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, 2000
- -- 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) 497-3000
________________________________________________________
(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 9, 2000, the Company had 105,572,301 shares of common stock
outstanding.
<PAGE>
<TABLE>
PART I
ITEM 1 - FINANCIAL STATEMENTS
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<CAPTION>
For Three Months Ended
March 31,
March 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
REVENUES
$ 364,864
$ 321,768
EXPENSES:
Operations
206,693
153,560
Maintenance
17,276
19,630
Selling, general, and administrative
36,928
33,143
Taxes other than income taxes
26,331
25,768
Depreciation, depletion, and amortization
25,105
27,754
312,333
259,855
INCOME FROM OPERATIONS
52,531
61,913
INTEREST EXPENSE AND OTHER INCOME:
Interest
11,390
13,629
Distributions on mandatorily redeemable
Preferred securities of subsidiary trusts
1,373
1,373
Other (income) deductions - net
(8,343)
(3,869)
4,420
11,133
INCOME TAXES
16,832
16,956
NET INCOME
31,279
33,824
DIVIDENDS ON PREFERRED STOCK
923
923
NET INCOME AVAILABLE FOR COMMON STOCK
$ 30,356
$ 32,901
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - BASIC (000)
105,552
110,146
BASIC EARNINGS PER SHARE OF COMMON STOCK
$ 0.29
$ 0.30
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING - DILUTED (000)
107,041
110,799
DILUTED EARNINGS PER SHARE OF COMMON STOCK
$ 0.28
$ 0.30
<FN>
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
A S S E T S
<CAPTION>
March 31,
December 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
PLANT AND PROPERTY IN SERVICE:
UTILITY PLANT (includes $5,950 and $3,782
Plant under construction)
Electric
$ 1,054,545
$ 1,050,344
Natural gas
413,546
416,383
1,468,091
1,466,727
Less - accumulated depreciation and depletion
475,726
464,653
992,365
1,002,074
NONUTILITY PROPERTY (includes $125,329 and $134,817
Property under construction)
1,112,941
1,051,997
Less - accumulated depreciation and depletion
395,435
349,045
717,506
702,952
1,709,871
1,705,026
MISCELLANEOUS INVESTMENTS:
Independent power investments
22,658
23,460
Reclamation fund
44,037
43,460
Other
95,673
93,231
162,368
160,151
CURRENT ASSETS:
Cash and cash equivalents
417,218
554,407
Temporary investments
32,677
40,417
Accounts receivable, net of allowance for doubtful
accounts
190,042
182,248
Materials and supplies (principally at average cost)
36,772
37,928
Prepayments and other assets
75,554
53,733
Deferred income taxes
19,017
18,303
771,280
887,036
DEFERRED CHARGES:
Advanced coal royalties
12,280
12,506
Regulatory assets related to income taxes
60,539
60,538
Regulatory assets - other
149,302
150,486
Other deferred charges
42,554
73,000
264,675
296,530
$ 2,908,194
$3,048,743
<FN>
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
L I A B I L I T I E S
<CAPTION>
March 31,
December 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
CAPITALIZATION:
Common shareholders' equity:
Common stock (240,000,000 shares without par
value authorized; 110,241,951 and 110,218,973
shares issued)
$ 703,153
$ 702,773
Treasury stock (4,682,100 shares authorized,
issued, and repurchased by the Company)
(144,872)
(144,872)
Unallocated stock held by trustee for
Retirement Savings Plan
(19,573)
(20,401)
Retained earnings and other shareholders' equity
500,596
488,975
Accumulated other comprehensive loss
(18,547)
(17,659)
1,020,757
1,008,816
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
601,236
618,512
1,744,647
1,749,982
CURRENT LIABILITIES:
Long-term debt - portion due within one year
39,854
58,955
Dividends payable
18,908
22,746
Income taxes
40,918
152,739
Other taxes
72,319
54,630
Accounts payable
129,826
115,654
Interest accrued
11,702
11,597
Other current liabilities
96,316
92,277
409,843
508,598
DEFERRED CREDITS:
Deferred income taxes
18,755
8,847
Investment tax credits
13,211
13,330
Accrued mining reclamation costs
136,326
135,075
Deferred revenue
266,198
311,751
Net proceeds from the generation sale
216,545
219,726
Other deferred credits
102,669
101,434
753,704
790,163
CONTINGENCIES AND COMMITMENTS (Notes 2 and 5)
$ 2,908,194
$ 3,048,743
<FN>
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
THE MONTANA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
For Three Months Ended
March 31,
March 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
NET CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income
$ 31,279
$ 33,824
Adjustments to reconcile net income to net cash
Provided by operating activities:
Depreciation, depletion, and amortization
25,105
27,754
Deferred income taxes
9,075
(16,954)
Noncash earnings from unconsolidated investments
(5,050)
(6,533)
Other - net
6,492
3,963
Changes in assets and liabilities:
Accounts and notes receivable
(7,794)
26,492
Generation asset sale - net proceeds
(3,181)
- -
Accounts payable
14,172
(15,246)
Income taxes payable
(111,821)
22,501
Deferred revenue and other
(45,553)
251,850
Other assets and liabilities - net
42,476
18,147
Net cash provided by (used for) operating activities
(44,800)
345,798
NET CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
(37,208)
(23,764)
Proceeds from sales of property and investments
2,638
6,536
Additional investments
277
(843)
Net cash used for investing activities
(34,293)
(18,071)
NET CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid
(22,035)
(22,947)
Sales of common stock
377
321
Issuance of long-term debt
16,044
31,048
Retirement of long-term debt
(52,482)
(56,699)
Net change in short-term borrowing
- -
(69,820)
Net cash used for financing activities
(58,096)
(118,097)
CHANGE IN CASH FLOWS
(137,189)
209,630
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
554,407
10,116
CASH AND CASH EQUIVALENTS, END OF PERIOD
$ 417,218
$ 219,746
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during three months for:
Income taxes, net refunds
$ 144,295
$ 113
Interest
12,383
14,971
<FN>
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements of The Montana Power
Company for the interim periods ended March 31, 2000 and 1999 are unaudited.
In the opinion of management, the accompanying consolidated financial
statements reflect all normally recurring accruals necessary for a fair
statement of the results of operations for those interim periods. Results of
operations for the interim periods are not necessarily indicative of the
results to be expected for the full year, and these financial statements do not
contain the detail or footnote disclosure concerning accounting policies and
other matters that would be included in full fiscal year financial statements.
Therefore, these statements should be read in conjunction with our audited
financial statements included in our Annual Report on Form 10-K for the year
ended December 31, 1999.
In prior years, to facilitate the timely preparation of the consolidated
financial statements, we consolidated the accounts of certain operations for
fiscal years ending in November. The consolidated financial statements for the
quarter ended March 31, 2000, eliminate the one-month lag in reporting for
these operations. The results of operations of December 1999 for these
entities, which would have previously been reported in results of the first
quarter of 2000, have been recorded as an adjustment to beginning retained
earnings as of January 1, 2000. This adjustment increased retained earnings by
approximately $1,500,000.
We have made reclassifications to certain prior-year amounts to make them
comparable to the 2000 presentation. These changes had no significant effect
on previously reported results of operations or shareholders' equity.
NOTE 1 - DEREGULATION, REGULATORY MATTERS, SALE OF ELECTRIC GENERATING ASSETS,
AND PROPOSED DIVESTITURE OF ENERGY BUSINESSES
Deregulation
The electric and natural gas utility businesses are in transition to a
competitive market in which commodity energy products and related services are
sold directly to wholesale and retail customers. Montana's Electric Industry
Restructuring and Customer Choice Act (Electric Act), passed in 1997, provides
that all customers will be able to choose their electric supplier by July 1,
2002. Montana's Natural Gas Utility Restructuring and Customer Choice Act
(Natural Gas Act), also passed in 1997, provides that a utility may
voluntarily offer its customers choice of natural gas suppliers and provide
open access. Since natural gas restructuring is voluntary, no deadline for
choice exists.
Electric
Through March 31, 2000, approximately 1,200 electric customers
representing more than 1,800 accounts crossing all customer classifications -
or approximately 27 percent of our pre-choice electric load - have moved to
competitive supply since the inception of customer choice on July 1, 1998.
Residential customers were eligible to move to choice during the fourth
quarter of 1999. However, the majority of the load associated with our pre-
choice electric customers who moved to other suppliers was industrial and
large commercial customers.
As required by the Electric Act, we filed a comprehensive transition
plan with the Montana Public Service Commission (PSC) in July 1997. On
July 1, 1999, we filed a case with the PSC to resolve the Tier II issues under
the filing. Tier II issues address the recovery and treatment of the
<PAGE>
Qualifying Facility (QF) power-purchase contract costs, which are above-market
costs; regulatory assets associated with the electric generating business; and
a review of our electric generating assets sale, including the treatment of
sales proceeds above book value of the assets. We will update our Tier II
filing as a result of the closing of the sale of our electric generating
assets, but we do not expect an order from the PSC until late 2000.
In implementing our comprehensive transition plan, we initiated
litigation in Montana District Court in Butte to seek reversal of a PSC
decision regarding our ability to use tracking mechanisms to ensure fair and
accurate recovery of above-market QF costs and certain other transition costs.
In an order issued as part of its consideration of the transition plan, the
PSC concluded that the Electric Act does not provide for tracking mechanisms
and that transition costs must be mitigated and determined as a final matter
in the transition filing. In the litigation, we also sought court
clarification on whether the Electric Act authorized a rate freeze or a rate
cap during the transition period that ends July 1, 2002. The PSC concluded
that the Electric Act authorized a rate cap, but we disagreed with this
interpretation.
In May 2000, the district court heard oral arguments and issued an
order. The court ruled in our favor on the first issue, emphasizing that the
PSC must allow us to incorporate tracking mechanisms in our transition plan
proposal and that an unconstitutional taking from either shareholders or
customers would result if tracking mechanisms were not used. The court agreed
with the PSC on the second issue, ruling that the Electric Act authorized a
rate cap. We cannot predict whether the PSC will appeal the court's decision,
and we have not yet determined whether we will appeal.
Natural Gas
Through March 31, 2000, approximately 240 natural gas customers with
annual consumption of 5,000 dekatherms or more - 52 percent of our pre-choice
natural gas supply load - have chosen alternate suppliers since the transition
to a competitive natural gas environment began in 1991.
Regulatory Matters
Electric/Federal Energy Regulatory Commission (FERC)
On March 30, 1998, we filed a request with the FERC to increase our open
access transmission rates and the rates for bundled wholesale electric service
to two rural electric cooperatives. FERC approved an interim increase in
rates charged for transmission service, pending final approval in 2000.
In January 1999, we reached a rate settlement with one of the
cooperatives who moved to another supplier in December 1999. In March 1999,
we reached a separate settlement with the other cooperative. We agreed to
assist the cooperative in moving to choice when its full-service wholesale
contract expires in exchange for its agreement to withdraw the rate-reduction
complaint. This cooperative will move to another supplier in June 2000.
Through a filing made with FERC in April 2000, we are seeking recovery
of approximately $23,800,000 in transition costs associated with serving both
of the wholesale electric cooperatives. We do not expect a FERC decision on
this filing, which corresponds with our transition-costs recovery proceedings
with the PSC in Montana, until 2001.
Electric/PSC
Montana's Electric Act established a rate freeze for all electric
customers, meaning that transmission and distribution rates cannot be changed
<PAGE>
until July 1, 2000. In January 2000, as a result of the sale of our electric
generating assets and sales proceeds in excess of the book value of the assets
sold, we filed a voluntary rate reduction with the PSC for approximately
$16,700,000 annually. This reduction became effective February 2, 2000. We
expect to submit a combined electric and natural gas filing with the PSC,
requesting increased rates, in the third quarter of 2000.
Natural Gas/PSC
On August 12, 1999, we filed a natural gas rate case with the PSC
requesting increased annual revenues of $15,400,000, with a proposed interim
increase of $11,500,000. The filing represented our first transmission and
distribution gas filing since Montana's Natural Gas Act was passed.
An interim increase of $7,600,000 became effective on December 10, 1999.
A final PSC order that became effective on April 1, 2000, approved an
additional increase of $2,800,000. As discussed above, we expect to submit a
combined filing with the PSC in the third quarter of 2000 seeking increased
natural gas and electric rates.
Sale of Electric Generating Assets
The sale of our electric generating assets in December 1999 to PPL
Montana, LLC negatively affected the utility's net income for first quarter
2000. Utility revenues decreased because of discontinued off-system revenues
related to the electric generating assets sold. Although the sale of the
assets resulted in lower property taxes for the first quarter 2000, increased
power-supply expenses offset these decreases. Power-supply expenses
increased, despite decreases in fuel expenses. We no longer purchase fuel to
operate the generating plants because we now purchase most of the power to
serve our core customers pursuant to buyback contracts with PPL Montana. The
maximum price that we pay for power in the buyback contracts, $22.25/MWh,
represents our net fully allocated costs of service in current rates,
replacing operations and maintenance expense, depreciation expense, and return
on investment.
In the sale of these assets, we generally retained all pre-closing
obligations, and PPL Montana generally assumed all post-closing obligations.
However, with respect to environmental liabilities, PPL Montana assumed all
pre-closing (subject to certain indemnification provisions) and post-closing
environmental liabilities associated with the purchased assets, with certain
exceptions for pre-closing liabilities.
We agreed to indemnify PPL Montana, on a limited basis, from losses
arising from required remediation of pre-closing environmental conditions,
whether known or unknown at the closing. During the first quarter of 2000,
PPL Montana did not deliver any claim notices to us with respect to this
indemnity obligation. We do not expect this indemnity obligation to have a
material adverse effect on our consolidated financial position, results of
operations, or cash flows.
Proposed Divestiture of Energy Businesses
On March 28, 2000, we announced our intent to separate our
telcommunications business from our energy businesses through stock sale(s) of
our energy businesses. When we complete the sale(s), expected to take six to
twelve months from the end of the first quarter, Touch America, Inc. will
remain as the entity through which we will continue to conduct our
telecommunications business. We intend to invest the proceeds received from
the sale of our energy businesses into Touch America.
<PAGE>
NOTE 2 - CONTINGENCIES
Kerr Project
A FERC order that preceded our sale of the Kerr Project to PPL Montana
required us to implement a plan to mitigate the effect of the Kerr Project
operations on fish, wildlife, and habitat. To implement this plan, we were
required to make payments of approximately $135,000,000 between 1985 and 2020,
the term during which we would have been the licensee. The net present value
of the total payments, assuming a 9.5 percent annual discount rate, was
approximately $57,000,000, an amount we recognized as license costs in plant
and long-term debt on the Consolidated Balance Sheet in 1997. In the sale of
the Kerr Project, PPL Montana assumed the obligation to make post-closing
license compliance payments.
In December 1998 and January 1999, we asked the United States Court of
Appeals for the District of Columbia Circuit to review FERC's orders and the
United States Department of Interior's conditions contained in them. On
September 17, 1999, the court granted the motion of the parties and
intervenors to hold up the appeal pending settlement efforts. In December
1999, we, along with PPL Montana, the United States Department of the
Interior, the Confederated Salish and Kootenai Tribes (the Tribes), and Trout
Unlimited, in a court-ordered mediation, agreed in principle to settle this
litigation.
A Statement of Agreement containing the principles for settlement of the
disputes underlying the appeals was developed in December 1999. It provides
that its terms are binding against all parties, with the understanding that
the signatory parties will jointly draft additional documents as necessary to
establish the terms of the settlement in detail. The parties have drafted
these documents, and we have paid our settlement payment of approximately
$24,000,000 under the Statement of Agreement into an escrow account. If FERC
approves, in a final non-appealable order, the settlement terms as reflected
in proposed license amendments discussed below, we will dismiss the petitions
in the court of appeals, and the escrow agent will release the payments to the
Tribes. In addition, we will transfer to the Tribes 669 acres of land we own
on the Flathead Indian Reservation. If FERC does not approve the proposed
license amendments in the form agreed to by the parties, or if, as a result of
the appeal of a FERC order, that order is not final after a specified period,
the money will be returned to us, and the litigation will resume. The
settlement, subject to the conditions described above, substantially reduces
our obligation to pay for fish, wildlife, and habitat mitigation assigned to
the pre-closing period in the sale of the Kerr Project.
In April 2000, PPL Montana and the Tribes, as co-licensees, filed
proposed license amendments with FERC to effect the settlement described
above. We supported these proposed license amendments. FERC is reviewing the
filing, but we do not expect a decision until late 2000 or early 2001.
Miscellaneous
We and our subsidiaries are parties to various other legal claims,
actions and complaints arising in the ordinary course of business. We do not
expect the conclusion of any of these matters to have a material adverse
effect on our consolidated financial position, results of operations, or cash
flows.
<PAGE>
NOTE 3 - DERIVATIVE FINANCIAL INSTRUMENTS
Derivative Financial Instruments Used
We use derivative financial instruments to reduce earnings volatility
and stabilize cash flows by hedging some of the price risk associated with our
nonutility energy commodity-producing assets, contractual commitments for firm
supply, and natural gas transportation agreements. We also use derivative
financial instruments in speculative transactions to seek enhanced
profitability based on expected market movements, as discussed below in
"Speculative Transactions." In all cases, financial swap and option
agreements constitute the principal kinds of derivative financial instruments
used for these purposes.
Swap Agreements
Under a typical swap agreement, we make or receive payments based on the
difference between a specified fixed price and a variable price of crude oil
or natural gas at the time of settlement. The variable price is either a
crude oil or natural gas price quoted on the New York Mercantile Exchange or a
natural gas price quoted in Inside FERC's Gas Market Report or other
recognized industry index.
Option Agreements
Under a typical option agreement, we make or receive monthly payments
based on the difference between the actual price of crude oil or natural gas
at settlement and the price established in a private agreement at the time of
execution. Making or receiving payments is dependent on whether we buy (own
or hold) or sell (write or issue) the option. Buying options involves paying
a premium - the price of the option - and selling options involves receiving a
premium. When we use options, we defer all premiums paid or received and
recognize the applicable expenses or revenues monthly throughout the option
term. As of March 31, 2000, our deferred revenues due to option premiums were
approximately $1,500,000.
Hedged Transactions
Hedged transactions are those in which we have a position (either current
or anticipated) in an underlying commodity or derivative of that commodity that
exposes us to risk if the price of the underlying item adversely changes. We
enter into these transactions primarily to reduce earnings volatility and
stabilize cash flows. We recognize gains or losses from these derivative
financial instruments in the Consolidated Statement of Income at the same time
that we recognize the revenues or expenses associated with the underlying
hedged item; until then, we do not reflect these gains or losses in our
financial statements. At March 31, 2000, we had unrecognized gains of
approximately $1,700,000 related to these transactions. As of March 31, 2000,
we had not terminated any significant hedging instrument before the date of the
anticipated commodity production, commodity purchase or sale, or natural gas
transportation commitment.
At March 31, 2000, we had swap and option agreements on approximately:
? 1,460,000 barrels, or 58 percent, of our estimated nonutility crude
oil and natural gas liquids production through March 2002;
? 15 Bcf, or 42 percent, of our expected delivery obligations under
long-term natural gas sales contracts through October 2001; and
? 0.15 Bcf, or 1 percent, of our natural gas production through
December 2000.
<PAGE>
In addition, at March 31, 2000, we had sold swap and option agreements
to hedge approximately 27 Bcf of our nonutility natural gas pipeline
transportation obligations under contracts through December 2001, and we had
purchased swap and option agreements to hedge approximately 33 Bcf of these
obligations.
Speculative Transactions
We also enter into derivative financial transactions in which we have no
underlying price risk exposure nor any interest in making or taking delivery
of crude oil or natural gas commodities. We seek, by these speculative
transactions, to profit from the market movements of the prices of these
commodities. In accordance with Emerging Issues Task Force Issue No. 98-10,
we mark to market all of our speculative transactions and recognize any
corresponding gain or loss in the Consolidated Statement of Income. During
the first quarter 2000, we recorded pretax losses of approximately $600,000
related to these transactions.
NOTE 4 - COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST
We established Montana Power Capital I (Trust) as a wholly owned
business trust to issue common and preferred securities and hold Junior
Subordinated Deferrable Interest Debentures (Subordinated Debentures) that we
issue. The Trust has issued 2,600,000 units of 8.45 percent 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 percent of the liquidation preference value of $25 per security. The
sole asset of the Trust is $67,000,000 of our Subordinated Debentures,
8.45 percent Series due 2036. The Trust will use interest payments received
on the Subordinated Debentures that it holds to make the quarterly cash
distributions on the QUIPS.
NOTE 5 - COMMITMENTS
Touch America's Commitments
Construction Projects
Before 2000, Touch America contracted with Northern Telecom,
Inc. (Nortel) to furnish and install optical electronic equipment on certain
fiber-optic networks. We expect Nortel to complete these installations in the
fourth quarter of 2000 at a cost of $51,800,000, of which we have paid
$28,300,000. The remaining $23,500,000 is scheduled for payment in 2000 as
various segments of the fiber-optic network under construction, discussed
below, are completed. Touch America continues to enter into arrangements with
Nortel for installations of Nortel's optical electronic equipment on Touch
America's network, including installations related to Touch America's
acquisition from Qwest Communications International Inc. (Qwest) discussed
below under "Investments and Acquisitions."
Joint Ventures
In accordance with the agreements governing the following relationships,
Touch America is committed to contribute capital at various times.
In May 2000, Touch America and Sierra Pacific Communications, a
subsidiary of Sierra Pacific Resources, formed a 50-50 joint venture named
Sierra Touch America LLC to construct a fiber-optic network between Sacramento
<PAGE>
and Salt Lake City. This network will make up 750 miles of the 4,300-mile
build-out that Touch America is constructing in tandem with its construction
of a fiber-optic network for AT&T. Sierra Touch America will begin
construction of the Sacramento-Salt Lake City route immediately and expects to
complete the route in mid-2001 at an estimated cost of $100,000,000. Touch
America's portion of this estimated cost (directly and through its interest in
the joint venture) will be approximately $83,000,000, of which it expects to
recover approximately 50 percent from AT&T and other third parties. The terms
of the joint venture agreement give Sierra Touch America a partial interest in
the metropolitan fiber networks that Sierra Pacific Resources operates in Reno
and Las Vegas.
In June 1999, Touch America and Iowa Network Services, Inc. (INS) formed
Iowa Telecommunications Services, Inc. (ITS) to purchase from a third party
domestic access lines connected to telephone exchanges in Iowa. However,
because the emerging organizational and capital structure of ITS does not fit
Touch America's growth strategy, Touch America exited from its equity position
in ITS in April 2000. Under the terms of the exit agreement:
? Touch America sold its 31 percent interest in ITS to INS, and INS
released Touch America from all of ITS' obligations;
? Upon the closing of the third-party purchase transaction, expected to
occur in mid-2000, INS will reimburse Touch America approximately
$8,000,000 for Touch America's cash outlays to ITS; and
? Touch America will not withdraw its $14,000,000 letter of credit from
ITS until the closing of the third-party purchase transaction.
In January 2000, Touch America and AEP Communications LLC, a subsidiary
of American Electric Power, formed a 50-50 joint venture named America Fiber
Touch LLC (AFT) to connect national and regional fiber-optic networks. The
venture's first project is to construct a 330-mile fiber-optic route between
St. Louis, Missouri, and Plano, Illinois, which makes up the Midwest route of
the 4,300 mile build-out for AT&T. This Midwest route is scheduled for
completion in December 2000, at an estimated cost of $25,000,000, of which
Touch America's portion is $12,500,000.
Exchanges and Leases
In March 2000, Touch America and Williams Communications, Inc. agreed to
an exchange of dark fiber to expand both companies' fiber-optic networks.
Touch America receives approximately 1,050 route miles of dark fiber and cash
from Williams, in exchange for approximately 1,200 route miles of Touch
America's dark fiber (from Denver to Dallas through Colorado Springs). This
exchange will expand Touch America's network from Minneapolis to Denver
through Des Moines, Iowa and Topeka, Kansas. Both routes are currently
operational.
In January 2000, Touch America and PF.Net, a privately held
telecommunications company, agreed to a cross lease of fiber and conduit to
expand both companies' fiber-optic networks. Touch America will receive
approximately 5,900 route miles of fiber and conduit from PF.Net for 4,400
route miles of Touch America's fiber and conduit and a cash payment of
$48,500,000 for the difference in route miles. Touch America has made an
initial payment of $4,850,000 and will pay the remainder as segments of the
routes under construction are completed. Segments are scheduled for
completion at various times in 2000 and 2001.
Investments and Acquisitions
In January 2000, Touch America signed an agreement to purchase, from
Century Tel Inc., 400 route miles of fiber-optic network linking Chicago and
<PAGE>
Detroit. Touch America will pay approximately $10,000,000 for the rights to
these route miles, which it expects to be in service by late 2000. Touch
America has made an initial payment of $2,000,000 and will make the remaining
payments as construction is completed.
In January 2000, Touch America signed a purchase agreement with
Minnesota PCS, LP (MPCS) to acquire a 25 percent interest in MPCS' wireless
telephone business, which owns PCS licenses in North Dakota, South Dakota,
Minnesota, and Wisconsin. In accordance with the agreement, Touch America
made an initial equity investment of $2,700,000 in MPCS and, over the years
2000-2001, will loan MPCS $12,000,000 in interest-bearing notes payable on
October 1, 2002, of which a total of $6,000,000 had been loaned in early May
2000. In addition, Touch America will guarantee payment of $7,000,000 in
loans owned by MPCS through the year 2007. The guarantees are callable only
upon MPCS' default.
In March 2000, Touch America signed an agreement with Qwest to acquire
for approximately $193,000,000, subject to certain adjustments, Qwest's
wholesale, private-line, long-distance, and other telecommunications services
in US WEST's 14-state region, which covers 250,000 customer accounts for
voice, data, and video services. By this agreement, Touch America will also
acquire a fiber-optic network of 1,800 route miles and associated optronics
and switches. If the Qwest acquisition is closed, we estimate that related
capital expenditures will be an additional $100,000,000. The network will
connect to Touch America's fiber-optic network, and Touch America will offer
employment to approximately 120 of Qwest's sales agents in the region. We
expect this acquisition to close in mid-2000, subject to the satisfaction of
various conditions and the receipt of required regulatory approvals.
NOTE 6 - LONG-TERM DEBT
On January 3, 2000, we made a payment of approximately $10,200,000 for
our share of the costs associated with the Kerr mitigation plan (Plan). This
amount represented our final liability for costs under the Plan through the
December 17, 1999, sale date of the electric generating assets.
Two issues of Medium-Term Notes (MTNs) were retired prior to maturity in
January of 2000. On January 13, 2000, we retired $5,000,000 of 7.25 percent
Series A Secured MTNs due January 19, 2024. On January 14, 2000, we retired
$7,000,000 of 8.68 percent Series A Unsecured MTNs due February 7, 2022.
We retired at maturity $10,000,000 of 8.80 percent Series A Unsecured
MTNs on February 22, 2000.
On April 13, 2000, we retired prior to maturity $25,000,000 of our
7.5 percent First Mortgage Bonds (Bonds) due April 1, 2001.
On April 25, 2000, we offered to purchase any or all of the following
series of our outstanding debt: 8.95 percent Bonds due February 1, 2022;
7.33 percent Secured MTNs due April 15, 2025; 8.11 percent Secured MTNs due
January 25, 2023; 7.00 percent Bonds due March 1, 2005; and 8.25 percent Bonds
due February 1, 2007. The total amount outstanding for these issues was
$190,000,000 as of March 31, 2000. Prices for the redemption will be set on
May 18, 2000, and the offer to purchase expires on May 23, 2000.
Proceeds received from the sale of the electric generating assets have
been or will be used to make all of the retirements discussed above.
In April 1997, we entered into a $160,000,000 Revolving Credit Agreement
for some of our nonutility operations. Under the terms of the Revolving
<PAGE>
Credit Agreement, the amount of the facility decreased on March 31, 1998,
reducing the borrowing ability to $100,000,000, all of which was unused at
March 31, 2000. This agreement terminated on April 4, 2000, with no amount
outstanding.
NOTE 7 - COMPREHENSIVE INCOME
The Financial Accounting Standards Board defines comprehensive income as
all changes to the equity of a business enterprise during a period, except for
those resulting from transactions with owners. For example, dividend
distributions are excepted. Comprehensive income consists of net income and
other comprehensive income. Net income includes such items as income from
continuing operations, discontinued operations, extraordinary items, and
cumulative effects of changes in accounting principles. Other comprehensive
income includes foreign currency translations, adjustments of minimum pension
liability, and unrealized gains and losses on certain investments in debt and
equity securities.
For the three months ended March 31, 2000 and 1999, our only item of
other comprehensive income was foreign currency translation adjustments of the
assets and liabilities of our foreign subsidiaries. These adjustments
resulted in decreases to retained earnings of $888,000 in the first quarter of
2000, and increases to retained earnings of $665,000 in the first quarter of
1999. No current income tax effects resulted from the adjustments, nor do we
expect there will be any net income effects until we sell a foreign
subsidiary.
NOTE 8 - INFORMATION ON INDUSTRY SEGMENTS:
Our utility operations purchase, transmit, and distribute electricity and
natural gas. With the sale of our electric generating assets other than
Milltown Dam, we no longer are primarily engaged in regulated electric
generation. In our nonutility businesses, our telecommunications operation
designs, develops, constructs, operates, maintains, and manages a fiber-optic
network and wireless facilities; it also sells long-distance, Internet, and
private-line services and equipment. In other nonutility operations, we mine
and sell coal and lignite; manage long-term power sales, and develop and invest
in independent power projects and other energy-related businesses; and explore
for, develop, produce, process, and sell crude oil and natural gas. We also
trade crude oil, natural gas, and natural gas liquids.
Identifiable assets of each industry segment are principally those assets
used in our operation of those industry segments. Corporate assets are
principally cash and cash equivalents and temporary investments.
We consider segment information for foreign operations immaterial.
<PAGE>
<TABLE>
Operations Information:
<CAPTION>
Three Months Ended
March 31, 2000
(Thousands of Dollars)
<S>
<C>
<C>
<C>
UTILITY
Electric
Natural Gas
Sales to unaffiliated customers
$ 101,491
$ 44,794
Earnings from unconsolidated investments
- -
- -
Intersegment sales
1,570
203
Pretax operating income (loss)
12,271
12,052
Capital expenditures
5,607
(3,035)(a)
Identifiable assets
997,301
403,220
NONUTILITY
Tele-
Communications
Coal(b)
Independent
Power(c)
Sales to unaffiliated customers
$ 24,126
$ 57,281
$ 17,749
Earnings from unconsolidated investments
602
- -
5,700
Intersegment sales
308
3,938
200
Pretax operating income (loss)
7,074
8,007
4,659
Capital expenditures
16,930
1,790
61
Identifiable assets
372,719
238,800
45,383
NONUTILITY (continued)
Oil and
Natural Gas
Other
Sales to unaffiliated customers
$ 105,415
$ 7,706
Earnings from unconsolidated investments
- -
- -
Intersegment sales
5,365
1,524
Pretax operating income (loss)
8,950
(482)
Capital expenditures
8,996
1,926
Identifiable assets
306,256
30,780
CORPORATE
Capital expenditures
$ 4,933
Identifiable assets
513,735
RECONCILIATION TO CONSOLIDATED
Segment
Total
Adjustments(d)
Consolidated
Total
Sales to unaffiliated customers
$ 358,562
- -
$ 358,562
Earnings from unconsolidated investments
6,302
- -
6,302
Intersegment sales
13,108
$ (13,108)
- -
Pretax operating income (loss)
52,531
- -
52,531
Capital expenditures
37,208
- -
37,208
Identifiable assets
2,908,194
- -
2,908,194
<FN>
(a) Decreased capital expenditures resulted from reduced levels of natural gas in
underground storage.
(b) The loss of revenues pursuant to one contract with a single customer would have a
material adverse effect on the segment.
(c) The loss of revenues pursuant to contracts with two customers would have a material
adverse effect on the segment.
(d) The amounts indicated include certain eliminations between the business segments.
</TABLE
<PAGE>
</TABLE>
<TABLE>
Operations Information (continued):
<CAPTION>
Three Months Ended
March 31, 1999
(Thousands of Dollars)
<S>
<C>
<C>
<C>
UTILITY
Electric
Natural Gas
Sales to unaffiliated customers
$ 116,534
$ 40,345
Earnings from unconsolidated investments
- -
- -
Intersegment sales
3,690
199
Pretax operating income (loss)
29,674
10,140
Capital expenditures
8,024
- -
Identifiable assets
1,575,186
392,195
NONUTILITY
Tele-
Communications
Coal(a)
Independent
Power(b)
Sales to unaffiliated customers
$ 19,775
$ 43,438
$ 18,234
Earnings from unconsolidated investments
1,423
- -
5,333
Intersegment sales
228
9,904
238
Pretax operating income (loss)
6,743
7,746
6,001
Capital expenditures
5,540
1,634
246
Identifiable assets
196,310
236,726
110,028
NONUTILITY (continued)
Oil and
Natural Gas
Other
Sales to unaffiliated customers
$ 68,809
$ 7,877
Earnings from unconsolidated investments
- -
- -
Intersegment sales
4,400
441
Pretax operating income (loss)
3,441
(1,832)
Capital expenditures
10,314
13
Identifiable assets
296,810
64,252
CORPORATE
Capital expenditures
$ 408
Identifiable assets
244,552
RECONCILIATION TO CONSOLIDATED
Segment
Total
Adjustments(c)
Consolidated
Total
Sales to unaffiliated customers
$ 315,012
- -
$ 315,012
Earnings from unconsolidated investments
6,756
- -
6,756
Intersegment sales
19,100
$ (19,100)
- -
Pretax operating income (loss)
61,913
- -
61,913
Capital expenditures
26,179
(2,415)
23,764
Identifiable assets
3,116,059
- -
3,116,059
<FN>
(a) The loss of revenues pursuant to one contract with a single customer would have a
material adverse effect on the segment.
(b) The loss of revenues pursuant to contracts with two customers would have a material
adverse effect on the segment.
(c) The amounts indicated include certain eliminations between the business segments.
</TABLE>
<PAGE>
NOTE 9 - COMMON STOCK
STOCK SPLIT
On June 22, 1999, the Board of Directors approved a two-for-one split of
our outstanding common stock. As a result of the split, which was effective
August 6, 1999, for all shareholders of record on July 16, 1999, 55,099,015
outstanding shares of common stock were converted to 110,198,030 outstanding
shares of common stock. We have retroactively applied the split to all
periods presented.
SHARE REPURCHASE PROGRAM
In 1998, the Board of Directors authorized a share-repurchase program
over the next five years to repurchase up to 20,000,000 shares (approximately
18 percent of our then outstanding common stock) on the open market or in
privately negotiated transactions. As of May 9, 2000, we had 105,572,301
common shares outstanding. The number of shares to be purchased and the
timing of the purchases will be based on the level of cash balances, general
business conditions, and other factors, including alternative investment
opportunities.
Subsequent to this authorization, we entered into a Forward Equity
Acquisition Transaction (FEAT) program with a bank that committed to purchase
shares on our behalf. Under the terms of the program, the amount owed to the
bank and the number of shares held by the bank cannot exceed certain limits.
In March 2000, these limits were amended and now are $125,000,000 and
2,500,000 shares. The expiration date of the program is October 31, 2000.
Until that date, when all transactions must be settled, we can elect to fully
or partially settle either on a full physical (cash) or a net share basis. A
full physical settlement would be the purchase of shares from the bank for
cash at the bank's average purchase price plus interest costs less dividends.
A net share settlement would be the exchange of shares between the parties so
that the bank receives shares with value equivalent to its original purchase
price plus interest costs less dividends. Only at the time that the
transactions are settled can our capital or outstanding stock be affected, and
settlement has no effect on results of operations.
In December 1999, when the limits described above were $200,000,000 and
8,000,000 shares, we used proceeds from the sale of our generation assets to
acquire 4,682,100 shares of our stock under the FEAT program. The purchase of
these shares averaged approximately $30.94 per share and ranged from $27.05
per share to $33.52 per share for a total cost of $144,872,000. We have
reflected the shares purchased as treasury stock on the Consolidated Balance
Sheet. No additional shares have been acquired under the program in 2000.
<PAGE>
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Please read the following discussion in conjunction with the statements
included in our Annual Report on Form 10-K for the year ended December 31, 1999
at Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
Warnings About Forward-Looking Statements
This Quarterly Report on Form 10-Q may contain forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934. Forward-looking statements are qualified by and should be read together
with the cautionary statements and important factors included in our Annual
Report on Form 10-K for the year ended December 31, 1999. See Part I,
"Warnings About Forward-Looking Statements."
We are 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 us,
or on our behalf, in this 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
statements other than those of historical fact. Forward-looking statements
may be identified, without limitation, by the use of the words "anticipates,"
"estimates," "expects," "intends," "believes," and similar expressions. We
disclaim any obligation to update any forward-looking statements to reflect
events or circumstances after the date that we file this Form 10-Q.
Forward-looking statements that we make 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 our
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 and
telecommunication industries and other industries in which we operate.
Investors or other readers of the forward-looking statements are cautioned
that these statements are not a guarantee of future performance and that the
forward-looking statements are subject to risks and uncertainties that could
cause actual results to differ materially from those expressed in, or implied
by, the statements. Some, but not all, of the risks and uncertainties
include:
? General economic and weather conditions in the areas in which we have
operations;
? Competitive factors and the effects of restructuring in the electric,
natural gas, and telecommunications industries;
? Sanctity and enforceability of contracts;
? Market prices;
? Environmental laws and policies and 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 and interest rates; and
? Changes in accounting principles or the application of such
principles.
<PAGE>
Strategy
We are focused on growing Touch America's revenues and earnings as
demonstrated by the expansion of our fiber-optic network, which we expect to
span more than 26,000 miles by the end of 2001. In pursuing this strategy, we
will continue to investigate different approaches, including asset purchases
and sales, the issuance of securities, and other transactions that may
materially affect our results of operations, liquidity, and capital resources.
For a discussion of how we intend to use proceeds from the sale(s) of our
energy businesses, see the "Proposed Divestiture of Energy Businesses" section
of Note 1, "Deregulation, Regulatory Matters, Sale of Electric Generating
Assets, and Proposed Divestiture of Energy Businesses."
Results of Operations
The following discussion describes significant events or trends that have
had an effect on our operations or which we expect to have an effect on our
future operating results. We have adjusted all 1999 earnings-per-share
information to reflect the two-for-one stock split effective August 6, 1999.
Quarter Ended March 31, 2000 and 1999:
Net Income Per Share of Common Stock (Basic)
First quarter earnings were $0.29 per share, $0.01 less than first
quarter 1999. Utility earnings were $0.08, compared with $0.12 last year.
Nonutility earnings were $0.21, up $0.03 from the $0.18 figure of a year
earlier.
Because we have not yet reinvested all of the proceeds from the
generation sale, we were negatively affected by the marginal difference
between the returns received on the temporary investment of these funds versus
what we would expect to earn as we reinvest the funds. Our repurchase last
December of approximately 4,700,000 shares of common stock and our continued
retirement of long-term debt mitigated these effects.
Utility Operating Income
? Income from electric utility operations decreased approximately
$17,400,000, or 59 percent, compared with the first quarter of 1999
because of the effects of the fourth quarter 1999 sale of our
electric generating assets, customers continuing to choose other
commodity suppliers, and the voluntary rate reduction that became
effective on February 2, 2000.
? Income from our natural gas utility operations increased
approximately $1,900,000, or 19 percent, during the period mainly
because of an interim increase in rates that became effective on
December 10, 1999.
Nonutility Operating Income
? Income from our telecommunications operations increased approximately
$300,000 compared with the first quarter of 1999 principally as a
result of increased private-line and long-distance revenues.
? Income from our coal operations increased approximately $300,000
during the period because of higher revenues, mainly due to an
increase in tons sold and average revenue per ton at Western Energy's
Rosebud Mine because of the absence in 2000 of a $2,700,000 refund
that Western Energy paid to a customer in the first quarter of 1999.
<PAGE>
? Income from our independent power operations decreased approximately
$1,300,000 during the period. While Continental Energy Services
continues to benefit from improved operations at generating projects
in which it holds interests, its Colstrip 4 Lease Management Division,
which sells the leased share of Colstrip Unit 4 generation, had lower
income compared with first quarter 1999 because of the effects of a
restructured contract with the Los Angeles Department of Water and
Power (LADWP) and higher operations and maintenance expenses
associated with Colstrip Unit 4.
? Oil and natural gas operating income increased approximately
$5,500,000 during the period, resulting from increased sales volumes
and significantly higher commodity prices.
For comparative purposes, the following table shows consolidated basic
net income per share by principal business segment.
Quarter Ended
March 31,
2000
March 31,
1999
Utility operations
$ 0.08
$ 0.12
Nonutility operations
0.21
0.18
Consolidated
$ 0.29
$ 0.30
<PAGE>
<TABLE>
UTILITY OPERATIONS
<CAPTION>
For Three Months Ended
March 31,
March 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
ELECTRIC UTILITY:
REVENUES:
Revenues
$ 101,491
$ 116,534
Intersegment revenues
1,570
3,690
103,061
120,224
EXPENSES:
Power supply
48,149
38,687
Transmission and distribution
9,057
11,677
Selling, general, and administrative
14,702
13,753
Taxes other than income taxes
9,725
12,754
Depreciation and amortization
9,157
13,679
90,790
90,550
INCOME FROM ELECTRIC OPERATIONS
12,271
29,674
NATURAL GAS UTILITY:
REVENUES:
Revenues (other than gas supply cost revenues)
29,467
26,293
Gas supply cost revenues
15,327
14,052
Intersegment revenues
203
199
44,997
40,544
EXPENSES:
Gas supply costs
15,327
14,052
Other production, gathering, and exploration
750
793
Transmission and distribution
3,623
3,636
Selling, general, and administrative
7,145
5,755
Taxes other than income taxes
3,732
3,817
Depreciation, depletion, and amortization
2,368
2,351
32,945
30,404
INCOME FROM NATURAL GAS OPERATIONS
12,052
10,140
INTEREST EXPENSE AND OTHER INCOME:
Interest
13,034
14,438
Distributions on mandatorily redeemable
Preferred securities of subsidiary trusts
1,373
1,373
Other (income) deductions - net
(6,589)
(1,284)
7,818
14,527
INCOME BEFORE INCOME TAXES
16,505
25,287
INCOME TAXES
7,514
10,674
DIVIDENDS ON PREFERRED STOCK
923
923
UTILITY NET INCOME AVAILABLE FOR COMMON STOCK
$ 8,068
$ 13,690
</TABLE
<PAGE>
UTILITY OPERATIONS
Electric Utility
The following table categorizes revenues and volumes into General
Business Revenues, Sales To Other Utilities, Other, and Intersegment. It also
shows Bundled Revenues and Distribution Only Revenues separately for General
Business Revenues. While we no longer supply the electricity for customers
who have chosen other commodity suppliers, we continue to earn transmission
and distribution revenues for moving their electricity across our transmission
and distribution lines. We reflect transmission revenues as Other Revenues
and distribution revenues as Distribution Only Revenues. We expect these
revenues to continue to increase as additional customers move to choice. For
customers who have not chosen other suppliers, Bundled Revenues reflect fully
bundled rates for supplying, transmitting, and distributing electricity. We
expect these revenues to continue to decrease as additional customers move to
choice.
</TABLE>
<TABLE>
<CAPTION>
Revenues and
Power Supply Expenses
Volumes
(Thousands of Dollars)
(Thousands of MWh)
3/31/00
3/31/99
3/31/00
3/31/99
<S>
<C>
<C>
<C>
<C>
<C>
<C>
REVENUES:
GENERAL BUSINESS BUNDLED REVENUES:
Residential
$ 36,063
$ 36,135
- -
542
531
2%
Small commercial, small
industrial, and government and
municipal
37,541
41,533
(10%)
602
644
(7%)
Large commercial, large
Industrial
9,788
12,294
(20%)
261
447
(42%)
Irrigation and street lighting
2,423
2,496
(3%)
14
15
(7%)
Total
85,815
92,458
(7%)
1,419
1,637
(13%)
GENERAL BUSINESS DISTRIBUTION ONLY
REVENUES:
Residential
56
- -
- -
2
- -
- -
Small commercial, small
industrial, and government and
municipal
1,022
227
350%
60
11
445%
Large commercial, large
Industrial
1,745
2,640
(34%)
479
225
113%
Total
2,823
2,867
(2%)
541
236
129%
TOTAL GENERAL BUSINESS
REVENUES
88,638
95,325
(7%)
1,960
1,873
5%
SALES TO OTHER UTILITIES
5,252
16,443
(68%)
154
878
(82%)
OTHER
7,601
4,766
59%
INTERSEGMENT
1,570
3,690
(57%)
- -
34
- -
TOTAL
$103,061
$120,224
(14%)
2,114
2,785
(24%)
POWER SUPPLY EXPENSES:
Hydroelectric
- -
5,460
- -
- -
870
- -
Steam
- -
12,986
- -
221
1,269
(83%)
Purchased power and other
48,149
20,241
138%
1,671
551
203%
Total
$ 48,149
$ 38,687
24%
1,892
2,690
(30%)
Dollars per MWh
$ 25.45
$ 14.38
</TABLE
<PAGE>
General Business Revenues
General Business Revenues decreased mainly from customers continuing to
choose different suppliers and a voluntary rate reduction filed with the PSC,
effective February 2, 2000. An increase in prices to recover the cost of
public-purpose programs in accordance with the Electric Act partially offset
these decreases.
Sales to Other Utilities
With the sale of substantially all of our generating assets, we no
longer sell energy in the secondary markets. The elimination of these sales
resulted in a decrease in revenues from Sales to Other Utilities.
Other
Other revenues increased mainly from transmitting energy for PPL Montana
and customers who chose other suppliers. Prior to the generation sale, the
energy transmitted for PPL Montana was the same energy generated by us and
sold by MPT&M in the secondary markets, with MPT&M using our lines to transmit
the energy across our service territory. The transmission of this energy was
reflected as intersegment revenues in the table above. We reflect
transmission revenues from customers who are not supplied by us as Other
Revenues. Consequently, revenues from transmitting energy for PPL Montana and
customers who chose other suppliers are reflected as Other Revenues in the
table above. We report transmission revenues from customers who have not
chosen other suppliers as General Business Revenues.
Intersegment
Intersegment revenues decreased principally because the absence of sales
in the secondary markets eliminated the need for MPT&M to transmit energy
across our lines. As discussed above, revenues from transmitting energy for
PPL Montana partially offset this decrease.
Expenses
Power-supply expenses increased, despite decreased fuel expenses because
we no longer purchase fuel to operate the generating plants, mainly because of
increased purchased power costs required to supply electric energy to our core
customers. Prior to the generation sale, we supplied these customers with
electric energy primarily from our generation plants. As discussed above, we
now purchase most of the power to serve our core customers at a price of
approximately $22.25/MWh. This price represents our net fully allocated costs
of service in current rates, replacing operations and maintenance expense,
depreciation expense, and return on investment.
Transmission and distribution expenses decreased primarily because, as
discussed above, we are no longer selling energy in the secondary markets. As
a result, we did not incur the costs associated with using other utilities'
lines outside our service territory to transmit this energy.
Selling, general, and administrative (SG&A) expenses increased
approximately $950,000. The following items contributed to changes in
administrative expenses:
? An increase of approximately $2,500,000 relating to energy efficiency
and public-purpose programs in compliance with the Universal System
Benefits Charge requirements of the Electric Act. In accordance with
the Electric Act, we collect the costs associated with the energy
efficiency and public-purpose programs through a separate component
of rates;
<PAGE>
? Costs of approximately $800,000 incurred to train staff and to adapt
business processes to implement our new Enterprise Customer-Care
information system (E-CIS);
? Reduced pension expense of approximately $900,000 because of the
generation sale, which resulted in the transfer of 474 employees to
PPL Montana;
? A decrease of approximately $900,000 in conservation program
expenses; and
? A decrease in other miscellaneous administrative costs of
approximately $550,000.
Decreased taxes other than income taxes and depreciation expense
represent a decrease in property taxes and plant related to the generation
assets sold.
<PAGE>
Natural Gas Utility
The following table categorizes revenues and volumes into General
Business Revenues, Sales to Other Utilities, Transportation, and Other.
</TABLE>
<TABLE>
<CAPTION>
Revenues
Volumes*
(Thousands of Dollars)
(Thousands of Dkt)
3/31/00
3/31/99
3/31/00
3/31/99
<S>
<C>
<C>
<C>
<C>
<C>
<C>
REVENUES:
Residential
$ 26,852
$ 23,989
12%
4,772
11,505
(59%)
Small commercial, small
industrial, and government and
municipal
13,130
11,326
16%
2,355
6,006
(61%)
General business revenues
39,982
35,315
13%
7,127
17,511
(59%)
Less: Gas supply cost
Revenues (GSC)
15,327
14,052
9%
- -
- -
- -
General business revenues
Without GSC
24,655
21,263
16%
7,127
17,511
(59%)
Sales to other utilities
297
288
3%
106
101
5%
Transportation
4,329
4,192
3%
7,253
7,024
3%
Other
186
550
(66%)
- -
- -
- -
Total
$ 29,467
$ 26,293
12%
14,486
24,636
(41%)
<FN>
*With the implementation of our E-CIS, we now report natural gas revenues in
dekatherms (Dkt). A Dkt measures the heat used and is the basis of how we bill our
customers.
</TABLE>
<PAGE>
Revenues
All of our former Large Industrial and Large Commercial customers have
now chosen other commodity suppliers. While we no longer supply the natural
gas for those customers, we still earn transportation revenues from moving
their natural gas through our pipelines. We reflect these revenues as
Transportation revenues in the table.
General Business Revenues increased in the first quarter of 2000
primarily due to an increase in rates, customer growth, and a weather-related
increase in volumes sold. For information on our natural gas rate case with
the PSC, see Note 1, "Deregulation, Regulatory Matters, Sale of Electric
Generating Assets, and Proposed Divestiture of Energy Businesses."
Expenses
SG&A expenses increased mainly because of costs for implementing the E-
CIS system and for incentive compensation accruals.
Utility Interest Expense and Other Income
Retirement of long-term debt in 1999 and early 2000 and the absence of
accruals in 2000 related to the Kerr Project mitigation liability account for
the majority of the decrease of approximately $1,400,000 in interest expense.
Other Income - Net increased approximately $5,300,000 primarily because of
interest income earned on the higher cash balances held in 2000 compared to
1999.
<PAGE>
<TABLE>
NONUTILITY OPERATIONS
<CAPTION>
For Three Months Ended
March 31,
March 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
TELECOMMUNICATIONS:
REVENUES:
Revenues
$ 24,126
$ 19,775
Earnings from unconsolidated investments
602
1,423
Intersegment revenues
308
228
25,036
21,426
EXPENSES:
Operations and maintenance
9,558
8,446
Selling, general, and administrative
3,962
2,782
Taxes other than income taxes
2,068
1,040
Depreciation and amortization
2,374
2,415
17,962
14,683
INCOME FROM TELECOMMUNICATIONS OPERATIONS
7,074
6,743
COAL:
REVENUES:
Revenues
57,281
43,438
Intersegment revenues
3,938
9,904
61,219
53,342
EXPENSES:
Operations and maintenance
37,838
32,332
Selling, general, and administrative
5,357
5,022
Taxes other than income taxes
8,004
6,357
Depreciation, depletion, and amortization
2,013
1,885
53,212
45,596
INCOME FROM COAL OPERATIONS
8,007
7,746
INDEPENDENT POWER:
REVENUES:
Revenues
17,749
18,234
Earnings from unconsolidated investments
5,700
5,333
Intersegment revenues
200
238
23,649
23,805
EXPENSES:
Operations and maintenance
16,440
15,734
Selling, general, and administrative
1,044
830
Taxes other than income taxes
636
463
Depreciation and amortization
870
777
18,990
17,804
INCOME FROM INDEPENDENT POWER OPERATIONS
$ 4,659
$ 6,001
</TABLE
<PAGE>
</TABLE>
<TABLE>
NONUTILITY OPERATIONS (CONTINUED)
<CAPTION>
For Three Months Ended
March 31,
March 31,
2000
1999
(Thousands of Dollars)
<S>
<C>
<C>
OIL AND NATURAL GAS:
REVENUES:
Revenues
$ 105,415
$ 68,809
Intersegment revenues
5,365
4,400
110,780
73,209
EXPENSES:
Operations and maintenance
87,888
58,951
Selling, general, and administrative
5,219
4,228
Taxes other than income taxes
2,000
1,024
Depreciation, depletion, and amortization
6,723
5,565
101,830
69,768
INCOME FROM OIL AND NATURAL GAS OPERATIONS
8,950
3,441
OTHER OPERATIONS:
REVENUES:
Revenues
7,706
7,876
Intersegment revenues
1,524
441
9,230
8,317
EXPENSES:
Operations and maintenance
8,170
7,431
Selling, general, and administrative
(224)
1,324
Taxes other than income taxes
166
313
Depreciation and amortization
1,600
1,081
9,712
10,149
LOSS FROM OTHER OPERATIONS
(482)
(1,832)
INTEREST EXPENSE AND OTHER INCOME:
Interest
773
2,104
Other income - net
(4,171)
(5,497)
(3,398)
(3,393)
INCOME BEFORE INCOME TAXES
31,606
25,492
INCOME TAXES
9,318
6,281
NONUTILITY NET INCOME AVAILABLE FOR COMMON STOCK
$ 22,288
$ 19,211
</TABLE>
<PAGE>
NONUTILITY OPERATIONS
Telecommunications Operations
Revenues from telecommunications operations increased approximately
$4,400,000. This increase principally consists of the effects of the
following elements:
? Increased private-line revenues of approximately $3,400,000 as a
result of an increase in customer growth.
? Increased long-distance revenues, including Internet revenues, of
approximately $800,000 as a result of more minutes sold and more
long-distance and Internet customers.
? Decreased equipment-service sales of approximately $1,000,000,
primarily because of 1999 equipment upgrades to address Year 2000
concerns and 1999 sales to a school district.
? Increased revenues of approximately $500,000 earned by Tetragenics
Company, which designs and manufactures electronic monitoring,
control, and data acquisition hardware and software for electric and
communications systems.
The following table shows changes from the previous year, in millions of
dollars, in long-distance revenues (excluding Internet revenues) and the
related percentage changes in minutes sold, price per minute, and customer
growth:
For The Three Months Ended
March 31,
March 31,
2000
1999
Revenues
$ -
$ 1
Minutes sold
9%
41%
Price per minute
(1%)
(7%)
Customer growth
21%
45%
Earnings from unconsolidated investments were approximately $800,000
lower compared with the same period in 1999. Dark-fiber revenues, primarily
from the FTV Communications LLC joint venture, were approximately $1,100,000
lower than in 1999. This decrease was somewhat offset by approximately
$300,000 in net earnings from various joint ventures in which Touch America
owns interests.
After adjusting private-line revenues for the accounting effects of the
$257,000,000 prepayment received in January 1999 and after excluding the dark-
fiber sales included in earnings from unconsolidated investments, Touch
America's operating revenues for the first three months of 2000 increased more
than 20 percent as compared to the first three months of 1999. With the same
adjustments above, Touch America's operating income for the first three months
of 2000 increased more than 40 percent as compared to the first three months
of 1999.
Operations and maintenance expense increased approximately $1,100,000,
attributable chiefly to higher cost of sales for Tetragenics. SG&A expenses
increased approximately $1,200,000 as a result of a combination of expenses
associated with outside consultants, salaries, costs relating to joint
<PAGE>
ventures, increased marketing efforts, and Touch America's share of expenses
for our new Enterprise Resource Planning (ERP) information system. Taxes
other than income taxes increased approximately $1,000,000 as a result of
increased property taxes, resulting from expansion of Touch America's fiber-
optic network. Depreciation and amortization expense remained relatively flat
because the absence in 2000 of amortization expense associated with Personal
Communication Services (PCS) licenses owned by Touch America, which Touch
America transferred in late 1999 to its TW Wireless joint venture, offset
increases associated with expansion of the fiber-optic network.
As discussed in the "Touch America's Commitments" section of Note 5 under
"Investments and Acquisitions," Touch America signed a purchase agreement with
Qwest in March 2000. We expect this acquisition will close in mid-2000 and
that it will increase Touch America's revenues in 2001 by approximately
$300,000,000.
For a discussion of Touch America's forecasted capital expenditures for
2000, see the "Investing Activities" section of "Liquidity and Capital
Resources."
Coal Operations
Income from coal operations increased approximately $300,000 when
compared with the first quarter of 1999. Revenues from Western Energy's
Rosebud mine increased $7,600,000. Volume of coal sold to the Colstrip Units
increased by approximately 8 percent and average revenue per ton was
approximately 16 percent higher. The average revenue per ton increase was
largely the result of a one-time $2,700,000 refund in the first quarter of
1999 to a customer for final pit reclamation funds previously collected. The
customer has agreed to be responsible for a portion of all final pit
reclamation expenses in the future. Sales to a midwest utility under a new
contract also contributed to the improved revenues. Revenues from
Northwestern Resource's Jewett mine increased $300,000 as a 3 percent increase
in price more than offset a 2 percent decrease in tons sold.
Operations and maintenance expense increased approximately $5,500,000
from higher royalties, reclamation costs, equipment rentals, and diesel fuel
costs. A one-time reversal of reclamation expenses in the first quarter of
1999 associated with the refund discussed above contributed to this increase.
Taxes other than income taxes also increased as a result of the increased
revenues at the Rosebud Mine.
Independent Power Operations
Income from our independent power operations decreased approximately
$1,300,000. Revenues decreased approximately $500,000 mainly because of the
effects of a December 1999 agreement with LADWP. Continental Energy Services'
Colstrip 4 Lease Management Division sells the leased share of Colstrip Unit 4
generation, and the December agreement terminated an existing power-supply
contract and established a new contract expiring in December 2010. As a
result of this transaction, we received approximately $106,000,000 from LADWP
in December 1999.
Earnings from unconsolidated investments increased approximately
$400,000. This was attributable mainly to improved operations in generating
projects in which Continental Energy Services holds equity interests -
particularly Encogen One in Texas and Ferndale in Washington state.
Operations and maintenance expense increased approximately $700,000
principally because of an increase in expenses associated with Colstrip Unit 4
operations. SG&A expenses increased approximately $200,000 mainly as a result
<PAGE>
of Continental Energy's share of expenses associated with the ERP information
system.
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
$ 2
- -volume
2%
- -price/bbl
165%
Natural gas
- -revenue
$ 27
- -volume
1%
- -price/Mcf
41%
Natural gas liquids
- -revenue
$ 7
- -volume
41%
- -price/bbl
75%
Miscellaneous
$ 2
Income from oil and natural gas operations increased approximately
$5,500,000 due primarily to higher commodity prices and increased natural gas
liquids trading and marketing activities in the first quarter of 2000 compared
with 1999. Oil and natural gas revenues increased because of significant
increases in prices along with slightly higher sales volumes. Revenues from
natural gas liquids operations were higher because of both a sizable increase
in prices and increased trading and marketing activities.
Operations and maintenance expense increased mainly because of higher
purchased gas costs and royalties caused by the higher prices discussed above.
Taxes other than income nearly doubled compared to the prior year because of
the higher value of the oil, natural gas, and natural gas liquids produced
from our reserves. Depreciation, depletion, and amortization increased mainly
because depletion rates applied to production from our Canadian properties
were higher in the first quarter of 2000 compared to 1999.
Nonutility Interest Expense and Other Income
Reduced needs for short-term cash resulted in the decrease in interest
expense of approximately $1,300,000. Other Income - Net decreased
approximately $1,300,000 because the funds available for investments in the
first quarter of 2000 were less than the funds available in the first quarter
of 1999.
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
Net cash used for operating activities was $44,800,000 for the three
months ended March 31, 2000, compared with net cash provided by operations of
$345,798,000 in the first three months of 1999. The current-year decrease of
$390,598,000 was attributable mainly to the $257,000,000 prepayment received
in January 1999 from a Touch America customer. We are recognizing the
prepayment in revenues over the remaining eleven-year term of the agreement.
The decrease in cash provided by operating activities also was attributable to
income taxes paid during the first quarter of 2000 as a result of the
following items: (1) the telecommunications prepayment discussed above, (2)
the $106,000,000 received in December 1999 from LADWP relating to a power-
supply agreement, and (3) the gain from the December 1999 sale of our electric
generating assets.
Investing Activities
Net cash used for investing activities was $34,293,000 for the three
months ended March 31, 2000, compared with $18,071,000 in the first three
months of 1999. The current-year increase of $16,222,000 was attributable
mainly to an increase in capital expenditures and a decrease in proceeds from
sales of property and investments in 2000.
Touch America's forecasted capital expenditures for 2000, including
those required for the Qwest acquisition, are approximately $700,000,000. If
the Qwest acquisition is closed, Touch America does not expect the purchase
price and related capital expenditures to exceed $300,000,000.
Financing Activities
Net cash used for financing activities was $58,096,000 for the three
months ended March 31, 2000, compared with $118,097,000 in the first three
months of 1999.
On January 3, 2000, we made a payment of approximately $10,200,000 for
our share of the costs associated with the Kerr mitigation plan (Plan). This
amount represented our final liability for costs under the Plan through the
December 17, 1999, sale date of the electric generating assets.
Two issues of Medium-Term Notes (MTNs) were retired prior to maturity in
January of 2000. On January 13, 2000, we retired $5,000,000 of 7.25 percent
Series A Secured MTNs due January 19, 2024. On January 14, 2000, we retired
$7,000,000 of 8.68 percent Series A Unsecured MTNs due February 7, 2022.
We retired at maturity $10,000,000 of 8.80 percent Series A Unsecured
MTNs on February 22, 2000.
On April 13, 2000, we retired prior to maturity $25,000,000 of our
7.5 percent First Mortgage Bonds (Bonds) due April 1, 2001.
On April 25, 2000, we offered to purchase any or all of the following
series of our outstanding debt: 8.95 percent Bonds due February 1, 2022;
7.33 percent Secured MTNs due April 15, 2025; 8.11 percent Secured MTNs due
January 25, 2023; 7.00 percent Bonds due March 1, 2005; and 8.25 percent Bonds
due February 1, 2007. The total amount outstanding for these issues was
$190,000,000 as of March 31, 2000. Prices for the redemption will be set on
May 18, 2000, and the offer to purchase expires on May 23, 2000.
Proceeds received from the sale of the electric generating assets have
been or will be used to make all of the retirements discussed above.
<PAGE>
Our consolidated borrowing ability under our Revolving Credit and Term
Loan Agreements was $179,264,000, of which $165,670,000 was unused at
March 31, 2000. On April 4, 2000, our Revolving Credit Agreement for some of
our nonutility operations terminated with no amounts outstanding. This
reduced our consolidated borrowing ability by $100,000,000.
We also have short-term borrowing facilities with commercial banks that
provide committed and uncommitted lines of credit and the ability to sell
commercial paper.
The Board of Directors periodically reviews our dividend policy to
ensure that our dividend payout and dividend rate are appropriate given our
business plan, strategy, and outlook. Our common stock dividend rate is
dependent on our results of operations, financial position, anticipated future
uses of cash, and other factors. In assessing the dividend policy, the Board
of Directors also evaluates the effect of the sale of our generation assets
and the continued growth of, and investment in, Touch America. As discussed
more fully in Note 1, "Deregulation, Regulatory Matters, Sale of Electric
Generating Assets, and Proposed Divestiture of Energy Businesses," on
March 28, 2000, we announced our intent to separate our telecommunications
business from our energy businesses through stock sale(s) of our energy
businesses, with Touch America remaining as the entity through which we will
continue to conduct our telecommunications business. The Board of Directors
will continue to assess and adjust our dividend policy in light of these and
other developments.
For information regarding our authorization to repurchase common stock,
refer to Note 9, "Common Stock."
SEC RATIO OF EARNINGS TO FIXED CHARGES
For the twelve months ended March 31, 2000, our ratio of earnings to
fixed charges was 3.36 times. Fixed charges include interest, distributions on
preferred securities of a subsidiary trust, the implicit interest of the
Colstrip Unit No. 4 rentals, and one-third of all other rental payments.
YEAR 2000 COMPLIANCE
We did not have any significant disruptions as a result of the calendar
rollover from 1999 to 2000 or the "leap year" rollover.
NEW ACCOUNTING PRONOUNCEMENTS
New requirements associated with the accounting for derivative
instruments and hedging and trading activities will affect MPT&M and
ultimately may affect Touch America.
Statement of Financial Accounting Standards Nos. 133 and 137
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
all derivative instruments be recorded on an entity's balance sheet at fair
value. The statement also expands the definition of a derivative. In July
1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and
Hedging Activities: Deferral of the Effective Date of FASB Statement
No. 133." SFAS No. 137 delays for one year the effective date of SFAS
No. 133. This delay means that we are not required to adopt SFAS No. 133
until January 1, 2001.
<PAGE>
We expect to complete the sale(s) of our unregulated energy businesses,
including MPT&M, before January 1, 2001. While we have begun a review of our
commodity purchase and sale agreements to evaluate exposure to potential
embedded derivatives, we do not expect the adoption of SFAS No. 137 to have a
material effect on our consolidated financial position, results of operations,
or cash flows.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our energy commodity-producing, trading, and marketing activities and
other investments and agreements expose us to the market risks associated with
fluctuations in commodity prices, interest rates, and changes in foreign
currency translation rates.
Trading Instruments
Because we do not use derivative financial instruments to hedge against
exposure to fluctuations in interest rates or foreign currency exchange rates,
commodity price risk represents the primary market risk to which our non-
regulated energy-commodity producing, trading, and marketing operations are
exposed. We discuss the derivative financial instruments that we use to
manage this risk in Note 3, "Derivative Financial Instruments."
Electricity
In June 1998, prior to our August 1998 decision to exit the electric
trading and marketing businesses, MPT&M entered into a derivative financial
transaction, called a "swap," in conjunction with one of our electric retail
sales contracts. That swap allows us to receive the difference between a
fixed price and market-index price for electricity. We net the difference
against the cost of purchasing electricity to serve the retail sales contract.
Crude Oil, Natural Gas, and Natural Gas Liquids
We have commodity risk-management policies and practices to govern the
execution, recording, and reporting of derivative financial instruments and
physical transactions associated with the trading and marketing activity of
crude oil, natural gas, and natural gas liquids engaged in by MPT&M. These
policies and practices require MPT&M to identify, quantify, and report
commodity risks and to hold regular Risk Management Committee meetings.
Our Audit Committee established a value-at-risk (VaR) limit to manage
our exposure to potential losses from trading activity. MPT&M must report to
that committee the number of times it exceeds the established limit. MPT&M's
VaR limit, including forecasts of affiliate-owned production, is $2,000,000.
MPT&M's VaR calculation indicates how much MPT&M could lose from its
trading transactions under certain assumptions. Because actual future changes
in markets - prices, volatilities, and correlations - may be inconsistent with
historical observations, MPT&M's VaR may not accurately reflect the potential
for future adverse changes in fair values. At March 31, 2000, MPT&M's VaR
calculation for physical and financial crude oil, natural gas, and natural gas
liquids transactions, including forecasts of affiliate-owned production, was
approximately $1,500,000.
From January 1, 2000, through the end of the first quarter, MPT&M
reported daily adverse changes in fair values in excess of its $2,000,000 VaR
limit on three occasions. From April 1, 2000, through May 8, 2000, MPT&M
reported one such occasion.
<PAGE>
Other-Than-Trading Agreements
We are exposed to commodity price risks through our utility and
nonutility operations. Our utility has entered into purchase, sale, and
transportation contracts for electric energy and natural gas. One of these
contracts obligates us to sell electric energy to an industrial customer at
terms that include a fixed price for a portion of the power delivered and an
index-based price for another portion through December 2002. For 2003 and
2004, we sell all power to the customer at an index-based price. Since the
sale of our electric generating assets, we have been supplying our customer
with power purchased through an index-based contract that remains effective
through July 2001. Our industrial customer has given us usage estimates that
do not exceed the amount of power that we are committed to purchase.
Because the price of power under the index-based purchase contract could
exceed the fixed price in our sales contract, we are subject to commodity
price risk. Due to uncertainties relating to the supply requirements of the
contract and uncertainties surrounding various arrangements that would allow
us to serve the contractual demand, we cannot determine at this time the
effects that this contract ultimately may have on our consolidated financial
position, results of operation, or cash flows. MPT&M has entered into
arrangements to mitigate the commodity price risk inherent in this contract,
and we continue to examine our options and take steps to mitigate the
commodity price risk resulting from this contract.
Our nonutility has entered into similar kinds of purchase, sale, and
transportation contracts for coal, lignite, natural gas, crude oil, and
natural gas liquids. Since December 31, 1999, there has been no material
change in these other instruments or the corresponding commodity price risk
associated with these instruments.
Our primary interest rate exposure with respect to other-than-trading
instruments relates to items that SFAS No. 107, "Disclosures about Fair Value
of Financial Instruments," defines as "financial instruments," which are
instruments readily convertible to cash. Since December 31, 1999, there has
been no material change in these instruments or the corresponding interest
rate risk associated with these instruments.
Our primary foreign currency exposure results from (1) our Canadian
subsidiaries - Altana Exploration Company and Altana Exploration Ltd. -
exploring for, producing, gathering, processing, transporting, and marketing
crude oil and natural gas in Canada, and (2) MPT&M trading and marketing
natural gas in Canada. (Effective January 1, 2000, we combined all of the
assets, liabilities, and undertakings of our Canadian subsidiaries, Altana
Exploration Ltd. and Canadian-Montana Gas Company Limited, with Altana
Exploration Ltd. surviving.) Since December 31, 1999, there has been no
material change in these activities or the corresponding foreign currency risk
associated with these activities.
<PAGE>
PART II
OTHER INFORMATION
ITEM 1. Legal Proceedings
Kerr Project
For information regarding the Kerr Project fish, wildlife and habitat
mitigation plan, refer to Note 2, "Contingencies."
Paladin Associates, Inc.
On May 4, 2000, the United States District Court for the District of
Montana granted motions for summary judgment submitted by us and North American
Resources Company (NARCo), a subsidiary of our subsidiary, Entech, Inc.,
challenging Paladin's antitrust claims on the grounds that they lacked merit as
a matter of law. The court dismissed Paladin's antitrust claims. The court
also ordered that Paladin's pending state claims (alleging breach of
contractual obligation and torts on the part of NARCo and us) be dismissed
without prejudice to the right of Paladin to prosecute those claims in state
court. We cannot predict whether Paladin will appeal the court's order
regarding the antitrust claims or whether it will pursue these claims in state
court.
TCA Building Company
On April 26, 2000, TCA appealed the summary judgment entered against it
in Texas district court. The counterclaims asserted by our subsidiary, Entech,
Inc., and its subsidiary, Northwestern Resources Co., against TCA have been
abated pending the resolution of the appeal. We cannot predict when this
matter will ultimately be resolved.
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,
2000
Exhibit 18 Letter of preferability on change of accounting
principle
Exhibit 27 Financial data schedule
(b) Reports on Form 8-K Filed During the Quarter Ended March 31, 2000.
DATE SUBJECT
January 25, 2000 Item 5. Other Events. Discussion of Fourth
Quarter 1999 Net Income.
Item 7. Exhibits. Preliminary Consolidated
Statements of Income for the Quarters Ended
December 31, 1999 and 1998 and for the Twelve
Months Ended December 31, 1999 and 1998.
Preliminary Utility Operations Statements of
Income for the Quarters Ended December 31, 1999
and 1998 and for the Twelve Months Ended
December 31, 1999 and 1998. Preliminary
Nonutility Operations Statements of Income for
the Quarters Ended December 31, 1999 and 1998
and for the Twelve Months Ended December 31,
1999 and 1998.
<PAGE>
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 Chairman and
Chief Financial Officer
Dated: May 15, 2000
<PAGE>
EXHIBIT INDEX
Exhibit 12
Computation of ratio of earnings
to fixed charges for
the twelve months ended March 31, 2000
Exhibit 18
Letter of preferability on change of accounting principle
Exhibit 27
Financial data schedule
- -5-
- -13-
- -26-
- -35-
- -36-
- -39-
Exhibit 12
<PAGE>
<TABLE>
THE MONTANA POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(Dollars in Thousands)
<CAPTION>
Twelve Months
Ended
March 31, 2000
<S>
<C>
Net Income
$ 147,715
Income Taxes
43,940
$ 191,655
Fixed Charges:
Interest
$ 46,805
Amortization of Debt Discount, Expense, and Premium
1,133
Rentals
33,308
$ 81,246
Earnings Before Income Taxes and Fixed Charges
$ 272,901
Ratio of Earning to Fixed Charges
$ 3.36x
</TABLE>
<PAGE>
Exhibit 18
May 12, 2000
To the Board of Directors
The Montana Power Company
Dear Directors:
We have been furnished with a copy of the Corporation's Form 10-Q for the
quarter ended March 31, 2000. The notes to the consolidated financial
statements therein describe a change in the method of reporting the accounts
of certain operations and eliminating a one-month lag in reporting for these
operations. Based upon our discussions with management and the stated
reasons for change, we believe that such change represents, in your
circumstances, the adoption of a preferable alternative method of accounting
for and reporting consolidated results of operations in conformity with
Accounting Principles Board Opinion No. 20.
We have not made an audit in accordance with generally accepted auditing
standards of the consolidated financial statements of The Montana Power
Company for the three-month period ended March 31, 2000, and accordingly, we
express no opinion thereon or on the consolidated financial information filed
as part of the Form 10-Q of which this letter is to be an exhibit.
Yours very truly,
/s/ PricewaterhouseCoopers LLP
PRICEWATERHOUSECOOPERS LLP
Portland, Oregon
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet at 03/31/00, the Consolidated Income Statement
and the Consolidated Statement of Cash Flows for the three months ended
03/31/00 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-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 992,365
<OTHER-PROPERTY-AND-INVEST> 879,874
<TOTAL-CURRENT-ASSETS> 771,280
<TOTAL-DEFERRED-CHARGES> 264,675
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,908,194
<COMMON> 558,281
<CAPITAL-SURPLUS-PAID-IN> 2,308
<RETAINED-EARNINGS> 460,168
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,020,757
65,000
57,654
<LONG-TERM-DEBT-NET> 599,854
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 39,085
0
<CAPITAL-LEASE-OBLIGATIONS> 1,382
<LEASES-CURRENT> 769
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,123,693
<TOT-CAPITALIZATION-AND-LIAB> 2,908,194
<GROSS-OPERATING-REVENUE> 364,864
<INCOME-TAX-EXPENSE> 16,832
<OTHER-OPERATING-EXPENSES> 312,333
<TOTAL-OPERATING-EXPENSES> 329,165
<OPERATING-INCOME-LOSS> 35,699
<OTHER-INCOME-NET> 8,343
<INCOME-BEFORE-INTEREST-EXPEN> 44,042
<TOTAL-INTEREST-EXPENSE> 12,763
<NET-INCOME> 31,279
923
<EARNINGS-AVAILABLE-FOR-COMM> 30,356
<COMMON-STOCK-DIVIDENDS> 20,176
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> (44,800)
<EPS-BASIC> 0.29
<EPS-DILUTED> 0.28
</TABLE>
