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NRG Energy, Inc. Reports First Quarter 2007 Results; Increases 2007 EBITDA Guidance; and Announces Comprehensive Capital Allocation Plan
First Quarter Financial Highlights:
-- $508 million of adjusted EBITDA, excluding mark-to-market (MtM) impacts;
-- $106 million of cash flow from operations, including $120 million cash collateral outflow;
-- Repurchased 1.5 million common shares for $103 million; and
-- Raising guidance for adjusted EBITDA from $2,050 to $2,150 million and cash flow from operations from $1,359 to $1,398 million.
Comprehensive Capital Allocation Plan:
-- Two for one common stock split for holders of record as of May 22, 2007;
-- Common share dividend of $0.50 per share (adjusted for the stock split) planned for first quarter 2008;
-- Continuation of remaining $165 million of current share repurchase plan plus capacity for future common share buybacks;
-- Senior credit agreement to be re-priced and amended; and
-- Formation of an NRG holding company, to facilitate the ongoing return of capital to shareholders.
NRG Energy, Inc. (NYSE:NRG) today reported income from continuing operations for the three months ended March 31, 2007 of $65 million or $0.41 per diluted common share, compared to $15 million or $0.04 per diluted common share for the first quarter of last year. The 2007 improvement primarily resulted from the inclusion of three months of operating results for NRG Texas, which was acquired by NRG in February 2006, increased generation and pricing in the Northeast region, and $107 million in after-tax refinancing expenses in 2006 associated with the acquisition of NRG Texas. MtM changes, primarily associated with economic hedges on our baseload assets, unfavorably impacted net income in 2007 by $55 million while benefiting 2006 earnings by $44 million.
Quarterly cash flow from operations of $106 million was impacted by $120 million of cash collateral outflows. First quarter 2006 adjusted operating cash flow of $313 million benefited from $230 million of collateral inflows. Operating cash flows, exclusive of collateral movements, increased by $143 million versus the same period last year. This improvement reflects NRG Texas' contributions for the entire quarter in 2007. In addition, current year cash flow from operations benefited from $39 million in higher contract prices that resulted from last November's hedge reset transaction.
"Over the past 3 1/2 years, our continuous focus on executing a multi-faceted growth plan off a foundation of strong commercial and plant operations has brought NRG to a much stronger place financially and strategically," said David Crane, NRG President and Chief Executive Officer. "NRG's operational effectiveness and the promise of our ongoing growth initiatives have put us in the position where we can both initiate a recurring cash dividend and generate the capital to reinvest in our business through RepoweringNRG and other core initiatives."
Regional Segment Review of Results
Table 1: Three Months Income from Continuing Operations and Adjusted EBITDA
($ in millions) Income (Loss) from Adjusted EBITDA
Continuing
Operations
before Taxes
----------------------------------------------------------------------
Three months ending 3/31/07 3/31/06 3/31/07 3/31/06
----------------------------------------------------------------------
Texas 113 (7) 251 93
Northeast 38 132 77 181
South Central 10 28 35 58
West 5 (4) 5 (4)
International 24 31 32 34
Thermal 23 4 10 9
Corporate and Eliminations (1) (92) (170) 7 (3)
----------------------------------------------------------------------
Total 121 14 417 368
----------------------------------------------------------------------
Less: MtM forward position
accruals (2) (79) 37 (79) 37
Add: Prior Period MtM reversals
(3) 56 (44) 56 (44)
Less: Hedge ineffectiveness (4) 44 (8) 44 (8)
----------------------------------------------------------------------
Total net of MtM Impacts 212 (59) 508 295
----------------------------------------------------------------------
(1) Includes interest and refinancing expenses of $98 million and $227 million for 2007 and 2006, respectively. Results in 2006 also include a $67 million gain related to a settlement agreement.
(2) Represents a net domestic MtM loss of $79 million in 2007 (primarily in the Northeast and Texas regions) and a net domestic MtM gain of $37 million in 2006, primarily in the Northeast region.
(3) Represents the reversal of $56 million in 2007 associated with the $172 million net domestic MtM gains recognized in 2006 and reversal of $44 million in 2006 associated with the $119 million net domestic MtM losses recognized in 2005.
(4) NRG also hedges power prices using natural gas contracts. To the extent gas and power prices are not correlated, the ineffectiveness is included in the MtM results (primarily Texas).
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. Although 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. For the first quarter 2007, we recorded $79 million of forward domestic net MtM loss representing the decrease in fair value of forward sales contracts of electricity and fuel, compared to a $37 million net domestic MtM gain recorded in the first quarter 2006. The MtM impacts from hedging activities also included a $44 million gain from hedge ineffectiveness related to the Company's Texas region due to a change in correlation between natural gas and power prices.
Texas: Operating results benefited from the full quarter in 2007 versus two months in 2006 as NRG Texas operations contributed $51 million of pre-tax operating income and $100 million of EBITDA in January 2007 alone. Improved operations and lower forced outage rates from the baseload fleet during the comparable period led to a $39 million reduction in purchased power expenses during 2007. Current quarter EBITDA and cash flow from operations benefited $39 million from the November 2006 hedge reset which increased contracted power prices.
Northeast: Quarter-over-quarter results for the Northeast, after adjusting for MtM impacts, achieved improvement in income from continuing operations and adjusted EBITDA, respectively. Increased demand and power prices were driven by more seasonable weather patterns that resulted in higher generation hours from our oil-fired peaking assets and baseload coal assets which led to a $49 million, or 22%, increase in energy revenues. Capacity revenues for the three-month period increased 43% to $83 million, reflecting higher capacity prices in the New York and Connecticut markets. Partially offsetting these improvements were higher than expected outage rates at certain units and lower sales of excess emission credits. Higher generation levels combined with a 59% decrease in SO(2) emission credit market prices led to the $61 million decline in excess credit sales.
South Central: Income from continuing operations for the quarter declined by $18 million in comparison to the region's strong performance in 2006. Increased demand from load serving customers combined with lower availability from the Big Cajun II coal plant reduced megawatts available for sale into the merchant energy market. Revenue from energy sold to contract customers increased by $17 million, while merchant revenues declined by $38 million. Reduced unit availability due to planned outages contributed to a 3% decline in generation. A new summer peak demand record was set in 2006 which reset and increased capacity payments.
West: Results for 2007 reflect the acquisition of Dynegy, Inc.'s 50% interest in West Coast Power (WCP), which closed on March 31, 2006. Regional operating results also improved as capacity revenues were favorably impacted by new tolling agreements executed by our Encina and El Segundo units after the acquisition date.
Thermal: Current year results included an $18 million pre-tax gain from the January 2007 sale of our Red Bluff and Chowchilla, California generation assets.
Corporate: First quarter 2006 results included other income of $67 million related to a settlement agreement reached with an equipment manufacturer associated with turbine purchase agreements from 1999 and 2001. Last year also included $178 million of refinancing expenses associated with the Texas Genco acquisition.
Liquidity and Capital Resources
Table 2: Corporate Liquidity
($ in millions) March 31, December 31, March 31,
2007 2006(1) 2006(1)
----------------------------------------------------------------------
Unrestricted Cash 655 795 818
Restricted Cash 49 44 67
----------------------------------------------------------------------
Total Cash 704 839 885
Letter of Credit Availability 546 533 202
Revolver Availability 822 855 846
----------------------------------------------------------------------
Total Current Liquidity $2,072 $2,227 $1,933
(1) These amounts have not been restated for discontinued operations
Liquidity at March 31, 2007 was approximately $2.1 billion, down $155 million since December 31, 2006. The $135 million cash decrease during the quarter resulted from $106 million of cash from operations inclusive of $120 million in collateral outflows and $114 million used to fund seasonal movements in working capital. Investing activities included $29 million in proceeds from the sale of Red Bluff and Chowchilla and $107 million in capital expenditures. Financing activities included $103 million in cash used for common share purchases, $19 million in scheduled principal debt repayments and $14 million in preferred dividend payments.
RepoweringNRG Update
Plants under Development
The originally planned RepoweringNRG development initiative continues on track. During the first quarter, a number of RepoweringNRG projects made progress in permitting, site planning and other critical development activities. However, some RepoweringNRG projects, including projects in Connecticut and in Delaware are less likely to move forward as they have not been successful to date in winning offtake mandates offered as part of requests for proposals sponsored by these states.
Plants under Construction
260 MW of repowered gas-fueled capacity at NRG's Long Beach Generating Station remains on schedule to be online by August 1, 2007 to support the anticipated summer peak on the Southern California Edison and California Independent System Operator systems. Total cash costs for the project are expected to be approximately $73 million, with $22 million of capital expenditures incurred during this year's first quarter. In addition to the Long Beach project, the Company is proceeding with the repowering project at the Cos Cob site in Connecticut. The project will add 40 megawatts of peaking capacity at a cash cost of $18 million.
Development Expenses
During the first quarter 2007, NRG incurred approximately $23 million in costs associated with our development efforts across all business units, but predominantly in Texas, to support the planned STP nuclear generating station expansion as we prepare to submit the combined operating license application to the Nuclear Regulatory Commission.
Comprehensive Capital Allocation Plan
With the successful implementation of its hedging strategy, the Company has created a strong and stable earnings and cash flow profile. As a result, the Company is pursuing a refinancing plan along with amendments to its Senior Credit facility to support and facilitate its capital allocation strategy. Under the planned refinancing, NRG will become a wholly owned operating company subsidiary ("Opco") of a newly created holding company ("Holdco"). Holdco will borrow up to $1 billion from the Term B market and pay the net proceeds to Opco as an equity contribution. Opco will use the net proceeds for the prepayment of a portion of its existing Term B loan resulting in no change to the Company's consolidated debt levels. Upon completion, the restricted payments capacity under the Company's high yield bond indentures will increase by an amount equal to the equity contribution from Holdco to Opco.
Planned amendments to the Senior Credit Facility include a reduction in pricing, a $150 million per year carve out enabling a recurring common share cash dividend, additional flexibility to invest in RepoweringNRG projects, and a commitment from the lenders to fund the Holdco loan. The Company has obtained commitments for the Holdco financing from a number of financial institutions.
Further, in order to provide additional liquidity to the Company's common stock, the Company's Board of Directors has approved a 2-for-1 stock split effected in the form of a stock dividend payable on May 31, 2007. The stock split will entitle each stockholder of record at the close of business on May 22, 2007, to receive one additional share for every common share held. The number of common shares outstanding upon completion of the stock split will be approximately 242 million shares, excluding the impact of any additional share repurchases which may be completed by the Company.
Contingent upon the successful implementation of the Holdco financing, which requires certain regulatory approvals, and sufficient cash resources the Company plans to commence an annual common share cash dividend of $0.50 per share, paid quarterly beginning in the first quarter 2008. In addition to the cash dividend, the Company plans to continue with common share repurchase programs from time to time even after the completion of the current share buyback. In light of the Company's projected earnings and cash flow profile, the Company plans to target an annual return of capital to shareholders, consisting of both fixed (dividend) and variable (share repurchase) components, of approximately 3% per annum. In connection with the Company's previously announced share repurchase program, $103 million of common share repurchases were completed during the first quarter 2007 at an average price of $68.74 per share, leaving $165 million of authorized repurchases to be completed. The Company expects to complete the remaining share repurchases in 2007.
"The Capital Allocation Plan announced today reflects steadfast confidence in our business model and our unwavering commitment to capital discipline," commented Robert C. Flexon, NRG's Executive Vice President and Chief Financial Officer. "All elements of our capital allocation philosophy--reinvestment, debt management, returning capital to shareholders, and RepoweringNRG--are covered by this plan."
Outlook
The Company is raising 2007 adjusted EBITDA guidance from $2,050 million to $2,150 million and cash flow from operations guidance from $1,359 to $1,398 million to reflect the first quarter performance, improving power prices and margins, and higher equity earnings due to the delay in the sale of Gladstone. Free cash flow guidance is being increased from $879 million to $893 million. Not all of the adjusted EBITDA guidance increase will flow through cash as a result of cash collateral outflows that increased as the Company posted $25 million in cash to support hedges which settle primarily in 2008. In addition, funds used for working capital are projected to increase mainly due to voluntary pension funding in connection with recent pension legislation. Capital expenditure estimates increased $18 million across the regions to support ongoing maintenance and by $7 million in connection with our Cos Cob, Connecticut repowering.
Table 3: 2007 Reconciliation of Adjusted EBITDA Guidance ($ in millions)
5/02/07 2/28/07
Adjusted EBITDA, including MTM $2,356 $2,221
MtM adjustment 206 171
-------- --------
Adjusted EBITDA Guidance 2,150 2,050
Interest payments (624) (634)
Income tax (15) (15)
Collateral payments (71) (49)
Working capital/other changes (42) 7
-------- --------
Cash flow from operations $1,398 $1,359
Capital Expenditures:
Maintenance and environmental (370) (352)
RepoweringNRG (80) (73)
Preferred Dividends (55) (55)
-------- --------
Free cash flow $893 $879
Earnings Conference Call
On May 2, 2007, 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 866.584.6398. International callers should dial 416.849.9626. 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
A Fortune 500 company, NRG Energy, Inc. owns and operates a diverse portfolio of power-generating facilities, primarily in Texas and the Northeast, South Central and West regions of the United States. Its operations include baseload, intermediate, peaking, and cogeneration and thermal energy production facilities. NRG also has ownership interests in generating facilities in Australia, Germany and Brazil.
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, cash flow from operations and free cash flow guidance, the timing and completion of RepoweringNRG projects, our Comprehensive Capital Allocation Plan, expected earnings, future growth and financial performance, 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, adverse results in current and future litigation, the inability to implement value enhancing improvements to plant operations and companywide processes, and our ability to achieve the expected benefits and timing of our RepoweringNRG projects and our Comprehensive Capital Allocation Plan.
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, May 2, 2007 and are 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)
(In millions except per share amounts)
Three months ended March 31, 2007 2006
----------------------------------------------------------------------
Operating Revenues
Total operating revenues $1,310 $1,043
----------------------------------------------------------------------
Operating Costs and Expenses
Cost of operations 784 659
Depreciation and amortization 161 118
General and administrative 86 57
Development costs 23 --
----------------------------------------------------------------------
Total operating costs and expenses 1,054 834
Gain on sale of assets 17 --
----------------------------------------------------------------------
Operating Income 273 209
----------------------------------------------------------------------
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates 13 21
Write down of equity method investments -- (3)
Other income, net 16 80
Refinancing expenses -- (178)
Interest expense (181) (115)
----------------------------------------------------------------------
Total other expenses (152) (195)
----------------------------------------------------------------------
Income From Continuing Operations Before Income Taxes 121 14
Income tax expense/(benefit) 56 (1)
----------------------------------------------------------------------
Income From Continuing Operations 65 15
Income on Discontinued Operations, net of Income
Taxes -- 11
----------------------------------------------------------------------
Net Income $65 $26
Preference stock dividends 14 10
----------------------------------------------------------------------
Income Available for Common Stockholders $51 $16
----------------------------------------------------------------------
Weighted Average Number of Common Shares Outstanding
-- Basic 122 117
Income From Continuing Operations
per Weighted Average Common Share -- Basic $0.42 $0.04
Income From Discontinued Operations
per Weighted Average Common Share -- Basic -- 0.09
Net Income per Weighted Average Common Share -- Basic 0.42 0.13
Weighted Average Number of Common Shares Outstanding
-- Diluted 135 119
Income From Continuing Operations
per Weighted Average Common Share -- Diluted 0.41 0.04
Income From Discontinued Operations
per Weighted Average Common Share -- Diluted -- 0.09
Net Income per Weighted Average Common Share --
Diluted $0.41 $0.13
----------------------------------------------------------------------
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2007 2006
-------------------------
(in millions, except shares and par value) (unaudited)
----------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents $655 $795
Restricted cash 49 44
Accounts receivable, less allowance for
doubtful accounts of $1 and $1 409 372
Inventory 400 421
Derivative instruments valuation 854 1,230
Deferred income taxes 43 --
Prepayments and other current assets 259 221
----------------------------------------------------------------------
Total current assets 2,669 3,083
----------------------------------------------------------------------
Property, plant and equipment, net of
accumulated depreciation of $1,159 and $984 11,521 11,600
----------------------------------------------------------------------
Other Assets
Equity investments in affiliates 361 344
Notes receivable and capital lease, less
current portion 476 479
Goodwill 1,787 1,789
Intangible assets, net of accumulated
amortization of $292 and $259 958 981
Nuclear decommissioning trust fund 357 352
Derivative instruments valuation 187 439
Deferred income taxes 27 27
Other non-current assets 256 262
Intangible assets held-for-sale 112 79
----------------------------------------------------------------------
Total other assets 4,521 4,752
----------------------------------------------------------------------
Total Assets $18,711 $19,435
----------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and
capital leases $129 $130
Accounts payable 295 332
Derivative instruments valuation 824 964
Deferred income taxes -- 164
Accrued expenses and other current
liabilities 320 442
----------------------------------------------------------------------
Total current liabilities 1,568 2,032
----------------------------------------------------------------------
Other Liabilities
Long-term debt and capital leases 8,637 8,647
Nuclear decommissioning reserve 280 289
Nuclear decommissioning trust liability 335 324
Deferred income taxes 623 554
Derivative instruments valuation 418 351
Out-of-market contracts 839 897
Other non-current liabilities 437 435
----------------------------------------------------------------------
Total non-current liabilities 11,569 11,497
----------------------------------------------------------------------
Total Liabilities 13,137 13,529
----------------------------------------------------------------------
Minority Interest 1 1
3.625% Convertible perpetual preferred
stock (at liquidation value, net of
issuance costs) 247 247
Commitments and Contingencies
Stockholders' Equity
Preferred stock (at liquidation value,
net of issuance costs) 892 892
Common Stock 1 1
Additional paid-in capital 4,469 4,476
Retained earnings 790 739
Less treasury stock, at cost --
16,300,581 and 14,800,581 shares (835) (732)
Accumulated other comprehensive income 9 282
----------------------------------------------------------------------
Total Stockholders' Equity 5,326 5,658
----------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $18,711 $19,435
----------------------------------------------------------------------
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In millions)
Three months ended March 31, 2007 2006
----------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $65 $26
Adjustments to reconcile net income to net cash
provided by operating activities
Distributions less than equity in earnings of
unconsolidated affiliates (10) (12)
Depreciation and amortization of nuclear fuel 174 125
Amortization and write-off of financing costs and
debt discount/premiums 9 57
Amortization of intangibles and out-of-market
contracts (29) 9
Changes in deferred income taxes 47 46
Changes in nuclear decommissioning trust liability 9 (3)
Changes in derivatives 90 (21)
Changes in collateral deposits supporting energy
risk management activities (120) 230
Gain on sale of assets (17) --
Gain on legal settlement -- (67)
Gain on sale of discontinued operations -- (10)
Gain on sale of emission allowances (5) (59)
Amortization of unearned equity compensation 7 3
Write down of equity method investments -- 3
Cash provided/(used) by changes in other working
capital, net of acquisition and disposition affects (114) 15
----------------------------------------------------------------------
Net Cash Provided by Operating Activities 106 342
----------------------------------------------------------------------
Cash Flows from Investing Activities
Acquisition of Texas Genco LLC, net of cash acquired -- (4,263)
Acquisition of WCP, net of cash acquired -- (25)
Capital expenditures (107) (35)
Increase in restricted cash , net (5) (3)
Decrease in notes receivable 9 8
Purchases of emission allowances (61) (15)
Proceeds from sale of emission allowances 32 68
Investments in nuclear decommissioning trust fund
securities (68) (42)
Proceeds from sales of nuclear decommissioning trust
fund securities 59 45
Proceeds from sale of assets 29 --
Proceeds from sale of investments -- 45
Proceeds from sale of discontinued operations -- 15
----------------------------------------------------------------------
Net Cash Used by Investing Activities (112) (4,202)
----------------------------------------------------------------------
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders (14) (10)
Payment of financing element of acquired derivatives -- (29)
Payment for treasury stock (103) --
Funded letter of credit -- 350
Proceeds from issuance of common stock, net of
issuance costs -- 986
Proceeds from issuance of preferred shares, net of
issuance costs -- 486
Proceeds from issuance of long-term debt -- 7,175
Payment of deferred debt issuance costs -- (164)
Payments for short and long-term debt (19) (4,623)
----------------------------------------------------------------------
Net Cash Provided/(Used) by Financing Activities (136) 4,171
----------------------------------------------------------------------
Change in Cash from Discontinued Operations -- (17)
Effect of Exchange Rate Changes on Cash and Cash
Equivalents 2 1
----------------------------------------------------------------------
Net Increase/(Decrease) in Cash and Cash Equivalents (140) 295
Cash and Cash Equivalents at Beginning of Period 795 493
----------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $655 $788
----------------------------------------------------------------------
Appendix Table A-1: First Quarter 2007 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 Texas West
----------------------------------------------------------------------
Net Income (Loss) 38 10 60 5
======================================================================
Plus:
Income Tax - - 53 -
Interest Expense 14 11 47 -
Amortization of Finance Costs - - - -
Amortization of Debt
(Discount)/Premium - 2 - -
Depreciation Expense 25 17 114 -
Amortization of Power Contracts - (5) (47) -
Amortization of Fuel Contracts - - 14 -
Amortization of Emission Allowances - - 10 -
----------------------------------------------------------------------
EBITDA 77 35 251 5
Gain on Asset Sale of Red Bluff &
Chowchilla - - - -
----------------------------------------------------------------------
Adjusted EBITDA 77 35 251 5
(dollars in millions) International Thermal Corporate Total
----------------------------------------------------------------------
Net Income (Loss) 17 23 (88) 65
======================================================================
Plus:
Income Tax 7 - (4) 56
Interest Expense 7 2 91 172
Amortization of Finance Costs - - 7 7
Amortization of Debt
(Discount)/Premium - - - 2
Depreciation Expense 1 3 1 161
Amortization of Power Contracts - - - (52)
Amortization of Fuel Contracts - - - 14
Amortization of Emission
Allowances - - - 10
----------------------------------------------------------------------
EBITDA 32 28 7 435
Gain on Asset Sale of Red Bluff
& Chowchilla - (18) - (18)
----------------------------------------------------------------------
Adjusted EBITDA 32 10 7 417
Appendix Table A-2: First 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) Northeast Central Texas West
----------------------------------------------------------------------
Net Income (Loss) 132 28 18 (2)
======================================================================
Plus:
Income Tax - - (25) (2)
Interest Expense 19 14 26 -
Amortization of Finance Costs 1 - - -
Amortization of Debt
(Discount)/Premium - 2 - -
Refinancing Expense - - - -
Depreciation Expense 22 16 74 -
Amortization of Power Contracts - (4) (41) -
Amortization of Fuel Contracts - - 28 -
Amortization of Emission Allowances 7 2 13 -
----------------------------------------------------------------------
EBITDA 181 58 93 (4)
(Income)/Loss from Discontinued
Operations - - - -
Acquisition Integration Costs - - - -
Audrain Asset Sale Adjustment - - - -
Legal Settlement - - - -
Write Down on Sale of Equity Method
Investment 0 - - -
----------------------------------------------------------------------
Adjusted EBITDA 181 58 93 (4)
----------------------------------------------------------------------
(dollars in millions) International Thermal Corporate Total
----------------------------------------------------------------------
Net Income (Loss) 23 4 (177) 26
======================================================================
Plus:
Income Tax 9 - 17 (1)
Interest Expense 2 2 45 108
Amortization of Finance Costs - - 4 5
Amortization of Debt
(Discount)/Premium - - - 2
Refinancing Expense - - 178 178
Depreciation Expense 1 3 2 118
Amortization of Power Contracts - - - (45)
Amortization of Fuel Contracts - - - 28
Amortization of Emission
Allowances - - (2) 20
----------------------------------------------------------------------
EBITDA 35 9 67 439
(Income)/Loss from Discontinued
Operations (1) - (10) (11)
Acquisition Integration Costs - - 2 2
Audrain Asset Sale Adjustment - - 2 2
Legal Settlement - - (67) (67)
Write Down on Sale of Equity
Method Investment - - 3 3
----------------------------------------------------------------------
Adjusted EBITDA 34 9 (3) 368
----------------------------------------------------------------------
Appendix Table A-3: First Quarter 2006 Cash from Operations reconciliation
The following table provides a reconciliation of cash flow from operations to adjusted cash flow from operations.
----------------------------------------------------------------------
Q1 2006
Cash Flow from Operations $342
Reclassification of payment of financing element of acquired
derivatives (29)
Adjusted Cash Flow from Operations $313
----------------------------------------------------------------------
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.
Free cash flow is cash flow from operations less capital expenditures and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow as a measure of cash available for discretionary expenditures. In addition, in evaluating free cash flow, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.
SOURCE: NRG Energy, Inc.
NRG Energy, Inc. Media: Meredith Moore, 609-524-4522 or Lori Neuman, 609-524-4525 Investors: Nahla Azmy, 609-524-4526 or Kevin Kelly, 609-524-4527