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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
/x/ | Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
or
/ / | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For Quarter Ended June 30, 2001
Commission File Number 1-3034
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota (State of other jurisdiction of incorporation or organization) | 41-0448030 (I.R.S. Employer Identification No.) | |
800 Nicollet Mall, Minneapolis, Minn. (Address of principal executive offices) | 55402 (Zip Code) |
Registrant's telephone number, including area code(612) 330-5500
Former name, former address and former fiscal year, if changed since last report
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /x/ No / /
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Class | Outstanding, at July 31, 2001 | |
---|---|---|
Common Stock, $2.50 par value | 344,697,884 shares |
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars, Except Per Share Data)
| Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2001 | 2000 | 2001 | 2000 | |||||||||||
Operating revenues: | |||||||||||||||
Electric utility | $ | 1,643,877 | $ | 1,282,780 | $ | 3,191,389 | $ | 2,496,016 | |||||||
Gas utility | 400,405 | 233,249 | 1,360,570 | 723,901 | |||||||||||
Electric and gas trading | 869,425 | 367,157 | 1,836,316 | 595,457 | |||||||||||
Nonregulated and other | 723,048 | 533,030 | 1,455,586 | 902,634 | |||||||||||
Equity earnings from investments in affiliates | 61,802 | 57,439 | 85,264 | 70,089 | |||||||||||
Total operating revenues | 3,698,557 | 2,473,655 | 7,929,125 | 4,788,097 | |||||||||||
Operating expenses: | |||||||||||||||
Electric fuel and purchased power—utility | 827,430 | 518,036 | 1,607,095 | 1,013,569 | |||||||||||
Cost of gas sold and transported—utility | 292,102 | 141,793 | 1,064,154 | 458,791 | |||||||||||
Electric and gas trading costs | 836,960 | 354,621 | 1,754,324 | 577,768 | |||||||||||
Cost of sales—nonregulated and other | 419,588 | 258,596 | 823,775 | 406,621 | |||||||||||
Other operating and maintenance expenses—utility | 362,159 | 348,691 | 728,951 | 688,662 | |||||||||||
Other operating and maintenance expenses—nonregulated | 191,572 | 137,415 | 380,767 | 285,230 | |||||||||||
Depreciation and amortization | 221,075 | 197,321 | 434,385 | 385,158 | |||||||||||
Taxes (other than income taxes) | 87,753 | 89,280 | 182,501 | 181,445 | |||||||||||
Special charges (see Note 2) | 23,018 | 0 | 23,018 | 937 | |||||||||||
Total operating expenses | 3,261,657 | 2,045,753 | 6,998,970 | 3,998,181 | |||||||||||
Operating income | 436,900 | 427,902 | 930,155 | 789,916 | |||||||||||
Other income (expense): | |||||||||||||||
Minority interest | (9,909 | ) | (7,929 | ) | (18,561 | ) | (9,727 | ) | |||||||
Other income—net | 7,230 | (1,888 | ) | 23,767 | 5,498 | ||||||||||
Total other income (expense) | (2,679 | ) | (9,817 | ) | 5,206 | (4,229 | ) | ||||||||
Interest charges and financing costs: | |||||||||||||||
Interest charges—net of amounts capitalized | 186,467 | 171,405 | 362,316 | 311,236 | |||||||||||
Distributions on redeemable preferred securities of subsidiary trusts | 9,700 | 9,700 | 19,400 | 19,400 | |||||||||||
Total interest charges and financing costs | 196,167 | 181,105 | 381,716 | 330,636 | |||||||||||
Income before income taxes and extraordinary items | 238,054 | 236,980 | 553,645 | 455,051 | |||||||||||
Income taxes | 70,197 | 80,240 | 176,478 | 144,979 | |||||||||||
Income before extraordinary items | 167,857 | 156,740 | 377,167 | 310,072 | |||||||||||
Extraordinary items (see Note 4) | 0 | (13,658 | ) | 0 | (13,658 | ) | |||||||||
Net income | 167,857 | 143,082 | 377,167 | 296,414 | |||||||||||
Dividend requirements and redemption premiums on preferred stock | 1,060 | 1,060 | 2,120 | 2,121 | |||||||||||
Earnings available for common shareholders | $ | 166,797 | $ | 142,022 | $ | 375,047 | $ | 294,293 | |||||||
Weighted average common shares outstanding: | |||||||||||||||
Basic | 342,553 | 337,466 | 341,670 | 336,663 | |||||||||||
Diluted | 343,688 | 337,634 | 342,591 | 336,769 | |||||||||||
Earnings per share—basic and diluted before extraordinary items | $ | 0.49 | $ | 0.46 | $ | 1.10 | $ | 0.91 | |||||||
Extraordinary items (see Note 4) | $ | 0.00 | $ | (0.04 | ) | $ | 0.00 | $ | (0.04 | ) | |||||
Earnings per share—basic and diluted | $ | 0.49 | $ | 0.42 | $ | 1.10 | $ | 0.87 | |||||||
See Notes to Consolidated Financial Statements
2
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)
| Six Months Ended June 30 | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2001 | 2000 | ||||||||
Operating activities: | ||||||||||
Net income | $ | 377,167 | $ | 296,414 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
Depreciation and amortization | 461,508 | 407,409 | ||||||||
Nuclear fuel amortization | 21,059 | 20,675 | ||||||||
Deferred income taxes | 800 | 33,045 | ||||||||
Amortization of investment tax credits | (6,482 | ) | (7,013 | ) | ||||||
Allowance for equity funds used during construction | (5,769 | ) | (743 | ) | ||||||
Undistributed equity in earnings of unconsolidated affiliates | (73,319 | ) | (61,384 | ) | ||||||
Conservation incentive accrual adjustment | (32,218 | ) | 0 | |||||||
Special charges | 23,018 | 0 | ||||||||
Unrealized loss on energy contracts | 2,432 | 0 | ||||||||
Extraordinary Item | 0 | 13,658 | ||||||||
Change in accounts receivable | 54,411 | (66,468 | ) | |||||||
Change in inventories | (67,511 | ) | 20,855 | |||||||
Change in other current assets | 256,128 | (18,454 | ) | |||||||
Change in accounts payable | (567,981 | ) | 9,816 | |||||||
Change in other current liabilities | 47,344 | 19,528 | ||||||||
Change in other assets and liabilities | 38,870 | 3,023 | ||||||||
Net cash provided by operating activities | 529,457 | 670,361 | ||||||||
Investing activities: | ||||||||||
Nonregulated capital expenditures and asset acquisitions | (2,831,627 | ) | (1,791,212 | ) | ||||||
Utility capital/construction expenditures | (452,775 | ) | (442,956 | ) | ||||||
Allowance for equity funds used during construction | 5,769 | 743 | ||||||||
Investments in external decommissioning fund | (28,446 | ) | (26,443 | ) | ||||||
Equity investments, loans, deposits and sales of nonregulated projects | 294,069 | (69,689 | ) | |||||||
Other investments—net | 3,844 | (53,519 | ) | |||||||
Net cash used in investing activities | (3,009,166 | ) | (2,383,076 | ) | ||||||
Financing activities: | ||||||||||
Short-term borrowings—net | 786,576 | 85,300 | ||||||||
Proceeds from issuance of long-term debt | 1,888,167 | 2,404,630 | ||||||||
Repayment of long-term debt, including reacquisition premiums | (361,042 | ) | (1,014,739 | ) | ||||||
Proceeds from issuance of common stock | 83,638 | 51,376 | ||||||||
Proceeds from the NRG Stock Offering | 474,348 | 453,705 | ||||||||
Dividends paid | (258,389 | ) | (250,709 | ) | ||||||
Net cash provided by financing activities | 2,613,298 | 1,729,563 | ||||||||
Effect of exchange rate changes on cash and cash equivalents | (3,457 | ) | 0 | |||||||
Net increase in cash and cash equivalents | 130,132 | 16,848 | ||||||||
Cash and cash equivalents at beginning of period | 216,491 | 139,731 | ||||||||
Cash and cash equivalents at end of period | $ | 346,623 | $ | 156,579 | ||||||
See Notes to Consolidated Financial Statements
3
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)
| June 30 2001 | Dec. 31 2000 | |||||||
---|---|---|---|---|---|---|---|---|---|
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 346,623 | $ | 216,491 | |||||
Accounts receivable—net of allowance for bad debts of $63,102 and $41,350, respectively | 1,298,875 | 1,289,724 | |||||||
Accrued unbilled revenues | 516,235 | 683,266 | |||||||
Materials and supplies inventories—at average cost | 326,199 | 286,453 | |||||||
Fuel inventory—at average cost | 230,728 | 148,305 | |||||||
Gas inventories—replacement cost in excess of LIFO: $59,112 and $106,790, respectively | 29,674 | 46,075 | |||||||
Recoverable purchased gas and electric energy costs | 181,260 | 283,167 | |||||||
Derivative instruments valuation—at market | 156,534 | 0 | |||||||
Prepayments and other | 338,103 | 174,593 | |||||||
Total current assets | 3,424,231 | 3,128,074 | |||||||
Property, plant and equipment, at cost: | |||||||||
Electric utility plant | 15,495,200 | 15,304,407 | |||||||
Gas utility plant | 2,407,941 | 2,376,868 | |||||||
Nonregulated property and other | 9,237,081 | 5,641,968 | |||||||
Construction work in progress | 772,510 | 622,494 | |||||||
Total property, plant and equipment | 27,912,732 | 23,945,737 | |||||||
Less: accumulated depreciation | (9,127,465 | ) | (8,759,322 | ) | |||||
Nuclear fuel—net of accumulated amortization of $988,987 and $967,927, respectively | 80,160 | 86,499 | |||||||
Net property, plant and equipment | 18,865,427 | 15,272,914 | |||||||
Other assets: | |||||||||
Investments in unconsolidated affiliates | 1,193,589 | 1,459,410 | |||||||
Nuclear decommissioning fund and other investments | 752,734 | 732,908 | |||||||
Regulatory assets | 467,777 | 524,261 | |||||||
Derivative instruments valuation—at market | 191,851 | 0 | |||||||
Other | 1,489,711 | 651,276 | |||||||
Total other assets | 4,095,662 | 3,367,855 | |||||||
Total Assets | $ | 26,385,320 | $ | 21,768,843 | |||||
LIABILITIES AND EQUITY | |||||||||
Current liabilities: | |||||||||
Current portion of long-term debt | $ | 710,766 | $ | 603,611 | |||||
Short-term debt | 2,269,184 | 1,475,072 | |||||||
Accounts payable | 1,257,774 | 1,608,989 | |||||||
Taxes accrued | 234,941 | 236,837 | |||||||
Dividends payable | 130,211 | 128,983 | |||||||
Derivative instruments valuation—at market | 170,425 | 0 | |||||||
Other | 656,286 | 618,316 | |||||||
Total current liabilities | 5,429,587 | 4,671,808 | |||||||
Deferred credits and other liabilities: | |||||||||
Deferred income taxes | 2,120,034 | 1,794,193 | |||||||
Deferred investment tax credits | 191,260 | 198,108 | |||||||
Regulatory liabilities | 480,776 | 494,566 | |||||||
Derivative instruments valuation—at market | 54,124 | 0 | |||||||
Benefit obligations and other | 826,696 | 588,288 | |||||||
Total deferred credits and other liabilities | 3,672,890 | 3,075,155 | |||||||
Minority interest in subsidiaries | 573,690 | 277,335 | |||||||
Capitalization: | |||||||||
Long-term debt | 10,085,968 | 7,583,441 | |||||||
Mandatorily redeemable preferred securities of subsidiary trusts | 494,000 | 494,000 | |||||||
Preferred stockholders' equity—authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800 | 105,320 | 105,320 | |||||||
Common stockholders' equity—authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 2001, 344,098,595; 2000, 340,834,147 | 6,023,865 | 5,561,784 | |||||||
Commitments and Contingent Liabilities (see Note 5) | |||||||||
Total Liabilities and Equity | $ | 26,385,320 | $ | 21,768,843 | |||||
See Notes to Consolidated Financial Statements
4
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED)
Three Months Ended June 30, 2001 and 2000
(Thousands of Dollars)
| Par Value | Premium | Retained Earnings | Shares Held by ESOP | Accumulated Other Comprehensive Income | Total Stockholders' Equity | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at March 31, 2000 | $ | 842,828 | $ | 2,319,229 | $ | 2,281,731 | $ | (9,874 | ) | $ | (112,233 | ) | $ | 5,321,681 | ||||||
Net income | 143,082 | 143,082 | ||||||||||||||||||
Currency translation adjustments | (28,448 | ) | (28,448 | ) | ||||||||||||||||
Comprehensive income for the period | 114,634 | |||||||||||||||||||
Dividends declared: | ||||||||||||||||||||
Cumulative preferred stock of Xcel Energy | (1,060 | ) | (1,060 | ) | ||||||||||||||||
Common stock | (125,416 | ) | (125,416 | ) | ||||||||||||||||
Issuances of common stock—net | 2,814 | 20,221 | 23,035 | |||||||||||||||||
Tax benefit from stock options exercised | 15 | 15 | ||||||||||||||||||
Gain recognized from NRG stock offering | 215,933 | 215,933 | ||||||||||||||||||
Repayment of ESOP loan(a) | 1,625 | 1,625 | ||||||||||||||||||
Balance at June 30, 2000 | $ | 845,642 | $ | 2,555,398 | $ | 2,298,337 | $ | (8,249 | ) | $ | (140,681 | ) | $ | 5,550,447 | ||||||
Balance at March 31, 2001 | $ | 856,055 | $ | 2,885,312 | $ | 2,363,972 | $ | (22,921 | ) | $ | (224,711 | ) | $ | 5,857,707 | ||||||
Net income | 167,857 | 167,857 | ||||||||||||||||||
Currency translation adjustments | 41,171 | 41,171 | ||||||||||||||||||
Net gains or (losses) on derivatives (see Note 8) | 42,540 | 42,540 | ||||||||||||||||||
Comprehensive income for the period | 251,568 | |||||||||||||||||||
Dividends declared: | ||||||||||||||||||||
Cumulative preferred stock of Xcel Energy | (1,060 | ) | (1,060 | ) | ||||||||||||||||
Common stock | (129,041 | ) | (129,041 | ) | ||||||||||||||||
Issuances of common stock—net | 4,156 | 39,117 | 43,273 | |||||||||||||||||
Other | (1 | ) | (1 | ) | ||||||||||||||||
Repayment of ESOP loan(a) | 1,419 | 1,419 | ||||||||||||||||||
Balance at June 30, 2001 | $ | 860,211 | $ | 2,924,429 | $ | 2,401,727 | $ | (21,502 | ) | $ | (141,000 | ) | $ | 6,023,865 | ||||||
- (a)
- Did not affect cash flows
See Notes to Consolidated Financial Statements
5
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED)
Six Months Ended June 30, 2001 and 2000
(Thousands of Dollars)
| Par Value | Premium | Retained Earnings | Shares Held by ESOP | Accumulated Other Comprehensive Income | Total Stockholders' Equity | ||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at Dec. 31, 1999 | $ | 838,193 | $ | 2,288,254 | $ | 2,253,800 | $ | (11,606 | ) | $ | (78,421 | ) | $ | 5,290,220 | ||||||
Net income | 296,414 | 296,414 | ||||||||||||||||||
Currency translation adjustments | (62,260 | ) | (62,260 | ) | ||||||||||||||||
Comprehensive income for the period | 234,154 | |||||||||||||||||||
Dividends declared: | ||||||||||||||||||||
Cumulative preferred stock of Xcel Energy | (2,121 | ) | (2,121 | ) | ||||||||||||||||
Common stock | (249,756 | ) | (249,756 | ) | ||||||||||||||||
Issuances of common stock—net | 7,449 | 51,164 | 58,613 | |||||||||||||||||
Tax benefit from stock options exercised | 47 | 47 | ||||||||||||||||||
Gain recognized from NRG stock offering | 215,933 | 215,933 | ||||||||||||||||||
Repayment of ESOP loan(a) | 3,357 | 3,357 | ||||||||||||||||||
Balance at June 30, 2000 | $ | 845,642 | $ | 2,555,398 | $ | 2,298,337 | $ | (8,249 | ) | $ | (140,681 | ) | $ | 5,550,447 | ||||||
Balance at Dec. 31, 2000 | $ | 852,085 | $ | 2,607,025 | $ | 2,284,220 | $ | (24,617 | ) | $ | (156,929 | ) | $ | 5,561,784 | ||||||
Net income | 377,167 | 377,167 | ||||||||||||||||||
Currency translation adjustments | (21,462 | ) | (21,462 | ) | ||||||||||||||||
Cumulative effect of accounting change—SFAS 133 | (28,780 | ) | (28,780 | ) | ||||||||||||||||
Net gains or (losses) on derivatives (see Note 8) | 66,171 | 66,171 | ||||||||||||||||||
Comprehensive income for the period | 393,096 | |||||||||||||||||||
Dividends declared: | ||||||||||||||||||||
Cumulative preferred stock of Xcel Energy | (2,120 | ) | (2,120 | ) | ||||||||||||||||
Common stock | (257,497 | ) | (257,497 | ) | ||||||||||||||||
Issuances of common stock—net | 8,126 | 75,513 | 83,639 | |||||||||||||||||
Other | (43 | ) | (43 | ) | ||||||||||||||||
Gain recognized from NRG stock offering | 241,891 | 241,891 | ||||||||||||||||||
Repayment of ESOP loan(a) | 3,115 | 3,115 | ||||||||||||||||||
Balance at June 30, 2001 | $ | 860,211 | $ | 2,924,429 | $ | 2,401,727 | $ | (21,502 | ) | $ | (141,000 | ) | $ | 6,023,865 | ||||||
- (a)
- Did not affect cash flows
See Notes to Consolidated Financial Statements
6
XCEL ENERGY INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of June 30, 2001, and Dec. 31, 2000, the results of its operations and stockholders' equity for the three and six months ended June 30, 2001 and 2000, and its cash flows for the six months ended June 30, 2001 and 2000. Due to the seasonality of Xcel Energy's electric and gas sales and variability of nonregulated operations, quarterly and year-to-date results are not necessarily an appropriate base from which to project annual results.
The accounting policies followed by Xcel Energy are set forth in Note 1 to the consolidated financial statements in Xcel Energy's Annual Report on Form 10-K for the year ended Dec. 31, 2000. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K.
1. Merger to Create Xcel Energy
On Aug. 18, 2000, New Century Energies, Inc. (NCE) and Northern States Power Co. (NSP) merged and formed Xcel Energy Inc. Xcel Energy, a Minnesota corporation, is a registered holding company under the Public Utility Holding Company Act (PUHCA). Each share of NCE common stock was exchanged for 1.55 shares of Xcel Energy common stock. NSP shares became Xcel Energy shares on a one-for-one basis. The merger was structured as a tax-free, stock-for-stock exchange for shareholders of both companies (except for fractional shares), and accounted for as a pooling-of-interests. As part of the merger, NSP transferred its existing utility operations that were being conducted directly by NSP at the parent company level to a newly formed subsidiary of Xcel Energy named Northern States Power Company. Amounts reported for periods prior to the merger have been restated for comparability with post-merger results.
Xcel Energy directly owns six utility subsidiaries that serve electric and natural gas customers in 12 states. These six utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota), Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin), Public Service Co. of Colorado (PSCo), Southwestern Public Service Co. (SPS), Black Mountain Gas Co. (BMG) and Cheyenne Light, Fuel and Power Co. (Cheyenne). Their service territories include portions of Arizona, Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wisconsin and Wyoming. Xcel Energy's regulated businesses also include Viking Gas Transmission Co. and WestGas InterState Inc. (WGI), both interstate natural gas pipeline companies.
Xcel Energy also owns or has an interest in a number of nonregulated businesses, the largest of which is NRG Energy, Inc., a publicly traded independent power producer. At June 30, 2001, Xcel Energy indirectly owned approximately 74 percent of NRG. Xcel Energy owned 100 percent of NRG until the second quarter of 2000, when NRG completed its initial public offering and 82 percent until a secondary offering was completed in March 2001.
In addition to NRG, Xcel Energy's nonregulated subsidiaries include Utility Engineering (engineering, construction and design), Seren Innovations, Inc. (broadband telecommunications services), e prime inc. (natural gas marketing and trading), Planergy International, Inc. (energy management, consulting and demand-side management services), Eloigne Company (investments of rental housing projects that qualify for low-income housing tax credits) and Independent Power Corporation/Independent Power International (IPC/IPI, an international independent power producer).
Consistent with pooling accounting requirements, during 2000, Xcel Energy expensed all merger-related costs as discussed in Note 2. An allocation of merger costs was made to utility operating companies using a basis consistent with prior regulatory filings, in proportion to expected merger
7
savings by company and consistent with service company cost allocation methodologies utilized under Public Utility Holding Company Act requirements.
2. Special Charges
Merger Related—In 2000, Xcel Energy expensed pretax special charges totaling $241 million. These special charges reduced Xcel Energy's 2000 earnings by 52 cents per share. Of these special charges $201 million, or 43 cents per share, was expensed during the third quarter of 2000, and $40 million, or 9 cents per share, was expensed during the fourth quarter of 2000.
The pretax charges included $52 million of one-time transaction-related costs incurred in connection with the merger of NSP and NCE, $147 million of pretax charges pertaining to incremental costs of transition and integration activities associated with merging NSP and NCE to begin operations as Xcel Energy, and $42 million of asset impairments and other costs resulting from the post-merger strategic alignment of Xcel Energy's nonregulated businesses.
The transition costs included costs for severance and related expenses associated with staff reductions of 721 employees, approximately 680 of whom were released through July 31, 2001.
A portion of these special charges was accrued as a liability at Dec. 31, 2000. The following table summarizes the change in the liability for special charges during the first six months of 2001.
| Dec. 31, 2000 Liability* | Accrual Adjustments Expensed | Payments Against Liability | June 30, 2001 Liability* | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Millions of dollars) | |||||||||||
Employee separation and other related costs | $ | 48 | — | $ | (18 | ) | $ | 30 | ||||
Regulatory transition costs | 5 | — | — | 5 | ||||||||
Other transition and integration costs | 2 | — | (2 | ) | — | |||||||
Total accrued merger costs | $ | 55 | — | $ | (20 | ) | $ | 35 | ||||
- *
- Reported on the balance sheet in other current liabilities.
Postemployment Benefits—PSCo adopted accrual accounting for postemployment benefits under Statement of Financial Accounting Standards (SFAS) No. 112—"Employers Accounting for Postemployment Benefits" in 1994. The costs of these benefits were historically recorded on a pay-as-you-go basis and, accordingly, PSCo recorded a regulatory asset in anticipation of obtaining future rate recovery of these transition costs. PSCo recovered its FERC jurisdictional portion of these costs. PSCo requested approval to recover its Colorado retail natural gas jurisdictional portion in a 1996 retail rate case and its retail electric jurisdictional portion in the electric earnings test filing for 1997.
In the 1996 rate case, the Colorado Public Utility Commission (CPUC) allowed recovery of postemployment benefit costs on an accrual basis, but denied PSCo's request to amortize the transition costs regulatory asset. PSCo appealed this decision to the Denver District Court. In 1998, the CPUC deferred the final determination of the regulatory treatment of the electric jurisdictional costs pending
8
the outcome of PSCo's appeal on the natural gas rate case. On Dec. 16, 1999, the Denver District Court affirmed the decision by the CPUC.
On Jan. 31, 2000, PSCo filed a Notice of Appeal with the Colorado Supreme Court and in February 2001 presented oral arguments. On July 2, 2001, the Colorado Supreme Court affirmed the District Court decision. Accordingly, PSCo has written off $23 million, or by 4 cents per share, of regulatory assets related to deferred postemployment benefit costs as of June 30, 2001, since any means of regulatory recovery has been denied.
3. Business Developments
Completed NRG Asset Acquisitions
Audrain—In June 2001, NRG purchased an approximately 640 megawatt natural gas-fired power plant in Audrain County, Missouri from Duke Energy North America LLC. Operation of the Audrain facility has been suspended due to problems with the plant's transformers. The transformers are currently under repair and NRG expects that commercial operation of the plant will resume in the third quarter of 2001.
Brazos Valley—In June 2001, NRG closed on the construction financing for a 633-megawatt gas-fired power plant in Texas that NRG will build, operate and manage. At the time of the closing, NRG also became the 100 percent owner of the project by purchasing STEAG Power LLC's 50 percent interest in the project. NRG estimates that its investment in the project will total approximately $170 million. NRG expects the project to begin commercial operation in February 2003.
Conectiv—In June 2001, NRG purchased 1,081 megawatts of interests in power generation plants from a subsidiary of Conectiv for approximately $644 million. NRG acquired a 100 percent interest in the 784-megawatt coal-fired Indian River Generating Station located in Delaware and in the 170-megawatt oil-fired Vienna Generating Station located in Maryland. In addition, NRG acquired 64 megawatts of the 1,711-megawatt coal-fired Conemaugh Generating Station and 63 megawatts of the 1,711-megawatt coal-fired Keystone Generating Station, both located near Pittsburgh, Pennsylvania.
Vattenfall—In June 2001, NRG acquired Vattenfall's interests in three South American projects. Those projects consist of Compania Boliviana de Energia Electrica S.A.—Bolivian Power Company Ltd. (COBEE) and Compania Electrica Central Bulo Bulo S.A., both in Bolivia, and Itiquira Energetica S.A. in Brazil. In addition, NRG acquired the ownership interest of Inepar Energia S.A. (Inepar) in the Itiquira project. NRG now owns 98.9 percent of COBEE, 60 percent of Bulo Bulo and 99 percent of the common shares of Itiquira. COBEE, with 220 megawatts of predominantly hydroelectric generation, is the second largest electric generator in Bolivia. Bulo Bulo is an 88-megawatt, natural gas-fired facility in Bolivia. Itiquira is a 156-megawatt hydroelectric project in the advanced stage of construction in Brazil. Full commercial operation of Itiquira is expected in March 2002.
PowerGen—In June 2001, NRG purchased a 389-megawatt gas-fired power plant and a 116-megawatt thermal power plant, both of which are located in Hungary, from PowerGen. In April 2001, NRG also purchased PowerGen's interest in Saale Energie GmbH and MIBRAG BV. By acquiring PowerGen's interest in Saale Energie, NRG increased its ownership interest in the 960-megawatt coal-fired Schkopau power station located in Germany from 200 megawatts to 400 megawatts. By acquiring PowerGen's interest in MIBRAG, consisting primarily of two lignite mines and
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three power stations in Germany, NRG increased its ownership of MIBRAG from 33.3 percent to 50 percent. NRG paid approximately $190 million to PowerGen for all of these interests.
Hsin Yu—In July 2001, NRG acquired approximately sixty percent of Hsin Yu Energy Development Co. Ltd, a Taiwan company that owns and develops power generation facilities. Hsin Yu currently owns a 170-megawatt cogeneration facility, Hsinchu Phase I. Hsin Yu is developing a 245-megawatt expansion of the Hsinchu facility and a new 490-megawatt greenfield project.
Pending NRG Asset Acquisitions
Conectiv—In June 2001, NRG extended purchase agreements that it had entered into with a subsidiary of Conectiv to acquire 794 megawatts of coal and oil-fired electric generating capacity and other assets in New Jersey and Pennsylvania, including an additional 66 megawatts of the Conemaugh Generating Station and an additional 42 megawatts of the Keystone Generating Station. NRG will pay approximately $180 million for these assets. NRG expects the acquisition to close in the third quarter of 2001 following approval of the New Jersey Board of Public Utilities.
Indeck—In May 2001, NRG signed a purchase agreement to acquire an approximately 2,255-megawatt portfolio of operating projects and projects in advanced development that are located in Illinois and upstate New York from Indeck Energy Services, Inc. Approximately 402 megawatts are currently in operation and NRG expects that an additional $1.3 billion will be required to complete construction of the projects. NRG expects the acquisition to close in the third quarter of 2001.
Narva Power—In August 2000, NRG signed an agreement with Eesti Energia, the Estonian state-owned electric utility, to purchase for approximately $65.5 million a 49 percent stake in Narva Power, the owner and operator of the oil shale-fired Eesti and Balti power plants, located near Narva, Estonia. The plants have a combined capacity of approximately 2,700 megawatts. NRG is working to close the acquisition in the second half of 2001.
Bridgeport Harbor and New Haven Harbor—In December 2000, NRG signed asset purchase agreements to acquire the 585-megawatt coal-fired Bridgeport Harbor Station and the 466-megawatt oil and gas-fired New Haven Harbor Station in Connecticut for approximately $325 million. In July 2001, the Federal Energy Regulatory Commission (FERC) instructed its staff to convene a technical conference to "further explore issues related to the competitive effects" resulting from NRG's proposed acquisition of the Bridgeport and New Haven Harbor Stations in Connecticut. The order directs FERC staff to report back to the Commission within 90 days after exploring "issues regarding market power concerns." This action will result in the acquisition being delayed beyond its previously expected close in the third quarter of 2001.
Meriden—In December 2000, NRG signed a purchase agreement to acquire a 540-megawatt natural gas-fired generation facility being developed in Connecticut, for a purchase price of approximately $25 million. NRG expects to close the acquisition in the third quarter of 2001. NRG estimates it will cost approximately $384 million to complete construction of the plant, which has a planned commercial operation date of June 2003.
McClain—In May 2001, NRG signed a purchase agreement to acquire Duke Energy's 77 percent interest in the McClain Energy Generating Facility located in Oklahoma for approximately $283 million. The Oklahoma Municipal Power Authority owns the remaining 23 percent interest. The
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500-megawatt natural gas fired McClain facility is in the final stage of construction and is expected to begin commercial operation during the third quarter of 2001. NRG expects to close the acquisition in the third quarter of 2001.
Other Developments
Yorkshire Power—During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power to Innogy Holdings plc. As a result of this sales agreement, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001. In April 2001, Xcel Energy closed the sale of Yorkshire Power. Xcel Energy retains an interest of approximately 5 percent in Yorkshire Power to comply with pooling-of-interests accounting requirements associated with the merger of NSP and NCE in 2000. Xcel Energy received approximately $366 million for the sale, which approximated the book value of Xcel Energy's investment. Xcel Energy used the proceeds of the sale to pay down short-term debt and eliminate the need for an equity issuance planned for the second half of 2001.
Fort St. Vrain Repowering—In June 2001, PSCo completed the six-year, $283 million repowering of the Fort St. Vrain Generating Station in Colorado. The phased repowering has added 720 megawatts of electric supply to PSCo's system. Fort St. Vrain utilizes three combined-cycle turbine generators of approximately 140-megawatts, powered by natural gas. After producing electricity in the newer turbine generators, waste heat is captured for steam production for the plant's original 300-megawatt generator. Fort St. Vrain, formerly a nuclear power plant, was dismantled and decommissioned as a nuclear facility in August 1996.
Wind Power—In April 2001, NSP-Minnesota selected a developer to add more wind-generated electricity to its portfolio. Chanarambie Power Partners, LLC, will build wind turbines in southwestern Minnesota to add another 80 megawatts of wind power. Execution of this contract will mean that NSP-Minnesota has fulfilled a 1994 Minnesota legislative requirement to develop 425 megawatts of Minnesota wind energy relating to the authorization to store spent nuclear fuel in dry casks outside the Prairie Island nuclear plant. Xcel Energy is also developing additional wind power projects in Texas, Wyoming, Colorado and New Mexico.
Independent Transmission Company (ITC)—Xcel Energy is working with several other utility partners in regards to compliance with FERC Order 2000 and may jointly file an ITC proposal with FERC in August of 2001. The purpose of the ITC would be to enhance transmission access in the region, strengthen reliability and comply with recent FERC objectives.
Brunetti Elected Chairman—On June 27, 2001, the Xcel Energy Board of Directors elected Wayne H. Brunetti as chairman, president and chief executive officer effective Aug. 18, 2001. Brunetti has been serving as president and chief executive officer since the merger of NSP and NCE, which created Xcel Energy. The board also voted unanimously to designate James J. Howard as chairman emeritus effective upon his retirement as chairman of the board on Aug. 18, 2001. Howard's retirement date was specified in the merger agreement between the two companies.
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4. Restructuring and Regulation
NSP-Wisconsin Electric Power Supply Rate Request—In May 2001, NSP-Wisconsin filed an application with the Public Service Commission of Wisconsin (PSCW) requesting an increase in Wisconsin retail electric rates due to significant increases in power supply costs. This increase is necessary to recover fuel and purchased power costs from wholesale suppliers at market based prices. On June 28, 2001, the PSCW approved an interim fuel cost surcharge, which will increase NSP-Wisconsin's electric revenue by approximately $5.6 million for the last six months of 2001. A hearing will be held on Aug. 16, 2001 to establish a final fuel cost surcharge. An order authorizing the final surcharge is expected in September 2001.
NSP-Wisconsin General Rate Case—On June 1, 2001 NSP-Wisconsin filed its required biennial rate application with the PSCW requesting no change in Wisconsin retail electric and gas base rates. NSP-Wisconsin requested the PSCW approve its application without hearing, pending completion of the Staff's audit. An order is expected by the end of the year.
SPS Restructuring—In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business due to the issuance of a written order by the Public Utilities Commission of Texas (PUCT) in May 2000, addressing the implementation of electric utility restructuring. SPS' transmission and distribution business continued to meet the requirements of SFAS 71, as that business was expected to remain regulated. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. During the third quarter of 2000, SPS recorded an extraordinary charge of $8.2 million before tax, or $5.3 million after tax, related to the tender offer and defeasance of first mortgage bonds. The first mortgage bonds were defeased to facilitate the legal separation of generation, transmission and distribution assets, which was expected to eventually occur in 2001 under restructuring requirements.
In March 2001, the state of New Mexico enacted legislation that delayed customer choice until 2007 and amended the Electric Utility Restructuring Act of 1999. SPS has requested recovery of its costs incurred to prepare for customer choice in New Mexico. A decision on this and other matters is pending before the New Mexico Public Regulation Commission (NMPRC). SPS expects to receive regulatory recovery of these costs through a rate rider in the next New Mexico rate case filed.
In June 2001, the Governor of Texas signed legislation postponing the deregulation and restructuring of SPS until 2007. This legislation amended the 1999 legislation, Senate Bill No. 7 (SB-7), which provided for retail electric competition beginning January 2002. Under the newly-adopted legislation, prior PUCT orders issued in connection with the restructuring of SPS will be considered null and void. SPS' restructuring and rate unbundling proceedings in Texas have been terminated. In addition, under the new legislation, SPS is entitled to recover all reasonable and necessary expenditures made or incurred before Sept. 1, 2001, to comply with SB-7. As required, SPS plans to file an application during the fourth quarter of 2001, requesting a rate rider to recover these costs incurred preparing for customer choice.
As a result of these recent legislative developments, SPS reapplied the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" for its generation business during the second quarter of 2001. More than 95 percent of SPS' retail electric revenues are from operations in Texas and New Mexico. Because of the delays to electric restructuring passed by Texas and New Mexico, SPS' previous plans to implement restructuring, including the divestiture of generation assets,
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have been abandoned. Accordingly, SPS will now continue to be subject to rate regulation under traditional cost of service regulation, consistent with its past accounting and ratemaking practices. At this time, management is uncertain as to whether restructuring will be completed in 2007 or later and as to what the transition plan to competition will be at that time. SPS has not restored regulatory assets or capitalized defeasance costs previously written off in 2000. Due to the regulatory uncertainty regarding the recovery of these costs in future rates, SPS has delayed the restoration of regulatory assets until it is determined that specific regulatory recovery is achieved. Consequently, SPS has not recognized any earnings impact for financial reporting purposes as a result of its reapplication of SFAS 71 through June 30, 2001. However, future regulatory developments may create earnings increases (should additional cost recovery be provided) or decreases (should deferred costs not be fully recovered).
As of June 30, 2001, SPS had incurred approximately $45 million of restructuring costs, including $8 million of debt defeasance costs allocated to the generation business, which was expensed as an extraordinary item in the third quarter of 2000 and $37 million of restructuring costs, which have been deferred based on anticipated future recovery in jurisdictional rates.
SPS Texas Retail Fuel Factor and Fuel Surcharge Application—SPS has filed an application with the PUCT to increase its fixed fuel factor and to surcharge past fuel cost under-recoveries. Intervenors in the proceeding are protesting SPS' application and are claiming SPS should be crediting margins from wholesale firm sales to Texas retail eligible fuel expenses. Hearings were held in May 2001 and a final decision is pending before the PUCT. SPS and the PUCT Staff oppose the revenue treatment suggested by the intervenors. The final outcome or impact of the wholesale firm sales on Xcel Energy's earnings will not be known until later in 2001.
Cheyenne Purchased Power Costs—For the past 37 years, Cheyenne has purchased all electric supply requirements from PacifiCorp. Cheyenne's most recent full-requirements power purchase agreement with PacifiCorp expired on Feb. 24, 2001. During 2000, as contract details for a new agreement were being finalized between Cheyenne and PacifiCorp, energy supply conditions and market prices in the western United States dramatically changed. Cheyenne was unable to execute a new agreement with PacifiCorp for the prices and terms it had been negotiating. Consequently, since Feb. 24, 2001, PSCo has been currently supplying Cheyenne's power requirements, although the rates under this agreement have not yet been approved by the FERC.
In March 2001, Cheyenne requested an increase in retail electric rates to provide for recovery of increasing power costs. As a result of the significant increase in electric energy costs since late February 2001, Cheyenne under recovered its costs under its electric cost adjustment (ECA) mechanism. On May 25, 2001, the Wyoming Public Service Commission (WPSC) approved a Stipulation Agreement between Cheyenne and intervenors in connection with a proposed increase in rates charged to Cheyenne's retail customers to recover increased power costs.
The Stipulation provides for an ECA rate structure with a fixed energy supply rate for Cheyenne's customers through 2003 (an estimated combined capacity and energy rate of approximately $54 per megawatt-hour); the continuation of the ECA with certain modifications, including the amortization through December 2005 of unrecovered costs incurred during 2001 up to the agreed upon fixed supply rates; and an agreement that Cheyenne's energy supply needs will be provided, in whole or in part, by PSCo in accordance with wholesale tariff rates to be approved by FERC. The estimated retail rate
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increases under the Stipulation would provide recovery of an additional $18 million (in comparison to prior rate levels) through the remainder of 2001 and a total of $28 million for each of the years 2002 and 2003. In 2004 and 2005, Cheyenne will return to requesting recovery of its actual costs incurred plus the outstanding balance of any deferral from earlier years. New cost levels consistent with the Stipulation Agreement has been reflected in Cheyenne's expenses, and in deferred costs based on current ECA recovery levels, with an effective date of June 1, 2001, and retroactive adjustments back to the date of the increase in costs on Feb. 25, 2001. The power costs underlying the Stipulation Agreement are based on wholesale tariff rates filed with FERC in June 2001. FERC action on the new tariffs is anticipated within 60 days of filing.
5. Commitments and Contingent Liabilities
Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.
Xcel Energy and its subsidiaries have been or are currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, Xcel Energy is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, Xcel Energy is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense for such unrecoverable amounts.
The circumstances set forth in Notes 14 and 15 to Xcel Energy's financial statements in Xcel Energy's Annual Report on Form 10-K for the year ended Dec. 31, 2000, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, except as for the following updated developments.
California Power Market—NRG's California generation assets consist primarily of its interests in the Crockett and Mt. Poso facilities and a 50 percent interest in West Coast Power LLC, formed in 1999 with Dynegy Inc. The West Coast Power facilities sold power through the California Power Exchange (PX) and the California Independent System Operator (ISO) to Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas and Electric Company (SDG&E). Currently, the West Coast Power facilities sell power through the California ISO to the California Department of Water Resources (the CDWR). Crockett, Mt.Poso and certain other NRG California facilities also sell directly to PG&E, SCE and SDG&E. The combination of rising wholesale electric prices, increases in the cost of natural gas, the scarcity of hydroelectric power and regulatory limitations on the rates that PG&E and SCE may charge their retail customers caused both PG&E and SCE to default in their payments to the California PX, the California ISO and other suppliers, including NRG. In March 2001, the California PX filed for Chapter 11 bankruptcy and in April 2001, PG&E filed for Chapter 11 bankruptcy.
In March 2001, affiliates of West Coast Power entered into a contract with the CDWR in which the affiliates agreed to sell up to 1,000 megawatts to the CDWR for the remainder of 2001 and up to 2,300 megawatts from January 2002 through December 2004, any of which may be resold by the CDWR to utilities such as SCE, PG&E and SDG&E. The ability of the CDWR to make future
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payments is subject to the CDWR having a continued source of funding, whether from legislative or other emergency appropriations, from a bond issuance or from amounts collected from SCE, PG&E and SDG&E. As a result of the situation in California, NRG's interests in California are exposed to the heightened risk of delayed payments and/or non-payment regardless of whether the sales are made directly to PG&E, SCE or SDG&E or to the California ISO or the CDWR.
NRG's share of the net amounts owed to its California affiliates by the California PX, the California ISO, and the three major California utilities totaled approximately $218 million as of June 30, 2001. This amount reflects NRG's share of (a) total amounts owed to its California affiliates of $371 million, less (b) amounts that are currently treated as disputed revenues and are not recorded as accounts receivable in the financial statements of NRG's California affiliates, and reserves taken against accounts receivable that have been recorded in the financial statements, both of which together totaled $153 million. NRG believes that it will ultimately collect in full the net amount of $218 million owed to its California affiliates; however, if some form of financial relief or support is not provided to PG&E and SCE, the collectibility of this amount will become more questionable in terms of both timing and amount. With respect to disputed revenues, these amounts relate to billing disputes arising in the ordinary course of business and to disputes that have arisen as a result of the California ISO and the FERC imposing various revenue caps on the wholesale price of electricity. None of these disputed revenues will be recorded until these matters are resolved. Since the date of the PG&E bankruptcy filing, PG&E has been paying NRG's Crockett and Mt. Poso affiliates on a current basis.
The delayed collection of receivables owed to West Coast Power resulted in a covenant default under its credit agreement. West Coast Power has entered into a forbearance agreement with its lenders in connection with the covenant default. In addition, NRG's Crockett affiliate was notified by its lenders that it has incurred a covenant default under its loan agreement. As a result, NRG has reclassified the long-term portion of the Crockett debt to current. Defaults under the Crockett and West Coast Power credit agreements do not trigger defaults under any of NRG's corporate-level financing debt securities or borrowing arrangements.
FERC has jurisdiction over sales for resale of electricity in the California wholesale power markets. In March 2001, FERC issued orders that presumptively approved prices up to $273 per megawatt-hour during January 2001 and $430 per megawatt-hour during February 2001. The orders direct electricity suppliers either to refund a portion of their January and February sales or justify prices charged above these approved prices. The orders, if finalized, could require West Coast Power to refund approximately $45 million in revenues from January and February, of which NRG's share would be approximately $22.5 million. Dynegy Power Marketing, Inc., as the power marketer for West Coast Power, has submitted information to justify each component of the prices it charged that were in excess of the presumptively approved prices.
On June 19, 2001, FERC issued an order establishing a maximum pricing methodology for spot markets in California and throughout the Western Systems Coordinating Council (WSCC) region at times when reserves fall below 7 percent in California. The maximum prices for sales in the WSCC spot markets during those hours, called the "market clearing price", is derived from the costs of the least efficient provider based in California and selling through the California ISO. At all other times, this order establishes a maximum price equal to 85 percent of the last market clearing price. This maximum price program will terminate on September 30, 2002. FERC also mandated settlement negotiations among sellers and buyers in the California ISO markets in respect of the settlement of
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past accounts, refund issues related to periods after October 2, 2000, and the structuring of future arrangements for meeting California's energy requirements. The settlement talks concluded without reaching a resolution on July 9, 2001. NRG cannot predict what action FERC will take on any of the issues presented, including any refunds sought from the generators.
French Island—NSP-Wisconsin's French Island plant generates electricity by burning a mixture of wood waste and refuse derived fuel. The fuel is derived from municipal solid waste furnished under a contract with LaCrosse County, Wisconsin. In 1997, the EPA found that the French Island plant was a "small municipal waste combustor" and therefore not subject to EPA regulations applicable to large combustors. In October 2000, the EPA reversed its decision and found that the plant was subject to the large combustor regulations. Those regulations became effective on Dec. 19, 2000. NSP-Wisconsin did not have adequate time to install the emission controls necessary to come into compliance with the large combustor regulations by the compliance date. As a result, on March 29, 2001, the EPA issued a finding of violation to the company. On April 2, 2001, a conservation group sent NSP-Wisconsin a notice of intent to sue under the citizen suit provisions of the Clean Air Act. On July 27, 2001, the state of Wisconsin filed a lawsuit against NSP-Wisconsin in the Wisconsin Circuit Court for La Crosse County, contending that NSP-Wisconsin exceeded dioxin emission limits on numerous occasions between July 1995 and December 2000 at French Island. NSP-Wisconsin faces fines between $10 and $25,000 for each violation. On July 27, 2001, NSP-Wisconsin filed for a Certificate of Authority to install control equipment necessary to bring the French Island plant into compliance with the large combustor regulations. NSP-Wisconsin plans to begin construction of the new air quality equipment in August 2001 upon issuance of a Certificate of Authority from the PSCW.
6. Short-Term Borrowings and Financial Instruments
At June 30, 2001, Xcel Energy and its subsidiaries had approximately $2.3 billion of short-term debt outstanding at a weighted average interest rate of 4.55 percent.
As of June 30, 2001, Xcel Energy had several interest rate swaps with a notional amount of approximately $1.0 billion, the majority of these swaps were related to NRG. If the swaps were terminated at June 30, 2001, Xcel Energy would have had to pay the counterparties approximately $47 million.
NRG had several interest rate swap agreements outstanding at June 30, 2001, with a total notional amount of approximately $976 million. These swaps convert project financing from variable rate to fixed rate debt. If the swaps were terminated at June 30, 2001, NRG would have had to pay the counterparties approximately $35 million. These swaps are described below.
- •
- One swap effectively converts a $16 million issue of non-recourse variable rate debt into fixed rate debt. The swap expires in September 2002 and is secured by the Camas Power Boiler assets.
- •
- One swap converts $140 million of non-recourse variable rate debt into fixed rate debt. The swap expires in December 2014 and is secured by the Crockett Cogeneration assets.
- •
- One swap converts notional amount of GBP 188 million or approximately $268 million of non-recourse variable rate debt into fixed rate debt. The swap expires in June 2019 and is secured by the Killingholme assets.
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- •
- One swap converts variable rate debt to fixed rate debt. The notional amount is the equivalent of approximately $54 million as of June 30, 2001. The swap expires in September 2012 and is secured by the Flinders Power assets.
- •
- Several swaps convert variable rate debt to fixed rate debt. The notional amount is the equivalent of approximately $498 million as of June 30, 2001. The swaps expire at various times between June 2002 and September 2006 and are secured by the LSP Kendell assets.
SPS has an interest rate swap with a notional amount of $25 million, converting variable rate debt to a fixed rate. Young Gas Storage and Quixx Linden, projects which are unconsolidated equity investments of Xcel Energy, have interest rate swaps converting project debt from variable rate to fixed rate. These two swaps had a total notional amount of approximately $39 million on June 30, 2001. The approximate termination cost of Xcel Energy's portion of these three swaps was approximately $11 million at June 30, 2001.
As of June 30, 2001, NRG currently had one foreign currency swap outstanding, hedging $9.2 million of expected cash flows from the Killingholme project. The swap expired July 31, 2001. Had this contract been terminated on June 30, 2001, NRG would have received $0.2 million from the counterparty.
7. Segment Information
Xcel Energy has the following reportable segments: Electric Utility, Gas Utility and two of its nonregulated energy businesses, NRG and e prime. During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power. As a result of this sales agreement, Xcel International (Yorkshire Power was Xcel International's most significant holding) is no longer a reportable segment. Prior periods have been restated for comparability.
Three months ended June 30, 2001
| Electric Utility | Gas Utility | NRG | e prime | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Thousands of dollars) | ||||||||||||||||||||||
Operating revenues from external customers | $ | 2,077,863 | $ | 401,256 | $ | 659,207 | $ | 435,252 | $ | 63,843 | — | $ | 3,637,421 | ||||||||||
Intersegment revenues | 186 | (415 | ) | 1,047 | 5,408 | 18,117 | (25,009 | ) | (666 | ) | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | — | — | 61,598 | 378 | (174 | ) | — | 61,802 | |||||||||||||||
Total revenues | $ | 2,078,049 | $ | 400,841 | $ | 721,852 | $ | 441,038 | $ | 81,786 | $ | (25,009 | ) | $ | 3,698,557 | ||||||||
Segment net income (loss) | $ | 135,571 | $ | 4,715 | $ | 49,114 | $ | 5,752 | $ | (22,027 | ) | $ | (5,268 | ) | $ | 167,857 | |||||||
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Three months ended June 30, 2000
| Electric Utility | Gas Utility | NRG | e prime | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Thousands of dollars) | ||||||||||||||||||||||
Operating revenues from external customers | $ | 1,384,538 | $ | 225,343 | $ | 474,428 | $ | 265,088 | $ | 66,667 | — | $ | 2,416,064 | ||||||||||
Intersegment revenues | 311 | 7,906 | 300 | 8,200 | 23,047 | (39,612 | ) | 152 | |||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 48,173 | 246 | 9,020 | — | 57,439 | ||||||||||||||||
Total revenues | $ | 1,384,849 | $ | 233,249 | $ | 522,901 | $ | 273,534 | $ | 98,734 | $ | (39,612 | ) | $ | 2,473,655 | ||||||||
Segment income (loss) before extraordinary items | $ | 113,273 | $ | 1,011 | $ | 43,581 | $ | 940 | $ | 1,706 | $ | (3,771 | ) | $ | 156,740 | ||||||||
Extraordinary items, net of tax | (13,658 | ) | — | — | — | — | — | (13,658 | ) | ||||||||||||||
Segment net income (loss) | $ | 99,615 | $ | 1,011 | $ | 43,581 | $ | 940 | $ | 1,706 | $ | (3,771 | ) | $ | 143,082 | ||||||||
Six months ended June 30, 2001
| Electric Utility | Gas Utility | NRG | e prime | All Other | Reconciling Eliminations | Consolidated Total | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Thousands of dollars) | |||||||||||||||||||||
Operating revenues from external customers | $ | 3,951,130 | $ | 1,360,702 | $ | 1,282,176 | $ | 1,076,112 | $ | 173,410 | — | $ | 7,843,530 | |||||||||
Intersegment revenues | 463 | 2,159 | 1,694 | 59,472 | 27,440 | (90,897 | ) | 331 | ||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 80,502 | 699 | 4,063 | — | 85,264 | |||||||||||||||
Total revenues | $ | 3,951,593 | $ | 1,362,861 | $ | 1,364,372 | $ | 1,136,283 | $ | 204,913 | $ | (90,897 | ) | $ | 7,929,125 | |||||||
Segment net income (loss) | $ | 266,484 | $ | 53,759 | $ | 84,292 | $ | 5,838 | $ | (22,534 | ) | $ | (10,672 | ) | $ | 377,167 | ||||||
Six months ended June 30, 2000
| Electric Utility | Gas Utility | NRG | e prime | All Other | Reconciling Eliminations | Consolidated Total | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (Thousands of dollars) | ||||||||||||||||||||||
Operating revenues from external customers | $ | 2,642,332 | $ | 715,929 | $ | 805,305 | $ | 448,573 | $ | 105,393 | — | $ | 4,717,532 | ||||||||||
Intersegment revenues | 569 | 7,972 | 601 | 9,177 | 34,536 | (52,379 | ) | 476 | |||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 38,529 | 517 | 31,043 | — | 70,089 | ||||||||||||||||
Total revenues | $ | 2,642,901 | $ | 723,901 | $ | 844,435 | $ | 458,267 | $ | 170,972 | $ | (52,379 | ) | $ | 4,788,097 | ||||||||
Segment income (loss) before extraordinary items | $ | 198,286 | $ | 44,505 | $ | 52,327 | $ | 926 | $ | 21,817 | $ | (7,789 | ) | $ | 310,072 | ||||||||
Extraordinary items, net of tax | (13,658 | ) | — | — | — | — | — | (13,658 | ) | ||||||||||||||
Segment net income (loss) | $ | 184,628 | $ | 44,505 | $ | 52,327 | $ | 926 | $ | 21,817 | $ | (7,789 | ) | $ | 296,414 | ||||||||
8. Adoption of SFAS 133
On Jan. 1, 2001, Xcel Energy adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activity," as amended by SFAS 137 and SFAS 138 (collectively referred to as SFAS 133). These statements require that all derivative instruments be recorded on the balance sheet at fair value. Changes in the derivative instrument's fair value must be recognized currently in earnings unless
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specific accounting criteria are met or specific exclusions are applicable. Accounting for qualifying hedges within the terms of SFAS 133 allows a derivative instrument's gains and losses to offset related results of the hedged item in the income statement, to the extent effective. SFAS 133 requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability, or firm commitment being hedged through earnings. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in other comprehensive income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument's change in fair value is recognized in earnings. Additionally, both the fair value changes excluded from the effectiveness assessment and the time value component of options used as cash flow hedges are recognized in earnings.
SFAS 133 applies to Xcel Energy's energy and energy related commodities financial instruments, long-term power sales contracts and long-term gas purchase contracts used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investment in fuel inventories. SFAS 133 also applies to various interest rate swaps used to mitigate the risks associated with movements in interest rates and foreign exchange contracts to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions.
Xcel Energy conducts energy acquisition, wholesale sales and trading activities through its utility and non-regulated operations. The primary objective of Xcel Energy's energy acquisition and trading operations is to maximize asset value while simultaneously minimizing pricing and credit risks. These activities are subject to SFAS 133 as they typically meet the definition of derivative instruments. For the Company's regulated utility customers, Xcel Energy acquires electric capacity and energy as well as natural gas supplies. Included in this operation are certain wholesale trading activities to optimize asset utilization. Xcel Energy is exposed to some level of market and credit risk under its obligation to manage its retail electric distribution and natural gas needs. Xcel Energy enters into derivative instruments to hedge fuel requirements, inventories, excess generation capacity, and purchase power contracts. The unregulated activities are conducted primarily by NRG and e prime, two unregulated subsidiaries of Xcel Energy. As with the utility operations, derivative instruments are entered into which seek to optimize asset utilization, market inventories, minimize price and credit risks, and market and hedge existing supplies and purchases.
Xcel Energy formally documents its hedge relationships, including the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged transaction. Derivatives are recorded in the balance sheet at fair value. Xcel Energy also formally assesses both at inception and at least quarterly thereafter, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.
The adoption of SFAS 133 on Jan. 1, 2001, resulted in an earnings impact of less than $1 million, which is not being reported separately as a cumulative effect of accounting change due to immateriality. In addition, upon adoption of SFAS 133, Xcel Energy recorded a net transition loss of approximately $29 million recorded in other comprehensive income. The impact to other comprehensive income is related to existing cash flow hedges during increasing price conditions.
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The components of SFAS 133 impacts on Xcel Energy's other comprehensive income are detailed in the following table (in millions of dollars).
Net transition loss, January 1, 2001 | $ | (28.8 | ) | |
After-tax net unrealized gains related to derivatives accounted for as hedges | 46.3 | |||
After-tax net realized losses on derivative transactions reclassified into earnings | 19.9 | |||
Other comprehensive income, June 30, 2001 | $ | 37.4 | ||
The components of SFAS 133 impacts on Xcel Energy's income statement are detailed in the following table (in millions of dollars except per share data).
| Three months ended June 30, 2001 | Six months ended June 30, 2001 | ||||||
---|---|---|---|---|---|---|---|---|
Nonregulated and other revenues | $ | (11.4 | ) | $ | (11.4 | ) | ||
Equity earnings from investment in affiliates | 2.7 | 0.8 | ||||||
Electric fuel and purchased power—utility | (0.9 | ) | 0.2 | |||||
Cost of goods sold—nonregulated and other | (25.9 | ) | (5.2 | ) | ||||
Other income (deductions) | 0.9 | 2.2 | ||||||
Total impact before minority interest and income tax | $ | (34.6 | ) | $ | (13.4 | ) | ||
Total impact to net income | $ | (12.5 | ) | $ | (2.4 | ) | ||
EPS impact (diluted) | $ | (0.04 | ) | $ | (0.01 | ) | ||
Energy and energy related commodities—Xcel Energy is exposed to commodity price variability and credit risk in its generation, retail distribution and energy trading operations. In order to manage these commodity price risks, Xcel Energy enters into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps. Derivatives designated to be hedges by Xcel Energy are accounted for as cash flow hedges and recorded as electric fuel and purchased power for Xcel Energy's regulated subsidiaries, as cost of goods sold—nonregulated and other for Xcel Energy's nonregulated subsidiaries, and as equity earnings from investment in affiliates for activities by NRG's equity investments.
Xcel Energy generally attempts to balance its fixed-price physical and financial purchase and sales commitments in terms of contract volumes, and the timing of performance and delivery obligations. These derivatives do not qualify for hedge accounting and, accordingly, changes in the fair value are reported in earnings. Furthermore, Xcel Energy has elected not to designate certain commodity derivatives considered to be economic hedges as accounting hedges due to the documentation requirements under SFAS 133.
At June 30, 2001, Xcel Energy had various commodity related contracts extending through December 2003 and several fixed-price gas purchase contracts extending through 2005 to 2018. Xcel Energy expects to reclassify into earnings during the next twelve months net gains from other comprehensive income of approximately $11.9 million.
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Interest rates—To manage interest rate risk, Xcel Energy (primarily at NRG) has entered into interest rate swaps that effectively fix the interest payments of certain floating rate debt instruments. Interest rate swap agreements are accounted for as cash flow hedges and recorded as interest expense. Xcel Energy expects to reclassify into earnings during the next twelve months net losses from other comprehensive income of approximately $1.8 million.
Foreign currency exchange rates—To preserve the U.S. dollar value of projected foreign currency cash flows, NRG may hedge, or protect, those cash flows if appropriate foreign hedging instruments are available. For the three and six months ended June 30, 2001, NRG had various foreign currency exchange contracts not designated as accounting hedges but as natural hedges. Accordingly, the changes in fair value of these derivatives are reported in other income (deductions) in the income statement.
Cash flow hedge quantitative disclosures—The net gain (loss) recognized in earnings for derivative instruments that have been designated and qualify as cash flow hedging instruments are detailed in the following table (in millions of dollars).
| Hedge ineffectiveness | Derivatives excluded from assessment of hedge effectiveness | Firm commitments no longer qualifying as cash flow hedges | ||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
Three months ended June 30, 2001: | |||||||||||
Energy and energy related commodities | $ | 13.6 | $ | (0.2 | ) | $ | (0.01 | ) | |||
Interest rates | — | — | — | ||||||||
Six months ended June 30, 2001: | |||||||||||
Energy and energy related commodities | $ | 13.9 | $ | 1.2 | $ | 0.01 | |||||
Interest rates | — | — | — |
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Xcel Energy Inc.:
We have reviewed the accompanying consolidated balance sheet of Xcel Energy Inc. (a Minnesota corporation) and subsidiaries as of June 30, 2001, the related consolidated statements of income and stockholders' equity for the three-month and six-month periods ended June 30, 2001 and the related consolidated statement of cash flows for the six-month period ended June 30, 2001. These financial statements are the responsibility of the Company's management. We did not review the interim financial statements of NRG Energy, Inc., whose total assets constitute 42 percent and total revenues for the three-month and six-month periods constitute 20 percent and 17 percent, respectively, of the related consolidated totals but were furnished with the report of other accountants of their review of those statements.
We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review and report of other accountants, we are not aware of any material modifications that should be made to the consolidated financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.
We have previously audited, in accordance with auditing standards generally accepted in the United States, the balance sheet of Xcel Energy Inc. and subsidiaries as of Dec. 31, 2000 (not presented herein), and, in our report dated March 2, 2001, we expressed an unqualified opinion on that statement. In our opinion, the information set forth in the accompanying consolidated balance sheet as of Dec. 31, 2000 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota
August 14, 2001
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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL REVIEW
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy's financial condition and results of operations during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and Notes.
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate," "estimate," "expect," "objective," "outlook," "projected," "possible," "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:
- •
- general economic conditions, including their impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms;
- •
- business conditions in the energy industry;
- •
- competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy and its subsidiaries;
- •
- unusual weather;
- •
- state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed and degree to which competition enters the electric and gas markets;
- •
- the higher risk associated with Xcel Energy's nonregulated businesses compared with its regulated businesses;
- •
- currency translation and transaction adjustments;
- •
- risks associated with the California power market; and
- •
- the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including Exhibit 99.01 to this report on Form 10-Q for the quarter ended June 30, 2001.
RESULTS OF OPERATIONS
Earnings per Share Summary
Xcel Energy's earnings per share were $0.49 for the second quarter of 2001, compared with $0.42 for the second quarter of 2000. Xcel Energy's earnings per share for the second quarter of 2000 were reduced by 4 cents per share for an extraordinary item related to the restructuring of SPS' generation business.
Xcel Energy's earnings per share were $1.10 for the first six months of 2001, compared with $0.87 for the first six months of 2000. Xcel Energy's earnings per share for the first six months of 2000 were reduced by 4 cents per share for an extraordinary item related to the restructuring of SPS' generation
23
business. The following table details the earnings per share contribution of Xcel Energy's regulated and nonregulated businesses.
| Three months ended: | Six months ended: | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Earnings per share (EPS) | |||||||||||||
6/30/01 | 6/30/00 | 6/30/01 | 6/30/00 | ||||||||||
Regulated EPS before extraordinary item | $ | 0.43 | $ | 0.34 | $ | 0.99 | $ | 0.73 | |||||
Extraordinary item | 0.00 | (0.04 | ) | 0.00 | (0.04 | ) | |||||||
Total regulated EPS | 0.43 | 0.30 | 0.99 | 0.69 | |||||||||
Nonregulated EPS | 0.06 | 0.12 | 0.11 | 0.18 | |||||||||
Total Xcel Energy EPS | $ | 0.49 | $ | 0.42 | $ | 1.10 | $ | 0.87 | |||||
Conservation Incentive Recovery—Regulated Earnings for the second quarter of 2001, were increased by 7 cents per share due to the reversal of the Minnesota Public Utilities Commission (MPUC) decision to deny NSP-Minnesota recovery of 1998 conservation incentives.
In June 1999, the MPUC denied NSP-Minnesota recovery of 1998 lost margins, load management discounts and incentives associated with state-mandated programs for electric energy conservation. Xcel Energy recorded a $35 million charge in 1999, which reduced earnings by 7 cents per share, based on this action. NSP-Minnesota appealed the MPUC decision and in December 2000, the Minnesota Court of Appeals reversed the MPUC decision.
In January 2001, the MPUC appealed the lower court decision to the Minnesota Supreme Court. On Feb. 23, 2001, the Minnesota Supreme Court declined to hear the MPUC's appeal. During the second quarter of 2001, NSP-Minnesota filed with the MPUC a plan that carried out, among other things, the court's decision. On June 28, 2001, the MPUC approved the plan and issued an order to that effect shortly thereafter. As a result, the previously recorded liabilities of approximately $41 million (including carrying charges) for potential refunds to customers are no longer required and were reversed as of June 30, 2001.
This accounting adjustment increased second quarter revenue by approximately $35 million and increased allowance for funds used during construction (equity and debt) by approximately $6 million, increasing earnings by 7 cents per share. The revenue increase relates to the elimination of potential refunds of amounts previously billed and collected, and the other income represents reversal of accrued carrying charges.
Postemployment Benefits—Earnings for the second quarter of 2001, were decreased by 4 cents per share due to a Colorado Supreme Court decision that resulted in a pretax write-off of $23 million of a regulatory asset related to deferred postemployment benefit costs at PSCo. For more information, see Note 2 to the Financial Statements.
Extraordinary Item Electric—Utility Restructuring—In the second quarter of 2000, SPS discontinued regulatory accounting under SFAS 71 for the generation portion of its business due to the issuance of a written order by the Public Utilities Commission of Texas (PUCT) in May 2000, addressing the implementation of electric utility restructuring. During the second quarter of 2000, SPS wrote off its generation-related regulatory assets and other deferred costs totaling approximately $19.3 million. This resulted in an after-tax extraordinary charge of approximately $13.7 million. This extraordinary charge reduced Xcel Energy's earnings by 4 cents per share for the second quarter of 2000. For more information on restructuring, including the reapplication of regulatory accounting under SFAS 71 in 2001, see Note 4 to the Financial Statements.
SFAS 133—The adoption of SFAS 133 on Jan. 1, 2001, resulted in an earnings impact of less than $1 million, which is not being reported separately as a cumulative effect of accounting change due to
24
immateriality. In addition, upon adoption of SFAS 133 Xcel Energy recorded a net transition loss of approximately $29 million recorded in other comprehensive income. At June 30, 2001, Xcel Energy had cumulative gains recorded in other comprehensive income of $37.4 million. For more information on SFAS 133, see Note 8 to the Financial Statements.
Xcel Energy's earnings for the second quarter of 2001 were decreased by approximately $12.5 million (net of minority interest and after tax), or 4 cents per share, primarily at NRG, due to the mark-to-market impacts of SFAS 133 on the valuation of derivative instruments.
Xcel Energy's earnings for the first six months of 2001 were decreased by approximately $2.4 million (net of minority interest and after tax), or 1 cents per share, primarily at NRG, due to the mark-to-market impacts of SFAS 133 on the valuation of derivative instruments.
Other comprehensive income has also been affected each quarter since the implementation of SFAS of 133, as shown in the Statement of Consolidated Common Stockholders' Equity.
Nonregulated Results
The following table summarizes the earnings contributions of Xcel Energy's nonregulated businesses:
| Three months ended: | Six months ended: | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Earning per share (EPS) | |||||||||||||
6/30/01 | 6/30/00 | 6/30/01 | 6/30/00 | ||||||||||
NRG Energy Inc. | $ | 0.11 | $ | 0.13 | $ | 0.19 | $ | 0.16 | |||||
Yorkshire Power | 0.00 | 0.02 | 0.01 | 0.10 | |||||||||
Seren Innovations Inc. | (0.02 | ) | (0.02 | ) | (0.04 | ) | (0.03 | ) | |||||
e prime | 0.02 | 0.00 | 0.02 | 0.00 | |||||||||
Planergy International | (0.02 | ) | 0.00 | (0.02 | ) | (0.01 | ) | ||||||
Financing costs and preferred dividends | (0.02 | ) | (0.02 | ) | (0.06 | ) | (0.04 | ) | |||||
Other | (0.01 | ) | 0.01 | 0.01 | 0.00 | ||||||||
Total nonregulated EPS | $ | 0.06 | $ | 0.12 | $ | 0.11 | $ | 0.18 | |||||
NRG—NRG's earnings for the second quarter and first six months of 2001 benefited from increased electric revenues resulting from recently acquired generation assets. NRG's earnings were also influenced by increased demand for electricity, market dynamics, strong performance from existing assets and higher market prices for electricity. NRG's earnings for the second quarter and the first six months of 2001 were reduced by 3 cents per share and 1 cent per share, respectively due to the mark-to-market impacts of SFAS 133 on the valuation of derivative instruments.
The NRG earnings for the second quarter and the first six months of 2001 in this report exclude earnings of approximately 4 cents per share and 6 cents per share, respectively, related to minority shareholder interests. In comparison, NRG earnings for the second quarter and the first six months of 2000, in this report exclude earnings of approximately 2 cents per share for both periods, related to minority shareholder interests.
Yorkshire Power—During February 2001, Xcel Energy reached an agreement to sell the majority of its investment in Yorkshire Power to Innogy Holdings plc. As a result of this sales agreement, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001. For more information, see Note 3 to the Financial Statements. In addition, during the first quarter of 2000, Yorkshire Power changed its depreciation method, which increased Xcel Energy's equity earnings for the first six months of 2000 by approximately $6.5 million, or approximately 2 cents per share.
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Seren—As expected, Seren's construction of its broadband communications network in Minnesota and California resulted in higher losses for the first six months of 2001. Seren is constructing a combination cable television, telephone and high-speed Internet access system in two locations, St. Cloud, Minn. and Contra Costa county in the east bay area of northern California. As of June 30, 2001, Xcel Energy's investment in Seren was approximately $226 million. Seren had capitalized $132 million for plant in service and had incurred another $70 million for construction work in progress for these systems at June 30, 2001. The majority of the system construction in St. Cloud is expected to be completed this year. The ultimate viability of Seren is dependent on securing a customer and revenue base sufficient to recover the capital investment and ongoing operating costs.
e prime—e prime's results for the second quarter and the first six months of 2001 reflect capitalizing on favorable market opportunities utilizing gas transmission and storage positions. These favorable market conditions may not continue to exist during the remainder of 2001 in the volatile natural gas markets.
Planergy International—During the second quarter of 2001, Planergy recorded a loss of nearly 2 cents per share largely due to lower margins on performance contracts, higher project development expenses and final costs related to the consolidation of Planergy and EMI operations.
Financing Costs and Preferred Dividends—Nonregulated results include interest expense and preferred dividend costs, which are incurred at the Xcel Energy and intermediate holding company levels and are not directly assigned to individual subsidiaries.
Other—At June 30, 2001, Xcel Energy had invested approximately $62 million in various international energy projects through its subsidiaries IPC/IPI. Xcel Energy is currently exploring the alternatives available for these projects. A decision may be reached in the second half of 2001 regarding Xcel Energy's future plans for IPC/IPI projects.
Income Statement Analysis—Second Quarter 2001 vs. Second Quarter 2000
Electric Utility Margins
The following table details the changes in electric utility revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric margin. However, the fuel cost recovery mechanisms in the various jurisdictions do not allow for complete recovery of all variable production expenses, and, therefore, higher costs can result in an adverse margin and earnings impact. Electric margins reflect the impact of sharing of energy costs and savings relative to a target cost per
26
delivered kilowatt-hour and certain trading margins under the incentive cost adjustment (ICA) in Colorado.
| Three months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Electric retail and firm wholesale revenue | $ | 1,453 | $ | 1,192 | |||
Short-term wholesale revenue | 191 | 91 | |||||
Total electric utility revenue | 1,644 | 1,283 | |||||
Electric retail and firm wholesale fuel and purchase power | 672 | 451 | |||||
Short-term wholesale fuel and purchase power | 155 | 67 | |||||
Total electric utility fuel and purchase power | 827 | 518 | |||||
Electric retail and firm wholesale margin | 781 | 741 | |||||
Short-term wholesale margin | 36 | 24 | |||||
Total electric utility margin | $ | 817 | $ | 765 | |||
Electric revenue increased by approximately $361 million, or 28.1 percent, in the second quarter of 2001. Electric margin increased by approximately $52 million, or 6.8 percent, in the second quarter of 2001. Electric retail revenue increased largely due to increases in fuel costs and purchased power expenses. Retail electric revenue and margin increased due to sales growth, more favorable weather conditions in the second quarter of 2001 and the recovery of conservation incentives in Minnesota. As discussed previously, the reversal of the MPUC decision to deny NSP-Minnesota recovery of 1998 conservation incentives increased retail revenue and margin by $35 million. Favorable temperatures during the second quarter of 2001 increased retail revenue by approximately $23 million and retail margin by approximately $13 million. These increases were partially offset by increased fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to various cost sharing mechanisms. Retail revenue and margin were also reduced in the second quarter of 2001 by approximately $7 million due to rate reductions in various jurisdictions agreed to as part of the merger approval process.
Short-term wholesale revenue and margin increased due to the expansion of Xcel Energy's wholesale marketing operations and favorable market conditions, including strong prices in the western markets, particularly before the establishment of price caps. It is not expected that short-term wholesale margins in the second half of 2001 will be as strong, due to a decline in the forward price curve.
Gas Utility Margins
The following table details the changes in gas utility revenue and margin. The cost of gas tends to vary with changing sales requirements and the unit cost of gas purchases. However, due to purchased
27
gas cost recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on natural gas margin.
| Three months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Gas revenue | $ | 400 | $ | 233 | |||
Cost of gas purchased and transported | (292 | ) | (142 | ) | |||
Gas margin | $ | 108 | $ | 91 | |||
Gas revenue increased by approximately $167 million, or 71.7 percent, in the second quarter of 2001, primarily due to increases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Gas margin increased by approximately $17 million, or 18.4 percent, in the second quarter of 2001, largely due to sales growth.
Electric and Gas Trading Margins
Xcel Energy's trading operations are conducted mainly by PSCo and e prime. Trading revenues and costs of goods sold do not include the revenue and production costs associated with energy produced from Xcel Energy's generation assets or energy and capacity purchased to serve native load or NRG. Margins from these generating assets for utility operations are included in the short-term wholesale portion of Electric Utility Margins, discussed previously. The trading margins reflect the impact of the sharing of certain trading margins under the ICA. The following table details the changes in electric and gas trading revenue and margin.
| Three months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Trading revenue | $ | 869 | $ | 367 | |||
Trading cost of goods sold | (837 | ) | (355 | ) | |||
Trading margin | $ | 32 | $ | 12 | |||
Trading revenue increased by approximately $502 million and trading margin increased by approximately $20 million for the second quarter of 2001. The increase in trading revenue and margin is a result of the expansion of electric trading at PSCo and natural gas trading at e prime and favorable market conditions, including strong prices in the western markets, particularly before the establishment of price caps. It is not expected that trading margins in the second half of 2001 will be as strong, due to a decline in the forward price curve.
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Nonregulated Operating Margins
The following table details the change in nonregulated revenue and margin.
| Three months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Nonregulated and other revenue | $ | 723 | $ | 533 | |||
Earnings from equity investments | 62 | 57 | |||||
Nonregulated cost of goods sold | (420 | ) | (259 | ) | |||
Nonregulated margin | $ | 365 | $ | 331 | |||
Nonregulated revenue and margin increased for the second quarter of 2001, largely due to NRG's acquisitions of generating facilities, increased demand for electricity, market dynamics, strong performance from existing assets, and higher market prices for electricity.
Earnings from equity investments increased for the second quarter of 2001, primarily due to increased equity earnings from NRG projects, which offset lower equity earnings from Yorkshire. As a result of a sales agreement to sell the majority of its investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.
Non-Fuel Operating Expense and Other Costs
Regulated Other Operation and Maintenance Expenses increased by approximately $13 million, or 3.9 percent for the second quarter of 2001, compared with the second quarter of 2000. The change is largely due to increased transmission costs from the Southwest Power Pool (which are offset in electric revenue), timing of plant outages and increased costs due to customer growth.
Nonregulated Other Operation and Maintenance Expenses increased by approximately $54 million, or 39.4 percent for the second quarter of 2001, compared with the second quarter of 2000, primarily due to the expansion of NRG's operations including acquisition costs, business development activities and legal, technical and accounting expenses.
Depreciation and amortization increased by approximately $24 million, or 12.0 percent for the second quarter of 2001, compared with the second quarter of 2000, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.
Interest expense increased by approximately $15 million, or 8.8 percent for the second quarter of 2001, compared with the second quarter of 2000, primarily due to increased debt levels to fund several asset acquisitions by NRG.
Other income-net increased by approximately $9 million for the second quarter of 2001, primarily due to higher interest income on temporary cash investments.
Income Statement Analysis—First Six Months of 2001 vs. First Six Months of 2000
Electric Utility Margins
The following table details the changes in electric utility revenue and margin. Electric production expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel clause cost recovery mechanisms for retail customers in several states, most fluctuations in energy costs do not materially affect electric margin. However, the fuel cost recovery mechanisms in the various jurisdictions do not allow for complete recovery of all variable production expenses, and, therefore, higher costs can result in an adverse margin and earnings impact.
29
Electric margins reflect the impact of sharing of energy costs and savings relative to a target cost per delivered kilowatt-hour and certain trading margins under the incentive cost adjustment (ICA) in Colorado.
| Six months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Electric retail and firm wholesale revenue | $ | 2,714 | $ | 2,340 | |||
Short-term wholesale revenue | 477 | 156 | |||||
Total electric utility revenue | 3,191 | 2,496 | |||||
Electric retail and firm wholesale fuel and purchase power | 1,251 | 898 | |||||
Short-term wholesale fuel and purchase power | 356 | 116 | |||||
Total electric utility fuel and purchase power | 1,607 | 1,014 | |||||
Electric retail and firm wholesale margin | 1,463 | 1,442 | |||||
Short-term wholesale margin | 121 | 40 | |||||
Total electric utility margin | $ | 1,584 | $ | 1,482 | |||
Electric revenue increased by approximately $695 million, or 27.9 percent, for the first six months of 2001. Electric margin increased by approximately $102 million, or 6.9 percent, for the first six months of 2001. Electric retail revenue increased largely due increases in fuel costs and purchased power expenses. Retail electric revenue and margin increased due to sales growth, more favorable weather conditions in the first six months of 2001 and the recovery of conservation incentives in Minnesota. As discussed previously, the reversal of the MPUC decision to deny NSP-Minnesota recovery of 1998 conservation incentives increased retail revenue and margin by $35 million. Favorable temperatures during the first six months of 2001 increased retail revenue by approximately $50 million and retail margin by approximately $32 million. These increases were partially offset by increased fuel and purchased power costs, which are not completely recoverable from customers in Colorado due to various cost sharing mechanisms. Retail revenue and margin were also reduced in the first six months of 2001 by approximately $14 million due to rate reductions in various jurisdictions agreed to as part of the merger approval process.
Short-term wholesale revenue and margin increased due to the expansion of Xcel Energy's wholesale marketing operations and favorable market conditions, including strong prices in the western markets, particularly before the establishment of price caps. It is not expected that short-term wholesale margins in the second half of 2001 will be as strong, due to a decline in the forward price curve.
Gas Utility Margins
The following table details the changes in gas utility revenue and margin. The cost of gas tends to vary with changing sales requirements and the unit cost of gas purchases. However, due to purchased
30
gas cost recovery mechanisms for retail customers, fluctuations in the cost of gas have little effect on natural gas margin.
| Six months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Gas revenue | $ | 1,361 | $ | 724 | |||
Cost of gas purchased and transported | (1,064 | ) | (459 | ) | |||
Gas margin | $ | 297 | $ | 265 | |||
Gas revenue increased by approximately $637 million, or 87.9 percent, for the first six months of 2001, primarily due to increases in the cost of natural gas, which are largely passed on to customers and recovered through various rate adjustment clauses in most of the jurisdictions in which Xcel Energy operates. Gas margin increased by approximately $32 million, or 11.8 percent, for the first six months of 2001. Favorable temperatures during the first six months of 2001 increased gas revenue by approximately $70 million and gas margin by approximately $22 million. These gas margin increases were partially offset by customer conservation efforts in reaction to higher natural gas prices.
Electric and Gas Trading Margins
Xcel Energy's trading operations are conducted mainly by PSCo and e prime. Trading revenues and costs of goods sold do not include the revenue and production costs associated with energy produced from Xcel Energy's generation assets or energy and capacity purchased to serve native load or NRG. Margins from these generating assets for utility operations are included in the short-term wholesale portion of Electric Utility Margins, discussed previously. Trading margins reflect the impact of sharing of certain trading margins under the ICA. The following table details the changes in electric and gas trading revenue and margin.
| Six months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Trading revenue | $ | 1,836 | $ | 595 | |||
Trading cost of goods sold | (1,754 | ) | (578 | ) | |||
Trading margin | $ | 82 | $ | 17 | |||
Trading revenue increased by approximately $1,241 million and trading margin increased by approximately $65 million for the first six months of 2001. The increase in trading revenue and margin is a result of the expansion of electric trading at PSCo and natural gas trading at e prime and favorable market conditions, including strong prices in the western markets, particularly before the establishment of price caps. It is not expected that trading margins in the second half of 2001 will be as strong, due to a decline in the forward price curve.
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Nonregulated Operating Margins
The following table details the change in nonregulated revenue and margin.
| Six months ended | ||||||
---|---|---|---|---|---|---|---|
| 6/30/01 | 6/30/00 | |||||
| (Millions of dollars) | ||||||
Nonregulated and other revenue | $ | 1,456 | $ | 903 | |||
Earnings from equity investments | 85 | 70 | |||||
Nonregulated cost of goods sold | (824 | ) | (407 | ) | |||
Nonregulated margin | $ | 717 | $ | 566 | |||
Nonregulated revenue and margin increased for the first six months of 2001, largely due to NRG's acquisitions of generating facilities, increased demand for electricity, market dynamics, strong performance from existing assets and higher market prices for electricity.
Earnings from equity investments for the first six months of 2001, increased compared with the first six months of 2000, primarily due to increased equity earnings from NRG projects, which offset lower equity earnings from Yorkshire. As a result of a sales agreement to sell the majority of its investment in Yorkshire Power, Xcel Energy did not record any equity earnings from Yorkshire Power after January 2001.
Non-Fuel Operating Expense and Other Costs
Regulated Other Operation and Maintenance Expenses increased by approximately $40 million, or 5.9 percent for the first six months of 2001, compared with the first six months of 2000. The change is largely due to increased transmission costs from the Southwest Power Pool (which are offset in electric revenue), timing of plant outages and increased costs due to customer growth.
Nonregulated Other Operation and Maintenance Expenses increased by approximately $96 million, or 33.5 percent for the first six months of 2001, compared with the first six months of 2000, primarily due to expansion of the NRG's operations including acquisition costs, business development activities and legal, technical and accounting expenses.
Depreciation and amortization increased by approximately $49 million, or 12.8 percent for the first six months of 2001, compared with the first six months of 2000, primarily due to acquisitions of generating facilities by NRG and increased capital additions to utility plant.
Interest expense increased by approximately $51 million, or 16.4 percent for the first six months of 2001, compared with the first six months of 2000, primarily due to increased debt levels to fund several asset acquisitions by NRG.
Other income-net increased by approximately $18 million in the first six months of 2001, compared with the first six months of 2000. In March 2001, Xcel Energy sold its Boulder Hydro facility in Colorado and recorded a gain of $11 million (before tax), or 2 cents per share on this transaction. The gain on this sale was shared with customers due to its inclusion in the PSCo Electric Earnings Test in Colorado.
Pending Accounting Changes
SFAS 142—In June 2001, the Financial Accounting Standards Board (FASB) approved the issuance of SFAS No. 142, "Goodwill and Other Intangible Assets". This statement will require new accounting for intangible assets, including goodwill. Intangible assets will be amortized over their economic useful life and reviewed for impairment in accordance with SFAS No. 121, "Accounting for the Impairment of
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Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Goodwill will no longer be amortized to comply with the provisions of SFAS 142. Instead, goodwill and intangible assets that will not be amortized should be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. An impairment test is required to be performed within six months of the date of adoption, and the first annual impairment test must be performed in the year the statement is initially adopted.
SFAS 142 is effective for Xcel Energy and its subsidiaries as of Jan. 1, 2002. At June 30, 2001, Xcel Energy had unamortized intangible assets of $161 million, including $71 million of goodwill, mainly at its nonregulated subsidiaries. These amounts and all intangible assets and goodwill acquired in the future will be accounted for under the new accounting standard. The new accounting can be expected to initially increase earnings due to the elimination of regular amortization expense, but occasionally cause reductions in earnings when impairment write-downs of goodwill and/or intangible assets are required. Xcel Energy is in the process of evaluating the effects SFAS 142, but expects the earnings impact to be immaterial and does not expect to recognize any asset impairments.
SFAS 143—In June 2001, the FASB approved the issuance of SFAS No. 143, "Accounting for Asset Retirement Obligations". This statement will require Xcel Energy to record its future nuclear plant decommissioning obligations as a liability at fair value with a corresponding increase to the carrying value of the related long-lived asset. The liability will be increased to its present value each period, and the capitalized cost will be depreciated over the useful life of the related long-lived asset. If the recorded liability differs from the actual obligations paid a gain or loss will be currently recognized.
Xcel Energy currently follows industry practice by ratably accruing the costs for decommissioning over the approved cost recovery period and including the accruals in accumulated depreciation. At Dec. 31, 2000, Xcel Energy recorded and recovered in rates $583 million of decommissioning obligations and had estimated discounted decommissioning cost obligations of $838 million.
If Xcel Energy adopted the standard on Jan. 1, 2001, the initial value of the liability, including cumulative interest expense through that date, would have been approximately $705 million, with an offsetting increase to net plant assets of approximately $600 million. The resulting cumulative effect adjustment for unrecognized depreciation and other expenses under the new standard is approximately $105 million. Management expects that the entire transition amount would be recoverable in rates and, therefore, would recognize an additional regulatory asset opposed to reporting a cumulative effect of accounting change in the income statement.
SFAS 143 will also affect Xcel Energy's accrued plant removal costs for other generation, transmission and distribution facilities. Xcel Energy expects these costs will be reclassified from accumulated depreciation to regulatory liabilities based on the recoverability of these costs in rates. Xcel Energy expects to adopt SFAS 143 on Jan. 1, 2003.
Stockholder Protection Rights Agreement
As previously announced, the Xcel Energy has adopted a Stockholder Protection Rights Agreement (Rights Agreement). Under the Rights Agreement, rights were distributed as a dividend at the rate of one right per each share of Xcel Energy's common stock. The dividend was paid to shareholders of record as of June 28, 2001. Under its principal provision, if any person or group acquires 15 percent or more of Xcel Energy's outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially diluting the acquiring person's or group's investment. The rights may cause substantial dilution to a person or group that acquires 15 percent or more of Xcel Energy's common stock. The rights should not interfere with a
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transaction that is in the best interests of Xcel Energy and its shareholders, because the rights can be redeemed prior to a triggering event for $0.01 per right.
Market Risks
Xcel Energy and its subsidiaries are exposed to market risks, including changes in commodity prices, interest rates and currency exchange rates as disclosed in Management's Discussion and Analysis in its annual report on Form 10-K for the year ended Dec. 31, 2000. Xcel Energy's regulated subsidiaries have limited exposure to commodity price and interest rate risk due to cost-based rate regulation. There have been no material changes in the market risk exposures that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2000, with the exception of the risks associated with the California power market as discussed in Note 5 to Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
| Six months ended June 30 | |||||
---|---|---|---|---|---|---|
| 2001 | 2000 | ||||
Net cash provided by operating activities(in millions) | $ | 529 | $ | 670 |
Cash provided by operating activities decreased for the first six months of 2001, compared with the first six months of 2000. Increases in net income were offset by decreases in working capital cash flows.
| Six months ended June 30 | ||||||
---|---|---|---|---|---|---|---|
| 2001 | 2000 | |||||
Net cash used in investing activities(in millions) | $ | (3,009 | ) | $ | (2,383 | ) |
Cash used in investing activities increased for the first six months of 2001, compared with the first six months of 2000. The change is largely due to increased levels of nonregulated capital expenditures and asset acquisitions, primarily at NRG. The increase was partially offset by Xcel Energy's sale of the majority of its investment in Yorkshire Power.
| Six months ended June 30 | |||||
---|---|---|---|---|---|---|
| 2001 | 2000 | ||||
Net cash provided by financing activities(in millions) | $ | 2,613 | $ | 1,730 |
Cash provided by financing activities increased for the first six months of 2001, compared with the first six months of 2000. The cash provided by financing activities for both periods reflects the issuance of debt and equity by NRG to fund various asset acquisitions. The change is largely due to increased short-term borrowings and lower repayments of long-term debt, partially offset by lower levels of debt issuances.
Financing Activities
NRG Public Offering—In March 2001, NRG issued 18.4 million shares of common stock at a price of $27 per share and 11.5 million corporate units at a price of $25 per unit. The net proceeds from the offerings were approximately $753 million, including $478 million recorded in NRG's common equity and $275 million recorded in long-term debt instruments of NRG. The offering's net proceeds were used exclusively by NRG for general corporate purposes, including funding a portion of NRG's project
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investments and other capital requirements. No proceeds of these offerings were received by Xcel Energy.
Management has concluded that these offerings of NRG stock do not affect Xcel Energy's ability to use the pooling-of-interests method of accounting for the merger of NSP and NCE. This secondary offering caused Xcel Energy's ownership interest in NRG to decline from approximately 82 percent to approximately 74 percent. A portion of the proceeds was accounted for as a gain on the sale of Xcel Energy's ownership in NRG. This gain of $242 million was not recorded in earnings, but consistent with Xcel Energy's accounting policy was recorded as an increase in the common stock premium component of stockholders' equity.
NRG Financings—In April 2001, NRG issued $350 million of 7.75 percent senior notes due April 2011 and $340 million of 30-year, 8.625-percent notes. The proceeds were used to repay short-term debt incurred to fund acquisitions and other general corporate purposes.
In May 2001, NRG entered into a $2 billion revolving credit facility with various lenders. The facility will be used to finance the acquisition, development and construction of power generating plants located in the United States and to finance the acquisition of turbines for such facilities. The facility provides for borrowings of base rate loans and Eurocurrency loans and is secured by mortgages and security agreements in respect of the assets of the projects financed under the facility, pledges of the equity interests in the subsidiaries or affiliates of the borrower that own such projects, and by guaranties from each such subsidiary or affiliate. Provided that certain conditions, NRG may repay loans and have the liens relating to that project released. NRG is permitted under the revolver to repay borrowed funds, thus making them available to be borrowed again. The facility terminates in May 2006. The facility is non-recourse to NRG other than the obligation to contribute equity at certain times in respect of projects and turbines financed under the facility.
In June 2001, NRG entered into a $600 million term loan facility with various lenders. The facility is unsecured and provides for borrowings of base rate loans and Eurocurrency loans. The facility terminates on June 21, 2002.
In June 2001, NRG filed a shelf registration with the SEC to sell up to $2 billion in debt securities, common and preferred stock, warrants and other securities. NRG expects to use the net proceeds for general corporate purposes, which may include the financing and development of new facilities, working capital and debt reduction. In July 2001, NRG issued $500 million of debt securities under this shelf registration. The first tranche was $340 million of 6.75 percent senior notes due July 2006 and the second tranche was $160 million of 8.625 percent notes due April 2031. The $160 million tranche was a reopening of the 30-year bonds issued by NRG in April 2001. NRG used the proceeds to pay down its revolving credit facility, other general corporate purposes and to provide capital for planned acquisitions.
In June 2001, NRG Midatlantic Generating LLC, a wholly owned subsidiary of NRG, borrowed approximately $415 million under a five year term loan agreement to finance, in part, the acquisition of certain generating facilities from Conectiv. The agreement terminates in November 2005 and provides for a total credit facility of $580 million.
NSP-Minnesota Shelf Registration—In April 2001, NSP-Minnesota filed a $600 million long-term debt shelf registration with the SEC. NSP-Minnesota intends to issue debt under this shelf registration during the third quarter of 2001.
SPS Shelf Registration—In June 2001, SPS filed a $500 million long-term debt shelf registration with the SEC. SPS plans to issue debt under this shelf registration during the third quarter of 2001. The proceeds from the shelf offering will be used for short-term debt repayment.
Short-term debt and financial instruments are discussed in Note 6 to the Financial Statements.
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In the normal course of business, various lawsuits and claims have arisen against Xcel Energy. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. See Notes 4 and 5 of the Financial Statements in this Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 of Xcel Energy's 2000 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against Xcel Energy or its subsidiaries and there have been no notable changes in the previously reported proceedings, except as set forth below.
Light Rail Transit (LRT)—On Feb. 16, 2001, NSP-Minnesota filed a suit in the United States District Court in Minneapolis, against the Minnesota Metropolitan Council, Minnesota Department of Transportation, State of Minnesota and the Federal Transit Administration to prevent pave-over of NSP-Minnesota's underground facilities during construction of the LRT system. NSP-Minnesota is also seeking recovery of relocation expenses. State defendants countersued, seeking delay damages and a $330 million surety bond. On May 24, 2001, the District Court issued a preliminary injunction requiring NSP-Minnesota to commence the relocation project and to cooperate with defendants. NSP-Minnesota immediately commenced design engineering for the relocation project in compliance with the preliminary injunction. NSP-Minnesota has appealed the Judge's Order to relocate. This matter is at the very early stages of litigation. NSP-Minnesota denies the merits of the defendants' countersuits and intends to vigorously defend against their claims.
Stubrud Case—On Sept. 25, 2000, NSP-Wisconsin was served with a complaint in Eau Claire County Circuit Court on behalf of Claron and Janice Stubrud. The complaint alleged that stray voltage from NSP-Wisconsin's system harmed their dairy herd resulting in lost milk production, lost profits and income, property damage, and injury to their dairy herd. The complaint also alleges that NSP-Wisconsin acted willfully and wantonly, entitling plaintiffs to treble damages. The plaintiffs allege farm damages of approximately $3.8 million. A ten-day trial commencing December 2, 2002, has been scheduled.
Craig Station—In 1996, a conservation organization filed a complaint in the U. S. District Court pursuant to provisions of the Clean Air Act against the joint owners of the Craig Steam Electric Generating Station, located in western Colorado. Tri-State Generation and Transmission Association, Inc. is the operator of the Craig station and PSCo owns an undivided interest in each of two units at the station, totaling approximately 9.7 percent. In October 2000, the parties, the EPA and the Colorado Department of Public Health and Environment (CDPHE) reached an agreement in principle resolving all air quality matters related to the facility. The final agreement was negotiated during the fourth quarter of 2000 and was filed with the court on Jan. 10, 2001. The final agreement requires the installation of additional emission control equipment at a cost of approximately $105 million (based on an estimate from Tri-State). The equipment will be installed over a period of several years. In addition, the settlement requires the defendants collectively to pay a civil penalty of $500,000 and to contribute $1.5 million to fund conservation activities. The contribution to conservation activities will be refunded if the plant achieves a specified level of emissions control. The agreement became enforceable after approval by the court on March 19, 2001.
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Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following Exhibits are filed with this report:
15 | Letter from Arthur Andersen LLP regarding unaudited interim information for Xcel Energy. | |
99.01 | Statement pursuant to Private Securities Litigation Reform Act. |
(b) Reports on Form 8-K
The following reports on Form 8-K were filed either during the three months ended June 30, 2001, or between June 30, 2001, and the date of this report:
April 2, 2001 (filed April 2, 2001)—Item 5. Other Events. Re: Disclosure of information related to a Xcel Energy investor relation's presentation.
May 25, 2001 (filed June 4, 2001)—Item 5 and 7. Other Events and Exhibits. Re: Disclosure of the status of the rate filing to recover expected increase in purchase power costs for Cheyenne Light, Fuel & Power Co., a subsidiary of Xcel Energy.
June 5, 2001 (filed June 14, 2001)—Item 5 and 7. Other Events and Exhibits. Re: Disclosure of Shareholders rights program.
June 15, 2001 (filed June 22, 2001)—Item 5 and 7. Other Events and Exhibits. Re: Disclosure of delay for restructuring in SPS' service territory.
June 28, 2001 (filed July 12, 2001)—Item 5. Other Events. Re: Disclosure of reversal of MPUC decision to deny recovery of NSP-Minnesota's conservation incentives and Colorado Supreme Court decision denying PSCo recovery of deferred costs for employees' postemployment benefits.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
XCEL ENERGY INC. (Registrant) | ||||
/s/ DAVID E. RIPKA | ||||
David E. Ripka Vice President and Controller | ||||
/s/ EDWARD J. MCINTYRE | ||||
Edward J. McIntyre Vice President and Chief Financial Officer |
Date: Aug. 14, 2001
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PART 1. FINANCIAL INFORMATION
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Thousands of Dollars, Except Per Share Data)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Thousands of Dollars)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Thousands of Dollars)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED) Three Months Ended June 30, 2001 and 2000 (Thousands of Dollars)
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (UNAUDITED) Six Months Ended June 30, 2001 and 2000 (Thousands of Dollars)
XCEL ENERGY INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
Part II. OTHER INFORMATION
SIGNATURES