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, 1997
-- 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 5, 1997, the Company had 54,624,636 shares of common stock
outstanding.
<TABLE>
<CAPTION>
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
For Three Months Ended
March 31, March 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
REVENUES $ 281,052 $ 264,405
EXPENSES:
Operations 104,342 105,031
Maintenance 17,964 16,093
Selling, general and administrative 27,123 24,484
Taxes other than income taxes 25,298 22,680
Depreciation, depletion and amortization 22,956 20,755
197,683 189,043
INCOME FROM OPERATIONS 83,369 75,362
INTEREST EXPENSE AND OTHER INCOME:
Interest 12,563 11,986
Other (income) deductions-net (4,817) (741)
7,746 11,245
INCOME TAXES 28,045 23,802
NET INCOME 47,578 40,315
DIVIDENDS ON PREFERRED STOCK 923 1,807
DISTRIBUTIONS ON COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY TRUST 1,373 0
NET INCOME AVAILABLE FOR COMMON STOCK $ 45,282 $ 38,508
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,634 54,639
NET INCOME PER SHARE OF COMMON STOCK $ 0.83 $ 0.70
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
March 31, December 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $55,653 and $52,125
plant under construction)
Electric $ 1,774,194 $ 1,764,702
Natural gas 517,410 516,693
2,291,604 2,281,395
Less - accumulated depreciation and depletion 721,341 705,119
1,570,263 1,576,276
NONUTILITY PROPERTY (includes $47,721 and $39,252
property under construction) 658,593 666,679
Less - accumulated depreciation and depletion 247,319 256,489
411,274 410,190
1,981,537 1,986,466
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 52,608 53,035
Reclamation fund 44,893 43,001
Other 40,526 39,531
138,027 135,567
CURRENT ASSETS:
Cash and temporary cash investments 25,604 32,404
Accounts receivable 121,915 142,347
Materials and supplies (principally at average cost) 39,913 39,322
Prepayments and other assets 50,597 46,408
Deferred income taxes 11,133 11,095
249,162 271,576
DEFERRED CHARGES:
Advanced coal royalties 19,662 19,298
Regulatory assets related to income taxes 149,161 149,150
Regulatory assets - other 65,849 66,688
Other deferred charges 71,187 69,470
305,859 304,606
$ 2,674,585 $ 2,698,215
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<CAPTION>
L I A B I L I T I E S
March 31, December 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,634,994 and
54,630,994 shares issued) $ 691,924 $ 691,853
Retained earnings and other shareholders' equity 330,456 307,804
Unallocated stock held by trustee for retirement
savings plan (27,777) (28,360)
994,603 971,297
Preferred stock 57,654 57,654
Company obligated mandatorily redeemable preferred
securities of subsidiary trust, which holds solely,
company junior subordinated debentures 65,000 65,000
Long-term debt 617,670 633,339
1,734,927 1,727,290
CURRENT LIABILITIES:
Short-term borrowing 45,262 104,702
Long-term debt - portion due within one year 40,384 69,268
Dividends payable 22,617 22,707
Income taxes 36,391 11,083
Other taxes 59,565 41,667
Accounts payable 56,290 62,218
Interest accrued 14,894 11,909
Accrued lease payments 7,920
Other current liabilities 43,047 41,155
326,370 364,709
DEFERRED CREDITS:
Deferred income taxes 338,439 332,861
Investment tax credit 44,049 44,467
Accrued mining reclamation costs 132,170 129,878
Other deferred credits 98,630 99,010
613,288 606,216
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,674,585 $ 2,698,215
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
For Three Months Ended
March 31, March 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 47,578 $ 40,315
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 22,956 20,755
Deferred income taxes 5,152 1,933
Noncash earnings form unconsolidated
independent power investments. (2,860) (2,429)
Reclamation expensed and paid - net 2,292 1,169
Other noncash charges to net income - net 2,563 4,850
Changes in other assets and liabilities:
Accounts receivable 20,432 20,839
Materials and supplies (591) 107
Accounts payable (5,928) (10,594)
Accrued lease payments 7,920 (7,920)
Other - net 37,802 34,422
Net cash provided by operating activities 137,316 103,447
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (28,391) (21,940)
Reclamation funding (1,892)
Sales of property 15,442 (126)
Additional investments (898) (711)
Net cash used by investing activities (15,739) (22,777)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (22,775) (23,689)
Distributions on mandatorily redeemable preferred
securities of subsidiary trust (1,373)
Sales of common stock 61 832
Issuance of long-term debt (170)
Retirement of long-term debt (44,615) (10,805)
Issuance of mandatorily redeemable preferred
securities of subsidiary trust (65)
Net change in short-term borrowing (59,440) (46,536)
Net cash used by financing activities (128,377) (80,198)
CHANGE IN CASH FLOWS (6,800) 472
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 32,404 15,541
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 25,604 $ 16,013
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Three Months For:
Income taxes $ 1,114 $ 1,117
Interest 9,597 10,547
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, 1997 and 1996 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, 1996.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1997 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, wildlife and
habitat affected by the operation of the 180 megawatt Kerr Project (Project),
which would cost the Company $15,600,000 initially and, thereafter, $965,000
annually. Management's estimate of the initial cost has been capitalized to
plant. The United States Department of Interior (Department) has proposed an
alternative to the plan, which the Company estimates would cost approximately
$35,000,000 initially and, thereafter, $1,300,000 annually. An Environmental
Impact Statement prepared by the FERC staff concludes that the Department's
alternative is preferable, from an environmental perspective, to the Company's
plan. In addition to requiring expenditures for environmental mitigation
which are not included in the Company's plan, the alternative proposed by the
Department would change the operation of the Project from a peaking to a
baseload operation. This matter is pending FERC's decision, which is expected
in 1997. The Company cannot predict what FERC's decision might be.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. The net present value of relicensing and environmental mitigation
is estimated to be approximately $158,000,000. The FERC staff is expected to
issue a draft environmental impact statement in mid-1997. The Company expects
to receive a license order in late 1998 or early 1999. The majority of the
cost is capital for physical improvements, which is not expected to be spent
before 2006.
In 1994, the Company entered an agreement to purchase 98 megawatts of
capacity during the winter months from Basin Electric Power Cooperative
(Basin), delivery of which was to begin in November 1996. The purchase
obligation under the agreement was from November 1, 1996 to April 30, 2010.
Under the terms of the agreement, the Company would have purchased seasonal
power between November and April of each year at a cost estimated to be
approximately $11,200,000 in 1997 and escalating annually, pursuant to the
contract. On October 31, 1996, the Company notified Basin of the Company's
rescission of the agreement as a consequence of Basin's refusal to provide
electricity at the delivery points the Company had requested under the terms
of the agreement without imposing unacceptable precedent conditions. On
November 5, 1996, Basin sued the Company in the Federal District Court for the
Southwestern District of North Dakota seeking specific performance, a stay of
the litigation and an order compelling the Company to arbitrate the dispute.
On March 20, 1997, the court ordered that all claims and counterclaims, except
counterclaims against Basin regarding antitrust and wrongful interference with
business or trade, be sent immediately to arbitration. All litigation is
stayed pending further order of the court. While it is continuing to prepare
for arbitration, the Company is discussing with Basin potential settlement of
the matter. As of March 31, 1997, the Company did not accrue $6,300,000 that
would have been payable under the rescinded agreement. The outcome cannot be
predicted at this time.
Western Energy Company (Western), a subsidiary of the Company, is a
party in a dispute concerning the Coal Supply Agreement for Colstrip Units 3
and 4 with the non-operating owners (NOOs), other than Puget Sound Energy,
Inc. (Puget). Puget withdrew from this dispute as part of a settlement
concerning a power sales agreement between Puget and the Company. During the
spring of 1996, the Consumer Price Index (CPI) doubled when compared to the
CPI level at the time that the Coal Supply Agreement was executed. Under the
terms of the Coal Supply Agreement, this change in the CPI allows any party to
seek a modification of the coal price if that party can demonstrate that an
"unusual condition" has occurred causing a "gross inequity." These NOOs are
asserting that a number of "unusual conditions" have occurred, including (i)
the deregulation of various aspects of the electric utility industry, (ii)
increased scrutiny of electric utilities by their public utility commissions,
and (iii) changes in economic conditions not anticipated at the time of
execution of the Coal Supply Agreement. These NOOs claim these "unusual
conditions" have created a "gross inequity" that must be remedied by a
reduction in the coal price. Western disputes that any "unusual condition" or
"gross inequity" has occurred. Western, the Company and these NOOs are
considering whether this dispute may be resolved as part of a proposed effort
to restructure the relationship of the NOOs, including Puget, the Company and
Western at the Colstrip Project. The outcome of this dispute or the
restructuring proposal cannot be predicted at this time.
Houston Lighting & Power (HL&P), the purchaser of lignite produced by
Northwestern Resources Co. (Northwestern), a Company subsidiary, has filed
litigation in the District Court of the 157th Judicial District, Harris
County, Texas, seeking, among other remedies, a declaratory judgment that
changed conditions require a renegotiation of management and dedication fees
paid to Northwestern under the terms of the Lignite Sales Agreement (LSA)
between it and Northwestern. The LSA governs the delivery of approximately
8,000,000 tons of lignite per year and is effective until July 29, 2015. Under
the terms of the LSA, Northwestern realizes approximately $25,000,000 per year
from these fees. HL&P alleges Northwestern failed to renegotiate these fees
in good faith as HL&P alleges the agreement requires. As its remedy, HL&P
seeks to terminate the LSA or, alternatively, asks the court to declare
reasonable fees. HL&P is seeking an approximate 60% reduction in these fees
and alleges that the reduction should be retroactive to September 1, 1995.
Additionally, HL&P is seeking a declaration that it may substitute other fuels
for lignite without violating the LSA. If HL&P does not have this right, it
further seeks a declaration that the absence of this right constitutes a gross
inequity, which entitles HL&P to have the court reform the LSA to provide the
right to substitute fuels. Finally, HL&P alleges that the parties were
mutually mistaken regarding the quantity and the quality of lignite dedicated
to the LSA and, consequently, the original bargain has been so altered that
either no agreement was made or the agreement should be reformed.
Northwestern disputes HL&P's claims and does not believe the Texas
district court has jurisdiction to make the declarations HL&P is seeking.
Trial is expected to begin in September 1997. The outcome of this litigation
cannot be predicted at this time.
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.
On February 28, 1997, the Company, through a Nonutility oil and natural
gas subsidiary, North American Resources Company (NARCO), signed agreements
for the acquisition of $85,000,000 of oil and natural gas assets from Vessels
Energy, Inc. (Vessels). These assets, in the Denver-Julesburg Basin north of
Denver, will allow NARCO to double its production of oil, natural gas and
natural gas liquids in that area. On April 23, 1997, NARCO acquired
$41,000,000 of Vessels' gathering, transmission and processing assets and also
acquired an option, exercisable through year-end, to purchase $44,000,000 of
Vessels' exploration and production assets. The acquisition will be financed
internally from the oil and natural gas operations and by the use of short-
term bank financing. The Company intends to sell non-strategic oil and natural
gas assets in a manner that allows it to acquire the exploration and
production properties of Vessels in a transaction that will qualify as a like-
kind exchange under the Internal Revenue Code.
NOTE 2 - RATES, REGULATORY AND LEGISLATIVE MATTERS:
Electric:
The Company has been promoting a transition to retail electric
competition over the next several years. Montana's "Electric Industry
Restructuring and Customer Choice Act", which was supported by the Company and
others, has been passed by the Montana Legislature and was signed into law by
the Governor in May 1997.
The legislation provides for choice of electricity supplier for the
Company's customers; by July 1, 1998 for large customers, for pilot programs
for other customers by July 1, 1998 and choice for all customers no later than
July 1, 2002. Transmission and distribution services will remain fully
regulated by FERC and the Montana Public Service Commission (PSC). Generation
assets will be removed from rate base on July 1, 1998 and costs will be
reflected in utility operations through a cost-based contract through July 1,
2002 for those customers that do not have choice or have not selected a
competitive based supplier. For those customers that exercise choice during
the transition period there would be a transition charge for generation costs
above market. Generation assets will compete for customers that have choice
during the transition period and will be expected to fully compete in an
unregulated market after the transition period is complete. Electric rates for
all customers will be frozen for two years beginning July 1, 1998, with the
electric-energy supply component frozen for an additional two years for
smaller customers.
The legislation allows for the recovery of transition costs,
specifically recovery of above-market qualifying facility power-purchase
contract costs and regulatory assets, and a four-year recovery period for
utility-owned above-market generation costs. The legislation authorizes the
use of transition bonds, subject to the approval of a financing order by the
PSC, as a method of financing transition obligations at lower costs. The
legislation also defines the role the PSC will have in regulating distribution
services, licensing electricity suppliers in the state, and promulgating rules
regarding anti-competitive and abusive practices. Finally, the legislation
provides for reciprocity between utility companies.
The legislation also states that utilities must file a transition plan
with the PSC one-year before any customer is entitled to choice. Consequently,
the Company is in the process of updating its December 20, 1996 electric
"informational filing" into a comprehensive transition plan filing for
submission to the PSC in July 1997. The filing will contain the Company's
four-year transition plan, and the proposed handling and resolution of
transition costs, as well as other issues required by the legislation. The PSC
will act on the filing, including the Company's efforts to mitigate transition
costs, and it will determine what amount of transition costs, subject to the
above mentioned legislative guidelines, the Company will be allowed to
recover.
As a result of a three-year rate plan approved by the PSC, electric
rates increased 4.2% or approximately $14,800,000 on July 1, 1996. The plan
also included revenue increases of 2.4% or approximately $8,800,000, effective
January 1, 1997. An additional 2.4% increase or approximately $9,000,000 is
scheduled on January 1, 1998.
Natural Gas:
The Natural Gas Restructuring Act was also passed by the Montana
Legislature and signed into law in May 1997. This legislation allows for
natural gas utilities to open their systems to full customer choice and also
for the issuance of transition bonds to lower transition costs to customers.
The legislation will facilitate the resolution of the natural gas
restructuring filing now before the PSC. The July 1996 filing had requested an
increase in natural gas revenues of $4,800,000 or 3.8% annually to recover
increased costs of service and had included a formal open-access and
restructuring plan. The plan proposed an increase in the number of customers
eligible to choose their own natural gas supplier, with all customers having
choice by mid-2002. The plan also requested recovery of natural gas production
and regulatory assets that will be uneconomic or stranded under full customer
choice. The procedural schedule for the filing was suspended subject to
continuing settlement efforts among the parties to the filing. Hearings on the
uncontested items were conducted in late March 1997. The procedural schedule
on the remaining unsettled matters recommenced in May 1997. A stipulation
addressing many of the remaining items, including stranded costs, has been
agreed-to by many of the contesting parties to the filing and has been
submitted to the PSC for approval. A hearing is scheduled for July 8, 1997. A
final decision is expected in the third quarter of 1997.
On July 1, 1996, natural gas rates increased 5.3% or approximately
$6,700,000 annually as a result of a PSC-approved rate order.
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS:
To manage Nonutility price risk, the Company uses a variety of derivative
financial instruments, including crude oil and natural gas swap, collar and cap
agreements, to hedge revenue from anticipated production and sales of oil and
natural gas. Under swap agreements, the Company receives or makes payments
based on the differential between a specified price and the market price of oil
or natural gas when the hedged transaction is settled. Under collar
agreements, the Company makes or receives monthly payments when the actual
price of oil or natural gas exceeds the ceiling or drops below the floor
established in the agreement. Under cap agreements, the Company makes or
receives monthly payments based on the differential between the actual price of
oil or natural gas and the cap established in the agreement. At March 31,
1997, the Company had cap agreements on approximately 30,000 barrels of crude
oil; 28% of its expected production from proved, developed and producing oil
reserves through April 1997. The Company had swap and cap agreements on
approximately 600 Mmcf of Nonutility natural gas; 9% of its expected production
from proved, developed and producing Nonutility reserves through October 1997.
In addition, the Company had swap and collar agreements to hedge approximately
3.4 Bcf of Nonutility natural gas; 27% of its expected delivery obligations
under long-term natural gas sales contracts through March 1998. At March 31,
1997, the Company had no material gains or losses from these transactions.
The Company also 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 natural
gas price fluctuations. At March 31, 1997, the Company believes it would not
experience any materially adverse impacts from the risks inherent in these
instruments.
NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST:
Montana Power Capital I (Trust) was established as a wholly owned
business trust of the Company for the purpose of issuing common and preferred
securities (Trust Securities) and holding Junior Subordinated Deferrable
Interest Debentures (Subordinated Debentures) issued by the Company. The Trust
has issued 2,600,000 units of 8.45% Cumulative Quarterly Income Preferred
Securities, Series A (QUIPS). Holders of the QUIPS are entitled to receive
quarterly distributions at an annual rate of 8.45% of the liquidation
preference value of $25 per security. The sole asset of the Trust is
$67,000,000 of Subordinated Debentures, 8.45% Series due 2036, issued by the
Company. The Trust will use interest payments received on the Subordinated
Debentures it holds to make the quarterly cash distributions on the QUIPS.
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, 1996.
Results of Operations:
The following discussion presents significant events or trends that have
had an effect on the operations of the Company or which are expected to have an
impact on operating results in the future.
Safe Harbor for Forward-Looking Statements:
The Company is including the following cautionary statements to make
applicable and take advantage of the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company in this Quarterly Report on Form 10-Q.
Forward-looking statements include statements concerning plans, objectives,
goals, strategies, future events or performance and underlying assumptions and
other statements which are other than statements of historical facts. Such
forward-looking statements may be identified, without limitation, by the use
of the words "anticipates", "estimates", "expects", "intends", "believes" and
similar expressions. From time to time, the Company or one of its subsidiaries
individually may publish or otherwise make available forward-looking
statements of this nature. All such forward-looking statements, whether
written or oral, and whether made by, or on behalf of, the Company or its
subsidiaries, are expressly qualified by these cautionary statements and any
other cautionary statements which may accompany the forward-looking
statements. In addition, the Company disclaims any obligation to update any
forward-looking statements to reflect events or circumstances after the date
hereof.
Forward-looking statements made by the Company are subject to risks and
uncertainties that could cause actual results or events to differ materially
from those expressed in, or implied by, the forward-looking statements. These
forward-looking statements include, among others, statements concerning the
Company's revenue and cost trends, cost recovery, cost-reduction strategies
and anticipated outcomes, pricing strategies, planned capital expenditures,
financing needs, and availability and changes in the utility industry.
Investors or other users of the forward-looking statements are cautioned that
such statements are not a guarantee of future performance by the Company and
that such forward-looking statements are subject to risks and uncertainties
that could cause actual results to differ materially from those expressed in,
or implied by, such statements. Some, but not all, of the risks and
uncertainties include general economic and weather conditions in the areas in
which the Company has operations, competitive factors and the impact of
restructuring initiatives in the electric and natural gas industry, market
prices, environmental laws and policies, federal and state regulatory and
legislative actions, drilling successes in oil and natural gas operations,
changes in foreign trade and monetary policies, laws and regulations related
to foreign operations, tax rates and policies, rates of interest and changes
in accounting principles or the application of such principles to the Company.
For the Quarters Ended March 31, 1997 and 1996:
Net Income Per Share of Common Stock:
Net income for the quarter ended March 31, 1997 was 83 cents per share,
a 19% increase over the first quarter 1996.
Nonutility earnings increased 11 cents per share due primarily to
significantly higher market prices for oil and natural gas in the U.S. and
Canada and increased production. Oil production increased nearly 9% due in
part to a waterflood injection project initiated in 1996 while average oil
prices increased 45%. Natural gas sales volumes increased 6% and average
natural gas prices increased 32%. These increases and a $2,200,000 after-tax
gain on property dispositions boosted net income approximately $6,300,000. The
price of coal sold to Puget decreased due to the settlement of a dispute with
Puget. This was more than offset by increased sales volumes from the Rosebud
and Jewett Mines resulting in a slight increase in earnings from coal
operations.
Utility earnings for the first quarter increased slightly over 1996
primarily due to increased natural gas revenues resulting from higher rates
and customer growth, higher margins on increased brokering activities, and
reduced power-supply expenses. These positives were largely offset by reduced
retail electric and natural gas volumes sold due to weather 10% warmer than
1996 and costs related to permanent employee reductions, increased property
taxes and depreciation expenses.
In November 1996, the Company through its subsidiary trust, issued
$65,000,000 of QUIPS on which it is paying quarterly cash distributions.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share by principal business segment.
Quarter Ended
March 31, March 31,
1997 1996
Utility Operations $ 0.52 $ 0.50
Nonutility Operations 0.31 0.20
Consolidated $ 0.83 $ 0.70
</TABLE>
<TABLE>
<CATPION>
UTILITY OPERATIONS
For Three Months Ended
March 31, March 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 121,690 $ 119,887
Intersegment revenues 1,337 2,028
123,027 121,915
EXPENSES:
Power supply 35,566 41,746
Transmission and distribution 7,975 7,459
Selling, general and administrative 14,205 11,313
Taxes other than income taxes 12,979 11,938
Depreciation and amortization 13,214 11,547
83,939 84,003
INCOME FROM ELECTRIC OPERATIONS 39,088 37,912
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 40,228 37,888
Gas supply cost revenues 6,852 10,076
Intersegment revenues 233 207
47,313 48,171
EXPENSES:
Gas supply costs 6,852 10,076
Other production, gathering and exploration 2,467 2,366
Transmission and distribution 2,876 3,070
Selling, general and administrative 4,757 4,348
Taxes other than income taxes 4,309 4,012
Depreciation, depletion and amortization 3,256 2,931
24,517 26,803
INCOME FROM NATURAL GAS OPERATIONS 22,796 21,368
INTEREST EXPENSE AND OTHER INCOME:
Interest 12,138 11,740
Other (income) deductions - net (755) (495)
11,383 11,245
INCOME BEFORE INCOME TAXES 50,501 48,035
INCOME TAXES 20,209 19,027
UTILITY NET INCOME $ 30,292 $ 29,008
</TABLE>
UTILITY OPERATIONS:
Weather affects the demand for electricity and natural gas, especially
among residential and commercial customers. Very cold winters increase demand,
while mild weather reduces demand. The weather's effect is measured using
degree-days. A degree-day is the difference between the average daily actual
temperature and a baseline temperature of 65 degrees. Heating degree-days
result when the average daily actual temperature is less than the baseline. As
measured by heating degree days, the temperatures for the first quarter of 1997
in the Company's service territory were 10% warmer than 1996 and 1% warmer than
the historic average.
Weather, streamflow conditions and the wholesale power markets in the
Northwest and California influence the Company's electric wholesale revenues
and power-purchase expenses. The surplus of hydroelectric power that existed
in the region during 1996 continued in 1997, keeping purchased-power prices
low during the first quarter. The abundance of hydroelectricity in the region
is expected to continue into the summer months. Spring run-off to date is
below what was anticipated. The extended availability of hydroelectricity may
result in low-cost purchase-power prices that could displace higher-cost
thermal generation.
As a result of the legislation recently enacted in Montana, the Company
intends to submit a filing with Montana regulators in July 1997 to implement
customer choice of electric supply for its retail customers. As required by
the legislation, the Company's electric generation assets will be removed from
rate base on July 1, 1998. Generation from the assets will continue to be
provided to customers without competitive choice selections through a four-
year transition contract. For those customers that exercise choice during
the transition period there would be a transition charge for generation costs
above market. After the transition period, the generation is expected to
compete in an unregulated market. As a result of the restructuring, Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation" will no longer be applicable to the generation
assets of the Company. The Company is examining the appropriate timing and
extent of the discontinuance of SFAS No. 71 in light of recent opinions
expressed by the Securities and Exchange Commission (SEC) that question the
continued applicability of SFAS No. 71 in states that have adopted
restructuring legislation even where the recovery of transition costs is
provided through a statutory funding mechanism.
Under the legislation passed in Montana for electric utilities,
regulatory assets previously related to the supply function are recoverable as
transition costs. The settlement stipulation on natural gas would also allow
for recovery of regulatory assets. As such, it is the Company's belief that
these assets will continue to be regulated and that SFAS No. 71 continues to
apply.
The Financial Accounting Standards Board's (FASB) Emerging Issues Task
Force (EITF) is expected to issue additional guidance on restructuring during
the second or third quarter of 1997. In the event that the SEC or the EITF
would rule that regulatory assets are no longer governed by SFAS No. 71, a
noncash write-off of up to $210,000,000 may be required.
Preliminary calculations required by SFAS No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" do
not indicate a need for any material write-off of physical generation or
natural gas production assets.
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh)
3/31/97 3/31/96 3/31/97 3/31/96 3/31/97 3/31/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 73,867 $ 70,451 5 % 1,142 1,146 0 % 272,287 267,519 2 %
Industrial 26,320 29,691 (11)% 603 608 (1)% 2,334 2,292 2 %
Government 2,141 1,995 7 % 26 27 (4)% 3,055 3,243 (6)%
General Business 102,328 102,137 0 % 1,771 1,781 (1)% 277,676 273,054 2 %
Sales to Other
Utilities 16,615 14,407 15 % 898 859 5 % 84 74 14 %
Other 2,747 3,343 (18)%
Intersegment 1,337 2,028 (34)% 46 142 (68)% 228 233 (2)%
Total 123,027 121,915 1 % 2,715 2,782 (2)% 277,988 273,361 2 %
Power Supply
Expenses:
Hydroelectric 5,057 4,643 9 % 1,083 1,135 (5)%
Steam 11,459 11,487 0 % 1,040 1,006 3 %
Purchases
and Other 19,050 25,616 (26)% 847 885 (4)%
Total Power Supply $ 35,566 $ 41,746 (15)% 2,970 3,026 (2)%
Cents Per kWh $1.198 $1.379
</TABLE>
Income from electric operations during the first quarter 1997 increased
approximately $1,200,000, or 3 percent, compared to 1996 primarily due to
higher prices on sales to other utilities combined with reduced costs per kWh
for power supply expenses.
The Company realized better margins on its increased volumes of secondary
energy purchased for resale, more than offsetting the decreased revenues
resulting from the expiration of a firm sales contract in early 1996. Purchased
power costs declined largely due to the expiration of two higher-priced firm
contracts. Revenues from general business customers remained relatively
unchanged for the quarter. Rate design changes and warmer weather largely
offset higher tariffs implemented in 1996 and 1997 and increased customer
growth. Rate design changes are expected to increase revenues in the second and
third quarters and decrease revenues in the first and fourth quarters. The
Company also accrued approximately $1,500,000 of 1997 employee severance costs
increasing selling, general and administrative expenses. The increase in taxes
other than income taxes was due to increased property taxes resulting from
property additions. Depreciation expense increased as a result of greater plant
investment and a change in the PSC-approved depreciation rate.
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf)
3/31/97 3/31/96 3/31/97 3/31/96 3/31/97 3/31/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential
and Commercial $ 41,600 $ 42,375 (2)% 9,286 9,501 (2)% 141,181 136,824 3 %
Industrial 1,020 1,086 (6)% 238 255 (7)% 426 420 1 %
Government 328 339 (3)% 94 104 (10)% 16 17 (6)%
Subtotal 42,948 43,800 (2)% 9,618 9,860 (2)% 141,623 137,261 3 %
Gas Supply Cost
Revenues (GSC) (6,852) (10,076) (32)%
General Business
without GSC 36,096 33,724 7 % 9,618 9,860 (2)% 141,623 137,261 3 %
Sales to Other
Utilities 353 357 (1)% 167 127 31 % 3 3 0 %
Transportation 2,545 2,455 4 % 8,015 6,759 19 % 33 30 10 %
Other 1,234 1,352 (9)%
Total $ 40,228 $ 37,888 6 % 17,800 16,746 6 % 141,659 137,294 3 %
</TABLE>
Revenues from general business customers increased during the first
quarter of 1997 primarily due to higher tariff rates, residential and
commercial customer growth, offset by reduced volumes sold due to the warmer
weather experienced during the period. Gas supply cost revenues and expenses
of $6,852,000, which are always equal due to rate and accounting procedures,
decreased due to reduced volumes sold, lower commodity costs and the
amortization of prior period over-collections.
<TABLE>
<CAPTION>
NONUTILTY OPERATIONS
For Three Months Ended
March 31, March 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 42,574 $ 38,390
Intersegment revenues 7,876 8,197
50,450 46,587
EXPENSES:
Operations and maintenance 29,708 27,536
Selling, general and administrative 4,611 5,135
Taxes other than income taxes 5,819 5,375
Depreciation, depletion and amortization 1,494 1,143
41,632 39,189
INCOME FROM COAL OPERATIONS 8,818 7,398
OIL AND NATURAL GAS:
REVENUES:
Revenues 42,356 29,063
Intersegment revenues 106 99
42,462 29,162
EXPENSES:
Operations and maintenance 24,469 17,649
Selling, general and administrative 2,250 2,426
Taxes other than income taxes 1,560 834
Depreciation, depletion and amortization 4,300 3,953
32,579 24,862
INCOME FROM OIL AND NATURAL GAS OPERATIONS 9,883 4,300
INDEPENDENT POWER:
REVENUES:
Revenues 17,198 19,717
Earnings from unconsolidated investments 3,025 2,709
Intersegment revenues 817 69
21,040 22,495
EXPENSES:
Operations and maintenance 15,904 16,612
Selling, general and administrative 1,089 822
Taxes other than income taxes 495 431
Depreciation, depletion and amortization 305 784
17,793 18,649
INCOME FROM INDEPENDENT POWER OPERATIONS $ 3,247 $ 3,846
<CAPTION>
NONUTILITY OPERATIONS (continued)
For Three Months Ended
March 31, March 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 7,004 $ 6,315
Intersegment revenues 181
7,185 6,315
EXPENSES:
Operations and maintenance 4,835 4,164
Selling, general and administrative 1,635 1,295
Taxes other than income taxes 136 91
Depreciation, depletion and amortization 254 223
6,860 5,773
INCOME FROM TELECOMMUNICATIONS OPERATIONS 325 542
OTHER OPERATIONS:
REVENUES:
Revenues 162 235
Intersegment revenues 290 136
452 371
EXPENSES:
Operations and maintenance 1,698 264
Selling, general and administrative (590) (64)
Depreciation, depletion and amortization 133 174
1,241 374
LOSS FROM OTHER OPERATIONS (789) (3)
INTEREST EXPENSE AND OTHER INCOME:
Interest 1,112 929
Other (income) deductions - net (4,750) (929)
(3,638) 0
INCOME BEFORE INCOME TAXES 25,122 16,083
INCOME TAXES 7,836 4,776
NONUTILITY NET INCOME $ 17,286 $ 11,307
</TABLE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations increased as a result of increased volumes
sold at both the Rosebud and Jewett Mines. Revenues from the Rosebud Mine
increased $2,000,000. The increase in volumes sold to Colstrip Units 3 & 4
more than offset decreases caused by a price reduction resulting from the
settlement of a dispute with Puget and decreased volumes sold to Colstrip
Units 1 & 2 and the Corette Plant. The Corette Plant switched fuel suppliers
in early 1996 for early compliance with air quality standards. Jewett mine
revenues increased $1,900,000 due to a 23% increase in volumes of lignite
sold. Coal volumes sold to the Colstrip units throughout the remainder of the
year may be affected if thermal generation is displaced due to the
availability of low-cost hydroelectric power in the region.
Operating expenses increased primarily as a result of increases in
maintenance and royalty expenses associated with the increased volumes sold at
both mines.
Oil and Natural Gas Operations:
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 $ 3
-volume 9%
-price/bbl 45%
Natural gas -revenue $ 9
-volume 6%
-price/Mcf 32%
Miscellaneous $ 1
Income from the oil and natural gas operations improved due to
significantly higher market prices for oil and natural gas. Natural gas
revenues increased $9,400,000. Revenues from oil operations in the U.S.
increased $2,500,000 due to increased production resulting from a waterflood
injection project initiated in 1996 and other additional production from
existing wells along with significantly higher market prices.
Expenses of oil and natural gas operations increased due to higher
prices on natural gas purchases and increased production costs associated with
higher volumes.
Independent Power Operations:
Income from independent power operations decreased primarily as a result
of decreased revenues from Colstrip Unit 4 long-term power sales due to the
settlement of a dispute with Puget and decreased volumes sold. Partially
offsetting the decrease was continued increases in income from independent
power investments and reduced project development costs.
Interest Expense and Other Income:
Other income increased due to a $4,200,000 gain realized on dispositions
of oil and natural gas properties. The increase was offset by increased costs
associated with a discontinued SynCoal? project.
LIQUIDITY AND CAPITAL RESOURCES:
On January 2, 1997, $5,000,000 of the 8.9% Series A Unsecured Medium-
Term Notes matured. The Company used short-term borrowings to retire the
Notes.
During the first quarter 1997, $35,000,000 borrowed under a Nonutility
Revolving Credit Agreement was repaid.
On April 4, 1997, the Company negotiated a Revolving Credit Agreement
for certain of its Nonutility operations. As a result, the Company's
consolidated borrowing capacity increased from $135,000,000 to $220,000,000.
Under terms of the agreement, the amount of the facility decreases on March
31, 1998, reducing the consolidated borrowing capacity to $160,000,000. On
April 22, 1997, the proceeds of a $50,000,000 borrowing under the new
Agreement were used to partially fund the acquisition of Vessels' assets. See
Note 1 to the Consolidated Financial Statements for further discussion of
Vessels.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended March 31, 1997, the Company's ratio of
earnings to fixed charges was 3.28 times. Fixed charges include interest,
distributions on preferred securities of a subsidiary trust, the implicit
interest of the Colstrip Unit 4 rentals and one-third of all other rental
payments.
NEW ACCOUNTING PRONOUNCEMENTS:
The FASB has issued SFAS No. 128, "Earnings Per Share", which is
effective for financial statements issued for periods ending after December
15, 1997, including interim periods. The new standard requires entities with
complex capital structures to present "basic EPS" and "dilutive EPS" on the
face of the income statement. Basic EPS is the same EPS presentation that is
currently included in the Company's consolidated income statement. The
computation of dilutive EPS includes all dilutive potential common shares that
were outstanding during the period. Based upon the computation methods
included in the new standard, the Company expects that dilutive EPS will not
differ significantly from basic EPS.
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
Basin Electric Power Cooperative Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
Houston Power & Light Lignite Sales Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 1" for additional information pertaining to legal proceedings.
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, 1997.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K
DATE SUBJECT
January 28, 1997 Item 5 Other Events. Discussion of Fourth
Quarter Net Income.
Item 7 Exhibits. Consolidated Statements
of Income for the Quarters Ended
December 31, 1996 and 1995 and for the
Years Ended December 31, 1996 and 1995.
Utility Operations Schedule of Revenues
and Expenses for the Quarters Ended
December 31, 1996 and 1995 and the Years
Ended December 31, 1996 and 1995.
Nonutility Operations Schedule of Revenues
and Expenses for the Quarters Ended
December 31, 1996 and 1995 and the Years
Ended December 31, 1996 and 1995.
February 21, 1997 Item 5. Other Events. Montana Power
Company and Puget Sound Power and Light
Resolve a Pending Litigation Matter.
February 28, 1997 Item 2. Acquisition or Disposition of
Assets. Montana Power Company, through
its subsidiary, North American Resources
Co., announced its commitment to purchase
Vessels Energy's oil and natural gas
assets in Colorado's Denver-Julesburg
Basin
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 and Information
Officer
Dated: May 15, 199
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended March 31, 1997
Exhibit 27
Financial data schedule
- - - -17-
- - - -22-
- - - -26-
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
March 31,1997
Net Income $ 126,016
Income Taxes 76,218
$ 202,234
Fixed Charges:
Interest $ 52,568
Amortization of Debt Discount,
Expense and Premium 1,632
Rentals 34,315
$ 88,515
Earnings Before Income Taxes
and Fixed Charges $ 290,749
Ratio of Earning to Fixed Charges 3.28 x
- - - -23-
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 3/31/97, the Consolidated Income Statement and
Consolidated Statement of Cash Flows for the three months ended 3/31/97 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-31-1997
<PERIOD-START> JAN-31-1997
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,570,263
<OTHER-PROPERTY-AND-INVEST> 549,301
<TOTAL-CURRENT-ASSETS> 249,162
<TOTAL-DEFERRED-CHARGES> 305,859
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,674,585
<COMMON> 691,924
<CAPITAL-SURPLUS-PAID-IN> 2,201
<RETAINED-EARNINGS> 300,478
<TOTAL-COMMON-STOCKHOLDERS-EQ> 994,603
65,000
57,654
<LONG-TERM-DEBT-NET> 611,605
<SHORT-TERM-NOTES> 45,262
<LONG-TERM-NOTES-PAYABLE> 4,634
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 39,650
0
<CAPITAL-LEASE-OBLIGATIONS> 1,431
<LEASES-CURRENT> 734
<OTHER-ITEMS-CAPITAL-AND-LIAB> 854,012
<TOT-CAPITALIZATION-AND-LIAB> 2,674,585
<GROSS-OPERATING-REVENUE> 281,052
<INCOME-TAX-EXPENSE> 28,045
<OTHER-OPERATING-EXPENSES> 197,683
<TOTAL-OPERATING-EXPENSES> 225,728
<OPERATING-INCOME-LOSS> 55,324
<OTHER-INCOME-NET> 4,817
<INCOME-BEFORE-INTEREST-EXPEN> 60,141
<TOTAL-INTEREST-EXPENSE> 12,563
<NET-INCOME> 47,578
2,296
<EARNINGS-AVAILABLE-FOR-COMM> 45,282
<COMMON-STOCK-DIVIDENDS> 21,850
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 137,316
<EPS-PRIMARY> 0.83
<EPS-DILUTED> 0.83
</TABLE>
