UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
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
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): October 17, 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)) |
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 the investment community as part of NRG’s Analyst
Conference on October 17, 2006. The event, which will be webcast, will provide analysts and
investors with an overview of the Company’s “Repowering NRG” program and include presentations from
President and Chief Executive Officer, David Crane, Chief Financial Officer, Robert Flexon, and
other senior management.
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.
The information contained in this Item 7.01 is not filed for purposes of the Securities Exchange
Act of 1934, as amended, and is not deemed incorporated by reference by any general statements
incorporating by reference this report or future filings into any filings under the Securities Act
of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent NRG
specifically incorporates the information by reference. By including this Item 7.01 disclosure in
the filing of this Current Report on Form 8-K and furnishing this information, we make no admission
as to the materiality of any information in this report that is required to be disclosed solely by
reason of Regulation FD.
Item 9.01 Financial Statements and Exhibits
| Exhibit No. | Document | |
99.1
|
Slides, dated October 17, 2006 |
2
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: October 17, 2006
3
Exhibit 99.1
| Safe Harbor & Legend This investor presentation 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 NRG's expectations regarding the timing, construction, equipment, costs, financing, environmental impact, job creation and financial success of the development projects described herein, our hedging strategy and our environmental compliance strategy and typically can be identified by the use of words such as "will," "should," "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, permitting and regulatory obstacles, construction delays, the performance of new equipment and technologies, the volatility of energy and fuel prices, changes in the wholesale power markets and related government regulation, the availability of financing and the condition of capital markets generally, our ability to access capital markets, and the inability to implement value enhancing improvements to plant operations and companywide processes, and our inability to achieve expected benefits of our repowering 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 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 investor presentation 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. |
| Reinforcing the Business Model Load serving entities in our core regions willing to contract for their bulk generation needs at a premium price in exchange for our assistance mitigating their customers' aggregate electricity and fuel cost and transmission constraint risks. A regionally focused, multi-fuel, carbon-diversifed scale generator with assets across the merit order and around transmission in each of our core markets with the capability to procure, transport and trade all of the commodities involved in our business. Our target customer: What we strive to be: Reflects pro-forma net MW post-repowering: assumes 100% success rate and net of retirements Includes other North America capacity of 594 MW. For combined scale 2,831 MW (12.4%) is dual-fuel capable. Reflects only domestic generation capacity. South Central Western Northeast Texas Nuclear 2,296 MW 18% Gas 2,096MW 40% Combined Scale1,2 Fuel Combined Scale1,2 Region Gas 3,339MW 96% Wind 150MW 4% Gas 5,490MW 43% Coal 4,821MW 37% Coal 2,048MW 74% Gas 706MW 26% Wind 300MW 2% Oil 2,768MW 34% Coal 3,294MW 40% Other 594MW 2.1% Wind 450MW 1.6% Nuclear 2,296 MW 8.2% Oil 2,767 MW 9.9% Gas 12,209 MW 43.8% Coal 10,179 MW 36.5% Texas 12,907 MW 46.3% Northeast 8,156MW 29.2% West 3,489MW 12.5% S. Central 2,754MW 9.9% Gross MW Fuel Operation Technology Repowering Plan *Likelihood for peaker and real estate development |
| Texas STP - units 3&4 2,716 NUCLEAR ABWR 2014-2015 Limestone - unit 3 800 COAL PRB/EASTERN Pulverized Coal (BACT) 2012 CTs - Houston 500 GAS Simple/Combined Cycle 2008 Texas Adds 4,016 Louisiana BC-II - unit 4 775 COAL - /ILLINOIS Pulverized Coal (BACT) 2010 BC-1 230 PET COKE/COAL Fluidized Bed Boiler 2010 South Central Adds 1,005 Northeast Indian River 752 COAL-L/PETCOKE IGCC - Shell Gasifier 2011-2012 Montville 752 COAL-L/PETCOKE IGCC - Shell Gasifier 2011-2012 Cos Cob 40 GAS/OIL P&W FT4 2008 Middletown 300 GAS/OIL GE LMS 100 2009 Devon 200 GAS/OIL GE LM 6000 2009 Huntley 752 COAL-B/PETCOKE IGCC - Shell Gasifier 2012 Astoria 200-400 GAS/OIL GE LMS 100 2008-2010 Northeast Adds 3,096 California Long Beach Rebuild 250 GAS Simple Cycle Gas Turbine 2007 Long Beach 360 GAS Simple Cycle Gas Turbine 2010 Encina Peakers* 200 GAS Simple Cycle Gas Turbine 2009 El Segundo 630 GAS Combined Cycle Gas Turbine 2009 West Adds 1,440 New Business Wind Power - Texas 300 WIND Wind turbines 2008-2010 Wind Power - California 150 WIND Wind turbines 2008 Total New Business 450 Total Gross MW Added 10,007 |
| Impact on Portfolio Scale in Core Regions 22,800 to 32,600 MWs Regenerate Asset Base 392 to 28 Year of avg unit life3 Reduce Carbon Profile 0.9 to 0.7 Carbon intensity4 Reduce Merchant Volatility 78%5 to 85%6 Hedged as % of asset base Assume 100% success rate and 100% equity ownership in new projects Age of assets by 2015 with no repowering Comparison of average unit life of current fleet in 2015 vs average unit life in 2015 after repowering effort is complete. Average life is weighted by summer capacity. Carbon intensity expressed in tons/Mwh; fleet carbon intensity reduces further to 0.6 if we assume the three IGCC plants are built and their carbon is sequestered. Average across 2007-2011 period (baseload only) Expected average across 2015-2019 period (baseload only). Assumes the following: hedge profile on current baseload fleet is maintained. Baseload assets hedged at 90%, IGCCs with 10+ year PPAs. Repowering provides financial and operational benefits to NRG's portfolio After1 Current |
| What We Are Not Going To Do Gross MW TPC ($MM) Type Number Success Probability Leverage (%) NRG Ownership (%) NRG Equity1 ($MM) 450 $750 Wind 2 75% 70% 50% $75 2,800 $2,150 Gas 9 75% 70% 80% $375 1,800 $2,950 Solid Fuel 3 50% 70% 67% $275 2,250 $4,550 IGCC 3 67% 65% 50% $525 2,700 $5,500 Nuclear 1 50% 80% 44% $250 10,000 $15,900 18 $1,500 2007 2008 2009 2010 2011 2012 2013 2014 2015 Probability Adj. Capital 1220 2927 4940 7205 8744 10166 10956 11682 12187 Probability Adj. Equity 397 956 1466 2066 2383 2858 2976 3085 3222 NRG Equity 240 579 885 1195 1352 1594 1646 1694 1754 Repowering NRG: Probability Matrix (current base case) 2007 2008 2009 2010 2011 2012 2013 2014 2015 Probability Adj. Total Capital 1129 2701 4339 5753 6403 6714 6714 6714 6712 Probability Adj. Total Equity 306 729 1184 1656 1839 2148 2148 2148 2148 NRG Equity 200 480 761 1015 1113 1281 1281 1281 1281 With Nuclear Without Nuclear Probability Adjusted Total Capital Probability Adjusted Total Equity NRG Equity Dissipate the Company's long term Free Cash Flow on Repowering NRG capital expenditures... $12,200 $3,200 $1,750 $6,700 $2,100 $1,250 1) Excludes potential value from in-kind contributions |
| What We Are Not Going To Do Pre-PPA Development Spend (Excl. STP) Net Development Benefit (Costs)1 Permit PPA Financial Closing 2006E 2007E 2008E Pre-PPA Costs2 ($20) ($20) ($15) Development Fee3 - $45 $80 Net Benefit (Cost) ($20) $25 $65 Excludes STP 3&4 Costs from PPA to Financial Closing are deemed to be capitalized Assumes gas, wind, and solid fuel unit projects achieve financial closing in 2007 and an additional IGCC and remaining solid fuel units in 2008 "Total Development Spend" is back-end loaded, with great majority of spend incurred after PPA is negotiated with. Post-PPA is much lower risk and mainly capitalized Development fees, paid at financial closing, render the development program self- sustaining by 2008 ....nor dissipate the Company's short term Free Cash Flow on Repowering NRG development spend |
| STP 3&4 COL Application in Perspective NRG Gross Expense Mitigant NRG Net Exposure COL Application $40 56% sell-down $18 Finalize ABWR Design 40 Design centered workgroup 10 NRG Response 6 56% sell-down 3 Options on Heavy Forging 8 Transferable 0 Total Expenditures $94 $31 The "cost at risk" of the COL application has not been fully explained The time benefit of an approved COL has not been fully appreciated 2006-2007 Development Spend "First Mover" Benefit An early Construction Operating License is an extremely valuable asset for NRG regardless of whether NRG is the company that actually builds and operates STP 3&4 "Apply to Win" 100% 44% Unrealized Site Value1 $500 $220 Production Tax Credit2 500 220 Federal Loan Guarantee3 400 176 Standby Support [Priceless] [Priceless] [Priceless] Total $1,400 $616 Reflects value of cooling pond, security, administrative and common facilities PV of 8 year credits 80% leverage at Treasuries vs. 80% leverage at NRG borrowing rates for 30 years |
| Enhancing Shareholder Value Competitive Advantages Competitive Advantages Wind Gas Solid Fuel IGCC Nuclear NRG Intrinsic Value NRG Intrinsic Value NRG Intrinsic Value NRG Intrinsic Value NRG Intrinsic Value NRG Intrinsic Value NRG Intrinsic Value Existing Sites ? ? ? ? Location in Constrained Areas ? ? Trading and Risk Management ? ? ? ? ? ? Coal Supply and Transport ? ? Operational Expertise ? ? ? ? ? ? Corp/Regional Infrastructure ? ? ? ? ? ? Environmental Technology ? ? ? ? Project Value Enhancements Project Value Enhancements Project Value Enhancements PPAs ? ? ? ? ? ? Loan Guarantees ? ? Tax Credits ? ? ? ? Implied Value Creation: >$150 / kw >10% NPV/I >$10 / Share Repowering NRG opportunity in excess of $10 per share for shareholders Potential Value Creation: $1.5 Billion + |
| NRG Can Satisfy These Unique Needs Amount Available (MWs) Up to 4,200 Up to 1,100 Up to 5,500 800 1,200 300 500 Basis ($/MWhr) $40 $40 Varying Heat Rates $52-$54 $35-$44 Cost net of PTCs <9,000 Heat Rate Dispatch Position Baseload Baseload Shaping Baseload Baseload Baseload Shaping Deliveries Begin 2007 2007 2007 2012 2014 2008 2008 Emissions Sensitivity No Yes Yes No Yes Yes Yes Ownership PPA PPA PPA Equity or PPA Equity or PPA Equity or PPA Equity or PPA NRG has the capability to create low-cost customer solutions by blending our generation Existing Coal Existing Nuclear Existing Gas New Coal New Nuclear New Wind New Gas |
| Three Initiatives Permit will be filed with TCEQ this month Combined Cycle with by-pass stacks 10,500 heat rate as 340 MW simple cycle (first two hours of a cold start) 7,200 heat rate as 500 MW combined cycle Online in early 2009 Utilize Bourbonnais settlement equipment Cedar Bayou 3 to be retired eventually All-in cash cost of less than $500/kW Permit filed with TCEQ this month 8 LM 6000 9,400 or lower heat rate units Online dates for mid- 2008 All-in cash cost of $450/kW 800 MW pulverized coal unit Coal flexibility Air-cooled condenser Upgrades to existing units will offset NOx and SO2 emissions from the new unit All-in cash cost of $1,600/kW Creating optionality by permitting multiple sites and technologies Cedar Bayou SR Bertron Limestone |
| Representative Timeline 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Early Equipment Orders Safety Related Construction COLA Development Non-Safety Related Construction Operation PTCs COLA Review Option Sell down after securing early position for COLA Application Option Sell down (or out) upon receipt of License NRG will mitigate risk through equity, technological and public-private partnerships 1 2 3 commercial operation Option Sell down (or out) upon |
| 2006 and 2007 Spend Update of Design $40mm 4th Quarter 2006 1st Quarter 2007 2nd Quarter 2007 3rd Quarter 2007 4th Quarter 2007 Site Specific COL Costs $40mm NRC Review Support $6mm Long Lead Procurement $8mm Our anticipated 44% of design cost is $18mm These costs are shared with a "design-centered work group" with other ABWR developers. Assuming one other, our net exposure would be ~$10mm Our anticipated 44% of design cost is $18mm $40mm site specific cost for two units is consistent with other announced nuclear build |
| Shortlisted El Segundo - A Winning Formula Design: Technology: Fuel: 630 MW CCGT (2 on 1) General Electric 7FA Gas Unique Qualifications: CEC Permit to construct (only Project!) Fully approved Emissions Offsets (Only Project!) Ability to meet 2009 COD Located in Load Pocket Use of Once-through cooling (Heat Rate Advantage) Existing Gas and Electrical Interconnects El Segundo Repowering PPA award anticipated by January 2007 |
| Shortlisted Development Potential: Long Beach Projects Specs: Design: Technology: Fuel: 360 MW Peakers 2 Siemens 501FD3s Gas Rebuild existing units (250 MW) Existing Alstom Units Gas Comparable Advantage: Located in Load Pocket Existing gas and electrical interconnects Ability to meet 2010 COD Ability to meet 2007 COD Holds significant portion of necessary Emission Credits < $400/kW to build Located in load pocket Long Beach Peakers Long Beach Rebuild Two solid options for advantaged site |
| Development Potential - Encina Prime north San Diego county location 363 total acres, 91 acres can be developed 4,600 feet of frontage along Carlsbad Blvd (fronts Pacific Ocean) Substantial NPV value ($300-$500MM) East Parcel can host 200+ MW Potential for a desalination plant Gas and electrical interconnects Significant inventory of air credits Potential inland site under review Repowering Real Estate AND Development options will maximize value for NRG shareholders |
| Competitive Advantage Advantaged sites Astoria in-city site: scarce land in NYC to develop generation Montville (CT), Indian River (DE) and Huntley (NY) ideal for IGCC Brownfield sites with an average of $100-150/kW advantage versus greenfield Access to rail, water and grid Sufficient land and skilled labor Strong local support Cos Cob and Devon in Southwest CT load pocket Scale economies IGCC 3-pack could offer lower cost on gasifier, EPC, turbine packs, and other equipment Scale savings could be in the $50-100/kW range Shell gasification technology Overall cost advantage of $25-$35/kW relative to other gasification technologies Advantage from lower fuel cost due to greater fuel flexibility, lower O&M, higher availability, lower heat rate, less O2 consumption, and higher quality saleable slag Category Advantage NRG in the lead on IGCC and instrumental in shaping RFPs to address IGCC demand |
| Competitive Advantage (Cont.) Competition Intelligence suggests few, if any, players ready to bid IGCC plants Few power generation brownfield sites with NRG advantages Potential Competitors: NY In-City (NYPA) - PSEG (trans-river cable); NY Clean Coal (NYPA) - AES Somerset (PC) and Dynegy (PC); CT Peakers - LS Power, Kleen Energy, Competitive Power Ventures, CMEEC; CT Baseload - Kleen Energy (CCGT); DE - SCS Energy (CCGT - dry cooled), BlueWater Wind (Offshore Wind) Attractive environmental tradeoffs Retirements and/or emissions control investments on existing units in exchange for new, state of the art generation with PPAs EBITDA loss from CT retirements not material relative to estimated potential upside from CT repowering IRS Section 48A tax credits NRG IGCC projects only to file for Section 48A credits in the Northeast Could result in $30-50 million in tax savings per project Category Advantage NRG can bid attractive economics and price at, or below, current annual average energy prices |
| Expectations (12 to 18 months) IGCCs 2 3 CT Peakers Devon - 200 MWs Cos Cob - 40 MWs Middletown - 100 MWs Devon - 200 MWs Cos Cob - 40 MWs Middletown - 200 MWs Astoria-NYPA In-City 200 MWs 400 MWs Selected for the following projects: Negotiated PPAs for awarded projects Following PPA signing, completed the following: Front-end engineering and design for EPC Technology license agreement Partnership, O&M, commercial management, fuel supply and transport, project management agreement, and common facilities arrangements Filed and received approval for environmental permits and interconnection agreement for all projects Solicited project financing and closed; negotiated intercreditor agreements Probable Reasonable Likelihood Due to auction processes, we will know early |
| Equity Participation/PPAs Net Development Megawatts 912 MW Final Stages of Negotiating Final Stages of Negotiating MW Entity E (PPA) 30 Entity F (PPA) 10 Entity G (PPA) 375 Entity H (Equity) 50 Total 465 Equity Negotiating Equity Negotiating MW Entity I 150 Total 150 Equity Committed Equity Committed MW Entity A 150 Entity B 50 Entity C 60 Entity D 50 Total 310 Committed (310) + Final Stages of Negotiating (465) + Negotiating (460) = 1,235 MW PPAs Negotiating PPAs Negotiating MW Entity J 30 Entity K 30 Entity L 50 Entity M 200 Total 310 Strong market demand driving potential oversubscription for new solid fuel resources |
| Development Progress and Critical Path - BC II-4 and BC I Feasibility Initial Cost Analysis Environmental Analysis Risk Analysis Definition Tech & Fuel Selection Public Relations Environmental Permit Developed Development Licenses/Permits Business Structure and Off-takes Construction Financial Close EPC & Issue NTP 100% Complete 90% Complete Finalize Business Structure & Off takes - 50% Complete Bid & Select EPC and issue NTP, Financial Close - 40% Complete Progress Critical Path Development Spend ($millions) Development Spend ($millions) Development Spend ($millions) Development Spend ($millions) 2005 2006 Total Big Cajun II - Unit 4 $0.4 $0.6 $1.0 Modified Air Permit - $0.6 $0.6 Big Cajun I Repowering - $0.3 $0.3 Development Spend ($millions) Development costs are recovered pro-rata from equity partners |
| Capital Allocation Alternatives and Criteria 2007 Allocation Long-Term Strategy Complete $750 million share repurchase program ($250 million in 2007) Ongoing return of capital to shareholders Compliance with and impact on covenants Credit impact Implied FCF yield on equity Balanced approach to returning capital to debt and equity holders Maintenance and environmental capex of approximately $350 million Optimize operational performance- achieve FORNRG goals Safe and reliable operations Environmental regulations Excess bank of emission allowances and retrofit costs ROIC Debt reduction of at least $400 million Maintain "BB" credit metrics Compliance with and impact on covenants Credit impact Preserve access to various markets on attractive terms Gross development expenses ~$99 million, potentially offset by ~$108 million of cost sharing and development fees Long-term PPAs and acceptable EPC contracts, diversifying and reducing the risk associated with NRG's existing asset profile ROIC consistent with development risk NPV relative to equity at risk Equity at risk relative to NRG market value Payback period Credit impact Criteria in Allocating Capital All repowering opportunities are subject to a disciplined cost / benefit comparison to other uses of capital Reinvestment in Core Facilities Debt Management Share Repurchase Program Repowering Opportunities |
| Potential Development Expenses and Fee Income Cost of near-term development activities, net of likely development fees and cost reimbursements, is less than $1 per share (1) Assumes 56% reimbursed by partners and other risk mitigations in 2007 (2) Assumes ~67% hit rate on certain gas, wind, and solid fuel unit projects achieving financial close in 2007 $millions pre-tax 2006 2007 Total Nuclear Outflows (15) (79) (94) Inflows - 63 63 Net (15) (16) (31) Non-Nuclear Outflows (20) (20) (40) Inflows - 45 45 Net (20) 25 5 Total Outflows (35) (99) (134) Inflows - 108 108 Net (35) 9 (26) |
| Potential Capital Requirements1 Gross MW ~2,800 ~2,250 Cost2 / kW ~$700 ~$2,050 Sub-total Cost ($MM) ~$2,000 ~$3,900 Primary Outlay Years '07-'09 '08-'12 Likely Debt/Cap 70%+ 65%+ Target NRG Stake 50%-80% 40%-50% NRG Contribution ~$350-500MM ~$650-800MM ~1,800 ~$1,400 ~$2,500 '07-'11 70%+ 50%-80% ~$450-700MM ~2,700 ~$1,800 ~$4,900 '09-'14 TBD; 80% 25%-45% ~$250-500MM ~10,000 ~$1,400 ~$14,000 72%+ 40%-60% ~$1,800-2,700MM (1) Assumes all projects are developed (2) Costs excluding IDC (3) Potential development fees and common facilities value from equity sell-downs NRG In-Kind3 Contribution NRG Cash Contribution ~$750MM+ ~$1,050-1,950MM IDC Cost ($MM) ~$150 ~$650 ~$450 ~$600 ~$1,900 Total Cost ($MM) ~$2,150 ~$4,550 ~$2,950 ~$5,500 ~$15,900 ~450 ~$1,550 ~$700 '07-'08 70%+ 50%-80% ~$100-200MM ~$50 ~$750 Level of cash contribution is manageable even if all projects are developed Wind Gas Solid Fuel IGCC Nuclear Total |
| Potential Capital Requirements: Scenario Analysis Gross MW ~10,000 ~5,000 Cost1 / kW ~$1,400 ~$1,400 Total Cost ($MM) ~$15,900 ~$7,950 Likely Debt/Cap 72%+ 72%+ Target NRG Stake 40%-60% 40%-60% NRG Total Contribution ~$1,800-2,700MM ~$900-1,350MM ~7,500 ~$1,400 ~$11,900 72%+ 40%-60% ~$1,350-2,000MM NRG In-Kind2 Contribution ~750MM+ ~$375MM+ ~550MM+ ~2,500 ~$1,400 ~$3,950 72%+ 40%-60% ~$450-650MM ~$200MM+ Repowering Development Success Ratio NRG Cash Contribution ~$1,050-1,950MM ~$525-975MM ~$800-1,450MM ~$250-450MM Sub-total Cost ($MM) IDC Cost ($MM) ~$14,000 ~$1,900 ~$7,000 ~$10,450 ~$3,500 ~$950 ~$1,450 ~$450 (1) Costs excluding IDC (2) Potential development fees and common facilities value from equity sell-downs Required cash contribution from NRG is expected to be less than less than $1.5 billion 100% 75% 50% 25% |
| Allocation of Cash Flow From Operations 2007-2012 With in-kind Contribution(1)(2)(3) Without in-kind Contribution(1)(3) Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 1.5 4.3 Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 1.1 4.6 Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 0.7 4.8 Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 0.4 5 Repowering Capex (NRG cash) Standalone Capex Cash available for debt management, share repurchases and dividends (1) Assumes 80% ownership for all gas assets and Limestone; 50% for wind, IGCCs, and Big Cajuns; and 44% for STP (2) Assumes in-kind contribution of $750 million for 100% success ratio or average of ~$150/kw for each interest sold (3) All figures in $Bn Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 2.3 3.5 Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 1.7 4 Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 1.1 4.4 Standalone Capex Repowering Capex +IDC Available Cash 1 2.2 0.5 4.9 $2.2 28% $1.5 18% $4.3 54% $2.2 28% $2.3 28% $3.5 44% $2.2 28% $1.1 14% $4.6 58% $2.2 28% $1.7 21% $4.0 51% $2.2 28% $0.7 10% $4.8 62% $2.2 28% $1.1 15% $4.4 57% $2.2 29% $0.4 5% $5.0 66% $2.2 29% $0.5 7% $4.9 64% Cash from operations over next several years can fund standalone and Repowering NRG while preserving substantial free cash flow for debt and equity holders Repowering Development Success Ratio 100% 75% 50% 25% |
| Risk Management: Focus on Baseload Power Locking in Dark Spread Energy position as of Sep 9, 2006; 2006 reflects balance of year revenues and ancillary services. Includes Northeast, South Central and Texas portfolios within the U.S portfolio and excludes Thermal and International. 3. Includes financial gas swaps (reflected in equivalent MWh by taking the volume in MMBtu's and divided by the forward market heat rate in ERCOT). 4. Hedge percentages are subject to change due to market volatility and commodity prices which drive changes in expected generation. 5. Hedged fuel represents weighted average of coal and uranium. Optimizing Excess SO2 Allowances Historic Bank from prior years 209,547 YTD Actual vs Expected Allowance Consumption 22,046 Sales @ avg. price ~ $1,117 per allowance (70,777) Purchases @ avg. price ~ $798 per allowance 93,700 Net sales and purchases (tons) 22,923 Net cash difference ($ in thousands) $4,295 Forecasted Dec 31 Bank 312,000 Locking in 2009 and beyond utilizing commodity cycles Hedging Baseload Power |
| Risk Management: Focus on Baseload Power Locking in Dark Spread Optimizing Excess SO2 Allowances Historic Bank from prior years 209,547 YTD Actual vs Expected Allowance Consumption 22,046 Sales @ avg. price ~ $1,117 per allowance (70,777) Purchases @ avg. price ~ $798 per allowance 93,700 Net sales and purchases (tons) 22,923 Net cash difference ($ in thousands) $4,295 Forecasted Dec 31 Bank 312,000 Locking in 2009 and beyond utilizing commodity cycles |
| Procuring Commodity RFP for coal supply issued in early September Strong response with over 400 million tons offered Coal supply offers cover 2007-2021 timeframe Plan to select short list of suppliers mid-October and finalize contract price and terms by year end RFP for transportation to be issued this month Bring in third parties with low cost of capital Structure long-term contracts which take advantage of each party's strengths Identify coal supply partners whose long-term strategies align with ours Hedging strategy for the new fleet: |
| Proactive Strategy for Environmental and Emissions Compliance - Emissions Allowances Harvest economic value of excess bank of allowances Active management of emissions portfolio Incremental fuel switching between coal types Conservative approach: maintain at least enough allowances to operate fleet through 2020 Note: Excess allowances do not reflect any forecasted sales NRG SO2 Allowance Position - Current Fleet NRG SO2 Allowance Position - Repowering SO2 CAIR Reductions 2010: 2 for 1 2015: 2.86 for 1 SO2 CAIR Reductions 2010: 2 for 1 2015: 2.86 for 1 |
| Financial Impact of Revised Capex Spending Total Budget 1,283 7731 510 South Central portion at 90%3 433 227 206 Less emissions2 196 N/A 196 Net impact to shareholders 654 546 108 2007-2011 from 2005 Form 10K; 2012 capex (previously not reported) from internal estimates at Dec 2005 Estimated value of all emissions allowance sales beyond what is required to operate current fleet through 2020 Assumes contracts renew with capital recovery 2007-2011 from 2005 Form 10K; 2012 capex (previously not reported) from internal estimates at Dec 2005 Estimated value of all emissions allowance sales beyond what is required to operate current fleet through 2020 Assumes contracts renew with capital recovery 2007-2011 from 2005 Form 10K; 2012 capex (previously not reported) from internal estimates at Dec 2005 Estimated value of all emissions allowance sales beyond what is required to operate current fleet through 2020 Assumes contracts renew with capital recovery 2007-2011 from 2005 Form 10K; 2012 capex (previously not reported) from internal estimates at Dec 2005 Estimated value of all emissions allowance sales beyond what is required to operate current fleet through 2020 Assumes contracts renew with capital recovery Impact Current Budget 2007 - 2012 ($M) 2005 10K Budget 2007 - 2012 ($M) Variance ($M) Capex Increase - after value of credits and South Central contract recovery - ~$100M |
| Additional Mitigation Possibilities EPC/commercial strategy Dropping commodity/steel prices Securitization of South Central environmental capital expenditures Retirement of certain assets in conjunction with the Repowering program South Central customer discussions Alternate commercial procurement strategies, e.g., Scale benefits Lower price with NRG carrying additional risks (i.e., non-turnkey approaches to EPC's) Price quotes at top of commodity markets - some evidence of increasing inventories potentially creating downward pressure on steel Opportunity to remove South Central spending from balance sheet given contractual obligation of customers Select RFP responses to include creative options for different retrofit/retirement plans for some plants Delaying South Central capex through allowance purchases that would be recouped through co-op charges Opportunities in process |
| Summary of Changes and Rationale in Investment Decisions Huntley & Dunkirk New York No scrubbers on Huntley 67, 68 Earlier SNCRs and baghouses Scrubbers not required under consent decree - SO2 reductions can be achieved via the co-benefit of Hg retrofits (FF-ACI) Timing advanced with NY Hg and particulate rules and substitute for scrubbers Indian River Delaware Added SCR to unit 4 Added baghouse to units 1-3 Added low-NOx burners to all units Expected minimum investment under one multi-pollutant settlement Big Cajun II South Central Use of baghouses in place of other controls for Hg mitigation. One SCR required, not two Delayed Capex on other units Certainty in Hg compliance Louisiana expected to adopt federal cap and trade program Limestone Texas SNCR on Units 1 and 2 Further NOx controls anticipated by 2012 for regional compliance or to offset new Limestone 3 unit Units Region Change Rationale Regulatory rule evolution driving majority of planned retro-fit changes |
| Key Takeaways on Retrofits Program still in some flux with state rules and RFP program - unlikely to do any additional retrofits beyond those described South Central contracts provide meaningful incremental cash flow Various mitigants to cash flow impact exist with real potential for impact Conservatively, $200m of allowance sales Potential for securitization of South Central spread Additional $/kw savings from procurement and commodity pricing |
| Environmental Benefit of Repowering SO2 emissions decrease overall and on a per mwh basis 1.3 lbs/ MWh 185K tons 96 K tons 5 lbs/ MWh 2005 2014 2005 2014 Total Per Mwh NOx emissions decrease slightly overall and on a per mwh basis 2005 2014 2005 2014 Total Per Mwh 53K tons 49K tons 1.5 lbs/ MWh 0.7 lbs/ MWh Total Per Mwh Mercury emissions decrease overall and on a per mwh basis 3398 lbs 1167 lbs 0.000736 oz/MWh 2005 2014 2005 2014 0.000088 oz/ MWh New build program will dramatically lower the NRG emissions profile |