MDU RESOURCES GROUP, INC.
1994 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
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, 1994 1993 1992
(In thousands, except per share amounts)
Operating Revenues
Electric $133,953 $131,109 $123,908
Natural gas 160,970 178,981 159,438
Mining and construction materials 116,646 90,397 45,032
Oil and natural gas production 37,959 39,125 33,797
449,528 439,612 362,175
Operating Expenses
Fuel and purchased power 43,203 41,298 37,892
Purchased natural gas sold 52,893 78,121 58,420
Operation and maintenance 203,269 167,374 126,311
Depreciation, depletion and
amortization 48,113 45,162 39,694
Taxes, other than income 23,875 23,565 22,799
371,353 355,520 285,116
Operating Income
Electric 27,596 30,520 30,188
Natural gas distribution 3,948 4,730 4,509
Natural gas transmission 21,281 20,108 21,331
Mining and construction materials 16,593 16,984 11,532
Oil and natural gas production 8,757 11,750 9,499
78,175 84,092 77,059
Other income--net 10,480 3,877 273
Interest expense--net 25,350 25,273 25,227
Carrying costs on natural gas
repurchase commitment (Note 4) 4,627 3,897 5,834
Income before taxes 58,678 58,799 46,271
Income taxes 18,833 19,982 10,900
Income before cumulative effect
of accounting change 39,845 38,817 35,371
Cumulative effect of accounting
change (Note 1) --- 5,521 ---
Net income 39,845 44,338 35,371
Dividends on preferred stocks 797 802 807
Earnings on common stock $ 39,048 $ 43,536 $ 34,564
Earnings per common share:
Earnings before cumulative effect
of accounting change $ 2.06 $ 2.00 $ 1.82
Cumulative effect of accounting
change --- .29 ---
Earnings $ 2.06 $ 2.29 $ 1.82
Dividends per common share $ 1.58 $ 1.52 $ 1.46
Average common shares outstanding 18,985 18,985 18,985
Pro forma amounts assuming
retroactive application of
accounting change:
Net income $ 39,845 $ 38,817 $ 35,852
Earnings per common share $ 2.06 $ 2.00 $ 1.85
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
December 31, 1994 1993 1992
(In thousands)
ASSETS
Property, Plant and Equipment
Electric $ 514,152 $ 503,690 $ 491,943
Natural gas distribution 157,174 141,100 125,314
Natural gas transmission 263,971 258,766 278,978
Mining and construction materials 147,284 145,014 104,370
Oil and natural gas production 151,532 116,833 93,667
1,234,113 1,165,403 1,094,272
Less accumulated depreciation,
depletion and amortization 541,842 501,451 469,232
692,271 663,952 625,040
Current Assets
Cash and cash equivalents 37,190 71,699 66,838
Receivables--net 55,409 67,553 57,902
Inventories 27,090 19,415 18,214
Deferred income taxes 26,694 32,243 18,962
Other prepayments and
current assets 12,287 14,262 40,497
158,670 205,172 202,413
Natural gas available under
repurchase commitment (Note 4) 70,913 79,031 92,038
Investments 16,914 16,858 61,934
Deferred charges and other assets 65,950 76,038 43,085
$1,004,718 $1,041,051 $1,024,510
CAPITALIZATION AND LIABILITIES
Capitalization (See Separate
Statements)
Common stockholders' investment $ 327,183 $ 318,131 $ 303,452
Preferred stocks 17,000 17,100 17,200
Long-term debt 217,693 231,770 249,845
561,876 567,001 570,497
Commitments and contingencies
(Notes 2, 3, 4, 5, 13 and 15) --- --- ---
Current Liabilities
Short-term borrowings 680 9,540 7,775
Accounts payable 20,222 24,967 25,397
Taxes payable 8,817 9,204 8,958
Other accrued liabilities,
including reserved revenues 88,516 107,566 112,996
Dividends payable 7,793 7,605 7,226
Long-term debt and preferred
stock due within one year 20,450 15,300 300
146,478 174,182 162,652
Natural gas repurchase commitment
(Note 4) 88,404 98,525 114,937
Deferred credits:
Deferred income taxes and
unamortized investment tax
credit 124,706 124,978 135,571
Other 83,254 76,365 40,853
207,960 201,343 176,424
$1,004,718 $1,041,051 $1,024,510
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
December 31, 1994 1993 1992
(In thousands)
Common Stockholders' Investment
Common stock (Note 9):
Authorized-- 75,000,000 shares,
$3.33 par value in 1994,
50,000,000 shares,
$5 par value in 1993
and 1992
Outstanding--18,984,654 shares $ 63,219 $ 94,923 $ 94,923
Other paid in capital 95,914 64,210 64,210
Retained earnings (Note 10) 168,050 158,998 144,319
Total common stockholders'
investment 327,183 318,131 303,452
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--21,000 shares
in 1994 (22,000 in 1993 and
23,000 in 1992) 2,100 2,200 2,300
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 17,100 17,200 17,300
Less current maturities and
sinking fund requirements 100 100 100
Net preferred stocks 17,000 17,100 17,200
Long-term Debt (Note 12)
First mortgage bonds and notes 180,850 195,850 195,850
Pollution control lease and note
obligation, 6.2%, due in
annual installments to 2004 4,600 4,800 5,000
Senior secured note, 8.43%,
due December 31, 2000 15,000 15,000 ---
interest rates, terminating
October 6, 2002 3,000 1,500 19,400
Term loans at rates ranging from
5.95% to 8.50%, terminating
July 1, 1999 34,750 30,000 30,000
Other (157) (180) (205)
Total long-term debt 238,043 246,970 250,045
Less current maturities and sinking
fund requirements 20,350 15,200 200
Net long-term debt 217,693 231,770 249,845
Total capitalization $561,876 $567,001 $570,497
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
Years ended December 31, 1994 1993 1992
(In thousands)
Operating Activities
Net income $ 39,845 $ 44,338 $ 35,371
Cumulative effect of accounting
change --- (5,521) ---
Adjustments to reconcile net income
to net cash provided by operations:
Depreciation, depletion and
amortization 48,113 45,162 39,694
Deferred income taxes and
investment tax credit--net 1,689 16,040 (789)
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes 5,148 8,467 3,996
Changes in current assets and
liabilities:
Receivables 12,144 (775) (14,568)
Inventories (6,799) (1,201) (1,834)
Other current assets 7,524 12,954 (11,219)
Accounts payable (4,745) (430) 6,902
Other current liabilities (19,249) (8,160) 16,042
Other noncurrent changes 14,143 (13,687) 190
Net cash provided by operating
activities 97,813 97,187 73,785
Financing Activities
Net change in short-term borrowings (8,860) 1,765 7,775
Issuance of long-term debt 26,750 --- 158,350
Repayment of long-term debt (35,700) (3,100) (131,450)
Retirement of preferred stocks (100) (100) (100)
Retirement of natural gas
repurchase commitment (10,121) (16,412) (9,044)
Dividends paid (30,793) (29,659) (28,524)
Net cash used in financing
activities (58,824) (47,506) (2,993)
Investing Activities
Additions to property, plant and
equipment and acquisitions of
businesses:
Electric (14,188) (16,156) (13,226)
Natural gas distribution (19,033) (15,012) (6,461)
Natural gas transmission (6,147) (3,669) (9,452)
Mining and construction materials (3,597) (43,123) (16,295)
Oil and natural gas production (38,595) (24,943) (25,778)
(81,560) (102,903) (71,212)
Sale of natural gas available
under repurchase commitment 8,118 13,007 7,411
Investments (56) 45,076 5,254
Net cash used in investing
activities (73,498) (44,820) (58,547)
Increase (decrease) in cash
and cash equivalents (34,509) 4,861 12,245
Cash and cash equivalents--
beginning of year 71,699 66,838 54,593
Cash and cash equivalents--
end of year $ 37,190 $ 71,699 $ 66,838
The accompanying notes are an integral part of these consolidated statements.
NOTE 1
Statement of Principal Accounting Policies
Basis of Presentation
The consolidated financial statements of MDU Resources Group, Inc.
(the "company") include the accounts of two regulated businesses--
retail and wholesale sales of electricity and retail sales and/or
transportation of natural gas and propane, and natural gas
transmission and storage and, in 1992 and 1993, 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.
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 consistent with
the regulatory treatment established by the FERC and the public
service commissions of Montana, North Dakota, South Dakota and
Wyoming.
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 1994, 1993 and 1992. 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 market which
approximates cost.
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. 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. Unbilled
utility revenues at December 31, 1994 and 1993, aggregated $15.6
million and $18.3 million, respectively, and are included in
"Receivables" in the company's Consolidated Balance Sheets. 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 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 SFAS No. 109, "Accounting for Income
Taxes" (SFAS No. 109) on January 1, 1993, as further described below,
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.
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, 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.
Cash Flow Information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 1994 1993 1992
(In thousands)
Interest, net of amount capitalized $22,775 $22,717 $25,578
Income taxes $13,539 $24,545 $21,577
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 1993 and 1992 to conform to the 1994 presentation. Such
reclassifications had no effect on net income or common stockholders'
investment as previously reported.
NOTE 2
Pending Litigation
W.A. Moncrief
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 against Williston Basin and the company disputing certain
price and volume issues under the contract. In its complaint,
Moncrief alleged that, for the period January 1, 1985, through
December 31, 1992, it had suffered damages ranging from $1.2 million
to $5.0 million, without interest, on the price paid by Williston
Basin for natural gas purchased. Moncrief requested that the Court
award it such amount and further requested that Williston Basin be
obligated for damages for additional volumes not purchased for the
period November 1, 1993, (the date when Williston Basin implemented
FERC Order 636 and abandoned its natural gas sales merchant function,
see "Order 636" contained in Note 3 for a further discussion of
Williston Basin's implementation of Order 636) to mid-1996, the
remaining period of the contract.
On June 9, 1994, Moncrief filed a motion to amend its complaint
whereby it alleged a new pricing theory under Section 105 of the
Natural Gas Policy Act for natural gas purchased in the past and for
future volumes which Williston Basin refused to purchase effective
November 1, 1993. On July 13, 1994, the Court denied Moncrief's
motion to amend its complaint.
However, on July 15, 1994, the Court, as part of addressing the
proper litigants in this matter, allowed Moncrief to amend its
complaint to assert its new pricing theory under the contract.
Through the course of this action Moncrief has submitted its damage
calculations which total approximately $18 million or, under its
alternative pricing theory, $38 million. Trial is scheduled for
June 12, 1995.
Moncrief's damage claims, in Williston Basin's opinion, are
grossly overstated. Williston Basin further believes it has
meritorious defenses and intends to vigorously defend such suit.
Williston Basin plans to file for recovery from ratepayers of amounts
which may be ultimately due to Moncrief, if any.
NOTE 3
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. On May 3, 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 on July 20,
1994, Williston Basin refunded $47.8 million to its customers,
including $33.4 million to Montana-Dakota, all of which had been
reserved. Williston Basin's requested rehearing is currently pending
as is the issuance of an initial order by the FERC with respect to the
1992 rate change application.
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, 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 August 1993, Williston Basin filed to recover 75 percent of $28.7
million ($21.5 million) in buy-out/buy-down costs paid to Koch
Hydrocarbon Company (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, in October 1993, pending
final approval by the FERC. On August 17, 1994, the FERC issued an
order approving Williston Basin's request to collect such costs.
Order 636
In 1992, the FERC issued Order 636, which required fundamental changes
in the way natural gas pipelines operate. Under Order 636, pipelines
are required to offer unbundled sales, transportation, storage and
other services. Customers now have the option of purchasing gas from
other suppliers and pipelines are required to provide "equivalent"
services for all customers regardless from whom they are purchasing
gas. This order provides for the use of the straight fixed variable
rate design, under which all fixed storage and transmission costs,
including return on equity and associated taxes, are included in a
demand charge and all variable costs are recovered through a commodity
charge based on volumes. Order 636 allows pipelines to recover 100
percent of prudently incurred costs (transition costs) resulting from
implementation of the order.
Williston Basin had previously filed a tariff with the FERC
designed to comply with Order 636. In September 1993, the FERC issued
its order authorizing Williston Basin's implementation of Order 636
tariffs effective November 1, 1993. Also included in the order was
the requirement that Williston Basin's excess storage gas inventories
must be offered for sale at Williston Basin's cost, as opposed to fair
market value. Williston Basin requested rehearing of this issue on
the grounds that the FERC's order constitutes a confiscation of its
assets. This matter is currently on appeal.
Williston Basin has also filed tariff sheets with the FERC
requesting recovery of certain gas supply realignment (GSR) costs. On
January 9, 1995, the FERC issued an order approving Williston Basin's
request to collect $13.4 million of GSR costs related to payments made
to Koch as part of a lawsuit settlement effective December 1, 1993.
In addition, Williston Basin has filed tariff sheets with the FERC
requesting recovery of $925,000 of GSR costs (effective February 1,
1995) paid as part of a settlement agreement with a natural gas
producer which terminated all natural gas contracts effective with the
implementation of Order 636.
Montana-Dakota has also received approval for revised gas cost
tariffs from each of its four state regulatory commissions reflecting
the effects of Williston Basin's November 1, 1993 implementation of
Order 636.
The financial effect of implementing Order 636 was not material
to the company's financial position or results of operations.
NOTE 4
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, 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 under a term loan agreement with several banks. At
December 31, 1994, borrowings totalled $89.5 million at a weighted
average interest rate of 6.2 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, 1994, 17.4 MMdk of this natural gas had been sold and
transported by Williston Basin to both on- and off-system markets.
Williston Basin will continue to aggressively market the remaining
43.3 MMdk of this natural gas whenever market conditions are
favorable. In addition, it will continue to seek long-term sales
contracts.
NOTE 5
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. On
January 31, 1994, Montana-Dakota, Williston Basin and Rockwell
International Corporation (Rockwell), manufacturer of the valve
sealant, reached an agreement under which Rockwell will 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 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. Both
Montana-Dakota and Williston Basin consider unreimbursed environmental
remediation costs to be recoverable through rates, since they are
prudent costs incurred in the ordinary course of business.
Accordingly, Montana-Dakota and Williston Basin have sought and will
continue to seek recovery of such costs through rate filings. Based
on the estimated cost of the remediation program and the expected
recovery from third parties and 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 discussions with the Bureau regarding test results and requirements
in meeting these air emissions standards. Because the permitting
process is not complete at this time, Williston Basin is 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. 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, 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 6
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 $45 million at December 31, 1994,
$49 million at December 31, 1993, and $51 million at December 31,
1992. In addition, $6.9 million, $1.3 million and $3.7 million at
December 31, 1994, 1993 and 1992, respectively, of natural gas in
underground storage is included in inventories.
NOTE 7
Financial Instruments
Derivatives
In October 1994, the Financial Accounting Standards Board (FASB)
issued SFAS No. 119, "Disclosure about Derivative Financial
Instruments and Fair Value of Financial Instruments" (SFAS No. 119).
SFAS No. 119 establishes disclosure practices for derivative and other
financial instruments.
The company periodically enters into swap and collar agreements
to hedge its exposure to price fluctuations in connection with
marketing of its oil and natural gas production. The company believes
that there is a high degree of correlation because the timing of
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. The company's
hedging transactions did not have a material effect on its results of
operations for the years ended December 31, 1994, 1993 and 1992.
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:
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Long-term debt $238,043 $233,196 $246,970 $268,937
Preferred stocks $ 17,100 $ 6,614 $ 17,200 $ 6,110
The fair value of other financial instruments for which estimated
fair values have not been presented is not materially different than
the related book value.
NOTE 8
Short-term Borrowings
The company and its subsidiaries had unsecured lines of credit from
several banks totalling $91.4 million at December 31, 1994, $86
million at December 31, 1993, and $80 million at December 31, 1992.
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 $680,000 at December 31, 1994,
$9.5 million at December 31, 1993, and $7.8 million at December 31,
1992. The weighted average interest rate for borrowings outstanding
at December 31, 1994, 1993 and 1992, was 8.5 percent, 4.2 percent and
5.2 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 on April 26, 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. This
change had the effect of reducing the aggregate par value of common
stock outstanding by $31.7 million with a corresponding increase in
other paid in capital. There were no changes in the amounts
outstanding for common stock and other paid in capital during the
years ended December 31, 1993 and 1992.
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, 1994,
there were 1,020,229 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-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.
NOTE 10
Retained Earnings
Changes in retained earnings for the years ended December 31, 1994,
1993 and 1992 are as follows:
1994 1993 1992
(In thousands)
Balance at beginning of year $158,998 $144,319 $137,472
Net income 39,845 44,338 35,371
198,843 188,657 172,843
Deduct:
Dividends declared--
Preferred stocks at required
annual rates 797 802 807
Common stock 29,996 28,857 27,717
30,793 29,659 28,524
Balance at end of year $168,050 $158,998 $144,319
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, 1994, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
First mortgage bonds and notes outstanding at December 31 are as
follows:
1994 1993 1992
(In thousands)
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 15,000
6.30%, due April 1, 1995 10,000 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 $180,850 $195,850 $195,850
The company has a revolving credit and term loan agreement which
totalled $30 million at December 31, 1994, 1993 and 1992. Amounts
outstanding under this agreement were $17 million at December 31,
1994, and $30 million at December 31, 1993 and 1992, respectively.
On April 1, 1994, Williston Basin borrowed $25 million under a
term loan agreement, with the proceeds used solely for the purpose of
refinancing purchase money mortgages payable to the company. At
December 31, 1994, there was $17.5 million available and outstanding
under the term loan agreement.
Fidelity Oil Co. has $15 million outstanding under a senior
secured note at December 31, 1994. In addition, Fidelity Oil Co. has
available $20 million under a secured line of credit, $3 million of
which was outstanding at December 31, 1994, and $1.5 million 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, in January 1993, $15 million of the
line was converted to a senior secured note.
The amounts of long-term debt maturities and sinking fund
requirements for the five years following December 31, 1994, aggregate
$20.4 million in 1995; $34.4 million in 1996; $16.4 million in 1997;
$10.1 million in 1998 and $9.9 million in 1999. 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 $114 million of
additional first mortgage bonds at December 31, 1994.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1994 1993 1992
(In thousands)
Current:
Federal $11,995 $25,665 $ 18,272
State 2,644 3,997 3,359
Foreign 210 10 ---
14,849 29,672 21,631
Deferred:
Investment tax credit--net (1,137) (1,144) (1,183)
Income taxes--
Federal 4,589 (9,560) (8,505)
State 532 1,014 (1,043)
3,984 (9,690) (10,731)
Total income tax expense $18,833 $19,982 $ 10,900
Components of deferred tax assets and deferred tax liabilities
recognized in the company's Consolidated Balance Sheets at December 31
are as follows:
1994 1993
(In thousands)
Deferred tax assets:
Reserves for regulatory matters $ 25,212 $ 40,195
Natural gas available under
repurchase commitment 6,778 7,554
Accrued pension costs 5,646 4,955
Deferred investment tax credits 4,022 4,462
Accrued land reclamation 4,256 4,017
Natural gas costs refundable through
rate adjustments 4,034 ---
Other 10,638 5,149
Total deferred tax assets $ 60,586 $ 66,332
Deferred tax liabilities:
Depreciation and basis differences
on property, plant and equipment $109,648 $108,846
Basis differences on oil and natural gas
producing properties 21,049 15,889
Natural gas contract settlement and
restructuring costs 9,327 13,530
Long-term debt refinancing costs 4,745 5,223
Other 3,449 4,078
Total deferred tax liabilities $148,218 $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:
1994 1993 1992
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate $20,537 35.0 $20,580 35.0 $15,732 34.0
Increases (reductions)
in provision for
taxes resulting from:
Depletion allowance (1,454) (2.5) (1,424) (2.4) (1,393)(3.0)
State income
taxes--net of
federal income tax
benefit 2,337 4.0 2,171 3.7 1,664 3.6
Tax-exempt interest (514) (.9) (725) (1.2) (958)(2.1)
Investment tax credit
amortization (1,137) (1.9) (1,144) (2.0) (1,183)(2.5)
Other items (936) (1.6) 524 .9 (2,962)(6.4)
Actual taxes $18,833 32.1 $19,982 34.0 $10,900 23.6
In 1992 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 are as follows:
1992
(In thousands)
Tax over book depreciation $ 1,426
Natural gas costs recoverable through
rate adjustments 1,478
Natural gas contract settlement and
restructuring (2,533)
Reserves for regulatory matters (7,270)
Unbilled utility revenue (1,778)
Well drilling and development costs 2,343
Land reclamation and other (3,214)
Total deferred income tax expense $(9,548)
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 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 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 the inside front cover.
Segment operating information at December 31, 1994, 1993 and
1992, is presented in the Consolidated Statements of Income. Other
segment information is presented below:
1994 1993 1992
(In thousands)
Depreciation, depletion and
amortization:
Electric $ 15,513 $ 15,307 $ 15,132
Natural gas distribution 6,118 5,114 4,809
Natural gas transmission 6,590 7,113 6,409
Mining and construction
materials 6,394 5,594 4,527
Oil and natural gas production 13,498 12,034 8,817
Total depreciation, depletion
and amortization $ 48,113 $ 45,162 $ 39,694
Investment information:
Identifiable assets--
Electric (a) $ 307,861 $ 306,179 $ 301,959
Natural gas distribution (a) 124,275 104,013 90,979
Natural gas transmission (a) 311,992 383,355 404,250
Mining and construction
materials 116,347 120,105 105,761
Oil and natural gas
production 106,631 89,690 80,128
Total identifiable assets 967,106 1,003,342 983,077
Corporate assets (b) 37,612 37,709 41,433
Total consolidated assets $1,004,718 $1,041,051 $1,024,510
(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, 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 6 percent of mining and construction materials
revenues in 1994 (7 percent in 1993 and 13 percent in 1992) 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 8 percent of mining and construction materials revenues
in 1994, 10 percent in 1993 and 20 percent in 1992.
In May 1992, KRC Holdings, Inc. (KRC Holdings), a wholly-owned
subsidiary of Knife River, entered into the sand and gravel business
in north-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.
The assets of Alaska Basic Industries, Inc. (ABI) and its
subsidiaries were purchased by KRC Holdings in April 1993. 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.
In September 1993, KRC Holdings, purchased the stock of LTM,
Incorporated (LTM), Rogue Aggregates, Inc. (Rogue Aggregates) and
Concrete, Inc., then construction materials subsidiaries of Terra
Industries. Headquartered in Medford, Oregon, LTM and Rogue
Aggregates 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 Holding'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:
1994 1993 1992
(In thousands)
Service cost/benefits earned during
the year $ 4,035 $ 3,277 $ 2,957
Interest cost on projected benefit
obligation 9,912 9,488 8,464
Loss (return) on plan assets 3,154 (14,540) (11,384)
Net amortization and deferral (15,410) 2,916 491
Total pension costs 1,691 1,141 528
Less amounts capitalized 198 133 75
Total pension expense $ 1,493 $ 1,008 $ 453
The funded status of the company's plans at December 31 is
summarized as follows:
1994 1993 1992
(In thousands)
Projected benefit obligation:
Vested $105,561 $108,718 $ 92,623
Nonvested 4,124 4,696 3,251
Accumulated benefit obligation 109,685 113,414 95,874
Provision for future pay increases 25,084 26,379 22,614
Projected benefit obligation 134,769 139,793 118,488
Plan assets at market value 139,332 149,184 140,623
(4,563) (9,391) (22,135)
Plus:
Unrecognized transition asset 9,315 10,305 11,295
Unrecognized net gains and prior
service costs 2,466 4,953 16,018
Accrued pension costs $ 7,218 $ 5,867 $ 5,178
The projected benefit obligation was determined using an assumed
discount rate of 8 percent (7 percent in 1993 and 8 percent in 1992)
and assumed long-term rates for estimated compensation increases of
5 percent (4 1/2 percent in 1993 and 5 percent in 1992). The change
in these assumptions had the effect of decreasing the projected
benefit obligation at December 31, 1994, by $16 million but 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. 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:
1994 1993
(In thousands)
Service cost/benefits earned during the year $1,454 $1,098
Interest cost on accumulated postretirement
benefit obligation 4,584 3,932
Return on plan assets (176) ---
Amortization of transition obligation 2,458 2,458
Net amortization and deferral 76 ---
Total postretirement benefits cost 8,396 7,488
Less amounts capitalized 419 ---
Total postretirement benefits expense $7,977 $7,488
The funded status of the company's plans at December 31 is
summarized as follows:
1994 1993
(In thousands)
Accumulated postretirement benefit obligation:
Retirees eligible for benefits $36,985 $31,029
Active employees fully eligible for benefits 22 ---
Active employees not fully eligible 22,898 28,592
Total 59,905 59,621
Plan assets at market value 9,938 4,450
49,967 55,171
Less:
Unrecognized transition obligation 44,237 46,694
Unrecognized net losses 4,896 7,992
Accrued postretirement benefits cost $ 834 $ 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, 1994, by $3.4
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $270,000.
The accumulated postretirement benefit obligation was determined
using an assumed discount rate of 8 percent at December 31, 1994,
7 percent at December 31, 1993, and 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
5 percent (4 1/2 percent at December 31, 1993, and 5 1/2 percent at
January 1, 1993). The change in these assumptions had the effect of
decreasing the accumulated postretirement benefit obligation at
December 31, 1994, by $9 million but 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, 1994, consist primarily of short-term
investments.
The public service commissions of Montana, North Dakota, South
Dakota and Wyoming have authorized 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. The majority of these costs are being recovered through
rates currently in effect. 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 was $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 800,000 shares of
common stock with an option price equal to market value on the date of
grant. At December 31, 1994, 128,190 options, with an average option
price of $23.73 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 $1.9 million
in 1994, $1.7 million in 1993 and $1.5 million in 1992.
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:
1994 1993 1992
(In thousands)
Big Stone Station:
Utility plant in service $ 46,923 $ 47,349 $ 46,398
Accumulated depreciation 25,505 24,663 23,326
$ 21,418 $ 22,686 $ 23,072
Coyote Station:
Utility plant in service $121,784 $121,380 $121,294
Accumulated depreciation 45,546 42,482 39,129
$ 76,238 $ 78,898 $ 82,165
NOTE 17
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1994 and 1993:
First Second Third Fourth
Quarter Quarter Quarter Quarter
(In thousands, except per share amounts)
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 .61 .29 .64 .52
Average common shares
outstanding 18,985 18,985 18,985 18,985
1993
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
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 18
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 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.
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:
1994 1993 1992
(In thousands)
Subject to amortization $155,316 $114,572 $91,058
Not subject to amortization 8,517 2,022 2,383
Total capitalized costs 163,833 116,594 93,441
Accumulated depreciation, depletion
and amortization 53,387 36,084 24,083
Net capitalized costs $110,446 $ 80,510 $69,358
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:
1994 1993 1992
(In thousands)
Acquisitions $ 5,542 $ 9,296 $ 9,976
Exploration 13,241 7,787 11,074
Development 21,189 7,836 4,715
Total capital expenditures $39,972 $24,919 $25,765
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:
1994 1993 1992
(In thousands)
Revenues $45,053 $39,125 $33,797
Production costs 18,463 13,700 13,965
Depreciation, depletion and
amortization 13,753 11,998 8,782
Pretax income 12,837 13,427 11,050
Income tax expense 4,324 4,606 3,658
Results of operations for
producing activities $8,513 $ 8,821 $ 7,392
The following table summarizes the company's estimated quantities
of proved developed oil and natural gas reserves at December 31, 1994,
1993 and 1992 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.
1994 1993 1992
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year 11,200 50,300 12,200 37,200 11,600 27,500
Production (1,600) (9,200)(1,500)(8,800)(1,500) (5,000)
Extensions and
discoveries 1,300 17,800 600 10,600 100 5,300
Purchases of proved
reserves 600 2,900 500 9,200 900 8,200
Sales of reserves
in place (400) (2,700) (300) (100) --- (100)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions 1,400 95,100* (300) 2,200 1,100 1,300
Balance at end of year 12,500 154,200 11,200 50,300 12,200 37,200
*Includes 99,300 MMcf of Williston Basin's natural gas reserves.
Proved developed reserves:
January 1, 1992 11,200 22,600
December 31, 1992 11,800 36,500
December 31, 1993 11,100 43,100
December 31, 1994 12,200 147,200**
**Includes 98,700 MMcf of Williston Basin's natural gas reserves.
Virtually all of the company's interests in oil and natural gas
reserves are located in the continental United States. Reserve
interests at December 31, 1994, applicable to the company's $9 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:
1994 1993 1992
(In thousands)
Future net cash flows before
income taxes $197,900 $119,800 $138,500
Future income tax expenses 48,800 15,600 26,600
Future net cash flows 149,100 104,200 111,900
10% annual discount for estimated
timing of cash flows 54,200 32,600 35,200
Discounted future net cash flows
relating to proved oil and natural
gas reserves $ 94,900 $ 71,600 $ 76,700
The following are the sources of change in the standardized
measure of discounted future net cash flows by year:
1994 1993 1992
(In thousands)
Beginning of year $ 71,600 $ 76,700 $ 54,100
Net revenues from production (23,800) (26,000) (19,700)
Change in net realization (4,100) (24,000) 13,100
Extensions, discoveries and improved
recovery, net of future production
and development costs 31,700 16,800 8,200
Purchases of proved reserves 5,800 14,100 16,000
Sales of reserves in place (3,700) (1,600) (200)
Changes in estimated future
development costs--net of those
incurred during the year (2,900) (3,800) 1,700
Accretion of discount 8,300 8,900 6,400
Net change in income taxes (4,000) 6,000 (8,000)
Revisions of previous quantity
estimates 16,500* 4,400 5,000
Other (500) 100 100
Net change 23,300 (5,100) 22,600
End of year $ 94,900 $ 71,600 $ 76,700
*Includes $19.1 million related to Williston Basin's natural gas
reserves.
The estimated discounted future cash inflows from estimated
future production of proved reserves were computed using year-end oil
and natural gas prices. Future development and production costs
attributable to proved reserves were computed by applying year-end
costs to be incurred in producing and further developing the proved
reserves. Future income tax expenses were computed by applying
statutory tax rates (adjusted for permanent differences and tax
credits) to estimated net future pretax cash flows.
To 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, 1994, 1993 and 1992,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1994. 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, 1994,
1993 and 1992, and the results of their operations and their cash
flows for each of the three years in the period ended December 31,
1994, 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, 1995
1994 1993 1992
Selected Financial Data
Operating revenues: (000's)
Electric $133,953 $131,109 $123,908
Natural gas 160,970 178,981 159,438
Mining and construction
materials 116,646 90,397 45,032
Oil and natural gas production 37,959 39,125 33,797
$449,528 $439,612 $362,175
Operating income: (000's)
Electric $ 27,596 $ 30,520 $ 30,188
Natural gas distribution 3,948 4,730 4,509
Natural gas transmission 21,281 20,108 21,331
Mining and construction
materials 16,593 16,984 11,532
Oil and natural gas production 8,757 11,750 9,499
$ 78,175 $ 84,092 $ 77,059
Earnings (loss) on common
stock: (000's)
Electric $ 11,719 $ 12,652* $ 13,302
Natural gas distribution 285 1,182* 1,370
Natural gas transmission 6,155 4,713 3,479
Mining and construction
materials 11,622 12,359 10,662
Oil and natural gas production 9,267 7,109 5,751
Earnings on common stock
before cumulative effect
of accounting change 39,048 38,015* 34,564
Cumulative effect of
accounting change --- 5,521 ---
$ 39,048 $ 43,536 $ 34,564
Earnings per common share before
cumulative effect of
accounting change $ 2.06 $ 2.00* $ 1.82
Cumulative effect of accounting
change --- .29 ---
$ 2.06 $ 2.29 $ 1.82
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 39,845 $ 38,817 $ 35,852
Earnings per common share $ 2.06 $ 2.00 $ 1.85
Common Stock Statistics
Weighted average common shares
outstanding (000's) 18,985 18,985 18,985
Dividends per common share $ 1.58 $ 1.52 $ 1.46
Book value per common share $ 17.23 $ 16.76 $ 15.98
Market price ratios:
Dividend payout 77% 76%* 80%
Yield 5.9% 5.0% 5.6%
Price/earnings ratio 13.2x 15.8x* 14.5x
Market value as a percent of
book value 157.4% 188.0% 165.0%
Profitability Indicators
Return on average common equity 12.1% 12.3%* 11.6%
Return on average invested
capital 9.1% 9.4%* 8.7%
Interest coverage 3.3x 3.4x* 3.3x
Fixed charges coverage, including
preferred dividends 2.9x 3.0x* 2.4x
General
Total assets (000's) $1,004,718 $1,041,051 $1,024,510
Net long-term debt (000's) $ 217,693 $ 231,770 $ 249,845
Redeemable preferred stock (000's) $ 2,100 $ 2,200 $ 2,300
Capitalization ratios:
Common stockholders' investment 58% 56% 53%
Preferred stocks 3 3 3
Long-term debt 39 41 44
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the accrual
of estimated unbilled revenues.
1991 1990 1989
Selected Financial Data
Operating revenues: (000's)
Electric $128,708 $124,156 $126,228
Natural gas 173,865 151,599 159,703
Mining and construction
materials 41,201 38,276 41,643
Oil and natural gas production 33,939 31,213 25,199
$377,713 $345,244 $352,773
Operating income: (000's)
Electric $ 34,647 $ 32,221 $ 32,592
Natural gas distribution 8,518 6,578 7,781
Natural gas transmission 19,904 19,362 24,835
Mining and construction
materials 9,682 7,749 9,087
Oil and natural gas production 12,552 12,523 10,420
$ 85,303 $ 78,433 $ 84,715
Earnings (loss) on common
stock: (000's)
Electric $ 15,292 $ 14,280 $ 13,385
Natural gas distribution 3,645 2,704 3,123
Natural gas transmission 449 (7,578)* 3,722
Mining and construction
materials 9,809 9,632 8,890
Oil and natural gas production 8,010 8,071 6,765
Earnings on common stock
before cumulative effect
of accounting change 37,205 27,109* 35,885
Cumulative effect of
accounting change --- --- ---
$ 37,205 $ 27,109* $ 35,885
Earnings per common share before
cumulative effect of
accounting change $ 1.96 $ 1.43* $ 1.89
Cumulative effect of accounting
change --- --- ---
$ 1.96 $ 1.43* $ 1.89
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) $ 37,619 $ 28,395* $ 36,861
Earnings per common share $ 1.94 $ 1.45 $ 1.90
Common Stock Statistics
Weighted average common shares
outstanding (000's) 18,985 18,985 18,985
Dividends per common share $ 1.435 $ 1.42 $ 1.47
Book value per common share $ 15.62 $ 15.12 $ 15.11
Market price ratios:
Dividend payout 73% 99%* 78%
Yield 5.8% 6.9% 6.5%
Price/earnings ratio 12.6x 14.3x* 12.0x
Market value as a percent of
book value 157.7% 135.6% 149.7%
Profitability Indicators
Return on average common equity 12.7% 9.4%* 12.5%
Return on average invested capital 9.6% 7.8%* 9.2%
Interest coverage 3.8x** 2.7x* 2.8x
Fixed charges coverage, including
preferred dividends 2.4x 1.9x* 2.3x
General
Total assets (000's) $964,691 $959,946 $971,401
Net long-term debt (000's) $220,623 $229,786 $234,333
Redeemable preferred stock (000's) $ 2,400 $ 2,500 $ 2,600
Capitalization ratios:
Common stockholders' investment 56% 54% 53%
Preferred stocks 3 3 3
Long-term debt 41 43 44
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.
** Calculation reflects the provisions of the company's restatement of its
Indenture of Mortgage effective April 1992.
1994 1993 1992
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,955,136 1,893,713 1,829,933
Sales for resale (thousand kWh) 444,492 510,987 352,550
Electric system generating and
firm purchase capability--kW
(Interconnected system) 470,900 465,200 460,200
Demand peak--kW
(Interconnected system) 369,800 350,300 339,100
Electricity produced
(thousand kWh) 1,901,119 1,870,740 1,774,322
Electricity purchased
(thousand kWh) 700,912 701,736 593,612
Cost of fuel and purchased
power per kWh $.017 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk) 31,840 31,147 26,681
Transportation (Mdk) 9,278 12,704 13,742
Weighted average degree days--% of
previous year's actual 92% 115% 98%
Natural Gas Transmission Operations
Sales for resale (Mdk) --- 13,201 16,841
Transportation (Mdk) 63,870 59,416 64,498
Produced (Mdk) 4,732 3,876 3,551
Net recoverable reserves (MMcf) 99,265 --- ---
Energy Marketing Operations
Natural gas volumes (Mdk) 7,301 6,827 3,292
Propane (thousand gallons) 6,462 2,210 ---
Mining and Construction Materials Operations
Coal: (000's)
Sales in tons 5,206 5,066 4,913
Recoverable reserves in tons 236,100 230,600 235,700
Construction materials: (000's)
Aggregates (tons sold) 2,688 2,391 263
Asphalt (tons sold) 391 141 ---
Ready-mixed concrete (cubic
yards sold) 315 157 ---
Recoverable aggregate reserves
in tons 71,000 74,200 20,600
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,565 1,497 1,531
Natural gas (MMcf) 9,228 8,817 5,024
Average sales prices:
Oil (per barrel) $ 13.14 $14.84 $16.74
Natural gas (per Mcf) $ 1.84 $1.86 $ 1.53
Net recoverable reserves:
Oil (000's of barrels) 12,500 11,200 12,200
Natural gas (MMcf) 54,900 50,300 37,200
1991 1990 1989
Electric Operations
Sales to ultimate consumers
(thousand kWh) 1,877,634 1,820,150 1,836,099
Sales for resale (thousand kWh) 331,314 285,564 311,327
Electric system generating and
firm purchase capability--kW
(Interconnected system) 454,400 451,600 451,600
Demand peak--kW
(Interconnected system) 387,100 381,600 383,600
Electricity produced
(thousand kWh) 1,736,187 1,674,648 1,773,849
Electricity purchased
(thousand kWh) 611,884 573,099 557,650
Cost of fuel and purchased
power per kWh $.016 $.016 $.017
Natural Gas Distribution Operations
Sales (Mdk) 30,074 28,278 31,643
Transportation (Mdk) 12,261 11,806 9,321
Weighted average degree days--% of
previous year's actual 101% 88% 112%
Natural Gas Transmission Operations
Sales for resale (Mdk) 19,572 19,658 27,274
Transportation (Mdk) 53,930 50,809 51,159
Produced (Mdk) 3,742 1,881 1,907
Net recoverable reserves (MMcf) --- --- ---
Energy Marketing Operations
Natural gas volumes (Mdk) 991 1,853 843
Propane (thousand gallons) --- --- ---
Mining and Construction Materials Operations
Coal: (000's)
Sales in tons 4,731 4,439 4,747
Recoverable reserves in tons 256,700 261,500 266,000
Construction materials: (000's)
Aggregates (tons sold) --- --- ---
Asphalt (tons sold) --- --- ---
Ready-mixed concrete (cubic
yards sold) --- --- ---
Recoverable aggregate reserves
in tons --- --- ---
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) 1,491 1,374 1,348
Natural gas (MMcf) 2,565 1,846 1,605
Average sales prices:
Oil (per barrel) $19.90 $20.11 $16.26
Natural gas (per Mcf) $ 1.48 $ 1.63 $ 1.66
Net recoverable reserves:
Oil (000's of barrels) 11,600 12,400 12,000
Natural gas (MMcf) 27,500 16,100 10,800