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 September 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 November 6, 1995, the Company had 54,578,666 shares of common stock
outstanding.
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
For the Nine Months Ended
September 30, September 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES $ 685,369 $ 716,565
EXPENSES:
Operations 312,803 318,181
Maintenance 52,921 59,385
Selling, general and administrative 72,754 77,291
Taxes other than income taxes 69,639 73,660
Depreciation, depletion and amortization 65,998 64,760
574,115 593,277
INCOME FROM OPERATIONS 111,254 123,288
INTEREST EXPENSE AND OTHER INCOME:
Interest 32,765 32,332
Other (income) deductions - net (4,971) (8,254)
) 27,794 24,078
INCOME TAXES 25,407 31,042
NET INCOME 58,053 68,168
DIVIDENDS ON PREFERRED STOCK 5,420 5,420
NET INCOME AVAILABLE FOR COMMON STOCK $ 52,633 $ 62,748
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 53,986 53,000
NET INCOME PER SHARE OF COMMON STOCK $ 0.97 $ 1.18
</TABLE>
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
For the Three Months Ended
September 30, September 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES $ 217,545 $ 233,304
EXPENSES:
Operations 101,666 111,356
Maintenance 16,900 19,937
Selling, general and administrative 23,241 26,226
Taxes other than income taxes 24,580 24,851
Depreciation, depletion and amortization 21,828 21,117
188,215 203,487
INCOME FROM OPERATIONS 29,330 29,817
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,018 10,980
Other (income) deductions - net (3,665) (5,583)
7,353 5,397
INCOME TAXES 5,825 6,139
NET INCOME 16,152 18,281
DIVIDENDS ON PREFERRED STOCK 1,807 1,807
NET INCOME AVAILABLE FOR COMMON STOCK $ 14,345 $ 16,474
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,243 53,250
NET INCOME PER SHARE OF COMMON STOCK $ 0.26 $ 0.31
</TABLE>
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
A S S E T S
September 30, December 31,
1995 1994
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $105,276 and $79,510
plant under construction)
Electric $ 1,673,751 $ 1,608,615
Natural gas 482,524 463,134
2,156,275 2,071,749
Less - accumulated depreciation and depletion 659,295 619,195
1,496,980 1,452,554
ENTECH PROPERTY (includes $10,565 and $3,030
property under construction) 570,096 530,167
Less - accumulated depreciation and depletion 209,739 189,926
360,357 340,241
INDEPENDENT POWER GROUP PROPERTY (includes $3,282 and
$671 property under construction) 73,018 70,253
Less - accumulated depreciation 18,075 17,560
54,943 52,693
1,912,280 1,845,488
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 50,666 54,397
Other 52,312 49,713
102,978 104,110
CURRENT ASSETS:
Cash and temporary cash investments 16,998 21,564
Accounts receivable 111,909 159,975
Materials and supplies (principally at average cost) 47,656 47,937
Prepayments and other assets 59,473 65,154
236,036 294,630
DEFERRED CHARGES:
Advanced coal royalties 22,602 22,939
Regulatory assets related to income taxes 147,071 146,844
Regulatory assets - other 59,343 49,880
Other deferred charges 52,915 48,806
281,931 268,469
$ 2,533,225 $ 2,512,697
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
September 30, December 31,
1995 1994
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,342,521 and
53,578,737 shares issued) $ 684,906 $ 667,344
Retained earnings and other shareholders' equity 310,776 320,756
Unallocated Stock held by Trustee for Deferred
Savings and Employee Stock Ownership Plan (31,087) (32,580)
964,595 955,520
Preferred stock 101,416 101,416
Long-term debt 617,800 588,876
1,683,811 1,645,812
CURRENT LIABILITIES:
Short-term borrowing 68,356 113,989
Long-term debt - portion due within one year 16,799 16,980
Dividends payable 23,561 23,249
Income taxes (2,609) 9,210
Other taxes 59,794 46,521
Accounts payable 51,661 50,788
Interest accrued 14,261 11,785
Other current liabilities 51,768 40,546
283,591 313,068
DEFERRED CREDITS:
Deferred income taxes 329,754 322,835
Investment tax credit 47,418 48,729
Accrued mining reclamation costs 114,189 110,035
Other deferred credits 74,462 72,218
565,823 553,817
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,533,225 $ 2,512,697
</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 Nine Months Ended
September 30, September 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 58,053 $ 68,168
Noncash charges (credits) to net income:
Depreciation and depletion 65,998 64,760
Mining reclamation costs expenses 13,181 12,650
Deferred income taxes. 5,563 6,332
Amortization of loss on long-term sale
of power (2,448) (3,170)
Other - net 16,506 16,780
Changes in other assets and liabilities 8,538 (2,229)
Accounts receivable 48,066 31,648
Materials and supplies 281 (4,143)
Accounts payable 873 (10,384)
Payment of mining reclamation costs (9,027) (7,290)
Net Cash Flows from Operating Activities 205,584 173,122
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Gross additions to property and plant (134,570) (121,085)
Investments in other operations 5,718 (2,408)
Sales of property 5,014 15,418
Additional investments (16,289) (9,258)
Net Cash Flows from Investing Activities (140,127) (117,333)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Sales of common stock 17,314 18,750
Issuance of long-term debt 30,880 23,758
Retirement of long-term debt (2,547) (20,644)
Short-term debt (45,633) (9,082)
Notes payable cogeneration project 0 (1,311)
Dividends on common and preferred stock (70,037) (68,954)
Net Cash Flows from Financing Activities (70,023) (57,483)
Net Cash Flows (4,566) (1,694)
Cash and cash equivalents at beginning of period 21,564 11,604
Cash and cash equivalents at end of period $ 16,998 $ 9,910
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Nine Months For:
Income taxes $ 31,662 $ 35,472
Interest 32,180 32,189
</TABLE>
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying financial statements of the Company for the interim
periods ended September 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.
FERC has prepared a Draft Environment Impact Statement (DEIS) which
generally agrees with the non-operational provisions of the Plan but recommends
changing the Kerr operations from peaking and load following operations to
baseload operations to provide maximum benefit to fish and wildlife habitat in
the Flathead River, below the dam. The recommended operational change is
similar to changes proposed by the Department of Interior (the Department), but
differs substantially from the non-operational changes proposed by the
Department.
The Company estimates the operational changes proposed by FERC in its
DEIS would increase power costs by approximately $5,500,000 annually. Other
changes to the Plan proposed in the DEIS would result in a one-time payment
made to the Tribe of approximately $26,000,000, without a requirement for
annual payments. The Department's proposed 4(e) conditions, on the other hand,
would result in a one-time payment of approximately $36,200,000 and annual
payments of approximately $945,000. The Company has already responded to the
Department's 4(e) conditions and will file its responsive comments to the DEIS
by the end of the year.
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,
pursuant to the license, to take over the project in 2015 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
obtained a restraining order and later a status quo agreement pending final
court decision. 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; however, it
cannot assure the outcome of this controversy.
This matter is pending before a Federal District Court in Montana. On
October 6, 1995, Puget filed a motion in the federal court seeking an order
staying the court action pending receipt from FERC of a declaratory judgment.
On October 24, 1995, Puget petitioned FERC to obtain a declaratory judgment
that the transmission service which is subject to this dispute is not "firm" as
required by the Agreement. The Company believes this dispute to be a matter of
contract interpretation which does not require specialized agency expertise
triggering FERC's primary jurisdiction and does not believe either the motion
filed with the court or the petition filed with FERC should be granted. The
Company has filed with the federal court appropriate responses asserting its
positions and will file a response within 30 days after FERC publishes notice
of Puget's petition.
If the Company is unsuccessful in this matter, 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, approximately 315,000 MWhs at September 30, 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. In the future,
the Company's revenues would be reduced by the difference, if any, between
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 non-cash adjustment to its accounting records reducing an
asset related to the Agreement by approximately $23,000,000 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 3 and 4 (i.e., Puget, Washington Water Power Company,
Portland General Electric Company and PacificCorp - collectively the "Buyers")
to resolve a variety of disputes arising under the contracts with Western for
the supply and transportation of coal from these Units. The arbitration
hearing concluded in November and a decision is expected in March 1996.
The Buyers allege that certain coal transportation, the cost of which has
been paid by the Buyers was to have been provided without charge by Western.
Western asserts that these costs were properly payable by the Buyers. The
Buyers sought a refund or credit of approximately $118,000,000 plus interest,
an increase over earlier amounts associated with this claim of $62,000,000. On
October 13, 1995, the arbitrator granted Western's motion for summary judgment,
denying the Buyers' claim for this refund or credit.
The Buyers also allege that either (i) they 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 (ii) the price of coal and coal
transportation in excess of these quantities is to be determined by negotiation
or arbitration. The Buyers also allege 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 contracts require the Buyers to purchase
and transport all of the coal requirements at Units 3 and 4 from Western at
specified contract prices. As to these claims, the Buyers seek prospective
relief almost exclusively.
The Buyers also allege that Western has violated the coal supply contract
by not mining in an "economic and efficient" manner and by not adopting a
mining plan suggested by the Buyers. Western asserts that its mining plan is
reasonable and denies that the Buyers have any right to insist upon a mining
plan of their choosing. The Buyers seek damages of approximately $6,000,000,
plus interest on this claim, an increase over earlier amounts of $4,500,000.
The Buyers also assert that Western is required to sell the mine to the Buyers
at its depreciated cost or to turn operation of the mine over to a contract
miner.
The Buyers also allege that Western is required to fund an external mine
reclamation account of approximately $36,000,000 including interest and to
accept the future income tax consequences associated with this account.
Western acknowledges that a reclamation account must be maintained and has
accrued the associated liability, but denies that it must be external to
Western or that it must bear the associated cash tax consequences prior to the
time reclamation expenditures are made.
Western is confident regarding its positions on the issues in dispute,
but, nevertheless, cannot predict the outcome of this arbitration.
The Entech Oil Division has agreed to supply 129 Bcf of natural gas to
four cogeneration facilities through mid-2011. The Oil Division has sufficient
proved, 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, included $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.
On September 21, 1995, the Company filed an electric and natural gas rate
increase request with the PSC. The request contains a traditional filing based
upon an adjusted historic test year and an alternative rate proposal which
consists of a three-year rate plan providing for rate increases in 1996, 1997
and 1998. In conjunction with both the traditional filing and the alternative
proposal, the Company also requested an interim electric rate increase of
$11,100,000 annually and an interim natural gas rate increase of $4,400,000
annually, both of which would be subject to refund if in excess of the final
rate adjustment under either the traditional or alternative filings. A decision
on the interim requests is expected by the end of December 1995.
In its traditional filing, the Company has requested rate increases from
the PSC which would increase electric revenues by $34,900,000 annually, or
9.84%, and natural gas revenues by $12,000,000 annually, or 10.45% both based
upon a return on equity of 12.5%. Under the traditional approach, the Company
anticipates consideration of further annual rate filings in 1996 and 1997.
The alternative plan, which is the preferred alternative recommended by
the Company would establish rates for the next three years and limit
conventional rate filings until 1998. The plan's three-year rate increases
provide approximately $27,000,000 in additional electric revenues and
$8,400,000 additional natural gas revenues effective in May 1996; $11,400,000
additional electric revenues and $5,100,000 additional natural gas revenues
effective in January 1997; and finally $12,000,000 additional electric revenues
and $5,000,000 additional natural gas revenues effective in January 1998. The
alternative plan includes cost recovery provisions providing timely rate
adjustments for full recovery of state property taxes and federally mandated
power purchases and predetermined rate percentage adjustments to recover
increases in all other normal costs of service.
Hearings on the rate filing are scheduled to begin in April 1996 and a
decision is expected in June 1996.
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.
In July 1995, Entech borrowed $10,000,000 at an interest rate of 6.4375%
under their Revolving Credit and Term Loan Agreement, which expires in
September 1997.
NOTE 4. FINANCIAL INSTRUMENTS:
To manage price risk Entech uses swap agreements to hedge revenues from
anticipated sales of oil and natural gas. 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 September 30, 1995, Entech had swap agreements to hedge approximately
274,000 barrels, or 34% of its expected production from proved, developed and
producing oil reserves through June 1996, and for approximately 366,500 Mmcf,
or 12% of its expected production from proved, developed and producing natural
gas reserves through March 1996. In addition, Entech had swap agreements to
hedge approximately 442,000 Mmcf, or 12% of its delivery obligations under
long-term natural gas sales contracts through February 1996. At September 30,
1995, the Company had no material deferred gains or losses from these
transactions.
The Independent Power Group 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. At September 30, 1995, the Company
believes it would 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, 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.
Nine Months Ended September 30, 1995 and 1994:
Net Income Per Share of Common Stock
Consolidated net income for the nine months ended September 30, 1995
declined from $1.18 per share in the comparable period of 1994 to 97 cents per
share. Approximately 5 cents per share of the decrease was due to a retroactive
adjustment reflecting a coal arbitration decision which reduced the price
charged per ton of coal sold to Colstrip Units 1 and 2 (see Part II, Item 1,
Legal Proceedings). While this decision reduced Entech's earnings, the Utility
benefited through lower fuel costs. The Utility also experienced strong
earnings gains resulting from increased hydroelectric generation and reduced
purchased power costs. Entech's earnings were also negatively impacted by
lower volumes of coal sales from the Rosebud Mine and production problems at
the underground mine in Colorado. Independent Power Group earnings decreased
as a result of a decline in project development activities, a loss on the sale
of an investment and because a 1994 gain on the sale of a 50% interest in North
American Energy Services enhanced last year's earnings.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Nine Months Ended
September 30,
1995 1994
Utility Operations $ 0.66 $ 0.42
Entech 0.24 0.64
Independent Power Group 0.07 0.12
Consolidated $ 0.97 $ 1.18
UTILITY OPERATIONS
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
1995 1994
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES
Revenues $ 296,402 $ 300,833
Intersegment revenues 4,437 4,466
300,839 305,299
EXPENSES
Power supply 102,781 127,792
Transmission and distribution 20,612 20,895
Selling, general and administrative 31,204 34,809
Taxes other than income taxes 34,807 31,759
Depreciation and amortization 31,878 30,524
221,282 245,779
INCOME FROM ELECTRIC OPERATIONS 79,557 59,520
NATURAL GAS UTILITY:
REVENUES
Revenues (other than gas supply
cost revenues) 61,702 56,517
Gas supply cost revenues 15,306 12,461
Intersegment revenues 665 645
77,673 69,623
EXPENSES
Gas supply costs 15,306 12,461
Other production, gathering and exploration 7,153 6,465
Transmission and distribution 8,183 7,514
Selling, general and administrative 13,418 13,603
Taxes other than income taxes 10,899 9,936
Depreciation, depletion and amortization 7,710 7,063
62,669 57,042
INCOME FROM GAS OPERATIONS 15,004 12,581
INTEREST EXPENSE AND OTHER INCOME:
Interest 33,074 32,174
Other (income) deductions - net (4,305) (2,801)
28,769 29,373
INCOME BEFORE INCOME TAXES 65,792 42,728
INCOME TAXES 24,806 15,162
UTILITY NET INCOME $ 40,986 $ 27,566
</TABLE>
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 nine
months ended September 30, 1995 in the Company's service territory was equal to
the historic average and 12% 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. During the nine months ended September 30, 1995
there was a surplus of energy in the region which depressed wholesale and
purchased power prices.
During the past year, the Company has performed a strategic analysis of
certain business functions, to determine what is needed in those areas to meet
changing conditions in the utility industry. Study teams have developed methods
to be more effective and efficient and changes are being implemented in the
Utility's organizational structure. The changes, which began in 1994, are
anticipated to be completed in 1997 and will reduce the workforce by
approximately 350 employees from the 1994 levels.
The Company has accrued an estimated $4,500,000 of severance benefits
applicable to employees for certain of the functional areas; however,
additional amounts will be identified and accrued in the remainder of 1995 and
future periods. The Utility's costs of the program are being deferred as
authorized by an Accounting Order from the Montana Public Service Commission
(PSC) and are not reflected in income. The Company believes these costs will
be recovered through rates.
Electric Utility:
Income from electric operations increased $20,000,000. The increase is
primarily due to a $25,000,000 reduction in power supply costs offset by a
$4,500,000 decrease in operating revenues. Power supply costs decreased as a
result of the previously discussed coal price arbitration decision and reduced
purchased power costs resulting from an 8% increase in low cost hydroelectric
generation and reduced brokering transactions. The decrease in operating
revenues is the result of reductions in sales to other utilities and reductions
in miscellaneous revenues, partially offset by an increase in sales to general
business customers.
The electric utility's largest firm wholesale customer, Central Montana
Generation and Transmission Cooperative (Central Montana), has given a notice
they will not renew their contract when it expires in June 2000. The customer
is considering other possible power supply sources. In 1994, Central Montana
required 451,000 MWh of energy and 78 MW during the Company's system peak.
This represents approximately 5% of the Company's firm sales and peak load
requirements. Central Montana paid a rate of 3.49 cents per kWh. The Company
is implementing strategies to offset the effects if this customer leaves the
system.
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 $ 11
- volume -
- price/kWh 4%
Other utilities - revenue $ (12)
- volume (11)%
- price/kWh (17)%
Miscellaneous - revenue $ (3)
Revenues:
Sales to general business customers increased $10,600,000 largely the
result of 4% higher tariffs. Continued customer growth of 1.6% and colder
weather increased volumes sold to the residential and commercial classes.
However, sales to industrial customers were down by a corresponding amount due
to industrial business interruptions.
As a result of an abundance of low-cost power in the region, both volumes
sold, and the price received from sales to other utilities decreased during the
period.
Miscellaneous revenues decreased $2,700,000 primarily as a result of
regulatory accounting entries and a decrease in wheeling revenues resulting
from reduced sales to other utilities.
Expenses:
The following table shows the Company's sources of electricity and power
supply expenses (operation, fuel for electric generation and maintenance) for
the nine months ended September 30, 1995 and 1994.
1995 1994
Sources MWH
Hydroelectric 2,505,284 2,315,336
Steam 3,495,353 3,529,968
Purchases 1,778,828 2,147,904
Total Power Supply 7,779,465 7,993,208
Thousands of Dollars
Hydroelectric (including maintenance) $ 14,172 $ 13,518
Steam (including fuel and maintenance) 30,448 46,803
Purchases 58,161 67,471
Total Power Supply Expenses $ 102,781 $ 127,792
Cents Per Kilowatt-Hour 1.321 1.599
Power supply costs decreased $25,000,000 during the period. Of this
decrease, steam generation expenses accounted for $16,400,000, including a
$13,200,000 reduction in fuel costs which primarily resulted from a coal
arbitration decision that reduced the price of coal sold by Entech's Western
Energy Company to Colstrip Units 1 and 2 and the Corette Plant. This price
decrease was retroactive to July 1991, and current period expenses include an
$11,300,000 credit for coal purchased in prior years. In addition, steam
maintenance expenses decreased $3,000,000 as a result of improved productivity
and maintenance practices at the Colstrip generating units.
A $9,300,000 reduction in purchased power costs also contributed to the
lower power supply costs. This reduction was due to increased generation from
the Utility's hydroelectric facilities and reduced volumes sold to other
utilities.
Selling, general and administrative expenses decreased primarily due to a
reimbursement received from insurers for Colstrip housing repair costs which
were expensed in 1994.
The $3,000,000 increase in taxes other than income taxes and the
$1,300,000 increase in depreciation expense are primarily due to property
additions.
Natural Gas Utility:
Income from natural gas operations increased $2,400,000 principally due
to increased volumes sold as a result of colder weather and residential and
commercial 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 11%
-price/Mcf 1%
Transportation -revenue $ -
-volume 23%
-price/Mcf 5%
Miscellaneous -revenue $ -
Revenues:
Natural gas revenues (other than gas supply costs) increased $5,200,000,
of which 40% is attributable to a 4.1% increase in the number of customers and
60% is attributable to weather which was 12% colder than in 1994.
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 $2,800,000 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.
Interruptible transportation revenues are fixed by the most recent rate
case. Amounts in excess of or lower than amounts considered in the rate case
are deferred for treatment in a future rate filing. Transportation volumes
change as a result of increasing/decreasing customer loads.
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:
Interest expense increased $900,000 as a result of increased
borrowing to finance plant additions.
The increase in other income resulted principally from miscellaneous
non-recurring income and expense transactions.
ENTECH OPERATIONS
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
1995 1994
Thousands of Dollars
COAL OPERATIONS:
<S> <C> <C>
REVENUES
Revenues $ 157,148 $ 186,695
Intersegment revenues 15,015 30,291
172,163 216,986
EXPENSES
Cost of sales 120,816 123,832
Selling, general and administrative 20,807 21,483
Taxes other than income taxes 20,210 27,719
Depreciation, depletion and amortization 9,320 9,382
171,153 182,416
INCOME FROM COAL OPERATIONS 1,010 34,570
OIL AND NATURAL GAS OPERATIONS:
REVENUES
Revenues 73,003 73,192
Intersegment revenues 170 162
73,173 73,354
EXPENSES
Cost of sales 43,142 40,825
Selling, general and administrative 6,811 6,322
Taxes other than income taxes 1,986 2,640
Depreciation, depletion and amortization 13,610 13,943
65,549 63,730
INCOME FROM OIL AND NATURAL GAS OPERATIONS 7,624 9,624
OTHER OPERATIONS:
REVENUES
Revenues 18,891 17,597
Intersegment revenues 479 465
19,370 18,062
EXPENSES
Cost of sales 12,607 12,273
Selling, general and administrative 3,611 3,557
Taxes other than income taxes 245 211
Depreciation, depletion and amortization 1,261 1,465
17,724 17,506
INCOME FROM OTHER OPERATIONS 1,646 556
INTEREST EXPENSE AND OTHER INCOME:
Interest 3,764 1,191
Other (income) deductions - net (4,101) (2,486)
(337) (1,295)
INCOME BEFORE INCOME TAXES 10,617 46,045
INCOME TAXES (2,411) 12,052
ENTECH NET INCOME $ 13,028 $ 33,993
</TABLE>
ENTECH OPERATIONS:
Coal Operations:
Income from coal operations decreased $33,500,000 of which $13,800,000
resulted from the Colstrip Units 1 and 2 coal arbitration decision for coal
sold between July 1991 and December 1994, and $2,600,000 resulted from coal
sold during 1995. The remainder of the decrease was primarily attributable to
lower volumes sold to Colstrip Units 3 and 4, 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 (Golden Eagle) incurred losses of
approximately $9,500,000 and $4,900,000 through September 30, 1995, and 1994,
respectively. Management expects the loss during the fourth quarter of 1995 to
be an additional $1,600,000 compared to the loss of $2,900,000 recorded in the
fourth quarter of 1994. All of these losses are on an after-tax basis. The
production problems that were encountered are being resolved.
Related to its decision to concentrate on operating coal mines that serve
mine-mouth electric generation plants, such as the Rosebud Mine at Colstrip,
Montana, and the Jewett Mine in Texas, Entech has provided data to parties
interested in purchasing the underground Golden Eagle Mine in Colorado and the
Rocky Butte reserves in Wyoming's Powder River Basin.
The December 1994 expiration of the Midwestern coal contract caused
reductions in the workforce at the Rosebud Mine. Through September 30, 1995,
the workforce has been reduced by 61 salaried and union workers. The estimated
cost savings to be realized in 1995 is $1,600,000. Further reductions of 7
salaried and union workers are expected in 1996 after the second Midwestern
contract expires. Total estimated cost savings from reductions in both years
is $3,700,000 in 1996. Severance costs were not material and, therefore, did
not impact results of operations.
Revenues:
Revenues, including intersegment revenues, decreased primarily from
operations at the Rosebud Mine. Revenues from sales to Colstrip Units 1 and 2
and the Company's Corette Plant decreased $24,700,000 as a result of the
Colstrip Units 1 and 2 coal arbitration decision in 1995, which reduced the
sales price to Colstrip Units 1 and 2 from July 1991 forward. An 11% decrease
in volumes sold was principally the result of the expiration of a Midwestern
contract at the end of 1994, which resulted in a $9,000,000 decrease in
revenues. A second Midwestern contract will expire in December 1995. It will
not be renewed and will reduce revenues in 1996 by approximately $16,800,000.
Revenues from sales to Colstrip Units 3 and 4 also decreased $6,500,000 due to
fewer tons sold for thermal generation caused by the increased availability of
hydroelectric generation in the region. Revenues decreased $3,900,000 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
$3,300,000 as a result of increased reimbursable mining expenses for overburden
stripping costs and surface damage settlements. Golden Eagle Mine revenues
decreased $4,100,000 as a result of lower volumes available for sale due to
production problems.
Expenses:
The decrease in cost of sales includes a combination of $11,300,000
decreased mining costs at the Rosebud Mine due to lower volumes sold, decreased
royalties resulting from lower coal revenues and the expiration of coal
brokering agreements. The decreased costs at the Rosebud Mine were mostly
offset by $4,300,000 increased operating costs at the Golden Eagle Mine and
$3,900,000 increased costs at the Jewett Mine due to the reasons mentioned
above. Taxes other than income taxes decreased $7,500,000 as a result of the
recording of the arbitration decision mentioned above and lower revenues from
Midwestern customers and Colstrip Units 3 and 4.
Oil and Natural Gas Operations:
Income from oil and natural gas operations decreased principally due to
lower natural gas prices and volumes sold, 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 revenue classifications, with the related percentage
changes in volumes sold and prices received:
Oil -revenue $ 1
-volume (7)%
-price/bbl 19%
Natural gas -revenue $ (8)
-volume (9)%
-price/Mcf (25)%
Natural gas marketing -revenue $ 7
-volume 23%
-price/Mcf (1)%
Revenues:
Oil revenues increased $1,400,000 from higher market prices, while
natural gas revenues decreased $8,200,000 from a combination of lower market
prices and lower volumes produced and sold in the U.S. The lower volumes were
principally a result of well shut-ins that occurred because of the low market
prices. Revenues from natural gas marketing increased $6,600,000 due to higher
volumes sold.
Expenses:
Higher volumes of natural gas purchased for resale increased the cost of
sales by $2,400,000.
Other Operations:
Income from other operations increased from telecommunications
operations, land sales, and lower employee benefit costs.
Revenues:
Revenues from Entech's other operations increased $1,500,000 from
telecommunications operations resulting from additional circuits sold to common
carriers and a 26% increase in minutes sold to long-distance customers.
Interest Expense and Other Income:
The increase in interest expense was a combination of $2,000,000 non-
recurring interest paid to the Utility Division pursuant to the arbitration
decision discussed above and increased borrowings. Other income increased
approximately $1,600,000 due to non-recurring interest income from the
arbitration decision and Oil Division property sales.
INDEPENDENT POWER GROUP OPERATIONS
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES:
Revenues $ 59,481 $ 67,326
Earnings from unconsolidated investments 2,958 1,480
Intersegment revenues 709 1,312
63,148 70,118
EXPENSES:
Operation and maintenance 50,561 57,032
Selling, general and administrative 2,465 2,870
Taxes other than income taxes 1,494 1,395
Depreciation and amortization 2,219 2,384
56,739 63,681
INCOME FROM OPERATIONS 6,409 6,437
INTEREST EXPENSE AND OTHER INCOME:
Interest 16 15
Other (income) deductions - net (657) (4,015)
(641) (4,000)
INCOME BEFORE INCOME TAXES 7,050 10,437
INCOME TAXES 3,011 3,828
IPG NET INCOME $ 4,039 $ 6,609
</TABLE>
INDEPENDENT POWER GROUP OPERATIONS:
The net income of the Independent Power Group (IPG) decreased primarily
as a result of a decline in project development activities, the 1994 gain on
the sale of a 50% interest in North American Energy Services Company (NAES),
and the 1995 loss on the sale of another investment. The decline was partially
offset by decreases in maintenance and power supply costs at the Colstrip plant
as well as increased earnings from investments in operating independent power
projects.
Net income of the IPG for the fourth quarter of 1994 included earnings
from the successful development of an independent power project. These
earnings are not expected to recur in the fourth quarter of 1995.
Revenues:
The $7,000,000 decrease in IPG revenues resulted from a decrease in power
project development fees which were not expected to meet the levels achieved in
1994 and a decrease in sales of energy to the Utility Division. The decrease
was partially offset by an increase in earnings from investments in operating
independent power projects.
Expenses:
IPG operation and maintenance expense decreased $6,500,000. The decrease
results principally from a $3,000,000 decrease in power project development
expenses due to reduced development activity. Also contributing to the
decrease in operation and maintenance expense was a $2,000,000 decrease in
maintenance due to improved productivity and maintenance practices at the
Colstrip generating unit and a $1,400,000 decrease in power supply expenses
resulting primarily from decreased generation at the unit.
Interest Expense and Other Income:
Other income decreased primarily as a result of the gain on the sale of a
50% interest in NAES in 1994 and the loss on the sale of another investment in
the current year. The decrease was partially offset by an increase in interest
income.
Three Months Ended September 30, 1995 and 1994:
Net Income Per Share of Common Stock
Consolidated net income for the three months ended September 30, 1995
declined 5 cents per share to 26 cents from 31 cents per share in 1994.
Utility Division earnings improved substantially as a result of a 65% increase
in hydroelectric generation, reduced power purchases and improved productivity
and maintenance practices at the Colstrip coal-fired generating units. This
improvement, however, was more than offset by reduced earnings in the Entech
Coal Division and the absence of development revenues and a gain recorded
during 1994 in the IPG.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Three Months Ended
September 30,
1995 1994
Utility Operations $ 0.08 $ (0.03)
Entech 0.15 0.23
Independent Power Group 0.03 0.11
Consolidated $ 0.26 $ 0.31
UTILITY OPERATIONS
<TABLE>
<CAPTION>
Three Months Ended
September 30,
1995 1994
Thousands of Dollars
ELECTRIC UTILITY:
<S> <C> <C>
REVENUES
Revenues $ 94,593 $ 95,813
Intersegment revenues 1,209 1,265
95,802 97,078
EXPENSES
Power supply 34,549 46,000
Transmission and distribution 7,478 6,948
Selling, general and administrative 9,822 11,362
Taxes other than income taxes 11,532 10,560
Depreciation and amortization 10,627 10,175
74,008 85,045
INCOME FROM ELECTRIC OPERATIONS 21,794 12,033
NATURAL GAS UTILITY:
REVENUES
Revenues (other than gas supply
cost revenues) 12,410 11,595
Gas supply cost revenues 1,920 1,468
Intersegment revenues 122 254
14,452 13,317
EXPENSES
Gas supply costs 1,920 1,468
Other production, gathering and exploration 1,954 2,394
Transmission and distribution 2,672 2,644
Selling, general and administrative 4,291 4,597
Taxes other than income taxes 3,626 3,237
Depreciation, depletion and amortization 2,565 2,340
17,028 16,680
INCOME FROM GAS OPERATIONS (2,576) (3,363)
INTEREST EXPENSE AND OTHER INCOME:
Interest 11,176 10,928
Other (income) deductions - net (1,453) (1,173)
9,723 9,755
INCOME BEFORE INCOME TAXES 9,495 (1,085)
INCOME TAXES 3,244 (1,215)
UTILITY NET INCOME $ 6,251 $ 130
</TABLE>
UTILITY OPERATIONS:
Electric Utility:
Income from electric operations increased $9,800,000 primarily as a
result of an $11,500,000 reduction in power supply costs. Increased generation
from the Company's hydroelectric facilities allowed the Utility to meet its
requirements for firm loads while significantly reducing purchased power
expenses. In addition, improved productivity and maintenance practices at the
Colstrip generating units reduced steam generating expenses.
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 $ 5
- volume -
- price/kWh 5%
Other utilities - revenue $ (5)
- volume (11)%
- price/kWh (21)%
Miscellaneous - revenue $ (1)
Revenues:
Increases in customer growth and tariff rates for residential and
commercial classes had a positive effect on revenue of approximately $5,400,000
during the period. The increase in revenues was partially offset by reduced
air conditioning and irrigation sales due to cooler weather during the quarter.
Sales to other utilities decreased $5,000,000 due to reduced volumes sold
and prices received on energy marketed.
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 September 30, 1995 and 1994.
1995 1994
Sources MWH
Hydroelectric 884,599 536,920
Steam 1,296,195 1,306,358
Purchases 411,803 834,025
Total Power Supply 2,592,597 2,677,303
Thousands of Dollars
Hydroelectric (including maintenance) $ 4,907 $ 4,516
Steam (including fuel and maintenance) 12,968 16,727
Purchases 16,674 24,757
Total Power Supply Expenses $ 34,549 $ 46,000
Cents Per Kilowatt-Hour 1.333 1.718
As a result of a 65% increase in generation from the Utility's
hydroelectric facilities and lower sales to other utilities, $8,100,000 less
purchased power was needed to meet energy requirements. In addition, steam
generation expenses decreased $3,800,000 principally as a result of reduced
maintenance costs of $2,100,000 and reduced fuel costs of $1,500,000.
Selling, general and administrative costs were lower because accruals for
housing damages at Colstrip increased 1994 expenses by $600,000, amortizations
of regulatory liabilities decreased 1995 expenses by $400,000 and
administrative costs capitalized to construction decreased 1995 expenses by
$500,000.
Taxes other than income taxes, which includes property taxes, and
depreciation both increased to reflect additional plant in service.
Natural Gas Utility:
Income from gas operations increased $800,000 principally due to cooler
weather and growth in the number of residential and commercial customers.
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 $ 1
-volume 15%
-price/Mcf (1)%
Transportation -revenue $ -
-volume 10%
-price/Mcf 2%
Miscellaneous -revenue $ -
Revenues:
Natural gas revenues (other than gas supply costs) increased $800,000
principally as the result of a 15% increase in volumes sold due to cooler
weather and a 4.2% growth 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 $450,000 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. Revenue remained relatively unchanged, due to the explanation
provided in the nine-months ended discussion.
Expenses:
The increase in gas supply costs resulted from the reasons mentioned in
the foregoing gas supply cost revenue discussion.
ENTECH OPERATIONS
<TABLE>
<CAPTION>
Three Months Ended
September 30,
1995 1994
Thousands of Dollars
COAL OPERATIONS:
<S> <C> <C>
REVENUES
Revenues $ 55,058 $ 64,727
Intersegment revenues 8,501 10,591
63,559 75,318
EXPENSES
Cost of sales 41,099 44,005
Selling, general and administrative 6,243 7,409
Taxes other than income taxes 8,157 9,652
Depreciation, depletion and amortization 3,073 2,933
58,572 63,999
INCOME FROM COAL OPERATIONS 4,987 11,319
OIL AND NATURAL GAS OPERATIONS:
REVENUES
Revenues 25,525 25,916
Intersegment revenues 0 0
25,525 25,916
EXPENSES
Cost of sales 15,419 14,314
Selling, general and administrative 2,261 2,054
Taxes other than income taxes 672 868
Depreciation, depletion and amortization 4,378 4,573
22,730 21,809
INCOME FROM OIL AND NATURAL GAS OPERATIONS 2,795 4,107
OTHER OPERATIONS:
REVENUES
Revenues 6,373 6,456
Intersegment revenues 144 104
6,517 6,560
EXPENSES
Cost of sales 4,364 4,418
Selling, general and administrative 1,235 1,424
Taxes other than income taxes 82 68
Depreciation, depletion and amortization 446 504
6,127 6,414
INCOME FROM OTHER OPERATIONS 390 146
INTEREST EXPENSE AND OTHER INCOME:
Interest 1,033 527
Other (income) deductions - net (2,523) (1,845)
(1,490) (1,318)
INCOME BEFORE INCOME TAXES 9,662 16,890
INCOME TAXES 1,446 4,498
ENTECH NET INCOME $ 8,216 $ 12,392
</TABLE>
ENTECH OPERATIONS:
Coal Operations:
Income from coal operations decreased $6,300,000 primarily as a result of
reduced revenues and coal volumes sold at the Rosebud Mine and lower coal
volumes sold at the Golden Eagle Mine due to production problems.
Revenues:
Revenues, including intersegment revenues, decreased with the majority
attributable to the Rosebud Mine, where volumes of coal sold to customers
decreased by 13%. Revenues from sales to two Midwestern customers decreased
$3,500,000 as the result of one customer taking fewer tons in the third quarter
of 1995 and the expiration of the second customer's contract at the end of
1994. The first Midwestern customer's purchases for 1995 are expected to be at
the same level as 1994. In addition, revenues from sales to Colstrip Units 1
and 2 decreased $3,400,000 due to reduced sales prices as a result of the
arbitration decision in 1995. Revenues from coal sales to Colstrip Units 3
and 4 decreased $1,600,000 for the same reasons included in the nine-month
discussion. Revenues also decreased $1,200,000 due to the conclusion of coal
brokering agreements in December 1994. Coal sold under brokering agreements
was sold at cost. At the Golden Eagle Mine revenues decreased $1,900,000 for
the same reasons mentioned in the nine-month discussion.
Expenses:
The decrease in cost of sales includes the net impact of $3,300,000
decreased mining costs at the Rosebud Mine for the same reasons mentioned in
the nine-month discussion. Also, mining costs at the Golden Eagle Mine
decreased $1,000,000 due to lower volumes sold for the same reasons mentioned
in the nine-month discussion. These costs were partially offset by $1,400,000
increased costs at the Jewett Mine for reimbursable royalties and surface
damage payments. Selling, general and administrative expenses decreased
$1,200,000 from less use of outside services. Taxes other than income taxes
decreased $1,500,000 due to lower revenues at the Rosebud Mine.
Oil and Natural Gas Operations:
Income from oil and natural gas operations decreased principally due to
lower natural gas prices and volumes sold, partially offset by increased
volumes of and higher margins on gas sold under cogeneration supply agreements.
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 $ -
-volume (7)%
-price/bbl (1)%
Natural gas -revenue $ (3)
-volume (19)%
-price/Mcf (19)%
Natural gas marketing -revenue $ 3
-volume 13%
-price/Mcf 10%
Revenues:
Natural gas revenues decreased $2,700,000 from both lower prices and
decreased volumes. This decrease in volumes reflects wells that were shut-in
in the U.S. due to low prices and producing properties sold in 1995. Revenues
from natural gas marketing increased $2,800,000 due to the same reasons
mentioned in the nine-month discussion.
Expenses:
The higher volumes of natural gas purchased for resale increased the cost
of sales by $1,100,000.
Other Operations:
Income from other operations increased from telecommunications
operations, income from land sales and lower corporate association fees.
Interest Expense and Other Income:
The increases in interest expense and other income were for the same
reasons mentioned in the nine-month discussion.
INDEPENDENT POWER GROUP OPERATIONS
<TABLE>
<CAPTION>
Three Months Ended
September 30,
1995 1994
Thousands of Dollars
<S> <C> <C>
REVENUES:
Revenues $ 20,170 $ 27,199
Earnings from unconsolidated investments 1,353 26
Intersegment revenues 93 179
21,616 27,404
EXPENSES:
Operation and maintenance 17,332 19,865
Selling, general and administrative 1,093 908
Taxes other than income taxes 511 466
Depreciation and amortization 740 590
19,676 21,829
INCOME FROM OPERATIONS 1,940 5,575
INTEREST EXPENSE AND OTHER INCOME:
Interest 10 5
Other (income) deductions - net (889) (3,045)
(879) (3,040)
INCOME BEFORE INCOME TAXES 2,819 8,615
INCOME TAXES 1,134 2,856
IPG NET INCOME $ 1,685 $ 5,759
</TABLE>
INDEPENDENT POWER GROUP OPERATIONS:
IPG net income for the quarter decreased primarily as a result of a
decline in project development activities and the 1994 gain on the sale of a
50% interest in NAES which were partially offset by increased earnings from
investments in operating independent power projects.
Revenues:
The $7,000,000 decrease in IPG revenues results from a decrease in power
project development fees as presented in the nine-month discussion. Also as
previously discussed, the decrease for the quarter was partially offset by an
increase in earnings from investments in operating independent power projects.
Expenses:
IPG operation and maintenance expense decreased $2,500,000. The decrease
results principally from a $1,800,000 decrease in power project development
expenses and a $700,000 decrease in power supply and maintenance expenses at
the Colstrip unit as presented in the nine-month discussion.
Interest Expense and Other Income:
The decrease in other income for the quarter results from the gain on the
sale of a 50% interest in NAES in 1994 which was partially offset by an
increase in interest income.
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, and Entech's
capital expenditures for the same period have been reduced by approximately
30%, from $441,000,000 to $306,000,000. During the first nine months of 1995,
$99,850,000 was expended for the Utility construction program and $40,078,000
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.
In July 1995, Entech borrowed $10,000,000 at an interest rate of 6.4375%
under their Revolving Credit and Term Loan Agreement, which expires in
September 1997.
The Company's Mortgage and Deed of Trust contains certain restrictions
upon the issuance of additional First Mortgage Bonds. At September 30, 1995,
the unfunded net property additions and retired bonds test, which is the most
restrictive test, would have permitted the issuance of approximately
$540,000,000 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 September 30, 1995, the Company's ratio of
earnings to fixed charges was 2.84 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 the Company's financial
position or results of operations has not been determined.
UTILITY INDUSTRY RESTRUCTURING
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.
The Company's Electric Utility continues to analyze how it might be
affected by the proposal. The Utility submitted comments which generally
supported the concepts contained in the NOPR but suggested some modifications
to the transmission tariffs. The Company emphasized its support for the
Commission's position on stranded costs.
The Montana Public Service Commission initiated a Notice of Inquiry that
is designed to solicit comments concerning the changing electric utility
industry. Parties submitted a suggested list of issues and the Commission
issued the final list on October 6, 1995. Parties have until December 11,
1995, to submit their initial comments on the issues. Reply comments are due
January 5, 1996, and an informal discussion is planned for January 31, 1996.
During 1995 the Company became a charter member of the Western Regional
Transmission Association (WRTA) and the Northwest Regional Transmission
Association (NRTA). Both organizations are Regional Transmission Groups (RTGs)
certified by FERC to foster transmission access for wholesale power
transactions. The Company has also been an active participant in discussions
with other interested parties about the formation of a single-operator
transmission system for the Pacific Northwest region. The form of ownership
for such an entity, if it forms, has not been determined. In part to meet its
obligations as a WRTA member, the Company filed open access transmission
tariffs with FERC on November 10, 1995. The Company expects to submit an
application to FERC to create an affiliated power marketing subsidiary by mid-
November 1995.
CORPORATE RESTRUCTURING
With approval of Company directors, a corporate restructuring is being
explored which would be aimed at two major activities: energy supply and energy
services. Additional information will be provided as details become available.
PART II
Other Information
ITEM 1. Legal Proceedings
Colstrip Units 1 and 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 Units 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 has decreased 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 1995, Western refunded approximately
$11,700,000, 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 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.
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.
Frederickson Litigation
Through one of its IPG subsidiaries which owns 25% of a power development
partnership, the Company is participating in litigation filed in U.S. Court of
Federal Claims against the Bonneville Power Administration (BPA). The suit,
filed by the power development partnership, alleges the BPA breached 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 acknowledged responsibility to pay
some measure of damages resulting from its decision. On October 24, 1995, the
federal court ordered the parties to submit this matter to arbitration. The
court retained jurisdiction pending the arbitration. The partnership, which
includes the IPG's subsidiary, is pursuing this matter aggressively.
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
September 30, 1995.
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K
DATE SUBJECT
July 26, 1995 Item 5 Other Events. Discussion of Second
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements of
Income for the Quarters Ended June 30, 1995
and 1994, Six Months Ended June 30, 1995 and
1994, and for the Twelve Months Ended June 30,
1995 and 1994; Utility Operations Schedule of
Revenues and Expenses for the Quarters Ended
June 30, 1995 and 1994, Six Months Ended
June 30, 1995 and 1994, and for the Twelve
Months Ended June 30, 1995 and 1994; Entech
Operations Schedule of Revenues and Expenses
for the Quarters Ended June 30, 1995 and 1994,
Six Months Ended June 30, 1995 and 1994, and
for the Twelve Months Ended June 30, 1995 and
1994; and Independent Power Group Operations
Schedule of Revenues and Expenses for the
Quarters Ended June 30, 1995 and 1994, Six
Months Ended June 30, 1995 and 1994, and for
the Twelve Months Ended June 30, 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)
/s/ J. P. Pederson
J. P. Pederson
Vice President and Chief
Financial Officer
Date: November 14, 1995
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended September 30, 1995
Exhibit 27
Financial Data Schedule
- -4-
- -8-
- -38-
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
September 30,
1995
Net Income $ 105,800
Income Taxes 48,511
$ 154,311
Fixed Charges:
Interest $ 46,515
Amortization of Debt Discount,
Expense and Premium 1,603
Rentals 35,876
$ 83,994
Earnings Before Income Taxes
and Fixed Charges $ 238,305
Ratio of Earnings to Fixed Charges 2.84x
Exhibit 12
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