UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 North Fourth Street, Bismarck, North Dakota 58501
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X. No.
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of August 11, 1995:
18,984,654 shares.
INTRODUCTION
MDU Resources Group, Inc. (Company) is a diversified natural
resource company which was incorporated under the laws of the State
of Delaware in 1924. Its principal executive offices are at 400
North Fourth Street, Bismarck, North Dakota 58501, telephone (701)
222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), the public
utility division of the Company, provides electric and/or natural
gas and propane distribution service at retail to 255 communities
in North Dakota, eastern Montana, northern and western South Dakota
and northern Wyoming, and owns and operates electric power
generation and transmission facilities.
The Company, through its wholly-owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns Williston Basin Interstate
Pipeline Company (Williston Basin), Knife River Coal Mining Company
(Knife River), the Fidelity Oil Group (Fidelity Oil) and
Prairielands Energy Marketing, Inc. (Prairielands).
Williston Basin produces natural gas and provides
underground storage, transportation and gathering services
through an interstate pipeline system serving Montana,
North Dakota, South Dakota and Wyoming.
Knife River surface mines and markets low sulfur lignite
coal at mines located in Montana and North Dakota and,
through its wholly-owned subsidiary KRC Holdings, Inc.,
surface mines and markets aggregates and related
construction materials in the Anchorage, Alaska area,
southern Oregon and north-central California.
Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity
Oil Holdings, Inc., which own oil and natural gas
interests in the western United States, the Gulf Coast and
Canada through investments with several oil and natural
gas producers.
Prairielands seeks new energy markets while continuing to
expand present markets for natural gas. Its activities
include buying and selling natural gas and arranging
transportation services to end users, pipelines and local
distribution companies and, through its wholly-owned
subsidiary, Gwinner Propane, Inc., operates bulk propane
facilities in southeastern North Dakota.
INDEX
Part I
Consolidated Statements of Income --
Three and Six Months Ended June 30, 1995 and 1994
Consolidated Balance Sheets --
June 30, 1995 and 1994, and December 31, 1994
Consolidated Statements of Cash Flows --
Six Months Ended June 30, 1995 and 1994
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Part II
Signatures
Exhibit Index
Exhibit
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Six Months
Ended Ended
June 30, June 30,
1995 1994 1995 1994
(In thousands, except per share amounts)
Operating revenues:
Electric. . . . . . . . . . . . . $ 30,384 $ 30,656 $ 65,510 $ 66,454
Natural gas . . . . . . . . . . . 38,462 33,896 91,046 94,003
Mining and construction
materials . . . . . . . . . . . 31,112 31,064 49,975 50,946
Oil and natural gas
production. . . . . . . . . . . 11,309 9,420 21,254 17,995
111,267 105,036 227,785 229,398
Operating expenses:
Fuel and purchased power. . . . . 9,398 10,406 20,646 21,828
Purchased natural gas sold. . . . 11,101 9,446 31,031 36,283
Operation and maintenance . . . . 52,415 52,211 96,118 95,867
Depreciation, depletion and
amortization. . . . . . . . . . 13,324 11,852 26,159 23,572
Taxes, other than income. . . . . 5,452 5,965 11,783 12,177
91,690 89,880 185,737 189,727
Operating income (loss):
Electric. . . . . . . . . . . . . 5,366 4,516 13,590 13,227
Natural gas distribution. . . . . (676) (1,397) 4,760 4,276
Natural gas transmission. . . . . 7,482 4,872 13,004 11,632
Mining and construction
materials . . . . . . . . . . . 4,312 5,039 5,072 6,690
Oil and natural gas
production. . . . . . . . . . . 3,093 2,126 5,622 3,846
19,577 15,156 42,048 39,671
Other income -- net . . . . . . . . 1,339 1,275 2,133 2,203
Interest expense. . . . . . . . . . 6,003 6,539 12,006 13,077
Carrying costs on natural gas
repurchase commitment . . . . . . 1,537 1,239 2,977 2,148
Income before taxes . . . . . . . . 13,376 8,653 29,198 26,649
Income taxes. . . . . . . . . . . . 4,714 2,976 10,264 9,273
Net income . . . . . . . . . . . . 8,662 5,677 18,934 17,376
Dividends on preferred stocks . . . 198 200 397 400
Earnings on common stock. . . . . . $ 8,464 $ 5,477 $ 18,537 $ 16,976
Earnings per common share . . . . . $ .45 $ .29 $ .98 $ .89
Dividends per common share. . . . . $ .40 $ .39 $ .80 $ .78
Average common shares
outstanding . . . . . . . . . . . 18,985 18,985 18,985 18,985
The accompanying notes are an integral part of these statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
1995 1994 1994
(In thousands)
ASSETS
Property, plant and equipment:
Electric. . . . . . . . . . . . . . . .$ 526,405 $ 505,613 $ 514,152
Natural gas distribution. . . . . . . . 161,831 155,301 157,174
Natural gas transmission. . . . . . . . 267,757 258,022 263,971
Mining and construction materials . . . 151,215 146,140 147,284
Oil and natural gas production. . . . . 174,446 131,737 151,532
1,281,654 1,196,813 1,234,113
Less accumulated depreciation,
depletion and amortization. . . . . . 572,498 522,465 541,842
709,156 674,348 692,271
Current assets:
Cash and cash equivalents . . . . . . . 26,605 80,871 37,190
Receivables . . . . . . . . . . . . . . 44,324 47,366 55,409
Inventories . . . . . . . . . . . . . . 25,330 23,877 27,090
Deferred income taxes . . . . . . . . . 29,180 37,514 26,694
Other prepayments and current assets. . 11,396 9,690 12,287
136,835 199,318 158,670
Natural gas available under
repurchase commitment . . . . . . . . . 70,910 73,966 70,913
Investments . . . . . . . . . . . . . . . 17,888 17,081 16,914
Deferred charges and other assets . . . . 58,564 69,587 65,950
$ 993,353 $1,034,300 $ 1,004,718
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (Shares outstanding --
18,984,654, $3.33 par value at
June 30, 1995 and 1994, and
December 31, 1994). . . . . . . . . .$ 63,219 $ 63,219 $ 63,219
Other paid in capital . . . . . . . . . 95,914 95,914 95,914
Retained earnings . . . . . . . . . . . 171,398 161,165 168,050
330,531 320,298 327,183
Preferred stock subject to mandatory
redemption requirements . . . . . . . 2,000 2,100 2,000
Preferred stock redeemable at option
of the Company. . . . . . . . . . . . 15,000 15,000 15,000
Long-term debt. . . . . . . . . . . . . 190,126 218,832 217,693
537,657 556,230 561,876
Commitments and contingencies . . . . . . --- --- ---
Current liabilities:
Short-term borrowings . . . . . . . . . --- 500 680
Accounts payable. . . . . . . . . . . . 20,056 23,460 20,222
Taxes payable . . . . . . . . . . . . . 10,221 16,750 8,817
Other accrued liabilities, including
reserved revenues . . . . . . . . . . 99,322 124,042 88,516
Dividends payable . . . . . . . . . . . 7,792 7,603 7,793
Long-term debt and preferred stock due
within one year . . . . . . . . . . . 19,240 10,400 20,450
156,631 182,755 146,478
Natural gas repurchase commitment . . . . 88,401 92,211 88,404
Deferred credits:
Deferred income taxes . . . . . . . . . 114,561 112,100 114,341
Other . . . . . . . . . . . . . . . . . 96,103 91,004 93,619
210,664 203,104 207,960
$ 993,353 $1,034,300 $ 1,004,718
The accompanying notes are an integral part of these statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
1995 1994
(In thousands)
Operating activities:
Net income. . . . . . . . . . . . . . . . . . . . . . $ 18,934 $ 17,376
Adjustments to reconcile net income to net cash provided
by operations:
Depreciation, depletion and amortization . . . . . 26,159 23,572
Deferred income taxes and investment tax credit--net 2,482 1,054
Recovery of deferred natural gas contract litigation
settlement costs, net of income taxes. . . . . . 4,387 4,693
Changes in current assets and liabilities --
Receivables. . . . . . . . . . . . . . . . . . . 11,085 20,187
Inventories. . . . . . . . . . . . . . . . . . . 1,760 (4,462)
Other current assets . . . . . . . . . . . . . . (1,595) (699)
Accounts payable . . . . . . . . . . . . . . . . (166) (1,507)
Other current liabilities. . . . . . . . . . . . 12,209 24,020
Other noncurrent changes . . . . . . . . . . . . . 4,330 3,202
Net cash provided by operating activities . . . . . . 79,585 87,436
Financing activities:
Net change in short-term borrowings . . . . . . . . . (680) (9,040)
Issuance of long-term debt. . . . . . . . . . . . . . 3,600 29,850
Repayment of long-term debt . . . . . . . . . . . . . (32,387) (47,700)
Retirement of natural gas repurchase commitment . . . (3) (6,314)
Dividends paid. . . . . . . . . . . . . . . . . . . . (15,586) (15,209)
Net cash used in financing activities . . . . . . . . (45,056) (48,413)
Investing activities:
Additions to property, plant and equipment --
Electric. . . . . . . . . . . . . . . . . . . . . (8,745) (2,704)
Natural gas distribution. . . . . . . . . . . . . (4,482) (14,811)
Natural gas transmission. . . . . . . . . . . . . (3,780) 493
Mining and construction materials . . . . . . . . (4,058) (1,884)
Oil and natural gas production. . . . . . . . . . (23,078) (15,787)
(44,143) (34,693)
Sale of natural gas available under repurchase commitment 3 5,065
Investments . . . . . . . . . . . . . . . . . . . . . (974) (223)
Net cash used in investing activities . . . . . . . . (45,114) (29,851)
Increase (decrease) in cash and cash equivalents. . . (10,585) 9,172
Cash and cash equivalents--beginning of year. . . . . 37,190 71,699
Cash and cash equivalents--end of period. . . . . . . $ 26,605 $ 80,871
The accompanying notes are an integral part of these statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
June 30, 1995 and 1994
(Unaudited)
1. Basis of presentation
The accompanying consolidated interim financial statements
were prepared in conformity with the basis of presentation
reflected in the consolidated financial statements included in
the Annual Report to Stockholders for the year ended
December 31, 1994 (1994 Annual Report), and the standards of
accounting measurement set forth in Accounting Principles Board
Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board. Interim financial
statements do not include all disclosures provided in annual
financial statements and, accordingly, these financial
statements should be read in conjunction with those appearing
in the Company's 1994 Annual Report. The information is
unaudited but includes all adjustments which are, in the opinion
of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
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,
the interim results may not be indicative of results for the
full fiscal year.
3. Pending litigation
In November 1993, the estate of W.A. Moncrief (Moncrief), a
producer from whom Williston Basin purchased a portion of its
natural gas supply, filed suit in Federal District Court for the
District of Wyoming (Court) 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 of the
1994 Annual Report 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, approximately
$38 million. On March 10, 1995, the Court issued a summary
judgment dismissing Moncrief's pricing theories and
substantially reducing Moncrief's claims. On May 31, 1995, the
United States Court of Appeals for the Tenth Circuit determined
not to hear, at that time, Moncrief's attempt to appeal the
summary judgment ruling. Trial will be rescheduled with the
District Court.
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.
4. Regulatory matters and revenues subject to refund
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. On
April 5, 1995, the FERC issued an order granting in part and
denying in part Williston Basin's rehearing request. As a
result of the FERC's order, Williston Basin, on May 18, 1995,
billed its customers, approximately $2.7 million, plus interest,
to recover a portion of the amount previously refunded in
July 1994. On July 25, 1995, the FERC issued an order, which
Williston Basin is currently evaluating, relating to Williston
Basin's 1992 rate change application.
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 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.
5. Natural gas repurchase commitment
The Company has offered for sale since 1984 the inventoried
natural gas available under a repurchase commitment with
Frontier Gas Storage Company, as described in Note 4 of its 1994
Annual Report. As part of the corporate realignment effected
January 1, 1985, the Company agreed, pursuant to the settlement
approved by the FERC, to remove from rates the financing costs
associated with this natural gas.
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 June 30, 1995, 17.4 MMdk of this natural gas had been
sold by Williston Basin for use by both on- and off-system
markets. Williston Basin will continue to aggressively market
the remaining 43.3 MMdk of this natural gas whenever market
conditions are favorable. In addition, it will continue to seek
long-term sales contracts.
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. 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. On May 18, 1995, Williston Basin and the
Bureau reached a settlement of this issue wherein Williston
Basin agreed to pay certain fines as well as to upgrade certain
facilities, with the cost of both being immaterial.
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.
7. Federal tax matters
The Company's consolidated federal income tax returns were
under examination by the Internal Revenue Service (IRS) for the
tax years 1983 through 1991. In 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 and
penalties. In 1992 and the first quarter of 1995, similar
notices of proposed deficiency were received for the years 1986
through 1988 and 1989 through 1991, respectively. Although the
notices of proposed deficiency encompass a number of separate
issues, the principal issue is related to the tax treatment of
deductions claimed in connection with certain investments made
by Knife River and Fidelity Oil.
The Company intends to contest vigorously the deficiencies
proposed by the IRS and, in that regard, has timely filed
protests for the 1983 through 1991 tax years contesting the
treatment proposed in the notices of proposed deficiency.
Although it is reasonably possible that the ultimate resolution
of such matters could result in a loss of up to approximately
$18 million in excess of consolidated reserves, management
believes the Company has meritorious defenses to mitigate or
eliminate the proposed deficiencies. In that regard, the
Company's outside 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.
8. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Six Months Ended
June 30,
1995 1994
(In thousands)
Interest, net of amount capitalized $12,941 $11,795
Income taxes $ 9,407 $ 7,237
During the six month period ended June 30, 1994, the
Company's natural gas transmission business sold $8.3 million
of natural gas in underground storage to the natural gas
distribution business. The cash flow effects of this
intercompany sale and purchase shown under "Investing
activities" were not eliminated.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Overview
The following table (in millions of dollars) summarizes the
contribution to consolidated earnings by each of the Company's
businesses.
Three Months Six Months
Ended Ended
June 30, June 30,
Business 1995 1994 1995 1994
Electric $ 1.7 $ 1.1 $ 5.2 $ 4.9
Natural gas distribution (.9) (1.3) 1.7 1.8
Natural gas transmission 3.3 1.4 4.9 3.7
Mining and construction
materials 2.8 3.3 3.7 4.7
Oil and natural gas production 1.6 1.0 3.0 1.9
Earnings on common stock $ 8.5 $ 5.5 $ 18.5 $ 17.0
Earnings per common share $ .45 $ .29 $ .98 $ .89
Return on average common
equity for the 12 months
ended 12.4% 11.3%
Earnings for the quarter ended June 30, 1995, were up $3.0
million from the comparable period a year ago. Weather within the
primary four-state operating area of Montana, North Dakota, South
Dakota and Wyoming was 51 percent colder than a year ago,
increasing throughput at the natural gas distribution and
transmission businesses. Improved sales and decreased maintenance
costs at the electric business, increased oil prices and oil and
natural gas production at the oil and natural gas production
business and benefits derived from favorable rate changes at the
natural gas distribution and transmission businesses further
improved earnings. The favorable rate change at the natural gas
transmission business resulted from a Federal Energy Regulatory
Commission (FERC) order received in April 1995 on a rehearing
request relating to a 1989 general rate proceeding. The order
allowed for the one-time billing of customers for approximately
$2.2 million (after-tax) to recover a portion of the amount
previously refunded in July 1994. Sales declines at the Oregon
construction materials operations, due to higher than normal
rainfall which slowed construction activity, and the effect of
lower natural gas prices at the natural gas transmission and oil
and natural gas production businesses, partially offset the
increase in consolidated earnings.
Earnings for the six months ended June 30, 1995, were up $1.5
million from the comparable period a year ago. Lower maintenance
costs at the electric business, increased oil prices and oil and
natural gas production at the oil and natural gas production
business and benefits derived from favorable rate changes at the
natural gas distribution and transmission businesses increased
earnings. The favorable rate change at the natural gas
transmission business resulted from a FERC order received in April
1995 on a rehearing request relating to a 1989 general rate
proceeding as previously described. Lower throughput at the
natural gas transmission business, weather-related sales declines
at the Oregon construction materials operations, the effects of
decreased natural gas prices at the natural gas transmission and
oil and natural gas production businesses, and higher operation
expenses at the natural gas distribution business, partially offset
the increase in consolidated earnings.
-----------------------
Reference should be made to Notes to Consolidated Financial
Statements for information concerning various commitments and
contingencies.
Financial and operating data
The following tables (in millions, where applicable) are key
financial and operating statistics for each of the Company's
business units. Certain reclassifications have been made in the
following statistics for 1994 to conform to the 1995 presentation.
Such reclassifications had no effect on net income or common
stockholders' investment as previously reported.
Montana-Dakota -- Electric Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1995 1994 1995 1994
Operating revenues:
Retail sales $ 28.6 $ 28.3 $ 60.7 $ 61.3
Sales for resale and other 1.8 2.3 4.8 5.2
30.4 30.6 65.5 66.5
Operating expenses:
Fuel and purchased power 9.4 10.4 20.6 21.8
Operation and maintenance 9.8 10.1 19.5 20.1
Depreciation, depletion and
amortization 4.1 3.9 8.1 7.9
Taxes, other than income 1.7 1.7 3.7 3.5
25.0 26.1 51.9 53.3
Operating income 5.4 4.5 13.6 13.2
Retail sales (kWh) 454.0 447.1 971.2 972.8
Sales for resale (kWh) 59.6 83.8 204.8 211.3
Cost of fuel and purchased
power per kWh $ .017 $ .018 $ .016 $ .017
Montana-Dakota -- Natural Gas Distribution Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1995 1994 1995 1994
Operating revenues:
Sales $ 26.5 $ 23.6 $ 83.9 $ 92.1
Transportation and other .9 .7 1.8 1.8
27.4 24.3 85.7 93.9
Operating expenses:
Purchased natural gas sold 17.9 15.9 60.1 69.8
Operation and maintenance 7.5 7.3 15.5 14.8
Depreciation, depletion and
amortization 1.7 1.5 3.3 3.0
Taxes, other than income 1.0 1.0 2.1 2.0
28.1 25.7 81.0 89.6
Operating income (.7) (1.4) 4.7 4.3
Volumes (dk):
Sales 5.7 4.5 19.3 18.9
Transportation 2.4 1.7 5.5 4.6
Total throughput 8.1 6.2 24.8 23.5
Degree days (% of normal) 131.2% 86.6% 100.8% 99.7%
Cost of natural gas, including
transportation, per dk $ 3.16 $ 3.54 $ 3.12 $ 3.70
Williston Basin -- Natural Gas Transmission Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1995 1994 1995 1994
Operating revenues:
Transportation $ 15.2* $ 12.5* $ 29.7* $ 28.4*
Storage 2.7 2.2 6.0 4.9
Natural gas production and
other 1.1 2.3 2.5 4.5
19.0 17.0 38.2 37.8
Operating expenses:
Operation and maintenance 8.7* 9.4* 19.6* 20.6*
Depreciation, depletion and
amortization 1.8 1.6 3.5 3.3
Taxes, other than income 1.0 1.1 2.1 2.3
11.5 12.1 25.2 26.2
Operating income 7.5 4.9 13.0 11.6
Volumes (dk):
Transportation--
Montana-Dakota 7.1 5.8 19.6 20.3
Other 8.2 6.6 15.4 16.3
Total transportation 15.3 12.4 35.0 36.6
Produced (Mdk) 1,153 1,166 2,465 2,350
*Includes amortization and related recovery
of deferred natural gas contract
buy-out/buy-down and gas supply
realignment costs $ 2.9 $ 3.0 $ 6.9 $ 7.6
Knife River -- Mining and Construction Materials Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1995 1994 1995 1994
Operating revenues:
Coal $ 9.9 $ 9.5 $ 22.5 $ 22.3
Construction materials 21.2 21.6 27.5 28.6
31.1 31.1 50.0 50.9
Operating expenses:
Operation and maintenance 24.0 23.2 39.2 38.4
Depreciation, depletion and
amortization 1.6 1.6 3.2 3.2
Taxes, other than income 1.2 1.2 2.5 2.6
26.8 26.0 44.9 44.2
Operating income 4.3 5.1 5.1 6.7
Sales (000's):
Coal (tons) 1,096 1,172 2,492 2,603
Aggregates (tons) 834 939 1,079 1,217
Asphalt (tons) 114 107 138 125
Ready-mixed concrete
(cubic yards) 95 86 138 137
Fidelity Oil -- Oil and Natural Gas Production Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1995 1994 1995 1994
Operating revenues:
Natural gas $ 4.2 $ 4.5 $ 8.3 $ 9.0
Oil 7.1 4.9 13.0 9.0
11.3 9.4 21.3 18.0
Operating expenses:
Operation and maintenance 3.4 3.1 6.3 6.1
Depreciation, depletion and
amortization 4.1 3.2 8.0 6.2
Taxes, other than income .7 1.0 1.4 1.8
8.2 7.3 15.7 14.1
Operating income 3.1 2.1 5.6 3.9
Production (000's):
Natural gas (Mcf) 2,847 2,195 5,478 4,339
Oil (barrels) 440 386 835 756
Average sales price:
Natural gas (per Mcf) $ 1.49 $ 2.07 $ 1.51 $ 2.08
Oil (per barrel) 15.82 12.44 15.30 11.66
Amounts presented in the above tables for natural gas operating
revenues, purchased natural gas sold and operation and maintenance
expenses will not agree to the Consolidated Statements of Income due
to the elimination of intercompany transactions between Montana-
Dakota's natural gas distribution business and Williston Basin's
natural gas transmission business.
Three Months Ended June 30, 1995 and 1994
Montana-Dakota--Electric Operations
Operating income at the electric business increased primarily due
to higher retail sales revenue and lower fuel and purchased power
costs. Increased average usage by residential customers and customer
additions both contributed to the revenue improvement. However, lower
sales to large industrial customers, largely reduced demand by oil
producers and refiners, somewhat offset the retail sales revenue
improvement. Fuel and purchased power costs declined due to decreased
demand charges and lower average fuel costs. The decline in demand
costs, related to a participation power contract, is the result of the
pass-through of periodic maintenance charges during the second quarter
of 1994, offset in part by the purchase of an additional five
megawatts of capacity beginning in May 1995. The decline in average
fuel costs is primarily due to increased usage of the lower cost
Coyote Station versus other higher cost company-owned facilities.
Decreased maintenance costs at the Coyote Station, due to less
scheduled downtime, also improved operating income. Lower sales for
resale revenue, due to lower demand and system constraints within the
Mid-Continent Area Power Pool which both lowered sales, partially
offset the increase in operating income.
Earnings for the electric business improved due to the operating
income increase.
Montana-Dakota--Natural Gas Distribution Operations
Operating income at the natural gas distribution business improved
primarily due to an increase in sales revenue. The sales revenue
improvement resulted from increased volumes sold, due to 51% colder
weather and the addition of over 5,300 customers. In addition, the
effect of general rate increases placed into effect in North Dakota,
South Dakota and Montana in late 1994 further improved sales revenue.
The effects of a Wyoming Supreme Court order granting recovery in 1994
of a prior refund made by Montana-Dakota and the pass-through of lower
per unit natural gas costs partially offset the sales revenue
increase. Transportation revenues increased due to increased volumes
transported, but were largely offset by lower average rates. Higher
operation expenses, primarily increased payroll and benefit-related
costs, and increased depreciation expense, due to higher depreciable
balances, partially offset the improvement in operating income.
Natural gas distribution earnings increased due to the operating
income improvement. A decreased return recognized on net storage gas
inventory and demand balances partially offset the earnings increase.
This return decline of approximately $217,000 results from decreases
in the net book balance on which the natural gas distribution business
is allowed to earn a return.
Williston Basin
Natural gas transmission operating income improved primarily due
to an increase in transportation and storage revenues. The
transportation revenue increase resulted from the benefits of a
favorable FERC order received in April 1995 on a rehearing request
relating to a 1989 general rate proceeding. The order allowed for the
one-time billing of customers for approximately $2.7 million ($1.7
million after-tax) to recover a portion of the amount previously
refunded in July 1994. In addition, increased volumes transported to
local distribution companies and to storage added to the
transportation revenue improvement. Higher demand revenues associated
with the storage enhancement project completed in late 1994
contributed to the storage revenue improvement. Lower operation and
maintenance expenses, primarily lower production expenses, further
contributed to the increase in operating income. A decline in company
production revenue, largely resulting from a 62 cent per decatherm
decline in realized natural gas prices, partially offset the increase
in operating income.
Earnings for this business increased primarily due to the increase
in operating income, higher interest income and lower interest
expense. Higher interest income of $952,000 ($583,000 after-tax) is
related to the previously described refund recovery. The interest
expense decline of $541,000 resulted from debt retirements and lower
reserved revenue balances. Increased carrying costs associated with
the natural gas repurchase commitment, due to higher average interest
rates, partially offset the earnings increase.
Knife River
Coal Operations --
Operating income for the coal operations decreased $214,000
primarily due to higher operation expenses, the result of increased
reclamation costs at the Beulah Mine due to working in higher leveling
and respreading cost areas. Although sales volumes were down, coal
revenues increased as a result of higher average sales prices due to
price increases at the Gascoyne Mine and the effect of changes in
sales mix between higher-priced versus lower-priced mines. The volume
decrease results from lower sales to the Big Stone electric generating
station due to its increased usage of stockpiled coal in anticipation
of the expiration of the coal contract in the third quarter. However,
higher sales at the Beulah Mine due to less scheduled down time this
year at the Coyote Station somewhat offset the sales volume decrease.
Construction Materials Operations --
Construction materials operating income declined $513,000 primarily
due to lower revenues, primarily lower aggregate sales at the Oregon
operations due to above normal rainfall which slowed construction
activity. However, increased ready-mixed concrete sales at the Alaska
operations and higher ready-mixed concrete prices at the Oregon
operations somewhat offset the revenue decline. Operation and
maintenance expenses increased due primarily from the timing of
maintenance work and increased work performed by subcontractors, both
at the Oregon operations, and increased volumes at the Alaska
operations, partially offset by lower aggregate processing costs at
the California operations due primarily to capital improvements made
in 1994 and 1995.
Consolidated --
Earnings decreased due to the decline in coal and construction
materials operating income.
Fidelity Oil
Operating income for the oil and natural gas production business
increased as a result of higher oil revenues, $1.5 million of which
was due to higher average oil prices, and $678,000 of which stemmed
from increased production. Decreased natural gas prices reduced
natural gas revenues by $1.6 million but were largely offset by a $1.3
million revenue improvement due to higher volumes produced. Adding
to operating income were decreased production taxes stemming largely
from the timing of payments in 1995 as compared to 1994. Also,
partially offsetting the operating income improvement was increased
depreciation, depletion and amortization, primarily the result of
increased production.
Earnings for this business improved as a result of the increase in
operating income. Higher interest expense of $210,000, due primarily
to higher average borrowings, partially offset the earnings increase.
Six Months Ended June 30, 1995 and 1994
Montana-Dakota--Electric Operations
Operating income at the electric business increased due to lower
fuel and purchased power costs due to changes in generation mix
between lower cost versus higher cost generating stations and
decreased maintenance expenses, both as previously described in the
three month's discussion. Decreased sales for resale revenue, also
as previously discussed, and increased depreciation expense and taxes
other than income partially offset the increase in operating income.
Earnings for the electric business improved due to the operating
income increase.
Montana-Dakota--Natural Gas Distribution Operations
Operating income increased at the natural gas distribution business
due to the effect of $1.4 million in general rate increases, as
previously described, and higher sales due to the addition of over
5,300 customers. However, the pass-through of lower per unit natural
gas costs more than offset the sales revenue improvement. The effect
of higher volumes transported were offset by lower average
transportation rates. Higher operation expenses and depreciation
expense partially offset the increase in operating income. The
increase in operation expense is primarily due to increased payroll
and benefit-related costs. The increase in depreciation expense is
due to higher depreciable plant balances.
Natural gas distribution earnings decreased due to a decreased
return recognized on net storage gas inventory and demand balances of
$853,000, as previously described in the three month's discussion,
partially offset by the increase in operating income.
Williston Basin
Operating income increased primarily due to an increase in
transportation and storage revenues. The transportation revenue
increase resulted from the benefits of a favorable FERC order received
in April 1995, as previously described in the three month's
discussion, offset in part by lower volumes transported. Decreased
transportation of natural gas held under the repurchase commitment,
offset in part by increased volumes moved to storage, contributed to
the decline in transportation volumes. Higher demand revenues
associated with the storage enhancement project completed in late 1994
contributed to the storage revenue improvement. Lower operation and
maintenance expenses, primarily lower production expenses, further
contributed to the increase in operating income. A decline in company
production revenue, primarily due to a 76 cent per decatherm decline
in realized natural gas prices, partially offset the increase in
operating income.
Earnings for this business increased due primarily to the increase
in operating income, higher interest income and lower interest
expense. Higher interest income of $952,000 ($583,000 after-tax) is
related to the previously described refund recovery. The decline in
interest expense of $1.4 million is due to debt refinancing in April
1994, debt retirements and lower reserved revenue balances. Increased
carrying costs on the natural gas repurchase commitment, due to higher
average interest rates, partially offset the increase in earnings.
Knife River
Coal Operations --
Operating income for the coal operations decreased $528,000
primarily due to higher operation expenses at the Beulah Mine. The
operation expense increase results from higher stripping costs, and
higher reclamation costs stemming from working in higher leveling and
respreading cost areas. Higher revenues resulting from price
increases at all mines and increased sales at the Beulah Mine,
partially offset by lower sales at the Gascoyne Mine, improved
operating income. The higher sales at the Beulah Mine are due mainly
to less scheduled downtime this year at the Coyote Station, while the
lower sales at the Gascoyne Mine result from increased coal usage from
the stockpile at the Big Stone Station in anticipation of the
expiration of the coal contract in the third quarter.
Construction Materials Operations --
Construction materials operating income declined $1.1 million due
to lower revenues and higher operation and maintenance expenses. The
revenue decline resulted from lower aggregate sales at the Oregon
operations due to above normal rainfall which slowed construction
activity. However, increased ready-mixed concrete sales at the Alaska
operations and higher ready-mixed concrete prices at the Oregon
operations somewhat offset the revenue decline. Operation and
maintenance expenses increased due primarily to the timing of
maintenance work and increased work performed by subcontractors, both
at the Oregon operations, and increased volumes at the Alaska
operations, partially offset by lower aggregate processing costs at
the California operations due primarily to capital improvements made
in 1994 and 1995.
Consolidated --
Earnings decreased due to the decline in coal and construction
materials operating income.
Fidelity Oil
Operating income for the oil and natural gas production business
increased as a result of higher oil revenues, $3.0 million of which
was due to higher average oil prices, and $921,000 of which stemmed
from increased production. Decreased natural gas prices reduced
natural gas revenues by $3.1 million but were partially offset by a
$2.4 million revenue improvement due to higher volumes produced. Also
adding to operating income were decreased production taxes stemming
largely from the timing of payments in 1995 as compared to 1994.
Increased depreciation, depletion and amortization, primarily the
result of increased production, also partially offset the operating
income improvement.
Earnings for this business improved as a result of the increase in
operating income. Increased interest expense of $289,000, due
primarily to higher average borrowings, partially offset the increase
in earnings.
Prospective Information
Each of the Company's businesses is subject to competition, varying
in both type and degree. See Items 1 and 2 in the 1994 Annual Report
on Form 10-K (1994 Form 10-K) for a further discussion of the effects
these competitive forces have on each of the Company's businesses.
The operating results of the Company's electric, natural gas
distribution, natural gas transmission, and mining and construction
materials businesses are, in varying degrees, influenced by the
weather as well as by the general economic conditions within their
respective market areas. Additionally, the ability to recover costs
through the regulatory process affects the operating results of the
Company's electric, natural gas distribution and natural gas
transmission businesses.
On June 30, 1995, Montana-Dakota filed a general natural gas rate
increase application with the Montana Public Service Commission (MPSC)
requesting an increase of $2.1 million or 4.4%. The MPSC has until
April 1, 1996, to issue an order. Also, on June 30, 1995, Williston
Basin filed a general rate increase application with the FERC
requesting an increase of $3.6 million or 6.55%, effective August 1,
1995. On July 27, 1995, the FERC issued an order suspending the
implementation of the increased rates, subject to refund, until
January 1, 1996.
In early 1995, Montana-Dakota, in an effort to increase the
efficiency of its electric and natural gas operations, announced plans
to close 45 district offices throughout the four-state service
territory during 1995 and early 1996. These closings along with other
operating efficiencies are expected to result in a reduction of
between 7 and 8 percent of the utility's workforce. Through June 30,
1995, 21 district offices have been closed. Additionally, two
operating divisions were combined to increase efficiency. The utility
now operates from five division centers, down from eight three years
ago.
Knife River continues to seek additional growth opportunities.
These include not only identifying possibilities for alternate uses
of lignite coal but also investigating the acquisition of other
surface mining properties, particularly those relating to sand and
gravel aggregates and related products such as ready-mixed concrete,
asphalt and various finished aggregate products.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of" (SFAS No. 121). SFAS No. 121 imposes stricter criteria
for assets, including regulatory assets, by requiring that such assets
be probable of future recovery at each balance sheet date. The
Company anticipates adopting SFAS No. 121 on January 1, 1996, and does
not expect that adoption will have a material affect on the Company's
financial position or results of operations. This conclusion may
change in the future depending on the extent to which recovery of the
Company's long-lived assets is influenced by an increasingly
competitive environment.
FERC Rulemaking on Transmission Access --
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking
(NOPR) on Open Access Non-Discriminatory Transmission Services by
Public Utilities and Transmitting Utilities (FERC Docket No. RM95-8-
000) and a supplemental NOPR on Recovery of Stranded Costs (FERC
Docket No. RM94-7-001).
The rules proposed in the NOPR are intended to facilitate
competition among generators for sales to the bulk power supply
market. If adopted, the NOPR on open access transmission would
require public utilities under the Federal Power Act to file a generic
set of transmission tariff terms and conditions as set forth in the
rulemaking to provide open access to their transmission systems.
Previously, the FERC had not imposed on utilities a general obligation
to provide access to their transmission systems. In addition, each
public utility would also be required to establish separate rates for
its transmission and generation services for new wholesale service,
and to take transmission services (including ancillary services) under
the same tariffs that would be applicable to third-party users for all
of its new wholesale sales and purchases of energy.
The supplemental NOPR on stranded costs provides a basis for
recovery by regulated public utilities of legitimate and verifiable
stranded costs associated with exiting wholesale requirements
customers and retail customers who become unbundled wholesale
transmission customers of the utility. FERC would provide public
utilities a mechanism for recovery of stranded costs that result from
municipalization, former retail customers becoming wholesale
customers, or the loss of a wholesale customer. FERC will consider
allowing recovery of stranded investment costs associated with retail
wheeling only if a state regulatory commission lacks the authority to
consider that issue.
It is anticipated that the proposed rule may be modified and that
a final rule may take effect in early 1996. The Company is continuing
to evaluate the NOPR to determine its impact on the Company and its
customers, but cannot predict the outcome of this matter.
Liquidity and Capital Commitments
The Company's regulated businesses operated by Montana-Dakota
and Williston Basin estimate construction costs of approximately
$39.9 million for the year 1995. The Company's 1995 capital needs
to retire maturing long-term securities are estimated at $20.6
million.
It is anticipated that Montana-Dakota will continue to provide
all of the funds required for its construction requirements from
internal sources and through the use of its $30 million revolving
credit and term loan agreement, none of which is outstanding at
June 30, 1995, and through the issuance of long-term debt, the
amount and timing of which will depend upon the Company's needs,
internal cash generation and market conditions.
Williston Basin expects to meet its construction requirements
and financing needs with a combination of internally generated
funds and lines of credit aggregating $35 million, none of which is
outstanding at June 30, 1995, and through the issuance of long-term
debt, the amount and timing of which will depend upon the Company's
needs, internal cash generation and market conditions. 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
June 30, 1995, $12.5 million is outstanding under the term loan
agreement.
Knife River's capital needs for 1995, estimated at $7.4 million,
excluding those required for potential mining acquisitions, will be
met through funds on hand, funds generated from internal sources
and lines of credit aggregating $11 million, none of which is
outstanding at June 30, 1995. It is anticipated that funds
required for future acquisitions will be met primarily from
additional borrowings.
Fidelity Oil's 1995 capital needs related to its oil and natural
gas acquisition, development and exploration program, estimated at
$43.5 million, will be met through funds generated from internal
sources and lines of credit aggregating $55 million. On July 14,
1995, amounts available under the lines of credit were increased
from $35 to $55 million. At June 30, 1995, $20.6 million is
outstanding under the lines of credit.
See Note 7 for a discussion of notices of proposed deficiency
received from the IRS proposing substantial additional income
taxes. If the IRS position were upheld, the level of funds
required would be significant.
Prairielands' 1995 capital needs, estimated at $2.9 million,
will be met through funds generated internally and lines of credit
aggregating $5.4 million, none of which is outstanding at June 30,
1995.
The Company utilizes its lines of credit aggregating $40 million
and its $30 million revolving credit and term loan agreement to
meet its short-term financing needs and to take advantage of market
conditions when timing the placement of long-term or permanent
financing. There were no borrowings outstanding at June 30, 1995,
under the lines of credit.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to pledge $1.43 of unfunded property to the Trustee for
each dollar of indebtedness incurred under the Indenture and that
annual earnings (pretax and before interest charges), as defined in
the Indenture, equal at least two times its annualized first
mortgage bond interest costs. Under the more restrictive of the
two tests, as of June 30, 1995, the Company could have issued
approximately $145 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 3.0 and 2.9 times for the twelve months ended
June 30, 1995, and for the year 1994, respectively. Additionally,
the Company's first mortgage bond interest coverage was 3.6 and 3.3
times for the twelve months ended June 30, 1995, and for the year
1994, respectively. Stockholders' equity as a percent of total
capitalization was 62% and 58% at June 30, 1995, and December 31,
1994, respectively.
PART II - OTHER INFORMATION
6. Exhibits and Reports on Form 8-K
a) Exhibits
(27) Financial Data Schedule
b) Reports on Form 8-K
None.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE August 14, 1995 BY /s/ Warren L. Robinson
Warren L. Robinson
Vice President, Treasurer
and Chief Financial Officer
/s/ Vernon A. Raile
Vernon A. Raile
Vice President, Controller and
Chief Accounting Officer
EXHIBIT INDEX
Exhibit No.
(27) Financial Data Schedule