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, 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 November 7, 1997 the Company had 54,661,474 shares of common stock
outstanding.
<TABLE>
<CAPTION>
PART I
FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Nine Months Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
REVENUES $ 731,661 $ 678,397
EXPENSES:
Operations 288,812 276,920
Maintenance 60,631 49,810
Selling, general and administrative 86,761 75,036
Taxes other than income taxes 74,073 64,561
Depreciation, depletion and amortization 70,117 65,138
580,394 531,465
INCOME FROM OPERATIONS 151,267 146,932
INTEREST EXPENSE AND OTHER:
Interest 39,394 36,481
Distributions on preferred
securities of subsidiary trust 4,119
Other (income) deductions - net (13,742) (4,196)
29,771 32,285
INCOME TAXES 44,298 41,817
NET INCOME 77,198 72,830
DIVIDENDS ON PREFERRED STOCK 2,768 5,420
NET INCOME AVAILABLE FOR COMMON STOCK $ 74,430 $ 67,410
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,636 54,634
NET INCOME PER SHARE OF COMMON STOCK $ 1.36 $ 1.23
The accompanying notes are an integral part of these statements.
</TABLE>
<TABLE>
<CAPTION>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Quarter Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
REVENUES $ 234,240 $ 216,073
EXPENSES:
Operations 98,455 89,058
Maintenance 22,073 18,360
Selling, general and administrative 27,955 24,587
Taxes other than income taxes 24,767 21,751
Depreciation, depletion and amortization 24,198 23,032
197,448 176,788
INCOME FROM OPERATIONS 36,792 39,285
INTEREST EXPENSE AND OTHER:
Interest 13,958 12,803
Distributions on preferred
securities of subsidiary trust 1,373
Other (income) deductions - net (1,238) (1,745)
14,093 11,058
INCOME TAXES 6,458 9,998
NET INCOME 16,241 18,229
DIVIDENDS ON PREFERRED STOCK 923 1,807
NET INCOME AVAILABLE FOR COMMON STOCK $ 15,318 $ 16,422
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,645 54,632
NET INCOME PER SHARE OF COMMON STOCK $ 0.28 $ 0.30
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
September 30, December 31,
1997 1996
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $43,846 and $52,125
plant under construction)
Electric $ 1,846,430 $ 1,764,702
Natural gas 510,981 516,693
2,357,411 2,281,395
Less - accumulated depreciation and depletion 734,223 705,119
1,623,188 1,576,276
NONUTILITY PROPERTY (includes $73,055 and $39,252
property under construction) 714,043 666,679
Less - accumulated depreciation and depletion 251,917 256,489
462,126 410,190
2,085,314 1,986,466
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 49,241 53,035
Reclamation fund 46,607 43,001
Other 39,293 39,531
135,141 135,567
CURRENT ASSETS:
Cash and temporary cash investments 32,404
Accounts receivable 111,568 142,347
Notes receivable (Note 1) 30,944
Materials and supplies (principally at average cost) 40,122 39,322
Prepayments and other assets 33,961 26,063
Regulatory assets 19,064 20,345
Deferred income taxes 12,002 11,095
247,661 271,576
DEFERRED CHARGES:
Advanced coal royalties 19,611 19,298
Regulatory assets related to income taxes 149,523 149,150
Regulatory assets - other 64,437 66,688
Other deferred charges 71,857 69,470
305,428 304,606
$ 2,773,544 $ 2,698,215
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,
1997 1996
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares authorized;
54,650,901 and 54,630,994 shares issued) $ 692,464 $ 691,853
Retained earnings and other shareholders' equity 315,953 307,804
Unallocated stock held by trustee for retirement
savings plan (26,569) (28,360)
981,848 971,297
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 700,769 633,339
1,805,271 1,727,290
CURRENT LIABILITIES:
Short-term borrowing 75,008 104,702
Long-term debt - portion due within one year 76,405 69,268
Dividends payable 22,495 22,707
Income taxes 15,588 11,083
Other taxes 63,315 41,667
Accounts payable 49,219 62,218
Interest accrued 15,045 11,909
Deferred credits 18,381 10,621
Accrued lease payments 7,920
Other current liabilities 21,064 30,534
364,440 364,709
DEFERRED CREDITS:
Deferred income taxes 336,837 332,861
Investment tax credit 43,215 44,467
Accrued mining reclamation costs 129,507 129,878
Other deferred credits 94,274 99,010
603,833 606,216
CONTINGENCIES AND COMMITMENTS (Note 1)
$ 2,773,544 $ 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
Nine Months Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 77,198 $ 72,830
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 70,117 65,138
Deferred income taxes 2,444 3,937
Noncash earnings form unconsolidated
independent power investments. (7,648) (8,497)
Reclamation expensed and paid - net (371) 5,558
Other noncash charges to net income - net 21,624 (14,278)
Changes in other assets and liabilities:
Accounts and notes receivable (166) 52,818
Materials and supplies (799) 1,814
Accounts payable (5,077) (13,184)
Other - net (13,698) 20,444
Net cash provided by operating activities 143,624 186,580
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (197,302) (108,015)
Reclamation funding (3,606) (42,295)
Sales of property 48,407 6,187
Additional investments (135) (1,871)
Net cash used by investing activities (152,636) (145,994)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (68,326) (71,008)
Sales of common stock 529 813
Issuance of long-term debt 104,906 18,812
Retirement of long-term debt (30,740) (7,591)
Issuance of mandatorily redeemable preferred
securities of subsidiary trust (67)
Net change in short-term borrowing (29,694) 23,481
Net cash used by financing activities (23,392) (35,493)
CHANGE IN CASH FLOWS (32,404) 5,093
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 32,404 15,541
CASH AND CASH EQUIVALENTS, END OF PERIOD - $ 20,634
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Nine Months For:
Income taxes $ 27,614 $ 38,793
Interest 39,964 34,670
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 September 30, 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 July 1985, the Federal Energy Regulatory Commission (FERC) issued to
the Company a new license for the 180 megawatt Kerr Project (Project) and
required the subsequent adoption of conditions to mitigate the impact of
Project operations on fish, wildlife, and habitat. The Company proposed a
consensus plan in June 1990 that was agreed to by the Confederated Salish and
Kootenai Tribes (Tribes) and other state and federal resource agencies. In
November 1995, the United States Department of Interior (Department) submitted
alternative conditions to those stated in the Company's plan. This matter has
been pending FERC's consideration. For further information, see Item 8,
"Financial Statements and Supplementary Data - Note 2 to the Consolidated
Financial Statements" in the Company's Annual Report on Form 10-K for the year
ended December 31, 1996.
On June 25, 1997, FERC approved a mitigation plan, substantially adopting
the Department's conditions. FERC's order requires the Company to change
Project operations from peaking and load following to "baseload" generation.
The order requires the Company to make payments, beginning within 60 days of
the date of the order, to a fish and wildlife mitigation fund. The payments
are to be deposited in a separate interest-bearing account jointly held by the
Tribes and the Company and managed by a fiduciary according to the terms of an
escrow agreement. The Tribes, in consultation with the Company, may use moneys
in the fund for the benefit of fish and wildlife. Required payments include a
payment of approximately $15,600,000 for the period from 1985 to 1997, a two-
part "start-up" payment of $2,800,000 and $1,100,000, the second part due a
year from the date of the order, and annual payments of approximately
$1,400,000 payable through the end of the license term in 2035 or until the
Tribes elect to accept transfer of the license on or after 2015. In addition,
the order requires the Company to purchase approximately 6,800 acres of habitat
and build a revetment to minimize erosion at the north end of Flathead Lake.
The net present value of the total amount attributed to the mitigation plan is
approximately $57,000,000, which the Company recognized as license costs in
plant and long-term debt in the Consolidated Balance Sheet during the second
quarter 1997. FERC concluded that the Department's conditions adversely affect
the Project's economics, but that, under the Federal Power Act, it has no
authority to reject or modify them. FERC noted, however, that the
reasonableness of the Department's conditions may be appealed to the Federal
Court of Appeals for review.
On July 30, 1997, the Company obtained from FERC a stay of the
obligation to make the $15,600,000 payment and on August 25, 1997, the Company
paid into the fund, the "start-up" payment of $2,800,000 and the first annual
payment of $1,400,000, reducing the current portion of long-term debt. The
Company, the Tribes and the Department have requested rehearing. In the event
that FERC does not alter the order to correct the unreasonableness of the
Department's conditions, the Company expects to seek judicial review.
In November 1992, the Company applied to FERC to relicense nine Madison
and Missouri River hydroelectric projects, with generating capacity of 292
megawatts. On September 26, 1997, FERC Staff issued its draft environmental
impact statement, recommending acceptance of most of the measures proposed by
the Company in its application. FERC Staff recommended adoption of limited
additional measures. The Company is analyzing the recommendations to prepare
comments. Preliminary analysis suggests that the FERC staff's recommendations
do not materially change the cost of relicensing and proposed environmental
mitigation, previously estimated to be approximately $158,000,000 on a net
present value basis. The Company expects to receive a license order in late
1998 or early 1999.
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, under the terms of
the contract. In October 1996, the Company requested that Basin prepare to
deliver the electricity at alternative delivery points. Basin refused, and
the Company rescinded the agreement on October 31, 1996.
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. The
arbitration hearing concluded in October 1997. The arbitrator's decision is
expected by the end of the year. As of September 30, 1997, the Company had not
accrued approximately $7,900,000 that would have been payable under the terms
of the rescinded agreement. The outcome of this dispute 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
(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 does not believe that under the terms of
the contract any "unusual condition" or "gross inequity" has occurred.
Western, the Company and these NOOs are seeking to resolve this dispute
as part of an on-going mediation 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 mediation 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 Supply Agreement (LSA)
between it and Northwestern. The LSA governs the delivery of approximately
9,000,000 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 is
seeking a reduction in excess of 60% in the LSA fees. It 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. Trial testimony began October 20, 1997 and the trial should
conclude by the end of November 1997. The outcome of this litigation cannot
be predicted.
In the HL&P case, the court granted a summary judgment motion filed by
HL&P and declared that HL&P may substitute other fuel for lignite under the
LSA, without incurring standby charges. Northwestern has preserved its right
to appeal this ruling. It is the Company's belief that, even if this ruling is
upheld, lignite provided under the LSA will be a more economic source of fuel
than other options currently available to HL&P. However, if such ruling is
upheld, there can be no assurance that HL&P will not at some time seek other
sources of fuel.
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 is being financed
internally from the oil and natural gas operations and by the use of bank
financing. The Company is selling 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. At September 30, 1997, the Company had a short-term
note receivable from an unrelated party associated with the acquisition of
Vessel's exploration and production assets which is expected to be realized
before year-end 1997.
During the third quarter of 1997, the Company entered into an operating
lease arrangement for approximately $20,000,000 of automated meter reading
(AMR) equipment for its electric and natural gas customers, to be acquired and
installed over the next two years. Operating lease payments are calculated,
using a seven-year lease term, when an installation is complete. At September
30, 1997, the Company's minimum lease payments on AMR equipment that had been
installed were not material.
NOTE 2 - RATES, REGULATORY AND LEGISLATIVE MATTERS:
Electric:
The Company is transitioning 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, was passed by the
Montana Legislature and signed into law by the Governor in May 1997.
The legislation provides for choice of electricity supplier for the
Company's large customers by July 1, 1998, for pilot programs for residential
and small commercial customers by July 1, 1998 and 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 no later than July 1, 1998 and costs
will be recoverable in utility operations through a cost-based contract
between the Company's regulated operations and its non-regulated Supply
Division through July 1, 2002 for those customers that do not have choice or
have not selected a competitive based supplier. The Company's Supply Division
will compete for customers that have choice during and after the transition
period is complete. The legislation established a rate moratorium on electric
rates for all customers for two years beginning July 1, 1998, and an electric-
energy supply component rate moratorium for an additional two years for
smaller customers. The legislation contemplates that rates cannot be increased
under the rate moratorium except under limited circumstances.
The legislation provides for the recovery of non-mitigatable 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.
As required by the legislation, the Company filed a comprehensive
transition plan with the PSC on July 1, 1997. The filing contains the
Company's transition plan, including the proposed handling and resolution of
transition costs, and addresses other issues required by the legislation. The
Company expects the PSC to render a decision in May 1998, subject to the
above-mentioned legislative guidelines, on the amount of transition costs that
will be recoverable. The PSC will consider the Company's efforts to mitigate
transition costs in making its determination.
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 a revenue increase of 2.4% or approximately $8,800,000,
effective January 1, 1997, and an additional 2.4% increase or approximately
$9,000,000 is scheduled to go into effect on January 1, 1998.
Natural Gas:
The Natural Gas Restructuring and Customer Choice Act (Act) was also
passed by the Montana Legislature and signed into law in May 1997. This
legislation allowed for natural gas utilities to open their systems to full
customer choice for gas supply and authorized the issuance of transition bonds
to lower transition costs. In July 1996, the Company filed a formal open-access
and restructuring plan with the PSC that proposed an immediate increase in the
number of customers eligible to choose their own natural gas supplier, with all
customers having choice by mid-2002, and the recovery of natural gas production
and regulatory assets that will be uneconomic or stranded under full customer
choice.
On October 28, 1997, the PSC approved an order giving the Company's
natural gas customers the right to choose their own suppliers based upon
stipulation agreements agreed-to by the Company and many of the contesting
parties to the July 1996 filing. Natural gas transmission, distribution and
storage will remain regulated by the PSC. The decision allows approximately 230
smaller industrial and larger commercial customers using 5,000 decatherms or
more of natural gas annually, to have choice by early November 1997. The 230
customers represent an additional 5% of the Company's pre-transportation load
that may choose their own supplier. Natural gas customers who use 60,000 or
more decatherms of natural gas annually, which included 23 industrial customers
who represented 49% of the Company's pre-transportation load, have had choice
since 1991. The Company's remaining 140,000 customers will have choice no later
than July 1, 2002. A pilot program allowing approximately 3,500 residential and
small commercial customers to choose their own supplier, beginning with the
1998-99 heating season, will also be implemented.
The PSC order also reduced annual natural gas revenues by $2,800,000 or
2.3% and froze base rates for two years. The order also addressed the recovery
of $60,000,000 associated with stranded natural gas production and regulatory
assets through a competitive transition charge (CTC) and the implementation of
a non-bypassable Universal System Benefits Charge for public purpose programs.
As the Act allows for the securitization of transition costs, the Company is
pursuing the issuance of transition bonds that will refinance the transition
costs at a lower cost of capital. A natural gas transition cost financing
filing will be made in November 1997 to the PSC.
The Company does not anticipate a materially negative impact on earnings
due to the reduction in natural gas supply revenues from customers choosing
other suppliers as the decrease will be offset by reduced natural gas supply
costs, CTC charges, transportation and distribution revenues and transition
bond financing savings.
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:
The Company has a formal policy regarding the execution, recording, and
reporting of derivative instruments. The purpose of the policy is to manage a
portion of the price risk associated with its Nonutility producing assets and
firm-supply commitments. The Company uses derivatives as hedging instruments
to achieve revenue targets, reduce earnings volatility, and provide stable
cash flow. When fluctuations in natural gas and crude oil market prices result
in the Company realizing gains on the price swap agreements into which it has
entered, the Company is exposed to credit risk relating to the nonperformance
by counterparties of their obligation to make payments under the agreements.
Such risk to the Company is mitigated by the fact that the counterparties, or
the parent companies of such counterparties, are investment grade financial
institutions. The Company does not anticipate any material impact to its
financial position, results of operations or cash flow as a result of
nonperformance by counterparties.
To manage a portion of Nonutility price risk, the Company uses a variety
of derivative instruments including crude oil and natural gas swap, collar,
and cap agreements to hedge revenue from anticipated production of crude oil
and natural gas reserves and supply costs to its firm markets. Under swap
agreements, the Company receives or makes payments based on the differential
between a specified price and a variable price of oil or natural gas when the
hedged transaction is settled. The variable price is either a crude oil or
natural gas price quoted on the New York Mercantile Exchange or a quoted
natural gas price in Inside FERC's Gas Market Report or other recognized
industry index. These variable prices are highly correlated with the market
prices received by the Company for its natural gas and crude oil production.
Under collar agreements, the Company makes or receives monthly payments at the
settlement date 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 at the settlement
date based on the differential between the actual price of oil or natural gas
and the cap established in the agreement depending on whether the Company
sells or buys a cap. At September 30, 1997, the Company had cap agreements on
approximately 138,000 barrels of crude oil, or 51% of its expected production
from proved, developed and producing oil reserves through December 1997. The
Company had cap and swap agreements on approximately 4.4 Bcf of Nonutility
natural gas; or 21% of its expected production from proved, developed and
producing Nonutility natural gas reserves through November 1998. In addition,
the Company had swap and collar agreements to hedge approximately 900 Mmcf of
Nonutility natural gas, or 16% of its expected delivery obligations under
long-term natural gas sales contracts through March 1998.
The Company accounts for derivative transactions through hedge
accounting. The Company designates all its derivatives as fair value hedges.
A fair value hedge is based on the following criteria:
? The hedged item is specifically identified as a recognized asset or a firm
commitment.
? The hedged item is a single asset or a portfolio of similar assets.
? The hedged item presents an exposure to changes in fair value for the
hedged risk that could affect earnings.
? The hedged item is not an asset or liability that is measured at fair value
with changes in fair value attributable to the hedged risk reported
currently in earnings.
Gains or losses from these price swap agreements are reflected in
operating revenues on the Consolidated Statement of Income at the time of
settlement with the other parties. The Company uses the accrual method to
record its gains or losses. If the Company terminates a price swap agreement
prior to the date of the anticipated natural gas or crude oil production, the
gain or loss from the agreement is deferred in the Consolidated Balance Sheet
at the termination date. When the anticipated natural gas or crude oil
production occurs, the gain or loss from the price swap agreement is
recognized in the Consolidated Statement of Income. If the Company determines
that a portion of its anticipated natural gas or crude oil production will not
occur, thus creating a matching problem between the price swap agreements and
the anticipated production, any such unmatched price swap agreements are
marked-to-market and any unrealized gain or loss is recorded in the
Consolidated Statement of Income. At September 30, 1997, the Company had no
material deferred gains or losses related to 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 September 30, 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.
NOTE 5 - LONG-TERM DEBT
During the second quarter of 1997, the Company borrowed $75,000,000
under a Revolving Credit Agreement, a portion of which was used to fund the
Vessels acquisition discussed in Note 1 to the Consolidated Financial
Statements.
In June 1997, in response to FERC's decision regarding the Kerr
mitigation plan discussed in Note 1 to the Consolidated Financial Statements,
the Company recognized long-term debt of approximately $57,000,000.
Approximately $35,000,000 is classified as due within one year in the
Consolidated Balance Sheet at September 30, 1997.
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.
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.
Utility Restructuring:
See Note 2 to the Consolidated Financial Statements for a discussion of
electric and natural gas restructuring legislation and the Company's
restructuring filings with the PSC.
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.
For the Nine Months Ended September 30, 1997 and 1996:
Net Income Per Share of Common Stock:
Consolidated net income per share for the nine months ended September
30, 1997 was $1.36, an increase of 13 cents over the same period last year.
Earnings from Nonutility oil and natural gas operations contributed
significantly to the increase primarily due to considerably higher market
prices for natural gas during the first quarter of 1997 and gains on the sales
of non-strategic properties as the Company focuses its efforts on natural gas
markets. Coal operations earnings increased primarily due to increased sales
to the Colstrip generating units, moderated somewhat by decreased prices. The
Colstrip units are operating normally this year after being curtailed during
the second quarter of 1996 due to the availability of low-cost power in the
region. Earnings from independent power operations decreased primarily due to
a reduction in long-term power sales revenue resulting from a settlement with
Puget Sound Energy.
Nine-month ended Utility earnings decreased due to weather related
reductions in electric and natural gas volumes sold and increases in steam
plant maintenance, interest expenses, property taxes and selling, general and
administrative costs. Decreased earnings were partially offset by customer
growth and increased revenues related to higher electric and natural gas
rates. Lower purchased power costs and higher electric wholesale prices also
moderated the decreases.
Nine Months Ended
September 30,
1997 1996
Utility Operations $ 0.61 $ 0.68
Nonutility Operations 0.75 0.55
Consolidated $ 1.36 $ 1.23
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Nine Months Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 323,635 $ 305,013
Intersegment revenues 3,403 4,526
327,038 309,539
EXPENSES:
Power supply 99,754 99,726
Transmission and distribution 23,936 23,368
Selling, general and administrative 40,435 32,010
Taxes other than income taxes 39,057 34,878
Depreciation and amortization 39,986 35,814
243,168 225,796
INCOME FROM ELECTRIC OPERATIONS 83,870 83,743
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 72,504 70,413
Gas supply cost revenues 11,135 15,469
Intersegment revenues 439 463
84,078 86,345
EXPENSES:
Gas supply costs 11,135 15,469
Other production, gathering and exploration 6,781 6,921
Transmission and distribution 8,398 8,911
Selling, general and administrative 14,217 12,496
Taxes other than income taxes 12,811 11,379
Depreciation, depletion and amortization 9,750 8,995
63,092 64,171
INCOME FROM GAS OPERATIONS 20,986 22,174
INTEREST EXPENSE AND OTHER:
Interest 38,107 35,091
Distributions on QUIPS 4,119
Other (income) deductions - net (384) (1,609)
41,842 33,482
INCOME BEFORE INCOME TAXES AND DIVIDENDS 63,014 72,435
INCOME TAXES 26,695 29,960
DIVIDENDS ON PREFERRED STOCK 2,768 5,420
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 33,551 $ 37,055
</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 nine months of
1997 in the Company's service territory were 8% warmer than 1996 and comparable
to the historic average.
Weather, streamflow conditions and the wholesale power markets in the
Northwest and California influence the Company's electric wholesale revenues,
power-purchase expenses and output of thermal generation. Regional opportunity
purchased-power prices were higher than last year and consequently, the
Company did not curtail its thermal generation as it had during the second
quarter of 1996. Margins on off-system sales are tightening as competition
among suppliers increases.
As discussed in Note 2 to the Consolidated Financial Statements, on
October 28, 1997, the PSC approved an order addressing the Company's natural
gas restructuring filing. The Company does not anticipate a materially
negative impact on earnings from the additional customers choosing other
suppliers.
As a result of the passage of electric and natural gas restructuring
legislation and the Company's restructuring filings, electric generation and
natural gas production assets of the Company will be removed from rate base.
Consequently, Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation" will no longer be
applicable to these electric generation and natural gas production assets of
the Company. As a consequence of the issuance by the PSC of the natural gas
restructuring order, the Company's natural gas production assets will be
removed from SFAS No. 71 accounting in the fourth quarter of 1997. The timing
of the removal of the electric generating assets from SFAS No. 71 has not yet
been determined. The Financial Accounting Standards Board's (FASB) Emerging
Issues Task Force (EITF) met in July 1997 to discuss issues related to
removing the generation portion of a utility company from SFAS No. 71.
Recovery of Company's existing regulatory assets related to these natural gas
production assets was provided in the PSC order and recovery of existing
regulatory assets related to electric generation is provided in the electric
restructuring legislation. Based upon the EITF's conclusions regarding
regulatory assets and liabilities and the Company's anticipated recovery of
its regulatory assets, the Company believes that the discontinuation of
regulatory accounting for these generation and production assets will not have
a material impact on the Company's financial position or results of
operations. 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 electric
generation or natural gas production assets.
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh)
9/30/97 9/30/96 9/30/97 9/30/96 9/30/97 9/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $ 197,171 $ 181,797 8% 3,197 3,207 0% 275,251 270,828 2%
Industrial 78,425 78,223 0% 1,906 1,921 (1)% 3,464 3,368 3%
General Business 275,596 260,020 6% 5,103 5,128 0% 278,715 274,196 2%
Sales to Other
Utilities 38,381 36,650 5% 2,112 1,973 7% 84 77 9%
Other 9,658 8,343 16%
Intersegment 3,403 4,526 (25)% 112 295 (62)% 229 229 0%
Total $ 327,038 $ 309,539 6% 7,327 7,396 (1)% 279,028 274,502 2%
Power Supply
Expenses:
Hydroelectric $ 15,394 $ 14,604 5% 3,095 3,178 (3)%
Steam 39,945 33,476 19% 3,097 2,933 6%
Purchases
and Other 44,415 51,646 (14)% 1,989 1,918 4%
Total Power Supply $ 99,754 $ 99,726 0% 8,181 8,029 2%
Cents Per kWh $1.219 $1.242
</TABLE>
Revenue increases from general business customers during the first nine
months of 1997 were primarily a result of higher rates, customer growth and a
1997 change in rate design that shifted a portion of revenue from winter to
summer months. These increases were partially offset by volume decreases
related to warmer weather. Higher prices and greater volumes sold in the
wholesale electric market more than offset decreases related to the expiration
of a high-priced firm sales contract in the second quarter of 1996.
Increased power supply expenses related to maintenance costs at the
Billings steam plant, greater secondary purchase volumes and higher qualifying
facility rates were offset by reductions related to the expiration of two
high-priced firm purchase contracts in the first half of 1996. Selling,
general and administrative expenses for the period increased largely due to
reduced billings to third parties, increased consulting and outsourcing
charges and expense allocation changes. Taxes other than income taxes
increased due to higher property taxes related to 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)
9/30/97 9/30/96 9/30/97 9/30/96 9/30/97 9/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $ 70,320 $ 72,573 (3)% 15,181 15,707 (3)% 140,412 136,520 3%
Industrial 1,869 1,959 (5)% 435 456 (5)% 395 420 (6)%
Subtotal 72,189 74,532 (3)% 15,616 16,163 (3)% 140,807 136,940 3%
Gas Supply Cost
Revenues (GSC) (11,135) (15,469) (28)%
General Business
without GSC 61,054 59,063 3% 15,616 16,163 (3)% 140,807 136,940 3%
Sales to Other
Utilities 558 563 (1)% 154 155 (1)% 4 3 33%
Transportation 6,961 7,012 (1)% 19,527 19,114 2% 41 37 11%
Other 3,931 3,775 4%
Total $ 72,504 $ 70,413 3% 35,297 35,432 0% 140,852 136,980 3%
</TABLE>
Natural gas revenues, excluding gas supply cost revenues, increased for
the first nine months of 1997 due to slightly higher tariff rates and customer
growth. Revenue increases were partially offset by lower volumes sold due to
warmer weather. Selling, general and administrative expenses and taxes other
than income taxes increased due to the reasons mentioned in the Electric
Utility nine months ended discussion.
Interest Expense and Other:
Medium-term note and QUIPS issuances at the end of 1996 resulted in
increased interest expense for the first nine months of 1997. Interest
related to the Kerr Project mitigation liability also contributed to the
increase. Other income decreased for the period due to costs associated with
the Flint Creek Dam property transfer to Granite County, Montana during the
second quarter of 1997.
Preferred Dividends:
During the fourth quarter of 1996, the Company repurchased and retired
139,200 shares of its $6.875 series and redeemed all outstanding shares of its
$2.15 series, decreasing the amount of preferred dividends paid during the
nine months ended 1997.
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Nine Months Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $122,252 $113,650
Intersegment revenues 23,872 21,949
146,124 135,599
EXPENSES:
Operations and maintenance 86,774 82,683
Selling, general and administrative 15,608 16,166
Taxes other than income taxes 16,605 14,295
Depreciation, depletion and amortization 4,286 3,914
123,273 117,058
INCOME FROM COAL OPERATIONS 22,851 18,541
OIL AND NATURAL GAS:
REVENUES:
Revenues 116,114 87,153
Intersegment revenues 230 192
116,344 87,345
EXPENSES:
Operations and maintenance 76,912 53,372
Selling, general and administrative 7,521 7,479
Taxes other than income taxes 3,562 2,374
Depreciation, depletion and amortization 12,769 12,826
100,764 76,051
INCOME FROM OIL AND NATURAL GAS OPERATIONS 15,580 11,294
INDEPENDENT POWER:
REVENUES:
Revenues 52,225 56,773
Earnings from unconsolidated investments 7,938 8,991
Intersegment revenues 1,572 734
61,735 66,498
EXPENSES:
Operations and maintenance 47,275 47,861
Selling, general and administrative 3,092 3,805
Taxes other than income taxes 1,468 1,362
Depreciation, depletion and amortization 1,914 2,409
53,749 55,437
INCOME FROM INDEPENDENT POWER OPERATIONS $ 7,986 $ 11,061
NONUTILITY OPERATIONS (continued)
Nine Months Ended
September 30,
1997 1996
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 23,898 $ 19,518
Intersegment revenues 587
24,485 19,518
EXPENSES:
Operations and maintenance 15,568 12,969
Selling, general and administrative 4,927 4,011
Taxes other than income taxes 570 272
Depreciation, depletion and amortization 1,013 673
22,078 17,925
INCOME FROM TELECOMMUNICATIONS OPERATIONS 2,407 1,593
OTHER OPERATIONS:
REVENUES:
Revenues 1,690 878
Intersegment revenues 2,031 578
3,721 1,456
EXPENSES:
Operations and maintenance 1,854 869
Selling, general and administrative 3,881 1,554
Depreciation, depletion and amortization 399 507
6,134 2,930
LOSS FROM OTHER OPERATIONS (2,413) (1,474)
INTEREST EXPENSE AND OTHER:
Interest 4,234 3,504
Other (income) deductions - net (16,305) (4,700)
(12,071) (1,196)
INCOME BEFORE INCOME TAXES 58,482 42,211
INCOME TAXES 17,603 11,856
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 40,879 $ 30,355
</TABLE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations for the nine months ended September 1997
increased due to significantly higher volumes of coal sold at the Rosebud Mine
and higher volumes of lignite sold at the Jewett Mine. Revenues from the
Rosebud Mine increased $6,000,000. Volumes of coal sold to Colstrip Units 3 &
4 in 1997 increased 60% due to plant curtailments during 1996 as a result of
the availability of low-cost hydroelectric power in the region. This increase
was partially offset by a price reduction resulting from the settlement of a
dispute with Puget and a short-term contract modification with the remaining
Colstrip partners, a slight decrease in volumes sold to Colstrip Units 1 & 2
and the reduction in sales to the Corette Plant resulting from the 1996
switching of fuel suppliers for early compliance with air quality standards.
Revenues from the Jewett mine increased $3,400,000 due primarily to a 9%
increase in volumes of lignite sold.
Operation and maintenance expense and taxes other than income taxes
increased primarily due to higher maintenance, royalties, and production taxes
resulting from the increased sales at both mines along with increased
litigation and leasehold abandonment costs.
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 $ 1
-volume (7)%
-price/bbl 16%
Natural gas -revenue $ 20
-volume 3%
-price/Mcf 26%
Miscellaneous $ 8
Income from the oil and natural gas operations improved primarily due to
significantly higher market prices in the first quarter of 1997. Although
natural gas market prices have also increased in the third quarter of 1997
compared to 1996, increased purchased gas costs have significantly reduced
margins on natural gas activities.
Revenues from U.S. oil operations increased $5,100,000 due to increased
production resulting from a waterflood injection project initiated in 1996 and
other additional production from existing wells along with higher market
prices. The increase was partially offset by decreased Canadian oil
production resulting from the sale of production properties in conjunction
with the Company's increased emphasis on its natural gas operations.
Additionally, in accordance with the natural gas focus, the sale of the
waterflood property will be finalized in the fourth quarter of 1997.
Miscellaneous revenues increased primarily as a result of increased processing
and gathering revenues.
Operation and maintenance expense and taxes other than income taxes for
oil and natural gas operations increased due primarily to higher prices on
natural gas purchases, increased production costs and production taxes due to
increased volumes.
Independent Power Operations:
Independent power operations' net income for the nine months ended 1997
decreased largely as a result of a $4,200,000 decrease in revenue due to the
settlement reached with Puget Sound Energy (Puget). Earnings from
unconsolidated investments decreased $1,000,000 primarily from a decrease
resulting from a change in accounting method for one of the investments
combined with a decrease in earnings as a result of a back down of power at
another project. Partially offsetting the decrease in earnings is an increase
due to continued growth in earnings of other investments and additional
earnings from an investment that became operational in the first quarter of
1997.
Lower project development costs and decreased amortization of
independent power investments due to a change in accounting method caused a
year to date decrease in expenses.
Telecommunications Operations:
Revenues and expenses from telecommunications operations increased
primarily due to higher volumes of long-distance minutes sold, increased
private line revenues and the completion of equipment sales projects during
the year. During the third quarter of 1997, the Company has begun receiving
revenues on its new Washington to Minnesota, Colorado to Canada fiber optic
network and these revenues are expected to increase in the fourth quarter of
1997.
Other Operations:
Revenue and expense activity in other operations relates primarily to
the Company's new electric, natural gas, and oil marketing subsidiary, The
Montana Power Trading and Marketing Company.
In August 1997, the Company reached an agreement in principle to sell
its 16 percent interest in the Brasilia gold mine located in Paracatu, Brazil.
The transaction is expected to close in the fourth quarter 1997 and is
expected to result in an after-tax gain of approximately $6,000,000.
Interest Expense and Other:
Other income increased due to $13,000,000 of gains on dispositions of
oil and natural gas properties realized in the first and second quarters. The
increase was offset by costs associated with a discontinued SynCoal? project.
Quarter Ended September 30, 1997 and 1996:
Net Income Per Share of Common Stock:
Net income for the quarter ended September 30, 1997 was 28 cents per
share, compared to 30 cents per share for the third quarter of 1996.
Third quarter earnings from Utility operations decreased two cents per
share as weather related decreases in electric and natural gas volumes and
increased expenses related to steam plant maintenance, interest costs,
property taxes and selling, general and administrative costs were not fully
offset by increased revenues resulting from customer growth and higher
electric and natural gas rates. Nonutility earnings were the same as last
year. Earnings from telecommunication operations increased slightly as the
Company began receiving revenue late in the quarter on its expanded fiber
optic network. This positive earnings trend is expected to accelerate during
the fourth quarter. The telecommunication increase was offset by lower
earnings in coal and oil and natural gas operations.
For comparative purposes, the following table shows the breakdown of
consolidated net income per share:
Quarter Ended
September 30,
1997 1996
Utility Operations $ 0.05 $ 0.07
Nonutility Operations 0.23 0.23
Consolidated $ 0.28 $ 0.30
<TABLE>
<CAPTION>
UTILITY OPERATIONS
Quarter Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 106,118 $ 99,716
Intersegment revenues 1,140 1,011
107,258 100,727
EXPENSES:
Power supply 33,520 32,981
Transmission and distribution 8,027 8,347
Selling, general and administrative 12,742 9,955
Taxes other than income taxes 12,870 11,462
Depreciation and amortization 13,524 12,719
80,683 75,464
INCOME FROM ELECTRIC OPERATIONS 26,575 25,263
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 12,342 13,212
Gas supply cost revenues 1,201 1,489
Intersegment revenues 113 105
13,656 14,806
EXPENSES:
Gas supply costs 1,201 1,489
Other production, gathering and exploration 2,106 2,230
Transmission and distribution 2,762 3,004
Selling, general and administrative 4,708 3,814
Taxes other than income taxes 4,160 3,659
Depreciation, depletion and amortization 3,247 3,135
18,184 17,331
LOSS FROM GAS OPERATIONS (4,528) (2,525)
INTEREST EXPENSE AND OTHER:
Interest 13,541 12,040
Distributions on QUIPS 1,373
Other (income) deductions - net (29) (148)
14,885 11,892
INCOME BEFORE INCOME TAXES AND DIVIDENDS 7,162 10,846
INCOME TAXES 3,227 5,202
DIVIDENDS ON PREFERRED STOCK 923 1,807
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 3,012 $ 3,837
</TABLE>
UTILITY OPERATIONS:
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh)
9/30/97 9/30/96 9/30/97 9/30/96 9/30/97 9/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $ 61,398 $ 57,166 7% 1,032 1,044 (1)% 275,554 271,456 2%
Industrial 27,532 26,274 5% 696 722 (4)% 4,597 4,757 (3)%
General Business 88,930 83,440 7% 1,728 1,766 (2)% 280,151 276,213 1%
Sales to Other
Utilities 13,000 13,828 (6)% 720 793 (9)% 86 81 6%
Other 4,188 2,448 71%
Intersegment 1,140 1,011 13% 34 51 (33)% 230 227 1%
Total $ 107,258 $ 100,727 6% 2,482 2,610 (5)% 280,467 276,521 1%
Power Supply
Expenses:
Hydroelectric $ 5,271 $ 5,060 4% 979 933 5%
Steam 14,669 12,556 17% 1,227 1,229 0%
Purchases
and Other 13,580 15,365 (12)% 624 595 5%
Total Power Supply $ 33,520 $ 32,981 2% 2,830 2,757 3%
Cents Per kWh $1.184 $1.196
</TABLE>
Electric revenues from general business customers increased during the
third quarter of 1997 as compared to 1996 primarily due to higher rates,
customer growth and a 1997 change in rate design that shifted a portion of
revenue from winter to summer months. These increases were partially offset
by volume decreases related to warmer, wetter weather conditions. Other
electric revenues increased as a result of additional wheeling activities.
Reduced volumes sold, partially offset by higher wholesale prices, led to a
slight decrease in revenues from sales to other utilities.
Increased power supply expenses related to additional maintenance costs
at the Billings steam plant were partially offset by decreased secondary
purchase prices. Selling, general and administrative expenses and taxes other
than income taxes increased for the same reasons mentioned in the Electric
Utility nine months ended discussion.
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf)
9/30/97 9/30/96 9/30/97 9/30/96 9/30/97 9/30/96
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial &
Government $ 9,773 $ 10,760 (9)% 1,778 1,957 (10)% 139,347 136,246 2%
Industrial 331 363 (9)% 76 81 (6)% 355 417 (15)%
Subtotal 10,104 11,123 (9)% 1,854 2,038 (9)% 139,702 136,663 2%
Gas Supply Cost
Revenues (GSC) (1,201) (1,489) (19)%
General Business
without GSC 8,903 9,634 (8)% 1,854 2,038 (9)% 139,702 136,663 2%
Sales to Other
Utilities 71 76 (7)% 7 9 (22)% 4 3 33%
Transportation 2,143 2,145 0% 5,037 6,222 (19)% 37 33 12%
Other 1,225 1,357 (10)%
Total $ 12,342 $ 13,212 (7)% 6,898 8,269 (17)% 139,743 136,699 2%
</TABLE>
Natural gas revenues for the quarter decreased from 1996 primarily due to
reduced volumes sold as a result of warmer weather. Selling, general and
administrative expenses and taxes other than income taxes increased for the
same reasons mentioned in the Electric Utility nine months ended discussion.
Interest Expense and Other:
Interest expense increased for the same reasons mentioned in the nine
months ended discussion.
Preferred Dividends:
Preferred dividends decreased for the same reasons mentioned in the nine
months ended discussion.
<TABLE>
<CAPTION>
NONUTILITY OPERATIONS
Quarter Ended
September 30,
1997 1996
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 44,131 $ 43,941
Intersegment revenues 9,223 8,916
53,354 52,857
EXPENSES:
Operations and maintenance 31,838 29,853
Selling, general and administrative 5,510 5,611
Taxes other than income taxes 6,367 5,453
Depreciation, depletion and amortization 1,539 1,693
45,254 42,610
INCOME FROM COAL OPERATIONS 8,100 10,247
OIL AND NATURAL GAS:
REVENUES:
Revenues 39,306 28,684
Intersegment revenues 35 26
39,341 28,710
EXPENSES:
Operations and maintenance 28,974 17,921
Selling, general and administrative 2,515 2,547
Taxes other than income taxes 909 616
Depreciation, depletion and amortization 4,334 4,238
36,732 25,322
INCOME FROM OIL AND NATURAL GAS OPERATIONS 2,609 3,388
INDEPENDENT POWER:
REVENUES:
Revenues 18,007 18,773
Earnings from unconsolidated investments 3,266 3,132
Intersegment revenues 358 313
21,631 22,218
EXPENSES:
Operations and maintenance 16,615 16,375
Selling, general and administrative 896 1,939
Taxes other than income taxes 222 480
Depreciation, depletion and amortization 948 841
18,681 19,635
INCOME FROM INDEPENDENT POWER OPERATIONS $ 2,950 $ 2,583
NONUTILITY OPERATIONS (continued)
Quarter Ended
September 30,
1997 1996
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 8,824 $ 6,639
Intersegment revenues 201
9,025 6,639
EXPENSES:
Operations and maintenance 5,204 4,470
Selling, general and administrative 1,401 1,289
Taxes other than income taxes 241 80
Depreciation, depletion and amortization 472 238
7,318 6,077
INCOME FROM TELECOMMUNICATIONS OPERATIONS 1,707 562
OTHER OPERATIONS:
REVENUES:
Revenues 985 333
Intersegment revenues 917 169
1,902 502
EXPENSES:
Operations and maintenance 1,159 314
Selling, general and administrative 1,232 253
Depreciation, depletion and amortization 133 168
2,524 735
LOSS FROM OTHER OPERATIONS (622) (233)
INTEREST EXPENSE AND OTHER:
Interest 1,335 1,526
Other (income) deductions - net (2,128) (2,359)
(793) (833)
INCOME BEFORE INCOME TAXES 15,537 17,380
INCOME TAXES 3,231 4,795
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 12,306 $ 12,585
</TABLE>
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations for the quarter decreased as a slight
increase in revenues was more than offset by increased operating costs.
Revenues increased slightly due to higher volumes of coal sold to Colstrip
Units 3 & 4 and an increase in reimbursable mining expenses at the Jewett
Mine. The increase was offset by a decrease in price due to the Puget
settlement and temporary contract modification mentioned in the nine months
ended discussion.
The increase in operations and maintenance expense was due primarily to
increased royalty expense resulting from mining more lignite from customer
leases at the Jewett Mine and the items mentioned in the nine months ended
discussion.
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 $ (1)
-volume (13)%
-price/bbl (2)%
Natural gas -revenue $ 8
-volume 2%
-price/Mcf 36%
Miscellaneous $ 3
Income from oil and natural gas operations decreased slightly due
primarily to higher prices for natural gas purchases. The increase in natural
gas revenues resulting from higher market prices was more than offset by
increased prices on purchased natural gas. Oil revenues increases from the
waterflood injection project were more than offset by the decreased Canadian
oil production resulting from the sale of production properties. Miscellaneous
revenues increased primarily as a result of increased processing and gathering
revenues.
Independent Power Operations:
Net income for the independent power operations increased for the third
quarter 1997 as a slight decrease in revenues, resulting from the Puget
settlement was more than offset by a decrease in selling, general and
administrative expense due to lower legal costs and reduced payroll expense at
the Colstrip unit.
Telecommunications Operations:
Income from telecommunications operations increased primarily due to
higher volumes of long-distance minutes and increased private line revenues
partially offset by increased costs of sales as mentioned in the nine months
ended discussion.
Other Operations:
As mentioned in the nine months ended discussion, revenue and expense
activity in other operations relates primarily to the Company's new electric,
natural gas, and oil marketing subsidiary, The Montana Power Trading and
Marketing Company.
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 using short-term borrowings.
In April 1997, the Company entered into a Revolving Credit Agreement for
certain of its Nonutility operations. Including this facility, the Company's
consolidated borrowing ability under its Revolving Credit and Term Loan
Agreements (Agreements) is $220,000,000. Under terms of the new agreement, the
amount of the facility decreases on March 31, 1998, reducing the consolidated
borrowing ability under the Agreements to $160,000,000. At September 30 1997,
$65,000,000 had been borrowed under the new agreement; a portion of which was
used to fund the acquisition of Vessels' assets. See Note 1 to the
Consolidated Financial Statements for further discussion of Vessels.
As discussed in Notes 1 and 5 to the Consolidated Financial Statements,
the Company recorded approximately $57,000,000 in long-term debt related to the
Kerr mitigation decision. Of this amount approximately $35,000,000 has been
classified as due within one year. The Company made a payment of $4,200,000 on
August 25, 1997 to a fish and wildlife implementation fund in accordance with
the FERC order.
FTV Communications LLC, a limited liability company owned equally by
Touch America (a subsidiary of the Company), Williams Communications Group,
Inc. (a subsidiary of Williams Companies) and FirstPoint Communications, Inc.
(a subsidiary of Enron) will construct, operate and maintain a 1,600 mile
fiber-optic cable network linking Portland, Oregon and Los Angeles, California.
The project, which is scheduled to be completed in December 1998, is expected
to cost in excess of $100,000,000. In addition to Portland and Los Angeles, the
new network will serve Boise, Idaho; Salt Lake City, Utah; and Las Vegas,
Nevada, as well as provide advanced telecommunications services to rural
populations along the route. The Company's investment in the project is
expected to be funded through existing credit facilities, internally generated
funds and the sale of fiber to other firms.
Roan Resources Ltd., a Canadian subsidiary of the Company, has signed a
letter of intent to purchase the stock of Questar Exploration Inc., a Canadian
corporation with oil and natural gas properties. Roan's proposal is contingent
on completion of satisfactory due diligence, and regulatory and common
stockholders' approval at a meeting to be convened on December 10, 1997. The
Company intends to sell certain properties, reducing its overall investment in
Questar to approximately $16,000,000. The Company will seek debt financing in
Canada to fund the remaining investment.
As previously mentioned in the quarter ended discussion of net income
per share, the Company began receiving revenue on its expanded fiber optic
network late in the third quarter of 1997. With the 5,000-mile fiber optic
network from the mid-west to the Pacific Coast now in operation, the Company
is estimating an improvement in operating cash flows from telecommunications
in excess of $20,000,000 after taxes over the next 12 months.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended September 30, 1997, the Company's ratio of
earnings to fixed charges was 3.12 times. Fixed charges include interest,
distributions on QUIPS, the implicit interest of the Colstrip Unit 4 rentals
and one-third of all other rental payments.
YEAR 2000 COMPLIANCE:
As the year 2000 approaches, most companies will face a potentially
serious problem resulting from the possible failure of computer software
programs and other operational electronic systems to recognize calendar dates
beyond the year 1999. This failure could force computers to shut down or
create erroneous results. The Company is currently addressing this "Year
2000" issue to ensure the availability and integrity of its financial systems.
The Company is also in the process of identifying the other operational
electronic systems that could be affected by this issue. Although it is not
currently possible to estimate the overall cost of the required modifications,
the Company presently believes that the ultimate cost of this work will not
have a material effect on the Company's current financial position, liquidity
or results of operations.
UTILITY INDUSTRY CHANGES:
The Montana Power Group (MPG), an energy supply and management
alliance, was endorsed by the California Manufacturers Association (CMA) to
assist its members with their energy decisions as full customer choice in
electric supply comes to the California market on January 1, 1998. As a
participant in the MPG, The Montana Power Trading and Marketing Company (MPT),
a Nonutility subsidiary of The Montana Power Company, agreed to offer
comprehensive energy services, including energy supply, discounted from the
power exchange prices, and energy management products and services to
qualified CMA members. The CMA has agreed to endorse and promote such products
and services to its members. The approximate 1,000 members of CMA represent
an estimated 8,000,000 megawatt hours of electric use annually. The supply
program is offered on a limited basis to CMA members capped at predetermined
volumes. The program will be subscribed on a first come, first serve basis.
Once the caps are fully subscribed, MPT will have, at its sole discretion, the
option to extend the offered supply and services to other CMA members.
As of the filing of this Form 10-Q, one contract for energy supply and
services had been signed with a CMA member. At this time, the Company is
unable to estimate the potential impacts of the CMA agreement on the current
financial position, liquidity or results of operations.
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.
During June 1997, the FASB released SFAS No. 130, "Reporting
Comprehensive Income". SFAS No. 130 requires the reporting in the financial
statements of all items recognized as components of comprehensive income which
is defined as changes in equity during the period from transactions, events or
circumstances from non-owner sources. The statement is effective for fiscal
years beginning after December 15, 1997.
Also during June 1997, the FASB released SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information". SFAS No. 131
requires the disclosure of certain operating information in complete financial
statements as well as condensed statements for interim periods issued to
shareholders. The statement is effective for financial statements for periods
beginning after December 15, 1997.
The Company is evaluating SFAS No. 130 and SFAS No. 131 at this time to
determine the effects on the financial statements and related disclosures.
Although the statements will affect the presentation of the information, they
are not expected to materially affect the Company's financial position or
results of operations.
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
September 30, 1997.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K
DATE SUBJECT
July 23, 1997 Item 5. Other Events. Discussion of
Second Quarter Net Income.
Item 7. Exhibits. Consolidated Statements
of Income for the Quarters Ended June 30,
1997 and 1996 for the Six Months Ended
June 30, 1997 and 1996 and for the Twelve
Months Ended June 30, 1997 and 1996.
Utility Operations Schedule of Revenues
and Expenses for the Quarters Ended
June 30, 1997 and 1996 for the Six Months
Ended June 30, 1997 and 1996 and the
Twelve Months Ended June 30, 1997 and
1996. Nonutility Operations Schedule of
Revenues and Expenses for the Quarters
Ended June 30, 1997 and 1996 for the Six
Months Ended June 30, 1997 and 1996 and
the Twelve Months Ended June 30, 1997 and
1996.
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: November 14, 1997
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended September 30, 1997
Exhibit 27
Financial data schedule
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
September 30,1997
Net Income $ 125,911
Income Taxes 74,455
$ 200,366
Fixed Charges:
Interest $ 58,549
Amortization of Debt Discount,
Expense and Premium 1,600
Rentals 34,158
$ 94,307
Earnings Before Income Taxes
and Fixed Charges $ 294,673
Ratio of Earning to Fixed Charges 3.12 x
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 9/30/97, the Consolidated Income Statement and the
Consolidated Statement of Cash Flows for the nine months ended 9/30/97 and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,623,188
<OTHER-PROPERTY-AND-INVEST> 597,267
<TOTAL-CURRENT-ASSETS> 247,661
<TOTAL-DEFERRED-CHARGES> 305,428
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,773,544
<COMMON> 692,464
<CAPITAL-SURPLUS-PAID-IN> 2,128
<RETAINED-EARNINGS> 287,256
<TOTAL-COMMON-STOCKHOLDERS-EQ> 981,848
65,000
57,654
<LONG-TERM-DEBT-NET> 699,654
<SHORT-TERM-NOTES> 75,008
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 76,405
0
<CAPITAL-LEASE-OBLIGATIONS> 1,115
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 816,860
<TOT-CAPITALIZATION-AND-LIAB> 2,773,544
<GROSS-OPERATING-REVENUE> 731,661
<INCOME-TAX-EXPENSE> 44,298
<OTHER-OPERATING-EXPENSES> 580,394
<TOTAL-OPERATING-EXPENSES> 624,692
<OPERATING-INCOME-LOSS> 106,969
<OTHER-INCOME-NET> 13,742
<INCOME-BEFORE-INTEREST-EXPEN> 120,711
<TOTAL-INTEREST-EXPENSE> 43,513
<NET-INCOME> 77,198
2,768
<EARNINGS-AVAILABLE-FOR-COMM> 74,430
<COMMON-STOCK-DIVIDENDS> 65,570
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 143,624
<EPS-PRIMARY> 1.36
<EPS-DILUTED> 1.36
</TABLE>
