EX-99.1 3 dex991.txt EXCERPTS FROM OFFERING MEMORANDUM Exhibit 99.1 Reference in this offering memorandum to "we," "us," "our" and "NPC" refer to Nevada Power Company, unless the context indicates otherwise. ------------------------ 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; 1 . 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; . 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. 2 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. 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. 3 In connection with the lawsuit filed by Enron in the Bankruptcy Court, Enron filed a motion for partial summary judgment to require us to make immediate payment of the full amount of their claim, pending final resolution of the lawsuit. On October 11, 2002, the Bankruptcy Court heard further arguments regarding the issue of FERC's primary jurisdiction over the contract claims. The Bankruptcy Court judge is expected to render a decision on the issue of FERC's jurisdiction on or about October 24, 2002. If the judge decides not to stay Enron's lawsuit pending the outcome of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for partial summary judgment. At this time, we are not able to predict the outcome of a decision in this matter. An adverse decision on Enron's motion for partial summary judgment 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. 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. 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. Six of our continuing power suppliers, who accounted for approximately 69% 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 six suppliers who accepted our delayed payment terms in full by October 25, 2002. Although we expect to be able to pay most of the delayed amounts owed to our other suppliers prior to the issuance of the notes, 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 $31 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. 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 4 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. 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. On October 8, 2002, we received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPPA transactions. At the present time, we disagree with EPME's calculation, and 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 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. Lehman Brothers Holdings, Inc. would be the sole initial committed purchaser of all of the variable rate revolving notes. 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 $125 million 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 plus interest thereon to the extent not paid when due. 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. For further information regarding the General and Refunding Mortgage Bond to be issued to secure certain obligations with respect to this proposed facility, see "Description of Other Indebtedness--Receivables Facility." [For reference purposes, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financial Condition, Liquidity and Capital Resources" for the information referred to in the above cross-reference to "Description of Other Indebtedness--Receivables Facility."] We are in the process of negotiating a 364-day credit facility of up to $50 million. The 364-day credit facility will be secured by $50 million aggregate principal amount of our General and Refunding Mortgage Bonds. The closing of the 364-day credit facility will be subject to the completion of the lender's due diligence, the negotiation and finalization of documentation and other customary closing conditions. Although we have commenced negotiations of the terms of the 364-day credit facility, we cannot assure you that we will enter into the credit facility or any similar arrangement. Based upon a preliminary analysis of unaudited financial information for the quarter ended September 30, 2002, we estimate that our total operating revenues for the quarter were approximately 50% of our total operating revenues for the comparable period last year, primarily as a result of decreases in the prices and sales volume of wholesale electric power sold due to changing wholesale market conditions. Since the decline in wholesale revenues is accompanied by a decline in purchased power expenses, we do not believe that our net income for the 2002 quarterly period will be significantly different than our net income for the 2001 quarterly period. ----------------- 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. 5 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 Year Ended December 31, June 30, ------------------------------------- ---------------------- 1999 2000 2001 2001 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 Operating Income............................ 116,983 73,460 144,364 25,358 (230,597) ----------- ----------- ----------- ---------- ---------- Net Income (Loss)(1)........................ $ 38,692 $ (7,928) $ 63,405 $ (22,292) $ (295,329) =========== =========== =========== ========== ========== Other Financial Data: EBITDA(2)................................... $ 217,570 $ 147,287 $ 255,240 $ 55,443 $ (339,128) Capital Expenditures........................ 220,919 196,636 196,896 88,948 116,106 Interest Expense............................ 64,913 70,390 92,677 42,759 51,875 Net Cash Flows from Operating Activities(1). 191,236 81,859 (764,074) (102,074) 49,368 Net Cash Used in Investing Activities....... (219,420) (196,636) (197,011) (88,948) (117,048) Net Cash Provided by Financing Activities... 39,715 126,540 919,060 220,222 66,983 Balance Sheet Data (end of period): Cash and Cash Equivalents................... $ 243 $ 43,858 $ 8,505 $ 80,210 $ 59,877 Utility Plant(3)............................ 2,352,641 2,462,962 2,562,351 2,502,362 2,630,280 Short-Term Borrowings....................... 182,000 100,000 130,500 100,000 200,000 Long-Term Obligations (Including Current Maturities)................................ 1,020,846 1,180,694 1,627,347 1,378,996 1,624,824 Total Debt.................................. 1,202,846 1,280,694 1,757,847 1,478,996 1,824,824 Preferred Trust Securities.................. 188,872 188,872 188,872 188,872 188,872 Accumulated other Comprehensive Income...... -- -- 520 1,061 415 Common Shareholders' Equity(4).............. 822,973 887,737 1,393,063 887,365 1,097,734 Total Capitalization(5)..................... 2,214,691 2,357,303 3,340,302 2,556,294 3,111,845 Operating Data: Number of Retail Customers: Residential.............................. 499,074 526,899 552,276 546,329 562,645 Commercial............................... 66,477 69,536 72,606 71,847 73,694 Industrial............................... 1,065 1,144 1,219 1,195 1,220 Other.................................... 56 64 68 69 67 ----------- ----------- ----------- ---------- ---------- Total Retail Customers................. 566,672 597,643 626,169 619,440 637,626 =========== =========== =========== ========== ========== Annual Load Factor.......................... 46.3% 49.3% 49.0% -- -- Peak Load (MW)(6)........................... 3,993 4,325 4,412 4,325 4,412 Total Retail Sales (MWh).................... 14,615,000 16,363,000 16,799,000 7,756,000 7,885,000 Average Retail Revenue per MWh.............. $ 62.06 $ 63.99 $ 83.06 $ 78.09 $ 86.51 Purchased Power (MWh)....................... 7,861,985 9,659,118 19,268,305 7,685,000 5,782,000 Average Cost per MWh of Purchased Power..... $ 43.12 $ 69.51 $ 157.06 $ 135.51 $ 114.49 Company Generated Power (MWh)............... 9,167,963 10,744,466 9,899,195 5,074,000 4,656,000 Average Fuel Cost per MWh of Generated Power $ 16.86 $ 27.25 $ 44.64 $ 42.89 $ 33.76
Twelve Months Ended June 30, ------------------- 2002 ------------------- Income Statement Data: Operating Revenues: Electric................................. $ 2,690,981 Operating Income............................ (111,591) ----------- Net Income (Loss)(1)........................ $ (209,632) =========== Other Financial Data: EBITDA(2)................................... $ (139,331) Capital Expenditures........................ 224,054 Interest Expense............................ 101,793 Net Cash Flows from Operating Activities(1). (612,632) Net Cash Used in Investing Activities....... (225,111) Net Cash Provided by Financing Activities... 765,821 Balance Sheet Data (end of period): Cash and Cash Equivalents................... $ 59,877 Utility Plant(3)............................ 2,630,280 Short-Term Borrowings....................... 200,000 Long-Term Obligations (Including Current Maturities)................................ 1,624,824 Total Debt.................................. 1,824,824 Preferred Trust Securities.................. 188,872 Accumulated other Comprehensive Income...... 415 Common Shareholders' Equity(4).............. 1,097,734 Total Capitalization(5)..................... 3,111,845 Operating Data: Number of Retail Customers: Residential.............................. 562,645 Commercial............................... 73,694 Industrial............................... 1,220 Other.................................... 67 ----------- Total Retail Customers................. 637,626 =========== Annual Load Factor.......................... 49.7% Peak Load (MW)(6)........................... 4,412 Total Retail Sales (MWh).................... 16,928,000 Average Retail Revenue per MWh.............. $ 86.95 Purchased Power (MWh)....................... 17,365,000 Average Cost per MWh of Purchased Power..... $ 152.43 Company Generated Power (MWh)............... 9,481,000 Average Fuel Cost per MWh of Generated Power $ 40.24
6 -------- (1)Amounts do not include equity in earnings (losses) of Sierra Pacific Resources. See note (6) 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 (6) 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 (6) 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 (6) 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. 7 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. We believe that our employee pension plan currently has assets with a fair value that is less than the present value of the accumulated benefit obligation under the plan. While the amount of the deficiency has not yet been determined, we expect our funding requirement for 2002 will be in excess of our funding requirement for 2001. The amount of our funding obligation for 2002 could be significant based upon the information currently available to us; however, we do not expect that funding the deficit for 2002 will have a material adverse effect on our liquidity. Although we are currently negotiating the terms of a receivables purchase facility and a 364-day credit facility which would provide us with up to an additional $125 million and $50 million of liquidity, respectively, we cannot assure you that we will enter into either of the facilities. If we do not enter into these facilities, 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 8 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 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, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to us. These terminating suppliers asserted their contractual right under the 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 filed a motion for partial summary judgment to require us to make immediate payment of the full amount of their claim, pending final resolution of the lawsuit. On October 11, 2002, the Bankruptcy Court heard further arguments regarding the issue of FERC's primary jurisdiction over the contract claims. The Bankruptcy Court judge is expected to render a decision on the issue of FERC's jurisdiction on or about October 24, 2002. If the judge decides not to stay Enron's lawsuit pending the outcome of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for partial summary judgment. At this time, we are not able to predict the outcome of a decision in this matter. An adverse decision on Enron's motion for partial summary judgment, 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, EPME notified us that it was terminating power deliveries to us. On October 8, 2002, we received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPPA transactions. 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 9 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 September 15, 2002. Six of our continuing power suppliers have 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 $31 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 10 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. 11 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. As of September 30, 2002, Sierra Pacific Resources had cash and cash equivalents of approximately $5.6 million. 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 12 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 13 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, production facilities, and transmission and distribution facilities) could be direct targets or indirect casualties of an act of terror. 14 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. 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 and $50 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 and our proposed 364-day facility, respectively. 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) 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. As of October 1, 2002, we had the capacity to issue approximately $871 million of additional debt under the G&R Indenture. 15 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 Holders--Change of Control." 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. 16 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. 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 17 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 (6) under "Capitalization." 18 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, 19 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 20 . 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. 21 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 ========= ========= ========= =========
22 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. 23 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. 24 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 25 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)
26 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 27 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. At September 30, 2002, we had cash and cash equivalents of approximately $207.7 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 28 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 believe that our employee pension plan currently has assets with a fair value that is less than the present value of the accumulated benefit obligation under the plan. While the amount of the deficiency has not yet been determined, we expect our funding requirement for 2002 will be in excess of our funding requirement for 2001. The amount of our funding obligation for 2002 could be significant based upon the information currently available to us; however, we do not expect that funding the deficit for 2002 will have a material adverse effect on our liquidity. 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. Lehman Brothers Holdings, Inc. would be the sole initial committed purchaser of all of the variable rate revolving notes. 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 $125 million principal amount of our General and Refunding Mortgage Bonds in connection with the receivables purchase facility. The full principal amount of the Bond would secure certain of our obligations as seller and servicer with respect to the receivables purchase facility, plus interest thereon to the extent not paid when due, regardless of the actual amounts owing with respect to our secured obligations. As a result, in the event of our bankruptcy or liquidation, the holder of the Bond securing our obligations in respect of the receivables purchase facility may recover more on a pro rata basis than the holders of notes would recover, in which case the holders of notes would recover less on a pro rata basis than they would otherwise recover. However, in no event would the holder of the Bond recover more than the amount of the secured obligations due thereunder. 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. 29 We are in the process of negotiating a 364-day credit facility of up to $50 million. The 364-day credit facility will be secured by $50 million aggregate principal amount of our General and Refunding Mortgage Bonds. The closing of the 364-day credit facility will be subject to the completion of the lender's due diligence, the negotiation and finalization of documentation and other customary closing conditions. Although we have commenced negotiations of the terms of the 364-day credit facility, we cannot assure you that we will enter into the credit 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 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. 30 In early May of 2002, Enron, MSCG, Reliant Energy Services, Inc. and several smaller suppliers terminated their power deliveries to us, exercising their contractual right under the 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 filed a motion for partial summary judgment to require us to make immediate payment of the full amount of their claim, pending final resolution of the lawsuit. On October 11, 2002, the Bankruptcy Court heard further arguments regarding the issue of FERC's primary jurisdiction over the contract claims. The Bankruptcy Court judge is expected to render a decision on the issue of FERC's jurisdiction on or about October 24, 2002. If the judge decides not to stay Enron's lawsuit pending the outcome of the FERC hearings, the judge would then schedule additional arguments with respect to Enron's motion for partial summary judgment. At this time, we are not able to predict the outcome of a decision in this matter. An adverse decision on Enron's motion for partial summary judgment 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. 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. 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. Six of our continuing power suppliers, who accounted for approximately 69% 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 six suppliers who accepted our delayed payment terms in full by October 25, 2002. Although we expect to be able to pay most of the delayed amounts owed to our other suppliers prior to the issuance of the notes, 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 $31 million is owed to the continuing suppliers that have not signed delayed payment agreements with us. On September 30, 2002, EPME notified us that it was terminating all transactions entered into with us under the WSPPA. On October 8, 2002, we received a letter from EPME seeking a termination payment of approximately $36 million with respect to the terminated WSPPA transactions. At the present time, we disagree with EPME's calculation, and 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 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 31 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
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. 32 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 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 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 33 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 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, 34 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. 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 35 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 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 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. 36 Additional Finance Authority The PUCN has issued an order 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 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. Hearings before the ALJ were conducted in October 2002 and a decision from the ALJ is expected 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. 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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