EXHIBIT 99.1
Reference in this offering memorandum to "we," "us," "our" and NPC refer to
Nevada Power Company, unless the context indicates otherwise.
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information in this offering memorandum includes forward-looking
statements within the meaning of the Private Securities Litigation Reform Act
of 1995. These forward-looking statements relate to anticipated financial
performance, management's plans and objectives for future operations, business
prospects, outcome of regulatory proceedings, market conditions and other
matters. Words such as "anticipate," "believe," "estimate," "expect," "intend,"
"plan" and "objective" and other similar expressions identify those statements
that are forward-looking. These statements are based on management's beliefs
and assumptions and on information currently available to management. Actual
results could differ materially from those contemplated by the forward-looking
statements. In addition to any assumptions and other factors referred to
specifically in connection with such statements, factors that could cause our
actual results to differ materially from those contemplated in any
forward-looking statement include, among others, those described in the "Risk
Factors" section of this offering memorandum beginning on page 11 and the
following:
. unfavorable rulings in rate cases to be filed by us with the Public
Utilities Commission of Nevada (the "PUCN"), including the periodic
applications to recover costs for fuel and purchased power that have been
recorded by us in our deferred energy accounts;
. the outcome of our pending lawsuit in Nevada state court seeking to
reverse portions of the PUCN's March 29, 2002 order denying the recovery
of $434 million of our deferred energy costs, including the outcome of
the cross-petition filed by the Bureau of Consumer Protection of the
Nevada Attorney General's Office seeking additional disallowances;
. our ability to access the capital markets to support our requirements for
working capital, including amounts necessary to finance deferred energy
costs, construction costs and the repayment of maturing debt,
particularly in the event of additional unfavorable rulings by the PUCN,
a further downgrade of our current debt ratings and/or adverse
developments with respect to our power and fuel suppliers;
. whether suppliers, such as Enron, which have terminated their power
supply contracts with us will be successful in pursuing their claims
against us for liquidated damages under their power supply contracts, and
whether Enron will be successful in requesting that we now pay them in
full the amount of their claim pending final resolution of their lawsuit
against us;
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. whether we will be able to maintain sufficient stability with respect to
our liquidity and relationships with suppliers to be able to continue to
operate outside of bankruptcy;
. whether our current suppliers of purchased power, natural gas or fuel
will continue to do business with us or will terminate their contracts
and seek liquidated damages from us;
. whether we will be able, either through Federal Energy Regulatory
Commission (the "FERC") proceedings or negotiation, to obtain lower
prices on the long-term purchased power contracts that we entered into
during 2000 and 2001 that are priced above current market prices for
electricity;
. whether the PUCN will issue favorable orders in a timely manner to permit
us to borrow money and issue additional securities to finance our
operations and to purchase power and fuel necessary to serve our
customers;
. whether we will need to purchase additional power on the spot market to
meet unanticipated power demands (for example, due to unseasonably hot
weather) and whether suppliers will be willing to sell such power to us
in light of our weakened financial condition;
. wholesale market conditions, including availability of power on the spot
market, which affect the prices we have to pay for power as well as the
prices at which we can sell any excess power;
. the effect of a non-binding referendum to be included on the ballot in
Clark County, Nevada in November 2002 asking voters to indicate whether
they would favor the establishment of a non-profit entity to provide
electricity services in southern Nevada;
. the outcome of the proposal by the Southern Nevada Water Authority to
enter into negotiations to acquire our company;
. the effect that any future terrorist attacks may have on the tourism and
gaming industries in Nevada, particularly in Las Vegas, as well as on the
economy in general;
. the effect of existing or future Nevada or federal legislation or
regulations affecting electric industry restructuring, including laws or
regulations which could allow additional customers to choose new
electricity suppliers or change the conditions under which they may do so;
. unseasonable weather and other natural phenomena, which can have
potentially serious impacts on our ability to procure adequate supplies
of fuel or purchased power to serve our customers and on the cost of
procuring such supplies;
. industrial, commercial and residential growth in our service territories;
. the loss of any significant customers;
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. changes in the business of major customers, particularly those engaged in
gaming, which may result in changes in the demand for our services,
including the effect on the Nevada gaming industry of the opening of
additional Indian gaming establishments in California and other states;
. changes in environmental regulations, tax or accounting matters or other
laws and regulations to which we are subject;
. future economic conditions, including inflation or deflation rates and
monetary policy;
. financial market conditions, including changes in availability of capital
or interest rate fluctuations;
. unusual or unanticipated changes in normal business operations, including
unusual maintenance or repairs; and
. employee workforce factors, including changes in collective bargaining
unit agreements, strikes or work stoppages.
Other factors and assumptions not identified above may also have been
involved in deriving these forward-looking statements, and the failure of those
other assumptions to be realized, as well as other factors, may also cause
actual results to differ materially from those projected. We assume no
obligation to update forward-looking statements to reflect actual results,
changes in assumptions or changes in other factors affecting forward-looking
statements.
3
Recent Developments
Due to the impact of the recent energy crisis in the western United States
and the disallowance of a significant portion of our unrecovered purchased
power and fuel costs, our current operational focus is on enhancing the
performance of our existing assets, ensuring liquidity and improving our credit
quality. Our long-term strategy is focused on returning our credit quality to
investment-grade.
On March 29, 2002, the Public Utilities Commission of Nevada (the "PUCN")
issued a decision on our deferred energy application. The PUCN approved the
recovery of $488 million of our deferred purchased power and fuel costs
accumulated between March 1, 2001 and September 30, 2001 over a three-year
period, beginning April 1, 2002, which allows us to recover approximately $163
million per year, and disallowed $434 million of our unrecovered purchased
power and fuel costs incurred during that same period. The PUCN disallowance
had a significant negative impact on our results of operations for the six
months ended June 30, 2002. On April 11, 2002, we filed a lawsuit in the First
District Court of Nevada requesting that the District Court reverse portions of
the PUCN's decision and remand the matter to the PUCN with direction that the
PUCN grant us immediate authorization to establish rates that would allow us to
recover our entire deferred energy balance of $922 million, with a carrying
charge, over three years. A hearing on this matter has been scheduled for
February 2003. We cannot predict the outcome of this lawsuit.
On March 29 and April 1, 2002, following the decision by the PUCN in our
deferred energy rate case, the two major national rating agencies lowered our
unsecured debt ratings to below investment grade. On April 23 and 24, 2002, our
unsecured debt ratings were further downgraded and our secured debt ratings
were downgraded to below investment grade. Currently, the rating agencies have
our credit ratings on "watch negative" or "possible downgrade." As a result of
these recent developments, our ability to access the capital markets to raise
funds has become limited. In addition, because the credit ratings of Sierra
Pacific Resources were similarly downgraded and because of restrictions on our
ability to pay dividends on our common stock, Sierra Pacific Resources' ability
to make capital contributions to us has also become limited.
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Our $200 million unsecured revolving credit facility was also affected by
the PUCN's decision in our deferred energy rate case. Following the
announcement of the PUCN's decision, the banks participating in our credit
facility determined that a material adverse event had occurred, thereby
precluding us from borrowing funds under our credit facility. The banks agreed
to waive the consequences of the material adverse event in a waiver letter and
amendment that was executed on April 4, 2002, in return for the issuance and
delivery of our General and Refunding Mortgage Bond, Series C, due November 28,
2002, in the principal amount of $200 million to the administrative agent as
security for the credit facility. We do not intend to extend or renew the
facility beyond its currently scheduled maturity date of November 28, 2002. As
a result, on that date, we are obligated to repay our lenders $200 million,
together with accrued interest. As discussed in "Use of Proceeds," we intend to
use the proceeds from this offering to repay our existing credit facility prior
to November 28, 2002.
In early May of 2002, Enron Power Marketing Inc. ("Enron"), Morgan Stanley
Capital Group, Inc. ("MSCG"), Reliant Energy Services, Inc. and several smaller
suppliers terminated their power deliveries to us, exercising their contractual
right under the Western Systems Power Pool Agreement ("WSPPA") to terminate
deliveries based upon our decision not to provide adequate assurances of our
performance under the WSPPA to any of our suppliers. Each of these terminating
suppliers has asserted, or has indicated that it will assert, a claim against
us for liquidated damages.
On June 5, 2002, Enron filed suit against us in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims for
liquidated damages related to the termination of its power supply agreement
with us of approximately $216 million. Enron's claim is subject to our defense
that such claims are already at issue in our Federal Energy Regulatory
Commission ("FERC") proceeding against Enron under Section 206 of the Federal
Power Act challenging the contract prices of the terminated power supply
agreement. In connection with the lawsuit filed by Enron in the Bankruptcy
Court, Enron has filed a motion to require us to promptly pay the full amount of
their claim pending the final resolution of the lawsuit. At this time, we are
not able to predict the outcome of a decision in this matter. An adverse
decision on the motion seeking for us to promptly pay the full amount of Enron's
claim or an adverse decision in the lawsuit would have a material adverse affect
on our financial condition and liquidity and would render our ability to
continue to operate outside of bankruptcy uncertain. A hearing with respect to
Enron's motion is scheduled to be held on October 11, 2002 and a decision is
expected shortly thereafter. In addition, on September 5, 2002, MSCG filed a
Demand for Arbitration in accordance with the mediation and arbitration
procedures of the WSPPA seeking a termination payment from us of approximately
$25 million under their terminated power supply agreement with us.
5
As a result of the impact of the PUCN decision and our ratings downgrade, in
May of 2002, we began paying all of our continuing power suppliers on a delayed
basis. Under this arrangement, we paid the suppliers an amount equal to 110% of
a current benchmark price for power and delayed payment of the balance of the
contract price, together with interest on the delayed amounts, for the period
from May 1 to September 15, 2002. Five of our continuing power suppliers, who
accounted for approximately 47% of our total purchases from our continuing
suppliers, have signed written agreements accepting these terms. Our other
suppliers continued to deliver electricity while accepting our payments. We
intend to pay the five suppliers who accepted our delayed payment terms in full
prior to the issuance of the notes. Although we expect to be able to pay most
of the delayed amounts owed to our other suppliers by October 25, 2002, it is
possible that the remaining suppliers could seek and obtain payment from us of
damages for our failure to pay them in accordance with the original terms of
the WSPPA. As of September 30, 2002, the delayed payment amounts to the
continuing suppliers totaled approximately $100 million, of which approximately
$52 million is owed to the continuing suppliers that have not signed delayed
payment agreements with us.
On July 7, 2002, the Board of County Commissioners of Clark County, Nevada,
added an Electric Utility Advisory Question to its November 5, 2002 general
election ballot, which asks voters whether "the Nevada Legislature should take
appropriate action to enable the electrical energy provider for southern Nevada
to be a locally controlled, not for profit public utility." Although the
referendum is non-binding, the results of this advisory question may impact
future utility legislation by the Nevada Legislature in its next legislative
session which may, in turn, directly or indirectly affect us and our
operations. We filed a lawsuit seeking to remove the question from the ballot,
and the lawsuit was dismissed.
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On August 22, 2002, Sierra Pacific Resources received a letter from the
Southern Nevada Water Authority ("SNWA") stating that it was prepared to enter
into good faith negotiation of definitive agreements to acquire all of our
assets and assume certain of our existing indebtedness. On September 12, 2002,
Sierra Pacific Resources responded with a letter stating that it did not view
the SNWA's letter as an offer and expressing concerns with the SNWA's financing
plans, certain significant legal issues with the proposal and the SNWA's lack
of utility management experience. The SNWA has responded by reaffirming its
purported offer to acquire us.
On September 30, 2002, a lawsuit was filed by two individuals in the
District Court for Clark County, Nevada, on behalf of themselves and all
holders of securities of Sierra Pacific Resources, against Sierra Pacific
Resources and its directors named individually. The lawsuit alleges that the
defendants violated their fiduciary duties to the securityholders as a result
of Sierra Pacific Resources' response to SNWA's letters in which SNWA stated
that it was prepared to enter into negotiations to acquire our assets and
assume certain of our indebtedness. The lawsuit, which seeks certification as a
class action, requests that the court: (1) declare that the directors have
breached their fiduciary duties, (2) enjoin the defendants to undertake all
reasonable efforts to maximize shareholder value including mandating due
consideration of the SNWA proposal, (3) order the defendants to permit a
stockholders' committee to ensure a fair procedure in connection with any
disposition or retention of assets, and (4) if SNWA's purported offer is
withdrawn due to the actions or inactions of the defendants, to award
compensatory and/or punitive damages in an unspecified amount against the
defendants. Although Sierra Pacific Resources and its directors intend to
vigorously defend against the lawsuit, we cannot predict the outcome at this
time.
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On September 30, 2002, El Paso Merchant Energy Group ("EPME") notified us
that it was terminating all transactions entered into with us under the WSPPA.
At the present time, we expect that net gains and losses relating to the
terminated transactions, including a delayed payment amount of approximately
$19 million that we owed to EPME for power deliveries through September 15,
2002, will result in a small net payment due to us.
We are in the process of negotiating agreements for an accounts receivable
purchase facility of up to $125 million being arranged by Lehman Brothers.
Under the receivables purchase facility, we would sell all of the accounts
receivable generated from the sale of electricity to our customers to a newly
created bankruptcy-remote special purpose subsidiary of ours. This subsidiary
would sell these receivables to a bankruptcy-remote subsidiary of our parent,
Sierra Pacific Resources which, in turn, would issue variable rate revolving
notes backed by such receivables. The receivables sales would be without
recourse except for breaches of customary representations and warranties made
at the time of the sale. We plan to issue up to $125 million aggregate
principal amount of our General and Refunding Mortgage Bonds to secure certain
of our obligations as seller and servicer with respect to the receivables
purchase facility. The closing of the receivables purchase facility is subject
to satisfactory completion of due diligence and the finalization of
documentation. Commencement of the sale of accounts receivables pursuant to the
receivables purchase facility is subject to completion of the offering of notes
contemplated hereby, the termination of our existing credit facility and
certain other conditions. Although we are currently negotiating the terms of
the accounts receivable facility, we cannot assure you that we will enter into
the facility or any similar arrangement.
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We are incorporated in Nevada. Our principal executive offices are located
at 6226 W. Sahara Avenue, (P.O. Box 230), Las Vegas, Nevada 89146 and our
telephone number is (702) 367-5000.
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Summary Historical Financial and Operating Data
The following table summarizes our historical financial and operating data.
You should read this table in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and our financial
statements and related notes contained herein. The summary financial data as of
December 31, 2001 and 2000 and for each of the years in the three-year period
ended December 31, 2001 have been derived from our audited financial statements
included elsewhere in this offering memorandum. The summary financial data as
of June 30, 2002 and for the six-month periods ended June 30, 2002 and 2001
have been derived from our unaudited interim financial statements included
elsewhere in this offering memorandum, and the summary financial data as of
June 30, 2001 have been derived from our unaudited interim financial
statements, all of which, in our opinion, reflect all adjustments necessary to
present fairly the data for such periods. Interim results for the six months
ended June 30, 2002 are not necessarily indicative of results that can be
expected in future periods. "Operating Data" below are not directly derived
from our financial statements, but have been presented to provide additional
data for your analysis.
Six Months Ended Twelve Months Ended
Year Ended December 31, June 30, June 30,
------------------------------------- ---------------------- -------------------
1999 2000 2001 2001 2002 2002
----------- ----------- ----------- ---------- ---------- -------------------
(dollars in thousands, except operating data)
Income Statement Data:
Operating Revenues:
Electric................................. $ 977,262 $ 1,325,470 $ 3,025,103 $1,167,453 $ 833,331 $ 2,690,981
Operating Income............................ 116,983 73,460 144,364 25,358 (230,597) (111,591)
----------- ----------- ----------- ---------- ---------- -----------
Net Income (Loss)(1)........................ $ 38,692 $ (7,928) $ 63,405 $ (22,292) $ (295,329) $ (209,632)
=========== =========== =========== ========== ========== ===========
Other Financial Data:
EBITDA(2)................................... $ 217,570 $ 147,287 $ 255,240 $ 55,443 $ (339,128) $ (139,331)
Capital Expenditures........................ 220,919 196,636 196,896 88,948 116,106 224,054
Interest Expense............................ 64,913 70,390 92,677 42,759 51,875 101,793
Net Cash Flows from Operating Activities(1). 191,236 81,859 (764,074) (102,074) 49,368 (612,632)
Net Cash Used in Investing Activities....... (219,420) (196,636) (197,011) (88,948) (117,048) (225,111)
Net Cash Provided by Financing Activities... 39,715 126,540 919,060 220,222 66,983 765,821
Balance Sheet Data (end of period):
Cash and Cash Equivalents................... $ 243 $ 43,858 $ 8,505 $ 80,210 $ 59,877 $ 59,877
Utility Plant(3)............................ 2,352,641 2,462,962 2,562,351 2,502,362 2,630,280 2,630,280
Short-Term Borrowings....................... 182,000 100,000 130,500 100,000 200,000 200,000
Long-Term Obligations (Including Current
Maturities)................................ 1,020,846 1,180,694 1,627,347 1,378,996 1,624,824 1,624,824
Total Debt.................................. 1,202,846 1,280,694 1,757,847 1,478,996 1,824,824 1,824,824
Preferred Trust Securities.................. 188,872 188,872 188,872 188,872 188,872 188,872
Accumulated other Comprehensive Income...... -- -- 520 1,061 415 415
Common Shareholders' Equity(4).............. 822,973 887,737 1,393,063 887,365 1,097,734 1,097,734
Total Capitalization(5)..................... 2,214,691 2,357,303 3,340,302 2,556,294 3,111,845 3,111,845
Operating Data:
Number of Retail Customers:
Residential.............................. 499,074 526,899 552,276 546,329 562,645 562,645
Commercial............................... 66,477 69,536 72,606 71,847 73,694 73,694
Industrial............................... 1,065 1,144 1,219 1,195 1,220 1,220
Other.................................... 56 64 68 69 67 67
----------- ----------- ----------- ---------- ---------- -----------
Total Retail Customers................. 566,672 597,643 626,169 619,440 637,626 637,626
=========== =========== =========== ========== ========== ===========
Annual Load Factor.......................... 46.3% 49.3% 49.0% -- -- 49.7%
Peak Load (MW)(6)........................... 3,993 4,325 4,412 4,325 4,412 4,412
Total Retail Sales (MWh).................... 14,615,000 16,363,000 16,799,000 7,756,000 7,885,000 16,928,000
Average Retail Revenue per MWh.............. $ 62.06 $ 63.99 $ 83.06 $ 78.09 $ 86.51 $ 86.95
Purchased Power (MWh)....................... 7,861,985 9,659,118 19,268,305 7,685,000 5,782,000 17,365,000
Average Cost per MWh of Purchased Power..... $ 43.12 $ 69.51 $ 157.06 $ 135.51 $ 114.49 $ 152.43
Company Generated Power (MWh)............... 9,167,963 10,744,466 9,899,195 5,074,000 4,656,000 9,481,000
Average Fuel Cost per MWh of Generated Power $ 16.86 $ 27.25 $ 44.64 $ 42.89 $ 33.76 $ 40.24
9
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(1)Amounts do not include equity in earnings (losses) of Sierra Pacific
Resources. See note (3) under "Capitalization."
(2)EBITDA includes Operating Income before income taxes, depreciation and
amortization and may not be comparable to similar measures presented by
other companies. EBITDA is a measure we use in presentations to investors
and lenders and is not based on accounting principles generally accepted in
the United States of America ("GAAP"). EBITDA should not be considered an
alternative to net earnings or cash flows from operating activities, which
are determined in accordance with GAAP, as an indicator of operating
performance or as a measure of liquidity.
(3)Amounts include plant in service and construction work in progress, less
accumulated provision for depreciation.
(4)Amounts do not include equity in Sierra Pacific Resources. See note (3)
under "Capitalization."
(5)Amounts include total debt, preferred trust securities, accumulated other
comprehensive income and common shareholders' equity, and exclude equity in
Sierra Pacific Resources. See note (3) under "Capitalization."
(6)Nevada Power's current peak load through June 30, 2002 occurred on July 2,
2001.
- - For reference purposes, the text of note (3) under "Capitalization" is as
follows:
Does not include equity in Sierra Pacific Resources. The 1999 combination
between Sierra Pacific Resources and Nevada Power Company was accounted for
as a reverse purchase under generally accepted accounting principles, with
Nevada Power considered to be the acquiring entity for accounting purposes,
even though Sierra Pacific Resources became the legal parent of Nevada Power
and Sierra Pacific Power Company and even though Nevada Power has no equity
interest in Sierra Pacific Resources. Accordingly, the financial statements
of Nevada Power contain information relating to Sierra Pacific Resources as
if Nevada Power had become the legal parent. This information is summarized
in a few individual line items in Nevada Power's financial statements, as
follows:
Balance Sheet
. Investment in Sierra Pacific Resources
. Equity in Sierra Pacific Resources
Income and Cash Flow Statements
. Equity in Earnings (Losses) of Sierra Pacific Resources
These line items do not represent any asset or any item of revenue, income
or cash flow to which holders of securities issued by Nevada Power may look
for recovery of their investment and should be disregarded.
10
RISK FACTORS
You should consider carefully each of the following risks and all other
information contained in this offering memorandum before deciding to invest in
the notes. The risks and uncertainties described below are not the only ones we
face.
Risks Relating to Us and Our Business
Recent events have significantly adversely affected our liquidity. Further
downgrades of our credit ratings could limit our access to the capital markets.
Historically, in order to satisfy our substantial working capital, capital
expenditure and debt service requirements, we have relied on a combination of
(i) internally generated funds, (ii) our commercial paper program, which had
permitted the sale of up to $200 million of commercial paper on a revolving
basis, and other issuances of debt and preferred securities in the capital
markets, and (iii) capital contributions from our parent, Sierra Pacific
Resources.
As discussed below, on March 29, 2002, the PUCN issued its decision in our
deferred energy rate case disallowing $434 million of our request to recover
our deferred purchased power and fuel costs through rate increases to our
customers. On March 29 and April 1, 2002, following this decision by the PUCN,
each of S&P and Moody's lowered our unsecured debt ratings to below investment
grade. On April 23 and 24, 2002, our unsecured debt ratings were further
downgraded and our secured debt ratings were downgraded to below investment
grade. As a result of these downgrades, we can no longer issue commercial paper
and our ability to access the capital markets to raise funds has become
severely limited. By May 2, 2002, we had borrowed the entire $200 million of
funds available under our credit facility to pay off maturing commercial paper.
Currently, the rating agencies have our credit ratings on "watch negative" or
"possible downgrade." In addition, because the credit ratings of Sierra Pacific
Resources were similarly downgraded and because of restrictions on our ability
to pay dividends on our common stock, Sierra Pacific Resources' ability to make
capital contributions to us has also become severely limited. Any future
downgrades will further increase our cost of capital and further limit our
access to the capital markets.
Although we are currently negotiating the terms of a receivables purchase
facility which would provide us with up to an additional $125 million of
liquidity, we cannot assure you that we will enter into the facility. If we do
not enter into the facility, our liquidity will be adversely affected.
If we do not receive favorable rulings in the deferred energy applications that
we file with the PUCN and we are unable to recover our deferred purchased power
and fuel costs, we will experience an adverse impact on cash flow and earnings.
Any significant disallowance of deferred energy charges in the future could
make our ability to operate outside of bankruptcy uncertain.
The rates that we charge our customers and certain aspects of our operations
are subject to the regulation of the PUCN, which significantly influences our
operating environment and affects our ability to recover costs from our
customers. Under Nevada law, purchased power and fuel costs in excess of those
included in base rates are deferred as an asset on our balance sheet and are
not shown as an expense until recovered from our retail customers. We are
required to file deferred energy applications with the PUCN at least once every
twelve months so that the PUCN may verify the prudence of the energy costs and
allow us to clear our deferred energy accounts. Nevada law also requires the
PUCN to act on these cases within a specified time period. Any of these costs
determined by the PUCN to have been imprudently incurred cannot be recovered
from our customers. On November 30, 2001, we filed a deferred energy
application with the PUCN that sought to clear $922 million of purchased fuel
and power costs accumulated between March 1, 2001 and September 30, 2001 from
our deferred energy accounts. On March 29, 2002, the PUCN ruled on our deferred
energy application and disallowed the recovery of $434 million of our deferred
purchased fuel and power costs. As a result of the disallowance, the
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credit ratings on our debt decreased well below investment grade, we were
required to seek a waiver and amendment to our credit agreement and some of our
purchased power suppliers terminated their agreements to sell us power. We are
unable to predict how the PUCN will rule in our future deferred energy
applications. Unfavorable rulings by the PUCN in our future rate cases and
deferred energy applications, including our upcoming deferred energy
application to be filed in November 2002, could have a further adverse impact
on our business and results of operations, and could make our ability to repay
the notes and to continue to operate outside of bankruptcy uncertain.
If the power suppliers who terminated their deliveries to us succeed in their
claims against us for liquidated damages under their terminated power supply
contracts or in requiring that we pay the amount of such claims pending final
resolution of their disputes against us, it could make our ability to operate
outside of bankruptcy uncertain.
In early May of 2002, Enron, Morgan Stanley Capital Group, Inc, ("MSCG"),
Reliant Energy Services, Inc. and several smaller suppliers terminated their
power deliveries to us. These terminating suppliers asserted their contractual
right under the Western Systems Power Pool Agreement ("WSPPA") to terminate
deliveries based upon our decision not to provide adequate assurance of our
performance under the WSPPA to any of our suppliers. Each of these terminating
suppliers has asserted, or has indicated that it will assert, a claim for
liquidated damages against us under the terminated power supply contracts.
On June 5, 2002, Enron filed suit against us in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims against
us for liquidated damages in the amount of approximately $216 million related
to the termination of its power supply agreement with us. In connection with
the lawsuit filed by Enron in the Bankruptcy Court, Enron has filed a motion to
require us to promptly pay them in full the amount of their claim pending the
final resolution of their lawsuit against us. A hearing with respect to this
motion is scheduled to be held on October 11, 2002 and a decision with respect
to the motion is expected shortly thereafter. At this time, we are not able to
predict the outcome of a decision in this matter. An adverse decision on the
motion seeking for us to promptly pay in full the amount of Enron's claim, or
an adverse decision in the lawsuit, would have a material adverse affect on our
financial condition and liquidity and would render our ability to continue to
operate outside of bankruptcy uncertain.
On September 5, 2002, MSCG filed a Demand for Arbitration pursuant to the
mediation and arbitration procedures of the WSPPA seeking a termination payment
from us of approximately $25 million under their terminated power supply
agreement with us. If this claim is not resolved by arbitration, we expect that
MSCG will commence a lawsuit against us to recover liquidated damages under the
terminated contract. On September 30, 2002, El Paso Merchant Energy Group
notified us that it was terminating power deliveries to us.
Moreover, other terminating power suppliers may bring claims against us for
liquidated damages under their terminated power supply contracts. Adverse
decisions with respect to such existing and potential claims, including any
requirement to pay or provide security in the amount of the alleged liquidated
damages, may adversely affect our cash flow, liquidity and financial condition
and may render our ability to operate outside of bankruptcy uncertain.
If our continuing power suppliers object to our delay in making payments to
them, it could have an adverse effect on our financial condition.
Following the downgrades of our credit ratings in March and April of 2002,
Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers
terminated their power deliveries to us, exercising their contractual rights
under the WSPPA to terminate such deliveries based upon our decision not to
provide adequate assurances of our performance under the WSPPA to any of our
suppliers. In May of 2002, we began paying all of our remaining power suppliers
on a delayed basis. These suppliers were paid less than their contract prices,
but more than prevailing market prices, with interest accrued on the unpaid
portion, for the period from May 1 to
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September 15, 2002. As of October 2, 2002, five of our continuing power
suppliers signed amendments to the WSPPA pursuant to which they formally agreed
to accept the extended payment terms we implemented in May. Although our
remaining suppliers have not formally accepted our extended payment terms, they
continued to provide power to us during the applicable period. It is possible
that the remaining suppliers could seek and obtain payment from us of damages
for our failure to pay them in accordance with the original terms of the WSPPA.
The total aggregate amount of delayed payments to continuing suppliers that we
have yet to make is approximately $100 million, of which $52 million is owed to
continuing suppliers who did not agree to a delay in payment.
If we face any additional power supplier terminations, our ability to
provide power and our operations may be negatively impacted.
We rely on purchased power counterparties to sell power to us for a significant
portion of the power for our operations. If our financial position does not
improve or worsens, we may face increasing difficulty obtaining power necessary
for our operations.
Historically we have purchased a significant portion of the power that we
sell to our customers from power suppliers. If our credit ratings do not
improve or are further downgraded, we may experience considerable difficulty
entering into new power supply contracts, and to the extent that we must rely
on the spot market, we may experience difficulty obtaining such power from
suppliers in the spot market in light of our weakened financial condition. Any
difficulty securing our purchased power requirements could have a material
adverse effect on our ability to provide power, our operations and our
financial condition.
In light of our current financial condition, some of our current suppliers
have indicated that they are unwilling to sell us power under our traditional
payment terms. If these suppliers or future suppliers do not sell us power
under traditional payment terms, we may have to pre-pay our power requirements.
If we do not have sufficient funds or access to liquidity to pre-pay our power
requirements, particularly at the onset of the summer months, and are unable to
obtain power through other means, our business, operations and financial
condition will be adversely affected and our ability to continue operations
outside of bankruptcy may be jeopardized.
We have approximately $700 million of indebtedness maturing through December
31, 2004, that we may be required to refinance. The failure to refinance our
indebtedness would have an adverse effect on us.
The following is a description of our maturing debt that comes due prior to
and including December 31, 2004:
. $15,000,000 of 7 5/8% Series L First Mortgage Bonds due November 1, 2002;
. $200,000,000 credit facility with varying interest rates due November 28,
2002 (we intend to pay the indebtedness under our credit facility with
the proceeds of the sale of the notes);
. $210,000,000 of senior unsecured 6% Notes due September 15, 2003;
. $140,000,000 of General and Refunding Mortgage Notes, Floating Rate,
Series B, due October 15, 2003; and
. $130,000,000 of 6.20% Senior Unsecured Notes, Series B due April 15, 2004.
If we do not have sufficient funds to repay our indebtedness at maturity, we
will have to refinance the indebtedness through additional debt financing in
private or public offerings. If, at the time of any refinancing, prevailing
interest rates or other factors result in higher interest rates on
refinancings, increases in interest expense could adversely affect our cash
flow, and, consequently, cash available for payments on our
13
indebtedness, including the notes. If we are unable to refinance or extend
outstanding borrowings on commercially reasonable terms or at all, we may have
to:
. reduce or delay capital expenditures planned for replacements,
improvements and expansions; and/or
. dispose of assets on disadvantageous terms, potentially resulting in
losses and adverse effects on cash flow from operating activities.
We cannot assure you that we could effect or implement any of these
alternatives on satisfactory terms, if at all. If we are unable to repay our
indebtedness at maturity, we may not be able to continue to operate outside of
bankruptcy.
Our ability to access the capital markets is dependent on our ability to obtain
regulatory approval to do so.
We will need to continue to support working capital and capital
expenditures, and to refinance maturing debt, through external financing. We
must obtain regulatory approval in Nevada in order to borrow money or to issue
securities and will therefore be dependent on the PUCN to issue favorable
orders in a timely manner to permit us to finance our operations and to
purchase power and fuel necessary to serve our customers. We cannot assure you
that the PUCN will issue such orders or that such orders will be issued on a
timely basis.
We may not be able to mitigate fuel and wholesale electricity pricing risks
which could result in unanticipated liabilities or increased volatility in our
earnings.
Our business and operations are subject to changes in purchased power prices
and fuel costs that may cause increases in the amounts we must pay for power
supplies on the wholesale market and the cost of producing power in our
generation plants. As evidenced by the western utility crisis that began in
2000, prices for electricity, fuel and natural gas may fluctuate substantially
over relatively short periods of time and expose us to significant commodity
price risks.
Among the factors that could affect market prices for electricity and fuel
are:
. prevailing market prices for coal, oil, natural gas and other fuels used
in our generation plants, including associated transportation costs, and
supplies of such commodities;
. changes in the regulatory framework for the commodities markets that we
rely on for purchased power and fuel;
. liquidity in the general wholesale electricity market;
. the actions of external parties, such as the FERC or independent system
operators, that may impose price limitations and other mechanisms to
address some of the volatility in the western energy markets;
. weather conditions impacting demand for electricity or availability of
hydroelectric power or fuel supplies;
. union and labor relations;
. natural disasters, wars, embargoes and other catastrophic events; and
. changes in federal and state energy and environmental laws and
regulations.
As a part of our risk management strategy, we routinely enter into contracts
to hedge our exposure to the risks listed above; however, we do not always
hedge the entire exposure of our operations from commodity price volatility.
See "Business--Commodities Risk" for more information on our hedging policies.
To the extent that open positions exist, fluctuating commodity prices could
have a material adverse effect on our results of operations.
14
We may be adversely affected by the financial condition, liquidity problems and
possible bankruptcy of our parent, Sierra Pacific Resources, and its affiliates.
We are a wholly-owned subsidiary of Sierra Pacific Resources, the parent
company of Sierra Pacific Power Company, the public utility that provides power
and natural gas to Northern Nevada and the Lake Tahoe area of California.
Sierra Pacific Resources is a holding company with no significant operations of
its own. Its cash flows are substantially derived from dividends paid to it by
us and Sierra Pacific Power Company, which are typically utilized to service
debt and pay dividends on common stock of Sierra Pacific Resources, with the
balance, if any, reinvested in us and Sierra Pacific Power Company as
contributions to capital. Currently, we are restricted from paying dividends to
our parent under certain financing agreements, power contracts and a recent
order of the PUCN. If we cannot eliminate these dividend restrictions, Sierra
Pacific Resources' ability to continue outside of bankruptcy will become
increasingly uncertain.
Sierra Pacific Resources has a substantial amount of debt and other
obligations including, but not limited to: $200 million of its unsecured
Floating Rate Notes due April 20, 2003; $300 million of its unsecured 83/4%
Senior Notes due 2005; and $345 million of its unsecured 7.93% Senior Notes due
2007. In connection with the effects of the disallowance of a significant
portion of our deferred purchased power costs by the PUCN as stated above,
Sierra Pacific Resources' credit ratings, along with those of Sierra Pacific
Power Company, were downgraded to below investment grade. As a result of the
downgrades, Sierra Pacific Resources' ability to service its debt obligations
and refinance its maturing debt as it becomes due has become uncertain. In the
event that Sierra Pacific Resources' financial condition does not improve or
becomes worse, it may have to consider other options including the possibility
of seeking protection in a bankruptcy proceeding.
We cannot predict with certainty what impact a Sierra Pacific Resources'
bankruptcy would have on us. Under the equitable doctrine of substantive
consolidation, a bankruptcy court may consolidate and pool our assets and
liabilities with those of our parent. We do not believe that our assets and
liabilities would become part of Sierra Pacific Resources' estate in
bankruptcy. Although Sierra Pacific Resources owns all of our common stock,
which would become part of its bankruptcy estate, we own or lease the assets
used in our business as a separate corporation from our parent. Additionally,
certain regulatory protections restrict Sierra Pacific Resources' access to our
assets. However, we cannot assure you that Sierra Pacific Resources or its
creditors would not attempt to advance such claims in a Sierra Pacific
Resources bankruptcy proceeding or, if advanced, how a bankruptcy court would
resolve the issue. If a bankruptcy court were to allow the substantive
consolidation of our assets and liabilities in the context of a Sierra Pacific
Resources bankruptcy filing, our financial condition, operations and ability to
meet our obligations with respect to the notes may be materially adversely
affected.
Changes in our regulatory environment and recent events in the energy markets
that are beyond our control and future decisions in our general rate cases may
significantly affect our financial condition, results of operations or cash
flows.
As a regulated public utility, our rates and operations are subject to
regulation by various state and federal regulators as well as the actions of
state and federal legislators. As a result of the energy crisis in California
during 2000 and 2001, the financial troubles of certain energy companies,
including us, and general movements toward electric industry restructuring and
deregulation, the regulatory environment in which we operate has become
increasingly uncertain. Steps taken and being considered at the federal and
state levels continue to change the structure of the electric industry and
utility regulation.
At the federal level, the FERC has been mandating changes in the regulatory
framework in which transmission-owning public utilities operate. On July 31,
2002, FERC issued a Notice of Proposed Rulemaking (Docket No. RM01-12-000) that
would require, among other things, that (1) all transmission-owning utilities
transfer control of their transmission facilities to an independent
transmission provider; (2) transmission service
15
to bundled retail customers be provided under the FERC-regulated transmission
tariff, rather than state-mandated terms and conditions; and (3) new terms and
conditions for transmission service be adopted nationwide, including new
provisions for pricing transmission in the event of transmission congestion. If
adopted as proposed, the rules would materially alter the manner in which we
own and operate our transmission services.
The PUCN has jurisdiction, granted by the Nevada Legislature, over our
rates, standards of service, generation and certain distribution facilities,
accounting, issuance of securities, as well as other aspects of our operations.
The Nevada Legislature and the PUCN could pass measures that could affect
retail competition in Nevada, affect the prices that we charge for electricity,
impact the impairment and writedown of certain of our assets, including
generation-related plant and net regulatory assets, reduce our profit margins
and increase the costs of our capital and operations expenses. Prior to the
onset of the western utility crisis, the Nevada Legislature and the PUCN had
mandated that we sell our electric generation assets and prepare for retail
competition in Nevada. AB 369, which was passed into law on April 18, 2001,
halted the movement towards deregulation of the Nevada electric industry by
repealing all statutes authorizing retail competition, by voiding any license
issued to alternative sellers of electricity and by placing a moratorium on the
sale of generation assets by electric utilities. We cannot predict how future
actions by the PUCN or future legislation passed in Nevada will affect our
results of operations, cash flows or financial condition.
We periodically file general rate cases with the PUCN. In our general rate
cases, the PUCN establishes, among other things, our return on common equity,
overall rate of return, depreciation expenses and our cost of capital. In a
recent compliance order, the PUCN further required us to demonstrate that the
terms of any financings undertaken pursuant to such order are reasonable. Any
of such financing costs determined by the PUCN to have been imprudently
incurred, including the maturity and interest rate payable on the notes, cannot
be recovered from our customers. Unfavorable rulings by the PUCN in our future
general rate cases could adversely impact our results of operation.
As a result of the energy crisis in California during 2000 and 2001, the
volatility of natural gas prices in North America, the bankruptcy filings by
Enron Corporation and Pacific Gas and Electric, and investigations by
governmental authorities into energy trading activities, companies in the
regulated and unregulated utility businesses have generally been under an
increased amount of scrutiny by public, state and federal regulators, the
capital markets and the rating agencies. We cannot predict or control what
effect these types of events or future actions of regulatory agencies in
response to such events in the energy markets may have on our business or our
access to the capital markets.
We are subject to numerous environmental laws and regulations that may increase
our cost of operations, impact or limit our business plans, or expose us to
environmental liabilities.
We are subject to extensive federal, state, local and foreign statutes,
rules and regulations relating to environmental protection. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant
emissions obligations. These laws and regulations generally require us to
obtain and comply with a wide variety of environmental licenses, permits,
inspections and other approvals, and may be enforced by both public officials
and private individuals. We cannot predict the outcome or effect of any action
or litigation that may arise from applicable environmental regulations.
In addition, we may be required to be a responsible party for environmental
clean up at sites identified by environmental agencies or regulatory bodies. We
cannot predict with certainty the amount and timing of future expenditures
related to environmental matters because of the difficulty of estimating clean
up costs. There is also uncertainty in quantifying liabilities under
environmental laws that impose joint and several liability on all potentially
responsible parties. Environmental regulations may also require us to install
pollution control equipment at, or perform environmental remediation on, our
facilities.
Existing environmental regulations may be revised or new regulations may be
adopted or become applicable to us. For example, the laws governing air
emissions from coal-burning plants are being re-interpreted by federal
16
and state authorities which could result in the imposition of substantially
more stringent limitations on emissions than those currently in effect. Revised
or additional regulations, which result in increased compliance costs or
additional operating restrictions, could have a material adverse effect on our
financial condition and results of operations particularly if those costs are
not fully recoverable from our customers.
Furthermore, we may not be able to obtain or maintain all environmental
regulatory approvals necessary to our business. If there is a delay in
obtaining any required environmental regulatory approval or if we fail to
obtain, maintain or comply with any such approval, operations at our affected
facilities could be halted or subjected to additional costs. Further, at some
of our older facilities the cost of installing the necessary equipment may
cause us to shut down those generation units.
We are a wholly-owned subsidiary of Sierra Pacific Resources, which can
exercise substantial control over our dividend policy and business and
operations and may do so in a manner that is adverse to our interests.
Our board of directors exercises substantial control over our business and
operations and makes determinations with respect to, among other things, the
following:
. payment of dividends;
. decisions on financings and our capital raising activities;
. mergers or other business combinations; and
. acquisition or disposition of assets.
Our board of directors could decide to increase dividends to Sierra Pacific
Resources to help it support its cash needs. This could adversely affect our
liquidity.
Our operating results will likely fluctuate on a seasonal and quarterly basis.
Electric power generation is generally a seasonal business. In many parts of
the country, including our service areas, demand for power peaks during the hot
summer months, with market prices also peaking at that time. As a result, our
operating results in the future will likely fluctuate substantially on a
seasonal basis. In addition, we have historically sold less power, and
consequently earned less income, when weather conditions in our service areas
are milder. Unusually mild weather in the future could diminish our results of
operations and harm our financial condition.
Terrorism and the uncertainty of war may harm our future growth and operating
results.
The growth of our business depends in part on continued customer growth and
tourism demand in the Las Vegas portion of our service area. Changes in
consumer preferences or discretionary consumer spending in the Las Vegas
portion of our service area could harm our business. The terrorist attacks of
September 11, 2001, had a negative impact on travel and leisure expenditures,
including lodging, gaming and tourism. Although activity levels in the Las
Vegas area have recovered significantly in recent months, we cannot predict the
extent to which future terrorist and war activities in the United States and
elsewhere may affect us, directly or indirectly. An extended period of reduced
discretionary spending and/or disruptions or declines in airline travel and
business conventions could significantly harm the businesses in and the
continued growth of the Las Vegas portion of our service area, which could harm
our business and results of operations.
The long-range impact that the September 11, 2001 terrorist attacks may have
on the energy industry in general, and on us in particular, is not predictable
at this time. Uncertainty surrounding retaliatory military strikes or a
sustained military campaign may affect our business in unpredictable ways,
including disruptions of fuel supplies and markets, and the possibility that
our infrastructure facilities (which includes our pipelines,
17
production facilities, and transmission and distribution facilities) could be
direct targets or indirect casualties of an act of terror.
Risks Relating to the Notes
The notes impose restrictions on us that may adversely affect our ability to
operate our business.
The notes contain covenants that restrict, among other things, our ability
to:
. pay dividends and other distributions with respect to our capital stock
and purchase, redeem or retire our capital stock;
. incur additional indebtedness and issue preferred stock;
. enter into asset sales;
. enter into transactions with affiliates;
. incur liens on assets to secure certain debt;
. engage in certain business activities; and
. engage in certain mergers or consolidations and transfers of assets.
Our ability to comply with these covenants may be affected by many events
beyond our control and we cannot assure you that our future operating results
will be sufficient to comply with the covenants, or in the event of a default,
to remedy that default. Our failure to comply with those financial covenants
could result in a default, which could cause the notes (and by reason of
cross-default provisions, indebtedness under our indentures and other
indebtedness) to become immediately due and payable. If such an event of
default occurs and we are not able to remedy or obtain a waiver from such
default, we may not have sufficient funds to repay the notes.
The notes will be junior in right of payment to our obligations under the First
Mortgage Indenture.
Under the terms of the G&R Indenture, the lien securing the notes and all
other securities issued under the G&R Indenture is junior to the lien of our
First Mortgage Indenture. As of the date hereof, there is $387.5 million
aggregate principal amount of bonds issued and outstanding under the First
Mortgage Indenture. In the event of bankruptcy, liquidation, reorganization or
other winding-up of our company or upon a default in payment with respect to,
or the acceleration of, any indebtedness under our secured debt, our assets
that secure our secured debt will be available to pay obligations on the notes
only after all indebtedness under the First Mortgage Indenture has been repaid
in full from those assets. There may not be sufficient assets remaining to pay
amounts due on all the securities then outstanding under the G&R Indenture.
18
The holders of all of the notes offered hereby do not have the power, acting
alone, to enforce the lien of the G&R Indenture.
If any event of default occurs under the notes, including any breach of a
covenant that is still continuing after applicable grace periods, only the
holders of a majority in principal amount of all of the then outstanding
securities under the G&R Indenture have the power to direct the trustee in its
exercise of any trust or power, including its rights to enforce the lien of the
G&R Indenture on the collateral securing all those obligations, including the
notes offered hereby. As of October 1, 2002, there was $820 million aggregate
principal amount of securities issued under the G&R Indenture, which amount
does not include $125 million aggregate principal amount of our General and
Refunding Mortgage Bonds which will be reserved for issuance in connection with
our proposed receivables purchase facility. Accordingly, the holders of all of
the notes offered hereby do not have the power, acting alone, to enforce the
lien of the G&R Indenture.
Moreover, additional securities may be issued under the G&R Indenture on
the basis of (i) 70% of net utility property additions, (ii) the principal
amount of retired General and Refunding Mortgage bonds, and/or (iii)
theprincipal amount of first mortgage bonds retired after delivery to the
indenture trustee of the initial expert's certificate under the G&R Indenture.
As of October 1, 2002, we had the capacity to issue approximately $871 million
of additional debt under the G&R Indenture, which amount does not include $125
million aggregate principal amount of our General and Refunding Mortgage Bonds
which will be reserved for issuance in connection with our proposed receivables
purchase facility.
We may be unable to repurchase the notes if we experience a change in control.
We are required, under the terms of the notes, to offer to purchase all of
the outstanding notes if we experience a change of control. Our failure to
repay holders tendering notes upon a change of control will result in an event
of default under the notes. If a change of control were to occur, we cannot
assure you that we would have sufficient funds to repay debt outstanding to
purchase the notes, or any other securities that we would be required to offer
to purchase. We expect that we would require additional financing from third
parties to fund any such purchases but we cannot assure you that we would be
able to obtain such financing. See "Description of Other Indebtedness" and
"Description of Notes--Repurchase at the Option of the Holders--Change of
Control."
19
As described under "Summary--Recent Developments," Sierra Pacific Resources
recently received letters from the SNWA stating that it was prepared to enter
into good faith negotiation of definitive agreements to acquire all of our
assets and assume certain of our existing indebtedness. Any acquisition of our
company by the SNWA or another entity would likely constitute a change of
control under the terms of the notes.
No public market exists for the notes, and the offering and sale of the notes
is subject to significant legal restrictions as well as uncertainties regarding
the liquidity of the trading market for such securities.
The notes have not been registered under the Securities Act or any state or
foreign securities laws. As a result, you may only sell or resell your notes if:
. there are applicable exemptions from the registration requirement of the
Securities Act and any state or foreign laws that apply to the
circumstances of the sale; or
. we file a registration statement and it becomes effective.
Under the registration rights agreement applicable to the notes, we will be
required to use commercially reasonable efforts to commence the exchange offer
to exchange the notes within a specified period of time for equivalent
securities registered under the Securities Act or to register the notes under
the Securities Act. However, we cannot assure you that we will be successful in
having any such registration statement declared effective. See "Description of
Notes--Registration Rights; Liquidated Damages" and "Notice to Investors" for
additional information.
The notes are a new issue of securities with no established trading market.
We do not intend to list the notes for trading on any stock exchange or arrange
for any quotation system to quote prices for them. The initial purchasers have
informed us that they intend to make a market in the notes after this offering
is completed. However, the initial purchasers are not obligated to do so and
may cease market-making activities at any time. As a result, we cannot assure
you that an active trading market will develop for the notes or for any of the
registered notes exchanged for the notes pursuant to the exchange offer.
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Those statements in this section that are not historical in nature should be
deemed forward-looking statements that are inherently uncertain. See "Special
Note Regarding Forward-Looking Statements" on page iii and "Risk Factors" on
page 11 for a discussion of the factors that could cause actual results to
differ materially from those projected in these statements.
Overview
As discussed below under "--Major Factors Affecting Results of Operations,"
our financial condition and results of operations have been severely adversely
affected by certain events, including:
. the March 29, 2002 decision of the PUCN to disallow $434 million of our
deferred energy costs;
. the resulting downgrade in the credit ratings of our debt securities;
. the downgrade in the credit rating of the debt securities and substantial
decline in the market price of the common stock of Sierra Pacific
Resources, which has severely impaired Sierra Pacific Resources' ability
to make additional capital contributions to us;
. the termination of purchased power contracts by some of our suppliers and
the demand by some of those suppliers for liquidated damages under those
contracts; and
. the need to secure our credit facility with General and Refunding
Mortgage bonds, thus utilizing a portion of our capacity to issue secured
debt and triggering a further issuance of General and Refunding Mortgage
bonds to collateralize our senior notes.
Any further adverse developments could worsen our financial condition and
could make our ability to operate outside of bankruptcy uncertain.
21
Critical Accounting Policies
The following items represent critical accounting policies that under
different conditions or using different assumptions could have a material
effect on our financial condition, liquidity and capital resources.
Regulatory Accounting
Our rates are currently subject to the approval of the PUCN and are designed
to recover the cost of providing generation, transmission and distribution
services. As a result, we qualify for the application of Statement of Financial
Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation," issued by the Financial Accounting Standards Board
("FASB"). This statement recognizes that the rate actions of a regulator can
provide reasonable assurance of the existence of an asset and requires the
capitalization of incurred costs that would otherwise be charged to expense
where it is probable that future revenue will be provided to recover these
costs. SFAS No. 71 prescribes the method to be used to record the financial
transactions of a regulated entity. The criteria for applying SFAS No. 71
include the following: (i) rates are set by an independent third party
regulator, (ii) approved rates are intended to recover the specific costs of
the regulated products or services, and (iii) rates that are set at levels that
will recover costs can be charged to and collected from customers.
Deferred Energy Accounting
On April 18, 2001, the Governor of Nevada signed into law AB 369. The
provisions of AB 369, which are described in greater detail below under
"--Regulatory Matters," include, among others, a reinstatement of deferred
energy accounting for fuel and purchased power costs incurred by electric
utilities. In accordance with
22
the provisions of SFAS No. 71, we implemented deferred energy accounting on
March 1, 2001, for our electric operations. Under deferred energy accounting,
to the extent actual fuel and purchased power costs exceed fuel and purchased
power costs recoverable through current rates, that excess is not recorded as a
current expense on the statement of operations but rather is deferred and
recorded as an asset on the balance sheet. Conversely, a liability is recorded
to the extent fuel and purchased power costs recoverable through current rates
exceed actual fuel and purchased power costs. These excess amounts are
reflected in adjustments to rates and recorded as revenue or expense in future
time periods, subject to PUCN review. AB 369 provides that the PUCN may not
allow the recovery of any costs for purchased fuel or purchased power "that
were the result of any practice or transaction that was undertaken, managed or
performed imprudently by the electric utility." In reference to deferred energy
accounting, AB 369 specifies that fuel and purchased power costs include all
costs incurred to purchase fuel, to purchase capacity, and to purchase energy.
We also record, and are eligible under the statute to recover, a carrying
charge on such deferred balances.
As described in more detail below under "--Regulatory Matters--Deferred
Energy Case," on November 30, 2001, we filed an application with the PUCN
seeking to clear deferred balances for purchased fuel and power costs
accumulated between March 1, 2001 and September 30, 2001. The application
sought to establish a rate to clear accumulated purchased fuel and power costs
of $922 million and spread the cost recovery over a period of not more than
three years. On March 29, 2002, the PUCN issued its decision on our deferred
energy application, disallowing $434 million of deferred purchased fuel and
power costs and allowing us to collect the remaining $488 million over three
years beginning April 1, 2002. As a result of this disallowance, we wrote off
$465 million of deferred energy costs and related carrying charges, the two
major national rating agencies immediately downgraded the credit rating on our
debt securities (followed by further downgrades late in April) and the market
price of the common stock of our parent, Sierra Pacific Resources, fell
substantially.
In the meantime, we have continued to be entitled under AB 369 to utilize
deferred energy accounting for our electric operations. Because of contracts
entered into during the Western energy crisis in 2001 to assure adequate
supplies of electricity for our customers, we are continuing to incur fuel and
purchased power costs in excess of amounts we are permitted to recover in
current rates. As a result, as of June 30, 2002, we had a balance in our
deferred energy account of approximately $324.8 million subject to future
recovery. These costs include approximately $229 million reserved for claims
made by our terminated suppliers which we had not received approval from the
PUCN to include in our rates. These amounts are also subject to whatever
recovery may be ordered by the FERC in our Section 206 complaints. If not for
deferred energy accounting during the first six months of 2002, our results of
operations, financial condition, liquidity and capital resources would have
been adversely affected. For example, without the deferred energy accounting
provisions of AB 369, our reported net loss for the six months ended June 30,
2002 of $(295.3) million/1/ would have been (net of income tax) reported as a
net loss of $(422) million/1/. Similarly, our reported net income for the
quarter ended June 30, 2002 of $5.7 million would have been (net of income tax)
reported as a net loss of $(114.7) million. A significant disallowance by the
PUCN of our currently deferred costs could have a material adverse affect on
the future results of our operations. See "--Regulatory Matters" below for a
more detailed discussion of deferred energy accounting.
Derivatives and Hedging Activities
Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. As
amended, SFAS No. 133 requires that an entity recognize all derivative
instruments as either assets or liabilities in the statement of financial
position and measure the instruments at fair value.
In order to manage loads, resources and energy price risk, we buy fuel and
power under forward contracts. In addition to forward fuel and power purchase
contracts, we also use options and swaps to manage price risk. All of these
instruments are considered to be derivatives under SFAS No. 133. The risk
management assets and liabilities recorded in our balance sheet are primarily
comprised of the fair value of these forward fuel and power purchase contracts
and other energy related derivative instruments.
- --------
/1/ Excludes equity in losses of Sierra Pacific Resources. See note (3) under
"Capitalization."
23
Fuel and purchased power costs are subject to deferred energy accounting.
Accordingly, the energy related risk management assets and liabilities and the
corresponding unrealized gains and losses (changes in fair value) are offset
with a regulatory asset or liability rather than recognized in the statements
of income and comprehensive income. Upon settlement of a derivative instrument,
actual fuel and purchased power costs are recognized if they are currently
recoverable or deferred if they are recoverable or payable through future rates.
The fair values of the forward contracts and swaps are determined based on
quotes obtained from independent brokers and exchanges. The fair values of
options are determined using a pricing model which incorporates assumptions
such as the underlying commodity's forward price curve, time to expiration,
strike price, interest rates, and volatility. The use of different assumptions
and variables in the model could have a significant impact on the valuation of
the instruments.
We have other non-energy related derivative instruments such as interest
rate swaps. The transition adjustment resulting from the adoption of SFAS No.
133 related to these types of derivative instruments was reported as the
cumulative effect of a change in accounting principle in Other Comprehensive
Income. Additionally, the changes in fair values of these non-energy related
derivatives are also reported in the statements of comprehensive income until
the related transactions are settled or terminate, at which time the amounts
will be reclassified into earnings. No other amounts were reclassified into
earnings during the three- and six-month periods ended June 30, 2002 and 2001.
See Note 22 of "Notes to Financial Statements Years Ended December 31, 2001,
2000 and 1999," Note 10 of "Notes to Financial Statements Six Months Ended June
30, 2002 and 2001" and "Business--Commodities Risk" for additional information
regarding derivatives and hedging activities.
Provision for Uncollectible Accounts
We reserve for doubtful accounts based on past experience writing off
uncollectible customer accounts. The collapse of the energy markets in
California, and the subsequent bankruptcy of the California Power Exchange and
the financial difficulties of the Independent System Operator, resulted in us
reserving for outstanding receivables for power purchases $19.9 million (before
taxes) for 2001. The weakening economy and the disruption to the leisure travel
industry after September 11, 2001 also impacted our customer delinquencies in
2001. As of December 31, 2001, we reserved an additional $14.8 million for our
delinquent retail customer accounts. During the six months ended June 30, 2002,
we added $2.9 million to the provisions for our uncollectible retail customer
accounts. The adequacy of these reserves will vary to the extent that future
collections differ from past experience. We wrote off uncollectible retail
customer accounts amounting to $2.3 million against these provisions during the
six months ended June 30, 2002. Significant collection efforts are underway to
recover portions of the rest of our delinquent accounts.
Major Factors Affecting Results of Operations
As further discussed in the results of operations sections that follow,
operating results for the six months ended June 30, 2002 were severely affected
by the PUCN's March 29, 2002 decision in our deferred energy rate case to
disallow $434 million of deferred purchased fuel and power costs. As a result
of this disallowance, we wrote off $465 million of deferred energy costs and
related carrying charges during that quarter. The discussion below provides the
context in which this decision was made.
In an effort to mitigate the effects of higher fuel and purchased power
costs that developed in the Western United States in 2000, we, along with
Sierra Pacific Power Company, entered into the Global Settlement with the PUCN
in July 2000, which established a mechanism that initiated incremental rate
increases for us. Our cumulative electric rate increases under the Global
Settlement were $127 million per year.
However, because the rate adjustment mechanism of the Global Settlement was
subject to certain caps and could not keep pace with the continued escalation
of fuel and purchased power prices, on January 29, 2001, we,
24
along with Sierra Pacific Power Company, filed a Comprehensive Energy Plan
("CEP") with the PUCN. The CEP included a request for emergency rate increases
("CEP Riders"). On March 1, 2001, the PUCN permitted the requested CEP Riders
to go into effect subject to later review. The CEP Riders provided us with
further rate increases of $210 million per year.
Notwithstanding the increases under the Global Settlement and the CEP
Riders, our revenues for fuel and purchased power recovery continued to be less
than the related expenses. Accordingly, we sought additional relief pursuant to
legislation.
On April 18, 2001, the Governor of Nevada signed into law AB 369. The
provisions of AB 369 include a moratorium on the sale of generation assets by
electric utilities until 2003, the repeal of electric industry restructuring,
and, beginning March 1, 2001, a reinstatement of deferred energy accounting for
fuel and purchased power costs incurred by electric utilities. The stated
purposes of this emergency legislation included, among others, to control
volatility in the price of electricity in the retail market in Nevada and to
ensure that we have the necessary financial resources to provide adequate and
reliable electric service under present market conditions.
As discussed above in "--Critical Accounting Policies," deferred energy
accounting allows us to have an opportunity to recover in future periods that
portion of our costs for fuel and purchased power not covered by current rates
and defers to future periods the expense associated with the amounts by which
fuel and purchased power costs exceed the costs to be recovered in current
rates. Recovery is subject to PUCN review as to prudency and other matters.
AB 369 requires us to file general rate applications and deferred energy
applications with the PUCN by specific dates. Our deferred energy application,
filed on November 30, 2001, sought to establish a Deferred Energy Accounting
Adjustment ("DEAA") rate, effective on April 1, 2002, to clear accumulated
purchased fuel and power costs of $922 million and spread the cost recovery
over a period of not more than three years, resulting in an average net
increase of 21%. See "--Regulatory Matters" below for a discussion of our
general rate case filings and decisions.
The March 29, 2002 decision of the PUCN on our deferred energy application
to disallow $434 million of deferred purchased fuel and power costs accumulated
between March 1, 2001 and September 30, 2001 had a significant negative impact
on our results of operations for the six months ended June 30, 2002. Several of
the intervenors from our deferred energy rate case filed petitions with the
PUCN for reconsideration of its decision, seeking additional disallowances
ranging from $12.8 million to $488 million. The petitions for reconsideration
were granted in part and denied in part by the PUCN on May 24, 2002, but no
additional disallowances to the deferred energy balance resulted from that
decision. The Bureau of Consumer Protection of the Nevada Attorney General's
Office has since filed a motion in our pending state court case seeking
additional disallowances. Although we are challenging the PUCN's March 29, 2002
decision on our deferred energy application in a lawsuit filed in Nevada state
court, which is discussed below under "--Regulatory Matters," the decision
caused:
. the two major national rating agencies to issue an immediate downgrade of
the credit ratings on our debt securities (followed by further downgrades
late in April 2002);
. the market price of the common stock of our parent, Sierra Pacific
Resources, to fall substantially;
. our credit facility banks to require us, within five business days of the
downgrades, to issue General and Refunding Mortgage Bonds to secure our
bank line of credit;
. us to seek a waiver and amendment from our credit facility banks before
we were permitted to draw down on the facility;
. us to be unable to issue commercial paper;
. a number of our power suppliers to contact us regarding our ability to
pay the purchase price of outstanding contracts; and
25
. several power suppliers, including an affiliate of Enron Corp., to
terminate their power supply agreements with us and pursue claims for
liquidated damages under those contracts.
A significant disallowance in our future deferred energy rate cases could
further weaken our financial condition, liquidity, and capital resources. In
particular, such a decision or decisions could cause further downgrades of our
debt securities by the rating agencies, could make it impracticable for us to
access the capital markets, and could cause additional power suppliers to
terminate purchased power contracts with us and seek liquidated damages. Under
such circumstances, there can be no assurance that we would be able to remain
solvent or continue operations. Under such circumstances, there also can be no
assurance that we would not seek protection under the bankruptcy laws.
Results of Operations
Three and Six Months Ended June 30, 2002 Compared With Three and Six Months
Ended June 30, 2001
During the quarter ended June 30, 2002, we earned approximately $5.7 million
(excluding the losses of our parent, Sierra Pacific Resources) and paid no
dividends on our common stock. During the six months ended June 30, 2002, we
incurred a loss of approximately $295.3 million (excluding our equity in the
losses of our parent, Sierra Pacific Resources), and paid $10 million in
dividends on our common stock, all of which was reinvested in us as a
contribution to capital. The causes for significant changes in specific lines
comprising the results of our operations are as follows:
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------- ------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
-------- -------- ------------ -------- ---------- ------------
(dollars in thousands)
Electric Operating Revenues:
Residential.................. $166,825 $172,520 (3.3)% $297,931 $ 275,699 8.1%
Commercial................... 90,367 83,573 8.1% 160,058 139,129 15.0%
Industrial................... 135,402 118,603 14.2% 224,162 190,825 17.5%
-------- -------- -------- ----------
Retail revenues.............. 392,594 374,696 4.8% 682,151 605,653 12.6%
Other(1)..................... 84,465 433,745 (80.5)% 151,180 561,800 (73.1)%
-------- -------- -------- ----------
Total Revenues........... $477,059 $808,441 (41.0)% $833,331 $1,167,453 (28.6)%
======== ======== ======== ==========
Retail sales in thousands of
megawatt-hours (MWh)....... 4,315 4,440 (2.8)% 7,885 7,756 1.7%
Average retail revenue per
MWh........................ $ 90.98 $ 84.39 7.8% $ 86.51 $ 78.09 10.8%
- --------
(1)Primarily wholesale, as discussed below.
Residential electric revenues decreased for the three months ending June 30,
2002 in contrast to the previous period last year. This decrease was a result
of several factors, including, cooler weather (10% decrease in cooling degree
days) in 2002 compared to 2001. However, residential electric revenues
increased for the six months ended June 30, 2002 due to an overall increase in
the number of customers and rates. The milder second quarter 2002 weather
resulted in a minimal revenue impact for the six months ending June 30, 2002.
Higher rates resulted from an increase in rates effective March 1, 2001,
pursuant to the CEP and a rate change effective April 1, 2002, that included a
new DEAA rate. See "--Major Factors Affecting Results of Operations" above and
"--Regulatory Matters" below for more detailed DEAA and rate information. The
PUCN mandated a one-time rate increase of $0.01 per kilowatt-hour for the DEAA
for only the month of June 2002. This allowed us to accelerate the recovery
from all customer classes of approximately $16 million of the deferred energy
balance.
26
Both commercial and industrial electric revenues increased for the three and
six month periods, due, in part, to increases to the number of customers and
rates. There was also a one-time rate increase of $0.01 per kilowatt-hour for
the DEAA for only the month of June 2002 as discussed above.
The decreases in Electric Operating Revenues--Other for the three- and
six-month periods ended June 30, 2002, compared to the same periods in 2001
were due to a decrease in prices and sales volumes of wholesale electric power
to other utilities, as a result of changing market conditions. See
"Business--Commodities Risk" below for a discussion of our purchased power
procurement strategies.
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------- ------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
-------- -------- ------------ -------- ---------- ------------
(dollars in thousands)
Purchased Power $485,926 $839,538 (42.1)% $661,992 $1,041,360 (36.4)%
Purchased Power in thousands of
MWh.......................... 3,594 5,217 (31.1)% 5,782 7,685 (24.8)%
Average cost per MWh of
Purchased Power (1).......... $ 71.49 $ 160.92 (55.6)% $ 114.49 $ 135.51 (44.7)%
- --------
(1)Not including contract termination costs, discussed below.
Our purchased power costs and volume were lower for both the three- and
six-month periods ended June 30, 2002 than for the same period of the prior
year. These decreases were the result of lower volumes and prices of Short-Term
Firm energy purchased. The decreases were offset, in part, by a $229 million
reserve recorded in the current quarter for terminated contracts, which are
part of the power portfolio costs and which are described in more detail below
under "--Financial Condition, Liquidity, and Capital Resources." Purchases
associated with risk management activities, which are included in Short-Term
Firm energy, also decreased significantly in 2002, for both the current quarter
and year-to-date. Risk management activities include transactions entered into
for hedging purposes and to minimize purchased power costs. See
"Business--Commodities Risk" for a discussion of our purchased power
procurement strategies.
Three Months Six Months
Ended June 30, Ended June 30,
--------------------------- ----------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
------- -------- ------------ -------- -------- ------------
(dollars in thousands)
Fuel for Power Generation $73,474 $102,258 (28.1)% $157,196 $217,610 (27.8)%
Thousands of MWh generated....... 2,415 2,573 (6.1)% 4,656 5,074 (8.2)%
Average cost per MWh of Generated
Power.......................... $ 30.42 $ 39.74 (23.5)% $ 33.76 $ 42.89 (21.3)%
Fuel for generation costs for both the three and six months ended June 30,
2002, were significantly lower than the prior year due to substantial decreases
in natural gas prices and volume.
Three Months Six Months
Ended June 30, Ended June 30,
-------------------------------- --------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
--------- --------- ------------ --------- --------- ------------
(dollars in thousands)
Deferral of energy costs-net
Deferred energy costs........... $(185,199) $(281,145) (34.1)% $(194,835) $(269,837) (27.8)%
Deferred energy costs disallowed -- -- N/A 434,123 -- N/A
--------- --------- --------- ---------
$(185,199) $(281,145) (34.1)% $ 239,288 $(269,837) N/A
========= ========= ========= =========
27
Deferral of energy costs-net for the three- and six-month periods ended June
30, 2002, reflects the deferral in the second quarter of 2002 of approximately
$229 million for contract termination costs, as described in more detail below
under "--Financial Condition, Liquidity and Capital Resources." Deferral of
energy costs-net also reflects the amortization of prior deferred costs
resulting from an increase in rates beginning April 1, 2002, pursuant to the
PUCN's March 29, 2002, decision on our deferred energy rate case, and the
one-time rate increase of $0.01 per kilowatt-hour for the month of June 2002.
The amortization is offset, in part, by the recording of additional deferrals
of electric energy costs, reflecting the extent to which actual fuel and
purchased power costs exceeded the fuel and purchased power costs recovered
through current rates. Deferral of energy costs-net for the six-months ended
June 30, 2002, also reflects the write-off of $434 million of deferred energy
costs for the seven months ended September 30, 2001, that were disallowed by
the PUCN in their decision on our deferred energy rate case.
Three Months Six Months
Ended June 30, Ended June 30,
------------------------ --------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
---- ----- ------------ ------ ----- ------------
(dollars in thousands)
Allowance for other funds used during
construction.......................... $ 80 $(122) N/A $ 501 $(473) N/A
Allowance for borrowed funds used during
construction.......................... 849 265 220.4% 1,961 (87) N/A
---- ----- ------ -----
$929 $ 143 549.7% $2,462 $(560) N/A
==== ===== ====== =====
Our total allowance for funds used during construction ("AFUDC") is higher
for the three- and six-month periods ended June 2002 as a result of an increase
in capital expenditures for the Centennial Plan and adjustments in 2001 to
refine amounts assigned to specific components of facilities that were
completed in different periods. The increase is offset by a decrease in the
AFUDC rate in 2002 as a result of an increase in short-term debt.
Three Months Six Months
Ended June 30, Ended June 30,
--------------------------- -------------------------------
Change from Change from
2002 2001 Prior Year % 2002 2001 Prior Year %
------- ------- ------------ --------- -------- ------------
(dollars in thousands)
Other operating expense........... $37,284 $33,750 10.5% $ 77,270 $ 84,522 (8.6)%
Maintenance expense............... 11,876 13,478 (11.9)% 23,526 26,458 (11.1)%
Depreciation and amortization..... 17,140 22,427 (23.6)% 47,949 44,303 8.2%
Income taxes...................... (57) 16,246 (100.4)% (156,480) (14,218) 1,000.6%
Taxes other than income taxes..... 6,453 5,847 10.4% 13,187 11,897 10.8%
Interest charges on long-term debt 22,876 18,339 24.7% 46,954 34,959 34.3%
Interest charges--other........... 4,352 3,750 16.1% 6,882 7,713 (10.8)%
Other income (expense)--net....... 5,585 2,747 103.3% (5,772) 3,168 (282.2)%
Other operating expense for the three-month period ending June 30, 2002 was
higher, compared with the same period in the prior year, due to increased
expenses related to a new Credit and Collections Action Plan, higher reserve
rates for uncollectible accounts, costs associated with obtaining a tax refund
and legal fees associated with the PUCN's Deferred Energy Rate Case decision.
These increases were partially offset by credits associated with the reversal
of a $3.0 million reserve provision established in 2001 as a result of the
conclusion of electric industry restructuring in Nevada and a $2.7 million
reversal of our Short-term Incentive Plan accrual. Other operating expense for
the six-month period ending June 30, 2002 was less, compared with the same
period in the prior year. In addition to the previously mentioned items, the
decrease reflects a $16.1 million increase in the provision for uncollectible
accounts in 2001 related to the California Power Exchange, and the original
$3.0 million reserve provision established in 2001 as a result of the
conclusion of electric industry restructuring. These reductions in 2002 were
partially offset by increased expenses in 2002 related to insurance premiums, a
Mill Tax rate increase, and the delayed outage and adjustments at Reid Gardner.
28
Maintenance costs for the three- and six-month periods ending June 30, 2002,
decreased from the prior year due to delayed outages at Reid Gardner and Clark
Station. The 2001 costs are higher due to engineering costs associated with a
major turbine overhaul on Reid Gardner.
Depreciation and amortization is lower for the three-month period ended June
2002 as a result of a successful petition for reconsideration of a PUCN
decision, which reversed $8.7 million of additional depreciation recorded in
the first quarter of 2002. This decrease is partly offset by an increase in the
computer depreciation rate and additions to plant-in-service. Depreciation and
amortization increased in the six-month period ending June 2002 as a result of
additions to plant-in-service offset in part by plant-in-service asset
reconciliations pursuant to a PUCN order.
We recorded a small income tax benefit for the three months ended June 30,
2002, compared to income tax expense for the same period in 2001, as a result
of a net pre-tax loss in the current year compared to pre-tax net income in the
prior year. For the six months ended June 30, 2002, we recorded a significantly
increased income tax benefit compared to 2001, reflecting a much higher pre-tax
loss in the current year compared to the prior year.
Taxes other than income increased for the three- and six-month periods
ending June 30, 2002, due to increased property taxes related to an increase in
plant-in-service, and due to higher payroll taxes.
Interest charges on long-term debt for the three- and six-month periods
ending June 30, 2002, increased over the same periods in 2001 due to $446
million and $246 million net increases, respectively, in long-term debt
outstanding between the same periods.
Interest charges-other for the three-months ended June 30, 2002, increased
from the prior year due to $1.3 million in interest expense on delayed payments
not applicable to the same period 2001. For the six months ended June 30, 2002,
the $1.3 million partially offset the reduction in interest expense that
resulted from lower commercial paper and short-term debt balances carried
forward from the first quarter of the year.
Other income (expense) - net for the three months ended June 30, 2002,
increased compared to the same period in the prior year primarily due to a $5.0
million increase in carrying charges for deferred energy. Other income
(expense) - net for the six months ended June 30, 2002, reflects the first
quarter write-off of approximately $20.1 million, net of taxes, of carrying
charges on deferred energy costs that were disallowed by the PUCN in their
March 29, 2002 decision on our deferred energy rate case. The write-off was
offset in part by the recording of current year carrying charges on deferred
energy costs.
Year Ended December 31, 2001 Compared With Years Ended December 31, 2000 and
1999
We earned net income of $63.4 million in 2001, compared to a net loss of
($7.9) million in 2000, and 1999 net income before dividend requirements on
preferred stock of $38.8 million. These amounts do not include our equity in
the earnings (losses) of Sierra Pacific Resources. The causes for significant
changes in specific lines comprising our results of operations for the
respective years ended are provided below:
2001 2000 1999
----------------------- ----------------------- -----------
Change from Change from
Amount Prior Year % Amount Prior Year % Amount
----------- ------------ ----------- ------------ -----------
(dollars in thousands)
Electric Operation Revenues:
Residential................... $ 644,875 31.0% $ 492,365 18.3% $ 416,345
Commercial.................... 302,682 32.9% 227,790 13.8% 200,186
Industrial.................... 447,766 37.0% 326,916 12.6% 290,409
----------- ----------- -----------
Retail revenues............... 1,395,323 33.3% 1,047,071 15.5% 906,940
Other(1)...................... 1,629,780 485.4% 278,399 295.9% 70,322
----------- ----------- -----------
Total Revenues............ $ 3,025,103 128.2% $ 1,325,470 35.6% $ 977,262
=========== =========== ===========
Total retail sales (MWh)...... 16,799,000 2.7% 16,363,000 12.0% 14,615,000
Average retail revenue per MWh $ 83.06 29.8% $ 63.99 3.1% $ 62.06
- --------
(1)Primarily wholesale, as discussed below.
29
Our retail revenues increased in 2001 due to a combination of customer
growth, and rate increases resulting from the Global Settlement and CEP. See
"--Major Factors Affecting Results of Operations" above. The number of
residential, commercial, and industrial customers increased over the prior year
by 4.8%, 4.4% and 6.5%, respectively. As a result of the CEP, a rate increase
of 17% for retail customers became effective March 1, 2001. Substantially all
of the increase in Other electric revenues was due to the sale of wholesale
electric power to other utilities. The increase in our wholesale sales compared
to 2000 was a result of market conditions and our power procurement activities.
See "Business--Commodities Risk" below for a discussion of our purchased power
procurement strategies.
Our retail revenues increased in 2000 due to a combination of customer
growth, warmer than normal weather, and rate increases resulting from the
Global Settlement. The number of residential, commercial, and industrial
customers increased over the prior year by 5.6%, 4.6% and 7.4%, respectively.
As a result of the Global Settlement, We implemented monthly rate increases
starting August 1, 2000. Other electric revenues were higher in 2000 compared
to 1999 due to increased sales of wholesale electric power to other utilities.
See "Business--Commodities Risk" below for a discussion of our purchased power
procurement strategies.
2001 2000 1999
----------------------- ---------------------- ----------
Change from Change from
Amount Prior Year % Amount Prior Year % Amount
----------- ------------ ---------- ------------ ----------
(dollars in thousands)
Purchased Power:
Total purchased power......... $ 3,026,336 350.8% $ 671,396 98.1% $ 338,972
Less imputed capacity deferral -- -- -- -- (45,372)
----------- ---------- ----------
Purchased Power............... $ 3,026,336 350.8% $ 671,396 128.7% $ 293,600
=========== ========== ==========
Purchased power MWh........... 19,268,305 99.5% 9,659,118 22.9% 7,861,985
Average cost per MWh of
purchased power............. $ 157.06 126.0% $ 69.51 61.2% $ 43.12
Our purchased power costs were significantly higher in 2001 due to
substantial increases in prices and volumes. Per unit costs of power increased
126% primarily due to higher Short-Term Firm energy prices. These price
increases were the result of much higher fuel costs, combined with increased
demand and limited power supplies. Volumes purchased rose 100% to accommodate
increases in system load of approximately 2.7% and increases in wholesale sales
of approximately 310%. Purchases associated with risk management activities,
which include transactions entered into for hedging purposes and to optimize
purchased power costs, are included in the purchased power amounts. See
"Business--Commodities Risk" below for a discussion of our purchased power
procurement strategies.
Purchased power costs were higher in 2000 as compared to 1999 due to a 23%
increase in the volume purchased and an increase in the per unit cost of power
of 61%.
2001 2000 1999
--------------------- ----------------------- ----------
Change from Change from
Amount Prior Year % Amount Prior Year % Amount
---------- ------------ ----------- ------------ ----------
(dollars in thousands)
Fuel for Power Generation: $ 441,900 50.9% $ 292,787 89.4% $ 154,546
MWh generated............. 9,899,195 (7.9)% 10,744,466 17.2% 9,167,963
Average fuel cost per MWh
of generated power...... $ 44.64 63.8% $ 27.25 61.6% $ 16.86
Our 2001 fuel expense increased over 50% compared to 2000 primarily due to a
substantial increase in natural gas prices, offset in part, by decreased
generation late in 2001 when the cost of purchased power was
30
more economical than generation. In 2000, our fuel expense increased 89%
compared to 1999 primarily due to a substantial increase in natural gas prices.
2001 2000 1999
----------------------- ------------------ -------
Change from Change from
Amount Prior Year % Amount Prior Year % Amount
--------- ------------ ------- ------------ -------
(dollars in thousands)
Deferral of energy costs-electric-net: $(937,322) N/A $16,719 (82.8)% $97,238
We recorded a significant Deferral of energy costs-net in 2001 due to the
implementation of deferred energy accounting beginning March 1, 2001. The
current year amounts reflect the extent to which actual fuel and purchased
power costs exceeded the fuel and purchased power costs recovered through
current rates. Deferral of energy costs-net for 2000 represents energy costs
that had been deferred in prior periods and were then recovered in 2000, as a
result of deferred energy rate increases granted in 1999.
Deferral of energy costs-net decreased in 2000 compared to 1999 because we
discontinued deferred energy cost accounting effective August 1, 2000, pursuant
to the July 2000 Global Settlement with the PUCN, and because of decisions,
described below, by the PUCN affecting 1999's Deferral of energy costs-net. For
more information on the Global Settlement, see "--Major Factors Affecting
Results of Operations" above.
In February and March 2000, the PUCN issued orders that rejected our
requested rate relief in our 1999 deferred energy filings. As a result of these
decisions, a pre-tax charge of $80 million to Deferral of energy costs-net was
made in 1999 to write-off deferred energy and imputed capacity costs.
See "--Critical Accounting Policies" above and Note 1 of "Notes to Financial
Statements Years Ended December 31, 2001, 2000 and 1999" for more information
regarding deferred energy accounting.
2001 2000 1999
------------------ ------------------ -------
Change from Change from
Amount Prior Year % Amount Prior Year % Amount
------ ------------ ------- ------------ -------
(dollars in thousands)
Allowance for other funds used
during construction................... $ (382) (115.6)% $ 2,456 (33.9)% $ 3,713
Allowance for borrowed funds used during
construction.......................... 2,141 (72.7)% 7,855 (6.0)% 8,356
------ ------- -------
$1,759 (82.9)% $10,311 (14.6)% $12,069
====== ======= =======
Our AFUDC is lower in 2001 because of adjustments to amounts assigned to
specific components of facilities that were completed in different periods. In
2000, there was a small decrease in the AFUDC rate compared to 1999 because of
an increase in short-term debt.
2001 2000 1999
------------------- -------------------- --------
Change from Change from
Amount Prior Year % Amount Prior Year % Amount
-------- ------------ -------- ------------ --------
(dollars in thousands)
Other operating expense........... $169,442 21.3% $139,723 (0.9)% $141,041
Maintenance expense............... 45,136 32.5% 34,057 (33.0)% 50,805
Depreciation and amortization..... 93,101 8.3% 85,989 6.6% 80,644
Income taxes...................... 17,775 N/A (12,162) (161.0)% 19,943
Interest charges on long-term debt 81,599 26.5% 64,513 0.1% 64,454
Interest charges--other........... 13,219 (3.7)% 13,732 55.8% 8,815
Other income (expense)-net........ 27,272 1487.4% 1,718 (194.2)% (1,824)
31
Other operating expense increased in 2001 compared to 2000 due to a $16.6
million larger addition to the provision for uncollectible customer accounts
than in 2000, reflecting the impact of the weakening economy and disruption to
the leisure travel industry after September 11, 2001. Other operating expense
also increased due to the addition of $12.6 million to the uncollectible
provision related to receivables from the California Power Exchange ("PX") and
California's Independent System Operator ("ISO"). Our other operating expense
for 2000 was $8.8 million lower than 1999 due to reduced labor and benefit
costs as a result of merger efficiencies and unfilled vacancies. These savings
were offset, in part, by an increase in the provision for uncollectible
accounts that included a provision of $7.3 million related to the PX and ISO.
The level of our maintenance and repair expenses depends primarily upon the
scheduling, magnitude and number of generation unit overhauls at our generating
stations. Maintenance expense for 2001 increased from the prior year as a
result of increased outage work at Reid-Gardner, additional expenditures for
repairs and outages at Clark Station and increased work at Mohave. In 2000
maintenance expense decreased from the prior year primarily as a result of
fewer planned plant maintenance activities at our coal generation facilities.
In addition, in 2000 crews performed required activities of a capital nature,
thereby reducing the amount of maintenance expense.
An increase in plant-in-service was the cause of an increase in our
depreciation and amortization expense in 2001 compared to 2000. Depreciation
and amortization was also higher in 2000 than 1999 due to an increase in
plant-in-service.
As a result of net income for 2001, we incurred income tax expense. Due to a
net loss in 2000, we recorded an income tax benefit for the year. See Note 10
of "Notes to Financial Statements Years Ended December 31, 2001, 2000 and 1999"
for additional information regarding the computation of income taxes.
Our interest charges on long-term debt increased in 2001 compared to 2000,
following a net increase in associated debt of $450 million (new issuances of
$700 million and redemptions of $250 million during 2001). Interest charges on
long-term debt for 2000 were comparable to 1999. See Note 9 of "Notes to
Financial Statements Years Ended December 31, 2001, 2000 and 1999" and Note 4
of "Notes to Financial Statements Six Months Ended June 30, 2002 and 2001" for
additional information regarding long-term debt.
Our interest charges-other in 2001 were comparable to 2000. Interest
charges-other increased in 2000 compared to 1999 due to increased debt through
the issuance of commercial paper in 2000 and due to interest costs associated
with the issuance of floating rate notes in October 1999 and June, August, and
December 2000.
Our other income (expense)-net improved in 2001 due primarily to the
recognition in the current year of carrying charges on deferred fuel and
purchased power balances pursuant to AB 369. Other income (expense)-net
improved in 2000 over the prior year as a result of greater increases in life
insurance cash surrender values and reductions in contributions and membership
dues.
Analysis of Cash Flows
Six Months Ended June 30, 2002 Compared With Six Months Ended June 30, 2001
Our cash flows during the six months ended June 30, 2002, improved slightly
compared to the same period in 2001, resulting primarily from an increase in
cash flows from operating activities offset, in part, by a decrease in cash
flows from financing activities. Although we recorded a substantially larger
loss for the six months ended June 30, 2002 than the same period in 2001, the
increase in the current year's loss resulted largely from the write-off of
disallowed deferred energy costs for which the cash outflow had occurred in
2001. Current year cash flows from operating activities also benefited from a
smaller increase in accounts receivable compared to the prior year and from
lower energy prices, which necessitated a smaller deferral of energy costs.
These 2002 cash flow benefits were, however, largely offset by a much smaller
increase in accounts payable than in 2001. Cash flows from operating activities
in the current year also reflect the receipt of an income tax refund resulting
from a tax law change that took effect in March 2002. Cash flows from financing
activities were lower because of a
32
decrease in net long-term debt issued during the six months ended June 30, 2001
offset, in part, by an increase in short-term borrowings during the six months
ended June 30, 2002.
Year Ended December 31, 2001 Compared With Years Ended December 31, 2000 and
1999
Our net cash flows decreased in 2001 compared to 2000. The net decrease in
cash resulted from a significant increase in cash flows used in operating
activities combined with cash used in investing activities both partially
offset by an increase in cash provided by external financing sources. The
increase in cash flows used in operating activities resulted substantially from
the payment of significantly higher energy costs during 2001. Net cash used in
investing activities was comparable between 2001 and 2000. Net cash provided by
financing activities was higher in 2001 as a result of cash provided by the
issuance of short-term and long-term debt, as described in Notes 12 and 9 of
"Notes to Financial Statements Years Ended December 31, 2001, 2000 and 1999"
and Notes 3 and 4 of "Notes to Financial Statements Six Months Ended June 30,
2002 and 2001," and additional capital contributions from Sierra Pacific
Resources. Cash provided by financing activities was substantially utilized for
the payment of higher energy costs in 2001.
Our net cash flows increased in 2000 compared to 1999. The net increase in
cash resulted from less cash used in investing activities and more cash
provided by financing activities. A reduction in the net cash used for utility
plant was the main cause for the decrease in cash used for investing
activities. The increase in cash flows from financing activities was due to an
increase in funding received from Sierra Pacific Resources (less dividends
paid) offset, in part, by less cash provided by the net issuance of long and
short-term debt. The overall net increase in cash was also partially offset by
a reduction in cash received from operating activities that was mainly due to a
decrease in operating income.
Financial Condition, Liquidity And Capital Resources
At June 30, 2002, we had cash and cash equivalents of approximately $59.9
million. At August 31, 2002, we had cash and cash equivalents of approximately
$160.7 million.
As discussed below under "--Construction Expenditures and Financing," we
anticipated external capital requirements for construction costs and for the
repayment of maturing short-term and long-term debt during 2002 totaling
approximately $403 million, which we planned to fund through a combination of
(i) internally generated funds, (ii) the issuance of short-term debt and
preferred stock, and (iii) capital contributions from Sierra Pacific Resources.
On March 29 and April 1, 2002, following the decision by the PUCN in our
deferred energy rate case, S&P and Moody's, the two major national rating
agencies, lowered our unsecured debt ratings to below investment grade. On
April 23 and 24, 2002, our unsecured debt ratings were further downgraded and
our secured debt ratings were downgraded to below investment grade. Currently,
the rating agencies have our credit ratings on "watch negative" or "possible
downgrade." As a result of these recent developments, our ability to access the
capital markets to raise funds has become limited. In addition, because the
credit ratings of Sierra Pacific Resources were similarly downgraded and
because of restrictions on our ability to pay dividends on our common stock,
Sierra Pacific Resources' ability to make capital contributions to us has also
become limited.
In connection with the credit downgrades by S&P and Moody's, we lost our
A2/P2 commercial paper ratings and can no longer issue commercial paper. We had
a commercial paper balance outstanding of $198.9 million at the time with a
weighted average interest rate of 2.52%. Since we were no longer able to roll
over our commercial paper, we paid off our maturing commercial paper with the
proceeds of borrowings under our credit facility and terminated our commercial
paper program on May 28, 2002. We do not expect to have direct access to the
commercial paper market for the foreseeable future.
Our $200 million unsecured revolving credit facility was also affected by
the PUCN's decision in the deferred energy rate case. Following the
announcement of that decision, the banks participating in our credit
33
facility determined that a material adverse event had occurred, thereby
precluding us from borrowing funds under our credit facility. The banks agreed
to waive the consequences of the material adverse event in a waiver letter and
amendment that was executed on April 4, 2002. As required under the waiver
letter and amendment, we issued and delivered our General and Refunding
Mortgage Bond, Series C, due November 28, 2002, in the principal amount of $200
million, to the Administrative Agent as security for the credit facility.
The waiver letter and amendment also provided that (i) we may not create or
incur any liens on our properties to secure obligations to our power and/or
commodity trading counterparties or power suppliers, (ii) in the event that we
issue more than $250 million of our General and Refunding Mortgage Bonds, other
than to secure our 6.20% Senior Unsecured Notes, Series B due April 15, 2004,
the principal amounts of such issuances will be applied as mandatory
prepayments of the loans outstanding under the credit facility and the
commitments under the facility will correspondingly be reduced, and (iii) the
Sierra Pacific Resources credit facility be terminated.
On June 25, 2002, we and the banks executed Amendment No. 2 to our Credit
Agreement that prohibits us from paying any dividends and prohibits the
voluntary prepayment or redemption of our existing indebtedness,
except in the ordinary course of business. Amendment No. 2 also modifies the
restriction in the waiver letter and amendment with respect to creating or
incurring liens to secure obligations to our power and/or commodity trading
counterparties or power suppliers. Under Amendment No. 2, we may create or
incur liens on up to an aggregate total of $50 million of our deposit and
investment accounts and our investment properties to support our obligations to
fuel or other energy suppliers, to secure our cash management obligations,
and/or to secure liens on property securing all or part of the purchase price
of the property or liens existing in such property at the time of purchase.
By May 2, 2002, we had borrowed the entire $200 million of funds available
under our credit facility to pay off maturing commercial paper. The borrowing
costs under the credit agreement are at a variable interest rate consisting of
a spread over LIBOR or an alternate base rate that is based upon a pricing grid
tied to the credit rating on our senior unsecured long-term debt. Our credit
agreement contains certain financial covenants. As of June 30, 2002, we were in
compliance with these financial covenants. Our credit facility expires on
November 28, 2002.
We are in the process of negotiating agreements for an accounts receivable
purchase facility of up to $125 million being arranged by Lehman Brothers.
Under the receivables purchase facility we would sell all of the accounts
receivable generated from the sale of electricity to our customers to a newly
created bankruptcy-remote special purpose subsidiary of ours. This subsidiary
would sell these receivables to a bankruptcy-remote subsidiary of our parent,
Sierra Pacific Resources which, in turn, would issue variable rate revolving
notes backed by such receivables. The receivables sales would be without
recourse except for breaches of customary representations and warranties made
at the time of the sale. We plan to issue up to $125.0 million aggregate
principal amount of our General and Refunding Mortgage Bonds to secure certain
of our obligations as seller and servicer with respect to the receivables
purchase facility. The closing of the receivables purchase facility is subject
to satisfactory completion of due diligence and the finalization of
documentation. Commencement of the sale of accounts receivables pursuant to the
receivables purchase facility is subject to completion of the offering of notes
contemplated hereby, the termination of our existing credit facility and
certain other conditions. Although we are currently negotiating the terms of
the accounts receivable facility, we cannot assure you that we will enter into
the facility or any similar arrangement.
Our First Mortgage Indenture creates a first priority lien on substantially
all of our properties. As of June 30, 2002, we had $387.5 million of first
mortgage bonds outstanding. Although the First Mortgage Indenture allows us to
issue additional mortgage bonds on the basis of (i) 60% of net utility property
additions and/or (ii) the principal amount of retired mortgage bonds, our G&R
Indenture prohibits us from issuing additional bonds under our First Mortgage
Indenture, except in certain circumstances.
Our G&R Indenture creates a lien on substantially all of our properties in
Nevada that is junior to the lien of the first mortgage indenture. As of June
30, 2002, we had $820 million of General and Refunding Mortgage
34
securities outstanding. Additional securities may be issued under the G&R
Indenture on the basis of (1) 70% of net utility property additions, (2) the
principal amount of retired General and Refunding Mortgage bonds, and/or (3)
the principal amount of first mortgage bonds retired after delivery to the
indenture trustee of the initial expert's certificate under the G&R Indenture.
At June 30, 2002, we had the capacity to issue approximately $861 million of
additional General and Refunding Mortgage bonds. However, the financial
covenants contained in the credit agreement described above may limit our
ability to issue additional General and Refunding Mortgage Bonds or other debt.
In addition, the waiver letter and amendment to the credit agreement entered
into on April 4, 2002 requires that, in the event that we issue more than $250
million of our General and Refunding Mortgage Bonds, the principal amounts of
such issuances will be applied as mandatory prepayments of the loans
outstanding under the credit facility and the commitments under the facility
will correspondingly be reduced. The Duke agreement, referenced below, also
requires prepayments of certain deferred payments established under the
agreement in the event that we receive excess financing proceeds from issuances
of our General and Refunding Mortgage Bonds.
We also have the ability to release property from the liens of the two
mortgage indentures on the basis of net property additions, cash and/or retired
bonds. To the extent we release property from the lien of our G&R Indenture, we
will reduce the amount of bonds issuable under that indenture.
On May 13, 2002, we issued a General and Refunding Mortgage Bond, Series D,
due April 15, 2004, in the principal amount of $130 million, for the benefit of
the holders of our 6.20% Senior Unsecured Notes, Series B, due April 15, 2004.
The Senior Unsecured Note Indenture required that, in the event that we issued
debt secured by liens on our operating property in excess of 15% of its Net
Tangible Assets or Capitalization (as both terms are defined in the Senior
Unsecured Note Indenture), we would equally and ratably secure the Senior
Unsecured Notes.
On June 19, 2002, the PUCN issued a Compliance Order, Docket No. 02-4037,
authorizing us to issue $300 million of long-term debt. In the event that we
were able to issue $50 million of our remaining short-term debt authorized on
September 1, 2002, the $300 million of long-term debt authorized pursuant to
the order would be reduced to $250 million. We had requested authority for $450
million. The PUCN order provides that we will bear the burden of demonstrating
that any financings undertaken pursuant to the order, including any
determination made regarding the length of such commitment, the type of
security or rate, is reasonable. The order also requires that, until such time
as the order's authorization expires (December 31, 2003), we must either
receive the prior approval of the PUCN or reach an equity ratio of 42% before
paying any dividends to our parent, Sierra Pacific Resources. If we achieve a
42% equity ratio prior to December 31, 2003, the dividend restriction ceases to
have effect.
On July 3, 2002, the Bureau of Consumer Protection of the Nevada Attorney
General's Office filed a petition with the PUCN requesting that the hearing in
Docket No. 02-4037 be reopened to allow for the introduction of additional
evidence or for the PUCN to reconsider its decision granting us the authority
to issue long-term debt. On September 11, 2002, the PUCN denied the petition to
reopen the proceeding and rescinded the portion of its Compliance Order that
had previously required us to immediately issue $50 million to $100 million of
debt.
In early May of 2002, Enron Power Marketing Inc. ("Enron"), Morgan Stanley
Capital Group, Inc. ("MSCG"), Reliant Energy Services, Inc. and several smaller
suppliers terminated their power deliveries to us, exercising their contractual
right under the Western Systems Power Pool Agreement ("WSPPA") to terminate
deliveries based upon our decision not to provide adequate assurances of our
performance under the WSPPA to any of our suppliers. Each of these terminating
suppliers has asserted, or has indicated that it will assert, a claim against
us for liquidated damages.
On June 5, 2002, Enron filed suit against us in its bankruptcy case in the
Bankruptcy Court for the Southern District of New York asserting claims for
liquidated damages related to the termination of its power supply agreement
with us of approximately $216 million. Enron's claim is subject to our defense
that such claims are already at issue in our FERC proceeding against Enron
under Section 206 of the Federal Power Act challenging the contract prices of
the terminated power supply agreement. In connection with the lawsuit filed by
Enron in the Bankruptcy Court, Enron has filed a motion to require us to
promptly pay them in full the amount of their claim
35
pending the final resolution of their lawsuit against us. At this time, we are
not able to predict the outcome of a decision in this matter. An adverse
decision on the motion seeking for us to promptly pay the full amount of
Enron's claim or an adverse decision in the lawsuit would have a material
adverse affect on our financial condition and liquidity and would render our
ability to continue to operate outside of bankruptcy uncertain. A hearing with
respect to Enron's motion is scheduled to be held on October 11, 2002 and a
decision is expected shortly thereafter. In addition, on September 5, 2002,
MSCG filed a Demand for Arbitration in accordance with the mediation and
arbitration procedures of the WSPPA seeking a termination payment from us of
approximately $25 million under their terminated power supply agreement with us.
On June 10, 2002, Duke Energy Trading and Marketing ("Duke") entered into an
agreement with us, Sierra Pacific Resources and Sierra Pacific Power Company to
supply up to 1,000 megawatts of electricity per hour, as well as natural gas,
to fulfill our customers' power requirements during the peak summer period. The
effect of the Duke agreement was to replace the amount of contracted power and
natural gas that would have been supplied by the various terminating suppliers,
including Enron. Duke also agreed to accept deferred payment for a portion of
the amount due under its existing power contracts with us for purchases made
through September 15, 2002. Although the other continuing suppliers have not
entered into formal agreements with us regarding deferred payments, we have
been deferring a portion of the payments to such suppliers since May 1, 2002
and intend to continue to due so for charges incurred through September 15,
2002.
On September 30, 2002, El Paso Merchant Energy Group ("EPME") notified us
that it was terminating all transactions entered into with us under the WSPPA.
At the present time, we expect that net gains and losses relating to the
terminated transactions, including a delayed payment amount of approximately
$19 million that we owed to EPME for power deliveries through September 15,
2002, will result in a small net payment due to us.
Our liquidity would also be significantly affected by an adverse decision in
the pending lawsuit by Enron to collect liquidated damages (including its
motion requesting that we promptly pay the amount of the claim pending the
final resolution of the lawsuit), by unfavorable rulings by the PUCN in our
future rate cases, or by an inability to renew, replace or refinance all or a
portion of our credit facility that expires on November 28, 2002. Both S&P and
Moody's have our credit ratings on "watch negative" or "possible downgrade,"
and any further downgrades could further preclude our access to the capital
markets. Adverse developments with respect to any one or a combination of the
foregoing could cause us to become insolvent and would render our ability to
continue to operate outside of bankruptcy uncertain.
Construction Expenditures and Financing
The table below lists our consolidated cash construction expenditures and
internally generated cash, net for 1999 through 2001:
2001 2000 1999 Total
--------- -------- -------- ---------
(dollars in thousands)
Cash construction expenditures.................................. $ 196,896 $196,636 $220,919 $ 614,451
========= ======== ======== =========
Net cash flow from operating activities......................... $(757,402) $113,711 $178,178 $(465,513)
Less common & preferred cash dividends.......................... 33,014 88,308 121,646 242,968
--------- -------- -------- ---------
Internally generated cash....................................... (790,416) 25,403 56,532 (708,481)
Add equity contribution from parent............................. 474,921 137,000 18,000 629,921
--------- -------- -------- ---------
Total cash available............................................ $(315,495) $162,403 $ 74,532 $ (78,560)
========= ======== ======== =========
Internally generated cash as a percentage of cash construction
expenditures.................................................. N/A 13% 26% N/A
Total cash generated (used) as a percentage of cash construction
expenditures.................................................. N/A 83% 34% N/A
36
Our estimated cash construction expenditures for 2002 through 2006 are
$1.118 billion. Construction expenditures for 2002 (approximately $243 million)
will be financed through debt issuance and internally generated funds,
including recovery of deferred energy. Cash provided by internally generated
funds during 2002 assumed full recovery of deferred energy costs over three
years and general rate increases approved as filed effective at the beginning
of the second quarter.
Contractual Obligations
The table below lists our contractual obligations, not including estimated
construction expenditures described above, as of December 31, 2001, that we
expect to satisfy through a combination of internally generated cash and, as
necessary, through the issuance of short-term and long-term debt:
Payments Due By Period
----------------------------------------------
2002 2003 2004 2005 2006 Thereafter Total
---------- -------- -------- -------- -------- ---------- ----------
(dollars in thousands)
Long-Term Debt (1).... $ 149,880 $350,000 $130,000 $ -- $ -- $1,127,967 $1,757,847
Purchased Power....... 1,046,893 17,061 109,904 109,374 108,996 713,711 2,105,939
Coal and Natural Gas.. 187,663 55,493 63,780 31,043 31,064 373,228 742,271
Capital Lease
Obligations......... 6,156 6,156 6,946 7,736 7,736 58,016 92,746
Operating Leases...... 2,941 1,470 1,090 926 504 -- 6,931
---------- -------- -------- -------- -------- ---------- ----------
Total Contractual Cash
Obligations......... $1,393,533 $430,180 $311,720 $149,079 $148,300 $2,272,922 $4,705,734
========== ======== ======== ======== ======== ========== ==========
- --------
(1)Includes short-term debt of $130,500.
Regulatory Matters
In each regulatory jurisdiction, rates for retail electric services (other
than specially negotiated retail rates for industrial or large commercial
customers, which are subject to regulatory review and approval) are currently
determined on a "cost of service" basis and are designed to provide, after
recovery of allowable operating expenses, an opportunity to earn a reasonable
return on "rate base." "Rate base" is generally determined by reference to the
original cost (net of accumulated depreciation) of utility plant in service,
subject to various adjustments for deferred taxes and utility plant. To the
extent that the energy business is restructured, traditional "cost of service"
ratemaking may evolve into some other form of ratemaking. Rates for
transmission services are based on the "cost of service" principles and are
currently set forth in tariffs on file with the FERC.
As a regulated public utility, we are subject to the jurisdiction of the
PUCN with respect to rates, standards of service, siting of and necessity for,
generation and certain transmission facilities, accounting, issuance of
securities and other matters with respect to electric distribution and
transmission operations. We are required to submit integrated resource plans
detailing our sources of supply and our power procurement strategies to the
PUCN for approval. We are also subject to certain federal regulation primarily
by the FERC, which has jurisdiction, under the Federal Power Act, over rates,
service, interconnection, accounting, and other matters in connection with the
sale of electricity for resale and interstate transmission. The FERC also has
jurisdiction over the natural gas pipeline companies from which we take
service. As a result of applicable state and federal regulation, many of our
fundamental business decisions, as well as the rate of return we can earn on
our utility assets, are determined by governmental agencies.
On April 18, 2001, the Governor of Nevada signed into law Assembly Bill 369
("AB 369"). The provisions of AB 369 include a moratorium on the sale of
generation assets by electric utilities until July 2003, the repeal of electric
industry restructuring (which had been mandated by AB 366 which was signed into
law in 1997), and a
37
reinstatement of deferred energy accounting for fuel and purchased power costs
incurred by electric utilities. Part of the stated purpose of this emergency
legislation was to control volatility in the price of electricity in the retail
market in Nevada as well as to ensure that we and Sierra Pacific Power Company
had the necessary financial resources to provide adequate and reliable electric
service during the utility crisis beginning in 2000 in the western United
States. AB 369 allowed us to recover our unrecovered costs for wholesale power
and fuel which had risen dramatically during 2001, through the filing of a
deferred energy rate case with the PUCN. The reinstatement of deferred energy
accounting under AB 369 had the effect of delaying additional rate increases to
consumers until the second quarter of 2002 while providing a method for us to
recover our increased costs for fuel and purchased power. Set forth below is a
summary of key provisions of AB 369.
Generation Divestiture Moratorium
AB 369 prohibits all divestiture of generation assets by electric utilities
until July 2003. After January 1, 2003, we would be permitted to seek PUCN
permission to sell one or more generation assets if the sale were to be
effective on or after July 1, 2003. The PUCN could approve a request to divest
only if it found the transaction to be in the public interest. The PUCN could
base its approval of the request upon such terms, conditions, or modifications
as it deems appropriate.
Prior to the enactment of AB 369, we had been required to divest ourselves
of our electric generation assets as a condition to our 1999 merger with Sierra
Pacific Resources and to prepare for a competitive energy market in Nevada.
Deferred Energy Accounting
AB 369 required us to use deferred energy accounting beginning on March 1,
2001. The intent of deferred energy accounting is to ease the effect of
fluctuations in the cost of purchased power and fuel. Under deferred energy
accounting, to the extent actual fuel and purchased power costs exceed fuel and
purchased power costs recoverable through current rates, that excess is not
recorded as a current expense on the income statement but rather is deferred
and recorded as an asset on the balance sheet. Conversely, a liability is
recorded to the extent fuel and purchased power costs recoverable through
current rates exceed actual fuel and purchased power costs. These excess
amounts are reflected in adjustments to rates and recorded as revenue or
expense in future time periods, subject to PUCN review. AB 369 provided that
the PUCN may not allow the recovery of any costs for purchased fuel or
purchased power "that were the result of any practice or transaction that was
undertaken, managed or performed imprudently by the electric utility." In
reference to deferred energy accounting, AB 369 specifies that fuel and
purchased power costs include all costs incurred to purchase fuel, to purchase
capacity, and to purchase energy. We also record, and are eligible to recover,
a carrying charge on such deferred balances.
AB 369 requires that we file an application to clear our deferred energy
account balance after the end of each 12-month period, but allows the balances
from each 12-month period to be recovered over an adjustment period of up to
three years in order to reduce the volatility of rate changes. In addition,
after the initial deferred energy case, we are allowed to file an application
to clear our deferred energy account balance after the end of a six-month
period if the proposed net increase or decrease in fuel and purchased power
revenues for the six-month period is more than 5%. If we realize a rate of
return greater than the rate authorized by the PUCN, the portion that exceeds
the authorized rate of return will be transferred to the next deferred energy
adjustment period.
Before we may clear our deferred account, AB 369 requires the PUCN to
determine whether the costs for purchased fuel and purchased power that we
recorded in our deferred account are recoverable and whether the revenues that
we collected from customers for purchased fuel and purchased power are properly
recorded and credited in our deferred accounts. AB 369 prohibits the PUCN from
allowing us to recover any costs for purchased fuel and purchased power that
were the result of any practice or transaction that was undertaken, managed or
performed imprudently by us. To the extent that the PUCN finds that any amount
included in our deferred account was imprudently incurred, the PUCN will not
permit that amount to be recovered through
38
higher rates, and an equivalent amount of our deferred energy costs asset will
be required to be written off. Such a write-off occurred as a result of the
PUCN's March 29, 2002 decision to disallow $434 million of the $922 million in
deferred energy costs that we sought to clear from our deferred account and
recover through rates.
Restrictions on Mergers and Acquisitions
AB 369 imposes certain restrictions on mergers and acquisitions involving
Nevada electric utilities. In particular, the PUCN may not approve a merger or
acquisition involving an electric utility unless the utility complies with the
generation divestiture provisions of AB 369. AB 369 also provides that if an
electric utility holding company acquires an interest in an out-of-state public
utility prior to July 1, 2003, each electric utility in which the holding
company holds a controlling interest shall not be entitled to the benefit of
deferred energy accounting. Thus, in the event that Sierra Pacific Resources
were to acquire an out-of-state public utility, we would lose the ability to
utilize deferred energy accounting.
Repeal of Electric Industry Restructuring
AB 369 repealed all statutes authorizing retail competition in Nevada's
electric utility industry and voided any license issued to an alternative
seller in connection with retail electric competition.
General Rate Case
On October 1, 2001, we filed an application with the PUCN seeking an
electric general rate increase. This application was mandated by AB 369. On
December 21, 2001, we filed a certification to our general rate filing updating
costs and revenues pursuant to Nevada regulations. In the certification filing,
we requested an increase in the general rates that we are permitted to charge
to all classes of electric customers. Such request was designed to produce an
increase in annual electric revenues of $22.7 million, which is an overall 1.7%
rate increase. The application also sought a return on common equity ("ROE")
for our total electric operations of 12.25% and an overall rate of return
("ROR") of 9.30%.
On March 27, 2002, the PUCN issued its decision on the general rate
application, ordering a $43 million revenue decrease with an ROE of 10.1% and
ROR of 8.37%. The effective date of the decision was April 1, 2002. The
decision also resulted in negative adjustments to depreciation aggregating $7.9
million, and the adverse treatment of approximately $5 million of revenues
related to SO2 Allowances. On April 15, 2002, we filed a petition for
reconsideration with the PUCN. In the petition, we raised six issues for
reconsideration: the treatment of revenues related to SO2 Allowances, in
particular the calculation of the annual amortization amount, which appeared to
be in error; the adjustment for "excess" capital investment related to common
facilities at the Harry Allen generating station; the rejection of adjustments
to accumulated depreciation reserves related to the establishment of revised
depreciation rates for transmission, distribution and common facilities; the
delay in allowing us to recover our merger costs without the benefit of
carrying charges; the finding that we had no need for and are entitled to zero
funds cash working capital; and the establishment of a 10.1% ROE. On May 24,
2002, the PUCN issued an order on the petition for reconsideration. In its
order, the PUCN reaffirmed its findings in the original order for the issues
related to "excess" capital investment at the Harry Allen generating station,
merger costs, cash working capital, and the 10.1% ROE. The PUCN, however, did
modify its original order to include adjustments related to SO2 Allowances and
depreciation issues. Revised rates for these changes went into effect on June
1, 2002.
Deferred Energy Case
On November 30, 2001, we filed an application with the PUCN seeking to clear
our deferred balances for purchased fuel and power costs accumulated between
March 1, 2001 through September 30, 2001, as mandated by AB 369. The
application sought to establish a DEAA rate to clear accumulated purchased fuel
and power costs of $922 million and spread the recovery of the deferred costs,
together with a carrying charge, over a period of not more than three years.
39
On March 29, 2002, the PUCN issued its decision on the deferred energy
application, allowing us to recover $488 million over a three year period but
disallowing $434 million of deferred purchased fuel and power costs. The order
states that the disallowance was based on alleged imprudence in incurring the
disallowed costs. On April 11, 2002, we filed a lawsuit in First District Court
of Nevada seeking to reverse portions of the PUCN's decision. We assert that,
as a result of the PUCN's decision, our credit rating was reduced to below
investment grade, Sierra Pacific Resources suffered a reduction in its equity
market capitalization of approximately 41%, and the disallowed costs are
effectively imposed upon Sierra Pacific Resources' shareholders.
In our lawsuit, we allege that the order of the PUCN is in violation of
constitutional and statutory provisions, made upon unlawful procedure, affected
by other error of law, clearly erroneous in view of the reliable, probative and
substantial evidence on the whole record, arbitrary and capricious and
characterized by abuse of discretion. We also state that our decisions with
respect to the purchase of power during the energy crisis in the western United
States were made prudently, as required under AB 369. In early 2001, the PUCN
and the Nevada State Legislature expressly required that we secure sufficient,
safe and reliable power for anticipated summer loads and needs for the summer
of 2001. Prior to AB 369, we were operating under an order of the PUCN to
divest ourselves of our electric generating plants. To meet this requirement,
we had engaged in an open auction process that led to the signing of asset
purchase agreements for a number of our plants, in connection with which, we
entered into long-term purchase power contracts with the potential buyers that
would have availed us of reasonably priced purchase power over a long-term
period. In our petition, we challenge the disallowance by the PUCN of $180
million of our deferred energy costs relating to an informal offer made by an
agent for Merrill Lynch for the delivery of energy from January 2001 to March
2003. In addition to certain procedural questions relating to the PUCN's
finding with respect to the Merrill Lynch informal offer, we assert that the
energy being negotiated was not firm (uninterruptible), the obligations, costs
and arrangements for delivery in the informal offer were not specified, the
cost of the energy proposed under the informal offer was above then-current
market price, and that the supplier was a minor market participant and the
magnitude of the transaction proposed was more than 45 times its previously
combined annual transactions.
Our lawsuit requests the District Court to reverse portions of the PUCN's
order and remand the matter to the PUCN with direction that the PUCN authorize
us to immediately establish rates that would allow us to recover our entire
deferred energy balance of $922 million, with a carrying charge over three
years. A hearing on this matter has been scheduled for February 2003. At this
time, we are not able to predict the outcome or the timing of a decision in
this matter.
Various intervenors in our deferred energy case before the PUCN filed
petitions with the PUCN for reconsideration of the PUCN's order, seeking
additional disallowances of between $12.8 million and $488 million. On May 24,
2002, the PUCN issued an order denying any further disallowances and granted us
the authority to increase the deferred energy cost recovery charge for the
month of June 2002 by one cent per kilowatt-hour. This increase accelerated the
recovery of the deferred balance by approximately $16 million for the month of
June 2002 only. The Bureau of Consumer Protection of the Nevada Attorney
General's Office has since filed a petition in our pending state court case
seeking additional disallowances.
Customers File Under Assembly Bill 661
The Nevada legislature passed Assembly Bill 661 ("AB 661") in 2001 which
allows commercial and governmental customers with an average electric demand
greater than 1 megawatt ("MW") to select new energy suppliers. We would
continue to provide transmission, distribution, metering and billing services
to such customers. AB 661 requires customers wishing to choose a new supplier
to receive the PUCN approval and meet public interest standards. In particular,
departing customers must secure new energy resources that are not under
contract with us, the departure must not burden us with increased costs or
cause any remaining customers to pay increased costs, and the departing
customers must pay their portion of any deferred energy balances. The PUCN
adopted regulations prescribing the criteria that will be used to determine if
we or our remaining customers will be negatively impacted by such departures.
These regulations place certain limits upon the departure of our
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customers until 2003; most significantly, the amount of load departing is
limited to approximately 1100 MW in peak conditions. Customers wishing to
choose a new supplier must provide us with a 180-day notice. AB 661 permitted
customers to file applications with the PUCN beginning in the fourth quarter of
2001 and customers could begin to receive service from new suppliers by
mid-2002.
During May 2002, Rouse Fashion Show Management, LLC, Coast Hotels and
Casinos, Inc., Station Casinos, Inc., Gordon Gaming Corp., MGM Mirage, and Park
Place Entertainment filed separate applications with the PUCN to exit our
system and to purchase energy, capacity and ancillary services from another
provider. The loads of these customers aggregate 260 MW on peak. Hearings on
the applications of all the customers except Park Place Entertainment were
completed on July 19, 2002 and the PUCN issued a decision on July 31, 2002 that
approved the applications of these customers to choose a new energy supplier.
The earliest any of these customers could begin taking energy from an
alternative provider would be November 1, 2002. If all five customers whose
applications were approved were to leave our system, we would incur an annual
loss in revenue of $48 million, which would be offset by a reduction in costs,
primarily for fuel and purchased power, of $46 million with the difference
being paid by exit fees from the departing customers. These customers will also
be responsible for their share of balances in our deferred energy accounts up
to the time they leave and must continue to pay their share of these balances
after they leave until paid in full. For example, if all five customers whose
applications were approved leave our system on November 1, 2002, their
remaining share of our previously approved deferred energy balance is estimated
to be $27 million. Additionally, these departing customers would be responsible
for paying their share of yet to be approved accumulated deferred energy
balances from October 1, 2001 to their date of departure, over such period as
may be set by the PUCN in that deferred energy case. They will also remain
accountable to any rulings made by the District Court on legal actions brought
in our past deferred energy case. They could also benefit from any refunds that
might be granted on power contracts under review with the FERC. Additionally,
if any departed customers return to us as their energy provider, they will be
charged for their energy at a rate equivalent to our incremental cost of
service. A stipulation among the parties was filed with the PUCN for an
incremental cost of service tariff in late September 2002. The PUCN has not yet
acted on this stipulation.
A hearing on the application of Park Place Entertainment was held on August
2, 2002. On August 12, 2002, the PUCN approved the application with terms and
conditions similar to those described above for the aforementioned five
customers.
Additional Finance Authority
The PUCN has issued orders authorizing us to issue $250 million of long-term
debt. We had originally requested authority for $450 million. The PUCN order
provides that we will bear the burden of demonstrating that any financings
undertaken pursuant to the order, including any determination made regarding
the length of such commitment, the type of security or rate, is reasonable. The
order also requires that, until such time as the order's authorization expires
(December 31, 2003), we must either receive the prior approval of the PUCN or
reach an equity ratio of 42% before paying any dividends to our parent, Sierra
Pacific Resources. If we achieve a 42% equity ratio prior to December 31, 2003,
the dividend restriction ceases to have effect.
FERC Matters
In December 2001, we, along with Sierra Pacific Power Company, filed ten
wholesale purchased power complaints with the FERC under Section 206 of the
Federal Power Act seeking their review of certain long-term power purchase
contracts that we entered into prior to the price caps established by the FERC
during the western United States utility crisis. We believe the prices under
these purchased power contracts are unjust and unreasonable. The FERC ordered
the case set for hearing and assigned an administrative law judge ("ALJ"). A
primary issue is whether or not the dysfunctional short-term market, which was
previously declared by the FERC, impacted the long-term market. The parties
filed written direct testimony with the ALJ on June 28, 2002. The ALJ's
schedule calls for hearings to be held in October 2002 and for a draft decision
in December 2002. We have engaged in bilateral discussions with respondents in
this matter. At this time, we are not able to predict the outcome of a decision
in this matter.
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Market Risk
We have evaluated our risk related to financial instruments whose values are
subject to market sensitivity. Such instruments are fixed and variable rate
debt, and preferred trust securities obligations, which were as follows on June
30, 2002. Fair market value was determined using quoted market price for the
same or similar issues or on the current rates offered for debt of the same
remaining maturities.
Long-term debt:
-------------------------------
Expected Weighted
Expected Maturities Avg Int. Fair Market
Maturity Date Amounts Rate Value
------------- ---------- -------- -----------
(dollars in thousands)
Fixed Rate
2002............................ $ 15,000 7.63% $ 15,000
2003............................ 210,000 6.00% 189,000
2004............................ 130,000 6.20% 119,600
2005............................ -- -- --
2006............................ -- -- --
Thereafter....................... 938,835 6.21% 882,818
---------- ----------
Total Fixed Rate................. $1,293,835 $1,206,418
========== ==========
Variable Rate
2002............................ $ -- -- $ --
2003............................ 140,000 4.07% 135,800
2004............................ -- -- --
2005............................ -- -- --
2006............................ -- -- --
Thereafter....................... 115,000 1.82% 115,000
---------- ----------
$ 255,000 $ 250,800
========== ==========
Preferred securities (fixed rate) $ 188,872 8.03% $ 141,466
---------- ----------
Total............................ $1,737,707 $1,598,684
========== ==========
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