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NRG Energy, Inc. Reports Second Quarter 2006 Results; Expands FORNRG Performance Improvement Program; Announces Capital Allocation Plan; Revises 2006 Guidance
PRINCETON, N.J.--(BUSINESS WIRE)--Aug. 1, 2006--NRG Energy, Inc. (NYSE:NRG):
-- $238 million of cash flow from operations, including return of
$42 million cash collateral;
-- $338 million of adjusted EBITDA, excluding mark-to-market
(MtM) impacts;
-- 2006 cash flow from operations and adjusted EBITDA guidance
adjusted to $1,324 and $1,500 million, respectively;
-- $1.98 billion of total liquidity at June 30, 2006;
-- $200 million recurring cost improvement target by 2009 under
the FORNRG program (revised upward from the previous $105
million annual target by 2008); and
-- $750 million capital allocation program in two phases--the
first phase is a $500 million common stock repurchase program
to be completed by year end 2006.
NRG Energy, Inc. (NYSE:NRG) today reported second quarter 2006 operating income of $416 million versus $43 million for the second quarter of 2005. Cash flow from operations was $238 million, including a $42 million reduction in the amount of cash collateral posted in support of trading operations, compared to $27 million during the same period last year which included a collateral outflow of $179 million. For the six months ended June 30, 2006, operating income was $626 million versus $90 million for the same period last year. Cash flow from operations year to date was $604 million for 2006, an increase of $513 million over 2005. Net income for the three and six months ended June 30, 2006 was $203 million and $229 million, respectively, as compared to $24 million and $47 million for the same periods last year. Net income in 2006 included $105 million in after tax refinancing expenses incurred as part of the first quarter closing of the Texas Genco acquisition, partially offset by $49 million in after-tax one-time gains related to the resolution of disputes and litigation.
The quarter-on-quarter and year-to-date operating income increases largely reflect the February 2, 2006 acquisition of Texas Genco (now known as NRG Texas). Also contributing to the improved second quarter performance were plant operating rate improvements at five of the six classic NRG baseload coal plants and higher New York capacity prices versus the same period last year. These improvements were partially offset by increased general and administrative expenses associated with the NRG Texas integration and Mirant-related expenses. The year-to-date results benefited from $67 million in surplus emissions allowance sales and $30 million in improved South Central margins achieved primarily through higher plant operating rates and increased merchant sales. Offsetting these increases were $69 million in lower Northeast margins due primarily to the unseasonably mild weather in the first quarter, higher operations and maintenance expenses due to increased major maintenance, and higher general and administrative expenses.
"As we informed the market during the Texas Genco acquisition financing, we expected cash generation from both our Texas business and the classic NRG portfolio to pay immediate benefits in terms of a return to our shareholders," said David Crane, NRG's President and Chief Executive Officer. "Now, with all aspects of our business performing at higher levels as a result of the continued success of the FORNRG program and the integration of NRG Texas almost complete, we are in a position to fulfill our promise with a $750 million capital allocation program."
Regional Segment Review of Results
Table 1: Three Months Income from Continuing Operations and Adjusted
EBITDA
($in millions) Income from Adjusted EBITDA
Continuing
Operations
before Taxes
----------------------------------------------------------------------
Three months ending 6/30/06 6/30/05 6/30/06 6/30/05
----------------------------------------------------------------------
Texas 292 - 253 -
Northeast 51 39 75 59
South Central (6) (7) 15 8
Australia (1) 6 6 6 6
Western 8 6 9 6
Other North America 1 (6) (4) 2
Other International 16 23 15 13
Alternative Energy, Non-generation,
Corporate and Other (2) (74) (30) 27 14
----------------------------------------------------------------------
Total 294 31 396 108
----------------------------------------------------------------------
Less: MtM forward position accruals (3) (37) (5) (37) (5)
Add: Prior Period MtM reversals (4) (21) 8 (21) 8
----------------------------------------------------------------------
Total net of MtM Impacts 236 34 338 111
----------------------------------------------------------------------
(1) Includes only Gladstone Equity Earnings; Flinders is reported as a
Discontinued Operation.
(2) Includes net interest expense of $83 million and $38 million for
2006 and 2005, respectively.
(3) Represents a net domestic MtM gain of $37 million in 2006
(primarily in the Northeast and Texas regions) and a net domestic
MtM gain of $5 million in 2005, primarily in the Northeast region.
(4) Represents the reversal of $21 million in 2006 associated with the
$119 million net domestic MtM losses recognized in 2005 and
reversal of $8 million in 2005 associated with the $59 million net
domestic MtM gain recognized in 2004, primarily in the Northeast
region.
Table 1: Six Months Income from Continuing Operations and Adjusted
EBITDA
($in millions) Income from Adjusted EBITDA
Continuing
Operations
before Taxes
----------------------------------------------------------------------
Six months ending 6/30/06 6/30/05 6/30/06 6/30/05
----------------------------------------------------------------------
Texas 285 - 345 -
Northeast 183 72 255 112
South Central 29 2 74 34
Australia (1) 11 12 12 12
Western 4 9 5 9
Other North America (2) 60 (12) (2) 1
Other International 40 69 42 49
Alternative Energy, Non-generation,
Corporate and Other (3) (302) (99) 35 31
----------------------------------------------------------------------
Total 310 53 766 248
----------------------------------------------------------------------
Less: MtM forward position accruals (4) (67) 33 (67) 33
Add: Prior Period MtM reversals (5) (65) 50 (65) 50
----------------------------------------------------------------------
Total net of MtM Impacts 178 136 634 331
----------------------------------------------------------------------
(1) Includes only Gladstone Equity Earnings; Flinders is reported as a
Discontinued Operation.
(2) Includes $67 million pre-tax gain for settlement with equipment
manufacturer in 2006.
(3) Includes interest and refinancing expenses of $313 million and
$115 million for 2006 and 2005, respectively.
(4) Represents a net domestic MtM gain of $67 million in 2006
(primarily in the Northeast and Texas regions) and a net domestic
MtM loss of $33 million in 2005, primarily in the Northeast
region.
(5) Represents the reversal of $65 million in 2006 associated with the
$119 million net domestic MtM losses recognized in 2005 and
reversal of $50 million in 2005 associated with the $59 million
net domestic MtM gain recognized in 2004, primarily the Northeast
region.
Texas: Lower than anticipated power prices realized on merchant energy sales from our gas fleet and the unhedged portion of our baseload fleet offset these results during the quarter and half year. Results benefited from continued strong operating performances from our baseload fleet, coupled with higher than expected generation from our Texas gas plants. This was largely driven by increased demand from hotter than normal weather and significant outages by other baseload power plants in the region. Amortization associated with net out-of-market contracts increased pre-tax operating results by $212 million and $225 million, for the quarter and year-to-date, respectively. Quarterly baseload plant operating performance was excellent at Limestone, Parish and the South Texas Project. Integration of the NRG Texas business continued throughout the second quarter and is on target for completion during the third quarter.
Northeast: Lower quarterly results for the Northeast, after adjusting for MtM impacts, were driven by weaker power prices and lower generation. Decreased demand, predominantly due to milder than expected weather, for our peaking assets resulted in lower generation hours from the oil-fired and intermediate gas-fired assets. Partially offsetting the lower demand was significantly improved equivalent forced outage rate performances from the Indian River, Huntley and Dunkirk plants, the reversal of a net $15 million station service reserve, and improved capacity pricing in New York. For the year-to-date, mild weather in the first quarter and continuing weak power prices were partially offset by sales of surplus emission allowances related to the reduced first quarter generation levels, and the improved operating performance and capacity prices.
South Central: Quarterly and year to-date results reflect higher net merchant sales at prices above contracted energy prices. Improved unit availability reduced the need to purchase power to service our long-term coop contracts. By contrast, during the second quarter of 2005, Big Cajun II experienced a number of unplanned outages which required us to purchase energy to serve contracted load.
Western: Improved quarterly results are largely attributable to the acquisition of Dynegy's 50 percent interest in West Coast Power (WCP), which closed March 31, 2006. The impact of the additional ownership is offset by lower reliability-must-run (RMR) fixed cost recovery by Encina units 4 and 5 and lower equity earnings from our Saguaro investment due to the June 2005 expiration of its favorable gas contract.
Australia: In June 2006, NRG announced it had entered into a purchase and sale agreement to sell its Flinders and Gladstone investments in Australia to Babcock & Brown and Transfield Services, respectively. Flinders has been reclassified as discontinued operations and excluded from income from continuing operations while Gladstone results continue to be reported as part of equity earnings of unconsolidated affiliates. Completion of the Flinders sale is expected in the third quarter and the Company is seeking to close the Gladstone sale later in the fourth quarter, subject to significant conditions precedent.
Other North America: Results for the quarter reflect our continuing efforts to monetize non-strategic assets. This quarter, we sold our interests in the James River and Cadillac equity investments for total cash proceeds of $19 million and a book gain of $11 million. Year-to-date results include other income of $67 million related to a settlement agreement reached with an equipment manufacturer associated with turbine purchase agreements from 1999 and 2001, and the Rocky Road sale.
Other International: Improved quarterly results were due to lower operating costs at our Itiquira operation in Brazil and increased equity earnings from our MIBRAG investment, the 2005 quarterly results of which were lower due to customers' planned outages. Additionally, we sold our interests in various Latin Power funds for net cash proceeds of $23 million and a pre-tax gain of $3 million. Year-on-year results are lower largely due to the impact of the sale of Enfield on April 1, 2005, which contributed $16 million to earnings during the first half 2005, partially offset by higher equity earnings from our MIBRAG investment.
MtM Impacts of Hedging and Trading Activities
The Company, in the normal course of business, enters into contracts to lock in forward prices for a significant portion of its expected power generation. While these transactions are predominantly economic hedges of our baseload portfolio, a portion of these forward sales are not afforded hedge accounting treatment and the MtM change in value of these transactions is recorded to current period earnings. Driving the forward MtM gains in the first quarter of 2006 was the unseasonably mild weather in the Northeast that resulted in lower energy prices for the first quarter with further declines in the second quarter. For the second quarter 2006, we recorded $37 million of forward domestic net MtM gains, compared to a $5 million net domestic MtM loss recorded in the second quarter 2005. In addition to this forward gain in the quarter, of the $119 million MtM loss recognized in 2005, $21 million reversed to income during the second quarter in 2006 and $65 million year-to-date.
Liquidity and Capital Resources
Table 2: Corporate Liquidity
($ in millions) June 30, March 31, December 31,
2006 2006(1) 2005(1)
----------------------------------------------------------------------
Unrestricted Cash: 957 818 $506
Restricted Cash: 58 67 64
----------------------------------------------------------------------
Total Cash 1,015 885 $570
Letter of Credit Availability 116 202 38
Revolver Availability 846 846 150
----------------------------------------------------------------------
Total Current Liquidity 1,977 1,933 $758
(1) These amounts have not been reclassified for discontinued
operations
Liquidity at June 30, 2006 was $1.98 billion, up $44 million since March 31, 2006 and approximately $1.2 billion since December 31, 2005. The $130 million cash increase during the quarter resulted from $238 million of cash from operations which included a reduction of $42 million in the amount of cash collateral posted to support trading operations, and $42 million in proceeds from asset sales. These improvements were offset by $72 million in cash interest payments, $39 million in capital expenditures, $46 million in principal debt repayments and $13 million in preferred dividend payments.
Posted cash collateral supporting hedging and trading activities at June 30, 2006 totaled $209 million, of which $135 million is expected to be returned to the Company during 2006 as the underlying trading positions settle during the year.
Capital Allocation -- Share Repurchase Program
The Company is announcing today a $750 million share repurchase program which, due to the restrictions imposed by our loan covenants, will be implemented in two phases. Phase One is a $500 million common share repurchase program which the Company intends to commence immediately and complete over the course of 2006. In addition, the sale of the Australian business is expected to provide approximately $400 million in net cash proceeds that NRG intends to use to pay down its Term B loan in the first quarter of 2007. Consolidated project level debt associated with Australia is $177 million, bringing total expected debt reduction to $577 million. Phase Two of the share repurchase plan -- which will be initiated after the expected step up in the Company's restricted payment capacity at the end of the first quarter 2007 -- is an additional $250 million common share buyback. The Company reserves the flexibility--based on market conditions at the time -- to reallocate all or a portion of Phase Two to the initiation of a common share dividend.
"The capital allocation program that we are announcing today has been carefully sized and structured to return significant capital to shareholders in the near term, reduce leverage at the corporate level, and retain financial flexibility to support the ongoing fleet redevelopment initiative," said Robert Flexon, NRG's Executive Vice President and Chief Financial Officer. "By focusing on a large buyback in the near term, we expect to be able to take maximum advantage of the significant undervaluation of our equity," added Flexon.
To execute the first phase of the share repurchase plan, within the limitations contained in the Company's credit agreement and bond indenture, the Company will form two wholly owned subsidiaries to hold the repurchased shares. The initial capitalization of the subsidiaries includes $166 million in cash from the NRG parent. Additionally, the subsidiaries will enter into non-recourse debt and preferred purchase agreements with units of Credit Suisse for an incremental $334 million -- funded through $250 million in debt and $84 million of preferred equity. Neither the debt nor the preferred will be recourse to NRG. The shares, which will be repurchased between now and year end, will serve as collateral for the debt. Periodic funding will be drawn pro rata from the subsidiary's $166 million in cash received from the parent and the $334 million in debt and preferred financings from Credit Suisse. The difference between the $334 million of facilities and the $400 million of maturities reflects accrued interest and dividends to be paid at maturity. Credit Suisse will retain the economic benefit of share price appreciation in excess of a 20 percent compound annual growth rate.
FORNRG -- Increased Targets
The Company is also announcing today the expansion and extension of the Focus on ROIC@NRG (FORNRG) program. NRG achieved $39 million of related savings in 2005 and expects to have cumulative savings of $81 million by year end 2006. With the addition of NRG Texas, the current target of $105 million improvement in EBITDA by 2008 is being increased to $200 million of recurring EBITDA improvement plus an additional $50 million of incremental cash benefit by 2009 recognizing:
-- continued benefits from improved reliability and reduced EFOR
results; and
-- cost synergies and purchasing related initiatives, which are
driving enhanced returns for NRG Texas.
Repowering Update -- Analyst Conference
On June 21, 2006, NRG announced a comprehensive portfolio redevelopment effort, which involves the development, financing, construction and operation of up to 10,500 megawatts (MW) of new multi-fuel, multi-technology generation capacity at NRG's existing domestic sites to meet the growing demand for (principally) non gas-fired generation in all of the Company's core domestic markets. NRG expects to provide additional detail with respect to this program at our first Analyst Conference to be held October 16-18, 2006.
Outlook
The Company is lowering 2006 adjusted EBITDA guidance from $1,600 million to $1,500 million to reflect:
-- The classification of Flinders as discontinued operations
(approximately $45 million)
-- Development expenses associated with Requests for Proposals
for several repowering and development initiatives
(approximately $10 million);
-- Mild weather in the first quarter; and
-- Lower power prices due to the steep decline in 2006 natural
gas prices.
Although 2006 natural gas calendar strip prices have declined over 30 percent from fourth quarter 2005 levels, the net impact on our previous 2006 adjusted EBITDA guidance is approximately three percent, demonstrating the benefit of our actively managed hedging program and our diverse asset base. Cash flow from operations guidance is being reduced from $1,380 million to $1,324 million. The reduction reflects an August close for the Flinders sale. Achieving our revised target remains dependent on several factors, including normally seasonal weather and stable power prices, particularly for the balance of the third quarter.
Table 3: 2006 Reconciliation of Adjusted EBITDA Guidance
($ in millions)
2006 guidance
Adjusted EBITDA (1) 1,500
MtM adjustment 116
-------------------
Adjusted EBITDA, including MtM 1,616
Interest payments (439)
Income tax (13)
Other funds used by operations (236)
Return of posted collateral 407
Working capital changes (11)
----
Cash flow from operations 1,324
(1) Adjusted EBITDA and cash flow from operations guidance reflects
100 percent ownership of WCP and the sale of Rocky Road.
Earnings Conference Call
On August 1, 2006, NRG will host a conference call at 9:00 a.m. eastern to discuss these results. To access the live web cast and accompanying slide presentation, log on to NRG's website at http://www.nrgenergy.com and click on "Investors." To participate in the call, dial 877-407-8035. International callers should dial 201-689-8035. Participants should dial in or log on approximately five minutes prior to the scheduled start time.
The call will be available for replay shortly after completion of the live event on the "Investors" section of the NRG website.
About NRG
NRG Energy, Inc. now owns and operates a diverse portfolio of power-generating facilities, primarily in Texas and the Northeast, South Central and Western regions of the United States. Its operations include baseload, intermediate, peaking, and cogeneration facilities, thermal energy production and energy resource recovery facilities. NRG also has ownership interests in generating facilities in Australia and Germany.
Safe Harbor Disclosure
This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to certain risks, uncertainties and assumptions and include our Adjusted EBITDA and Cash Flow from Operations guidance, expected earnings, future growth and financial performance, expected results of the NRG Texas and WCP integration processes, and the expected timing of sales of our assets in Australia, and the expected benefits and timing of the capital allocation program and typically can be identified by the use of words such as "will," "expect," "estimate," "anticipate," "forecast," "plan," "believe" and similar terms. Although NRG believes that its expectations are reasonable, it can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated above include, among others, general economic conditions, hazards customary in the power industry, weather conditions, competition in wholesale power markets, the volatility of energy and fuel prices, failure of customers to perform under contracts, changes in the wholesale power markets, changes in government regulation of markets and of environmental emissions, the condition of capital markets generally, our ability to access capital markets, unanticipated outages at our generation facilities, our ability to convert facilities to use western coal successfully, adverse results in current and future litigation, the inability to implement value enhancing improvements to plant operations and companywide processes, our ability to achieve the benefits from the NRG Texas and WCP integration efforts, our inability to close the sales of Australia assets as described herein, and our ability to achieve the expected benefits of the capital allocation program.
NRG undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The adjusted EBITDA guidance and cash flow from operations are estimates as of today's date, August 1, 2006 and is based on assumptions believed to be reasonable as of this date. NRG expressly disclaims any current intention to update such guidance. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in the forward-looking statements included in this news release should be considered in connection with information regarding risks and uncertainties that may affect NRG's future results included in NRG's filings with the Securities and Exchange Commission at www.sec.gov.
More information on NRG is available at www.nrgenergy.com
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three months Six months
ended June 30 ended June 30
----------------------------
(In millions, except for per share
amounts) 2006 2005 2006 2005
----------------------------------------------------------------------
Operating Revenues
Revenues from majority-owned operations $1,423 $ 522 $2,513 $1,070
----------------------------------------------------------------------
Operating Costs and Expenses
Cost of majority-owned operations 746 387 1,447 796
Depreciation and amortization 178 41 297 83
General, administrative and development 83 50 143 97
Corporate relocation charges -- 1 -- 4
----------------------------------------------------------------------
Total operating costs and expenses 1,007 479 1,887 980
----------------------------------------------------------------------
Operating Income 416 43 626 90
----------------------------------------------------------------------
Other Income (Expense)
Equity in earnings of unconsolidated
affiliates 8 16 29 53
Write downs and gains on sales of equity
method investments 14 12 11 12
Other income, net 8 6 88 31
Refinancing expense -- -- (178) (35)
Interest expense (152) (46) (266) (98)
----------------------------------------------------------------------
Total other expense (122) (12) (316) (37)
----------------------------------------------------------------------
Income From Continuing Operations Before
Income Taxes 294 31 310 53
Income Tax Expense 90 8 89 14
----------------------------------------------------------------------
Income From Continuing Operations 204 23 221 39
Income/(loss) from discontinued operations,
net of income tax expense/(benefit) (1) 1 8 8
----------------------------------------------------------------------
Net Income 203 24 229 47
Dividends for Preferred Shares 13 4 23 8
----------------------------------------------------------------------
Income Available for Common Stockholders $ 190 $ 20 $ 206 $ 39
----------------------------------------------------------------------
Weighted Average Number of Common Shares
Outstanding -- Basic 137 87 127 87
Income From Continuing Operations per
Weighted Average Common Share -- Basic $ 1.39 $0.22 $ 1.55 $ 0.35
Income/(loss) From Discontinued Operations
per Weighted Average Common Share
-- Basic (0.01) 0.01 0.06 0.09
----------------------------------------------------------------------
Net Income per Weighted Average Common
Share -- Basic $ 1.38 $0.23 $ 1.61 $ 0.44
----------------------------------------------------------------------
Weighted Average Number of Common Shares
Outstanding -- Diluted 159 88 148 88
Income From Continuing Operations per
Weighted Average Common Share -- Diluted $ 1.26 $0.21 $ 1.47 $ 0.34
Income/(loss) From Discontinued Operations
per Weighted Average Common Share
-- Diluted -- 0.01 0.05 0.09
----------------------------------------------------------------------
Net Income per Weighted Average Common
Share -- Diluted $ 1.26 $0.22 $ 1.52 $ 0.43
----------------------------------------------------------------------
See notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30, December 31,
2006 2005
----------------------
(in millions, except shares and par value) (unaudited)
----------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $ 957 $ 493
Restricted cash 58 49
Accounts receivable, less allowance for
doubtful accounts of $2 and $2 473 259
Inventory 402 242
Derivative instruments valuation 528 387
Collateral on deposits in support of energy
risk and management activities 209 438
Prepayments and other current assets 187 188
Current assets - held-for-sale -- 43
Current assets -- discontinued operations 96 98
----------------------------------------------------------------------
Total current assets 2,910 2,197
----------------------------------------------------------------------
Property, plant and equipment, net of
accumulated depreciation of $668 and $343 11,815 2,620
----------------------------------------------------------------------
Other Assets
Equity investments in affiliates 307 603
Notes receivable, less current portion 480 458
Goodwill 1,462 --
Intangible assets, net of accumulated
amortization of $131 and $79 1,182 257
Nuclear decommissioning trust fund 326 --
Derivative instruments valuation 191 18
Funded letter of credit -- 350
Deferred income taxes 42 26
Other non-current assets 242 124
Intangible assets held-for-sale 66 --
Non-current assets - discontinued operations 419 813
----------------------------------------------------------------------
Total other assets 4,717 2,649
----------------------------------------------------------------------
Total Assets $ 19,442 $7,466
----------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital
leases $ 125 $ 95
Accounts payable 340 247
Derivative instruments valuation 640 679
Accrued expenses and other current
liabilities 467 174
Current liabilities -- discontinued
operations 58 162
----------------------------------------------------------------------
Total current liabilities 1,630 1,357
----------------------------------------------------------------------
Other Liabilities
Long-term debt and capital leases 7,631 2,410
Nuclear decommissioning reserve 226 --
Nuclear decommissioning trust liability 325 --
Deferred income taxes 152 129
Derivative instruments valuation 398 56
Out-of-market contracts 2,320 298
Other non-current liabilities 378 170
Non-current liabilities -- discontinued
operations 278 568
----------------------------------------------------------------------
Total non-current liabilities 11,708 3,631
----------------------------------------------------------------------
Total Liabilities 13,338 4,988
----------------------------------------------------------------------
Minority Interest 1 1
3.625% Convertible perpetual preferred
stock (at liquidation value, net of
issuance costs) 246 246
Commitments and Contingencies
Stockholders' Equity
Preferred stock (at liquidation value, net of
issuance costs) 892 406
Common Stock; $.01 par value; 500,000,000
shares authorized; 136,979,082 and
80,701,888 outstanding 1 1
Additional paid-in capital 4,454 2,431
Retained earnings 374 261
Less treasury stock, at cost -- 0 and
19,346,788 shares -- (663)
Accumulated other comprehensive income/(loss) 136 (205)
----------------------------------------------------------------------
Total stockholders' equity 5,857 2,231
----------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 19,442 $7,466
----------------------------------------------------------------------
See notes to condensed consolidated financial statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six months
ended June 30,
---------------
(In millions) 2006 2005
----------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $ 229 $ 47
Adjustments to reconcile net income to net cash
provided by operating activities
Distributions in excess of equity in earnings of
unconsolidated affiliates (13) 16
Depreciation and amortization 308 96
Amortization of financing costs and debt discount 16 5
Amortization of intangibles and out-of-market
contracts (211) 15
Amortization of unearned equity compensation 9 5
Write-off of deferred financing costs and debt
premium 47 (8)
Write down and (gains)/losses on sale of equity
method investments (11) (12)
Deferred income taxes 96 (4)
Nuclear decommissioning trust liability 3 --
Minority interest -- 1
Loss on sale of equipment 3 --
Unrealized (gains)/losses on derivatives (114) 82
Gain on legal settlement (67) (14)
Gain on sale of discontinued operations (10) --
Gain on sale of emission allowances (67) --
Collateral deposit payments in support of energy
risk management activities 272 (179)
Cash provided by changes in other working capital,
net of acquisition and disposition affects 114 41
----------------------------------------------------------------------
Net Cash Provided by Operating Activities 604 91
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, net of cash acquired (4,303) --
Acquisition of WCP, net of cash acquired (25) --
Decrease/(Increase) in restricted cash and trust
funds, net (9) 26
Decrease in notes receivable 14 93
Investments in nuclear decommissioning trust fund
securities (106) --
Purchases of emission allowances (78) --
Sales of emission allowances 84 --
Proceeds from sale of equipment 1 --
Proceeds on sale of investments 86 65
Proceeds on sale of discontinued operations 15 --
Proceeds from sales of nuclear decommissioning trust
fund securities 103 --
Return of capital from (investments in) equity method
investments and projects -- 1
Capital expenditures (74) (37)
----------------------------------------------------------------------
Net Cash Provided by Investing Activities (4,292) 148
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders (23) (8)
Funded letter of credit 350 --
Issuance of common stock, net of issuance costs 986 --
Issuance of preferred shares, net of issuance costs 486 --
Deferred debt issuance costs (164) (1)
Proceeds from issuance of long-term debt, net 7,175 204
Principal payments on short and long-term debt (4,662) (722)
----------------------------------------------------------------------
Net Cash Used by Financing Activities 4,148 (527)
----------------------------------------------------------------------
Change in Cash from Discontinued Operations 1 (3)
Effect of Exchange Rate Changes on Cash and Cash
Equivalents 3 (1)
----------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 464 (292)
Cash and Cash Equivalents at Beginning of Period 493 1,071
----------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 957 $ 779
----------------------------------------------------------------------
See notes to condensed consolidated financial statements.
Appendix Table A-1: Second Quarter 2006 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and
provides a reconciliation to net income/(loss)
South
(dollars in millions) Texas Northeast Central Western
-----------------------------------------------------------------
Net Income (Loss) 256 51 (6) 8
=================================================================
Plus:
Income Tax 36 - - -
Interest Expense 38 15 9 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - - 1 -
Depreciation Expense 131 22 15 1
Amortization of Power
Contracts (225) - (5) -
Amortization of Fuel Contracts 11 - - -
Amortization of Emission
Credits 6 2 1 -
-----------------------------------------------------------------
EBITDA 253 90 15 9
(Income) Loss from
Discontinued Operations - - - -
Write-Down and (Gain)/Losses
on Sales of Equity Method
Investments - - - -
Acquisition Integration Costs - - - -
Station Service Reserve
Reversal - (15) - -
Mirant Defense - - - -
-----------------------------------------------------------------
Adjusted EBITDA 253 75 15 9
Other
(dollars in millions) Other NA Australia Int'l Other Total
---------------------------------------------------------------------
Net Income (Loss) 2 3 13 (124) 203
=====================================================================
Plus:
Income Tax - 1 3 50 90
Interest Expense 3 - 2 77 144
Amortization of Finance Costs - - - 6 6
Amortization of Debt
(Discount)/Premium 1 - - - 2
Depreciation Expense 2 - - 7 178
Amortization of Power
Contracts - - - - (230)
Amortization of Fuel Contracts - - - - 11
Amortization of Emission
Credits - - - - 9
---------------------------------------------------------------------
EBITDA 8 4 18 16 413
(Income) Loss from
Discontinued Operations (1) 2 - - 1
Write-Down and (Gain)/Losses
on Sales of Equity Method
Investments (11) - (3) - (14)
Acquisition Integration Costs - - - 5 5
Station Service Reserve
Reversal - - - - (15)
Mirant Defense - - - 6 6
---------------------------------------------------------------------
Adjusted EBITDA (4) 6 15 27 396
Appendix Table A-1: Second Quarter 2005 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and
provides a reconciliation to net income/(loss)
South
(dollars in millions) Northeast Central Western
----------------------------------------------------------------
Net Income (Loss) 39 (7) 6
================================================================
Plus:
Income Tax - - -
Interest Expense - 1 -
Amortization of Finance Costs - - -
Amortization of Debt
(Discount)/Premium - 1 -
Depreciation Expense 18 15 -
Amortization of Power Contracts - (3) -
Amortization of Emission Credits 2 1 -
----------------------------------------------------------------
EBITDA 59 8 6
(Income) Loss from Discontinued
Operations - - -
Write-Down and (Gain)/Losses on
Sales of Equity Method
Investments - - -
----------------------------------------------------------------
Adjusted EBITDA 59 8 6
Other
(dollars in millions) Other NA Australia Int'l Other Total
----------------------------------------------------------------------
Net Income (Loss) (5) 4 19 (32) 24
======================================================================
Plus:
Income Tax 1 1 4 2 8
Interest Expense 4 - 1 38 44
Amortization of Finance Costs - - - 1 1
Amortization of Debt
(Discount)/Premium 1 - - (1) 1
Depreciation Expense 1 - 1 6 41
Amortization of Power Contracts 2 - - - (1)
Amortization of Emission Credits - - - - 3
----------------------------------------------------------------------
EBITDA 4 5 25 14 121
(Income) Loss from Discontinued
Operations (2) 1 - - (1)
Write-Down and (Gain)/Losses on
Sales of Equity Method
Investments - - (12) - (12)
----------------------------------------------------------------------
Adjusted EBITDA 2 6 13 14 108
Appendix Table A-2: YTD 2006 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and
provides a reconciliation to net income/(loss)
South
(dollars in millions) Texas Northeast Central Western
-----------------------------------------------------------------
Net Income (Loss) 274 183 29 6
=================================================================
Plus:
Income Tax 11 - - (2)
Interest Expense 64 34 19 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - - 1 -
Refinancing Expense - - - -
Depreciation Expense 205 44 30 1
Amortization of Power
Contracts (263) - (8) -
Amortization of Fuel Contracts 37 - - -
Amortization of Emission
Credits 17 9 3 -
-----------------------------------------------------------------
EBITDA 345 270 74 5
(Income) loss from Discontinued
Operations - - - -
Write-Down and (Gain)/Losses
on Sales of Equity Method
Investments - - - -
Bourbonnais Legal Settlement - - - -
Acquisition Integration Costs - - - -
Audrain Bad Debt Reserve - - - -
Station Service Reserve
Reversal - (15) - -
Mirant Defense - - - -
-----------------------------------------------------------------
Adjusted EBITDA 345 255 74 5
Other
(dollars in millions) Other NA Australia Int'l Other Total
---------------------------------------------------------------------
Net Income (Loss) 68 8 30 (369) 229
=====================================================================
Plus:
Income Tax 1 3 10 66 89
Interest Expense 7 - 4 125 253
Amortization of Finance Costs - - - 10 10
Amortization of Debt
(Discount)/Premium 2 - - - 3
Refinancing Expense - - - 178 178
Depreciation Expense 4 - 1 12 297
Amortization of Power
Contracts - - - - (271)
Amortization of Fuel Contracts - - - - 37
Amortization of Emission
Credits - - - (2) 27
---------------------------------------------------------------------
EBITDA 82 11 45 20 852
(Income) loss from Discontinued
Operations (9) 1 - - (8)
Write-Down and (Gain)/Losses
on Sales of Equity Method
Investments (8) - (3) - (11)
Bourbonnais Legal Settlement (67) - - - (67)
Acquisition Integration Costs - - - 7 7
Audrain Bad Debt Reserve - - - 2 2
Station Service Reserve
Reversal - - - - (15)
Mirant Defense - - - 6 6
---------------------------------------------------------------------
Adjusted EBITDA (2) 12 42 35 766
Appendix Table A-2: YTD 2005 Regional EBITDA Reconciliation
The following table summarizes the calculation of adjusted EBITDA and
provides a reconciliation to net income/(loss)
South
(dollars in millions) Northeast Central Western
----------------------------------------------------------------
Net Income (Loss) 72 2 9
================================================================
Plus:
Income Tax - - -
Interest Expense - 4 -
Amortization of Finance Costs - - -
Amortization of Debt
(Discount)/Premium - 1 -
Refinancing Expense - - -
Depreciation Expense 37 30 -
Amortization of Power Contracts - (6) -
Amortization of Emission Credits 3 3 -
----------------------------------------------------------------
EBITDA 112 34 9
(Income) from Discontinued
Operations - - -
Corporate Relocation charges - - -
Write-Down and (Gain)/Losses on
Sales of Equity Method
Investments - - -
Proceeds Received from Crockett
Contingency - - -
Gain on TermoRio Settlement - - -
----------------------------------------------------------------
Adjusted EBITDA 112 34 9
Other
(dollars in millions) Other NA Australia Int'l Other Total
----------------------------------------------------------------------
Net Income (Loss) (10) 14 61 (101) 47
======================================================================
Plus:
Income Tax 1 3 8 2 14
Interest Expense 7 - 4 78 93
Amortization of Finance Costs - - - 3 3
Amortization of Debt
(Discount)/Premium 2 - - (1) 2
Refinancing Expense - - - 35 35
Depreciation Expense 3 - 2 11 83
Amortization of Power Contracts 5 - - - (1)
Amortization of Emission Credits - - - - 6
----------------------------------------------------------------------
EBITDA 8 17 75 27 282
(Income) from Discontinued
Operations (3) (5) - - (8)
Corporate Relocation charges - - - 4 4
Write-Down and (Gain)/Losses on
Sales of Equity Method
Investments - - (12) - (12)
Proceeds Received from Crockett
Contingency (4) - - - (4)
Gain on TermoRio Settlement - - (14) - (14)
----------------------------------------------------------------------
Adjusted EBITDA 1 12 49 31 248
EBITDA, adjusted EBITDA and adjusted net income are nonGAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of adjusted EBITDA and adjusted net income should not be construed as an inference that NRG's future results will be unaffected by unusual or non-recurring items.
EBITDA represents net income before interest, taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:
-- EBITDA does not reflect cash expenditures, or future
requirements for capital expenditures, or contractual
commitments;
-- EBITDA does not reflect changes in, or cash requirements
for, working capital needs;
-- EBITDA does not reflect the significant interest expense,
or the cash requirements necessary to service interest or
principal payments, on debts;
-- Although depreciation and amortization are non-cash
charges, the assets being depreciated and amortized will
often have to be replaced in the future, and EBITDA does
not reflect any cash requirements for such replacements;
and
-- Other companies in this industry may calculate EBITDA
differently than NRG does, limiting its usefulness as a
comparative measure.
Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG's business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release.
Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for reorganization, restructuring, impairment and corporate relocation charges, discontinued operations, and write downs and gains or losses on the sales of equity method investments; factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.
Similar to adjusted EBITDA, adjusted net income represents net income adjusted for reorganization, restructuring, impairment and corporate relocation charges, discontinued operations, and write downs and gains or losses on the sales of equity method investments; factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. In addition, in evaluating adjusted net income, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.
CONTACT: NRG Energy, Inc.
Meredith Moore, 609-524-4522 (Media)
or
Nahla Azmy, 609-524-4526 (Investors)
or
Kevin Kelly, 609-524-4527 (Investors)
or
Jon Baylor, 609-524-4528 (Investors)
SOURCE: NRG Energy, Inc.