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FORM 8-K
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 8-K
CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported) January 5, 2006
NRG Energy, Inc.
 
 
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
(State or Other Jurisdiction of Incorporation)
     
001-15891   41-1724239
     
(Commission File Number)   (IRS Employer Identification No.)
     
211 Carnegie Center   Princeton, NJ 08540
     
(Address of Principal Executive Offices)   (Zip Code)
609-524-4500
 
(Registrant’s Telephone Number, Including Area Code)
Not Applicable
 
(Former Name or Former Address, if Changed Since Last Report)
     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
     o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
     o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
     o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
     o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
 
 

 

TABLE OF CONTENTS

Item 7.01 Regulation FD Disclosure
Item 9.01 Financial Statements and Exhibits
SIGNATURES
EX-99.1: SLIDES

Table of Contents

Item 7.01 Regulation FD Disclosure
NRG Energy, Inc., or NRG, is furnishing the slides included as Exhibit 99.1 to this Current Report on Form 8-K because they are being provided to potential financing sources.
Certain of the slides in Exhibit 99.1 contain 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, but are not limited to statements regarding the expected timing of the closing of the acquisition, and can be identified by the use of words such as “will,” “would,” “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. NRG undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 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.
Certain of the slides in Exhibit 99.1 also contain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures, to the extent available without unreasonable effort, is included in Exhibit 99.1
Item 9.01 Financial Statements and Exhibits
     (c) Exhibits:
     
Exhibit No.   Document
99.1
  Slides, dated January 5, 2006

 

Table of Contents

SIGNATURES
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 hereunto duly authorized.
             
    NRG Energy, Inc.    
    (Registrant)    
 
            
 
  By:   /s/ TIMOTHY W.J. O’BRIEN
 
Timothy W. J. O’Brien 		   
 
      Vice President and General Counsel    
     Dated: January 5, 2006

 

Table of Contents

Exhibits
     
Exhibit No.   Document
99.1
  Slides, dated January 5, 2006

 

EX-99.1
 

....While Continuing to Implement our Proactive Environmental and Emissions Compliance Strategy... CAIR/CAMR Compliance plans in place TG portfolio has best in class environmental compliance equipment Material reductions in SO2 and NOx through 2010 at Dunkirk and Huntley 2009 - 2010 capex for substantial upgrade equipment Harvest economic value of excess bank of allowances Active management of emissions portfolio Incremental fuel switching between coal types Note: Excess allowances do not reflect any forecasted sales Significant bank of excess allowances provides predictability to compliance capital spend

 

West Coast Power Purchase Rationale ($ millions) Purchase Price $ 205 Acquired cash(1)(2) (88) Fair value of acquired emissions credits(1) (20) Net Assets Acquired $ 97 EBITDA 2005(1) $ 17 EBITDA 2006(1) $ 13 Purchase Multiple 2005 5.7x 2006 7.5x Operating reserve margins in SDG&E and SCE territories forecasted to be below desired 7% level by 2006 2006 EBITDA excludes potential merchant revenues from Encina unit 5 Brownfield development opportunities exist at El Segundo, Long Beach and Encina locations Third party property appraisals confirmed substantial alternative use values 100% ownership provides NRG with maximum strategic flexibility with respect to assets (1) Represents Dynegy's 50% share to be acquired by NRG (2) Purchase agreement requires $262 million of working capital at December 31, 2005. Cash component is estimated. 2005 2006 EBITDA $ 17 $ 13 Other funds provided by operations 40 - Cash flow from operations $ 57 $ 13

 

Liquidity Ample liquidity to support risk management strategy (1) Excludes additional MTM positions that are secured by a 2nd Lien on the Company's assets (2) Approximately $190 million of returned collateral anticipated in Q1 2006 (3) Excludes 2nd Lien capacity used to secure additional MTM positions

 

Natural Gas Prices Hedged power prices remain substantially below the forward curve providing future upside potential (1) Substantially all hedged revenues in 2007 utilize power put options, preserving upside potential (2) Henry Hub Terminal year (2011) gas price required to meet return requirements was $5.25 to $5.50/mmBtu range. Valuation remains conservatively levered to the upside and limited on downside.

 

Contracted and Hedged Positions Hedged Solid Fuel Generation TG Baseload generation largely hedged through 2009 High gas/power correlation in ERCOT provides opportunity to hedge out in 2010 and beyond NRG Baseload peak generation fully hedged in 2006 Options based hedge strategy in 2007 establishes floor for on-peak generation under current prices, providing price upside while requiring minimal collateral 2006 2007 2008 2009 2010 TG NRG % Contracted % Merchant Total % Contracted % Merchant 71% 29% 79% 21% 52%(1) 48% 68% 32% 37% 63% 58% 42% 34% 66% 48% 52% 31% 69% 28% 72% % Contracted % Merchant 88% 12% 87% 13% 82% 18% 62% 38% 25% 75% Revenue Weighted Avg. Forward Price/Mwh $44 $39 $41 $48 $53 Hedged Coal Supply Average annual price change is relatively flat, excluding diesel fuel index adjustments TG NRG 95% 102% 80% 49% Total 97% 92% 72% 2006 2007 2008 Highly hedged in 2006 and 2007 99% 85% (1) Includes 1,000 MW of peak power put options in the Northeast at an $82.31 weighted average strike price, preserving upside potential

 

Cash Generation Combined company expected to generate double digit free cash flow yield even in 2007, the year hedged furthest below current market prices (1) Assumes February 2, 2006 TG closing (2) December 30, 2005 closing share price

 

Texas Genco 1Q06 50 2Q06 37 3Q06 22 4Q06 10 Key Sensitivities Texas Genco NRG Total 2006 41 24 65 2007 55 43 98 2008 59 62 121 2009 100 62 162 2010 209 62 271 NRG Gas Price Sensitivity Gross Margin Change ($mm) from $1/mmBtu Gas Price Change 100 bps change in rates = $37 mm/yr Projected Fixed/Floating at close: 54% fixed, 46% floating Collateral Sensitivity Change in Cash/LC Collateral ($mm) from $1/mmBtu Gas Price Change Coal Price Sensitivity - Domestic Gross Margin Change ($mm) from $1/ton Change in Coal Price Texas Genco NRG Total 2006 0 1 1 2007 0 3 3 2008 4 7 11 2009 5 7 12 2010 5 13 18 NRG Interest Rate Sensitivity Interest Expense Change From Changes in Interest Rates NRG strategy to mitigate out-year volatility (1) (1) Upside of $1/mmBtu gas price change to NRG is $58 million due to put options

 

Credit Statistics (1) 2005 NRG 2006 2007 Gross 2.7 2.6 2.8 Net 2005 NRG 2006 2007 Gross 3.3 4.2 3.8 2005 NRG 2006 2007 Gross 0.54 0.55 0.49 2005 NRG 2006 2007 Gross 0.19 0.14 0.17 Adj. EBITDA/Interest Coverage (X) (2) Total Net Debt/Adj. EBITDA (2) (X) FFO/Total Net Debt (%) Total Debt/Total Capital (%) (1) Assumes February 2, 2006 TG closing (2) Excludes MTM 2.7x 2.6x 2.8x 3.3x 4.2x 3.8x 54% 55% 49% 19% 14% 17% Strong NRG credit profile continues to improve over forecast period

 

Strong Balance Sheet ETR 5.8 FPL 4 PSEG 3.1 NRG 2.5 EME 2.1 Reliant 1.7 Dynegy 1.2 FFO Interest Coverage(1)(2) (x) FFO/Debt(1)(2) (%) Total Debt/Capitalization(1)(2) (%) FPL Public Service Enterprise Group NRG Edison Mission Energy Reliant Dynegy ETR 31.8 FPL 20.9 PSEG 14.9 NRG 13.9 Reliant 7.9 EME 7.4 Dynegy 2.4 FPL NRG(3) Edison Mission Energy Reliant Dynegy Public Service Enterprise Group EME 80.6 Dynergy 75.6 Reliant 58.2 PSEG 57.2 NRG 55 FPL 50.8 ETR 49.9 FPL Reliant NRG Edison Mission Energy Public Service Enterprise Group Dynegy % of Avg 06-07 Output Hedged Texas Genco Total Entergy 82 82 PSEG 79 79 NRG 74 74 FPL 71 71 Reliant 56.5 56.5 Edison Mission Energy 37.1 37.1 Dynegy 18.25 18.25 2004 estimates for all statistics except NRG. Source: Standard & Poors. NRG statistics are Proforma combined for the year ended 2006. FFO / Net Debt for NRG.

 

Asset Value Over Collateralization Valuation Based on $/kW Metrics (1) Pro Forma Market Value Baseload Valuation ($/kW) Mid-merit, Peaking Valuation ($/kW) Resulting Aggregate Value 1st Lien Term Loan B Asset Value Coverage Total Debt Asset Value Coverage 1,000 200 $11.4Bn 3.5x 1.6x 1,200 300 $14.5Bn 4.5x 2.0x 1,400 400 $17.6Bn 5.5x 2.5x $14.5Bn(2) 4.5x 2.0x Excludes value of non-US businesses. Assumes 8,558 MW of baseload generation and 13,989 MW of mid-merit and peaking assets (excluding Audrain) Excludes $470MM of non-recourse debt at international assets

 

Forecast Amortization Schedules 2006 2007 2008 2009 2010 2011 NRG: NRG power contracts1 $7.6 $18.7 $24.2 $23.7 $20.2 $20.4 NRG emissions credits2 $18.3 $14.1 $14.5 $13.0 $17.7 $15.8 Texas Genco: Texas Genco power contracts $1,326 $1,140 $688 $244 $48 $0 1 Amortization of power contracts occur in the revenue line and are primarily related to the South Central and Australia segments. The amortizations are based on actual generation. These figures are estimates as of December 7, 2005. 2 Amortization of emissions credits occurs in the cost of goods sold line and are primarily related to the Northeast and South Central regions. These amortizations are based on expected emission credit consumption due to estimated plant generation. These amortizations are estimates as of December 7, 2005. 3 Amortization of power contracts of nearly $3.4 billion occur in the revenue line. The amortizations are based on actual generation. These figures are on a pro forma basis as of September 30, 2005. Emissions credit inventory was valued at approximately $1.3 billion and is anticipated to be amortized based on consumption. On a pro-forma basis, as of September 30, 2005, we estimated that the amortization expense for emissions credits for 9 months ended September 30, 2005 and 12 months ended December 31, 2005 was $91.5 million and $122 million, respectively.

 

Regulation G Reconciliations Appendix Table 1: 2005 to 2007 EBITDA to Interest Coverage Net Debt to EBITDA Appendix Table 1: 2005 to 2007 EBITDA to Interest Coverage Net Debt to EBITDA Appendix Table 1: 2005 to 2007 EBITDA to Interest Coverage Net Debt to EBITDA 2005 2006 2007 Numerator Adjusted EBITDA1 $ 745 $ 1,600 $ 1,558 Denominator Interest2 279 615 565 EBITDA to Interest Coverage 2.7 2.6 2.8 1 Adjusted EBITDA presented on an economic basis -- MTM losses/gains are included in years when such transactions settled. 1 Adjusted EBITDA presented on an economic basis -- MTM losses/gains are included in years when such transactions settled. 1 Adjusted EBITDA presented on an economic basis -- MTM losses/gains are included in years when such transactions settled. 1 Adjusted EBITDA presented on an economic basis -- MTM losses/gains are included in years when such transactions settled. 2 Represents cash interest; 2005 estimate includes cash expense of $44 million for the bridge loan financing commitment 2 Represents cash interest; 2005 estimate includes cash expense of $44 million for the bridge loan financing commitment 2 Represents cash interest; 2005 estimate includes cash expense of $44 million for the bridge loan financing commitment 2 Represents cash interest; 2005 estimate includes cash expense of $44 million for the bridge loan financing commitment 2 Represents cash interest; 2005 estimate includes cash expense of $44 million for the bridge loan financing commitment Appendix Table 2: 2005 to 2007 Total Debt to Total Capital1 Appendix Table 2: 2005 to 2007 Total Debt to Total Capital1 2005 2006 2007 Numerator Gross Debt $ 2,918 $ 7,875 $ 7,121 Denominator Gross Debt 2,918 7,875 7,121 Mezzanine Preferred 246 246 246 Book Value of Equity 2,218 6,216 7,041 Capital $ 5,382 $ 14,337 $ 14,408 Total Debt to Capital 54% 55% 49% 1 Assumes debt pay down occurs in February of each year beginning in 2007. 1 Assumes debt pay down occurs in February of each year beginning in 2007.

 

Regulation G Reconciliations Appendix 3: 2005 to 2007 Net Debt to Total Capital1 Appendix 3: 2005 to 2007 Net Debt to Total Capital1 2005 2006 2007 Numerator Gross Debt $ 2,918 $ 7,875 $ 7,121 Total Cash $ (452) $ (1,181) $ (1,153) Net Debt $ 2,466 $ 6,694 $ 5,968 Denominator Net Debt $ 2,466 $ 6,694 $ 5,968 Mezzanine Preferred 246 246 246 Book Value of Equity 2,218 6,216 7,041 Capital $ 4,930 $ 13,156 $ 13,255 Net Debt to Capital 50% 51% 45% 1 Assumes debt pay down occurs in February of each year beginning in 2007. 1 Assumes debt pay down occurs in February of each year beginning in 2007. Appendix Table 4: Net Debt to EBITDA1 Appendix Table 4: Net Debt to EBITDA1 2005 2006 2007 Numerator Gross Debt $ 2,918 $ 7,875 $ 7,121 Total Cash $ (452) $ (1,181) $ (1,153) Net Debt $ 2,466 $ 6,694 $ 5,968 Denominator Adjusted EBITDA $ 745 $ 1,600 $ 1,558 Net Debt to EBITDA 3.31 4.18 3.83 1 Assumes debt pay down occurs in February of each year beginning in 2007. 1 Assumes debt pay down occurs in February of each year beginning in 2007.

 

Regulation G Reconciliations Appendix Table 5: FFO to Net Debt1 Appendix Table 5: FFO to Net Debt1 2005 2006 2007 Numerator Cash Flow From Operations $ 57 $ 1,247 $ 1,015 Less: Working Capital (39) 38 (30) Return of Collateral 433 (406) (27) Pension 13 53 40 FFO $ 464 $ 932 $ 999 Denominator Gross Debt $ 2,918 $ 7,875 $ 7,121 Total Cash (452) (1,181) (1,153) Net Debt $ 2,466 $ 6,694 $ 5,968 FF0 to Net Debt 19% 14% 17% 1 Assumes debt pay down occurs in February of each year beginning in 2007. 1 Assumes debt pay down occurs in February of each year beginning in 2007.

 

Reg. G Reconciliation EBITDA and Adjusted EBITDA 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 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 presentation. 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 presentation.