third quarter 2004 financial results
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Third Quarter 2004 Financial Results. Safe Harbor Statement. - PowerPoint PPT PresentationTRANSCRIPT
Third Quarter 2004 Financial Results
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Safe Harbor Statement
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. Forward-looking statements are subject to certain risks, uncertainties and assumptions and typically can be identified by the use of words such as “expect,” “estimate,” “anticipate,” “forecast,” “plan,” “believe” and similar terms. Such forward-looking statements include, but are not limited to, expected earnings, future growth and financial performance, the sufficiency of the disputed claims reserve, the successful closing of announced transactions, the successful refinancing of our credit agreement, the successful closing of coal transportation agreements, the successful implementation of our acquisition and repowering strategy, and the EBITDA impact of the RMR settlement. 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, 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 and related government regulation, the condition of capital markets generally, our ability to access capital markets, unanticipated outages at generation facilities, our ability to convert facilities to western coal, our substantial indebtedness and the possibility that we may incur additional indebtedness, adverse results in current and future litigation, delays in or failure to meet closing conditions in announced transactions, failure to identify or successfully implement acquisitions and repowerings, the amount of proceeds from asset sales and failure to obtain FERC approval of the RMR settlement.
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 is an estimate as of November 9, 2004 and is based on assumptions believed to be reasonable as of that date. NRG disclaims any current intention to update such guidance from November 9, 2004. 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.
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Agenda
Third Quarter Overview Financial Highlights Operating Performance Review Portfolio Management International Current Focus
Financial Results Review 3rd Quarter and YTD Results Liquidity Update Capital Allocation Plan
Questions and Answers
4
Third quarter performance Adjusted EBITDA of $272 million Net cash flow of $284 million
YTD performance Adjusted EBITDA of $762 million Net cash flow of $554 million Liquidity increased nearly $450 million to $1.6 billion
Net Debt/Capital Ratio1
Improved to 50% from 60% since the beginning of 2004
Financial HighlightsFinancial Highlights
1 Excludes $200 million in operating cash and Kendall
5
Q3 Operating Highlights
South Central generation was 27% higher in Q3 2004 than Q3 2003 due to strong performance from Big Cajun 2
Northeast generation was down 22% due to milder weather which limited runtimes at our intermediate and peaking facilities
Equivalent Availability – is the total available hours a unit is available in a year minus the summation of all partial outage events in a year converted to Equivalent Hours (EH) where EH is partial megawatts lost divided by unit Net Available Capacity times hours of each event and the net of these hours is divided by hours in a year to achieve Equivalent Availability Factor in percent.
RegionNet
Generation (MWH)
Equivalent Availability (%)
Average Heat Rate (Btu/nKwh)
Net Capacity Factor (%)
Net Owned Capacity
Northeast 2,983,705 87% 11,289 38.5% 7,884
South Central 3,424,242 99% 10,551 71.8% 2,469
West 1,010,456 88% 11,425 19.1% 1,321
6
2004 Gross Margin
Gross Margin ($ thousands) 3Q YTD
Dark Spread 1,2 $59,131 $230,164
Gas Spread $ 6,929 $ 10,463
Dual Fuel/Oil Spread $11,299 $ 48,839
In Q3, gross margin from dual fuel and coal fired generation impacted by mild weather No generation from Oswego Norwalk Harbor responsible for majority of dual fuel/oil
gross margin
1 Dark spread is the spread between energy prices and coal-fired generation costs2 Does not include LaGen contracted output
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Portfolio Management-2004 Noncore Asset SalesPortfolio Management-2004 Noncore Asset Sales
Sold for value Minimal proceeds
leakage to advisors Minimal tax
leakage
Name LocationActual or expected
cash proceeds(Millions)
Balance Sheet Debt
(Millions)
Status
Loy Yang A Australia $27 N/A Completed Q2
Cobee Bolivia $50 $24 Completed Q2
Calpine Cogen Various, U.S. $3 N/A Completed Q1
PERC Maine $18 $25 Completed Q2
Illinois $1 $450Kendall Executed PSA
TOTAL $156 $993
Batesville Mississippi $27 $292 Completed Q3
Oklahoma N/A $157McClain Completed Q3
Taiwan N/A $45Hsin Yu Completed Q2
Various $12 N/ANEO Projects Completed Q3
Virginia $4 N/AJames River Executed PSA
Virginia $14 N/ACALP Executed PSA
Itiquira Brazil $? ? Sale in Progress
Enfield U.K. $? N/A Sale in Progress
Saguaro Nevada $? N/A Sale in Progress
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Portfolio Management - Connecticut
Plants MWs Regulatory Status 2004E EBITDA Impact
Devon 11-14, Montville, Middletown
1,392 2004-2005 RMR $91.2 million
Devon 7 and 8 1 214 Both units deactivated by Oct. 1, 2004
$ 7.7 million
Norwalk Harbor 353 PUSH bidding continues until LICAP is in place
$39.5 million
Reached Settlement with CT Authorities related to RMR: Settlement with multiple CT parties eliminates refund risk Settlement provides for 2004 and 2005 certainty Effectively bridges us to scheduled LICAP introduction by
1/1/06
1 Devon 7 deactivated 10/1/2004, Devon 8 deactivated 6/1/2004
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Portfolio Management - California
Plant Net MWs
Regulatory Status
Potential Alternative Use Value (AUV)
Source of AUV
Cabrillo I 482 RMR Highest Commercial Real Estate; Desalination
Cabrillo II 93 RMR None N/A
El Segundo 335 TBD High Commercial Real Estate; Power Redevelopment
Long Beach 265 Market Marginal Port Usage
No solution yet, but progress is being made. Signals are positive:
CPUC ordered acceleration of excess reserve requirements from 1/1/08 to 6/1/06
RMR status for Cabrillo I and Cabrillo II successfully extended through 2005
Additional requests for offer have been initiated by California’s LSE in recent weeks
Veto of AB2006, support for AB57, pro-competition appointments to CAISO, Interim Procurement Order (7/8/04) from CPUC
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International - Australia
What value added does our Australian portfolio provide? Significant, predominately contracted, EBITDA Properly functioning market, countercyclical to U.S regional
markets Portfolio dominated by low-in-the-merit-order black coal plants Operations know-how, technical and commercial, across the
portfolio Ability to dividend cash to parent through refinancing
NRG FacilitiesNRG Facilities
Gladstone
Flinders Adelaide
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Current Focus: Wrap up of Back to BasicsCurrent Focus: Wrap up of Back to Basics
Operational Priorities
4. Internal audit plan 2005
1. 2004 Guidance
3. CAPEX approval template
2. Capital Allocation strategy
5. Risk Mgmt self-assessment
X
First 100 Days 11/11 Second 100 Days 12/15
4. Resolve Connecticut
1. Safe, reliable, efficient
3. Maintain momentum inasset sale program
2. Increase contracted portionof merchant generation
Financial Priorities
1. Simplify cap structure
3. Reduce borrowing cost
2. Enhance liquidity
Organizational Priorities
2. Phase-out of advisers
3. Redirect mgmt team
4. Restructure corp org
1. New CFO
2. Germany & Australia
1. Regional strategic plans
2. Function specific transition plan
3. 3rd party advisor cost control
4. Incentive compensation scheme
1. Hire key staff
X
4. Resolve California
1. Summer Operations
3. Sell Kendall
2. Advance contract positionfor winter ’04-’05
X
Third 100 Days ?/16
4. Resolve California
3. Itiquira and Enfield
2. Hedge gas exposure
5. Process control cost savings initiative
3. Internal audit plan 2005
1. Address senior debt facility
2. File S-4
4. Sarbanes-Oxley compliance
3. 3rd party advisor cost control
4. Comp. scheme detailed roll out
1. Complete PMI transition
2. New business/brownfield strategy
1. Translate strategic plan into 2005 budget
6. Implement coal strategy
2. Succession Plan
1. Winter operation preparedness
Operational Priorities
Strategic Priorities
Financial Priorities
Organizational Priorities
Operational Priorities
Strategic Priorities
Financial Priorities
Organizational Priorities
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Current Focus – Hedging
Active hedging program focused on 4 key drivers:
Coal dark spreads currently high – driven by natural gas-related increase in power prices
Gas spark spreads very compressed and not attractive at current levels
Coal portfolio leveraging scale and flexibility
Oil spark spreads remain volatile, driven by weather and natural gas prices
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Current Focus – HedgingNYC Gas Spark Spread: Winter/Summer ‘05 On-Peak
Summer2005
Winter2005
Note: Indicative spark spread trend using Transco Z6 NY @ 10 mmbtu/Mwh heat rate
Spark spreads have compressed with rising natural gas prices and do not represent attractive hedging opportunities at current market levels
25
27
29
31
33
35
37
39
July-04 August-04 September-04 October-04
$/M
Wh
6
6.5
7
7.5
8
$/m
mbtu
NYC Spark Spread
Natural Gas
-10
-5
0
5
10
July-04 August-04 September-04 October-04
$/M
Wh
8
9
10
11
12
13
14
$/m
mbtu
NYC Spark Spread
Natural Gas
14
0
2
4
6
8
10
12
14
16
July-04 August-04 September-04 October-04
$/M
Wh
NY West Dark Spread on Oil
Current Focus – HedgingNY West Oil Spark Spread: Winter ‘05 On-Peak
Note: Indicative spark spread on #6 oil 1% @ 12 mmbtu/MWh heat rate
Forward oil spark spreads have increased with NG related rise in power prices
Spot oil margins are highly dependent on natural gas prices and weather: we are taking a balanced approach.
Winter hedges increased to ~60%
15
30.00
35.00
40.00
45.00
50.00
55.00
60.00
J uly-04 August-04 September-04 October-04
$/
MW
h
5
5.5
6
6.5
7
7.5
8
8.5
$/
mm
btu
NY West Dark Spread
Nymex Natural Gas
Current Focus – HedgingNY West Dark Spread: Cal ‘05 On-Peak
Note: Indicative trend for dark spread on coal @ 10 mmbtu/MWh heat rate
Dark spreads have increased with rising natural gas prices providing favorable hedging opportunities for coal margins
Winter hedges increased to 98%Calendar ‘05 hedges increased to 75%
Winter hedged 53%Calendar ‘05 hedged 34%
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Coal market dynamics have been challenging High eastern U.S. coal prices Transportation congestion Low stockpiles
We expect strong coal pricing to continue into 2005
Western U.S. coal has remained relatively stable These challenges are manageable
Current Focus – HedgingCoal Market Outlook
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Current Focus – Hedging
Huntley760 MW1.4 MM tons/year
Dunkirk600 MW2.0 MM tons/year
Somerset136 MW250 k tons/year
Indian River784 MW 1.0 MM tons/year
Big Cajun1489 MW7.8 MM tons/year
Dover106 MW 70 k tons/year
Coal Supply
2004 2005
Import 100 k 200 k
Eastern U.S. 3.0 MM 1.0 MM
Western U.S. 9.4 MM 11.3 MM
NRG Coal Generation Fleet: 12.5 million tons/year
Reducing reliance on Eastern US Coal
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Current Focus – Hedging
UPBNCSXNSVesselBarge
UPBNCSXNSVesselBarge
The Four Key Components of Coal Supply1. Transportation Infrastructure (railcars, barges, vessels)2. Transportation Service (railroads, shipping companies)3. Coal Storage/Transshipment (Conneaut, ACT, DTA)4. Coal Supply (producers and other suppliers)
Coal strategy must first meet environmental remediation and compliance
Coal Portfolio: Competitive advantage through scale and optionality across the 4 Key Components of Supply
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Current Focus – Hedging Summary
Currently we focus on: Hedging coal and oil margins opportunistically to allow us
to capture recent gas related increases in power prices Remaining largely unhedged on gas margins to optimize
upside swings Leveraging optionality in coal supply and transportation
to minimize delivered cost of fuel
Our positions are never static; we actively manage our portfolio as market conditions change
Our hedging program focuses on balancing upside potential against downside uncertainties.
Financial and Operating Results
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Operating revenues 607 1,781
Gross margin 342 1,025
Net income 54167
EBITDA 224752
Adjusted EBITDA 272762
$ millions$ millions
Key Financial HighlightsKey Financial Highlights
YTDYTDQ3Q3
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EBITDA by Operating Segment
($ millions)
Q3 EBITDA
Q3 Adj.
Q3 Adj. EBITDA
YTD Adj. EBITDA
Northeast 110 - 110 303.5
South Central 30 - 30 92.0
West Coast 47 - 47 135.5
Other North America 6 32 38 72.5
Australia 9 - 9 60.2
Other International 34 - 34 72.5
Alternative Energy 5 .5 6 11.0
Nongeneration 12 - 12 38.0
Corp - Unallocated (29) 15 (14) (23.2)
Total 224 48 272 762.0
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Cash Flow YTD
$ in millions YTD
EBITDA 752
Interest Payments (193)
Income Tax (27)
Other Funds used by Operations (66)
FFO 466
Working Capital Changes 4
Xcel Settlement, net 125
CFO 595
Asset Divestitures 276
CapEx (78)
Other Cash used by Investing 13
FX Rate Changes & Disc Ops (25)
FCF 782
Cash Used by Financing (228)
Net Cash Flow 554
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Liquidity
12/30/03 09/30/04
Unrestricted Cash:
Domestic 418 936
International 134 169
Restricted Cash:
Domestic 70 94
International 46 55
Total Cash 668 1,254
Letter of Credit Availability 248 97
Revolver Availability 250 250
Total Current Liquidity $1,166 $1,601
$ millions
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Capital Allocation Planning-Threshold Issue
Examples of Restrictive Covenants Senior Debt Facility High-Yield Note Indenture
Permitted Acquisition Indebtedness
Up to $100MM secured by acquired assets plus debt
reduced by asset sales
$150MM basket, plus $250MM general basket
plus ratio debt
General Unrestricted Investment Basket
Up to $150MM Up to $200MM
Use of CashMandatory prepayment
obligations applyDoes not apply
Return of Capital to Shareholders-Dividend
-Share Repurchase-Special Dividend
Not allowed$50MM plus 50% of
retained earnings plus proceeds of equity issued
Reinvestment in Existing AssetsCapex limited to
$150MM/yearDoes not apply
Acquisition of Additional Assets Various basketsIncurrence test dictates
debt amount
At this point in the Company’s development, the Senior Debt Facility terms and conditions are excessively restrictive, resulting in inefficient allocation of capital
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Refinancing Rationale
Improved Pricing: The Company expects pricing to improve significantly, due to improvement in market conditions
Less Restrictive Covenants: The covenants on the new credit facilities will more closely resemble those in the indenture for the existing second priority senior secured notes
Maintain Liquidity: The Company will maintain liquidity through:
$150 million Revolving Credit Facility
$350 million Pre-Funded Letter of Credit Facility
Cash Balances
While we have the liquidity, it does not make sense for us simply to repay the facility since it is low cost capital
27
Capital Allocation Plan-Beyond the Threshold
Maintaining progress towards achieving our target net debt/total capital ratio is fundamental
Objective is to keep substantial, but not excessive, liquidity inside the business
Cost of modifying in a material way the terms of the bond indenture make this option unattractive at this time
28
2004 Outlook
$ in millions ReportedOutlook
Adjustment RecurringOutlook
Forecasted Adjusted EBITDA1 865 10 875
Interest Payments (278) 15 (263)
Income Tax (32) – (32)
Other Cash Used by Operations (40) – (40)
FFO 515 25 540
Working Capital Changes (60) – (60)
Xcel Settlement, net 100 (100) –
CFO 555 (75) 480
Asset Divestitures 156 (156) –
CapEx (130) – (130)
Other Cash used by Investing (7) – (7)
FCF 574 (231) 343
1Includes $42.4 million of Kendall EBITDA and does not include any costs associated with a potential refinancing
29
$2.0 million100 bpsInterest rates
$0.7 million$1.00/mmbtuNatural Gas
--$1.00/tonCoal
Results in the following change to
2004 pre-tax income:SensitivityFactors
Sensitivities are for the remaining 3 months of 2004, assuming current hedged positions
2004 Forecast Sensitivity Analysis2004 Forecast Sensitivity Analysis
NRG has substantially hedged operating gross margin for the remainder of the year
--$1.00/barrelOil
30
Enterprise Value
As of 9/30/04 $ in millions Supported Nonsupported Kendall Total
Consolidated Debt $ 3,053 $ 558 $ 0 $ 3,611
Unrestricted Cash 1,086 19 1,105
Restricted Cash 75 74 149
Total Cash 1,161 93 1,254
Net Debt $ 1,892 $ 465 $ 2,357
Equity Value $ 2,925 – $ 2,925
Enterprise Value $ 4,817 $ 465 $ 5,282
2004 Forecasted Adj. EBITDA $ 765 $ 68 $ 42 $ 875
TEV / FY Adjusted EBITDA 6.3x
1 Debt balances do not include Kendall but EBITDA contains $42.4 million from Kendall
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$18
$20
$22
$24
$26
$28
$30
12/2/03 2/24/04 5/18/04 8/10/04 11/2/04
Capital Markets Performance
5.0%
6.0%
7.0%
8.0%
9.0%
Dec-03 Jan-04 Mar-04 Apr-04 Jun-04 Jul-04 Aug-04 Oct-04CSFB HY Index CSFB BB Index NRG Energy
NRG’s share price has increased over 40% since exiting from bankruptcy, and the Company’s High-Yield Notes are trading at a yield of 6.2%.
Share Price Performance Second Priority Notes – Yield to Worst
Second Priority Notes – Spread to Worst
Maintaining a balance is good for equity and debt holders
200
300
400
500
600
Dec-03 Jan-04 Mar-04 Apr-04 Jun-04 Jul-04 Aug-04 Oct-04
CSFB HY Index CSFB BB Index NRG Energy
32
Q&A
Appendix
34
Debt Schedule (US $mm) – 9/30/2004
S Xcel Note 9.1
S Senior Credit Facility 691.3
S 8% Notes 1736.7
Camas 11.1
Conemaugh 0.2
NEO Northbrook 25.6
NEO NY 16.7
Peakers 245
S Processing-Capital Lease 0.1
S Thermal San Francisco 0.3
S Thermal Pittsburgh 0.4
S Thermal 127
S Meriden 0.5
Audrain-Capital Lease 239.9
S Schkopau-Capital Lease 286.4
Itiquira-ST Debt 19.4
S Flinders 201.5
Total consolidated $ 3611.2“S” indicates Supported Project as discussed on Slide 29
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YTD Operational Statistics – 9/30/04
RegionNet
Generation (MWH)
Equivalent Availability
(%)
Average Heat Rate
(Btu/nKwh)
Net Capacity
Factor (%)
Net Owned
Capacity
Northeast 8,508,652 80% 11,123 36.5% 7,884
South Central
9,306,924 91% 10,584 65.0% 2,469
West 2,806,300 78% 10,849 17.9% 1,321
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Adj. Net Income GAAP Reconciliation
Adjusted Net Income ReconciliationThe following table summarizes the calculation of adjusted net income and provides a reconciliation to GAAP net income/(loss), including per share amounts:
Three Months Ended YTD
Reorganized NRG
Predecessor NRG
September 30, 2004
(Dollars in thousands, except per share amounts)
September 30, 2004
Diluted EPS September 30, 2003
Diluted EPS
Net Income (Loss) $ 54,221 $ 0.54 $ (284,794)
$ 167,480
$ 1.67
Plus:
(Income) Loss from Discontinued Operations, net of tax
(400) (0.01) (374)
(915) (0.01)
(Gain) Loss from Discontinued Operations
(10,491) (0.10) 624
(22,389) (0.22)
Corporate relocation charges, net of tax 4,296 0.04 - 8,607
0.08
Reorganization items, net of tax (3,944) (0.04) 20,305
(1,143) (0.01)
Restructuring and impairment charges, net of tax
30,461 0.30 6,133
29,106 0.29
FERC-authorized settlement with Connecticut Light and Power, net of tax
- - - (26,466) (0.26)
Write down of Note Receivable, net of tax 3,438 0.04 - 3,155
0.03
Write downs and (gains)/losses on sales of equity method investments, net of tax
10,170 0.10 (12,064)
13,776
0.14
Adjusted Net Income $ 87,751 $ 0.87 $ (270,170)
$ 171,211
$ 1.71
37
Adj. EBITDA GAAP ReconciliationThree Months Ended YTD
Reorganized NRG
Predecessor NRG
September 30, 2004
September 30, 2003
September 30, 2004
(Dollars in thousands)
Net Income / (Loss) $ 54,221 $ (284,794) $ 167,480
Plus:
Income Tax Expense 14,264 5,437 64,866
Interest expense, excluding amortization of debt issuance costs and debt discount/ (premium)
61,061 30,932 193,260
Depreciation and amortization 51,373 56,510 159,547
WCP CDWR contract amortization (included in equity in earnings of unconsolidated affiliates)
28,098 - 89,704
Amortization of power contracts 3,715 - 29,294
Amortization of emission credits 4,919 - 14,837
Amortization of debt issuance costs and debt discount/(premium) 5,822 3,492 32,994
EBITDA $ 223,473 $ (188,423) $ 751,982
Plus:
(Income) Loss from Discontinued Operations, net of Income Taxes (400) (374) (915)
(Gain) Loss from Discontinued Operations (10,491) 624 (22,389)
Corporate relocation charges 5,713 - 12,474
Reorganization items (5,245) 20,698 (1,656)
Restructuring and impairment charges 40,507 6,252 42,183
FERC-authorized settlement with Connecticut Light and Power - - (38,357)
Write down of Note Receivable 4,572 - 4,572
Write downs and (gains)/losses on sales of equity method investments 13,524 (12,310) 14,057
Adjusted EBITDA $ 271,653 $ (173,533) $ 761,951
38
GAAP Reconciliation
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 press 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 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.
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 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 presentation.