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, 1998
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _______________
________________________________________
Commission file number 1-4566
THE MONTANA POWER COMPANY
(Exact name of registrant as specified in its charter)
Montana 81-0170530
(State or other jurisdiction (IRS Employer
of incorporation) Identification No.)
40 East Broadway, Butte, Montana 59701-9394
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (406) 723-5421
________________________________________________________
(Former name, former address and former fiscal year,
if changed since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
On May 6, 1998, the Company had 54,969,841 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,
1998 1997
Thousands of Dollars
<S> <C> <C>
REVENUES $ 294,102 $ 281,370
EXPENSES:
Operations 128,479 103,784
Maintenance 19,782 19,275
Selling, general and administrative 29,367 27,806
Taxes other than income taxes 25,525 25,094
Depreciation, depletion and amortization 27,086 22,042
230,239 198,001
INCOME FROM OPERATIONS 63,863 83,369
INTEREST EXPENSE AND OTHER INCOME:
Interest 14,504 12,563
Distributions on mandatorily redeemable preferred
securities of subsidiary trust 1,373 1,373
Other (income) deductions-net (1,729) (4,817)
14,148 9,119
INCOME TAXES 13,848 28,045
NET INCOME 35,867 46,205
DIVIDENDS ON PREFERRED STOCK 923 923
NET INCOME AVAILABLE FOR COMMON STOCK $ 34,944 $ 45,282
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (000) 54,875 54,634
BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.64 $ 0.83
FULLY DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.64 $ 0.83
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,
1998 1997
Thousands of Dollars
<S> <C> <C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $40,924 and $39,425
plant under construction)
Electric $ 1,806,539 $ 1,820,280
Natural gas 384,940 395,918
2,191,479 2,216,198
Less - accumulated depreciation and depletion 683,252 684,960
1,508,227 1,531,238
NONUTILITY PROPERTY (includes $26,023 and $17,259
property under construction) 822,377 781,406
Less - accumulated depreciation and depletion 286,059 260,567
536,318 520,839
2,044,545 2,052,077
MISCELLANEOUS INVESTMENTS (at cost):
Independent power investments 44,455 51,534
Reclamation fund 47,903 47,312
Other 37,577 35,619
129,935 134,465
CURRENT ASSETS:
Cash and temporary cash investments 25,805 16,706
Accounts receivable 154,113 126,787
Materials and supplies (principally at average cost) 40,944 39,471
Prepayments and other assets 59,250 49,673
Deferred income taxes 10,587 10,539
290,699 243,176
DEFERRED CHARGES:
Advanced coal royalties 17,204 16,698
Regulatory assets related to income taxes 125,515 122,903
Regulatory assets - other 150,892 158,573
Other deferred charges 75,761 73,804
369,372 371,978
$ 2,834,551 $ 2,801,696
The accompanying notes are an integral part of these statements.
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
March 31, December 31,
1998 1997
Thousands of Dollars
CAPITALIZATION:
Common shareholders' equity:
Common stock (120,000,000 shares
authorized; 54,921,409 and
54,728,709 shares issued) $ 698,852 $ 694,561
Retained earnings and other shareholders' equity 352,201 342,973
Unallocated stock held by trustee for retirement
savings plan (25,305) (25,945)
1,025,748 1,011,589
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 670,516 653,168
1,818,918 1,787,411
CURRENT LIABILITIES:
Short-term borrowing 101,482 133,958
Long-term debt - portion due within one year 63,798 81,659
Dividends payable 22,730 22,684
Income taxes 23,242 3,803
Other taxes 66,334 47,818
Accounts payable 63,341 77,821
Interest accrued 15,150 13,836
Accrued lease payments 7,920
Other current liabilities 53,492 35,158
417,489 416,737
DEFERRED CREDITS:
Deferred income taxes 341,007 340,251
Investment tax credit 34,786 35,182
Accrued mining reclamation costs 132,624 131,108
Other deferred credits 89,727 91,007
598,144 597,548
CONTINGENCIES AND COMMITMENTS (Notes 2 and 5)
$ 2,834,551 $ 2,801,696
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,
1998 1997
Thousands of Dollars
<S> <C> <C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 35,867 $ 46,205
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 27,086 22,042
Deferred income taxes (2,218) 5,152
Noncash earnings from unconsolidated
independent power investments. (1,425) (2,860)
Reclamation expensed and paid - net 1,516 2,292
Deferred stripping expenses and payments - net 48 (887)
Gains on sales of property (135) (4,131)
Other - net 5,119 5,097
Changes in other assets and liabilities:
Accounts receivable (27,326) 20,432
Materials and supplies (1,473) (591)
Accounts payable (14,480) (5,928)
Accrued lease payments 7,920 7,920
Other assets and liabilities 50,564 41,200
Net cash provided by operating activities 81,063 135,943
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (20,620) (28,391)
Reclamation funding (591) (1,892)
Sales of property 2,811 15,442
Additional investments (1,958) (898)
Net cash used by investing activities (20,358) (15,739)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid (22,847) (22,775)
Sales of common stock 4,294 61
Issuance of long-term debt 2,743 (170)
Retirement of long-term debt (3,320) (44,615)
Issuance of mandatorily redeemable preferred
securities of subsidiary trust (65)
Net change in short-term borrowing (32,476) (59,440)
Net cash used by financing activities (51,606) (127,004)
CHANGE IN CASH FLOWS 9,099 (6,800)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 16,706 32,404
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 25,805 $ 25,604
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Three Months For:
Income taxes, net of refunds $ 12,074 $ 16,497
Interest 14,742 9,597
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, 1998 and 1997 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, 1997.
Certain reclassifications have been made to the prior year amounts to
make them comparable to the 1998 presentation. These changes had no impact on
previously reported results of operations or shareholders' equity.
NOTE 1 -- DEREGULATION AND ASSET DIVESTITURE, AND OTHER REGULATORY MATTERS:
The electric and natural gas utility businesses are in transition to
competition to provide energy commodity and related services to wholesale and
retail customers. In Montana, electric and natural gas restructuring and
customer choice legislation was passed by the Montana Legislature and signed
into law in 1997.
Both the electric and natural gas legislation authorized the issuance of
transition bonds, often referred to as securitization. The issuance of
transition bonds involves the issuance of a debt instrument which is repaid
through, and secured by, a specified component of future revenues, thereby
reducing the credit risk of the securities. Although the bonds are expected to
be shown as debt on the Consolidated Balance Sheet of the Company, the bonds
will be issued by a special purpose entity and will be without recourse to the
general credit of the Company. Similarly, the right to receive the revenues
pledged to secure the bonds is a specific right of the special purpose entity
and not the Company. However, as a wholly owned subsidiary of the Company,
revenues of the special purpose entity are expected to be shown as revenues on
the Consolidated Statement of Income of the Company. This right to receive
revenues will have been transferred to the special purpose entity issuing the
bonds and will not be the property of the Company. As a result of such
features, the bonds carry a relatively low interest rate and allow the Company,
on a consolidated basis, to carry higher debt levels in relation to equity than
would otherwise be desirable.
A filing requesting authorization to issue up to $65,000,000 in
transition bonds related to the natural gas transition costs and bond issuance
costs was made to the PSC in November 1997. In April 1998, the PSC approved
the issuance of up to $65,000,000 of transition bonds and the Company expects
the issuance of approximately $60,000,000 of bonds to occur in the third
quarter of this year.
On January 5, 1998, Enron Capital & Trade Resources Corp. (Enron)
requested court review of the Montana Public Service Commission's (PSC)
decision regarding the measure of natural gas transition costs as well as the
level of functional separation of the various segments of the Company's
natural gas business. This appeal was resolved by settlement in April 1998.
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.
As required by the electric 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. Initial hearings on the filing began April 26, 1998 and the
issues involved in the restructuring filing have been separated into three
groups. The Company expects the PSC to render a decision on the issues
surrounding customer choice for the large industrial group and the pilot
programs before July 1998. The Company expects a decision on the remaining
issues, including the amount of transition costs, the effect of the sale of
the generation assets and the Uniform Systems Benefits Charge, later this
year. The PSC will consider the Company's efforts to mitigate transition costs
in making its determination.
In December 1997, the Company announced that it would offer for sale all
of its electric generating facilities in Montana, consisting of 1,157.4
megawatts of capacity from 13 hydroelectric projects and its interests in four
coal-fired thermal generating units. In addition, the Company offered for sale
its 222 megawatt leasehold interest in Colstrip Unit 4, its power purchase
contracts with qualifying facilities and Basin Electric Power Cooperative
(Basin), and two power exchange agreements.
The sale process began in 1998 with offering memorandums being sent to
30 to 50 potential buyers. In June, the Company expects to receive non-
binding preliminary bids from potential buyers. The top bidders, expected to
number less than ten, will be short-listed for further negotiations and
binding bids. The winning bidder is expected to be selected in mid- to late
summer and financial closing will occur as soon as all required legal and
regulatory approvals are complete, possibly three months to two years after
selection of the winning bidder. The Company intends to proceed with the sale
process as tentatively scheduled, however, this divestiture is not a
requirement of the restructuring bill as is the case in other states with
deregulation legislation and the Company may at any time cease to continue
this option.
Responses to the restructuring legislation and the Company's decision to
offer for sale its generations assets include two calls for a special
legislative session to amend or repeal the electric restructuring legislation
and two proposed ballot issue initiatives. One of the proposed ballot issue
initiatives would seek from voters in the November 1998 general election repeal
of the electric restructuring legislation. The second would seek approval of
law to require the condemnation of the Company's water rights associated with
its hydroelectric plants. The first call for a special legislative session was
unsuccessful. Such efforts are in the preliminary stages and the Company is
unable to predict the outcome of such efforts or any other efforts to modify or
repeal the legislation.
As a result of a three-year rate plan approved by the PSC in 1996,
electric rates increased 2.5%, or approximately $9,000,000, effective January
1, 1998.
NOTE 2 - CONTINGENCIES:
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.
On June 25, 1997, FERC approved a mitigation plan, substantially adopting
the Department's conditions. The mitigation plan calls for payments totaling
approximately $135,000,000 over the 35-year term of the license. The net
present value of the total amount, using an assumed discount rate of 9.5%, 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 of 1997.
The Company, the Tribes and the Department requested rehearing of FERC's
June 25, 1997 order. The Company asserted that the Department's conditions are
unreasonable and that FERC should modify them. In the event FERC does not
modify the mitigation plan it ordered, 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 has analyzed the recommendations and
submitted comments. The analysis indicates that the FERC Staff's
recommendations do not materially change the cost of relicensing and proposed
environmental mitigation, previously estimated to be approximately
$162,000,000 on a net present value basis. The Company expects to receive a
license order in late 1999 or early 2000.
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 an "unusual
condition" 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 is uncertain.
Houston Lighting & Power (HL&P), the purchaser of lignite produced by
Northwestern Resources Co. (Northwestern), a Company subsidiary, filed
litigation on October 5, 1995 in the District Court of the 157th Judicial
District, Harris County, Texas, seeking, among other remedies, a declaratory
judgment that changed conditions required 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 alleged Northwestern failed to
renegotiate these fees in good faith. HL&P sought a reduction exceeding 60% in
the LSA fees. It alleged that the reduction should be retroactive to
September 1, 1995. Additionally, HL&P sought a declaration that it may
substitute other fuels for lignite without violating the LSA.
Trial concluded in December 1997 with the jury denying all of HL&P's
claims regarding changed circumstances and Northwestern's alleged obligations
to negotiate reduced fees. Thus, current pricing under the terms of the LSA is
unchanged. In a pretrial summary judgment, the trial court concluded other
fuel may be substituted for lignite at the Limestone Plant. Northwestern
intends to appeal this summary judgment. Northwestern believes it will
maintain a price for lignite that is competitive with alternate fuels.
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.
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,
firm-supply commitments and natural gas transportation agreements. The
Company uses derivatives as hedging instruments to achieve earnings targets,
reduce earnings volatility and provide more stablized cash flows. When
fluctuations in natural gas and crude oil market prices result in the Company
realizing gains on the derivative instruments 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 and option
agreements to hedge revenue from anticipated production of crude oil and
natural gas reserves, supply costs and transportation commitments 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 or paid by the Company for commodity purchases. Under option
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 price established in the agreement depending on whether the Company
sells or buys the option. At March 31, 1998, the Company had no hedge
agreements on crude oil. The Company had swap and option agreements on
approximately 0.46 Bcf of Nonutility natural gas, or 5% of its expected
production from proved, developed and producing Nonutility natural gas
reserves through October 1998. The Company had swap and option agreements to
hedge approximately 3.4 Bcf of Nonutility natural gas, or 26% of its expected
delivery obligations under long-term natural gas sales contracts through March
1999. In addition, the Company had swap and option agreements to hedge
approximately 1.8 Bcf, or 4%, of its Nonutility natural gas pipeline
transportation obligations under contracts through October 1999.
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 derivative instruments are reflected in
operating revenues on the Consolidated Statement of Income at the same time as
the recognition of the revenue or expense associated with the underlying
hedged item. If the Company determines that any portion of the underlying
hedged item will not be produced or purchased, the unmatched portion of the
instrument is marked-to-market and any gain or loss is recognized in the
Consolidated Statement of Income. If the Company terminates a hedging
instrument prior to the date of the anticipated natural gas or crude oil
production, commodity purchase or transportation commitment, the gain or loss
from the agreement is deferred in the Consolidated Balance Sheet at the
termination date. At March 31, 1998, 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 March 31, 1998, 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 - COMMITMENTS:
The Montana Power Group (MPG), an energy supply and management alliance,
was exclusively endorsed by the California Manufacturers Association (CMA) to
assist its members with their energy decisions. As a participant in the MPG,
Montana Power Trading and Marketing Company (MPT&M), a Nonutility subsidiary
of the Company has agreed to offer energy supply, discounted from the power
exchange prices, and energy management products and services to members of the
CMA. The supply program is offered on a limited basis and is capped at
predetermined volumes. Once the caps are fully subscribed, the Company will
have, at its sole discretion, the option to extend the offered supply and
services to other CMA members. At March 31, 1998, three contracts had been
signed by the Company for electric supply for the next two years with service
beginning April 1, 1998. At this time, the Company cannot predict the impact
of the CMA agreement on future earnings, however, due to the limits provided
in the agreement, any potential negative impacts are not expected to have a
material impact on the Company's financial position or results of operations.
NOTE 6 - LONG-TERM DEBT
On January 2, 1998, the Company used short term borrowings to retire
$16,000,000 in sinking fund debentures.
On April 6, 1998, the Company issued $60,000,000 of floating rate Medium
Term Notes, Series B, due April 6 2001, the proceeds of which were used to
reduce outstanding debt.
NOTE 7 - COMPREHENSIVE INCOME
During June 1997, the Financial Accounting Standards Board (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.
During the three-month periods ended March 31, 1998 and 1997, the
Company's components included adjustments of $3,900,000 and $771,000,
respectively, to retained earnings for the foreign currency translation
adjustments. The 1998 adjustment results not only from the change in the
valuation of the assets of the Company's Canadian operations, but also a change
in the rate used to adjust certain Canadian assets. Until November 1, 1997,
the plant of the Company's natural gas utility operations, owned by a wholly
owned subsidiary, were included in natural gas utility rate base. As such, the
Company earned a rate of return on these assets stated at their historical
costs, converted to U.S. dollars using historical foreign currency exchange
rates. When the assets were transferred from the Company's regulated
operations to the unregulated operations, and removed from utility rate base,
they were converted to U.S. dollars using current foreign currency exchange
rates which resulted in a decrease of approximately $5,100,000 in retained
earnings in 1998.
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, 1997.
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.
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 Quarters Ended March 31, 1998 and 1997:
Net Income Per Share of Common Stock:
The Montana Power Company had consolidated net income of $0.64 per share
for the quarter ended March 31, 1998, compared to first-quarter earnings of
$0.83 per share a year earlier.
For the quarter, Utility earnings were 34 cents a share compared to 52
cents in the first quarter of 1997. Nonutility earnings were 30 cents a share
compared to 31 cents a year earlier.
The Utility was adversely affected by winter's El Nino weather patterns,
which had a compound effect in the Company's Montana service territory. First,
winter weather in the primary heating months of January and February was 9
percent warmer than normal, reducing the natural gas utility's earnings by 4
cents per share. And because normal winter moisture was pushed further south,
there was a significant reduction in hydro-electric generation capability.
The combination of reduced hydro output and commencement of a long-term
seasonal power-purchase agreement reduced the electric utility's performance
by 9 cents per share. A timing difference on natural gas utility
restructuring costs reduced net income by 4 cents a share.
The earnings improvements by Touch America nearly offset the impact of
an $8.2 million (15 cents per share) decrease in Nonutility income resulting
primarily from reduced volumes and prices for oil and natural gas as well as 5
cents from a non-recurring asset sale.
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,
1998 1997
Utility Operations $ 0.34 $ 0.52
Nonutility Operations 0.30 0.31
Consolidated $ 0.64 $ 0.83
</TABLE>
<TABLE>
<CAPTION>
UTILITY OPERATIONS
For Three Months Ended
March 31, March 31,
1998 1997
Thousands of Dollars
<S> <C> <C>
ELECTRIC UTILITY:
REVENUES:
Revenues $ 116,798 $ 122,008
Intersegment revenues 996 1,337
117,794 123,345
EXPENSES:
Power supply 39,967 35,845
Transmission and distribution 8,584 9,317
Selling, general and administrative 13,316 13,510
Taxes other than income taxes 12,097 12,829
Depreciation and amortization 13,185 12,756
87,149 84,257
INCOME FROM ELECTRIC OPERATIONS 30,645 39,088
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues) 26,666 40,228
Gas supply cost revenues 14,378 6,852
Intersegment revenues 130 233
41,174 47,313
EXPENSES:
Gas supply costs 14,378 6,852
Other production, gathering and exploration 645 2,533
Transmission and distribution 3,635 3,487
Selling, general and administrative 4,558 4,263
Taxes other than income taxes 3,372 4,254
Depreciation, depletion and amortization 2,204 3,128
28,792 24,517
INCOME FROM NATURAL GAS OPERATIONS 12,382 22,796
INTEREST EXPENSE AND OTHER INCOME:
Interest 13,445 12,138
Distributions on mandatorily redeemable preferred
securities of subsidiary trust 1,373 1,373
Other (income) deductions - net (116) (755)
14,702 12,756
INCOME BEFORE INCOME TAXES 28,325 49,128
INCOME TAXES 8,456 20,209
DIVIDENDS ON PREFERRED STOCK 923 923
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 18,946 $ 27,996
</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
1998 in the Company's service territory were 5% warmer than 1997 and 6% warmer
than the historic average. In addition, winter weather for the primary
heating months of January and February was 9% warmer than normal.
See Note 1 - Deregulation and Asset Divestiture, and Other Regulatory
Matters in the Notes to the Consolidated Financial Statements for a
description of the transition in the electric and natural gas utility business
to competition.
For its regulated operations, the Company follows SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Pursuant to this
pronouncement, certain expenses and credits, normally reflected in income as
incurred, are recognized when included in rates and recovered from or refunded
to the customers. Changes in regulation or changes in the competitive
environment could result in the Company not meeting the criteria of SFAS No.
71. If the Company were to discontinue application of SFAS No. 71 for some or
all of its operations, the regulatory assets and liabilities related to those
portions would have to be eliminated from the balance sheet and included in
income in the period when the discontinuation occurred unless recovery of
those costs was provided through rates charged to those customers in a portion
of the business that remains regulated. In conjunction with the ongoing
changes in the electric industry, the Company will continue to evaluate the
applicability of this accounting principle to that business. Based upon the
Company's anticipated recovery of its regulatory assets in accordance with the
electric restructuring legislation, the Company believes that the
discontinuation of regulatory accounting for these generation assets will not
have a material impact on the Company's financial position or results of
operations.
The Company has existing long-term contracts for the purchase and sale
of electricity that have fixed price components. To the extent that these
contracts are not addressed in the restructuring docket, the Company would
become subject to the commodity price risks associated with meeting these
obligations.
<TABLE>
<CAPTION>
Electric Utility:
Revenues and
Power Supply Expenses Volumes Customers
(Thousands of Dollars) (Thousands of MWh) (Quarterly Average)
3/31/98 3/31/97 3/31/98 3/31/97 3/31/98 3/31/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial and
Government $ 74,488 $ 76,008 (2)% 1,131 1,168 (3)% 279,473 275,342 2 %
Industrial 28,567 26,320 9 % 656 603 9 % 2,340 2,334 0 %
General Business 103,055 102,328 1 % 1,787 1,771 1 % 281,813 277,676 1 %
Sales to Other
Utilities 9,335 15,973 (42)% 437 898 (51)% 84 84 0 %
Other 4,408 3,707 19 %
Intersegment 996 1,337 (26)% 21 46 (54)% 231 228 1 %
Total $117,794 $123,345 (5)% 2,245 2,715 (17)% 282,128 277,988 1 %
Power Supply
Expenses:
Hydroelectric $ 5,664 $ 5,385 5 % 818 1,083 (24)%
Steam 11,708 12,280 (5)% 1,022 1,040 (2)%
Purchases
and Other 22,595 18,180 24 % 795 847 (6)%
Total Power Supply $ 39,967 $ 35,845 11 % 2,635 2,970 (11)%
Cents Per kWh $1.517 $1.207
</TABLE>
Revenues from general business customers increased slightly in the first
quarter of 1998 as a result of increased rates and customer growth. Warmer
weather for the period partially offset these increases. Decreased
hydroelectric generation resulting from reduced winter moisture as well as
scheduled maintenance and other generator repairs at the Corette thermal plant
resulted in decreased sales to other utilities. The Corette plant was off-
line from December 1997 through mid-April 1998 and is expected to be taken
off-line for further maintenance from mid-May through mid-June 1998.
The combination of reduced electric generation and the commencement of a
long-term seasonal power-purchase agreement in January 1998 resulted in
increased purchase power costs. Higher qualifying facility rates also
contributed to the increase.
<TABLE>
<CAPTION>
Natural Gas Utility:
Revenues Volumes Customers
(Thousands of Dollars) (Thousands of Mmcf) (Quarterly Average)
3/31/98 3/31/97 3/31/98 3/31/97 3/31/98 3/31/97
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Residential,
Commercial and
Government $ 35,880 $ 41,681 (14)% 8,115 9,380 (13)% 145,243 141,197 3 %
Industrial 642 1,020 (37)% 151 238 (37)% 399 426 (6)%
Subtotal 36,522 42,701 (14)% 8,266 9,618 (14)% 145,642 141,623 3 %
Gas Supply Cost
Revenues (GSC) (14,378) (6,852) (110)%
General Business
without GSC 22,144 35,849 (38)% 8,266 9,618 (14)% 145,642 141,623 3 %
Sales to Other
Utilities 250 353 (29)% 94 114 (18)% 3 3 0 %
Transportation 3,102 2,545 22 % 6,953 7,607 (9)% 21 33 (36)%
Other 1,170 1,481 (21)%
Total $ 26,666 $ 40,228 (34)% 15,313 17,339 (12)% 145,666 141,659 3 %
</TABLE>
Sales volume decreases due to warmer winter weather, partially offset by
customer growth, resulted in decreased revenues in the first quarter of 1998.
The restructuring of the natural gas utility also affected its operating
results for the period. In November 1997, almost all of the Company's regulated
natural gas production assets were transferred to its Nonutility affiliate, MP
Gas. Since that time, operating expenses related to the transferred assets
have been included in the Company's Nonutility oil and natural gas operations.
The absence of these expenses in the Utility's natural gas operations resulted
in reduced non-gas supply cost revenues and expenses in the first quarter of
1998. Timing differences between reductions in non-gas supply cost accruals
and corresponding reductions in consumption-based revenues caused a decrease in
operating income.
As part of the restructuring mentioned above, the Utility is no longer
producing most of its natural gas, but has contracted to purchase gas from its
Nonutility affiliate. The contract price includes costs associated with the
transferred assets and returns on those assets. Gas cost revenues and
expenses, which are always equal due to regulated rate and accounting
procedures, increased in the first quarter of 1998 due to the new purchase
contract. Amortizations of prior period under-collections also contributed to
the increase.
Other Income and Expense:
Increases in interest expense in the first quarter of 1998 due to
increased short-term borrowing and the mid-1997 recognition of the Kerr
Project mitigation liability were partially offset by decreases related to
retirements of long-term debt in the first and fourth quarters of 1998 and
1997, respectively.
Income taxes decreased in the first quarter of 1998 due to lower before-
tax net income and a reduced effective tax rate.
<TABLE>
<CAPTION>
NONUTILTY OPERATIONS
For Three Months Ended
March 31, March 31,
1998 1997
Thousands of Dollars
<S> <C> <C>
COAL:
REVENUES:
Revenues $ 43,426 $ 42,371
Intersegment revenues 10,198 8,079
53,624 50,450
EXPENSES:
Operations and maintenance 31,765 29,708
Selling, general and administrative 5,052 4,939
Taxes other than income taxes 6,689 5,819
Depreciation, depletion and amortization 2,736 1,166
46,242 41,632
INCOME FROM COAL OPERATIONS 7,382 8,818
OIL AND NATURAL GAS:
REVENUES:
Revenues 23,546 42,356
Intersegment revenues 4,746 106
28,292 42,462
EXPENSES:
Operations and maintenance 16,514 24,469
Selling, general and administrative 3,483 2,250
Taxes other than income taxes 1,351 1,560
Depreciation, depletion and amortization 5,377 4,300
26,725 32,579
INCOME FROM OIL AND NATURAL GAS OPERATIONS 1,567 9,883
INDEPENDENT POWER:
REVENUES:
Revenues 18,576 17,198
Earnings from unconsolidated investments 1,553 3,025
Intersegment revenues 569 817
20,698 21,040
EXPENSES:
Operations and maintenance 18,673 15,904
Selling, general and administrative 974 1,089
Taxes other than income taxes 466 495
Depreciation, depletion and amortization 919 305
21,032 17,793
INCOME (LOSS) FROM INDEPENDENT POWER OPERATIONS $ (334) $ 3,247
NONUTILITY OPERATIONS (continued)
For Three Months Ended
March 31, March 31,
1998 1997
Thousands of Dollars
TELECOMMUNICATIONS:
REVENUES:
Revenues $ 20,382 $ 6,981
Earnings from unconsolidated investments 2,080 23
Intersegment revenues 251 181
22,713 7,185
EXPENSES:
Operations and maintenance 5,947 4,835
Selling, general and administrative 2,207 1,635
Taxes other than income taxes 1,245 136
Depreciation, depletion and amortization 1,532 254
10,931 6,860
INCOME FROM TELECOMMUNICATIONS OPERATIONS 11,782 325
OTHER OPERATIONS:
REVENUES:
Revenues 26,616 252
Intersegment revenues 345 290
26,961 542
EXPENSES:
Operations and maintenance 24,103 218
Selling, general and administrative 982 980
Taxes other than income taxes 304
Depreciation, depletion and amortization 1,133 133
26,522 1,331
INCOME (LOSS) FROM OTHER OPERATIONS 439 (789)
INTEREST EXPENSE AND OTHER INCOME:
Interest 2,229 1,112
Other (income) deductions - net (2,783) (4,750)
(554) (3,638)
INCOME BEFORE INCOME TAXES 21,390 25,122
INCOME TAXES 5,392 7,836
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK $ 15,998 $ 17,286
</TABLE>
This table was included as an exhibit to a Current Report on Form 8-K,
dated April 23, 1998, filed with the Securities and Exchange Commission. The
information has been revised from that included in such Form 8-K to eliminate
the material intersegment sales and expenses which are not arm's length
transactions. These revisions had no effect on the previously reported
consolidated net income or the income from operations of any of the segments.
NONUTILITY OPERATIONS:
Coal Operations:
Income from coal operations decreased compared to a year ago first
quarter. Revenues from the Rosebud Mine increased $3,500,000. Volume of coal
sold to the Colstrip Units in 1998 increased 29% which was partially offset by
a price reduction resulting from the settlement of a dispute with Puget and a
short-term contract modification with certain other Colstrip partners.
Revenues from the Jewett mine decreased $1,000,000 as a result of a 22%
decrease in volumes of lignite sold due to generating plants being shut down
for repairs.
Operation and maintenance expense, taxes other than income taxes and
depreciation, depletion and amortization increased primarily due to increased
volumes at the Rosebud mine and increased stripping costs at the Jewett mine.
Oil and Natural Gas Operations:
The following table shows changes from the previous year, in millions of
dollars, in the various classifications of revenue and the related percentage
changes in volumes sold and prices received:
Oil -revenue $ (5)
-volume (45)%
-price/bbl (37)%
Natural gas -revenue $ (11)
-volume (17)%
-price/Mcf (19)%
Miscellaneous $ 2
Income from oil and natural gas operations decreased due to lower market
prices in the first quarter of 1998 and accounting changes in the Company.
Revenues from oil operations decreased from lower prices and due to the sale
of production properties in conjunction with the Company's increased emphasis
on its natural gas operations. Natural gas revenues decreased due to lower
prices and a change in the accounting for the natural gas marketing activities
from oil and gas operations to Montana Power Trading and Marketing Company
(MPT&M), which is included in other operations. Effective January 1, 1998,
with the exception of gas sold to supply long-term contracts to co-generators,
substantially all market purchases of natural gas and their subsequent resale
are now recorded on the books of MPT&M. These decreases in revenue were
partially offset by the sale of production from the Vessels properties
acquired in the second quarter of 1997 and from formerly regulated gas
production assets transferred to oil and natural gas operations in the fourth
quarter of 1997. Miscellaneous revenues increased primarily as a result of
increased processing and gathering revenues.
Operation and maintenance expense decreased due to lower gas purchase
costs resulting from the accounting change for marketing activities discussed
above. This decrease was partially offset by expenses of operating the Vessels
properties and transferred regulated assets. These new operations also
accounted for the increases in selling, general and administrative and
depreciation, depletion and amortization expenses.
Independent Power Operations:
Net income from independent power operations for the first quarter 1998
decreased primarily as a result of a $2,800,000 increase in operations and
maintenance expense. Increased project development costs of $2,300,000 due to
a new domestic investment opportunity combined with higher power supply
expense of $970,000 contributed to the increase. Slightly offsetting the
increase was a decrease in purchase power expense of $570,000. During the
first quarter of 1998, the Colstrip plant generated more energy than in the
first quarter of 1997 due to increased long-term power sales volumes and a
stronger market.
Earnings from unconsolidated investments decreased $1,700,000 due to
costs associated with refinancing an existing project. The decrease was
offset by a $1,460,000 increase in revenues from long-term power sales
resulting from an increase in volumes sold.
Telecommunications Operations:
Revenues from telecommunications operations increased primarily due to
revenues on its Washington to Minnesota, Colorado to Canada fiber optic
network and a 36% higher volume of long-distance minutes sold. Revenues from
the additional fiber optic network did not begin until the third quarter of
1997. Telecommunications operations has a one-third interest in a limited
liability company which made sales in the first quarter on a Portland to Los
Angeles fiber optic network currently under construction. These sales account
for the $2,000,000 increase in earnings from unconsolidated investment.
Expenses for the first quarter were higher due to the operation of the
Washington to Minnesota, Colorado to Canada fiber optic network mentioned
above.
Other Operations:
Revenues and expenses in other operations include primarily the
activities of MPT&M. In addition to the natural gas marketing activities
discussed in oil and gas operations above, MPT&M is also recording on its
books the purchase and resale of any electricity which does not utilize the
Utility's electric system. Natural gas revenues were approximately $25,000,000
and the corresponding gas purchase expense was approximately $22,000,000.
Interest Expense and Other Income:
Interest expense increased primarily due to increases in the amount of
outstanding borrowings to provide short-term financing for the Company's
expansion of telecommunications and oil and natural gas operations.
Other (income) and deductions - net decreased due to a $4,200,000 gain
realized on dispositions of oil and natural gas properties in the first
quarter of 1997. This gain was partially offset by increased costs associated
with a discontinued project.
LIQUIDITY AND CAPITAL RESOURCES:
Operating Activities --
Net cash provided by operating activities was $81,063,000 during the
period compared to $135,943,000 in the first quarter 1997. The current year
decrease of $54,880,000 was due primarily to decreased Utility revenues during
December 1997 and January and February of 1998 compared to the same period last
year and construction costs incurred which will be reimbursed in future
periods.
Investing Activities --
Net cash used for investing activities was $20,358,000 during the period
compared to $15,739,000 in the first quarter 1997. The current year increase
of $4,619,000 was due primarily to the decrease in property sales in 1998,
partially offset by a decrease in capital expenditures.
Forecasted capital expenditures for 1998 are as follows:
Forecasted
1998
Thousands of Dollars
Utility $ 77,000
Nonutility 174,000
Total $ 251,000
Financing Activities --
On January 2, 1998, the Company used short term borrowings to retire
$16,000,000 in sinking fund debentures.
On April 6, 1998, the Company issued $60,000,000 of floating rate Medium
Term Notes, Series B, due April 6 2001, the proceeds of which were used to
reduce outstanding debt.
The Company's consolidated borrowing ability under its Revolving Credit
and Term Loan Agreements was $160,000,000, of which $65,000,000 was unused at
March 31, 1998.
SEC RATIO OF EARNINGS TO FIXED CHARGES:
For the twelve months ended March 31, 1998, the Company's ratio of
earnings to fixed charges was 2.71 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 PRONOUNCEMENT:
During February 1998, the FASB issued SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits". SFAS No. 132
revises employers' disclosures about pension and other postretirement plans
currently provided under the provisions of SFAS Nos. 87, 88 and 106. Although
the statement will affect the presentation of the information, it does not
change the measurement or recognition of those plans, and therefore it will not
affect the Company's financial position or results of operations. The statement
is effective for fiscal years beginning after December 15, 1997.
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
Houston Power & Light Lignite Sales Agreement Dispute
Refer to Part 1, "Notes to the Consolidated Financial Statements -
Note 2" 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, 1998.
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K
DATE SUBJECT
January 27,1998 Item 5 Other Events. Discussion of Fourth
Quarter Net Income.
Item 7 Exhibits. Preliminary Consolidated
Statements of Income for the Quarters
Ended December 31, 1997 and 1996 and for
the Years Ended December 31, 1997 and
1996. Preliminary Utility Operations
Schedule of Revenues and Expenses for the
Quarters Ended December 31, 1997 and 1996
and for the Years Ended December 31, 1997
and 1996. Preliminary Nonutility
Operations Schedule of Revenues and
Expenses for the Quarters Ended
December 31, 1997 and 1996 and for the
Years Ended December 31, 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: May 14, 1998
Exhibit 12
THE MONTANA POWER COMPANY
Computation of Ratio Earnings to Fixed Charges
(Dollars in Thousands)
Twelve Months
Ended
March 31,1998
Net Income $ 123,649
Income Taxes 47,673
$ 171,322
Fixed Charges:
Interest $ 63,678
Amortization of Debt Discount,
Expense and Premium 1,510
Rentals 35,108
$ 100,296
Earnings Before Income Taxes
and Fixed Charges $ 271,618
Ratio of Earning to Fixed Charges 2.71 x
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 3/31/98, the Consolidated Income Statement and
Consolidated Statement of Cash Flows for the three months ended 3/31/98 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-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> MAR-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,508,227
<OTHER-PROPERTY-AND-INVEST> 666,253
<TOTAL-CURRENT-ASSETS> 290,699
<TOTAL-DEFERRED-CHARGES> 369,372
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,834,551
<COMMON> 698,852
<CAPITAL-SURPLUS-PAID-IN> 2,072
<RETAINED-EARNINGS> 324,824
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,025,748
65,000
57,654
<LONG-TERM-DEBT-NET> 669,701
<SHORT-TERM-NOTES> 101,482
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 63,105
0
<CAPITAL-LEASE-OBLIGATIONS> 815
<LEASES-CURRENT> 693
<OTHER-ITEMS-CAPITAL-AND-LIAB> 850,353
<TOT-CAPITALIZATION-AND-LIAB> 2,834,551
<GROSS-OPERATING-REVENUE> 294,102
<INCOME-TAX-EXPENSE> 13,848
<OTHER-OPERATING-EXPENSES> 230,239
<TOTAL-OPERATING-EXPENSES> 244,087
<OPERATING-INCOME-LOSS> 50,015
<OTHER-INCOME-NET> 1,729
<INCOME-BEFORE-INTEREST-EXPEN> 51,744
<TOTAL-INTEREST-EXPENSE> 15,877
<NET-INCOME> 35,867
923
<EARNINGS-AVAILABLE-FOR-COMM> 34,944
<COMMON-STOCK-DIVIDENDS> 21,970
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 81,063
<EPS-PRIMARY> 0.64
<EPS-DILUTED> 0.64
</TABLE>
