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 March 31, 1996
-- 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 May 6, 1996, the Company had 54,632,075 shares of common stock
outstanding.
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
For Three Months Ended
March 31, March 31,
1996 1995
Thousands of Dollars
<S> <C> <C>
REVENUES $ 264,405 $ 262,297
EXPENSES:
Operations 109,470 113,803
Maintenance 11,654 15,340
Selling, general and administrative 24,484 27,536
Taxes other than income taxes 22,680 21,920
Depreciation, depletion and amortization 20,755 22,693
189,043 201,292
INCOME FROM OPERATIONS 75,362 61,005
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,986 10,955
Other (income) deductions-net (741) (1,558)
11,245 9,397
INCOME TAXES 23,802 17,276
NET INCOME 40,315 34,332
DIVIDENDS ON PREFERRED STOCK 1,807 1,807
NET INCOME AVAILABLE FOR COMMON STOCK $ 38,508 $ 32,525
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,639 53,738
NET INCOME PER SHARE OF COMMON STOCK $ 0.70 $ 0.61
The accompanying notes are an integral part of these statements.
</TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
A S S E T S
March 31, December 31,
1996 1995
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $57,891 and $57,095
plant under construction)
Electric $ 1,724,931 $ 1,713,133
Natural gas 492,133 492,431
2,217,064 2,205,564
Less - accumulated depreciation and depletion 677,257 663,215
1,539,807 1,542,349
ENTECH PROPERTY (includes $15,147 and $12,716
property under construction) 565,922 559,722
Less - accumulated depreciation and depletion 235,672 232,947
330,250 326,775
INDEPENDENT POWER GROUP PROPERTY (includes $3,260 and
$3,171 property under construction) 72,282 72,179
Less - accumulated depreciation 20,219 19,666
52,063 52,513
1,922,120 1,921,637
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 57,757 57,013
Other 47,686 46,966
105,443 103,979
CURRENT ASSETS:
Cash and temporary cash investments 16,013 15,541
Accounts receivable 131,547 152,386
Materials and supplies (principally at average cost) 42,087 42,194
Prepayments and other assets 68,057 62,071
257,704 272,192
DEFERRED CHARGES:
Advanced coal royalties 20,081 20,175
Regulatory assets related to income taxes 148,358 148,350
Regulatory assets - other 68,517 68,637
Other deferred charges 52,707 51,121
289,663 288,283
$ 2,574,930 $ 2,586,091
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
March 31, December 31,
1996 1995
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,632,075 and
54,614,481 shares issued) $ 691,930 $ 691,043
Retained earnings and other shareholders' equity 301,700 285,000
Unallocated stock held by trustee for deferred
savings and employee stock ownership plan (30,033) (30,565)
963,597 945,478
Preferred stock 101,416 101,416
Long-term debt 606,402 616,574
1,671,415 1,663,468
CURRENT LIABILITIES:
Short-term borrowing 49,812 96,348
Long-term debt - portion due within one year 24,234 24,804
Dividends payable 23,659 23,668
Income taxes 30,689 9,937
Other taxes 56,898 43,302
Accounts payable 53,326 63,920
Interest accrued 14,058 12,341
Accrued lease payments 7,920
Other current liabilities 56,643 63,488
317,239 337,808
DEFERRED CREDITS:
Deferred income taxes 323,065 320,736
Investment tax credit 46,565 47,001
Accrued mining reclamation costs 123,177 122,008
Other deferred credits 93,469 95,070
586,276 584,815
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,574,930 $ 2,586,091
</TABLE>
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
For the Three Months Ended
March 31, March 31,
1996 1995
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 40,315 $ 34,332
Noncash charges (credits) to net income:
Depreciation and depletion 20,755 22,693
Mining reclamation costs expensed 3,777 4,381
Deferred income taxes. 1,933 3,701
Amortization of loss on long-term sales
of power (572) (816)
Other - net 2,993 2,663
Changes in other assets and liabilities 26,502 43,622
Accounts receivable 20,839 31,973
Materials and supplies 107 286
Accounts payable (10,594) (5,480)
Payment of mining reclamation costs (2,608) (2,331)
Net Cash Flows from Operating Activities 103,447 135,024
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (21,940) (46,865)
Sales of property (126) 3,609
Additional investments (711) (562)
Net Cash Flows from Investing Activities (22,777) (43,818)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock 832 5,643
Issuance of long-term debt 96
Retirement of long-term debt (10,805) (449)
Short-term debt (46,536) (80,897)
Dividends on common and preferred stock (23,689) (23,249)
Net Cash Flows from Financing Activities (80,198) (98,856)
Change in Cash Flows 472 (7,650)
Cash and cash equivalents at beginning of period 15,541 21,564
Cash and cash equivalents at end of period $ 16,013 $ 13,914
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Three Months For:
Income taxes $ 1,117 $ 6
Interest 10,547 9,991
The accompanying notes are an integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying financial statements of the Company for the interim
periods ended March 31, 1996 and 1995 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, 1995.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1996 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1. CONTINGENCIES AND COMMITMENTS:
In 1990, pursuant to a Federal Energy Regulatory Commission (FERC)
license obligation, the Company proposed a plan to protect fish and wildlife
habitat affected by the operation of the Kerr hydroelectric project, which
would cost the Company $15,500,000 initially and, thereafter, $1,000,000
annually. FERC and the Department of the Interior have proposed alternatives
which would cost $48,000,000 initially and, thereafter, $1,300,000 annually
and would require baseload as opposed to load following operation.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. The total cost of relicensing, including physical improvements, is
estimated at $151,000,000. In addition, operating changes associated with
environmental protection are expected to decrease project capability by 26
megawatts.
The Company has brought an action against Puget Sound Power & Light
Company (Puget) in the Federal District Court for the Western District of
Montana seeking a determination that the Company is in compliance with an
agreement to sell Puget 94 megawatts of power annually to the year 2010. This
action arose out of an allegation by Puget that the Company had breached the
agreement by failing to provide a firm transmission path for the power,
thereby entitling Puget to terminate the agreement. The Company and Puget
have agreed that, should it be determined that Puget is entitled to terminate
the agreement, the Company would reimburse Puget for the excess, if any, of
the cost of power purchased under the agreement after February 1995, over the
cost which Puget may demonstrate it would have paid for such power elsewhere.
Also, the Company would be obligated to reimburse Puget for approximately
$40,000,000, excluding interest, the amount by which Puget's payments through
February 1995 have exceeded its projected avoided cost. In addition, the
Company's future revenues would be reduced by the difference, if any, between
sales at prices under the agreement, approximately $30,000,000 per year, and
prices it might receive from alternative sales. In accordance with SFAS
No. 121, the Company would be required to write down assets related to the
agreement by approximately $25,000,000, before taxes. The Company believes
that Puget's intention is to reduce its purchase power costs, since the price
of power under the agreement is in excess of current market rates. While
confident of its position, the Company cannot be certain of the decision in
this proceeding, which is expected in 1997.
Western Energy Company (Western) was a party in an arbitration initiated
by the non-operating owners of the Colstrip Units 3 and 4 (i.e., Puget,
Washington Water Power Company, Portland General Electric Company and
PacifiCorp -- collectively, the "Buyers") to resolve a variety of disputes
arising under the contracts with Western for the supply and transportation of
coal for these Units. The principal issues were the amounts of and prices for
coal that the Buyers are obligated to purchase in excess of 600,000 tons
monthly, 6,000,000 tons yearly and 170,000,000 tons over the lives of the
contracts, Western's obligation to mine in a manner dictated by the Buyers,
and Western's obligation to place reclamation funds received in a trust
account.
The arbitrator's decision was favorable to Western with respect to the
amounts and prices for coal that the Colstrip owners are obligated to
purchase, indicating that the Buyers must purchase the Units' requirements
from Western at prices and under terms stated in the contracts. The decision
affirms Western's mine plan and interpretation of its mining obligations and
does not assess damages against Western for not adopting mine plan changes
suggested by the Buyers. The decision does, however, obligate Western to
initiate a permit application seeking mine plan changes regarding the mining
sequence which the Buyers may propose and to exercise good faith in supporting
the application. If the mine plan sequence changes are permitted, Western must
bear the Buyers' cost incurred in developing, proposing and advocating for the
sequence changes. The decision also requires the deposit of $42,000,000 of
mine reclamation funds to an interest-bearing bank account. Previously, the
arbitrator had dismissed the non-operating owners' claims for refunds of
certain coal transportation charges. The decision will not materially affect
Western Energy's financial position or results of operations.
Continental Energy Services, Inc., a wholly-owned subsidiary of the
Company, is a general partner in a partnership (the Partnership) formed to
construct and own a 248 megawatt Tenaska power plant at Frederickson,
Washington. The Partnership contracted in 1994 to sell the output of this
plant to the Bonneville Power Administration (BPA) over a 20-year period. In
May of 1995, BPA informed the Partnership that it would not purchase the
power. BPA alleged that decreases in demand for power and increasing
constraints in protection of endangered species have frustrated its purposes
for entering into the power purchase contract and, consequently, have excused
it from performance. The Partnership halted construction of the plant and
sued BPA, seeking damages, including lost future profits. This matter has
been referred to binding arbitration by the United States Court of Federal
Claims. The Company does not believe this dispute will adversely affect its
consolidated financial position or its consolidated results of operation.
The Company and its subsidiaries are party to various other legal
claims, actions and complaints arising in the ordinary course of business.
Management does not expect disposition of these matters to have a material
adverse effect on the Company's consolidated financial position or its
consolidated results of operations.
The Entech Oil Division has agreed to supply 118 Bcf of natural gas to
four co-generation facilities through mid-2011. The Oil Division has proven,
developed and undeveloped reserves sufficient to supply all of the remaining
natural gas required by these agreements.
NOTE 2. RATE MATTERS:
In September 1995, the Company requested the Montana Public Service
Commission (PSC) to authorize an increase in both electric and natural gas
rates. Effective March 1, 1996 the PSC granted interim increases of $5,800,000
for electricity and $3,100,000 for natural gas. The Company, the Montana
Consumer Counsel and the Large Customer Group (the parties) reached a
settlement on an alternative rate plan for the Electric Utility, which would
increase revenues 4.2 percent or $14,800,00 on July 1, 1996 (including the
interim increase), 2.4 percent or approximately $8,800,000 on January 1, 1997
and 2.4 percent or approximately $9,000,000 on January 1, 1998, based on an 11
percent return on common equity. Earnings in excess of an 11.4 percent return
on common equity would be shared on a 50 percent basis between ratepayers and
shareholders.
The Company, with the agreement of the parties, requested an accounting
order from the PSC which would permit it, subject to approval of the Internal
Revenue Service, to flow through additional amounts of Accumulated Deferred
Investment Tax Credit (ADITC) to shareholders in the event that its electric
year-end return on equity, when calculated on a regulated basis, falls below
10.20 percent. The amount of ADITC to be flowed through would be limited to
$7,000,000.
The parties did not agree on an alternative rate plan for the Gas
Utility. They agreed natural gas revenues should increase by $6,700,000 on
July 1, 1996 (including the interim increase), based on an 11.25 percent
return on equity. The Company has committed to file a natural gas general and
allocated cost of service rate design case in the third quarter of 1996. The
11.25 percent equity return will not be contested in that proceeding by the
parties to the agreement.
The settlement was heard by the PSC in April. On May 13, 1996, the PSC
instructed their staff to draft a final order approving the settlement.
NOTE 3. FINANCIAL INSTRUMENTS:
To manage price risk, Entech uses swap and collar agreements to hedge
revenue from anticipated production and sales of oil and natural gas. Under
swap agreements, Entech receives or makes payments based on the differential
between a specified price and the market price of oil or natural gas when the
hedged production is sold. Under collar agreements, Entech makes or receives
monthly payments when the actual price of oil exceeds the ceiling or drops
below the floor established in the agreement. At March 31, 1996, Entech had
swap agreements to hedge approximately 323,000 barrels of oil, or 50%, of its
expected production through November 1996. In addition, Entech had swap
agreements to hedge approximately 2 Bcf of natural gas, or 28 percent, of its
delivery obligations under long-term natural gas sales contracts through
February 1997. At March 31, 1996, the Company had no material deferred gains
or losses from these transactions.
The 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. The Company believes it will not experience any materially
adverse impacts from the risks inherent in these instruments.
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, 1995.
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.
Quarter Ended March 31, 1996 and 1995:
Net Income Per Share of Common Stock:
Net income for the quarter ended March 31, 1996 was 70 cents per share,
compared with 61 cents per share for the first quarter 1995. The nine cent
increase is primarily due to nonrecurring charges recorded in the first
quarter of 1995. A coal contract arbitration decision decreased Entech's
earnings by 18 cents per share, but benefited Utility earnings by 13 cents
through a retroactive adjustment to power supply costs. In addition, Entech's
Colorado coal mine, which had sustained operating losses of six cents per
share during last year's first quarter, has been closed and was written down
to net salvage value effective October 1995.
Colder weather, increased hydroelectric generation and 2.6 percent
customer growth contributed to higher Utility earnings. An abundance of
hydroelectric generation in the region permitted the Company to substitute
this lower cost energy for higher cost steam generation. While benefiting the
Utility and the Independent Power Group (IPG), this substitution reduces
Entech's earnings when generation at the Colstrip units is cut back. A
Midwestern coal contract, that expired in December 1995, also reduced Entech's
earnings.
During the first quarter, the IPG continued its earnings growth from
investments in operating projects.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Quarter Ended
March 31, March 31,
1996 1995
Utility Operations $ 0.50 $ 0.55
Entech 0.15 0.03
Independent Power Group 0.05 0.03
Consolidated $ 0.70 $ 0.61
UTILITY OPERATIONS
<TABLE>
<CAPTION>
For Three Months Ended
March 31, March 31,
1996 1995
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES:
Revenues $ 119,887 $ 117,184
Intersegment revenues 2,028 1,573
121,915 118,757
EXPENSES:
Power supply 41,746 35,347
Transmission and distribution 7,459 6,428
Selling, general and administrative 11,313 12,048
Taxes other than income taxes 11,938 11,605
Depreciation and amortization 11,547 10,621
84,003 76,049
INCOME FROM ELECTRIC OPERATIONS 37,912 42,708
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 37,888 32,099
Gas supply cost revenues 10,076 8,898
Intersegment revenues 207 351
48,171 41,348
EXPENSES:
Gas supply costs 10,076 8,898
Other production, gathering and exploration 2,366 2,611
Transmission and distribution 3,070 2,581
Selling, general and administrative 4,348 4,388
Taxes other than income taxes 4,012 3,545
Depreciation, depletion and amortization 2,931 2,699
26,803 24,722
INCOME FROM GAS OPERATIONS 21,368 16,626
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,740 11,094
Other (income) deductions - net (495) (2,087)
11,245 9,007
INCOME BEFORE INCOME TAXES 48,035 50,327
INCOME TAXES 19,027 19,360
UTILITY NET INCOME $ 29,008 $ 30,967
</TABLE>
UTILITY OPERATIONS:
Weather can significantly affect revenues and net income, and should be
considered when analyzing trends. The Company's sales increase as a result of
colder weather in the winter months. As measured by heating degree days, the
temperature in 1996 in the Company's service territory was 11 percent colder
than normal and 19 percent colder than 1995.
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. The surplus of hydroelectric power
that existed during 1995 continued on into 1996, keeping wholesale power
prices low during the first quarter. The abundance of hydroelectricity in the
region is expected to continue into the summer months.
Electric Utility:
First quarter 1996 income from electric operations decreased primarily
as a result of the coal contract arbitration decision which retroactively
reduced power supply costs by $10,100,000 in the first quarter of 1995. Colder
weather, an increase in the number of customers and higher tariffs offset the
decline from the nonrecurring charge. In addition, the continued availability
of low cost hydroelectric generation in the region helped to reduce power
supply costs over last year but also reduced brokering opportunities. Overall,
the regional hydroelectric situation benefits Utility pre-tax net income
$1,600,000.
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 $ 4
- volume (1)%
- price/kWh 5%
Other utilities - revenue $ (2)
- volume (2)%
- price/kWh (7)%
Miscellaneous - revenue $ 1
Revenues:
Residential and commercial customer revenues increased $6,500,000 or 10
percent during the first three months of the year, principally the result of an
8 percent increase in volumes sold due to colder weather and 2 percent customer
growth. The increase was partially offset by a $2,500,000 decrease in revenues
from industrial customers, due largely to the loss of the Utility's largest
retail customer in December 1995.
Revenues from off-system sales to other utilities decreased due to a
reduction in volumes sold and lower prices both resulting from the abundance
of lower cost hydroelectric generation in the region.
Increased miscellaneous wheeling revenue resulted from a new agreement
negotiated in November 1995.
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 March 31, 1996 and 1995.
1996 1995
Sources MWH
Hydroelectric 1,134,483 741,576
Steam 1,006,433 1,350,075
Purchases and other 885,338 797,090
Total Power Supply 3,026,254 2,888,741
Thousands of Dollars
Hydroelectric $ 4,643 $ 4,553
Steam 11,487 3,817
Purchases and other 25,616 26,977
Total Power Supply Expenses $ 41,746 $ 35,347
Cents Per Kilowatt-Hour 1.379 1.224
Excluding the impact of the coal contract arbitration decision that
reduced steam expenses $10,100,000, power supply expenses decreased $3,700,000.
This reduction was the result of increased precipitation throughout the region,
which increased Utility hydroelectric generation 53 percent, and reduced the
price of purchased power. Low cost purchases allowed the Utility to take
Colstrip Unit 3 off line on February 16, reducing fuel expenses. The unit was
returned to service on April 21, 1996. The decrease in power supply expenses
was offset in part by increased payments to independent power producers.
Depreciation and amortization costs increased as a result of additional
property in service.
Natural Gas Utility:
Income from natural gas operations increased primarily due to increased
volumes sold as a result of colder weather and customer growth.
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 $ 5
-volume 18%
-price/Mcf -%
Transportation -revenue $ 1
-volume 1%
-price/Mcf (3)%
Revenues:
Higher revenues (other than gas supply costs) resulted from increased
sales volumes due to 19 percent colder weather and 3.8 percent growth in
residential and commercial customers.
Gas supply cost revenues consist of the amount authorized by the PSC to
be collected in rates to cover the cost of gas supplied. The increase in gas
supply cost revenue resulted from increased volumes sold. Gas supply cost
revenues and gas supply cost expenses are always equal due to rate and
accounting procedures.
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 increased by $1,800,000 on a non-recurring basis, in the
first quarter of 1995, as the result of the receipt of interest under the coal
contract arbitration decision.
ENTECH OPERATIONS
<TABLE>
<CAPTION>
For Three Months Ended
March 31, March 31,
1996 1995
Thousands of Dollars
COAL OPERATIONS:
<S> <C> <C>
REVENUES:
Revenues $ 38,390 $ 53,083
Intersegment revenues 8,197 298
46,587 53,381
EXPENSES:
Cost of sales 27,536 40,440
Selling, general and administrative 5,135 7,815
Taxes other than income taxes 5,375 5,540
Depreciation, depletion and amortization 1,143 3,743
39,189 57,538
INCOME FROM COAL OPERATIONS 7,398 (4,157)
OIL AND NATURAL GAS OPERATIONS:
REVENUES:
Revenues 29,063 23,269
Intersegment revenues 99 132
29,162 23,401
EXPENSES:
Cost of sales 17,649 12,861
Selling, general and administrative 2,426 2,242
Taxes other than income taxes 834 630
Depreciation, depletion and amortization 3,953 4,488
24,862 20,221
INCOME FROM OIL AND NATURAL GAS OPERATIONS 4,300 3,180
OTHER OPERATIONS:
REVENUES:
Revenues 6,494 6,283
Intersegment revenues 192 286
6,686 6,569
EXPENSES:
Cost of Sales 4,428 4,356
Selling, general and administrative 1,231 1,271
Taxes other than income taxes 91 81
Depreciation, depletion and amortization 397 403
6,147 6,111
INCOME FROM OTHER OPERATIONS 539 458
INTEREST EXPENSE AND OTHER INCOME:
Interest 929 2,348
Other (income) deductions-net (137) (1,208)
792 1,140
INCOME BEFORE INCOME TAXES 11,445 (1,659)
INCOME TAXES 2,907 (3,328)
ENTECH NET INCOME $ 8,538 $ 1,669
</TABLE>
ENTECH OPERATIONS:
Coal Operations:
Income from coal operations increased as a result of two nonrecurring
charges recorded during 1995 which were the Colstrip 1 & 2 arbitration
decision and the operating losses incurred at Golden Eagle Mine in Colorado.
Accruals for the permanent closure and write down to net salvage value of the
Golden Eagle Mine were recorded effective October 1995. Partially offsetting
the increase were lower sales to Colstrip Units 3 & 4 and the expiration of a
Midwestern contract.
Revenues:
Rosebud Mine revenues increased $1,100,000. Revenues from Colstrip
Units 1 & 2 and the Company's Corette plant increased $19,200,000 primarily
due to the nonrecurring coal contract arbitration settlement recorded during
1995. These increases were partially offset by coal and coal transportation
revenue decreases of $9,700,000 primarily due to fewer tons sold to Colstrip
Units 3 & 4. The availability of lower cost hydroelectricity displaced this
thermal generation. The expiration of a Midwestern contract during 1995,
including the related take or pay provision, and spot sales contributed to
revenue decreases of $8,400,000. Jewett Mine revenues decreased $1,900,000
because the majority of the tons sold during 1996 do not have an overriding
royalty provision. Related expenses are reduced by a similar amount. The
closure of the Golden Eagle Mine decreased revenues by $5,800,000.
Expenses:
Operating expenses were reduced by $11,100,000 due to the closure of
the Golden Eagle Mine. Rosebud mine operating costs decreased by $6,800,000
due to reduced tons sold for reasons mentioned above.
Oil and Natural Gas Operations:
Income from the oil and natural gas operations improved primarily due
to increased earnings from natural gas marketing activities.
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenue (excluding intersegment
revenues) and the related percentage changes in volumes sold and prices
received:
Oil -revenue $ (1)
-volume (17)%
-price/bbl 5%
Natural gas -revenue $ -
-volume (3)%
-price/Mcf 11%
Natural gas marketing -revenue $ 6
-volume 50%
-price/Mcf 3%
Revenues:
Natural gas marketing revenues increased $6,000,000 primarily due to
higher volumes sold. Oil revenues decreased in Canada because of natural
declining production, and in the U.S., six producing oil wells were converted
to waterflood injection wells during the fourth quarter of 1995. Increased
production from the waterflood project is expected to occur during the fourth
quarter 1996.
Expenses:
Purchased natural gas for resale increased the cost of sales
approximately $5,000,000 due to higher volumes and prices.
Interest Expense and Other Income:
Interest expense decreased as a result of the arbitration settlement for
Colstrip Units 1 & 2 during 1995. Other income also decreased from the impact
of recording the arbitration decision and reduced income from Brazil in the
first quarter 1996.
INDEPENDENT POWER GROUP OPERATIONS
<TABLE>
<CAPTION>
For Three Months Ended
March 31, March 31,
1996 1995
Thousands of Dollars
<S> <C> <C>
REVENUES:
Revenues $ 19,717 $ 20,024
Earnings from unconsolidated investments 2,709 1,180
Intersegment revenues 69 336
22,495 21,540
EXPENSES:
Operation and maintenance 16,612 17,276
Selling, general and administrative 822 814
Taxes other than income taxes 431 520
Depreciation and amortization 784 740
18,649 19,350
INCOME FROM OPERATIONS 3,846 2,190
INTEREST EXPENSE AND OTHER INCOME:
Other (income) deductions - net (792) (750)
(792) (750)
INCOME BEFORE INCOME TAXES 4,638 2,940
INCOME TAXES 1,869 1,244
IPG NET INCOME $ 2,769 $ 1,696
</TABLE>
INDEPENDENT POWER GROUP OPERATIONS:
IPG net income for the first three months increased primarily as a
result of continued earnings growth from investments in operating projects and
the continuing availability of low cost hydroelectric generation in the region
to supply long-term sales contracts. This increase was partially offset by an
increase in power project development expenses.
Revenues:
IPG revenues increased primarily from a $1,500,000 increase in earnings
from investments in operating projects partially offset by a $600,000 decrease
in revenues from long-term power sales agreements due to decreased volumes
sold.
Expenses:
IPG operating and maintenance expenses decreased $600,000 due primarily
to a $1,500,000 reduction in power supply costs partially offset by a
$1,000,000 increase in power project development expenses. Power supply costs
decreased due to lower volumes sold and the displacement of higher cost
thermal generation from the Colstrip plant with lower cost hydroelectric
generation.
LIQUIDITY AND CAPITAL RESOURCES:
Touch America, Inc., an indirect wholly owned subsidiary, is spending
$62,000,000 to expand its fiber optic network. Of this amount, $11,000,000 was
spent in previous years, $30,000,000 will be spent in 1996, and the remainder
will be spent in 1997 and 1998. These amounts reflect increases of $15,000,000
for 1996, $7,000,000 for 1997 and $4,000,000 for 1998 in Entech's previously
reported capital budgets (See Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations, Liquidity and Capital
Resources". in the Company's Annual Report on Form 10-K for the year ended
December 31, 1995). The expansion will allow access to markets extending from
Seattle, Washington to St. Paul, Minnesota and from Denver, Colorado to the
Canadian Border, increasing the population of Touch America's market area from
one to twelve million people. The expanded network will provide partial
service by the end of 1996 with full service provided by mid-1997. While the
return on this investment, which will depend upon such future uncertainties as
demand for service, competition and technological change, cannot be accurately
estimated, Touch America anticipates that, because of existing long-term
commitments for the expanded network's capacity, its long-term return on this
investment will exceed the 11 percent allowed on the Company's regulated
electric business.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended March 31, 1996, the Company's ratio of
earnings to fixed charges was 2.10 times. Excluding the effects of the
implementation of Statement of Financial Accounting Standards No. 121 and the
writedown of a coal mining investment, effective October 1, 1995, the ratio of
earnings to fixed charges would have been 2.98 times. Fixed charges include
interest, the implicit interest of the Colstrip Unit 4 rentals and one-third of
all other rental payments.
UTILITY INDUSTRY CHANGES:
FERC issued its final open access rules on April 24, 1996. Highlights of
the final rules are:
1. Require public utilities to file a single open access tariff that
offers specific transmission services.
2. Permit transmitting utilities to seek to recover legitimate, prudent,
stranded investments that were incurred with a reasonable expectation
that the utility would continue to serve a particular customer.
3. Require public utilities to implement a transmission information
system. Utilities must obtain information about their transmission
the same way competitors do -- through the information system.
4. Does not require divestiture of assets but utilities must separate
transmission and generation functions from each other.
5. Does not require utilities to create an independent system
transmission operator (ISO). However, the rules do establish
principles concerning how an ISO should be constructed.
The Company is taking the necessary steps to comply with all aspects of
the final ruling.
PART II
Other Information
ITEM 1. Legal Proceedings
Puget Sound Power and Light Power Sales Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Colstrip Units 3 and 4 Coal Arbitration
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Frederickson Litigation
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
ITEM 5. Other Information
None.
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 March 31,
1996.
Exhibit 27 Financial Data Schedule
Exhibits and Reports on Form 8-K (continued)
(b) Reports on Form 8-K
DATE SUBJECT
January 5, 1996 Item 5 Other Events. MPC Reports Fourth-Quarter
Charge for Asset Impairment.
January 23, 1996 Item 5 Other Events. Discussion of Fourth
Quarter Net Income.
Item 7 Exhibits. Preliminary Condensed Balance
Sheet at December 31, 1995 and 1994. Preliminary
Consolidated Statements of Income for the
Quarters Ended December 31, 1995 and 1994 and
for the Years Ended December 31, 1995 and 1994.
Preliminary Utility Operations Schedule of
Revenues and Expenses for the Quarters Ended
December 31, 1995 and 1994 and the Years Ended
December 31, 1995 and 1994. Preliminary Entech
Operations Schedule of Revenues and Expenses for
the Quarters Ended December 31, 1995 and 1994
and the Years ended December 31, 1995 and 1994.
Preliminary Independent Power Group Operations
Schedule of Revenues and Expenses for the
Quarters Ended December 31, 1995 and 1994 and
the Years Ended December 31, 1995 and 1994.
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)
By /s/ J. P. Pederson
J. P. Pederson
Vice President and Chief
Financial Officer
Dated: May 15, 1996
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended March 31, 1996
Exhibit 27
Financial Data Schedule
- -21-
- -23-
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
December 31, 1995
Net Income $ 59,053
Income Taxes 21,573
$ 80,626
Fixed Charges:
Interest $ 47,330
Amortization of Debt Discount,
Expense and Premium 1,567
Rentals 35,300
$ 84,197
Earnings Before Income Taxes
and Fixed Charges $164,823
Ratio of Earning to Fixed Charges 1.96 x
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 3/31/96, the Consolidated Income Statement and
Consolidated Statement of Cash Flows for the three months ended 3/31/96 and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,539,807
<OTHER-PROPERTY-AND-INVEST> 487,756
<TOTAL-CURRENT-ASSETS> 257,704
<TOTAL-DEFERRED-CHARGES> 289,663
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,574,930
<COMMON> 691,930
<CAPITAL-SURPLUS-PAID-IN> 2,244
<RETAINED-EARNINGS> 269,423
<TOTAL-COMMON-STOCKHOLDERS-EQ> 963,597
0
101,416
<LONG-TERM-DEBT-NET> 604,351
<SHORT-TERM-NOTES> 49,812
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 23,526
0
<CAPITAL-LEASE-OBLIGATIONS> 2,051
<LEASES-CURRENT> 708
<OTHER-ITEMS-CAPITAL-AND-LIAB> 829,469
<TOT-CAPITALIZATION-AND-LIAB> 2,574,930
<GROSS-OPERATING-REVENUE> 264,405
<INCOME-TAX-EXPENSE> 23,802
<OTHER-OPERATING-EXPENSES> 189,043
<TOTAL-OPERATING-EXPENSES> 212,845
<OPERATING-INCOME-LOSS> 51,560
<OTHER-INCOME-NET> 741
<INCOME-BEFORE-INTEREST-EXPEN> 52,301
<TOTAL-INTEREST-EXPENSE> 11,986
<NET-INCOME> 40,315
1,807
<EARNINGS-AVAILABLE-FOR-COMM> 38,508
<COMMON-STOCK-DIVIDENDS> 21,874
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 103,447
<EPS-PRIMARY> 0.70
<EPS-DILUTED> 0.70
</TABLE>
