuing these issues before both the MMS and the courts.
On December 21, 1993, Williston Basin received from the Montana
Department of Revenue (MDR) an assessment claiming additional
production taxes due of $3.7 million, plus interest, for 1988 through
1991 production. These claimed taxes result from the MDR's belief
that certain natural gas production during the period at issue was not
properly valued. Williston Basin does not agree with the MDR and has
reached an agreement with the MDR that the appeal process be held in
abeyance pending further review.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of 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, 1993, 1992 and 1991,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1993. 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, 1993, 1992
and 1991, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993 in
conformity with generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements,
effective January 1, 1993, the company changed its methods of
accounting for recording electric and natural gas distribution
revenues, postretirement benefits other than pensions, and income
taxes.
/s/ Arthur Andersen & Co.
Arthur Andersen & Co.
Minneapolis, Minnesota,
January 25, 1994
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
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
Mining and construction
materials. . . . . . . . . . . 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
Mining and construction
materials. . . . . . . . . . . 16,984 11,532 9,682
Oil and natural gas production . 11,750 9,499 12,552
$ 84,092 $ 77,059 $ 85,303
Earnings (loss) 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
Mining and construction
materials. . . . . . . . . . . 12,359 10,662 9,809
Oil and natural gas production . 7,109 5,751 8,010
Earnings on common stock
before cummulative 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. . . . . . . . $ 2.00* $ 1.82 $ 1.96
Cumulative effect of accounting
change . . . . . . . . . . . . . .29 --- ---
$ 2.29 $ 1.82 $ 1.96
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) . . . . . . . $ 38,817 $ 35,852 $ 37,619
Earnings per common share. . . . $ 2.00 $ 1.85 $ 1.94
Common Stock Statistics
Weighted average common shares
outstanding (000's). . . . . . . 18,985 18,985 18,985
Dividends per common share . . . . $ 1.52 $ 1.46 $ 1.435
Book value per common share. . . . $ 16.76 $ 15.98 $ 15.62
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.
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1990 1989 1988
Selected Financial Data
Operating revenues: (000's)
Electric . . . . . . . . . . . . $124,156 $126,228 $126,128
Natural gas. . . . . . . . . . . 151,599 159,703 168,125
Mining and construction
materials. . . . . . . . . . . 38,276 41,643 42,388
Oil and natural gas production . 31,213 25,199 20,918
$345,244 $352,773 $357,559
Operating income: (000's)
Electric . . . . . . . . . . . . $ 32,221 $ 32,592 $ 33,505
Natural gas distribution . . . . 6,578 7,781 5,368
Natural gas transmission . . . . 19,362 24,835 21,189
Mining and construction
materials. . . . . . . . . . . 7,749 9,087 9,841
Oil and natural gas production . 12,523 10,420 7,352
$ 78,433 $ 84,715 $ 77,255
Earnings (loss) on common
stock: (000's)
Electric . . . . . . . . . . . . $ 14,280 $ 13,385 $ 13,444
Natural gas distribution . . . . 2,704 3,123 1,474
Natural gas transmission . . . . (7,578)* 3,722 2,320
Mining and construction
materials. . . . . . . . . . . 9,632 8,890 11,493
Oil and natural gas production . 8,071 6,765 5,115
Earnings on common stock
before cummulative effect
of accounting change . . . . . 27,109* 35,885 33,846
Cumulative effect of
accounting change. . . . . . . --- --- ---
$ 27,109* $ 35,885 $ 33,846
Earnings per common share before
cumulative effect of
accounting change. . . . . . . . $ 1.43* $ 1.89 $ 1.81
Cumulative effect of accounting
change . . . . . . . . . . . . . --- --- ---
$ 1.43* $ 1.89 $ 1.81
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) . . . . . . . $ 28,395* $ 36,861 $ 34,957
Earnings per common share. . . . $ 1.45 $ 1.90 $ 1.81
Common Stock Statistics
Weighted average common shares
outstanding (000's). . . . . . . 18,985 18,985 18,718
Dividends per common share . . . . $ 1.42 $ 1.47 $ 1.42
Book value per common share. . . . $ 15.12 $ 15.11 $ 14.75
Market price ratios:
Dividend payout. . . . . . . . . 99%* 78% 78%
Yield. . . . . . . . . . . . . . 6.9% 6.5% 7.5%
Price/earnings ratio . . . . . . 14.3x* 12.0x 10.5x
Market value as a percent of
book value . . . . . . . . . . 135.6% 149.7% 128.8%
Profitability Indicators
Return on average common equity. . 9.4%* 12.5% 12.4%
Return on average invested capital 7.8%* 9.2% 9.0%
Interest coverage. . . . . . . . . 2.7x* 2.8x 2.7x
Fixed charges coverage, including
preferred dividends. . . . . . . 1.9x* 2.3x 2.2x
General
Total assets (000's) . . . . . . . $959,946 $971,401 $949,509
Net long-term debt (000's) . . . . $229,786 $234,333 $242,593
Redeemable preferred stock (000's) $ 2,500 $ 2,600 $ 3,100
Capitalization ratios:
Common stockholders' investment. 54% 53% 52%
Preferred stocks . . . . . . . . 3 3 3
Long-term debt . . . . . . . . . 43 44 45
100% 100% 100%
* Reflects a $6.8 million or 36 cent per share after-tax effect of an
absorption of certain natural gas contract litigation settlement
costs.
/TABLE
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
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
Natural gas:
Produced (Mdk) . . . . . . . . . . . . 3,876 3,551 3,742
Purchased from others -- gross (Mdk) . 5,562 14,132 16,366
Stored (owned or controlled)
Net injection (withdrawal)--MMcf . . (10,786) (2,931) (2,834)
Cost of natural gas purchased
per dk . . . . . . . . . . . . . . . . 1.78 $1.91 $2.07
Energy Marketing Operations
Natural gas volumes (Mdk). . . . . . . . 6,827 3,292 991
Mining and Construction Materials Operations
Coal: (000's)
Tonnage sales. . . . . . . . . . . . . 5,066 4,913 4,731
Recoverable reserves in tons . . . . . 230,600 235,700 256,700
Construction materials: (000's)
Aggregates (tons sold) . . . . . . . . 2,391 263 ---
Ready-mixed concrete (cubic
yards sold). . . . . . . . . . . . . 157 --- ---
Asphalt (tons sold). . . . . . . . . . 141 --- ---
Recoverable aggregate reserves
in tons. . . . . . . . . . . . . . . 74,200 20,600 ---
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
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
1990 1989 1988
Electric Operations
Sales to ultimate consumers
(thousand kWh). . . . . . . . . . . . 1,820,150 1,836,099 1,843,982
Sales for resale (thousand kWh). . . . 285,564 311,327 246,425
Electric system generating and
firm purchase capability -- kW
(Interconnected system). . . . . . . . 451,600 451,600 451,600
Demand peak -- kW
(Interconnected system). . . . . . . . 381,600 383,600 386,700
Electricity produced
(thousand kWh) . . . . . . . . . . . .1,674,648 1,773,849 1,691,778
Electricity purchased
(thousand kWh) . . . . . . . . . . . . 573,099 557,650 598,443
Cost of fuel and purchased
power per kWh. . . . . . . . . . . . . $.016 $.017 $.017
Natural Gas Distribution Operations
Sales (Mdk). . . . . . . . . . . . . . . 28,278 31,643 32,557
Transportation (Mdk) . . . . . . . . . . 11,806 9,321 3,314
Weighted average degree days - % of
previous year's actual . . . . . . . . 88% 112% 113%
Natural Gas Transmission Operations
Sales for resale (Mdk) . . . . . . . . . 19,658 27,274 33,515
Transportation (Mdk) . . . . . . . . . . 50,809 51,159 33,892
Natural gas:
Produced (Mdk) . . . . . . . . . . . . 1,881 1,907 1,744
Purchased from others -- gross (Mdk) . 23,158 28,869 33,841
Stored (owned or controlled)
Net injection (withdrawal)-- MMcf. . 2,782 (24) (41)
Cost of natural gas purchased
per dk . . . . . . . . . . . . . . . . $2.01 $1.68 $1.78
Energy Marketing Operations
Natural gas volumes (Mdk). . . . . . . . 1,853 843 ---
Mining and Construction Materials Operations
Coal: (000's)
Tonnage sales. . . . . . . . . . . . . 4,439 4,747 4,759
Recoverable reserves in tons . . . . . 261,500 266,000 270,800
Construction materials: (000's)
Aggregates (tons sold) . . . . . . . . --- --- ---
Ready-mixed concrete (cubic
yards sold). . . . . . . . . . . . . --- --- ---
Asphalt (tons sold). . . . . . . . . . --- --- ---
Recoverable aggregate reserves
in tons. . . . . . . . . . . . . . . --- --- ---
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) . . . . . . . . 1,374 1,348 1,358
Natural gas (MMcf) . . . . . . . . . . 1,846 1,605 1,464
Average sales prices:
Oil (per barrel) . . . . . . . . . . . $20.11 $16.26 $13.43
Natural gas (per Mcf). . . . . . . . . $ 1.63 $ 1.66 $ 2.14
Net recoverable reserves:
Oil (000's of barrels) . . . . . . . . 12,400 12,000 11,500
Natural gas (MMcf) . . . . . . . . . . 16,100 10,800 9,400