UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
________________________________________
(Mark One)
(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 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
________________________________________________________
(Former name, former address and former fiscal year,
if changed since last report.)
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 the latest practicable date.
On August 7, 1995, the Company had 54,295,352 shares of common stock
outstanding.
<PAGE>
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
For the Six Months Ended
June 30, June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 467,805 $ 483,261
EXPENSES:
Operations. . . . . . . . . . . . . . . . . . . . . . . . . 210,336 206,825
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . 36,021 39,447
Selling, general and administrative . . . . . . . . . . . . 50,312 51,066
Taxes other than income taxes . . . . . . . . . . . . . . . 45,060 48,809
Depreciation, depletion and amortization. . . . . . . . . . 44,170 43,643
385,899 389,790
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . . 81,906 93,471
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . 21,747 21,337
Other (income) deductions-net . . . . . . . . . . . . . . . (1,325) (2,656)
20,422 18,681
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . 19,582 24,903
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . 41,902 49,887
DIVIDENDS ON PREFERRED STOCK. . . . . . . . . . . . . . . . . 3,614 3,614
NET INCOME AVAILABLE FOR COMMON STOCK . . . . . . . . . . . . $ 38,288 $ 46,273
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) . . . . . . 53,857 52,876
NET INCOME PER SHARE OF COMMON STOCK. . . . . . . . . . . . . $ 0.71 $ 0.88
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
For the Three Months Ended
June 30, June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 205,522 $ 205,446
EXPENSES:
Operations. . . . . . . . . . . . . . . . . . . . . . . . . 96,223 90,893
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . 20,681 23,136
Selling, general and administrative . . . . . . . . . . . . 22,951 25,280
Taxes other than income taxes . . . . . . . . . . . . . . . 23,140 22,755
Depreciation, depletion and amortization. . . . . . . . . . 21,604 21,420
184,599 183,484
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . . 20,923 21,962
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . 10,792 10,555
Other (income) deductions-net . . . . . . . . . . . . . . . 255 (2,777)
11,047 7,778
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . 2,306 3,475
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . 7,570 10,709
DIVIDENDS ON PREFERRED STOCK. . . . . . . . . . . . . . . . . 1,807 1,807
NET INCOME AVAILABLE FOR COMMON STOCK . . . . . . . . . . . . $ 5,763 $ 8,902
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) . . . . . . 53,976 53,009
NET INCOME PER SHARE OF COMMON STOCK. . . . . . . . . . . . . $ 0.11 $ 0.17
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
<TABLE>
<CAPTION>
June 30, December 31,
1995 1994
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $88,691 and $79,510
plant under construction)
Electric. . . . . . . . . . . . . . . . . . . . . . . . . $ 1,652,206 $ 1,608,615
Natural gas . . . . . . . . . . . . . . . . . . . . . . . 471,051 463,134
2,123,257 2,071,749
Less - accumulated depreciation and depletion . . . . . . . 647,353 619,195
1,475,904 1,452,554
ENTECH PROPERTY (includes $8,687 and $3,030
property under construction). . . . . . . . . . . . . . . 558,707 530,167
Less - accumulated depreciation and depletion . . . . . . . 203,780 189,926
354,927 340,241
INDEPENDENT POWER GROUP PROPERTY (includes $2,976 and
$671 property under construction) . . . . . . . . . . . . 72,663 70,253
Less - accumulated depreciation . . . . . . . . . . . . . . 17,563 17,560
55,100 52,693
1,885,931 1,845,488
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments . . . . . . . . . . . . . . . 50,095 54,397
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 51,586 49,713
101,681 104,110
CURRENT ASSETS:
Cash and temporary cash investments . . . . . . . . . . . . 14,402 21,564
Accounts receivable . . . . . . . . . . . . . . . . . . . . 102,141 159,975
Materials and supplies (principally at average cost). . . . 45,281 47,937
Prepayments and other assets. . . . . . . . . . . . . . . . 65,131 65,154
226,955 294,630
DEFERRED CHARGES:
Advanced coal royalties . . . . . . . . . . . . . . . . . . 22,860 22,939
Regulatory assets related to income taxes . . . . . . . . . 147,072 146,844
Regulatory assets - other . . . . . . . . . . . . . . . . . 56,844 49,880
Other deferred charges. . . . . . . . . . . . . . . . . . . 49,216 48,806
275,992 268,469
$ 2,490,559 $ 2,512,697
The accompanying notes are an integral part of these statements.
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
June 30, December 31,
1995 1994
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,056,127 and
53,578,737 shares issued) . . . . . . . . . . . . . . . $ 678,458 $ 667,344
Retained earnings and other shareholders' equity. . . . . 316,988 320,756
Unallocated Stock held by Trustee for Deferred
Savings and Employee Stock Ownership Plan . . . . . . . (31,596) (32,580)
963,850 955,520
Preferred stock . . . . . . . . . . . . . . . . . . . . . . 101,416 101,416
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . 608,359 588,876
1,673,625 1,645,812
CURRENT LIABILITIES:
Short-term borrowing. . . . . . . . . . . . . . . . . . . . 63,196 113,989
Long-term debt - portion due within one year. . . . . . . . 17,030 16,980
Dividends payable . . . . . . . . . . . . . . . . . . . . . 23,445 23,249
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . 857 9,210
Other taxes . . . . . . . . . . . . . . . . . . . . . . . . 46,444 46,521
Accounts payable. . . . . . . . . . . . . . . . . . . . . . 45,029 50,788
Interest accrued. . . . . . . . . . . . . . . . . . . . . . 11,767 11,785
Other current liabilities . . . . . . . . . . . . . . . . . 46,437 40,546
254,205 313,068
DEFERRED CREDITS:
Deferred income taxes . . . . . . . . . . . . . . . . . . . 330,198 322,835
Investment tax credit . . . . . . . . . . . . . . . . . . . 47,855 48,729
Accrued mining reclamation costs. . . . . . . . . . . . . . 112,716 110,035
Other deferred credits. . . . . . . . . . . . . . . . . . . 71,960 72,218
562,729 553,817
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,490,559 $ 2,512,697
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
For the Six Months Ended
June 30, June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income. . . . . . . . . . . . . . . . . . . . . . . . . $ 41,902 $ 49,887
Noncash charges (credits) to net income:
Depreciation and depletion. . . . . . . . . . . . . . . . 44,170 43,643
Mining reclamation costs expenses . . . . . . . . . . . . 8,345 7,385
Deferred income taxes.. . . . . . . . . . . . . . . . . . 6,283 1,694
Amortization of loss on long-term sale
of power. . . . . . . . . . . . . . . . . . . . . . . . (1,632) (2,113)
Other - net . . . . . . . . . . . . . . . . . . . . . . . 8,967 11,864
Changes in other assets and liabilities . . . . . . . . . . (10,195) (16,066)
Accounts receivable . . . . . . . . . . . . . . . . . . . . 57,834 34,741
Materials and supplies. . . . . . . . . . . . . . . . . . . 2,656 (3,714)
Accounts payable. . . . . . . . . . . . . . . . . . . . . . (5,759) (9,402)
Payment of mining reclamation costs . . . . . . . . . . . . (5,664) (4,223)
Net Cash Flows from Operating Activities. . . . . . . . . 146,907 113,696
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Gross additions to property and plant . . . . . . . . . . . (94,024) (81,742)
Investments in other operations . . . . . . . . . . . . . . 2,365 (1,256)
Sales of property . . . . . . . . . . . . . . . . . . . . . 6,359 3,127
Additional investments. . . . . . . . . . . . . . . . . . . (1,897) (286)
Net Cash Flows from Investing Activities. . . . . . . . . (87,197) (80,157)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock . . . . . . . . . . . . . . . . . . . 11,259 12,912
Issuance of long-term debt. . . . . . . . . . . . . . . . . 19,949 23,760
Retirement of long-term debt. . . . . . . . . . . . . . . . (692) (20,991)
Short-term debt . . . . . . . . . . . . . . . . . . . . . . (50,793) (6,803)
Dividends on common and preferred stock . . . . . . . . . . (46,595) (45,799)
Net Cash Flows from Financing Activities. . . . . . . . . (66,872) (36,921)
Net Cash Flows. . . . . . . . . . . . . . . . . . . . . (7,162) (3,382)
Cash and cash equivalents at beginning of period. . . . . . . 21,564 11,604
Cash and cash equivalents at end of period. . . . . . . . . . $ 14,402 $ 8,222
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Six Months For:
Income taxes. . . . . . . . . . . . . . . . . . . . . . . $ 21,651 $ 27,009
Interest. . . . . . . . . . . . . . . . . . . . . . . . . 22,964 22,528
</TABLE>
The accompanying notes are an integral part of these statements.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying financial statements of the Company for the interim
periods ended June 30, 1995 and 1994 are unaudited but, in the opinion of
management, reflect all adjustments, consisting only of normal recurring
accruals, necessary for a fair statement of the results of operations for
those interim periods. The results of operations for the interim periods are
not necessarily indicative of the results to be expected for the full year.
These financial statements do not contain the detail or footnote disclosure
concerning accounting policies and other matters which would be included in
full fiscal year financial statements; therefore, they should be read in
conjunction with the Company's audited financial statements included in the
Company's Annual Report on Form 10-K for the year ended December 31, 1994.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1995 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1. CONTINGENCIES AND COMMITMENTS:
In 1990, the Company filed with the Federal Energy Regulatory
Commission (FERC) a plan (the Plan) to mitigate damages to, and to manage fish
and wildlife habitat impacted by the operation of the Kerr Hydroelectric
Project. The Plan was prepared pursuant to a joint license issued by the FERC
to the Company and the Confederated Salish and Kootenai Tribes (Tribes). The
Plan provides for a one-time payment by the Company of $15,418,000 and annual
payments of $965,000 which would be adjusted annually to reflect the effects
of inflation and which are to be allocated among the Tribes and various
groups.
As part of its review of the Plan, FERC is preparing a draft
environmental impact statement which is expected to suggest modifications to
the Plan. In addition, the Department of Interior has proposed certain
conditions, requiring changes in the operation of the project, as well as
non-operational measures which would be funded by an initial payment, annual
payments based on a calculation of the Project's value as a base-load facility
and further capital investments. The Company estimates the proposed
operational changes would increase its power costs by approximately $5,500,000
per year. In addition, the proposed conditions would increase the one-time
payment to approximately $33,000,000 and change the annual payments to
approximately $945,000.
While it cannot predict when or in what form the Plan finally will be
approved, the Company expects that the cost of mitigation measures will be
recovered through rates or from the Tribes if they exercise their right to
take over the project and will not have a materially adverse effect on the
Company's financial condition or results of operations.
In November 1992, the Company filed with FERC its application to
relicense nine Madison and Missouri River hydroelectric facilities with
electric generating capacity totaling 292 megawatts. The original application
proposed an additional 74 megawatts of generation. The Company has amended
the application to reduce the proposed additional generation to 36 megawatts
by eliminating a planned expansion of one of the facilities and reducing
generation at another. The total cost of relicensing, including physical
improvements, environmental protection, mitigation and enhancement measures,
is estimated to have a present value of $218,000,000. The Company expects
that the relicensing costs will be recovered through rates and, therefore,
will not have a materially adverse effect on the Company's financial condition
or results of operations.
The Company is challenging an attempt by Puget Sound Power & Light
Company (Puget) to terminate contractual obligations to purchase 94 MW of
capacity and associated energy per year under an agreement (the Agreement)
which expires in 2010. On February 27, 1995, Puget notified the Company of
its intention to terminate the Agreement, effective the next day, alleging the
Company had failed to satisfy a requirement to secure firm contractual rights
to a transmission path for the delivery of the electricity. The Company
believes that Puget has no right to terminate the Agreement because the
required transmission path has been provided. The Company is confident
regarding its position and is pursuing its rights vigorously; however, it
cannot assure the outcome of this controversy.
This matter is pending before a Federal District Court in Montana. If
the Company is unsuccessful, it would be required to reimburse Puget for any
increased power purchase costs paid by Puget attributable to the difference
between the power purchase price under the Agreement, approximately
4.6 cents/kWh escalating annually, and the lower price Puget may demonstrate
it otherwise would have paid for electricity after February 28, 1995. In
addition, the Company would be obligated to reimburse Puget approximately
$39,000,000, plus interest, for the amount by which Puget's payments through
February 28, 1995 have exceeded its projection of avoided costs. Additional
potential liability for the Company includes the difference in revenue
resulting from sales at prices under the Agreement, approximately $29,000,000
per year, and lower prices it might receive from future alternative sales of
the electricity, which cannot be estimated. The Company may also be required
to make a noncash adjustment to its accounting records reducing an asset
related to the Agreement by approximately $20,000,000 pre-tax.
Western Energy Company (Western), a wholly-owned subsidiary of the
Company, is a party in an arbitration initiated by the non-operating owners of
the Colstrip Units Nos. 3 & 4 (i.e., Puget Sound Power and Light Company,
Washington Water Power Company, Portland General Electric Company and
PacifiCorp - collectively the "Buyers") to resolve a variety of disputes
arising under the Coal Supply Agreement, dated July 2, 1980, and a Coal
Transportation Agreement, dated July 10, 1981, as amended. The fuel supply
for Colstrip Units Nos. 3 & 4 has been supplied and transported to the Buyers
by Western pursuant to these Agreements. The arbitration hearing is now
scheduled for late October of 1995 and a decision is expected by the end of
the year.
The Buyers have requested a declaration that (i) the Buyers have the
right to purchase coal from others in excess of 600,000 tons monthly,
6,000,000 tons yearly and 170,000,000 tons over the contract life or that (ii)
the cost of coal and coal transportation in excess of these quantities is at a
price to be negotiated or selected by arbitration. The Buyers also have
requested a declaration that they have the right to "release" tons they would
otherwise be obligated to purchase and purchase those tons from others.
Western asserts that these Agreements require the Buyers to purchase and
transport all of the coal requirements at Units Nos. 3 & 4 from Western
pursuant to these Agreements at specified contract prices. As to these
claims, the Buyers seek prospective relief almost exclusively.
The Buyers assert that pursuant to a "1980 arbitration award", which
proceeded these Agreements, certain transportation charges which have been
paid by the Buyers were to be provided without charge by Western. Western
asserts that these transportation charges were properly assigned to the Buyers
under these Agreements. On this claim, the Buyers seek a refund or credit of
$62,000,000.
The Buyers assert that Western has violated the Coal Supply Agreement
because its mining has not been conducted in an "economic and efficient"
manner and that Western has failed to adopt a mining plan suggested by the
Buyers. Western asserts that its mine plan is reasonable and denies that the
Buyers have a contract right to insist upon a mine plan of their choosing.
The Buyers seek damages of approximately $4,500,000 on this claim, as well as,
equitable relief requiring Western to sell the mine to the Buyers at
depreciated cost or to turn operation of the mine over to a contract miner.
The Buyers seek to require Western to fund an external reclamation
account in the approximate amount of $36,000,000 and to accept the tax
consequences associated with this account going forward. Western acknowledges
that a reclamation account must be maintained, but denies that this account
must be external to Western or that it must bear the associated tax
consequences.
Western is confident regarding its position on the issues in dispute and
is vigorously pursuing each of these claims. A series of pre-hearing filings
are scheduled which will require the Buyers to further describe their claims
and the evidence in support of the Buyers' position. At present, in part
because of the preliminary stage of these proceedings, Western cannot predict
the outcome of this arbitration.
The Entech Oil Division has agreed to supply 132 Bcf of natural gas to
four cogeneration facilities through mid-2011. The Oil Division has
sufficient proven, developed and undeveloped reserves, and controls related
sales of production sufficient to supply all of the remaining natural gas
required by these agreements.
NOTE 2. RATE MATTERS:
On April 25, 1995, the Montana Public Service Commission (PSC) approved
an electric rate increase of $13,900,000, on an annual basis, effective May 1,
1995. This increase, which affirmed a settlement negotiated with the Montana
Consumer Counsel and other interested parties, includes $7,700,000, which had
been previously approved on an interim basis. The final order in accordance
with the settlement did not itemize an allowed rate of return or other
components of the negotiated amount.
The Company will file an electric and natural gas general rate case
during the third quarter of 1995. The rate filing will request an increase in
annual electric revenues ranging from $30,000,000 to $38,000,000 and an
increase in annual natural gas revenues ranging from $11,000,000 to
$14,000,000.
NOTE 3. LONG-TERM DEBT:
In April 1995, the Company sold $20,000,000 of Secured Medium-Term
Notes, 7.33% series due 2025, the proceeds of which were used to finance
construction and repay short-term debt.
NOTE 4. FINANCIAL INSTRUMENTS:
Entech currently uses swap agreements to hedge revenues from anticipated
sales of oil and natural gas to manage price risk. Under the swap agreements,
Entech receives or makes payments based on the differential between the
agreed-upon price and the market price of oil or natural gas when the hedged
production is sold. At June 30, 1995, Entech had swap agreements to hedge
approximately 41% of its production from proved, developed and producing oil
reserves through June 1996, and for approximately 8% of its production from
proved, developed and producing natural gas reserves through March 1996. In
addition, Entech had swap agreements to hedge approximately 4% of its delivery
obligations under long-term natural gas sales contracts through February 1996.
At June 30, 1995, the Company had no material deferred gains or losses from
these transactions.
The Independent Power Group (IPG) has investments in independent power
partnerships, some of which have entered into derivative financial instruments
to hedge against interest rate exposure on floating rate debt, and foreign
currency and gas price fluctuations.
<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion should be read in conjunction with the management's
discussion included in the Company's Annual Report on Form 10-K for the year
ended December 31, 1994.
RESULTS OF OPERATIONS
The following discussion presents significant events or trends which
have had an effect on the operations of the Company or which are expected to
have an impact on operating results in the future.
Six Months Ended June 30, 1995 and 1994:
Net Income Per Share of Common Stock
Consolidated net income for the six months ended June 30, 1995 declined
17 cents per share to 71 cents as compared with 88 cents for the same period
last year. Of this decrease, approximately 5 cents per share was due to a
retroactive adjustment reflecting a coal arbitration decision reducing the
price charged per ton of coal sold to Colstrip Units Nos. 1 & 2 (see Part II,
Item 1., Legal Proceedings). While the decision reduced Entech's earnings,
the Utility benefited through lower fuel costs. In addition, earnings were
lower because coal sales of Western Energy declined as a result of reduced
volumes sold to the Colstrip generating units due to reductions in steam
generation. Production problems at Entech's underground mine in Colorado also
decreased consolidated net income.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Six Months Ended
June 30,
1995 1994
Utility Operations $ 0.58 $ 0.45
Entech 0.09 0.41
Independent Power Group 0.04 0.02
Consolidated $ 0.71 $ 0.88
<PAGE>
UTILITY OPERATIONS
<TABLE>
<CAPTION>
Six Months Ended
June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 201,809 $ 205,020
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 3,228 3,201
205,037 208,221
EXPENSES
Power supply. . . . . . . . . . . . . . . . . . . . . . . . . 68,232 81,792
Transmission and distribution . . . . . . . . . . . . . . . . 13,134 13,947
Selling, general and administrative . . . . . . . . . . . . . 21,382 23,447
Taxes other than income taxes . . . . . . . . . . . . . . . . 23,275 21,199
Depreciation and amortization . . . . . . . . . . . . . . . . 21,251 20,349
147,274 160,734
INCOME FROM ELECTRIC OPERATIONS . . . . . . . . . . . . . . . 57,763 47,487
NATURAL GAS UTILITY:
REVENUES
Revenues (other than gas supply
cost revenues). . . . . . . . . . . . . . . . . . . . . . . 49,294 44,922
Gas supply cost revenues. . . . . . . . . . . . . . . . . . . 13,386 10,993
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 542 391
63,222 56,306
EXPENSES
Gas supply costs. . . . . . . . . . . . . . . . . . . . . . . 13,386 10,993
Other production, gathering and exploration . . . . . . . . . 5,198 4,072
Transmission and distribution . . . . . . . . . . . . . . . . 5,511 4,870
Selling, general and administrative . . . . . . . . . . . . . 9,128 9,006
Taxes other than income taxes . . . . . . . . . . . . . . . . 7,273 6,699
Depreciation, depletion and amortization. . . . . . . . . . . 5,146 4,723
45,642 40,363
INCOME FROM GAS OPERATIONS. . . . . . . . . . . . . . . . . . 17,580 15,943
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . 21,898 21,245
Other (income) deductions - net . . . . . . . . . . . . . . . (2,852) (1,628)
19,046 19,617
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . 56,297 43,813
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . 21,562 16,377
UTILITY NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 34,735 $ 27,436
</TABLE>
<PAGE>
UTILITY OPERATIONS:
The Company is a winter peaking utility, which earns most of its revenue
from retail customers in the first and fourth quarters of the year. Weather
can significantly affect revenues and net income, and should be considered
when analyzing trends. As measured by heating degree days, the weather for
the six months ended June 30, 1995 in the Company's service territory was 8%
colder than the same period last year.
The Company's electric wholesale revenues and power purchase expenses
are influenced by weather, streamflow conditions, and the wholesale power
market in the Northwest and California. Therefore, the situation in the
region affects sales and expenses for the reported time period.
Electric Utility:
Income from electric operations increased $10,300,000 primarily due to
the coal price arbitration decision and low wholesale prices, which benefited
the utility through reduced power supply costs. Higher tariffs and customer
growth also contributed to the increase. The increase was partially offset by
a decline in revenues from sales to other utilities due to less favorable
wholesale market conditions.
The electric utility's largest firm wholesale customer, Central Montana
Generation and Transmission Cooperative, has given a five-year notice of
contract termination, which will allow this customer to exercise wholesale
transmission access as eventually defined by the Federal Energy Regulatory
Commission. The customer is considering other possible power supply sources.
Discussions between the customer and the electric utility are continuing on
the matters of power supply and power transmission services.
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of electric revenues (excluding
intersegment revenues) and the related percentage changes in volumes sold and
prices received:
General business - revenue $ 6
- volume -
- price/kWh 4%
Other utilities - revenue $ (7)
- volume (10)%
- price/kWh (15)%
Miscellaneous - revenue $ (2)
<PAGE>
Revenues:
The increase in sales to general business customers of $6,000,000 was
largely due to 4% higher tariffs and customer growth in the residential and
commercial classes. While higher volumes were sold to residential and
commercial customers due to colder weather, industrial volumes declined as a
result of business interruptions at industrial sites, producing no change in
consumption for the period.
Favorable hydroelectric generation throughout the region reduced both
volumes and prices of sales to other utilities.
Miscellaneous revenues decreased $2,000,000 primarily due to a reduction
in wheeling revenue due to the weak wholesale market.
<PAGE>
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation and Maintenance) for
the six months ended June 30, 1995 and 1994.
<TABLE>
<CAPTION>
1995 1994
Sources MWH
<S> <C> <C>
Hydroelectric. . . . . . . . . . . . . . . . . . 1,620,423 1,778,415
Steam . . . . . . . . . . . . . . . . . . . . . 2,199,158 2,223,611
Purchases. . . . . . . . . . . . . . . . . . . . 1,360,426 1,313,879
Total Power Supply . . . . . . . . . . . . 5,180,007 5,315,905
Thousands of Dollars
Hydroelectric (including maintenance). . . . . . $ 9,265 $ 9,001
Steam (including fuel and maintenance) . . . . . 17,480 30,076
Purchases. . . . . . . . . . . . . . . . . . . . 41,487 42,715
Total Power Supply Expenses. . . . . . . . $ 68,232 $ 81,792
Cents Per Kilowatt-Hour. . . . . . . . . . 1.317 1.539
</TABLE>
While hydroelectric generation increased in the region the Utility's
hydroelectric generation was down due to an upstream Federal dam on the
Columbia River System reducing outflows. Hydroelectric expenses increased,
however, due to increases in rental payments.
Steam generation expenses decreased as a result of the coal arbitration
decision which reduced the price of coal sold by Entech's Western Energy
Company to Colstrip Unit Nos. 1 and 2. This price decrease was retroactive to
July 1991 and current period expenses include a $10,500,000 credit for coal
purchased in prior years. The electric utility benefited through a reduction
of power supply expense while Entech's earnings were reduced by an adjustment
to revenues. See Part II, Item 1., Legal Proceedings.
As a result of the availability of low cost wholesale hydroelectric
power in the region, increased MWH purchases displaced steam generation,
further reducing steam expenses.
For the remainder of 1995, as a result of increased streamflows
hydroelectric generation is expected to exceed 1994 levels. This additional
generation will reduce power purchase requirements and increase amounts
available for sale in the wholesale market. Prices in this market fluctuate
with the availability of surplus power and have a direct impact on the margins
received. For the remainder of 1995, the Company expects wholesale prices to
be lower than the second half of 1994. However, due to the reduced level of
purchases and increased volumes available for sale, power supply costs, net of
wholesale sales, should be lower when compared to the last six months of 1994.
Selling, general and administrative expenses decreased primarily due to
a reimbursement by insurers for Colstrip housing repair costs previously
expensed.
The increase in taxes other then income taxes is the result of
additional property taxes due to property additions and higher mill levies.
Natural Gas Utility:
Income from natural gas operations increased $1,600,000 principally due
to increased volumes sold resulting from 8% colder weather and customer growth
in the residential and commercial classes.
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of natural gas revenues (excluding
intersegment revenues and gas supply costs) and the related percentage changes
in volumes sold and prices received:
Full requirement customers -revenue $ 4
-volume 10%
-price/Mcf -
Transportation -revenue $ -
-volume 29%
-price/Mcf 7%
Miscellaneous -revenue $ -
Revenues:
Natural gas revenues (other than gas supply cost) increased $4,400,000
resulting from increased volumes sold due to colder weather and increases in
the number of residential and commercial customers.
Gas supply cost revenues consist of the amount authorized by the PSC to
be collected in rates from full requirement customers to cover the cost of
supplying the gas. The $2,400,000 increase in gas supply revenue resulted
from increased volumes sold and a refund made in 1994 for overcollection of
prior years' costs. Gas supply cost revenues and gas supply cost expenses are
always equal due to rate and accounting procedures.
Transportation volumes increased primarily as a result of additional
customer loads, a significant portion being gas stored for others. Because of
the Gas Transportation Adjustment Clause (GTAC), which passes through to full
requirement customers the difference between estimated interruptible
transportation (IT) revenues assumed for ratemaking purposes and actual IT
revenues, revenues will remain relatively unchanged.
Expenses:
The increase in gas supply costs resulted from the reasons mentioned in
the foregoing gas supply cost revenue discussion.
Interest Expense and Other Income:
The increase in other income principally resulted from the non-recurring
receipt of $1,600,000 in interest income from Entech due to the arbitration
decision. This amount was partially offset by a decrease in non-recurring
investment income in 1994.
<PAGE>
ENTECH OPERATIONS
<TABLE>
<CAPTION>
Six Months Ended
June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
COAL OPERATIONS:
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 102,111 $ 121,968
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 6,514 19,700
108,625 141,668
EXPENSES
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . 79,717 79,827
Selling, general and administrative . . . . . . . . . . . . . 14,564 14,075
Taxes other than income taxes . . . . . . . . . . . . . . . . 12,053 18,067
Depreciation, depletion and amortization. . . . . . . . . . . 6,247 6,449
112,581 118,418
INCOME FROM COAL OPERATIONS . . . . . . . . . . . . . . . . . (3,956) 23,250
OIL AND NATURAL GAS OPERATIONS:
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . 47,484 47,276
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 170 162
47,654 47,438
EXPENSES
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . 27,723 26,511
Selling, general and administrative . . . . . . . . . . . . . 4,550 4,268
Taxes other than income taxes . . . . . . . . . . . . . . . . 1,314 1,772
Depreciation, depletion and amortization. . . . . . . . . . . 9,232 9,370
42,819 41,921
INCOME FROM OIL AND NATURAL GAS OPERATIONS. . . . . . . . . . 4,835 5,517
OTHER OPERATIONS:
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . 12,472 11,141
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 335 361
12,807 11,502
EXPENSES
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . 8,242 7,855
Selling, general and administrative . . . . . . . . . . . . . 2,376 2,133
Taxes other than income taxes . . . . . . . . . . . . . . . . 163 143
Depreciation, depletion and amortization. . . . . . . . . . . 815 961
11,596 11,092
INCOME FROM OTHER OPERATIONS. . . . . . . . . . . . . . . . . 1,211 410
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,730 665
Other (income) deductions-net . . . . . . . . . . . . . . . . (1,595) (641)
1,135 24
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . 955 29,153
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . (3,857) 7,554
ENTECH NET INCOME . . . . . . . . . . . . . . . . . . . . . . . $ 4,812 $ 21,599
/TABLE
<PAGE>
ENTECH OPERATIONS:
Coal Operations:
Income from coal operations decreased $27,200,000, of which $14,200,000
pertains to the sales from July 1991 through December 1994, as a result of the
Colstrip Units Nos. 1 & 2 coal arbitration decision in March 1995. The
remainder of the decrease is primarily attributable to the expiration of a
Midwestern coal contract and operating losses at the Golden Eagle Mine caused
by production problems.
The Company's Golden Eagle Mine (Mine) incurred a loss of approximately
$7,800,000 in 1994. Through June 30, 1995, the Mine has incurred a loss of
approximately $7,200,000. Management expects the loss during the second half
of 1995 to be an additional $2,800,000. The production problems that were
encountered are being resolved and the second half of 1995 projections include
a significant increase in tons produced over the first half of 1995.
Revenues:
Revenues, including intersegment revenues, decreased primarily from
operations at the Rosebud Mine. Revenues from sales to Colstrip Units
Nos. 1 & 2 decreased $21,400,000, of which $19,000,000 was the result of the
Colstrip Units Nos. 1 & 2 arbitration decision in March 1995. This decision
reduced the sales price to Units Nos. 1 & 2 from July 1991 forward. A 13%
decrease in volumes sold was principally the result of the expiration of a
Midwestern contract at the end of 1994, which resulted in a $6,900,000
decrease in revenues. Revenues from sales to Colstrip Units Nos. 3 & 4 also
decreased $4,300,000 due to decreased generation caused by the increased
availability of hydroelectric generation in the region. Revenues decreased
$2,700,000 due to the conclusion of coal brokering agreements in December
1994. Coal sold under brokering agreements was sold at cost. At the Jewett
Mine, revenues increased $2,800,000 due to higher prices received as a result
of increased reimbursable mining expenses from stripping costs and maintenance
work. Golden Eagle Mine revenues decreased $2,200,000 as a result of lower
volumes available for sale due to production problems.
Expenses:
Cost of sales includes the net impact of $8,200,000 decreased mining
costs at the Rosebud Mine due to lower volumes sold and cost purchased for
brokering, offset by $5,500,000 increased operating costs at Golden Eagle Mine
plus $2,600,000 increased costs at the Jewett Mine due to the reasons
mentioned above. The impact of the recording of the arbitration decision
mentioned above reduced taxes other than income taxes by $6,000,000.
Oil and Natural Gas Operations:
Income from oil and natural gas operations decreased principally due to
lower natural gas prices, partially offset by increased volumes of marketed
natural gas and higher oil prices.
<PAGE>
The following table shows changes from the previous year, in millions of
dollars, in the various revenue classifications, with the related percentage
changes in volumes sold and prices received:
Oil -revenue $ 2
-volume (7)%
-price/bbl 32%
Natural gas -revenue $ (5)
-volume (3)%
-price/Mcf (29)%
Natural gas marketing -revenue $ 4
-volume 30%
-price/Mcf (7)%
Revenues:
Oil revenues increased $1,700,000 from higher market prices, while
natural gas revenues decreased $5,400,000 as a result of lower market prices.
Revenues from natural gas marketing increased $3,900,000 due to higher volumes
sold.
Expenses:
The higher volumes of natural gas purchased for resale increased the
cost of sales by $1,200,000.
Other Operations:
Income from other operations increased from telecommunications
operations and income from land sales.
Revenues:
Revenues from Entech's other operations increased $1,300,000 from
telecommunications operations resulting from additional circuits sold to
common carriers, equipment sales, and a 27% increase in minutes sold to long-
distance customers.
Interest Expense and Other Income:
The increase in interest expense of $1,600,000 was due to non-recurring
interest paid to the Utility Division pursuant to the arbitration decision
discussed above. Other income increased approximately $1,000,000 from the
sale of assets and from interest income earned in Canada.
Income Taxes:
Income taxes decreased $11,400,000 due to lower pre-tax net income from
coal operations.
<PAGE>
INDEPENDENT POWER GROUP OPERATIONS
<TABLE>
<CAPTION>
Six Months Ended
June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 39,307 $ 40,127
Earnings from unconsolidated investments. . . . . . . . . . . 1,608 1,454
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 616 1,133
41,531 42,714
EXPENSES:
Operation and maintenance . . . . . . . . . . . . . . . . . . 33,227 37,167
Selling, general and administrative . . . . . . . . . . . . . 1,372 1,961
Taxes other than income taxes . . . . . . . . . . . . . . . . 983 929
Depreciation and amortization . . . . . . . . . . . . . . . . 1,479 1,793
37,061 41,850
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . . . . 4,470 864
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . 6 10
Other (income) deductions - net . . . . . . . . . . . . . . . 232 (970)
238 (960)
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . 4,232 1,824
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . 1,877 972
IPG NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . $ 2,355 $ 852
</TABLE>
<PAGE>
INDEPENDENT POWER GROUP OPERATIONS:
The net income of the Independent Power Group (IPG) increased primarily
as a result of reductions in operation and maintenance expenses for the
Colstrip unit and a decrease in power project development expense. The
increase was partially offset by the writedown of an investment which is
expected to be sold before the end of the year.
During the last six months of 1994 earnings from IPG operations included
13 cents per share from successful power project developments and a gain on
the sale of a half interest in North American Energy Services Company. These
earnings will not recur in 1995.
Revenues:
Revenues of the IPG decreased principally due to a 6% decrease in
electric volumes sold to other utilities from the Colstrip unit along with a
6% decrease in volumes sold to the Company's electric utility. These volume
decreases resulted from a substantial increase in hydroelectric generation in
the region.
Expenses:
Operation and maintenance expenses decreased $3,900,000. The decrease
results primarily from a $1,800,000 decrease in scheduled maintenance expenses
associated with the Colstrip unit, an $800,000 decrease in fuel expenses and a
$1,200,000 decrease in funding of power project developments.
Interest Expense and Other Income:
Other deductions increased as a result of a $1,900,000 writedown of an
investment which is expected to be sold before the end of the year. This
increase was offset by a $700,000 increase in interest income.
<PAGE>
Three Months Ended June 30, 1995 and 1994:
Net Income Per Share of Common Stock
Consolidated net income for the quarter ended June 30, 1995, was
11 cents per share compared with 17 cents per share for the second quarter of
1994. The decrease was primarily the result of reduced earnings in Entech's
coal division. The previously mentioned coal sales reductions and production
problems at the Colorado mine decreased consolidated net income. The Entech
decrease was tempered by an increase in the Utility division's net income.
Lower wholesale prices reduced the utility's cost of providing electric power.
In addition, colder weather and customer growth resulted in increased natural
gas sales.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Three Months Ended
June 30,
1995 1994
Utility Operations $ 0.04 $ (0.01)
Entech 0.06 0.18
Independent Power Group 0.01 -
Consolidated $ 0.11 $ 0.17
<PAGE>
UTILITY OPERATIONS
<TABLE>
<CAPTION>
Three Months Ended
June 30,
1995 1994
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 84,625 $ 83,752
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 1,655 1,666
86,280 85,418
EXPENSES
Power supply. . . . . . . . . . . . . . . . . . . . . . . . . 32,885 35,701
Transmission and distribution . . . . . . . . . . . . . . . . 6,705 7,451
Selling, general and administrative . . . . . . . . . . . . . 9,334 11,296
Taxes other than income taxes . . . . . . . . . . . . . . . . 11,670 10,469
Depreciation and amortization . . . . . . . . . . . . . . . . 10,631 10,174
71,225 75,091
INCOME FROM ELECTRIC OPERATIONS . . . . . . . . . . . . . . . 15,055 10,327
NATURAL GAS UTILITY:
REVENUES
Revenues (other than gas supply
cost revenues). . . . . . . . . . . . . . . . . . . . . . . 17,194 15,279
Gas supply cost revenues. . . . . . . . . . . . . . . . . . . 4,488 3,422
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 187 196
21,869 18,897
EXPENSES
Gas supply costs. . . . . . . . . . . . . . . . . . . . . . . 4,488 3,422
Other production, gathering and exploration . . . . . . . . . 2,583 2,245
Transmission and distribution . . . . . . . . . . . . . . . . 2,930 2,538
Selling, general and administrative . . . . . . . . . . . . . 4,612 4,671
Taxes other than income taxes . . . . . . . . . . . . . . . . 3,728 3,279
Depreciation, depletion and amortization. . . . . . . . . . . 2,574 2,340
20,915 18,495
INCOME FROM GAS OPERATIONS. . . . . . . . . . . . . . . . . . 954 402
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . 10,804 10,496
Other (income) deductions - net . . . . . . . . . . . . . . . (765) (1,349)
10,039 9,147
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . 5,970 1,582
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . 2,202 420
UTILITY NET INCOME. . . . . . . . . . . . . . . . . . . . . . . $ 3,768 $ 1,162
/TABLE
<PAGE>
UTILITY OPERATIONS:
Weather can significantly affect revenues and net income, and should be
considered when analyzing trends. As measured by heating degree days, the
weather for second quarter of 1995 in the Company's service territory was 31%
colder than the same period last year.
The Company's electric wholesale revenues and power purchase expenses
are influenced by the situation in the region, as presented in the six months
ended discussion.
Electric Utility:
Income from electric operations increased $4,700,000 largely as a result
of reduced power supply expense as steam generation was curtailed due to
opportunity purchases arising from low cost hydroelectric energy available in
the region.
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of electric revenues (excluding
intersegment revenues) and the related percentage changes in volumes sold and
prices received:
General business - revenue $ 3
- volume (1)%
- price/kWh 5 %
Other utilities - revenue $ (1)
- volume (13)%
- price/kWh (1)%
Miscellaneous - revenue $ (1)
Revenues:
Electric sales to general business customers increased $2,700,000
largely due to higher tariffs and customer growth in the residential and
commercial classes. While residential volumes increased due to additional
customers, commercial and industrial volumes declined as a result of reduced
irrigation and air conditioning loads and industrial business interruptions,
producing a net decrease in consumption.
Electric revenues from sales to other utilities decreased $1,100,000
primarily due to reduced volumes sold due to the weak wholesale market
conditions which resulted from increased availability of low-cost energy in
the region. These conditions also reduced miscellaneous wheeling revenues by
$800,000.
<PAGE>
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (Operation, Fuel for electric generation and Maintenance) for
the three months ended June 30, 1995 and 1994.
<TABLE>
<CAPTION>
1995 1994
Sources MWH
<S> <C> <C>
Hydroelectric. . . . . . . . . . . . . . . . . . 878,999 881,739
Steam . . . . . . . . . . . . . . . . . . . . . 849,083 932,789
Purchases. . . . . . . . . . . . . . . . . . . . 567,894 499,535
Total Power Supply . . . . . . . . . . . . 2,295,976 2,314,063
Thousands of Dollars
Hydroelectric (including maintenance). . . . . . $ 4,712 $ 4,604
Steam (including fuel and maintenance) . . . . . 13,663 15,280
Purchases. . . . . . . . . . . . . . . . . . . . 14,510 15,817
Total Power Supply Expenses. . . . . . . . $ 32,885 $ 35,701
Cents Per Kilowatt-Hour. . . . . . . . . . 1.432 1.543
</TABLE>
As a result of the availability of low cost wholesale hydroelectric
power in the region, increased MWH purchases displaced steam generation,
decreasing steam expenses.
Selling, general and administrative expenses decreased primarily due to
a reimbursement by insurers for Colstrip housing repair costs previously
expensed.
The increase in taxes other than income taxes is the result of
additional property taxes due to property additions and higher mill levies.
Natural Gas Utility:
Income from natural gas operations increased $500,000 principally due to
increased volumes sold resulting from 31% colder weather and customer growth
in the residential and commercial classes.
The following table shows the change from the previous year, in millions
of dollars, in the various classifications of natural gas revenues (excluding
intersegment revenues and gas supply costs) and the related percentage changes
in volumes sold and prices received:
Full requirement customers -revenue $ 2
-volume 16%
-price/Mcf -
Transportation -revenue $ -
-volume 26%
-price/Mcf 8%
Miscellaneous -revenue $ -
<PAGE>
Revenues:
Natural gas revenues (other than gas supply cost) increased $2,000,000
principally the result of increases in volumes sold due to colder weather and
residential and commercial customer growth.
Gas supply cost revenues consist of the amount authorized by the PSC to
be collected in rates from full requirement customers to cover the cost of
supplying the gas. The $1,000,000 increase in gas supply revenue resulted
from increased volumes sold and a refund made in 1994 for overcollection of
prior years' costs. Gas supply cost revenues and gas supply cost expenses are
always equal due to rate and accounting procedures.
Transportation volumes increased primarily as a result of additional
customer loads, a significant portion being gas stored for others. Because of
the Gas Transportation Adjustment Clause (GTAC), which passes through to full
requirement customers the difference between estimated interruptible
transportation (IT) revenues assumed for ratemaking purposes and actual IT
revenues, revenues will remain relatively unchanged.
Expenses:
The increase in gas supply costs resulted from the reasons mentioned in
the foregoing gas supply cost revenue discussion.
Interest Expense and Other Income:
Other income decreased $500,000 due primarily to non-recurring
investment income in 1994.
<PAGE>
ENTECH OPERATIONS
<TABLE>
<CAPTION>
Three Months Ended
June 30,
1995 1994
Thousands of Dollars
COAL OPERATIONS:
<S> <C> <C>
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 49,008 $ 56,275
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 6,216 8,173
55,224 64,448
EXPENSES
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . 39,277 38,487
Selling, general and administrative . . . . . . . . . . . . . 6,749 6,479
Taxes other than income taxes . . . . . . . . . . . . . . . . 6,513 7,567
Depreciation, depletion and amortization. . . . . . . . . . . 2,504 2,935
55,043 55,468
INCOME FROM COAL OPERATIONS . . . . . . . . . . . . . . . . . 181 8,980
OIL AND NATURAL GAS OPERATIONS:
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . 24,209 21,072
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 38 77
24,247 21,149
EXPENSES
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . 14,862 10,710
Selling, general and administrative . . . . . . . . . . . . . 2,308 2,064
Taxes other than income taxes . . . . . . . . . . . . . . . . 684 872
Depreciation, depletion and amortization. . . . . . . . . . . 4,744 4,774
22,598 18,420
INCOME FROM OIL AND NATURAL GAS OPERATIONS. . . . . . . . . . 1,649 2,729
OTHER OPERATIONS:
REVENUES
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . 6,092 5,609
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 191 173
6,283 5,782
EXPENSES
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . 3,886 3,643
Selling, general and administrative . . . . . . . . . . . . . 1,105 1,150
Taxes other than income taxes . . . . . . . . . . . . . . . . 82 71
Depreciation, depletion and amortization. . . . . . . . . . . 412 487
5,485 5,351
INCOME FROM OTHER OPERATIONS. . . . . . . . . . . . . . . . . 798 431
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . 382 349
Other (income) deductions-net . . . . . . . . . . . . . . . . (368) (1,199)
14 (850)
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . 2,614 12,990
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . (529) 3,218
ENTECH NET INCOME . . . . . . . . . . . . . . . . . . . . . . . $ 3,143 $ 9,772
</TABLE>
<PAGE>
ENTECH OPERATIONS:
Coal Operations:
Income from coal operations decreased $8,800,000, as a result of reduced
revenues and coal volumes sold at the Rosebud Mine, and operating losses at
the Golden Eagle Mine.
Revenues:
Revenues, including intersegment revenues, decreased with the majority
attributable to the Rosebud Mine, where volumes of coal sold to customers
decreased by 22%. Revenues from sales to Colstrip Units Nos. 3 & 4 decreased
$3,500,000 due to decreased generation caused by the increased availability of
hydroelectric generation in the region. Revenues decreased $3,200,000 as a
result of the expiration of a Midwestern contract at the end of 1994.
Revenues also decreased $1,400,000 due to the conclusion of coal brokering
agreements in December 1994, and decreased $1,000,000 due to lower volumes
sold to Corette while the plant tested other coal for air quality compliance.
Coal sold under brokering agreements was sold at cost. At the Jewett Mine,
revenues increased $1,700,000 for the same reasons mentioned in the six-month
discussion.
Expenses:
Cost of sales includes the net impact of $4,300,000 decreased mining
costs at the Rosebud Mine primarily due to lower volumes sold and coal
purchased for brokering, offset by $3,400,000 increased operating costs at
Golden Eagle Mine plus $1,700,000 increased costs at the Jewett Mine due to
the reasons mentioned in the six-month discussion. Taxes other than income
taxes decreased $1,000,000 due to lower volumes sold at the Rosebud Mine.
Oil and Natural Gas Operations:
Income from oil and natural gas operations decreased principally due to
lower natural gas prices, partially offset by increased volumes of marketed
natural gas and higher oil prices.
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenues with the related
percentage changes in volumes sold and prices received:
Oil -revenue $ 1
-volume (9)%
-price/bbl 26%
Natural gas -revenue $ (3)
-volume (8)%
-price/Mcf (28)%
Natural gas marketing -revenue $ 5
-volume 49%
-price/Mcf 19%
<PAGE>
Revenues:
Oil revenues increased $600,000 from higher market prices, while natural
gas revenues decreased $2,800,000 as a result of lower market prices.
Revenues from natural gas marketing increased $5,200,000 due to higher volumes
sold and higher prices received under cogeneration supply agreements.
Expenses:
The higher volumes of natural gas purchased for resale increased the
cost of sales by $4,100,000.
Other Operations:
Income from other operations increased due to telecommunications
operations and income from land sales.
Revenues:
Revenues from Entech's other operations increased $500,000 from
telecommunications operations for the same reasons mentioned in the six-month
discussion.
Interest Expense and Other Income:
Other income decreased approximately $800,000 as a result of less income
received from Entech's investment in a Brazilian gold mine in 1995.
Income Taxes:
Income taxes decreased $3,700,000 due to lower pre-tax net income from
coal operations.
<PAGE>
INDEPENDENT POWER GROUP OPERATIONS
<TABLE>
<CAPTION>
Three Months Ended
June 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES:
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 19,287 $ 19,171
Earnings from unconsolidated investments. . . . . . . . . . . 428 693
Intersegment revenues . . . . . . . . . . . . . . . . . . . . 280 876
19,995 20,740
EXPENSES:
Operation and maintenance . . . . . . . . . . . . . . . . . . 15,950 19,105
Selling, general and administrative . . . . . . . . . . . . . 559 1,334
Taxes other than income taxes . . . . . . . . . . . . . . . . 463 496
Depreciation and amortization . . . . . . . . . . . . . . . . 740 710
17,712 21,645
INCOME FROM OPERATIONS. . . . . . . . . . . . . . . . . . . . 2,283 (905)
INTEREST EXPENSE AND OTHER INCOME:
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . 5 4
Other (income) deductions - net . . . . . . . . . . . . . . . 986 (522)
991 (518)
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . 1,292 (387)
INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . 633 (162)
IPG NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . $ 659 $ (225)
</TABLE>
<PAGE>
INDEPENDENT POWER GROUP OPERATIONS:
IPG net income for the quarter increased primarily as a result of
decreases in operation and maintenance expenses for the Colstrip unit offset
by the writedown of an investment.
Revenues:
Revenues of the IPG decreased principally due to a reduction in electric
volumes sold to the Company's electric utility from the Colstrip unit. This
reduction in volume results primarily from a decrease in generation at the
Colstrip unit.
Expenses:
Operation and maintenance expense decreased $3,200,000. The decrease
results primarily from a $1,800,000 decrease in scheduled maintenance expenses
associated with the Colstrip unit, a $600,000 decrease in fuel expenses and a
$400,000 decrease in transmission expenses due to a contract renegotiation.
Interest Expense and Other Income:
Other deductions increased as a result of a $1,900,000 writedown of an
investment which is expected to be sold before the end of the year. This
increase was offset by a $300,000 increase in interest income.
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements, long-term debt maturities and
sources of funds for the period 1995-1999 have been discussed in the Company's
Annual Report on Form 10-K for the year ended December 31, 1994. Since that
report was issued, the Utility's capital expenditures for the period 1995-1999
have been reduced by approximately 28%, from $716,000,000 to $516,000,000.
During the first six months of 1995, $60,066,000 was expended for the Utility
construction program and $53,107,000 was expended for Entech capital
expenditures.
In April 1995, the Company sold $20,000,000 of Secured Medium-Term
Notes, 7.33% series due 2025, the proceeds of which were used to finance
construction and repay short-term debt.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. At June 30, 1995, the
unfunded net property additions and retired bonds test, which is the most
restrictive test, would have permitted the issuance of approximately
$524,000,000 additional First Mortgage Bonds. There are no material
restrictions upon issuance of unsecured debt or preferred stock in the
Company's Restated Articles of Incorporation, its Mortgage and Deed of Trust
or its Sinking Fund Debenture Agreement.
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended June 30, 1995, the Company's ratio of
earnings to fixed charges was 2.89 times. Fixed charges include interest, the
implicit interest of the Colstrip Unit No. 4 rentals and one-third of all
other rental payments.
NEW ACCOUNTING PRONOUNCEMENTS
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). This statement, which is effective for 1996 financial statements,
requires that an asset be reviewed for impairment whenever events indicate
that the carrying value of the asset may not be recoverable and whenever a
regulator excludes a portion of an asset's cost from a company's rate base.
The Company is evaluating SFAS No. 121. The impact it may have on its
financial position or results of operations has not been determined.
UTILITY INDUSTRY CHANGES
On March 29, 1995, FERC issued a Notice of Proposed Rulemaking (NOPR) on
Open-Access Non-Discriminatory Transmission Services by Public and
Transmitting Utilities and a supplemental NOPR on Recovery of Stranded Costs.
The NOPR would require utilities owning transmission lines to file
non-discriminatory rates available to all buyers and sellers of electricity,
require utilities to use that tariff for their own wholesale sales and
purchases, and allow utilities to recover stranded costs.
<PAGE>
The Company's Electric Utility continues to analyze how it might be
affected by the proposal. Comments on the NOPR were due on August 7, 1995.
The Utility submitted comments which generally supported the concepts
contained in the NOPR but suggested some modifications to the transmission
tariffs. It is anticipated that a final rule could take effect in early 1996.
The Company cannot predict the outcome of this matter.
<PAGE>
PART II
Other Information
ITEM 1. Legal Proceedings
Colstrip Unit Nos. 1 & 2 Coal Arbitration Decision
A pricing dispute between Western Energy Company (Western), a subsidiary
of the Company, and Puget Sound Power & Light Company (Puget) regarding the
Coal Supply Agreement for Colstrip Unit Nos. 1 and 2 between Puget and the
Company's Utility Division, as co-owners of the units, and Western, as coal
supplier, has been resolved through arbitration. See Annual Report on Form
10-K for 1994, Note 2 to the Consolidated Financial Statements.
On March 24, 1995, the Company received the arbitration decision.
Excluding production taxes and royalties, the contract price was reduced
approximately $1.20 per ton. As a result, the Company's consolidated pre-tax
income will decrease approximately $6,000,000 on coal sold to Puget since July
1991. The Company does not expect a significant cash flow impact to result
from the arbitration decision, because Puget paid less than invoiced amounts
for coal delivered after April 1992. In March 1995, Western refunded
approximately $10,500,000, plus interest, on coal sold to the Company's
Utility Division since July 1991. This refund did not affect consolidated
income. On an annual basis, the redetermined contract price is estimated to
result in a pre-tax reduction of consolidated income of approximately
$3,500,000 per year.
Colstrip Unit Nos. 3 & 4 Coal Arbitration
Reference Note 1, page 8 for further discussion of this matter.
Frederickson Litigation
Through one of its IPG subsidiaries which owns 25% of a power
development partnership, the Company is participating in litigation filed in
federal court against the Bonneville Power Administration (BPA). The suit,
filed by the power development partnership, alleges the BPA abrogated a 20-
year power purchase contract with the partnership and seeks payment of
slightly more than $1,000,000,000 in damages. The BPA has stated that changed
circumstances in the power market and in its environmental obligations,
occurring since the power purchase contract was signed in 1994, have
frustrated the purposes of the power purchase contract. BPA alleges these
changed circumstances excuse it from the contractual obligation to purchase
power from the 248 megawatt generation plant at Frederickson, Washington.
Construction was expected to be complete and the plant operational in 1996,
however, pending resolution of this matter, construction has been suspended.
BPA has publicly acknowledged responsibility to pay some measure of damages
resulting from its decision. The partnership, which includes the IPG's
subsidiary, is pursuing this litigation aggressively.
Notice of Intent by Puget Sound Power and Light
Reference Note 1, page 8 for further discussion of this matter.
<PAGE>
ITEM 4. Submission of Matters to a Vote of Security Holders.
A. The Company's Annual Meeting of Shareholders was held on May 9,
1995.
B. Security holders elected four persons to the Board of Directors.
<TABLE>
<CAPTION>
Director For Withheld Abstentions
<S> <C> <C> <C>
R. D. Corette 47,232,740 250 853,296
Beverly D. Harris 47,257,190 250 801,041
Arthur K. Neill 47,159,617 926,419
Noble E. Vosburg 47,257,373 250 800,858
</TABLE>
Directors whose term of office as a director continued after the
meeting are as follows:
Daniel T. Berube Daniel P. Lambros
Allen F. Cain Carl Lehrkind III
Kay Foster James P. Lucas
Robert P. Gannon Jerrold P. Pederson
Chase T. Hibbard George H. Selover
C. Security holders voted to adopt the amendment to the restated
Articles of Incorporation which requires the affirmative vote of
two-thirds of the outstanding shares of the Company in order to
change the current staggered board structure or the number of
directors.
For Against Abstentions
37,635,330 5,941,380 1,070,538
<PAGE>
ITEM 6. Exhibits and Reports on Form 8-K:
(a) Exhibits
Exhibit 12 Computation of ratio of earnings to fixed
charges for the twelve months ended
June 30, 1995.
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K
DATE SUBJECT
April 26, 1995 Item 5 Other Events. Discussion of First
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements
of Income for the Quarters Ended March 31,
1995 and 1994 and for the Twelve Months
Ended March 31, 1995 and 1994, Utility
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1995 and 1994 and for the Twelve Months
Ended March 31, 1995 and 1994, Entech
Operations Schedule of Revenues and
Expenses for the Quarters Ended March 31,
1995 and 1994 and for the Twelve Months
Ended March 31, 1995 and 1994 and
Independent Power Group Operations
Schedule of Revenues and Expenses for the
Quarters Ended March 31, 1995 and 1994 and
for the Twelve Months Ended March 31, 1995
and 1994.
<PAGE>
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.
THE MONTANA POWER COMPANY
(Registrant)
/s/ J.P. Pederson
J. P. Pederson
Vice President and Chief
Financial Officer
Date: August 14, 1995
<PAGE>
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended June 30, 1995
Exhibit 27
Financial Data Schedule
<PAGE>
EXHIBIT 12
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
June 30,1995
------------------
Net Income $109,340
Income Taxes 48,825
----------
$158,165
----------
Fixed Charges:
Interest $ 45,791
Amortization of Debt Discount,
Expense and Premium 1,630
Rentals 36,076
----------
$ 83,497
----------
Earnings Before Income Taxes
and Fixed Charges $241,662
==========
Ratio of Earnings to Fixed Charges 2.89X
==========
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AT 6/30/95, THE CONSOLIDATED INCOME STATEMENT AND
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE 6 MONTHS ENDED 6/30/95 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> JUN-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,475,904
<OTHER-PROPERTY-AND-INVEST> 511,708
<TOTAL-CURRENT-ASSETS> 226,955
<TOTAL-DEFERRED-CHARGES> 275,992
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,490,559
<COMMON> 678,458
<CAPITAL-SURPLUS-PAID-IN> 2,380
<RETAINED-EARNINGS> 283,012
<TOTAL-COMMON-STOCKHOLDERS-EQ> 963,850
0
101,416
<LONG-TERM-DEBT-NET> 599,739
<SHORT-TERM-NOTES> 63,196
<LONG-TERM-NOTES-PAYABLE> 8,430
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 16,265
0
<CAPITAL-LEASE-OBLIGATIONS> 190
<LEASES-CURRENT> 765
<OTHER-ITEMS-CAPITAL-AND-LIAB> 736,708
<TOT-CAPITALIZATION-AND-LIAB> 2,490,559
<GROSS-OPERATING-REVENUE> 467,805
<INCOME-TAX-EXPENSE> 19,582
<OTHER-OPERATING-EXPENSES> 385,899
<TOTAL-OPERATING-EXPENSES> 405,481
<OPERATING-INCOME-LOSS> 62,324
<OTHER-INCOME-NET> 1,325
<INCOME-BEFORE-INTEREST-EXPEN> 63,649
<TOTAL-INTEREST-EXPENSE> 21,747
<NET-INCOME> 41,902
3,614
<EARNINGS-AVAILABLE-FOR-COMM> 38,288
<COMMON-STOCK-DIVIDENDS> 42,981
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 135,024
<EPS-PRIMARY> 0.71
<EPS-DILUTED> 0.71
</TABLE>
